Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61571 

1The Norman Y. Mineta Research and Special 

Programs Improvement Act (Pub. L. 108–426, 118; 

November 30, 2004) reorganized RSPA into two 

new DOT administrations: the Pipeline and 

Hazardous Materials Safety Administration 

(PHMSA) and the Research and Innovative 

Technology Administration. RSPA’s regulatory 

authority over pipeline and hazardous materials 

safety was transferred to PHMSA. 

2The standard on external corrosion direct 

assessment § 192.925) requires operators to 

integrate data on physical characteristics and 

operating history, conduct indirect aboveground 

inspections, directly examine pipe surfaces, and 

evaluate the effectiveness of the assessment process. 

Under the standard for direct assessment of internal 

corrosion (§ 192.927), operators must predict 

locations where electrolytes may accumulate in 

normally dry-gas pipelines, examine those 

locations, and validate the assessment process. The 

standard for direct assessment of stress corrosion 

cracking (§ 192.929) involves collecting data 

relevant to stress corrosion cracking, assessing the 

risk of pipeline segments, and examining and 

evaluating segments at risk. 

area(s) which result from a CERCLA 

administrative order, a CERCLA or RCRA 

consent decree or a court order. 

* * * * * 

Limitation of Future Contracting Alternate II 

(Start) (Apr 2004) 

* * * * * 

(d) During the life of this contract, 

including any options, the Contractor agrees 

that unless otherwise authorized by the 

Contracting Officer: 

(1) It will not provide to EPA cleanup 

services (e.g., Emergency and Rapid 

Response Services (ERRS) contracts) within 

the Contractor’s START assigned 

geographical area(s), either as a prime 

Contractor, subcontractor, or consultant. 

(2) Unless an individual design for the site 

has been prepared by a third party, it will not 

provide to EPA as a prime contractor, 

subcontractor or consultant any remedial 

construction services at a site where it has 

performed or plans to perform START work. 

This clause will not preclude START 

contractors from performing construction 

management services under other EPA 

contracts. 

(3) It will be ineligible for award of ERRS 

type activities contracts for sites within its 

respective START assigned geographical 

area(s) which result from a CERCLA 

administrative order, a CERCLA or RCRA 

consent decree or a court order. 

* * * * * 

Limitation of Future Contracting Alternate 

III (ESAT) (Apr 2004) 

* * * * * 

Limitation of Future Contracting Alternate 

IV (TES) (Apr 2004) 

* * * * * 

Limitation of Future Contracting Alternate V 

(Headquarters Support) (Apr 2004) 

* * * * * 

(c) The Contractor, during the life of this 

contract, will be ineligible to enter into a 

contract with EPA to perform response action 

work (e.g., Response Action Contract (RAC), 

Emergency and Rapid Response Services 

(ERRS), Superfund Technical Assistance and 

Removal Team (START), and Enforcement 

Support Services (ESS) contracts), unless 

otherwise authorized by the Contracting 

Officer. 

* * * * * 

Limitation of Future Contracting Alternate 

VI (Site Specific) (Apr 2004) 

* * * * * 

(d) During the life of this contract, 

including any options, the Contractor agrees 

that unless otherwise authorized by the 

Contracting Officer: 

(1) It will not provide any Superfund 

Technical Assistance and Removal Team 

(START) type activities (e.g., START 

contracts) to EPA on the site either as a prime 

contractor, subcontractor, or consultant. 

* * * * * 

1552.215–76 [Removed and reserved] 

■ 10. Remove and reserve section 

1552.215–76. 

1552.229–70 [Removed and reserved] 

■ 11. Remove and reserve section 

1552.229–70. 

1552.237–73 [Removed and reserved] 

■ 12. Remove and reserve section 

1552.237–73. 

[FR Doc. 05–21196 Filed 10–24–05; 8:45 am] 

BILLING CODE 6560–50–P 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Parts 192 and 195 

[Docket No. RSPA–04–16855; Amdt. 192–

101 and 195–85] 

RIN 2137—AD97 

Pipeline Safety: Standards for Direct 

Assessment of Gas and Hazardous 

Liquid Pipelines 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), DOT. 

ACTION: Final rule. 

SUMMARY: Under current regulations 

governing integrity management of gas 

transmission lines, if an operator uses 

direct assessment to evaluate corrosion 

risks, it must carry out the direct 

assessment according to PHMSA 

standards. In response to a statutory 

directive, this Final Rule prescribes 

similar standards operators must meet 

when they use direct assessment on 

certain other onshore gas, hazardous 

liquid, and carbon dioxide pipelines. 

PHMSA believes broader application of 

direct assessment standards will 

enhance public confidence in the use of 

direct assessment to assure pipeline 

safety. 

DATES: This Final Rule takes effect 

November 25, 2005. Incorporation by 

reference of NACE Standard RP0502–

2002 in this rule is approved by the 

Director of the Federal Register as of 

November 25, 2005. 

FOR FURTHER INFORMATION CONTACT: L.M. 

Furrow by phone at 202–366–4559, by 

fax at 202–366–4566, by mail at U.S. 

Department of Transportation, 400 

Seventh Street, SW., Washington, DC 

20590, or by e-mail at 

buck.furrow@dot.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

This Final Rule concerns direct 

assessment, a process of managing the 

effects of external corrosion, internal 

corrosion, or stress corrosion cracking 

on pipelines made primarily of steel or 

iron. The process involves data 

collection, indirect inspection, direct 

examination, and evaluation. Operators 

use direct assessment not only to find 

existing corrosion defects but also to 

prevent future corrosion problems. 

