Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services

Federal RegisterFeb 25, 2000

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 154, 161, 250, and 284

[Docket Nos. RM98-10-000 & RM98-12-000; Order No. 637]

Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services

Issued February 9, 2000.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is amending its regulations in response to the growing development of more competitive markets for natural gas and the transportation of natural gas. In this rule, the Commission is revising its current regulatory framework to improve the efficiency of the market and provide captive customers with the opportunity to reduce their cost of holding long-term pipeline capacity while continuing to protect against the exercise of market power. The rule revises Commission pricing policy to enhance the efficiency of the market by waiving price ceilings for short-term released capacity for a two year period and permitting pipelines to file for peak/off-peak and term differentiated rate structures. It effects changes in regulations relating to scheduling procedures, capacity segmentation and pipeline penalties to improve the competitiveness and efficiency of the interstate pipeline grid. It narrows the right of first refusal to remove economic biases in the current rule, while still protecting captive customers' ability to resubscribe to long-term capacity. And, it improves the Commission's reporting requirements to provide more transparent pricing information and permit more effective monitoring of the market.

DATES:

The rule will become effective March 27, 2000, with the exception of the removal of paragraph (c)(6) of redesignated § 284.10, which will be effective on September 1, 2000.

Pro forma

tariff filings to comply with certain requirements of the rule are due by May 1, 2000. Changes to reporting requirements are to be implemented by September 1, 2000.

ADDRESSES:

Federal Energy Regulatory Commission, 888 First Street, NE., Washington DC, 20426.

FOR FURTHER INFORMATION CONTACT:

Michael Goldenberg, Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. (202) 208-2294; or Robert A. Flanders, Office of Markets, Tariffs, and Rates, Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. (202) 208-2084.

SUPPLEMENTARY INFORMATION:

Regulation of Short-Term Natural Gas Transportation Services

Docket No. RM98-10-000

Regulation of Interstate Natural Gas Transportation Services

Docket No. RM98-12-000

Order No. 637

Final Rule

Table of Contents

I. Introduction

A. The Changing Natural Gas Market

B. The Commission's Response to the Transition in the Market

II. Adjustments to Rate Policies To Improve Efficiency and Protect Against the Exercise of Market Power

A. Removal of the Rate Ceiling for Short-Term Capacity Release Transactions

B. Peak And Off-Peak Rates

C. Term-differentiated Rates

D. Voluntary Auctions

III. Improving Competition and Efficiency Across the Pipeline Grid

A. Scheduling Equality

B. Segmentation and Flexible Point Rights

C. Imbalance Services, Operational Flow Orders and Penalties

IV. Reporting Requirements for Interstate Pipelines

A. Transactional Information

B. Information on Market Structure

C. Information on Available Capacity

D. Coordination With GISB Standardization Efforts

V. Other Pipeline Service Offerings

A. Right of First Refusal

B. Negotiated Terms and Conditions of Service

VI. Reorganization of Part 284 Regulations

VII. Implementation Schedule

VIII. Information Collection Statement

List of Figures

Figure 1—Retail Unbundling by End User Segment

Figure 2—Current and Proposed Market Centers as of June 1999

Figure 3—Average Prices of Natural Gas by Industry Sector 1967-1998

Figure 4—Altrade and Natural Gas Exchange Trading Points

Figure 5—Regional Natural Gas Prices and Differentials in Transportation Values September 1999

Figure 6—Implicit Transportation Values

Figure 7—Price Differentials During January 2000

The Federal Energy Regulatory Commission (Commission) is amending Part 284 of its open access regulations in response to the growing development of more competitive markets for natural gas and the transportation of natural gas. In this rule, the Commission is revising its current regulatory framework to improve the efficiency of the market and to provide captive customers with the opportunity to reduce their cost of holding long-term pipeline capacity while continuing to protect against the exercise of market power. To this end, the final rule makes the following changes in the Commission's current regulatory model:

• The rule grants a waiver for a limited period of the price ceiling for short-term released capacity to enhance the efficiency of the market while continuing regulation of pipeline rates and services to provide protection against the exercise of market power.

• The rule revises the Commission's regulatory approach to pipeline pricing by permitting pipelines to propose peak/off-peak and term differentiated rate structures. Peak/off-peak rates can better accommodate rate regulation to the seasonal demands of the market, while term differentiated rates can be used to better allocate the underlying risk of contracting to both shippers and pipelines.

• The rule adds regulations to improve the competitiveness and efficiency of the interstate pipeline grid by making changes in regulations relating to scheduling procedures, capacity segmentation and pipeline penalties.

• The rule narrows the right of first refusal to remove economic biases in the current rule, while still protecting captive customers' ability to resubscribe to long-term capacity.

• The rule improves reporting requirements to provide more transparent pricing information and to permit more effective monitoring for the exercise of market power and undue discrimination.

While the regulatory revisions adopted in this rule primarily affect the regulation of short-term transportation options, the changing nature of the natural gas market also poses significant challenges to the Commission's current model for regulating long-term transportation capacity. Changing the Commission's fundamental regulatory model goes beyond the scope of this proceeding. However, the Commission is beginning a new effort to monitor the changes taking place in the market so that, after this rulemaking terminates, the Commission can be prepared to reexamine its regulatory framework in light of the challenges posed by the growing competitive market.

The changes in the gas market since wellhead decontrol and Order Nos. 436 and 636 have created a better functioning and more reliable gas market. But the very growth of a more efficient market for natural gas and transportation capacity poses significant

challenges to the Commission's regulatory model which was developed when the market was not competitive or efficient. The Commission discusses below the growth that has occurred in the market since Order No. 636, the current trends and their regulatory implications. The Commission then discusses its regulatory objectives and why the Commission is instituting a new process, independent of this proceeding, to examine whether fundamental changes to its current regulatory framework are needed to respond to the changed structure of the natural gas market. In Parts II through VII, the Commission discusses the adjustments to its current regulatory model that it is making in this rule.

I. Introduction

A. The Changing Natural Gas Market

1. Prologue to Competition

Prior to Order Nos. 436 and 636, and the implementation of the Wellhead Decontrol Act, all aspects of the natural gas market were regulated. The Commission, pursuant to the dictates of the Natural Gas Act (NGA)

and then the Natural Gas Policy Act (NGPA) established the prices for natural gas. Interstate pipelines purchased gas at the wellhead and delivered that gas at regulated rates to local distribution companies (LDCs). The LDCs, in turn, distributed gas to industrial, commercial, and residential consumers at rates regulated by the states, which permitted passthrough of the interstate pipeline costs. There was little choice in the market for natural gas or the market for transportation capacity. The market distortions and inefficiencies created by this regulatory regime are well known. The regulation of natural gas prices created economic incentives for producers to divert interstate gas to the unregulated intrastate market where they could obtain higher prices. The regulated prices dampened the incentive to invest in the production of natural gas, which led to the gas shortages in the 1970's.

Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954) (mandating Commission regulation of the gas commodity).

See

Transcontinental Gas Pipe Line Corporation v. State Oil & Gas Board, 474 U.S. 409 (1986) (NGA's artificial pricing scheme major cause of imbalance between supply and demand); Public Service Commission of New York v. Mid-Louisiana Gas Co., 463 U.S. 319, 30-31 (1983) (interstate natural gas prices could not compete with intrastate prices).

The passage of the Natural Gas Policy Act (NGPA)

in 1978 began to alleviate the problems caused by regulation of the gas commodity by regulating both interstate and intrastate gas prices in an effort to limit the incentives for diversion of gas, seeking to break down the artificial barriers between interstate and intrastate gas markets, and gradually providing for deregulation of natural gas prices. In 1985, in response to the changed market conditions created by the NGPA, the Commission adopted Order No. 436

which established rules for pipelines to offer open access transportation service independent of pipelines' sales service. In 1989, Congress passed the Wellhead Decontrol Act

which removed all regulation from the gas commodity by 1993. In passing the Wellhead Decontrol Act, Congress assigned to the Commission the task of regulating interstate pipeline capacity in a way that would “maximize the benefits of [wellhead] decontrol.”

15 U.S.C. 3301-3432 (1978).

Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol. Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. & Regs. Regulations Preambles [1982-1985] ¶ 30,665, at 31,472-74 (Oct. 9, 1985).

Pub. L. 101-60 (1989); 15 U.S.C. 3431 (b)(1)(A) (as of Jan. 1, 1993, any amount paid for a first sales of natural gas is just and reasonable).

Natural Gas Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989).

In Order No. 636,

the Commission found that the pipelines' provision of a bundled gas and transportation service had anticompetitive effects that limited the benefits of open access service and wellhead decontrol. The Commission, therefore, required pipelines to separate their sales of gas from their transportation service and to provide comparable transportation service to all shippers whether they purchase gas from the pipeline or another gas seller. The Commission further adopted initiatives to increase competition for pipeline capacity in order to reduce the prices paid for transportation and ultimately the overall price consumers pay for gas. The Commission allowed firm holders of pipeline capacity to resell or release their capacity to other shippers and required pipelines to permit shippers to use flexible receipt and delivery points. Enabling firm shippers to resell their capacity created competitive alternatives to purchasing pipeline services. The ability to use flexible receipt or delivery points also expanded the capacity alternatives available to buyers of capacity because it meant that buyers were not restricted to using the primary points in the releasing shipper's contract. Capacity buyers could seek capacity from any number of firm capacity holders and use flexible point authority to inject and deliver gas at the points the purchasing shipper chose to use.

Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] ¶ 30,939 (Apr. 8, 1992).

The combination of wellhead decontrol, open access transportation, and the unbundling of pipeline gas sales from the pipelines' transportation function created an opportunity for increased efficiency and competition both in the gas commodity market and the transportation market. The Commission's initiatives were supplemented by the actions of state regulators who too saw the need to begin to open local distribution systems by allowing large industrial and commercial customers to purchase their own gas and transport that gas both on the interstate pipeline and on the LDC's facilities.

As a result of the Commission and state open access and unbundling efforts, the stage was set for more efficient and competitive markets to develop that would reduce overall gas prices to consumers. LDCs began to contract for gas supplies in the production area and separately for transportation service from pipelines. Large industrial customers began to do the same, contracting for interstate pipeline capacity and transportation service on LDCs. Market centers began to develop to facilitate the buying and selling of natural gas and, in 1990, NYMEX established a futures market using the Henry Hub as the market exchange center.

Shippers and marketers began to use the capacity release mechanism as an alternative to obtaining transportation service from the pipeline, particularly for short-term service.

NYMEX, Henry Hub Natural Gas,

http://www.nymex.com

(November 17, 1999) (futures contract began in 1990).

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 26 (June 1999) (growth of capacity release from 1993 to the present).

2. Trends in the Gas Market Today

Today's natural gas market is again in the process of change, and is substantially different operationally and economically from the market in 1993. Upstream and downstream wholesale markets are maturing. As part of this process, both upstream and downstream market centers and gas trading points are increasing, providing shippers with greater gas and capacity choices. The financial marketplace has developed a variety of options and futures contracts that better enable participants to hedge against price risk. Electronic commerce (eCommerce) has grown rapidly

providing greater liquidity in commodity markets and with the promise of providing such liquidity in the transportation market as well. The industry is relying more on self-regulation to develop standards for business and electronic processes that create greater efficiency in moving gas across the integrated pipeline grid. There is greater integration between the natural gas and the electric generation market, with gas usage for power generation expected to grow substantially in the near future. Residential unbundling at the state level is underway which may provide the opportunity for small commercial firms and residential consumers to purchase their gas supplies in a competitive market. These trends are in various stages of development, with the growth of wholesale markets firmly established while residential retail unbundling is still in its infancy. These trends, and the challenges they present the Commission in its regulation of the natural gas industry, are discussed below.

Wholesale Markets.

The wholesale market, composed of both the natural gas commodity market and the transportation market, has grown with new participants with the unbundling of transportation and sales service at the LDC level. Since 1984, large numbers of industrial customers, electric generators, and end use customers have been buying gas from parties other than the pipelines or LDCs, as shown in Figure 1.

As of 1998, the percentage of customers unbundled at the retail level were: industrials—84.5%, electric utilities—66.1%, other end users—49.3%, commercial customers—33%, residential consumers—2.3%. Energy Information Administration, Natural Gas Annual 1998, at 35-37, 39, 41 (Oct. 1999).

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While industrial customers consume the largest amount of gas of any sector, the use of gas for electric generation shows the greatest recent growth, estimated for the first 11 months of 1998 at 11% greater than in 1997.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 31-33 (1999).

Since Order No. 636, the industry has witnessed a dramatic growth in the use of marketers to provide gas, arrange transportation, or provide both services to LDCs, industrials, end users, and electric generators. Marketing is still relatively unconcentrated, with the shares of the top 4 marketers actually declining by one-third from 1992-1997.

At the same time, marketing sales volume has increased sharply, with the sales volume of the top twenty marketers tripling to 40 trillion cubic feet from 1992 to 1997.

Marketers currently hold over 20% of pipeline firm capacity.

Gas customers use marketers in a variety of ways. LDCs, which hold firm transportation on a single pipeline, can use the marketer to obtain and deliver gas to an interconnect point on that pipeline and the LDC can use its firm transportation service to deliver that gas to its citygate delivery point. Other customers, such as industrials, may employ a marketer to acquire gas and interstate transportation service to deliver the gas to the industrial's citygate delivery point. Increasingly, marketers are offering additional services to customers such as asset management services where the marketer manages capacity for LDCs as well as price hedging and risk management services, including the provision of financing options.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 152-153 and Figure 55 (June 1999). According to one source, there are 541 electric and gas marketers as of 1998. The Energy Report, June 8, 1998.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 152-153 and Figure 55 (June 1999).

Id.

at 222, Table D12.

See

Comments of Dynegy (national marketer of both gas and electricity, asset manager for LDC capacity, owner of interstate pipelines and gathering systems, partner in retail gas ventures); Duke Energy Trading (provides gas and energy-related services); Enron Capital (asset management services, supplying gas for electric loads, price hedging and risk management services, provision of financing options).

Market centers:

In order for producers and marketers to serve LDCs and other customers, active wholesale markets have developed upstream (in production areas) and they are growing in downstream markets as well. Gas customers have the choice of entering into long-term gas contracts to assure supply or price or they can rely upon monthly and daily spot markets to obtain their gas supplies. Customers further have the option of buying gas at upstream market centers in the production area or at market centers in downstream markets. A market center is a point of interconnection between pipelines where traders can exchange gas and shippers can obtain a variety of services, including gas trading, wheeling, parking, loaning, storage, and transfer facilities.

S. Holmes, The Development of Market Centers and Electronic Trading in Natural Gas Markets 1-2 (June 1999) (Discussion Paper 99-01, Office of Economic Policy, Federal Energy Regulatory Commission) (available from the Commission).

