42982 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

31See Kern River Gas Transmission Company, 58

FERC 61,073; Mojave Pipeline Company, 58 FERC

61,074 (1992); Florida Gas Transmission Company,

62 FERC 61,024 (1993), Order Granting and

Denying Rehearing and Granting Clarification FERC

61,093 (1993); TransColorado Gas Transmission

Company, 67 FERC 61,301 (1994), Order Granting

in Part and Denying in Part Rehearing and Granting

Clarification, 69 FERC 61,066 (1994); Sunshine

Interstate Transmission Company, 67 FERC 61,229

(1994); and Mojave Pipeline Company, 69 FERC

61,244 (1994), Order Granting Rehearing in Part,

Denying Rehearing in Part and Modifying Prior

Order, 70 FERC 61,296 (1995).

though the asset will physically provide

benefits for longer than the initial

contract term and to other customers.

This policy gives prospective shippers

an opportunity to influence a significant

part of their rates (i.e., the depreciation

component) by their choice of contract

length. Continuation of this policy, or a

broader application of it, could also

help resolve the ‘‘need’’ issue discussed

below by encouraging a greater shipper

commitment before capacity is built.

The Commission could both encourage

longer term contracting for new capacity

and shelter existing ratepayers from

capacity turnback by declaring that new

pipeline costs are fully recoverable over

the contract term that supports its

construction. However, on the other

hand, such a policy could make the

rates too high to make the project

economically viable, and also results in

a situation where later ratepayers would

not pay any depreciation component for

use of the facilities.

The Commission seeks comments on

what criteria it should use to determine

a depreciation period and rate for

ratemaking purposes. Parties may

address some or all of the following

questions.

Given that the industry will stay in a

partially cost-based rate regulated

environment (i.e., for determining

recourse rates), on what criteria should

the Commission base a depreciation

rate? Would customers be willing to

sign up for life-of-the-facilities

contracts, thus promoting long-term

service? Is it fair to require initial

customers who sign up for less than the

life-of-the-facilities contracts to pay for

all costs of the asset over that shorter

term since future customers may use

and benefit from the facilities? If the

initial customers are unwilling to pay

the full costs, should the pipeline be

built?

If use of the economic life is more

suitable to foster fairness between new

and existing customers, how should the

economic life or benefit period be

determined? Should the economic life

be viewed as the expected period of

time customers will use the asset or

should it be viewed as the known

period of time that customers contracted

for using the asset? What amount of

depreciation, if any, should be allocated

to short-term services? What criteria

should be used to make this

determination? Will the criteria be

sufficiently objective to avoid claims of

cross-subsidization? How should

depreciation be treated when some of

the rates are market-based? To what

extent does depreciation flexibility aid

pipelines having cost recovery

problems? Lastly, how should capacity

be priced after it has been fully

depreciated by its first generation of

customers?

For cost-of-service purposes, these

questions are not easily answered. For

general purpose financial accounting

and reporting, the Commission has

required pipelines to depreciate

facilities over their economic useful life

and record regulatory assets and

liabilities for the differences between

ratemaking depreciation and accounting

depreciation.31 What are the

implications of different depreciation

rates for cost-of-service rate purposes

versus accounting purposes if some

portion of pipeline rates is not based on

traditional cost-of-service ratemaking?

Will pipelines be able to continue to

record the difference as a regulatory

asset or liability? What about income tax

related issues?

V. Comment Procedures

The Commission invites interested

persons to submit written comments on

the matters and issues discussed in this

notice of inquiry, and any related

matters or alternatives that commenters

may wish to discuss. An original and 14

copies of comments must be filed with

the Commission no later than November

9, 1998. Comments should be submitted

to the Office of the Secretary, Federal

Energy Regulatory Commission, 888

First Street, NE, Washington, DC 20426,

and should refer to Docket No. RM98–

12–000. All written comments will be

placed in the Commission’s public files

and will be available for inspection in

the Commission’s Public Reference

Room at 888 First Street, NE,

Washington, DC 20426, during regular

business hours.

Additionally, comments should be

submitted electronically. Commenters

are encouraged to file comments using

Internet E-Mail. Comments should be

submitted through the Internet by EMail to comment.rm@ferc.fed.us in the

following format: on the subject line,

specify Docket No. RM98–12–000; in

the body of the E-Mail message, specify

the name of the filing entity and the

name, telephone number and E-Mail

address of a contact person; and attach

the comment in WordPerfect  6.1 or

lower format or in ASCII format as an

attachment to the E-Mail message. The

Commission will send a reply to the EMail to acknowledge receipt. Questions

or comments on electronic filing using

Internet E-Mail should be directed to

Marvin Rosenberg at 202–208–1283, EMail address

marvin.rosenberg@ferc.fed.us.

Commenters also can submit

comments on computer diskette in

WordPerfect  6.1 or lower format or in

ASCII format, with the name of the filer

and Docket No. RM98–10–000 on the

outside of the diskette.

By direction of the Commission.

David P. Boergers,

Acting Secretary.

[FR Doc. 98–20996 Filed 8–10–98; 8:45 am]

BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Parts 161, 250, and 284

[Docket No. RM98–10–000]

Regulation of Short-Term Natural Gas

Transportation Services

July 29, 1998.

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Notice of proposed rulemaking.

SUMMARY: The Federal Energy

Regulatory Commission (Commission) is

proposing an integrated package of

revisions to its regulations governing

interstate natural gas pipelines to reflect

the changes in the market for short-term

transportation services on pipelines.

Under the proposed approach, costbased regulation would be eliminated

for short-term transportation and

replaced by regulatory policies intended

to maximize competition in the shortterm transportation market, mitigate the

ability of firms to exercise residual

monopoly power, and provide

opportunities for greater flexibility in

the provision of pipeline services. The

proposed changes include initiatives to

revise pipeline scheduling procedures,

receipt and delivery point policies, and

penalty policies, to require pipelines to

auction short-term capacity, to improve

the Commission’s reporting

requirements, to permit pipelines to

negotiate rates and terms of services,

and to revise certain rate and certificate

policies that affect competition.

DATES: Comments are due November 9,

1998.
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42983

1Secondary Market Transactions on Interstate

Natural Gas Pipelines, Notice of Proposed

Rulemaking, 61 FR 41046 (Aug. 7, 1996), IV FERC

Stats. & Regs. Proposed Regulations ¶ 32,520 (Jul.

31, 1996).

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

Erica Yanoff, Office of the General

Counsel, Federal Energy Regulatory

Commission, 888 First Street, NE,

Washington, DC 20426. (202) 208–

0708

Ingrid Olson, Office of the General

Counsel, Federal Energy Regulatory

Commission, 888 First Street, NE,

Washington, DC 20426. (202) 208–

2015.

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in the Public Reference Room at 888

First Street, NE, Room 2A, Washington,

DC 20426.

The Commission Issuance Posting

System (CIPS) provides access to the

texts of formal documents issued by the

Commission. CIPS can be accessed via

Internet through FERC’s Homepage

(http://www.ferc.fed.us) using the CIPS

Link or the Energy Information Online

icon. The full text of this document will

be available on CIPS in ASCII and

WordPerfect 6.1 format. CIPS is also

available through the Commission’s

electronic bulletin board service at no

charge to the user and may be accessed

using a personal computer with a

modem by dialing 202–208–1397, if

dialing locally, or 1–800–856–3920, if

dialing long distance. To access CIPS,

set your communications software to

19200, 14400, 12000, 9600, 7200, 4800,

2400, or 1200 bps, full duplex, no

parity, 8 data bits and 1 stop bit. User

assistance is available at 202–208–2474

or by E-mail to

CipsMaster@FERC.fed.us.

This document is also available

through the Commission’s Records and

Information Management System

(RIMS), an electronic storage and

retrieval system 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. RIMS is available

in the Public Reference Room or

remotely via Internet through FERC’s

Homepage using the RIMS link or the

Energy Information Online icon. User

assistance is available at 202-208–2222,

or by E-mail to

RimsMaster@FERC.fed.us.

Finally, the complete text on diskette

in WordPerfect format may be

purchased from the Commission’s copy

contractor, La Dorn System Corporation.

La Dorn Systems Corporation is located

in the Public Reference Room at 888

First Street, NE, Washington, DC, 20426.

Table of Contents

I. Reexamination of the Transportation

Market

A. The Developing Short-term Market

B. Implications for Commission

Regulatory Policies of the Changing

Nature of Short-term Markets

II. Proposed Change in Regulatory

Approach

A. A Different Model for Regulating the

Short-term Market

B. Legal Basis for the Proposed

Regulatory Change

C. Interrelated Proposals for Regulatory

Change

III. Creating Greater Competition Among

Short-term Service Offerings

A. Nomination Equality

B. Segmentation and Flexibility of

Receipt and Delivery Points

C. Capacity Auctions

D. Information Reporting and Remedies

for the Exercise of Market Power

IV. Penalties and Operational Flow Orders

A. Pipelines Should Provide, on a Timely

Basis, as Much Imbalance and Overrun

Information as Possible

B. Transportation Penalties Must Be

Necessary and Appropriate to Protect

System Operations

C. Pipelines Must Provide Services, to the

Extent Operationally Feasible, That

Facilitate Imbalance Management

D. Pipelines Must Adopt Incentives and

Procedures That Minimize the Use and

Adverse Impact of OFOs

V. Negotiated Rates and Services

A. Guiding Principles

B. Implementation of the Negotiated

Rates and Services Policy

VI. Long-term Services

A. The Interaction Between Long-term

and Short-term Services

B. Specific Impediments to Long-term

Contracts

C. New Capacity Certificate Issues

VII. Reorganization of Part 284 Regulations

VIII. Information Collection Statement

IX. Environmental Analysis

X. Regulatory Flexibility Act Certification

XI. Comment Procedures

Notice of Proposed Rulemaking

Five years have passed since

Congress, in the Wellhead Decontrol

Act, completed the decontrol of natural

gas prices. Six years ago the

Commission, in Order No. 636,

unbundled the purchase of gas from the

purchase of gas transportation. Since

then, the natural gas market has

changed from a largely regulated market

to one increasingly driven by market

forces. In order to continue to fulfill its

statutory duties to ensure just and

reasonable rates in the rapidly evolving

gas market of today, the Commission

has engaged in a comprehensive, critical

examination of the regulatory

assumptions and procedures that it has

been using to determine whether other

regulatory approaches would better fit

the needs of this changing marketplace.

Since Order No. 636, the natural gas

marketplace has fundamentally

changed. Active short-term markets

have begun to develop. Shippers are

trading gas at market centers on a daily

or sometimes an intra-day basis with

prices varying from day-to-day. Prior to

Order No. 636, the majority of contracts

were long-term with less price volatility.

As local distribution companies (LDCs)

unbundle the gas commodity from

transportation, new players, such as

electric cogenerators, industrial endusers, and small businesses (such as

restaurants) are entering the gas

marketplace with gas and transportation

needs different from those of the LDCs

that previously transported and sold the

majority of gas. Increasingly, LDC

unbundling is even bringing

homeowners into the gas marketplace.

These new entrants often use marketers

or other facilitators to arrange for their

gas supplies on a delivered basis.

The use of transportation capacity

also has changed. Before Order No. 636,

shippers could acquire transportation

only from the pipeline. They could buy

gas from the pipeline at the city-gate

either on a short-term or long-term

basis, acquire long-term firm capacity

from the pipelines, often with 20-year

contracts, or purchase short-term

interruptible capacity. In today’s

market, shippers have additional

options. They can acquire capacity from

other firm capacity holders through the

capacity release market. They also can

obtain capacity indirectly by purchasing

gas bundled with transportation from

producers, marketers, or aggregators for

one delivered price (often called a gray

market sale).

The changes in the short-term market

have caused the Commission to closely

examine its regulatory structure to see

whether it provides a good fit with the

developing short-term market. The

Commission has received comments on

the impact of these changes through a

number of proceedings, among them a

prior Notice of Proposed Rulemaking

(NOPR) on the secondary market,1 a

request for comments on whether

pipelines should be permitted to
42984 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

2Alternatives 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, at 61,242 (1996).

3 Issues and Priorities for the Natural Gas

Industry, PL97–1–000 (conference held May 29–30,

1997).

4See 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, 57 FR 13267, FERC Stats.

& Regs. Regulations Preambles [Jan. 1991–June

1996] ¶ 30,939, at 30,408 (Apr. 8, 1992), Order No.

636–A, 57 FR 36128 (Aug. 12, 1992), FERC Stats.

& Regs. Regulations Preambles [Jan. 1991–June

1996] ¶ 30,950, at 30,570 (Aug. 3, 1992) (concerns

about providing transportation service equal in

reliability to bundled sales service).

5See S. Walsh, A Hot (and Cold) New Investment

Opportunity, Washington Post, July 4, 1998, C12

(Business) (discussing development of new weather

derivative to enable companies to hedge against

abnormal weather patterns).

negotiate terms of service,2 and an

industry conference on issues and

priorities in the gas industry.3

Upon review of the changes in the

market and the comments it has

received, the Commission is concerned

that its current regulatory approach,

which relies on a constant maximum

rate in the short-term market, may not

be the best approach in light of the

variability in pricing in the short-term

market. Due to the variability in

transportation value, the current

approach may not provide the best

protection against the exercise of market

power during peak and off-peak periods.

Or, the protection it does provide may

come at the expense of a more efficient

capacity market during peak periods,

when shippers are most in need of a

market that works efficiently.

The Commission recognizes that

despite all the competitive

improvements in the short-term market,

the short-term market still may not be

fully competitive. Thus, the

Commission must continue to have a

regulatory presence in the short-term

market to protect against the exercise of

market power and undue

discrimination.

The Commission is, therefore,

proposing in this NOPR a different

approach for regulating the short-term

transportation market which is designed

to permit the market to function

efficiently while continuing to protect

shippers against the exercise of market

power. This approach has a number of

objectives. It is designed to improve

competition in short-term markets by

facilitating the trading of capacity, so

that shippers will have a larger number

of capacity alternatives from which to

choose. By expanding options, it seeks

to help reduce the number of captive

customers. Additionally, it seeks to

provide the opportunity for greater

flexibility in pipeline contracting

practices so that pipelines can design

services that better meet the needs of

existing and new players in the gas

marketplace.

The proposal uses different regulatory

structures for short-term and long-term

markets. Long-term transportation

prices (i.e., transportation of one-year or

longer) would continue to be regulated

under a cost-based regulatory regime to

protect against the exercise of pipeline

monopoly power. For short-term

transportation services, however, costbased regulation would be eliminated.

In its place, the Commission proposes to

regulate the short-term market through

regulatory policies that are intended to

maximize competition in the short-term

transportation market, to mitigate the

ability of firms to exercise residual

monopoly power, and to improve the

ability of market participants and the

Commission to monitor the market for

exercises of monopoly power or undue

discrimination. The goal of this

approach to the short-term market is to

ensure that the Commission’s regulatory

policy does not inhibit competitive

market forces from creating efficient

capacity markets, while still providing

captive customers and others with

protection against the exercise of market

power in the transportation market.

Specifically, to maximize competition

(which is the best protection against the

exercise of market power) the

Commission is proposing in this NOPR

to revise pipeline nomination and

scheduling procedures, and flexible

receipt and delivery point policies so

that capacity release can compete on a

more equal footing with pipeline

capacity. To further mitigate the

exercise of market power and the

potential for undue discrimination, the

Commission is proposing to require that

all short-term capacity be sold through

capacity auctions. To improve shippers’

and the Commission’s ability to monitor

the marketplace the Commission is

proposing changes to its reporting

requirements. To improve competition

across the pipeline grid, the

Commission is making proposals to

change pipeline penalty procedures so

that penalties, although necessary to

deter conduct inimical to system

operations, do not unnecessarily limit

shippers’ competitive alternatives.

At the same time, the Commission

recognizes that changes in the shortterm market also influence shippers’

decisions in the long-term market. For

example, the value of long-term capacity

lies in the guarantee of capacity at a

relatively stable price as compared with

buying capacity at the more volatile

short-term price. Long-term contracts,

therefore, are a means by which

shippers and pipelines can manage the

risks inherent in the short-term market.

To foster greater innovation in

pipeline services and to permit

pipelines and shippers to better allocate

the risks of long-term contracts, the

Commission is proposing to allow

pipelines’ greater flexibility in

negotiating contracts with individual

shippers, subject to criteria that will

protect captive customers against the

risk of undue discrimination. Further, to

create a more efficient marketplace,

regulatory policies should not affect the

allocation of risk between acquiring

short-term or long-term capacity. As

part of this integrated package,

therefore, the Commission is proposing

changes to some of its policies

governing long-term contracts to ensure

that these policies do not unfairly bias

shippers’ contracting decisions. The

Commission also is considering whether

changes to its policies regarding

authorization for new construction are

needed so that these policies do not

unnecessarily limit competition.

The Commission recognizes that the

impact on the long-term market of the

changes in the short-term market go

beyond the proposals outlined above.

Therefore, in a Notice of Inquiry (NOI)

issued contemporaneously with this

NOPR, the Commission asks for

additional comment on the future

direction of its policies for pricing of

long-term capacity.

I. Reexamination of the Transportation

Market

A. The Developing Short-term Market

Natural gas markets have developed

rapidly since wellhead price

deregulation and unbundling of

pipeline merchant and transportation

services. In many ways, the gas market

performs very well, without the loss of

reliability that many feared when Order

No. 636 was being contemplated.4

Gas commodity markets have arisen,

along with market mechanisms to

enable consumers to manage price risk

for the gas.5 There are monthly and

growing daily spot markets for gas

supplies which enable shippers not only

to buy their own gas supplies at the

wellhead, but to trade gas among

themselves on a daily or even more

frequent basis. Many of these spot

markets are organized around market

centers that facilitate trading of gas

across pipelines as well as providing a

variety of new services, such as storage,

wheeling, parking, lending, electronic

gas trading, and tracking of gas title
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42985

6 Department of Energy/Energy Information

Administration, Pub. No. DOE/EIA–0560(96),

Natural Gas 1996 Issues and Trends, Chapter, The

Emergence of Natural Gas Market Centers (1996).

7See Standards For Business Practices Of

Interstate Natural Gas Pipelines, Order No. 587, 61

FR 39053 (Jul. 26, 1996), III FERC Stats. & Regs.

Regulations Preambles ¶ 31,038 (Jul. 17, 1996)

(requiring pipelines to provide pooling services).

8See Moss Bluff Hub Partners, 80 FERC ¶ 61,181

(1997) (firm storage and interruptible hub services);

Egan Hub Partners, L.P., 77 FERC ¶ 61,016 (1996)

firm storage and interruptible hub services).

9See Mojave Pipeline Company, 79 FERC

¶ 61,347 (1997); Colorado Interstate Gas Company,

83 FERC ¶ 61,273 (1998).

10See Koch Gateway Pipeline Company, 66 FERC

¶ 61,385 (1994) (firm and interruptible storage);

New York State Electric Gas Corporation, 81 FERC

¶ 61,020 (1997) (issuing certificate).

11 Department of Energy/Energy Information

Administration, Pub. No. DOE/EIA–0618(98),

Deliverability on the Interstate Natural Gas Pipeline

System 88–89 (1998).

12 Id. at 82 (representing about 16% of the gas

delivered for market).

13 Id. at 83.

14 Id. at 85–86 (2,960 trillion Btu from November

to March 1996–97).

15 Id. at 85 (about 16% of total throughput for the

12 months ending March 31, 1997).

16 Id. at 87 (2,000 TBtu moved during heating

season).

17See Order No. 636, FERC Stats. & Regs.

Regulations Preambles [Jan. 1991–June 1996]

¶ 30,939, at 30,410.

18Standards For Business Practices Of Interstate

Natural Gas Pipelines, Order No. 587, 61 FR 39053

(Jul. 26, 1996), III FERC Stats. & Regs. Regulations

Preambles ¶ 31,038 (Jul. 17, 1996), Order No. 587–

B, 62 FR 5521 (Feb. 6, 1997), III FERC Stats. & Regs.

Regulations Preambles ¶ 31,046 (Jan. 30, 1997),

Order No. 587–C, 62 FR 10684 (Mar. 10, 1997), III

FERC Stats. & Regs. Regulations Preambles ¶ 31,050

(Mar. 4, 1997), Order No. 587–G, 63 FR 20072 (Apr.

23, 1998), III FERC Stats. & Regs. Regulations

Preambles ¶ 31,062 (Apr. 16, 1998).

