Gas Gathering Line Definition; Alternative Definition for Onshore Lines and New Safety Standards, 13289-13303 [06-2562]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 71, Number 50 (Wednesday, March 15, 2006)]
[Rules and Regulations]
[Pages 13289-13303]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-2562]



[[Page 13289]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-1998-4868; Amdt. 192-102]
RIN 2137-AB15


Gas Gathering Line Definition; Alternative Definition for Onshore 
Lines and New Safety Standards

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), 
DOT.

ACTION: Final rule.

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SUMMARY: This action adopts a consensus standard to distinguish onshore 
gathering lines from other gas pipelines and production operations. In 
addition, it establishes safety rules for certain onshore gathering 
lines in rural areas and revises current rules for certain onshore 
gathering lines in nonrural areas. Operators will use a new risk-based 
approach to determine which onshore gathering lines are subject to 
PHMSA's gas pipeline safety rules and which of these rules the lines 
must meet. PHMSA intends this action to reduce disagreements over 
classifications of onshore gathering lines, increase public confidence 
in the safety of onshore gathering lines, and provide safety rules 
consistent with the risks of onshore gathering lines.

DATES: This final rule takes effect April 14, 2006. The Director of the 
Federal Register approves the incorporation by reference of API RP 80 
in this rule as of April 14, 2006.

FOR FURTHER INFORMATION CONTACT: DeWitt Burdeaux by phone at 405-954-
7220 or by e-mail at dewitt.burdeaux@dot.gov.

SUPPLEMENTARY INFORMATION: 

I. Background

A. Current Regulation of Onshore Gathering Lines; Definition Problem

    Gas gathering lines are pipelines used to collect natural gas from 
production facilities and transport it to transmission or distribution 
lines, which then transports it to the consumer. PHMSA's pipeline 
safety rules in 49 CFR part 192 apply to the transportation of natural 
gas and other gas by pipeline. However, onshore gathering lines in 
rural areas (areas outside cities, towns, villages, or designated 
residential or commercial areas) are subject only to Sec.  192.612, 
which prescribes inspection and burial requirements for lines within 
Gulf of Mexico inlets (Sec. Sec.  192.1(b)(4) and (b)(5)). (Note: Lines 
in these inlets are not covered by this final rule.)
    Under Sec.  192.9, gathering lines in nonrural areas must meet the 
same safety standards for design, construction, testing, operation, and 
maintenance as gas transmission lines, except the requirements of Sec.  
192.150 on passage of an internal inspection device (also known as 
smart pigs) and subpart O on integrity management. In addition, PHMSA's 
drug and alcohol testing regulations in 49 CFR part 199 apply to 
nonrural gas gathering lines.
    Section 192.3 currently defines the terms ``gathering line,'' 
``transmission line,'' and ``distribution line'':

    ``Gathering line'' means a pipeline that transports gas from a 
current production facility to a transmission line or main. 
``Transmission line'' means a pipeline, other than a gathering line, 
that transports gas from a gathering line or storage facility to a 
gas distribution center or storage facility; operates at a hoop 
stress of 20 percent or more of a Specified Minimum Yield Strength 
(SMYS), or transports gas within a storage field. ``Distribution 
line'' means a pipeline other than a gathering or transmission line.

Because these definitions are circular and part 192 does not define 
``production facility,'' operators and government inspectors have had 
difficulty distinguishing regulated gathering lines from unregulated 
production facilities and unregulated gathering lines from regulated 
transmission and distribution lines. Also, the complexity of many 
gathering systems has increased the difficulty of distinguishing 
gathering lines.

B. Past Attempts To Resolve the Definition Problem and Determine the 
Need To Regulate Rural Gathering Lines

    In 1974, DOT tried to correct the problem of distinguishing 
gathering lines by proposing to revise the gathering line definition 
(39 FR 34569; Sept. 26, 1974). However, the proposal was later 
withdrawn because comments indicated many terms and phrases were 
unclear (43 FR 42773; Sept. 21, 1978). Afterward, the problem lingered 
until 1986, when the National Association of Pipeline Safety 
Representatives (NAPSR), a nonprofit association of State pipeline 
safety officials, surveyed its members and reported numerous and 
continuing disagreements with operators over gathering lines. Driven by 
the NAPSR survey, in 1991 DOT again proposed to revise the gathering 
line definition (56 FR 48505; Sept. 25, 1991). However, the public 
response was generally unfavorable, so DOT delayed any further action 
until it collected and considered more information.
    Part 192 does not regulate the safety of most rural gathering lines 
because, until 1992, the pipeline safety law (49 U.S.C. Chapter 601) 
restricted DOT's authority over onshore gathering lines to lines in 
nonrural locations.\1\ In 1992, Congress gave DOT specific authority to 
define gas gathering lines for purposes of safety regulation, and to 
regulate a class of rural gathering lines called ``regulated gathering 
lines'' (49 U.S.C. 60101(a)(21) and 60101(b)). The new authority 
directed DOT to consider functional and operational characteristics in 
defining gathering lines. Further direction was to consider such 
factors as location, length of line, operating pressure, throughput, 
and gas composition in deciding which rural lines warrant regulation. 
This authority also expressly allows PHMSA to depart from the concepts 
of gathering under the Natural Gas Act (15 U.S.C. 717 et seq.)
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    \1\ In 1990 Congress gave DOT limited authority over gathering 
lines in Gulf of Mexico inlets (see Pub. L. 101-599).
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    In 1999, in furtherance of the still open 1991 gathering line 
proceeding and Congress' action on gathering lines, DOT opened a Web 
site for public discussion of the definition problem and the need to 
regulate rural gathering lines (Docket No. PHMSA-1998-4868; 64 FR 
12147; Mar. 11, 1999). The comments mainly focused on the comprehensive 
work by the American Petroleum Institute (API), later published as API 
Recommended Practice 80, ``Guidelines for the Definition of Onshore Gas 
Gathering Lines'' (API RP 80). API RP 80 defines onshore gas gathering 
lines through a series of definitions, descriptions, and diagrams 
intended to represent the varied and complex nature of production and 
gathering in the U.S. Although industry commenters spoke favorably 
about the API RP 80 gathering line definition, NAPSR objected to the 
use of certain ``furthermost downstream'' endpoints to mark the 
beginning and end of gathering. NAPSR's concern was if the definition 
were included in part 192, operators would have an incentive to 
establish or move the endpoints further downstream to reduce the amount 
of regulated pipelines. While considering its next step, DOT published 
an Advisory Bulletin to remind operators it was still regulating 
gathering lines according to court precedents and its prior 
interpretations (67 FR 64447; October 18, 2002).
    Then in 2003, DOT held public meetings in Austin, Texas (68 FR 
62555; November 5, 2003) and Anchorage, Alaska (68 FR 67129; December 
1, 2003)