Market centers enhance competition because buyers and sellers of gas have a greater number of alternative pipelines from which to choose in order to obtain and deliver gas supplies. The number of market centers has increased from 5 in 1992 to 38 today with additional market centers being proposed.

Although the initial market centers were in the upstream production areas, downstream market centers are now developing. (

See

Figure 2)

Id.

Id.,

at Figure 1 and Table 1 (showing market centers in the Midwest, Northeast, and West).

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The buying and selling of gas similarly has moved from the production area into downstream markets. Trade publications, for instance, report monthly prices at over 100 locations, including many downstream markets.

See

Henning & Sloan, Analysis of Short-Term Natural Gas Markets, A-2 (Energy and Environmental Analysis, Inc., Nov. 1998).

Financial market:

At the same time, an active financial market has developed on the NYMEX to enable wholesale shippers to hedge against future price risks in gas. The NYMEX futures contract has been the fastest growing instrument in its history, and in October 1992, NYMEX began offering options on natural gas futures, giving market participants additional flexibility in managing their market risk.

NYMEX, Henry Hub Natural Gas,

http://www.nymex.com

(November 17, 1999).

Hedging occurs when a seller uses a financial instrument to fix the price at which it will buy or sell a commodity at some future date. By locking in a known price in the future, a buyer in the natural gas market, for example, can protect itself against future increases in the spot market price. Two financial instruments commonly used for hedging are a forward contract and a futures contract.

A forward contract is a contract made now for the exchange (sale and purchase) of a physical commodity (or financial instrument) at some future date. For many forward contracts, no price is paid or received at the time the contract is entered into. The exchange contemplated in the forward contract almost always takes place. Forward contracts are usually used as a way to buy or sell the commodity.

A futures contract is a standardized contract to take or make delivery of a commodity (or financial instrument) at some future date at the prevailing price at the time they are entered into. Futures contracts differ from forward contracts in that delivery or receipt of the commodity almost never takes place. Holders of futures contracts get out of their contracts by acquiring opposite contracts for the same commodity and delivery date as their own. For example, a person who purchased a futures contract initially would sell a similar contract to get out of the initial contract prior to its delivery date. This process is known as “offsetting” the initial contract. After completing it, the purchaser is no longer a party to either contract.

When using futures to hedge, a seller or buyer of natural gas takes a position on the futures market that is the opposite of its position in the physical or cash market. The objective is to lock in a price (and consequently a margin) that is acceptable to the hedger. For example, a producer who wants to receive $2.00 per MMBtu for gas next month would sell a futures contract for $2.00 to deliver gas in that month. If the price on the cash market and the futures market both drop to $1.80 for the next month, the producer will obtain only $1.80 for its gas in the cash market. However, the producer can now close out its futures position by buying a similar contract (offsetting his contract) for $1.80. Since it originally sold for $2.00, it earns $0.20 on its futures position. This, added to the $1.80 received for its gas, provides the producer with the desired $2.00 price for its gas.

Transportation market:

The growth of downstream markets has affected the transportation market as well. Shippers now have the choice of buying gas in upstream markets and transporting that gas to their downstream delivery points or purchasing gas in downstream markets.

Although not as well developed as the gas market, a more competitive transportation market also has developed with shippers able to choose between alternative means of acquiring capacity. Shippers can choose either short- or long-term services from the pipeline or acquire capacity from other shippers through the capacity release mechanism. As an example of the growth of the capacity release market, released capacity for the 12 month period ending March 1997 averaged 20 trillion Btu/day, totaling 7.4 quadrillion Btu for the year, a 22% percent increase over the previous 12 month period and almost double the level for the 12 months ending March 1995.

Unlike the commodity market, however, a formal forward or options market for transportation capacity has not developed, although private parties are providing price hedging and risk management services.

See

Gas Daily, September 14, 1999, at 2 (reports on citygate and pooling point prices); Natural Gas Week, November 1, 1999, at 7-8 (spot differentials between market hubs in production and consumption markets).

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0618(98), Deliverability on the Interstate Natural Gas Pipeline System 83 (1998).

See

Comment of Enron Capital (providing price hedging and risk management services).

The development of the wholesale gas market is dynamic, reflecting the ever changing supply conditions in the industry. In the past, gas supplies generally flowed north into the mid-west and Northeastern markets. But, with the development of new and increased gas supplies from Canada, gas supplies now flow south and east as well as north. Natural gas supplies from Canada have increased from less than 1 Tcf in 1985 to 3Tcf in 1998, and pipeline expansions would add approximately 3 Bcf per day of capacity to ship gas from Canada to the United States.

This flow creates additional market centers and trading points, such as the Chicago hub. Pipeline projects are being proposed to pick up gas at the Chicago hub and carry the gas eastward.

New supplies in the outer continental shelf, the production areas of Wyoming and Montana, and in Nova Scotia also create demand for new pipeline construction that will change the way in which shippers and pipelines do business and can lead to the creation of additional market centers and trading points.

See

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 12-13 (June 1999).

See

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 21 (June 1999).

; If You Build It, Will They Come (1999 Status Report), American Gas Association, Appendix A (summarizing new pipeline construction projects related to gas supplies in the Western Canada sedimentary basin, the deepwater Gulf of Mexico, and the Rocky Mountain states.)

Changes have already occurred in the way shippers use pipelines because the growth of downstream market and trading centers has enlarged the purchasing options for gas buyers. As a result of market centers, for example, an industrial gas customer no longer needs to hold pipeline capacity upstream at the wellhead or production area. The industrial customer can hold firm capacity on the downstream pipeline that directly connects to its plant (or the LDC serving its plant) and purchase its gas from a marketer at a downstream market center. The marketer makes the arrangements for providing gas at the market center, which could include purchasing gas at the wellhead or an upstream market center in the production area and transporting the gas to the market center or simply purchasing gas from another party at the downstream market center.

The use of released capacity has made possible the development of virtual pipelines. A virtual pipeline can be created when a marketer or other shipper acquires capacity on interconnecting pipelines and can schedule gas supplies across the interconnect, creating in effect a new pipeline between receipt and delivery points that are not physically connected under a single pipeline management.

Comments of Dynegy and Reliant.

Reliability and price:

The changes in the wholesale market have increased efficiency and competition in the natural gas market. For example, NYMEX states “the Commission's actions to date have promoted and produced a short-term gas market that is robust, functioning, efficient, and effective.”

The increase in competition has not come at the expense of reliability, although that was a concern expressed prior to issuance of Order No. 636. For example, the first winter after implementation of Order No. 636, in February 1994, a cold spell hit the Northeast, but the market responded with prices rising to balance supply and demand, with only minor distribution outages well removed from the interstate system. Similarly, the market cleared even during severe

demand conditions during the winter of 1996.

Indeed, competition may improve reliability by enabling the market to adjust to demand conditions quickly without the need to rely on regulatory allocation or curtailment policies to determine who obtains gas.

Comments of NYMEX, at 2.

See

R. O'Neill, C. Whitmore, M. Veloso, The Governance of Energy Displacement Network Oligopolies, Discussion Paper 96-08, at 16-17 Federal Energy Regulatory Commission, Office of Economic Policy, revised May 1997) (copy available from the Federal Energy Regulatory Commission).

Id.

(concluding that the unbundled gas market has responded to severe demand conditions better than the traditionally regulated electric market).

The ultimate test of any regulatory change is the impact of those changes on consumers. By this measure, wellhead decontrol and the Commission's policies have benefitted consumers by lowering the overall price they pay for natural gas. From 1983-1997, the price of natural gas to all industry sectors has fallen significantly from the peaks reached during the periods of gas price regulation and bundled sales. (See Figure 3)

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eCommerce:

The development of the wholesale gas market has been aided by the standardization of pipeline business practices and communication methodologies and the growth of eCommerce. As a result of Commission initiatives, the industry formed a self-governing standards development organization, the Gas Industry Standards Board (GISB), to develop standards for pipeline business and communication practices that enhance efficiency by better enabling shippers to move gas through markets centers and across interconnected pipelines.

GISB is a private organization which brings together all segments of the natural gas industry to develop needed standards. Its purpose is to reduce the disparities and inconsistencies in pipeline business and communication practices that have impeded the development of an integrated pipeline grid.

Standards For Business Practices Of Interstate Natural Gas Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC Stats. & Regs. Regulations Preambles ¶ 31,038 (Jul. 17, 1996).

The Commission has encouraged the gas industry to move toward the use of eCommerce to increase efficiency. Beginning in 1993, the Commission established industry working groups to develop a set of electronic standards governing the trading of released capacity on pipeline Electronic Bulletin Boards.

Since then, GISB has been developing standards for conducting a wide range of business transactions over the Internet, including scheduling, transmission of flowing gas information, invoicing, and capacity release transactions.

Standards of Electronic Bulletin Boards Required Under Part 284 of the Commission's Regulations, 59 FR 516 (Jan. 5, 1994), FERC Stats. & Regs. Regulations Preambles (Jan. 1991-June 1996) ¶ 30,988 (Dec. 23, 1993).

Standards For Business Practices Of Interstate Natural Gas Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC Stats. & Regs. Regulations Preambles ¶ 31,038 (Jul. 17, 1996), Order No. 587-B, 62 FR 5521 (Feb. 6, 1997), III FERC Stats. & Regs. Regulations Preambles ¶ 31,046 (Jan. 30, 1997).

Along with the development of electronic communication between pipelines and shippers, an electronic market has developed to facilitate the buying and selling of natural gas. Electronic trading of natural gas is the furthest along of all energy markets.

Without electronic trading, shippers have to obtain gas by checking industry publications for a range of gas prices for the previous day, contacting potential gas suppliers using the telephone or fax machines to obtain price quotes to compare, deciding which is the best deal, and consummating the final transaction. Electronic trading creates a more efficient market by expanding the number of buyers and sellers interacting, reducing the time and resources needed to obtain price information and consummate trades, providing anonymity so traders do not have to disclose their market positions, and providing traders with more confidence in the prices they obtain.

One study estimates that on-line trading of natural gas in 1999 will amount to $10 billion.

Many of these electronic transactions occur at downstream markets. (See Figure 4 showing the electronic gas trading points for Altrade and Natural Gas Exchange).

V. Lief, The Surge of Online Energy, The Forrester Report, 2-3 (Sept. 1999); Comment of Altra; Enermetrix.com,

http://www.enermetrix.com.

As one interviewee in the Forrester report explained: “before online trading, if you didn't talk to people all morning—you'd miss the market. We use it quite a bit and sometimes its the only market.” V. Lief, The Surge of Online Energy, The Forrester Report, 2 (Sept. 1999).

See

Electronic Trading Revolution Not Over, Gas Daily, Vol. 15, No. 224, (Nov. 18, 1998) (electronic trading provides access to hundreds of potential transaction partners and price transparency).

V. Lief, The Surge of Online Energy, The Forrester Report, 9 (Sept. 1999).

The trading points for Altrade were provided courtesy of Ultra. The Natural Gas Exchange trading points are taken from S. Holmes, The Development of Market Centers and Electronic Trading in Natural Gas Markets 7 (June 1999) (Discussion Paper 99-01, Office of Economic Policy, Federal Energy Regulatory Commission) (available from the Commission).

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New electronic trading companies are entering the market

and eCommerce for gas is expected to grow, reaching 20% of total gas business within two years.

The development of eCommerce can equalize the marketplace between large and small customers. As a customer quoted by Forrester Research states: “Using online services has made us more efficient. We're a small shop so our resources are limited. The system puts us on the same page as the big guys.”

Enron Launches Global Web-based Commodity Trading Site,

http://www4.enron.com/corp/pr/releases/1999/ene/EnronOnline.html

(Internet online trading for wholesale energy and other commodities).

V. Lief, The Surge of Online Energy, The Forrester Report (Sept. 1999).

Id.

at 5. Another customer stated: “Before we just always went to the big guys even though we were not necessarily getting the best prices. Now everyone is using the screens, everyone has the prices, and everyone has the advantage—making the net one culprit along the path towards reduced margins.”

Implications for Commission regulation:

Commodity and transportation markets are closely interdependent in the natural gas business with changes in one market affecting the other. This interdependence has important implications for the Commission's regulation of pipeline transportation. While the growth of a vibrant active wholesale marketplace has enhanced competition, this growth, particularly the development of downstream market centers and trading points, also creates both challenges and opportunities for Commission regulatory policy.

Many LDCs' contracts have expired, or are expiring soon, providing, in many cases, the first opportunity for these LDCs to recontract in the competitive market spawned by Order Nos. 436 and 636.

LDCs are considering whether to continue their current firm-to-the-wellhead capacity contracts or whether to reduce their contractual entitlements or to rely more heavily on purchasing gas from producers or gas marketers at downstream market centers or trading points. It is not clear whether marketers will choose to pick up all or some of the firm capacity relinquished by LDCs. Marketers' purchase of firm capacity, for instance, has been increasing, with their holdings increasing by 18% during the 12-months ending July 1, 1998.

But, unlike LDCs, marketers are not guaranteed passthrough of capacity costs and therefore are likely to subscribe to shorter term contracts than what the LDCs signed in the past.

Marketers, and other transportation customers, also may be less willing than LDCs to sign long-term contracts with

Memphis

clauses that permit pipelines to increase prices unilaterally by filing new rate cases.

See

Comments of Columbia.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 136 (June 1999).

Id.

at 137.

United Gas Pipeline Co. v. Memphis, 358 U.S. 103 (1958).

The renegotiation of contracts, both as to coverage and term, increases the risks for pipelines that may have greater difficulty reselling capacity (capacity turnback).

This raises issues about how to compensate pipelines for the increased risk as well as the proper way to design rates for customers remaining on the system.

The Energy Information Agency has estimated the nationwide turnback level at 20% of the long-term contracted capacity as of July 1998, with variations by region. Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 144 (1999).

The Commission already has been faced with some of these difficulties.

See

El Paso Natural Gas Company, 83 FERC ¶ 61,286 (1998)(remarketing of turnback capacity); El Paso Natural Gas Company, 79 FERC ¶ 61,028,

reh'g denied,

80 FERC ¶ 61,084 (1997),

remanded

Southern California Edison Company v. FERC, 162 F.3d 116 (D.C. Cir. 1999) (attempt to reach settlement on capacity turnback); Natural Gas Pipeline Company of America, 73 FERC ¶ 61,050, at 61,128-29 (1995) (recovery of turnback capacity costs).