19Standards For Business Practices Of Interstate

Natural Gas Pipelines, Order No. 587–H, 63 FR

39509 (Jul. 23, 1998), 84 FERC ¶ 61,031 (July 15,

1998).

20El Paso Natural Gas Company, 81 FERC

¶ 61,174, at 61,760 (1997) (approving a limit on

pool to pool transfers because pipeline could not

handle the volume of transactions under new

scheduling timeline).

21See, e.g., Gas Daily, March 2, 1998, at 1–2;

Natural Gas Intelligence, Jan. 5, 1998, at 4; Natural

Gas Week, Jan. 12, 1998, at 12, 17, 20–21.

transfers.6 Active forward markets also

have developed to enable gas consumers

to hedge against price risk. The New

York Mercantile Exchange (NYMEX)

launched its natural gas futures contract

in 1992, and it is very heavily traded.

Along with the development of a

more liquid commodity market,

shippers’ transportation options have

expanded. In the past, shippers could

purchase capacity only from the

pipeline and had, for the most part, only

two transportation choices: long-term

firm capacity or interruptible service.

Pipeline offerings have expanded as

well, with pipelines offering short-term

firm transportation service, pooling,7

hub services,8 parking and loan

services,9 and both short-term and longterm storage services.10

Non-traditional players also have

entered the capacity market, so that

today firm shippers holding pipeline

capacity include electric utilities (21%

of total pipeline firm capacity),

industrial end-users (5%), marketers

(17%), pipelines (7%), and others,

including producers (6%) in addition to

the traditional LDCs (44%). While many

of these shippers still hold pipeline

contracts longer than a year, short-term

firm contracts are rising in significance.

Among the shipper groups, marketers

are the largest users of short-term

capacity, with over three-quarters of the

total.11

In today’s market, shippers also have

the added option of buying firm

capacity released by other shippers in a

variety of ways (such as on a fixed, or

volumetric basis, or with other release

conditions, including provisions for

handling capacity recalls). Since its

inception in 1992, capacity release

transactions have been growing

dramatically.12 For instance, the amount

of capacity held by replacement

shippers for the 12 month period ending

March 1997, totaled 7.4 quadrillion Btu,

a 22% percent increase over the

previous 12 month period and almost

double the level for the 12 months

ending March 1995.13 While the amount

of capacity held by replacement

shippers declined during the heating

season, EIA reports it still represents a

sizable amount.14 Despite the growing

use of released capacity, interruptible

pipeline service also continues to be a

viable service option, maintaining a

relatively constant share of

throughput.15 As in the case of released

capacity, EIA reports that interruptible

service is available during the heating

season.16

In addition to acquiring capacity from

pipelines and releasing shippers,

purchasers in the short-term market

have other capacity options. Implicit in

the Commission’s decision to unbundle

the gas commodity from transportation

was a recognition that the market would

develop so that customers who did not

want to assume the responsibility of

purchasing or transporting their own gas

could purchase delivered gas from

marketers or third parties with the

marketer providing all or a portion of

the needed transportation, for example

to a nearby market center.17 Capacity

rights holders can now sell gas as a

commodity in downstream markets at

market-based prices.

Further, as a result of Commission

initiatives, the gas industry, through the

Gas Industry Standards Board (GISB),

has developed standards that make it

easier to move and trade gas on

individual pipeline systems and across

pipeline systems.18 These standards

establish a daily, along with an intraday, nomination schedule which permit

shippers to adjust their nominations to

conform to changes in weather and

other circumstances. The Commission

recently adopted GISB standards

providing for three intra-day

nomination opportunities.19 These

standards also significantly enhance

shipper flexibility, for example, by

giving shippers the ability to aggregate

gas supplies from numerous sources in

a pipeline pool for nomination purposes

and by allowing shippers to assign

priority rankings to gas packages.

These changes, operating together,

have changed the character of shortterm markets. Five years ago, most gas

was purchased during bid week under

monthly contracts and transportation

was arranged at the same time on a

monthly basis. Transactions occurring

outside of bid week were unusual and

were referred to as the aftermarket.

Today, daily markets for gas and

capacity are developing rapidly.

Shippers now trade gas on a daily or

even an intra-day basis at various

market centers and pipeline

interconnect points or at pipeline

pooling points. For example, at pipeline

interconnect points or at pools, there

may be repeated sales of the same gas

between producers and marketers before

the gas is scheduled for transportation.

As described in a recent proceeding,

shippers can use pooling to effectuate

gas exchanges (pool to pool transfers) as

a means of enhancing supply and

pricing options and of market hedging.20

For example, a shipper may buy gas

from a pool as insurance against a

change in its system requirements and

then sell that gas to another pool if the

load does not develop in its market.

Shippers also can take advantage of

trading opportunities by making daily or

intra-day changes to their gas

nominations to react quickly to

changing weather, changing prices or

supply sources, or other circumstances.

For instance, a shipper that loses a

supply source can submit an intra-day

nomination to change its receipt point

for gas so that it can purchase gas from

an alternate supply source. The reports

in trade publications of daily gas prices

at delivered markets are further

evidence of the increasing scope of the

developing short-term market.21

The developing gas market, however,

is in some respects still in its infancy

and there are still impediments, both

regulatory and non-regulatory, to the
42986 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

22The source for the spot price data is the Gas

Daily Weekly Weighted Average Prices ($/MMBtu).

The source for the maximum interruptible tariff rate

is from PIPELINE Grid published by the Petroleum

Information Corporation Logistics Solution. The

range of tariff rates includes the interruptible rates

from Columbia Gas Transmission Corporation

($.45/MMBtu), Tennessee Gas Pipeline Company

($.57/MMBtu), and Transcontinental Gas Pipe Line

Corporation ($.44/MMBtu).

development of a well-functioning

market. Price information, which is

crucial to a well-developed market,

could be improved. While the

Commission requires the posting of

information on capacity release

transactions, posting of pipeline

discount transactions occurs well afterthe-fact and cannot be used by shippers

to make daily market decisions.

Moreover, it is difficult for shippers to

obtain accurate information about

delivered gas transactions or the value

of transportation inherent in such

transactions. Shippers are left to

personal communication or trade

publications to determine prices at

receipt and delivery points. Acquiring

market information through personal

communication is time consuming and

expensive, particularly for small

customers who would have difficulty

canvassing a large enough number of

sources to obtain sufficient market

information. Each trade publication uses

different reporting methods. Some mix

long and short-term transactions and

some report price ranges while others

report averages, and most do not report

quantities traded.

Also, capacity markets are

fragmented. Different regulatory rules

apply to pipeline sales of interruptible

and firm capacity, capacity obtained

through release transactions, and

capacity used as part of delivered gas

transactions. For example, the

nomination and scheduling procedures

and rate regulation differ among

pipeline capacity, released capacity, and

delivered gas transactions. In addition,

different rights may apply depending on

the type of capacity a shipper tries to

acquire. Shippers purchasing released

capacity from certain firm shippers may

have to rely on alternate receipt or

delivery points, and the use of such

points are sometimes restricted by

pipelines’ tariffs.

All of these factors increase the

shippers’ transaction costs by increasing

the difficulty and risk of doing business

in the short-term market. Absent good

price and capacity information, shippers

cannot easily compare capacity

alternatives or obtain full, comparable

information about the alternatives

available at any time. This inhibits their

ability to make informed decisions

about acquiring gas and capacity and

prevents them from finding the best gas

and capacity deals available. These

costs may be particularly meaningful for

small customers, who do not have the

time and resources to unearth, through

personal contacts, the information they

need to make informed choices.

In the developing short-term market,

market forces impact regulated services.

The growing emphasis on daily

transactions means that customers are

more concerned with the daily price of

transportation capacity. For example,

many short-term decisions are based on

the delivered price for gas (including

transportation) on a daily basis. Often

narrow differences in delivered prices

may affect shippers’ decisions.

The existence of a market price for gas

at all points along the pipeline grid has

created a market-driven value for

transportation between receipt and

delivery points. In effect, the implicit

value of transportation between two

such points is the spot price of gas at the

delivery point minus the spot price of

gas at the receipt point.

This market driven value can

fluctuate widely on a daily basis. As

shown in the following example, many

such valuations remain near zero for

long periods of time, only to rise during

periods of peak demand. On this

illustration, the market-driven value of

transportation represents the difference

between the spot price for gas at the

upstream hub in Louisiana and the

delivered price for gas in the New York

downstream market. In other words, the

price for delivered gas in the

downstream New York market reflects

the spot price for gas at the upstream

hub plus the value of the transportation

needed to deliver the gas to the

downstream market. The market value

of transportation can then be compared

with the cost-based, regulated maximum

interruptible rates for the three

pipelines transporting from Louisiana to

New York (represented by the dotted

lines).22

BILLING CODE 6717–01–P
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42987

23For instance, gas from markets other than

Louisiana may have affected delivered prices in

New York, and the data contain unexplained

anomalies, such as transportation values of less

than 0, indicating that the price of gas was lower

in New York than at the receipt point in Louisiana.

During that time, either no gas moved from

Louisiana to New York or, if gas did move, the

markets were not clearing properly or the price data

were not accurate.

BILLING CODE 6717–01–C

This illustrates that the value of

transportation during the peak winter

period of 1995–1996 rose to $10/MMBtu

(20 times the maximum daily tariff rates

of between $.44 and $.57/MMBtu) and

during the 1996–1997 winter to over $1/

MMBtu (2 times the maximum tariff

rate). During non-peak periods, the

value of transportation was uniformly

below the maximum daily tariff rate.

While the illustration may not portray

precise transportation values,23 it

nonetheless does provide a picture of

the fluctuation in transportation values

over time.

The fluctuation of transportation

values raises questions about whether

the Commission’s current rate policies

are attuned to the realities of the

developing short-term market. The

Commission currently establishes a

daily maximum rate for pipeline

services and capacity release by taking

the pipelines’ annual rate and

converting it to a daily rate (by dividing

the yearly rate by 365). But this single

rate does not reflect the variability of

daily pricing in the short-term market.

While the $10 value during the 1995–

1996 may not be repeated,

transportation values during the next

winter were double the maximum rate.

These data on delivered prices, and

derived transportation values, do not

establish either the presence or absence

of market power. Delivered markets for

gas can, and probably do, coexist with

the continued exercise of market power

over transportation. Pricing by a

pipeline with market power would

exhibit the same pricing variability as

shown in the illustration, with higher

prices during periods when demand is

greatest. Also, even though prices

during off-peak periods are below the

maximum rate, that does not guarantee

that market power cannot be exercised.

The existence of a delivered market

does not, in and of itself, establish that

the market is operating efficiently.

Regulatory impediments, such as poorly

designed penalty structures or the

maximum rate cap, may create

transaction costs, reducing market

efficiency and raising prices. The price
42988 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

24See Mary L. Barcella, How Commodity Markets

Drive Gas Pipeline Values, Public Utilities

Fortnightly, Feb. 1, 1998, 24, 25 (price cap limits

shippers’ incentive to release capacity and can

result in shutting out other shippers needing

capacity).

25 During off-peak periods, the pipeline can price

discriminate by offering discounts to some

customers that are greater than those offered to

other customers. This practice brings in more

revenue than the pipeline would earn if it could

only charge the same price to all customers. The

additional revenue benefits the firm capacity

holders because, in the pipelines’ rate case, the

increased revenue reduces the reservation charges

firm shippers might otherwise pay. See Associated

Gas Distributors v. FERC (D.C. Cir. 1987) (selective

discounting by a monopolist justified on equitable

grounds because it would reduce captive customers’

contributions to fixed costs).

26Consumers Energy Company, 82 FERC ¿ 61,284

(1997). See Inside FERC’s Gas Market Report,

December 1, 1995, at 14 (discussing various

methods of avoiding the price cap).

27For example, in the automobile market, the

time and expense of comparison shopping may

result in some customers paying higher prices than

others.

28See Gas Daily, February 2, 1996, at 1.

cap, for instance, can create a

disincentive for firm capacity holders to

make capacity available for release

during peak periods, because the

capacity holder is unable to realize the

market value for its capacity. This can

create a less efficient market by

depriving other shippers of the ability to

obtain capacity when they place a

greater value on the capacity than the

shipper holding it.24 The buyer’s

alternative is to try and purchase

delivered gas. But the market for

delivered gas may not be as efficient as

giving the buyer the added option of

purchasing transportation capacity in an

open and transparent market in which

the buyer can decide for itself whether

it obtains greater value by purchasing

delivered gas or using its own gas

contracts and obtaining transportation

separately.

In sum, the short-term market is

changing, with greater emphasis on

daily transactions and daily prices for

the gas commodity both at origin and

delivered markets which vary with

demand. The constant maximum rate

approach to regulation does not appear

to fit well in this new fast-paced market

and may result in a less efficient market,

with increased transaction costs. Yet,

market power over transportation

continues to exist and must be

addressed.

B. Implications for Commission

Regulatory Policies of the Changing

Nature of Short-term Markets

The development of active

commodity markets at both ends of the

pipeline poses a significant challenge to

the Commission’s traditional method of

rate regulation. The current maximum

rate provides some regulatory protection

for shippers during peak periods,

because it prevents pipelines from

exercising monopoly power at least to

the extent that shippers cannot be

charged prices above the maximum rate.

Even during off-peak periods, the

maximum rate provides some protection

because it protects some shippers

against discriminatory prices that might

otherwise exceed the cap. During offpeak periods, some shippers still place

a high value on moving gas, and the

price cap limits the price such shippers

can be forced to pay. Moreover, the

Commission permits pipelines to price

discriminate (at prices below the

maximum rate) during off-peak periods

to provide benefits to captive customers

who hold long-term firm contracts. The

added revenue the pipeline generates by

selectively discounting helps to reduce

the reservation charges owed by the

captive firm shippers.25

As the short-term market continues to

grow, maximum rate regulation in the

short-term market may become an

increasingly more ineffective method of

regulating the short-term market.

Maximum rate regulation may not

provide shippers with the most effective

protection against the exercise of market

power. Moreover, the protection it does

provide may come at too great a cost in

efficiency.

The rate cap may, for instance, result

in misallocation of capacity where those

shippers placing the greatest value on

the capacity are unable to obtain it.

During peak periods, pipelines can only

sell capacity which is not under

contract or used by those shippers

holding firm capacity. Thus, a pipeline

may have little capacity to sell on a peak

day. Even if the pipeline did have

capacity to sell, a particular shipper

placing the highest value on the

capacity may be unable to obtain that

capacity. Under current Commission

rules, when demand for capacity

exceeds the supply available, and all

shippers bid the maximum rate, the

pipeline awards its capacity using a

queue based on contract execution date

or on a pro rata basis. In either case, the

shipper placing the greatest value on the

capacity may not obtain capacity or not

obtain as much capacity as it needs and

for which it is willing to pay.

The shipper’s other alternative is to

try to obtain capacity from firm capacity

holders, but in this market the price cap

may not provide much protection to the

purchasing shipper. The price cap

applies to released capacity. But, the

price cap has little effect on delivered

gas transactions, in which the

transportation value may exceed the

maximum rate.

There is little hard empiric evidence

on how extensive the delivered market

is, but the existence of delivered gas

transactions during peak periods

suggests that, due to the price cap,

capacity holders with available capacity

will choose to use that capacity to make

delivered transactions, where the profit

opportunity is greater, rather than

releasing the capacity, where the price

is capped. In addition, a pending

proceeding raises the question whether

shippers have developed other methods

for avoiding the maximum rate that are

difficult to detect and prevent on a

systematic basis.26

Attempting to regulate the

transportation component of delivered

gas transactions would be difficult. But

even if this market could be effectively

regulated, it is not clear that such

regulation would be beneficial. If

capacity transactions could not occur

above the price cap, then, as described

above, capacity would not be allocated

efficiently; those customers most

needing gas during peak periods would

be unable to obtain the gas they need

and the market would not clear

efficiently.

In addition, as described earlier, the

price cap may reduce the efficiency of

the delivered gas market itself by raising

transaction costs, thus resulting in

higher delivered prices. Because

unbundled sales of capacity by releasing

shippers cannot be made above the

maximum rate, the market may not

operate in as open, transparent, or

efficient a manner as is possible.

Information for delivered gas is not

publicly posted and shippers relying on

word of mouth may not be able to easily

locate all available sources of

transportation. The difficulty of locating

potential sellers and obtaining accurate

price information may lead some

customers to pay higher than necessary

prices. 27 For instance, during the winter

of 1996 when gas prices rose

dramatically, while the market worked

well to prevent shortages and ensure

that customers received gas, it could

have worked more efficiently.

According to the trade press, the

delivered prices for gas in Chicago on

the same day ranged from $20.50 to

$46.00 per MMBtu.28 In an efficient

market, one would not expect such a

wide differential in prices, but would

expect transactions in the same market

to clear at roughly similar prices. The

Commission seeks input from the

industry on whether the price cap

creates transaction costs and prevents
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42989

29See Industry Surveys the Damage as Winter’s

Strength Runs Out, Natural Gas Intelligence, April

22, 1996, at 1, 4 (penalties started to be a real factor

in determining the price of gas in the Midwest).

30See El Paso Natural Gas Company, 83 FERC ¶

61,286 (1998) (pipeline not required to discount

below the maximum rate); Southern California

Edison Company v. Southern California Gas

Company, 79 FERC ¶ 61,157 (1997), reh’g denied,

80 FERC ¶ 61,390 (1997) (no requirement that

pipelines or shippers offer discounts below the

maximum rate).

31See 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); Atlantic Refining Company v.

Public Service Commission of N.Y., 360 U.S. 378,

388 (1959) (rate regulation should ensure

reasonable rates consistent with the maintenance of

adequate service).

the development of an efficient shortterm market.

Maximum rate regulation may have

an unintended effect by reducing the

capacity available during peak periods,

the time at which the industry would

most benefit from having as much

pipeline capacity available as is

possible. As a result of the maximum

rate cap, firm capacity holders may not

find it sufficiently profitable to make

their capacity available. It may be that

due to state restrictions not all local

distribution companies (LDCs) may be

able to make delivered gas transactions

off-system. Thus, they may not make

capacity available during peak periods if

they cannot receive the market price for

their capacity.

For instance, an LDC might have a

peak shaving capability (storage or

liquified natural gas (LNG)) that costs

more to operate than the maximum

transportation rate. The LDC might be

willing to release its transportation

capacity and use the peak shaving

device instead if the price it could

receive for pipeline transportation

exceeded its cost to operate the peak

shaving device. By using its peak

shaving device instead of transportation,

the shipper would be expanding the

amount of transportation capacity

available for resale during a peak

period. But if the price cap prevented

the shipper from obtaining a price

higher than the cost of turning on the

peak shaving device, and the shipper

could not sell the gas on a delivered

basis, the shipper would use its

transportation capacity, thus depriving

other shippers (without peak shaving) of

the opportunity to acquire needed

transportation capacity. Thus,

maximum rate regulation may actually

reduce the amount of pipeline capacity

available for sale during peak periods. A

restriction on the amount of available

capacity would cause peak period prices

to be higher than they would be without

the cap. Comments should address

whether the price cap has these effects

and whether it does significantly limit

the amount of capacity available in the

short-term market.

Maximum rate regulation during peak

periods also may increase shipper

imbalances and penalties. During peak

periods, penalties affect the value of

transportation.29 In a cold snap, a

shipper may be willing to pay a penalty

for overrunning its contract demand to

obtain the gas it needs. If that shipper

faced a $100/MMBtu penalty, it might

be willing to pay any amount for

capacity up to $100 to avoid the

penalty. For example, if the value of

capacity in an efficient market were $80,

the shipper willing to pay a $100

penalty would be better off by $20 if it

obtained capacity instead. But, as

described above, the price cap may

reduce the efficiency of the marketplace,

limiting the shipper’s ability to obtain

the capacity it needs. The shipper,

therefore, may choose to overrun its

contract demand and pay the penalty. In

this situation, the price cap may result

in increasing shipper imbalances,

thereby increasing the penalty revenue

paid to pipelines, and perhaps

decreasing the reliability of the system.

