Rule: Pipeline safety: Gas gathering line definition; alternative definition for onshore lines

8/14/2019 Rule: Pipeline safety: Gas gathering line definition; alternative definition for onshore lines

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13289Federal Register / Vol. 71, No. 50 / Wednesday, March 15, 2006/ Rules and Regulations

1 In 1990 Congress gave DOT limited authorityover gathering lines in Gulf of Mexico inlets (seePub. L. 101599).

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous MaterialsSafety Administration

49 CFR Part 192

[Docket No. PHMSA19984868; Amdt. 192102]

RIN 2137AB15

Gas Gathering Line Definition;Alternative Definition for OnshoreLines and New Safety Standards

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

ACTION: Final rule.

SUMMARY: This action adopts aconsensus standard to distinguishonshore gathering lines from other gaspipelines and production operations. Inaddition, it establishes safety rules for

certain onshore gathering lines in ruralareas and revises current rules forcertain onshore gathering lines innonrural areas. Operators will use a newrisk-based approach to determine whichonshore gathering lines are subject toPHMSAs gas pipeline safety rules andwhich of these rules the lines mustmeet. PHMSA intends this action toreduce disagreements overclassifications of onshore gatheringlines, increase public confidence in thesafety of onshore gathering lines, andprovide safety rules consistent with therisks of onshore gathering lines.

DATES: This final rule takes effect April14, 2006. The Director of the FederalRegister approves the incorporation byreference of API RP 80 in this rule as ofApril 14, 2006.

FOR FURTHER INFORMATION CONTACT:DeWitt Burdeaux by phone at 4059547220 or by e-mail [email protected].

SUPPLEMENTARY INFORMATION:

I. Background

A. Current Regulation of OnshoreGathering Lines; Definition Problem

Gas gathering lines are pipelines usedto collect natural gas from productionfacilities and transport it to transmissionor distribution lines, which thentransports it to the consumer. PHMSAspipeline safety rules in 49 CFR part 192apply to the transportation of naturalgas and other gas by pipeline. However,onshore gathering lines in rural areas(areas outside cities, towns, villages, ordesignated residential or commercialareas) are subject only to 192.612,which prescribes inspection and burialrequirements for lines within Gulf of

Mexico inlets (192.1(b)(4) and (b)(5)).(Note: Lines in these inlets are notcovered by this final rule.)

Under 192.9, gathering lines innonrural areas must meet the samesafety standards for design,construction, testing, operation, andmaintenance as gas transmission lines,except the requirements of192.150 on

passage of an internal inspection device(also known as smart pigs) and subpartO on integrity management. In addition,PHMSAs drug and alcohol testingregulations in 49 CFR part 199 apply tononrural gas gathering lines.

Section 192.3 currently defines theterms gathering line,transmissionline, and distribution line:

Gathering line means a pipeline thattransports gas from a current productionfacility to a transmission line or main.Transmission line means a pipeline, otherthan a gathering line, that transports gas froma gathering line or storage facility to a gasdistribution center or storage facility;operates at a hoop stress of 20 percent ormore of a Specified Minimum Yield Strength(SMYS), or transports gas within a storagefield. Distribution line means a pipelineother than a gathering or transmission line.

Because these definitions are circularand part 192 does not defineproduction facility, operators andgovernment inspectors have haddifficulty distinguishing regulatedgathering lines from unregulatedproduction facilities and unregulatedgathering lines from regulatedtransmission and distribution lines.Also, the complexity of many gathering

systems has increased the difficulty ofdistinguishing gathering lines.

B. Past Attempts To Resolve theDefinition Problem and Determine theNeed To Regulate Rural Gathering Lines

In 1974, DOT tried to correct theproblem of distinguishing gatheringlines by proposing to revise thegathering line definition (39 FR 34569;Sept. 26, 1974). However, the proposalwas later withdrawn because commentsindicated many terms and phrases wereunclear (43 FR 42773; Sept. 21, 1978).Afterward, the problem lingered until

1986, when the National Association ofPipeline Safety Representatives(NAPSR), a nonprofit association ofState pipeline safety officials, surveyedits members and reported numerous andcontinuing disagreements withoperators over gathering lines. Driven bythe NAPSR survey, in 1991 DOT againproposed to revise the gathering linedefinition (56 FR 48505; Sept. 25, 1991).However, the public response wasgenerally unfavorable, so DOT delayedany further action until it collected andconsidered more information.

Part 192 does not regulate the safetyof most rural gathering lines because,until 1992, the pipeline safety law (49U.S.C. Chapter 601) restricted DOTsauthority over onshore gathering lines tolines in nonrural locations.1 In 1992,Congress gave DOT specific authority todefine gas gathering lines for purposesof safety regulation, and to regulate a

class of rural gathering lines calledregulated gathering lines (49 U.S.C.60101(a)(21) and 60101(b)). The newauthority directed DOT to considerfunctional and operationalcharacteristics in defining gatheringlines. Further direction was to considersuch factors as location, length of line,operating pressure, throughput, and gascomposition in deciding which rurallines warrant regulation. This authorityalso expressly allows PHMSA to departfrom the concepts of gathering under theNatural Gas Act (15 U.S.C. 717 et seq.)

In 1999, in furtherance of the still

open 1991 gathering line proceedingand Congress action on gathering lines,DOT opened a Web site for publicdiscussion of the definition problemand the need to regulate rural gatheringlines (Docket No. PHMSA19984868;64 FR 12147; Mar. 11, 1999). Thecomments mainly focused on thecomprehensive work by the AmericanPetroleum Institute (API), laterpublished as API RecommendedPractice 80, Guidelines for theDefinition of Onshore Gas GatheringLines (API RP 80). API RP 80 definesonshore gas gathering lines through aseries of definitions, descriptions, anddiagrams intended to represent thevaried and complex nature ofproduction and gathering in the U.S.Although industry commenters spokefavorably about the API RP 80 gatheringline definition, NAPSR objected to theuse of certain furthermostdownstream endpoints to mark the

beginning and end of gathering.NAPSRs concern was if the definitionwere included in part 192, operatorswould have an incentive to establish ormove the endpoints further downstreamto reduce the amount of regulatedpipelines. While considering its next

step, DOT published an AdvisoryBulletin to remind operators it was stillregulating gathering lines according tocourt precedents and its priorinterpretations (67 FR 64447; October18, 2002).

Then in 2003, DOT held publicmeetings in Austin, Texas (68 FR 62555;November 5, 2003) and Anchorage,Alaska (68 FR 67129; December 1, 2003)

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13290 Federal Register / Vol. 71, No. 50 / Wednesday, March 15, 2006/ Rules and Regulations

to attract more comments on the bestway to define gas gathering lines andwhat, if any, safety rules may be neededfor rural gathering lines. At themeetings, DOT gave the history of thegas gathering issue and proffered asliding corridor concept as a possible

basis for deciding which lines should beregulated. Under this concept,

previously used in a pipeline safetyenforcement case, operators would slidealong their gathering lines an imaginarycorridor with dimensions 1000 feet longand the width would be based on thestress level. Wherever the corridorcontained five or more dwellings, thegathering line would be subject to safetyrules, the intensity of which wouldincrease with the stress level.Transcripts of both meetings are in thedocket (PHMSA19984868120 and122).

As a follow-up to these two meetings,DOT published a notice extending the

time for comments and clarifying itsintentions about defining and regulatinggathering lines (69 FR 5305; February 4,2004). DOT said definitions ofproduction and gathering should notoverlap State regulations on productionand should be capable of consistentapplication by regulators and operators.Also, the notice explained the need forcomments on an appropriate approachto identify rural lines warrantingregulation. After the 2003 publicmeetings, DOT met several times withState agency officials, industryrepresentatives, and others to obtain

views on gathering line risks and theneed for safety rules. Notes of theseinformal meetings are in Docket No.PHMSA19984868.

C. Public Comments Resulting From thePublic Meetings

Twenty-three comments weresubmitted as a result of the publicmeetings and clarification notice. Threeindustry commenters expressedsatisfaction with the current part 192gathering line definition and prior DOTinterpretations. But most commenters,including a coalition of trade

associations, urged adoption of API RP80 as the basis for determining onshoregas gathering lines. These commenters

believed it would result in few, if any,reclassifications of pipelines fromproduction to gathering or gathering totransmission. However, NAPSRopposed the unqualified use of API RP80 because of its use of the termfurthermost downstream to identifythe beginning and possible ends ofgathering. NAPSR suggested severallimitations to prevent manipulating theterm furthermost downstream to

change production to gathering orgathering to transmission.