Congress recognized the advantages of 

using direct assessment on U.S. 

Department of Transportation (DOT) 

regulated gas, hazardous liquid, and 

carbon dioxide pipeline facilities. 

Section 14 of the Pipeline Safety 

Improvement Act of 2002 (Pub. L. 107–

355; Dec. 17, 2002) directs DOT to issue 

regulations on using internal inspection, 

pressure testing, and direct assessment 

to manage the risks to gas pipeline 

facilities in high consequence areas. In 

addition, Section 23 directs DOT to 

issue regulations prescribing standards 

for inspecting pipeline facilities by 

direct assessment. 

In response to the first statutory 

directive, Section 14, DOT’s Research 

and Special Programs Administration 

(RSPA) 1 published regulations in 49 

CFR part 192, subpart O, that require 

operators to follow detailed programs to 

manage the integrity of gas transmission 

line segments in high consequence 

areas. Subpart O also requires an 

operator electing to use direct 

assessment in its integrity management 

program, to carry out the direct 

assessment according to § § 192.925, 

192.927, and 192.929, as appropriate.2

Sections 192.925, 192.927, and 

192.929 cross-reference the American 

Society of Mechanical Engineers’

(ASME), ASME B31.8S–2001, 

‘‘Managing System Integrity of Gas 

Pipelines.’’ ASME B31.8S–2001 

describes a comprehensive process to 

assess and mitigate the likelihood and 

consequences of gas pipeline risks. In 

addition, § 192.925 cross-references a 

61572 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 

NACE International (NACE) standard, 

NACE Standard RP0502–2002, 

‘‘Pipeline External Corrosion Direct 

Assessment Methodology.’’ NACE 

Standard RP0502–2002 describes a stepby-step process for identifying and 

addressing external corrosion activity, 

repairing defects, and taking remedial 

action. Other parts of § § 192.925, 

192.927, and 192.929 ensure operators 

use appropriate criteria in making direct 

assessment decisions. 

II. Proposed Rules 

In response to the second statutory 

directive, Section 23, PHMSA published 

a notice of proposed rulemaking 

(NPRM) (69 FR 61771; Oct. 21, 2004). 

The NPRM proposed standards for using 

direct assessment on any onshore gas 

pipeline made primarily of steel or iron 

and regulated by 49 CFR part 192 or 

onshore steel hazardous liquid or 

carbon dioxide pipeline regulated by 49 

CFR part 195. Under proposed 

§ 192.490, if an operator chooses to use 

direct assessment to evaluate the threat 

of external corrosion, internal corrosion, 

or stress corrosion cracking on a 

regulated onshore gas pipeline, the 

direct assessment would have to be 

done according to § § 192.925, 192.927, 

or 192.929, as appropriate. For regulated 

hazardous liquid and carbon dioxide 

pipelines, proposed § 195.588 would 

require similar action, except 

compliance with § 192.927 would not be 

required, because § 192.927 

requirements are only suitable for dry 

gas pipelines. 

III. Advisory Committee 

Recommendations 

The Technical Pipeline Safety 

Standards Committee (TPSSC) and the 

Technical Hazardous Liquid Pipeline 

Safety Standards Committee (THLPSSC) 

considered the NPRM at meetings in 

Washington, DC, on December 14 and 

15, 2004. The TPSSC, a statutorily 

mandated advisory committee, advises 

PHMSA on proposed safety standards 

and other policies concerning gas 

pipelines. The THLPSSC is a similar 

committee that provides advice about 

hazardous liquid and carbon dioxide 

pipelines. Each committee has an 

authorized membership of 15 persons 

with membership evenly divided 

between government, industry, and the 

public. Each member is qualified to 

consider the technical feasibility, 

reasonableness, cost-effectiveness, and 

practicability of proposed pipeline 

safety standards. A transcript of each 

committee’s meeting is available in 

Docket No. PHMSA–98–4470. 

After careful consideration of the 

NPRM, the THLPSSC voted 

unanimously to recommend the 

following: (1) Adopt a single definition 

of direct assessment for use by 

hazardous liquid pipeline operators 

inside and outside high consequence 

areas; (2) state direct assessment 

standards directly in part 195, rather 

than by cross-referencing part 192 

standards; (3) consider adopting the 

consensus standard under development 

by NACE for direct assessment of stress 

corrosion cracking; and (4) amend the 

integrity management rule (§ 195.452) to 

allow use of direct assessment without 

prior notice. 

As a result of its deliberation, the 

TPSSC voted unanimously that 

proposed § 192.490 should not be 

applied to gas distribution lines. It also 

voted unanimously that the Final Rule 

should distinguish direct assessment 

from similar methods of assessing 

corrosion. Such a distinction would 

identify situations where similar 

methods of addressing corrosion are 

appropriate but are not regulated under 

the proposed direct assessment 

standard. 

IV. Disposition of Comments and 

Advisory Committee Recommendations 

on Proposed Rules 

We received written comments on the 

proposed rules from 19 sources. These 

sources are categorized as follows: 

State pipeline safety agency ................................................... Pennsylvania Public Utility Commission. 

Gas pipeline operators ............................................................ Duke Energy Gas Transmission (Duke), El Paso Corporation (El Paso), Nicor 

Gas (Nicor), NiSource Corporate Services Company (Nisource), Pacific Gas 

& Electric Company (PG&E), Paiute Pipeline Company (Paiute), Puget 

Sound Energy (Puget), Southwest Gas Corporation (SWGas). 

Gas pipeline trade associations .............................................. American Public Gas Association (APGA), American Gas Association (AGA), 

Interstate Natural Gas Association of America (INGAA), Northeast Gas Association (NGA). 

