Certification of New Interstate Natural Gas Facilities, 18020-18032 [2018-08658]
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Federal Register / Vol. 83, No. 80 / Wednesday, April 25, 2018 / Notices
• Schedule sufficient reactive
resources to regulate voltage levels
(Requirement R2);
• Operate or direct the operation of
devices to regulate transmission voltage
and reactive flows (Requirement R3);
• Develop a set of criteria to exempt
generators from certain requirements
under Reliability Standard VAR–002–3
related to voltage or Reactive Power
schedules, automatic voltage
regulations, and notification
(Requirement R4);
• Specify a voltage or Reactive Power
schedule (which is either a range or a
target value with an associated tolerance
band) for generators at either the high or
low voltage side of the generator stepup transformer, provide the schedule to
the associated Generator Operator,
direct the Generator Operator to comply
with that schedule in automatic voltage
control mode, provide the Generator
Operator the notification requirements
for deviating from the schedule, and, if
requested, provide the Generator
Operator the criteria used to develop the
schedule (Requirement R5); and
• Communicate step-up transformer
tap changes, the time frame for
completion, and the justification for
these changes to Generator Owners
(Requirement R6).
Reliability Standard VAR–002–3 3
Reliability Standard VAR–002–3
contains the following requirements:
• Operate each of its generators
connected to the interconnected
transmission system in automatic
voltage control mode or in a different
control mode as instructed by the
Transmission Operator, unless the
Generator Operator (1) is exempted
pursuant to the criteria developed under
VAR–001–4, Requirement R4, or (2)
makes certain notifications to the
Transmission Operator specifying the
reasons it cannot so operate
(Requirement R1);
• Maintain the Transmission
Operator’s generator voltage or Reactive
Power schedule, unless the Generator
Operator (1) is exempted pursuant to the
criteria developed under VAR–001–4,
Requirement R4, or (2) complies with
the notification requirements for
deviations as established by the
Transmission Owner pursuant to
Requirement R5 in VAR–001–4
(Requirement R2);
• Notify the Transmission Operator of
a change in status of its voltage
controlling device within 30 minutes,
unless the status is restored within that
time period (Requirement R3);
• Notify the Transmission Operator of
a change in reactive capability due to
factors other than those described in
VAR–002–3, Requirement R3 within 30
minutes unless the capability has been
restored during that time period
(Requirement R4).
• Provide information on its step-up
transformers and auxiliary transformers
within 30 days of a request from the
Transmission Operator or Transmission
Planner (Requirement R5); and
• Comply with the Transmission
Operator’s step-up transformer tap
change directives unless compliance
would violate safety, an equipment
rating, or applicable laws, rules or
regulations (Requirement R6).
Type of Respondents: Generator
operators and transmission operators.
Estimate of Annual Burden: 4 The
Commission estimates the annual public
reporting burden for the information
collection as:
FERC–725X, MANDATORY RELIABILITY STANDARDS: VOLTAGE AND REACTIVE (VAR) STANDARDS
Number of
respondents 5
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Total ................................
Total number
of responses
Average
Burden &
Cost per
response 6
Total annual
burden hours
& total
annual Cost
Cost per
respondent
($)
(1)
VAR–001–4 (Requirement
R1–R6).
VAR–002–3 (Requirement
R1).
VAR–002–3 (Requirement
R2–R6).
Annual
number of
responses per
respondent
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
(5) ÷ (1)
181 (TOP) .........
1
181
160 hrs.; $10,899.20 .............
28,960 hrs.; $1,972,755 ........
$10,899.20
944 (GOP) .........
1
944
80 hrs.; 5,449.60 ...................
75,520 hrs.; $5,144,422 ........
5,449.60
944 (GOP) .........
1
944
120 hrs.; $8,174.40 ...............
113,280 hrs.; $7,716,634 ......
8,174.40
...........................
........................
2,069
................................................
217,760 hrs.; $14,833,811 ....
........................
Comments: Comments are invited on:
(1) Whether the collection of
information is necessary for the proper
performance of the functions of the
Commission, including whether the
information will have practical utility;
(2) the accuracy of the agency’s estimate
of the burden and cost of the collection
of information, including the validity of
the methodology and assumptions used;
(3) ways to enhance the quality, utility
and clarity of the information collection;
and (4) ways to minimize the burden of
the collection of information on those
who are to respond, including the use
3 Applies
to transmission operators only.
is defined as the total time, effort, or
financial resources expended by persons to
generate, maintain, retain, or disclose or provide
information to or for a Federal agency. For further
4 Burden
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of automated collection techniques or
other forms of information technology.
Dated: April 19, 2018.
Kimberly D. Bose,
Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. PL18–1–000]
[FR Doc. 2018–08670 Filed 4–24–18; 8:45 am]
BILLING CODE 6717–01–P
Certification of New Interstate Natural
Gas Facilities
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Notice of Inquiry.
AGENCY:
In this Notice of Inquiry, the
Federal Energy Regulatory Commission
(Commission) seeks information and
stakeholder perspectives to help the
SUMMARY:
explanation of what is included in the information
collection burden, reference 5 Code of Federal
Regulations 1320.3.
5 TOP = transmission operator; GOP = generator
operators.
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6 The estimate for hourly cost is $68.12/hour.
This figure is the average salary plus benefits for an
electrical engineer (Occupation Code: 17–2071)
from the Bureau of Labor Statistics at https://
www.bls.gov/oes/current/naics2_22.htm.
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Federal Register / Vol. 83, No. 80 / Wednesday, April 25, 2018 / Notices
Commission explore whether, and if so
how, it should revise its approach under
its currently effective policy statement
on the certification of new natural gas
transportation facilities to determine
whether a proposed natural gas project
is or will be required by the present or
future public convenience and
necessity, as that standard is established
in section 7 of the Natural Gas Act.
DATES: Comments are due June 25, 2018.
ADDRESSES: Comments, identified by
docket number, may be filed in the
following ways:
• Electronic Filing through https://
www.ferc.gov. Documents created
electronically using word processing
software should be filed in native
applications or print-to-PDF format and
not in a scanned format.
• Mail/Hand Delivery: Those unable
to file electronically may mail or handdeliver comments to: Federal Energy
Regulatory Commission, Secretary of the
Commission, 888 First Street NE,
Washington, DC 20426.
Instructions: For detailed instructions
on submitting comments and additional
information on the rulemaking process,
see the Comment Procedures Section of
this document.
FOR FURTHER INFORMATION CONTACT:
Thomas Chandler (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC
20426, 202–502–6699.
Maggie Suter (Technical Information),
Office of Energy Projects, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC
20426, 202–502–6463.
Caroline Wozniak (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, 202–502–
8931.
Brian White (Technical Information),
Office of Energy Market Regulation,
Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, 202–502–
8332.
SUPPLEMENTARY INFORMATION:
1. In this Notice of Inquiry, the
Commission seeks information and
stakeholder perspectives to help the
Commission explore whether, and if so
how, it should revise its approach under
its currently effective policy statement
on the certification of new natural gas
transportation facilities (Policy
Statement) 1 to determine whether a
1 Certification of New Interstate Natural Gas
Pipeline Facilities, 88 FERC ¶ 61,227 (1999),
clarified, 90 FERC ¶ 61,128, further clarified, 92
FERC ¶ 61,094 (2000) (Policy Statement).
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proposed natural gas project is or will
be required by the present or future
public convenience and necessity, as
that standard is established in section 7
of the Natural Gas Act (NGA).2
Specifically, the Commission seeks
input on whether, and if so how, the
Commission should adjust: (1) Its
methodology for determining whether
there is a need for a proposed project,
including the Commission’s
consideration of precedent agreements
and contracts for service as evidence of
such need; (2) its consideration of the
potential exercise of eminent domain
and of landowner interests related to a
proposed project; and (3) its evaluation
of the environmental impact of a
proposed project. Finally, the
Commission seeks input on whether
there are specific changes the
Commission could consider
implementing to improve the efficiency
and effectiveness of its certificate
processes including pre-filing, postfiling, and post-order issuance.
2. Nineteen years have passed since
the Commission issued the Policy
Statement to describe the criteria and
analytical steps that the Commission
uses to balance a proposed natural gas
pipeline project’s public benefits against
its potential adverse consequences. That
period has seen significant changes,
such as: (1) A revolution in natural gas
production technology leading to
dramatic increases in production; (2)
new areas of major natural gas
production; (3) flows on pipeline
systems becoming bidirectional or
reversing; (4) customers routinely
entering into long-term precedent
agreements for firm service during the
formative stage of potential projects and
the use of those precedent agreements as
applicants’ principal evidence of the
need for their projects; (5) the increased
use of natural gas as a fuel source for
electric generation, resulting in a closer
relationship between natural gas
transportation and natural gas-fired
electric generation; (6) increased
concerns expressed by landowners and
communities potentially affected 3 by
proposed projects; (7) an increased
interest regarding the Commission’s
evaluation of the impact that
greenhouse gas (GHG) emissions
associated with a proposed project have
U.S.C. 717f.
total miles of interstate natural gas pipeline
authorized by the Commission on an annual basis
has fluctuated over time, but in recent years
reached a high of 2,739 miles in 2017. See generally
Federal Energy Regulatory Commission, 2017 State
of the Markets Report, at 4 (Apr. 2018),
www.ferc.gov/market-oversight/marketoversight.asp (providing the number of approved
pipelines projects and miles for 2017).
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on global climate change; (8) an
increased focus on environmental
concerns within the NGA public interest
determination; and (9) a desire to
generally expand or limit the
Commission’s evaluation under the
National Environmental Policy Act of
1969 (NEPA).4
3. The Commission’s aim in this
proceeding is the same as in the Policy
Statement: ‘‘to appropriately consider
the enhancement of competitive
transportation alternatives, the
possibility of over building, the
avoidance of unnecessary disruption of
the environment, and the unneeded
exercise of eminent domain.’’ 5 In
issuing this Notice of Inquiry, the
Commission seeks information to
examine the Policy Statement and its
application, as well as the structure and
scope of the Commission’s
environmental analysis of proposed
natural gas projects. Further, it is the
Commission’s desire to improve the
transparency, timing, and predictability
of the Commission’s certification
process. To these ends, we encourage
commenters to identify, with specificity,
any perceived issues with the
Commission’s current analytical and
procedural approaches and to provide
detailed recommendations to address
these issues.
4. During the pendency of this
proceeding, the Commission intends to
continue to process natural gas facility
matters before it consistent with the
Policy Statement, and to make
determinations on the issues raised in
those proceedings on a case-by-case
basis.6 Should the Commission decide
to generally revise its procedures as a
result of this proceeding, it will address
at that time how and when those
changes will be implemented. The
Commission will decide any next steps
with regard to this review of the Policy
Statement after the Commission has
reviewed the comments filed in
response to this Notice of Inquiry.
I. Background
A. The Natural Gas Act of 1938
5. The NGA declares ‘‘that the
business of transporting and selling
natural gas for ultimate distribution to
the public is affected with a public
interest, and that Federal regulation in
matters relating to the transportation of
2 15
3 The
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4 42
U.S.C. 4332–4370f.
Statement, 88 FERC ¶ 61,227 at 61,737.
6 The Commission is aware that some of the
issues raised in this Notice of Inquiry may overlap
with issues raised in pending matters. In this Notice
of Inquiry proceeding, the Commission will
consider only generic issues, and will not consider
any comments that refer to open, contested
Commission proceedings.
5 Policy
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Federal Register / Vol. 83, No. 80 / Wednesday, April 25, 2018 / Notices
natural gas and the sale thereof in
interstate and foreign commerce is
necessary in the public interest.’’ 7 NGA
section 7(c) requires that any person
seeking to construct or operate a facility
for the transportation of natural gas in
interstate commerce must obtain a
certificate of public convenience and
necessity from the Commission.8 Under
NGA section 7(e), the Commission shall
issue a certificate to any qualified
applicant upon finding that the
construction and operation of the
proposed project—whether pipeline,
storage, or liquefaction facilities—‘‘is or
will be required by the present or future
public convenience and necessity.’’ 9
The Commission’s regulations provide
for public notice and the opportunity to
intervene in certificate proceedings to
comment on or protest an application,
and to participate in the environmental
review process.10 If an applicant
receives a certificate from the
Commission, NGA section 7(h)
authorizes the certificate holder to
acquire the property rights necessary to
construct and operate its project by use
of eminent domain if it cannot reach a
voluntary agreement with a
landowner.11
6. The public convenience and
necessity standard encompasses all
factors bearing on the public interest.12
The words ‘‘public interest,’’ however,
are ‘‘not a broad license to promote the
general public welfare.’’ 13 The Supreme
Court has stated that:
in order to give content and meaning to the
words ‘public interest’ as used in the
[Federal] Power and [Natural] Gas Acts, it is
necessary to look to the purposes for which
the Acts were adopted. In the case of the
Power and Gas Acts it is clear that the
principal purpose of those Acts was to
encourage the orderly development of
plentiful supplies of electricity and natural
gas at reasonable prices.14
7. As part of its decision-making
process, the Commission, in accord with
the Policy Statement, determines
whether there is a need for a proposed
project. This analysis is distinct from
that required by the Council on
Environmental Quality (CEQ)
7 15
U.S.C. 717(a).
717f(c)(1)(A).
9 Id. 717f(e).
10 See generally 18 CFR 157.1–157.22 (regulations
governing applications); id. pt. 380 (implementing
NEPA, the Endangered Species Act, and the
National Historic Preservation Act, and prescribing
environmental reports for Natural Gas Act
applications).
11 15 U.S.C. 717f(h).
12 Atl. Refining Co. v. Pub. Serv. Comm’n of N.Y.,
360 U.S. 378, 391 (1959).
13 NAACP v. Fed. Power Comm’n, 425 U.S. 662,
669–70 (1976).
14 Id.
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8 Id.
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regulations, which specify that
environmental documents contain a
‘‘purpose and need statement’’ used to
determine the objectives of the proposed
action and then to identify and consider
reasonable alternative actions.15 Under
the NGA, the Commission will take into
account all information in the record
from the applicant, parties to the
proceeding, commenters, and the
environmental document to determine
whether a proposed project is required
by the public convenience and
necessity.16
8. The Commission’s powers under
NGA section 7 are limited. The
Commission can issue a certificate for a
proposed project, subject to ‘‘such
reasonable terms and conditions as the
public convenience and necessity may
require.’’ 17 The Commission can deny
an application if, and only if, a
balancing of all of the factors weighs
against authorization of the proposed
project.18 The Policy Statement explains
that relevant factors reflecting the need
for the project might include, but would
not be limited to, precedent agreements,
demand projections, potential cost
savings to consumers, or a comparison
of projected demand with the amount of
capacity currently serving the market
while adverse effects include economic,
competitive, environmental, or other
effects on the relevant interests.19 We
note the Commission only has authority
over facilities for the transportation of
natural gas in interstate commerce. The
Commission has no authority to
certificate intrastate facilities or
facilities for the production, gathering,
or local distribution of natural gas.20
Nor does the Commission have
jurisdiction over facilities used for the
generation of electric energy.21
15 40
CFR 1502.13.
Power Comm’n v. Transcontinental Gas
Pipe Line Corp., 365 U.S. 1, 23 (1961).
17 15 U.S.C. 717f(e).
18 See, e.g., Transcontinental Gas Pipe Line Corp.,
365 U.S. at 17 (the Commission ‘‘can only exercise
a veto power over proposed transportation and it
can only do this when a balance of all the
circumstances weighs against certification’’).
19 Policy Statement, 88 FERC ¶ 61,227 at 61,747.
20 NGA section 1(b) states that Commission
authority applies to interstate transportation of
natural gas and sales for resale, ‘‘but shall not apply
to any other transportation or sale of natural gas or
to the local distribution of natural gas or to the
facilities used for such distribution or to the
production or gathering of natural gas.’’ 15 U.S.C.
717(b).
21 Section 201 of the Federal Power Act states, the
Commission ‘‘shall not have jurisdiction, except as
specifically provided in this Part and the Part next
following, over facilities used for the generation of
electric energy.’’ 16 U.S.C. 824.
16 Fed.
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B. The National Environmental Policy
Act of 1969
9. The Commission’s consideration of
an application triggers environmental
review under NEPA.22 NEPA and its
implementing regulations require that
before taking a major action, such as
action on an application for a natural
gas project, an agency must take a ‘‘hard
look’’ at the environmental
consequences of the proposed action
and at alternatives, and disclose its
analysis to the public.23 Regulations
issued by the CEQ to implement
NEPA 24 require agencies, including the
Commission, to consider the
environmental impacts of a proposed
action, generally by preparing either an
Environmental Assessment (EA) or an
Environmental Impact Statement
(EIS).25 The requirements of NEPA are
procedural: They are intended to
disclose impacts and allow for informed
decision-making, but do not mandate a
particular result or give preeminent
weight to environmental
considerations.26
10. An agency’s environmental
document must include a statement to
‘‘briefly specify the underlying purpose
and need to which the agency is
responding in proposing the alternatives
including the proposed action.’’ 27
Agencies use the purpose and need
statement to define the objectives of a
proposed action and then to identify
and consider reasonable alternatives.28
Agencies consider alternatives ‘‘that are
practical or feasible from the technical
and economic standpoint and using
common sense, rather than simply
desirable from the standpoint of the
applicant.’’ 29 An agency need only
evaluate alternatives that can satisfy the
purpose and need of the proposed
project, and the evaluation is shaped by
the application and the function that the
agency plays in the decisional process.30
Alternatives that are not
environmentally preferable, not able to
22 42
U.S.C. 4332(2)(C).
Gas & Elec. Co. v. Nat. Res. Defense
Council, Inc., 462 U.S. 87, 97 (1983) (discussing the
twin aims of NEPA).
24 40 CFR 1500.1–1508.28.
25 Id. 1501.4 (detailing when to prepare an EA
versus an EIS).
26 Robertson v. Methow Valley Citizen’s Council,
490 U.S. 332, 350 (1989); see also Baltimore Gas &
Elec. Co., 462 U.S. at 97 (citing Stryckers’ Bay
Neighborhood Council v. Karlen, 444 U.S. 223, 227
(1980)).
27 40 CFR 1508.9 (describing requirements for an
EA).
28 Colo. Envtl. Coal. v. Dombeck, 185 F.3d 1162,
1175 (10th Cir. 1999).
29 Forty Most Asked Questions Concerning CEQ’s
National Environmental Policy Act Regulations, 46
FR 18026, 18027 (Mar. 23, 1981).
30 Citizens Against Burlington, Inc. v. Busey, 938
F.2d 190, 195, 199 (DC Cir. 1991).
23 Baltimore
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provide equivalent services,
uneconomic, speculative ventures as
opposed to planned projects, or
otherwise inadequate to function as a
serviceable alternative to the proposed
project may be eliminated so long as the
agency briefly discusses the reasons for
the elimination.31
11. Commission documents under
NEPA first address the scope of the
project (i.e., ‘‘the range of actions,
alternatives, and impacts to be
considered’’) 32, then address the
environmental impacts of the proposed
action, connected actions, and
cumulative actions.33 Commission
documents under NEPA may also
address similar actions if a combined
analysis would be the best way to
adequately assess combined impacts.34
These NEPA documents disclose and
evaluate the direct, indirect, and
cumulative impacts of the project on
various environmental resources in the
context of temporary, short-term, longterm, and permanent impacts, and then
consider practical measures to avoid,
minimize, or mitigate those impacts.
Direct impacts are caused by the
proposed action and occur at the same
time and place. Indirect impacts are
‘‘caused by the [proposed] action and
are later in time or farther removed in
distance, but are still reasonably
foreseeable.’’ 35 Cumulative impacts are
defined as ‘‘the impact on the
environment which results from the
incremental impact of the [proposed]
action when added to other past,
present, and reasonably foreseeable
future actions, regardless of what agency
(Federal or non-Federal) or person
undertakes such actions.’’ 36 The
impacts of these other actions must
occur within the same geographic area
and same time period in which the
proposed project’s impacts will occur.37
31 40 CFR 1502.14(a). See, e.g., Bradwood Landing
LLC, 126 FERC ¶ 61,035, at P 158 (2009);
Broadwater Energy LLC, 124 FERC ¶ 61,225, at PP
187–189 (2008) (rejecting alternatives that were not
technically and economically feasible and practical,
or did not offer significant environmental
advantages over the proposed project or its
components, or were unavailable and/or incapable
of being implemented, or do not meet the
applicants’ stated project objectives).
32 40 CFR 1508.25.
33 Id. 1508.25(a)(1)–(2).
34 Id. 1508.25(a)(3).
35 Id. 1508.8(b).
36 Id. 1508.7.
37 ‘‘[A] consideration of cumulative impacts must
also consider ‘[c]losely related and proposed or
reasonably foreseeable actions that are related by
timing or geography.’’’ O’Reilly v. U.S. Army Corps
of Engineers, 477 F.3d 225 at 234 (5th Cir. 2007)
(quoting Vieux Carre Prop. Owners, Residents, &
Assocs., Inc. v. Pierce, 719 F.2d 1272, 1277 (5th Cir.
