Federal Register Vol. 80, No.47,

I. Background A. Creation of the Federal Housing Finance Agency

Effective July 30, 2008, the Housing and Economic Recovery Act of 2008 (HERA) 1 created FHFA as a new independent agency of the Federal Government, and transferred to FHFA the supervisory and oversight responsibilities of the Office of Federal Housing Enterprise Oversight (OFHEO) over the Federal National Mortgage Association and the Federal Home Loan Mortgage Corporation (collectively, the Enterprises), the oversight responsibilities of the Finance Board over the Banks and the Office of Finance (OF) (which acts as the Banks' fiscal agent) and certain functions of the Department of Housing and Urban Development.2 Under the legislation, the Enterprises, the Banks, and the OF continue to operate under regulations promulgated by OFHEO and the Finance Board until such regulations are superseded by regulations issued by FHFA.3 While FHFA has amended or re-adopted and transferred most of the former Finance Board regulations, certain Finance Board regulations, including those which address Bank capital, have not yet been transferred by FHFA, although they continue to apply to the Banks.

The twelve Banks are instrumentalities of the United States organized under the Federal Home Loan Bank Act (Bank Act).4 The Banks are cooperatives; only members of a Bank may purchase the capital stock of a Bank, and only members or certain eligible housing associates (such as state housing finance agencies) may obtain access to secured loans, known as advances, or other products provided by a Bank.5 Each Bank is managed by its own board of directors and serves the public interest by enhancing the availability of residential mortgage and community lending credit through its member institutions.6

In 1999, the GLB Act 7 amended the Bank Act to replace the capital structure of the Bank System. Under the GLB Act, the Banks became subject to risk-based and leverage capital requirements similar to those applicable to depository institutions and other housing GSEs. The GLB Act also directed the Finance Board to adopt regulations prescribing uniform capital standards applicable to each Bank. It also required the Banks to replace their existing capital stock with new classes of capital stock that would have different terms from the stock then held by Bank System members. Specifically, the GLB Act authorized the Banks to issue new Class A stock, which the GLB Act defined as redeemable six months after filing of a notice by a member, and Class B stock, defined as redeemable five years after filing of a notice by a member. The GLB Act allowed Banks to issue Class A and Class B stock in any combination and to establish terms and preferences for each class or subclass of stock issued, consistent with Finance Board regulations and the Bank Act.8

As part of the process for converting the “old” capital stock to the new GLB Act Class A and Class B stock, the GLB Act required each Bank to adopt and maintain a capital plan that established the rights, terms and preferences of each class or subclass of capital stock that it would issue.9 The GLB Act also required that each Bank's capital plan establish the minimum investment in capital stock required for its members to maintain membership and to conduct business with the Bank. Such minimum investment requirements needed to be sufficient for the Bank to meet its new minimum regulatory capital requirements. The GLB Act provided each Bank's board of directors the discretion to develop and implement a capital plan that it determined was best suited for the conditions and operations of the Bank and the interests of the Bank's members.10 It also required Finance Board approval of each Bank's capital plan prior to it taking effect.

Under the Finance Board regulations, each Bank had discretion as to when it would convert to the new capital structure. The Finance Board regulations also addressed in detail the process for the one-time conversion to the new capital structure, including requirements for disclosure to be given to members prior to the conversion. Since the Finance Board originally adopted these regulations in 2001, all Banks have converted to the GLB Act capital structure. The original Finance Board regulations were never amended, however, to remove provisions that applied only to the initial conversion process.11

When promulgating regulations relating to the Banks, section 1313(f) of the Federal Housing Enterprises Financial Safety and Soundness Act of 1992 (Safety and Soundness Act) requires the Director of FHFA (Director) to consider the differences between the Banks and the Enterprises with respect to the Banks' cooperative ownership structure; mission of providing liquidity to members; affordable housing and community development mission; capital structure; and joint and several liability.12 This requirement does not apply to regulations of the Finance Board that the Director reissues.

The changes to the Bank capital stock and capital plan regulations proposed by FHFA in October 2014 were clarifying and conforming in nature and applied exclusively to the Banks. The proposed amendments did not alter the substance of the existing Finance Board regulations. Accordingly, the proposed rule did not trigger this statutory requirement. Nonetheless, FHFA, in preparing the proposed rule, considered the differences between the Banks and the Enterprises as they related to the above factors and specifically requested comments from the public about whether these differences should have resulted in any revisions to the proposed rule. FHFA received no comments in response to this request.

FHFA published a proposed rule on Bank capital stock and capital plans in the Federal Register on October 8, 2014, with a 60-day comment period.13 The proposed rule would have transferred the Finance Board Bank capital stock regulations from 12 CFR part 931 and the Bank capital plan regulations from 12 CFR part 933 to subparts C and D of new part 1277 of FHFA regulations, respectively. Relevant definitions for parts 931 and 933 also would have been transferred to subpart A of new part 1277.14 FHFA also proposed to make certain non-substantive, clarifying and conforming changes to these provisions and to remove requirements which applied only to the Banks' initial conversion to the GLB Act capital structure.

Among other changes, FHFA proposed to replace definitions for “regulatory risk-based capital requirement” and “regulatory total capital requirement” with a new single definition for “regulatory capital requirements.” It also proposed to define the term “former member” and to add relevant references to “former member” in the regulatory text to clarify that under the Bank Act and existing regulations, such institutions could be required to hold Bank stock in certain situations after termination of their Bank membership.

With regard to existing capital stock provisions, FHFA proposed to transfer current 12 CFR part 931 to new subpart C of part 1277. Most of these provisions were to be transferred without change, beyond necessary conforming changes. FHFA, however, proposed to delete current § 931.9 which addresses various transition requirements related to the Banks' conversion to the GLB Act capital structure. Given that all Banks have successfully completed this process, § 931.9 has no future applicability.

FHFA also proposed to add clarifying language to § 1277.24 that any provision in a Bank's capital plan related to stockholder rights in a liquidation, merger, or consolidation of the Bank cannot limit FHFA's authority under the Bank Act or the Safety and Soundness Act to issue a regulation or order or to take any other action that may affect or otherwise alter the rights or privileges of stock holders in these situations. FHFA noted that it believed that the proposed change was consistent with existing provisions in each Bank's approved capital plan.

FHFA proposed to relocate relevant provisions in current part 933 to subpart D of new part 1277. As part of this process, it proposed to remove those provisions that related only to the Banks' initial conversion to the GLB Act capital structure, given that the provisions had no continuing applicability.15

FHFA also proposed not to reissue duplicative provisions related to the calculation and application of a member's, or former member's, minimum investment requirements, and instead, incorporated into proposed § 1277.28(a) the requirements governing the calculation and maintenance of the minimum investment set forth in proposed § 1277.22 by reference. FHFA noted that this change was not intended to alter the current capital plan requirements in any substantive manner.

FHFA also proposed to add to subpart D of new § 1277.29 to address the process for amending a Bank's approved capital plan. The Finance Board rules did not specifically address the process for submitting capital plan amendments for approval, although the Bank Act allows Banks to amend their capital plans with FHFA approval.16 The amendments proposed in this new section reflected long-standing guidance first provided to the Banks in 2003 governing the submission of capital plan amendments for approval. FHFA also proposed to carry over in § 1277.29(c), current language from § 933.1(c) stating that the Director can approve an amendment to a capital plan subject to specific conditions.

Finally, as discussed more fully in the SUPPLEMENTARY INFORMATION section of the proposed rule, FHFA also proposed other conforming or clarifying changes to the existing Finance Board regulations on Bank capital stock and capital plans.

FHFA received one comment on the proposed rule, but the comment did not address issues relevant to this rulemaking.17 As a result and for the reasons discussed above and in the notice of proposed rulemaking, FHFA is adopting the proposed rule as a final rule without change.

The information collection, entitled “Capital Requirements for the Federal Home Loan Banks,” contained in the 12 CFR parts 931 and 933 of the regulations that are being relocated to 12 CFR part 1277 by this final rule, has been assigned control number 2590-0002 by the Office of Management and Budget (OMB). The final rule does not substantively or materially modify the current, approved information collection. OMB has approved the relocation of this information collection to part 1277 as a non-substantive change under the Paperwork Reduction Act of 1995, 44 U.S.C. 3501, et seq.

The final rule applies only to the Banks, which do not come within the meaning of small entities as defined in the Regulatory Flexibility Act (RFA). See 5 U.S.C. 601(6). Therefore, in accordance with section 605(b) of the RFA, FHFA certifies that this final rule does not have a significant economic impact on a substantial number of small entities.

Accordingly, for reasons stated in the SUPPLEMENTARY INFORMATION and under the authority of 12 U.S.C. 1426, 1436, 1440, 1443, 1446, 4511, 4513, 4526, FHFA hereby amends subchapter E of chapter IX and subchapter D of chapter XII of title 12 of the Code of Federal Regulations as follows:

I. Discussion

1. The Commission is revising and updating Part 389 of its regulations related to the display of Office of Management and Budget (OMB) control numbers,1 by updating the existing table and revising the regulations to explain that an updated table displaying OMB control numbers is available on www.ferc.gov.

2. Part 389 aids in fulfilling the requirements of the Paperwork Reduction Act 2 to display current OMB control numbers for information collections. The Commission also displays OMB control numbers on its Web site at www.ferc.gov under “Documents and Filings” and then “Information Collections” or directly at http://www.ferc.gov/docs-filing/info-collections.asp. The Web site is updated regularly. For the most up-to-date information, interested persons are urged to consult the Commission's Web site.

3. OMB's regulations require that it approve certain information collection requirements imposed by agency rule.3 This Final Rule does not contain new or revised information collection requirements and thus does not require OMB approval.

4. The Commission is required to prepare an Environmental Assessment or Environmental Impact Statement for any action that may have a significant adverse effect on the quality of the human environment.4 Part 380 of the Commission's regulations provides exemptions to the requirement to prepare an Environmental Assessment or Environmental Impact Statement. Included is an exemption for procedural, ministerial or internal administrative actions and management.5 This Final Rule falls within that exemption; consequently, no environmental analysis is required.

5. The Regulatory Flexibility Act of 1980 (RFA) 6 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. This Final Rule, which revises and updates regulations on the display of OMB control numbers, will not have a significant economic impact on a substantial number of small entities. Thus, an analysis under the RFA is not required.

6. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page (http://www.ferc.gov) and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington DC 20426.

7. From the Commission's Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

8. User assistance is available for eLibrary and the Commission's Web site during normal business hours from FERC Online Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at [email protected], or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at [email protected].

9. These regulations are effective March 11, 2015. Pursuant to 5 U.S.C. 553(d), this is not a substantive rule and thus may become effective less than 30 days from publication.

10. The Commission is issuing this rule as a Final Rule without a period for public comment. Under 5 U.S.C. 553(b), notice and comment procedures are unnecessary where a rulemaking concerns only agency procedure and practice, or where the agency finds that notice and comment are unnecessary. The Commission finds that notice and comment are unnecessary because the affected regulations are administrative in nature and will not substantially affect the rights of non-agency parties. Moreover, no new burden or regulatory requirement is imposed on regulated entities or the general public.

