[Federal Register Volume 65, Number 38 (Friday, February 25, 2000)]
[Rules and Regulations]
[Pages 10156-10226]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-3595]



[[Page 10155]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Parts 154, 161, et al.



Regulation of Short-Term Natural Gas Transportation Services and 
Regulation of Interstate Natural Gas Transportation Services; Final 
Rule



Termination of Rulemaking Proceedings; Proposed Rule

  Federal Register / Vol. 65, No. 38 / Friday, February 25, 2000 / 
Rules and Regulations  

[[Page 10156]]


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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.

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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 
Sec. 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

[[Page 10157]]

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) \1\ 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.\2\
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    \1\ Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954) 
(mandating Commission regulation of the gas commodity).
    \2\ 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).
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    The passage of the Natural Gas Policy Act (NGPA) \3\ 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 \4\ which established rules for 
pipelines to offer open access transportation service independent of 
pipelines' sales service. In 1989, Congress passed the Wellhead 
Decontrol Act \5\ 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.'' \6\
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    \3\ 15 U.S.C. 3301-3432 (1978).
    \4\ 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] para. 30,665, at 31,472-74 
(Oct. 9, 1985).
    \5\ 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).
    \6\ Natural Gas Decontrol Act of 1989, H.R. Rep. No. 101-29, 
101st Cong., 1st Sess., at 6 (1989).
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    In Order No. 636,\7\ 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.
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    \7\ 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] para. 30,939 (Apr. 8, 1992).
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    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.\8\ 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.\9\
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    \8\ NYMEX, Henry Hub Natural Gas, http://www.nymex.com (November 
17, 1999) (futures contract began in 1990).
    \9\ 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).
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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

[[Page 10158]]

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.
    a. 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.\10\
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    \10\ 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.\11\
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    \11\ Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 31-33 
(1999).
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    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.\12\ 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.\13\ Marketers currently hold 
over 20% of pipeline firm capacity.\14\ 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.\15\
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    \12\ 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.
    \13\ Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 152-153 
and Figure 55 (June 1999).
    \14\ Id. at 222, Table D12.
    \15\ 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).
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    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.\16\
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    \16\ 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).
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    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.\17\ Although the initial market centers were in 
the upstream production areas, downstream market centers are now 
developing. (See Figure 2) \18\
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    \17\ Id.
    \18\ 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.\19\
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    \19\ See Henning & Sloan, Analysis of Short-Term Natural Gas 
Markets, A-2 (Energy and Environmental Analysis, Inc., Nov. 1998).
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    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.\20\
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    \20\ NYMEX, Henry Hub Natural Gas, http://www.nymex.com 
(November 17, 1999).
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    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.\21\
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    \21\ 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.
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    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.\22\ 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.\23\ 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.\24\
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    \22\ 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).
    \23\ Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0618(98), Deliverability on the Interstate Natural 
Gas Pipeline System 83 (1998).
    \24\ See Comment of Enron Capital (providing price hedging and 
risk management services).
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    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.\25\ 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.\26\ 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.\27\
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    \25\ See Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 12-13 
(June 1999).
    \26\ See Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 21 (June 
1999).
    \27\ Id; 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.)
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    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.\28\
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    \28\ Comments of Dynegy and Reliant.
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    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.'' \29\ 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

[[Page 10163]]

demand conditions during the winter of 1996.\30\ 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.\31\
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    \29\ Comments of NYMEX, at 2.
    \30\ 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).
    \31\ Id. (concluding that the unbundled gas market has responded 
to severe demand conditions better than the traditionally regulated 
electric market).
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    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.\32\ 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.
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    \32\ Standards For Business Practices Of Interstate Natural Gas 
Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC 
Stats. & Regs. Regulations Preambles para. 31,038 (Jul. 17, 1996).
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    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.\33\ 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.\34\
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    \33\ 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) para. 
30,988 (Dec. 23, 1993).
    \34\ Standards For Business Practices Of Interstate Natural Gas 
Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC 
Stats. & Regs. Regulations Preambles para. 31,038 (Jul. 17, 1996), 
Order No. 587-B, 62 FR 5521 (Feb. 6, 1997), III FERC Stats. & Regs. 
Regulations Preambles para. 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.\35\ 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.\36\ One study estimates that 
on-line trading of natural gas in 1999 will amount to $10 billion.\37\ 
Many of these electronic transactions occur at downstream markets. (See 
Figure 4 showing the electronic gas trading points for Altrade and 
Natural Gas Exchange).\38\
---------------------------------------------------------------------------

    \35\ V. Lief, The Surge of Online Energy, The Forrester Report, 
2-3 (Sept. 1999); Comment of Altra; Enermetrix.com, http://www.enermetrix.com.
    \36\ 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).
    \37\ V. Lief, The Surge of Online Energy, The Forrester Report, 
9 (Sept. 1999).
    \38\ 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).

BILLING CODE 6717-01-P

[[Page 10166]]

[GRAPHIC] [TIFF OMITTED] TR25FE00.003


BILLING CODE 6717-01-C

[[Page 10167]]

    New electronic trading companies are entering the market \39\ and 
eCommerce for gas is expected to grow, reaching 20% of total gas 
business within two years.\40\ 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.'' \41\
---------------------------------------------------------------------------

    \39\ 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).
    \40\ V. Lief, The Surge of Online Energy, The Forrester Report 
(Sept. 1999).
    \41\ 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.\42\ 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.\43\ 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.\44\ Marketers, and other transportation 
customers, also may be less willing than LDCs to sign long-term 
contracts with Memphis \45\ clauses that permit pipelines to increase 
prices unilaterally by filing new rate cases.
---------------------------------------------------------------------------

    \42\ See Comments of Columbia.
    \43\ Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560, Natural Gas 1998 Issues and Trends, 136 (June 
1999).
    \44\ Id. at 137.
    \45\ 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).\46\ 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.\47\
---------------------------------------------------------------------------

    \46\ 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).
    \47\ The Commission already has been faced with some of these 
difficulties. See El Paso Natural Gas Company, 83 FERC para. 61,286 
(1998)(remarketing of turnback capacity); El Paso Natural Gas 
Company, 79 FERC para. 61,028, reh'g denied, 80 FERC para. 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 para. 
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.\48\ 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.
---------------------------------------------------------------------------

    \48\ 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.\49\ Such title transfer services could form the basis 
for electronic trading that fully integrates gas and capacity trades 
with the pipelines' scheduling system.
---------------------------------------------------------------------------

    \49\ 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,\50\ 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.\51\ 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.\52\ 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.\53\ 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.\54\
---------------------------------------------------------------------------

    \50\ 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] para. 31,036 (Apr. 24, 1996).
    \51\ Department of Energy/Energy Information Administration, 
Pub. No. DOE/EIA-0560(98), Natural Gas Issues and Trends 33 (1999).
    \52\ 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).
    \53\ 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).
    \54\ See Comments of INGAA, Williams Companies, Reliant, Sithe, 
Sempra Energy, EEI. See also Reliant Energy Gas Transmission 
Company, 87 FERC para. 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

[[Page 10168]]

mergers between power generators and pipeline companies as well as the 
number of marketers that resell both gas and electricity.\55\ Some 
marketers are operating their own generation plants.\56\ 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.
---------------------------------------------------------------------------

    \55\ 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).
    \56\ See Comments of Dynegy (owner of power generation 
facilities).
---------------------------------------------------------------------------

    The pace of mergers and alliances raises questions about the future 
structure of the industry.\57\ 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.\58\ The increasing use of asset 
managers by LDCs \59\ 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.\60\
---------------------------------------------------------------------------

    \57\ See Comment of Dynegy (expressing concern about the 
integrated corporations using transportation capacity as a marketing 
lever to obtain business for a generation affiliate).
    \58\ 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).
    \59\ See Comments of Dynegy, Enron Capital (providing asset 
management services).
    \60\ 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,\61\ 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.\62\ 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.\63\
---------------------------------------------------------------------------

    \61\ See text and notes, supra, at Figure 1.
    \62\ 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).
    \63\ 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.\64\ There are 
business alliances between gas distributors and traditional consumer 
retailers to sell both gas and electricity to residential and 
commercial customers.\65\
---------------------------------------------------------------------------

    \64\ See Power Trust.com, http://www.powertrust.com; 
Essential.com, http://essential.com.
    \65\ 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.\66\ 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.\67\
---------------------------------------------------------------------------

    \66\ Comments of AGA I, PSE&G, Columbia.
    \67\ 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.\68\ Just and reasonable rates 
and services need to be designed to achieve two principal objectives. 
They should promote competitive and efficient markets,\69\ while 
mitigating market power and preventing undue discrimination, especially 
for the Commission's ``prime constituency, captive customers vulnerable 
to pipelines' market power''.\70\ In short, the Commission's regulatory 
policy must seek to reconcile the objectives of fostering an efficient 
market that provides good alternatives

[[Page 10169]]

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.
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    \68\ Natural Gas Act, Sec. 4, 15 U.S.C. 717(d).
    \69\ 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] para. 30,939, at 30,932 (Apr. 8, 1992).
    \70\ 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.\71\ 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.
---------------------------------------------------------------------------

    \71\ 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) para. 30,665, at 
31,534 (Oct. 9., 1985); 18 CFR 284.7(c); Interstate Natural Gas 
Pipeline Rate Design, 47 FERC para. 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

[[Page 10170]]

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) \72\ and Notice of 
Inquiry (NOI),\73\ 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.
---------------------------------------------------------------------------

    \72\ 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) 
para.32,533 (July 29, 1998).
    \73\ Regulation of Interstate Natural Gas Transportation 
Services, Notice of Inquiry, 63 FR 42973, IV FERC Stats. & Regs. 
Notices para.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.''\74\
---------------------------------------------------------------------------

    \74\ 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,\75\ 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.\76\ 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.
---------------------------------------------------------------------------

    \75\ Comments of Amoco, Altra, Sithe, Southern Company Energy 
Marketing.
    \76\ 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.\77\ 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.
---------------------------------------------------------------------------

    \77\ 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

[[Page 10171]]

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.\78\ 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.
---------------------------------------------------------------------------

    \78\ 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

[[Page 10172]]

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 
\79\ where the competitive price would be insufficient to permit the 
firm to recover its costs.\80\ 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

[[Page 10173]]

jeopardizing protections against the exercise of market power.
---------------------------------------------------------------------------

    \79\ 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).
    \80\ 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, Sec. 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.\81\ 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.
---------------------------------------------------------------------------

    \81\ 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.\82\
---------------------------------------------------------------------------

    \82\ 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.\83\ When Order No. 636 was issued, most gas transactions 
occurred at the wellhead or upstream market centers.
---------------------------------------------------------------------------

    \83\ 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. para. 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

[[Page 10174]]

downstream markets, such as the Chicago Citygate, represent the price 
paid by shippers purchasing delivered gas at that market.\84\ 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).\85\
---------------------------------------------------------------------------

    \84\ 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.
    \85\ 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.

BILLING CODE 6717-01-P

[[Page 10175]]

[GRAPHIC] [TIFF OMITTED] TR25FE00.004


BILLING CODE 6717-01-C

[[Page 10176]]

    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.

BILLING CODE 6717-01-P

[[Page 10177]]

[GRAPHIC] [TIFF OMITTED] TR25FE00.005


BILLING CODE 6717-01-C

[[Page 10178]]

    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.\86\ As the 
chart shows, as temperatures dropped in the Northeast during 
January,\87\ 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.
---------------------------------------------------------------------------

    \86\ 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).
    \87\ 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).

BILLING CODE 6717-01-P

[[Page 10179]]

[GRAPHIC] [TIFF OMITTED] TR25FE00.006


BILLING CODE 6717-01-C

[[Page 10180]]

    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.'' \88\ 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.
---------------------------------------------------------------------------

    \88\ 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.\89\ 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.
---------------------------------------------------------------------------

    \89\ 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),\90\ 
it would provide little benefit to shippers purchasing capacity during 
peak periods. The maximum rate cap

[[Page 10181]]

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.\91\ 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.
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    \90\ 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).
    \91\ 18 CFR 284.7(b)(1), redesignated Sec. 284.10(b)(1).
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    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.\92\
---------------------------------------------------------------------------

    \92\ 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.\93\ 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.\94\
---------------------------------------------------------------------------

    \93\ 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.
    \94\ 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,\95\ to determine whether markets are sufficiently 
competitive to remove regulatory rate ceilings for all services.
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    \95\ 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 
para. 61,076 (1996).
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    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

[[Page 10182]]

for long-term capacity.\96\ 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.\97\ Several commenters, particularly LDCs, support 
removal of price caps for short-term capacity release transactions, but 
not for pipeline services.\98\
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    \96\ Comments of Consolidated Natural Gas I, IMD, Koch I, 
MichCon, NYMEX, Nicor, PG&E, Mercatus, Sempra Energy, TransCanada, 
and Williams I.
    \97\ 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.
    \98\ 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.\99\ 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\
---------------------------------------------------------------------------

    \99\ 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\
---------------------------------------------------------------------------

    \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 Sec. 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.

[[Page 10183]]

    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

[[Page 10184]]

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\
---------------------------------------------------------------------------

    \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 para. 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.

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[[Page 10185]]

    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 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) (``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) para.30,939, at 30,932 
(Apr. 8, 1992).
    \115\ FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944); 
Elizabethtown Gas Company v. 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 v. FERC, 996 F.2d 401, 410 (D.C. Cir. 
1993).
    \119\ Elizabethtown Gas Company v. 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 v. FERC, 761 F.2d 768 (D.C. 
Cir. 1985); Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C. 
Cir. 1985) (special concern for effect of program on core captive 
customers).
    \121\ See American Gas Association v. 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 v. 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.
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    \122\ Environmental Action v.  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.

[[Page 10186]]

    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 v. 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

[[Page 10187]]

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

[[Page 10188]]

of transmission facilities used to provide service above the annual 
load factor to the peak period.\132\
---------------------------------------------------------------------------

    \129\ 18 CFR Sec. 284.7(c)(3)(i) (1999).
    \130\ See, e.g., Opinion No. 369, Panhandle Eastern Pipe Line 
Co., FERC para. 61,264 (1991); Maritimes & Northeast Pipeline, 
L.L.C., 80 FERC para. 61,346 (1997).
    \131\ Policy Statement Providing Guidance with Respect to the 
Designing of Rates (Rate Design Policy Statement), 47 FERC para. 
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 
reasonably reflect any material variation in the cost of providing 
service due to whether the service is provided during a peak or non-
peak period.\134\ While the regulations specifically recognize the 
validity of seasonal rates to ration capacity, maximize throughput, and 
reflect cost differences, they do not limit the use of seasonal rates 
to these circumstances, and nothing in the Commission's regulations 
prohibits the use of peak/off-peak rates that reflect differences in 
peak and off-peak demand. Thus, peak/off-peak rates are consistent with 
the Commission's existing regulations, and no changes to the 
regulations are necessary to implement peak/off-peak rates.
---------------------------------------------------------------------------

    \133\ 18 CFR 284.7(b).
    \134\ 18 CFR 284.7(c)(3)(i).
---------------------------------------------------------------------------

    The Commission recognizes that some of its prior decisions could be 
interpreted as limiting the use of peak/off-peak rates to circumstances 
where seasonal rate differences are cost-based.\135\ Although the 
regulations require seasonal rates to reflect seasonal cost 
differences, the regulations do not preclude seasonal rates designed on 
other bases, and the Commission has approved peak/off-peak rates using 
a value based method for setting peak/off-peak rates.\136\ The 
Commission clarifies that nothing in its prior decisions was intended 
to limit the use of peak/off-peak rates to situations where seasonal 
rate differences are cost-based.
---------------------------------------------------------------------------

    \135\ See, e.g., Opinion No. 369, Panhandle Eastern Pipe Line 
Co., 57 FERC para. 61,264 at 61,831 (1991) (the Commission permitted 
seasonalization of the sales reservation charge, but found that, 
based on the facts of that case, seasonalized firm rates could not 
be justified based on the need to ration capacity).
    \136\ See Maritimes & Northeast Pipeline, L.L.C., 80 FERC para. 
61,346 (1997).
---------------------------------------------------------------------------

    Of these two methods, basing peak/off-peak rates on value of 
service concepts, rather than specific costs, is more consistent with 
the goal of providing efficient pricing signals. Those customers that 
value capacity more highly should expect to pay higher prices when 
capacity is scarce. The prices they would be willing to pay have little 
relationship to the accounting cost of the facilities used to provide 
additional service at peak periods. In practice, it is very difficult 
to identify specific facilities, with the exception of storage, that 
are used to provide transportation service at peak periods rather than 
year round. A similar problem occurs on most systems if one attempts to 
identify specific costs that are attributable to peak/off-peak usage.
2. Implementation
    The Commission will facilitate the implementation of peak/off-peak 
rates with a flexible policy that will permit the use of a wide variety 
of peak/off-peak rate methods. The pipelines can make changes in their 
peak/off-peak rates on a monthly basis, within existing cost of service 
constraints. Pipelines can implement peak/off-peak rates either through 
a general section 4 rate case or a pro forma tariff filing. The 
following discusses the basic parameters applicable to peak/off-peak 
filings and the procedures to be followed in processing the filings.
    a. Parameters for Establishing Peak/Off-Peak Rates. Value-based 
peak/off-peak rates are just and reasonable cost-based rates.\137\ Like 
uniform maximum rates, peak/off-peak rates would be established by 
taking the pipeline's annual revenue requirement and deriving from it a 
daily or monthly rate. The difference in developing peak/off-peak rates 
and the current uniform maximum rate is that instead of dividing the 
annual revenue requirement by 365 to obtain a daily rate, different 
daily or monthly rates will be developed for peak and off-peak periods 
using one of several possible methods of measuring the value of 
capacity at peak and off-peak.\138\ The sum of the daily or monthly 
rates, multiplied by the quantity used or reserved, still must not 
exceed the pipeline's annual revenue requirement, and thus, any 
increases in rates at peak must be offset by decreases in off-peak 
rates. In other words, if a shipper paid the peak and off-peak rate for 
the same volume of transportation every day of the year, the amount it 
paid annually for service would be no more than if it had paid the 
uniform maximum daily rate for the same transportation volume based on 
the same revenue requirement.
---------------------------------------------------------------------------

    \137\ Rate Design Policy Statement, 48 FERC para. 61,122 at 
61,446 (1989).
    \138\ Some of these methodologies are discussed below.
---------------------------------------------------------------------------

    This requirement limits the rate the pipeline may charge. For 
example, if the pipeline wanted to charge a rate greatly in excess of 
the current uniform maximum rate in the four month period December 
through March, it would have to match this increase with a 
corresponding reduction in rates for the remaining months. This places 
a check on the ability of the pipelines to propose extraordinarily high 
rates during peak periods because any rate increase for peak periods 
must be matched by a rate decrease during the off-peak periods. This is 
a disincentive for pipelines to raise peak period rates to 
unrealistically high levels since this would require an off-setting 
lowering of off-peak rates that could compromise the pipeline's ability 
to recover maximum off-peak revenues.
    As illustrated by the comments, there is more than one reasonable 
way to implement peak/off-peak rates based on value of service 
concepts. The methods proposed by the commenters include using a ratio 
of the prices for capacity release and IT on a system to develop a 
ratio,\139\ looking at usage of compression to develop a ratio,\140\ 
looking at peak/off-peak volumes/load factors to develop a ratio,\141\ 
developing a ratio based on historic price differentials between 
receipt and delivery point prices, or allowing a shaping of prices to 
try to capture the value of the capacity,\142\ and tailoring of 
contract demand levels during the year.\143\ Other methods of 
developing peak/off-peak rates could include looking at the price at 
which capacity has traded, load factors, basis or other indexing, or 
other methods of measuring the value of capacity throughout the year. 
Since capacity prices are currently capped at uniform maximum rates, 
the historical data on pricing may not be the best indicator of the 
value.
---------------------------------------------------------------------------

    \139\ See, e.g., comments of Amoco.
    \140\ See, e.g., comments of Columbia.
    \141\ See, e.g., comments of Columbia.
    \142\ See comments of Texas Eastern/Algonquin, CMS Panhandle. 
Under this approach the pipeline would assess the relative value of 
capacity throughout the year and design reservation charges based on 
this assessment. The sum of the annual peak/off-peak reservation 
charges would equal the sum of the current annual average 
reservation charges.
    \143\ See comments of Enron Pipelines.
---------------------------------------------------------------------------

    Some methods may work better for certain systems than others. For 
example, on some systems' data may be more readily available to base 
peak/off-peak differences on basis differentials because the pipeline 
is directly connected to major market centers so that there is already 
considerable data on the value of the pipeline's capacity. On other 
systems where there is a wide swing in load factors from peak to off 
peak periods, a method based on load factors may make more sense.
    Therefore, the best method of developing peak/off-peak rates will 
depend in part on the specific characteristics of each pipeline, and 
the

[[Page 10189]]

Commission will not adopt any one method of developing peak/off-peak 
rates, but will leave the details of the implementation of peak/off-
peak rates to individual pipelines. The Commission will consider any 
reasonable method of implementation that is consistent with the general 
principles discussed in this section, but the pipeline will have the 
burden of proof to show that its proposed method is just and 
reasonable.
    b. Process for Implementing Peak/Off-Peak Rates. The implementation 
of peak/off-peak rates could lead to higher pipeline revenues from 
short-term services since a pipeline could reduce off-peak price caps 
so that they would be close to recent discount history, and 
correspondingly increase peak price caps. The pipeline might see little 
or no reduction in off-peak revenues since market prices are usually 
below the uniform maximum price caps. Because the price cap would be 
higher in the peak with peak/off-peak rates, the pipeline's revenues 
should increase if it adopts peak/off-peak rates.
    The process for implementing peak/off-peak rates, therefore, must 
take the increased revenues into account. One method for doing so would 
be for the pipeline to file a general rate case to implement peak/off-
peak rates. In a general rate case, all pipeline costs and revenues can 
be examined and the appropriate revenue responsibility of each service 
can be decided. Thus, the rates for long-term services would be reduced 
in recognition that the pipeline could be expected to recover more 
revenues from short-term services.
    However, the filing of general section 4 rate case may not be well-
suited to this context. The Commission's rate methodology relies on a 
historical test period to project future throughput for each service, 
and revenue responsibility is assigned to each service based on those 
projections. There is no historical experience that would adequately 
project future short-term service demand with peak/off-peak pricing. 
Also, using general rate cases to implement peak/off-peak rates could 
be time consuming.
    Therefore, the Commission will establish a procedure under which 
pipelines can establish peak/off-peak rates through a pro forma tariff 
filing so that the Commission and the parties will have an adequate 
opportunity to review the proposal prior to implementation. Under this 
procedure, the pro forma filing would be noticed with comments due on 
the pipeline's proposal within 21 days, rather than the 12 days 
permitted for tariff filings. The Commission would take action on the 
filing within 60 days. Pipelines interested in implementing peak/off-
peak rates are encouraged to file proposals as soon as possible.
    Consistent with the goal of benefitting long-term captive 
customers, if peak/off-peak rates result in the pipeline's recovering 
increased revenues from short-term peak services, those increased 
revenues should be used to offset the costs borne by long-term 
customers. Therefore, if the pipeline seeks to implement seasonal rates 
through a pro forma tariff filing, the pipeline must include in its 
proposal a revenue sharing mechanism that will provide for at least an 
equal sharing of any increased revenues with its long-term customers. 
The actual amount of the revenue credit can be negotiated with the 
pipeline's customers before or during the pro forma tariff proceeding. 
After 12 months experience with peak/off-peak rates, the pipeline must 
prepare a cost and revenue study and file the study with the 
Commission. Pipelines must file the cost and revenue study pursuant to 
the format prescribed in Sec. 154.313 of the Commission's 
regulations.\144\ The study must be filed within 15 months of 
implementing peak/off-peak rates. Based on the cost and revenue study, 
the Commission will determine whether any rate adjustments are 
necessary to the long-term rates, and may order such adjustments 
prospectively.
---------------------------------------------------------------------------

    \144\ 18 CFR 154.313 (1999). See Trunkline LNG Company, 82 FERC 
para. 61,198 (1998), aff'd, 194 F.3d 68 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    As explained above, one of the policy rationales for adopting peak/
off-peak rates is that under the current cost-of-service rate 
methodology, underpricing short-term peak capacity results in the 
pipeline's long-term customers paying higher rates because a greater 
share of the pipeline's costs are recovered from its long-term rates. 
The Commission is seeking to lower the rates to long-term customers in 
recognition of the additional risks they take by signing long-term 
contracts. Therefore, if a pipeline moves to peak/off-peak rates it 
should benefit the pipeline's long-term customers, and a revenue 
sharing mechanism that benefits only long-term customers is 
appropriate.
    The Commission will not require any specific method of determining 
the amount of additional revenues that are attributable to 
implementation of peak pricing, since the same approach may not work 
equally well on all pipelines. The pipeline must propose a reasonable 
method when it files to implement peak pricing. The issues involved in 
developing an appropriate revenue sharing mechanism may be more complex 
than deriving the seasonal rate itself, and these issues could be 
considered independently of the rate. Pipelines are encouraged to work 
with their customers to develop a method that has wide support. The 
method should be fair to the pipeline and its long-term customers and 
should be easy to implement. Whatever method is chosen, the pipeline is 
not required to share excess revenues if there really are none. A 
pipeline will not be required to share revenues if it demonstrates that 
its total revenues from peak/off-peak rates were less than the revenues 
allowed for the relevant services in its last rate case.

C. Term-Differentiated Rates

    In the NOPR, the Commission stated that one method of reducing 
asymmetry of risk that favors short-term contracts, and of 
strengthening the long-term market would be to encourage contracts that 
contain lower maximum rates for longer term service than for shorter 
term service in recognition of the value of longer term contracts in 
limiting the pipeline's risk. The Commission sought comments on whether 
and how to encourage such term-differentiated rates. Upon review of the 
comments, the Commission has determined that term-differentiated rates 
should be available to the pipeline as one of several methods that 
could be used to price capacity more efficiently. As explained below, 
the Commission will not adopt any one method of establishing term-
differentiated rates, but will permit a pipeline and its customers to 
develop specific methodologies suitable to the characteristics of the 
specific pipeline in a section 4 rate proceeding.
    Term-differentiated rates would match price more closely with risk-
adjusted value, and could result in a rate structure that prices 
capacity held for a longer term at a lower rate than capacity held for 
a shorter term. With term-differentiated rates, maximum posted rates 
for longer terms would be lower than rates for shorter term service on 
a per unit basis and at comparable load factors. Term-differentiated 
rates do not differentiate between seasons, but instead, differentiate 
based on the length of the contract. Term-differentiated rates would 
more accurately reflect in the price of service the relative levels of 
risk that pipelines must face when selling service for a shorter period 
than for a longer period, as well as the higher risks that customers 
face when they purchase service for a longer period of time.
    As the Commission explained in the NOPR, a shorter term contract is 
riskier for the pipeline, and a higher rate would compensate the 
pipeline for this

[[Page 10190]]

additional risk. A shorter term contract provides greater flexibility 
and less risk to the shipper, and a higher rate would recognize and 
require payment for these benefits. The Commission has already 
recognized, in the context of oil pipeline rates, that the lower risk 
to the shipper and the higher risk to the pipeline, associated with 
shorter term contracts may properly be reflected in a higher rate for 
such service. In Express Pipeline Partnership,\145\ the Commission 
explained that shorter term shippers have less risk because they have 
maximum flexibility to react to changes in their own circumstances or 
in market conditions, and are a greater risk to the pipeline because 
they do not provide the revenue assurances or planning assurances to 
the pipeline that long-term shippers do.
---------------------------------------------------------------------------

    \145\ 76 FERC para. 61,245, reh'g denied, 77 FERC para. 61,188, 
(1996).
---------------------------------------------------------------------------

    Several commenters \146\ argue that term-differentiated rates are 
inconsistent with cost-based regulation. They argue that term-
differentiated rates are not based on cost incurrence because there is 
no evidence that it costs more for the pipeline to meet the needs of 
short-term contracts. However, as explained above in the discussion of 
peak/off-peak rates, cost-based ratemaking is not simply a matter of 
strict cost incurrence. ``Value and costs are inexorably linked'' in 
ratemaking, and the Commission can legitimately consider the overall 
goals of its ratemaking policy in developing just and reasonable cost-
based rates.\147\ Further, the existence of long-term contracts reduces 
pipeline risks and therefore lowers its cost of capital.
---------------------------------------------------------------------------

    \146\ See, for example, comments of Dynegy, Amoco, and Indicated 
Shippers/
    \147\ Interstate Natural Gas Pipeline Rate Design, 48 para. 
61,122 at 61,446 (1989).
---------------------------------------------------------------------------

    Like peak/off-peak rates, term-differentiated rates would be cost-
based, just and reasonable rates because the Commission will limit the 
rates in the aggregate to produce the pipeline's annual revenue 
requirement. The difference between developing constant average rates 
and term-differentiated rates is that instead of establishing a single 
rate cap for each service, as in current practice, with term-
differentiated rates, different rates would be charged to different 
customers based on the length of their contract.
    There are various methods that could be used to develop reasonable 
term differentiated rates. For example, in its comments, INGAA 
suggested that term-differentiated rates could be developed using a 
cost allocation approach that would allocate costs between shorter term 
and longer term service based on an allocation factor such as projected 
percentages of throughput.
    Several commenters \148\ asserted that the Commission should not 
approve term-differentiated rates as a ratemaking option without 
setting forth a specific proposal for comment in a generic proceeding. 
However, the Commission has concluded that since there is more than one 
appropriate method of establishing term-differentiated rates, and some 
methods might be more appropriate on certain pipelines than on others, 
it will not limit the pipeline to one method, but will allow the 
pipelines and the customers to work out the details of the 
methodologies in specific rate proceedings.
---------------------------------------------------------------------------

    \148\ See, for example, comments of Process Gas Consumers.
---------------------------------------------------------------------------

    A pipeline may propose term-differentiated rates just for long-term 
services or for both short- and long-term services. The Commission 
recognizes that the use of term-differentiated rates for short-term 
services may enhance the potential for price discrimination, 
particularly during off-peak periods, by increasing the rate caps that 
would apply to short-term service acquired in off-peak periods. 
Consequently, a pipeline proposing term-differentiated rates for short-
term services will need to fully explain the basis and justification 
for the price differentials.
    Term-differentiated rates have a much greater potential for 
effecting the rates of all customers than peak/off-peak rates. Term-
differentiated rates would raise the maximum tariff rates for some 
customers, and there should be a decrease in the maximum tariff rates 
for long term customers. The general reallocation of revenue 
responsibility among customer classes must be done through rate changes 
for all customers simultaneously in the section 4 rate filing in which 
the pipeline seeks to implement term-differentiated rates.

