[Federal Register Volume 71, Number 50 (Wednesday, March 15, 2006)]
[Rules and Regulations]
[Pages 13289-13303]
From the Federal Register Online via the Government Publishing 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 [email protected].

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: http://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 suggested, would cure the 
irregularity NAPSR recognized. So we did not adopt Equitable's comment 
to allow use of a potential impact circles with a minimum radius of 150 
feet for Type B lines.
    However, we favor Equitable's idea of offering operators more than 
one way to identify Type B lines outside Class 3 and 4 locations. As an 
alternative to the 5-per-1000 method, Coalition and Equitable suggested 
a variation of Class 2 criteria in which the sliding mile would extend 
only 150 feet on either side of the centerline instead of 220 yards. 
Because the potential impact of lines operating is less than 20 percent 
of SMYS is closer to 150 feet than 220 yards, we think this suggestion 
is reasonable. We also think small operators or operators who do not 
have Class 2 survey data may want to use the proposed 5-per-1000 method 
to minimize regulated mileage. So it remains an option in final Sec.  
192.8(b)(2). Also, operators well acquainted with Class 2 location 
surveys may prefer to treat all low-stress gathering lines in Class 2 
locations as Type B lines. Thus, final Sec.  192.8(b)(2) allows this 
option as well.
    Regarding NFGSC's comment, Sec.  192.5(c)(2) provides the following 
cluster exception for Class 2 and 3 locations: ``When a cluster of 
buildings intended for human occupancy requires a Class 2 or 3 
location, the class location ends 220 yards (200 meters) from the 
nearest building in the cluster.'' As NFGSC recommended, we think a 
similar exception is appropriate for Type B lines identified by any of 
the options. The exception is in final Sec.  192.8(b)(2).

V. Safety Requirements

A. Applying Operator Qualification (OQ) Rules to Type A Lines Outside 
Class 3 and 4 Locations

    Under proposed Sec.  192.9(c), the safety rules now applicable to 
nonrural gathering lines would apply to Type A

[[Page 13298]]

regulated onshore gathering lines. These rules include all part 192 
rules for gas transmission lines, except the rules in Sec.  192.150 on 
passage of smart pigs and in subpart O on integrity management. 
Consequently, the proposed rules would require operators to comply with 
OQ rules in subpart N on Type A lines, no matter where the lines are 
located.
1. Comments
    Coalition and Duke said because most gathering incidents are caused 
by excavation damage or corrosion rather than operator error, 
application of OQ rules outside Class 3 and 4 locations would impose 
significant costs with no proportionate reduction in risk. Duke 
reasoned compliance would be very costly because, for efficient use of 
personnel, operators would apply OQ rules to all lines in a gathering 
system not just to regulated segments. These commenters recommended we 
drop the proposal to require OQ rules for Type A lines outside Class 3 
and 4 locations. In addition, Coalition recommended we collect incident 
data on regulated lines, and if operator error contributes noticeably 
to incidents, consider extending the OQ rules at that time.
2. PHMSA Response
    In response to Coalition's and Duke's comments, PHMSA again 
reviewed the GPA study results that were submitted to the TPSSC.\3\ 
This study looked at incidents \4\ reported by 40 companies 
representing an aggregate 171,628 miles of non-regulated onshore gas 
gathering and found 1 incident attributable to human error. PHMSA notes 
that other operator qualification factors may indirectly contribute to 
pipeline failures. Furthermore, Congress directed DOT to establish 
regulations for OQ programs on pipelines. Congress also directed 
pipeline facility operators to develop and adopt a qualification 
program should DOT fail to prescribe standards and criteria. Congress 
further allowed DOT and State pipeline safety agencies to waive or 
modify any OQ requirements if not inconsistent with pipeline safety 
laws (49 U.S.C. 60131(e)(5) and (f)). Thus, Congress recognized that 
compliance with OQ regulations may not be suitable in all situations. 
In consideration of this data and Congress' intent, PHMSA modified the 
requirements of subpart N for Type A gathering lines in Class 2 
locations. This change will allow operators of Type A lines in Class 2 
locations to describe the processes they have in place to ensure that 
the personnel performing operations and maintenance activities are 
qualified. Because Congress directed operators to have OQ programs, 
this change should not impose any additional administrative costs.
---------------------------------------------------------------------------