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to attract more comments on the best way to define gas gathering lines 
and what, if any, safety rules may be needed for rural gathering lines. 
At the meetings, DOT gave the history of the gas gathering issue and 
proffered a ``sliding corridor'' concept as a possible basis for 
deciding which lines should be regulated. Under this concept, 
previously used in a pipeline safety enforcement case, operators would 
slide along their gathering lines an imaginary corridor with dimensions 
1000 feet long and the width would be based on the stress level. 
Wherever the corridor contained five or more dwellings, the gathering 
line would be subject to safety rules, the intensity of which would 
increase with the stress level. Transcripts of both meetings are in the 
docket (PHMSA-1998-4868-120 and 122).
    As a follow-up to these two meetings, DOT published a notice 
extending the time for comments and clarifying its intentions about 
defining and regulating gathering lines (69 FR 5305; February 4, 2004). 
DOT said definitions of production and gathering should not overlap 
State regulations on production and should be capable of consistent 
application by regulators and operators. Also, the notice explained the 
need for comments on an appropriate approach to identify rural lines 
warranting regulation. After the 2003 public meetings, DOT met several 
times with State agency officials, industry representatives, and others 
to obtain views on gathering line risks and the need for safety rules. 
Notes of these informal meetings are in Docket No. PHMSA-1998-4868.

C. Public Comments Resulting From the Public Meetings

    Twenty-three comments were submitted as a result of the public 
meetings and clarification notice. Three industry commenters expressed 
satisfaction with the current part 192 gathering line definition and 
prior DOT interpretations. But most commenters, including a coalition 
of trade associations, urged adoption of API RP 80 as the basis for 
determining onshore gas gathering lines. These commenters believed it 
would result in few, if any, reclassifications of pipelines from 
production to gathering or gathering to transmission. However, NAPSR 
opposed the unqualified use of API RP 80 because of its use of the term 
``furthermost downstream'' to identify the beginning and possible ends 
of gathering. NAPSR suggested several limitations to prevent 
manipulating the term ``furthermost downstream'' to change production 
to gathering or gathering to transmission.
    On the need to regulate rural lines, some trade associations 
contended rural gathering lines generally pose a low risk to public 
safety, citing an incident survey the Gas Processors Association (GPA), 
a trade association representing gatherers and processors, conducted in 
December 2003. These trade associations and the U.S. Department of 
Energy (DOE) suggested that DOT should first identify and analyze the 
risks involved and then target regulations to specific problems. Cook 
Inlet Keeper, a nonprofit organization dedicated to protecting Alaska's 
Cook Inlet Watershed and North Slope Borough, the northernmost county 
of Alaska, advocated regulation of all unregulated lines threatening 
people and the environment. Cook Inlet Keeper also submitted data on 
releases from unregulated pipelines in Alaska.
    GPA presented the survey at a meeting of PHMSA's gas pipeline 
safety advisory committee on February 5, 2004 (Docket No. PHMSA-1998-
4470-120). The survey asked 40 operators of rural gas gathering lines 
about incidents impacting the public during a 5-year period (1999-
2003). The survey showed 58 incidents occurred on 171,768 miles of 
pipeline, about 96 percent of GPA members' gathering lines. The 
incidents resulted in three injuries and one death as well as 
evacuations, minor property damage ($5,000-$25,000), and major property 
damage (over $25,000). Corrosion caused most of the incidents, followed 
by third-party excavation, which produced the most severe consequences 
(including the death and two of the injuries). No other cause occurred 
more than twice. In comparison to transmission incidents reported to 
DOT over the same period, transmission lines impacted the public from 
three to six times more often, even though the reporting threshold for 
property damage was 10 times as high as the survey's threshold. GPA 
attributed the lower impact of rural gathering lines to operators' 
safety practices and to operating conditions generally involving 
sparsely populated areas, low pressures, and small pipe sizes.
    Concerning the approach to regulation, the coalition suggested an 
overall plan covering rural and nonrural lines under which the 
intensity of regulation would increase with risk determined by 
operating parameters and population density. Under the current plan, 
regulated nonrural gathering lines posing a lower risk would be subject 
to fewer safety rules than they are now. ONEOK, Inc., an operator of 
gas gathering lines, suggested a similar but more detailed tiered 
approach. Delta County, Colorado preferred the ``sliding corridor'' 
approach discussed at the public meetings. Two industry commenters 
favored a hands-off approach that would leave the regulation of rural 
gathering to State agencies already regulating oil and gas production.
    Several trade associations were concerned about the impact of any 
new DOT regulations on rural gathering lines. DOE and the Independent 
Petroleum Association of America were particularly concerned that 
increased costs could cause producers to shut in marginally profitable 
wells. They pointed out that since marginal wells account for about 10 
percent of U.S. gas production, additional costs could reduce gas 
supplies.

D. Alternatives To Resolve the Definition Problem

    Considering the previous attempts in 1974 and again in 1991 to 
resolve the definition problem were controversial, we concluded a 
single definition wholly consistent with industry's complex practices 
probably could not be developed. So we looked closer at API RP 80. Its 
development by a wide range of experienced personnel, its attention to 
detail, and its backing by commenters led us to believe it could, if 
used appropriately, distinguish gathering lines under part 192 without 
the controversy attendant to the earlier proposals. In reaching this 
conclusion, we did not intend persons to use API RP 80 for non-safety 
purposes, such as to identify gathering under the Natural Gas Act. By 
its own terms, API RP 80 applies only in the context of pipeline 
safety: ``[T]he definitions presented herein are not designed to 
address issues--nor are they intended for application--in any 
regulatory context other than gas pipeline safety pursuant to the 
Federal Pipeline Safety Act'' (section 2.6.2.4 of API RP 80).
    We considered the following ways API RP 80 could serve to determine 
onshore gas gathering under part 192:
    1. Use API RP 80 as guidance to determine the beginning and end of 
onshore gathering under the present part 192 definition. The advantages 
of this alternative were some operators would likely support it and 
rulemaking would not be necessary. On the other hand, this alternative 
would probably not be sufficient to satisfy the congressional directive 
to define gas gathering and it would provide a shaky basis for 
regulating rural gathering lines. In addition, NAPSR's comments 
suggested many State pipeline safety

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agencies would be unlikely to accept some API RP 80 provisions even as 
guidance.
    2. Adopt API RP 80 as the basis for determining onshore gas 
gathering lines. This alternative had wide industry support, would 
likely minimize the difficulty of distinguishing gathering lines, and 
would likely result in few pipeline reclassifications. However, API RP 
80's many supplemental definitions, descriptions, and diagrams, 
although helpful, could be difficult to apply uniformly. Also, as NAPSR 
contended, the ``furthermost downstream'' provisions of API RP 80 could 
result in manipulation of endpoints to avoid pipeline regulation. If 
that happened, State pipeline safety agencies could lose control over 
many miles of pipeline they now regulate, and public safety could be 
compromised.
    3. Adopt API RP 80, but with limitations to remove opportunities 
for manipulation. The main advantage of this alternative was it would 
balance industry's desire to use API RP 80 with NAPSR's desire for 
definite endpoints. The disadvantage was limitations could make API RP 
80 more difficult to apply. In addition, any limitation could renew 
industry's claims of line reclassifications. As discussed further in 
section II of this preamble, we chose this alternative for the proposed 
definition of ``onshore gathering line.''