D. Voluntary Auctions

    Auctions, if properly designed, can provide for efficient 
allocation of capacity and natural gas, reduce transaction costs in 
finding and arranging capacity transactions, and provide for more 
accurate dissemination of relative pricing information to the 
marketplace. Auctions also can be used as methods of mitigating the 
effects of market power by limiting the ability of sellers to withhold 
capacity, to price discriminate, or to show favoritism. With the growth 
of the Internet, electronic auctions have become an effective and 
efficient method of exchanging goods and services. Auctions 
increasingly are being used successfully in energy industries. 
Electronic auctions have been established to facilitate exchanges of 
gas. Auctions similarly are being used in the electric industry to 
allocate generation and transmission capacity. Pipelines have been 
using electronic open seasons to determine demand for new construction. 
The capacity release posting and bidding system itself is a form of 
auction.
    A number of commenters recognize the potential value in the use of 
auctions, but urge the Commission and the industry to obtain greater 
familiarity with the use of auctions in order to obtain better 
understanding of the auction formats that work well and those that do 
not. Although the Commission is not moving forward with mandatory 
auctions for pipeline capacity as well as short-term released capacity 
at this time, the Commission is still of the view that more extensive 
use of auctions can provide a wide range of benefits to the gas 
industry. Pipelines are encouraged to file proposals for implementing 
auctions and this section discusses principles for evaluating such 
proposals. Third-parties also encouraged to develop capacity auctions, 
and, as discussed below, the Commission, in appropriate circumstances, 
may be willing to modify certain regulatory requirements to facilitate 
such auctions.
    The existing third-party auctions for natural gas, for instance, 
may form the basis for the development of an efficient auction for 
transportation capacity or one that would combine the gas commodity and 
transportation capacity within a single auction format. Such auctions 
could resolve one of the objections to capacity-only auctions: that 
capacity-only auctions would force buyers to obtain capacity, without 
knowing whether they would be able to obtain gas at a reasonable 
price.\149\ Pipelines also may find it efficient to use a form of 
auction to allocate short-term capacity on a monthly, daily, or even 
intra-day basis. As a result of restructuring under Order No. 636, most 
pipeline tariffs require that interruptible capacity be allocated based 
on price when the pipeline is unable to fulfill all nominations for 
service.\150\ The use of a more formal auction method, therefore,

[[Page 10191]]

may be a reasonable method of allocating capacity.
---------------------------------------------------------------------------

    \149\ See Comment of Dynegy. Dynegy was concerned that if a 
shipper obtained capacity and then had to negotiate for gas, the gas 
producer would obtain leverage in the transaction, because the 
shipper had already committed to pay for capacity from a particular 
receipt point.
    \150\ See Robin Pipeline Company, 81 FERC para. 61,041, at 
61,225 (1997); Pacific Gas Transmission Company, 76 FERC para. 
61,258 (1996).
---------------------------------------------------------------------------

    The Commission also encourages pipelines and third-parties to 
consider establishing multi-pipeline or regional auctions. Such 
auctions could eliminate concerns expressed in the comments about 
possible difficulties in using auctions on individual pipelines to 
acquire a capacity path traversing multiple pipelines.\151\ Pipelines 
in a region, for instance, could arrange with a third-party auctioneer 
to sell the pipelines' available capacity in the same auction as 
capacity release transactions in that region, thereby providing 
shippers with one-stop capacity shopping.
---------------------------------------------------------------------------

    \151\ See Comments of Process Gas Consumers I, Wisconsin 
Distributors, Nicor Gas, PG&E, Shell Energy Services.
---------------------------------------------------------------------------

    The Commission recognizes that some of its existing regulations may 
impede the development of auctions. For instance, Altra has identified 
the requirement that all capacity release transactions must be posted 
for bidding on pipeline Internet sites as a potential barrier to third-
party auctions, because it would require the double posting of 
capacity: once on the third-party's auction mechanism and a second time 
on the pipeline's Internet site. The Commission also has required, and, 
in this rule is continuing to require, the publication of the names of 
shippers acquiring capacity from releasing shippers and the pipeline in 
order to provide price transparency and to permit effective monitoring 
of potential undue discrimination. In a properly designed auction, 
however, the requirement for posting the winning bidder's name may not 
be necessary, so long as the market price is disclosed. A waiver of the 
requirement to post the winning bidder's name, or to delay such 
posting, could be granted when the auction is designed in such a way 
that shippers can verify that the auction was properly conducted and 
the winning bid awarded fairly without favoritism.\152\ Upon 
application by a third-party or pipeline, the Commission would consider 
waiving these or other regulatory requirements that unnecessarily 
impede the development of auctions. Pipelines, however, may need to 
continue to post the results of affiliate transactions unless they can 
demonstrate that the format of the auction and the results are designed 
in such a way as to preclude affiliate favoritism. The use of third-
party auctioneers or certification may be methods of providing 
sufficient security against affiliate abuse.
---------------------------------------------------------------------------

    \152\ For instance, the use of an independent firm to verify the 
results of the auction may be sufficient without the posting of 
winning shippers' names.
---------------------------------------------------------------------------

    An auction also may be a means by which a pipeline could sell some 
or all of its capacity without a price cap if the auction is designed 
in such a way as to protect against the pipeline's ability to withhold 
capacity and exercise market power. Not all types of capacity would 
have to be allocated through the auction process. For example, the 
pipeline may have a reasonable basis for limiting the auction only to 
short-term firm or interruptible capacity. The Commission also still 
sees value in permitting the pipelines to negotiate prearranged deals 
while they conduct auctions for remaining capacity, although, as 
discussed below, pipelines must not withhold available capacity from 
the auction simply because they believe a better pre-arranged deal may 
be arranged in the future.
    Once capacity is placed in the auction, the pipelines must design 
the auction in ways to prevent the withholding of capacity and the 
exercise of market power. Capacity can be withheld by a pipeline in two 
primary ways: the pipeline can withhold capacity directly by not 
putting it into the auction; or it can indirectly withhold capacity 
through the use of a reserve price. In a proposal for auctions without 
a rate cap, all capacity available at that time of the auction would 
have to be included in the auction. The auction proposal also needs to 
address the appropriate limitations that should be placed on the level 
at which the pipeline can establish reserve prices, particularly 
whether different reserve prices should be established for peak and 
off-peak capacity.
    While the Commission will not insist on any particular auction 
format for pipelines or third-parties, the Commission sets forth below 
some basic principles to which auctions should adhere:

     The timing of the auction should be predictable, and 
shippers potentially offering or bidding on capacity should have 
notice of when the auction will be held and what capacity will be 
included.
     The auction should be open to all potential bidders on 
a non-discriminatory basis.
     The auction should be user-friendly with information on 
the rules and procedures easily accessible to all.
     The bidding procedures as well as the methods for 
selecting the best bid should be fully disclosed prior to the 
auction. For instance, if net present values formulas are used, the 
discount rate and the method of calculation should be disclosed.
     There should be no favoritism in the determination of 
the winning bidder and mechanisms should be included to permit 
monitoring of how the selection criteria were applied. This would 
include methods of verifying any reserve price applied in an 
auction.
     Transaction information (such as prices, volumes, and 
receipt and delivery points) should be disclosed so that shippers 
can ascertain the value of transportation. The names of shippers may 
not need to be disclosed or could be disclosed at a later date if 
the auction results are verifiable and free from potential affiliate 
favoritism.

    Adherence to these principles should help to ensure that auctions 
are transparent, verifiable, and non-discriminatory. The Commission 
strongly encourages pipelines and third-parties to begin the 
development of auction formats so that the industry will gain greater 
experience and familiarity with the use of auction techniques. Toward 
that end, Commission staff will be available to assist pipelines or 
third-parties in their development of auction formats.

III. Improving Competition and Efficiency Across the Pipeline Grid

    The Commission in this rule is making changes to enhance 
competition and improve efficiency across the pipeline grid. By 
improving efficiency and shipper options, these changes should provide 
shippers with market mechanisms that will better enable them to avoid 
market power where it exists. The changes include revising Commission 
regulations to: require pipelines to revise their scheduling procedures 
so that capacity release transactions can be scheduled on a comparable 
basis with other pipeline services; require pipelines to permit 
shippers to segment capacity and to facilitate capacity release 
transactions; and require pipelines to offer services that shippers can 
use to avoid penalties and to provide shippers with additional 
information that will enhance their ability to avoid penalties. 
Pipelines must file pro forma tariff sheets to comply with these 
requirements by May 1, 2000. Interested parties will be provided 30 
days to comment on the pro forma tariff filings.

A. Scheduling Equality

    The Commission is adopting in this final rule, the proposal set 
forth in the NOPR to amend its regulations to include a new 
Sec. 284.12(c)(1)(ii) to provide that pipelines must provide purchasers 
of released capacity the same ability to submit a nomination at the 
first available opportunity after consummation of the deal as shippers 
purchasing capacity from the pipeline. This will enable shippers to 
acquire released capacity at any of the nomination or intra-day 
nomination

[[Page 10192]]

times, and nominate gas coincident with their acquisition of capacity. 
By enabling released capacity to compete on a comparable basis with 
pipeline capacity, this will foster a more competitive short-term 
market.
    In the NOPR, the Commission explained that the current regulations 
put capacity obtained in the release market at a disadvantage compared 
to capacity obtained directly from the pipeline because nomination and 
scheduling opportunities for capacity release transactions are 
significantly circumscribed. As the Commission explained, pipelines can 
sell their interruptible and short-term firm capacity at any time, and 
shippers can schedule that capacity at the earliest available 
nomination opportunity. Further, shippers purchasing from the pipeline 
have three opportunities for intra-day nominations.\153\ Similarly, 
capacity holders making delivered sales can nominate and schedule at 
every available opportunity. By contrast, shippers utilizing released 
capacity must consummate their deals by 9:00 AM in order to submit a 
nomination by 11:30 AM to take effect at 9:00 AM the next gas day, and 
they cannot use an intra-day nomination opportunity to submit a 
nomination for the current gas day.
---------------------------------------------------------------------------

    \153\ Standards for Business Practices of Interstate Natural Gas 
Pipelines, Final Rule, 63 FR 39509 (July 23, 1998), 84 FERC para. 
61,031 (1998).
---------------------------------------------------------------------------

    In order to place capacity release transactions on a more equal 
footing with pipeline services, the Commission is amending its 
regulations to include a new Sec. 284.12(c)(1)(ii) to provide that 
pipelines must provide purchasers of released capacity, like shippers 
purchasing capacity from the pipeline, with the opportunity to submit a 
nomination at the first available opportunity after consummation of the 
deal. The regulation specifically provides that the contracting process 
should not interfere with the ability of the replacement shipper to 
nominate at the time the transaction is complete. In the NOPR, the 
Commission explained that there are several ways that a pipeline can 
protect itself, and suggested that pipelines can institute procedures 
under which replacement shippers receive pre-approval of their credit-
worthiness or receive a master contract, such as those given to 
interruptible shippers, permitting the replacement shipper to nominate 
under the contract at any time. The Commission will not require any 
specific method of compliance with this regulation, but will allow the 
pipeline to develop procedures suitable for its system.
    The vast majority of the commenters fully supported the 
Commission's proposal.\154\ These parties agree that providing 
replacement shippers with the same opportunities to nominate gas as the 
shippers nominating primary capacity will promote more competitive 
markets and help mitigate the pipeline's market power. For example, 
Dynegy characterizes the Commission's proposal as a ``common sense 
adjustment'' that will pave the way to more competitive markets and 
mitigate pipeline market power.
---------------------------------------------------------------------------

    \154\ For example, AEC Marketing, AF&PA, AGA, Amoco, Atlanta Gas 
Light, Colorado Springs, Columbia LDCs, Consolidated Natural, Duke 
Energy Trading, Exxon, Florida Cities, FPL Group, IPAA, Indicated 
Shippers, Louisville, Market Hub Partners, MichCon, Midland, NARUC, 
NEMA, NGSA, New England Gas Distributors, PanCanadian, Philadelphia 
Gas Works, Process Gas Consumers, et al., Proliance, PSC of 
Kentucky, PSC of New York, PSC of Wisconsin, Sithe, Washington Gas 
Light, and Wisconsin Distributors.
---------------------------------------------------------------------------

    Several of the commenters asked the Commission to clarify the 
bumping right of replacement shippers in view of the new 
procedures.\155\ For example, Industrials state that it seems clear 
that a replacement shipper should have the same bumping rights as any 
firm shipper vis-a-vis an interruptible shipper, but that the question 
of whether a replacement shipper should be able to bump secondary firm 
if the replacement shipper has primary firm is more difficult, and the 
Commission should clarify the entire issue of intra-day bumping of 
secondary firm by primary firm.
---------------------------------------------------------------------------

    \155\ For example, see the comments of Industrials, New York 
Public Service Commission, and NGSA.
---------------------------------------------------------------------------

    Nothing in the revised regulation adopted here changes the current 
rules on bumping, and the bumping rules in effect on each pipeline will 
remain unchanged and will continue to govern the priorities among 
shippers. A replacement shipper would, as a firm shipper, bump an 
interruptible shipper, subject to the requirement of notice to the 
interruptible shipper and an opportunity to renominate.\156\ Generally, 
primary firm will not interrupt secondary firm on an intra-day basis 
once the gas has begun to flow, but again that rule is pipeline-
specific, and will be governed by the particular pipeline's 
tariff.\157\
---------------------------------------------------------------------------

    \156\ E.g. Tennessee Gas Pipeline Corporation, 73 FERC para. 
61,158 (1995).
    \157\ See El Paso Natural Gas Company, 81 FERC para. 61174 at 
61,763 (1997).
---------------------------------------------------------------------------

    Some of the commenters suggested procedural changes which they 
state would expedite the execution of an agreement between the pipeline 
and the replacement shippers where such an agreement is required by the 
pipeline. For example, Dynegy suggests that the Commission require 
pipelines to adopt a master pro forma capacity release service 
agreement, or an umbrella agreement, that would include pre-approved 
credit, upon which replacement shippers can aggregate released 
capacity.
    The regulation adopted by the Commission specifically provides that 
if the pipeline requires the replacement shipper to enter into a 
contract, ``the requirement for contracting must not inhibit the 
ability to submit a nomination at the time the transaction is 
complete.'' The Commission suggested in the NOPR several methods, 
including the type of procedure suggested by Dynegy, that pipelines 
could use to meet this requirement. The Commission will not mandate any 
one method, but will leave this to be resolved by the pipelines and 
shippers.
    Dynegy argues the Commission should, in this proceeding, require 
all restrictions on capacity release to be removed. For example, Dynegy 
states that releasing shippers should be given the same rights as 
pipelines to sell capacity for less than a day. Further, Dynegy states 
that certain pipelines place other restrictions on released capacity, 
such as refusing to continue a discount if the capacity is released, 
requiring additional paperwork for capacity releases, requiring 
releasing shippers to remit to the pipeline any amounts received from 
the replacement shipper in excess of the releasing shipper's discounted 
rate, and requiring a deposit every time a capacity release bid is 
submitted.
    Dynegy's concerns about discounting have been resolved by the 
Commission in prior proceedings. The Commission has specifically held 
that a discount cannot be conditioned on an agreement not to release 
the capacity, and a pipeline cannot refuse to continue a discount if 
capacity is released.\158\ Further, Order No. 636-A specifically 
provides that ``a releasing shipper paying discounted rates is entitled 
to receive the proceeds from a release even if such proceeds exceed its 
reservation fee.'' \159\ The Commission has recognized an exception to 
this general rule only if the pipeline and the releasing shipper 
negotiate a revenue sharing agreement that is approved as part of a 
general section 4 rate

[[Page 10193]]

proceeding or specifically approved as a non-conforming discount 
agreement.\160\
---------------------------------------------------------------------------

    \158\ Natural Gas Pipeline Co., 84 FERC para. 61,099 (1998).
    \159\ Order No. 636-A, FERC Stats. & Regs. para. 30,950 at 
30,562 (1992).
    \160\ Natural Gas Pipeline Co., 82 FERC para. 61,289 (1998); 84 
FERC para. 61,099 (1998).
---------------------------------------------------------------------------

    In addition, there is no basis for a pipeline to charge a deposit 
every time capacity is released. Under the new regulation adopted here, 
as well as under GISB Standard 5.3.2, the pipeline must approve a 
contract within an hour, and therefore will know before gas flows under 
the release whether the replacement shipper is creditworthy. If the 
replacement shipper is creditworthy, then there is no basis for 
requiring a bond. The only time this issue would arise is when the 
replacement shipper is determined not to be creditworthy. In these 
circumstances, the pipeline could give the releasing shipper the option 
of posting a bond for the usage charge or assuming liability for the 
usage charge in the event of the replacement shipper's default.
    Some of the other problems cited by Dynegy, such as additional 
paperwork for capacity release, should be alleviated by the rule 
adopted here. Creating equality in nominations for capacity release 
will foster a more competitive market. However, the Commission has 
recognized that some of the differences in the treatment of different 
types of capacity reflect differences in the nature of the services 
that should be preserved. The Commission is not prepared to say at this 
time that all differences in the treatment of capacity release are 
unwarranted and should be eliminated.
    INGAA and Enron Pipelines argue that the different treatment of 
capacity release does not result from a lack of nomination 
opportunities, but stems from the deadline by which shippers currently 
must complete capacity release transactions. INGAA suggests that the 
problem could be solved by not requiring pre-posting and bidding for 
capacity release transactions. If the Commission does not accept this 
proposal, INGAA states that it would support revisions to the standard 
capacity release timeline to permit capacity release transactions to be 
conducted in the morning before the timely nomination deadline, rather 
than requiring such transactions to close on the day before 
nominations. INGAA states that an updated timeline is a better approach 
than setting a one-hour contracting requirement.
    The rule adopted here will speed up the capacity release nomination 
process for pre-arranged deals, but the Commission will not change the 
requirement for posting and bidding for longer deals. Posting and 
bidding is necessary to continue to protect against undue 
discrimination, and where capacity release is for a period of a month 
or longer, posting and bidding should not interfere with execution of 
the contract.
    The Coastal Companies state that while they do not oppose the goal 
of achieving parity between pipeline capacity and release capacity, 
they believe that the Commission's proposal will create additional 
unnecessary burdens on pipelines and shippers. Coastal states that, 
contrary to the Commission's assumption, shippers do not avoid capacity 
release, but instead seek out the capacity release market in order to 
maximize flexibility and minimize disclosure. They state that their 
companies are already handling release transactions expeditiously. 
Specifically, they state that ANR already has in its tariff a master 
agreement for replacement shippers to utilize, and CIG and WIC create a 
contract immediately at the time of the award. If the Commission does 
mandate these changes, the Coastal Companies ask the Commission to 
permit the pipelines to submit limited section 4 filings in order to 
recoup the costs associated with the mandated procedures.
    Contrary to the assertion of the Coastal Companies, the comments 
received by the Commission on this issue indicated a general consensus 
that current restrictions on nominations and scheduling of capacity 
release do inhibit the use of release capacity, and that the 
Commission's proposal will alleviate this problem. If the Coastal 
Companies already expedite capacity release agreements and use a master 
contract, they should not have to make any significant changes in their 
procedures, and implementation should not be burdensome to them.
    Finally, some commenters \161\ have asked that the Commission 
eliminate the ``shipper must have title'' policy. For example, AGA 
asserts that the Commission should consider repeal of the policy 
because the market has changed since issuance of Order Nos. 436 and 
636. Several other commenters ask that the Commission consider waivers 
of the shipper must have title policy for LDCs.\162\
---------------------------------------------------------------------------

    \161\ See, for example, comments of AGA, Atlanta Gas Light, 
Edison Electric, Brooklyn Union, Atlanta Gas Light Co.
    \162\ See, for example, comments of Columbia LDCs, Shell Energy, 
and ConEd.
---------------------------------------------------------------------------

    The shipper must have title policy developed in the individual 
pipeline proceedings to implement open access transportation under 
Order No. 436, and was intended to assure nondiscriminatory access to 
transportation.\163\ Thus, the policy predates the Commission's 
capacity release program established in Order No. 636, but the capacity 
release rules were designed with this policy as their foundation. For 
example, the rules are designed with all transactions conducted through 
the pipeline, with each shipper who acquired capacity contracting with 
the pipeline.
---------------------------------------------------------------------------

    \163\ E.g., Consolidated Gas Transmission Corp., 38 FERC para. 
61,150 at 61,408 (1987) (``all shippers shall have title to the gas 
at the time the gas is delivered to the transporter and while it is 
being transported by the transporter''); Texas Eastern Transmission 
Corporation, 37 FERC para. 61,260 at 61,683-85 (1986)).
---------------------------------------------------------------------------

    Under the capacity release rules, all allocations of capacity must 
be nondiscriminatory. The current regulations are designed to assure 
the transparency of capacity release transactions and thereby assure 
that capacity is allocated on a non-discriminatory basis. The 
regulations are also designed to assure that capacity is allocated to 
the highest bidder and thereby promote efficient pricing of capacity. 
Without the shipper must have title policy, it is unlikely that 
shippers would need to use capacity release because capacity holders 
could simply transport gas over the pipeline for another entity. These 
transactions would not be subject to any of the capacity release 
requirements, such as the reporting requirements or the allocation 
rules. Without the shipper must have title rule, the identity of the 
users of the pipeline's transportation and the conditions under which 
they moved gas would not be known.
    It is possible that the Commission could revise the capacity 
release program so that it could operate without the shipper must have 
title policy and still achieve the objectives of nondiscriminatory, 
efficient allocation of capacity with transparency. However, this would 
require major revisions to the current capacity release regulations, 
and such a change is not within the scope of this proceeding. The 
Commission recognizes that the current policy may impose some 
transaction costs, but this is necessary to ensure the ability to 
achieve the Commission's regulatory objectives.
    The Commission would consider any such changes to the capacity 
release program in a separate proceeding at a later date.

B. Segmentation and Flexible Point Rights

    In Order No. 636, the Commission established two principles--
flexible point rights and segmentation--that are important to creating 
efficient

[[Page 10194]]

competition in the market, both between shippers releasing capacity and 
the pipeline as well as between releasing shippers.\164\ Flexible point 
rights refer to the rights of firm shippers to change receipt or 
delivery point so they can receive and deliver gas to any point within 
the firm capacity rights for which they pay. Segmentation refers to the 
ability of firm capacity holders to subdivide their capacity into 
segments and to use the segments for different capacity transactions.
---------------------------------------------------------------------------

    \164\ 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] para. 30,939, at 30,428, 30,420-21 (Apr. 8, 1992), Order No. 
636-A, 57 FR 36128 (Aug. 12, 1992), FERC Stats. & Regs. Regulations 
Preambles [Jan. 1991-June 1996] para. 30,950, at 30,559 n.151 (Aug. 
3, 1992), Order No. 636-B, 61 FERC para. 61,272, at 61,997 (1992).
---------------------------------------------------------------------------

    The ability to use flexible receipt and delivery point rights and 
to segment capacity enhances the value of firm capacity and the ability 
of firm capacity holders to compete with capacity available from the 
pipeline as well as capacity available from other releasing shippers. 
In the example used in Order No. 636, a shipper holding firm capacity 
from a primary receipt point in the Gulf of Mexico to primary delivery 
points in New York could release that capacity to a replacement shipper 
moving gas from the Gulf to Atlanta while the New York releasing 
shipper could inject gas downstream of Atlanta and use the remainder of 
the capacity to deliver the gas to New York. In order for such a 
transaction to work, both the releasing and replacement shippers need 
the right to change their receipt and delivery points from the primary 
points in their contracts to use other available points.
    The combination of flexible point rights and segmentation increases 
the alternatives available to shippers looking for capacity. In the 
example, a shipper in Atlanta looking for capacity has multiple 
choices. It can purchase available capacity from the pipeline. It can 
obtain capacity from a shipper with firm delivery rights at Atlanta or 
from any shipper with delivery point rights downstream of Atlanta. The 
ability to segment capacity enhances options further. The shipper in 
New York does not have to forgo deliveries of gas to New York in order 
to release capacity to the shipper seeking to deliver gas in Atlanta. 
The New York shipper can both sell capacity to the shipper in Atlanta 
and retain the right to inject gas downstream of Atlanta to serve its 
New York market.
    The Commission's segmentation policy was not included in the 
Commission's regulations. Moreover, the segmentation policy is not 
being uniformly implemented across the pipeline grid. Some pipelines 
may not permit segmentation at all or may only permit segmentation for 
release purposes, but not by the shipper for its own uses. In order to 
improve competition, the Commission is requiring pipelines to permit 
shippers to segment their capacity for their own use or for release to 
the extent operationally feasible.
    Another issue raised in the NOPR concerned the Commission's policy 
with respect to relative priorities for shippers to use secondary 
points within their path and for confirmations at points of 
interconnection between pipelines. On these issues, the Commission has 
determined that a generally applicable regulation is not appropriate 
and that these issues are best handled on a case-by-case basis.
    The Commission addresses below its determinations with respect to 
segmentation and with respect to relative priorities for shippers using 
secondary points and at points of pipeline interconnection.
1. Segmentation Policies
    In the NOPR, the Commission sought comment on whether further 
regulatory change in its segmentation and flexible receipt and delivery 
point policies are needed to enhance competition. The Commission 
pointed out that the segmentation policy adopted in Order No. 636 
applied to capacity release transactions and that the Commission had 
not required pipelines to permit shippers to segment capacity for their 
own use. The Commission further sought comment on limitations on the 
ability to use flexible receipt and delivery points in segmented 
releases that had been accepted in pipeline restructuring proceedings 
under Order No. 636.
    In some restructuring proceedings, the Commission permitted 
pipelines to restrict replacement shippers' ability to choose primary 
points based on historic tariff provisions that limited primary point 
rights to the same level as the shipper's mainline contract 
demand.\165\ But even at that time, the Commission questioned whether 
those restrictions were justified.\166\ Although the Commission 
accepted the restrictions, the Commission also sought to minimize the 
effect of the restrictions on the ability to engage in segmented 
releases by permitting releasing and replacement shippers in segmented 
releases to choose separate primary point rights. The Commission found 
that because the releasing and replacement shippers were both shippers 
on the system, they should both be able to choose primary points 
consistent with their mainline contract demand:
---------------------------------------------------------------------------

    \165\ Compare Transwestern Pipeline Company, 62 FERC para. a 
few,090, at 61,659, 63 FERC para. 61,138, at 61,911-12 (1993); El 
Paso Natural Gas Company, 62 FERC para. 61,311, at 62,982-83 (1993) 
(permitting pipelines to continue historic limitations on primary 
receipt point rights) with Northwest Pipeline Coporation, 63 FERC 
para. 61,124, at 61,806-08 (1993) (not permitting the pipeline to 
add such restrictions).
    \166\ Transwestern Pipeline Company, 62 FERC para. 61,090, at 
61,659, 63 FERC para.61,138, at 61,911-12 (1993).

    The releasing and replacement shippers must be treated as 
separate shippers with separate contract demands. Thus, the 
releasing shipper may reserve primary points on the unreleased 
segment up to its capacity entitlement on that segment, while the 
replacement shipper simultaneously reserves primary points on the 
released segment up to its capacity on that segment.\167\
---------------------------------------------------------------------------

    \167\ Texas Eastern Transmission Corporation, 63 FERC para. 
61,100 at 61,452 (1993); El Paso Natural Gas Company, 62 FERC para. 
63,311 at 62,991. See also Transwestern Pipeline Company, 61 FERC 
para. 61,332, at 62,232 (1992).

    Under this Texas Eastern/El Paso approach, the releasing shipper 
could protect its New York delivery point right by choosing Atlanta as 
its primary receipt point and New York as its primary delivery point, 
while the replacement shipper designated its primary receipt point as 
the Gulf and Atlanta as its primary delivery point. In this example, 
neither releasing nor replacement shipper held contract demand in 
excess of their mainline rights. In other cases, where historic 
contract demand restrictions did not apply, the Commission allowed 
replacement shippers in all circumstances to change primary points 
without the releasing shipper losing its primary point rights.\168\
---------------------------------------------------------------------------

    \168\ See Northwest Pipeline Company, 63 FERC para. 61,124, at 
61,806-08 n. 72 (1993).
---------------------------------------------------------------------------

    Most shippers strongly support the ability to segment capacity and 
to use flexible receipt and delivery points to enhance competition 
throughout the pipeline grid.\169\ They contend that pipelines' 
implementation of segmentation policies vary, with some pipelines 
permitting no segmentation at all and with little consistency in the 
way pipelines treat segmented releases. Dynegy contends that 
differences in segmentation policy among pipelines

[[Page 10195]]

has made it difficult to compete effectively on certain pipelines. It 
points out, for example, that on some pipelines, shippers can segment 
their capacity through the nomination process while other pipelines 
restrict segmentation to capacity release transactions, forcing 
shippers to release capacity to themselves in order to segment 
capacity. The shippers urge the Commission to clearly establish and 
standardize its segmentation policy.
---------------------------------------------------------------------------

    \169\ See Comments of AlliedSignal, AFPA, AGA, Columbia LDCs, 
Duke Energy Trading, Dynegy, Fertilizer Institute, IPAA, Market Hub 
Partners, Midland, NEMA, New England Distributors, NGSA, Nicor, 
PanCanadian, PSC of Wisconsin, Sithe, and Wisconsin Distributors.
---------------------------------------------------------------------------

    INGAA supports the Commission's objective of implementing workable 
segmentation policies that broaden shippers' opportunities and increase 
competition. INGAA cautions, however, that any segmentation policy must 
be cognizant of the wide differences in pipeline configurations, some 
of which are less conducive to segmentation than others.\170\ INGAA 
also recommends that the Commission adhere to its policy recently 
enunciated in Tennessee \171\ that shippers do not have a right to 
release overlapping segments or to have the releasing and replacement 
shippers submit nominations that would have the effect of exceeding the 
contract demand of the original contract on any segment of the 
pipeline.
---------------------------------------------------------------------------

    \170\ See also Comments of Coastal, Koch, National Fuel.
    \171\ Tennessee Gas Pipeline Company, 85 FERC para. 61,052 
(1998).
---------------------------------------------------------------------------

    Shippers generally support a policy of permitting replacement 
shippers maximum flexibility to choose primary points in a segmented 
release that differ from those of the releasing shipper. In particular, 
they support the Texas Eastern/El Paso policy under which, in a 
segmented release, the replacement shipper is considered a new shipper 
who can choose primary receipt and delivery points from among the 
points available.\172\ Some also support the position that, if a 
replacement shipper changes primary points, a releasing shipper should 
be able to regain its primary points after the release ends.\173\ The 
pipelines generally oppose allowing segmented releases to expand 
primary receipt and delivery point rights on their systems or to permit 
the releasing and replacement shipper to hold more primary point 
capacity than the releasing shipper initially held.\174\ Koch maintains 
that while the Texas Eastern/El Paso policy would work on some 
pipelines, it would not work on its system which is a reticulated or 
cancellated network without defined paths.
---------------------------------------------------------------------------

    \172\ See Comments of AFPA, AGA I, Amoco I, Consolidated 
Natural, National Fuel Gas Distribution, New England Distributors, 
Proliance, Reliant Energy, Sithe.
    \173\ See Comments of AGA I, Florida Cities, MichCon, Proliance, 
National Fuel Gas Distribution, and Sithe.
    \174\ See Comments of INGAA.
---------------------------------------------------------------------------

    Although the Commission sought to ensure consistency during the 
restructuring proceedings under Order No. 636, the comments demonstrate 
that segmentation rights have not been implemented consistently across 
the pipeline grid. Accordingly, the Commission is adopting a regulation 
in new Sec. 284.7(e) stating:

    An interstate pipeline that offers transportation service under 
subpart B or G of this part must permit a shipper to make use of the 
firm capacity for which it has contracted by segmenting that 
capacity into separate parts for its own use or for the purpose of 
releasing that capacity to replacement shippers to the extent such 
segmentation is operationally feasible.

