Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Site Security, 81356-81459 [2016-25407]
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004–AE15
Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases;
Site Security
Bureau of Land Management,
Interior.
ACTION: Final rule.
AGENCY:
This final rule replaces
Onshore Oil and Gas Order No. 3, Site
Security (Order 3), with new regulations
codified in the Code of Federal
Regulations (CFR). The final rule
establishes minimum standards for oil
and gas facility site security, and
includes provisions to ensure that oil
and gas produced from Federal and
Indian (except Osage Tribe) oil and gas
leases are properly and securely
handled, so as to ensure accurate
measurement, production
accountability, and royalty payments,
and to prevent theft and loss.
The BLM developed this rule based
on the proposed rule that was published
in the Federal Register on July 13, 2015,
and tribal and public comments the
BLM received on the proposed rule.
This rule strengthens the BLM’s policies
governing production verification and
accountability by updating and
replacing the existing requirements of
Order 3 to address changes in
technology and industry practices that
have occurred in the 25 years since
Order 3 was issued, and to respond to
recommendations made by the
Government Accountability Office
(GAO) and the Office of the Inspector
General (OIG) with respect to the BLM’s
production verification efforts.
Like the proposed rule, the final rule
addresses Facility Measurement Points
(FMPs), site facility diagrams, the use of
seals, bypasses around meters,
documentation, recordkeeping,
commingling, off-lease measurement,
the reporting of incidents of
unauthorized removal or mishandling of
oil and condensate, and immediate
assessments for certain acts of
noncompliance. The final rule also
establishes a process for the BLM to
consider variances from the
requirements of the final regulation.
Some of the key changes from the
proposed rule that are incorporated into
the final rule include: Additional
exemptions from the final rule’s
commingling requirements; a
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streamlined FMP application and
approval process; simplified site facility
diagram submissions; and clarifications
to tank gauging procedures and
frequency.
The BLM believes that this final rule,
as well as the final rules to update and
replace Onshore Oil and Gas Order No.
4 (Order 4), related to measurement of
oil, and Onshore Oil and Gas Order No.
5 (Order 5), related to measurement of
gas enhance the BLM’s overall
production verification and
accountability program.
DATES: The final rule is effective on
January 17, 2017.
FOR FURTHER INFORMATION CONTACT:
Michael Wade, BLM Colorado State
Office, at 303–239–3737, for information
about the requirements of this final rule,
or Steven Wells, Division Chief, Fluid
Minerals Division, 202–912–7143, for
information regarding the BLM’s Fluid
Minerals Program. Persons who use a
telecommunications device for the deaf
(TDD) may call the Federal Relay
Service at 1–800–877–8339 to contact
the above individuals during normal
business hours. The Service is available
24 hours a day, 7 days a week to leave
a message or question with the above
individual. You will receive a reply
during normal business hours.
SUPPLEMENTARY INFORMATION:
I. Executive Summary and Background
II. Overview of the Final Rule, Section-bySection Analysis, and Response to
Comments
III. Overview of Public Involvement and
Consistency With GAO
Recommendations
IV. Procedural Matters
I. Executive Summary and Background
Under applicable law, royalties are
owed on all production removed or sold
from Federal and Indian oil and gas
leases, as well as on any oil or gas that
is avoidably lost during production. The
basis for those royalty payments is the
measured production from those leases.
In the fiscal year (FY) 2015 sales year,
onshore Federal oil and gas leases sold
180 million barrels (bbl) of oil,1 2.50
trillion cubic feet of natural gas,2 and
2.6 billion gallons of natural gas liquids,
with a market value of more than $17.7
billion and generating royalties of
almost $2.0 billion. Nearly half of these
1 Figures related to total production of oil include
168 million bbl of regularly classified oil, plus
additional sales of condensate, sweet and sour
crude, black wax crude, other liquid hydrocarbons,
inlet scrubber and drip or scrubber condensate, and
avoidable oil losses, all of which are considered to
be part of oil sales for accounting purposes.
2 Includes all processed and unprocessed
volumes recovered on-lease, nitrogen, fuel gas, coal
bed methane, and any volumes of gas avoidably lost
due to venting or flaring.
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revenues were distributed to the States
in which the leases are located. Leases
on tribal and Indian lands sold 59
million bbl of oil, 239 billion cubic feet
of natural gas, 182 million gallons of
natural gas liquids, with a market value
of over $3.6 billion and generating
royalties of over $0.6 billion, which
were distributed in their entirety to the
applicable tribes and individual allottee
owners.
As explained in the preamble for the
proposed rule (80 FR 40768), given the
magnitude of this production and the
BLM’s statutory and management
obligations, it is critically important that
the BLM ensure that operators
accurately measure, properly report, and
account for all production. This final
rule helps the BLM achieve that
objective by updating and replacing
Order 3’s requirements with regulations
codified in the CFR that reflect changes
in oil and gas measurement practices
and technology since Order 3 was first
promulgated in 1989.3
Specifically, the requirements in this
rule ensure the proper and secure
handling of production from Federal
and Indian (except Osage Tribe) oil and
gas leases. The proper handling of
production is essential to accurate
measurement, proper reporting, and
overall production accountability, all of
which are necessary to ensure that the
American public, as well as Indian
tribes and allottees, receive the royalties
to which they are entitled on oil and gas
produced from Federal and Indian
leases, respectively.
Order 3 was one of seven Onshore Oil
and Gas Orders that the BLM issued
under its regulations at 43 CFR part
3160.4 Order 3 primarily supplemented
the regulations at 43 CFR 3162.4
(records and reports), 3162.5
(environmental safety), 3162.7
(disposition and measurement of oil and
gas production and site security on
Federal and Indian (except Osage Tribe)
oil and gas leases), subpart 3163 (noncompliance, assessments, and civil
penalties), and subpart 3165 (relief,
conflicts, and appeals). While the BLM’s
Onshore Orders have all been published
in the Federal Register, both for public
comment and in final form, they were
never codified in the CFR. With this
final rule, the BLM is replacing Order 3
and updating and codifying its
3 Order 3, which was published in the Federal
Register on February 24, 1989 (54 FR 8056), has
been in effect since March 27, 1989.
4 These regulations provide for the issuance of
Onshore Oil and Gas Orders to ‘‘implement and
supplement’’ the regulations found in part 3160. 43
CFR 3164.1(a). The Onshore Orders apply
nationwide to all Federal onshore and Indian
(except Osage Tribe) oil and gas leases.
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requirements regarding site security, as
explained below.
The development of this rule was
driven largely by internal and external
reviews of the BLM’s existing
production measurement and
accountability program. These reviews
began in 2007 when the Secretary
appointed an independent panel—the
Subcommittee on Royalty Management
(Subcommittee)—to review the
Department’s procedures and processes
related to the management of mineral
revenues and to provide advice to the
Department based on that review.5 In a
report dated December 17, 2007, the
Subcommittee determined that the
BLM’s guidance regarding production
accountability is ‘‘unconsolidated,
outdated, and sometimes insufficient’’
(Subcommittee report, p. 30). The
Subcommittee report found that this
results in inconsistent and outmoded
approaches to production accountability
tasks, and the potential loss of royalty
revenue.
The Subcommittee report expressed
concern that the applicable ‘‘BLM
policy and guidance is outdated’’ and
‘‘some policy memoranda have expired’’
(Subcommittee report, p. 31). The
Subcommittee also expressed concern
that ‘‘BLM policy and guidance have not
been consolidated in a single document
or publication,’’ which has led to the
‘‘BLM’s 31 oil and gas field offices using
varying policy and guidance’’ (id.). For
example, ‘‘some BLM State Offices have
issued their own ‘Notices to Lessees’ for
oil and gas operations’’ (id.). While the
Subcommittee recognized that such
Notices to Lessees may have a positive
effect on some oil and gas field
operations, it also observed that they
necessarily ‘‘lack a national perspective
and may introduce inconsistencies
among State [Offices]’’ (id.).
The Subcommittee made a number of
recommendations relevant to site
security. It recommended that the BLM
re-evaluate its regulations and update its
policy and guidance on production
accountability, including requiring that
requests to commingle production from
multiple leases, unit participating areas
(PAs), or areas subject to
communitization agreements (CAs)
identify allocation among zones
(Subcommittee report, p. 32). The
Subcommittee also recommended that
5 The Subcommittee was commissioned to report
to the Royalty Policy Committee, which was
chartered under the Federal Advisory Committee
Act to provide advice to the Secretary and other
departmental officials responsible for managing
mineral leasing activities and to provide a forum for
the public to voice concerns about mineral leasing
activities. The Royalty Policy Committee’s chart has
since expired.
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the BLM re-evaluate its policies and
guidance for royalty-free use of gas in
lease operations. It also specifically
recommended that the BLM establish a
workgroup to evaluate Order 3. In
response, the Department formed a fluid
minerals team, comprising
Departmental employees who are oil
and gas experts. Based on its review, the
team determined that Order 3 should be
updated.
In addition to the Subcommittee
report, the GAO and the OIG have
performed multiple audits since 2009
and issued reports that included many
findings and recommendations
addressing similar issues: (1) Report to
Congressional Requesters, Oil and Gas
Management, Interior’s Oil and Gas
Production Verification Efforts Do Not
Provide Reasonable Assurance of
Accurate Measurement of Production
Volumes GAO–10–313 (GAO Report 10–
313); (2) Report to Congressional
Requesters, Oil and Gas Resources,
Interior’s Production Verification
Efforts: Data Have Improved but Further
Actions Needed, GAO 15–39 (GAO
Report 15–39); (3) Bureau of Land
Management’s Oil and Gas Inspection
and Enforcement Program, CR–EV–
0001–2009 (OIG Report 2009); and (4)
Energy Related Management Advisories,
CR–IS–MOA–0005–2014 (OIG Report
2014).
In 2010, the GAO found that Interior’s
measurement regulations and policies
do not provide reasonable assurance
that oil and gas are accurately measured.
Regarding matters relevant to site
security, the report found that the BLM
lacks regulatory or policy requirements
for operators to clearly identify points of
royalty measurement, creating
challenges for the BLM in verifying
production (GAO Report 10–313, p. 34).
It also found that the BLM does not have
sufficient national policies or a
consistent process for approving
arrangements that allow operators to
commingle production from multiple
Federal, Indian, State, and private
leases, which also makes it difficult for
the agency to verify production (GAO
Report 10–313, p. 36). In response, the
GAO specifically recommended that the
BLM: (1) Develop guidance clarifying
when Federal oil and gas may be
commingled and establish standardized
measurement methods for such
circumstances so that production can be
adequately measured and verified; (2)
Confirm that commingling agreements
are consistent with Interior guidance
before they are approved, and that the
agreements facilitate key production
verification activities; and (3) Track all
onshore meters, including information
about meter location, identification
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number, and owner, to help ensure that
Interior (through the BLM) is accurately
and consistently tracking where and
how onshore oil and gas are measured
nationwide.
The GAO reiterated some of these
concerns in 2015 (GAO Report 15–39).
In that report, the GAO acknowledged
the improvements the BLM had made in
its processes and policies (e.g., issuing
additional guidance in 2013 regarding
commingling approvals), but reiterated
the importance of the BLM updating its
regulations related to measurement and
site security (GAO Report 15–39, pp.
31–32).
Based in part on its concern that the
BLM’s production verification efforts do
‘‘not provide reasonable assurance that
operators are accurately measuring and
reporting’’ the volumes of oil and gas
produced from Federal and Indian
leases, the GAO included the BLM’s
onshore oil and gas program on its High
Risk List in 2011 (Report to
Congressional Committees, High Risk
Series, An Update, GAO–11–278 (GAO
Report 11–278), p. 15). Because the
GAO’s recommendations have not yet
been fully implemented, including
those related to production verification,
the onshore oil and gas program has
remained on the High Risk List in
subsequent updates in 2013 (Report to
Congressional Committees, High Risk
Series, An Update, GAO–13–283) and
2015 (Report to Congressional
Committees, High Risk Series, An
Update, GAO–15–290).
The OIG made similar observations as
part of its reviews of the BLM’s
inspection and enforcement program.
For example, in 2009 the OIG observed
that the BLM’s ‘‘inspection efforts are
hampered because of provisions in the
bureau’s regulations that have not kept
up with modern technology. Most
notably, six of the seven Onshore Oil
and Gas Orders, which address
activities, such as drilling operations,
the measurement of oil and gas, and site
security, are outdated as they were
enacted in the late 1980s and early
1990s.’’ The OIG specifically
recommended that the BLM ‘‘(e)nsure
that oil and gas regulations are current
by updating and issuing onshore
orders.’’ (OIG Report 2009, p. 10–11).
The OIG also expressed concern that
‘‘(c)urrent BLM policies (with respect to
penalties and assessments) do not allow
for immediate assessments for chronic
offenders. As a result, at times there is
little incentive for companies to meet
their regulatory responsibilities.’’ (id., p.
13). As a result, the OIG recommended
that the BLM ‘‘(e)nhance the deterrent
for operator noncompliance by
increasing the dollar amount of
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monetary assessments, seeking
congressional action for increasing civil
penalties, and expanding the infractions
for which immediate assessments may
be issued.’’ (id., p. 14).
The OIG supplemented these
recommendations in 2014 with a series
of recommendations that flowed from
individual OIG investigations that were
consolidated into one report—Energy
Related Management Advisories, CR–
IS–MOA–0005–2014 (Nov. 2014) (OIG
Report 2014).6 That report made a
number of recommendations, including
the following relevant to this rule:
• Develop and implement procedures
to ensure timely receipt of site facility
diagrams and ensure that they contain
adequate information related to
production and sales phases (OIG
Report 2014 at 10, 18);
• Take steps to address misreporting
associated with off-lease measurement
(id.);
• Ensure that adequate information
exists regarding on-lease beneficial use
in order to identify inappropriate
deductions (id., at 12); and
• Ensure that Federal measurement
points are properly documented and
recorded (id. at 21).
In addition to the concerns from these
entities, the BLM also recognized, based
on its own experience, that its site
security requirements needed
strengthening. For example, as
explained in the proposed rule, it is not
uncommon for a BLM inspector, a lease
operator, and field employees to all
have different understandings of where
the point of royalty measurement is on
a given lease, because Order 3 did not
require operators to formally identify
and obtain BLM approval for the use of
a particular royalty measurement point
on a given lease, unit PA, or CA. This
type of discrepancy can create needless
uncertainties in production, accounting,
and verification, and can increase the
time spent on individual inspections
and audits by both operators and the
BLM, which strains the BLM’s limited
resources and requires additional
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6 The OIG Report 2014, covered the following
investigations: Berry Petroleum Co. & Quinex
Energy Corp., DOI–OIG Case File Nos. OI–OG–07–
0359–I & OI–OG–07–0389–I; Petrox Resources, Inc.,
DOI–OIG Case File No. OI–OG–09–0266–I; SEECO,
Inc., OIG Case File No. OI–OG–09–0722–1; and
TEPPCO Partners, DOI–OIG Case File No. OI–OG–
09–0346–I).
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response and resources on the part of
operators. This final rule corrects this
problem by requiring operators to
identify and obtain BLM approval for
their royalty measurement points,
which are called FMPs under this rule.
Similarly, with respect to
commingling approvals, the BLM
recognizes that the absence of uniform
national guidance means that some
BLM-approved commingling agreements
may not provide the production data
that the BLM needs to independently
verify production that is attributable to
the Federal or Indian leases covered by
those agreements. The absence of this
data limits the BLM’s ability to fulfill its
obligation to ensure that all production
from Federal and Indian (except Osage
Tribe) oil and gas leases is properly
accounted for and that royalties are
properly calculated. The final rule
addresses these concerns by establishing
uniform requirements for both existing
and future commingling approvals.
With respect to existing approvals, the
final rule includes provisions: (1)
Specifically grandfathering existing
CAAs involving downhole commingling
and where production falls below
certain specified thresholds; (2)
Expressly exempting from compliance
with the rule’s commingling
requirements downhole commingling in
new wells in areas where the BLM has
specifically recognized that downhole
commingling is necessary to ensure
maximum economic recovery (such as
when a lower formation is necessary to
produce an upper one) or when
commingled production is below certain
levels; and, (3) Expressly recognizing as
compliant CAAs authorized by tribal
law or agreement. As explained in this
preamble, the provisions related to
grandfathering and the additional
exemptions were developed in response
to comments and are consistent with the
exceptions in the original proposed rule.
As explained in Section III of this
preamble, the requirements in this final
rule respond to the Subcommittee,
GAO, and OIG recommendations by
updating, enhancing, clarifying, and
codifying the Order 3 requirements to
reflect changes in technology, industry
practice, and applicable statutory
requirements. The final rule also
responds to comments received during
the public comment period on the
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proposed rule.7 In aggregate, the
provisions in the final rule help ensure
that the production of Federal and
Indian (except Osage Tribe) oil and gas
is adequately accounted for. By
replacing the patchwork of guidance
developed by BLM state and field
offices, the final rule also provides
operators with a level of consistency as
to the requirements applicable to their
operations on Federal and Indian
(except Osage Tribe) lands nationwide.
The Department of the Interior
(Department) plays the critical role of
ensuring that the country’s oil and gas
assets are carefully developed and that
the American people, Indian tribes and
individual allottees receive fair
compensation when these assets are
leased and developed. A key part of this
role consists of providing reasonable
assurance that Federal and Indian oil
and gas are accurately measured and
that measurement efforts undertaken by
the private companies developing these
resources are held to high standards.
II. Overview of the Final Rule, Sectionby-Section Analysis, and Response to
Comments
A. General Overview of the Final Rule
As discussed in the background
section of this preamble, the BLM’s
rules concerning site security and
production accountability found in
Order 3 have not kept pace with
industry standards and practices,
statutory requirements, or applicable
measurement technology and practices.
This final rule enhances the BLM’s
overall production accountability efforts
by addressing these concerns and will
ensure that the oil and gas produced
from Federal and Indian (except Osage
Tribe) leases is adequately accounted
for, ultimately ensuring that all royalties
due are paid. The following table
provides an overview of the changes
between the proposed rule and this final
rule. A similar chart explaining the
differences between the proposed rule
and Order 3 appears in the proposed
rule at 80 FR 40771.
7 As explained in the preamble to the proposed
rule, the proposal was developed based, in part, on
feedback received during a series of public meetings
held by the BLM on April 24 and 25, 2013. The
BLM also held public meetings and accepted
comments in December 2015.
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Proposed rule
43 CFR 3161.1(e)
Final rule
Jurisdiction ......
43 CFR 3162.4–1(d)
and reports.
Well records
43 CFR 3161.1(b)
Substantive changes
Jurisdiction ....
43
CFR
3162.4–1(d)
records and reports.
Well
None ................................................
43 CFR 3163.2
43 CFR 3163.2(a)(l)
Civil penalties
43 CFR 3163.2(a)(1)
alties.
Civil pen-
43 CFR 3163.2(b)(l)
Civil penalties
43 CFR 3163.2(b)(l)
alties.
Civil pen-
43 CFR 3163.2(b)(2)
alties.
Civil pen-
43 CFR 3163.2(b)(2)
alties.
Civil pen-
Generally ...........
43 CFR 3163.2(d)
Civil penalties
43 CFR 3163.2(e) Civil penalties.
Proposed as part of the Order 5
rulemaking.
43 CFR 3163.2(e)
Civil penalties
43 CFR 3163.2(f) Civil penalties.
Proposed as part of the Order 5
rulemaking.
43 CFR 3163.2(f)
Civil penalties
43 CFR 3165.3(a) Notice, State
Director review and hearing on
the record.
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43 CFR 3163.2(d) Civil penalties.
Proposed as part of the Order 5
rulemaking.
43 CFR 3165.3(a) Notice, State
Director review and hearing on
the record.
43 CFR 3170.3
acronyms.
43 CFR 3170.3
acronyms.
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The final rule removes a provision from the proposed rule that could
have unintentionally extended the regulations in part 3160 to State
or private tracts committed to a federally approved unit or CA.
In its place, the BLM clarifies that the regulations under part 3170, including subparts 3173, 3174, and 3175, relating to site security,
measurement, reporting of production and operations, and assessments or penalties for non-compliance with such requirements,
apply to all wells and facilities on State or privately owned lands
committed to a unit or CA, which includes Federal or Indian lease
interests, notwithstanding any contrary provision of the unit or communization agreement.
Consistent with the proposed rule, paragraph (d) has been revised to
incorporate the new records-retention period for Federal leases established by the 1996 amendments to Federal Oil and Gas Royalty
Management Act (FOGRMA), 30 U.S.C. 1701 et seq. In the final
rule, that provision has been restructured consistent with the
changes in paragraphs (c) through (e) of § 3170.7.
The changes being made as part of this rule are a combination of
the changes proposed as part of this rulemaking effort and the proposed rule to update and replace Order 5 (80 FR 61645). These
changes also reflect the modifications made by the BLM’s interim
final rule—Onshore Oil and Gas Operations—Civil Penalties Inflation Adjustments (81 FR 41860) (the ‘‘Civil Penalty Rule’’)—that
updates the various daily penalty maximums in this section.
Paragraph (a)(2) of the proposed rule is carried forward into the final.
The final rule deletes existing paragraphs (g) and (j) in their entirety and redesignates existing paragraph (i) as paragraph (g).
The final rule revises paragraph (a)(1) of the proposed rule to clarify
that this section applies to ‘‘any person,’’ as opposed to limiting it
to ‘‘operating rights owner or operator.’’ This change was proposed
as part of the Order 5 rulemaking and conforms the regulation to
the applicable statutory authority.
The final rule changes the references in the proposed rule to ‘‘operating rights owner, operator, purchaser, or transporter’’ to just ‘‘the
person’’ consistent with the change to paragraph (a)(1) to reference ‘‘any person.’’ Paragraph (b)(1) of the final also reflects the
increase in maximum daily penalty from $500 to $1,031 made by
the BLM’s Civil Penalty Rule.
The final rule changes the references in the proposed rule to ‘‘operating rights owner, operator, purchaser, or transporter’’ to just ‘‘the
person’’ consistent with the change to paragraph (a)(1) to reference ‘‘any person.’’ Paragraph (b)(2) of the final rule also reflects
the increase in the maximum daily penalty from $5,000 to $10,314
made by the BLM’s Civil Penalty Rule.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil-penalty assessments.
It also reflects the increase in maximum daily penalty from $500 to
$1,031 made by the BLM’s Civil Penalty Rule. Finally, it moves the
substance of existing paragraph (k) to paragraph (d). As a result,
paragraph (k) is removed.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil penalty assessments
and reflects the increase in maximum daily penalty from $10,000
to $20,628 made by the BLM’s Civil Penalty Rule.
Consistent with the proposed rule to update and replace Order 5, the
final rule removes the regulatory cap on civil penalty assessments
and reflects the increase in the maximum daily penalty from
$25,000 to $51,570 made by the BLM’s Civil Penalty Rule.
The final rule clarifies in paragraph (a) that any person is subject to
written notice or order by the authorized officer (AO) whenever
they fail to comply with any provisions of the lease, the regulations
in this part, applicable orders or notices, or any other appropriate
order of the AO. The proposed rule made this provision applicable
only to an operating rights owner or operator, as appropriate.
New definitions have been added for the terms ‘‘averaging period,’’
‘‘bias,’’ and ‘‘tampering’’ in response to comments received and
additional internal reviews.
In the final rule, the acronym Btu (British thermal unit) is moved from
§ 3173.1 to this section, and new acronyms—S&W (sediment and
water) and LACT (lease automatic custody transfer), are included
because they are used across multiple subparts in part 3170.
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Proposed rule
Final rule
Substantive changes
43 CFR 3170.6(a)(2)
Variances ....
43 CFR 3170.6(a)(2)
Variances
43 CFR 3170.6(a)(3)
Variances ....
43 CFR 3170.6(a)(3)
Variances
43 CFR 3170.7(c) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(d) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(e) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(c)(1) & (c)(2) Required recordkeeping, records
retention, and records submission.
43 CFR 3170.7(d)(1) & (d)(2)
Required
recordkeeping,
records retention, and records
submission.
43 CFR 3170.7(e)(1) & (e)(2)
Required
recordkeeping,
records retention, and records
submission.
43 CFR 3170.7(g) Required recordkeeping, records retention,
and records submission.
43 CFR 3170.7(g) Required recordkeeping, records retention,
and records submission.
3170.8
Appeal procedures ............
3170.8(a) & (b)
dures.
3173.1
Definitions and acronyms ..
3173.1
Appeal proce-
Definitions and acronyms
43 CFR 3173.3(a) Oil measurement system components—
seals.
43 CFR 3173.6
operations.
mstockstill on DSK3G9T082PROD with RULES3
43 CFR 3173.3(a) Oil measurement system components—seals.
43 CFR 3173.6
operations.
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Final paragraph (a)(2) adds a sentence that encourages operators to
simultaneously submit variance requests and plans or applications
if those plans or applications are contingent upon the BLM approving the variance requests.
Final paragraph (a)(3) clarifies the process operators must use to
submit their variance requests to the BLM—via WIS, or, if the operator is a small business without access to the Internet, to the
BLM office having jurisdiction over the lease, unit, or CA.
Paragraph (c) did not change substantively, but is split into two paragraphs. Paragraph (c)(1) states that records must be maintained
for at least 7 years, and paragraph (c)(2) codifies the applicable
statutory requirements for further retention beyond 7 years.
Paragraph (d) did not change substantively, but is split into two paragraphs. Paragraph (d)(1) states that records must be maintained
for at least 6 years, and subparagraph (d)(2) codifies the applicable statutory requirements for further retention beyond 6 years.
The final rule moves paragraph (e)(2) of the proposed rule to (e)(1)
and removes the phrase ‘‘or until the Secretary or his designee releases the record holder from the obligation to maintain the
records, whichever is later.’’
The phrase in paragraph (e)(1) of the proposed rule—‘‘but a judicial
proceeding or demand is not commenced within 7 years after the
records are generated, the record holder must retain all records regarding production from the unit or CA until the Secretary or his
designee releases the record holder from the obligation to maintain
the records’’—is moved to its own paragraph (e)(2).
The final rule is revised to require record holders to include the FMP
number or the lease, unit PA, or CA number, along with a unique
equipment identifier (e.g., a unique tank identification number and
meter station number), on all their records.
The language from the proposed rule is moved to a new paragraph
(a) and a new paragraph (b) is added that creates a separate appeal process for decisions made by the BLM, based on a recommendation from the Production Measurement Team (PMT).
Under paragraph (b), a party may file a request for discretionary
review by the Assistant Secretary for Land and Minerals Management (ASLM). Paragraph (b) also provides that the ASLM may delegate this review function.
The final rule adds new definitions for the terms ‘‘commingling and
allocation approval (CAA),’’ ‘‘free water,’’ ‘‘permanent measurement
facility,’’ ‘‘payout period,’’ and ‘‘royalty net present value’’ in response to comments on the proposed rule.
The term ‘‘low volume property’’ is replaced with the term ‘‘economically marginal property,’’ and the definition has also been modified.
Lastly, the definition of the term ‘‘land description’’ is modified to be
consistent with the well and facility identification requirements contained in § 3162.6 of the final rule.
CAA (commingling and allocation approval) is removed from the acronym list because the acronym is introduced in the definition section; BIA (Bureau of Indian Affairs) is added to the list of acronyms.
The requirement in paragraph (a)(5) that flow computers be effectively sealed is removed and instead a new requirement is added
in paragraph (a)(6) that a LACT or CMS must be effectively
sealed.
Paragraph (a)(7) in the final rule clarifies that sealing the back pressure valve refers to the ‘‘pressure adjustment’’ on the valve, not
the valve itself.
The final rule removes the requirements that, when draining water
from a production storage tank, operators, purchasers, or transporters document the FMP number associated with the tank, the
time for when the opening and closing gauges took place, and the
name of the person and company draining the tank.
The final rule also clarifies that the gauging operation may be performed manually or automatically, to accommodate the use of
automatic tank gauging systems. If gauging is performed manually,
the final rule no longer specifies that the color cut method be used
for measurement. It leaves the method for capturing the measurement up to the operator and simply requires the accuracy of the
measurement to be to the nearest 1⁄2 inch.
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule
Final rule
Substantive changes
43 CFR 3173.7(a) Hot oiling,
clean-up, and completion operations.
43 CFR 3173.7(a) Hot oiling,
clean-up, and completion operations.
43 CFR 3173.7(d) Hot oiling,
clean-up, and completion operations.
43 CFR 3173.7(d) Hot oiling,
clean-up, and completion operations.
None ................................................
43 CFR 3173.8(b)(8) Report of
theft or mishandling of production.
43 CFR 3173.9(a) Required recordkeeping for inventory and seal
records.
43 CFR 3173.9(a) Required recordkeeping for inventory and
seal records.
43 CFR 3173.10(b) Form 3160–5,
Sundry Notices and Reports on
Wells.
43 CFR 3173.10(b) Form 3160–
5, Sundry Notices and Reports
on Wells.
43 CFR 3173.11(c)(10)(i)
cility diagram.
43 CFR 3173.11(c)(9)(i)
cility diagram.
Site fa-
Site fa-
Site facility
None ..............................................
43 CFR 3173.11(c)(1)
diagram.
Site facility
43 CFR 3173.11(d)(1)
ity diagram.
Site facil-
43 CFR 3173.11(d)
diagram.
mstockstill on DSK3G9T082PROD with RULES3
43 CFR 3173.11(c)(11)
diagram.
Site facility
43 CFR 3173.11(d)(2)
ity diagram.
Site facil-
43 CFR 3173.11(e)
diagram.
Site facility
43 CFR 3173.11(e)(1)
ity diagram.
Site facil-
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The final rule also clarifies that during the opening gauge operations,
the total observed volume (TOV) and free-water measurements
must be documented, while during closing gauge operations only
the TOV must be measured, since the water will have already
been drained.
The final rule removes the requirements that operators document the
FMP number associated with the tank or group of tanks involved in
a hot oiling, clean-up, or completion operation, the time at which
the opening and closing gauges took place, and the name of the
person and company removing production from the tank.
The final rule also clarifies that the gauging operation may be performed manually or automatically; the accuracy of the measurement taken in either case must be to the nearest 1⁄2 inch.
Paragraph (d) of the final rule clarifies that when reporting production
used during hot oiling, line flushing, or completion operations, the
operator’s report must include ‘‘the period covering the production
in question.’’
In the final rule, a new reporting item is added to the list of information that an operator must include in their incident report: ‘‘Whether
the incident was reported to local law enforcement agencies and
company security.’’ This change was made in response to comments.
The final rule provides greater flexibility in how an operator determines the monthly volumes of production in their tanks. Unlike the
proposed rule, where the operator was required to measure the
TOV at the end of each calendar month, the final rule allows the
operator to either perform the inventory within +/¥ 3 days of the
last day of the calendar month or estimate the end of month inventory based on daily production that takes place between two measured inventories that are not more than 31 days, nor less than 20,
days apart. An equation has also been provided if the operator
elects to estimate the end-of-month inventory instead of performing
the inventory at the end of the calendar month.
Paragraph (b) now clarifies the process operators must use to submit
their Sundry Notices to the BLM Office having jurisdiction over the
lease, unit, or CA—namely via the applicable BLM electronic filing
system, unless the operator is a small business without access to
the Internet.
In paragraph (c)(9)(i), the final rule removes the requirement to identify the equipment manufacturer’s name, rated use, and equipment
serial number for each engine, motor, or major component powered by production from the lease, unit PA, or CA.
Proposed paragraph (c)(11) is eliminated. The final rule does not require the diagram to include a signature block to certify accuracy
and completeness of the information contained within this site facility diagram.
Paragraph (c)(1) is eliminated in its entirety and is replaced with
paragraph (d)(1), which now requires operators to submit site facility diagrams for new facilities within 30 days after the BLM assigns
an FMP to a facility. This is a change from the proposed rule,
which required operators to submit diagrams for new facilities within 30 days after completing construction of the new facilities.
Paragraph (d)(2), which applies to facilities that require FMP numbers and are in service before the effective date of this final rule, is
changed. Under the final rule, if such a facility already has a diagram on file with the BLM that meets the minimum site-facility-diagram requirements of Order 3, the operator is not initially required
to submit a new diagram meeting the requirements of this section.
However, the operator must submit a new site facility diagram for
the facility that complies with this section within 30 days after the
facility is modified, a non-Federal facility located on a Federal
lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
Paragraph (e)(1) of the final rule applies to new facilities in service
after the effective date of the final rule that do not require an FMP
number (e.g., a water disposal facility). This paragraph is revised
to require the operator of such a facility to submit a new site facility
diagram within 30 days after that facility becomes operational.
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81362
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule
Final rule
Substantive changes
43 CFR 3173.11(e)(2)
ity diagram.
None ................................................
43 CFR 3173.11(f)
diagram.
43 CFR 3173.12(d) Applying for a
facility measurement point.
43 CFR 3173.12(d) Applying for
a facility measurement point.
43 CFR 3173.12(e) Applying for a
facility measurement point.
43 CFR 3173.12(e) Applying for
a facility measurement point.
43 CFR 3173.12(e)(1) to (e)(3)
Applying for a facility measurement point.
43 CFR 3173.12(e)(1) to (e)(3)
Applying for a facility measurement point.
None ................................................
43 CFR 3173.12(e)(4) Applying
for a facility measurement point.
43 CFR 3173.12(e)(5) Applying for
a facility measurement point.
43 CFR 3173.12(e)(6) Applying for
a facility measurement point.
43 CFR 3173.12(f)(3) Applying for
a facility measurement point.
mstockstill on DSK3G9T082PROD with RULES3
None ................................................
43 CFR 3173.12(f)(3) Applying
for a facility measurement point.
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A new paragraph (e)(2) is added, which applies to facilities that do
not require an FMP number and are in service before the effective
date of the final rule, is added to the final rule. If such a facility already has a diagram on file with the BLM that meets the minimum
requirements of Order 3, the operator is not initially required to
submit a diagram meeting the requirements of this section. However, the operator must submit a new site facility diagram for the
facility that complies with this section within 30 days after the facility is modified, a non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified, or there is a change in operator.
The BLM added a new paragraph (f), which requires operators to
submit updated site facility diagrams on an ongoing basis within 30
days after that facility is modified, a non-Federal facility located on
a Federal lease or federally approved unit or communitized area is
constructed or modified, or there is a change in operator.
Paragraph (d) of this section applies to measurement facilities that
come into service after the effective date of the final rule. This
paragraph is changed to clarify that only ‘‘permanent’’ measurement facilities require an FMP number, and not temporary measurement equipment used during well-testing operations. New language has also been added that requires the operator to ‘‘apply’’
for FMP approval (as opposed to ‘‘obtaining’’ FMP approval, as in
the proposed rule) before removing any production from that facility. Finally, this paragraph clarifies that an operator must use the
lease, unit PA, or CA number for reporting production to ONRR,
until the BLM assigns an FMP number. After the BLM assigns the
FMP number, the operator must use the FMP number for all reporting to ONRR.
The final rule clarifies that the requirement to apply for an FMP for
facilities in service before the effective date of the final rule applies
only to permanent measurement facilities. The final rule also clarifies that the production levels that serve as the triggers for when
an operator must apply for an FMP for an existing facility are
based on the production level of any one of the leases, unit PAs,
or CAs, whether or not they are part of a CAA.
The deadlines for applying for FMP numbers have been changed
from 9 months, 18 months, and 27 months in the proposed rule to
1 year, 2 years, and 3 years in the final rule for existing producing
leases, unit PAs, and CAs. The deadlines are based on the production levels of any one of the leases, unit PAs, or CAs, which
have also been modified from the proposed rule. Under the final
rule, those facilities that produce:
1. 10,000 Mcf or more for gas or 100 bbl of oil or more—must file
within 1 year of the effective date;
2. 1,500 Mcf or more but less than 10,000 Mcf of gas per month or
10 bbl or more, but less than 100 bbl of oil per month—must file
within 2 years; and
3. Less than 1,500 Mcf of gas per month or less than 10 bbl of oil
per month—must file within 3 years.
A new paragraph (e)(4) is added to the final rule requiring the operator of a stand-alone lease, unit PA, or CA that has not produced
for a year or more before the effective date of the final rule to
apply for an FMP prior to the resumption of production.
Paragraph (e)(6) was paragraph (e)(5) in the proposed rule, but is renumbered because of the addition of a new paragraph (e)(4). The
final rule also clarifies that if the operator applies for an FMP within
the timeframes outlined in paragraphs (e)(1) to (e)(3), then the operator may continue using the lease, unit PA, or CA number for reporting production to ONRR, until the effective date of the BLM-assigned FMP number.
The final rule is revised and no longer requires operators to identify
the names and the manufacturer, model, and serial number of
each measurement component.
Paragraph (f)(3)(i) now requires operators to submit the following information on gas measurement equipment:
• The operator/purchaser/transporter unique station number;
• For primary elements, the meter tube size or serial number; and
• The type of secondary device, whether it is mechanical or electronic.
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule
Final rule
Substantive changes
43 CFR 3173.12(f)(4) Applying for
a facility measurement point.
None ..............................................
None ................................................
43 CFR 3173.12(f)(5) Applying
for a facility measurement point.
43 CFR 3173.12(g) Applying for
a facility measurement point.
43 CFR 3173.12(g) Applying for a
facility measurement point.
None ..............................................
43 CFR 3173.13(c) Requirements
for approved facility measurement
points.
43 CFR 3173.13(a) Requirements for approved facility
measurement points.
43 CFR 3173.13(d)(1) and (d)(2)
Requirements for approved facility measurement points.
43 CFR 3173.13(b)(1) Requirements for approved facility
measurement points.
None ................................................
43 CFR 3173.13(b)(2) Requirements for approved facility
measurement points.
43 CFR 3173.13(d)(3) Requirements for approved facility measurement points.
43 CFR 3173.14(a) Conditions for
commingling and allocation approval (surface and downhole).
mstockstill on DSK3G9T082PROD with RULES3
43 CFR 3173.12(h) Applying for a
facility measurement point.
43 CFR 3173.13(a) and (b) Requirements for approved facility
measurement points.
43 CFR 3173.13(b)(3) Requirements for approved facility
measurement points.
43 CFR 3173.14(a) Conditions
for commingling and allocation
approval
(surface
and
downhole).
3173.14(a)(1)(i) Conditions
for
commingling and allocation approval (surface and downhole).
3173.14(a)(1)(i) Conditions
for
commingling and allocation approval (surface and downhole).
3173.14(a)(1)(ii) Conditions
for
commingling and allocation approval (surface and downhole).
3173.14(a)(1)(ii) Conditions
for
commingling and allocation approval (surface and downhole).
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Paragraph (f)(3)(ii) now requires operators who measure oil tanks by
tank gauge to identify the equipment by either the tank number or
tank serial number (The proposed rule required operators to provide both pieces of information.). The final rule adds a new requirement that operators specify the tank size(s), in barrels or gallons.
Paragraphs (f)(3)(iii) and (f)(3)(iv) of the proposed rule have been
combined into a new paragraph (f)(3)(iii). This paragraph now requires operators who measure oil using LACT systems or CMSs to
identify the associated oil tank number(s) or tank serial number(s),
the size of the tank(s) in barrels or gallons, and whether the equipment used is a LACT system or CMS.
The final rule removes the requirement in paragraph (f)(4) to identify
the gas sampling method for gas measurements. Paragraph (f)(5)
in the proposed rule is now renumbered to paragraph (f)(4) in the
final rule and is unchanged.
New paragraph (f)(5) adds to the list of information that operators
must include in their FMP request.
Language is added to clarify that FMP requests—if they are submitted concurrently with requests for off-lease measurement or
commingling and allocation approvals—must be submitted separately from the other requests.
Paragraph (h) is eliminated from the final rule because it was determined to be redundant.
The final rule removes the requirement for operators to stamp or
stencil the FMP number on a fixed plate onto various pieces of oil
and gas measurement equipment and to maintain the number in a
legible condition.
The final rule removes the requirement for operators to begin using
the FMP number for recordkeeping on the first day of the month
after the FMP number is assigned.
A new provision is incorporated into paragraph (a) in the final rule
that requires operators of existing facilities to begin using their
FMP numbers for reporting production to the Office of Natural Resources Revenue (ONRR) on their Oil and Gas Operations Report
(OGOR) for the fourth production month after the BLM assigns the
FMP numbers. Operators of new facilities in service after this rule’s
effective date must start using their FMP numbers for production
reporting on their OGORs for the first production month after the
BLM assigns the FMP numbers.
Paragraph (b)(1) in the final rule requires operators to notify the BLM
via a Sundry Notice within 30 days after changing or modifying an
FMP (the proposed rule gave operators 20 business days). This
paragraph also describes the types of changes that require the operator to submit a Sundry Notice, e.g., changes in the metering
equipment or the wells served by the FMP. Paragraph (b)(1) also
clarifies that temporary modifications, such as those made for
maintenance purposes, do not require the filing of a Sundry Notice.
The final rule removes the requirement in proposed paragraph
(d)(2) that operators provide information about the old and new
meter manufacturer, serial number(s), and the owner’s name.
The final rule adds a new requirement that the operator’s description
of any modifications being made include details, such as the primary element, secondary element, LACT/CMS meter, tank number(s), and wells or facilities using the FMP.
Final paragraph (b)(3) removes the requirement that operators specify why a change was made to a piece of equipment.
Final paragraph (a) is modified so that it explicitly states that the criteria the BLM uses to approve a commingling application under
this paragraph is when the proposed allocation method used for
commingled measurement does not have the potential to affect the
BLM’s determination of the total volume or quality of the production
on which royalty is owed for all of the Federal or Indian leases,
unit PAs, or CAs which are proposed for commingling.
Paragraph (a)(1)(i) clarifies that commingling is permissible when it
involves properties that contain 100 percent Federal mineral interests, the same fixed royalty rate, and the same revenue distribution.
Paragraph (a)(1)(ii) clarifies that commingling is permissible when it
involves properties that are wholly owned by the same tribe and
have the same fixed royalty rate.
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81364
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Final rule
Substantive changes
None ................................................
3173.14(a)(1)(iii) Conditions for
commingling and allocation approval (surface and downhole).
None ................................................
3173.14(a)(1)(iv) Conditions for
commingling and allocation approval (surface and downhole).
3173.14(a)(2) Conditions for commingling and allocation approval
(surface and downhole).
3173.14(a)(2) Conditions
for
commingling and allocation approval (surface and downhole).
None ................................................
3173.14(b) Conditions for commingling and allocation approval
(surface and downhole).
3173.14(b)(1) Conditions for commingling and allocation approval
(surface and downhole).
3173.14(b)(1) Conditions
for
commingling and allocation approval (surface and downhole).
3173.14(b)(2) Conditions for commingling and allocation approval
(surface and downhole).
3173.14(b)(2) Conditions
for
commingling and allocation approval (surface and downhole).
3173.14(b)(3) Conditions for commingling and allocation approval
(surface and downhole).
3173.14(b)(3) Conditions
for
commingling and allocation approval (surface and downhole).
None ................................................
3173.14(b)(4) Conditions
for
commingling and allocation approval (surface and downhole).
43 CFR 3173.15(a)(1) and (a)(2)
Applying for a commingling and
allocation approval.
43 CFR 3173.15(a) Applying for
a commingling and allocation
approval.
3173.15(a)(2) Applying for a commingling and allocation approval.
mstockstill on DSK3G9T082PROD with RULES3
Proposed rule
43 CFR 3173.15(b) .......................
43 CFR 3173.15(b) Applying for a
commingling and allocation approval.
43 CFR 3173.15(c) Applying for
a commingling and allocation
approval.
None ................................................
43 CFR 3173.15(d) .......................
A new paragraph (a)(1)(iii) is added which clarifies that commingling
of Federal unit PAs or CAs is permissible even if Federal ownership is not 100 percent, so long as the properties have the same
proportion of Federal ownership, royalty rate and revenue distribution.
A new paragraph (a)(1)(iv) is added which clarifies that commingling
of tribal unit PAs or CAs is permissible even if tribal ownership is
not 100 percent, so long as the properties have the same proportion of tribal interest and fixed royalty rate.
This paragraph recognizes there are cases where multiple operators
are party to a CAA and clarifies that there must be a signed agreement amongst the operators about the allocation methodology for
the commingling proposal.
To complement paragraphs (a)(1)(iii) and (a)(1)(iv) to this section,
paragraph (b) clarifies that the BLM may consider commingling
that involves production from properties with different royalty rates
or revenue distributions, or multiple mineral ownerships.
This paragraph is revised to reflect the BLM’s switch from the term
‘‘low-volume property’’ to ‘‘economically marginal property.’’ It also
clarifies that if the BLM determines that a Federal or Indian lease,
unit PA, or CA included in a CAA ceases to be an economically
marginal property, then (b)(1) is no longer met.
In the proposed rule, paragraph (b)(2) allowed operators to be exempted from the BLM’s commingling standards if there are overriding considerations that indicated approval of the CAA was appropriate in spite of royalty impacts. In the final rule, this provision
is replaced with a new exemption if the average monthly production rate over the previous 12 months for each Federal or Indian
lease, unit PA, and CA included in the CAA is less than 1,000 Mcf
of gas per month or 100 bbl of oil per month.
Paragraph (b)(2) from the proposed rule is now renumbered as paragraph (b)(5).
New paragraph (b)(3) of the final rule adds a new exemption that allows the BLM to consider approval of a commingling proposal that
includes Indian leases, unit PAs, or CAs that has been authorized
under tribal law or otherwise approved by a tribe.
In the proposed rule, paragraph (b)(3) required the BLM to ensure
that approval of a CAA in cases where the CAA would be exempted from the standards in this rule was in the public interest. This
paragraph is eliminated and incorporated into the new paragraph
(b)(5).
A new exemption is included as part of the final rule that allows the
BLM to consider a commingling proposal if it covers the downhole
commingling of production from multiple formations where the BLM
has determined that the proposed commingling is an acceptable
practice for the purpose of achieving maximum ultimate economic
recovery and resource conservation.
Paragraph (a) of the final rule eliminates the numbering for paragraph (a)(1) in the proposed rule, and clarifies that if off-lease
measurement is a feature of the commingling proposal, then a
separate Sundry Notice requesting approval for off-lease measurement is not necessary as long as the off-lease measurement request is included as part of the commingling application and the information required in § 3173.23(b) through (e) and, where applicable, § 3173.23(f) through (i) is included in the commingling application.
Paragraph (a)(2) from the proposed rule is renumbered to a new
paragraph (b) and clarifies that submission of a completed Sundry
Notice for approval of off-lease measurement is required if any of
the proposed FMPs are outside the boundaries of any lease, unit
PA, or CA whose production would be commingled. This paragraph clarifies that this requirement does not apply if the circumstances under paragraph (a) of this section are applicable.
In addition to requiring operators to provide their proposed allocation
agreement, final paragraph (c) is revised to require operators to
provide an allocation methodology, along with an example of how
the methodology is to be applied.
Requires the operator to include a list of all Federal or Indian lease,
unit PA, or CA numbers in the proposed CAA, specifying the type
of production (i.e., oil, gas, or both) for which commingling is requested.
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
81365
Final rule
Substantive changes
43 CFR 3173.15(d) Applying for a
commingling and allocation approval.
43 CFR 3173.15(e) Applying for
a commingling and allocation
approval.
43 CFR 3173.15(e) Applying for a
commingling and allocation approval.
None ..............................................
43 CFR 3173.15(f)
commingling and
proval.
43 CFR 3173.15(g)
commingling and
proval.
Applying for a
allocation ap-
None ..............................................
Applying for a
allocation ap-
43 CFR 3173.15(f) Applying for a
commingling and allocation approval.
43 CFR 3173.15(h) Applying for a
commingling and allocation approval.
43 CFR 3173.15(g) Applying for
a commingling and allocation
approval.
43 CFR 3173.15(i) Applying for a
commingling and allocation approval.
None ................................................
43 CFR 3173.15(h) Applying for
a commingling and allocation
approval.
43 CFR 3173.15(i) Applying for a
commingling and allocation approval.
Final paragraph (e) continues to require operators to provide maps
with their commingling and allocation requests, but the information
requirements for the maps are changed. Please note that in the
final rule, paragraphs (d)(2) and (d)(3) have been consolidated and
renumbered as paragraphs (e)(1) and (e)(2) in the final rule. The
final rule also reduces the amount of information that must be submitted with a commingling application relative to the proposed
rule.8
Proposed paragraph (e), which required submission a site facility diagram showing any changes to existing diagrams if changes were
being proposed to an existing facility, is eliminated from the final
rule.
Proposed paragraph (f), which required submission of a schematic or
engineering drawing for all new proposed facilities, is eliminated
from the final rule.
Paragraph (f) of the final rule (paragraph (g) of the proposed rule) is
revised to clarify that operators must submit a surface use plan of
operations if new surface disturbance is proposed for the FMP and
its associated facilities, if those facilities are located on BLM-managed land within the boundaries of the lease, units, or
communitized areas whose production will be commingled.
Final paragraph (g) clarifies that the operator must submit a right-ofway grant application (Standard Form 299) if the proposed FMP is
on a pipeline or is a meter or storage tank that entails new surface
disturbance located on BLM-managed land outside any of the
leases, units, or communitized areas whose production would be
commingled.
Final paragraph (h) is essentially the same as proposed paragraph (i)
but is renumbered.
None ................................................
43 CFR 3173.15(j) .........................
43 CFR 3173.15(k) Applying for a
commingling and allocation approval.
43 CFR 3173.16(a) Existing commingling and allocation approvals.
43 CFR 3173.15(k) Applying for
a commingling and allocation
approval.
43
CFR
3173.16(a) Existing
commingling and allocation approvals.
43 CFR 3173.16(b) Existing commingling and allocation approvals.
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Proposed rule
43
CFR
3173.16(b) Existing
commingling and allocation approvals.
43 CFR 3173.16(c) Existing commingling and allocation approvals.
43 CFR 3173.16(b)(2) Existing
commingling and allocation approvals.
43 CFR 3173.16(e) Existing commingling and allocation approvals.
43
CFR
3173.16(c) Existing
commingling and allocation approvals.
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A new final paragraph (i) has been added to clarify that the operator
must submit a right-of-way grant application to the appropriate BIA
office if any of the proposed surface facilities are on Indian land
outside the lease, unit, or communitized area from which the production would be commingled.
Requires the operator to include documentation demonstrating that
each of the leases, unit PAs, or CAs proposed for inclusion in the
CAA is producing or capable of production in paying quantities.
Final paragraph (k) clarifies that gas analysis and oil gravity data is
not needed if the CAA falls under § 3173.14(a).
This section is extensively rewritten from the proposed rule based on
comments received. Final paragraph (a) includes new provisions
that grandfather the following types of existing commingling operations and their associated off-lease measurement approvals,
where applicable, that are in effect prior to the effective date of the
final rule:
• Existing CAAs involving downhole commingling that includes Federal or Indian leases, unit PAs, or CAs; or
• Existing CAAs for surface commingling whose average production
rate over the previous 12 months for each Federal or Indian lease,
unit PA, and CA included in the CAA is less than 1,000 Mcf of gas
per month or 100 bbl of oil per month.
A new provision has been added to paragraph (b), which clarifies
that if the grandfathering conditions in paragraph (a) of this section
are not met, then the existing CAA must meet the minimum standards and requirements for a CAA under § 3173.14 of the final rule.
This section also clarifies that the AO will notify the operator in writing of any inconsistencies or deficiencies with an existing CAA.
When the AO is satisfied that the operator has corrected any inconsistencies or deficiencies, the AO will terminate the existing
CAA and grant a new CAA based on the operator’s corrections.
Paragraph (b)(2) of the final rule clarifies that the AO may terminate
an existing CAA and grant a new CAA with new or amended
COAs to make the approval consistent with the requirements for
CAAs under § 3173.14 of the final rule. Under the proposed rule
the AO could simply impose new or amended COAs to an existing
commingling approval.
Proposed paragraph (e) is now paragraph (c) and clarifies that any
new allocation percentages resulting from the new CAA will only
apply from the effective date of the CAA forward.
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81366
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Final rule
Substantive changes
43 CFR 3173.18(a) Modification of
a commingling and allocation approval.
43 CFR 3173.18(a) Modification
of a commingling and allocation
approval.
43 CFR 3173.18(b) Modification of
a commingling and allocation approval.
43 CFR 3173.18(b) Modification
of a commingling and allocation
approval.
None ................................................
43 CFR 3173.18(c) Modification
of a commingling and allocation
approval.
43 CFR 3173.20(c) Terminating
a commingling and allocation
approval.
Paragraph (a) is changed to require operators to modify a CAA
under certain circumstances. The final rule no longer includes ‘‘a
change in operator’’ in the list of circumstances that warrant a CAA
modification.
Final paragraph (b)(2) includes a new requirement to describe not
only a new allocation methodology for oil and gas production, if appropriate, but also an allocation methodology for produced water
and an example of how the methodology is applied.
A new paragraph (c) is added that states that a change in operator
does not trigger the need to modify a CAA.
43 CFR 3173.20(a) Terminating a
commingling and allocation approval.
43 CFR 3173.20(d) Terminating a
commingling and allocation approval.
43 CFR 3173.20(d) Terminating
a commingling and allocation
approval.
43 CFR 3173.20(e) Terminating a
commingling and allocation approval.
43 CFR 3173.20(e) Terminating
a commingling and allocation
approval.
43 CFR 3173.21(b) Combining
production downhole in certain
circumstances.
43 CFR 3173.21(b) Combining
production downhole in certain
circumstances.
43 CFR 3173.22(c) Requirements
for off-lease measurement.
43 CFR 3173.22(c) Requirements for off-lease measurement.
43 CFR 3173.23(a) Applying for
off-lease Measurement.
43 CFR 3173.23(a) Applying for
off-lease Measurement.
43 CFR 3173.23(c)(2) Applying for
off-lease Measurement.
43 CFR 3173.23(c)(2) Applying
for off-lease Measurement.
43 CFR 3173.23(d) Applying for
off-lease Measurement.
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Proposed rule
None ..............................................
43 CFR 3173.23(e) Applying for
off-lease Measurement.
None ..............................................
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The final rule redesignates and modifies proposed paragraph (a),
which allows any operator who is a party to a CAA to unilaterally
terminate the CAA.
New paragraph (c) in the final rule clarifies that it allows an operator
to terminate the CAA through the submission of a Sundry Notice to
the BLM. It also clarifies that the termination by one operator does
not terminate the CAA for all other operators, so long as the requirements of this part with respect to CAAs are still met as to the
remaining operators and they submit a Sundry Notice requesting a
new CAA as required by § 3173.20(e).
Paragraph (d) of the final rule clarifies that the BLM will notify all parties to a CAA the effective date of the termination and the inconsistencies or deficiencies with their CAA that serve as the reason(s) for termination.
The final rule also gives operators the opportunity to correct the inconsistencies or deficiencies, or provide additional information,
within 20 business days after receipt of the BLM’s notice. Otherwise, the CAA will be terminated.
Paragraph (e) of the final rule clarifies that if a CAA is terminated,
each lease, unit PA, or CA that was included in the CAA may require a new FMP number, or a new CAA may need to be applied
for. In such cases, operators will have 30 days to apply for a new
FMP number or CAA. Unlike the proposed rule—where operators
would have been required to revert back to separate measurement
for each lease, unit PA, or CA—the final rule allows the operator to
use the existing FMP number for production reporting until a new
FMP number is assigned or a new CAA is approved.
Paragraph (b) makes clear that combining production downhole from
different geologic formations on the same lease in a single well is
not considered to be commingling for production accounting purposes. This applies even in cases where the respective geologic
formations have different ownership. The proposed rule made this
distinction, which no longer applies in the final rule.
The final rule also clarifies that such activities are not subject to the
commingling standards and requirements contained in §§ 3173.14
through 3173.20.
Changes to this paragraph clarify that topographic and environmental
issues that make on-lease measurement physically impractical are
factors to be considered when deciding if off-lease measurement is
in the public interest.
The second sentence of proposed paragraph (a) is removed because
§ 3173.15(a) states that if off-lease measurement is a feature of
the CAA proposal, then a separate Sundry Notice is not necessary
as long as the information required under § 3173.23(b) through (e)
and, where applicable, § 3173.23(f) through (i), is included as part
of the request for approval of a CAA.
The final rule in this paragraph no longer requires location identification by land description, but does include a new requirement to
identify existing or proposed (to the extent known) FMPs.
Paragraph (d) of the proposed rule requiring operators to submit a
schematic or engineering drawing for all new proposed facilities is
deleted.
Paragraph (e) of the proposed rule, which required operators to submit as part of their off-lease measurement application, site facility
diagrams clearly showing any proposed change to current site facility diagrams for existing facilities is deleted.
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
81367
Proposed rule
Final rule
Substantive changes
43 CFR 3173.23(f) Applying for
off-lease Measurement.
43 CFR 3173.23(e) Applying for
off-lease Measurement.
43 CFR 3173.23(g) Applying for
off-lease Measurement.
43 CFR 3173.23(f) Applying for
off-lease Measurement.
43 CFR 3173.23(h) Applying for
off-lease Measurement.
43 CFR 3173.23(g) Applying for
off-lease Measurement.
None ................................................
43 CFR 3173.23(h) Applying for
off-lease Measurement.
3173.25(b) Existing approved offlease measurement.
3173.25(b) Existing approved offlease measurement.
3173.25(c) Existing approved offlease measurement.
3173.25(c) Existing approved offlease measurement.
None ................................................
43 CFR 3173.25(e) Existing approved off-lease measurement.
43 CFR 3173.25(e) Existing approved off-lease measurement.
43 CFR 3173.27(a) Termination of
off-lease measurement approval.
43 CFR 3173.25(f) Existing approved off-lease measurement.
43 CFR 3173.27(c) Termination
of off-lease measurement approval.
43 CFR 3173.27(a) Termination
of off-lease measurement approval.
43 CFR 3173.27(b) Termination
of off-lease measurement approval.
In the event there is a change in the ownership of the non-Federal
surface or of the measurement facilities, the final rule includes a
new 30-day deadline for when an operator must submit written
concurrence from the new owner that it will give the BLM unrestricted access to the off-lease measurement facility and the surface on which it is located to inspect the FMP and any associated
equipment.
Final paragraph (f) clarifies that if the proposed off-lease FMP is on a
pipeline or is a meter or storage tank, then a right-of-way grant application using Standard Form 299 must be submitted.
This paragraph also clarifies that this requirement applies only when
new surface disturbance is proposed for the FMP and its associated facilities are located on BLM-managed land.
Final paragraph (g) (re-lettered from paragraph (h)) clarifies that if
any of the proposed surface facilities are on Indian land outside
the lease, unit, or communitized area, then a right-of-way grant application filed under 25 CFR part 169 must be filed with the appropriate BIA office.
The final rule adds a new paragraph (h) that requires written approval from the appropriate surface-management agency if new
surface disturbance is proposed for the FMP and its associated facilities are located on Federal land managed by an agency other
than the BLM.
Paragraph (b) of the final rule has been revised to provide an opportunity for operators to request additional time to correct any inconsistencies or deficiencies that the AO identifies. This paragraph
also clarifies that the extension request must explain the factors
preventing the operator from timely compliance.
Paragraph (c) of the final rule clarifies that if new or amended conditions of approval (COAs) are necessary to make an existing offlease measurement approval consistent with the final rule’s standards, then the BLM could address that situation by terminating the
existing approval and issuing a new off-lease measurement approval with new or amended COAs.
A new paragraph (e) is added to the final rule, clarifying that if the
existing off-lease measurement approval under this section is consistent with the requirements under § 3173.22, then that existing
off-lease measurement is grandfathered and will be part of its FMP
approval.
Proposed paragraph (e) is re-lettered to paragraph (f).
43 CFR 3173.27(b) Termination of
off-lease measurement approval.
43 CFR 3173.27(c) Termination of
off-lease measurement approval.
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43 CFR 3173.27(d) Termination of
off-lease measurement approval.
43 CFR 3173.27(d) Termination
of off-lease measurement approval.
43 CFR 3173.29
sessments.
43 CFR 3173.29
sessments.
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Proposed paragraph (a) is deleted from the final rule and the provision in that paragraph allowing an operator to terminate off-lease
measurement is moved to paragraph (c).
Paragraphs re-lettered. No change.
Final paragraph (b) is changed to say the BLM will notify the operator in writing of any inconsistencies or deficiencies with its offlease measurement approval that serve as the reason(s) for termination.
The final rule is also changed to give the operator 20 business days
after receipt of the notification to correct the inconsistencies or deficiencies that the BLM identifies, or provide additional information
that the AO requests, or the off lease measurement approval terminates. The operator may request an extension of the 20-business-day timeframe.
Final paragraph (d) explains that if an off lease measurement approval is terminated, each lease, unit PA, or CA that was in the approval may require a new FMP number(s) or a new off lease
measurement approval. Operators will have 30 days to apply for a
new FMP number or off lease measurement approval. The final
rule allows operators to use the existing FMP number for production reporting until a new FMP number is assigned or a new off
lease measurement approval is approved.
The final rule exempts purchasers and transporters from the immediate assessments that will be imposed for certain instances of
non-compliance. In addition, the final rule modifies the description
of violations number 7 through 11.
• For violation number 7, the final rule clarifies that the applicable
regulation is § 3170.7, not § 3173.9(a)(1) and (a)(2).
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81368
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Proposed rule
Final rule
Substantive changes
• For violation 8, the final rule clarifies that an immediate assessment could result if operators fail to ‘‘apply for’’ the required FMP
approval. The proposed rule required operators to ‘‘obtain’’ FMP
approval.
• For violations 9, 10, and 11, the final rule clarifies that an immediate assessment could result if production is removed from a facility in operation after the effective of the final rule prior to receiving
BLM approval for off-lease measurement or commingling. For an
existing facility in service on or before the effective date of the final
rule, an immediate assessment could result if production is removed from a facility that does not already have an existing BLM
approval for off-lease measurement or commingling, if applicable.
Subpart 3170 and Related Provisions
B. Section-by-Section Analysis and
Response to Comments on Specific
Provisions
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This final rule is codified primarily in
a new 43 CFR subpart 3173 within a
new part 3170. The BLM is also issuing
final rules that update and replace
Order 4 (oil measurement) and Order 5
(gas measurement). Those final rules are
codified at new 43 CFR subparts 3174
and 3175, respectively, within the new
part 3170. Subpart 3170 of this final rule
contains definitions of certain terms and
provisions that are common to all three
rules (and to any other provisions
within part 3170), i.e., provisions
prohibiting by-pass of or tampering with
meters; procedures for obtaining
variances from the requirements of a
particular rule; requirements for
recordkeeping, records retention, and
submission; and administrative appeal
procedures.
In addition, this final rule makes
changes to various provisions in 43
CFR part 3160 and in 43 CFR 3161.1,
3162.3–2, 3162.4–1, 3162.6, 3162.7–1,
3163.2, and 3165.3. Public comments on
changes to the provisions in part 3160
are discussed in connection with the
new subparts 3170 or 3173 provisions to
which the particular comment relates.
Other comments on changes to
provisions in part 3160 are discussed at
the end of this Section-by-Section
analysis.
8 Specifically, the final rule no longer requires the
commingling application to include the following
items: (i) The land description of the FMP that will
be used to measure the commingled production; (ii)
Production facilities and flow lines proposed to be
installed to the extent known; and (iii) A map or
diagram showing all of the infrastructure-related
facilities that are part of the commingling proposal.
The final rule only requires identification of
existing or planned facilities, all wellheads, and
piping that will be included in the CAA, as well
as existing or proposed FMPs to be installed (if
known).
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Section 3170.1 Authority
Section 3170.1 of the final rule
identifies the various grants of
rulemaking authority in the Federal and
Indian mineral leasing statutes and
related statutes that give the Secretary
authority to promulgate this rule. As
explained in that section, the
Department is authorized to lease
Federal and Indian (except Osage Tribe)
oil and gas under various mineral
leasing statutes, including the Mineral
Leasing Act, 30 U.S.C. 181 et seq.; the
Mineral Leasing Act for Acquired
Lands, 30 U.S.C. 351 et seq.; the Federal
Oil and Gas Royalty Management Act
(FOGRMA), 30 U.S.C. 1701 et seq.; the
Indian Mineral Leasing Act, 25 U.S.C.
396a et seq.; the Act of March 3, 1909,
25 U.S.C. 396; the Indian Mineral
Development Act, 25 U.S.C. 2101 et
seq.; and the Federal Land Policy and
Management Act (FLPMA), 43 U.S.C.
1701 et seq.
Each of these statutes expressly
authorizes the Secretary of the Interior
to promulgate necessary and
appropriate rules and regulations
governing those leases. See e.g., 30
U.S.C. 189; 30 U.S.C. 359; 30 U.S.C.
1751; 25 U.S.C. 396d; 25 U.S.C. 396; 25
U.S.C. 2107; and 43 U.S.C 1740. The
Secretary has delegated this authority to
the Bureau of Land Management (BLM).
Specifically, under Secretarial Order
Number 3087, dated December 3, 1982,
as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual
(235 DM 1.1), the Secretary has
delegated regulatory authority over
onshore oil and gas development on
Federal and Indian (except Osage Tribe)
lands to the BLM. For Indian leases, the
delegation of authority to the BLM is
reflected in 25 CFR parts 211, 212, 213,
225, and 227. In addition, as authorized
by 43 U.S.C. 1731(a), the Secretary has
delegated to the BLM regulatory
responsibility for oil and gas operations
in Indian lands. 235 DM 1.1.K.
These statutes and regulations form
the basis of and provide the authority
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for the issuance of this final rule. For
example, § 101(a) of FOGRMA directs
the Secretary to ‘‘establish a
comprehensive inspection, collection
and fiscal and production accounting
and auditing system to provide the
capability to accurately determine oil
and gas royalties, interest, fines,
penalties, fees, deposits, and other
payments owed, and to collect and
account for such amounts in a timely
manner.’’ Ensuring that oil and gas
produced from Federal and Indian
leases is accurately measured and
properly accounted for is a critical
component of any system to ensure that
all royalties due are paid. Under § 101(a)
of FOGRMA, the Secretary is authorized
to promulgate ‘‘such rules and
regulations as [s]he deems reasonably
necessary to carry out.’’ the purposes of
the act. The FOGRMA mandate
complements the policy articulated in
FLPMA that the United States receive
fair compensation for the use of public
lands and resources. See 43 U.S.C.
1701(a)(9). This rule, by improving BLM
requirements governing site security
and related measures, helps ensure that
all royalties due are paid, and thus that
the United States receives fair
compensation for the use of public
minerals.
The BLM did not receive any public
comments related to this provision and
only made minor changes for clarity
between the proposed and final
versions.
Section 3170.2
Scope
Section 3170.2(a) explains that the
regulations in part 3170 apply to all
onshore Federal and Indian (except
Osage Tribe) oil and gas leases.
Paragraph (b) explains that part 3170
also applies to agreements for oil and
gas development under the Indian
Mineral Development Act, unless the
relevant provisions of the rule are
inconsistent with the specific terms of
such agreement. Paragraph (c) explains
that a Tribal Energy Resource
Agreement entered into with the
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Secretary is subject to part 3170, unless
specifically excluded in such lease,
other business agreement or Tribal
Energy Resource Agreement. Paragraph
(d) explains that State or private tracts
committed to a federally approved unit
or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180 are also subject to the
requirements of part 3170. Finally,
paragraph (e) states that all FMPs
measuring production from any of the
aforementioned leases or agreements are
subject to the requirements of part 3170.
The BLM received several comments
expressing concern with proposed
paragraph (d), which applies the part
3170 regulations to State or private
tracts committed to a federally approved
unit or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180. The same language also
appeared in a new paragraph (e) that
was proposed to be added to § 3161.1
Jurisdiction. Comments received on
both sections are discussed here.
Many commenters thought that the
new paragraph (e) language proposed
for § 3161.1 would extend the BLM’s
jurisdiction over oil and gas to activities
that are not covered by this rule.
Specifically, commenters were
concerned that adding the proposed
language to § 3161.1 and also to
proposed § 3170.2 would expand the
BLM’s authority over the processing and
approval of Applications for Permits to
Drill (APDs) within State and private
tracts committed to a BLM-approved
Federal or Indian unit or CA.
Commenters said that such an
expansion of authority would force
operators to obtain Federal drilling
permits for drilling on State and private
tracts. From the commenters’
perspective, this perceived expansion in
jurisdiction would fundamentally alter
the way in which operators plan for
development.
The BLM disagrees with this
interpretation of the new language and
never intended for this rule to extend
the BLM’s permitting authority over
State and private drilling approvals.
However, to avoid confusion, the BLM
in this final rule added a new paragraph
(b) to its § 3161.1 revisions, which
clarifies that it is the regulations in parts
3160 and 3170 relating to site security,
measurement, reporting of production
and operations, and assessments or
penalties for non-compliance with such
requirements (i.e., those found in
subparts 3173, 3174, and 3175) that are
applicable to all wells and facilities on
State or privately owned lands
committed to a unit or CA where the
unit or CA affects Federal or Indian
interests. Proposed § 3170.2(d) has not
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Jkt 241001
been changed because it is appropriate
for this rule to state that the regulations
under part 3170, which includes
subparts 3173, 3174, and 3175, do in
fact apply to State or private tracts
committed to a federally approved unit
or CA as defined by or established
under 43 CFR subpart 3105 or 43 CFR
part 3180. This is consistent with the
BLM’s past application of its
regulations, including its Onshore
Orders, under existing 43 CFR
3161.1(b).
Section 3170.3 Definitions and
Acronyms
This section defines terms and
acronyms used across all of the various
subparts of part 3170.
The BLM did not receive any
comments on the majority of the
definitions that appeared in the
proposed rule and that are now in the
final rule. Those definitions for which
we received no comments were carried
forward in this final rule and are not
discussed further here. As explained in
the proposed rule, a number of the
definitions in § 3170.3 of the proposed
rule were the same definitions that were
found in Order 3, with only minor
revisions to either simplify or clarify
those definitions.
The following discussion first
describes the new definitions that have
been added to § 3170.3 in the final rule,
and then summarizes and responds to
comments that the BLM received on a
handful of the proposed definitions.
With respect to the former, based on
comments received and its own internal
reviews, the BLM added three new
definitions to § 3170.3: ‘‘Averaging
period,’’ ‘‘bias,’’ and ‘‘tampering.’’ As
explained below some of these
definitions were originally proposed as
part of the proposed rules to replace
Order 4 (80 FR 58952) and Order 5 (80
CFR 61646). The BLM determined that
it was appropriate to move those
definitions from those rulemakings to
§ 3170.3, because the terms are used in
multiple subparts, and should therefore
be defined once in a section that covers
the entirety of part 3170. Other
definitions were added in response to
public comments.
The final rule defines ‘‘averaging
period’’ to mean the previous 12 months
or the life of the meter, whichever is
shorter. For FMPs that measure
production from a newly drilled well,
the averaging period excludes
production from that well that occurred
in or before the first full month after
production began. For example, if an oil
FMP or a gas FMP were installed to
measure the production from a new well
that first produced on April 10, the
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81369
averaging period for this FMP would not
include the production that occurred in
April and May of that year. The BLM
added this definition to § 3170.3
because the term is used multiple times
in subparts 3174 (oil measurement) and
3175 (gas measurement), relating to the
applicability of uncertainty threshold
requirements. The BLM determined it
was important to provide a single
definition of the averaging period in
order to provide for consistent
application of the BLM’s oil and gas
measurement rules.
The final rule adds a definition for the
term ‘‘bias’’ to § 3170.3 because that
term is used in both subparts 3174 and
3175. ‘‘Bias’’ is defined to mean a ‘‘shift
in the mean value of a set of
measurements away from the true value
of what is being measured.’’ This
definition was originally proposed as
part of the rule to replace Order 5 in
§ 3175.10. The definition added to part
3170.3 is identical to the definition in
proposed § 3175.10, because the BLM
did not receive any comments on that
definition in the context of the Order 5
rulemaking.
In response to recommendations from
many commenters, the BLM added a
definition of the term ‘‘tampering’’ to
§ 3170.3. The proposed and final rules
prohibit operators from tampering with
measurement equipment, components,
or processes and appropriate valves.
While the meaning of tampering is
commonly understood, the BLM agrees
with commenters that the term should
be defined to ensure there is a common
understanding of what is meant by
tampering for purposes of this rule.
Section 3170.3 defines tampering to
include ‘‘any deliberate adjustment or
alteration to a meter or measurement
device, appropriate valve, or
measurement process that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported.’’ The BLM modified
the definition of ‘‘commingling’’ in the
final rule to clarify that combining
production from multiple wells within
a single lease, unit PA, or CA, or the
downhole combining of production
from different zones or formations that
are part of the same lease, unit PA, or
CA, is not considered ‘‘commingling’’
for the purpose of the final rule. Many
commenters expressed concern that the
definition for commingling in the
proposed rule would have required an
operator to obtain approval to combine
production from multiple properties
within a CA or unit PA prior to
measurement, particularly when the CA
or unit PA contains leases with multiple
owners (i.e., Federal, Indian, State, or
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private). Commenters said the proposed
definition negates one of the primary
benefits of establishing a CA or unit PA,
which is the operation of the CA or unit
PA as one entity and the sharing of
revenues from that CA or unit PA on a
fixed allocation schedule, typically
based on ownership percentage within
the CA or unit PA.
The conclusions reached by these
commenters were incorrect. Neither the
proposed rule nor the final rule defined
‘‘commingling’’ to include the
combining of production from multiple
properties within a CA or unit PA prior
to measurement. However, in response
to these comments, the BLM revised the
definition of commingling to help
clarify the situations that are and are not
considered commingling, and to
emphasize that the combining of
production from multiple properties
within a CA or unit PA prior to royalty
measurement is not commingling.
One commenter said the proposed
commingling definition could deter
operators from drilling horizontal wells
through several sections that contain
different mineral estates and reduce the
production and utilization of the State’s
oil and gas resources. The BLM agrees
with this comment with respect to the
limited situations in which there is no
unit agreement or CA in place for those
sections. Downhole commingling when
there is multiple ownership and no unit
or CA in place would adversely affect
the uncertainty, bias, and verifiability of
the measurement of the volumes
produced from each property, and the
BLM would deny such a request unless
it qualified under § 3173.14(b) of the
final rule. If there was a unit or CA in
place, however, the BLM would not
consider the combining of production
between several sections within the unit
or CA to be commingling and no
approval would be required. The BLM
did not make any changes to the rule
based on this comment.
The definition of an FMP in this final
rule is carried forward from the
proposed rule, which defined an FMP to
be a ‘‘BLM-approved point where oil or
gas produced from a Federal or Indian
lease, unit PA, or CA is measured and
the measurement affects the calculation
of the volume or quality of production
on which royalty is owed.’’ As
explained in more detail below in the
discussion of comments for § 3173.12,
the final rule sets forth a process for an
operator of a new or existing facility to
apply for approval of an FMP and
issuance of an FMP number in proposed
§ 3173.12. Because § 3173.12 of the final
rule requires operators of existing
facilities to apply for an FMP in stages
over a 36-month period, it will require
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3 years from the effective date of the
final rule for the BLM to receive,
evaluate, and act on an FMP application
for existing facilities. Therefore, for
purposes of compliance with other
provisions of this final rule, during this
interim period, the definition of an FMP
makes clear, as in the proposed rule,
that an FMP ‘‘also includes a meter or
measurement facility used in the
determination of the volume or quality
of royalty-bearing oil or gas produced
before BLM approval of an FMP under
§ 3173.12 of this part.’’
The BLM received many comments
on the proposed definition of an FMP.
A couple of commenters pointed out
that there are differences between the
BLM’s proposed definition and the
ONRR’s definition at 30 CFR 1206.171.
Commenters said these differences
could cause confusion for industry, the
BLM, and ONRR, and recommended
that a single definition be established
for both agencies. These commenters
did not provide specific details or any
examples of the confusion that could
arise as a result of these definitional
differences. The BLM compared both
definitions and agrees that there are
differences, but disagrees with
commenters that these differences will
cause confusion. The intent of both
definitions is the same. Both agencies
want to ensure that the FMP is the point
at which measurement determines the
royalty that is owed to the Federal
Government or the Indian mineral
owners. In general, the ONRR definition
applies to offshore oil and gas
operations, whereas the BLM definition
applies only to onshore operations. So,
while the two agencies’ FMP definitions
are not exactly the same, they capture a
similar concept (i.e., the specific
measurement point where operators
determine the royalty due the Federal
Government or Indian mineral owners).
These comments did not result in a
change to the final rule.
It should be noted that in 2013, the
GAO specifically noted in report GAO–
10–313 that Interior’s onshore and
offshore policies for tracking and
approving where and how oil and gas
are measured are inconsistent. The
Bureau of Safety and Environmental
Enforcement (BSEE) already assigns
FMP numbers for offshore oil and gas
leases, which the operator, transporter,
or purchaser must then use when
reporting production results to ONRR.
Based on that practice, the GAO
recommended that the BLM clearly
identify points of measurement where
oil and gas royalties due to the Federal
Government are determined and
reported. By including the definition of
FMP in the final rule, the BLM is able
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to both address the GAO’s concerns and
bring onshore reporting in-line with the
approach used offshore.
The BLM received additional
comments pertaining to the FMP
definition. One recommended that the
definition be changed to allow operators
to use gas processing plant tailgate
meters located off the lease, unit, or CA
as FMPs as a general matter, or to allow
those meters to be used as FMPs under
a variance. Another commenter asked
whether an FMP is the same as a Central
Delivery Point or Point of Royalty
Measurement as defined in Washington
Office Instruction Memorandum (IM)
2013–152, a BLM policy document
created in 2013 regarding commingling
approvals.
The BLM did not change the
definition of an FMP to include tailgate
meters because, under the Mineral
Leasing Act (MLA) and FOGRMA, the
Secretary’s authority to regulate onshore
oil and gas operations applies to lessees/
operators and, during certain activities,
to purchasers and transporters. While
the owners of off-lease/unit/CA gas
processing plants may sometimes fall
into these categories of regulated
entities, they will not always, and while
the BLM may consider requests for offlease measurement it is not required to
approve such request. Therefore, the
BLM chose not to include off-lease/unit/
CA tailgate meters in the definition of
an FMP in order to avoid default
applications of this rule that might be
inconsistent with BLM’s statutory
authority or the requirements of this
final rule related to off-lease
measurement at §§ 3173.23 through
3173.28. With respect to whether the
definition of an FMP is the same as the
Central Delivery Point or Point of
Royalty Measurement as defined in IM
2013–152, the BLM can confirm that
they are the same.
The definition of ‘‘off-lease
measurement,’’ in both the proposed
and final rules, means measurement at
an FMP that is not located on the lease,
unit, or communitized area from which
the production came. The BLM received
several comments requesting that the
definition be expanded to exempt from
the proposed rule’s off-lease
measurement approval requirement
cases in which a horizontally or
directionally drilled well is completed
through a Federal or Indian lease, unit,
or communitized area, but conducts
measurement operations off-lease at the
wellhead. The commenters said that, in
many instances, wells are being drilled
from a surface location that is sited offlease due to environmental conditions,
such as rugged terrain or sensitive
wildlife habitat. The BLM did not
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change the definition of off-lease
measurement in response to this
comment because § 3173.28(a) of the
proposed and final rules already
addresses this situation. Under
§ 3173.28(a), measurement at an
approved FMP is not considered offlease measurement when the FMP is
located on the well pad of a
directionally or horizontally drilled well
that produces oil and gas from a lease,
unit, or CA on which the well pad is not
located. Therefore, approval for off-lease
measurement is not required under
those circumstances, so long as
measurement operations occur on the
well pad of the directionally or
horizontally drilled well.
The final rule makes minor changes to
the list of acronyms that appear in
proposed § 3170.3 based on the
acronyms used in part 3170. The BLM
did not receive any comments on this
list. The acronym Btu (British thermal
unit) has been relocated from § 3173.1 to
§ 3170.3 because this acronym is used in
both subparts 3173 and 3175. The
acronym S&W (sediment and water) is
new to section. The BLM decided to
include it in § 3170.3 because the
acronym is used in both subparts 3173
and. Although it is a commonly
understood acronym in the oil and gas
industry, the BLM believes it is
appropriate to include the acronym here
for clarity and to help inform the
general public. The BLM also added the
acronym LACT (lease automatic custody
transfer) because it is used in both
subparts 3173 and 3174.
Section 3170.4 Prohibitions Against
By-Pass and Tampering
The BLM did not make any changes
to the requirements of this section
between the proposed and final
versions. Section 3170.4 strengthens the
prohibition against meter by-passes
contained within section III.D of Order
3 by adding language that prohibits
tampering with any measurement
device, component of a measurement
device, or measurement process. As
explained in § 3170.3, tampering
includes any deliberate adjustment or
alteration to the meter or measurement
device or measurement process that
could introduce bias into the
measurement or affect the BLM’s ability
to independently verify volumes or
qualities reported. Examples of
tampering include deliberately
installing an orifice plate in a gas meter
with the bevel upstream, adjusting a
transducer to read higher or lower than
a certified test device, entering incorrect
information into the configuration log of
an electronic gas measurement system,
submitting derived integral values on a
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volume statement in lieu of raw data, or
making analogous adjustments or
alterations to an oil measurement
system.
The BLM received many comments
on this section of the proposed rule,
most of which suggested that the BLM
clarify that inadvertent human error or
force majeure events should not be
considered ‘‘tampering’’ for purposes of
this section. For example, one
commenter said meter reports may use
derived values due to tap freezes or data
loss. The commenter believes that these
situations should not be considered
‘‘tampering.’’ The commenter said the
language in the proposed rule would not
allow for such cases, and should be
modified. The BLM agrees with this
comment and in the final rule has
provided a definition for the term
‘‘tampering,’’ as previously discussed,
that clearly states that the act of
tampering must be deliberate on the part
of the operator. By requiring acts to be
deliberate, consistent with the
commenter’s suggestion, the BLM is
able to take into consideration whether
a particular act is due to human error or
is outside of the operator’s control.
The BLM did not amend the
definition of tampering in response to
the comment about the use of derived
values rather than raw data in a meter
report, such as when a tap freezes or
other malfunctions are experienced.
These circumstances can occur in the
context of either oil or gas measurement,
and they are addressed in specific
provisions of subparts 3174 and 3175
(the new rules replacing Orders 4 and 5)
that establish procedures that an
operator must follow to notify the BLM
of the malfunctioning equipment,
document how derived values were
determined, and indicate on the
quantity transaction record that derived
values, rather than raw data, were used
to determine volumes. As a result, the
BLM did not amend the definition of
tampering in response to comments
about derived values.
Section 3170.5 Industry Standards
Incorporated by Reference
Section 3170.5 is reserved for
potential future incorporation by
reference of standards that apply to
more than one of the subparts of part
3170.
Section 3170.6
Variances
Section 3170.6 of the final rule
clarifies and makes more uniform the
BLM’s existing process and regulations
for granting variances from the
minimum standards contained in part
3170.
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81371
Paragraph (a)(1) lists all the
information that a party seeking a
variance from the requirements of part
3170 must include when filing a
request, including: Identification of the
specific requirement from which a
variance is sought, and the length of
time the variance is requested; an
explanation of the need for the variance;
a detailed explanation of the proposed
alternative means of compliance; and a
showing that the proposed alternative
meets or exceed the objectives of the
applicable requirement. Paragraph (a)(2)
requires that variance requests be
submitted as separate documents from
any plans or applications. The BLM will
not consider variance-request
documents that are submitted as part of
a master development plan, APD, rightof-way application, or other
applications for approval. This
requirement does not preclude operators
from submitting variance requests at the
same time that they submit a master
development plan or other application.
In fact, the final rule encourages
operators to submit their variance
requests simultaneously with, but
separately from, their development
plans or applications, especially if the
operators’ proposals are contingent
upon the BLM approving their variance
requests. The BLM’s primary rationale
for requiring separate submittal is that,
in the past, operators have put their
variance requests in the cover letters
that accompanied their development
proposals, where they are sometimes
overlooked. Having operators submit
their variance requests via a separate
Sundry Notice will help the BLM easily
identify them when they are submitted
simultaneously with other applications.
Paragraph (a)(2) clarifies that approval
of a plan or application that contains a
request for a variance does not
constitute approval of the variance. The
BLM made this clarification to ensure
that variances are submitted separately
and brought to the attention of the BLM.
Paragraph (a)(3) tells operators how to
submit their variance requests.
Operators must use WIS, which is an
acronym described in the final rule to
mean the Well Information System or
any successor electronic filing system
that might be developed by the BLM, to
file their request, along with any
supporting documents associated with
it. This paragraph also provides an
option for operators to submit a
hardcopy application if electronic filing
is not possible or practical. In such
cases, the operator must submit a
variance in hardcopy as directed by the
AO in the Field Office having
jurisdiction over the lands described in
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the application. The BLM made minor
revisions to this section to clarify the
intent of this provision regarding
electronic filing, and to provide
additional flexibility as the BLM rolls
out new electronic systems to replace its
existing systems, including the Well
Information System and the Automated
Fluid Management Support System
(AFMSS).
No substantive changes were made to
proposed paragraph (a)(4). This
paragraph strengthens and standardizes
the criteria the BLM uses for granting
variances. Under Order 3, the AO was
required to make only one
determination—whether or not the
variance request meets or exceeds the
objectives of the applicable minimum
standard. Under this paragraph in the
final rule, the AO will still have to make
that determination before granting a
variance. Additionally, the final rule
requires the AO to make two more
determinations before granting a
variance—that issuing a variance: (1)
Will not adversely affect royalty income
or production accountability; and (2) Is
consistent with maximum ultimate
economic recovery.
Paragraphs (a)(5) and (a)(6) specify
that granting or denying a variance is
entirely within the BLM’s discretion,
and that a variance from a requirement
in a regulation does not constitute a
variance from any other regulations,
including other Onshore Oil and Gas
Orders. These paragraphs did not
change from the proposed rule.
Paragraph 3170.6(b) affirms the BLM’s
authority to rescind a variance or
modify any condition of approval of a
variance due to changes in Federal law,
technology, regulation, BLM policy,
field operations, noncompliance, or for
any other reason.
The BLM received many comments
on this section of the proposed rule. A
few commenters were concerned that
the proposed rule would void existing
variances and that operators with
existing variances would have to apply
for new ones. These commenters were
concerned this would place an
unnecessary burden on affected parties.
They recommended that the provision
be revised to expressly ‘‘grandfather’’
existing variances.
The BLM did not make a change to
the rule in response to these comments.
This final rule does not automatically
rescind any existing variance approvals.
Rather, it clarifies the BLM’s authority
to rescind variances and provides the
means by which it may rescind an
existing approval if necessary. The BLM
will re-evaluate existing variance
approvals on a case-by-case basis, such
as during the FMP application and
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review process under § 3173.16. For
example, if an operator has an existing
variance approval from the BLM’s
previous commingling requirements,
but during the FMP approval process
the BLM determines that the existing
approval is inconsistent with this final
rule’s new commingling standards, or
the operator cannot be exempted from
the new commingling standards, then
the BLM will rescind the existing
variance if the deficiencies are not
corrected within the time specified by
the BLM.
Several commenters disagreed with
the provision in paragraph (b) that
allows the BLM to rescind variance
approvals and modify conditions of
approval. These commenters stated that
companies made investments and
proceeded with projects based on
previously approved BLM variances.
These commenters said that rescinding
existing authorizations and what they
believe to be contractual agreements
would pose a great risk to their
operations.
The BLM did not make a change in
the rule in response to these comments.
The BLM’s overriding contractual
agreement with the operator is the lease
agreement, which is expressly made
subject to regulations and formal orders
subsequently promulgated as long as
such regulations are not inconsistent
with the lease rights granted or the
specific lease provisions (See BLM
Lease Form 3100–11). The Department
has long interpreted this language as
‘‘incorporat(ing) future regulations, even
though inconsistent with those in effect
at the time of lease execution, and even
though to do so creates additional
obligations or burdens for the lessee.’’ 9
The BLM’s authority to update the
regulations that apply to existing leases
and operations is well-established, and
this authority necessarily includes the
authority to rescind existing variances
and authorizations when these
variances and authorizations are
inconsistent with applicable
regulations.
The BLM recognizes that the
commingling and off-lease measurement
requirements in this rule may result in
the termination of existing commingling
and off-lease measurement variance
approvals. However, the BLM has
sought to minimize the adverse impacts
of these requirements by providing
exemptions for economically marginal
properties. These additional exemptions
are discussed in further detail in the
sections of this preamble that address
commingling and off lease
9 Coastal Oil & Gas Corp., et al., 108 IBLA 62, 66
(1989).
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measurement. See the Section-bySection discussions of §§ 3173.1,
3173.14, 3173.25, and 3173.27. For
example, the final rule provides publicinterest exemptions for operators that
cannot meet its new off-lease
measurement standards.
One commenter supported the
standards in paragraph (a)(4) that the
BLM will use to determine whether to
grant a variance but went one step
further to recommend that operators be
required to demonstrate that compliance
with the regulation is not feasible, so
that the rule’s relatively limited
opportunities for variances are not
abused. The BLM does not expect
operators to abuse the variance process,
which requires them to submit an
application requesting a variance, and
provide sufficient information and
justification for the variance that the
BLM will then review prior to making
a determination on the variance request.
In fact, this rule strengthens and
standardizes the criteria that the BLM
will use to determine whether to grant
a variance and requires that the BLM
make a determination that ‘‘the
proposed alternative meets or exceeds
the objectives of the applicable
requirement(s) of the regulation.’’ As a
result, the BLM does not believe the
change requested by the commenter is
necessary and did not make any changes
the rule based on this comment.
A few commenters expressed concern
with language in paragraph (b) that
allows the BLM to rescind a variance for
‘‘other reasons’’ because, they said, it
could result in the BLM acting
arbitrarily. The BLM disagrees that this
language would allow it to act
arbitrarily because paragraph (b)
requires the BLM to provide a written
justification when it rescinds a variance.
The BLM included the term ‘‘other
reason’’ because the BLM cannot
anticipate every possible situation in
which there will be good cause for
rescinding a variance. The BLM must
preserve its ability to rescind a variance
approval if that approval adversely
affects royalty income or production
accountability, or is not consistent with
maximum ultimate economic recovery.
If the operator does not agree with the
BLM’s decision to rescind a variance,
the operator may file an appeal under
applicable BLM regulations at 43 CFR
subpart 3165—Relief, Conflicts, and
Appeals.
A few commenters stated that even
though the BLM will provide written
justification when it rescinds a variance
or modifies a COA, operators should be
given a 30-day advance notice if their
variance is about to be rescinded, or
COA modified, in order to give them an
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opportunity to avoid a rescission or
modification, or to adjust to operating
without the variance. The BLM
disagrees with this comment and did
not change the rule in response. As
previously noted, if an operator
disagrees with the BLM’s decision to
rescind a variance or change a COA, the
operator may file an appeal under the
applicable regulations.
Section 3170.7 Required
Recordkeeping, Records Retention and
Records Submission
Section 3170.7 of the final rule
updates BLM regulations to reflect the
records-retention requirement for
Federal oil and gas leases that Congress
established in the 1996 amendments to
FOGRMA.10
Paragraphs (a) and (b) are the same as
in the proposed rule. These paragraphs
establish both the entities covered and
the time period over which the recordsretention requirements apply. In the
final rule, purchasers and transporters
are held to the same minimum
standards as operators for
recordkeeping, records retention, and
records submission—i.e., to maintain all
records that are relevant to determining
the quality, quantity, disposition, and
verification of production from Federal
and Indian leases. As described in the
proposed rule, the BLM has authority to
impose these requirements on
purchasers and transporters under
FOGRMA. Specifically, Section 103(a)
of FOGRMA, 30 U.S.C. 1713(a), requires
persons involved in transporting and
purchasing oil or gas through the point
of first sale or the point of royalty
computation, whichever is later (along
with persons involved in producing or
selling), to ‘‘establish and maintain any
records, make any reports, and provide
any information that the Secretary may,
by rule, reasonably require.’’
Although paragraph (c) did not
change substantively from the proposed
rule, the final rule splits it up into two
paragraphs for clarity. Paragraph (c)(1)
states that records pertaining to Federal
leases, units, or CAs must be maintained
for at least 7 years, consistent with
applicable statutory requirements.
Paragraph (c)(2) codifies the applicable
statutory requirements for further
retention beyond 7 years under the
circumstances specifically identified by
statute (see 30 U.S.C. 1724(f)), as
required under the 1996 amendments to
FOGRMA.
Similarly, although paragraph (d) did
not change substantively from the
10 Federal Oil and Gas Royalty Simplification and
Fairness Act of 1996, Public Law 104–185, 110 Stat.
1700 (Aug. 13, 1996).
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proposed rule, the final rule splits it up
into two paragraphs for clarity.
Paragraph (d)(1) states that records
pertaining to Indian leases, units, or
CAs must be maintained for at least 6
years, consistent with applicable
statutory requirements. Paragraph (d)(2)
codifies the applicable statutory
requirements for further retention
beyond 6 years under the circumstances
specifically identified by statute (see 30
U.S.C. 1713(b)). The records-retention
requirement on Indian leases remains
unchanged because the 1996
amendments to FOGRMA, by their
express terms, applied only to Federal
leases and not to Indian leases.
Paragraph (e)(1) addresses the
discrepancy between the recordsretention requirements for Federal (7
years) and Indian (6 years) leases, as
relevant to units and CAs that contain
both Federal and Indian leases. No
substantive changes were made as part
of the final rule. However, the phrase,
‘‘but a judicial proceeding or demand is
not commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the unit or CA until the
Secretary or his designee releases the
record holder from the obligation to
maintain the records’’ has been
eliminated from this paragraph of the
proposed rule and moved to its own
paragraph (e)(2).
In paragraph (e)(2) of the proposed
rule, which is now paragraph (e)(1) of
the final rule, the phrase ‘‘or until the
Secretary or his designee releases the
record holder from the obligation to
maintain the records, whichever is
later,’’ was removed from the final rule
in order to more closely track the
authorizing language in FOGRMA, and
also to make the record-retention
obligation clearer.
Paragraph (f) requires the record
holder to maintain an audit trail and is
unchanged from the proposed rule.
Paragraph (g) requires operators,
purchasers, and transporters to place
specific identifying information on all
records, including source records, used
to determine quality, quantity,
disposition, and verification of
production attributable to a Federal or
Indian lease, unit PA, or CA. The
proposed rule would have required
record holders to use BLM-assigned
FMP numbers on such records. The
final rule is revised to allow record
holders, in lieu of an FMP number, to
use the lease, unit PA, or CA number,
as applicable, on their records,
including source records. In any case,
the record holder must also include a
unique equipment identifier, such as a
unique tank identification number or
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81373
meter station number. The BLM made
this change in response to many
comments that it would be difficult or
impossible for some record holders to
modify their electronic systems to
accommodate FMP numbers on their
records. In these instances, the final rule
allows record holders to use the lease,
unit PA, or CA number instead of the
FMP number.
Paragraph (h) requires operators,
purchasers, and transporters to provide
all records to the BLM upon request.
This ensures that all records—whether
they are created by lessees, operators,
transporters, or purchasers—are readily
available to the BLM. The BLM did not
receive any comments on this paragraph
and did not change it in the final rule.
Paragraph (i) requires that all records
be legible. The BLM did not receive any
comments on this paragraph and did not
change it in the final rule.
Paragraph (j) requires that all records
requiring a signature must also have the
signer’s printed name. The BLM did not
receive any comments on this paragraph
of the proposed rule and did not change
it in the final rule.
The BLM received a number of
comments on § 3170.7 of the proposed
rule as a whole requesting various
changes to be made to the proposed
requirements. Each of these comments
is addressed below.
One commenter stated that
maintaining audit records for 7 years, as
required in paragraph (c)(1), would
result in unnecessary costs for
purchasers and transporters, and that
they should not have to account for
production volumes. The BLM does not
agree with this comment, nor can it
make the changes suggested by the
commenter. As discussed earlier, the
records retention period set by
FOGRMA for Federal leases is now 7
years and the change in retention period
in this final rule merely conforms the
regulations to that statutory authority.
A number of other commenters
asserted that the BLM does not have the
authority to hold purchasers and
transporters to the same recordsretention and recordkeeping
requirements as lessees and operators,
as outlined in paragraphs (a) and (f) of
§ 3170.7. Other commenters indicated
that they did not see a need for this new
requirement and that it would be too
costly. Still others disagreed that
FOGRMA authorizes the BLM to impose
recordkeeping and records-retention
requirements on purchasers and
transporters in the first instance. One
commenter argued that the BLM had not
properly defined ‘‘any person directly
involved in producing, transporting,
purchasing, selling, or measuring oil
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and gas’’ under FOGRMA, and therefore
had improperly extended these
recordkeeping requirements to
purchasers and transporters.
The BLM disagrees with these
comments. Section 103(a) of FOGRMA,
30 U.S.C. 1713(a), requires a ‘‘lessee,
operator, or other person directly
involved in developing, producing,
transporting, purchasing, or selling oil
or gas . . . through the point of first sale
or the point of royalty computation,
whichever is later, [to] establish and
maintain any records, make any reports,
and provide any information that the
Secretary may, by rule, reasonably
require.’’ While FOGRMA does not
specifically define ‘‘any person directly
involved,’’ the intent of the provision is
clear. It authorizes the Secretary to
establish by rule requirements for
anyone involved ‘‘. . . in developing,
producing, transporting, purchasing, or
selling oil or gas,’’ which plainly
includes purchasers and transporters. 30
U.S.C. 1713(a) (emphasis added).
Based on its experience in the field,
the BLM believes it is appropriate to
implement this statutory authority and
have purchasers and transporters adhere
to the same recordkeeping and recordsretention requirements as lessees and
operators. This is because the BLM must
occasionally rely on purchasers’ and
transporters’ records to verify
production when operators do not
maintain their own records properly, or
go out of business, or are acquired by
other companies and their records are
destroyed. For this reason, the BLM
believes that it is important for everyone
involved in the production and sale of
oil and gas produced from Federal and
Indian leases to be responsible for
maintaining and providing the
necessary records to account for and
verify that production. The BLM did not
make any changes in response to these
comments.
Another commenter said the BLM did
not adequately analyze the economic
impact that this requirement would
have on purchasers and transporters.
The BLM does not agree with this
comment. As part of this rulemaking
process the BLM prepared an Economic
and Threshold Analysis For Final Rule
Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases;
Site Security (Economic and Threshold
Analysis). That analysis specifically
analyzed, among other things, the
impact of these proposed recordkeeping
requirements on purchasers and
transporters. Based on that analysis, the
BLM estimates that 200 to 300
purchasers and transporters will have to
comply with this final rule’s new
recordkeeping and records-retention
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requirements. However, it is likely that
many purchasers and transporters
already compile records that will, for
the most part, satisfy this rule’s
requirements, and therefore the
additional compliance costs imposed by
this rule should be minimal. For more
details, please see the Economic and
Threshold Analysis.
Several commenters said that some
transporters do not have space to store
records and would not be capable of
meeting the paragraph (a) requirements.
They said that transporters would create
inaccurate records, and that operators
would be held responsible. They asked
that the BLM not hold operators
responsible for transporters’
recordkeeping violations. Conversely,
some commenters said operators may
provide incorrect information to
purchasers and transporters, such as
incorrect FMP numbers, which could
subject purchasers and transporters to
recordkeeping penalties if they were to
use the inaccurate information in their
records. The BLM does not agree with
the concerns raised by these
commenters, as under the rules each
party will be responsible for the content
of their own records and must also bear
some responsibility for ensuring the
accuracy of the information they are
tracking. The BLM does not believe that
the provision should be modified to
account for the possibility that operators
might provide faulty information to a
purchaser or transporter. Parties bear
the responsibility to ensure the accuracy
of their own records, and the BLM
anticipates that provision of faulty
information to a purchaser or
transporter by an operator could be
handled on a case-by-case basis in the
enforcement context. The final rule was
not changed as a result of these
comments.
Some commenters said the BLM
should make the records-retention
requirements for both Federal and
Indian leases the same—6 years.
Paragraph (c) requires Federal-lease
operators to retain their records for 7
years (consistent with Congress’ 1996
amendments to FOGRMA), while
paragraph (d) requires Indian-lease
operators to retain theirs for 6 years.
One commenter said the 6-year
retention requirement for all records
under Order 3 has not been a problem
and questioned why Congress extended
the retention period for Federal-lease
operators from 6 years to 7 years. The
BLM understands these concerns, but
the retention period for records
maintained by Federal-lease operators is
7 years by statute. 30 U.S.C. 1724(f).
That statutory requirement has been in
place for 20 years. This final rule simply
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codifies that requirement. Thus, the
BLM did not change the final rule in
response to these comments.
Several commenters expressed
concern about the requirement in
paragraph (g) of the proposed rule that
lessees, operators, purchasers, and
transporters place FMP numbers on all
of their source records, particularly
records generated by flow computers.
They said that flow computers cannot
handle the 11-digit FMP numbers and
that it would take operators years to
modify their production accounting
systems to accommodate the new
numbers. The BLM agrees with these
commenters and changed the final rule
to allow lessees, operators, purchasers
and transporters, as an alternative, to
use the lease, unit PA, or CA number,
along with a unique equipment
identifier, on their records. The BLM
believes this change will simplify the
final rule’s record-keeping requirements
because in its experience lessees,
operators, purchasers and transporters
are already using a lease, unit PA, or CA
number, plus some unique equipment
identifier in connection with existing
operations, which means this
information is already reflected on
records being generated under existing
recordkeeping systems.
In addition to the preceding
comments on specific provisions of
§ 3170.7, the BLM received some
general comments on § 3170.7 that were
not directed to any specific paragraph.
Several commenters said the
recordkeeping requirements do not
address new production reporting
technology and practices that are used
by regulators outside of the U.S., such
as the Norwegian Petroleum Directorate.
These commenters did not suggest any
specific changes, and therefore the BLM
did not make any changes in the final
rule in response to these comments.
That said, it should be noted that the
BLM is currently updating its existing
database system (AFMSS) that it uses to
track Federal and Indian oil and gas
production. As part of this
comprehensive update, the BLM is
following data management models and
standards established by industry
organizations, such as the Professional
Petroleum Data Management
Association. These update efforts
respond to the concerns raised by
commenters.
Another commenter said the new
recordkeeping and records-retention
requirements would cause problems for
the BLM. This commenter said BLM
field offices do not have room for the
additional records that would be
generated under the final rule. The BLM
disagrees with this commenter. The
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BLM will not be storing or accepting all
of the records that a lessee, operator,
purchaser, or transporter will be
required to create and retain under this
final rule, rather records must be
available to the BLM if requested (see
§ 3170.7(h)). The BLM did not change
the final rule as a result of these
comments.
Several commenters suggested that
requiring purchasers and transporters to
keep and retain records would be
redundant because purchasers and
transporters already provide this
information to the operators, who use it
to fill out their own production records.
The BLM agrees that operators do often
base their production reporting on
information that purchasers and
transporters provide them, however, the
BLM cannot confirm that this happens
in all cases. Moreover, as noted,
operators’ records may sometimes be or
become unavailable. Requiring each
party involved in production from
Federal and Indian oil and gas leases to
maintain its own records allows the
BLM to compare the information and
make an independent determination
that production is being properly
accounted for and that the correct
royalties are being paid.
One commenter said this section’s
new recordkeeping and recordsretention requirements will be costly
and cause delays, and will discourage
oil and gas development on Federal
lands, as well as on adjacent State and
private lands. The commenter said this
in turn will result in lost royalties and
jobs. The BLM does not agree with this
comment. These recordkeeping
requirements are not substantially
different from the requirements that
operators are currently following (e.g.,
the records retention requirements have
only increased from 6 to 7 years). As
explained above, it is likely that most
purchasers and transporters are already
maintaining records that will, for the
most part, satisfy this final rule’s
requirements. No change was made to
the final rule as a result of this
comment.
Section 3170.8 Appeal Procedures
Section 3170.8 provides that BLM
decisions, orders, assessments, or other
actions under part 3170 are
administratively appealable (first to the
BLM State Director and then to the
Interior Board of Land Appeals) under
43 CFR 3165.3(b), 3165.4, and part 4.
The BLM did not receive any comments
on this section; however, in response to
comments received on provisions of the
proposed rules to replace Orders 4 and
5 the BLM made several changes to this
section.
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The language from the proposed rule
was moved to a new paragraph (a) and
a new paragraph (b) was added that
creates a separate appeal process for
decisions made by the BLM, based on a
recommendation from the PMT, for
approval or denial of specific
measurement equipment or procedures.
Under paragraph (b) a party may file a
request for discretionary review by the
ASLM. Paragraph (b) also provides that
the ASLM may delegate this review
function as he or she deems appropriate,
in which case the application for
discretionary review must be made to
the person or persons to whom the
review function has been delegated.
A specific appeals procedure for
recommendations from the PMT was
developed for two reasons. First, such a
procedure responds directly to
comments received on Orders 4 and 5
specifically requesting a procedure to
review decisions made by the PMT.
Second, the BLM determined that a
separate appeal process is necessary
because it determined that PMT reviews
did not fit under the existing appeals
procedure at 43 CFR 3170.8. As
explained in this preamble and the
preambles for the rules to replace
Orders 4 and 5, the PMT will review
new measurement technologies and
methods and then make
recommendations to the BLM as to
whether they should be approved. It is
the BLM’s intent that those approvals be
made at the national or Washington
Office level, as a result those decisions
would not properly be appealable to a
BLM State Director as contemplated in
paragraph (a). The new language under
paragraph (b) reads: ‘‘For any
recommendation made by the PMT, and
approved by the BLM, a party affected
by such decision may file a request for
discretionary review by the Assistant
Secretary for Land and Minerals
Management. Under paragraph (b), the
Assistant Secretary may delegate this
review function as he or she deems
appropriate, in which case the affected
party’s application for discretionary
review must be made to the person or
persons to whom the Assistant
Secretary’s review function has been
delegated.’’ 11
Section 3170.9
Enforcement
Section 3170.9 provides that
noncompliance with any requirements
of part 3170 or any order issued
thereunder may result in enforcement
actions under 43 CFR subpart 3163 or
11 It should be noted that decisions by the
Assistant Secretary would not be reviewable by the
Interior Board of Land Appeals.
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any other remedy available under
applicable law or regulation.
The BLM received numerous
comments regarding the BLM’s
proposal, in proposed § 3170.9, not to
include in this rule the enforcement,
corrective action, and abatement period
provisions that were in Order 3, and
instead to develop an internal
Inspection and Enforcement Handbook
that would provide direction to BLM
inspectors on how to classify a violation
as major or minor, and what the
corrective action and timeframes for
correction should be. These comments
and the BLM’s response are discussed
later in this preamble in connection
with § 3173.29.
Subpart 3173—Requirements for Site
Security and Production Handling and
Related Provisions
Section 3173.1
Acronyms
Definitions and
This section defines the terms used in
subpart 3173 that pertain to site security
and production handling. The BLM did
not receive any comments on a majority
of the definitions that appeared in
proposed § 3173.1. Those definitions,
for which we received no comment,
were carried forward into this final rule
and are not discussed further here. The
following discussion summarizes and
responds to comments that the BLM
received on a handful of proposed
definitions, describes modifications to
some of those definitions, and describes
five definitions that were added to
§ 3173.1 of the final rule: ‘‘Free water,’’
‘‘permanent measurement facility,’’
‘‘payout period,’’ ‘‘royalty net present
value (NPVR),’’ and ‘‘royalty-free use of
oil and gas.’’
At the outset it should be noted that
as explained in the preamble to the
proposed rule, a number of the
definitions in § 3173.1 are the same
definitions that were found in Order 3,
with only minor simplifications or
clarifications.
As noted in the Section-by-Section
discussion for § 3170.3, the acronym for
‘‘British thermal unit (Btu)’’ has been
moved from this section to § 3170.3 of
the final rule because it is used in more
than one subpart of § 3170. The
acronym BIA (Bureau of Indian Affairs)
was added to this final rule because it
is used in §§ 3173.14 and 3173.23.
Similarly, the acronym for ‘‘CAA
(commingling and allocation approval)’’
was provided in the proposed rule, but
the term was not otherwise defined. One
commenter suggested that a definition
for this term be provided. The BLM
agrees with this comment and has
provided a definition in the final rule
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for this commonly used term. The final
rule defines ‘‘commingling and
allocation approval (CAA)’’ to mean ‘‘a
formal allocation agreement to combine
production from two or more sources
(leases, unit PAs, CAs, or non-Federal or
non-Indian properties) before that
production reaches an FMP.’’ This
definition is consistent with the
commonly understood meaning of the
term and its use in the proposed rule.
The BLM also replaced the term ‘‘lowvolume property’’ with the term
‘‘economically marginal property’’ and
modified the definition based on
comments received. The term ‘‘lowvolume property’’ was intended to
identify category of leases, unit PAs,
and CAs for which commingled
measurement of production may be
justified, even though the property
would not meet the conditions of
proposed § 3173.14(a)(1) regarding
mineral interest ownership of
commingled production. In response to
comments, the BLM made a number of
changes to this definition, most notably
changing the term to ‘‘economically
marginal property’’ in the final rule.
The BLM believes this new term is
more reflective of the BLM’s intent,
which is to describe a type of property
that should be allowed to be part of a
CAA in order to avoid premature
plugging and abandonment. The
thresholds that the proposed and final
rules use to identify a property as at risk
of being shut-in are not exclusively
volume-based. The new name
recognizes that the thresholds are
actually based on production volume
and other economic considerations,
including commodity price, fixed and
variable operating costs, and taxes.
Specifically, under both the proposed
and final rules, the BLM can approve
commingling in two circumstances
relating to economics of well operations:
(1) When a prudent operator, for
economic reasons, would plug a well or
shut-in the lease, unit PA, or CA instead
of spending the money to achieve noncommingled measurement of
production; or (2) When the capital
expenditure on equipment necessary to
achieve non-commingled measurement
of production would exceed the net
present value of projected Federal or
Indian royalty over the life of the new
equipment. The BLM captured both of
these circumstances in the definition of
a ‘‘low-volume property’’ in the
proposed rule, and carried that structure
into the final rule’s definition of an
‘‘economically marginal property.’’
Under the final rule, a lease, unit PA,
or CA qualifies as an ‘‘economically
marginal property’’:
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(1) ‘‘If the operator demonstrates that the
expected revenue generated from crude oil or
nature gas production volumes on that
property (above the operating costs
associated with those production activities)
is not sufficient to cover the nominal costs
of the capital expenditures required to
achieve measurement of non-commingled
production of oil or gas from that property
over a payout period of 18 months,’’ or
(2) If the operator demonstrates that ‘‘its
royalty net present value, or the discounted
value of the Federal or Indian royalties
collected on revenue earned from crude oil
or natural gas production on the lease, unit
PA, or CA over the expected life of the
equipment that would need to be installed to
achieve non-commingled measurement
volumes, is less than the capital cost of
purchasing and installing this equipment.’’
The final rule takes a somewhat
different approach than the proposed
rule to define these two circumstances.
Specifically, the final rule:
• Changes the threshold for what
qualifies as an economically marginal
property from a 10 percent, before tax,
rate of return in the proposed rule to an
18-month, after-tax, payout period in
the final rule;
• States explicitly that the economic
analysis considers operating costs;
• Clarifies that the analyses for oil
and gas commodities are done
separately, based on the income streams
from the commodity and the expenses
required to achieve non-commingled
measurement of that commodity; and
• States explicitly that if economic
circumstances change, and a Federal or
Indian lease, unit PA, or CA ceases to
be an economically marginal property,
the lease, unit PA, or CA will no longer
qualify for a CAA.
The BLM changed the first economic
threshold test from a 10 percent, before
tax, rate of return in the proposed rule
to an 18-month, after-tax, payout in the
final rule, primarily based on comments
received. As explained in the preamble
to the proposed rule, the initial test was
developed based on the provisions of
Instruction Memorandum (IM) 2013–
152. The purpose of the economic
analysis in IM 2013–152, the proposed
rule, and the final rule is to simulate the
analysis that a prudent operator would
make in deciding whether or not to
invest money to achieve noncommingled measurement of
production. If that analysis concludes
that it would be uneconomic for the
operator to make the investment and
they would instead opt to shut in the
property, then the BLM will grant
commingling approval. In these
situations, the BLM believes that it is in
the public interest to sustain production
by allowing commingling, even if
commingled measurement may be
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somewhat less accurate and hard to
verify than non-commingled
measurement.