On the need to regulate rural lines,some trade associations contended ruralgathering lines generally pose a low riskto public safety, citing an incidentsurvey the Gas Processors Association(GPA), a trade association representinggatherers and processors, conducted in

December 2003. These tradeassociations and the U.S. Department ofEnergy (DOE) suggested that DOTshould first identify and analyze therisks involved and then targetregulations to specific problems. CookInlet Keeper, a nonprofit organizationdedicated to protecting Alaskas CookInlet Watershed and North SlopeBorough, the northernmost county ofAlaska, advocated regulation of allunregulated lines threatening peopleand the environment. Cook Inlet Keeperalso submitted data on releases fromunregulated pipelines in Alaska.

GPA presented the survey at ameeting of PHMSAs gas pipeline safetyadvisory committee on February 5, 2004(Docket No. PHMSA19984470120).The survey asked 40 operators of ruralgas gathering lines about incidentsimpacting the public during a 5-yearperiod (19992003). The survey showed58 incidents occurred on 171,768 milesof pipeline, about 96 percent of GPAmembers gathering lines. The incidentsresulted in three injuries and one deathas well as evacuations, minor propertydamage ($5,000$25,000), and majorproperty damage (over $25,000).Corrosion caused most of the incidents,

followed by third-party excavation,which produced the most severeconsequences (including the death andtwo of the injuries). No other causeoccurred more than twice. Incomparison to transmission incidentsreported to DOT over the same period,transmission lines impacted the publicfrom three to six times more often, eventhough the reporting threshold forproperty damage was 10 times as highas the surveys threshold. GPAattributed the lower impact of ruralgathering lines to operators safetypractices and to operating conditions

generally involving sparsely populatedareas, low pressures, and small pipesizes.

Concerning the approach toregulation, the coalition suggested anoverall plan covering rural and nonrurallines under which the intensity ofregulation would increase with riskdetermined by operating parameters andpopulation density. Under the currentplan, regulated nonrural gathering linesposing a lower risk would be subject tofewer safety rules than they are now.ONEOK, Inc., an operator of gas

gathering lines, suggested a similar butmore detailed tiered approach. DeltaCounty, Colorado preferred the slidingcorridor approach discussed at thepublic meetings. Two industrycommenters favored a hands-offapproach that would leave theregulation of rural gathering to Stateagencies already regulating oil and gas

production.Several trade associations were

concerned about the impact of any newDOT regulations on rural gatheringlines. DOE and the IndependentPetroleum Association of America wereparticularly concerned that increasedcosts could cause producers to shut inmarginally profitable wells. Theypointed out that since marginal wellsaccount for about 10 percent of U.S. gasproduction, additional costs couldreduce gas supplies.

D. Alternatives To Resolve theDefinition Problem

Considering the previous attempts in1974 and again in 1991 to resolve thedefinition problem were controversial,we concluded a single definition whollyconsistent with industrys complexpractices probably could not bedeveloped. So we looked closer at APIRP 80. Its development by a wide rangeof experienced personnel, its attentionto detail, and its backing by commentersled us to believe it could, if usedappropriately, distinguish gatheringlines under part 192 without thecontroversy attendant to the earlierproposals. In reaching this conclusion,

we did not intend persons to use API RP80 for non-safety purposes, such as toidentify gathering under the Natural GasAct. By its own terms, API RP 80applies only in the context of pipelinesafety: [T]he definitions presentedherein are not designed to addressissuesnor are they intended forapplicationin any regulatory contextother than gas pipeline safety pursuantto the Federal Pipeline Safety Act(section 2.6.2.4 of API RP 80).

We considered the following waysAPI RP 80 could serve to determineonshore gas gathering under part 192:

1. Use API RP 80 as guidance todetermine the beginning and end ofonshore gathering under the presentpart 192 definition. The advantages ofthis alternative were some operatorswould likely support it and rulemakingwould not be necessary. On the otherhand, this alternative would probablynot be sufficient to satisfy thecongressional directive to define gasgathering and it would provide a shaky

basis for regulating rural gathering lines.In addition, NAPSRs commentssuggested many State pipeline safety



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agencies would be unlikely to acceptsome API RP 80 provisions even asguidance.

2. Adopt API RP 80 as the basis fordetermining onshore gas gathering lines.This alternative had wide industrysupport, would likely minimize thedifficulty of distinguishing gatheringlines, and would likely result in few

pipeline reclassifications. However, APIRP 80s many supplemental definitions,descriptions, and diagrams, althoughhelpful, could be difficult to applyuniformly. Also, as NAPSR contended,the furthermost downstreamprovisions of API RP 80 could result inmanipulation of endpoints to avoidpipeline regulation. If that happened,State pipeline safety agencies could losecontrol over many miles of pipelinethey now regulate, and public safetycould be compromised.

3. Adopt API RP 80, but withlimitations to remove opportunities formanipulation. The main advantage ofthis alternative was it would balanceindustrys desire to use API RP 80 withNAPSRs desire for definite endpoints.The disadvantage was limitations couldmake API RP 80 more difficult to apply.In addition, any limitation could renewindustrys claims of linereclassifications. As discussed further insection II of this preamble, we chosethis alternative for the proposeddefinition ofonshore gathering line.

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

PHMSA has authority under 49 U.S.C.

60102(a) to issue safety standards for gaspipeline transportation. In 1992,Congress granted DOT specific authorityto define gas gathering for purposes ofsafety regulations. Congress alsorecognized that some rural gatheringlines might present unacceptable risksand authorized DOT to regulate lineswhose risk warranted regulation. In itsreport on H.R. 1489, a bill leading to the1992 change in the law, the HouseCommittee on Energy and Commercesaid DOT should find out whether anygathering lines present a risk to peopleor the environment, and if so how large

a risk and what measures should betaken to mitigate the risk. (H.R. ReportNo. 102247, Part 1, 102nd Cong., 1stSess. 23 (1991)).

As discussed above, because DOTlacked information about whether therisks of rural lines warranted regulation,it held a Web discussion and then twopublic meetings to get input from thepublic on the need to regulate theselines. GPA submitted the most detailedinformation based on a survey of itsmembers. Although the survey resultsshowed rural gathering lines presented

a lower risk to the public thantransmission lines, the impacts to thepublic and property during the surveyperiod were not insignificant. Manypeople living or working near rural linessuffered adverse consequences. Also,the potential for future harm wasapparent, because the survey confirmedthe leading threats to rural gathering

lines: corrosion and excavation damage,matched the leading threats to regulatedgas pipelines.

Not all rural gathering lines present aslow a risk as the lines in GPAs survey.Some rural lines are near pockets ofhousing or operate at high pressuresthreatening housing further away. Infact, high-pressure gathering lines inpopulated areas can present the samerisk as regulated transmission lines.

In consideration of the known andforeseeable risks presented by ruralgathering lines, we decided it was nolonger appropriate to maintain the

almost total exemption of rural linesfrom part 192. But in changing thepresent exemption, we also decided tofocus on lines posing significant risk, orlines located where a release of gascould have serious consequences.

F. Approach To Regulating OnshoreGathering Lines

We believe the potential for harm ofsome onshore gathering lines is too lowto warrant DOT regulation. These linesgenerally have small diameters andoperate at low pressures in remote orsecluded areas.

For other lines, we agree with

commenters that the level of regulationshould increase as risk increases byoperating pressure and proximity topeople. Under this approach, thehighest risk lines would have the mostregulation. This approach is consistentwith the statutory directive ondetermining which rural gathering lineswarrant regulation.

In deciding what safety rules to applyaccording to risk, we favored the tieredmodels two commenters suggested.Tiers are a reasonable way to pair safetyregulations with lines posing differentlevels of risk. However, considering the

need for practicality in both complianceand enforcement, we created a modelwith only two tiers. This approach isdiscussed in more detail in section II ofthis preamble.

Currently, part 192 regulates nonruralgathering lines and transmission linessimilarly, except 192.150 pig passageand subpart O apply only totransmission lines. Nevertheless,PHMSAs incident data indicategathering and transmission lines do notpose the same overall level of risk to thepublic. This data shows that

transmission line incidents have had agreater impact on the public thangathering line incidents. We therefore

believe a significant factor in manynonrural gathering line segments is thatthey operate at low pressures away fromhighly populated areas. So safety rulesintended for all transmission lines areprobably not appropriate for all

gathering lines.A related problem with the current

part 192 approach to regulation ofnonrural lines involves line segmentsinside sparsely populated areas of citiesor towns. Often a city or town willextend its boundaries to incorporatethese rural-like areas. For instance, alow-pressure gathering line in suchareas may be distant from any populatedsite but because it lies within city ortown boundaries it becomes subject topart 192 and must meet transmissionline rules.

We believe a risk-based approach isthe most suitable for applying part 192rules to onshore gathering lines whetherthe lines are in rural or nonrural areas.Regulation of an onshore gathering lineshould not depend on subdivision orlocal government boundaries as it doesnow, but on the risk the line poses tothe public based on its pressure andproximity to people. For example, theproximity of a line to dwellings is amuch more precise measure of risk thanthe rural-nonrural approach currently inuse. For nonrural lines, this change toa risk-based approach would maintainthe current level of regulation wherejustified by risk. At the same time, it

would lighten the present regulatoryburden on less risky lines.

