RM07-10-000FROMBjust.wpd

FERC Form No. 552 Final Rule (Docket No. RM07-10-000)

Issued: December 26, 2007 (Docket No. RM96-1-011)

Issued December 17, 1998

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Supporting Statement for

FERC Form 552, Annual Report of Natural Gas Transactions

As Proposed In Docket No. RM07-10-000 & AD 96-1-015

(Final Rule Issued December 26, 2007)

The Federal Energy Regulatory Commission (Commission) requests Office of Management and Budget (OMB) review and approval of FERC Form 552, Annual Report of Natural Gas Transactions. FERC Form No. 552 (Form No. 552) is a new data requirement that amends Part 284 of the Commission’s regulations in order to facilitate market transparency in natural gas markets as proposed in a Final Rule. (In a NOPR issued on April 19, 2007, in Docket No. RM07-10-000 the Commission also proposed FERC-551 “Reporting of Flow Volume and Capacity by Intrastate Pipelines”. In response to the many comments received concerning FERC-551, the Commission is addressing those comments which also prompted additional inquiries in a separate rulemaking “Pipeline Posting Requirements under Section 23 of the Natural Gas Act.”(RM08-2-000)) RM08-2-000 will be submitted to OMB separately.

We estimate that the total annual reporting-burden related to the subject Final Rule will be 6,000 hours under Form 552 or unchanged from the Commission’s estimate in the NOPR. This is equal to an average of 4 hours per company under Form No. 552. All of the changes in the subject final rule are provided for under sections 4 and 5 of the Natural Gas Act (NGA), and new section 23 of the NGA as added by section 316 of the Energy Policy Act of 2005 (EPAct 2005).

Background

The Commission’s market-oriented policies for the wholesale electric and natural gas industries require that interested persons have broad confidence that reported market prices accurately reflect the interplay of legitimate market forces. Without confidence in the basic processes of price formation, market participants cannot have faith in the value of their transactions, the public cannot believe that the prices they see are fair, and it is more difficult for the Commission to ensure that jurisdictional prices are “just and reasonable”¹.

The performance of Western electric and natural gas markets early in the decade shook confidence in posted market prices for energy. In examining these markets, the Commission’s staff found, inter alia, that some companies submitted false information to the publishers of natural gas price indices, so that the resulting reported prices were inaccurate and untrustworthy.² As a result, questions arose about the legitimacy of published price indices, remaining even after the immediate crisis passed. Moreover, market participants feared that the indices might have become even more unreliable, since reporting (which has always been voluntary) declined to historically low levels in late 2002.

The Commission recognized staff concerns about price discovery in electric and natural gas markets as early as January 2003, when, prior to passage of EPAct 2005, the Commission made use of its existing authority under the Natural Gas Act and the Federal Power Act to restore confidence in natural gas and electricity price indices. The Commission expected that, over time, improved price discovery processes would naturally increase confidence in market performance. On July 24, 2003, the Commission issued a Policy Statement on Electric and Natural Gas Price Indices (Policy Statement) that explained its expectations of natural gas and electricity price index developers and the companies that report transaction data to them.³ On November 17, 2003, the Commission adopted behavior rules for certain electric market participants in its Order Amending Market-Based Rate Tariffs and Authorizations relying on section 206 of the Federal Power Act to condition market-based rate authorizations,⁴ and for certain natural gas market participants in Amendments to Blanket Sales Certificates, relying on section 7 of the Natural Gas Act to condition blanket marketing certificates.⁵ The behavior rules bar false statements and require certain market participants, if they report transaction data, to report such data in accordance with the Policy Statement. These participants must also notify the Commission whether or not they report prices to price index developers in accordance with the Policy Statement.⁶ On November 19, 2004, the Commission issued an order that addressed issues concerning prices indices in natural gas and electricity markets and adopted specific standards for the use of price indices in jurisdictional tariffs.⁷

Congress recognized that the Commission might need expanded authority to mandate additional reporting to improve market confidence through greater price transparency and included in the Energy Policy Act of 2005 (EPAct 2005)⁸ authority for the Commission to obtain information on wholesale electric and natural gas prices and availability. Under the Federal Power Act⁹ and the Natural Gas Act¹⁰, the Commission has long borne a responsibility to protect wholesale electric and natural gas consumers. EPAct 2005 emphasized the Commission’s responsibility for protecting the integrity of the markets themselves as a way of protecting consumers in an active market environment. In particular, Congress directed the Commission to facilitate price transparency “having due regard for the public interest, the integrity of [interstate energy] markets, [and] fair competition.”¹¹ In the new transparency provisions of section 23 of the Natural Gas Act and section 220 of the Federal Power Act, Congress provided that the Commission may, but is not obligated to, prescribe rules for the collection and dissemination of information regarding the wholesale, interstate markets for natural gas and electricity, and authorized the Commission to adopt rules to assure the timely dissemination of information about the availability and prices of natural gas and natural gas transportation and electric energy and transmission service in such markets.

Consistent with the directive to facilitate price transparency in natural gas and electric markets as well as to explore options for action under EPAct 2005’s expansion of the Commission’s authority, Commission staff met with interested entities in the summer of 2006. On September 26, 2006, staff conducted a workshop to review sources of energy market information with interested persons and to lay the groundwork for a technical conference held on October 13, 2006. In that conference, ideas for potential policy actions by the Commission were identified.

NOPR (Docket No. RM07-10-000)

On April 19, 2007 as noted above, in Docket No. RM07-10-000 “Transparency Provisions of Section 23 of the Natural Gas Act; Transparency Provisions of the Energy Policy Act” the Commission made two proposals to facilitate market transparency in natural gas markets. The first proposal, designed to make available the information needed to track daily flows of natural gas throughout the United States, would create a requirement that intrastate pipelines post daily to the Internet the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments.

The second proposal and the subject of the final rule, was designed to permit the annual estimate of (a) the size of the physical domestic natural gas market, (b) the use of index pricing in that market, (c) the size of the fixed-price trading market that produces price indices from the subset reported to index publishers, and (d) the relative size of major traders, would create an annual requirement that buyers and sellers of more than a de minimis volume of natural gas report numbers and volumes of relevant transactions to the Commission. As part of this proposal, the Commission would require each holder of blanket marketing certificate authority or blanket unbundled sales services certificate authority to notify the Commission as to whether it reports its transactions to publishers of electricity or natural gas price indices and whether any such reporting complies with certain standards. Currently, a holder of a blanket marketing certificate or a blanket unbundled sales service certificate is required to notify the Commission only when it changes its practice regarding such reporting. This part of the proposal would make notifications of reporting status more reliable.

Subject Final Rule (Docket No. RM07-10-000)

On December 26, in Docket No. RM07-10-000, the Commission issued a final rule that implements regulations to require certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, and to report annually certain information regarding their wholesale, physical natural gas transactions for the previous calendar year. Certain market participants engaged in a de minimis volume of transactions will not be required to report information regarding their transactions for the calendar year. The reported information will make it possible to estimate the size of the physical U.S. natural gas market, to assess the use of index pricing in that market, and to determine the size of the fixed-priced trading market that produces the information. These regulations facilitate price transparency in markets for the wholesale sale of physical natural gas in interstate commerce. The final rule is the Commission’s first exercise of transparency authority under section 23 of the Natural Gas Act. It requires market participants to file a new form regarding their annual purchases and sales, Form No. 552. These regulations implement the Commission’s expanded authority under section 23 of the Natural Gas Act,¹² which was added by the Energy Policy Act of 2005 (EPAct 2005) to require reporting from entities not under the Commission’s traditional jurisdiction.¹³

The Commission largely adopts the annual reporting proposal in the NOPR, with a few changes and a few clarifications. The final rule requires that any buyer or seller of more than a de minimis volume of natural gas report aggregate volumes of relevant transactions in an annual filing using Form No. 552. A market participant buying or selling less than a de minimis volume that operates under blanket sales certificate authority pursuant to § 284.402 or § 284.284 of the Commission’s regulations must also submit a Form No. 552 for identification and certain reporting purposes, but is not required to report aggregate volumes of relevant transactions. A market participant that buys or sells less than a de minimis volume but that does not operate under blanket sales certificate authority need not submit a Form No. 552.

The significant changes from the proposal in the NOPR fall generally into four categories. The first category of changes focuses the reporting requirement solely on wholesale buyers and sellers by excluding retail transactions. The second category of changes, intended to focus on price formation in the spot markets, narrows the questions on new Form No. 552 to obtain information about the amount of daily or monthly fixed-priced trading that are eligible to be reported to price index publishers as compared to the amount of trading that uses or refers to price indices. The third category of changes expands the number of companies that must state publicly whether or not they report to index price publishers. The last category involves other clarifications of questions raised in comments and changes made to streamline completion of the form.