E. Need for DOT Rules on the Safety of Onshore Rural Gathering Lines

    PHMSA has authority under 49 U.S.C. 60102(a) to issue safety 
standards for gas pipeline transportation. In 1992, Congress granted 
DOT specific authority to define gas gathering for purposes of safety 
regulations. Congress also recognized that some rural gathering lines 
might present unacceptable risks and authorized DOT to regulate lines 
whose risk warranted regulation. In its report on H.R. 1489, a bill 
leading to the 1992 change in the law, the House Committee on Energy 
and Commerce said ``DOT should find out whether any gathering lines 
present a risk to people or the environment, and if so how large a risk 
and what measures should be taken to mitigate the risk.'' (H.R. Report 
No. 102-247, Part 1, 102nd Cong., 1st Sess. 23 (1991)).
    As discussed above, because DOT lacked information about whether 
the risks of rural lines warranted regulation, it held a Web discussion 
and then two public meetings to get input from the public on the need 
to regulate these lines. GPA submitted the most detailed information 
based on a survey of its members. Although the survey results showed 
rural gathering lines presented a lower risk to the public than 
transmission lines, the impacts to the public and property during the 
survey period were not insignificant. Many people living or working 
near rural lines suffered adverse consequences. Also, the potential for 
future harm was apparent, because the survey confirmed the leading 
threats to rural gathering lines: corrosion and excavation damage, 
matched the leading threats to regulated gas pipelines.
    Not all rural gathering lines present as low a risk as the lines in 
GPA's survey. Some rural lines are near pockets of housing or operate 
at high pressures threatening housing further away. In fact, high-
pressure gathering lines in populated areas can present the same risk 
as regulated transmission lines.
    In consideration of the known and foreseeable risks presented by 
rural gathering lines, we decided it was no longer appropriate to 
maintain the almost total exemption of rural lines from part 192. But 
in changing the present exemption, we also decided to focus on lines 
posing significant risk, or lines located where a release of gas could 
have serious consequences.

F. Approach To Regulating Onshore Gathering Lines

    We believe the potential for harm of some onshore gathering lines 
is too low to warrant DOT regulation. These lines generally have small 
diameters and operate at low pressures in remote or secluded areas.
    For other lines, we agree with commenters that the level of 
regulation should increase as risk increases by operating pressure and 
proximity to people. Under this approach, the highest risk lines would 
have the most regulation. This approach is consistent with the 
statutory directive on determining which rural gathering lines warrant 
regulation.
    In deciding what safety rules to apply according to risk, we 
favored the tiered models two commenters suggested. Tiers are a 
reasonable way to pair safety regulations with lines posing different 
levels of risk. However, considering the need for practicality in both 
compliance and enforcement, we created a model with only two tiers. 
This approach is discussed in more detail in section II of this 
preamble.
    Currently, part 192 regulates nonrural gathering lines and 
transmission lines similarly, except Sec.  192.150 pig passage and 
subpart O apply only to transmission lines. Nevertheless, PHMSA's 
incident data indicate gathering and transmission lines do not pose the 
same overall level of risk to the public. This data shows that 
transmission line incidents have had a greater impact on the public 
than gathering line incidents. We therefore believe a significant 
factor in many nonrural gathering line segments is that they operate at 
low pressures away from highly populated areas. So safety rules 
intended for all transmission lines are probably not appropriate for 
all gathering lines.
    A related problem with the current part 192 approach to regulation 
of nonrural lines involves line segments inside sparsely populated 
areas of cities or towns. Often a city or town will extend its 
boundaries to incorporate these rural-like areas. For instance, a low-
pressure gathering line in such areas may be distant from any populated 
site but because it lies within city or town boundaries it becomes 
subject to part 192 and must meet transmission line rules.
    We believe a risk-based approach is the most suitable for applying 
part 192 rules to onshore gathering lines whether the lines are in 
rural or nonrural areas. Regulation of an onshore gathering line should 
not depend on subdivision or local government boundaries as it does 
now, but on the risk the line poses to the public based on its pressure 
and proximity to people. For example, the proximity of a line to 
dwellings is a much more precise measure of risk than the rural-
nonrural approach currently in use. For nonrural lines, this change to 
a risk-based approach would maintain the current level of regulation 
where justified by risk. At the same time, it would lighten the present 
regulatory burden on less risky lines.

II. Proposed Rules

    To get public comments on its latest approach to defining and 
regulating the safety of onshore gas gathering lines, on October 3, 
2005, PHMSA published a supplementary notice of proposed rulemaking 
(SNPRM) (70 FR 57536). The SNPRM was a continuation of the rulemaking 
proceeding started by the 1991 notice of proposed rulemaking (NPRM).
    The SNPRM sought comments on proposed new definitions of the terms 
``onshore gathering line'' and ``regulated onshore gathering line.'' 
These definitions would provide the basis for determining which gas 
pipelines would be subject to part 192 rules for regulated onshore 
gathering lines. Any onshore gathering line not covered by the proposed 
definition of ``regulated onshore gathering line'' would not be subject 
to part 192. The SNPRM also sought comments on proposed risk-based 
safety rules for regulated onshore gathering lines. A description of 
the

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proposed definitions and safety rules follows.