The growing importance of market centers suggests the need for policy development that will continue to foster the development of both upstream and downstream market centers. For instance, some urge that in order to further market center development, pipeline rate zones need to be redrawn to coincide better with market centers, rates need to be reestablished so that upstream capacity costs are not included in downstream rates, and capacity segmentation policies should be enhanced so that shippers can obtain capacity only on portions of a pipeline.

Reliant also suggests that the use of market centers can be encouraged by the creation of virtual pipelines in which one pipeline is able to acquire capacity on another pipeline.

See

Comments of Production Area Rate Design Group; Reliant.

The movement toward eCommerce highlights the need to create greater integration between the allocation system for pipeline and released capacity and the pipeline scheduling system. In addition, the integration of electronic trading for gas and pipeline capacity would further efficiency by permitting shippers to complete all aspects of a transaction in a single online auction. GISB has recently approved standards for title transfer tracking under which pipelines will track gas transactions between parties at pooling points using the electronic protocols for scheduling gas. Third parties also will be able to consummate gas trades at pooling points and have those trades processed by the pipeline.

Such title transfer services could form the basis for electronic trading that fully integrates gas and capacity trades with the pipelines' scheduling system.

Final Actions Regarding Title Transfer Tracking, standard 1.3.64,

http://www.gisb,org/final.htm

(ratified on January 23, 1999).

b. Integration of the Gas and Electric Markets.

The increasing development of wholesale markets for gas also are affected by the growing synergy between the gas and electric markets. The Commission, in Order No. 888,

and the states have begun to open the electric market to competitive forces in generation, a trend which is having, and is projected to have, a significant effect on gas markets. Gas for power generation is projected to grow 4.5% annually from 1997 through 2020, reaching 9.2 Tcf, a level three times the 1997 level of usage.

As a result of this new demand, the gas market is projected to grow from 22 Tcf per year today to 30 Tcf per year by 2010, a 27% increase over current levels.

Distributed power generation located near the end user may provide another vehicle for the use of natural gas, as many of these units are projected to use natural gas as an energy source.

Gas fired electric generators contend that their use of natural gas as a supply source would be improved by the provision of transportation service that enables them to coordinate the delivery of gas with their need to generate electricity.

Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] ¶ 31,036 (Apr. 24, 1996).

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 33 (1999).

Department of Energy/Energy Information Administration, 1999 Annual Energy Outlook (30 Tcf by 2010).

See

Gas Research Institute, Baseline Projection Data Book, at Page Sum 20 (1998 edition) (30 Tcf by 2015).

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 33. Distributed power is projected to account for 20 percent of additions to generating capacity, or 35 Gigawatts, over the next two decades.

See

Distributed Power Coalition of America,

http://www.dpc.org/faq.html

(November 17, 1999) (gas turbines most popular means of generating distributed power).

See Comments of INGAA, Williams Companies, Reliant, Sithe, Sempra Energy, EEI. See

also

Reliant Energy Gas Transmission Company, 87 FERC ¶ 61,298 (1999) (hourly flexibility service designed to meet needs of power generators).

The increased integration of gas and electric markets is reflected in the

mergers between power generators and pipeline companies as well as the number of marketers that resell both gas and electricity.

Some marketers are operating their own generation plants.

For some customers, the energy markets have converged to a Btu market where the customer can purchase whatever energy source is cheapest at the time.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 147-67, 231-42 (1999) (discussing the increased trend toward corporate alliances and mergers).

See

Comments of Dynegy (owner of power generation facilities).

The pace of mergers and alliances raises questions about the future structure of the industry.

Mergers between pipeline corporations can increase concentration and reduce competition in markets where the merged firms previously competed. Vertical mergers between pipeline companies and gas fired power generators raise concerns about the ability of the integrated firm to injure competition by favoring its vertically integrated affiliate.

The increasing use of asset managers by LDCs

and other shippers to manage their pipeline capacity could result in the concentration of pipeline capacity in a few hands, reducing the competitiveness of the capacity resale market. The potential for increasing affiliation between pipelines and power generators also raises questions about whether changes are needed in the Commission's regulations of pipeline affiliate relationships, which are limited to pipeline marketing affiliates.

See

Comment of Dynegy (expressing concern about the integrated corporations using transportation capacity as a marketing lever to obtain business for a generation affiliate).

The Federal Trade Commission entered into a consent decree in one vertical merger between a pipeline and an LDC out of concern about the ability of the LDC to manipulate its confirmation practices to favor its pipeline affiliate. CMS Energy Corp, 64 FR 14725 (Mar. 26, 1999).

See

Comments of Dynegy, Enron Capital (providing asset management services).

18 CFR 161 (1999).

c. Residential Retail Markets.

The unbundling that already has taken place may be only a harbinger of the future. While unbundling for the larger industrial and end-use customers is at relatively high level,

unbundling for smaller commercial customers and for residential consumers has not taken place to the same extent. The growing focus in the states is on efforts to complete the unbundling process by offering unbundled services to commercial and residential consumers. According to the Energy Information Administration, as of June 1999, eleven states have active unbundling programs or are in the implementation phase, nine states and the District of Columbia have pilot programs or partial unbundling programs (with one state scheduled to begin its pilot program in November 1999), eleven states are considering action on unbundling plans, and eighteen states have taken no action. Consumer acceptance of these programs is mixed.

In Nebraska, 97% of eligible residential consumers have elected to choose their own supplier, while in other states participation of eligible consumers is 2% or less.

See text and notes,

supra,

at Figure 1.

Department of Energy/Energy Information Administration

http://www.eia.doe.gov/oil gas/natural gas/restructure/state/us.html

(2/2/00) (The eleven states that have active unbundling programs or are in the implementation phase are: New Mexico, New York, West Virginia, Georgia, Maryland, Massachusetts, New Jersey, Ohio, California, Colorado, Pennsylvania).

Id.

The competitive dynamics of both gas and electric unbundling are generating a movement toward new ways of selling energy products to residential consumers. For instance, eCommerce is beginning to enter the consumer arena with companies offering residential customers one-stop shopping over the Internet for electric and gas service from affiliated companies as well as offering other utility services, such as long-distance telephone and Internet services.

There are business alliances between gas distributors and traditional consumer retailers to sell both gas and electricity to residential and commercial customers.

See

Power Trust.com,

http://www.powertrust.com;

Essential.com,

http://essential.com.

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 231 (1999) (alliance between Columbia Energy and Amway Corporation for door-to-door marketing of gas and electricity);

http://www.amway.com/infocenter/pressrel/pressrel49.asp

(November 18, 1999) (program expands from Georgia to Ohio); Ga. Marketers Unveil Deals, Gas Daily, November 16, 1999, at 5 (alliance between SCANA Energy and Krogers grocery stores to market natural gas services at kiosks).

Whether and how far residential unbundling will progress is one of the major unknowns in the current market and, even if it does occur, the implications of such a change are hard to predict. To the extent full residential unbundling occurs, LDCs would exit the interstate transportation function entirely, being replaced by producers and marketers, neither of which have the ability automatically to pass costs on to consumers. In the short-run, retail unbundling has created more uncertainty about contract duration. LDCs, which may unbundle their transportation service from gas sales, are unwilling to enter into long-term contracts for interstate capacity until the structure of unbundling in their state is determined.

Similarly, the marketers that may replace the LDCs are not in position yet to determine whether to sign long-term capacity contracts and for what quantities. In the long-run, however, the effect of unbundling on firm capacity holdings is less clear. Marketers still may choose to subscribe to firm capacity in order to guarantee service. In some states, regulators, concerned with ensuring reliable deliveries, are considering whether LDCs should be required to be the suppliers of last resort in case marketers default or whether marketers will be required to hold primary firm capacity as a prerequisite to participation in unbundling programs.

Comments of AGA I, PSE&G, Columbia.

See Comment of ConEd.

B. The Commission's Response to the Transition in the Market

The Commission's response to the changes taking place in the market must be informed by its regulatory responsibilities and objectives.

1. The Commission's Regulatory Objectives

The Commission has the regulatory responsibility under the Natural Gas Act to ensure that pipeline rates and services are just and reasonable and not unduly discriminatory.

Just and reasonable rates and services need to be designed to achieve two principal objectives. They should promote competitive and efficient markets,

while mitigating market power and preventing undue discrimination, especially for the Commission's “prime constituency, captive customers vulnerable to pipelines' market power”.

In short, the Commission's regulatory policy must seek to reconcile the objectives of fostering an efficient market that provides good alternatives

to as many shippers as possible while at the same time creating a regulatory framework that is fair and protects captive customers without good alternatives.

Natural Gas Act, § 4, 15 U.S.C. 717(d).

Under the Wellhead Decontrol Act, for example, the Commission is obliged to structure its regulatory framework to “improve (the) competitive structure [of the natural gas industry] in order to maximize the benefits of (Wellhead) decontrol. Natural Gas Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989); Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636.57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] ¶ 30,939, at 30,932 (Apr. 8, 1992).

United Distribution Companies v. FERC, 88 F.3d 1105, 1123 (D.C Cir. 1996).

See

Maryland People's Counsel v. FERC, 761 F.2d 780, 781 (D.C. Cir 1985); FPC v. Hope Natural Gas Co., 320 U.S. 591, 610 (1944); Associated Gas Distributors v. FERC, 824 F.2d 981, 995 (D.C. Cir. 1987),

cert. denied,

485 U.S. 1006 (1988).

In order to achieve these basic objectives, there are several subsidiary ends that regulatory policy should strive to achieve. Regulatory policies should seek to expand customers' alternatives and choices, which will in turn dissipate the ability to exercise market power. These policies need to create efficient market mechanisms that will enhance competitive options. They also should ensure that reliable information is available to better enable shippers to make informed choices in the market and to permit shippers and the Commission to monitor for undue discrimination and the exercise of market power. At the same time, to the extent adequate competition does not exist, regulation needs to mitigate residual market power and protect captive customers. In addition, regulation needs to be fair and administratively efficient, so that the regulation itself does not impose undue or unnecessary costs on the industry.

2. The Commission's Response to the Changing Gas Market

Since Order No. 436, the Commission has been reexamining its rate and regulatory policies to adapt those policies to changes in the competitive market and to ensure that its regulatory policies promote its goals and objectives.

In analyzing the interrelation between the Commission's current regulatory policy and the changing natural gas market, the Commission has concluded that its current regulatory framework does not meet the current needs of the market. In some situations, the current regulatory model inhibits the ability of the market to respond efficiently to demand conditions, limits shippers' capacity choices, and may not provide the lowest rates to captive customers.

See

Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. & Regs. Regulations Preambles (1982-1985) ¶ 30,665, at 31,534 (Oct. 9., 1985); 18 CFR 284.7(c); Interstate Natural Gas Pipeline Rate Design, 47 FERC ¶ 61,295 (1989) (requiring that rate methodologies must be designed to improve allocative and productivity efficiency).

The Commission is taking two steps to better achieve its regulatory objectives. First, in this rule, the Commission is taking an interim step to revise aspects of its current regulatory model to improve competition and efficiency, without making fundamental changes to that model. Second, the Commission is beginning an effort, outside of this proceeding, to examine more fundamental changes to its regulatory model.

a. The Changes Adopted in this Rule.

The changes adopted in this rule are designed to improve the efficiency of the market and increase competition while continuing cost-of-service regulation to protect against the exercise of market power by pipelines. These changes involve modifications to the Commission's ratesetting policies to enable rates to better reflect market demand and to reduce the rate burden on captive customers, improvements to the Commission's regulation of the pipeline grid to increase competition, and revisions to the Commission's reporting requirements.

With respect to rates, the Commission is waiving the price ceiling for short-term capacity release transactions for a period of two years. This change is intended to improve shipper options and market efficiency during peak periods, when an efficient and effective market is most needed. During peak periods, the maximum rate cap on capacity release transactions inhibits the creation of an effective transportation market by preventing capacity from going to those who value it the most. The elimination of the rate ceiling will eliminate this inefficiency and enhance shipper options in the short-term market. To protect against the potential exercise of market power, the Commission is maintaining cost-of-service regulation of the pipelines as well as improving efficiency and competition across the pipeline grid along with enhanced reporting requirements that will provide more information to the market and permit better detection of market power abuses. While the changes in the natural gas industry support the removal of the rate ceiling, the Commission recognizes that this is a significant change in policy. The limited term waiver is intended to provide an opportunity for Commission review of this policy after the industry and the Commission have experience over two winters, which should be sufficient to analyze the results of this change.

The Commission further is revising its regulatory policies regarding rates for pipeline services to enable pipelines to file for peak/off-peak and term differentiated rates if a pipeline finds that such rates better reflect the demands and risks it faces. Such rates, however, would still have to satisfy the revenue and cost constraints of the traditional regulatory model. To help facilitate the trend toward eCommerce, the Commission is encouraging both pipelines and third-parties to develop voluntary auctions and is willing to consider waivers of some of its regulatory requirements that may impede the development of capacity auctions.

The removal of the rate ceiling for short-term capacity release transactions and the ability of pipelines to institute peak/off-peak and term-differentiated rates should help to reduce the cost of capacity to captive customers. The captive customers currently pay maximum rates for transportation capacity during peak and off-peak periods to support the pipeline system, while short-term shippers benefit by paying lower market prices during off-peak periods reflecting the reduced demand on the system, but do not face the market rate for capacity during peak periods as a result of the rate ceiling. The changes in ratemaking policies adopted in this rule will help to reduce the revenue responsibility of captive customers by placing on short-term shippers more of the burden of paying for peak period usage of the system. The Commission's objective is for the reduction in captive customers' revenue responsibility to be achieved through a combination of increased capacity release revenues, as well as revenue credits, reduced discount adjustments, and lower long-term rates on pipelines instituting peak/off-peak or term-differentiated rates.

To create greater substitutability between different forms of capacity and enhance competition across the pipeline grid, the Commission is revising its regulations regarding scheduling, segmentation and flexible point rights, penalties, and reporting requirements. The Commission is revising pipeline scheduling procedures so that capacity release transactions can be better coordinated with the nomination process. The Commission is further requiring pipelines to permit shippers to segment capacity wherever feasible, which increases potential capacity alternatives and helps to facilitate the development and use of market centers. The Commission's revision to penalty procedures will create appropriate incentives and will provide shippers with increased information and additional services to help them avoid the incurrence of penalties. The changes to the Commission's reporting requirements will enhance the reliability of information about capacity availability and price that shippers need to make informed decisions in a competitive market as well as improve shippers' and the Commission's ability to monitor marketplace behavior to

detect, and remedy anticompetitive behavior.