A. Justification

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

Pursuant to sections 4, 5, and 16 of the NGA, (15 USC 717c ‑ 717o, P.L. 75‑688, 52 Stat. 822 and 830), and Title III of the NGPA, (15 USC 3301‑3432, P.L. 95‑621), a natural gas company must obtain Commission authorization for all rates and charges made, demanded, or received in connection with the transportation or sale of natural gas in interstate commerce. The Commission is authorized to investigate the rates charged by natural gas pipeline companies subject to its jurisdiction. If, after the investigation, the Commission is of the opinion that the rates are "unjust or unreasonable or unjustly discriminatory or unduly preferential," it is authorized to determine and prescribe just and reasonable rates. The NGA also provides the Commission with a means for considering the reasonableness of rates through settlement conferences or hearings.

With the passage of EPAct 2005, Congress affirmed a commitment to competition in wholesale natural gas and electricity markets as national policy, the fifth major federal law in the last 30 years to do so.¹⁴ As part of this commitment to competition, in the transparency provisions, Congress charged the Commission with assuring the integrity of the wholesale markets and assuring fair competition by facilitating price transparency in those markets. It also significantly strengthened the Commission’s regulatory tools in the transparency provisions, specifically, in new section 220 of the Federal Power Act and new section 23 of the Natural Gas Act.

In new section 23(a) (1) of the Natural Gas Act, Congress provided the Commission’s mandate:

The Commission is directed to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, having due regard for the public interest, the integrity of those markets, fair competition, and the protection of consumers.¹⁵

In new section 23(a) (2) of the Natural Gas Act, Congress left to the Commission’s discretion whether to enact rules to carry out this mandate and provided that any rules implementing the transparency provisions provide for public dissemination of the information gathered:

The Commission may prescribe such rules as the Commission determines necessary and appropriate to carry out the purposes of this section. The rules shall provide for the dissemination, on a timely basis, of information about the availability and prices of natural gas sold at wholesale and in interstate commerce to the Commission, State commissions, buyers and sellers of wholesale natural gas, and the public.¹⁶

In new section 23(a)(3) of the Natural Gas Act, Congress contemplated that the transparency provisions would differ from other provisions in the Natural Gas Act, both as to the entities covered by the Commission’s jurisdiction and the possible involvement of third parties in implementing the rules. That section reads, with emphasis added:

The Commission may –

(A) obtain the information described in paragraph (2) [i.e., information about the availability and prices of natural gas sold at wholesale and interstate commerce] from any market participant; and

(B) rely on entities other than the Commission to receive and make public the information, subject to the disclosure rules in subsection (b).¹⁷

Finally, new section 23(d) (2) of the natural gas transparency provisions mandates an exemption from any reporting for “natural gas producers, processors, or users who have a de minimis market presence….”¹⁸ This paragraph does not exempt all producers and all processors from reporting, but exempts only producers that have a de minimis market presence and only processors that have a de minimis market presence.

Specifically, the Commission adopts rules to require certain market participants to report annually information about their wholesale, physical natural gas transactions delivered in the previous calendar year in the United States on Form No. 552. For purposes of the annual reporting requirement, a market participant is defined as “any buyer or seller that engaged in wholesale, physical natural gas transactions in the previous calendar year.”¹⁹ Specifically, on Form No. 552, a market participant must provide the Commission with contact information and answer questions about whether it sells pursuant to a blanket sales certificate and whether it reports to price index publishers. A market participant that sold or purchased more than a specified de minimis volume of natural gas during the previous calendar year, regardless of whether it holds a blanket sales certificate, must also provide the following information:

•the total volume of transactions for the previous calendar year;

•the volume of transactions that were priced at fixed prices for next-day delivery and were reportable to price index publishers;

•the volume of transactions priced by reference to next-day gas price indices;

•the volume of transactions that were priced at fixed prices for next-month delivery and were reportable to price index publishers; and,

•the volume of transactions priced by reference to next-month gas price indices.

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

Congress directed the Commission to “facilitate price transparency in markets for the sale… of physical natural gas in interstate commerce,” but that language does not limit the Commission to seeking information regarding only sales.²⁰ Purchases of physical natural gas are also a part of such markets; there is no market for the sale of natural gas that does not include purchases. Nor does the natural gas transparency provision language that provides for the “dissemination… of information about the availability and prices of natural gas sold at wholesale and interstate commerce” restrict the Commission.²¹ As a practical matter, information regarding purchases of natural gas is necessary to evaluate the reliability of information regarding sales of natural gas. The information is necessary to obtain a useful gauge of price transparency in natural gas markets. The annual filing of transaction information by market participants is necessary to provide information regarding the size of the physical natural gas market, the use of the natural gas spot markets and the use of fixed and index price transactions.

The final rule retains several of the specific proposals presented in the NOPR: the de minimis threshold is to remain the same; all filings are to be made public; both purchases and sales are to be reported; and the filing will be annual. The final rule makes several changes to the proposal in the NOPR. They include the following:

•Reporting will be limited to buyers and sellers only of wholesale natural gas delivered in the United States, i.e., it excludes sales to end-users.

•All wholesale buyers and sellers of natural gas operating under a blanket sales certificate and all others buying or selling more than the de minimis volume must provide contact information; indicate whether they are operating under a blanket sales certificate, and whether they report prices to an index publisher. In the NOPR, the Commission did not propose asking wholesale buyers and sellers that are not operating under a blanket sales certificate whether they report prices to index publishers.

•A company with multiple affiliates may choose to report separately or in aggregate, as best meets its needs. In the NOPR, we assumed that reporting would be by affiliate or subsidiary.

•The questions on the form now request data relating to transactions with expected deliveries in the reporting year, rather than transaction dates.

•The form no longer requests the number of transactions.

•The definitions of fixed-price transactions in the form have been changed to tie more directly to those volumes that could be reported to index providers. To clarify those terms, the Commission will establish a web site defining reportable locations previous to each reporting year, and providing links to active index publishers and their reporting definitions.

The final rule includes further instructions regarding certain specific categories of reportable and non-reportable transactions.

By obtaining the volume of transactions conducted for each significant market participant, the Commission, market participants and others will be able to determine the overall level of activity of market participants in the physical natural gas market. In particular, the information will provide regularly an estimate of (a) the size of the physical U.S. domestic natural gas market, (b) the use of index pricing in that market, (c) the size of the fixed-price trading market that produces price indices, and (d) the relative sizes of major traders.

This information will improve the understanding of index pricing by interested entities, including the market participants and state commissions who use them. The volume break-down of transactions by price type, fixed-price or index-price, should permit an overall assessment of the ratio of index-using transactions to price-forming transactions, i.e., fixed-price transactions. At present, the Commission does not know how much fixed-price transactions are a part of the universe of natural gas transactions, although they may be the minority of natural gas transactions.²² The Commission has taken several steps to restore confidence in natural gas index prices and their formation. By obtaining information regarding the extent that market participants make fixed-price transactions, market participants will be able to evaluate their confidence in the index prices that are formed by those fixed-price transactions.

By collecting sales and purchases information, results may also be cross-checked to ensure that information is accurate. In effect, total sales should roughly equal total purchases, with some allowance for de minimis buyers and sellers.

FERC Form No. 552 Annual Reporting of Natural Gas Transmission

Under the proposed reporting requirement, certain natural gas buyers and sellers would identify themselves to the Commission and report summary information about physical natural gas transactions for the previous calendar year including: (a) their total amount of physical²³ natural gas transactions by number and volume; (b) the breakdown of their transactions by purchases and sales; (c) the number and volume breakdown of their purchases and sales by whether they were conducted in monthly or daily spot markets; and, (d) the number and volume breakdown of their purchases and sales by type of pricing, in particular whether that pricing was fixed or indexed.

The final rule will also require a market participant to report whether it operated under a blanket sales certificate under the Commission’s regulations, § 284.402 or § 284.284. This information will allow the Commission to measure overall market activity of the entities subject to its jurisdiction under the Natural Gas Act as well as allow the Commission to maintain records of such entities. The final rule will require a market participant to indicate whether it reports transactions to any price index publishers, and, if so, whether their reporting conforms to the standards set forth in § 248.403 or § 248.288, as applicable. This information will allow the Commission to ensure the accuracy of price indices and to monitor adherence to the Commission’s transaction reporting standards.

Specifically, the final rule requires reporting by a market participant – that is – by any buyer or seller of physical natural gas that either:

1. holds a blanket sales certificate or

2. buys or sells more than 2.2 million MMBtu of wholesale, physical natural gas annually.

On Form No. 552, a market participant must report three categories of information:

First, whether it holds a blanket sales certificate.

Second, whether it reports transaction prices to a price index publisher, and if so, whether it’s reporting follows the Commission’s policy for reporting to price index publishers.

Third, a market participant must provide information about the annual volume of physical, natural gas transactions, aggregated for the entire year and aggregated nationally.

FERC Form No. 552 is to be filed on May first of each calendar year, starting May 1, 2009 for calendar year 2008.