    This regulation will help achieve a more uniform and systematic 
application of segmentation rights across the interstate pipeline grid. 
Requiring pipelines to permit shippers to segment their capacity will 
increase the number of alternative capacity sources and therefore 
improve the competitiveness of the pipeline grid. The regulation 
further ensures a shipper's right to segment capacity for its own use 
as well as for release transactions. This will eliminate the 
inefficiencies present in the current system, such as shippers having 
to release capacity to themselves in order to segment their own 
capacity.\175\
---------------------------------------------------------------------------

    \175\ See Comment of Dynegy.
---------------------------------------------------------------------------

    Providing for more effective segmentation also is important in 
facilitating the development of market centers and liquid gas trading 
points. Without the ability to segment capacity, a shipper with firm-
to-the-wellhead capacity on a long-line pipeline has an incentive to 
obtain gas from an upstream production area attached to the long-line 
pipeline, rather than at a downstream interconnect with another 
pipeline. Because the firm shipper has paid for upstream transportation 
in its demand charge, the shipper has to pay only a small usage charge 
to move gas from the production area to the shipper's delivery point. 
In contrast, if the shipper or its gas supplier does not hold firm 
capacity on the connecting pipeline, they would have to pay additional 
transportation charges for interruptible service or released capacity 
to move gas along the connecting route to the interconnect point. For 
example, if the price for gas at the upstream production area on the 
long-line pipeline is $2.00/MMBtu and the delivered gas price at the 
interconnect point is $2.15/MMBtu (with an implicit transportation 
value of $.15/MMBtu) and the firm shipper's usage charge is less than 
$.01/MMBtu, the shipper would save $0.14/MMBtu by purchasing gas at the 
upstream production area, rather than at the interconnect point.
    Capacity segmentation, however, permits the shipper to release its 
capacity upstream of the market center for the market-determined value 
while retaining capacity downstream of that point in order to transport 
gas to market. In the prior example, the firm shipper's ability to 
release its upstream capacity for the market-determined value of $0.15/
MMBtu would permit it to purchase gas for $2.15/MMBtu at the 
interconnect without suffering an economic loss. Segmentation, 
therefore, reduces the economic incentive to favor the pipeline on 
which the shipper holds firm capacity, making the development of a 
market center or gas trading point at the interconnect point more 
viable.
    The regulation provides that segmentation must be permitted to the 
extent operationally feasible. This recognizes that, as INGAA points 
out, the configurations of some pipelines may make segmentation more 
difficult because these pipelines do not always provide straight-line 
paths. But the Commission expects a pipeline to permit segmentation to 
the maximum extent possible given the configuration of its system. 
Pipelines also need to make the process of segmentation as easy as 
possible, for example, by permitting segmentation to take place quickly 
and efficiently through the nomination process.
    Pipelines will be required to make a pro forma tariff filing by May 
1, 2000, showing how they will comply with this regulation. That filing 
must include whatever tariff changes are necessary for full compliance 
with the regulation or an explanation of how the pipeline's current 
tariff meets the requirements of the regulation. Pipelines claiming 
that all or any parts of their systems do not permit complete 
segmentation must demonstrate in their compliance filing why they must 
limit segmentation either to ensure service to other shippers or to 
ensure the operational integrity of their systems. Pipelines that are 
reticulated only in some portions of their system must permit full 
segmentation on the non-reticulated portion.
    In the compliance filings, pipelines must provide operational 
justifications for restrictions on segmentation rights. As discussed 
above, some pipelines imposed restrictions on segmentation during the 
restructuring proceedings under Order No. 636 based on historic 
provisions in their tariffs. However, many of these historic tariff 
provisions

[[Page 10196]]

date back to the pipelines' provision of merchant service and may no 
longer be justified for open access service provided in a more 
competitive market environment. In ruling on compliance filings, the 
Commission will not accept limitations on segmentation rights based 
solely on existing tariff conditions. Pipelines need to provide 
operational justifications for restricting the rights of shippers to 
effectively segment capacity and use flexible receipt and delivery 
points and must justify a proposal to deviate from the Texas Eastern/El 
Paso policy with respect to assignment of primary receipt and delivery 
points between releasing and replacement shippers.
2. Priorities for Capacity Within a Path
    In Order No. 636, the Commission required pipelines to permit 
shippers to change receipt and delivery points or to use any receipt or 
delivery point within the zone for which the shipper pays as a 
secondary point with a priority greater than interruptible capacity. 
When pipelines implemented Order No. 636, they assigned priorities to 
the types of services they provide. The general practice was to accord 
the highest priority to capacity at primary points. Shippers using 
secondary points receive equal priority regardless of where their 
primary points are located in the zone, because the shippers are paying 
the same zone rate: shipper A, with a primary point upstream in the 
zone, has the same right to deliver to a downstream point in that zone 
as Shipper B with a primary point further downstream in the zone, even 
though shipper B's path goes past the secondary point, and shipper A's 
path does not. Thus, if the pipeline cannot serve all the nominations 
to secondary points, each shipper will receive a pro rata allocation of 
capacity. Interruptible capacity is assigned the lowest value.
    A number of shippers contend that the Commission should adopt a 
regulation requiring that pipelines provide a shipper that is using a 
secondary point within its path a higher priority than a shipper in the 
same zone using a secondary point outside of its path (path 
approach).\176\ Dynegy argues that where constraints occur, a shipper 
using a secondary point within its path may lose capacity because the 
pipeline curtails all secondary point nominations equally even though 
the pipeline could make a delivery to that secondary point. Dynegy 
contends that often the shipper with the priority path can still reach 
the upstream secondary point, but that it may have to pay the pipeline 
a fee for a backhaul to do so. Some pipelines also have proposed to 
provide higher priority to shippers within a primary path.\177\ Koch 
and National Fuel, on the other hand, maintain that on their 
reticulated systems, shippers often do not have capacity paths and 
that, therefore, there cannot be a distinction between in-path and out-
of-path secondary points.
---------------------------------------------------------------------------

    \176\ See Comments of Dynegy, Enron Capital & Trade, Indicated 
Shippers, NEMA, National Fuel Gas Distribution, PanCanadian, PSC of 
Wisconsin, and Sithe.
    \177\ Panhandle Eastern Pipe Line Company, 87 F.E.R.C. para. 
61,331 (1999).
---------------------------------------------------------------------------

    The Commission has decided not to adopt the path approach as a 
generic policy. Providing priority to shippers within the path is not 
necessarily a more efficient allocation method than treating all 
shippers who pay the same rate equally. Capacity allocation is the most 
efficient when the capacity is allocated to the person placing the 
highest value on the capacity. In a perfect competitive environment, 
without transaction costs, the initial allocation of capacity among 
shippers will not matter because, through trading, capacity can be 
allocated to the highest valued user. Where transaction costs do exist, 
the goal of allocation should be to make the initial allocation to the 
party placing the highest value on obtaining the service in question. 
However, when dealing with the allocation of capacity to secondary 
points, there is no reason to believe that a shipper with a downstream 
primary delivery point necessarily places greater value on using a 
secondary point in the zone than a shipper paying the same rate with an 
upstream primary delivery point.
    The real problem in allocating secondary receipt or delivery points 
in constraint situations is not with initial priority allocations, but 
with the pricing structure on pipelines. Pipelines charge all shippers 
within a zone the same rate even though many pipelines do not divide 
zones along constraint points: a single zone encompasses points 
upstream or downstream of the constraint. Thus, adoption of the path 
approach would require shippers paying for capacity in the upstream 
portion of the zone to pay the same rate as those shippers with 
capacity downstream of the constraint point, although the upstream 
shippers would, in many cases, be unable to reach points downstream of 
the constraint.
    Because zones do not correspond with constraint points, adoption of 
the path approach also could result in difficulties in allocating 
primary point capacity. Shippers currently have an incentive to 
subscribe to the primary delivery points at which they most need gas, 
because nominations to primary points are accorded the highest 
scheduling priority. Under the path approach, however, all shippers 
within a zone will have an incentive to subscribe to a primary point as 
far downstream in the zone as they can even though the pipeline does 
not have sufficient capacity to satisfy all shippers' downstream 
requests for capacity. All shippers would have the incentive to move 
their primary points to the end of a zone because each shipper pays the 
same rate to subscribe to the downstream delivery point as its former 
upstream delivery point and, under the path approach, would obtain 
essentially the same priority to deliver to its former upstream 
delivery point as it would if it chose that upstream delivery point as 
its primary point. Meanwhile, by subscribing to the downstream primary 
delivery point, the shipper would obtain more valuable rights in the 
capacity release market because its path would go through the 
constraint point. As a consequence, adoption of the path approach could 
result in all shippers in a zone seeking to subscribe to downstream 
primary points even though the pipeline does not have sufficient 
capacity to provide all shippers with downstream capacity.
    Making adjustments to secondary point priority, therefore, is not 
the most effective solution to the constraint problem. A more direct 
solution would be for the pipeline to revise its zone boundary so that 
the shipper upstream of the constraint point pays a lower rate than the 
shipper downstream of the constraint point.
    Another approach to solving constraint issues is to design a 
capacity trading system for the future that improves upon the current 
system by permitting shippers to reallocate capacity rights after the 
pipeline has scheduled capacity and imposed whatever cuts may be 
applicable. For instance, if, due to constraints, the pipeline 
allocates capacity at secondary points on a pro rata basis, and the 
upstream shipper values the right to deliver to the secondary point 
more than the downstream shipper, an efficient capacity trading system 
would permit the upstream shipper to buy extra rights from the 
downstream shipper. Dynegy contends that, on some pipelines, shippers 
often are able to reach secondary delivery points even when the 
pipeline limits shipments to those points by paying to arrange a 
backhaul from their downstream primary delivery point to the upstream 
secondary delivery point. The

[[Page 10197]]

Commission obviously cannot resolve the appropriateness of the 
pipeline's backhaul charge under the current system in this generic 
rulemaking. However, the payment of an added charge, either to the 
pipeline or to another shipper, might be appropriate to reflect the 
additional value the shipper places on the capacity if an efficient 
trading system were in place so there was effective competition to the 
pipeline's provision of a backhaul service.
    Because some pipelines' reticulated systems do not provide shippers 
with capacity paths and because the path concept is not inherently a 
more efficient allocation system than the current system used on most 
pipelines, the Commission will not adopt a generic requirement that all 
pipelines adopt the path priority system. Issues relating to priority 
schemes on individual pipelines can be addressed in pipeline filings 
where all factors, such as zone boundaries, rate structures, and the 
effect of such changes on shippers and competition can be examined.
3. Confirmation Practices
    The Commission is not adopting a generic regulation regarding 
pipeline confirmation practices. In the NOPR, the Commission asked if 
the current practices of pipelines in confirming gas flows across 
interconnect points between pipelines adversely affects capacity 
allocation. Confirmation refers to the practice by which a pipeline 
communicates with upstream and downstream parties (other pipelines, 
producers, LDCs, point operators) to determine whether a shipper 
submitting a nomination on its system will receive the nominated gas 
from the upstream producer or pipeline and whether the downstream 
pipeline or LDC is able to take delivery of that quantity of gas. If a 
nomination is not confirmed on either the upstream or downstream ends 
of the system, the shipper may not receive the amount of gas it has 
nominated.
    The Commission requested comment on whether confirmation practices 
between interstate pipelines was affecting the allocation of primary 
and secondary capacity between pipelines. In particular, the Commission 
asked whether, when a constraint exists at an interconnect point, the 
general rule should be that the shipper with the higher priority on the 
downstream or take-away pipeline should receive priority.
    The comments on this issue varied greatly. AGA advocates giving 
priority to the shipper on the downstream pipeline. Amoco argues 
priority should be given to the shipper on the upstream pipeline. 
Indicated Shippers argues that priority should be determined by the 
priority rules of the pipeline operating the interconnect point. NGSA 
contends the priority rule of the pipeline with the constraint should 
govern, but if the constraint is at the meter, then the priority rule 
of the party responsible for measurement at the meter should control. 
INGAA maintains that no changes in confirmation practices are 
necessary, since its companies report that very little gas flow has 
been affected by confirmation practices and no complaints have been 
made to the Commission about this issue. INGAA contends that, rather 
than favoring shippers with firm transportation either on the upstream 
or downstream pipeline, shippers should be responsible for contracting 
for primary or secondary firm capacity on both pipelines to assure 
their gas flows.
    Given the lack of agreement among the industry and the paucity of 
complaints at this time, the Commission is not adopting a generic rule 
to govern confirmation at pipeline interconnects. However, the 
Commission agrees with INGAA's position that when pipelines do not have 
sufficient capacity at an interconnect to handle all nominations to 
that point, a shipper that has obtained firm capacity on both sides of 
an interconnect generally should have shipping priority over a shipper 
that is using interruptible transportation on one of the pipelines. If 
shippers believe that pipelines are not allocating capacity properly at 
interconnects, such problems can be handled individually through the 
complaint process.

C. Imbalance Services, Operational Flow Orders and Penalties

    One of the fundamental purposes of this rule is to improve 
efficiency in the short-term market. The operational flow orders (OFOs) 
and penalties imposed by a pipeline to protect the integrity of the 
pipeline system are an area where improvements in efficiency can be 
achieved.
    OFOs generally restrict service or require shippers to take 
particular actions. For instance, an OFO can reduce or eliminate 
tolerances for imbalances or contract overruns; institute severe 
penalties; or restrict intra-day nominations, the use of secondary 
receipt and delivery points, or firm storage withdrawals. Penalties are 
designed to deter shippers from creating imbalances, or from 
overrunning contract entitlements, and include penalties for physical 
imbalances (differences between commodity input and output), scheduling 
imbalances (differences between actual and scheduled quantities), and 
non-compliance with OFO and other tariff provisions.
    While OFOs and penalties can be important tools to correct and 
deter shipper behavior that threatens the reliability of the pipeline 
system, the current system of OFOs and penalties is not the most 
efficient system of maintaining pipeline reliability. The manner in 
which pipelines impose OFOs and penalties often limits efficiency in 
the short-term market by restricting shippers' abilities to effectively 
use their transportation capacity. Shippers make purchasing decisions 
based on gas commodity prices in the market. OFOs can limit the ability 
of shippers to respond to prices in the market, undermining the 
fluidity of the commodity market. For example, an OFO that eliminates a 
secondary receipt point for a shipper may eliminate the shipper's 
access to alternate suppliers with the lowest priced gas, or force the 
shipper to points where it has no purchase or sales agreements. By 
eliminating or changing a transaction that otherwise would have taken 
place, an OFO can interfere with the liquidity of the commodity market.
    Commission-authorized penalties provide an opportunity for shippers 
to engage in a form of penalty arbitrage, both across pipeline systems, 
and within a single pipeline system. Arbitrage across pipeline systems 
occurs where shippers intentionally overrun contract entitlements on 
those pipelines and LDCs that have the lowest penalties for contract 
overruns, and then flow gas to shippers on other systems with higher 
penalties, in an attempt to capture the economic gain of the difference 
in the level of penalties. In that situation, penalties skew the 
choices shippers might otherwise have made. The consequence is that, 
subsequently, pipelines in the area escalate their penalties to achieve 
the highest overrun/imbalance penalties. \178\
---------------------------------------------------------------------------

    \178\ Panhandle Eastern Pipe Line Company, 78 FERC para. 61,202 
at 61,876 (1997) (penalties ranging from $25 per Dth for variances 
of 5-10 percent to $200 for variances over 50 percent).
---------------------------------------------------------------------------

    Penalty arbitrage on a single pipeline system involves pipelines' 
existing tariff provisions for remedying monthly imbalances of a 
shipper--often described as ``cash-outs.'' Under these provisions, 
shippers are allowed to cash-out net monthly imbalances using an 
average monthly price. That procedure invites shippers to game the 
system within the month. For example, a shipper may take more than it 
delivers when gas prices are higher than cash-out prices, and deliver 
more than it

[[Page 10198]]

takes when gas prices are lower than cash-out prices. To the extent 
that pipelines rely on additional storage capacity to accommodate these 
imbalances, the arbitrage activity imposes costs on all shippers on the 
system through higher transportation rates that include more storage 
costs. In addition, at peak, arbitrage behavior may imperil systemwide 
reliability and trigger OFOs and emergency penalties that replace 
market forces with administrative rules.
    In order to protect the reliability of their systems, many 
pipelines have responded to arbitrage on their systems by imposing 
stricter imbalance tolerances and higher penalties. High penalty levels 
often operate to limit and distort market forces. For example, the 
prospect of incurring high overrun and/or imbalance penalties, may 
cause shippers to fail to maximize their use of pipeline 
transportation, or to contract for more transportation capacity than 
they need.
    The existence of arbitrage on and across pipeline systems indicates 
that in today's market, shippers are using penalties to achieve 
flexibility with respect to obtaining gas supplies and transportation 
capacity. In effect, shippers are treating the ability to overrun 
contract entitlements or create an imbalance as a ``service.'' Instead 
of buying gas or transportation, shippers are overrunning their 
contract entitlements, or taking more or less gas than they deliver, 
and paying cashouts and penalties, where that option is less expensive 
than purchasing gas or transportation directly. For example, by 
incurring an imbalance, a shipper is essentially borrowing gas from the 
pipeline, and the amount of the imbalance cash-outs and penalties are, 
in effect, the price for such borrowing. Indeed, during peak periods, 
the level of penalties can set the market price for gas since the 
maximum penalty level for overrunning a contract can set the maximum 
price that a shipper would pay for obtaining additional capacity.\179\ 
In many cases, however, the amount of the penalty is unlikely to match 
the cost to the pipeline of providing this flexibility, so that other 
shippers must pay for some of the costs.
---------------------------------------------------------------------------

    \179\ See Industry Surveys the Damage as Winter's Strength Runs 
Out, Natural Gas Intelligence, April 22, 1996, at 1, 4 (penalty 
levels were a real factor in determining the price of gas during 
peak demand period in the Midwest).
---------------------------------------------------------------------------

    Since the penalty system is being used by shippers to indirectly 
gain needed flexibility, and engage in behavior that may be harmful to 
the system as a way to obtain such flexibility, the Commission finds 
that a general shift in Commission policy is warranted so that 
penalties are imposed only when needed to protect system integrity. 
Shippers need to be given tools that will enable them to reduce 
penalties without jeopardizing pipeline integrity, and shipper and 
pipeline incentives need to be properly structured to avoid the need to 
impose penalties. For example, simply because one shipper runs a 
positive imbalance, system integrity may not be jeopardized if other 
shippers run negative imbalances that offset the positive imbalance. 
The Commission has previously required pipelines in such situations to 
permit shippers to trade offsetting imbalances, which reduces the need 
for imbalance penalties while maintaining pipeline integrity.\180\
    Another method of using market transactions to reduce the need for 
penalties is for pipelines or third-parties to enable shippers to avoid 
penalties by providing shippers with flexibility, directly, through the 
provision of separate imbalance management services, and to require the 
shippers who use that flexibility to pay for it. Thus, the Commission 
is refocusing its policy away from a ``command and control'' type of 
policy that fosters the use of OFOs and penalties to a ``service-
oriented'' policy that gives shippers other options to obtain 
flexibility.
---------------------------------------------------------------------------

    \180\ Standards For Business Practices Of Interstate Natural Gas 
Pipelines, Order No. 587-G, 63 FR 20072 (Apr. 23, 1998), III FERC 
Stats. & Regs. Regulations Preambles para. 31,062 (Apr. 16, 1998).
---------------------------------------------------------------------------

    Under the new policy, pipelines will be required to provide 
imbalance management services, like parking and loaning service, and 
greater information about the imbalance status of shippers and the 
system, to make it easier for shippers to remain in balance in the 
first instance. Pipelines also will be required to permit third-parties 
to offer imbalance management services that will allow shippers to 
avoid imbalances. The use of these techniques will obviate the need for 
pipelines to rely on penalties to prevent or solve operational problems 
caused by shippers. This will allow penalties to be more narrowly 
crafted to focus on conduct that is truly detrimental to the system.
    Equally as important as providing shippers with greater ability to 
avoid imbalances and penalties, is providing shippers with increased 
incentives to avoid imbalances and conduct harmful to the system. To 
this end, the Commission is encouraging pipelines to develop financial 
incentives for shippers to stay in balance, or to incorporate other 
types of incentives in the design of their imbalance management 
services. Replacing the negative incentive that penalties provide to 
deter behavior with more positive incentives to induce desirable 
shipper behavior will reduce imbalances and penalties, and may help 
alleviate gaming on pipeline systems.
    Moreover, to effectively shift pipelines to the use of the non-
penalty mechanisms described above to solve and prevent operational 
problems, it will be necessary to eliminate the pipelines' financial 
incentive to impose penalties and OFOs. Thus, the Commission is 
requiring pipelines to credit the revenues from penalties and OFOs to 
shippers.
    More specifically, the Commission is revising its regulations 
governing standards for pipeline business operations and communications 
\181\ to add three new provisions, concerning imbalance management, 
operational flow orders, and penalties, that establish several general 
policies designed to help shippers avoid penalties and OFOs, and help 
pipelines minimize their need for and use of penalties and OFOs. As 
described in more detail below, these provisions require pipelines to 
offer imbalance management services, to establish incentives and 
procedures to minimize the use of OFOs, to establish only those penalty 
structures and levels that are necessary and appropriate to protect the 
system, to credit penalty and OFO revenues to shippers, and to provide 
more imbalance information on a timely basis. To implement these new 
regulations, each pipeline will be required to make a pro forma 
compliance filing no later than May 1, 2000. In its filing, each 
pipeline must either propose pro forma changes to its tariff to 
implement the requirements discussed above, or explain how its existing 
tariff and operating practices are already consistent with, or in 
compliance with, the new requirements.
---------------------------------------------------------------------------

    \181\ These regulations appear in existing section 284.10, which 
the Commission is redesignating Sec. 284.12.
---------------------------------------------------------------------------

    The policies set forth in the provisions below are the same general 
policies that the Commission proposed in the NOPR. There was 
considerable support among the commenters for the goals underlying the 
Commission's proposed policies.\182\
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    \182\ Comments of AEC, AF&PA, AGA, Columbia LDCs, Duke Energy, 
Dynegy, Exxon, Florida Cities, IPAA, Indicated Shippers, MichCon, 
Midland, NEMA, Philadelphia Gas Works, Process Gas Consumers, WGL, 
and Wisconsin Distributors.
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1. Policies Adopted by This Rule
    a. Imbalance Management. The Commission is adopting a new 
subsection addressing imbalance

[[Page 10199]]

management in its regulation governing the standards for pipeline 
business operations and communications. New Sec. 284.12(c)(2)(iii), 
adopted herein, provides as follows:

    (iii) Imbalance management. A pipeline must provide, to the 
extent operationally practicable, parking and lending or other 
services that facilitate the ability of its shippers to manage 
transportation imbalances. A pipeline also must provide its shippers 
the opportunity to obtain similar imbalance management services from 
other providers and shall provide those shippers using other 
providers access to transportation and other pipeline services 
without undue discrimination or preference.

    This provision establishes the policy that pipelines must provide 
to shippers, to the extent operationally feasible, imbalance management 
services, such as park and loan service, swing on storage service, or 
imbalance netting and trading. As part of this policy, the Commission 
specifically encourages the use of auctions for shippers to trade 
imbalances so that they can avoid the imposition of unnecessary 
penalties. In addition, under this policy, pipelines will not be 
permitted to give undue preference to their own storage or balancing 
services over such services that are provided by a third party. The 
Commission is requiring pipelines to include these imbalance management 
services as part of their tariffs.
    The Commission expects pipelines to provide as many different 
imbalance management services as is operationally feasible, and to work 
to develop new, innovative services that help shippers manage or 
prevent imbalances. In order to give pipelines an incentive to develop 
these new imbalance management services, the Commission is not changing 
its current policy that pipelines may retain the revenues from a new 
service initiated between rate cases. In addition, the Commission 
particularly encourages pipelines to design imbalance management 
services that will give shippers a built-in incentive to utilize the 
service, or to otherwise stay in balance. Pipelines are also urged to 
create positive financial inducements for shippers to remain in balance 
or avoid behavior that is harmful to the system, rather than the 
negative incentives provided by penalties.
    The Commission in Order No. 587-G has already taken a first step 
toward increasing shippers' abilities to manage imbalances by requiring 
that every pipeline: (a) Allow firm shippers to revise nominations 
during the day (thereby reducing the probability of imbalances caused 
by inaccurate nominations); (b) enter into operational balancing 
agreements at all pipeline to pipeline interconnections; (c) permit 
shippers to offset imbalances across contracts and trade imbalances 
amongst themselves when such imbalances have similar operational impact 
on the pipeline's system; and (d) provide notice of OFOs and other 
critical notices by posting the notice on their Internet web 
sites.\183\ The other actions the Commission is taking in this rule 
will also help shippers avoid imbalances and penalties, and reduce the 
need for OFOs. For example, shippers will have an alternative means of 
acquiring capacity during peak periods, other than overrunning their 
contract entitlements and incurring unauthorized overrun penalties, now 
that the Commission is removing the price cap from released capacity.
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    \183\ Standards For Business Practices Of Interstates Natural 
Gas Pipelines, Order No. 587-G, 63 FR 20072 (Apr. 23, 1998), III 
FERC Stats. & Regs. Regulations Preambles para. 31,062 (Apr. 16, 
1998). GISB's Executive Committee approved business practice 
standards for trading and netting of imbalances at its July 15-16, 
1999 meeting, however the electronic standards have yet to be 
finalized. Http://www.gisb.org/ec.htm (Nov. 15, 1999).
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    However, many pipelines currently do not offer effective imbalance 
management services, such as swing on storage or parking and loaning 
services. Other pipelines already offer some imbalance management 
services, but could improve upon them, or supplement them with 
additional imbalance management services, to the extent operationally 
feasible. The ready availability of imbalance management services will 
make it easier for shippers to stay in balance and avoid causing 
operational problems. Thus, a further expansion of the number of 
services available on each pipeline that facilitate a shipper's ability 
to manage imbalances will significantly increase shippers' ability to 
avoid imbalances, and correspondingly reduce the need for pipelines to 
impose penalties.
    Moving towards a system where customers pay directly for imbalance 
management services will impose the costs of those services on those 
shippers needing the service, minimizing the impact on other customers 
that require less flexibility. Thus, it should shift costs that are now 
collected from all shippers through general transportation charges to 
those shippers that most require the needed flexibility.
    However, pipelines will not be permitted to implement the new 
imbalance services until they also implement imbalance netting and 
trading on their systems. Pipelines should not expect shippers to 
purchase new services until the shippers can determine whether 
imbalance trading will be adequate for their needs. Thus, the 
implementation of the new imbalance management services must coincide 
with the implementation of imbalance netting and trading. Since GISB 
has already approved business practice standards for imbalance netting 
and trading, pipelines should be able to implement imbalance netting 
and trading at the same time that they implement the new imbalance 
management services.
    This policy is the same policy proposed in the NOPR. Various 
commenters offered their support for this principle, urging the need 
for pipelines to offer imbalance management solutions prior to imposing 
penalties.\184\ The little opposition to this principle comes from 
INGAA, and several pipelines who maintain that no changes at all are 
needed to the Commission's penalty policy.\185\ INGAA maintains that a 
policy requiring pipelines to provide imbalance management services is 
unnecessary given that pipelines must provide such services to stay 
competitive with those pipelines that already provide such 
services.\186\ Williston Basin states that services such as park and 
loan service do not need to be mandated by the Commission. It asserts 
that the need for, and implementation of, imbalance management services 
should be between the pipeline and its shippers. Williston Basin argues 
that having the Commission require a ``cookie-cutter'' imbalance 
management service for all pipelines will not provide the best 
imbalance service for a specific pipeline.\187\
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    \184\ Comments of AF&PA, AlliedSignal, Amoco, Dynegy, FPL, 
Indicated Shippers, IPAA, and Shell.
    \185\ Comments of INGAA, Williston Basin, and Koch.
    \186\ Comments of INGAA at 107.
    \187\ Comments of Williston Basin at 35.
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    The Commission finds that requiring pipelines to provide imbalance 
management services, to the extent operationally feasible, is a key 
step in creating a policy that focuses more on providing flexible 
service options, minimizing the need for OFOs and penalties. The 
availability of imbalance management services is critical for providing 
many shippers with the flexibility they need to avoid or correct 
imbalances, which in turn obviates the need for pipelines to impose 
OFOs and penalties. The Commission must require pipelines to provide 
imbalance management services, despite the competitive incentive INGAA 
states pipelines already have to provide these services, since an 
incentive to provide

[[Page 10200]]

such services alone will not guarantee that each pipeline will in fact 
provide the services. However, to the extent pipelines are already 
motivated to provide imbalance management services to remain 
competitive, compliance with the requirement in this rule that 
pipelines offer such services should not be particularly difficult or 
burdensome.
    With respect to Williston Basin's argument that the choice whether 
to provide imbalance management services and how to do so are business 
decisions that the Commission should allow each individual pipeline to 
make, the Commission stresses that by requiring pipelines to offer 
imbalance management services, the Commission is not dictating which 
services, or how many services, a pipeline must provide. Much of the 
decisionmaking, including whether the provision of such services is 
operationally practicable, is still left to the pipeline and its 
shippers. Also, the Commission is not dictating the exact details of 
these services for each pipeline, so that contrary to Williston Basin's 
understanding, the Commission is not imposing a one-size-fits-all 
imbalance management service on pipelines.
    b. Operational Flow Orders. The Commission is adopting another new 
subsection in Sec. 284.12(c)(2) of its regulations to govern OFOs. New 
Sec. 284.12(c)(2)(iv), adopted herein, provides as follows:

    (iv) Operational flow orders. A pipeline must take all 
reasonable actions to minimize the issuance and adverse impacts of 
operational flow orders (OFOs) or other measures taken to respond to 
adverse operational events on its system. A pipeline must set forth 
in its tariff clear standards for when such measures will begin and 
end and must provide timely information that will enable shippers to 
minimize the adverse impacts of these measures.