In consideration of the foregoing, the Commission amends part 389, Chapter I, Title 18, Code of Federal Regulations, as follows:

The final regulations (TD 9709) that are the subject of this correction is under section 501(c)(29) of the Internal Revenue Code.

As published, the final regulations (TD 9709) contain errors that may prove to be misleading and are in need of clarification.

Accordingly, the final regulations (TD 9709), that are the subject of FR Doc. 2015-01677, are corrected as follows:

1. On page 4792, third column, the tenth line of the second full paragraph, the language “thereunder generally requires all” is corrected to read “thereunder generally require all”.

2. On page 4793, first column, under the paragraph heading “Drafting Information” the third line, the language “Office of Division Counsel/Associate” is corrected to read “Office of Associate”.

3. On page 4793, second column, the fourth line of the signature block, the language “Approved: January 22, 2015.” is corrected to read “Approved: January 23, 2015.”.

Background

The final regulations (TD 9708) that are the subject of this correction is under section 501(r)(3) of the Internal Revenue Code.

As published, the final regulations (TD 9708) contains errors that may prove to be misleading and are in need of clarification.

Accordingly, the final regulations (TD 9708), that are the subject of FR Doc. 2014-30525, are corrected as follows:

1. On page 78961, first column, the eleventh line of the first full paragraph, the language “only very serious failures, taking into” is corrected to read “only a very serious failure, taking into”.

2. On page 78975, third column, the last line of the column, the language “members of the hospital's community” is corrected to read “members of the hospital facility's community”.

3. On page 78979, third column, the eighth line from the bottom the first full paragraph, the language “co-payments, co-insurance, or” is corrected to read “co-payments, co-insurance, and”.

4. On page 78980, the third column, the seventh line from the top of the page, the language “form of co-payments, co-insurance, or” is corrected to read “co-payments, co-insurance, and”.

5. On page 78981, the second column, the twenty-third line from the top of the page, the language “payments, co-insurance, or deductibles),” is corrected to read “payments, co-insurance, and deductibles),”.

6. On page 78982, the first column, the thirteenth line from the top of the page, the language “obtain such percentages, a hospital” is corrected to read “obtain such percentage(s), a hospital”.

7. On page 78983, the first column, the thirteenth line from the top of the page, the language “required under section 501(r)(6)).” is corrected to read “required by the regulations under section 501(r)(6)).”.

8. On page 78983, the first column, the twelfth line from the bottom of the first full paragraph, the language “facility must refund any amounts the” is corrected to read “facility must refund any amount the”.

9. On page 78997, the first column, the heading “Adoption of Amendment to the Regulation” is corrected to read “Adoption of Amendments to the Regulation”.

Background

The final regulations (TD 9708) that are the subject of this correction is under section 501(r)(3) of the Internal Revenue Code.

As published, the final regulations (TD 9708) contains errors that may prove to be misleading and are in need of clarification.

Accordingly, 26 CFR parts 1 and 53 are corrected by making the following correcting amendments:

On November 29, 2011, PHMSA published a Notice of Proposed Rulemaking (NPRM) under the docket, PHMSA-2010-0026, (76 FR 73570), notifying the public of the proposed changes to 49 CFR parts 191, 192, and 195. We allowed an initial 90-day comment period, but based on requests from several pipeline trade associations, the comment period was extended from February 3, 2012, to March 6, 2012, (77 FR 5472). Most of the amendments proposed in the NPRM were intended to provide relief to industry by eliminating, revising, clarifying, or relaxing regulatory requirements.

On July 11 and 12, 2012, the Technical Pipeline Safety Standards Committee (commonly referred to as the Gas Pipeline Advisory Committee (GPAC)) and the Technical Hazardous Liquid Pipeline Safety Standards Committee (commonly referred to as the Liquid Pipeline Advisory Committee (LPAC)), met jointly at the Marriott Hotel at Metro Center in Washington, DC. The Pipeline Advisory Committees (PACs) are statutorily mandated advisory committees that advise PHMSA on proposed safety standards, risk assessments and safety policies for natural gas pipelines and hazardous liquid pipelines. The PACs were established under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1-16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among the Federal and state agencies, the regulated industry and the public. The PACs advise PHMSA on the technical feasibility, practicability and cost-effectiveness of each proposed pipeline safety standard. During the meeting, the PACs considered the NPRM and discussed the various comments and edits proposed by the pipeline industry and the public regarding changes to the regulations.

The PACs recommended PHMSA adopt the following proposals with minor or no changes to the regulatory text:

• Leak Surveys for Type B Gathering Lines;

• Qualifying Plastic Pipe Joiners;

• Regulating the Transportation of Ethanol by Pipeline;

• Transportation of Pipe;

• Threading Copper Pipe;

• Offshore Pipeline Condition Reports;

• Alternative Maximum Allowable Operating Pressure (MAOP) Notifications;

• National Pipeline Mapping System;

• Welders vs. Welding Operators;

• Components Fabricated by Welding; and

• Editorial Amendments.

The PACs recommended PHMSA adopt the following proposals with changes to the regulatory text:

• Responsibility to Conduct Construction Inspections;

• Mill Hydrostatic Tests for Pipe to Operate at Alternative MAOP;

• Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies; and

• Testing Components other than Pipe Installed in Low-Pressure Gas Pipelines.

The PACs recommended that PHMSA not adopt the proposed changes to:

• Limitation of Indirect Costs in State Grants; and

• Odorization of gas.

This Final Rule adopts the recommendations of the PACs. Additional discussion of the amendments and associated comments of the PACs are provided below:

1. Responsibility to Conduct Construction Inspections.

2. Leak Surveys for Type B Gathering Lines.

3. Qualifying Plastic Pipe Joiners.

4. Mill Hydrostatic Tests for Pipe to Operate at Alternative MAOP.

5. Regulating the Transportation of Ethanol by Pipeline.

6. Limitation of Indirect Costs in State Grants.

7. Transportation of Pipe.

8. Threading Copper Pipe.

9. Offshore Pipeline Condition Reports.

10. Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies.

11. Testing Components other than Pipe Installed in Low-Pressure Gas Pipelines.

12. Alternative MAOP Notifications.

13. National Pipeline Mapping System.

14. Welders vs. Welding Operators.

15. Components Fabricated by Welding.

16. Odorization of Gas.

17. Editorial Amendments.

PHMSA received a total of 42 comments on the NPRM, to include:

• 15 from pipeline trade associations.

• 17 from pipeline operators.

• 3 from pipeline manufacturers.

• 3 from states and municipalities.

• 1 from a Federal source (the National Transportation Safety Board (NTSB)).

• 3 from private organizations/citizens.

In this section, PHMSA discusses the changes proposed in the NPRM and the comments received in response to the NPRM. Based on an assessment of the proposed changes and the comments received, PHMSA identifies the proposals that are adopted in this Final Rule.

Proposal: PHMSA proposed to revise § 192.305 to specify that a transmission pipeline or main cannot be inspected by someone who participated in its construction. This proposal was based, in part, on a petition (Docket No. PHMSA-2010-0026) from the National Association of Pipeline Safety Representatives (NAPSR),1 that suggested that contractors who install a transmission line or main should be prohibited from inspecting their own work for compliance purposes. This petition was also based on the experiences of NAPSR members concerned with the poor quality of construction by unsupervised contractors.

PHMSA agreed with NAPSR but recognized that the same concerns should apply to non-contractor pipeline personnel and to hazardous liquid lines. Accordingly, PHMSA proposed to revise §§ 192.305 and 195.204 to specify that a transmission pipeline main, or pipeline system, cannot be inspected by someone who participated in its construction.

Comments: This topic was the most controversial of all the proposed items. Comments included the following concerns and recommendations:

• The proposed rule will result in significant cost impact to operators;

• The proposal is overly burdensome economically and has the potential to compromise site safety due to additional personnel, congestion, inattention, carelessness and unnecessary overhead expenses;

• The proposed amendment is clearly a significant regulatory action and is inappropriately included in a non-significant rulemaking and should be considered in a separate rulemaking;

• The proposed language does not differentiate between an operator's employee and a contractor's employee;

• PHMSA should clarify the meaning of “person participating in the construction” of a pipeline;

• Inspection and new construction should be an Operator Qualification (OQ) task;

• Prohibiting any “person” involved in the construction of a pipeline could be interpreted to prohibit any other municipal employee from performing inspection; and

• PHMSA should re-define “a person who participated” in the construction of the pipeline.

NAPSR commented that their resolution was intended to preclude operators from allowing contractor personnel to self-inspect their own work and was based on its members' experience with poor quality of construction by unsupervised contractors.

Members of the Association of Oil Pipelines (AOPL) said they do not agree with the statement that “the proposed rule does not impose any compliance, recordkeeping or other reporting requirement.” AOPL said the proposed change to § 192.305 will result in significant cost to the operators. In addition, AOPL asserted that the proposal is overly burdensome economically and has the potential to compromise site safety due to additional personnel, congestion, inattention, carelessness and unnecessary overhead expense.

The American Gas Association (AGA) noted that PHMSA has failed to provide an analysis to support the significant expansion of the construction inspection revision to all entities and personnel encompassed in the § 192.3 definition of “person.” Another commenter noted that PHMSA did not provide a basis for its conclusion on construction inspection and PHMSA's proposed rule does not address the same concerns as NAPSR. The Interstate Natural Gas Association of America (INGAA) noted that instead of adopting the proposed amendment, which increases regulatory confusion and adds to the issues already surrounding construction, PHMSA should convene a public hearing or workshop to develop the fundamental regulatory changes needed to align PHMSA's policy objectives with common pipeline configurations.

Response: Consistent with the petition from NAPSR, PHMSA proposed to revise §§ 192.305 and 195.204 to prohibit individuals involved in the construction of a transmission line, main or pipeline system from inspecting his or her own work. These inspections are important because transmission pipelines and mains are generally buried after construction. Subsequent examinations often involve a difficult excavation process. PHMSA believes that allowing individuals to inspect their own work defeats, in part, the measure of safety garnered from such inspections. PHMSA was not intending to require third party inspections or attempting to prohibit any person from a company to inspect the work of another person from the same company.

The PACs did not agree with the proposed language. There was considerable discussion on the use of alternative language proposed by INGAA and the original language from the NAPSR petition.

Following the discussion, the PACs agreed on the revised language for gas and hazardous liquid pipelines. After reviewing the PACs' recommendations and evaluating public comments, PHMSA has adopted language that more clearly identifies the types of individuals who should be excluded from the required inspections, (i.e., the individual who performed the construction task that requires inspection).

In regard to the comments that dealt with costs and the significance of the rule, PHMSA believes that the commenters overstated the impact of the proposal.

Proposal: In the NPRM, PHMSA proposed that operators of Type B gathering lines must perform leak surveys in accordance with § 192.706 and fix any leaks discovered.

Operators of Type B gathering lines currently must ensure that any new or substantially changed Type B line complies with the design, installation, construction, and initial testing and inspection requirements for transmission lines and, if of metallic construction, comply with the corrosion control requirements for transmission lines. Operators must also include Type B gathering lines in their damage prevention and public education programs, establish the MAOP of those lines under § 192.619, and comply with the requirements for maintaining and installing line markers that apply to transmission lines.