1983)); see also CEQ, Considering Cumulative
Effects Under the National Environmental Policy
Act, at 12–16 (Jan. 1997), https://www.energy.gov/
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C. Conditions and Considerations
Leading to the Development of the
Policy Statement
12. Historically, the Commission
established prices for natural gas sales
and transportation, and there was little
competition for gas supply or
transportation capacity. Interstate
pipelines, operating as merchants,
produced and/or purchased natural gas
at the wellhead, transported it to a city
gate, and sold it to a local distribution
company (LDC) at a Commissionregulated price that reflected combined
(i.e., bundled) commodity and
transportation costs. Congress and the
Commission introduced increasingly
competitive elements into this merchant
model. The Natural Gas Policy Act of
1978 began the process of decontrolling
wellhead natural gas prices and eased
barriers between intrastate and
interstate markets.38 The Commission
issued Order No. 436, which initiated
open access transportation to allow
downstream gas users, such as LDCs
and industrial customers, to buy gas
directly from producers or merchants
and transport their gas on interstate
pipelines.39 The Wellhead Decontrol
Act of 1989 lifted remaining price
controls on wellhead sales as of January
1, 1993.40 In 1992, the Commission
issued Order No. 636 to ‘‘reflect and
finally complete the evolution to
competition in the natural gas industry
initiated by [the above-cited statutory
and regulatory revisions] so that all
natural gas suppliers, including the
pipeline as merchant, will compete for
gas purchasers on an equal footing.’’ 41
sites/prod/files/nepapub/nepa_documents/
RedDont/G–CEQ-ConsidCumulEffects.pdf.
38 15 U.S.C. 3301–3432.
39 Regulation of Natural Gas Pipelines After
Partial Wellhead Decontrol, FERC Stats. & Regs. ¶
30,665 (1985), vacated and remanded, Associated
Gas Distribs. v. FERC, 824 F.2d 981 (D.C. Cir. 1987),
readopted on an interim basis, Order No. 500, FERC
Stats. & Regs. ¶ 30,761 (1987), remanded, Am. Gas
Ass’n v. FERC, 888 F.2d 136 (D.C. Cir. 1989),
readopted, Order No. 500–H, FERC Stats. & Regs.
¶ 30,867 (1989), reh’g granted in part and denied
in part, Order No. 500–I, FERC Stats. & Regs. ¶
30,880 (1990), aff’d in part and remanded in part,
Am. Gas Ass’n v. FERC, 912 F.2d 1496 (D.C. Cir.
1990), order on remand, Order No. 500–J, FERC
Stats. & Regs. ¶ 30,915, order on remand, Order No.
500–K, FERC Stats. & Regs. ¶ 30,917, reh’g denied,
Order No. 500–L (1991).
40 Public Law 101–60, 103 Stat. 157 (1989).
41 Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing
Transportation; and Regulation of Natural Gas
Pipelines After Partial Wellhead Decontrol, Order
No. 636, FERC Stats. & Regs. ¶ 30,939, at 30,391
(footnote omitted), order on reh’g, Order No. 636–
A, FERC Stats. & Regs. ¶ 30,950, order on reh’g,
Order No. 636–B, 61 FERC ¶ 61,272 (1992), order
on reh’g, 62 FERC ¶ 61,007 (1993), aff’d in part and
remanded in part sub nom. United Dist. Cos. v.
FERC, 88 F.3d 1105 (D.C. Cir. 1996), order on
remand, Order No. 636–C, 78 FERC ¶ 61,186 (1997).
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As a result, natural gas markets have
changed from being highly regulated to
being largely driven by competition and
market forces. Instead of merchant
pipelines delivering natural gas to
customers at a Commission-regulated
bundled price, most natural gas
pipelines have exited the merchant
business and now provide unbundled
transportation and storage services. As a
result, shippers are able to purchase
natural gas at the wellhead or from gas
marketers, trade gas among themselves,
and purchase pipeline and storage
capacity from marketers and other
shippers in the secondary market as
well as directly from the pipeline. These
changes have benefitted natural gas
consumers by providing a wider range
of options in pipeline services.
13. As natural gas commodity and
transportation markets were becoming
more competitive, the 1990s saw
significant growth in natural gas
consumption in the industrial and
electric generation segments. This
prompted jurisdictional natural gas
companies to urge the Commission to
expeditiously authorize new projects to
meet anticipated growth in demand.
Due to the lower capital costs and
shorter construction times of advanced
combined-cycle gas-fired plants in
comparison with conventional coalfired plants, and the relative
environmental benefits of natural gas
compared to coal combustion, industry
forecasts at the time showed natural gasfired electric generation demand tripling
in the following twenty years and
overall gas demand reaching 32 Trillion
Cubic Feet (Tcf) by 2020.42
14. In addition, in the 1990s, many
LDCs were going through significant
changes as they implemented retail
unbundling programs, also known as
customer choice programs, on their
systems. Prior to retail unbundling,
LDCs, similar to interstate pipelines,
provided a composite bundled service
to customers that included the bundled
price of the gas and associated pipeline
capacity and the price of the
distribution service. Retail unbundling
programs provided residential and
commercial customers with access to
competitive markets through the ability
to purchase gas supplies from retail
marketers that may be different from
their LDCs. As a result, LDCs were not
certain to what degree they would
continue to be responsible for
purchasing gas supplies and pipeline
capacity in order to provide service for
their core retail customers. Because of
42 Energy Information Administration (EIA),
Natural Gas 1998: Issues and Trends, DOE/EIA–
0560(98), at 71, 109, 115 (Apr. 1999).
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this uncertainty, many LDCs sought to
reduce their firm contract commitments
with interstate pipelines, both in terms
of the duration and quantity of firm
service (this reduction in service is
referred to as capacity turnback). In light
of the capacity turnback situation and
potential stranded cost issues that arose
on certain pipelines following
restructuring, many LDCs were
concerned about the impact any new
pipeline expansion construction could
have on the value of their existing
pipeline capacity contracts, and the
potential rate implications of
overbuilding.43 These concerns were
exacerbated by the fact that the
Commission’s pricing policy for new
construction prior to the Policy
Statement called for expansion project
costs to be rolled into existing system
costs to derive rolled-in rates in a future
NGA section 4 rate case.44 At that time,
the Commission generally ruled in favor
of rolled-in rates when the cost impact
of the expansion project, spread across
the pipeline’s system, resulted in a rate
impact on existing customers of five
percent or less and the expansion
provided operational and/or financial
benefits to the system.45 All shippers
bore some burden of the expansion
project’s cost, whether they benefitted
from the project or not, without being
allowed to adjust their contracted
volumes. LDCs and other parties
believed that this pricing policy sent the
wrong price signals by masking the real
costs of an expansion project and could
result in overbuilding of capacity and
subsidization of an expansion by a
pipeline’s existing shippers.
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D. Proceedings Leading to the Policy
Statement, Purpose of the Policy
Statement, and the Issues It Sought To
Address
15. In response to the concerns
described above, the Commission issued
the Notice of Proposed Rulemaking
(NOPR), Regulation of Short-Term
Natural Gas Transportation Services,46
and the Notice of Inquiry, Regulation of
Interstate Natural Gas Transportation
43 See, e.g., Policy Statement, 88 FERC ¶ 61,227
at 61,741 (summarizing comments from the
American Gas Association, Baltimore Gas and
Electric Company, and Philadelphia Gas Works
requesting that pipelines not be allowed to impose
the costs of unsubscribed capacity created through
the construction of excess capacity on existing
shippers).
44 Pricing Policy for New and Existing Facilities
Constructed by Interstate Natural Gas Pipelines, 71
FERC ¶ 61,241 (1995), order on reh’g, 75 FERC
¶ 61,105 (1996).
45 Id., 71 FERC ¶ 61,241 at 61,916–61,917.
46 Regulation of Short-Term Natural Gas
Transportation Services, Notice of Proposed
Rulemaking, FERC Stats. & Regs. ¶ 32,533 (1998)
(cross-referenced at 84 FERC ¶ 61,085).
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Services,47 to explore issues related to
its policies on certification and pricing
of new construction projects. In the
NOPR, the Commission asked questions
relating to many of the issues that have
arisen in recent certificate proceedings
including: Whether the Commission
should look behind the precedent
agreements or contracts presented as
evidence of market demand to assess
independently the market’s need for
additional gas service; whether the
Commission should apply a different
standard to precedent agreements or
contracts with affiliates than with nonaffiliates; whether the Commission
should, in an effort to check
overbuilding and capacity turnback,
take a harder look at proposals that are
designed to compete for existing market
share rather than bring service to a new
customer base; and whether the
Commission should apply a different
standard to project sponsors who do not
plan to use either federal or stategranted rights of eminent domain to
acquire right-of-way.48
16. Information received in these
proceedings, as well as experience
evaluating proposals for new pipeline
construction, persuaded the
Commission to revisit its policy for
certificating new construction.49 The
Commission issued the Policy
Statement intending that it would
provide the natural gas industry with
guidance as to how the Commission
would evaluate applications for new
natural gas projects. The Commission
sought ‘‘to foster competitive markets,
protect captive customers, and avoid
unnecessary environmental and
community impacts while serving
increasing demands for natural gas.’’ 50
17. These objectives were realized
primarily by a shift from rolled-in
pricing to incremental pricing. Under
incremental pricing, existing customers
using existing facilities do not
contribute to, and thereby do not
subsidize, the cost of constructing and
operating new projects.51 Applicants
47 Regulation of Interstate Natural Gas
Transportation Services, Notice of Inquiry, FERC.
Stats. & Regs. ¶ 35,533 (1998) (cross-referenced at
84 FERC ¶ 61,087).
48 NOPR, FERC Stats. & Regs. ¶ 32,533 at 33,489–
90.
49 Policy Statement, 88 FERC ¶ 61,227 at 61,737.
50 Id. at 61,743. These same aims apply to this
Notice of Inquiry.
51 The Policy Statement recognized there may be
instances where expansion project costs should be
rolled into the rates of existing customers; for
example, when inexpensive expansibility is made
possible because of earlier, costly construction. In
such a case, ‘‘because the existing customers bear
the cost of the earlier, more costly construction in
their rates, incremental pricing could result in the
new customers receiving a subsidy from the
existing customers because the new customers
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can recover the costs of the new
facilities only from shippers who use
them, and are fully at risk for the cost
of the new facilities and will bear the
financial burden of any unsubscribed
capacity. In the Policy Statement, the
Commission reasoned that incremental
pricing would send the proper price
signals for new construction and
indicate whether a project is financially
viable.52
18. The Policy Statement stated that
the Commission will approve an
application for a new project only if its
public benefits outweigh its residual
adverse effects.53 The Policy Statement
described this balancing of benefits and
adverse effects as an economic test.54 In
addition to the economic screen
established by the Policy Statement, the
Commission simultaneously considers
the environmental impacts of a
proposed project and imposes
mitigation measures to address potential
environmental impacts.
E. Changed Circumstances Since
Issuance of the Policy Statement
19. Over the last decade, the United
States has seen an unprecedented
change in the dynamics of the natural
gas market and the supply and demand
forces driving it. Led by advancements
in production technologies, primarily in
accessing shale reserves, natural gas
supplies have increased dramatically.
Domestic natural gas production has
increased from 21.3 Tcf in 2010 to 26.9
Tcf in 2017.55 The Energy Information
Administration’s (EIA) Annual Energy
Outlook 2018 forecasts continued
supply growth over the next 25 years,
increasing to nearly 39 Tcf by 2035 and
43 Tcf by 2050.56 In addition, driven by
liquefied natural gas (LNG) exports,
increased pipeline exports to Mexico,
and reduced imports from Canada, the
EIA shows that the United States
became a net exporter of natural gas in
2017.57
20. As natural gas production has
increased, so has demand, rising from
would not face the full cost of the construction that
makes their new service possible.’’ Policy
Statement, 88 FERC ¶ 61,227 at 61,746.
52 Id.
53 Id. at 61,745.
54 Id.
55 EIA, Natural Gas Summary (Mar. 30, 2018) (in
table see row labeled ‘‘Dry Production;’’ click link
in the final column to view history) (Natural Gas
Summary), https://www.eia.gov/dnav/ng/ng_sum_
lsum_dcu_nus_a.htm.
56 EIA, Annual Energy Outlook 2018, at tbl.13
(Feb. 6, 2018) (in table see row labeled ‘‘Dry Gas
Production’’ under the reference case) (Annual
Energy Outlook 2018), https://www.eia.gov/
outlooks/aeo/data/browser/#/ ?id=13AEO2018&cases=ref2018&sourcekey=0.
57 Natural Gas Summary (in table compare rows
labeled ‘‘Imports’’ and ‘‘Exports’’).
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24.1 Tcf in 2010 to 27.1 Tcf in 2017,
driven in part by an increase in gas-fired
electric generation.58 The EIA’s 2018
Annual Energy Outlook projects
continued growth in domestic demand
to over 31.4 Tcf by 2035 and nearly 35
Tcf by 2050.59
21. Increases in both domestic and
international demand for natural gas
produced in the United States,
combined with the availability of
competitively-priced gas from shale
reserves and associated gas extracted in
tandem with oil, have reduced prices
and price volatility and shifted the
emphasis of the types of proposed
natural gas infrastructure projects from
storage to transportation and exports,
leading to the Commission receiving
and approving an increased number of
pipeline and LNG export terminal
applications since 2010.60 Much of the
increased production is attributable to
Appalachian shale deposits,
predominately the Marcellus and Utica,
located in Pennsylvania, West Virginia,
Ohio, and New York.61 Although these
areas have historically produced natural
gas, the volumes had been relatively
small and much of the infrastructure in
the area was built to deliver natural gas
to traditional regional markets and was
not able to transport the burgeoning
supply volumes to more distant markets
without significant system expansions.
In response to this take-away bottleneck,
the Commission received a host of
applications proposing either to
construct greenfield pipelines 62 to
transport gas out of the region or to
increase the capacity of existing
infrastructure through the addition of
compression and pipeline looping.63
58 Id. (in table see row labeled ‘‘Total
Consumption;’’ click link in the final column to
view history).
59 Annual Energy Outlook 2018, at tbl.13 (in table
see row labeled ‘‘Consumption by Sector’’ under the
reference case).
60 In 2010, the Commission authorized about 24
pipeline projects comprising 9.2 billion cubic feet
(Bcf) per day, 20 storage projects comprising 149
Bcf per day capacity with 5.6 Bcf per day
deliverability, and no LNG import/export facilities.
In 2017, the Commission authorized about 49
pipeline projects comprising 30.8 Bcf per day and
2 storage projects comprising no new capacity but
increased deliverability. Between 2014 and 2017
the Commission also authorized 13 LNG import/
export projects for 16 Bcf per day deliverability.
61 New York’s shale reserves remain undeveloped
due to a prohibition on high-volume hydraulic
fracturing in effect since 2008.
62 A greenfield pipeline is defined as a new
pipeline system that is operated as a separately
regulated company with its own rates and tariff. For
example, the NEXUS Project is a greenfield
pipeline. NEXUS Gas Transmission, LLC, 160 FERC
¶ 61,022 (2017).
63 A pipeline loop is a segment of pipe
constructed parallel to an existing pipeline to
increase capacity. For example, Southern Natural
Gas Company, L.L.C.’s Fairburn Expansion Project
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Other producing areas have also
experienced a dramatic growth in
output starting in the mid-2000s, from
traditional oil and gas fields in the
Permian Basin in West Texas to the
more recently developed Bakken Shale
Formation in North Dakota. This
increased production has also prompted
applications to add capacity to transport
gas to consumers.
22. In addition, contracting patterns
are changing significantly as a result of
the supply growth. In the past, LDCs
contracted for a large percentage of the
total interstate pipeline capacity,
transporting supplies from the
production area to their customers.
Increasingly, however, LDCs are
purchasing gas supplies further
downstream at market area pooling
points or their citygates as other parties
increasingly contract for pipeline
capacity. Natural gas producers are now
contracting for an increasing amount of
firm pipeline capacity on expansion
projects in an effort to provide a secured
commercial outlet for their supplies. For
many of these projects, producers are
interested in transporting their natural
gas to the nearest pooling point on the
pipeline system, where the gas can be
sold to other parties serving
downstream markets. Therefore, an
increasing number of projects are being
designed to transport gas to a point of
distribution on the interstate pipeline
grid, which may not correspond to a
defined market or end use.
F. Executive Order 13807, ‘‘Establishing
Discipline and Accountability in the
Environmental Review and Permitting
Process for Infrastructure Projects’’
23. On August 15, 2017, President
Trump issued Executive Order 13807
‘‘Establishing Discipline and
Accountability in the Environmental
Review and Permitting Process for
Infrastructure Projects’’ to ‘‘ensure that
the Federal environmental review and
permitting process for infrastructure
projects is coordinated, predictable, and
transparent.’’ 64 Executive Order 13807
states that inefficiencies in the project
decision-making process, including the
management of environmental reviews
and permit decisions or authorizations,
‘‘have delayed infrastructure
investments, increased project costs,
and blocked the American people from
enjoying improved infrastructure that
would benefit our economy, society,
and environment.’’ 65 Executive Order
includes a 1.6-mile-long, 30-inch-diameter pipeline
loop to add capacity to the system. S. Nat. Gas Co.,
L.L.C., 162 FERC ¶ 61,122 (2018).
64 Exec. Order No. 13807, 82 FR 40463, 40463
(Aug. 15, 2017).
65 Id.
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13807 sets forth several components of
its policy, including to ‘‘ensure that
Federal authorities make informed
decisions concerning the environmental
impacts of infrastructure projects,’’
‘‘provide transparency and
accountability to the public regarding
environmental review and authorization
decisions,’’ and ‘‘make timely decisions
with the goal of completing all Federal
environmental reviews and
authorization decisions for major
infrastructure projects within 2
years.’’ 66 The Commission is committed
to carrying out the goals of Executive
Order 13807 to improve the efficiency,
timing, and overall predictability of the
Commission’s certification process.67
G. The Commission’s Evaluation Under
the Policy Statement
24. The Policy Statement explained
that the Commission will consider
whether a proposed project’s
anticipated public benefits outweigh its
residual adverse effects on economic
interests. If so, the Commission will
then complete an analysis of the
project’s environmental impacts and
incorporate those findings in reaching a
conclusion on whether a project is
required by the public convenience and
necessity. If not, an application will be
denied and there will be no reason to
consider environmental impacts.68
25. Because the NEPA review
typically takes longer than the review of
the non-environmental aspects of a
proposed project, in practice the
Commission often initiates its study of
environmental impacts at the
applicant’s request during pre-filing and
before an application is filed. Also, most
natural gas projects require approvals
from numerous other federal, state, and
local agencies or federally recognized
Indian tribes.69 Coordinating with other
agencies and ensuring that NEPA
documents adequately address the
66 Id. Executive Order 13807 defines ‘‘major
infrastructure project’’ as ‘‘an infrastructure project
for which multiple authorizations by Federal
agencies will be required to proceed with
construction, the lead Federal agency has
determined that it will prepare an environmental
impact statement’’ under NEPA ‘‘and the project
sponsor has identified the reasonable availability of
funds sufficient to complete the project.’’ Id. 40464.
67 The Commission is a signatory to the
Memorandum of Understanding Implementing the
One Federal Decision under Executive Order 13807,
which is available at https://www.whitehouse.gov/
wp-content/uploads/2018/04/MOU-One-FederalDecision-m-18-13-Part-2.pdf.
68 E.g., Turtle Bayou Gas Storage Co., LLC, 135
FERC ¶ 61,233 (2014) (Turtle Bayou).
69 For example, projects may require Clean Water
Act section 401 water quality certifications, Clean
Air Act permits, and concurrence letters or
Biological Opinions from the National Marine
Fisheries Service or United States Fish and Wildlife
Service.
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concerns of agencies, federally
recognized tribes,70 and stakeholders
can extend the time needed to complete
the NEPA review process.
H. Applying the Policy Statement
1. Threshold Requirement
26. The Policy Statement’s threshold
requirement is that an applicant
financially support the project without
relying on subsidization from its
existing customers.71 For greenfield
projects, this is the case by definition,
as these new projects have no existing
customers.72 For existing jurisdictional
natural gas companies, the Policy
Statement’s adoption of incremental
rates as the default pricing mechanism
for new capacity ensures that the project
sponsor and its expansion customers
bear all the economic risks of
constructing and operating new
facilities, without subsidization from
the company’s existing customers.73
When an existing natural gas company
proposes to use its existing system rates
as initial recourse rates for an
expansion, the natural gas company is
required to demonstrate that the
incremental revenue received would
exceed the incremental cost of the new
project before being granted approval to
roll the costs of the expansion into its
system rates, thereby ensuring existing
customers will not subsidize the
expansion.74
2. Factors To Be Balanced in Assessing
the Need for a New Project
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(a) Potential Adverse Effects on Affected
Interests
27. When the no-subsidy threshold
requirement is met, the next step in the
Commission’s analysis is to determine
whether the applicant has eliminated or
minimized any residual adverse effects
the project might have on: (1) The
applicant’s existing customers, (2)
existing pipelines in the market and
their captive customers, and (3)
70 The Commission consults with potentially
affected federally recognized Indian tribes as set
forth in our tribal consultation policy statement.
