Supporting Statement RM6-7-000

FERC-537 and FERC-577 Final Rule (Docket No. RM06-7-000)

Issued: October 19, 2006

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Supporting Statement for

FERC-537, Gas Pipeline Certificates: Construction, Acquisition and Abandonment;

FERC-577, Gas Pipeline Certificates: Environmental Impact Statement;

With regard to Regulations to the Blanket Certificate Regulations and

Clarification Regarding Rates

As proposed in Docket No. RM06-7-000

(Final Rule Issued October 19, 2006)

The Federal Energy Regulatory Commission (FERC/Commission) requests Office of Management and Budget (OMB) review and approval of FERC-537 and FERC-577. FERC-537 and FERC-577 are existing data requirements that amend Parts 153 and 157 of the Commission’s regulations.

The Commission is amending its Part 157, Subpart F, blanket authorization regulations to expand the scope and scale of activities that may be under taken in accordance with its blanket authority.¹ The Commission is expanding the types of natural gas projects permitted under blanket authority and to increase the cost limits that apply to blanket projects. In addition, FERC is clarifying that a natural gas company is not necessarily engaged in an unduly discriminatory practice if it charges different customers different rates for the same service on the date that customers commit to service.

We estimate that the annual reporting-burden related to the subject Final Rule will be 7,727 hours under FERC-537 and -11,997 hours under FERC-577 for a total of 4,270 hours as adopted in the subject final rule. FERC-537 (OMB Control No. 1902-0060) is currently approved by OMB through December 31, 2008 and FERC-577 (OMB Control No. 1902-0128) is currently approved through December 31, 2008.

Background

A natural gas company must obtain a certificate of public convenience and necessity in accordance with section 7 of the Natural Gas Act (NGA) to construct, acquire, alter, abandon, or operate jurisdictional gas facilities or to provide jurisdictional gas services. Natural gas companies holding an NGA section 7(c) certificate may also obtain blanket certificate authority under Part 157, Subpart F, of the Commission’s regulations to undertake certain types of activities without the need to obtain case-specific certificate authorization for each project. Activities undertaken pursuant to blanket certificate authority are not subject to the longer and more exacting review process associated with individual authorizations issued on an application-by-application basis.²

Natural gas facilities that may be constructed, acquired, altered, or abandoned in accordance with blanket authority are currently constrained by a cost limit of $8,200,000 for projects which can be undertaken without prior notice (also referred to as self-implementing or automatic authorization projects) and $22,700,000 for projects for which prior notice is required.³ In addition, the blanket certificate provisions apply only to a restricted set of eligible facilities;⁴ ineligible facilities currently include mainlines, storage field facilities, and facilities receiving gas from a liquefied natural gas (LNG) plant or a synthetic gas plant.⁵

NOPR (Docket No. RM06-7-000)

In RM06-7-000 Notice of Proposed Rulemaking (NOPR) (June 16, 2006), the Commission proposed to expand the scope of activities that can be undertaken in accordance with blanket authority by (1) increasing the project cost limit to $9,600,000 for an automatic authorization project and $27,400,000 for a prior notice project and (2) expanding the category of facilities eligible for construction under blanket certificate authority to include mainline facilities, certain LNG and synthetic gas facilities, and certain storage facilities. In addition, the Commission clarified that a natural gas company is not necessarily engaged in an unduly discriminatory practice if it charges different customers different rates for the same service based on the date that customers commit to service. The NOPR was in response to a petition filed by the Interstate Natural Gas Association of America (INGAA) and the Natural Gas Supply Association (NGSA).

On November 22, 2005, the Interstate Natural Gas Association of America (INGAA) and the Natural Gas Supply Association (NGSA) (Petitioners) jointly filed a petition under

§ 385.207(a) of the Commission’s regulations proposing that the blanket certificate provisions be expanded “to improve the industry’s ability to ensure the adequacy of infrastructure, without impairing any legitimate rights of any party and without frustrating any public-policy objectives.”⁶ Petitioners pointed to natural gas prices and tight gas supply and demand, and stressed the need to ensure that natural gas facilities are adequate to reliably move available gas supplies to consuming markets. By way of example, Petitioners observed that natural gas producers faced with takeaway constraints can experience shut-ins, the depression of wellhead prices, and uncertainty as to when and where to drill new wells. Petitioners added that companies faced with an inability to build new facilities when and where they are needed can experience a lack of growth, operational problems, and constraints on system flexibility. Petitioners argued that implementing their requested regulatory revisions will diminish the likelihood of experiencing such adverse events.⁷

Petitioners observed that the natural gas industry has undergone a fundamental change since the blanket certificate provisions were put in place in 1982,⁸ and believes that the rationale for certain limitations imposed when the blanket certificate program was implemented should no longer apply. Petitioners requested that blanket certificate authority be expanded to include mainline facilities, LNG takeaway facilities, and certain underground storage field facilities which are currently excluded from the blanket certificate program, and requested that the cost limits for blanket projects be raised.

Petitioners commented that “in the Commission’s original justification for the [blanket certificate program] restrictions in Order No. 234, the primary reason given was the impact on ratepayers, not environmental impact or safety.”⁹ In 1982, the blanket project cost limits were set at $4,200,000 for automatic projects and $12,000,000 for prior notice projects; presently, these cost limits stand at an inflation adjusted $8,200,000 and $22,700,000, respectively. Petitioners asserted that the current blanket project cost cap is “sufficiently small” to render any rate impacts de minimis and stated their belief in “the likelihood that new investments will produce new revenue that covers the cost of the investments.”¹⁰

Petitioners claimed that natural gas project costs have escalated faster than inflation, citing costs attributable to more extensive public outreach, greater agency involvement, a more complex permitting process, additional environmental remediation requirements, and the use of technologically advanced construction equipment. In view of this, Petitioners asked the Commission to reassess project costs and raise the blanket project cost limits in § 157.208(d), Table I, of the regulations. Petitioners do not characterize this as enlarging the scale of projects permitted under blanket authorization,¹¹ but as recalibrating the cost limits to permit a project that could have been constructed within the cost limit in effect in 1982 to be built again today within today’s updated cost limit.

Petitioners stated that a natural gas company’s decision to go forward with a proposed project can turn on whether there are customer service commitments in hand sufficient to demonstrate the proposal’s economic viability. Petitioners requested that the Commission allow preferential rate treatment for “foundation shippers,” i.e., customers that sign up early for firm service and thereby establish the financial foundation for a new project. Doing so, Petitioners claim, will “provide a strong incentive for more potential shippers to become foundation shippers, thus allowing needed infrastructure projects to get underway earlier.”¹² Petitioners sought assurance that offering customers that commit early to a proposed project a more favorable rate than customers that seek service later will not be viewed as unduly discriminatory.

Subject Final Rule (Docket No. RM06-7-000)

In RM06-7-000 Final Rule (issued October 19, 2006) the Commission amends its blanket certification regulations to expand the scope and scale of activities that may be undertaken pursuant to blanket certificate authority. The Commission is expanding the types of natural gas projects permitted under blanket certificate authority and increasing the cost limits that apply to blanket projects. In addition, the Commission clarifies that a natural gas company is not necessarily engaged in an unduly discriminatory practice if it charges different customers different rates for the same service based on the date that customers commit to service. Rather than rely on the more demanding process of submitting an application under section 7(c) of the Natural Gas Act for certificate authorization for every project, the revised regulations will allow interstate natural gas pipelines to employ the streamlined blanket certificate procedures for larger projects and for a wider variety of types of projects, thereby increasing efficiencies, and decreasing time and costs, associated with the construction and maintenance of the nation’s natural gas infrastructure.