The only question is how best to
identify the point at which a prudent
operator would choose to shut in rather
than invest in equipment to achieve
non-commingled measurement. Several
commenters said the proposed 10
percent rate-of-return cutoff point
(calculated before Federal, State, and
local taxes) was too low, and that the
BLM, should instead use a 20 percent
rate of return. Other commenters
recommended replacing the 10 percent
rate of return threshold with a payout
period. The BLM agrees with the
commenters who recommended that the
BLM use a payout period method rather
than a rate-of-return method, because
the former provides a simpler and more
objective picture of whether a particular
course of action is economically viable,
and it is a method commonly used by
industry.
Under the rate-of-return method in
the proposed rule, the BLM would have
had to assume a rate of return on initial
investment that would be sufficient for
a prudent operator to install metering
equipment to achieve non-commingled
measurement of a lease, unit PA, or CA.
The payout method used in the final
rule uses a formula to determine
whether the production volumes at that
lease, unit PA, or CA are sufficient to
generate enough net revenue, after taxes
and operating costs, to cover the
nominal cost of equipment installation
within the payout period. Additionally
it was clear from the comments received
that different companies apply different
rates of return to evaluate their
investments. For these reasons, the BLM
felt it was appropriate to replace the
rate-of-return method with the payout
method.
One commenter stated that industry
typically uses a payout period of 6
months to 18 months as the criterion for
deciding whether or not to invest in a
new project. The commenter went on to
state that a 15 percent rate of return
(before tax) yields approximately the
same result as a 22-month payout. An
18-month payout would be
approximately the same as a 20 percent
(before tax) rate of return, which is a
threshold suggested by several
commenters. Based on these comments,
the BLM believes that an 18-month
payout period is reasonably
representative of the threshold a
prudent operator would use to
determine the economic viability of
achieving non-commingled
measurement of production.
Additionally, there were a few
comments that recommended that the
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BLM evaluate alternative cost-benefit
methodologies and definitions,
including those found in the Federal Oil
and Gas Royalty Simplification and
Fairness Act of 1996, and the Interstate
Oil and Gas Commission report, entitled
Marginal Wells: Fuel for Economic
Growth, (2012). The BLM agrees with
these comments, noting that the
proposed 10 percent rate of return was
a starting point, as the proposed rule
specifically asked for feedback on the
suitability of the BLM’s using this rate
of return for identifying a ‘‘low-volume
property.’’ The BLM believes the 18month payout threshold used in the
final rule is consistent with these
comments.
Also unlike the proposed definition of
‘‘low-volume property,’’ the definition
of ‘‘economically marginal property’’ in
the final rule specifically considers
taxes, fixed and variable operating costs,
and commodity prices. While the ‘‘lowvolume property’’ definition in the
proposed rule implicitly included
operating costs and commodity prices in
the rate-of-return calculation, it did not
include taxes. The BLM believes that
the addition of taxes and the explicit
addition of operating costs and
commodity price considerations help to
make the payout calculation more
representative of an economic analysis
that a prudent operator would perform.
Finally, in the final rule definition,
the BLM clarified that the economic
analyses are specific to the commodity
to which the commingling request
applies. For example, if a lease produces
a high volume of gas with small
amounts of associated condensate, and
the operator wishes to commingle the
condensate production with similar
volumes of condensate produced from
private leases, the economic analysis
performed under § 3173.14(b)(1) would
only consider the income, costs, and
payout period related to measuring the
condensate. The BLM made this
addition to the final rule to clarify that
neither operators nor BLM field offices
should include the income and costs
from a commodity which the operator is
not proposing to commingle. The
proposed rule was silent on whether the
economic analysis should be based on
total oil and gas production or just on
the commodity the operator requests for
commingling. However, it was always
the BLM’s intent that this analysis occur
on the basis of the commodity for which
commingled measurement is proposed.
This clarification in the final rule is
consistent with that intent.
In support of the new definition for
‘‘economically marginal property’’ the
BLM added two additional definitions—
‘‘payout period’’ and ‘‘royalty net
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present value (RNPV)’’—each of which
is discussed (in alphabetical order)
below.
In addition, in the final rule the BLM
added a definition for the term ‘‘free
water.’’ That term appeared multiple
times in the proposed rule but was not
defined because the BLM believes it is
commonly understood by the industry.
While the BLM did not receive any
comments on the use of this term, the
BLM determined that it should
nevertheless include a definition in the
final rule to clarify its intent with
respect to the use of the term in this
regulation. The final rule therefore
defines ‘‘free water’’ as ‘‘the measured
volume of water that is present in a
container and that is not in suspension
in the contained liquid at observed
temperature.’’ This definition tracks the
commonly understood definition of the
term used routinely by industry and the
BLM.
The final rule modifies the definition
of the term ‘‘land description’’ from the
proposed rule in § 3173.1, to clarify the
information needed by the BLM. The
purpose of defining the term ‘‘land
description’’ in both the proposed and
final rules is to ensure that the
geographic location information that
operators occasionally provide to the
BLM meets the applicable standards.
Under the proposed rule, the BLM
defined ‘‘land description’’ to mean ‘‘the
geographical coordinates referenced to
the National Spatial Reference System,
North American Datum 1983 or latest
edition, in feet and direction from the
nearest two adjacent section lines, or, if
not within the Rectangular Survey
System, the nearest two adjacent
property lines, generated from the
BLM’s current Geographic Coordinate
database (Public Land Survey System).’’
The final rule modifies this definition to
require operators to provide information
about location that is consistent with
the U.S. Department of the Interior’s
Manual of Surveying Instructions (2009)
and that includes information about the
quarter-quarter section, section,
township, range, and principal meridian
of the proposed location. This
definitional change was not suggested
by commenters, but was made to make
the definition in § 3173.1 consistent
with the existing geographic location
information requirements of 43 CFR.
3162.6, which requires operators to have
geographic location information on their
well- and facility-identification signs.
Subpart 3173 requires operators to
record land descriptions on their site
facility diagrams, FMP applications,
water draining and hot-oiling
paperwork, and reports of theft or
mishandling of production. By
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confirming the definitional provisions
of these two requirements, the final rule
ensures consistency and allows BLM
inspectors to cross-reference the land
description information on a site facility
diagram with the geographic location
information on a given facility sign and
confirm that they are inspecting the
correct measurement facility. It should
be noted that the definition of ‘‘land
description’’ does contemplate the use
of ‘‘other authorized survey
designations acceptable to the AO, such
as metes-and-bounds, or latitude and
longitude,’’ which accounts for
instances where the land may be
unsurveyed or another survey method is
necessary.
As noted in the discussion above, to
support the implementation of the
definition of ‘‘economically marginal
property’’ the BLM added a definition
for the term ‘‘payout period,’’ which is
defined as ‘‘the time required, in
months, for the cost of an investment in
an oil or gas FMP at a specific lease, unit
PA, or CA to equal the nominal revenue
earned from crude oil production for an
oil FMP, or natural gas production for
a gas FMP, minus taxes, royalties, and
any operating and variable costs.’’ This
definition is consistent with the intent
behind the definition of ‘‘economically
marginal property’’ established by this
final rule. The definition clarifies that
payout periods are determined
independently for each oil and gas FMP
at a given lease, unit PA, or CA.
The BLM included a definition for the
term ‘‘permanent measurement facility’’
to the final rule in response to a
commenter’s concern with § 3173.12(d)
of the proposed rule, which required
operators to obtain FMP approval before
any production leaves a measurement
facility. The commenter pointed out that
during well testing, and before initiating
production, operators send oil to a
temporary tank or send gas down the
sales line to determine the well’s
production rate. The test results help
the operator determine the size and type
of measurement facility needed. The
commenter said it would be overly
burdensome to require operators to
obtain FMP approvals for temporary
measurement equipment used during
well testing as well as for permanent
measurement facilities.
The BLM agrees in part with this
comment and has provided a definition
for the term ‘‘permanent measurement
facility,’’ which means ‘‘all equipment
constructed or installed and used onsite for 6 months or longer for the
purpose of determining the quantity,
quality, or storage of production that
meets the definition of FMP under
§ 3170.3.’’ In addition, the final rule also
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clarifies that paragraphs (d) and (e) of
§ 3173.12, which pertain to when
operators must apply for their FMP
numbers, apply only to permanent
measurement facilities. Therefore,
temporary equipment used during well
testing operations, including temporary
tanks to store oil, are not affected by the
FMP requirement. However, since a
‘‘sales line’’ by definition is a permanent
facility, and any gas that travels through
it is royalty bearing, the BLM added a
6-month timeframe to the definition of
permanent measurement facility to
make clear that the FMP requirement
does not apply during well testing. Six
months was chosen because that is
when the BLM typically performs its
first environmental inspection of
production facilities after a well is
completed, and after that point, the
continued use of temporary equipment
at the wellsite would raise concerns that
an operator is having difficulty
installing its permanent facilities.
The BLM added a definition of
‘‘royalty net present value (RNPV)’’ to
support implementation of the term
‘‘economically marginal property.’’ The
final rule defines RNPV as the ‘‘net
present value of all Federal or Indian
royalties paid on revenue earned from
crude oil production or natural gas
production from an oil or gas FMP at a
given lease, unit PA, or CA over the
expected life of the metering equipment
that must be installed for that lease, unit
PA, or CA to achieve non-commingled
measurement.’’ This definition is
consistent with the intent behind the
definition of ‘‘economically marginal
property’’ established by this final rule.
The BLM also received comments
concerning its use of the term ‘‘royaltyfree use.’’ Specifically, a commenter
expressed concern that the terms
‘‘beneficial use’’ and ‘‘royalty-free use’’
were used interchangeably multiple
times in the preamble discussion of the
proposed rule, without any definitions
being offered for either term. The
commenter also noted that only the term
‘‘royalty-free use’’ was used in the
proposed rule itself, and no definition
was provided. The commenter
suggested a definition of ‘‘royalty-free
uses,’’ which specifically included all
equipment and facilities serving
directionally or horizontally drilled
wells that may be located off the lease.
The BLM agrees with the commenter
that it should not have used the two
terms interchangeably. The BLM should
have used the term ‘‘royalty-free use’’
rather than ‘‘beneficial use,’’ because the
former is more specific and more
applicable in the context of this rule.
For example, the term ‘‘beneficial use’’
sometimes refers to using produced
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water for other purposes, such as a
water source for livestock or for
enhancing vegetation regrowth during
reclamation, both of which have nothing
to do with production verification and
accountability.
The BLM did not, however, feel it was
necessary to provide a definition for
royalty-free use at this time. First, the
royalty-free use of oil or gas from
onshore Federal and Indian leases,
units, and CAs is governed by the
longstanding Notice to Lessees and
Operators 4A (NTL–4A) and the BLM
believes the concept to be well
understood by operators. Second, the
BLM plans to update its regulations
pertaining to the royalty-free use of oil
and gas as part of a separate
rulemaking—Waste Prevention,
Production Subject to Royalties, and
Resource Conservation (81 FR 6616)
(Waste Prevention Rule)—that will
provide additional clarity on the
royalty-free use of oil and gas from
onshore Federal and Indian leases. Until
such time as the Waste Prevention Rule
is finalized, for the purpose of this final
rule, the meaning of the term ‘‘royaltyfree use of oil and gas’’ will be
consistent with the royalty-free use of
oil or gas as currently defined in NTL–
4A. No changes were made to proposed
rule in response to this comment.
Section 3173.2 Storage and Sales
Facilities—Seals
Paragraphs (a) and (b) of § 3173.2
require any lines entering or leaving any
oil storage tank or storage facility to
have valves capable of being effectively
sealed during specific operational
phases—production, sales, water
draining, or hot oiling.
Paragraph (c) identifies the specific
types of valves that are not considered
‘‘appropriate valves’’ (i.e., valves that
must be sealed during the production
phase or the sales phase) and, as such,
are not subject to the requirements of
subpart 3173. These valves include
valves on production equipment; valves
on water tanks, so long as there is no
possibility of access to production;
valves on tanks contains waste or slop
oil; sample cock valves; fill-line valves
on certain marginal production tanks;
gas line valves; heating system valves;
pump valves; tank vent-line valves; and
sales, equalizer or fill-line valves on
systems where production may only be
removed through an approved metering
system.
Paragraph (d) prohibits tampering
with an ‘‘appropriate valve,’’ and
specifies that tampering may result in
assessment of civil penalties for
knowingly or willfully preparing,
maintaining, or submitting false,
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inaccurate, or misleading information
under Section 109(d)(1) of FOGRMA, 30
U.S.C. 1719(d)(1), and 43 CFR
3163.2(f)(1), or for knowingly or
willfully taking, removing, transporting,
using, or diverting oil or gas from a lease
site without valid legal authority under
Section 109(d)(2) of FOGRMA, 30 U.S.C.
1719(d)(2), and 43 CFR 3163.2(f)(2).
The BLM received many comments
on proposed § 3173.2. Several
commenters expressed concern with the
relationship between the general
prohibition against tampering under
§ 3170.4 of the proposed rule and the
specific prohibition against tampering
with any appropriate valve under
proposed paragraph (d) of this section.
One commenter, in particular, was
concerned that under the new
requirements the commenter would not
be able to perform maintenance on
valves without the procedure being
considered tampering or unauthorized
seal removal. Two other commenters
stated that the criteria for determining
what qualifies as tampering were
overbroad and ambiguous. They also
questioned if an unintentional act or
human error would be considered
tampering.
The BLM believes these comments
have merit and, as discussed previously,
has added a definition of the term
‘‘tampering’’ to § 3170.3 of the final rule.
As previously noted, ‘‘tampering’’
means any deliberate adjustment or
alteration to the meter or measurement
device, appropriate valve, or
measurement processes that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported. This definition
should help the public understand how
the BLM will determine whether a
particular incident constitutes
tampering.
As for operator maintenance on
valves, such acts will not be considered
tampering as long as the maintenance
work does not alter the valve or
introduce bias into the measurement. If
the valve being worked on falls under
the seal requirements (i.e., it is used in
the process for determining the quantity
or quality of oil for royalty purposes), it
is permissible to remove the seal for
maintenance purposes as long as the
specific reason for removing the seal is
noted in the seal record. The BLM did
not change the final rule to address this
comment.
Another commenter stated that valves
would need to be changed out in
response to the requirements under this
section, making marginal wells
unprofitable. The BLM does not believe
that any valves will need to be changed
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out because these requirements are the
same as those in Order 3, which already
requires all appropriate valves capable
of being effectively sealed to be sealed.
Since this provision merely continues
existing requirements, no changes to the
final rule were made in response to this
comment.
Another commenter was concerned
that proposed § 3173.2(c)(3), which
exempts valves on tanks that contain oil
that the AO or authorized representative
(AR) has determined to be waste or slop,
would impose additional costs on
operators because of the time it could
take the AO or AR to make the
determination. While waiting for the AO
or AR determination, the commenter
said, operators would have to spend
money on additional tanks to store their
slop or waste oil. The BLM disagrees.
This requirement is very similar to the
existing requirements of Order 3, and
therefore will not impose any additional
burdens on operators. A company will
not need a new tank while waiting for
a determination from the AO or AR;
rather the company will have to
properly seal any tanks holding such oil
until it is determined to be slop oil or
waste oil. The cost to obtain a seal
should not present any sort of monetary
hardship for the operator. Thus, the
BLM did not make any changes in
response to this comment.
Section 3173.3 Oil Measurement
System Components—Seals
Section 3173.3 of the final rule
identifies a nonexclusive list of the
components used in LACT meters or
Coriolis oil measurement systems (CMS)
that must be effectively sealed to
indicate whether tampering may have
occurred. The BLM received a few
comments on this section of the
proposed rule.
One commenter stated that the
proposed seal requirements are much
more extensive than those in Order 3
and will create additional burden and
expense for the operator because seals
routinely break and the seal-reporting
requirements for these instances under
§ 3173.9 are fairly detailed. In addition,
the commenter said there is a risk of
delayed revenue while the operator
waits for the AO to approve removal of
a seal. The BLM disagrees that the seal
requirements are much more extensive
than those found in Order 3. This final
rule adds only four items to the Order
3 list of components that are used for
quantity or quality determination of oil
and that must therefore be effectively
sealed. Those four additional
components are the right-angle drive,
totalizer, prover connections, and valves
on diverter lines larger than 1 inch in
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nominal diameter. The BLM does not
believe seal requirements for these
components are particularly
burdensome, and, since they all are
points where tampering could occur, it
is important that they be subject to the
same sealing requirements as other
components of the measurement system.
As for the commenter’s concern about
revenue being delayed while an
operator waits for the AO to approve
removal of a seal—under normal
circumstances, there is no need to wait
for AO approval to remove a seal. Seals
may be taken off and put back on as
long as these events are recorded in the
seal record. In the event a Federal seal
is placed on a component, the AO must
provide approval prior to any removal;
however, an AO can provide verbal
approval to remove a Federal seal as
soon as the associated violation is
corrected. These comments did not
result in any changes to the final rule.
One commenter said they could not
determine what effect proposed § 3173.3
would have on their operations when
related requirements—contained in the
rulemaking that is replacing Order 4 (oil
measurement)—had not yet published
or been made available for public
comment. The additional requirements
cross referenced in proposed § 3173.3
can be found in proposed 43 CFR
3174.8(a) (for LACT systems) and
proposed 43 CFR 3174.9(e) (for Coriolis
systems). The BLM recognized the need
for both sets of requirements to be
available for public comment at the
same time, which is why the comment
period for this proposed rule was
extended from its original September
11, 2015, closure date until December
14, 2015, in order to ensure there was
sufficient overlap between the comment
periods for the proposed rules for
subparts 3173, 3174, and 3175. This
overlap gave operators an opportunity to
review the parts of proposed subpart
3174 that were referenced in § 3173.3.
This comment did not result in any
changes to the final rule.
Another commenter said that the seal
requirements for oil measurement
systems are only appropriate at those
points where theft or mishandling can
realistically occur, and the requirements
under this section are unnecessary. The
commenter suggested that the BLM
maintain the seal requirements in Order
3, which address the sealing of tanks
when oil is sold through a LACT. The
BLM did not make a change in response
to this comment. The BLM does not
believe that theft or mishandling, which
affects only the quantity of the oil being
measured, are the only factors that may
impact the determination of royalties
owed. The quality of the oil being
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produced will also influence royalty
determination. For this reason, the BLM
believes it is necessary to have a section
in the rule dedicated to ensuring that all
components of an oil measurement
system that are used to determine the
quality and quantity of oil must be
effectively sealed. The BLM does agree
with the commenter’s suggestion that
we maintain Order 3’s seal
requirements, which is why they were
incorporated into the list of components
that must be sealed under § 3173.3 of
this final rule.
The BLM also received several
comments stating that some components
of a LACT are not capable of being
sealed, such as flow computers and back
pressure valves. The commenters said
flow computers are not capable of
accepting a seal and back-pressure
valves cannot operate if they are sealed.
These commenters recommended that
the BLM not subject these two
components to the § 3173.3 sealing
requirements. A third commenter stated,
without providing specifics, that some
of the devices listed in this proposed
section are not constructed to be sealed.
The commenter suggested that sealable
components would have to be
purchased or a secondary device would
have to be built to allow for sealing.
Without more specific information, the
BLM cannot address this comment.
However, prior to issuing this final rule,
the BLM re-assessed the components
listed in this section and continues to
believe, except as noted below, that all
of the identified components can
reasonably be sealed, as all of them are
routinely sealed today.
With regards to requiring flow
computers to follow this final rule’s seal
requirements, commenters should be
aware that the intent of sealing the flow
computer is to have a log of when
someone accesses the software. Sealing
a flow computer could be accomplished
through a lead wire seal, adhesive
backed paper (sticker), or plastic seal, or
a password and an event log. However,
in response to this comment, the BLM
has changed the final rule. The BLM
removed flow computers from
paragraph (a)(5) of this section and
added a new item to the list—LACT or
CMS—in paragraph (a)(6), giving the
operator the opportunity to decide how
best to ensure that the flow computer is
sealed. As a result of these changes,
paragraphs § 3173.3(a)(6) through (12) in
the proposed rule are redesignated as
§ 3173.3(a)(7) through (13) in the final
rule.
As for concerns raised about the
inability to seal back-pressure valves,
the BLM has made a change in response
to this comment. In 3173.3(a)(7) of the
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final rule (§ 3173.3(a)(6) in the proposed
rule), the BLM has clarified that the
component that is subject to the seal
requirement is the back pressure valve
pressure adjustment. Sealing the
pressure adjustment on the backpressure valve was already required
under Order 3. The BLM believes it is
important to preserve this requirement
because if the pressure adjustment is
changed after a meter proving, it could
change the flow rate of hydrocarbons
through the meter, impacting the
accuracy of the measurement based on
the prior proving.
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Section 3173.4
Federal Seals
In the final rule, paragraph (a) of
§ 3173.4 codifies the authority in section
IV of Order 3, which calls for the BLM
to place a Federal seal on any
appropriate valve, sealing device, or oil
meter system component that does not
comply with the requirements of final
§§ 3173.2 or 3173.3. Paragraph (b)
clarifies that the placement of a Federal
seal does not relieve the operator of the
requirement to comply with §§ 3713.2
or 3173.3. Paragraph (c) prohibits the
removal of a Federal seal without BLM
approval.
The BLM received several comments
requesting that Federal seals not be
attached immediately upon discovery of
a violation that warrants placement of a
seal. Two commenters requested a 10day notice prior to the BLM placing a
Federal seal, and another commenter
requested that a reasonable time be
given to bring the component into
compliance prior to the BLM attaching
a Federal seal. Other commenters said
the BLM should not be sealing or
changing valves or any other production
components without an operator’s
representative being present to witness
the change. Commenters recommended
that the BLM give notice to the operator
as to why the seal was placed, and the
procedure for removing the seal.
The BLM did not change the final rule
in response to these comments because
the only violations that would cause the
BLM to place a Federal seal on valves
or production equipment would be
those that are considered major, as
defined in 43 CFR 3160.0–5—that is,
noncompliance actions that could cause
or threaten immediate, substantial, and
adverse impacts on health and safety,
the environment, production
accountability, or royalty income. Since
the seal requirements in §§ 3173.2 or
3173.3 of this final rule were put in
place to ensure that tampering does not
occur, the BLM generally believes these
incidents of noncompliance constitute
major violations.
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However, the BLM believes that some
of the commenters’ concerns have merit,
and will ensure that its Inspection and
Enforcement Handbook provides clear
guidance to BLM inspectors that: They
must not change the position of a valve
or component; the Federal seal must be
attached to the valve or component as
found; and each Federal seal installed
must have a card attached that identifies
it as a Federal seal, and advises that the
removal or violation of the seal without
approval by the AO will result in an
immediate assessment of $1,000. The
name and telephone number of the AO
will be shown on the card. In addition,
the operator will also receive notice in
the form of an INC that will address all
the violations associated with the
Federal seal that the operator must
correct prior to removal of the seal. The
BLM did not make any changes to the
final rule in response to this comment.
Section 3173.5 Removing Production
From Tanks for Sale and Transportation
by Truck
Section 3173.5, paragraphs (a) and (b),
of the final rule make clear that, at the
completion of either a single or a
multiple truckload sale, the driver of the
load(s) must possess all the information
that is required in § 3174.12. Under
paragraph (c), once the seals are broken,
the purchaser or transporter is
responsible for the entire contents of a
tank until it is resealed.
The BLM received a comment asking
us to delay this final rule until we
publish and make available for public
comment two related rulemakings that
will replace Orders 4 (subpart 3174) and
5 (subpart 3175). The commenter noted
that § 3173.5(a) and (b) require truck
drivers to possess certain information
after oil sales, but the information will
be set forth in § 3174.12, which was
proposed in the separate Order 4. The
BLM recognizes the commenter’s
concern, at least as it relates to the
proposed rule to replace Order 4, which
is why the comment period for this
proposed rule was extended from its
original September 11, 2015, closure
date until December 14, 2015, to ensure
there was sufficient overlap between the
comment periods for the proposed rules
for subparts 3173, 3174, and 3175. This
overlap gave operators an opportunity to
review the parts of proposed subpart
3174 that were referenced in § 3173.5.
This comment did not result in any
changes to the final rule.
Several commenters expressed
concern with language in paragraph (c)
that makes the purchaser or transporter
responsible for the entire contents of the
oil tank from the time that the seals are
broken until it is resealed. The
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requirements in paragraph (c) are taken
directly from Order 3 with one minor
modification. Under section III.C.1.c of
Order 3, only the ‘‘purchaser’’ is
responsible for the entire contents of the
unsealed tank during a sale. The
commenters stated that § 3173.5(c)
would be a burden on transporters
because it will cost them time and
money to wait on-site for tanks to be
resealed by the facility’s operator after
an oil sale. The BLM disagrees with this
comment. It is standard practice for
transporters, whether or not they are the
purchasers, to remove and replace seals
without the operator’s representative
being on location. Transporters do this
because it protects them from liability if,
subsequently, produced oil cannot be
accounted for. No changes were made to
the final rule as a result of this
comment.
Section 3173.6 Water-Draining
Operations
Section 3173.6 of the final rule
requires the operator, purchaser, or
transporter, as appropriate, to record
specific information when water is
drained from tanks that hold
hydrocarbons, including the total
observed volume (TOV) and free water
that are in the tank before, and TOV
after, water is drained. Order 3 did not
require operators to record these
volumes, which could have led to
hydrocarbons being drained with the
water and removed without proper
measurement and accounting, and
without royalties being paid.
The BLM received many comments
regarding this section. Several
commenters stated that the
documentation requirements were
excessive and added little to no value to
accounting for production. The BLM
made several changes in response to
these comments, to reduce
documentation requirements and
eliminate any confusion over when
operators should document the FMP
number during water-draining
operations. Specifically, the BLM
reduced the overall amount of
information that operators must
document by eliminating from this
section the requirements that operators
record the opening and closing gauge
times, the name of the person and
company draining the tank, and the
FMP number associated with the tank.
Another commenter questioned
whether the requirement to identify the
FMP associated with a tank subject to
this provision would mean that an FMP
is required for each condensate tank in
the field. By way of clarification,
condensate tanks, just like oil storage
tanks, must have FMP numbers.
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However, oil and condensate tanks that
are part of a tank battery share the same
FMP number.
Another commenter recommended
that the BLM exempt ‘‘low-volume
sources’’ from the requirements, to
reduce the paperwork and recordmaintenance costs for operators of such
sources. The BLM does not believe that
an exemption for small producers (or
operators of low-volume sources) is
appropriate and did not change the final
rule as a result of this comment. As
noted earlier, it is important for all
operators to ensure that hydrocarbons
are not being drained with the water
and removed without proper
measurement and accounting, and
without the royalties due being paid.
Having operators record the volume of
hydrocarbons that are in the tank before
and after water is drained helps ensure
that the proper royalties are paid. When
performing production accountability
inspections, the BLM will compare
these water-draining records, along with
other production and sales records, with
production reports that operators submit
to ONRR. These records will allow the
BLM to independently verify
production that is attributable to Federal
and Indian leases. The BLM did not
make any changes in response to this
comment.
One commenter said the existing
Order 3 seal requirements already
prevent theft of oil because they provide
a tracking mechanism for the transfer of
any liquids from production tanks, and
therefore the provisions of the proposed
rule were unnecessary. The BLM
disagrees that Order 3’s seal
requirements already prevent theft of
oil. Existing requirements related to seal
records do not provide any information
on how much TOV is in a tank before
and after water is drained. They merely
show when a tank is sealed and
unsealed, and by whom, not what was
drained, nor how much was removed
from the tank. No changes were made to
the final rule as a result of this
comment.
Other commenters stated that § 3173.6
would require the gauging of tanks prior
to and after a sale. They said that while
such a practice is necessary during
custody transfer, this requirement could
be hazardous to employees because it
would unnecessarily expose them to
benzene or volatile organic compounds
(VOC). In response to these comments,
the BLM added new language to
paragraphs (e) and (g) that allows either
manual or automatic gauging for the
opening and closing gauge, TOV, and
free-water measurements, all of which
must be to the nearest 1⁄2 inch. Giving
operators the option of conducting this
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measurements using automatic gauging
will provide an opportunity for
operators to reduce employees’
exposure in the field.
Finally, one commenter said the
color-cut measurement method
requirement in the proposed rule is not
accurate for indicating water oil contact
with heavy oils that are less than 30
degrees gravity. The commenter said
that an opening and closing gauge
would be a sufficient indicator to
determine the amount of water in the
tank. The BLM agrees with the comment
that color-cut measurements are not
accurate in some situations and has
removed this requirement from the final
rule. Instead, paragraph (e) has been
rewritten to require operators to simply
document ‘‘free-water measurements,’’
which allows operators to use any
reliable method for measuring free
water, including electronic equipment.
Section 3173.7 Hot Oiling, Clean-Up,
and Completion Operations
Section 3173.7(a) of the final rule
requires that specific information be
recorded when hydrocarbons are
removed from storage and used on the
lease, unit PA, or CA for hot oiling,
clean-up, and completion operations,
including the volume of hydrocarbons
removed from storage and expected to
be returned to storage. Paragraph (b)
requires operators to consider as sold,
and to measure following the
requirements of this final rule, any
production used from storage for hot
oiling, line flushing, or completion
operations on a different lease, unit PA,
or CA.
Under Order 3, the operator was
required to record only the date, seal
number removed, new seal number
installed, and the reason for removing
oil for hot-oiling, clean-up, or
completion operations. The operator
was not required to record the volume
of hydrocarbons that was removed from
storage and were expected to be
returned. This omission could have led
to the volume of produced
hydrocarbons being counted twice—first
when it was initially produced then
later after it was returned to storage.
The BLM received many comments
on this requirement. A few commenters
said that an operator’s field personnel
are on hand, closely monitoring these
types of operations, ensuring that the oil
is returned to the tank and that it is
counted just once. Commenters said
there is no reason for the BLM to require
operators to maintain records of these
volumes because operators only pay
royalties on oil that is sold, not oil that
is produced, and hot-oiling, clean-up,
and completion operations are unrelated
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to sales. The BLM agrees that having an
operator’s field personnel on hand,
closely monitoring these operations, is
ideal for ensuring that oil is not counted
twice during these operations. However,
the BLM’s experience has shown that in
many instances field personnel do not
monitor these operations because they
are called away for other duties. The
BLM did not change the final rule in
response to this comment, because the
BLM believes there is a need to address
inconsistent practices among operators
and to ensure there is proper
documentation of the volume of oil used
in these operations.
In response to the comment that hot
oiling, clean-up, and completion
operations have nothing to do with sales
volumes, the BLM notes that it is
required to verify not only sales
volumes but also production volumes
and to report on avoidably lost gas
under NTL–4A. Hot oiling, clean-up,
and completion all involve production
volumes, and therefore are properly
within the scope of the proposed rule.
Another commenter said the BLM
does not have the authority to impose
the requirements under this section,
requested that the BLM explain why
these new requirements are necessary,
and asked that we provide the legal
citation for the new law that justifies
this authority. The BLM’s authority to
impose site-security, record-keeping,
and production accountability
requirements for the production of
Federal and Indian oil and gas is not
‘‘new.’’ The statutes authorizing the
BLM to issue this rule have been in
place for decades and were identified
earlier in this preamble. These statutes
include the ones that were identified as
the basis for existing Order 3.
A few commenters said that the
requirement that operators gauge oil
level, maintain seals, track FMPs, gauge
tanks, etc., during completion
operations will add to the workload of
field personnel performing those tasks.
For example, an employee will need to
be onsite 24 hours a day, 7 days a week
to make sure the seal changes are
recorded on the run tickets and logged
properly for tracking purposes. Several
commenters said the documentation
requirements under this section were
excessive and added little to no value to
production accounting.
The BLM agrees with these
commenters that the proposed
documentation requirements were too
expansive and in response changed the
final rule to reduce the amount of
information that operators must
document during hot oiling, clean-up,
and completion operations. In the final
rule, the BLM removed requirements
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that operators document the opening
and closing gauge times; the name of
person and company removing
production from the tank; and the FMP
number associated with the tank or
group of tanks. The BLM has accounted
for the costs of these revised
recordkeeping requirements in its
Paperwork Reduction Act analysis,
which we discuss later in this preamble,
and concludes that they are not a
significant financial burden on
operators.
With respect to the general concern
that these requirements are unnecessary,
the BLM does not agree. These
requirements are important and
represent an important part of the final
rule, because in their absence, operators
could drain, transfer, or sell
hydrocarbons without measuring and
accounting for them during hot oiling,
clean-up, and completion operations,
resulting in incorrect royalties being
paid. The BLM will use these records
when performing production
accountability inspections. Specifically,
it will compare records from hot oiling,
clean-up and completion operations,
and other production and sales records,
with reports that operators submit to
ONRR. This will allow the BLM to
independently verify production that is
attributable to Federal and Indian
leases.
As for the commenter’s claim that
these recordkeeping requirements for
well completion operations would
necessitate an operator’s field personnel
to be present at the wellsite 24/7, the
BLM does not have enough information
to respond to this comment. While the
BLM agrees that, in general, operators
will now have to document more
information than they have been
documenting under Order 3, the BLM
does not believe that any of these
additional recordkeeping requirements
will require company personnel to be
onsite 24/7. The final rule was not
changed as a result of this comment.
The BLM did not receive any
comments on paragraph (b). However,
the BLM makes a clarification in the
final rule that the production reported
to ONRR as sold must be ‘‘for the period
covering the production in question.’’
Section 3173.8 Report of Theft or
Mishandling of Production
Section 3173.8 of the final rule
includes security provisions that are
intended to prevent theft or
mishandling of oil, complementing the
minimum standards for site security and
production handling established in this
rule. Paragraph (a) requires operators,
transporters, and purchasers to report
verbally all incidents of theft and
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mishandling of production to the BLM
no later than the next business day after
they or their employees discover them.
Paragraph (b) specifies the information
that must be included in a written
incident report, which is required
within 10 business days of any oral
report. Such reports must be made the
next business day after discovery and
may be made orally or through a
‘‘written incident report.’’ Oral reports
must be followed by written reports
within 10 business days. Adding
purchasers and transporters to these
requirements is a change from Order 3,
which required only operators to report
theft or production mishandling, but is
consistent with the overall approach to
these requirements in the proposed and
final rules.
Many commenters were concerned
about the requirement in paragraph (a)
that purchasers and transporters report
incidents of theft and mishandling to
the BLM, and questioned the BLM’s
authority to impose such a requirement
on them. Since the wells and facilities
belong to the operator, commenters said,
the operator should be the one reporting
all theft and production mishandling.
The commenters said it would be
redundant and unnecessary to have
purchasers and transporters reporting
theft and mishandling to the BLM, and
could lead to multiple reports and
confusion. A few commenters added
that this change could make operators
accountable for potentially arbitrary and
inaccurate third-party reports of theft or
production mishandling.
Finally, some commenters asked why
operators could be subject to an
immediate assessment when they fail to
report theft or mishandling to the BLM.
The BLM believes it is necessary to
require purchaser and transporters, in
addition to operators, to report instances
of theft or production mishandling
when they discover them because, as
noted in the proposed rule preamble,
purchases and transporters are
sometimes the first to discover such
instances or to recognize suspicious
activity. When transporters or
purchasers report theft or production
mishandling, the BLM intends to work
with transporters, purchasers, and
operators to verify the reports, with each
party being responsible for the
information it provides. The BLM’s
authority to require purchasers and
transporters to report theft or
production mishandling comes from
Section 103(a) of FOGRMA, which
provides that ‘‘a lessee, operator, or
other person directly involved in
developing, producing, transporting,
purchasing, or selling oil or gas . . .
shall establish and maintain any
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records, make any reports, and provide
any information that the Secretary may,
by rule, reasonably require for the
purposes of implementing this Act or
determining compliance with rules or
orders under this Act.’’ Sections
102(b)(2) and 301(a) of FOGRMA allow
the BLM to prescribe any rules,
regulations, or appropriate measures to
protect oil from theft. The final rule
simply places the same expectations on
purchasers, transporters, and operators,
which are all parties involved in
production, for reporting theft and
mishandling of production.
The BLM does not agree that requiring
purchasers and transporters to report
theft and production mishandling
creates confusion or is redundant and
unnecessary. Reports by purchasers and
transporters, together with information
provided by operators, will improve the
existing reporting system by giving the
BLM more facts faster to investigate
these situations. No changes were made
to the final rule as a result of these
comments.
Other commenters discussing the
provisions of the proposed rule related
to theft or mishandling did not agree
with the BLM’s decision to eliminate
the self-inspection requirements
contained in Order 3 section III.F,
which are related to Order 3’s
requirements for reporting theft or
mishandling of oil. The purpose of the
self-inspection requirement, according
to those commenters, was for operators
to periodically measure production
volumes to assure that they complied
with the BLM’s minimum site security
requirements. These commenters said
that self-inspection programs are a good
practice, and that it would not be
appropriate for the BLM to find an
operator in violation of this section if
they elect to implement a selfinspection program and report
incidences of theft and mishandling.
The commenters encouraged the BLM to
maintain the Order 3 requirements for a
self-inspection compliance program,
rather than eliminate them.
It has been impractical for the BLM to
enforce the Order 3 self-inspection
requirements because the requirements
were vague, and the BLM never
supplemented them with internal
guidance or enforcement policy. This
final rule replaces the Order 3 selfinspection program with stronger
recordkeeping and documentation
requirements, such as those in § 3173.9
(Required recordkeeping for inventory
and seal records). As explained in the
recordkeeping section of this preamble,
we believe this approach will ultimately
improve overall production verification
and accountability. That said, the BLM
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does not disagree with the notion that
self-inspection programs can help with
a company’s internal compliance efforts,
and nothing in the final rule would
prohibit a company from implementing
such a program on its own initiative. No
changes were made in response to this
comment.
As for the commenters’ suggestion
that the BLM not issue immediate
assessments or take enforcement actions
against those operators who are
implementing a self-inspection program,
the BLM does not agree with this
suggestion. The BLM takes enforcement
actions against operators that fail to
report theft or production mishandling.
The fact that an operator has a selfinspection plan in place does not and
should not immunize the operator from
enforcement for a failure to report.
Under the final rule, consistent with the
proposed rule, an operator that fails to
report is subject to an immediate
assessment under § 3173.29 (Immediate
Assessments) of the final rule. No
change was made in response to this
comment.
Finally, a number of commenters
suggested that the BLM should be told
whether incidents of theft or production
mishandling have also been reported to
law enforcement and company security
in addition to the BLM. The BLM agrees
that it needs to know if law enforcement
and company security have been
notified and added a new paragraph
(b)(8), which now includes this
requirement. This change will help the
BLM work with company security and
law enforcement to investigate and
prosecute alleged incidents of theft and
production mishandling in order to
prevent future occurrences.
Section 3173.9 Required
Recordkeeping for Inventory and Seal
Records
Paragraph (a) of this section of the
final rule requires operators to perform
an end-of-month inventory consisting of
the TOV in storage (measured to the
nearest 1⁄2 inch), subtracting free water,
and the volume not corrected for
temperature/S&W, as reported to ONRR
on the OGOR. Paragraph (b) specifies
the records that an operator must
maintain for each seal.
The BLM received several comments
on proposed § 3173.9. In the proposed
rule, operators were simply required to
measure and record the TOV in storage
at the end of each calendar month. A
few commenters said they did not have
the ability to measure inventory at all
sites on the actual last day of the month
due to the number of tanks they operate,
the volume corrections for temperature/
S&W, and the accuracy needed to meet
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the measurement standards of this
section.
The BLM agrees that operators may
not be able to measure all inventory on
the very last day of the month,
especially those operators who have
large numbers of storage tanks. In
response, the final rule provides two
options for an operator to perform an
end-of-month inventory. The operator
can either perform the measurements
within +/¥3 days of the end of the
month, or it can interpolate the values
based on daily production values and
gross sales volumes, using inventory
measurements taken before and after the
final day of the month. To help guide
operators on the interpolation of their
end-of-month inventories, the BLM
provides the following equation in
paragraph (b)(2) of this section, as well
as an example of how the equation is to
be applied:
{[(X + Y¥W)/Z1] * Z2} + X = A,
Where:
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and
second inventory;
Z1 = number of actual days produced
between the first and second inventory;
and
Z2 = number of actual days produced
between the second inventory and end of
calendar month for which the OGOR
report is due.
These alternate approaches to
maintaining inventories give operators
more flexibility to meet the BLM’s
recordkeeping requirements, but still
ensure monthly volume measurements
are recorded.
Other commenters interpreted the
proposed section to mean that operators
were required to gauge their storage
tanks manually, since at the time the
proposed rule was released the BLM’s
oil measurement regulations did not
allow operators to use automatic tank
gauging systems. As a result, these
commenters asserted that requiring
operators to manually gauge tanks
would unnecessarily expose their
employees to hazardous fumes. The
BLM understands this concern and has
added clarifying language to the final
rule that allows operators to measure
TOV either manually or with automated
systems. The BLM was able to make this
change because in the related
rulemaking that is replacing Order 4
with a new subpart 3174, operators now
have the ability to use automatic tank
gauging systems for oil sales, and thus
such a system will also be permissible
for inventory maintenance.
Other commenters said this section
was not necessary because recording the
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81383
TOV in tanks is routine practice under
sales contracts, and the seal
requirements in paragraph (b) of this
section are unnecessary because they
are already covered in §§ 3173.2 and
3173.3 of the proposed rules. With
respect to those comments stating that
recording the tank TOV is routine
operator practice under sales contracts,
it should be noted that those
recordkeeping activities relate to
periodic tank sales. Those records do
not allow the BLM or the operator to
determine monthly production or to
detect theft or improper handling of
production like an end-of-month
inventory does. Additionally, operators
are already required to report end-ofmonth inventories to ONRR so this
requirement should not create an
additional burden for operators. The
BLM did not change the final rule in
response to this comment.
With respect to the concerns about
paragraph (b), the BLM disagrees that
the seal recordkeeping requirements are
already covered in §§ 3173.2 and
3173.3. Those two sections only identify
which valves or components must be
sealed. They do not address the
recordkeeping requirements associated
with such seals. The BLM did not
change the final rule in response to this
comment.
Finally, some commenters asserted
that paragraph (b) should not apply to
purchasers and transporters because
they are not responsible for installing or
maintaining such seals. The BLM agrees
that § 3173.9, particularly paragraph (b),
does not apply to purchasers and
transporters. However, the BLM did not
change the rule in response to this
comment because the text in § 3173.9
makes clear that its requirements apply
solely to operators.
Section 3173.10 Form 3160–5, Sundry
Notices and Reports on Wells
Section 3173.10, paragraphs (a) and
(b), require all parties involved in
Federal and Indian oil and gas
production to submit Sundry Notices,
Form 3160–5, electronically to the BLM
for their site facility diagrams, requests
for FMP designations, requests for
CAAs, requests for off-lease
measurement, and any amendments to
the diagrams or requests. As noted in
the preamble of the proposed rule,
requiring electronic submission will, in
the long run, increase efficiencies
throughout BLM field offices, for both
the BLM and operators, by making the
diagrams easier to track and more
accessible to inspectors in the field.
Paragraph (b) provides an exemption
from the electronic-filing requirement
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for small operators that do not have
access to the Internet.
Several commenters supported the
proposed requirements for online filing,
but were concerned with the BLM’s
ability to handle a significant increase
in electronic submissions ‘‘at one time,’’
and wanted the BLM to clarify what it
means when it says that this change
will, in the long run, increase BLM
efficiencies. Some of these same
commenters said they were concerned
with the ability of the BLM’s existing
WIS to handle this volume of
submissions.
Requiring electronic submission of
Sundry Notices and Reports on wells
provides both operators and the BLM
with an efficient chronological method
for tracking items submitted for
approval, rather than relying on hard
copies. The BLM is aware that the Well
Information System has had problems in
the past, and is working on an improved
version of its in-house database, known
as AFMSS II. As part of its transition to
AFMSS II, the BLM is evaluating
industry information technology
standards, such as XML, to develop a
system that will make data sharing and
management as seamless as possible
between the BLM and the public. That
said, even the existing system should
not prevent the BLM from realizing the
benefits of electronic filing of facility
diagrams.
One of the reasons the proposed rule
gave operators a phase-in period to
apply for an FMP on existing leases,
units, and CAs was to help the BLM
avoid having to process a flood of
Sundry Notices at one time. Under the
proposed rule, operators would have
applied for their FMP numbers over a 9to 27-month period, starting on the
effective date of the final rule, on a
tiered scheduled based on production
level, with the highest producing wells
having the earliest required application
date. As discussed later in this
preamble, the final rule extends the
phase-in periods for the FMP
application process to 12, 24, and 36
months, based on production level
thresholds that are similar to those in
the proposed rule. This will give some
operators up to 3 years after the effective
date of this final rule to apply for an
FMP for stand-alone leases, CAs, unit
PAs and CAAs. If a stand-alone lease,
unit PA, or CA has not produced for a
year or more before the effective date of
this final rule, the operator will not
need to apply for an FMP until
resuming production. The BLM believes
that these changes will substantially
reduce the number of electronic filings
the BLM must process at any one time,
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reducing the risk that its systems lack
the capacity to handle the submissions.
Similarly, and as explained below in
connection with § 3173.11(d) and (e),
the BLM has also modified the proposed
rule’s requirements for updated site
facility diagrams. Instead of requiring all
facilities to upgrade their diagrams with
30 days of receiving an FMP, as was
suggested in the proposed rule, under
the final rule site facility diagrams at
existing facilities will only have to be
updated when or if the existing facility
is modified (e.g., when equipment or
wells are added or removed, when colocated facilities are added, or when
there is a change in operator). This
change reduces the overall number of
Sundry Notice submissions associated
with site facility diagrams and helps
distribute notice submissions over time.
Some commenters wanted to know if
the BLM will send out electronic
notifications when it approves Sundry
Notices that have been filed
electronically. The BLM will provide
such notifications, just as it does now as
part of its new APD system.
One commenter suggested that the
BLM use off-the-shelf software common
to industry to handle its electronic data
submissions, saying it would reduce
reporting costs to industry since these
programs are already used industrywide. The BLM disagrees because the
BLM already has an existing e-filing
system up and running, and operators
are already familiar with using it. This
system allows operators to see the status
of their submissions and provides them
an electronic response of the AO’s
decision. The AFMSS II update builds
on this existing infrastructure. The BLM
did not change this final rule as a result
of these comments.
Section 3173.11 Site Facility Diagrams
As discussed in the proposed rule, the
requirements in § 3171.11 update and
replace Order 3’s Site Facility Diagram
requirements, which are currently found
in section III.I. Paragraphs (a) through
(c) of § 3171.11 set forth the
requirements for the content and format
of site facility diagrams, while
Appendix A to subpart 3173 provides
some basic examples of what these
diagrams should look like.
Under § 3173.11(a) through (c), a site
facility diagrams must include, in
addition to drawings that show the
relative locations of equipment, specific
information, such as FMP numbers; the
land description; unit PA, or CA
numbers; site equipment; and royaltyfree use information. Site facility
diagrams are one of the BLM’s primary
mechanisms for ensuring that operators
are complying with measurement
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regulations and policy, which is why it
is important that accurate diagrams are
submitted to the BLM in a timely
manner.
As explained in the preamble to the
proposed rule, under Order 3 the BLM
required operators to provide
generalized diagrams showing each
piece of equipment being used at a
facility, including connections between
each piece of equipment, valve
positions on production storage tanks
(sales valves, drain valves, equalizers,
and overflow valves), and their relative
positions to each other. While these
diagrams were useful to the BLM, they
did not provide all of the information
necessary for inspection and
enforcement activities. The more
detailed information required by this
final rule will provide the BLM with a
more useful tool to achieve improved
production accountability.
For example, the requirement in
paragraph (c)(9) of this final rule
(paragraph (c)(10) in the proposed rule)
will allow the BLM, for the first time, to
verify royalty-free-use volumes that
operators report on their OGORs. This
paragraph requires operators to specify
on their site facility diagrams which
equipment on the lease is using oil or
gas royalty-free and how they determine
the volumes of oil or gas used by that
equipment, if the volume is not
measured. This requirement will
provide greater consistency in how
operators determine the volumes of oil
and gas used royalty-free, and will
enable the BLM to more easily verify
those volumes, which enhances
production accountability. This
particular change also responds to the
GAO recommendations (Report 10–313)
that the BLM establish uniform systems
for collecting and tracking information
about royalty-free use in order to ensure
that such use can be properly verified.
Affirmatively requiring this information
to be reported on a site facility diagram
will ultimately save the BLM and
operator time because it will eliminate
the need for the BLM to obtain the
information in connection with a
production accountability review.
Paragraph (d) sets forth the timeframe
within which facilities that are required
to obtain an FMP under § 3173.12 must
submit a site facility diagram that
complies with this rule. It covers both
existing and new facilities. Paragraph
(d)(1) in this final rule (paragraph (c)(1)
in the proposed rule) requires operators,
whose facilities become operational on
or after the effective date of this rule to
submit their diagrams within 30 days
after the BLM assigns their FMP. For
operators of existing facilities that were
in operation on or before the effective
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date of this rule, paragraph (d)(2)
explains that such facilities are not
initially required to submit an updated
site facility diagram if they already have
one on file with the BLM that meets the
minimum requirements of Order 3.
These operators are only required to
submit an updated site facility diagram
consistent with the requirements of this
final rule if and when the operators
modify their facilities, construct or
modify a non-Federal facility located on
their Federal lease or federally approved
unit or communitized area, or if there is
a change in operator.
Paragraph (e) sets forth the timeframe
within which facilities that do not
require FMP numbers under § 3173.12
(e.g., facilities that dispose of produced
water) must submit a site facility
diagram that complies with this rule. It
covers both existing and new facilities.
Paragraph (e)(1) requires operators of
facilities that become operational after
this rule’s effective date to submit their
diagrams within 30 days after the
facilities become operational. For
operators of facilities in operation on or
before the effective date of this rule that
do not require an FMP, paragraph (e)(2)
in this final rule explains that such
facilities are not initially required to
submit an updated site facility diagram
if they already have one on file with the
BLM that meet the minimum
requirements of Order 3. These
operators are only required to submit an
updated site facility diagram consistent
with the requirements of this final rule
if and when the operators modify their
facilities, construct or modify a nonFederal facility located on their Federal
lease or federally approved unit or
communitized area, or if there is a
change in operator.
Paragraph (f) explains that operators
of facilities required to have a site
facility diagram have an ongoing
obligation to update those diagrams
within 30 days after the operator
modifies its facilities, constructs or
modifies a non-Federal facility located
on the Federal lease or federally
approved unit or communitized area, or
if there is a change in operator.
The BLM received many comments
on this section of the proposed rule.
One commenter suggested that the BLM
develop a database that allows operators
to submit the information needed for
site facility diagrams using a standard
form. The commenter said any changes
to a site facility diagram, along with
other information, could be
automatically and periodically
submitted by operators, thus making the
process of submitting and updating
diagram information to the BLM
effortless. The BLM recognizes the
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potential efficiencies provided by the
commenter, but did not make any
changes at this time because the BLM’s
WIS—which follows the Sundry Notice
format—is currently the only method for
electronic submission. At this time, that
system does not allow for submission
along the lines suggested by the
commenter. As result, the BLM will
accept electronic records that contain
the requested information on additional
pages as long as they are submitted with
the actual diagram on Form 3160–5
(Sundry Notices) and they follow the
prescribed numbering format. The BLM
did not change the final rule based on
this comment.
Many commenters expressed concern
that application of the proposed rule’s
site facility diagram requirements to
existing facilities is unnecessary, and
that the deadlines in the proposed rule
for submitting the diagrams would be
onerous. These commenters also said
the demands in this section are so
burdensome that they would cause
operators to reconsider future
development plans, after having
invested money in complying with
previous regulations.
Although the BLM believes the new
site facility diagrams for existing
facilities, including those that handle
waste water, will allow the BLM to
improve production accountability, the
BLM also believes that commenters’
concerns with the deadlines for
submitting the new diagrams have
merit. In response to these comments,
and in an effort to reduce the number of
diagrams that operators must initially
submit to the BLM, we have revised
paragraph (d)(2) (formerly paragraph (d)
in the proposed rule) and added a new
paragraph (e)(2) to the final rule which
specifies that operators of existing
facilities are not initially required to
submit updated site diagrams, so long as
they have a diagram on file that
complies with the requirements of
Order 3. As noted, these paragraphs
require updates to existing diagrams
only when facilities undergo changes.
The BLM believes that this change
addresses the identified concern, while
ensuring that as these existing facilities
undergo changes the agency will
eventually receive site facility diagrams
that meet the requirements of § 3173.11.
Although the existing site-facility
diagrams are not as detailed, the BLM
will continue to work off the diagrams
that it has on file to perform its
production accountability-related
inspections on existing facilities, until
such time as those diagrams are
updated.
Other commenters questioned why it
was necessary to provide a diagram for
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salt-water disposal facilities because,
they said, these facilities are unrelated
to actual oil and gas production
operations. The BLM does not agree
with this commenter. These diagrams
are not a new requirement. Operators
are already required to have site facility
diagrams on file with the BLM for their
water-disposal facilities; Order 3.III.I.1.
requires diagrams for ‘‘all facilities.’’
The BLM is responsible for accounting
for all production, including water, not
just oil and gas. No changes were made
to the final rule as a result of these
comments.
A few comments sought clarification
on how to legibly depict multiple wells
and headers, encompassing an area
several miles in size, on a single sheet
of 81⁄2 x 11 paper. The BLM did not
change the final rule based on these
comments because paragraph (b) in the
proposed and paragraph (c)(1) in the
final rule (paragraph (c)(2) in the
proposed) already state that, while
diagrams need to reflect equipment
locations, they need not be to scale, and
more than one page can be used, if
necessary. The Appendix to subpart
3173 provides examples of multi-well
submissions.
One commenter said the valvepositioning and labeling requirements
in paragraph (c) and the examples in the
Appendix would result in operators
putting redundant information on the
diagrams when multiple tanks, with
similar valves that are operated
similarly, are involved. The BLM did
not make a change in response to this
comment. The BLM cannot create a
single template that addresses how all
site facility diagrams, for a myriad of
field configurations, should be drawn.
The Appendix examples are meant to be
a starting point for operators. It is up to
the operator to determine how best to
identify valve positioning on paper, as
long as the valves and their positions
are identified, legible, and
comprehensible as required in
§ 3173.11.
The BLM received several comments
on the requirement in paragraph (c)(9)
of the final rule (paragraph (c)(10) of the
proposed rule) that operators identify on
their diagrams any equipment that uses
production royalty-free, and either the
calculated or measured volumes that are
used. Under the final rule, operators are
permitted to use any method they want
to determine their royalty-free use
volume, as long as they show on the
diagram how they determined it.
Several commenters pointed out that
royalty-free fuel use fluctuates monthly,
and one commenter even provided its
method for determining ‘‘on lease use
fuel gas.’’ The commenter recommended
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that the BLM consider letting operators
provide an average lease use fuel gas
estimate and questioned the need for
operators to report this information on
their diagrams since on-lease fuel gas is
already reported to the BLM. The BLM
did not change the final rule in response
to this comment. The commenter has
confused BLM and ONRR requirements.
Operators are required to report the
volumes of fuel used royalty-free to
power production equipment on a lease
to ONRR, not the BLM. In order to
enhance accountability, BLM field
inspectors need to be able to
independently verify royalty-free-use
volumes reported to the ONRR, using
the information in the diagrams
pertaining to the equipment that uses
the royalty-free oil and gas. Currently,
the BLM has no method for determining
whether the royalty-free use rate that
operators report on their OGORs is
accurate. This new requirement
enhances production accountability and
responds to key recommendations made
by the GAO (Report 10–313), as
explained above.
A few commenters questioned the
BLM’s rationale for creating the new
site-facility-diagram requirement, while
eliminating the Order 3 requirement for
site security plans, which some
operators had established. The BLM
agrees that these two requirements are
related. The site-facility diagram was
part of the larger site-security plan
required in Order 3. As discussed earlier
in this preamble, the Order 3 sitesecurity plan’s self-inspection
requirements are not in the final rule.
However, elements of the old site
security plan requirements have been
incorporated into this final rule at
§§ 3170.4 (Prohibitions against by-pass
and tampering), 3173.8 (Report of theft
or mishandling of production), 3173.9
(Required recordkeeping for inventory
and seal records), and 3173.11 (Site
facility diagrams); and into the final rule
that is replacing Order 4 at 43 CFR
3174.12 (Measurement tickets).
Many commenters questioned the
need for operators to provide
information and documentation on their
site facility diagrams, as required under
proposed § 3173.11, for what they
consider to be extraneous equipment
and components. Commenters offered to
work with the BLM to create a
pragmatic approach for allowing the
BLM to verify royalty-free volumes and
for operators to submit their diagrams
within a sensible time. However, as
proposed, many commenters saw this
section as unnecessary and
unreasonable overreach by the BLM,
and a drain on resources for both
operators and the agency, especially
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given that operators would need to track
information on multiple components on
numerous pieces of equipment across
several locations. For example, one
commenter did not understand how
putting equipment serial numbers, rated
fuel use, and manufacturer information
on a site facility diagram would help the
BLM verify whether a reasonable
determination was made on royalty-free
use volumes reported to ONRR.
Depending on their configuration,
production facilities can have an
extensive number of major components,
and requiring operators to track down
this information and report it on their
diagrams would cause a hardship on
many operators, commenters said.
Another commenter disagreed with
the requirement in proposed paragraph
(c)(11) that an operator or its
representative include a signed
certification statement on the diagram.
This requirement is redundant and
unnecessary, the commenter said,
because existing statutes—18 U.S.C.
1001 and 43 U.S.C. 1212—already make
it a crime for any person to knowingly
and willfully make a false statement to
the BLM.
The BLM agrees with these comments
and in response has made changes to
the final rule that reduce the
information that must be submitted and
expand the timeframe within which the
submission must occur, including
deleting paragraph (c)(11). The final rule
will not require operators to include a
signed certification statement as part of
their site facility diagrams, because, as
noted by a commenter, operators are
responsible by law for ensuring the
accuracy of the information in their
diagrams. In response to comments
questioning the requirement in
paragraph (c)(10)(i) of the proposed rule,
which directed operators to provide
equipment serial numbers, rated fuel
use, and manufacturer information on
their site-facility diagrams, the BLM
removed this requirement in paragraph
(c)(10)(i) of the proposed rule from the
final rule because the information,
although useful in verifying whether
equipment had been replaced, would
not help the BLM verify that the royaltyfree-use volumes reported to ONRR
were accurate.
One commenter said that the
requirement in paragraph (a), that
operators submit a site facility diagram
for each FMP, is cumbersome,
particularly in cases where the FMP for
oil facilities and gas facilities are on the
same site. The commenter
recommended that the BLM require a
single FMP number for an entire facility
at a single site in order make it simpler
for operators, while providing the
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necessary information to the BLM. The
BLM disagrees with this comment
because the BLM’s inspection
verification process is based, in large
part, on comparing production
information that is reported to ONRR
against information contained in a site
facility diagram, and operators report
their oil and gas production separately
to ONRR. Having information on both
types of facilities on one diagram could
complicate and undermine the BLM’s
verification process. No change has been
made to the rule based on this comment.
Many commenters were also very
concerned with the cost to operators to
comply with the proposed diagram
requirement, particularly the costs of resubmitting all site facility diagrams
within the proposed rule’s 30-day
submission deadline. However, as
discussed above and in greater detail in
the Economic and Threshold Analysis,
the final rule greatly scales back the
range of circumstances in which
operators of existing operations must
submit new site-facility diagrams. This
reduces the number of diagrams that
must be prepared and the amount of
information that operators need to
provide on those diagrams, which will
significantly reduce compliance costs.
The BLM estimated in the proposed rule
that it would take operators 8 hours to
prepare and submit a revised diagram.
The BLM now believes that with the
reduced workload, operators can
perform this task in 6 hours. The BLM
originally estimated in the proposed
rule that operators would submit
revised diagrams for 125,000 existing
facilities over a 27-month phase-in
period. After taking a more detailed look
at our computer data, the BLM has
revised downward its estimate of the
number of existing facilities to 83,116.
The BLM now estimates under this final
rule’s revised requirements that only 5
percent of existing facilities, or about
4,165 facilities, do not have accurate
and up-to-date site facility diagrams on
file with the BLM and will have to
submit revised diagrams to the BLM
over the 3-year phase-in period. The
BLM now estimates that the total onetime cost to industry to submit revised
site facility diagrams will be $1.6
million, spread over 3 years, down from
the BLM’s previous estimate in the
proposed rule of $63.6 million. On an
ongoing basis, the BLM estimates
operators will submit about 5,000 new
diagrams per year for a total annual cost
to the regulated community of $1.9
million.
Other commenters said they were
physically limited—by the sizes of their
staff and facilities—from submitting site
facility diagrams for multiple existing
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and new facilities within 30 days of
receiving their new FMP numbers.
Commenters said carrying out such a
labor-intensive effort within 30 days of
receiving an FMP number was
impractical, unreasonable, and a
burden. Some comments suggested that
a 60- to 90-day timeframe was more
realistic. One commenter suggested 180
days would be more reasonable, with a
couple of others suggesting that
operators have up to 1 year to complete
the diagrams. Another commenter
proposed that the BLM set a 30-day
deadline for new facilities to submit
their diagrams that would start from the
date of first production, while another
suggested a phase-in process, and still
another comment proposed diagrams for
new facilities only.
The BLM agrees that operators need
more time to submit diagrams for new
and existing facilities, and made
corresponding changes to the final rule.
The commenter misstated the
requirement of the proposed rule, which
would have required operators to
submit their diagrams much earlier—
within 30 days of completing
construction of their facilities. Under
the final rule, operators will need to
submit diagrams for new facilities (those
that become operational on or after the
effective date of this final rule) within
30 days after the BLM assigns an FMP
to those facilities. The BLM believes
these changes ensures that it will not
receive a site facility diagram for a new
facility prior to having assigned that
facility an FMP number, which means
operators will not have to go back and
subsequently revise their diagrams to
reflect the new FMP numbers. As
discussed earlier, under the final rule,
operators of existing facilities that
already have site facility diagrams on
file with the BLM that meet the
requirements of Order 3 do not have to
revise those diagrams unless they
modify their facilities or there is a
change in operator.
Finally, one commenter was
concerned about having to submit and
resubmit multiple site facility diagrams
for a facility with multiple FMPs, if the
FMPs were not approved within 30 days
of each other. The commenter said
compliance would be impossible under
these circumstances. The BLM believes
that this commenter was trying to
describe a well pad with multiple wells
that are coming in to production
consecutively. In this case, the FMP
numbers will not change, but a new sitefacility diagram will be required within
30 days from the onset of production
from each well to reflect the new facility
coming online. The BLM did not change
the final rule in response to this
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comment. With respect to the
commenter’s concern about facilities
having multiple FMPs, for the most part,
facilities will have no more than two
FMPs—one for oil and one for gas. Even
though the applications for each FMP
number will be submitted under a
separate Sundry Notices, there is no
reason an operator could not submit
them at the same time, nor for the BLM
to assign the FMP numbers at different
times, as it is unlikely that the
measurement system for oil would come
online later than the measurement
system for gas.
Section 3173.12 Applying for a
Facility Measurement Point
Section 3173.12 of the final rule
establishes a formal nationwide process
for designating and approving the point
at which oil or gas must be measured for
the purpose of determining royalty.
Prior to this final rule, the BLM did not
have a formal, written process for
designating measurement points on the
leases it manages. While some Field
Offices had their own internal policies
for establishing these points, this lack of
uniform guidance across Field Offices
resulted in instances of confusion about
the location of royalty measurement
points, which interfered with the BLM’s
production verification process. This
section now requires operators to obtain
BLM approval of FMPs for all
measurement points used to determine
royalties.
The BLM will approve an FMP that
meets the requirements of this final rule
(the most important elements of which
are the identification of the wells
associated with the FMP and the
measurement method). The BLM will
assign each FMP a unique identifying
number, which the operator,
transporter, or purchaser will use when
reporting production results to ONRR.
Each FMP number will be 11 digits
long. The first two digits (ranging from
52 to 99) will identify the product—oil
or gas—as well as other information,
such as whether the FMP is on-lease or
off-lease, whether it is part of a
commingling arrangement, and the
measurement method used at the FMP—
tank gauge, LACT, Coriolis, etc. The
next 5 digits will represent the
American Petroleum Institute (API) state
and county code, while the last 4 digits
will be a combination of letters or
numbers that will make each FMP
number unique.
The BSEE already assigns similar
FMP numbers for the offshore oil and
gas leases that it manages, which the
operator, transporter, or purchaser must
then use when reporting production
results to ONRR. The changes in this
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final rule will make BLM practices
consistent with existing BSEE and
ONRR practices for production
reporting.
Paragraph (a)(1) of this final section
provides that, unless otherwise
approved, the FMPs for all Federal or
Indian leases, unit PAs, or CAs must be
located within the boundaries of the
lease, unit PA, or communitized area
from which the production originated,
and must measure only production from
that lease, unit PA, or communitized
area, unless otherwise approved.
Paragraph (a)(2) provides that off-lease
measurement or commingling and
allocation of production requires prior
approval under 43 CFR 3162.7–2 and
3162.7–3, and §§ 3173.15, 3173.16,
3173.24, and 3173.25 of this final rule.
Paragraph (b) provides that the BLM
will not approve a meter at the tailgate
of a gas processing plant located off the
lease, unit, or communitized area as an
FMP. This paragraph codifies existing
BLM practice with respect to tailgate
meters.
Paragraph (c) provides that the
operator must submit separate
applications for approval of separate
FMP numbers for a measurement point
that measures oil produced from a
particular lease, unit PA, CA, or
pursuant to an approved CAA, and a
measurement point that measures gas
produced from the same lease, unit PA,
or CA, or pursuant to an approved CAA.
The requirements for a separate FMP
apply even if the measurement
equipment or facilities are at the same
location. As discussed earlier, the first
two numbers in the FMP number
specify whether the FMP measures oil
or gas. The BLM will not approve the
same FMP number for a facility that
measures oil and a facility that measures
gas.
Paragraph (d) requires the operator to
apply for approval of an FMP for a new
permanent measurement facility (i.e.,
one coming into service after the
effective date of the final rule) before
any production leaves the facility. In the
final rule, we clarify that this
requirement does not apply to
temporary measurement equipment
used during well-testing operations.
Until the BLM assigns the FMP number,
the operator must use the lease, unit PA,
or CA number for reporting production
to ONRR.
Paragraph (e) provides that for
existing permanent production
measurement facilities, an operator has
1 year, 2 years or 3 years from the
effective date of the final rule within
which to apply for BLM approval of its
FMP, depending on the production level
of the lease, unit PA, or CA that the
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measurement facility serves. The
prescribed application deadline applies
to both oil and gas measurement
facilities measuring production from
that lease, unit PA, and CA, whether or
not it is part of a CAA. The final rule
requires FMP applications for existing
measurement facilities that serve
operations with the highest production
volumes to be submitted first:
1. Under paragraph (e)(1), operators of
stand-alone leases, unit PAs, or CAs,
which produce 10,000 Mcf or more of
gas per month, or 100 bbl or more of oil
per month must, apply for FMP
approval within 1 year after the effective
date of the final rule.
2. Paragraph (e)(2) requires operators
of stand-alone leases, unit PAs, or CAs,
which produce 1,500 Mcf or more but
less than 10,000 Mcf of gas per month,
or 10 bbl or more but less than 100 bbl
of oil per month, to apply for FMP
approval within 2 years after the
effective date of the final rule.
3. Paragraph (e)(3) requires operators
of stand-alone leases, unit PAs, or CAs
that produce less than 1,500 Mcf of gas
per month, or less than 10 bbl of oil per
month, to apply for FMP approval
within 3 years after the effective date of
the final rule.
To determine which category a
facility is in, the final rule requires the
facility to calculate average production
over the 12 months preceding the
effective date of the final rule, or over
the period the lease, unit, CA, or CAA
has been in production, whichever is
shorter.
Paragraph (e)(4) explains that if a
stand-alone lease, unit PA, or CA has
not produced for a year or more before
the effective date of this final rule, the
operator is not required to apply for an
FMP immediately, but rather need only
apply prior to resuming production.
Under paragraph (e)(6), if an operator
applies for FMP approval by the date,
the operator may continue to use the
lease, unit PA, or CA number for
reporting production to ONRR while the
application is pending, until the
effective date of the BLM-assigned FMP
number, at which point the operator
must use the FMP number for such
reporting. If, however, an operator fails
to apply for an FMP approval by the
date required by the final rule,
paragraph (e)(7) explains that the
operator will be subject to an incident
of noncompliance and may also be
subject to an assessment of civil penalty
under 43 CFR subpart 3163, together
with any other remedy available under
applicable law or regulation.
Paragraph (f) identifies the
information that a request for FMP
approval must include. Under
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paragraph (f)(1), FMP requests must be
submitted on a Sundry Notice and
include information pertaining to the
equipment that will be used to measure
the oil and gas. Paragraph (f)(2) requires
the applicable Measurement Type Code
specified in WIS. Paragraph (f)(3)
requires information about the
equipment used for oil and gas
measurement: (i) For gas measurement,
specify unique station number, primary
element (meter tube) size or serial
number, and type of secondary device
(mechanical or electronic); (ii) For oil
measurement by tank gauge, specify oil
tank number or tank serial number and
size in barrels or gallons for all tanks
associated with measurement at an
FMP; and (iii) For oil measurement by
LACT or CMS, specify whether the
equipment is LACT or CMS and the
associated oil tank number or tank serial
number and size in barrels or gallons
(there may be more than one tank
associated with an FMP). Paragraph
(f)(4) requires operators to include a list
of the API well numbers that will flow
to the requested FMP if that FMP will
serve more than one well, and provide
a land description for the FMP location.
Under paragraph (f)(5), the FMP
location by land description must also
be included in the FMP application.
As explained below, the BLM in the
final rule has also reduced the quantity
of information that operators must
submit on their FMP number
applications. For consistency with
§ 3173.10(c)(10)(i), the BLM removed
requirements that operators provide
component names, manufacturer,
model, serial number, range limits for
electronic flow computers, transducer
(static, differential, and temperature),
chart recorders, LACT totalizer, and
Coriolis meter from § 3173.12(f)(3)(i),
(ii), (iii), (iv) and combined
subparagraphs (iii) and (iv) into (iii).
Paragraph (g) allows concurrent
requests for FMP approval and for
approval of off-lease measurement or
commingling and allocation.
Section 3173.12 is a key element of
the final rule as it implements one of the
GAO’s central recommendations: That
the Interior Department consistently
track where and how oil and gas are
measured, including information about
meter location, identification number,
and owner. By requiring operators to
obtain approval from the BLM for the
location of the FMP at which oil or gas
is measured, the final rule provides that
consistent tracking. The BLM will also
now tie the FMP numbers to other
appropriate approvals and
documentation that are part of its
production verification and
accountability efforts, such as site
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facility diagrams, off-lease measurement
approvals, commingling approvals, and
royalty-free use (if volumes used
royalty-free are measured).
In the final rule, operators,
purchasers, and transporters must
include on all records the FMP number
or until the BLM approves the FMP
number, the lease, unit PA, or CA
number, along with a unique equipment
identifier and the name of the company
that created the record.12 Records
include, but are not limited to,
calibration reports, gas analysis, sales
statements, manifests, seal records, and
related approvals. Once assigned, the
operator must use the FMP number for
production reporting to ONRR after the
effective date of the BLM’s FMP
approval.
The BLM estimates there are
approximately 83,116 existing oil and
gas facilities associated with Federal
and Indian leases. Many facilities have
one FMP for oil and one FMP for gas for
a total of approximately 166,232 FMPs
for existing facilities.
In connection with its creation of the
new FMP system in § 3173.12, the BLM
has also revised its existing well and
facility identification provisions at 43
CFR 3162.6(b) and (c) to include a
signage requirement for wells on
Federal or Indian lands and facilities at
which Federal or Indian oil or gas is
measured or processed. Additional
revisions to § 3162.6 include: (1) Making
the surveyed-location language in
paragraphs (b) and (c) consistent,
including a new reference to longitude
and latitude; and (2) Removing a
sentence in paragraph (b) that provided
a grace period for well signs that were
in existence on the effective date of the
rulemaking in which that section was
first promulgated.
The BLM received a comment
requesting that the definition of an FMP
in § 3173.1 include more details on how
to obtain an FMP, the deadlines for
operators to obtain an FMP, and the
economic impacts that the FMP
requirement would have on industry.
The BLM disagrees with this
commenter. Section 3173.12 of this final
rule provides all of the information
requested by the commenter related to
requests to apply for an FMP. It
addresses the deadlines—which are
based on average production volumes—
for operators to submit FMP
applications for facilities that are in
service on or before the effective date of
this rule, or that will come into service
after the effective date. It also specifies
12 Once an FMP number is approved, it must be
used on all subsequent reporting as outlined in this
rule.
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the three production thresholds on
which the FMP application deadlines
are based. As for the economic impacts,
the BLM carefully evaluated those as
part of the rulemaking process in both
a draft and a final regulatory impact
analysis for this rulemaking, both of
which are made available to the public.
The Procedural Matters section of this
preamble contains a short discussion of
this rule’s potential economic impact on
industry. We did not change the final
rule as a result of this comment.
A number of commenters were
concerned that they could not meet the
proposed rule’s deadlines in
§ 3173.12(e) for applying for and then
receiving an FMP number before
producing oil and gas. They said the
resources needed to prepare FMP
applications would be exorbitant,
especially for large producers that have
many thousands of wells, many of
which will likely have associated
commingling or off-lease measurement
approvals that the BLM will need to
review (see discussion of § 3173.16
below).
Many commenters also complained
about the proposed tiered volume
thresholds that figured into the
timelines for filing FMP applications.
Many operators said that most of their
wells’ production levels would require
them to submit their FMP applications
within 9 months of the final rule’s
effective date. Commenters said such
timeframes would be unreasonably
short for operators with large well
inventories, considering that they would
also be required to submit new site
facility diagrams and possibly update
existing commingling and off-lease
measurement approvals.
Under the proposed rule, operators
would have had to submit their FMP
application within:
• Twenty seven months from the
effective date of the final rule for leases,
unit PAs, and CAs that produced less
than 3,000 thousand cubic feet (Mcf) of
gas or 20 bbl of oil per month;
• Eighteen months from the effective
date of the final rule for leases, unit
PAs, and CAs that produced between
3,000 and 6,000 Mcf of gas or 20 and 40
bbl of oil per month; and
• Nine months from the effective date
of the final rule for leases, unit PAs, and
CAs that produced over 6,000 Mcf of gas
or 40 bbl of oil per month.
The BLM agrees with commenters
that the proposed deadlines were too
tight. In response, the BLM changed the
final rule to give operators additional
time to submit FMP applications for
facilities that are in service before the
effective date of the final rule. The
amount of additional time is based on
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the facility’s average reported monthly
oil and gas production volumes over the
previous 12 months. When establishing
the new thresholds, the BLM analyzed
lease production data in AFMSS to
determine the impacts on all currently
producing leases. In setting the FMP
application deadlines, the BLM
attempted to spread the impact evenly
across the three timeframes and across
all BLM-administered leases.
As discussed previously, the final rule
also allows operators to continue to
produce oil and gas while their FMP
applications are pending BLM approval,
provided that those applications are
submitted within the deadlines
specified in § 3173.12(e). While waiting
for their FMP approvals, operators may
continue to use the lease, unit PA, or CA
numbers that they have been using for
reporting their production to ONRR.
These changes should make it easier for
operators to meet the final rule’s FMP
application deadlines and give them
more time to plan and budget for this
new requirement, while continuing
their production operations. As
explained in connection with
§ 3173.11(d) and (e), this final rule
removes the proposed rule’s
requirement that all existing facilities
submit updated site facility diagrams
within 30 days of approval of an FMP,
further reducing requirements on
existing facilities.
In addition, as discussed previously,
the BLM changed the final rule to
eliminate some of the information
required in the FMP applications (e.g.,
equipment serial numbers and
manufacturer information).
Furthermore, the final rule exempts
leases, unit PAs, and CAs, which have
not produced any oil or gas within the
past 12 months. Only when operators
resume production from these idle
leases, unit PAs, and CAs must they
then apply for FMPs.
A number of commenters also
expressed concern that the BLM would
not have been able to handle the
number of FMP applications that the
agency would have received under the
proposed rule’s timeline and
requirements. However, the BLM now
anticipates having a much smaller
workload, spread more evenly over
time. For one thing, a review of AFMSS
data suggests that there are only 83,116
active facilities affected by this rule—
about 25 percent fewer than the BLM
had estimated in analyzing the proposed
rule. In addition, the final rule requires
operators to provide less information on
their FMP applications and site facility
diagrams than the proposed rule would
have required. We now estimate that it
will take BLM staff 2 hours to process
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each FMP application, instead of the 4
hours we anticipated under the
proposed rule’s information
requirements. Additionally, because of
the provisions allowing continued
production and reporting while an FMP
application is pending, operators should
no longer be concerned about potential
FMP application backlogs.
Several commenters said they were
concerned about delays in the FMP
approval process holding them up from
putting new wells online and removing
production from the lease. The
proposed rule at § 3173.12(d) required
operators to ‘‘obtain’’ FMP approval for
measurement facilities that came into
service after the rule’s effective date
before they could begin removing
production from a lease, unit PA, CA, or
CAA. The BLM agrees that proposed
paragraph (d) needed to be changed to
avoid production delays on new
facilities. To address these concerns, the
BLM has made several changes to
paragraph (d) in the final rule. First, the
BLM added language to the section to
clarify that operators must apply for
FMP approvals for permanent
measurement facilities only—not
temporary test facilities—as defined in
§ 3173.1 of this final rule. In addition,
the BLM added language to paragraph
(d) that requires operators of new
facilities to simply ‘‘apply for’’ FMP
approval before any production leaves
the permanent measurement facility.
This change allows operators to install
a new measurement facility, remove
production from that facility without
delay, and use the lease, unit PA, or CA
number for production reporting to
ONRR until the BLM assigned an FMP
number, as long as they apply for their
FMP approval before any production
leaves that permanent facility. While the
applications are pending, operators may
continue using their lease, unit PA, or
CA number for reporting production to
ONRR.
One commenter thought the BLM
should allow operators to file one
application on the facility as a whole,
and not be required to submit one
application for oil and another for gas.
The BLM did not revise the rule as a
result of this comment. One of the
purposes of an FMP is to be able to
consistently verify where and how oil or
gas is measured. The BLM does this by
comparing information that operators
report to the BLM against information
operators report to ONRR, which does,
in fact, collect the oil and gas
production information separately.
Using one FMP number to track oil and
gas measurement operations together
would compromise the BLM’s ability to
consistently verify production
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measurements for royalty purposes.
Such a system is also incompatible with
ONRR’s existing reporting systems, and
it would not meet the goals of
establishing an FMP.
Finally, one commenter said that BLM
staff should be given a deadline for
approving FMPs, since it is not fair to
hold operators to multiple deadlines,
making them subject to INCs for missing
those deadlines, while not holding the
BLM to the same standard. As discussed
above, the BLM’s new FMP approval
process will not interfere with
operators’ production. Once operators
file a timely request for an FMP
approval on existing facilities, they may
continue to operate and use their lease,
unit PA, or CA number for reporting
production to ONRR until the BLM
assigns an FMP number.
Once an FMP number is assigned to
a facility, § 3173.13(a) of this final rule
gives the operator several months before
it must use the FMP number when
reporting production to ONRR.
Specifically, for existing facilities, the
operator will have to begin using the
FMP number for reporting production to
ONRR on its OGOR for the fourth
production month after the FMP
number is assigned. For facilities that
come into service after the effective date
of this final rule, operators are required
to apply for FMP approval before any
production leaves the permanent
measurement facility and then use the
FMP number for reporting production to
ONRR on its OGOR for the first
production month after the FMP
number is assigned. As result of these
changes, we do not believe deadlines for
BLM review are necessary or
appropriate.
Section 3173.13 Requirements for
Approved Facility Measurement Points
Section 3173.13 of the final rule sets
forth the requirements that are
applicable to all approved FMPs.
Paragraph (a) requires the operator of an
existing facility to use assigned FMP
numbers in reporting production to
ONRR on its OGORs for the fourth
production month after an FMP is
assigned. For new facilities in service
after the effective date of this rule,
paragraph (a) requires the operator to
begin using its assigned FMP numbers
on its OGORs for the first production
month after the FMP number is
assigned.
Paragraph (b) requires an operator to
file, within 30 days after any changes or
modifications to an approved FMP, a
Sundry Notice notifying the BLM of the
change. It also describes the information
that operators must provide to the BLM
in the Sundry Notice, including any
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changes or modifications to the
equipment that is used for measuring oil
or gas at the FMP, or to the API well
numbers associated with the FMP.
The BLM received several comments
on this section of the proposed rule.
Unlike the final rule, the proposed rule
required operators to use their FMP
numbers for both recordkeeping
purposes and production reporting to
ONRR beginning on the first day of the
month after the FMP number was
assigned. A few commenters said they
needed more time to start using the
number for production reporting and
recordkeeping because an FMP could be
issued on the last day of the month,
thereby obligating the operator to use
the FMP on the next day. The
commenters said that this would not
give them enough time to take the steps
they need to comply with FMP
requirements, such as stenciling the
FMP number onto equipment, labeling
all records with the FMP number, and
making updates to their existing
database systems that track oil and gas
production operations.
The BLM agrees that requiring
operators to begin using their FMP
numbers for recordkeeping and
production reporting on the first day of
the month after the FMP number is
assigned may not be possible for some
operators. As discussed earlier, the BLM
changed § 3170.7(g) from requiring
operators to use FMP numbers on all
records, to allowing operators to use
either FMP numbers or lease, unit PA,
or CA numbers, along with unique
equipment identifiers, on their records.
In addition, the BLM changed final
§ 3173.13(a) to extend the effective date
that operators of existing facilities are
required to begin using their FMP
numbers in production reporting to
ONRR. Under the final § 3173.13(a),
operators must start using FMP numbers
for reporting production to ONRR on
their OGORs for the fourth production
month after the FMP number is
assigned. For example, if the BLM
assigns an existing facility an FMP
number on January 17, the operator
must begin using that FMP number on
its May production OGORs. Because
ONRR requires operators to submit their
electronic reports ‘‘on the 15th day of
the second month following the
production month being reported,’’ the
May production report must be
submitted by July 15, effectively giving
the operator 5-1⁄2 months of leeway
before having to submit a report using
the FMP number assigned on January
17. The BLM chose this new timeframe
because it believes that nearly six
months is ample time for operators of
existing facilities to start using their
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new FMP numbers for reporting
production to ONRR.
For new facilities, operators will be
required to begin using their FMP
numbers in reporting production to
ONRR on their OGORs for the first
production month after the FMP
number is assigned. For example, if the
BLM assigns the FMP number on April
30, the operator must begin using that
FMP number for its May production. As
noted, however, the May production
report is not due to ONRR until July 15,
effectively giving the operator 2-1⁄2
months leeway before having to submit
the report using the FMP number.
Some commenters asked why
proposed § 3173.13(d) required
operators to submit a Sundry Notice
detailing ‘‘any’’ modifications they
make to an approved FMP and why the
changes were made. Commenters said
the BLM does not need this information.
The BLM agrees that it does not need to
know why a change was made and has
removed this requirement from the final
rule. However, the BLM does need to
know when operators change out
measurement equipment at an approved
FMP, along with specific information
about the replacement equipment, and
when they add or remove wells served
by an FMP, along with the associated
API well numbers. The BLM needs this
information so that it can keep track of
these types of changes, which directly
impact the BLM’s efforts to verify
production. In addition, the BLM has
provided some additional context, by
clarifying that it does not need to be
notified when temporary modifications
(e.g., for maintenance purposes) are
made. With these clarifications, the final
rule in paragraph (b)(1) still requires
operators to file a Sundry Notice within
30 days notifying the BLM of changes in
measuring equipment at an approved
FMP or of the addition or subtraction of
wells served by an approved FMP.
These are essentially changes in the
information that operators submitted on
their FMP applications, as required
under § 3173.12(f)(3) and (4).
The BLM received several comments
on the requirement in proposed
§ 3173.13(a) that operators stamp or
stencil FMP numbers on specific pieces
of equipment within 30 days after an
FMP number assignment. Commenters
said this requirement was too expensive
and would take too much time. Several
commenters recommended that the
BLM, instead, cross-reference the FMP
number to a unique meter station
identifier supplied by the operator, such
as the meter station number, LACT ID
number, or tank number, all of which
are already available and visible to BLM
inspectors. The BLM agrees that the
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requirement to stamp or stencil FMP
numbers on equipment that is used to
measure for royalty is unnecessary and
has removed it from the final rule.
The BLM changed the final rule at
§ 3173.12(f) to require operators, when
they apply for a gas FMP number, to
identify the royalty measurement point
by specifying a unique station number;
primary element (meter tube) size or
serial number; type of secondary device
(mechanical or electronic); and
associated API well numbers where
production from more than one well
will flow to the requested FMP; along
with a land description of the FMP’s
location. On an oil FMP number
application, operators must supply the
tank number or tank serial number and
size in barrels or gallons; specify
whether LACT or CMS, if applicable;
associated API well numbers where
production from more than one well
will flow to the requested FMP; along
with a land description of the FMP’s
location.
One commenter said operators should
be exempt from the requirement that
they file a Sundry Notice when they
temporarily modify an FMP due to
changing out equipment for
maintenance. The commenter said the
replacement equipment, using the same
measurement methodology, would not
impact accuracy. The BLM agrees that
operators do not need to notify the BLM
when they install temporary
replacement equipment while
performing maintenance on the
permanent equipment. As noted, the
final rule clarifies in paragraph (b)(1)
that the BLM does not need to be
notified when temporary modifications
(e.g., for maintenance purposes) are
made.
Finally, one commenter objected to
the requirement in proposed paragraph
(b)(2) that operators file a Sundry Notice
whenever there is a change in the wells
or facilities served by an FMP. This
commenter said an operator may need
to transfer product to different meters
several times a day when the meters
freeze during the winter months. The
commenter said it would be impossible
to maintain a list of the wells going to
the FMPs under these conditions. The
BLM is not aware of situations where
operators direct their gas stream to
different sales meters because of line
freezing. This practice may be allowed
on State and private wells, but, such a
transfer is not allowed on Federal and
Indian wells. We did not change the
final rule as a result of this comment.
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Sections 3173.14 through 3173.21
Commingling and Allocation Approvals
As explained in the Definitions
section of this preamble, commingling,
for production accounting and reporting
purposes, means the ‘‘combining, before
the point of royalty measurement,
production from more than one lease,
unit PA, or CA, or production from one
or more leases, unit PAs, or CAs with
production from State, local
governmental, or private properties that
are outside the boundaries of those
leases, unit Pas, or CAs.’’ Operators
apply for commingling approval for
several reasons, including:
(1) It can simplify accounting to have
the sales point be the same as the point
of royalty measurement;
(2) Lower operating costs can be
achieved by reducing the number of
meters required (such as when well
testing is an appropriate allocation
method); and
(3) Lower operating costs can also be
achieved by eliminating the need for
separate plumbing and surface
equipment (pipelines, separators,
dehydrators, compressors, tanks, etc.).
Commingling can also have some
advantages for the BLM:
(1) More accurate measurement can
sometimes be achieved from a meter
measuring combined flows, which can
be better-conditioned and, more
consistent, and have higher flow rates,
than from a single low-volume meter
measuring erratic flow with a higher
potential for multiple phases of fluid;
(2) The environmental footprint can
be reduced by reducing the need for
duplicate surface equipment; and
(3) Production accounting can be
simplified by reducing the number of
meters to inspect and verify.
However, in many situations the
advantages of commingling are offset by
increased measurement uncertainty,
increased potential for measurement
bias, and a decrease in the BLM’s ability
to verify reported production volumes.
This is especially true if the properties
proposed for commingling are of
different ownership, have different
royalty rates, or have different royalty
distributions.
As explained below, §§ 3173.14
through 3173.21 of the final rule restrict
the instances in which the BLM will
approve commingling and establish the
standards that an operator must meet to
obtain an approval. Existing regulations
at 43 CFR 3162.7–2 and 3162.7–3
require BLM approval before operators
commingle production from a Federal or
Indian lease with production from other
sources; however, prior to this rule,
there were no regulations addressing
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81391
how or under what circumstance
commingling should be approved. The
requirements in this final rule are based
on and codify the policy outlined by the
BLM with respect to commingling
approvals in IM 2013–152 (2013),
‘‘Reviewing Requests for Surface and
Downhole Commingling of Oil and Gas
Produced from Federal and Indian
Leases.’’ The principal difference
between the provisions of this rule and
the BLM’s existing IM is that the final
rule establishes a new process for the
BLM to review existing CAAs when
operators apply for their FMP approvals.
In contrast, the IM focused solely on
new CAAs. Also, in response to public
comment and additional internal
reviews, the final rule expands the
number of exemptions under which an
existing or proposed CAA could be
commingled if the CAA does not meet
the criteria identified in § 3173.14 (a) of
the final rule.
Section 3173.14 Conditions for
Commingling and Allocation Approval
(Surface and Downhole)
Section 3174.14(a)
To ensure the accuracy and
verifiability of the volume and quality
measurements on which royalty is
based, § 3173.14(a) states that the BLM
‘‘may grant a CAA only if the proposed
allocation method used for any such
commingled measurement does not
have the potential to affect the
determination of the total volume or
quality of production on which royalty
owed is determined for all the Federal
or Indian leases, unit PAs, or CAs which
are proposed for commingling. . . .’’
Paragraph (a)(1) goes on to identify the
conditions under which this occurs.
The most common situation when
this occurs is when all the properties
proposed for commingling are 100
percent Federal or leased 100 percent by
the same Indian tribe, have the same
fixed royalty rate, and have the same
revenue distribution. In these situations,
the allocation method is irrelevant
because the total amount of royalty
received by the Federal Government or
tribal mineral interest owner will be the
same regardless of how it is allocated to
the individual leases, unit PAs, or CAs
that are part of the CAA. Consequently,
the BLM can ensure accurate
measurement and proper reporting by
inspecting and verifying only the
commingled point of royalty
measurement (i.e., the commingled
FMP). This would also apply in
situations where, for example, ‘‘leaseline’’ CAs proposed for commingling are
all 50 percent Federal and 50 percent
non-Federal.
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Based on comments received on the
proposed rule and additional internal
reviews, the BLM revised paragraph (a)
and its subparagraphs as outlined
below. In paragraph (a) itself, the BLM
added language which explicitly states
the criteria the BLM uses to approve a
commingling application. Paragraphs
(a)(1)(i) and (a)(1)(ii) were retained, with
modifications for clarity, from the
proposed rule. Those provisions
recognize that if the leases, unit PAs, or
CAs to be commingled are 100 percent
Federal or leased 100 percent by the
same Indian tribe, and at the same fixed
royalty rate, then commingling is
generally acceptable, assuming the other
requirements of this part are met. Indian
allotted leases are not included under
paragraph (a) because there would be
virtually no instances where the
revenue distribution to the allottees
would be identical in different leases,
unit PAs, or CAs.
Several commenters suggested that
commingling among unit PAs or CAs
that have less than 100 percent Federal
ownership should be recognized as
permissible, so long as they have the
same proportion of Federal interest. The
BLM agrees with this comment and
added paragraph (a)(1)(iii) to allow
commingling of Federal unit PAs or CAs
where each unit PA or CA proposed for
commingling has the same proportion of
Federal interest, which is subject to the
same fixed royalty rate and revenue
distribution. Under this provision, the
BLM could approve a commingling
request where an operator proposes to
commingle two Federal CAs of mixed
ownership where both are 50 percent
Federal/50 percent private, so long as
the Federal interests have the same
royalty rates and royalty distributions.
The BLM also added a new paragraph
(a)(1)(iv), which provides a parallel
provision for tribal interests, with the
key again being identical percentage of
tribal participation and royalty rates.
In paragraph (a)(2) of the final rule,
the BLM makes it clear that the operator
or group of operators that are part of a
CAA must provide the BLM with the
allocation methodology for the
properties from which production is to
be commingled, along with an
agreement signed by the operators that
are parties to the CAA if there is more
than one operator. Paragraphs (a)(3) and
(a)(4) remain unchanged from the
proposed rule.
Paragraph 3173.14(a)(3) requires
operators to demonstrate that each of
the leases, unit PAs, or CAs proposed
for inclusion in a CAA is producing in
paying quantities or, in the case of
Federal leases, capable of producing in
paying quantities. One commenter
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asked why the BLM wants to know that
wells involved in commingling are
capable of production in paying
quantities. The purpose of this
requirement is to ensure that CAAs are
not used to extend the terms of a
nonproducing lease, by allocating
production to it. The BLM did not
change the rule as a result of this
comment.
Paragraph (a)(4) requires that the
FMP(s) for the proposed CAA measure
production originating exclusively from
the leases, unit PAs, or communitized
areas in the proposed CAA. The BLM
received no comments on this
provision.
Section 3173.14(b)
Paragraph (b) of final § 3173.14 sets
forth the exceptional circumstances in
which the BLM will allow commingling
even when the circumstances outlined
in paragraph (a) are not met because, for
example, there is a combination of
Federal and non-Federal ownership,
Indian allotted leases are involved, or
the Federal or Indian leases have
different royalty rates. This paragraph
includes the two circumstances given in
the proposed rule: Economically
marginal properties (called low-volume
properties in the proposed rule) and
overriding considerations, such as
environmental impacts. The final rule
also adds three additional
circumstances where the BLM can
approve commingling:
• When the average monthly
production over the preceding 12
months for each Federal or Indian lease,
unit PA, or CA proposed for the CAA is
less than 1,000 Mcf of gas per month, or
100 bbl of oil per month;
• The CAA has been authorized
under tribal law or otherwise approved
by a tribe; or
• The CAA covers the downhole
commingling of production from
multiple formations that are covered by
separate leases, CAs, or unit PAs where
the BLM has deemed the commingling
of these formations to be an acceptable
practice for the purpose of achieving
maximum ultimate economic recovery
and resource conservation.
The BLM received numerous
comments on this paragraph in the
proposed rule, stating that the
exceptions granted in paragraph (b) of
the proposed rule were not adequate for
surface commingling approvals in cases
involving low production volumes. The
commenters said that this would result
in lost oil and gas production, revenue,
and royalties from operators forced to
shut-in thousands of wells covered by
existing CAAs where surface
commingling takes place and where the
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economics did not justify the cost of
installing new metering and
measurement equipment. In many of
these instances, the commenters stated
that production volumes have declined
to the point where the revenue from
continued operation would not be
sufficient to justify installing new
measurement equipment, particularly in
the current low-price environment.
The BLM disagrees with these
comments. The provisions for approving
a CAA for economically marginal
properties (low-volume properties in the
proposed rule) in both the proposed rule
and the final rule were designed
specifically to allow the BLM to
determine if a property would truly be
shut in if the only alternative was for
the operator to achieve non-commingled
measurement of production. The BLM
believes many of the worst case
scenarios flagged by commenters would
fit within the economically marginal
property exception. Unlike downhole
commingling, the costs for surface
commingling are relatively easy to
define. An operator on the edge of
profitability should be able to
demonstrate to the BLM under
paragraph (b)(1) that the properties
proposed for commingling qualify as
economically marginal properties. The
commenters did not submit any data to
substantiate that the existing provisions
under paragraph (b)(1) were inadequate
as they relate to surface commingling.
Although the BLM did not make any
changes to the rule based on these
comments, the BLM changed the
economic threshold in the final rule
based on comments on the definition of
low-volume property in the proposed
rule. As discussed in connection with
§ 3173.1, under the new definition of an
economically marginal property, the
BLM changed the threshold from a 10
percent before-tax rate of return in the
proposed rule to an 18-month after-tax
payout in the final rule. The BLM
believes this change will increase the
number of leases, unit PAs, or CAs that
would qualify as economically marginal
leases and, therefore, might qualify for
a CAA under this paragraph. The BLM
does not have any data to quantify this
increase, however.
Commenters also expressed concern
about the workload and timeframes
involved with obtaining a commingling
approval under paragraph (b). Because
the provisions of paragraph (b)(1) of
both the proposed and final rule are
very similar to the provisions of IM
2013–152, the BLM has experience with
the process of reviewing CAAs for
economically marginal properties.
Based on its experience processing
commingling requests under IM 2013–
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152, the BLM agrees that the process for
requesting and reviewing a CAA can
take time, especially for properties that
do not clearly fit within the economic
thresholds established in the final rule.
As a result, the BLM made two
changes in the final rule. The first
change was to grandfather any existing
surface commingling approval where
the average production rate over the
previous 12 months for each of the
Federal or Indian leases, unit PAs, or
CAs included in the approval is less
than 100 bbl of oil per month or 1,000
Mcf of gas per month (see
§ 3173.16(a)(1) and (2)). Second,
recognizing that such limited
production may also occur in
connection with new CAA approvals,
§ 3173.14(b)(2) now allows the BLM to
approve new CAAs if the average
production rate from the proposed CAA
satisfy the thresholds for grandfathering
of existing CAAs. The new CAA would
also have to comply with § 3173.14(a)(2)
through (4); however, under the final
rule, the BLM will not require any
additional economic analysis from the
operator.
The BLM chose these thresholds
because properties producing below
these thresholds would almost always
qualify as economically marginal
properties under this rule. Therefore,
the BLM can approve commingling
requests that qualify under this
paragraph with significantly less
paperwork burden on both the BLM and
industry, and without the in-depth
economic analysis that would have been
required in the proposed rule. The BLM
chose the oil threshold of 100 bbl per
month by assuming the cost of
achieving non-commingled
measurement of oil would be $50,000
(setting a small oil tank, for example).
The production rate required to achieve
an 18-month payout of this investment,
assuming a $60 per bbl oil price and
including taxes, royalty payments, and
fixed and variable operating costs,
would be about 3.5 bbl per day, or
approximately 100 bbl per month.
The BLM used a similar approach for
determining the gas threshold. The BLM
assumed that an operator would have to
invest $20,000 to achieve noncommingled measurement of gas (the
cost of installing a new meter). The
production rate required to achieve an
18-month payout of this investment,
assuming a $3 per MMBtu gas price, and
including taxes, royalty payments, and
operating costs, would be about 30 Mcf/
day, or roughly 1,000 Mcf per month.
The BLM added § 3173.14(b)(3) to the
final rule, which provides for CAAs that
have been authorized under tribal law
or otherwise approved by a tribe. The
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BLM included this provision in
response to tribal comments indicating
that tribal law or agreements may
independently identify circumstances
where commingling is appropriate. The
BLM added this provision because it
believes that tribes should have a say in
approving CAAs that involve
production from tribal leases.
The BLM received many comments
stating that the exceptions provided in
§ 3173.14(b) of the proposed rule did
not address downhole commingling
agreements in the New Mexico portions
of the San Juan and Permian Basins and
elsewhere that would not meet the
requirements § 3173.14(a). The
commenters said that this omission
would result in lost oil and gas
production, revenue, and royalties from
operators forced to shut-in thousands of
wells at existing CAAs where downhole
commingling takes place and where the
economics do not justify the cost of
drilling additional wells or segregating
downhole production. Many of the
wells, according to the commenters,
were drilled specifically to commingle
downhole production from multiple
leases, CAs, and unit PAs, including
combinations of Federal, Indian, fee,
and State ownership. The commenters
said downhole commingling allows
operators to reduce costs and
environmental impacts by reducing the
number of wellbores because multiple
zones can be produced out of a single
wellbore. In addition, commenters
stated that some individual zones do not
have enough production to justify the
drilling and completion costs for
separate wells. Other commenters
stressed that downhole commingling
increases the maximum ultimate
economic recovery because reservoir
energy from lower formations allows oil
and gas from highly-depleted upper
formations to be produced (i.e.,
production from the lower formation is
necessary to produce the upper
formation). In many of these instances,
production volumes have declined to
the point where the revenue from
continued operation would not be
sufficient to justify drilling new wells or
re-completing existing wells to avoid
downhole commingling, particularly in
the current price environment.
The BLM agrees with commenters
that the exceptions listed in the
proposed rule, need to be expanded to
account for downhole CAAs, to ensure
that improvements in measurement
accuracy and the BLM’s ability to verify
production made by this rule do not
unnecessarily result in operators
shutting in large numbers of existing
wells, particularly during times of low
commodity prices. The BLM believes
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that it is in the public interest to receive
royalty on a volume of oil or gas that
may have heightened levels of
uncertainty and may not be perfectly
verifiable by the BLM, rather than
receiving no royalty at all if the property
is shut in to avoid the cost of achieving
uncertainty and verifiability goals.
The low-volume exemption in the
proposed rule would have provided an
objective measure of the economic
viability of a lease, CA, or unit PA, as
it relates to downhole commingling.
However, this economic test has been
difficult to implement for downhole
commingling applications under IM
2013–152 because the costs associated
with achieving non-commingled
downhole production are highly
speculative and vary by facility and
formations. These costs could be in the
millions of dollars if an operator had to
drill multiple wells in lieu of downhole
commingling in one wellbore. It is also
difficult to predict or quantify the
benefits of increasing the maximum
ultimate economic recovery from a well
due to the ability to produce more oil
and gas from downhole commingling.
As a result of these comments, the
BLM made two changes in the final rule.
First, the BLM added an exception for
certain categories of downhole
commingling under paragraph (b)(4).
This new exception allows the BLM to
approve downhole commingling of
production from multiple leases, CAs,
and unit PAs if the BLM deems the
proposed operation to be an acceptable
practice for the purpose of achieving
maximum economic recovery and
conservation of the oil and gas resource.
This exception provides a means for the
BLM to recognize downhole
commingling practices that have
historically been approved in areas
where such practices provide the only
way to produce the Federal or Indian
interest, and therefore are necessary to
avoid having some operators
prematurely plug existing wells. The
addition of this provision gives Field
Offices flexibility to approve downhole
commingling requests based on local
knowledge and experience with the
characteristics of a particular oil or gas
reservoir. Second, for existing downhole
commingling approvals, the BLM added
§ 3173.16(a)(1), which will grandfather
all downhole commingling approvals in
existence prior to the effective date of
this rule (see discussion under
§ 3173.16(a)(1)).
Several commenters said that the final
regulations should state clearly how the
BLM will balance the Federal interest in
royalty measurement against competing
interests, such as environmental
concerns. One commenter
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recommended that the BLM include an
exemption from the commingling
requirements in situations where the
BLM’s denial of a request for a CAA
would increase a project’s
environmental impact. The BLM did not
make any changes to the rule in
response to these comments because
paragraph (b)(5) of the final rule already
expressly allows the BLM to consider
approving a CAA if there are overriding
conditions, such as topographic or other
environmental considerations,
notwithstanding potential negative
royalty impacts from commingled
measurement. Section 3173.14(b)(2) of
the proposed rule contained a similar
provision. The BLM has determined that
this language would allow the BLM to
grant new CAAs in instances where the
BLM determines that minimizing
environmental impacts takes
precedence over ensuring accurate and
verifiable measurement and proper
reporting of oil and gas removed or sold
from a lease, unit PA, or CA. The BLM
believes these situations will be rare and
CAA approval will only be considered
after exhausting all feasible alternatives,
including alternate measurement
techniques. The environmental analysis
for the final rule indicates that in most
cases where operators are required to
install new facilities, they will likely
place those facilities at sites where there
is existing surface disturbance and
where the environmental impact would
be minimal (see the Procedural Matters
section below for more discussion about
the environmental analysis). If new
equipment requirements result in new
surface disturbances, the BLM, under
the provisions of this rule, will evaluate
any potential environmental impacts
and require operators to mitigate them.
One commenter stated that the added
and unnecessary cost to industry to
have to build and maintain separate
pipelines and facilities without a
substantial benefit for the BLM in return
is unreasonable. The commenter said
that they have a few wells in a field that
are not in the unit, but use the same
facilities that service the unit. The
commenter is concerned that they
would not be able to continue
commingling in the future without
doing a substantial economic study to
quantify the cost to build separate
facilities including shipping facilities.
Another commenter asked the BLM to
consider exempting those properties
that are in close proximity to an existing
gathering system and allowing
production from those properties to be
commingled with other properties, even
if they are not considered to be lowvolume properties.
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The BLM disagrees with these
comments and did not make any
changes to the rule as a result.
Allocation methods that affect royalty
measurement and reporting have the
potential to increase measurement
uncertainty, introduce bias, and inhibit
the BLM’s ability to verify and account
for oil and gas production removed or
sold from a lease, unit PA, or CA. The
exceptions that allow for commingling
when allocation methods affect royalty
are included in paragraph (b) of the final
rule; they cover cases where the
requirement to achieve non-commingled
measurement of production would
cause a prudent operator to shut in
production or would cause significant
and unavoidable environmental
impacts. When demonstrating whether a
lease, unit PA, or CA is economically
marginal, operators can and should
include the cost of building additional
gathering lines, any new facilities, and
mitigating environmental impacts into
their capital cost calculations to see if
they would qualify for commingling
approval under paragraph (b)(1) of this
section. If they do not meet the
definition, or any of the other
exceptions in paragraph (b) of this
section, then the operator should be able
to construct the additional facilities
while still realizing a reasonable return
on that investment, rather than shutting
in production from a particular well.
One commenter was concerned that,
under the CAA requirements, operators
who currently commingle small
amounts of saleable liquids produced
from gas wells (e.g., condensate) would
have to install separate storage tanks for
that liquid, imposing a significant and
unjustified cost on operators. The BLM
agrees with this concern raised by the
commenter and made two changes to
the final rule as a result. First, the
definition of economically marginal
property (low volume property in the
proposed rule) was changed in the final
rule to clarify that the expected costs
and revenues for the economic analysis
need only take into consideration the
commodity for which the measurement
equipment would be built, whether it is
the oil or gas. In the example provided
by the commenter, the economic
analysis of condensate measurement
would only consider the income stream
from the sale of condensate and would
not include the income stream from the
sale of gas. Therefore, the small amounts
of condensate generated would likely
qualify for an exemption under
paragraph (b)(1). Second, the BLM
added paragraph (b)(2) to the final rule
which provides an automatic exemption
from the CAA restrictions and from
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performing an economic analysis for
leases, unit PAs, or CAs that produce
less than 100 bbl of oil per month or
1,000 Mcf of gas per month, averaged
over the previous 12 months. In this
example, if the small amount of saleable
condensate was less than 100 bbl per
month averaged over the previous 12
months, the BLM could grant
commingling approval for the
condensate without any further
analysis, assuming that the conditions
in paragraph (a)(2) through (a)(4) were
also met.
One commenter representing Native
Alaskan interests said it would not be
economically feasible to prevent
commingling of production from BLM
lands that are within a unit PA that has
an existing measurement system
approved by all parties, when the BLM
lands comprise only a small portion of
the production. The BLM did not make
any changes to the final rule in response
to this comment, for two reasons. First,
if the BLM portion of the unit PA is very
small or the production is low, it might
qualify as an ‘‘economically marginal
property’’ under the definition of an
economically marginal property in
§ 3173.1. In this case, the BLM could
approve commingling with other unit
PAs within the unit or other properties
outside of the unit. The BLM may also
be able to approve commingling under
§ 3173.14(b)(5) if achieving noncommingled measurement of
production addresses some overriding
consideration, such as avoiding undue
environmental impacts. If, on the other
hand, the properties that are proposed
for inclusion in a CAA do not meet the
definition of economically marginal
properties, do not present some other
overriding consideration, such as
environmental impacts, or otherwise
satisfy one of this rule’s criteria, then
the BLM will require the operator to
achieve non-commingled measurement
of that unit PA.
A couple of commenters suggested
that the BLM is creating new law by
establishing standards and requirements
for existing CAAs that were not in Order
3. The BLM does not understand the
comment. The purpose of the
rulemaking process that the BLM is
going through is to establish new
standards and requirements. By
following the BLM’s authorizing statues
and the procedures established by the
Administrative Procedure Act, 5 U.S.C.
551 et seq., the BLM is able to establish
new or different standards and
requirements than those found in
existing Order 3. As explained
elsewhere in this preamble, the final
rule is squarely within the scope of the
BLM’s authorizing statutes and the
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related delegations of authority from the
Secretary.
Several commenters also said the
BLM has not analyzed the impacts of
the rule on industry and the BLM, and
requested clarification on how the BLM
will balance the Federal interest in
royalty measurement against competing
interests. The BLM disagrees that it has
not analyzed the impacts on industry or
the BLM. As stated earlier in this
preamble, the BLM has rigorously
weighed and considered the economic
impacts that this final rule will have on
industry and prepared draft and final
regulatory impact analyses for this
rulemaking, which are available to the
public. The Procedural Matters section
of this preamble contains a short
discussion of this rule’s potential
economic impact on industry. The
analysis estimates that this rule’s CAA
requirements will have a one-time cost
to industry of $4.9 million to $7.6
million for operators to submit
documentation and respond to the
BLM’s informational requests for
existing leases, and $2.7 million to
install meters where the BLM rescinds
existing commingling agreements. The
analysis also estimates there will be an
annual paperwork cost to industry from
these provisions of $3 million to $4.6
million for new and modified
commingling agreements, and $1.6
million in new annual metering
installation costs for those FMPs where
a commingling agreement is rescinded.
The BLM believes that the final rule
provides clear guidance on how the
BLM will balance the Federal interest in
accurate measurement with competing
interests, such as not causing
production to be shut in or creating
additional environmental impacts. The
final rule includes numerous provisions
that allow commingling in cases where
the public interest is better served by
allowing commingling even if it results
in potential negative effects to royalty
measurement. These instances include
properties that the BLM determines to
be economically marginal, properties
that produce below set thresholds,
situations that involve downhole
commingling, and where unnecessary or
undue degradation or unavoidable
environmental impacts or other
overriding considerations would result
if commingling were denied. The BLM
did not make any changes to the rule
based on these comments.
Section 3173.15 Applying for a
Commingling and Allocation Approval
Section 3173.15 of the final rule
establishes the requirements operators
must follow when requesting a CAA,
and the information they need to
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include. Most of these requirements
were in the proposed rule, but the final
rule includes changes to the amount and
type of information operators must
include in their applications. The BLM
made these changes in response to many
comments it received on this section.
The following discussion describes
those comments and the changes that
were made.
One commenter suggested that
proposed paragraph (b) be changed to
require operators to submit as part of
their CAA applications an allocation
method, instead of an allocation
schedule, which is subject to frequent
changes. The BLM agrees that
information about a CAA’s allocation
method would be more useful, and as a
result changed the final rule to require
an allocation method instead of a
schedule.
Several commenters said they did not
believe the BLM has the authority to
require operators to submit site facility
diagrams as part of new CAA approvals
for existing facilities, as required in
paragraph (e) of the proposed rule. The
BLM agrees that it does not need a site
facility diagram to approve a CAA
application for existing facilities and
has eliminated that requirement in the
final rule in response to these
comments.
One of the commenters asked about
the purpose in § 3173.15(e), for
requiring operators to provide a map
showing the boundaries, FMPs, and
location of wellheads and production
facilities as part of their commingling
and allocation application. In response,
the BLM changed paragraph (e) of the
final rule to reduce the amount of
information that operators must include
in maps submitted as part of CAA
applications. The required maps need
only show the boundaries of any lease,
unit, unit PA, or CA from which
production is proposed to be
commingled and indicate the locations
of existing or planned facilities with the
relative location of all wellheads (with
API numbers), the piping, and existing
or proposed FMPs included as part of
the CAA request. The BLM needs this
information for several reasons, one of
which is to determine if all the
production flowing through the
proposed FMP originates from the
leases, unit PAs, or CAs proposed to be
part of the CAA. Another reason is to
obtain clarity on what leases, unit PAs,
or CAs are actually proposed for
commingling. This is especially
important when unit PAs or CAs are
included in the proposal. In these
situations, the location of a well or
facility in relation to lease, unit PA, or
CA boundaries, is critical for the BLM
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81395
to understand when evaluating a
commingling application. For example,
one well may be physically located on
a Federal lease but only produce from
a CA that covers one of the formations
under that lease, while another well on
the same lease may only produce from
a portion of the lease that is not part of
the CA. In this case, the BLM would
have to understand that even though
both wells are physically located on the
same lease, a CAA is required to
combine their production because their
production originates from different
properties. The BLM did not make any
changes to the rule based on these
comments.
One commenter asked whether the
BLM planned to monitor which wells
are flowing to which FMP and make
operational recommendations. While
the BLM has no intention of making
operational recommendations, it will
monitor which wells are flowing to
which FMPs if that affects the CAA or
the underlying allocation of production.
The BLM did not make any changes to
the rule based on these comments.