Policy Statement on Consultation with Indian
Tribes in Commission Proceedings, Order No. 635,
FERC Stats. & Regs. ¶ 31,148 (2003) (crossreferenced at 104 FERC ¶ 61,108).
71 Policy Statement, 88 FERC ¶ 61,227 at 61,746.
72 E.g., Sierrita Gas Pipeline, LLC, 147 FERC
¶ 61,192 (2014).
73 Trailblazer Pipeline Co., 95 FERC ¶ 61,258
(2001); see also E. Tenn. Nat. Gas LLC, 154 FERC
¶ 61,161 (2016).
74 The Policy Statement also allows projects that
are designed to improve service to existing
customers (i.e., by replacing existing capacity or
improving reliability) to be rolled into system rates.
The Policy Statement explained that increasing the
rates of the existing customers to pay for these
improvements is not a subsidy. Policy Statement,
88 FERC ¶ 61,227 at 61,746 n.12.
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landowners and communities affected
by the proposed project.75
28. The Policy Statement recognized
that the interests of an applicant’s
existing customers may be adversely
affected if the proposed expansion
results in a degradation in service for
existing customers.76 Furthermore, the
interests of an existing pipeline in the
same market area and its captive
customers may be adversely affected by
a new competitor because, under the
Commission’s current rate model,
customer rates on an existing pipeline
can rise to cover the costs of any
capacity that goes unsubscribed due to
volumes (i.e., customers) migrating to a
new competing pipeline.
29. The Commission has historically
taken a pro-competitive approach in
approving new projects, believing that
potential adverse impacts on existing
competitors through the potential future
loss of load are likely to be outweighed
by the economic and reliability benefits
to natural gas consumers that come from
increased access to new supply sources
of competitively-priced natural gas.77
The Commission’s longstanding policy
has been to allow companies to compete
for markets and to uphold the results of
that competition absent a showing of
anticompetitive or unfair competition.78
There have been few instances where
companies or their customers have
raised concerns over the impact that the
construction of a new project would
have on an existing pipeline system or
its captive customers. In those
instances, competitor pipelines have
argued that their captive shippers would
be burdened with stranded costs or
discount adjustments.79 The
Commission has historically not been
persuaded by the objections, finding
that a new pipeline would benefit
consumers through increased
competition.80
30. Finally, under the Policy
Statement, the Commission looks at
adverse impacts on landowners and
75 Id
at 61,745.
part of the certification process the
Commission confirms through engineering analyses
that the proposed facilities are appropriately
designed to provide the proposed new services and
verifies that the proposed project will not adversely
affect the services the applicant is obligated to
provide to its existing customers. See, e.g., Tex. Gas
Transmission, LLC, 152 FERC ¶ 61,160 (2015).
77 E.g., Ruby Pipeline, L.L.C., 128 FERC ¶ 61,224,
at PP 37–39 (2009); Guardian Pipeline, L.L.C., 91
FERC ¶ 61,285, at 61,976–61,977 (2000).
78 Ruby Pipeline, 128 FERC ¶ 61,224 at P 35;
Guardian Pipeline, 91 FERC ¶ 61,285 at 61,977.
79 Ruby Pipeline, 128 FERC ¶ 61,224 at PP 22–26;
Guardian Pipeline, 91 FERC ¶ 61,285 at 61,974–
61,975.
80 Ruby Pipeline, 128 FERC ¶ 61,224 at P 37;
Guardian Pipeline, 91 FERC ¶ 61,285 at 61,976–
61,977.
communities affected by a proposed
project. The Policy Statement noted that
‘‘[t]raditionally, the interests of the
landowners and the surrounding
community have been considered
synonymous with the environmental
impacts of a project,’’ but explains that
‘‘[l]andowner property rights issues are
different in character from other
environmental issues considered under
[NEPA].’’ 81 Since issuance of the Policy
Statement, the Commission’s
environmental analyses have come to
adopt a more expansive consideration of
property rights issues, so issues that
previously might not have been
routinely reviewed in the environmental
document—e.g., a project’s potential
impact on property values, community
development, employment, tax revenue,
and disadvantaged populations—now
are. Thus, these issues are, in effect,
considered twice, once in the context of
the Policy Statement assessment
focusing on economic impacts, and
again in the NEPA review focusing on
environmental impacts. Economic
impacts on landowners and surrounding
communities can be, and often are,
mitigated, for example, through
alternative routing of the proposed
rights-of-way, co-location with existing
utility corridors, and negotiating the
purchase of rights-of-way.82
(b) Public Benefits
31. The Policy Statement identified
various public benefits including: (1)
Meeting unserved demand (2)
eliminating bottlenecks; (3) providing
access to new supplies; (4) lowering
costs to consumers; (5) providing new
interconnects that improve the interstate
pipeline network; (6) providing
competitive alternatives; (7) increasing
electric reliability; and (8) advancing
clean air objectives.83 As evidence of
unserved demand following issuance of
the Policy Statement, applicants have
most often presented precedent
agreements with prospective customers
for long-term firm service.84
76 As
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81 Policy
Statement, 88 FERC ¶ 61,227 at 61,748.
example, Columbia Gas Transmission, LLC,
incorporated eight route variations between
issuance of the draft EIS and final EIS of its Leach
XPress Project to address landowner requests. Final
EIS, at 2–5 (Sept. 1, 2016) (Docket No. CP15–514–
000). Also, Algonquin Gas Transmission, LLC,
collocated 93 percent of its Algonquin Incremental
Market Project pipeline facilities within or adjacent
to existing right-of-ways, including its own
pipelines, public roadways, railways and electric
transmission line corridors. Final EIS, at 2–12 (Jan.
23, 2014) (Docket No. CP14–96–000).
83 Policy Statement, 88 FERC ¶ 61,227 at 61,748.
84 In the order authorizing a new project, the
Commission requires that prior to construction, the
certificate-holder must file a written statement
affirming that it has executed contracts that reflect
82 For
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(c) Balancing Public Benefits and
Adverse Effects
32. The Policy Statement recognized
that, in the context of balancing public
benefits against adverse effects, it is
difficult to construct bright line
standards or tests, as such tests are
unlikely to be flexible enough to resolve
specific cases and to allow the
Commission to take into account
different relevant interests. The Policy
Statement described a sliding scale
approach where the ‘‘more interests
adversely affected or the more adverse
impact a project would have on a
particular interest, the greater the
showing of public benefits from the
project required to balance the adverse
impact.’’ 85
33. The Policy Statement provided
two examples of the sliding scale
approach. First, if an applicant is able
to acquire all or substantially all of the
necessary rights-of-way by negotiation
prior to filing the application, and the
proposal is to serve a new, previously
unserved market, it would not adversely
impact the applicant’s existing shippers,
competing companies or their existing
shippers, or affected landowners and
communities.86 Under these
circumstances, landowners would not
be subject to eminent domain
proceedings, and because the proposed
project would be new, there would be
no existing customers who might be
called upon to subsidize the project. In
the second example, the Policy
Statement recognized that an applicant
may not be able to acquire all the
necessary rights-of-way by negotiation
prior to filing the application.87
Therefore, the applicant might minimize
the effect of the project on landowners
by negotiating to acquire as much of the
rights-of-way as possible. In this case,
the applicant may be called upon to
present some evidence of market
demand, but under the sliding scale
approach, the benefits that would need
to be shown would be less than in a case
where no rights-of-way had been
previously acquired by negotiation. If an
applicant had precedent agreements
with multiple parties for most of the
new capacity, this would be strong
evidence of market demand and
potential public benefits that could
outweigh the inability to negotiate rightof-way agreements with some
landowners.
34. The Policy Statement observed
that a few holdout landowners cannot
the service commitments described in precedent
agreements.
85 Policy Statement, 88 FERC ¶ 61,227 at 61,749.
86 Id.
87 Id.
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veto a project if the applicant provides
evidence of project benefits sufficient to
justify a finding of public convenience
and necessity and issuance of a
certificate.88 The strength of the benefit
showing will need to be proportional to
the applicant’s anticipated reliance on
eminent domain to acquire necessary
property rights. If the Commission finds
project benefits will outweigh adverse
impacts on economic interests, it then
proceeds to consider the results of its
NEPA review in reaching a decision on
whether the proposed project is
required by the public convenience and
necessity.89
I. Commission Precedent and the
Evolution of the Implementation of the
Policy Statement
35. Prior to adopting the Policy
Statement, the Commission required
applicants to show that some percentage
of proposed capacity was subscribed
under long-term firm service
agreements.90 The Policy Statement
adopted a new approach, under which
the Commission would allow an
applicant to rely on a variety of
operational, economic, and
environmental factors to demonstrate
need.91 In practice, applicants have
generally elected to present, and the
Commission has accepted, customer
commitments as the principal factor in
demonstrating project need.92 Today,
many proposed projects are fully, or
nearly fully, subscribed under long-term
firm service agreements that the
Commission accepts as strong evidence
that there is market demand for a
proposed project.93 The Commission
88 Policy
Statement, 88 FERC ¶ 61,227 at 61,749.
practice the environmental document is
prepared concurrently with the analysis of the
economic considerations. However, as described
above, if a project’s anticipated public benefits fail
to outweigh its residual adverse effects on economic
interests, the proposal will be denied and there will
be no need to consider what the environmental
impacts of the project would have been.
90 E.g., El Paso Nat. Gas Co., 65 FERC ¶ 61,276,
at 61,270–61,271 (1993) (requiring applicant to
submit ‘‘long-term’’ contracts or precedent
agreements for a ‘‘substantial amount’’ of proposed
firm transportation capacity); Tex. E. Transmission
Corp., 82 FERC ¶ 61,238, at 61,915–61,917 (1998)
(explaining that a minimum level of 25 percent
evolved after El Paso Natural Gas).
91 Policy Statement, 88 FERC ¶ 61,227 at 61,747
(‘‘the Commission will consider all relevant factors
reflecting on the need for the project. These might
include, but would not be limited to, precedent
agreements, demand projections, potential cost
savings to consumers, or a comparison of projected
demand with the amount of capacity currently
serving the market.’’).
92 See, e.g., PennEast Pipeline Co., LLC, 162 FERC
¶ 61,053, at PP 27–36 (2018) (PennEast); Atlantic
Coast Pipeline, LLC, 161 FERC ¶ 61,042, at PP 56–
63 (2017) (Atlantic Coast).
93 Policy Statement, 88 FERC ¶ 61,227 at 61,743;
see, e.g., PennEast, 162 FERC ¶ 61,053 (990,000
89 In
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has not looked beyond contracts for a
further determination of market or
supply need since the adoption of
incremental pricing and the resultant
shifting of the risk of constructing new
capacity to the pipeline and the
expansion shippers. In instances where
an applicant has neither entered into
any precedent agreements for its project
nor submitted other evidence to show
need, and the project will cause adverse
effects, the Commission has declined to
issue a certificate.94
36. Stakeholders in some proceedings
have raised questions as to whether
precedent agreements continue to be an
appropriate indicator of project need
and whether the Commission should
reconsider its approach to examining
project need. This includes both the
question of the overall need for the
proposed project within the energy
marketplace, as well as the need for the
capacity of individual project shippers.
Specific concerns raised have included:
(1) Whether existing infrastructure can
accommodate the incremental service to
be provided by proposed project; (2)
whether anticipated demand in the
project’s markets will truly materialize;
(3) the potential for renewable energy to
meet future demand for electricity
generation and its potential impacts on
projects designed to serve natural gasfired generators; (4) the need for the
Commission to evaluate the new natural
gas pipeline infrastructure on a regionwide basis; and (5) whether agreements
with affiliates constitute a showing of
market need.
II. The Commission’s NEPA Review
37. Since the early 2000s, the
Commission has encouraged
jurisdictional natural gas companies to
use a voluntary pre-filing program for
natural gas pipeline projects.95 During
the pre-filing process, applicants can
coordinate with Commission staff and
other agencies to identify and resolve
major environmental issues on a project
before filing an application.96 Proposed
Dth/d of 1,107,000 Dth/d capacity subscribed);
Mountain Valley Pipeline, LLC, 161 FERC ¶ 61,043
(2017) (2,000,000 Dth/d fully subscribed); Atlantic
Coast, 161 FERC ¶ 61,042 (1,440,000 Dth/d of
1,500,000 Dth/d capacity subscribed); Rover
Pipeline LLC, 158 FERC ¶ 61,109, at P 44 (2017)
(3,100,000 Dth/d of 3,250,000 Dth/d capacity
subscribed).
94 See, e.g., Jordan Cove Energy Project, L.P., 154
FERC ¶ 61,190, reh’g denied, 157 FERC ¶ 61,194
(2016); Turtle Bayou, 135 FERC ¶ 61,233.
95 In addition, in response to the Energy Policy
Act of 2005, the Commission established pre-filing
regulations, which are mandatory for LNG terminal
facilities. 18 CFR 157.21.
96 The Kern River 2003 Expansion Project (Docket
No. CP01–422–000) was the first project to use the
Commission’s Pre-filing Process.
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projects that would typically benefit
from this pre-filing process have opted
to use it. The pre-filing process allows
applicants and staff to engage in
enhanced and early outreach efforts
with stakeholders, and often results in
major and minor route modifications
prior to the applicant submitting an
application to avoid or minimize
impacts on sensitive environmental
resources identified by Commission
staff, other agencies, federally
recognized tribes, and affected
landowners.97 In addition to enhanced
outreach efforts, during the pre-filing
process Commission staff performs site
visits, consults other agencies and
federally recognized tribes, reviews
drafts of an applicant’s environmental
resource reports, and provides
comments to applicants regarding
alternatives, siting concerns,
inaccuracies, additional surveys or
studies, and needed mitigation plans to
improve the quality of an application.
These efforts routinely result in
improvements and changes to the
proposed projects compared to the
applicants’ initial plan when initiating
the pre-filing process. In conducting its
assessment of the economic effects of a
proposed project after an application is
filed, the Commission can include
relevant information about residual
adverse effects developed in the prefiling process or during a concurrent
environmental review.98
38. In reviewing an application, the
Commission currently performs a
lengthy NEPA review, including
numerous opportunities for public
involvement, consultation with other
federal, state, and local agencies, and an
independent evaluation of the
environmental impacts of a proposed
project. In July 2015, the Commission
issued guidance on best practices for
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97 For
example, after participating in the pre-filing
process and holding over 200 meetings with public
officials, as well as 15 ‘‘informational sessions’’ for
impacted landowners, PennEast incorporated 70 of
101 identified route variations into its final
proposed route. PennEast, 162 FERC ¶ 61,053 at P
39.
98 The early elimination or refinement of
proposals before and during Commission review
leads to a high rate of project certification, subject
to protective conditions. This does not demonstrate
a bias in favor of certification, as past participants
have claimed. See, e.g., NO Gas Pipeline v. FERC,
756 F.3d 764, 770 (DC Cir. 2014) (‘‘Presumably
under most regulatory schemes, by the time
applicants and their expert counsel have worked
through changes, adaptations, and amendments,
they are not likely to pursue many certificates that
are hopeless. The fact that they generally succeed
in choosing to expend their resources on
applications that serve their own financial interests
does not mean that an agency which recognizes
merit in such applications is biased.’’); Minisink
Residents for Envtl. Pres. and Safety v. FERC, 762
F.3d 97, 108 n.7 (DC Cir. 2014) (Minisink) (same).
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stakeholder outreach programs for
natural gas projects.99 This guidance
identifies the various opportunities for
public engagement by project applicants
and Commission staff throughout the
pre-filing and NEPA review process,
including project briefings to elected
officials, open houses, scoping sessions,
agency meetings, site visits, and NEPA
document comment periods.
39. Commission staff performs a
thorough independent review of the
environmental impacts of a proposed
project through verifying submitted
information and comments, issuing
information requests to clarify
inaccuracies or obtain additional
information, and consulting with
federal, state, and local agencies and
federally recognized tribes. Commission
NEPA documents address impacts on
various environmental resources,
including geology, soils, groundwater,
surface water, wetlands, aquatic
resources, vegetation, wildlife, special
status species, cultural resources, land
use, recreation, aesthetics,
socioeconomics, air quality, climate
change, noise, and reliability and safety.
40. Over the past decade there has
been a marked increase in the
involvement of federally recognized
tribes, affected landowners, and
environmental organizations in
proposed natural gas project
proceedings. Concerns raised have
primarily focused on the need for new
projects, alternatives, cumulative
impacts, and the effects related to the
production and consumption of natural
gas (particularly the contribution of
GHG emissions to global climate
change).
A. Alternatives
41. The Commission’s NEPA
documents address a wide variety of
alternatives. These include the noaction alternative (i.e., the status quo),
system alternatives (using existing,
modified, or other proposed gas
facilities), design alternatives (using a
different pipeline diameter, looping
versus compression, and electric-driven
versus gas-driven compressor
equipment), and route and siting
alternatives that could satisfy the
purpose and need of the proposed
project. Alternatives considered include
those contemplated by the applicant
and those proposed by agencies,
99 FERC, Suggested Best Practices for Industry
Outreach Programs to Stakeholders, (2015), https://
www.ferc.gov/industries/gas/enviro/guidelines/
stakeholder-brochure.pdf. See also FERC,
Guidelines for Reporting on Cultural Resources
Investigations for Natural Gas Projects (2017),
https://www.ferc.gov/industries/gas/enviro/
guidelines/cultural-guidelines-final.pdf.
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federally recognized tribes,
stakeholders, and Commission staff.
42. Should the Commission find that
there is insufficient support for the need
for a project, it could select the noaction alternative by rejecting the
proposed project. However, the
Commission has neither authority to
require the construction of any
alternative other than the project
proposed, nor does it have authority to
require the development of
nonjurisdictional actions or projects
(e.g., renewable projects or energy
conservation measures). When an
alternative is not reasonable, i.e., when
it cannot function as a substitute for the
proposed project, the Commission does
not consider it in its NEPA analysis.
B. GHG Emissions and Climate Change
43. GHG emissions are unique in that,
unlike other environmental impacts
studied in pipeline proceedings that
have localized effects, emissions from
around the globe accumulate in the
atmosphere and contribute to climate
change impacts worldwide.100 In 2010,
CEQ issued its first draft guidance on
how federal agencies can consider the
effects of GHG emissions and climate
change under NEPA.101 CEQ revised the
draft guidance in 2014,102 and issued
final guidance in 2016.103 Throughout
the guidance’s evolution, CEQ
consistently advised agencies to
quantify GHG emissions and consider
both the extent to which a proposed
project’s GHG emissions would
contribute to climate change and also
how a changing climate may impact the
proposed project in their NEPA
documents. In April 2017, CEQ
rescinded its 2016 final guidance as
directed by Executive Order 13783
100 On December 15, 2009, the Environmental
Protection Agency (EPA) defined air pollution to
include the mix of six long-lived and directly
emitted GHGs, finding that the presence of GHGs
in the atmosphere may endanger public health and
welfare through climate change. Endangerment
Finding and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the
Clean Air Act, 74 FR 66496 (Dec. 15, 2009).
101 CEQ, Draft NEPA Guidance on Consideration
of the Effects of Climate Change and Greenhouse
Gas Emissions, (Feb. 18, 2010), https://ceq.doe.gov/
docs/ceq-regulations-and-guidance/20100218-nepaconsideration-effects-ghg-draft-guidance.pdf.
102 Revised Draft Guidance for Federal
Departments and Agencies on Consideration of
Greenhouse Gas Emissions and the Effects of
Climate Change in NEPA Reviews, 79 FR 77802
(Dec. 18, 2014) (Revised Draft GHG Guidance).
103 CEQ, Final Guidance for Federal Departments
and Agencies on Consideration of Greenhouse Gas
Emissions and the Effects of Climate Change in
National Environmental Policy Act Reviews, (Aug.
1, 2016) (Final GHG Guidance), https://ceq.doe.gov/
docs/ceq-regulations-and-guidance/nepa_final_
ghg_guidance.pdf.
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Promoting Energy Independence and
Economic Growth.104
44. Since CEQ issued its initial draft
guidance, Commission staff has
addressed climate change in its NEPA
documents. Over the past seven years,
Commission staff has expanded its
efforts to address GHG emissions and
climate change by including GHG
emission estimates from project
construction (e.g., tailpipe emissions
from construction equipment) and
operation (e.g., fuel combustion from
compressor stations and gas venting and
leaks). The Commission’s NEPA
documents also currently include any
mitigation measures the applicant will
employ to reduce GHG emissions,
including mitigation of methane leaks.