    \3\ The results of this study were presented at the February 
2004 meeting of PHMSA's Technical Pipeline Safety Standards Advisory 
Committee.
    \4\ The GPA used the following criteria to define incidents for 
the informal study:
    (1) Death or injury;
    (2) Evacuation;
    (3) Minor property damage ($5,000-$25,000);
    (4) Major property damage (over $25,000).
---------------------------------------------------------------------------

B. Applying Safety Requirements to Lines ``Otherwise Changed''

1. Comment
    Commenting on proposed Sec.  192.9(d)(1), NFGSC considered the term 
``otherwise changed'' unnecessary and vague. It asked us to drop the 
term unless we clearly explain its meaning.
2. PHMSA Response
    Use of the term ``otherwise changed'' in proposed Sec.  192.9(d)(1) 
parallels its use in existing Sec.  192.13(b). This latter section, 
which has been part of part 192 since its initial publication in 1970, 
provides:

    No person may operate a segment of pipeline that is replaced, 
relocated, or otherwise changed after November 12, 1970, or in the 
case of an offshore gathering line, after July 31, 1977, unless that 
replacement, relocation, or change has been made in accordance with 
this part.

Though not defined in part 192, ``otherwise changed'' refers to a 
substantial physical alteration of a pipeline facility as opposed to a 
repair or restoration.

C. Compliance Times

    Under proposed Sec.  192.9(e)(1), design, installation, 
construction, initial inspection, and initial testing requirements 
would not apply to new, replaced, relocated, or otherwise changed lines 
until 1 year after publication of the final rule. Under proposed Sec.  
192.9(e)(2), the following compliance deadlines for lines not 
previously subject to part 192 would apply:

------------------------------------------------------------------------
                Requirement                 Proposed compliance deadline
------------------------------------------------------------------------
Control corrosion under subpart I.........  2 years after final rule
                                             takes effect.
Prevent excavation damage under Sec.        6 months after final rule
 192.614.                                    takes effect.
Establish MAOP under Sec.   192.619.......  6 months after final rule
                                             takes effect.
Install line markers under Sec.   192.707.  1 year after final rule
                                             takes effect.
Educate public under Sec.   192.616.......  1 year after final rule
                                             takes effect.
Other requirements for Type A lines.......  2 years after final rule is
                                             published.
------------------------------------------------------------------------

    PHMSA proposed the shorter timelines for provisions that require 
less time to implement, such as damage prevention. It proposed longer 
time frames for provisions that may require more time to procure and 
install materials.
    Lastly, as proposed in Sec.  192.9(e)(3), if an onshore gathering 
line becomes regulated because of a change in class location or an 
increase in dwelling density, the operator would have 1 year to comply 
with applicable requirements.
1. Comments
    Coalition requested at least 1 additional year to complete training 
for and to carry out initial classifications if we adopted the 
Coalition's alternatives to the 5 per 1000 proposal (described in 
section IV. B. 4. of this preamble). AGA thought operators would need 2 
years to complete the proposed classifications, and 4 years for full 
compliance. Dominion believed most operators would need 3 years for 
classifications, and large operators would need 4 years to meet 
corrosion control requirements. Duke said compliance times for large 
operators should be about twice as long as proposed, and 5 years for 
full compliance if operators have to determine classifications based on 
5 dwellings per 1000 feet.
    For lines that become regulated because of a change in class 
location or dwelling density, Columbia recommended allowing 2 years to 
meet the proposed safety requirements. It said this timeframe--1 year 
longer than we proposed--would be consistent with the time allowed for 
confirmation or revision of MAOP under Sec.  192.611.
2. PHMSA Response
    On the whole, comments indicated the proposed compliance times 
would not allow enough time to complete initial classifications and 
assure all regulated lines are in compliance. Since the final rule does 
not mandate 5 per 1000 surveys, we adopted Coalition's comment and, in 
final Sec.  192.9(e)(2), added 1 year to the proposed times to allow 
more time for classifications. This change results in 3 years for full 
compliance. If an operator finds it needs more time final Sec.  
192.9(e)(2) allows operators to petition for more time on a case-by-
case basis. For consistency with the time allowed for corrosion 
control, in final Sec.  192.9(e)(2), we added 1 month to the time 
proposed for compliance

[[Page 13299]]

with ``other requirements for Type A lines.''
    After initial classifications, we expect most class location or 
dwelling density changes would cause only short segments of lines to 
become newly regulated. The bulk of these changes will probably affect 
Type B lines, requiring compliance with only a few part 192 safety 
rules. Operators could largely meet these requirements by folding the 
segments into their existing programs. In these cases, allowing 2 years 
for compliance as Columbia suggested does not appear necessary. 
However, if Type A lines are affected, operators would have to comply 
with many more requirements. Therefore, for Type A lines, final Sec.  
192.9(e)(3) allows 2 years for compliance.