In summary: The form will aid the Commission and market observers in determining how price indices are formed and used. The stated goal is not only to understand the transactions used to form price indices, it is also to understand how influential price indices are in the valuation of natural gas in U.S. wholesale markets. In addition, the information reported would allow the Commission and other market observers to answer the question: how much volume is transacted in the physical natural gas market?

The annual filing of transaction information by market participants is necessary to provide information regarding the size of the physical natural gas market, the use of the natural gas spot markets and the use of fixed and index price transactions.

The final rule will facilitate transparency of the price formation process in natural gas markets by collecting information to understand in broad terms the size of the natural gas market and the use of fixed prices and of index prices. Currently, because of the way transactions take place in the natural gas industry, there is no way to estimate in even the broadest terms the overall size of the natural gas market or its breakdown by types of contract provision, including pricing and term (e.g., spot or for delivery farther in the future).²⁴ As noted by the price index developer Platts, the question of what is the total size of the traded market has “hung over the gas market for years.”²⁵ More particularly, there is no way to determine important volumetric relationships between (a) the fixed-price, day-ahead or month-ahead transactions that form price indices; and (b) transactions that use price indices. Without the most basic information about these volumetric relationships, the Commission has been hampered in its oversight and its ability to assess the adequacy of price-forming transactions. Market participants are likewise unable to evaluate their use of indexed transactions. Typically, market participants rely on index-priced transactions as a way to reference market prices without taking on the risks of active trading. These market participants rely on index prices, often whether or not those prices are derived from a robust market of fixed-price transactions.

3. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE BURDEN AND 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. To alleviate the burden to respondents, they may file Form No. 552 electronically with the Commission.

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION 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 have been found. The Commission staff is continuously 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.).

Calpine Corporation (Calpine) contended that the Commission should avoid collection of information that is available elsewhere. As an example, Calpine suggested that a market participant that submits information on its fossil-fuel purchases to the U.S. Department of Energy’s Energy Information Administration (EIA) not be required to file an annual report at the Commission.²⁶

Commission Response

The information sought in the final rule is not obtainable elsewhere. Section 23(a)(4) of the Natural Gas Act requires the Commission to “consider the degree of price transparency provided by existing price publishers and providers of trade processing services….”²⁷ As the Commission stated in the NOPR, because of the way transactions currently take place in the natural gas industry, there is no way to estimate in even the grossest terms the overall size of the natural gas market or its breakdown by types of contract provision, including pricing (fixed prices or prices using or referring to price indices) and term (e.g., spot transactions for next-day or next-month delivery or forward transactions for longer-term delivery).²⁸ Further, currently there is no way to determine important volumetric relationships between the fixed-price, day-ahead or month-ahead transactions that form price indices or to determine the use of price indices themselves.

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

The annual reporting requirement set forth in the final rule will not have a significant economic impact on a substantial number of small entities. By incorporating a de minimis exemption into the regulations, the Commission has reduced the number of small entities subject to the requirements: de minimis entities without blanket sales certificates will not be required to report. (The Commission has defined a de minimis market participant as a market participant that engages in physical natural gas transactions that amount by volume to less than 2,200,000 MMBtus annually. ²⁹ This figure is based on the rather simple calculation of one-ten thousandth (1/10,000th) of the annual physical volumes consumed in the United States, which is approximately 22 trillion cubic feet (Tcf) (or roughly 22,000,000,000 MMBtus).³⁰ Consequently, a de minimis market participant would trade the equivalent of less than one standard NYMEX futures contract per day. Although a market participant that contracts for 1/10,000th of the nation’s annual physical volume may appear to have little effect on natural gas prices, that participant may be transacting only at one location and, thus, have a much greater pricing effect there. Although the Commission does not expect annual physical volumes consumed in the United States to remain constant, the figure of 22 Tcf is a useful snapshot of consumption and a useful starting-point for setting the de minimis exemption.) The Commission would impose these requirements on all blanket certificate holders regardless of size.³¹

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

The annual filing of transaction information by market participants is necessary to provide information regarding the size of the physical natural gas market, the use of the natural gas spot markets and the use of fixed and index price transactions. This reporting frequency meets the provisions of OMB’s guidance. (See item number 8 for further discussion on filing frequency).

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

These proposed information collection requirements meet all of OMB's section 1320.5 requirements.

The data provided in FERC-552 will be an annual filing with the Commission that will be filed electronically using Commission developed software and downloaded from its web site.

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. On the basis of the comments, the Commission has determined to adopt in large part the proposed annual reporting of certain natural gas transaction information, but to modify its proposal in several ways. Below are summaries of issues raised by commenters and the Commission’s response.

Jurisdiction

No commenter asserted that the Commission lacked jurisdiction to implement the annual reporting proposal or lacked jurisdiction over market participants required to report, i.e., “any buyer or seller that engaged in wholesale physical natural gas transactions the previous calendar year.”³²

The vast majority of commenters on this issue supported the annual reporting proposal, although many suggested refinements. For instance, MidAmerican Energy Company and PacifiCorp (MidAmerican) supported the reporting proposal and praised FERC’s “sensible approach,” which would “help market participants and state and federal regulators better understand the natural gas market and pricing process.”³³ Similarly, Wisconsin Electric Power Company and Wisconsin Gas Company LLC (the Wisconsin Companies) supported the reporting proposal stating that the “benefits of such a reporting regime outweigh the expenditures of resources necessary to implement.”³⁴ The Wisconsin Companies cautioned, however, that “[a]ny further frequency or granularity in the reporting requirements … would be unduly burdensome.”³⁵ The Wisconsin Companies proposed changes to the information reported; suggesting a simple breakdown for transaction information between monthly or daily spot markets would be insufficient and suggesting obtaining information about transactions of longer than a month and intraday transactions.³⁶ The Wisconsin Companies reasoned that these categories of transactions “make up a substantial amount of the purchases and sales conducted by the Companies and therefore need to be included in the reporting.”³⁷

The Public Service Commission of New York (PSCNY) supported the annual reporting proposal as a way to “provide critical information to analyze the important volumetric relationships between the fixed-price day-ahead or month-ahead transactions that form price indices.”³⁸ The Producer Coalition³⁹ also supported the annual reporting proposal as a way to create greater market confidence and transparency. The information obtained from the requirement, according to the Producers Coalition, would result in greater understanding of the prices and availability of physical natural gas in interstate commerce and allow for assessment of the ratio of fixed-price transactions to index-priced transactions.⁴⁰ AGA supported the annual reporting of transaction data “because it could provide valuable information regarding the size of the physical natural gas markets.”⁴¹

In opposition to the annual reporting proposal, Morgan Stanley Capital Group Inc. (MSCG) contended that the Commission did not establish in the NOPR a clear connection between the required annual reporting and the statutory goal to achieve price transparency in the physical gas markets.⁴² For its part, MSCG asserted its confidence in the markets and contended it did not need the information that would be provided through the annual reporting requirement proposal.⁴³ MSCG observed that the price indices are already good and are getting better which renders any annual reporting requirement an unnecessary burden.⁴⁴ MSCG described the proposal as an “additional regulatory intervention to benefit the publishers’ commercial enterprise.”⁴⁵ Also in opposition, DCP Midstream LLC (DCP) objected to the annual reporting proposal as unnecessary given that there are other sources available for the information sought in the proposal.⁴⁶

Platts, a price index publisher, proposed revisions to the annual reporting proposal. Platts contended that as drafted the annual reporting proposal could provide misleading information regarding the universe of fixed-price transactions and create a misleading comparison of fixed-priced transactions and index-priced transactions.⁴⁷ This problem arises, according to Platts, because the proposed definition of fixed-price transactions lumped together two categories of fixed-price transactions: (a) fixed-price transactions that are eligible for inclusion in a published price index (“indexable” as described by Platts); and (b) fixed-price transactions that are not eligible. Without distinguishing these two categories, the information reported could not be used to determine the percentage of fixed-price transactions that are reported to price index publishers.⁴⁸ Platts summarized the problem: “the proposed reporting form would sweep up far more physical fixed-price deals than are eligible for inclusion in Platts’s indices. Rather than enabling a comparison of apples to apples, it would compare apples and fruit salad.”⁴⁹

To avoid this problem, Platts recommended that the Commission distinguish between “transactions that are eligible to be included in [published price] indices and those that are not.”⁵⁰ In support of this recommendation, American Public Gas Association (APGA) advocated changing the survey form to obtain data to determine “what proportion of reportable fixed-price transactions is actually being reported” to index publishers.⁵¹ APGA asserted that, when survey data are collected, FERC should “be able to determine once and for all whether the indices, on the basis of which hundreds of millions of dollars of natural gas are traded, are grounded in fixed-price transactions representing most of the fixed-price transactions being consummated in the market.”⁵²

Platts, in its comments, also suggested that all companies – not just blanket certificate holders – notify the Commission annually of their price reporting status.⁵³ Additionally, Platts suggested that all companies affirm that their price reporting practices comply with the Policy Statement procedures.⁵⁴

Commission Response

By using the term “any market participant,” Congress deliberately expanded the universe subject to the Commission’s transparency authority beyond the entities subject to the Commission’s rate and certificate jurisdiction under other parts of the Natural Gas Act. The term “market participant” is not defined in the Natural Gas Act and is not on its face limited to otherwise jurisdictional entities.