The Commission is clarifying its policies regarding two aspects of pipeline service: the right of first refusal and negotiated rates and terms and conditions of service. The Commission is narrowing the right of first refusal (ROFR) in its regulations so that this right interferes as little as possible with the efficient allocation of pipeline capacity, while protecting captive customers against the loss of transportation service. The Commission is clarifying the operation of its policies regarding negotiated rates and negotiated terms and conditions of service in light of its decision in this rule not to adopt regulations providing pre-approval for pipelines to negotiate terms and conditions of service.

b. Process for Future Regulatory Policy Development.

All of the changes in this rule remain within the Commission's current regulatory framework. As discussed earlier, many of the trends in the current market raise questions about a number of Commission regulatory policies, including the effectiveness of the current regulatory model in light of changes to long-term contracts, the effect of regulatory policies on market centers, the need to improve the effectiveness of eCommerce, and the regulation of pipeline affiliates not covered by the current affiliate regulations. It is not yet clear in what direction these trends will lead the market. The changes adopted in this rule are designed to improve the efficiency of the market and to facilitate its development, primarily toward the open and competitive marketplace that current conditions appear to support. Whether more fundamental changes are needed will depend on future market developments and especially how the industry responds to the changes adopted in this rule.

In the Notice of Proposed Rulemaking (NOPR)

and Notice of Inquiry (NOI),

the Commission sought comment on a variety of fundamental changes to its current regulatory methods to respond to issues raised by the changes in the gas market. In the NOPR, for example, the Commission sought comment on whether mandatory auctions should be used to allocate pipeline capacity and whether pipelines should receive pre-approval for negotiation of the terms and conditions of service with individual shippers. In the NOI, the Commission inquired as to whether fundamental changes in the cost-of-service rate methodology, such as indexing and incentive and performance based rates, should be implemented, whether market based rates are appropriate for turned back capacity, whether a periodic review of pipeline rates should be implemented, whether to revise the straight-fixed-variable rate design requirement, and whether options other than cost-based ratemaking would be more efficient.

Regulation of Short-Term Natural Gas Transportation Services, Notice of Proposed Rulemaking, 63 FR 42982 (Aug. 11, 1998), FERC Stats. & Regs. Proposed Regulations (1988-1998) ¶32,533 (July 29, 1998).

Regulation of Interstate Natural Gas Transportation Services, Notice of Inquiry, 63 FR 42973, IV FERC Stats. & Regs. Notices ¶35,533 (July 29, 1998).

Some commenters contend the Commission should make fundamental changes in its regulatory model to accommodate the changes in the market, maintaining that such changes would be consistent with the Commission's responsibilities under the Natural Gas Act. AGA and Williams, for instance, envision a market that is moving toward a structure divided between two classes of pipeline shippers: One class comprised of those customers with sufficient alternatives and options which insulate them from the exercise of market power by the pipelines; the other class comprised of those customers who are captive and have limited choices. As AGA states:

Some LDCs are captive to pipelines' market power because they are tied to capacity contracts for many more years or because pipeline capacity is constrained into their region.* * * Other LDCs are not subject to abuse of market power by pipelines because they have been able to renegotiate their capacity contracts to better reflect their current and anticipated need for capacity and because capacity is not constrained into the region.”

AGA II, at 5.

AGA proposes that the Commission institute two tracks for regulating pipeline transportation service, each available for any shipper to choose. One track would be for cost-based regulated tariff service and the other track for market-responsive negotiated services. The Williams Companies similarly assert that pipelines need to be able to respond to the needs of new customers, like gas fired power generators, by offering market responsive rates and contracts, while still providing cost-based rates as protections for all shippers.

Reliant contends that the development of greater competition in certain areas should lead the Commission to place greater reliance on the use of market forces to establish rates. It contends, for example, that market-based rates should be permitted for pipelines in producing regions where interstate pipelines compete with intrastate pipelines, when a pipeline is unable to sell turned back capacity, and where customers can solicit bids for services from more than one pipeline.

A number of parties support the use of auctions as creating more efficient and fairer methods of allocating capacity,

although many other parties are concerned about whether auctions can be designed efficiently and the ability to coordinate gas and capacity purchases in an auction limited to pipeline capacity.

INGAA is concerned that auctions would lower capacity prices which would threaten pipeline revenue recovery, and AGA is concerned about similar impacts on the value of released capacity.

Comments of Amoco, Altra, Sithe, Southern Company Energy Marketing.

E.g.,

Comment of Dynegy.

Amoco and NGSA recommend significant changes in current regulatory policy through the adoption of an incentivized cost-of-service of service regulatory model to replace existing cost-of-service procedures. Others support periodic rate reviews or other methods of readjusting pipeline rates.

The Customer Coalition argues that the need to review these long-term issues requires that the Commission consider changes through a new NOPR, additional comments, or further technical conferences.

Comments and Supplemental Comments of the Customer Coalition.

After reviewing the comments, and the current state of the industry, the Commission has determined that (1) it must approach its regulatory policymaking more strategically to determine whether it needs to examine and begin developing fundamentally new regulatory methods in anticipation of changing market conditions and (2) it must monitor market conditions on an ongoing basis to ensure that its decisions do not inhibit competition or foster inefficiency. In these proceedings, the Commission has studied improvements to its regulatory policies that would comport with current developments in the market. It must now ask whether it is effective in this dynamic environment to engage in generic policymaking without a deeper understanding of which possible regulatory model best achieves the Commission's regulatory objectives within the changing structure of the natural gas market and energy markets generally. The Commission, therefore, will be instituting a new process to undertake a continuing examination of

the market and the relationship of its rules to the market. This examination will involve questions of rate design and risk allocation in light of changes to long-term contracting policies, improving market centers, creating greater integration of capacity allocation and scheduling processes with the growing trend toward eCommerce, and reexamining the methods for setting and reviewing pipeline rates.

In a nutshell, the Commission still largely applies a coherent “model” of regulation designed for traditional regulated monopolies. Its ratemaking tenets were not fundamentally questioned even as Order Nos. 436 and 636 were adopted. However, the current market may in fact call into question the basic underpinnings of this model and require the Commission to examine the legitimacy of alternative models. Some commenters suggest, for example, that the market is moving toward a dual market structure in which some customers want to negotiate with the pipelines, while others are still captive and need protection against the exercise of market power and undue discrimination. If that is the case, such a trend raises significant questions about the nature of the Commission's regulatory model. Designing a regulatory framework to accommodate such a trend, if that is the direction of the industry, would involve issues such as whether to permit negotiated terms and conditions of service, whether to allow market-based pricing for pipeline services (both long and short term), whether and how to support pipeline revenue requirements, and whether to change rate designs or the ratemaking process itself.

The Commission's current regulatory model is premised on the assumption that regulation of all pipeline services is necessary and that pipeline rates should be set so that the pipeline is given a reasonable opportunity to recover its prudently incurred costs. But this model would need to be changed to accommodate a two-track model of regulation in which non-captive customers would face market priced services and service flexibility and captive customers would be able to obtain service at regulated rates to protect against the exercise of market power.

A two-track regulatory model would require development of new regulatory methods developed for both the non-captive and captive customers. Customers opting for negotiated service should be subject to the risk of that choice and not be able to choose to negotiate only when it benefits them. New methods would be needed for determining just and reasonable rates and services to protect captive customers.

Captive customers should not be forced to pay for pipeline losses or additional risks in the unregulated portion of their businesses. Indeed, such an outcome may be difficult to square with the Commission's mandate under the NGA. If pipelines are given the upside potential inherent in lifting regulatory controls over prices and services, it is questionable whether they should have their revenues supported by a ratemaking regime that also guarantees the recovery of all “prudently incurred” costs.

Under a two-track regulatory model, therefore, the rates for captive customers would likely need to be established separate from the revenues from the pipelines' market-based services. One possibility would be to establish captive customer rates based on the proportion of pipeline capacity used by the captive and non-captive customers rather than as is done today on throughput and contract demand. It also might be necessary to change from rates based on a pipeline's individual cost-of-service to rates developed more on average industry costs. In addition, quality of service would need to factor into rate design so that pipelines would have an incentive to continue to improve the quality of service for captive customers.

Williams, for instance, recognizes that if pipelines are to be given the same potential as competitive firms to earn greater returns through market opportunities, they need to be subject to the risks of market failure just as are unregulated firms.

The industry indeed may be headed in a direction that would make a two-track regulatory model appropriate. If so, these are the kinds of issues with which the Commission would need to grapple. It is not clear, however, whether this is in fact the industry's direction or whether a two-track regulatory model would be the best regulatory model to use. The market's development may reveal that other regulatory models are more desirable. It is possible that a sound regulatory approach could fall anywhere on a spectrum, from traditional utility regulation to a lighter-handed, highly market-oriented focus. Where Commission regulation should fall on that spectrum will depend on the developments in the market and the specific measures that would promote efficiency and protect captive customers at any moment in time. Simply because the industry is in transition today and these choices are therefore difficult, does not mean that the larger questions, of how to adapt the Commission's regulatory approach to changing conditions and how to move policy toward identifiable goals or models, are to be avoided.

The Commission, therefore, is still considering whether to move forward on various proposals for changes in its current regulatory framework, including the use of negotiated terms and conditions of service, changes to SFV rate design, whether to permit discount adjustments, whether to adopt rate reviews or refreshers, and whether to permit more market-based rates. But these issues are interrelated in many respects and cannot be considered separately. Rather, they must be considered within the overall context of the regulatory model that is most appropriate for the current conditions in the market and its likely future direction.

In order to better address these interrelated issues, the Commission has determined to institute a new process outside of this proceeding that will undertake a more systematic approach to evaluating the direction of future natural gas regulation than was possible in this proceeding. This process will be a flexible one and will involve Commission monitoring of the market, dialog between various industry segments, as well as participation by Commission staff in industry conferences or the establishment of new Commission docketed proceedings if needed.

Any such systematic approach to continuous improvement must do two things. First, it should not contribute greater uncertainty to commercial transactions. The Commission, therefore, needs to collaborate with the pipeline industry and its customers to advance market efficiency on a consensus basis where possible. Second, it should be based on current information. Therefore, the Commission needs to gather and analyze data on an ongoing basis to ensure that its decisions, even in individual cases, reflect the current state of the market. In order to address the comprehensive regulatory issues raised by the changing gas market, the Commission is directing its staff to develop the appropriate market monitoring capability and to begin engaging in a continuing dialog with the industry about potential regulatory improvements.

Through monitoring, the Commission staff will seek to evaluate the structure, conduct, and performance of the industry. For example, Commission staff is directed to look at issues relating to capacity availability during periods of peak and nonpeak demand, the concentration of capacity holdings

during peak and nonpeak periods, and the rates charged for service.

This analysis should seek to identify markets where light-handed regulation may be appropriate, as well as those markets in which competitive constraints still exist and the reasons for such constraints. This will allow an assessment of the need for negotiated terms and conditions of service. Such monitoring also will include examination of the industry's response to the changes in this rule to see the effects of these developments on the market. In this regard, the revised reporting requirements adopted in this rule will permit the Commission to examine how capacity prices respond to the lifting of the price ceiling on short-term capacity release transactions and how delivered prices and capacity prices track each other.

The staff should also monitor pipeline rates and operating and maintenance expenditures to see how well pipelines are performing both as an industry and individually compared to the rest of the industry. Such measures should provide a better measure of pipeline performance than relying on earnings or profitability based on historic investment in plant and equipment. In this regard, the staff should examine whether to change the annual reporting forms filed by pipelines to reduce the burden of supplying unnecessary information, while focusing the reports on data that will provide for a better evaluation of pipeline performance and efficiency. As part of this review, staff should consider whether performance based ratemaking should be pursued as a means to establish rates that appropriately reimburse pipelines for efficiency gains while passing on some of those gains to ratepayers through reduced rates.

In addition, the Commission will be looking at the development of the market in a number of areas, including residential unbundling, evolution of downstream gas markets, the development of eCommerce and auctions, mergers and changes in market structure, affiliate relationships and conduct, the effect of penalties on the market, and long-term investments.

But monitoring, by itself, is not sufficient to develop a full picture of the trends in the industry. It is important for all segments of the industry to engage in a dialog to consider how industry changes do or should affect Commission regulatory policy. Such a dialog will enable the Commission and state regulators to achieve a better understanding of industry trends and regulatory changes that better meet the changing character of the industry. Also, constructive dialog between all the industry segments such as was held under the auspices of the Natural Gas Council will be needed if the industry is to grow to the levels some project. This kind of industry dialog can occur independently of government regulators or it can begin initially with regularly scheduled Commission staff conferences with the industry and market participants. The frequency of these conferences and the nature of any reports or recommendations to the Commission can be determined by the participants themselves.

Some of the topics that need to be considered are:

• Whether regulatory changes would further facilitate upstream and downstream market centers, trading areas, and greater gas liquidity;

• Whether changes are needed in gas transportation policies to accommodate the increasing convergence of energy markets;

• Whether the Commission should seek to create greater standardization in terms and conditions of service across the grid;

• Whether regulatory policy with respect to pipeline affiliates and nonaffiliates, as well as asset managers and agents, should be revised to reflect the changing nature of the gas market;

• Whether auctions should be developed to coordinate the allocation and scheduling of capacity and the purchase and sale of gas;

• Whether rate design policies need to be changed to establish incentives for pipelines to enhance quality and efficiency and reward pipelines appropriately;

• Whether the Commission should fundamentally reform its current regulatory model, moving to a two track model or to performance based ratemaking; and

• Whether adjustments to reporting requirements beyond those adopted in this rule are needed to better reflect pipeline performance and efficiency.

Examination of these topics could show that changes in certain areas would be inconsistent with changes in other areas, while other changes would complement each other. Whether discussion of these topics ultimately leads to regulatory changes, and what those changes might be, will depend on the outcome of the dialog and developments in the market. The objective is to establish, as routine, an industry-wide dialog with the Commission, through its staff, to determine whether changes are needed in Commission policy and regulation to achieve the Commission's regulatory objectives.

To begin this process, staff will be scheduling technical conferences over the course of the year to discuss issues relating to: whether changes are needed to facilitate the development of upstream and downstream market centers and trading areas, including rate design changes; whether changes are needed to accommodate the convergence of electric and gas markets; whether the Commission should seek to create greater standardization of services and penalty provisions; and whether there need to be revisions to regulations relating to pipeline affiliates.

In the sections that follow, the Commission discusses the changes in its regulations and policies that are being adopted in this order.

II. Adjustments to Rate Policies to Improve Efficiency and Protect Against the Exercise of Market Power

The Commission's objective in designing rates is to establish a ratesetting framework that increases efficiency in the marketplace, while protecting against the potential exercise of market power. No regulated rate can perfectly emulate the prices found in a competitive marketplace nor protect perfectly against the exercise of market power. This is particularly true when the regulated firm is a natural monopoly

where the competitive price would be insufficient to permit the firm to recover its costs.