During off-peak periods, the

maximum rate cap does not affect the

efficiency of the market because market

values do not appear to reach the

maximum rate ceiling. The rate cap,

however, may not provide sufficient

protection against the exercise of market

power. During off-peak periods,

pipelines and releasing shippers are not

required to sell available capacity at

prices less than the maximum rate.30 By

limiting the supply of capacity during

off-peak periods, pipelines or releasing

shippers may be able to charge

monopoly prices because even a

monopoly price may be less than the

daily maximum rate. Since pipelines are

permitted to price discriminate at rates

below the maximum rate, they may

charge shippers, at least those without

other choices, higher prices than would

prevail in an efficient competitive

market. Although the Commission has

permitted pipelines to price

discriminate by discounting below the

maximum rate, it may be that the

benefits for captive customers holding

long-term transportation contracts come

at too great a cost to other shippers or

that the benefits even to captive

customers no longer warrant

continuation of this policy.

In summary, the interface between the

regulated and unregulated sectors of the

gas industry has become much more

complicated in the last five years.

Regulatory policies that worked well in

one market setting may not work as well

today. For this reason, the Commission

is reassessing its current policies and

proposing changes.

II. Proposed Change in Regulatory

Approach

The Commission’s regulatory policies

must be attuned to the realities of the

market it is regulating. As became clear

during the period when wellhead prices

were regulated, consumers receive little

benefit from artificially low regulated

prices if such prices distort the market

and create shortages so consumers

cannot acquire gas when they most need

it.31 Moreover, in fashioning regulatory

policies, it must be recognized that

market power varies over a continuum

between perfect competition at one end

of the continuum and a single firm

monopoly with impenetrable entry

barriers at the other. Thus, a regulatory

approach appropriate for pure

monopoly markets may not be the best

method for regulating the markets where

market power, while not absent, may be

partially disciplined by market forces.

The changes to the short-term market

raise the question of whether the

Commission needs to change its

regulatory philosophy. Prior to

unbundling, maximum rate regulation

in the short-term market was more

effective, because the short-term market

essentially was limited to the pipelines’

interruptible transportation service.

However, as the short-term market

continues to develop, the continuation

of maximum rate regulation in the shortterm market may become increasingly

troublesome. First, maximum rate

regulation, by its very nature,

inefficiently allocates capacity because

those shippers placing the greatest value

on capacity may not be able to obtain it.

Therefore, during peak periods, when

the market is under the most stress, the

rate cap may result in a less efficient

and more opaque market in which

shippers cannot acquire capacity they

need or must pay higher prices for

delivered gas than would have prevailed

in a more efficient short-term market.

Second, maximum rate regulation may

not be the most effective tool for

preventing the exercise of market

power, particularly for transactions

during off-peak periods. Thus, while the

ostensible goal of Commission

regulatory policy is to protect shippers

against the exercise of monopoly power

by the pipelines, the current system of

maximum rate regulation may no longer

be the best method for meeting this goal.
42990 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

32Minimum rates would be retained.

33 18 CFR 284.221(d)(2) (right of first refusal

applies to contracts with a term of one year or

more); Pipeline Service Obligations and Revisions

to Regulations Governing Self-Implementing

Transportation Under Part 284 of the Commission’s

Regulations, Order No. 636–A, 57 FR 36128 (Aug.

12, 1992), FERC Stats. & Regs. Regulations

Preambles [Jan. 1991–June 1996] ¶ 30,950, at 30,627

(Aug. 3, 1992).

34 In defining short-term for the purposes of

capacity release transactions, the industry, through

the Gas Industry Standards Board, defined shortterm releases as releases of less than five months.

18 CFR 284.10(b)(1)(v), Capacity Release Related

Standards 5.3.2.

A. A Different Model for Regulating the

Short-term Market

To respond to the emerging short-term

market, the Commission is proposing in

this NOPR a change in regulatory focus

to better reflect the way in which shortterm gas markets function and to do a

better job of protecting against the

exercise of market power and helping to

foster a more competitive commodity

market. The Commission, however,

recognizes that the ability to exercise

market power still exists in the shortterm market and, therefore, any

regulatory approach it adopts must

continue to provide effective protection

against the exercise of market power.

To do this, there are several criteria

that a regulatory approach must satisfy.

It should maximize efficient

competition among releasing shippers

and between releasing shippers and the

pipelines, because competition and

efficient markets are the best overall

protection against the exercise of market

power. It should include policies that

will mitigate any residual market power

and monitor for its continued exercise.

It should fairly balance the interests of

those customers that purchase long-term

capacity and those who choose to

acquire transportation in the short-term

market. And, it should promote

innovation in service offerings to attract

new customers.

The Commission believes its statutory

objectives can better be met by a

regulatory model that recognizes the

distinction between short-term and

long-term markets. Therefore, in the

short-term transportation market, the

Commission proposes to replace the

reliance on maximum rate regulation 32

with a regulatory approach focusing on

creating competitive alternatives for

shippers, developing policies to mitigate

residual market power, and monitoring

the marketplace for the exercise of

market power. In the long-term

transportation market, the Commission

proposes to continue to rely upon

regulated cost-based rates to protect

against the exercise of monopoly power

by the pipelines. Price regulation for the

long-term transportation market will

ensure continued protection for captive

customers with long-term contracts with

the pipeline. It will also help discipline

the potential exercise of market power

in the short-term market by enabling

shippers to purchase long-term capacity

at regulated rates.

The Commission fully recognizes that

pipelines still possess monopoly power

in the transportation market as a result

of economies of scale and barriers to

entry. This is particularly true in the

long-term market where the pipeline

may be the only source of capacity. The

Commission also recognizes that simply

because competition exists for the gas

commodity at receipt and delivery

points on the grid does not mean that

the transportation between all points is

necessarily fully competitive.

On the other hand, in the short-term

market, the Commission’s capacity

release and flexible receipt and delivery

point policies, together with other

market changes such as pooling, hub

and market center services, and storage

services, have increased the competitive

alternatives available to buyers of

capacity. While these measures have not

resulted in effective competition

everywhere throughout the pipeline

grid, it cannot be disputed that they

have increased the level of competition

and reduced the ability of pipelines to

exercise monopoly power. Thus, while

a regulatory presence is still needed in

the short-term transportation market,

the Commission may not need to

continue to regulate this market as if

each pipeline was still a single firm

monopoly.

At the same time the Commission is

proposing to eliminate maximum rate

regulation in the short-term market, it is

proposing several initiatives in this

NOPR to maximize competition in the

short-term market, minimize the

potential for the exercise of market

power, and monitor the marketplace for

the continuing exercise of market

power. To maximize the extent of

competition, the Commission is

proposing a number of measures to

create more efficient competition among

capacity offerings so that shippers will

have more choice in obtaining capacity.

The Commission is proposing to create

more uniform nominating procedures

for released capacity so that it can better

compete with capacity from the

pipelines and delivered gas

transactions. The Commission further is

requesting comment on whether

changes in regulatory policy are needed

to maximize shippers’ ability to segment

their capacity to provide greater

competitive alternatives. To further

improve competition in the short-term

market across the pipeline grid, the

Commission is suggesting potential

methods of reforming penalty

procedures to ensure that different

penalty processes across pipelines do

not limit shippers’ flexibility in using

capacity or otherwise distort shippers’

decisions about how best to use

capacity.

As an additional measure to mitigate

potential market power, the

Commission is proposing the use of

capacity auctions for all short-term

capacity. A properly designed capacity

auction can protect against the exercise

of market power by limiting the ability

to withhold capacity and to engage in

price discrimination.

To monitor the marketplace, the

Commission is proposing to establish

reporting requirements to provide

capacity and pricing information to all

shippers. This information will have the

further benefit of making competition

more efficient by providing the pricing

information that a competitive market

needs for shippers to make informed

decisions about their capacity

purchases. All of these proposals are

addressed in more detail in Parts III and

IV of this NOPR.

In addition to these proposals for

monitoring the short-term market, the

Commission proposes to conduct a

generic review of the operation of the

short-term market without a price cap

after two winter heating seasons.

Because the proposed regulatory

approach differs between short-term and

long-term services, there is a need to

define the period encompassed by each.

The Commission is proposing to define

short-term transactions as all

transactions of less than one year. The

Commission has traditionally drawn the

line between long-term and short-term

transactions at one year.33 A term of one

year corresponds with naturally

repeating weather and planning cycles

for production, transportation, and

storage. A term of one year also

corresponds with the period used to

calculate long-term rates.

The Commission, however, requests

comment on whether a shorter period,

such as five months, should be used. If

a period of less than one year were

chosen, it could either be a discrete

period (e.g., November through March)

or could refer to any transaction with a

term of less than the chosen period. A

five month period, for instance, would

generally correspond to the length of

time of the heating season.34 The use of

a period of less than one year could

reduce the outlay that any shipper

would have to make in order to buy
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42991

35For instance, under a five month definition, the

maximum charge a shipper would have to incur to

purchase long-term capacity would be the current

monthly rate times five.

36 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.’’).

37Natural Gas Decontrol Act of 1989, H.R. Rep.

No. 101–29, 101st Cong., 1st Sess., at 6 (1989);

Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing

Transportation Under Part 284 of the Commission’s

Regulations, Order No. 636, 57 FR 13267 (Apr. 16,

1992), FERC Stats. & Regs. Regulations Preambles

[Jan. 1991–June 1996] ¶ 30,939, at 30,932 (Apr. 8,

1992).

38Elizabethtown Gas Company v. FERC, 10 F.3d

866, 870 (D.C. Cir. 1993) (approving market-based

rates).

39See Farmers Union Central Exchange v. FERC,

734 F.2d 1486, 1509–10 (D.C. Cir. 1984).

40Environmental Action v. FERC, 996 F.2d 401,

408, 411 (D.C. Cir. 1993) (approving flexible pricing

program to permit efficient trading of electric

power).

41As 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.

capacity at cost-based rates to avoid the

potential exercise of market power. 35

B. Legal Basis for the Proposed

Regulatory Change

The Commission’s statutory

responsibility under the Natural Gas Act

(NGA) is to establish rates that are just

and reasonable and that protect

consumers of natural gas from the

exercise of monopoly power by

pipelines.36 In addition, the

Commission has the obligation, under

the Wellhead Decontrol Act, to structure

its regulatory framework to ‘‘improve

[the] competitive structure [of the

natural gas industry] in order to

maximize the benefits of [wellhead]

decontrol.’’ 37

The courts have recognized that the

Commission needs to be able to develop

flexible pricing programs that

accommodate its regulation to the needs

of the marketplace. The Commission is

not bound to ‘‘use any single pricing

formula’’ in determining just and

reasonable rates,38 and cost-based

regulation can be relaxed when the

overall ‘‘regulatory scheme’’ ensures

that rates are within a zone of

reasonableness.39 The case law makes

clear that flexible rate regulation is

permissible as long as, on balance, the

benefits of the program outweigh the

potential risks, and the Commission

takes reasonable measures to protect

against the exercise of market power,

even though not every transaction

would be free of market power.40 In

Environmental Action v. FERC, the

court approved a flexible pricing

program, which fostered efficient

trading of energy and transmission

service, even though the program

created a risk that market power could

be exercised over captive customers.

Given the benefits of effective trading

and the protections adopted by the

Commission to limit the potential

exercise of market power, the court

concluded that the Commission acted

reasonably in approving the program

despite the potential risks.41

The Commission believes the model it

is proposing satisfies the Commission’s

statutory obligations by achieving the

appropriate balance between the

benefits to be garnered from efficient

trading in the short-term market and the

protection needed against the exercise

of market power. As discussed earlier,

removing maximum rate regulation from

the short-term market provides

significant benefits by allowing markets

to efficiently allocate capacity in an

environment in which cost-based

solutions do not accommodate the

volatile price changes in the industry.

The potential risk of this approach is

that it could give pipelines or shippers

greater latitude to exercise market

power during peak periods. Although

competition clearly has increased in the

short-term market, the Commission is

not making a finding that the short-term

market is sufficiently competitive to

satisfy its traditional market power

analysis. Nor is the Commission making

a finding that the proposals in this

NOPR will necessarily create a fully

competitive market. Rather, as

discussed below, the proposed approach

in this NOPR is intended to place

effective limits on the ability of

pipelines and shippers to exercise

market power by enhancing competitive

options in the short-term market,

mitigating market power by limiting the

ability to withhold capacity and price

discriminate, and monitoring the

marketplace.

The proposed approach should

provide benefits to all shippers—both

those holding long-term capacity, and

those purchasing short-term capacity.

Long-term capacity holders would still

be protected by the cost-based rate in

the long-term market and would benefit

by being able to realize the value of their

long-term capacity. Shippers relying on

the short-term market would not be

unreasonably harmed since the

proposals in the NOPR are designed to

protect them against the withholding of

capacity and price discrimination, both

during peak and off-peak periods. At the

same time, short-term shippers would

benefit because the proposals would

help to create a more efficient

marketplace during peak periods, with

capacity allocated to those valuing it

most, prices undistorted by regulatory

allocation priorities, clearer price

signals, and more open, transparent, and

efficient capacity allocations. These

benefits are fully described below.

The approach proposed here also

appears better suited than other

potential approaches for responding to

the changing dynamics of the short-term

market. The Commission, however,

requests comment on whether this

proposal is the best approach for

protecting against market power given

the realities of the short-term market.

Commenters should address whether

the Commission should seek evidence

to determine whether it can make a

finding that the market is competitive or

pursue other regulatory approaches.

1. Protection Against the Exercise of

Market Power by Pipelines and

Shippers

The Commission’s primary

responsibility is to protect against the

exercise of monopoly power by

pipelines. Even under the current

maximum rate approach, such

protection is not absolute. Pipelines are

able to price discriminate below the

existing price cap.

The approach proposed here seeks to

control the pipelines’ exercise of

monopoly power in a different way, by

enhancing the competition from firm

shippers releasing capacity, by requiring

pipeline capacity to be sold through an

auction that limits the ability to

withhold capacity, and by monitoring

the marketplace for evidence of the

exercise of monopoly power. Moreover,

the proposed approach would reduce

the ability of pipelines to withhold

future capacity (by not expanding their

systems) in order to increase price and

earn a supra-competitive rate of return.

If pipelines sought to limit capacity in

order to earn high returns on short-term

transactions, shippers could purchase

long-term capacity at cost-based rates

and capture the profit opportunities in

the short-term market for themselves by

releasing the capacity. Further, any

revenues from short-term sales would be

accounted for in the pipeline’s next rate

case ensuring that the long-term benefits

of increased revenue from sales of shortterm capacity go to the long-term firm

capacity holders. The Commission also

could act under section 5 of the NGA in

cases where monitoring revealed that
42992 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

42See Elizabethtown, 10 F.3d at 870 (Commission

can use its section 5 authority to assure that marketbased rates are just and reasonable); Environmental

Action, 996 F.2d at 411 (emphasizing provisions for

monitoring market-based rates to protect against

exercise of market power).

43See 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)

(remanding special marketing program because it

excluded core captive customers); Environmental

Action, 761 F.2d at 411 (permitting flexible pricing

program even though there was some possibility of

discrimination against captive utilities).

44See American Gas Association v. FERC, 912

F.2d 1496, 1518 (D.C. Cir. 1990). The court

remanded the Commission’s decision to permit pregranted abandonment of all long-term contracts,

because of a concern about the pipeline’s ability to

exercise monopoly market power over long-term

capacity holders. The court, however, found that

holders of interruptible and short-term services did

not need similar protection against the exercise of

pipeline monopoly power.

45Alternatives 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).

the market rate is not just and

reasonable.42

The approach proposed here also can

be expected to limit the exercise of

market power by firm capacity holders.

Releasing shippers face competition

from other releasing shippers and from

the sale of pipeline firm and

interruptible service. Firm capacity

holders should not be able to withhold

capacity to raise price, because if they

do not use their capacity it then

becomes available either as interruptible

or short-term firm capacity from the

pipeline. The proposed auction would

then require the pipeline to sell that

capacity at a market-determined price.

The auction also would limit the ability

of firm capacity holders to unduly

discriminate. Moreover, the pipelines’

ability to build additional capacity is a

final protection against releasing

shippers’ exercise of market power. If

the pipeline observes shippers earning

high returns from constrained capacity,

the pipelines have every incentive to try

to capture those returns by building

additional capacity to satisfy that

demand.

2. Protection for Shippers Relying on

Long-term and Short-term Capacity

While the Commission has an

obligation to consider the interests of all

shippers, its paramount obligation is to

protect long-term firm capacity holders

that cannot risk going without long-term

capacity.43 Interruptible or short-term

shippers, by definition, take the risk that

they may be unable to acquire

capacity.44 The proposed regulatory

model would protect those shippers

holding long-term capacity, while at the

same time not putting short-term

shippers at unreasonable risk and

perhaps even providing them with

benefits.

Under the proposed approach,

shippers holding long-term capacity

would continue to receive the

traditional protection accorded them

because long-term capacity would still

be subject to cost-based regulation.

Indeed, removal of the price cap for

short-term transactions should benefit

long-term capacity holders, because it

would permit them to recover more of

their reservation charges during peak

periods. For those shippers holding

long-term contracts that are unable to

sell delivered gas, the price cap

currently limits their ability to recover

their reservation charges by releasing

capacity during peak periods when

capacity is valuable. On the other hand,

during off-peak periods, competition

from other releasers or the pipeline may

limit a shipper’s ability to recover its

reservation charges. At the same time,

interruptible or short-term shippers

benefit from the competition during offpeak periods because they pay prices

lower than what the pipeline charged

when it was the sole supplier of

capacity. Thus, removal of the rate cap

would permit long-term firm capacity

holders to realize the full value of their

transportation capacity during both

peak and off-peak periods.

Even if a long-term firm capacity

holder is unable to release its own

capacity during a peak period, it may

benefit if the pipeline can charge

competitive rates for peak period

capacity. In the pipeline’s next rate case,

the revenue received from such sales

would be used to reduce the reservation

charges for firm customers.

Nonetheless, the Commission expects

that the proposed regulatory model

would not put shippers in the shortterm market at unreasonable risk and

may even benefit them. These shippers

would have the option of buying longterm capacity at regulated cost-based

rates, which should help to limit the

potential exercise of market power in

the short-term market. Pipelines would

continue to be required to sell long-term

capacity to anyone offering the

maximum rate regardless of the rates bid

for short-term capacity. Further, to

ensure that long-term capacity is

available, the Commission would

examine closely pipeline refusals to

construct taps requested by customers

as well as pipeline refusals to construct

new capacity when demand for new

construction exists.

This model also should work to the

benefit of short-term customers during

both off-peak and peak periods. During

peak periods, the price cap offers only

limited protection against the exercise

of market power, and may actually

create inefficiency which reduces shortterm shippers’ ability to obtain capacity

when they need it. During peak periods,

when capacity is constrained, shortterm customers currently run a

significant risk that they may be unable

to obtain capacity from the pipeline

even if they place the highest value on

that capacity. If they instead seek to

acquire capacity through a delivered gas

transaction, they receive little protection

against the exercise of market power

and the price for such gas may be higher

than it would be in a more efficient

market. By removing the price cap, but

at the same time offering initiatives for

enhancing competition among capacity

alternatives, the approach proposed in

this NOPR should be more effective

than the current system in creating a

transparent and efficient short-term

market in which shippers, even on peak,

can acquire gas and capacity at efficient

market-clearing prices.

During off-peak periods, the rate cap

provides little protection against the

exercise of market power, because

pipelines and shippers are not required

to sell capacity at rates below the

maximum rate. The proposals for

increasing competition and the auction

ought to limit the pipelines’ ability to

exercise market power or price

discriminate so all short-term shippers

would be paying prices closer to a

competitive level.

3. Alternative Approaches for

Regulating the Short-Term

Transportation Market

The approach proposed in this NOPR

appears better suited than other possible

methods of dealing with the dynamics

of the short-term transportation market.

An alternative approach would be to

continue the current maximum rate

system, but allow pipelines and firm

capacity holders to seek removal of the

cap in the short-term market upon a

demonstration that they cannot exercise

market power. In effect, this approach

presumes market power is present and

requires the parties to try to predict,

through market concentration data or

other approaches, whether market

power will be exercised if the rate cap

is removed. This is essentially the

approach the Commission uses with

respect to market power in its

Alternative Rate Design policy, which

focuses on the exercise of market power

in the long-term market for pipeline

capacity.45

The approach of screening for market

power is certainly a possible alternative,

but it would move the Commission in

a direction very different from the one
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42993

46See Environmental Action, 996 F.2d 401

(approving a flexible pricing program for an electric

power pool with a rate ceiling based on the most

valuable and expensive transportation service).