II. Proposed Rules

To get public comments on its latestapproach to defining and regulating thesafety of onshore gas gathering lines, onOctober 3, 2005, PHMSA published asupplementary notice of proposedrulemaking (SNPRM) (70 FR 57536).The SNPRM was a continuation of therulemaking proceeding started by the1991 notice of proposed rulemaking(NPRM).

The SNPRM sought comments on

proposed new definitions of the termsonshore gathering line and regulatedonshore gathering line. Thesedefinitions would provide the basis fordetermining which gas pipelines would

be subject to part 192 rules for regulatedonshore gathering lines. Any onshoregathering line not covered by theproposed definition ofregulatedonshore gathering line would not besubject to part 192. The SNPRM alsosought comments on proposed risk-

based safety rules for regulated onshoregathering lines. A description of the



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proposed definitions and safety rulesfollows.

A. Proposed Definition ofOnshoreGathering Line

We wanted to define onshoregathering line in a way that not onlyreasonably matched currentclassifications but also addressed

NAPSRs concerns. So we proposed toallow operators to use API RP 80 todetermine onshore gathering lines.But use of API RP 80 would be subjectto the following five limitations on the

beginning of gathering and the possibleendpoints of gathering under section2.2(a) of API RP 80:

1. Under section 2.2(a)(1), thebeginning of an onshore gathering lineis the furthermost downstream point ina production operation. We proposed torestrict this point to piping orequipment used solely in the process ofextracting natural gas from the earth forthe first time and preparing it fortransportation or delivery. The purposeof the limitation was to ensure certaindual-use equipment, capable of use ineither production or transportation,would be part of gathering when notused solely in the process of extractingand preparing gas for transportation.

2. Under section 2.2(a)(1)(A), the firstpossible endpoint is the inlet of thefurthermost downstream natural gasprocessing plant, other than a naturalgas processing plant located on atransmission line. We proposed thisendpoint may not be a natural gasprocessing plant located further

downstream than the first downstreamnatural gas processing plant unless theoperator can demonstrate, based onsound engineering reasons, gatheringshould extend beyond the first plant.Past DOT interpretations and Stateagency enforcement actions haverecognized the first downstream naturalgas processing plant as the customaryend of gathering. (See PHMSAs Website for interpretations and enforcementactions: http://www.phmsa.dot.gov/.)

3. Under section 2.2(a)(1)(B), thesecond possible endpoint is the outlet ofthe furthermost downstream gathering

line gas treatment facility. We proposedthis endpoint would apply only if noother endpoint under sections 2.2(a)(1)(A), (C), (D) or (E) existed.

4. Under section 2.2(a)(1)(C), the thirdpossible endpoint is the furthermostdownstream point where gas producedin the same production field or separateproduction fields are commingled. Thisendpoint recognizes a gathering linemay receive gas from several productionfields. But because it does not restrictthe distance between fields, gatheringcould potentially continue endlessly,

causing reclassifications fromtransmission to gathering along the way.To set a reasonable limit, we proposedthat separate production fields fromwhich gas is commingled must bewithin 50 miles of each other. Wespecifically invited comments onwhether a maximum distance is needed.

5. Under section 2.2(a)(1)(D), the

fourth possible endpoint is the outlet ofthe furthermost downstream compressorstation used to lower gathering lineoperating pressure to facilitatedeliveries into the pipeline fromproduction operations or to increasegathering line pressure for delivery toanother pipeline. For consistency withour past interpretations and currentenforcement policy, we proposed tolimit this endpoint to the outlet of acompressor used to deliver gas toanother pipeline.

We did not propose a limitation onthe fifth possible endpoint undersection 2.2(a)(1)(E). This endpoint is theconnection to another pipelinedownstream of the furthermostdownstream endpoint under sections2.2(a)(1)(A) through (D), or in theabsence of such an endpoint, thefurthermost downstream productionoperation. The endpoint applies toconnecting lines described asincidental gathering under section2.2.1.2.6 of API RP 80. An example ofa connecting line is a pipeline that runsfrom the outlet of a natural gasprocessing plant to a transmission line.PHMSA considers incidentalgathering to include only lines that

directly connect a transmission line toone of the endpoints (A) through (D), aslimited by this final rule. Lines thatconnect a transmission line to one ofthese endpoints by way of anotherfacility are not considered incidentalgathering.

B. Proposed Definition ofRegulatedOnshore Gathering Line

We proposed to amend 192.3 todefine regulated onshore gatheringlines by either of two risk categories,Type A and Type B, based on operatingstress and location. Type A would

include lines whose maximumallowable operating pressure (MAOP)results in a hoop stress of 20 percent ormore of SMYS, and non-metallic lineswhose MAOP is more than 125 persquare inch gauge (psig). The locationwould be Class 3 and 4 locations, asdefined in 192.5, and other areas theoperator determines using potentialimpact circles with five or moredwellings or a sliding corridor 440 yards

by 1000 feet with either 5 or moredwellings per 1000 feet or 25 or moredwellings per mile, whichever results in

more regulated lines. Type A lines in aClass 1 or Class 2 location would alsoinclude additional lengths of lineupstream and downstream to serve as ashield against potential harm to nearbydwellings.

Type B lines would include metalliclines whose MAOP produces a hoopstress of less than 20 percent of SMYS,

and non-metallic lines whose MAOP is125 psig or less. The location would beClass 3 and 4 locations and other areasdetermined by a sliding corridor 300feet by 1000 feet with 5 or moredwellings per 1000 feet. Lines within aClass 1 or Class 2 location wouldinclude additional lengths of line as ashield against potential harm to nearbydwellings.

C. Proposed Safety Requirements

We proposed to revise 192.9 toinclude safety requirements for allgathering lines subject to part 192.Paragraph (b) would simply restate thepresent part 192 requirementsapplicable to offshore gathering lines.

Under paragraph (c), Type Aregulated onshore gathering lines wouldhave to meet part 192 requirementsapplicable to transmission lines, exceptrequirements concerning the passage ofsmart pigs (192.150) and integritymanagement (subpart O). Because of thehigher stress at which Type A linesoperate and their ability to harm moreof the public, we considered Type Alines to warrant safety requirementsequivalent to transmission linerequirements. Currently regulated

gathering lines are subject to theserequirements.

Paragraph (d) contains the proposedrequirements for Type B regulatedonshore gathering lines. These lines,although located near the public andhousing, operate at a lower stress thanType A lines and pose a lower-risk. Sofor Type B lines, we proposed safetyrequirements focused just on the mainthreats to these linescorrosion andexcavation damage. First, new lines andexisting lines replaced, relocated, orotherwise changed would have to bedesigned, installed, constructed,

initially inspected, and initially testedaccording to part 192 requirements.Second, operators of Type B lines wouldhave to control corrosion according toapplicable subpart I requirements; carryout a damage prevention program under192.614; establish MAOP under192.619; install and maintain linemarkers under 192.707 according totransmission line requirements; andestablish a public education program asrequired by 192.616.

To allow time for line identificationand preparation for compliance, we

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2As defined in section 2.3 of API RP 80,production operation means piping andequipment used for production and preparation fortransportation 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 productioncompression, gas lift, gas injection, or fuel gassupply.

proposed extended compliancedeadlines in paragraph (e) for operationand maintenance requirements.Similarly, we proposed to amend192.13 to allow 1 year after the finalrule takes effect before new, replaced,relocated, or otherwise changed lineswould have to meet design andconstruction requirements. Also in

paragraph (e), we proposed to allowoperators 1 year to bring unregulatedlines into compliance if they becomeregulated because of changes inpopulation.

In addition, we proposed to ease thetransition to regulated status of newlyregulated lines and lines subsequentlyregulated due to population increases byrevising the MAOP requirements of192.619(a)(3) and (c). The proposalwould allow operation of a line at thehighest actual operating pressure towhich it was subjected during the 5years before the final rule is published

or the line becomes regulated.As part of the corrosion controlrequirements, we proposed to applythose subpart I requirements specificallyapplicable to pipelines installed beforeAugust 1, 1971, to regulated onshoregathering lines in existence when thefinal rule takes effect and not previouslysubject to subpart I (lines in rurallocations). Other subpart I requirementsspecifically applicable to pipelinesinstalled after July 31, 1971, would notapply to these existing lines unless theysubstantially meet the requirements.

D. Related Proposals

We proposed to amend 192.1(b)(4)to exclude from part 192 onshoregathering lines operating under vacuum,or at less than atmospheric pressure. Wereasoned that regulation was notnecessary because these lines pose littlerisk since they cannot release naturalgas to the atmosphere. An additionalamendment to this section clarifies thepresent rulemaking on onshoregathering lines does not affect gatheringlines in inlets of the Gulf of Mexico.