A. Proposed Definition of ``Onshore Gathering Line''

    We wanted to define ``onshore gathering line'' in a way that not 
only reasonably matched current classifications but also addressed 
NAPSR's concerns. So we proposed to allow operators to use API RP 80 to 
determine ``onshore gathering lines.'' But use of API RP 80 would be 
subject to the following five limitations on the beginning of gathering 
and the possible endpoints of gathering under section 2.2(a) of API RP 
80:
    1. Under section 2.2(a)(1), the beginning of an onshore gathering 
line is the furthermost downstream point in a production operation. We 
proposed to restrict this point to piping or equipment used solely in 
the process of extracting natural gas from the earth for the first time 
and preparing it for transportation or delivery. The purpose of the 
limitation was to ensure certain dual-use equipment, capable of use in 
either production or transportation, would be part of gathering when 
not used solely in the process of extracting and preparing gas for 
transportation.
    2. Under section 2.2(a)(1)(A), the first possible endpoint is the 
inlet of the furthermost downstream natural gas processing plant, other 
than a natural gas processing plant located on a transmission line. We 
proposed this endpoint may not be a natural gas processing plant 
located further downstream than the first downstream natural gas 
processing plant unless the operator can demonstrate, based on sound 
engineering reasons, gathering should extend beyond the first plant. 
Past DOT interpretations and State agency enforcement actions have 
recognized the first downstream natural gas processing plant as the 
customary end of gathering. (See PHMSA's Web site for interpretations 
and enforcement actions: https://www.phmsa.dot.gov/.)
    3. Under section 2.2(a)(1)(B), the second possible endpoint is the 
outlet of the furthermost downstream gathering line gas treatment 
facility. We proposed this endpoint would apply only if no other 
endpoint under sections 2.2(a)(1) (A), (C), (D) or (E) existed.
    4. Under section 2.2(a)(1)(C), the third possible endpoint is the 
furthermost downstream point where gas produced in the same production 
field or separate production fields are commingled. This endpoint 
recognizes a gathering line may receive gas from several production 
fields. But because it does not restrict the distance between fields, 
gathering could potentially continue endlessly, causing 
reclassifications from transmission to gathering along the way. To set 
a reasonable limit, we proposed that separate production fields from 
which gas is commingled must be within 50 miles of each other. We 
specifically invited comments on whether a maximum distance is needed.
    5. Under section 2.2(a)(1)(D), the fourth possible endpoint is the 
outlet of the furthermost downstream compressor station used to lower 
gathering line operating pressure to facilitate deliveries into the 
pipeline from production operations or to increase gathering line 
pressure for delivery to another pipeline. For consistency with our 
past interpretations and current enforcement policy, we proposed to 
limit this endpoint to the outlet of a compressor used to deliver gas 
to another pipeline.
    We did not propose a limitation on the fifth possible endpoint 
under section 2.2(a)(1)(E). This endpoint is the connection to another 
pipeline downstream of the furthermost downstream endpoint under 
sections 2.2(a)(1)(A) through (D), or in the absence of such an 
endpoint, the furthermost downstream production operation. The endpoint 
applies to connecting lines described as ``incidental gathering'' under 
section 2.2.1.2.6 of API RP 80. An example of a connecting line is a 
pipeline that runs from the outlet of a natural gas processing plant to 
a transmission line. PHMSA considers ``incidental gathering'' to 
include only lines that directly connect a transmission line to one of 
the endpoints (A) through (D), as limited by this final rule. Lines 
that connect a transmission line to one of these endpoints by way of 
another facility are not considered ``incidental gathering.''

B. Proposed Definition of ``Regulated Onshore Gathering Line''

    We proposed to amend Sec.  192.3 to define ``regulated onshore 
gathering lines'' by either of two risk categories, Type A and Type B, 
based on operating stress and location. Type A would include lines 
whose maximum allowable operating pressure (MAOP) results in a hoop 
stress of 20 percent or more of SMYS, and non-metallic lines whose MAOP 
is more than 125 per square inch gauge (psig). The location would be 
Class 3 and 4 locations, as defined in Sec.  192.5, and other areas the 
operator determines using potential impact circles with five or more 
dwellings or a sliding corridor 440 yards by 1000 feet with either 5 or 
more dwellings per 1000 feet or 25 or more dwellings per mile, 
whichever results in more regulated lines. Type A lines in a Class 1 or 
Class 2 location would also include additional lengths of line upstream 
and downstream to serve as a shield against potential harm to nearby 
dwellings.
    Type B lines would include metallic lines whose MAOP produces a 
hoop stress of less than 20 percent of SMYS, and non-metallic lines 
whose MAOP is 125 psig or less. The location would be Class 3 and 4 
locations and other areas determined by a sliding corridor 300 feet by 
1000 feet with 5 or more dwellings per 1000 feet. Lines within a Class 
1 or Class 2 location would include additional lengths of line as a 
shield against potential harm to nearby dwellings.

C. Proposed Safety Requirements

    We proposed to revise Sec.  192.9 to include safety requirements 
for all gathering lines subject to part 192. Paragraph (b) would simply 
restate the present part 192 requirements applicable to offshore 
gathering lines.
    Under paragraph (c), Type A regulated onshore gathering lines would 
have to meet part 192 requirements applicable to transmission lines, 
except requirements concerning the passage of smart pigs (Sec.  
192.150) and integrity management (subpart O). Because of the higher 
stress at which Type A lines operate and their ability to harm more of 
the public, we considered Type A lines to warrant safety requirements 
equivalent to transmission line requirements. Currently regulated 
gathering lines are subject to these requirements.
    Paragraph (d) contains the proposed requirements for Type B 
regulated onshore gathering lines. These lines, although located near 
the public and housing, operate at a lower stress than Type A lines and 
pose a lower-risk. So for Type B lines, we proposed safety requirements 
focused just on the main threats to these lines--corrosion and 
excavation damage. First, new lines and existing lines replaced, 
relocated, or otherwise changed would have to be designed, installed, 
constructed, initially inspected, and initially tested according to 
part 192 requirements. Second, operators of Type B lines would have to 
control corrosion according to applicable subpart I requirements; carry 
out a damage prevention program under Sec.  192.614; establish MAOP 
under Sec.  192.619; install and maintain line markers under Sec.  
192.707 according to transmission line requirements; and establish a 
public education program as required by Sec.  192.616.
    To allow time for line identification and preparation for 
compliance, we

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proposed extended compliance deadlines in paragraph (e) for operation 
and maintenance requirements. Similarly, we proposed to amend Sec.  
192.13 to allow 1 year after the final rule takes effect before new, 
replaced, relocated, or otherwise changed lines would have to meet 
design and construction requirements. Also in paragraph (e), we 
proposed to allow operators 1 year to bring unregulated lines into 
compliance if they become regulated because of changes in population.
    In addition, we proposed to ease the transition to regulated status 
of newly regulated lines and lines subsequently regulated due to 
population increases by revising the MAOP requirements of Sec. Sec.  
192.619(a)(3) and (c). The proposal would allow operation of a line at 
the highest actual operating pressure to which it was subjected during 
the 5 years before the final rule is published or the line becomes 
regulated.
    As part of the corrosion control requirements, we proposed to apply 
those subpart I requirements specifically applicable to pipelines 
installed before August 1, 1971, to regulated onshore gathering lines 
in existence when the final rule takes effect and not previously 
subject to subpart I (lines in rural locations). Other subpart I 
requirements specifically applicable to pipelines installed after July 
31, 1971, would not apply to these existing lines unless they 
substantially meet the requirements.

D. Related Proposals

    We proposed to amend Sec.  192.1(b)(4) to exclude from part 192 
onshore gathering lines operating under vacuum, or at less than 
atmospheric pressure. We reasoned that regulation was not necessary 
because these lines pose little risk since they cannot release natural 
gas to the atmosphere. An additional amendment to this section 
clarifies the present rulemaking on onshore gathering lines does not 
affect gathering lines in inlets of the Gulf of Mexico.