Several commenters wanted to know
why, in § 3173.15(k), submission of up
to 6 years of gas analyses, including Btu
content and all oil gravities, is required
for CAA requests. They indicated that it
would be too burdensome for CAA
applicants to provide historical crude
oil gravity and natural gas heating value
data, as only current data is relevant for
trying to determine the prices received
for these products. A couple of other
commenters said this information
requirement is excessive and would not
improve the quality of the application.
The BLM does not believe this to be an
onerous requirement. First, 6 years’
worth of data would not necessarily
include a lot of data, especially for
lower producing leases, unit PAs, and
CAs for which the BLM would consider
approving a CAA. For example, under
43 CFR 3175.100, a very-low-volume
FMP (producing 35 Mcf per day or less),
is only required to have a gas analysis
taken once per year, so 6 years of data
for that well is only 6 gas analyses. For
oil, the API gravity is only determined
when an oil sale takes place. A lowproducing oil lease may only have an oil
sale several times per year, in which
case 6 years of API gravities would
include only one or two dozen API
gravities. Second, operators should
already have this information readily
available because they are currently
required to maintain records for at least
6 years under 43 CFR 3170.7, which
retention period has been increased to 7
years for Federal leases under this rule.
One of the reasons the BLM needs
historical Btu and API gravities is to
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assess the allocation methodology
proposed by the operator. If, for
example, the gas analysis data showed
statistically significant variations
between Federal and non-Federal
properties proposed for a CAA, the BLM
may require that the allocation method
account for the Btu differences. On the
other hand, if the gas analyses for the
properties proposed for commingling
were not significantly different, then the
allocation method could be purely
volume based. The BLM could also
analyze the historical trend of Btu
content or API gravity to determine if,
for example, increasing Btu content
could result in greater future royalty.
Without this data, it would be
impossible for the BLM to perform any
analysis on the allocation method or on
future revenue projections as part of an
economic analysis.
Another commenter noted that this
information has no royalty impact if the
properties are 100 percent Federal or
Indian mineral ownership with the
same fixed royalty rate and distribution.
The BLM agrees with this comment and
added a caveat to § 3173.15(k)
indicating that this information is
required only if the CAA is not
approved under § 3173.14(a)(1).
The BLM also determined it was
necessary to make other changes to
§ 3174.15 in the final rule to address
considerations related to the
administration of the rule. As part of the
final rule, the BLM clarifies in
paragraphs (f) through (i) which
additional approvals operators must
seek if their commingling proposals
entail new surface disturbance or take
place on Indian lands or on lands
administered by other Federal surface
management agencies, in case operators
are unaware of these requirements.
Finally, this section clarifies that if offlease measurement is part of a
commingling and allocation proposal,
then a separate Sundry Notice under
§ 3173.23 is not needed as long as the
information required under paragraphs
(b) through (e) and, where applicable,
paragraphs (f) through (i) of § 3173.23 is
included as part of the request for
approval for commingling and
allocation. This revision clarifies that an
applicant may submit both proposals in
one Sundry Notice request.
Section 3173.16 Existing Commingling
and Allocation Approvals
Under § 3173.16 of the final rule, the
BLM will review an existing CAA when
it receives an operator’s request for an
FMP number for a facility associated
with the CAA. The BLM made
numerous changes to both the structure
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and content of this section in the final
rule in response to comments.
Section 3173.16(a)
A new paragraph (a) was added to the
final rule that grandfathers existing
commingling approvals in some specific
situations. Paragraph (a)(1) grandfathers
all existing downhole commingling
approvals.
Based on the numerous comments the
BLM received on downhole
commingling approvals (see a
discussion of those comments under
§ 3173.14(b)), the BLM decided to
grandfather all existing downhole
commingling approvals. The BLM is
aware that there are large numbers of
wells in the San Juan basin and
elsewhere that are currently approved
for downhole commingling. The BLM
believes that the vast majority of these
wells are producing low volumes of oil
and gas and that continued production
of these wells increases the maximum
ultimate recovery of oil and gas. As a
result, the BLM has made a
determination that it is in the public
interest to ensure these wells continue
to produce even if the methods used to
allocate production to Federal and
Indian leases, unit PAs, and CAs
potentially result in higher levels of
uncertainty, bias, and make verification
of production more difficult. The BLM
also believes that most of these wells
would be approved by the BLM to
continue commingling even if the BLM
were to perform an evaluation on them
as would have been required under this
section of the proposed rule.
Grandfathering all existing downhole
commingling approvals will streamline
the review process and reduce the paper
work burden on both industry and the
BLM. When the BLM receives a request
for an FMP for a well that has an
existing downhole CAA, the BLM will
document that the existing downhole
CAA qualifies under § 3173.16(a)(1) of
the final rule. The BLM will address any
shortcomings of the existing approval,
such as the absence of a defined
allocation method, on a case-by-case
basis during inspections and production
audits. The BLM may issue written
orders to operators to correct these
deficiencies.
Paragraph (a)(2) grandfathers existing
surface commingling approvals where
each lease, unit PA, or CA that is part
of the approval produces less than 100
bbl of oil per month or 1,000 Mcf of gas
per month, averaged over the previous
12 months. See the discussion under
§ 3173.14(b) for an explanation of how
the BLM derived these thresholds. As
with downhole commingling, the BLM
decided to grandfather these existing
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commingling approvals based on
comments received on the proposed
rule. However, the BLM does not agree
with comments stating that the
economic exemptions in the proposed
rule were inadequate. The BLM believes
that the economic exemptions in both
the proposed and final rules are
adequate to address those operations
where achieving non-commingled
measurement of production would truly
be uneconomic. In addition, the
definition of an economically marginal
property in the final rule expands the
criteria in the proposed rule by
changing the threshold from a 10
percent before tax rate of return to an
18-month after tax payout. The BLM
believes this could significantly increase
the number of leases, unit PAs, and CAs
that would be able to qualify for the
economic exemption.
The BLM does, however, agree with
comments expressing concern over the
paperwork burden associated with
preparing and reviewing applications
involving lower volume leases, unit
PAs, and CAs. The BLM chose to
grandfather these existing surface
commingling approvals based on the
understanding that leases, CA, and unit
PAs producing below these thresholds
would almost certainly qualify under
the definition of an economically
marginal property. The purpose of
grandfathering these approvals,
therefore, was to reduce the paperwork
burden for both the BLM and industry.
Under this provision, the operator of
any lease, unit PA, or CA that is below
these thresholds would retain the
existing CAA from the BLM without any
further information or analysis required.
The BLM would only have to verify that
the average monthly production rates of
the leases, CAs, and unit PAs included
in the approval are below the thresholds
listed in this section.
Section 3173.16(b)
A new provision has been added to
paragraph (b), which clarifies that if the
grandfathering conditions in paragraph
(a) of this section are not met, then the
existing CAA must meet the minimum
standards and requirements for a CAA
under § 3173.14 of the final rule.
This section also sets out a process if
the AO identifies deficiencies.
Paragraph (b)(1) requires the AO to
notify the operator in writing of any
inconsistencies or deficiencies with an
existing CAA. The operator will then be
given 20 days after receipt of such
notice to correct any inconsistencies or
deficiencies, provide the additional
information requested, or request an
extension of time. When the AO is
satisfied that the operator has corrected
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any inconsistencies or deficiencies, the
AO will terminate the existing CAA and
grant a new CAA based on the
operator’s corrections.
Paragraph (b)(2) clarifies that the AO
may terminate an existing CAA and
grant a new CAA with new or amended
COAs to make the approval consistent
with the requirements for CAAs under
§ 3173.14 of the final rule. Under the
proposed rule the AO could simply
impose new or amended COAs to an
existing commingling approval.
Section 3173.16(c)
One of the primary goals of paragraph
(c) in the final rule (§ 3173.16(a) through
(d) of the proposed rule) is to ensure
that existing commingling approvals
that do not qualify for grandfathering
under paragraph (a) of this section, meet
the standards for commingling under
§ 3173.14. Another primary goal is to
ensure that, if the existing commingling
approval does meet the standards under
§ 3173.14, it also contains the
information required under § 3173.15, to
ensure that the BLM can verify the
volumes allocated to each lease, unit
PA, or CA that are part of the existing
CAA.
Under paragraph (c), the BLM will
review existing CAAs that do not
qualify for grandfathering under
paragraph (a), for their consistency with
the minimum standards and
requirements under § 3173.14 when the
operator submits a request for an FMP
number. If the BLM determines that the
existing CAA does not meet the
requirements under § 3173.14, the BLM
may take several courses of action.
Under paragraph (c)(1), the AO will
notify the operator in writing of any
inconsistencies or deficiencies that the
BLM identifies. The operator will have
20 business days to provide additional
information requested by the BLM,
request an extension of time in which to
reply to the AO, or correct any
inconsistencies or deficiencies. Under
paragraph (c)(2), the BLM can impose
new or amended COAs on an existing
CAA to make it compliant with the
requirements of this final rule.
Paragraph (c)(3) allows the AO to
terminate the CAA if the operator fails
to correct the deficiencies that the BLM
identifies.
The only significant change to
paragraph (c)(1) of the final rule relative
to paragraph (b) of the proposed rule is
that the BLM clarifies that when the
operator corrects any inconsistencies or
deficiencies, the BLM will terminate the
existing CAA and grant a new CAA in
its place. The BLM made a similar
change to paragraph (c)(2) of the final
rule (paragraph (c) of the proposed rule),
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which clarifies that the BLM will
impose new or amended COAs on an
existing CAA by terminating the
existing CAA and granting a new CAA
in its place that includes those COAs.
Under paragraph (d) of the final rule
(paragraph (e) of the proposed rule), if
the BLM approves a new CAA to replace
an existing agreement, it will be
effective on the first day of the month
following its approval. The BLM also
included a new sentence in this
paragraph that clarifies that any
resulting change in the allocation
method will only apply from the
effective date of the CAA forward. The
BLM added this clause to clarify that
changes in the allocation method will
not be applied retroactively. The BLM
believes that retroactive application of
new allocation percentages would
impose a large paperwork burden on
both industry and the BLM and would
not be necessary.
Numerous commenters requested that
the BLM consider grandfathering all
existing CAA approvals. One
commenter said the modifications to
their facilities will put up to 87 percent
of their production at risk of being shut
in and possibly lost forever, along with
the royalties to each of the mineral
owners. The BLM agrees that there are
instances where existing commingling
agreements do not need to meet the final
rule’s commingling standards outlined
in § 3173.14(a)(1), and has provided
exemptions in § 3173.16(a) that allow
operators to maintain existing
agreements. See the discussion under
§ 3173.16(a) for further discussion. In
addition, § 3173.14(c) includes three
additional circumstances, beyond the
three provided under the proposed rule,
in which the BLM can approve a CAA.
Given the grandfathering provisions and
the expanded number of situations
where the BLM can approve a CAA
under the final rule, the BLM does not
believe that any existing CAAs that are
truly on the edge of profitability will be
impacted by the final rule’s
requirements.
Other commenters did not like the
idea of being required to upgrade
existing wells and facilities that comply
with existing laws, regulations, and
policies. While the BLM notes that
standard terms and conditions found in
Federal oil and gas leases require
compliance with all applicable
requirements, including requirements
that might be subsequently promulgated
by the BLM, the BLM nevertheless
believes that this comment has some
merit. Most existing surface
commingling approvals are for leases,
unit PAs, and CAs where production
volumes are low enough, or other
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81397
overriding considerations exist, such
that the CAA will comply with the
requirements of § 3173.14(a) or (b) of the
final rule with little or no changes
required. Similarly, any CAA granted
under IM 2013–152 should already meet
the requirements of the final rule,
especially considering that the final rule
adds four additional exemptions under
which the BLM may grant a CAA as
compared to the two exemptions
allowed under the IM (for low-volume
properties and overriding
considerations), and lowers the
threshold for leases, unit PAs, and CAs
to meet the definition of an
economically marginal property. For the
relatively few existing CAAs that do not
meet the requirements of the final rule,
some changes to plumbing or
measurement equipment may be
required. In these cases, the BLM will
determine that a CAA is not justified
because these leases, unit PAs, or CAs
do not meet the definition of an
economically marginal property and no
other overriding conditions exist that
would allow the BLM to grant a CAA.
One commenter said the proposed
rule would require operators to submit
all existing authorizations to the BLM
for re-approval, and added that many
operators and BLM staff spent countless
hours negotiating approvals of existing
CAAs to ensure they protect
environmentally sensitive areas while
providing accurate measurement of
production. Although the BLM did not
make any changes to the rule based on
this comment, the final rule includes
grandfathering provisions under
§ 3173.16(a), which would no longer
require operators to submit existing
downhole commingling authorizations
or surface commingling authorizations
that qualify under § 3173.16(a)(1) and
(2) when applying for an FMP. In
addition, for those existing CAAs that
do not meet the grandfathering criteria
of paragraph (a) of this section, but
comply with the requirements of the
new rule, the BLM will not require reapproval—these CAAs will be allowed
to continue as originally approved.
Several commenters disagreed with
the requirement in § 3173.16(c)(1) that
operators correct any inconsistencies or
deficiencies that the AO finds with an
existing CAA within 20 business days.
One commenter said North Slope
operators have significant weatherrelated challenges that would make it
difficult for them to meet the 20business-day deadline, while another
said that the required fixes could
involve installing new piping, which
would likely take longer than 20
business days. Several commenters said
this final rule will require every existing
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CAA to have some work done and
operators must be given flexibility if
they have multiple CAAs because 20
business days may not be enough time
to bring them all into compliance.
Another commenter said that they have
made substantial investments in their
gathering systems and would need a
reasonable amount of time to make the
changes to facilities that handle leases
with mixed ownerships that are not
already part of a unit PA or CA.
In response to these comments, the
BLM added language to the final rule at
§ 3173.16(c)(1) which allows an operator
to request an extension during the 20business-day timeframe. The operator
should justify the extension request by
explaining the factors that will not
allow it to comply within the 20business-day timeframe, and provide a
timeframe under which they can
comply. The BLM will consider the
request and grant an extension if the
justification is adequate. This final rule
will not require every existing CAA to
undergo significant work to bring it into
conformity with the new requirements
as one commenter suggested. In fact, the
BLM estimates that the majority of
existing CAAs will continue operating
as they have been because they are
exempt from the requirements due to
their low production volumes or other
factors.
Several commenters said it would be
unfair for the BLM to apply new COAs
that existing CAAs could not meet,
causing production to be shut in.
Another commenter said it would be
unreasonable for the BLM to impose
new or amended conditions of
approvals on existing commingling
agreements and recommended that
§ 3173.16(c) be deleted altogether. The
BLM does not agree with these
comments and did not make any
changes to the final rule as a result.
The BLM estimates that only a small
percentage of existing CAAs will require
new COAs and most of those COAs will
be for minor deficiencies such as
providing a better explanation of the
allocation process. For those new COAs
that require additional work to which
the operator may object, the BLM has
already included a provision in
paragraph (c)(2) of the final rule that
will allow the existing CAA to continue
in effect during the pendency of any
appeal of the decision that requires the
new COAs. The BLM did not make any
changes to the rule based on these
comments.
Lastly, some commenters expressed
concern that existing CAAs were at risk
of being terminated if the BLM did not
timely respond to their FMP
applications and review their CAA
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approvals. As stated earlier, operators
may continue to produce oil and gas
prior to FMP approval and CAA review
and may continue to use their lease,
unit PA, or CA numbers for reporting
production to ONRR as long as they
have applied for their FMP numbers
within the deadlines specified under
§ 3173.12. The BLM did not make any
changes to the rule based on these
comments.
Section 3173.17 Relationship of a
Commingling and Allocation Approval
to Royalty-Free Use of Production
Section 3173.17 clarifies that approval
of a CAA does not constitute approval
of off-lease royalty-free use of
production in facilities located at an offlease FMP approved under the CAA.
The BLM did not make any changes to
this section.
One commenter from the San Juan
Basin said the new CAA requirements
would reduce Federal royalties from
existing CAAs because operators would
have to install new compressors at each
well, resulting in more royalty-free
production used as fuel to power those
compressors. The commenter provided
a diagram that showed a compressor for
each lease that they believe would be
required if commingling was not
approved. For comparison, another
diagram showed one large compressor
located at an off-lease FMP in lieu of the
wellhead compressors, if commingling
was approved. The commenter stated
that with commingling approval,
operators must pay royalty on the fuel
used at the commingled off-lease
compressor because it does not qualify
as royalty-free use.
The BLM disagrees with the premise
of this comment because there is
nothing in the scenario presented by the
commenter that would compel them to
install separate lease compressors if the
BLM denied commingling. The small
amount of royalty the operator would
not have to pay if the compressors were
located on-lease would never offset the
additional capital and ongoing expense
of having to install, operate, and
maintain three lease compressors as
compared to one large compressor
located at a central delivery point.
Instead, if the BLM did not grant a CAA,
a prudent operator would simply use
the allocation meters already installed at
each property they were proposing to
commingle as FMPs, continue to use the
large off-lease compressor, and continue
to pay royalties on the fuel used to run
that compressor as they do now. The
BLM did not make any changes to the
rule based on this comment.
Another commenter stated that other
royalty owners will be burdened by all
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the downstream losses (fuel, etc.) if the
operator must install an on-lease FMP
rather than rely on measurements taken
at a downstream commingled
measurement point.
According to the commenter this
raises legal concerns with respect to
other agency regulations and contractual
agreements between operators. The BLM
disagrees with this comment and did
not make any changes as a result. The
requirement to install an FMP on the
lease, unit PA, or communitized area,
and pay royalty based on that FMP only
applies to Federal and Indian leases. It
would not preclude other royalty
owners to base their royalty distribution
on a down-stream commingled
measurement point that is different from
the FMP on which the Federal or Indian
royalties are based.
Section 3173.18 Modification of a
Commingling and Allocation Approval
Section 3173.18(a) of the final rule
identifies the circumstances under
which all operators who are parties to
a CAA must request a modification,
including: Modifications to the
allocation agreement; inclusion of
additional leases, unit PAs, or CAs into
a CAA; or termination of a lease, unit
PA, or CA within a CAA. Paragraph (b)
identifies the information that must be
submitted in connection with a
modification request. Paragraph (c) was
added to the final rule to clarify that a
CAA does not need to be modified when
there is a change in operator.
One commenter suggested that the
BLM change proposed § 3173.18(a)(1),
which allowed operators who are a
party to a CAA to modify the CAA when
there is a change in the allocation
schedule. The commenter said it was
not practical or beneficial to update the
CAA each time the allocation schedule
changes. The BLM agrees that requiring
an update to the CAA when the
allocation schedule changes is not
necessary. The intent of requiring
information on the allocation was to
ensure that the BLM can verify and recalculate the volumes reported on the
OGORs. Allocation schedules are often
based on periodic well testing and can
change each time a well test is
conducted. As long as the BLM
thoroughly understands the allocation
methodology, we can request the well
testing or other data from which the
operator determines the allocation
schedule and verify that the allocation
was done in accordance with the
allocation methodology and was
properly reported on the OGOR.
Paragraph (a)(1) has been modified to
require a CAA modification only when
there is a modification to an allocation
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agreement, which in the final rule must
include an allocation methodology
rather than an allocation schedule.
Thus, only if there is a change in the
methodology used to determine
allocation percentages would an
operator have to make changes to their
existing CAA. A change to the allocation
schedule itself would not require such
a modification.
One commenter did not like the idea
of having a CAA re-evaluated when new
leases are proposed to be added to the
CAA, as required under § 3173.18(a)(2).
The BLM disagrees with this comment
and did not make any changes to the
rule as a result. The addition of a lease,
unit PA, or CA to an existing CAA will
affect the allocation of production in a
CAA, and therefore the BLM will need
to review the addition to ensure that the
allocation method is verifiable and
provides a fair return to the Federal
Government or Indian tribes or allottees.
Finally, several commenters asked
whether submission of a ‘‘Successor of
Operator Sundry Notice’’ would
automatically change the operator of the
FMP and the CAA. A Sundry Notice for
a change in operator of a well(s) and a
facility on a lease, unit PA, or CA will
designate that new operator as being
responsible for reporting production
from the property, and therefore will
include the CAA agreement. In response
to this comment, the BLM has removed
one of the conditions under which a
CAA may be modified—when there is a
change in operator. Furthermore, a new
paragraph (c) has been added to the
final rule stating that a change in
operator will not trigger the need to
modify the CAA. The FMP will
automatically transfer since it is part of
the facility.
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Section 3173.19 Effective Date of a
Commingling and Allocation Approval
Section 3173.19 (a) and (b) of the final
rule identifies the effective date of a
CAA after the approval of an application
or modification, respectively. Paragraph
(c) of this section clarifies that a CAA
does not modify any of the terms of any
leases, unit PAs, or CAs. The BLM did
not receive any public comments on this
section and did not change it in the final
rule, except to make minor
modifications for clarity.
Section 3173.20 Terminating a
Commingling and Allocation Approval
Paragraph (a) of § 3173.20 of this final
rule (paragraph (b) of the proposed rule)
authorizes the BLM to terminate an
approved CAA for any reason, including
changes in technology, regulation, or
policy, or where the operator has not
complied with the terms of the CAA.
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Paragraph (b) (paragraph (c) of the
proposed rule) provides for automatic
termination of a CAA if only one lease,
unit PA, or CA remains in the CAA.
Paragraph (c) (paragraph (a) of the
proposed rule) states that an operator
may terminate its participation in a
CAA by submitting a Sundry Notice to
the BLM. Unlike the provision in the
proposed rule, paragraph (c) of the final
rule clarifies that the termination by one
operator does not automatically
terminate the CAA as to all other
operators, so long as the requirements of
this part are met with respect to the
remaining participants in the CAA.
After termination of a CAA, paragraph
(d) requires the BLM to notify in writing
all operators who are a party to the CAA
of the effective date of the termination
and any inconsistencies or deficiencies
with their CAA approval that caused the
termination. The BLM modified this
provision from the proposed rule to
provide that upon receipt of the BLM’s
notice of termination, the operator has
20 business days to correct any
inconsistencies or deficiencies, or
provide additional information that the
AO has requested or that explains or
justifies the inconsistency or deficiency.
If the operator does not correct the
inconsistency or deficiency within 20
business days after receipt of the BLM’s
notice, the CAA is terminated as of the
effective date in the BLM’s notice. The
effective date of the termination will not
be earlier than the 20 business days
outlined in paragraph (d). Paragraph (e)
provides that upon termination, each
lease, unit PA, or CA may require a new
FMP number or a new CAA. Under the
final rule, operators will have up to 30
days to apply for a new FMP number or
CAA, whichever is applicable.
Following termination, while the BLM
is processing the application for a new
FMP number or CAA, the operator may
use the existing FMP number for
recordkeeping and production
reporting.
Several commenters were concerned
that paragraph (a) in the proposed rule
would have allowed a party to a CAA
to unilaterally terminate the CAA by
submitting a Sundry Notice to the BLM,
and that paragraph (b) in the proposed
rule, or paragraph (a) in the final rule,
allows the BLM to terminate a CAA for
any reason. One commenter said it
would be fine to allow a party to
terminate their participation in the
CAA, but the remaining operators
should have the opportunity to continue
with the CAA. One commenter asked
that the final rule be changed to allow
an existing CAA to continue after one of
the parties pulls out, as long as the
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81399
remaining operator(s) follow the COAs
for the CAA.
The BLM agrees with the commenters
and believes that the continued
operation of a CAA when one operator
decides to pull out is in the public
interest. All the CAA requirements of
this rule are designed to ensure that the
CAA is in the public interest by, for
example, allowing continued
production of low volume properties,
addressing other overriding
considerations, or allowing the
maximum ultimate recovery of oil and
gas resources. The BLM does not believe
that the decision of one operator to pull
out of the CAA would change the BLM’s
public interest determination and
terminating the CAA as a result would
only result in additional paperwork for
both the BLM and industry. Instead, the
operator who wants to terminate its
own, individual participation in the
CAA should be able to do so. In
response to this comment, the BLM
removed proposed paragraph (a) in the
final rule and re-designated it with
modifications as paragraph (c). While
paragraph (c) still allows an operator to
terminate a CAA through submission of
a Sundry Notice, the BLM clarified that
paragraph in response to comments to
make clear that termination of
participation in a CAA by one operator
does not necessarily impact all
operators, so long as the other
requirements of this part are met with
respect to that CAA and the other
operators submit a Sundry Notice for a
new CAA as required by paragraph (e).
An operator who wishes to terminate
its participation will need to submit the
appropriate paperwork to the BLM as
outlined in 3173.20(c). Additionally, if
a CAA is terminated, paragraph (e) of
the final rule no longer requires separate
measurement. Rather, it gives operators
30 days to apply for a new FMP number
and/or CAA, if applicable. The old FMP
number may be used for recordkeeping
and production reporting until a new
FMP number is assigned or a new CAA
is approved. If more than one lease, unit
PA, or CA remains in a CAA, the
operator(s) of those leases, unit PAs, or
CAs will need to submit a Sundry
Notice for a new CAA under § 3173.18.
Another commenter stated that they
have established gathering systems that
are subject to the existence of CAAs. If
the CAA is terminated by the BLM, the
commenter states that operators could
no longer sell gas into the gathering
system, which could result in the shut
in of wells, lost production and lost
revenues. Instead, the operator suggests
that if an operator no longer wants their
lease to be part of a CAA, the CAA
could be easily modified to include only
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the remaining leases. The BLM agrees
with this comment and removed
paragraph (a) as discussed above.
Regarding comments that the BLM
should not have the authority to
terminate existing CAA approvals for
any reason, commenters already should
be aware that under the terms of all
existing CAAs, the BLM retains the right
to terminate a CAA for any reason.
Thus, the requirements found in
paragraph (a) are a codification of
existing practices. However, the reasons
listed under paragraphs (a)(1) through
(a)(3) of this final rule should cover the
majority of the situations that could lead
to termination of a CAA. If a CAA is not
in compliance with this rule’s
commingling requirements, the BLM
will work with the operators on a caseby-case basis to bring the CAA back into
compliance to avoid a termination. If a
CAA is terminated because of changes
in technology, regulation, or BLM
policy, operators will be given sufficient
time to make any necessary changes. In
the event that the BLM does take steps
to terminate a CAA, paragraph (c) of this
final section provides that the BLM’s
notice-of-termination letter will describe
the inconsistencies or deficiencies that
will lead to the CAA termination, along
with the effective date of the
termination. The parties to a CAA will
then have an opportunity to avoid
termination of the CAA by correcting
those inconsistencies or deficiencies
within 20 business days of their receipt
of notification.
Section 3173.21 Combining
Production Downhole in Certain
Circumstances
Section 3173.21 of this final rule
identifies certain circumstances in
which downhole combining of
production is subject to the
commingling requirements contained in
§§ 3173.14 through 3173.20. Under
paragraph (a)(1), the combination of
production from a single directional
well drilled into different hydrocarbon
pools or geologic formations under
separate adjacent properties, regardless
of ownership, where none of the pools
or formations are common to more than
one of the properties, constitutes
commingling under the final rule, and is
therefore subject to the requirements in
§§ 3173.14 through 3173.21 of this
subpart. If, on the other hand, the pools
or geologic formations are common to
more than one property, then under
paragraph (a)(2), the operator is required
to establish a unit PA or CA as opposed
to obtaining a CAA. Paragraph (b)
clarifies that combining production
downhole from different geologic
formations on the same lease from a
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single well, while requiring AO
approval, is not considered
commingling for purposes of this final
rule, unless those formations have
different ownership.
The BLM did not receive any public
comments on this section, but did make
one small change. In paragraph (b), the
final rule clarifies that the requirements
of §§ 3173.14 through 3173.20 do not
apply when operators combine
production downhole from different
geologic formations on the same lease in
a single well.
Sections 3173.22 through 3173.28 OffLease Measurement Approvals
Sections 3173.22 through 3173.28 of
this final rule establish the
circumstances in which the BLM will
approve measurement of production off
of the lease, unit, or CA (referred to as
‘‘off-lease measurement’’). Prior to this
rule, there were no national standards
that operators had to meet when
applying for off-lease measurement.
Neither Order 3 nor other regulations
addressed how or under what
circumstances the BLM would approve
off-lease measurement. This lack of
guidance led to much confusion over
the location of off-lease measurement
points. Off-lease measurement is also
often associated with commingling.
Meters that measure commingled
production are often referred to as
central delivery points. In most
situations, the meter at the central
delivery point is located off of at least
one of the Federal or Indian leases,
units, or CAs from which the
production originates. This
configuration requires the BLM to
approve both the commingling and the
off-lease location of the measurement
point.
In the absence of uniform national
standards governing off-lease
measurement, BLM State Offices created
their own policies for approving offlease measurement applications, which
were not necessarily consistent.
Sections 3173.22 through 3173.28 of
this final rule, discussed below, provide
such uniform national standards,
addressing the concerns identified by
the GAO, the OIG, and the
Subcommittee.
Some commenters said that this
section contains new record-keeping
requirements that are vague and that
could cause operators to submit
incorrect applications for off-lease
measurement. The commenters did not
specify the sections that they believe are
vague, nor did they provide any
explanation as to why they are vague.
The BLM did not make any changes to
the rule based on these comments. The
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BLM notes, however, that § 3173.23
contains a complete list all of the
information and documentation that
operators need to provide to the BLM
when applying for off-lease
measurement approvals.
Section 3173.22 Requirements for OffLease Measurement
Section 3173.22 of the final rule
establishes the conditions under which
the BLM will consider granting a
request for off-lease measurement. It
requires such requests to satisfy the
requirements of paragraphs (a) through
(d). Under paragraph (a), the BLM will
consider off-lease measurement of
production only from a single CAA or
a single Federal or Indian lease, unit PA,
or CA. Paragraph (b) requires that the
off-lease measurement provide for
accurate production accountability and
paragraph (c) requires that off-lease
measurement be in the public interest.
Paragraph (d) requires off-lease
measurement to occur at an approved
FMP.
Commenters asked that the BLM list
the conditions under which off-lease
measurement will be approved. The
BLM did not make any changes to the
rule based on this comment because this
section clearly lists the conditions
under which off-lease measurement will
be considered for approval. Requests
that meet the requirements of this
section will be approved, while requests
that do not will not be approved.
Another commenter requested that
the BLM provide exemptions from the
off-lease measurement requirements in
situations where topography or other
environmental issues prevent operators
from measuring on-lease. The BLM
agrees that there are circumstances
when it is physically impractical to
measure on-lease or where measuring
on-lease could cause additional
environmental impacts. Examples
include situations where well pads are
located at high altitudes that could be
inaccessible in the winter or when the
BLM has imposed seasonal access
restrictions due to environmental
concerns. In response to this comment,
final paragraph (c) has been changed to
allow off-lease measurement when onlease measurement is not practical due
to topographic or environmental
concerns. As with any of the
requirements in this subpart, an
operator may also request a variance to
the off-lease measurement requirements
on a case-by-case basis.
One commenter said its liquidsgathering system, which is within the
boundary of a CAA, should be exempt
from the off-lease measurement
requirements of § 3173.22 because this
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system has been in place for over 10
years, was approved by the BLM, and
works well. The BLM did not change
the final rule in response to this
comment. Instead, the BLM will review
existing off-lease measurement
approvals associated with CAAs, along
with the CAAs themselves, on a case-bycase basis as part of the FMP approval
process to ensure consistency with the
minimum standards and requirements
under § 3173.22 of the final rule.
Several commenters said that the new
off-lease measurement requirements
will result in more FMPs and that offlease measurement—because it requires
fewer FMPs—provides better accuracy
and reduces recordkeeping, allowing
multiple wells or pads (in a unit
operation) to commingle production at a
central tank battery. These commenters
asserted that this made it easier for the
BLM to track production and audit
facilities.
The BLM believes the commenters are
confused about the definition of offlease measurement. The operator can
locate an FMP, including a central tank
battery as mentioned by the
commenters, anywhere within the
boundary of a lease, a unit, or a CA from
which the production originates without
meeting the definition of off-lease
measurement and without needing
approval from the BLM. Although the
requirements for approving a CAA in
this rule may increase the number of
FMPs required, the BLM does not agree
that the off-lease measurement
requirements of this rule would have
any effect on the number of FMPs
required. As noted earlier in discussion
of § 3173.15(a) of the final rule, if offlease measurement is a feature of a
commingling and allocation proposal,
then a separate Sundry Notice
application for off-lease measurement is
not necessary and the off-lease
measurement proposal will be
considered as part of the CAA request.
The BLM expects that this final rule will
have a smaller impact than the proposed
rule would have had on existing offlease measurement approvals tied to
CAAs because §§ 3173.14(b) and
3173.16(a) of the final rule includes an
expanded list of exemptions that allow
commingling as well as grandfathering
provisions for some existing CAAs.
Finally, a few commenters said that
some existing off-lease measurement
approvals could be at risk if they do not
meet the BLM’s conditions for being ‘‘in
the public interest,’’ as outlined in
paragraph (c) of this section. We agree
that some existing off-lease
measurement approvals may not be in
the public interest, and they will
therefore be terminated. The public
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interest generally includes minimizing
environmental impacts, achieving
maximum ultimate economic recovery,
and allowing the BLM to verify volumes
and qualities of oil and gas reported on
the OGORs. Existing approvals that are
merely for the convenience of the
operator may not be in the public
interest. If, for example, an existing offlease measurement approval allows the
FMP to be located on private land that
makes BLM access difficult or
impossible, and the approval cannot be
justified based on environmental
circumstances or achieving maximum
ultimate economic recovery, it is likely
that the BLM will terminate the
approval. The BLM estimates that best
management practices and
environmental and topographic
considerations will outweigh the need
to terminate many existing off-lease
measurement approvals or to deny new
ones. The final rule was not changed in
response to these comments.
Section 3173.23 Applying for OffLease Measurement
Section 3173.23 of this final rule
establishes the requirements operators
must follow when applying for an offlease measurement approval or
amending an existing approval,
including required supporting
information and related documentation.
One commenter said that this section
of the rule is unnecessary and
redundant and that the off-lease
measurement application and approval
process should be part of the APD
process. The BLM does not agree that
this section is unnecessary and
redundant because it establishes the
process that operators will use to apply
for an off-lease measurement approval,
which is entirely separate from and
independent of the process the BLM
uses to process an APD. However,
§ 3173.23 does not prohibit operators
from submitting new off-lease
measurement applications with their
APDs. The BLM, in fact, would prefer to
receive comprehensive proposals
upfront from operators when they
submit their APDs because it
streamlines the BLM’s review process
by allowing BLM staff to look at a
project in its entirety early in the
permitting process.
Section 3173.23(a) requires operators
to submit their off-lease measurement
application via a Sundry Notice. That
Sundry Notice package may be
submitted at the same time as, but
separately from, an operator’s APD
package(s) and the BLM will process
both applications at the same time. The
final rule did not change as a result of
this comment.
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Several commenters said it would be
too burdensome to require operators,
whose off-lease measurement facilities
are located on non-federally owned
surface, to include in their off-lease
measurement applications written
concurrence from the surface owners,
including from future owners if the
ownership changes, as called for in
paragraph (e) of the final rule. The BLM
does not agree with these commenters.
Operators should already be obtaining
concurrences from surface owners as
part of the APD process as Onshore
Order 1 (Approval of Operations)
specifically requires operators to make a
good faith effort to obtain a Surface
Access Agreement from the surface
owner. Therefore, this requirement does
not place any additional burden on the
operator.
In addition, the BLM must have
guaranteed access to the off-lease
measurement location. Without this
guaranteed access, the BLM may not be
able to verify or account for the volumes
and qualities of oil and gas on which
royalty is due and would therefore deny
the off-lease measurement request or
terminate the existing off-lease
measurement approval. No change to
the rule was made in response to this
comment.
Finally, one commenter said that the
proposed rule did not specifically
require operators to obtain the written
consent of the owner and operator of
measurement facilities. As a result, the
commenter said, this rule would subject
owners and operators of the
measurement facility to the jurisdiction
of the BLM without its consent or
knowledge. The BLM believes that this
is a valid concern. However, the BLM
did not make a change to the rule in
response to this comment because
paragraph (e) (paragraph (f) in the
proposed rule) already requires
operators to obtain written concurrence
signed not only by the surface owner(s),
but also by the owner(s) of the
measurement facilities.
In addition to these changes, the BLM
made a few minor administrative
changes to final § 3173.23. These
clarifications were consistent with the
overall changes made to the final rule
and were not made in response to any
particular comments. The BLM added a
new paragraph (h) to the final rule to
clarify that operators, under existing
BLM regulations, must obtain approval
from the appropriate surfacemanagement agency, if new surface
disturbance is proposed for the FMP,
and its associated facilities are located
on Federal land managed by an agency
other than the BLM. The BLM also
clarified paragraph (f) to state that an
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operator needs to submit a right-of-way
grant application to the BLM along with
the off-lease measurement request only
when new surface disturbance is
proposed for the FMP and its associated
facilities are located on BLM-managed
land. If the proposed surface facilities
are on Indian land, then paragraph (g)
of the final rule requires that a right-ofway grant application must be filed with
the appropriate BIA office.
Other changes we made that were
unrelated to public comments include
modifications to the type of information
operators must submit as part of their
off-lease measurement application. In
paragraph (c)(2) of the final rule, the
BLM no longer requires the operator to
identify the land description of all
wells, pipelines, and other facilities
expected to be installed as part of their
proposal. Operators need only identify
the relative location of such facilities.
Paragraph (e) in the proposed rule
required submission of a schematic or
engineered drawing showing all new
facilities that are part of the off-lease
measurement proposal. This
requirement is no longer in the final
rule. Finally, the requirement in
paragraph (e) of the proposed rule that
called for the submission of a site
facility diagram for existing facilities if
changes are being proposed to the
facility is removed as unnecessary
because the requirements related to site
facility diagrams for existing facilities
are already addressed by § 3173.11. The
BLM elected to make these changes
consistent with the changes made to the
information-submission requirements
for commingling applications under
§ 3173.15 of the final rule. It is not
necessary for the information-collection
requirements for commingling
applications to be different than the
information-collection requirements for
off-lease measurement applications.
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Section 3173.24 Effective Date of an
Off-Lease Measurement Approval
Section 3173.24 provides that offlease measurement approvals are
effective on the date the BLM issues the
approval, unless the BLM specifies a
different effective date in the approval.
The BLM did not receive any public
comments on this provision and did not
make any changes to the final rule.
Section 3173.25 Existing Approved
Off-Lease Measurement
Under this section of the final rule, an
existing off-lease measurement approval
will be reviewed upon receipt of an
operator’s request for the assignment of
an FMP number to a facility associated
with the off-lease measurement
approval. Section 3173.25(a) states that
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the AO reviews the existing off-lease
measurement approval for consistency
with the minimum standards and
requirements in § 3173.22. The AO will
notify the operator in writing of any
inconsistencies or deficiencies. Under
paragraph (b), the operator will have to
correct the inconsistencies or
deficiencies, provide the additional
information that the AO has requested,
or request an extension from the AO
within 20 business days. If an operator
is requesting an extension, they must
justify the request by explaining the
factors that will not allow the operator
to comply within 20 days and provide
a timeframe under which the operator
can comply.
Under paragraph (c), in connection
with approving the requested FMP, the
AO may terminate an existing off-lease
measurement approval and grant a new
off-lease measurement approval with
new or amended COAs to make the
approval consistent with the
requirements of this rule. In addition,
paragraph (c) provides that the existing
off-lease measurement approval will
continue in effect during any pendency
of an appeal of the new off-lease
measurement approval. If the operator
fails to correct the deficiencies,
paragraph (d) provides that the AO may
terminate the off-lease measurement
approval. If the existing off-lease
measurement approval under this
section is consistent with the
requirements under § 3173.22(e) of the
final rule allows that existing off-lease
measurement be grandfathered and be
part of the operator’s FMP approval.
Under paragraph (f), if the BLM grants
a new off-lease measurement approval,
that new approval is effective on the
first day of the month following its
approval.
Several commenters had concerns
with the paragraph (a) requirement that
the AO review existing off-lease
measurement approvals to determine if
they comply with the new off-lease
measurement requirements in § 3173.22.
These commenters requested that the
BLM ‘‘grandfather in’’ existing off-lease
measurement approvals. Another
commenter said that operators spent
countless hours negotiating their
existing CAAs, along with their off-lease
measurement approvals, with BLM field
staff, which resulted in protections for
environmentally sensitive areas and
accurate measurement of production.
The BLM agrees with the comments
as they relate to grandfathered CAAs
and included language under
§ 3173.16(a) that also grandfathers
existing off-lease measurement
approvals that are included as part of
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those grandfathered CAAs under
§ 3173.16(a)(1) or (2).
The BLM does not, however, agree
that existing off-lease measurement
approvals that are not included in
§ 3173.16(a) should be grandfathered.
As we stated earlier in this preamble, a
major goal of this final rule is to ensure
that new and existing approvals—be
they for CAAs or off-lease
measurement—allow BLM staff to verify
that oil and gas are being measured and
reported accurately under these
approvals. Without the ability to
consistently track where and how oil
and gas are measured, the BLM cannot
be assured that production reporting is
accurate. Section 3173.25 sets up a
process for the BLM to review existing
non-grandfathered off-lease
measurement approvals that were
granted before the BLM established
guidance and standards that ensure
such approvals were structured so that
BLM staff can verify production
reporting.
For existing off-lease measurement
approvals that are associated with a
non-grandfathered CAA, the CAA
would provide the public interest
justification for the off-lease
measurement approval, whether that is
due to economics, protection of the
environment, or to achieve maximum
ultimate economic recovery. The BLM
estimates that more than 95 percent of
existing CAAs will be either
grandfathered or approved under the
provisions of the final rule. Therefore,
the only aspect of non-grandfathered
off-lease measurement approval that the
BLM will be concerned with is the
BLM’s access to the proposed off-lease
measurement location.
Another commenter said that the
proposed rule would have required
operators to submit all existing off-lease
measurement approvals to the BLM for
re-approval. The BLM disagrees. This
rule does not require operators to
submit all existing authorizations to the
BLM for re-approval. It does provide
that the AO, when an operator submits
an application for an FMP number
associated with an existing off-lease
measurement approval, the AO will
review that existing approval for
consistency with the minimum
standards and requirements for off-lease
measurement under § 3173.22 and
notify the operator in writing of any
inconsistency or deficiency, or request
additional information. No changes to
the final rule were made as a result of
this comment.
Several commenters were concerned
that paragraph (b) gives operators only
20 business days to correct any
inconsistencies or deficiencies that the
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AO identifies with existing off-lease
measurement approvals or to provide
any additional information the AO
requests. The commenters said 20
business days is not enough time to
make such corrections and
recommended that operators be given 60
to 90 days to fix any problems. One
commenter said some operators could
be required to reconfigure their pipes in
order to maintain their off-lease
measurement approvals, which would
likely take longer than 20 days to
accomplish. Several others said that
since this is the first time that the BLM
will be reviewing existing CAAs and offlease measurement approvals for
compliance with the new requirements,
every commingling facility with offlease measurement will need some
corrective work and operators must be
given more than 20 days to bring their
operations into compliance if they
receive multiple notices.
The BLM believes that some of the
commenters have confused the
requirements relating to the review of
existing off-lease measurement
approvals with those relating to the
review of existing CAAs under
§ 3173.16(b). The review of existing offlease measurement approvals will have
nothing to do with allocation methods
and will rarely involve any on-theground work. The BLM will be
concerned with only four issues when
reviewing existing off-lease
measurement approvals:
1. Does the existing off-lease
measurement point only measure
production from one lease, unit PA, CA,
or CAA?
2. Is the off-lease measurement point
reasonably accessible to the BLM for the
purpose of production accountability?
3. Is the off-lease measurement
approval in the public interest?
4. Does the off-lease measurement
occur at an approved FMP?
For the majority of existing off-lease
measurement approvals that are
associated with a CAA, items 1, 3, and
4 will already be addressed by the CAA.
Therefore, the only review the BLM will
do is to ensure the off-lease
measurement point is reasonably
accessible to the BLM. In the rare case
where it is not, the BLM may require
that the operator either modify the
location to make it more accessible to
the BLM or, in the most extreme cases,
move the measurement facility to a
location where it is accessible to the
BLM.
Second, in response to these
comments, the BLM added language to
the final rule that allows an operator to
request an extension of the 20-day
timeframe. The operator should justify
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the extension request by explaining the
factors that will not allow them to
comply within the 20-day timeframe
and provide a timeframe under which
they can comply.
One commenter objected to a
provision in paragraph (c) that allows
the AO to impose new or amended
COAs on an existing off-lease
measurement approval to make the
approval consistent with the off-lease
measurement requirements in § 3173.22.
The commenter was referring to an offlease measurement approval that is part
of an existing CAA. The commenter
stated that numerous sales contracts are
based on existing approvals and that by
changing the approval, gas sales
contracts may be at risk of termination.
Other commenters expressed concern
that new COAs could result in economic
burdens that would result in the shutin of production and loss of Federal or
Indian royalty. Other commenters said
the new off-lease measurement
requirements would force them to
reconfigure gathering lines at sites
where existing off-lease measurement
agreements were not approved, which
would be costly and cause additional
environmental impacts that may not be
necessary.
The BLM did not make any changes
to the rule based on this comment
because this has little do with the offlease measurement approval and much
more to do with the CAA approvals,
discussed previously in the preamble.
As discussed in the portion of this
preamble dealing with commingling, the
primary concern of the BLM when
reviewing existing off-lease
measurement approvals that are
associated with a CAA is to ensure that
the BLM has reasonable access to
inspect the off-lease measurement
facility. Generally, the only COAs that
the BLM would impose on an existing
off-lease measurement approval that is
associated with a CAA would relate to
ensuring BLM access to the FMP. These
COAs could include remedies such as
obtaining express authorization for the
BLM to access the facility in situations
where the facility is not located on land
managed by the BLM, or in rare cases,
moving the measurement facility to a
location that does provide the BLM
reasonable access. This paragraph
further provides that if the operator
appeals one or more of the new COAs,
the existing off-lease measurement
approval will continue during the
pendency of the appeal.
The BLM would like to reiterate that
most of the existing wells in the San
Juan Basin, where surface and
downhole commingling are occurring
together with off-lease measurement,
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81403
may be exempt from having to meet the
new commingling and related off-lease
measurement requirements because they
qualify for grandfathering under
§ 3173.16(a). Section 3173.16(a)
grandfathers all existing downhole
commingling CAAs and any existing
surface CAAs if the average production
over the past 12 months is less than
1,000 Mcf of gas per month, or 100 bbl
of oil per month for each lease, unit PA,
or CA included in the CAA. In such
cases, the associated off-lease
measurement approval would also be
grandfathered under § 3173.16(a).
Section 3173.26 Relationship of OffLease Measurement Approval to
Royalty-Free Use of Production
Section 3173.26 of the final rule
clarifies that approval of off-lease
measurement does not constitute
approval of off-lease royalty-free use of
production as fuel in facilities located at
an approved off-lease FMP. Under NTL–
4A, the lessee or operator may claim
royalty-free use only for gas or oil used
on the same lease, on the unit for the
same unit PA, or on the same CA from
which the gas or oil was produced.
Thus, the lessee or operator may not
claim royalty-free use for any of the
production used as fuel at an off-lease
FMP, absent BLM approval.
One commenter asked that the BLM
define the term ‘‘royalty-free use’’ in
this rule. As explained in this preamble
with respect to § 3173.1, the BLM does
not believe such a change is necessary.
The definition of royalty-free use in
NTL–4A will control unless and until it
is replaced.
Section 3173.27 Termination of OffLease Measurement Approval
Section 3173.27(a) of the final rule
provides that the BLM may terminate an
off-lease measurement approval for any
reason. By way of illustration, this
paragraph identifies certain
circumstances under which the BLM
might exercise that authority—such as
changes in technology, regulation, or
BLM policy; operator non-compliance
with the terms or conditions of the offlease measurement approval; or operator
non-compliance with §§ 3173.22
through 3173.26. Under paragraph (b),
the BLM will notify the operator in
writing of the effective date of the
termination and any inconsistencies or
deficiencies with the operator’s
approval that serve as the reason(s) for
the termination. Upon receipt of the
BLM’s notice, the operator will have 20
business days to correct any
inconsistencies or deficiencies, or
provide any additional information the
AO requests. Paragraph (b) also provides
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an opportunity for an operator to
request an extension of time from the
AO within 20 business days after receipt
of the BLM’s notice, or the off lease
measurement approval terminates.
Paragraph (c) provides that an
operator may terminate an off-lease
measurement approval by submitting to
the BLM a Sundry Notice, which must
identify the new FMPs for the lease(s),
unit PA(s), or CA(s) previously subject
to the off-lease measurement approval.
Under paragraph (d), each lease, unit
PA, or CA that was subject to the offlease measurement approval may
require a new FMP number(s) or a new
off-lease measurement approval.
Operators will have up to 30 days to
apply for a new FMP number or offlease measurement approval, whichever
is applicable. While the BLM processes
the application for a new FMP number
or off-lease measurement approval, the
operator may continue to use the
existing FMP number.
The BLM received several comments
on this section of the proposed rule, one
of which expressed concern that
proposed § 3173.27 did not provide an
explicit timeframe or process for the
BLM to terminate off-lease measurement
approvals or for operators to correct the
inconsistencies or deficiencies that led
to the termination. This commenter
recommended that the BLM give
operators 9 months to correct their
inconsistencies or deficiencies before
terminating their approvals. Several
other commenters objected to paragraph
(a) of the final rule (paragraph (b) of the
proposed rule), which authorizes the
BLM to terminate an off-lease
measurement approval for any reason.
One commenter stated that some gas
sales contracts involving gathering
systems are based on having off-lease
measurement approvals and CAAs and
that if the BLM terminates the off-lease
measurement approval, the operator
will no longer be able to sell gas into the
gathering system. The commenter stated
that operators need to have some
confidence that the existing off-lease
measurement approval will allow
continued operations as long as the
operator follows the COA for the offlease measurement approval. If there are
issues to be resolved, the operator
should be given a reasonable time to
resolve the issues.
The BLM agrees in part with these
comments and made several changes to
the final rule in response. Under
revisions to final paragraph (b), the
BLM’s notification letter will describe
the inconsistencies or deficiencies in
the operator’s existing off-lease
measurement approval that will result
in the termination, and state the
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effective date of the termination. The
revisions also give the operator 20
business days from receipt of the letter
to correct the inconsistencies or
deficiencies identified by the BLM,
provide more information, or request an
extension of time from the AO in order
to avoid termination. The BLM does not
agree with a 9-month timeframe as
recommended by one commenter
because unique circumstances may
warrant different timeframes. If an
operator believes that correcting the
inconsistencies or deficiencies will take
longer than 20 days, it may request a
reasonable extension of time from the
AO in order to make any necessary
corrections.
The BLM received several comments
on paragraph (d) of the proposed rule.
Proposed paragraph (d) said that if an
off-lease measurement approval is
terminated, each lease, unit PA, or CA
subject to the approval reverts to
measurement on the respective lease,
unit, or communitized area.
Commenters said that this requirement
should not apply to gathering systems
that were installed with BLM approval
for the purpose of off-lease
measurement. If such an approval were
terminated, commenters said, the
gathering system could no longer
transport gas to the sales meter that is
off-lease and wells connected to the
gathering system would likely be shut in
or plugged as they could no longer sell
their gas. The new on-lease
measurement system would not be
connected to a gas sales line as well, the
commenter said. The commenter
recommended that the BLM delete the
whole section from the final rule.
The BLM disagrees with this
comment and did not make any changes
to the final rule as a result. The
commenter’s concern principally relates
to the underlying CAA approval, not to
the off-lease measurement approval
itself. The BLM’s primary concern with
off-lease measurement approvals that
are tied to a CAA is the BLM’s access
to the off-lease FMP for the purpose of
inspection and production accounting.
For off-lease measurement approvals
that are not tied to a CAA, § 3173.22(c)
allows the BLM to consider an
operator’s ability to achieve maximum
ultimate economic recovery from a
lease, unit PA, or CA in determining
whether it is in the public interest to
approve off-lease measurement. This
provision gives the BLM the leeway it
needs to exempt leases, unit PAs, or
CAs from the off-lease measurement
requirements in situations where denial
of off-lease measurement might result in
shut-ins.
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Section 3173.28 Instances Not
Constituting Off-Lease Measurement, for
Which No Approval Is Required
Section 3173.28 of the final rule
identifies two circumstances that will
not be considered off-lease
measurement for purposes of the rule.
The first is where an FMP is located on
a well pad of a directionally drilled well
that produces oil or gas from a lease,
unit, or CA on which the well pad is not
located. The second is where a lease,
unit, or CA is made up of separate noncontiguous tracts. If production is
moved from one tract to another tract
within the same lease, unit, or CA, and
the production is not diverted during
movement between the tracts before the
FMP (except for production used
royalty-free), measurement would not be
considered to be off-lease.
Several commenters were under the
impression that they would need offlease measurement approval for
horizontal and directionally drilled
wells where the well pad itself is
located off the lease, CA or unit. Under
paragraph (a), off-lease measurement
approval for such wells is not needed,
unless the FMP is also located off of the
well pad, regardless of distance. If any
of the facilities are located on nonfederally owned surface, the operator
will still need to obtain written
concurrence signed by the surface
owner(s), and the operator(s) of the
measurement facilities that grants the
BLM unrestricted access to the off-lease
measurement facility and the surface on
which it is located, in order to conduct
production verification inspections. The
BLM did not make any changes to the
rule based on this comment.
One commenter said that, in some
cases, there may by reasons to locate the
FMP near, but not actually on, the well
pad, triggering the need for the operator
to obtain off-lease measurement
approval. The commenter stated that if
the FMP is located a small distance off
the well pad, but clearly serves the
wells on the pad this should not require
an off-lease measurement approval. The
BLM disagrees with this comment and
did not make any changes to the rule as
a result. Paragraph (a) of this section
clearly states that the FMP must be
located on the well pad to avoid the
need for an off-lease measurement
approval. Normally, well pads are
clearly delineated in the field by a berm,
fence, or other easily-identifiable
feature. This makes the requirement
clear, objective, and enforceable.
Adding a provision that would, as
suggested by the commenter, include
FMPs that are only a short distance off
the well pad would render the provision
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for each applicable lease, unit PA, or
CA, since off-lease measurement or
commingling without approval is a
violation of this final rule and existing
BLM requirements under 43 CFR
3162.7–2 and 3162.7–3, both of which
require BLM approval before operators
store or measure production from a
Federal or Indian lease off-lease.
Some commenters argued that these
immediate assessments are inconsistent
with due process because there is no
opportunity for an operator to correct its
violations before an assessment is
imposed. To the contrary, the use of
immediate assessments for breaches of
the oil and gas operating regulations is
well established and is consistent with
the notice requirements of due process.
Section 3173.29 Immediate
Operators obligate themselves to fulfill
Assessments for Certain Violations
the terms and conditions of the Federal
Section 3173.29 expands the number
or Indian oil and gas leases under which
and types of violations that would be
they operate. These leases incorporate
subject to immediate assessments.
the BLM’s regulations by reference.
Immediate assessments are not civil
Thus, the immediate assessments
penalties and are separate from the civil contained in the regulations act as
penalties authorized under Section 109
‘‘liquidated damages’’ owed by
of FOGRMA, 30 U.S.C. 1719. Unlike the operators who have breached their
proposed rule, the final rule does not
leases by breaching the regulations. See,
subject purchasers and transporters to
e.g., M. John Kennedy, 102 IBLA 396,
immediate assessments—only operators. 400 (1988). Operators are expected to
For violation 7, non-retention of records know the obligations and requirements
necessary to determine quantity and
of the Federal or Indian oil and gas lease
quality of production, the final rule
under which they operate; additional
clarifies that the applicable regulation is notice is not required.
§ 3170.7, not § 3173.9(a)(1) and (2).
Several commenters said there could
Also, the final rule clarifies that
be instances when an operator is not
violation 8 could result in an immediate aware that a violation exists. One
assessment if operators fail to ‘‘apply
commenter said the assessment should
for,’’ rather than ‘‘obtain,’’ the required
be imposed only if the violation was a
FMP approval.
willful or knowing act of
With respect to violations 9, 10, and
noncompliance. Another commenter
11, which pertain to approvals for offsuggested the BLM place a Federal seal
lease measurement and surface or
and notify the operator of the violation
downhole commingling, respectively,
instead of issuing an immediate
the final rule clarifies that removing
assessment for something that they are
production from a facility that begins
not aware of or that might be beyond
operation after the effective date of the
their control. The BLM disagrees with
final rule, prior to receiving BLM
these comments. Operators have a
approval for off-lease measurement or
responsibility to inspect their properties
commingling, could result in an
to ensure site security, consistent with
immediate assessment. If the facility
all applicable regulations, including this
will be servicing new wells not yet
final rule. The violations outlined in
drilled, as well as existing wells already this section of the final rule all have
in production, then the existing wells
substantial adverse impacts on
must use their respective existing FMP
production accountability or royalty
numbers when reporting production to
income and, thus, the BLM believes the
ONRR’s OGOR until the BLM assigns
assessments are warranted. No changes
to the rule were made in response to
the new FMP number associated with
these comments.
its off-lease measurement or
Numerous commenters said that the
commingling approval.
An existing facility (i.e., one in service increases in the number of immediate
assessments related to producing
on or before the effective date of the
operations, from 1 to 11, and in the
final rule) would be subject to an
dollar amount of the assessments, from
immediate assessment if it engaged in
$250 to $1,000, are unreasonable. The
off-lease measurement or commingling
number of immediate assessments was
without an existing BLM approval.
expanded to include violations that
Under such circumstances, the BLM
pose particular threats to the integrity of
could issue an immediate assessment
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subjective and unenforceable. If the
operator can demonstrate that locating
the FMP a small distance off the well
pad is in the public interest and that the
BLM has guaranteed access to inspect
the FMP, then the BLM would approve
off-lease measurement.
Another commenter suggested that
the BLM add a paragraph to this section
that states gas used for fuel at locations
that are not considered to be ‘‘off lease’’
under paragraphs (a) and (b) of this
section qualifies as royalty-free usage.
The BLM did not make any changes to
the rule based on these comments
because what qualifies as royalty-free
use is outside the scope of this
rulemaking.
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81405
the BLM’s production accounting
system and that significantly increase
the BLM’s workload and enforcement
costs. The increase to $1,000 is justified
because it generally approximates what
it will cost the agency, on average, to
identify and document a violation and
verify remedial action and compliance.
Commenters objected to this section
of the proposed rule subjecting
purchasers and transporters to
immediate assessments. One said that
purchasers and transporters should not
be involved in retaining records
pertaining to the quality and quantity of
production. Another commenter said
that oil and gas lease agreements are a
contract between the government and
lessees and that purchasers and
transporters are not a party to those
agreements and, therefore, should not be
subject to these assessments. Other
commenters argued that the proposed
immediate assessments on purchasers
and transporters exceeded the BLM’s
statutory authority under FOGRMA.
Upon consideration of these arguments,
and further review and analysis of
FOGRMA and other authorities, the
BLM has removed the immediate
assessments on purchasers and
transporters from final § 3173.29.
Enforcement Actions
As explained in the proposed rule, the
final rule removes the enforcement,
corrective action, and abatement period
provisions of Order 3. In their place, the
BLM will develop an internal Inspection
and Enforcement Handbook that will
provide direction to BLM inspectors on
how to classify a violation—as either
major or minor—what the corrective
action should be, and what the
timeframes for correction should be.
The AO will use the Inspection and
Enforcement Handbook in conjunction
with 43 CFR subpart 3163, which
provides for assessments and civil
penalties when lessees and operators
fail to remedy their violations in a
timely fashion, and for immediate
assessments for certain violations.
As previously discussed in the
proposed rule, the final rule allows the
BLM to make a case-by-case
determination of the severity of a
violation, based on applicable
definitions in the regulations. In
deciding how severe a violation is, BLM
inspectors must take into account
whether a violation could result in
‘‘immediate, substantial, and adverse
impacts on public health and safety, the
environment, production accountability,
or royalty income.’’ (Definition of
‘‘major violation,’’ 43 CFR 3160.0–5.)
Under the existing definition of ‘‘major
violation,’’ which is not being revised as
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part of this rulemaking, the same
violation could be major or minor,
depending on the context.
Several commenters objected to the
BLM using internal guidance or the
Inspection and Enforcement Handbook
to address violations, assessments for
noncompliance, and corrective actions.
Commenters argued that the use of
internal enforcement guidance is
inconsistent with the APA and that
these guidance documents constitute
substantive rules that must be
developed through notice-and-comment
rulemaking. These comments
misunderstand the nature of the Internal
Inspection and Enforcement Handbook
that the BLM will develop. The
Handbook will not establish new
obligations to be imposed on the
regulated community in a manner that
will improve consistency in how those
BLM personnel excise there discretion
in applying existing regulations and
addressing instances of non-compliance.
Those obligations are spelled out in
applicable regulations, orders, and
permits, as well as the terms and
conditions of leases and other
agreements. Rather, the Handbook will
provide guidance to BLM personnel as
to how to apply the existing regulations
and address instances of noncompliance. The overarching
enforcement infrastructure of 43 CFR
subpart 3163 remains in effect, and the
definitions of ‘‘major violation’’ and
‘‘minor violation’’ in § 3160.0–5 remain
unchanged. It is these duly promulgated
regulations (among other authorities),
and not the Inspection and Enforcement
Handbook, that will provide the legal
basis for the BLM’s enforcement actions;
the BLM’s enforcement actions must be
consistent with these regulations
irrespective of what may be contained
in its Inspection and Enforcement
Handbook. It is not necessary for the
BLM to develop its Handbook—which
does not expand the BLM’s authorities
or impose binding obligations on the
regulated community—through noticeand-comment rulemaking.
The commenters requested that the
BLM use a transparent process to
develop this internal guidance and that
operators be given the opportunity to
comment on it. The BLM did not accept
these comments; however, the BLM will
post the Inspection and Enforcement
Handbook on the BLM Web site after it
is developed and finalized.
Elimination of Self Inspections
Consistent with the proposed rule,
this final rule eliminates the selfinspection provision of Order 3, section
III.F., because it has been impractical for
the BLM to enforce. Under the self-
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inspection program, operators were
supposed to establish a program for the
purpose of periodically measuring
production volumes and assuring they
were complying with the BLM’s
minimum site security requirements.
But, as discussed earlier in response to
comments on this topic during the
discussion of § 3173.8, the Order 3
requirements were vague and the BLM
never supplemented them with internal
guidance or enforcement policy. As a
result, the BLM determined that this
requirement was of limited utility.
Nonetheless, the BLM received a
comment that recommended that
instead of removing the requirement,
the language should be improved to
ensure that an inspection program is
established for periodically measuring
production volumes and ensuring
compliance with the BLM’s site security
requirements from Order 3. The BLM
disagrees with this comment and did
not make a change in response. In lieu
of reworking or updating this
requirement, the final rule strengthens
recordkeeping requirements for
operators, including for transporters and
purchasers, which the BLM believes
will ultimately accomplish the same
results and be more useful going
forward. It should also be noted that
although the self-inspection
requirement from Onshore Order 3 has
been eliminated, the actions that an
operator, transporter, or purchaser must
take to conduct periodic production
volume inspections and ensure site
security have been incorporated into
this final rule as required elements
under §§ 3173.2 through 3173.10 of the
final rule.
General Comments
The BLM received a few comments
that were general in nature and do not
necessarily relate to a specific provision
of the rule.
A number of comments argued that
the rule is impermissibly ‘‘retroactive.’’
These comments argued that the rule is
retroactive because it will apply to
wells, facilities, and authorizations that
existed before the rule’s effective date.
While the BLM agrees that retroactive
regulations raise special legal concerns,
those concerns are not implicated here
because this rule is not a retroactive
regulation. The comments
misunderstand the nature of the
‘‘retroactive’’ regulations that the law
disfavors. ‘‘A law does not operate
‘retrospectively’ merely because it is
applied in a case arising from conduct
antedating the statute’s enactment or
upsets expectations based in prior law.’’
Landgraf v. USI Film Prods., 511 U.S.
244, 269 (1994) (internal citations
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omitted). Rather, the test for
retroactivity is whether the new
regulation ‘‘attaches new legal
consequences to events completed
before its enactment.’’ Id. at 270. The
rule at hand does not attach any new
legal consequence to the operation of
existing wells and facilities prior to the
rule’s effective date. As the U.S. Court
of Appeals for the D.C. Circuit has
explained, the fact that a change in the
law adversely affects pre-existing
business arrangements does not render
that law ‘‘retroactive:’’
It is often the case that a business will
undertake a certain course of conduct based
on the current law, and will then find its
expectations frustrated when the law
changes. This has never been thought to
constitute retroactive lawmaking, and indeed
most economic regulation would be
unworkable if all laws disrupting prior
expectations were deemed suspect.
Chemical Waste Mgmt., Inc. v. EPA, 869
F.2d 1526, 1536 (D.C. Cir. 1989). Thus,
despite the fact that this rule may
require operators to update or modify
their existing wells, facilities, and
authorizations, the rule is nonetheless
prospective—not retroactive—in nature.
A couple of comments expressed that
the BLM was employing discriminatory
regulation, and gave as their examples
the inequality of producers, operators,
and transporters in regard to equity
interest in production. The proposed
rule would treat producers, operators,
and transporters equally even though
some of these parties (specifically
transporters) have no ownership interest
in the oil and gas product generated
from Federal or Indian lands. Because
they have no interest, it is most likely
that the costs they incur will be passed
directly on to equity holders,
commenters said. Over time, the
commenter asserted, because equity
holders may deduct transportation costs
from royalties owed, this may result in
reduced royalty payments for both the
government and the tribes. While the
BLM recognizes the possibility of some
pass through of compliance costs from
purchasers and transporters to
operators, based on its analysis of the
costs of this final rule, it does not
believe those costs will be significant.
Additionally, this change is consistent
with the provisions of FOGRMA, which
addresses responsibilities and duties of
operators, purchasers, and transporters.
By statute, Congress applied these legal
requirements to those parties equally.
One commenter pointed out that the
regulations fail to recognize the current
industry business models, as it pertains
to Master Limited Partnerships. Unlike
C Corporations, MLPs have no
mechanism for capitalizing the required
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changes and will be forced to expense
the cost. This passes the cost
immediately to unit holders. The
commenter recommended that the BLM
remove MLPs from the regulation. The
BLM did not understand this comment
in the context of this rule. Under the
applicable statutes and regulations
operators, purchasers, and transporters
are subject to the regulations governing
operations on a Federal or Indian
(except Osage Tribe) lease. The
underlying corporate structure of those
entities has no bearing on their duty to
comply with these requirements.
Many commenters questioned
whether the BLM has the resources to
implement this and other rules that it
has finalized, or will finalize in the
coming months, for example the new
hydraulic fracturing regulations, which
went into effect on June 24, 2015
(currently enjoined by order of the
District Court of Wyoming), and the
proposed Waste Prevention, Production
Subject to Royalties, and Resource
Conservation proposed rule, which
published on February 8, 2016 (85 FR
6616). Commenters stated that the BLM
does not have enough staff to enforce its
existing regulations, let alone new ones.
Commenters also said that the
cumulative economic impact of this
final rule should be analyzed together
with the economic impacts of the final
rules that are updating and replacing
Orders 4 and 5.
The BLM does not agree with these
comments. Most of the requirements in
this final rule are not new—they codify
existing requirements that are found in
Order 3 or they are standard industry
practices that most operators,
transporters, and purchasers already
follow. Those requirements that are new
have been added for two reasons: (1) To
give operators the flexibility to use new
technology, which could, in the long
run, reduce costs for both industry and
the BLM; and (2) To address production
accountability and site security
concerns raised by governmental
oversight bodies, such as the
Subcommittee, the GAO, and the OIG.
The BLM did not change the final rule
as a result of these comments.
One commenter stated that the
regulations should consider laws and
lease provisions that apply only in
Alaska, and should more clearly provide
for balancing measurement accuracy
and environmental considerations.
According to the commenter, these laws
and lease provisions impose heightened
restrictions on development in Alaska
with which the site security regulations,
in particular the requirements for
additional measurement facilities,
would conflict. The BLM does not agree
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with the commenter that changes to the
rule are necessary. To the extent tradeoffs between measurement accuracy and
environmental considerations are
appropriate, the BLM has already
addressed those issues in the rule—see
e.g., the discussion of considerations
that go into reviewing requests for offlease measurement or commingling
approvals. Additionally, whether the
final rule requires additional facilities is
facility-specific. Moreover, as explained
throughout this preamble and the
associated EA, the BLM expects that, to
the extent the final rule requires the
construction of new facilities on a lease,
the relocation of existing facilities onto
a lease, or the retrofitting of existing
facilities on a lease, it would likely be
done on surfaces that have already been
disturbed. Thus, the BLM does not
believe that this rule will result in the
significant ‘‘footprint’’ expansion the
commenter identified. Furthermore,
should compliance with a requirement
of this rule necessitate surface
disturbance inconsistent with
applicable laws or lease terms, the
operator may, through the PMT or under
§ 3170.6, as applicable, seek approval of
an alternative means of compliance that
would meet the objectives of that
requirement.
Miscellaneous Changes to Other BLM
Regulations in 43 CFR Part 3160
As noted at the beginning of this
Section-by-Section discussion, the BLM
has made other changes to provisions in
43 CFR part 3160. Some of those have
already been discussed above in
connection with provisions of this final
rule to which they relate. The remaining
revisions are those noted here.
1. The authority citation for part 3160
is corrected to include 25 U.S.C. 396,
the grant of rulemaking authority to the
Secretary for allotted Indian leases,
which does not appear in the current
print edition of the CFR. The BLM did
not receive any comments on this
change.
2. Section 3160.0–3, Authority, is
updated to include the amendments to
the Federal Oil and Gas Royalty
Management Act of 1982 enacted by the
Federal Oil and Gas Royalty
Simplification Act of 1996. The BLM
did not receive any comments on this
change.
3. Section 3161.1, Jurisdiction, is
updated to include references to FMPs,
the Indian Mineral Development Act,
and Tribal Energy Resource Agreements.
To see the BLM’s response to public
comment on these changes, please see
the discussion of related changes to
§ 3170.2 earlier in this preamble.
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81407
4. Section 3162.3–2 is revised by
adding a new paragraph (d), which
refers operators to provisions in subpart
3173 for details on how to apply for
approval of FMPs, surface or subsurface
commingling from different leases, unit
PAs and CAs, or off-lease measurement.
The BLM did not receive any comments
on this change.
5. Section 3162.4–1, Well records and
reports, is amended in a number of
respects by this final rule. Consistent
with the proposed rule, this final rule
revises paragraph (a) to make clear that
the new recordkeeping requirements
also apply to ‘‘source records’’ that are
relevant to ‘‘determining and verifying
the quality, quantity, and disposition of
production from or allocable to Federal
or Indian leases.’’ Similarly, paragraph
(d) has been revised to establish the new
records-retention period established by
the 1996 amendments to FOGRMA, and
mirror for part 3160 the provisions in
paragraphs (c) through (e) of § 3170.7 of
the final rule. A new paragraph (e) lists
those ‘‘record holders’’ who would be
subject to the new recordkeeping
requirements. This section also makes
clear that all record holders must
maintain their records when directed by
the Secretary, or his/her designee, in
cases where there is a judicial
proceeding or demand involving such
records. In this section of the previous
rule, the Secretary, or his/her designee,
could direct record holders to maintain
their records only in cases where there
was an audit or investigation.
6. Section 3162.4–3, the provisions
regarding the no-longer-used Form
3160–6 (the monthly report of
operations), is removed. The BLM did
not receive any comments on this
change.
7. Section 3162.6, Well and facility
identification, is revised to correct the
misspelled word ‘‘indentification’’ in
paragraph (a) to read ‘‘identification.’’
Paragraph (b) is revised to remove a
provision allowing abbreviated sign
designations and a ‘‘grandfathering’’
provision for old well signs. Paragraph
(c) is revised to extend signage
requirements to include facilities at
which oil or gas produced from Federal
or Indian leases is stored or processed.
The fifth sentence of the current
paragraph (c) becomes the new
paragraph (d), with its wording revised.
The current paragraph (d) is now
paragraph (e). The BLM did not receive
any comments on this change.
8. Section 3162.7–1, Disposition of
production. This final rule removes
paragraph (f), which currently refers to
a 6-year retention period, since the
initial statutory retention period for
records concerning Federal leases is
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now 7 years. The BLM opted not to
retain paragraph (f) because this
retention period is already prescribed
§§ 3162.4–1 and 3170.7 of the final rule.
The BLM received no comments on this
proposed change and did not make any
changes from the proposed rule to the
final rule.
9. Section 3162.7–5, Site security on
Federal and Indian (except Osage Tribe)
oil and gas leases, has been removed.
The provisions in the final rule that
correspond to, or cover the same subject
matter as, the several paragraphs in
§ 3162.7–5 are shown in the following
table:
43 CFR 3162.7–5 paragraph
Final new provision
(a) Definitions ...........................................................................................
(b)(1) Lines and valves; effective sealing ................................................
(b)(2) LACT meters and effective sealing of components .......................
43 CFR 3173.1.
43 CFR 3173.2(a), 3173.9(b) and 3173.11(c)(7).
43 CFR 3170.4, 3173.3, and two sections in anticipated new subpart
3174.
43 CFR 3170.4.
43 CFR 3173.2(a) and (b).
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(b)(3) By-passes around meters ..............................................................
(b)(4) Sealing of appropriate valves during oil measurement by hand
gauging.
(b)(5) Circulating lines with valves allowing access to remove oil from
storage tanks.
(b)(6) Records retention requirements .....................................................
(b)(7) Removal of oil for transportation by vehicle and required documentation.
(b)(8) Reporting theft or mishandling of oil ..............................................
(b)(9) Variances ........................................................................................
(c) Site security plans ...............................................................................
(d) Site facility diagrams ...........................................................................
10. Section 3163.2, Civil penalties, is
rewritten in several respects by this
final rule. The changes being made to
this section as part of this rule are a
combination of the changes proposed as
part of this rulemaking effort and the
proposed rule to update and replace
Order 5 (80 FR 61645). In addition,
following the publication of those
proposed rules, but prior to the
publication of this rule, the BLM
published an interim final rule—
Onshore Oil and Gas Operations—Civil
Penalties Inflation Adjustments (81 FR
41860)—that made adjustments for
inflation to all of the daily civil
monetary penalty maximums found in
§ 3163.2. The adjustments made by the
interim final rule were required by the
Federal Civil Penalties Inflation
Adjustment Act Improvements Act of
2015 (Sec. 701 of Pub. L. 114–74).
The BLM is making the following
additional changes to § 3163.2 in this
final rule. These changes are not a result
of the Federal Civil Penalties Inflation
Adjustment Act Improvements Act.
First, the BLM is amending the civil
penalty regulations to reflect the fact
that purchasers and transporters who
fail to maintain and submit records as
required by the BLM can be subject to
civil penalties under Section 109 of
FOGRMA (30 U.S.C. 1719). As
explained in the proposed rule, this
change is being made because the BLM’s
existing regulations do not reflect this
longstanding statutory authority. In
order to effectuate this change the BLM
is designating the first sentence of
paragraph (a) of the existing § 3163.2 as
paragraph (a)(1), and adding a new
paragraph (a)(2) that reads as follows:
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43 CFR 3173.1.
43 CFR 3170.7.
43 CFR 3173.5.
43 CFR 3173.8.
43 CFR 3170.6.
None (site security plans eliminated).
43 CFR 3173.11.
(2) Whenever a purchaser or
transporter who is not an operating
rights owner or operator fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil or gas lease, the
authorized officer will notify the
purchaser or transporter, as appropriate,
in writing of the violation. The second
sentence of the existing paragraph (a)
(pertaining to the maximum amount of
the penalty if the violation is not
corrected within 20 days of the date of
notice) is redesignated as paragraph
(b)(1). The existing paragraph (b)
(pertaining to the maximum amount of
the penalty if the violation is not
corrected within 40 days of the date of
notice) is redesignated as paragraph
(b)(2).
The BLM received a number of
comments asserting that it was unfair to
subject purchasers and transporters to
the civil penalties under the onshore oil
and gas regulations because purchasers
and transporters often do not have
control over the information provided
by operators. The BLM does not agree
with these comments. As explained
above, this change is being driven
primarily by longstanding statutory
requirements. Additionally, it should be
noted that there are instances where the
purchaser or transporter actually owns
the oil and gas delivery point, and
therefore has control of much of the
relevant information. With respect to
concerns about the accuracy of
information provided by an operator to
a purchaser or transporter, while
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entities are generally responsible for the
content of their records, the BLM
recognizes that such a situation (i.e.,
inaccurate information provided by an
operator) would be a factor that could be
considered in an enforcement action on
a case-by-case basis.
In addition to the changes identified
above, the BLM is also revising
paragraphs (a)(1) and (b)(1) to refer to
‘‘any person’’ and ‘‘the person,’’
respectively, rather than limiting the
applicability of civil penalties to an
operating rights owner or operator. This
change is consistent with the statutory
language found in Section 109(a) of
FOGRMA (30 U.S.C. 1719(a)). It also
clarifies that potential penalty liability
exists for parties who contract with
operating rights owners or operators to
perform activities on Federal or Indian
leases and who violate applicable
regulations, statutes, permits, or lease
terms in performing those activities.
While the operating rights owner or
operator is responsible (and liable for
penalties) for violations committed by
contractors, the contractors are also
themselves subject to the requirements
of certain statutes, regulations, permits,
and lease terms. The BLM is revising the
regulations in this manner in order to
enable the agency to hold contractors
directly responsible for violations they
commit.
In addition, this rule also removes the
regulatory caps on civil penalty
assessments found in the current
regulations paragraphs (b) (paragraph
(b)(2) in the final rule), (d), (e), and (f).
As explained in the proposed rule to
update and replace Order 5 (80 FR
61645), this change is based on
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comments received on an Advance
Notice of Proposed Rulemaking (ANPR)
(80 FR 22148) that sought input on a
variety of issues related to the onshore
oil and gas program, including whether
the regulatory civil penalty caps should
be removed. The ANPR explained that
these caps are not required by statute,
and that in the BLM’s view they impose
a limit on the total penalties that may
be assessed that do not seem reasonable
in the modern oil and gas context where
it can cost $5 to $10 million dollars to
drill a well.
As the BLM explained, it does not
believe that the existing regulatory caps
provide an adequate deterrence for
unlawful conduct, particularly drilling
on Federal onshore leases without
authorization and drilling into leased
parcels in knowing and willful trespass.
Similar concerns were expressed by the
Department’s OIG in a report, dated
September 29, 2014—Bureau of Land
Management, Federal Onshore Oil & Gas
Trespass and Drilling Without Approval
(No. CR–IS–BLM–0004–2014). In that
report, the OIG specifically questioned
the adequacy of the BLM’s policies to
deter such activities and recommended
that the BLM pursue increased
monetary fines. Based on the foregoing,
the final rule rewrites paragraphs (b)
(paragraph (b)(2) in the final rule), (d),
(e), and (f) accordingly, to remove the
regulatory caps, while maintaining the
statutory limits imposed on the amount
that may be assessed on a daily basis (30
U.S.C. 1719(a)–(d)), as amended by the
BLM’s recent interim final rule
adjusting those amounts for inflation.
Due to the removal of the regulatory
civil penalty caps, the BLM determined
that paragraph (j) is unnecessary given
that its requirements would have tiered
off the expiration of those caps. As a
result, this rule removes paragraph (j).
The BLM is also deleting all of
paragraph (g). The existing requirements
of paragraph (g)(1) and (g)(2)(iii), which
require initial proposed penalties to be
at the maximum rate, are being removed
because they are inconsistent with
subsequent judicial and administrative
decisions regarding the computation
and setting of penalties. The BLM also
determined that the requirements in
paragraph (g)(1) and (g)(2)(iii)
(establishing caps on a per operating
rights owner or operator per lease) are
inconsistent with the BLM’s removal of
regulatory caps on penalties found in
paragraphs (b) (paragraph (b)(2) in the
final rule), (d), (e), and (f). With respect
to paragraphs (g)(2)(i) and (g)(2)(ii), the
BLM is removing the additional notice
procedure and corrective period for
minor violations required under those
paragraphs because it does not believe
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those provisions are necessary. The
BLM’s regulations governing oil and gas
operations are clear, and provide more
than adequate notice of what is
required, making additional notification
requirements unnecessary and
administratively inefficient. As a result,
this rule removes all of paragraph (g)
and redesignates existing paragraph (i)
as (g). Existing paragraph (h) is
unaffected by this rule.
Finally, the BLM is moving the
substance of existing paragraph (k),
which requires the revocation of a
transporter’s authority to remove crude
oil produced from, or allocated to, any
Federal or Indian lease if it fails to
permit inspection for required
documentation under 43 CFR 3162.7–
1(c)), to paragraph (d) in order to
streamline the regulations. As a result,
paragraph (k) is removed as part of this
rule.
One commenter on the proposed rule
to replace Order 5 objected to the BLM’s
expansion of the civil penalty provision
to ‘‘purchasers and transporters’’ and to
the change to ‘‘any person,’’ instead of
retaining the existing language that
limited § 3163.2 to the operating rights
owner or operator. That commenter
contended that the BLM lacked
authority to impose liability on
contractors undertaking activities on a
Federal or Indian lease. The BLM
disagrees with this comment because
this change is consistent with Section
109(a) of FOGRMA (30 U.S.C. 1719(a)),
which states that ‘‘any person’’ who
violates the mineral leasing laws, any
rule or regulation issued under those
laws, or the terms of any lease or permit
shall be liable for civil penalties.
The BLM also heard a range of
opinions on the removal of the
regulatory civil penalty caps. Some
commenters contended that the
provisions would result in the
imposition of penalties that are
excessive, while others supported the
change. As explained early in this
section, the existing regulatory caps on
civil penalties result in maximum
penalties that are small relative to the
costs of drilling a modern oil and gas
well such that the potential deterrent
effect of civil penalties is limited. For
example, the maximum penalty that
could be assessed under existing
paragraph (b) is $600,000, which is only
10 percent of the cost of drilling a
typical well, which is potentially
insufficient to act as a deterrent to noncompliance.
Finally, several commenters suggested
that the BLM amend the proposed
regulations to require that any time a
purchaser, transporter, or contractor
receives an INC, a copy be provided to
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81409
the operating rights owner. The BLM
agrees with commenters that adequate
notice of potential violations is
important; however, it determined that
such changes are unnecessary. By
existing policy and practice, the BLM
addresses INCs to the party who is the
subject of the action and does not
believe it is appropriate to automatically
copy unrelated third parties.
Additionally, the regulations already
require that if a party is going to be
subject to such penalties, it has to
receive notice in writing first from the
BLM. Thus, under the scenarios
identified by the commenters, if they
were going to be penalized they would
have to first receive a written notice
from the BLM identifying the
violation(s) in question.
11. Section 3164.1, Onshore Oil and
Gas Orders, is revised to remove the
reference to Order No. 3, Site Security,
from the table in paragraph (b) because
the Order is now replaced by this
codified final rule.
12. Section 3165.3, Notice, State
Director review and hearing on the
record, is rewritten in several respects
by this final rule. Specifically,
consistent with the changes to § 3163.2
and the proposed rule, this rule amends
the notice requirements of the existing
regulations at 43 CFR 3165.3 to include
a provision regarding notice to a
purchaser or transporter (who is not an
operating rights owner or operator) of a
failure to comply with records
maintenance or production
requirements. This final rule also adopts
the changes proposed as part of the
Order 5 rulemaking to revise this
section to clarify that any person, not
just ‘‘an operating rights owner or
operator’’ (as previously provided for in
paragraph (a)(1)), is subject to a written
notice or order of they fail to comply
with any provisions of the lease, the
regulations in this part, applicable
orders or notices, or any other
appropriate order of the authorized
officer.
In addition, the BLM has also divided
the several sentences of the existing
paragraph (a) into numbered paragraphs
(a)(1) through (a)(7) and added
clarifying, nonsubstantive revisions
throughout the section. After the first
sentence, which has been redesignated
as paragraph (a)(1) (and rephrased into
active voice), the BLM has added a new
paragraph (a)(2) as set out in the
regulatory text of this final rule.
In addition, the second and third
sentences of existing paragraph (a) are
redesignated as paragraph (a)(3), and the
fourth, fifth and sixth and seventh
sentences are redesignated as
paragraphs (a)(4) through (a)(7). The
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BLM did not receive any comments on
these changes and as a result did not
make any further changes in this final
rule.
III. Overview of Public Involvement
and Consistency With GAO
Recommendations
Public Outreach
The BLM conducted extensive public
and tribal outreach on this rule both
prior to its publication as a proposed
rule and during the public comment
period on the proposed rule. Prior to the
publication of the proposed rule, the
BLM held both tribal and public forums
to discussion potential changes to the
rule. In 2011, the BLM held three tribal
meetings in Tulsa, Oklahoma (July 11,
2011); Farmington, New Mexico (July
13, 2011); and Billings, Montana
(August 24, 2011). On April 24 and 25,
2013, the BLM held a series of public
meetings in Washington, DC, to discuss
draft proposed revisions to Orders 3, 4,
and 5. The meetings were webcast so
tribal members, industry, and the public
across the country could participate and
ask questions either in person or over
the Internet. Following those meetings,
the BLM opened a 36-day informal
comment period, during which 13
comment letters were submitted. The
comments received during that
comment period were summarized in
the preamble for the proposed rule (80
FR 58952).
The proposed rule was made available
for public comment from September 30,
2015, through December 14, 2015.
During that period, the BLM held tribal
and public meetings on December 1
(Durango, Colorado), December 3
(Oklahoma City, Oklahoma), and
December 8 (Dickinson, North Dakota).
The BLM also held a tribal webinar on
November 19, 2015. In total, the BLM
received 106 comment letters on the
proposed rule, the substance of which
are addressed in the Section-by-Section
analysis of this preamble.
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Consistency With GAO
Recommendations
As explained in the background
section of this preamble, three outside
independent entities—the
Subcommittee, the OIG, and the GAO—
have repeatedly found that the BLM’s
oil and gas measurement rules do not
provide sufficient assurance that
operators pay the royalties due.
Specifically, these groups found that the
BLM needed updated guidance on oil
and gas measurement technologies, to
address existing technological advances,
as well as technologies that might be
developed in the future. These groups
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have all found that the BLM’s existing
guidance is ‘‘unconsolidated, outdated,
and sometimes insufficient,’’ and more
specifically with respect to Order 3,
that:
• There was no uniform means of
tracking all onshore meters, including
information about meter location,
identification number, and owner;
• Some BLM State offices have issued
their own guidance, which lacks a
national perspective; more specifically
there were concerns about the lack of
uniform national guidance with respect
to the review and approval of
commingling and off-lease
measurements requests; and
• There was insufficient information
collected with respect to on-lease
royalty-free use.
The final rule addresses these
recommendations by establishing
uniform national guidance governing
the review and approval of FMPs,
CAAs, and off-lease measurements. It
also requires operators to provide more
information about royalty-free use. The
provisions of the final rule specifically
address modern oil industry practices
with respect to each of these, while also
updating relevant documentation and
recordkeeping requirements in order to
ensure that all production is properly
accounted for.
IV. Procedural Matters
Executive Orders 12866 and 13563,
Regulatory Planning and Review
Executive Order 12866 provides that
the Office of Information and Regulatory
Affairs (OIRA) will review all significant
rules. The OIRA has determined that
this rule is not significant.
Executive Order 13563 reaffirms the
principles of E.O. 12866 while calling
for improvements in the nation’s
regulatory system to promote
predictability, to reduce uncertainty,
and to use the best, most innovative,
and least burdensome tools for
achieving regulatory ends. The
executive order directs agencies to
consider regulatory approaches that
reduce burdens and maintain flexibility
and freedom of choice for the public
where these approaches are relevant,
feasible, and consistent with regulatory
objectives. E.O. 13563 emphasizes
further that regulations must be based
on the best available science and that
the rulemaking process must allow for
public participation and an open
exchange of ideas. The BLM has
developed this rule in a manner
consistent with these requirements.
Regulatory Flexibility Act
The BLM certifies that this final rule
will not have a significant economic
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effect on a substantial number of small
entities as defined under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.).
The Small Business Administration
(SBA) has developed size standards to
carry out the purposes of the Small
Business Act and those size standards
can be found at 13 CFR 121.201. The
Small Business Act applies to oil and
gas extraction firms with fewer than
1,250 employees, oil and gas drilling
firms with fewer than 1,000 employees,
and firms providing oil and gas support
activities with annual receipts of no
more than $38.5 million. These small
entities must be considered as being at
‘‘arm’s length’’ from the control of any
parent companies.
Of the 6,460 domestic firms involved
in crude oil and gas extraction in 2013,
U.S. Census data show that 99 percent
(or 6,370) had fewer than 500
employees, which means that nearly all
U.S. firms involved in oil and gas
extraction in 2013 fell within the SBA’s
size standard of fewer than 1,250
employees. Of the 2,097 firms
participating in oil and gas drilling
activities in 2013, U.S. Census data
show that 2,044 (97 percent) had fewer
than 500 employees, which means that
nearly all U.S. firms involved in oil and
gas support activities in 2013 fell within
the SBA’s size standard of fewer than
1,000 employees. In 2012, there were
8,877 firms involved in drilling and
other support functions, of which 96
percent (8,561) had annual net receipts
of no more than $35 million, with a
greater number below the SBA’s $38.5
million threshold.
In addition to lessees and operators,
we must consider the size of the
purchaser and transporter firms. There
are multiple NAICS categories that
could include firms involved in the
purchasing and transporting of
petroleum from Federal and Indian
leases. For example, petroleum refiners
could be identified as purchasers. For
petroleum refiners (NAICS code
324110), the SBA standard says a small
business cannot have more than 1,500
employees or more than 200,000 bbl per
calendar day total operable atmospheric
crude oil distillation capacity. In that
context, capacity includes owned or
leased facilities as well as facilities
under a processing agreement or an
arrangement such as an exchange
agreement or a throughput agreement.
Purchasers could also be wholesalers,
truck transporters, or natural gas or
pipeline operators. For wholesalers,
including petroleum wholesalers
(NAICS codes 424710 and 424720), the
SBA standard for a small entity is one
that has fewer than 200 employees. For
truck transporters (NAICS subsector
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484), the SBA defines a small entity as
a firm with less than $27.5 million in
annual receipts. For natural gas pipeline
operators (NAICS code 486210), the
standard is a maximum of $27.5 million
in receipts per year. For crude oil
pipeline operators (NAICS code
486110), the standard is fewer than
1,500 employees.
As discussed above, national data,
including number of firms, number of
employees by firm, and annual receipts
by firm, is not discretely identified for
purchasers and transporters of
petroleum or natural gas. The
potentially affected purchasers and
transporters will likely be a minor
component in any number of the
relevant NAICS categories. Of the few
NAICS categories where reported
employment, receipt, and production
data matches up with the SBA size
standards, the preponderance of the
firms will be considered small entities
as defined by the SBA.
Based on the available national data,
the preponderance of firms involved in
developing, producing, purchasing, and
transporting oil and gas from Federal
and Indian lands are small entities as
defined by the SBA. As such, it appears
a substantial number of small entities
could be affected by this final rule.
Using the best available data, the BLM
estimates there are approximately 3,700
lessees and operators conducting oil and
gas operations on Federal and Indian
lands that could be affected by this final
rule. Additionally, the BLM estimates
there are approximately 200 to 300
purchasers and transporters operating
on Federal and Indian lands that
potentially could be affected by this
final rule.
In addition to determining whether a
substantial number of small entities are
likely to be affected by this rule, the
BLM must also determine whether the
rule is anticipated to have a significant
economic impact on those small
entities. Based on the Economic and
Threshold Analysis prepared for this
final rule, the BLM anticipates the cost
of implementing the provisions could
reduce the average annual net income of
impacted small entities by less than
0.001 percent. Except for the electronic
filing requirement, all of the provisions
apply to entities regardless of size.
However, entities with the greatest
activity will likely experience the
greatest increase in compliance costs.
As a general matter, smaller business
entities are more likely to operate a
smaller number of sites and FMPs for
which they will have to submit the
information and documentation that
this final rule requires. Copies of the
analysis can be obtained from the
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contact person listed earlier (see FOR
FURTHER INFORMATION CONTACT).
Based on the available information,
we conclude that the final rule will not
have a significant impact on a
substantial number of small entities.
Therefore, a final Regulatory Flexibility
Analysis is not required, and a Small
Entity Compliance Guide is not
required.
Small Business Regulatory Enforcement
Fairness Act
This final rule is not a major rule
under 5 U.S.C. (2), the Small Business
Regulatory Enforcement Fairness Act.
This rule will not have an annual effect
on the economy of $100 million or
more. As explained in the Economic
and Threshold Analysis, the final rule
will increase the estimated ongoing
costs associated with the development
of Federal and Indian oil and gas
resources by an estimated $11.7 million
annually for the regulated community.
In addition, there will be an estimated
one-time cost to the regulated
community to implement the new
provisions of $31.2 million. The onetime implementation costs will be
spread over 3 years, or about $10.4
million per year. As discussed in the
Economic and Threshold Analysis, the
BLM anticipates the cost of
implementing the provisions could
reduce the average annual net income of
impacted small entities by
approximately 0.01 percent.
This rule replaces Order 3 to ensure
that oil and gas produced from Federal
and Indian leases is properly and
securely handled so that these resources
are accurately accounted for.
This rule:
• Will not cause a major increase in
costs or prices for consumers,
individual industries, Federal, State,
tribal, or local government agencies, or
geographic regions; and
• Will not have significant adverse
effects on competition, employment,
investment, productivity, innovation, or
the ability of U.S.-based enterprises to
compete with foreign-based enterprises.
Unfunded Mandates Reform Act
In accordance with the Unfunded
Mandates Reform Act (2 U.S.C. 1501 et
seq.), the BLM finds that:
• This rule will not ‘‘significantly or
uniquely’’ affect small governments. A
Small Government Agency Plan is
unnecessary.
• This rule will not produce a Federal
mandate of $100 million or greater in
any single year.
The rule is not a ‘‘significant
regulatory action’’ under the Unfunded
Mandates Reform Act. The changes in
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this rule will not impose any
requirements on any non-Federal
Governmental entity.
Executive Order 12630, Governmental
Actions and Interference With
Constitutionally Protected Property
Rights (Takings)
Under Executive Order 12630, the
rule will not have significant takings
implications. A takings implication
assessment is not required. This rule
will set minimum standards for
ensuring that oil and gas produced from
Federal and Indian (except the Osage
Tribe) oil and gas leases are properly
and securely handled, so as to prevent
theft and loss and to enable accurate
measurement and production
accountability. All such actions are
subject to lease terms which expressly
require that subsequent lease activities
be conducted in compliance with
applicable Federal laws and regulations.
The rule conforms to the terms of those
Federal leases and applicable statutes,
and as such the rule is not a
governmental action capable of
interfering with constitutionally
protected property rights. Therefore, the
rule will not cause a taking of private
property or require further discussion of
takings implications under this
Executive Order.
Executive Order 13132, Federalism
In accordance with Executive Order
13132, the BLM finds that the rule
would not have significant Federalism
effects. A Federalism assessment is not
required. This rule will not change the
role of or responsibilities among
Federal, State, and local governmental
entities. It does not relate to the
structure and role of the States and will
not have direct, substantive, or
significant effects on States.
Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
Under Executive order 13175, the
President’s memorandum of April 29,
1994, ‘‘Government-to-Government
Relations with Native American Tribal
Governments’’ (59 FR 22951), and 512
Departmental Manual 2, the BLM
evaluated possible effects of the final
rule on federally recognized Indian
tribes. The BLM approves proposed
operations on all Indian onshore oil and
gas leases (except Osage Tribe).
Therefore, the final rule has the
potential to affect Indian tribes. In
conformance with the Secretary’s policy
on tribal consultation, the BLM held
tribal consultation meetings to which
more than 175 tribal entities were
invited, both before the rule was
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proposed and during the public
comment period on the proposed rule.
The consultations were held in:
Pre-Publication Meetings
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July
13, 2011; and
• Billings, Montana on August 24,
2011.
• Tribal workshop and webcast in
Washington, DC, on April 24, 2013.
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Post-Publication Meetings
• The BLM hosted a webinar to
discuss the requirements of the
proposed rule and solicit feedback from
affected tribes on November 19, 2015;
and
• In-person meetings were held in:
Æ Durango Colorado, on December 1,
2015;
Æ Oklahoma City, Oklahoma, on
December 3, 2015; and
Æ Dickinson, North Dakota, on
December 8, 2015.
The BLM also met with interested
tribes on a one-on-one basis as
requested to address questions on the
proposed rule prior to the publication of
the final rule. In each instance, the
purpose of these meetings was to solicit
feedback and comments from the tribes.
The primary concerns expressed by
tribes related to the subordination of
tribal laws, rules, and regulations by the
proposed rule; tribal representation on
the Department’s Gas and Oil
Measurement Team; and the BLM’s
Inspection and Enforcement program’s
ability to enforce the terms of this rule.
In general, the tribes, as royalty
recipients, expressed support for the
goals of the rulemaking, namely
accurate measurement. With respect to
tribal representation on the
Department’s Gas and Oil Measurement
Team, it should be noted that the team
is internal only. That said, the BLM will
continue to consult with tribes on
measurement issues that impact them
and their resources. None of the tribal
comments received were directed
specifically at this rule’s oil
measurement requirements, and
therefore no changes were made as a
result of these comments. While the
BLM will continue to address these
concerns, none of the concerns affect
the substance of the proposed rule.
Executive Order 12988, Civil Justice
Reform
Under Executive Order 12988, the
Office of the Solicitor has determined
that the final rule will not unduly
burden the judicial system and meets
the requirements of Sections 3(a) and
3(b)(2) of the Executive Order. The
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Office of the Solicitor has reviewed the
final rule to eliminate drafting errors
and ambiguity. It has been written to
minimize litigation, provide clear legal
standards for affected conduct rather
than general standards, and promote
simplification and burden reduction.
Executive Order 13352, Facilitation of
Cooperative Conservation
Under Executive Order 13352, the
BLM has determined that this final rule
will not impede facilitating cooperative
conservation and will take appropriate
account of and consider the interests of
persons with ownership or other legally
recognized interests in land or other
natural resources. This rulemaking
process involved Federal, tribal, State,
and local governments, private for-profit
and nonprofit institutions, other
nongovernmental entities and
individuals in the decision-making via
the public comment process. That
process provides that the programs,
projects, and activities are consistent
with protecting public health and safety.
Paperwork Reduction Act
The Paperwork Reduction Act (PRA)
(44 U.S.C. 3501–3521) provides that an
agency may not conduct or sponsor, and
a person is not required to respond to,
a collection of information, unless it
displays a currently valid OMB control
number. Collections of information
include requests and requirements that
an individual, partnership, or
corporation obtain information, and
report it to a Federal agency. See 44
U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information
collection activities that require
approval by the OMB under the PRA.
The BLM included an information
collection request in the proposed rule.
OMB has approved the information
collection for the final rule under
control number 1004–0207.
Some of the information collection
activities in the rule will add new uses
and burdens for BLM Form 3160–5,
Sundry Notices and Reports on Wells.
Form 3160–5 has been approved by
OMB for uses enumerated at 43 CFR
3162.3–2, and is one of 17 information
collection activities that are included in
control number 1004–0137, Onshore Oil
and Gas Operations (43 CFR part 3160)
(expiration date January 31, 2018).
The information collection activities
in this rule are described below along
with estimates of the annual burdens.
Included in the burden estimates are the
time for reviewing instructions,
searching existing data sources,
gathering and maintaining the data
needed, and completing and reviewing
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each component of the information
collection.
Summary of Information Collection
Activities
Title: Oil and Gas Facility Site
Security (43 CFR Subparts 3170 and
3173).
Forms: Form 3160–5, Sundry Notices
and Reports on Wells.
OMB Control Number: 1004–0207.
Description of Respondents: Oil and
gas operators, lessees, operators,
purchasers, transporters, and any other
person directly involved in producing,
transporting, purchasing, selling, or
measuring oil or gas.
Abstract: This rule establishes
minimum security standards for Federal
and Indian (except Osage Tribe) oil and
gas leases.
Frequency of Collection: On occasion.
Obligation To Respond: Required to
obtain or retain benefits.
Estimated Annual Responses:
274,886.
Estimated Reporting and
Recordkeeping ‘‘Hour’’ Burden: 578,240
hours.
Estimated ‘‘Non-Hour’’ Burden:
$4,891.972.
Discussion of Information Collection
Activities
Some of the activities will be onetime-only, while others will be ongoing.
Similarly, the BLM recognizes that for
some of the activities, there will be both
an annual burden for some respondents,
and a one-time burden for virtually all
respondents in the initial
implementation. Because of the way the
rule is structured, the one-time burdens
that are applicable to all respondents are
phased-in over 3 years based on
production volumes.
The preamble to the proposed rule
solicited public comments on the
information collection. Those
comments, and responses of the BLM,
are discussed above in the preamble. All
comments—both those pertaining to
information collection and other
comments—are addressed in the final
rule. The comments and BLM responses
pertaining specifically to the collection
of information are discussed in the
Section-by-Section analysis of the
following sections of the final rule:
• 3170.7;
• 3173.6 through 3173.9;
• 3173.11 through 3173.13;
• 3173.15;
• 3173.23; and
• 3173.25.
The information-collection activities
in this rule are described below.
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Well and Facility Identification (43 CFR
3162.6)
The information-collection activity in
the current version of § 3162.6 has been
approved by OMB under control
number 1004–0137. The revisions
effected by this rule are not expected to
exceed the existing burden hours
authorized by control number 1004–
0137. This activity is not included in
the burdens for this rule.
Variance Requests (43 CFR 3170.6)
Section 3170.6, a new regulation,
authorizes any party that is subject to
the regulations in 43 CFR part 3170 to
request a variance from any of the
regulations in part 3170. While § 3170.6
states that a request for a variance
should be filed using the BLM’s
electronic system, it also allows the use
of paper copies of Form 3160–5 (Sundry
Notices). Thus, § 3170.6 represents a
new use of Form 3160–5, Sundry
Notices and Reports on Wells.
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Required Recordkeeping and Records
Submission (43 CFR 3170.7)
Section 3170.7 applies to lessees,
operators, purchasers, transporters, and
any other person directly involved in
producing, transporting, purchasing,
selling, or measuring oil or gas through
the point of royalty measurement or the
point of first sale, whichever is later.
This regulation applies to records
generated during or for the period for
which the lessee or operator has an
interest in or conducted operations on
the lease, or in which a person is
involved in transporting, purchasing, or
selling production from the lease. This
information collection activity assists
the BLM in accurate accounting of oil
and gas production.
In general, records from Federal leases
must be maintained for 7 years, and
records from Indian leases must be
maintained for 6 years. Additional
details and exceptions are explained
below.
For Federal leases, and units or
communitized areas that include
Federal leases but do not include Indian
leases, the record holder must maintain
records for 7 years after the records are
generated. If a judicial proceeding or
demand involving such records is
timely commenced, the record holder
must maintain such records until the
final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary, her designee, or
the applicable delegated State
authorizes in writing an earlier release
of the requirement to maintain such
records.
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For Indian leases, and units or
communitized areas that include Indian
leases but do not include Federal leases,
the record holder must maintain records
for 6 years after the records are
generated. If the Secretary or her
designee notifies the record holder that
the Department of the Interior has
initiated or is participating in an audit
or investigation involving such records,
the record holder must maintain such
records until the Secretary or his
designee releases the record holder from
the obligation to maintain the records.
For units and communitized areas
that include both Federal and Indian
leases, if the Secretary or his designee
has notified the record holder within 6
years after the records are generated that
an audit or investigation involving such
records has been initiated, but a judicial
proceeding or demand is not
commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the unit or
communitized area until the Secretary
or her designee releases the record
holder from the obligation to maintain
the records. If a judicial proceeding or
demand is commenced within 7 years
after the records are generated, the
record holder must retain all records
regarding production from the unit or
communitized area until the final
nonappealable decision in such judicial
proceeding is made, or with respect to
that demand is rendered, unless the
Secretary or her designee authorizes in
writing a release of the requirement to
maintain such records before a final
nonappealable decision is made or
rendered.
For all types of Federal and Indian
leases, the lessee, operator, purchaser,
and transporter must maintain an audit
trail that includes all records, including
source records that are used to
determine quality, quantity, disposition,
and verification of production
attributable to a Federal or Indian lease,
unit participating area (unit PA), or CA,
must include the FMP number or the
lease, unit PA, or CA number along with
a unique equipment identifier (e.g., a
unique tank identification number and
meter station number); and the name of
the company that created the record. For
existing measurement facilities, in the
interim period before the assignment of
an FMP number, all records must
include the following information:
• The name of the operator;
• The lease, unit PA, or CA number;
and
• The well or facility name and
number.
Section 3170.7(h) requires operators,
purchasers, and transporters to submit
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all records, including source records
that are relevant to determining the
quality, quantity, disposition, and
verification of production attributable to
Federal or Indian leases, upon request,
in accordance with a regulation, written
order, Onshore Order, NTL, or COA.
Water-Draining Operations—Data
Collection (43 CFR 3173.6); and
Water-Draining Operations—
Recordkeeping and Records Submission
(43 CFR 3170.7 and 3173.6)
Section 3173.6 requires submission of
information when water is drained from
a production storage tank. The
information is required from the
operator, purchaser, or transporter, as
appropriate. Previously, the operator
was not required to record the volume
of hydrocarbons that are in the tank
before and after water is drained. As a
result, hydrocarbons could be drained
with the water and removed without
proper measurement and accounting,
and without royalties being paid. This
information collection activity assists
the BLM in accurate accounting of oil
and gas produced from Federal and
Indian leases.
The following information is required:
• Federal or Indian lease, unit PA, or
CA number(s);
• The tank location by land
description;
• The unique tank number and
nominal capacity;
• Date for opening gauge;
• Opening gauge of the total oil
volume and free-water measurements;
• Unique identifying number of each
seal removed;
• Closing gauge of the total oil
volume measurement; and
• Unique identifying number of each
seal installed.
Hot Oiling, Clean-Up, and Completion
Operations—Data Collection (43 CFR
3173.7); and
Hot Oiling, Clean-Up, and Completion
Operations—Recordkeeping and
Records Submission (43 CFR 3170.7 and
3173.7)
Section 3173.7 requires the
submission of information during hot
oil, clean-up, or completion operations,
or any other situation where the
operator removes oil from storage,
temporarily uses it for operational
purposes, and then returns it to storage
on the same lease, unit PA, or CA.
Previously, the operator was not
required to record the volume of
hydrocarbons removed from storage
with the expectation that they will be
returned to storage. As a result, the
volume of produced hydrocarbons
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could be counted twice; first when it
was initially produced then later after it
is returned to storage. This information
collection activity assists the BLM in
accurate accounting of oil and gas
produced from Federal and Indian
leases.
The following information is required:
• Federal or Indian lease, unit PA, or
CA number(s);
• The tank location by land
description;
• The unique tank number and
nominal capacity;
• Date of the opening gauge;
• Opening gauge measurement;
• Closing gauge measurement;
• Unique identifying number of each
seal installed;
• How the oil was used; and
• Where the oil was used (i.e., well or
facility name and number).
mstockstill on DSK3G9T082PROD with RULES3
Report of Theft or Mishandling of
Production (43 CFR 3173.8)
Section 3173.8 requires operators,
transporters, or purchasers to submit a
report (either oral or written) no later
than the next business day after
discovery of an incident of apparent
theft or mishandling of production. All
oral reports must be followed up with
a written incident report within 10
business days of the oral report. By
applying not only to operators but also
to transporters and purchasers (who
often are the first ones to discover theft
and mishandling or to recognize
suspicious activity), this information
collection activity assists in prompt
disclosure of theft or mishandling. The
incident report must include the
following information:
• Company name and name of the
person reporting the incident;
• Lease, unit PA, or CA number, well
or facility name and number, and FMP
number, as appropriate;
• Land description of the facility
location where the incident occurred;
• The estimated volume of
production removed;
• The manner in which access was
obtained to the production or how the
mishandling occurred;
• The name of the person who
discovered the incident;
• The date and time of the discovery
of the incident; and
• Whether the incident was reported
to local law enforcement agencies and
company security
Required Recordkeeping for Inventory
and Seal Records (43 CFR 3173.9)
Section 3173.9 requires operators to
measure and record within ± 3 days of
the final day of each calendar month an
inventory consisting of TOV in storage
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(less free water). If the inventory is not
taken on the final day of each month, it
must be estimated based on two
measurements no less than 20 days and
no more than 31 days apart, based upon
the prorated difference between these
inventory levels and any sales that have
occurred between the two
measurements. This information
collection activity assists the BLM in
accurate accounting of oil and gas
production.
For each seal, the operator must
maintain a record that includes the
unique identifying number of each seal
and the valve or meter component on
which the seal is or was used; the date
of installation or removal of each seal;
for valves, the position (open or closed)
in which it was sealed; and the reason
the seal was removed.
Site Facility Diagrams for Existing
Facilities (43 CFR 3173.11(d)(2)); and
Site Facility Diagrams for Future
Facilities (43 CFR 3173.11(d)(1))
Section 3173.11 requires a site facility
diagram for all facilities. Section 3170.3
of the final rule defines ‘‘facility’’ as a
site and associated equipment used to:
• Process, treat, store, or measure oil
or gas production from or allocated to a
Federal or Indian lease, unit, or CA that
is located upstream of or at (and
including) the approved point of royalty
measurement; or
• Store, measure, or dispose of
produced water that is located on a
lease, unit, or CA.
A site facility diagram is one of the
BLM’s primary mechanisms for
monitoring operators’ compliance with
measurement regulations and policy.
These information collection activities
enable the BLM to verify, among other
things, royalty-free-use volumes
reported by the operator on its OGORs.
These activities also enhance
production accountability and respond
to key recommendations made by the
GAO and the OIG. In the long term, this
information collection request will
eliminate the need for the BLM to obtain
the information in connection with a
production verification and
accountability review.
Paragraphs (a) through (c) of § 3173.11
require that each site facility diagram be
submitted with a completed Sundry
Notice.13 The diagram itself should be
formatted to fit on an 81⁄2 x 11 sheet of
paper, if possible, and must be legible
and comprehensible to an individual
with an ordinary working knowledge of
oilfield operations. If more than one
13 Form 3160–3, which is approved under OMB
control number 1004–0137 for uses enumerated at
43 CFR 3162.3–2.
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page is required, each page must be
numbered (in the format ‘‘N of X
pages’’). Paragraph (c) specifies that a
site facility diagram must:
• Reflect the position of the
production and water recovery
equipment, piping for oil, gas, and
water, and metering or other measuring
systems in relation to each other, but
need not be to scale;
• Commencing with the header,
identify all of the equipment, including,
but not limited to, the header, wellhead,
piping, tanks, and metering systems
located on the site, and include the
appropriate valves and any other
equipment used in the handling,
conditioning, or disposal of production
and water, and indicate the direction of
flow;
• Identify by API number the wells
flowing into headers;
• Indicate which valve(s) must be
sealed and in what position during the
production and sales phases and during
the conduct of other production
activities (e.g., circulating tanks or
drawing off water), which may be
shown by an attachment, if necessary;
• Clearly identify the lease, unit PA,
or CA to which the diagram applies and
the land description of the facility, and
the name of the company submitting the
diagram, with co-located facilities being
identified for each lease, unit PA, or CA;
and
• Clearly identify as an attachment all
meters and measurement equipment.
Specifically identify all approved and
assigned FMPs.
If another operator operates a colocated facility, the site facility diagram
must depict the co-located facilities on
the diagram or list them on an
attachment and identify them by
company name, facility name(s), lease,
unit PA, or CA number, and FMP
number(s). When describing co-located
facilities operated by one operator, the
site facility diagram must include a
skeleton diagram of the co-located
facility, showing equipment only. For
storage facilities common to co-located
facilities operated by one operator, one
diagram would be sufficient.
If the operator claims royalty-free use,
the site facility diagram must clearly
identify on the diagram or as an
attachment, the equipment for which
the operator claims royalty-free use.
Section 3173.11(d) specifies the
timing requirements for submission of
an updated site facility diagram for
facilities for which the BLM will assign
an FMP number under § 3173.12. This
section applies to both new and existing
facilities.
• For facilities that are in service on
or after the effective date of the final
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mstockstill on DSK3G9T082PROD with RULES3
rule, a site facility diagram must be
submitted within 30 days after the BLM
assigns an FMP number to the facility.
