54524 Federal Register / Vol. 58, No. 203 / Friday, October 22, 1993 / Rules and Regulations

(c) The contracting officer shall insertthe clause at 552.238-74, Submissionand Distribution of Authorized GSASchedule Pricelists, in solicitations andcontracts awarded under the multipleaward schedule program. When GSA isnot prepared to accept electronicsubmissions for a particular schedule,the cqntracting officer is authorized tomodify the clause by deletingsubparagraph (c)(1)(ii) and (c)(3) andmodifying subparagraph (c)(1) toeliminate "(i)" and the word "and" atthe end of subparagraph (i).

PART 55--SOUCITATIONPROVISIONS AND CONTRACTCLAUSES

3. Section 552.238-74 is added toread as follows:

552.238-74 Submission and distribution ofauthorized GSA schedule pricellets.

As prescribed in 538.203-71(c). insertthe following clause:

SUBMISSION AND DISTRIBUTION OFAUTHORIZED GSA SCHEDULE PRICELISTS(SEP 1993)

(a) Definition. For the purposes of thisclause, the Mailing List is [Contracting officershall insert either: "the list of Federaladdressees provided to the Contractor by theContracting Officer" or "the Contractor'slisting of its Federal government customers"].

(b) The Contracting Officer will return onecopy of the Authorized GSA SchedulePricelist to the Contractor with the

-notification of contract award. TheContractor shall not print or distribute thepricelist without written approval from theContracting Officer. NOTE: Approval by theContracting Officer shall not absolve thecontractor from responsibility for theaccuracy of the pricelist.

(c)(1) The Contractor shall provide to theGSA Contracting Officer:

(i) Two paper copies of Authorized GSASchedule Pricelist; and

(ii) The Authorized GSA Schedule Priceliston a common-use electronic medium.

The Contracting Officer will providedetailed instructions for the electronicsubmission with the award notification.Some structured data entry In a prescribedformat may be required.

(2) The Contractor shall provide to eachaddressee on the mailing list either:

(i) One paper copy of the Authorized GSASchedule Price List; or

(ii) A self-addressed, postage-paidenvelope or postcard to be returned byaddressees that want to receive a paper copyof the pricelist. The Contractor shalldistribute price lists within 20 calendar daysafter receipt of returned requests.

(3) The Contractor shall advise eachaddressee of the availability of pricelistinformation through the on-line MultipleAward Schedule electronic data base.

(d) The Contractor shall make all of thedistributions required in paragraph (c) atleast 15,calendar days before the beginning

of the contract period, or within 30 calendardays after receipt of the Contracting Officer'sapproval for printing, whichever is later.

(e) During the period of the contract, thecontractor shall provide one copy of itsAuthorized GSA Schedule Pricelist to anyauthorized schedule user, upon request. Useof the mailing list for any other purpose isnot authorized.(End of Clause)

Dated: October 5, 1993.Richard H. Hopf, I,Associate Administrator for AcquisitionPolicy.[FR Doc. 93-25947 Filed 10-21-93; 8:45 am]BLLNG CODE 5620-41-

DEPARTMENT OF TRANSPORTATION

Research and Special ProgramsAdministration

49 CFR Part 192

(Docket PS-123; Amdt. 192-70]

RIN 2137-ABS4

Leakage Surveys on Distribution UnesLocated Outside Business Districts

AGENCY: Research and Special ProgramsAdministration (RSPA), DOT.ACTION: Final rule.

SUMMARY: This final rule requiresoperators of distribution lines locatedoutside business districts to use leakdetectors to carry out required leakagesurveys. Instead of using leak detectors,some operators survey for leaks bylooking for dead or dying vegetation, aless reliable method. The rule willprovide greater assurance that operatorsidentify all hazardous leaks duringrequired leakage surveys..

Also, where electrical surveys forcorrosion are impractical oncathodically unprotected metallicdistribution lines located outsidebusiness districts, operators commonlyuse leakage survey data to determinewhether the lines are corroding.However, under the present leakagesurvey standard, those data may be tooold for purposes of evaluating lines forcorrosion at 3-year intervals. Thus, thefinal rule assures that leakage surveydata no more than 3 years old are usedto evaluate lines for corrosion.EFFECTIVE DATE: November 22, 1993.FOR FURTHER INFORMATION CONTACT: L.M.Furrow, (202) 366-2392, regarding thesubject matter of this final rule, or theDockets Unit, (202) 366-5046, regardingcopies of this final rule document orother material in the docket.