III. Advisory CommitteeRecommendations

The Technical Pipeline SafetyStandards Committee (TPSSC), astatutorily mandated advisorycommittee, advises PHMSA onproposed safety standards and otherpolicies concerning gas pipelines. Thecommittee has an authorizedmembership of 15 persons withmembership evenly divided betweengovernment, industry, and the public.Each member is qualified to considerthe technical feasibility, reasonableness,cost-effectiveness, and practicability ofproposed pipeline safety standards.

The TPSSC considered the SNPRM ata teleconference on January 19, 2006.During the conference, we discussed thepublic comments summarized in sectionIV of this preamble and the draftRegulatory Evaluation of costs and

benefits. After careful consideration, theTPSSC voted unanimously to find theSNPRM and supporting Regulatory

Evaluation technically feasible,reasonable, practicable, and cost-effective, subject to resolution of thecomments in the manner we discussed.A transcript of the teleconference isavailable in Docket No. PHMSA984470.

IV. Disposition of Comments onProposed Rules

We received written comments on theSNPRM from 19 sources: American GasAssociation (AGA), Clark ResourceCouncil and Powder River BasinResource Council, Columbia GasTransmission Corporation (Columbia),Cook Inlet Keeper, Dominion Delivery(Dominion), Duke Energy Field Services(Duke), Equitable Resources (Equitable),Independent Petroleum Association ofAmerica (IPAA), National Association ofPipeline Safety Representatives(NAPSR), National Fuel Gas SupplyCorporation (NFGSC), Oil and GasIndustry Onshore Gas GatheringRegulation Coalition (Coalition),Oklahoma Corporation Commission(OCC), Oklahoma IndependentPetroleum Association (OIPA), PipelineSafety Trust (PST), Public ServiceCommission of West Virginia (PSCWV),

Public Utilities Commission of Ohio,Robert A. Honig, Susan Franzheim, andWest Texas Gas, Inc. (West).

In the SNPRM, we discussed theimpact our proposed gathering linedefinition might have on economicdecisions of the Federal EnergyRegulatory Commission (FERC).Although we concluded the definitionwas unlikely to influence FERCsdecisions, we suggested an alternativeapproach that would not definegathering lines, just which gatheringlines would be regulated for safety. Wespecifically invited comments on the

potential impact of the proposeddefinition on FERC decisions, on waysto avoid difficulties of the alternativeapproach, and on advantages anddisadvantages of either approach. Noone who submitted comments on theSNPRM addressed any of these issueseither directly or indirectly. Wecontinue to believe that the approachwe adopt in this final rule will not haveimplications on FERC practice. Thisapproach does not rely on the NaturalGas Act for determining if a pipeline isa gathering line.

Commenters generally favored theproposed definitions and tiered safetyrequirements subject to changesdiscussed in the outline below.However, West was against regulation ofrural gathering lines, saying it was notneeded because strong economic andliability-avoidance incentives encouragesafe operations, and States can act if

needed. West also said the RegulatoryEvaluation was based onunsubstantiated assumptions,particularly with respect to the impactof lost reserves due to prematureabandonment of stripper wells.

We disagree with West on the needfor DOT regulation of rural gas gatheringlines. Although operators haveeconomic and legal incentives tooperate these lines safely and States cantake regulatory action, we think DOTregulation is still needed. As explainedabove in section I of this preamble, thisneed derives from the Congress concern

about the safety of higher-risk ruralgathering, public comments favoringregulation where warranted by risk, andthe incident data industry submittedshowing rural gathering linesexperience the same leading causes ofaccidents as lines PHMSA nowregulates. Thus, the present exemptionof rural gathering lines from nearly allsafety rules in part 192 is no longerappropriate. We took Wests commenton the draft Regulatory Evaluation intoaccount in preparing a final evaluation.

A. Limitations on Using API RP 80Definition ofGathering Line

As explained in the SNPRM, weproposed to adopt API RP 80 as the

basis for determining onshore gatheringlines and which of these lines would besubject to part 192 (70 FR 57540). Underthis proposal, to determine if a pipelineis an onshore gathering line, operatorswould use API RP 80 in its entirety,including the definition ofgatheringline in section 2.2, the definition ofproduction operation in section 2.3,2the supplemental terms in section 2.4,and the Decision Trees, andRepresentative Applications.

However, we recognized the

definition ofgathering line

in section2.2 of API RP 80 is susceptible to

manipulation because it uses the termfurthermost downstream to identify



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facilities marking the beginning and endof a gathering line. By installing certaindual-use equipment (equipment used ineither production or pipelinetransportation, such as separators ordehydrators) further downstream fromnormal production, operators couldarguably extend production and reducethe amount of regulated gathering.

Similarly, the furthermostdownstream feature would allowoperators to manipulate gatheringendpoints marking the changeover totransmission, resulting ininconsistencies with prior DOTinterpretations. So we proposed thefollowing five limitations on use of thedefinition.

1. Limitation on Furthermost Point ofProduction

Under section 2.2(a)(1) of API RP 80,gathering begins at the furthermostdownstream point in a productionoperation. We proposed the followinglimitation on this aspect of thedefinition:

The beginning of a gathering line may notbe further downstream than piping orequipment used solely in the process ofextracting natural gas from the earth for thefirst time and preparing it for transportationor delivery.

The purpose was to classify dual-useequipment as transportation equipmentif it is not used in the process ofproducing and preparing gas fortransportation. In other words, onceproduced gas enters pipelinetransportation, any dual-use equipment

installed further downstream would betransportation equipment and notproduction equipment.

a. Comments

Coalition thought the limitationwould expand gathering to includefacilities, such as centralized separation,that API RP 80 describes as productionoperations. It offered the followingalternative wording to precludeproduction 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 downstreamlocation not normally associated with aproduction operation; or

(2) Natural gas injection into, andsubsequent withdrawal from, a gas storagecavern or field.

Similarly, IPAA found the proposalconfusing and said it would impactpotentially thousands of producersacross the country. It urged us to adopta clear production definition, andsuggested the following:

Production Operation means any pipingand equipment that qualify as a production

operation under section 2.3 of API RP80,with the following limitations: (1) Facilitiesoperated in connection with natural gasstorage operations shall be excluded; and (2)separation and dehydration facilities locatedcontrary to the prudent operating standardscommonly applicable in the industry to theparticular geographic location and solely forthe purpose of avoiding regulation as agathering line under Title 49 of the Code of

Federal Regulations, part 192, shall beexcluded.

OCC, OIPA, NAPSR, and PST found theproposed limitation ambiguous. Theytoo recommended alternative solutions.OCC and OIPA asked us to clarify thereference to the API RP 80 definition ofproduction operations. NAPSR andPST recommended adding the phrasefor the first time at the end of theproposed limitation.

b. PHMSA Response

We think the text of the proposed rule(70 FR 47546) was the cause of thecommenters concerns. Nowhere doesthe proposed text say operators mustuse API RP 80 in its entirety todetermine onshore gathering lines, eventhough in the SNPRM preamble weproposed such use subject to certainlimitations on section 2.2. Thisomission created uncertainty about useof the API RP 80 definition ofproduction operations. In addition,commenters may have thought thephrasing of the proposed limitationwould narrow the meaning ofproduction operations in API RP 80.However, we merely intended thelimitation to clarify the classification of

dual-use equipment positioneddownstream from productionoperations.

To resolve this misunderstanding, thefinal rule does not add a definition ofonshore gathering line to 192.3 asproposed. Instead, we created a new192.8, titled How are onshoregathering lines and regulated onshoregathering lines determined? Paragraph(a) of this new section allows operatorsto determine onshore gathering linesaccording to API RP 80, subject tocertain limitations. Thus, operatorsmust use API RP 80 in its entirety to

determine onshore gathering lines, notjust section 2.2 as the proposeddefinition ofonshore gathering lineimplied.

In addition, in final 192.8(a)(1), wechanged the proposed limitation on thefurthermost point of production to focuson the classification of dual-useequipment. The limitation now providesthe beginning of gathering may notextend beyond the furthermostdownstream point in a productionoperation. This furthermost point doesnot include equipment capable of use in

either production or transportation,such as separators or dehydrators,unless the equipment is involved in theprocesses ofproduction andpreparation for transportation ordelivery of hydrocarbon gas within themeaning ofproduction operationunder section 2.3 of API RP 80. Thischange removes any inference that the

limitation narrows the meaning ofproduction operation under section2.3 of API RP 80.

We did not adopt commenterssuggestions to exclude from productionequipment at an extreme downstreamlocation not normally associated with aproduction operation or facilitieslocated contrary to the prudentoperating standards because theseterms are not precise enough for a safetyrule. However, we think the situationsthey depict are relevant to deciding ifequipment falls within the meaning ofproduction operation under API RP

80. Also, we did not think additionaluse of the term for the first time, astwo commenters suggested, wouldlessen the confusion the proposedlimitation created. Finally, we did notsee any need to exclude fromproduction any equipment used inconnection with a natural gas storagecavern or field because section 2.4.4 ofAPI RP 80 indicates the term storagein the definition ofproductionoperation does not includeunderground storage of natural gas.