Congress could have limited the scope of entities subject to the Commission’s transparency authority by referring to “natural gas company” as defined in the Natural Gas Act⁵⁵ or by referring to sections 1, 3, or 7 of the Natural Gas Act⁵⁶. The former approach would have excluded intrastate pipelines from the Commission’s transparency authority. The latter approach would have entailed the jurisdictional limitations of those sections, which exclude from the Commission’s jurisdiction first sales, sales of imported natural gas, sales of imported liquefied natural gas, and sales and transportation by entities engaged in production and gathering, local distribution, “Hinshaw” pipelines, or vehicular natural gas.⁵⁷ These limitations do not apply to the Commission’s transparency authority. Given Congress’ use of the term “market participant,” the Commission’s transparency authority includes any person or form of organization, including, for instance, natural gas producers, processors and users.

The Commission’s authority to obtain information from “any market participant” is not plenary. In the natural gas transparency provisions, Congress limited that authority in two respects: the scope of the markets at issue and the type of information to obtain and disseminate.

First, Congress directed the Commission to “facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce….”⁵⁸ Thus; any information collected and disseminated must be for the purpose of price transparency in those markets. The Commission does not interpret this language to limit its ability to obtain information only about physical natural gas sales or transportation in those markets, provided that the information obtained and disseminated pertains to price transparency in those markets. Second, Congress provided that any rules “provide for the dissemination, on a timely basis, of information about the availability and prices of natural gas sold at wholesale and in interstate commerce….”⁵⁹ Thus, the Commission’s authority is limited to “information about the availability and prices of natural gas sold at wholesale and in interstate commerce.”⁶⁰ Again, this language does not limit the type of information the Commission could collect to implement its mandate, provided that such information is “about” (i.e., pertains to) the “availability and prices of natural gas sold at wholesale and in interstate commerce.” For instance, some transportation or sales of natural gas is not in interstate commerce, but, nonetheless, would affect the availability and prices of natural gas at wholesale and in interstate commerce.

The natural gas transparency provisions further provide that the Commission shall “rely on existing price publishers and providers of trade processing services to the maximum extent possible.”⁶¹ Thus, Congress authorized the Commission to rely on third parties to collect and disseminate transparency information. The Commission does not herein authorize or empower third parties to collect or disseminate information. Nonetheless, the Commission expects that third parties may use the information collected pursuant to the Final Rule and repackage it, if sufficient demand for such services arises in the information marketplace.

Also, in the transparency provisions, Congress cautioned the Commission in providing for any dissemination of information pursuant to the transparency provisions to ensure that “consumers and competitive markets are protected from the adverse effects of potential collusion or other anticompetitive behaviors by untimely disclosure of transaction-specific information.”⁶²

De Minimis Threshold

In the NOPR, the Commission proposed to define a de minimis market participant as a market participant that engages in physical natural gas transactions that amount by volume to less than 2,200,000 MMBtus annually and to exclude such de minimis market participants from reporting transaction information.⁶³ Several commenters sought to increase the de minimis threshold.⁶⁴ MSCG supported a higher de minimis volume based on 200 standard futures contracts per day as a way to focus only on large sellers.⁶⁵ Northwest Industrial Gas Users (Northwest Industrials) argued for increasing the annual volume threshold significantly from the proposed 2,200,000 MMBtus per year to 136,000,000 MMBtu per year.⁶⁶ Independent Oil & Gas Association of West Virginia proposed a greater de minimis threshold of 10,000,000 MMBtu/year.⁶⁷ A greater de minimis threshold would reduce the burden, it contended, for some of its small producer-members.⁶⁸ The Wisconsin Companies called for a greater de minimis threshold because the threshold set forth in the NOPR uses “physical volumes consumed [and, thus], may ignore the reality of daisy chain sales; that is, many transactions can occur before natural gas ultimately reaches the consumer.”⁶⁹

Some commenters supported the Commission’s proposed de minimis threshold.⁷⁰ The Texas Alliance of Energy Producers (Texas Alliance) contended that the de minimis threshold for annual transaction reporting is reasonable.⁷¹ IPAA advocated setting the de minimis threshold as a function of the market size rather than setting it as a fixed number.⁷²

The Interstate Natural Gas Association of America (INGAA) sought clarification that a de minimis market participant need only file basic identification and whether it reports transactions to index price publishers.⁷³

Commission Response

In the final rule, the Commission retains the volumetric de minimis threshold proposed in the NOPR and clarifies its application.⁷⁴ A market participant is required to report its transactions annually if it engages either in wholesale sales that amount to 2,200,000 MMBtus or more or wholesale purchases that amount to 2,200,000 MMBtus or more. Each market participant operating under a blanket certificate under §284.284 or §284.402 must file a Form No. 552. However, if a market participant operating under a blanket certificate under §284.284 or §284.402 buys or sells less than the de minimis volumes in the reporting year, it is not required to provide information about the volumes of its transactions. A market participant that does not operate under a blanket certificate under § 284.284 or § 284.402, and that buys or sells less than the de minimis volumes in the reporting year, is not required to file a Form No. 552. The creation here of a de minimis threshold is consistent with the transparency provisions. Notwithstanding Congress’s broadening of the scope of the Commission’s jurisdiction in new section 23 of the Natural Gas Act with respect to transparency, Congress mandated that the Commission exempt “natural gas producers, processors or users who have a de minimis market presence [from compliance] with the reporting requirements of this section.”⁷⁵

In proposing in the NOPR a de minimis threshold for reporting which would apply to market participants, the Commission sought to require reporting from a sufficient number of significant market participants to ensure, in the aggregate, an accurate picture of the physical natural gas market as a whole. To this end, the Commission proposed in the NOPR to define such a de minimis market participant as a market participant that engages in physical natural gas transactions that amount by volume to less than 2,200,000 MMBtus annually. ⁷⁶ This figure was based on the simple calculation of one-ten thousandth (1/10,000th) of the annual physical volumes consumed in the United States, which is approximately 22 trillion cubic feet (Tcf) (or roughly 22 billion MMBtus).⁷⁷ Looked at another way, a de minimis market participant would trade the equivalent of less than one standard NYMEX futures contract per day. Although a market participant that contracts for 1/10,000th of the nation’s annual physical volume may appear to have little effect on natural gas prices, that participant may be transacting only at one location and, thus, have a much greater pricing effect there. In the NOPR, the Commission indicated that it does not expect annual physical volumes consumed in the United States to remain constant, however the figure of 22 Tcf was a useful snapshot of consumption and a useful starting-point for setting the de minimis exemption.

As requested by INGAA, the Commission clarifies in the final rule that each market participant that (a) either holds a blanket certificate under § 284.284 or § 284.402, or (b) buys or sells more than the de minimis volumes in the reporting year must report: identification information; whether it holds a blanket certificate under § 284.284 or § 284.402; whether it reports transactions to price index publishers, and, if so, whether its reporting conforms to the applicable regulations. A market participant that holds a blanket certificate under § 284.284 or § 284.402 but that buys or sells less than the de minimis volumes in the reporting year must complete the form except it need not report its volumes.

Several commenters, including MSCG,⁷⁸ Northwest Industrial Gas Users,⁷⁹ and the Independent Oil & Gas Association of West Virginia,⁸⁰ proposed greater de minimis thresholds. Other commenters, including the Texas Alliance,⁸¹ supported the proposed threshold. No commenter suggested a lesser threshold. In response, the Commission believes the proposed threshold is small enough to allow it to accurately determine the size of the physical natural gas market, while at the same time, large enough to exclude market participants, who in the aggregate, do not contribute significantly to that market.

The spot wholesale natural gas markets that create index prices – those markets that involve fixed-price trading for next-day or next-month delivery at reportable locations and that are actually reported to price index publishers – make up only a tiny part of the overall wholesale natural market in the United States. This is true whether one compares those particular trading volumes to total U.S. consumption or whether, as Wisconsin Companies points out in their comments⁸² (in support of a higher de minimis threshold) an appropriate total trading volume would also include those transactions that take place between the production and consumption of natural gas. When the spot wholesale natural gas markets that create index prices are then broken down among many varied geographical locations, even very small market participants can be very important in narrow regional contexts. It is conceivable that these small, local wholesale market participants do not actually contribute to price formation in this type of trading, but the Commission and other market observers are in no position to know at this time. If these small, local wholesale market participants do contribute to this type of price formation – which would be a healthy thing for these markets – such contribution would not be detectable if the de minimis threshold were set too high.