    This provision establishes the policy that each pipeline must adopt 
incentives and procedures that minimize the use and potential adverse 
impact of OFOs. The imposition of OFOs may severely restrict the 
purchase and transportation alternatives available to a customer during 
peak periods, precisely when such alternatives are critically needed to 
enhance the opportunities of a shipper to purchase such services at the 
lowest competitive prices. Under current practice, pipelines have 
incentives to favor OFOs as the first option, not the last resort. The 
pipeline is likely to err on the side of using an OFO, because it bears 
the risk that if it does not, curtailment of load may result that could 
in turn precipitate strong public disapproval and law suits from firm 
customers. In contrast, shippers--not pipelines--bear the costs that 
result from imposition of OFOs. A pipeline could also prefer OFOs 
because it would limit or eliminate a shipper's ability to purchase 
transportation that would be in lieu of transportation services 
provided by that pipeline. In some cases, shippers have complained that 
OFOs have been issued too frequently, for too long, and were larger in 
scope than required to protect the integrity of system operations.\188\
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    \188\ See, e.g., NorAm Gas Transmission Company, 79 FERC para. 
61,126 at 61,546-47 (1997); Southern Natural Gas Company, 80 FERC 
para. 61,233, at 61,890 (1997) Northern Natural Gas Company, 77 FERC 
para. 61,282 (1997); Panhandle Eastern Pipe Line Company, 78 FERC 
para. 61,202 (1997); Northwest Pipeline Company, 71 FERC para. 
61,315 (1995).
---------------------------------------------------------------------------

    In light of these considerations, it is appropriate to require the 
revision of existing pipeline tariffs to ensure that the imposition and 
adverse impact of OFOs are reduced to the maximum extent 
practicable.\189\ Many commenters favored this proposal in the NOPR to 
make each pipeline's tariff conform to this standard.\190\ Therefore, 
to implement this policy, the Commission is requiring each pipeline to 
revise its tariff in the following respects, to the extent necessary.
---------------------------------------------------------------------------

    \189\ The requirement in this rule that pipelines automatically 
credit OFO penalty revenues to shippers will also help limit any 
incentive for the pipeline to use an OFO to generate revenues.
    \190\ Comments of AF&PA, AGA, Florida Cities, Indicated 
Shippers, IPAA, MichCon, Midland, NEMA, Proliance and Shell.
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    First, each pipeline's tariff must state clear, individual 
pipeline-specific standards, based on objective operational conditions, 
for when OFOs begin and end. This will enable shippers to better 
anticipate in advance, based on market conditions, when OFOs are likely 
to be in effect and to plan their business affairs accordingly.
    Second, the tariff must require the pipeline to post, as soon as 
available, information about the status of operational variables that 
determine when an OFO will begin and end. For example, if an OFO will 
remain in effect until repairs are completed on a compressor, the 
pipeline must be required to update shippers on the status of the 
repairs.
    Third, the tariff must state the steps and order of operational 
remedies that will be followed before an OFO is issued to assure that 
the OFO has the most limited application practicable and to limit the 
consequences of its imposition. For example, one requirement would be 
that a pipeline provide as much advance warning as possible of the 
conditions that may create an OFO and the specific OFO itself that 
would allow customers to respond to such conditions and/or prepare 
alternative arrangements in the event the OFO is implemented.
    Fourth, the tariff must set forth standards for different levels or 
degrees of severity of OFOs to correspond to different degrees of 
system emergencies the pipeline may confront. For example, a large OFO 
penalty may be appropriate in severe cases, whereas a small OFO penalty 
may be appropriate in others.
    Fifth, the tariff must establish reporting requirements that 
provide information after OFOs are issued on the factors that caused 
the OFO to be issued and then lifted. This requirement is in addition 
to the existing requirement that pipelines provide notice of OFOs and 
other critical notices by posting the notice on the pipelines' Internet 
web sites and by notifying the affected customers directly.\191\
---------------------------------------------------------------------------

    \191\ Redesignated Sec. 284.12(c)(3)(vi).
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    A few commenters request that the Commission refrain from requiring 
pipelines to adopt tariff provisions designed to curb the use of OFOs. 
Enron Pipelines state that OFOs are a vitally important tool to effect 
operational changes by specific shippers causing problems, and are not 
designed to assess penalties.\192\ Enron Pipelines believe that the 
potential for operating conflicts among shippers will only increase in 
the future, making OFOs increasingly important. Enron Pipelines argue 
that by requiring a pipeline to take all reasonable actions to minimize 
the issuance of OFOs, the Commission is essentially saying that it 
prefers that the pipeline take systemwide measures, such as the 
purchase of line pack gas, or the operation at reduced capacity levels, 
rather than the narrowly targeted solution of an OFO. Enron Pipelines 
do not believe that is the Commission's intent.
---------------------------------------------------------------------------

    \192\ Comments of Enron Pipelines at 48-50.
---------------------------------------------------------------------------

    The requirement that pipelines establish standards and procedures 
for the imposition of OFOs, and the Commission's guidance to pipelines 
in that effort, is not meant to prevent pipelines from issuing OFOs 
where necessary, as Enron apparently believes. However, while the 
Commission is not committing pipelines to take systemwide measures to 
resolve operational problems, in some instances, it could be more 
appropriate to take actions other than issuing a specific OFO.
    Williams, also, maintains that no major policy changes are needed 
regarding OFOs.\193\ It asserts that any OFO problems are confined to 
only a few systems, and are not industry-wide.

[[Page 10201]]

Therefore, Williams suggests that rather than requiring pipelines to 
revise their existing OFO provisions, the Commission should monitor the 
frequency of OFOs on individual pipelines. Then, Williams states, if a 
pipeline frequently issues OFOs, a proceeding could be established to 
determine if changes are necessary to that pipeline's tariff. INGAA, as 
well, agrees with a pipeline-specific approach.\194\
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    \193\ Comments of Williams at 21-23.
    \194\ Comments of INGAA at 109-112.
    \4\ Regulation of Natural
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    The Commission disagrees with Williams that it is not necessary at 
this time to require all pipelines to develop OFO standards. The 
Commission is not requiring all pipelines to adopt the same, generic 
standards. The Commission is requiring OFO guidelines on an individual 
pipeline basis to allow each pipeline to devise a set of OFO procedures 
that are specific to its system, and that may take into account the 
pipeline's OFO track record. These guidelines will help limit the 
imposition of OFOs to only those that are necessary, as well as limit 
the incurrence and duration of necessary OFOs, so that shippers can 
rely more on market forces in making their decisions. However, the 
Commission may, in the future, decide also to monitor the frequency of 
OFOs on individual pipelines, and thereafter institute proceedings to 
determine if further tariff changes are warranted for particular 
pipelines, as Williams suggests. With respect to INGAA's concern, the 
guidelines set forth in this rule will not prevent pipelines from 
determining what OFO standards are appropriate for their systems, or 
from issuing OFOs where necessary.
    c. Penalties. Finally, new Sec. 284.12(c)(2)(v), governing 
penalties and adopted herein, provides as follows:

    (v) Penalties. A pipeline may include in its tariff 
transportation penalties only to the extent necessary to prevent the 
impairment of reliable service. Pipelines may not retain net penalty 
revenues, but must credit them to shippers in a manner to be 
prescribed in the pipeline's tariff. A pipeline must provide to 
shippers, on a timely basis, as much information as possible about 
the imbalance and overrun status of each shipper and the imbalance 
of the pipeline's system.

    -This new provision establishes three general principles with 
respect to penalties. First, penalties are not required, but to the 
extent that a pipeline assesses penalties, they must be limited to only 
those transportation situations that are necessary and appropriate to 
protect against system reliability problems. The Commission has 
authorized extremely high overrun and imbalance penalties for several 
pipelines on the basis that doing so was required to protect system 
integrity.\195\ However, the Commission finds that there is not 
necessarily a connection between the high level of authorized penalties 
and the level that is necessary to ensure system reliability. By 
requiring that all penalties be necessary to prevent the impairment of 
reliable service, the Commission is requiring pipelines to narrowly 
design penalties to deter only conduct that is actually harmful to the 
system.
---------------------------------------------------------------------------

    \195\ See, e.g., Northern Natural Gas Company, 77 FERC para. 
61,282, at 62,236 (1997); Panhandle Eastern Pipe Line Company, 78 
FERC para. 61,202, at 61,876-77 (1997), reh'g denied, 82 FERC para. 
61,163 (1998).
---------------------------------------------------------------------------

    Also, the Commission is aware that some pipelines have penalties 
that are at the same level during peak and non-peak periods and may be 
imposed regardless of whether the pipeline is faced with emergency 
conditions.\196\ Non-critical day penalties, or penalties imposed 
during off-peak periods, may not be the most appropriate and effective 
to protect system operations. Establishing a principle that all 
penalties must be necessary for reliable system operations will help 
ensure that penalties are appropriately drawn and tailored to reflect 
the potential harm to the system. Therefore, in the compliance filing 
to implement this principle, the Commission directs all pipelines to 
either explain or justify their current penalty levels and structures 
under these standards, or revise them to be consistent with this 
principle.
---------------------------------------------------------------------------

    \196\ See Tennessee Gas Pipeline Company, 81 FERC para. 61,266, 
at 62, 312; reh'g denied, 83 FERC para. 61063, at 61,335 (1998) 
(contrasting a penalty based on spot pricing which varies penalty 
levels in response to market conditions with other pipelines with 
fixed penalty levels).
---------------------------------------------------------------------------

    In cases in which penalties are needed to protect against harm to 
the pipeline system, the requirement that pipelines provide imbalance 
management services and permit third-parties to offer such services 
provides shippers with the flexibility to avoid conduct harmful to the 
system and penalties associated with such conduct. Thus, pipelines 
should be able to recraft their current broad penalty provisions in 
ways that directly focus on harm to the system and do not encourage the 
use of penalties as a substitute for obtaining services. As an example, 
pipelines may be able to change the methods by which they cash-out 
imbalances to eliminate the incentives for shippers to borrow gas from 
the pipeline because the cash-out price is less than the market price 
for gas. Rather than borrowing gas from the pipeline and paying the 
cash-out price, shippers can more directly obtain the flexibility they 
need by directly purchasing a parking and lending service from the 
pipeline or a third-party.
    Second, new Sec. 284.12(c)(2)(v) establishes the policy that a 
pipeline may not retain the revenues from penalties, but must credit 
them to shippers. The Commission is requiring pipelines to 
automatically credit all revenues from all penalties, net of costs, 
including imbalance, overrun, cash-out, and OFO penalties, to shippers. 
Ideally, penalty revenues should be credited only to non-offending 
shippers so that offending shippers are not able to recoup the 
penalties they have paid, and thus, shippers are given a positive 
incentive to avoid incurring penalties. It is possible for pipelines to 
construct penalty revenue crediting mechanisms that exclude shippers 
who were assessed the penalty from the revenue credits. \197\ However, 
the Commission recognizes that for some pipelines it may be difficult 
to develop or implement such a penalty revenue crediting mechanism. 
Thus, the Commission will not prescribe on a generic basis the details 
of the revenue crediting mechanism, including which shippers will 
receive the penalty revenue credits. Instead, the Commission will 
permit each pipeline to formulate an appropriate method for 
implementing penalty revenue crediting on its system. Pipelines should 
include the detail of their revenue crediting mechanism in the pro 
forma tariff filings, discussed infra, that the Commission is requiring 
pipelines to make to comply with this new rule.
---------------------------------------------------------------------------

    \197\ For example, under Northwest Pipeline Corporation's 
penalty revenue crediting mechanism, Northwest credits penalty 
revenues monthly only to shippers who were not assessed a penalty. 
See section 14(g) of the General Terms and Conditions of Northwest's 
tariff. Fourth Revised Sheet No. 232-D and Second Revised Sheet No. 
232-E, third Revised Volume No. 1 of Northwest's FERC Gas Tariff.
---------------------------------------------------------------------------

    The Commission's policy has been to allow pipelines to retain 
penalty revenues until the next rate case, and then to permit penalty 
revenues to be taken into account in the rate case when developing a 
pipeline's revenue requirement. The theory underlying the Commission's 
policy was that a properly designed penalty deters violations, and 
thus, there should be little or no penalty revenues to credit. This 
rationale was upheld by the U.S. Court of Appeals for the D.C. Circuit 
in Pennsylvania Office of Consumer Advocate v. FERC.\198\ There, the 
court rejected a claim that the pipeline should be required to credit 
back all penalty

[[Page 10202]]

revenues to non-offending shippers, where in the prior year, no 
penalties had been assessed under the penalty rate at issue. The court 
agreed with the Commission that based on such circumstances, ``the mere 
possibility of revenue gains'' did not ``justif[y] a prospective 
requirement that the revenues be credited to customers.'' \199\
---------------------------------------------------------------------------

    \198\ Pennsylvania Office of Consumer Advocate v. FERC, 131 F.3d 
182 (D.C. Cir. 1997), modified on other grounds, 134 F.3d 422 (D.C. 
Cir. 1998) (Pennsylvania).
    \199\ Id., 131 F.2d at 187.
---------------------------------------------------------------------------

    However, the prospect of retaining revenues from penalties offers 
an incentive for pipelines to propose or implement inappropriate 
penalties and OFOs that can hinder efficiency and competition. Also, to 
the extent the penalty revenues are not reflected in rates, since 
pipelines are no longer required to file rate cases on a periodic 
basis, the penalty provisions have had the ability to result in profit 
centers for the pipelines. \200\
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    \200\ FERC Form No. 2 data indicate that gross penalty revenues 
from the 15 pipelines that attributed revenue to penalties amounted 
to approximately $24.3 million in 1996, $9.6 million in 1997, and $5 
million in 1998. This reduction in gross penalty revenues may simply 
be a reflection of the relatively mild winters that have occurred in 
the past few years.
---------------------------------------------------------------------------

    Given the Commission's new emphasis in this rule on providing 
services to facilitate shippers' ability to avoid imbalances and 
penalties and providing inducements to shippers to remain in balance, 
rather than on penalties, the Commission does not expect that 
significant revenues will be generated from penalties. However, to the 
extent that penalty revenues are generated, the required crediting of 
penalty revenues will eliminate any economic incentive for pipelines to 
rely on penalties rather than inducements. The Commission is requiring 
penalty revenue crediting not so much for the purpose of preventing 
penalties from becoming a profit center, but more for the purpose of 
eliminating any financial incentive on the part of pipelines to impose 
penalties that would naturally hinder the pipelines' movement toward 
reliance on the provision of imbalance services, greater imbalance 
information, and shipper incentives.
    In addition, requiring pipelines to credit penalty revenues to 
shippers also responds to concerns that the court had subsequent to its 
Pennsylvania decision, in Amoco v. FERC,\201\ about allowing pipelines 
to retain penalty revenues. In Amoco v. FERC, the court found that the 
Commission had not adequately supported its finding that the proposed 
increase in the penalty level would not provide the pipeline with 
significant penalty revenues, especially where the pipeline had 
collected $1.8 million in overrun penalty revenues in the year prior to 
the pipeline's filing. The court remanded the case to the Commission 
for an explanation of how its decision to permit the pipeline to retain 
the penalty revenues and not require penalty revenue crediting is 
consistent with the NGA. Requiring the crediting of penalty revenues to 
shippers in this case will eliminate the potential for pipelines to 
receive penalty revenue windfalls, and consequently, the court's 
concern.
---------------------------------------------------------------------------

    \201\ 158 F.3d 593 (D.C. Cir. 1998).
---------------------------------------------------------------------------

    In the NOPR, the Commission suggested the crediting of penalty 
revenues as one of a number of options that could help pipelines to 
impose only necessary and appropriate penalties. The idea of crediting 
penalty revenues garnered much support in the comments.\202\ However, a 
few parties are opposed to revenue crediting because they contend that 
no changes at all are necessary to the Commission's policies on 
penalties and OFOs.\203\ They assert that the current penalty tariff 
provisions have been carefully crafted by pipelines and their 
customers, meet each pipeline's operational needs, and deter 
inappropriate conduct.
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    \202\ Comments of AGA, Dynegy, FPL, Indicated Shippers, 
Louisville, Minnesota, NASUCA, Nicor, Penn. PUC, process Gas 
Consumers, and PSC of Wisconsin.
    \203\ Comments of INGAA, Koch, Williams, and Williston Basin.
---------------------------------------------------------------------------

    The Commission disagrees. Allowing pipelines to retain penalty 
revenues gives pipelines the wrong incentives for the design and 
imposition of penalties, and provides no incentive for the pipeline to 
develop other, non-penalty mechanisms that would give shippers 
incentives to control their imbalances. As stated above, the crediting 
of penalty revenues eliminates the pipelines' financial incentive to 
use and impose penalties.
    Third, Sec. 284.12(c)(2)(v) establishes the requirement that 
pipelines provide to shippers, on a timely basis, as much information 
as possible about the imbalance and overrun status of each shipper and 
the imbalance of its system as a whole. Under this policy, pipelines 
will be required to distribute to shippers the information that they 
currently have available on deliveries and imbalances at each shipper's 
delivery point, as well as on system imbalances. However, the 
Commission is not requiring pipelines to install upgraded, real time 
meters at receipt and delivery points.\204\ In other words, the 
requirement that pipelines provide as much imbalance information as 
possible is not meant to require that pipelines make an investment in 
additional metering equipment. The Commission will leave the decision 
of when and where to install upgraded metering to the pipeline and 
individual shippers, based on their own economic and operational 
judgment. The Commission will continue the current policy of permitting 
pipelines and their shippers to address these cost issues as they 
arise, i.e., in general rate cases or, as provided in the pipelines' 
tariffs. At this time, no change in this aspect of the Commission's 
policy is necessary.
---------------------------------------------------------------------------

    \204\ This is consistent with the NOPR proposal.
---------------------------------------------------------------------------

    The pipelines must disseminate the available imbalance information 
on a timely basis, so that shippers will have a reasonable opportunity 
to avoid penalties. The Commission will require pipelines to establish 
a system that notifies each shipper individually of the imbalance/
delivery information that the pipeline possesses, or to give shippers 
access to such information via the Internet. The pipelines, however, 
may post relevant system imbalance information more generally. The 
obligation that such information be provided on a timely basis will 
vary from pipeline to pipeline, depending on the pipeline's penalties. 
For example, a pipeline that imposes imbalance penalties only on a 
monthly basis would have a different obligation to provide imbalance 
information to its shippers than a pipeline that imposes daily 
imbalance penalties.
    Providing imbalance information on a timely basis will enhance the 
opportunities of a shipper to avoid penalties and help prevent penalty 
situations. Information on the precise level of a shipper's deliveries 
and imbalances will help the shipper avoid overruns and imbalances, and 
maximize the use of its transportation rights on the pipeline system. 
Providing such information might also allow pipelines to reduce the 
level of penalty-free tolerances and to thus reduce system costs (e.g., 
storage capacity to provide such tolerances). Finally, such 
information, together with information on system imbalances, will 
facilitate the trading of imbalances and capacity, or other self-help 
measures, that in turn could alleviate or prevent conditions that 
imperil system integrity.
    Under the regulations adopted in this rule, pipelines will only be 
able to impose penalties to the extent necessary. This requirement may 
result in either no penalties for non-critical days or higher 
tolerances and lower penalties for non-critical as opposed to critical 
days. To the extent that pipelines generally justify the imposition of 
penalties for non-critical days, the pipeline should not impose such 
penalties on shippers where the existing metering equipment does not

[[Page 10203]]

provide the shipper with sufficiently accurate information about its 
imbalance status so that the shipper can take actions to avoid the 
penalty. During non-critical periods, to the extent a pipeline can 
justify having a penalty at all, the pipeline will only be allowed to 
impose penalties in time frames comparable to the information it 
collects and disseminates to shippers, and for which reasonable notice 
and opportunity to cure overruns and imbalances is given. For example, 
if shippers are given information about their overrun and imbalance 
status on a daily basis, daily tolerances and penalties may be adopted. 
However, if shippers are given this information only on a monthly 
basis, only monthly penalties may be imposed. This approach will 
provide the pipeline with the appropriate incentive to install upgraded 
metering equipment if controlling imbalances at the point in question 
is important to the operation of its system.
    During critical operating periods, however, the Commission will 
still permit pipelines to impose penalties on shippers when real-time 
metering, and/or timely reporting of shippers' imbalance status is not 
available. The need to maintain system integrity during critical days 
is of sufficient importance that the Commission does not want to limit 
the pipelines' ability to deter conduct that may be harmful to other 
shippers even if it cannot provide current information.
    The Commission proposed this restriction as one of two options for 
addressing situations where, at particular receipt or delivery points, 
the pipeline might not have the type of metering and related equipment 
that would provide the shipper with timely information on its 
deliveries and imbalances. A number of commenters supported this 
option.\205\ The other option presented in the NOPR was to require the 
pipeline to install equipment sufficient to provide shippers at those 
points with timely information on imbalances and deliveries. Many 
commenters opposed that option because it raises difficult issues, such 
as who should pay the costs of purchasing and installing the equipment. 
Requiring the pipeline to install adequate metering equipment at those 
points is inconsistent with the Commission's determination not to 
require upgraded metering equipment at all points. The Commission is 
not adopting this option.
---------------------------------------------------------------------------

    \205\ Comments of Florida DMS, Louisville, NGSA, Process Gas 
Consumers, and TransCanada.
---------------------------------------------------------------------------

    While a significant percentage of the commenters support requiring 
pipelines to provide, on a timely basis, as much information as 
possible on imbalances and overrun status of each shipper, and system 
imbalance status,\206\ several commenters object to the Commission's 
requiring pipelines to provide ``as much information as possible.'' 
National Fuel argues that this standard is nebulous, and is likely to 
result in the posting of much useless information. National Fuel 
requests that the Commission modify the proposed policy to require that 
pipelines ``provide, on a timely basis, a quantification of the 
imbalance and overrun status of each shipper and the imbalance of the 
pipeline's system.'' \207\ Williston Basin maintains that the 
Commission should not require pipelines to provide as much volume 
information as possible, but should require pipelines to provide 
appropriate volume information on a net benefit basis and the relevance 
of the volume information to the specific pipeline and its 
shippers.\208\ Consolidated Natural states that the language of the new 
provisions suggests that a pipeline must have real time measurement 
equipment in place.\209\ It asserts that pipelines' existing business, 
measurement and computer systems cannot manage the calculation of more 
detailed or more timely information.
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    \206\ Comments of AlliedSignal, Florida Cities,NEMA, NGSA, 
Paiute, Process Gas Consumers, PUC of Ohio, Dynegy, and PSC of 
Wisconsin.
    \207\ Comments of National Fuel at 5.
    \208\ Comments of Williston Basin at 35.
    \209\ Comments of Consolidated Natural at 25-26.
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    The Commission is requiring the provision of only as much 
information as the pipelines already have available on shippers' 
imbalance and overrun status, and on system imbalance status. The 
Commission reiterates that it is not requiring that pipelines upgrade 
their existing business, measurement, and computer systems to provide 
this information. Also, the Commission does not wish to limit this 
information to a quantification of the shippers' imbalance and overrun 
status, and system imbalance status. There may be other information 
about imbalances, particularly with respect to system imbalances, that 
pipelines have available that could aid shippers in planning their 
actions and avoiding imbalances and penalties.
    Atlanta, also, has a concern with the Commission's requirement that 
pipelines provide timely imbalance information.\210\ Atlanta asserts 
that increasing the amount of information available to shippers will 
not be sufficient to prevent shippers from incurring imbalances unless 
shippers have the appropriate incentives to avoid imbalances. Atlanta 
believes that shippers currently have the ability to control their 
imbalance activity, but choose not to because they find it economically 
beneficial to game the system. Atlanta supports requiring pipelines to 
provide as much information as possible, but only in conjunction with 
the provision of incentives for shippers to remain in balance. Further, 
Atlanta maintains that forbidding pipelines to impose imbalance 
penalties during non-critical periods where the pipeline has failed to 
notify the shipper of the imbalance situation will exacerbate the 
imbalance problem by removing disincentives for shippers to incur 
imbalances.
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    \210\ Comments of Atlanta at 17-18.
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    The Commission agrees with Atlanta that the existence of proper 
incentives for shippers to avoid imbalances is of paramount importance. 
The policy being adopted here, focused on avoiding penalties and 
reducing the need for penalties, is intended precisely to promote such 
incentives. The measures the Commission is taking here are designed to 
move the pipeline away from the use of negative incentives--penalties 
and OFOs--to the use of positive incentives to control shipper 
behavior. It is up to the pipeline to develop such positive incentives. 
However, the Commission's actions here are laying the groundwork for, 
and will facilitate, the pipelines' efforts in this direction. For 
example, by requiring pipelines to offer imbalance management services, 
the Commission is prompting pipelines to become creative in developing 
such services that may not only make it easier for pipelines to avoid 
imbalances, but may also provide built-in incentives for shippers to 
stay in balance. Also, the provision of timely information of shipper 
and system imbalance status, together with the pipeline's ability to 
establish appropriate imbalance penalties, should in and of itself 
produce good incentives for shippers to stay in balance.
    The Commission does not agree with Atlanta, however, that 
forbidding pipelines from imposing non-critical day penalties where the 
pipeline has failed to notify the shipper of the imbalance strips away 
shipper incentives to comply with tariff requirements. To the extent 
that pipelines continue to use a negative incentive, such as a penalty, 
to encourage shippers to remain in balance and deter behavior, it is a 
matter of basic fairness that the pipeline give notice of the imbalance 
situation and the opportunity to cure the imbalance prior

[[Page 10204]]

to imposing a penalty that is not critical to operations.
2. Future Consideration of Penalty and OFO Issues
    The Commission is adopting the general policies set forth above as 
an initial step toward increasing shipper flexibility to avoid 
penalties, and minimizing the need to impose penalties. However, in the 
NOPR, the Commission sought comment on a variety of options for 
implementing and expanding these general policies. For example, the 
Commission requested comment on whether more appropriate penalties 
might result from establishing uniform penalties and OFOs across 
pipelines on a national or regional basis, revising pipelines' cash-out 
procedures, or establishing a ``no-harm, no-foul'' policy that would 
permit beneficial imbalances to escape penalties. The comments to the 
NOPR produced no strong consensus on most of the specific options that 
the Commission presented for implementing and expanding the general 
policies.
    As a result, while it is appropriate to take a modest step toward 
remedying the inefficiencies caused by penalties and OFOs through the 
adoption of the general policies, it is premature, without additional 
study and examination of the market, to undertake the more ambitious 
policies presented as options in the NOPR, or many of the detailed 
suggestions for a revised Commission policy on penalties that the 
commenters presented.\211\ The Commission recognizes that they may hold 
promise for the future. Thus, the Commission will continue to monitor 
the natural gas market and the role penalties play in that market, as 
the industry responds to the initial changes being adopted in this 
final rule to the Commission's penalty and other policies, and to the 
GISB standards for imbalance management recently put into place. In the 
event that the inefficiencies associated with penalties and OFOs 
persist, the Commission will revisit whether the more comprehensive and 
innovative policy changes are necessary.
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    \211\ Comments of AF&PA, Amoco, Dynegy, Process Gas Consumers, 
and Exxon.
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    To facilitate the Commission's consideration of additional, more 
significant changes in the Commission's penalty policy, if necessary 
after some experience under the rules adopted here, the Commission or 
its Staff may convene an industry-wide conference to examine the need 
for further generic reform of the industry's penalty standards. Such a 
conference would explore whether there are commodity arbitrage problems 
on individual systems and gaming across pipelines and LDCs due to 
different penalty levels, and whether it is feasible to set penalties 
and OFO standards on a regional or national basis.

IV. Reporting Requirements for Interstate Pipelines

    The free flow of information regarding the natural gas market is 
critical to the successful creation of a competitive and efficient 
marketplace. Access to relevant information is necessary for shippers 
to make informed decisions about capacity purchases, and for the 
Commission and shippers to monitor transactions to determine if market 
power is being exercised. Also, as competition is improved in the 
natural gas marketplace by the changes the Commission is making in this 
final rule, the ready availability of information will become 
increasingly important, both for efficient trading and for the 
monitoring for the exercise of market power.
    The market needs several different types of information, both for 
decision-making and monitoring purposes: information on capacity 
transactions, such as rates, contract duration, and contract terms; 
information on the structure of the market; and information on capacity 
availability. Transactional information provides price transparency so 
shippers can make informed purchasing decisions, and also permits both 
shippers and the Commission to monitor actual transactions for evidence 
of the possible abuse of market power. Information on market structure 
enables shippers and the Commission to know who holds or controls 
capacity on each portion of the pipeline system, so the potential 
sources of capacity can be determined. Information on the amount of 
capacity available at receipt and delivery points and on mainline 
segments, as well as on the daily amount of capacity that pipelines 
schedule at these points, helps shippers structure gas transactions and 
casts light on whether shippers or the pipeline may be withholding 
capacity.
    The Commission's current regulations already require the reporting 
and maintenance of much of the necessary information.\212\ However, the 
information required by the existing regulations gives market 
participants and the Commission an uneven picture of the market because 
the reporting requirements are different for competing types of 
capacity, both in terms of the content of the information and the 
formats used to report the information. For instance, pipelines are 
required to post detailed information on capacity release transactions, 
including the releasing and replacement shipper names, the rate paid, 
and points covered by the release, when the transactions occur.\213\ In 
contrast, pipelines are only required to file limited information on 
their discount transactions well after the transaction has taken 
place.\214\ In addition, some information needed to enable shippers to 
effectively make capacity decisions and monitor the market is not 
currently required by the existing regulations, such as certain point-
specific data.
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    \212\ Information is currently provided through a variety of 
formats: the capacity release reporting standards 
(Sec. 284.10(b)(1)(v), Capacity Release Related Standards 5.4.1, 
5.4.3), the Index of Customers Sec. 284.106(c)), the discount report 
(Sec. 284.7(c)(6)), and the maintenance requirement for discount 
information (Sec. 250.16(d)).
    \213\ 18 CFR 284.10(b)(1)(v), Capacity Release Related Standards 
5.4.1, 5.4.3.
    \214\ 18 CFR 284.7(c)(6).
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    Therefore, the Commission is revising its reporting requirements in 
a few main respects to improve the availability and usefulness of the 
information currently reported. First, the Commission is changing and 
consolidating the reporting formats in which it collects the 
information, including the time frames within which information is 
reported, to enable the Commission to equalize the reporting 
requirements for capacity release transactions and pipeline 
transactions, and to simplify the overall reporting system. The new 
reporting system reduces the amount of periodic reporting to the 
Commission currently required, and instead relies on Internet posting 
and maintenance of information. Second, the Commission is adding 
certain data to the information that is already collected on pipeline 
transactions, the structure of the market, and capacity availability in 
various reporting formats. Specifically, the most significant 
additional information being required here is receipt and delivery 
point data in the report on pipeline transactions and the Index of 
Customers, certain organizational and personnel information on 
affiliates, and information on design and scheduled capacity and 
service outages. Third, the Commission is reorganizing its regulations 
to consolidate all of the existing and new Part 284 reporting 
requirements into a single, new Sec. 284.13 governing open-access 
reporting requirements for interstate pipelines.
    Under the new requirements, as detailed below, pipelines will be 
required to provide transactional information, information regarding 
capacity and service outages, an index of firm transportation 
customers, and information concerning marketing

[[Page 10205]]

affiliates, most of which is already reported or maintained.\215\

    \215\ As a result of consolidating the reporting requirements 
into one place in the regulations, Sec. 284.13 also includes the 
annual report on peak day capacity and storage capacity, and the 
semi-annual storage report, which are filed with the Commission. The 
Commission is not changing these regulations in this rule.
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     The transactional information on firm and interruptible 
transportation will be provided by posting the information on the 
pipelines' Internet web sites and through downloadable files. The 
transactional information on firm transportation, whether provided 
by the pipeline or through capacity release, is to be reported 
contemporaneously with the transaction. The information on 
interruptible transportation will be provided daily.
     The capacity information will provide information on 
available, scheduled, and design capacity and service outages 
through posting on the pipelines' web site and through downloadable 
files. The information on available and scheduled capacity will be 
posted daily. Information on design capacity will be posted one time 
(and thereafter maintained on the web site), and then updated as 
necessary. Service outages will be posted when required.
     The Index of Customers will be provided through a 
quarterly filing with the Commission, as well as by posting the 
information quarterly on the pipelines' Internet web sites.
     The affiliate information will be posted on the 
pipelines' Internet web sites, and will be updated within three days 
of changes in the information.