III. Advisory Committee Recommendations

    The Technical Pipeline Safety Standards Committee (TPSSC), a 
statutorily mandated advisory committee, advises PHMSA on proposed 
safety standards and other policies concerning gas pipelines. The 
committee has an authorized membership of 15 persons with membership 
evenly divided between government, industry, and the public. Each 
member is qualified to consider the technical feasibility, 
reasonableness, cost-effectiveness, and practicability of proposed 
pipeline safety standards.
    The TPSSC considered the SNPRM at a teleconference on January 19, 
2006. During the conference, we discussed the public comments 
summarized in section IV of this preamble and the draft Regulatory 
Evaluation of costs and benefits. After careful consideration, the 
TPSSC voted unanimously to find the SNPRM and supporting Regulatory 
Evaluation technically feasible, reasonable, practicable, and cost-
effective, subject to resolution of the comments in the manner we 
discussed. A transcript of the teleconference is available in Docket 
No. PHMSA-98-4470.

IV. Disposition of Comments on Proposed Rules

    We received written comments on the SNPRM from 19 sources: American 
Gas Association (AGA), Clark Resource Council and Powder River Basin 
Resource Council, Columbia Gas Transmission Corporation (Columbia), 
Cook Inlet Keeper, Dominion Delivery (Dominion), Duke Energy Field 
Services (Duke), Equitable Resources (Equitable), Independent Petroleum 
Association of America (IPAA), National Association of Pipeline Safety 
Representatives (NAPSR), National Fuel Gas Supply Corporation (NFGSC), 
Oil and Gas Industry Onshore Gas Gathering Regulation Coalition 
(Coalition), Oklahoma Corporation Commission (OCC), Oklahoma 
Independent Petroleum Association (OIPA), Pipeline Safety Trust (PST), 
Public Service Commission of West Virginia (PSCWV), Public Utilities 
Commission of Ohio, Robert A. Honig, Susan Franzheim, and West Texas 
Gas, Inc. (West).
    In the SNPRM, we discussed the impact our proposed gathering line 
definition might have on economic decisions of the Federal Energy 
Regulatory Commission (FERC). Although we concluded the definition was 
unlikely to influence FERC's decisions, we suggested an alternative 
approach that would not define gathering lines, just which gathering 
lines would be regulated for safety. We specifically invited comments 
on the potential impact of the proposed definition on FERC decisions, 
on ways to avoid difficulties of the alternative approach, and on 
advantages and disadvantages of either approach. No one who submitted 
comments on the SNPRM addressed any of these issues either directly or 
indirectly. We continue to believe that the approach we adopt in this 
final rule will not have implications on FERC practice. This approach 
does not rely on the Natural Gas Act for determining if a pipeline is a 
gathering line.
    Commenters generally favored the proposed definitions and tiered 
safety requirements subject to changes discussed in the outline below. 
However, West was against regulation of rural gathering lines, saying 
it was not needed because strong economic and liability-avoidance 
incentives encourage safe operations, and States can act if needed. 
West also said the Regulatory Evaluation was based on unsubstantiated 
assumptions, particularly with respect to the impact of lost reserves 
due to premature abandonment of stripper wells.
    We disagree with West on the need for DOT regulation of rural gas 
gathering lines. Although operators have economic and legal incentives 
to operate these lines safely and States can take regulatory action, we 
think DOT regulation is still needed. As explained above in section I 
of this preamble, this need derives from the Congress' concern about 
the safety of higher-risk rural gathering, public comments favoring 
regulation where warranted by risk, and the incident data industry 
submitted showing rural gathering lines experience the same leading 
causes of accidents as lines PHMSA now regulates. Thus, the present 
exemption of rural gathering lines from nearly all safety rules in part 
192 is no longer appropriate. We took West's comment on the draft 
Regulatory Evaluation into account in preparing a final evaluation.

A. Limitations on Using API RP 80 Definition of ``Gathering Line''

    As explained in the SNPRM, we proposed to adopt API RP 80 as the 
basis for determining onshore gathering lines and which of these lines 
would be subject to part 192 (70 FR 57540). Under this proposal, to 
determine if a pipeline is an onshore gathering line, operators would 
use API RP 80 in its entirety, including the definition of ``gathering 
line'' in section 2.2, the definition of ``production operation'' in 
section 2.3,\2\ the supplemental terms in section 2.4, and the Decision 
Trees, and Representative Applications.
---------------------------------------------------------------------------

    \2\ As defined in section 2.3 of API RP 80, ``production 
operation'' means piping and equipment used for production and 
preparation for transportation or delivery of hydrocarbon gas and/or 
liquids and includes the following processes: (a) Extraction and 
recovery, lifting, stabilization, treatment, separation, production 
processing, storage, and measurement of hydrocarbon gas and/or 
liquids; and (b) associated production compression, gas lift, gas 
injection, or fuel gas supply.
---------------------------------------------------------------------------

    However, we recognized the definition of ``gathering line'' in 
section 2.2 of API RP 80 is susceptible to manipulation because it uses 
the term ``furthermost downstream'' to identify

[[Page 13294]]

facilities marking the beginning and end of a gathering line. By 
installing certain dual-use equipment (equipment used in either 
production or pipeline transportation, such as separators or 
dehydrators) further downstream from normal production, operators could 
arguably extend production and reduce the amount of regulated 
gathering. Similarly, the ``furthermost downstream'' feature would 
allow operators to manipulate gathering endpoints marking the 
changeover to transmission, resulting in inconsistencies with prior DOT 
interpretations. So we proposed the following five limitations on use 
of the definition.
1. Limitation on Furthermost Point of Production
    Under section 2.2(a)(1) of API RP 80, gathering begins at the 
furthermost downstream point in a ``production operation.'' We proposed 
the following limitation on this aspect of the definition:

    The beginning of a gathering line may not be further downstream 
than piping or equipment used solely in the process of extracting 
natural gas from the earth for the first time and preparing it for 
transportation or delivery.

The purpose was to classify dual-use equipment as transportation 
equipment if it is not used in the process of producing and preparing 
gas for transportation. In other words, once produced gas enters 
pipeline transportation, any dual-use equipment installed further 
downstream would be transportation equipment and not production 
equipment.
a. Comments
    Coalition thought the limitation would expand gathering to include 
facilities, such as centralized separation, that API RP 80 describes as 
``production operations.'' It offered the following alternative wording 
to preclude production manipulation:

    The beginning of a gathering line * * * shall not be 
artificially circumvented by:
    (1) The installation of one or more pieces of equipment at an 
extreme downstream location not normally associated with a 
production operation; or
    (2) Natural gas injection into, and subsequent withdrawal from, 
a gas storage cavern or field.

Similarly, IPAA found the proposal confusing and said it would impact 
potentially thousands of producers across the country. It urged us to 
adopt a clear production definition, and suggested the following:

    ``Production Operation'' means any piping and equipment that 
qualify as a production operation under section 2.3 of API RP-80, 
with the following limitations: (1) Facilities operated in 
connection with natural gas storage operations shall be excluded; 
and (2) separation and dehydration facilities located contrary to 
the prudent operating standards commonly applicable in the industry 
to the particular geographic location and solely for the purpose of 
avoiding regulation as a gathering line under Title 49 of the Code 
of Federal Regulations, part 192, shall be excluded.