Such measures predominantly take the
form of best practices and specific
technologies developed under the EPA’s
Natural Gas STAR Program.105 Further,
the Commission’s NEPA documents
discuss the regulations under the Clean
Air Act applicable to GHG emissions,
recognize that natural gas infrastructure
projects contribute GHG emissions that
affect global climate change, identify the
existing and projected climate change
impacts occurring in a project’s
geographic region, and explain the
impacts that climate change may have
on a specific project (e.g., future sea
level rise and storm surge).106 Current
and projected regional climate change
impacts are based on the most recently
issued National Climate Assessment 107
by the United States Global Change
Research Program.108 The current
assessment provides a regional analysis
of climate change for eight defined
United States regions: Northeast,
Southeast, Northwest, Southwest,
104 Exec. Order No. 13783, 82 FR 16576 (Apr. 5,
2017).
105 EPA’s Natural Gas STAR program is a
voluntary partnership between the EPA and
industry to ‘‘encourage oil and natural gas
companies to adopt cost-effective technologies and
best practices that improve operational efficiency
and reduce methane emissions.’’
106 42 U.S.C. 7401–7671q.
107 The current report is the Third National
Climate Assessment, issued in May 2014. https://
nca2014.globalchange.gov/. The United States
Global Change Research Program anticipates
releasing the Fourth National Climate Assessment
in late 2018.
108 The United States Global Change Research
Program consists of 13 federal agencies and is
overseen by the Subcommittee on Global Change
Research of the National Science and Technology
Council’s Committee on Environment, Natural
Resources and Sustainability, and the White House
Office of Science and Technology Policy. The
federal agencies are the Departments of Agriculture,
Commerce, Defense, Energy, Health and Human
Services, Interior, State, and Transportation, as well
as the EPA, the National Aeronautics and Space
Administration, the National Science Foundation,
the Smithsonian Institution, and the United States
Agency for International Development.
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Midwest, Great Plains, Coasts, and
Alaska.
45. To the extent there exist relevant
federal, regional, state, tribal, or local
plans, policies, or laws for GHG
emissions reductions or climate
adaptations, the Commission’s NEPA
documents address the consistency of a
proposed project’s direct impacts (e.g.,
compressor station emissions) with
those known climate goals. Individual
plans may range in scope and specificity
from, for example, general commitments
to reduce GHG emissions, to particular
plans to reduce GHG emissions by
sector, as well as plans to adapt to a
changing climate.
46. Historically, CEQ recognized the
difficulty in identifying the extent to
which a specific action or project may
contribute to overall climate change,
given that climate change results from
the cumulative buildup of carbon
dioxide and other GHGs, rather than
from the incremental emissions of any
one project. Additionally, there is no
standard established by international or
federal policy, or by a recognized
scientific body that the Commission
could rely on in determining whether
project-specific GHG emissions are
significant. Thus, the Commission has
stated that, given the information
available to date, any attempt by the
Commission to create a significance
threshold would be arbitrary.109 CEQ’s
revised draft and final guidance
cautioned agencies about calculating a
proposed project’s emissions as a
percentage of sector, nationwide, or
global emissions in determining
significance, ‘‘unless the agency
determines that such information would
be helpful to decision makers and the
public to distinguish among alternatives
and mitigations. . . . .’’ 110 Generally,
this percentage would be too low to be
considered meaningful because project
emissions would be miniscule
compared to nationwide or global
emissions. CEQ’s past guidance also
stated that agencies need not undertake
new research or analysis of potential
climate change in the proposed project
area, but may instead summarize and
incorporate by reference the relevant
scientific literature.111
47. In recent years, commenters began
raising GHG issues on an increasingly
frequent basis in Commission
proceedings and on appellate review,
with emphasis on upstream and
109 Fla. Se. Connection, LLC, 162 FERC ¶ 61,233,
at PP 26–27 (2018) (LaFleur and Glick, Comm’rs,
dissenting).
110 Revised Draft GHG Guidance, 79 FR at 77808;
accord Final GHG Guidance at 11, 15–16.
111 Final GHG Guidance at 22.
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downstream GHG emissions.112 Some
commenters suggest that the
Commission’s current analyses of GHG
emissions and climate change are
inadequate. They argue that all projects
relying on fossil fuels should be
considered to cause a significant impact
on climate change. Commenters also
request that the Commission employ the
Social Cost of Carbon tool 113 to
monetize climate change impacts from
estimated GHG emissions.
48. The Commission has generally
declined to consider the upstream or
downstream GHG emissions impacts of
natural gas production or end use as
indirect impacts of the proposed project
because the Commission found no
requisite causation and/or because the
impacts of such production or end use
were speculative and unknown, and
therefore not reasonably foreseeable.114
With respect to the cumulative impacts
analysis in which causation is not
relevant, no analysis of GHG emissions
from upstream and downstream
activities was included except where
identified upstream production wells
(new) or end-use facilities (existing or
proposed) were within the geographic
and temporal scope of the proposed
project’s direct and indirect impacts.115
49. In late 2016 the Commission
began providing the public with
additional information, beyond the
requirements of NEPA and its
implementing regulations, regarding
potential impacts associated with
upstream unconventional natural gas
production and downstream natural gas
combustion even where the criteria of
causation and reasonable foreseeability
112 See, e.g., Atlantic Coast, 161 FERC ¶ 61,042;
Transcontinental Gas Pipe Line Co., LLC, 158 FERC
¶ 61,125, order amending certificate, 159 FERC
¶ 62,181, order on reh’g, 161 FERC ¶ 61,250 (2017),
order denying reh’g, 162 FERC ¶ 61,192 (2018).
113 See generally Interagency Working Group on
Social Cost of Carbon, United States Government,
Technical Support Document: Technical Update of
the Social Cost of Carbon for Regulatory Impact
Analysis Under Executive Order 12866 (Aug. 2016),
https://www.epa.gov/sites/production/files/201612/documents/sc_co2_tsd_august_2016.pdf.
114 See, e.g., Cent. N.Y. Oil & Gas Co., 137 FERC
¶ 61,121, at PP 95–105, on reh’g, 138 FERC
¶ 61,104, at PP 46–48 (2012), aff’d sub nom. Coal.
For Responsible Growth & Res. Conservation v.
FERC, 485 F. App’x 472 (2d Cir. 2012) (unpublished
opinion).
115 For example, in the EIS for the proposed
Aguirre Offshore GasPort, a jurisdictional floating
storage regasification unit and subsea pipeline to
deliver gas to an existing non-jurisdictional
generating complex, Commission staff disclosed the
expected emissions, including GHG emissions, from
both the jurisdictional project and nonjurisdictional generating station. Final EIS for the
Aquirre Offshore GasPort Project,— at 4–221,
tbl.4.12.2–1 (Feb. 20, 2015) (Docket No. CP13–193–
000).
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were absent.116 Recent studies identify,
on a generic, high-level basis, potential
environmental impacts associated with
natural gas production and natural gasfired power generation.117 In
Commission orders for projects
intended to transport gas produced from
the Marcellus and Utica shales, the
Commission used this information to
provide general estimates of productionrelated GHG emissions, such as methane
released from wells and gathering
facilities, and production-related land
disturbance and water consumption.118
The Commission estimated downstream
GHG emissions by assuming the full
combustion of the total volume of gas
capable of being transported by the
project, typically as part of the
cumulative impact analysis.119 The
Commission described the full
combustion estimate as a worst-case
scenario that is unlikely to reflect actual
impacts.120 However, in a recent order,
DTE Midstream Appalachia, LLC,121 the
Commission did not include
information on upstream, productionrelated impacts, stating that ‘‘[a] broad
analysis, based on generalized
assumptions rather than specific
information, will not provide
meaningful assistance to the
Commission in its decision making, e.g.,
evaluating potential alternatives to a
specific proposal.’’ 122
50. As for the use of the Social Cost
of Carbon tool, the Commission has
116 See, e.g., Columbia Gas Transmission, LLC,
158 FERC ¶ 61,046, at PP 116–120 (2017).
117 E.g., National Energy Technology Laboratory,
U.S. Department of Energy, Life Cycle Analysis of
Natural Gas Extraction and Power Generation,
DOE/NETL–2015/1714 (2016), https://
www.netl.doe.gov/energy-analyses/temp/LifeCycle
AnalysisofNaturalGasExtractionandPower
Generation_083016.pdf.
118 E.g., PennEast, 162 FERC ¶ 61,053 at PP 193–
210; Millennium Pipeline Co., LLC, 161 FERC
¶ 61,229, PP 151–165 (2017) (Millennium).
119 This information was initially included in
certificate orders (in cases where NEPA documents
had already been finalized), and subsequently in
new NEPA documents. Typically, the end use of the
gas to be transported by a project is not known.
120 E.g., Millennium, 161 FERC ¶ 61,229, at P 164
(2017) (‘‘We note that this CO2e [carbon dioxide
equivalents] estimate represents an upper bound for
the amount of end-use combustion that could result
from the gas transported by this project. This is
because some of the gas may displace other fuels
(i.e., fuel oil and coal) that could result in lower
total CO2e emissions. It may also displace gas that
otherwise would be transported via different
systems, resulting in no change in CO2e emissions,
or be used as a feedstock. This estimate also
assumes the maximum capacity is transported 365
days per year, which is rarely the case because
many projects are designed for peak use.
Consequently, it is unlikely that this total amount
of GHG emissions would occur, and emissions are
likely to be significantly lower than the above
estimate.’’).
121 162 FERC ¶ 61,238 (2018) (LaFleur and Glick
Comm’rs, dissenting).
122 Id. at P 54 (footnote omitted).
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found that although this tool is
appropriate to use as part of cost-benefit
analyses associated with certain
rulemakings, it is not useful or
appropriate to apply in its NEPA
documents.123
III. Request for Comments
51. As part of ensuring that the
Commission continues to meet its
statutory obligations, the Commission,
on occasion, engages in public inquiry
to gauge whether there is a need to add
to, modify, or eliminate certain policies
or regulatory requirements. In this
proceeding, the Commission seeks
comments on potential modifications to
its approach to determining whether a
proposed project is required by the
public convenience and necessity. The
Commission has identified four general
areas of examination in this inquiry: (1)
The reliance on precedent agreements to
demonstrate need for a proposed
project; (2) the potential exercise of
eminent domain and landowner
interests; (3) the Commission’s
evaluation of alternatives and
environmental effects under NEPA and
the NGA; and (4) the efficiency and
effectiveness of the Commission’s
certificate processes. The Commission
seeks comment on the questions set
forth below, organized according to
these four broad categories. Commenters
need not answer every question
enumerated below.
A. Potential Adjustments to the
Commission’s Determination of Need
52. In practice, the Commission does
not look ‘‘behind’’ or ‘‘beyond’’
precedent agreements when making a
determination about the need for new
projects or the needs of the individual
shippers. The United States Court of
Appeals for the District of Columbia
Circuit recently found ‘‘nothing in the
policy statement or in any precedent
construing it to suggest that it requires,
rather than permits, the Commission to
assess a project’s benefits by looking
beyond the market need reflected by the
applicant’s existing contracts with
shippers.’’ 124
53. In retail gas distribution markets,
state regulators review LDC commodity
and capacity purchases. State regulators
also may review electric distribution
company fuel purchases. Thus, in these
regions, state regulators may review the
purchases to determine the prudence of
expenditures by the utilities they
regulate. For parties purchasing
123 Fla. Se. Connection, 162 FERC ¶ 61,233 at PP
37–38 (LaFleur and Glick, Comm’rs, dissenting).
124 Myersville Citizens for a Rural Cmty. Inc. v
FERC, 783 F.3d 1301, 1311 (D.C. Cir. 2015) (citing
Minisink, 762 F.3d at 111 n.10).
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interstate transportation capacity who
are not subject to state regulatory
oversight, the fact that a purchaser is
fully at risk for the cost of the capacity
and cannot directly pass through the
costs to another party has lessened the
need to scrutinize such agreements.
To date, the Commission has not
distinguished between affiliate and nonaffiliate precedent agreements in
considering the need for a proposed
project.125
54. However, recent changes in the
gas industry, whereby producers are
contracting for an increasing amount of
transportation capacity as well as an
increase in the number of shippers that
are affiliated with the pipeline
companies, have raised questions
among some entities as to whether
precedent agreements remain an
appropriate indicator of need and
whether the Commission should
examine additional information in
evaluating the need for proposed
pipeline infrastructure projects.
Accordingly, comments are requested
on the following questions.
A1. Should the Commission consider
changes in how it determines whether
there is a public need for a proposed
project?
A2. In determining whether there is a public
need for a proposed project, what benefits
should the Commission consider? For
example, should the Commission examine
whether the proposed project meets market
demand, enhances resilience or reliability,
promotes competition among natural gas
companies, or enhances the functioning of
gas markets?
A3. Currently, the Commission considers
precedent agreements, whereby entities
intending to be shippers on the
contemplated pipeline commit
contractually to such shipments, to be
strong evidence that there is a public need
for a proposed project. If the Commission
were to look beyond precedent agreements,
what types of additional or alternative
evidence should the Commission examine
to determine project need? What would
such evidence provide that cannot be
determined with precedent agreements
alone? How should the Commission assess
such evidence? Is there any heightened
litigation risk or other risk that could result
from any broadening of the scope of
evidence the Commission considers during
a certificate proceeding? If so, how should
the Commission safeguard against or
otherwise address such risks?
A4. Should the Commission consider
distinguishing between precedent
agreements with affiliates and nonaffiliates in considering the need for a
proposed project? If so, how?
A5. Should the Commission consider
whether there are specific provisions or
125 See, e.g., E. Shore Nat. Gas Co., 132 FERC
¶ 61,204, at P 31 (2010); Millennium Pipeline Co.,
L.P., 100 FERC ¶ 61,277, at P 57 (2002).
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characteristics of the precedent agreements
that the Commission should more closely
review in considering the need for a
proposed project? For example, should the
term of the precedent agreement have any
bearing on the Commission’s consideration
of need or should the Commission consider
whether the contracts are subject to state
review?
A6. In its determinations regarding project
need, should the Commission consider the
intended or expected end use of the natural
gas? Would consideration of end uses
better inform the Commission’s
determination regarding whether there is a
need for the project? What are the
challenges to determining the ultimate end
use of the new capacity a shipper is
contracting for? How could such
challenges be overcome?
A7. Should the Commission consider
requiring additional or alternative evidence
of need for different end uses? What would
be the effect on pipeline companies,
consumers, gas prices, and competition?
Examples of end uses could include: LDC
contracts to serve domestic use; contracts
with marketers to move gas from a
production area to a liquid trading point;
contracts for transporting gas to an export
facility; projects for reliability and/or
resilience; and contracts for electric
generating resources.
A8. How should the Commission take into
account that end uses for gas may not be
permanent and may change over time?
A9. Should the Commission assess need
differently if multiple pipeline
applications to provide service in the same
geographic area are pending before the
Commission? For example, should the
Commission consider a regional approach
to a needs determination if there are
multiple pipeline applications pending for
the same geographic area? Should the
Commission change the way it considers
the impact of a new project on competing
existing pipeline systems or their captive
shippers? If so, what would that analysis
look like in practice?
A10. Should the Commission consider
adjusting its assessment of need to examine
(1) if existing infrastructure can
accommodate a proposed project (beyond
the system alternatives analysis examined
in the Commission’s environmental
review); (2) if demand in a new project’s
markets will materialize; or (3) if reliance
on other energy sources to meet future
demand for electricity generation would
impact gas projects designed to supply gasfired generators? If so, how?
B. The Exercise of Eminent Domain and
Landowner Interests
55. The Policy Statement described
how the Commission takes into account
the extent to which an applicant expects
to acquire property rights by relying on
eminent domain in determining
whether a proposed project is needed.
Although Commission authorization of
a project through the issuance of a
certificate of public convenience and
necessity under the NGA conveys the
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right of eminent domain, the
Commission itself does not grant the use
of eminent domain across specific
properties. Only after the Commission
authorizes a project can the project
sponsor assert the right of eminent
domain for outstanding lands for which
it could not negotiate an easement.
56. Recently, the Commission has
been seeing more proposed projects
where applicants are unable to access
potential rights-of-way prior to the
Commission’s decision on an
application, which limits the
information that can be included in an
application.
57. Historically, an applicant’s
inability to complete on-site survey
work has not precluded the Commission
from completing a meaningful review of
a proposal since partial on-site surveys,
in combination with aerial overflight
and data from other sources, can
provide an adequate basis for the
Commission to reach an informed
decision. The Commission’s NEPA
documents are based on the best
available data at the time of
development.126 When information
from other data sources is used to
complete a NEPA review, the
Commission routinely conditions its
authorizations requiring applicants to
perform on-site surveys to verify this
information, prior to construction. In
addition, the Commission has
developed standard and effective
construction mitigation, and restoration
and rehabilitation procedures applicable
to wetlands and waterbodies, cultural
resources, and endangered, threatened,
and special concern species.127 Because
project sponsors must adhere to these
established procedures, if survey work
is incomplete at the time a Commission
certificate order is issued, these
procedures assure that impacts on
resources are adequately minimized
126 An agency reasonably uses ‘‘the best
information available when it [begins] its analysis
and then check[s] the assumptions . . . as new
information [becomes] available . . . .’’ Village of
Bensenville v. FAA, 457 F.3d 52, 71 (DC Cir. 2006).
See also 40 CFR 1502.22(b)(3) (if relevant
information is unavailable, ‘‘the agency shall
include . . . a summary of existing credible
scientific evidence’’) (emphasis added).
127 The Commission’s Upland Erosion Control,
Revegetation, and Maintenance Plan establishes
baseline mitigation measures that project sponsors
must implement, except when specifically
exempted by Commission staff, to minimize erosion
and enhance revegetation associated with their
proposed projects. https://www.ferc.gov/industries/
gas/enviro/plan.pdf. The Commission’s Wetland
and Waterbody Construction and Mitigation
Procedures establishes baseline mitigation measures
that project sponsors must implement, except when
specifically exempted by Commission staff, to
minimize the extent and duration of project-related
disturbance on wetlands and waterbodies. https://
www.ferc.gov/industries/gas/enviro/procedures.pdf.
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18031
during construction. The Commission
invites comments on the following
questions.
B1. Should the Commission consider
adjusting its consideration of the potential
exercise of eminent domain in reviewing
project applications? If so, how should the
Commission adjust its approach?
B2. Should applicants take additional
measures to minimize the use of eminent
domain? If so, what should such measures
be? How would that affect a project’s
overall costs? How could such a
requirement affect an applicant’s ability to
adjust a proposed route based on public
input received during the Commission’s
project review?
B3. For proposed projects that will
potentially require the exercise of eminent
domain, should the Commission consider
changing how it balances the potential use
of eminent domain against the showing of
need for the project? Since the amount of
eminent domain used cannot be
established with certainty until after a
Commission order is issued, is it possible
for the Commission to reliably estimate the
amount of eminent domain a proposed
project may use such that the Commission
could use that information during the
consideration of an application?
B4. Does the Commission’s current certificate
process adequately take landowner
interests into account? Are there steps that
applicants and the Commission should
implement to better take landowner
interests into account and encourage
landowner participation in the process? If
so, what should the steps be?
B5. Should the Commission reconsider how
it addresses applications where the
applicant is unable to access portions of
the right-of-way? Should the Commission
consider changes in how it considers
environmental information gathered after
an order authorizing a project is issued?
C. The Commission’s Consideration of
Environmental Impacts
58. Among the goals in the Policy
Statement is the avoidance of
unnecessary disruption of the
environment. The Commission
incorporates a proposed project’s
environmental impacts into the balance
of factors under the public convenience
and necessity standard. Although the
Commission performs a comprehensive
and independent NEPA review, as
described above, there has been
increased stakeholder interest regarding
the alternatives that the Commission
evaluates in its public interest
determination, how the Commission
addresses climate change, and the
evolving science behind GHG emissions
and climate change. Therefore, the
Commission invites comments on the
following ways that the Commission
could review its environmental
evaluations within the bounds of NEPA
and the NGA:
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Federal Register / Vol. 83, No. 80 / Wednesday, April 25, 2018 / Notices
C1. NEPA and its implementing regulations
require an agency to consider reasonable
alternatives to the proposed action.
Currently the Commission considers the
no-action alternative, system alternatives,
design alternatives, and route alternatives.
Should the Commission consider
broadening its environmental analysis to
consider alternatives beyond those that are
currently included? If so, what specific
types of additional alternatives should the
Commission consider?
C2. Are there any environmental impacts that
the Commission does not currently
consider in its cumulative impact analysis
that could be captured with a broader
regional evaluation? If so, how broadly
should regions be defined (e.g., which
states or geographic boundaries best define
different regions), and which
environmental resources considered in
NEPA would be affected on a larger,
regional scale?
C3. In conducting an analysis of a project,
should the Commission consider
calculating the potential GHG emissions
from upstream activities (e.g., the drilling
of natural gas wells)? What information
would be necessary for the Commission to
reliably and accurately conduct this
calculation? Should the Commission also
evaluate the significance of these upstream
impacts? If so, what criteria would be used
to determine the significance of these
impacts?