Gas pipeline industry committee ........................................... Gas Piping Technology Committee (GPTC). 

Hazardous liquid pipeline trade associations ....................... American Petroleum Institute (API), Association of Oil Pipe Lines (AOPL). 

Nonprofit organizations .......................................................... Cook Inlet Regional Citizens Advisory Council, Pipeline Safety Trust 

Consultant ................................................................................ Glen F. Armstrong. 

Only one commenter, the Cook Inlet 

Regional Citizens Advisory Council 

(Council), created by the Oil Pollution 

Act of 1990, supported the proposed 

rules without change. The Council 

welcomed the additional Federal 

standards because of the need to control 

pipeline corrosion. The remaining 

commenters’ issues are stated below 

along with our disposition of those 

issues and the advisory committee’s 

recommendations. 

Is this rulemaking necessary? AGA, 

Duke, El Paso, GPTC, INGAA, NiSource, 

and Puget claimed the integrity 

management regulations for gas 

transmission lines (subpart O of part 

192) satisfy the statutory directive to 

prescribe direct assessment standards. 

Taking a similar position, AOPL and 

API contended that Congress did not 

intend direct assessment standards to 

apply outside integrity management 

regulations. To support this position, 

these commenters stated that Congress 

did not require operators to use direct 

assessment on pipelines outside 

integrity management regulations. They 

also pointed out that direct assessment 

was developed for use in integrity 

management programs. 

Because the legislative history does 

not support the commenter’s argument 

that direct assessment standards should 

apply only to pipelines subject to 

integrity management rules, PHMSA 

believes this rulemaking is necessary. It 

is reasonable to conclude Congress did 

not intend to restrict direct assessment 

standards to pipelines covered by 

integrity management regulations. 

Unlike the first statutory directive 

concerning direct assessment, which 

applies only to pipeline facilities in 

high consequence areas, the second 

directive applies to pipeline facilities 

regardless of location. Also, the first and 

second directives appear in separate 

sections of the statute (Sections 14 and 

23 of Pub. L. 107–355), with no 

apparent connection. Had Congress 

wanted to restrict direct assessment 

standards to pipelines covered by 

integrity management regulations, it 

could have expressly linked the second 

directive to the first or included the 

second directive in the same section as 

the first. 

Is proposed § 192.490 appropriate for 

gas distribution lines? AGA, APGA, 

Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61573 

Duke, El Paso, GPTC, INGAA, NGA, 

Nicor, NiSource, Paiute, and PG&E 

argued direct assessment was developed 

for gas transmission integrity 

management and has not been shown to 

be appropriate for gas distribution lines. 

They said the relevant technical data 

and experience do not show direct 

assessment would be effective on gas 

distribution lines. In addition, some of 

these commenters thought because gas 

distribution lines differ from gas 

transmission lines in design, operation, 

configuration, and location, direct 

assessment may be impractical on gas 

distribution lines. The many 

aboveground and belowground utility 

facilities—both in-service and 

abandoned—were thought to pose 

significant technical hurdles. The 

Pennsylvania Public Utility Commission 

and the Pipeline Safety Trust also 

questioned the suitability of direct 

assessment for gas distribution lines. 

These comments came as a surprise to 

PHMSA because the two documents 

that are the mainstays of the proposed 

direct assessment standards, ASME 

B31.8S–2001 and NACE Standard 

RP0502–2002, can be interpreted to 

cover gas distribution lines. Each 

document states that it applies to 

onshore pipelines. Although neither 

document defines ‘‘pipeline,’’ ASME’s 

B31.8 Code, to which ASME B31.8S–

2001 is a supplement, defines 

‘‘pipeline’’ as ‘‘all parts of physical 

facilities through which gas moves in 

transportation.’’ And ‘‘transportation of 

gas’’ is defined as the ‘‘gathering, 

transmission, or distribution of gas.’’

No matter how ASME B31.8S–2001 

and NACE Standard RP0502–2002 are 

interpreted, the comments persuaded us 

that direct assessment, as depicted by 

these two documents, is not appropriate 

for gas distribution lines. Both ASME 

B31.8S–2001 and NACE Standard 

RP0502–2002, were developed during 

the rulemaking proceeding on gas 

transmission integrity management and 

in furtherance of that proceeding. 

Consequently, neither document was 

developed with a focus on gas 

distribution lines. Furthermore, 

although both documents apply to 

pipelines, they do not take full account 

of gas distribution line features as 

comments suggest they should to treat 

gas distribution lines appropriately. 

Given these considerations and the 

TPSSC’s unanimous recommendation 

that we not apply the proposed direct 

assessment standards to gas distribution 

lines, we decided to exclude 

distribution lines from final § 192.490. 

Removing ‘‘pipeline’’ from the proposed 

wording and adding ‘‘transmission line’’

in its place accomplishes this change. 

Would the proposed standards 

discourage the voluntary use of 

corrosion control methods? AGA, 

Armstrong, Duke, El Paso, GPTC, 

INGAA, NGA, Nicor, NiSource, Paiute, 

PG&E, Puget, and SWGas were 

concerned the proposed standards 

(§ § 192.490 and 195.588) would 

discourage operators from voluntarily 

using corrosion control methods related 

to direct assessment on pipelines not 

subject to the integrity management 

regulations. Their concern stemmed 

from the difficulty of recognizing when 

direct assessment is being used. They 

said performance of any one of the four 

steps that constitute direct assessment 

could imply use of direct assessment 

and lead to disagreements with 

government inspectors over whether 

direct assessment is being used. For 

example, some commenters said 

performing a close interval electrical 

survey resembled the indirect 

examination step of direct assessment. 