SUPPLEMENTARY INFORMATION:

BackgroundA string of accidents due to corrosion

and other causes occurred on residentialservice lines operated by the KansasPower and Light Company (KPL) inKansas and Missouri during a 7-monthperiod of 1988 and 1989. Overall, fourpersons were killed and 16 wereinjured, with property damageexceeding $740,000. The service lineswere mostly steel lines installed bycontractors of the operator's customersbefore issuance of the gas pipelinesafety standards in 49 CFR part 192.

The lines had been checked for leaksthrough vegetation surveys carried outby KPL's meter readers, but KPL hadnever used gas detectors to survey thelines for leaks. Responding to theaccidents, KPL conducted acomprehensive gas detector survey thatrevealed 2,156 leaks in 55,213 houseservice lines. KPL considered 303 ofthese leaks to need immediate repair.

After the KPL accidents, the NationalTransportation Safety Board (NTSB)recommended the following to RSPA:

e Amend the provisions of 49 CFRpart 192 that allow alternatives to theuse of electric surveys for identifyingareas of active corrosion to require thatany alternative must provide dataequivalent, both in timeliness andquality, to that obtained using electricalsurveys. (P-90-17)• Amend 49 CFR part 192 to disallow

the use of vegetation-type surveys forcomplying with any leakage surveyrequirement. (P-90-18)

In addition, the National Associationof Pipeline Safety Representatives(NAPSR), an organization of Statepipeline inspectors, has recommendedthat operators use gas detectors inleakage surveys on distribution lines.NAPSR believes that vegetation surveysare too imprecise to assure safety in.residential areas.

Vegetation surveys are based on theassumption that a high proportion ofnatural gas in the subsurfaceenvironment displaces air in the soil.Lack of air inhibits the growth ofvegetation, producing an effect visibleon the ground. Hence, observation ofdead or dying vegetation is used to inferthe existence of an underground gasleak. While the vegetation survey is awell-established technique, it suffersfrom a number of weaknesses. Atvarious times of the year, primarilybecause of seasonal, weather, orclimatical conditions, the growth ofvegetation is insufficient to support aproper vegetation survey. In addition,vegetation is noticeably affected onlyafter gas has leaked at a significant rate

Federal Register / Vol. 58, No. 203 / Friday, October 22, 1993 / Rules and Regulations

for a significant time. Thus, vegetationsurveys may not discover incipientleaks; and very small, or "pinhole,"leaks may not be discovered unless theyincrease in size.

In contrast, leakage surveys usingportable gas detector equipment can bedone at any time of the year. Althoughthe sensitivity of available gas detectorsvaries, all equipment can detect thepresence of natural gas in theatmosphere without the aid of humanjudgment. Consequently, theuncertainty associated with vegetationsurveys is eliminated with gas detectorsurveys. Whenever a trained techniciandoes a gas detector survey, the operatorcan assume with reasonable certaintythat all hazardous leaks will be found.Notice of Proposed Rulemaking

Because of the KPL accidents and theNTSB and NAPSR recommendations,RSPA proposed to strengthen the rulethat governs leakage surveys of gasdistribution lines in residential areas(§ 192.723(b)(2)). In a notice of proposedrulemaking (NPRM) published October23, 1991 (56 FR 54816), RSPA proposedto require that operators use gasdetection equipment in leakage surveysunder § 192.723(b)(2). (Operators whosurvey their lines for leaks more often.than once every 5 years, the minimumfrequency under § 192.723(b)(2), couldcontinue to use vegetation surveys forthose additional leakage surveys.) At thesame time, RSPA proposed to clarify§ 192.723(b)(2) and make it consistentwith § 192.723(b)(1) by replacing thephrase, "outside of the principalbusiness areas," with "outside businessdistricts."

Another proposed amendment of§ 192.723(b)(2) concerned cathodicallyunprotected metallic distribution linesthat must be evaluated for corrosionunder § 192.465(e). Operators mustevaluate these pipelines at least every 3years to determine whether areas ofactive corrosion exist on the lines. Areasof active corrosion must be determinedby electrical survey, or if an electricalsurvey is impractical, by the study ofcorrosion and leak history records, byleak detection survey, or by othermeans.

It is common practice for operators torely on leakage surveys as an alternativeto electrical surveys in complying with§ 192.465(e). RSPA's concern is thatwhen.only 5-year-old data collectedunder § 192.723(b)(2) are used for thispurpose, corrosion may go uncheckedon distribution lines in residential areaslonger than the 3 years that § 192.465(e)allows. Therefore, RSPA proposed toamend § 192.723(b)(2) to require thatwhen electrical surveys are impractical

on cathodically unprotected distributionlines that are subject to § 192.465(e),leakage surveys must be done at leastevery 3 years.