C4. In conducting an analysis of a project,
should the Commission consider
calculating the potential GHG emissions
from the downstream consumption of the
gas? If so, should the Commission base this
calculation on total consumption, or some
other amount? What information would be
necessary for the Commission to reliably
and accurately conduct this calculation?
Should the Commission also evaluate the
significance of these downstream impacts?
If so, what criteria would be used to
determine the significance of these
impacts?
C5. How would additional information
related to the GHG impacts upstream or
downstream of a proposed project inform
the Commission’s decision on an
application? What topics or criteria should
be included in this additional information?
C6. As part of the Commission’s public
interest determination, should the
Commission consider changing how it
weighs a proposed project’s adverse
environmental impacts against favorable
economic benefits to determine whether
the proposed project is required by the
public convenience and necessity and still
provide regulatory certainty to
stakeholders?
C7. Should the Commission reconsider how
it uses the Social Cost of Carbon tool in its
environmental review of a proposed
project? How could the Commission use
the Social Cost of Carbon tool in its
weighing of the costs versus benefits of a
proposed project? How could the
Commission acquire complete information
to appropriately quantify all of the
monetized costs/negative impacts and
monetized benefits of a proposed project?
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D. Improvements to the Efficiency of the
Commission’s Review Process
59. It is the Commission’s desire to
improve the transparency, timing, and
predictability of the Commission’s
certification process.128 In addition, as
noted above, Executive Order 13807
encourages agencies to make timely
decisions with the goal of completing all
Federal environmental reviews and
authorization decisions for major
infrastructure projects within 2 years.
Inefficiencies in project decisionmaking can delay infrastructure
investments, increase project costs, and
block infrastructure that would benefit
the economy.
60. The Commission seeks comment
on the following questions regarding its
certificate application review process:
processing software should be filed in
native applications or print-to-PDF
format and not in a scanned format.
Commenters filing electronically do not
need to make a paper filing.
63. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
64. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
D1. Should certain aspects of the
Commission’s application review process
(i.e., pre-filing, post-filing, and post-orderissuance) be shortened, performed
concurrently with other activities, or
eliminated, to make the overall process
more efficient? If so, what specific changes
could the Commission consider
implementing?
D2. Should the Commission consider
changes to the pre-filing process? How can
the Commission ensure the most effective
participation by interested stakeholders
during the pre-filing process and how
would any such changes affect the
implementation and duration of the prefiling process?
D3. Are there ways for the Commission to
work more efficiently and effectively with
other agencies, federal and state, that have
a role in the certificate review process? If
so, how?
D4. Are there classes of projects that should
appropriately be subject to a shortened
process? What would the shortened
process entail?
V. Document Availability
IV. Comment Procedures
61. The Commission invites interested
persons to submit comments on the
matters and issues proposed in this
notice, including any related matters or
alternative proposals that commenters
may wish to discuss. Comments are due
June 25, 2018. Comments must refer to
Docket No. PL18–1–000, and must
include the commenter’s name, the
organization they represent, if
applicable, and their address in their
comments.
62. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
website at https://www.ferc.gov. The
Commission accepts most standard
word-processing formats. Documents
created electronically using word-
65. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the internet through the
Commission’s Home Page (https://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
eastern time) at 888 First Street NE,
Room 2A, Washington, DC 20426.
66. From the Commission’s Home
Page on the internet, this information is
available on eLibrary. The full text of
this document is available on eLibrary
in PDF and Microsoft Word format for
viewing, printing, and/or downloading.
To access this document in eLibrary,
type the docket number excluding the
last three digits of this document in the
docket number field.
67. User assistance is available for
eLibrary and the Commission’s website
during normal business hours from the
Commission’s Online Support at 202–
502–6652 (toll free at 1–866–208–3676)
or email at ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
By direction of the Commission.
Issued: April 19, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2018–08658 Filed 4–24–18; 8:45 am]
BILLING CODE 6717–01–P
128 E.g., Tenn. Gas Pipeline Co., L.L.C., 162 FERC
¶ 61,167, at PP 49–51 (2018) (order addressing
timely intervention).
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]]>Agencies
[Federal Register Volume 83, Number 80 (Wednesday, April 25, 2018)]
[Notices]
[Pages 18020-18032]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-08658]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. PL18-1-000]
Certification of New Interstate Natural Gas Facilities
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Notice of Inquiry.
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SUMMARY: In this Notice of Inquiry, the Federal Energy Regulatory
Commission (Commission) seeks information and stakeholder perspectives
to help the
[[Page 18021]]
Commission explore whether, and if so how, it should revise its
approach under its currently effective policy statement on the
certification of new natural gas transportation facilities to determine
whether a proposed natural gas project is or will be required by the
present or future public convenience and necessity, as that standard is
established in section 7 of the Natural Gas Act.
DATES: Comments are due June 25, 2018.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways:
Electronic Filing through https://www.ferc.gov. Documents
created electronically using word processing software should be filed
in native applications or print-to-PDF format and not in a scanned
format.
Mail/Hand Delivery: Those unable to file electronically
may mail or hand-deliver comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document.
FOR FURTHER INFORMATION CONTACT:
Thomas Chandler (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, 202-502-6699.
Maggie Suter (Technical Information), Office of Energy Projects,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, 202-502-6463.
Caroline Wozniak (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, 202-502-8931.
Brian White (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, 202-502-8332.
SUPPLEMENTARY INFORMATION:
1. In this Notice of Inquiry, the Commission seeks information and
stakeholder perspectives to help the Commission explore whether, and if
so how, it should revise its approach under its currently effective
policy statement on the certification of new natural gas transportation
facilities (Policy Statement) \1\ to determine whether a proposed
natural gas project is or will be required by the present or future
public convenience and necessity, as that standard is established in
section 7 of the Natural Gas Act (NGA).\2\ Specifically, the Commission
seeks input on whether, and if so how, the Commission should adjust:
(1) Its methodology for determining whether there is a need for a
proposed project, including the Commission's consideration of precedent
agreements and contracts for service as evidence of such need; (2) its
consideration of the potential exercise of eminent domain and of
landowner interests related to a proposed project; and (3) its
evaluation of the environmental impact of a proposed project. Finally,
the Commission seeks input on whether there are specific changes the
Commission could consider implementing to improve the efficiency and
effectiveness of its certificate processes including pre-filing, post-
filing, and post-order issuance.
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\1\ Certification of New Interstate Natural Gas Pipeline
Facilities, 88 FERC ] 61,227 (1999), clarified, 90 FERC ] 61,128,
further clarified, 92 FERC ] 61,094 (2000) (Policy Statement).
\2\ 15 U.S.C. 717f.
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2. Nineteen years have passed since the Commission issued the
Policy Statement to describe the criteria and analytical steps that the
Commission uses to balance a proposed natural gas pipeline project's
public benefits against its potential adverse consequences. That period
has seen significant changes, such as: (1) A revolution in natural gas
production technology leading to dramatic increases in production; (2)
new areas of major natural gas production; (3) flows on pipeline
systems becoming bidirectional or reversing; (4) customers routinely
entering into long-term precedent agreements for firm service during
the formative stage of potential projects and the use of those
precedent agreements as applicants' principal evidence of the need for
their projects; (5) the increased use of natural gas as a fuel source
for electric generation, resulting in a closer relationship between
natural gas transportation and natural gas-fired electric generation;
(6) increased concerns expressed by landowners and communities
potentially affected \3\ by proposed projects; (7) an increased
interest regarding the Commission's evaluation of the impact that
greenhouse gas (GHG) emissions associated with a proposed project have
on global climate change; (8) an increased focus on environmental
concerns within the NGA public interest determination; and (9) a desire
to generally expand or limit the Commission's evaluation under the
National Environmental Policy Act of 1969 (NEPA).\4\
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\3\ The total miles of interstate natural gas pipeline
authorized by the Commission on an annual basis has fluctuated over
time, but in recent years reached a high of 2,739 miles in 2017. See
generally Federal Energy Regulatory Commission, 2017 State of the
Markets Report, at 4 (Apr. 2018), www.ferc.gov/market-oversight/market-oversight.asp (providing the number of approved pipelines
projects and miles for 2017).
\4\ 42 U.S.C. 4332-4370f.
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3. The Commission's aim in this proceeding is the same as in the
Policy Statement: ``to appropriately consider the enhancement of
competitive transportation alternatives, the possibility of over
building, the avoidance of unnecessary disruption of the environment,
and the unneeded exercise of eminent domain.'' \5\ In issuing this
Notice of Inquiry, the Commission seeks information to examine the
Policy Statement and its application, as well as the structure and
scope of the Commission's environmental analysis of proposed natural
gas projects. Further, it is the Commission's desire to improve the
transparency, timing, and predictability of the Commission's
certification process. To these ends, we encourage commenters to
identify, with specificity, any perceived issues with the Commission's
current analytical and procedural approaches and to provide detailed
recommendations to address these issues.
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\5\ Policy Statement, 88 FERC ] 61,227 at 61,737.
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4. During the pendency of this proceeding, the Commission intends
to continue to process natural gas facility matters before it
consistent with the Policy Statement, and to make determinations on the
issues raised in those proceedings on a case-by-case basis.\6\ Should
the Commission decide to generally revise its procedures as a result of
this proceeding, it will address at that time how and when those
changes will be implemented. The Commission will decide any next steps
with regard to this review of the Policy Statement after the Commission
has reviewed the comments filed in response to this Notice of Inquiry.
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\6\ The Commission is aware that some of the issues raised in
this Notice of Inquiry may overlap with issues raised in pending
matters. In this Notice of Inquiry proceeding, the Commission will
consider only generic issues, and will not consider any comments
that refer to open, contested Commission proceedings.
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I. Background
A. The Natural Gas Act of 1938
5. The NGA declares ``that the business of transporting and selling
natural gas for ultimate distribution to the public is affected with a
public interest, and that Federal regulation in matters relating to the
transportation of
[[Page 18022]]
natural gas and the sale thereof in interstate and foreign commerce is
necessary in the public interest.'' \7\ NGA section 7(c) requires that
any person seeking to construct or operate a facility for the
transportation of natural gas in interstate commerce must obtain a
certificate of public convenience and necessity from the Commission.\8\
Under NGA section 7(e), the Commission shall issue a certificate to any
qualified applicant upon finding that the construction and operation of
the proposed project--whether pipeline, storage, or liquefaction
facilities--``is or will be required by the present or future public
convenience and necessity.'' \9\ The Commission's regulations provide
for public notice and the opportunity to intervene in certificate
proceedings to comment on or protest an application, and to participate
in the environmental review process.\10\ If an applicant receives a
certificate from the Commission, NGA section 7(h) authorizes the
certificate holder to acquire the property rights necessary to
construct and operate its project by use of eminent domain if it cannot
reach a voluntary agreement with a landowner.\11\
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\7\ 15 U.S.C. 717(a).
\8\ Id. 717f(c)(1)(A).
\9\ Id. 717f(e).
\10\ See generally 18 CFR 157.1-157.22 (regulations governing
applications); id. pt. 380 (implementing NEPA, the Endangered
Species Act, and the National Historic Preservation Act, and
prescribing environmental reports for Natural Gas Act applications).
\11\ 15 U.S.C. 717f(h).
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6. The public convenience and necessity standard encompasses all
factors bearing on the public interest.\12\ The words ``public
interest,'' however, are ``not a broad license to promote the general
public welfare.'' \13\ The Supreme Court has stated that:
---------------------------------------------------------------------------
\12\ Atl. Refining Co. v. Pub. Serv. Comm'n of N.Y., 360 U.S.
378, 391 (1959).
\13\ NAACP v. Fed. Power Comm'n, 425 U.S. 662, 669-70 (1976).
in order to give content and meaning to the words `public
interest' as used in the [Federal] Power and [Natural] Gas Acts, it
is necessary to look to the purposes for which the Acts were
adopted. In the case of the Power and Gas Acts it is clear that the
principal purpose of those Acts was to encourage the orderly
development of plentiful supplies of electricity and natural gas at
reasonable prices.\14\
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\14\ Id.
7. As part of its decision-making process, the Commission, in
accord with the Policy Statement, determines whether there is a need
for a proposed project. This analysis is distinct from that required by
the Council on Environmental Quality (CEQ) regulations, which specify
that environmental documents contain a ``purpose and need statement''
used to determine the objectives of the proposed action and then to
identify and consider reasonable alternative actions.\15\ Under the
NGA, the Commission will take into account all information in the
record from the applicant, parties to the proceeding, commenters, and
the environmental document to determine whether a proposed project is
required by the public convenience and necessity.\16\
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\15\ 40 CFR 1502.13.
\16\ Fed. Power Comm'n v. Transcontinental Gas Pipe Line Corp.,
365 U.S. 1, 23 (1961).
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8. The Commission's powers under NGA section 7 are limited. The
Commission can issue a certificate for a proposed project, subject to
``such reasonable terms and conditions as the public convenience and
necessity may require.'' \17\ The Commission can deny an application
if, and only if, a balancing of all of the factors weighs against
authorization of the proposed project.\18\ The Policy Statement
explains that relevant factors reflecting the need for the project
might include, but would not be limited to, precedent agreements,
demand projections, potential cost savings to consumers, or a
comparison of projected demand with the amount of capacity currently
serving the market while adverse effects include economic, competitive,
environmental, or other effects on the relevant interests.\19\ We note
the Commission only has authority over facilities for the
transportation of natural gas in interstate commerce. The Commission
has no authority to certificate intrastate facilities or facilities for
the production, gathering, or local distribution of natural gas.\20\
Nor does the Commission have jurisdiction over facilities used for the
generation of electric energy.\21\
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\17\ 15 U.S.C. 717f(e).
\18\ See, e.g., Transcontinental Gas Pipe Line Corp., 365 U.S.
at 17 (the Commission ``can only exercise a veto power over proposed
transportation and it can only do this when a balance of all the
circumstances weighs against certification'').
\19\ Policy Statement, 88 FERC ] 61,227 at 61,747.
\20\ NGA section 1(b) states that Commission authority applies
to interstate transportation of natural gas and sales for resale,
``but shall not apply to any other transportation or sale of natural
gas or to the local distribution of natural gas or to the facilities
used for such distribution or to the production or gathering of
natural gas.'' 15 U.S.C. 717(b).
\21\ Section 201 of the Federal Power Act states, the Commission
``shall not have jurisdiction, except as specifically provided in
this Part and the Part next following, over facilities used for the
generation of electric energy.'' 16 U.S.C. 824.
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B. The National Environmental Policy Act of 1969
9. The Commission's consideration of an application triggers
environmental review under NEPA.\22\ NEPA and its implementing
regulations require that before taking a major action, such as action
on an application for a natural gas project, an agency must take a
``hard look'' at the environmental consequences of the proposed action
and at alternatives, and disclose its analysis to the public.\23\
Regulations issued by the CEQ to implement NEPA \24\ require agencies,
including the Commission, to consider the environmental impacts of a
proposed action, generally by preparing either an Environmental
Assessment (EA) or an Environmental Impact Statement (EIS).\25\ The
requirements of NEPA are procedural: They are intended to disclose
impacts and allow for informed decision-making, but do not mandate a
particular result or give preeminent weight to environmental
considerations.\26\
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\22\ 42 U.S.C. 4332(2)(C).
\23\ Baltimore Gas & Elec. Co. v. Nat. Res. Defense Council,
Inc., 462 U.S. 87, 97 (1983) (discussing the twin aims of NEPA).
\24\ 40 CFR 1500.1-1508.28.
\25\ Id. 1501.4 (detailing when to prepare an EA versus an EIS).
\26\ Robertson v. Methow Valley Citizen's Council, 490 U.S. 332,
350 (1989); see also Baltimore Gas & Elec. Co., 462 U.S. at 97
(citing Stryckers' Bay Neighborhood Council v. Karlen, 444 U.S. 223,
227 (1980)).
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10. An agency's environmental document must include a statement to
``briefly specify the underlying purpose and need to which the agency
is responding in proposing the alternatives including the proposed
action.'' \27\ Agencies use the purpose and need statement to define
the objectives of a proposed action and then to identify and consider
reasonable alternatives.\28\ Agencies consider alternatives ``that are
practical or feasible from the technical and economic standpoint and
using common sense, rather than simply desirable from the standpoint of
the applicant.'' \29\ An agency need only evaluate alternatives that
can satisfy the purpose and need of the proposed project, and the
evaluation is shaped by the application and the function that the
agency plays in the decisional process.\30\ Alternatives that are not
environmentally preferable, not able to
[[Page 18023]]
provide equivalent services, uneconomic, speculative ventures as
opposed to planned projects, or otherwise inadequate to function as a
serviceable alternative to the proposed project may be eliminated so
long as the agency briefly discusses the reasons for the
elimination.\31\
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\27\ 40 CFR 1508.9 (describing requirements for an EA).
\28\ Colo. Envtl. Coal. v. Dombeck, 185 F.3d 1162, 1175 (10th
Cir. 1999).
\29\ Forty Most Asked Questions Concerning CEQ's National
Environmental Policy Act Regulations, 46 FR 18026, 18027 (Mar. 23,
1981).
\30\ Citizens Against Burlington, Inc. v. Busey, 938 F.2d 190,
195, 199 (DC Cir. 1991).
\31\ 40 CFR 1502.14(a). See, e.g., Bradwood Landing LLC, 126
FERC ] 61,035, at P 158 (2009); Broadwater Energy LLC, 124 FERC ]
61,225, at PP 187-189 (2008) (rejecting alternatives that were not
technically and economically feasible and practical, or did not
offer significant environmental advantages over the proposed project
or its components, or were unavailable and/or incapable of being
implemented, or do not meet the applicants' stated project
objectives).
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11. Commission documents under NEPA first address the scope of the
project (i.e., ``the range of actions, alternatives, and impacts to be
considered'') \32\, then address the environmental impacts of the
proposed action, connected actions, and cumulative actions.\33\
Commission documents under NEPA may also address similar actions if a
combined analysis would be the best way to adequately assess combined
impacts.\34\ These NEPA documents disclose and evaluate the direct,
indirect, and cumulative impacts of the project on various
environmental resources in the context of temporary, short-term, long-
term, and permanent impacts, and then consider practical measures to
avoid, minimize, or mitigate those impacts. Direct impacts are caused
by the proposed action and occur at the same time and place. Indirect
impacts are ``caused by the [proposed] action and are later in time or
farther removed in distance, but are still reasonably foreseeable.''
\35\ Cumulative impacts are defined as ``the impact on the environment
which results from the incremental impact of the [proposed] action when
added to other past, present, and reasonably foreseeable future
actions, regardless of what agency (Federal or non-Federal) or person
undertakes such actions.'' \36\ The impacts of these other actions must
occur within the same geographic area and same time period in which the
proposed project's impacts will occur.\37\
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\32\ 40 CFR 1508.25.
\33\ Id. 1508.25(a)(1)-(2).
\34\ Id. 1508.25(a)(3).
\35\ Id. 1508.8(b).
\36\ Id. 1508.7.
\37\ ``[A] consideration of cumulative impacts must also
consider `[c]losely related and proposed or reasonably foreseeable
actions that are related by timing or geography.''' O'Reilly v. U.S.
Army Corps of Engineers, 477 F.3d 225 at 234 (5th Cir. 2007)
(quoting Vieux Carre Prop. Owners, Residents, & Assocs., Inc. v.
Pierce, 719 F.2d 1272, 1277 (5th Cir. 1983)); see also CEQ,
Considering Cumulative Effects Under the National Environmental
Policy Act, at 12-16 (Jan. 1997), https://www.energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/G-CEQ-ConsidCumulEffects.pdf.
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C. Conditions and Considerations Leading to the Development of the
Policy Statement
12. Historically, the Commission established prices for natural gas
sales and transportation, and there was little competition for gas
supply or transportation capacity. Interstate pipelines, operating as
merchants, produced and/or purchased natural gas at the wellhead,
transported it to a city gate, and sold it to a local distribution
company (LDC) at a Commission-regulated price that reflected combined
(i.e., bundled) commodity and transportation costs. Congress and the
Commission introduced increasingly competitive elements into this
merchant model. The Natural Gas Policy Act of 1978 began the process of
decontrolling wellhead natural gas prices and eased barriers between
intrastate and interstate markets.\38\ The Commission issued Order No.
436, which initiated open access transportation to allow downstream gas
users, such as LDCs and industrial customers, to buy gas directly from
producers or merchants and transport their gas on interstate
pipelines.\39\ The Wellhead Decontrol Act of 1989 lifted remaining
price controls on wellhead sales as of January 1, 1993.\40\ In 1992,
the Commission issued Order No. 636 to ``reflect and finally complete
the evolution to competition in the natural gas industry initiated by
[the above-cited statutory and regulatory revisions] so that all
natural gas suppliers, including the pipeline as merchant, will compete
for gas purchasers on an equal footing.'' \41\ As a result, natural gas
markets have changed from being highly regulated to being largely
driven by competition and market forces. Instead of merchant pipelines
delivering natural gas to customers at a Commission-regulated bundled
price, most natural gas pipelines have exited the merchant business and
now provide unbundled transportation and storage services. As a result,
shippers are able to purchase natural gas at the wellhead or from gas
marketers, trade gas among themselves, and purchase pipeline and
storage capacity from marketers and other shippers in the secondary
market as well as directly from the pipeline. These changes have
benefitted natural gas consumers by providing a wider range of options
in pipeline services.