Others thought examining buried pipe 

for corrosion could be considered the 

direct examination step. El Paso, 

INGAA, Nicor, and Armstrong suggested 

the Final Rule clarify that operators may 

use corrosion control methods related to 

direct assessment without having to 

meet the proposed direct assessment 

standards. 

We recognize disagreements could 

arise over whether the use of a corrosion 

control method is part of the direct 

assessment process. However, we do not 

think such disagreements are likely to 

be serious enough to discourage 

operators from continuing to use such 

methods separately from direct 

assessment. To minimize potential 

disagreements, operators may explain in 

their corrosion control procedures the 

situations in which they use methods 

related to direct assessment separately 

from direct assessment. 

In view of the commenters’ concern, 

PHMSA has added provisions to final 

§ § 192.490 and 195.588 to clarify 

application of the direct assessment 

standards. The statement provides that 

the direct assessment standards do not 

apply to methods related to direct 

assessment, such as close interval 

surveys, voltage gradient surveys, or 

examination of exposed pipelines, when 

used separately from the direct 

assessment process. This change is 

consistent with the TPSSC’s second 

recommendation. 

Are the gas pipeline standards crossreferenced in proposed § 195.588 

suitable for hazardous liquid and 

carbon dioxide pipelines? In their 

comments on proposed § 195.588, AOPL 

and API opposed cross-referencing 

§ § 192.925 and 192.929 primarily 

because these standards refer to ASME 

B31.8S–2001. They argued ASME 

B31.8S–2001 was developed for natural 

gas transmission lines and without the 

involvement of hazardous liquid 

pipeline operators. They were also 

concerned that cross-referencing part 

192 gas pipeline standards could lead to 

misunderstandings by hazardous liquid 

pipeline operators. The THLPSSC 

similarly opposed cross-referencing part 

192 standards. 

In developing the NPRM, we assumed 

the cross-referenced part 192 standards 

and their cross-references to ASME 

B31.8S–2001 would be suitable for 

hazardous liquid and carbon dioxide 

pipelines. However, the AOPL and API 

comments and the THLPSSC’s 

recommendation have caused us to 

doubt that assumption. In addition, we 

are concerned that application of the 

part 192 direct assessment standards to 

hazardous liquid and carbon dioxide 

pipelines could present compliance 

problems. Contributing to this concern 

is the comment that ASME B31.8S–2001 

was not developed with an eye to 

hazardous liquid pipelines. In fact, 

paragraph 1.1 of ASME B31.8S–2001 

specifically states that the scope of 

ASME B31.8S–2001 is limited to 

‘‘onshore pipeline systems * * * that 

transport gas.’’

Therefore, we decided not to include 

cross-references to part 192 standards or 

to ASME B31.8S–2001 in final 

§ 195.588. Instead, final § 195.588 

includes a complete statement of direct 

assessment standards, with crossreferences only to NACE Standard 

RP0502–2002. 

Should the integrity management 

regulations for hazardous liquid and 

carbon dioxide pipelines allow use of 

direct assessment without advance 

notice? The integrity management 

regulations for hazardous liquid and 

carbon dioxide pipelines (§ 195.452) 

prescribe three ways to assess pipeline 

integrity: internal inspection via a smart 

pig, pressure testing, and any other 

technology the operator demonstrates 

can provide an equivalent 

understanding of pipe conditions. 

However, before another technology, 

such as direct assessment may be used, 

the operator must notify PHMSA at least 

90 days in advance 

(§ § 195.452(c)(1)(i)(C) and 

195.452(j)(5)(iii)). 

In contrast to § 195.452, the proposed 

direct assessment standards do not 

include a requirement to give 90 days’

advance notice as a precondition to 

using direct assessment. We see no need 

to propose such a requirement since the 

current Part 192 direct assessment 

standards do not require operators to 

61574 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 

3Section 192.903 defines ‘‘direct assessment’’ as 

‘‘an integrity assessment method that utilizes a 

process to evaluate certain threats (i.e., external 

corrosion, internal corrosion and stress corrosion 

cracking) to a covered pipeline segment’s intergrity. 

The process includes the gathering and integration 

of risk factor data, indirect examination or analysis 

to identify areas of suspected corrosion, direct 

examination of the pipeline in these areas, and post 

assessment evaluation.’’

give advance notice before using direct 

assessment. 

In their comments on proposed 

§ 195.588, AOPL and API suggested 

direct assessment of external corrosion 

should be listed directly in § 195.452 as 

a permissible method of integrity 

assessment. They believe that when 

external corrosion direct assessment is 

performed according to NACE Standard 

RP0502–2002, it is an acceptable use of 

‘‘other technology’’ for which 90 days 

advance notice is no longer necessary. 

As discussed above under Advisory 

Committee Recommendations, the 

THLPSSC also favored listing direct 

assessment directly in § 195.452 as a 

recognized assessment method that 

would bypass the 90-day advance notice 

requirement. 

The purpose of the 90 days advance 

notice requirement in § 195.452 is to 

provide time for PHMSA and State 

pipeline safety agencies to review 

technology other than pigging and 

pressure testing to learn what 

information the technology provides 

about pipe conditions. According to 

information on a PHMSA Web site 

(http://primis.phmsa.dot.gov/iim/ 

notifications.imd), several operators 

have submitted notices of their intent to 

use direct assessment on hazardous 

liquid or carbon dioxide pipelines. In a 

majority of cases, there were no PHMSA 

or State government objections to the 

use of direct assessment. Objections 

were raised where the notification 

lacked information explaining how the 

direct assessment was to be performed. 