• For facilities that are in service
before the effective date of the final rule
and that have a site facility diagram on
file that meets the minimum
requirements of the previous rule (i.e.,
Order 3), operators must submit a new
site facility diagram within 30 days
after:
Æ Existing facilities are modified;
Æ A non-Federal facility located on a
Federal lease or federally approved unit
or communitized area is constructed or
modified; or
Æ There is a change in operator.
The submitted diagram must comply
with the requirements of paragraphs (a)
through (c) of § 3173.11. Those
requirements are described above.
Section 3173.11(e) specifies the
timing requirements for submission of
an updated site facility diagram for
facilities for which the BLM will not
assign an FMP number under § 3173.12.
This section applies to both new and
existing facilities.
• For facilities that are in service on
or after the effective date of the final
rule, a site facility diagram must be
submitted within 30 days after the BLM
assigns an FMP number to the facility.
• For facilities that are in service
before the effective date of the final rule
and that have a site facility diagram on
file that meets the minimum
requirements of the previous rule (i.e.,
Order 3), operators must submit a new
site facility diagram within 30 days
after:
Æ Existing facilities are modified;
Æ A non-Federal facility located on a
Federal lease or federally approved unit
or communitized area is constructed or
modified; or
Æ There is a change in operator.
Section 3173.11(f) specifies that after
a site facility diagram has been
submitted that complies with the
requirements of § 3173.11, operators
have an ongoing obligation to update
and amend them within 30 days after
such facilities are modified, a nonFederal facility located on a Federal
lease or federally approved unit or
communitized area is constructed or
modified, or there is a change in
operator.
Request for Approval of an FMP for
Existing Measurement Facilities (43 CFR
3173.12(e)); and
Request for Approval of an FMP for
Future Measurement Facilities (43 CFR
3173.12(d))
Section 3173.12 requires operators to
obtain BLM approval of FMPs for all
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measurement points that are used to
determine royalties. An FMP is a BLMapproved point where oil or gas
produced from a Federal or Indian lease,
unit, or CA is measured and the
measurement affects the calculation of
the volume or quality of production on
which royalty is owed. See 43 CFR
3170.3.
This information collection activity
provides the BLM with a formal
nationwide process for designating and
approving the point at which oil or gas
must be measured for the purpose of
determining royalty. This activity assists
the BLM in verifying production. Upon
receiving an initial request for an FMP,
the BLM will approve it if it meets the
requirements of this rule, and assign
each FMP a unique identifying number,
which the operator, transporter, or
purchaser will use when reporting
production results to the Office of
Natural Resources Revenue (ONRR).
All requests for an FMP must include
the following:
• A complete Sundry Notice;
• The applicable Measurement Type
Code specified in the BLM’s Well
Information System (WIS);
• For gas measurement, identification
of the operator/purchaser/transporter
unique station number, meter tube size
or serial number, and type of secondary
device;
• For oil measurement, identification
of the oil tank number(s) or tank serial
number(s) and size of each tank, and
whether the oil was measured by LACT
or CMS if not measured by tank gauge;
• Where production from more than
one well will flow to the requested
FMP, a list of the API well numbers
associated with the FMP; and
• FMP location by land description.
Section 3173.12(d) requires operators
to request a new FMP for new
permanent measurement facilities
before any production leaves the
facility. Each request must meet the
requirements listed above.
Modifications to an FMP (43 CFR
3173.13(b)(1))
Section 3173.13(b)(1) requires
operators with an approved FMP to
submit a Sundry Notice that details any
modifications to the FMP within 30
days after the change. These details
include, but are not limited to, tank
numbers or serial numbers and sizes for
oil FMPs, unique station numbers,
meter tube sizes or serial numbers, and
type of secondary devices for gas FMPs,
and for all FMPs with more than one
well, the API numbers for all wells
associated with the facility. The Sundry
Notice must specify what was changed,
the effective date, and include, if
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81415
appropriate, an amended site facility
diagram. This information collection
activity assists the BLM in accurate
accounting of oil and gas production.
Request for Approval of an Existing
CAA (43 CFR 3173.15); and
Request for Approval of a Future CAA
(43 CFR 3173.15)
A CAA is a formal allocation
agreement to combine production from
two or more sources (leases, unit PAs,
CAs, or non-Federal or non-Indian
properties) before the FMP. See 43 CFR
3173.1. This information collection
activity helps the BLM obtain the
production data that is necessary to
verify production from Federal or
Indian leases covered by CAAs.
Section 3173.15 requires the
following information:
• A completed Sundry Notice seeking
approval of commingling and allocation,
and of off-lease measurement, if any of
the proposed FMPs are outside the
boundaries of any of the leases, units, or
CAs whose production would be
commingled;
• A proposed allocation agreement
and a proposed allocation methodology
with an example of how the
methodology is applied (including
allocation of produced water) signed by
each operator of each of the leases, unit
PAs, or CAs whose production would be
included in the CAA;
• A list of all Federal or Indian lease,
unit PA, or CA numbers in the proposed
CAA, specifying the type of production
(i.e., oil, gas, or both) for which
commingling is requested;
• A topographic map or maps
showing the boundaries of all the leases,
units, unit PAs, or communitized areas
whose production is proposed to be
commingled; the location of all existing
or planned facilities and relative
location of all wellheads and piping
included in the CAA, and FMPs existing
or proposed to be installed to the extent
known or anticipated;
• Documentation demonstrating that
each of the leases, unit PAs, or CAs
proposed for inclusion in the CAA is
producing in paying quantities (or, in
the case of Federal leases, is capable of
production in paying quantities)
pending approval of the CAA; and
• All gas analyses, including Btu
content (if the CAA request includes
gas) and all oil gravities (if the CAA
request includes oil) for previous
periods of production from the leases,
units, unit PAs, or CAs proposed for
inclusion in the CAA, up to 6 years
before the date of the application for
approval of the CAA. However, gas
analysis and oil gravity data is not
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needed if the CAA meets the
requirements and standards of
§ 3173.14(a) of the final rule.
If new surface disturbance is
proposed on one or more of the leases,
units, or CAs, and the surface is
managed by the BLM, the application
must include a proposed surface use
plan of operations for the proposed
surface disturbance.
If new surface disturbance is
proposed on BLM-managed land outside
any of the leases, units, or CAs whose
production would be commingled, the
application must include a right-of-way
grant application, under 43 CFR part
2880 if the FMP is on a pipeline, or
under 43 CFR part 2800, if the FMP is
a meter or storage tank. Applications for
right-of-way (i.e., on SF–299) are
authorized under OMB control number
0596–0082.
If new surface disturbance is
proposed on Federal land managed by
an agency other than the BLM, the
application must include written
approval from the appropriate surfacemanagement agency.
If a new surface disturbance is
proposed on Indian land outside the
lease, unit, or communitized area from
which the production would be
commingled, a right-of-way grant
application must be filed under 25 CFR
part 169, with the appropriate BIA
office.
mstockstill on DSK3G9T082PROD with RULES3
Request for Modification of a CAA (43
CFR 3173.18)
Section 3173.18 provides that a CAA
must be modified when there is
modification to the allocation
agreement, additional leases, unit PAs,
or CAs are proposed for inclusion in the
CAA, or any of the leases, unit PAs, or
CAs within the CAA terminate or
permanently cease production. The
following information would be
required in a request to modify a CAA:
• A completed Sundry Notice
describing the modification requested;
• A new allocation methodology, if
appropriate, and an example of how the
methodology is applied; and
• Certification by each operator that it
agrees to the CAA modification.
This information collection activity
helps the BLM obtain the production
data that is necessary to verify
production from Federal or Indian
leases covered by CAAs.
Response to Notice of Insufficient CAA
(43 CFR 3173.16)
Upon receipt of an operator’s request
for assignment of an FMP number to a
facility associated with a CAA existing
on the effective date of the final rule, (1)
The BLM may determine that the CAA
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meets the requirements (at 43 CFR
3173.16) for grandfathering the CAA; or
(2) If grandfathering is not appropriate,
the BLM will review the CAA for
consistency with the minimum
standards and requirements for a CAA
under 43 CFR 3173.14. The BLM will
notify the operator in writing of any
inconsistencies or deficiencies. The
operator must then correct any
inconsistencies or deficiencies that the
AO identifies, provide additional
information, or request an extension of
time, within 20 business days after
receipt of the BLM’s notice. When the
BLM is satisfied that the operator has
corrected any inconsistencies or
deficiencies, the BLM will terminate the
existing CAA and grant a new CAA
based on the operator’s corrections. If
the existing CAA does not meet the
applicable standards and the operator
does not correct the deficiencies, the
BLM may terminate the existing CAA
and deny the request for an FMP
number for the facility associated with
the existing CAA.
Request To Modify a CAA (43 CFR
3173.18)
A CAA must be modified when there
is a modification to the allocation
agreement; additional leases, unit PAs,
or CAs are proposed for inclusion in the
CAA; or any of the leases, unit PAs, or
CAs within the CAA terminate or
permanently cease production.
To request a modification of a CAA,
all operators must submit to the BLM:
• A completed Sundry Notice
describing the modification requested;
• A new allocation methodology,
including an allocation methodology
which includes allocation of produced
water and an example of how the
methodology is applied, if appropriate;
and
• Certification by each operator in the
CAA that it agrees to the CAA
modification.
A change in operator does not trigger
the need to modify a CAA.
Request To Terminate a CAA (43 CFR
3173.20)
Section 3173.20 authorizes the BLM
to terminate an approved CAA and
allows for the CAA to be terminated by
the operator at their request. The
operator must submit a Sundry Notice
to the BLM requesting the termination
in which the notice must identify the
FMP(s) for the lease(s), unit(s), or CA(s)
previously subject to the CAA.
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Request for Approval of Off-Lease
Measurement—General (43 CFR
3173.23);
Request for Approval of Off-Lease
Measurement—Amendment of an
Existing Approval (43 CFR 3173.23);
and
Response to Notice of Insufficient OffLease Measurement Approval (43 CFR
3173.25)
These information collection
activities assist the BLM in reducing
discrepancies between operatorallocated volumes, which operators
report to ONRR, and the volumes that
the BLM calculates during follow-up
audits. In accordance with this final
rule, the BLM will allow off-lease
measurement of production only from a
single Federal or Indian lease, unit PA,
CA, or CAA, and only at an approved
FMP.
Section 3173.23(a) through (j) requires
the following information in an
application for approval of off-lease
measurement:
• A completed Sundry Notice;
• Justification for off-lease
measurement;
• A topographic map of appropriate
scale showing the boundary of the
lease(s), unit(s), or CA(s) from which the
production originates, the location of
existing or planned facilities, the
relative location of all wellheads
(including the API number for each
well) and piping included in the offlease measurement proposal, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
• The surface ownership of all land
on which equipment is, or is proposed
to be, located; and
• A statement that indicates whether
the proposal includes all, or only a
portion of, the production from the
lease, unit, or CA and if the proposal
includes only a portion of the
production, the application would be
required to identify the FMP(s) where
the remainder of the production from
the lease, unit, or CA is measured or is
proposed to be measured.
If any of the proposed off-lease
measurement facilities are located on
non-federally owned surface, the
application must include a written
concurrence signed by the owner(s) of
the surface and the owner(s) of the
measurement facilities, including each
owner(s)’ name, address, and telephone
number, granting the BLM unrestricted
access to the off-lease measurement
facility and the surface on which it is
located, for the purpose of inspecting
any production, measurement, water
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handling, or transportation equipment
located on the non-Federal surface up to
and including the FMP, and for
otherwise verifying production
accountability. If the ownership of the
non-Federal surface or of the
measurement facility changes, the
operator must obtain and provide to the
AO the written concurrence required
under this paragraph from the new
owner(s) within 30 days of the change
in ownership.
If a proposed off-lease FMP with
facilities on BLM land would involve
new surface disturbance and consists of
a meter or storage tank, or is on a
pipeline, a right-of-way grant
application must be submitted.
Applications for rights-of-way (SF–299)
are authorized under control number
0596–0082, which is administered by
the U.S. Forest Service on behalf of
several Federal agencies. If new surface
disturbance if proposed for an FMP that
includes facilities on Federal land
managed by an agency other than the
BLM, written approval is required from
that agency. A right-of-way grant
application must also be submitted with
the appropriate BIA office if any of the
proposed facilities are on Indian lands
outside of the producing area.
If the operator proposes to use
production from the lease, unit or CA as
fuel at the off-lease measurement facility
without payment of royalty, the
application must include an application
for approval of off-lease royalty-free use
under applicable rules. The BLM is
developing the applicable rules and will
seek OMB clearance for the information
collection activities in those rules.
Section 3173.23(k) provides that to
apply for an amendment of an existing
approval of off-lease measurement, the
operator must submit a completed
Sundry Notice required under
paragraph (a), and information listed at
paragraphs (b) through (j) of § 3173.23 to
the extent the previously submitted
information has changed. This
information collection activity assists
the BLM in reducing discrepancies
between operator-allocated volumes,
which operators report to ONRR, and
the volumes that the BLM calculates
during follow-up audits.
Upon receipt of an operator’s request
for assignment of an FMP number for a
facility associated with an off-lease
measurement approval existing on the
effective date of the final rule, the BLM
will review the existing approval for
consistency with the requirements at 43
CFR 3173.22. The BLM will notify the
81417
operator of any inconsistencies or
deficiencies. The operator must correct
any of the identified flaws, provide
additional information, or request an
extension of time from the AO, within
20 business days after receiving the
notice. This information collection
activity assists the BLM in reducing
discrepancies between operatorallocated volumes, which operators
report to ONRR, and the volumes that
the BLM calculates during follow-up
audits.
Request To Terminate an Off-Lease
Measurement Approval (43 CFR
3173.27)
Section 3173.27 authorizes the BLM
to terminate an off-lease measurement
approval and allows for the off-lease
measurement approval to also be
terminated by the operator at their
request. The operator must submit a
Sundry Notice to the BLM requesting
the termination in which the notice
must identify the new FMP(s) for the
lease(s), unit(s), or CA(s) previously
subject to the off-lease measurement
approval.
The following table itemizes the
estimated hour and cost burdens for the
information collection activities.
ESTIMATED HOUR BURDENS
Number of
responses
Hours per
response
Total hours
(Column B ×
Column C)
A.
mstockstill on DSK3G9T082PROD with RULES3
Type of response
B.
C.
D.
Variance Requests (43 CFR 3170.6) Annual ..............................................................................
Required Recordkeeping and Records Submission (43 CFR 3170.7) Annual ...........................
Water-Draining Operations—Data Collection (43 CFR 3173.6) Annual .....................................
Water-Draining Operations —Recordkeeping and Records Submission (43 CFR 3173.6) Annual ...........................................................................................................................................
Hot Oiling, Clean-Up, and Completion Operations—Data Collection (43 CFR 3173.7) Annual
Hot Oiling, Clean-Up, and Completion Operations—Recordkeeping and Records Submission
(43 CFR 3173.6) Annual ..........................................................................................................
Report of Theft or Mishandling of Production (43 CFR 3173.8) Annual ....................................
Required Recordkeeping for Inventory and Seal Records (43 CFR 3173.9) Annual .................
Site Facility Diagrams for Existing Facilities) (43 CFR 3173.11(d)(2)) One-time .......................
Site Facility Diagrams for Future Facilities (43 CFR 3173.11(d)(1)) Annual ..............................
Request for Approval of an FMP for Existing Measurement Facilities (43 CFR 3173.12(e))
One-time ...................................................................................................................................
Request for Approval of an FMP for Future Measurement Facilities (43 CFR 3173.12(d)) Annual ...........................................................................................................................................
Modifications to an FMP (43 CFR 3173.13(b)(1)) Annual ..........................................................
Request for Approval of an Existing CAA (43 CFR 3173.15) One-time .....................................
Request for Approval of a Future CAA (43 CFR 3173.15) Annual ............................................
Response to Notice of Insufficient CAA (43 CFR 3173.16) Annual ...........................................
Request to Modify a CAA (43 CFR 3173.18) Annual .................................................................
Request for Approval of Off-Lease Measurement—General (43 CFR 3173.23) Annual ...........
Request for Approval of Off-Lease Measurement—Amendment of an Existing Approval (43
CFR 3173.23) One-time ...........................................................................................................
Response to Notice of Insufficient Off-Lease Measurement Approval (43 CFR 3173.25) Annual ...........................................................................................................................................
Totals ....................................................................................................................................
VerDate Sep<11>2014
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Frm 00063
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Sfmt 4700
100
4,300
5,000
8
5
2
800
21,500
10,000
60,000
5,000
0.25
2
15,000
10,000
15,000
5
5,000
4,156
5,000
0.25
10
2
6
6
3,750
50
10,000
24,935
30,000
166,232
2
332,464
1,000
1,000
1,662
500
150
500
100
2
2
40
40
40
40
10
2,000
2,000
66,480
20,000
6,000
20,000
1,000
166
10
1,662
15
40
600
274,886
........................
578,240
E:\FR\FM\17NOR3.SGM
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
National Environmental Policy Act
The BLM prepared an environmental
assessment (EA), a Finding of No
Significant Impact (FONSI), and
Decision Record (DR) that concludes
that the final rule will not constitute a
major Federal action significantly
affecting the quality of the human
environment under Section 102(2)(C) of
the National Environmental Policy Act
(NEPA), 42 U.S.C. 4332(2)(C). Therefore,
a detailed statement under NEPA is not
required. A copy of the EA, FONSI, and
DR are available for review and on file
in the BLM Administrative Record at
the address specified in the ADDRESSES
section.
As explained in the EA, FONSI, and
DR, the final rule will not have a
significant effect on the human
environment because, for the most part,
its requirements involve changes that
are of an administrative, technical, or
procedural nature that apply to the
BLM’s and the lessee’s or operator’s
management processes. For example,
operators are now required to maintain
records generated for Federal leases for
at least 7 years, consistent with statutory
requirements. Similarly, the final rule
requires more detailed information on
site facility diagrams such as
information about the equipment for
which an operator claims royalty-free
use. The submission of this additional
information will not result in any onthe-ground impacts. In contrast with
these provisions, compliance with some
of the rule’s other requirements may
result in additional surface-disturbing
activities (e.g., additional surface
disturbance might be required if an
operator with an existing off lease
measurement authorization has to move
those measurement facilities back on
lease because they did not comply with
the requirements of this final rule.) Such
surface-disturbing activities will be
subject to their own project-specific
NEPA analyses, as appropriate, and will
be conducted in accordance with
existing surface operating standards and
guidelines for oil and gas exploration
and development, including appropriate
Best Management Practices (BMP).
A draft of the EA was shared with the
public during the public comment
period on the proposed rule. During that
process the BLM received a handful of
comments on the EA. Some commenters
questioned the BLM’s level of NEPA
analysis, specifically whether the BLM
had met the ‘‘hard look’’ test of
describing the environmental
consequences of the proposed action,
and the BLM’s ability to reach a FONSI
based on the level of analysis prepared.
One commenter requested a complete
VerDate Sep<11>2014
22:18 Nov 16, 2016
Jkt 241001
NEPA revision with formal scoping on
the EA and a meaningful socioeconomic
analysis. Many commenters questioned
the use of three separate EAs to disclose
impacts of three separate orders. Those
commenters asserted that CEQ
regulations require connected actions to
be evaluated in a single document and
suggested a single EIS to address all
three rules.
CEQ’s NEPA regulations at 40 CFR
1508.18 identify new or revised agency
rules and regulations as an example of
a Federal action. Drafting new agency
regulations of a technical or
administrative nature is a Federal action
that is categorically excluded from
NEPA review pursuant to 43 CFR
46.210(i). Instead of relying on the
categorical exclusion, the BLM chose to
complete a more robust level of NEPA
documentation in the form of an EA for
each of the proposed rules to replace
Orders 3, 4, and 5. By preparing an EA
for each of the proposed regulations, the
BLM was able to disclose the potential
environmental effects of the Federal
agency decision on each of the
regulations. This analysis addressed the
impact of each rule individually, as well
as the impact of all three rules
cumulatively. With respect to socioeconomic impacts, the BLM completed
an Economic and Threshold Analyses
for each of the rules. These analyses
were not referenced in the Draft EAs for
the rules, but have been addressed in
the EAs for the final rules.
Other commenters stated that the
BLM understated the potential surface
impacts associated with the new rules
and did not: (i) Adequately address
potential surface impacts to private
land; (ii) Address a reasonable range of
alternatives; and (iii) Adequately
describe the affected environment. As
explained in the EA, the BLM
anticipates that in the majority of cases,
operators will use existing surface
disturbances such as existing well pad
locations in connection with activities
undertaken in compliance with the final
rule, which will minimize new surface
construction and surface impacts.
Similarly, the codification of BLM
regulations does not hinder or prevent
development of private minerals. The
likelihood of impacts to private surface
is low. It is unclear whether private
lands would be affected at all by the
denial of off-lease measurement
agreements and the resultant re-location
of measurement facilities on to a lease,
CA or unit PA. In the rare instances
when new pipelines or other facilities
were found to be necessary on private
surface, BLM authorization for activities
on split estate would include sitespecific NEPA documentation, with
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Fmt 4701
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appropriate project-level mitigation and
BMPs. In short, the impact of these
provisions on private lands in terms of
surface disturbance is likely to be
minimal, and any attempt to estimate
these impacts would be speculative.
The BLM’s obligation under NEPA is
to analyze alternatives that would meet
the purpose and need for the proposed
action and allow for a reasoned choice
to be made. As described in the EA, a
number of alternatives were considered,
but eliminated from detailed study
because they did not meet the purpose
and need. Similarly, the discussion of
the affected environment should only
contain data and analysis commensurate
in detail with the importance of the
impacts, which the BLM anticipates to
be minimal. The EA, FONSI, and DR
were updated to address these
comments, but did not change the
BLM’s overall analysis of the potential
environmental impacts of the rule.
Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This final rule will not have a
substantial direct effect on the nation’s
energy supply, distribution or use,
including a shortfall in supply or price
increase. The final rule strengthens the
BLM’s production accountability
requirements for operators of Federal
and Indian oil and gas leases. These
changes increase recordkeeping
requirements, place additional
restrictions on CAAs and on off-lease
measurement, and provide for
significant new immediate assessments
for violations of the regulations. All of
these changes in the final rule are
administrative in nature and will have
a one-time average transition cost of
about $8,400 per regulated entity and an
ongoing annual average cost of about
$3,200 per entity per year. Entities with
the greatest activity (e.g., numerous
FMPs) will incur higher costs, but they
will still be relatively minor. As a result,
the BLM does not expect that the final
rule will result in a net change in the
quantity of oil and gas that is produced
from oil and gas leases on Federal and
Indian lands.
Information Quality Act
In developing this rule, the BLM did
not conduct or use a study, experiment,
or survey requiring peer review under
the Information Quality Act (Pub. L.
106–554, Appendix C Title IV, 515, 114
Stat. 2763A–153).
Authors
The principal authors of this final rule
are Michael Wade, Senior Oil and Gas
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Compliance Specialist, BLM
Washington Office; Adrienne Brumley,
Petroleum Engineer, BLM New Mexico
State Office; Conan Donnelly, Petroleum
Engineering Technician, BLM Miles
City Field office; Kahindo Kamau,
Petroleum Engineer, BLM Great Falls
Field Office; Steve McCracken,
Petroleum Engineering Technician,
BLM Great Falls Field Office; Chris
Carey, ONRR Denver Office; Luke
Lundmark, ONRR Denver Office; and
Vicky Stafford, ONRR Denver Office.
The team was assisted by Rich
Estabrook, BLM Washington Office;
Faith Bremner, Jean Sonneman and Ian
Senio, Office of Regulatory Affairs, BLM
Washington Office; Michael Ford,
Economist, BLM Washington Office;
Barbara Sterling, Natural Resource
Specialist, BLM Colorado State Office;
Bryce Barlan, Senior Policy Analyst,
BLM Washington Office; and Dylan
Fuge, Counselor to the Director, BLM
Washington Office; Christopher
Rhymes, Attorney Advisor, Office of the
Solicitor, Department of the Interior;
and Leslie Peterson and Geoffrey Heath
(both now retired).
List of Subjects
43 CFR Part 3160
Administrative practice and
procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and
gas exploration, Penalties, Public
lands—mineral resources, Reporting
and recordkeeping requirements.
43 CFR Part 3170
Administrative practice and
procedure, Immediate assessments,
Incorporation by reference, Indianslands, Mineral royalties, Oil and gas
measurement, Public lands—mineral
resources.
Dated: October 6, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals
Management.
1. Revise the authority citation for part
3160 to read as follows:
mstockstill on DSK3G9T082PROD with RULES3
■
Authority: 25 U.S.C. 396, 396d and 2107;
30 U.S.C. 189, 306, 359, and 1751; and 43
U.S.C. 1732(b), 1733, and 1740.
[Amended]
2. Amend § 3160.0–3 by removing the
words ‘‘the Federal Oil and Gas Royalty
Management Act of 1982 (30
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Jkt 241001
Jurisdiction.
(a) The regulations in this part apply
to all operations conducted on:
(1) All Federal and Indian (except
those of the Osage Tribe) onshore oil
and gas leases;
(2) All onshore facility measurement
points where Federal or Indian (except
those of the Osage Tribe) oil or gas is
measured;
(3) Indian Mineral Development Act
agreements for oil and gas, unless
specifically excluded in the agreement;
and
(4) Leases and other business
agreements for the development of tribal
energy resources under a Tribal Energy
Resource Agreement entered into with
the Secretary, unless specifically
excluded in the lease, other business
agreement, or Tribal Energy Resource
Agreement.
(b) The regulations in this part and 43
CFR part 3170, including subparts 3173,
3174, and 3175, relating to site security,
measurement of oil and gas, reporting of
production and operations, and
assessments or penalties for noncompliance with such requirements, are
applicable to all wells and facilities on
State or privately owned lands
committed to a unit or communitization
agreement, which include Federal or
Indian lease interests, notwithstanding
any provision of a unit or
communitization agreement to the
contrary.
■ 4. Amend § 3162.3–2 by adding
paragraph (d) to read as follows:
Subsequent well operations.
*
PART 3160—ONSHORE OIL AND GAS
OPERATIONS
■
§ 3161.1
§ 3162.3–2
For the reasons set out in the
preamble, the Bureau of Land
Management amends 43 CFR chapter II
as follows:
§ 3160.0–3
U.S.C.1701)’’ and adding in their place
the words ‘‘the Federal Oil and Gas
Royalty Management Act of 1982, as
amended by the Federal Oil and Gas
Royalty Simplification Act of 1996 (30
U.S.C. 1701 et seq.)’’.
■ 3. Revise § 3161.1 to read as follows:
*
*
*
*
(d) For details on how to apply for
approval of a facility measurement
point; approval for surface or subsurface
commingling from different leases, unit
participating areas and communitized
areas; or approval for off-lease
measurement, see 43 CFR 3173.12,
3173.15, and 3173.23, respectively.
■ 5. Amend § 3162.4–1 by revising
paragraphs (a) and (d) and adding
paragraph (e) to read as follows:
§ 3162.4–1
Well records and reports.
(a) The operator must keep accurate
and complete records with respect to:
(1) All lease operations, including, but
not limited to, drilling, producing,
redrilling, repairing, plugging back, and
abandonment operations;
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81419
(2) Production facilities and
equipment (including schematic
diagrams as required by applicable
orders and notices); and
(3) Determining and verifying the
quantity, quality, and disposition of
production from or allocable to Federal
or Indian leases (including source
records).
*
*
*
*
*
(d) All records and reports required
by this section must be maintained for
the following time periods:
(1) For Federal leases and units or
communitized areas that include
Federal leases, but do not include
Indian leases:
(i) Seven years after the records are
generated; unless,
(ii) A judicial proceeding or demand
involving such records is timely
commenced, in which case the record
holder must maintain such records until
the final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or the applicable
delegated State authorizes in writing an
earlier release of the requirement to
maintain such records.
(2) For Indian leases, and units or
communitized areas that include Indian
leases, but do not include Federal
leases:
(i) Six years after the records are
generated; unless,
(ii) The Secretary or his/her designee
notifies the record holder that the
Department has initiated or is
participating in an audit or investigation
involving such records, in which case
the record holder must maintain such
records until the Secretary or his/her
designee releases the record holder from
the obligation to maintain the records.
(3) For units and communitized areas
that include both Federal and Indian
leases, 6 years after the records are
generated, unless the Secretary or his/
her designee has notified the record
holder within those 6 years that an audit
or investigation involving such records
has been initiated, then:
(i) If a judicial proceeding or demand
is commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the lease, unit or
communitization agreement until the
final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or his/her designee
authorizes in writing a release of the
requirement to maintain such records
before a final nonappealable decision is
made or rendered;
(ii) If a judicial proceeding or demand
is not commenced within 7 years after
E:\FR\FM\17NOR3.SGM
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the records are generated, the record
holder must retain all records regarding
production from the unit or
communitized area until the Secretary
or his/her designee releases the record
holder from the obligation to maintain
the records.
(e) Record holders include lessees,
operators, purchasers, transporters, and
any other person directly involved in
producing, transporting, purchasing, or
selling, including measuring, oil or gas
through the point of royalty
measurement or the point of first sale,
whichever is later. Record holders must
maintain records generated during or for
the period for which the lessee or
operator has an interest in or conducted
operations on the lease, or in which a
person is involved in transporting,
purchasing, or selling production from
the lease, for the period of time required
in paragraph (d) of this section.
§ 3162.4–3
[Removed]
6. Remove § 3162.4–3.
■ 7. Amend § 3162.6 as follows:
■ a. In paragraph (a), remove the word
‘‘indentification’’ and add in its place
‘‘identification’’; and
■ b. Revise paragraphs (b) and (c),
redesignate paragraph (d) as paragraph
(e), and add a new paragraph (d).
The revisions and addition read as
follows:
■
§ 3162.6
Well and facility identification.
mstockstill on DSK3G9T082PROD with RULES3
*
*
*
*
*
(b) For wells located on Federal and
Indian lands, the operator must properly
identify, by a sign in a conspicuous
place, each well, other than those
permanently abandoned. The well sign
must include the well number, the name
of the operator, the lease serial number,
and the surveyed location (the quarterquarter section, section, township and
range or other authorized survey
designation acceptable to the authorized
officer, such as metes and bounds or
longitude and latitude). When
specifically requested by the authorized
officer, the sign must include the unit or
communitization agreement name or
number. The authorized officer may also
require the sign to include the name of
the Indian allottee lessor(s) preceding
the lease serial number.
(c) All facilities at which oil or gas
produced from a Federal or Indian lease
is stored, measured, or processed must
be clearly identified with a sign that
contains the name of the operator, the
lease serial number or communitization
or unit agreement identification
number, as appropriate, and the
surveyed location (the quarter-quarter
section, section, township and range or
other authorized survey designation
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acceptable to the authorized officer,
such as metes and bounds or longitude
and latitude). On Indian leases, the sign
also must include the name of the
appropriate tribe and whether the lease
is tribal or allotted. For situations of one
tank battery servicing one well in the
same location, the requirements of this
paragraph and paragraph (b) of this
section may be met by one sign as long
as it includes the information required
by both paragraphs. In addition, each
storage tank must be clearly identified
by a unique number. With regard to the
quarter-quarter designation and the
unique tank number, any such
designation established by State law or
regulation satisfies this requirement.
(d) All signs must be maintained in
legible condition and must be clearly
apparent to any person at or
approaching the storage, measurement,
or transportation point.
*
*
*
*
*
§ 3162.7–1
[Amended]
8. Amend § 3162.7–1 by removing
paragraph (f).
■
§ 3162.7–5
[Removed]
9. Remove § 3162.7–5.
■ 10. Amend § 3163.2 by:
■ a. Revising paragraphs (a), (b), (d), (e)
introductory text, and (f) introductory
text;
■ b. Removing paragraph (g);
■ c. Redesignating paragraphs (h) and (i)
as paragraphs (g) and (h);
■ d. Revising newly redesignated
paragraphs (g) and (h); and
■ e. Removing paragraphs (j) and (k).
The revisions read as follows:
■
§ 3163.2
Civil penalties.
(a)(1) Whenever any person fails or
refuses to comply with any applicable
requirements of the Federal Oil and Gas
Royalty Management Act, any mineral
leasing law, any regulation thereunder,
or the terms of any lease or permit
issued thereunder, the authorized
officer will notify the person in writing
of the violation, unless the violation was
discovered and reported to the
authorized officer by the liable person
or the notice was previously issued
under § 3163.1.
(2) Whenever a purchaser or
transporter who is not an operating
rights owner or operator fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil and gas lease, the
authorized officer will notify the
purchaser or transporter, as appropriate,
in writing of the violation.
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Fmt 4701
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(b)(1) If the violation specified in
paragraph (a) of this section is not
corrected within 20 days of such notice
or report, or such longer time as the
authorized officer may agree to in
writing, the person will be liable for a
civil penalty of up to $1,031 per
violation for each day such violation
continues, dating from the date of such
notice or report. Any amount imposed
and paid as assessments under
§ 3163.1(a)(1) will be deducted from
penalties under this section.
(2) If the violation specified in
paragraph (a) of this section is not
corrected within 40 days of such notice
or report, or a longer period as the
authorized officer may agree to in
writing, the person will be liable for a
civil penalty of up to $10,314 per
violation for each day the violation
continues, dating from the date of such
notice or report. Any amount imposed
and paid as assessments under
§ 3163.1(a)(1) will be deducted from
penalties under this section.
*
*
*
*
*
(d) Whenever a transporter fails to
permit inspection for proper
documentation by any authorized
representative, as provided in § 3162.7–
1(c) of this chapter, the transporter is
liable for a civil penalty of up to $1,031
per day for the violation, dating from
the date of notice of the failure to permit
inspection and continuing until the
proper documentation is provided. If
the violation continues beyond 20 days,
the authorized officer will revoke the
transporter’s authority to remove crude
oil produced from, or allocated to, any
Federal or Indian lease under the
authority of that authorized officer. This
revocation of the transporter’s authority
will continue until the transporter
provides proper documentation and
pays any related penalty.
(e) Any person is liable for a civil
penalty of up to $20,628 per violation
for each day such violation continues, if
the person:
*
*
*
*
*
(f) Any person is liable for a civil
penalty of up to $51,570 per violation
for each day such violation continues, if
the person:
*
*
*
*
*
(g) On a case-by-case basis, the
Secretary may compromise or reduce
civil penalties under this section. In
compromising or reducing the amount
of a civil penalty, the Secretary will
state on the record the reasons for such
determination.
(h) Civil penalties provided by this
section are supplemental to, and not in
derogation of, any other penalties or
assessments for noncompliance in any
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other provision of law, except as
provided in paragraphs (a) and (b) of
this section.
§ 3164.1
[Amended]
11. Amend § 3164.1, in paragraph (b),
by removing the third entry in the table
(the reference to Order No. 3, Site
Security).
■ 12. Amend § 3165.3 by revising
paragraphs (a) and (d) to read as follows:
■
mstockstill on DSK3G9T082PROD with RULES3
§ 3165.3 Notice, State Director review and
hearing on the record.
(a) Notice. (1) Whenever any person
fails to comply with any provisions of
the lease, the regulations in this part,
applicable orders or notices, or any
other appropriate order of the
authorized officer, the authorized officer
will issue a written notice or order to
the appropriate party and the lessee(s)
to remedy any defaults or violations.
(2) Whenever any purchaser or
transporter, who is not an operating
rights owner or operator, fails or refuses
to comply with 30 U.S.C. 1713 or
applicable rules or regulations regarding
records relevant to determining the
quality, quantity, and disposition of oil
or gas produced from or allocable to a
Federal or Indian oil and gas lease,
applicable orders or notices, or any
other appropriate orders of the
authorized officer, the authorized officer
will give written notice or order to the
purchaser or transporter to remedy any
violations.
(3) Written orders or a notice of
violation, assessment, or proposed
penalty will be issued and served by
personal service by the authorized
officer, or by certified mail, return
receipt requested. Service will be
deemed to occur when the document is
received or 7 business days after the
date it is mailed, whichever is earlier.
(4) Any person may designate a
representative to receive any notice of
violation, order, assessment, or
proposed penalty on that person’s
behalf.
(5) In the case of a major violation, the
authorized officer will make a good faith
effort to contact such designated
representative by telephone, to be
followed by a written notice or order.
Receipt of a notice or order will be
deemed to occur at the time of such
verbal communication, and the time of
notice and the name of the receiving
party will be documented in the file. If
the good faith effort to contact the
designated representative is
unsuccessful, notice of the major
violation or order may be given to any
person conducting or supervising
operations subject to the regulations in
this part.
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(6) In the case of a minor violation,
the authorized officer will only provide
a written notice or order to the
designated representative.
(7) A copy of all orders, notices, or
instructions served on any contractor or
field employee or designated
representative will also be mailed to the
operator. Any notice involving a civil
penalty against an operator will be
mailed to the operator, with a copy to
the operating rights owner.
*
*
*
*
*
(d) Action on request for State
Director review. The State Director will
issue a final decision within 10 business
days after the receipt of a complete
request for administrative review or,
where oral presentation has been made,
within 10 business days after the oral
presentation. The State Director’s
decision represents the final Bureau
decision from which further review may
be obtained as provided in paragraph (c)
of this section for proposed penalties,
and in § 3165.4 for all other decisions.
*
*
*
*
*
■ 13. Add part 3170 to read as follows:
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
Subpart 3170—Onshore Oil and Gas
Production: General
Sec.
3170.1 Authority.
3170.2 Scope.
3170.3 Definitions and acronyms.
3170.4 Prohibitions against by-pass and
tampering.
3170.5 [Reserved]
3170.6 Variances.
3170.7 Required recordkeeping, records
retention, and records submission.
3170.8 Appeal procedures.
3170.9 Enforcement.
Subpart 3171—[Reserved]
Subpart 3172—[Reserved]
Subpart 3173—Requirements for Site
Security and Production Handling
3173.1 Definitions and acronyms.
3173.2 Storage and sales facilities—seals.
3173.3 Oil measurement system
components—seals.
3173.4 Federal seals.
3173.5 Removing production from tanks for
sale and transportation by truck.
3173.6 Water-draining operations.
3173.7 Hot oiling, clean-up, and completion
operations.
3173.8 Report of theft or mishandling of
production.
3173.9 Required recordkeeping for
inventory and seal records.
3173.10 Form 3160–5, Sundry Notices and
Reports on Wells.
3173.11 Site facility diagram.
3173.12 Applying for a facility
measurement point.
3173.13 Requirements for approved facility
measurement points.
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3173.14 Conditions for commingling and
allocation approval (surface and
downhole).
3173.15 Applying for a commingling and
allocation approval.
3173.16 Existing commingling and
allocation approvals.
3173.17 Relationship of a commingling and
allocation approval to royalty-free use of
production.
3173.18 Modification of a commingling and
allocation approval.
3173.19 Effective date of a commingling
and allocation approval.
3173.20 Terminating a commingling and
allocation approval.
3173.21 Combining production downhole
in certain circumstances.
3173.22 Requirements for off-lease
measurement.
3173.23 Applying for off-lease
measurement.
3173.24 Effective date of an off-lease
measurement approval.
3173.25 Existing approved off-lease
measurement.
3173.26 Relationship of off-lease
measurement approval to royalty-free
use of production.
3173.27 Termination of off-lease
measurement approval.
3173.28 Instances not constituting off-lease
measurement, for which no approval is
required.
3173.29 Immediate assessments for certain
violations.
Appendix A to Subpart 3173—Examples of
Site Facility Diagrams
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; and 43 U.S.C.
1732(b), 1733, and 1740.
Subpart 3170—Onshore Oil and Gas
Production: General
§ 3170.1
Authority.
The authorities for promulgating the
regulations in this part are the Mineral
Leasing Act, 30 U.S.C. 181 et seq.; the
Mineral Leasing Act for Acquired
Lands, 30 U.S.C. 351 et seq.; the Federal
Oil and Gas Royalty Management Act,
30 U.S.C. 1701 et seq.; the Indian
Mineral Leasing Act, 25 U.S.C. 396a et
seq.; the Act of March 3, 1909, 25 U.S.C.
396; the Indian Mineral Development
Act, 25 U.S.C. 2101 et seq.; and the
Federal Land Policy and Management
Act, 43 U.S.C. 1701 et seq. Each of these
statutes gives the Secretary the authority
to promulgate necessary and
appropriate rules and regulations
governing Federal and Indian (except
Osage Tribe) oil and gas leases. See 30
U.S.C. 189; 30 U.S.C. 359; 25 U.S.C.
396d; 25 U.S.C. 396; 25 U.S.C. 2107; and
43 U.S.C. 1740. Under Secretarial Order
Number 3087, dated December 3, 1982,
as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual
(235 DM 1.1), the Secretary has
delegated regulatory authority over
onshore oil and gas development on
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Federal and Indian (except Osage Tribe)
lands to the BLM. For Indian leases, the
delegation of authority to the BLM is
reflected in 25 CFR parts 211, 212, 213,
225, and 227. In addition, as authorized
by 43 U.S.C. 1731(a), the Secretary has
delegated to the BLM regulatory
responsibility for oil and gas operations
on Indian lands. 235 DM 1.1.K.
§ 3170.2
Scope.
The regulations in this part apply to:
(a) All Federal onshore and Indian oil
and gas leases (other than those of the
Osage Tribe);
(b) Indian Mineral Development Act
(IMDA) agreements for oil and gas,
unless specifically excluded in the
agreement or unless the relevant
provisions of the rule are inconsistent
with the agreement;
(c) Leases and other business
agreements for the development of tribal
energy resources under a Tribal Energy
Resource Agreement entered into with
the Secretary, unless specifically
excluded in the lease, other business
agreement, or Tribal Energy Resource
Agreement;
(d) State or private tracts committed
to a federally approved unit or
communitization agreement (CA) as
defined by or established under 43 CFR
subpart 3105 or 43 CFR part 3180; and
(e) All onshore facility measurement
points where oil or gas produced from
the leases or agreements identified
earlier in this section is measured.
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§ 3170.3
Definitions and acronyms.
(a) As used in this part, the term:
Allocated or allocation means a
method or process by which production
is measured at a central point and
apportioned to the individual lease, or
unit Participating Area (PA), or CA from
which the production originated.
API (followed by a number) means the
American Petroleum Institute Manual of
Petroleum Measurement Standards,
with the number referring to the Chapter
and Section in that manual.
Audit trail means all source records
necessary to verify and recalculate the
volume and quality of oil or gas
production measured at a facility
measurement point (FMP) and reported
to the Office of Natural Resources
Revenue (ONRR).
Authorized officer (AO) has the same
meaning as defined in 43 CFR 3000.0–
5.
Averaging period means the previous
12 months or the life of the meter,
whichever is shorter. For FMPs that
measure production from a newly
drilled well, the averaging period
excludes production from that well that
occurred in or before the first full month
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of production. (For example, if an oil
FMP and a gas FMP were installed to
measure only the production from a
new well that first produced on April
10, the averaging period for this FMP
would not include the production that
occurred in April (partial month) and
May (full month) of that year.)
Bias means a shift in the mean value
of a set of measurements away from the
true value of what is being measured.
By-pass means any piping or other
arrangement around or avoiding a meter
or other measuring device or method (or
component thereof) at an FMP that
allows oil or gas to flow without
measurement. Equipment that permits
the changing of the orifice plate of a gas
meter without bleeding the pressure off
the gas meter run (e.g., senior fitting) is
not considered to be a by-pass.
Commingling, for production
accounting and reporting purposes,
means combining, before the point of
royalty measurement, production from
more than one lease, unit PA, or CA, or
production from one or more leases,
unit PAs, or CAs with production from
State, local governmental, or private
properties that are outside the
boundaries of those leases, unit PAs, or
CAs. Combining production from
multiple wells within a single lease,
unit PA, or CA, or combining
production downhole from different
geologic formations within the same
lease, unit PA, or CA, is not considered
commingling for production accounting
purposes.
Communitized area means the area
committed to a BLM approved
communitization agreement.
Communitization agreement (CA)
means an agreement to combine a lease
or a portion of a lease that cannot
otherwise be independently developed
and operated in conformity with an
established well spacing or well
development program, with other tracts
for purposes of cooperative
development and operations.
Condition of Approval (COA) means a
site-specific requirement included in
the approval of an application that may
limit or modify the specific actions
covered by the application. Conditions
of approval may minimize, mitigate, or
prevent impacts to public lands or
resources.
Days means consecutive calendar
days, unless otherwise indicated.
Facility means:
(i) A site and associated equipment
used to process, treat, store, or measure
production from or allocated to a
Federal or Indian lease, unit PA, or CA
that is located upstream of or at (and
including) the approved point of royalty
measurement; and
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(ii) A site and associated equipment
used to store, measure, or dispose of
produced water that is located on a
lease, unit, or communitized area.
Facility measurement point (FMP)
means a BLM-approved point where oil
or gas produced from a Federal or
Indian lease, unit PA, or CA is measured
and the measurement affects the
calculation of the volume or quality of
production on which royalty is owed.
FMP includes, but is not limited to, the
approved point of royalty measurement
and measurement points relevant to
determining the allocation of
production to Federal or Indian leases,
unit PAs, or CAs. However, allocation
facilities that are part of a commingling
and allocation approval under § 3173.15
or that are part of a commingling and
allocation approval approved after July
9, 2013, are not FMPs. An FMP also
includes a meter or measurement
facility used in the determination of the
volume or quality of royalty-bearing oil
or gas produced before BLM approval of
an FMP under § 3173.12. An FMP must
be located on the lease, unit, or
communitized area unless the BLM
approves measurement off the lease,
unit, or CA. The BLM will not approve
a gas processing plant tailgate meter
located off the lease, unit, or CA, as an
FMP.
Gas means any fluid, either
combustible or noncombustible,
hydrocarbon or non-hydrocarbon, that
has neither independent shape nor
volume, but tends to expand
indefinitely and exists in a gaseous state
under metered temperature and
pressure conditions.
Incident of Noncompliance (INC)
means documentation that the BLM
issues that identifies violations and
notifies the recipient of the notice of
required corrective actions.
Lease has the same meaning as
defined in 43 CFR 3160.0–5.
Lessee has the same meaning as
defined in 43 CFR 3160.0–5.
NIST traceable means an unbroken
and documented chain of comparisons
relating measurements from field or
laboratory instruments to a known
standard maintained by the National
Institute of Standards and Technology
(NIST).
Notice to lessees and operators (NTL)
has the same meaning as defined in 43
CFR 3160.0–5.
Off-lease measurement means
measurement at an FMP that is not
located on the lease, unit, or
communitized area from which the
production came.
Oil means a mixture of hydrocarbons
that exists in the liquid phase at the
temperature and pressure at which it is
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measured. Condensate is considered to
be oil for purposes of this part. Gas
liquids extracted from a gas stream
upstream of the approved point of
royalty measurement are considered to
be oil for purposes of this part.
(i) Clean oil or Pipeline oil means oil
that is of such quality that it is
acceptable to normal purchasers.
(ii) Slop oil means oil that is of such
quality that it is not acceptable to
normal purchasers and is usually sold to
oil reclaimers. Oil that can be made
acceptable to normal purchasers
through special treatment that can be
economically provided at existing or
modified facilities or using portable
equipment at or upstream of the FMP is
not slop oil.
(iii) Waste oil means oil that has been
determined by the AO or authorized
representative to be of such quality that
it cannot be treated economically and
put in a marketable condition with
existing or modified lease facilities or
portable equipment, cannot be sold to
reclaimers, and has been determined by
the AO to have no economic value.
Operator has the same meaning as
defined in 43 CFR 3160.0–5.
Participating area (PA) has the same
meaning as defined in 43 CFR 3180.0–
5.
Point of royalty measurement means a
BLM-approved FMP at which the
volume and quality of oil or gas which
is subject to royalty is measured. The
point of royalty measurement is to be
distinguished from meters that
determine only the allocation of
production to particular leases, unit
PAs, CAs, or non-Federal and nonIndian properties. The point of royalty
measurement is also known as the point
of royalty settlement.
Production means oil or gas removed
from a well bore and any products
derived therefrom.
Production Measurement Team (PMT)
means a panel of members from the
BLM (which may include BLMcontracted experts) that reviews changes
in industry measurement technology,
methods, and standards to determine
whether regulations should be updated,
and provides guidance on measurement
technologies and methods not addressed
in current regulation. The purpose of
the PMT is to act as a central advisory
body to ensure that oil and gas
produced from Federal and Indian
leases is accurately measured and
properly reported.
Purchaser means any person or entity
who legally takes ownership of oil or
gas in exchange for financial or other
consideration.
Source record means any unedited
and original record, document, or data
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that is used to determine volume and
quality of production, regardless of
format or how it was created or stored
(e.g., paper or electronic). It includes,
but is not limited to, raw and
unprocessed data (e.g., instantaneous
and continuous information used by
flow computers to calculate volumes);
gas charts; measurement tickets;
calibration, verification, prover, and
configuration reports; pumper and
gauger field logs; volume statements;
event logs; seal records; and gas
analyses.
Statistically significant describes a
difference between two data sets that
exceeds the threshold of significance.
Tampering means any deliberate
adjustment or alteration to a meter or
measurement device, appropriate valve,
or measurement process that could
introduce bias into the measurement or
affect the BLM’s ability to
independently verify volumes or
qualities reported.
Threshold of significance means the
maximum difference between two data
sets (a and b) that can be attributed to
uncertainty effects. The threshold of
significance is determined as follows:
Where:
Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of
data set a, in percent
Ub = Uncertainty (95 percent confidence) of
data set b, in percent
Total observed volume (TOV) means
the total measured volume of all oil,
sludges, sediment and water, and free
water at the measured or observed
temperature and pressure.
Transporter means any person or
entity who legally moves or transports
oil or gas from an FMP.
Uncertainty means the statistical
range of error that can be expected
between a measured value and the true
value of what is being measured.
Uncertainty is determined at a 95
percent confidence level for the
purposes of this part.
Unit means the land within a unit
area as defined in 43 CFR 3180.0–5.
Unit PA means the unit participating
area, if one is in effect, the exploratory
unit if there is no associated
participating area, or an enhanced
recovery unit.
Variance means an approved
alternative to a provision or standard of
a regulation, Onshore Oil and Gas
Order, or NTL.
(b) As used in this part, the following
additional acronyms apply:
API means American Petroleum
Institute.
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BLM means the Bureau of Land
Management.
Btu means British thermal unit.
CMS means Coriolis Measurement
System.
LACT means lease automatic custody
transfer.
OGOR means Oil and Gas Operations
Report (Form ONRR–4054 or any
successor report).
ONRR means the Office of Natural
Resources Revenue, U.S. Department of
the Interior, and includes any successor
agency.
S&W means sediment and water.
WIS means Well Information System
or any successor electronic filing
system.
§ 3170.4 Prohibitions against by-pass and
tampering.
(a) All by-passes are prohibited.
(b) Tampering with any measurement
device, component of a measurement
device, or measurement process is
prohibited.
(c) Any by-pass or tampering with a
measurement device, component of a
measurement device, or measurement
process may, together with any other
remedies provided by law, result in an
assessment of civil penalties for
knowingly or willfully:
(1) Taking, removing, transporting,
using, or diverting oil or gas from a lease
site without valid legal authority under
30 U.S.C. 1719(d)(2) and 43 CFR
3163.2(f)(2); or
(2) Preparing, maintaining, or
submitting false, inaccurate, or
misleading reports, records, or
information under 30 U.S.C. 1719(d)(1)
and 43 CFR 3163.2(f)(1).
§ 3170.5
[Reserved]
§ 3170.6
Variances.
(a) Any party subject to a requirement
of a regulation in this part may request
a variance from that requirement.
(1) A request for a variance must
include the following:
(i) Identification of the specific
requirement from which the variance is
requested;
(ii) Identification of the length of time
for which the variance is requested, if
applicable;
(iii) An explanation of the need for
the variance;
(iv) A detailed description of the
proposed alternative means of
compliance;
(v) A showing that the proposed
alternative means of compliance will
produce a result that meets or exceeds
the objectives of the applicable
requirement for which the variance is
requested; and
(vi) The FMP number(s) for which the
variance is requested, if applicable.
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(2) A request for a variance must be
submitted as a separate document from
any plans or applications. A request for
a variance that is submitted as part of a
master development plan, application
for permit to drill, right-of-way
application, or application for approval
of other types of operations, rather than
submitted separately, will not be
considered. Approval of a plan or
application that contains a request for a
variance does not constitute approval of
the variance. A separate request for a
variance may be submitted
simultaneously with a plan or
application. For plans or applications
that are contingent upon the approval of
the variance request, the BLM
encourages the simultaneous
submission of the variance request and
the plan or application.
(3) The party requesting the variance
must file the request and any supporting
documents using WIS. If electronic
filing is not possible or practical, the
operator may submit a request for
variance on the Form 3160–5, Sundry
Notices and Reports on Wells (Sundry
Notice) to the BLM Field Office having
jurisdiction over the lands described in
the application.
(4) The AO, after considering all
relevant factors, may approve the
variance, or approve it with COAs, only
if the AO determines that:
(i) The proposed alternative means of
compliance meets or exceeds the
objectives of the applicable
requirement(s) of the regulation;
(ii) Approving the variance will not
adversely affect royalty income and
production accountability; and
(iii) Issuing the variance is consistent
with maximum ultimate economic
recovery, as defined in 43 CFR 3160.0–
5.
(5) The decision whether to grant or
deny the variance request is entirely
within the BLM’s discretion.
(6) A variance from the requirements
of a regulation in this part does not
constitute a variance from provisions of
other regulations, including Onshore Oil
and Gas Orders.
(b) The BLM reserves the right to
rescind a variance or modify any COA
of a variance due to changes in Federal
law, technology, regulation, BLM
policy, field operations, noncompliance,
or other reasons. The BLM will provide
a written justification if it rescinds a
variance or modifies a COA.
§ 3170.7 Required recordkeeping, records
retention, and records submission.
(a) Lessees, operators, purchasers,
transporters, and any other person
directly involved in producing,
transporting, purchasing, selling, or
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measuring oil or gas through the point
of royalty measurement or the point of
first sale, whichever is later, must retain
all records, including source records,
that are relevant to determining the
quality, quantity, disposition, and
verification of production attributable to
Federal or Indian leases for the periods
prescribed in paragraphs (c) through (e)
of this section.
(b) This retention requirement applies
to records generated during or for the
period for which the lessee or operator
has an interest in or conducted
operations on the lease, or in which a
person is involved in transporting,
purchasing, or selling production from
the lease.
(c) For Federal leases, and units or
CAs that include Federal leases, but do
not include Indian leases, the record
holder must maintain records for:
(1) Seven years after the records are
generated; unless,
(2) A judicial proceeding or demand
involving such records is timely
commenced, in which case the record
holder must maintain such records until
the final nonappealable decision in such
judicial proceeding is made, or with
respect to that demand is rendered,
unless the Secretary or his/her designee
or the applicable delegated State
authorizes in writing an earlier release
of the requirement to maintain such
records.
(d) For Indian leases, and units or CAs
that include Indian leases, but do not
include Federal leases, the record
holder must maintain records for:
(1) Six years after the records are
generated; unless,
(2) The Secretary or his/her designee
notifies the record holder that the
Department of the Interior has initiated
or is participating in an audit or
investigation involving such records, in
which case the record holder must
maintain such records until the
Secretary or his/her designee releases
the record holder from the obligation to
maintain the records.
(e) For units and communitized areas
that include both Federal and Indian
leases, 6 years after the records are
generated. If the Secretary or his/her
designee has notified the record holder
within those 6 years that an audit or
investigation involving such records has
been initiated, then:
(1) If a judicial proceeding or demand
is commenced within 7 years after the
records are generated, the record holder
must retain all records regarding
production from the lease, unit PA, or
CA until the final nonappealable
decision in such judicial proceeding is
made, or with respect to that demand is
rendered, unless the Secretary or his/her
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designee authorizes in writing a release
of the requirement to maintain such
records before a final nonappealable
decision is made or rendered.
(2) If a judicial proceeding or demand
is not commenced within 7 years after
the records are generated, the record
holder must retain all records regarding
production from the unit or
communitized area until the Secretary
or his/her designee releases the record
holder from the obligation to maintain
the records;
(f) The lessee, operator, purchaser, or
transporter must maintain an audit trail.
(g) All records, including source
records, that are used to determine
quality, quantity, disposition, and
verification of production attributable to
a Federal or Indian lease, unit PA, or
CA, must include the FMP number or
the lease, unit PA, or CA number, along
with a unique equipment identifier (e.g.,
a unique tank identification number and
meter station number), and the name of
the company that created the record. For
all facilities existing prior to the
assignment of an FMP number, all
records must include the following
information:
(1) The name of the operator;
(2) The lease, unit PA, or CA number;
and
(3) The well or facility name and
number.
(h) Upon request of the AO, the
operator, purchaser, or transporter must
provide such records to the AO as may
be required by regulation, written order,
Onshore Order, NTL, or COA.
(i) All records must be legible.
(j) All records requiring a signature
must also have the signer’s printed
name.
§ 3170.8
Appeal procedures.
(a) BLM decisions, orders,
assessments, or other actions under the
regulations in this part are
administratively appealable under the
procedures prescribed in 43 CFR
3165.3(b), 3165.4, and part 4.
(b) For any recommendation made by
the PMT, and approved by the BLM, a
party affected by such recommendation
may file a request for discretionary
review by the Assistant Secretary for
Land and Minerals Management. The
Assistant Secretary may delegate this
review function as he or she deems
appropriate, in which case the affected
party’s application for discretionary
review must be made to the person or
persons to whom the Assistant
Secretary’s review function has been
delegated.
§ 3170.9
Enforcement.
Noncompliance with any of the
requirements of this part or any order
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issued under this part may result in
enforcement actions under 43 CFR
subpart 3163 or any other remedy
available under applicable law or
regulation.
Subpart 3171—[Reserved]
Subpart 3172—[Reserved]
Subpart 3173—Requirements for Site
Security and Production Handling
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§ 3173.1
Definitions and acronyms.
(a) As used in this subpart, the term:
Access means the ability to:
(i) Add liquids to or remove liquids
from any tank or piping system, through
a valve or combination of valves or by
moving liquids from one tank to another
tank; or
(ii) Enter any component in a
measuring system affecting the accuracy
of the measurement of the quality or
quantity of the liquid being measured.
Appropriate valves means those
valves that must be sealed during the
production or sales phase (e.g., fill lines,
equalizer, overflow lines, sales lines,
circulating lines, or drain lines).
Authorized representative (AR) has
the same meaning as defined in 43 CFR
3160.0–5.
Business day means any day Monday
through Friday, excluding Federal
holidays.
Commingling and allocation approval
(CAA) means a formal allocation
agreement to combine production from
two or more sources (leases, unit PAs,
CAs, or non-Federal or non-Indian
properties) before that product reaches
an FMP.
Economically marginal property
means a lease, unit PA, or CA that does
not generate sufficient revenue above
operating costs, such that a prudent
operator would opt to plug a well or
shut-in the lease, unit PA, or CA instead
of making the investments needed to
achieve non-commingled measurement
of production from that lease, unit PA,
or CA. A lease, unit PA, or CA may be
regarded as economically marginal if the
operator demonstrates that the expected
revenue (net any associated operating
costs) generated from crude oil or
natural gas production volumes on that
property is not sufficient to cover the
nominal cost of the capital expenditures
required to achieve measurement of
non-commingled production of oil or
gas from that property over a payout
period of 18 months. A lease, unit PA,
or CA can also be considered
economically marginal if the operator
demonstrates that its royalty net present
value (RNPV), or the discounted value
of the Federal or Indian royalties
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collected on revenue earned from crude
oil or natural gas production on the
lease, unit PA, or CA, over the expected
life of the equipment that would need
to be installed to achieve noncommingled measurement volumes, is
less than the capital cost of purchasing
and installing this equipment. Both the
payout period and the RNPV are
determined separately for each lease,
unit PA, or CA oil or gas FMP.
Additionally, oil FMPs are evaluated
using estimated revenue (net of taxes
and operating costs) from crude oil
production, as defined in this section,
while gas FMPs are evaluated using
estimated revenue (net of taxes and
operating costs) from natural gas
production, as defined in this section.
Effectively sealed means the
placement of a seal in such a manner
that the sealed component cannot be
accessed, moved, or altered without
breaking the seal.
Free water means the measured
volume of water that is present in a
container and that is not in suspension
in the contained liquid at observed
temperature.
Land description means a location
surveyed in accordance with the U.S.
Department of the Interior’s Manual of
Surveying Instructions (2009), that
includes the quarter-quarter section,
section, township, range, and principal
meridian, or other authorized survey
designation acceptable to the AO, such
as metes-and-bounds, or latitude and
longitude.
Maximum ultimate economic
recovery has the same meaning as
defined in 43 CFR 3160.0–5.
Mishandling means failing to measure
or account for removal of production
from a facility.
Payout period means the time
required, in months, for the cost of an
investment in an oil or gas FMP for a
specific lease, unit PA, or CA to be
covered by the nominal revenue earned
from crude oil production, for an oil
FMP, or natural gas production, for a gas
FMP, minus taxes, royalties, and any
operating and variable costs. The payout
period is determined separately for each
oil or gas FMP for a given lease, unit PA,
or CA.
Permanent measurement facility
means all equipment constructed or
installed and used on-site for 6 months
or longer, for the purpose of
determining the quantity, quality, or
storage of production, and which meets
the definition of FMP under § 3170.3.
Piping means a tubular system (e.g.,
metallic, plastic, fiberglass, or rubber)
used to move fluids (liquids and gases).
Production phase means that event
during which oil is delivered directly to
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81425
or through production equipment to the
storage facilities and includes all
operations at the facility other than
those defined by the sales phase.
Royalty Net Present Value (RNPV)
means the net present value of all
Federal or Indian royalties paid on
revenue earned from crude oil
production or natural gas production
from an oil or gas FMP for a given lease,
unit PA, or CA over the expected life of
metering equipment that must be
installed for that lease, unit PA, or CA
to achieve non-commingled
measurement.
Sales phase means that event during
which oil is removed from storage
facilities for sale at an FMP.
Seal means a uniquely numbered
device that completely secures either a
valve or those components of a
measuring system that affect the quality
or quantity of the oil being measured.
(b) As used in this subpart, the
following additional acronyms apply:
BIA means the Bureau of Indian
Affairs.
BMP means Best Management
Practice.
§ 3173.2
seals.
Storage and sales facilities—
(a) All lines entering or leaving any
oil storage tank must have valves
capable of being effectively sealed
during the production and sales phases
unless otherwise provided under this
subpart. During the production phase,
all appropriate valves that allow
unmeasured production to be removed
from storage must be effectively sealed
in the closed position. During any other
phase (sales, water drain, or hot oiling),
and prior to taking the top tank gauge
measurement, all appropriate valves
that allow unmeasured production to
enter or leave the sales tank must be
effectively sealed in the closed position
(see Appendix A to subpart 3173). Each
unsealed or ineffectively sealed
appropriate valve is a separate violation.
(b) Valves or combinations of valves
and tanks that provide access to the
production before it is measured for
sales are considered appropriate valves
and are subject to the seal requirements
of this subpart (see Appendix A to
subpart 3173). If there is more than one
valve on a line from a tank, the valve
closest to the tank must be sealed. All
appropriate valves must be in an
operable condition and accurately
reflect whether the valve is open or
closed.
(c) The following are not considered
appropriate valves and are not subject to
the sealing requirements of this subpart:
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(1) Valves on production equipment
(e.g., separator, dehydrator, gun barrel,
or wash tank);
(2) Valves on water tanks, provided
that the possibility of access to
production in the sales and storage
tanks does not exist through a common
circulating, drain, overflow, or equalizer
system;
(3) Valves on tanks that contain oil
that has been determined by the AO or
AR to be waste or slop oil;
(4) Sample cock valves used on piping
or tanks with a Nominal Pipe Size of 1
inch or less in diameter;
(5) Fill-line valves during shipment
when a single tank with a nominal
capacity of 500 barrels (bbl) or less is
used for collecting marginal production
of oil produced from a single well (i.e.,
production that is less than 3 bbl per
day). All other seal requirements of this
subpart apply;
(6) Gas line valves used on piping
with a Nominal Pipe Size of 1 inch or
less used as tank bottom ‘‘roll’’ lines,
provided there is no access to the
contents of the storage tank and the roll
lines cannot be used as equalizer lines;
(7) Valves on tank heating systems
that use a fluid other than the contents
of the storage tank (i.e., steam, water, or
glycol);
(8) Valves used on piping with a
Nominal Pipe Size of 1 inch or less
connected directly to the pump body or
used on pump bleed off lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves
on systems where production may be
removed only through approved oil
metering systems (e.g., LACT or CMS).
However, any valve that allows access
for removing oil before it is measured
through the metering system must be
effectively sealed (see Appendix A to
subpart 3173).
(d) Tampering with any appropriate
valve is prohibited. Tampering with an
appropriate valve may result in an
assessment of civil penalties for
knowingly or willfully preparing,
maintaining, or submitting false,
inaccurate, or misleading reports,
records, or written information under 30
U.S.C. 1719(d)(1) and 43 CFR
3163.2(f)(1), or knowingly or willfully
taking, removing, transporting, using, or
diverting oil or gas from a lease site
without valid legal authority under 30
U.S.C. 1719(d)(2) and 43 CFR
3163.2(f)(2), together with any other
remedies provided by law.
§ 3173.3 Oil measurement system
components—seals.
(a) Components used for quantity or
quality determination of oil must be
effectively sealed to indicate tampering,
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including, but not limited to, the
following components of LACT meters
(see § 3174.8(a)) and CMSs (see
§ 3174.9(e)):
(1) Sample probe;
(2) Sampler volume control;
(3) All valves on lines entering or
leaving the sample container, excluding
the safety pop-off valve (if so equipped).
Each valve must be sealed in the open
or closed position, as appropriate;
(4) Meter assembly, including the
counter head and meter head;
(5) Temperature averager;
(6) LACT meters or CMS;
(7) Back pressure valve pressure
adjustment downstream of the meter;
(8) Any drain valves in the system;
(9) Manual-sampling valves (if so
equipped);
(10) Valves on diverter lines larger
than 1 inch in nominal diameter;
(11) Right-angle drive;
(12) Totalizer; and
(13) Prover connections.
(b) Each missing or ineffectively
sealed component is a separate
violation.
§ 3173.4
Federal seals.
(a) In addition to any INC issued for
a seal violation, the AO or AR may place
one or more Federal seals on any
appropriate valve, sealing device, or oilmetering-system component that does
not comply with the requirements in
§§ 3173.2 and 3173.3 if the operator is
not present, refuses to cooperate with
the AO or AR, or is unable to correct the
noncompliance.
(b) The placement of a Federal seal
does not constitute compliance with the
requirements of §§ 3173.2 and 3173.3.
(c) A Federal seal may not be removed
without the approval of the AO or AR.
§ 3173.5 Removing production from tanks
for sale and transportation by truck.
(a) When a single truck load
constitutes a completed sale, the driver
must possess documentation containing
the information required in § 3174.12.
(b) When multiple truckloads are
involved in a sale and the oil
measurement method is based on the
difference between the opening and
closing gauges, the driver of the last
truck must possess the documentation
containing the information required in
§ 3174.12. All other drivers involved in
the sale must possess a trip log or
manifest.
(c) After the seals have been broken,
the purchaser or transporter is
responsible for the entire contents of the
tank until it is resealed.
§ 3173.6
Water-draining operations.
When water is drained from a
production storage tank, the operator,
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Fmt 4701
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purchaser, or transporter, as
appropriate, must document the
following information:
(a) Federal or Indian lease, unit PA, or
CA number(s);
(b) The tank location by land
description;
(c) The unique tank number and
nominal capacity;
(d) Date of the opening gauge;
(e) Opening gauge (gauged manually
or automatically), TOV, and free-water
measurements, all to the nearest 1⁄2 inch;
(f) Unique identifying number of each
seal removed;
(g) Closing gauge (gauged manually or
automatically) and TOV measurement to
the nearest 1⁄2 inch; and
(h) Unique identifying number of each
seal installed.
§ 3173.7 Hot oiling, clean-up, and
completion operations.
(a) During hot oil, clean-up, or
completion operations, or any other
situation where the operator removes oil
from storage, temporarily uses it for
operational purposes, and then returns
it to storage on the same lease, unit PA,
or communitized area, the operator
must document the following
information:
(1) Federal or Indian lease, unit PA,
or CA number(s);
(2) Tank location by land description;
(3) Unique tank number and nominal
capacity;
(4) Date of the opening gauge;
(5) Opening gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(6) Unique identifying number of each
seal removed;
(7) Closing gauge measurement
(gauged manually or automatically) to
the nearest 1⁄2 inch;
(8) Unique identifying number of each
seal installed;
(9) How the oil was used; and
(10) Where the oil was used (i.e., well
or facility name and number).
(b) During hot oiling, line flushing, or
completion operations or any other
situation where the operator removes
production from storage for use on a
different lease, unit PA, or
communtized area, the production is
considered sold and must be measured
in accordance with the applicable
requirements of this subpart and
reported as sold to ONRR on the OGOR
under 30 CFR part 1210 subpart C for
the period covering the production in
question.
§ 3173.8 Report of theft or mishandling of
production.
(a) No later than the next business day
after discovery of an incident of
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apparent theft or mishandling of
production, the operator, purchaser, or
transporter must report the incident to
the AO. All oral reports must be
followed up with a written incident
report within 10 business days of the
oral report.
(b) The incident report must include
the following information:
(1) Company name and name of the
person reporting the incident;
(2) Lease, unit PA, or CA number,
well or facility name and number, and
FMP number, as appropriate;
(3) Land description of the facility
location where the incident occurred;
(4) The estimated volume of
production removed;
(5) The manner in which access was
obtained to the production or how the
mishandling occurred;
(6) The name of the person who
discovered the incident;
(7) The date and time of the discovery
of the incident; and
(8) Whether the incident was reported
to local law enforcement agencies and/
or company security.
is 150 bbl, the gross sales volume
between the first and second inventory
is 198 bbl, and February is the calendar
month for which the report is due. For
purposes of this example, we assume
February had 28 days and that the well
was non-producing for two of those
days.
{[(150 bbl + 198 bbl ¥ 125 bbl)/29 days]
* 16 days} + 150 bbl = 273 bbl for
the February end-of-month
inventory.
(b) For each seal, the operator must
maintain a record that includes:
(1) The unique identifying number of
each seal and the valve or meter
component on which the seal is or was
used;
(2) The date of installation or removal
of each seal;
(3) For valves, the position (open or
closed) in which it was sealed; and
(4) The reason the seal was removed.
§ 3173.10 Form 3160–5, Sundry Notices
and Reports on Wells.
mstockstill on DSK3G9T082PROD with RULES3
(a) The operator must submit a Form
3160–5, Sundry Notices and Reports on
Wells (Sundry Notice) for the following:
§ 3173.9 Required recordkeeping for
(1) Site facility diagrams (see
inventory and seal records.
§ 3173.11);
(a) The operator must perform an end(2) Request for an FMP number (see
of-month inventory (gauged manually or § 3173.12);
automatically) that records: TOV in
(3) Request for FMP amendments (see
storage (measured to the nearest 1⁄2 inch) § 3173.13(b));
subtracting free water, the volume not
(4) Requests for approval of off-lease
corrected for temperature/S&W, and the measurement (see § 3173.23);
volume as reported to ONRR on the
(5) Request to amend an approval of
OGOR;
off-lease measurement (see
(1) The end-of-month inventory must
§ 3173.23(k));
be completed within +/¥ 3 days of the
(6) Requests for approval of CAAs (see
last day of the calendar month; or
§ 3173.15); and
(2) The end of month inventory must
(7) Request to modify a CAA (see
be a calculated ‘‘end of month’’
§ 3173.18).
inventory based on daily production
(b) The operator must submit all
that takes place between two measured
Sundry Notices electronically to the
inventories that are not more than 31,
BLM office having jurisdiction over the
nor fewer than 20, days apart. The
lease, unit, or CA using WIS, unless the
calculated monthly inventory is
submitter:
determined based on the following
(1) Is a small business, as defined by
equation:
the U.S. Small Business Administration;
and
{[(X + Y ¥ W)/Z1] * Z2} + X = A,
(2) Does not have access to the
Where:
Internet.
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and
second inventory;
Z1 = number of actual days produced
between the first and second inventory;
and
Z2 = number of actual days produced
between the second inventory and end of
calendar month for which the OGOR
report is due.
For example: If the first inventory
measurement performed on January 12
is 125 bbl, the second inventory
measurement performed on February 10
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§ 3173.11
Site facility diagram.
(a) A site facility diagram is required
for all facilities.
(b) Except for the requirement to
submit a Form 3160–5, Sundry Notice,
with the site facility diagram, no format
is prescribed for site facility diagrams.
The diagram should be formatted to fit
on an 81⁄2 x 11 sheet of paper, if
possible, and must be legible and
comprehensible to an individual with
an ordinary working knowledge of oil
field operations (see Appendix A to
subpart 3173). If more than one page is
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81427
required, each page must be numbered
(in the format ‘‘N of X pages’’).
(c) The diagram must:
(1) Reflect the position of the
production and water recovery
equipment, piping for oil, gas, and
water, and metering or other measuring
systems in relation to each other, but
need not be to scale;
(2) Commencing with the header,
identify all of the equipment, including,
but not limited to, the header, wellhead,
piping, tanks, and metering systems
located on the site, and include the
appropriate valves and any other
equipment used in the handling,
conditioning, or disposal of production
and water, and indicate the direction of
flow;
(3) Identify by API number the wells
flowing into headers;
(4) If another operator operates a colocated facility, depict the co-located
facility(ies) on the diagram or list them
as an attachment and identify them by
company name, facility name(s), lease,
unit PA, or CA number(s), and FMP
number(s);
(5) Indicate which valve(s) must be
sealed and in what position during the
production and sales phases and during
the conduct of other production
activities (e.g., circulating tanks or
drawing off water), which may be
shown by an attachment, if necessary;
(6) When describing co-located
facilities operated by one operator,
include a skeleton diagram of the colocated facility(ies), showing equipment
only. For storage facilities common to
co-located facilities operated by one
operator, one diagram is sufficient;
(7) Clearly identify the lease, unit PA,
or CA to which the diagram applies, the
land description of the facility, and the
name of the company submitting the
diagram, with co-located facilities being
identified for each lease, unit PA, or CA;
(8) Clearly identify, on the diagram or
as an attachment, all meters and
measurement equipment. Specifically
identify all approved and assigned
FMPs; and
(9) If the operator claims royalty-free
use, clearly identify the equipment for
which the operator claims royalty-free
use. The operator must either:
(i) For each engine, motor, or major
component (e.g., compressor, separator,
dehydrator, heater-treater, or tank
heater) powered by production from the
lease, unit PA, or CA, state the volume
(oil or gas) consumed (per day or per
month) and how the volume is
determined; or
(ii) Measure the volume used, by
meter or tank gauge.
(d) At facilities for which the BLM
will assign an FMP number under
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§ 3173.12, the operator must submit a
new site facility diagram as follows:
(1) For facilities that become
operational after January 17, 2017,
within 30 days after the BLM assigns an
FMP; or
(2) For a facility that is in service on
or before January 17, 2017, and that has
a site facility diagram on file with the
BLM that meets the minimum
requirements of Onshore Oil and Gas
Order 3, Site Security, an amended site
facility diagram meeting the
requirements of this section is not due
until 30 days after the existing facility
is modified, a non-Federal facility
located on a Federal lease or federally
approved unit or communitized area is
constructed or modified, or there is a
change in operator.
(e) At facilities for which an FMP
number is not required under § 3173.12
(e.g., facilities that dispose of produced
water), the operator must submit a new
site facility diagram as follows:
(1) For new facilities in service after
January 17, 2017, the new site facility
diagram must be submitted within 30
days after the facility becomes
operational; or
(2) For a facility that is in service on
or before January 17, 2017, and that has
a site facility diagram on file with the
BLM that meets the minimum
requirements of Onshore Oil and Gas
Order 3, Site Security, an amended site
facility diagram meeting the
requirements of this section is not due
until 30 days after the existing facility
is modified, a non-Federal facility
located on a Federal lease or federally
approved unit or communitized area is
constructed or modified, or there is a
change in operator.
(f) After a site facility diagram has
been submitted that complies with the
requirements of this part, the operator
has an ongoing obligation to update and
amend the diagram within 30 days after
such facility is modified, a non-Federal
facility located on a Federal lease or
federally approved unit or
communitized area is constructed or
modified, or there is a change in
operator.
mstockstill on DSK3G9T082PROD with RULES3
§ 3173.12 Applying for a facility
measurement point.
(a)(1) Unless otherwise approved, the
FMP(s) for all Federal and Indian leases,
unit PAs, or CAs must be located within
the boundaries of the lease, unit, or
communitized area from which the
production originated and must
measure only production from that
lease, unit PA, or CA.
(2) Off-lease measurement or
commingling and allocation of Federal
or Indian production requires prior
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approval (see 43 CFR 3162.7–2, 3162.7–
3, 3173.15, 3173.16, 3173.24, and
3173.25).
(b) The BLM will not approve as an
FMP a gas processing plant tailgate
meter located off the lease, unit, or
communitized area.
(c) The operator must submit separate
applications for approval of an FMP that
measures oil produced from a lease, unit
PA, or CA, or under a CAA that
complies with the requirements of this
subpart, and an FMP that measures gas
produced from the same lease, unit PA,
or CA, or under a CAA that complies
with the requirements of this subpart.
This requirement applies even if the
measurement equipment or facilities are
at the same location.
(d) For a permanent measurement
facility that comes into service after
January 17, 2017, the operator must
apply for approval of the FMP before
any production leaves the permanent
measurement facility. This requirement
does not apply to temporary
measurement equipment used during
well testing operations. After timely
submission and prior to approval of an
FMP request, an operator must use the
lease, unit PA, or CA number for
reporting production to ONRR, until the
BLM assigns an FMP number, at which
point the operator must use the FMP
number for all reporting to ONRR as set
forth in § 3173.13.
(e) For a permanent measurement
facility in service on or before January
17, 2017, the operator must apply for
BLM approval of an FMP within the
time prescribed in this paragraph, based
on the production level of any one of
the leases, unit PAs, or CAs, whether or
not they are part of a CAA. The deadline
to apply for an FMP approval applies to
both oil and gas measurement facilities
measuring production from that lease,
unit PA, or CA.
(1) For a stand-alone lease, unit PA,
or CA that produced 10,000 Mcf or more
of gas per month or 100 bbl or more of
oil per month, by January 17, 2018.
(2) For a stand-alone lease, unit PA,
or CA that produced 1,500 Mcf or more,
but less than 10,000 Mcf of gas per
month, or 10 bbl or more, but less than
100 bbl of oil per month, by January 17,
2019.
(3) For a stand-alone lease, unit PA,
or CA that produced less than 1,500 Mcf
of gas per month or less than 10 bbl of
oil per month, January 17, 2020.
(4) For a stand-alone lease, unit PA,
or CA that has not produced for a year
or more before January 17, 2017, the
operator must apply for an FMP prior to
the resumption of production.
(5) The production levels identified in
paragraphs (e)(1) through (3) of this
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section should be calculated using the
average production of oil or gas over the
12 months preceding the effective date
of this section or over the period the
lease, unit PA, or CA has been in
production, whichever is shorter.
(6) If the operator of any facility
covered by this section applies for an
FMP approval by the deadline in this
paragraph, the operator may continue
using the lease, unit PA, or CA number
for reporting production to ONRR, until
the BLM’s assigns an FMP number, at
which point the operator must use the
FMP number for all reporting to ONRR
as set forth in § 3173.13.
(7) If the operator fails to apply for an
FMP approval by the deadline in this
paragraph, the operator will be subject
to an INC and may also be subject to an
assessment of a civil penalty under 43
CFR part 3160, subpart 3163, together
with any other remedy available under
applicable law or regulation.
(f) All requests for FMP approval must
include the following:
(1) A complete Sundry Notice
requesting approval of each FMP;
(2) The applicable Measurement Type
Code specified in WIS;
(3) Information about the equipment
used for oil and gas measurement,
including, for:
(i) ‘‘Gas measurement,’’ specify
operator/purchaser/transporter unique
station number, primary element (meter
tube) size or serial number, and type of
secondary device (mechanical or
electronic);
(ii) ‘‘Oil measurement by tank gauge,’’
specify oil tank number or tank serial
number and size in barrels or gallons for
all tanks associated with measurement
at an FMP; and
(iii) ‘‘Oil measurement by LACT or
CMS,’’ specify whether the equipment is
LACT or CMS and the associated oil
tank number or tank serial number and
size in barrels or gallons (there may be
more than one tank associated with an
FMP);
(4) Where production from more than
one well will flow to the requested
FMP, list the API well numbers
associated with the FMP; and
(5) FMP location by land description.
(g) Request for approval of an FMP
may be submitted concurrently with
separate requests for off-lease
measurement and/or CAA.
§ 3173.13 Requirements for approved
facility measurement points.
(a) For an existing facility in service
on or before January 17, 2017, an
operator must start using an FMP
number for reporting production to
ONRR on its OGOR for the fourth
production month after the BLM assigns
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the FMP number(s), and every month
thereafter. (For example, for a facility
that is assigned an FMP number on
January 15, 2016, the effective date of
the FMP is the May production report.)
For a new facility in service after
January 17, 2017, an operator must start
using an FMP number for reporting
production to ONRR on its OGOR for
the first production month after the
BLM assigns the FMP number(s), and
every month thereafter. (For example,
for a facility that is assigned an FMP
number on January 15, 2016, the
effective date of the FMP is the February
production report.)
(b)(1) The operator must file a Sundry
Notice that describes any changes or
modifications made to the FMP within
30 days after the change. This
requirement does not apply to
temporary modifications (e.g., for
maintenance purposes). These include
any changes and modifications to the
information listed on an application
submitted under § 3173.12.
(2) The description must include
details such as the primary element,
secondary element, LACT/CMS meter,
tank number(s), and wells or facilities
using the FMP.
(3) The Sundry Notice must specify
what was changed and the effective
date, and include, if appropriate, an
amended site facility diagram (see
§ 3173.11).
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§ 3173.14 Conditions for commingling and
allocation approval (surface and downhole).
(a) Subject to the exceptions provided
in paragraph (b) of this section, the BLM
may grant a CAA only if the proposed
allocation method used for any such
commingled measurement does not
have the potential to affect the
determination of the total volume or
quality of production on which royalty
owed is determined for all the Federal
or Indian leases, unit PAs, or CAs which
are proposed for commingling, and only
if the following criteria are met:
(1) The proposed commingling
includes production from more than
one:
(i) Federal lease, unit PA, or CA,
where each lease, unit PA, or CA
proposed for commingling has 100
percent Federal mineral interest, the
same fixed royalty rate and, and the
same revenue distribution;
(ii) Indian tribal lease, unit PA, or CA,
where each lease, unit PA, or CA
proposed for commingling is wholly
owned by the same tribe and has the
same fixed royalty rate;
(iii) Federal unit PA or CA where each
unit PA or CA proposed for
commingling has the same proportion of
Federal interest, and which interest is
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subject to the same fixed royalty rate
and revenue distribution. (For example,
the BLM could approve a commingling
request under this paragraph where an
operator proposes to commingle two
Federal CAs of mixed ownership and
both CAs are 50 percent Federal/50
percent private, so long as the Federal
interests have the same royalty rates and
royalty distributions.); or
(iv) Indian unit PA or CA where each
unit PA or CA proposed for
commingling has the same proportion of
Indian interests, and which interest is
held by the same tribe and has the same
fixed royalty rate; and
(2) The operator or operators provide
a methodology acceptable to BLM for
allocation among the properties from
which production is to be commingled
(including a method for allocating
produced water), with a signed
agreement if there is more than one
operator;
(3) For each of the leases, unit PAs, or
CAs proposed for inclusion in the CAA,
the applicant demonstrates to the AO
that a lease, unit PA, or CA proposed for
inclusion is producing in paying
quantities (or, in the case of Federal
leases, capable of production in paying
quantities) pending approval of the
CAA; and
(4) The FMP(s) for the proposed CAA
measure production originating only
from the leases, unit PAs, or CAs in the
CAA.
(b) The BLM may also approve a CAA
in instances where the proposed
commingling of production involves
production from Federal or Indian
leases, unit PAs, or CAs that do not
meet the criteria of paragraph (a)(1) of
this section (e.g., the commingling of
leases, unit PAs, or CAs with different
royalty rates or different distributions of
revenue, or where the commingling
involves multiple mineral ownerships).
In order to be approved, a CAA under
this subparagraph must meet the
requirements of paragraphs (a)(2)
through (4) of this section and at least
one of the following conditions:
(1) The Federal or Indian lease, unit
PA, or CA meets the definition of an
economically marginal property.
However, if the BLM determines that a
Federal or Indian lease, unit PA, or CA
included in a CAA ceases to be an
economically marginal property, then
this condition is no longer met;
(2) The average monthly production
over the preceding 12 months for each
Federal or Indian lease, unit PA, or CA
proposed for the CAA on an individual
basis is less than 1,000 Mcf of gas per
month, or 100 bbl of oil per month;
(3) A CAA that includes Indian leases,
unit PAs, or CAs has been authorized
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81429
under tribal law or otherwise approved
by a tribe;
(4) The CAA covers the downhole
commingling of production from
multiple formations that are covered by
separate leases, unit PAs, or CAs, where
the BLM has determined that the
proposed commingling from those
formations is an acceptable practice for
the purpose of achieving maximum
ultimate economic recovery and
resource conservation; or
(5) There are overriding
considerations that indicate the BLM
should approve a commingling
application in the public interest
notwithstanding potential negative
royalty impacts from the allocation
method. Such considerations could
include topographic or other
environmental considerations that make
non-commingled measurement
physically impractical or undesirable, in
view of where additional measurement
and related equipment necessary to
achieve non-commingled measurement
would have to be located.
§ 3173.15 Applying for a commingling and
allocation approval.
To apply for a CAA, the operator(s)
must submit the following, if applicable,
to the BLM office having jurisdiction
over the leases, unit PAs, or CAs from
which production is proposed to be
commingled:
(a) A completed Sundry Notice for
approval of commingling and allocation
(if off-lease measurement is a feature of
the commingling and allocation
proposal, then a separate Sundry Notice
under § 3173.23 is not necessary as long
as the information required under
§ 3173.23(b) through (e) and, where
applicable, § 3173.23(f) through (i) is
included as part of the request for
approval of commingling and
allocation);
(b) A completed Sundry Notice for
approval of off-lease measurement
under § 3173.23, if any of the proposed
FMPs are outside the boundaries of any
of the leases, units, or CAs from which
production would be commingled
(which may be included in the same
Sundry Notice as the request for
approval of commingling and
allocation), except as provided in
paragraph (a) of this section;
(c) A proposed allocation agreement,
including an allocation methodology
(including allocation of produced
water), with an example of how the
methodology is applied, signed by each
operator of each of the leases, unit PAs,
or CAs from which production would be
included in the CAA;
(d) A list of all Federal or Indian
lease, unit PA, or CA numbers in the
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proposed CAA, specifying the type of
production (i.e., oil, gas, or both) for
which commingling is requested;
(e) A topographic map or maps of
appropriate scale showing the
following:
(1) The boundaries of all the leases,
units, unit PAs, or communitized areas
whose production is proposed to be
commingled; and
(2) The location of existing or planned
facilities and the relative location of all
wellheads (including the API number)
and piping included in the CAA, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
(f) A surface use plan of operations
(which may be included in the same
Sundry Notice as the request for
approval of commingling and
allocation) if new surface disturbance is
proposed for the FMP and its associated
facilities are located on BLM-managed
land within the boundaries of the lease,
units, and communitized areas from
which production would be
commingled;
(g) A right-of-way grant application
(Standard Form 299), filed under 43
CFR part 2880, if the proposed FMP is
on a pipeline, or under 43 CFR part
2800, if the proposed FMP is a meter or
storage tank. This requirement applies
only when new surface disturbance is
proposed for the FMP, and its associated
facilities are located on BLM-managed
land outside any of the leases, units, or
communitized areas whose production
would be commingled;
(h) Written approval from the
appropriate surface-management
agency, if new surface disturbance is
proposed for the FMP and its associated
facilities are located on Federal land
managed by an agency other than the
BLM;
(i) A right-of-way grant application for
the proposed FMP, filed under 25 CFR
part 169, with the appropriate BIA
office, if any of the proposed surface
facilities are on Indian land outside the
lease, unit, or communitized area from
which the production would be
commingled;
(j) Documentation demonstrating that
each of the leases, unit PAs, or CAs
proposed for inclusion in the CAA is
producing in paying quantities (or, in
the case of Federal leases, is capable of
production in paying quantities)
pending approval of the CAA; and
(k) All gas analyses, including Btu
content (if the CAA request includes
gas) and all oil gravities (if the CAA
request includes oil) for previous
periods of production from the leases,
units, unit PAs, or communitized areas
proposed for inclusion in the CAA, up
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to 6 years before the date of the
application for approval of the CAA.
Gas analysis and oil gravity data is not
needed if the CAA falls under
§ 3173.14(a)(1).
§ 3173.16 Existing commingling and
allocation approvals.
Upon receipt of an operator’s request
for assignment of an FMP number to a
facility associated with a CAA existing
on January 17, 2017, the AO will review
the existing CAA and take the following
action:
(a) The AO will grandfather the
existing CAA and associated off-lease
measurement, where applicable, if the
existing CAA meets one of the following
conditions:
(1) The existing CAA involves
downhole commingling that includes
Federal or Indian leases, unit PAs, or
CAs; or
(2) The existing CAA is for surface
commingling and the average
production rate over the previous 12
months for each Federal or Indian lease,
unit PA, and CA included in the CAA
is:
(i) Less than 1,000 Mcf per month for
gas; or
(ii) Less than 100 bbl per month for
oil.
(b) If the existing CAA does not meet
the conditions of paragraphs (a)(1) or
(a)(2) of this section, the AO will review
the CAA for consistency with the
minimum standards and requirements
for a CAA under § 3173.14.
(1) The AO will notify the operator in
writing of any inconsistencies or
deficiencies with an existing CAA. The
operator must correct any
inconsistencies or deficiencies that the
AO identifies, provide the additional
information that the AO has requested,
or request an extension of time from the
AO, within 20 business days after
receipt of the AO’s notice. When the AO
is satisfied that the operator has
corrected any inconsistencies or
deficiencies, the AO will terminate the
existing CAA and grant a new CAA
based on the operator’s corrections.
(2) The AO may terminate the existing
CAA and grant a new CAA with new or
amended COAs to make the approval
consistent with the requirements under
§ 3173.14 in connection with approving
the requested FMP. If the operator
appeals any COAs of the new CAA, the
existing CAA approval will continue in
effect during the pendency of the
appeal.
(3) If the existing CAA does not meet
the standards and requirements of
§ 3173.14 and the operator does not
correct the deficiencies, the AO may
terminate the existing CAA under
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§ 3173.20 and deny the request for an
FMP number for the facility associated
with the existing CAA.
(c) If the AO grants a new CAA to
replace an existing CAA under
paragraph (b) of this section, the new
CAA is effective on the first day of the
month following its approval. Any new
allocation percentages resulting from
the new CAA will apply from the
effective date of the CAA forward.
§ 3173.17 Relationship of a commingling
and allocation approval to royalty-free use
of production.
A CAA does not constitute approval
of off-lease royalty-free use of
production as fuel in facilities located at
an FMP approved under the CAA.
§ 3173.18 Modification of a commingling
and allocation approval.
(a) A CAA must be modified when
there is:
(1) A modification to the allocation
agreement;
(2) Inclusion of additional leases, unit
PAs, or CAs are proposed in the CAA;
or
(3) Termination of or permanent
production cessation from any of the
leases, unit PAs, or CAs within the
CAA.
(b) To request a modification of a
CAA, all operators must submit to the
AO:
(1) A completed Sundry Notice
describing the modification requested;
(2) A new allocation methodology,
including an allocation methodology
which includes allocation of produced
water and an example of how the
methodology is applied, if appropriate;
and
(3) Certification by each operator in
the CAA that it agrees to the CAA
modification.
(c) A change in operator does not
trigger the need to modify a CAA.
§ 3173.19 Effective date of a commingling
and allocation approval.
(a) If the BLM approves a CAA, the
effective date of the CAA is the first day
of the month following first production
through the FMPs for the CAA.
(b) If the BLM approves a
modification, the effective date is the
first day of the month following
approval of the modification.
(c) A CAA does not modify any of the
terms of the leases, units, or CAs
covered by the CAA.
§ 3173.20 Terminating a commingling and
allocation approval.
(a) The AO may terminate a CAA for
any reason, including, but not limited
to, the following:
(1) Changes in technology, regulation,
or BLM policy;
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(2) Operator non-compliance with the
terms or COAs of the CAA or this
subpart; or
(3) The AO determines that a lease,
unit, or CA subject to the CAA has
terminated, or a unit PA subject to the
CAA has ceased production.
(b) If only one lease, unit PA, or CA
remains subject to the CAA, the CAA
terminates automatically.
(c) An operator may terminate its
participation in a CAA by submitting a
Sundry Notice to the BLM. The Sundry
Notice must identify the FMP(s) for the
lease(s), unit PA(s), or CA(s) previously
subject to the CAA. Termination by one
operator does not mean the CAA
terminates as to all other participating
operators, so long as one of the other
provisions of this subpart is met and the
remaining operators submit a Sundry
Notice requesting a new CAA as
outlined in paragraph (e) of this section.
(d) The AO will notify in writing all
operators who are a party to the CAA of
the effective date of the termination and
any inconsistencies or deficiencies with
their CAA approval that serve as the
reason(s) for termination. The operator
must correct any inconsistencies or
deficiencies that the AO identifies,
provide the additional information that
the AO has requested, or request an
extension of time from the AO, within
20 business days after receipt of the
BLM’s notice, or the CAA is terminated.
(e) If a CAA is terminated, each lease,
unit PA, or CA that was included in the
CAA may require a new FMP number(s)
or a new CAA. Operators will have 30
days to apply for a new FMP number
(§ 3173.12) or CAA (§ 3173.15), if
applicable. The existing FMP number
may be used for production reporting
until a new FMP number is assigned or
CAA is approved.
mstockstill on DSK3G9T082PROD with RULES3
§ 3173.21 Combining production downhole
in certain circumstances.
(a)(1) Combining production from a
single well drilled into different
hydrocarbon pools or geologic
formations (e.g., a directional well)
underlying separate adjacent properties
(whether Federal, Indian, State, or
private), where none of the hydrocarbon
pools or geologic formations underlie or
are common to more than one of the
respective properties, constitutes
commingling for purposes of §§ 3173.14
through 3173.20.
(2) If any of the hydrocarbon pools or
geologic formations underlie or are
common to more than one of the
properties, the operator must establish a
unit PA (see 43 CFR part 3180) or CA
(see 43 CFR 3105.2–1–3105.2–3), as
applicable, rather than applying for a
CAA.
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(b) Combining production downhole
from different geologic formations on
the same lease, unit PA, or CA in a
single well requires approval of the AO
(see 43 CFR 3162.3–2), but it is not
considered commingling for production
accounting purposes.
§ 3173.22 Requirements for off-lease
measurement.
The BLM will consider granting a
request for off-lease measurement if the
request:
(a) Involves only production from a
single lease, unit PA, CA, or CAA;
(b) Provides for accurate production
accountability;
(c) Is in the public interest
(considering factors such as BMPs,
topographic and environmental
conditions that make on-lease
measurement physically impractical,
and maximum ultimate economic
recovery); and
(d) Occurs at an approved FMP. A
request for approval of an FMP (see
§ 3173.12) may be filed concurrently
with the request for off-lease
measurement.
§ 3173.23 Applying for off-lease
measurement.
To apply for approval of off-lease
measurement, the operator must submit
the following to the BLM office having
jurisdiction over the leases, units, or
communitized areas:
(a) A completed Sundry Notice;
(b) Justification for off-lease
measurement (considering factors such
as BMPs, topographic and
environmental issues, and maximum
ultimate economic recovery);
(c) A topographic map or maps of
appropriate scale showing the
following:
(1) The boundary of the lease, unit,
unit PA, or communitized area from
which the production originates; and
(2) The location of existing or planned
facilities and the relative location of all
wellheads (including the API number
for each well) and piping included in
the off-lease measurement proposal, and
existing FMPs or FMPs proposed to be
installed to the extent known or
anticipated;
(d) The surface ownership of all land
on which equipment is, or is proposed
to be, located;
(e) If any of the proposed off-lease
measurement facilities are located on
non-federally owned surface, a written
concurrence signed by the owner(s) of
the surface and the owner(s) of the
measurement facilities, including each
owner’s name, address, and telephone
number, granting the BLM unrestricted
access to the off-lease measurement
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81431
facility and the surface on which it is
located, for the purpose of inspecting
any production, measurement, water
handling, or transportation equipment
located on the non-Federal surface up to
and including the FMP, and for
otherwise verifying production
accountability. If the ownership of the
non-Federal surface or of the
measurement facility changes, the
operator must obtain and provide to the
AO the written concurrence required
under this paragraph from the new
owner(s) within 30 days of the change
in ownership;
(f) A right-of-way grant application
(Standard Form 299), filed under 43
CFR part 2880, if the proposed off-lease
FMP is on a pipeline, or under 43 CFR
part 2800, if the proposed off-lease FMP
is a meter or storage tank. This
requirement applies only when new
surface disturbance is proposed for the
FMP and its associated facilities are
located on BLM-managed land;
(g) A right-of-way grant application,
filed under 25 CFR part 169 with the
appropriate BIA office, if any of the
proposed surface facilities are on Indian
land outside the lease, unit, or
communitized area from which the
production originated;
(h) Written approval from the
appropriate surface-management
agency, if new surface disturbance is
proposed for the FMP and its associated
facilities are located on Federal land
managed by an agency other than the
BLM;
(i) An application for approval of offlease royalty-free use (if required under
applicable rules), if the operator
proposes to use production from the
lease, unit, or CA as fuel at the off-lease
measurement facility without payment
of royalty;
(j) A statement that indicates whether
the proposal includes all, or only a
portion of, the production from the
lease, unit, or CA. (For example, gas, but
not oil, could be proposed for off-lease
measurement.) If the proposal includes
only a portion of the production,
identify the FMP(s) where the
remainder of the production from the
lease, unit, or CA is measured or is
proposed to be measured; and
(k) If the operator is applying for an
amendment of an existing approval of
off-lease measurement, the operator
must submit a completed Sundry Notice
required under paragraph (a) of this
section, and information required under
paragraphs (b) through (j) of this section
to the extent the information previously
submitted has changed.
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§ 3173.24 Effective date of an off-lease
measurement approval.
If the BLM approves off-lease
measurement, the approval is effective
on the date that the approval is issued,
unless the approval specifies a different
effective date.
§ 3173.25 Existing approved off-lease
measurement.
(a) Upon receipt of an operator’s
request for assignment of an FMP
number to a facility associated with an
off-lease measurement approval existing
on January 17, 2017, the AO will review
the existing approved off-lease
measurement for consistency with the
minimum standards and requirements
for an off-lease measurement approval
under § 3173.22. The AO will notify the
operator in writing of any
inconsistencies or deficiencies.
(b) The operator must correct any
inconsistencies or deficiencies that the
AO identifies, provide any additional
information the AO requests, or request
an extension of time from the AO,
within 20 business days after receipt of
the AO’s notice. The extension request
must explain the factors that will
prevent the operator from complying
within 20 days and provide a timeframe
under which the operator can comply.
(c) The AO may terminate the existing
off-lease measurement approval and
grant a new off-lease measurement
approval with new or amended COAs to
make the approval consistent with the
requirements for off-lease measurement
under § 3173.22 in connection with
approving the requested FMP. If the
operator appeals the new off-lease
measurement approval, the existing offlease measurement approval will
continue in effect during the pendency
of the appeal.
(d) If the existing off-lease
measurement approval does not meet
the standards and requirements of
§ 3173.22 and the operator does not
correct the deficiencies, the AO may
terminate the existing off-lease
measurement approval under § 3173.27
and deny the request for an FMP
number for the facility associated with
the existing off-lease measurement
approval.
(e) If the existing off-lease
measurement approval under this
section is consistent with the
requirements under § 3173.22, then that
existing off-lease measurement is
grandfathered and will be part of its
FMP approval.
(f) If the BLM grants a new off-lease
measurement approval to replace an
existing off-lease measurement
approval, the new approval is effective
on the first day of the month following
its approval.
(d) If off-lease measurement is
terminated, each lease, unit PA, or CA
that was subject to the off-lease
measurement approval may require a
new FMP number(s) or a new off-lease
measurement approval. Operators will
have 30 days to apply for a new FMP
number or off-lease measurement
approval, whichever is applicable. The
existing FMP number may be used for
production reporting until a new FMP
number is assigned or off-lease
measurement is approved.
§ 3173.26 Relationship of off-lease
measurement approval to royalty-free use
of production.
§ 3173.28 Instances not constituting offlease measurement, for which no approval
is required.
Approval of off-lease measurement
does not constitute approval of off-lease
royalty-free use of production as fuel in
facilities located at an FMP approved
under the off-lease measurement
approval.
(a) If the approved FMP is located on
the well pad of a directionally or
horizontally drilled well that produces
oil and gas from a lease, unit, or
communitized area on which the well
pad is not located, measurement at the
FMP does not constitute off-lease
measurement. However, if the FMP is
located off of the well pad, regardless of
distance, measurement at the FMP
constitutes off-lease measurement, and
BLM approval is required under
§§ 3173.22 through 3173.26.
(b) If a lease, unit, or CA consists of
more than one separate tract whose
boundaries are not contiguous (e.g., a
single lease comprises two or more
separate tracts), measurement of
production at an FMP located on one of
the tracts is not considered to be offlease measurement if:
(1) The production is moved from one
tract within the same lease, unit, or
communitized area to another area of
the lease, unit, or communitized area on
which the FMP is located; and
(2) Production is not diverted during
the movement between the tracts before
the FMP, except for production used
royalty free.
§ 3173.27 Termination of off-lease
measurement approval.
(a) The BLM may terminate off-lease
measurement approval for any reason,
including, but not limited to, the
following:
(1) Changes in technology, regulation,
or BLM policy; or
(2) Operator non-compliance with the
terms or conditions of approval of the
off-lease measurement approval or
§§ 3173.22 through 3173.26.
(b) The BLM will notify the operator
in writing of the effective date of the
termination and any inconsistencies or
deficiencies with its off-lease
measurement approval that serve as the
reason(s) for termination. The operator
must correct any inconsistencies or
deficiencies that the BLM identifies,
provide any additional information the
AO requests, or request an extension of
time from the AO within 20 business
days after receipt of the BLM’s notice,
or the off lease measurement approval
terminates on the effective date.
(c) The operator may terminate the
off-lease measurement by submitting a
Sundry Notice to the BLM. The Sundry
Notice must identify the new FMP(s) for
the lease(s), unit(s), or CA(s) previously
subject to the off-lease measurement
approval.
§ 3173.29 Immediate assessments for
certain violations.
Certain instances of noncompliance
warrant the imposition of immediate
assessments upon discovery, as
prescribed in the following table.
Imposition of these assessments does
not preclude other appropriate
enforcement actions:
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TABLE 1 TO § 3173.29—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation
($)
Violation
1.
2.
3.
4.
An appropriate valve on an oil storage tank was not sealed, as required by § 3173.2 .................................................................
An appropriate valve or component on an oil metering system was not sealed, as required by § 3173.3 ...................................
A Federal seal is removed without prior approval of the AO or AR, as required by § 3173.4 .......................................................
Oil was not properly measured before removal from storage for use on a different lease, unit, or CA, as required by
§ 3173.7(b) .......................................................................................................................................................................................
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TABLE 1 TO § 3173.29—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT—Continued
Assessment
amount per
violation
($)
Violation
5.
6.
7.
8.
9.
An FMP was bypassed, in violation of § 3170.4 .............................................................................................................................
Theft or mishandling of production was not reported to the BLM, as required by § 3173.8 ..........................................................
Records necessary to determine quantity and quality of production were not retained, as required by § 3170.7 ........................
FMP application was not submitted, as required by § 3173.12 ......................................................................................................
(i) For facilities that begin operation after January 17, 2017, BLM approval for off-lease measurement was not obtained before removing production, as required by § 3173.23 .......................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for off-lease measurement.
10. (i) For facilities that begin operation after January 17, 2017, BLM approval for surface commingling was not obtained before
removing production, as required by § 3173.15 ..............................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for surface commingling.
11. (i) For facilities that begin operation after January 17, 2017, BLM approval for downhole commingling was not obtained before removing production, as required by § 3173.15 .......................................................................................................................
(ii) Facilities that were in operation on or before January 17, 2017, are subject to an assessment if they do not have an existing
BLM approval for downhole commingling.
1,000
1,000
1,000
1,000
1,000
1,000
1,000
2. Diagrams
Appendix A to Subpart 3173—
Examples of Site Facility Diagrams
I. Diagrams
1. Site Facility Diagrams and Sealing of Valve
Introduction
Diagrams
I–A
I–B
I–C
I–D
I–E
............
............
............
............
............
I–F ............
I–G ...........
I–H ............
I–I .............
I–J ............
Description
Gas well without separation equipment.
Gas well with separation equipment.
Single operator with co-located facilities single oil tank, gas, and water storage.
Oil sales with multiple oil tanks, gas, and water storage.
Co-located facilities with multiple operators, oil sales by liquid meter (Lease Automatic Custody Transfer or Coriolis Measurement
System), gas, and water storage.
On-lease gas plant, with oil sales by liquid meter, Liquefied Petroleum Gas (LPG)/Natural Gas Liquids (NGL) sales by liquid meter,
inlet gas, tailgate gas, flared or vented and plant process gas used.
Enhanced recovery water injection or other water disposal facility.
Pod Facility.
On-lease with gas measurement after the Joule–Thomson Plant (JT-Skid), oil sales by liquid meter, Liquefied Petroleum Gas
(LPG)/Natural Gas Liquids (NGL) sales by liquid meter.
On-lease with gas measurement before the Joule–Thomson Plant (JT-Skid) and oil sales by liquid meter.
Note: No FMP number required for Liquefied Petroleum Gas (LPG)/Natural Gas Liquids (NGL) liquid meter.
mstockstill on DSK3G9T082PROD with RULES3
1. Site Facility Diagrams and Sealing of
Valves Introduction
Introduction
Appendix A is provided not as a
requirement but solely as an example to aid
operators, purchasers and transporters in
VerDate Sep<11>2014
22:18 Nov 16, 2016
Jkt 241001
determining what valves are considered
‘‘appropriate valves’’ subject to the seal
requirements of this rule, and to aid in the
preparation of facility diagrams. It is
impossible to include every type of
equipment that could be used or situation
that could occur in production activities. In
PO 00000
Frm 00079
Fmt 4701
Sfmt 4700
making the determination of what is an
‘‘appropriate valve,’’ the entire facility must
be considered as a whole, including the
facility size, the equipment type, and the ongoing activities at the facility.
BILLING CODE 4310–4–P
E:\FR\FM\17NOR3.SGM
17NOR3
mstockstill on DSK3G9T082PROD with RULES3
81434
VerDate Sep<11>2014
Jkt 241001
PO 00000
Frm 00080
Gas meter:
FMP No. 72300451234
Fmt 4701
Well Fed 10
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
I
ER17NO16.001</GPH>
N
I-A
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of 1
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of 1
Jkt 241001
PO 00000
Frm 00081
Gas meter:
FMP No. 72300451234
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
Free Water
Knockout
Gas
Water
17NOR3
Water Trucked
Fiberglass Pit
Tank
I
N
Free Water Knockout
Gas Usage 0.1 Mcf/day X days produced= Mcfper month.
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
I-B
81435
ER17NO16.002</GPH>
mstockstill on DSK3G9T082PROD with RULES3
81436
VerDate Sep<11>2014
Facility Operator/Owner Name: ABC Oil and Gas
Federal/Indian Lease, unit PA, orCA Number: NMNM12345 and NMNM54321
Land Description: As defined in § 3170.3
Jkt 241001
Page 1 of3
PO 00000
Gas meter
FMP No. 7230045AZ12
Well Fed lOA
NMNM12345
Gas meter
FMP No. 72300451234
Well Fed lOB
NMNM54321
Frm 00082
Fmt 4701
Oil
FMP No. 52300451234
Water Trucked
Separator
Sfmt 4725
Gas
E:\FR\FM\17NOR3.SGM
Water Trucked
Water
17NOR3
Fiberglass Pit
Tank
I
N
X
Sealable Valve
'l_s_e_e_a_tt_a_c_hm_e_n_t_fo_r_V_al_v_e_P_o_s_it-io_m_·_ng_d_un_·_n_g---.,1
Production, Sales, and Draining Phases
ER17NO16.003</GPH>
Fiberglass Pit
Tank
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
1-C
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Jkt 241001
PO 00000
Diagram #I-C:
F1 is the Fill Valve
S 1 is the Sales Valve
D1 is the Drain Valve
Frm 00083
Fmt 4701
Valve Positioning in the Production Phase
Production into T5678
S 1 is Sealed Closed
F1 is Open
D 1 is Sealed Closed
Sfmt 4725
E:\FR\FM\17NOR3.SGM
Valve Positioning in the Sales Phase
Sales from T5678
S1 is Open
F1 is Open
D 1 is Sealed Closed
17NOR3
Valve Positioning in the Drain Phase
Draining from T5678
S 1 is Sealed Closed
F1 is Open
D1 is Open
Free Water Knockout
Gas Usage 0.1 Mcf/day X days produced= Mcfper month.
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
I-C
Page 2 of3
81437
ER17NO16.004</GPH>
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81438
VerDate Sep<11>2014
Jkt 241001
PO 00000
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Frm 00084
Separator
Fire box rated at 150,000 btu/hour (btu/hr) operated, 20 hours/day (hrs/day)
150,000 btu/hr 7 1157 btu/cubic foot (btu/ft3) X 20 hrs/d 7 1000 = 2.51 Mcf/day
Fmt 4701
Sfmt 4725
Pump Jack
Manufacturer fuel use when operated at 75% of rated maximum RPM, 5.87 Mcflhr X hours operating 12 hrs. = 70.44 Mcf/day
E:\FR\FM\17NOR3.SGM
Water Tank
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr (November, December, January, February), 10 hrs/week,
200,000 btu/hr 7 1157 btu/ft3 X 40 hrs/mo 7 1000 = 6.91 MCF/mo.
17NOR3
Oil Tank
Tank No.: 5678
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr (November, December, January, February), 5 hrs/week
200,000 btu/hr 7 1157 btu/ft3 X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 7230045AZ12 on MM/DD/YYY
ER17NO16.005</GPH>
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
I-C
Page 3 of3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
1-D
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Jkt 241001
t
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 1 of3
Gas meter
FMP No. 72300451234
PO 00000
Frm 00085
N
Fmt 4701
I
Dehydrator
Sfmt 4725
Water Trucked
Separator
Oil
FMP No. 52300451234
E:\FR\FM\17NOR3.SGM
Oil
Gas
Water
17NOR3
Lined
Emergency Pit
See (diagram) attachment for Valve
Positioning during Production, Sales, and
Draining Phases
Equalizer
Sealable Valve
X
81439
ER17NO16.006</GPH>
Fiberglass Pit
Tank
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
Page 1 of3
mstockstill on DSK3G9T082PROD with RULES3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Jkt 241001
PO 00000
Diagram #I-D:
F1 and F2 are Fill Valves
S1 and S2 and Sales Valves
D 1 and D2 are Drain Valves
Frm 00086
Fmt 4701
Valve Positioning in the Production Phase
Production into T5678
Production into T1234
S2 and D2 are Sealed Closed
S 1 and D 1 are Sealed Closed
Overflow/Equalizer is Open
Overflow/Equalizer is Open
F2 is Open and F 1 is Closed
F 1 is open and F2 is Closed
Sfmt 4725
E:\FR\FM\17NOR3.SGM
Valve Positioning in the Sales Phase
Sales from T5678 through S1:
D 1 and F 1 are Sealed Closed
Overflow/Equalizer is Sealed Closed
S1 is Open
S2 Sealed closed
F2 open
D2 open or closed
Sales from T1234 through S2:
D2 and F2 are Sealed Closed
Overflow/Equalizer is Sealed Closed
S2 is Open
S 1 sealed closed
F1 open
D 1 open or closed
17NOR3
Valve Positioning in the Drain Phase
Draining from T5678
Draining from T1234
S1 and F1 are Sealed Closed
S2 and F2 are Sealed Closed
Overflow/Equalizer is Sealed Closed
Overflow/Equalizer is Sealed Closed
D1 is Open
D2 is Open
S-2 sealed close
S 1 sealed close
F1 open
F2 open
D2 open or closed
D 1 open or closed
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
81440
VerDate Sep<11>2014
ER17NO16.007</GPH>
I-D
Page 2 of3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
Jkt 241001
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
PO 00000
Compressor
Manufacturer fuel use when operated at 80% of rated maximum, 24.87 Mcf/hr X 24 hrs. = 596.88 Mcf/day
Frm 00087
Dehydrator
Fire box rated at 75,000 btulhr operated, 20 hrs/day
75,000 btulhr 7 1,157 btu/ft3 X 20 hrs/day 4 7 1,000 = 1.30 Mcf/day
Fmt 4701
Sfmt 4725
Separator
Fire box rated at 150,000 btulhr operated 4 mo/yr, 20 hrs/day
150,000 btulhr 7 1,157 btu/ft3 X 20 hrs/day 71,000 = 2.59 Mcf/day
E:\FR\FM\17NOR3.SGM
Water Tank
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 10 hrs/week, 70% efficiency
200,000 btulhr 7 1,157 btu/ft3 X 40 hrs/mo 7 1,000 = 6.91 Mcf/mo.