Disposition of CommentsThe.56 organizations that filed

comments on the NPRM are categorizedas follows:Federal agency-2: NTSB, U.S.

Environmental Protection Agency (EPA)State pipeline agency--6: Oregon, Kansas,

Iowa, Massachusetts, Kentucky, MarylandTrade association-3: American Gas

Association (AGA), NY Gas Group, OilHeat Task Force

Professional association-I: Gas PipingTechnology Committee

Leak survey business-i: Southern CrossConsultant-I: ConReg AssociatesDistribution operator-42: Alagasco; ARKLA;

Atlanta Gas Light Company; Atmos EnergyCorporation; Boston Gas Company; TheBrooklyn Union Gas Company; CitizensGas and Coke Utility; Colorado SpringsUtilities; The Columbia DistributionCompanies; Consolidated Edison Companyof N.Y., Inc.; Consumers Power Company;The East Ohio Gas Company; Entex;Equitable Resources, Inc.; Hope Gas, Inc.;Iowa-Illinois Gas and Electric Company;'Laclede Gas Company; Louisiana GasService Company; Minnegasco; MississippiValley Gas Company; Montana-DakotaUtilities Co.; Mountain Fuel SupplyCompany; National Fuel Gas DistributionCorporation; Natural Gas PipelineCompany of America; New York StateElectric and Gas Corporation; NorthernIndiana Public Service Company; NorthernIllinois Gas; Northern Minnesota Utilities;Northwest Natural Gas Company; OkaloosaCounty Gas District; Oklahoma Natural GasCompany; Pacific Gas and ElectricCompany; The Peoples Gas Light and CokeCompany; Peoples Gas System, Inc.; ThePeoples Natural Gas Company;Philadelphia Electric Company; PublicService Company of Colorado; SouthernCalifornia Gas Company; Southwest GasCorporation; Washington Gas; Willmut Gas& Oil Company; Wisconsin Natural Gas Co.

Gas Detector v. Vegetation SurveySome 50 commenters addressed the

issue of whether operators should berequired to use gas detectors in leakagesurveys of distribution systems outsidebusiness districts. Of these commenters,16, including NTSB, Oregon, Kansas,Massachusetts, Maryland, NY GasGroup, Oil Heat Task Force, and 9distribution operators, voiced generalsupport for the proposal. Another 17commenters, all distribution operators,supported the proposal because theynow use gas detectors, either hydrogenflame ionization equipment orcombustible gas indicators, or both, intheir surveys.

Two distribution operators supportedthe proposal, but preferred that the finalrule use the term "instrumented leak

detection equipment" instead of "gasdetector." They said this change wouldallow the use of sonics for leakagesurveys, a technology that does not relyon actual detection of gas. Thiscomment is important because RSPAdoes not want the final rule to deter theuse of advancements in leakage surveytechnology. In addition, § 192.706,governing leakage surveys oftransmission lines, requires the use of"leak detector equipment." To beconsistent with § 192.706, final§ 192.723(b)(2) uses the term "leakagesurvey with leak detector equipment"instead of "gas detector survey." Forconsistency, we also replaced "gasdetector survey" in § 192.723(b)(1) with"leakage survey with leak detectorequipment."

Three other distribution operatorssupported the proposal, but suggestedwe limit the final rule to buried pipe.They saw no need to include interiorpiping under the leakage surveyrequirement, stating that leaks insidebuildings are readily detectable withoutgas detectors. However, existing§ 192.723(b)(2) requires leakage surveyson interior piping that is subject to part192. Although the NPRM did notpropose to alter this requirement, RSPAdoes not agree that there is no need forleakage surveys on interior piping.Many people have a diminished senseof smell, and conceivably could notreadily smell odorized gas escapingfrom a pinhole leak. Periodic interiorleakage surveys protect againstaccidents caused by otherwiseundetected leaks.

Several commenters thought the term"business district" should be defined inthe final rule. Two of these commentersreferred to the definition in the Guidefor Gas Transmission and DistributionPiping Systems. One asked that wedefine the term to distinguish olderinnercity business areas from newercommercial developments. RSPA didnot adopt these comments because theterm "business district" has been usedin § 192.723(b)(1) since the rule'sinception without significantcompliance difficulties.

Two commenters thought we shoulddefine "gas detector survey." Asdiscussed above, the final rule uses"leakage survey with leak detectorequipment" instead of "gas detectorsurvey." RSPA believes this alternativeterm is clear and needs no definition.