A. Justification

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

The blanket certificate program was designed to provide an administratively efficient

means to authorize a generic class of routine activities, without assessing each prospective project on a case-by-case basis. In 1982, in instituting the blanket certificate program, the Commission explained the new program as follows:

[T]he final regulations divide the various actions that the Commission certificates into several categories. The first category applies to certain activities performed by interstate pipelines that either have relatively little impact on ratepayers, or little effect on pipeline operations. This first category also includes minor investments in facilities which are so well understood as an established industry practice that little scrutiny is required to determine their compatibility with the public convenience and necessity. The second category of activities provides for a notice and protest procedure and comprises certain activities in which various interested parties might have a concern. In such cases there is a need to provide an opportunity for a greater degree of review and to provide for possible adjudication of controversial aspects. Activities not authorized under the blanket certificate are those activities which may have a major potential impact on ratepayers, or which propose such important considerations that close scrutiny and case-specific deliberation by the Commission is warranted prior to the issuance of a certificate.¹³

The Commission continues to apply the above criteria in an effort to distinguish those types of activities that may appropriately be constructed under blanket certificate authority from those projects that merit closer, case-specific scrutiny due to their potentially significant impact on rates, services, safety, security, competing natural gas companies or their customers, or on the environment.

“Under section 7 of the NGA, pursuant to which the blanket certificate rule is promulgated,” the Commission has “an obligation to issue certificates only where they are required by the public convenience and necessity. The blanket certificate rules set out a class of transactions, subject to specific conditions, that the Commission has determined to be in the public convenience and necessity.”¹⁴ To the extent this class of transactions is enlarged, there must be an assessment, and assurance, that each added class of transactions is similarly required by the public convenience and necessity.

In the Final Rule, the Commission expands the scope of blanket certificate activities to include mainlines, storage facilities, and certain facilities carrying regasified LNG and synthetic gas, and to expand the scale of blanket certificate activities by raising the project cost limits.

FERC-537

Under the Natural Gas Act (NGA) (Public Law 75-688) (15 U.S.C. 717-717w) a natural

gas company must obtain FERC authorization to engage in the transportation of natural gas in interstate commerce, to undertake the construction or extension of any facilities, or to acquire or operate any such facilities or extensions in accordance with Section 7(c) of the NGA. A natural gas company must also obtain FERC approval under Section 7(b) of the NGA prior to abandoning any jurisdictional facility or service. Under the Natural Gas Policy Act (NGPA) (Public Law 96-621) interstate and intrastate pipelines must also obtain FERC authorization for certain transportation arrangements.

If a certificate is granted, the natural gas company can engage in the interstate transportation of natural gas and construct, acquire, or operate facilities. Conversely, approval of an abandonment application permits the pipeline to cease service and discontinue the operation of such facilities. Authorization under NGPA Section 311(a) allows the interstate or intrastate pipeline applicants to render certain transportation services.

FERC-577

Section 102(2)(c) of the of the National Environmental Policy Act of 1969 (NEPA)(Pub. L. 91-190)¹⁵ requires that all Federal agencies must include in every recommendation or report on proposals for legislation and other major federal actions significantly affecting the quality of the human environment, a detailed statement on: the environmental impact on the proposed actions; any adverse environmental effects which cannot be avoided should the proposal be implemented; alternatives to the proposed action; the relationship between local short-term uses of man’s environment and the maintenance and enhancement of long term productivity; and any irreversible and irretrievable commitment of resources which would be involved in the proposed action should it be implemented. FERC-577 identifies the Commission’s information collections relating to Part 380 of its regulations implementing NEPA and includes the environmental compliance conditions of §157.206(b).

2. HOW, BY WHOM AND FOR WHAT PURPOSE IS THE INFORMATION TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION

The natural gas companies file the necessary information with FERC so that the Commission can determine from the data if the requested certificate should be authorized. The data required to be submitted in a normal certificate filing consists of identification of the company and responsible officials, factors considered in the location of the facilities and the impact on the area for environmental considerations. Also to be submitted are the following:

• Flow diagrams showing the design capacity for engineering design verification and safety determination;

• Gas reserve data for appraisal of the feasibility of the project;

• Market data presenting the economic basis for the proposed action; and

• Cost of proposed facilities, plans for financing, and estimated revenues and expenses related to the proposed facility for accounting and financial evaluation.

Because of the greater demand for natural gas as seen in rapidly evolving market conditions, FERC established in FY ’99 a performance plan to process cases as efficiently as possible. The Commission grouped certificate applications by the level of effort required to respond to the applications and established clear targets for the time it should take to process each type of application. Among the four types of certificate cases, three met or beat targets, and the fourth approximated the target time.

Environmental concerns play a significant role in the review of certificate construction applications. Pipelines are facing increased opposition from landowners as new projects are proposed in more heavily populated areas. When new pipelines propose to serve markets currently served by existing pipelines, FERC has to balance the benefits of alternative supplies of natural gas with the environmental impact of a new project. Critical to the Commission’s efforts to balance benefits and environmental impacts are the environmental conditions the Commission builds into the certificates.

If the collection of data for FERC-537 and FERC-577 were not conducted, the Commission would not be able to meet its NGA statutory responsibilities and meet the Commission’s objectives of expediting appropriate infrastructure development to ensure sufficient energy supplies while addressing landowner and environmental concerns fairly. The information is expected to permit the Commission to meet the request of the natural gas industry, as expressed in the INGAA and NGSA’s petition to improve industry’s ability to ensure the adequacy of the infrastructure to meet the increased demands from consuming markets, to expand the scope and scale of the blanket certificate program to provide a streamlined means to build and maintain infrastructure necessary to ensure all gas supplies are available to fulfill market needs.

2. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE BURDEN AND THE TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN

There is an ongoing effort to determine the potential and value of improved information technology to reduce burden. Specifically, in order to increase the efficiency with which it carries out its program responsibilities, the Commission has been implementing measures to use information technology to reduce the amount of paperwork required in its proceedings. In Order No. 619, FERC established an electronic filing initiative to meet the goals of the Government Paperwork Elimination Act, which directed agencies to provide for optimal use and acceptance of electronic documents and signatures and electronic recordkeeping, where practical, by October 2003. Among the qualified documents that can now be filed electronically are comments on a filing. “Comments on a Filing” is a document filed in response to a FERC public notice or order in a specific FERC docketed proceeding. It includes comments on applications, comments filed with environmental documents, protests or statements of positions. In addition, in the Commission’s regulations at 18 CFR Part 157, section 157.6 directs applicants to file in an electronic format (1) applications covering acquisitions and all attached exhibits; (2) applications to abandon facilities; (3) progress reports; (4) request for authorizations under the notice procedures established in 157.205; (5) applications submitted under subpart F of Part 157 and (6) annual report required by §157.207.

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATON AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2.

Commission filings and data requirements are periodically reviewed in conjunction with OMB clearance expiration dates. This includes a review of the Commis­sion's regulations and data requirements to identify any duplication. To date, no duplication of the proposed data requirements has been found. The Commission staff is reviewing its various filings in an effort to alleviate duplication. There are no similar sources of information available that can be used or modified for use for the purpose described in Item A (1.).