17NOR3
Oil Tank No.: 5678
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 5 hrs/week
200,000 btulhr 7 1,157 btu/ft3 X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
Oil Tank No.: 1234
Tank Heater rated at 200,000 btu/hr operated 4 mo/yr, 5 hrs/week
200,000 btulhr 7 1,157 btu/ft3 (see current gas analysis) X 20 hrs/mo 7 1,000 = 3.46 Mcf/mo.
1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MM/DD/YYY
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
I-D
Page 3 of3
81441
ER17NO16.008</GPH>
mstockstill on DSK3G9T082PROD with RULES3
81442
VerDate Sep<11>2014
1-E
Jkt 241001
Co-located Facility Operated by:
Oil & Gas Major LTD.,
NMNM54321
PO 00000
Gas meter
FMP No. 72300451234
Bad Oil Recirculation System
Frm 00088
Oil
FMP No. 62300451234
Dehydrator
Bad Oil Return
Fmt 4701
Water Pumped
Separator
Sfmt 4725
Gas
Oil
Water
E:\FR\FM\17NOR3.SGM
17NOR3
I
N
Steel Pit
Tank
Unlined
Emergency Pit
z
Sealable Valve
Header
f
Weill
API No.
ER17NO16.009</GPH>
f
Well2
API No.
f
Well3
API No.
See (diagram) attachment for Valve
Positioning during Production, Sales, and
Draining Phases
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Page 1 of3
Federal/Indian Lease, unit PA, or CA Number: NMNM12345
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Jkt 241001
PO 00000
Diagram #I-E:
F1, F2 and F3 are Fill Valves
S 1 and S2 are Sales Valves
D1, D2 and D3 are Drain Valves
R1 is a Recirculation Valve
Frm 00089
Fmt 4701
Valve Positioning in the Production Phase for FMP No. 62300451234
Production into 5678, 1234 and 6851
S1, F1, F2, F3 and R1 are Open
D 1 and D2 are Sealed Closed
Equalizer is open
Sfmt 4725
E:\FR\FM\17NOR3.SGM
Valve Positioning in the Sales Phase
Production into 5678, 1234 and 6851
S1, F1, F2, F3 and R1 are Open
D 1 and D2 are Sealed Closed
Equalizer is open
17NOR3
Valve Positioning in the Drain Phase
Draining from 5678
Draining from 1234
S1 and F1 are Sealed Closed
S2 and F2 are Sealed Closed
Equalizer is Sealed Closed
Equalizer is Sealed Closed
D2 and S 1 are Open
D 1 and S2 are Open
D2 Sealed Closed
D1 Sealed Closed
Draining from 6851
R1 is Sealed Closed
F3 is Sealed Closed
D3 Open
81443
Dehydrator
Fire box rated at 75,000 btu/hr operated 24 hrs/day, 20 hrs/day
75,000 btu/hr 7 1,157 btu/ft3 X 20 7 1,000 = 1.30 Mcf/day
ER17NO16.010</GPH>
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
I-E
Page 2 of3
mstockstill on DSK3G9T082PROD with RULES3
81444
VerDate Sep<11>2014
Jkt 241001
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
PO 00000
Separator
Fire box rated at 150,000 btu!hr operated 4 mo/yr, 20 hrs/day
150,000 btu!hr -c- 1,157 btu/ft3 X 20 -c- 1,000 = 2.59 Mcf/day
Frm 00090
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
ER17NO16.011</GPH>
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
1157 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MM/DD/YYY
Charge pump, water pump and oil recirculation pump are electric motor/gasoline engine powered and not subject to royalty-free.
The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for FMP No.: 62300451234
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-offvalve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer; and
13. Prover connections.
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
1-E
Page3of3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
1-F
Well 1, API No.
Well2, API No.
Jkt 241001
PO 00000
Gas Plant FlareNenting
Meter
Gas Plant Process/Used
Meter
Gas Plant Tailgate
Meter
FMP No. 72300391234
Frm 00091
Gas Plant Inlet Meter
To Separator 1111
1
Oil/Drip/Condensate
Fmt 4701
Lease, Unit PA, or CA Gas Plant
Processes/Processing
N
I
FMP No. 62300391234
Sfmt 4725
E:\FR\FM\17NOR3.SGM
t:ti
Pl
0..
.s
o:s
.....
Q
Lffl T~-~0~2w
0
IPressurized Storage
LPG/NGLto
~
Vessels
I~
17NOR3
LACT/CMS
FMP No. 62300391235
z
Sealable Valve
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: Oil and Gas Plant Operations Inc.
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Land Description: As defined in § 3170.3
Page 1 of 3
81445
ER17NO16.012</GPH>
mstockstill on DSK3G9T082PROD with RULES3
81446
VerDate Sep<11>2014
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of3
Jkt 241001
PO 00000
Frm 00092
Diagram #I-F:
F1, F2, F3, F4, F5, and F6 are Fill Valves
S1, S2, S3, S4, S5, and S6 are Sales Valves
D1, D2, D3, D4, D5 and D6 are Drain Valves
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
Production into T5678
D3 is Sealed Closed
Valve Positioning in the Sales Phase
Sales from T5677 through S2:
Sales from T5676 through S 1:
D 1 is Sealed Closed
D2 is Sealed Closed
Sales from T5678 through S3:
D3 is Sealed Closed
Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F1 is Sealed Closed
F2 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D2 is Open
D1 is Open
Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open
Valve Positioning in the Production Phase
Production into T5680
Production into T5681:
D5 is Sealed Closed
D4 is Sealed Closed
ER17NO16.013</GPH>
Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed
Production into T5682
D6 is Sealed Closed
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
I-F
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
I-F
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 3 of3
Jkt 241001
PO 00000
Frm 00093
Fmt 4701
Valve Positioning in the Sales Phase
Sales from T5681 through S5:
Sales from T5680 through S4:
D5 is Sealed Closed
D4 is Sealed Closed
Sales from T5682 through S6:
D6 is Sealed Closed
Valve Positioning in the Drain Phase
Draining from T5680
Draining from T5681:
S4 is Sealed Closed
S5 is Sealed Closed
F5 is Sealed Closed
F4 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D4 is Open
D5 is Open
Draining from T5682
S6 is Sealed Closed
F6 is Sealed Closed
Overflow is Sealed Closed
D6 is Open
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer; and
13. Prover connections.
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
81447
ER17NO16.014</GPH>
mstockstill on DSK3G9T082PROD with RULES3
81448
VerDate Sep<11>2014
I-G
Federal/Indian Lease, unit PA, or CA Number: NMNM98765
Page 1 of2
Jkt 241001
Water from
Producing Wells by
Pipeline
Enhanced Recovery Water
Injection or other Water
Disposal Facility
Water from
Producing Wells by
Water
PO 00000
Frm 00094
Water Supply
Well No 200
Equalize
r
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
Injection Pump,
Filter Building and
Chemical Treatment
I
All Royalty-Free gas is first measured
through the "Fuel Gas Supply Meter"
I
Injection Header
~
Well1 API
ER17NO16.015</GPH>
~Fuel Gas Supply Meter
~
We112 API
~
Wel13 API
I
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
mstockstill on DSK3G9T082PROD with RULES3
VerDate Sep<11>2014
Attachment
Jkt 241001
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3
PO 00000
Frm 00095
Diagram #I -G:
Fl is the Fill Valve
S 1 is the Sales Valve
D1 is the Drain Valve
Fmt 4701
Sfmt 4725
Valve Positioning in the Production Phase
Production into T5555
S 1 is Sealed Closed
Fl is Open
D 1 is Sealed Closed
E:\FR\FM\17NOR3.SGM
Valve Positioning in the Sales Phase
Sales form T5555
S1 is Open
Fl is Open
D 1 is Sealed Closed
17NOR3
Valve Positioning in the Drain Phase for
Draining from T5555
S 1 is Sealed Closed
Fl is Open
D1 is Open
Federal/Indian Lease, unit PA, or CA Number: NMNM98765
Page 2 of2
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
I-G
81449
ER17NO16.016</GPH>
mstockstill on DSK3G9T082PROD with RULES3
81450
VerDate Sep<11>2014
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM98765
Page 1 of3
Jkt 241001
PO 00000
Pod 1
0
Frm 00096
Pod2
FMP No. 230045A24E
Fmt 4701
Sfmt 4725
E:\FR\FM\17NOR3.SGM
Free Water
Knockout
Gas
Water
17NOR3
Water Trucked
Fiberglass Pit
Tank
I
ER17NO16.017</GPH>
N
Free Water Knockout
Gas Usage 0.1 Mcf/day
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
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2
Frm 00097
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Sfmt 4725
FMP No. 7230045A24E
FMP No. 7230045AD44
POD Facility
1
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·
POD Master Meter
FMP No. 74300459029Z
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)
E:\FR\FM\17NOR3.SGM
FMP No. 733004537NM
F~Ql23
FMP No. 7430045S5G9
FMP Ne. 733QQ45'38FG
•I
FMP No. 7430045MI89
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)
FMP No. 7430045VM34
•I
17NOR3
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
81451
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FMP No. 743004590292
Federal/Indian Lease, unit PA, orCA Number: NMNM98765
FMP No. 7430045K5L8
Federal/Indian Lease, unit PA, orCA Number: NMNM98765
FMP No. 7430045S5G9
Federal/Indian Lease, unit PA, orCA Number: NMNM1234A
FMP No. 7430045VM34
Federal/Indian Lease, unit PA, orCA Number: NMNM56789D
FMP No. 7430045MI89
Federal/Indian Lease, unit PA, orCA Number: NMSF10254
FMP No. 7430045NX30
Federal/Indian Lease, unit PA, orCA Number: NMSF10254
E:\FR\FM\17NOR3.SGM
POD2
17NOR3
FMP No. 7230045AD44
Federal/Indian Lease, unit PA, orCA Number: NMNM54321A
FMP No. 7230045Z4GB
Federal/Indian Lease, unit PA, orCA Number: NMNM1234C
FMP No. 733004537NM
Federal/Indian Lease, unit PA, orCA Number: NMNM56789B
FMP No. 73300450123
Federal/Indian Lease, unit PA, orCA Number: NMSF10983
ER17NO16.019</GPH>
FMP No. 7230045A24E
Federal/Indian Lease, unit PA, orCA Number: NMNM56789
FMP No. 733004538FG
Federal/Indian Lease, unit PA, orCA Number: NMSF10254
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in§ 3170.3,
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FMP No. 72300391234
PO 00000
Gas
Frm 00099
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Oil/Drip/Condensate
Fmt 4701
Joule-Thomson Plant (JT -Skid)
I
FMP No. 62300391234
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t:ti
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0..
.s
....
"'
Ci
Lffl T~-~0~2w
0
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~
IPressurized Storage
LPG/NGLto
Vessels
17NOR3
LACT/CMS
z
Sealable Valve
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
81453
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Facility Operator/Owner Name: ABC Oil and Gas
Land Description: As defined in § 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of4
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Diagram #I-I:
F1, F2, F3, F4, F5, and F6 are Fill Valves
S1, S2, S3, S4, S5, and S6 are Sales Valves
D1, D2, D3, D4, D5 and D6 are Drain Valves
Fmt 4701
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E:\FR\FM\17NOR3.SGM
17NOR3
Production into T5678
D3 is Sealed Closed
Valve Positioning in the Sales Phase
Sales from T5677 through S2:
Sales from T5676 through S 1:
D 1 is Sealed Closed
D2 is Sealed Closed
Sales from T5678 through S3:
D3 is Sealed Closed
Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F1 is Sealed Closed
F2 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D2 is Open
D1 is Open
Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open
Valve Positioning in the Production Phase
Production into T5680
Production into T5681:
D5 is Sealed Closed
D4 is Sealed Closed
ER17NO16.021</GPH>
Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed
Production into T5682
D6 is Sealed Closed
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Valve Positioning in the Sales Phase
Sales from T5680 through S4:
Sales from T5681 through S5:
D4 is Sealed Closed
D5 is Sealed Closed
Sales from T5682 through S6:
D6 is Sealed Closed
Valve Positioning in the Drain Phase
Draining from T5680
Draining from T5681:
S4 is Sealed Closed
S5 is Sealed Closed
F5 is Sealed Closed
F4 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D5 is Open
D4 is Open
Draining from T5682
S6 is Sealed Closed
F6 is Sealed Closed
Overflow is Sealed Closed
D6 is Open
Sfmt 4725
E:\FR\FM\17NOR3.SGM
17NOR3
The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-offvalve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.
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Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 4 of4
PO 00000
Frm 00102
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E:\FR\FM\17NOR3.SGM
The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5680, 5681,
and 5682.
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.
17NOR3
Separator
Fire box rated at 150,000 btu/hr operated, 20 hrs/day
150,000 btu/hr -o- 1,450 btu/ft3 (estimated) X 20 -o- 1,000 = 2.07 Mcf/day
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
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We112, .APT No.
Well 1, tPI No.
Header
Jkt 241001
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FMP No. 72300391234
Separator
PO 00000
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Joule-Thomson Plant (JT -Skid)
I
N
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Petroleum Gas (LPG)/Natural Gas Liquids (NGL)
liquid meter.
E:\FR\FM\17NOR3.SGM
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Vessels
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FMP No. 62300391235
X
Sealable Valve
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
22:18 Nov 16, 2016
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Page 1 of3
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Land Description: As defined in§ 3170.3
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Land Description: As defined in § 3170.3
Federal/Indian Lease, unit PA, orCA Number: NMNM12345
Page 2 of3
PO 00000
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Diagram #I -J:
F1, F2, and F3, are Fill Valves
S1, S2, and S3 are Sales Valves
D1, D2, and D3 Drain Valves
Fmt 4701
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E:\FR\FM\17NOR3.SGM
17NOR3
Valve Positioning in the Production Phase
Production into T5676
Production into T5677:
D 1 is Sealed Closed
D2 is Sealed Closed
Production into T5678
D3 is Sealed Closed
Valve Positioning in the Sales Phase
Sales from T5676 through S 1:
Sales from T5677 through S2:
D 1 is Sealed Closed
D2 is Sealed Closed
Sales from T5678 through S3:
D3 is Sealed Closed
Valve Positioning in the Drain Phase
Draining from T5676
Draining from T5677:
S2 is Sealed Closed
S 1 is Sealed Closed
F2 is Sealed Closed
F1 is Sealed Closed
Overflow is Sealed Closed
Overflow is Sealed Closed
D1 is Open
D2 is Open
Draining from T5678
S3 is Sealed Closed
F3 is Sealed Closed
Overflow is Sealed Closed
D3 is Open
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
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ER17NO16.025</GPH>
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Page 3 of3
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The following components on liquid measurement metering system will be effectively sealed (list as appropriate) for tanks numbered 5676, 5677,
and 5678.
Frm 00105
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E:\FR\FM\17NOR3.SGM
1. Sample probe;
2. Sampler volume control;
3. All valves on lines entering or leaving the sample container excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
4. Meter assembly, including the counter head and meter head;
5. Temperature averager/recorder;
6. Pressure adjustment on the back-pressure valve downstream of the meter;
7. CMS or LACT;
8. Any drain valves in the system;
9. Manual sampling valves (if so equipped);
10. Valves larger than 1 inch on the diverter lines;
11. Right-angle;
12. Totalizer, manufacturer; and
13. Prover connections.
17NOR3
Separator
Fire box rated at 150,000 btu/hr operated, 20 hrs/day
150,000 btu/hr -o- 1,450 btu/ft3 (estimated) X 20 -o- 1,000 = 2.07 Mcf/day
1450 btu/ft3 as dry determined by gas analysis taken at FMP No. 72300451234 on MMIDD/YYY
Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
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BILLING CODE 4310–84–C
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]]>Agencies
[Federal Register Volume 81, Number 222 (Thursday, November 17, 2016)]
[Rules and Regulations]
[Pages 81356-81459]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-25407]
[[Page 81355]]
Vol. 81
Thursday,
No. 222
November 17, 2016
Part V
Department of the Interior
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Bureau of Land Management
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43 CFR Parts 3160 and 3170
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases;
Site Security; Final Rule
Federal Register / Vol. 81 , No. 222 / Thursday, November 17, 2016 /
Rules and Regulations
[[Page 81356]]
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DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004-AE15
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas
Leases; Site Security
AGENCY: Bureau of Land Management, Interior.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule replaces Onshore Oil and Gas Order No. 3, Site
Security (Order 3), with new regulations codified in the Code of
Federal Regulations (CFR). The final rule establishes minimum standards
for oil and gas facility site security, and includes provisions to
ensure that oil and gas produced from Federal and Indian (except Osage
Tribe) oil and gas leases are properly and securely handled, so as to
ensure accurate measurement, production accountability, and royalty
payments, and to prevent theft and loss.
The BLM developed this rule based on the proposed rule that was
published in the Federal Register on July 13, 2015, and tribal and
public comments the BLM received on the proposed rule. This rule
strengthens the BLM's policies governing production verification and
accountability by updating and replacing the existing requirements of
Order 3 to address changes in technology and industry practices that
have occurred in the 25 years since Order 3 was issued, and to respond
to recommendations made by the Government Accountability Office (GAO)
and the Office of the Inspector General (OIG) with respect to the BLM's
production verification efforts.
Like the proposed rule, the final rule addresses Facility
Measurement Points (FMPs), site facility diagrams, the use of seals,
bypasses around meters, documentation, recordkeeping, commingling, off-
lease measurement, the reporting of incidents of unauthorized removal
or mishandling of oil and condensate, and immediate assessments for
certain acts of noncompliance. The final rule also establishes a
process for the BLM to consider variances from the requirements of the
final regulation.
Some of the key changes from the proposed rule that are
incorporated into the final rule include: Additional exemptions from
the final rule's commingling requirements; a streamlined FMP
application and approval process; simplified site facility diagram
submissions; and clarifications to tank gauging procedures and
frequency.
The BLM believes that this final rule, as well as the final rules
to update and replace Onshore Oil and Gas Order No. 4 (Order 4),
related to measurement of oil, and Onshore Oil and Gas Order No. 5
(Order 5), related to measurement of gas enhance the BLM's overall
production verification and accountability program.
DATES: The final rule is effective on January 17, 2017.
FOR FURTHER INFORMATION CONTACT: Michael Wade, BLM Colorado State
Office, at 303-239-3737, for information about the requirements of this
final rule, or Steven Wells, Division Chief, Fluid Minerals Division,
202-912-7143, for information regarding the BLM's Fluid Minerals
Program. Persons who use a telecommunications device for the deaf (TDD)
may call the Federal Relay Service at 1-800-877-8339 to contact the
above individuals during normal business hours. The Service is
available 24 hours a day, 7 days a week to leave a message or question
with the above individual. You will receive a reply during normal
business hours.
SUPPLEMENTARY INFORMATION:
I. Executive Summary and Background
II. Overview of the Final Rule, Section-by-Section Analysis, and
Response to Comments
III. Overview of Public Involvement and Consistency With GAO
Recommendations
IV. Procedural Matters
I. Executive Summary and Background
Under applicable law, royalties are owed on all production removed
or sold from Federal and Indian oil and gas leases, as well as on any
oil or gas that is avoidably lost during production. The basis for
those royalty payments is the measured production from those leases. In
the fiscal year (FY) 2015 sales year, onshore Federal oil and gas
leases sold 180 million barrels (bbl) of oil,\1\ 2.50 trillion cubic
feet of natural gas,\2\ and 2.6 billion gallons of natural gas liquids,
with a market value of more than $17.7 billion and generating royalties
of almost $2.0 billion. Nearly half of these revenues were distributed
to the States in which the leases are located. Leases on tribal and
Indian lands sold 59 million bbl of oil, 239 billion cubic feet of
natural gas, 182 million gallons of natural gas liquids, with a market
value of over $3.6 billion and generating royalties of over $0.6
billion, which were distributed in their entirety to the applicable
tribes and individual allottee owners.
---------------------------------------------------------------------------
\1\ Figures related to total production of oil include 168
million bbl of regularly classified oil, plus additional sales of
condensate, sweet and sour crude, black wax crude, other liquid
hydrocarbons, inlet scrubber and drip or scrubber condensate, and
avoidable oil losses, all of which are considered to be part of oil
sales for accounting purposes.
\2\ Includes all processed and unprocessed volumes recovered on-
lease, nitrogen, fuel gas, coal bed methane, and any volumes of gas
avoidably lost due to venting or flaring.
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As explained in the preamble for the proposed rule (80 FR 40768),
given the magnitude of this production and the BLM's statutory and
management obligations, it is critically important that the BLM ensure
that operators accurately measure, properly report, and account for all
production. This final rule helps the BLM achieve that objective by
updating and replacing Order 3's requirements with regulations codified
in the CFR that reflect changes in oil and gas measurement practices
and technology since Order 3 was first promulgated in 1989.\3\
---------------------------------------------------------------------------
\3\ Order 3, which was published in the Federal Register on
February 24, 1989 (54 FR 8056), has been in effect since March 27,
1989.
---------------------------------------------------------------------------
Specifically, the requirements in this rule ensure the proper and
secure handling of production from Federal and Indian (except Osage
Tribe) oil and gas leases. The proper handling of production is
essential to accurate measurement, proper reporting, and overall
production accountability, all of which are necessary to ensure that
the American public, as well as Indian tribes and allottees, receive
the royalties to which they are entitled on oil and gas produced from
Federal and Indian leases, respectively.
Order 3 was one of seven Onshore Oil and Gas Orders that the BLM
issued under its regulations at 43 CFR part 3160.\4\ Order 3 primarily
supplemented the regulations at 43 CFR 3162.4 (records and reports),
3162.5 (environmental safety), 3162.7 (disposition and measurement of
oil and gas production and site security on Federal and Indian (except
Osage Tribe) oil and gas leases), subpart 3163 (non-compliance,
assessments, and civil penalties), and subpart 3165 (relief, conflicts,
and appeals). While the BLM's Onshore Orders have all been published in
the Federal Register, both for public comment and in final form, they
were never codified in the CFR. With this final rule, the BLM is
replacing Order 3 and updating and codifying its
[[Page 81357]]
requirements regarding site security, as explained below.
---------------------------------------------------------------------------
\4\ These regulations provide for the issuance of Onshore Oil
and Gas Orders to ``implement and supplement'' the regulations found
in part 3160. 43 CFR 3164.1(a). The Onshore Orders apply nationwide
to all Federal onshore and Indian (except Osage Tribe) oil and gas
leases.
---------------------------------------------------------------------------
The development of this rule was driven largely by internal and
external reviews of the BLM's existing production measurement and
accountability program. These reviews began in 2007 when the Secretary
appointed an independent panel--the Subcommittee on Royalty Management
(Subcommittee)--to review the Department's procedures and processes
related to the management of mineral revenues and to provide advice to
the Department based on that review.\5\ In a report dated December 17,
2007, the Subcommittee determined that the BLM's guidance regarding
production accountability is ``unconsolidated, outdated, and sometimes
insufficient'' (Subcommittee report, p. 30). The Subcommittee report
found that this results in inconsistent and outmoded approaches to
production accountability tasks, and the potential loss of royalty
revenue.
---------------------------------------------------------------------------
\5\ The Subcommittee was commissioned to report to the Royalty
Policy Committee, which was chartered under the Federal Advisory
Committee Act to provide advice to the Secretary and other
departmental officials responsible for managing mineral leasing
activities and to provide a forum for the public to voice concerns
about mineral leasing activities. The Royalty Policy Committee's
chart has since expired.
---------------------------------------------------------------------------
The Subcommittee report expressed concern that the applicable ``BLM
policy and guidance is outdated'' and ``some policy memoranda have
expired'' (Subcommittee report, p. 31). The Subcommittee also expressed
concern that ``BLM policy and guidance have not been consolidated in a
single document or publication,'' which has led to the ``BLM's 31 oil
and gas field offices using varying policy and guidance'' (id.). For
example, ``some BLM State Offices have issued their own `Notices to
Lessees' for oil and gas operations'' (id.). While the Subcommittee
recognized that such Notices to Lessees may have a positive effect on
some oil and gas field operations, it also observed that they
necessarily ``lack a national perspective and may introduce
inconsistencies among State [Offices]'' (id.).
The Subcommittee made a number of recommendations relevant to site
security. It recommended that the BLM re-evaluate its regulations and
update its policy and guidance on production accountability, including
requiring that requests to commingle production from multiple leases,
unit participating areas (PAs), or areas subject to communitization
agreements (CAs) identify allocation among zones (Subcommittee report,
p. 32). The Subcommittee also recommended that the BLM re-evaluate its
policies and guidance for royalty-free use of gas in lease operations.
It also specifically recommended that the BLM establish a workgroup to
evaluate Order 3. In response, the Department formed a fluid minerals
team, comprising Departmental employees who are oil and gas experts.
Based on its review, the team determined that Order 3 should be
updated.
In addition to the Subcommittee report, the GAO and the OIG have
performed multiple audits since 2009 and issued reports that included
many findings and recommendations addressing similar issues: (1) Report
to Congressional Requesters, Oil and Gas Management, Interior's Oil and
Gas Production Verification Efforts Do Not Provide Reasonable Assurance
of Accurate Measurement of Production Volumes GAO-10-313 (GAO Report
10-313); (2) Report to Congressional Requesters, Oil and Gas Resources,
Interior's Production Verification Efforts: Data Have Improved but
Further Actions Needed, GAO 15-39 (GAO Report 15-39); (3) Bureau of
Land Management's Oil and Gas Inspection and Enforcement Program, CR-
EV-0001-2009 (OIG Report 2009); and (4) Energy Related Management
Advisories, CR-IS-MOA-0005-2014 (OIG Report 2014).
In 2010, the GAO found that Interior's measurement regulations and
policies do not provide reasonable assurance that oil and gas are
accurately measured. Regarding matters relevant to site security, the
report found that the BLM lacks regulatory or policy requirements for
operators to clearly identify points of royalty measurement, creating
challenges for the BLM in verifying production (GAO Report 10-313, p.
34). It also found that the BLM does not have sufficient national
policies or a consistent process for approving arrangements that allow
operators to commingle production from multiple Federal, Indian, State,
and private leases, which also makes it difficult for the agency to
verify production (GAO Report 10-313, p. 36). In response, the GAO
specifically recommended that the BLM: (1) Develop guidance clarifying
when Federal oil and gas may be commingled and establish standardized
measurement methods for such circumstances so that production can be
adequately measured and verified; (2) Confirm that commingling
agreements are consistent with Interior guidance before they are
approved, and that the agreements facilitate key production
verification activities; and (3) Track all onshore meters, including
information about meter location, identification number, and owner, to
help ensure that Interior (through the BLM) is accurately and
consistently tracking where and how onshore oil and gas are measured
nationwide.
The GAO reiterated some of these concerns in 2015 (GAO Report 15-
39). In that report, the GAO acknowledged the improvements the BLM had
made in its processes and policies (e.g., issuing additional guidance
in 2013 regarding commingling approvals), but reiterated the importance
of the BLM updating its regulations related to measurement and site
security (GAO Report 15-39, pp. 31-32).
Based in part on its concern that the BLM's production verification
efforts do ``not provide reasonable assurance that operators are
accurately measuring and reporting'' the volumes of oil and gas
produced from Federal and Indian leases, the GAO included the BLM's
onshore oil and gas program on its High Risk List in 2011 (Report to
Congressional Committees, High Risk Series, An Update, GAO-11-278 (GAO
Report 11-278), p. 15). Because the GAO's recommendations have not yet
been fully implemented, including those related to production
verification, the onshore oil and gas program has remained on the High
Risk List in subsequent updates in 2013 (Report to Congressional
Committees, High Risk Series, An Update, GAO-13-283) and 2015 (Report
to Congressional Committees, High Risk Series, An Update, GAO-15-290).
The OIG made similar observations as part of its reviews of the
BLM's inspection and enforcement program. For example, in 2009 the OIG
observed that the BLM's ``inspection efforts are hampered because of
provisions in the bureau's regulations that have not kept up with
modern technology. Most notably, six of the seven Onshore Oil and Gas
Orders, which address activities, such as drilling operations, the
measurement of oil and gas, and site security, are outdated as they
were enacted in the late 1980s and early 1990s.'' The OIG specifically
recommended that the BLM ``(e)nsure that oil and gas regulations are
current by updating and issuing onshore orders.'' (OIG Report 2009, p.
10-11).
The OIG also expressed concern that ``(c)urrent BLM policies (with
respect to penalties and assessments) do not allow for immediate
assessments for chronic offenders. As a result, at times there is
little incentive for companies to meet their regulatory
responsibilities.'' (id., p. 13). As a result, the OIG recommended that
the BLM ``(e)nhance the deterrent for operator noncompliance by
increasing the dollar amount of
[[Page 81358]]
monetary assessments, seeking congressional action for increasing civil
penalties, and expanding the infractions for which immediate
assessments may be issued.'' (id., p. 14).
The OIG supplemented these recommendations in 2014 with a series of
recommendations that flowed from individual OIG investigations that
were consolidated into one report--Energy Related Management
Advisories, CR-IS-MOA-0005-2014 (Nov. 2014) (OIG Report 2014).\6\ That
report made a number of recommendations, including the following
relevant to this rule:
---------------------------------------------------------------------------
\6\ The OIG Report 2014, covered the following investigations:
Berry Petroleum Co. & Quinex Energy Corp., DOI-OIG Case File Nos.
OI-OG-07-0359-I & OI-OG-07-0389-I; Petrox Resources, Inc., DOI-OIG
Case File No. OI-OG-09-0266-I; SEECO, Inc., OIG Case File No. OI-OG-
09-0722-1; and TEPPCO Partners, DOI-OIG Case File No. OI-OG-09-0346-
I).
---------------------------------------------------------------------------
Develop and implement procedures to ensure timely receipt
of site facility diagrams and ensure that they contain adequate
information related to production and sales phases (OIG Report 2014 at
10, 18);
Take steps to address misreporting associated with off-
lease measurement (id.);
Ensure that adequate information exists regarding on-lease
beneficial use in order to identify inappropriate deductions (id., at
12); and
Ensure that Federal measurement points are properly
documented and recorded (id. at 21).
In addition to the concerns from these entities, the BLM also
recognized, based on its own experience, that its site security
requirements needed strengthening. For example, as explained in the
proposed rule, it is not uncommon for a BLM inspector, a lease
operator, and field employees to all have different understandings of
where the point of royalty measurement is on a given lease, because
Order 3 did not require operators to formally identify and obtain BLM
approval for the use of a particular royalty measurement point on a
given lease, unit PA, or CA. This type of discrepancy can create
needless uncertainties in production, accounting, and verification, and
can increase the time spent on individual inspections and audits by
both operators and the BLM, which strains the BLM's limited resources
and requires additional response and resources on the part of
operators. This final rule corrects this problem by requiring operators
to identify and obtain BLM approval for their royalty measurement
points, which are called FMPs under this rule.
Similarly, with respect to commingling approvals, the BLM
recognizes that the absence of uniform national guidance means that
some BLM-approved commingling agreements may not provide the production
data that the BLM needs to independently verify production that is
attributable to the Federal or Indian leases covered by those
agreements. The absence of this data limits the BLM's ability to
fulfill its obligation to ensure that all production from Federal and
Indian (except Osage Tribe) oil and gas leases is properly accounted
for and that royalties are properly calculated. The final rule
addresses these concerns by establishing uniform requirements for both
existing and future commingling approvals. With respect to existing
approvals, the final rule includes provisions: (1) Specifically
grandfathering existing CAAs involving downhole commingling and where
production falls below certain specified thresholds; (2) Expressly
exempting from compliance with the rule's commingling requirements
downhole commingling in new wells in areas where the BLM has
specifically recognized that downhole commingling is necessary to
ensure maximum economic recovery (such as when a lower formation is
necessary to produce an upper one) or when commingled production is
below certain levels; and, (3) Expressly recognizing as compliant CAAs
authorized by tribal law or agreement. As explained in this preamble,
the provisions related to grandfathering and the additional exemptions
were developed in response to comments and are consistent with the
exceptions in the original proposed rule.
As explained in Section III of this preamble, the requirements in
this final rule respond to the Subcommittee, GAO, and OIG
recommendations by updating, enhancing, clarifying, and codifying the
Order 3 requirements to reflect changes in technology, industry
practice, and applicable statutory requirements. The final rule also
responds to comments received during the public comment period on the
proposed rule.\7\ In aggregate, the provisions in the final rule help
ensure that the production of Federal and Indian (except Osage Tribe)
oil and gas is adequately accounted for. By replacing the patchwork of
guidance developed by BLM state and field offices, the final rule also
provides operators with a level of consistency as to the requirements
applicable to their operations on Federal and Indian (except Osage
Tribe) lands nationwide.
---------------------------------------------------------------------------
\7\ As explained in the preamble to the proposed rule, the
proposal was developed based, in part, on feedback received during a
series of public meetings held by the BLM on April 24 and 25, 2013.
The BLM also held public meetings and accepted comments in December
2015.
---------------------------------------------------------------------------
The Department of the Interior (Department) plays the critical role
of ensuring that the country's oil and gas assets are carefully
developed and that the American people, Indian tribes and individual
allottees receive fair compensation when these assets are leased and
developed. A key part of this role consists of providing reasonable
assurance that Federal and Indian oil and gas are accurately measured
and that measurement efforts undertaken by the private companies
developing these resources are held to high standards.
II. Overview of the Final Rule, Section-by-Section Analysis, and
Response to Comments
A. General Overview of the Final Rule
As discussed in the background section of this preamble, the BLM's
rules concerning site security and production accountability found in
Order 3 have not kept pace with industry standards and practices,
statutory requirements, or applicable measurement technology and
practices. This final rule enhances the BLM's overall production
accountability efforts by addressing these concerns and will ensure
that the oil and gas produced from Federal and Indian (except Osage
Tribe) leases is adequately accounted for, ultimately ensuring that all
royalties due are paid. The following table provides an overview of the
changes between the proposed rule and this final rule. A similar chart
explaining the differences between the proposed rule and Order 3
appears in the proposed rule at 80 FR 40771.
[[Page 81359]]
----------------------------------------------------------------------------------------------------------------
Proposed rule Final rule Substantive changes
----------------------------------------------------------------------------------------------------------------
43 CFR 3161.1(e) Jurisdiction........... 43 CFR 3161.1(b) The final rule removes a provision from
Jurisdiction. the proposed rule that could have
unintentionally extended the regulations
in part 3160 to State or private tracts
committed to a federally approved unit
or CA.
In its place, the BLM clarifies that the
regulations under part 3170, including
subparts 3173, 3174, and 3175, relating
to site security, measurement, reporting
of production and operations, and
assessments or penalties for non-
compliance with such requirements, apply
to all wells and facilities on State or
privately owned lands committed to a
unit or CA, which includes Federal or
Indian lease interests, notwithstanding
any contrary provision of the unit or
communization agreement.
43 CFR 3162.4-1(d) Well records and 43 CFR 3162.4-1(d) Well Consistent with the proposed rule,
reports. records and reports. paragraph (d) has been revised to
incorporate the new records-retention
period for Federal leases established by
the 1996 amendments to Federal Oil and
Gas Royalty Management Act (FOGRMA), 30
U.S.C. 1701 et seq. In the final rule,
that provision has been restructured
consistent with the changes in
paragraphs (c) through (e) of Sec.
3170.7.
None.................................... 43 CFR 3163.2 Generally.... The changes being made as part of this
rule are a combination of the changes
proposed as part of this rulemaking
effort and the proposed rule to update
and replace Order 5 (80 FR 61645). These
changes also reflect the modifications
made by the BLM's interim final rule--
Onshore Oil and Gas Operations--Civil
Penalties Inflation Adjustments (81 FR
41860) (the ``Civil Penalty Rule'')--
that updates the various daily penalty
maximums in this section.
Paragraph (a)(2) of the proposed rule is
carried forward into the final. The
final rule deletes existing paragraphs
(g) and (j) in their entirety and
redesignates existing paragraph (i) as
paragraph (g).
43 CFR 3163.2(a)(l) Civil penalties..... 43 CFR 3163.2(a)(1) Civil The final rule revises paragraph (a)(1)
penalties. of the proposed rule to clarify that
this section applies to ``any person,''
as opposed to limiting it to ``operating
rights owner or operator.'' This change
was proposed as part of the Order 5
rulemaking and conforms the regulation
to the applicable statutory authority.
43 CFR 3163.2(b)(l) Civil penalties..... 43 CFR 3163.2(b)(l) Civil The final rule changes the references in
penalties. the proposed rule to ``operating rights
owner, operator, purchaser, or
transporter'' to just ``the person''
consistent with the change to paragraph
(a)(1) to reference ``any person.''
Paragraph (b)(1) of the final also
reflects the increase in maximum daily
penalty from $500 to $1,031 made by the
BLM's Civil Penalty Rule.
43 CFR 3163.2(b)(2) Civil penalties..... 43 CFR 3163.2(b)(2) Civil The final rule changes the references in
penalties. the proposed rule to ``operating rights
owner, operator, purchaser, or
transporter'' to just ``the person''
consistent with the change to paragraph
(a)(1) to reference ``any person.''
Paragraph (b)(2) of the final rule also
reflects the increase in the maximum
daily penalty from $5,000 to $10,314
made by the BLM's Civil Penalty Rule.
43 CFR 3163.2(d) Civil penalties. 43 CFR 3163.2(d) Civil Consistent with the proposed rule to
Proposed as part of the Order 5 penalties. update and replace Order 5, the final
rulemaking. rule removes the regulatory cap on civil-
penalty assessments. It also reflects
the increase in maximum daily penalty
from $500 to $1,031 made by the BLM's
Civil Penalty Rule. Finally, it moves
the substance of existing paragraph (k)
to paragraph (d). As a result, paragraph
(k) is removed.
43 CFR 3163.2(e) Civil penalties. 43 CFR 3163.2(e) Civil Consistent with the proposed rule to
Proposed as part of the Order 5 penalties. update and replace Order 5, the final
rulemaking. rule removes the regulatory cap on civil
penalty assessments and reflects the
increase in maximum daily penalty from
$10,000 to $20,628 made by the BLM's
Civil Penalty Rule.
43 CFR 3163.2(f) Civil penalties. 43 CFR 3163.2(f) Civil Consistent with the proposed rule to
Proposed as part of the Order 5 penalties. update and replace Order 5, the final
rulemaking. rule removes the regulatory cap on civil
penalty assessments and reflects the
increase in the maximum daily penalty
from $25,000 to $51,570 made by the
BLM's Civil Penalty Rule.
43 CFR 3165.3(a) Notice, State Director 43 CFR 3165.3(a) Notice, The final rule clarifies in paragraph (a)
review and hearing on the record. State Director review and that any person is subject to written
hearing on the record. notice or order by the authorized
officer (AO) whenever they fail to
comply with any provisions of the lease,
the regulations in this part, applicable
orders or notices, or any other
appropriate order of the AO. The
proposed rule made this provision
applicable only to an operating rights
owner or operator, as appropriate.
43 CFR 3170.3 Definitions and acronyms.. 43 CFR 3170.3 Definitions New definitions have been added for the
and acronyms. terms ``averaging period,'' ``bias,''
and ``tampering'' in response to
comments received and additional
internal reviews.
In the final rule, the acronym Btu
(British thermal unit) is moved from
Sec. 3173.1 to this section, and new
acronyms--S&W (sediment and water) and
LACT (lease automatic custody transfer),
are included because they are used
across multiple subparts in part 3170.
[[Page 81360]]
43 CFR 3170.6(a)(2) Variances........... 43 CFR 3170.6(a)(2) Final paragraph (a)(2) adds a sentence
Variances. that encourages operators to
simultaneously submit variance requests
and plans or applications if those plans
or applications are contingent upon the
BLM approving the variance requests.
43 CFR 3170.6(a)(3) Variances........... 43 CFR 3170.6(a)(3) Final paragraph (a)(3) clarifies the
Variances. process operators must use to submit
their variance requests to the BLM--via
WIS, or, if the operator is a small
business without access to the Internet,
to the BLM office having jurisdiction
over the lease, unit, or CA.
43 CFR 3170.7(c) Required recordkeeping, 43 CFR 3170.7(c)(1) & Paragraph (c) did not change
records retention, and records (c)(2) Required substantively, but is split into two
submission. recordkeeping, records paragraphs. Paragraph (c)(1) states that
retention, and records records must be maintained for at least
submission. 7 years, and paragraph (c)(2) codifies
the applicable statutory requirements
for further retention beyond 7 years.
43 CFR 3170.7(d) Required recordkeeping, 43 CFR 3170.7(d)(1) & Paragraph (d) did not change
records retention, and records (d)(2) Required substantively, but is split into two
submission. recordkeeping, records paragraphs. Paragraph (d)(1) states that
retention, and records records must be maintained for at least
submission. 6 years, and subparagraph (d)(2)
codifies the applicable statutory
requirements for further retention
beyond 6 years.
43 CFR 3170.7(e) Required recordkeeping, 43 CFR 3170.7(e)(1) & The final rule moves paragraph (e)(2) of
records retention, and records (e)(2) Required the proposed rule to (e)(1) and removes
submission. recordkeeping, records the phrase ``or until the Secretary or
retention, and records his designee releases the record holder
submission. from the obligation to maintain the
records, whichever is later.''
The phrase in paragraph (e)(1) of the
proposed rule--``but a judicial
proceeding or demand is not commenced
within 7 years after the records are
generated, the record holder must retain
all records regarding production from
the unit or CA until the Secretary or
his designee releases the record holder
from the obligation to maintain the
records''--is moved to its own paragraph
(e)(2).
43 CFR 3170.7(g) Required recordkeeping, 43 CFR 3170.7(g) Required The final rule is revised to require
records retention, and records recordkeeping, records record holders to include the FMP number
submission. retention, and records or the lease, unit PA, or CA number,
submission. along with a unique equipment identifier
(e.g., a unique tank identification
number and meter station number), on all
their records.
3170.8 Appeal procedures................ 3170.8(a) & (b) Appeal The language from the proposed rule is
procedures. moved to a new paragraph (a) and a new
paragraph (b) is added that creates a
separate appeal process for decisions
made by the BLM, based on a
recommendation from the Production
Measurement Team (PMT). Under paragraph
(b), a party may file a request for
discretionary review by the Assistant
Secretary for Land and Minerals
Management (ASLM). Paragraph (b) also
provides that the ASLM may delegate this
review function.
3173.1 Definitions and acronyms......... 3173.1 Definitions and The final rule adds new definitions for
acronyms. the terms ``commingling and allocation
approval (CAA),'' ``free water,''
``permanent measurement facility,''
``payout period,'' and ``royalty net
present value'' in response to comments
on the proposed rule.
The term ``low volume property'' is
replaced with the term ``economically
marginal property,'' and the definition
has also been modified.
Lastly, the definition of the term ``land
description'' is modified to be
consistent with the well and facility
identification requirements contained in
Sec. 3162.6 of the final rule.
CAA (commingling and allocation approval)
is removed from the acronym list because
the acronym is introduced in the
definition section; BIA (Bureau of
Indian Affairs) is added to the list of
acronyms.
43 CFR 3173.3(a) Oil measurement system 43 CFR 3173.3(a) Oil The requirement in paragraph (a)(5) that
components--seals. measurement system flow computers be effectively sealed is
components--seals. removed and instead a new requirement is
added in paragraph (a)(6) that a LACT or
CMS must be effectively sealed.
Paragraph (a)(7) in the final rule
clarifies that sealing the back pressure
valve refers to the ``pressure
adjustment'' on the valve, not the valve
itself.
43 CFR 3173.6 Water-Draining operations. 43 CFR 3173.6 Water- The final rule removes the requirements
Draining operations. that, when draining water from a
production storage tank, operators,
purchasers, or transporters document the
FMP number associated with the tank, the
time for when the opening and closing
gauges took place, and the name of the
person and company draining the tank.
The final rule also clarifies that the
gauging operation may be performed
manually or automatically, to
accommodate the use of automatic tank
gauging systems. If gauging is performed
manually, the final rule no longer
specifies that the color cut method be
used for measurement. It leaves the
method for capturing the measurement up
to the operator and simply requires the
accuracy of the measurement to be to the
nearest \1/2\ inch.
[[Page 81361]]
The final rule also clarifies that during
the opening gauge operations, the total
observed volume (TOV) and free-water
measurements must be documented, while
during closing gauge operations only the
TOV must be measured, since the water
will have already been drained.
43 CFR 3173.7(a) Hot oiling, clean-up, 43 CFR 3173.7(a) Hot The final rule removes the requirements
and completion operations. oiling, clean-up, and that operators document the FMP number
completion operations. associated with the tank or group of
tanks involved in a hot oiling, clean-
up, or completion operation, the time at
which the opening and closing gauges
took place, and the name of the person
and company removing production from the
tank.
The final rule also clarifies that the
gauging operation may be performed
manually or automatically; the accuracy
of the measurement taken in either case
must be to the nearest \1/2\ inch.
43 CFR 3173.7(d) Hot oiling, clean-up, 43 CFR 3173.7(d) Hot Paragraph (d) of the final rule clarifies
and completion operations. oiling, clean-up, and that when reporting production used
completion operations. during hot oiling, line flushing, or
completion operations, the operator's
report must include ``the period
covering the production in question.''
None.................................... 43 CFR 3173.8(b)(8) Report In the final rule, a new reporting item
of theft or mishandling of is added to the list of information that
production. an operator must include in their
incident report: ``Whether the incident
was reported to local law enforcement
agencies and company security.'' This
change was made in response to comments.
43 CFR 3173.9(a) Required recordkeeping 43 CFR 3173.9(a) Required The final rule provides greater
for inventory and seal records. recordkeeping for flexibility in how an operator
inventory and seal records. determines the monthly volumes of
production in their tanks. Unlike the
proposed rule, where the operator was
required to measure the TOV at the end
of each calendar month, the final rule
allows the operator to either perform
the inventory within +/- 3 days of the
last day of the calendar month or
estimate the end of month inventory
based on daily production that takes
place between two measured inventories
that are not more than 31 days, nor less
than 20, days apart. An equation has
also been provided if the operator
elects to estimate the end-of-month
inventory instead of performing the
inventory at the end of the calendar
month.
43 CFR 3173.10(b) Form 3160-5, Sundry 43 CFR 3173.10(b) Form 3160- Paragraph (b) now clarifies the process
Notices and Reports on Wells. 5, Sundry Notices and operators must use to submit their
Reports on Wells. Sundry Notices to the BLM Office having
jurisdiction over the lease, unit, or
CA--namely via the applicable BLM
electronic filing system, unless the
operator is a small business without
access to the Internet.
43 CFR 3173.11(c)(10)(i) Site facility 43 CFR 3173.11(c)(9)(i) In paragraph (c)(9)(i), the final rule
diagram. Site facility diagram. removes the requirement to identify the
equipment manufacturer's name, rated
use, and equipment serial number for
each engine, motor, or major component
powered by production from the lease,
unit PA, or CA.
43 CFR 3173.11(c)(11) Site facility None....................... Proposed paragraph (c)(11) is eliminated.
diagram. The final rule does not require the
diagram to include a signature block to
certify accuracy and completeness of the
information contained within this site
facility diagram.
43 CFR 3173.11(c)(1) Site facility 43 CFR 3173.11(d)(1) Site Paragraph (c)(1) is eliminated in its
diagram. facility diagram. entirety and is replaced with paragraph
(d)(1), which now requires operators to
submit site facility diagrams for new
facilities within 30 days after the BLM
assigns an FMP to a facility. This is a
change from the proposed rule, which
required operators to submit diagrams
for new facilities within 30 days after
completing construction of the new
facilities.
43 CFR 3173.11(d) Site facility diagram. 43 CFR 3173.11(d)(2) Site Paragraph (d)(2), which applies to
facility diagram. facilities that require FMP numbers and
are in service before the effective date
of this final rule, is changed. Under
the final rule, if such a facility
already has a diagram on file with the
BLM that meets the minimum site-facility-
diagram requirements of Order 3, the
operator is not initially required to
submit a new diagram meeting the
requirements of this section. However,
the operator must submit a new site
facility diagram for the facility that
complies with this section within 30
days after the facility is modified, a
non-Federal facility located on a
Federal lease or federally approved unit
or communitized area is constructed or
modified, or there is a change in
operator.
43 CFR 3173.11(e) Site facility diagram. 43 CFR 3173.11(e)(1) Site Paragraph (e)(1) of the final rule
facility diagram. applies to new facilities in service
after the effective date of the final
rule that do not require an FMP number
(e.g., a water disposal facility). This
paragraph is revised to require the
operator of such a facility to submit a
new site facility diagram within 30 days
after that facility becomes operational.
[[Page 81362]]
None.................................... 43 CFR 3173.11(e)(2) Site A new paragraph (e)(2) is added, which
facility diagram. applies to facilities that do not
require an FMP number and are in service
before the effective date of the final
rule, is added to the final rule. If
such a facility already has a diagram on
file with the BLM that meets the minimum
requirements of Order 3, the operator is
not initially required to submit a
diagram meeting the requirements of this
section. However, the operator must
submit a new site facility diagram for
the facility that complies with this
section within 30 days after the
facility is modified, a non-Federal
facility located on a Federal lease or
federally approved unit or communitized
area is constructed or modified, or
there is a change in operator.
None.................................... 43 CFR 3173.11(f) Site The BLM added a new paragraph (f), which
facility diagram. requires operators to submit updated
site facility diagrams on an ongoing
basis within 30 days after that facility
is modified, a non-Federal facility
located on a Federal lease or federally
approved unit or communitized area is
constructed or modified, or there is a
change in operator.
43 CFR 3173.12(d) Applying for a 43 CFR 3173.12(d) Applying Paragraph (d) of this section applies to
facility measurement point. for a facility measurement measurement facilities that come into
point. service after the effective date of the
final rule. This paragraph is changed to
clarify that only ``permanent''
measurement facilities require an FMP
number, and not temporary measurement
equipment used during well-testing
operations. New language has also been
added that requires the operator to
``apply'' for FMP approval (as opposed
to ``obtaining'' FMP approval, as in the
proposed rule) before removing any
production from that facility. Finally,
this paragraph clarifies that an
operator must use the lease, unit PA, or
CA number for reporting production to
ONRR, until the BLM assigns an FMP
number. After the BLM assigns the FMP
number, the operator must use the FMP
number for all reporting to ONRR.
43 CFR 3173.12(e) Applying for a 43 CFR 3173.12(e) Applying The final rule clarifies that the
facility measurement point. for a facility measurement requirement to apply for an FMP for
point. facilities in service before the
effective date of the final rule applies
only to permanent measurement
facilities. The final rule also
clarifies that the production levels
that serve as the triggers for when an
operator must apply for an FMP for an
existing facility are based on the
production level of any one of the
leases, unit PAs, or CAs, whether or not
they are part of a CAA.
43 CFR 3173.12(e)(1) to (e)(3) Applying 43 CFR 3173.12(e)(1) to The deadlines for applying for FMP
for a facility measurement point. (e)(3) Applying for a numbers have been changed from 9 months,
facility measurement point. 18 months, and 27 months in the proposed
rule to 1 year, 2 years, and 3 years in
the final rule for existing producing
leases, unit PAs, and CAs. The deadlines
are based on the production levels of
any one of the leases, unit PAs, or CAs,
which have also been modified from the
proposed rule. Under the final rule,
those facilities that produce:
1. 10,000 Mcf or more for gas or 100 bbl
of oil or more--must file within 1 year
of the effective date;
2. 1,500 Mcf or more but less than 10,000
Mcf of gas per month or 10 bbl or more,
but less than 100 bbl of oil per month--
must file within 2 years; and
3. Less than 1,500 Mcf of gas per month
or less than 10 bbl of oil per month--
must file within 3 years.
None.................................... 43 CFR 3173.12(e)(4) A new paragraph (e)(4) is added to the
Applying for a facility final rule requiring the operator of a
measurement point. stand-alone lease, unit PA, or CA that
has not produced for a year or more
before the effective date of the final
rule to apply for an FMP prior to the
resumption of production.
43 CFR 3173.12(e)(5) Applying for a 43 CFR 3173.12(e)(6) Paragraph (e)(6) was paragraph (e)(5) in
facility measurement point. Applying for a facility the proposed rule, but is renumbered
measurement point. because of the addition of a new
paragraph (e)(4). The final rule also
clarifies that if the operator applies
for an FMP within the timeframes
outlined in paragraphs (e)(1) to (e)(3),
then the operator may continue using the
lease, unit PA, or CA number for
reporting production to ONRR, until the
effective date of the BLM-assigned FMP
number.
43 CFR 3173.12(f)(3) Applying for a 43 CFR 3173.12(f)(3) The final rule is revised and no longer
facility measurement point. Applying for a facility requires operators to identify the names
measurement point. and the manufacturer, model, and serial
number of each measurement component.
Paragraph (f)(3)(i) now requires
operators to submit the following
information on gas measurement
equipment:
The operator/purchaser/
transporter unique station number;
For primary elements, the meter
tube size or serial number; and
The type of secondary device,
whether it is mechanical or electronic.
[[Page 81363]]
Paragraph (f)(3)(ii) now requires
operators who measure oil tanks by tank
gauge to identify the equipment by
either the tank number or tank serial
number (The proposed rule required
operators to provide both pieces of
information.). The final rule adds a new
requirement that operators specify the
tank size(s), in barrels or gallons.
Paragraphs (f)(3)(iii) and (f)(3)(iv) of
the proposed rule have been combined
into a new paragraph (f)(3)(iii). This
paragraph now requires operators who
measure oil using LACT systems or CMSs
to identify the associated oil tank
number(s) or tank serial number(s), the
size of the tank(s) in barrels or
gallons, and whether the equipment used
is a LACT system or CMS.
43 CFR 3173.12(f)(4) Applying for a None....................... The final rule removes the requirement in
facility measurement point. paragraph (f)(4) to identify the gas
sampling method for gas measurements.
Paragraph (f)(5) in the proposed rule is
now renumbered to paragraph (f)(4) in
the final rule and is unchanged.
None.................................... 43 CFR 3173.12(f)(5) New paragraph (f)(5) adds to the list of
Applying for a facility information that operators must include
measurement point. in their FMP request.
43 CFR 3173.12(g) Applying for a 43 CFR 3173.12(g) Applying Language is added to clarify that FMP
facility measurement point. for a facility measurement requests--if they are submitted
point. concurrently with requests for off-lease
measurement or commingling and
allocation approvals--must be submitted
separately from the other requests.
43 CFR 3173.12(h) Applying for a None....................... Paragraph (h) is eliminated from the
facility measurement point. final rule because it was determined to
be redundant.
43 CFR 3173.13(a) and (b) Requirements None....................... The final rule removes the requirement
for approved facility measurement for operators to stamp or stencil the
points. FMP number on a fixed plate onto various
pieces of oil and gas measurement
equipment and to maintain the number in
a legible condition.
43 CFR 3173.13(c) Requirements for 43 CFR 3173.13(a) The final rule removes the requirement
approved facility measurement points. Requirements for approved for operators to begin using the FMP
facility measurement number for recordkeeping on the first
points. day of the month after the FMP number is
assigned.
A new provision is incorporated into
paragraph (a) in the final rule that
requires operators of existing
facilities to begin using their FMP
numbers for reporting production to the
Office of Natural Resources Revenue
(ONRR) on their Oil and Gas Operations
Report (OGOR) for the fourth production
month after the BLM assigns the FMP
numbers. Operators of new facilities in
service after this rule's effective date
must start using their FMP numbers for
production reporting on their OGORs for
the first production month after the BLM
assigns the FMP numbers.
43 CFR 3173.13(d)(1) and (d)(2) 43 CFR 3173.13(b)(1) Paragraph (b)(1) in the final rule
Requirements for approved facility Requirements for approved requires operators to notify the BLM via
measurement points. facility measurement a Sundry Notice within 30 days after
points. changing or modifying an FMP (the
proposed rule gave operators 20 business
days). This paragraph also describes the
types of changes that require the
operator to submit a Sundry Notice,
e.g., changes in the metering equipment
or the wells served by the FMP.
Paragraph (b)(1) also clarifies that
temporary modifications, such as those
made for maintenance purposes, do not
require the filing of a Sundry Notice.
The final rule removes the requirement
in proposed paragraph (d)(2) that
operators provide information about the
old and new meter manufacturer, serial
number(s), and the owner's name.
None.................................... 43 CFR 3173.13(b)(2) The final rule adds a new requirement
Requirements for approved that the operator's description of any
facility measurement modifications being made include
points. details, such as the primary element,
secondary element, LACT/CMS meter, tank
number(s), and wells or facilities using
the FMP.
43 CFR 3173.13(d)(3) Requirements for 43 CFR 3173.13(b)(3) Final paragraph (b)(3) removes the
approved facility measurement points. Requirements for approved requirement that operators specify why a
facility measurement change was made to a piece of equipment.
points.
43 CFR 3173.14(a) Conditions for 43 CFR 3173.14(a) Final paragraph (a) is modified so that
commingling and allocation approval Conditions for commingling it explicitly states that the criteria
(surface and downhole). and allocation approval the BLM uses to approve a commingling
(surface and downhole). application under this paragraph is when
the proposed allocation method used for
commingled measurement does not have the
potential to affect the BLM's
determination of the total volume or
quality of the production on which
royalty is owed for all of the Federal
or Indian leases, unit PAs, or CAs which
are proposed for commingling.
3173.14(a)(1)(i) Conditions for 3173.14(a)(1)(i) Conditions Paragraph (a)(1)(i) clarifies that
commingling and allocation approval for commingling and commingling is permissible when it
(surface and downhole). allocation approval involves properties that contain 100
(surface and downhole). percent Federal mineral interests, the
same fixed royalty rate, and the same
revenue distribution.
3173.14(a)(1)(ii) Conditions for 3173.14(a)(1)(ii) Paragraph (a)(1)(ii) clarifies that
commingling and allocation approval Conditions for commingling commingling is permissible when it
(surface and downhole). and allocation approval involves properties that are wholly
(surface and downhole). owned by the same tribe and have the
same fixed royalty rate.
[[Page 81364]]
None.................................... 3173.14(a)(1)(iii) A new paragraph (a)(1)(iii) is added
Conditions for commingling which clarifies that commingling of
and allocation approval Federal unit PAs or CAs is permissible
(surface and downhole). even if Federal ownership is not 100
percent, so long as the properties have
the same proportion of Federal
ownership, royalty rate and revenue
distribution.
None.................................... 3173.14(a)(1)(iv) A new paragraph (a)(1)(iv) is added which
Conditions for commingling clarifies that commingling of tribal
and allocation approval unit PAs or CAs is permissible even if
(surface and downhole). tribal ownership is not 100 percent, so
long as the properties have the same
proportion of tribal interest and fixed
royalty rate.
3173.14(a)(2) Conditions for commingling 3173.14(a)(2) Conditions This paragraph recognizes there are cases
and allocation approval (surface and for commingling and where multiple operators are party to a
downhole). allocation approval CAA and clarifies that there must be a
(surface and downhole). signed agreement amongst the operators
about the allocation methodology for the
commingling proposal.
None.................................... 3173.14(b) Conditions for To complement paragraphs (a)(1)(iii) and
commingling and allocation (a)(1)(iv) to this section, paragraph
approval (surface and (b) clarifies that the BLM may consider
downhole). commingling that involves production
from properties with different royalty
rates or revenue distributions, or
multiple mineral ownerships.
3173.14(b)(1) Conditions for commingling 3173.14(b)(1) Conditions This paragraph is revised to reflect the
and allocation approval (surface and for commingling and BLM's switch from the term ``low-volume
downhole). allocation approval property'' to ``economically marginal
(surface and downhole). property.'' It also clarifies that if
the BLM determines that a Federal or
Indian lease, unit PA, or CA included in
a CAA ceases to be an economically
marginal property, then (b)(1) is no
longer met.
3173.14(b)(2) Conditions for commingling 3173.14(b)(2) Conditions In the proposed rule, paragraph (b)(2)
and allocation approval (surface and for commingling and allowed operators to be exempted from
downhole). allocation approval the BLM's commingling standards if there
(surface and downhole). are overriding considerations that
indicated approval of the CAA was
appropriate in spite of royalty impacts.
In the final rule, this provision is
replaced with a new exemption if the
average monthly production rate over the
previous 12 months for each Federal or
Indian lease, unit PA, and CA included
in the CAA is less than 1,000 Mcf of gas
per month or 100 bbl of oil per month.
Paragraph (b)(2) from the proposed rule
is now renumbered as paragraph (b)(5).
3173.14(b)(3) Conditions for commingling 3173.14(b)(3) Conditions New paragraph (b)(3) of the final rule
and allocation approval (surface and for commingling and adds a new exemption that allows the BLM
downhole). allocation approval to consider approval of a commingling
(surface and downhole). proposal that includes Indian leases,
unit PAs, or CAs that has been
authorized under tribal law or otherwise
approved by a tribe.
In the proposed rule, paragraph (b)(3)
required the BLM to ensure that approval
of a CAA in cases where the CAA would be
exempted from the standards in this rule
was in the public interest. This
paragraph is eliminated and incorporated
into the new paragraph (b)(5).
None.................................... 3173.14(b)(4) Conditions A new exemption is included as part of
for commingling and the final rule that allows the BLM to
allocation approval consider a commingling proposal if it
(surface and downhole). covers the downhole commingling of
production from multiple formations
where the BLM has determined that the
proposed commingling is an acceptable
practice for the purpose of achieving
maximum ultimate economic recovery and
resource conservation.
43 CFR 3173.15(a)(1) and (a)(2) Applying 43 CFR 3173.15(a) Applying Paragraph (a) of the final rule
for a commingling and allocation for a commingling and eliminates the numbering for paragraph
approval. allocation approval. (a)(1) in the proposed rule, and
clarifies that if off-lease measurement
is a feature of the commingling
proposal, then a separate Sundry Notice
requesting approval for off-lease
measurement is not necessary as long as
the off-lease measurement request is
included as part of the commingling
application and the information required
in Sec. 3173.23(b) through (e) and,
where applicable, Sec. 3173.23(f)
through (i) is included in the
commingling application.
3173.15(a)(2) Applying for a commingling 43 CFR 3173.15(b).......... Paragraph (a)(2) from the proposed rule
and allocation approval. is renumbered to a new paragraph (b) and
clarifies that submission of a completed
Sundry Notice for approval of off-lease
measurement is required if any of the
proposed FMPs are outside the boundaries
of any lease, unit PA, or CA whose
production would be commingled. This
paragraph clarifies that this
requirement does not apply if the
circumstances under paragraph (a) of
this section are applicable.
43 CFR 3173.15(b) Applying for a 43 CFR 3173.15(c) Applying In addition to requiring operators to
commingling and allocation approval. for a commingling and provide their proposed allocation
allocation approval. agreement, final paragraph (c) is
revised to require operators to provide
an allocation methodology, along with an
example of how the methodology is to be
applied.
None.................................... 43 CFR 3173.15(d).......... Requires the operator to include a list
of all Federal or Indian lease, unit PA,
or CA numbers in the proposed CAA,
specifying the type of production (i.e.,
oil, gas, or both) for which commingling
is requested.
[[Page 81365]]
43 CFR 3173.15(d) Applying for a 43 CFR 3173.15(e) Applying Final paragraph (e) continues to require
commingling and allocation approval. for a commingling and operators to provide maps with their
allocation approval. commingling and allocation requests, but
the information requirements for the
maps are changed. Please note that in
the final rule, paragraphs (d)(2) and
(d)(3) have been consolidated and
renumbered as paragraphs (e)(1) and
(e)(2) in the final rule. The final rule
also reduces the amount of information
that must be submitted with a
commingling application relative to the
proposed rule.\8\
43 CFR 3173.15(e) Applying for a None....................... Proposed paragraph (e), which required
commingling and allocation approval. submission a site facility diagram
showing any changes to existing diagrams
if changes were being proposed to an
existing facility, is eliminated from
the final rule.
43 CFR 3173.15(f) Applying for a None....................... Proposed paragraph (f), which required
commingling and allocation approval. submission of a schematic or engineering
drawing for all new proposed facilities,
is eliminated from the final rule.
43 CFR 3173.15(g) Applying for a 43 CFR 3173.15(f) Applying Paragraph (f) of the final rule
commingling and allocation approval. for a commingling and (paragraph (g) of the proposed rule) is
allocation approval. revised to clarify that operators must
submit a surface use plan of operations
if new surface disturbance is proposed
for the FMP and its associated
facilities, if those facilities are
located on BLM-managed land within the
boundaries of the lease, units, or
communitized areas whose production will
be commingled.
43 CFR 3173.15(h) Applying for a 43 CFR 3173.15(g) Applying Final paragraph (g) clarifies that the
commingling and allocation approval. for a commingling and operator must submit a right-of-way
allocation approval. grant application (Standard Form 299) if
the proposed FMP is on a pipeline or is
a meter or storage tank that entails new
surface disturbance located on BLM-
managed land outside any of the leases,
units, or communitized areas whose
production would be commingled.
43 CFR 3173.15(i) Applying for a 43 CFR 3173.15(h) Applying Final paragraph (h) is essentially the
commingling and allocation approval. for a commingling and same as proposed paragraph (i) but is
allocation approval. renumbered.
None.................................... 43 CFR 3173.15(i) Applying A new final paragraph (i) has been added
for a commingling and to clarify that the operator must submit
allocation approval. a right-of-way grant application to the
appropriate BIA office if any of the
proposed surface facilities are on
Indian land outside the lease, unit, or
communitized area from which the
production would be commingled.
None.................................... 43 CFR 3173.15(j).......... Requires the operator to include
documentation demonstrating that each of
the leases, unit PAs, or CAs proposed
for inclusion in the CAA is producing or
capable of production in paying
quantities.
43 CFR 3173.15(k) Applying for a 43 CFR 3173.15(k) Applying Final paragraph (k) clarifies that gas
commingling and allocation approval. for a commingling and analysis and oil gravity data is not
allocation approval. needed if the CAA falls under Sec.
3173.14(a).
43 CFR 3173.16(a) Existing commingling 43 CFR 3173.16(a) Existing This section is extensively rewritten
and allocation approvals. commingling and allocation from the proposed rule based on comments
approvals. received. Final paragraph (a) includes
new provisions that grandfather the
following types of existing commingling
operations and their associated off-
lease measurement approvals, where
applicable, that are in effect prior to
the effective date of the final rule:
Existing CAAs involving downhole
commingling that includes Federal or
Indian leases, unit PAs, or CAs; or
Existing CAAs for surface
commingling whose average production
rate over the previous 12 months for
each Federal or Indian lease, unit PA,
and CA included in the CAA is less than
1,000 Mcf of gas per month or 100 bbl of
oil per month.
43 CFR 3173.16(b) Existing commingling 43 CFR 3173.16(b) Existing A new provision has been added to
and allocation approvals. commingling and allocation paragraph (b), which clarifies that if
approvals. the grandfathering conditions in
paragraph (a) of this section are not
met, then the existing CAA must meet the
minimum standards and requirements for a
CAA under Sec. 3173.14 of the final
rule.
This section also clarifies that the AO
will notify the operator in writing of
any inconsistencies or deficiencies with
an existing CAA. When the AO is
satisfied that the operator has
corrected any inconsistencies or
deficiencies, the AO will terminate the
existing CAA and grant a new CAA based
on the operator's corrections.
43 CFR 3173.16(c) Existing commingling 43 CFR 3173.16(b)(2) Paragraph (b)(2) of the final rule
and allocation approvals. Existing commingling and clarifies that the AO may terminate an
allocation approvals. existing CAA and grant a new CAA with
new or amended COAs to make the approval
consistent with the requirements for
CAAs under Sec. 3173.14 of the final
rule. Under the proposed rule the AO
could simply impose new or amended COAs
to an existing commingling approval.
43 CFR 3173.16(e) Existing commingling 43 CFR 3173.16(c) Existing Proposed paragraph (e) is now paragraph
and allocation approvals. commingling and allocation (c) and clarifies that any new
approvals. allocation percentages resulting from
the new CAA will only apply from the
effective date of the CAA forward.
[[Page 81366]]
43 CFR 3173.18(a) Modification of a 43 CFR 3173.18(a) Paragraph (a) is changed to require
commingling and allocation approval. Modification of a operators to modify a CAA under certain
commingling and allocation circumstances. The final rule no longer
approval. includes ``a change in operator'' in the
list of circumstances that warrant a CAA
modification.
43 CFR 3173.18(b) Modification of a 43 CFR 3173.18(b) Final paragraph (b)(2) includes a new
commingling and allocation approval. Modification of a requirement to describe not only a new
commingling and allocation allocation methodology for oil and gas
approval. production, if appropriate, but also an
allocation methodology for produced
water and an example of how the
methodology is applied.
None.................................... 43 CFR 3173.18(c) A new paragraph (c) is added that states
Modification of a that a change in operator does not
commingling and allocation trigger the need to modify a CAA.
approval.
43 CFR 3173.20(a) Terminating a 43 CFR 3173.20(c) The final rule redesignates and modifies
commingling and allocation approval. Terminating a commingling proposed paragraph (a), which allows any
and allocation approval. operator who is a party to a CAA to
unilaterally terminate the CAA.
New paragraph (c) in the final rule
clarifies that it allows an operator to
terminate the CAA through the submission
of a Sundry Notice to the BLM. It also
clarifies that the termination by one
operator does not terminate the CAA for
all other operators, so long as the
requirements of this part with respect
to CAAs are still met as to the
remaining operators and they submit a
Sundry Notice requesting a new CAA as
required by Sec. 3173.20(e).
43 CFR 3173.20(d) Terminating a 43 CFR 3173.20(d) Paragraph (d) of the final rule clarifies
commingling and allocation approval. Terminating a commingling that the BLM will notify all parties to
and allocation approval. a CAA the effective date of the
termination and the inconsistencies or
deficiencies with their CAA that serve
as the reason(s) for termination.
The final rule also gives operators the
opportunity to correct the
inconsistencies or deficiencies, or
provide additional information, within
20 business days after receipt of the
BLM's notice. Otherwise, the CAA will be
terminated.
43 CFR 3173.20(e) Terminating a 43 CFR 3173.20(e) Paragraph (e) of the final rule clarifies
commingling and allocation approval. Terminating a commingling that if a CAA is terminated, each lease,
and allocation approval. unit PA, or CA that was included in the
CAA may require a new FMP number, or a
new CAA may need to be applied for. In
such cases, operators will have 30 days
to apply for a new FMP number or CAA.
Unlike the proposed rule--where
operators would have been required to
revert back to separate measurement for
each lease, unit PA, or CA--the final
rule allows the operator to use the
existing FMP number for production
reporting until a new FMP number is
assigned or a new CAA is approved.
43 CFR 3173.21(b) Combining production 43 CFR 3173.21(b) Combining Paragraph (b) makes clear that combining
downhole in certain circumstances. production downhole in production downhole from different
certain circumstances. geologic formations on the same lease in
a single well is not considered to be
commingling for production accounting
purposes. This applies even in cases
where the respective geologic formations
have different ownership. The proposed
rule made this distinction, which no
longer applies in the final rule.
The final rule also clarifies that such
activities are not subject to the
commingling standards and requirements
contained in Sec. Sec. 3173.14
through 3173.20.
43 CFR 3173.22(c) Requirements for off- 43 CFR 3173.22(c) Changes to this paragraph clarify that
lease measurement. Requirements for off-lease topographic and environmental issues
measurement. that make on-lease measurement
physically impractical are factors to be
considered when deciding if off-lease
measurement is in the public interest.
43 CFR 3173.23(a) Applying for off-lease 43 CFR 3173.23(a) Applying The second sentence of proposed paragraph
Measurement. for off-lease Measurement. (a) is removed because Sec. 3173.15(a)
states that if off-lease measurement is
a feature of the CAA proposal, then a
separate Sundry Notice is not necessary
as long as the information required
under Sec. 3173.23(b) through (e) and,
where applicable, Sec. 3173.23(f)
through (i), is included as part of the
request for approval of a CAA.
43 CFR 3173.23(c)(2) Applying for off- 43 CFR 3173.23(c)(2) The final rule in this paragraph no
lease Measurement. Applying for off-lease longer requires location identification
Measurement. by land description, but does include a
new requirement to identify existing or
proposed (to the extent known) FMPs.
43 CFR 3173.23(d) Applying for off-lease None....................... Paragraph (d) of the proposed rule
Measurement. requiring operators to submit a
schematic or engineering drawing for all
new proposed facilities is deleted.
43 CFR 3173.23(e) Applying for off-lease None....................... Paragraph (e) of the proposed rule, which
Measurement. required operators to submit as part of
their off-lease measurement application,
site facility diagrams clearly showing
any proposed change to current site
facility diagrams for existing
facilities is deleted.
[[Page 81367]]
43 CFR 3173.23(f) Applying for off-lease 43 CFR 3173.23(e) Applying In the event there is a change in the
Measurement. for off-lease Measurement. ownership of the non-Federal surface or
of the measurement facilities, the final
rule includes a new 30-day deadline for
when an operator must submit written
concurrence from the new owner that it
will give the BLM unrestricted access to
the off-lease measurement facility and
the surface on which it is located to
inspect the FMP and any associated
equipment.
43 CFR 3173.23(g) Applying for off-lease 43 CFR 3173.23(f) Applying Final paragraph (f) clarifies that if the
Measurement. for off-lease Measurement. proposed off-lease FMP is on a pipeline
or is a meter or storage tank, then a
right-of-way grant application using
Standard Form 299 must be submitted.
This paragraph also clarifies that this
requirement applies only when new
surface disturbance is proposed for the
FMP and its associated facilities are
located on BLM-managed land.
43 CFR 3173.23(h) Applying for off-lease 43 CFR 3173.23(g) Applying Final paragraph (g) (re-lettered from
Measurement. for off-lease Measurement. paragraph (h)) clarifies that if any of
the proposed surface facilities are on
Indian land outside the lease, unit, or
communitized area, then a right-of-way
grant application filed under 25 CFR
part 169 must be filed with the
appropriate BIA office.
None.................................... 43 CFR 3173.23(h) Applying The final rule adds a new paragraph (h)
for off-lease Measurement. that requires written approval from the
appropriate surface-management agency if
new surface disturbance is proposed for
the FMP and its associated facilities
are located on Federal land managed by
an agency other than the BLM.
3173.25(b) Existing approved off-lease 3173.25(b) Existing Paragraph (b) of the final rule has been
measurement. approved off-lease revised to provide an opportunity for
measurement. operators to request additional time to
correct any inconsistencies or
deficiencies that the AO identifies.
This paragraph also clarifies that the
extension request must explain the
factors preventing the operator from
timely compliance.
3173.25(c) Existing approved off-lease 3173.25(c) Existing Paragraph (c) of the final rule clarifies
measurement. approved off-lease that if new or amended conditions of
measurement. approval (COAs) are necessary to make an
existing off-lease measurement approval
consistent with the final rule's
standards, then the BLM could address
that situation by terminating the
existing approval and issuing a new off-
lease measurement approval with new or
amended COAs.
None.................................... 43 CFR 3173.25(e) Existing A new paragraph (e) is added to the final
approved off-lease rule, clarifying that if the existing
measurement. off-lease measurement approval under
this section is consistent with the
requirements under Sec. 3173.22, then
that existing off-lease measurement is
grandfathered and will be part of its
FMP approval.
43 CFR 3173.25(e) Existing approved off- 43 CFR 3173.25(f) Existing Proposed paragraph (e) is re-lettered to
lease measurement. approved off-lease paragraph (f).
measurement.
43 CFR 3173.27(a) Termination of off- 43 CFR 3173.27(c) Proposed paragraph (a) is deleted from
lease measurement approval. Termination of off-lease the final rule and the provision in that
measurement approval. paragraph allowing an operator to
terminate off-lease measurement is moved
to paragraph (c).
43 CFR 3173.27(b) Termination of off- 43 CFR 3173.27(a) Paragraphs re-lettered. No change.
lease measurement approval. Termination of off-lease
measurement approval.
43 CFR 3173.27(c) Termination of off- 43 CFR 3173.27(b) Final paragraph (b) is changed to say the
lease measurement approval. Termination of off-lease BLM will notify the operator in writing
measurement approval. of any inconsistencies or deficiencies
with its off-lease measurement approval
that serve as the reason(s) for
termination.
The final rule is also changed to give
the operator 20 business days after
receipt of the notification to correct
the inconsistencies or deficiencies that
the BLM identifies, or provide
additional information that the AO
requests, or the off lease measurement
approval terminates. The operator may
request an extension of the 20-business-
day timeframe.
43 CFR 3173.27(d) Termination of off- 43 CFR 3173.27(d) Final paragraph (d) explains that if an
lease measurement approval. Termination of off-lease off lease measurement approval is
measurement approval. terminated, each lease, unit PA, or CA
that was in the approval may require a
new FMP number(s) or a new off lease
measurement approval. Operators will
have 30 days to apply for a new FMP
number or off lease measurement
approval. The final rule allows
operators to use the existing FMP number
for production reporting until a new FMP
number is assigned or a new off lease
measurement approval is approved.
43 CFR 3173.29 Immediate assessments.... 43 CFR 3173.29 Immediate The final rule exempts purchasers and
assessments. transporters from the immediate
assessments that will be imposed for
certain instances of non-compliance. In
addition, the final rule modifies the
description of violations number 7
through 11.
For violation number 7, the
final rule clarifies that the applicable
regulation is Sec. 3170.7, not Sec.
3173.9(a)(1) and (a)(2).
[[Page 81368]]
For violation 8, the final rule
clarifies that an immediate assessment
could result if operators fail to
``apply for'' the required FMP approval.
The proposed rule required operators to
``obtain'' FMP approval.
For violations 9, 10, and 11,
the final rule clarifies that an
immediate assessment could result if
production is removed from a facility in
operation after the effective of the
final rule prior to receiving BLM
approval for off-lease measurement or
commingling. For an existing facility in
service on or before the effective date
of the final rule, an immediate
assessment could result if production is
removed from a facility that does not
already have an existing BLM approval
for off-lease measurement or
commingling, if applicable.
----------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\8\ Specifically, the final rule no longer requires the
commingling application to include the following items: (i) The land
description of the FMP that will be used to measure the commingled
production; (ii) Production facilities and flow lines proposed to be
installed to the extent known; and (iii) A map or diagram showing
all of the infrastructure-related facilities that are part of the
commingling proposal. The final rule only requires identification of
existing or planned facilities, all wellheads, and piping that will
be included in the CAA, as well as existing or proposed FMPs to be
installed (if known).
---------------------------------------------------------------------------
B. Section-by-Section Analysis and Response to Comments on Specific
Provisions
This final rule is codified primarily in a new 43 CFR subpart 3173
within a new part 3170. The BLM is also issuing final rules that update
and replace Order 4 (oil measurement) and Order 5 (gas measurement).
Those final rules are codified at new 43 CFR subparts 3174 and 3175,
respectively, within the new part 3170. Subpart 3170 of this final rule
contains definitions of certain terms and provisions that are common to
all three rules (and to any other provisions within part 3170), i.e.,
provisions prohibiting by-pass of or tampering with meters; procedures
for obtaining variances from the requirements of a particular rule;
requirements for recordkeeping, records retention, and submission; and
administrative appeal procedures.
In addition, this final rule makes changes to various provisions in
43 CFR part 3160 and in 43 CFR 3161.1, 3162.3-2, 3162.4-1, 3162.6,
3162.7-1, 3163.2, and 3165.3. Public comments on changes to the
provisions in part 3160 are discussed in connection with the new
subparts 3170 or 3173 provisions to which the particular comment
relates. Other comments on changes to provisions in part 3160 are
discussed at the end of this Section-by-Section analysis.
Subpart 3170 and Related Provisions
Section 3170.1 Authority
Section 3170.1 of the final rule identifies the various grants of
rulemaking authority in the Federal and Indian mineral leasing statutes
and related statutes that give the Secretary authority to promulgate
this rule. As explained in that section, the Department is authorized
to lease Federal and Indian (except Osage Tribe) oil and gas under
various mineral leasing statutes, including the Mineral Leasing Act, 30
U.S.C. 181 et seq.; the Mineral Leasing Act for Acquired Lands, 30
U.S.C. 351 et seq.; the Federal Oil and Gas Royalty Management Act
(FOGRMA), 30 U.S.C. 1701 et seq.; the Indian Mineral Leasing Act, 25
U.S.C. 396a et seq.; the Act of March 3, 1909, 25 U.S.C. 396; the
Indian Mineral Development Act, 25 U.S.C. 2101 et seq.; and the Federal
Land Policy and Management Act (FLPMA), 43 U.S.C. 1701 et seq.
Each of these statutes expressly authorizes the Secretary of the
Interior to promulgate necessary and appropriate rules and regulations
governing those leases. See e.g., 30 U.S.C. 189; 30 U.S.C. 359; 30
U.S.C. 1751; 25 U.S.C. 396d; 25 U.S.C. 396; 25 U.S.C. 2107; and 43
U.S.C 1740. The Secretary has delegated this authority to the Bureau of
Land Management (BLM). Specifically, under Secretarial Order Number
3087, dated December 3, 1982, as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual (235 DM 1.1), the Secretary has
delegated regulatory authority over onshore oil and gas development on
Federal and Indian (except Osage Tribe) lands to the BLM. For Indian
leases, the delegation of authority to the BLM is reflected in 25 CFR
parts 211, 212, 213, 225, and 227. In addition, as authorized by 43
U.S.C. 1731(a), the Secretary has delegated to the BLM regulatory
responsibility for oil and gas operations in Indian lands. 235 DM
1.1.K.
These statutes and regulations form the basis of and provide the
authority for the issuance of this final rule. For example, Sec.
101(a) of FOGRMA directs the Secretary to ``establish a comprehensive
inspection, collection and fiscal and production accounting and
auditing system to provide the capability to accurately determine oil
and gas royalties, interest, fines, penalties, fees, deposits, and
other payments owed, and to collect and account for such amounts in a
timely manner.'' Ensuring that oil and gas produced from Federal and
Indian leases is accurately measured and properly accounted for is a
critical component of any system to ensure that all royalties due are
paid. Under Sec. 101(a) of FOGRMA, the Secretary is authorized to
promulgate ``such rules and regulations as [s]he deems reasonably
necessary to carry out.'' the purposes of the act. The FOGRMA mandate
complements the policy articulated in FLPMA that the United States
receive fair compensation for the use of public lands and resources.
See 43 U.S.C. 1701(a)(9). This rule, by improving BLM requirements
governing site security and related measures, helps ensure that all
royalties due are paid, and thus that the United States receives fair
compensation for the use of public minerals.
The BLM did not receive any public comments related to this
provision and only made minor changes for clarity between the proposed
and final versions.
Section 3170.2 Scope
Section 3170.2(a) explains that the regulations in part 3170 apply
to all onshore Federal and Indian (except Osage Tribe) oil and gas
leases. Paragraph (b) explains that part 3170 also applies to
agreements for oil and gas development under the Indian Mineral
Development Act, unless the relevant provisions of the rule are
inconsistent with the specific terms of such agreement. Paragraph (c)
explains that a Tribal Energy Resource Agreement entered into with the
[[Page 81369]]
Secretary is subject to part 3170, unless specifically excluded in such
lease, other business agreement or Tribal Energy Resource Agreement.
Paragraph (d) explains that State or private tracts committed to a
federally approved unit or CA as defined by or established under 43 CFR
subpart 3105 or 43 CFR part 3180 are also subject to the requirements
of part 3170. Finally, paragraph (e) states that all FMPs measuring
production from any of the aforementioned leases or agreements are
subject to the requirements of part 3170.
The BLM received several comments expressing concern with proposed
paragraph (d), which applies the part 3170 regulations to State or
private tracts committed to a federally approved unit or CA as defined
by or established under 43 CFR subpart 3105 or 43 CFR part 3180. The
same language also appeared in a new paragraph (e) that was proposed to
be added to Sec. 3161.1 Jurisdiction. Comments received on both
sections are discussed here.
Many commenters thought that the new paragraph (e) language
proposed for Sec. 3161.1 would extend the BLM's jurisdiction over oil
and gas to activities that are not covered by this rule. Specifically,
commenters were concerned that adding the proposed language to Sec.
3161.1 and also to proposed Sec. 3170.2 would expand the BLM's
authority over the processing and approval of Applications for Permits
to Drill (APDs) within State and private tracts committed to a BLM-
approved Federal or Indian unit or CA. Commenters said that such an
expansion of authority would force operators to obtain Federal drilling
permits for drilling on State and private tracts. From the commenters'
perspective, this perceived expansion in jurisdiction would
fundamentally alter the way in which operators plan for development.
The BLM disagrees with this interpretation of the new language and
never intended for this rule to extend the BLM's permitting authority
over State and private drilling approvals. However, to avoid confusion,
the BLM in this final rule added a new paragraph (b) to its Sec.
3161.1 revisions, which clarifies that it is the regulations in parts
3160 and 3170 relating to site security, measurement, reporting of
production and operations, and assessments or penalties for non-
compliance with such requirements (i.e., those found in subparts 3173,
3174, and 3175) that are applicable to all wells and facilities on
State or privately owned lands committed to a unit or CA where the unit
or CA affects Federal or Indian interests. Proposed Sec. 3170.2(d) has
not been changed because it is appropriate for this rule to state that
the regulations under part 3170, which includes subparts 3173, 3174,
and 3175, do in fact apply to State or private tracts committed to a
federally approved unit or CA as defined by or established under 43 CFR
subpart 3105 or 43 CFR part 3180. This is consistent with the BLM's
past application of its regulations, including its Onshore Orders,
under existing 43 CFR 3161.1(b).
Section 3170.3 Definitions and Acronyms
This section defines terms and acronyms used across all of the
various subparts of part 3170.
The BLM did not receive any comments on the majority of the
definitions that appeared in the proposed rule and that are now in the
final rule. Those definitions for which we received no comments were
carried forward in this final rule and are not discussed further here.
As explained in the proposed rule, a number of the definitions in Sec.
3170.3 of the proposed rule were the same definitions that were found
in Order 3, with only minor revisions to either simplify or clarify
those definitions.
The following discussion first describes the new definitions that
have been added to Sec. 3170.3 in the final rule, and then summarizes
and responds to comments that the BLM received on a handful of the
proposed definitions. With respect to the former, based on comments
received and its own internal reviews, the BLM added three new
definitions to Sec. 3170.3: ``Averaging period,'' ``bias,'' and
``tampering.'' As explained below some of these definitions were
originally proposed as part of the proposed rules to replace Order 4
(80 FR 58952) and Order 5 (80 CFR 61646). The BLM determined that it
was appropriate to move those definitions from those rulemakings to
Sec. 3170.3, because the terms are used in multiple subparts, and
should therefore be defined once in a section that covers the entirety
of part 3170. Other definitions were added in response to public
comments.
The final rule defines ``averaging period'' to mean the previous 12
months or the life of the meter, whichever is shorter. For FMPs that
measure production from a newly drilled well, the averaging period
excludes production from that well that occurred in or before the first
full month after production began. For example, if an oil FMP or a gas
FMP were installed to measure the production from a new well that first
produced on April 10, the averaging period for this FMP would not
include the production that occurred in April and May of that year. The
BLM added this definition to Sec. 3170.3 because the term is used
multiple times in subparts 3174 (oil measurement) and 3175 (gas
measurement), relating to the applicability of uncertainty threshold
requirements. The BLM determined it was important to provide a single
definition of the averaging period in order to provide for consistent
application of the BLM's oil and gas measurement rules.
The final rule adds a definition for the term ``bias'' to Sec.
3170.3 because that term is used in both subparts 3174 and 3175.
``Bias'' is defined to mean a ``shift in the mean value of a set of
measurements away from the true value of what is being measured.'' This
definition was originally proposed as part of the rule to replace Order
5 in Sec. 3175.10. The definition added to part 3170.3 is identical to
the definition in proposed Sec. 3175.10, because the BLM did not
receive any comments on that definition in the context of the Order 5
rulemaking.
In response to recommendations from many commenters, the BLM added
a definition of the term ``tampering'' to Sec. 3170.3. The proposed
and final rules prohibit operators from tampering with measurement
equipment, components, or processes and appropriate valves. While the
meaning of tampering is commonly understood, the BLM agrees with
commenters that the term should be defined to ensure there is a common
understanding of what is meant by tampering for purposes of this rule.
Section 3170.3 defines tampering to include ``any deliberate adjustment
or alteration to a meter or measurement device, appropriate valve, or
measurement process that could introduce bias into the measurement or
affect the BLM's ability to independently verify volumes or qualities
reported.'' The BLM modified the definition of ``commingling'' in the
final rule to clarify that combining production from multiple wells
within a single lease, unit PA, or CA, or the downhole combining of
production from different zones or formations that are part of the same
lease, unit PA, or CA, is not considered ``commingling'' for the
purpose of the final rule. Many commenters expressed concern that the
definition for commingling in the proposed rule would have required an
operator to obtain approval to combine production from multiple
properties within a CA or unit PA prior to measurement, particularly
when the CA or unit PA contains leases with multiple owners (i.e.,
Federal, Indian, State, or
[[Page 81370]]
private). Commenters said the proposed definition negates one of the
primary benefits of establishing a CA or unit PA, which is the
operation of the CA or unit PA as one entity and the sharing of
revenues from that CA or unit PA on a fixed allocation schedule,
typically based on ownership percentage within the CA or unit PA.
The conclusions reached by these commenters were incorrect. Neither
the proposed rule nor the final rule defined ``commingling'' to include
the combining of production from multiple properties within a CA or
unit PA prior to measurement. However, in response to these comments,
the BLM revised the definition of commingling to help clarify the
situations that are and are not considered commingling, and to
emphasize that the combining of production from multiple properties
within a CA or unit PA prior to royalty measurement is not commingling.
One commenter said the proposed commingling definition could deter
operators from drilling horizontal wells through several sections that
contain different mineral estates and reduce the production and
utilization of the State's oil and gas resources. The BLM agrees with
this comment with respect to the limited situations in which there is
no unit agreement or CA in place for those sections. Downhole
commingling when there is multiple ownership and no unit or CA in place
would adversely affect the uncertainty, bias, and verifiability of the
measurement of the volumes produced from each property, and the BLM
would deny such a request unless it qualified under Sec. 3173.14(b) of
the final rule. If there was a unit or CA in place, however, the BLM
would not consider the combining of production between several sections
within the unit or CA to be commingling and no approval would be
required. The BLM did not make any changes to the rule based on this
comment.
The definition of an FMP in this final rule is carried forward from
the proposed rule, which defined an FMP to be a ``BLM-approved point
where oil or gas produced from a Federal or Indian lease, unit PA, or
CA is measured and the measurement affects the calculation of the
volume or quality of production on which royalty is owed.'' As
explained in more detail below in the discussion of comments for Sec.
3173.12, the final rule sets forth a process for an operator of a new
or existing facility to apply for approval of an FMP and issuance of an
FMP number in proposed Sec. 3173.12. Because Sec. 3173.12 of the
final rule requires operators of existing facilities to apply for an
FMP in stages over a 36-month period, it will require 3 years from the
effective date of the final rule for the BLM to receive, evaluate, and
act on an FMP application for existing facilities. Therefore, for
purposes of compliance with other provisions of this final rule, during
this interim period, the definition of an FMP makes clear, as in the
proposed rule, that an FMP ``also includes a meter or measurement
facility used in the determination of the volume or quality of royalty-
bearing oil or gas produced before BLM approval of an FMP under Sec.
3173.12 of this part.''
The BLM received many comments on the proposed definition of an
FMP. A couple of commenters pointed out that there are differences
between the BLM's proposed definition and the ONRR's definition at 30
CFR 1206.171. Commenters said these differences could cause confusion
for industry, the BLM, and ONRR, and recommended that a single
definition be established for both agencies. These commenters did not
provide specific details or any examples of the confusion that could
arise as a result of these definitional differences. The BLM compared
both definitions and agrees that there are differences, but disagrees
with commenters that these differences will cause confusion. The intent
of both definitions is the same. Both agencies want to ensure that the
FMP is the point at which measurement determines the royalty that is
owed to the Federal Government or the Indian mineral owners. In
general, the ONRR definition applies to offshore oil and gas
operations, whereas the BLM definition applies only to onshore
operations. So, while the two agencies' FMP definitions are not exactly
the same, they capture a similar concept (i.e., the specific
measurement point where operators determine the royalty due the Federal
Government or Indian mineral owners). These comments did not result in
a change to the final rule.
It should be noted that in 2013, the GAO specifically noted in
report GAO-10-313 that Interior's onshore and offshore policies for
tracking and approving where and how oil and gas are measured are
inconsistent. The Bureau of Safety and Environmental Enforcement (BSEE)
already assigns FMP numbers for offshore oil and gas leases, which the
operator, transporter, or purchaser must then use when reporting
production results to ONRR. Based on that practice, the GAO recommended
that the BLM clearly identify points of measurement where oil and gas
royalties due to the Federal Government are determined and reported. By
including the definition of FMP in the final rule, the BLM is able to
both address the GAO's concerns and bring onshore reporting in-line
with the approach used offshore.
The BLM received additional comments pertaining to the FMP
definition. One recommended that the definition be changed to allow
operators to use gas processing plant tailgate meters located off the
lease, unit, or CA as FMPs as a general matter, or to allow those
meters to be used as FMPs under a variance. Another commenter asked
whether an FMP is the same as a Central Delivery Point or Point of
Royalty Measurement as defined in Washington Office Instruction
Memorandum (IM) 2013-152, a BLM policy document created in 2013
regarding commingling approvals.
The BLM did not change the definition of an FMP to include tailgate
meters because, under the Mineral Leasing Act (MLA) and FOGRMA, the
Secretary's authority to regulate onshore oil and gas operations
applies to lessees/operators and, during certain activities, to
purchasers and transporters. While the owners of off-lease/unit/CA gas
processing plants may sometimes fall into these categories of regulated
entities, they will not always, and while the BLM may consider requests
for off-lease measurement it is not required to approve such request.
Therefore, the BLM chose not to include off-lease/unit/CA tailgate
meters in the definition of an FMP in order to avoid default
applications of this rule that might be inconsistent with BLM's
statutory authority or the requirements of this final rule related to
off-lease measurement at Sec. Sec. 3173.23 through 3173.28. With
respect to whether the definition of an FMP is the same as the Central
Delivery Point or Point of Royalty Measurement as defined in IM 2013-
152, the BLM can confirm that they are the same.
The definition of ``off-lease measurement,'' in both the proposed
and final rules, means measurement at an FMP that is not located on the
lease, unit, or communitized area from which the production came. The
BLM received several comments requesting that the definition be
expanded to exempt from the proposed rule's off-lease measurement
approval requirement cases in which a horizontally or directionally
drilled well is completed through a Federal or Indian lease, unit, or
communitized area, but conducts measurement operations off-lease at the
wellhead. The commenters said that, in many instances, wells are being
drilled from a surface location that is sited off-lease due to
environmental conditions, such as rugged terrain or sensitive wildlife
habitat. The BLM did not
[[Page 81371]]
change the definition of off-lease measurement in response to this
comment because Sec. 3173.28(a) of the proposed and final rules
already addresses this situation. Under Sec. 3173.28(a), measurement
at an approved FMP is not considered off-lease measurement when the FMP
is located on the well pad of a directionally or horizontally drilled
well that produces oil and gas from a lease, unit, or CA on which the
well pad is not located. Therefore, approval for off-lease measurement
is not required under those circumstances, so long as measurement
operations occur on the well pad of the directionally or horizontally
drilled well.
The final rule makes minor changes to the list of acronyms that
appear in proposed Sec. 3170.3 based on the acronyms used in part
3170. The BLM did not receive any comments on this list. The acronym
Btu (British thermal unit) has been relocated from Sec. 3173.1 to
Sec. 3170.3 because this acronym is used in both subparts 3173 and
3175. The acronym S&W (sediment and water) is new to section. The BLM
decided to include it in Sec. 3170.3 because the acronym is used in
both subparts 3173 and. Although it is a commonly understood acronym in
the oil and gas industry, the BLM believes it is appropriate to include
the acronym here for clarity and to help inform the general public. The
BLM also added the acronym LACT (lease automatic custody transfer)
because it is used in both subparts 3173 and 3174.
Section 3170.4 Prohibitions Against By-Pass and Tampering
The BLM did not make any changes to the requirements of this
section between the proposed and final versions. Section 3170.4
strengthens the prohibition against meter by-passes contained within
section III.D of Order 3 by adding language that prohibits tampering
with any measurement device, component of a measurement device, or
measurement process. As explained in Sec. 3170.3, tampering includes
any deliberate adjustment or alteration to the meter or measurement
device or measurement process that could introduce bias into the
measurement or affect the BLM's ability to independently verify volumes
or qualities reported. Examples of tampering include deliberately
installing an orifice plate in a gas meter with the bevel upstream,
adjusting a transducer to read higher or lower than a certified test
device, entering incorrect information into the configuration log of an
electronic gas measurement system, submitting derived integral values
on a volume statement in lieu of raw data, or making analogous
adjustments or alterations to an oil measurement system.
The BLM received many comments on this section of the proposed
rule, most of which suggested that the BLM clarify that inadvertent
human error or force majeure events should not be considered
``tampering'' for purposes of this section. For example, one commenter
said meter reports may use derived values due to tap freezes or data
loss. The commenter believes that these situations should not be
considered ``tampering.'' The commenter said the language in the
proposed rule would not allow for such cases, and should be modified.
The BLM agrees with this comment and in the final rule has provided a
definition for the term ``tampering,'' as previously discussed, that
clearly states that the act of tampering must be deliberate on the part
of the operator. By requiring acts to be deliberate, consistent with
the commenter's suggestion, the BLM is able to take into consideration
whether a particular act is due to human error or is outside of the
operator's control.
The BLM did not amend the definition of tampering in response to
the comment about the use of derived values rather than raw data in a
meter report, such as when a tap freezes or other malfunctions are
experienced. These circumstances can occur in the context of either oil
or gas measurement, and they are addressed in specific provisions of
subparts 3174 and 3175 (the new rules replacing Orders 4 and 5) that
establish procedures that an operator must follow to notify the BLM of
the malfunctioning equipment, document how derived values were
determined, and indicate on the quantity transaction record that
derived values, rather than raw data, were used to determine volumes.
As a result, the BLM did not amend the definition of tampering in
response to comments about derived values.
Section 3170.5 Industry Standards Incorporated by Reference
Section 3170.5 is reserved for potential future incorporation by
reference of standards that apply to more than one of the subparts of
part 3170.
Section 3170.6 Variances
Section 3170.6 of the final rule clarifies and makes more uniform
the BLM's existing process and regulations for granting variances from
the minimum standards contained in part 3170.
Paragraph (a)(1) lists all the information that a party seeking a
variance from the requirements of part 3170 must include when filing a
request, including: Identification of the specific requirement from
which a variance is sought, and the length of time the variance is
requested; an explanation of the need for the variance; a detailed
explanation of the proposed alternative means of compliance; and a
showing that the proposed alternative meets or exceed the objectives of
the applicable requirement. Paragraph (a)(2) requires that variance
requests be submitted as separate documents from any plans or
applications. The BLM will not consider variance-request documents that
are submitted as part of a master development plan, APD, right-of-way
application, or other applications for approval. This requirement does
not preclude operators from submitting variance requests at the same
time that they submit a master development plan or other application.
In fact, the final rule encourages operators to submit their variance
requests simultaneously with, but separately from, their development
plans or applications, especially if the operators' proposals are
contingent upon the BLM approving their variance requests. The BLM's
primary rationale for requiring separate submittal is that, in the
past, operators have put their variance requests in the cover letters
that accompanied their development proposals, where they are sometimes
overlooked. Having operators submit their variance requests via a
separate Sundry Notice will help the BLM easily identify them when they
are submitted simultaneously with other applications. Paragraph (a)(2)
clarifies that approval of a plan or application that contains a
request for a variance does not constitute approval of the variance.
The BLM made this clarification to ensure that variances are submitted
separately and brought to the attention of the BLM.
Paragraph (a)(3) tells operators how to submit their variance
requests. Operators must use WIS, which is an acronym described in the
final rule to mean the Well Information System or any successor
electronic filing system that might be developed by the BLM, to file
their request, along with any supporting documents associated with it.
This paragraph also provides an option for operators to submit a
hardcopy application if electronic filing is not possible or practical.
In such cases, the operator must submit a variance in hardcopy as
directed by the AO in the Field Office having jurisdiction over the
lands described in
[[Page 81372]]
the application. The BLM made minor revisions to this section to
clarify the intent of this provision regarding electronic filing, and
to provide additional flexibility as the BLM rolls out new electronic
systems to replace its existing systems, including the Well Information
System and the Automated Fluid Management Support System (AFMSS).
No substantive changes were made to proposed paragraph (a)(4). This
paragraph strengthens and standardizes the criteria the BLM uses for
granting variances. Under Order 3, the AO was required to make only one
determination--whether or not the variance request meets or exceeds the
objectives of the applicable minimum standard. Under this paragraph in
the final rule, the AO will still have to make that determination
before granting a variance. Additionally, the final rule requires the
AO to make two more determinations before granting a variance--that
issuing a variance: (1) Will not adversely affect royalty income or
production accountability; and (2) Is consistent with maximum ultimate
economic recovery.
Paragraphs (a)(5) and (a)(6) specify that granting or denying a
variance is entirely within the BLM's discretion, and that a variance
from a requirement in a regulation does not constitute a variance from
any other regulations, including other Onshore Oil and Gas Orders.
These paragraphs did not change from the proposed rule.
Paragraph 3170.6(b) affirms the BLM's authority to rescind a
variance or modify any condition of approval of a variance due to
changes in Federal law, technology, regulation, BLM policy, field
operations, noncompliance, or for any other reason.
The BLM received many comments on this section of the proposed
rule. A few commenters were concerned that the proposed rule would void
existing variances and that operators with existing variances would
have to apply for new ones. These commenters were concerned this would
place an unnecessary burden on affected parties. They recommended that
the provision be revised to expressly ``grandfather'' existing
variances.
The BLM did not make a change to the rule in response to these
comments. This final rule does not automatically rescind any existing
variance approvals. Rather, it clarifies the BLM's authority to rescind
variances and provides the means by which it may rescind an existing
approval if necessary. The BLM will re-evaluate existing variance
approvals on a case-by-case basis, such as during the FMP application
and review process under Sec. 3173.16. For example, if an operator has
an existing variance approval from the BLM's previous commingling
requirements, but during the FMP approval process the BLM determines
that the existing approval is inconsistent with this final rule's new
commingling standards, or the operator cannot be exempted from the new
commingling standards, then the BLM will rescind the existing variance
if the deficiencies are not corrected within the time specified by the
BLM.
Several commenters disagreed with the provision in paragraph (b)
that allows the BLM to rescind variance approvals and modify conditions
of approval. These commenters stated that companies made investments
and proceeded with projects based on previously approved BLM variances.
These commenters said that rescinding existing authorizations and what
they believe to be contractual agreements would pose a great risk to
their operations.
The BLM did not make a change in the rule in response to these
comments. The BLM's overriding contractual agreement with the operator
is the lease agreement, which is expressly made subject to regulations
and formal orders subsequently promulgated as long as such regulations
are not inconsistent with the lease rights granted or the specific
lease provisions (See BLM Lease Form 3100-11). The Department has long
interpreted this language as ``incorporat(ing) future regulations, even
though inconsistent with those in effect at the time of lease
execution, and even though to do so creates additional obligations or
burdens for the lessee.'' \9\ The BLM's authority to update the
regulations that apply to existing leases and operations is well-
established, and this authority necessarily includes the authority to
rescind existing variances and authorizations when these variances and
authorizations are inconsistent with applicable regulations.
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\9\ Coastal Oil & Gas Corp., et al., 108 IBLA 62, 66 (1989).
---------------------------------------------------------------------------
The BLM recognizes that the commingling and off-lease measurement
requirements in this rule may result in the termination of existing
commingling and off-lease measurement variance approvals. However, the
BLM has sought to minimize the adverse impacts of these requirements by
providing exemptions for economically marginal properties. These
additional exemptions are discussed in further detail in the sections
of this preamble that address commingling and off lease measurement.
See the Section-by-Section discussions of Sec. Sec. 3173.1, 3173.14,
3173.25, and 3173.27. For example, the final rule provides public-
interest exemptions for operators that cannot meet its new off-lease
measurement standards.
One commenter supported the standards in paragraph (a)(4) that the
BLM will use to determine whether to grant a variance but went one step
further to recommend that operators be required to demonstrate that
compliance with the regulation is not feasible, so that the rule's
relatively limited opportunities for variances are not abused. The BLM
does not expect operators to abuse the variance process, which requires
them to submit an application requesting a variance, and provide
sufficient information and justification for the variance that the BLM
will then review prior to making a determination on the variance
request. In fact, this rule strengthens and standardizes the criteria
that the BLM will use to determine whether to grant a variance and
requires that the BLM make a determination that ``the proposed
alternative meets or exceeds the objectives of the applicable
requirement(s) of the regulation.'' As a result, the BLM does not
believe the change requested by the commenter is necessary and did not
make any changes the rule based on this comment.
A few commenters expressed concern with language in paragraph (b)
that allows the BLM to rescind a variance for ``other reasons''
because, they said, it could result in the BLM acting arbitrarily. The
BLM disagrees that this language would allow it to act arbitrarily
because paragraph (b) requires the BLM to provide a written
justification when it rescinds a variance. The BLM included the term
``other reason'' because the BLM cannot anticipate every possible
situation in which there will be good cause for rescinding a variance.
The BLM must preserve its ability to rescind a variance approval if
that approval adversely affects royalty income or production
accountability, or is not consistent with maximum ultimate economic
recovery. If the operator does not agree with the BLM's decision to
rescind a variance, the operator may file an appeal under applicable
BLM regulations at 43 CFR subpart 3165--Relief, Conflicts, and Appeals.
A few commenters stated that even though the BLM will provide
written justification when it rescinds a variance or modifies a COA,
operators should be given a 30-day advance notice if their variance is
about to be rescinded, or COA modified, in order to give them an
[[Page 81373]]
opportunity to avoid a rescission or modification, or to adjust to
operating without the variance. The BLM disagrees with this comment and
did not change the rule in response. As previously noted, if an
operator disagrees with the BLM's decision to rescind a variance or
change a COA, the operator may file an appeal under the applicable
regulations.
Section 3170.7 Required Recordkeeping, Records Retention and Records
Submission
Section 3170.7 of the final rule updates BLM regulations to reflect
the records-retention requirement for Federal oil and gas leases that
Congress established in the 1996 amendments to FOGRMA.\10\
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\10\ Federal Oil and Gas Royalty Simplification and Fairness Act
of 1996, Public Law 104-185, 110 Stat. 1700 (Aug. 13, 1996).
---------------------------------------------------------------------------
Paragraphs (a) and (b) are the same as in the proposed rule. These
paragraphs establish both the entities covered and the time period over
which the records-retention requirements apply. In the final rule,
purchasers and transporters are held to the same minimum standards as
operators for recordkeeping, records retention, and records
submission--i.e., to maintain all records that are relevant to
determining the quality, quantity, disposition, and verification of
production from Federal and Indian leases. As described in the proposed
rule, the BLM has authority to impose these requirements on purchasers
and transporters under FOGRMA. Specifically, Section 103(a) of FOGRMA,
30 U.S.C. 1713(a), requires persons involved in transporting and
purchasing oil or gas through the point of first sale or the point of
royalty computation, whichever is later (along with persons involved in
producing or selling), to ``establish and maintain any records, make
any reports, and provide any information that the Secretary may, by
rule, reasonably require.''
Although paragraph (c) did not change substantively from the
proposed rule, the final rule splits it up into two paragraphs for
clarity. Paragraph (c)(1) states that records pertaining to Federal
leases, units, or CAs must be maintained for at least 7 years,
consistent with applicable statutory requirements. Paragraph (c)(2)
codifies the applicable statutory requirements for further retention
beyond 7 years under the circumstances specifically identified by
statute (see 30 U.S.C. 1724(f)), as required under the 1996 amendments
to FOGRMA.
Similarly, although paragraph (d) did not change substantively from
the proposed rule, the final rule splits it up into two paragraphs for
clarity. Paragraph (d)(1) states that records pertaining to Indian
leases, units, or CAs must be maintained for at least 6 years,
consistent with applicable statutory requirements. Paragraph (d)(2)
codifies the applicable statutory requirements for further retention
beyond 6 years under the circumstances specifically identified by
statute (see 30 U.S.C. 1713(b)). The records-retention requirement on
Indian leases remains unchanged because the 1996 amendments to FOGRMA,
by their express terms, applied only to Federal leases and not to
Indian leases.
Paragraph (e)(1) addresses the discrepancy between the records-
retention requirements for Federal (7 years) and Indian (6 years)
leases, as relevant to units and CAs that contain both Federal and
Indian leases. No substantive changes were made as part of the final
rule. However, the phrase, ``but a judicial proceeding or demand is not
commenced within 7 years after the records are generated, the record
holder must retain all records regarding production from the unit or CA
until the Secretary or his designee releases the record holder from the
obligation to maintain the records'' has been eliminated from this
paragraph of the proposed rule and moved to its own paragraph (e)(2).
In paragraph (e)(2) of the proposed rule, which is now paragraph
(e)(1) of the final rule, the phrase ``or until the Secretary or his
designee releases the record holder from the obligation to maintain the
records, whichever is later,'' was removed from the final rule in order
to more closely track the authorizing language in FOGRMA, and also to
make the record-retention obligation clearer.
Paragraph (f) requires the record holder to maintain an audit trail
and is unchanged from the proposed rule.
Paragraph (g) requires operators, purchasers, and transporters to
place specific identifying information on all records, including source
records, used to determine quality, quantity, disposition, and
verification of production attributable to a Federal or Indian lease,
unit PA, or CA. The proposed rule would have required record holders to
use BLM-assigned FMP numbers on such records. The final rule is revised
to allow record holders, in lieu of an FMP number, to use the lease,
unit PA, or CA number, as applicable, on their records, including
source records. In any case, the record holder must also include a
unique equipment identifier, such as a unique tank identification
number or meter station number. The BLM made this change in response to
many comments that it would be difficult or impossible for some record
holders to modify their electronic systems to accommodate FMP numbers
on their records. In these instances, the final rule allows record
holders to use the lease, unit PA, or CA number instead of the FMP
number.
Paragraph (h) requires operators, purchasers, and transporters to
provide all records to the BLM upon request. This ensures that all
records--whether they are created by lessees, operators, transporters,
or purchasers--are readily available to the BLM. The BLM did not
receive any comments on this paragraph and did not change it in the
final rule.
Paragraph (i) requires that all records be legible. The BLM did not
receive any comments on this paragraph and did not change it in the
final rule.
Paragraph (j) requires that all records requiring a signature must
also have the signer's printed name. The BLM did not receive any
comments on this paragraph of the proposed rule and did not change it
in the final rule.
The BLM received a number of comments on Sec. 3170.7 of the
proposed rule as a whole requesting various changes to be made to the
proposed requirements. Each of these comments is addressed below.
One commenter stated that maintaining audit records for 7 years, as
required in paragraph (c)(1), would result in unnecessary costs for
purchasers and transporters, and that they should not have to account
for production volumes. The BLM does not agree with this comment, nor
can it make the changes suggested by the commenter. As discussed
earlier, the records retention period set by FOGRMA for Federal leases
is now 7 years and the change in retention period in this final rule
merely conforms the regulations to that statutory authority.