When applied to direct assessment, 

we believe the 90-day advance notice 

requirement of § 195.452 is no longer 

useful and is inconsistent with the 

proposed rules. Direct assessment is 

now being used under the part 192 

integrity management regulations 

without advance notice. As a result, 

government inspectors are fully aware 

of the direct assessment technology and 

the situations for which it is suited, 

making advance case-by-case review 

under § 195.452 unnecessary. In 

addition, requiring operators to follow 

prescribed standards when using direct 

assessment will remove the primary 

objection previously raised about 

operators’ advance notices—insufficient 

information to explain the method of 

assessment. Therefore, we are changing 

§ § 195.452(c)(1)(i)(C) and 

195.452(j)(5)(iii) to allow use of direct 

assessment in accordance with final 

§ 195.588 without 90 days advance 

notice. 

What standard should apply to direct 

assessment of stress corrosion cracking 

on hazardous liquid and carbon dioxide 

pipelines? The NPRM proposed that 

§ 192.929 be the standard for direct 

assessment of stress corrosion cracking 

on hazardous liquid and carbon dioxide 

pipelines. This standard relies largely 

on cross-references to ASME B31.8S–

2001. 

Besides their objections to crossreferencing part 192 standards and 

particularly ASME B31.8S–2001, AOPL 

and API suggested that we not adopt 

any standard for the direct assessment 

of stress corrosion cracking on 

hazardous liquid pipelines. They said 

because methods of detecting stress 

corrosion cracking are developing 

rapidly, direct assessment may not be 

the optimum technology for hazardous 

liquid pipelines. The THLPSSC 

recommended we consider adopting the 

consensus standard that NACE 

International was developing for direct 

assessment of stress corrosion cracking. 

As explained above, we decided not 

to cross-reference directly or indirectly 

ASME B31.8S–2001 in final § 195.588, 

because the document is closely 

identified with gas pipelines. 

Consequently, since provisions of 

ASME B31.8S–2001 are an important 

part of the proposed stress corrosion 

standard, we have not included a direct 

assessment standard for stress corrosion 

cracking in final § 195.588. As the 

THLPSSC recommended, we will 

consider the recently published NACE 

Standard RP0204–2004, Stress 

Corrosion Cracking (SCC) Direct 

Assessment Methodology, for possible 

future rulemaking action. By removing 

the proposed cross-reference to 

§ 192.929, final § 195.588 consists of the 

text of § 192.925 without its crossreferences to ASME B31.8S–2001. 

V. Editorial Changes 

• Final § § 192.490 and 195.588 do 

not include the proposed phrase ‘‘or to 

meet any requirement of this Subpart 

regarding that threat.’’ The phrase was 

used in the proposed rules to draw 

attention to situations in which 

operators might choose to use direct 

assessment. However, the phrase 

appears to be unnecessary and, 

according to comments, possibly 

confusing. 

• Final § 192.490 clarifies that ‘‘direct 

assessment’’ means direct assessment as 

defined in § 192.903.3 This definition 

applies to ‘‘direct assessment’’ as it is 

used in subpart O of part 192, including 

§ § 192.925, 192.927, and 192.929—the 

bases of the proposed direct assessment 

standards. Also, in final § 192.490, 

instead of using the proposed term 

‘‘ferrous’’ to limit pipelines to which the 

direct assessment standards apply, we 

used ‘‘made primarily of steel or iron.’’

This change removes the possibility of 

confusion over the meaning of ferrous. 

• We added a similar definition of 

‘‘direct assessment’’ to § 195.553, which 

contains definitions applicable to 

subpart H of part 195, including final 

§ 195.588. This addition satisfies the 

first THLPSSC recommendation. The 

definition of ‘‘external corrosion direct 

assessment,’’ which was proposed 

through the cross-reference to § 192.925, 

is also added to § 195.553. 

• In final § 195.588, we substituted 

‘‘pipeline segment’’ for the terms 

‘‘covered segment’’ and ‘‘covered 

pipeline segment’’ to avoid the 

possibility that the definition of these 

terms in § 192.903—a segment of 

transmission pipeline located in a high 

consequence area—would 

unintentionally constrain the scope of 

final § 195.588. A footnote resolves a 

similar problem in final § 192.490. 

• Section 192.925(b) provides that if 

coating damage is detected by external 

corrosion direct assessment, the 

operator must integrate that information 

with data gathered and integrated under 

certain other requirements 

(§ § 192.917(b) and 192.917(e)(1)). These 

other requirements, which involve 

evaluating and addressing risks besides 

corrosion, including third-party damage, 

apply only to gas transmission lines 

subject to the integrity management 

regulations in subpart O of part 192. 

Although the proposed direct 

assessment standards for other pipelines 

included cross-references to § 192.925, 

the NPRM did not address extending 

§ § 192.917(b) and 192.917(e)(1) to 

pipelines outside subpart O by virtue of 

the cross-references. The focus of the 

NPRM was strictly on using direct 

assessment to evaluate and address 

corrosion risks. Using direct assessment 

data to evaluate non-corrosion risks to 

pipeline integrity was not discussed. So 

it would be inappropriate to infer that 

the proposed references to § 192.925 

meant that operators who voluntarily 

use external corrosion direct assessment 

on pipelines outside subpart O would 

also have to comply with § § 192.917(b) 

and 192.917(e)(1). To ensure this 

possible inference does not affect the 

Final Rules, final § § 192.490 and 

195.588 exclude pipelines outside 

subpart O from the § 192.925(b) 

requirement related to integrating 

coating damage data. Nevertheless, for 

Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61575 

hazardous liquid and carbon dioxide 

pipelines that are subject to the integrity 

management regulations in § 195.452, 

the detection of coating damage is an 

important factor to consider in the 

information analysis required by 

§ 195.452(g) and the continual integrity 

evaluation required by § 195.452(j)(2). 