5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

The information requirements under FERC-537 and FERC-577 apply to jurisdictional pipelines. Most of the companies regulated by the Commission do not fall within the Regulatory Flexibility Act’s (RFA) definition of a small entity. Under the industry standards used for purposes of the RFA, a natural gas pipeline company qualifies as a “small entity” if it has annual revenues of $6.5 million or less. Most companies regulated by the Commission do not fall within the RFA’s definition of a small entity.¹⁶

6. CONSEQUENCE TO FEDERAL PROGRAM IF COLELCTION WERE CONDUCTED LESS FREQUENTLY

FERC-537 and FERC-577 data collections are required for statutory purposes and cannot be discontinued nor collected less frequently. The information that must be submitted to the Commission is event driven. The same applies to requirements in the Final Rule.

Without such information, the Commission would be unable to fulfill its statutory responsibilities under the NGA, NGPA, NEPA and the Energy Policy Act of 2005.

The Final Rule expands the scope of activities that can be undertaken pursuant to blanket authority by (1) increasing the project cost limit to $9,600,000 for an automatic authorization project and $27,400,000 for a prior notice project¹⁷ and (2) expanding the types of facilities that may be acquired, constructed, modified, replaced, abandoned, and operated under blanket certificate authority to include mainline facilities, certain LNG and synthetic gas facilities, and certain storage facilities. In addition, the Commission clarifies that a natural gas company is not necessarily engaged in an unduly discriminatory practice if it charges different customers different rates for the same service based on the date that customers commit to service.

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION

The number of copies of a certificate application to be filed in compliance with Section 157.6 includes an electronic media submission along with an original and seven hard copies. The number of copies to be filed is more than prescribed by OMB in their guidelines at 5 CFR 1320.5(d) (2). The additional copies are necessary because of the number of offices within the Commission that must review and analyze the application in a timely fashion. Project sponsors will be required to submit an additional exhibit with each application. However, the information in the new exhibit already should be readily available to the project sponsor; the new reporting requirement merely directs that this information be summarized and presented in tabular form.

8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY’S RESPONSE TO THESE COMMENTS

The Commission's procedures require that the rulemaking notice be published in the Federal Register, thereby allowing all pipeline companies, state commissions, federal agencies, and other interested parties an opportunity to submit comments, or suggestions concerning the proposal. The rulemaking procedures also allow for public conferences to be held as required. Comments to the NOPR were due 60 days from publication in the Federal Register.

INGAA/NGSA Petition

Notice of the INGAA/NGSA petition was published in the Federal Register on December 9, 2005.¹⁸ The Commission sought comments on whether it should take further action on the petition. Responses were filed by: American Gas Association (AGA); American Public Gas Association (APGA); Anadarko Petroleum Corporation (Anadarko); Devon Energy Corporation (Devon); Duke Energy Gas Transmission Corporation (Duke); Enstor Operating Company, LLC (Enstor); Honeoye Storage Corporation (Honeoye Storage); Illinois Municipal Gas Agency (Illinois Municipal); Independent Petroleum Association of America (IPAA); Kinder Morgan Interstate Gas Transmission, LLC (Kinder Morgan); NiSource Inc. (NiSource); Process Gas Consumers Group (Process Gas Consumers); Public Service Commission of New York (PSCNY); and Sempra Global (Sempra).

Duke, Enstor, Honeoye Storage, IPAA, and Process Gas Consumers unequivocally support the petition, and the majority of the remaining comments supported aspects of the proposal. Several commentors questioned and/or opposed the petition’s proposals. The comments are discussed below.

AGA requested the Commission convene a technical conference to consider whether the proposal could adversely impact rates or degrade service, and thus be inconsistent with Commission policy which requires weighing the impact of new facilities on existing customers.¹⁹ AGA is concerned that expanding blanket certificate authority would undermine the Commission’s rationale for initiating the blanket certificate program, which rests on the premise that blanket activities are minor in scope and “so well understood as an established industry practice that little scrutiny is required to determine their compatibly with the public convenience and necessity.”²⁰

APGA questioned the rationale for revising the blanket certificate program. Unlike Petitioners, APGA sees no cause to attribute current high natural gas prices and recent price volatility to inadequate gas transportation or storage facilities. Instead, APGA contends prices reflect tight supplies and a relatively inelastic demand.²¹ Consequently, APGA does not expect the proposed regulatory revisions to result in lower gas prices or less price volatility. APGA contends the proposed changes will eliminate protections mandated by the NGA and will be contrary to Commission’s Policy Statement on New Facilities.

APGA observed that in the past, the Commission has temporarily altered provisions of the blanket certificate program in response to natural gas emergencies, and states that these temporary measures have proved effective. In view of the Commission’s success in making temporary adjustments, APGA sees no need to permanently expand blanket certificate authority. APGA contended that but for the electric crisis in the Western United States in 2000-2001, Petitioners have not cited any instance of mainline pipeline capacity constraint that would justify lifting the prohibition on adding mainline capacity under blanket certificate authority. APGA stated that the Commission’s response to the 2005 Gulf Coast hurricanes is designed to expedite rebuilding infrastructure to restore lost services, and does not reflect a need to permanently alter the blanket certificate regulations in order to promote a nationwide expansion of facilities and services.

Commission’s Response

AGA raises legitimate issues relevant to the outcome of this proceeding. However, the Commission expects all interested persons will have an adequate opportunity to express their views in comments in response to the NOPR. Given that comments have yet to be submitted on the merits of the regulatory revisions proposed herein, the Commission will dismiss AGA’s request for a technical conference as premature. Following a review of the comments received in response to the NOPR, the request will be reassessed.

The Commission concurs with APGA that flexibility afforded by the NGA and the intermittent use of provisional waivers of certain Commission regulations, have proved effective in accelerating the industry’s recovery from natural gas emergencies. However, the Commission does not view the result of a temporary waiver of compliance with certain blanket certificate requirements – whether the result is deemed a success or not – as a reason to adopt or reject the blanket certificate program expansion as Petitioners propose. The Commission believes the emphasis of the blanket certificate program should remain, as it always has, on expediting the process of adding and improving gas facilities and services, while ensuring that there are no adverse impacts on existing rates, services, or the environment. The immediate crisis in the aftermath of the hurricanes has eased. However, the need to restore and add infrastructure remains critical: (1) to attach new supplies to offset the continuing decline from existing gas sources; (2) to add interconnections, extensions, and other new facilities to enhance the flexibility and responsiveness of the grid; and (3) to accommodate anticipated increases in imports of LNG. It is with these objectives in mind that the Commission proposes to expand its blanket certificate program.

Blanket Certificate Costs

Blanket certificate projects are constrained (1) by cost caps, (2) by compliance with the § 157.206(b) environmental requirements, and (3) by being limited to a restricted set of facilities.²² The Commission proposes to raise the cost caps for blanket certificate projects.

The blanket certificate project cost limits were initially set at $4,200,000 for an automatic authorization project and $12,000,000 for a prior notice project. Since 1982, the Commission has used an inflation tracker (the gross domestic product implicit price deflator as determined by the Department of Commerce) that has resulted in incrementally ratcheting up blanket project cost limits to the current level of $8,200,000 for an automatic authorization project and $22,700,000 for a prior notice project. Petitioners contend these inflation-adjusted cost caps fail to take into account additional costs, such as regulatory compliance requirements and the use of more expensive construction technology, which did not play as prominent a part in 1982 as they do today, and request the Commission initiate a study to analyze and compare costs in 1982 to costs today. Petitioners request the Commission reassess construction costs to determine if a project constructed within 1982 cost limits could be replicated within today’s cost limits.

Commission’s Response

There is no question that construction costs vary over time, and do so in a manner that is not easily predicted. Recently, for example, certain project components – notably the price of steel pipe – have risen far faster than any measure of overall inflation. However, although steel prices have run up over the past several years, in looking back to 1982, there were periods during which steel prices fell substantially. Further, changing regulatory requirements and construction techniques, to which Petitioners attribute cost increases, do not always add to project costs, and may well contribute to cost reductions and efficiencies.