2. Limitation on Furthermost GasProcessing Plant Endpoint

Under section 2.2(a)(1)(A) of API RP80, gathering ends at the inlet of thefurthermost downstream natural gasprocessing plant not on a transmissionline. We proposed the followinglimitation:

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

The purpose of the limitation was tomaintain consistency with prior DOTinterpretations and State agency

enforcement actions on gathering.a. Comments

Coalition and Duke were concernedabout the impact the closing of a gasprocessing plant could have ongathering line classifications. Theyasked us to clarify that the endpoint ofgathering would not change if a plantcloses temporarily for maintenance ormarket reasons.

West objected to placing the burdenon operators to prove the need forfurther downstream processing. It



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thought the government should have theburden of proving further downstreamprocessing is not needed. In addition,West thought we should alloweconomic reasons as proof.

b. PHMSA Response

We have not experienced a situationin which the closing of a gas processing

plant affected a gathering lineclassification. Although closings of afew weeks for maintenance reasonswould not trigger a classificationchange, longer closings could occur fora variety of reasons and the durationcould be uncertain. So we decided notto make a general statement on howtemporary plant closures would affectthe end of gathering. Instead, whenrequested, we will determine the impactof closings on an individual basis as theneed to do so arises. We expect certifiedState agencies with safety jurisdictionover gathering lines under 49 U.S.C.60105 will do likewise.

Regarding Wests burden of proofissue, it is not unusual for part 192safety rules to include exceptionsapplicable only if operators candemonstrate certain conditions exist.For example, under 192.479(c),operators do not have to protectaboveground pipelines fromatmospheric corrosion if theydemonstrate the corrosion will havecertain characteristics. We requireoperators to demonstrate grounds forexceptions when they are the bestsource of information on which theexception is based. In the case of

gathering lines, we think operators arethe best source of information todemonstrate why further downstreamprocessing is necessary to complete thegathering process.

As for the proof required in thedemonstration, no doubt economicswould be a factor in any decisioninvolving further downstreamprocessing. However, many of our priorinterpretations have based the end ofgathering on the first downstreamprocessing plant. Maintainingconsistency with this policy as far aspossible is desirable for both

government and industry. For thisreason, we think any future variationshould be based on the fundamentalqualities of gas processing, which is bestdetermined by engineering analysesrather than economic conditions, whichare transitory. Therefore, the proposedlimitation is unchanged in the final rule.

3. Limitation on Furthermost TreatmentFacility Endpoint

Under section 2.2(a)(1)(B) of API RP80, gathering ends at the outlet of thefurthermost downstream gathering line

gas treatment facility. We proposed thefollowing limitation:

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

We intended this limitation to precludemanipulation of the transition from

gathering to transmission by installingequipment used in gas treatment.

a. Comments

Coalition, supported by Duke, said theproposed limitation would make thefurthermost treatment endpointunusable, because processing,commingling, or compression is almostalways upstream of a treatment facility.These commenters insisted gatheringshould continue downstream to a gastreatment facility endpoint no matter ifcompression, commingling, orprocessing occurs upstream. Coalition

offered an alternative approach topreclude treatment manipulation:

(1) Use the following wording: The end ofa gathering line * * * shall not be defined

by the installation of one or more pieces ofgas treating equipment at an extremedownstream location that is not justified bysound engineering and economic principlesindependent of the pipelines regulatoryclassification. (2) Explain in the final rulepreamble that this endpoint refers to a gastreating plant or similar facility and is notintended to be a simple piece of equipmentlike a separator or dehydrator (other than ascan be shown, using sound engineering andeconomic principles, to be needed at thatlocation to meet transmission pipeline

specifications).

b. PHMSA Response

Section 2.2.1.2.2 of API RP 80explains the meaning of a gas treatmentfacility under section 2.2(a)(1)(B). Thisprovision describes gathering gastreatment (other than treatment in gasprocessing or compression) as involvingsignificant stand-alone facilities (e.g., asulfur recovery or large dehydrationfacility). We think this explanation issufficient to preclude possiblemanipulation of the treatment endpoint

by installing a simple piece of

treatment-related equipment, such as aseparator or dehydrator. Thus,Coalitions alternative is not necessaryand the proposed limitation iswithdrawn.

4. Limitation on FurthermostCommingling Endpoint

Under section 2.2(a)(1)(C) of API RP80, gathering ends at the furthermostdownstream point where gas producedin the same production field or separateproduction fields is commingled. Weproposed the following limitation:

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

With no limit on the distance betweenseparate production fields, a gatheringline could continue endlessly, causingreclassification of pipelines fromtransmission to gathering.

a. Comments

Coalition, Duke, and West said theproposed limitation was not flexibleenough to account for futureacquisitions and use of maturing fields.Duke said its existing commingled fieldswere less than 50 miles apart. AlthoughCoalition thought some commingledfields were 125 miles apart, it did notcite an actual example. Coalition andDuke recommended allowing case-by-case regulatory approvals of longerdistances based on sound engineeringand economic reasons.

b. PHMSA Response

Because, Duke, the largest gasgathering line operator in the U.S., saidthe proposed 50-mile limit would beadequate for its current systems, theproposed 50-mile limit is unchanged inthe final rule. We did not adoptCoalitions request to change the limit to125 miles because it did not provide anyexamples of an existing system wherethe 50-mile limit would be toorestrictive. However, to provideflexibility, the final rule allowsoperators to petition PHMSA, under the

procedures in 49 CFR 190.9, to find alonger limit is justified in a particularcase.

5. Limitation on FurthermostCompressor Endpoint

Under section 2.2(a)(1)(D) of API RP80, gathering ends at the outlet of thefurthermost downstream compressorstation used to lower gathering lineoperating pressure to facilitatedeliveries into the pipeline fromproduction operations or to increasegathering line pressure for delivery toanother pipeline. We proposed the

following limitation:The endpoint may not extend beyond the

furthermost downstream compressor used toincrease gathering line pressure for deliveryto another pipeline.

This limitation is consistent with ourpast interpretations.

a. Comment

Coalition agreed with the proposedlimitation, but asked us to clarifydelivery to another pipeline does notmean delivery to another gathering line.



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b. PHMSA Response

Section 3.2.8 of API RP 80 says, thedefinition of gathering line did notdirectly address the issue of oneoperators gathering line beginning orending with a connection to anotheroperators gathering line. Based on thisclarification, we believe the termanother pipeline in section2.2(a)(1)(D) of API RP 80 does not meandelivering to another gathering line.

B. DefiningRegulated OnshoreGathering Line

We proposed to change how part 192applies to onshore gathering linesoutside inlets of the Gulf of Mexico bymaking the rules fit the level of riskgathering lines present. The proposalwould restrict rules to two categories oflines, Type A and Type B, and definethese lines as regulated onshoregathering lines. A description of theproposed definition is in section II of

this preamble.1. Approach To Defining RegulatedLines

a. Comments

Columbia suggested we adopt asimpler definition ofregulated onshoregathering line limited to lines in Class3 and Class 4 locations and lines inClass 1 and Class 2 locations where apotential impact circle includes 20 ormore dwellings. It said the alternativewould be easier to understand andapply, and consistent with thescientific-based definition ofhigh

consequence area in 192.903. PSTalso suggested a more straightforwardapproach under which gathering andtransmission lines of similar pressuresand operating conditions would beregulated alike, and other gatheringlines would be regulated the same asdistribution lines.

b. PHMSA Response

We did not adopt Columbiasalternative because it would apply thesame classification method (potentialimpact circles with 20 or moredwellings) 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 toosmall to include 20 or more dwellings.So the risk of low-pressure lines tofewer than 20 nearby dwellings wouldnot be addressed.

PSTs alternative parallels ourproposal to regulate higher-riskgathering lines the same as transmissionlines, but most transmission line rulesare more stringent than appear to benecessary for lower-risk gathering lines.

Also, gathering lines are not sufficientlysimilar to distribution lines to apply thesame rules to both types of lines.

2. Identifying Regulated Lines byPotential Impact Circles

a. Comments

AGA and Dominion supported usingpotential impact circles to identifyhigher-risk regulated gathering, but saidthe population criteria (proposed 5 ormore dwellings) should not be morestringent than the criteria applied to gastransmission lines (20 or moredwellings under 192.903). Dominionalso suggested allowing use of impactcircles as an optional identificationmethod for Type B lines, not just TypeA lines as proposed.