D. Corrosion Control

1. Comment
    Regarding proposed Sec. Sec.  192.9(c) and (d)(2)), PSCWV said 
where cathodic protection is impractical, operators should have to 
survey the line for leaks each calendar year, not to exceed 15 months, 
using gas detection equipment.
2. PHMSA Response
    We did not adopt this comment because the SNPRM did not include a 
proposal to require leak surveys where cathodic protection is 
impractical. In such cases, which should be few, operators may petition 
PHMSA or a State agency under 49 U.S.C. 60118 to waive applicable 
requirements, if not inconsistent with pipeline safety. PSCWV may have 
been concerned about situations in which Sec.  192.465(e) requires 
operators to reevaluate unprotected piping but it is impractical to 
perform an electrical survey to determine the need for cathodic 
protection. In these situations, Sec.  192.465(e) allows use of 
alternative means if they include review and analysis of leak repairs 
and other relevant information.

E. Determining MAOP

    For any gathering line part 192 regulates for the first time on and 
after the effective date of this final rule, proposed Sec. Sec.  
192.619(a)(3) and (c) would allow the operator to determine the line's 
MAOP based on the line's highest actual operating pressures during the 
preceding 5-year period.
1. Comment
    Coalition recommended we also apply the proposed rules to 
transmission lines part 192 regulates for the first time because of the 
final rule.
2. PHMSA Response
    Although we expect few reclassifications of gathering to 
transmission lines, we agree any newly regulated transmission lines 
should have the same MAOP options as gathering lines. So we adopted 
Coalition's comment. For simplicity, we based the pressure date in the 
table in final Sec.  192.619(a)(3) on the publication date of the final 
rule rather than the first day of the month preceding the publication 
date as proposed.

F. Editorial Changes

    The proposed definition of ``regulated onshore gathering line'' 
distinguished Type A metallic lines by whether the MAOP produces a hoop 
stress of 20 percent or more of SMYS. In most cases, determining 
operating stress level is not a problem. However, on some older lines, 
the stress level corresponding to MAOP may be unknown because a pipe 
characteristic relevant to calculating stress, such as SMYS or wall 
thickness, is unknown. Subpart C of part 192 provides options to deal 
with these uncertainties. Final Sec.  192.8(b) provides that operators 
are to apply applicable provisions in subpart C if the stress level is 
unknown.
    The proposal to amend Sec.  192.9 to require operators of Type B 
lines to control corrosion according to subpart I requirements did not 
specifically refer to subpart I requirements applicable to transmission 
lines. Final Sec.  192.9(d)(2) makes it clear Type B lines are to meet 
transmission line requirements.
    We proposed to amend Sec.  192.452 to clarify how subpart I 
requirements specifically applicable to pipelines installed before or 
after certain past dates would apply to regulated onshore gathering 
lines existing when the final rule takes effect and not previously 
subject to subpart I (lines in rural locations). Final Sec.  192.452(b) 
extends this provision to any onshore gathering line that becomes a 
regulated onshore gathering line because of an increase in population.
    We have made some wording changes in final Sec. Sec.  192.452 and 
192.619 to use more plain language. These non substantive wording 
changes do not change any of the proposed or existing requirements in 
these sections.

VI. Regulatory Analyses and Notices

Privacy Act

    Anyone is able to search the electronic form of all comments 
received into any of our dockets by the name of the individual 
submitting the comment (or signing the comment, if submitted on behalf 
of an association, business, labor union, etc.). You may review DOT's 
complete Privacy Act Statement in the Federal Register published on 
April 11, 2000 (65 FR 19477) or you may visit http://dms.dot.gov.