Thus, price regulation often permits some exercise of market power and involves tradeoffs between pricing efficiency and the regulatory control over market power. On balance, the Commission finds that the changes to regulation made in this rule—removing the rate ceiling from capacity release transactions, permitting pipelines to file for peak/off-peak and term differentiated rates, plus the improvements to scheduling, segmentation, penalties, and reporting requirements—will enhance marketplace efficiency and competition, protect captive customers, and set prices for short-term transactions that reflect demand during peak periods, while not

jeopardizing protections against the exercise of market power.

See

United Distribution Companies v. FERC, 88 F.3d 1105, 1122 & n.4 (D.C. Cir. 1996) (pipelines are treated as natural monopolies with enormous economies of scale producing declining average costs).

The competitive price is the single price at which the marginal cost curve intersects the demand curve. Due to declining average costs at the point where demand intersects marginal cost (the competitive price), a natural monopoly charging what would be the competitive price for capacity would not cover its total investment. This creates difficult questions of devising an efficient price structure.

See

Comment of El Paso Energy, Appendix A, at 15 (no way to ensure revenue adequacy for pipelines without deviating in some way from short-run optimal prices); 1 A. Kahn, The Economics of Regulation, 130 (1970) (in decreasing cost cases, price at marginal cost insufficient to cover total costs); R. Posner, Economic Analysis of the Law, § 12.1, 251-254 (2d ed. 1977) (difficulty of devising an efficient price structure for natural monopolies).

In this Part, the Commission discusses the changes in rate policies for capacity release transactions as well as for pipeline services. The first section discusses generally the inefficiencies created by the current regulatory method and how the removal of the rate ceiling for short-term capacity release transactions will create a more efficient and competitive marketplace. That is followed by discussion of changes in policy with respect to pipeline service, i.e., peak/off-peak and term differential rates. Finally, the use of voluntary auctions as a means of pricing short-term services is discussed.

A. Removal of the Rate Ceiling for Short-Term Capacity Release Transactions

During peak demand periods, when capacity is at a premium, the need to provide shippers with the greatest number of potential options and the most efficient competitive marketplace is crucial. Shippers that most need capacity during periods of scarce supply need a market that can efficiently respond to their demands and provide the capacity they need. The Commission's regulatory framework also needs to protect captive customers and fairly apportion revenue responsibility between captive customers with limited alternatives and short-term shippers with greater options. At the same time, the Commission's regulatory mechanism needs to provide all shippers with as much regulatory protection against the exercise of market power as possible. The removal of the rate ceiling for capacity release transactions with continued cost-of-service regulation of pipeline services better satisfies these objectives than continuation of the current uniform maximum rate ceiling for capacity release transactions.

This section first examines the inefficiencies engendered by the current uniform maximum rate ceiling; second, it summarizes the options put forward in the NOPR and comments for dealing with these inefficiencies; third, it discusses how the removal of the rate ceiling for capacity release transactions provides for more efficient markets and protects captive customers, while maintaining cost-based regulation of pipeline services as a protection against market power; and fourth, it addresses the comments on the legal and policy basis for these regulatory changes.

1. Current Regulatory Framework

a. Description of the Current Regulatory Framework.

Under section 4 of the NGA, rates are established by the pipeline filing for rate changes. The rates thus established continue in effect until the pipeline makes a subsequent rate case filing or the Commission takes action under section 5 of the NGA and determines that the existing rates are not just and reasonable.

The Commission currently develops a maximum annual transportation rate for each pipeline that, when applied to the pipeline's contract demand and throughput levels, will enable the pipeline to recover its annual cost-of-service revenue requirement. When the Commission sought to develop a maximum rate for monthly or daily interruptible or short-term firm transactions, it simply took the yearly maximum rate and divided by 12 or 365, respectively.

The principal reason for limiting pipeline rates to a level that would permit recovery of the pipeline's annual revenue requirement is to limit the ability of the pipelines to exercise market power, so that the pipeline does not charge excessive rates. Without rate regulation, pipelines would have the economic incentive to exercise market power by withholding capacity (including not building new capacity) in order to raise rates and earn greater revenue by creating scarcity. Because pipeline rates are regulated, however, there is little incentive for a pipeline to withhold capacity, because even if it creates scarcity, it cannot charge rates above those set by its cost-of-service. Since pipelines cannot increase revenues by withholding capacity, rate regulation has the added benefit of providing pipelines with a financial incentive to build new capacity when demand exists. The investment in new capacity increases a pipeline's revenue because the new investment increases the pipeline's rate base on which the pipeline earns a rate of return.

Thus, annual rate regulation protects against the pipeline's exercise of market power by limiting the incentive of a monopolist to withhold capacity in order to increase price as well as creates a positive incentive for a pipeline to add capacity when needed by the market.

For instance, if a pipeline has a current rate base of $1 million and an approved overall rate of return of 10%, the pipeline earns $100,000. However, if demand justifies an expansion of the pipeline's system at a cost of $500,000, at the same rate of return, the pipeline would earn $150,000, thus creating a financial incentive to expand the pipeline's system whenever demand permits.

The protection provided by rate regulation, however, is related solely to the pipeline's annual revenue requirement, not to the monthly or daily rate charged by the pipelines for capacity. The monthly or daily rate does not approximate the rates that would be charged in a competitive market, since such short-term rates do not seek to match price with the demands placed on the system. Indeed, the current regulatory model permits pipelines to exercise market power by selectively discounting their daily, monthly, and sometimes yearly rates (in effect price discriminating) at rates less than the maximum rate. Selective discounting helps the pipeline generate more annual revenue than it could receive by charging a single fixed price. The justification for permitting selective discounting is that the additional revenue benefits those shippers paying maximum cost-of-service rates by reducing, in the pipeline's rate case, the amount of the costs that otherwise would be recovered through the rates paid by those captive customers.

Associated Gas Distributors v. FERC, 824 F.2d 981, 1010-1012 (D.C. Cir. 1987),

cert. denied,

485 U.S. 1006 (1988); Comment of El Paso Energy, Appendix A (price discrimination below the existing maximum rate helps pipelines recover cost-of-service); 1 A. Kahn, The Economics of Regulation 131-33 (1970) (price discrimination one solution to problems of natural monopoly and declining costs).

In Order No. 636, the Commission applied the daily maximum rate to capacity release transactions. At that time, the Commission declined requests to remove the price cap for released capacity on the ground that the release market had not been shown to be sufficiently competitive.

When Order No. 636 was issued, most gas transactions occurred at the wellhead or upstream market centers.

Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under part 284 and regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 636-A, (Regs. Preambles Jan. 1991-June 1992) FERC Stats. & Regs. ¶ 30,950, at 30,569 (1992).

Since Order No. 636, the gas market has continued to evolve with the development of spot markets in downstream markets at which customers without firm capacity or without sufficient capacity to cover their needs purchase delivered gas on a short-term basis. The price for these transactions reflects both the cost of gas and the value of transportation to the delivered market. Figure 5 shows the variances between weekly average gas prices in various upstream and downstream markets as well as the implicit price for transportation between each of the markets. The prices at each designated market represent the price of gas and the figures in parenthesis between markets represent the implicit value of transporting gas from the lower priced to the higher priced market. The prices in

downstream markets, such as the Chicago Citygate, represent the price paid by shippers purchasing delivered gas at that market.

The implicit price for transportation represents the most any shipper purchasing delivered gas at a downstream market would pay to move gas from the lower priced market to the higher priced market. For instance, the implicit value of transportation between the Henry Hub and the Chicago Citygate market was $.07 in September 1999 (the difference between the $2.67 price for gas in Chicago and the $2.60 price at the Henry Hub).

The prices in downstream markeets do not represent the price firm shippers would pay. A firm shipper could purchase gas at the Henry Hub price and would pay only the low usage charge to transport gas to Chicago.

A shipper would not pay more than $.07 to transport gas purchased at $2.60 at the Henry Hub to the Chicago Citygate market, because the shipper could buy gas for $2.67 at the Chicago Citygate.

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The value of the transportation component of these bundled sales transactions results from the interaction of supply and demand forces and, unlike capacity release transactions, is not constrained by the maximum rate. Particularly during peak periods, shippers making bundled sales in the current market can avoid the maximum transportation rate and thereby obtain the market value for their capacity.

Figure 6 shows the increasing value of the transportation component during peak periods when demand for capacity is high. The transportation values in this chart represent the implicit amount that shippers that are unable to use firm capacity would pay for the transportation component of a bundled sales transaction. In the graph, for instance, the value of transportation rose to $6.50/MMBtu during the peak winter period of 1995-1996, to $1 during the winter of 1996-1997, and to less than $.50 during the winter of 1997-1998.

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Figure 7 illustrates how the value of transportation can vary on a daily basis. This graph shows the price of gas in the New York market for January 2000 compared with the price of gas in the production area. The line entitled production area price plus maximum transportation rate reflects the price that would be paid by a shipper purchasing gas in the production area and transporting that gas to New York at the maximum interruptible transportation rate on the pipeline.

As the chart shows, as temperatures dropped in the Northeast during January,

the price of buying delivered gas in New York rose to $15/MMBtu. In contrast, before the weather turned colder, the price of delivered gas in New York essentially reflected the price of gas in the production area plus the maximum transportation rate to transport that gas to New York. The difference between the price in the New York market area and the production area price represents the implicit price for (or value of) transportation paid by those shippers buying delivered gas in New York.

Firm shippers would pay a lower rate because they would pay the production area price plus a usage charge of only $.0202 which is much lower than the maximum interruptible transportation rate of $.3147.

See

Transcontinental Gas Pipe Line Corporation FERC Gas Tariff, Third Revised Volume No. 1, Eighth Revised Sheet No. 35-A (firm usage charge zones 4-6) and Eighth Revised Sheet No. 42 (interruptible rate zones 4-6).

The temperatures during this period changed from daily range in the low mid-thirties to low fifties to mid-thirties during the early part of the month to temperature ranges in the teens and low twenties during the later part of the month. The temperatures are reported at http://www.wunderground.com/US/NY/New_York.html (historical data).

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Market Area Price—The market area price is the price paid by short-term customers (those without sufficient firm capacity for their needs) to obtain gas in the New York market. Shippers using firm capacity would pay the production area price plus the 2 cent usage charge to transport gas to New York.

Production Area Price—This is the price of gas purchased at the production area.

Production Area + Maximum Transportation rate—This is the price a shipper would pay if it could buy gas in the production area and ship it to New York at the pipeline's maximum IT rate.

Value of Transportation—The value of transportation is the area between the market area price and the production area price. During much of January, the value of transportation is shown to be about equal to the maximum IT rate. The value exceeds that rate only on days of peak demand.

These graphs show that the value of transportation, particularly during peak periods, is not related to the maximum tariff rates for transportation. As one commentator has stated, “gas commodity markets now determine the economic value of pipeline transportation services in many parts of the country. Thus, even as FERC has sought to isolate pipeline services from commodity sales, it is within the commodity markets that one can see revealed the true price for gas transportation.”

Because the Commission's current regulatory model permits discounting below the maximum rate, the Commission's regulation does not inhibit pipelines and shippers from adjusting transportation rates to the off-peak demand in the market. However, during peak periods, the Commission's maximum rate cap does not allow unbundled transportation prices to equilibrate with demand.

M. Barcella, How Commodity Markets Drive Gas Pipeline Values, Public Utilities Fortnightly, Feb. 1, 1998, 24-25;

See

Henning & Sloan, Analysis of Short-Term Natural Gas Markets (Energy and Environmental Analysis, Inc., Nov. 1998) (showing how basis differentials between prices in different pipeline corridors correlate with value of capacity release transactions); B. Schlesinger, Natural Gas Industry Trends: Commoditizing Everything in Sight,

http://www.nymex.com

(November 17, 1999) (basis competition establishes the value of transportation capacity); R. O'Neill, C. Whitmore, M. Veloso, The Governance of Energy Displacement Network Oligopolies, Discussion Paper 96-08, at 41 Federal Energy Regulatory Commission, Office of Economic Policy, revised May 1997) (copy available from the Federal Energy Regulatory Commission) (the option to buy transmission rights is worth the difference in spot prices between two geographic areas, as opposed to a rate relating to embedded costs).

The fact that the value of transportation in the short-term bundled sales market exceeds the daily or monthly maximum rate now permitted in pipeline tariffs is not surprising, nor is it evidence that market power is being exercised. The daily or monthly rates (derived by simple division of the annual rate) were never intended to replicate prices that demand conditions would produce.

Particularly during peak periods, the value of transportation will rise because the transportation quantity demanded begins to exceed the quantity of capacity supplied. As a result, a higher price is needed to efficiently allocate transportation to those who most need to obtain it and are willing to pay the highest price for the bundled commodity. Such price increases would occur in any competitive market when supply becomes constrained relative to demand. This situation must be distinguished from the exercise of market power when a pipeline has power to raise prices by withholding capacity, creating greater scarcity than would occur in a competitive market. Indeed, all commenters recognize that the bundled sales market operates independently of the regulated rate governing straight-forward (unbundled) capacity transactions, but none suggest that the Commission should attempt to impose more stringent regulation on the bundled sales market.

The rationale for the commission's method of regulating the rates of pipeline transactions does not apply to capacity release transactions. As discussed earlier, by regulating pipelines' rates so they cannot recover more than their annual revenue requirement, the Commission seeks to ensure that the pipelines do not have an incentive to withhold capacity to create excess returns. But this justification for rate regulation has little applicability to capacity release transactions, since releasing shippers are not in the position to withhold long-term capacity by failing to add capacity when necessary.

b. The Price Constraint for Capacity Release Transactions Reduces Efficiency.

Applying a ceiling to the rate for capacity release transactions does not achieve the Commission's regulatory objectives. It reduces shippers' options, decreases the efficient operation of the market, and does not adequately protect captive customers.

Particularly during peak constraint periods on pipelines, preventing transportation prices from exceeding the pipeline's maximum rate can reduce the options of shippers purchasing in the short-term market. With the maximum rate cap, a shipper, without a contract sufficient to cover its requirements on a peak day, that is seeking to acquire additional capacity has limited options. It can first try to obtain pipeline interruptible capacity at the maximum rate cap, if the capacity is available. Even if pipeline capacity is available, the shipper may be unable to obtain that capacity despite placing the highest value on the capacity. Because the pipeline cannot exceed the maximum rate, the pipeline must allocate its available capacity either on a

pro rata

basis or on the basis of a queue based on contract execution date. In either case, a shipper may not obtain the capacity or the amount of capacity it needs regardless of whether it places the highest value on the capacity.