The Commission is concerned that a focus on changes in construction costs over time risks losing sight of the fundamental premise of the blanket certificate program, namely, that blanket authorization be restricted (1) to projects that are modest in scale and routine in nature, i.e., projects that are sufficiently well understood so as to permit them to proceed with a lesser level of regulatory scrutiny, and (2) to projects that will not result in unjustified increases in existing customers’ rates. With respect to the latter, comparing construction costs over time is irrelevant; the relevant question is whether the project cost caps have served to adequately insulate existing rates from increases attributable to blanket program costs. The Commission cautions that even if it were possible to mirror 1982 costs to costs today, the dollar amounts would not reflect proportionate impacts on existing rates, since in 1982 the commodity cost of gas was a significant portion of pipeline customers’ merchant service rate, whereas today, gas costs are no longer a component of pipeline customers’ transportation service rate. In view of this, the Commission questions the utility of undertaking a formal inquiry to try to true up construction costs from 1982 to today, and so declines Petitioners’ invitation to do so.

Nevertheless, in an effort to gauge whether the inflation tracker employed by the Commission over the past quarter century has functioned as a reliable indicator of the rise in construction costs; the Commission has reviewed changes in gas utility construction materials costs. Between 1982 and 2005, such costs have risen by a factor of approximately 2.29,²³ compared to a factor of approximately 1.90 using the inflation tracker employed by the Commission. To account for this divergence, the Commission proposes to raise blanket cost limits to $9,600,000 for a no-notice project and to $27,400,000 for a prior notice project. In view of the relatively small disparity demonstrated between utility construction materials costs and the Department of Commerce’s GDP implicit price deflator, the Commission proposes to continue to rely the latter, a commonly used and generally accepted measure of overall inflation levels, as the measure for making annual adjustments to the project cost limits. The Commission declines to tie the blanket cost limit adjustment to commodity prices (such as steel), labor rates, or other potentially subjective and varying project cost components out of a concern that this could result in volatile or inappropriate cost limit adjustments.

Responses to the NOPR

Comments on the NOPR were filed by the AGA; APGA; Boardwalk Pipeline Partners, LP (Boardwalk); Consolidated Edison Company of New York, Inc. (Con Ed) jointly with Orange and Rockland Utilities, Inc. (Orange and Rockland); Dominion Transmission, Inc., Dominion Cove Point LNG, LP, and Dominion South Pipeline Company, LP (Dominion); Duke; HFP Acoustical Consultants Inc. (HFP Acoustical ); INGAA; IPAA; NGSA; Process Gas Consumers; Sempra; and Williston Basin Interstate Pipeline Company (Williston). Further comments were filed by INGAA jointly with NGSA, and by AGA.

Notification Requirements

a. Content of Landowner Notification

The NOPR proposed revising § 157.203(d)(2)(iv) to state that in the notice to affected landowners of a proposed project, the project sponsor include the most recent edition of the Commission pamphlet titled “An Interstate Natural Gas Facility on My Land? What Do I Need to Know?” INGAA and Williston point out that the current edition of the pamphlet describes the Part 157, Subpart A, case-specific certificate process generally, but does not describe the Part 157, Subpart F, blanket program specifically, and suggest the pamphlet be revised or a separate pamphlet be prepared to cover the blanket certificate procedures.

Commission Response: The Commission will adopt the latter approach, and to enhance administrative efficiency and ensure information remains up-to-date, rather than a pamphlet, the Commission will require that notice include blanket-specific information that will be available on the Commission’s website. Accordingly, § 157.203(d)(2)(iv) of the Commission’s regulations is revised to read as follows: “A general description of the blanket certificate program and procedures, as posted on the Commission’s website at the time the landowner notification is prepared, and the link to the information on the Commission’s website.”

In response to Williston, the Commission clarifies that the information requirements stated in § 157.203(d)(1), including the additional requirements of revised § 157.203(d)(1)(iii), are applicable to landowner notification for proposed blanket certificate projects that qualify for automatic authorization. The information requirements stated in § 157.203(d)(2), including the additional requirements of revised § 157.203(d)(2)(i), (ii), (iv), (v), and (vii), are applicable to public notice for proposed blanket certificate projects that do not qualify for automatic authorization.

b. Summary of Rights

Revised § 157.203(d)(2)(v) requires that in the notice to affected landowners of a proposed project, the project sponsor include a brief summary of the rights the landowner has in Commission proceedings and in proceedings under the eminent domain rules of the relevant state(s). INGAA contends affected landowners will perceive any discussion of eminent domain “as a threat that their property will be condemned if they do not consent to an easement agreement,” an interpretation that “could cause more harm than good,”²⁴ and comments that the description of state eminent domain rules may prove misleading if a project sponsor proceeds with condemnation actions under federal eminent domain law. Duke worries discussing landowner rights would “constitute the provision of legal advice in most jurisdictions,” and because “[m]any bar associations prohibit lawyers from giving advice to unrepresented third parties,” this could create a “potential legal conflict for natural gas companies.”²⁵ Duke recommends the contents of the notice be limited to informing affected landowners of their right to obtain local counsel.

Commission Response: As INGAA recognizes, discussions concerning the potential to acquire property rights by means of eminent domain can be disconcerting to affected landowners. It has been the Commission’s experience that such discussions are most prone to be perceived as threatening when the initial contact with landowners is made in person by a project sponsor’s representative seeking physical access to the property. The Commission believes a far less provocative means to inform affected landowners is to present them with a brief, clear, and candid description of the eminent domain process in written form. Landowners cannot be expected to engage in negotiations and reach decisions regarding their property without such information. The Commission concurs with INGAA’s apprehension that landowners may be confused by a description of state condemnation if federal condemnation is employed; accordingly, § 157.203(d)(2)(v) of the Commission’s regulations is revised to omit the reference to state proceedings and to instead require a “brief summary of the rights the landowner has in Commission proceedings and in proceedings under the relevant eminent domain rules.”

The Commission agrees with Duke’s observation that affected landowners ought to be informed of their right to obtain counsel, and this fact should be included in the required summary of landowner rights. In response to Duke’s concern that complying with § 157.203(d)(2)(v) could constitute the practice of law or place project sponsors with an ethical quandary, the Commission clarifies that the required brief summary of rights and procedures is descriptive, not interpretative. Project sponsors are expected to summarize or recite applicable law, and no more. Not only is there not a need for advice be proffered, none should be. Finally, the Commission notes similar arguments were presented when the original landowner notification rule was instituted in 1999;²⁶ subsequently, there has been no evidence of significant difficulties in complying with the requirements of the rule.

c. Landowner Contact

As proposed, § 157.203(d)(1)(B) requires that in a notice to affected landowners of a proposed project, the project sponsor include a local contact to call first with problems or concerns. INGAA points out that for certain projects, the personnel best able to respond to problems or concerns may be remotely located, e.g., at a company’s central office. Therefore, INGAA asks that the “local” specification be removed, and in its place, project sponsors be required to include the toll-free telephone number of a company representative responsible for responding to affected landowners.

Commission Response: The Commission accepts INGAA’s argument that its alternative procedure will provide the same protections for landowners. Therefore, § 157.203(d)(1)(B) of the Commission’s regulations is revised to read as follows: “Provide a local or toll-free phone number and a name of a specific person to be contacted by landowners and with responsibility for responding to landowner problems and concerns, and who will indicate when a landowner should expect a response.”