Another commenter disliked the term"gas detector survey" because it wouldallow use of combustible gas indicators,a method the commenter said is not aseffective as hydrogen flame ionizationequipment. The NPRM did not proposeto standardize the equipment operators

54525

54526 Federal Register / Vol. 58, No. 203 / Friday, October 22. 1993 / Rules and Regulations

may use in conducting leakage surveys.Rather, the purpose of the proposal wasto disallow the use of vegetation surveysto meet leakage survey requirements. Soany kind of equipment capable ofdetecting leaks in gas distributionsystems may be used under the finalrule.

Several commenters opposed the gasdetector proposal because they favoredthe continued use of vegetation surveysto meet leakage survey requirements.One said that vegetation surveys are35% effective on a single pass(compared to 85 percent for hydrogenflame ionization equipment), 5 timesfaster than hydrogen flame ionizationequipment, and 20 percent asexpensive. This commenter saidvegetation surveys are reliable if run bytrained personnel at frequent intervals(2 or 3 times as often as hydrogen flameionization). Two other commentersargued that an abundance of vegetationis available for efficient scheduling andrunning of effective vegetation surveys.One of these commenters also said arecent trial survey with gas detectorsproduced only 5% more leaks than avegetation survey, and they were of lowpriority.

RSPA does not find these argumentspersuasive. The above statisticsthemselves show that vegetation surveysare less effective than leak detectorequipment on a single pass overdistribution lines, even when usingtrained personnel. Also, the savings intime and money seem to be offset by theneed to run vegetation surveys moreoften for results as reliable as with gasdetectors. This need for more frequentsurveys is not compatible with the 5-year minimum frequency specified by§ 192.723(b)(2). Further, whilevegetation is essential for vegetationsurveys, abundant vegetation does notovercome these drawbacks: leaks mustbe inferred rather than detected, andincipient leaks need time before theyvisually affect vegetation. The fact thata commenter found only minoradditional leaks with leak detectorequipment is fortunate but notnecessarily typical, as the KPLexperience shows. Moreover,undetected minor leaks can grow tobecome hazardous.

One commenter argued against themandatory use of gas detectors byasserting that most leaks are reportedthrough odorization of gas. Only 10percent or less are found by leakagesurveys the commenter said. Even so,public safety demands that operatorsuse reliable means to discover leaks notreported through odorization. Gasdetectors, unquestionably, are morereliable than vegetation surveys. And

our analysis shows that gas detectorscan be used to meet the present leakagesurvey rule at minimal additional cost.Thus, RSPA believes that disallowingthe use of vegetation surveys to meetthat rule is reasonable.

AGA opposed the proposal on theground that one company's results areinadequate justification to change§ 192.723(b)(2). AGA also saw onlyminimal potential benefits frommandatory gas detector surveys, becausesince 1984 there have been only 57distribution incidents caused bycorrosion, with 6 deaths, 39 injuries,and $2.35 million of property damage.However, RSPA notes that the KPLaccidents were not the sole justificationfor proposing to change § 192.723(b)(2).The NPRM was also based on ananalysis of the effectiveness ofvegetation surveys, onrecommendations by NTSB and NAPSR,and the fact that Kansas, Missouri, andother states have required operators touse gas detectors in residential leakagesurveys. Moreover, corrosion is not theonly cause of leaks on distribution lineslocated outside business districts.Outside force damage to pipe is a majorcause of leaks, as are pipelineconstruction and material defects. Theseother causes of leaks add to thecorrosion-related benefits of leakagesurveys. As with corrosion, leaks fromthese other causes can result long afterthe damage or defect occurs, creating anopportunity for the operator to discoverthe leak during a leakage survey.

One commenter asked that RSPAexempt lines in unoccupied rural areaswhere steep terrain and high vegetationgrowth limit the effectiveness of gasdetector surveys. Although leakagesurveys with gas detectors may takelonger in areas of steep terrain and highvegetation, RSPA does not haveevidence that such surveys are lesseffective in those areas. Considering theallowable interval between requiredsurveys (5 years), RSPA feels operatorshave ample time to survey lines in thoseareas with leak detection equipment.The final rule does not have thesuggested exemption.

Corrosion Evaluation by Leakage SurveyForty-two commenters addressed the

issue of whether cathodicallyunprotected pipe subject to the 3-yearelectrical survey requirement of§ 192.465(e) should be surveyed forleaks at least every 3 years if electricalsurveys are impractical. Of thesecommenters, 16, includinq NTSB,Southern Cross, Kansas, Iowa,Massachusetts, Oil Heat Task Force, and10 distribution operators, expressedgeneral support for the proposal.