47 In unregulated and even in regulated

industries, sellers often create innovative service

options for individual customers while still

providing a basic service to all. For instance,

telecommunication firms provide specialized

services for small and large businesses while still

providing standard service to the public.

proposed here. The approach proposed

here does not rely on a finding of a lack

of market power, relying instead on

regulatory measures to reduce or limit

the exercise of market power.

The market power screen, in contrast,

would require the Commission to make

a finding of lack of market power in

each relevant market. This not only

could be a time consuming and

daunting task to undertake on an

industry-wide basis, but it might have to

be repeated periodically as contracts

expire or the competitive circumstances

on individual pipelines change. The

market power screen approach also was

developed to isolate market power in

circumstances in which the pipeline is

the sole source of capacity, and it,

therefore, imposes a relatively heavy

evidentiary burden on pipelines seeking

market-based rates. Such a screen may

not be discriminating enough or the

most appropriate means of dealing with

market power in the short-term market

where more competition is clearly

present. The use of the traditional

market power screen, therefore, might

suggest the presence of market power in

areas that ought to be found reasonably

competitive.

Moreover, in cases where the

concentration data do not satisfy the

market power screen, the market

analysis approach would continue to

rely on maximum rate regulation which,

as discussed earlier, may not be very

effective in protecting against market

power in the short-term market and also

promotes more inefficient short-term

markets. The Commission, however,

requests comment on whether a

modified version of the market power

screen could and should be developed

for the short-term market that would be

easier to administer and could

determine whether market power is a

significant problem.

Another cost-of-service option would

be to attempt to develop a cost-based,

seasonal rate design that would better

approximate pricing activity that would

occur during peak and off-peak periods.

But price swings can be very large on a

daily, weekly, or monthly basis, making

the development of a rate structure that

would accurately reflect competitive

market conditions particularly difficult.

Moreover, if the price cap is raised high

enough to accommodate peak period

competitive prices, this approach is

little different than simply removing the

rate cap, since it would afford firms

with market power substantial latitude

to exercise that power at prices below

the price cap.46

Of the regulatory options available,

the proposed regulatory model appears

to create the best balance between

achieving the Commission’s objectives

of preventing the exercise of market

power and creating a regulatory

environment that fosters a competitive,

efficient commodity market that is fair

to all shippers. This approach would

free the short-term market from

regulatory impediments that prevent the

market from responding to the

competitive supply and demand forces

that may result in competitive prices

exceeding the price cap. At the same

time, the proposals to increase

competition in the short-term market

should help to keep the prices for most

transactions within reasonable levels.

Because firm shippers would be better

able to release capacity in competition

with the pipelines, the pipelines’ ability

to exercise market power would be

limited. At the same time, firm shippers’

ability to exercise market power would

be restrained because, if they tried to

withhold capacity to raise prices, the

pipelines would be required to sell that

capacity at market clearing prices. The

proposed auction also would restrain

the ability of both pipelines and firm

shippers to exercise market power and

to unduly discriminate in the allocation

of capacity. Further, the overall scheme

of the proposal limits the pipelines’

ability to charge monopoly prices

because shippers can discipline the

pipelines’ exercise of market power by

purchasing long-term capacity at costbased levels.

C. Interrelated Proposals for Regulatory

Change

The principal focus of the regulatory

changes proposed in this NOPR is on

improving efficiency and competition in

the short-term transportation market.

Yet, the regulation of long-term

transportation service is an integral part

of the Commission’s proposal because

continued regulation of long-term

services is an important back-stop to

protect against the pipelines’ exercise of

market power. Long-term and short-term

transportation services are linked in

other ways since the value of

purchasing long-term capacity lies in its

ability to insure shippers against the

risk of price swings in the short-term

market. Thus, the changing nature of

short-term markets has a concomitant

effect on how shippers use the longterm market and, likewise, actions

affecting long-term contracts can affect

the short-term market. For example, if a

pipeline can attract more shippers to its

system, the long-term rate will be

reduced, which, in turn, would limit the

ability of pipelines to raise price in the

short-term market. On the other hand,

policies discouraging shippers from

entering long-term contracts could

reduce the extent of competition in the

short-term market. Because of the

relationship between short-term and

long-term services, the Commission also

is proposing in this NOPR initiatives to

improve competition and innovation in

the market for long-term services and to

ensure that its regulatory policies in the

long-term market do not bias shippers’

purchasing decisions.

The Commission is proposing to give

pipelines more flexibility in negotiating

rates and terms of service with

individual shippers. Allowing greater

flexibility in contract terms for longterm service can be an important

element in the allocation of risk

between pipelines and potential

customers. Permitting negotiation of

services will provide an incentive for

pipelines to innovate and create

additional value in transportation

service.47 Also, negotiated rates and

services may permit the pipelines to

attract new customers, which would

reduce reservation charges for existing

customers.

On the other hand, allowing the

pipelines to negotiate individual terms

of service creates the possibility of

discrimination against captive

customers as well as a risk that such

terms could degrade competition in the

short-term market by limiting the range

of capacity alternatives available to

shippers. To fully realize the benefits

from negotiated services while reducing

the risks, the Commission is proposing

to permit pipelines and shippers to

enter into contracts for negotiated

services, while also proposing criteria to

protect against the risks of undue

discrimination or impairment of the

competitiveness of the short-term

market.

Further, to ensure that contracting

decisions are made efficiently,

regulatory policies should not unfairly

bias shippers’ contracting decisions.

Some Commission policies, like the

right of first refusal, may well create an

asymmetry in the risks facing pipelines

and capacity purchasers and bias

shippers towards shorter term contracts.

The Commission, therefore, is proposing

certain changes in regulatory policy to
42994 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

48The references in this NOPR to proposed

regulatory changes are to the new regulatory

sections. References to existing regulations are to

the existing regulatory framework.

49Market power can be exercised in two ways. A

holder of capacity may withhold capacity from the

market to drive up the price that all shippers pay

for the remaining capacity, or it can price

discriminate by charging captive customers more

than those customers with more alternatives. In

either case, however, competition will prevent the

exercise of market power.

50See Compliant Procedures, Docket No. RM98–

13–000 (issued contemporaneously with this

NOPR).

51Standards For Business Practices Of Interstate

Natural Gas Pipelines, Final Rule, 63 FR 39509 (July

23, 1998), 84 FERC ¶ 61,031 (Jul. 15, 1998).

eliminate provisions that may tilt

shipper decisions towards the purchase

of short-term capacity.

The construction of new capacity also

affects competition in the short-term

market. For instance, the ability of

shippers to purchase long-term capacity

at cost-based rates is a protection against

the exercise of market power in the

short-term market. The Commission is,

therefore, considering changes in

certificate policy so that these policies

do not unnecessarily inhibit

competition.

In addition, to better reflect the

changing nature of services in the shortterm market and to consolidate pipeline

reporting requirements under Part 284,

the Commission is proposing to

reorganize Part 284 to put the

regulations into a more logical order.48

III. Creating Greater Competition

Among Short-Term Service Offerings

Increasing competition is the best

antidote to market power. As long as

buyers have good alternative sources of

capacity, no seller can exercise market

power, because any attempt to raise

price above the competitive level will

result in the buyer moving to another

seller.49 Prior to Order No. 636, the

pipeline was the only source of both

long-term and short-term capacity. The

Commission’s establishment, in Order

No. 636, of the capacity release

mechanism has significantly increased

competition on most pipelines both

between the pipeline and shippers and

among shippers themselves.

But there remain means of enhancing

competition and improving the

substitutability of capacity alternatives.

Three such improvements are to make

nomination and scheduling procedures

more uniform for all short-term services;

provide shippers with a greater ability

to segment capacity and use alternate

receipt and delivery points so

transportation alternatives are more

comparable; and employ auctions for all

capacity to limit the ability of pipelines

or shippers to withhold capacity or

discriminate. In addition, the

Commission is proposing changes to its

reporting requirements to ensure that

comparable information about pipeline

and release transactions is provided.

Improved information enables shippers

to make more informed capacity choices

while it also permits the Commission

and the industry to monitor transactions

for the potential exercise of market

power in the event the Commission’s

efforts to mitigate market power are not

successful. The Commission is

committed to take appropriate and

timely action in individual cases to deal

with the exercise of market power. To

this end, the Commission is in the

process of considering improvements to

its procedures for handling

complaints.50

A. Nomination Equality

In order to foster a more competitive

short-term market, all forms of

transportation—pipeline interruptible

and short-term firm capacity, released

capacity, and delivered sales

transactions—must be able to compete

on as equal a basis as possible. While

there are obviously differences in rights

associated with the different types of

capacity, the Commission is concerned

that differences in nomination and

scheduling procedures for capacity

release inhibit the ability of capacity

release transactions to compete with

pipeline capacity. The Commission,

however, requests comment on whether

the existing differences in nomination

and scheduling procedures for capacity

release transactions reflect important

differences in the nature of the services

that should be preserved.

Under current regulations, pipelines

can sell their interruptible and shortterm services at any time and shippers

can schedule such services at the

earliest available nomination

opportunity. Similarly, capacity holders

making delivered sales can nominate

and schedule at every available

opportunity. In contrast, nomination

and scheduling opportunities under

capacity release transactions currently

are significantly circumscribed.

Under Commission regulations,

shippers currently submit their daily

nominations at 11:30 a.m. to take effect

at 9 a.m. the next gas day. Pipelines

presently are required to provide

shippers at least one intra-day

nomination change after the 11:30 a.m.

nomination, although many pipelines

provide additional intra-day nomination

opportunities. While a pipeline may sell

interruptible or short-term firm service

and permit the recipient of that service

to submit a nomination at the earliest

available nomination opportunity,

shippers consummating a release

transaction must do so prior to 9 a.m.

and can only submit a nomination at

11:30 a.m. for the next gas day. They

cannot consummate a release

transaction later than 9 a.m., nor can the

replacement shipper utilize an intra-day

nomination opportunity to submit a

nomination for the current gas day.

The disparate treatment of capacity

release transactions, if left uncorrected,

promises to become even more severe as

a result of the industry’s agreement to

enhance intra-day nomination

opportunities. In a final rule issued on

July 15, 1998,51 the Commission

adopted the consensus agreement of the

Gas Industry Standards Board (GISB) to

expand shippers’ intra-day nomination

opportunities by establishing three

synchronized intra-day nomination

periods across the grid. Under the

industry’s schedule, the three

synchronization times are 6 p.m. (for the

next gas day), 10 a.m. and 5 p.m. (for the

current gas day). A shipper obtaining

short-term firm or interruptible capacity

from the pipeline, or making a delivered

sales transaction, will be able to submit

a nomination at any of these intra-day

nomination opportunities. Significantly,

however, a replacement shipper cannot

acquire released capacity immediately

prior to these intra-day nomination

times and nominate at these times. The

replacement shipper must consummate

a capacity release deal by 9 a.m. and

must wait a full day before it can flow

gas under the release transaction.

In order to place capacity release

transactions on a more equal footing

with pipeline services, the Commission

is proposing, in proposed section

284.13(c)(1)(ii), that pipelines 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. This will enable shippers, for

instance, to acquire released capacity at

any of the nomination or intra-day

nomination synchronization times and

nominate gas coincident with their

acquisition of capacity.

In some cases, pipelines currently

require replacement shippers to pass a

credit-worthiness check and execute

contracts prior to nominating. Under the

proposed regulation, such requirements

could not prevent a replacement shipper

from nominating when it completes the

release transaction. Proposed section

284.13(c)(1)(ii) would provide that a

pipeline that requires the replacement

shipper to enter into a contract must
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42995

52The current regulations require pipelines to

issue contracts within one hour. 18 CFR

284.10(b)(1)(v), Capacity Release Related Standards

5.3.2.

53The Commission previously issued a proposed

rule suggesting that pipelines use pre-approved

credit-worthiness procedures for replacement

shippers. Secondary Market Transactions on

Interstate Natural Gas Pipelines, Notice of Proposed

Rulemaking, 61 FR 41046 (Aug. 7, 1996), IV FERC

Stats. & Regs. Proposed Regulations ¶ 32,520 (Jul.

31, 1996). In the comments on the proposal, the

pipelines, in general, did not object to the use of

pre-approval for credit-worthiness or master

contracts. Tenneco Energy objected only to the use

of master contracts, arguing that because capacity

release is a firm service, the pipeline needs prior

notice of the specific terms of the release including

the firm transportation quantity, the zones of the

release, and the rights to primary and secondary

points.

54Releasing shippers already are responsible for

all reservation charges under the Commission’s

capacity release regulations. 18 CFR 284.243(f).

55See Transwestern Pipeline Company, 62 FERC

at 61,659, 63 FERC at 61,911–12 (1993); El Paso

Natural Gas Company, 62 FERC ¶ 61,311, at

62,982–83 (1993).

56Texas Eastern Transmission Corporation, 63

FERC ¶ 61,100, at 61,452 (1993). El Paso Natural

Gas Company, 62 FERC ¶ 63,311, at 62,991. See

also Transwestern Pipeline Company, 61 FERC ¶

61,332, at 62,232 (1992).

57See Colorado Interstate Gas Company FERC Gas

Tariff, First Revised Volume No. 1, Third Revised

Sheet No. 254 (replacement shippers are not

permitted to change primary points and can

nominate only the original primary or at secondary

points).

58For example, if the replacement shipper seeks

to change its primary receipt point right from the

Gulf to another point, then the releasing New York

shipper might lose the ability to return to its

primary Gulf receipt point at the end of the release.

59See Transwestern Pipeline Company, 62 FERC

at 61,659, 63 FERC at 61,911–12 (1993); El Paso

Natural Gas Company, 62 FERC ¶ 61,311, at

62,982–83 (1993).

issue the contract within one hour of

submission of the transaction 52 and that

the requirement for contracting must not

inhibit the ability to submit a

nomination at the time the transaction

is complete.

Pipelines have available several

procedures which they can use to

protect themselves against the credit

risk of the replacement shipper. The

pipelines can institute procedures under

which replacement shippers receive

pre-approval of their credit-worthiness

or receive a master contract, like those

used for interruptible shippers,

permitting the replacement shipper to

nominate under that contract at any

time.53 For replacement shippers that do

not have a master contract, the pipeline

could provide a contract number for

nominating as soon as the pipeline is

notified of the release transaction. For

replacement shippers that have not

received pre-approved credit, the

releasing shipper may agree to be liable

for any usage charges incurred by the

replacement shipper while the pipeline

conducts the credit-worthiness check.54

B. Segmentation and Flexibility of

Receipt and Delivery Points

1. Background

In Order No. 636, the Commission

established two principles that are

important to creating efficient

competition between holders of capacity

and the pipelines: segmentation of

capacity and the ability of shippers to

use alternative receipt and delivery

points. Segmentation refers to the ability

of firm capacity holders to subdivide

their capacity into segments to enhance

the value of the capacity and the

capacity holders’ ability to compete

with the pipeline. 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 contract to use other

available points.

Without the ability to segment and

use alternate points, the New York

releasing shipper in the example would

not be an effective competitor to another

shipper holding firm primary point

capacity at Atlanta. The ability to

segment capacity and use alternate

points, therefore, provides a potential

replacement shipper who wants to ship

to Atlanta with additional capacity

options. It can buy from the releasing

shipper holding primary point capacity

in Atlanta or from the New York

releasing shipper or any other shipper

holding capacity downstream of

Atlanta.

However, under current Commission

policies, the ability of the releasing

shipper in New York to compete with

the pipeline or with the shipper in

Atlanta may be limited. Under the

Commission’s current policies, the

releasing shipper in New York only has

a secondary delivery point right at

Atlanta, which is inferior to the primary

point right of the releasing shipper

holding primary point rights at Atlanta.

In other words, if the pipeline is unable

to make both deliveries to Atlanta, the

shipper with the primary right at

Atlanta will be given delivery priority

over the releasing shipper in New York

or the replacement shipper buying

capacity from the New York shipper,

each of which only has secondary point

rights at Atlanta. To the extent that this

is a possibility, capacity from the

releasing shipper in New York is not

equal in quality or fully competitive

with the capacity from the shipper

holding primary point rights at Atlanta.

Receipt and delivery point flexibility

is not applied consistently across

pipelines, and pipelines do not treat

different types of segmentation

similarly. During the restructuring

proceedings mandated by Order No.

636, the Commission permitted certain

pipelines to adopt tariff provisions

under which releasing shippers would

lose their rights to primary receipt or

delivery points if replacement shippers

changed primary points under the

release.55 The Commission permitted

such restrictions where the pipelines

had pre-existing tariff provisions that

did not permit shippers’ primary receipt

and delivery point CD rights to exceed

their mainline rights. To prevent the

possible loss of primary point rights, the

releasing shipper would have to include

a condition in the release prohibiting

the replacement shipper from changing

primary points. The Commission,

however, sought to minimize the effect

of this restriction on segmented releases

by adopting a policy for segmented

releases under which:

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.56

Under this policy [hereinafter referred

to as the Texas Eastern/El Paso policy],

the releasing shipper could protect its

delivery point rights by choosing

Atlanta as its primary receipt point and

New York as its primary delivery point,

while the replacement shipper designate

its primary receipt point as the Gulf and

Atlanta as its primary delivery point.

However, it is not clear whether all

pipelines adhere to this policy.57

Even on those pipelines following the

Texas Eastern/El Paso policy,

replacement shippers face limitations

on their ability to change primary

receipt and delivery points.58 However,

even at the time the Commission

permitted those pipelines with preexisting tariff restrictions on receipt and

delivery point rights to continue such

restrictions, it was skeptical about the

justifications for imposing such limits.59

In fact, the Commission rejected

applications to impose similar
42996 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

60See Northwest Pipeline Company, 63 FERC ¶

61,124, at 61,806–08 n.72 (1993).

61Northwest Pipeline Company, 63 FERC ¶

61,124, at 61,807 (1993). See also Questar Pipeline

Company, 62 FERC ¶ 61,192, at 62,306 (1993).

62Secondary Market Transactions on Interstate

Natural Gas Pipelines, Notice of Proposed

Rulemaking, 61 FR 41046 (Aug. 7, 1996), IV FERC

Stats. & Regs. Proposed Regulations ¶ 32,520 (Jul.

31, 1996).

63See El Paso Natural Gas Company, 81 FERC

¶ 61,174 (1997) (because the pipeline does not

assign receipt point rights, it effectively allocates

constrained mainline capacity based on whether

customers are nominating to primary or secondary

delivery points).

restrictions by pipelines without preexisting restrictions.60 In these cases, the

Commission required pipelines to

permit replacement shippers to change

primary points without releasing

shippers losing their right to return to

their original primary point at the end

of the release. As the Commission

explained in Northwest:

Northwest’s restriction on replacement

shippers’ ability to designate primary receipt

or delivery points different from those of the

releasing shipper unless the releasing shipper

agrees to relinquish the original primary

point could operate to limit or impair

capacity release transactions. A releasing

shipper may be unwilling to enter into a

short term release if, in so doing, it loses

priority to its primary receipt and delivery

points for the remainder of a 20 year contract.

Replacement shippers may be reluctant to

bid on mainline capacity if they cannot be

assured of receipt and delivery point capacity

at available points (not subject to bumping by

shippers coming later in time).61

Under both the Texas Eastern/El Paso

and Northwest policies, replacement

shippers can change primary points

only if the new point is available and is

not fully subscribed. In addition,

shippers can only change to available

points that are within the capacity path

for which they paid. Pipelines,

therefore, are not required to permit

shippers to change primary points if

doing so would mean that the pipeline’s

mainline capacity would be

oversubscribed.

During the restructuring proceedings,

the Commission addressed

segmentation only in the context of

release transactions. It did not address

whether a shipper could segment

capacity, for instance, by delivering gas

to Atlanta and then shipping to New

York for its own use. It is not clear

whether pipelines permit such

transactions. Even if pipelines do permit

the segmented transaction, the shipper

may be unable to designate both Atlanta

and New York as primary delivery

points.

In the Commission’s NOPR on

secondary market transactions

(Secondary Market NOPR),62 the

Commission requested comment on

whether it needed to provide more

flexibility for shippers and replacement

shippers to change primary points. Most

shippers supported providing more

flexibility, arguing that a shipper using

capacity on a secondary basis within the

primary path has the same rights

afforded transportation between primary

points. The pipelines, however,

opposed increased flexibility, arguing

that allowing releasing shippers to

return to previously vacated points

would require the pipeline to hold

otherwise available capacity in reserve

for shippers without collecting

reservation charges for that capacity.