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\38\ 15 U.S.C. 3301-3432.
\39\ Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, FERC Stats. & Regs. ] 30,665 (1985), vacated and
remanded, Associated Gas Distribs. v. FERC, 824 F.2d 981 (D.C. Cir.
1987), readopted on an interim basis, Order No. 500, FERC Stats. &
Regs. ] 30,761 (1987), remanded, Am. Gas Ass'n v. FERC, 888 F.2d 136
(D.C. Cir. 1989), readopted, Order No. 500-H, FERC Stats. & Regs. ]
30,867 (1989), reh'g granted in part and denied in part, Order No.
500-I, FERC Stats. & Regs. ] 30,880 (1990), aff'd in part and
remanded in part, Am. Gas Ass'n v. FERC, 912 F.2d 1496 (D.C. Cir.
1990), order on remand, Order No. 500-J, FERC Stats. & Regs. ]
30,915, order on remand, Order No. 500-K, FERC Stats. & Regs. ]
30,917, reh'g denied, Order No. 500-L (1991).
\40\ Public Law 101-60, 103 Stat. 157 (1989).
\41\ Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation; and Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol, Order No.
636, FERC Stats. & Regs. ] 30,939, at 30,391 (footnote omitted),
order on reh'g, Order No. 636-A, FERC Stats. & Regs. ] 30,950, order
on reh'g, Order No. 636-B, 61 FERC 61,272 (1992), order on
reh'g, 62 FERC 61,007 (1993), aff'd in part and remanded
in part sub nom. United Dist. Cos. v. FERC, 88 F.3d 1105 (D.C. Cir.
1996), order on remand, Order No. 636-C, 78 FERC ] 61,186 (1997).
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13. As natural gas commodity and transportation markets were
becoming more competitive, the 1990s saw significant growth in natural
gas consumption in the industrial and electric generation segments.
This prompted jurisdictional natural gas companies to urge the
Commission to expeditiously authorize new projects to meet anticipated
growth in demand. Due to the lower capital costs and shorter
construction times of advanced combined-cycle gas-fired plants in
comparison with conventional coal-fired plants, and the relative
environmental benefits of natural gas compared to coal combustion,
industry forecasts at the time showed natural gas-fired electric
generation demand tripling in the following twenty years and overall
gas demand reaching 32 Trillion Cubic Feet (Tcf) by 2020.\42\
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\42\ Energy Information Administration (EIA), Natural Gas 1998:
Issues and Trends, DOE/EIA-0560(98), at 71, 109, 115 (Apr. 1999).
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14. In addition, in the 1990s, many LDCs were going through
significant changes as they implemented retail unbundling programs,
also known as customer choice programs, on their systems. Prior to
retail unbundling, LDCs, similar to interstate pipelines, provided a
composite bundled service to customers that included the bundled price
of the gas and associated pipeline capacity and the price of the
distribution service. Retail unbundling programs provided residential
and commercial customers with access to competitive markets through the
ability to purchase gas supplies from retail marketers that may be
different from their LDCs. As a result, LDCs were not certain to what
degree they would continue to be responsible for purchasing gas
supplies and pipeline capacity in order to provide service for their
core retail customers. Because of
[[Page 18024]]
this uncertainty, many LDCs sought to reduce their firm contract
commitments with interstate pipelines, both in terms of the duration
and quantity of firm service (this reduction in service is referred to
as capacity turnback). In light of the capacity turnback situation and
potential stranded cost issues that arose on certain pipelines
following restructuring, many LDCs were concerned about the impact any
new pipeline expansion construction could have on the value of their
existing pipeline capacity contracts, and the potential rate
implications of overbuilding.\43\ These concerns were exacerbated by
the fact that the Commission's pricing policy for new construction
prior to the Policy Statement called for expansion project costs to be
rolled into existing system costs to derive rolled-in rates in a future
NGA section 4 rate case.\44\ At that time, the Commission generally
ruled in favor of rolled-in rates when the cost impact of the expansion
project, spread across the pipeline's system, resulted in a rate impact
on existing customers of five percent or less and the expansion
provided operational and/or financial benefits to the system.\45\ All
shippers bore some burden of the expansion project's cost, whether they
benefitted from the project or not, without being allowed to adjust
their contracted volumes. LDCs and other parties believed that this
pricing policy sent the wrong price signals by masking the real costs
of an expansion project and could result in overbuilding of capacity
and subsidization of an expansion by a pipeline's existing shippers.
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\43\ See, e.g., Policy Statement, 88 FERC ] 61,227 at 61,741
(summarizing comments from the American Gas Association, Baltimore
Gas and Electric Company, and Philadelphia Gas Works requesting that
pipelines not be allowed to impose the costs of unsubscribed
capacity created through the construction of excess capacity on
existing shippers).
\44\ Pricing Policy for New and Existing Facilities Constructed
by Interstate Natural Gas Pipelines, 71 FERC ] 61,241 (1995), order
on reh'g, 75 FERC ] 61,105 (1996).
\45\ Id., 71 FERC ] 61,241 at 61,916-61,917.
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D. Proceedings Leading to the Policy Statement, Purpose of the Policy
Statement, and the Issues It Sought To Address
15. In response to the concerns described above, the Commission
issued the Notice of Proposed Rulemaking (NOPR), Regulation of Short-
Term Natural Gas Transportation Services,\46\ and the Notice of
Inquiry, Regulation of Interstate Natural Gas Transportation
Services,\47\ to explore issues related to its policies on
certification and pricing of new construction projects. In the NOPR,
the Commission asked questions relating to many of the issues that have
arisen in recent certificate proceedings including: Whether the
Commission should look behind the precedent agreements or contracts
presented as evidence of market demand to assess independently the
market's need for additional gas service; whether the Commission should
apply a different standard to precedent agreements or contracts with
affiliates than with non-affiliates; whether the Commission should, in
an effort to check overbuilding and capacity turnback, take a harder
look at proposals that are designed to compete for existing market
share rather than bring service to a new customer base; and whether the
Commission should apply a different standard to project sponsors who do
not plan to use either federal or state-granted rights of eminent
domain to acquire right-of-way.\48\
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\46\ Regulation of Short-Term Natural Gas Transportation
Services, Notice of Proposed Rulemaking, FERC Stats. & Regs. ]
32,533 (1998) (cross-referenced at 84 FERC ] 61,085).
\47\ Regulation of Interstate Natural Gas Transportation
Services, Notice of Inquiry, FERC. Stats. & Regs. ] 35,533 (1998)
(cross-referenced at 84 FERC ] 61,087).
\48\ NOPR, FERC Stats. & Regs. ] 32,533 at 33,489-90.
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16. Information received in these proceedings, as well as
experience evaluating proposals for new pipeline construction,
persuaded the Commission to revisit its policy for certificating new
construction.\49\ The Commission issued the Policy Statement intending
that it would provide the natural gas industry with guidance as to how
the Commission would evaluate applications for new natural gas
projects. The Commission sought ``to foster competitive markets,
protect captive customers, and avoid unnecessary environmental and
community impacts while serving increasing demands for natural gas.''
\50\
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\49\ Policy Statement, 88 FERC ] 61,227 at 61,737.
\50\ Id. at 61,743. These same aims apply to this Notice of
Inquiry.
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17. These objectives were realized primarily by a shift from
rolled-in pricing to incremental pricing. Under incremental pricing,
existing customers using existing facilities do not contribute to, and
thereby do not subsidize, the cost of constructing and operating new
projects.\51\ Applicants can recover the costs of the new facilities
only from shippers who use them, and are fully at risk for the cost of
the new facilities and will bear the financial burden of any
unsubscribed capacity. In the Policy Statement, the Commission reasoned
that incremental pricing would send the proper price signals for new
construction and indicate whether a project is financially viable.\52\
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\51\ The Policy Statement recognized there may be instances
where expansion project costs should be rolled into the rates of
existing customers; for example, when inexpensive expansibility is
made possible because of earlier, costly construction. In such a
case, ``because the existing customers bear the cost of the earlier,
more costly construction in their rates, incremental pricing could
result in the new customers receiving a subsidy from the existing
customers because the new customers would not face the full cost of
the construction that makes their new service possible.'' Policy
Statement, 88 FERC ] 61,227 at 61,746.
\52\ Id.
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18. The Policy Statement stated that the Commission will approve an
application for a new project only if its public benefits outweigh its
residual adverse effects.\53\ The Policy Statement described this
balancing of benefits and adverse effects as an economic test.\54\ In
addition to the economic screen established by the Policy Statement,
the Commission simultaneously considers the environmental impacts of a
proposed project and imposes mitigation measures to address potential
environmental impacts.
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\53\ Id. at 61,745.
\54\ Id.
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E. Changed Circumstances Since Issuance of the Policy Statement
19. Over the last decade, the United States has seen an
unprecedented change in the dynamics of the natural gas market and the
supply and demand forces driving it. Led by advancements in production
technologies, primarily in accessing shale reserves, natural gas
supplies have increased dramatically. Domestic natural gas production
has increased from 21.3 Tcf in 2010 to 26.9 Tcf in 2017.\55\ The Energy
Information Administration's (EIA) Annual Energy Outlook 2018 forecasts
continued supply growth over the next 25 years, increasing to nearly 39
Tcf by 2035 and 43 Tcf by 2050.\56\ In addition, driven by liquefied
natural gas (LNG) exports, increased pipeline exports to Mexico, and
reduced imports from Canada, the EIA shows that the United States
became a net exporter of natural gas in 2017.\57\
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\55\ EIA, Natural Gas Summary (Mar. 30, 2018) (in table see row
labeled ``Dry Production;'' click link in the final column to view
history) (Natural Gas Summary), https://www.eia.gov/dnav/ng/ng_sum_lsum_dcu_nus_a.htm.
\56\ EIA, Annual Energy Outlook 2018, at tbl.13 (Feb. 6, 2018)
(in table see row labeled ``Dry Gas Production'' under the reference
case) (Annual Energy Outlook 2018), https://www.eia.gov/outlooks/aeo/data/browser/#/ ?id=13-AEO2018&cases=ref2018&sourcekey=0.
\57\ Natural Gas Summary (in table compare rows labeled
``Imports'' and ``Exports'').
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20. As natural gas production has increased, so has demand, rising
from
[[Page 18025]]
24.1 Tcf in 2010 to 27.1 Tcf in 2017, driven in part by an increase in
gas-fired electric generation.\58\ The EIA's 2018 Annual Energy Outlook
projects continued growth in domestic demand to over 31.4 Tcf by 2035
and nearly 35 Tcf by 2050.\59\
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\58\ Id. (in table see row labeled ``Total Consumption;'' click
link in the final column to view history).
\59\ Annual Energy Outlook 2018, at tbl.13 (in table see row
labeled ``Consumption by Sector'' under the reference case).
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21. Increases in both domestic and international demand for natural
gas produced in the United States, combined with the availability of
competitively-priced gas from shale reserves and associated gas
extracted in tandem with oil, have reduced prices and price volatility
and shifted the emphasis of the types of proposed natural gas
infrastructure projects from storage to transportation and exports,
leading to the Commission receiving and approving an increased number
of pipeline and LNG export terminal applications since 2010.\60\ Much
of the increased production is attributable to Appalachian shale
deposits, predominately the Marcellus and Utica, located in
Pennsylvania, West Virginia, Ohio, and New York.\61\ Although these
areas have historically produced natural gas, the volumes had been
relatively small and much of the infrastructure in the area was built
to deliver natural gas to traditional regional markets and was not able
to transport the burgeoning supply volumes to more distant markets
without significant system expansions. In response to this take-away
bottleneck, the Commission received a host of applications proposing
either to construct greenfield pipelines \62\ to transport gas out of
the region or to increase the capacity of existing infrastructure
through the addition of compression and pipeline looping.\63\ Other
producing areas have also experienced a dramatic growth in output
starting in the mid-2000s, from traditional oil and gas fields in the
Permian Basin in West Texas to the more recently developed Bakken Shale
Formation in North Dakota. This increased production has also prompted
applications to add capacity to transport gas to consumers.
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\60\ In 2010, the Commission authorized about 24 pipeline
projects comprising 9.2 billion cubic feet (Bcf) per day, 20 storage
projects comprising 149 Bcf per day capacity with 5.6 Bcf per day
deliverability, and no LNG import/export facilities. In 2017, the
Commission authorized about 49 pipeline projects comprising 30.8 Bcf
per day and 2 storage projects comprising no new capacity but
increased deliverability. Between 2014 and 2017 the Commission also
authorized 13 LNG import/export projects for 16 Bcf per day
deliverability.
\61\ New York's shale reserves remain undeveloped due to a
prohibition on high-volume hydraulic fracturing in effect since
2008.
\62\ A greenfield pipeline is defined as a new pipeline system
that is operated as a separately regulated company with its own
rates and tariff. For example, the NEXUS Project is a greenfield
pipeline. NEXUS Gas Transmission, LLC, 160 FERC ] 61,022 (2017).
\63\ A pipeline loop is a segment of pipe constructed parallel
to an existing pipeline to increase capacity. For example, Southern
Natural Gas Company, L.L.C.'s Fairburn Expansion Project includes a
1.6-mile-long, 30-inch-diameter pipeline loop to add capacity to the
system. S. Nat. Gas Co., L.L.C., 162 FERC ] 61,122 (2018).
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22. In addition, contracting patterns are changing significantly as
a result of the supply growth. In the past, LDCs contracted for a large
percentage of the total interstate pipeline capacity, transporting
supplies from the production area to their customers. Increasingly,
however, LDCs are purchasing gas supplies further downstream at market
area pooling points or their citygates as other parties increasingly
contract for pipeline capacity. Natural gas producers are now
contracting for an increasing amount of firm pipeline capacity on
expansion projects in an effort to provide a secured commercial outlet
for their supplies. For many of these projects, producers are
interested in transporting their natural gas to the nearest pooling
point on the pipeline system, where the gas can be sold to other
parties serving downstream markets. Therefore, an increasing number of
projects are being designed to transport gas to a point of distribution
on the interstate pipeline grid, which may not correspond to a defined
market or end use.
F. Executive Order 13807, ``Establishing Discipline and Accountability
in the Environmental Review and Permitting Process for Infrastructure
Projects''
23. On August 15, 2017, President Trump issued Executive Order
13807 ``Establishing Discipline and Accountability in the Environmental
Review and Permitting Process for Infrastructure Projects'' to ``ensure
that the Federal environmental review and permitting process for
infrastructure projects is coordinated, predictable, and transparent.''
\64\ Executive Order 13807 states that inefficiencies in the project
decision-making process, including the management of environmental
reviews and permit decisions or authorizations, ``have delayed
infrastructure investments, increased project costs, and blocked the
American people from enjoying improved infrastructure that would
benefit our economy, society, and environment.'' \65\ Executive Order
13807 sets forth several components of its policy, including to
``ensure that Federal authorities make informed decisions concerning
the environmental impacts of infrastructure projects,'' ``provide
transparency and accountability to the public regarding environmental
review and authorization decisions,'' and ``make timely decisions with
the goal of completing all Federal environmental reviews and
authorization decisions for major infrastructure projects within 2
years.'' \66\ The Commission is committed to carrying out the goals of
Executive Order 13807 to improve the efficiency, timing, and overall
predictability of the Commission's certification process.\67\
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\64\ Exec. Order No. 13807, 82 FR 40463, 40463 (Aug. 15, 2017).
\65\ Id.
\66\ Id. Executive Order 13807 defines ``major infrastructure
project'' as ``an infrastructure project for which multiple
authorizations by Federal agencies will be required to proceed with
construction, the lead Federal agency has determined that it will
prepare an environmental impact statement'' under NEPA ``and the
project sponsor has identified the reasonable availability of funds
sufficient to complete the project.'' Id. 40464.
\67\ The Commission is a signatory to the Memorandum of
Understanding Implementing the One Federal Decision under Executive
Order 13807, which is available at https://www.whitehouse.gov/wp-content/uploads/2018/04/MOU-One-Federal-Decision-m-18-13-Part-2.pdf.
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G. The Commission's Evaluation Under the Policy Statement
24. The Policy Statement explained that the Commission will
consider whether a proposed project's anticipated public benefits
outweigh its residual adverse effects on economic interests. If so, the
Commission will then complete an analysis of the project's
environmental impacts and incorporate those findings in reaching a
conclusion on whether a project is required by the public convenience
and necessity. If not, an application will be denied and there will be
no reason to consider environmental impacts.\68\
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\68\ E.g., Turtle Bayou Gas Storage Co., LLC, 135 FERC ] 61,233
(2014) (Turtle Bayou).
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25. Because the NEPA review typically takes longer than the review
of the non-environmental aspects of a proposed project, in practice the
Commission often initiates its study of environmental impacts at the
applicant's request during pre-filing and before an application is
filed. Also, most natural gas projects require approvals from numerous
other federal, state, and local agencies or federally recognized Indian
tribes.\69\ Coordinating with other agencies and ensuring that NEPA
documents adequately address the
[[Page 18026]]
concerns of agencies, federally recognized tribes,\70\ and stakeholders
can extend the time needed to complete the NEPA review process.
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\69\ For example, projects may require Clean Water Act section
401 water quality certifications, Clean Air Act permits, and
concurrence letters or Biological Opinions from the National Marine
Fisheries Service or United States Fish and Wildlife Service.
\70\ The Commission consults with potentially affected federally
recognized Indian tribes as set forth in our tribal consultation
policy statement. Policy Statement on Consultation with Indian
Tribes in Commission Proceedings, Order No. 635, FERC Stats. & Regs.
] 31,148 (2003) (cross-referenced at 104 FERC ] 61,108).
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H. Applying the Policy Statement
1. Threshold Requirement
26. The Policy Statement's threshold requirement is that an
applicant financially support the project without relying on
subsidization from its existing customers.\71\ For greenfield projects,
this is the case by definition, as these new projects have no existing
customers.\72\ For existing jurisdictional natural gas companies, the
Policy Statement's adoption of incremental rates as the default pricing
mechanism for new capacity ensures that the project sponsor and its
expansion customers bear all the economic risks of constructing and
operating new facilities, without subsidization from the company's
existing customers.\73\ When an existing natural gas company proposes
to use its existing system rates as initial recourse rates for an
expansion, the natural gas company is required to demonstrate that the
incremental revenue received would exceed the incremental cost of the
new project before being granted approval to roll the costs of the
expansion into its system rates, thereby ensuring existing customers
will not subsidize the expansion.\74\
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\71\ Policy Statement, 88 FERC ] 61,227 at 61,746.
\72\ E.g., Sierrita Gas Pipeline, LLC, 147 FERC ] 61,192 (2014).
\73\ Trailblazer Pipeline Co., 95 FERC ] 61,258 (2001); see also
E. Tenn. Nat. Gas LLC, 154 FERC ] 61,161 (2016).
\74\ The Policy Statement also allows projects that are designed
to improve service to existing customers (i.e., by replacing
existing capacity or improving reliability) to be rolled into system
rates. The Policy Statement explained that increasing the rates of
the existing customers to pay for these improvements is not a
subsidy. Policy Statement, 88 FERC ] 61,227 at 61,746 n.12.
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2. Factors To Be Balanced in Assessing the Need for a New Project
(a) Potential Adverse Effects on Affected Interests
27. When the no-subsidy threshold requirement is met, the next step
in the Commission's analysis is to determine whether the applicant has
eliminated or minimized any residual adverse effects the project might
have on: (1) The applicant's existing customers, (2) existing pipelines
in the market and their captive customers, and (3) landowners and
communities affected by the proposed project.\75\
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\75\ Id at 61,745.
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28. The Policy Statement recognized that the interests of an
applicant's existing customers may be adversely affected if the
proposed expansion results in a degradation in service for existing
customers.\76\ Furthermore, the interests of an existing pipeline in
the same market area and its captive customers may be adversely
affected by a new competitor because, under the Commission's current
rate model, customer rates on an existing pipeline can rise to cover
the costs of any capacity that goes unsubscribed due to volumes (i.e.,
customers) migrating to a new competing pipeline.
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\76\ As part of the certification process the Commission
confirms through engineering analyses that the proposed facilities
are appropriately designed to provide the proposed new services and
verifies that the proposed project will not adversely affect the
services the applicant is obligated to provide to its existing
customers. See, e.g., Tex. Gas Transmission, LLC, 152 FERC ] 61,160
(2015).