Another 7 of the 42, all distributionoperators, said they supported theproposal because they now survey theirunprotected lines for leaks at 3-yearintervals.

Four distribution operators supportedthe proposal, but suggested that theproposed frequency (intervals notexceeding 3 years) be changed to read"at intervals within 3 calendar years,but not exceeding 39 months." Theysaid this change would be consistentwith other part 192 requirements forperiodic inspections by allowing time tocope with extreme weather conditions.RSPA agrees that in scheduling leakagesurveys to comply with the rule,operators will have to consider theweather. However, 3 years should beample time within which to scheduleand conduct a survey in good weather.None of the present part 192 standardsthat prescribe inspections every 3 yearsallow more than 36 months betweeninspections (e.g., § 192.465(e)).

Three commenters, including AGA,opposed the proposal on the ground thatevery 3 years is too frequent to check forleaks, given the low corrosion accidentrate. They suggested we extend the 3-year electrical survey minimumfrequency to 5 years to match theminimum leak survey frequency. Thischange, they said, would reducecompliance cost with no adverse safetyimpact. RSPA did not adopt thisapproach, because it would weaken theexisting rule on monitoring unprotectedmetallic pipelines for corrosion(9192.465(e)). This rule was establishedto hold down the corrosion accident rateon distribution lines. The low corrosionaccident rate that has been attained withthis rule is not a sufficient reason toslacken the minimum frequency ofcorrosion monitoring.

Four distribution operators opposedthe proposal because they felt the use of5-year old leak survey data has notcaused a safety problem. One of thesecommenters pointed out that under§ 192.465(e), the use of leak history dataas an alternative to electrical surveysincludes data from sources besides leaksurveys, such as reports from the public.Another of these commenters thoughtthe existing § 192.723(b)(2) issatisfactory because it requires surveys"as frequently as necessary." Similarly,another of the four said the use ofimproved leak survey techniques andreliance on corrosion and leak historyare sufficient measures under§ 192.465(e) to insure pipeline integrity,without more frequent surveys.

RSPA did not change the final rule asa result of these comments. Theavailable safety data are insufficient tosubstantiate the commenters' assertion

Federal Register / Vol. 58, No. 203 / Friday, October 22, 1993 / Rules and Reguiations 54527

that using 5-year old data to meet a 3-year monitoring rule has not caused asafety problem. In the absence of suchinformation, since pipeline corrosioncontinues to pose a serious threat topublic.safety, it is reasonable to requirethat unprotected pipelines be evaluatedfor corrosion on the basis of currentdata. Admittedly, the otherconsiderations the commentersmentioned compensate to some degreefor the use of out-of-date leak surveydata. However, in our opinion, they donot overcome the need for leak surveydata that reflect the state of corrosionactivity within the prescribed period ofevaluation.

Five operators opposed the proposalbecause of the scattered nature ofunprotected parts of their distributionsystems. For cost effective leakagesurveys, these commenters said theywould have to survey areas of theirsystems at 3-year intervals regardless ofwhether the areas contain protected orunprotected lines. It would be tooimpractical, they said, to surveyunprotected lines selectively at 3-yearintervals and the remainder at 5-yearintervals. One operator suggested thatchanging the 5-year survey requirementto 6 years would alleviate this problem.

In response to these operators, RSPAnotes that under § 192.465(a), protectedlines must be monitored at leastannually, while under § 192.465(e),operators have as long as 3 years tomonitor unprotected lines. Thus,distribution systems with both protectedand unprotected pipelines are alreadysubject to different intervals forcorrosion monitoring. In RSPA'sexperience, operators have not hadsignificant trouble in applying thesedifferent monitoring intervals toseparate parts of their systems. Since theproposed 3-year leakage survey ismerely a means of carrying out the 3-year corrosion monitoring requirementon unprotected pipelines, RSPA doesnot believe it would add to theoperators' present burden of compliancewith § 192.465(e). Therefore, RSPA wasnot persuaded to alter the final rulebecause of the alleged impracticality ofsurveying different parts of a system atdifferent rates. Moreover, the prescribedintervals under final § 192.723(b)(2) aremaximum times between surveys.Operators who find it more convenientto survey separate parts of their systemsat compatible frequencies, such as 2 and4 years, or at the same frequency, suchas every 3 years, may do so, providedthe prescribed intervals are notexceeded.

Specific Comments RequestedIn the NPRM, RSPA announced that

it was reconsidering the need for morefrequent leakage surveys on alldistribution lines outside businessdistricts. In that regard, we requestedcomments on the following topics tohelp us decide whether to propose a 1-year minimum frequency for leakagesurveys on unprotected lines and a 3-year minimum frequency on all otherines.