A number of other commenters asserted that the BLM does not have
the authority to hold purchasers and transporters to the same records-
retention and recordkeeping requirements as lessees and operators, as
outlined in paragraphs (a) and (f) of Sec. 3170.7. Other commenters
indicated that they did not see a need for this new requirement and
that it would be too costly. Still others disagreed that FOGRMA
authorizes the BLM to impose recordkeeping and records-retention
requirements on purchasers and transporters in the first instance. One
commenter argued that the BLM had not properly defined ``any person
directly involved in producing, transporting, purchasing, selling, or
measuring oil
[[Page 81374]]
and gas'' under FOGRMA, and therefore had improperly extended these
recordkeeping requirements to purchasers and transporters.
The BLM disagrees with these comments. Section 103(a) of FOGRMA, 30
U.S.C. 1713(a), requires a ``lessee, operator, or other person directly
involved in developing, producing, transporting, purchasing, or selling
oil or gas . . . through the point of first sale or the point of
royalty computation, whichever is later, [to] establish and maintain
any records, make any reports, and provide any information that the
Secretary may, by rule, reasonably require.'' While FOGRMA does not
specifically define ``any person directly involved,'' the intent of the
provision is clear. It authorizes the Secretary to establish by rule
requirements for anyone involved ``. . . in developing, producing,
transporting, purchasing, or selling oil or gas,'' which plainly
includes purchasers and transporters. 30 U.S.C. 1713(a) (emphasis
added).
Based on its experience in the field, the BLM believes it is
appropriate to implement this statutory authority and have purchasers
and transporters adhere to the same recordkeeping and records-retention
requirements as lessees and operators. This is because the BLM must
occasionally rely on purchasers' and transporters' records to verify
production when operators do not maintain their own records properly,
or go out of business, or are acquired by other companies and their
records are destroyed. For this reason, the BLM believes that it is
important for everyone involved in the production and sale of oil and
gas produced from Federal and Indian leases to be responsible for
maintaining and providing the necessary records to account for and
verify that production. The BLM did not make any changes in response to
these comments.
Another commenter said the BLM did not adequately analyze the
economic impact that this requirement would have on purchasers and
transporters. The BLM does not agree with this comment. As part of this
rulemaking process the BLM prepared an Economic and Threshold Analysis
For Final Rule Onshore Oil and Gas Operations; Federal and Indian Oil
and Gas Leases; Site Security (Economic and Threshold Analysis). That
analysis specifically analyzed, among other things, the impact of these
proposed recordkeeping requirements on purchasers and transporters.
Based on that analysis, the BLM estimates that 200 to 300 purchasers
and transporters will have to comply with this final rule's new
recordkeeping and records-retention requirements. However, it is likely
that many purchasers and transporters already compile records that
will, for the most part, satisfy this rule's requirements, and
therefore the additional compliance costs imposed by this rule should
be minimal. For more details, please see the Economic and Threshold
Analysis.
Several commenters said that some transporters do not have space to
store records and would not be capable of meeting the paragraph (a)
requirements. They said that transporters would create inaccurate
records, and that operators would be held responsible. They asked that
the BLM not hold operators responsible for transporters' recordkeeping
violations. Conversely, some commenters said operators may provide
incorrect information to purchasers and transporters, such as incorrect
FMP numbers, which could subject purchasers and transporters to
recordkeeping penalties if they were to use the inaccurate information
in their records. The BLM does not agree with the concerns raised by
these commenters, as under the rules each party will be responsible for
the content of their own records and must also bear some responsibility
for ensuring the accuracy of the information they are tracking. The BLM
does not believe that the provision should be modified to account for
the possibility that operators might provide faulty information to a
purchaser or transporter. Parties bear the responsibility to ensure the
accuracy of their own records, and the BLM anticipates that provision
of faulty information to a purchaser or transporter by an operator
could be handled on a case-by-case basis in the enforcement context.
The final rule was not changed as a result of these comments.
Some commenters said the BLM should make the records-retention
requirements for both Federal and Indian leases the same--6 years.
Paragraph (c) requires Federal-lease operators to retain their records
for 7 years (consistent with Congress' 1996 amendments to FOGRMA),
while paragraph (d) requires Indian-lease operators to retain theirs
for 6 years. One commenter said the 6-year retention requirement for
all records under Order 3 has not been a problem and questioned why
Congress extended the retention period for Federal-lease operators from
6 years to 7 years. The BLM understands these concerns, but the
retention period for records maintained by Federal-lease operators is 7
years by statute. 30 U.S.C. 1724(f). That statutory requirement has
been in place for 20 years. This final rule simply codifies that
requirement. Thus, the BLM did not change the final rule in response to
these comments.
Several commenters expressed concern about the requirement in
paragraph (g) of the proposed rule that lessees, operators, purchasers,
and transporters place FMP numbers on all of their source records,
particularly records generated by flow computers. They said that flow
computers cannot handle the 11-digit FMP numbers and that it would take
operators years to modify their production accounting systems to
accommodate the new numbers. The BLM agrees with these commenters and
changed the final rule to allow lessees, operators, purchasers and
transporters, as an alternative, to use the lease, unit PA, or CA
number, along with a unique equipment identifier, on their records. The
BLM believes this change will simplify the final rule's record-keeping
requirements because in its experience lessees, operators, purchasers
and transporters are already using a lease, unit PA, or CA number, plus
some unique equipment identifier in connection with existing
operations, which means this information is already reflected on
records being generated under existing recordkeeping systems.
In addition to the preceding comments on specific provisions of
Sec. 3170.7, the BLM received some general comments on Sec. 3170.7
that were not directed to any specific paragraph. Several commenters
said the recordkeeping requirements do not address new production
reporting technology and practices that are used by regulators outside
of the U.S., such as the Norwegian Petroleum Directorate. These
commenters did not suggest any specific changes, and therefore the BLM
did not make any changes in the final rule in response to these
comments. That said, it should be noted that the BLM is currently
updating its existing database system (AFMSS) that it uses to track
Federal and Indian oil and gas production. As part of this
comprehensive update, the BLM is following data management models and
standards established by industry organizations, such as the
Professional Petroleum Data Management Association. These update
efforts respond to the concerns raised by commenters.
Another commenter said the new recordkeeping and records-retention
requirements would cause problems for the BLM. This commenter said BLM
field offices do not have room for the additional records that would be
generated under the final rule. The BLM disagrees with this commenter.
The
[[Page 81375]]
BLM will not be storing or accepting all of the records that a lessee,
operator, purchaser, or transporter will be required to create and
retain under this final rule, rather records must be available to the
BLM if requested (see Sec. 3170.7(h)). The BLM did not change the
final rule as a result of these comments.
Several commenters suggested that requiring purchasers and
transporters to keep and retain records would be redundant because
purchasers and transporters already provide this information to the
operators, who use it to fill out their own production records. The BLM
agrees that operators do often base their production reporting on
information that purchasers and transporters provide them, however, the
BLM cannot confirm that this happens in all cases. Moreover, as noted,
operators' records may sometimes be or become unavailable. Requiring
each party involved in production from Federal and Indian oil and gas
leases to maintain its own records allows the BLM to compare the
information and make an independent determination that production is
being properly accounted for and that the correct royalties are being
paid.
One commenter said this section's new recordkeeping and records-
retention requirements will be costly and cause delays, and will
discourage oil and gas development on Federal lands, as well as on
adjacent State and private lands. The commenter said this in turn will
result in lost royalties and jobs. The BLM does not agree with this
comment. These recordkeeping requirements are not substantially
different from the requirements that operators are currently following
(e.g., the records retention requirements have only increased from 6 to
7 years). As explained above, it is likely that most purchasers and
transporters are already maintaining records that will, for the most
part, satisfy this final rule's requirements. No change was made to the
final rule as a result of this comment.
Section 3170.8 Appeal Procedures
Section 3170.8 provides that BLM decisions, orders, assessments, or
other actions under part 3170 are administratively appealable (first to
the BLM State Director and then to the Interior Board of Land Appeals)
under 43 CFR 3165.3(b), 3165.4, and part 4. The BLM did not receive any
comments on this section; however, in response to comments received on
provisions of the proposed rules to replace Orders 4 and 5 the BLM made
several changes to this section.
The language from the proposed rule was moved to a new paragraph
(a) and a new paragraph (b) was added that creates a separate appeal
process for decisions made by the BLM, based on a recommendation from
the PMT, for approval or denial of specific measurement equipment or
procedures. Under paragraph (b) a party may file a request for
discretionary review by the ASLM. Paragraph (b) also provides that the
ASLM may delegate this review function as he or she deems appropriate,
in which case the application for discretionary review must be made to
the person or persons to whom the review function has been delegated.
A specific appeals procedure for recommendations from the PMT was
developed for two reasons. First, such a procedure responds directly to
comments received on Orders 4 and 5 specifically requesting a procedure
to review decisions made by the PMT. Second, the BLM determined that a
separate appeal process is necessary because it determined that PMT
reviews did not fit under the existing appeals procedure at 43 CFR
3170.8. As explained in this preamble and the preambles for the rules
to replace Orders 4 and 5, the PMT will review new measurement
technologies and methods and then make recommendations to the BLM as to
whether they should be approved. It is the BLM's intent that those
approvals be made at the national or Washington Office level, as a
result those decisions would not properly be appealable to a BLM State
Director as contemplated in paragraph (a). The new language under
paragraph (b) reads: ``For any recommendation made by the PMT, and
approved by the BLM, a party affected by such decision may file a
request for discretionary review by the Assistant Secretary for Land
and Minerals Management. Under paragraph (b), the Assistant Secretary
may delegate this review function as he or she deems appropriate, in
which case the affected party's application for discretionary review
must be made to the person or persons to whom the Assistant Secretary's
review function has been delegated.'' \11\
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\11\ It should be noted that decisions by the Assistant
Secretary would not be reviewable by the Interior Board of Land
Appeals.
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Section 3170.9 Enforcement
Section 3170.9 provides that noncompliance with any requirements of
part 3170 or any order issued thereunder may result in enforcement
actions under 43 CFR subpart 3163 or any other remedy available under
applicable law or regulation.
The BLM received numerous comments regarding the BLM's proposal, in
proposed Sec. 3170.9, not to include in this rule the enforcement,
corrective action, and abatement period provisions that were in Order
3, and instead to develop an internal Inspection and Enforcement
Handbook that would provide direction to BLM inspectors on how to
classify a violation as major or minor, and what the corrective action
and timeframes for correction should be. These comments and the BLM's
response are discussed later in this preamble in connection with Sec.
3173.29.
Subpart 3173--Requirements for Site Security and Production Handling
and Related Provisions
Section 3173.1 Definitions and Acronyms
This section defines the terms used in subpart 3173 that pertain to
site security and production handling. The BLM did not receive any
comments on a majority of the definitions that appeared in proposed
Sec. 3173.1. Those definitions, for which we received no comment, were
carried forward into this final rule and are not discussed further
here. The following discussion summarizes and responds to comments that
the BLM received on a handful of proposed definitions, describes
modifications to some of those definitions, and describes five
definitions that were added to Sec. 3173.1 of the final rule: ``Free
water,'' ``permanent measurement facility,'' ``payout period,''
``royalty net present value (NPVR),'' and ``royalty-free use of oil and
gas.''
At the outset it should be noted that as explained in the preamble
to the proposed rule, a number of the definitions in Sec. 3173.1 are
the same definitions that were found in Order 3, with only minor
simplifications or clarifications.
As noted in the Section-by-Section discussion for Sec. 3170.3, the
acronym for ``British thermal unit (Btu)'' has been moved from this
section to Sec. 3170.3 of the final rule because it is used in more
than one subpart of Sec. 3170. The acronym BIA (Bureau of Indian
Affairs) was added to this final rule because it is used in Sec. Sec.
3173.14 and 3173.23.
Similarly, the acronym for ``CAA (commingling and allocation
approval)'' was provided in the proposed rule, but the term was not
otherwise defined. One commenter suggested that a definition for this
term be provided. The BLM agrees with this comment and has provided a
definition in the final rule
[[Page 81376]]
for this commonly used term. The final rule defines ``commingling and
allocation approval (CAA)'' to mean ``a formal allocation agreement to
combine production from two or more sources (leases, unit PAs, CAs, or
non-Federal or non-Indian properties) before that production reaches an
FMP.'' This definition is consistent with the commonly understood
meaning of the term and its use in the proposed rule.
The BLM also replaced the term ``low-volume property'' with the
term ``economically marginal property'' and modified the definition
based on comments received. The term ``low-volume property'' was
intended to identify category of leases, unit PAs, and CAs for which
commingled measurement of production may be justified, even though the
property would not meet the conditions of proposed Sec. 3173.14(a)(1)
regarding mineral interest ownership of commingled production. In
response to comments, the BLM made a number of changes to this
definition, most notably changing the term to ``economically marginal
property'' in the final rule.
The BLM believes this new term is more reflective of the BLM's
intent, which is to describe a type of property that should be allowed
to be part of a CAA in order to avoid premature plugging and
abandonment. The thresholds that the proposed and final rules use to
identify a property as at risk of being shut-in are not exclusively
volume-based. The new name recognizes that the thresholds are actually
based on production volume and other economic considerations, including
commodity price, fixed and variable operating costs, and taxes.
Specifically, under both the proposed and final rules, the BLM can
approve commingling in two circumstances relating to economics of well
operations: (1) When a prudent operator, for economic reasons, would
plug a well or shut-in the lease, unit PA, or CA instead of spending
the money to achieve non-commingled measurement of production; or (2)
When the capital expenditure on equipment necessary to achieve non-
commingled measurement of production would exceed the net present value
of projected Federal or Indian royalty over the life of the new
equipment. The BLM captured both of these circumstances in the
definition of a ``low-volume property'' in the proposed rule, and
carried that structure into the final rule's definition of an
``economically marginal property.''
Under the final rule, a lease, unit PA, or CA qualifies as an
``economically marginal property'':
(1) ``If the operator demonstrates that the expected revenue
generated from crude oil or nature gas production volumes on that
property (above the operating costs associated with those production
activities) is not sufficient to cover the nominal costs of the
capital expenditures required to achieve measurement of non-
commingled production of oil or gas from that property over a payout
period of 18 months,'' or
(2) If the operator demonstrates that ``its royalty net present
value, or the discounted value of the Federal or Indian royalties
collected on revenue earned from crude oil or natural gas production
on the lease, unit PA, or CA over the expected life of the equipment
that would need to be installed to achieve non-commingled
measurement volumes, is less than the capital cost of purchasing and
installing this equipment.''
The final rule takes a somewhat different approach than the
proposed rule to define these two circumstances. Specifically, the
final rule:
Changes the threshold for what qualifies as an
economically marginal property from a 10 percent, before tax, rate of
return in the proposed rule to an 18-month, after-tax, payout period in
the final rule;
States explicitly that the economic analysis considers
operating costs;
Clarifies that the analyses for oil and gas commodities
are done separately, based on the income streams from the commodity and
the expenses required to achieve non-commingled measurement of that
commodity; and
States explicitly that if economic circumstances change,
and a Federal or Indian lease, unit PA, or CA ceases to be an
economically marginal property, the lease, unit PA, or CA will no
longer qualify for a CAA.
The BLM changed the first economic threshold test from a 10
percent, before tax, rate of return in the proposed rule to an 18-
month, after-tax, payout in the final rule, primarily based on comments
received. As explained in the preamble to the proposed rule, the
initial test was developed based on the provisions of Instruction
Memorandum (IM) 2013-152. The purpose of the economic analysis in IM
2013-152, the proposed rule, and the final rule is to simulate the
analysis that a prudent operator would make in deciding whether or not
to invest money to achieve non-commingled measurement of production. If
that analysis concludes that it would be uneconomic for the operator to
make the investment and they would instead opt to shut in the property,
then the BLM will grant commingling approval. In these situations, the
BLM believes that it is in the public interest to sustain production by
allowing commingling, even if commingled measurement may be somewhat
less accurate and hard to verify than non-commingled measurement.
The only question is how best to identify the point at which a
prudent operator would choose to shut in rather than invest in
equipment to achieve non-commingled measurement. Several commenters
said the proposed 10 percent rate-of-return cutoff point (calculated
before Federal, State, and local taxes) was too low, and that the BLM,
should instead use a 20 percent rate of return. Other commenters
recommended replacing the 10 percent rate of return threshold with a
payout period. The BLM agrees with the commenters who recommended that
the BLM use a payout period method rather than a rate-of-return method,
because the former provides a simpler and more objective picture of
whether a particular course of action is economically viable, and it is
a method commonly used by industry.
Under the rate-of-return method in the proposed rule, the BLM would
have had to assume a rate of return on initial investment that would be
sufficient for a prudent operator to install metering equipment to
achieve non-commingled measurement of a lease, unit PA, or CA. The
payout method used in the final rule uses a formula to determine
whether the production volumes at that lease, unit PA, or CA are
sufficient to generate enough net revenue, after taxes and operating
costs, to cover the nominal cost of equipment installation within the
payout period. Additionally it was clear from the comments received
that different companies apply different rates of return to evaluate
their investments. For these reasons, the BLM felt it was appropriate
to replace the rate-of-return method with the payout method.
One commenter stated that industry typically uses a payout period
of 6 months to 18 months as the criterion for deciding whether or not
to invest in a new project. The commenter went on to state that a 15
percent rate of return (before tax) yields approximately the same
result as a 22-month payout. An 18-month payout would be approximately
the same as a 20 percent (before tax) rate of return, which is a
threshold suggested by several commenters. Based on these comments, the
BLM believes that an 18-month payout period is reasonably
representative of the threshold a prudent operator would use to
determine the economic viability of achieving non-commingled
measurement of production.
Additionally, there were a few comments that recommended that the
[[Page 81377]]
BLM evaluate alternative cost-benefit methodologies and definitions,
including those found in the Federal Oil and Gas Royalty Simplification
and Fairness Act of 1996, and the Interstate Oil and Gas Commission
report, entitled Marginal Wells: Fuel for Economic Growth, (2012). The
BLM agrees with these comments, noting that the proposed 10 percent
rate of return was a starting point, as the proposed rule specifically
asked for feedback on the suitability of the BLM's using this rate of
return for identifying a ``low-volume property.'' The BLM believes the
18-month payout threshold used in the final rule is consistent with
these comments.
Also unlike the proposed definition of ``low-volume property,'' the
definition of ``economically marginal property'' in the final rule
specifically considers taxes, fixed and variable operating costs, and
commodity prices. While the ``low-volume property'' definition in the
proposed rule implicitly included operating costs and commodity prices
in the rate-of-return calculation, it did not include taxes. The BLM
believes that the addition of taxes and the explicit addition of
operating costs and commodity price considerations help to make the
payout calculation more representative of an economic analysis that a
prudent operator would perform.
Finally, in the final rule definition, the BLM clarified that the
economic analyses are specific to the commodity to which the
commingling request applies. For example, if a lease produces a high
volume of gas with small amounts of associated condensate, and the
operator wishes to commingle the condensate production with similar
volumes of condensate produced from private leases, the economic
analysis performed under Sec. 3173.14(b)(1) would only consider the
income, costs, and payout period related to measuring the condensate.
The BLM made this addition to the final rule to clarify that neither
operators nor BLM field offices should include the income and costs
from a commodity which the operator is not proposing to commingle. The
proposed rule was silent on whether the economic analysis should be
based on total oil and gas production or just on the commodity the
operator requests for commingling. However, it was always the BLM's
intent that this analysis occur on the basis of the commodity for which
commingled measurement is proposed. This clarification in the final
rule is consistent with that intent.
In support of the new definition for ``economically marginal
property'' the BLM added two additional definitions--``payout period''
and ``royalty net present value (RNPV)''--each of which is discussed
(in alphabetical order) below.
In addition, in the final rule the BLM added a definition for the
term ``free water.'' That term appeared multiple times in the proposed
rule but was not defined because the BLM believes it is commonly
understood by the industry. While the BLM did not receive any comments
on the use of this term, the BLM determined that it should nevertheless
include a definition in the final rule to clarify its intent with
respect to the use of the term in this regulation. The final rule
therefore defines ``free water'' as ``the measured volume of water that
is present in a container and that is not in suspension in the
contained liquid at observed temperature.'' This definition tracks the
commonly understood definition of the term used routinely by industry
and the BLM.
The final rule modifies the definition of the term ``land
description'' from the proposed rule in Sec. 3173.1, to clarify the
information needed by the BLM. The purpose of defining the term ``land
description'' in both the proposed and final rules is to ensure that
the geographic location information that operators occasionally provide
to the BLM meets the applicable standards.
Under the proposed rule, the BLM defined ``land description'' to
mean ``the geographical coordinates referenced to the National Spatial
Reference System, North American Datum 1983 or latest edition, in feet
and direction from the nearest two adjacent section lines, or, if not
within the Rectangular Survey System, the nearest two adjacent property
lines, generated from the BLM's current Geographic Coordinate database
(Public Land Survey System).'' The final rule modifies this definition
to require operators to provide information about location that is
consistent with the U.S. Department of the Interior's Manual of
Surveying Instructions (2009) and that includes information about the
quarter-quarter section, section, township, range, and principal
meridian of the proposed location. This definitional change was not
suggested by commenters, but was made to make the definition in Sec.
3173.1 consistent with the existing geographic location information
requirements of 43 CFR. 3162.6, which requires operators to have
geographic location information on their well- and facility-
identification signs. Subpart 3173 requires operators to record land
descriptions on their site facility diagrams, FMP applications, water
draining and hot-oiling paperwork, and reports of theft or mishandling
of production. By confirming the definitional provisions of these two
requirements, the final rule ensures consistency and allows BLM
inspectors to cross-reference the land description information on a
site facility diagram with the geographic location information on a
given facility sign and confirm that they are inspecting the correct
measurement facility. It should be noted that the definition of ``land
description'' does contemplate the use of ``other authorized survey
designations acceptable to the AO, such as metes-and-bounds, or
latitude and longitude,'' which accounts for instances where the land
may be unsurveyed or another survey method is necessary.
As noted in the discussion above, to support the implementation of
the definition of ``economically marginal property'' the BLM added a
definition for the term ``payout period,'' which is defined as ``the
time required, in months, for the cost of an investment in an oil or
gas FMP at a specific lease, unit PA, or CA to equal the nominal
revenue earned from crude oil production for an oil FMP, or natural gas
production for a gas FMP, minus taxes, royalties, and any operating and
variable costs.'' This definition is consistent with the intent behind
the definition of ``economically marginal property'' established by
this final rule. The definition clarifies that payout periods are
determined independently for each oil and gas FMP at a given lease,
unit PA, or CA.
The BLM included a definition for the term ``permanent measurement
facility'' to the final rule in response to a commenter's concern with
Sec. 3173.12(d) of the proposed rule, which required operators to
obtain FMP approval before any production leaves a measurement
facility. The commenter pointed out that during well testing, and
before initiating production, operators send oil to a temporary tank or
send gas down the sales line to determine the well's production rate.
The test results help the operator determine the size and type of
measurement facility needed. The commenter said it would be overly
burdensome to require operators to obtain FMP approvals for temporary
measurement equipment used during well testing as well as for permanent
measurement facilities.
The BLM agrees in part with this comment and has provided a
definition for the term ``permanent measurement facility,'' which means
``all equipment constructed or installed and used on-site for 6 months
or longer for the purpose of determining the quantity, quality, or
storage of production that meets the definition of FMP under Sec.
3170.3.'' In addition, the final rule also
[[Page 81378]]
clarifies that paragraphs (d) and (e) of Sec. 3173.12, which pertain
to when operators must apply for their FMP numbers, apply only to
permanent measurement facilities. Therefore, temporary equipment used
during well testing operations, including temporary tanks to store oil,
are not affected by the FMP requirement. However, since a ``sales
line'' by definition is a permanent facility, and any gas that travels
through it is royalty bearing, the BLM added a 6-month timeframe to the
definition of permanent measurement facility to make clear that the FMP
requirement does not apply during well testing. Six months was chosen
because that is when the BLM typically performs its first environmental
inspection of production facilities after a well is completed, and
after that point, the continued use of temporary equipment at the
wellsite would raise concerns that an operator is having difficulty
installing its permanent facilities.
The BLM added a definition of ``royalty net present value (RNPV)''
to support implementation of the term ``economically marginal
property.'' The final rule defines RNPV as the ``net present value of
all Federal or Indian royalties paid on revenue earned from crude oil
production or natural gas production from an oil or gas FMP at a given
lease, unit PA, or CA over the expected life of the metering equipment
that must be installed for that lease, unit PA, or CA to achieve non-
commingled measurement.'' This definition is consistent with the intent
behind the definition of ``economically marginal property'' established
by this final rule.
The BLM also received comments concerning its use of the term
``royalty-free use.'' Specifically, a commenter expressed concern that
the terms ``beneficial use'' and ``royalty-free use'' were used
interchangeably multiple times in the preamble discussion of the
proposed rule, without any definitions being offered for either term.
The commenter also noted that only the term ``royalty-free use'' was
used in the proposed rule itself, and no definition was provided. The
commenter suggested a definition of ``royalty-free uses,'' which
specifically included all equipment and facilities serving
directionally or horizontally drilled wells that may be located off the
lease.
The BLM agrees with the commenter that it should not have used the
two terms interchangeably. The BLM should have used the term ``royalty-
free use'' rather than ``beneficial use,'' because the former is more
specific and more applicable in the context of this rule. For example,
the term ``beneficial use'' sometimes refers to using produced water
for other purposes, such as a water source for livestock or for
enhancing vegetation regrowth during reclamation, both of which have
nothing to do with production verification and accountability.
The BLM did not, however, feel it was necessary to provide a
definition for royalty-free use at this time. First, the royalty-free
use of oil or gas from onshore Federal and Indian leases, units, and
CAs is governed by the longstanding Notice to Lessees and Operators 4A
(NTL-4A) and the BLM believes the concept to be well understood by
operators. Second, the BLM plans to update its regulations pertaining
to the royalty-free use of oil and gas as part of a separate
rulemaking--Waste Prevention, Production Subject to Royalties, and
Resource Conservation (81 FR 6616) (Waste Prevention Rule)--that will
provide additional clarity on the royalty-free use of oil and gas from
onshore Federal and Indian leases. Until such time as the Waste
Prevention Rule is finalized, for the purpose of this final rule, the
meaning of the term ``royalty-free use of oil and gas'' will be
consistent with the royalty-free use of oil or gas as currently defined
in NTL-4A. No changes were made to proposed rule in response to this
comment.
Section 3173.2 Storage and Sales Facilities--Seals
Paragraphs (a) and (b) of Sec. 3173.2 require any lines entering
or leaving any oil storage tank or storage facility to have valves
capable of being effectively sealed during specific operational
phases--production, sales, water draining, or hot oiling.
Paragraph (c) identifies the specific types of valves that are not
considered ``appropriate valves'' (i.e., valves that must be sealed
during the production phase or the sales phase) and, as such, are not
subject to the requirements of subpart 3173. These valves include
valves on production equipment; valves on water tanks, so long as there
is no possibility of access to production; valves on tanks contains
waste or slop oil; sample cock valves; fill-line valves on certain
marginal production tanks; gas line valves; heating system valves; pump
valves; tank vent-line valves; and sales, equalizer or fill-line valves
on systems where production may only be removed through an approved
metering system.
Paragraph (d) prohibits tampering with an ``appropriate valve,''
and specifies that tampering may result in assessment of civil
penalties for knowingly or willfully preparing, maintaining, or
submitting false, inaccurate, or misleading information under Section
109(d)(1) of FOGRMA, 30 U.S.C. 1719(d)(1), and 43 CFR 3163.2(f)(1), or
for knowingly or willfully taking, removing, transporting, using, or
diverting oil or gas from a lease site without valid legal authority
under Section 109(d)(2) of FOGRMA, 30 U.S.C. 1719(d)(2), and 43 CFR
3163.2(f)(2).
The BLM received many comments on proposed Sec. 3173.2. Several
commenters expressed concern with the relationship between the general
prohibition against tampering under Sec. 3170.4 of the proposed rule
and the specific prohibition against tampering with any appropriate
valve under proposed paragraph (d) of this section.
One commenter, in particular, was concerned that under the new
requirements the commenter would not be able to perform maintenance on
valves without the procedure being considered tampering or unauthorized
seal removal. Two other commenters stated that the criteria for
determining what qualifies as tampering were overbroad and ambiguous.
They also questioned if an unintentional act or human error would be
considered tampering.
The BLM believes these comments have merit and, as discussed
previously, has added a definition of the term ``tampering'' to Sec.
3170.3 of the final rule. As previously noted, ``tampering'' means any
deliberate adjustment or alteration to the meter or measurement device,
appropriate valve, or measurement processes that could introduce bias
into the measurement or affect the BLM's ability to independently
verify volumes or qualities reported. This definition should help the
public understand how the BLM will determine whether a particular
incident constitutes tampering.
As for operator maintenance on valves, such acts will not be
considered tampering as long as the maintenance work does not alter the
valve or introduce bias into the measurement. If the valve being worked
on falls under the seal requirements (i.e., it is used in the process
for determining the quantity or quality of oil for royalty purposes),
it is permissible to remove the seal for maintenance purposes as long
as the specific reason for removing the seal is noted in the seal
record. The BLM did not change the final rule to address this comment.
Another commenter stated that valves would need to be changed out
in response to the requirements under this section, making marginal
wells unprofitable. The BLM does not believe that any valves will need
to be changed
[[Page 81379]]
out because these requirements are the same as those in Order 3, which
already requires all appropriate valves capable of being effectively
sealed to be sealed. Since this provision merely continues existing
requirements, no changes to the final rule were made in response to
this comment.
Another commenter was concerned that proposed Sec. 3173.2(c)(3),
which exempts valves on tanks that contain oil that the AO or
authorized representative (AR) has determined to be waste or slop,
would impose additional costs on operators because of the time it could
take the AO or AR to make the determination. While waiting for the AO
or AR determination, the commenter said, operators would have to spend
money on additional tanks to store their slop or waste oil. The BLM
disagrees. This requirement is very similar to the existing
requirements of Order 3, and therefore will not impose any additional
burdens on operators. A company will not need a new tank while waiting
for a determination from the AO or AR; rather the company will have to
properly seal any tanks holding such oil until it is determined to be
slop oil or waste oil. The cost to obtain a seal should not present any
sort of monetary hardship for the operator. Thus, the BLM did not make
any changes in response to this comment.
Section 3173.3 Oil Measurement System Components--Seals
Section 3173.3 of the final rule identifies a nonexclusive list of
the components used in LACT meters or Coriolis oil measurement systems
(CMS) that must be effectively sealed to indicate whether tampering may
have occurred. The BLM received a few comments on this section of the
proposed rule.
One commenter stated that the proposed seal requirements are much
more extensive than those in Order 3 and will create additional burden
and expense for the operator because seals routinely break and the
seal-reporting requirements for these instances under Sec. 3173.9 are
fairly detailed. In addition, the commenter said there is a risk of
delayed revenue while the operator waits for the AO to approve removal
of a seal. The BLM disagrees that the seal requirements are much more
extensive than those found in Order 3. This final rule adds only four
items to the Order 3 list of components that are used for quantity or
quality determination of oil and that must therefore be effectively
sealed. Those four additional components are the right-angle drive,
totalizer, prover connections, and valves on diverter lines larger than
1 inch in nominal diameter. The BLM does not believe seal requirements
for these components are particularly burdensome, and, since they all
are points where tampering could occur, it is important that they be
subject to the same sealing requirements as other components of the
measurement system.
As for the commenter's concern about revenue being delayed while an
operator waits for the AO to approve removal of a seal--under normal
circumstances, there is no need to wait for AO approval to remove a
seal. Seals may be taken off and put back on as long as these events
are recorded in the seal record. In the event a Federal seal is placed
on a component, the AO must provide approval prior to any removal;
however, an AO can provide verbal approval to remove a Federal seal as
soon as the associated violation is corrected. These comments did not
result in any changes to the final rule.
One commenter said they could not determine what effect proposed
Sec. 3173.3 would have on their operations when related requirements--
contained in the rulemaking that is replacing Order 4 (oil
measurement)--had not yet published or been made available for public
comment. The additional requirements cross referenced in proposed Sec.
3173.3 can be found in proposed 43 CFR 3174.8(a) (for LACT systems) and
proposed 43 CFR 3174.9(e) (for Coriolis systems). The BLM recognized
the need for both sets of requirements to be available for public
comment at the same time, which is why the comment period for this
proposed rule was extended from its original September 11, 2015,
closure date until December 14, 2015, in order to ensure there was
sufficient overlap between the comment periods for the proposed rules
for subparts 3173, 3174, and 3175. This overlap gave operators an
opportunity to review the parts of proposed subpart 3174 that were
referenced in Sec. 3173.3. This comment did not result in any changes
to the final rule.
Another commenter said that the seal requirements for oil
measurement systems are only appropriate at those points where theft or
mishandling can realistically occur, and the requirements under this
section are unnecessary. The commenter suggested that the BLM maintain
the seal requirements in Order 3, which address the sealing of tanks
when oil is sold through a LACT. The BLM did not make a change in
response to this comment. The BLM does not believe that theft or
mishandling, which affects only the quantity of the oil being measured,
are the only factors that may impact the determination of royalties
owed. The quality of the oil being produced will also influence royalty
determination. For this reason, the BLM believes it is necessary to
have a section in the rule dedicated to ensuring that all components of
an oil measurement system that are used to determine the quality and
quantity of oil must be effectively sealed. The BLM does agree with the
commenter's suggestion that we maintain Order 3's seal requirements,
which is why they were incorporated into the list of components that
must be sealed under Sec. 3173.3 of this final rule.
The BLM also received several comments stating that some components
of a LACT are not capable of being sealed, such as flow computers and
back pressure valves. The commenters said flow computers are not
capable of accepting a seal and back-pressure valves cannot operate if
they are sealed. These commenters recommended that the BLM not subject
these two components to the Sec. 3173.3 sealing requirements. A third
commenter stated, without providing specifics, that some of the devices
listed in this proposed section are not constructed to be sealed. The
commenter suggested that sealable components would have to be purchased
or a secondary device would have to be built to allow for sealing.
Without more specific information, the BLM cannot address this comment.
However, prior to issuing this final rule, the BLM re-assessed the
components listed in this section and continues to believe, except as
noted below, that all of the identified components can reasonably be
sealed, as all of them are routinely sealed today.
With regards to requiring flow computers to follow this final
rule's seal requirements, commenters should be aware that the intent of
sealing the flow computer is to have a log of when someone accesses the
software. Sealing a flow computer could be accomplished through a lead
wire seal, adhesive backed paper (sticker), or plastic seal, or a
password and an event log. However, in response to this comment, the
BLM has changed the final rule. The BLM removed flow computers from
paragraph (a)(5) of this section and added a new item to the list--LACT
or CMS--in paragraph (a)(6), giving the operator the opportunity to
decide how best to ensure that the flow computer is sealed. As a result
of these changes, paragraphs Sec. 3173.3(a)(6) through (12) in the
proposed rule are redesignated as Sec. 3173.3(a)(7) through (13) in
the final rule.
As for concerns raised about the inability to seal back-pressure
valves, the BLM has made a change in response to this comment. In
3173.3(a)(7) of the
[[Page 81380]]
final rule (Sec. 3173.3(a)(6) in the proposed rule), the BLM has
clarified that the component that is subject to the seal requirement is
the back pressure valve pressure adjustment. Sealing the pressure
adjustment on the back-pressure valve was already required under Order
3. The BLM believes it is important to preserve this requirement
because if the pressure adjustment is changed after a meter proving, it
could change the flow rate of hydrocarbons through the meter, impacting
the accuracy of the measurement based on the prior proving.
Section 3173.4 Federal Seals
In the final rule, paragraph (a) of Sec. 3173.4 codifies the
authority in section IV of Order 3, which calls for the BLM to place a
Federal seal on any appropriate valve, sealing device, or oil meter
system component that does not comply with the requirements of final
Sec. Sec. 3173.2 or 3173.3. Paragraph (b) clarifies that the placement
of a Federal seal does not relieve the operator of the requirement to
comply with Sec. Sec. 3713.2 or 3173.3. Paragraph (c) prohibits the
removal of a Federal seal without BLM approval.
The BLM received several comments requesting that Federal seals not
be attached immediately upon discovery of a violation that warrants
placement of a seal. Two commenters requested a 10-day notice prior to
the BLM placing a Federal seal, and another commenter requested that a
reasonable time be given to bring the component into compliance prior
to the BLM attaching a Federal seal. Other commenters said the BLM
should not be sealing or changing valves or any other production
components without an operator's representative being present to
witness the change. Commenters recommended that the BLM give notice to
the operator as to why the seal was placed, and the procedure for
removing the seal.
The BLM did not change the final rule in response to these comments
because the only violations that would cause the BLM to place a Federal
seal on valves or production equipment would be those that are
considered major, as defined in 43 CFR 3160.0-5--that is, noncompliance
actions that could cause or threaten immediate, substantial, and
adverse impacts on health and safety, the environment, production
accountability, or royalty income. Since the seal requirements in
Sec. Sec. 3173.2 or 3173.3 of this final rule were put in place to
ensure that tampering does not occur, the BLM generally believes these
incidents of noncompliance constitute major violations.
However, the BLM believes that some of the commenters' concerns
have merit, and will ensure that its Inspection and Enforcement
Handbook provides clear guidance to BLM inspectors that: They must not
change the position of a valve or component; the Federal seal must be
attached to the valve or component as found; and each Federal seal
installed must have a card attached that identifies it as a Federal
seal, and advises that the removal or violation of the seal without
approval by the AO will result in an immediate assessment of $1,000.
The name and telephone number of the AO will be shown on the card. In
addition, the operator will also receive notice in the form of an INC
that will address all the violations associated with the Federal seal
that the operator must correct prior to removal of the seal. The BLM
did not make any changes to the final rule in response to this comment.
Section 3173.5 Removing Production From Tanks for Sale and
Transportation by Truck
Section 3173.5, paragraphs (a) and (b), of the final rule make
clear that, at the completion of either a single or a multiple
truckload sale, the driver of the load(s) must possess all the
information that is required in Sec. 3174.12. Under paragraph (c),
once the seals are broken, the purchaser or transporter is responsible
for the entire contents of a tank until it is resealed.
The BLM received a comment asking us to delay this final rule until
we publish and make available for public comment two related
rulemakings that will replace Orders 4 (subpart 3174) and 5 (subpart
3175). The commenter noted that Sec. 3173.5(a) and (b) require truck
drivers to possess certain information after oil sales, but the
information will be set forth in Sec. 3174.12, which was proposed in
the separate Order 4. The BLM recognizes the commenter's concern, at
least as it relates to the proposed rule to replace Order 4, which is
why the comment period for this proposed rule was extended from its
original September 11, 2015, closure date until December 14, 2015, to
ensure there was sufficient overlap between the comment periods for the
proposed rules for subparts 3173, 3174, and 3175. This overlap gave
operators an opportunity to review the parts of proposed subpart 3174
that were referenced in Sec. 3173.5. This comment did not result in
any changes to the final rule.
Several commenters expressed concern with language in paragraph (c)
that makes the purchaser or transporter responsible for the entire
contents of the oil tank from the time that the seals are broken until
it is resealed. The requirements in paragraph (c) are taken directly
from Order 3 with one minor modification. Under section III.C.1.c of
Order 3, only the ``purchaser'' is responsible for the entire contents
of the unsealed tank during a sale. The commenters stated that Sec.
3173.5(c) would be a burden on transporters because it will cost them
time and money to wait on-site for tanks to be resealed by the
facility's operator after an oil sale. The BLM disagrees with this
comment. It is standard practice for transporters, whether or not they
are the purchasers, to remove and replace seals without the operator's
representative being on location. Transporters do this because it
protects them from liability if, subsequently, produced oil cannot be
accounted for. No changes were made to the final rule as a result of
this comment.
Section 3173.6 Water-Draining Operations
Section 3173.6 of the final rule requires the operator, purchaser,
or transporter, as appropriate, to record specific information when
water is drained from tanks that hold hydrocarbons, including the total
observed volume (TOV) and free water that are in the tank before, and
TOV after, water is drained. Order 3 did not require operators to
record these volumes, which could have led to hydrocarbons being
drained with the water and removed without proper measurement and
accounting, and without royalties being paid.
The BLM received many comments regarding this section. Several
commenters stated that the documentation requirements were excessive
and added little to no value to accounting for production. The BLM made
several changes in response to these comments, to reduce documentation
requirements and eliminate any confusion over when operators should
document the FMP number during water-draining operations. Specifically,
the BLM reduced the overall amount of information that operators must
document by eliminating from this section the requirements that
operators record the opening and closing gauge times, the name of the
person and company draining the tank, and the FMP number associated
with the tank.
Another commenter questioned whether the requirement to identify
the FMP associated with a tank subject to this provision would mean
that an FMP is required for each condensate tank in the field. By way
of clarification, condensate tanks, just like oil storage tanks, must
have FMP numbers.
[[Page 81381]]
However, oil and condensate tanks that are part of a tank battery share
the same FMP number.
Another commenter recommended that the BLM exempt ``low-volume
sources'' from the requirements, to reduce the paperwork and record-
maintenance costs for operators of such sources. The BLM does not
believe that an exemption for small producers (or operators of low-
volume sources) is appropriate and did not change the final rule as a
result of this comment. As noted earlier, it is important for all
operators to ensure that hydrocarbons are not being drained with the
water and removed without proper measurement and accounting, and
without the royalties due being paid. Having operators record the
volume of hydrocarbons that are in the tank before and after water is
drained helps ensure that the proper royalties are paid. When
performing production accountability inspections, the BLM will compare
these water-draining records, along with other production and sales
records, with production reports that operators submit to ONRR. These
records will allow the BLM to independently verify production that is
attributable to Federal and Indian leases. The BLM did not make any
changes in response to this comment.
One commenter said the existing Order 3 seal requirements already
prevent theft of oil because they provide a tracking mechanism for the
transfer of any liquids from production tanks, and therefore the
provisions of the proposed rule were unnecessary. The BLM disagrees
that Order 3's seal requirements already prevent theft of oil. Existing
requirements related to seal records do not provide any information on
how much TOV is in a tank before and after water is drained. They
merely show when a tank is sealed and unsealed, and by whom, not what
was drained, nor how much was removed from the tank. No changes were
made to the final rule as a result of this comment.
Other commenters stated that Sec. 3173.6 would require the gauging
of tanks prior to and after a sale. They said that while such a
practice is necessary during custody transfer, this requirement could
be hazardous to employees because it would unnecessarily expose them to
benzene or volatile organic compounds (VOC). In response to these
comments, the BLM added new language to paragraphs (e) and (g) that
allows either manual or automatic gauging for the opening and closing
gauge, TOV, and free-water measurements, all of which must be to the
nearest \1/2\ inch. Giving operators the option of conducting this
measurements using automatic gauging will provide an opportunity for
operators to reduce employees' exposure in the field.
Finally, one commenter said the color-cut measurement method
requirement in the proposed rule is not accurate for indicating water
oil contact with heavy oils that are less than 30 degrees gravity. The
commenter said that an opening and closing gauge would be a sufficient
indicator to determine the amount of water in the tank. The BLM agrees
with the comment that color-cut measurements are not accurate in some
situations and has removed this requirement from the final rule.
Instead, paragraph (e) has been rewritten to require operators to
simply document ``free-water measurements,'' which allows operators to
use any reliable method for measuring free water, including electronic
equipment.
Section 3173.7 Hot Oiling, Clean-Up, and Completion Operations
Section 3173.7(a) of the final rule requires that specific
information be recorded when hydrocarbons are removed from storage and
used on the lease, unit PA, or CA for hot oiling, clean-up, and
completion operations, including the volume of hydrocarbons removed
from storage and expected to be returned to storage. Paragraph (b)
requires operators to consider as sold, and to measure following the
requirements of this final rule, any production used from storage for
hot oiling, line flushing, or completion operations on a different
lease, unit PA, or CA.
Under Order 3, the operator was required to record only the date,
seal number removed, new seal number installed, and the reason for
removing oil for hot-oiling, clean-up, or completion operations. The
operator was not required to record the volume of hydrocarbons that was
removed from storage and were expected to be returned. This omission
could have led to the volume of produced hydrocarbons being counted
twice--first when it was initially produced then later after it was
returned to storage.
The BLM received many comments on this requirement. A few
commenters said that an operator's field personnel are on hand, closely
monitoring these types of operations, ensuring that the oil is returned
to the tank and that it is counted just once. Commenters said there is
no reason for the BLM to require operators to maintain records of these
volumes because operators only pay royalties on oil that is sold, not
oil that is produced, and hot-oiling, clean-up, and completion
operations are unrelated to sales. The BLM agrees that having an
operator's field personnel on hand, closely monitoring these
operations, is ideal for ensuring that oil is not counted twice during
these operations. However, the BLM's experience has shown that in many
instances field personnel do not monitor these operations because they
are called away for other duties. The BLM did not change the final rule
in response to this comment, because the BLM believes there is a need
to address inconsistent practices among operators and to ensure there
is proper documentation of the volume of oil used in these operations.
In response to the comment that hot oiling, clean-up, and
completion operations have nothing to do with sales volumes, the BLM
notes that it is required to verify not only sales volumes but also
production volumes and to report on avoidably lost gas under NTL-4A.
Hot oiling, clean-up, and completion all involve production volumes,
and therefore are properly within the scope of the proposed rule.
Another commenter said the BLM does not have the authority to
impose the requirements under this section, requested that the BLM
explain why these new requirements are necessary, and asked that we
provide the legal citation for the new law that justifies this
authority. The BLM's authority to impose site-security, record-keeping,
and production accountability requirements for the production of
Federal and Indian oil and gas is not ``new.'' The statutes authorizing
the BLM to issue this rule have been in place for decades and were
identified earlier in this preamble. These statutes include the ones
that were identified as the basis for existing Order 3.
A few commenters said that the requirement that operators gauge oil
level, maintain seals, track FMPs, gauge tanks, etc., during completion
operations will add to the workload of field personnel performing those
tasks. For example, an employee will need to be onsite 24 hours a day,
7 days a week to make sure the seal changes are recorded on the run
tickets and logged properly for tracking purposes. Several commenters
said the documentation requirements under this section were excessive
and added little to no value to production accounting.
The BLM agrees with these commenters that the proposed
documentation requirements were too expansive and in response changed
the final rule to reduce the amount of information that operators must
document during hot oiling, clean-up, and completion operations. In the
final rule, the BLM removed requirements
[[Page 81382]]
that operators document the opening and closing gauge times; the name
of person and company removing production from the tank; and the FMP
number associated with the tank or group of tanks. The BLM has
accounted for the costs of these revised recordkeeping requirements in
its Paperwork Reduction Act analysis, which we discuss later in this
preamble, and concludes that they are not a significant financial
burden on operators.
With respect to the general concern that these requirements are
unnecessary, the BLM does not agree. These requirements are important
and represent an important part of the final rule, because in their
absence, operators could drain, transfer, or sell hydrocarbons without
measuring and accounting for them during hot oiling, clean-up, and
completion operations, resulting in incorrect royalties being paid. The
BLM will use these records when performing production accountability
inspections. Specifically, it will compare records from hot oiling,
clean-up and completion operations, and other production and sales
records, with reports that operators submit to ONRR. This will allow
the BLM to independently verify production that is attributable to
Federal and Indian leases.
As for the commenter's claim that these recordkeeping requirements
for well completion operations would necessitate an operator's field
personnel to be present at the wellsite 24/7, the BLM does not have
enough information to respond to this comment. While the BLM agrees
that, in general, operators will now have to document more information
than they have been documenting under Order 3, the BLM does not believe
that any of these additional recordkeeping requirements will require
company personnel to be onsite 24/7. The final rule was not changed as
a result of this comment.
The BLM did not receive any comments on paragraph (b). However, the
BLM makes a clarification in the final rule that the production
reported to ONRR as sold must be ``for the period covering the
production in question.''
Section 3173.8 Report of Theft or Mishandling of Production
Section 3173.8 of the final rule includes security provisions that
are intended to prevent theft or mishandling of oil, complementing the
minimum standards for site security and production handling established
in this rule. Paragraph (a) requires operators, transporters, and
purchasers to report verbally all incidents of theft and mishandling of
production to the BLM no later than the next business day after they or
their employees discover them. Paragraph (b) specifies the information
that must be included in a written incident report, which is required
within 10 business days of any oral report. Such reports must be made
the next business day after discovery and may be made orally or through
a ``written incident report.'' Oral reports must be followed by written
reports within 10 business days. Adding purchasers and transporters to
these requirements is a change from Order 3, which required only
operators to report theft or production mishandling, but is consistent
with the overall approach to these requirements in the proposed and
final rules.
Many commenters were concerned about the requirement in paragraph
(a) that purchasers and transporters report incidents of theft and
mishandling to the BLM, and questioned the BLM's authority to impose
such a requirement on them. Since the wells and facilities belong to
the operator, commenters said, the operator should be the one reporting
all theft and production mishandling. The commenters said it would be
redundant and unnecessary to have purchasers and transporters reporting
theft and mishandling to the BLM, and could lead to multiple reports
and confusion. A few commenters added that this change could make
operators accountable for potentially arbitrary and inaccurate third-
party reports of theft or production mishandling.
Finally, some commenters asked why operators could be subject to an
immediate assessment when they fail to report theft or mishandling to
the BLM.
The BLM believes it is necessary to require purchaser and
transporters, in addition to operators, to report instances of theft or
production mishandling when they discover them because, as noted in the
proposed rule preamble, purchases and transporters are sometimes the
first to discover such instances or to recognize suspicious activity.
When transporters or purchasers report theft or production mishandling,
the BLM intends to work with transporters, purchasers, and operators to
verify the reports, with each party being responsible for the
information it provides. The BLM's authority to require purchasers and
transporters to report theft or production mishandling comes from
Section 103(a) of FOGRMA, which provides that ``a lessee, operator, or
other person directly involved in developing, producing, transporting,
purchasing, or selling oil or gas . . . shall establish and maintain
any records, make any reports, and provide any information that the
Secretary may, by rule, reasonably require for the purposes of
implementing this Act or determining compliance with rules or orders
under this Act.'' Sections 102(b)(2) and 301(a) of FOGRMA allow the BLM
to prescribe any rules, regulations, or appropriate measures to protect
oil from theft. The final rule simply places the same expectations on
purchasers, transporters, and operators, which are all parties involved
in production, for reporting theft and mishandling of production.
The BLM does not agree that requiring purchasers and transporters
to report theft and production mishandling creates confusion or is
redundant and unnecessary. Reports by purchasers and transporters,
together with information provided by operators, will improve the
existing reporting system by giving the BLM more facts faster to
investigate these situations. No changes were made to the final rule as
a result of these comments.
Other commenters discussing the provisions of the proposed rule
related to theft or mishandling did not agree with the BLM's decision
to eliminate the self-inspection requirements contained in Order 3
section III.F, which are related to Order 3's requirements for
reporting theft or mishandling of oil. The purpose of the self-
inspection requirement, according to those commenters, was for
operators to periodically measure production volumes to assure that
they complied with the BLM's minimum site security requirements. These
commenters said that self-inspection programs are a good practice, and
that it would not be appropriate for the BLM to find an operator in
violation of this section if they elect to implement a self-inspection
program and report incidences of theft and mishandling. The commenters
encouraged the BLM to maintain the Order 3 requirements for a self-
inspection compliance program, rather than eliminate them.
It has been impractical for the BLM to enforce the Order 3 self-
inspection requirements because the requirements were vague, and the
BLM never supplemented them with internal guidance or enforcement
policy. This final rule replaces the Order 3 self-inspection program
with stronger recordkeeping and documentation requirements, such as
those in Sec. 3173.9 (Required recordkeeping for inventory and seal
records). As explained in the recordkeeping section of this preamble,
we believe this approach will ultimately improve overall production
verification and accountability. That said, the BLM
[[Page 81383]]
does not disagree with the notion that self-inspection programs can
help with a company's internal compliance efforts, and nothing in the
final rule would prohibit a company from implementing such a program on
its own initiative. No changes were made in response to this comment.
As for the commenters' suggestion that the BLM not issue immediate
assessments or take enforcement actions against those operators who are
implementing a self-inspection program, the BLM does not agree with
this suggestion. The BLM takes enforcement actions against operators
that fail to report theft or production mishandling. The fact that an
operator has a self-inspection plan in place does not and should not
immunize the operator from enforcement for a failure to report. Under
the final rule, consistent with the proposed rule, an operator that
fails to report is subject to an immediate assessment under Sec.
3173.29 (Immediate Assessments) of the final rule. No change was made
in response to this comment.
Finally, a number of commenters suggested that the BLM should be
told whether incidents of theft or production mishandling have also
been reported to law enforcement and company security in addition to
the BLM. The BLM agrees that it needs to know if law enforcement and
company security have been notified and added a new paragraph (b)(8),
which now includes this requirement. This change will help the BLM work
with company security and law enforcement to investigate and prosecute
alleged incidents of theft and production mishandling in order to
prevent future occurrences.
Section 3173.9 Required Recordkeeping for Inventory and Seal Records
Paragraph (a) of this section of the final rule requires operators
to perform an end-of-month inventory consisting of the TOV in storage
(measured to the nearest \1/2\ inch), subtracting free water, and the
volume not corrected for temperature/S&W, as reported to ONRR on the
OGOR. Paragraph (b) specifies the records that an operator must
maintain for each seal.
The BLM received several comments on proposed Sec. 3173.9. In the
proposed rule, operators were simply required to measure and record the
TOV in storage at the end of each calendar month. A few commenters said
they did not have the ability to measure inventory at all sites on the
actual last day of the month due to the number of tanks they operate,
the volume corrections for temperature/S&W, and the accuracy needed to
meet the measurement standards of this section.
The BLM agrees that operators may not be able to measure all
inventory on the very last day of the month, especially those operators
who have large numbers of storage tanks. In response, the final rule
provides two options for an operator to perform an end-of-month
inventory. The operator can either perform the measurements within +/-3
days of the end of the month, or it can interpolate the values based on
daily production values and gross sales volumes, using inventory
measurements taken before and after the final day of the month. To help
guide operators on the interpolation of their end-of-month inventories,
the BLM provides the following equation in paragraph (b)(2) of this
section, as well as an example of how the equation is to be applied:
{[(X + Y-W)/Z1] * Z2{time} + X = A,
Where:
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and second inventory;
Z1 = number of actual days produced between the first and second
inventory; and
Z2 = number of actual days produced between the second inventory and
end of calendar month for which the OGOR report is due.
These alternate approaches to maintaining inventories give operators
more flexibility to meet the BLM's recordkeeping requirements, but
still ensure monthly volume measurements are recorded.
Other commenters interpreted the proposed section to mean that
operators were required to gauge their storage tanks manually, since at
the time the proposed rule was released the BLM's oil measurement
regulations did not allow operators to use automatic tank gauging
systems. As a result, these commenters asserted that requiring
operators to manually gauge tanks would unnecessarily expose their
employees to hazardous fumes. The BLM understands this concern and has
added clarifying language to the final rule that allows operators to
measure TOV either manually or with automated systems. The BLM was able
to make this change because in the related rulemaking that is replacing
Order 4 with a new subpart 3174, operators now have the ability to use
automatic tank gauging systems for oil sales, and thus such a system
will also be permissible for inventory maintenance.
Other commenters said this section was not necessary because
recording the TOV in tanks is routine practice under sales contracts,
and the seal requirements in paragraph (b) of this section are
unnecessary because they are already covered in Sec. Sec. 3173.2 and
3173.3 of the proposed rules. With respect to those comments stating
that recording the tank TOV is routine operator practice under sales
contracts, it should be noted that those recordkeeping activities
relate to periodic tank sales. Those records do not allow the BLM or
the operator to determine monthly production or to detect theft or
improper handling of production like an end-of-month inventory does.
Additionally, operators are already required to report end-of-month
inventories to ONRR so this requirement should not create an additional
burden for operators. The BLM did not change the final rule in response
to this comment.
With respect to the concerns about paragraph (b), the BLM disagrees
that the seal recordkeeping requirements are already covered in
Sec. Sec. 3173.2 and 3173.3. Those two sections only identify which
valves or components must be sealed. They do not address the
recordkeeping requirements associated with such seals. The BLM did not
change the final rule in response to this comment.
Finally, some commenters asserted that paragraph (b) should not
apply to purchasers and transporters because they are not responsible
for installing or maintaining such seals. The BLM agrees that Sec.
3173.9, particularly paragraph (b), does not apply to purchasers and
transporters. However, the BLM did not change the rule in response to
this comment because the text in Sec. 3173.9 makes clear that its
requirements apply solely to operators.
Section 3173.10 Form 3160-5, Sundry Notices and Reports on Wells
Section 3173.10, paragraphs (a) and (b), require all parties
involved in Federal and Indian oil and gas production to submit Sundry
Notices, Form 3160-5, electronically to the BLM for their site facility
diagrams, requests for FMP designations, requests for CAAs, requests
for off-lease measurement, and any amendments to the diagrams or
requests. As noted in the preamble of the proposed rule, requiring
electronic submission will, in the long run, increase efficiencies
throughout BLM field offices, for both the BLM and operators, by making
the diagrams easier to track and more accessible to inspectors in the
field. Paragraph (b) provides an exemption from the electronic-filing
requirement
[[Page 81384]]
for small operators that do not have access to the Internet.
Several commenters supported the proposed requirements for online
filing, but were concerned with the BLM's ability to handle a
significant increase in electronic submissions ``at one time,'' and
wanted the BLM to clarify what it means when it says that this change
will, in the long run, increase BLM efficiencies. Some of these same
commenters said they were concerned with the ability of the BLM's
existing WIS to handle this volume of submissions.
Requiring electronic submission of Sundry Notices and Reports on
wells provides both operators and the BLM with an efficient
chronological method for tracking items submitted for approval, rather
than relying on hard copies. The BLM is aware that the Well Information
System has had problems in the past, and is working on an improved
version of its in-house database, known as AFMSS II. As part of its
transition to AFMSS II, the BLM is evaluating industry information
technology standards, such as XML, to develop a system that will make
data sharing and management as seamless as possible between the BLM and
the public. That said, even the existing system should not prevent the
BLM from realizing the benefits of electronic filing of facility
diagrams.
One of the reasons the proposed rule gave operators a phase-in
period to apply for an FMP on existing leases, units, and CAs was to
help the BLM avoid having to process a flood of Sundry Notices at one
time. Under the proposed rule, operators would have applied for their
FMP numbers over a 9- to 27-month period, starting on the effective
date of the final rule, on a tiered scheduled based on production
level, with the highest producing wells having the earliest required
application date. As discussed later in this preamble, the final rule
extends the phase-in periods for the FMP application process to 12, 24,
and 36 months, based on production level thresholds that are similar to
those in the proposed rule. This will give some operators up to 3 years
after the effective date of this final rule to apply for an FMP for
stand-alone leases, CAs, unit PAs and CAAs. If a stand-alone lease,
unit PA, or CA has not produced for a year or more before the effective
date of this final rule, the operator will not need to apply for an FMP
until resuming production. The BLM believes that these changes will
substantially reduce the number of electronic filings the BLM must
process at any one time, reducing the risk that its systems lack the
capacity to handle the submissions.
Similarly, and as explained below in connection with Sec.
3173.11(d) and (e), the BLM has also modified the proposed rule's
requirements for updated site facility diagrams. Instead of requiring
all facilities to upgrade their diagrams with 30 days of receiving an
FMP, as was suggested in the proposed rule, under the final rule site
facility diagrams at existing facilities will only have to be updated
when or if the existing facility is modified (e.g., when equipment or
wells are added or removed, when co-located facilities are added, or
when there is a change in operator). This change reduces the overall
number of Sundry Notice submissions associated with site facility
diagrams and helps distribute notice submissions over time.
Some commenters wanted to know if the BLM will send out electronic
notifications when it approves Sundry Notices that have been filed
electronically. The BLM will provide such notifications, just as it
does now as part of its new APD system.
One commenter suggested that the BLM use off-the-shelf software
common to industry to handle its electronic data submissions, saying it
would reduce reporting costs to industry since these programs are
already used industry-wide. The BLM disagrees because the BLM already
has an existing e-filing system up and running, and operators are
already familiar with using it. This system allows operators to see the
status of their submissions and provides them an electronic response of
the AO's decision. The AFMSS II update builds on this existing
infrastructure. The BLM did not change this final rule as a result of
these comments.
Section 3173.11 Site Facility Diagrams
As discussed in the proposed rule, the requirements in Sec.
3171.11 update and replace Order 3's Site Facility Diagram
requirements, which are currently found in section III.I. Paragraphs
(a) through (c) of Sec. 3171.11 set forth the requirements for the
content and format of site facility diagrams, while Appendix A to
subpart 3173 provides some basic examples of what these diagrams should
look like.
Under Sec. 3173.11(a) through (c), a site facility diagrams must
include, in addition to drawings that show the relative locations of
equipment, specific information, such as FMP numbers; the land
description; unit PA, or CA numbers; site equipment; and royalty-free
use information. Site facility diagrams are one of the BLM's primary
mechanisms for ensuring that operators are complying with measurement
regulations and policy, which is why it is important that accurate
diagrams are submitted to the BLM in a timely manner.
As explained in the preamble to the proposed rule, under Order 3
the BLM required operators to provide generalized diagrams showing each
piece of equipment being used at a facility, including connections
between each piece of equipment, valve positions on production storage
tanks (sales valves, drain valves, equalizers, and overflow valves),
and their relative positions to each other. While these diagrams were
useful to the BLM, they did not provide all of the information
necessary for inspection and enforcement activities. The more detailed
information required by this final rule will provide the BLM with a
more useful tool to achieve improved production accountability.
For example, the requirement in paragraph (c)(9) of this final rule
(paragraph (c)(10) in the proposed rule) will allow the BLM, for the
first time, to verify royalty-free-use volumes that operators report on
their OGORs. This paragraph requires operators to specify on their site
facility diagrams which equipment on the lease is using oil or gas
royalty-free and how they determine the volumes of oil or gas used by
that equipment, if the volume is not measured. This requirement will
provide greater consistency in how operators determine the volumes of
oil and gas used royalty-free, and will enable the BLM to more easily
verify those volumes, which enhances production accountability. This
particular change also responds to the GAO recommendations (Report 10-
313) that the BLM establish uniform systems for collecting and tracking
information about royalty-free use in order to ensure that such use can
be properly verified. Affirmatively requiring this information to be
reported on a site facility diagram will ultimately save the BLM and
operator time because it will eliminate the need for the BLM to obtain
the information in connection with a production accountability review.
Paragraph (d) sets forth the timeframe within which facilities that
are required to obtain an FMP under Sec. 3173.12 must submit a site
facility diagram that complies with this rule. It covers both existing
and new facilities. Paragraph (d)(1) in this final rule (paragraph
(c)(1) in the proposed rule) requires operators, whose facilities
become operational on or after the effective date of this rule to
submit their diagrams within 30 days after the BLM assigns their FMP.
For operators of existing facilities that were in operation on or
before the effective
[[Page 81385]]
date of this rule, paragraph (d)(2) explains that such facilities are
not initially required to submit an updated site facility diagram if
they already have one on file with the BLM that meets the minimum
requirements of Order 3. These operators are only required to submit an
updated site facility diagram consistent with the requirements of this
final rule if and when the operators modify their facilities, construct
or modify a non-Federal facility located on their Federal lease or
federally approved unit or communitized area, or if there is a change
in operator.
Paragraph (e) sets forth the timeframe within which facilities that
do not require FMP numbers under Sec. 3173.12 (e.g., facilities that
dispose of produced water) must submit a site facility diagram that
complies with this rule. It covers both existing and new facilities.
Paragraph (e)(1) requires operators of facilities that become
operational after this rule's effective date to submit their diagrams
within 30 days after the facilities become operational. For operators
of facilities in operation on or before the effective date of this rule
that do not require an FMP, paragraph (e)(2) in this final rule
explains that such facilities are not initially required to submit an
updated site facility diagram if they already have one on file with the
BLM that meet the minimum requirements of Order 3. These operators are
only required to submit an updated site facility diagram consistent
with the requirements of this final rule if and when the operators
modify their facilities, construct or modify a non-Federal facility
located on their Federal lease or federally approved unit or
communitized area, or if there is a change in operator.
Paragraph (f) explains that operators of facilities required to
have a site facility diagram have an ongoing obligation to update those
diagrams within 30 days after the operator modifies its facilities,
constructs or modifies a non-Federal facility located on the Federal
lease or federally approved unit or communitized area, or if there is a
change in operator.
The BLM received many comments on this section of the proposed
rule. One commenter suggested that the BLM develop a database that
allows operators to submit the information needed for site facility
diagrams using a standard form. The commenter said any changes to a
site facility diagram, along with other information, could be
automatically and periodically submitted by operators, thus making the
process of submitting and updating diagram information to the BLM
effortless. The BLM recognizes the potential efficiencies provided by
the commenter, but did not make any changes at this time because the
BLM's WIS--which follows the Sundry Notice format--is currently the
only method for electronic submission. At this time, that system does
not allow for submission along the lines suggested by the commenter. As
result, the BLM will accept electronic records that contain the
requested information on additional pages as long as they are submitted
with the actual diagram on Form 3160-5 (Sundry Notices) and they follow
the prescribed numbering format. The BLM did not change the final rule
based on this comment.
Many commenters expressed concern that application of the proposed
rule's site facility diagram requirements to existing facilities is
unnecessary, and that the deadlines in the proposed rule for submitting
the diagrams would be onerous. These commenters also said the demands
in this section are so burdensome that they would cause operators to
reconsider future development plans, after having invested money in
complying with previous regulations.
Although the BLM believes the new site facility diagrams for
existing facilities, including those that handle waste water, will
allow the BLM to improve production accountability, the BLM also
believes that commenters' concerns with the deadlines for submitting
the new diagrams have merit. In response to these comments, and in an
effort to reduce the number of diagrams that operators must initially
submit to the BLM, we have revised paragraph (d)(2) (formerly paragraph
(d) in the proposed rule) and added a new paragraph (e)(2) to the final
rule which specifies that operators of existing facilities are not
initially required to submit updated site diagrams, so long as they
have a diagram on file that complies with the requirements of Order 3.
As noted, these paragraphs require updates to existing diagrams only
when facilities undergo changes. The BLM believes that this change
addresses the identified concern, while ensuring that as these existing
facilities undergo changes the agency will eventually receive site
facility diagrams that meet the requirements of Sec. 3173.11. Although
the existing site-facility diagrams are not as detailed, the BLM will
continue to work off the diagrams that it has on file to perform its
production accountability-related inspections on existing facilities,
until such time as those diagrams are updated.
Other commenters questioned why it was necessary to provide a
diagram for salt-water disposal facilities because, they said, these
facilities are unrelated to actual oil and gas production operations.
The BLM does not agree with this commenter. These diagrams are not a
new requirement. Operators are already required to have site facility
diagrams on file with the BLM for their water-disposal facilities;
Order 3.III.I.1. requires diagrams for ``all facilities.'' The BLM is
responsible for accounting for all production, including water, not
just oil and gas. No changes were made to the final rule as a result of
these comments.
A few comments sought clarification on how to legibly depict
multiple wells and headers, encompassing an area several miles in size,
on a single sheet of 8\1/2\ x 11 paper. The BLM did not change the
final rule based on these comments because paragraph (b) in the
proposed and paragraph (c)(1) in the final rule (paragraph (c)(2) in
the proposed) already state that, while diagrams need to reflect
equipment locations, they need not be to scale, and more than one page
can be used, if necessary. The Appendix to subpart 3173 provides
examples of multi-well submissions.
One commenter said the valve-positioning and labeling requirements
in paragraph (c) and the examples in the Appendix would result in
operators putting redundant information on the diagrams when multiple
tanks, with similar valves that are operated similarly, are involved.
The BLM did not make a change in response to this comment. The BLM
cannot create a single template that addresses how all site facility
diagrams, for a myriad of field configurations, should be drawn. The
Appendix examples are meant to be a starting point for operators. It is
up to the operator to determine how best to identify valve positioning
on paper, as long as the valves and their positions are identified,
legible, and comprehensible as required in Sec. 3173.11.
The BLM received several comments on the requirement in paragraph
(c)(9) of the final rule (paragraph (c)(10) of the proposed rule) that
operators identify on their diagrams any equipment that uses production
royalty-free, and either the calculated or measured volumes that are
used. Under the final rule, operators are permitted to use any method
they want to determine their royalty-free use volume, as long as they
show on the diagram how they determined it.
Several commenters pointed out that royalty-free fuel use
fluctuates monthly, and one commenter even provided its method for
determining ``on lease use fuel gas.'' The commenter recommended
[[Page 81386]]
that the BLM consider letting operators provide an average lease use
fuel gas estimate and questioned the need for operators to report this
information on their diagrams since on-lease fuel gas is already
reported to the BLM. The BLM did not change the final rule in response
to this comment. The commenter has confused BLM and ONRR requirements.
Operators are required to report the volumes of fuel used royalty-free
to power production equipment on a lease to ONRR, not the BLM. In order
to enhance accountability, BLM field inspectors need to be able to
independently verify royalty-free-use volumes reported to the ONRR,
using the information in the diagrams pertaining to the equipment that
uses the royalty-free oil and gas. Currently, the BLM has no method for
determining whether the royalty-free use rate that operators report on
their OGORs is accurate. This new requirement enhances production
accountability and responds to key recommendations made by the GAO
(Report 10-313), as explained above.
A few commenters questioned the BLM's rationale for creating the
new site-facility-diagram requirement, while eliminating the Order 3
requirement for site security plans, which some operators had
established. The BLM agrees that these two requirements are related.
The site-facility diagram was part of the larger site-security plan
required in Order 3. As discussed earlier in this preamble, the Order 3
site-security plan's self-inspection requirements are not in the final
rule. However, elements of the old site security plan requirements have
been incorporated into this final rule at Sec. Sec. 3170.4
(Prohibitions against by-pass and tampering), 3173.8 (Report of theft
or mishandling of production), 3173.9 (Required recordkeeping for
inventory and seal records), and 3173.11 (Site facility diagrams); and
into the final rule that is replacing Order 4 at 43 CFR 3174.12
(Measurement tickets).
Many commenters questioned the need for operators to provide
information and documentation on their site facility diagrams, as
required under proposed Sec. 3173.11, for what they consider to be
extraneous equipment and components. Commenters offered to work with
the BLM to create a pragmatic approach for allowing the BLM to verify
royalty-free volumes and for operators to submit their diagrams within
a sensible time. However, as proposed, many commenters saw this section
as unnecessary and unreasonable overreach by the BLM, and a drain on
resources for both operators and the agency, especially given that
operators would need to track information on multiple components on
numerous pieces of equipment across several locations. For example, one
commenter did not understand how putting equipment serial numbers,
rated fuel use, and manufacturer information on a site facility diagram
would help the BLM verify whether a reasonable determination was made
on royalty-free use volumes reported to ONRR. Depending on their
configuration, production facilities can have an extensive number of
major components, and requiring operators to track down this
information and report it on their diagrams would cause a hardship on
many operators, commenters said.
Another commenter disagreed with the requirement in proposed
paragraph (c)(11) that an operator or its representative include a
signed certification statement on the diagram. This requirement is
redundant and unnecessary, the commenter said, because existing
statutes--18 U.S.C. 1001 and 43 U.S.C. 1212--already make it a crime
for any person to knowingly and willfully make a false statement to the
BLM.
The BLM agrees with these comments and in response has made changes
to the final rule that reduce the information that must be submitted
and expand the timeframe within which the submission must occur,
including deleting paragraph (c)(11). The final rule will not require
operators to include a signed certification statement as part of their
site facility diagrams, because, as noted by a commenter, operators are
responsible by law for ensuring the accuracy of the information in
their diagrams. In response to comments questioning the requirement in
paragraph (c)(10)(i) of the proposed rule, which directed operators to
provide equipment serial numbers, rated fuel use, and manufacturer
information on their site-facility diagrams, the BLM removed this
requirement in paragraph (c)(10)(i) of the proposed rule from the final
rule because the information, although useful in verifying whether
equipment had been replaced, would not help the BLM verify that the
royalty-free-use volumes reported to ONRR were accurate.
One commenter said that the requirement in paragraph (a), that
operators submit a site facility diagram for each FMP, is cumbersome,
particularly in cases where the FMP for oil facilities and gas
facilities are on the same site. The commenter recommended that the BLM
require a single FMP number for an entire facility at a single site in
order make it simpler for operators, while providing the necessary
information to the BLM. The BLM disagrees with this comment because the
BLM's inspection verification process is based, in large part, on
comparing production information that is reported to ONRR against
information contained in a site facility diagram, and operators report
their oil and gas production separately to ONRR. Having information on
both types of facilities on one diagram could complicate and undermine
the BLM's verification process. No change has been made to the rule
based on this comment.
Many commenters were also very concerned with the cost to operators
to comply with the proposed diagram requirement, particularly the costs
of re-submitting all site facility diagrams within the proposed rule's
30-day submission deadline. However, as discussed above and in greater
detail in the Economic and Threshold Analysis, the final rule greatly
scales back the range of circumstances in which operators of existing
operations must submit new site-facility diagrams. This reduces the
number of diagrams that must be prepared and the amount of information
that operators need to provide on those diagrams, which will
significantly reduce compliance costs. The BLM estimated in the
proposed rule that it would take operators 8 hours to prepare and
submit a revised diagram. The BLM now believes that with the reduced
workload, operators can perform this task in 6 hours. The BLM
originally estimated in the proposed rule that operators would submit
revised diagrams for 125,000 existing facilities over a 27-month phase-
in period. After taking a more detailed look at our computer data, the
BLM has revised downward its estimate of the number of existing
facilities to 83,116. The BLM now estimates under this final rule's
revised requirements that only 5 percent of existing facilities, or
about 4,165 facilities, do not have accurate and up-to-date site
facility diagrams on file with the BLM and will have to submit revised
diagrams to the BLM over the 3-year phase-in period. The BLM now
estimates that the total one-time cost to industry to submit revised
site facility diagrams will be $1.6 million, spread over 3 years, down
from the BLM's previous estimate in the proposed rule of $63.6 million.
On an ongoing basis, the BLM estimates operators will submit about
5,000 new diagrams per year for a total annual cost to the regulated
community of $1.9 million.
Other commenters said they were physically limited--by the sizes of
their staff and facilities--from submitting site facility diagrams for
multiple existing
[[Page 81387]]
and new facilities within 30 days of receiving their new FMP numbers.
Commenters said carrying out such a labor-intensive effort within 30
days of receiving an FMP number was impractical, unreasonable, and a
burden. Some comments suggested that a 60- to 90-day timeframe was more
realistic. One commenter suggested 180 days would be more reasonable,
with a couple of others suggesting that operators have up to 1 year to
complete the diagrams. Another commenter proposed that the BLM set a
30-day deadline for new facilities to submit their diagrams that would
start from the date of first production, while another suggested a
phase-in process, and still another comment proposed diagrams for new
facilities only.
The BLM agrees that operators need more time to submit diagrams for
new and existing facilities, and made corresponding changes to the
final rule. The commenter misstated the requirement of the proposed
rule, which would have required operators to submit their diagrams much
earlier--within 30 days of completing construction of their facilities.
Under the final rule, operators will need to submit diagrams for new
facilities (those that become operational on or after the effective
date of this final rule) within 30 days after the BLM assigns an FMP to
those facilities. The BLM believes these changes ensures that it will
not receive a site facility diagram for a new facility prior to having
assigned that facility an FMP number, which means operators will not
have to go back and subsequently revise their diagrams to reflect the
new FMP numbers. As discussed earlier, under the final rule, operators
of existing facilities that already have site facility diagrams on file
with the BLM that meet the requirements of Order 3 do not have to
revise those diagrams unless they modify their facilities or there is a
change in operator.
Finally, one commenter was concerned about having to submit and
resubmit multiple site facility diagrams for a facility with multiple
FMPs, if the FMPs were not approved within 30 days of each other. The
commenter said compliance would be impossible under these
circumstances. The BLM believes that this commenter was trying to
describe a well pad with multiple wells that are coming in to
production consecutively. In this case, the FMP numbers will not
change, but a new site-facility diagram will be required within 30 days
from the onset of production from each well to reflect the new facility
coming online. The BLM did not change the final rule in response to
this comment. With respect to the commenter's concern about facilities
having multiple FMPs, for the most part, facilities will have no more
than two FMPs--one for oil and one for gas. Even though the
applications for each FMP number will be submitted under a separate
Sundry Notices, there is no reason an operator could not submit them at
the same time, nor for the BLM to assign the FMP numbers at different
times, as it is unlikely that the measurement system for oil would come
online later than the measurement system for gas.
Section 3173.12 Applying for a Facility Measurement Point
Section 3173.12 of the final rule establishes a formal nationwide
process for designating and approving the point at which oil or gas
must be measured for the purpose of determining royalty. Prior to this
final rule, the BLM did not have a formal, written process for
designating measurement points on the leases it manages. While some
Field Offices had their own internal policies for establishing these
points, this lack of uniform guidance across Field Offices resulted in
instances of confusion about the location of royalty measurement
points, which interfered with the BLM's production verification
process. This section now requires operators to obtain BLM approval of
FMPs for all measurement points used to determine royalties.
The BLM will approve an FMP that meets the requirements of this
final rule (the most important elements of which are the identification
of the wells associated with the FMP and the measurement method). The
BLM will assign each FMP a unique identifying number, which the
operator, transporter, or purchaser will use when reporting production
results to ONRR. Each FMP number will be 11 digits long. The first two
digits (ranging from 52 to 99) will identify the product--oil or gas--
as well as other information, such as whether the FMP is on-lease or
off-lease, whether it is part of a commingling arrangement, and the
measurement method used at the FMP--tank gauge, LACT, Coriolis, etc.
The next 5 digits will represent the American Petroleum Institute (API)
state and county code, while the last 4 digits will be a combination of
letters or numbers that will make each FMP number unique.
The BSEE already assigns similar FMP numbers for the offshore oil
and gas leases that it manages, which the operator, transporter, or
purchaser must then use when reporting production results to ONRR. The
changes in this final rule will make BLM practices consistent with
existing BSEE and ONRR practices for production reporting.
Paragraph (a)(1) of this final section provides that, unless
otherwise approved, the FMPs for all Federal or Indian leases, unit
PAs, or CAs must be located within the boundaries of the lease, unit
PA, or communitized area from which the production originated, and must
measure only production from that lease, unit PA, or communitized area,
unless otherwise approved. Paragraph (a)(2) provides that off-lease
measurement or commingling and allocation of production requires prior
approval under 43 CFR 3162.7-2 and 3162.7-3, and Sec. Sec. 3173.15,
3173.16, 3173.24, and 3173.25 of this final rule.
Paragraph (b) provides that the BLM will not approve a meter at the
tailgate of a gas processing plant located off the lease, unit, or
communitized area as an FMP. This paragraph codifies existing BLM
practice with respect to tailgate meters.
Paragraph (c) provides that the operator must submit separate
applications for approval of separate FMP numbers for a measurement
point that measures oil produced from a particular lease, unit PA, CA,
or pursuant to an approved CAA, and a measurement point that measures
gas produced from the same lease, unit PA, or CA, or pursuant to an
approved CAA. The requirements for a separate FMP apply even if the
measurement equipment or facilities are at the same location. As
discussed earlier, the first two numbers in the FMP number specify
whether the FMP measures oil or gas. The BLM will not approve the same
FMP number for a facility that measures oil and a facility that
measures gas.
Paragraph (d) requires the operator to apply for approval of an FMP
for a new permanent measurement facility (i.e., one coming into service
after the effective date of the final rule) before any production
leaves the facility. In the final rule, we clarify that this
requirement does not apply to temporary measurement equipment used
during well-testing operations. Until the BLM assigns the FMP number,
the operator must use the lease, unit PA, or CA number for reporting
production to ONRR.
Paragraph (e) provides that for existing permanent production
measurement facilities, an operator has 1 year, 2 years or 3 years from
the effective date of the final rule within which to apply for BLM
approval of its FMP, depending on the production level of the lease,
unit PA, or CA that the
[[Page 81388]]
measurement facility serves. The prescribed application deadline
applies to both oil and gas measurement facilities measuring production
from that lease, unit PA, and CA, whether or not it is part of a CAA.
The final rule requires FMP applications for existing measurement
facilities that serve operations with the highest production volumes to
be submitted first:
1. Under paragraph (e)(1), operators of stand-alone leases, unit
PAs, or CAs, which produce 10,000 Mcf or more of gas per month, or 100
bbl or more of oil per month must, apply for FMP approval within 1 year
after the effective date of the final rule.
2. Paragraph (e)(2) requires operators of stand-alone leases, unit
PAs, or CAs, which produce 1,500 Mcf or more but less than 10,000 Mcf
of gas per month, or 10 bbl or more but less than 100 bbl of oil per
month, to apply for FMP approval within 2 years after the effective
date of the final rule.
3. Paragraph (e)(3) requires operators of stand-alone leases, unit
PAs, or CAs that produce less than 1,500 Mcf of gas per month, or less
than 10 bbl of oil per month, to apply for FMP approval within 3 years
after the effective date of the final rule.
To determine which category a facility is in, the final rule
requires the facility to calculate average production over the 12
months preceding the effective date of the final rule, or over the
period the lease, unit, CA, or CAA has been in production, whichever is
shorter.
Paragraph (e)(4) explains that if a stand-alone lease, unit PA, or
CA has not produced for a year or more before the effective date of
this final rule, the operator is not required to apply for an FMP
immediately, but rather need only apply prior to resuming production.
Under paragraph (e)(6), if an operator applies for FMP approval by the
date, the operator may continue to use the lease, unit PA, or CA number
for reporting production to ONRR while the application is pending,
until the effective date of the BLM-assigned FMP number, at which point
the operator must use the FMP number for such reporting. If, however,
an operator fails to apply for an FMP approval by the date required by
the final rule, paragraph (e)(7) explains that the operator will be
subject to an incident of noncompliance and may also be subject to an
assessment of civil penalty under 43 CFR subpart 3163, together with
any other remedy available under applicable law or regulation.
Paragraph (f) identifies the information that a request for FMP
approval must include. Under paragraph (f)(1), FMP requests must be
submitted on a Sundry Notice and include information pertaining to the
equipment that will be used to measure the oil and gas. Paragraph
(f)(2) requires the applicable Measurement Type Code specified in WIS.
Paragraph (f)(3) requires information about the equipment used for oil
and gas measurement: (i) For gas measurement, specify unique station
number, primary element (meter tube) size or serial number, and type of
secondary device (mechanical or electronic); (ii) For oil measurement
by tank gauge, specify oil tank number or tank serial number and size
in barrels or gallons for all tanks associated with measurement at an
FMP; and (iii) For oil measurement by LACT or CMS, specify whether the
equipment is LACT or CMS and the associated oil tank number or tank
serial number and size in barrels or gallons (there may be more than
one tank associated with an FMP). Paragraph (f)(4) requires operators
to include a list of the API well numbers that will flow to the
requested FMP if that FMP will serve more than one well, and provide a
land description for the FMP location. Under paragraph (f)(5), the FMP
location by land description must also be included in the FMP
application.
As explained below, the BLM in the final rule has also reduced the
quantity of information that operators must submit on their FMP number
applications. For consistency with Sec. 3173.10(c)(10)(i), the BLM
removed requirements that operators provide component names,
manufacturer, model, serial number, range limits for electronic flow
computers, transducer (static, differential, and temperature), chart
recorders, LACT totalizer, and Coriolis meter from Sec.
3173.12(f)(3)(i), (ii), (iii), (iv) and combined subparagraphs (iii)
and (iv) into (iii).
Paragraph (g) allows concurrent requests for FMP approval and for
approval of off-lease measurement or commingling and allocation.
Section 3173.12 is a key element of the final rule as it implements
one of the GAO's central recommendations: That the Interior Department
consistently track where and how oil and gas are measured, including
information about meter location, identification number, and owner. By
requiring operators to obtain approval from the BLM for the location of
the FMP at which oil or gas is measured, the final rule provides that
consistent tracking. The BLM will also now tie the FMP numbers to other
appropriate approvals and documentation that are part of its production
verification and accountability efforts, such as site facility
diagrams, off-lease measurement approvals, commingling approvals, and
royalty-free use (if volumes used royalty-free are measured).
In the final rule, operators, purchasers, and transporters must
include on all records the FMP number or until the BLM approves the FMP
number, the lease, unit PA, or CA number, along with a unique equipment
identifier and the name of the company that created the record.\12\
Records include, but are not limited to, calibration reports, gas
analysis, sales statements, manifests, seal records, and related
approvals. Once assigned, the operator must use the FMP number for
production reporting to ONRR after the effective date of the BLM's FMP
approval.
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\12\ Once an FMP number is approved, it must be used on all
subsequent reporting as outlined in this rule.
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The BLM estimates there are approximately 83,116 existing oil and
gas facilities associated with Federal and Indian leases. Many
facilities have one FMP for oil and one FMP for gas for a total of
approximately 166,232 FMPs for existing facilities.
In connection with its creation of the new FMP system in Sec.
3173.12, the BLM has also revised its existing well and facility
identification provisions at 43 CFR 3162.6(b) and (c) to include a
signage requirement for wells on Federal or Indian lands and facilities
at which Federal or Indian oil or gas is measured or processed.
Additional revisions to Sec. 3162.6 include: (1) Making the surveyed-
location language in paragraphs (b) and (c) consistent, including a new
reference to longitude and latitude; and (2) Removing a sentence in
paragraph (b) that provided a grace period for well signs that were in
existence on the effective date of the rulemaking in which that section
was first promulgated.
The BLM received a comment requesting that the definition of an FMP
in Sec. 3173.1 include more details on how to obtain an FMP, the
deadlines for operators to obtain an FMP, and the economic impacts that
the FMP requirement would have on industry. The BLM disagrees with this
commenter. Section 3173.12 of this final rule provides all of the
information requested by the commenter related to requests to apply for
an FMP. It addresses the deadlines--which are based on average
production volumes--for operators to submit FMP applications for
facilities that are in service on or before the effective date of this
rule, or that will come into service after the effective date. It also
specifies
[[Page 81389]]
the three production thresholds on which the FMP application deadlines
are based. As for the economic impacts, the BLM carefully evaluated
those as part of the rulemaking process in both a draft and a final
regulatory impact analysis for this rulemaking, both of which are made
available to the public. The Procedural Matters section of this
preamble contains a short discussion of this rule's potential economic
impact on industry. We did not change the final rule as a result of
this comment.
A number of commenters were concerned that they could not meet the
proposed rule's deadlines in Sec. 3173.12(e) for applying for and then
receiving an FMP number before producing oil and gas. They said the
resources needed to prepare FMP applications would be exorbitant,
especially for large producers that have many thousands of wells, many
of which will likely have associated commingling or off-lease
measurement approvals that the BLM will need to review (see discussion
of Sec. 3173.16 below).
Many commenters also complained about the proposed tiered volume
thresholds that figured into the timelines for filing FMP applications.
Many operators said that most of their wells' production levels would
require them to submit their FMP applications within 9 months of the
final rule's effective date. Commenters said such timeframes would be
unreasonably short for operators with large well inventories,
considering that they would also be required to submit new site
facility diagrams and possibly update existing commingling and off-
lease measurement approvals.
Under the proposed rule, operators would have had to submit their
FMP application within:
Twenty seven months from the effective date of the final
rule for leases, unit PAs, and CAs that produced less than 3,000
thousand cubic feet (Mcf) of gas or 20 bbl of oil per month;
Eighteen months from the effective date of the final rule
for leases, unit PAs, and CAs that produced between 3,000 and 6,000 Mcf
of gas or 20 and 40 bbl of oil per month; and
Nine months from the effective date of the final rule for
leases, unit PAs, and CAs that produced over 6,000 Mcf of gas or 40 bbl
of oil per month.
The BLM agrees with commenters that the proposed deadlines were too
tight. In response, the BLM changed the final rule to give operators
additional time to submit FMP applications for facilities that are in
service before the effective date of the final rule. The amount of
additional time is based on the facility's average reported monthly oil
and gas production volumes over the previous 12 months. When
establishing the new thresholds, the BLM analyzed lease production data
in AFMSS to determine the impacts on all currently producing leases. In
setting the FMP application deadlines, the BLM attempted to spread the
impact evenly across the three timeframes and across all BLM-
administered leases.
As discussed previously, the final rule also allows operators to
continue to produce oil and gas while their FMP applications are
pending BLM approval, provided that those applications are submitted
within the deadlines specified in Sec. 3173.12(e). While waiting for
their FMP approvals, operators may continue to use the lease, unit PA,
or CA numbers that they have been using for reporting their production
to ONRR. These changes should make it easier for operators to meet the
final rule's FMP application deadlines and give them more time to plan
and budget for this new requirement, while continuing their production
operations. As explained in connection with Sec. 3173.11(d) and (e),
this final rule removes the proposed rule's requirement that all
existing facilities submit updated site facility diagrams within 30
days of approval of an FMP, further reducing requirements on existing
facilities.
In addition, as discussed previously, the BLM changed the final
rule to eliminate some of the information required in the FMP
applications (e.g., equipment serial numbers and manufacturer
information). Furthermore, the final rule exempts leases, unit PAs, and
CAs, which have not produced any oil or gas within the past 12 months.
Only when operators resume production from these idle leases, unit PAs,
and CAs must they then apply for FMPs.
A number of commenters also expressed concern that the BLM would
not have been able to handle the number of FMP applications that the
agency would have received under the proposed rule's timeline and
requirements. However, the BLM now anticipates having a much smaller
workload, spread more evenly over time. For one thing, a review of
AFMSS data suggests that there are only 83,116 active facilities
affected by this rule--about 25 percent fewer than the BLM had
estimated in analyzing the proposed rule. In addition, the final rule
requires operators to provide less information on their FMP
applications and site facility diagrams than the proposed rule would
have required. We now estimate that it will take BLM staff 2 hours to
process each FMP application, instead of the 4 hours we anticipated
under the proposed rule's information requirements. Additionally,
because of the provisions allowing continued production and reporting
while an FMP application is pending, operators should no longer be
concerned about potential FMP application backlogs.
Several commenters said they were concerned about delays in the FMP
approval process holding them up from putting new wells online and
removing production from the lease. The proposed rule at Sec.
3173.12(d) required operators to ``obtain'' FMP approval for
measurement facilities that came into service after the rule's
effective date before they could begin removing production from a
lease, unit PA, CA, or CAA. The BLM agrees that proposed paragraph (d)
needed to be changed to avoid production delays on new facilities. To
address these concerns, the BLM has made several changes to paragraph
(d) in the final rule. First, the BLM added language to the section to
clarify that operators must apply for FMP approvals for permanent
measurement facilities only--not temporary test facilities--as defined
in Sec. 3173.1 of this final rule. In addition, the BLM added language
to paragraph (d) that requires operators of new facilities to simply
``apply for'' FMP approval before any production leaves the permanent
measurement facility. This change allows operators to install a new
measurement facility, remove production from that facility without
delay, and use the lease, unit PA, or CA number for production
reporting to ONRR until the BLM assigned an FMP number, as long as they
apply for their FMP approval before any production leaves that
permanent facility. While the applications are pending, operators may
continue using their lease, unit PA, or CA number for reporting
production to ONRR.
One commenter thought the BLM should allow operators to file one
application on the facility as a whole, and not be required to submit
one application for oil and another for gas. The BLM did not revise the
rule as a result of this comment. One of the purposes of an FMP is to
be able to consistently verify where and how oil or gas is measured.
The BLM does this by comparing information that operators report to the
BLM against information operators report to ONRR, which does, in fact,
collect the oil and gas production information separately. Using one
FMP number to track oil and gas measurement operations together would
compromise the BLM's ability to consistently verify production
[[Page 81390]]
measurements for royalty purposes. Such a system is also incompatible
with ONRR's existing reporting systems, and it would not meet the goals
of establishing an FMP.
Finally, one commenter said that BLM staff should be given a
deadline for approving FMPs, since it is not fair to hold operators to
multiple deadlines, making them subject to INCs for missing those
deadlines, while not holding the BLM to the same standard. As discussed
above, the BLM's new FMP approval process will not interfere with
operators' production. Once operators file a timely request for an FMP
approval on existing facilities, they may continue to operate and use
their lease, unit PA, or CA number for reporting production to ONRR
until the BLM assigns an FMP number.
Once an FMP number is assigned to a facility, Sec. 3173.13(a) of
this final rule gives the operator several months before it must use
the FMP number when reporting production to ONRR. Specifically, for
existing facilities, the operator will have to begin using the FMP
number for reporting production to ONRR on its OGOR for the fourth
production month after the FMP number is assigned. For facilities that
come into service after the effective date of this final rule,
operators are required to apply for FMP approval before any production
leaves the permanent measurement facility and then use the FMP number
for reporting production to ONRR on its OGOR for the first production
month after the FMP number is assigned. As result of these changes, we
do not believe deadlines for BLM review are necessary or appropriate.
Section 3173.13 Requirements for Approved Facility Measurement Points
Section 3173.13 of the final rule sets forth the requirements that
are applicable to all approved FMPs. Paragraph (a) requires the
operator of an existing facility to use assigned FMP numbers in
reporting production to ONRR on its OGORs for the fourth production
month after an FMP is assigned. For new facilities in service after the
effective date of this rule, paragraph (a) requires the operator to
begin using its assigned FMP numbers on its OGORs for the first
production month after the FMP number is assigned.
Paragraph (b) requires an operator to file, within 30 days after
any changes or modifications to an approved FMP, a Sundry Notice
notifying the BLM of the change. It also describes the information that
operators must provide to the BLM in the Sundry Notice, including any
changes or modifications to the equipment that is used for measuring
oil or gas at the FMP, or to the API well numbers associated with the
FMP.
The BLM received several comments on this section of the proposed
rule. Unlike the final rule, the proposed rule required operators to
use their FMP numbers for both recordkeeping purposes and production
reporting to ONRR beginning on the first day of the month after the FMP
number was assigned. A few commenters said they needed more time to
start using the number for production reporting and recordkeeping
because an FMP could be issued on the last day of the month, thereby
obligating the operator to use the FMP on the next day. The commenters
said that this would not give them enough time to take the steps they
need to comply with FMP requirements, such as stenciling the FMP number
onto equipment, labeling all records with the FMP number, and making
updates to their existing database systems that track oil and gas
production operations.
The BLM agrees that requiring operators to begin using their FMP
numbers for recordkeeping and production reporting on the first day of
the month after the FMP number is assigned may not be possible for some
operators. As discussed earlier, the BLM changed Sec. 3170.7(g) from
requiring operators to use FMP numbers on all records, to allowing
operators to use either FMP numbers or lease, unit PA, or CA numbers,
along with unique equipment identifiers, on their records. In addition,
the BLM changed final Sec. 3173.13(a) to extend the effective date
that operators of existing facilities are required to begin using their
FMP numbers in production reporting to ONRR. Under the final Sec.
3173.13(a), operators must start using FMP numbers for reporting
production to ONRR on their OGORs for the fourth production month after
the FMP number is assigned. For example, if the BLM assigns an existing
facility an FMP number on January 17, the operator must begin using
that FMP number on its May production OGORs. Because ONRR requires
operators to submit their electronic reports ``on the 15th day of the
second month following the production month being reported,'' the May
production report must be submitted by July 15, effectively giving the
operator 5-\1/2\ months of leeway before having to submit a report
using the FMP number assigned on January 17. The BLM chose this new
timeframe because it believes that nearly six months is ample time for
operators of existing facilities to start using their new FMP numbers
for reporting production to ONRR.
For new facilities, operators will be required to begin using their
FMP numbers in reporting production to ONRR on their OGORs for the
first production month after the FMP number is assigned. For example,
if the BLM assigns the FMP number on April 30, the operator must begin
using that FMP number for its May production. As noted, however, the
May production report is not due to ONRR until July 15, effectively
giving the operator 2-\1/2\ months leeway before having to submit the
report using the FMP number.
Some commenters asked why proposed Sec. 3173.13(d) required
operators to submit a Sundry Notice detailing ``any'' modifications
they make to an approved FMP and why the changes were made. Commenters
said the BLM does not need this information. The BLM agrees that it
does not need to know why a change was made and has removed this
requirement from the final rule. However, the BLM does need to know
when operators change out measurement equipment at an approved FMP,
along with specific information about the replacement equipment, and
when they add or remove wells served by an FMP, along with the
associated API well numbers. The BLM needs this information so that it
can keep track of these types of changes, which directly impact the
BLM's efforts to verify production. In addition, the BLM has provided
some additional context, by clarifying that it does not need to be
notified when temporary modifications (e.g., for maintenance purposes)
are made. With these clarifications, the final rule in paragraph (b)(1)
still requires operators to file a Sundry Notice within 30 days
notifying the BLM of changes in measuring equipment at an approved FMP
or of the addition or subtraction of wells served by an approved FMP.
These are essentially changes in the information that operators
submitted on their FMP applications, as required under Sec.
3173.12(f)(3) and (4).
The BLM received several comments on the requirement in proposed
Sec. 3173.13(a) that operators stamp or stencil FMP numbers on
specific pieces of equipment within 30 days after an FMP number
assignment. Commenters said this requirement was too expensive and
would take too much time. Several commenters recommended that the BLM,
instead, cross-reference the FMP number to a unique meter station
identifier supplied by the operator, such as the meter station number,
LACT ID number, or tank number, all of which are already available and
visible to BLM inspectors. The BLM agrees that the
[[Page 81391]]
requirement to stamp or stencil FMP numbers on equipment that is used
to measure for royalty is unnecessary and has removed it from the final
rule.
The BLM changed the final rule at Sec. 3173.12(f) to require
operators, when they apply for a gas FMP number, to identify the
royalty measurement point by specifying a unique station number;
primary element (meter tube) size or serial number; type of secondary
device (mechanical or electronic); and associated API well numbers
where production from more than one well will flow to the requested
FMP; along with a land description of the FMP's location. On an oil FMP
number application, operators must supply the tank number or tank
serial number and size in barrels or gallons; specify whether LACT or
CMS, if applicable; associated API well numbers where production from
more than one well will flow to the requested FMP; along with a land
description of the FMP's location.
One commenter said operators should be exempt from the requirement
that they file a Sundry Notice when they temporarily modify an FMP due
to changing out equipment for maintenance. The commenter said the
replacement equipment, using the same measurement methodology, would
not impact accuracy. The BLM agrees that operators do not need to
notify the BLM when they install temporary replacement equipment while
performing maintenance on the permanent equipment. As noted, the final
rule clarifies in paragraph (b)(1) that the BLM does not need to be
notified when temporary modifications (e.g., for maintenance purposes)
are made.
Finally, one commenter objected to the requirement in proposed
paragraph (b)(2) that operators file a Sundry Notice whenever there is
a change in the wells or facilities served by an FMP. This commenter
said an operator may need to transfer product to different meters
several times a day when the meters freeze during the winter months.
The commenter said it would be impossible to maintain a list of the
wells going to the FMPs under these conditions. The BLM is not aware of
situations where operators direct their gas stream to different sales
meters because of line freezing. This practice may be allowed on State
and private wells, but, such a transfer is not allowed on Federal and
Indian wells. We did not change the final rule as a result of this
comment.
Sections 3173.14 through 3173.21 Commingling and Allocation Approvals
As explained in the Definitions section of this preamble,
commingling, for production accounting and reporting purposes, means
the ``combining, before the point of royalty measurement, production
from more than one lease, unit PA, or CA, or production from one or
more leases, unit PAs, or CAs with production from State, local
governmental, or private properties that are outside the boundaries of
those leases, unit Pas, or CAs.'' Operators apply for commingling
approval for several reasons, including:
(1) It can simplify accounting to have the sales point be the same
as the point of royalty measurement;
(2) Lower operating costs can be achieved by reducing the number of
meters required (such as when well testing is an appropriate allocation
method); and
(3) Lower operating costs can also be achieved by eliminating the
need for separate plumbing and surface equipment (pipelines,
separators, dehydrators, compressors, tanks, etc.).
Commingling can also have some advantages for the BLM:
(1) More accurate measurement can sometimes be achieved from a
meter measuring combined flows, which can be better-conditioned and,
more consistent, and have higher flow rates, than from a single low-
volume meter measuring erratic flow with a higher potential for
multiple phases of fluid;
(2) The environmental footprint can be reduced by reducing the need
for duplicate surface equipment; and
(3) Production accounting can be simplified by reducing the number
of meters to inspect and verify.
However, in many situations the advantages of commingling are
offset by increased measurement uncertainty, increased potential for
measurement bias, and a decrease in the BLM's ability to verify
reported production volumes. This is especially true if the properties
proposed for commingling are of different ownership, have different
royalty rates, or have different royalty distributions.
As explained below, Sec. Sec. 3173.14 through 3173.21 of the final
rule restrict the instances in which the BLM will approve commingling
and establish the standards that an operator must meet to obtain an
approval. Existing regulations at 43 CFR 3162.7-2 and 3162.7-3 require
BLM approval before operators commingle production from a Federal or
Indian lease with production from other sources; however, prior to this
rule, there were no regulations addressing how or under what
circumstance commingling should be approved. The requirements in this
final rule are based on and codify the policy outlined by the BLM with
respect to commingling approvals in IM 2013-152 (2013), ``Reviewing
Requests for Surface and Downhole Commingling of Oil and Gas Produced
from Federal and Indian Leases.'' The principal difference between the
provisions of this rule and the BLM's existing IM is that the final
rule establishes a new process for the BLM to review existing CAAs when
operators apply for their FMP approvals. In contrast, the IM focused
solely on new CAAs. Also, in response to public comment and additional
internal reviews, the final rule expands the number of exemptions under
which an existing or proposed CAA could be commingled if the CAA does
not meet the criteria identified in Sec. 3173.14 (a) of the final
rule.
Section 3173.14 Conditions for Commingling and Allocation Approval
(Surface and Downhole)
Section 3174.14(a)
To ensure the accuracy and verifiability of the volume and quality
measurements on which royalty is based, Sec. 3173.14(a) states that
the BLM ``may grant a CAA only if the proposed allocation method used
for any such commingled measurement does not have the potential to
affect the determination of the total volume or quality of production
on which royalty owed is determined for all the Federal or Indian
leases, unit PAs, or CAs which are proposed for commingling. . . .''
Paragraph (a)(1) goes on to identify the conditions under which this
occurs.
The most common situation when this occurs is when all the
properties proposed for commingling are 100 percent Federal or leased
100 percent by the same Indian tribe, have the same fixed royalty rate,
and have the same revenue distribution. In these situations, the
allocation method is irrelevant because the total amount of royalty
received by the Federal Government or tribal mineral interest owner
will be the same regardless of how it is allocated to the individual
leases, unit PAs, or CAs that are part of the CAA. Consequently, the
BLM can ensure accurate measurement and proper reporting by inspecting
and verifying only the commingled point of royalty measurement (i.e.,
the commingled FMP). This would also apply in situations where, for
example, ``lease-line'' CAs proposed for commingling are all 50 percent
Federal and 50 percent non-Federal.
[[Page 81392]]
Based on comments received on the proposed rule and additional
internal reviews, the BLM revised paragraph (a) and its subparagraphs
as outlined below. In paragraph (a) itself, the BLM added language
which explicitly states the criteria the BLM uses to approve a
commingling application. Paragraphs (a)(1)(i) and (a)(1)(ii) were
retained, with modifications for clarity, from the proposed rule. Those
provisions recognize that if the leases, unit PAs, or CAs to be
commingled are 100 percent Federal or leased 100 percent by the same
Indian tribe, and at the same fixed royalty rate, then commingling is
generally acceptable, assuming the other requirements of this part are
met. Indian allotted leases are not included under paragraph (a)
because there would be virtually no instances where the revenue
distribution to the allottees would be identical in different leases,
unit PAs, or CAs.
Several commenters suggested that commingling among unit PAs or CAs
that have less than 100 percent Federal ownership should be recognized
as permissible, so long as they have the same proportion of Federal
interest. The BLM agrees with this comment and added paragraph
(a)(1)(iii) to allow commingling of Federal unit PAs or CAs where each
unit PA or CA proposed for commingling has the same proportion of
Federal interest, which is subject to the same fixed royalty rate and
revenue distribution. Under this provision, the BLM could approve a
commingling request where an operator proposes to commingle two Federal
CAs of mixed ownership where both are 50 percent Federal/50 percent
private, so long as the Federal interests have the same royalty rates
and royalty distributions. The BLM also added a new paragraph
(a)(1)(iv), which provides a parallel provision for tribal interests,
with the key again being identical percentage of tribal participation
and royalty rates.
In paragraph (a)(2) of the final rule, the BLM makes it clear that
the operator or group of operators that are part of a CAA must provide
the BLM with the allocation methodology for the properties from which
production is to be commingled, along with an agreement signed by the
operators that are parties to the CAA if there is more than one
operator. Paragraphs (a)(3) and (a)(4) remain unchanged from the
proposed rule.
Paragraph 3173.14(a)(3) requires operators to demonstrate that each
of the leases, unit PAs, or CAs proposed for inclusion in a CAA is
producing in paying quantities or, in the case of Federal leases,
capable of producing in paying quantities. One commenter asked why the
BLM wants to know that wells involved in commingling are capable of
production in paying quantities. The purpose of this requirement is to
ensure that CAAs are not used to extend the terms of a nonproducing
lease, by allocating production to it. The BLM did not change the rule
as a result of this comment.
Paragraph (a)(4) requires that the FMP(s) for the proposed CAA
measure production originating exclusively from the leases, unit PAs,
or communitized areas in the proposed CAA. The BLM received no comments
on this provision.
Section 3173.14(b)
Paragraph (b) of final Sec. 3173.14 sets forth the exceptional
circumstances in which the BLM will allow commingling even when the
circumstances outlined in paragraph (a) are not met because, for
example, there is a combination of Federal and non-Federal ownership,
Indian allotted leases are involved, or the Federal or Indian leases
have different royalty rates. This paragraph includes the two
circumstances given in the proposed rule: Economically marginal
properties (called low-volume properties in the proposed rule) and
overriding considerations, such as environmental impacts. The final
rule also adds three additional circumstances where the BLM can approve
commingling:
When the average monthly production over the preceding 12
months for each Federal or Indian lease, unit PA, or CA proposed for
the CAA is less than 1,000 Mcf of gas per month, or 100 bbl of oil per
month;
The CAA has been authorized under tribal law or otherwise
approved by a tribe; or
The CAA covers the downhole commingling of production from
multiple formations that are covered by separate leases, CAs, or unit
PAs where the BLM has deemed the commingling of these formations to be
an acceptable practice for the purpose of achieving maximum ultimate
economic recovery and resource conservation.
The BLM received numerous comments on this paragraph in the
proposed rule, stating that the exceptions granted in paragraph (b) of
the proposed rule were not adequate for surface commingling approvals
in cases involving low production volumes. The commenters said that
this would result in lost oil and gas production, revenue, and
royalties from operators forced to shut-in thousands of wells covered
by existing CAAs where surface commingling takes place and where the
economics did not justify the cost of installing new metering and
measurement equipment. In many of these instances, the commenters
stated that production volumes have declined to the point where the
revenue from continued operation would not be sufficient to justify
installing new measurement equipment, particularly in the current low-
price environment.
The BLM disagrees with these comments. The provisions for approving
a CAA for economically marginal properties (low-volume properties in
the proposed rule) in both the proposed rule and the final rule were
designed specifically to allow the BLM to determine if a property would
truly be shut in if the only alternative was for the operator to
achieve non-commingled measurement of production. The BLM believes many
of the worst case scenarios flagged by commenters would fit within the
economically marginal property exception. Unlike downhole commingling,
the costs for surface commingling are relatively easy to define. An
operator on the edge of profitability should be able to demonstrate to
the BLM under paragraph (b)(1) that the properties proposed for
commingling qualify as economically marginal properties. The commenters
did not submit any data to substantiate that the existing provisions
under paragraph (b)(1) were inadequate as they relate to surface
commingling.
Although the BLM did not make any changes to the rule based on
these comments, the BLM changed the economic threshold in the final
rule based on comments on the definition of low-volume property in the
proposed rule. As discussed in connection with Sec. 3173.1, under the
new definition of an economically marginal property, the BLM changed
the threshold from a 10 percent before-tax rate of return in the
proposed rule to an 18-month after-tax payout in the final rule. The
BLM believes this change will increase the number of leases, unit PAs,
or CAs that would qualify as economically marginal leases and,
therefore, might qualify for a CAA under this paragraph. The BLM does
not have any data to quantify this increase, however.
Commenters also expressed concern about the workload and timeframes
involved with obtaining a commingling approval under paragraph (b).
Because the provisions of paragraph (b)(1) of both the proposed and
final rule are very similar to the provisions of IM 2013-152, the BLM
has experience with the process of reviewing CAAs for economically
marginal properties. Based on its experience processing commingling
requests under IM 2013-
[[Page 81393]]
152, the BLM agrees that the process for requesting and reviewing a CAA
can take time, especially for properties that do not clearly fit within
the economic thresholds established in the final rule.
As a result, the BLM made two changes in the final rule. The first
change was to grandfather any existing surface commingling approval
where the average production rate over the previous 12 months for each
of the Federal or Indian leases, unit PAs, or CAs included in the
approval is less than 100 bbl of oil per month or 1,000 Mcf of gas per
month (see Sec. 3173.16(a)(1) and (2)). Second, recognizing that such
limited production may also occur in connection with new CAA approvals,
Sec. 3173.14(b)(2) now allows the BLM to approve new CAAs if the
average production rate from the proposed CAA satisfy the thresholds
for grandfathering of existing CAAs. The new CAA would also have to
comply with Sec. 3173.14(a)(2) through (4); however, under the final
rule, the BLM will not require any additional economic analysis from
the operator.
The BLM chose these thresholds because properties producing below
these thresholds would almost always qualify as economically marginal
properties under this rule. Therefore, the BLM can approve commingling
requests that qualify under this paragraph with significantly less
paperwork burden on both the BLM and industry, and without the in-depth
economic analysis that would have been required in the proposed rule.
The BLM chose the oil threshold of 100 bbl per month by assuming the
cost of achieving non-commingled measurement of oil would be $50,000
(setting a small oil tank, for example). The production rate required
to achieve an 18-month payout of this investment, assuming a $60 per
bbl oil price and including taxes, royalty payments, and fixed and
variable operating costs, would be about 3.5 bbl per day, or
approximately 100 bbl per month.
The BLM used a similar approach for determining the gas threshold.
The BLM assumed that an operator would have to invest $20,000 to
achieve non-commingled measurement of gas (the cost of installing a new
meter). The production rate required to achieve an 18-month payout of
this investment, assuming a $3 per MMBtu gas price, and including
taxes, royalty payments, and operating costs, would be about 30 Mcf/
day, or roughly 1,000 Mcf per month.
The BLM added Sec. 3173.14(b)(3) to the final rule, which provides
for CAAs that have been authorized under tribal law or otherwise
approved by a tribe. The BLM included this provision in response to
tribal comments indicating that tribal law or agreements may
independently identify circumstances where commingling is appropriate.
The BLM added this provision because it believes that tribes should
have a say in approving CAAs that involve production from tribal
leases.
The BLM received many comments stating that the exceptions provided
in Sec. 3173.14(b) of the proposed rule did not address downhole
commingling agreements in the New Mexico portions of the San Juan and
Permian Basins and elsewhere that would not meet the requirements Sec.
3173.14(a). The commenters said that this omission would result in lost
oil and gas production, revenue, and royalties from operators forced to
shut-in thousands of wells at existing CAAs where downhole commingling
takes place and where the economics do not justify the cost of drilling
additional wells or segregating downhole production. Many of the wells,
according to the commenters, were drilled specifically to commingle
downhole production from multiple leases, CAs, and unit PAs, including
combinations of Federal, Indian, fee, and State ownership. The
commenters said downhole commingling allows operators to reduce costs
and environmental impacts by reducing the number of wellbores because
multiple zones can be produced out of a single wellbore. In addition,
commenters stated that some individual zones do not have enough
production to justify the drilling and completion costs for separate
wells. Other commenters stressed that downhole commingling increases
the maximum ultimate economic recovery because reservoir energy from
lower formations allows oil and gas from highly-depleted upper
formations to be produced (i.e., production from the lower formation is
necessary to produce the upper formation). In many of these instances,
production volumes have declined to the point where the revenue from
continued operation would not be sufficient to justify drilling new
wells or re-completing existing wells to avoid downhole commingling,
particularly in the current price environment.