Executive Order 12866 and DOT Policies and Procedures

    This rulemaking is not a significant regulatory action under 
Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). 
Therefore, the Office of Management and Budget (OMB) has not received a 
copy of this rulemaking to review. This rulemaking is also not 
significant under DOT regulatory policies and procedures (44 FR 11034: 
February 26, 1979).
    PHMSA prepared a Regulatory Evaluation of this rulemaking and a 
copy is in Docket No. PHMSA-1998-4868. The evaluation concludes that 
there will be a net cost savings from implementing this final rule. The 
savings result from reducing the regulatory burden currently imposed on 
regulated gas gathering lines by establishing a tiered approach to 
safety requirements. PHMSA estimates that the total amount of gas 
gathering pipeline mileage that will be subject to part 192 will be 
about the same after implementing this rulemaking as it is now. 
However, requirements applicable to approximately three fourths of the 
regulated gathering line mileage, that which poses less public safety 
risk, will be reduced compared to the requirements now applicable to 
regulated lines. This proposal will result in a total cost of $26.54 
million over a 20-year period. PHMSA estimates that the benefit of 
reducing the frequency of gas gathering pipeline incidents that have 
public safety consequences will cause a net benefit that is consistent 
with the increased regulatory burden.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities.
    This rulemaking will affect operators of gas gathering pipelines. 
This rulemaking refines the definition of gas gathering pipelines 
subject to regulation and establishes a tiered regulatory

[[Page 13300]]

structure, under which regulated gas gathering lines posing less risk 
will be subject to only some of the requirements now applied to all 
regulated gathering lines. PHMSA estimates that the overall economic 
effect of this regulation will be a net reduction in costs to 
operators.
    At present, many operators of such pipelines are subject to federal 
safety regulation. The particular portions of their pipeline that are 
subject to regulation may change, in some cases, due to the changes in 
the definition, but the economic impact on these operators is expected 
to be a net reduction in costs, consistent with the regulatory 
analysis.
    There may be some operators of gas gathering pipelines that are not 
now subject to safety regulations that will become so because portions 
of their pipeline will meet the criteria in the new definition for 
regulated gas gathering lines. These companies will experience added 
costs. The costs will depend on the risk posed by their pipelines. The 
number of companies expected to come under safety regulation for the 
first time is approximately 25, some of which may be small entities. In 
this SNPRM, however, PHMSA invited comments specifically on this 
estimate, but received no comments. Nevertheless, PHMSA believes the 
estimate may be too high. The Small Business Administration (SBA) also 
reviewed the SNPRM analysis and the comments filed in response to the 
SNPRM. The SBA discussed the SNPRM with its constituents and it 
resulted in the SBA providing favorable comments. Based on these facts, 
only a few companies will experience increased costs, and PHMSA 
believes that there will not be a significant economic impact on a 
``substantial'' number of small entities.
    The regulatory flexibility analysis accompanies the regulatory 
evaluation and is in the docket for review.

Executive Order 13175

    PHMSA has analyzed this rulemaking according to the principles and 
criteria contained in Executive Order 13175, ``Consultation and 
Coordination with Indian Tribal Governments.'' Because the rulemaking 
will not significantly or uniquely affect the communities of the Indian 
tribal governments nor impose substantial direct compliance costs, the 
funding and consultation requirements of Executive Order 13175 do not 
apply.

Paperwork Reduction Act

    This rulemaking contains information collection requirements 
applicable to operators of regulated onshore gas gathering lines. As 
required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), 
PHMSA submitted a paperwork analysis to the Office of Management and 
Budget for its review. A copy of the analysis is in the docket. The OMB 
control numbers are: OMB No. 2137-0049 (recordkeeping under 49 CFR part 
192) and OMB No. 2137-0579 (drug and alcohol testing under 49 CFR part 
199).
    For Type B regulated onshore gathering lines, operators will have 
to comply with part 192 information collection requirements regarding 
corrosion control, damage prevention programs, and public education 
programs. For Type A regulated onshore gathering lines, operators will 
have to comply not only with these requirements but also with others 
under various part 192 rules applicable to gas transmission lines. All 
operators of onshore gathering lines that are regulated will have to 
comply with the information collection requirements in 49 CFR part 199 
concerning drug and alcohol testing. The small operators while required 
to collect test information, do not have to send reports annually and 
therefore are excluded from the reporting burden estimates but not the 
reporting estimates.
    As explained above in section III of this preamble, gas gathering 
lines in non-rural locations are currently subject to PHMSA's safety 
regulations. The number of gathering line operators subject to 
regulation varies by year as pipelines are brought, taken out of 
service, and as changes occur in the boundaries of non-rural locations. 
Currently there are 284 onshore natural gas gathering pipeline 
operators subject to PHMSA safety regulation.
    At present, all 284 of these operators are required to comply with 
part 192 rules applicable to transmission lines, including information 
collection requirements. The specific portions of these operators' 
gathering lines that are subject to part 192 regulations may change as 
a result of the final rule. Some portions may no longer be regulated, 
while others could become Type A or Type B lines. For Type B lines, the 
part 192 information collection burden will be significantly reduced, 
because Type B lines will be subject to far fewer part 192 regulations. 
The net effect on the paperwork burden faced by these 284 operators is 
thus expected to be a reduction. However, the magnitude of this 
reduction is difficult to estimate because PHMSA lacks the data 
necessary to determine which portions of operators currently regulated 
gathering lines will continue to be regulated by part 192 and which 
portions will become Type A or Type B lines.
    Under the final rulemaking, some operators of gas gathering lines 
in rural locations could become subject to part 192 regulations for the 
first time. PHMSA estimates that no more than 25 operators will be 
newly subject to part 192 regulations as a result of this final rule. 
These operators will be required to comply with part 192 regulations 
proposed for Type A and Type B lines and with part 199 drug and alcohol 
testing regulations, including associated information collection 
requirements.
    PHMSA's estimate of the paperwork burden on these newly-regulated 
operators is an average of approximately 40 hours per year. Much of 
this time will involve clerical personnel, but some involvement by 
managers and technical personnel will be required. At an estimated 
average hourly rate of $75 the estimated cost for 25 operators of this 
new paperwork burden, is $75,000.
    PHMSA expects that this increase in cost for newly-regulated 
operators will be more than offset by the reduction in paperwork burden 
associated with currently regulated gas gathering lines that become 
either unregulated or Type B lines, as described above. Thus, the 
overall paperwork impact will be a small reduction.