Comments: The Texas Pipeline Association (TPA) suggested that if PHMSA decided to move forward with the proposal to survey Type B lines, then several topics would need to be addressed to assure the reasonableness of the proposed regulation. TPA suggested that:

• PHMSA share any supporting information provided by NAPSR to show that leaks are the primary hazard for Type B gathering pipelines;

• Section 21 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 requires the Secretary of Transportation to review the existing Federal and state regulations for gathering pipelines to determine their sufficiency to ensure the safety of such lines. As such, PHMSA should not move forward with additional regulatory requirements for Type B gathering lines since Congress has mandated a review of the sufficiency of existing regulations;

• The docket contains no supporting evidence to show that the proposed amendment is based on facts and not speculation;

• Excavation damage may pose a greater risk than leaks in Type B gathering lines;

• PHMSA should develop estimates of the cost of compliance for affected operators;

• The economic impact may exceed the threshold for a non-significant regulatory action; and

• If PHMSA implements the change, it must provide at least one year adequate time for affected operators to purchase leak detection equipment, establish leak survey routes, develop recordkeeping systems for these surveys and hire additional personnel following adoption of the new leak survey equipment.

The Iowa Utilities Board (IUB) commented that the proposed amendment appears responsive to NAPSR Resolution 2006-3, which called for the reinstatement of leak surveys that were not included when requirements for Type B gathering lines were adopted in Amendment 192-102. The IUB further noted that the proposed amendment includes a second part that was not in the NAPSR resolution. The language of the second part reads: “and fix hazardous leaks that are discovered in accordance with § 192.703(c).” “Fix” is hardly usual regulatory language and has no specified definition or usage history in Part 192. The IUB and MichCon DTE Energy suggested that PHMSA use alternate language that removes a nonstandard term and an unnecessarily complicated rule reference by simply saying “and promptly repair hazardous leaks that are discovered.”

The Northeast Gas Association suggested that PHMSA revise its proposal to require operators of Type B regulated gathering lines to apply leak survey methods in accordance with § 192.723 which provides the leak survey requirements for low-stress pipelines with a MAOP of less than 20 percent specified minimum yield strength (SMYS).

Response: As for the comment that PHMSA should wait until its congressionally mandated review of existing regulations for gas and hazardous liquid gathering lines is complete, the study required by Section 21 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act requires PHMSA to study and report to Congress on:

(A) The sufficiency of existing Federal and state laws and regulations to ensure the safety of gas and hazardous liquid gathering lines;

(B) The economic impacts, technical practicability and challenges of applying existing Federal regulations to gathering lines that are not currently subject to Federal regulation when compared to the public safety benefits; and

(C) Subject to a risk-based assessment, the need to modify or revoke existing exemptions from Federal regulation for gas and hazardous liquid gathering lines.

The need to include leakage surveys as a compliance activity was identified between the publications of the Supplemental Notice of Proposed Rule Making (SNPRM) titled: “Pipeline Safety: Gas Gathering Line Definition: Alternative Definition for Onshore Lines and Proposed Safety Standards,” published October 3, 2005; 70 FR 57536 [Docket No. RSPA-1998-4868; Notice 5], and the Final Rule of the same title published March 15, 2006; 71 FR 13289 [Docket No. PHMSA-1998-4868]. The inclusion of leakage surveys as a compliance action was not included in the Final Rule because it was beyond the scope of the SNPRM and the agency did not want to further delay the rulemaking. During its annual meeting in September 2006, NAPSR also passed a resolution [NAPSR Resolution 2006-3] requesting the regulatory change to Type B lines.

As for the comment that Type B leaks due to excavation damage may pose a greater risk, the annual Type B report data for calendar year 2011 indicated that there were 289 leaks eliminated or repaired by operators of onshore Type B gathering lines, with the leading cause of leaks being external. Excavation damage is and has been recognized as a high risk for Type B gathering lines. This point was elaborated on in the Gas Gathering Line Definition in the SNPRM (October 3, 2005; 70 FR 57536) and Final Rule (March 15, 2006; 71 FR 13289), and served as the basis for the compliance activities for Type B lines (damage prevention programs, placement of line markers, and public awareness programs). This amendment will add one more recognized risk control activity required on Type B gathering lines.

Regarding the comment that PHMSA should estimate the costs of compliance, PHMSA performed a cost analysis by averaging the daily rate of two leak survey service providers. The average cost of surveying two miles of pipeline per day equaled $600. The estimated that approximately 3,650 miles of Type B gathering lines will be required to be inspected annually at an average cost of $300 per mile for an upper bound annual cost of approximately $1.1 million.

However, leak surveys, while not currently required for Type B gathering lines, are a widespread industry practice because they serve a business purpose in helping to detect leaks, thereby reducing lost gas and liability exposure. Although operators do not submit data on the extent of these surveys, PHMSA believes that approximately half of all Type B gathering line mileage that would otherwise be affected by this proposal is already being inspected. This is based on the fact that this is a widespread industry practice and until 2006, this was an existing regulatory requirement. Therefore, a more realistic estimate of the actual incremental cost is approximately 50% of the upper bound of $1.1 million, or $0.55 million per year.

The Northeast Gas Association, in a comment on PHMSA's published NPRM, noted there were operational similarities between Type B gathering lines and gas distribution lines that operate at similar, lower pressures, and requested PHMSA apply leak survey standards to Type B gathering lines that were more in line with leak survey standards for distribution lines, rather than leak survey standards for transmission lines.

Title 49 CFR 192.706 requires transmission line leak surveys at intervals not exceeding 15 months, but at least once each calendar year, and more frequently in densely populated areas. NAPSR believes that Type B gathering lines should be subject to the same requirements, as Type B gathering lines can carry gas that is corrosive, and gas leaks are a significant hazard on those low-stress pipelines. Therefore, requiring leak surveys on Type B gathering lines is an appropriate and necessary risk-management measure.

NAPSR also noted in their comments that some Type B gathering lines are located under broad paved areas, where electrical surveys that detect pipe damage may be difficult to perform, and leaking gas can migrate under the pavement and accumulate in surrounding structures. NAPSR recommends that leak detection surveys should be required to ensure the safety of these lines.

As it stands, distribution lines in business districts must be surveyed each calendar year, with the remainder of distribution lines subject to leak survey at frequencies driven by local conditions but at an interval that does not exceed 5 years. Distribution lines, per the regulations, are required to be odorized which provides members of the public with a warning system for the period between surveys. The gas in gathering lines is un-odorized, so the public does not have any advance warning of line leaks outside of those leak surveys. Leak surveys would serve as the warning bell.

Regarding the concerns raised by commenters about the cost of this proposal, under the current regulations, Type B gathering lines are treated the same as transmission lines for design, installation, construction, and initial testing and inspection. If the line in question is composed of metal, the line must also comply with the same corrosion control requirements as transmission lines. Similar to transmission lines, Type B gathering lines must be included in damage prevention and public education programs, have established MAOPs under § 192.619, and comply with the requirements for installing and maintaining line markers.

Because Type B gathering lines are regulated with many of the same requirements as transmission lines, it would follow that Type B gathering lines and transmission lines have a similar risk profile. Therefore, because transmission lines are subject to annual leak surveys, Type B gathering lines should be subject to the same requirement for safety reasons.

While leak surveys are not currently required for Type B gathering lines, they are a widespread industry practice that help operators detect leaks early and avoid loss of lives, gas and liability exposure. When this voluntary practice becomes a regulation it will provide a standard and consistent level of safety to the American public and ensure the integrity of these lines.

Taking this into consideration, as well as the GPAC's recommendation and the evaluation of public comments, PHMSA has adopted § 192.9(d)(7) as proposed with the minor modification of substituting the word “fix” with “repair.”

Proposal: Section 192.285 contains requirements for qualifying persons to make joints in plastic pipe. Under § 192.285(c), “[a] person must be re-qualified under an applicable procedure, if during any 12-month period that person: (1) Does not make any joints under that procedure; or (2) has three joints or three percent of the joints made, whichever is greater under that procedure that are found unacceptable by testing under § 192.513.” In its petition to amend the regulations (2008-03-AC-1), NAPSR noted that the current rule, with its 12-month time period, requires detailed records of each individual joiner's activities and sets the stage for requalification date “creep,” where a joiner must requalify at an earlier date every year. NAPSR commented that the existing regulatory language sets a very low standard for joiner requalification and noted that the large number of operators requesting similar waivers demonstrates that a requalification system like the one proposed in its resolution is acceptable and preferred by pipeline operators.

In the NPRM, based on the NAPSR petition, PHMSA proposed to revise § 192.285 to provide greater scheduling flexibility and require requalification of a joiner if any production joint is found unacceptable.

Comments: Center Point Energy (CPE) noted that it is overly excessive to disqualify and retrain a joiner if one joint is found unacceptable during a 12-month period CPE suggested that PHMSA leave § 192.285(c)(2) as written and that quality assurance/quality checks of potentially unacceptable joints be accomplished through § 192.513 testing. CPE also queried whether PHMSA has data from a study to show that an individual who makes one unacceptable joint will make more. City Utilities of Springfield, Missouri, suggested that we amend the language to clarify that requalification is necessary only if the joint failure is due to operator error.

Nicor Gas (Nicor), while supporting the proposal to add a three-month grace period in the requalification interval, does not support the proposed revision that would require requalification of the joiner if one joint is found unacceptable by the required pressure testing. Nicor commented that the proposal is unnecessarily restrictive and not validated or supported by documentation from NAPSR. Nicor noted that there are field conditions and/or circumstances beyond the joiner's control (rain, snow, blowing dirt, trench cave-ins, equipment malfunctions and material flaws) that would affect the joining process without reflecting a lack of skill or proper training. All these incidents may lead to an unacceptable joint.

TPA also disagrees with the proposal to impose a zero-failure tolerance standard for plastic pipe joiners and commented that perfection in the performance of any task in any industry 100 percent of the time is rarely, if ever, achieved. TPA commented on the contrast of the regulations in plastic joining versus welding of steel pipelines and noted that the existing regulations for welders do not impose a zero-tolerance standard, even though most steel pipelines operate at higher pressures than plastic pipelines, and would pose a higher safety risk to the public. The zero tolerance proposal for plastic pipe joiners also fails to consider that all plastic pipe is required to be pressure tested before going into service and that this testing provides an additional layer of safety assurance that plastic pipe joints are safe before pipeline operation begins.

AGA suggested that PHMSA analyze data on fusion failures, present the information to the public and then determine how best to address the issue. AGA further commented that the amendment to prohibit the entire crew from further fusion after one joint failure until requalification occurs seems unnecessarily severe, is unsupported by statistical evidence and has the potential to create unexpected adverse consequences.