The shipper is therefore left with only two available options: to purchase gas in a bundled transaction in the downstream market at a price reflecting the market-determined value of transportation, or to simply take the gas out of the pipeline and pay the pipeline's scheduling or overrun penalties. The shipper generally will not be able to obtain released capacity at the capped price, because holders of that capacity are unlikely to release capacity at a price less than the amount they can receive by making a bundled sales transaction. Thus, during a peak day, capping the price of released capacity does not effectively limit the price a purchaser has to pay to obtain transportation service. It only serves to limit the purchasing shipper's capacity options.

But the shipper's other options—using a bundled sales transaction or incurring overrun and scheduling penalties—may not be the most efficient choice. The purchaser may prefer not to use the bundled gas sales market when it has a natural gas contract at a less expensive price than the price of gas included in the bundled transaction and, as a result, would prefer to use its own gas. To use its own gas supplies to meet its peak day needs, the shipper would have to pay substantial penalties for overrunning its transportation contract. Shippers accumulating overruns also compromise the operational integrity of the pipeline's system, leading to a degradation of service for all shippers, including the possibility of service curtailment through operational flow orders, during peak periods when shippers most need the system to run efficiently.

Moreover, even if the maximum rate cap were more effective in limiting the prices at which firm capacity holders could resell capacity (for instance, LDCs who are unable to make bundled sales),

it would provide little benefit to shippers purchasing capacity during peak periods. The maximum rate cap

reduces the efficiency of the market by preventing the efficient allocation of capacity to those who most need it and are willing to pay for it. During a time of capacity constraint, there may not be sufficient capacity to serve all shippers seeking capacity at the maximum rate. It is therefore necessary to allocate or ration that capacity among the shippers desiring it. The Commission's regulations, in fact, require that one of the objectives in setting rates is to ration capacity during peak periods.

The appropriate method of rationing scarce capacity is to allocate the capacity to those who place the greatest value on obtaining that capacity. Maximum rate regulation prevents such allocation during constrained periods, resulting in shippers who place a lower value on capacity retaining their capacity, rather than selling the capacity to shippers placing a greater value on obtaining the capacity.

See

Comment of Arkansas PSC (price ceiling is effective, if at all, only on LDC capacity releases which tend to be unbundled sales of capacity).

18 CFR 284.7(b)(1), redesignated § 284.10(b)(1).

Restrictions on capacity release transactions limit the development of an efficient and viable capacity market and can skew customer capacity choices. If a customer could rely on an effective short-term market to obtain additional capacity during peak periods, it might decide that it was not necessary to reserve sufficient long-term firm transportation to cover all of its peak day needs. It could be more economic for it to purchase short-term daily capacity, even at a high price, when it needed additional capacity, as opposed to paying for long-term capacity to meet peak needs. However, if the short-term market is less reliable, and, as a result, the customer valuing the capacity the most cannot acquire as much as it needs, the customer will be more reluctant to relinquish long-term capacity and rely upon the short-term market for its peak needs.

The comments recognize that the Commission's current regulatory policy can result in market distortions and inefficiencies.

See

Comments of Amoco I, at 17-18 (“maximum rates can result in inefficiencies); INGAA, at 25 (graph of transportation value shows that the market value of capacity is less than its allocated cost during off-peak periods and must be discounted); AGA I, at 13 (off-peak customers receive transportation at discounted rates which cannot be recouped during peak periods); El Paso Energy, Appendix A (allocative inefficiencies exist when prices exceed maximum rate).

Indeed, the use of the pipeline's maximum rate as the cap for capacity release transactions, can reduce the amount of released capacity available during peak periods, precisely the period when capacity is needed most. As a result of the maximum rate, firm capacity holders may not find it sufficiently profitable to make their capacity available for release. For instance, a dual fuel industrial customer might determine that it would be more economic not to use gas, and to substitute a different fuel, if it could obtain a sufficiently high price for its released capacity. Similarly, an LDC might have a peak shaving capability (storage or liquefied natural gas (LNG)) that costs more to produce and deliver gas than purchasing the gas in upstream markets and using its transportation capacity to transport that gas to its citygate. The LDC might be willing to release its transportation capacity and use the peak shaving device instead if it could receive a price above the maximum rate for its transportation capacity so that the amount it receives for the release of its transportation capacity covers the costs of the peak shaving device.

By using its peak shaving device instead of transportation, the shipper would be expanding the amount of released capacity available during a peak period. But if the price cap prevents the shipper from obtaining a price higher than the cost of the peak shaving device, and the shipper cannot sell the gas on a delivered basis, the shipper will use its transportation capacity, thus depriving other shippers (without peak shaving) of the opportunity to acquire needed transportation capacity. Removal of the price cap, therefore, could make additional released capacity available during peak periods to those most needing that capacity. As more capacity enters the marketplace during peak periods, the consequence would be a lowering of transportation prices, which would be of significant benefit to all shippers needing capacity when the pipeline system is most constrained.

Suppose the costs to the LDC of using the peak shaving device were $6.00/MMBtu and the costs of buying gas in the upstream market was $4.00/MMBtu with a $.10/MMBtu usage charge (under its firm contract) for transportation, If the LDC could resell its transportation capacity for more than $1.90/MMBtu (the difference between using its peak shaving device and its transportation service), it would release that capacity and use its peak shaving instead. If the release were subject to a maximum cap of less that $1.90, however, the LDC would choose not to peak shave and the capacity would not be released to others.

See

Comments of Amoco I, at 17-18 (“incremental costs due to market inefficiencies (which may be described as transaction costs) may arise during periods when the demand for capacity exceeds its supply, resulting in delivered gas prices in downstream markets that are higher than they would be in a more allocatively efficient, i.e., liquid and transparent market”).

Capping capacity release transactions during peak periods at the current maximum rate system also harms captive customers holding long-term contracts on the pipeline. These customers have to pay maximum rates for both peak and off-peak periods. During off-peak periods, when prices are generally low, they cannot recover the cost of their investment. But, when demand increases the value of capacity, captive customers cannot reap the benefits of the higher value through a straight-forward release of capacity. Instead, their only alternative in selling capacity is to seek to make bundled sales transactions, which may be more difficult for smaller customers and raise transactions costs for both parties.

2. Alternatives to the Price Cap

In the NOPR, the Commission proposed one alternative to respond to the inefficiencies created by price caps, as well as requesting comments on other approaches. The Commission proposed to eliminate the maximum rate from both short-term (less than one year) capacity release and pipeline transactions, together with a number of proposals to increase competition in the short-term market and limit the exercise of market power. Chief among the proposals was the requirement that all short-term capacity would be sold through an auction process in which daily pipeline capacity would be sold without a reserve (or minimum) price. The purpose of the no-reserve price proposal was to protect against the exercise of market power in the short-term market by ensuring that pipelines could not withhold capacity. In addition, the Commission solicited comment on other potential approaches, such as the use of seasonal rates or the application of market power analysis similar to that used in the Alternative Rate Design Policy Statement,

to determine whether markets are sufficiently competitive to remove regulatory rate ceilings for all services.

Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and Regulation of Negotiated Transportation Services of Natural Gas Pipelines, 61 FR 4633 (Feb. 7, 1996), FERC ¶ 61,076 (1996).

The comments, for the most part, do not challenge the Commission's analysis of the inefficiencies created by maximum rate regulation in the short-term market, but they take very different positions as to the possible solution. Some commenters, principally pipelines, support removal of the price cap for all services in the short-term market, contending removal would improve market efficiency, mitigate the adverse effects of the current cost-based rate designs, increase competition, and remove a major obstacle to contracting

for long-term capacity.

Many of the comments, however, contend that the Commission should not remove rate regulation over pipelines, because pipelines continue to hold market power. They maintain that rate caps can be removed only upon a showing that market power cannot be exercised.

Several commenters, particularly LDCs, support removal of price caps for short-term capacity release transactions, but not for pipeline services.

Comments of Consolidated Natural Gas I, IMD, Koch I, MichCon, NYMEX, Nicor, PG&E, Mercatus, Sempra Energy, TransCanada, and Williams I.

Comments of Arkansas Gas Consumers, Market Hub Partners, NWIGU, Process Gas Consumers, et al., and Southern Company Services, Amoco I, IPAA, Indicated Shippers, NGSA, PanCanadian, PSC of New York I, and CPUC.

Comments of AGA I, Arkansas PSC, ConEd, Enron Pipelines, Illinois Commerce Commission, INGAA, NARUC, NASUCA, Nisource, Pennsylvania/Ohio Consumer Advocates, Pennsylvania PUC, Philadelphia Gas Works, Piedmont/UGI, PSC of Wisconsin I, PUC of Ohio, and Washington Gas Light.

Some commenters support the use of auctions as a method for limiting the exercise of market power and providing a non-discriminatory method for allocating capacity, although they recognize that there may be a need to implement some mechanism to protect pipelines against cost under-recovery.

By far the vast majority of commenters, however, oppose the use of mandatory auctions at this time, principally out of a concern that auctions would be complex and expensive, would require more personnel to monitor the auctions on multiple pipelines, would not work as efficiently as the use of pre-arranged deals for capacity exchanges, would not permit coordination between gas and capacity purchases, could interfere with state unbundling plans by inhibiting prearranged releases, and would frustrate asset management arrangements.

100

INGAA and AGA raise concerns about the impact of mandatory no-reserve price auctions on pipelines' or firm shippers' abilities to recover their investments. Several commenters suggest the use of voluntary rather than mandatory auctions as a way to gain more experience with auctions.

101

Others suggest that while auctions may be a viable method of allocating capacity, a mandatory auction may not be the most efficient method of allocating capacity and may inhibit the development of other equally efficient approaches, in particular pre-arranged deals. They suggest that the Commission should not mandate the use of auctions, but instead consider a variety of options, including auctions that would prevent withholding of capacity.

102

Comments of Altra Amoco I, Florida DMS, Sithe, Southern Company Energy Marketing, and Southern Company Services. While not directly supporting removal of the maximum rate cap, Indicated Shippers and NGSA maintain that if the price cap is lifted, auctions need to be required.

100

Comments of AEC Marketing, Allenergy Marketing, et al., AGA I, CMS Panhandle, Coastal I, Colorado Springs I, Columbia LDCs, Consolidated Natural Gas I, Cove Point, Duke Energy Trading, El Paso, Enron Pipelines, INGAA, KN, Koch I, Louisville, Mississippi Valley, et al., National Fuel Gas Supply, Nisource, NWIGU, PanCanadian, Pennsylvania PUC, Peoples Energy I, Philadelphia Gas Works, Piedmont/UGI, Process Gas Consumers, et al., Reliant, Sempra Energy, TETCO/Algonquin, TransCanada, Williston Basin, Williams I, and UGI. Other commenters, while not specifically opposing auctions, raise similar concerns about the use of auctions. APGA, Enron Capital & Trade, Entergy, Fertilizer Institute, Foothills, Illinois Commerce Commission, IMD, Market Hub Partners, NARUC, Nicor, PG&E, PNGTS, Proliance, PSC of Kentucky, PSC of New York I, PSC of Wisconsin I, CPUC, Mercatus, Shell, and Southwest Gas.

101

Comments of Colorado Springs I, Enron Capital & Trade, Enron Pipelines, INGAA, K N, National Fuel Gas Supply, Sempra Energy, and TransCanada.

102

Comments of Mercatus; CAPP/ADOE.

In place of mandatory auctions, INGAA, along with most pipelines, and AGA, and most of the LDCs, propose an alternative to mandatory auctions under which the Commission would remove maximum rate caps from capacity release transactions, but not pipeline transactions. INGAA and AGA argue that such an approach would eliminate inefficiencies in the marketplace while preserving pipeline capacity as a “just and reasonable” safe harbor or recourse service. INGAA also proposes that pipelines be permitted to institute seasonal rates to better reflect peak and off-peak demands faced by many pipelines. INGAA maintains that permitting pipelines to institute seasonal rates where demand differs throughout the year would help to ameliorate the inequities of the current ratemaking structure in which shippers purchasing short-term capacity are able to shift costs to those customers purchasing capacity on a long-term basis at maximum rates. INGAA further proposes that seasonal rates be cost-based in the sense that they be limited by the pipeline's revenue requirement. INGAA suggests a number of ways in which seasonal rates could be designed, for instance, using seasonal pipeline utilization, and others suggest other approaches.

103

Comments of Enron Pipelines, Amoco I.

3. The Regulatory Changes Implemented in this Rule

In this rule, the Commission is revising its policies on rate regulation to improve marketplace efficiency by adopting the two-part approach suggested by commenters: removing the rate ceiling for capacity release transactions and clarifying its policy on seasonal rates to permit pipelines to file for differing peak and off-peak rates based on different demand conditions on those pipelines. The Commission is waiving the rate ceiling in its capacity release regulations

104

until September 30, 2002 for short-term releases of capacity of less than one year beginning upon the effective date of this rule. The Commission, however, is continuing its current regulations regarding the posting and bidding for capacity release transactions of greater than one month.

104

The waiver is contained in redesignated § 284.8(i). The existing capacity release regulations are not being revised.

While the removal of the price cap is justified based on the record in this rulemaking, the Commission recognizes that this is a significant regulatory change that should be subject to ongoing review by the Commission and the industry. No matter how good the data suggesting that a regulatory change should be made, there is no substitute for reviewing the actual results of a regulatory action. The two year waiver will provide an opportunity for such a review after sufficient information is obtained to validly assess the results. Due to the variation between years in winter temperatures, the waiver will provide the Commission and the industry with two winter's worth of data with which to examine the effects of this policy change and determine whether changes or modifications may be needed prior to the expiration of the waiver.

At this point, the Commission is retaining the price cap for capacity release transactions over one year because this rule is focused on revising regulations that interfere with the efficient allocation of capacity during the short-term periods when demand pushes the value of transportation above the current maximum rate. There has been no showing made that for capacity release transactions of one year or more the value of capacity exceeds the uniform annual rate such that maximum rates impede efficiency. This policy too may be reassessed based on the results during the two year waiver period.

a. Consistency with the Commission's Regulatory Objectives.

The removal of the price cap from short-term capacity release transactions better satisfies the Commission's regulatory objectives than the current system. Removal of the rate cap will expand shippers' options, create a more efficient marketplace, increase market transparency, and better protect captive customers, without changing the current regulatory environment.

Removal of the rate ceiling from short-term capacity release transactions will remove an impediment to the development of an efficient capacity market by giving purchasers an additional option for obtaining capacity during peak periods. Instead of having only the choices of purchasing a bundled sale or incurring a contract overrun, a customer needing gas can directly obtain the capacity it needs from a firm capacity holder. Removal of the rate ceiling for capacity release transactions also will enhance efficiency by ensuring that capacity is properly allocated to those placing the most value on obtaining capacity during peak periods.