Exclusion of Certain Transactions

Commenters sought to exclude certain transactions from the reporting requirement. INGAA sought to exclude interstate pipeline transactions associated with cash-out and operations because such information is already reported by some in Form No. 2 and on electronic bulletin board (EBB) postings and because such operational transactions would only distort assessment of the quantity of gas available for trading in the interstate market.⁸³ The Oklahoma Independent Petroleum Association (Oklahoma IPA) sought to exclude transactions priced pursuant to a “percentage of proceeds” contract under which a producer is required to sell any gas produced and receive the percentage of proceeds realized by the buyer.⁸⁴ Oklahoma IPA argued that sellers of such contracts have no influence on the price for the sale of gas.⁸⁵ Along those lines, Oklahoma IPA argued that the de minimis threshold is too low.⁸⁶

Shell sought to exclude reporting transactions that are related to operational functions and transactions between affiliates.⁸⁷ As transactions related to operational functions, Shell included imbalance make-up, royalty-in-kind payments, gas provided for processing such as plant thermal reduction (shrinkage), and purchases and sales related to the production and gathering function.⁸⁸ Such transactions, Shell contended, are not part of the wholesale market and their reporting would not provide a meaningful benefit.⁸⁹ As to affiliate transactions, Shell noted that the Commission’s Policy Statement excludes transactions between affiliate companies.⁹⁰

MSCG supported the exclusion of financially settled transactions from the proposed reports, claiming that the Commission lacks jurisdiction over natural gas futures contracts that are not settled through physical delivery.⁹¹ Further, MSCG asserted that the Commission’s memorandum of understanding with the Commodity Futures Trading Commission could facilitate obtaining such information.⁹²

The Natural Gas Supply Association (NGSA) sought clarification that a market participant did not need to report the following transactions: 1) liquefied natural gas (LNG) import transactions prior to regasification; 2) natural gas exports from LNG liquefaction facilities; 3) transactions related to export for re-import; 4) transactions among affiliates; 5) sales and purchases in Alaska; and 5) sales to or purchases by an end-user.⁹³

Several commenters sought to exclude retail transactions involving end-use customers from reporting. In its reply comments, the American Forest & Paper Association contended that end-use customers should not be required to report end-use purchases because end-use purchases do not play a role in setting index prices.⁹⁴ NGSA sought clarification that the Commission did not intend to require the reporting of non-wholesale transactions in the annual report.⁹⁵ NGSA contended that the Commission must limit reporting to wholesale transactions made in interstate commerce because section 23 of the Natural Gas Act limits the information the Commission may obtain to wholesale transactions in interstate commerce.⁹⁶

Commission Response

Interstate pipelines must report sale and purchase volumes related to cash-outs, imbalance makeups and operations. INGAA advocated that transactions associated with cash-out and operations be excluded from Form No. 552 because similar information is available from Form No. 2 and from pipeline electronic bulletin boards (EBBs), and the volumes used are not available for trading.⁹⁷ Similarly, Shell indicated that imbalance makeup volumes should be excluded.⁹⁸ The Commission finds these commenters’ views unpersuasive. The partial availability of information on Form No. 2 submissions and through EBBs does not provide a complete view of that information in an assessment of wholesale natural gas market activity. In addition, while it is true that volumes of sales and purchases related to pipeline cash-out and operations are unlikely to be used to create price indices, such sales and purchases do use price indices as a way of transferring value among market participants. Consequently, the information is useful in assessing how spot prices are being used commercially in the nation.

Market participants must include on Form No. 552 sale and purchase volumes attributable to royalty-in-kind transactions, gas provided for processing such as plant thermal reduction, and purchases and sales related to the production and gathering function. Shell advocated excluding these transactions from reporting.⁹⁹ While these transactions may not affect the formation of price indices in wholesale markets, these transactions often make use of price indices. Again, to the extent that transfers of value take place based on price indices, it is important that the Commission and other market observers be able to understand the extent of that transfer and its dependency on price indices as well.

NGSA further sought clarification regarding transactions related to export for re-import.¹⁰⁰ The sale of these volumes, assuming they could be identified, has an effect on overall wholesale markets and could, potentially, either help create or make use of price indices, consequently they should be reported. If such transactions take place among affiliates, they should be excluded.

Non-Reportable Volumes

The instructions to Form No. 552 now explicitly exclude volumes due to transactions among affiliates. Several commenters emphasized the importance of excluding volumes transacted among affiliates.¹⁰¹ A transaction between affiliates is not part of the price formation process in wholesale natural gas markets.

Market participants may not include any type of financially-settled transaction on Form No. 552. However, transactions with physical delivery obligations must be reported – whether those transactions actually continued through delivery or not. When the physical transaction was executed, it may have either contributed to or used spot market price information regardless of its later disposition. In other words, sales or purchase obligations that were “booked out” must be included. The Commission intends “physical natural gas transaction” to mean a sale or purchase of natural gas with an obligation to deliver or receive physically, even if the natural gas is not physically transferred due to some offsetting or countervailing trade. Thus, even if the transaction does not go to physical delivery, it would still be included as a physical transaction.

In response to NGSA, ¹⁰² the Commission clarifies in the final rule that a market participant should not include volumes of imported LNG traded prior to regasification. LNG traded prior to regasification is not wholesale natural gas, though it is a source of natural gas through regasification itself. NGSA further sought clarification regarding natural gas exports from LNG liquefaction facilities.¹⁰³ LNG traded after liquefaction is also not wholesale natural gas, consequently a market participant must exclude such volumes.

Unlike in the NOPR, Form No. 552 no longer requests information on NYMEX contracts that go to physical delivery because the purpose of the form is to focus on fixed-priced spot transactions and how they are used. Further, information attributable to such contracts is available from NYMEX. Consequently, to reduce the burden on market participants, this instruction has been removed and a market participant may not include volume information related to physically-settled future contracts.

Frequency of Reporting

Several commenters support reporting no more frequently than annually. EnCana Marketing contended that reporting more frequently than annually would be burdensome while not providing a significant benefit.¹⁰⁴ MSCG contended that any reporting should be annual, unless a clear connection can be established that more frequent reporting results in greater transparency.¹⁰⁵ In contrast, the National Association of Royalty Owners (NARO) favored monthly transaction reporting rather than just annual reporting; it stated that monthly as well as regional reporting would be more useful to royalty owners, including for the monitoring of price index reliability.¹⁰⁶

Commission Response

The Commission retains from the NOPR the requirement that Form No. 552 be submitted annually. Commenters provided a variety of perspectives on the frequency of filing, but none supported less frequently than annually. NARO favored monthly, regional reporting.¹⁰⁷ EnCana Marketing and MSCG commented that more frequent reporting would not provide a significant benefit¹⁰⁸ Annual, national information alone will significantly improve both the Commission’s and others’ understanding of index pricing. Annual reporting should provide a useful amount of information to assess the volume break-down of transactions by price type, fixed-priced or index-priced, and the ratio of index-using transactions to price-forming transactions, i.e., fixed-priced transactions. A more granular breakdown, which would result from more frequent reporting or from regional reporting, would be more likely to reveal the strategies of particular market participants, raising the concerns Congress in the transparency provisions cautioned the Commission to avoid, that is, “the adverse effects of potential collusion or other anticompetitive behaviors that can be facilitated by untimely public disclosure of transaction-specific information.”¹⁰⁹

Aggregation of Data

The Wisconsin Companies call for the discretion to submit separate reports because “[a] requirement for [combination utilities] to submit a single annual report is problematic in that the separation of these business units currently prevents the sharing of market information that would be relevant to the reporting requirements.”¹¹⁰

The Electric Power Supply Association (EPSA) called for companies to have the option to file either aggregated data for all its affiliate companies that buy and sell natural gas or individual reports for each entity that buys or sells gas.¹¹¹ Similarly, Calpine Corporation called for the Commission to allow companies to aggregate data from subsidiaries in order to reduce the burden on industry and to provide the benefit of eliminating double-counting of intracompany transactions.¹¹²

NGSA wanted clarification that the annual transaction report, with a few exceptions, applies to all nonaffiliated third parties, and one report can be filed on behalf of all entities in a corporate family.¹¹³ NGSA advocated exclusion of sales between affiliates because such information would not be meaningful.¹¹⁴ NGSA contended that such exclusion is consistent with the price index reporting standards set forth in the Policy Statement, which “prohibit the reporting of sales between affiliates to price index developers.”¹¹⁵

Commission Response

In reporting transactions on Form No. 552, a market participant may, but is not required to, aggregate information from its affiliates. One commenter, Wisconsin Companies, underscored its difficulties in providing an aggregated report.¹¹⁶ Others, including EPSA, Calpine and NGSA, sought the ability to file an aggregate report. ¹¹⁷ Given the comments both for and against aggregation and the ease with which Staff can process the information in either form, the Commission is providing the option to reporting companies. A company must indicate on Form No. 552 the affiliates for which it is reporting. If an affiliate or subsidiary holds a blanket certificate pursuant to § 284.284 or § 284.402, each affiliate must report separately that it has such a certificate. Similarly, if an affiliate reports transactions to price index publishers, it must report so separately.