2. Is There a Need To Revise Policies To

Improve Competition Between Primary

and Alternate Point Capacity?

Shippers’ rights to segment and use

receipt and delivery points clearly differ

across pipelines. In today’s gas market,

shippers are acquiring capacity from

multiple sources and need the ability to

use their capacity more flexibly. The

issue is whether, in operation, the

current system fairly allocates capacity

so no changes need to be made to the

policies or whether changes are

necessary to maximize the extent of

competition in the short-term market.

The concerns involve two interrelated

areas: segmentation policy, including

priorities for primary and secondary

points, and the confirmation process

between pipelines and between

pipelines and other entities, such as

LDCs.

The first concern, as discussed above,

is whether on some pipelines,

replacement shippers may be unable to

use certain receipt or delivery points as

primary points under segmented release

transactions and whether this

significantly limits shippers’ flexibility

or raises transaction costs. These

limitations would be more severe on

pipelines that do not follow the Texas

Eastern/El Paso policy by permitting

both releasing shippers and replacement

shippers on segmented releases to hold

primary point capacity equal to their

contract demand.

On some pipelines, delivery or receipt

point priorities may be used to

determine priorities over constrained

mainline capacity even if both shippers

have equal firm rights over the

constrained mainline. For example, if

pipelines are unable to schedule

competing firm nominations, the

pipelines may give higher priority to

shippers moving between primary firm

points over shippers moving to

secondary points even if both sets of

shippers have equal firm rights past the

area that has become constrained.63 It is

not clear how frequently pipelines use

receipt or delivery point priority to

allocate mainline capacity in the event

of constraints or whether the use of such

an allocation policy significantly limits

shippers’ flexibility.

Second, confirmation practices may

affect the allocation of primary and

secondary capacity at interconnects

between two pipelines (which includes

interconnects between interstate and

intrastate pipelines and interstate

pipelines and local distribution

companies). Suppose there are two

shippers with firm capacity on pipeline

A that covers an interconnect with

pipeline B, but shipper 1 holds the

interconnect as a primary delivery point

and shipper 2 as a secondary delivery

point. Further, suppose there is

insufficient capacity to effect both

deliveries and shipper 1 holds only

interruptible capacity on pipeline B,

while shipper 2 holds firm capacity on

pipeline B.

BILLING CODE 6717–01–P
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42997

64Pipeline A would allocate the delivery point

right to shipper 1, whose primary firm right has

priority over shipper 2’s secondary firm right.

Pipeline B would allocate the receipt point right to

shipper 2, whose firm capacity right has priority

over shipper 1’s interruptible capacity. Thus, the

capacity allocations would not match and neither

would be confirmed.

65See, e.g., Southwest Gas Corporation v. El Paso

Natural Gas Company, 63 FERC ¶ 61,111 (1993)

(finding that allocation of delivery point rights had

not abrogated Southwest’s delivery point priority

since Southwest controlled the capacity to take gas

away from the delivery point). This case would

seem to suggest that the confirmation by the LDC

takes precedence over upstream primary or

secondary delivery point rights.

66See, e.g., Northwest Pipeline Company, 67

FERC ¶ 61,095 (1994) (mainline constraints

allocated according to path rights rather than point

rights). As this case illustrates, even on web or

displacement systems, capacity path rights may be

defined. 67See text accompanying note 64, supra.

BILLING CODE 6717–01–C

Shipper 1: Pipeline A—Firm Primary at

Delivery Point; Pipeline B—

Interruptible at Receipt Point

Shipper 2: Pipeline A—Firm Secondary

at Delivery Point; Pipeline B—Firm

Secondary at Receipt Point

If both pipelines independently allocate

capacity according to their tariff-based

priorities before seeking confirmation,

neither shipper would be able to flow,

even though shipper 2 has firm capacity

on both pipelines.64

In some contexts, however, gas flows

may be determined by the decision of

the downstream party as to which gas it

will accept.65 If that were the case in the

above example, shipper 2 would flow

gas because it had the priority right on

downstream pipeline B.

The confirmation practices of

pipelines in this situation are not

specified in Commission regulations or

pipeline tariffs. Thus, the result in this

situation is not predictable, which may

raise the costs of doing business.

The Commission is seeking comment

on whether the current system works

efficiently or whether changes to the

current practices are needed. The

comments should focus on: (1) How the

current system works, particularly with

respect to any differences between

interconnections between pipelines and

interconnections between pipelines and

LDCs; (2) whether the current system

impedes efficient competition and

flexibility or raises transaction costs,

and if so, whether the problem results

from current Commission policies, from

a failure to understand and adhere to

those policies, or from a lack of uniform

application of Commission policies; and

(3) whether changes in policies would

help to enhance competition and reduce

the ability of pipelines or shippers to

exercise market power. To help focus

comments, the Commission will lay out

below some options which commenters

can consider. The first set of options

deal with segmentation and receipt and

delivery point priority issues, while the

second deals with issues relating to

pipeline confirmation procedures.

First, the current system under which

receipt and delivery point priorities are

determined on a pipeline-by-pipeline

basis could continue. This option would

be appropriate if current policies do not

unfairly restrict competition or if nonuniform rules are necessary due to

pipelines’ differing operational

capabilities.

Second, all pipelines could be

required to conform to the Texas

Eastern/El Paso requirement that, in a

segmented release, both releasing

shippers and replacement shippers can

designate available primary receipt and

delivery point capacity rights equal to

their contract demand. This would help

to increase efficient competition by

giving buyers a better opportunity to

substitute capacity acquired through

segmented releases for pipeline capacity

or capacity provided by a shipper with

primary point capacity.

Third, to further expand the extent of

efficient competition, all pipelines

could be required to adhere to the

Northwest approach under which

replacement shippers could change

primary point rights to any available

point without the releasing shippers

losing their right to return to their initial

primary point at the end of the release.

The pipeline could still sell the vacated

point to another shipper during the term

of the release. The Northwest policy also

could be extended beyond release

situations to permit a shipper to

segment its own capacity. As described

earlier, a shipper with firm capacity

with a primary receipt point in the Gulf

of Mexico and a primary delivery point

to New York would be able to deliver

gas to Atlanta as a primary delivery

point, while choosing a receipt point

downstream of Atlanta as a primary

receipt point for making a delivery to

New York as a primary delivery point.

Fourth, pipelines could be required to

provide all shippers with firm capacity

rights over the mainline with equal

rights to flow gas past a mainline

constraint point.66 This would increase

shipper capacity options by giving

released capacity flowing to secondary

points priority at a mainline constraint

point along the shipper’s path equal to

pipeline capacity or released capacity

flowing to primary points.

This principle could be expanded so

that all shippers with firm capacity

would have equal rights to receive or

deliver gas at all points along their path.

This would provide a shipper moving to

a secondary delivery point along its

path rights to deliver at that point equal

to shippers buying pipeline capacity or

shippers buying released capacity

which have that point as a primary

delivery point. Such an approach would

ensure that all capacity along the

mainline path would compete equally,

giving shippers seeking capacity more

capacity alternatives from which to

choose. A possible conflict might arise

if the receipt or delivery point could not

accommodate all the receipts or

deliveries sought by the shippers. It is

not clear how frequently such a problem

would occur.

Fifth, a monetary value could be

developed for all receipt and delivery

points so that shippers could choose to

pay for additional primary point rights,

especially those outside their contract

path. Under this approach, shippers

would be able to buy unsubscribed

primary receipt and delivery point

rights independent of mainline

transportation. One issue under this

approach would be to determine a value

for additional receipt and delivery point

rights. One option is to take a strictly

cost-based approach in which the

pipelines would have to establish the

cost of making or receiving deliveries.

Another might be to conduct an auction

for all available points.

The previous options deal with ways

of enhancing the ability of shippers with

mainline capacity at secondary points to

compete with capacity from the pipeline

or other shippers at primary points, but

do not address confirmation practices

across interconnect points. One possible

approach would be for the pipelines to

seek to confirm all transactions before

they apply tariff-based priority rules,

and to require that, in the confirmation

process, pipelines must seek to

maximize the flow of firm

transportation across an interconnect.

Thus, in the example given above,

shipper 2 holding firm capacity on both

the upstream and downstream pipeline

would get priority over shipper 1, since

shipper 1 holds only interruptible

transportation on the downstream

pipeline.67/ Another potential option

would be for priority through pipeline

interconnect points to be determined

based on which shipper has the takeaway capacity on the downstream

pipeline. The Commission requests

comment on these options as well as the

submission of other proposals for

handling confirmations that would

create greater substitutability between

primary and secondary releases and

lower the associated transactions costs
42998 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

68See 18 CFR 284.10(b)(1)(v), Capacity Release

Related Standards 5.3.3 and 7.3.14 (three methods

for valuing bids, highest rate, net revenue, and net

present value). 69See CFR 284.243(e).

while still fairly allocating capacity

among shippers.

C. Capacity Auctions

Auctions are often used as effective

methods of selling goods and services.

A well-structured auction can assure

that pipeline capacity is allocated to the

party placing the greatest value on the

capacity and can assure fairness in the

allocation process by preventing price

discrimination or favoritism by the

capacity seller. An auction provides

customers with equal opportunities to

acquire capacity, preventing the

pipeline or releasing shipper from

treating different bidders differently.

Auctions also have value because they

provide the market with accurate

information on the value of capacity.

If a market is perfectly competitive

with a sufficiently large number of

capacity holders, and equal access to

market information, an auction would

not be necessary to limit the exercise of

market power, because market power

would not be present. But, even in that

case, an auction may help reduce the

transaction costs of trading capacity.

Any attempt to charge more than a

competitive price would result in the

potential buyer looking elsewhere for

capacity.

The current regulations seek to

protect against pipeline exercise of

market power by requiring pipelines to

sell capacity when they have received

an offer at the maximum tariff rate. This

requirement prevents the pipelines from

withholding capacity at the maximum

rate in order to raise prices. The current

regulations, however, do not require

pipelines to sell capacity at a

discounted rate. Thus, pipelines may be

able to exercise market power at rates

below the maximum rate because the

pipeline is not obligated to sell capacity

(can withhold capacity) at less than the

maximum rate.

In markets where market power is

present, an auction that limits capacity

withholding can be an effective method

of limiting the exercise of market power

and creating a more efficient market. In

today’s market, during peak periods, the

price cap may restrict shippers’ ability

to obtain capacity from the pipelines or

may result in shippers paying a higher

price than necessary for delivered gas

either because releasing shippers

exercise market power or because the

market simply is not transparent enough

for potential buyers to be able to locate

and negotiate with alternative capacity

sources. During off-peak periods,

shippers similarly may have to pay

more than necessary to obtain capacity

if pipelines or releasing shippers can

withhold capacity or price discriminate.

Placing all available capacity in an

auction would help ensure that shippers

will pay lower prices both during peak

and off-peak periods, because the

auction process helps to ensure that

prices reflect competitive market forces

rather than resulting from the exercise

of market power or shippers’ inability to

obtain accurate market information.

1. Proposed Auction Requirement

To help prevent the exercise of market

power, the Commission is proposing, in

revised § 284.10(c)(5), to require all

available short-term pipeline firm and

interruptible capacity and released

capacity to be allocated through an

auction process. The proposed auction

requirement applies to all sales of shortterm pipeline capacity, both

interruptible and firm, and released

capacity. Thus, all capacity sold for a

term of less than a year (or whatever

other time period is chosen to define

short-term capacity) would be sold

through an auction process. Using an

auction process for all capacity, during

both peak and off-peak periods, is

necessary to limit the exercise of market

power and to allow the market to

determine the value of capacity.

The Commission is proposing that

pipelines adhere to the following

principles in designing an auction:

• all available short-term capacity

must be sold through an auction;

• daily capacity from the pipeline

must be allocated based on the auction

without the establishment of a reserve

or minimum bid price;

• all eligible shippers must be

permitted to bid with no favoritism

shown to pipeline affiliates or other

shippers;

• the procedures and rules for each

auction, including the auction schedule,

must be disclosed in the pipeline’s tariff

in advance of the auction and must be

applied in each auction;

• capacity must be allocated based on

established criteria and parameters

known in advance to all bidders and the

same criteria and parameters must apply

to pipeline and released capacity; 68 and

• shippers must be able to validate

that the auction was run properly either

through the posting of information

sufficient to permit them to validate that

the winners were selected appropriately

or through the use of other mechanisms,

such as an independent third-party,

which will validate the results.

The requirement of an auction for

short-term capacity still leaves the

question of whether to retain the current

bidding procedure for long-term

capacity release transactions.69

Pipelines are not subject to any auction

or bidding requirements in selling longterm capacity. To ensure comparability,

the Commission, therefore, proposes to

permit shippers to release capacity on a

long-term basis without going through a

bidding process. As is the case for the

pipelines, no sales of long-term capacity

can exceed the pipeline’s maximum

rate.

The proposal for auctions of capacity

raises issues about auction design that

will be discussed below. The first issue

is whether to permit pipelines or

releasing shippers to establish a reserve

or minimum price below which they are

not obligated to sell capacity. The

second is how to design the auction to

work most efficiently.

2. Reserve Prices

The Commission is proposing two

different auction methodologies for

pipeline capacity. For capacity sold for

one day, the Commission is proposing a

daily auction in which pipelines cannot

establish a reserve price. Pipelines

would not be required to sell below the

minimum rate (variable cost) in their

tariffs. For auctions of longer than one

day, pipelines would be permitted to

establish reserve prices.

Prohibiting pipelines from

establishing a reserve price would limit

their ability to withhold capacity.

Requiring pipelines to auction their

daily capacity, without a reserve price,

should be sufficient to prevent them

from withholding capacity for longer

short-term transactions, for instance, a

deal for three months’ worth of capacity.

The pipeline should not be able to

demand a monopoly price for three

months’ worth of capacity because

shippers would not pay that price. A

shipper would pay only the amount that

it would expect to have to pay if it

purchased the capacity in the daily

auction plus a premium for the

insurance value of locking-in the

capacity and price for a set period of

time.

For capacity available for periods of

longer than one day, pipelines could

establish reserve prices. Pipelines may

have a legitimate basis for believing that

the market value for their capacity on a

single day is less than what the capacity

will be worth at a later date or if the

capacity ultimately was sold on a

longer-term basis.

The auctions of pipeline capacity

would work in the following manner.

When a pipeline has firm capacity
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42999

70The market clearing price is the price at which

all available capacity is sold and no shipper bidding

that price or higher would be denied capacity.

71Pipelines are generally considered to be natural

monopolies because they have very large fixed

costs, with significant economies of scale. Thus, it

is less expensive to have one pipeline provide

service than to have two or more pipelines compete

over the same route. However, when a natural

monopolist is at the efficient size, where the cost

of producing one additional unit (marginal cost)

equals the price that a customer is willing to pay

(demand), that price is not sufficient to cover the

average costs of the firm. See R. Posner, Economic

Analysis of the Law, 251–264 (2d ed. 1977).

72Many pipelines, however, may be at less than

efficient size and, therefore, be sufficiently

congested that they will be able to recover their

costs.

73These options are discussed in the NOI on

long-term services which is being issued

contemporaneously with this NOPR.

74Shippers have complained that the

Commission’s current bidding process for capacity

release is too cumbersome and slow. See Secondary

Continued

available for more than one day, for

instance six months beginning on July 1,

the pipeline could establish a reserve

price for the six month block of

capacity. If that capacity was not sold by

June 30, the pipeline would have to sell

the capacity for July 1 through the

auction process for that day. The

pipeline, however, could continue the

reserve price for shippers willing to bid

on the six month (less one day) block of

capacity. This process would continue

until the capacity is sold.

The daily auction also would apply to

available pipeline storage capacity. But

comments should address whether a

daily auction for storage capacity is

practical, whether different rules should

apply to storage capacity, and whether

storage capacity needs to be included in

the daily auction to prevent capacity

withholding.

The Commission is proposing that all

short-term releases of capacity by firm

shippers take place through the auction

to ensure that capacity is allocated on a

non-discriminatory basis to the

purchaser placing the greatest value on

the capacity. Releasing shippers would

be permitted to place reserve prices on

their capacity, because they have a

legitimate basis for retaining capacity

for their own use. For instance, firm

shippers may need to reserve capacity to

meet unanticipated weather changes, to

replace depleted storage, or to change to

a substitute supply to ensure reliable

service. Moreover, firm capacity holders

should not be able to withhold capacity

because, under the proposal, if a firm

capacity holder does not nominate (use)

its capacity, the pipeline would be

required to sell the unnominated

capacity as interruptible or short-term

firm capacity through the auction.

The Commission, however, requests

comment on a number of aspects of its

proposed approach to reserve prices.

Commenters should address whether

requiring pipelines to sell capacity at

the bid price for only one day is

sufficient to limit the pipeline’s ability

to withhold capacity. Commenters

should address the question of the price

at which capacity should be sold. For

example, should all shippers pay the

market-clearing price (lowest price

necessary to get capacity) 70 or should

each shipper pay the price it bids?

Commenters also should address

whether the proposed requirement to

sell pipeline daily capacity without a

reserve price could cause cost-recovery

problems for some pipelines. If shippers

on a pipeline where capacity is not

sufficiently constrained relied

exclusively on the daily auction, the

revenue received may be insufficient to

cover the pipeline’s costs allocated to

interruptible and short-term firm

capacity.71 The daily auction without a

reserve price also may affect the ability

of pipelines to resubscribe firm capacity

at maximum rates as contracts expire,

which could cause cost recovery

problems. If the pipeline is expected to

be uncongested, shippers may prefer to

rely on the daily auction rather than

resubscribing to firm capacity.

On the other hand, it may be that

most pipelines are sufficiently

constrained so that the daily auction

requirement will not limit their ability

to recover their costs.72 The proposal to

limit the requirement to sell capacity

without a reserve price to one day may

itself reduce the risk to pipeline cost

recovery. Some shippers may be

unwilling to take the risk of not having

firm capacity.

In addition, on some pipelines, the

requirement for a daily auction may give

large customers greater leverage over

pipelines in negotiating renewal

contracts. When a large customer’s firm

contract expires, it may well decide not

to renew that contract and to submit low

bids for capacity in the daily auction. If

the purchaser is the principal, if not the

only, shipper for a large block of

pipeline capacity, it could be reasonably

confident that it would not be outbid by

other shippers.

There are potential approaches to

address these kinds of cost recovery

problems if they materialize, without

rejecting the benefits of an auction

process. One set of possibilities is for

pipelines to charge a fixed access charge

to all customers using its system to

recover fixed costs or a volumetric usage

charge designed to recover the fixed

costs of the system. These are similar to

methods that are being considered in

connection with congestion pricing in

the electric industry.73

Another alternative is to allow the

pipeline to set a reserve price in the

daily auction that is above variable

costs, but below the current maximum

rate. In effect, this would be a minimum

price floor below which the pipeline

would not have to sell. The price floor

could be established by using the dollar

amounts associated with specified costof-service elements, such as rate of

return, or could be established at a

percentage of the maximum rate. This

approach would still provide shippers

with protection against the exercise of

market power and would prevent the

pipeline from discriminating in the

prices it charges to specific customers

while permitting the pipeline a

reasonable opportunity to recover its

fixed costs. However, preventing the

pipelines from price discriminating may

still result in cost recovery problems.

Another approach would be to limit

the auction only to transactions above

the maximum rate (as converted to a

daily rate). The current regulations

require a pipeline to sell capacity at the

maximum rate to all shippers, thus

preventing the pipeline from

withholding capacity at the maximum

rate to derive a higher price. A

requirement that pipelines must auction

capacity at the market clearing price,

whenever such prices exceed the

maximum rate, would continue the

protection in the current regulations. It

would protect against the pipelines’

withholding capacity to raise price and

would prevent them from price

discriminating between shippers,

because all shippers would pay the

market clearing price. It also would help

to ensure that the pipelines’ opportunity

to recover their cost-of-service is not

impaired. However, such an approach

would not help to constrain the

pipelines’ ability to exercise market

power at prices below the existing cap.

Commenters should address the

merits of the potential methods for

dealing with situations in which the

requirement to sell capacity without a

reserve price would result in cost

recovery problems for pipelines.

Commenters also should address

whether solutions should be determined

on a pipeline by pipeline basis or

whether there needs to be a uniform

approach applicable to all pipelines.

3. Auction Design

The Commission recognizes the need

for the auction to work quickly and

efficiently.74 Shippers buying capacity
43000 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

Market NOPR, IV FERC Stats. & Regs. Proposed

Regulations at 33,244.