By fostering a more efficient short-term market, removal of the rate ceiling on short-term capacity release transactions will help create a more reliable short-term capacity market where shippers who need short-term capacity will know they can obtain as much capacity as they need by paying the market price. The development of a more reliable short-term capacity market, in turn, will enable shippers to make better informed choices about whether to purchase long or short-term capacity depending on their circumstances. Some shippers may prefer the price stability they obtain from a long-term firm contract. On the other hand, some shippers may opt not to contract for long-term capacity if they are assured of a reliable short-term capacity market in which they could obtain transportation by offering to pay the market price for the capacity.

105

Even demand inelastic customers in Chicago might not want to subscribe to sufficient firm capacity to meet the worst-case scenario that occurred in 1996

106

if an effective spot market exists in which they can obtain capacity when needed or hedge against the financial risk of buying in the spot market.

105

A low load factor shipper (one with greater demand during peak than off-peak) might find that paying reservation rates for a full year to hold long-term capacity sufficient to meet its peak needs is less economic than purchasing capacity only for the short time when it needs the capacity even if the rate for that short-term capacity is much higher than the yearly rate.

106

See

Figure 6,

supra

(showing the spike in gas price to $6.50/MMBtu during the winter of 1996).

The more reliable the market the less shippers and regulators may be pushed toward requiring long-term capacity contracts to ensure reliability. For example, with an effective market for transportation capacity, there could be less need for states contemplating retail unbundling to require marketers or LDCs, as suppliers of last resort, to hold firm capacity on pipelines to guarantee transportation, just as long-term contracts are no longer necessary to guarantee access to the gas commodity.

Removal of the rate cap for short-term capacity release transactions also will have an added benefit of increasing market transparency. In today's market, there is little information on the price of transportation capacity during peak periods, because, due to the price caps, transactions move to the bundled sales market. Permitting transportation capacity to trade freely during peak periods will increase the number of transactions moving from the bundled sales market to the transportation market, which, given the changes in reporting requirements adopted in this rule, will increase pricing information during peak periods, when such information is most critical to the marketplace.

Removal of the rate ceiling will have limited effect on the effective prices paid by customers using short-term transportation capacity. In today's market, when the value of transportation exceeds the maximum rate, firm capacity holders have an incentive not to release capacity, but to bundle that capacity with gas so that they can obtain the full market value of the transportation capacity by selling gas in the delivery market. Thus, removal of the rate ceiling should not significantly raise transportation prices, but will instead provide shippers looking for capacity with the alternative of buying transportation capacity directly rather than obtaining that capacity indirectly through a bundled sale.

Moreover, even if some replacement shippers do end up paying higher prices for capacity during peak periods than they did with the regulated rate in effect, it is appropriate for shippers using the system only during peak periods to pay higher prices reflecting the greater demand on the system. Short-term shippers currently receive the benefit of paying reduced capacity release prices during off-peak periods, but face a cap on the market price during peak periods. Removal of the rate ceiling on capacity release prices will ensure that those shippers which receive the benefit of lower market prices during off-peak periods face the higher market prices during peak periods. Removing the price ceiling for released capacity also will benefit captive customers by eliminating the regulatory bias built into the current rate structure. Long-term shippers pay the same rate for capacity during both peak and off-peak periods. During off-peak periods, they can recover only a small portion of their capacity cost through capacity release, because the market value for released capacity is generally quite low due to the reduced demand for capacity and the increased availability of released capacity. But during peak periods, the price cap limits long-term captive customers (who cannot make bundled sales) from receiving the full market value of their capacity. Long-term shippers pay for the largest proportion of the pipeline's fixed costs through their annual reservation charges, and permitting them to receive more revenue from capacity release transactions during peak periods will help them defray those costs.

b. Protections Against the Exercise of Market Power.

While removal of the rate cap for short-term capacity releases will add an additional capacity option, such removal does not significantly reduce the protection of shippers buying short-term transportation. First, the capacity release rate cap is largely ineffective in protecting short-term capacity purchasers in today's market since shippers can make bundled sales to evade the cap. Thus, removal of the rate cap will not provide releasing shippers with significant additional pricing freedom. Instead, it will improve the market for buyers by giving them an additional capacity option from which to choose.

Second, the fact that prices for transportation rise during peak periods is not evidence of the exercise of market power, but may be the appropriate market response to an increase in demand for capacity. During peak periods when there is insufficient capacity to satisfy all the demand for short-term capacity, an increase in market price would be the competitive response to a situation in which the quantity of transportation demanded increases relative to the quantity that can be supplied.

The rule also continues to provide protections against the possible exercise of market power by releasing shippers. Market power can be exercised in two ways: through withholding capacity to raise price or through price discrimination.

Firm shippers cannot successfully withhold capacity from the market to raise price above the existing maximum just and reasonable rate because, if the firm shippers do not use their capacity, the pipeline has the incentive to sell the capacity as interruptible service. Moreover, the Commission is continuing to protect against the possibility that, in an oligopolistic market structure, the pipeline and the firm shippers will have a mutual interest in withholding capacity to raise

price because the Commission is continuing cost-based regulation of pipeline transportation transactions. The pipelines will be required to sell both short-term and long-term capacity at just and reasonable cost-based rates. In the short-term, a releasing shipper's attempt to withhold capacity in order to raise price above maximum rates will be undermined because the pipeline will be required to sell that capacity as interruptible capacity to a shipper willing to pay the maximum rate. Shippers also have the option of purchasing long-term firm capacity from the pipelines at just and reasonable rates.

In addition, the ability of pipelines to build additional capacity will check the potential exercise of market power by releasing shippers. Regardless of the value of scarce capacity, pipelines' rates are capped. Thus, if a pipeline observes that the market price for capacity exceeds the pipeline's maximum rate in the short-term market, and the market prices are sufficient to cover the cost of new pipeline capacity, the pipeline can capture that revenue only by building additional capacity to serve the demand. In many cases, capacity can be added relatively quickly simply by adding compression. Thus, firm shippers have little incentive to exercise market power by withholding capacity given the pipeline's ability and incentive to dissipate that market power through new construction.

The cost-based regulation of pipeline services also limits firm shippers' ability to price discriminate, since a purchaser who is unwilling to pay the price quoted by the releasing shipper can obtain pipeline capacity at cost-based rates. Firm shippers also would have difficulty engaging in price discrimination, because, given the ease with which capacity can be transferred between shippers, a releasing shipper would have trouble preventing arbitrage—a shipper which benefits from the lower price buying more capacity than it needs and reselling the excess to less-favored shippers.

107

See

Comment of Mercatus (price discrimination cannot be maintained where releasing shipper cannot limit arbitrage).

Besides the availability of pipeline capacity, the competitive pressures fostered by competition from released capacity will limit the potential exercise of market power. Many of the commenters argue that due to the competition for released capacity, release rates are low and firm shippers are unable to come close to recouping their investment in pipeline capacity.

108

CNG cites to a study commissioned by AGA and INGAA analyzing 17 major pipeline corridors, which showed that the average value of capacity release transactions varied from 31% to 76% of the maximum rate tariff rate applicable to the corridor.

109

108

Comments of AGA I, Arkansas PSC, Consolidated Edison, Enron Pipelines, Illinois Commerce Commission, INGAA, NARUC, NASUCA, Nisource, Pennsylvania/Ohio Consumer Advocates, Pennsylvania PUC, Philadelphia Gas Works, Piedmont/UGI, PSC of Wisconsin, PUC of Ohio, and Washington Gas Light.

109

The study cited is Henning & Sloan, Analysis of Short-Term Natural Gas Markets (Energy and Environmental Analysis, Inc., November 1998).

Since Order No. 636, capacity release transactions have grown significantly, averaging 20 trillion Btu/day, for a total of 7.4 quadrillion Btu for the 12 month period ending March, 1997.

110

Competition from numerous shippers releasing capacity, therefore, will also lessen the ability of firm shippers to exercise market power. The Commission's policy requiring pipelines to provide flexible receipt and delivery points rights has enhanced competition. Due to the ability to use alternate receipt and delivery points, capacity purchasers are not limited to purchasing capacity only from shippers holding the primary point rights the purchaser needs. A purchaser can obtain capacity from any of a number of shippers and use the flexibility to use alternate points to access the receipt and delivery points it needs. In this rule, the Commission is improving various aspects of the capacity release mechanism, by speeding up the nomination process and requiring pipelines to permit shippers to segment capacity, which will further enhance competition between releasing shippers. Thus, capacity available from other shippers together with the availability of pipeline capacity will limit the ability of releasing shippers to exercise market power.

110

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0618(98), Deliverability on the Interstate Natural Gas Pipeline System 83 (1998).

As additional protection against the potential exercise of market power, the Commission in this rule is improving its reporting requirements to permit better monitoring of the marketplace and has recently instituted a revamped complaint process.

111

The improved reporting requirements will improve competition in the market by expanding shippers' information about potential capacity alternatives. Difficulty in obtaining information can reduce competition because buyers may not be aware of potential alternatives and cannot compare prices between those alternatives. The reporting requirements will expand shippers' knowledge of alternative capacity offerings by providing more information about the capacity available from the pipeline as well as those shippers holding capacity that is potentially available for release. The reporting requirements further will provide shippers with more accurate information about the value of capacity over particular pipeline corridors so that shippers can make more informed choices about the prices of capacity they may wish to purchase.

111

18 CFR 385.206 (adopted by Complaint Procedures, Order No. 602, 64 FR 17087 (Apr. 8, 1999), III FERC Stats. & Regs. Regulations Preambles ¶ 31,071 (Mar. 31, 1999).

In addition to providing better information about competitive alternatives that will enhance competition, the improved reporting requirements will better enable shippers and the Commission to monitor the market. Thus, both shippers and the Commission will be better able to identify situations in which market power is being abused, and the Commission will have more information to use in tailoring remedies in individual cases as the need arises.

Thus, the removal of rate ceilings will improve shipper options, create a more efficient marketplace, and make the Commission's ratemaking policies more responsive to market forces. Reasonable protection against the exercise of market power by releasing shippers will be provided by continuing cost-of-service regulation of the pipelines and competition in the release market, together with enhanced reporting requirements that will improve information about capacity alternatives and shippers' ability to monitor the market for market power abuses.

4. Legal Basis for Removing the Rate Ceiling for Short-Term Capacity Release Transactions

Several commenters maintain that, under its statutory mandate, the Commission cannot legally rely upon market-based rates without making a finding that market power cannot be exercised.

112

APGA, for example, contends that the existence of the bundled sales market should not be used as justification for removing rate regulation in the capacity market. Process Gas Consumers (Process Gas Consumers I) and Indicated Shippers (Indicated Shippers Reply) contend the Commission cannot remove price caps for released capacity even if ceilings remain on pipeline capacity.

112

Comments of Process Gas Consumers, Indicated Shippers, NGSA, APGA, IPAA.

The Commission concludes that the removal of the price cap for capacity release transactions, together with continued regulation of pipeline rates, comports with its statutory responsibilities. The Commission has the statutory obligation under the NGA to ensure that pipeline rates and services are just and reasonable. Establishing just and reasonable rates requires the Commission to protect consumers of natural gas from the exercise of monopoly power by pipelines,

113

while, at the same time, ensuring that those rates improve the competitive structure of the natural gas industry to maximize the benefits of wellhead decontrol.”

114

In seeking to achieve these goals, the courts have recognized that the Commission is not bound to use any particular pricing formula in determining just and reasonable rates

115

and that cost-based regulation can be relaxed as long as the overall “regulatory scheme” ensures that rates are within a zone of reasonableness.

116

The Commission is permitted to move to lighter-handed regulation as long as it ensures that the goals and purposes of the statute will still be accomplished.

117

The courts have permitted the Commission to institute flexible pricing to improve market efficiency so long as the overall regulatory scheme protects against price gouging.

118

Market-based rates have been approved when the Commission has found sufficient protection against the exercise of market power.

119

113

FPC

Hope Natural Gas Co.,

320 U.S. 591, 610 (1944);

Associated Gas Distributors

FERC,

824 F.2d 981, 995 (D.C. Cir. 1987),

cert. denied,

485 U.S. 1006 (1988) (“The Natural Gas Act has the fundamental purpose of protecting interstate gas consumers from pipelines' monopoly power.”).

114

Natural Gas Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989); Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Oder No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles (Jan. 1991-June 1996) ¶30,939, at 30,932 (Apr. 8, 1992).

115

FPC

Hope Natural Gas Co.,

320 U.S. 591, 602 (1944);

Elizabethtown Gas Company

FERC,

10 F.3d 866, 870 (D.C. Cir. 1993).

116

See

Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 1509-10 (D.C. Cir. 1984).

117

Farmers Union, 734 F.2d 1486 at 1510.

118

Environmental Action

FERC,

996 F.2d 401, 410 (D.C. Cir. 1993).

119

Elizabethtown Gas Company

FERC,

10 F.3d 866 (D.C. Cir. 1993).

The Commission finds that the regulatory changes made in this rule ensure a regulatory scheme that protects against the exercise of market power and ensures that rates are within the “zone of reasonableness” even without a price cap on short-term capacity release transactions. In the first place, the removal of the rate cap for capacity release transactions does not effectively change the status quo, since the value of transportation in the bundled sales market can exceed maximum tariff-based rates. Thus, continuation of the maximum rate cap on unbundled capacity release transactions does little to protect against the exercise of market power by firm capacity holders. Its principal effect is to provide shippers with additional transportation options, to create greater efficiency in capacity allocation, and to move transactions from the less-well-reported bundled sales market to the better-reported transportation market. By removing the price cap from capacity release transactions, the Commission is not reducing protection for customers seeking released capacity, but is expanding their options and helping to foster a more efficient and transparent marketplace for released capacity.

In addition, the Commission is not adopting market-based rates for all capacity. It is removing rate regulation only from one element of the competitive mix—short-term capacity release transactions by shippers—while retaining regulation for sales of pipeline capacity. The Commission also is continuing to protect its primary constituency—captive long-term firm capacity holders—by continuing the same cost-of-service rate regulation that has been used for years.

120

The regulatory change in this rule affects only shippers buying short-term released capacity who are already at risk of not being able to acquire capacity.

121

As explained earlier, the Commission's regulation of pipeline transactions, as well as the operation of market forces, also will protect against the exercise of market power and keep capacity release rates within the zone of reasonableness.

120

See

Maryland People's Counsel

FERC,

761 F.2d 768 (D.C. Cir. 1985);

Maryland People's Counsel

FERC,

761 F.2d 780 (D.C. Cir. 1985) (special concern for effect of program on core captive customers).

121

See

American Gas Association

FERC,

912 F.2d 1496, 1518 (D.C. Cir. 1990) (interruptible and short-term capacity holders not entitled to the same protection against market power as long-term firm capacity holders).