By contrast, asset managers may not report aggregated information for their customers in Form No. 552. Several commenters sought clarification on the reporting obligations of asset managers.¹¹⁸ It is unlikely that transactions between asset managers and their clients would be used to create price indices, although such transactions may use price indices. Given the variety and diversity of services available from asset managers, and the interest of the Commission in tracking the amount of wholesale natural gas activity that both creates and relies on spot price indices, information about the use of price indices would be lost if such aggregation were permitted.

Filing Date

In the NOPR, the Commission proposed an annual filing deadline of February 15 and asked for comment on whether this deadline would be unduly burdensome.¹¹⁹ MSCG and Statoil called for a deadline of April 30.¹²⁰ AGA recommended a filing date of May 1.¹²¹ NGSA recommended a filing date of either May 1 or April 18, which is the filing deadline of FERC Form No. 2.¹²²

Commission Response

Unlike in the NOPR, Form No. 552 will have a filing deadline of May 1 in the year after the reporting year. In this regard, the Commission agrees with the commenters who sought more time for filing than permitted by the February 15 deadline proposed in the NOPR.¹²³ Because the data used for the form would come from the accounting and other official records of the market participants reporting, the response to Form No. 552 must be coordinated with a variety of other regular annual financial and regulatory reports. May 1 was the latest filing date recommended in comments. Given the aggregate nature of the data, a time lag of four months from the reporting year should keep the information timely while providing market participants the time needed to coordinate a new regulatory filing with other obligations.

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 generally does not consider the data posted concerning transactions to be confidential. Specific requests for confidential treatment to the extent permitted by law will be entertained pursuant to 18 C.F.R. Section 388.110.

Public Filing

Several commenters supported maintaining as non-public any aggregated transaction data to be filed.¹²⁴ NGSA contended that “the annual aggregated transactional information could cause competitive harm to the market by potentially revealing corporate proprietary trading strategies of a company particularly [if it has] geographically concentrated trading or supply portfolios.”¹²⁵ Pacific Gas & Electric (PG&E) contended that data filed by market participants should be maintained as non-public for one year following the calendar year for which the data pertain to avoid revealing competitive buying strategies.¹²⁶ Enbridge contended that each entity should have the option to file information non-publicly.¹²⁷

NGSA advocated that any reporting be non-public. NGSA argued that even “annual aggregated transactional information could cause competitive harm to the market by potentially revealing corporate proprietary trading strategies of a company, particularly for companies with geographically concentrated trading or supply portfolios.”¹²⁸ NGSA explained that making public “the percentage of a company’s portfolio that is index-based or fixed-price-based and the percentage of natural gas sold in the monthly and daily markets” would reveal the company’s “procurement strategy and risk profile,” thus reducing its competitiveness in future deals.¹²⁹ To address this concern, NGSA suggested not publicly disclosing the individual company filings or “redacting the identity of the market participant making the filing.”¹³⁰

Commission Response

A market participant must submit Form No. 552, in a public filing. Some commenters objected to filing the form publicly because, in their view, public filing of the annual report could reveal confidential trading strategies.¹³¹ The Commission finds these commenters’ concerns are misplaced and ignore Congress’s directive in the transparency provisions. Public access to Form No. 552 data would comport with the transparency provisions which require that any such rules “provide for the dissemination, on a timely basis, of information… to the public.”¹³² The transparency provisions further direct the Commission to “rely on [existing price publishers and providers of trade processing services] to the maximum extent possible.”¹³³ By requiring public filings by market participants, the Commission would provide an opportunity for trade publications and commercial vendors to aggregate the information filed and provide any analysis should a desire for such services arise in the energy information marketplace.

Under the transparency provisions, the Commission is required to balance confidentiality concerns with the transparency goal that the information collected be disseminated publicly. The annual filing requirement balances these two statutory requirements. By requiring a company to file its report publicly, the requirement adheres to Congress’s directive that “[t]he rules shall provide for the dissemination, on a timely basis, of information about the availability and prices of natural gas at wholesale and in interstate commerce to the Commission, State commissions, buyers and sellers of wholesale natural gas, and the public.”¹³⁴ Because the filing requires aggregated information and does not require reporting of price information or of transaction-specific information, the annual reporting requirement adheres to Congress’s other directive “to ensure that consumers and competitive markets are protected from the adverse effects of potential collusion or other anticompetitive behaviors that can be facilitated by untimely public disclosure of transaction-specific information.”¹³⁵ The annual reporting requirement avoids facilitating anti-competitive behavior in several ways: (i) reported information would not include specific price information; (ii) reported information would be aggregated information over a period of one year and not transaction-specific information; (iii) reported information would be made on an aggregated, national level, and not by point or even region; and (iv) information would not be reported until four months after the end of the reporting year.

This approach is consistent with the opinion of the U.S. Department of Justice, which observed that the Commission “may be able to achieve the benefits of transparency while limiting its potential harm by aggregating, masking, and lagging the release of such information.”¹³⁶ The Commission determines that “masking” or permitting filings on a confidential basis is unnecessary to avoid potential harm. The aggregation of the information and lagging of public filing is sufficient to avoid such harm.¹³⁷ Any potential harm from the public filing of Form No. 552 would be minimal given the aggregation of data, both aggregation across the nation and aggregation across the calendar year, and given the lagging of the public filing of information until May 1 of the year following the reporting year. In circumstances in which any potential harm is minimal, it is not the Commission’s practice to permit confidential filings.¹³⁸ In addition, smaller market participants whose operations are limited to a smaller region of the country are likely to transact less than the de minimis amount required to report their transaction information. Further, without public filings by market participants, market observers would not be able to estimate the relative size of major traders.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE

There are no questions of a sensitive nature proposed in the subject NOPR.

12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION

The burden estimate of 6,000 hours (an average of 4 hours per entity) for information requirements/collections under FERC-552 as proposed in the subject final rule. The proposal to require market participants to file annually a form regarding their physical natural gas transactions would impose an information collection burden on market participants. Again, we presume that market participants already collect transaction information and, thus, the burden imposed by this proposed requirement is only for completing and submitting the form.

A detailed summary of FERC Form No. 552 burden estimates is shown below:

CURRENT OMB PROPOSED NEW OMB

DATA REQUIREMENT (FERC-552) INVENTORY* IN 010 NOPR INVENTORY

Estimated number of respondents : 0 1,500 1,500

Estimated number of responses per respondent: 0 1 4

Estimated number of responses per year : 0 1,500 1,500 Estimated number of hours per response : 0 4 4

Total estimated burden (hours per year) : 0 6,000 6,000

Program change in industry burden hours : + 6,000

Adjustment change in industry burden hours ; -0-

Total hours in the Final Rule + 6,000

NEM and Sequent Energy Management, L.P. (Sequent) stated that the Commission significantly underestimated in the NOPR the cost burden imposed by the annual reporting proposal.¹³⁹ NEM stated an estimate that it would take approximately 200 hours annually to comply with the reporting requirement.¹⁴⁰ NEM explained that because market participants’ data is not currently stored in a format that could be used to fill out the proposed form, market participants would need to develop ancillary information technology systems to store such data at significant cost.¹⁴¹ NEM also stated that although the proposal would require annual reporting, data collection would be needed daily, which would be costly.¹⁴² Sequent pointed out that the Commission estimate overlooks the costs of legal and regulatory compliance for each annual report.¹⁴³ Sequent also stated that the cost burden estimate ignores asset management arrangements because an annual reporting requirement would trigger renegotiation of those asset management contracts.¹⁴⁴

Commission Response

In requiring annual aggregated reporting of a limited set of transactions, the Commission intends that each market participant would have the data necessary to complete Form No. 552 in the course of its business operations, for instance, in the course of preparing year-end aggregations for management, accounting and shareholder reporting purposes. The information needed to complete Form No. 552 is information that can be extracted from the market participant’s book of accounts that it would already have developed as part of its normal business operations. If a market participant buys or sells natural gas under complex arrangements, then it is likely to have an accounting system to manage the complexity and sort out the categories of purchases and sales. The Commission bases its estimated cost burden on a market participant adapting existing information to the standard format for Form No. 552 and submitting the form annually. On that basis, the Commission will retain its estimate of the cost burden as set forth in the NOPR. This estimate does not include the regulatory and compliance costs attributable to reporting as those costs are part of the overhead that market participants bear as part of their participation in Commission-regulated markets. Although Sequent asserted that asset managers would have to renegotiate contracts to provide for the annual reporting requirement, the Commission considers it likely that such asset management agreements already require collection of the transactions executed which could be used to complete Form No. 552.