The BLM agrees with commenters that the exceptions listed in the
proposed rule, need to be expanded to account for downhole CAAs, to
ensure that improvements in measurement accuracy and the BLM's ability
to verify production made by this rule do not unnecessarily result in
operators shutting in large numbers of existing wells, particularly
during times of low commodity prices. The BLM believes that it is in
the public interest to receive royalty on a volume of oil or gas that
may have heightened levels of uncertainty and may not be perfectly
verifiable by the BLM, rather than receiving no royalty at all if the
property is shut in to avoid the cost of achieving uncertainty and
verifiability goals.
The low-volume exemption in the proposed rule would have provided
an objective measure of the economic viability of a lease, CA, or unit
PA, as it relates to downhole commingling. However, this economic test
has been difficult to implement for downhole commingling applications
under IM 2013-152 because the costs associated with achieving non-
commingled downhole production are highly speculative and vary by
facility and formations. These costs could be in the millions of
dollars if an operator had to drill multiple wells in lieu of downhole
commingling in one wellbore. It is also difficult to predict or
quantify the benefits of increasing the maximum ultimate economic
recovery from a well due to the ability to produce more oil and gas
from downhole commingling.
As a result of these comments, the BLM made two changes in the
final rule. First, the BLM added an exception for certain categories of
downhole commingling under paragraph (b)(4). This new exception allows
the BLM to approve downhole commingling of production from multiple
leases, CAs, and unit PAs if the BLM deems the proposed operation to be
an acceptable practice for the purpose of achieving maximum economic
recovery and conservation of the oil and gas resource. This exception
provides a means for the BLM to recognize downhole commingling
practices that have historically been approved in areas where such
practices provide the only way to produce the Federal or Indian
interest, and therefore are necessary to avoid having some operators
prematurely plug existing wells. The addition of this provision gives
Field Offices flexibility to approve downhole commingling requests
based on local knowledge and experience with the characteristics of a
particular oil or gas reservoir. Second, for existing downhole
commingling approvals, the BLM added Sec. 3173.16(a)(1), which will
grandfather all downhole commingling approvals in existence prior to
the effective date of this rule (see discussion under Sec.
3173.16(a)(1)).
Several commenters said that the final regulations should state
clearly how the BLM will balance the Federal interest in royalty
measurement against competing interests, such as environmental
concerns. One commenter
[[Page 81394]]
recommended that the BLM include an exemption from the commingling
requirements in situations where the BLM's denial of a request for a
CAA would increase a project's environmental impact. The BLM did not
make any changes to the rule in response to these comments because
paragraph (b)(5) of the final rule already expressly allows the BLM to
consider approving a CAA if there are overriding conditions, such as
topographic or other environmental considerations, notwithstanding
potential negative royalty impacts from commingled measurement. Section
3173.14(b)(2) of the proposed rule contained a similar provision. The
BLM has determined that this language would allow the BLM to grant new
CAAs in instances where the BLM determines that minimizing
environmental impacts takes precedence over ensuring accurate and
verifiable measurement and proper reporting of oil and gas removed or
sold from a lease, unit PA, or CA. The BLM believes these situations
will be rare and CAA approval will only be considered after exhausting
all feasible alternatives, including alternate measurement techniques.
The environmental analysis for the final rule indicates that in most
cases where operators are required to install new facilities, they will
likely place those facilities at sites where there is existing surface
disturbance and where the environmental impact would be minimal (see
the Procedural Matters section below for more discussion about the
environmental analysis). If new equipment requirements result in new
surface disturbances, the BLM, under the provisions of this rule, will
evaluate any potential environmental impacts and require operators to
mitigate them.
One commenter stated that the added and unnecessary cost to
industry to have to build and maintain separate pipelines and
facilities without a substantial benefit for the BLM in return is
unreasonable. The commenter said that they have a few wells in a field
that are not in the unit, but use the same facilities that service the
unit. The commenter is concerned that they would not be able to
continue commingling in the future without doing a substantial economic
study to quantify the cost to build separate facilities including
shipping facilities. Another commenter asked the BLM to consider
exempting those properties that are in close proximity to an existing
gathering system and allowing production from those properties to be
commingled with other properties, even if they are not considered to be
low-volume properties.
The BLM disagrees with these comments and did not make any changes
to the rule as a result. Allocation methods that affect royalty
measurement and reporting have the potential to increase measurement
uncertainty, introduce bias, and inhibit the BLM's ability to verify
and account for oil and gas production removed or sold from a lease,
unit PA, or CA. The exceptions that allow for commingling when
allocation methods affect royalty are included in paragraph (b) of the
final rule; they cover cases where the requirement to achieve non-
commingled measurement of production would cause a prudent operator to
shut in production or would cause significant and unavoidable
environmental impacts. When demonstrating whether a lease, unit PA, or
CA is economically marginal, operators can and should include the cost
of building additional gathering lines, any new facilities, and
mitigating environmental impacts into their capital cost calculations
to see if they would qualify for commingling approval under paragraph
(b)(1) of this section. If they do not meet the definition, or any of
the other exceptions in paragraph (b) of this section, then the
operator should be able to construct the additional facilities while
still realizing a reasonable return on that investment, rather than
shutting in production from a particular well.
One commenter was concerned that, under the CAA requirements,
operators who currently commingle small amounts of saleable liquids
produced from gas wells (e.g., condensate) would have to install
separate storage tanks for that liquid, imposing a significant and
unjustified cost on operators. The BLM agrees with this concern raised
by the commenter and made two changes to the final rule as a result.
First, the definition of economically marginal property (low volume
property in the proposed rule) was changed in the final rule to clarify
that the expected costs and revenues for the economic analysis need
only take into consideration the commodity for which the measurement
equipment would be built, whether it is the oil or gas. In the example
provided by the commenter, the economic analysis of condensate
measurement would only consider the income stream from the sale of
condensate and would not include the income stream from the sale of
gas. Therefore, the small amounts of condensate generated would likely
qualify for an exemption under paragraph (b)(1). Second, the BLM added
paragraph (b)(2) to the final rule which provides an automatic
exemption from the CAA restrictions and from performing an economic
analysis for leases, unit PAs, or CAs that produce less than 100 bbl of
oil per month or 1,000 Mcf of gas per month, averaged over the previous
12 months. In this example, if the small amount of saleable condensate
was less than 100 bbl per month averaged over the previous 12 months,
the BLM could grant commingling approval for the condensate without any
further analysis, assuming that the conditions in paragraph (a)(2)
through (a)(4) were also met.
One commenter representing Native Alaskan interests said it would
not be economically feasible to prevent commingling of production from
BLM lands that are within a unit PA that has an existing measurement
system approved by all parties, when the BLM lands comprise only a
small portion of the production. The BLM did not make any changes to
the final rule in response to this comment, for two reasons. First, if
the BLM portion of the unit PA is very small or the production is low,
it might qualify as an ``economically marginal property'' under the
definition of an economically marginal property in Sec. 3173.1. In
this case, the BLM could approve commingling with other unit PAs within
the unit or other properties outside of the unit. The BLM may also be
able to approve commingling under Sec. 3173.14(b)(5) if achieving non-
commingled measurement of production addresses some overriding
consideration, such as avoiding undue environmental impacts. If, on the
other hand, the properties that are proposed for inclusion in a CAA do
not meet the definition of economically marginal properties, do not
present some other overriding consideration, such as environmental
impacts, or otherwise satisfy one of this rule's criteria, then the BLM
will require the operator to achieve non-commingled measurement of that
unit PA.
A couple of commenters suggested that the BLM is creating new law
by establishing standards and requirements for existing CAAs that were
not in Order 3. The BLM does not understand the comment. The purpose of
the rulemaking process that the BLM is going through is to establish
new standards and requirements. By following the BLM's authorizing
statues and the procedures established by the Administrative Procedure
Act, 5 U.S.C. 551 et seq., the BLM is able to establish new or
different standards and requirements than those found in existing Order
3. As explained elsewhere in this preamble, the final rule is squarely
within the scope of the BLM's authorizing statutes and the
[[Page 81395]]
related delegations of authority from the Secretary.
Several commenters also said the BLM has not analyzed the impacts
of the rule on industry and the BLM, and requested clarification on how
the BLM will balance the Federal interest in royalty measurement
against competing interests. The BLM disagrees that it has not analyzed
the impacts on industry or the BLM. As stated earlier in this preamble,
the BLM has rigorously weighed and considered the economic impacts that
this final rule will have on industry and prepared draft and final
regulatory impact analyses for this rulemaking, which are available to
the public. The Procedural Matters section of this preamble contains a
short discussion of this rule's potential economic impact on industry.
The analysis estimates that this rule's CAA requirements will have a
one-time cost to industry of $4.9 million to $7.6 million for operators
to submit documentation and respond to the BLM's informational requests
for existing leases, and $2.7 million to install meters where the BLM
rescinds existing commingling agreements. The analysis also estimates
there will be an annual paperwork cost to industry from these
provisions of $3 million to $4.6 million for new and modified
commingling agreements, and $1.6 million in new annual metering
installation costs for those FMPs where a commingling agreement is
rescinded.
The BLM believes that the final rule provides clear guidance on how
the BLM will balance the Federal interest in accurate measurement with
competing interests, such as not causing production to be shut in or
creating additional environmental impacts. The final rule includes
numerous provisions that allow commingling in cases where the public
interest is better served by allowing commingling even if it results in
potential negative effects to royalty measurement. These instances
include properties that the BLM determines to be economically marginal,
properties that produce below set thresholds, situations that involve
downhole commingling, and where unnecessary or undue degradation or
unavoidable environmental impacts or other overriding considerations
would result if commingling were denied. The BLM did not make any
changes to the rule based on these comments.
Section 3173.15 Applying for a Commingling and Allocation Approval
Section 3173.15 of the final rule establishes the requirements
operators must follow when requesting a CAA, and the information they
need to include. Most of these requirements were in the proposed rule,
but the final rule includes changes to the amount and type of
information operators must include in their applications. The BLM made
these changes in response to many comments it received on this section.
The following discussion describes those comments and the changes that
were made.
One commenter suggested that proposed paragraph (b) be changed to
require operators to submit as part of their CAA applications an
allocation method, instead of an allocation schedule, which is subject
to frequent changes. The BLM agrees that information about a CAA's
allocation method would be more useful, and as a result changed the
final rule to require an allocation method instead of a schedule.
Several commenters said they did not believe the BLM has the
authority to require operators to submit site facility diagrams as part
of new CAA approvals for existing facilities, as required in paragraph
(e) of the proposed rule. The BLM agrees that it does not need a site
facility diagram to approve a CAA application for existing facilities
and has eliminated that requirement in the final rule in response to
these comments.
One of the commenters asked about the purpose in Sec. 3173.15(e),
for requiring operators to provide a map showing the boundaries, FMPs,
and location of wellheads and production facilities as part of their
commingling and allocation application. In response, the BLM changed
paragraph (e) of the final rule to reduce the amount of information
that operators must include in maps submitted as part of CAA
applications. The required maps need only show the boundaries of any
lease, unit, unit PA, or CA from which production is proposed to be
commingled and indicate the locations of existing or planned facilities
with the relative location of all wellheads (with API numbers), the
piping, and existing or proposed FMPs included as part of the CAA
request. The BLM needs this information for several reasons, one of
which is to determine if all the production flowing through the
proposed FMP originates from the leases, unit PAs, or CAs proposed to
be part of the CAA. Another reason is to obtain clarity on what leases,
unit PAs, or CAs are actually proposed for commingling. This is
especially important when unit PAs or CAs are included in the proposal.
In these situations, the location of a well or facility in relation to
lease, unit PA, or CA boundaries, is critical for the BLM to understand
when evaluating a commingling application. For example, one well may be
physically located on a Federal lease but only produce from a CA that
covers one of the formations under that lease, while another well on
the same lease may only produce from a portion of the lease that is not
part of the CA. In this case, the BLM would have to understand that
even though both wells are physically located on the same lease, a CAA
is required to combine their production because their production
originates from different properties. The BLM did not make any changes
to the rule based on these comments.
One commenter asked whether the BLM planned to monitor which wells
are flowing to which FMP and make operational recommendations. While
the BLM has no intention of making operational recommendations, it will
monitor which wells are flowing to which FMPs if that affects the CAA
or the underlying allocation of production. The BLM did not make any
changes to the rule based on these comments.
Several commenters wanted to know why, in Sec. 3173.15(k),
submission of up to 6 years of gas analyses, including Btu content and
all oil gravities, is required for CAA requests. They indicated that it
would be too burdensome for CAA applicants to provide historical crude
oil gravity and natural gas heating value data, as only current data is
relevant for trying to determine the prices received for these
products. A couple of other commenters said this information
requirement is excessive and would not improve the quality of the
application. The BLM does not believe this to be an onerous
requirement. First, 6 years' worth of data would not necessarily
include a lot of data, especially for lower producing leases, unit PAs,
and CAs for which the BLM would consider approving a CAA. For example,
under 43 CFR 3175.100, a very-low-volume FMP (producing 35 Mcf per day
or less), is only required to have a gas analysis taken once per year,
so 6 years of data for that well is only 6 gas analyses. For oil, the
API gravity is only determined when an oil sale takes place. A low-
producing oil lease may only have an oil sale several times per year,
in which case 6 years of API gravities would include only one or two
dozen API gravities. Second, operators should already have this
information readily available because they are currently required to
maintain records for at least 6 years under 43 CFR 3170.7, which
retention period has been increased to 7 years for Federal leases under
this rule. One of the reasons the BLM needs historical Btu and API
gravities is to
[[Page 81396]]
assess the allocation methodology proposed by the operator. If, for
example, the gas analysis data showed statistically significant
variations between Federal and non-Federal properties proposed for a
CAA, the BLM may require that the allocation method account for the Btu
differences. On the other hand, if the gas analyses for the properties
proposed for commingling were not significantly different, then the
allocation method could be purely volume based. The BLM could also
analyze the historical trend of Btu content or API gravity to determine
if, for example, increasing Btu content could result in greater future
royalty. Without this data, it would be impossible for the BLM to
perform any analysis on the allocation method or on future revenue
projections as part of an economic analysis.
Another commenter noted that this information has no royalty impact
if the properties are 100 percent Federal or Indian mineral ownership
with the same fixed royalty rate and distribution. The BLM agrees with
this comment and added a caveat to Sec. 3173.15(k) indicating that
this information is required only if the CAA is not approved under
Sec. 3173.14(a)(1).
The BLM also determined it was necessary to make other changes to
Sec. 3174.15 in the final rule to address considerations related to
the administration of the rule. As part of the final rule, the BLM
clarifies in paragraphs (f) through (i) which additional approvals
operators must seek if their commingling proposals entail new surface
disturbance or take place on Indian lands or on lands administered by
other Federal surface management agencies, in case operators are
unaware of these requirements. Finally, this section clarifies that if
off-lease measurement is part of a commingling and allocation proposal,
then a separate Sundry Notice under Sec. 3173.23 is not needed as long
as the information required under paragraphs (b) through (e) and, where
applicable, paragraphs (f) through (i) of Sec. 3173.23 is included as
part of the request for approval for commingling and allocation. This
revision clarifies that an applicant may submit both proposals in one
Sundry Notice request.
Section 3173.16 Existing Commingling and Allocation Approvals
Under Sec. 3173.16 of the final rule, the BLM will review an
existing CAA when it receives an operator's request for an FMP number
for a facility associated with the CAA. The BLM made numerous changes
to both the structure and content of this section in the final rule in
response to comments.
Section 3173.16(a)
A new paragraph (a) was added to the final rule that grandfathers
existing commingling approvals in some specific situations. Paragraph
(a)(1) grandfathers all existing downhole commingling approvals.
Based on the numerous comments the BLM received on downhole
commingling approvals (see a discussion of those comments under Sec.
3173.14(b)), the BLM decided to grandfather all existing downhole
commingling approvals. The BLM is aware that there are large numbers of
wells in the San Juan basin and elsewhere that are currently approved
for downhole commingling. The BLM believes that the vast majority of
these wells are producing low volumes of oil and gas and that continued
production of these wells increases the maximum ultimate recovery of
oil and gas. As a result, the BLM has made a determination that it is
in the public interest to ensure these wells continue to produce even
if the methods used to allocate production to Federal and Indian
leases, unit PAs, and CAs potentially result in higher levels of
uncertainty, bias, and make verification of production more difficult.
The BLM also believes that most of these wells would be approved by the
BLM to continue commingling even if the BLM were to perform an
evaluation on them as would have been required under this section of
the proposed rule. Grandfathering all existing downhole commingling
approvals will streamline the review process and reduce the paper work
burden on both industry and the BLM. When the BLM receives a request
for an FMP for a well that has an existing downhole CAA, the BLM will
document that the existing downhole CAA qualifies under Sec.
3173.16(a)(1) of the final rule. The BLM will address any shortcomings
of the existing approval, such as the absence of a defined allocation
method, on a case-by-case basis during inspections and production
audits. The BLM may issue written orders to operators to correct these
deficiencies.
Paragraph (a)(2) grandfathers existing surface commingling
approvals where each lease, unit PA, or CA that is part of the approval
produces less than 100 bbl of oil per month or 1,000 Mcf of gas per
month, averaged over the previous 12 months. See the discussion under
Sec. 3173.14(b) for an explanation of how the BLM derived these
thresholds. As with downhole commingling, the BLM decided to
grandfather these existing commingling approvals based on comments
received on the proposed rule. However, the BLM does not agree with
comments stating that the economic exemptions in the proposed rule were
inadequate. The BLM believes that the economic exemptions in both the
proposed and final rules are adequate to address those operations where
achieving non-commingled measurement of production would truly be
uneconomic. In addition, the definition of an economically marginal
property in the final rule expands the criteria in the proposed rule by
changing the threshold from a 10 percent before tax rate of return to
an 18-month after tax payout. The BLM believes this could significantly
increase the number of leases, unit PAs, and CAs that would be able to
qualify for the economic exemption.
The BLM does, however, agree with comments expressing concern over
the paperwork burden associated with preparing and reviewing
applications involving lower volume leases, unit PAs, and CAs. The BLM
chose to grandfather these existing surface commingling approvals based
on the understanding that leases, CA, and unit PAs producing below
these thresholds would almost certainly qualify under the definition of
an economically marginal property. The purpose of grandfathering these
approvals, therefore, was to reduce the paperwork burden for both the
BLM and industry.
Under this provision, the operator of any lease, unit PA, or CA
that is below these thresholds would retain the existing CAA from the
BLM without any further information or analysis required. The BLM would
only have to verify that the average monthly production rates of the
leases, CAs, and unit PAs included in the approval are below the
thresholds listed in this section.
Section 3173.16(b)
A new provision has been added to paragraph (b), which clarifies
that if the grandfathering conditions in paragraph (a) of this section
are not met, then the existing CAA must meet the minimum standards and
requirements for a CAA under Sec. 3173.14 of the final rule.
This section also sets out a process if the AO identifies
deficiencies. Paragraph (b)(1) requires the AO to notify the operator
in writing of any inconsistencies or deficiencies with an existing CAA.
The operator will then be given 20 days after receipt of such notice to
correct any inconsistencies or deficiencies, provide the additional
information requested, or request an extension of time. When the AO is
satisfied that the operator has corrected
[[Page 81397]]
any inconsistencies or deficiencies, the AO will terminate the existing
CAA and grant a new CAA based on the operator's corrections.
Paragraph (b)(2) clarifies that the AO may terminate an existing
CAA and grant a new CAA with new or amended COAs to make the approval
consistent with the requirements for CAAs under Sec. 3173.14 of the
final rule. Under the proposed rule the AO could simply impose new or
amended COAs to an existing commingling approval.
Section 3173.16(c)
One of the primary goals of paragraph (c) in the final rule (Sec.
3173.16(a) through (d) of the proposed rule) is to ensure that existing
commingling approvals that do not qualify for grandfathering under
paragraph (a) of this section, meet the standards for commingling under
Sec. 3173.14. Another primary goal is to ensure that, if the existing
commingling approval does meet the standards under Sec. 3173.14, it
also contains the information required under Sec. 3173.15, to ensure
that the BLM can verify the volumes allocated to each lease, unit PA,
or CA that are part of the existing CAA.
Under paragraph (c), the BLM will review existing CAAs that do not
qualify for grandfathering under paragraph (a), for their consistency
with the minimum standards and requirements under Sec. 3173.14 when
the operator submits a request for an FMP number. If the BLM determines
that the existing CAA does not meet the requirements under Sec.
3173.14, the BLM may take several courses of action. Under paragraph
(c)(1), the AO will notify the operator in writing of any
inconsistencies or deficiencies that the BLM identifies. The operator
will have 20 business days to provide additional information requested
by the BLM, request an extension of time in which to reply to the AO,
or correct any inconsistencies or deficiencies. Under paragraph (c)(2),
the BLM can impose new or amended COAs on an existing CAA to make it
compliant with the requirements of this final rule. Paragraph (c)(3)
allows the AO to terminate the CAA if the operator fails to correct the
deficiencies that the BLM identifies.
The only significant change to paragraph (c)(1) of the final rule
relative to paragraph (b) of the proposed rule is that the BLM
clarifies that when the operator corrects any inconsistencies or
deficiencies, the BLM will terminate the existing CAA and grant a new
CAA in its place. The BLM made a similar change to paragraph (c)(2) of
the final rule (paragraph (c) of the proposed rule), which clarifies
that the BLM will impose new or amended COAs on an existing CAA by
terminating the existing CAA and granting a new CAA in its place that
includes those COAs.
Under paragraph (d) of the final rule (paragraph (e) of the
proposed rule), if the BLM approves a new CAA to replace an existing
agreement, it will be effective on the first day of the month following
its approval. The BLM also included a new sentence in this paragraph
that clarifies that any resulting change in the allocation method will
only apply from the effective date of the CAA forward. The BLM added
this clause to clarify that changes in the allocation method will not
be applied retroactively. The BLM believes that retroactive application
of new allocation percentages would impose a large paperwork burden on
both industry and the BLM and would not be necessary.
Numerous commenters requested that the BLM consider grandfathering
all existing CAA approvals. One commenter said the modifications to
their facilities will put up to 87 percent of their production at risk
of being shut in and possibly lost forever, along with the royalties to
each of the mineral owners. The BLM agrees that there are instances
where existing commingling agreements do not need to meet the final
rule's commingling standards outlined in Sec. 3173.14(a)(1), and has
provided exemptions in Sec. 3173.16(a) that allow operators to
maintain existing agreements. See the discussion under Sec. 3173.16(a)
for further discussion. In addition, Sec. 3173.14(c) includes three
additional circumstances, beyond the three provided under the proposed
rule, in which the BLM can approve a CAA. Given the grandfathering
provisions and the expanded number of situations where the BLM can
approve a CAA under the final rule, the BLM does not believe that any
existing CAAs that are truly on the edge of profitability will be
impacted by the final rule's requirements.
Other commenters did not like the idea of being required to upgrade
existing wells and facilities that comply with existing laws,
regulations, and policies. While the BLM notes that standard terms and
conditions found in Federal oil and gas leases require compliance with
all applicable requirements, including requirements that might be
subsequently promulgated by the BLM, the BLM nevertheless believes that
this comment has some merit. Most existing surface commingling
approvals are for leases, unit PAs, and CAs where production volumes
are low enough, or other overriding considerations exist, such that the
CAA will comply with the requirements of Sec. 3173.14(a) or (b) of the
final rule with little or no changes required. Similarly, any CAA
granted under IM 2013-152 should already meet the requirements of the
final rule, especially considering that the final rule adds four
additional exemptions under which the BLM may grant a CAA as compared
to the two exemptions allowed under the IM (for low-volume properties
and overriding considerations), and lowers the threshold for leases,
unit PAs, and CAs to meet the definition of an economically marginal
property. For the relatively few existing CAAs that do not meet the
requirements of the final rule, some changes to plumbing or measurement
equipment may be required. In these cases, the BLM will determine that
a CAA is not justified because these leases, unit PAs, or CAs do not
meet the definition of an economically marginal property and no other
overriding conditions exist that would allow the BLM to grant a CAA.
One commenter said the proposed rule would require operators to
submit all existing authorizations to the BLM for re-approval, and
added that many operators and BLM staff spent countless hours
negotiating approvals of existing CAAs to ensure they protect
environmentally sensitive areas while providing accurate measurement of
production. Although the BLM did not make any changes to the rule based
on this comment, the final rule includes grandfathering provisions
under Sec. 3173.16(a), which would no longer require operators to
submit existing downhole commingling authorizations or surface
commingling authorizations that qualify under Sec. 3173.16(a)(1) and
(2) when applying for an FMP. In addition, for those existing CAAs that
do not meet the grandfathering criteria of paragraph (a) of this
section, but comply with the requirements of the new rule, the BLM will
not require re-approval--these CAAs will be allowed to continue as
originally approved.
Several commenters disagreed with the requirement in Sec.
3173.16(c)(1) that operators correct any inconsistencies or
deficiencies that the AO finds with an existing CAA within 20 business
days. One commenter said North Slope operators have significant
weather-related challenges that would make it difficult for them to
meet the 20-business-day deadline, while another said that the required
fixes could involve installing new piping, which would likely take
longer than 20 business days. Several commenters said this final rule
will require every existing
[[Page 81398]]
CAA to have some work done and operators must be given flexibility if
they have multiple CAAs because 20 business days may not be enough time
to bring them all into compliance. Another commenter said that they
have made substantial investments in their gathering systems and would
need a reasonable amount of time to make the changes to facilities that
handle leases with mixed ownerships that are not already part of a unit
PA or CA.
In response to these comments, the BLM added language to the final
rule at Sec. 3173.16(c)(1) which allows an operator to request an
extension during the 20-business-day timeframe. The operator should
justify the extension request by explaining the factors that will not
allow it to comply within the 20-business-day timeframe, and provide a
timeframe under which they can comply. The BLM will consider the
request and grant an extension if the justification is adequate. This
final rule will not require every existing CAA to undergo significant
work to bring it into conformity with the new requirements as one
commenter suggested. In fact, the BLM estimates that the majority of
existing CAAs will continue operating as they have been because they
are exempt from the requirements due to their low production volumes or
other factors.
Several commenters said it would be unfair for the BLM to apply new
COAs that existing CAAs could not meet, causing production to be shut
in. Another commenter said it would be unreasonable for the BLM to
impose new or amended conditions of approvals on existing commingling
agreements and recommended that Sec. 3173.16(c) be deleted altogether.
The BLM does not agree with these comments and did not make any changes
to the final rule as a result.
The BLM estimates that only a small percentage of existing CAAs
will require new COAs and most of those COAs will be for minor
deficiencies such as providing a better explanation of the allocation
process. For those new COAs that require additional work to which the
operator may object, the BLM has already included a provision in
paragraph (c)(2) of the final rule that will allow the existing CAA to
continue in effect during the pendency of any appeal of the decision
that requires the new COAs. The BLM did not make any changes to the
rule based on these comments.
Lastly, some commenters expressed concern that existing CAAs were
at risk of being terminated if the BLM did not timely respond to their
FMP applications and review their CAA approvals. As stated earlier,
operators may continue to produce oil and gas prior to FMP approval and
CAA review and may continue to use their lease, unit PA, or CA numbers
for reporting production to ONRR as long as they have applied for their
FMP numbers within the deadlines specified under Sec. 3173.12. The BLM
did not make any changes to the rule based on these comments.
Section 3173.17 Relationship of a Commingling and Allocation Approval
to Royalty-Free Use of Production
Section 3173.17 clarifies that approval of a CAA does not
constitute approval of off-lease royalty-free use of production in
facilities located at an off-lease FMP approved under the CAA. The BLM
did not make any changes to this section.
One commenter from the San Juan Basin said the new CAA requirements
would reduce Federal royalties from existing CAAs because operators
would have to install new compressors at each well, resulting in more
royalty-free production used as fuel to power those compressors. The
commenter provided a diagram that showed a compressor for each lease
that they believe would be required if commingling was not approved.
For comparison, another diagram showed one large compressor located at
an off-lease FMP in lieu of the wellhead compressors, if commingling
was approved. The commenter stated that with commingling approval,
operators must pay royalty on the fuel used at the commingled off-lease
compressor because it does not qualify as royalty-free use.
The BLM disagrees with the premise of this comment because there is
nothing in the scenario presented by the commenter that would compel
them to install separate lease compressors if the BLM denied
commingling. The small amount of royalty the operator would not have to
pay if the compressors were located on-lease would never offset the
additional capital and ongoing expense of having to install, operate,
and maintain three lease compressors as compared to one large
compressor located at a central delivery point. Instead, if the BLM did
not grant a CAA, a prudent operator would simply use the allocation
meters already installed at each property they were proposing to
commingle as FMPs, continue to use the large off-lease compressor, and
continue to pay royalties on the fuel used to run that compressor as
they do now. The BLM did not make any changes to the rule based on this
comment.
Another commenter stated that other royalty owners will be burdened
by all the downstream losses (fuel, etc.) if the operator must install
an on-lease FMP rather than rely on measurements taken at a downstream
commingled measurement point.
According to the commenter this raises legal concerns with respect
to other agency regulations and contractual agreements between
operators. The BLM disagrees with this comment and did not make any
changes as a result. The requirement to install an FMP on the lease,
unit PA, or communitized area, and pay royalty based on that FMP only
applies to Federal and Indian leases. It would not preclude other
royalty owners to base their royalty distribution on a down-stream
commingled measurement point that is different from the FMP on which
the Federal or Indian royalties are based.
Section 3173.18 Modification of a Commingling and Allocation Approval
Section 3173.18(a) of the final rule identifies the circumstances
under which all operators who are parties to a CAA must request a
modification, including: Modifications to the allocation agreement;
inclusion of additional leases, unit PAs, or CAs into a CAA; or
termination of a lease, unit PA, or CA within a CAA. Paragraph (b)
identifies the information that must be submitted in connection with a
modification request. Paragraph (c) was added to the final rule to
clarify that a CAA does not need to be modified when there is a change
in operator.
One commenter suggested that the BLM change proposed Sec.
3173.18(a)(1), which allowed operators who are a party to a CAA to
modify the CAA when there is a change in the allocation schedule. The
commenter said it was not practical or beneficial to update the CAA
each time the allocation schedule changes. The BLM agrees that
requiring an update to the CAA when the allocation schedule changes is
not necessary. The intent of requiring information on the allocation
was to ensure that the BLM can verify and re-calculate the volumes
reported on the OGORs. Allocation schedules are often based on periodic
well testing and can change each time a well test is conducted. As long
as the BLM thoroughly understands the allocation methodology, we can
request the well testing or other data from which the operator
determines the allocation schedule and verify that the allocation was
done in accordance with the allocation methodology and was properly
reported on the OGOR. Paragraph (a)(1) has been modified to require a
CAA modification only when there is a modification to an allocation
[[Page 81399]]
agreement, which in the final rule must include an allocation
methodology rather than an allocation schedule. Thus, only if there is
a change in the methodology used to determine allocation percentages
would an operator have to make changes to their existing CAA. A change
to the allocation schedule itself would not require such a
modification.
One commenter did not like the idea of having a CAA re-evaluated
when new leases are proposed to be added to the CAA, as required under
Sec. 3173.18(a)(2). The BLM disagrees with this comment and did not
make any changes to the rule as a result. The addition of a lease, unit
PA, or CA to an existing CAA will affect the allocation of production
in a CAA, and therefore the BLM will need to review the addition to
ensure that the allocation method is verifiable and provides a fair
return to the Federal Government or Indian tribes or allottees.
Finally, several commenters asked whether submission of a
``Successor of Operator Sundry Notice'' would automatically change the
operator of the FMP and the CAA. A Sundry Notice for a change in
operator of a well(s) and a facility on a lease, unit PA, or CA will
designate that new operator as being responsible for reporting
production from the property, and therefore will include the CAA
agreement. In response to this comment, the BLM has removed one of the
conditions under which a CAA may be modified--when there is a change in
operator. Furthermore, a new paragraph (c) has been added to the final
rule stating that a change in operator will not trigger the need to
modify the CAA. The FMP will automatically transfer since it is part of
the facility.
Section 3173.19 Effective Date of a Commingling and Allocation Approval
Section 3173.19 (a) and (b) of the final rule identifies the
effective date of a CAA after the approval of an application or
modification, respectively. Paragraph (c) of this section clarifies
that a CAA does not modify any of the terms of any leases, unit PAs, or
CAs. The BLM did not receive any public comments on this section and
did not change it in the final rule, except to make minor modifications
for clarity.
Section 3173.20 Terminating a Commingling and Allocation Approval
Paragraph (a) of Sec. 3173.20 of this final rule (paragraph (b) of
the proposed rule) authorizes the BLM to terminate an approved CAA for
any reason, including changes in technology, regulation, or policy, or
where the operator has not complied with the terms of the CAA.
Paragraph (b) (paragraph (c) of the proposed rule) provides for
automatic termination of a CAA if only one lease, unit PA, or CA
remains in the CAA. Paragraph (c) (paragraph (a) of the proposed rule)
states that an operator may terminate its participation in a CAA by
submitting a Sundry Notice to the BLM. Unlike the provision in the
proposed rule, paragraph (c) of the final rule clarifies that the
termination by one operator does not automatically terminate the CAA as
to all other operators, so long as the requirements of this part are
met with respect to the remaining participants in the CAA.
After termination of a CAA, paragraph (d) requires the BLM to
notify in writing all operators who are a party to the CAA of the
effective date of the termination and any inconsistencies or
deficiencies with their CAA approval that caused the termination. The
BLM modified this provision from the proposed rule to provide that upon
receipt of the BLM's notice of termination, the operator has 20
business days to correct any inconsistencies or deficiencies, or
provide additional information that the AO has requested or that
explains or justifies the inconsistency or deficiency. If the operator
does not correct the inconsistency or deficiency within 20 business
days after receipt of the BLM's notice, the CAA is terminated as of the
effective date in the BLM's notice. The effective date of the
termination will not be earlier than the 20 business days outlined in
paragraph (d). Paragraph (e) provides that upon termination, each
lease, unit PA, or CA may require a new FMP number or a new CAA. Under
the final rule, operators will have up to 30 days to apply for a new
FMP number or CAA, whichever is applicable. Following termination,
while the BLM is processing the application for a new FMP number or
CAA, the operator may use the existing FMP number for recordkeeping and
production reporting.
Several commenters were concerned that paragraph (a) in the
proposed rule would have allowed a party to a CAA to unilaterally
terminate the CAA by submitting a Sundry Notice to the BLM, and that
paragraph (b) in the proposed rule, or paragraph (a) in the final rule,
allows the BLM to terminate a CAA for any reason. One commenter said it
would be fine to allow a party to terminate their participation in the
CAA, but the remaining operators should have the opportunity to
continue with the CAA. One commenter asked that the final rule be
changed to allow an existing CAA to continue after one of the parties
pulls out, as long as the remaining operator(s) follow the COAs for the
CAA.
The BLM agrees with the commenters and believes that the continued
operation of a CAA when one operator decides to pull out is in the
public interest. All the CAA requirements of this rule are designed to
ensure that the CAA is in the public interest by, for example, allowing
continued production of low volume properties, addressing other
overriding considerations, or allowing the maximum ultimate recovery of
oil and gas resources. The BLM does not believe that the decision of
one operator to pull out of the CAA would change the BLM's public
interest determination and terminating the CAA as a result would only
result in additional paperwork for both the BLM and industry. Instead,
the operator who wants to terminate its own, individual participation
in the CAA should be able to do so. In response to this comment, the
BLM removed proposed paragraph (a) in the final rule and re-designated
it with modifications as paragraph (c). While paragraph (c) still
allows an operator to terminate a CAA through submission of a Sundry
Notice, the BLM clarified that paragraph in response to comments to
make clear that termination of participation in a CAA by one operator
does not necessarily impact all operators, so long as the other
requirements of this part are met with respect to that CAA and the
other operators submit a Sundry Notice for a new CAA as required by
paragraph (e).
An operator who wishes to terminate its participation will need to
submit the appropriate paperwork to the BLM as outlined in 3173.20(c).
Additionally, if a CAA is terminated, paragraph (e) of the final rule
no longer requires separate measurement. Rather, it gives operators 30
days to apply for a new FMP number and/or CAA, if applicable. The old
FMP number may be used for recordkeeping and production reporting until
a new FMP number is assigned or a new CAA is approved. If more than one
lease, unit PA, or CA remains in a CAA, the operator(s) of those
leases, unit PAs, or CAs will need to submit a Sundry Notice for a new
CAA under Sec. 3173.18.
Another commenter stated that they have established gathering
systems that are subject to the existence of CAAs. If the CAA is
terminated by the BLM, the commenter states that operators could no
longer sell gas into the gathering system, which could result in the
shut in of wells, lost production and lost revenues. Instead, the
operator suggests that if an operator no longer wants their lease to be
part of a CAA, the CAA could be easily modified to include only
[[Page 81400]]
the remaining leases. The BLM agrees with this comment and removed
paragraph (a) as discussed above.
Regarding comments that the BLM should not have the authority to
terminate existing CAA approvals for any reason, commenters already
should be aware that under the terms of all existing CAAs, the BLM
retains the right to terminate a CAA for any reason. Thus, the
requirements found in paragraph (a) are a codification of existing
practices. However, the reasons listed under paragraphs (a)(1) through
(a)(3) of this final rule should cover the majority of the situations
that could lead to termination of a CAA. If a CAA is not in compliance
with this rule's commingling requirements, the BLM will work with the
operators on a case-by-case basis to bring the CAA back into compliance
to avoid a termination. If a CAA is terminated because of changes in
technology, regulation, or BLM policy, operators will be given
sufficient time to make any necessary changes. In the event that the
BLM does take steps to terminate a CAA, paragraph (c) of this final
section provides that the BLM's notice-of-termination letter will
describe the inconsistencies or deficiencies that will lead to the CAA
termination, along with the effective date of the termination. The
parties to a CAA will then have an opportunity to avoid termination of
the CAA by correcting those inconsistencies or deficiencies within 20
business days of their receipt of notification.
Section 3173.21 Combining Production Downhole in Certain Circumstances
Section 3173.21 of this final rule identifies certain circumstances
in which downhole combining of production is subject to the commingling
requirements contained in Sec. Sec. 3173.14 through 3173.20. Under
paragraph (a)(1), the combination of production from a single
directional well drilled into different hydrocarbon pools or geologic
formations under separate adjacent properties, regardless of ownership,
where none of the pools or formations are common to more than one of
the properties, constitutes commingling under the final rule, and is
therefore subject to the requirements in Sec. Sec. 3173.14 through
3173.21 of this subpart. If, on the other hand, the pools or geologic
formations are common to more than one property, then under paragraph
(a)(2), the operator is required to establish a unit PA or CA as
opposed to obtaining a CAA. Paragraph (b) clarifies that combining
production downhole from different geologic formations on the same
lease from a single well, while requiring AO approval, is not
considered commingling for purposes of this final rule, unless those
formations have different ownership.
The BLM did not receive any public comments on this section, but
did make one small change. In paragraph (b), the final rule clarifies
that the requirements of Sec. Sec. 3173.14 through 3173.20 do not
apply when operators combine production downhole from different
geologic formations on the same lease in a single well.
Sections 3173.22 through 3173.28 Off-Lease Measurement Approvals
Sections 3173.22 through 3173.28 of this final rule establish the
circumstances in which the BLM will approve measurement of production
off of the lease, unit, or CA (referred to as ``off-lease
measurement''). Prior to this rule, there were no national standards
that operators had to meet when applying for off-lease measurement.
Neither Order 3 nor other regulations addressed how or under what
circumstances the BLM would approve off-lease measurement. This lack of
guidance led to much confusion over the location of off-lease
measurement points. Off-lease measurement is also often associated with
commingling. Meters that measure commingled production are often
referred to as central delivery points. In most situations, the meter
at the central delivery point is located off of at least one of the
Federal or Indian leases, units, or CAs from which the production
originates. This configuration requires the BLM to approve both the
commingling and the off-lease location of the measurement point.
In the absence of uniform national standards governing off-lease
measurement, BLM State Offices created their own policies for approving
off-lease measurement applications, which were not necessarily
consistent. Sections 3173.22 through 3173.28 of this final rule,
discussed below, provide such uniform national standards, addressing
the concerns identified by the GAO, the OIG, and the Subcommittee.
Some commenters said that this section contains new record-keeping
requirements that are vague and that could cause operators to submit
incorrect applications for off-lease measurement. The commenters did
not specify the sections that they believe are vague, nor did they
provide any explanation as to why they are vague. The BLM did not make
any changes to the rule based on these comments. The BLM notes,
however, that Sec. 3173.23 contains a complete list all of the
information and documentation that operators need to provide to the BLM
when applying for off-lease measurement approvals.
Section 3173.22 Requirements for Off-Lease Measurement
Section 3173.22 of the final rule establishes the conditions under
which the BLM will consider granting a request for off-lease
measurement. It requires such requests to satisfy the requirements of
paragraphs (a) through (d). Under paragraph (a), the BLM will consider
off-lease measurement of production only from a single CAA or a single
Federal or Indian lease, unit PA, or CA. Paragraph (b) requires that
the off-lease measurement provide for accurate production
accountability and paragraph (c) requires that off-lease measurement be
in the public interest. Paragraph (d) requires off-lease measurement to
occur at an approved FMP.
Commenters asked that the BLM list the conditions under which off-
lease measurement will be approved. The BLM did not make any changes to
the rule based on this comment because this section clearly lists the
conditions under which off-lease measurement will be considered for
approval. Requests that meet the requirements of this section will be
approved, while requests that do not will not be approved.
Another commenter requested that the BLM provide exemptions from
the off-lease measurement requirements in situations where topography
or other environmental issues prevent operators from measuring on-
lease. The BLM agrees that there are circumstances when it is
physically impractical to measure on-lease or where measuring on-lease
could cause additional environmental impacts. Examples include
situations where well pads are located at high altitudes that could be
inaccessible in the winter or when the BLM has imposed seasonal access
restrictions due to environmental concerns. In response to this
comment, final paragraph (c) has been changed to allow off-lease
measurement when on-lease measurement is not practical due to
topographic or environmental concerns. As with any of the requirements
in this subpart, an operator may also request a variance to the off-
lease measurement requirements on a case-by-case basis.
One commenter said its liquids-gathering system, which is within
the boundary of a CAA, should be exempt from the off-lease measurement
requirements of Sec. 3173.22 because this
[[Page 81401]]
system has been in place for over 10 years, was approved by the BLM,
and works well. The BLM did not change the final rule in response to
this comment. Instead, the BLM will review existing off-lease
measurement approvals associated with CAAs, along with the CAAs
themselves, on a case-by-case basis as part of the FMP approval process
to ensure consistency with the minimum standards and requirements under
Sec. 3173.22 of the final rule.
Several commenters said that the new off-lease measurement
requirements will result in more FMPs and that off-lease measurement--
because it requires fewer FMPs--provides better accuracy and reduces
recordkeeping, allowing multiple wells or pads (in a unit operation) to
commingle production at a central tank battery. These commenters
asserted that this made it easier for the BLM to track production and
audit facilities.
The BLM believes the commenters are confused about the definition
of off-lease measurement. The operator can locate an FMP, including a
central tank battery as mentioned by the commenters, anywhere within
the boundary of a lease, a unit, or a CA from which the production
originates without meeting the definition of off-lease measurement and
without needing approval from the BLM. Although the requirements for
approving a CAA in this rule may increase the number of FMPs required,
the BLM does not agree that the off-lease measurement requirements of
this rule would have any effect on the number of FMPs required. As
noted earlier in discussion of Sec. 3173.15(a) of the final rule, if
off-lease measurement is a feature of a commingling and allocation
proposal, then a separate Sundry Notice application for off-lease
measurement is not necessary and the off-lease measurement proposal
will be considered as part of the CAA request. The BLM expects that
this final rule will have a smaller impact than the proposed rule would
have had on existing off-lease measurement approvals tied to CAAs
because Sec. Sec. 3173.14(b) and 3173.16(a) of the final rule includes
an expanded list of exemptions that allow commingling as well as
grandfathering provisions for some existing CAAs.
Finally, a few commenters said that some existing off-lease
measurement approvals could be at risk if they do not meet the BLM's
conditions for being ``in the public interest,'' as outlined in
paragraph (c) of this section. We agree that some existing off-lease
measurement approvals may not be in the public interest, and they will
therefore be terminated. The public interest generally includes
minimizing environmental impacts, achieving maximum ultimate economic
recovery, and allowing the BLM to verify volumes and qualities of oil
and gas reported on the OGORs. Existing approvals that are merely for
the convenience of the operator may not be in the public interest. If,
for example, an existing off-lease measurement approval allows the FMP
to be located on private land that makes BLM access difficult or
impossible, and the approval cannot be justified based on environmental
circumstances or achieving maximum ultimate economic recovery, it is
likely that the BLM will terminate the approval. The BLM estimates that
best management practices and environmental and topographic
considerations will outweigh the need to terminate many existing off-
lease measurement approvals or to deny new ones. The final rule was not
changed in response to these comments.
Section 3173.23 Applying for Off-Lease Measurement
Section 3173.23 of this final rule establishes the requirements
operators must follow when applying for an off-lease measurement
approval or amending an existing approval, including required
supporting information and related documentation.
One commenter said that this section of the rule is unnecessary and
redundant and that the off-lease measurement application and approval
process should be part of the APD process. The BLM does not agree that
this section is unnecessary and redundant because it establishes the
process that operators will use to apply for an off-lease measurement
approval, which is entirely separate from and independent of the
process the BLM uses to process an APD. However, Sec. 3173.23 does not
prohibit operators from submitting new off-lease measurement
applications with their APDs. The BLM, in fact, would prefer to receive
comprehensive proposals upfront from operators when they submit their
APDs because it streamlines the BLM's review process by allowing BLM
staff to look at a project in its entirety early in the permitting
process.
Section 3173.23(a) requires operators to submit their off-lease
measurement application via a Sundry Notice. That Sundry Notice package
may be submitted at the same time as, but separately from, an
operator's APD package(s) and the BLM will process both applications at
the same time. The final rule did not change as a result of this
comment.
Several commenters said it would be too burdensome to require
operators, whose off-lease measurement facilities are located on non-
federally owned surface, to include in their off-lease measurement
applications written concurrence from the surface owners, including
from future owners if the ownership changes, as called for in paragraph
(e) of the final rule. The BLM does not agree with these commenters.
Operators should already be obtaining concurrences from surface owners
as part of the APD process as Onshore Order 1 (Approval of Operations)
specifically requires operators to make a good faith effort to obtain a
Surface Access Agreement from the surface owner. Therefore, this
requirement does not place any additional burden on the operator.
In addition, the BLM must have guaranteed access to the off-lease
measurement location. Without this guaranteed access, the BLM may not
be able to verify or account for the volumes and qualities of oil and
gas on which royalty is due and would therefore deny the off-lease
measurement request or terminate the existing off-lease measurement
approval. No change to the rule was made in response to this comment.
Finally, one commenter said that the proposed rule did not
specifically require operators to obtain the written consent of the
owner and operator of measurement facilities. As a result, the
commenter said, this rule would subject owners and operators of the
measurement facility to the jurisdiction of the BLM without its consent
or knowledge. The BLM believes that this is a valid concern. However,
the BLM did not make a change to the rule in response to this comment
because paragraph (e) (paragraph (f) in the proposed rule) already
requires operators to obtain written concurrence signed not only by the
surface owner(s), but also by the owner(s) of the measurement
facilities.
In addition to these changes, the BLM made a few minor
administrative changes to final Sec. 3173.23. These clarifications
were consistent with the overall changes made to the final rule and
were not made in response to any particular comments. The BLM added a
new paragraph (h) to the final rule to clarify that operators, under
existing BLM regulations, must obtain approval from the appropriate
surface-management agency, if new surface disturbance is proposed for
the FMP, and its associated facilities are located on Federal land
managed by an agency other than the BLM. The BLM also clarified
paragraph (f) to state that an
[[Page 81402]]
operator needs to submit a right-of-way grant application to the BLM
along with the off-lease measurement request only when new surface
disturbance is proposed for the FMP and its associated facilities are
located on BLM-managed land. If the proposed surface facilities are on
Indian land, then paragraph (g) of the final rule requires that a
right-of-way grant application must be filed with the appropriate BIA
office.
Other changes we made that were unrelated to public comments
include modifications to the type of information operators must submit
as part of their off-lease measurement application. In paragraph (c)(2)
of the final rule, the BLM no longer requires the operator to identify
the land description of all wells, pipelines, and other facilities
expected to be installed as part of their proposal. Operators need only
identify the relative location of such facilities. Paragraph (e) in the
proposed rule required submission of a schematic or engineered drawing
showing all new facilities that are part of the off-lease measurement
proposal. This requirement is no longer in the final rule. Finally, the
requirement in paragraph (e) of the proposed rule that called for the
submission of a site facility diagram for existing facilities if
changes are being proposed to the facility is removed as unnecessary
because the requirements related to site facility diagrams for existing
facilities are already addressed by Sec. 3173.11. The BLM elected to
make these changes consistent with the changes made to the information-
submission requirements for commingling applications under Sec.
3173.15 of the final rule. It is not necessary for the information-
collection requirements for commingling applications to be different
than the information-collection requirements for off-lease measurement
applications.
Section 3173.24 Effective Date of an Off-Lease Measurement Approval
Section 3173.24 provides that off-lease measurement approvals are
effective on the date the BLM issues the approval, unless the BLM
specifies a different effective date in the approval. The BLM did not
receive any public comments on this provision and did not make any
changes to the final rule.
Section 3173.25 Existing Approved Off-Lease Measurement
Under this section of the final rule, an existing off-lease
measurement approval will be reviewed upon receipt of an operator's
request for the assignment of an FMP number to a facility associated
with the off-lease measurement approval. Section 3173.25(a) states that
the AO reviews the existing off-lease measurement approval for
consistency with the minimum standards and requirements in Sec.
3173.22. The AO will notify the operator in writing of any
inconsistencies or deficiencies. Under paragraph (b), the operator will
have to correct the inconsistencies or deficiencies, provide the
additional information that the AO has requested, or request an
extension from the AO within 20 business days. If an operator is
requesting an extension, they must justify the request by explaining
the factors that will not allow the operator to comply within 20 days
and provide a timeframe under which the operator can comply.
Under paragraph (c), in connection with approving the requested
FMP, the AO may terminate an existing off-lease measurement approval
and grant a new off-lease measurement approval with new or amended COAs
to make the approval consistent with the requirements of this rule. In
addition, paragraph (c) provides that the existing off-lease
measurement approval will continue in effect during any pendency of an
appeal of the new off-lease measurement approval. If the operator fails
to correct the deficiencies, paragraph (d) provides that the AO may
terminate the off-lease measurement approval. If the existing off-lease
measurement approval under this section is consistent with the
requirements under Sec. 3173.22(e) of the final rule allows that
existing off-lease measurement be grandfathered and be part of the
operator's FMP approval. Under paragraph (f), if the BLM grants a new
off-lease measurement approval, that new approval is effective on the
first day of the month following its approval.
Several commenters had concerns with the paragraph (a) requirement
that the AO review existing off-lease measurement approvals to
determine if they comply with the new off-lease measurement
requirements in Sec. 3173.22. These commenters requested that the BLM
``grandfather in'' existing off-lease measurement approvals. Another
commenter said that operators spent countless hours negotiating their
existing CAAs, along with their off-lease measurement approvals, with
BLM field staff, which resulted in protections for environmentally
sensitive areas and accurate measurement of production.
The BLM agrees with the comments as they relate to grandfathered
CAAs and included language under Sec. 3173.16(a) that also
grandfathers existing off-lease measurement approvals that are included
as part of those grandfathered CAAs under Sec. 3173.16(a)(1) or (2).
The BLM does not, however, agree that existing off-lease
measurement approvals that are not included in Sec. 3173.16(a) should
be grandfathered. As we stated earlier in this preamble, a major goal
of this final rule is to ensure that new and existing approvals--be
they for CAAs or off-lease measurement--allow BLM staff to verify that
oil and gas are being measured and reported accurately under these
approvals. Without the ability to consistently track where and how oil
and gas are measured, the BLM cannot be assured that production
reporting is accurate. Section 3173.25 sets up a process for the BLM to
review existing non-grandfathered off-lease measurement approvals that
were granted before the BLM established guidance and standards that
ensure such approvals were structured so that BLM staff can verify
production reporting.
For existing off-lease measurement approvals that are associated
with a non-grandfathered CAA, the CAA would provide the public interest
justification for the off-lease measurement approval, whether that is
due to economics, protection of the environment, or to achieve maximum
ultimate economic recovery. The BLM estimates that more than 95 percent
of existing CAAs will be either grandfathered or approved under the
provisions of the final rule. Therefore, the only aspect of non-
grandfathered off-lease measurement approval that the BLM will be
concerned with is the BLM's access to the proposed off-lease
measurement location.
Another commenter said that the proposed rule would have required
operators to submit all existing off-lease measurement approvals to the
BLM for re-approval. The BLM disagrees. This rule does not require
operators to submit all existing authorizations to the BLM for re-
approval. It does provide that the AO, when an operator submits an
application for an FMP number associated with an existing off-lease
measurement approval, the AO will review that existing approval for
consistency with the minimum standards and requirements for off-lease
measurement under Sec. 3173.22 and notify the operator in writing of
any inconsistency or deficiency, or request additional information. No
changes to the final rule were made as a result of this comment.
Several commenters were concerned that paragraph (b) gives
operators only 20 business days to correct any inconsistencies or
deficiencies that the
[[Page 81403]]
AO identifies with existing off-lease measurement approvals or to
provide any additional information the AO requests. The commenters said
20 business days is not enough time to make such corrections and
recommended that operators be given 60 to 90 days to fix any problems.
One commenter said some operators could be required to reconfigure
their pipes in order to maintain their off-lease measurement approvals,
which would likely take longer than 20 days to accomplish. Several
others said that since this is the first time that the BLM will be
reviewing existing CAAs and off-lease measurement approvals for
compliance with the new requirements, every commingling facility with
off-lease measurement will need some corrective work and operators must
be given more than 20 days to bring their operations into compliance if
they receive multiple notices.
The BLM believes that some of the commenters have confused the
requirements relating to the review of existing off-lease measurement
approvals with those relating to the review of existing CAAs under
Sec. 3173.16(b). The review of existing off-lease measurement
approvals will have nothing to do with allocation methods and will
rarely involve any on-the-ground work. The BLM will be concerned with
only four issues when reviewing existing off-lease measurement
approvals:
1. Does the existing off-lease measurement point only measure
production from one lease, unit PA, CA, or CAA?
2. Is the off-lease measurement point reasonably accessible to the
BLM for the purpose of production accountability?
3. Is the off-lease measurement approval in the public interest?
4. Does the off-lease measurement occur at an approved FMP?
For the majority of existing off-lease measurement approvals that
are associated with a CAA, items 1, 3, and 4 will already be addressed
by the CAA. Therefore, the only review the BLM will do is to ensure the
off-lease measurement point is reasonably accessible to the BLM. In the
rare case where it is not, the BLM may require that the operator either
modify the location to make it more accessible to the BLM or, in the
most extreme cases, move the measurement facility to a location where
it is accessible to the BLM.
Second, in response to these comments, the BLM added language to
the final rule that allows an operator to request an extension of the
20-day timeframe. The operator should justify the extension request by
explaining the factors that will not allow them to comply within the
20-day timeframe and provide a timeframe under which they can comply.
One commenter objected to a provision in paragraph (c) that allows
the AO to impose new or amended COAs on an existing off-lease
measurement approval to make the approval consistent with the off-lease
measurement requirements in Sec. 3173.22. The commenter was referring
to an off-lease measurement approval that is part of an existing CAA.
The commenter stated that numerous sales contracts are based on
existing approvals and that by changing the approval, gas sales
contracts may be at risk of termination. Other commenters expressed
concern that new COAs could result in economic burdens that would
result in the shut-in of production and loss of Federal or Indian
royalty. Other commenters said the new off-lease measurement
requirements would force them to reconfigure gathering lines at sites
where existing off-lease measurement agreements were not approved,
which would be costly and cause additional environmental impacts that
may not be necessary.
The BLM did not make any changes to the rule based on this comment
because this has little do with the off-lease measurement approval and
much more to do with the CAA approvals, discussed previously in the
preamble. As discussed in the portion of this preamble dealing with
commingling, the primary concern of the BLM when reviewing existing
off-lease measurement approvals that are associated with a CAA is to
ensure that the BLM has reasonable access to inspect the off-lease
measurement facility. Generally, the only COAs that the BLM would
impose on an existing off-lease measurement approval that is associated
with a CAA would relate to ensuring BLM access to the FMP. These COAs
could include remedies such as obtaining express authorization for the
BLM to access the facility in situations where the facility is not
located on land managed by the BLM, or in rare cases, moving the
measurement facility to a location that does provide the BLM reasonable
access. This paragraph further provides that if the operator appeals
one or more of the new COAs, the existing off-lease measurement
approval will continue during the pendency of the appeal.
The BLM would like to reiterate that most of the existing wells in
the San Juan Basin, where surface and downhole commingling are
occurring together with off-lease measurement, may be exempt from
having to meet the new commingling and related off-lease measurement
requirements because they qualify for grandfathering under Sec.
3173.16(a). Section 3173.16(a) grandfathers all existing downhole
commingling CAAs and any existing surface CAAs if the average
production over the past 12 months is less than 1,000 Mcf of gas per
month, or 100 bbl of oil per month for each lease, unit PA, or CA
included in the CAA. In such cases, the associated off-lease
measurement approval would also be grandfathered under Sec.
3173.16(a).
Section 3173.26 Relationship of Off-Lease Measurement Approval to
Royalty-Free Use of Production
Section 3173.26 of the final rule clarifies that approval of off-
lease measurement does not constitute approval of off-lease royalty-
free use of production as fuel in facilities located at an approved
off-lease FMP. Under NTL-4A, the lessee or operator may claim royalty-
free use only for gas or oil used on the same lease, on the unit for
the same unit PA, or on the same CA from which the gas or oil was
produced. Thus, the lessee or operator may not claim royalty-free use
for any of the production used as fuel at an off-lease FMP, absent BLM
approval.
One commenter asked that the BLM define the term ``royalty-free
use'' in this rule. As explained in this preamble with respect to Sec.
3173.1, the BLM does not believe such a change is necessary. The
definition of royalty-free use in NTL-4A will control unless and until
it is replaced.
Section 3173.27 Termination of Off-Lease Measurement Approval
Section 3173.27(a) of the final rule provides that the BLM may
terminate an off-lease measurement approval for any reason. By way of
illustration, this paragraph identifies certain circumstances under
which the BLM might exercise that authority--such as changes in
technology, regulation, or BLM policy; operator non-compliance with the
terms or conditions of the off-lease measurement approval; or operator
non-compliance with Sec. Sec. 3173.22 through 3173.26. Under paragraph
(b), the BLM will notify the operator in writing of the effective date
of the termination and any inconsistencies or deficiencies with the
operator's approval that serve as the reason(s) for the termination.
Upon receipt of the BLM's notice, the operator will have 20 business
days to correct any inconsistencies or deficiencies, or provide any
additional information the AO requests. Paragraph (b) also provides
[[Page 81404]]
an opportunity for an operator to request an extension of time from the
AO within 20 business days after receipt of the BLM's notice, or the
off lease measurement approval terminates.
Paragraph (c) provides that an operator may terminate an off-lease
measurement approval by submitting to the BLM a Sundry Notice, which
must identify the new FMPs for the lease(s), unit PA(s), or CA(s)
previously subject to the off-lease measurement approval. Under
paragraph (d), each lease, unit PA, or CA that was subject to the off-
lease measurement approval may require a new FMP number(s) or a new
off-lease measurement approval. Operators will have up to 30 days to
apply for a new FMP number or off-lease measurement approval, whichever
is applicable. While the BLM processes the application for a new FMP
number or off-lease measurement approval, the operator may continue to
use the existing FMP number.
The BLM received several comments on this section of the proposed
rule, one of which expressed concern that proposed Sec. 3173.27 did
not provide an explicit timeframe or process for the BLM to terminate
off-lease measurement approvals or for operators to correct the
inconsistencies or deficiencies that led to the termination. This
commenter recommended that the BLM give operators 9 months to correct
their inconsistencies or deficiencies before terminating their
approvals. Several other commenters objected to paragraph (a) of the
final rule (paragraph (b) of the proposed rule), which authorizes the
BLM to terminate an off-lease measurement approval for any reason. One
commenter stated that some gas sales contracts involving gathering
systems are based on having off-lease measurement approvals and CAAs
and that if the BLM terminates the off-lease measurement approval, the
operator will no longer be able to sell gas into the gathering system.
The commenter stated that operators need to have some confidence that
the existing off-lease measurement approval will allow continued
operations as long as the operator follows the COA for the off-lease
measurement approval. If there are issues to be resolved, the operator
should be given a reasonable time to resolve the issues.
The BLM agrees in part with these comments and made several changes
to the final rule in response. Under revisions to final paragraph (b),
the BLM's notification letter will describe the inconsistencies or
deficiencies in the operator's existing off-lease measurement approval
that will result in the termination, and state the effective date of
the termination. The revisions also give the operator 20 business days
from receipt of the letter to correct the inconsistencies or
deficiencies identified by the BLM, provide more information, or
request an extension of time from the AO in order to avoid termination.
The BLM does not agree with a 9-month timeframe as recommended by one
commenter because unique circumstances may warrant different
timeframes. If an operator believes that correcting the inconsistencies
or deficiencies will take longer than 20 days, it may request a
reasonable extension of time from the AO in order to make any necessary
corrections.
The BLM received several comments on paragraph (d) of the proposed
rule. Proposed paragraph (d) said that if an off-lease measurement
approval is terminated, each lease, unit PA, or CA subject to the
approval reverts to measurement on the respective lease, unit, or
communitized area. Commenters said that this requirement should not
apply to gathering systems that were installed with BLM approval for
the purpose of off-lease measurement. If such an approval were
terminated, commenters said, the gathering system could no longer
transport gas to the sales meter that is off-lease and wells connected
to the gathering system would likely be shut in or plugged as they
could no longer sell their gas. The new on-lease measurement system
would not be connected to a gas sales line as well, the commenter said.
The commenter recommended that the BLM delete the whole section from
the final rule.
The BLM disagrees with this comment and did not make any changes to
the final rule as a result. The commenter's concern principally relates
to the underlying CAA approval, not to the off-lease measurement
approval itself. The BLM's primary concern with off-lease measurement
approvals that are tied to a CAA is the BLM's access to the off-lease
FMP for the purpose of inspection and production accounting. For off-
lease measurement approvals that are not tied to a CAA, Sec.
3173.22(c) allows the BLM to consider an operator's ability to achieve
maximum ultimate economic recovery from a lease, unit PA, or CA in
determining whether it is in the public interest to approve off-lease
measurement. This provision gives the BLM the leeway it needs to exempt
leases, unit PAs, or CAs from the off-lease measurement requirements in
situations where denial of off-lease measurement might result in shut-
ins.
Section 3173.28 Instances Not Constituting Off-Lease Measurement, for
Which No Approval Is Required
Section 3173.28 of the final rule identifies two circumstances that
will not be considered off-lease measurement for purposes of the rule.
The first is where an FMP is located on a well pad of a directionally
drilled well that produces oil or gas from a lease, unit, or CA on
which the well pad is not located. The second is where a lease, unit,
or CA is made up of separate non-contiguous tracts. If production is
moved from one tract to another tract within the same lease, unit, or
CA, and the production is not diverted during movement between the
tracts before the FMP (except for production used royalty-free),
measurement would not be considered to be off-lease.
Several commenters were under the impression that they would need
off-lease measurement approval for horizontal and directionally drilled
wells where the well pad itself is located off the lease, CA or unit.
Under paragraph (a), off-lease measurement approval for such wells is
not needed, unless the FMP is also located off of the well pad,
regardless of distance. If any of the facilities are located on non-
federally owned surface, the operator will still need to obtain written
concurrence signed by the surface owner(s), and the operator(s) of the
measurement facilities that grants the BLM unrestricted access to the
off-lease measurement facility and the surface on which it is located,
in order to conduct production verification inspections. The BLM did
not make any changes to the rule based on this comment.
One commenter said that, in some cases, there may by reasons to
locate the FMP near, but not actually on, the well pad, triggering the
need for the operator to obtain off-lease measurement approval. The
commenter stated that if the FMP is located a small distance off the
well pad, but clearly serves the wells on the pad this should not
require an off-lease measurement approval. The BLM disagrees with this
comment and did not make any changes to the rule as a result. Paragraph
(a) of this section clearly states that the FMP must be located on the
well pad to avoid the need for an off-lease measurement approval.
Normally, well pads are clearly delineated in the field by a berm,
fence, or other easily-identifiable feature. This makes the requirement
clear, objective, and enforceable. Adding a provision that would, as
suggested by the commenter, include FMPs that are only a short distance
off the well pad would render the provision
[[Page 81405]]
subjective and unenforceable. If the operator can demonstrate that
locating the FMP a small distance off the well pad is in the public
interest and that the BLM has guaranteed access to inspect the FMP,
then the BLM would approve off-lease measurement.
Another commenter suggested that the BLM add a paragraph to this
section that states gas used for fuel at locations that are not
considered to be ``off lease'' under paragraphs (a) and (b) of this
section qualifies as royalty-free usage. The BLM did not make any
changes to the rule based on these comments because what qualifies as
royalty-free use is outside the scope of this rulemaking.
Section 3173.29 Immediate Assessments for Certain Violations
Section 3173.29 expands the number and types of violations that
would be subject to immediate assessments. Immediate assessments are
not civil penalties and are separate from the civil penalties
authorized under Section 109 of FOGRMA, 30 U.S.C. 1719. Unlike the
proposed rule, the final rule does not subject purchasers and
transporters to immediate assessments--only operators. For violation 7,
non-retention of records necessary to determine quantity and quality of
production, the final rule clarifies that the applicable regulation is
Sec. 3170.7, not Sec. 3173.9(a)(1) and (2). Also, the final rule
clarifies that violation 8 could result in an immediate assessment if
operators fail to ``apply for,'' rather than ``obtain,'' the required
FMP approval.
With respect to violations 9, 10, and 11, which pertain to
approvals for off-lease measurement and surface or downhole
commingling, respectively, the final rule clarifies that removing
production from a facility that begins operation after the effective
date of the final rule, prior to receiving BLM approval for off-lease
measurement or commingling, could result in an immediate assessment. If
the facility will be servicing new wells not yet drilled, as well as
existing wells already in production, then the existing wells must use
their respective existing FMP numbers when reporting production to
ONRR's OGOR until the BLM assigns the new FMP number associated with
its off-lease measurement or commingling approval.
An existing facility (i.e., one in service on or before the
effective date of the final rule) would be subject to an immediate
assessment if it engaged in off-lease measurement or commingling
without an existing BLM approval. Under such circumstances, the BLM
could issue an immediate assessment for each applicable lease, unit PA,
or CA, since off-lease measurement or commingling without approval is a
violation of this final rule and existing BLM requirements under 43 CFR
3162.7-2 and 3162.7-3, both of which require BLM approval before
operators store or measure production from a Federal or Indian lease
off-lease.
Some commenters argued that these immediate assessments are
inconsistent with due process because there is no opportunity for an
operator to correct its violations before an assessment is imposed. To
the contrary, the use of immediate assessments for breaches of the oil
and gas operating regulations is well established and is consistent
with the notice requirements of due process. Operators obligate
themselves to fulfill the terms and conditions of the Federal or Indian
oil and gas leases under which they operate. These leases incorporate
the BLM's regulations by reference. Thus, the immediate assessments
contained in the regulations act as ``liquidated damages'' owed by
operators who have breached their leases by breaching the regulations.
See, e.g., M. John Kennedy, 102 IBLA 396, 400 (1988). Operators are
expected to know the obligations and requirements of the Federal or
Indian oil and gas lease under which they operate; additional notice is
not required.
Several commenters said there could be instances when an operator
is not aware that a violation exists. One commenter said the assessment
should be imposed only if the violation was a willful or knowing act of
noncompliance. Another commenter suggested the BLM place a Federal seal
and notify the operator of the violation instead of issuing an
immediate assessment for something that they are not aware of or that
might be beyond their control. The BLM disagrees with these comments.
Operators have a responsibility to inspect their properties to ensure
site security, consistent with all applicable regulations, including
this final rule. The violations outlined in this section of the final
rule all have substantial adverse impacts on production accountability
or royalty income and, thus, the BLM believes the assessments are
warranted. No changes to the rule were made in response to these
comments.
Numerous commenters said that the increases in the number of
immediate assessments related to producing operations, from 1 to 11,
and in the dollar amount of the assessments, from $250 to $1,000, are
unreasonable. The number of immediate assessments was expanded to
include violations that pose particular threats to the integrity of the
BLM's production accounting system and that significantly increase the
BLM's workload and enforcement costs. The increase to $1,000 is
justified because it generally approximates what it will cost the
agency, on average, to identify and document a violation and verify
remedial action and compliance.
Commenters objected to this section of the proposed rule subjecting
purchasers and transporters to immediate assessments. One said that
purchasers and transporters should not be involved in retaining records
pertaining to the quality and quantity of production. Another commenter
said that oil and gas lease agreements are a contract between the
government and lessees and that purchasers and transporters are not a
party to those agreements and, therefore, should not be subject to
these assessments. Other commenters argued that the proposed immediate
assessments on purchasers and transporters exceeded the BLM's statutory
authority under FOGRMA. Upon consideration of these arguments, and
further review and analysis of FOGRMA and other authorities, the BLM
has removed the immediate assessments on purchasers and transporters
from final Sec. 3173.29.
Enforcement Actions
As explained in the proposed rule, the final rule removes the
enforcement, corrective action, and abatement period provisions of
Order 3. In their place, the BLM will develop an internal Inspection
and Enforcement Handbook that will provide direction to BLM inspectors
on how to classify a violation--as either major or minor--what the
corrective action should be, and what the timeframes for correction
should be. The AO will use the Inspection and Enforcement Handbook in
conjunction with 43 CFR subpart 3163, which provides for assessments
and civil penalties when lessees and operators fail to remedy their
violations in a timely fashion, and for immediate assessments for
certain violations.
As previously discussed in the proposed rule, the final rule allows
the BLM to make a case-by-case determination of the severity of a
violation, based on applicable definitions in the regulations. In
deciding how severe a violation is, BLM inspectors must take into
account whether a violation could result in ``immediate, substantial,
and adverse impacts on public health and safety, the environment,
production accountability, or royalty income.'' (Definition of ``major
violation,'' 43 CFR 3160.0-5.) Under the existing definition of ``major
violation,'' which is not being revised as
[[Page 81406]]
part of this rulemaking, the same violation could be major or minor,
depending on the context.
Several commenters objected to the BLM using internal guidance or
the Inspection and Enforcement Handbook to address violations,
assessments for noncompliance, and corrective actions. Commenters
argued that the use of internal enforcement guidance is inconsistent
with the APA and that these guidance documents constitute substantive
rules that must be developed through notice-and-comment rulemaking.
These comments misunderstand the nature of the Internal Inspection and
Enforcement Handbook that the BLM will develop. The Handbook will not
establish new obligations to be imposed on the regulated community in a
manner that will improve consistency in how those BLM personnel excise
there discretion in applying existing regulations and addressing
instances of non-compliance. Those obligations are spelled out in
applicable regulations, orders, and permits, as well as the terms and
conditions of leases and other agreements. Rather, the Handbook will
provide guidance to BLM personnel as to how to apply the existing
regulations and address instances of non-compliance. The overarching
enforcement infrastructure of 43 CFR subpart 3163 remains in effect,
and the definitions of ``major violation'' and ``minor violation'' in
Sec. 3160.0-5 remain unchanged. It is these duly promulgated
regulations (among other authorities), and not the Inspection and
Enforcement Handbook, that will provide the legal basis for the BLM's
enforcement actions; the BLM's enforcement actions must be consistent
with these regulations irrespective of what may be contained in its
Inspection and Enforcement Handbook. It is not necessary for the BLM to
develop its Handbook--which does not expand the BLM's authorities or
impose binding obligations on the regulated community--through notice-
and-comment rulemaking.
The commenters requested that the BLM use a transparent process to
develop this internal guidance and that operators be given the
opportunity to comment on it. The BLM did not accept these comments;
however, the BLM will post the Inspection and Enforcement Handbook on
the BLM Web site after it is developed and finalized.
Elimination of Self Inspections
Consistent with the proposed rule, this final rule eliminates the
self-inspection provision of Order 3, section III.F., because it has
been impractical for the BLM to enforce. Under the self-inspection
program, operators were supposed to establish a program for the purpose
of periodically measuring production volumes and assuring they were
complying with the BLM's minimum site security requirements. But, as
discussed earlier in response to comments on this topic during the
discussion of Sec. 3173.8, the Order 3 requirements were vague and the
BLM never supplemented them with internal guidance or enforcement
policy. As a result, the BLM determined that this requirement was of
limited utility.
Nonetheless, the BLM received a comment that recommended that
instead of removing the requirement, the language should be improved to
ensure that an inspection program is established for periodically
measuring production volumes and ensuring compliance with the BLM's
site security requirements from Order 3. The BLM disagrees with this
comment and did not make a change in response. In lieu of reworking or
updating this requirement, the final rule strengthens recordkeeping
requirements for operators, including for transporters and purchasers,
which the BLM believes will ultimately accomplish the same results and
be more useful going forward. It should also be noted that although the
self-inspection requirement from Onshore Order 3 has been eliminated,
the actions that an operator, transporter, or purchaser must take to
conduct periodic production volume inspections and ensure site security
have been incorporated into this final rule as required elements under
Sec. Sec. 3173.2 through 3173.10 of the final rule.
General Comments
The BLM received a few comments that were general in nature and do
not necessarily relate to a specific provision of the rule.
A number of comments argued that the rule is impermissibly
``retroactive.'' These comments argued that the rule is retroactive
because it will apply to wells, facilities, and authorizations that
existed before the rule's effective date. While the BLM agrees that
retroactive regulations raise special legal concerns, those concerns
are not implicated here because this rule is not a retroactive
regulation. The comments misunderstand the nature of the
``retroactive'' regulations that the law disfavors. ``A law does not
operate `retrospectively' merely because it is applied in a case
arising from conduct antedating the statute's enactment or upsets
expectations based in prior law.'' Landgraf v. USI Film Prods., 511
U.S. 244, 269 (1994) (internal citations omitted). Rather, the test for
retroactivity is whether the new regulation ``attaches new legal
consequences to events completed before its enactment.'' Id. at 270.
The rule at hand does not attach any new legal consequence to the
operation of existing wells and facilities prior to the rule's
effective date. As the U.S. Court of Appeals for the D.C. Circuit has
explained, the fact that a change in the law adversely affects pre-
existing business arrangements does not render that law
``retroactive:''
It is often the case that a business will undertake a certain
course of conduct based on the current law, and will then find its
expectations frustrated when the law changes. This has never been
thought to constitute retroactive lawmaking, and indeed most
economic regulation would be unworkable if all laws disrupting prior
expectations were deemed suspect.
Chemical Waste Mgmt., Inc. v. EPA, 869 F.2d 1526, 1536 (D.C. Cir.
1989). Thus, despite the fact that this rule may require operators to
update or modify their existing wells, facilities, and authorizations,
the rule is nonetheless prospective--not retroactive--in nature.
A couple of comments expressed that the BLM was employing
discriminatory regulation, and gave as their examples the inequality of
producers, operators, and transporters in regard to equity interest in
production. The proposed rule would treat producers, operators, and
transporters equally even though some of these parties (specifically
transporters) have no ownership interest in the oil and gas product
generated from Federal or Indian lands. Because they have no interest,
it is most likely that the costs they incur will be passed directly on
to equity holders, commenters said. Over time, the commenter asserted,
because equity holders may deduct transportation costs from royalties
owed, this may result in reduced royalty payments for both the
government and the tribes. While the BLM recognizes the possibility of
some pass through of compliance costs from purchasers and transporters
to operators, based on its analysis of the costs of this final rule, it
does not believe those costs will be significant. Additionally, this
change is consistent with the provisions of FOGRMA, which addresses
responsibilities and duties of operators, purchasers, and transporters.
By statute, Congress applied these legal requirements to those parties
equally.
One commenter pointed out that the regulations fail to recognize
the current industry business models, as it pertains to Master Limited
Partnerships. Unlike C Corporations, MLPs have no mechanism for
capitalizing the required
[[Page 81407]]
changes and will be forced to expense the cost. This passes the cost
immediately to unit holders. The commenter recommended that the BLM
remove MLPs from the regulation. The BLM did not understand this
comment in the context of this rule. Under the applicable statutes and
regulations operators, purchasers, and transporters are subject to the
regulations governing operations on a Federal or Indian (except Osage
Tribe) lease. The underlying corporate structure of those entities has
no bearing on their duty to comply with these requirements.
Many commenters questioned whether the BLM has the resources to
implement this and other rules that it has finalized, or will finalize
in the coming months, for example the new hydraulic fracturing
regulations, which went into effect on June 24, 2015 (currently
enjoined by order of the District Court of Wyoming), and the proposed
Waste Prevention, Production Subject to Royalties, and Resource
Conservation proposed rule, which published on February 8, 2016 (85 FR
6616). Commenters stated that the BLM does not have enough staff to
enforce its existing regulations, let alone new ones. Commenters also
said that the cumulative economic impact of this final rule should be
analyzed together with the economic impacts of the final rules that are
updating and replacing Orders 4 and 5.
The BLM does not agree with these comments. Most of the
requirements in this final rule are not new--they codify existing
requirements that are found in Order 3 or they are standard industry
practices that most operators, transporters, and purchasers already
follow. Those requirements that are new have been added for two
reasons: (1) To give operators the flexibility to use new technology,
which could, in the long run, reduce costs for both industry and the
BLM; and (2) To address production accountability and site security
concerns raised by governmental oversight bodies, such as the
Subcommittee, the GAO, and the OIG. The BLM did not change the final
rule as a result of these comments.
One commenter stated that the regulations should consider laws and
lease provisions that apply only in Alaska, and should more clearly
provide for balancing measurement accuracy and environmental
considerations. According to the commenter, these laws and lease
provisions impose heightened restrictions on development in Alaska with
which the site security regulations, in particular the requirements for
additional measurement facilities, would conflict. The BLM does not
agree with the commenter that changes to the rule are necessary. To the
extent trade-offs between measurement accuracy and environmental
considerations are appropriate, the BLM has already addressed those
issues in the rule--see e.g., the discussion of considerations that go
into reviewing requests for off-lease measurement or commingling
approvals. Additionally, whether the final rule requires additional
facilities is facility-specific. Moreover, as explained throughout this
preamble and the associated EA, the BLM expects that, to the extent the
final rule requires the construction of new facilities on a lease, the
relocation of existing facilities onto a lease, or the retrofitting of
existing facilities on a lease, it would likely be done on surfaces
that have already been disturbed. Thus, the BLM does not believe that
this rule will result in the significant ``footprint'' expansion the
commenter identified. Furthermore, should compliance with a requirement
of this rule necessitate surface disturbance inconsistent with
applicable laws or lease terms, the operator may, through the PMT or
under Sec. 3170.6, as applicable, seek approval of an alternative
means of compliance that would meet the objectives of that requirement.
Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160
As noted at the beginning of this Section-by-Section discussion,
the BLM has made other changes to provisions in 43 CFR part 3160. Some
of those have already been discussed above in connection with
provisions of this final rule to which they relate. The remaining
revisions are those noted here.
1. The authority citation for part 3160 is corrected to include 25
U.S.C. 396, the grant of rulemaking authority to the Secretary for
allotted Indian leases, which does not appear in the current print
edition of the CFR. The BLM did not receive any comments on this
change.
2. Section 3160.0-3, Authority, is updated to include the
amendments to the Federal Oil and Gas Royalty Management Act of 1982
enacted by the Federal Oil and Gas Royalty Simplification Act of 1996.
The BLM did not receive any comments on this change.
3. Section 3161.1, Jurisdiction, is updated to include references
to FMPs, the Indian Mineral Development Act, and Tribal Energy Resource
Agreements. To see the BLM's response to public comment on these
changes, please see the discussion of related changes to Sec. 3170.2
earlier in this preamble.
4. Section 3162.3-2 is revised by adding a new paragraph (d), which
refers operators to provisions in subpart 3173 for details on how to
apply for approval of FMPs, surface or subsurface commingling from
different leases, unit PAs and CAs, or off-lease measurement. The BLM
did not receive any comments on this change.
5. Section 3162.4-1, Well records and reports, is amended in a
number of respects by this final rule. Consistent with the proposed
rule, this final rule revises paragraph (a) to make clear that the new
recordkeeping requirements also apply to ``source records'' that are
relevant to ``determining and verifying the quality, quantity, and
disposition of production from or allocable to Federal or Indian
leases.'' Similarly, paragraph (d) has been revised to establish the
new records-retention period established by the 1996 amendments to
FOGRMA, and mirror for part 3160 the provisions in paragraphs (c)
through (e) of Sec. 3170.7 of the final rule. A new paragraph (e)
lists those ``record holders'' who would be subject to the new
recordkeeping requirements. This section also makes clear that all
record holders must maintain their records when directed by the
Secretary, or his/her designee, in cases where there is a judicial
proceeding or demand involving such records. In this section of the
previous rule, the Secretary, or his/her designee, could direct record
holders to maintain their records only in cases where there was an
audit or investigation.
6. Section 3162.4-3, the provisions regarding the no-longer-used
Form 3160-6 (the monthly report of operations), is removed. The BLM did
not receive any comments on this change.
7. Section 3162.6, Well and facility identification, is revised to
correct the misspelled word ``indentification'' in paragraph (a) to
read ``identification.'' Paragraph (b) is revised to remove a provision
allowing abbreviated sign designations and a ``grandfathering''
provision for old well signs. Paragraph (c) is revised to extend
signage requirements to include facilities at which oil or gas produced
from Federal or Indian leases is stored or processed. The fifth
sentence of the current paragraph (c) becomes the new paragraph (d),
with its wording revised. The current paragraph (d) is now paragraph
(e). The BLM did not receive any comments on this change.
8. Section 3162.7-1, Disposition of production. This final rule
removes paragraph (f), which currently refers to a 6-year retention
period, since the initial statutory retention period for records
concerning Federal leases is
[[Page 81408]]
now 7 years. The BLM opted not to retain paragraph (f) because this
retention period is already prescribed Sec. Sec. 3162.4-1 and 3170.7
of the final rule. The BLM received no comments on this proposed change
and did not make any changes from the proposed rule to the final rule.
9. Section 3162.7-5, Site security on Federal and Indian (except
Osage Tribe) oil and gas leases, has been removed. The provisions in
the final rule that correspond to, or cover the same subject matter as,
the several paragraphs in Sec. 3162.7-5 are shown in the following
table:
------------------------------------------------------------------------
43 CFR 3162.7-5 paragraph Final new provision
------------------------------------------------------------------------
(a) Definitions........................ 43 CFR 3173.1.
(b)(1) Lines and valves; effective 43 CFR 3173.2(a), 3173.9(b) and
sealing. 3173.11(c)(7).
(b)(2) LACT meters and effective 43 CFR 3170.4, 3173.3, and two
sealing of components. sections in anticipated new
subpart 3174.
(b)(3) By-passes around meters......... 43 CFR 3170.4.
(b)(4) Sealing of appropriate valves 43 CFR 3173.2(a) and (b).
during oil measurement by hand gauging.
(b)(5) Circulating lines with valves 43 CFR 3173.1.
allowing access to remove oil from
storage tanks.
(b)(6) Records retention requirements.. 43 CFR 3170.7.
(b)(7) Removal of oil for 43 CFR 3173.5.
transportation by vehicle and required
documentation.
(b)(8) Reporting theft or mishandling 43 CFR 3173.8.
of oil.
(b)(9) Variances....................... 43 CFR 3170.6.
(c) Site security plans................ None (site security plans
eliminated).
(d) Site facility diagrams............. 43 CFR 3173.11.
------------------------------------------------------------------------
10. Section 3163.2, Civil penalties, is rewritten in several
respects by this final rule. The changes being made to this section as
part of this rule are a combination of the changes proposed as part of
this rulemaking effort and the proposed rule to update and replace
Order 5 (80 FR 61645). In addition, following the publication of those
proposed rules, but prior to the publication of this rule, the BLM
published an interim final rule--Onshore Oil and Gas Operations--Civil
Penalties Inflation Adjustments (81 FR 41860)--that made adjustments
for inflation to all of the daily civil monetary penalty maximums found
in Sec. 3163.2. The adjustments made by the interim final rule were
required by the Federal Civil Penalties Inflation Adjustment Act
Improvements Act of 2015 (Sec. 701 of Pub. L. 114-74).
The BLM is making the following additional changes to Sec. 3163.2
in this final rule. These changes are not a result of the Federal Civil
Penalties Inflation Adjustment Act Improvements Act.
First, the BLM is amending the civil penalty regulations to reflect
the fact that purchasers and transporters who fail to maintain and
submit records as required by the BLM can be subject to civil penalties
under Section 109 of FOGRMA (30 U.S.C. 1719). As explained in the
proposed rule, this change is being made because the BLM's existing
regulations do not reflect this longstanding statutory authority. In
order to effectuate this change the BLM is designating the first
sentence of paragraph (a) of the existing Sec. 3163.2 as paragraph
(a)(1), and adding a new paragraph (a)(2) that reads as follows:
(2) Whenever a purchaser or transporter who is not an operating
rights owner or operator fails or refuses to comply with 30 U.S.C. 1713
or applicable rules or regulations regarding records relevant to
determining the quality, quantity, and disposition of oil or gas
produced from or allocable to a Federal or Indian oil or gas lease, the
authorized officer will notify the purchaser or transporter, as
appropriate, in writing of the violation. The second sentence of the
existing paragraph (a) (pertaining to the maximum amount of the penalty
if the violation is not corrected within 20 days of the date of notice)
is redesignated as paragraph (b)(1). The existing paragraph (b)
(pertaining to the maximum amount of the penalty if the violation is
not corrected within 40 days of the date of notice) is redesignated as
paragraph (b)(2).
The BLM received a number of comments asserting that it was unfair
to subject purchasers and transporters to the civil penalties under the
onshore oil and gas regulations because purchasers and transporters
often do not have control over the information provided by operators.
The BLM does not agree with these comments. As explained above, this
change is being driven primarily by longstanding statutory
requirements. Additionally, it should be noted that there are instances
where the purchaser or transporter actually owns the oil and gas
delivery point, and therefore has control of much of the relevant
information. With respect to concerns about the accuracy of information
provided by an operator to a purchaser or transporter, while entities
are generally responsible for the content of their records, the BLM
recognizes that such a situation (i.e., inaccurate information provided
by an operator) would be a factor that could be considered in an
enforcement action on a case-by-case basis.
In addition to the changes identified above, the BLM is also
revising paragraphs (a)(1) and (b)(1) to refer to ``any person'' and
``the person,'' respectively, rather than limiting the applicability of
civil penalties to an operating rights owner or operator. This change
is consistent with the statutory language found in Section 109(a) of
FOGRMA (30 U.S.C. 1719(a)). It also clarifies that potential penalty
liability exists for parties who contract with operating rights owners
or operators to perform activities on Federal or Indian leases and who
violate applicable regulations, statutes, permits, or lease terms in
performing those activities. While the operating rights owner or
operator is responsible (and liable for penalties) for violations
committed by contractors, the contractors are also themselves subject
to the requirements of certain statutes, regulations, permits, and
lease terms. The BLM is revising the regulations in this manner in
order to enable the agency to hold contractors directly responsible for
violations they commit.
In addition, this rule also removes the regulatory caps on civil
penalty assessments found in the current regulations paragraphs (b)
(paragraph (b)(2) in the final rule), (d), (e), and (f). As explained
in the proposed rule to update and replace Order 5 (80 FR 61645), this
change is based on
[[Page 81409]]
comments received on an Advance Notice of Proposed Rulemaking (ANPR)
(80 FR 22148) that sought input on a variety of issues related to the
onshore oil and gas program, including whether the regulatory civil
penalty caps should be removed. The ANPR explained that these caps are
not required by statute, and that in the BLM's view they impose a limit
on the total penalties that may be assessed that do not seem reasonable
in the modern oil and gas context where it can cost $5 to $10 million
dollars to drill a well.
As the BLM explained, it does not believe that the existing
regulatory caps provide an adequate deterrence for unlawful conduct,
particularly drilling on Federal onshore leases without authorization
and drilling into leased parcels in knowing and willful trespass.
Similar concerns were expressed by the Department's OIG in a report,
dated September 29, 2014--Bureau of Land Management, Federal Onshore
Oil & Gas Trespass and Drilling Without Approval (No. CR-IS-BLM-0004-
2014). In that report, the OIG specifically questioned the adequacy of
the BLM's policies to deter such activities and recommended that the
BLM pursue increased monetary fines. Based on the foregoing, the final
rule rewrites paragraphs (b) (paragraph (b)(2) in the final rule), (d),
(e), and (f) accordingly, to remove the regulatory caps, while
maintaining the statutory limits imposed on the amount that may be
assessed on a daily basis (30 U.S.C. 1719(a)-(d)), as amended by the
BLM's recent interim final rule adjusting those amounts for inflation.
Due to the removal of the regulatory civil penalty caps, the BLM
determined that paragraph (j) is unnecessary given that its
requirements would have tiered off the expiration of those caps. As a
result, this rule removes paragraph (j). The BLM is also deleting all
of paragraph (g). The existing requirements of paragraph (g)(1) and
(g)(2)(iii), which require initial proposed penalties to be at the
maximum rate, are being removed because they are inconsistent with
subsequent judicial and administrative decisions regarding the
computation and setting of penalties. The BLM also determined that the
requirements in paragraph (g)(1) and (g)(2)(iii) (establishing caps on
a per operating rights owner or operator per lease) are inconsistent
with the BLM's removal of regulatory caps on penalties found in
paragraphs (b) (paragraph (b)(2) in the final rule), (d), (e), and (f).
With respect to paragraphs (g)(2)(i) and (g)(2)(ii), the BLM is
removing the additional notice procedure and corrective period for
minor violations required under those paragraphs because it does not
believe those provisions are necessary. The BLM's regulations governing
oil and gas operations are clear, and provide more than adequate notice
of what is required, making additional notification requirements
unnecessary and administratively inefficient. As a result, this rule
removes all of paragraph (g) and redesignates existing paragraph (i) as
(g). Existing paragraph (h) is unaffected by this rule.
Finally, the BLM is moving the substance of existing paragraph (k),
which requires the revocation of a transporter's authority to remove
crude oil produced from, or allocated to, any Federal or Indian lease
if it fails to permit inspection for required documentation under 43
CFR 3162.7-1(c)), to paragraph (d) in order to streamline the
regulations. As a result, paragraph (k) is removed as part of this
rule.
One commenter on the proposed rule to replace Order 5 objected to
the BLM's expansion of the civil penalty provision to ``purchasers and
transporters'' and to the change to ``any person,'' instead of
retaining the existing language that limited Sec. 3163.2 to the
operating rights owner or operator. That commenter contended that the
BLM lacked authority to impose liability on contractors undertaking
activities on a Federal or Indian lease. The BLM disagrees with this
comment because this change is consistent with Section 109(a) of FOGRMA
(30 U.S.C. 1719(a)), which states that ``any person'' who violates the
mineral leasing laws, any rule or regulation issued under those laws,
or the terms of any lease or permit shall be liable for civil
penalties.
The BLM also heard a range of opinions on the removal of the
regulatory civil penalty caps. Some commenters contended that the
provisions would result in the imposition of penalties that are
excessive, while others supported the change. As explained early in
this section, the existing regulatory caps on civil penalties result in
maximum penalties that are small relative to the costs of drilling a
modern oil and gas well such that the potential deterrent effect of
civil penalties is limited. For example, the maximum penalty that could
be assessed under existing paragraph (b) is $600,000, which is only 10
percent of the cost of drilling a typical well, which is potentially
insufficient to act as a deterrent to non-compliance.
Finally, several commenters suggested that the BLM amend the
proposed regulations to require that any time a purchaser, transporter,
or contractor receives an INC, a copy be provided to the operating
rights owner. The BLM agrees with commenters that adequate notice of
potential violations is important; however, it determined that such
changes are unnecessary. By existing policy and practice, the BLM
addresses INCs to the party who is the subject of the action and does
not believe it is appropriate to automatically copy unrelated third
parties. Additionally, the regulations already require that if a party
is going to be subject to such penalties, it has to receive notice in
writing first from the BLM. Thus, under the scenarios identified by the
commenters, if they were going to be penalized they would have to first
receive a written notice from the BLM identifying the violation(s) in
question.
11. Section 3164.1, Onshore Oil and Gas Orders, is revised to
remove the reference to Order No. 3, Site Security, from the table in
paragraph (b) because the Order is now replaced by this codified final
rule.
12. Section 3165.3, Notice, State Director review and hearing on
the record, is rewritten in several respects by this final rule.
Specifically, consistent with the changes to Sec. 3163.2 and the
proposed rule, this rule amends the notice requirements of the existing
regulations at 43 CFR 3165.3 to include a provision regarding notice to
a purchaser or transporter (who is not an operating rights owner or
operator) of a failure to comply with records maintenance or production
requirements. This final rule also adopts the changes proposed as part
of the Order 5 rulemaking to revise this section to clarify that any
person, not just ``an operating rights owner or operator'' (as
previously provided for in paragraph (a)(1)), is subject to a written
notice or order of they fail to comply with any provisions of the
lease, the regulations in this part, applicable orders or notices, or
any other appropriate order of the authorized officer.
In addition, the BLM has also divided the several sentences of the
existing paragraph (a) into numbered paragraphs (a)(1) through (a)(7)
and added clarifying, nonsubstantive revisions throughout the section.
After the first sentence, which has been redesignated as paragraph
(a)(1) (and rephrased into active voice), the BLM has added a new
paragraph (a)(2) as set out in the regulatory text of this final rule.
In addition, the second and third sentences of existing paragraph
(a) are redesignated as paragraph (a)(3), and the fourth, fifth and
sixth and seventh sentences are redesignated as paragraphs (a)(4)
through (a)(7). The
[[Page 81410]]
BLM did not receive any comments on these changes and as a result did
not make any further changes in this final rule.
III. Overview of Public Involvement and Consistency With GAO
Recommendations
Public Outreach
The BLM conducted extensive public and tribal outreach on this rule
both prior to its publication as a proposed rule and during the public
comment period on the proposed rule. Prior to the publication of the
proposed rule, the BLM held both tribal and public forums to discussion
potential changes to the rule. In 2011, the BLM held three tribal
meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico
(July 13, 2011); and Billings, Montana (August 24, 2011). On April 24
and 25, 2013, the BLM held a series of public meetings in Washington,
DC, to discuss draft proposed revisions to Orders 3, 4, and 5. The
meetings were webcast so tribal members, industry, and the public
across the country could participate and ask questions either in person
or over the Internet. Following those meetings, the BLM opened a 36-day
informal comment period, during which 13 comment letters were
submitted. The comments received during that comment period were
summarized in the preamble for the proposed rule (80 FR 58952).
The proposed rule was made available for public comment from
September 30, 2015, through December 14, 2015. During that period, the
BLM held tribal and public meetings on December 1 (Durango, Colorado),
December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North
Dakota). The BLM also held a tribal webinar on November 19, 2015. In
total, the BLM received 106 comment letters on the proposed rule, the
substance of which are addressed in the Section-by-Section analysis of
this preamble.
Consistency With GAO Recommendations
As explained in the background section of this preamble, three
outside independent entities--the Subcommittee, the OIG, and the GAO--
have repeatedly found that the BLM's oil and gas measurement rules do
not provide sufficient assurance that operators pay the royalties due.
Specifically, these groups found that the BLM needed updated guidance
on oil and gas measurement technologies, to address existing
technological advances, as well as technologies that might be developed
in the future. These groups have all found that the BLM's existing
guidance is ``unconsolidated, outdated, and sometimes insufficient,''
and more specifically with respect to Order 3, that:
There was no uniform means of tracking all onshore meters,
including information about meter location, identification number, and
owner;
Some BLM State offices have issued their own guidance,
which lacks a national perspective; more specifically there were
concerns about the lack of uniform national guidance with respect to
the review and approval of commingling and off-lease measurements
requests; and
There was insufficient information collected with respect
to on-lease royalty-free use.
The final rule addresses these recommendations by establishing
uniform national guidance governing the review and approval of FMPs,
CAAs, and off-lease measurements. It also requires operators to provide
more information about royalty-free use. The provisions of the final
rule specifically address modern oil industry practices with respect to
each of these, while also updating relevant documentation and
recordkeeping requirements in order to ensure that all production is
properly accounted for.
IV. Procedural Matters
Executive Orders 12866 and 13563, Regulatory Planning and Review
Executive Order 12866 provides that the Office of Information and
Regulatory Affairs (OIRA) will review all significant rules. The OIRA
has determined that this rule is not significant.
Executive Order 13563 reaffirms the principles of E.O. 12866 while
calling for improvements in the nation's regulatory system to promote
predictability, to reduce uncertainty, and to use the best, most
innovative, and least burdensome tools for achieving regulatory ends.
The executive order directs agencies to consider regulatory approaches
that reduce burdens and maintain flexibility and freedom of choice for
the public where these approaches are relevant, feasible, and
consistent with regulatory objectives. E.O. 13563 emphasizes further
that regulations must be based on the best available science and that
the rulemaking process must allow for public participation and an open
exchange of ideas. The BLM has developed this rule in a manner
consistent with these requirements.
Regulatory Flexibility Act
The BLM certifies that this final rule will not have a significant
economic effect on a substantial number of small entities as defined
under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). The Small
Business Administration (SBA) has developed size standards to carry out
the purposes of the Small Business Act and those size standards can be
found at 13 CFR 121.201. The Small Business Act applies to oil and gas
extraction firms with fewer than 1,250 employees, oil and gas drilling
firms with fewer than 1,000 employees, and firms providing oil and gas
support activities with annual receipts of no more than $38.5 million.
These small entities must be considered as being at ``arm's length''
from the control of any parent companies.
Of the 6,460 domestic firms involved in crude oil and gas
extraction in 2013, U.S. Census data show that 99 percent (or 6,370)
had fewer than 500 employees, which means that nearly all U.S. firms
involved in oil and gas extraction in 2013 fell within the SBA's size
standard of fewer than 1,250 employees. Of the 2,097 firms
participating in oil and gas drilling activities in 2013, U.S. Census
data show that 2,044 (97 percent) had fewer than 500 employees, which
means that nearly all U.S. firms involved in oil and gas support
activities in 2013 fell within the SBA's size standard of fewer than
1,000 employees. In 2012, there were 8,877 firms involved in drilling
and other support functions, of which 96 percent (8,561) had annual net
receipts of no more than $35 million, with a greater number below the
SBA's $38.5 million threshold.
In addition to lessees and operators, we must consider the size of
the purchaser and transporter firms. There are multiple NAICS
categories that could include firms involved in the purchasing and
transporting of petroleum from Federal and Indian leases. For example,
petroleum refiners could be identified as purchasers. For petroleum
refiners (NAICS code 324110), the SBA standard says a small business
cannot have more than 1,500 employees or more than 200,000 bbl per
calendar day total operable atmospheric crude oil distillation
capacity. In that context, capacity includes owned or leased facilities
as well as facilities under a processing agreement or an arrangement
such as an exchange agreement or a throughput agreement. Purchasers
could also be wholesalers, truck transporters, or natural gas or
pipeline operators. For wholesalers, including petroleum wholesalers
(NAICS codes 424710 and 424720), the SBA standard for a small entity is
one that has fewer than 200 employees. For truck transporters (NAICS
subsector
[[Page 81411]]
484), the SBA defines a small entity as a firm with less than $27.5
million in annual receipts. For natural gas pipeline operators (NAICS
code 486210), the standard is a maximum of $27.5 million in receipts
per year. For crude oil pipeline operators (NAICS code 486110), the
standard is fewer than 1,500 employees.
As discussed above, national data, including number of firms,
number of employees by firm, and annual receipts by firm, is not
discretely identified for purchasers and transporters of petroleum or
natural gas. The potentially affected purchasers and transporters will
likely be a minor component in any number of the relevant NAICS
categories. Of the few NAICS categories where reported employment,
receipt, and production data matches up with the SBA size standards,
the preponderance of the firms will be considered small entities as
defined by the SBA.
Based on the available national data, the preponderance of firms
involved in developing, producing, purchasing, and transporting oil and
gas from Federal and Indian lands are small entities as defined by the
SBA. As such, it appears a substantial number of small entities could
be affected by this final rule.
Using the best available data, the BLM estimates there are
approximately 3,700 lessees and operators conducting oil and gas
operations on Federal and Indian lands that could be affected by this
final rule. Additionally, the BLM estimates there are approximately 200
to 300 purchasers and transporters operating on Federal and Indian
lands that potentially could be affected by this final rule.
In addition to determining whether a substantial number of small
entities are likely to be affected by this rule, the BLM must also
determine whether the rule is anticipated to have a significant
economic impact on those small entities. Based on the Economic and
Threshold Analysis prepared for this final rule, the BLM anticipates
the cost of implementing the provisions could reduce the average annual
net income of impacted small entities by less than 0.001 percent.
Except for the electronic filing requirement, all of the provisions
apply to entities regardless of size. However, entities with the
greatest activity will likely experience the greatest increase in
compliance costs. As a general matter, smaller business entities are
more likely to operate a smaller number of sites and FMPs for which
they will have to submit the information and documentation that this
final rule requires. Copies of the analysis can be obtained from the
contact person listed earlier (see FOR FURTHER INFORMATION CONTACT).
Based on the available information, we conclude that the final rule
will not have a significant impact on a substantial number of small
entities. Therefore, a final Regulatory Flexibility Analysis is not
required, and a Small Entity Compliance Guide is not required.
Small Business Regulatory Enforcement Fairness Act
This final rule is not a major rule under 5 U.S.C. (2), the Small
Business Regulatory Enforcement Fairness Act. This rule will not have
an annual effect on the economy of $100 million or more. As explained
in the Economic and Threshold Analysis, the final rule will increase
the estimated ongoing costs associated with the development of Federal
and Indian oil and gas resources by an estimated $11.7 million annually
for the regulated community. In addition, there will be an estimated
one-time cost to the regulated community to implement the new
provisions of $31.2 million. The one-time implementation costs will be
spread over 3 years, or about $10.4 million per year. As discussed in
the Economic and Threshold Analysis, the BLM anticipates the cost of
implementing the provisions could reduce the average annual net income
of impacted small entities by approximately 0.01 percent.
This rule replaces Order 3 to ensure that oil and gas produced from
Federal and Indian leases is properly and securely handled so that
these resources are accurately accounted for.
This rule:
Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, tribal, or local
government agencies, or geographic regions; and
Will not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
Unfunded Mandates Reform Act
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
et seq.), the BLM finds that:
This rule will not ``significantly or uniquely'' affect
small governments. A Small Government Agency Plan is unnecessary.
This rule will not produce a Federal mandate of $100
million or greater in any single year.
The rule is not a ``significant regulatory action'' under the
Unfunded Mandates Reform Act. The changes in this rule will not impose
any requirements on any non-Federal Governmental entity.
Executive Order 12630, Governmental Actions and Interference With
Constitutionally Protected Property Rights (Takings)
Under Executive Order 12630, the rule will not have significant
takings implications. A takings implication assessment is not required.
This rule will set minimum standards for ensuring that oil and gas
produced from Federal and Indian (except the Osage Tribe) oil and gas
leases are properly and securely handled, so as to prevent theft and
loss and to enable accurate measurement and production accountability.
All such actions are subject to lease terms which expressly require
that subsequent lease activities be conducted in compliance with
applicable Federal laws and regulations. The rule conforms to the terms
of those Federal leases and applicable statutes, and as such the rule
is not a governmental action capable of interfering with
constitutionally protected property rights. Therefore, the rule will
not cause a taking of private property or require further discussion of
takings implications under this Executive Order.
Executive Order 13132, Federalism
In accordance with Executive Order 13132, the BLM finds that the
rule would not have significant Federalism effects. A Federalism
assessment is not required. This rule will not change the role of or
responsibilities among Federal, State, and local governmental entities.
It does not relate to the structure and role of the States and will not
have direct, substantive, or significant effects on States.
Executive Order 13175, Consultation and Coordination With Indian Tribal
Governments
Under Executive order 13175, the President's memorandum of April
29, 1994, ``Government-to-Government Relations with Native American
Tribal Governments'' (59 FR 22951), and 512 Departmental Manual 2, the
BLM evaluated possible effects of the final rule on federally
recognized Indian tribes. The BLM approves proposed operations on all
Indian onshore oil and gas leases (except Osage Tribe). Therefore, the
final rule has the potential to affect Indian tribes. In conformance
with the Secretary's policy on tribal consultation, the BLM held tribal
consultation meetings to which more than 175 tribal entities were
invited, both before the rule was
[[Page 81412]]
proposed and during the public comment period on the proposed rule. The
consultations were held in:
Pre-Publication Meetings
Tulsa, Oklahoma on July 11, 2011;
Farmington, New Mexico on July 13, 2011; and
Billings, Montana on August 24, 2011.
Tribal workshop and webcast in Washington, DC, on April
24, 2013.
Post-Publication Meetings
The BLM hosted a webinar to discuss the requirements of
the proposed rule and solicit feedback from affected tribes on November
19, 2015; and
In-person meetings were held in:
[cir] Durango Colorado, on December 1, 2015;
[cir] Oklahoma City, Oklahoma, on December 3, 2015; and
[cir] Dickinson, North Dakota, on December 8, 2015.
The BLM also met with interested tribes on a one-on-one basis as
requested to address questions on the proposed rule prior to the
publication of the final rule. In each instance, the purpose of these
meetings was to solicit feedback and comments from the tribes. The
primary concerns expressed by tribes related to the subordination of
tribal laws, rules, and regulations by the proposed rule; tribal
representation on the Department's Gas and Oil Measurement Team; and
the BLM's Inspection and Enforcement program's ability to enforce the
terms of this rule. In general, the tribes, as royalty recipients,
expressed support for the goals of the rulemaking, namely accurate
measurement. With respect to tribal representation on the Department's
Gas and Oil Measurement Team, it should be noted that the team is
internal only. That said, the BLM will continue to consult with tribes
on measurement issues that impact them and their resources. None of the
tribal comments received were directed specifically at this rule's oil
measurement requirements, and therefore no changes were made as a
result of these comments. While the BLM will continue to address these
concerns, none of the concerns affect the substance of the proposed
rule.
Executive Order 12988, Civil Justice Reform
Under Executive Order 12988, the Office of the Solicitor has
determined that the final rule will not unduly burden the judicial
system and meets the requirements of Sections 3(a) and 3(b)(2) of the
Executive Order. The Office of the Solicitor has reviewed the final
rule to eliminate drafting errors and ambiguity. It has been written to
minimize litigation, provide clear legal standards for affected conduct
rather than general standards, and promote simplification and burden
reduction.
Executive Order 13352, Facilitation of Cooperative Conservation
Under Executive Order 13352, the BLM has determined that this final
rule will not impede facilitating cooperative conservation and will
take appropriate account of and consider the interests of persons with
ownership or other legally recognized interests in land or other
natural resources. This rulemaking process involved Federal, tribal,
State, and local governments, private for-profit and nonprofit
institutions, other nongovernmental entities and individuals in the
decision-making via the public comment process. That process provides
that the programs, projects, and activities are consistent with
protecting public health and safety.
Paperwork Reduction Act
The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) provides
that an agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information, unless it displays a
currently valid OMB control number. Collections of information include
requests and requirements that an individual, partnership, or
corporation obtain information, and report it to a Federal agency. See
44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information collection activities that require
approval by the OMB under the PRA. The BLM included an information
collection request in the proposed rule. OMB has approved the
information collection for the final rule under control number 1004-
0207.
Some of the information collection activities in the rule will add
new uses and burdens for BLM Form 3160-5, Sundry Notices and Reports on
Wells. Form 3160-5 has been approved by OMB for uses enumerated at 43
CFR 3162.3-2, and is one of 17 information collection activities that
are included in control number 1004-0137, Onshore Oil and Gas
Operations (43 CFR part 3160) (expiration date January 31, 2018).
The information collection activities in this rule are described
below along with estimates of the annual burdens. Included in the
burden estimates are the time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing each component of the information collection.
Summary of Information Collection Activities
Title: Oil and Gas Facility Site Security (43 CFR Subparts 3170 and
3173).
Forms: Form 3160-5, Sundry Notices and Reports on Wells.
OMB Control Number: 1004-0207.
Description of Respondents: Oil and gas operators, lessees,
operators, purchasers, transporters, and any other person directly
involved in producing, transporting, purchasing, selling, or measuring
oil or gas.
Abstract: This rule establishes minimum security standards for
Federal and Indian (except Osage Tribe) oil and gas leases.
Frequency of Collection: On occasion.
Obligation To Respond: Required to obtain or retain benefits.
Estimated Annual Responses: 274,886.
Estimated Reporting and Recordkeeping ``Hour'' Burden: 578,240
hours.
Estimated ``Non-Hour'' Burden: $4,891.972.
Discussion of Information Collection Activities
Some of the activities will be one-time-only, while others will be
ongoing. Similarly, the BLM recognizes that for some of the activities,
there will be both an annual burden for some respondents, and a one-
time burden for virtually all respondents in the initial
implementation. Because of the way the rule is structured, the one-time
burdens that are applicable to all respondents are phased-in over 3
years based on production volumes.
The preamble to the proposed rule solicited public comments on the
information collection. Those comments, and responses of the BLM, are
discussed above in the preamble. All comments--both those pertaining to
information collection and other comments--are addressed in the final
rule. The comments and BLM responses pertaining specifically to the
collection of information are discussed in the Section-by-Section
analysis of the following sections of the final rule:
3170.7;
3173.6 through 3173.9;
3173.11 through 3173.13;
3173.15;
3173.23; and
3173.25.
The information-collection activities in this rule are described
below.
[[Page 81413]]
Well and Facility Identification (43 CFR 3162.6)
The information-collection activity in the current version of Sec.
3162.6 has been approved by OMB under control number 1004-0137. The
revisions effected by this rule are not expected to exceed the existing
burden hours authorized by control number 1004-0137. This activity is
not included in the burdens for this rule.
Variance Requests (43 CFR 3170.6)
Section 3170.6, a new regulation, authorizes any party that is
subject to the regulations in 43 CFR part 3170 to request a variance
from any of the regulations in part 3170. While Sec. 3170.6 states
that a request for a variance should be filed using the BLM's
electronic system, it also allows the use of paper copies of Form 3160-
5 (Sundry Notices). Thus, Sec. 3170.6 represents a new use of Form
3160-5, Sundry Notices and Reports on Wells.
Required Recordkeeping and Records Submission (43 CFR 3170.7)
Section 3170.7 applies to lessees, operators, purchasers,
transporters, and any other person directly involved in producing,
transporting, purchasing, selling, or measuring oil or gas through the
point of royalty measurement or the point of first sale, whichever is
later. This regulation applies to records generated during or for the
period for which the lessee or operator has an interest in or conducted
operations on the lease, or in which a person is involved in
transporting, purchasing, or selling production from the lease. This
information collection activity assists the BLM in accurate accounting
of oil and gas production.
In general, records from Federal leases must be maintained for 7
years, and records from Indian leases must be maintained for 6 years.
Additional details and exceptions are explained below.
For Federal leases, and units or communitized areas that include
Federal leases but do not include Indian leases, the record holder must
maintain records for 7 years after the records are generated. If a
judicial proceeding or demand involving such records is timely
commenced, the record holder must maintain such records until the final
nonappealable decision in such judicial proceeding is made, or with
respect to that demand is rendered, unless the Secretary, her designee,
or the applicable delegated State authorizes in writing an earlier
release of the requirement to maintain such records.
For Indian leases, and units or communitized areas that include
Indian leases but do not include Federal leases, the record holder must
maintain records for 6 years after the records are generated. If the
Secretary or her designee notifies the record holder that the
Department of the Interior has initiated or is participating in an
audit or investigation involving such records, the record holder must
maintain such records until the Secretary or his designee releases the
record holder from the obligation to maintain the records.
For units and communitized areas that include both Federal and
Indian leases, if the Secretary or his designee has notified the record
holder within 6 years after the records are generated that an audit or
investigation involving such records has been initiated, but a judicial
proceeding or demand is not commenced within 7 years after the records
are generated, the record holder must retain all records regarding
production from the unit or communitized area until the Secretary or
her designee releases the record holder from the obligation to maintain
the records. If a judicial proceeding or demand is commenced within 7
years after the records are generated, the record holder must retain
all records regarding production from the unit or communitized area
until the final nonappealable decision in such judicial proceeding is
made, or with respect to that demand is rendered, unless the Secretary
or her designee authorizes in writing a release of the requirement to
maintain such records before a final nonappealable decision is made or
rendered.
