[Federal Register: March 15, 2006 (Volume 71, Number 50)]
[Rules and Regulations]
[Page 13289-13303]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15mr06-28]
[[Page 13289]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-1998-4868; Amdt. 192-102]
RIN 2137-AB15
Gas Gathering Line Definition; Alternative Definition for Onshore
Lines and New Safety Standards
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Final rule.
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SUMMARY: This action adopts a consensus standard to distinguish onshore
gathering lines from other gas pipelines and production operations. In
addition, it establishes safety rules for certain onshore gathering
lines in rural areas and revises current rules for certain onshore
gathering lines in nonrural areas. Operators will use a new risk-based
approach to determine which onshore gathering lines are subject to
PHMSA's gas pipeline safety rules and which of these rules the lines
must meet. PHMSA intends this action to reduce disagreements over
classifications of onshore gathering lines, increase public confidence
in the safety of onshore gathering lines, and provide safety rules
consistent with the risks of onshore gathering lines.
DATES: This final rule takes effect April 14, 2006. The Director of the
Federal Register approves the incorporation by reference of API RP 80
in this rule as of April 14, 2006.
FOR FURTHER INFORMATION CONTACT: DeWitt Burdeaux by phone at 405-954-
7220 or by e-mail at dewitt.burdeaux@dot.gov.
SUPPLEMENTARY INFORMATION:
I. Background
A. Current Regulation of Onshore Gathering Lines; Definition Problem
Gas gathering lines are pipelines used to collect natural gas from
production facilities and transport it to transmission or distribution
lines, which then transports it to the consumer. PHMSA's pipeline
safety rules in 49 CFR part 192 apply to the transportation of natural
gas and other gas by pipeline. However, onshore gathering lines in
rural areas (areas outside cities, towns, villages, or designated
residential or commercial areas) are subject only to Sec. 192.612,
which prescribes inspection and burial requirements for lines within
Gulf of Mexico inlets (Sec. Sec. 192.1(b)(4) and (b)(5)). (Note: Lines
in these inlets are not covered by this final rule.)
Under Sec. 192.9, gathering lines in nonrural areas must meet the
same safety standards for design, construction, testing, operation, and
maintenance as gas transmission lines, except the requirements of Sec.
192.150 on passage of an internal inspection device (also known as
smart pigs) and subpart O on integrity management. In addition, PHMSA's
drug and alcohol testing regulations in 49 CFR part 199 apply to
nonrural gas gathering lines.
Section 192.3 currently defines the terms ``gathering line,''
``transmission line,'' and ``distribution line'':
``Gathering line'' means a pipeline that transports gas from a
current production facility to a transmission line or main.
``Transmission line'' means a pipeline, other than a gathering line,
that transports gas from a gathering line or storage facility to a
gas distribution center or storage facility; operates at a hoop
stress of 20 percent or more of a Specified Minimum Yield Strength
(SMYS), or transports gas within a storage field. ``Distribution
line'' means a pipeline other than a gathering or transmission line.
Because these definitions are circular and part 192 does not define
``production facility,'' operators and government inspectors have had
difficulty distinguishing regulated gathering lines from unregulated
production facilities and unregulated gathering lines from regulated
transmission and distribution lines. Also, the complexity of many
gathering systems has increased the difficulty of distinguishing
gathering lines.
B. Past Attempts To Resolve the Definition Problem and Determine the
Need To Regulate Rural Gathering Lines
In 1974, DOT tried to correct the problem of distinguishing
gathering lines by proposing to revise the gathering line definition
(39 FR 34569; Sept. 26, 1974). However, the proposal was later
withdrawn because comments indicated many terms and phrases were
unclear (43 FR 42773; Sept. 21, 1978). Afterward, the problem lingered
until 1986, when the National Association of Pipeline Safety
Representatives (NAPSR), a nonprofit association of State pipeline
safety officials, surveyed its members and reported numerous and
continuing disagreements with operators over gathering lines. Driven by
the NAPSR survey, in 1991 DOT again proposed to revise the gathering
line definition (56 FR 48505; Sept. 25, 1991). However, the public
response was generally unfavorable, so DOT delayed any further action
until it collected and considered more information.
Part 192 does not regulate the safety of most rural gathering lines
because, until 1992, the pipeline safety law (49 U.S.C. Chapter 601)
restricted DOT's authority over onshore gathering lines to lines in
nonrural locations.\1\ In 1992, Congress gave DOT specific authority to
define gas gathering lines for purposes of safety regulation, and to
regulate a class of rural gathering lines called ``regulated gathering
lines'' (49 U.S.C. 60101(a)(21) and 60101(b)). The new authority
directed DOT to consider functional and operational characteristics in
defining gathering lines. Further direction was to consider such
factors as location, length of line, operating pressure, throughput,
and gas composition in deciding which rural lines warrant regulation.
This authority also expressly allows PHMSA to depart from the concepts
of gathering under the Natural Gas Act (15 U.S.C. 717 et seq.)
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\1\ In 1990 Congress gave DOT limited authority over gathering
lines in Gulf of Mexico inlets (see Pub. L. 101-599).
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In 1999, in furtherance of the still open 1991 gathering line
proceeding and Congress' action on gathering lines, DOT opened a Web
site for public discussion of the definition problem and the need to
regulate rural gathering lines (Docket No. PHMSA-1998-4868; 64 FR
12147; Mar. 11, 1999). The comments mainly focused on the comprehensive
work by the American Petroleum Institute (API), later published as API
Recommended Practice 80, ``Guidelines for the Definition of Onshore Gas
Gathering Lines'' (API RP 80). API RP 80 defines onshore gas gathering
lines through a series of definitions, descriptions, and diagrams
intended to represent the varied and complex nature of production and
gathering in the U.S. Although industry commenters spoke favorably
about the API RP 80 gathering line definition, NAPSR objected to the
use of certain ``furthermost downstream'' endpoints to mark the
beginning and end of gathering. NAPSR's concern was if the definition
were included in part 192, operators would have an incentive to
establish or move the endpoints further downstream to reduce the amount
of regulated pipelines. While considering its next step, DOT published
an Advisory Bulletin to remind operators it was still regulating
gathering lines according to court precedents and its prior
interpretations (67 FR 64447; October 18, 2002).
Then in 2003, DOT held public meetings in Austin, Texas (68 FR
62555; November 5, 2003) and Anchorage, Alaska (68 FR 67129; December
1, 2003)
[[Page 13290]]
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
[[Page 13291]]
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
[[Page 13292]]
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
[[Page 13293]]
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