A. Transactional Information

    To assure parity of the transactional information that is reported 
for capacity release transactions and for pipeline transactions, the 
Commission is requiring that pipelines provide the same information 
about their firm and interruptible transactions as is currently 
reported about capacity release transactions, in the same format. 
Therefore, the Commission is adding a new Sec. 284.13(b) that will 
require pipelines to post on their Internet web site, and provide 
downloadable files of, transactional information about their own 
capacity transactions and released capacity transactions.\216\ 
Pipelines will be required to keep the firm and interruptible 
transactional information, described below, available on their web 
sites for 90 days. In accordance with the Commission's existing 
regulations, pipelines will also have to archive this information after 
the 90-day period expires, maintaining the information for a period of 
three years.\217\
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    \216\ While new Sec. 284.13(b) enumerates information the 
Commission needs for firm and capacity release transactions, it does 
not replace the existing GISB capacity release data set.
    \217\ Section 284.10(c)(3)(v), redesignated as 
Sec. 284.12(c)(3)(v).
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    Specifically, for firm service, pipelines will be required to post 
the following information, contemporaneously with the execution of the 
contract: the names of the parties to the contract; an identification 
number for each shipper, such as a DUNS number; the contract number for 
the shipper receiving service and for the releasing shipper; the rate 
charged under each contract and the maximum rate, if applicable; the 
duration of the contract; the receipt and delivery points and zones or 
segments covered by the contract, as well as the common transaction 
point codes; the contract quantity, or volumetric quantity under a 
volumetric release; special terms and conditions applicable to a 
capacity release and special details pertaining to a pipeline 
transportation contract; \218\ and any affiliate relationship between 
the pipeline and the shipper or between the releasing and replacement 
shipper.
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    \218\ Under this requirement, a pipeline must report any special 
conditions attached to a discounted transportation contract, such as 
requirements for volume commitments to obtain the discount.
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    For interruptible transportation, the pipeline will be required to 
post the following information on a daily basis: The name of the 
shipper; a shipper identification number; the rate charged and maximum 
rate, if applicable; the receipt and delivery points and zones or 
segments over which the shipper is entitled to nominate gas, as well as 
the common transaction point codes; the quantity of gas the shipper is 
entitled to nominate; special details pertaining to a pipeline 
transportation contract; and any affiliate relationship between the 
shipper and the pipeline.
    The Commission is also eliminating the separate discount report 
previously required by Sec. 284.7(c)(6). It will no longer be required, 
since the same information will be reported under the reports on firm 
and interruptible transactions in new Sec. 284.13(b). However, 
pipelines will be required to continue to file discount reports until 
September 1, 2000, when they are required to comply with the new 
reporting requirements.
    Pipelines already provide, via the Internet, virtually all of the 
above transactional information for capacity release transactions, at 
the time of the transaction.\219\ However, under the current 
regulations, pipelines are required to provide limited transactional 
information for their own capacity transactions, and the information 
that is required is neither as timely nor as easy to access as the 
capacity release information. Currently, pipelines must file discount 
reports, which require only some information on firm and interruptible 
transactions at less than the maximum rate--the name of the shipper, 
the maximum rate, the rate actually charged, and any corporate 
affiliation between the pipeline and the shipper.\220\ The discount 
report does not include any information on volumes, the receipt and 
delivery points for the transaction, or the duration of the contract. 
And, the discount report is filed, but not posted electronically, 15 
days after the close of the billing period applicable to the 
transaction. Thus, the information provided in the discount report is 
limited in nature, is provided well after the transaction has taken 
place, and is filed with the Commission, rather than posted on the 
pipeline's EBB or on the Internet.
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    \219\ 18 CFR 284.10(b)(1)(v), Capacity Release Related Standards 
5.4.1, 5.4.3. The only exceptions are that some pipelines are not 
required to report whether a capacity release transaction is between 
a releasing shipper and an affiliate, and contract numbers are not 
required to be reported.
    \220\ 18 CFR 284.7(c)(6).
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    Some information regarding firm transactions is available in the 
Index of Customers, which requires that pipelines file the following 
information electronically with the Commission and on the pipelines' 
EBBs for each customer receiving firm transportation or storage 
service: the customer name, the amount of capacity held, the duration 
of the contract, and the applicable rate schedule.\221\ However, the 
Index of Customers cannot truly be considered a transactional report, 
since it does not provide any price information or information on the 
capacity path held by the shipper. Therefore, it is of limited use in 
monitoring transactions for discrimination. In addition, the Index of 
Customers is only filed quarterly, and therefore reflects only those 
shippers that have contracts with the pipeline on the quarterly filing 
day. As a result, it is inadequate to capture shipper and contract 
information for short-term firm contracts that may begin and end within 
a quarterly filing period.
---------------------------------------------------------------------------

    \221\ 18 CFR 284.106(c)(3).
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    Thus, the discount report only provides some after-the-fact 
information regarding transactions at less than the maximum rate, the 
Index of Customers only provides some quarterly information regarding 
firm contracts, and neither reporting requirement provides any 
transactional information with respect to interruptible transactions at 
the maximum rate. Consequently, the content and reporting formats of 
the existing reporting requirements for pipeline transactions are 
inadequate to give shippers and the

[[Page 10206]]

Commission a real-time snapshot of what price capacity sold for on a 
particular day. The pipeline data and reporting formats are not 
comparable to the existing reporting requirements for capacity release 
transactions. The reporting of the same information required to be 
provided in the capacity release reports, in the same format, is 
necessary with respect to pipeline transactions for shippers to have a 
complete and comprehensive view of the market.
    The transactional reporting requirements the Commission is adopting 
here are generally the same reporting requirements proposed in the 
NOPR, with a few minor modifications. The Commission is adding to the 
firm and interruptible transactional reports proposed in the NOPR the 
maximum rate under each pipeline contract, to enable the magnitude of 
any discounts to be known, since the existing discount report is now 
subsumed within the reports on firm and interruptible transactions. In 
addition, the Commission is adding to the transactional reporting 
requirements an individual shipper identification number, such as a 
DUNS number, to the extent one exists for a particular shipper, so that 
it will be easier to link together, or match-up, customer-specific data 
from different reports. The Commission is also adding the common point 
codes for the receipt and delivery points. The Commission has 
previously adopted the consensus recommendation of GISB that pipelines 
use common transaction point codes.\222\
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    \222\ See redesignated 18 CFR 284.12(b)(1)(v) Capacity Release 
Related Standards (Version 1.3), Firm Transportation and Storage-
Award Notice, tab 8, at 2, tab 8 EDI, at 17-18. Under this 
provision, however, a pipeline can use a propriety code if no common 
transaction point code exists, but will have two months within which 
to obtain a common code for that point.
---------------------------------------------------------------------------

    Many commenters support the reporting requirements the Commission 
proposed in the NOPR and is adopting in this rule.\223\ Some commenters 
even advocate that the Commission should impose greater reporting 
requirements than those proposed in the NOPR.\224\ Other commenters, 
though, object to the Commission requiring pipelines to disclose 
specific information about pipeline transactions on confidentiality 
grounds.\225\ They argue that such information, particularly customer 
names, receipt and delivery points, and contract numbers, is 
commercially sensitive information, which, if disclosed 
contemporaneously with the transaction, will cause shippers competitive 
harm.
---------------------------------------------------------------------------

    \223\ E.g., Comments of AEC, AF&PA, AGA, Amoco, CPUC, Duke 
Energy, Enron Capital, Florida Cities, Florida DMS, Industrials, 
Louisville, NEMA, Penn. PUC, Proliance, PSC or Kentucky, PUC of 
Ohio, Soutehrn Co. Services, WGL, and Wisconsin Distributors.
    \224\ Comments of Amoco, Indicated Shippers, New England, 
Southern Company Services, TransCanada, WGL, and Wisconsin 
Distributors.
    \225\ Comments of Coastal, Dynegy, Duke, Process Gas Consumers, 
NICOR, PUC of Ohio, Sithe, Tejas, Williams, and Williston Basin.
---------------------------------------------------------------------------

    For instance, Dynegy argues that disclosure of individual contract 
numbers and receipt and delivery points will make it easy for shippers 
to track the chain of title to determine where other shippers' supply 
came from and where it will end up. Dynegy states that knowledge of 
this information, together with the rates paid for the transportation, 
will allow shippers to undercut or steal other shippers' 
transactions.\226\ Dynegy does indicate, however, that it might not 
object to the release of such information to only the Commission, with 
appropriate confidentiality protection. Dynegy further maintains that 
it does not object to the disclosure of this information with respect 
to pipelines' transactions with their affiliates because there is an 
overriding need for pipelines to report such information for their 
marketing affiliates that outweighs concerns about commercial 
sensitivity.\227\
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    \226\ Comments of Dynegy at 14-15.
    \227\ Comments of Dynegy at 8 and 14.
---------------------------------------------------------------------------

    Similarly, Duke asserts that there is no need to identify specific 
shipper's nominated capacity at each point because such information 
would give shippers knowledge of their competitor's general marketing 
strategy and allow shippers to deduce the identity of the markets 
themselves. Duke states that the identity of the shipper should be 
redacted from postings.\228\
---------------------------------------------------------------------------

    \228\ Comments of Duke at 7.
---------------------------------------------------------------------------

    Some commenters maintain that requiring pipelines to report the 
additional transactional information may have the unintended effect of 
increasing bundled sales activity.\229\ They state that because many 
shippers do not want to have the details of their transactions 
disclosed, they currently avoid capacity release transactions in favor 
of bundled sales transactions. Thus, the commenters argue that a policy 
of immediate disclosure of transactional information for pipeline 
transactions will cause even greater bundled sales transactions, and 
thereby frustrate the Commission's goal of increased market 
transparency.
---------------------------------------------------------------------------

    \229\ Comments of Coastal 93-94 and PUC of Ohio at 8. The 
comments of the PUC of Ohio on this point are limited to the 
disclosure of the transacting parties' identities.
---------------------------------------------------------------------------

    In addition, the opposing commenters request that if the Commission 
decides to require public disclosure of the transactional information, 
at a minimum, it should not require the immediate disclosure of the 
information, but should revise the timing of the reporting 
requirement.\230\ They request that the reporting of the information, 
particularly the identity of the shipper, be delayed, so pipelines and 
shippers are not given an opportunity to use such information to gain a 
competitive advantage. They suggest delays ranging from 30 days after 
the transaction, to six months after service under the contract begins.
---------------------------------------------------------------------------

    \230\ See Comments of Dynegy at 16, NICOR, at 21, and 
Industrials at 89.
---------------------------------------------------------------------------

    The Commission finds that the disclosure of detailed transactional 
information is necessary to provide shippers with the price 
transparency they need to make informed decisions, and the ability to 
monitor transactions for undue discrimination and preference. Shippers 
need to know the price paid for capacity over a particular path to 
enable them to decide, for instance, how much to offer for the specific 
capacity they seek. While the Commission acknowledges that the 
disclosure of shipper names is not necessary for this type of 
decisionmaking and price transparency, the disclosure of the identity 
of the shipper in each transaction, together with the price and 
capacity path information on each shipper's transaction, is necessary 
to enable shippers and the Commission to effectively monitor for 
potential undue discrimination or undue preference. The disclosure of 
all of the transactional information without the shipper's name will be 
inadequate for other shippers to determine whether they are similarly 
situated to the transacting shipper for purposes of revealing undue 
discrimination or preference. For example, the disclosure of the name 
of the shipper in the transaction may help other shippers to determine 
whether a transacting shipper may be entitled to a discount because it 
is fuel-switchable. In addition, the disclosure of the identity of 
shippers in the transactional reports enables shippers and the 
Commission to determine how much total firm capacity (both pipeline 
capacity and released capacity) a shipper holds on each individual 
pipeline, as well as on connecting pipelines. Such information is 
important for examining market power

[[Page 10207]]

and whether a shipper has sufficient market presence to unduly 
discriminate.
    Moreover, the general regulatory scheme of section 4 of the Natural 
Gas Act is based on the public disclosure of all prices and 
contracts.\231\ Thus, the posting of customer-specific information in 
the transactional reports being required here is consistent with this 
statutory framework. In addition, in requiring the shipper identity to 
be disclosed, the Commission is not changing or reversing its treatment 
of shipper names in the reporting requirements. The names of shippers 
are currently required to be posted for capacity release transactions 
and for discount transactions in the discount reports.
---------------------------------------------------------------------------

    \231\ 15 U.S.C. 717(c).
---------------------------------------------------------------------------

    Finally, to be meaningful for decisionmaking purposes, the 
transactional information must be reported at the time of the actual 
transaction. A delayed reporting of the information 30 days or more 
after the transaction has occurred, as some commenters suggest, will 
not be timely enough to enable shippers to use the information on a 
day-to-day basis to make purchasing decisions. At that point, the 
information is historical, and is of no value for current 
decisionmaking. In other words, the knowledge of what capacity sold for 
what price 30 days earlier would not aid shippers in making a current 
capacity decision. Some commenters advocate a delayed posting of the 
shippers' names only. The Commission acknowledges that immediate 
disclosure of shippers' names is not necessary for the Commission and 
other shippers to monitor for undue discrimination and preference. A 
delayed posting of the shipper names would suffice for the monitoring 
purpose for which the names are needed. However, a requirement that 
pipelines report different transactional information at different times 
is likely to be impracticable to implement, creating a burden that 
outweighs the need for confidentiality. Because it is necessary for all 
of the other transactional information to be posted at the time of the 
transaction, the Commission will require the identity of the shipper 
for each transaction also to be disclosed at the time of the 
transaction.
    Commenters also have concerns regarding the burden that the 
Commission's revised transactional reporting requirements will place on 
pipelines.\232\ For example, some commenters contend that requiring 
pipelines to post information on interruptible transactions on a daily 
basis is too burdensome.\233\ Williston Basin states that requiring 
these data on a daily basis is akin to uploading each pipeline's daily 
interruptible nominations (including all intraday cycles) on its 
Internet web site every day.\234\ It asserts that a pipeline's single 
timely nomination cycle can be thousands of records long, and that 
multiplying this by the intraday cycles day after day will prove to be 
an enormous amount of data. PSC of New York states that it may be 
impossible or impractical to post interruptible transactions before gas 
flows. PSC of New York suggests that the posting of interruptible 
transactions should be required as soon as possible after gas 
flows.\235\ In contrast, Amoco argues that the Commission should 
require the posting of all interruptible transactions contemporaneous 
with the execution of the contract.
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    \232\ Comments of AGA, Koch, MichCon, Tejas, and Williston 
Basin.
    \233\ Comments of Williston Basin and PSC of New York I.
    \234\ Comments of Williston Basin at 32.
    \235\ Comments of PSC of New York I at 14-15.
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    The Commission does not expect that the burden of complying with 
the transactional reporting requirements will be great. Most of the 
information required for the pipeline's transactional report on firm 
and interruptible service is already required to be reported or 
maintained under existing requirements, such as the Index of Customers, 
the discount report, or the affiliate discount information maintenance 
requirement in Sec. 250.16(d) of the Commission's regulations, albeit 
separately, and in different formats.\236\ Thus, the burden will not be 
in collecting or gathering the data, but will largely be in creating 
the new formats for displaying the information on the pipelines' 
Internet web sites. Pipelines may, however, be able to adapt their 
already existing capacity release data sets to apply to pipeline 
transactions without much difficulty. Moreover, the Commission is 
reducing the periodic reporting currently required under the 
regulations by eliminating the monthly discount report.
---------------------------------------------------------------------------

    \236\ The only true gap in the information currently reported is 
information on interruptible transactions at the maximum rate, since 
the discount reporting requirements, by definition, do not apply to 
maximum rate transactions.
---------------------------------------------------------------------------

    While the Commission is requiring that some new data, not required 
in existing reports, be posted on firm and interruptible transactions, 
it is not an extensive amount of information compared to what is 
already provided. For the firm transactional report, the Commission is 
adding the receipt and delivery points and the zones or segments under 
the contract, the common transaction point codes, the contract number, 
a shipper identification number, and special terms and conditions 
applicable to a capacity release and special details pertaining to a 
pipeline transportation contract. Similarly, for the interruptible 
transactional report, the Commission is adding the receipt and delivery 
points and zones or segments, the common transaction point codes, the 
contract quantity, a shipper identification number, and special details 
pertaining to a pipeline transportation contract. Further, these 
additional data are information that pipelines use in the course of 
their daily business activities, and thus, have in their possession, so 
that pipelines should not encounter great difficulty in assembling the 
information. Again, for pipelines to comply with the new reporting 
requirements, their task will be to develop a method for displaying the 
information on the web sites.
    The Commission recognizes that the quantity of data to be posted on 
interruptible transactions could be voluminous for some pipelines. 
However, in order for shippers to have a true understanding of pricing 
in the marketplace, they must know what prices are being paid for 
interruptible transportation service and when such interruptible prices 
change. The existing discount report for interruptible transactions at 
less than the maximum rate is inadequate because it provides only a 
monthly average of the price paid. Since the prices for interruptible 
service can change daily, it is necessary for the pipeline to post 
interruptible transactions on a daily basis. In addition, the 
Commission emphasizes that the Commission is requiring the posting of 
these data once daily, not contemporaneously with the execution of each 
contract.

B. Information on Market Structure

    To provide shippers with a more useful picture of the structure of 
the market for both decisionmaking purposes and monitoring purposes, 
The Commission is expanding two of its reporting requirement 
regulations: the Index of Customers and the affiliate regulations.

1. Index of Customers

    Pipelines currently file with the Commission, and post on their 
Internet web sites, on the first business day of each calendar quarter, 
an Index of Customers under existing Sec. 284.106(c)(3) of the 
regulations, which provides the names of shippers holding

[[Page 10208]]

firm capacity, the amount of capacity they hold, the applicable rate 
schedule, and the contract effective and expiration dates. The 
Commission is adding the following new information requirements to the 
Index of Customers, which is now Sec. 284.13(c): The receipt and 
delivery points held under the contract and the zones or segments in 
which the capacity is held; the common transaction point codes; the 
contract number; a shipper identification number, such as DUNS; an 
indication whether the contract includes negotiated rates; the names of 
any agents or asset managers that control capacity in a pipeline rate 
zone; and any affiliate relationship between the pipeline and the 
holder of capacity.
    The Commission is requiring that pipelines report the receipt and 
delivery points and zones or segments in which the capacity is held so 
that the capacity path held by the shipper can be traced, and the data 
can be used to determine which shippers can compete in providing 
capacity on segments of the pipeline. The contract number and shipper 
identification number are needed on the Index of Customers, as well as 
on the report of capacity release transactions, so capacity can be 
traced through release transactions to reveal how much total capacity 
each shipper holds. In addition, in the current market, shippers may be 
using agents or asset managers to manage their capacity, and such 
managers may be given wide latitude over the way in which capacity is 
used. Requiring that pipelines disclose the names of the agents or 
asset managers will help to show the degree of control over pipeline 
capacity that an agent or asset manager may exercise. This will aid in 
the detection of potentially anticompetitive market dominance. Finally, 
to permit effective monitoring of the capacity held on pipelines, it is 
necessary to know any affiliate relationship between the pipeline and a 
shipper or a shipper's agent or asset manager in order to determine the 
total amount of capacity held by the parent entity.
    The information in the Index of Customers that the Commission is 
requiring in this rule is different from the information that the 
Commission proposed in the NOPR to include in the Index of Customers. 
Essentially, as described below, the Commission is requiring less 
information with respect to agency and affiliate relationships to be 
reported than the Commission proposed to require in the NOPR.
    In the NOPR, the Commission proposed to require pipelines to report 
for each customer the names of any agents or asset managers that 
control 20 percent or more of capacity in a pipeline rate zone, as well 
as the rights of the agent or asset manager with respect to managing 
the transportation service. Several commenters objected to this 
reporting requirement.\237\
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    \237\ Comments of Dynegy, WGL, and Coastal.
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    Dynegy indicates that it holds a number of agency arrangements with 
pipeline customers under which it sometimes provides an array of 
services, and which its competitors would want to replicate. Dynegy 
argues that if the breadth and depth of agency relationships are 
disclosed, an agent will be stripped of any competitive advantage it 
has gained through experience and commercial expertise.\238\ Dynegy 
also contends that to the extent that the market would learn of an 
agency relationship, the ability of that agent or asset manager to act 
on behalf of a large shipper without moving the market would be 
significant reduced.
---------------------------------------------------------------------------

    \238\ Comments of Dynegy at 13.
---------------------------------------------------------------------------

    WGL, in its comments, states that it is unclear what purpose is 
served by this reporting requirement.\239\ WGL believes that if the 
information disclosed is limited to the details of operational rights, 
the release of such information may not be objectionable. However, WGL 
contends that contracts between the shipper and the agent/asset manager 
may contain sensitive commercial information, and in many cases where 
the shipper is an LDC, such agreement is subject to local regulatory 
review. Coastal requests that the Commission limit the scope of this 
requirement to the disclosure of only the existence of an agent or 
asset manager, when known by the pipeline, not the rights of the agent 
or asset manager, which may be impossible for the pipeline to 
track.\240\
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    \239\ Comments of WGL at 15.
    \240\ Comments of Coastal at 94.
---------------------------------------------------------------------------

    The Commission finds that asset manager reporting is needed to 
reveal potentially unhealthy market dominance by an asset manager that 
would not otherwise be apparent. However, the reporting of only the 
names of any asset manager or agent, without including the details of 
the asset manager/agency relationships, will be adequate for this 
purpose. Thus, the Commission is requiring pipelines to report the 
names of asset managers or agents, but not the agent's/asset manager's 
rights with respect to managing the transportation service. However, 
the Commission will require that all asset managers or agents be 
identified, not just those that manage 20 percent of more of the 
transportation service in a pipeline rate zone. The determination of 
which asset managers and agents meet this 20 percent threshold 
requirement may be too difficult to make in many instances. In 
addition, the Commission disagrees with Dynegy that reporting the names 
of asset managers or agents of customers will somehow reveal the 
identity of the particular customer the asset manager or agent is 
acting on behalf of during contract negotiations. Since the asset 
manager or agent presumably would have several clients, the market 
would not know which client a given gas purchase would be for. There is 
no requirement that the actual capacity transactions arranged by the 
asset manager or agent be reported.
    The Commission is also reducing the information required in the 
Index of Customers with respect to affiliates from what was proposed in 
the NOPR. In the NOPR, the Commission proposed to require that 
pipelines indicate, in the Index of Customers, any affiliate 
relationship between the pipeline and the holder of capacity, and any 
affiliate relationship between holders of capacity.
    Several commenters objected to the requirement that pipelines 
identify affiliate relationships among holders of capacity.\241\ PG&E 
objects to this requirement when such affiliate relationships involve 
third parties unrelated to the pipeline responsible for the 
posting.\242\ PG&E and Williston Basin argue that pipelines do not have 
access to such information, nor the ability to obtain or ensure the 
accuracy of such information. Similarly, National Fuel maintains that 
it may not be practical for a pipeline to identify every affiliate 
relationship between a particular shipper and every other shipper using 
the pipeline's system.\243\ At a minimum, National Fuel argues, this 
requirement should be limited to major holders of capacity--perhaps 
those holding 20 percent of the pipeline's capacity--and that the onus 
should be on the capacity holder to identify whether it is affiliated 
with the pipeline's other shippers. Dynegy, also, asserts that this 
requirement gives pipelines too much discretion to research their 
shipper's transactions.\244\
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    \241\ Comments of PG&E, National Fuel, Dynegy, and Williston 
Basin.
    \242\ Comments of PG&E at 18-19.
    \243\ Comments of National Fuel Gas Supply at 4-5.
    \244\ Comments of Dynegy at 12.
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    As a result of these comments, the Commission has reconsidered its 
proposal to require the reporting of third-party affiliates. The 
Commission agrees with the commenters that it may not be feasible for 
pipelines to

[[Page 10209]]

accurately identify their customers' affiliates. Therefore, the 
Commission is requiring that pipelines identify only their own 
affiliates, and not affiliate relationships among customers.
    Dynegy and others that object to the disclosure of customer names, 
receipt and delivery points and contract numbers required in the 
transactional reports in Sec. 284.13(c) also object to the requirement 
that they be disclosed in the Index of Customers, on the same bases of 
confidentiality and burden. Some commenters argue that the 
transactional reports and the Index of Customers are duplicative.\245\
---------------------------------------------------------------------------

    \245\ E.g., Comments of Williams.
---------------------------------------------------------------------------

    The rationale for including customer names, receipt and delivery 
points and contract numbers in the Index of Customers is essentially 
the same as it is for including such information in the transactional 
reports. The additional information being required in the Index of 
Customers, particularly the receipt and delivery points and zones or 
segments in which capacity is held, which raises the most concern with 
respect to burden for commenters, is necessary for shippers to 
determine who holds capacity, the amount, and where it is held. Such 
information reveals potential sources of capacity for shippers making 
purchase decisions, provides information on market concentration and 
structure, and will permit shippers to better monitor for potential 
undue discrimination or preference. The benefits and importance of 
requiring the posting of the additional data in the Index of Customers 
outweigh the concerns of the commenters about confidentiality, just as 
it does with respect to the transactional reports.
    With respect to the burden of posting the additional information in 
the Index of Customers, some of the additional Index of Customer data--
the affiliate indicator and the delivery points under the contract--are 
already reported or maintained for discounted transactions. Pipelines 
will simply have to add this and the other, new, data (contract number, 
shipper identification number, receipt points, whether the contract 
includes negotiated rates, and the names of any agent/asset manager) to 
the existing data sets for the current Index of Customers. In addition, 
as discussed above, the Commission has reduced the burden that some of 
the informational requirements for the Index of Customers proposed in 
the NOPR would otherwise have place on pipelines (i.e., the 
identification of affiliate and agent/asset manager relationships). In 
sum, the additional reporting burden with respect to the Index of 
Customers should not be too great given that the additional 
information, for the most part, is straightforward information that is 
a part of each shipper's contract.
    Finally, the information required in the Index of Customers is not 
duplicative of the information in the transactional reports. The Index 
of Customers provides a snapshot view of who holds firm capacity on 
each pipeline that otherwise could not be obtained without continuously 
tracking every firm capacity transaction. Conversely, the transactional 
reports are necessary to provide the price information that is not 
included, and would be meaningless to include, in the quarterly Index 
of Customers.
2. Affiliate Regulations
    The Commission is expanding its affiliate regulations to provide 
more information to permit monitoring and self-policing of affiliate 
transactions. The Commission is revising Sec. 161.3(l) of the standards 
of conduct for interstate pipelines to specifically require that 
pipelines with marketing affiliates post certain information concerning 
their affiliates on their Internet web sites, and to update the 
information within three business days of any change.\246\ These 
revisions also will apply to pipelines with sales operating units.\247\ 
Under revised Sec. 161.3(l), the Commission is requiring that pipelines 
post a list of the names of operating personnel and facilities shared 
by the interstate pipeline and its marketing affiliate. The pipelines 
currently provide this information in their tariffs, under 
Sec. 250.16(b)(1); however this new requirement will make such 
affiliate information easily available on the Internet.
---------------------------------------------------------------------------

    \246\ The regulation adopted here incorporates the changes in 
the affiliate regulations made previously in Docket No. RM98-7-000, 
Reporting Interstate Natural Gas Pipeline Marketing Affiliates on 
the Internet, III FERC Stats. & Regs. Regulations Preambles para. 
31,064 (July 30, 1998), 63 FR 43075 (Aug. 12, 1998).
    \247\ 18 CFR 284.286 (c) (requiring pipelines with sales 
operating units to comply with standards of conduct applicable to 
marketing affiliates).
---------------------------------------------------------------------------

    The Commission also is requiring pipelines, under Sec. 161.3(l), to 
post on their Internet web sites comprehensive organizational charts 
that include several types of information, set forth below. The 
Commission has adopted a similar requirement for the posting of 
organizational charts and job descriptions in the electric industry, to 
help monitor and protect against improper communications between 
transmission and wholesale merchant function employees. \248\
---------------------------------------------------------------------------

    \248\ See American Electric Power Service Corporation, 81 FERC 
para. 61,332 (1997), 82 FERC para.Sec. 61,131, order on reh'g, 83 
FERC para. 61,357 (1998).
---------------------------------------------------------------------------

    First, the pipeline must post an organizational chart showing the 
organizational structure of the parent corporation and indicating the 
relative position within the corporate structure of the pipeline and 
all marketing affiliates.
    Second, the pipeline must post an organizational chart showing 
business units, job titles, job descriptions, and chain of command for 
all positions within the pipeline, including officers and directors. 
The pipeline need not include such information for clerical, 
maintenance, and field positions, since employees in those positions 
would not have access to information concerning the processing or 
administration of requests for service. The job titles and descriptions 
must include the employee's title, duties, and an indication whether 
the employee is involved in transportation or gas sales. Employees 
involved in transportation or gas sales include any member of the board 
of directors, officers, managers, supervisors, and regulatory and 
technical personnel with duties involving day-to-day gas purchasing, 
marketing, sales, transportation, operations, dispatching, storage, or 
related activities.\249\ In addition, the pipeline must also include 
the names of supervisory employees who manage non-clerical employees 
involved in transportation or gas sales.
---------------------------------------------------------------------------

    \249\ Order No. 497-E, order on rehearing and extending sunset 
date, 59 FR 243 (January 4, 1994), FERC Stats. & Regs. 1991-1996 
para. 30,958 at 30,996 (December 23, 1993) (defining ``operating 
employee'').
---------------------------------------------------------------------------

    Third, for all employees shared by the pipeline and a marketing 
affiliate, the pipeline must post an organizational chart showing the 
business unit or sub-unit within the marketing affiliate organizational 
structure in which the shared employee is located, the employee's name, 
the employee's job title, and job description within the marketing 
affiliate, and the employee's position within the chain of command of 
the marketing affiliate.
    The reporting requirements being adopted here are essentially the 
same general requirements proposed in the NOPR. However, the Commission 
has decreased the reporting burden that would have been required by the 
NOPR. In the NOPR, the Commission proposed to require pipelines to post 
detailed organizational charts, including detailed employee job 
descriptions, for the pipelines' marketing affiliates. In this

[[Page 10210]]

final rule the Commission is not requiring organizational charts for 
the marketing affiliates, except to the extent that they share 
employees with the pipeline, and the reporting requirement is limited 
to data regarding the shared employee. The Commission is making this 
change to conform the affiliate reporting requirements for pipelines to 
those required for the electric utilities.
    Several commenters fully support the reporting requirements that 
were proposed.\250\ Dynegy maintains that these reporting requirements 
are a valuable tool to police pipeline affiliate activities, as well as 
a resource for contacting employees within a corporation. Several 
commenters also oppose these affiliate reporting requirements, 
particularly the requirement that pipelines post organizational charts 
and employee names.\251\ Williston Basin objects to the posting of 
organizational charts, names, and job descriptions for marketing 
affiliates. Williston Basin argues that the Commission has never before 
imposed a marketing affiliate reporting requirement on pipelines that 
do not conduct business with the marketing affiliate. Williston Basin 
also maintains that requiring the names of pipeline and marketing 
affiliate employees to be posted on the pipeline's web site, even 
though their job requirements do not entail contact with outside 
parties, would violate the personal privacy of those employees.
---------------------------------------------------------------------------

    \250\ Comments of Dynegy, Indicated Shippers, and PUC of Ohio.
    \251\ Comments of Williston Basin, Williams, and Tejas.
---------------------------------------------------------------------------

    Requiring that pipelines post shared personnel, organizational 
charts, job titles and descriptions, and the names of senior employees 
is essential to ensure that pipelines deal fairly with their customers. 
These reporting requirements will act to deter undue discrimination and 
preference, and will permit the market to monitor and self-police 
affiliate transactions.
    In response to Williston Basin, the Commission clarifies that all 
of the marketing affiliate reporting requirements in part 161, 
including the new requirements added here, apply only to pipelines that 
conduct transportation transactions with their marketing or brokering 
affiliates.\252\ Also, as stated above, the Commission is not requiring 
the detailed organizational charts for marketing affiliates, to which 
Williston Basin objects, in all instances. Only where there are shared 
employees between the marketing affiliate and the pipeline is the 
pipeline required to post information regarding the shared employee's 
position within the marketing affiliate. The Commission further 
clarifies that it is requiring posting of the names of only senior 
employees. A pipeline will not be required to post the names of non-
senior employees, so concerns about privacy for lower level employees 
are somewhat misplaced.
---------------------------------------------------------------------------