Unfunded Mandates Reform Act of 1995

    This rulemaking does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. It does not result in costs of 
$100 million or more to either State, local, or tribal governments, in 
the aggregate, or to the private sector, and is the least burdensome 
alternative that achieves the objective of the rulemaking.

National Environmental Policy Act

    PHMSA has analyzed this rulemaking for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the 
rulemaking will require limited physical modification or other work 
that will disturb pipeline rights-of-way, PHMSA has determined the 
rulemaking is unlikely to significantly affect the quality of the human 
environment. Much of the pipeline mileage that will be subject to this 
final rule is already regulated, and no new actions likely to affect 
the environment are adopted for currently regulated lines. Also much of 
the existing rural mileage that become regulated under this final rule 
is already equipped with cathodic protection and location markers, the 
two requirements that will involve any installation/modification work 
along the pipeline. An environmental assessment document

[[Page 13301]]

is available for review in the docket. By requiring operators to 
participate in damage prevention programs and follow the applicable 
requirements for corrosion control, it may be expected that the number 
of failures on gathering lines will be reduced. Since gathering lines 
often contain gas streams laden with condensates and natural gas 
liquids (NGL's), the reduced number of failures also means a reduced 
number of spills of these liquids.

Executive Order 13132

    PHMSA has analyzed this rulemaking according to the principles and 
criteria contained in Executive Order 13132 (``Federalism''). In its 
meetings with state agency officials on gathering lines, PHMSA 
discussed Federalism issues. None of the rules (1) Has substantial 
direct effects on the States, the relationship between the national 
government and the States, or the distribution of power and 
responsibilities among the various levels of government; (2) impose 
substantial direct compliance costs on State and local governments; or 
(3) preempt state law. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply.

Executive Order 13211

    Executive Order 13211 (May 18, 2001; 66 FR 28355) requires Federal 
agencies to prepare a statement of energy effects to ensure that 
agencies weigh and consider the effects of governmental regulations on 
the supply, distribution, and use of energy. This statement constitutes 
the required statement of energy effects for the final rule redefining 
gas gathering lines and establishing the scope of safety regulations 
applicable to them.
    The Department of Energy (DOE) expressed concerns about the 
potential adverse effect on the nation's energy supply derived from 
``marginal well'' \5\ production in the Alaska, Rocky Mountain, and 
Appalachian regions of the United States. Production from marginal 
wells represents approximately 10% of the domestic gas supply.\6\
---------------------------------------------------------------------------

    \5\ A marginal well is generally defined as a well that produces 
less than 60,000 cubic feet of gas per day.
    \6\ ``Interstate Oil and Gas Compact Commission, Marginal Oil 
and Gas: Fuel for Economic Growth (2003 Edition).''
---------------------------------------------------------------------------