(1) The need to increase from every 5years to every 3 years the minimumfrequency of leakage surveys ondistribution lines of any materiallocated outside business districts.

Only four commenters supported thenotion of increasing from every 5 yearsto every 3 years the minimum frequencyrequired for leak surveys on portions ofdistribution systems outside businessdistricts. The Oil Heat Task Forcefavored more frequent surveys on theground that total reported leaks arehigh, and more frequent surveys wouldpositively affect the environment byreducing methane emissions. However,EPA advised that preliminary results ofa Gas Research Institute studycommissioned under the Clean Air Actshow that system-wide leak rates arelow. AGA argued that the Oil Heat TaskForce merely wants to increase the costof gas to enlarge the market for oil.

NTSB asserted that 5 years is too longbetween checks for leaks on flammablegas systems in view of aging systems.The agency suggested RSPA studyincident data to learn the correlationbetween leak rate and age, type of pipe,and other characteristics. NTSB thensaid leak survey frequency should be setaccording to these correlations. Oneother commenter also said leak surveyfrequency should be based on age,material, leak history, and soilcharacteristics.

AGA opposed the idea of an increasedfrequency, saying an increase is notlikely to have a beneficial effect giventhe low leak rate from corrosion since1984. AGA foresaw minimal benefitsbut a significant increase in costs.

The large majority of commenters onthis issue opposed the increase, sayingit is not justified and would not be costbeneficial. Numerous commenters said aminimum 5-year frequency is sufficientfor cathodically protected steel pipe andplastic pipe, because these pipesexperience relatively few leaks. Anothercommenter who opposed an increaseargued that gas detectors eliminate theneed for more surveys. Still anothercommenter noted that effective cathodicprotection and odorization programsmake more frequent surveys

unnecessary. One commenter whoexpressed opposition said its existingleak survey and replacement programwas satisfactory, while anothercommenter stated its oppositionsuccinctly: expensive, impractical, andunnecessary.

One commenter who argued aminimum 3-year rate was unjustifiednoted that the KPL incidents involvedold, customer-owned, unprotected linesthat had been vegetation surveyed bymeter readers. This commenter said theKPL evidence showed a need for gasdetector surveys, but not moe frequentsurveys. More frequent surveys, thiscommenter said, should be tied to highleak rates, as from corrosion,deteriorating couplings, or constructiondefects. Another commenter similarlysaid that a frequency of more than 5years should be based on need.

(2) The need to conduct leakagesurveys at least annually oncathodically unprotected metallicdistribution lines that lie outsidebusiness districts and on whichelectrical surveys are impractical.

The Oil Heat Task Force supportedthe notion of annual surveys onunprotected steel lines because of whatthe commenter considered a largenumber of leaks annually across thenation.

Three other commenters supportedannual surveys to help combat theeffects of corrosion on old unprotectedlines and prevent multiple leaks fromexisting for up to 5 years betweensurveys. An additional commentersupported the increase because itsurveys annually now.

One commenter supported annualsurveys, but only in areas of highleakage.

Most who commented on the issuewere opposed to the suggested increasein leak survey frequency, saying itlacked corresponding safety benefits.Many said it's too impractical toschedule more frequent surveys onunprotected parts of a system, sincecathodic protection can vary by area orstreet. In some cases, these commenterssaid, unprotected services are randomlyscattered over a city. The suggestedincrease would cause whole areas orsystems to be surveyed annuallywithout'sufficient cause.

One commenter who saw no benefitsaid older systems are the source ofcorrosion leaks. These systems, thecommenter said, have already beensurveyed many times and possible areasof corrosion are protected or replaced.

Two other commenters who opposed'the increase said there would be nocorresponding benefits because

54528 Federal Register / Vol. 58, No. 203 / Friday, October 22, 1993 / Rules and Regulations

corrosion incidents can occur shortlyafter a survey.

(3) How would such an increase (insurvey frequency) affect the presentcosts of conducting leakage surveys ondistribution lines in small and largesystems?

About 15 commenters gave estimatesranging from $140,000 to $4 million ayear per operator if the 5 year frequencywere increased to 3 years. The range ofestimated cost increases for surveyingunprotected lines annually was from$66,000 to $19 million a year peroperator. These estimates covered thecosts of equipment, personnel, andtraining.

(4) [What] benefits would result fromsuch rules. Information concerningaccidents that operators might haveavoided had they surveyed pipelines forleaks more frequently would be helpful.