VI. Regulatory Analyses and Notices 

Executive Order 12866 and DOT 

Policies and Procedures. PHMSA does 

not consider this rulemaking to be a 

significant regulatory action under 

Section 3(f) of Executive Order 12866 

(58 FR 51735; Oct. 4, 1993). Therefore, 

the Office of Management and Budget 

(OMB) has not received a copy of the 

Final Rule to review. PHMSA also does 

not consider this rulemaking to be 

significant under DOT regulatory 

policies and procedures (44 FR 11034: 

February 26, 1979). 

PHMSA has evaluated the costs and 

benefits of this Final Rule and a copy of 

the evaluation is in the docket. The 

evaluation concludes operators will 

incur only minimal costs to comply 

with the Final Rule. 

Regulatory Flexibility Act. Under the 

Regulatory Flexibility Act (5 U.S.C. 601 

et seq.), PHMSA must consider whether 

rulemaking actions have a significant 

economic impact on a substantial 

number of small entities. Based on the 

facts available about the anticipated 

impacts of this rulemaking, I certify that 

this rulemaking will not have a 

significant impact on a substantial 

number of small entities. 

Executive Order 13175. PHMSA has 

analyzed this rulemaking according to 

the principles and criteria contained in 

Executive Order 13175, ‘‘Consultation 

and Coordination with Indian Tribal 

Governments.’’ Because the Final Rule 

will not significantly or uniquely affect 

the communities of the Indian Tribal 

Governments nor impose substantial 

direct compliance costs, the funding 

and consultation requirements of 

Executive Order 13175 do not apply. 

Paperwork Reduction Act. Operators 

have just recently begun to use direct 

assessment to assess the effects of 

corrosion on onshore gas transmission 

lines subject to the integrity 

management regulations in subpart O of 

part 192. The use of direct assessment 

on other pipelines regulated by part 192 

or part 195 is voluntary. This Final Rule 

does not change this voluntary use 

status. It merely sets standards for 

performing direct assessment if 

operators choose to use it. 

Pipeline operators covered by the 

Final Rule who choose to use direct 

assessment would have to prepare 

appropriate plans and procedures and 

keep records as required by Section 7 of 

NACE Standard RP0502–2002. To help 

estimate the paperwork burden these 

operators would face, the NPRM invited 

comments on how many operators plan 

to use direct assessment voluntarily and 

what the burden hours and cost would 

be. 

None of the commenters foresaw any 

voluntary use of direct assessment or 

commented on the potential paperwork 

burden. This result was not a surprise, 

for direct assessment is a new process 

and so far its use is mostly limited to gas 

transmission lines subject to subpart O 

of part 192. Under these circumstances, 

it is reasonable to expect that few, if 

any, operators will be affected by the 

Final Rule. So no net increase in 

paperwork burdens is likely from this 

Final Rule. For this reason, we believe 

that submitting an analysis of the 

burdens to OMB under the Paperwork 

Reduction Act is unnecessary. 

Unfunded Mandates Reform Act of 

1995. This Final Rule does not impose 

unfunded mandates under the 

Unfunded Mandates Reform Act of 

1995. It does not result in costs of $100 

million or more to either State, local, or 

tribal governments, in the aggregate, or 

to the private sector, and is the least 

burdensome alternative that achieves 

the objective of the rulemaking. 

National Environmental Policy Act. 

PHMSA has analyzed the Final Rule for 

purposes of the National Environmental 

Policy Act (42 U.S.C. 4321 et seq.). 

Because the Final Rule affects only 

those operators that voluntarily use 

direct assessment and because it largely 

involves processes of data collection 

and evaluation, we have determined 

that it is unlikely to significantly affect 

the quality of the human environment. 

An Environmental Assessment is 

available for review in the docket. 

Executive Order 13132. PHMSA has 

analyzed the Final Rule according to the 

principles and criteria contained in 

Executive Order 13132, ‘‘Federalism.’’

No part of the rule (1) has substantial 

direct effects on the States, the 

relationship between the national 

government and the States, or the 

distribution of power and 

responsibilities among the various 

levels of government; (2) imposes 

substantial direct compliance costs on 

State and local governments; or (3) 

preempts State law. Therefore, the 

consultation and funding requirements 

of Executive Order 13132 do not apply. 

Executive Order 13211. This Final 

Rule is not a ‘‘Significant Energy 

Action’’ under Executive Order 13211. It 

is not a significant regulatory action 

under Executive Order 12866 and is not 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy. Further, this rulemaking has not 

been designated by the Administrator of 

the Office of Information and Regulatory 

Affairs as a significant energy action. 

List of Subjects 

49 CFR Part 192 

Natural gas, Pipeline safety, Reporting 

and recordkeeping requirements. 

49 CFR Part 195 

Ammonia, Carbon dioxide, 

Incorporation by reference, Petroleum, 

Pipeline safety, Reporting and 

recordkeeping requirements. 

■ In consideration of the foregoing, 

PHMSA amends 49 CFR parts 192 and 

195 as follows: 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 1. The authority citation for part 192 

continues to read as follows: 

Authority: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60110, 60113, and 60118; and 

49 CFR 1.53. 

■ 2. Add § 192.490 to read as follows: 

§ 192.490 Direct assessment. 