OCC, OIPA, NAPSR, and PST found the proposed limitation ambiguous. They 
too recommended alternative solutions. OCC and OIPA asked us to clarify 
the reference to the API RP 80 definition of ``production operations.'' 
NAPSR and PST recommended adding the phrase ``for the first time'' at 
the end of the proposed limitation.
b. PHMSA Response
    We think the text of the proposed rule (70 FR 47546) was the cause 
of the commenters' concerns. Nowhere does the proposed text say 
operators must use API RP 80 in its entirety to determine onshore 
gathering lines, even though in the SNPRM preamble we proposed such use 
subject to certain limitations on section 2.2. This omission created 
uncertainty about use of the API RP 80 definition of ``production 
operations.'' In addition, commenters may have thought the phrasing of 
the proposed limitation would narrow the meaning of ``production 
operations'' in API RP 80. However, we merely intended the limitation 
to clarify the classification of dual-use equipment positioned 
downstream from production operations.
    To resolve this misunderstanding, the final rule does not add a 
definition of ``onshore gathering line'' to Sec.  192.3 as proposed. 
Instead, we created a new Sec.  192.8, titled ``How are onshore 
gathering lines and regulated onshore gathering lines determined?'' 
Paragraph (a) of this new section allows operators to determine onshore 
gathering lines according to API RP 80, subject to certain limitations. 
Thus, operators must use API RP 80 in its entirety to determine onshore 
gathering lines, not just section 2.2 as the proposed definition of 
``onshore gathering line'' implied.
    In addition, in final Sec.  192.8(a)(1), we changed the proposed 
limitation on the furthermost point of production to focus on the 
classification of dual-use equipment. The limitation now provides the 
beginning of gathering may not extend beyond the furthermost downstream 
point in a production operation. This furthermost point does not 
include equipment capable of use in either production or 
transportation, such as separators or dehydrators, unless the equipment 
is involved in the processes of ``production and preparation for 
transportation or delivery of hydrocarbon gas'' within the meaning of 
``production operation'' under section 2.3 of API RP 80. This change 
removes any inference that the limitation narrows the meaning of 
``production operation'' under section 2.3 of API RP 80.
    We did not adopt commenters' suggestions to exclude from production 
``equipment at an extreme downstream location not normally associated 
with a production operation'' or ``facilities located contrary to the 
prudent operating standards'' because these terms are not precise 
enough for a safety rule. However, we think the situations they depict 
are relevant to deciding if equipment falls within the meaning of 
``production operation'' under API RP 80. Also, we did not think 
additional use of the term ``for the first time,'' as two commenters 
suggested, would lessen the confusion the proposed limitation created. 
Finally, we did not see any need to exclude from production any 
equipment used in connection with a natural gas storage cavern or field 
because section 2.4.4 of API RP 80 indicates the term ``storage'' in 
the definition of ``production operation'' does not include underground 
storage of natural gas.
2. Limitation on Furthermost Gas Processing Plant Endpoint
    Under section 2.2(a)(1)(A) of API RP 80, gathering ends at the 
inlet of the furthermost downstream natural gas processing plant not on 
a transmission line. We proposed the following limitation:

    Under section 2.2(a)(1)(A) of API RP 80, the endpoint may not 
extend beyond the first downstream natural gas processing plant, 
unless the operator can demonstrate, using sound engineering 
principles, that gathering extends to a further downstream plant.

The purpose of the limitation was to maintain consistency with prior 
DOT interpretations and State agency enforcement actions on gathering.
a. Comments
    Coalition and Duke were concerned about the impact the closing of a 
gas processing plant could have on gathering line classifications. They 
asked us to clarify that the endpoint of gathering would not change if 
a plant closes temporarily for maintenance or market reasons.
    West objected to placing the burden on operators to prove the need 
for further downstream processing. It

[[Page 13295]]

thought the government should have the burden of proving further 
downstream processing is not needed. In addition, West thought we 
should allow economic reasons as proof.
b. PHMSA Response
    We have not experienced a situation in which the closing of a gas 
processing plant affected a gathering line classification. Although 
closings of a few weeks for maintenance reasons would not trigger a 
classification change, longer closings could occur for a variety of 
reasons and the duration could be uncertain. So we decided not to make 
a general statement on how temporary plant closures would affect the 
end of gathering. Instead, when requested, we will determine the impact 
of closings on an individual basis as the need to do so arises. We 
expect certified State agencies with safety jurisdiction over gathering 
lines under 49 U.S.C. 60105 will do likewise.
    Regarding West's burden of proof issue, it is not unusual for part 
192 safety rules to include exceptions applicable only if operators can 
demonstrate certain conditions exist. For example, under Sec.  
192.479(c), operators do not have to protect aboveground pipelines from 
atmospheric corrosion if they demonstrate the corrosion will have 
certain characteristics. We require operators to demonstrate grounds 
for exceptions when they are the best source of information on which 
the exception is based. In the case of gathering lines, we think 
operators are the best source of information to demonstrate why further 
downstream processing is necessary to complete the gathering process.
    As for the proof required in the demonstration, no doubt economics 
would be a factor in any decision involving further downstream 
processing. However, many of our prior interpretations have based the 
end of gathering on the first downstream processing plant. Maintaining 
consistency with this policy as far as possible is desirable for both 
government and industry. For this reason, we think any future variation 
should be based on the fundamental qualities of gas processing, which 
is best determined by engineering analyses rather than economic 
conditions, which are transitory. Therefore, the proposed limitation is 
unchanged in the final rule.
3. Limitation on Furthermost Treatment Facility Endpoint
    Under section 2.2(a)(1)(B) of API RP 80, gathering ends at the 
outlet of the furthermost downstream gathering line gas treatment 
facility. We proposed the following limitation:

    The endpoint under section 2.2(a)(1)(B) of API RP 80 applies 
only if no other endpoint identified under section 2.2(a)(1)(A) 
[processing], (a)(1)(C) [commingling], or (a)(1)(D) [compression] 
exists.

We intended this limitation to preclude manipulation of the transition 
from gathering to transmission by installing equipment used in gas 
treatment.
a. Comments
    Coalition, supported by Duke, said the proposed limitation would 
make the furthermost treatment endpoint unusable, because processing, 
commingling, or compression is almost always upstream of a treatment 
facility. These commenters insisted gathering should continue 
downstream to a gas treatment facility endpoint no matter if 
compression, commingling, or processing occurs upstream. Coalition 
offered an alternative approach to preclude treatment manipulation:

    (1) Use the following wording: ``The end of a gathering line * * 
* shall not be defined by the installation of one or more pieces of 
gas treating equipment at an extreme downstream location that is not 
justified by sound engineering and economic principles independent 
of the pipeline's regulatory classification.'' (2) Explain in the 
final rule preamble that this endpoint refers to a ``gas treating 
plant'' or similar facility and is not intended to be a simple piece 
of equipment like a separator or dehydrator (other than as can be 
shown, using sound engineering and economic principles, to be needed 
at that location to meet transmission pipeline specifications).

 b. PHMSA Response
    Section 2.2.1.2.2 of API RP 80 explains the meaning of a gas 
treatment facility under section 2.2(a)(1)(B). This provision describes 
gathering gas treatment (other than treatment in gas processing or 
compression) as involving significant stand-alone facilities (e.g., a 
sulfur recovery or large dehydration facility). We think this 
explanation is sufficient to preclude possible manipulation of the 
treatment endpoint by installing a simple piece of treatment-related 
equipment, such as a separator or dehydrator. Thus, Coalition's 
alternative is not necessary and the proposed limitation is withdrawn.
4. Limitation on Furthermost Commingling Endpoint
    Under section 2.2(a)(1)(C) of API RP 80, gathering ends at the 
furthermost downstream point where gas produced in the same production 
field or separate production fields is commingled. We proposed the 
following limitation:

    If the endpoint is determined by the commingling of gas from 
separate production fields, the fields may not be more than 50 miles 
from each other.