75 18 CFR 284.10(b)(1)(v) (1997), Capacity Release

Related Standards 5.3.2.

76The Commission’s current regulations, for

instance, provide for longer posting and bidding

periods for transactions of five months or longer

than for shorter-term transactions. 18 CFR

284.10(b)(1)(v), Capacity Release Related Standards

5.3.2.

77See Sea Robin Pipeline Company, 81 FERC

¶ 61,041, at 61,225 (1997); Pacific Gas Transmission

Company, 76 FERC ¶61,258 (1996).

78 18 CFR 284.10(b) (1)(v), Capacity Release

Related Standards 5.4.1, 5.4.3.

79 18 CFR 284.7(c) (6).

not only want the ability to consummate

deals quickly, they also want the

assurance they can acquire capacity in

sufficient time to finalize their gas

supply arrangements. The current

system, which takes four hours, and

must be completed the day prior to

nominations,75 is inadequate to meet the

needs of the market.

An electronic auction, designed

properly, can be efficient and can

operate faster than the current process

of sending facsimiles and using

telephones to arrange deals. Electronic

auctions used for trading stocks and

other commodities demonstrate this

efficiency.

There are a variety of auction formats

that would meet the Commission’s

criteria as well as provide the speed the

market requires. The Commission

ultimately would decide on the proper

auction format. It could do so either

through this rulemaking, through a

subsequent proceeding, or by reviewing

proposals on a pipeline-by-pipeline

basis, and it requests comment on

which approach would be preferable. To

assist the Commission in evaluating

potential auction formats, comments

should focus on the details of how the

auction or multiple auctions should be

conducted and on whether a uniform

auction format should be applied to all

pipelines.

For example, different auction formats

could be used for intra-day, daily,

monthly, and longer auctions.76

Auctions for capacity of one day or less

could be held as part of each intra-day

nomination opportunity or could be

held continuously, every hour during

the business day. Consideration also

should be given to establishing

standardized parameters for recall or

other conditions in order to facilitate

trading for daily or intra-day capacity.

To further expedite the daily auction, it

could be integrated with the nomination

process using a computerized auction

process.

To accomplish such integration,

releasing shippers could submit

nominations establishing the minimum

or reserve price or prices at which they

would be willing to sell some or all of

their capacity. For capacity the shipper

wanted to use, it could establish a very

high reserve price while for capacity it

clearly wanted to release it could

establish a zero reserve price. Bidders

would submit nominations with the

price they are willing to pay. Pipelines

would be required to offer the released

capacity along with their own available

capacity. The pipeline would then

apply Commission-approved procedures

to determine a market clearing price and

all bidders submitting bids above this

price would be automatically

scheduled.

Auctions for periods longer than a day

could use a different format, while

auctions of monthly capacity could

employ posting and bidding periods

that would coincide with the industry’s

monthly gas purchasing cycle. Longer

posting and bidding times might be

needed for auctions of greater than one

month.

The Commission also requests

comment on whether alternatives to the

comprehensive auction described above

would be sufficient to protect against

the exercise of market power. One

possibility would be only to require

pipelines to sell available interruptible

capacity to the highest bidder. While

such an approach would not cover

capacity releases or sales of pipeline

firm capacity, it may be sufficient to

ensure that capacity is not withheld

from the market to raise price. For

instance, it would protect against the

incentives present in a duopoly or

oligopolistic market in which firm

shippers and the pipeline recognize a

mutual interest in withholding capacity.

If the releasing shipper tried to withhold

capacity by not releasing it, the

pipeline, under this option, would be

forced to sell the resulting interruptible

capacity to the highest bidder. Pipelines

already are generally required to

allocate interruptible capacity based on

price when they are unable to satisfy all

nominations for interruptible service at

the maximum rate.77 While this

proposal would expand the requirement

to all transactions, it could be

implemented using the same process.

The information the Commission is

proposing to require pipelines to

provide is intended to enable the market

to effectively monitor transactions.

Indeed, the knowledge that information

will be provided to the market should

itself act as a check against

anticompetitive transactions.

D. Information Reporting and Remedies

for the Exercise of Market Power

1. Reporting Requirements

In creating a competitive marketplace,

information plays a crucial role. Equal

access to relevant information is

necessary for shippers to make informed

decisions about capacity purchases and

for markets to perform efficiently.

Market information also is needed so

that the Commission and shippers can

monitor transactions to determine if

market power is being exercised.

The information needed by the

market, both for decision-making and

monitoring purposes, falls into three

general categories: information on

capacity availability, information on the

structure of the market, and information

on capacity transactions, such as rates,

contract duration, and contract terms.

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 will

help shippers structure gas transactions

and cast light on whether shippers or

the pipeline may be withholding

capacity. To assess market structure,

shippers and the Commission need to

know who holds or controls capacity on

each portion of the pipeline system so

they can determine the number of

potential sources of capacity.

Transactional information provides

price transparency so shippers can make

informed purchasing decisions as well

as permitting both shippers and the

Commission to monitor actual

transactions for evidence of the possible

exercise of market power.

The current regulations already

require the posting of much of the

needed information. The proposals here

would require expansion of these

current reporting requirements, but such

expansion appears justified to give

shippers the information they need both

for competitive and monitoring

purposes. Moreover, in some cases, the

proposals are designed to ensure that

the same information is provided for

competing types of capacity. For

instance, detailed information on

capacity release transactions, including

the releasing and replacement shipper

names, the rate paid, and points covered

by the release are already being posted

at the time of the transaction.78 In

contrast, pipelines are only required to

file limited information on their

discount transactions well after the

transaction has taken place.79
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43001

80 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.

81Some pipelines now require disclosure of

affiliate transactions for capacity release

transactions. 18 CFR 284.10(b) (1) (v), Capacity

Release Related Standards 5.4.3. This requirement

would become mandatory for all pipelines under

this proposal.

82Senior employee would be defined as an

employee who supervises non-clerical employees

engaged in transmission/reliability or gas marketing

functions.

83Contemporaneously with this NOPR, the

Commission is issuing a final rule adding a

requirement to 18 CFR 161.3 requiring pipelines to

post the names and addresses of their marketing

affiliates on their web sites. Reporting Interstate

Natural Gas Pipleline Marketing Affiliates on the

Internet, Docket No. RM98–7–000. For the NOPR,

see Reporting Interstate Natural Gas Pipeline

Marketing Affiliates on the Internet, Notice of

Proposed Rulemaing, 63 FR 27526 (May 19, 1998),

IV FERC Stats. & Regs. Proposed Regulations ¶

32,530 (May 13, 1998). Should the Commission

adopt the regulations proposed in this NOPR, the

changes could be consolidated with the

requirement for posting affiliate names and

addresses.

84American Electric Power Service Corporation,

83 FERC ¶ 61,357 (1998).

85 18 CFR 284.10(b)(1)(v), Capacity Release

Related Standards 5.4.1, 5.4.3.

86 18 CFR 284.7(c)(6).

a. Information on Available Capacity.

For capacity availability, the current

regulations require posting of

information about the amount of

operationally available capacity at

points and on the mainline.80 But, in

order to effectively determine whether

capacity is being withheld, information

also is needed to show the total design

capacity of the point or segment and the

amount scheduled on a daily basis. The

Commission proposes in proposed

section 284.14(d) to add this

information to the posting requirements.

The Commission also proposes, in

proposed § 284.14(d) to require

pipelines to post information on

planned and actual maintenance or

system outages that would reduce the

amount of capacity available. While

some pipelines currently post such

information, it is not currently a

Commission requirement. Shippers can

better make decisions about their use of

capacity if they 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.

b. Information on Market Structure.

With respect to the structure of the

marketplace, pipelines currently file

with the Commission, and post on their

Internet web sites, an Index of

Customers, which (under § 284.106(c)(3)

of the regulations, new § 284.14(b))

provides information on the names of

shippers holding firm capacity, the

amount of capacity they hold, and the

duration of their contracts. But the

Index of Customers does not provide

information on the capacity path held

by the shipper, so the data cannot be

used to determine which shippers can

compete in providing capacity on

segments of the pipeline. The

Commission, therefore, proposes to add

a requirement, in proposed section

284.14(b), to include in the Index of

Customers the receipt and delivery

points held under the contract, the

zones or segments in which the capacity

is held, and the shipper’s contract

number. The contract number is 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. Since the current capacity release

requirements do not include the

contract number, the Commission is

proposing to require that the number be

provided.

In addition, to permit effective

monitoring of the capacity held on

pipelines, it is necessary to know

affiliate relationships, which may affect

the amount of capacity held by a single

parent entity. The Commission,

therefore, proposes to add a requirement

in proposed section 284.14(b) that

pipelines disclose in the Index of

Customers any affiliate relationship

between the pipeline and the holder of

capacity and any affiliate relationship

between holders of capacity.

Additionally, the Commission would

require disclosure of affiliate

transactions in capacity release

transactions.81

The Commission also is proposing to

expand its affiliate regulations to

provide more information to permit

monitoring and self-policing of affiliate

transactions. The Commission is

proposing to add a new section 161.3(i)

and revise section 284.286(c) to require

pipelines to post on their web sites

organizational charts, and job

descriptions, including the names of

senior employees,82 for the pipeline, its

marketing affiliates, and gas sales

operating units.83 The pipeline would

not be required to include employees

whose duties are purely clerical or those

who do not have access to information

concerning the processing or

administration of requests for service

(such as employees who operate or

repair the pipeline facilities). The

Commission also is proposing to

include in the Internet posting the list

of the operating personnel and facilities

shared by the interstate pipeline and its

marketing affiliate or gas sales operating

unit. The pipelines currently provide

this information in their tariffs, under

§ 250.16(b)(1), and this requirement will

make all affiliate information easily

available on the Internet. The

Commission has adopted a similar

requirement in the electric industry to

help monitor, and protect against,

improper communications between

transmission and wholesale merchant

function employees.84/

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. The Commission, therefore, is

proposing to add a requirement in

§ 284.14(b) that pipelines disclose such

agents or asset managers when they

control 20% 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. This information would help to

show the degree of control over pipeline

capacity that an agent or asset manager

may exercise.

c. Transactional Information.

Pipelines already provide transactional

information for their own capacity

transactions and for capacity release

transactions, although the type of

information and the manner of

accessing it differ. For capacity release

transactions, pipelines provide via the

Internet the names of the releasing and

acquiring shippers, the price, the receipt

and delivery points under the deal, the

quantity of capacity traded, and the

duration of the deal.85 This information

is posted immediately upon

consummation of the transaction. The

information provided about pipeline

transactions is not as complete, nor is it

as timely or as easy to access. Pipeline

discount reports are filed, but not

posted, 15 days after the close of the

billing period applicable to the

transaction and include only the rate

paid and the maximum rate, but do not

include any information on volumes,

the receipt and delivery points under

the transaction, or the duration of the

deal.86

To assure parity of transactional

information, the Commission proposes,

as described, to require the pipelines to

provide the same information about

their transactions as is currently

provided about capacity release

transactions. The Commission

recognizes that some pipelines and

shippers have previously expressed

concern about posting information on

shipper names to preserve
43002 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

87See Buckeye Pipe Line Company, 53 FERC

¶ 61,473, at 62,683 (1991) (basing price changes in

non-competitive markets on the changes in

competitive markets).

confidentiality. However, shipper

names currently are posted for capacity

release transactions and the

Commission is unable to see how other

shippers can effectively monitor

transactions for favoritism if names are

not provided.

In many cases, much of the

transactional information would be

provided in a properly designed,

transparent short-term capacity auction.

To ensure that the information is

provided, the Commission is proposing

to add a new section, 284.14(c), that

would 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. For firm service, the

Commission proposes that the pipelines

provide contemporaneously with the

execution of the contract, the same

information already posted for capacity

release transactions: the parties to the

contract; the contract number for the

shipper receiving service and for the

releasing shipper; the rate charged

under each contract; the duration of the

contract; the receipt and delivery points

and mainline segments covered by the

contract; the contract quantity; any

special terms and conditions applicable

to the contract; and any affiliate

relationship between the pipeline and

the shipper or between the releasing and

replacement shipper. For interruptible

transportation, the following

information on a daily basis would be

required: the name of the shipper; the

rate charged; the receipt and delivery

points and mainline segments over

which the shipper is entitled to

nominate gas; the quantity of gas the

shipper is entitled to nominate; and any

affiliate relationship between the

shipper and the pipeline.

2. Remedies if the Exercise of Market

Power Is Found

While the Commission’s proposals

should enhance efficient competition

and mitigate market power, the

Commission is committed to take

remedial action when pipelines or

shippers exercise market power.

Because the facts of each such case

would be different, it is difficult to

describe in advance the type of remedy

the Commission would impose if market

power is being exercised, and not all

remedies would be appropriate in every

case. As a general matter, the

Commission’s preference would be to

use a structural remedy that would

enhance efficient competition.

Examples of such remedies would

include revising contractual provisions

that inhibit competition, strengthening

the capacity auction requirement,

requiring pipelines to build taps to

increase access to capacity, or

conducting auctions to determine

whether sufficient demand exists for

additional construction. Another

potential remedy would be to use a

benchmark for regulating price increases

based on price changes in comparable

competitive markets.87 Reimposition of

some form of price cap also would be

a possible option if other available

remedies are not adequate. Commenters

should address the potential remedies

suggested here as well as suggest other

possible remedies.

IV. Penalties and Operational Flow

Orders

A major goal of the changes proposed

in this NOPR is to improve competition

in the short-term market both to

improve the efficiency of the market and

to protect against the potential exercise

of market power. To improve efficiency

and competition across the pipeline

grid, the Commission previously has

adopted standards, promulgated by

GISB, as well as the Commission’s own

standards governing business practices

and electronic communication. But

these standards have only partially

addressed the effect that pipeline

operational flow orders, tolerances, and

penalties have on competition across

the pipeline grid.

Penalties and operational flow orders

(OFOs) are necessary tools to deter

shipper behavior that threaten the

integrity of the pipeline system. At the

same time, they have a significant effect

on efficiency and competition by

restricting shippers’ abilities to

effectively use their transportation

capacity. As just one example of the

interrelation between penalties and the

short-term market, penalty levels can

affect the value of capacity in the shortterm market; shippers needing gas might

be willing to buy transportation capacity

at any rate less than the penalty they

would have to pay if, for instance, they

overran their contract entitlement. In

this section, the Commission considers

reforms to its policies for regulating

OFOs and transportation penalties to

ensure that they can continue in their

legitimate role of protecting pipeline

integrity, while not unnecessarily

limiting or restricting competition in the

marketplace.

These policies have their origin in the

regulatory reforms instituted by the

Commission in Order No. 636. To

promote competition in the sales and

transportation markets, Order No. 636

required that pipelines unbundle sales

and transportation services. The

bundled sales service provided

considerable flexibility for the pipeline

in how it would meet the requirements

of its customers, particularly on peak

days. In the implementation of Order

No. 636, the Commission was

particularly concerned that the

unbundled transportation services be as

reliable as the bundled sales service the

pipelines previously provided.

To address that concern, the

Commission accorded each pipeline

considerable discretion and authority to

operate its system to ensure its

reliability, particularly during peak and

emergency times. One important tool

the Commission has sanctioned is the

use by pipelines of OFOs that can

restrict service or require shippers to

take particular actions. As examples,

Commission-sanctioned OFOs can:

reduce or eliminate tolerances for

imbalances or contract overruns;

institute severe penalties; restrict intraday nominations; restrict or eliminate

the use of secondary receipt and

delivery points; and restrict firm storage

withdrawals and eliminate interruptible

storage withdrawals.

Another means the Commission has

provided pipelines to protect system

reliability is the approval of tariff

penalties designed to deter shippers

from creating imbalances or from

overrunning contract entitlements. The

Commission has approved particularly

high penalties, with little or no

tolerance for imbalances or overruns,

applicable during peak or emergency

periods to protect pipeline reliability.

The Commission also has approved

penalties, usually at lower dollar levels

and greater tolerances, applicable

during non-peak times to help ensure

that shipper imbalances or overruns do

not create emergency conditions on a

pipeline that could have been prevented

or minimized.

The Commission believes that a

review of present policies and pipeline

practices in these areas is appropriate as

part of the new approach to pipeline

regulation proposed in this NOPR— and

particularly its objective of promoting

competition in the short-term market.

On initial review, it appears that some

pipeline practices and Commission

policies regarding penalties can inhibit

competition not only with respect to

transportation, but also in the sale of

natural gas. 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
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43003

88See Industry Surveys the Damage as Winter’s

Strength Runs Out, Natural Gas Intelligence, April

22, 1996, at 1; Freezer Burn, Gas Daily’s NG, April

1996, at 30.

89See Panhandle Eastern Pipeline Company, 78

FERC ¶ 61,202, at 61,876 (1997)(penalties ranging

from $25 per Dth for variances of 5–10% to $200

for variances over 50%).

90See text accompanying note 22, infra.

91Standards For Business Practices Of Interstate

Natural Gas Pipelines, Order No. 587-G, 63 FR

20072 (Apr. 23, 1998), III FERC Stats. & Regs.

Regulations Preambles ¶ 31,062 (Apr. 16, 1998).

points where it has no purchase or sales

agreements. An OFO that limits or

eliminates a shipper’s storage

withdrawals may require the shipper to

purchase more costly gas on the spot

market if the OFO allows the shipper to

shift to new points. The longer OFOs are

in effect, the more restrictive they

become. Across all customers, OFOs

may fragment markets by making it

impossible for many potential sales of

gas or transportation services to take

place.

High penalties on contract overruns or

imbalances as well as low or no

tolerances during peak periods may also

operate to limit and distort market

forces. For example, not all shippers

have immediate access to metering

information on their imbalances or even

the volumes of gas they receive at their

delivery points. This lack of information

may adversely affect shippers in several

ways. For example, to avoid overrun

and/or imbalance penalties, shippers

may not maximize use of pipeline

transportation, and shippers may

contract for more transportation

capacity than they need. Also, the lack

of information on imbalances and

delivered volumes may inhibit shippers

from trading imbalances or

transportation capacity that could

alleviate or prevent system operational

problems.

The presence of severe penalties/

tolerances during peak or emergency

periods also may preclude other uses of

market forces that could alleviate or

prevent system operational problems.

For example, a shipper that delivers

more gas than nominated into a pipeline

when the pipeline is short of gas would

help to maintain system integrity. Yet,

under most currently approved tariff

provisions, the shipper could be

penalized for doing so.

Moreover, Commission-authorized

penalties may provide an opportunity

for shippers to engage in a form of

penalty arbitrage. For example, during

the 1995–96 winter there was a shortage

of natural gas to serve Chicago markets.

Shippers reacted by intentionally

overrunning contract entitlements on

those pipelines and LDCs that had the

lowest penalties for contract overruns.

88 In that situation, penalties appeared

to have skewed choices shippers might

otherwise have made. The consequence

was that pipelines in the Chicago area

appear to have entered into bidding

wars for the highest overrun/imbalance

penalties, with penalties for large

variances running as high as $200/dth.89

The fluctuation of transportation

values also supports a reexamination of

Commission policies on OFOs and

penalties. As discussed earlier, the

value of transportation varies widely.

For example, as shown on the earlier

graph, during the winter of 1996–1997,

the value of capacity was double the

maximum rate, while during the winter

of 1995–1996, spikes occurred on

several occasions to much higher levels,

with the highest value reaching $10/

MMBtu.90

The fluctuation in short-term

transportation values during peak

periods suggests the need to increase

opportunities, as much as practicable,

for shippers to obtain transportation

services at the lowest competitive price

during such times. Yet, the pipelines’

current OFO and penalty structures may

restrict shippers’ options more than is

necessary.

Current pipeline tariff provisions for

remedying monthly imbalances of a

shipper—often described as ‘‘cashouts’’— also appear to inhibit market

forces and may be otherwise unfair.

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 high

and deliver more than it takes when gas

prices are low. At peak, such behavior

may imperil system-wide reliability and

unnecessarily trigger OFOs and

emergency penalties that restrict or

eliminate market forces. Such gaming

also promotes inefficient use of pipeline

capacity. For example, to the extent

gaming is substantial on a pipeline, the

pipeline is likely to react by imposing

stricter imbalance tolerances and higher

penalties. Moreover, gaming by some

shippers is subsidized by other

shippers. A pipeline’s tolerance and

penalty levels are often a function of the

amount of storage it has retained; a

pipeline with more storage can tolerate

greater imbalances. But all shippers pay

for storage in their firm rates.