Each operator that uses direct 

assessment as defined in § 192.903 on 

an onshore transmission line made 

primarily of steel or iron to evaluate the 

effects of a threat in the first column 

must carry out the direct assessment 

according to the standard listed in the 

second column. These standards do not 

apply to methods associated with direct 

assessment, such as close interval 

surveys, voltage gradient surveys, or 

examination of exposed pipelines, when 

used separately from the direct 

assessment process. 

Threat Standard 1

External corrosion ................... § 192.925 2

Internal corrosion in pipelines 

that transport dry gas.

§ 192.927 

Stress corrosion cracking ....... § 192.929 

1For lines not subject to subpart O of this 

part, the terms ‘‘covered segment’’ and ‘‘covered pipeline segment’’ in §§ 192.925, 

192.927, and 192.929 refer to the pipeline 

segment on which direct assessment is performed. 2 In § 192.925(b), the provision regarding detection of coating damage applies only to pipelines subject to subpart O of this part. 

PART 195—TRANSPORTATION OF 

HAZARDOUS LIQUIDS BY PIPELINE 

■ 3. The authority citation for part 195 

continues to read as follows: 

61576 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 

Authority: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60118; and 49 CFR 1.53. 

■ 4. In § 195.3(c), amend the table of 

referenced material by adding item G.(2) 

to read as follows: 

§ 195.3 Matter incorporated by reference in 

whole or in part. 

* * * * * 

(c) * * * 

G. * * * ................................. * * * 

(2) NACE Standard RP0502–

2002 ‘‘Pipeline External 

Corrosion Direct Assessment Methodology’’ (2002).

§ 195.588 

■ 5. Amend § 195.452 as follows: 

■ a. Redesignate paragraph (c)(1)(i)(C) as 

(c)(1)(i)(D); 

■ b. Remove ‘‘or’’ from the end of 

paragraph (c)(1)(i)(B); 

■ c. Redesignate paragraph (j)(5)(iii) as 

(j)(5)(iv); 

■ d. Remove ‘‘or’’ from the end of 

paragraph (j)(5)(ii); and 

■ e. Add new paragraphs (c)(1)(i)(C) and 

(j)(5)(iii) to read as follows: 

§ 195.452 Pipeline integrity management in 

high consequence areas. 

* * * * * 

(c) * * * 

(1) * * * 

(i) * * * 

(C) External corrosion direct 

assessment in accordance with 

§ 195.588; or 

* * * * * 

(j) * * * 

(5) * * * 

(iii) External corrosion direct 

assessment in accordance with 

§ 195.588; or 

* * * * * 

■ 6. In § 195.553, add definitions for 

‘‘direct assessment’’ and ‘‘external 

corrosion direct assessment (ECDA)’’ as 

follows: 

§ 195.553 What special definitions apply to 

this Subpart? 

* * * * * 

Direct assessment means an integrity 

assessment method that utilizes a 

process to evaluate certain threats (i.e., 

external corrosion, internal corrosion 

and stress corrosion cracking) to a 

pipeline segment’s integrity. The 

process includes the gathering and 

integration of risk factor data, indirect 

examination or analysis to identify areas 

of suspected corrosion, direct 

examination of the pipeline in these 

areas, and post assessment evaluation. 

* * * * * 

External corrosion direct assessment 

(ECDA) means a four-step process that 

combines pre-assessment, indirect 

inspection, direct examination, and 

post-assessment to evaluate the threat of 

external corrosion to the integrity of a 

pipeline. 

* * * * * 

■ 7. Add § 195.588 to read as follows: 

§ 195.588 What standards apply to direct 

assessment? 

(a) If you use direct assessment on an 

onshore pipeline to evaluate the effects 

of external corrosion, you must follow 

the requirements of this section for 

performing external corrosion direct 

assessment. This section does not apply 

to methods associated with direct 

assessment, such as close interval 

surveys, voltage gradient surveys, or 

examination of exposed pipelines, when 

used separately from the direct 

assessment process. 

(b) The requirements for performing 

external corrosion direct assessment are 

as follows: 

(1) General. You must follow the 

requirements of NACE Standard 

RP0502–2002 (incorporated by 

reference, see § 195.3). Also, you must 

develop and implement an ECDA plan 

that includes procedures addressing 

pre-assessment, indirect examination, 

direct examination, and postassessment. 

(2) Pre-assessment. In addition to the 

requirements in Section 3 of NACE 

Standard RP0502–2002, the ECDA plan 

procedures for pre-assessment must 

include—

(i) Provisions for applying more 

restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) The basis on which you select at 

least two different, but complementary, 

indirect assessment tools to assess each 

ECDA region; and 

(iii) If you utilize an indirect 

inspection method not described in 

Appendix A of NACE Standard 

RP0502–2002, you must demonstrate 

the applicability, validation basis, 

equipment used, application procedure, 

and utilization of data for the inspection 

method. 

(3) Indirect examination. In addition 

to the requirements in Section 4 of 

NACE Standard RP0502–2002, the 

procedures for indirect examination of 

the ECDA regions must include—

(i) Provisions for applying more 

restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) Criteria for identifying and 

documenting those indications that 

must be considered for excavation and 

direct examination, including at least 

the following: 

(A) The known sensitivities of 

assessment tools; 

(B) The procedures for using each 

tool; and 

(C) The approach to be used for 

decreasing the physical spacing of 

indirect assessment tool readings when 

the presence of a defect is suspected; 

(iii) For each indication identified 

during the indirect examination, criteria 

for—

(A) Defining the urgency of 

excavation and direct examination of 

the indication; and 

(B) Defining the excavation urgency as 

immediate, scheduled, or monitored; 

and 

(iv) Criteria for scheduling 

excavations of indications in each 

urgency level. 