For all types of Federal and Indian leases, the lessee, operator,
purchaser, and transporter must maintain an audit trail that includes
all records, including source records that are used to determine
quality, quantity, disposition, and verification of production
attributable to a Federal or Indian lease, unit participating area
(unit PA), or CA, must include the FMP number or the lease, unit PA, or
CA number along with a unique equipment identifier (e.g., a unique tank
identification number and meter station number); and the name of the
company that created the record. For existing measurement facilities,
in the interim period before the assignment of an FMP number, all
records must include the following information:
The name of the operator;
The lease, unit PA, or CA number; and
The well or facility name and number.
Section 3170.7(h) requires operators, purchasers, and transporters
to submit all records, including source records that are relevant to
determining the quality, quantity, disposition, and verification of
production attributable to Federal or Indian leases, upon request, in
accordance with a regulation, written order, Onshore Order, NTL, or
COA.
Water-Draining Operations--Data Collection (43 CFR 3173.6); and
Water-Draining Operations--Recordkeeping and Records Submission (43 CFR
3170.7 and 3173.6)
Section 3173.6 requires submission of information when water is
drained from a production storage tank. The information is required
from the operator, purchaser, or transporter, as appropriate.
Previously, the operator was not required to record the volume of
hydrocarbons that are in the tank before and after water is drained. As
a result, hydrocarbons could be drained with the water and removed
without proper measurement and accounting, and without royalties being
paid. This information collection activity assists the BLM in accurate
accounting of oil and gas produced from Federal and Indian leases.
The following information is required:
Federal or Indian lease, unit PA, or CA number(s);
The tank location by land description;
The unique tank number and nominal capacity;
Date for opening gauge;
Opening gauge of the total oil volume and free-water
measurements;
Unique identifying number of each seal removed;
Closing gauge of the total oil volume measurement; and
Unique identifying number of each seal installed.
Hot Oiling, Clean-Up, and Completion Operations--Data Collection (43
CFR 3173.7); and
Hot Oiling, Clean-Up, and Completion Operations--Recordkeeping and
Records Submission (43 CFR 3170.7 and 3173.7)
Section 3173.7 requires the submission of information during hot
oil, clean-up, or completion operations, or any other situation where
the operator removes oil from storage, temporarily uses it for
operational purposes, and then returns it to storage on the same lease,
unit PA, or CA.
Previously, the operator was not required to record the volume of
hydrocarbons removed from storage with the expectation that they will
be returned to storage. As a result, the volume of produced
hydrocarbons
[[Page 81414]]
could be counted twice; first when it was initially produced then later
after it is returned to storage. This information collection activity
assists the BLM in accurate accounting of oil and gas produced from
Federal and Indian leases.
The following information is required:
Federal or Indian lease, unit PA, or CA number(s);
The tank location by land description;
The unique tank number and nominal capacity;
Date of the opening gauge;
Opening gauge measurement;
Closing gauge measurement;
Unique identifying number of each seal installed;
How the oil was used; and
Where the oil was used (i.e., well or facility name and
number).
Report of Theft or Mishandling of Production (43 CFR 3173.8)
Section 3173.8 requires operators, transporters, or purchasers to
submit a report (either oral or written) no later than the next
business day after discovery of an incident of apparent theft or
mishandling of production. All oral reports must be followed up with a
written incident report within 10 business days of the oral report. By
applying not only to operators but also to transporters and purchasers
(who often are the first ones to discover theft and mishandling or to
recognize suspicious activity), this information collection activity
assists in prompt disclosure of theft or mishandling. The incident
report must include the following information:
Company name and name of the person reporting the
incident;
Lease, unit PA, or CA number, well or facility name and
number, and FMP number, as appropriate;
Land description of the facility location where the
incident occurred;
The estimated volume of production removed;
The manner in which access was obtained to the production
or how the mishandling occurred;
The name of the person who discovered the incident;
The date and time of the discovery of the incident; and
Whether the incident was reported to local law enforcement
agencies and company security
Required Recordkeeping for Inventory and Seal Records (43 CFR 3173.9)
Section 3173.9 requires operators to measure and record within
3 days of the final day of each calendar month an
inventory consisting of TOV in storage (less free water). If the
inventory is not taken on the final day of each month, it must be
estimated based on two measurements no less than 20 days and no more
than 31 days apart, based upon the prorated difference between these
inventory levels and any sales that have occurred between the two
measurements. This information collection activity assists the BLM in
accurate accounting of oil and gas production.
For each seal, the operator must maintain a record that includes
the unique identifying number of each seal and the valve or meter
component on which the seal is or was used; the date of installation or
removal of each seal; for valves, the position (open or closed) in
which it was sealed; and the reason the seal was removed.
Site Facility Diagrams for Existing Facilities (43 CFR 3173.11(d)(2));
and
Site Facility Diagrams for Future Facilities (43 CFR 3173.11(d)(1))
Section 3173.11 requires a site facility diagram for all
facilities. Section 3170.3 of the final rule defines ``facility'' as a
site and associated equipment used to:
Process, treat, store, or measure oil or gas production
from or allocated to a Federal or Indian lease, unit, or CA that is
located upstream of or at (and including) the approved point of royalty
measurement; or
Store, measure, or dispose of produced water that is
located on a lease, unit, or CA.
A site facility diagram is one of the BLM's primary mechanisms for
monitoring operators' compliance with measurement regulations and
policy. These information collection activities enable the BLM to
verify, among other things, royalty-free-use volumes reported by the
operator on its OGORs. These activities also enhance production
accountability and respond to key recommendations made by the GAO and
the OIG. In the long term, this information collection request will
eliminate the need for the BLM to obtain the information in connection
with a production verification and accountability review.
Paragraphs (a) through (c) of Sec. 3173.11 require that each site
facility diagram be submitted with a completed Sundry Notice.\13\ The
diagram itself should be formatted to fit on an 8\1/2\ x 11 sheet of
paper, if possible, and must be legible and comprehensible to an
individual with an ordinary working knowledge of oilfield operations.
If more than one page is required, each page must be numbered (in the
format ``N of X pages''). Paragraph (c) specifies that a site facility
diagram must:
---------------------------------------------------------------------------
\13\ Form 3160-3, which is approved under OMB control number
1004-0137 for uses enumerated at 43 CFR 3162.3-2.
---------------------------------------------------------------------------
Reflect the position of the production and water recovery
equipment, piping for oil, gas, and water, and metering or other
measuring systems in relation to each other, but need not be to scale;
Commencing with the header, identify all of the equipment,
including, but not limited to, the header, wellhead, piping, tanks, and
metering systems located on the site, and include the appropriate
valves and any other equipment used in the handling, conditioning, or
disposal of production and water, and indicate the direction of flow;
Identify by API number the wells flowing into headers;
Indicate which valve(s) must be sealed and in what
position during the production and sales phases and during the conduct
of other production activities (e.g., circulating tanks or drawing off
water), which may be shown by an attachment, if necessary;
Clearly identify the lease, unit PA, or CA to which the
diagram applies and the land description of the facility, and the name
of the company submitting the diagram, with co-located facilities being
identified for each lease, unit PA, or CA; and
Clearly identify as an attachment all meters and
measurement equipment. Specifically identify all approved and assigned
FMPs.
If another operator operates a co-located facility, the site
facility diagram must depict the co-located facilities on the diagram
or list them on an attachment and identify them by company name,
facility name(s), lease, unit PA, or CA number, and FMP number(s). When
describing co-located facilities operated by one operator, the site
facility diagram must include a skeleton diagram of the co-located
facility, showing equipment only. For storage facilities common to co-
located facilities operated by one operator, one diagram would be
sufficient.
If the operator claims royalty-free use, the site facility diagram
must clearly identify on the diagram or as an attachment, the equipment
for which the operator claims royalty-free use.
Section 3173.11(d) specifies the timing requirements for submission
of an updated site facility diagram for facilities for which the BLM
will assign an FMP number under Sec. 3173.12. This section applies to
both new and existing facilities.
For facilities that are in service on or after the
effective date of the final
[[Page 81415]]
rule, a site facility diagram must be submitted within 30 days after
the BLM assigns an FMP number to the facility.
For facilities that are in service before the effective
date of the final rule and that have a site facility diagram on file
that meets the minimum requirements of the previous rule (i.e., Order
3), operators must submit a new site facility diagram within 30 days
after:
[cir] Existing facilities are modified;
[cir] A non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified; or
[cir] There is a change in operator.
The submitted diagram must comply with the requirements of paragraphs
(a) through (c) of Sec. 3173.11. Those requirements are described
above.
Section 3173.11(e) specifies the timing requirements for submission
of an updated site facility diagram for facilities for which the BLM
will not assign an FMP number under Sec. 3173.12. This section applies
to both new and existing facilities.
For facilities that are in service on or after the
effective date of the final rule, a site facility diagram must be
submitted within 30 days after the BLM assigns an FMP number to the
facility.
For facilities that are in service before the effective
date of the final rule and that have a site facility diagram on file
that meets the minimum requirements of the previous rule (i.e., Order
3), operators must submit a new site facility diagram within 30 days
after:
[cir] Existing facilities are modified;
[cir] A non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified; or
[cir] There is a change in operator.
Section 3173.11(f) specifies that after a site facility diagram has
been submitted that complies with the requirements of Sec. 3173.11,
operators have an ongoing obligation to update and amend them within 30
days after such facilities are modified, a non-Federal facility located
on a Federal lease or federally approved unit or communitized area is
constructed or modified, or there is a change in operator.
Request for Approval of an FMP for Existing Measurement Facilities (43
CFR 3173.12(e)); and
Request for Approval of an FMP for Future Measurement Facilities (43
CFR 3173.12(d))
Section 3173.12 requires operators to obtain BLM approval of FMPs
for all measurement points that are used to determine royalties. An FMP
is a BLM-approved point where oil or gas produced from a Federal or
Indian lease, unit, or CA is measured and the measurement affects the
calculation of the volume or quality of production on which royalty is
owed. See 43 CFR 3170.3.
This information collection activity provides the BLM with a formal
nationwide process for designating and approving the point at which oil
or gas must be measured for the purpose of determining royalty. This
activity assists the BLM in verifying production. Upon receiving an
initial request for an FMP, the BLM will approve it if it meets the
requirements of this rule, and assign each FMP a unique identifying
number, which the operator, transporter, or purchaser will use when
reporting production results to the Office of Natural Resources Revenue
(ONRR).
All requests for an FMP must include the following:
A complete Sundry Notice;
The applicable Measurement Type Code specified in the
BLM's Well Information System (WIS);
For gas measurement, identification of the operator/
purchaser/transporter unique station number, meter tube size or serial
number, and type of secondary device;
For oil measurement, identification of the oil tank
number(s) or tank serial number(s) and size of each tank, and whether
the oil was measured by LACT or CMS if not measured by tank gauge;
Where production from more than one well will flow to the
requested FMP, a list of the API well numbers associated with the FMP;
and
FMP location by land description.
Section 3173.12(d) requires operators to request a new FMP for new
permanent measurement facilities before any production leaves the
facility. Each request must meet the requirements listed above.
Modifications to an FMP (43 CFR 3173.13(b)(1))
Section 3173.13(b)(1) requires operators with an approved FMP to
submit a Sundry Notice that details any modifications to the FMP within
30 days after the change. These details include, but are not limited
to, tank numbers or serial numbers and sizes for oil FMPs, unique
station numbers, meter tube sizes or serial numbers, and type of
secondary devices for gas FMPs, and for all FMPs with more than one
well, the API numbers for all wells associated with the facility. The
Sundry Notice must specify what was changed, the effective date, and
include, if appropriate, an amended site facility diagram. This
information collection activity assists the BLM in accurate accounting
of oil and gas production.
Request for Approval of an Existing CAA (43 CFR 3173.15); and
Request for Approval of a Future CAA (43 CFR 3173.15)
A CAA is a formal allocation agreement to combine production from
two or more sources (leases, unit PAs, CAs, or non-Federal or non-
Indian properties) before the FMP. See 43 CFR 3173.1. This information
collection activity helps the BLM obtain the production data that is
necessary to verify production from Federal or Indian leases covered by
CAAs.
Section 3173.15 requires the following information:
A completed Sundry Notice seeking approval of commingling
and allocation, and of off-lease measurement, if any of the proposed
FMPs are outside the boundaries of any of the leases, units, or CAs
whose production would be commingled;
A proposed allocation agreement and a proposed allocation
methodology with an example of how the methodology is applied
(including allocation of produced water) signed by each operator of
each of the leases, unit PAs, or CAs whose production would be included
in the CAA;
A list of all Federal or Indian lease, unit PA, or CA
numbers in the proposed CAA, specifying the type of production (i.e.,
oil, gas, or both) for which commingling is requested;
A topographic map or maps showing the boundaries of all
the leases, units, unit PAs, or communitized areas whose production is
proposed to be commingled; the location of all existing or planned
facilities and relative location of all wellheads and piping included
in the CAA, and FMPs existing or proposed to be installed to the extent
known or anticipated;
Documentation demonstrating that each of the leases, unit
PAs, or CAs proposed for inclusion in the CAA is producing in paying
quantities (or, in the case of Federal leases, is capable of production
in paying quantities) pending approval of the CAA; and
All gas analyses, including Btu content (if the CAA
request includes gas) and all oil gravities (if the CAA request
includes oil) for previous periods of production from the leases,
units, unit PAs, or CAs proposed for inclusion in the CAA, up to 6
years before the date of the application for approval of the CAA.
However, gas analysis and oil gravity data is not
[[Page 81416]]
needed if the CAA meets the requirements and standards of Sec.
3173.14(a) of the final rule.
If new surface disturbance is proposed on one or more of the
leases, units, or CAs, and the surface is managed by the BLM, the
application must include a proposed surface use plan of operations for
the proposed surface disturbance.
If new surface disturbance is proposed on BLM-managed land outside
any of the leases, units, or CAs whose production would be commingled,
the application must include a right-of-way grant application, under 43
CFR part 2880 if the FMP is on a pipeline, or under 43 CFR part 2800,
if the FMP is a meter or storage tank. Applications for right-of-way
(i.e., on SF-299) are authorized under OMB control number 0596-0082.
If new surface disturbance is proposed on Federal land managed by
an agency other than the BLM, the application must include written
approval from the appropriate surface-management agency.
If a new surface disturbance is proposed on Indian land outside the
lease, unit, or communitized area from which the production would be
commingled, a right-of-way grant application must be filed under 25 CFR
part 169, with the appropriate BIA office.
Request for Modification of a CAA (43 CFR 3173.18)
Section 3173.18 provides that a CAA must be modified when there is
modification to the allocation agreement, additional leases, unit PAs,
or CAs are proposed for inclusion in the CAA, or any of the leases,
unit PAs, or CAs within the CAA terminate or permanently cease
production. The following information would be required in a request to
modify a CAA:
A completed Sundry Notice describing the modification
requested;
A new allocation methodology, if appropriate, and an
example of how the methodology is applied; and
Certification by each operator that it agrees to the CAA
modification.
This information collection activity helps the BLM obtain the
production data that is necessary to verify production from Federal or
Indian leases covered by CAAs.
Response to Notice of Insufficient CAA (43 CFR 3173.16)
Upon receipt of an operator's request for assignment of an FMP
number to a facility associated with a CAA existing on the effective
date of the final rule, (1) The BLM may determine that the CAA meets
the requirements (at 43 CFR 3173.16) for grandfathering the CAA; or (2)
If grandfathering is not appropriate, the BLM will review the CAA for
consistency with the minimum standards and requirements for a CAA under
43 CFR 3173.14. The BLM will notify the operator in writing of any
inconsistencies or deficiencies. The operator must then correct any
inconsistencies or deficiencies that the AO identifies, provide
additional information, or request an extension of time, within 20
business days after receipt of the BLM's notice. When the BLM is
satisfied that the operator has corrected any inconsistencies or
deficiencies, the BLM will terminate the existing CAA and grant a new
CAA based on the operator's corrections. If the existing CAA does not
meet the applicable standards and the operator does not correct the
deficiencies, the BLM may terminate the existing CAA and deny the
request for an FMP number for the facility associated with the existing
CAA.
Request To Modify a CAA (43 CFR 3173.18)
A CAA must be modified when there is a modification to the
allocation agreement; additional leases, unit PAs, or CAs are proposed
for inclusion in the CAA; or any of the leases, unit PAs, or CAs within
the CAA terminate or permanently cease production.
To request a modification of a CAA, all operators must submit to
the BLM:
A completed Sundry Notice describing the modification
requested;
A new allocation methodology, including an allocation
methodology which includes allocation of produced water and an example
of how the methodology is applied, if appropriate; and
Certification by each operator in the CAA that it agrees
to the CAA modification.
A change in operator does not trigger the need to modify a CAA.
Request To Terminate a CAA (43 CFR 3173.20)
Section 3173.20 authorizes the BLM to terminate an approved CAA and
allows for the CAA to be terminated by the operator at their request.
The operator must submit a Sundry Notice to the BLM requesting the
termination in which the notice must identify the FMP(s) for the
lease(s), unit(s), or CA(s) previously subject to the CAA.
Request for Approval of Off-Lease Measurement--General (43 CFR
3173.23);
Request for Approval of Off-Lease Measurement--Amendment of an Existing
Approval (43 CFR 3173.23); and
Response to Notice of Insufficient Off-Lease Measurement Approval (43
CFR 3173.25)
These information collection activities assist the BLM in reducing
discrepancies between operator-allocated volumes, which operators
report to ONRR, and the volumes that the BLM calculates during follow-
up audits. In accordance with this final rule, the BLM will allow off-
lease measurement of production only from a single Federal or Indian
lease, unit PA, CA, or CAA, and only at an approved FMP.
Section 3173.23(a) through (j) requires the following information
in an application for approval of off-lease measurement:
A completed Sundry Notice;
Justification for off-lease measurement;
A topographic map of appropriate scale showing the
boundary of the lease(s), unit(s), or CA(s) from which the production
originates, the location of existing or planned facilities, the
relative location of all wellheads (including the API number for each
well) and piping included in the off-lease measurement proposal, and
existing FMPs or FMPs proposed to be installed to the extent known or
anticipated;
The surface ownership of all land on which equipment is,
or is proposed to be, located; and
A statement that indicates whether the proposal includes
all, or only a portion of, the production from the lease, unit, or CA
and if the proposal includes only a portion of the production, the
application would be required to identify the FMP(s) where the
remainder of the production from the lease, unit, or CA is measured or
is proposed to be measured.
If any of the proposed off-lease measurement facilities are located
on non-federally owned surface, the application must include a written
concurrence signed by the owner(s) of the surface and the owner(s) of
the measurement facilities, including each owner(s)' name, address, and
telephone number, granting the BLM unrestricted access to the off-lease
measurement facility and the surface on which it is located, for the
purpose of inspecting any production, measurement, water
[[Page 81417]]
handling, or transportation equipment located on the non-Federal
surface up to and including the FMP, and for otherwise verifying
production accountability. If the ownership of the non-Federal surface
or of the measurement facility changes, the operator must obtain and
provide to the AO the written concurrence required under this paragraph
from the new owner(s) within 30 days of the change in ownership.
If a proposed off-lease FMP with facilities on BLM land would
involve new surface disturbance and consists of a meter or storage
tank, or is on a pipeline, a right-of-way grant application must be
submitted. Applications for rights-of-way (SF-299) are authorized under
control number 0596-0082, which is administered by the U.S. Forest
Service on behalf of several Federal agencies. If new surface
disturbance if proposed for an FMP that includes facilities on Federal
land managed by an agency other than the BLM, written approval is
required from that agency. A right-of-way grant application must also
be submitted with the appropriate BIA office if any of the proposed
facilities are on Indian lands outside of the producing area.
If the operator proposes to use production from the lease, unit or
CA as fuel at the off-lease measurement facility without payment of
royalty, the application must include an application for approval of
off-lease royalty-free use under applicable rules. The BLM is
developing the applicable rules and will seek OMB clearance for the
information collection activities in those rules.
Section 3173.23(k) provides that to apply for an amendment of an
existing approval of off-lease measurement, the operator must submit a
completed Sundry Notice required under paragraph (a), and information
listed at paragraphs (b) through (j) of Sec. 3173.23 to the extent the
previously submitted information has changed. This information
collection activity assists the BLM in reducing discrepancies between
operator-allocated volumes, which operators report to ONRR, and the
volumes that the BLM calculates during follow-up audits.
Upon receipt of an operator's request for assignment of an FMP
number for a facility associated with an off-lease measurement approval
existing on the effective date of the final rule, the BLM will review
the existing approval for consistency with the requirements at 43 CFR
3173.22. The BLM will notify the operator of any inconsistencies or
deficiencies. The operator must correct any of the identified flaws,
provide additional information, or request an extension of time from
the AO, within 20 business days after receiving the notice. This
information collection activity assists the BLM in reducing
discrepancies between operator-allocated volumes, which operators
report to ONRR, and the volumes that the BLM calculates during follow-
up audits.
Request To Terminate an Off-Lease Measurement Approval (43 CFR 3173.27)
Section 3173.27 authorizes the BLM to terminate an off-lease
measurement approval and allows for the off-lease measurement approval
to also be terminated by the operator at their request. The operator
must submit a Sundry Notice to the BLM requesting the termination in
which the notice must identify the new FMP(s) for the lease(s),
unit(s), or CA(s) previously subject to the off-lease measurement
approval.
The following table itemizes the estimated hour and cost burdens
for the information collection activities.
Estimated Hour Burdens
----------------------------------------------------------------------------------------------------------------
Total hours
Type of response Number of Hours per (Column B x
responses response Column C)
A. B. C. D.
----------------------------------------------------------------------------------------------------------------
Variance Requests (43 CFR 3170.6) Annual........................ 100 8 800
Required Recordkeeping and Records Submission (43 CFR 3170.7) 4,300 5 21,500
Annual.........................................................
Water-Draining Operations--Data Collection (43 CFR 3173.6) 5,000 2 10,000
Annual.........................................................
Water-Draining Operations --Recordkeeping and Records Submission 60,000 0.25 15,000
(43 CFR 3173.6) Annual.........................................
Hot Oiling, Clean-Up, and Completion Operations--Data Collection 5,000 2 10,000
(43 CFR 3173.7) Annual.........................................
Hot Oiling, Clean-Up, and Completion Operations--Recordkeeping 15,000 0.25 3,750
and Records Submission (43 CFR 3173.6) Annual..................
Report of Theft or Mishandling of Production (43 CFR 3173.8) 5 10 50
Annual.........................................................
Required Recordkeeping for Inventory and Seal Records (43 CFR 5,000 2 10,000
3173.9) Annual.................................................
Site Facility Diagrams for Existing Facilities) (43 CFR 4,156 6 24,935
3173.11(d)(2)) One-time........................................
Site Facility Diagrams for Future Facilities (43 CFR 5,000 6 30,000
3173.11(d)(1)) Annual..........................................
Request for Approval of an FMP for Existing Measurement 166,232 2 332,464
Facilities (43 CFR 3173.12(e)) One-time........................
Request for Approval of an FMP for Future Measurement Facilities 1,000 2 2,000
(43 CFR 3173.12(d)) Annual.....................................
Modifications to an FMP (43 CFR 3173.13(b)(1)) Annual........... 1,000 2 2,000
Request for Approval of an Existing CAA (43 CFR 3173.15) One- 1,662 40 66,480
time...........................................................
Request for Approval of a Future CAA (43 CFR 3173.15) Annual.... 500 40 20,000
Response to Notice of Insufficient CAA (43 CFR 3173.16) Annual.. 150 40 6,000
Request to Modify a CAA (43 CFR 3173.18) Annual................. 500 40 20,000
Request for Approval of Off-Lease Measurement--General (43 CFR 100 10 1,000
3173.23) Annual................................................
Request for Approval of Off-Lease Measurement--Amendment of an 166 10 1,662
Existing Approval (43 CFR 3173.23) One-time....................
Response to Notice of Insufficient Off-Lease Measurement 15 40 600
Approval (43 CFR 3173.25) Annual...............................
-----------------------------------------------
Totals...................................................... 274,886 .............. 578,240
----------------------------------------------------------------------------------------------------------------
[[Page 81418]]
National Environmental Policy Act
The BLM prepared an environmental assessment (EA), a Finding of No
Significant Impact (FONSI), and Decision Record (DR) that concludes
that the final rule will not constitute a major Federal action
significantly affecting the quality of the human environment under
Section 102(2)(C) of the National Environmental Policy Act (NEPA), 42
U.S.C. 4332(2)(C). Therefore, a detailed statement under NEPA is not
required. A copy of the EA, FONSI, and DR are available for review and
on file in the BLM Administrative Record at the address specified in
the ADDRESSES section.
As explained in the EA, FONSI, and DR, the final rule will not have
a significant effect on the human environment because, for the most
part, its requirements involve changes that are of an administrative,
technical, or procedural nature that apply to the BLM's and the
lessee's or operator's management processes. For example, operators are
now required to maintain records generated for Federal leases for at
least 7 years, consistent with statutory requirements. Similarly, the
final rule requires more detailed information on site facility diagrams
such as information about the equipment for which an operator claims
royalty-free use. The submission of this additional information will
not result in any on-the-ground impacts. In contrast with these
provisions, compliance with some of the rule's other requirements may
result in additional surface-disturbing activities (e.g., additional
surface disturbance might be required if an operator with an existing
off lease measurement authorization has to move those measurement
facilities back on lease because they did not comply with the
requirements of this final rule.) Such surface-disturbing activities
will be subject to their own project-specific NEPA analyses, as
appropriate, and will be conducted in accordance with existing surface
operating standards and guidelines for oil and gas exploration and
development, including appropriate Best Management Practices (BMP).
A draft of the EA was shared with the public during the public
comment period on the proposed rule. During that process the BLM
received a handful of comments on the EA. Some commenters questioned
the BLM's level of NEPA analysis, specifically whether the BLM had met
the ``hard look'' test of describing the environmental consequences of
the proposed action, and the BLM's ability to reach a FONSI based on
the level of analysis prepared. One commenter requested a complete NEPA
revision with formal scoping on the EA and a meaningful socioeconomic
analysis. Many commenters questioned the use of three separate EAs to
disclose impacts of three separate orders. Those commenters asserted
that CEQ regulations require connected actions to be evaluated in a
single document and suggested a single EIS to address all three rules.
CEQ's NEPA regulations at 40 CFR 1508.18 identify new or revised
agency rules and regulations as an example of a Federal action.
Drafting new agency regulations of a technical or administrative nature
is a Federal action that is categorically excluded from NEPA review
pursuant to 43 CFR 46.210(i). Instead of relying on the categorical
exclusion, the BLM chose to complete a more robust level of NEPA
documentation in the form of an EA for each of the proposed rules to
replace Orders 3, 4, and 5. By preparing an EA for each of the proposed
regulations, the BLM was able to disclose the potential environmental
effects of the Federal agency decision on each of the regulations. This
analysis addressed the impact of each rule individually, as well as the
impact of all three rules cumulatively. With respect to socio-economic
impacts, the BLM completed an Economic and Threshold Analyses for each
of the rules. These analyses were not referenced in the Draft EAs for
the rules, but have been addressed in the EAs for the final rules.
Other commenters stated that the BLM understated the potential
surface impacts associated with the new rules and did not: (i)
Adequately address potential surface impacts to private land; (ii)
Address a reasonable range of alternatives; and (iii) Adequately
describe the affected environment. As explained in the EA, the BLM
anticipates that in the majority of cases, operators will use existing
surface disturbances such as existing well pad locations in connection
with activities undertaken in compliance with the final rule, which
will minimize new surface construction and surface impacts.
Similarly, the codification of BLM regulations does not hinder or
prevent development of private minerals. The likelihood of impacts to
private surface is low. It is unclear whether private lands would be
affected at all by the denial of off-lease measurement agreements and
the resultant re-location of measurement facilities on to a lease, CA
or unit PA. In the rare instances when new pipelines or other
facilities were found to be necessary on private surface, BLM
authorization for activities on split estate would include site-
specific NEPA documentation, with appropriate project-level mitigation
and BMPs. In short, the impact of these provisions on private lands in
terms of surface disturbance is likely to be minimal, and any attempt
to estimate these impacts would be speculative.
The BLM's obligation under NEPA is to analyze alternatives that
would meet the purpose and need for the proposed action and allow for a
reasoned choice to be made. As described in the EA, a number of
alternatives were considered, but eliminated from detailed study
because they did not meet the purpose and need. Similarly, the
discussion of the affected environment should only contain data and
analysis commensurate in detail with the importance of the impacts,
which the BLM anticipates to be minimal. The EA, FONSI, and DR were
updated to address these comments, but did not change the BLM's overall
analysis of the potential environmental impacts of the rule.
Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This final rule will not have a substantial direct effect on the
nation's energy supply, distribution or use, including a shortfall in
supply or price increase. The final rule strengthens the BLM's
production accountability requirements for operators of Federal and
Indian oil and gas leases. These changes increase recordkeeping
requirements, place additional restrictions on CAAs and on off-lease
measurement, and provide for significant new immediate assessments for
violations of the regulations. All of these changes in the final rule
are administrative in nature and will have a one-time average
transition cost of about $8,400 per regulated entity and an ongoing
annual average cost of about $3,200 per entity per year. Entities with
the greatest activity (e.g., numerous FMPs) will incur higher costs,
but they will still be relatively minor. As a result, the BLM does not
expect that the final rule will result in a net change in the quantity
of oil and gas that is produced from oil and gas leases on Federal and
Indian lands.
Information Quality Act
In developing this rule, the BLM did not conduct or use a study,
experiment, or survey requiring peer review under the Information
Quality Act (Pub. L. 106-554, Appendix C Title IV, 515, 114 Stat.
2763A-153).
Authors
The principal authors of this final rule are Michael Wade, Senior
Oil and Gas
[[Page 81419]]
Compliance Specialist, BLM Washington Office; Adrienne Brumley,
Petroleum Engineer, BLM New Mexico State Office; Conan Donnelly,
Petroleum Engineering Technician, BLM Miles City Field office; Kahindo
Kamau, Petroleum Engineer, BLM Great Falls Field Office; Steve
McCracken, Petroleum Engineering Technician, BLM Great Falls Field
Office; Chris Carey, ONRR Denver Office; Luke Lundmark, ONRR Denver
Office; and Vicky Stafford, ONRR Denver Office. The team was assisted
by Rich Estabrook, BLM Washington Office; Faith Bremner, Jean Sonneman
and Ian Senio, Office of Regulatory Affairs, BLM Washington Office;
Michael Ford, Economist, BLM Washington Office; Barbara Sterling,
Natural Resource Specialist, BLM Colorado State Office; Bryce Barlan,
Senior Policy Analyst, BLM Washington Office; and Dylan Fuge, Counselor
to the Director, BLM Washington Office; Christopher Rhymes, Attorney
Advisor, Office of the Solicitor, Department of the Interior; and
Leslie Peterson and Geoffrey Heath (both now retired).
List of Subjects
43 CFR Part 3160
Administrative practice and procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and gas exploration, Penalties,
Public lands--mineral resources, Reporting and recordkeeping
requirements.
43 CFR Part 3170
Administrative practice and procedure, Immediate assessments,
Incorporation by reference, Indians-lands, Mineral royalties, Oil and
gas measurement, Public lands--mineral resources.
Dated: October 6, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.
For the reasons set out in the preamble, the Bureau of Land
Management amends 43 CFR chapter II as follows:
PART 3160--ONSHORE OIL AND GAS OPERATIONS
0
1. Revise the authority citation for part 3160 to read as follows:
Authority: 25 U.S.C. 396, 396d and 2107; 30 U.S.C. 189, 306,
359, and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
Sec. 3160.0-3 [Amended]
0
2. Amend Sec. 3160.0-3 by removing the words ``the Federal Oil and Gas
Royalty Management Act of 1982 (30 U.S.C.1701)'' and adding in their
place the words ``the Federal Oil and Gas Royalty Management Act of
1982, as amended by the Federal Oil and Gas Royalty Simplification Act
of 1996 (30 U.S.C. 1701 et seq.)''.
0
3. Revise Sec. 3161.1 to read as follows:
Sec. 3161.1 Jurisdiction.
(a) The regulations in this part apply to all operations conducted
on:
(1) All Federal and Indian (except those of the Osage Tribe)
onshore oil and gas leases;
(2) All onshore facility measurement points where Federal or Indian
(except those of the Osage Tribe) oil or gas is measured;
(3) Indian Mineral Development Act agreements for oil and gas,
unless specifically excluded in the agreement; and
(4) Leases and other business agreements for the development of
tribal energy resources under a Tribal Energy Resource Agreement
entered into with the Secretary, unless specifically excluded in the
lease, other business agreement, or Tribal Energy Resource Agreement.
(b) The regulations in this part and 43 CFR part 3170, including
subparts 3173, 3174, and 3175, relating to site security, measurement
of oil and gas, reporting of production and operations, and assessments
or penalties for non-compliance with such requirements, are applicable
to all wells and facilities on State or privately owned lands committed
to a unit or communitization agreement, which include Federal or Indian
lease interests, notwithstanding any provision of a unit or
communitization agreement to the contrary.
0
4. Amend Sec. 3162.3-2 by adding paragraph (d) to read as follows:
Sec. 3162.3-2 Subsequent well operations.
* * * * *
(d) For details on how to apply for approval of a facility
measurement point; approval for surface or subsurface commingling from
different leases, unit participating areas and communitized areas; or
approval for off-lease measurement, see 43 CFR 3173.12, 3173.15, and
3173.23, respectively.
0
5. Amend Sec. 3162.4-1 by revising paragraphs (a) and (d) and adding
paragraph (e) to read as follows:
Sec. 3162.4-1 Well records and reports.
(a) The operator must keep accurate and complete records with
respect to:
(1) All lease operations, including, but not limited to, drilling,
producing, redrilling, repairing, plugging back, and abandonment
operations;
(2) Production facilities and equipment (including schematic
diagrams as required by applicable orders and notices); and
(3) Determining and verifying the quantity, quality, and
disposition of production from or allocable to Federal or Indian leases
(including source records).
* * * * *
(d) All records and reports required by this section must be
maintained for the following time periods:
(1) For Federal leases and units or communitized areas that include
Federal leases, but do not include Indian leases:
(i) Seven years after the records are generated; unless,
(ii) A judicial proceeding or demand involving such records is
timely commenced, in which case the record holder must maintain such
records until the final nonappealable decision in such judicial
proceeding is made, or with respect to that demand is rendered, unless
the Secretary or the applicable delegated State authorizes in writing
an earlier release of the requirement to maintain such records.
(2) For Indian leases, and units or communitized areas that include
Indian leases, but do not include Federal leases:
(i) Six years after the records are generated; unless,
(ii) The Secretary or his/her designee notifies the record holder
that the Department has initiated or is participating in an audit or
investigation involving such records, in which case the record holder
must maintain such records until the Secretary or his/her designee
releases the record holder from the obligation to maintain the records.
(3) For units and communitized areas that include both Federal and
Indian leases, 6 years after the records are generated, unless the
Secretary or his/her designee has notified the record holder within
those 6 years that an audit or investigation involving such records has
been initiated, then:
(i) If a judicial proceeding or demand is commenced within 7 years
after the records are generated, the record holder must retain all
records regarding production from the lease, unit or communitization
agreement until the final nonappealable decision in such judicial
proceeding is made, or with respect to that demand is rendered, unless
the Secretary or his/her designee authorizes in writing a release of
the requirement to maintain such records before a final nonappealable
decision is made or rendered;
(ii) If a judicial proceeding or demand is not commenced within 7
years after
[[Page 81420]]
the records are generated, the record holder must retain all records
regarding production from the unit or communitized area until the
Secretary or his/her designee releases the record holder from the
obligation to maintain the records.
(e) Record holders include lessees, operators, purchasers,
transporters, and any other person directly involved in producing,
transporting, purchasing, or selling, including measuring, oil or gas
through the point of royalty measurement or the point of first sale,
whichever is later. Record holders must maintain records generated
during or for the period for which the lessee or operator has an
interest in or conducted operations on the lease, or in which a person
is involved in transporting, purchasing, or selling production from the
lease, for the period of time required in paragraph (d) of this
section.
Sec. 3162.4-3 [Removed]
0
6. Remove Sec. 3162.4-3.
0
7. Amend Sec. 3162.6 as follows:
0
a. In paragraph (a), remove the word ``indentification'' and add in its
place ``identification''; and
0
b. Revise paragraphs (b) and (c), redesignate paragraph (d) as
paragraph (e), and add a new paragraph (d).
The revisions and addition read as follows:
Sec. 3162.6 Well and facility identification.
* * * * *
(b) For wells located on Federal and Indian lands, the operator
must properly identify, by a sign in a conspicuous place, each well,
other than those permanently abandoned. The well sign must include the
well number, the name of the operator, the lease serial number, and the
surveyed location (the quarter-quarter section, section, township and
range or other authorized survey designation acceptable to the
authorized officer, such as metes and bounds or longitude and
latitude). When specifically requested by the authorized officer, the
sign must include the unit or communitization agreement name or number.
The authorized officer may also require the sign to include the name of
the Indian allottee lessor(s) preceding the lease serial number.
(c) All facilities at which oil or gas produced from a Federal or
Indian lease is stored, measured, or processed must be clearly
identified with a sign that contains the name of the operator, the
lease serial number or communitization or unit agreement identification
number, as appropriate, and the surveyed location (the quarter-quarter
section, section, township and range or other authorized survey
designation acceptable to the authorized officer, such as metes and
bounds or longitude and latitude). On Indian leases, the sign also must
include the name of the appropriate tribe and whether the lease is
tribal or allotted. For situations of one tank battery servicing one
well in the same location, the requirements of this paragraph and
paragraph (b) of this section may be met by one sign as long as it
includes the information required by both paragraphs. In addition, each
storage tank must be clearly identified by a unique number. With regard
to the quarter-quarter designation and the unique tank number, any such
designation established by State law or regulation satisfies this
requirement.
(d) All signs must be maintained in legible condition and must be
clearly apparent to any person at or approaching the storage,
measurement, or transportation point.
* * * * *
Sec. 3162.7-1 [Amended]
0
8. Amend Sec. 3162.7-1 by removing paragraph (f).
Sec. 3162.7-5 [Removed]
0
9. Remove Sec. 3162.7-5.
0
10. Amend Sec. 3163.2 by:
0
a. Revising paragraphs (a), (b), (d), (e) introductory text, and (f)
introductory text;
0
b. Removing paragraph (g);
0
c. Redesignating paragraphs (h) and (i) as paragraphs (g) and (h);
0
d. Revising newly redesignated paragraphs (g) and (h); and
0
e. Removing paragraphs (j) and (k).
The revisions read as follows:
Sec. 3163.2 Civil penalties.
(a)(1) Whenever any person fails or refuses to comply with any
applicable requirements of the Federal Oil and Gas Royalty Management
Act, any mineral leasing law, any regulation thereunder, or the terms
of any lease or permit issued thereunder, the authorized officer will
notify the person in writing of the violation, unless the violation was
discovered and reported to the authorized officer by the liable person
or the notice was previously issued under Sec. 3163.1.
(2) Whenever a purchaser or transporter who is not an operating
rights owner or operator fails or refuses to comply with 30 U.S.C. 1713
or applicable rules or regulations regarding records relevant to
determining the quality, quantity, and disposition of oil or gas
produced from or allocable to a Federal or Indian oil and gas lease,
the authorized officer will notify the purchaser or transporter, as
appropriate, in writing of the violation.
(b)(1) If the violation specified in paragraph (a) of this section
is not corrected within 20 days of such notice or report, or such
longer time as the authorized officer may agree to in writing, the
person will be liable for a civil penalty of up to $1,031 per violation
for each day such violation continues, dating from the date of such
notice or report. Any amount imposed and paid as assessments under
Sec. 3163.1(a)(1) will be deducted from penalties under this section.
(2) If the violation specified in paragraph (a) of this section is
not corrected within 40 days of such notice or report, or a longer
period as the authorized officer may agree to in writing, the person
will be liable for a civil penalty of up to $10,314 per violation for
each day the violation continues, dating from the date of such notice
or report. Any amount imposed and paid as assessments under Sec.
3163.1(a)(1) will be deducted from penalties under this section.
* * * * *
(d) Whenever a transporter fails to permit inspection for proper
documentation by any authorized representative, as provided in Sec.
3162.7-1(c) of this chapter, the transporter is liable for a civil
penalty of up to $1,031 per day for the violation, dating from the date
of notice of the failure to permit inspection and continuing until the
proper documentation is provided. If the violation continues beyond 20
days, the authorized officer will revoke the transporter's authority to
remove crude oil produced from, or allocated to, any Federal or Indian
lease under the authority of that authorized officer. This revocation
of the transporter's authority will continue until the transporter
provides proper documentation and pays any related penalty.
(e) Any person is liable for a civil penalty of up to $20,628 per
violation for each day such violation continues, if the person:
* * * * *
(f) Any person is liable for a civil penalty of up to $51,570 per
violation for each day such violation continues, if the person:
* * * * *
(g) On a case-by-case basis, the Secretary may compromise or reduce
civil penalties under this section. In compromising or reducing the
amount of a civil penalty, the Secretary will state on the record the
reasons for such determination.
(h) Civil penalties provided by this section are supplemental to,
and not in derogation of, any other penalties or assessments for
noncompliance in any
[[Page 81421]]
other provision of law, except as provided in paragraphs (a) and (b) of
this section.
Sec. 3164.1 [Amended]
0
11. Amend Sec. 3164.1, in paragraph (b), by removing the third entry
in the table (the reference to Order No. 3, Site Security).
0
12. Amend Sec. 3165.3 by revising paragraphs (a) and (d) to read as
follows:
Sec. 3165.3 Notice, State Director review and hearing on the record.
(a) Notice. (1) Whenever any person fails to comply with any
provisions of the lease, the regulations in this part, applicable
orders or notices, or any other appropriate order of the authorized
officer, the authorized officer will issue a written notice or order to
the appropriate party and the lessee(s) to remedy any defaults or
violations.
(2) Whenever any purchaser or transporter, who is not an operating
rights owner or operator, fails or refuses to comply with 30 U.S.C.
1713 or applicable rules or regulations regarding records relevant to
determining the quality, quantity, and disposition of oil or gas
produced from or allocable to a Federal or Indian oil and gas lease,
applicable orders or notices, or any other appropriate orders of the
authorized officer, the authorized officer will give written notice or
order to the purchaser or transporter to remedy any violations.
(3) Written orders or a notice of violation, assessment, or
proposed penalty will be issued and served by personal service by the
authorized officer, or by certified mail, return receipt requested.
Service will be deemed to occur when the document is received or 7
business days after the date it is mailed, whichever is earlier.
(4) Any person may designate a representative to receive any notice
of violation, order, assessment, or proposed penalty on that person's
behalf.
(5) In the case of a major violation, the authorized officer will
make a good faith effort to contact such designated representative by
telephone, to be followed by a written notice or order. Receipt of a
notice or order will be deemed to occur at the time of such verbal
communication, and the time of notice and the name of the receiving
party will be documented in the file. If the good faith effort to
contact the designated representative is unsuccessful, notice of the
major violation or order may be given to any person conducting or
supervising operations subject to the regulations in this part.
(6) In the case of a minor violation, the authorized officer will
only provide a written notice or order to the designated
representative.
(7) A copy of all orders, notices, or instructions served on any
contractor or field employee or designated representative will also be
mailed to the operator. Any notice involving a civil penalty against an
operator will be mailed to the operator, with a copy to the operating
rights owner.
* * * * *
(d) Action on request for State Director review. The State Director
will issue a final decision within 10 business days after the receipt
of a complete request for administrative review or, where oral
presentation has been made, within 10 business days after the oral
presentation. The State Director's decision represents the final Bureau
decision from which further review may be obtained as provided in
paragraph (c) of this section for proposed penalties, and in Sec.
3165.4 for all other decisions.
* * * * *
0
13. Add part 3170 to read as follows:
PART 3170--ONSHORE OIL AND GAS PRODUCTION
Subpart 3170--Onshore Oil and Gas Production: General
Sec.
3170.1 Authority.
3170.2 Scope.
3170.3 Definitions and acronyms.
3170.4 Prohibitions against by-pass and tampering.
3170.5 [Reserved]
3170.6 Variances.
3170.7 Required recordkeeping, records retention, and records
submission.
3170.8 Appeal procedures.
3170.9 Enforcement.
Subpart 3171--[Reserved]
Subpart 3172--[Reserved]
Subpart 3173--Requirements for Site Security and Production Handling
3173.1 Definitions and acronyms.
3173.2 Storage and sales facilities--seals.
3173.3 Oil measurement system components--seals.
3173.4 Federal seals.
3173.5 Removing production from tanks for sale and transportation by
truck.
3173.6 Water-draining operations.
3173.7 Hot oiling, clean-up, and completion operations.
3173.8 Report of theft or mishandling of production.
3173.9 Required recordkeeping for inventory and seal records.
3173.10 Form 3160-5, Sundry Notices and Reports on Wells.
3173.11 Site facility diagram.
3173.12 Applying for a facility measurement point.
3173.13 Requirements for approved facility measurement points.
3173.14 Conditions for commingling and allocation approval (surface
and downhole).
3173.15 Applying for a commingling and allocation approval.
3173.16 Existing commingling and allocation approvals.
3173.17 Relationship of a commingling and allocation approval to
royalty-free use of production.
3173.18 Modification of a commingling and allocation approval.
3173.19 Effective date of a commingling and allocation approval.
3173.20 Terminating a commingling and allocation approval.
3173.21 Combining production downhole in certain circumstances.
3173.22 Requirements for off-lease measurement.
3173.23 Applying for off-lease measurement.
3173.24 Effective date of an off-lease measurement approval.
3173.25 Existing approved off-lease measurement.
3173.26 Relationship of off-lease measurement approval to royalty-
free use of production.
3173.27 Termination of off-lease measurement approval.
3173.28 Instances not constituting off-lease measurement, for which
no approval is required.
3173.29 Immediate assessments for certain violations.
Appendix A to Subpart 3173--Examples of Site Facility Diagrams
Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359,
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
Subpart 3170--Onshore Oil and Gas Production: General
Sec. 3170.1 Authority.
The authorities for promulgating the regulations in this part are
the Mineral Leasing Act, 30 U.S.C. 181 et seq.; the Mineral Leasing Act
for Acquired Lands, 30 U.S.C. 351 et seq.; the Federal Oil and Gas
Royalty Management Act, 30 U.S.C. 1701 et seq.; the Indian Mineral
Leasing Act, 25 U.S.C. 396a et seq.; the Act of March 3, 1909, 25
U.S.C. 396; the Indian Mineral Development Act, 25 U.S.C. 2101 et seq.;
and the Federal Land Policy and Management Act, 43 U.S.C. 1701 et seq.
Each of these statutes gives the Secretary the authority to promulgate
necessary and appropriate rules and regulations governing Federal and
Indian (except Osage Tribe) oil and gas leases. See 30 U.S.C. 189; 30
U.S.C. 359; 25 U.S.C. 396d; 25 U.S.C. 396; 25 U.S.C. 2107; and 43
U.S.C. 1740. Under Secretarial Order Number 3087, dated December 3,
1982, as amended on February 7, 1983 (48 FR 8983), and the Departmental
Manual (235 DM 1.1), the Secretary has delegated regulatory authority
over onshore oil and gas development on
[[Page 81422]]
Federal and Indian (except Osage Tribe) lands to the BLM. For Indian
leases, the delegation of authority to the BLM is reflected in 25 CFR
parts 211, 212, 213, 225, and 227. In addition, as authorized by 43
U.S.C. 1731(a), the Secretary has delegated to the BLM regulatory
responsibility for oil and gas operations on Indian lands. 235 DM
1.1.K.
Sec. 3170.2 Scope.
The regulations in this part apply to:
(a) All Federal onshore and Indian oil and gas leases (other than
those of the Osage Tribe);
(b) Indian Mineral Development Act (IMDA) agreements for oil and
gas, unless specifically excluded in the agreement or unless the
relevant provisions of the rule are inconsistent with the agreement;
(c) Leases and other business agreements for the development of
tribal energy resources under a Tribal Energy Resource Agreement
entered into with the Secretary, unless specifically excluded in the
lease, other business agreement, or Tribal Energy Resource Agreement;
(d) State or private tracts committed to a federally approved unit
or communitization agreement (CA) as defined by or established under 43
CFR subpart 3105 or 43 CFR part 3180; and
(e) All onshore facility measurement points where oil or gas
produced from the leases or agreements identified earlier in this
section is measured.
Sec. 3170.3 Definitions and acronyms.
(a) As used in this part, the term:
Allocated or allocation means a method or process by which
production is measured at a central point and apportioned to the
individual lease, or unit Participating Area (PA), or CA from which the
production originated.
API (followed by a number) means the American Petroleum Institute
Manual of Petroleum Measurement Standards, with the number referring to
the Chapter and Section in that manual.
Audit trail means all source records necessary to verify and
recalculate the volume and quality of oil or gas production measured at
a facility measurement point (FMP) and reported to the Office of
Natural Resources Revenue (ONRR).
Authorized officer (AO) has the same meaning as defined in 43 CFR
3000.0-5.
Averaging period means the previous 12 months or the life of the
meter, whichever is shorter. For FMPs that measure production from a
newly drilled well, the averaging period excludes production from that
well that occurred in or before the first full month of production.
(For example, if an oil FMP and a gas FMP were installed to measure
only the production from a new well that first produced on April 10,
the averaging period for this FMP would not include the production that
occurred in April (partial month) and May (full month) of that year.)
Bias means a shift in the mean value of a set of measurements away
from the true value of what is being measured.
By-pass means any piping or other arrangement around or avoiding a
meter or other measuring device or method (or component thereof) at an
FMP that allows oil or gas to flow without measurement. Equipment that
permits the changing of the orifice plate of a gas meter without
bleeding the pressure off the gas meter run (e.g., senior fitting) is
not considered to be a by-pass.
Commingling, for production accounting and reporting purposes,
means combining, before the point of royalty measurement, production
from more than one lease, unit PA, or CA, or production from one or
more leases, unit PAs, or CAs with production from State, local
governmental, or private properties that are outside the boundaries of
those leases, unit PAs, or CAs. Combining production from multiple
wells within a single lease, unit PA, or CA, or combining production
downhole from different geologic formations within the same lease, unit
PA, or CA, is not considered commingling for production accounting
purposes.
Communitized area means the area committed to a BLM approved
communitization agreement.
Communitization agreement (CA) means an agreement to combine a
lease or a portion of a lease that cannot otherwise be independently
developed and operated in conformity with an established well spacing
or well development program, with other tracts for purposes of
cooperative development and operations.
Condition of Approval (COA) means a site-specific requirement
included in the approval of an application that may limit or modify the
specific actions covered by the application. Conditions of approval may
minimize, mitigate, or prevent impacts to public lands or resources.
Days means consecutive calendar days, unless otherwise indicated.
Facility means:
(i) A site and associated equipment used to process, treat, store,
or measure production from or allocated to a Federal or Indian lease,
unit PA, or CA that is located upstream of or at (and including) the
approved point of royalty measurement; and
(ii) A site and associated equipment used to store, measure, or
dispose of produced water that is located on a lease, unit, or
communitized area.
Facility measurement point (FMP) means a BLM-approved point where
oil or gas produced from a Federal or Indian lease, unit PA, or CA is
measured and the measurement affects the calculation of the volume or
quality of production on which royalty is owed. FMP includes, but is
not limited to, the approved point of royalty measurement and
measurement points relevant to determining the allocation of production
to Federal or Indian leases, unit PAs, or CAs. However, allocation
facilities that are part of a commingling and allocation approval under
Sec. 3173.15 or that are part of a commingling and allocation approval
approved after July 9, 2013, are not FMPs. An FMP also includes a meter
or measurement facility used in the determination of the volume or
quality of royalty-bearing oil or gas produced before BLM approval of
an FMP under Sec. 3173.12. An FMP must be located on the lease, unit,
or communitized area unless the BLM approves measurement off the lease,
unit, or CA. The BLM will not approve a gas processing plant tailgate
meter located off the lease, unit, or CA, as an FMP.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or non-hydrocarbon, that has neither independent shape nor
volume, but tends to expand indefinitely and exists in a gaseous state
under metered temperature and pressure conditions.
Incident of Noncompliance (INC) means documentation that the BLM
issues that identifies violations and notifies the recipient of the
notice of required corrective actions.
Lease has the same meaning as defined in 43 CFR 3160.0-5.
Lessee has the same meaning as defined in 43 CFR 3160.0-5.
NIST traceable means an unbroken and documented chain of
comparisons relating measurements from field or laboratory instruments
to a known standard maintained by the National Institute of Standards
and Technology (NIST).
Notice to lessees and operators (NTL) has the same meaning as
defined in 43 CFR 3160.0-5.
Off-lease measurement means measurement at an FMP that is not
located on the lease, unit, or communitized area from which the
production came.
Oil means a mixture of hydrocarbons that exists in the liquid phase
at the temperature and pressure at which it is
[[Page 81423]]
measured. Condensate is considered to be oil for purposes of this part.
Gas liquids extracted from a gas stream upstream of the approved point
of royalty measurement are considered to be oil for purposes of this
part.
(i) Clean oil or Pipeline oil means oil that is of such quality
that it is acceptable to normal purchasers.
(ii) Slop oil means oil that is of such quality that it is not
acceptable to normal purchasers and is usually sold to oil reclaimers.
Oil that can be made acceptable to normal purchasers through special
treatment that can be economically provided at existing or modified
facilities or using portable equipment at or upstream of the FMP is not
slop oil.
(iii) Waste oil means oil that has been determined by the AO or
authorized representative to be of such quality that it cannot be
treated economically and put in a marketable condition with existing or
modified lease facilities or portable equipment, cannot be sold to
reclaimers, and has been determined by the AO to have no economic
value.
Operator has the same meaning as defined in 43 CFR 3160.0-5.
Participating area (PA) has the same meaning as defined in 43 CFR
3180.0-5.
Point of royalty measurement means a BLM-approved FMP at which the
volume and quality of oil or gas which is subject to royalty is
measured. The point of royalty measurement is to be distinguished from
meters that determine only the allocation of production to particular
leases, unit PAs, CAs, or non-Federal and non-Indian properties. The
point of royalty measurement is also known as the point of royalty
settlement.
Production means oil or gas removed from a well bore and any
products derived therefrom.
Production Measurement Team (PMT) means a panel of members from the
BLM (which may include BLM-contracted experts) that reviews changes in
industry measurement technology, methods, and standards to determine
whether regulations should be updated, and provides guidance on
measurement technologies and methods not addressed in current
regulation. The purpose of the PMT is to act as a central advisory body
to ensure that oil and gas produced from Federal and Indian leases is
accurately measured and properly reported.
Purchaser means any person or entity who legally takes ownership of
oil or gas in exchange for financial or other consideration.
Source record means any unedited and original record, document, or
data that is used to determine volume and quality of production,
regardless of format or how it was created or stored (e.g., paper or
electronic). It includes, but is not limited to, raw and unprocessed
data (e.g., instantaneous and continuous information used by flow
computers to calculate volumes); gas charts; measurement tickets;
calibration, verification, prover, and configuration reports; pumper
and gauger field logs; volume statements; event logs; seal records; and
gas analyses.
Statistically significant describes a difference between two data
sets that exceeds the threshold of significance.
Tampering means any deliberate adjustment or alteration to a meter
or measurement device, appropriate valve, or measurement process that
could introduce bias into the measurement or affect the BLM's ability
to independently verify volumes or qualities reported.
Threshold of significance means the maximum difference between two
data sets (a and b) that can be attributed to uncertainty effects. The
threshold of significance is determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.000
Where:
Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of data set a,
in percent
Ub = Uncertainty (95 percent confidence) of data set b,
in percent
Total observed volume (TOV) means the total measured volume of all
oil, sludges, sediment and water, and free water at the measured or
observed temperature and pressure.
Transporter means any person or entity who legally moves or
transports oil or gas from an FMP.
Uncertainty means the statistical range of error that can be
expected between a measured value and the true value of what is being
measured. Uncertainty is determined at a 95 percent confidence level
for the purposes of this part.
Unit means the land within a unit area as defined in 43 CFR 3180.0-
5.
Unit PA means the unit participating area, if one is in effect, the
exploratory unit if there is no associated participating area, or an
enhanced recovery unit.
Variance means an approved alternative to a provision or standard
of a regulation, Onshore Oil and Gas Order, or NTL.
(b) As used in this part, the following additional acronyms apply:
API means American Petroleum Institute.
BLM means the Bureau of Land Management.
Btu means British thermal unit.
CMS means Coriolis Measurement System.
LACT means lease automatic custody transfer.
OGOR means Oil and Gas Operations Report (Form ONRR-4054 or any
successor report).
ONRR means the Office of Natural Resources Revenue, U.S. Department
of the Interior, and includes any successor agency.
S&W means sediment and water.
WIS means Well Information System or any successor electronic
filing system.
Sec. 3170.4 Prohibitions against by-pass and tampering.
(a) All by-passes are prohibited.
(b) Tampering with any measurement device, component of a
measurement device, or measurement process is prohibited.
(c) Any by-pass or tampering with a measurement device, component
of a measurement device, or measurement process may, together with any
other remedies provided by law, result in an assessment of civil
penalties for knowingly or willfully:
(1) Taking, removing, transporting, using, or diverting oil or gas
from a lease site without valid legal authority under 30 U.S.C.
1719(d)(2) and 43 CFR 3163.2(f)(2); or
(2) Preparing, maintaining, or submitting false, inaccurate, or
misleading reports, records, or information under 30 U.S.C. 1719(d)(1)
and 43 CFR 3163.2(f)(1).
Sec. 3170.5 [Reserved]
Sec. 3170.6 Variances.
(a) Any party subject to a requirement of a regulation in this part
may request a variance from that requirement.
(1) A request for a variance must include the following:
(i) Identification of the specific requirement from which the
variance is requested;
(ii) Identification of the length of time for which the variance is
requested, if applicable;
(iii) An explanation of the need for the variance;
(iv) A detailed description of the proposed alternative means of
compliance;
(v) A showing that the proposed alternative means of compliance
will produce a result that meets or exceeds the objectives of the
applicable requirement for which the variance is requested; and
(vi) The FMP number(s) for which the variance is requested, if
applicable.
[[Page 81424]]
(2) A request for a variance must be submitted as a separate
document from any plans or applications. A request for a variance that
is submitted as part of a master development plan, application for
permit to drill, right-of-way application, or application for approval
of other types of operations, rather than submitted separately, will
not be considered. Approval of a plan or application that contains a
request for a variance does not constitute approval of the variance. A
separate request for a variance may be submitted simultaneously with a
plan or application. For plans or applications that are contingent upon
the approval of the variance request, the BLM encourages the
simultaneous submission of the variance request and the plan or
application.
(3) The party requesting the variance must file the request and any
supporting documents using WIS. If electronic filing is not possible or
practical, the operator may submit a request for variance on the Form
3160-5, Sundry Notices and Reports on Wells (Sundry Notice) to the BLM
Field Office having jurisdiction over the lands described in the
application.
(4) The AO, after considering all relevant factors, may approve the
variance, or approve it with COAs, only if the AO determines that:
(i) The proposed alternative means of compliance meets or exceeds
the objectives of the applicable requirement(s) of the regulation;
(ii) Approving the variance will not adversely affect royalty
income and production accountability; and
(iii) Issuing the variance is consistent with maximum ultimate
economic recovery, as defined in 43 CFR 3160.0-5.
(5) The decision whether to grant or deny the variance request is
entirely within the BLM's discretion.
(6) A variance from the requirements of a regulation in this part
does not constitute a variance from provisions of other regulations,
including Onshore Oil and Gas Orders.
(b) The BLM reserves the right to rescind a variance or modify any
COA of a variance due to changes in Federal law, technology,
regulation, BLM policy, field operations, noncompliance, or other
reasons. The BLM will provide a written justification if it rescinds a
variance or modifies a COA.
Sec. 3170.7 Required recordkeeping, records retention, and records
submission.
(a) Lessees, operators, purchasers, transporters, and any other
person directly involved in producing, transporting, purchasing,
selling, or measuring oil or gas through the point of royalty
measurement or the point of first sale, whichever is later, must retain
all records, including source records, that are relevant to determining
the quality, quantity, disposition, and verification of production
attributable to Federal or Indian leases for the periods prescribed in
paragraphs (c) through (e) of this section.
(b) This retention requirement applies to records generated during
or for the period for which the lessee or operator has an interest in
or conducted operations on the lease, or in which a person is involved
in transporting, purchasing, or selling production from the lease.
(c) For Federal leases, and units or CAs that include Federal
leases, but do not include Indian leases, the record holder must
maintain records for:
(1) Seven years after the records are generated; unless,
(2) A judicial proceeding or demand involving such records is
timely commenced, in which case the record holder must maintain such
records until the final nonappealable decision in such judicial
proceeding is made, or with respect to that demand is rendered, unless
the Secretary or his/her designee or the applicable delegated State
authorizes in writing an earlier release of the requirement to maintain
such records.
(d) For Indian leases, and units or CAs that include Indian leases,
but do not include Federal leases, the record holder must maintain
records for:
(1) Six years after the records are generated; unless,
(2) The Secretary or his/her designee notifies the record holder
that the Department of the Interior has initiated or is participating
in an audit or investigation involving such records, in which case the
record holder must maintain such records until the Secretary or his/her
designee releases the record holder from the obligation to maintain the
records.
(e) For units and communitized areas that include both Federal and
Indian leases, 6 years after the records are generated. If the
Secretary or his/her designee has notified the record holder within
those 6 years that an audit or investigation involving such records has
been initiated, then:
(1) If a judicial proceeding or demand is commenced within 7 years
after the records are generated, the record holder must retain all
records regarding production from the lease, unit PA, or CA until the
final nonappealable decision in such judicial proceeding is made, or
with respect to that demand is rendered, unless the Secretary or his/
her designee authorizes in writing a release of the requirement to
maintain such records before a final nonappealable decision is made or
rendered.
(2) If a judicial proceeding or demand is not commenced within 7
years after the records are generated, the record holder must retain
all records regarding production from the unit or communitized area
until the Secretary or his/her designee releases the record holder from
the obligation to maintain the records;
(f) The lessee, operator, purchaser, or transporter must maintain
an audit trail.
(g) All records, including source records, that are used to
determine quality, quantity, disposition, and verification of
production attributable to a Federal or Indian lease, unit PA, or CA,
must include the FMP number or the lease, unit PA, or CA number, along
with a unique equipment identifier (e.g., a unique tank identification
number and meter station number), and the name of the company that
created the record. For all facilities existing prior to the assignment
of an FMP number, all records must include the following information:
(1) The name of the operator;
(2) The lease, unit PA, or CA number; and
(3) The well or facility name and number.
(h) Upon request of the AO, the operator, purchaser, or transporter
must provide such records to the AO as may be required by regulation,
written order, Onshore Order, NTL, or COA.
(i) All records must be legible.
(j) All records requiring a signature must also have the signer's
printed name.
Sec. 3170.8 Appeal procedures.
(a) BLM decisions, orders, assessments, or other actions under the
regulations in this part are administratively appealable under the
procedures prescribed in 43 CFR 3165.3(b), 3165.4, and part 4.
(b) For any recommendation made by the PMT, and approved by the
BLM, a party affected by such recommendation may file a request for
discretionary review by the Assistant Secretary for Land and Minerals
Management. The Assistant Secretary may delegate this review function
as he or she deems appropriate, in which case the affected party's
application for discretionary review must be made to the person or
persons to whom the Assistant Secretary's review function has been
delegated.
Sec. 3170.9 Enforcement.
Noncompliance with any of the requirements of this part or any
order
[[Page 81425]]
issued under this part may result in enforcement actions under 43 CFR
subpart 3163 or any other remedy available under applicable law or
regulation.
Subpart 3171--[Reserved]
Subpart 3172--[Reserved]
Subpart 3173--Requirements for Site Security and Production
Handling
Sec. 3173.1 Definitions and acronyms.
(a) As used in this subpart, the term:
Access means the ability to:
(i) Add liquids to or remove liquids from any tank or piping
system, through a valve or combination of valves or by moving liquids
from one tank to another tank; or
(ii) Enter any component in a measuring system affecting the
accuracy of the measurement of the quality or quantity of the liquid
being measured.
Appropriate valves means those valves that must be sealed during
the production or sales phase (e.g., fill lines, equalizer, overflow
lines, sales lines, circulating lines, or drain lines).
Authorized representative (AR) has the same meaning as defined in
43 CFR 3160.0-5.
Business day means any day Monday through Friday, excluding Federal
holidays.
Commingling and allocation approval (CAA) means a formal allocation
agreement to combine production from two or more sources (leases, unit
PAs, CAs, or non-Federal or non-Indian properties) before that product
reaches an FMP.
Economically marginal property means a lease, unit PA, or CA that
does not generate sufficient revenue above operating costs, such that a
prudent operator would opt to plug a well or shut-in the lease, unit
PA, or CA instead of making the investments needed to achieve non-
commingled measurement of production from that lease, unit PA, or CA. A
lease, unit PA, or CA may be regarded as economically marginal if the
operator demonstrates that the expected revenue (net any associated
operating costs) generated from crude oil or natural gas production
volumes on that property is not sufficient to cover the nominal cost of
the capital expenditures required to achieve measurement of non-
commingled production of oil or gas from that property over a payout
period of 18 months. A lease, unit PA, or CA can also be considered
economically marginal if the operator demonstrates that its royalty net
present value (RNPV), or the discounted value of the Federal or Indian
royalties collected on revenue earned from crude oil or natural gas
production on the lease, unit PA, or CA, over the expected life of the
equipment that would need to be installed to achieve non-commingled
measurement volumes, is less than the capital cost of purchasing and
installing this equipment. Both the payout period and the RNPV are
determined separately for each lease, unit PA, or CA oil or gas FMP.
Additionally, oil FMPs are evaluated using estimated revenue (net of
taxes and operating costs) from crude oil production, as defined in
this section, while gas FMPs are evaluated using estimated revenue (net
of taxes and operating costs) from natural gas production, as defined
in this section.
Effectively sealed means the placement of a seal in such a manner
that the sealed component cannot be accessed, moved, or altered without
breaking the seal.
Free water means the measured volume of water that is present in a
container and that is not in suspension in the contained liquid at
observed temperature.
Land description means a location surveyed in accordance with the
U.S. Department of the Interior's Manual of Surveying Instructions
(2009), that includes the quarter-quarter section, section, township,
range, and principal meridian, or other authorized survey designation
acceptable to the AO, such as metes-and-bounds, or latitude and
longitude.
Maximum ultimate economic recovery has the same meaning as defined
in 43 CFR 3160.0-5.
Mishandling means failing to measure or account for removal of
production from a facility.
Payout period means the time required, in months, for the cost of
an investment in an oil or gas FMP for a specific lease, unit PA, or CA
to be covered by the nominal revenue earned from crude oil production,
for an oil FMP, or natural gas production, for a gas FMP, minus taxes,
royalties, and any operating and variable costs. The payout period is
determined separately for each oil or gas FMP for a given lease, unit
PA, or CA.
Permanent measurement facility means all equipment constructed or
installed and used on-site for 6 months or longer, for the purpose of
determining the quantity, quality, or storage of production, and which
meets the definition of FMP under Sec. 3170.3.
Piping means a tubular system (e.g., metallic, plastic, fiberglass,
or rubber) used to move fluids (liquids and gases).
Production phase means that event during which oil is delivered
directly to or through production equipment to the storage facilities
and includes all operations at the facility other than those defined by
the sales phase.
Royalty Net Present Value (RNPV) means the net present value of all
Federal or Indian royalties paid on revenue earned from crude oil
production or natural gas production from an oil or gas FMP for a given
lease, unit PA, or CA over the expected life of metering equipment that
must be installed for that lease, unit PA, or CA to achieve non-
commingled measurement.
Sales phase means that event during which oil is removed from
storage facilities for sale at an FMP.
Seal means a uniquely numbered device that completely secures
either a valve or those components of a measuring system that affect
the quality or quantity of the oil being measured.
(b) As used in this subpart, the following additional acronyms
apply:
BIA means the Bureau of Indian Affairs.
BMP means Best Management Practice.
Sec. 3173.2 Storage and sales facilities--seals.
(a) All lines entering or leaving any oil storage tank must have
valves capable of being effectively sealed during the production and
sales phases unless otherwise provided under this subpart. During the
production phase, all appropriate valves that allow unmeasured
production to be removed from storage must be effectively sealed in the
closed position. During any other phase (sales, water drain, or hot
oiling), and prior to taking the top tank gauge measurement, all
appropriate valves that allow unmeasured production to enter or leave
the sales tank must be effectively sealed in the closed position (see
Appendix A to subpart 3173). Each unsealed or ineffectively sealed
appropriate valve is a separate violation.
(b) Valves or combinations of valves and tanks that provide access
to the production before it is measured for sales are considered
appropriate valves and are subject to the seal requirements of this
subpart (see Appendix A to subpart 3173). If there is more than one
valve on a line from a tank, the valve closest to the tank must be
sealed. All appropriate valves must be in an operable condition and
accurately reflect whether the valve is open or closed.
(c) The following are not considered appropriate valves and are not
subject to the sealing requirements of this subpart:
[[Page 81426]]
(1) Valves on production equipment (e.g., separator, dehydrator,
gun barrel, or wash tank);
(2) Valves on water tanks, provided that the possibility of access
to production in the sales and storage tanks does not exist through a
common circulating, drain, overflow, or equalizer system;
(3) Valves on tanks that contain oil that has been determined by
the AO or AR to be waste or slop oil;
(4) Sample cock valves used on piping or tanks with a Nominal Pipe
Size of 1 inch or less in diameter;
(5) Fill-line valves during shipment when a single tank with a
nominal capacity of 500 barrels (bbl) or less is used for collecting
marginal production of oil produced from a single well (i.e.,
production that is less than 3 bbl per day). All other seal
requirements of this subpart apply;
(6) Gas line valves used on piping with a Nominal Pipe Size of 1
inch or less used as tank bottom ``roll'' lines, provided there is no
access to the contents of the storage tank and the roll lines cannot be
used as equalizer lines;
(7) Valves on tank heating systems that use a fluid other than the
contents of the storage tank (i.e., steam, water, or glycol);
(8) Valves used on piping with a Nominal Pipe Size of 1 inch or
less connected directly to the pump body or used on pump bleed off
lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves on systems where
production may be removed only through approved oil metering systems
(e.g., LACT or CMS). However, any valve that allows access for removing
oil before it is measured through the metering system must be
effectively sealed (see Appendix A to subpart 3173).
(d) Tampering with any appropriate valve is prohibited. Tampering
with an appropriate valve may result in an assessment of civil
penalties for knowingly or willfully preparing, maintaining, or
submitting false, inaccurate, or misleading reports, records, or
written information under 30 U.S.C. 1719(d)(1) and 43 CFR 3163.2(f)(1),
or knowingly or willfully taking, removing, transporting, using, or
diverting oil or gas from a lease site without valid legal authority
under 30 U.S.C. 1719(d)(2) and 43 CFR 3163.2(f)(2), together with any
other remedies provided by law.
Sec. 3173.3 Oil measurement system components--seals.
(a) Components used for quantity or quality determination of oil
must be effectively sealed to indicate tampering, including, but not
limited to, the following components of LACT meters (see Sec.
3174.8(a)) and CMSs (see Sec. 3174.9(e)):
(1) Sample probe;
(2) Sampler volume control;
(3) All valves on lines entering or leaving the sample container,
excluding the safety pop-off valve (if so equipped). Each valve must be
sealed in the open or closed position, as appropriate;
(4) Meter assembly, including the counter head and meter head;
(5) Temperature averager;
(6) LACT meters or CMS;
(7) Back pressure valve pressure adjustment downstream of the
meter;
(8) Any drain valves in the system;
(9) Manual-sampling valves (if so equipped);
(10) Valves on diverter lines larger than 1 inch in nominal
diameter;
(11) Right-angle drive;
(12) Totalizer; and
(13) Prover connections.
(b) Each missing or ineffectively sealed component is a separate
violation.
Sec. 3173.4 Federal seals.
(a) In addition to any INC issued for a seal violation, the AO or
AR may place one or more Federal seals on any appropriate valve,
sealing device, or oil-metering-system component that does not comply
with the requirements in Sec. Sec. 3173.2 and 3173.3 if the operator
is not present, refuses to cooperate with the AO or AR, or is unable to
correct the noncompliance.
(b) The placement of a Federal seal does not constitute compliance
with the requirements of Sec. Sec. 3173.2 and 3173.3.
(c) A Federal seal may not be removed without the approval of the
AO or AR.
Sec. 3173.5 Removing production from tanks for sale and
transportation by truck.
(a) When a single truck load constitutes a completed sale, the
driver must possess documentation containing the information required
in Sec. 3174.12.
(b) When multiple truckloads are involved in a sale and the oil
measurement method is based on the difference between the opening and
closing gauges, the driver of the last truck must possess the
documentation containing the information required in Sec. 3174.12. All
other drivers involved in the sale must possess a trip log or manifest.
(c) After the seals have been broken, the purchaser or transporter
is responsible for the entire contents of the tank until it is
resealed.
Sec. 3173.6 Water-draining operations.
When water is drained from a production storage tank, the operator,
purchaser, or transporter, as appropriate, must document the following
information:
(a) Federal or Indian lease, unit PA, or CA number(s);
(b) The tank location by land description;
(c) The unique tank number and nominal capacity;
(d) Date of the opening gauge;
(e) Opening gauge (gauged manually or automatically), TOV, and
free-water measurements, all to the nearest \1/2\ inch;
(f) Unique identifying number of each seal removed;
(g) Closing gauge (gauged manually or automatically) and TOV
measurement to the nearest \1/2\ inch; and
(h) Unique identifying number of each seal installed.
Sec. 3173.7 Hot oiling, clean-up, and completion operations.
(a) During hot oil, clean-up, or completion operations, or any
other situation where the operator removes oil from storage,
temporarily uses it for operational purposes, and then returns it to
storage on the same lease, unit PA, or communitized area, the operator
must document the following information:
(1) Federal or Indian lease, unit PA, or CA number(s);
(2) Tank location by land description;
(3) Unique tank number and nominal capacity;
(4) Date of the opening gauge;
(5) Opening gauge measurement (gauged manually or automatically) to
the nearest \1/2\ inch;
(6) Unique identifying number of each seal removed;
(7) Closing gauge measurement (gauged manually or automatically) to
the nearest \1/2\ inch;
(8) Unique identifying number of each seal installed;
(9) How the oil was used; and
(10) Where the oil was used (i.e., well or facility name and
number).
(b) During hot oiling, line flushing, or completion operations or
any other situation where the operator removes production from storage
for use on a different lease, unit PA, or communtized area, the
production is considered sold and must be measured in accordance with
the applicable requirements of this subpart and reported as sold to
ONRR on the OGOR under 30 CFR part 1210 subpart C for the period
covering the production in question.
Sec. 3173.8 Report of theft or mishandling of production.
(a) No later than the next business day after discovery of an
incident of
[[Page 81427]]
apparent theft or mishandling of production, the operator, purchaser,
or transporter must report the incident to the AO. All oral reports
must be followed up with a written incident report within 10 business
days of the oral report.
(b) The incident report must include the following information:
(1) Company name and name of the person reporting the incident;
(2) Lease, unit PA, or CA number, well or facility name and number,
and FMP number, as appropriate;
(3) Land description of the facility location where the incident
occurred;
(4) The estimated volume of production removed;
(5) The manner in which access was obtained to the production or
how the mishandling occurred;
(6) The name of the person who discovered the incident;
(7) The date and time of the discovery of the incident; and
(8) Whether the incident was reported to local law enforcement
agencies and/or company security.
Sec. 3173.9 Required recordkeeping for inventory and seal records.
(a) The operator must perform an end-of-month inventory (gauged
manually or automatically) that records: TOV in storage (measured to
the nearest \1/2\ inch) subtracting free water, the volume not
corrected for temperature/S&W, and the volume as reported to ONRR on
the OGOR;
(1) The end-of-month inventory must be completed within +/- 3 days
of the last day of the calendar month; or
(2) The end of month inventory must be a calculated ``end of
month'' inventory based on daily production that takes place between
two measured inventories that are not more than 31, nor fewer than 20,
days apart. The calculated monthly inventory is determined based on the
following equation:
{[(X + Y - W)/Z1] * Z2{time} + X = A,
Where:
A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and second inventory;
Z1 = number of actual days produced between the first and second
inventory; and
Z2 = number of actual days produced between the second inventory and
end of calendar month for which the OGOR report is due.
For example: If the first inventory measurement performed on
January 12 is 125 bbl, the second inventory measurement performed on
February 10 is 150 bbl, the gross sales volume between the first and
second inventory is 198 bbl, and February is the calendar month for
which the report is due. For purposes of this example, we assume
February had 28 days and that the well was non-producing for two of
those days.
{[(150 bbl + 198 bbl - 125 bbl)/29 days] * 16 days{time} + 150 bbl =
273 bbl for the February end-of-month inventory.
(b) For each seal, the operator must maintain a record that
includes:
(1) The unique identifying number of each seal and the valve or
meter component on which the seal is or was used;
(2) The date of installation or removal of each seal;
(3) For valves, the position (open or closed) in which it was
sealed; and
(4) The reason the seal was removed.
Sec. 3173.10 Form 3160-5, Sundry Notices and Reports on Wells.
(a) The operator must submit a Form 3160-5, Sundry Notices and
Reports on Wells (Sundry Notice) for the following:
(1) Site facility diagrams (see Sec. 3173.11);
(2) Request for an FMP number (see Sec. 3173.12);
(3) Request for FMP amendments (see Sec. 3173.13(b));
(4) Requests for approval of off-lease measurement (see Sec.
3173.23);
(5) Request to amend an approval of off-lease measurement (see
Sec. 3173.23(k));
(6) Requests for approval of CAAs (see Sec. 3173.15); and
(7) Request to modify a CAA (see Sec. 3173.18).
(b) The operator must submit all Sundry Notices electronically to
the BLM office having jurisdiction over the lease, unit, or CA using
WIS, unless the submitter:
(1) Is a small business, as defined by the U.S. Small Business
Administration; and
(2) Does not have access to the Internet.
Sec. 3173.11 Site facility diagram.
(a) A site facility diagram is required for all facilities.
(b) Except for the requirement to submit a Form 3160-5, Sundry
Notice, with the site facility diagram, no format is prescribed for
site facility diagrams. The diagram should be formatted to fit on an
8\1/2\ x 11 sheet of paper, if possible, and must be legible and
comprehensible to an individual with an ordinary working knowledge of
oil field operations (see Appendix A to subpart 3173). If more than one
page is required, each page must be numbered (in the format ``N of X
pages'').
(c) The diagram must:
(1) Reflect the position of the production and water recovery
equipment, piping for oil, gas, and water, and metering or other
measuring systems in relation to each other, but need not be to scale;
(2) Commencing with the header, identify all of the equipment,
including, but not limited to, the header, wellhead, piping, tanks, and
metering systems located on the site, and include the appropriate
valves and any other equipment used in the handling, conditioning, or
disposal of production and water, and indicate the direction of flow;
(3) Identify by API number the wells flowing into headers;
(4) If another operator operates a co-located facility, depict the
co-located facility(ies) on the diagram or list them as an attachment
and identify them by company name, facility name(s), lease, unit PA, or
CA number(s), and FMP number(s);
(5) Indicate which valve(s) must be sealed and in what position
during the production and sales phases and during the conduct of other
production activities (e.g., circulating tanks or drawing off water),
which may be shown by an attachment, if necessary;
(6) When describing co-located facilities operated by one operator,
include a skeleton diagram of the co-located facility(ies), showing
equipment only. For storage facilities common to co-located facilities
operated by one operator, one diagram is sufficient;
(7) Clearly identify the lease, unit PA, or CA to which the diagram
applies, the land description of the facility, and the name of the
company submitting the diagram, with co-located facilities being
identified for each lease, unit PA, or CA;
(8) Clearly identify, on the diagram or as an attachment, all
meters and measurement equipment. Specifically identify all approved
and assigned FMPs; and
(9) If the operator claims royalty-free use, clearly identify the
equipment for which the operator claims royalty-free use. The operator
must either:
(i) For each engine, motor, or major component (e.g., compressor,
separator, dehydrator, heater-treater, or tank heater) powered by
production from the lease, unit PA, or CA, state the volume (oil or
gas) consumed (per day or per month) and how the volume is determined;
or
(ii) Measure the volume used, by meter or tank gauge.
(d) At facilities for which the BLM will assign an FMP number under
[[Page 81428]]
Sec. 3173.12, the operator must submit a new site facility diagram as
follows:
(1) For facilities that become operational after January 17, 2017,
within 30 days after the BLM assigns an FMP; or
(2) For a facility that is in service on or before January 17,
2017, and that has a site facility diagram on file with the BLM that
meets the minimum requirements of Onshore Oil and Gas Order 3, Site
Security, an amended site facility diagram meeting the requirements of
this section is not due until 30 days after the existing facility is
modified, a non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified, or there is a change in operator.
(e) At facilities for which an FMP number is not required under
Sec. 3173.12 (e.g., facilities that dispose of produced water), the
operator must submit a new site facility diagram as follows:
(1) For new facilities in service after January 17, 2017, the new
site facility diagram must be submitted within 30 days after the
facility becomes operational; or
(2) For a facility that is in service on or before January 17,
2017, and that has a site facility diagram on file with the BLM that
meets the minimum requirements of Onshore Oil and Gas Order 3, Site
Security, an amended site facility diagram meeting the requirements of
this section is not due until 30 days after the existing facility is
modified, a non-Federal facility located on a Federal lease or
federally approved unit or communitized area is constructed or
modified, or there is a change in operator.
(f) After a site facility diagram has been submitted that complies
with the requirements of this part, the operator has an ongoing
obligation to update and amend the diagram within 30 days after such
facility is modified, a non-Federal facility located on a Federal lease
or federally approved unit or communitized area is constructed or
modified, or there is a change in operator.
Sec. 3173.12 Applying for a facility measurement point.
(a)(1) Unless otherwise approved, the FMP(s) for all Federal and
Indian leases, unit PAs, or CAs must be located within the boundaries
of the lease, unit, or communitized area from which the production
originated and must measure only production from that lease, unit PA,
or CA.
(2) Off-lease measurement or commingling and allocation of Federal
or Indian production requires prior approval (see 43 CFR 3162.7-2,
3162.7-3, 3173.15, 3173.16, 3173.24, and 3173.25).
(b) The BLM will not approve as an FMP a gas processing plant
tailgate meter located off the lease, unit, or communitized area.
(c) The operator must submit separate applications for approval of
an FMP that measures oil produced from a lease, unit PA, or CA, or
under a CAA that complies with the requirements of this subpart, and an
FMP that measures gas produced from the same lease, unit PA, or CA, or
under a CAA that complies with the requirements of this subpart. This
requirement applies even if the measurement equipment or facilities are
at the same location.
(d) For a permanent measurement facility that comes into service
after January 17, 2017, the operator must apply for approval of the FMP
before any production leaves the permanent measurement facility. This
requirement does not apply to temporary measurement equipment used
during well testing operations. After timely submission and prior to
approval of an FMP request, an operator must use the lease, unit PA, or
CA number for reporting production to ONRR, until the BLM assigns an
FMP number, at which point the operator must use the FMP number for all
reporting to ONRR as set forth in Sec. 3173.13.
(e) For a permanent measurement facility in service on or before
January 17, 2017, the operator must apply for BLM approval of an FMP
within the time prescribed in this paragraph, based on the production
level of any one of the leases, unit PAs, or CAs, whether or not they
are part of a CAA. The deadline to apply for an FMP approval applies to
both oil and gas measurement facilities measuring production from that
lease, unit PA, or CA.
(1) For a stand-alone lease, unit PA, or CA that produced 10,000
Mcf or more of gas per month or 100 bbl or more of oil per month, by
January 17, 2018.
(2) For a stand-alone lease, unit PA, or CA that produced 1,500 Mcf
or more, but less than 10,000 Mcf of gas per month, or 10 bbl or more,
but less than 100 bbl of oil per month, by January 17, 2019.
(3) For a stand-alone lease, unit PA, or CA that produced less than
1,500 Mcf of gas per month or less than 10 bbl of oil per month,
January 17, 2020.
(4) For a stand-alone lease, unit PA, or CA that has not produced
for a year or more before January 17, 2017, the operator must apply for
an FMP prior to the resumption of production.
(5) The production levels identified in paragraphs (e)(1) through
(3) of this section should be calculated using the average production
of oil or gas over the 12 months preceding the effective date of this
section or over the period the lease, unit PA, or CA has been in
production, whichever is shorter.
(6) If the operator of any facility covered by this section applies
for an FMP approval by the deadline in this paragraph, the operator may
continue using the lease, unit PA, or CA number for reporting
production to ONRR, until the BLM's assigns an FMP number, at which
point the operator must use the FMP number for all reporting to ONRR as
set forth in Sec. 3173.13.
(7) If the operator fails to apply for an FMP approval by the
deadline in this paragraph, the operator will be subject to an INC and
may also be subject to an assessment of a civil penalty under 43 CFR
part 3160, subpart 3163, together with any other remedy available under
applicable law or regulation.
(f) All requests for FMP approval must include the following:
(1) A complete Sundry Notice requesting approval of each FMP;
(2) The applicable Measurement Type Code specified in WIS;
(3) Information about the equipment used for oil and gas
measurement, including, for:
(i) ``Gas measurement,'' specify operator/purchaser/transporter
unique station number, primary element (meter tube) size or serial
number, and type of secondary device (mechanical or electronic);
(ii) ``Oil measurement by tank gauge,'' specify oil tank number or
tank serial number and size in barrels or gallons for all tanks
associated with measurement at an FMP; and
(iii) ``Oil measurement by LACT or CMS,'' specify whether the
equipment is LACT or CMS and the associated oil tank number or tank
serial number and size in barrels or gallons (there may be more than
one tank associated with an FMP);
(4) Where production from more than one well will flow to the
requested FMP, list the API well numbers associated with the FMP; and
(5) FMP location by land description.
(g) Request for approval of an FMP may be submitted concurrently
with separate requests for off-lease measurement and/or CAA.
Sec. 3173.13 Requirements for approved facility measurement points.
(a) For an existing facility in service on or before January 17,
2017, an operator must start using an FMP number for reporting
production to ONRR on its OGOR for the fourth production month after
the BLM assigns
[[Page 81429]]
the FMP number(s), and every month thereafter. (For example, for a
facility that is assigned an FMP number on January 15, 2016, the
effective date of the FMP is the May production report.) For a new
facility in service after January 17, 2017, an operator must start
using an FMP number for reporting production to ONRR on its OGOR for
the first production month after the BLM assigns the FMP number(s), and
every month thereafter. (For example, for a facility that is assigned
an FMP number on January 15, 2016, the effective date of the FMP is the
February production report.)
(b)(1) The operator must file a Sundry Notice that describes any
changes or modifications made to the FMP within 30 days after the
change. This requirement does not apply to temporary modifications
(e.g., for maintenance purposes). These include any changes and
modifications to the information listed on an application submitted
under Sec. 3173.12.
(2) The description must include details such as the primary
element, secondary element, LACT/CMS meter, tank number(s), and wells
or facilities using the FMP.
(3) The Sundry Notice must specify what was changed and the
effective date, and include, if appropriate, an amended site facility
diagram (see Sec. 3173.11).
Sec. 3173.14 Conditions for commingling and allocation approval
(surface and downhole).
(a) Subject to the exceptions provided in paragraph (b) of this
section, the BLM may grant a CAA only if the proposed allocation method
used for any such commingled measurement does not have the potential to
affect the determination of the total volume or quality of production
on which royalty owed is determined for all the Federal or Indian
leases, unit PAs, or CAs which are proposed for commingling, and only
if the following criteria are met:
(1) The proposed commingling includes production from more than
one:
(i) Federal lease, unit PA, or CA, where each lease, unit PA, or CA
proposed for commingling has 100 percent Federal mineral interest, the
same fixed royalty rate and, and the same revenue distribution;
(ii) Indian tribal lease, unit PA, or CA, where each lease, unit
PA, or CA proposed for commingling is wholly owned by the same tribe
and has the same fixed royalty rate;
(iii) Federal unit PA or CA where each unit PA or CA proposed for
commingling has the same proportion of Federal interest, and which
interest is subject to the same fixed royalty rate and revenue
distribution. (For example, the BLM could approve a commingling request
under this paragraph where an operator proposes to commingle two
Federal CAs of mixed ownership and both CAs are 50 percent Federal/50
percent private, so long as the Federal interests have the same royalty
rates and royalty distributions.); or
(iv) Indian unit PA or CA where each unit PA or CA proposed for
commingling has the same proportion of Indian interests, and which
interest is held by the same tribe and has the same fixed royalty rate;
and
(2) The operator or operators provide a methodology acceptable to
BLM for allocation among the properties from which production is to be
commingled (including a method for allocating produced water), with a
signed agreement if there is more than one operator;
(3) For each of the leases, unit PAs, or CAs proposed for inclusion
in the CAA, the applicant demonstrates to the AO that a lease, unit PA,
or CA proposed for inclusion is producing in paying quantities (or, in
the case of Federal leases, capable of production in paying quantities)
pending approval of the CAA; and
(4) The FMP(s) for the proposed CAA measure production originating
only from the leases, unit PAs, or CAs in the CAA.
(b) The BLM may also approve a CAA in instances where the proposed
commingling of production involves production from Federal or Indian
leases, unit PAs, or CAs that do not meet the criteria of paragraph
(a)(1) of this section (e.g., the commingling of leases, unit PAs, or
CAs with different royalty rates or different distributions of revenue,
or where the commingling involves multiple mineral ownerships). In
order to be approved, a CAA under this subparagraph must meet the
requirements of paragraphs (a)(2) through (4) of this section and at
least one of the following conditions:
(1) The Federal or Indian lease, unit PA, or CA meets the
definition of an economically marginal property. However, if the BLM
determines that a Federal or Indian lease, unit PA, or CA included in a
CAA ceases to be an economically marginal property, then this condition
is no longer met;
(2) The average monthly production over the preceding 12 months for
each Federal or Indian lease, unit PA, or CA proposed for the CAA on an
individual basis is less than 1,000 Mcf of gas per month, or 100 bbl of
oil per month;
(3) A CAA that includes Indian leases, unit PAs, or CAs has been
authorized under tribal law or otherwise approved by a tribe;
(4) The CAA covers the downhole commingling of production from
multiple formations that are covered by separate leases, unit PAs, or
CAs, where the BLM has determined that the proposed commingling from
those formations is an acceptable practice for the purpose of achieving
maximum ultimate economic recovery and resource conservation; or
(5) There are overriding considerations that indicate the BLM
should approve a commingling application in the public interest
notwithstanding potential negative royalty impacts from the allocation
method. Such considerations could include topographic or other
environmental considerations that make non-commingled measurement
physically impractical or undesirable, in view of where additional
measurement and related equipment necessary to achieve non-commingled
measurement would have to be located.
Sec. 3173.15 Applying for a commingling and allocation approval.
To apply for a CAA, the operator(s) must submit the following, if
applicable, to the BLM office having jurisdiction over the leases, unit
PAs, or CAs from which production is proposed to be commingled:
(a) A completed Sundry Notice for approval of commingling and
allocation (if off-lease measurement is a feature of the commingling
and allocation proposal, then a separate Sundry Notice under Sec.
3173.23 is not necessary as long as the information required under
Sec. 3173.23(b) through (e) and, where applicable, Sec. 3173.23(f)
through (i) is included as part of the request for approval of
commingling and allocation);
(b) A completed Sundry Notice for approval of off-lease measurement
under Sec. 3173.23, if any of the proposed FMPs are outside the
boundaries of any of the leases, units, or CAs from which production
would be commingled (which may be included in the same Sundry Notice as
the request for approval of commingling and allocation), except as
provided in paragraph (a) of this section;
(c) A proposed allocation agreement, including an allocation
methodology (including allocation of produced water), with an example
of how the methodology is applied, signed by each operator of each of
the leases, unit PAs, or CAs from which production would be included in
the CAA;
(d) A list of all Federal or Indian lease, unit PA, or CA numbers
in the
[[Page 81430]]
proposed CAA, specifying the type of production (i.e., oil, gas, or
both) for which commingling is requested;
(e) A topographic map or maps of appropriate scale showing the
following:
(1) The boundaries of all the leases, units, unit PAs, or
communitized areas whose production is proposed to be commingled; and
(2) The location of existing or planned facilities and the relative
location of all wellheads (including the API number) and piping
included in the CAA, and existing FMPs or FMPs proposed to be installed
to the extent known or anticipated;
(f) A surface use plan of operations (which may be included in the
same Sundry Notice as the request for approval of commingling and
allocation) if new surface disturbance is proposed for the FMP and its
associated facilities are located on BLM-managed land within the
boundaries of the lease, units, and communitized areas from which
production would be commingled;
(g) A right-of-way grant application (Standard Form 299), filed
under 43 CFR part 2880, if the proposed FMP is on a pipeline, or under
43 CFR part 2800, if the proposed FMP is a meter or storage tank. This
requirement applies only when new surface disturbance is proposed for
the FMP, and its associated facilities are located on BLM-managed land
outside any of the leases, units, or communitized areas whose
production would be commingled;
(h) Written approval from the appropriate surface-management
agency, if new surface disturbance is proposed for the FMP and its
associated facilities are located on Federal land managed by an agency
other than the BLM;
(i) A right-of-way grant application for the proposed FMP, filed
under 25 CFR part 169, with the appropriate BIA office, if any of the
proposed surface facilities are on Indian land outside the lease, unit,
or communitized area from which the production would be commingled;
(j) Documentation demonstrating that each of the leases, unit PAs,
or CAs proposed for inclusion in the CAA is producing in paying
quantities (or, in the case of Federal leases, is capable of production
in paying quantities) pending approval of the CAA; and
(k) All gas analyses, including Btu content (if the CAA request
includes gas) and all oil gravities (if the CAA request includes oil)
for previous periods of production from the leases, units, unit PAs, or
communitized areas proposed for inclusion in the CAA, up to 6 years
before the date of the application for approval of the CAA. Gas
analysis and oil gravity data is not needed if the CAA falls under
Sec. 3173.14(a)(1).
Sec. 3173.16 Existing commingling and allocation approvals.
Upon receipt of an operator's request for assignment of an FMP
number to a facility associated with a CAA existing on January 17,
2017, the AO will review the existing CAA and take the following
action:
(a) The AO will grandfather the existing CAA and associated off-
lease measurement, where applicable, if the existing CAA meets one of
the following conditions:
(1) The existing CAA involves downhole commingling that includes
Federal or Indian leases, unit PAs, or CAs; or
(2) The existing CAA is for surface commingling and the average
production rate over the previous 12 months for each Federal or Indian
lease, unit PA, and CA included in the CAA is:
(i) Less than 1,000 Mcf per month for gas; or
(ii) Less than 100 bbl per month for oil.
(b) If the existing CAA does not meet the conditions of paragraphs
(a)(1) or (a)(2) of this section, the AO will review the CAA for
consistency with the minimum standards and requirements for a CAA under
Sec. 3173.14.
(1) The AO will notify the operator in writing of any
inconsistencies or deficiencies with an existing CAA. The operator must
correct any inconsistencies or deficiencies that the AO identifies,
provide the additional information that the AO has requested, or
request an extension of time from the AO, within 20 business days after
receipt of the AO's notice. When the AO is satisfied that the operator
has corrected any inconsistencies or deficiencies, the AO will
terminate the existing CAA and grant a new CAA based on the operator's
corrections.
(2) The AO may terminate the existing CAA and grant a new CAA with
new or amended COAs to make the approval consistent with the
requirements under Sec. 3173.14 in connection with approving the
requested FMP. If the operator appeals any COAs of the new CAA, the
existing CAA approval will continue in effect during the pendency of
the appeal.
(3) If the existing CAA does not meet the standards and
requirements of Sec. 3173.14 and the operator does not correct the
deficiencies, the AO may terminate the existing CAA under Sec. 3173.20
and deny the request for an FMP number for the facility associated with
the existing CAA.
(c) If the AO grants a new CAA to replace an existing CAA under
paragraph (b) of this section, the new CAA is effective on the first
day of the month following its approval. Any new allocation percentages
resulting from the new CAA will apply from the effective date of the
CAA forward.
Sec. 3173.17 Relationship of a commingling and allocation approval to
royalty-free use of production.
A CAA does not constitute approval of off-lease royalty-free use of
production as fuel in facilities located at an FMP approved under the
CAA.
Sec. 3173.18 Modification of a commingling and allocation approval.
(a) A CAA must be modified when there is:
(1) A modification to the allocation agreement;
(2) Inclusion of additional leases, unit PAs, or CAs are proposed
in the CAA; or
(3) Termination of or permanent production cessation from any of
the leases, unit PAs, or CAs within the CAA.
(b) To request a modification of a CAA, all operators must submit
to the AO:
(1) A completed Sundry Notice describing the modification
requested;
(2) A new allocation methodology, including an allocation
methodology which includes allocation of produced water and an example
of how the methodology is applied, if appropriate; and
(3) Certification by each operator in the CAA that it agrees to the
CAA modification.
(c) A change in operator does not trigger the need to modify a CAA.
Sec. 3173.19 Effective date of a commingling and allocation approval.
(a) If the BLM approves a CAA, the effective date of the CAA is the
first day of the month following first production through the FMPs for
the CAA.
(b) If the BLM approves a modification, the effective date is the
first day of the month following approval of the modification.
(c) A CAA does not modify any of the terms of the leases, units, or
CAs covered by the CAA.
Sec. 3173.20 Terminating a commingling and allocation approval.
(a) The AO may terminate a CAA for any reason, including, but not
limited to, the following:
(1) Changes in technology, regulation, or BLM policy;
[[Page 81431]]
(2) Operator non-compliance with the terms or COAs of the CAA or
this subpart; or
(3) The AO determines that a lease, unit, or CA subject to the CAA
has terminated, or a unit PA subject to the CAA has ceased production.
(b) If only one lease, unit PA, or CA remains subject to the CAA,
the CAA terminates automatically.
(c) An operator may terminate its participation in a CAA by
submitting a Sundry Notice to the BLM. The Sundry Notice must identify
the FMP(s) for the lease(s), unit PA(s), or CA(s) previously subject to
the CAA. Termination by one operator does not mean the CAA terminates
as to all other participating operators, so long as one of the other
provisions of this subpart is met and the remaining operators submit a
Sundry Notice requesting a new CAA as outlined in paragraph (e) of this
section.
(d) The AO will notify in writing all operators who are a party to
the CAA of the effective date of the termination and any
inconsistencies or deficiencies with their CAA approval that serve as
the reason(s) for termination. The operator must correct any
inconsistencies or deficiencies that the AO identifies, provide the
additional information that the AO has requested, or request an
extension of time from the AO, within 20 business days after receipt of
the BLM's notice, or the CAA is terminated.
(e) If a CAA is terminated, each lease, unit PA, or CA that was
included in the CAA may require a new FMP number(s) or a new CAA.
Operators will have 30 days to apply for a new FMP number (Sec.
3173.12) or CAA (Sec. 3173.15), if applicable. The existing FMP number
may be used for production reporting until a new FMP number is assigned
or CAA is approved.
Sec. 3173.21 Combining production downhole in certain circumstances.
(a)(1) Combining production from a single well drilled into
different hydrocarbon pools or geologic formations (e.g., a directional
well) underlying separate adjacent properties (whether Federal, Indian,
State, or private), where none of the hydrocarbon pools or geologic
formations underlie or are common to more than one of the respective
properties, constitutes commingling for purposes of Sec. Sec. 3173.14
through 3173.20.
(2) If any of the hydrocarbon pools or geologic formations underlie
or are common to more than one of the properties, the operator must
establish a unit PA (see 43 CFR part 3180) or CA (see 43 CFR 3105.2-1-
3105.2-3), as applicable, rather than applying for a CAA.
(b) Combining production downhole from different geologic
formations on the same lease, unit PA, or CA in a single well requires
approval of the AO (see 43 CFR 3162.3-2), but it is not considered
commingling for production accounting purposes.
Sec. 3173.22 Requirements for off-lease measurement.
The BLM will consider granting a request for off-lease measurement
if the request:
(a) Involves only production from a single lease, unit PA, CA, or
CAA;
(b) Provides for accurate production accountability;
(c) Is in the public interest (considering factors such as BMPs,
topographic and environmental conditions that make on-lease measurement
physically impractical, and maximum ultimate economic recovery); and
(d) Occurs at an approved FMP. A request for approval of an FMP
(see Sec. 3173.12) may be filed concurrently with the request for off-
lease measurement.
Sec. 3173.23 Applying for off-lease measurement.
To apply for approval of off-lease measurement, the operator must
submit the following to the BLM office having jurisdiction over the
leases, units, or communitized areas:
(a) A completed Sundry Notice;
(b) Justification for off-lease measurement (considering factors
such as BMPs, topographic and environmental issues, and maximum
ultimate economic recovery);
(c) A topographic map or maps of appropriate scale showing the
following:
(1) The boundary of the lease, unit, unit PA, or communitized area
from which the production originates; and
(2) The location of existing or planned facilities and the relative
location of all wellheads (including the API number for each well) and
piping included in the off-lease measurement proposal, and existing
FMPs or FMPs proposed to be installed to the extent known or
anticipated;
(d) The surface ownership of all land on which equipment is, or is
proposed to be, located;
(e) If any of the proposed off-lease measurement facilities are
located on non-federally owned surface, a written concurrence signed by
the owner(s) of the surface and the owner(s) of the measurement
facilities, including each owner's name, address, and telephone number,
granting the BLM unrestricted access to the off-lease measurement
facility and the surface on which it is located, for the purpose of
inspecting any production, measurement, water handling, or
transportation equipment located on the non-Federal surface up to and
including the FMP, and for otherwise verifying production
accountability. If the ownership of the non-Federal surface or of the
measurement facility changes, the operator must obtain and provide to
the AO the written concurrence required under this paragraph from the
new owner(s) within 30 days of the change in ownership;
(f) A right-of-way grant application (Standard Form 299), filed
under 43 CFR part 2880, if the proposed off-lease FMP is on a pipeline,
or under 43 CFR part 2800, if the proposed off-lease FMP is a meter or
storage tank. This requirement applies only when new surface
disturbance is proposed for the FMP and its associated facilities are
located on BLM-managed land;
(g) A right-of-way grant application, filed under 25 CFR part 169
with the appropriate BIA office, if any of the proposed surface
facilities are on Indian land outside the lease, unit, or communitized
area from which the production originated;
(h) Written approval from the appropriate surface-management
agency, if new surface disturbance is proposed for the FMP and its
associated facilities are located on Federal land managed by an agency
other than the BLM;
(i) An application for approval of off-lease royalty-free use (if
required under applicable rules), if the operator proposes to use
production from the lease, unit, or CA as fuel at the off-lease
measurement facility without payment of royalty;
(j) A statement that indicates whether the proposal includes all,
or only a portion of, the production from the lease, unit, or CA. (For
example, gas, but not oil, could be proposed for off-lease
measurement.) If the proposal includes only a portion of the
production, identify the FMP(s) where the remainder of the production
from the lease, unit, or CA is measured or is proposed to be measured;
and
(k) If the operator is applying for an amendment of an existing
approval of off-lease measurement, the operator must submit a completed
Sundry Notice required under paragraph (a) of this section, and
information required under paragraphs (b) through (j) of this section
to the extent the information previously submitted has changed.
[[Page 81432]]
Sec. 3173.24 Effective date of an off-lease measurement approval.
If the BLM approves off-lease measurement, the approval is
effective on the date that the approval is issued, unless the approval
specifies a different effective date.
Sec. 3173.25 Existing approved off-lease measurement.
(a) Upon receipt of an operator's request for assignment of an FMP
number to a facility associated with an off-lease measurement approval
existing on January 17, 2017, the AO will review the existing approved
off-lease measurement for consistency with the minimum standards and
requirements for an off-lease measurement approval under Sec. 3173.22.
The AO will notify the operator in writing of any inconsistencies or
deficiencies.
(b) The operator must correct any inconsistencies or deficiencies
that the AO identifies, provide any additional information the AO
requests, or request an extension of time from the AO, within 20
business days after receipt of the AO's notice. The extension request
must explain the factors that will prevent the operator from complying
within 20 days and provide a timeframe under which the operator can
comply.
(c) The AO may terminate the existing off-lease measurement
approval and grant a new off-lease measurement approval with new or
amended COAs to make the approval consistent with the requirements for
off-lease measurement under Sec. 3173.22 in connection with approving
the requested FMP. If the operator appeals the new off-lease
measurement approval, the existing off-lease measurement approval will
continue in effect during the pendency of the appeal.
(d) If the existing off-lease measurement approval does not meet
the standards and requirements of Sec. 3173.22 and the operator does
not correct the deficiencies, the AO may terminate the existing off-
lease measurement approval under Sec. 3173.27 and deny the request for
an FMP number for the facility associated with the existing off-lease
measurement approval.
(e) If the existing off-lease measurement approval under this
section is consistent with the requirements under Sec. 3173.22, then
that existing off-lease measurement is grandfathered and will be part
of its FMP approval.
(f) If the BLM grants a new off-lease measurement approval to
replace an existing off-lease measurement approval, the new approval is
effective on the first day of the month following its approval.
Sec. 3173.26 Relationship of off-lease measurement approval to
royalty-free use of production.
Approval of off-lease measurement does not constitute approval of
off-lease royalty-free use of production as fuel in facilities located
at an FMP approved under the off-lease measurement approval.
Sec. 3173.27 Termination of off-lease measurement approval.
(a) The BLM may terminate off-lease measurement approval for any
reason, including, but not limited to, the following:
(1) Changes in technology, regulation, or BLM policy; or
(2) Operator non-compliance with the terms or conditions of
approval of the off-lease measurement approval or Sec. Sec. 3173.22
through 3173.26.
(b) The BLM will notify the operator in writing of the effective
date of the termination and any inconsistencies or deficiencies with
its off-lease measurement approval that serve as the reason(s) for
termination. The operator must correct any inconsistencies or
deficiencies that the BLM identifies, provide any additional
information the AO requests, or request an extension of time from the
AO within 20 business days after receipt of the BLM's notice, or the
off lease measurement approval terminates on the effective date.
(c) The operator may terminate the off-lease measurement by
submitting a Sundry Notice to the BLM. The Sundry Notice must identify
the new FMP(s) for the lease(s), unit(s), or CA(s) previously subject
to the off-lease measurement approval.
(d) If off-lease measurement is terminated, each lease, unit PA, or
CA that was subject to the off-lease measurement approval may require a
new FMP number(s) or a new off-lease measurement approval. Operators
will have 30 days to apply for a new FMP number or off-lease
measurement approval, whichever is applicable. The existing FMP number
may be used for production reporting until a new FMP number is assigned
or off-lease measurement is approved.
Sec. 3173.28 Instances not constituting off-lease measurement, for
which no approval is required.
(a) If the approved FMP is located on the well pad of a
directionally or horizontally drilled well that produces oil and gas
from a lease, unit, or communitized area on which the well pad is not
located, measurement at the FMP does not constitute off-lease
measurement. However, if the FMP is located off of the well pad,
regardless of distance, measurement at the FMP constitutes off-lease
measurement, and BLM approval is required under Sec. Sec. 3173.22
through 3173.26.
(b) If a lease, unit, or CA consists of more than one separate
tract whose boundaries are not contiguous (e.g., a single lease
comprises two or more separate tracts), measurement of production at an
FMP located on one of the tracts is not considered to be off-lease
measurement if:
(1) The production is moved from one tract within the same lease,
unit, or communitized area to another area of the lease, unit, or
communitized area on which the FMP is located; and
(2) Production is not diverted during the movement between the
tracts before the FMP, except for production used royalty free.
Sec. 3173.29 Immediate assessments for certain violations.
Certain instances of noncompliance warrant the imposition of
immediate assessments upon discovery, as prescribed in the following
table. Imposition of these assessments does not preclude other
appropriate enforcement actions:
Table 1 to Sec. 3173.29--Violations Subject to an Immediate Assessment
------------------------------------------------------------------------
Assessment
Violation amount per
violation ($)
------------------------------------------------------------------------
1. An appropriate valve on an oil storage tank was not 1,000
sealed, as required by Sec. 3173.2...................
2. An appropriate valve or component on an oil metering 1,000
system was not sealed, as required by Sec. 3173.3....
3. A Federal seal is removed without prior approval of 1,000
the AO or AR, as required by Sec. 3173.4.............
4. Oil was not properly measured before removal from 1,000
storage for use on a different lease, unit, or CA, as
required by Sec. 3173.7(b)...........................
[[Page 81433]]
5. An FMP was bypassed, in violation of Sec. 3170.4... 1,000
6. Theft or mishandling of production was not reported 1,000
to the BLM, as required by Sec. 3173.8...............
7. Records necessary to determine quantity and quality 1,000
of production were not retained, as required by Sec.
3170.7.................................................
8. FMP application was not submitted, as required by 1,000
Sec. 3173.12.........................................
9. (i) For facilities that begin operation after January 1,000
17, 2017, BLM approval for off-lease measurement was
not obtained before removing production, as required by
Sec. 3173.23.........................................
(ii) Facilities that were in operation on or before
January 17, 2017, are subject to an assessment if they
do not have an existing BLM approval for off-lease
measurement.
10. (i) For facilities that begin operation after 1,000
January 17, 2017, BLM approval for surface commingling
was not obtained before removing production, as
required by Sec. 3173.15.............................
(ii) Facilities that were in operation on or before
January 17, 2017, are subject to an assessment if they
do not have an existing BLM approval for surface
commingling.
11. (i) For facilities that begin operation after 1,000
January 17, 2017, BLM approval for downhole commingling
was not obtained before removing production, as
required by Sec. 3173.15.............................
(ii) Facilities that were in operation on or before
January 17, 2017, are subject to an assessment if they
do not have an existing BLM approval for downhole
commingling.
------------------------------------------------------------------------
Appendix A to Subpart 3173--Examples of Site Facility Diagrams
I. Diagrams
1. Site Facility Diagrams and Sealing of Valve Introduction
2. Diagrams
------------------------------------------------------------------------
Diagrams Description
------------------------------------------------------------------------
I-A........................ Gas well without separation equipment.
I-B........................ Gas well with separation equipment.
I-C........................ Single operator with co-located facilities
single oil tank, gas, and water storage.
I-D........................ Oil sales with multiple oil tanks, gas, and
water storage.
I-E........................ Co-located facilities with multiple
operators, oil sales by liquid meter
(Lease Automatic Custody Transfer or
Coriolis Measurement System), gas, and
water storage.
I-F........................ On-lease gas plant, with oil sales by
liquid meter, Liquefied Petroleum Gas
(LPG)/Natural Gas Liquids (NGL) sales by
liquid meter, inlet gas, tailgate gas,
flared or vented and plant process gas
used.
I-G........................ Enhanced recovery water injection or other
water disposal facility.
I-H........................ Pod Facility.
I-I........................ On-lease with gas measurement after the
Joule-Thomson Plant (JT-Skid), oil sales
by liquid meter, Liquefied Petroleum Gas
(LPG)/Natural Gas Liquids (NGL) sales by
liquid meter.
I-J........................ On-lease with gas measurement before the
Joule-Thomson Plant (JT-Skid) and oil
sales by liquid meter.
------------------------------------------------------------------------
Note: No FMP number required for Liquefied Petroleum Gas (LPG)/Natural
Gas Liquids (NGL) liquid meter.
1. Site Facility Diagrams and Sealing of Valves Introduction
Introduction
Appendix A is provided not as a requirement but solely as an
example to aid operators, purchasers and transporters in determining
what valves are considered ``appropriate valves'' subject to the
seal requirements of this rule, and to aid in the preparation of
facility diagrams. It is impossible to include every type of
equipment that could be used or situation that could occur in
production activities. In making the determination of what is an
``appropriate valve,'' the entire facility must be considered as a
whole, including the facility size, the equipment type, and the on-
going activities at the facility.
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[FR Doc. 2016-25407 Filed 11-16-16; 8:45 am]
BILLING CODE 4310-84-C