With no limit on the distance between separate production fields, a 
gathering line could continue endlessly, causing reclassification of 
pipelines from transmission to gathering.
a. Comments
    Coalition, Duke, and West said the proposed limitation was not 
flexible enough to account for future acquisitions and use of maturing 
fields. Duke said its existing commingled fields were less than 50 
miles apart. Although Coalition thought some commingled fields were 125 
miles apart, it did not cite an actual example. Coalition and Duke 
recommended allowing case-by-case regulatory approvals of longer 
distances based on sound engineering and economic reasons.
b. PHMSA Response
    Because, Duke, the largest gas gathering line operator in the U.S., 
said the proposed 50-mile limit would be adequate for its current 
systems, the proposed 50-mile limit is unchanged in the final rule. We 
did not adopt Coalition's request to change the limit to 125 miles 
because it did not provide any examples of an existing system where the 
50-mile limit would be too restrictive. However, to provide 
flexibility, the final rule allows operators to petition PHMSA, under 
the procedures in 49 CFR Sec.  190.9, to find a longer limit is 
justified in a particular case.
5. Limitation on Furthermost Compressor Endpoint
    Under section 2.2(a)(1)(D) of API RP 80, gathering ends at the 
outlet of the furthermost downstream compressor station used to lower 
gathering line operating pressure to facilitate deliveries into the 
pipeline from production operations or to increase gathering line 
pressure for delivery to another pipeline. We proposed the following 
limitation:

    The endpoint may not extend beyond the furthermost downstream 
compressor used to increase gathering line pressure for delivery to 
another pipeline.

This limitation is consistent with our past interpretations.
a. Comment
    Coalition agreed with the proposed limitation, but asked us to 
clarify delivery to ``another pipeline'' does not mean delivery to 
another gathering line.

[[Page 13296]]

b. PHMSA Response
    Section 3.2.8 of API RP 80 says, ``the definition of gathering line 
did not directly address the issue of one operator's gathering line 
beginning or ending with a connection to another operator's gathering 
line.'' Based on this clarification, we believe the term ``another 
pipeline'' in section 2.2(a)(1)(D) of API RP 80 does not mean 
delivering to another gathering line.

B. Defining ``Regulated Onshore Gathering Line''

    We proposed to change how part 192 applies to onshore gathering 
lines outside inlets of the Gulf of Mexico by making the rules fit the 
level of risk gathering lines present. The proposal would restrict 
rules to two categories of lines, Type A and Type B, and define these 
lines as ``regulated onshore gathering lines.'' A description of the 
proposed definition is in section II of this preamble.
1. Approach To Defining Regulated Lines
a. Comments
    Columbia suggested we adopt a simpler definition of ``regulated 
onshore gathering line'' limited to lines in Class 3 and Class 4 
locations and lines in Class 1 and Class 2 locations where a potential 
impact circle includes 20 or more dwellings. It said the alternative 
would be easier to understand and apply, and consistent with the 
scientific-based definition of ``high consequence area'' in Sec.  
192.903. PST also suggested a more straightforward approach under which 
gathering and transmission lines of similar pressures and operating 
conditions would be regulated alike, and other gathering lines would be 
regulated the same as distribution lines.
b. PHMSA Response
    We did not adopt Columbia's alternative because it would apply the 
same classification method (potential impact circles with 20 or more 
dwellings) to high-pressure and low-pressure lines in Class 1 and 2 
locations. If impact circles were applied to low-pressure lines in 
Class 1 and 2 locations, the circles would most likely be too small to 
include 20 or more dwellings. So the risk of low-pressure lines to 
fewer than 20 nearby dwellings would not be addressed.
    PST's alternative parallels our proposal to regulate higher-risk 
gathering lines the same as transmission lines, but most transmission 
line rules are more stringent than appear to be necessary for lower-
risk gathering lines. Also, gathering lines are not sufficiently 
similar to distribution lines to apply the same rules to both types of 
lines.
2. Identifying Regulated Lines by Potential Impact Circles
a. Comments
    AGA and Dominion supported using potential impact circles to 
identify higher-risk regulated gathering, but said the population 
criteria (proposed 5 or more dwellings) should not be more stringent 
than the criteria applied to gas transmission lines (20 or more 
dwellings under Sec.  192.903). Dominion also suggested allowing use of 
impact circles as an optional identification method for Type B lines, 
not just Type A lines as proposed.
    NAPSR spotted an irregularity in using potential impact circles to 
identify Type A lines. Some smaller Type B lines (10 inches nominal 
diameter or less) uprated to operate above 20 percent of SMYS would 
lose their regulated status if operators use impact circles to identify 
Type A lines and the circles do not contain the minimum number of 
dwellings (5) found in the rectangles (300 ft x 1000 ft) previously 
used to identify the lines as Type B. Likewise, the use of impact 
circles could cause some currently regulated nonrural lines operating 
above 20% of SMYS to lose their regulated status, even though similarly 
situated Type B lines would remain regulated. Consequently, NAPSR 
suggested we adopt the proposed Type B rectangles and safety rules as 
the minimum standard of safety for all regulated lines.
b. PHMSA Response
    The decision discussed below (in response to NAPSR's comment) to 
withdraw the proposal on using potential impact circles to identify 
Type A lines makes the AGA and Dominion comments moot. Nevertheless, we 
offer the following: Section 192.903 requires 20 or more dwellings in 
potential impact circles used to identify transmission line segments 
subject to integrity management rules. These rules apply to the 
identified segments in addition to other applicable transmission rules. 
In contrast, we did not propose to apply integrity management rules to 
Type A lines identified by circles with just 5 dwellings or more. So we 
do not consider the proposed 5-per-circle method to be more stringent 
than the 20-per-circle method used for integrity management.
    We did not propose potential impact circles to identify Type B 
lines because for low-pressure lines the circles would most likely be 
too small to contain at least 5 dwellings. For this reason, they would 
not equate to the proposed method of 5 or more dwellings per 1000 feet. 
As further explained under subheading 4 of this section of the 
preamble, we did not adopt potential impact circles as a method to 
identify Type B lines.
    We believe NAPSR recognized a serious equivalency problem in 
allowing use of the proposed impact circles to identify Type A lines. 
The outcome could easily be an unregulated gathering line operating 
above 20 percent of SMYS next to a regulated Type B line, with both 
lines exposing the same dwellings to risk. To avoid this situation, we 
are withdrawing the proposal to use potential impact circles to 
identify Type A lines. We did not adopt NAPSR's suggested remedy 
because the compliance cost of detecting 5 dwellings per 1000 feet 
would likely be disproportionate to the benefits, as discussed below 
under subheading 4 of this section of the preamble.
3. Identifying Regulated Lines by Operating Stress
a. Comment
    Coalition said 20 percent of SMYS is too low to distinguish high-
stress Type A lines from low-stress Type B lines. It recommended using 
30 percent of SMYS as in Sec. Sec.  192.935, 192.937, and 192.941 for 
integrity management and in Sec. Sec.  192.505 and 192.507 for pressure 
testing because lines operating at less than 30 percent of SMYS may 
leak but not rupture.
b. PHMSA Response
    To regulate the safety of rural gas gathering lines, PHMSA must 
consider various physical characteristics, including operating 
pressure, to decide which lines warrant safety regulation (49 U.S.C. 
60101(a)(21)(B) and (b)(2)(A)). We proposed 20 percent of SMYS as 
indicative of onshore gathering lines whose operating pressure presents 
a significant enough risk in certain circumstances to warrant the same 
amount of regulation as transmission lines, except rules on integrity 
management and smart pig passage. The basis for this 20-percent 
threshold is the part 192 definition of ``transmission line,'' which 
includes pipelines other than gathering lines operating at 20 percent 
of SMYS or more. These pipelines must meet all applicable part 192 
safety rules. Because Type A lines can pose risks similar to 
transmission lines, we do not think 30 percent of