Accordingly, if a pipeline reduces

tolerances and raises penalties due to

the behavior of some shippers, the firm

shippers lose the flexibility for which

they are paying.

The apparent problems associated

with current OFO and penalty tariff

provisions suggest the need to reorient

policy away from penalties and towards

promoting the opportunities for

shippers to avoid penalties and to

prevent penalty situations, particularly

by allowing shippers to avail themselves

of remedies that the marketplace can

provide. Such remedies would include

the trading of imbalances, the provision

of timely information about system

imbalances so shippers can better

anticipate adverse operational

conditions and avoid possible penalties,

and no harm no foul rules under which

shippers will not be penalized for

actions that help maintain the

operational integrity of the pipeline

system. Stated in other terms, while

there may always be a need for penalties

and OFOs, the adoption of policies that

promote the opportunity for shippers to

avoid penalties and prevent penalty

situations, particularly by reliance on

market forces, may be the most efficient

means of ensuring the reliability of a

pipeline’s system operations. Towards

this end, the Commission, in Order No.

587-G, recently required pipelines to

permit shippers to offset imbalances

across their own contracts and to trade

imbalances with other shippers.91

Accordingly, the Commission

proposes to revise section 284.13 of its

regulations to establish the following

policies. First, the Commission proposes

to require each pipeline to provide, 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. The

adoption of this policy is a critical first

step to enhancing the opportunities of a

shipper to avoid penalties and help

prevent penalty situations. Second, to

ensure greater shipper flexibility, the

Commission proposes to require that

pipelines have in place only those

transportation penalties that are

necessary and appropriate to protect

system operations. Third, the

Commission proposes to require that

pipelines provide services, to the extent

operationally feasible, that facilitate a

shipper’s ability to manage imbalances,

which will also help the shipper avoid

penalties and prevent penalty

situations. Finally, the Commission

proposes to require pipelines to adopt

incentives and procedures that will

minimize the use and potential negative

impact of OFOs.

As discussed below, the Commission

solicits comments on these proposed

policies. The Commission also invites
43004 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

92See Northern Natural Gas Company, 77 FERC

¶ 61,282, at 62,236 (1997); Panhandle Eastern

Pipeline Company, 78 FERC ¶ 61,202, at 61,876–

77 (1997), reh’g denied, 82 FERC ¶ 61,163 (1998).

93See Tennessee Gas Pipeline Company, 81 FERC

¶ 61,266, at 62,312; reh’g denied, 83 FERC ¶ 61,063,

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).

comments on its assessment, set forth

above, of current OFO and penalty tariff

provisions on which the proposed

policies are based. Specifically, the

Commission solicits comments on how

well these current tariff provisions

protect the integrity of system

operations, the extent to which such

provisions have created the problems

discussed above, and whether changes

to such tariff provisions are warranted.

A. Pipelines Should Provide, on a

Timely Basis, as Much Imbalance and

Overrun Information as Possible

The Commission proposes to require

each pipeline to provide, 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. Providing such

information is a critical first step to a

new Commission approach to penalties.

To begin with, such information, by

itself, would help shippers avoid

overruns and imbalances. Moreover,

providing each shipper with

information on the precise level of its

deliveries and imbalances would help

the shipper maximize the use of its

transportation rights on the pipeline

system. Such information could also

allow the pipelines to reduce the level

of penalty-free tolerances and so reduce

system costs (e.g., storage capacity to

provide such tolerances). Finally, such

information together with information

on system imbalances would facilitate

trading of imbalances and capacity or

other self-help measures that in turn

could alleviate or prevent conditions

that imperil system integrity.

Under the proposed regulation,

§ 284.13(c)(2)(iv), the pipeline would

not be required to install real time

meters. The burden on the pipeline

would be limited to distributing on a

timely basis—i.e., so that the shipper

has a reasonable opportunity to avoid

penalties—the information the pipeline

currently has on deliveries and

imbalances at each shipper’s delivery

point as well as system imbalances. The

pipeline would be required 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

pipeline could post relevant system

imbalance information more generally.

The obligation that such information be

provided on a timely basis would 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.

During technical conferences in

individual cases, relating to proposals

by pipelines to institute or increase

penalties, many pipelines have

provided assurances that they were

moving toward better metering on their

system. On the other hand, customers

have complained of the imposition of

penalties because existing metering

equipment was insufficient to provide

them with timely information on

deliveries and imbalances. An

important question raised by the

proposed policy is the manner in which,

if at all, the Commission should address

the situation in which a shipper has

receipt or delivery points at which there

is not the type of metering and related

equipment that would provide the

shipper with timely information on its

deliveries and imbalances. The

Commission sets forth below two

options and solicits comment on them.

One option, which would be a

departure from the proposed policy set

forth above, is to require the pipeline to

install the equipment that would

provide all shippers with timely

information on imbalances and

deliveries. Important questions that

should be addressed when considering

this option are, first, the extent to which

such equipment is not in place today

and, second, the extent to which the

shippers without such equipment desire

the information that would be provided.

For example, the Commission is aware

that marketers and producers have

voiced complaints about the lack of

timely information on deliveries and

imbalances. Those complaints suggest

that there may be more of a problem in

obtaining timely information at receipt

points than at delivery points.

A closely related and critical question

is the cost of purchasing and installing

the equipment that will provide timely

information. Those costs must be

compared in some manner to the

benefits of providing the equipment.

The question of costs raises a host of

other related questions. For example,

who should pay for the equipment—the

pipeline (who could recover the costs in

generally applicable rates) or the

shipper? Is it appropriate to require all

shippers to have access to such

information? For example, it may be

cost effective only for large shippers.

Should the Commission require the

metering needed to provide timely

information only at those receipt/

delivery points where the gas volumes

are large enough to cover the equipment

costs, and exempt the remaining

receipt/delivery points? If so, what

alternatives are appropriate for receipt/

delivery points of small shippers to

provide some parity of treatment?

A second option would be to forbid a

pipeline from imposing a penalty for an

overrun/imbalance that does not

threaten system reliability unless the

pipeline has metering equipment to

measure the imbalance/overrun and

notifies the shipper in a timely manner

of the imbalance/overrun. The intent of

this option is to give a pipeline an

incentive to install only the metering

equipment associated with imbalances

or overruns that may imperil system

integrity. The option also would prevent

penalties that a shipper would have

been in a better position to avoid with

timely information.

This option also raises the question of

who should bear the costs of the

enhanced metering and related

facilities. Another relevant concern is

the extent to which the option could be

implemented—is there an objective

basis to determine which penalties are

required, and in what situations, to

prevent realistic threats to a pipeline’s

system integrity?

The Commission solicits comments

on its proposal, the alternative options,

and the related questions. The

Commission also solicits other

alternative proposals that commenters

believe merit consideration.

B. Transportation Penalties Must Be

Necessary and Appropriate to Protect

System Operations

The Commission proposes to require

that pipelines have in place only those

transportation penalties that are

necessary and appropriate to protect

system operations. 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.92

The Commission questions whether

there is necessarily a connection

between the high level of penalties that

have been authorized and the level that

is necessary to ensure system reliability.

Also, the Commission is aware that

some pipelines have penalties that are at

the same level during peak and nonpeak periods and may be imposed

regardless of whether the pipeline is

faced with emergency conditions.93 In

light of these considerations, the

Commission solicits comments on
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43005

whether currently effective penalties are

the most appropriate and effective

penalties to protect system operations.

The Commission also solicits comments

on the specific criteria the Commission

should rely on in determining what

penalty provisions would be the most

appropriate and effective.

There are many specific options the

Commission may pursue in this area on

which comments are requested. One

option would be to require, on an

industry-wide basis, penalties that are

not set at specific dollar levels, but

instead reflect the varying gas

commodity prices that are available to

the shipper—for example, a regional

index plus an adder. The use of such

indices could allow a more effective

deterrence based on current market

conditions. For example, a penalty

based on commodity prices might

eliminate a recurrence of the situation

during the 1995–96 winter in the

Chicago market where shippers sought

to overrun contract entitlements on the

pipeline system with the lowest stated

dollar penalty.

A related option is for the

Commission to establish procedures that

would allow all segments of the natural

gas industry to form a consensus, to the

extent practicable, on penalty tariff

provisions that could be uniform either

on a national or regional basis. Such

provisions could:

• define the particular penalties and

to whom they would apply;

• implement cash-out provisions on

all pipelines;

• set tolerance levels;

• determine the time periods when

the penalties would be applicable;

• define the time periods to notify

shippers of penalties; and

• allow make-up and/or trading of

imbalances.

A prominent concern underlying this

option is to eliminate the gaming where

a shipper shifts capacity use among

pipelines to overrun its rights on the

pipeline that has the lowest level of

penalties. Setting uniform standards for

penalty provisions should reduce this

gaming problem and the incentive for a

pipeline to adopt ever more onerous

penalty provisions to avoid having the

least onerous penalties in an area or

region.

Another objective underlying this

option is to eliminate the adverse effects

on competition that are caused by the

fact that penalty provisions vary from

pipeline to pipeline. Such variation

gives rise to administrative costs and

uncertainty and acts as a disincentive

for shippers seeking alternative

suppliers of gas and transportation

services.

The Commission has successfully

prompted, by adopting

recommendations of GISB, the

standardization of many of the operating

rules of interstate pipelines to enhance

competition. In that regard, the

Commission stresses that the intent of

this option is not to determine

standardized penalty provisions as part

of the rulemaking, but rather to initiate

a process in which a consensus may be

achieved. The Commission solicits

comment on whether the industry could

develop such standards through GISB or

whether the Commission would need to

establish its own process for developing

the standards.

A variant of the last option is to

establish procedures that would also

include state representatives that could

facilitate the coordination of (a) penalty

provisions used by interstate pipelines

with (b) penalty provisions that are used

by state regulated entities—LDCs,

Hinshaw and intrastate pipelines. The

Commission believes that such

coordination would better address the

problem of gaming as well as enhance

competition in both the sales and

transportation of natural gas. State

regulators are particularly invited to

comment on the desirability of this

option as well as to suggest procedures

to implement it.

In addressing the proposals to

develop a consensus process,

commenters should provide their views

on the practical extent to which certain

types of penalty provisions can be

standardized. For example, it may be

impractical to adopt particular levels of

penalties or tolerances on a national or

even regional basis, given the different

operational characteristics of each

pipeline. The Commission also seeks

alternative proposals to developing a

consensus process that would address

the goals, described above, of

eliminating gaming and the

administrative costs and uncertainty

that arise due to the fact that penalty

provisions vary from pipeline to

pipeline.

Another option would be to provide

an automatic credit to shippers for a

significant portion of the imbalance or

contract overrun penalty revenues a

pipeline collects. Such a credit would

not be provided to those shippers that

incurred the imbalance or overrun

penalty. Current Commission policy is

not to provide an automatic credit, but

to take such penalty revenues into

account in a rate case to develop a

pipeline’s revenue requirement.

Customers of pipelines have often

complained that such an approach is

inappropriate when pipelines are no

longer required to file rate cases on a

periodic basis. Those customers argue

that to the extent the penalty revenues

are not reflected in rates, penalty

provisions act as a profit center for

pipelines. Crediting penalty revenues

would eliminate an incentive for

pipelines to propose unnecessarily high

levels of penalties or provisions that

unduly restrict the transportation rights

of a shipper.

The Commission invites comments on

the extent to which there is a need to

provide an automatic credit of penalty

revenues. The Commission is

particularly interested in comments on

the extent to which penalties are, or are

not, a significant source of pipeline

revenues. The Commission is also

concerned that the crediting of penalty

revenues to specific non-offending

shippers may be difficult to implement.

The Commission seeks comments on

whether such crediting can be

implemented without substantial

administrative cost. The Commission

also solicits proposals for a specific

mechanism for crediting penalty

revenues.

Another option on which the

Commission solicits comments is the

desirability of revising the manner in

which a shipper’s cash-out payment is

determined. As discussed, current cashout procedures establish a payment

based on the average price of gas for a

given month, which has induced

shippers in some instances to game the

pipeline system to take advantage of

changes in the price of natural gas. A

revision that could eliminate such

gaming would be to require the pipeline

to provide a running imbalance of each

shipper for each day of the month. The

imbalance would be defined not in

volumes, but in imbalance revenues,

which would be the product of the

shipper’s volumes of imbalance that

particular day times that day’s gas index

price. One concern this option raises is

whether it would require pipelines to

install additional or enhanced meters

and, if so, whether the costs of doing so

would outweigh the benefits of

resolving the problems associated with

the gaming of the system.

The Commission solicits comments

on its proposal, the alternative options,

and the related questions. The

Commission also solicits other

alternative proposals that commenters

believe merit consideration.

C. Pipelines Must Provide Services, to

the Extent Operationally Feasible, That

Facilitate Imbalance Management

An expansion of the number of

imbalance management services would

reduce the need for penalties and the

imposition of unnecessary penalties.
43006 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

94Standards For Business Practices Of Interstate

Natural Gas Pipelines, Order No. 587–G, 63 FR

20072 (Apr. 23, 1998), III FERC Stats. & Regs.

Regulations Preambles ¶ 31,062 (Apr. 16, 1998).

95Panhandle Pipe Line Co., 82 FERC ¶ 61,163, at

61,600–601

96See, e.g., NorAm Gas Transmission Company,

79 FERC ¶ 61,126, at 61,546–47 (1997); Southern

Natural Gas Company, 80 FERC ¶ 61,233, at 61,890

(1997) Northern Natural Gas Company, 77 FERC

¶ 61,282 (1997); Panhandle Eastern Pipeline

Company, 78 FERC ¶ 61,202 (1997); Northwest

Pipeline Company, 71 FERC ¶ 61,315 (1995).

97For example, if a pipeline anticipates an OFO

will be in effect until weather conditions change,

it would aid shippers’ planning to so advise them.

98For example, if an OFO will remain in effect

until repairs are completed on a compressor, the

pipeline should be required to update shippers on

the status of the repairs.

99For 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.

100For example, a $100 OFO penalty may be

appropriated in severe cases, whereas a $25 OFO

penalty may be appropriate in others.

The Commission has recently taken a

first step in this direction in Order No.

587–G 94 when it required pipelines,

inter alia, to

• allow firm shippers to revise

nominations during the day (thereby

reducing the probability of imbalances

caused by inaccurate nominations);

• enter into operational balancing

agreements at all pipeline to pipeline

interconnections;

• 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

• provide notice of OFOs and other

critical notices by posting the notice on

their Internet web sites, which would be

accessible to shippers nationwide and

by notifying the affected customers

directly.

In this section the Commission

proposes to require pipelines to revise

their tariffs to expand the number of

imbalance management services and

opportunities available to shippers.

Parking (temporary storage) and lending

(temporary loan of gas) are currently

offered by several, but not all, pipelines

and allow shippers to avoid imbalances.

Under the proposal, a pipeline would be

required to provide such services if

operationally practicable. In addition, a

pipeline would be required to revise or

eliminate any tariff provision that gives

undue preference to its storage or

balancing services over such services

that are provided by a third party. In

response to the tariff filing, parties

could protest the proposals and propose

alternatives for Commission

consideration.

The Commission solicits comments

on whether more specific requirements

or additional initiatives would be

appropriate. One prominent area of

inquiry is the manner and extent to

which the Commission should

encourage the availability of parking

and lending as well as alternative

services. Some incentives are already

provided for in this NOPR. For example,

because parking and lending are shortterm services, providers of such services

would not be subject to a rate cap. The

Commission could also facilitate the use

of third-party storage by specifically

requiring that a pipeline’s transportation

charges for long-term services related to

injection and withdrawal of gas that

comes from third party storage must be

the same as the charges that apply for

long-term services when the gas comes

from the pipeline’s own storage

facilities.

The Commission could also adopt

policies that promote individual shipper

actions that alleviate system imbalances

or operational constraints. For example,

the Commission has recently

established a ‘‘no harm, no foul’’ policy

that would permit beneficial imbalances

to escape penalties.95 Such a policy is

especially important in emergency or

peak periods, when a shipper’s

imbalance can run in the opposite

direction from the conditions adversely

affecting the pipeline. A shipper with

such a beneficial imbalance (one that

runs in the opposite direction of the

imbalance that adversely affects the

pipeline system) is aiding rather than

adversely affecting the system at a

critical time. For example, a shipper

might be taking less than it nominated

on a pipeline that was suffering from

significant overtakes of gas. This policy

prohibits a pipeline from penalizing a

shipper to the extent that such ‘‘good’’

behavior can be tracked.

A variation of a ‘‘no harm, no foul’’

policy would be to go beyond

immunizing a shipper running a

beneficial imbalance from penalties, and

to reward such shippers especially

during emergency time periods. On the

other hand, in Order No. 587–G the

Commission has required pipelines to

permit shippers to net imbalances

across contracts and trade imbalances

with other shippers. In light of these

requirements, would rewarding

shippers running beneficial imbalances

provide significant additional benefit?

The Commission solicits comments

on its proposal, the alternative options,

and the related questions. The

Commission also solicits other

alternative proposals that commenters

believe merit consideration.

D. Pipelines Must Adopt Incentives and

Procedures That Minimize the Use and

Adverse Impact of OFOs

Finally, the Commission proposes to

require each pipeline to adopt

incentives and procedures that

minimize the use and 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 option to

purchase transportation that would be

in lieu of transportation services

provided by that pipeline. In technical

conferences, 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.96

In light of these considerations, it is

appropriate to review existing pipeline

tariffs to ensure that the resort to, and

adverse impact of, OFOs are reduced to

the maximum extent practicable. The

Commission therefore proposes to

require each pipeline to revise its tariff

to the extent necessary to:

• state clear standards, based on

objective operational conditions, for

when OFOs begin and end; 97

• 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; 98

• 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; 99

• set standards for different levels or

degrees of severity of OFOs to

correspond to different degrees of

system emergencies the pipeline may

confront; 100 and

• establish reporting requirements

that provide information after OFOs are
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43007

issued on the factors that caused the

OFO to be issued and then lifted.

In response to the tariff filing, parties

could protest the proposals and propose

alternatives for Commission

consideration.

The Commission requests comments

on the proposal set forth above. The

Commission is particularly interested in

comments on the extent to which

current OFOs have created significant

problems and, if so, the specific

problems that were created.

The Commission also solicits

comments on additional or alternative

options. One such option would be to

use financial incentives based on the

past OFO experiences of a pipeline to

minimize future imposition of OFOs.

For example, a pipeline that never

issues OFOs could be allowed to retain

a portion of cash-out penalties, which

under current Commission policy

would be automatically credited to its

customers. Conversely, a pipeline that

frequently issues OFOs could be

required to rebate a portion of the

customer’s reservation charges if it does

not fix within a reasonable time the

operational problems that give rise to

frequent OFOs. The Commission solicits

comments on the adequacy of such

incentives and also solicits alternative

incentives.

Another option would be to require

automatic crediting of OFO penalties,

even if the Commission retains its

current policy of not requiring pipelines

to credit most penalty revenues. As

discussed, currently pipelines have

incentive to impose OFOs as a first

reaction to a system operational

problem. Requiring the automatic

crediting of OFO penalties would at

least eliminate one potential incentive.

Another option is for the Commission

to institute a program that monitors on

a periodic basis the frequency of

impositions by each regulated pipeline

of OFOs. If the Commission determines

that an individual pipeline frequently

issues OFOs, the Commission could

audit the pipeline’s operations or

establish a proceeding to determine if

changes should be made to the

pipeline’s tariff.

The Commission solicits comments

on its proposal, the alternative options,

and the related questions. The

Commission also solicits other

alternative proposals that commenters

believe merit consideration.

V. Negotiated Rates and Services

Two of the objectives of the regulatory

changes proposed in this NOPR are to

promote greater innovation in service

offerings, and to increase the value of

long-term capacity as protection against

price swings in the short-term market.

As explained below, allowing the

negotiation of rates and services can

provide the flexibility necessary to

foster service innovation. The

negotiation of rates and services also has

the ability to increase the attractiveness

of long-term capacity, so that biases

toward short-term capacity are

weakened. In this manner, negotiated

rates and services can help achieve the

Commission’s goal of creating a more

neutral regulatory policy with respect to

short-term and long-term capacity.