13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS

The estimated annualized start-up and ongoing costs to respondents for the data collection/requirements as proposed in the subject final rule is as follows:

FERC-552

For each entity, that is required to comply with the annual reporting requirement, the Commission estimates that the compliance would require a one-time cost of approximately $4,000 and an annual cost thereafter of $400 (40 hours @$100/hr, annualized for 10 years $400 per year). Although some costs would increase for market participants with a greater number of transactions, the Commission expects that that increase would be likely offset because such entities would have already compiled information regarding their transactions in the aggregate. The Commission bases its one-time cost estimate on an assumption that it would take approximately one person one week to set up the reporting and file the report initially and that their time costs $100 per hour. The Commission bases its annual estimate on an assumption that it would take one person four hours to compile the information and that his or her time costs $100 per hour (4 hours to fill in the form @$100/hr for $400 per year). On an annualized basis, costs would amount to approximately $1,200 per entity. (See item 12 above for additional comments on cost estimates.)

	Annualized Capital/Startup Costs (10 year amortization)	Annual Costs	Annualized Costs Total
FERC-552
Transaction Reporting Requirement	$400	$400	$800

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT

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

Data Analysis Estimated FERC Forms Total Cost

Requirement of Data Salary ¹⁴⁵ Clearance One Year's

Number (FTEs) ¹⁴⁶ x Per Year + (FY '07 = Operation ¹⁴⁷

FERC-552 .5 $126,384 $ 1,896 65,088

Total .5 $126,384 1,896 $65,088

For annual transaction reporting, the burden to the Commission is for (a) creating the form electronically, (b) making sure it’s current and (c) aggregating the information annually.

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

In order to implement its authority under section 23 of the Natural Gas Act, which was added by section 316 of the Energy Policy Act of 2005 (EPAct 2005), the Commission proposes to revise its regulations to: require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the Commission in order to make possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricing in that market, and determine the size of the fixed-price trading market that produces the information. These revisions will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce.

16. TIME SCHEDULE FOR THE PUBLICATION OF DATA

Time Schedule for FERC-552 is as follows: An annual report/filing to the Commission for buyers and sellers of more than a de minimis volume of natural gas report numbers and volumes of relevant transactions. The report is designed to permit the annual estimate of (a) the size of the physical domestic natural gas market, (b) the use of index pricing in that market, (c) the size of the fixed-price trading market that produces price indices from the subset reported to index publishers, and (d) the relative size of major traders. The forms will be due May 1, 2009 for year 2008 data.

17. DISPLAY OF EXPIRATION DATE

The information to be completed on the annual filing for Form No. 552 will be obtainable from the Commission’s web site and the Commission will display the OMB control number and expiration date on the form.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

The Commission does not use statistical methodology for FERC Form No. 552.

B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS

As noted in item number 18 above, the Commission does not use statistical methodology for FERC Form No. 552.

1 See sections 4 and 5 of the Natural Gas Act, 15 U.S.C. 717c, 717d (2000); sections 205 and 206 of the Federal Power Act, 16 U.S.C. 824d, 824e (2000).

2 See Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies – Fact Finding Investigation of Potential Manipulation of Electric and Natural Gas Prices, Docket No. PA02-2-000 (August 2003).

3 Price Discovery in Natural Gas and Electric Markets, Policy Statement on Natural Gas and Electric Price Indices, 104 FERC ¶ 61,121 (Policy Statement). Subsequently, in the same proceeding, the Commission issued an Order on Clarification of Policy Statement on Natural Gas and Electric Price Indices, 105 FERC ¶ 61,282 (Dec. 12, 2003) (Order on Clarification of Policy Statement) and an Order on Further Clarification of Policy Statement on Natural Gas and Electric Price Indices, 112 FERC ¶ 61,040 (July 6, 2005) (Order on Further Clarification of Policy Statement).

4 Investigation of Terms and Conditions of Public Utility Market-Based Rate Authorizations,105 FERC ¶ 61,218, at P 1, superseded in part by Compliance for Public Utility market-Based Rate Authorization Holders, Order No. 674, 71 FR 9695 (Feb. 27, 2006), FERC Stats. and Regs. ¶31,208 (2006).

5 Amendments to Blanket Sales Certificates, Order No. 644, 68 FR 66,323 (Nov. 26, 2003), FERC Stats. and Regs. ¶ 31,153, at P 1 (2003) (citing 15 U.S.C. 717f (2000)), reh’g denied, 107 FERC ¶ 61,174 (2003) (Order No. 644-A).

6 Certain portions of the behavior rules were rescinded in Amendments to Codes of Conduct for Unbundled Sales Service and for Persons Holding Blanket Marketing Certificates, Order No. 673, 71 FR 9709 (Feb. 27, 2006), FERC Stats. and Regs. ¶ 31,207 (2006). The requirement to report transaction data in accordance with the Policy Statement and to notify the Commission of reporting status was retained in renumbered sections. 18 CFR 284.288(a), 284.403(a).

7 Price Discovery in Natural Gas and Electric Markets, 109 FERC ¶ 61,184, at P 73 (2004).

8 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005).

9 16 U.S.C. 824 et seq.

10 15 U.S.C. 717 et seq.

11 Section 23(a)(1) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(a)(1); see also section 220 of the Federal Power Act, to be codified at 16 U.S.C. 824t (identical language). Section 316 of EPAct 2005 added section 23 to the Natural Gas Act (natural gas transparency provisions); section 1281 of EPAct 2005 added section 220 to the Federal Power Act (electric transparency provisions) (together, the transparency provisions).

12 To be codified at 15 U.S.C. 717t-2.

13 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005).

14 See Energy Policy Act of 1992, Pub. L. No. 102-486, 106 Stat. 2776 (1992), codified as amended in scattered sections of 16 U.S.C.; Natural Gas Wellhead Decontrol Act of 1989, Pub. L. No. 101-60, 103 Stat. 157 (1989), codified in scattered sections of 15 U.S.C.; Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601-2645 (2000); Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3442 (2000).

15 To be codified at 15 U.S.C. 717(v)(a)(1). The electric transparency provisions of the Federal Power Act are nearly identical as to the electric wholesale markets. Section 220 of the Federal Power Act, to be codified at 16 U.S.C. 824t. Because the Commission’s proposals in the final rule address natural gas transparency, the Commission is not analyzing the electric transparency provisions, although the Commission expects that analysis of electric transparency provisions would be substantially similar.

16 To be codified at 15 U.S.C. 717t-2(a).

17 To be codified at 15 U.S.C. 717t-2(a)(3).

18 Section 23(d)(2) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(d)(2).

19 New 18 CFR 284.401(b).

20 Section 23(a)(1) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(a)(1).

21 Section 23(a)(2) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(a)(2) (emphasis added).

22Tr. at 32 (Comments of Ms. Jane Lewis-Raymond, American Gas Association) (surmising that the Commission currently cannot know the amount of fixed-price transactions and the amount of fixed-price trades that make up an index).

23 Although the standard contract for the most significant natural gas futures market traded on the New York Mercantile Exchange (NYMEX) requires physical delivery, the vast majority of those transactions do not go to delivery. For the purposes of the final rule, and despite the particulars of the futures contract language, the Commission intends to explicitly exclude volumes of futures transactions from consideration. Indeed, information about volumes of futures transactions is already publicly available through a variety of commercial means or directly through NYMEX at www.nymex.com, so collection of the information would be redundant and unnecessary.

24In its supplemental comments, Platts provided information regarding its use of physical basis transactions in compiling monthly indices. Supplemental Comments of Platt’s, Transparency Provisions of the Energy Policy Act, Docket No. AD06-11-000 (filed Feb. 23, 2007).

25Comments of Platts at 6, Transparency Provisions of the Energy Policy Act, Docket No. AD06-11-000 (filed Nov. 1, 2006).

26Calpine Comments at 4.

27Section 23(a)(4) of the Natural Gas Act; 15 U.S.C. 717t-2(a)(4) (2000 & Supp. V 2005).

28NOPR at 50 (“As noted by the price index developer Platt’s, the question of what is the total size of the traded market has ‘hung over the gas market for years.’”) (citing Comments of Platts at 6, Transparency Provisions of the Energy Policy Act, Docket No. AD06-11-000 (filed Nov. 1, 2006)).

29 Proposed 18 CFR 284.401 (defining de minimis market participant). The Commission proposes to define a market participant as “any buyer or seller that engaged in physical natural gas transactions for the previous calendar year.” Proposed 18 CFR 284.401.

30 Department of Energy, Energy Information Administration, Natural Gas Summary, Data Series: Total Consumption, 2006, http://tonto.eia.doe.gov/dnav/ng/ng_sum_lsum_dcu_nus_a.htm.

31 The Commission makes this proposal under section 4, 5 and 7 of the Natural Gas Act, 15 U.S.C. 717c, 717d, and 717f (2000), and, thus, is not required to create a de minimis exception for holders of blanket marketing certificates or for interstate pipelines that have blanket unbundled sales services certificates.

32 New 18 CFR 260.401(b).

33MidAmerican Comments at 1 & 5; see also Statoil Comments at 4-5 (supporting annual reporting requirement).