    To better understand the potential impact of changing the gas 
gathering definition and applying a risk-based approach, PHMSA 
conducted a study in West Virginia to determine if reclassification 
would occur as a result of applying the new definitions, to compare the 
effect on the amount of regulated mileage by applying the new 
``regulated segment'' criteria, and to evaluate the expected cost 
increase/reductions expected by applying tiered risk-based compliance 
activities. West Virginia operators were selected for the study as a 
representative sample of marginal well production. In the sample study, 
PHMSA found that the concept of applying a risk-based approach to 
regulating gas gathering for pipeline safety purposes is viable. The 
gas gathering definitions will not cause significant reclassification 
of pipelines from a gathering classification to a transmission or 
distribution classification. Redefining the areas that PHMSA regulates 
will focus operator and regulatory resources on areas that could have 
detrimental consequences to the public, in the event of a pipeline 
failure. Regulatory compliance activities driven by risk will reduce 
operating and maintenance compliance costs for gathering lines 
operating at lower stress levels. Given these facts, current and future 
domestic natural gas production should not be impacted in a negative 
manner as a result of the final rule.
    As described in more detail in the related regulatory analysis, the 
operators of some gas gathering pipelines will experience a reduction 
in costs to comply with safety regulations. This reduction in costs, if 
shared with operators of producing natural gas wells, could result in 
some wells operating beyond what would now be their economic end-of-
life. This could result, over time, in more natural gas being produced 
for U.S. consumption than would be the case absent this change. PHMSA 
also discussed this final rule with the DOE and received no negative 
comments.
    Based on the above considerations, and discussions with the DOE, 
PHMSA has determined that there will be no significant adverse impact 
on energy supply, distribution or prices as a result of implementing 
this final rule.

List of Subjects in 49 CFR Part 192

    Incorporation by reference, Natural gas, Pipeline safety, Reporting 
and recordkeeping requirements.

0
For the reasons discussed in the preamble, PHMSA amends 49 CFR part 192 
as follows:

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

0
1. The authority citation for part 192 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, and 60118; and 49 CFR 1.53.


0
2. In Sec.  192.1,
0
a. Revise the section heading,
0
b. Revise paragraph (b)(4),
0
c. Remove paragraph (b)(5), and
0
d. Redesignate paragraph (b)(6) as (b)(5).
    The changes read as follows:


Sec.  192.1  What is the scope of this part?

* * * * *
    (b) * * *
    (4) Onshore gathering of gas--
    (i) Through a pipeline that operates at less than 0 psig (0 kPa);
    (ii) Through a pipeline that is not a regulated onshore gathering 
line (as determined in Sec.  192.8); and
    (iii) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec.  192.612.
* * * * *

0
3. In Sec.  192.7, revise the section heading, and in paragraph (c)(2) 
amend the table of referenced material by redesignating items (B)(4) 
and (B)(5) as (B)(5) and (B)(6) and adding an a new item (B)(4) to read 
as follows:


Sec.  192.7  What documents are incorporated by reference partly or 
wholly in this part?

* * * * *
    (c) * * *
    (2) * * *

------------------------------------------------------------------------
                                                                49 CFR
           Source and name of referenced material             reference
------------------------------------------------------------------------
B. * * *...................................................        * * *
(4) API Recommended Practice 80 (API RP 80) ``Guidelines            Sec.
 for the Definition of Onshore Gas Gathering Lines'' (1st          192.8
 edition, April 2000)......................................
 
                              * * * * * * *
------------------------------------------------------------------------


[[Page 13302]]


0
4. Add a new Sec.  192.8 to read as follows:


Sec.  192.8  How are onshore gathering lines and regulated onshore 
gathering lines determined?

    (a) An operator must use API RP 80 (incorporated by reference, see 
Sec.  192.7), to determine if an onshore pipeline (or part of a 
connected series of pipelines) is an onshore gathering line. The 
determination is subject to the limitations listed below. After making 
this determination, an operator must determine if the onshore gathering 
line is a regulated onshore gathering line under paragraph (b) of this 
section.
    (1) The beginning of gathering, under section 2.2(a)(1) of API RP 
80, may not extend beyond the furthermost downstream point in a 
production operation as defined in section 2.3 of API RP 80. This 
furthermost downstream point does not include equipment that can be 
used in either production or transportation, such as separators or 
dehydrators, unless that equipment is involved in the processes of 
``production and preparation for transportation or delivery of 
hydrocarbon gas'' within the meaning of ``production operation.''
    (2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 
80, 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.
    (3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API 
RP 80, is determined by the commingling of gas from separate production 
fields, the fields may not be more than 50 miles from each other, 
unless the Administrator finds a longer separation distance is 
justified in a particular case (see 49 CFR Sec.  190.9).
    (4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 
80, may not extend beyond the furthermost downstream compressor used to 
increase gathering line pressure for delivery to another pipeline.
    (b) For purposes of Sec.  192.9, ``regulated onshore gathering 
line'' means:
    (1) Each onshore gathering line (or segment of onshore gathering 
line) with a feature described in the second column that lies in an 
area described in the third column; and
    (2) As applicable, additional lengths of line described in the 
fourth column to provide a safety buffer:

----------------------------------------------------------------------------------------------------------------
               Type                         Feature                     Area                  Safety buffer
----------------------------------------------------------------------------------------------------------------
A................................  --Metallic and the MAOP    Class 2, 3, or 4          None.
                                    produces a hoop stress     location (see Sec.
                                    of 20 percent or more of   192.5).
                                    SMYS. If the stress
                                    level is unknown, an
                                    operator must determine
                                    the stress level
                                    according to the
                                    applicable provisions in
                                    subpart C of this part.
                                   --Non-metallic and the
                                    MAOP is more than 125
                                    psig (862 kPa).
B................................  --Metallic and the MAOP    Area 1. Class 3 or 4      If the gathering line is
                                    produces a hoop stress     location.                 in Area 2(b) or 2(c),
                                    of less than 20 percent   Area 2. An area within a   the additional lengths
                                    of SMYS. If the stress     Class 2 location the      of line extend upstream
                                    level is unknown, an       operator determines by    and downstream from the
                                    operator must determine    using any of the          area to a point where
                                    the stress level           following three           the line is at least
                                    according to the           methods:.                 150 feet (45.7 m) from
                                    applicable provisions in  (a) A Class 2 location..   the nearest dwelling in
                                    subpart C of this part.   (b) An area extending      the area. However, if a
                                   --Non-metallic and the      150 feet (45.7 m) on      cluster of dwellings in
                                    MAOP is 125 psig (862      each side of the          Area 2 (b) or 2(c)
                                    kPa) or less.              centerline of any         qualifies a line as
                                                               continuous 1 mile (1.6    Type B, the Type B
                                                               km) of pipeline and       classification ends 150
                                                               including more than 10    feet (45.7 m) from the
                                                               but fewer than 46         nearest dwelling in the
                                                               dwellings.                cluster.
                                                              (c) An area extending
                                                               150 feet (45.7 m) on
                                                               each side of the
                                                               centerline of any
                                                               continous 1000 feet
                                                               (305 m) of pipeline and
                                                               including 5 or more
                                                               dwellings.
----------------------------------------------------------------------------------------------------------------


0
5. Revise Sec.  192.9 to read as follows:


Sec.  192.9  What requirements apply to gathering lines?

    (a) Requirements. An operator of a gathering line must follow the 
safety requirements of this part as prescribed by this section.
    (b) Offshore lines. An operator of an offshore gathering line must 
comply with requirements of this part applicable to transmission lines, 
except the requirements in Sec.  192.150 and in subpart O of this part.
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part 
applicable to transmission lines, except the requirements in Sec.  
192.150 and in subpart O of this part. However, an operator of a Type A 
regulated onshore gathering line in a Class 2 location may demonstrate 
compliance with subpart N by describing the processes it uses to 
determine the qualification of persons performing operations and 
maintenance tasks.
    (d) Type B lines. An operator of a Type B regulated onshore 
gathering line must comply with the following requirements:
    (1) If a line is new, replaced, relocated, or otherwise changed, 
the design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission 
lines;
    (3) Carry out a damage prevention program under Sec.  192.614;
    (4) Establish a public education program under Sec.  192.616;
    (5) Establish the MAOP of the line under Sec.  192.619; and
    (6) Install and maintain line markers according to the requirements 
for transmission lines in Sec.  192.707.
    (e) Compliance deadlines. An operator of a regulated onshore 
gathering line must comply with the following deadlines, as applicable.
    (1) An operator of a new, replaced, relocated, or otherwise changed 
line must be in compliance with the applicable requirements of this 
section by the date the line goes into service, unless an exception in 
Sec.  192.13 applies.
    (2) If a regulated onshore gathering line existing on April 14, 
2006 was not

[[Page 13303]]

previously subject to this part, an operator has until the date stated 
in the second column to comply with the applicable requirement for the 
line listed in the first column, unless the Administrator finds a later 
deadline is justified in a particular case:

------------------------------------------------------------------------
                Requirement                      Compliance deadline
------------------------------------------------------------------------
Control corrosion according to Subpart I    April 15, 2009.
 requirements for transmission lines.
Carry out a damage prevention program       October 15, 2007.
 under Sec.   192.614.
Establish MAOP under Sec.   192.619.......  October 15, 2007.
Install and maintain line markers under     April 15, 2008.
 Sec.   192.707.
Establish a public education program under  April 15, 2008.
 Sec.   192.616.
Other provisions of this part as required   April 15, 2009.
 by paragraph (c) of this section for Type
 A lines.
------------------------------------------------------------------------

    (3) If, after April 14, 2006, a change in class location or 
increase in dwelling density causes an onshore gathering line to be a 
regulated onshore gathering line, the operator has 1 year for Type B 
lines and 2 years for Type A lines after the line becomes a regulated 
onshore gathering line to comply with this section.
0
6. In Sec.  192.13,
0
a. Revise the section heading, and
0
b. Revise paragraphs (a) and (b), to read as follows:


Sec.  192.13  What general requirements apply to pipelines regulated 
under this part?

    (a) No person may operate a segment of pipeline listed in the first 
column that is readied for service after the date in the second column, 
unless:
    (1) The pipeline has been designed, installed, constructed, 
initially inspected, and initially tested in accordance with this part; 
or
    (2) The pipeline qualifies for use under this part according to the 
requirements in Sec.  192.14.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15 2007.
 this part did not apply until April 14,
 2006.
All other pipelines.......................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first 
column that is replaced, relocated, or otherwise changed after the date 
in the second column, unless the replacement, relocation or change has 
been made according to the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15, 2007.
 this part did not apply until April 14,
 2006.
All other pipelines.......................  November 12, 1970.
------------------------------------------------------------------------

* * * * *

0
7. In Sec.  192.452,
0
a. Revise the section heading,
0
b. Designate the existing text as paragraph (a),
0
c. Add ``Converted pipelines.'' as the heading of newly designated 
paragraph (a), and
0
d. Add a new paragraph (b), to read as follows:


Sec.  192.452  How does this subpart apply to converted pipelines and 
regulated onshore gathering lines?

    (a) Converted pipelines. * * *
    (b) Regulated onshore gathering lines. For any regulated onshore 
gathering line under Sec.  192.9 existing on April 14, 2006, that was 
not previously subject to this part, and for any onshore gathering line 
that becomes a regulated onshore gathering line under Sec.  192.9 after 
April 14, 2006, because of a change in class location or increase in 
dwelling density:
    (1) The requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, apply to the gathering line 
regardless of the date the pipeline was actually installed; and
    (2) The requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply only if the pipeline 
substantially meets those requirements.

0
8. In Sec.  192.619, revise the section heading and paragraphs (a)(3) 
and (c) to read as follows:


Sec.  192.619  What is the maximum allowable operating pressure for 
steel or plastic pipelines?

    (a) * * *
    (3) The highest actual operating pressure to which the segment was 
subjected during the 5 years preceding the applicable date in the 
second column. This pressure restriction applies unless the segment was 
tested according to the requirements in paragraph (a)(2) of this 
section after the applicable date in the third column or the segment 
was uprated according to the requirements in subpart K of this part:

------------------------------------------------------------------------
        Pipeline segment             Pressure date         Test date
------------------------------------------------------------------------
--Onshore gathering line that     March 15, 2006, or  5 years preceding
 first became subject to this      date line becomes   applicable date
 part (other than Sec.             subject to this     in second column.
 192.612) after April 13, 2006.    part, whichever
                                   is later.
--Onshore transmission line that
 was a gathering line not
 subject to this part before
 March 15, 2006.
Offshore gathering lines........  July 1, 1976......  July 1, 1971.
All other pipelines.............  July 1, 1970......  July 1, 1965.
------------------------------------------------------------------------

* * * * *
    (c) The requirements on pressure restrictions in this section do 
not apply in the following instance. An operator may operate a segment 
of pipeline found to be in satisfactory condition, considering its 
operating and maintenance history, at the highest actual operating 
pressure to which the segment was subjected during the 5 years 
preceding the applicable date in the second column of the table in 
paragraph (a)(3) of this section. An operator must still comply with 
Sec.  192.611.

    Issued in Washington, DC, on March 10, 2006.
Brigham A. McCown,
Acting Administrator.
[FR Doc. 06-2562 Filed 3-14-06; 8:45 am]
BILLING CODE 4910-60-P