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29. The Commission has historically taken a pro-competitive
approach in approving new projects, believing that potential adverse
impacts on existing competitors through the potential future loss of
load are likely to be outweighed by the economic and reliability
benefits to natural gas consumers that come from increased access to
new supply sources of competitively-priced natural gas.\77\ The
Commission's longstanding policy has been to allow companies to compete
for markets and to uphold the results of that competition absent a
showing of anticompetitive or unfair competition.\78\ There have been
few instances where companies or their customers have raised concerns
over the impact that the construction of a new project would have on an
existing pipeline system or its captive customers. In those instances,
competitor pipelines have argued that their captive shippers would be
burdened with stranded costs or discount adjustments.\79\ The
Commission has historically not been persuaded by the objections,
finding that a new pipeline would benefit consumers through increased
competition.\80\
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\77\ E.g., Ruby Pipeline, L.L.C., 128 FERC ] 61,224, at PP 37-39
(2009); Guardian Pipeline, L.L.C., 91 FERC ] 61,285, at 61,976-
61,977 (2000).
\78\ Ruby Pipeline, 128 FERC ] 61,224 at P 35; Guardian
Pipeline, 91 FERC ] 61,285 at 61,977.
\79\ Ruby Pipeline, 128 FERC ] 61,224 at PP 22-26; Guardian
Pipeline, 91 FERC ] 61,285 at 61,974-61,975.
\80\ Ruby Pipeline, 128 FERC ] 61,224 at P 37; Guardian
Pipeline, 91 FERC ] 61,285 at 61,976-61,977.
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30. Finally, under the Policy Statement, the Commission looks at
adverse impacts on landowners and communities affected by a proposed
project. The Policy Statement noted that ``[t]raditionally, the
interests of the landowners and the surrounding community have been
considered synonymous with the environmental impacts of a project,''
but explains that ``[l]andowner property rights issues are different in
character from other environmental issues considered under [NEPA].''
\81\ Since issuance of the Policy Statement, the Commission's
environmental analyses have come to adopt a more expansive
consideration of property rights issues, so issues that previously
might not have been routinely reviewed in the environmental document--
e.g., a project's potential impact on property values, community
development, employment, tax revenue, and disadvantaged populations--
now are. Thus, these issues are, in effect, considered twice, once in
the context of the Policy Statement assessment focusing on economic
impacts, and again in the NEPA review focusing on environmental
impacts. Economic impacts on landowners and surrounding communities can
be, and often are, mitigated, for example, through alternative routing
of the proposed rights-of-way, co-location with existing utility
corridors, and negotiating the purchase of rights-of-way.\82\
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\81\ Policy Statement, 88 FERC ] 61,227 at 61,748.
\82\ For example, Columbia Gas Transmission, LLC, incorporated
eight route variations between issuance of the draft EIS and final
EIS of its Leach XPress Project to address landowner requests. Final
EIS, at 2-5 (Sept. 1, 2016) (Docket No. CP15-514-000). Also,
Algonquin Gas Transmission, LLC, collocated 93 percent of its
Algonquin Incremental Market Project pipeline facilities within or
adjacent to existing right-of-ways, including its own pipelines,
public roadways, railways and electric transmission line corridors.
Final EIS, at 2-12 (Jan. 23, 2014) (Docket No. CP14-96-000).
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(b) Public Benefits
31. The Policy Statement identified various public benefits
including: (1) Meeting unserved demand (2) eliminating bottlenecks; (3)
providing access to new supplies; (4) lowering costs to consumers; (5)
providing new interconnects that improve the interstate pipeline
network; (6) providing competitive alternatives; (7) increasing
electric reliability; and (8) advancing clean air objectives.\83\ As
evidence of unserved demand following issuance of the Policy Statement,
applicants have most often presented precedent agreements with
prospective customers for long-term firm service.\84\
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\83\ Policy Statement, 88 FERC ] 61,227 at 61,748.
\84\ In the order authorizing a new project, the Commission
requires that prior to construction, the certificate-holder must
file a written statement affirming that it has executed contracts
that reflect the service commitments described in precedent
agreements.
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[[Page 18027]]
(c) Balancing Public Benefits and Adverse Effects
32. The Policy Statement recognized that, in the context of
balancing public benefits against adverse effects, it is difficult to
construct bright line standards or tests, as such tests are unlikely to
be flexible enough to resolve specific cases and to allow the
Commission to take into account different relevant interests. The
Policy Statement described a sliding scale approach where the ``more
interests adversely affected or the more adverse impact a project would
have on a particular interest, the greater the showing of public
benefits from the project required to balance the adverse impact.''
\85\
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\85\ Policy Statement, 88 FERC ] 61,227 at 61,749.
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33. The Policy Statement provided two examples of the sliding scale
approach. First, if an applicant is able to acquire all or
substantially all of the necessary rights-of-way by negotiation prior
to filing the application, and the proposal is to serve a new,
previously unserved market, it would not adversely impact the
applicant's existing shippers, competing companies or their existing
shippers, or affected landowners and communities.\86\ Under these
circumstances, landowners would not be subject to eminent domain
proceedings, and because the proposed project would be new, there would
be no existing customers who might be called upon to subsidize the
project. In the second example, the Policy Statement recognized that an
applicant may not be able to acquire all the necessary rights-of-way by
negotiation prior to filing the application.\87\ Therefore, the
applicant might minimize the effect of the project on landowners by
negotiating to acquire as much of the rights-of-way as possible. In
this case, the applicant may be called upon to present some evidence of
market demand, but under the sliding scale approach, the benefits that
would need to be shown would be less than in a case where no rights-of-
way had been previously acquired by negotiation. If an applicant had
precedent agreements with multiple parties for most of the new
capacity, this would be strong evidence of market demand and potential
public benefits that could outweigh the inability to negotiate right-
of-way agreements with some landowners.
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\86\ Id.
\87\ Id.
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34. The Policy Statement observed that a few holdout landowners
cannot veto a project if the applicant provides evidence of project
benefits sufficient to justify a finding of public convenience and
necessity and issuance of a certificate.\88\ The strength of the
benefit showing will need to be proportional to the applicant's
anticipated reliance on eminent domain to acquire necessary property
rights. If the Commission finds project benefits will outweigh adverse
impacts on economic interests, it then proceeds to consider the results
of its NEPA review in reaching a decision on whether the proposed
project is required by the public convenience and necessity.\89\
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\88\ Policy Statement, 88 FERC ] 61,227 at 61,749.
\89\ In practice the environmental document is prepared
concurrently with the analysis of the economic considerations.
However, as described above, if a project's anticipated public
benefits fail to outweigh its residual adverse effects on economic
interests, the proposal will be denied and there will be no need to
consider what the environmental impacts of the project would have
been.
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I. Commission Precedent and the Evolution of the Implementation of the
Policy Statement
35. Prior to adopting the Policy Statement, the Commission required
applicants to show that some percentage of proposed capacity was
subscribed under long-term firm service agreements.\90\ The Policy
Statement adopted a new approach, under which the Commission would
allow an applicant to rely on a variety of operational, economic, and
environmental factors to demonstrate need.\91\ In practice, applicants
have generally elected to present, and the Commission has accepted,
customer commitments as the principal factor in demonstrating project
need.\92\ Today, many proposed projects are fully, or nearly fully,
subscribed under long-term firm service agreements that the Commission
accepts as strong evidence that there is market demand for a proposed
project.\93\ The Commission has not looked beyond contracts for a
further determination of market or supply need since the adoption of
incremental pricing and the resultant shifting of the risk of
constructing new capacity to the pipeline and the expansion shippers.
In instances where an applicant has neither entered into any precedent
agreements for its project nor submitted other evidence to show need,
and the project will cause adverse effects, the Commission has declined
to issue a certificate.\94\
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\90\ E.g., El Paso Nat. Gas Co., 65 FERC ] 61,276, at 61,270-
61,271 (1993) (requiring applicant to submit ``long-term'' contracts
or precedent agreements for a ``substantial amount'' of proposed
firm transportation capacity); Tex. E. Transmission Corp., 82 FERC ]
61,238, at 61,915-61,917 (1998) (explaining that a minimum level of
25 percent evolved after El Paso Natural Gas).
\91\ Policy Statement, 88 FERC ] 61,227 at 61,747 (``the
Commission will consider all relevant factors reflecting on the need
for the project. These might include, but would not be limited to,
precedent agreements, demand projections, potential cost savings to
consumers, or a comparison of projected demand with the amount of
capacity currently serving the market.'').
\92\ See, e.g., PennEast Pipeline Co., LLC, 162 FERC ] 61,053,
at PP 27-36 (2018) (PennEast); Atlantic Coast Pipeline, LLC, 161
FERC ] 61,042, at PP 56-63 (2017) (Atlantic Coast).
\93\ Policy Statement, 88 FERC ] 61,227 at 61,743; see, e.g.,
PennEast, 162 FERC ] 61,053 (990,000 Dth/d of 1,107,000 Dth/d
capacity subscribed); Mountain Valley Pipeline, LLC, 161 FERC ]
61,043 (2017) (2,000,000 Dth/d fully subscribed); Atlantic Coast,
161 FERC ] 61,042 (1,440,000 Dth/d of 1,500,000 Dth/d capacity
subscribed); Rover Pipeline LLC, 158 FERC ] 61,109, at P 44 (2017)
(3,100,000 Dth/d of 3,250,000 Dth/d capacity subscribed).
\94\ See, e.g., Jordan Cove Energy Project, L.P., 154 FERC ]
61,190, reh'g denied, 157 FERC ] 61,194 (2016); Turtle Bayou, 135
FERC ] 61,233.
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36. Stakeholders in some proceedings have raised questions as to
whether precedent agreements continue to be an appropriate indicator of
project need and whether the Commission should reconsider its approach
to examining project need. This includes both the question of the
overall need for the proposed project within the energy marketplace, as
well as the need for the capacity of individual project shippers.
Specific concerns raised have included: (1) Whether existing
infrastructure can accommodate the incremental service to be provided
by proposed project; (2) whether anticipated demand in the project's
markets will truly materialize; (3) the potential for renewable energy
to meet future demand for electricity generation and its potential
impacts on projects designed to serve natural gas-fired generators; (4)
the need for the Commission to evaluate the new natural gas pipeline
infrastructure on a region-wide basis; and (5) whether agreements with
affiliates constitute a showing of market need.
II. The Commission's NEPA Review
37. Since the early 2000s, the Commission has encouraged
jurisdictional natural gas companies to use a voluntary pre-filing
program for natural gas pipeline projects.\95\ During the pre-filing
process, applicants can coordinate with Commission staff and other
agencies to identify and resolve major environmental issues on a
project before filing an application.\96\ Proposed
[[Page 18028]]
projects that would typically benefit from this pre-filing process have
opted to use it. The pre-filing process allows applicants and staff to
engage in enhanced and early outreach efforts with stakeholders, and
often results in major and minor route modifications prior to the
applicant submitting an application to avoid or minimize impacts on
sensitive environmental resources identified by Commission staff, other
agencies, federally recognized tribes, and affected landowners.\97\ In
addition to enhanced outreach efforts, during the pre-filing process
Commission staff performs site visits, consults other agencies and
federally recognized tribes, reviews drafts of an applicant's
environmental resource reports, and provides comments to applicants
regarding alternatives, siting concerns, inaccuracies, additional
surveys or studies, and needed mitigation plans to improve the quality
of an application. These efforts routinely result in improvements and
changes to the proposed projects compared to the applicants' initial
plan when initiating the pre-filing process. In conducting its
assessment of the economic effects of a proposed project after an
application is filed, the Commission can include relevant information
about residual adverse effects developed in the pre-filing process or
during a concurrent environmental review.\98\
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\95\ In addition, in response to the Energy Policy Act of 2005,
the Commission established pre-filing regulations, which are
mandatory for LNG terminal facilities. 18 CFR 157.21.
\96\ The Kern River 2003 Expansion Project (Docket No. CP01-422-
000) was the first project to use the Commission's Pre-filing
Process.
\97\ For example, after participating in the pre-filing process
and holding over 200 meetings with public officials, as well as 15
``informational sessions'' for impacted landowners, PennEast
incorporated 70 of 101 identified route variations into its final
proposed route. PennEast, 162 FERC ] 61,053 at P 39.
\98\ The early elimination or refinement of proposals before and
during Commission review leads to a high rate of project
certification, subject to protective conditions. This does not
demonstrate a bias in favor of certification, as past participants
have claimed. See, e.g., NO Gas Pipeline v. FERC, 756 F.3d 764, 770
(DC Cir. 2014) (``Presumably under most regulatory schemes, by the
time applicants and their expert counsel have worked through
changes, adaptations, and amendments, they are not likely to pursue
many certificates that are hopeless. The fact that they generally
succeed in choosing to expend their resources on applications that
serve their own financial interests does not mean that an agency
which recognizes merit in such applications is biased.''); Minisink
Residents for Envtl. Pres. and Safety v. FERC, 762 F.3d 97, 108 n.7
(DC Cir. 2014) (Minisink) (same).
---------------------------------------------------------------------------
38. In reviewing an application, the Commission currently performs
a lengthy NEPA review, including numerous opportunities for public
involvement, consultation with other federal, state, and local
agencies, and an independent evaluation of the environmental impacts of
a proposed project. In July 2015, the Commission issued guidance on
best practices for stakeholder outreach programs for natural gas
projects.\99\ This guidance identifies the various opportunities for
public engagement by project applicants and Commission staff throughout
the pre-filing and NEPA review process, including project briefings to
elected officials, open houses, scoping sessions, agency meetings, site
visits, and NEPA document comment periods.
---------------------------------------------------------------------------
\99\ FERC, Suggested Best Practices for Industry Outreach
Programs to Stakeholders, (2015), https://www.ferc.gov/industries/gas/enviro/guidelines/stakeholder-brochure.pdf. See also FERC,
Guidelines for Reporting on Cultural Resources Investigations for
Natural Gas Projects (2017), https://www.ferc.gov/industries/gas/enviro/guidelines/cultural-guidelines-final.pdf.
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39. Commission staff performs a thorough independent review of the
environmental impacts of a proposed project through verifying submitted
information and comments, issuing information requests to clarify
inaccuracies or obtain additional information, and consulting with
federal, state, and local agencies and federally recognized tribes.
Commission NEPA documents address impacts on various environmental
resources, including geology, soils, groundwater, surface water,
wetlands, aquatic resources, vegetation, wildlife, special status
species, cultural resources, land use, recreation, aesthetics,
socioeconomics, air quality, climate change, noise, and reliability and
safety.
40. Over the past decade there has been a marked increase in the
involvement of federally recognized tribes, affected landowners, and
environmental organizations in proposed natural gas project
proceedings. Concerns raised have primarily focused on the need for new
projects, alternatives, cumulative impacts, and the effects related to
the production and consumption of natural gas (particularly the
contribution of GHG emissions to global climate change).
A. Alternatives
41. The Commission's NEPA documents address a wide variety of
alternatives. These include the no-action alternative (i.e., the status
quo), system alternatives (using existing, modified, or other proposed
gas facilities), design alternatives (using a different pipeline
diameter, looping versus compression, and electric-driven versus gas-
driven compressor equipment), and route and siting alternatives that
could satisfy the purpose and need of the proposed project.
Alternatives considered include those contemplated by the applicant and
those proposed by agencies, federally recognized tribes, stakeholders,
and Commission staff.
42. Should the Commission find that there is insufficient support
for the need for a project, it could select the no-action alternative
by rejecting the proposed project. However, the Commission has neither
authority to require the construction of any alternative other than the
project proposed, nor does it have authority to require the development
of nonjurisdictional actions or projects (e.g., renewable projects or
energy conservation measures). When an alternative is not reasonable,
i.e., when it cannot function as a substitute for the proposed project,
the Commission does not consider it in its NEPA analysis.
B. GHG Emissions and Climate Change
43. GHG emissions are unique in that, unlike other environmental
impacts studied in pipeline proceedings that have localized effects,
emissions from around the globe accumulate in the atmosphere and
contribute to climate change impacts worldwide.\100\ In 2010, CEQ
issued its first draft guidance on how federal agencies can consider
the effects of GHG emissions and climate change under NEPA.\101\ CEQ
revised the draft guidance in 2014,\102\ and issued final guidance in
2016.\103\ Throughout the guidance's evolution, CEQ consistently
advised agencies to quantify GHG emissions and consider both the extent
to which a proposed project's GHG emissions would contribute to climate
change and also how a changing climate may impact the proposed project
in their NEPA documents. In April 2017, CEQ rescinded its 2016 final
guidance as directed by Executive Order 13783
[[Page 18029]]
Promoting Energy Independence and Economic Growth.\104\
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\100\ On December 15, 2009, the Environmental Protection Agency
(EPA) defined air pollution to include the mix of six long-lived and
directly emitted GHGs, finding that the presence of GHGs in the
atmosphere may endanger public health and welfare through climate
change. Endangerment Finding and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74 FR
66496 (Dec. 15, 2009).
\101\ CEQ, Draft NEPA Guidance on Consideration of the Effects
of Climate Change and Greenhouse Gas Emissions, (Feb. 18, 2010),
https://ceq.doe.gov/docs/ceq-regulations-and-guidance/20100218-nepa-consideration-effects-ghg-draft-guidance.pdf.
\102\ Revised Draft Guidance for Federal Departments and
Agencies on Consideration of Greenhouse Gas Emissions and the
Effects of Climate Change in NEPA Reviews, 79 FR 77802 (Dec. 18,
2014) (Revised Draft GHG Guidance).
\103\ CEQ, Final Guidance for Federal Departments and Agencies
on Consideration of Greenhouse Gas Emissions and the Effects of
Climate Change in National Environmental Policy Act Reviews, (Aug.
1, 2016) (Final GHG Guidance), https://ceq.doe.gov/docs/ceq-regulations-and-guidance/nepa_final_ghg_guidance.pdf.
\104\ Exec. Order No. 13783, 82 FR 16576 (Apr. 5, 2017).
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44. Since CEQ issued its initial draft guidance, Commission staff
has addressed climate change in its NEPA documents. Over the past seven
years, Commission staff has expanded its efforts to address GHG
emissions and climate change by including GHG emission estimates from
project construction (e.g., tailpipe emissions from construction
equipment) and operation (e.g., fuel combustion from compressor
stations and gas venting and leaks). The Commission's NEPA documents
also currently include any mitigation measures the applicant will
employ to reduce GHG emissions, including mitigation of methane leaks.
Such measures predominantly take the form of best practices and
specific technologies developed under the EPA's Natural Gas STAR
Program.\105\ Further, the Commission's NEPA documents discuss the
regulations under the Clean Air Act applicable to GHG emissions,
recognize that natural gas infrastructure projects contribute GHG
emissions that affect global climate change, identify the existing and
projected climate change impacts occurring in a project's geographic
region, and explain the impacts that climate change may have on a
specific project (e.g., future sea level rise and storm surge).\106\
Current and projected regional climate change impacts are based on the
most recently issued National Climate Assessment \107\ by the United
States Global Change Research Program.\108\ The current assessment
provides a regional analysis of climate change for eight defined United
States regions: Northeast, Southeast, Northwest, Southwest, Midwest,
Great Plains, Coasts, and Alaska.
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\105\ EPA's Natural Gas STAR program is a voluntary partnership
between the EPA and industry to ``encourage oil and natural gas
companies to adopt cost-effective technologies and best practices
that improve operational efficiency and reduce methane emissions.''
\106\ 42 U.S.C. 7401-7671q.
\107\ The current report is the Third National Climate
Assessment, issued in May 2014. https://nca2014.globalchange.gov/.
The United States Global Change Research Program anticipates
releasing the Fourth National Climate Assessment in late 2018.
\108\ The United States Global Change Research Program consists
of 13 federal agencies and is overseen by the Subcommittee on Global
Change Research of the National Science and Technology Council's
Committee on Environment, Natural Resources and Sustainability, and
the White House Office of Science and Technology Policy. The federal
agencies are the Departments of Agriculture, Commerce, Defense,
Energy, Health and Human Services, Interior, State, and
Transportation, as well as the EPA, the National Aeronautics and
Space Administration, the National Science Foundation, the
Smithsonian Institution, and the United States Agency for
International Development.
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45. To the extent there exist relevant federal, regional, state,
tribal, or local plans, policies, or laws for GHG emissions reductions
or climate adaptations, the Commission's NEPA documents address the
consistency of a proposed project's direct impacts (e.g., compressor
station emissions) with those known climate goals. Individual plans may
range in scope and specificity from, for example, general commitments
to reduce GHG emissions, to particular plans to reduce GHG emissions by
sector, as well as plans to adapt to a changing climate.
46. Historically, CEQ recognized the difficulty in identifying the
extent to which a specific action or project may contribute to overall
climate change, given that climate change results from the cumulative
buildup of carbon dioxide and other GHGs, rather than from the
incremental emissions of any one project. Additionally, there is no
standard established by international or federal policy, or by a
recognized scientific body that the Commission could rely on in
determining whether project-specific GHG emissions are significant.