Only a few commenters responded tothis inquiry. None saw any benefit toincreasing the survey frequencies. Someof the reasons were: Low corrosionaccident rate; lack of corrosionaccidents and system difference fromKPL situation; know of no accidents thatwould have been avoided had surveybeen every 3 instead of every 5 years;most lines plastic, little likelihood ofaccident avoidance through increasedleak survey frequency.Conclusion

Based on our review of theinformation submitted, we haveconcluded that the number of accidentsthat might be prevented by surveying atthe proposed increased frequencies isuncertain. In addition, the current safetydata for the nation's population of gasdistribution lines are not sufficient todetermine if a correlation exists betweenleak rates and pipe age, material, orother characteristics. Also, statepipeline safety agencies commonlyimpose more frequent surveyrequirements on individual distributionlines that are found to pose an unusualrisk. Under these circumstances andgiven the need to learn the effect of thefinal rule on leak rates, we are not atpresent considering any furtheramendment of the leak survey frequencyrule.

Advisory CommitteeAs part of this rulemaking proceeding,

RSPA obtained advice from theTechnical Pipeline Safety StandardsCommittee (TPSSC) on the technicalfeasibility, reasonableness, andpracticability of the proposed rule. TheTPSSC is a statutory advisory committeecomprised of 15 members, representingthe natural gas industry, government,and the general public.

The TPSSC met in Washington, DC onMarch 11, 1992, and discussed theNPRM. The TPSSC voted for theproposed rule 10 to 1, with I memberabstaining. A suggested revisionconcerning a typographical error In thetext of the proposed rule has beencorrected. The transcript and report ofthe meeting are available in the docket.

Rulemaking Analyses

E.O. 12866 and DOT Regulatory Policiesand Procedures

RSPA has concluded that theamendment to § 192.723(b)(2) is not asignificant rule under Executive Order12866. Also, it is not a significantregulation under DOT RegulatoryPolicies and Procedures (44 FR 11034,February 26, 1979).

RSPA believes that the final rule willadd minimally to the averagecompliance expense of the present rule.With respect to requiring the use of leakdetectors, first, operators of gasdistribution systems already have theequipment. They use portable gasdetectors in business districts and tocheck enclosed spaces for gas leaks.Second, in leakage surveys outsidebusiness districts, most operatorsalready use gas detectors for mains,because they generally lie beneathpaved areas where vegetation surveysare inappropriate. Also. for service linesin these areas, many operators arevoluntarily using gas detectors insteadof vegetation surveys, and some Statelaws require operators subject to Statejurisdiction to do so. Third, gas detectorequipment is easy to use. Personnel thatoperators have trained to do vegetationsurveys will need only slight, if any,additional training to use theequipment. Finally, although the surveyprocess will take longer with leakdetectors, any resulting additional costswill be mitigated by the period betweensurveys (maximum interval is 5 years)and the ability to conduct surveys withleak detectors any time of the year.

The benefits of requiring the use ofleak detectors in leakage surveys areprevention of deaths, injuries, andproperty damage that might otherwiseoccur when hazardous gas leaks goundetected in residentialneighborhoods. As an example of thesepotential benefits, the NPRM discussedthe results of leak detector surveys inKansas City, Missouri. Following astring of residential accidents in whichfour persons were killed and 16 wereinjured, with property damageexceeding $740,000, the local gascompany conducted leakage surveyswith leak detector equipment. Untilthen the company had relied on

vegetation surveys by meter readers todiscover previously undetected gasleaks. The leak detector surveysrevealed a large number of previouslyundetected hazardous leaks. Forinstance, during one period, leakdetector surveys revealed 2,156 leaks in55,213 house service lines, of which thegas company considered 303 leaks toneed immediate repair. Had these leakdetector surveys been conducted earlier,many of the Kansas City accidents mighthave been prevented by timely repair ofthe leaking lines. The final rule shouldachieve similar benefits nationwidewhere operators are not using leakdetector equipment to conduct leakagesurveys.

With respect to surveys of certainunprotected metallic lines at 3-yearintervals, the final rule will merelyassure that when operators use leakagedata to evaluate these lines for corrosionthe data are not less timely than what§ 192.465(e) intends for that purpose.RSPA did not attribute any additionalcompliance costs to this aspect of thefinal rule because the use of timely datais an inherent requirement of theexisting § 192.465(e).

RSPA believes the final rule does notwarrant a more detailed evaluation of itsImpact. The comments on the NPRMand the advice of the TPSSC areconsistent with this view.