34Wisconsin Companies Comments at 4.

35Id.

36Id. at 6.

37Id.

38PSCNY Comments at 2.

39The Producer Coalition consists of three independent producers: Forest Oil Corporation; Hydro Gulf of Mexico LLC; and, Newfield Exploration Company.

40Producer Coalition at 3.

41AGA Comments at 3.

42MSCG Comments at 7.

43Id.

44Id.

45Id.

46DCP Comments at 4-6.

47Platts Comments at 4-7.

48Id. at 5.

49Id. at 7.

50Id. at 4.

51APGA Reply Comments at 1; see also AGA Reply Comments at 7 (supporting “capture” of transactions eligible to be reported to a price index publisher).

52APGA Reply Comments at 3.

53Platts Comments at 8.

54Id.

55 Section 2(6) of the Natural Gas Act, 15 U.S.C. 717a(6).

56 15 U.S.C. 717, 717b, 717f.

57 Section 1(b)-(d) of the Natural Gas Act, 15 U.S.C. 717(b)-(d); section 3 of the Natural Gas Act, 15 U.S.C. 717b; section 7(f) of the Natural Gas Act, 15 U.S.C. 717f(f); see, also, section 601(a) of the Natural Gas Policy Act, 15 U.S.C. 3431(a). The Commission has explained in a previous order that the Natural Gas Policy Act of 1978 (NGPA or Natural Gas Policy Act) and the Natural Gas Wellhead Decontrol Act of 1989 narrowed its jurisdiction under the Natural Gas Act:

Under the NGPA, first sales of natural gas are defined as any sale to an interstate or intrastate pipeline, LDC [Local Distribution Company] or retail customer, or any sale in the chain of transactions prior to a sale to an interstate or intrastate pipeline or LDC or retail customer. NGPA Section 2(21)(A) sets forth a general rule stating that all sales in the chain from the producer to the ultimate consumer are first sales until the gas is purchased by an interstate pipeline, intrastate pipeline, or LDC. Once such a sale is executed and the gas is in the possession of a pipeline, LDC, or retail customer, the chain is broken, and no subsequent sale, whether the sale is by the pipeline, or LDC, or by a subsequent purchaser of gas that has passed through the hands of a pipeline or LDC, can qualify under the general rule as a first sale on natural gas. In addition to the general rule, NGPA Section 2(21)(B) expressly excludes from first sale status any sale of natural gas by a pipeline, LDC, or their affiliates, except when the pipeline, LDC, or affiliate is selling its own production. Order No. 644 at P 14.

58 Section 23(a)(1) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(a)(1).

59 Section 23(a)(2) of the Natural Gas Act, to be codified at 15 U.S.C.717t-2(a)(2).

60 Id.

61 Section 23(a)(4) of the Natural Gas Act, to be codified at 15 U.S.C.717t-2(a)(4).

62 Section 23(b)(2) of the Natural Gas Act, to be codified at 15 U.S.C. 717t-2(b)(2).

63NOPR at P 52.

64MSCG Comments at 10; Northwest Industrial Gas Users Comments at 7-10; Independent Oil & Gas Association of West Virginia at 3-4.

65MSCG Comments at 10; see also INGAA Comments at 8 (supporting MSCG’s de minimis proposal).

66Northwest Industrials at 7-10.

67West Virginia Independents Comments at 3-4.

68Id.

69Wisconsin Companies Comments at 5.

70See, e.g., APGA Comments at 10.

71Texas Alliance Comments at 12.

72IPAA Comments at 3-4.

73INGAA Comments at 8.

74 New 18 CFR 284.401(a) (defining de minimis market participant). The regulations define a market participant as “any buyer or seller that engaged in physical natural gas transactions for the previous calendar year.” New 18 CFR 284.401(b).

75Section 23(d) (2) of the Natural Gas Act, 15 U.S.C. 717t-2 (2000 & Supp. V 2005).

76 New 18 CFR 260.401.

77U.S. Department of Energy, Energy Information Administration, Natural Gas Summary, Data Series: Total Consumption, 2006, http://tonto.eia.doe.gov/dnav/ng/ng_sum_lsum_dcu_nus_a.htm.

78MSCG Comments at 10.

79Northwest Industrial Gas Users Comments at 7-10

80Independent Oil & Gas Association of West Virginia Comments at 3-4.

81Texas Alliance Comments at 12.

82Wisconsin Companies Comments at 5.

83Id. at 9.

84Oklahoma IPA Comments at 3.

85Id. at 3; see also Hess Corporation Comments at 4-6.

86Oklahoma IPA Comments at 3.

87Shell Comments at 8.

88Id.

89Id. at 8-9.

90Id. at 9 (citing Price Discovery in Natural Gas and Electric Markets, Policy Statement on Natural Gas and Electric Price Indices, 104 FERC ¶ 61,121 (2003) (Policy Statement)).

91MSCG Comments at 8.

92Id.

93NGSA Comments at 15.

94AF&PA Comments at 5-7; see also NGSA Comments at 12-14; Industrial Energy Consumers of America Comments at 3.

95NGSA Comments at 14.

96NGSA Comments at 12; see also Honeywell Reply Comments at 2.

97INGAA Comments at 9.

98Shell Comments at 8.

99Shell Comments at 8.

100Id.

101See, e.g., Shell Comments at 8; NGSA Comments at 15.

102NGSA Comments at 15.

103Id.

104EnCana Marketing Comments at 10.

105MSCG Comments at 9.

106NARO Comments at 4; see also Mewbourne Oil Company Comments at 5.

107NARO Comments at 4; see also Mewbourne Oil Company Comments at 5.

108EnCana Marketing Comments at 10 and MSCG Comments at 9

109 Section 23(b) (2) of the Natural Gas Act, 15 U.S.C. 717t-2(b) (2) (2000 & Supp. V 2005).

110Wisconsin Companies Comments at 6.

111EPSA Comments at 7-8.

112Calpine Comments at 4-5.

113NGSA Comments at 15.

114Id.

115NGSA Reply Comments at 4.

116Wisconsin Companies at 6.

117EPSA Comments at 7-8; Calpine Comments at 4-5; NGSA Comments at 15.

118AGA Comments at 3; Duke Energy Ohio, Inc. at 8-9.

119NOPR at P 68.

120MSCG Comments at 9; Statoil Comments at 6-7.

121AGA Comments at 4.

122NGSA Comments at 15-16.

123MSCG Comments at 9-10; Statoil Comments at 6-7; AGA Comments at 4; NGSA Comments at 15-16.

124Nicor Gas Company Comments at 6; Statoil Natural Gas LLC Comments at 5; PG&E Comments at 6; NGSA Reply Comments at 2.

125NGSA Reply Comments at 2.

126PG&E Comments at 6.

127Enbridge Comments at 26.

128NGSA Comments at 2.

129Id.

130Id.

131See, e.g., PG&E Comments at 6.

132Section 23(a) (2) of the Natural Gas Act, 15 U.S.C. 717t-2 (2000 & Supp. V 2005).

133Section 23(a) (4) of the Natural Gas Act, 15 U.S.C. 717t-2(a) (4) (2000 & Supp. V 2005).

134Section 23(a) (2) of the Natural Gas Act, 15 U.S.C. 717t-2(a) (2) (2000 & Supp. V 2005).

135Section 23(b) (2) of the Natural Gas Act, 15 U.S.C. 717t-2(b) (2) (2000 & Supp. V 2005).

136Comments of the U.S. Department of Justice, Antitrust Division, Transparency Provisions of the Energy Policy Act, Docket No. AD06-11-000 (filed Jan. 25, 2007). The Department of Justice’s comments focused on the electricity markets, although it did note that the same general considerations that applied to electricity markets also applied to natural gas markets.

137This is consistent with the Commission’s approach regarding the individual transaction data reported on Electric Quarterly Reports. For that much more detailed reporting of individual transactions, the Commission found that a delay of 30 days for reporting individual transaction data in EQR filings would greatly reduce the usefulness of the data as a tool for collusion. Revised Public Utility Filing Requirements, Order No. 2001,
67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (2002) at P 17.

138This is consistent with the Commission’s approach regarding the individual transaction data reported on Electric Quarterly Reports. For that much more detailed reporting of individual transactions, the Commission found that a delay of 30 days for reporting individual transaction data in EQR filings would greatly reduce the usefulness of the data as a tool for collusion. Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (2002) at P 17.

139 NEM Comments at 7; Sequent Comments at 6-7.

140 NEM Comments at 8.

141 NEM Comments at 7.

142 NEM Comments at 8.

143 Sequent Comments at 7.

144 Sequent Comments at 7.

145?/ "Salary" represents the allocated cost per gas program employee at the Commission based on its appropriated budget for fiscal year 2008. The $126,384 "salary" consists of $102,028 in salaries and $24,355 in benefits.

146?/ An "FTE" is a "Full Time Equivalent" employee that works the equivalent of 2,080 hours per year.

147

40