Response: PHMSA reviewed the comments received on the topic including those that raised concerns of, and requested clarification on, the changes surrounding requalification if one joint is found unacceptable. PHMSA understands some of the concerns may have been related to the language used in the preamble and additional clarification may be needed regarding PHMSA's intent. PHMSA does not believe the proposed requirements are as onerous as some of the commenters indicated, nor would there necessarily be a zero tolerance policy in effect as a result of the proposed changes. PHMSA agrees there could be a number of factors including some beyond the joiners control such as weather, equipment malfunctions and material flaws, which could result in an unacceptable joint. However, PHMSA expects some evaluation would be done following any unacceptable joint, and in some cases evaluation may be necessary on a case-by-case basis. If an unacceptable joint is a result of a factor(s) clearly beyond the joiner's control, PHMSA does not expect those conditions to affect the requalification of the joiner. Likewise, if an individual fusing a joint realizes that it is a bad joint, cuts it out, and fuses another (acceptable) joint immediately following, PHMSA does not expect that the joiner would have to requalify. On the other hand, if an unacceptable joint is related to issues that are within the joiner's control, that joiner would need to be re-qualified. While PHMSA has presented some general expectations, ultimate determination of the adequacy of an acceptable joint, whether or not the joiner would need to be requalify, and what may constitute an adequate qualifying joining test would be up to which ever entity inspects the joint. In most cases, particularly for intrastate systems, it would be up to the individual state.

In response to the comments regarding the burden of this provision, PHMSA notes that the changes may help reduce some of the current burden associated with the paperwork, tracking and record-keeping requirements that were associated with “three joints or three percent of the joints made, whichever is greater” in the current regulatory language. Regarding the comments inquiring about data or other studies surrounding joints, PHMSA is not aware of any studies showing that an individual who makes one unacceptable joint will make more. On the other hand, PHMSA is not aware of any data or studies that can guarantee that an individual who makes one unacceptable joint won't make another unacceptable joint. The potential safety issues surrounding an unacceptable joint those are not addressed through proper evaluation and requalification seem to outweigh any benefit with continuing the qualification requirements as they currently exist in the regulations. Many of these and other aspects were discussed with the GPAC, the transcripts of which are available in the docket.

Following some discussion, the GPAC unanimously supported PHMSA's proposal that was based on the NAPSR petition. The PACs, industry and the public indicated that the original language in the regulations required numerous letters of interpretation and caused problems in the application of the regulations. The proposed language is also in keeping with some state waivers granted by PHMSA. Accordingly, the Final Rule revises § 192.285 to provide greater scheduling flexibility and require requalification of a joiner if any production joint is found unacceptable.

Proposal: Section 192.112 applies to pipe that will operate at the higher stresses allowed under the alternative MAOP permitted under § 192.620 and specifies additional design requirements. In the NPRM, PHMSA proposed to revise § 192.112(e) by eliminating the allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment for the mill test. Eliminating the allowance to combine equipment loading stresses will have the effect of increasing the internal test pressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. This design requirement, combined with pipe mill dimensional checks for expansion, will help assure that all new pipes to be operated at an alternative MAOP receive an adequate mill test and have adequate strength.

Comments: Evraz, a steel and pipe manufacturer, noted that eliminating the allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment could put mills that use testing processes that apply high end loadings at a competitive disadvantage to mills that do not. The amount of end loading applied depends on the testing process and equipment used. Mills that apply higher end loadings will produce combined stresses in excess of 100 percent SMYS if required to achieve 95 percent of SMYS based on gauge pressure alone. Evraz noted that the more effective way of addressing the potential of low strength line pipe would be to fully institute the changes in the 3rd addendum of the 44th edition of the American Petroleum Institute's (API), API Specification 5L, “Specification for Line Pipe,” (API Spec 5L). TransCanada Corporation suggested that PHMSA consult with pipe manufacturers regarding the potential impacts of consideration of end loading in the calculations of mill hydrostatic tests before adopting changes to the procedure. TransCanada maintained that the increased safety factor was already added in the 2008 Final Rule titled: “Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines” (73 FR 62148).

Response: Pipe mill hydrostatic testing is a factory proof test used to ensure that new pipe has no structural or manufacturing flaws and adequate strength. Section 192.112 applies to pipe that will operate at the higher stresses allowed under the alternative MAOP rule. The mill test pressure of a minimum of 95 percent SMYS is being required to ensure that lower strength pipe is not used for alternative MAOP pipelines. The alternative MAOP rule allows pipelines to operate at stresses of up to 80 percent of SMYS, where other pipelines can only operate up to 72 percent SMYS. Pipelines that do not operate in accordance with the alternative MAOP must be mill tested as defined in the appropriate pipe manufacturing standard and the current edition of API Spec 5L incorporated by reference in § 192.7 (b)(7). The 45th edition of API Spec 5L was incorporated by reference on January 5, 2015 (80 FR 168). API Spec 5L offers a lower requirement than that of a mill test of 95 percent SMYS in § 192.112(e)(1) for non-alternative MAOP pipelines.

During the 2008 through 2010 construction seasons, PHMSA identified a number of cases where new pipe did not meet regulatory specified strength requirements. Pipe that is 15 percent below the mandated SMYS was found on several new pipeline construction projects. On May 21, 2009, PHMSA issued an advisory bulletin (ADB-09-01) Docket No. PHMSA-2009-0148—“Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe”), alerting pipeline operators of issues found with low strength pipe. Eliminating the mill test allowance to combine equipment loading stresses will have the effect of increasing the internal test pressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. When combined with pipe mill dimensional checks for expansion, that change will help assure that all new pipes for this service receive an adequate mill test and have adequate strength. This mill hydrostatic test criteria change will help to eliminate low strength pipe in alternative MAOP pipelines.

During 2009 to 2010, INGAA conducted two studies/white papers titled, “Guidelines for Evaluation and Mitigation of Expanded Pipes” dated June 9, 2010, and “Identification of Pipe with Low and Variable Mechanical Properties in High Strength, Low Alloy Steels” dated September, 2009 (Docket No. PHMSA-2010-0026). The INGAA studies confirm that if the mill hydrostatic pressure test produced a stress of 95 percent or more of SMYS, and diameter dimensions were taken at intervals along the length of each joint in addition to the required end dimension measurements, expansion of the pipe beyond the set tolerances in the pipe specification did not occur. If unacceptable expansion has occurred, those pipe joints can be identified and eliminated.

Since steel and pipe production are worldwide manufacturing processes, it is very difficult to determine that a standard quality assurance process has been fully implemented. Mill hydrostatic tests are the final quality assurance process in the pipe manufacturing chain. They are conducted by the pipe manufacturer and have the full quality assurance review of the pipe manufacturer and pipe purchaser/pipeline operator. This new requirement is based upon an INGAA sponsored industry review of pipe making practices. If pipe is not tested to a higher pressure in the mill then the low strength pipe will create operational concerns in the field. The adoption of this amendment should expose low strength pipe in operation. Thus, PHMSA has adopted § 192.112(e) as proposed.

Proposal: In the NPRM, PHMSA proposed to modify its definition of “hazardous liquid” to include ethanol. This action was based in part on a policy statement published in the Federal Register on August 10, 2007; 72 FR 45002 (Docket Number: PHMSA-2007-28136) on the transportation of ethanol, ethanol blends, and other biofuels by pipeline. PHMSA noted in the policy statement that the demand for biofuels was projected to increase as a result of several Federal energy policy initiatives, which would result in greater use of pipelines for transporting biofuels. PHMSA also stated that ethanol and other biofuels are substances that “may pose an unreasonable risk to life or property” within the meaning of 49 U.S.C. 60101(a)(4)(B), and accordingly, these materials constitute “hazardous liquids for purposes of the pipeline safety laws and regulations.” PHMSA went on to say that the agency was considering a possible modification to § 195.2 to include ethanol and biofuels in the definition of hazardous liquid. PHMSA invited comments on that proposal and on other issues related to the transportation of biofuels by pipeline.

Comments: Thomas Lael Services, L.P., suggested that the term “ethanol” and “bio-diesel petroleum” should be added to the definition of “hazardous liquid.” AOPL added that rather than having another Federal agency or a number of state agencies attempt to regulate the safety of pipeline transportation of ethanol, that denatured ethanol be defined as a “hazardous liquid” under § 195.2, so that ethanol transported via pipeline is regulated consistently with other energy liquids by PHMSA under 49 CFR part 195.

Response: After evaluating the comments on the proposal, PHMSA has adopted the amendment to add the term “ethanol” to the definition of “hazardous liquids” in § 195.2. In this Final Rule PHMSA will not adopt the commenter's suggestion that we add “bio-diesel petroleum” to the definition because this request is outside of the scope of this rulemaking. However, PHMSA may address this issue in a future rulemaking.

Proposal: PHMSA reimburses the states for a portion of the costs accrued in administering their pipeline safety programs and Congress appropriates the funds used to make these reimbursements on a regular basis. The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act) removed a provision that imposed a 20 percent cap on indirect expenses allocated to the pipeline safety program grants. In the NPRM, PHMSA proposed to incorporate the 20 percent limitation on indirect expenses into the regulations governing grants to state pipeline safety programs.

Comments: PHMSA received several comments opposed to this proposal. IUB and NAPSR objected to the proposal to limit the indirect cost rate that can be recovered through a state's pipeline safety grant to 20 percent. They both stated that the limit is arbitrary and capricious and may prevent the recovery of legitimate costs of state participation in the Federal/state pipeline safety program. IUB said the 20 percent limit is not mandated by law or by any referenced Federal grant guide material or requirement. IUB also noted that there was no clear rationale as to why PHMSA should impose a requirement by rule that Congress found unnecessary and removed from law when the PIPES Act was passed in 2006. IUB and NAPSR noted that different states have different methods of allocating costs within their budget and no basis was presented for punishing states that distribute a larger portion of their costs as indirect costs. NAPSR is concerned that states could artificially inflate indirect costs to receive a larger grant payment.

PACs' members pointed out that the way in which states do their budgeting and accounting varies and some states do have indirect costs that exceed the 20 percent limit. However, because of the 20 percent required cost share, states do not present their costs that are above that threshold. Some state representatives noted that their indirect cost submissions are required to be approved first at the Federal level and are highly scrutinized to ensure no padding is done. In addition to that, to ensure compliance, PHMSA performs frequent audits of the state programs.

Response: PHMSA has decided not to adopt the proposal into regulation. However, PHMSA will maintain the 20 percent indirect cost cap through language in our payment agreements with states. As part of its state program, PHMSA has payment agreements with each state. These agreements are binding and cap indirect costs at 20 percent.

Proposal: Section 192.65 states that if pipe is to be transported by railroad, it will be operated at a hoop stress of 20 percent or more of SMYS, and has a diameter-to-wall-thickness ratio of 70 to one or more; the pipe must be transported in accordance with API RP 5L1. An exception is provided for certain pipe transported before November 12, 1970. That exception allows operators to use pipe stockpiled prior to the effective date of the original pipeline safety regulations, the transportation of which cannot be verified under API standards.

Based on an NTSB investigation and recommendation resulting from an Enbridge pipeline incident that took place on July 4, 2002, near Cohasset, Minnesota, PHMSA proposed to revise the regulation to require that the rail transportation of all pipe be subject to the referenced API standards.

Comments: We received several comments, including one from the NTSB in support of the proposal. The Committee on Pipe and Tube Imports (CPTI) Ad Hoc Large Diameter Line Pipe Producers Group agreed that the proposal would not have an adverse impact on operations or the ability to manufacture products. El Paso Pipeline Group (EPPG) commented that if PHMSA promulgates this amendment, it should specify that the use restriction does not apply to any pipe already installed, or to any pipe transported after § 192.65 initially took effect. EPPG commented that the proposed wording may result in misinterpretation and unintended consequences, such as assuming that “use” applies to pipe currently installed rather than to pipe in stock, and that shipping records must be provided for all pipe exceeding the specified diameter-to-wall thickness ratio. EPPG proposed this rewording of the regulatory language:

NAPSR agrees that any remaining stock of such pipe is likely to be minimal.