    \252\ 18 CFR 161.1. However, as provided in Sec. 161.1, the 
marketing affiliate reporting requirements in part 161 apply not 
only to marketing affiliates, but also to pipeline sales operating 
units.
---------------------------------------------------------------------------

C. Information on Available Capacity

    In Sec. 284.8(b)(3) of the Commission's existing regulations, 
pipelines are required to post information about the amount of 
operationally available capacity at receipt and delivery points, on the 
mainline, in storage fields, and whether the capacity is available 
directly from the pipeline or through capacity release.\253\ In new 
Sec. 284.13(d)(1), being adopted here, the Commission is continuing to 
require that pipelines post this information, and is adding the 
following information on capacity availability to the information that 
is already collected: The total design capacity of the point or 
segment; the amount of capacity scheduled at each point on a daily 
basis; and information on planned and actual service outages that would 
reduce the amount of capacity available. The Commission expects that 
the pipelines will provide advance notice of planned outages or service 
disruptions so that shippers can plan for these events.
---------------------------------------------------------------------------

    \253\ 18 CFR 284.8(b)(3); 18 CFR 284.10(b)(1)(iv)(1997), 
Electronic Delivery Mechanism Related Standards 4.3.6; 18 CFR 
284.10(b)(1)(v), Capacity Release Related Standards 5.4.13.
---------------------------------------------------------------------------

    Information on the total design capacity of the point or segment, 
and the amount of capacity scheduled on a daily basis is needed for 
shippers to monitor capacity availability. With respect to the 
information on outages, while some pipelines currently post such 
information on outages, it is not currently a Commission requirement. 
Requiring pipelines to provide information on outages will enable 
shippers to better make decisions about their use of capacity because 
they will know whether the available capacity will be reduced on a 
particular day. Such information will also help in monitoring capacity 
withholding by revealing reasons for reductions in scheduled 
quantities.
    These reporting requirements for available capacity are the same 
reporting requirements proposed in the NOPR. Some commenters, however, 
object to the additional reporting requirements on capacity 
availability,\254\ while others appear to object to the continuation of 
the existing reporting requirements on operationally available 
capacity.\255\
---------------------------------------------------------------------------

    \254\ Comments of Coastal, CMS Pieplines, and Williams.
    \255\ Comments of CNG, and Peoples.
---------------------------------------------------------------------------

    Specifically, several pipelines argue that it will be difficult to 
comply with the additional requirements for posting design and 
scheduled capacity because for some pipeline configurations, and for 
particular pipeline segments, capacity is not fixed, but is dependent 
on operating conditions or operational strategies that may vary 
depending on requests for service. For instance, Coastal states that on 
web-like systems, the design capacity at particular points or segments 
is a function of the usage of other parts of the system, which varies 
constantly, particularly with the implementation of three intraday 
nomination cycles.\256\ CMS Pipelines state that they do not have the 
computer and technology capability to provide the additional capacity 
information in real time. For example, they assert that field outages 
that affect capacity are not conveyed immediately to the EBB. CMS 
Pipelines also add that human intervention, judgment and decisionmaking 
can all affect the determination of available capacity.
---------------------------------------------------------------------------

    \256\ Comments of Coastal at 93.
---------------------------------------------------------------------------

    More generally, CNG asserts that it cannot provide detailed 
information about available capacity over particular paths or segments, 
or in particular storage facilities, and lists a number of variables 
that influence the capacity available at any given moment.\257\ CNG 
argues that because such variables determine the level of available 
capacity at any given time, it is meaningless for pipelines to report 
calculated capacities throughout its system. In addition, some 
commenters appear to suggest that the Commission limit the existing 
reporting of operationally available capacity to key points, such as 
interconnections, market hubs, and points that are frequently 
constrained.\258\
---------------------------------------------------------------------------

    \257\ Comments of CNG at 33-34.
    \258\ Comments of Peoples at 15 and Philadelphia Gas Works at 1.
---------------------------------------------------------------------------

    In contrast, a few commenters argue that the Commission should 
require pipelines to post more information on available capacity than 
was proposed.\259\ For example, Dynegy maintains that shippers need 
information on design capacity, operationally available capacity, and 
actual and maximum flows, not only at all receipt and delivery points 
and on the mainline, but also at each point of

[[Page 10211]]

constraint and segment. Dynegy also asserts that shippers need 
information on unsubscribed capacity and capacity under expiring or 
terminating agreements, and that they need such information at least 18 
months in advance of when the capacity will become available. 
Similarly, Industrials request that the Commission require pipelines to 
post on the Internet detailed, rolling information regarding capacity 
becoming available over the next 18 months. Exxon, also, requests that 
the Commission require the posting of capacity under contracts that are 
due to expire in four months.
---------------------------------------------------------------------------

    \259\ E.g., Comments of Dynegy at 1-7.
---------------------------------------------------------------------------

    Several clarifications of this reporting requirement are needed to 
respond to the commenters' concerns. First, as stated above, the 
Commission's current regulations require pipelines to post 
operationally available capacity at receipt and delivery points, on the 
mainline, and in storage fields.\260\ The Commission did not propose in 
the NOPR to change these requirements, and in this rule is not 
modifying such requirements. Pipelines have been able to comply with 
the regulations requiring the reporting of operationally available 
capacity, and thus, there is no reason to modify such requirements. 
Pipelines must continue to report available capacity as required in the 
Commission's existing regulations, which necessarily involves pipelines 
taking into account operational variables.
---------------------------------------------------------------------------

    \260\ 18 CFR 284.8(b)(3); 18 CFR 284.10(b)(1)(iv)(1997), 
Electronic Delivery Mechanism Related Standards 4.3.6; 18 CFR 
284.10(b)(1)(v), Capacity Release Related Standards 5.4.13.
---------------------------------------------------------------------------

    Second, pipelines have information on the amount of capacity 
scheduled at each point or segment, and, therefore, should be able to 
post that data on a daily basis. In fact, GISB Standard 1.3.2 requires 
pipelines to inform shippers of scheduled quantities. However, the 
Commission is not requiring that pipelines post scheduled capacity at 
all points and segments. If, as some pipelines argue, it is difficult 
for them to provide scheduled capacity on segments of their systems, 
they need only post scheduled capacity for their receipt and delivery 
points. The Commission is requiring the posting of scheduled capacity 
for either receipt and delivery points, or segments, whichever makes 
the most sense for a particular pipeline system.
    Third, the Commission understands that it may be difficult for some 
pipelines to calculate the total design capacity of each point or 
segment on its system, due to operational or usage variables or 
particular system configurations. In those instances, pipelines must 
post design capacities for the most common operating conditions of 
their systems, such as peak period or off-peak period. In addition, the 
Commission clarifies that the posting of the total design capacity of 
the points or segments is not a daily posting requirement. Rather, 
pipelines must update this information from time-to-time as changes in 
design capacity occur.
    Finally, the Commission does not find it necessary to require 
pipelines to provide even more detailed information on design capacity 
and operationally available capacity than the Commission is requiring 
in this rule, or to provide information on the future availability of 
capacity. Currently, shippers can obtain information on firm capacity 
that will be coming available in the future by reviewing the Index of 
Customers, which includes contract expiration dates. With respect to 
requiring more detailed capacity information, including flow data, at 
not just receipt and delivery points, but also at constraint points and 
segments, as Dynegy suggests, the Commission finds that the reporting 
of scheduled capacity at each receipt and delivery point is sufficient, 
and that shippers should be aware of which points or segments are 
constrained.

D. Coordination With GISB Standardization Efforts

    The Commission recognizes that pipelines have just completed 
preparing their systems for the Year 2000 and are in the process of 
making changes to comply with Commission requirements to transfer data 
from Electronic Bulletin Boards to Internet web sites by June 1, 2000. 
The Commission, therefore, will require pipelines to implement the new 
data reporting requirements by September 1, 2000.
    Pipelines are required to provide much of the information in the 
revised reporting requirements by posting the information on their 
Internet web sites and in downloadable file formats. The industry, 
through the Gas Industry Standards Board (GISB), has developed, and is 
in the process of improving, standards for providing currently required 
information both on pipeline web sites and through downloadable file 
formats, using Electronic Data Interchange ASCX12 (EDI) formats.\261\ 
GISB also is examining whether to provide such downloads in flat ASCII 
file formats as well. GISB already has developed standards and the 
pipelines are posting some of the information in the revised 
regulations, such as capacity release information and operationally 
available capacity. Pipelines will continue to post that information 
pursuant to the GISB standards.
---------------------------------------------------------------------------

    \261\ See Standards For Business Practices Of Interstate Natural 
Gas Pipelines, Order No. 587-I, 63 FR 53565, 53569-75 (Oct. 6, 
1998), III FERC Stats. & Regs. Regulations Preambles para. 31,067, 
at 30,737-46 (Sept. 29, 1998).
---------------------------------------------------------------------------

    Ultimately, GISB needs to develop standards for the new reporting 
requirements (including pipeline firm and interruptible transportation 
transactions, design capacity, constraint information, and scheduled 
capacity) both for the presentation of the information on pipeline web 
sites and the provision of the information in Electronic Data 
Interchange ASCX12 (EDI) or ASCII file formats.
    The Commission encourages GISB to try and to complete the process 
of standardization in time for the September 1, 2000 implementation 
date. But the Commission recognizes that such a schedule may be 
ambitious given the other changes to electronic communication GISB is 
now in the process of developing. Because the provision of the new 
information is important both to improve market transparency and for 
monitoring, the Commission will require pipelines to provide this 
information in non-standardized formats in the event GISB is unable to 
develop the datasets in time for September 1, 2000 implementation. 
Pipelines, however, will not have to develop individual EDI file 
formats for the information during the period when GISB is developing 
the standards. Pipelines only will have to post the information on 
their web sites and provide flat ASCII file downloads for the relevant 
information. In addition, the Commission will issue in the near future 
revisions to its instruction for the electronic filing of the Index of 
Customers report to accommodate the new information required by this 
rule.
    The revised reporting requirements also call for the provision of 
both shipper names and a unique numeric identifier for each shipper. 
These requirements apply to both the Internet postings and the 
electronic file downloads. This requirement represents a change from 
the current practice under the GISB standards of providing only numeric 
identification in electronic file downloads. The industry, through 
GISB, has chosen to use the numbers developed by Dun & Bradstreet (D&B) 
as the numeric identifier for shipper names (DUNS numbers). Where 
pipelines use numeric identifiers in electronic communications without 
the accompanying shipper name, the Commission has required pipelines to 
provide a table that cross-references

[[Page 10212]]

shipper names with the applicable DUNS numbers. \262\ GISB has worked 
out an arrangement with D&B to verify the accuracy of the DUNS numbers 
used by pipelines and to post a cross-reference table on the GISB web 
site.
---------------------------------------------------------------------------

    \262\ 18 CFR 284.10(c)(3)(iii) (existing regulations) 18 CFR 
284.13(c)(3)(iii) (revised regulations).
---------------------------------------------------------------------------

    The Commission finds that the use of numeric identifiers for 
shippers is of great value, particularly for electronic processing, 
because electronic identifiers make electronic processing easier and 
eliminate confusion that may be introduced through the use of names 
alone, such as different spellings or abbreviations for the same 
entity. The Commission also appreciates GISB's agreement with DUNs to 
provide for verification of pipeline DUNS numbers, because that 
improves the accuracy of these numbers. The Commission, therefore, is 
requiring that all pipelines which have not yet had their DUNS numbers 
verified by D&B submit their numbers to D&B for verification.
    The Commission, however, is concerned with the current GISB 
standards which require the reporting of DUNS numbers only for 
electronic file downloads and do not contain a field for shipper names. 
While the GISB cross-reference table is extremely useful for 
associating the names and DUNS numbers, the Commission has noticed that 
with respect to almost all pipelines, the cross-reference table 
generally omits a small, but not insignificant, percentage of shippers, 
who are presumably new shippers on the system. One solution for this 
problem would be to require pipelines to make immediate updates to the 
cross-reference table when new shipper names are added. But it would 
appear difficult and burdensome for the pipelines to institute 
procedures to ensure that whenever a new shipper is added to their 
systems, they remember to inform GISB of the addition to the cross-
reference table. The need for such frequent changes also will pose 
administrative burdens for GISB, as well as make Commission monitoring 
of pipeline compliance more burdensome.
    Due to the difficulties and burdens of maintaining an accurate 
cross-reference table, the Commission has determined instead to require 
pipelines to provide both a name and a number in both their Internet 
postings and downloadable files. When GISB next updates its standards 
for electronic file downloads, it needs to include fields so that 
pipelines can include both the shipper name and the DUNS numbers in the 
electronic file. Until those changes occur, the pipelines must continue 
to use the cross-reference table and to update their information on 
that table at monthly intervals.

V. Other Pipeline Service Offerings

    In the NOPR, the Commission sought comment on whether, in light of 
the changes occurring in the natural gas market, the Commission should 
revise or eliminate the right-of-first refusal (ROFR) \263\ and revise 
its current regulations with respect to non-conforming service 
agreements \264\ to permit pre-approval of negotiated terms and 
conditions of service between pipelines and shippers. As discussed 
below, the Commission finds that some narrowing of the ROFR is needed 
so that it interferes as little as possible with the efficiency of the 
market while continuing to protect captive customers. As discussed 
earlier, the Commission has determined that further inquiry into the 
question of pre-approved negotiated terms and conditions is needed. In 
light of the decision not to move forward with pre-approved negotiated 
terms and conditions, the Commission will discuss several aspects of 
this decision, including its policies regarding non-conforming service 
agreements and the interrelation between negotiated terms and 
conditions of service and negotiated rates.
---------------------------------------------------------------------------

    \263\ 18 CFR 284.221(d)(1999).
    \264\ 18 CFR 154.1(d) and 154.112(b)(1999).
---------------------------------------------------------------------------

A. Right of First Refusal

    In the NOPR, the Commission considered whether any changes to the 
right of first refusal and its five-year term matching cap are 
appropriate in light of the changes that have occurred in the 
marketplace since implementation of Order No. 636. Upon consideration 
of the comments, the Commission has decided to retain the right of 
first refusal with the five-year term matching cap, but narrow the 
scope of the right. In the future, the right of first refusal will 
apply only to maximum rate contracts for 12 or more consecutive months 
of service. Because the right of first refusal will apply only to 
maximum rate contracts, there will be no regulatory right of first 
refusal for contracts containing negotiated rates. This modification is 
consistent with the purpose of the right of first refusal to protect 
the historical service of long-term captive customers. This limitation 
on the right of first refusal strikes the appropriate balance between 
the need to protect captive customers and the need to balance the risks 
between pipelines and existing shippers.
1. Background
    In Order No. 636, the Commission amended its regulations to permit 
pre-granted abandonment of transportation contracts. In order to 
protect captive customers from the pipelines' monopoly power, and 
permit them to continue to receive the historical service upon which 
they had relied, the Commission conditioned pre-granted abandonment on 
the right of first refusal.\265\ Pursuant to the right of first 
refusal, an existing shipper with a long-term firm contract can retain 
its service from the pipeline by matching the rate and length of 
service of a competing bid for that service. The rate is capped by the 
pipeline's maximum tariff rate, and the requirement that the existing 
shipper must match the length of the contract term of a competing bid 
is limited to a contract length of five years.\266\ In UDC v. FERC, 
\267\ the court found that the right of first refusal mechanism with a 
cap on the contract length was an adequate means of protecting 
customers from pipelines' market power.
---------------------------------------------------------------------------

    \265\ 18 CFR 284.221(d) (1999).
    \266\ In Order No. 636-A, the Commission adopted a term matching 
cap of 20 years. In UDC v. FERC, the court approved the basic right 
of first refusal and approved the concept of a term matching cap, 
but found that the Commission had not adequately explained the 20-
year cap. In Order No. 636-C, the Commission concluded that a 
matching cap of 5 years was appropriate given the trend to shorter 
contracts.
    \267\ 88 F.3d 1105, 1139 (D.C. Cir. 1996), cert. denied, 117 S. 
Ct. 1723 (1997).
---------------------------------------------------------------------------

    In the NOPR, the Commission explained that increased competition in 
the commodity and capacity markets since Order No. 636, affords greater 
protection to shippers from monopoly power. Further the Commission 
observed that since restructuring, some small LDCs no longer have to 
hold capacity on the pipeline in order to receive gas, and that, in 
fact, many LDCs have chosen not to hold capacity on pipelines. The 
Commission suggested that these changes could indicate that a right of 
first refusal is no longer necessary to protect shippers.
    The Commission was also concerned that the right of first refusal 
with the five-year matching cap provides a disincentive for an existing 
shipper to enter into a contract of more than five years, and results 
in a bias toward short-term contracts. Therefore, the Commission 
proposed in the NOPR to eliminate the term matching cap from the right 
of first refusal. In addition, the Commission stated that it would 
consider other options for modifying the right of first refusal, 
including whether it should be eliminated in its entirety, whether the 
length of the term matching

[[Page 10213]]

cap should be changed, and whether a right of first refusal should be a 
matter of negotiation between the parties.
    In the comments on the NOPR, the proposal to eliminate the five-
year term matching cap was generally opposed by shippers and shipper 
groups,\268\ as well as by several state agencies.\269\ These 
commenters argue that, contrary to the Commission's assertions in the 
NOPR, increased competition does not afford customers sufficient 
protection from the pipelines' market power. They state that the 
Commission itself acknowledges that pipelines still possess market 
power in the long-term market where the right of first refusal is 
applicable, and for that reason did not propose to eliminate rate 
regulation in the long-term market. They argue that removing the five-
year cap would require the shipper to commit to capacity for a term 
well beyond what would be prudent in light of the risks of doing 
business in the evolving market place. In addition, they argue that 
eliminating the right of first refusal or the five-year cap is not 
legally justified in light of the court's decision in UDC v. FERC.
---------------------------------------------------------------------------

    \268\ For example, AGA, APGA, Allied Signal, American Forest & 
Paper Assoc., Amoco Energy Trading Co., et al., Atlanta Gas Light, 
Brooklyn Union Gas Co. and Keyspan Gas, Colorado Springs Utilities, 
Columbia LDCs, Consolidated Edison Co. of New York, the Fertilizer 
Institute, Florida Cities, FPL Group, and New England Gas 
Distributors.
    \269\ E.g., Illinois Commerce Commission, Minnesota Department 
of Public Service, Pennsylvania Office of Consumer Advocate and 
Pennsylvania Public Utility Commission, New York Public Service 
Commission, Wisconsin Public Service Commission, Ohio Public 
Utilities Commission.
---------------------------------------------------------------------------

    Several of these commenters argue that the Commission should 
strengthen the right of first refusal by reducing the term-matching 
cap.\270\ For example, ConEd argues that a one-year cap is appropriate 
because LDCs must be able to assemble economically priced packages of 
transportation capacity without putting reliability at risk or 
needlessly creating stranded costs. Several parties, including Brooklyn 
Union/Keyspan and Consolidated Edison of New York, ask the Commission 
to enhance the right of first refusal by clarifying that an existing 
shipper may exercise its right of first refusal as to a geographic 
portion of the existing contract.
---------------------------------------------------------------------------

    \270\ For example, Brooklyn Union and Keyspan Gas, Consolidated 
Edison Co. of New York, and New England Gas Distributors argued that 
the term matching cap should be reduced to one year. The 
Pennsylvania Office of Consumer Advocate and the Pennsylvania Public 
Utility Commission suggested shortening the matching cap to two 
years, and revisiting the issue periodically. PSE&G suggested 
shortening the term to 2-3 years. AGA also suggested shortening the 
term.
---------------------------------------------------------------------------

    On the other hand, the pipelines \271\ argue that the right of 
first refusal should be eliminated because it no longer serves any 
purpose since increased competition affords customers protection from 
monopoly power. If the right of first refusal is not eliminated in its 
entirety, they argue that at a minimum, the term-matching cap should be 
removed. These parties assert that the right of first refusal reduces 
competition and distorts the competitive environment by denying the 
pipeline and a willing third party the right to contract for longer 
than the cap period. Further, they argue that the right of first 
refusal places disproportionate risks on the pipelines because the 
pipeline must bear the risk of standing ready to serve the existing 
shipper indefinitely, while the shipper has no such obligation.
---------------------------------------------------------------------------

    \271\ E.g., INGAA, Williams, Tejas, Williston, Enron Interstate 
Pipelines.
---------------------------------------------------------------------------

2. Discussion
    The purpose of the right of first refusal is to protect captive 
long-term customers from the pipelines' exercise of monopoly 
power.\272\ It is based on the customer's reliance on the pipeline for 
its historical service.\273\ It protects existing customers by 
providing them with the right to continue their existing service by 
matching the highest competitive bid for the service, up to the maximum 
rate and up to a period of five years. At the same time, by requiring 
that existing customers match competitive bids, the right of first 
refusal recognizes the role of market forces in determining contract 
price and term.
---------------------------------------------------------------------------

    \272\ UDC v. FERC, 88 F.3d 1105, 1140 (D.C. Cir. 1996), cert 
denied, 117 S. Ct. 1723 (1997); Order No. 636-C, 78 FERC para. 
61,186 at 61,772-773 (1997).
    \273\ Id.
---------------------------------------------------------------------------

    As markets become more competitive, and the secondary market 
continues to develop, it may become unnecessary to protect any customer 
with a right of first refusal. However, upon consideration of the 
comments, the Commission has determined that it cannot at this time 
reach the conclusion that all long-term shippers have sufficient 
competitive options to warrant elimination of the right of first 
refusal in its entirety. The Commission, therefore, will retain a right 
of first refusal and will retain, for the present, the five-year 
matching cap. However, the right of first refusal will apply in the 
future only to maximum rate contracts for 12 or more consecutive months 
of service.
    Limiting the right of first refusal to maximum rate contracts of 12 
or more consecutive months of service is consistent with its original 
purpose to protect long-term captive customers from the pipeline's 
monopoly power. If the customer is truly captive and has no 
alternatives for service, it is likely that its contract will be at the 
maximum rate. Shippers that are not captive customers and have 
alternatives in the marketplace do not need the protection of the right 
of first refusal.
    In addition, the ROFR will apply only when the contract provides 
for 12 or more consecutive months of service. This is a different 
result than the Commission reached in North American Energy 
Conservation, Inc. v. CNG Transmission Corp.\274\ under the current 
regulations, which provide that the right of first refusal applies to 
``a contract with a term of one year or more.'' \275\ In that case, the 
Commission concluded that the right of first refusal applied to a 
contract with a duration of 15 months that provided for two 
noncontinuous periods of seasonal service, each one of which was for 
less than 12 months. The Commission held that, under the current 
regulations, it was the term of the contract rather than the term of 
the service that determined the applicability of the right of first 
refusal. In the future, the right of first refusal will apply only when 
the contract provides for at least 12 consecutive months of service; it 
will be the term of the service rather than the term of the contract 
that will determine the applicability of the right of first refusal. 
Again, this is consistent with the purpose of the right of first 
refusal to protect long-term captive customers. Seasonal service is 
short-term service, even if the contract providing for the service is 
of a duration of more than a year, and the right of first refusal is 
intended to protect long-term customers.
---------------------------------------------------------------------------

    \274\ 88 FERC para. 61,255, reh'g, 89 FERC para. 61,122 (1999).
    \275\ 18 CFR 284.221(d)(2).
---------------------------------------------------------------------------

    With this modification captive customers still will be able to 
continue to receive their historical service as long as they pay the 
maximum rate. And, the pipeline is not disadvantaged by the right of 
first refusal if the contract is at the maximum rate. However, if a 
shipper has sufficient alternatives that it can negotiate a rate below 
the just and reasonable rate, it should not have the protection 
afforded by the right of first refusal. In these circumstances, the 
pipeline should be able to negotiate with other interested shippers. 
This limitation on the right of first refusal strikes the appropriate 
balance between the need to protect captive customers and the need to 
better balance the risks between the shipper and the pipeline.

[[Page 10214]]

    The maximum rate that the existing shipper must meet in order to 
exercise its right of first refusal may be higher than its current 
rate. The Commission's regulations provide that a shipper whose 
contract is expiring is entitled to renew that contract by matching the 
highest bid up to the maximum rate,\276\ but, there is nothing in the 
right of first refusal that guarantees that the maximum rate will 
remain the same. The Commission recognized in its recent Policy 
Statement concerning Certification of New Interstate Natural Gas 
Pipeline Facilities (Certificate Policy Statement),\277\ that a shipper 
exercising its ROFR could be required to match a bid up to a maximum 
rate higher than the historic maximum rate applicable to its capacity 
in certain limited circumstances: when a pipeline expansion has been 
completed and an incremental rate exists on the system; the pipeline is 
fully subscribed; and there is a competing bid above the maximum pre-
expansion rate applicable to existing shippers.\278\
---------------------------------------------------------------------------

    \276\ 18 CFR 284.221(d)(1999).
    \277\ Docket No. PL99-3-000, FERC para. 61,277 (1999).
    \278\ Under this procedure, the pipeline cannot require the 
existing shipper to pay a rate higher than that of competing bidder. 
For example, if the historic maximum rate is $1/MMBtu, the maximum 
rate the existing shipper has to match is $2/MMBtu, and the 
competing bid is $1.50/MMBtu, the pipeline must sell the capacity to 
the existing shipper if it is willing to match the $1.50 bid.
---------------------------------------------------------------------------

    The existing customers should not be required to subsidize 
expansion projects that are implemented during the term of their 
contracts. While their contracts are in effect, it would be inequitable 
to raise their rates to include the costs of expansion projects that 
will not be used to provide them with service. Thus, it is logical to 
price the new project incrementally and without subsidies from the 
rates of the existing shippers. However, when the existing customer's 
contract expires, the existing customer should be treated similarly to 
new customers for pipeline capacity, who face rates higher than the 
pre-expansion historic rate.\279\ Under the policy conditions 
established by the Commission (fully subscribed expansion, at least one 
bid above the existing rate, and a rate mechanism established in 
advance), there would be insufficient capacity to satisfy all the 
demands for service on the system. When insufficient capacity exists, a 
higher matching rate will improve the efficiency and fairness of 
capacity allocation, within the limits imposed by cost-of-service 
ratemaking, by allowing new shippers who place greater value on 
obtaining capacity than the existing shipper to better compete for the 
limited capacity that is available.
---------------------------------------------------------------------------

    \279\ Cf. PG&E Gas Transmission, Northwest Corporation, 82 FERC 
para. 61,289, at 62,124-26 (1998) aff'd Washington Water Power Co. 
v. FERC, No. 98-1245 (D.C. Cir. Feb. 1, 2000) (for permanent 
releases of capacity taking place after an expansion, the 
replacement shippers should pay the same rate as the expansion 
shippers).
---------------------------------------------------------------------------

    The logic for using a higher matching rate would not apply if the 
system were not fully utilized, and in those circumstances, the 
existing customer could exercise its right of first refusal by agreeing 
to pay the historic maximum rate. This protects an existing captive 
customer against the exercise of market power by the pipeline because 
the pipeline cannot insist on the shipper paying a higher rate unless 
its expansion is fully subscribed and there is another bid for capacity 
at a rate above the historic maximum rate charged the existing shipper. 
These conditions ensure that the pipeline is unable to use its market 
power over captive customers to withhold capacity from the market to 
raise price. Price will exceed the current maximum rate charged the 
existing shipper only when a higher price is needed to allocate scarce 
capacity.
    As the Commission explains in the Certificate Policy 
Statement,\280\ to adjust the maximum rate applicable to shippers 
exercising their ROFR in these circumstances, the pipeline would have 
to establish a mechanism for reallocating costs between the historic 
and incremental rates so all rates remain within the pipeline's cost-
of-service.\281\ The mechanism can be established either through a 
general section 4 rate case or through the filing of pro forma tariff 
sheets which would provide the Commission and the parties with an 
opportunity to review the proposal prior to implementation. The 
Commission would review the proposed mechanism to determine how well it 
achieves the following objectives: capacity pricing that permits as 
efficient an allocation of capacity as is possible under cost-of-
service ratemaking; protection against the exercise of market power by 
the pipeline (through withholding of capacity, for example, or the 
potential for skewed bidding); protection against the pipeline's 
overrecovery of its revenue requirement; and equity of treatment 
between shippers with expiring contracts and new shippers to the system 
seeking comparable service.
---------------------------------------------------------------------------

    \280\ Docket No. PL 99-3000, Order Clarifying Statement of 
Policy
    \281\ Cf. Viking Gas Transmission Company, 89 FERC para. 61,204 
(1999) (rejecting tariff filing to raise matching rates under a ROFR 
where, among other things, the filing did not readjust existing and 
expansion rates).
---------------------------------------------------------------------------

    Application of this approach could lead to rates for shippers 
exercising their ROFR that are higher than their existing vintaged 
rate. But this will occur only if the preconditions are met--the 
pipeline is full and there is a competing bid higher than the pre-
expansion rate so that a higher rate is needed to allocate available 
capacity--and the Commission has accepted the pipeline's mechanism for 
determining rates as just and reasonable.
    In the Certificate Policy Statement, the Commission explained that 
it is important for the rates for the new capacity to send the correct 
price signals so that shippers can decide whether the new capacity is 
really needed. As the Commission further explains in its clarification 
order in that proceeding, there is tension between sending efficient 
pricing signals to expansion customers and to customers whose contracts 
are expiring, while remaining within the pipeline's revenue 
requirement. There may be a number of ways to recompute rates to 
effectively balance these interests. The Appendix to that order 
provides two examples of potential approaches to the recomputation of 
rates, one in which the expansion rate is recomputed to establish the 
maximum matching rate and the other where the system average rate is 
used as the matching rate. Under these approaches, as contracts of 
existing shippers expire, the costs and contract demand represented by 
these contracts are reallocated between the existing and expansion 
service without changing the pipeline's overall revenue requirement.
    The Commission will not change the length of the term matching cap 
at this time. The Commission concluded in Order No. 636-C that a five-
year cap was appropriate given the evidence in that record of industry 
trends in contract length.\282\ The record there showed that five years 
was the median length of long-term contracts entered into since January 
1, 1995.\283\ None of the commenters presented evidence to support the 
conclusion that a five year contract is atypical in the current market. 
\284\
---------------------------------------------------------------------------

    \282\ Order No. 636-C, 78 FERC at 61,773-74.
    \283\ 78 FERC at 61,774.
    \284\ Several commenters suggested that the Commission should 
take additional evidence on current contract length and reduce the 
length of the cap if that evidence warrants. See, e.g., comments of 
New England Gas Distributors. The Commission could undertake this 
analysis of industry trends in a future proceeding, but will retain 
the five-year cap for the present.
---------------------------------------------------------------------------

    Further, the Commission will not enhance the right of first refusal 
by holding that it can be exercised for a

[[Page 10215]]

geographic portion of the existing contract, as requested by several 
commenters. The purpose of the right of first refusal is to protect the 
captive customer's historical service, and therefore it should apply 
only when the existing shipper is seeking to contract for its 
historical capacity. The right of first refusal is a limited right and 
it was never intended to permit shippers to increase or change their 
service.\285\ It is intended to be a means of defense against pipeline 
market power, not a mechanism to award an existing shipper a preference 
over a new shipper for different service.
---------------------------------------------------------------------------