Thus, the Commission has stated that, given the information available
to date, any attempt by the Commission to create a significance
threshold would be arbitrary.\109\ CEQ's revised draft and final
guidance cautioned agencies about calculating a proposed project's
emissions as a percentage of sector, nationwide, or global emissions in
determining significance, ``unless the agency determines that such
information would be helpful to decision makers and the public to
distinguish among alternatives and mitigations. . . . .'' \110\
Generally, this percentage would be too low to be considered meaningful
because project emissions would be miniscule compared to nationwide or
global emissions. CEQ's past guidance also stated that agencies need
not undertake new research or analysis of potential climate change in
the proposed project area, but may instead summarize and incorporate by
reference the relevant scientific literature.\111\
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\109\ Fla. Se. Connection, LLC, 162 FERC ] 61,233, at PP 26-27
(2018) (LaFleur and Glick, Comm'rs, dissenting).
\110\ Revised Draft GHG Guidance, 79 FR at 77808; accord Final
GHG Guidance at 11, 15-16.
\111\ Final GHG Guidance at 22.
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47. In recent years, commenters began raising GHG issues on an
increasingly frequent basis in Commission proceedings and on appellate
review, with emphasis on upstream and downstream GHG emissions.\112\
Some commenters suggest that the Commission's current analyses of GHG
emissions and climate change are inadequate. They argue that all
projects relying on fossil fuels should be considered to cause a
significant impact on climate change. Commenters also request that the
Commission employ the Social Cost of Carbon tool \113\ to monetize
climate change impacts from estimated GHG emissions.
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\112\ See, e.g., Atlantic Coast, 161 FERC ] 61,042;
Transcontinental Gas Pipe Line Co., LLC, 158 FERC ] 61,125, order
amending certificate, 159 FERC ] 62,181, order on reh'g, 161 FERC ]
61,250 (2017), order denying reh'g, 162 FERC ] 61,192 (2018).
\113\ See generally Interagency Working Group on Social Cost of
Carbon, United States Government, Technical Support Document:
Technical Update of the Social Cost of Carbon for Regulatory Impact
Analysis Under Executive Order 12866 (Aug. 2016), https://www.epa.gov/sites/production/files/2016-12/documents/sc_co2_tsd_august_2016.pdf.
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48. The Commission has generally declined to consider the upstream
or downstream GHG emissions impacts of natural gas production or end
use as indirect impacts of the proposed project because the Commission
found no requisite causation and/or because the impacts of such
production or end use were speculative and unknown, and therefore not
reasonably foreseeable.\114\ With respect to the cumulative impacts
analysis in which causation is not relevant, no analysis of GHG
emissions from upstream and downstream activities was included except
where identified upstream production wells (new) or end-use facilities
(existing or proposed) were within the geographic and temporal scope of
the proposed project's direct and indirect impacts.\115\
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\114\ See, e.g., Cent. N.Y. Oil & Gas Co., 137 FERC ] 61,121, at
PP 95-105, on reh'g, 138 FERC ] 61,104, at PP 46-48 (2012), aff'd
sub nom. Coal. For Responsible Growth & Res. Conservation v. FERC,
485 F. App'x 472 (2d Cir. 2012) (unpublished opinion).
\115\ For example, in the EIS for the proposed Aguirre Offshore
GasPort, a jurisdictional floating storage regasification unit and
subsea pipeline to deliver gas to an existing non-jurisdictional
generating complex, Commission staff disclosed the expected
emissions, including GHG emissions, from both the jurisdictional
project and non-jurisdictional generating station. Final EIS for the
Aquirre Offshore GasPort Project,-- at 4-221, tbl.4.12.2-1 (Feb. 20,
2015) (Docket No. CP13-193-000).
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49. In late 2016 the Commission began providing the public with
additional information, beyond the requirements of NEPA and its
implementing regulations, regarding potential impacts associated with
upstream unconventional natural gas production and downstream natural
gas combustion even where the criteria of causation and reasonable
foreseeability
[[Page 18030]]
were absent.\116\ Recent studies identify, on a generic, high-level
basis, potential environmental impacts associated with natural gas
production and natural gas-fired power generation.\117\ In Commission
orders for projects intended to transport gas produced from the
Marcellus and Utica shales, the Commission used this information to
provide general estimates of production-related GHG emissions, such as
methane released from wells and gathering facilities, and production-
related land disturbance and water consumption.\118\ The Commission
estimated downstream GHG emissions by assuming the full combustion of
the total volume of gas capable of being transported by the project,
typically as part of the cumulative impact analysis.\119\ The
Commission described the full combustion estimate as a worst-case
scenario that is unlikely to reflect actual impacts.\120\ However, in a
recent order, DTE Midstream Appalachia, LLC,\121\ the Commission did
not include information on upstream, production-related impacts,
stating that ``[a] broad analysis, based on generalized assumptions
rather than specific information, will not provide meaningful
assistance to the Commission in its decision making, e.g., evaluating
potential alternatives to a specific proposal.'' \122\
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\116\ See, e.g., Columbia Gas Transmission, LLC, 158 FERC ]
61,046, at PP 116-120 (2017).
\117\ E.g., National Energy Technology Laboratory, U.S.
Department of Energy, Life Cycle Analysis of Natural Gas Extraction
and Power Generation, DOE/NETL-2015/1714 (2016), https://www.netl.doe.gov/energy-analyses/temp/LifeCycleAnalysisofNaturalGasExtractionandPowerGeneration_083016.pdf.
\118\ E.g., PennEast, 162 FERC ] 61,053 at PP 193-210;
Millennium Pipeline Co., LLC, 161 FERC ] 61,229, PP 151-165 (2017)
(Millennium).
\119\ This information was initially included in certificate
orders (in cases where NEPA documents had already been finalized),
and subsequently in new NEPA documents. Typically, the end use of
the gas to be transported by a project is not known.
\120\ E.g., Millennium, 161 FERC ] 61,229, at P 164 (2017) (``We
note that this CO2e [carbon dioxide equivalents] estimate represents
an upper bound for the amount of end-use combustion that could
result from the gas transported by this project. This is because
some of the gas may displace other fuels (i.e., fuel oil and coal)
that could result in lower total CO2e emissions. It may also
displace gas that otherwise would be transported via different
systems, resulting in no change in CO2e emissions, or be used as a
feedstock. This estimate also assumes the maximum capacity is
transported 365 days per year, which is rarely the case because many
projects are designed for peak use.
Consequently, it is unlikely that this total amount of GHG
emissions would occur, and emissions are likely to be significantly
lower than the above estimate.'').
\121\ 162 FERC ] 61,238 (2018) (LaFleur and Glick Comm'rs,
dissenting).
\122\ Id. at P 54 (footnote omitted).
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50. As for the use of the Social Cost of Carbon tool, the
Commission has found that although this tool is appropriate to use as
part of cost-benefit analyses associated with certain rulemakings, it
is not useful or appropriate to apply in its NEPA documents.\123\
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\123\ Fla. Se. Connection, 162 FERC ] 61,233 at PP 37-38
(LaFleur and Glick, Comm'rs, dissenting).
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III. Request for Comments
51. As part of ensuring that the Commission continues to meet its
statutory obligations, the Commission, on occasion, engages in public
inquiry to gauge whether there is a need to add to, modify, or
eliminate certain policies or regulatory requirements. In this
proceeding, the Commission seeks comments on potential modifications to
its approach to determining whether a proposed project is required by
the public convenience and necessity. The Commission has identified
four general areas of examination in this inquiry: (1) The reliance on
precedent agreements to demonstrate need for a proposed project; (2)
the potential exercise of eminent domain and landowner interests; (3)
the Commission's evaluation of alternatives and environmental effects
under NEPA and the NGA; and (4) the efficiency and effectiveness of the
Commission's certificate processes. The Commission seeks comment on the
questions set forth below, organized according to these four broad
categories. Commenters need not answer every question enumerated below.
A. Potential Adjustments to the Commission's Determination of Need
52. In practice, the Commission does not look ``behind'' or
``beyond'' precedent agreements when making a determination about the
need for new projects or the needs of the individual shippers. The
United States Court of Appeals for the District of Columbia Circuit
recently found ``nothing in the policy statement or in any precedent
construing it to suggest that it requires, rather than permits, the
Commission to assess a project's benefits by looking beyond the market
need reflected by the applicant's existing contracts with shippers.''
\124\
---------------------------------------------------------------------------
\124\ Myersville Citizens for a Rural Cmty. Inc. v FERC, 783
F.3d 1301, 1311 (D.C. Cir. 2015) (citing Minisink, 762 F.3d at 111
n.10).
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53. In retail gas distribution markets, state regulators review LDC
commodity and capacity purchases. State regulators also may review
electric distribution company fuel purchases. Thus, in these regions,
state regulators may review the purchases to determine the prudence of
expenditures by the utilities they regulate. For parties purchasing
interstate transportation capacity who are not subject to state
regulatory oversight, the fact that a purchaser is fully at risk for
the cost of the capacity and cannot directly pass through the costs to
another party has lessened the need to scrutinize such agreements.
To date, the Commission has not distinguished between affiliate and
non-affiliate precedent agreements in considering the need for a
proposed project.\125\
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\125\ See, e.g., E. Shore Nat. Gas Co., 132 FERC ] 61,204, at P
31 (2010); Millennium Pipeline Co., L.P., 100 FERC ] 61,277, at P 57
(2002).
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54. However, recent changes in the gas industry, whereby producers
are contracting for an increasing amount of transportation capacity as
well as an increase in the number of shippers that are affiliated with
the pipeline companies, have raised questions among some entities as to
whether precedent agreements remain an appropriate indicator of need
and whether the Commission should examine additional information in
evaluating the need for proposed pipeline infrastructure projects.
Accordingly, comments are requested on the following questions.
A1. Should the Commission consider changes in how it determines
whether there is a public need for a proposed project?
A2. In determining whether there is a public need for a proposed
project, what benefits should the Commission consider? For example,
should the Commission examine whether the proposed project meets
market demand, enhances resilience or reliability, promotes
competition among natural gas companies, or enhances the functioning
of gas markets?
A3. Currently, the Commission considers precedent agreements,
whereby entities intending to be shippers on the contemplated
pipeline commit contractually to such shipments, to be strong
evidence that there is a public need for a proposed project. If the
Commission were to look beyond precedent agreements, what types of
additional or alternative evidence should the Commission examine to
determine project need? What would such evidence provide that cannot
be determined with precedent agreements alone? How should the
Commission assess such evidence? Is there any heightened litigation
risk or other risk that could result from any broadening of the
scope of evidence the Commission considers during a certificate
proceeding? If so, how should the Commission safeguard against or
otherwise address such risks?
A4. Should the Commission consider distinguishing between precedent
agreements with affiliates and non-affiliates in considering the
need for a proposed project? If so, how?
A5. Should the Commission consider whether there are specific
provisions or
[[Page 18031]]
characteristics of the precedent agreements that the Commission
should more closely review in considering the need for a proposed
project? For example, should the term of the precedent agreement
have any bearing on the Commission's consideration of need or should
the Commission consider whether the contracts are subject to state
review?
A6. In its determinations regarding project need, should the
Commission consider the intended or expected end use of the natural
gas? Would consideration of end uses better inform the Commission's
determination regarding whether there is a need for the project?
What are the challenges to determining the ultimate end use of the
new capacity a shipper is contracting for? How could such challenges
be overcome?
A7. Should the Commission consider requiring additional or
alternative evidence of need for different end uses? What would be
the effect on pipeline companies, consumers, gas prices, and
competition? Examples of end uses could include: LDC contracts to
serve domestic use; contracts with marketers to move gas from a
production area to a liquid trading point; contracts for
transporting gas to an export facility; projects for reliability
and/or resilience; and contracts for electric generating resources.
A8. How should the Commission take into account that end uses for
gas may not be permanent and may change over time?
A9. Should the Commission assess need differently if multiple
pipeline applications to provide service in the same geographic area
are pending before the Commission? For example, should the
Commission consider a regional approach to a needs determination if
there are multiple pipeline applications pending for the same
geographic area? Should the Commission change the way it considers
the impact of a new project on competing existing pipeline systems
or their captive shippers? If so, what would that analysis look like
in practice?
A10. Should the Commission consider adjusting its assessment of need
to examine (1) if existing infrastructure can accommodate a proposed
project (beyond the system alternatives analysis examined in the
Commission's environmental review); (2) if demand in a new project's
markets will materialize; or (3) if reliance on other energy sources
to meet future demand for electricity generation would impact gas
projects designed to supply gas-fired generators? If so, how?
B. The Exercise of Eminent Domain and Landowner Interests
55. The Policy Statement described how the Commission takes into
account the extent to which an applicant expects to acquire property
rights by relying on eminent domain in determining whether a proposed
project is needed. Although Commission authorization of a project
through the issuance of a certificate of public convenience and
necessity under the NGA conveys the right of eminent domain, the
Commission itself does not grant the use of eminent domain across
specific properties. Only after the Commission authorizes a project can
the project sponsor assert the right of eminent domain for outstanding
lands for which it could not negotiate an easement.
56. Recently, the Commission has been seeing more proposed projects
where applicants are unable to access potential rights-of-way prior to
the Commission's decision on an application, which limits the
information that can be included in an application.
57. Historically, an applicant's inability to complete on-site
survey work has not precluded the Commission from completing a
meaningful review of a proposal since partial on-site surveys, in
combination with aerial overflight and data from other sources, can
provide an adequate basis for the Commission to reach an informed
decision. The Commission's NEPA documents are based on the best
available data at the time of development.\126\ When information from
other data sources is used to complete a NEPA review, the Commission
routinely conditions its authorizations requiring applicants to perform
on-site surveys to verify this information, prior to construction. In
addition, the Commission has developed standard and effective
construction mitigation, and restoration and rehabilitation procedures
applicable to wetlands and waterbodies, cultural resources, and
endangered, threatened, and special concern species.\127\ Because
project sponsors must adhere to these established procedures, if survey
work is incomplete at the time a Commission certificate order is
issued, these procedures assure that impacts on resources are
adequately minimized during construction. The Commission invites
comments on the following questions.
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\126\ An agency reasonably uses ``the best information available
when it [begins] its analysis and then check[s] the assumptions . .
. as new information [becomes] available . . . .'' Village of
Bensenville v. FAA, 457 F.3d 52, 71 (DC Cir. 2006). See also 40 CFR
1502.22(b)(3) (if relevant information is unavailable, ``the agency
shall include . . . a summary of existing credible scientific
evidence'') (emphasis added).
\127\ The Commission's Upland Erosion Control, Revegetation, and
Maintenance Plan establishes baseline mitigation measures that
project sponsors must implement, except when specifically exempted
by Commission staff, to minimize erosion and enhance revegetation
associated with their proposed projects. https://www.ferc.gov/industries/gas/enviro/plan.pdf. The Commission's Wetland and
Waterbody Construction and Mitigation Procedures establishes
baseline mitigation measures that project sponsors must implement,
except when specifically exempted by Commission staff, to minimize
the extent and duration of project-related disturbance on wetlands
and waterbodies. https://www.ferc.gov/industries/gas/enviro/procedures.pdf.
B1. Should the Commission consider adjusting its consideration of
the potential exercise of eminent domain in reviewing project
applications? If so, how should the Commission adjust its approach?
B2. Should applicants take additional measures to minimize the use
of eminent domain? If so, what should such measures be? How would
that affect a project's overall costs? How could such a requirement
affect an applicant's ability to adjust a proposed route based on
public input received during the Commission's project review?
B3. For proposed projects that will potentially require the exercise
of eminent domain, should the Commission consider changing how it
balances the potential use of eminent domain against the showing of
need for the project? Since the amount of eminent domain used cannot
be established with certainty until after a Commission order is
issued, is it possible for the Commission to reliably estimate the
amount of eminent domain a proposed project may use such that the
Commission could use that information during the consideration of an
application?
B4. Does the Commission's current certificate process adequately
take landowner interests into account? Are there steps that
applicants and the Commission should implement to better take
landowner interests into account and encourage landowner
participation in the process? If so, what should the steps be?
B5. Should the Commission reconsider how it addresses applications
where the applicant is unable to access portions of the right-of-
way? Should the Commission consider changes in how it considers
environmental information gathered after an order authorizing a
project is issued?
C. The Commission's Consideration of Environmental Impacts
58. Among the goals in the Policy Statement is the avoidance of
unnecessary disruption of the environment. The Commission incorporates
a proposed project's environmental impacts into the balance of factors
under the public convenience and necessity standard. Although the
Commission performs a comprehensive and independent NEPA review, as
described above, there has been increased stakeholder interest
regarding the alternatives that the Commission evaluates in its public
interest determination, how the Commission addresses climate change,
and the evolving science behind GHG emissions and climate change.
Therefore, the Commission invites comments on the following ways that
the Commission could review its environmental evaluations within the
bounds of NEPA and the NGA:
[[Page 18032]]
C1. NEPA and its implementing regulations require an agency to
consider reasonable alternatives to the proposed action. Currently
the Commission considers the no-action alternative, system
alternatives, design alternatives, and route alternatives. Should
the Commission consider broadening its environmental analysis to
consider alternatives beyond those that are currently included? If
so, what specific types of additional alternatives should the
Commission consider?
C2. Are there any environmental impacts that the Commission does not
currently consider in its cumulative impact analysis that could be
captured with a broader regional evaluation? If so, how broadly
should regions be defined (e.g., which states or geographic
boundaries best define different regions), and which environmental
resources considered in NEPA would be affected on a larger, regional
scale?
C3. In conducting an analysis of a project, should the Commission
consider calculating the potential GHG emissions from upstream
activities (e.g., the drilling of natural gas wells)? What
information would be necessary for the Commission to reliably and
accurately conduct this calculation? Should the Commission also
evaluate the significance of these upstream impacts? If so, what
criteria would be used to determine the significance of these
impacts?
C4. In conducting an analysis of a project, should the Commission
consider calculating the potential GHG emissions from the downstream
consumption of the gas? If so, should the Commission base this
calculation on total consumption, or some other amount? What
information would be necessary for the Commission to reliably and
accurately conduct this calculation? Should the Commission also
evaluate the significance of these downstream impacts? If so, what
criteria would be used to determine the significance of these
impacts?
C5. How would additional information related to the GHG impacts
upstream or downstream of a proposed project inform the Commission's
decision on an application? What topics or criteria should be
included in this additional information?
C6. As part of the Commission's public interest determination,
should the Commission consider changing how it weighs a proposed
project's adverse environmental impacts against favorable economic
benefits to determine whether the proposed project is required by
the public convenience and necessity and still provide regulatory
certainty to stakeholders?
C7. Should the Commission reconsider how it uses the Social Cost of
Carbon tool in its environmental review of a proposed project? How
could the Commission use the Social Cost of Carbon tool in its
weighing of the costs versus benefits of a proposed project? How
could the Commission acquire complete information to appropriately
quantify all of the monetized costs/negative impacts and monetized
benefits of a proposed project?
D. Improvements to the Efficiency of the Commission's Review Process
59. It is the Commission's desire to improve the transparency,
timing, and predictability of the Commission's certification
process.\128\ In addition, as noted above, Executive Order 13807
encourages agencies to make timely decisions with the goal of
completing all Federal environmental reviews and authorization
decisions for major infrastructure projects within 2 years.
Inefficiencies in project decision-making can delay infrastructure
investments, increase project costs, and block infrastructure that
would benefit the economy.
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\128\ E.g., Tenn. Gas Pipeline Co., L.L.C., 162 FERC ] 61,167,
at PP 49-51 (2018) (order addressing timely intervention).
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60. The Commission seeks comment on the following questions
regarding its certificate application review process:
D1. Should certain aspects of the Commission's application review
process (i.e., pre-filing, post-filing, and post-order-issuance) be
shortened, performed concurrently with other activities, or
eliminated, to make the overall process more efficient? If so, what
specific changes could the Commission consider implementing?
D2. Should the Commission consider changes to the pre-filing
process? How can the Commission ensure the most effective
participation by interested stakeholders during the pre-filing
process and how would any such changes affect the implementation and
duration of the pre-filing process?
D3. Are there ways for the Commission to work more efficiently and
effectively with other agencies, federal and state, that have a role
in the certificate review process? If so, how?
D4. Are there classes of projects that should appropriately be
subject to a shortened process? What would the shortened process
entail?
IV. Comment Procedures
61. The Commission invites interested persons to submit comments on
the matters and issues proposed in this notice, including any related
matters or alternative proposals that commenters may wish to discuss.
Comments are due June 25, 2018. Comments must refer to Docket No. PL18-
1-000, and must include the commenter's name, the organization they
represent, if applicable, and their address in their comments.
62. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word-processing
formats. Documents created electronically using word-processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
63. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC 20426.
64. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
V. Document Availability
65. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (https://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. eastern time) at 888 First Street NE, Room 2A,
Washington, DC 20426.
66. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
67. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
By direction of the Commission.
Issued: April 19, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2018-08658 Filed 4-24-18; 8:45 am]
BILLING CODE 6717-01-P