Response: Surveys conducted by INGAA failed to find any vintage pipe covered by § 192.65(a)(2). Therefore, PHMSA has no reason to continue the exemption and is removing this exemption from the regulation and adopting the amendment with one minor change. PHMSA is replacing the phrase “operator may not use pipe” with the phrase “operator may not install pipe” to clearly indicate that this amendment does not apply to pipe already installed.

Proposal: Section 192.279 specifies when copper pipe may be threaded and refers to Table C1 of American Society of Mechanical Engineers (ASME) Standard ASME/ANSI B16.5. In a letter dated June 11, 2009, the Gas Piping Technology Committee (GPTC) advised PHMSA that Table C1 was deleted in the most recent version of the ASME/ANSI B16.5, which is incorporated into Part 192 by reference. The GPTC stated that the information in Table C1 was taken from a different standard and that ASME/ANSI B36.10M, “Standard for Welded and Seamless Wrought Steel Pipe,” should be substituted as a more appropriate reference. PHMSA proposed to use “threaded copper pipe if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe as listed in Table 1 of ASME B36.10M, Standard for Welded and Seamless Wrought Steel Pipe.”

Comments: We received no public or PAC comments on this proposal.

Response: PHMSA is unable to incorporate ASME/ANSI B36.10M, “Standard for Welded and Seamless Wrought Steel Pipe” due to the standards availability requirement described in Section 24 of the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” (Pub. L. 112-90, January 3, 2012). Section 24 added a new public availability requirement for documents incorporated by reference after January 3, 2013. The law stated that beginning 1 year after the date of enactment of this subsection, the Secretary may not issue guidance or a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge, on an Internet Web site.

This section was further amended on August 9, 2013. The current law continues to prohibit the Secretary from issuing a regulation that incorporates by reference any document unless that document is available to the public, free of charge, but removes the Internet Web site requirements (Pub. L. 113-30, August 9, 2013). PHMSA will address this proposal in a future rulemaking action.

Proposal: In the NPRM, PHMSA proposed to remove §§ 191.27 and 195.57. Sections 191.27 and 195.57 require operators to submit a report to PHMSA within 60 days of completing the underwater inspections of pipelines in the Gulf of Mexico required by §§ 192.612(a), and 195.413(a).

Sections 192.612(a) and 195.413(a) no longer require operators to perform an underwater inspection of all pipelines in the Gulf and its inlets. (See also Pub. L. 102-508 (Oct. 24, 1992) (modifying the statutory mandate for underwater inspection, reporting and reburial of pipelines in the Gulf and its inlets). Rather, those regulations call for periodic, risk-based inspections of shallow-water pipelines. The filing of a written report within 60 days of completing all of those inspections is not consistent with such an action. Additionally, sections 192.612(c) and 195.413(c) require operators to file their electronic/telephonic reports with the National Response Center within 24 hours of discovering that a pipeline in those areas is exposed or a hazard to navigation, which is sufficient to meet PHMSA's current information collection needs.

Comments: PHMSA received no public comments on this proposal.

Response: PHMSA has adopted the proposal to repeal §§ 191.27 and 195.57.

Proposal: Section 195.452(h)(4)(i) specifies the actions that an operator of a hazardous liquid pipeline must take after discovering an immediate repair condition. One of those actions is a temporary reduction in operating pressure as determined under the formula provided in section 451.6.2.2 (b) of ASME/ANSI B31.4, “Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids.” The particular focus of that pressure reduction formula is corrosion. However, corrosion is only one of the threats that could cause an immediate repair condition under § 195.452(h)(4)(i).

In a July 17, 2007, Final Rule (72 FR 39017), PHMSA sought to modify § 195.452(h)(4)(i) to provide for alternative methods of calculating a pressure reduction for immediate repair conditions caused by threats other than corrosion. The Office of the Federal Register was unable to incorporate that change due to inaccurate amendatory instructions. In the NPRM, PHMSA again proposed to revise § 195.452(h)(4)(i) to make the same change as published in the July 17, 2007, Final Rule, with corrected amendatory instructions.

Comments: In response to our proposal, the TransCanada Corporation commented that it acknowledges the limitations of the current language in § 195.452(h)(4)(i) and believes a revision to the language in this section is appropriate. However, since § 195.452(h)(4)(i)(B) provides for the calculation of the remaining strength using methods that include, “but are not limited to,” ASME/ANSI B31G, “Manual for Determining the Remaining Strength of Corroded Pipelines,” (ASME/ANSI B31G) or AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,” (PR-3-805 (RSTRING)), they do not believe a reference to the design requirements of § 195.106 is necessary. TransCanada commented that the ability to use alternative methods for calculating a pressure reduction would be incorporated with only a reference to § 195.452(h)(4)(i)(B). They suggested the following language in lieu of what PHMSA has proposed:

The AOPL commented that the proposed language requiring the calculation of pressure reductions for detected anomalies should be modified to appropriately reference suitable calculation methods.

API noted that § 195.452(h)(4)(i)(B) already allows the use of PR-3-805 (RSTRENG), modified PR-3-805 (RSTRENG), or a suitable alternative remaining strength calculation method to be used, and therefore already fully covers the calculation of a temporary reduction in operating pressure. The API suggests that the following sentence in the proposed section is redundant: “If the formula is not applicable to the type of anomaly or would produce a higher operating pressure, an operator must use an alternative acceptable method to calculate a reduced operating pressure.”

The LPAC suggested the following language:

Response: PHMSA believes both commenters were trying to make similar changes. In the Final Rule, PHMSA is adopting LPAC's suggested language as it best clarifies that an operator must calculate remaining strength or reduce operating pressure until a repair can be completed.

Proposal: In the NPRM, PHMSA proposed to amend §§ 192.503 and 192.505 to exempt certain components from the strength test requirement in Subpart J of Part 192. This proposal was based on a petition from the GPTC in a letter dated March 25, 2010. The GPTC argued that the primary purpose of a post-installation strength test is to prove the integrity of the entire pipeline system. The GPTC further noted that the most important parts to check of a single-component replacement are the joints that connect the component to the pipeline, and that these joints are currently exempted from testing for all gas pipelines by paragraph (d) of § 192.503.

Comments: PHMSA received many comments in support of this proposal. We also received some comments asking that we expand the list and sources of standards that can be used to establish pressure ratings. One commenter asked that we review all referenced standards and provide exemptions for all standards that establish pressure ratings.

Response: PHMSA is adopting the amendment as proposed. The request to expand the list and sources of standards that can be used to establish pressure ratings is out of the scope of this rulemaking, as is the request to review all referenced standards. Therefore, those requests have not been adopted but may be considered in future rulemaking actions.

Proposal: Section 192.620(c)(1) currently requires a pipeline operator to notify each PHMSA pipeline safety regional office where the pipeline is in service of its election to use an alternative MAOP pressure with respect to a segment at least 180 days before operating at the alternative pressure. An operator must also notify a state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state.

PHMSA proposed to require that for new pipelines, an operator would notify the PHMSA pipeline safety regional office of planned alternative MAOP design and operations 180 days prior to start of pipe manufacturing or construction activities. An operator would also notify state pipeline safety authorities when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state.

PHMSA also proposed to revise § 192.620(c)(8) to correct a typographical error related to the reference to § 192.611(a).

The proposal to require 180 day notice for new pipelines was to allow sufficient time for PHMSA to conduct any needed material manufacturing and construction inspections, including checks of new pipe rolling and coating processes, visit the new pipeline field sites during construction, analyze operating history of existing pipelines, and review test records, plans, and procedures.

Comments: INGAA suggested that the proposal should apply only prospectively, that the regulation should include an alternative notice period measured from the placement of the pipe purchasing order to the start of pipe manufacturing and that the language needs clarification with regard to new pipe. In its comments to the NPRM, INGAA noted that for new pipeline projects the application and permitting process can extend over months or years before approval to construct is granted. Once this approval is obtained, pipe orders are placed and production dates are established. The interval from the time the pipe is ordered until the start of production is sometimes less than 180 days making it impractical to provide the required notice as the proposed rule is currently worded. To address this INGAA recommends that the wording be changed to 180 days or 10 business days before the operator places a purchasing order for the pipe or the pipe starts being manufactured.

Panhandle Energy (Panhandle) recommended that the wording addressing new pipelines be changed to: “For new pipelines, notify the PHMSA pipeline safety regional office 180 days prior to the start of pipe manufacturing and/or construction activities, if practicable, but no more than 10 business days after the operator places an order for the pipe or executes the pipeline construction contract.”

TPA commented that if the operator wishes to utilize the existing pipe stock that satisfies the MAOP regulation requirement, the 180 day notice to the manufacturer would be impossible, and that the language should be revised to remove “and/or” to provide clear, unambiguous standards.

Response: PHMSA evaluated the comments and believes the proposed 180 days notification is too restrictive. Notification to PHMSA of new alternative MAOP pipeline project activities at least 60 days prior to start of pipe manufacturing or construction activities should not delay operator project activities. PHMSA needs this time to schedule personnel for safety inspections at both the pipe and coating mills and at the construction site prior to the start of pipe construction activities. PHMSA will require a 60 day notice by the operator prior to the start of pipe manufacturing or construction activities of new alternative MAOP pipelines.

Proposal: The National Pipeline Mapping System (NPMS) is a geospatial dataset that contains information about PHMSA-regulated gas transmission pipelines, hazardous liquid pipelines, and hazardous liquid low-stress gathering lines. The NPMS also contains data layers for all liquefied natural gas plants and a partial dataset of PHMSA-regulated breakout tanks.

In the NPRM, PHMSA proposed to codify the statutory requirement for the submission of the NPMS data into Parts 191 and 195. An NPMS submission consists of geospatial data, attribute data and metadata, public contact information, and a transmittal letter.

PHMSA also proposed to require operators to follow the submission guidelines and dates set forth in the July 31, 2008, advisory bulletin (73 FR 44800: Pipeline Safety; National Pipeline Mapping System). Gas transmission operators and liquefied natural gas (LNG) plant operators would make their NPMS submissions on or before March 15, representing their assets as of December 31 of the previous year. Hazardous liquid operators would make their NPMS submissions on or before June 15, representing their assets as of December 31 of the previous year.

Comments: Oleska commented that, though they agree that the requirements should be added to Part 191, requiring operators to report to both NPMS and PHMSA is unduly burdensome and is not necessary. The TPA asked that PHMSA revise the language to clarify that this proposal only covers hazardous liquid trunklines and regulated rural hazardous liquid gathering pipelines as defined in the NPMS Operator Standards. TPA and Oleska noted that the operator ID for each operator is the same as it is for PHMSA, and that PHMSA should have the ability to get whatever information it needs directly from the NPMS without operators having to submit two sets of data. TPA and Oleska suggested that it would be better for PHMSA to get its data from the NPMS, because two sets of data increase the chance of discrepancies, especially if changes are made between annual submissions.