Notification Times

Currently, under § 157.203(d)(1) of the Commission’s regulations, before commencing construction of an automatically authorized blanket project, project sponsors are required to give affected landowners 30 days notice in advance of construction. For blanket projects that do not qualify for automatic authorization, under § 157.203(d)(2), project sponsors are required to provide a 45-day prior notice to the public, during which any person, or the Commission, can protest the proposal. The Final Rule extends each of these time frames by 15 days. INGAA, NGSA, and pipelines object to offering additional notice time, arguing that (1) the proposed increase in project costs should not change the nature of the projects undertaken pursuant to blanket authority; (2) there is no evidence the current notice periods are too short; and (3) affected landowners and the public should be able to reach a decision on whether to protest well within the current notice periods.²⁷

The NOPR stated:

In view of the proposed expanded scope and scale of blanket certificate authority, which can be expected to increase the number of automatic authorization projects undertaken and the number of people impacted, an additional 15 days offers greater assurance that there will be adequate time for landowners to state their concerns and for project sponsors and the Commission to respond . . . [T]he additional time will provide the Commission with a more reasonable period of time to conduct and conclude its environmental assessment (EA) of a proposal. This NOPR contemplates an increase in the number, extent, kind, and complexity of facilities subject to blanket certificate authority, yet even for the types of projects currently permitted, 45 days has proved to be, on occasion, an unrealistically short time for the consultation and analysis required to complete an EA. The additional time will ensure the Commission is not forced to protest a prior notice project merely as a means to gain time to finish an EA. The Commission does not expect the extended landowner and public notice periods to unduly delay blanket certificate projects, since natural gas companies, in large part, can dictate when a blanket certificate project may begin construction by when the company elects to initiate the notice process.

Commission Response: It is not only the increase in project costs, i.e., an expansion in scale of blanket authorized activities, it is also the far wider range in the types of projects permitted under the blanket authority that warrant adding time to allow for adequate consideration of what the Commission anticipates will be blanket proposals that are both more complex and more numerous. The Commission notes that to the extent issues raised by a prior notice proposal cannot be addressed in the time provided; a protest is the probable outcome, which if not resolved, would result in the proposal being treated as a case-specific NGA section 7(c) application necessitating the preparation and issuance of a Commission order on the merits. The Commission affirms the need to add 15 days to the notice periods, for the reasons stated in the NOPR.

Annual Report on Automatic Authorization Projects

Revised §§ 157.208(e)(4)(ii) and (iii) require that the annual report filed for automatic authorization projects document the progress toward restoration and discuss problems or unusual construction issues and corrective actions. INGAA, Duke, and Williston contend that providing this information will be burdensome, especially for large pipelines that might rely on automatic authorization for numerous projects each year, and may require placing additional personnel on site to monitor progress on each project.

Commission Response: The Commission has a different perspective. Certificate holders are currently required to comply with all the conditions in § 157.206(b) of the Commission’s blanket certificate regulations. Section 157.206(b), in addition to setting forth specific conditions, makes blanket certificate activities subject to the conditions in § 380.15 of the Commission’s regulations implementing NEPA, as well as requiring that all blanket certificate activities be consistent with all applicable law implementing the Clean Water Act, the Clean Air Act, and other statutes relating to environmental concerns. Consequently, in order to satisfy all the conditions applicable to blanket certificate activities, it is already necessary for project sponsors (1) to have plans and procedures in place to ensure compliance with environmental conditions, and (2) to have environmental inspectors in place to record a project’s construction’s compliance with environmental conditions. Hence, the Commission does not view the new § 157.208(e)(4)(ii) and (iii) requirements as asking companies to gather and report new information, but rather, as having companies submit information that they are already obliged to compile. Similarly, to the extent project sponsors find they have to place personnel at construction sites to monitor a project’s progress; this does not constitute a new requirement, but rather, is a means to fulfill an ongoing obligation to verify that projects are built in accord with all applicable environmental conditions. Consequently, the Commission adopts the expanded annual reporting requirements.

Environmental Conditions

(a). Noise Levels

(1). Compressor Station Site Property Boundary

Revised § 157.206(b)(5)(i) states that noise attributable to a compressor station “must not exceed a day-night level (L_dn) of 55 dBA at the site property boundary.” In contrast, the current regulations specify that noise attributable to a compressor station is to be measured “at any pre-existing noise-sensitive area.”

Duke contends this new noise criterion could compel companies to expand compressor site boundaries, which would add to the cost of new or additional compression and, potentially, an increase in environmental impacts associated with adding acreage to existing and new sites. INGAA argues that compressors were installed in anticipation of meeting noise level require-ments as measured at the nearest noise sensitive area, and that it is inequitable to institute this change and compel ratepayers to bear the cost of compliance. Boardwalk objects to the revision. HFP Acoustical asks if compressor noise is to be measured as an average of noise levels at several spots on the perimeter of the property line or if every point on a site’s property boundary must meet the 55 dBA standard. HFP Acoustical seeks clarification on whether there will be any acknowledgment of existing sources of noise unrelated to compressor operations.

Commission Response: The Commission clarifies that this new noise measurement criterion only applies to facilities placed in service after the effective date of this rule;²⁸ thus, existing compressor stations continue to be required to meet the 55 dBA standard as measured at pre-existing noise-sensitive areas, not at the site’s property boundary. However, any increase in noise due to additions or modifications to an existing compressor station undertaken subsequent to the effective date of this rule will require that the noise attributable to additions or modifica-tions be measured at the site’s boundary. The Commission further clarifies that when measuring noise at new stations, the 55 dBA standard must be met at every point on a site’s property boundary.²⁹ Finally, with respect to existing noise levels at the property boundary, the certificate holder will only be responsible for taking measures to reduce noise in excess of the 55 dBA standard that is attributable to the operation of the compressor station.

Although existing compressor stations are grandfathered, the Commission concurs with comments that anticipate the new standard may compel companies to extend existing compressor station boundaries if additions or modifications are made that increase noise at the site boundary. However, while this may entail additional costs, the Commission does not view it as adding to adverse environmental impacts. Indeed, overall environmental impacts may diminish, since land within a station boundary is frequently set aside for benign environmental use. Further, the Commission does not accept the contention that this revision will induce the development of new compressor stations, since the cost to mitigate noise attributable to adding compression at an existing site is likely to be less than acquiring a new site.

(2). Noise Attributable to Drilling

In §157.206(5)(ii), the Commission establishes the goal that perceived noise from drilling in between 10 p.m. and 6 a.m. be kept at or below 55dBA in any preexisting noise-sensitive area. INGAA contends adherence to this goal would be impractical and costly. In particular, INGAA contends that suspending a horizontal directional drill (HDD) at night to adhere to noise restrictions would be a poor engineering practice, creating a substantial risk of failure. INGAA asks that the Commission (1) clarify the 55 dBA standard only applies if ambient noise at night is below that level; (2) clarify that where the existing noise level is 55 dBA or more, the noise standard be that a new project produces no appreciable increase in the ambient noise; and (3) clarify that mitigation measures may be employed to meet the 55 dBA noise level, such as temporarily relocating occupants of a noise sensitive area.

HFP Acoustical asks the Commission to clarify (1) whether the nighttime noise constraint impacts daytime drilling noise standards; (2) whether recirculation or other stabilizing activities could proceed at night; and (3) whether the reference to nighttime as from 10 p.m. to 6 a.m. should be changed to 10 p.m. to 7 a.m. to conform to the period during which a 10 dBA penalty currently applies. HFP Acoustical suggests that if the Commission intends to set a nighttime noise level limit, it state the limit in terms of the L_eq night or L_n value, rather than the L_dn value, which covers a 24-hour period.