AFPA contends that short-term shippers may be captive customers. But, short-term customers, those using interruptible or short-term firm pipeline service or relying on capacity release transactions, are, by the very nature of the services for which they contract, not captive. They are expressly taking the risk that during peak periods, they will be unable to obtain capacity and either are willing to forgo the use of gas entirely or are willing to pay the prices needed to obtain gas from alternative sources. Such customers, in fact, receive more protection if they can obtain the capacity they need by offering a sufficiently high price than if the price is regulated and they are unable to obtain capacity at all. If short-term customers want the insurance of having guaranteed transportation service, that security is available by obtaining long-term firm capacity from the pipeline.

Moreover, as explained in the previous section, the availability of regulated pipeline capacity as well as competition between holders of firm capacity mitigates the potential for releasing shippers to exercise market power. In

Environmental Action

FERC

122

the court recognized that the Commission may need to relax price regulation in order to improve market efficiency and approved a flexible pricing program as long as the program maintained protections against the exercise of market power.

123

Here, the Commission similarly is improving the efficiency of capacity trading during peak periods while maintaining cost-of-service regulation for pipeline firm and interruptible service that will limit the ability of both firm capacity holders and the pipelines to exercise market power by withholding capacity.

122

Environmental Action

FERC,

996 F.2d 401 (D.C. Cir. 1993).

123

As the Court stated:

We acknowledge that the flexible pricing that fosters trading among members of the Pool also permits price discrimination especially against captive utilities. Yet, given the benefits of this trading, the limited number of captive members, and the provisions for monitoring transactions and remedying any abuses of market power, we do not find that the Commission acted arbitrarily when it approved the use of flexible prices despite their admitted risk. 996 F.2d at 411.

Indicated Shippers suggest that removing the rate ceiling from capacity release transactions will permit firm capacity holders to exercise market power by withholding capacity from the market because they are not obligated to release that capacity. However, removing the rate ceiling will not permit a firm shipper to withhold capacity from the market to raise price above the maximum rate, because, in the short-run, that capacity always will be available from the pipeline as interruptible capacity, which the pipeline is obligated to sell at the approved just and reasonable rate. In the long run, pipeline firm transportation also is available as a check against short-term market power and the continuation of cost-of-service regulation for the pipelines provides an incentive for the pipeline to build additional capacity when justified by demand.

Process Gas Consumers maintains that competition may not limit the market power held by LDCs because they control access to primary delivery points and that obtaining secondary point access from other firm holders may not be the equivalent of obtaining primary point access from the LDC, particularly during periods of constraint when the pipeline may interrupt secondary deliveries. Process Gas Consumers also maintains that LDCs, by virtue of their control over their own facilities, can exercise market power over customers behind the city-gate and contends the Commission should not remove price ceilings for LDCs unless the LDCs provide shippers with reasonable city-gate access.

The Commission does not find that LDCs should be treated differently than other firm shippers with respect to their ability to release capacity. Such a distinction would skew the capacity release market by creating different classes of customers: one class without a price ceiling and the LDCs with a price ceiling. An LDC also is not more likely than other firm shippers to exercise market power by withholding capacity, because if it tried to do so, the capacity would be available from the pipeline as interruptible transportation, which the pipeline is obligated to sell at just and reasonable rates.

Moreover, as Process Gas Consumers itself recognizes, the Commission's jurisdiction does not extend to LDC activity behind their city-gates, which are the province of state regulatory authorities. Complaints about LDCs handling of transportation on their own systems are properly directed to the state regulatory agencies with jurisdiction over those activities. To the extent that an LDC engages in specific abuses of its market power over interstate transportation capacity, the Commission can remedy such abuses through individual action. The improved reporting requirements together with the Commission's revised complaint process will enable both shippers and the Commission to discern and redress abuses of market power. The possibility of abuse in specific circumstances, which can be addressed on an individual basis, should not preclude the Commission from adopting a policy that benefits the industry as a whole by enhancing customer options and improving marketplace efficiency.

AlliedSignal complains that removal of the price cap will leave the market open to hysteria leading to exorbitant prices during times of peak demand. In the first place, high prices during peak demand periods can be a function of supply and demand forces that raise prices to allocate capacity during peak periods. As long as capacity is not being withheld from the market and no discrimination is taking place, the high prices are a reasonable and necessary competitive response to market conditions to allocate capacity to those needing it the most. Indeed, as shown by the period of rate regulation of wellhead prices, maintenance of regulated prices can distort the market by upsetting the balance between supply and demand.

124

In any event, continuation of rate regulation for capacity release transactions will not limit the effect of so-called market hysteria, since the Commission's rate regulation has no effect on the prices for bundled gas and transportation capacity. Removal of price regulation from short-term capacity release transactions, therefore, will not add to pricing problems during peak periods, but instead should help to minimize these problems by increasing customers' options.

124

See Transcontinental Gas Pipe Line Corporation

State Oil and Gas Board,

474 U.S. 409, 420 (1986) (Natural Gas Act's artificial pricing scheme is a major cause of imbalance between supply and demand).

Dynegy and Process Gas Consumers raise the questions of whether pipelines can avoid protections against the exercise of market power by transferring capacity to their affiliates. In one respect, transfers of capacity to affiliates will not enable the corporate entity to exercise market power. Affiliates, like LDCs or other firm capacity holders will not be able to exercise market power, because they cannot effectively withhold capacity. If the affiliate refuses to release capacity, the pipeline still is obligated to sell the capacity at just and reasonable rates and cannot conspire with the affiliate to withhold capacity.

In another respect, transfers of capacity to affiliates could be troublesome, but not because the affiliate could exercise market power in the release market. One aspect of Commission regulation is intended to ensure that pipelines have the incentive to expand their pipeline when it is economic to do so. Through cost-of-service of regulation, the Commission ensures that pipelines do not benefit by creating scarcity by refusing to build long-term capacity.

125

However, if a pipeline affiliate holds a large enough block of capacity on its related pipeline, the corporate entity as a whole could benefit if the pipeline refused to build capacity, creating greater scarcity and higher prices and profits for the affiliate, which is not subject to cost-of-service limitations. This problem exists only in cases where an affiliate holds a large enough portion of pipeline capacity that the corporate entity as a whole can make more by creating scarcity than by building additional capacity and earning a rate of return on its investment.

125

Under cost-of-service regulation, the pipeline can only recover the costs of its investment in pipeline facilities. It cannot capture added revenues by refusing to build additional capacity thereby raising the price for capacity. The Commission's peak/off-peak rate policy articulated here similarly protects against this problem through the requirement that pipelines cannot recover more than their existing cost-of-service through peak/off-peak rates.

This theoretical problem, however, exists in today's market where pipeline affiliates are able to make bundled sales not subject to a rate cap. Yet, there seems little indication that profits from scarcity exceed those that can be earned through construction, since pipeline construction applications have not noticeably declined.

126

However, because of the possibility of affiliate abuse, the Commission will be particularly sensitive to complaints that pipelines, on which affiliates hold large amounts of transportation capacity, are refusing to undertake construction projects when demand for construction exists. In cases where such concerns are established, the Commission would need to take remedial measures. Depending on the circumstances, such remedies could include: requiring pipelines to put in taps to reduce capacity bottlenecks; requiring pipelines to build additional capacity when requested by customers willing to pay the costs of construction; limiting the rates at which the affiliate can release capacity; limiting the amount of capacity the affiliate can hold; or prohibiting the affiliate from holding capacity on its related pipeline.

126

From 1997 to October 1999, the Commission has certificated 30 major on-shore and off-shore projects, not including storage, totaling 12,594.8 MMCF/day of capacity. There are currently 13 major construction project applications, not including storage, pending at the Commission, totaling 6,440 MMcf/day of capacity.

See

Department of Energy/Energy Information Administration, Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 18 (June 1999) (80 natural gas pipeline projects completed between January 1997 and December 1998).

B. Peak and Off-Peak Rates

Use of peak/off-peak, or seasonal, rates for pipeline services could improve efficiency in the market place by better accommodating regulation to seasonal demand for capacity, and at the same time could benefit long-term captive customers. Therefore, as discussed below, the Commission will permit pipelines to institute peak/off-peak rates for all short-term services,

i.e.

, short-term firm and interruptible

service and multi-year seasonal contracts,

127

as one possible method of promoting allocative efficiency that is consistent with the goal of protecting customers from monopoly power. The current use of uniform maximum rates, where fixed costs are recovered in 12 monthly installments, was developed at a time when the vast majority of firm contracts were long-term contracts. The use of uniform maximum rates for long-term contracts is appropriate because, under an SFV rate design, once a shipper has committed to buy capacity for a year, the use of seasonal reservation charges will not affect the total amount the customer will pay.

127

If a shipper contracts for capacity for certain months of the year, over a period of several years, but service is not continuous for every month of a year, the contract is similar to several short-term contracts, rather than to a long-term contract of a year or more, where the shipper purchases capacity in consecutive months during both peak and off-peak periods.

However, the use of uniform maximum prices for short-term service can create situations where short-term customers are able to purchase peak capacity at a price that may be lower than its market value while the pipeline sells off-peak capacity at “discounted” rates. If short-term customers are able to purchase peak capacity at less than its market value and off-peak capacity at a discount, while the long-term customers pay a uniform maximum rate, the short-term customers will receive annual service at a lower cost than long-term shippers. This works to the disadvantage of captive customers with long-term contracts. Further, under this scenario, short-term shippers seeking winter-only service can obtain peak period capacity for a fraction of the annual cost of providing capacity, leaving the long-term shippers responsible for the remainder. This cost allocation disparity between short- and long-term shippers could increase as LDC contracts expire and more capacity is sold in the short-term market.

Peak/off-peak rates could allow pipelines to increase revenue recovery from short-term peak period shippers. Increased cost recovery from peak short-term services lessens the level of costs that need to be recovered from long-term customers and minimizes the cost shifting that occurs with off-peak discounting. By reducing the rates in the off-peak periods, peak/off-peak rates could reduce the need for discounts and reliance on discount adjustments. Many commenters

128

object to the Commission's current discount adjustment policy under which pipelines offering discounts are able, in the next rate case, to adjust maximum rates to reflect the discounts. Peak/off-peak rates could better reflect the value of capacity during peak and off-peak periods, thereby reducing the need to make discount adjustments.

128

See, for example, the comments of APGA, Brooklyn Union, FPL Group, Inc., Illinois Municipal Gas Agency, Mississippi Valley and Willmut Gas, NASUCA, New England Gas Distributors, Pennsylvania Office of the Consumer Advocate, Process Gas, and the Public Service Commission of Wisconsin.

In addition to benefitting captive long-term customers, use of peak/off-peak rates for short-term services could better reflect the true value of capacity during peak and off-peak periods, and thus improve allocative efficiency especially during peak periods when capacity is constrained and the price in a competitive market would exceed the average maximum rate. In the current marketplace, at times when demand for capacity exceeds the available capacity, pipelines cannot automatically allocate that capacity to the shipper placing the highest value on the capacity. Instead, they must allocate capacity

pro rata

or on the basis of a queue. This often prevents shippers who most value capacity from obtaining it. With peak/off-peak rates the pipeline would be able to allocate that capacity more efficiently to those shippers valuing the capacity the most. Charging shippers more for use during peak periods also can provide better price signals about the need for new construction. The demand for pipeline capacity at peak is a major factor in the pipeline's decision to add to its facilities.

Thus, peak/off-peak pricing for short-term services could promote several important policy goals. It could remove one of the biases favoring short-term contracts, and could lower the share of costs allocated to long-term transportation customers. It could increase efficiency in short-term markets by allowing prices to better reflect demand during peak periods. Therefore, as discussed below, the Commission will permit pipelines to implement value-based peak/off-peak rates for their short-term transportation services, within the pipeline's current cost-based revenue requirement. Under an SFV rate design, the use of peak/off-peak reservation charges for long-term contracts would not affect the total amount a long-term customer would pay over the year. Therefore, this policy will not apply to long-term contracts that are for 12 or more consecutive months of service. However, long-term customers can choose to pay peak/off-peak rates as a billing adjustment.

Rates developed under a peak/off-peak methodology will be higher at peak periods than off-peak periods. This result is the same as the result under the current uniform maximum rate method. Currently, the rates actually paid by shippers are higher during peak because the pipeline is generally able to charge the maximum rate at peak, but must discount rates during off-peak periods to customers that have alternatives available in the marketplace. Therefore, charging a higher rate during peak periods is consistent with current practice. However, peak/off-peak pricing would better match demand with price than does the current method. In allowing seasonal/peak pricing, the Commission is improving upon the existing pricing model and retaining the revenue constraints of its existing cost-based ratemaking regulatory model.

The Commission will allow the pipelines to determine the most appropriate method of implementation given the characteristics of their individual systems, consistent with the general principles discussed in this section. The Commission's discussion of peak/off-peak rates in this section, and its suggestion that pipelines voluntarily use peak/off-peak rates is a policy statement, and not a rule that imposes any requirements on pipelines or changes current Commission regulations.

1. Background

The Commission has long recognized the value of seasonal, or peak/off-peak rates, and in the NOPR sought comments on implementation of seasonal rates as one method of improving the regulatory scheme. The Commission's current regulations

129

and its precedent

130

recognize that peak/off-peak rates have a role in the ratemaking process, and the Commission has specifically recognized that differences in peak and off-peak demand may be considered in ratemaking. In the 1989 Rate Design Policy Statement, the Commission expressed concern that the derivation of rates without regard to seasonal variations in use of the pipeline does not properly ration peak capacity or lead to efficient use of the pipeline in periods of excess capacity.

131

The Commission suggested that pipelines could assign peak/off-peak costs by seasonal load factors, or assign the cost

of transmission facilities used to provide service above the annual load factor to the peak period.

132

129

18 CFR § 284.7(c)(3)(i) (1999).

130

See, e.g.,

Opinion No. 369, Panhandle Eastern Pipe Line Co., FERC ¶ 61,264 (1991); Maritimes & Northeast Pipeline, L.L.C., 80 FERC ¶ 61,346 (1997).

131

Policy Statement Providing Guidance with Respect to the Designing of Rates (Rate Design Policy Statement), 47 FERC ¶ 61,295 at 62,054 (1989).

132

Id.

Part 284 of the Commission's regulations has long contained the rate objectives that rates for peak periods should be designed to ration capacity and rates for off peak periods should be designed to maximize throughput.

133

These rate objectives are independent of the costs of providing service. Part 284 also requires that rates

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