NAPSR spotted an irregularity inusing potential impact circles to identifyType A lines. Some smaller Type Blines (10 inches nominal diameter orless) uprated to operate above 20

percent of SMYS would lose theirregulated status if operators use impactcircles to identify Type A lines and thecircles do not contain the minimumnumber of dwellings (5) found in therectangles (300 ft x 1000 ft) previouslyused to identify the lines as Type B.Likewise, the use of impact circlescould cause some currently regulatednonrural lines operating above 20% ofSMYS to lose their regulated status,even though similarly situated Type Blines would remain regulated.Consequently, NAPSR suggested weadopt the proposed Type B rectangles

and safety rules as the minimumstandard of safety for all regulated lines.

b. PHMSA Response

The decision discussed below (inresponse to NAPSRs comment) towithdraw the proposal on usingpotential impact circles to identify TypeA lines makes the AGA and Dominioncomments moot. Nevertheless, we offerthe following: Section 192.903 requires20 or more dwellings in potentialimpact circles used to identifytransmission line segments subject tointegrity management rules. These rules

apply to the identified segments inaddition to other applicabletransmission rules. In contrast, we didnot propose to apply integritymanagement rules to Type A linesidentified by circles with just 5dwellings or more. So we do notconsider the proposed 5-per-circlemethod to be more stringent than the20-per-circle method used for integritymanagement.

We did not propose potential impactcircles to identify Type B lines becausefor low-pressure lines the circles would

most likely be too small to contain atleast 5 dwellings. For this reason, theywould not equate to the proposedmethod of 5 or more dwellings per 1000feet. As further explained undersubheading 4 of this section of thepreamble, we did not adopt potentialimpact circles as a method to identifyType B lines.

We believe NAPSR recognized aserious equivalency problem inallowing use of the proposed impactcircles to identify Type A lines. Theoutcome could easily be an unregulatedgathering line operating above 20percent of SMYS next to a regulatedType B line, with both lines exposingthe same dwellings to risk. To avoid thissituation, we are withdrawing theproposal to use potential impact circlesto identify Type A lines. We did notadopt NAPSRs suggested remedy

because the compliance cost ofdetecting 5 dwellings per 1000 feet

would likely be disproportionate to thebenefits, as discussed below undersubheading 4 of this section of thepreamble.

3. Identifying Regulated Lines byOperating Stress

a. Comment

Coalition said 20 percent of SMYS istoo low to distinguish high-stress TypeA lines from low-stress Type B lines. Itrecommended using 30 percent ofSMYS as in 192.935, 192.937, and192.941 for integrity management and in

192.505 and 192.507 for pressuretesting because lines operating at lessthan 30 percent of SMYS may leak butnot rupture.

b. PHMSA Response

To regulate the safety of rural gasgathering lines, PHMSA must considervarious physical characteristics,including operating pressure, to decidewhich lines warrant safety regulation(49 U.S.C. 60101(a)(21)(B) and(b)(2)(A)). We proposed 20 percent ofSMYS as indicative of onshore gatheringlines whose operating pressure presents

a significant enough risk in certaincircumstances to warrant the sameamount of regulation as transmissionlines, except rules on integritymanagement and smart pig passage. The

basis for this 20-percent threshold is thepart 192 definition oftransmissionline, which includes pipelines otherthan gathering lines operating at 20percent of SMYS or more. Thesepipelines must meet all applicable part192 safety rules. Because Type A linescan pose risks similar to transmissionlines, we do not think 30 percent of



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SMYS would be an appropriatethreshold for Type A lines.

4. Identifying Regulated Lines OutsideClass 3 and 4 Locations by 5 Dwellingsper 1000 Feet

a. Comments

Coalition, Dominion, and Dukebelieved frequently surveying slightlypopulated areas (Class 1 and 2locations) to identify line segments with5 dwellings per 1000 feet would dilute,rather than expand, public safety bydiverting attention from heavilypopulated areas (Class 3 and 4locations). Coalition and Duke also said

because most operators do not have theproposed 5-per-1000 dwelling data, theywould have to create a new surveyprocess and train personnel to use it. Toapply the 5-per-1000 process initially,Coalition believed operators wouldsurvey all their onshore gathering lines(rather than 25 percent as we estimated)

at a cost of $99.5 million (four times ourestimate). From then on, Coalitionestimated operators would resurvey atleast 65 percent of lines each year at acost of over $12.9 million instead of ourestimate of 15 percent at $3 million.

To improve cost effectiveness,Coalition recommended an alternativeregulatory approach to identifyregulated onshore gathering lines inareas outside Class 3 and 4 locations.This approach focuses only on lines inClass 2 locations and uses the followingmethods rather than 5 dwellings per1000 feet:

For Type A lines, areas within (1)a Class 2 location; or (2) a potentialimpact circle with a minimum radius of150 feet including 5 or more dwellings.

For Type B lines, an area 150 feeton either side of the centerline of anycontinuous 1-mile length of pipelineincluding more than 10 but fewer than46 dwellings.

In addition, for Type A lines, Dukesupported our proposed sliding mileapproach using 25 or more houses permile.

Commenting on Coalitions approach,Equitable also recommended focusing

only on Class 2 locations. But it advisedallowing operators a wider choice ofidentification methods for Type B lines:Potential impact circles like Coalitionrecommended for Type A lines, ourproposed 5-per-1000 method, orCoalitions sliding mile alternative.Equitable said expanding the options toinclude potential impact circles wouldallow operators with advanced mappingsystems to use them for compliance.

NFGSC sought to add a clusterexception to the proposed 5-per-1000method for Type B lines to avoid

regulating substantial lengths of lineposing little risk. It said a Type Bgathering line might pass within 150feet of 5 dwellings clustered near ahighway intersection, but not pass nearanother dwelling for 1,000 feet in eitherdirection. Under the proposeddefinition, the regulated segment wouldextend for up to 1,000 feet in each

direction, but pose little risk beyond thecluster. NFGSC suggested the regulatedsegment should extend in each directiononly 150 feet from the nearest dwellingin the cluster.

b. PHMSA Response

On further consideration of theproposal, we agree with commenterswho suggested frequently searching forpockets of 5 dwellings per 1000 feet inlong, thinly populated Class 1 locations,which itself has at most 10 dwellingsper mile, does not appear to be areasonable use of available resources. Sowe are withdrawing the proposal todefine certain lines in Class 1 locationsas either Type A or Type B lines.However, as stated in the SNPRM, weare considering amending 49 CFR part191 to collect reports of gathering lineincidents in rural areas. If those reportsindicate the risk of gathering lines inClass 1 locations is unacceptable, wewill consider the need to expand ourgathering line rules to include segmentsof or all lines in Class 1 locations.

We also think the burden offrequently surveying lines in Class 2locations to look for line segments with5 dwellings per 1000 feet is not the least

costly way to tackle the risks involvedwith Type A lines. Thus we areadopting instead the commentersrecommendations to identify Type Alines outside Class 3 and 4 locations aslines in Class 2 locations. Most areasoutside Class 3 and 4 locations with apopulation density of 5 dwellings per1000 feet are found in Class 2 locations.Also, focusing on Class 2 as a whole,rather than by segments, is a clear andconcise risk identification method. Ithas the advantage of allowing use ofcustomary survey methods, eliminatingthe need for operators to devise new

methods and provide additionaltraining. Our proposed sliding mileapproach with 25 or more houses permile would have some of the samedrawbacks as the 5 per 1000 approach.So it too is withdrawn. The change toClass 2 locations appears in final192.8(b)(2).

Coalitions recommendation to allowuse of potential impact circles with aminimum radius of 150 feet to identifyType A line segments in Class 2locations would not cure the irregularityNAPSR recognized. In some cases, the

practical effect of the minimum radiuswould simply be a threshold density of5 dwellings per 300 feet. This densitywould still be less stringent than thethreshold of 5 dwellings per 1000 feetwe proposed for Type B lines.

Because Type B lines operate at lessthan 20 percent of SMYS, they are notlikely to have potential impact circles

large enough to include at least 5dwellings. So for Type B lines, theimpact circle method does not equate tothe proposed 5-per-1000 method weproposed for Class 2 locations. Nor dowe think requiring impact circles tohave a minimum radius of 150 feet, ascommenters suggested, would cure theirregularity NAPSR recognized. So wedid not adopt Equitables comment toallow use of a potential impact circleswith a minimum radius of 150 feet forType B lines.

However, we favor Equitables idea ofoffering operators more than one way to

identify Type B lines outside Class 3and 4 locations. As an alternative to the5-per-1000 method, Coalition andEquitable suggested a variation of Class2 criteria in which the sliding milewould extend only 150 feet on eitherside of the centerline instead of 220yards. Because the potential impact oflines operating is less than 20 percent ofSMYS is closer to 150 feet than 220yards, we think this suggestion isreasonable. We also think smalloperators or operators who do not haveClass 2 survey data may want to use theproposed 5-per-1000 method tominimize regulated mileage. So itremains an option in final 192.8(b)(2).Also, operators well acquainted withClass 2 location surveys may prefer totreat all low-stress gathering lines inClass 2 locations as Type B lines. Thus,final 192.8(b)(2) allows this option aswell.