Commission Response: In response to a request by Williston, the Commission clarifies that the noise standard for drilling at night is a goal, not a regulatory requirement. The Commission also clarifies that the §157.206(5)(ii) reference to “perceived noise from the drilling” has the same meaning as the §157.206(5)(i) reference to “noise attributable to” compression. Consequently, where the existing ambient noise level at night is below 55 dBA, and drilling activity boosts it above that threshold, the goal is to reduce the level down to 55 dBA; where the ambient noise level at night is above 55 dBA, and drilling activity causes that level to rise, the goal to take action to bring noise back to its pre-drilling level. As an alternative to reducing the noise from drilling, the Commission agrees that appropriate mitigation measures can include temporarily relocating or compensating people residing in areas affected by drilling activities.

The Commission acknowledges that reaching the stated goal may involve incurring additional costs, and recognizes that at times the goal may be impractical. Further, reaching the goal should not be achieved at the expense of adding to a project’s risk. For example, the Commission does not necessarily expect an ongoing HDD to be suspended at night if the interruption could cause the drill to fail, but does expect project sponsors to explore mitigation measures, such as erecting barriers so that continuous drilling can meet the 55 dBA goal. In response to HFP Acoustical, the Commission clarifies that all activities associated with drilling, such as recirculation or other stabilizing activities, are subject to the noise level goal; the Commission leaves it to the project sponsor’s discretion when, during a 24-hour cycle, to undertake a particular activity. The Commission will adopt HFP Acoustical’s suggestion and clarify that the nighttime noise goal will apply between the hours of 10 p.m. and 7 a.m., and will be expressed as a nighttime level, L_n, of 55 dBA.

b. Environmental Inspector Report

Revised § 157.208(c)(10) requires the project sponsor to commit to have the Environmental Inspector’s report filed weekly with the Commission for prior notice projects. INGAA, Duke, and Williston maintain this is unnecessary given blanket projects’ relatively short construction time, and is impractical given that inspectors may not be on site on a weekly basis. INGAA proposes compliance be ensured by having a completion report filed within 30 days of a project’s in-service date. INGAA believes this is adequate since the Commission “hotline” is available during construction to resolve allegations of improprieties. Williston suggests weekly reporting only be required when the Commission determines a particular blanket project merits such scrutiny.

Commission Response: The Commission does not believe that it can judge whether a particular project merits weekly reporting before the fact, or that its hotline can serve as a means to monitor ongoing construction progress, or that an after-the-fact summary can identify, prevent, or remedy irregularities in construction. The only practical means to monitor compliance with environmental requirements is to monitor progress during construction, hence the existing requirement that an Environmental Inspector be on site during a project’s construction. The Commission views revised § 157.208(c)(10) as a clarification of how certificate holders are to verify their fulfillment of this existing obligation. Neither the additional cost nor inconvenience of having an inspector available to review construction at multiple small project sites, nor the length of the construction phase of a project, has any bearing on the need for the regulatory requirement that a project sponsor have an inspector present. The Commission notes that an Environmental Inspector need not be an additional individual brought in to review a construction site; this function can be performed by someone on site, provided that individual has been properly trained and charged with inspecting and reporting on compliance with environmental plans and procedures and can perform all the Environmental Inspector’s responsibilities.

Different Rates for Different Customers for the Same Service

In the NOPR, the Commission expressed the belief that its existing policies permit a project sponsor to offer a rate incentive as an inducement to get customers to commit to a proposed project early (i.e., “foundation shippers”), while offering a less favorable rate to customers that commit later. Few commenters take issue with the Commission’s conclusion.

However, Process Gas Consumers stress the need for procedural fairness, e.g., that all prospective customers receive the same notice of a proposal, so as to preclude parties from making private bi-lateral agreements in advance of a public offer of new capacity. Boardwalk asks that pipelines be permitted to set rules for open seasons, provided there is no discrimination in the announcement and application of the rules.

Commission Response: The Commission affirms that there must be no discrimination in announcing an open season for new capacity and in accepting bids – all potential customers must have an equal opportunity to obtain firm capacity. Provided this condition holds, a project sponsor has the flexibility to set the parameters of the open season.

In the NOPR, the Commission observed that:

[u]nder the Petitioners’ proposal, the rate incentives a project sponsor offers to obtain early commitments to a project will be based solely on the timing of each shipper’s contractual commitment to the project. However, the Commission can envision that different project sponsors may prefer to offer rate incentives based on something other than the timing of contractual commitments. Because Commission policies permit rate differentials among customers based on a number of grounds – including differing elasticities of demand, volumes to be transported, and length of service commitments – a project sponsor might wish to offer preferential rates to shippers who contract for larger volumes of service.³⁰

APGA challenges the Commission’s conclusion that it is appropriate to permit project sponsors to offer preferential rates to customers willing to commit to greater capacity. APGA argues this is unfair because “a large LDC that gets a preferential rate can, for example, compete for new loads by offering lower delivery rates than the smaller LDC despite that fact that both entities committed for capacity at the same time.”³¹

Commission Response: The Commission stresses that the foregoing discussion in the NOPR regarding rates constitutes a statement of the Commission’s existing policies and practices and this rulemaking proceeding does not contemplate altering existing policies, practices, or regulations affecting rates. Indeed, with respect to rates, the Commission emphasized it did not intend to disturb the status quo, stating that:

[g]iven the variety of rate incentives that might be offered consistent with Commission policy, the Commission believes it would be premature to go beyond our general finding above and seek to itemize every rate incentive that might be offered in an open season without risk of undue discrimination. Instead, the Commission prefers to review different rate incentives on a case-by-case basis.³²

Thus, in the NOPR, the Commission made no determination beyond its general observation that currently there are a variety of rate incentives available to project sponsors to induce potential customers to commit to a new proposal. As one such incentive, quantity can be a legitimate basis for awarding new capacity at a lower rate during an open season. When a project sponsor is weighing market conditions in order to determine whether to invest in the construction of a new pipeline or storage field, a lower rate bid by a potential customer can nevertheless represent a significant incentive for the company to go forward with the project if the customer is willing to commit at an early stage to a large quantity.

Given the fact-specific circumstances associated with a particular project proposal, the Commission stated its intent to review rate incentives on a case-by-case basis. If APGA believes a project sponsor has employed an unduly discriminatory rate preference in a particular case, APGA may raise this issue in the case in question, and the Commission will address the merits of the matter in the context of that case.

As a general observation, a project sponsor can diminish its risk of being charged with undue discrimination if its announcement of an open season clearly specifies the parameters of the bidding provisions and the available rate options so that all potential customers have an equal opportunity to sign up for new service. For example, in their petition, INGAA and NGSA describe the eligibility standard for Group I foundation shippers variously as (1) the date established in the open season for executing contracts or (2) the date the project sponsor makes a “go/no go” decision for the project. The first date would appear to involve less risk of discrimination, since it would be announced and set at the start of the open season, whereas the second date appears to give the project sponsor considerable discretion as to when to terminate eligibility for Group I.