    \285\ As the Commission stated in Williams Natural Gas company, 
65 FERC para. 61,221 at 62,013 (1993), ``the character of the 
service being provided under the expiring contract cannot be changed 
through use of the right of first refusal.''
---------------------------------------------------------------------------

    In Order No. 636-B, the Commission clarified that the right of 
first refusal permits the existing capacity holder to elect to retain a 
volumetric portion of its capacity subject to the right of first 
refusal, and permit the pipeline's pregranted abandonment to apply to 
the remainder of the service.\286\ The Commission has explained that 
this is intended to ensure against the inefficient or unnecessary 
retention of capacity at the expiration of the contract.\287\ 
Unbundling has reduced the role of LDCs in providing transportation 
service. In 1998, over 80 percent of industrial users purchased their 
capacity directly from the pipeline or from marketers rather than from 
an LDC.\288\ Allowing LDCs to decrease their contractual volumes when 
they exercise the right of first refusal makes this capacity available 
to industrials and marketers. Thus, under the right of first refusal, 
if the LDC's market shrinks because its former sales customers are 
purchasing their own gas in the wholesale market, the LDC can reduce 
the volumes it has under contract.
---------------------------------------------------------------------------

    \286\ Order No. 636-B at 30,634-35.
    \287\ Williams Natural Gas Co., 83 FERC para. 61,052 at 61,299 
(1998).
    \288\ Energy Information Administration, Natural Gas Annual 
1998, 35-37, 39, 41 (October 1999).
---------------------------------------------------------------------------

    However, Order No. 636 did not include within the right of first 
refusal the option to contract for a geographic portion of the 
historical capacity, and permitting an existing shipper to exercise its 
right of first refusal for a geographic portion of its historical 
service is not consistent with its purpose. A shipper that can 
terminate a geographic portion of its historical service must have 
alternatives in the marketplace that can substitute for its historical 
service, and therefore is not a captive customer that requires the 
protection of the right of first refusal. In its comments, Con Ed gives 
an example of a shipper that has a contract for service from the 
pipeline's production area to points in the market area, and argues 
that the shipper should be able to retain its right of first refusal to 
capacity in the market area without being required to retain capacity 
in the production area. In this example, the shipper clearly has 
competitive options for transporting its gas and does not need the 
protection of a right of first refusal to protect its historical 
service.
    Moreover, permitting the exercise of the right of first refusal for 
a geographic portion of the historical capacity could leave the 
capacity unused and thus burden the pipeline and its other customers 
with the cost of this unused capacity. This is the significant 
distinction between permitting a shipper to exercise its right of first 
refusal for a portion of the contractual volumes and permitting a 
shipper to exercise its right of first refusal for less than the full 
length of haul. With the development of the pipeline grid, the need to 
hold capacity to access traditional supply areas has diminished and 
thus there is more likelihood that reductions in geographic capacity 
will lead to unused capacity on some segments. In contrast, exercise of 
the right of first refusal for less than the full contractual volume is 
unlikely to have the same impact on the pipeline and its shippers 
because with retail unbundling that capacity is likely to be contracted 
to move gas to the end-users previously served by the LDC. Gas 
consumption has not been shrinking, rather the contracting patterns 
have been changing.
    Therefore, maintaining the Commission's current policy and not 
expanding the right of first refusal beyond its original scope as set 
forth in Order No. 636 strikes the appropriate balance between 
protecting the historic service of the captive customer and not 
burdening the pipeline and its other customers with unused capacity.
    The Commission's ruling that a shipper cannot exercise its right of 
first refusal for a portion of its length of haul is also consistent 
with the rationale of the court's decision in Municipal Defense Group 
v. FERC.\289\ In that decision, the court upheld the Commission's 
approval in Texas Eastern Transmission Corp.,\290\ of a proposal by the 
pipeline to award new capacity on the basis of a net present value 
determination. The Commission held that while the small customers had 
special treatment for their existing service, \291\ they must compete 
on an equal basis with other customers for additional capacity. The 
court agreed, and stated that there was no reason to extend the special 
treatment given to small customers beyond their existing service in 
order to enable them to increase their capacity at a subsidized rate. 
Similarly, there is no basis for permitting customers with a right of 
first refusal to use that right to obtain an advantage over other 
customers in seeking to change their service to a shorter haul.
---------------------------------------------------------------------------

    \289\ 170 F.3d 197 (D.C. Cir. 1999).
    \290\ 79 FERC para. 61.258 (1997), reh'g, 80 FERC para. 61,270 
(1997).
    \291\ Small customers received a discounted rate on the pipeline 
pursuant to a settlement in the pipeline's Order No. 636 proceeding, 
and argued that the net present value method would be prejudicial to 
them because the value of their bids would be less that the value of 
bids of larger customers paying a higher rate.
---------------------------------------------------------------------------

    Several parties ask the Commission to clarify that shippers who 
have rollover or evergreen clauses in their contracts have the right to 
terminate a volumetric portion of that contract and exercise their 
right of first refusal with regard to the remaining portion of the 
contract. \292\ These parties state that clarification is necessary 
because certain pipelines have taken the position that the right of 
first refusal protects only shippers whose contracts do not contain 
rollover or evergreen clauses. The commenters state that these 
pipelines have concluded that while the right of first refusal permits 
a customer to renew its contract for less that its full MDQ, this right 
does not extend to a customer with a rollover contract. The commenters 
state that clarification of this issue is necessary at this time 
because many LDC long-term contracts will be expiring over the next few 
years.
---------------------------------------------------------------------------

    \292\ See comments of AGA and Con Ed.
---------------------------------------------------------------------------

    There are two possible sources of a shipper's right of first 
refusal. First, shippers have the right of first refusal as provided in 
the Commission's regulations. Thus, all shippers with a qualifying 
contract, (i.e., a contract of 12 months or more and, in the future, at 
the maximum rate), can continue to receive their service from the 
pipeline by matching the rate, up to the maximum rate, and the length 
of service, up to a period of five years, of a competing bid for that 
service. Under the right of first refusal conveyed by Sec. 284.221(d) 
of the regulations, shippers always have this regulatory right of first 
refusal, regardless of the provisions of their contract.
    Second, a pipeline and its shippers may agree to include a right of 
first refusal roll-over or evergreen clause in their contracts. If a 
contractual right of first refusal, rollover or evergreen clause

[[Page 10216]]

would allow the shipper to exercise a right of first refusal in 
situations where the regulatory right would not apply, the shipper may 
rely on its contractual rights in lieu of the regulatory right of first 
refusal. The choice is for the shipper to make. But, the shipper always 
has, at a minimum, the regulatory right of first refusal. As the 
Commission recently stated, ``a ROFR is a regulatory right that may 
achieve the same purpose as a contractual rollover, but it is a right 
guaranteed by the regulations and not dependent on the contract.'' 
\293\ Under the right of first refusal in Sec. 284.221(d), which is an 
exercise of the Commission's abandonment authority under NGA Section 
7(b), a contractual right of first refusal may broaden the regulatory 
right of first refusal, but it may not narrow it.
---------------------------------------------------------------------------

    \293\ North American Energy Conservation, Inc. v. CNG 
Transmission, 88 FERC para. 61,255 at 61,809 (1999).
---------------------------------------------------------------------------

    The regulatory right of first refusal includes the right of the 
existing shipper to elect to retain a volumetric portion of its 
capacity subject to the right of first refusal, and permit the 
pipeline's pregranted abandonment to apply to the remainder of the 
service.\294\ Therefore, the Commission clarifies that a customer with 
a contract that qualifies for a regulatory right of first refusal may 
exercise that regulatory right for a volumetric portion of the 
capacity, regardless of whether the contract contains a rollover or 
evergreen clause.
---------------------------------------------------------------------------

    \294\ Order No. 636-A, FERC Stats. & Regs. (1991-1996) para. 
30,950 at 30,635 (1992).
---------------------------------------------------------------------------

    Existing discounted long-term contracts that are now subject to the 
right of first refusal will be grandfathered, and the right of first 
refusal will apply at their expiration. However, the new rate 
limitation will apply to any of the contracts that are re-executed and, 
therefore, the right of first refusal will not apply if the re-executed 
contracts are not at the maximum rate. The grandfathering of current 
contracts gives all shippers notice of the new limitation, and the 
opportunity to re-execute their current contracts in view of this 
change. Further, the provisions of the pipelines' current tariffs will 
continue to govern the right of first refusal process until the 
pipeline files revised tariff sheets to limit the right of first 
refusal consistent with this discussion.

B. Negotiated Terms and Conditions of Service

    In the Commission's policy statement on Alternatives to Traditional 
Cost-of-Service Ratemaking,\295\ the Commission set forth its policy 
permitting pipelines the flexibility to negotiate rates so long as the 
shipper continued to have the option of choosing recourse service from 
the pipeline. The availability of a recourse service at just and 
reasonable rates was considered to provide reasonable protection 
against the exercise of market power. But the Commission at the time 
expressed concern about whether to permit individual negotiation of 
terms and conditions of service and requested further comment on 
whether such flexibility should be permitted. In the NOPR, the 
Commission proposed to permit pipelines to file tariff provisions 
providing for pre-approved authority to negotiate terms and conditions 
of service without making a separate tariff filing, so long as the 
pipeline adhered to a series of requirements intended to protect 
against degradation of recourse service.
---------------------------------------------------------------------------

    \295\ 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), 74 
FERC 61,076 (1996).
---------------------------------------------------------------------------

    There was a significant split among the commenters on this issue. 
Pipelines and LDCs strongly supported the implementation of negotiated 
terms and conditions of service as ways in which pipelines could 
attract new customers, particularly gas fired electric generation and 
industrial customers.\296\ INGAA asserts, for instance, that gas fired 
electric generation has service requirements that differ from those 
provided in typical tariff-based services. AGA similarly asserts that 
permitting negotiation of services will permit pipelines to tailor 
services to fit the different circumstances of individual customers. 
Those supporting pre-approval for negotiated terms and conditions 
maintain that the Commission can provide adequate oversight to avoid 
undue discrimination, degradation of recourse service, and reduced 
competition.
---------------------------------------------------------------------------

    \296\ See Comments of AGAI, INGAA, Southern Natural, Williams, 
Coastal Companies, Enron Capital and Trade.
---------------------------------------------------------------------------

    Those on the other side were equally vociferous in opposing pre-
approval for negotiated terms and conditions of service.\297\ These 
parties argue that the need for negotiated terms and conditions has not 
been demonstrated, because open access tariffs have been successful in 
serving all types of customers, and that even without pre-approval for 
negotiated terms and conditions of service, the electric generation 
market has shown the greatest growth of any natural gas consumption 
segment. These parties argue that allowing pipelines to negotiate terms 
and conditions of service gives rise to significant dangers to 
competitive markets, including the danger of discrimination in pricing, 
timing, and terms of service and that negotiated terms and conditions 
exacerbates affiliate advantages, permits pipelines to degrade recourse 
services, and harms the secondary market which depends on the sale of a 
uniform product. Moreover, they argue that the protections proposed by 
the Commission to avoid problems created by negotiated terms and 
conditions of service raise problems of their own and will not prevent 
the degradation of recourse service. These parties assert that instead 
of permitting negotiated terms and conditions, the Commission should 
continue to enhance the flexibility of tariff services.
---------------------------------------------------------------------------

    \297\ See Comments of Amoco Energy Trading, Arkansas Gas 
Consumers, Dynegy, Indicated Shippers, NGSA, Process Gas Consumers 
Group, PSC Wisconsin.
---------------------------------------------------------------------------

    The Commission has determined not to provide pipelines, at this 
time, with authority to file for pre-approval of the right to negotiate 
terms and conditions of service with individual customers. Given the 
changes occurring in the marketplace, it is not yet clear that pre-
approval for negotiated terms and conditions is necessary. Although 
pipelines and some gas fired generators support allowing negotiation of 
terms and conditions of service that will directly address the 
generators' service needs,\298\ other generators are not convinced that 
such negotiation flexibility is necessary or that it outweighs the 
risks of discrimination to those not receiving the negotiated 
services.\299\ Pipelines also have been able to create open access 
tariff-based services with enhanced flexibility for scheduling and 
handling imbalances without having to negotiate terms and conditions of 
service with individual shippers.\300\ Indeed, in this rule, the 
Commission is requiring that pipelines provide imbalance management 
services that will better enable all customers to deal with the 
potential risks of imbalance penalties.
---------------------------------------------------------------------------

    \298\ See Comments of Sithe, Sempra Energy, EEI.
    \299\ See Comments of Midland, Florida Cities, Dynegy, FPL.
    \300\ See Reliant Energy Gas Transmission Company, 87 FERC para. 
61,228 (1999) (hourly flexibility service designed to meet needs of 
gas generators); Mojave Pipeline Company, 79 FERC para. 61,347 
(1997); Colorado Interstate Gas Company, 83 FERC para. 61,273 (1998) 
(parking and loan service).
---------------------------------------------------------------------------

    The negotiation of terms and conditions of service further is 
directly related to the question whether the Commission needs to revise 
fundamental aspects of its regulatory policy to accommodate a dual 
market

[[Page 10217]]

structure in which some shippers with sufficient alternatives and 
negotiating leverage want to negotiate rates and terms and conditions 
of service while other shippers remain captive, still subject to the 
pipeline's market power and to undue discrimination. The development of 
a two-track regulatory model, as discussed earlier, requires further 
study of the interrelation between various aspects of Commission 
regulatory policy, such as whether rates should continue to support 
pipeline revenue requirements and how rates should be designed in a 
dual market to protect captive customers.
    In light of the questions about the need for and effects of 
negotiated terms and conditions and the interrelation between 
negotiated terms and conditions of service and other long-term 
regulatory issues that were not the subject of this proceeding, the 
Commission has decided not to move forward at this time to provide 
pipelines with pre-approval to negotiate terms and conditions of 
service. To the extent that pipelines, in certain circumstances, find 
that they are unable to file an open access tariff-based service to 
accommodate particular needs, and that individual negotiation is the 
only feasible method of providing service to a particular shipper, the 
pipeline is still permitted under the Commission's regulations to file 
a non-conforming contract with the Commission.\301\ Such a filing has 
to be made at least 30 days prior to the proposed effective date,\302\ 
which gives other parties and the Commission the opportunity to review 
all aspects of the non-conforming contract to determine whether the 
contract is unduly discriminatory or preferential or would negatively 
affect the service provided to other shippers.
---------------------------------------------------------------------------

    \301\ 18 CFR 154.1(d).
    \302\ 18 CFR 154.207.
---------------------------------------------------------------------------

    The determination not to move forward at this juncture with pre-
approved negotiated terms and conditions of service raises the question 
of how the Commission will differentiate between negotiated rates, 
permissible under the Commission's negotiated rates policy,\303\ and 
negotiated terms and conditions of service. While formulating a generic 
definition of rate applicable to all potential situations is not 
possible, the Commission generally considers negotiated terms and 
conditions to be related to operational conditions of transportation 
service. A negotiated rate would not include conditions or activities 
related to the transportation of gas on the pipeline, such as 
scheduling, imbalances, or operational obligations, such as OFOs. By 
contrast, negotiated rate agreements can include the price, the term of 
service, the receipt and delivery points, and the quantity.
---------------------------------------------------------------------------

    \303\ 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), 74 FERC 
61,076 (1996).
---------------------------------------------------------------------------

VI. Reorganization of Part 284 Regulations

    The Commission is reorganizing certain portions of its part 284 
regulations to better reflect the nature of services in the short-term 
market and to consolidate its Part 284 reporting and filing 
requirements in a single section. Aside from the regulatory revisions 
discussed in the body of the preamble, the Commission is not making 
substantive changes to the regulations, but is making changes to 
conform its regulations with the new organizational structure.
    Because capacity release has become an integral part of the short-
term market, the Commission is moving its capacity release regulations 
from subpart H of part 284 to the same location in its regulations as 
pipeline firm and interruptible service (newly designated Sec. 284.7 
(firm service), Sec. 284.8 (release of firm service), and Sec. 284.9 
(interruptible service)).\304\
---------------------------------------------------------------------------

    \304\ To eliminate redundancy between Sec. 284.7 dealing with 
pipeline firm service and Sec. 284.9 dealing with pipeline 
interruptible service, Sec. 284.9 is being revised to cross-
reference the sections of Sec. 284.7 that are applicable to both 
sections.
---------------------------------------------------------------------------

    In addition, reporting and filing requirements for pipeline 
services under part 284 are presently scattered throughout Part 284. 
For example, the Index of Customers and storage reports are presently 
located in subpart B, Sec. 284.106, which deals with interstate 
pipelines performing transportation service under the Natural Gas 
Policy Act (NGPA). But these regulations are then applied to interstate 
pipelines performing open access services in subpart G, Sec. 284.223. 
Other reporting requirements are located throughout various substantive 
provisions of Part 284.\305\ The Commission is collecting these 
requirements into new Sec. 284.13 applicable to interstate pipelines 
transporting gas under Subpart B (transportation under section 311 of 
the NGPA) and Subpart G (open access transportation under the NGA). 
Reporting requirements specific to Subpart B pipelines (by-pass 
reports) remain in subpart B.
---------------------------------------------------------------------------

    \305\ See, e.g., 18 CFR 284.8(b)(3) and 284.9(b)(3) 
(requirements to provide information on available capacity), 
284.7(c)(6) (discount reports), 284.12 (filing of capacity).
---------------------------------------------------------------------------

    Commenters did not object to the reorganization. Dynegy contends 
the Commission should not be proposing a requirement for pipelines to 
file the semi-annual storage report in Sec. 284.14(e) which discloses 
shippers' names. But the semi-annual storage report is not a new 
requirement. Pipelines were required to provide this information under 
existing Sec. 284.102 (b), and the Commission finds no basis for 
removing a currently applicable requirement. The storage report, 
however, is being revised to eliminate section (6) requiring pipelines 
to file the related docket numbers in which the pipeline reported 
storage related injections and withdrawals. This information is no 
longer relevant since, after Order No. 636, pipelines are no longer 
required to file the ST reports on which the injection and withdrawal 
information was included.
    The following is the new outline for subpart A of part 284.

284.1  Definitions.
284.2  Refunds and interest.
284.3  Jurisdiction under the Natural Gas Act.
284.4  Reporting.
284.5  Further terms and conditions.
284.6  Rate interpretations.
284.7  Firm transportation service.
284.8  Release of firm transportation service
284.9  Interruptible transportation service.
284.10  Rates.
284.11  Environmental compliance.
284.12  Standards for pipeline business operations and 
communications
284.13  Reporting requirements for interstate pipelines.

VII. Implementation Schedule

    The regulatory changes made in this rule are being implemented at 
different times and will require the pipelines to make tariff or pro 
forma tariff filings. The following summarizes the implementation and 
compliance schedule for the rule.
    1. Maximum Ceiling Rate for Capacity Release Transactions. The 
regulation removing the maximum ceiling rate for short-term capacity 
release transactions will become effective as of the date of this rule. 
Pipelines must file within 180 days to remove inconsistent tariff 
provisions and can incorporate this filing into any other tariff filing 
made by the pipeline within the 180 day period.
    2. Scheduling, Segmentation, Penalty Regulations. To comply with 
the regulations governing scheduling of capacity release transactions, 
segmentation, and penalties, pipelines are required to make pro forma 
tariff filings by May 1, 2000. Thirty days will be provided for the 
filing of comments and protests. After review of the filing and 
comments or protests, the

[[Page 10218]]

Commission will determine whether further procedures are needed and the 
effective date for any tariff changes.
    3. Reporting Requirements. Pipelines must comply with the reporting 
requirements by September 1, 2000, in accordance with the procedures 
discussed earlier.
    4. ROFR. The regulatory change to the ROFR becomes effective on the 
date this rule becomes effective. Pipelines that have different 
provisions in their tariffs can, but are not required to, file to 
modify their existing tariffs to accord with the regulatory changes 
made in this rule. Until such filing is accepted, the pipeline's 
current tariff provisions will continue to apply.

VIII. Information Collection Statement

    The Office of Management and Budget's (OMB) regulations in 5 CFR 
1320.11 require that it approve certain reporting and recordkeeping 
requirements (collections of information) imposed by an agency. Upon 
approval of a collection of information, OMB shall assign an OMB 
control number and an expiration date. Respondents subject to the 
filing requirements of this Final Rule shall not be penalized for 
failing to respond to these collections of information unless the 
collections of information display valid OMB control numbers.
    The collections of information related to the subject of this Final 
Rule fall under FERC-545, ``Gas Pipeline Rates: Rate Change (Non-
Formal)'' (OMB Control No. 1902-0154); FERC-549 ``Gas Pipeline Rates: 
Natural Gas Policy Act; Title III Transactions'' (OMB Control No. 1902-
0086); FERC-549B ``Capacity Information'' (OMB Control No. 1902-0169) 
and FERC-592 ``Marketing Affiliates of Interstate Pipelines'' (OMB 
Control No. 1902-0157).
    Under this Final Rule, the overall reporting requirements will be 
increased based on the addition of certain information, namely the 
receipt and delivery point data in transactional reports and the Index 
of Customers plus organizational and personnel information on 
affiliates. However, there will also be a reduction in the amount of 
periodic reporting to the Commission and the elimination of the 
requirement to submit discount reports. On the whole, the Commission 
estimates that the revised reporting schedule will increase the 
existing reporting burden by a total of 77,847 hours. The bulk of the 
increase will not be extensive, relying not on collecting the data but 
in creating new formats for displaying the information on the 
pipelines' Internet websites.
    Public Reporting Burden: The burden estimates for complying with 
this proposed rule are as follows: (reductions in parentheses)

----------------------------------------------------------------------------------------------------------------
                                                                            No. of       Estimated
                                                               No. of      responses   burden hours     Total
                      Data collection                       respondents       per           per         annual
                                                                          respondent     response       hours
----------------------------------------------------------------------------------------------------------------
FERC-545                                                            100          1.4         115.2        16,128
FERC-549                                                             78          1            (2.7)        (211)
FERC-549B                                                           100        333.9         183.86       61,391
FERC-592                                                             74          1             7.28          539
                                                           -----------------------------------------------------
    Total                                                                                                 77,847
----------------------------------------------------------------------------------------------------------------

    The total annual hours for collection (including recordkeeping) is 
estimated to be 77,847.
    Information Collection Costs: The average annualized cost for all 
respondents is projected to be the following (savings in parentheses):

----------------------------------------------------------------------------------------------------------------
                                                   FERC-545     FERC-549    FERC-549B     FERC-592      Totals
----------------------------------------------------------------------------------------------------------------
Annualized capital/startup costs...............      643,529         0.00    1,455,662         0.00    2,099,191
Annualized costs (Operations & maintenance)....      221,374     (11,315)    1,836,578       28,905    2,075,542
                                                ----------------------------------------------------------------
    Total annualized costs.....................      864,903     (11,315)    3,292,240       28,905    4,174,733
----------------------------------------------------------------------------------------------------------------

    Title: FERC-545, 549, 549B and 592.
    Action: Proposed Data Collections.
    Respondents: Business or other for profit, including small 
businesses.
    Frequency of Responses: On occasion.
    Necessity of Information: The proposed rule seeks to establish 
reporting requirements that will provide information needed for the 
market to operate more efficiently and for shippers and the Commission 
to effectively monitor transactions for undue discrimination and the 
exercise of market power. Information on market structure enables the 
Commission to know who holds or controls capacity on each portion of 
the pipeline system, so the potential sources of capacity can be 
determined. The information required in the current regulations is not 
as complete as that required in this rule and provides inconsistent 
information for competing types of capacity, both in terms of the 
content of the information and the formats used to report the 
information.
    Internal Review: The Commission has assured itself, by means of its 
internal review, that there is specific, objective support for the 
burden estimates associated with the information collection 
requirements. The internal review involves among other things, an 
examination of the necessity and adequacy of the information required, 
and the design, cost, reliability, and redundancy of the information. 
The data collected will enable the industry and the Commission to 
monitor the structure, conduct, and performance of the gas industry. 
This information will enable the Commission to monitor changes in the 
marketplace that affect Commission regulatory policy and help in 
identifying, and responding to, markets where light-handed regulation 
may be appropriate as well as markets in which constraints on 
competition still exist. These requirements conform to the Commission's 
plan for efficient information collection, communication, and 
management within the natural gas pipeline industry.
    One-hundred-forty-three comments were filed in response to the 
NOPR. While the Commission did not receive any comments concerning its 
estimates for reporting burden, seven entities commented on the 
additional reporting burden placed upon them by the changes made in 
this rule. The Commission has addressed their concerns within the 
preamble of the

[[Page 10219]]

rule in the appropriate section. Further, as required under OMB 
regulations, the Commission submitted the NOPR to OMB for review. OMB 
noted acceptance of the NOPR, but took no action on the NOPR. In its 
response, OMB stated that the Commission should submit its information 
requests when it takes final action.
    Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE, Washington, DC 20426, (Attention: 
Michael Miller, Office of the Chief Information Officer, Phone: (202) 
208-1415, fax: (202) 273-0873, E-mail: [email protected]) or the 
Office of Management and Budget, Office of Information and Regulatory 
Affairs, Attention: Desk Officer for the Federal Energy Regulatory 
Commission, phone: (202) 395-3087, fax: (202) 395-7285.

IX. Environmental Analysis

    The Commission is required to prepare an Environmental Assessment 
or an Environmental Impact Statement for any action that may have a 
significant adverse effect on the human environment.\306\ The 
Commission has categorically excluded certain actions from these 
requirements as not having a significant effect on the human 
environment.\307\ The actions taken here fall within categorical 
exclusions in the Commission's regulations for rules that are 
clarifying, corrective, or procedural, for information gathering, 
analysis, and dissemination, and for sales, exchange, and 
transportation of natural gas that requires no construction of 
facilities.\308\ Therefore, an environmental assessment is unnecessary 
and has not been prepared in this rulemaking.
---------------------------------------------------------------------------

    \306\ Order No. 486, Regulations Implementing the National 
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs. Preambles 1986-1990 para. 30,783 (1987).
    \307\ 18 CFR 380.4.
    \308\ See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 380.4(a)(27).
---------------------------------------------------------------------------

X. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act of 1980 (RFA) \309\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
The regulations adopted here impose requirements on interstate 
pipelines, which generally are not small businesses. Accordingly, 
pursuant to section 605(b) of the RFA, the Commission certifies that 
the regulations adopted herein will not have a significant adverse 
impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \309\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

XI. Document Availability

    In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.fed.us) and in 
FERC's Public Reference Room during normal business hours (8:30 a.m. to 
5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, Washington, 
D.C. 20426.
    From FERC's Home Page on the Internet, this information is 
available in both the Commission Issuance Posting System (CIPS) and the 
Records and Information Management System (RIMS).

    -- CIPS provides access to the texts of formal documents issued 
by the Commission since November 14, 1994.
    -- CIPS can be accessed using the CIPS link or the Energy 
Information Online.
    The full text of this document will be available on CIPS in 
ASCII or WordPerfect 8.0 format for viewing, printing, and/or 
downloading.
    -- RIMS contains images of documents submitted to and issued by 
the Commission after November 16, 1981. Documents from November 1995 
to the present can be viewed and printed from FERC's Home Page using 
the RIMS link or the Energy Information Online icon. Descriptions of 
documents back to November 16, 1981, are also available from RIMS-
on-the-Web; requests for copies of these and older documents should 
be submitted to the Public Reference Room.

    User assistance is available for RIMS, CIPS, and the Website during 
normal business hours from the Help line at 202-208-2222 (E-Mail to 
[email protected]) or the Public Reference Room at 202-208-1371 (E-
Mail to [email protected]).
    During normal business hours, documents can also be viewed and/or 
printed in FERC's Public Reference Room, where RIMS, CIPS, and the FERC 
Website are available. User assistance is also available.

XII. Effective Date

    These regulations are effective March 27, 2000, with the exception 
of the removal of paragraph (c)(6) of redesignated Sec. 284.10, which 
will be effective on September 1, 2000. The Commission has determined, 
with the concurrence of the Administrator of the Office of Information 
and Regulatory Affairs of OMB, that this rule is not a ``major rule'' 
as defined in section 351 of the Small Business Regulatory Enforcement 
Fairness Act of 1996.

List of Subjects

18 CFR Part 154

    Natural gas; Pipelines; Reporting and recordkeeping requirements.

18 CFR Part 161

    Natural gas; Reporting and recordkeeping requirements.

18 CFR Part 250

    Natural gas; Reporting and recordkeeping requirements.

18 CFR Part 284

    Continental shelf; Incorporation by reference; Natural gas; 
Reporting and recordkeeping requirements.

    By the Commission. Commissioner Hebert concurred with a separate 
statement attached.
David P. Boergers,
Secretary.


    In consideration of the foregoing, the Commission amends Part 154, 
Part 161, Part 250, and Part 284, Chapter I, Title 18, Code of Federal 
Regulations, as follows.

PART 154--RATE SCHEDULES AND TARIFFS

    1. The authority citation for Part 154 continues to read as 
follows:

    Authority: 15 U.S.C. 717-717w; 31 U.S.C. 9701; 42 U.S.C. 7102-
7352.


Sec. 154.111  [Amended]

    2. In Sec. 154.111(a), remove the words ``Sec. 284.106 or 
Sec. 284.223'' and add, in their place, the word ``Sec. 284.13(c)''.

PART 161--STANDARDS OF CONDUCT FOR INTERSTATE PIPELINES WITH 
MARKETING AFFILIATES

    3. The authority citation for Part 161 continues to read as 
follows:

    Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.

    4. Section 161.3 is amended as follows:
    a. In paragraph (h)(2), revise all references to ``Sec. 284.10(a)'' 
to read ``Sec. 284.12'' wherever it appears, revise the phrase 
``Electronic Bulletin Board operated pursuant to'' and add in its place 
the phrase ``Internet web site operated complying with'' wherever it 
appears, revise the phrase ``EBB'' and add in its place the phrase'' 
Internet web site'' wherever it appears, and revise the phrase 
``Electronic Bulletin Board'' and add in its place the phrase 
``Internet web site'' wherever it appears; and
    b. Revise paragraph (l) to read as follows:

[[Page 10220]]

Sec. 161.3  Standards of conduct

* * * * *
    (l)(1) A pipeline must post the names and addresses of its 
marketing affiliates on its web site on the public Internet and update 
the information within three business days of any change. A pipeline 
must also state the date the information was last updated. Postings 
must conform with the requirements of Sec. 284.12 of this chapter.
    (2) A pipeline must post the following information on its Internet 
web site complying with Sec. 284.12 of this chapter and update the 
information within three business days of any change, posting the date 
on which the information was updated:
    (i) A complete list of the names of operating personnel and 
facilities shared by the pipeline and its marketing affiliates; and
    (ii) Comprehensive organizational charts showing:
    (A) The organizational structure of the parent corporation with the 
relative position in the corporate structure of the pipeline and all 
marketing affiliates;
    (B) For the pipeline, the business units, job titles and 
descriptions, and chain of command for all positions, including 
officers and directors, with the exception of clerical, maintenance, 
and field positions. The job titles and descriptions must include the 
employee's title, the employee's duties, whether the employee is 
involved in transportation or gas sales, and the name of supervisory 
employees who manage non-clerical employees involved in transportation 
or gas sales.
    (C) For all employees shared by the pipeline and a marketing 
affiliate, the business unit within the marketing affiliate 
organizational structure in which the employee is located, the 
employee's name, job title and job description in the marketing 
affiliate, and the employees position within the chain of command of 
the marketing affiliate.