Regarding NFGSCs comment,192.5(c)(2) provides the followingcluster exception for Class 2 and 3locations: When a cluster of buildingsintended for human occupancy requiresa Class 2 or 3 location, the class locationends 220 yards (200 meters) from thenearest building in the cluster. As

NFGSC recommended, we think asimilar exception is appropriate forType B lines identified by any of theoptions. The exception is in final192.8(b)(2).

V. Safety Requirements

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

Under proposed 192.9(c), the safetyrules now applicable to nonruralgathering lines would apply to Type A



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3The results of this study were presented at theFebruary 2004 meeting of PHMSAs TechnicalPipeline Safety Standards Advisory Committee.

4The GPA used the following criteria to defineincidents 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).

regulated onshore gathering lines. Theserules include all part 192 rules for gastransmission lines, except the rules in192.150 on passage of smart pigs andin subpart O on integrity management.Consequently, the proposed rules wouldrequire operators to comply with OQrules in subpart N on Type A lines, nomatter where the lines are located.

1. Comments

Coalition and Duke said because mostgathering incidents are caused byexcavation damage or corrosion ratherthan operator error, application of OQrules outside Class 3 and 4 locationswould impose significant costs with noproportionate reduction in risk. Dukereasoned compliance would be verycostly because, for efficient use ofpersonnel, operators would apply OQrules to all lines in a gathering systemnot just to regulated segments. Thesecommenters recommended we drop theproposal to require OQ rules for Type Alines outside Class 3 and 4 locations. Inaddition, Coalition recommended wecollect incident data on regulated lines,and if operator error contributesnoticeably to incidents, considerextending the OQ rules at that time.

2. PHMSA Response

In response to Coalitions and Dukescomments, PHMSA again reviewed theGPA study results that were submittedto the TPSSC.3 This study looked atincidents 4 reported by 40 companiesrepresenting an aggregate 171,628 milesof non-regulated onshore gas gathering

and found 1 incident attributable tohuman error. PHMSA notes that otheroperator qualification factors mayindirectly contribute to pipelinefailures. Furthermore, Congress directedDOT to establish regulations for OQprograms on pipelines. Congress alsodirected pipeline facility operators todevelop and adopt a qualificationprogram should DOT fail to prescribestandards and criteria. Congress furtherallowed DOT and State pipeline safetyagencies to waive or modify any OQrequirements if not inconsistent withpipeline safety laws (49 U.S.C.

60131(e)(5) and (f)). Thus, Congressrecognized that compliance with OQregulations may not be suitable in allsituations. In consideration of this dataand Congress intent, PHMSA modified

the requirements of subpart N for TypeA gathering lines in Class 2 locations.This change will allow operators ofType A lines in Class 2 locations todescribe the processes they have inplace to ensure that the personnelperforming operations and maintenanceactivities are qualified. BecauseCongress directed operators to have OQ

programs, this change should notimpose any additional administrativecosts.

B. Applying Safety Requirements toLines Otherwise Changed

1. Comment

Commenting on proposed192.9(d)(1), NFGSC considered theterm otherwise changed unnecessaryand vague. It asked us to drop the termunless we clearly explain its meaning.

2. PHMSA Response

Use of the term otherwise changedin proposed 192.9(d)(1) parallels itsuse in existing 192.13(b). This lattersection, which has been part of part 192since its initial publication in 1970,provides:

No person may operate a segment ofpipeline that is replaced, relocated, orotherwise 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 inaccordance with this part.

Though not defined in part 192,otherwise changed refers to asubstantial physical alteration of apipeline facility as opposed to a repairor restoration.

C. Compliance Times

Under proposed 192.9(e)(1), design,installation, construction, initialinspection, and initial testingrequirements would not apply to new,replaced, relocated, or otherwisechanged lines until 1 year afterpublication of the final rule. Underproposed 192.9(e)(2), the followingcompliance deadlines for lines notpreviously subject to part 192 wouldapply:

RequirementProposed compliance

deadline

Control corrosionunder subpart I.

2 years after finalrule takes effect.

Prevent excavationdamage under192.614.

6 months after finalrule takes effect.

Establish MAOPunder 192.619.

6 months after finalrule takes effect.

Install line markersunder 192.707.

1 year after final ruletakes effect.

Educate public under192.616.

1 year after final ruletakes effect.

RequirementProposed compliance

deadline

Other requirementsfor Type A lines.

2 years after finalrule is published.

PHMSA proposed the shortertimelines for provisions that require lesstime to implement, such as damage

prevention. It proposed longer timeframes for provisions that may requiremore time to procure and installmaterials.

Lastly, as proposed in 192.9(e)(3), ifan onshore gathering line becomesregulated because of a change in classlocation or an increase in dwellingdensity, the operator would have 1 yearto comply with applicable requirements.

1. Comments

Coalition requested at least 1additional year to complete training forand to carry out initial classifications ifwe adopted the Coalitions alternatives

to the 5 per 1000 proposal (described insection IV. B. 4. of this preamble). AGAthought operators would need 2 years tocomplete the proposed classifications,and 4 years for full compliance.Dominion believed most operatorswould need 3 years for classifications,and large operators would need 4 yearsto meet corrosion control requirements.Duke said compliance times for largeoperators should be about twice as longas proposed, and 5 years for fullcompliance if operators have todetermine classifications based on 5dwellings per 1000 feet.

For lines that become regulatedbecause of a change in class location ordwelling density, Columbiarecommended allowing 2 years to meetthe proposed safety requirements. It saidthis timeframe1 year longer than weproposedwould be consistent with thetime allowed for confirmation orrevision of MAOP under 192.611.

2. PHMSA Response

On the whole, comments indicatedthe proposed compliance times wouldnot allow enough time to completeinitial classifications and assure allregulated lines are in compliance. Sincethe final rule does not mandate 5 per1000 surveys, we adopted Coalitionscomment and, in final 192.9(e)(2),added 1 year to the proposed times toallow more time for classifications. Thischange results in 3 years for fullcompliance. If an operator finds it needsmore time final 192.9(e)(2) allowsoperators to petition for more time on acase-by-case basis. For consistency withthe time allowed for corrosion control,in final 192.9(e)(2), we added 1 monthto the time proposed for compliance



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with other requirements for Type Alines.

After initial classifications, we expectmost class location or dwelling densitychanges would cause only shortsegments of lines to become newlyregulated. The bulk of these changeswill probably affect Type B lines,requiring compliance with only a fewpart 192 safety rules. Operators couldlargely meet these requirements byfolding the segments into their existingprograms. In these cases, allowing 2years for compliance as Columbiasuggested does not appear necessary.However, if Type A lines are affected,operators would have to comply withmany more requirements. Therefore, forType A lines, final 192.9(e)(3) allows2 years for compliance.

D. Corrosion Control

1. Comment

Regarding proposed 192.9(c) and(d)(2)), PSCWV said where cathodicprotection is impractical, operatorsshould have to survey the line for leakseach calendar year, not to exceed 15months, using gas detection equipment.

2. PHMSA Response

We did not adopt this commentbecause the SNPRM did not include aproposal to require leak surveys wherecathodic protection is impractical. Insuch cases, which should be few,operators may petition PHMSA or aState agency under 49 U.S.C. 60118 to

waive applicable requirements, if notinconsistent with pipeline safety.PSCWV may have been concerned aboutsituations in which 192.465(e) requiresoperators to reevaluate unprotectedpiping but it is impractical to performan electrical survey to determine theneed for cathodic protection. In thesesituations, 192.465(e) allows use ofalternative means if they include reviewand analysis of leak repairs and otherrelevant information.

E. Determining MAOP

For any gathering line part 192

regulates for the first time on and afterthe effective date of this final rule,proposed 192.619(a)(3) and (c) wouldallow the operator to determine thelines MAOP based on the lines highestactual operating pressures during thepreceding 5-year period.

1. Comment

Coalition recommended we also applythe proposed rules to transmission linespart 192 regulates for the first time

because of the final rule.

2. PHMSA Response

Although we expect fewreclassifications of gathering totransmission lines, we agree any newlyregulated transmission lines shouldhave the same MAOP options asgathering lines. So we adoptedCoalitions comment. For simplicity, we

based the pressure date in the table infinal 192.619(a)(3) on the publicationdate of the final rule rather than the firstday of the month preceding thepublication date as proposed.

F. Editorial Changes

The proposed definition ofregulatedonshore gathering line distinguishedType A metallic lines by whether theMAOP produces a hoop stress of 20percent or more of SMYS. In most cases,determining operating stress level is nota problem. However, on some olderlines, the stress level corresponding to

MAOP may be unknown because a pipecharacteristic relevant to calculatingstress, such as SMYS or wall thickness,is unknown. Subpart C of part 192provides options to deal with theseuncertainties. Final 192.8(b) providesthat operators are to apply applicableprovisions in subpart C if the stresslevel is unknown.