Response: In response to TPA's and Oleksa's concern about submitting the data twice, operators will continue to make only one NPMS submission following the guidelines in the NPMS Operator Standards Manual on the NPMS Web site (www.npms.phmsa.dot.gov). This Final Rule imposes no additional submission requirements. In response to the concern about the NPMS's and PHMSA's capability to process all the gas, LNG plant operator and liquid operator submissions received on or before March 15 and June 15, respectively, PHMSA encourages operators to make their submissions early beginning on January 1 of each year. In the Final Rule, PHMSA is adopting the amendment to the NPMS as proposed.

Proposal: The welding provisions in Subpart E of Part 192 and Subpart D of Part 195 allow qualification of welders in accordance with API Standard 1104, “Welding of the ASME Pipelines and Related Facilities,” (API Std 1104), section 6 or ASME Boiler and Pressure Vessel Code., section IX: “Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators,” (ASME BPVC, section IX). In the NPRM, PHMSA proposed to add references to additional qualification standards in API Std 1104, such as sections 12 and 13 for welders and welding operators of mechanized and automated welding equipment. The addition of these qualification references was intended to follow current industry practice. These standards have specific processes to ensure that qualified personnel are used for welding processes whether they are performed by welders or welding operators.

Comments: EPPG commented that the proposed language appears to not allow for the qualification of a welding operator whose welds are regularly being assessed per the criteria in API Std 1104, Appendix A, which is regarded as being equivalent to section 9. EPPG suggested a revision of the proposed language of § 192.227(a) to read: “under section 6, or section 9 or Appendix A, as applicable of API Std 1104 (incorporated by reference, see § 192.7).” [Proposed deletion indicated by strikeout; proposed addition in bold].

INGAA recommended that while PHMSA is amending the welding regulations, PHMSA should take the opportunity to formally incorporate by reference Appendix B to API Std 1104 for in-service (also known as “live line”) welding. Oleska suggested that the language of the proposed revision would be clearer if we changed “pipe and components” to read “pipe or components.”

Panhandle commented that the proposed language for § 192.229(c)(1) contains an oversight related to this equivalence. The section says, in part:

A welder or welding operator qualified under § 192.227(a)—

(1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding six calendar months the welder or welding operator has had one weld tested and found acceptable under section 6 or section 9 of API Std 1104 (incorporated by reference, see § 192.7).

According to Panhandle, sections 6 and 9 of API Std 1104 relate to workmanship criteria only. The proposed language would appear to exclude qualification of a welding operator whose welds are regularly being assessed per the criteria in API Std 1104, Appendix A which is regarded as being equivalent to ASME BPVC, section IX. It is reasonable to allow qualification for a welding operator whose work has been acceptable under the Appendix A criteria. Panhandle therefore suggested that PHMSA modify the proposed language in the notice to read:

Response: The Final Rule allows welds to be evaluated to API Std 1104, section 9 or Appendix A, and eliminates the requirement that the weld be first evaluated to section 9, before using Appendix A. Evaluating the welds first according to section 9 incurs unnecessary time and cost without any benefit.

PHMSA re-evaluated its proposal to add additional references to qualification standards in API Std 1104. PHMSA finds that adding API Std 1104, section 13 (“Automatic Welding Without Filler Metal Additions”) is inconsistent with pipeline safety. API Std 1104, section 13 is not used on regulated pipelines and would be a major change in girth welding standards. Also, for practical purposes, there are no commercially used pipeline welding systems in the United States to which API Std 1104, section 13 can be applied. Not adopting API Std 1104, section 13, will prevent an operator from using a potentially less safe welding system without a PHMSA special permit review.

INGAA suggested that PHMSA use the Final Rule as an opportunity to formally incorporate by reference Appendix B to API Std 1104 for in-service (“live line”) welding. Parts 192 and 195 currently require that all welding procedures be qualified to API Std 1104, section 5 or ASME BPVC, section IX, and that all welders be qualified to API Std 1104, section 6 or ASME BPVC, section IX. API Std 1104, Appendix B is only applicable to in-service welds on live or “hot” pipelines, with pressurized product in the pipe. The qualification requirements of Appendix B are optimized for in-service welds, and differ greatly from API Std 1104, sections 5 and 6 and ASME BPVC, section IX. Thus, adding API Std 1104, Appendix B to the Final Rule is a significant change that is outside the scope of this rule. We will consider this change for a future regulatory action.

Based upon further review by PHMSA of Part 192, Appendix C, PHMSA decided that adding welding operators for Appendix C qualification in § 192.227(b) would be inappropriate for the following reasons:

(1) Qualification of welding operators can be, and is more appropriately performed to API Std 1104, section 12, instead of Appendix C;

(2) Appendix C is primarily used for lower pressure, smaller diameter distribution lines, which are welded by welders, not welding operators; and

(3) The language in Appendix C was written for qualification of welders, and may not be appropriate for qualification of welding operators.

We agree with the comments that API 1104, Appendix A should be included as a qualification reference. When we proposed to add the relevant references to welding qualification standards to be consistent with industry practice, we intended to include the Appendix A reference, a widely accepted standard. Appendix A is now cited in the final regulations applicable to welding and welding operators.

Proposal: Pressure vessels can be found in meter stations, compressor stations and other pipeline facilities to facilitate the removal of liquids and other materials from the gas stream. These vessels are designed, fabricated and tested in accordance with the requirements of ASME Boiler & Pressure Vessel Code, section VIII Rules for Construction of Pressure Vessels,” as required by § 192.153 and § 192.165(b)(3), and the additional test requirements of § 192.505(b).

In the NPRM, PHMSA proposed that because the standard ASME pressure vessel test in ASME BPVC, section VIII, division 1 is 1.3 times MAOP, an operator must specify the correct test pressure when placing an order for an ASME vessel to ensure it is designed and tested to the requirements of 49 CFR part 192. Unless a vessel is specially ordered with a test pressure of 1.5 times MAOP as prescribed by the purchaser, the vessel will be tested in accordance with the standard test factor of 1.3. If the vessel is not tested to 1.5 times the MAOP, it cannot be used in a compressor or meter station, or other Class 3 or Class 4 locations. The failure to meet this requirement can potentially lead to exceeding the design parameters of the vessel during subsequent testing of the pipeline system.

The pressure test requirements in ASME BPVC, section VIII were lowered from a test factor of 1.5 to 1.3 by an earlier edition. PHMSA proposed to add § 192.153 to clearly specify the design and test requirements for pressure vessels in meter stations, compressor stations, and other locations that are tested to Class 3 requirements. Under the proposal, all ASME pressure vessels subject to § 192.153 and § 192.165(b)(3) would be designed and tested at a pressure that is 1.5 times the MAOP, in lieu of the standard ASME BPVC, section VIII test pressure of 1.3 times the MAOP. Additionally, PHMSA proposed to revise § 192.165(b)(3) reference to this requirement.

Comments: Kern River, INGAA and Northern Natural Gas maintained that this proposal is not a simple clarification but a change from the previous understanding and practice of both PHMSA and the operators. If the proposed regulation is applied retroactively, this change will place many facilities constructed after the change in the pressure test requirements in ASME BPVC, section VIII, as well as many facilities uprated under special permits, in violation of ASME BPVC, sections I and II. INGAA noted that these sections of Part 192 and the ASME BPVC revision history make it clear that the proposed rule will require a number of operators to make substantial and costly changes. Northern Natural Gas commented that retesting and replacing of these in-service components would be unnecessary, very expensive, and take several years to complete.

INGAA noted that station piping often includes fabricated sections that are assembled at the construction site. Many of these sections, such as compressor bottles, coolers and inlet scrubbers and separators are tested and certified by their manufacturers. Requiring a second test at the construction site as proposed would depart sharply from common practice, add costs that are not justified by a safety benefit and potentially invalidate the manufacturers' compliance certificates.

Kern River further commented that station piping is commonly tested in several segments and it is not common practice to include and retest ASME code vessels since they are certified by the manufacturers and retesting would require dewatering. INGAA advised PHMSA to adopt an alternate clarification that these components do not require testing beyond the ASME code. If PHMSA adopts the current recommendation, it should clarify that the amendment applies to components placed into service after the amendment's effective date.

Response: PHMSA has incorporated by reference ASME BPVC for pressure vessels. The revised ASME BPVC, section VII, division 1 has changed pressure testing standards from 1.5 times MAOP to 1.3 times MAOP. This proposal is not a change to the current pressure testing requirements found in Part 192, but simply a clarification to ensure a clearer understanding of PHMSA's pressure testing requirements for certain ASME BPVC vessels located in compressor stations, meter stations and other Class 3 or Class 4 locations. The pressure testing requirements for pipelines in the PSR (which by definition includes pressure vessels, meter stations, compressor stations and other facilities used to transport gas as defined in Part 192 and ASME/ANSI B31.8) in Class 3 and 4 areas, as well as those facilities located in Class 1 and Class 2 which are explicitly required by § 192.505(b), requires a pressure test equal to a minimum of 1.5 times the MAOP. The testing requirements of § 192.505(b) have not been revised and state that in a Class 1 or Class 2 location, each compressor station regulator station, and measuring station, must be tested to at least Class 3 location test requirements. This clarification of code requirements are to ensure that Industry does not incorrectly use the newer ASME BPVC standard for pressure testing even though that was never the requirement. This clarification will not lead to additional cost measures, and therefore, PHMSA is adopting this amendment as proposed.

Proposal: Section 192.625 contains requirements for operators to odorize combustible gas in a transmission line in Class 3 or Class 4 locations “so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.” Certain exceptions are recognized by regulation, including for a lateral line, “which transports gas to a distribution center, [if] at least 50 percent of the length of that line is in a Class 1 or Class 2 location.” This section does not specify a clear method for calculating the length of a lateral line, and that has led to inconsistencies in applying the odorization requirement. In the NPRM, PHMSA proposed to amend § 192.625(b)(3) to state that the length of a lateral line, for purposes of calculating whether at least 50 percent of the line is in a Class 1 or Class 2 location, be measured between the distribution center and the first upstream connection to the transmission line.

Comments: Texas Oil and Gas Association commented, and API supported this comment, that PHMSA's attempt to better define which natural gas transmission lateral pipelines are subject to the odorization requirement may create the unintended consequence of adversely impacting industrial facility (refinery) operations and product quality in addition to increasing emissions. TransCanada Corporation noted that the proposed amendment's apparent distinction between lateral and transmission lines appears to lack logic, as it allows parts of a line originally considered to be a “lateral” line to change classification due to introduction of a branch. TransCanada further noted that the industry is not aware of, nor has PHMSA presented in the preamble, statistical evidence that this understanding of lateral has caused safety issues resulting from operators applying this definition to exempt certain lines from odorization with commensurate safety benefits. TransCanada submits that the definition of “lateral” most commonly used by the industry more than adequately serves the interest of public safety. It also noted that “laterals are not distinct classification of lines; rather, `laterals' are described according to their function (e.g., transmission, distribution or gathering).”

INGAA had similar comments and suggested that PHMSA convene a public hearing or workshop to develop the fundamental regulatory changes needed to align its policy objectives with common pipeline configurations. The natural gas industry considers lateral lines to be any lines that branch off other lines. Section 192.625 does not specify a clear method to calculate the length of a lateral line, and that has led to inconsistency in applying the odorization requirement. Even with the proposed language, there is confusion on the calculation. There is no evidence, of record or otherwise, suggesting that the industry's understanding of “lateral” has caused any safety issues.