[[Page 13297]]

SMYS would be an appropriate threshold for Type A lines.
4. Identifying Regulated Lines Outside Class 3 and 4 Locations by 5 
Dwellings per 1000 Feet
a. Comments
    Coalition, Dominion, and Duke believed frequently surveying 
slightly populated areas (Class 1 and 2 locations) to identify line 
segments with 5 dwellings per 1000 feet would dilute, rather than 
expand, public safety by diverting attention from heavily populated 
areas (Class 3 and 4 locations). Coalition and Duke also said because 
most operators do not have the proposed 5-per-1000 dwelling data, they 
would have to create a new survey process and train personnel to use 
it. To apply the 5-per-1000 process initially, Coalition believed 
operators would survey all their onshore gathering lines (rather than 
25 percent as we estimated) at a cost of $99.5 million (four times our 
estimate). From then on, Coalition estimated operators would resurvey 
at least 65 percent of lines each year at a cost of over $12.9 million 
instead of our estimate of 15 percent at $3 million.
    To improve cost effectiveness, Coalition recommended an alternative 
regulatory approach to identify regulated onshore gathering lines in 
areas outside Class 3 and 4 locations. This approach focuses only on 
lines in Class 2 locations and uses the following methods rather than 5 
dwellings per 1000 feet:
     For Type A lines, areas within (1) a Class 2 location; or 
(2) a potential impact circle with a minimum radius of 150 feet 
including 5 or more dwellings.
     For Type B lines, an area 150 feet on either side of the 
centerline of any continuous 1-mile length of pipeline including more 
than 10 but fewer than 46 dwellings.
     In addition, for Type A lines, Duke supported our proposed 
sliding mile approach using 25 or more houses per mile.
    Commenting on Coalition's approach, Equitable also recommended 
focusing only on Class 2 locations. But it advised allowing operators a 
wider choice of identification methods for Type B lines: Potential 
impact circles like Coalition recommended for Type A lines, our 
proposed 5-per-1000 method, or Coalition's sliding mile alternative. 
Equitable said expanding the options to include potential impact 
circles would allow operators with advanced mapping systems to use them 
for compliance.
    NFGSC sought to add a cluster exception to the proposed 5-per-1000 
method for Type B lines to avoid regulating substantial lengths of line 
posing little risk. It said a Type B gathering line might pass within 
150 feet of 5 dwellings clustered near a highway intersection, but not 
pass near another dwelling for 1,000 feet in either direction. Under 
the proposed definition, the regulated segment would extend for up to 
1,000 feet in each direction, but pose little risk beyond the cluster. 
NFGSC suggested the regulated segment should extend in each direction 
only 150 feet from the nearest dwelling in the cluster.
b. PHMSA Response
    On further consideration of the proposal, we agree with commenters 
who suggested frequently searching for pockets of 5 dwellings per 1000 
feet in long, thinly populated Class 1 locations, which itself has at 
most 10 dwellings per mile, does not appear to be a reasonable use of 
available resources. So we are withdrawing the proposal to define 
certain lines in Class 1 locations as either Type A or Type B lines. 
However, as stated in the SNPRM, we are considering amending 49 CFR 
part 191 to collect reports of gathering line incidents in rural areas. 
If those reports indicate the risk of gathering lines in Class 1 
locations is unacceptable, we will consider the need to expand our 
gathering line rules to include segments of or all lines in Class 1 
locations.
    We also think the burden of frequently surveying lines in Class 2 
locations to look for line segments with 5 dwellings per 1000 feet is 
not the least costly way to tackle the risks involved with Type A 
lines. Thus we are adopting instead the commenters' recommendations to 
identify Type A lines outside Class 3 and 4 locations as lines in Class 
2 locations. Most areas outside Class 3 and 4 locations with a 
population density of 5 dwellings per 1000 feet are found in Class 2 
locations. Also, focusing on Class 2 as a whole, rather than by 
segments, is a clear and concise risk identification method. It has the 
advantage of allowing use of customary survey methods, eliminating the 
need for operators to devise new methods and provide additional 
training. Our proposed sliding mile approach with 25 or more houses per 
mile would have some of the same drawbacks as the 5 per 1000 approach. 
So it too is withdrawn. The change to Class 2 locations appears in 
final Sec.  192.8(b)(2).
    Coalition's recommendation to allow use of potential impact circles 
with a minimum radius of 150 feet to identify Type A line segments in 
Class 2 locations would not cure the irregularity NAPSR recognized. In 
some cases, the practical effect of the minimum radius would simply be 
a threshold density of 5 dwellings per 300 feet. This density would 
still be less stringent than the threshold of 5 dwellings per 1000 feet 
we proposed for Type B lines.
    Because Type B lines operate at less than 20 percent of SMYS, they 
are not likely to have potential impact circles large enough to include 
at least 5 dwellings. So for Type B lines, the impact circle method 
does not equate to the proposed 5-per-1000 method we proposed for Class 
2 locations. Nor do we think requiring impact circles to have a minimum 
radius of 150 feet, as commenters