Regulatory Flexibility Act

Based on the facts availableconcerning the impact of this final rule,I certify under Section 605 of theRegulatory Flexibility Act that it willnot have a significant economic Impacton a substantial number of smallentities.

E.O. 12612

RSPA has analyzed this final ruleunder the criteria of Executive Order12612 (52 FR 41685; October 30, 1987).We find it does not warrant preparationof a Federalism Assessment.

List of Subjects in 49 CFR Part 192

Natural gas, Pipeline safety, Reportingand recordkeeping requirements.

In consideration of the foregoing.RSPA amends 49 CFR part 192 asfollows:

PART 192--[AMENDED]

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

Authority: 49 App. US.C. 1672 and 1804;49 CFR 1.53.

2. In § 192.723(b)(1), the words "A gasdetector survey" are removed and thewords "A leakage survey with leak

Federal Register / Vol. 58, No. 203 / Friday, October 22, 1993 / Rules and Regulations 54529

detector equipment" are added in theirplace.

3. Section 192.723(b)(2) is revised toread as follows:

§ 192.723 Distribution systems: Leakagesurveys and procedures.

(b)* •. :

(2) A leakage survey with leakdetector equipment must be conducted -

outside business districts as frequentlyas necessary, but at intervals notexceeding 5 years. However, forcathodically unprotected distributionlines subject to § 192.465(e) on whichelectrical surveys for corrosion areimpractical, survey intervals may notexceed 3 years.

Issued in Washington. DC. on October 14.1993.Rose A. McMurray,Acting Administmtorfor Research andSpecial Programs Administration.[FR Doc. 93-25980 Filed 10-21-93; 8:45 amlBING COD 4910-4P

DEPARTMENT OF COMMERCE

National Oceanic and AtmosphericAdministration

50 CFR Part 875(Docket No. 921185-4021; ID 101893A]

Groundfish of the Bering Sea andAleutian Islands Area

AGENCY: National Marine FisheriesService (NMFS), National Oceanic and

Atmospheric Administration (NOAA).Commerce.ACTION: Modification of a closure.

SUMMARY: NMFS is rescinding theclosure to directed fishing for Pacificocean perch in the Aleutian Islandssubarea (AI) of the Bering Sea andAleutian Islands management area(BSAI). This action is necessary to fullyutilize the total allowable catch (TAC) ofPacific ocean perch in this area.EFFECTIVE DATE: 12 noon, Alaska localtime (A.l.t.), October 22, 1993, until 12midnight, A.LL, December 31,1993.FOR FURTHER INFORMATION CONTACT:Andrew N. Smoker, ResourceManagement Specialist, NMFS, 907-586-7228.SUPPLEMENTARY INFORMATION: Thegroundfish fishery in the BSAI exclusiveeconomic zone is managed by theSecretary of Commerce according to theFishery Management Plan for theGroundfish Fishery of the Bering Seaand Aleutian Islands Area (FMP)prepared by the North Pacific FisheryManagement Council under authority ofthe Magnuson Fishery Conservation andManagement Act. Fishing by U.S.vessels is governed by regulationsimplementing the FMP at 50 CFR parts620 and 675.

In accordance with § 675.20(a)(7)(ii),the Pacific ocean perch TAC for the Aiwas established by the final 1993 initialsped fications of groundfish (58 FR8703, February 17, 1993) and lateraugmented from the reserve (58 FR44136, August 19, 1993) to a total of

13,900 metric tons (mt). The directedfishery for Pacific ocean perch wasclosed on April 22, 1993 (58 FR 21951,April 26, 1993); the closure wasrescinded on August 9, 1993 (58 FR42031, August 6, 1993); and the fisherywas again closed on August 19 (58 FR44465, August.23. 1993). NMFS hasdetermined that as of October 9, 1,575mt remain unharvested.

The Regional Director, Alaska Region,NMFS, has determined that the 1993TAC for Pacific ocean perch in the Alhas not been reached. Therefore, NMFSis rescinding the August 19, 1993,closure and is re-opening directedfishing for Pacific ocean perch in the Al,effective at 12 noon. A.Lt.. October 22,1993, until 12 midnight, A.l.t.,December 31, 1993.

Classification

This action is taken under § 675.20.

List of Subjects in 50 CFR Part 675

Fisheries, Recordkeeplng andreporting requirements.

Authority- 16 U.S.C. 1801 et seq.Dated: October 19, 1993.

Richard IL Schaefer,Director of Office of Fisheries Conservationand Management, National Marine FisheriesService.[FR Doc. 93-26077 Filed 10-21-93-.8:45 am]

ILUN OOE 3510-22-M