Expanding Blanket Authority to Cover Currently Excluded Facilities

The Final Rule adds §§ 157.210, .212, and .213 to include, respectively, certain mainline, LNG and synthetic gas, and storage facilities within the blanket certificate program. As discussed in the NOPR, these facilities were initially barred from the blanket program out of concern that their cost and operation could adversely impact existing customers’ rates and services. These concerns remain valid, and in addition, there has been increased attention to the environmental, safety, and security implications of all natural gas facilities. To ensure these matters receive appropriate review, all projects involving the additional types of facilities now permitted under the expanded blanket certificate program (with the exception of the remediation and maintenance of underground storage field facilities) will be subject to the prior notice provisions of the regulations regardless of their estimated costs. As explained in the NOPR, the Commission expects that by requiring prior public notice for blanket projects involving these previously excluded facilities, and by providing for more information to be included in notices to affected landowners and the public, and by providing additional time to assess proposed blanket projects, the Commission, affected landowners, and others will be afforded a reasonable opportunity to review the potential impacts of proposed projects prior to construction.

APGA asked the Commission affirm these measures will ensure adequate staff review of prior notice submissions.

Commission Response: The Commission expects that the revised regulations will enable staff to make a meaningful assessment of proposed blanket projects – and as appropriate, protest pursuant to § 157.205(e) of the Commission’s regulations – prior to a project going forward.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

There are no payments or gifts to respondents in the proposed rule.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

The Commission does not consider the information to be confidential. However, the

Commission has encouraged prospective applicants to submit preliminary corridor or route information maps which may contain Critical Energy Infrastructure Information (CEII). CEII as defined in section 388.113 of the Commission’s regulations includes information about proposed or existing natural gas facilities that could be used by a person planning an attack on critical energy infrastructure. The Commission’s procedures in section 388.112 are designed to ensure that CEII is not placed in the Commission’s public records. .

11. PROVIDE ADDITIONAL JUSTIFICAITON FOR ANY QUESTIONS OF A SENSITIVE NATURE

There are no questions of a sensitive nature associated with the posting requirements

proposed in the subject Final Rule.

12. ESTIMATED BURDEN COLLECTION OF INFORMATION

The proposed revisions to the Commission’s regulations, as contained in the Final Rule, and the resulting change in collections of information burdens, are as follows.

►proposes to provide an additional 15 days for notice to landowners and the public. This will have no impact on the collections of information;

►proposes specific additional information to be included in the notice to landowners located along the route of a proposed blanket certificate project and in the prior notice to the public of a proposed project. This should have a minor impact on blanket certificate project sponsors, since the additional information is already required for the landowner notification for case-specific NGA section 7 applications. Expanding the blanket certificate program to include mainline, certain LNG and synthetic gas facilities, and storage facilities is expected to allow approximately 62 projects per year to proceed under blanket certificate authority that would otherwise be required to obtain case-specific NGA section 7 certificate authorization. Therefore, these 62 projects will be removed from FERC-577 and shifted to FERC-537. Project sponsors permitted to rely on the proposed expanded blanket certificate authority to undertake projects that currently require case-specific NGA section 7 certificate authorization will not need to submit any additional information to meet the blanket certificate notice requirements. The exception to this is the proposal to require a description of a natural gas company’s environmental complaint resolution procedure in the blanket certificate program notice. However, this information is also frequently required for case-specific NGA section 7 projects and may be satisfied by a generic description of the complaint resolution process applicable to all projects along with individual contact information applicable to each project.

►Final Rule proposes to specify additional information to be included in the prior notice to the public and in the annual report. This should result in a minor increase in the existing burden. Only proposed prior notice blanket certificate projects that involve HDD and well drilling will be required to include a description of how noise limits will be achieved.  Prior notice projects will also need to commit to file weekly environmental inspector reports. The annual reports covering projects subject to automatic blanket certificate authority will require discussions of the progress of restoration efforts, problems, and corrections.  Where applicable, noise surveys are also required in annual reports, but such surveys are normally done to verify compliance with the standard environmental conditions, so this requirement adds only a minimal burden.

►proposes to revise the environmental compliance conditions to apply the noise standard to the site property boundary instead of the noise-sensitive areas, and as a goal, to apply the noise standard to drilling. Neither of these changes involves a change in the reporting burden.

Because the proposed expansion of the blanket certificate program will permit projects that are now processed under the case-specific NGA section 7 procedures to go forward under the streamlined blanket certificate program, while the burden under the expanded blanket certificate program will increase, the overall burden on the industry will decrease. The Commission estimates that the total annual hours for the blanket certificate program burden will increase by 7,727, whereas the total annual hours associated with case-specific application projects will decrease by 11,997. This represents an overall reduction of 4,270 hours.

CURRENT OMB PROPOSED PROPOSED NEW OMB

DATA REQUIREMENT (FERC-537) INVENTORY* IN NOPR IN FR INVENTORY

Estimated number of respondents : 76 76 76 76

Estimated number of responses per respondent: 10.72 2.71 2.71 10.72

Estimated number of responses per year : 815 206 206 815

Estimated number of hours per response : 245.82 37.1 37.1 282.92

Total estimated burden (hours per year) : 200,344 7,727 7,727 208,071

Program change in industry burden hours : + 7,727

Adjustment change in industry burden hours : -0-

*OMB Inventory as of 6/30/06

CURRENT OMB PROPOSED PROPOSED NEW OMB

DATA REQUIREMENT (FERC-577) INVENTORY* IN NOPR IN FR INVENTORY

Estimated number of respondents : 76 76 76 76

Estimated number of responses per respondent: 16.84 1 1 16.84

Estimated number of responses per year : 1,280 -62 -62 1,218

Estimated number of hours per response : 185.2 193.50 193.50 193.50

Total estimated burden (hours per year) : 247,686 -11,997 -11,997 235,689

Program change in industry burden hours : - 11,997

Adjustment change in industry burden hours : -0-

Total Annual Hours for Collection: 4,270 hours

Data Collection	No. of Respondents	No. of Responses/Filings	No. of Hours per Response	Total Annual Hours
FERC-537 (Part 157)	76	206	– 42.02	7,727
FERC-577 (Part 380)	76	– 62	193.50	-11,997

The Commission did not receive specific comments concerning the burden estimates in the NOPR, and uses the same estimates in this Final Rule. Several commenters did indicate that providing information for the Annual Report on Automatic Authorization Projects would be burdensome. However, as explained above, the Commission believes that much of this information is already required to be compiled and therefore to report it to the Commission will not result in significant additional burdens to certificate holders.

13. ESTIMATE OF TOTAL ANNUAL COST OF BURDEN TO RESPONDENTS

Because of the regional differences and the various staffing levels that will be involved in preparing the documentation (legal, technical and support) the Commission is using an hourly rate of $150 to estimate the costs for filing and other administrative processes (reviewing instructions, searching data sources, completing and transmitting the collection of information). The estimated cost is anticipated to be $2,748,900, an amount that is $640,500 less than the current estimated cost.

13. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT:

The estimated annualized cost to the Federal government related only to the data collections/requirements as proposed in the subject Final Rule are shown below:

Data Analysis Estimated Total Cost

Requirement of Data Salary Year's

Number (FTEs) x per Year = Operation

FERC-537 6.0 $117,321 $ 703,926

FERC-577 10.0 $117,321 $ 1,117,321

Total 16.0 $117,321 $1,877,136#

#based on 2006 Budget estimate for FERC FTE staff (FTE=Full Time Equivalent)

15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

See reasons for program change in Background section above.

16. TIME SCHEDULE FOR PUBLICATION OF DATA

The time schedule for the proposed requirements in this Final Rule is shown in the following table.

Schedule for Data Collection and Analysis

Activity Estimated Completion Time

Application Filed Event Oriented

17. DISPLAY OF EXPIRATION DATE

Not applicable. The data requirements under FERC-537and FERC-577 are based on regulations and not filed on formatted/printed forms. Thus, the subject data requirements do not have an appropriate format to display an OMB expiration date. An applicant is to follow these procedures prior to filing an application with the Commission.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

There are exceptions to the Paperwork Reduction Act statement. Because the data collected are not submitted on a standardized form, the Commission does not display the expiration date. In addition, the Commission does not use statistical survey methodology for these information collections.