The American Chemical Council (ACC) commented that the use of gas odorants at certain facilities could affect some chemical manufacturing processes and the quality of some chemicals. While there are well-established safety benefits of odorants in natural gas transmission that are fully consistent with the ACC member company interests in enhanced natural gas production and use, the ACC is concerned that the potential requirement to odorize lateral lines that carry natural gas may affect some industrial facilities. Further, the proposal could force chemical manufacturers to remove the odorant before processing, leading to a substantial potential increase in the effective cost of natural gas and in the cost of production.

TPA commented that this change could also result in odorization equipment, including odorant storage tanks, being located in close proximity to populated areas, increasing the likelihood of false reports and odor complaints from nearby residents. According to TPA, some products manufactured with natural gas can be tainted by sulfur based odorant making the product worthless.

Response: This controversial topic was discussed at length at the advisory committee meeting. GPAC members found it difficult to agree on how to calculate the 50 percent length of a lateral line between the distribution center and the first upstream connection to the transmission line. Committee members were also concerned with the costs and benefits of this proposal. GPAC voted unanimously for PHMSA not to adopt this proposal. Although PHMSA believes that proper odorization is important, this proposal requires further analysis. Therefore, PHMSA will re-evaluate the proposal and may consider the revision in a future rulemaking action.

In the NPRM, PHMSA proposed several editorial amendments to the regulations.

(1) In § 195.571, we proposed to revise the reference to NACE SP0169 to specify compliance with one or more of the applicable criteria contained in paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3.

(2) In § 195.2, we proposed to amend the definition of “Alarm” to correct an error in the codification of the new control room management regulations (74 FR 63310).

(3) In §§ 192.925(b) and (b)(2), we proposed to replace “indirect examination” with “indirect inspection” to maintain consistency with § 192.925(a) and the applicable NACE standard.

(4) In § 195.428(c), we proposed to replace “sections 5.1.2” with “section 7.1.2” to correctly reference the overfill protection requirements for aboveground breakout tanks in the API Std 2510.

(5) In section 192.3 we proposed to add the definition of “Welder” and “Welding Operator.

(6) In § 195.2, we proposed to revise the definitions of “alarm” and “hazardous liquid.”

None of these editorial amendments received any comment and, as such, we are adopting them all as proposed.

Several administrative regulatory changes summarized in the following paragraphs are included in this Final Rule.

PHMSA discovered an error in the hazardous liquid regulations covering operator notifications of planned construction, and gave notice of its intention to correct the regulatory language (see March 21, 2012; 77 FR 16472, Advisory Bulletin ADB-2012-04). Section 195.64(c)(1)(iii) requires notification for construction of a new pipeline facility but does not specify a minimum dollar threshold for the construction project. Section 195.64(c)(1)(i) also requires notification for construction of a new pipeline facility, but only for those projects with a cost of ten million dollars ($10,000,000) or more. PHMSA does not wish to be notified about hazardous liquid pipeline facility construction with a cost of less than ten million dollars, so § 195.64(c)(1)(iii) is being deleted.

The NPRM proposed to remove the requirement to file offshore pipeline condition reports currently found in §§ 191.27 and 195.57. This Final Rule completes the removal and changes §§ 191.7 and 195.58 by removing the reference to offshore pipeline condition reports.

Sections 191.25 and 195.56 include the method for submitting safety-related condition reports. Since the receipt and processing of these reports is extremely time sensitive, the regulations currently require submittal by facsimile and do not provide an option for electronically mailing the report to PHMSA. These amendments are non-substantive and allow operators easier reporting methods. In this Final Rule, these regulations are revised to allow submittal of reports by electronic mail.

The remaining changes apply to the submittal methods for integrity management and operator qualification program notifications. Under changes made in this Final Rule, these notifications may now be submitted by either electronic mail or regular mail. For integrity management, changes are made in §§ 192.949 and 195.452. For operator qualification programs, changes are made in §§ 192.805 and 195.505.

This Final Rule is a non-significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was not reviewed by the Office of Management and Budget. This Final Rule is not significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034).

Executive Orders 12866 and 13563 require agencies to regulate in the “most cost-effective manner,” to make a “reasoned determination that the benefits of the intended regulation justify its costs,” and to develop regulations that “impose the least burden on society.” PHMSA amended miscellaneous provisions to clarify and eliminate unduly burdensome requirements. PHMSA also responded to requests from industry and state pipeline safety representatives to revise its regulations. PHMSA anticipates that a majority of the amendments contained in this Final Rule will have economic benefits to the regulated community by increasing the clarity of its regulations and reducing compliance costs.

For example, the changes related to NPMS and ethanol are simply a regulatory codification of current requirements. The elimination of the exception in § 192.65 related to the transportation of pipe should have minimal impact because the amount of pipe that would be eligible for the exception is very small. The elimination of the offshore pipeline condition report will eliminate a reporting requirement that is no longer necessary.

Several provisions of the Final Rule are specifically designed to eliminate confusion and potentially lower costs for regulated entities. For example, the final addition of § 192.153(e) is designed to prevent regulated entities from purchasing pressure vessels that do not comply with § 192.505(b), but that do comply with ASME BPVC, section VII, as required by § 192.165(b)(3). The changes with respect to qualifying plastic pipe joiners will prevent re-qualification date “creep” and provide operators greater re-qualification flexibility and overall cost savings.

Annual Compliance costs associated with this rulemaking are estimated to be $0.55 million, all of which are associated with requirement of leak Surveys for Type B gathering lines. PHMSA estimates approximately 3,650 miles of Type B gathering lines will be required to be inspected annually. PHMSA estimates that the average cost of inspection is $300 per mile, bringing the upper bound limit of the total annual expenditure to approximately $1.1 million. A more realistic estimate of the actual incremental cost is approximately 50% of the upper bound of $.55 million.

By performing leak surveys annually, operators are more likely to detect leaks early, thereby avoiding costlier future repairs and reducing the amount of gas lost. There are also practical, operational benefits to conducting leak surveys, in the form of greater knowledge of the state of the pipeline, including potential third-party encroachments, soil erosion, or intrusion by vegetation.

The lead cause of these leaks is external corrosion. Leak surveys are particularly important for low pressure gas gathering lines because these lines tend to leak rather than rupture and because their gas is non-odorized, making leaks more difficult to detect. In addition to the direct operational benefits, annual leak surveys will also reduce the environmental harm caused by lost gas (i.e., the greenhouse gas potential of methane released into the atmosphere). Operator leak reporting also gives PHMSA valuable information that can be used in trending analysis for the determination of problem materials or poor operating practices. These important benefits cannot be readily quantified, but PHMSA believes that they are substantial.

In addition, eliminating these leak helps to ensure that leaked gas does not collect and lead a catastrophic explosion or other incident. Although fortunately there have been no serious incidents involving Type B gathering lines in the past several years, increased leak surveys would reduce the potential of a future incident. At an incremental cost of $0.55 million per year, requiring annual leak surveys would be a cost-effective safety intervention if it prevents even a single fatal incident over a 16 year period.

A more thorough discussion of the subjects and the associated costs and benefits can be found in the Regulatory Impact Analysis, a copy of which has been placed in the Docket, PHMSA-2010-0026.

Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions would have a significant economic impact on a substantial number of small entities.

Description of the reasons that action by PHMSA was taken.

PHMSA, pipeline operators and others have identified certain errors, inconsistencies, and deficiencies in the pipeline safety regulations concerning the following subjects: (1) Performance of post-construction inspections; (2) leak surveys of Type B onshore gas gathering lines; (3) the requirements for qualifying plastic pipe joiners; (4) the transportation of ethanol by pipeline; (5) the transportation of pipe; (6) the filing of offshore pipeline condition reports and (7) the calculation of pressure reductions for hazardous pipeline anomalies. PHMSA is addressing these issues in this Final Rule.

Succinct statement of the objectives of, and legal basis, for the Final Rule.

Under the pipeline safety laws, 49 U.S.C. 60101 et seq., the Secretary of Transportation must prescribe minimum safety standards for pipeline transportation and for pipeline facilities. The Secretary has delegated the authority of 49 CFR 1.53(a) to the PHMSA Administrator. The Final Rule would make changes in the regulations consistent with the protection of persons and property, while changing unduly burdensome or confusing requirements.

Description of small entities to which the Final Rule will apply.

In general, the Final Rule will apply to pipeline operators, some of which may qualify as a small business as defined in Section 601(3) of the Regulatory Flexibility Act. Some pipelines are operated by jurisdictions with a population of less than 50,000 people, and thus qualify as small governmental jurisdictions.

Some portions of the rule apply to manufacturers of pipeline components, as well as the contractors constructing or repairing a pipeline. Many of these may qualify as a small business entity.

Description of the projected reporting, recordkeeping, and other compliance requirements of the Final Rule, including an estimate of the classes of small entities that will be subject to the rule, and the type of professional skills necessary for preparation of the report or record.

The Final Rule does not directly impose any reporting or recordkeeping requirements. However, the rule creates an obligation to perform leak surveys of Type B gathering lines. This sort of survey is currently required of transmission lines. Professional technicians will be needed to comply with this requirement, and the time required for compliance will vary greatly with each system, depending on the system's size.

The remainder of the Final Rule does not impose any significant compliance, recordkeeping, or reporting requirements. However, it affects the timing and substance of one type of report that must be created and maintained under existing regulations. The Final Rule stipulates that operators notify PHMSA field offices 60 days prior to pipe manufacturing or construction activities on new alternative MAOP pipelines. The current regulations require operators to notify PHMSA 180 days in advance of operating a pipeline at a higher alternative MAOP. Because operators must currently provide PHMSA with a 180 day notice prior to operating at the alternative MAOP the Final Rule does not impose any additional reporting requirements.

Identification, to the extent practicable, of all relevant Federal rules that may duplicate, overlap, or conflict with the Final Rule.

PHMSA is unaware of any duplicative, overlapping, or conflicting Federal rules.

Description of any significant alternatives to the Final Rule that accomplish the stated objectives of applicable statutes and that minimize any significant economic impact of the Final Rule on small entities, including alternatives considered.

PHMSA is unaware of any alternatives which would produce smaller economic impacts on small entities while at the same time meeting the objectives of the relevant statutes. Several provisions of the Final Rule are specifically designed to eliminate confusion and potentially lower costs for regulated entities. For example, the addition of 49 CFR 192.153(e) is designed to prevent regulated entities from purchasing pressure vessels that do not comply with § 192.505(b), but that do comply with ASME BPVC section VII, as required by § 192.165(b)(3). PHMSA believes that this Final Rule impacts a substantial number of small entities but that this impact will be negligible. The one requirement that may have a significant cost impact on small businesses is leak surveys for Type B gas gathering lines. PHMSA estimates that requiring leakage surveys on Type B gas gathering lines will necessitate an annual expenditure of approximately 0.55 million dollars. The costs are based on surveying two miles of pipeline per day at an approximate daily cost of $300 per mile and PHMSA's estimation that 50 percent of the mileage affected by this proposal already complies with the surveying. The daily costs are an average day rate provided by two providers of leak survey services.