(4) Direct examination. In addition to 

the requirements in Section 5 of NACE 

Standard RP0502–2002, the procedures 

for direct examination of indications 

from the indirect examination must 

include—

(i) Provisions for applying more 

restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) Criteria for deciding what action 

should be taken if either: 

(A) Corrosion defects are discovered 

that exceed allowable limits (Section 

5.5.2.2 of NACE Standard RP0502–2002 

provides guidance for criteria); or 

(B) Root cause analysis reveals 

conditions for which ECDA is not 

suitable (Section 5.6.2 of NACE 

Standard RP0502–2002 provides 

guidance for criteria); 

(iii) Criteria and notification 

procedures for any changes in the ECDA 

plan, including changes that affect the 

severity classification, the priority of 

direct examination, and the time frame 

for direct examination of indications; 

and 

(iv) Criteria that describe how and on 

what basis you will reclassify and reprioritize any of the provisions specified 

in Section 5.9 of NACE Standard 

RP0502–2002. 

(5) Post assessment and continuing 

evaluation. In addition to the 

requirements in Section 6 of NACE 

Standard UP 0502–2002, the procedures 

for post assessment of the effectiveness 

of the ECDA process must include—

(i) Measures for evaluating the longterm effectiveness of ECDA in 

addressing external corrosion in 

pipeline segments; and 

(ii) Criteria for evaluating whether 

conditions discovered by direct 

examination of indications in each 

ECDA region indicate a need for 

reassessment of the pipeline segment at 

an interval less than that specified in 

Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61577 

Sections 6.2 and 6.3 of NACE Standard 

RP0502–2002 (see Appendix D of NACE 

Standard RP0502–2002). 

Issued in Washington, DC, on October 19, 

2005. 

Brigham A. McCown, 

Acting Administrator, PHMSA. 

[FR Doc. 05–21233 Filed 10–24–05; 8:45 am] 

BILLING CODE 4910–60–P 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 648 

[Docket No. 031015257-3308-02 ; I.D. 

101705B] 

Fisheries of the Northeastern United 

States; Atlantic Surfclam and Ocean 

Quahog Fisheries; Suspension of 

Minimum Atlantic Surfclam Size Limit 

for Fishing Year 2006 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 

Atmospheric Administration (NOAA), 

Commerce. 

ACTION: Temporary rule; suspension of 

the Atlantic surfclam minimum size 

limit. 

SUMMARY: NMFS suspends the 

minimum size limit of 4.75 inches (120 

mm) for Atlantic surfclams for the 2006 

fishing year. This action is taken under 

the authority of the implementing 

regulations for this fishery, which allow 

for the annual suspension of the 

minimum size limit based upon set 

criteria. The intended effect is to relieve 

the industry from a regulatory burden 

that is not necessary, as the majority of 

surfclams harvested are larger than the 

minimum size limit. 

DATES: Effective January 1, 2006, 

through December 31, 2006. 

ADDRESSES: Written inquiries may be 

sent to Patricia A. Kurkul, Regional 

Administrator, National Marine 

Fisheries Service, Northeast Regional 

Office, One Blackburn Drive, 

Gloucester, MA 01930–2298. 

FOR FURTHER INFORMATION CONTACT: 

Brian R. Hooker, Fishery Policy Analyst, 

(978) 281-9220; fax (978) 281–9135. 

SUPPLEMENTARY INFORMATION: Section 

648.72(c) of the regulations 

implementing the Fishery Management 

Plan (FMP) for the Atlantic Surfclam 

and Ocean Quahog Fisheries allows the 

Administrator, Northeast Region, NMFS 

(Regional Administrator) to suspend 

annually, by publication of a 

notification in the Federal Register, the 

minimum size limit for Atlantic 

surfclams. This action may be taken 

unless discard, catch, and biological 

sampling data indicate that 30 percent 

of the Atlantic surfclam resource is 

smaller than 4.75 inches (120 mm) and 

the overall reduced size is not 

attributable to harvest from beds where 

growth of the individual clams has been 

reduced because of density-dependent 

factors. 

At its June 2004 meeting, the MidAtlantic Fishery Management Council 

(Council) voted to recommend that the 

Regional Administrator suspend the 

minimum size limit for the 2005, 2006, 

and 2007 fishing years. In accordance 

with the provisions of the FMP, the 

Regional Administrator will publish the 

suspension of the surfclam minimum 

size if the proportion of undersized 

surfclams is under 30 percent of the 

total surfclam landings for each fishing 

year. 

Commercial surfclam data for 2005 

were analyzed to determine the 

percentage of surfclams that were 

smaller than the minimum size 

requirement. The analysis indicated that 

6.8 percent of the overall commercial 

landings were composed of surfclams 

that were less than 4.75 inches (120 

mm). Based on these data, the Regional 

Administrator adopts the Council’s 

recommendation and suspends the 

minimum size limit for Atlantic 

surfclams from January 1, 2006, through 

December 31, 2006. 

Classification 

This action is authorized by 50 CFR 

part 648 and is exempt from review 

under Executive Order 12866.Authority: 

16 U.S.C. 1801 et seq. 

Dated: October 20, 2005. 

Alan D. Risenhoover, 

Acting Director, Office of Sustainable 

Fisheries, National Marine Fisheries Service. 

[FR Doc. 05–21302 Filed 10–24–05; 8:45 am] 

BILLING CODE 3510–22–S