The proposal to amend 192.9 torequire operators of Type B lines tocontrol corrosion according to subpart Irequirements did not specifically referto subpart I requirements applicable totransmission lines. Final 192.9(d)(2)

makes it clear Type B lines are to meettransmission line requirements.We proposed to amend 192.452 to

clarify how subpart I requirementsspecifically applicable to pipelinesinstalled before or after certain pastdates would apply to regulated onshoregathering lines existing when the finalrule takes effect and not previouslysubject to subpart I (lines in rurallocations). Final 192.452(b) extendsthis provision to any onshore gatheringline that becomes a regulated onshoregathering line because of an increase inpopulation.

We have made some wording changesin final 192.452 and 192.619 to usemore plain language. These nonsubstantive wording changes do notchange any of the proposed or existingrequirements in these sections.

VI. Regulatory Analyses and Notices

Privacy Act

Anyone is able to search theelectronic form of all commentsreceived into any of our dockets by thename of the individual submitting the

comment (or signing the comment, ifsubmitted on behalf of an association,

business, labor union, etc.). You mayreview DOTs complete Privacy ActStatement in the Federal Registerpublished on April 11, 2000 (65 FR19477) or you may visit http://dms.dot.gov.

Executive Order 12866 and DOTPolicies and Procedures

This rulemaking is not a significantregulatory action under Section 3(f) ofExecutive Order 12866 (58 FR 51735;Oct. 4, 1993). Therefore, the Office ofManagement and Budget (OMB) has notreceived a copy of this rulemaking toreview. This rulemaking is also notsignificant under DOT regulatorypolicies and procedures (44 FR 11034:February 26, 1979).

PHMSA prepared a Regulatory

Evaluation of this rulemaking and acopy is in Docket No. PHMSA19984868. The evaluation concludes thatthere will be a net cost savings fromimplementing this final rule. Thesavings result from reducing theregulatory burden currently imposed onregulated gas gathering lines byestablishing a tiered approach to safetyrequirements. PHMSA estimates that thetotal amount of gas gathering pipelinemileage that will be subject to part 192will be about the same afterimplementing this rulemaking as it isnow. However, requirements applicableto approximately three fourths of theregulated gathering line mileage, thatwhich poses less public safety risk, will

be reduced compared to therequirements now applicable toregulated lines. This proposal will resultin a total cost of $26.54 million over a20-year period. PHMSA estimates thatthe benefit of reducing the frequency ofgas gathering pipeline incidents thathave public safety consequences willcause a net benefit that is consistentwith the increased regulatory burden.

Regulatory Flexibility Act

Under the Regulatory Flexibility Act(5 U.S.C. 601 et seq.), PHMSA mustconsider whether rulemaking actionswould have a significant economicimpact on a substantial number of smallentities.

This rulemaking will affect operatorsof gas gathering pipelines. Thisrulemaking refines the definition of gasgathering pipelines subject to regulationand establishes a tiered regulatory

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structure, under which regulated gasgathering lines posing less risk will besubject to only some of the requirementsnow applied to all regulated gatheringlines. PHMSA estimates that the overalleconomic 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 oftheir pipeline that are subject toregulation may change, in some cases,due to the changes in the definition, butthe economic impact on these operatorsis expected to be a net reduction incosts, consistent with the regulatoryanalysis.

There may be some operators of gasgathering pipelines that are not nowsubject to safety regulations that will

become so because portions of theirpipeline will meet the criteria in thenew definition for regulated gasgathering lines. These companies will

experience added costs. The costs willdepend on the risk posed by theirpipelines. The number of companiesexpected to come under safetyregulation for the first time isapproximately 25, some of which may

be small entities. In this SNPRM,however, PHMSA invited commentsspecifically on this estimate, butreceived no comments. Nevertheless,PHMSA believes the estimate may betoo high. The Small BusinessAdministration (SBA) also reviewed theSNPRM analysis and the commentsfiled in response to the SNPRM. TheSBA discussed the SNPRM with its

constituents and it resulted in the SBAproviding favorable comments. Basedon these facts, only a few companieswill experience increased costs, andPHMSA believes that there will not bea significant economic impact on asubstantial number of small entities.

The regulatory flexibility analysisaccompanies the regulatory evaluationand is in the docket for review.

Executive Order 13175

PHMSA has analyzed this rulemakingaccording to the principles and criteriacontained in Executive Order 13175,

Consultation and Coordination withIndian Tribal Governments. Becausethe rulemaking will not significantly oruniquely affect the communities of theIndian tribal governments nor imposesubstantial direct compliance costs, thefunding and consultation requirementsof Executive Order 13175 do not apply.

Paperwork Reduction Act

This rulemaking contains informationcollection requirements applicable tooperators of regulated onshore gasgathering lines. As required by the

Paperwork Reduction Act of 1995 (44U.S.C. 3507(d)), PHMSA submitted apaperwork analysis to the Office ofManagement and Budget for its review.A copy of the analysis is in the docket.The OMB control numbers are: OMBNo. 21370049 (recordkeeping under 49CFR part 192) and OMB No. 21370579(drug and alcohol testing under 49 CFR

part 199).For Type B regulated onshore

gathering lines, operators will have tocomply with part 192 informationcollection requirements regardingcorrosion control, damage preventionprograms, and public educationprograms. For Type A regulated onshoregathering lines, operators will have tocomply not only with theserequirements but also with others undervarious part 192 rules applicable to gastransmission lines. All operators ofonshore gathering lines that areregulated will have to comply with the

information collection requirements in49 CFR part 199 concerning drug andalcohol testing. The small operatorswhile required to collect testinformation, do not have to send reportsannually and therefore are excludedfrom the reporting burden estimates butnot the reporting estimates.

As explained above in section III ofthis preamble, gas gathering lines innon-rural locations are currently subjectto PHMSAs safety regulations. Thenumber of gathering line operatorssubject to regulation varies by year aspipelines are brought, taken out of

service, and as changes occur in theboundaries of non-rural locations.Currently there are 284 onshore naturalgas gathering pipeline operators subjectto PHMSA safety regulation.

At present, all 284 of these operatorsare required to comply with part 192rules applicable to transmission lines,including information collectionrequirements. The specific portions ofthese operators gathering lines that aresubject to part 192 regulations maychange as a result of the final rule. Someportions may no longer be regulated,while others could become Type A or

Type B lines. For Type B lines, the part192 information collection burden willbe significantly reduced, because TypeB lines will be subject to far fewer part192 regulations. The net effect on thepaperwork burden faced by these 284operators is thus expected to be areduction. However, the magnitude ofthis reduction is difficult to estimate

because PHMSA lacks the datanecessary to determine which portionsof operators currently regulatedgathering lines will continue to beregulated by part 192 and which

portions will become Type A or Type Blines.

Under the final rulemaking, someoperators of gas gathering lines in rurallocations could become subject to part192 regulations for the first time.PHMSA estimates that no more than 25operators will be newly subject to part192 regulations as a result of this final

rule. These operators will be required tocomply with part 192 regulationsproposed for Type A and Type B linesand with part 199 drug and alcoholtesting regulations, including associatedinformation collection requirements.

PHMSAs estimate of the paperworkburden on these newly-regulatedoperators is an average of approximately40 hours per year. Much of this timewill involve clerical personnel, butsome involvement by managers andtechnical personnel will be required. Atan estimated average hourly rate of $75the estimated cost for 25 operators of

this new paperwork burden, is $75,000.PHMSA expects that this increase incost for newly-regulated operators will

be more than offset by the reduction inpaperwork burden associated withcurrently regulated gas gathering linesthat become either unregulated or TypeB lines, as described above. Thus, theoverall paperwork impact will be asmall reduction.

Unfunded Mandates Reform Act of 1995

This rulemaking does not imposeunfunded mandates under theUnfunded Mandates Reform Act of1995. It does not result in costs of $100

million or more to either State, local, ortribal governments, in the aggregate, orto the private sector, and is the least

burdensome alternative that achievesthe objective of the rulemaking.

National Environmental Policy Act

PHMSA has analyzed this rulemakingfor purposes of the NationalEnvironmental Policy Act (42 U.S.C.4321 et seq.). Because the rulemakingwill require limited physicalmodification or other work that willdisturb pipeline rights-of-way, PHMSAhas determined the rulemaking is

unlikely to significantly affect thequality of the human environment.Much of the pipeline mileage that will

be subject to this final rule is alreadyregulated, and no new actions likely toaffect the environment are adopted forcurrently regulated lines. Also much ofthe existing rural mileage that becomeregulated under this final rule is alreadyequipped with cathodic protection andlocation markers, the two requirementsthat will involve any installation/modification work along the pipeline.An environmental assessment document



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13301Federal Regis

Rule: Pipeline safety: Gas gathering line definition; alternative definition for onshore lines

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