B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS

Not Applicable. Statistical methods are not employed for these data collections.

1 18 CFR §§ 157.201-157.218 (2005).

2 Certain activities are exempted from the certificate requirements of NGA section 7(c). For example, § 2.55 of the Commission’s regulations exempts auxiliary installations and the replacement of physically deteriorated or obsolete facilities; Part 284, Subpart I, of the regulations provides for the construction and operation of facilities needed to alleviate a gas emergency.

3 ? See 18 CFR § 157.208(d), Table I (2006), as updated. In November 2005, in response to the impacts of hurricanes Katrina and Rita on gas production, processing, and transportation in and along the Gulf of Mexico, these cost limits were temporarily raised to $50,000,000 for prior notice projects and $16,000,000 for self-implementing projects, provided the projects increase access to gas supply and will be completed by October 31, 2006. See Expediting Infrastructure Construction To Speed Hurricane Recovery, 113 FERC ¶ 61,179 (2005). The October 31, 2006 deadline was subsequently extended to February 28, 2007. 114 FERC ¶ 61,186 (2006).

4 See § 157.202(b)(2)(i) of the Commission’s regulations, defining “eligible facilities,” and § 157.202(b)(2)(ii)(2005) of the regulations, describing facilities excluded from the definition of “eligible facilities.”

5 The November 2005 Order cited in note 3 also temporarily extended blanket certificate authority to include what would otherwise be ineligible facilities, namely, an extension of a mainline; a facility, including compression and looping, that alters the capacity of a mainline; and temporary compression that raises the capacity of a mainline.

6 INGAA/NGSA Petition at 2 (Nov. 22, 2005).

7 While Petitioners have “determined that there is little to be improved in the Commission’s processing of certificate applications,” and that “there are few changes to the current authorization process that would accelerate the process beyond its current, efficient state,” they nevertheless contend that adopting the proposed revisions will “further enhance the authorization process” and provide additional certainty regarding regulatory treatment. INGAA/NGSA Petition at 2 and 4 (Nov. 22, 2005).

8 Interstate Pipeline Certificates for Routine Transactions, Order No. 234, 47 FR 24254 (June 4, 1982), FERC Stats. & Regs. ¶ 30,368 (1982); Order No. 234-A, 47 FR 38871 (Sept. 3, 1982), FERC Stats. & Regs. ¶ 30,389 (1982).

9 INGAA/NGSA Petition at 8 (Nov. 22, 2005).

10 Id.

11 “[I]t is not contemplated that an increase in the dollar limits will cause blanket projects to be larger, in terms of the project foot print or right of way needed, than they would have been” in 1982. INGAA/NGSA Petition at 16 (Nov. 22, 2005).

12 Id. at 20.

13 47 FR 24254 (June 4, 1982).

14 Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985).

15 42 U.S.C. 4321, et seq, (2000).

16 5 U.S.C. 601(3), citing to section 3 of the Small Business Act, 15 U.S.C. 623 (2000). Section 3 of the Small Business Act defines a “small-business concern” as a business which is independently owned and operated and which is not dominant in its field of operation.

17 Upon the effective date of the Final Rule, these higher project cost limits will be substituted for the amounts that now appear for the current calendar year in 18 CFR 157.208(d), Table I, with these higher amounts then subject to the annual inflation adjustment.

18 70 FR 73,232 (2005).

19 See Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement on New Facilities), 88 FERC ¶ 61,227 (1999), orders clarifying statement of policy, 90 FERC ¶ 61,128 and 92 FERC ¶ 61,094 (2000), order further clarifying statement of policy, 92 FERC ¶ 61,094 (2000).

20 Interstate Pipeline Certificates for Routine Transactions, Order No. 234, FERC Stats. & Regs. ¶ 30,368 at 30,200 (1982). See also, Distrigas of Massachusetts Corp., 60 FERC ¶ 61,274 at 61,931 (1992), in which the Commission stated that “[t]he blanket procedures were intended to apply only to proposals which by their very nature require limited Commission involvement.”

21 APGA adds that the municipal and publicly-owned local distribution systems it represents, and the retail customers they serve, are “extremely sensitive” to increases in the cost of natural gas and it urges the Commission to “take all reasonable actions to ensure the lowest natural gas prices and to minimize price volatility.” APGA’s Comments at 4 (January 17, 2006).

22 Further, as a prerequisite for a blanket certificate, the Commission requires a company to first obtain a case-specific certificate, because it is in the context of evaluating an application for an NGA section 7 certificate authorization that the Commission establishes a “jurisdictional and informational base . . . concerning such matters as rates, system supplies and certificated customers.” Interstate Pipeline Certificates for Routine Transactions, Order No. 234, 47 FR 24254 (June 4, 1982); 47 FR 30724 (July 15, 1982), Reg. Preambles 1982-1985 P 30,200 (1982).

23 The gas utility construction materials cost factor is derived by averaging regional costs throughout the 48 contiguous states, as estimated in the Handy-Whitman Index of Public Utility Construction Costs, Trends of Construction Costs, Bulletin No. 162, 1912 to July 1, 2005. In initiating the blanket certificate program, “[m]any commenters argued against the use of the ‘GNP implicit price deflator’ for adjusting . . . [project cost] limits and recommended using the Handy-Whitman Index, a pricing index of various utility and utility-type equipment, updated semi-annually, for this purpose. The Commission believes that it is preferable to use the ‘GNP implicit price deflator’ instead of an index based on a private collection of data not easily susceptible to governmental verification.” (Footnote omitted.) 47 FR 24254 (June 4, 1982). The Commission reaffirms this preference.

24 INGAA’s Comments at 16 (Aug. 25, 2006).

25 Duke’s Comments at 15 (Aug. 25, 2006).

26 Landowner Notification, Expanded Categorical Exclusions, and Other Environmental Filing Requirements, Order No. 609, 64 FR 57374 (Oct. 25, 1999); FERC Stats. & Regs. ¶ 31,082 (1999).

27 As an alternative, Williston proposed that blanket projects that qualify for automatic authorization retain a 30-day landowner notification time period, with only larger, prior notice projects subject to a 45-day notice. Williston claims its suggestion will ensure that those parties affected by major projects, which are more likely to raise landowner concerns, will be afforded additional time, while minor and routine projects will be permitted to move forward faster.

28 In enacting the blanket certificate program, the Commission expressed its expectation that any “amendments would most likely not affect facilities constructed or service undertaken before the effective date of an amendment, but would apply prospectively.” Order No. 234-A, 47 FR 38871 (Sept. 3, 1982); FERC Stats. & Regs. ¶ 30,389; 20 FERC ¶ 61,271 (1982).

29 As a practical matter, the Commission expects noise readings to be taken at the boundary closest to the compressors or where noise is estimated to be loudest and at the site’s ordinal points.

30 71 FR 36276 at 36289 (June 26, 2006); FERC Stats. & Regs. ¶ 32,606 at 32,894 (2006); 115 FERC 61,338 at P 101 (2006) (footnote omitted). See, e.g., Rockies Express Pipeline LLC, 116 FERC ¶ 61,272 at P 69-73 (2006).

31 APGA’s Comments at 12 (Aug. 25, 2006).

32 71 FR 36276 at 36289 (June 26, 2006); FERC Stats. & Regs. ¶ 32,606 at 32,894 (2006); 115 FERC ¶ 61,338 at P 102 (2006).

28