PART 250--FORMS

    5. The authority citation for Part 250 continues to read as 
follows:

    Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.

    6. Section 250.16 is amended as follows:
    a. Paragraph (b)(1) is removed, paragraph (b)(2) is redesignated as 
(b)(1), and a new paragraph (b)(2) is added and reserved.
    b. In paragraph (c)(2), revise all references to ``284.10(a)'' to 
read ``284.12'' in paragraph (c)(2), revise the phrase ``Electronic 
Bulletin Board'' and add, in its place, the phrase ``Internet Web 
site'' and in paragraph (c)(2), revise the phrase ``Electronic Bulletin 
Boards'' and add, in its place, the phrase ``Internet Web sites''.

PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE 
NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES

    7. The authority citation for Part 284 continues to read as 
follows:

    Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7532; 
43 U.S.C. 1331-1356.


Sec. 284.12  [Removed]

    8. Part 284 is amended by removing Sec. 284.12.

    9. Part 284 is amended by redesignating the sections as set forth 
in the following redesignation table:

------------------------------------------------------------------------
                       Old section                          New section
------------------------------------------------------------------------
284.7...................................................          284.10
284.8...................................................          284.7
284.10..................................................          284.12
284.243.................................................          284.8
------------------------------------------------------------------------


    10. In newly redesignated Sec. 284.7, paragraph (b)(3) is removed 
and paragraph (b)(4) is redesignated as paragraph (b)(3), paragraphs 
(d) and (e) are redesignated as paragraphs (e) and (f) respectively, 
and new paragraph (d) is added to read as follows:


Sec. 284.7  Firm transportation service.

* * * * *
    (d) Segmentation. An interstate pipeline that offers transportation 
service under subpart B or G of this part must permit a shipper to make 
use of the firm capacity for which it has contracted by segmenting that 
capacity into separate parts for its own use or for the purpose of 
releasing that capacity to replacement shippers to the extent such 
segmentation is operationally feasible.
* * * * *
    11. Newly redesignated Sec. 284.8 is amended as follows:
    a. In paragraph (d), revise all references to ``electronic bulletin 
board'' to read ``Internet web site'' wherever it appears; and
    b. Paragraph (i) is added to read as follows:


Sec. 284.8  Release of firm transportation service.

* * * * *
    (i) Waiver of maximum rate ceiling. Until September 30, 2002, the 
maximum rate ceiling does not apply to capacity release transactions of 
less than one year. With respect to releases of 31 days or less under 
paragraph (h), the requirements of paragraph (h)(2) will apply to all 
such releases regardless of the rate charged.

    12. In Sec. 284.9, paragraphs (c) and (e) are removed, paragraph 
(d) is redesignated as paragraph (c), and paragraph (b) is revised to 
read as follows:


Sec. 284.9  Interruptible transportation service.

* * * * *
    (b) The provisions regarding non-discriminatory access, reasonable 
operational conditions, and limitations contained in Sec. 284.7 (b), 
(c), and (f) apply to pipelines providing interruptible service under 
this section.
* * * * *


Sec. 284.10  [Amended]

    13. In newly redesignated Sec. 284.10, paragraph (c)(6) is removed.

    14. In newly redesignated Sec. 284.12, paragraphs (c)(1)(ii) and 
(c)(2)(iii) through (v) are added to read as follows:


Sec. 284.12  Standards for pipeline business operations and 
communications.

* * * * *
    (c) * * *
    (1) * * *
    (ii) Capacity release nominations. Pipelines must permit shippers 
acquiring released capacity to submit a nomination at the earliest 
available nomination opportunity after the acquisition of capacity. If 
the pipeline requires the replacement shipper to enter into a contract, 
the contract must be issued within one hour after the pipeline has been 
notified of the release, but the requirement for contracting must not 
inhibit the ability of the replacement shipper to submit a nomination 
at the earliest available nomination opportunity.
    (2) * * *
    (iii) Imbalance management. A pipeline must provide, to the extent 
operationally practicable, parking and lending or other services that 
facilitate the ability of its shippers to manage transportation 
imbalances. A pipeline also must provide its shippers the opportunity 
to obtain similar imbalance management services from other providers 
and shall provide those shippers using other providers access to 
transportation and other pipeline services without undue discrimination 
or preference.
    (iv) Operational flow orders. A pipeline must take all reasonable 
actions to minimize the issuance and adverse impacts of operational 
flow orders (OFOs) or other measures taken to respond to adverse 
operational events on its system. A pipeline must set forth

[[Page 10221]]

in its tariff clear standards for when such measures will begin and end 
and must provide timely information that will enable shippers to 
minimize the adverse impacts of these measures.
    (v) Penalties. A pipeline may include in its tariff transportation 
penalties only to the extent necessary to prevent the impairment of 
reliable service. Pipelines may not retain net penalty revenues, but 
must credit them to shippers in a manner to be prescribed in the 
pipeline's tariff. A pipeline must provide to shippers, on a timely 
basis, as much information as possible about the imbalance and overrun 
status of each shipper and the imbalance of the pipeline's system.
* * * * *

    15. Part 284 is amended by adding Sec. 284.13 to read as follows:


Sec. 284.13  Reporting requirements for interstate pipelines.

    An interstate pipeline that provides transportation service under 
subparts B or G of this part must comply with the following reporting 
requirements.
    (a) Cross references. The pipeline must comply with the 
requirements in Part 161, Part 250, and Part 260 of this chapter, where 
applicable.
    (b) Reports on firm and interruptible services. An interstate 
pipeline must post the following information on its Internet web site, 
and provide the information in downloadable file formats, in conformity 
with Sec. 284.12 of this part, and must maintain access to that 
information for a period not less than 90 days from the date of 
posting.
    (1) For pipeline firm service and for release transactions under 
Sec. 284.8 of this part, the pipeline must post, contemporaneously with 
the execution or revision of a contract for service:
    (i) The full legal name of the shipper, and identification number, 
of the shipper receiving service under the contract, and the full legal 
name, and identification number, of the releasing shipper if a capacity 
release is involved or an indication that the pipeline is the seller of 
transportation capacity;
    (ii) The contract number for the shipper receiving service under 
the contract, and, in addition, for released transactions, the contract 
number of the releasing shipper's contract;
    (iii) The rate charged under each contract;
    (iv) The maximum rate, and for capacity release transactions not 
subject to a maximum rate, the maximum rate that would be applicable to 
a comparable sale of pipeline services;
    (v) The duration of the contract;
    (vi) The receipt and delivery points and zones or segments covered 
by the contract, including the industry common code for each point, 
zone, or segment;
    (vii) The contract quantity or the volumetric quantity under a 
volumetric release;
    (viii) Special terms and conditions applicable to a capacity 
release and special details pertaining to a pipeline transportation 
contract; and
    (ix) Whether there is an affiliate relationship between the 
pipeline and the shipper or between the releasing and replacement 
shipper.
    (2) For pipeline interruptible service, the pipeline must post on a 
daily basis:
    (i) The full legal name, and identification number, of the shipper 
receiving service;
    (ii) The rate charged;
    (iii) The maximum rate;
    (iv) The receipt and delivery points and zones or segments covered 
by the contract over which the shipper is entitled to transport gas, 
including the industry common code for each point, zone, or segment;
    (v) The quantity of gas the shipper is entitled to transport;
    (vi) Special details pertaining to the contract; and
    (vii) Whether the shipper is affiliated with the pipeline.
    (c) Index of customers. (1) On the first business day of each 
calendar quarter, an interstate pipeline must file with the Commission 
an index of all its firm transportation and storage customers under 
contract as of the first day of the calendar quarter that complies with 
the requirements set forth by the Commission. The Commission will 
establish the requirements and format for such filing. The index of 
customers must also posted on the pipeline's Internet web, in 
accordance with standards adopted in Sec. 284.12 of this part, and made 
available from the Internet web site in a downloadable format complying 
with the specifications established by the Commission. The information 
posted on the pipeline's Internet web site must be made available until 
the next quarterly index is posted.
    (2) For each shipper receiving firm transportation or storage 
service, the index must include the following information:
    (i) The full legal name, and identification number, of the shipper;
    (ii) The applicable rate schedule number under which the service is 
being provided;
    (iii) The contract number;
    (iv) The effective and expiration dates of the contract;
    (v) For transportation service, the maximum daily contract quantity 
(specify unit of measurement), and for storage service, the maximum 
storage quantity (specify unit of measurement);
    (vi) The receipt and delivery points and the zones or segments 
covered by the contract in which the capacity is held, including the 
industry common code for each point, zone, or segment;
    (vii) An indication as to whether the contract includes negotiated 
rates;
    (viii) The name of any agent or asset manager managing a shipper's 
transportation service; and
    (ix) Any affiliate relationship between the pipeline and a shipper 
or between the pipeline and a shipper's asset manager or agent.
    (3) The requirements of this section do not apply to contracts 
which relate solely to the release of capacity under Sec. 284.8, unless 
the release is permanent.
    (4) Pipelines that are not required to comply with the index of 
customers posting and filing requirements of this section must comply 
with the index of customer requirements applicable to transportation 
and sales under Part 157 as set forth under Sec. 154.111(b) and (c) of 
this chapter.
    (5) The requirements for the electronic index can be obtained from 
the Federal Energy Regulatory Commission, Division of Information 
Services, Public Reference and Files Maintenance Branch, Washington, DC 
20426.
    (d) Available capacity. (1) An interstate pipeline must provide on 
its Internet web site and in downloadable file formats, in conformity 
with Sec. 284.12 of this part, equal and timely access to information 
relevant to the availability of all transportation services, including, 
but not limited to, the availability of capacity at receipt points, on 
the mainline, at delivery points, and in storage fields, whether the 
capacity is available directly from the pipeline or through capacity 
release, the total design capacity of each point or segment on the 
system, the amount scheduled at each point or segment on a daily basis, 
and all planned and actual service outages or reductions in service 
capacity.
    (2) An interstate pipeline must make an annual filing by March 1 of 
each year showing the estimated peak day capacity of the pipeline's 
system, and the estimated storage capacity and maximum daily delivery 
capability of storage facilities under reasonably representative 
operating assumptions and the respective assignments of that capacity 
to the various firm services provided by the pipeline.
    (e) Semi-annual storage report. Within 30 days of the end of each 
complete storage injection and

[[Page 10222]]

withdrawal season, the interstate pipeline must file with the 
Commission a report of storage activity. The report must be signed 
under oath by a senior official, consist of an original and five 
conformed copies, and contain a summary of storage injection and 
withdrawal activities to include the following:
    (1) The identity of each customer injecting gas into storage and/or 
withdrawing gas from storage, identifying any affiliation with the 
interstate pipeline;
    (2) The rate schedule under which the storage injection or 
withdrawal service was performed;
    (3) The maximum storage quantity and maximum daily withdrawal 
quantity applicable to each storage customer;
    (4) For each storage customer, the volume of gas (in dekatherms) 
injected into and/or withdrawn from storage during the period; and (5) 
The unit charge and total revenues received during the injection/
withdrawal period from each storage customer, noting the extent of any 
discounts permitted during the period.

    16. In Sec. 284.102, paragraph (c) is revised to read as follows:


Sec. 284.102  Transportation by interstate pipelines.

* * * * *
    (c) An interstate pipeline that engages in transportation 
arrangements under this subpart must file reports in accordance with 
Sec. 284.13 and Sec. 284.106 of this chapter.
* * * * *

    17. In Sec. 284.106, paragraphs (b) through (c) are removed, the 
paragraph (a) designation and the associated heading are removed, and 
the section heading is revised to read as follows:


Sec. 284.106  Notice of bypass.

* * * * *

    18. In Sec. 284.221. paragraph (d)(2)(ii) is revised to read as 
follows:


Sec. 284.221  General rule; transportation by interstate pipelines on 
behalf of others.

* * * * *
    (d) * * *
    (2) * * *
    (ii) Gives notice that it wants to continue its transportation 
arrangement and will match the longest term and highest rate for its 
firm service, up to the applicable maximum rate under Sec. 284.10, 
offered to the pipeline during the period established in the pipeline's 
tariff for receiving such offers by any other person desiring firm 
capacity, and executes a contract matching the terms of any such offer. 
To be eligible to exercise this right of first refusal, the firm 
shipper's contract must be for service for twelve consecutive months or 
more at the applicable maximum rate for that service.
* * * * *

    19. In Sec. 284.223, the paragraph (a) designation is removed and 
paragraph (b) is removed.


Secs. 284.10, 284.123, 284.221, 284.261, 284.263, 284.266, and 
284.286  [Amended]

    In addition to the amendments set forth above, in 18 CFR part 284, 
the following nomenclature changes are made:
    a. In Subparts B through L, revise all references to ``Sec. 284.7'' 
to read ``Sec. 284.10'' wherever it appears in ``Secs. 284.221, 
284.261, 284.263, and 284.266.''
    b. In Subparts B through L, revise all references to ``Secs. 284.8-
284.13'' to read ``Secs. 284.7-284.9 and Secs. 284.11-284.13'' wherever 
it appears, in ``Secs. 284.261 and 284.263.''
    c. In newly redesignated Secs. 284.10(c)(1) and (c)(2), revise all 
references to ``Sec. 284.8(d)'' to read''Sec. 284.7(e)''.
    d. In Sec. 284.123 (b)(1), revise all references to ``Secs. 284.8'' 
to read''Secs. 284.7''.
    e. In Sec. 284.286(b), revise all references to 
``Secs. 284.8(b)(2)'' to read ``Secs. 284.7(b)(2)''.
    f. In section 284.286(c), revise all references to 
``Secs. 161.3(c), (e), (f), (g), and (h)'' to read ``Secs. 161.3(c), 
(e), (f), (g), (h), and (l)''.

    Note.
    The following Appendix will not appear in the Code of Federal 
Regulations.

Appendix

Comments Filed in Docket Nos. RM98-10-000 & RM98-12-000 \310\
---------------------------------------------------------------------------

    \310\ Parties filing a single document in response to the NOPR 
in Docket Nos. RM98-10-000 and the NOI in Docket No. RM98-12-000 are 
denominated as a joint filing.

------------------------------------------------------------------------
           Commenter               Abbreviation          Docket No.
------------------------------------------------------------------------
AEC Marketing (USA) Inc........  AEC.............  RM98-10-000.
Alabama Gas Corporation........  Alagasco........  RM98-10-000.
Allenergy Marketing Company,     Allenergy.......  RM98-10-000 & RM98-12-
 LLC, Enron Energy Services,                        000 (joint filing).
 Inc., Enserch Energy Services,
 Inc. and Statoil Energy, Inc.
Alliance Pipeline L.P..........  Alliance........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
AlliedSignal Inc...............  AlliedSignal I..  RM98-10-000.
AlliedSignal Inc...............  AlliedSignal II.  RM98-12-000.
Altra Energy Technologies, Inc.  Altra...........  RM98-10-000.
American Forest & Paper          AF&PA I.........  RM98-10-000.
 Association.
American Forest & Paper          AF&PA II........  RM98-12-000.
 Association.
American Gas Association.......  AGA I...........  RM98-10-000.
American Gas Association.......  AGA II..........  RM98-12-000.
American Public Gas Association  APGA............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Amoco Energy Trading             Amoco I.........  RM98-10-000.
 Corporation and Amoco
 Production Company.
Amoco Energy Trading             Amoco II........  RM98-12-000.
 Corporation, Amoco Production
 Company, Burlington Resources
 Oil & Gas Co., and Marathon
 Oil Company.
Arkansas Gas Consumers.........  Arkansas Gas      RM98-10-000.
                                  Consumers.
Arkansas Public Service          Arkansas PSC....  RM98-10-000 & RM98-12-
 Commission.                                        000 (joint filing).
Atlanta Gas Light Company......  AGLC I..........  RM98-10-000.
Atlanta Gas Light Company......  AGLC II.........  RM98-12-000.
Baltimore Gas and Electric       BG&E I..........  RM98-10-000.
 Company.
Baltimore Gas and Electric       BG&E II.........  RM98-12-000.
 Company.

[[Page 10223]]

 
Brooklyn Union Gas Company and   Brooklyn Union..  RM98-10-000 & RM98-12-
 Keyspan Gas East Corporation.                      000 (joint filing).
Canadian Association of          CAPP/ADOE.......  RM98-12-000.
 Petroleum Producers and
 Alberta Department of Energy.
City of Hamilton, Ohio.........  City of           RM98-10-000.
                                  Hamilton, Ohio.
CMS Panhandle Pipe Line          CMS Panhandle...  RM98-10-000 & RM98-12-
 Companies.                                         000 (joint filing).
Coastal Companies..............  Coastal I.......  RM98-10-000.
Coastal Companies..............  Coastal II......  RM98-12-000.
Colorado Springs Utilities.....  Colorado Springs  RM98-10-000.
                                  I.
Colorado Springs Utilities.....  Colorado Springs  RM98-12-000.
                                  II.
Columbia Gas of Kentucky, Inc.,  Columbia LDCs...  RM98-10-000 & RM98-12-
 Columbia Gas of Maryland,                          000 (joint filing).
 Inc., Columbia Gas of Ohio,
 Inc., Columbia Gas of
 Pennsylvania, Inc., and
 Columbia Gas of Virginia, Inc.
Columbia Gas Transmission        Columbia........  RM98-10-000 & RM98-12-
 Corporation and Columbia Gulf                      000 (joint filing).
 Transmission Company.
Conoco Inc.....................  Conoco..........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Consolidated Edison Company of   ConEd...........  RM98-10-000 & RM98-12-
 New York, Inc.                                     000 (joint filing).
Consolidated Natural Gas         Consolidated      RM98-10-000.
 Company.                         Natural I.
Consolidated Natural Gas         Consolidated      RM98-12-000.
 Company.                         Natural II.
Consumers Energy Company.......  Consumers Co....  RM98-12-000.
Cove Point LNG Limited           Cove Point......  RM98-10-000.
 Partnership.
Delta Natural Gas Company......  Delta...........  RM98-10-000.
Duke Energy Trading and          Duke Energy.....  RM98-10-000 & RM98-12-
 Marketing, LLC.                                    000 (joint filing).
Dynegy Inc.....................  Dynegy..........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Edison Electric Institute......  EEI.............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
El Paso Energy Corporation       El Paso Energy..  RM98-10-000 & RM98-12-
 Interstate Pipelines.                              000 (joint filing).
El Paso Natural Gas Company....  El Paso Natural.  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Enron Capital & Trade            Enron Capital...  RM98-10-000 & RM98-12-
 Corporation.                                       000 (joint filing).
Enron Interstate Pipelines.....  Enron Pipelines.  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Entergy Services, Inc..........  Entergy.........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Exxon Corporation..............  Exxon...........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Fertilizer Institute...........  Fertilizer        RM98-10-000 & RM98-12-
                                  Institute.        000 (joint filing).
Florida Cities.................  Florida Cities..  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Florida Department of            Florida DMS.....  RM98-10-000.
 Management Services.
Foothills Pipe Lines Ltd.......  Foothills.......  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
FPL Group, Inc.................  FPL.............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Illinois Commerce Commission...  Illinois          RM98-10-000 & RM98-12-
                                  Commerce Comm.    000 (joint filing).
Illinois Municipal Gas Agency..  IMGA............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
IMD Storage, Transportation and  IMD.............  RM98-10-000 & RM98-12-
 Asset Management Company, LLC.                     000 (joint filing).
Independent Oil and Gas          IOGA-PA.........  RM98-10-000 and RM98-
 Association of Pennsylvania.                       12-000 (joint
                                                    filing).
Independent Oil and Gas          IOGA-WV.........  RM98-10-000 & RM98-12-
 Association of West Virginia.                      000 (joint filing).
Independent Oil and Gas          IOGA-NY.........  RM98-10-000 & RM98-12-
 Association of New York.                           000 (joint filing).
Independent Oil and Gas          IOGA-KY.........
 Association of Kentucky.
Independent Petroleum            IPAA............  RM98-10-000 & RM98-12-
 Association of America.                            000 (joint filing).
Indicated Shippers.............  Indicated         RM98-10-000 & RM98-12-
                                  Shippers.         000 (joint filing).
Interstate Natural Gas           INGAA...........  RM98-10-000 & RM98-12-
 Association of America.                            000 (joint filing).
Iowa Utilities Board...........  Iowa............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
John A. Bell, Jr...............  John A. Bell, Jr  RM98-10-000.

[[Page 10224]]

 
K N Pipelines, Inc.............  K N.............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Koch Gateway Pipeline Company..  Koch I..........  RM98-10-000.
Koch Gateway Pipeline Company..  Koch II.........  RM98-12-000.
Louisville Gas and Electric      Louisville......  RM98-10-000 & RM98-12-
 Company (Jan. & April).                            000 (joint filing).
Market Hub Partners, L.P.......  Market Hub        RM98-10-000 & RM98-12-
                                  Partners.         000 (joint filing).
Michigan Consolidated Gas        MichCon.........  RM98-10-000 & RM98-12-
 Company.                                           000 (joint filing).
Midland Cogeneration Venture     Midland.........  RM98-10-000 & RM98-12-
 Limited Partnership.                               000 (joint filing).
Millennium Pipeline Company,     Millennium......  RM98-10-000 & RM98-12-
 L.P.                                               000 (joint filing).
Minnesota Department of Public   Minnesota.......  RM98-10-000 & RM98-12-
 Service.                                           000 (joint filing).
Mississippi Independent........  Mississippi       RM98-10-000.
                                  Independent.
Mississippi Valley Gas Company,  Mississippi       RM98-10-000 & RM98-12-
 Willmut Gas Company, City of     Valley.           000 (joint filing).
 Vicksburg, Mobile Gas Service
 Corporation, Wheeler Basin
 Natural Gas Company, Clarke-
 Mobile Counties Gas District.
National Association of State    NASUCA..........  RM98-10-000 & RM98-12-
 Utility Consumer Advocates.                        000 (joint filing).
National Association of          NARUC...........  RM98-10-000 & RM98-12-
 Regulatory Utility                                 000 (joint filing).
 Commissioners.
National Energy Marketers        NEMA............  RM98-10-000 & RM98-12-
 Association.                                       000 (joint filing).
National Fuel Gas Distribution.  National Fuel     RM98-10-000 & RM98-12-
                                  Distribution.     000 (joint filing).
National Fuel Gas Supply         National Fuel...  RM98-10-000.
 Corporation.
Natural Gas Supply Association.  NGSA............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
New England Gas Distributors...  New England.....  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
New York Mercantile Exchange...  NYMEX...........  RM98-10-000.
Nicor Gas......................  Nicor...........  RM98-10-000.
Nisource, Inc..................  Nisource........  RM98-10-000.
North Carolina Natural Gas       NC Natural Gas..  RM98-10-000 & RM98-12-
 Corporation.                                       000 (joint filing).
Northern Municipal Distributors  Northern          RM98-10-000.
 Group and The Midwest Region     Municipal I.
 Gas Task Force Association.
Northern Municipal Distributors  Northern          RM98-12-000.
 Group and The Midwest Region     Municipal II.
 Gas Task Force Association.
Northwest Industrial Gas Users.  NWIGU...........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Northwest Natural Gas Company..  NW Natural......  RM98-12-000.
Ohio Oil & Gas Association.....  OOGA............  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Oklahoma Independent Petroleum   OIPA............  RM98-10-000 & RM98-12-
 Association.                                       000 (joint filing).
Paiute Pipeline Company........  Paiute..........  RM98-10-000.
PanCanadian Petroleum Limited    PanCanadian.....  RM98-10-000 & RM98-12-
 and PanCanadian Energy                             000 (joint filing).
 Services, Inc.
Peco Energy Company............  Peco............  RM98-12-000.
Pennsylvania Office of Consumer  Penn./Ohio        RM98-10-000 & RM98-12-
 Advocate and the Ohio            Advocate.         000 (joint filing).
 Consumers' Counsel.
Pennsylvania Oil & Gas           Penn. Oil & Gas   RM98-10-000 & RM98-12-
 Association.                     Assoc.            000 (joint filing).
Pennsylvania Public Utility      Penn. PUC.......  RM98-10-000 & RM98-12-
 Commission.                                        000 (joint filing).
Peoples Energy Corporation.....  Peoples Energy I  RM98-10-000.
Peoples Energy Corporation.....  Peoples Energy    RM98-12-000.
                                  II.
Pepco Energy Company...........  Pepco...........  RM98-12-000.
PG&E Corporation...............  PG&E............  RM98-10-000 and RM98-
                                                    12-000 (joint
                                                    filing).
Philadelphia Gas Works.........  Philadelphia Gas  RM98-10-000 & RM98-12-
                                  Works.            000 (joint filing).
Piedmont Natural Gas Company,    Piedmont/UGI....  RM98-10-000 & RM98-12-
 Inc. and UGI Utilities, Inc.                       000 (joint filing).
Pipeline Transportation          P/L Customer      RM98-10-000 & RM98-12-
 Customer Coalition.              Coalition.        000 (joint filing).
Portland Natural Gas             PNGTS...........  RM98-10-000.
 Transmission System.
Process Gas Consumers Group--    Process Gas       RM98-10-000.
 American Iron and Steel          Consumers I.
 Institute, Georgia Industrial
 Group, Aluminum Company of
 America and United States
 Gypsum Company.

[[Page 10225]]

 
Process Gas Consumers Group--    Process Gas II    RM98-12-000.
 American Iron and Steel          Consumers.
 Institute, Georgia Industrial
 Group, Aluminum Company of
 America and United States
 Gypsum Company.
Production Area Rate Design      Production Area   RM98-10-000 & RM98-12-
 Group.                           Group.            000 (joint filing).
Proliance Energy, LLC..........  Proliance.......  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Public Service Commission of     PSC of New York   RM98-10-000.
 the State of New York.           I.
Public Service Commission of     PSC of New York   RM98-12-000.
 the State of New York.           II.
Public Service Commission of     PSC of Kentucky.  RM98-10-000 & RM98-12-
 the Commonwealth of Kentucky.                      000 (joint filing).
Public Service Commission of     PSC of Wisconsin  RM98-10-000.
 Wisconsin.                       I.
Public Service Commission of     PSC of Wisconsin  RM98-12-000.
 Wisconsin.                       II.
Public Service Electric and Gas  PSE&G...........  RM98-10-000 & RM98-12-
 Company.                                           000 (joint filing).
Public Utilities Commission of   CPUC............  RM98-10-000 & RM98-12-
 the State of California.                           000 (joint filing).
Public Utilities Commission of   PUC of Ohio.....  RM98-10-000.
 Ohio.
Regulatory Studies Program of    Mercatus........  RM98-10-000 & RM98-12-
 the Mercatus Center, George                        000 (joint filing).
 Mason University.
Reliant Energy Gas Transmission  Reliant.........  RM98-10-000 & RM98-12-
 Company and Mississippi River                      000 (joint filing).
 Transmission Corporation.
Sempra Energy..................  Sempra Energy...  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Shell Energy Services Company,   Shell...........  RM98-10-000.
 LLC.
Sithe Energies, Inc............  Sithe...........  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Southern Company Energy          Southern Co.      RM98-10-000.
 Marketing L.P.                   Energy.
Southern Company Services, Inc.  Southern Co.      RM98-10-000 & RM98-12-
                                  Services.         000 (joint filing).
Southern Natural Gas Company...  Southern Natural  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Southwest Gas Corporation......  Southwest Gas...  RM98-10-000 & RM98-12-
                                                    000 (joint filing).
Tejas Offshore Pipelines, LLC..  Tejas I.........  RM98-10-000.
Tejas Offshore Pipelines, LLC..  Tejas II........  RM98-12-000.
Tennessee Valley Authority.....  TVA.............  RM98-10-000 and RM98-
                                                    12-000 (joint
                                                    filing).
Texas Eastern Transmission       TETCO/Algonquin.  RM98-10-000 & RM98-12-
 Corporation and Algonquin Gas                      000 (joint filing).
 Transmission Company.
The Customer Coalition.........  The Customer      RM98-10-000.
                                  Coalition.
The Railroad Commission of       TRRC............  RM98-10-000 & RM98-12-
 Texas.                                             000 (joint filing).
TransCanada Gas Services, A      TransCanada.....  RM98-10-000 & RM98-12-
 Division of TransCanada                            000 (joint filing).
 Energy, LTD.
TransCapacity Limited            TransCapacity...  RM98-10-000.
 Partnership.
UGI Utilities, Inc.............  UGI.............  RM98-10-000 and RM98-
                                                    12-000 (joint
                                                    filing).
Vector Pipeline L.P............  Vector..........  RM98-10-000 & RM98-12-
                                                    000 (joint filing)
Washington Gas Light Company...  WGL I...........  RM98-10-000.
Washington Gas Light Company...  WGL II..........  RM98-12-000.
Williams Companies, Inc........  Williams I......  RM98-10-000.
Williams Companies, Inc........  Williams II.....  RM98-12-000.
Williston Basin Interstate       Williston Basin.  RM98-10-000 & RM98-12-
 Pipeline Company.                                  000 (joint filing).
Wisconsin Distribution Group...  Wisconsin         RM98-10-000 & RM98-12-
                                  Distributors.     000 (joint filing).
------------------------------------------------------------------------
Hebert, Commissioner, concurring.

    Without question, the steps taken in this rule, with one 
exception, are a significant victory for pricing flexibility 
necessary to stride confidently toward a market-based approach for 
transportation of natural gas instead of retaining elements of price 
controls.
    The removal of the price cap on capacity release transactions 
provides multiple benefits to the marketplace. Capacity release 
transactions become a viable alternative to bundled sales of natural 
gas. The incentive provided by the alternative will result in a more 
efficient use of existing capacity, storage facilities and peak 
shaving devices. Revenues resulting from capacity release 
transactions can materially benefit customers by reducing cost 
shifting. Peak and off-peak rates should also benefit customers in 
future rate proceedings through minimizing discounts during off-peak 
periods.
    Through this rule, I believe this Commission will gain a better 
understanding of the value of pipeline capacity and will provide 
proper pricing alternatives to the industry. It remains vital to the 
consumer that market demand for capacity not be ignored, nor 
unaddressed, in our efforts to ensure a reliable and sufficient 
infrastructure for the transportation of natural gas. I can only 
hope this Commission will

[[Page 10226]]

embrace the need for capacity, specifically the northeast. In light 
of the concerns vehemently expressed by Secretary Richardson on the 
rising price of heating oil in the northeast, this Commission must 
act in a reasonable manner and with the interest of the consumers at 
heart, wherever they are located. Delay, as well as unnecessary 
environmental and economic hurdles remain unacceptable.
    Further, the two-year waiver period concerning the removal of 
the price caps on capacity release transactions is also 
unacceptable. The data provided to me appears clear and convincing 
that removal of the price caps is a positive and substantiated step 
designed to benefit the consumer. The studies, contained in this 
docket as well as the information gathered by the staff, are more 
than sufficient to justify a permanent removal of the price caps. I 
will continue to advocate this position in order to ultimately 
remove the price caps of capacity release transactions. This 
Commission needs to move toward price reforms, not price controls.
    Therefore, I respectfully concur.

Commissioner Curt L. He bert, Jr.
[FR Doc. 00-3595 Filed 2-24-00; 8:45 am]
BILLING CODE 6717-17-P