The Small Business Administration's North American Industry Classification System Code for gas transmission pipeline operators defines a small business as those operators that have annual revenue of less than 25.5 million dollars. It is PHMSA's opinion that very few gas gathering operators have revenues less than 25.5 million dollars per year. No other types of small entities, such as manufacturers, will see a significant cost impact. Therefore, this amendment will not affect a substantial number of small businesses. Based on the facts available about the expected impact of this rulemaking, I certify, under Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605) that this Final Rule will not have a significant economic impact on a substantial number of small entities.

PHMSA has analyzed this Final Rule according to the principles and criteria in Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Because this Final Rule does not significantly or uniquely affect the communities of the Indian tribal governments or impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.

This Final Rule imposes no new requirements for recordkeeping and reporting.

This Final Rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million, adjusted for inflation, or more in any one year 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 Final Rule.

The National Environmental Policy Act (42 U.S.C. 4321-4375) requires that Federal agencies analyze final actions to determine whether those actions will have a significant impact on the human environment. The Council on Environmental Quality regulations requires Federal agencies to conduct an environmental review considering (1) the need for the final action, (2) alternatives to the final action, (3) probable environmental impacts of the final action and alternatives, and (4) the agencies and persons consulted during the consideration process. 40 CFR 1508.9(b).

PHMSA's mission is to protect people and the environment from the risks of hazardous materials transportation. The purpose of this rulemaking change is to improve compliance, provide clarification, address conflicting language and promote improved pipeline integrity and safety. In addition the purpose is to address small gaps in the current regulations and mitigate some of the negative externalities that can result from industry market failures.

The need for this action stems from statutory requirements described in the Pipeline Safety, Regulatory Certainty, and job Creation Act of 2011 (Public Law 112-90), safety recommendations from the NTSB, and petitions from industry groups. In addition, due to shortfalls and unenforceability of industry standards, there arises a need for government to set minimum safety levels in pipeline regulations.

PHMSA is making amendments and editorial changes to the regulations that includes modifying the requirements for: the performance of post-construction inspections, the conducting of leak surveys of Type B onshore gas gathering lines, qualifying plastic pipe joiners, the regulation of ethanol, the transportation of pipe, the filing of offshore pipeline condition reports, and the calculation of pressure reductions for hazardous liquid pipeline anomalies.

In developing the Final Rule, PHMSA considered three alternatives:

(1) No action.

(2) Adopting all proposed amendments.

(3) Adopting all proposed amendments except for leak surveys for Type Gas gathering lines.

PHMSA has an obligation to ensure the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this Final Rule serve that purpose by clarifying the regulations and eliminating unduly burdensome requirements. A failure to undertake these actions would allow for the continued imposition of unnecessary compliance costs without increasing public safety. Accordingly, PHMSA rejected the no action alternative.

PHMSA's Selected Action is a set of amendments and editorial changes to the Federal Pipeline Safety Regulations (49 CFR parts 191, 192, and 195). These revisions would eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this Final Rule will serve that purpose by clarifying certain regulatory requirements.

As discussed above under alternative 2, and in the published NPRM, PHMSA proposed to make certain amendments, corrections and editorial changes to the regulations. These revisions eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The proposal related to leak survey for Type B gas gathering lines. PHMSA established a new method for determining whether a gas pipeline is an “onshore gathering line” in 2006. PHMSA also imposed new safety standards for “regulated onshore gathering lines,” which divided regulated onshore gathering lines into two risk-based categories. Type A gathering lines are metallic lines with a MAOP of 20 percent or more of SMYS, as well as nonmetallic lines with an MAOP of more than 125 psig, in a Class 2, 3, or 4 location. These lines are subject to all of the requirements in Part 192 that apply to transmission lines, except for the regulation that requires the accommodation of in-line inspection tools in the design and construction of certain new and replaced pipelines (49 CFR 192.150) and the integrity management requirements of Part 192, Subpart O. Operators of Type A gathering lines are also permitted to use an alternative process for demonstrating compliance with the requirements of Part 192, Subpart N, Qualification of Pipeline Personnel.

Type B gathering lines includes metallic lines with a MAOP of less than 20 percent of SMYS, as well as nonmetallic lines with a MAOP of 125 psig or less, in a Class 2 location (as determined under one of three formulas) or in a Class 3 or Class 4 location. These lines are subject to less stringent requirements than Type A gathering lines. Specifically, any new or substantially changed Type B line must comply with the design, installation, construction, and initial testing and inspection requirements for transmission lines and, if of metallic construction, the corrosion control requirements for transmission lines. Operators must also include Type B gathering lines in their damage prevention and public education programs, establish the MAOP of those lines under § 192.619, and comply with the requirements for maintaining and installing line markers that apply to transmission lines. It is important that dependable leak detection surveys are used to identify leakage so that appropriate repairs can be initiated to our nation's pipeline system. Prompt repair can help reduce the consequences of incidents to the public, environment and property. Performing field leak surveys is a preventative and proactive safety measure. Operator leak reporting also gives PHMSA valuable information that can be used in trending analysis for the determination of problematic materials or poor operating practices. Over time, unchecked leakage can potentially impact safety in addition to the fact that gas leaks have the risk of accidental ignition causing a fire or explosion.

Prior to the 2006 Final Rule, operators had to perform leak surveys of non-rural gas gathering lines. Also, some Type B gathering lines are located under broad paved areas where electrical surveys (another means of detecting pipe damage) may be difficult to perform and leaking gas could migrate under the pavement and accumulate in surrounding structures. PHMSA believes that leak surveys are an effective means of ensuring the integrity of low-stress pipelines. Accordingly, PHMSA rejected this alternative.

The Nation's pipelines are located throughout the United States in a variety of diverse environments—from offshore locations, to highly populated urban sites, to unpopulated rural areas. The pipeline infrastructure is a network of over 2.5 million miles of pipeline that move millions of gallons of hazardous liquids and over 55 billion cubic feet of natural gas daily. The biggest source of energy is petroleum, including oil and natural gas. Together, these commodities supply 65 percent of the energy in the United States.

The physical environment potentially affected by the Final Rule includes airspace, water resources (e.g., oceans, streams, lakes), cultural and historical resources (e.g., properties listed on the National Register of Historic Places), biological and ecological resources (e.g., coastal zones, wetlands, plant and animal species and their habitat, forests, grasslands, offshore marine ecosystems) and special ecological resources (e.g., threatened and endangered plant and animal species and their habitat, national and state parklands, biological reserves, wild and scenic rivers) that exist directly adjacent to and within the vicinity of pipelines.

Because the pipelines subject to the Final Rule contain hazardous materials, resources within the physically affected environment, as well as public health and safety, may be affected by gas pipeline incidents such as spills and leaks. Incidents on pipelines can result in fires and explosions, resulting in damage to the local environment. In addition, since pipelines often contain gas streams laden with condensates and natural gas liquids, failures also result in spills of these liquids, which can cause environmental harm. Depending on the size of a spill or gas leak and the nature of the impact zone, the environmental impacts could vary from property and environmental damage to injuries or, on rare occasions, fatalities.

A majority of the amendments in this Final Rule are not substantive in nature and would have little or no impact on the human environment. It is likely that on a national scale, the cumulative environmental damage from pipelines is reduced, or at a minimum, unchanged. Requiring leakage surveys on Type B gathering lines will have positive environmental impacts. The Environmental Protection Agency (EPA) data indicate that methane contributed to nine percent of the reported greenhouse gas emissions in Calendar Year 2011 (www.epa.gov/methane/). Operators reported 289 leaks repaired on regulated Type B gathering lines in 2011. It is expected that with formalized leak survey programs in place, emissions will be further reduced, in addition to enhanced safety from leak repairs. Although beneficial, this would not be a large-scale impact on the environment.

For these reasons, PHMSA has concluded that neither of the alternatives discussed above would result in any significant impacts on the environment.

Various industry associations and state regulatory agencies, such as the American Gas Association, the American Petroleum Associations and NAPSR, were consulted in the development of this rulemaking.

PHMSA has determined that the selected alternative would not have a significant impact on the human environment.

Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT's complete Privacy Act Statement published in the Federal Register on April 11, 2000, (70 FR 19477).

PHMSA has analyzed this Final Rule according to Executive Order 13132 (“Federalism”). The Final Rule does not have a substantial direct effect 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. This Final Rule does not impose substantial direct compliance costs on state and local governments. This Final Rule does not preempt state law for intrastate pipelines. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.

This Final Rule is not a “significant energy action” under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on supply, distribution, or energy use. Further, the Office of Information and Regulatory Affairs has not designated this Final Rule as a significant energy action.

In consideration of the foregoing, 49 CFR Chapter I is amended as follows:

NMFS manages the groundfish fishery in the BSAI exclusive economic zone according to the Fishery Management Plan for Groundfish of the Bering Sea and Aleutian Islands Management Area (FMP) prepared by the North Pacific Fishery Management Council (Council) under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679.

In the Aleutian Islands subarea, the portion of the 2015 pollock total allowable catch (TAC) allocated to the Community Development Quota (CDQ) directed fishing allowance (DFA) is 1,900 metric tons (mt) as established by the final 2015 and 2016 harvest specifications for groundfish in the BSAI (80 FR 11919, March 5, 2015).

As of March 5, 2015, the Administrator, Alaska Region, NMFS, (Regional Administrator) has determined that 1,900 mt of pollock CDQ DFA in the Aleutian Islands subarea will not be harvested. Therefore, in accordance with § 679.20(a)(5)(iii)(B)(4), NMFS reallocates 1,900 mt of pollock CDQ DFA from the Aleutian Islands subarea to the 2015 Bering Sea subarea allocations. The 1,900 mt of pollock CDQ DFA is added to the 2015 Bering Sea CDQ DFA. As a result, the 2015 harvest specifications for pollock in the Aleutian Islands subarea included in the final 2015 and 2016 harvest specifications for groundfish in the BSAI (80 FR 11919, March 5, 2015) are revised as follows: 0 mt to CDQ DFA. Furthermore, pursuant to § 679.20(a)(5), Table 4 of the final 2015 and 2016 harvest specifications for groundfish in the BSAI (80 FR 11919, March 5, 2015), is revised to make 2015 pollock allocations consistent with this reallocation. This reallocation results in adjustments to the 2015 CDQ pollock allocations established at § 679.20(a)(5).

This action responds to the best available information recently obtained from the fishery. The Assistant Administrator for Fisheries, NOAA (AA), finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) as such requirement is impracticable and contrary to the public interest. This requirement is impracticable and contrary to the public interest as it would prevent NMFS from responding to the most recent fisheries data in a timely fashion and would delay the reallocation of AI pollock. Since the pollock fishery is currently underway, it is important to immediately inform the industry as to the final Bering Sea subarea pollock allocations. Immediate notification is necessary to allow for the orderly conduct and efficient operation of this fishery; allow the industry to plan for the fishing season and avoid potential disruption to the fishing fleet as well as processors; and provide opportunity to harvest increased seasonal pollock allocations while value is optimum. NMFS was unable to publish a notice providing time for public comment because the most recent, relevant data only became available as March 5, 2015.

The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment.

This action is required by § 679.20 and is exempt from review under Executive Order 12866.