Permitting pipelines to negotiate the

terms and conditions of service with

their customers can have several

beneficial effects. First, permitting

negotiated terms and conditions of

service may spur innovation and

creativity in the services provided, and

keep natural gas transportation service

from becoming stagnant. Traditional

regulation does not always allow for

innovation and gives regulated

companies little incentive to be creative

or to innovate. For example,

conventional tariff procedures may

inhibit the development of innovative

services, since the need for such

services may be immediate and may

arise quickly. Therefore, presently,

neither pipelines, customers, nor

regulators know with certainty what

innovations are feasible, or would be

worth their cost.

A policy that permits pipelines to

negotiate rates and terms of services

together may give pipelines more

incentive to innovate by allowing

pipelines to charge more for innovations

that customers value more. Also, the

ability to negotiate rates and services

may stimulate pipelines to offer service

innovations that are relatively costless

to provide, something they may have

had little incentive to do under costbased rates. These innovations should

ultimately improve the quality of the

pipelines’ other tariff services, if

pipelines are given incentives to

maintain and upgrade these services, as

well.

Second, while the negotiation of

service may be useful for short-term

services, its most significant use may be

as a valuable risk management tool for

pipelines and customers with respect to

long-term contracts.

When a customer enters into a longterm contract, it must undertake a

number of risks. It must bear the general

market risk that the value of capacity

may decrease in time, so that the

customer could have acquired the

capacity for a lower rate later, or the risk

that the pipeline will experience a

decrease in system throughput, which

would drive the maximum regulated

rate up. The customer must bear the

regulatory risk that the rates for the

capacity that it has committed to under

the firm contract will increase due to,

for example, the rolling-in of the costs

of new capacity construction, or other

general rate increases. The customer

must also bear the customer-specific

risk that its own need for capacity might

fluctuate or disappear.

When these risks are too high for a

customer, at the given rates for longterm and short-term capacity, the

customer may be unwilling to hold

long-term capacity contracts. In the past,

shippers accepted some regulatory price

risk in return for little or no gas supply

risk. Now, however, shippers appear

less willing to shoulder the price risks

associated with long-term contracts as a

result of the increased attractiveness of

short-term contracts, the presence of

regulatory disincentives to long-term

contracts, such as the right of first

refusal, and the uncertainty of potential

business impacts of state retail openaccess programs. The movement away

from long-term contracts increases the

pipeline’s risk that it will not earn

enough revenues during the pipeline’s

useful life to cover its total cost and an

acceptable return on the investment in

the pipeline.

Allowing pipelines and shippers to

negotiate terms and conditions of

service, as well as rates, may permit

greater flexibility in the allocation of the

shipper’s risk inherent in long-term

capacity contracts. Such negotiation of

rates and services could permit the

parties to negotiate more flexible

contracts for higher rates. Other options

for negotiation could include lower

rates for longer contract terms, differing

rates for the right to reopen the contract

in specified contingencies, or varying

rates for different payment schedules.

Thus, a negotiated rates and services

policy may give parties the ability to

negotiate terms that will reduce the

shipper’s risk in entering into a longterm contract, thereby increasing a

shipper’s willingness to execute longterm contracts and encouraging greater

long-term contracting, generally. This,

in turn, raises a third benefit of allowing

negotiated terms and conditions of

service. As the value of long-term

contracts increases, and more long-term

contracts are executed, problems of

capacity turnback may be alleviated.

Negotiated rates and services may give

pipelines the ability to attract new

customers and keep existing customers

as long-term contracts expire, helping to

ensure that pipelines are able to recover

their long-term investment costs. Such

negotiation is especially important as
43008 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

101 / Alternatives to Traditional Cost-of-Service

Ratemaking for Natural Gas Pipelines, 60 FR 8356

(Feb. 14, 1995), 70 FERC ¿ 61,139 (1995).

102 / 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).

103See § 284.11 of the proposed regulations.

markets increasingly define the value of

capacity.

Further, certain additional, indirect

benefits can result from permitting

negotiated services. A policy favorable

to negotiated services may facilitate the

unbundling of LDC services at the state

level, thereby extending customer

choice to more retail markets

nationwide. It may also position the gas

industry to be a viable competitor of the

increasingly competitive electric

industry for end use customers.

While the Commission recognizes the

important benefits that would result

from a negotiated rates and services

policy, the Commission is also mindful

that significant, although probably

manageable, concerns exist in

permitting negotiated services. Pipelines

will exercise market power if they can.

The concept of negotiated rates and

services—under which shippers and

pipelines would be able to negotiate

rates or service terms and conditions

that deviate from those in the pipeline’s

otherwise applicable tariff—relies on

the theory that shippers would be able

to choose a ‘‘recourse’’ rate or service

from the pipeline’s tariff as an

alternative to negotiating with the

pipeline. In this way, the recourse

service would act as a check on the

exercise of the pipeline’s market power.

Nevertheless, the negotiation of rates

and services, by its nature, gives

pipelines the ability to treat customers

differently, and thereby could facilitate

a pipeline’s ability to segregate

customers and exercise market power.

A pipeline with market power might

be able to force captive customers to pay

for unwanted terms or conditions of

service by bundling them with desired

services, or to pay for basic services at

premium prices. The Commission is

concerned that permitting the

negotiation of service could give

pipelines an incentive to degrade the

quality of recourse services in order to

sell other services on a negotiated basis.

Another way pipelines could exercise

their market power with negotiated

services is by unduly discriminating

against certain customers. Some level of

discrimination, or differentiation,

among customers is inherent to the

concept of negotiating differing rates

and terms of service. However, the

Commission is concerned that pipelines

could give undue preference to affiliates

or other customers in the offering of

negotiated services.

Further, the Commission is keenly

aware of the natural tension that exists

between allowing negotiated rates and

services, on the one hand, and ensuring

the tradability of capacity, on the other

hand. The negotiation of terms and

conditions of service could make

capacity less tradable and deter the

Commission’s goal of promoting

competition in capacity markets.

Many of these concerns were raised in

response to the Commission’s ‘‘Request

for Comments on Alternative Pricing

Methods’’ in Docket No. RM95–6–

000.101/ These concerns were part of the

reason that the Commission was

reluctant, in its subsequent ‘‘Statement

of Policy and Request for Comments’’ in

Docket Nos. RM95–6–000 and RM95–7–

000, to allow the full range of

negotiation, and therefore, declined to

permit the negotiation of terms and

conditions of service as part of its

negotiated rates policy at that time.102/

However, since then, the Commission

has had the benefit of the additional

industry comments filed in Docket No.

RM95–7–000, and has undertaken a

thorough review of its natural gas

policies. The Commission now

recognizes that the concept of

negotiated rates and services, taken

together with the other proposals in this

document, has the potential to improve

the Commission’s regulatory framework

for natural gas pipelines.

Given the above concerns, the

Commission concludes that the benefits

to increased service innovation and

long-term contracting that can result

from the negotiation of terms and

conditions of service, together with

rates, are valuable, but only if they do

not come at the expense of the interests

of recourse ratepayers, or hinder the

development of competitive markets.

Accordingly, the Commission

proposes to implement a policy

permitting the negotiation of rates,

terms, and conditions of service for

transportation services that will be

governed by a set of guiding principles

designed to protect recourse and captive

customers from the exercise of market

power, prevent undue discrimination

and preference, and foster competition

in the interstate capacity markets.103

These proposed guiding principles, as

described below, will provide limits and

conditions on the negotiation of rates

and services that should minimize the

risk of potential harm to recourse

shippers and capacity markets, and

thereby help ensure that the benefits of

the negotiated rates and services policy

outweigh such risks.

The Commission is seeking comment

on whether to permit the negotiation of

services in the short-term market. As the

short-term market develops, it can be

argued that the benefits of negotiated

services are especially important to the

short-term market, provided that such

negotiation does not impair the

tradability of short-term capacity. A

number of expected benefits to the

market may flow from allowing the

negotiation of short-term services.

Short-term peak market conditions

arguably require a maximum amount of

flexibility and customization for

shippers. On the other hand, the

Commission has not resolved how the

negotiation of short-term rates and

services could be coordinated with the

capacity auction process proposed in

this NOPR. Typically, auctions involve

the trading of standardized products

and services, whereas negotiated

services may not be sufficiently

tradable.

The Commission proposes to address

this issue in the final rule, and seeks

analysis and comment on the

alternatives of whether to permit or

prohibit the negotiation of terms and

conditions of service in the short-term

market. Should the negotiation of

services be reserved for the long-term

market? Can negotiation of services be

accomplished in combination with the

auction process? What effect would the

negotiation of short-term services have

on the tradability of short-term

capacity? What are the benefits to the

marketplace of permitting negotiation in

the short-term market?

In addition, while the Commission is

proposing in this NOPR to permit

negotiated rates, terms, and conditions

of service under the principles below,

the Commission also proposes to

conduct a generic review of the

negotiated services after they have been

in effect for two winter heating seasons.

A. Guiding Principles

The Commission is proposing to

permit the negotiation of any rate, or

term or condition of service for

transportation services to the extent :

• It does not result in undue

discrimination or preference;

• It does not degrade the quality of

existing services;

• It does not hinder the release of

capacity, or otherwise significantly

reduce competition;

• Pipelines do not require customers

to take negotiated transportation

services tied with any unwanted sales,

storage, or gathering services provided
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43009

104See Section 4(b) of the NGA. 15 U.S. C. 717c

(1994).

105See Tennessee Gas Pipeline Company, 77

FERC ¶ 61,877 (1996) (requiring the pipeline to file

specific information to enable shippers to

determine if they are similarly situated to particular

negotiated rate customers, including the type of

service, the receipt and delivery points applicable

to the service, and the volume of gas to be

transported); and Standards of Conduct and

Reporting Requirements for Transportation and

Affiliate Transactions, 59 FR 32885 (June 27, 1994),

FERC Stats. & Regs. ¶ 30,997 at 31,067–68 (1994)

(Order No. 566) (requiring pipelines to post

particular information on their EBBs regarding

affiliate discounts, including quantity and point

data, to enable non-affiliates to determine if they are

entitled to a similar discount). See also, Iroquois

Gas Transmission System, L.P., 79 FERC ¶ 61,394

(1997), reh’g denied, 82 FERC ¶ 61,086 (1998)

(holding that the pipeline may not charge new

expansion shippers and existing shippers different

rates, based on findings that differences between

each shipper group stemming from the time when

each group came on the system, such as differences

in receipt and delivery points or available

competitive alternatives, were insufficient to justify

disparate treatment); and El Paso Natural Gas

Company, 62 FERC ¶61,311 at 62,990–91 (1993),

followed in ANR Pipeline Company, 66 FERC

¶ 61,340 at 62,130–31 (1994) and Questar Pipeline

Company v. PacifiCorp, 70 FERC ¶ 61,328 at 62,009

(1995) (shippers holding discounted rate contracts

between certain primary points do not have the

right to use alternate points at the discounted rate,

since the market conditions may not be the same

at the primary and alternate points). 106This is discussed more fully below.

by the pipeline, its affiliates, or

upstream or downstream entities; and

• The terms of the negotiated

transactions are made publicly

available.

These general guiding principles will

provide the boundaries within which

the industry may conduct negotiations

of rates and services, and will be

applied on a case-by-case basis. They

will also give the Commission, and the

industry, a basic foundation for

evaluating future negotiated deals that

cannot be envisioned currently.

Establishing more specific or restrictive

guidelines could limit, in the future, the

degree of innovation that potentially

could be achieved.

Further, the Commission proposes

that if a pipeline violates any of these

proposed guiding principles, the

Commission would revoke that

pipeline’s authority to negotiate rates

and services. Establishment of this

penalty up-front for violating the

guidelines of the negotiated rates and

services policy should serve as an

incentive for compliance. In addition,

the traditional remedies available under

the NGA would also be available to the

Commission to use.

Each of the proposed guiding

principles is discussed more fully

below.

1. No Undue Discrimination or

Preference

The Commission is particularly

concerned that the negotiation of rates

and services does not violate the

statutory prohibition against undue

discrimination and preference in the

NGA.104 The very nature of negotiated

rates and services is to provide some

customers rates and services that differ

from those provided to others. However,

the negotiation of rates and services

under the proposed policy cannot be

unduly discriminatory or preferential.

Practically speaking, under existing

undue discrimination standards, this

would require that ‘‘similarly situated’’

shippers have rights to the same

negotiated deal. The cases in which the

Commission has applied the ‘‘similarly

situated’’ standard in the past provide

some guidance on the meaning of

‘‘similarly situated’’ shippers.105

Nevertheless, the Commission

recognizes that clear guidelines, or

standards, on what constitutes undue

discrimination or preference in

negotiating rates and services may need

to be established before any negotiation

takes place so that the industry can

abide by this principle. Such up-front

standards could provide guidance to

pipelines and shippers about acceptable

negotiation practices, eliminating

confusion about what does and does not

constitute permissible conduct, and

could minimize the risk of

discrimination occurring before

standards emerge from a case-by-case

complaint and review process. The

standards may also be critical to

effective monitoring and enforcement.

While the Commission is considering

developing such generic undue

discrimination guidelines, such

standards could prove difficult to craft,

since undue discrimination findings

usually depend on specific facts and

often are subject to widely varied and

subjective interpretation. Thus, the

Commission seeks comment on the need

for, and feasibility of, its developing

clear standards on what constitutes

undue discrimination or preference

before negotiations are permitted to

occur. The Commission further requests

commenters to discuss what should be

the standards for undue discrimination,

including whether the ‘‘similarly

situated’’ standard should continue to

be used, and if so, how that term should

be defined.

2. No Degradation of the Quality of

Existing Services

A core concern of captive customers,

shared by the Commission, is the effect

a negotiated rates and services policy

could have on the quality of service that

recourse shippers receive. Permitting

the negotiation of particular terms and

conditions of service might, in a direct

way, adversely affect the quality of one

or many recourse shippers’ service. For

example, negotiations to loosen a

pipeline’s imbalance provision for some

shippers may force the tightening of

allowed tolerances for others.

Therefore, the Commission proposes

to permit the negotiation of rates and

services as long as the quality of service

for recourse shippers is not diminished

or degraded. The Commission’s

objective in proposing this principle is

to prevent pipelines from negotiating

services at the expense of service quality

for recourse shippers.

3. No Impairment of the Tradability of

Capacity

The negotiation of terms and

conditions of service could impair or

reduce competition in capacity markets.

This may happen either because service

may become defined so differently that

capacity is no longer fungible, or

because customers voluntarily give up

the rights that make trading possible in

exchange for a rate reduction. This, in

turn, could diminish the degree of

competition in capacity markets

generally, or in some specific markets.

Therefore, to guard against this, the

Commission proposes to permit the

negotiation of rates and services as long

as such negotiation does not impair

tradability of capacity, result in a

significantly greater concentration of

sellers in capacity markets, or otherwise

significantly reduce existing

competition. Since the full range of

innovation that might occur under the

negotiated rates and services policy

cannot be known at this time, it may be

that shippers will be able to develop

negotiated services that do not impair

the tradability of capacity. To help

enable shippers to release negotiated

services, mechanisms may be developed

which allow negotiated service to revert

to standard service at the releasing

shipper’s option when released to

another shipper.106

4. No Unwanted Tying Arrangements

One of the Commission’s objectives in

Order No. 636 was to prevent the

exercise of market power over

transportation from being extended to

the sale of natural gas, through the tying

of the two different services. The

negotiation of terms and conditions of

service can raise new issues in this

regard. Permitting pipelines to negotiate

individualized services may prompt

pipelines to require customers to take

packages of service, either from the

pipeline, its affiliate, or another entity,
43010 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

107See June 17, 1998 letter of the Pipeline

Transportation Customer Coalitation filed in Docket

No. PL97–1–000.

108Further discussion of this aspect of the

proposal is included in the discussion below on the

establishment of initial recourse service. 109See 18 CFR 385.2007 (1998).

that include both transportation and

sales services that are currently

available separately. Similar concerns

arise from attempts to bundle

transportation with unwanted storage or

gathering services. Allowing pipelines

to force customers to take tied services

could adversely affect commodity

markets that are currently competitive,

or competition between sellers of

capacity, and could lead to increased

preferences for affiliates.

Therefore, the Commission proposes

that a pipeline may not require that a

negotiated transportation service be tied

with any unwanted sales service or

other services provided by the pipeline,

its affiliate, or by any upstream or

downstream entity, unless that service

is necessary to the provision of the

negotiated transportation service. While

the Commission does not envision that

the tying of gathering or sales service to

the transportation service would be

necessary to the transportation service,

there may be instances where storage

service could be a prerequisite for the

pipeline’s ability to provide the

negotiated transportation service.

5. Transparency of Negotiated

Transactions

The Commission proposes to require

that the essential elements of negotiated

transactions, including price, be

transparent to the public and the

Commission. The full disclosure of the

terms of the negotiated transactions is

critical to the ability of shippers and the

Commission to detect, and deter, the

exercise of market power and undue

discrimination and preference. The

transparency of negotiated arrangements

also enables shippers to make informed

purchasing decisions.

The need for transparency has guided

the Commission’s development of the

proposed procedures for implementing

a negotiated rates and services policy.

Thus, as discussed infra, the

Commission is proposing to require

pipelines to file with the Commission

and serve on firm shippers, written

notice of all essential information about

a negotiated transaction prior to the

transaction taking effect. The

Commission is also proposing to

increase its existing reporting

requirements.

B. Implementation of the Negotiated

Rates and Services Policy

1. Procedural Mechanism

The American Gas Association (AGA),

on behalf of itself and the Interstate

Natural Gas Association of America

(INGAA), proposed to the Commission,

by letter dated May 4, 1998, a method

for implementing a negotiated services

policy. AGA/INGAA’s proposed method

would entail each pipeline making an

initial ‘‘benchmark’’ filing, prior to its

first negotiation of service, that would

(a) set forth certain terms or conditions

of service that could not be negotiated

absent 30 days prior notice, and (b)

establish a high standard for quality and

reliability of recourse service, as well as

better define essential elements of the

pipeline’s tariff. Then, after Commission

approval of the initial benchmark filing,

the pipeline would be able to

implement, after 10 days prior notice,

negotiated deals containing items not

identified in the initial filing as

requiring 30 days prior notice. The

Pipeline Transportation Customer

Coalition (Coalition), comprised of end

users, marketers, producers, and

municipal distributors, filed with the

Commission a letter opposing AGA/

INGAA’s negotiated services proposal

and more broadly, the concept of

negotiated services.107

As discussed above, the negotiation of

rates and services can serve a valuable

role in the Commission’s proposed new

regulatory approach. While the

Commission acknowledges the potential

risk of harm to competitive markets and

recourse shippers, that risk appears to

be manageable. Therefore, the

Commission is proposing a method for

implementing negotiated services that

has some similarity to aspects of AGA/

INGAA’s proposed method.

The Commission is proposing to

require a pipeline interested in

negotiating terms and conditions of

service to make an initial filing

requesting authority to negotiate rates

and services on its system. This initial

filing would accomplish two equally

important functions. First, it would

define and establish a high quality

recourse service.108 Second, the initial

filing would establish the parameters of

permissible and impermissible

negotiation for that pipeline in advance

of any negotiation of service or

implementation of negotiated services.

This would be accomplished by the

pipeline identifying categories of nonnegotiable, negotiable, and potentially

negotiable terms or conditions of

service, as described in more detail

below. The Commission would closely

scrutinize the proposed categories of

terms and conditions of service,

particularly the terms and conditions of

service included within the negotiable

category, to ensure consistency with the

proposed guiding principles. For

example, the Commission would

analyze whether the negotiation of the

negotiable items could adversely affect

the quality of other services or the

tradability of capacity, and whether

additional terms and conditions should

be included in the non-negotiable

category. Interested parties would have

the opportunity to comment on and

protest any aspect of the initial filing,

and the Commission would carefully

consider all such comments and

protests. Only after such review, and

Commission approval of the initial

filing, would the pipeline be permitted

to begin negotiations and implement

negotiated services. In addition, after

the Commission approved the initial

filing, the pipeline would be required to

include the categories of terms and

conditions of service in its tariff.

The non-negotiable category of terms

and conditions of service would include

certain terms and conditions of service

that could never be negotiated, and

thus, would be per se non-negotiable. A

pipeline might include in this category

terms or conditions that, by their nature,

would directly affect the services of

other shippers (e.g., force majeure,

higher curtailment, or generic OFOs

provisions).

The negotiable category of terms and

conditions of service would include

particular items that the pipeline would

be permitted to negotiate, at its and its

customers’ discretion. A pipeline could

include permissible ranges of flexibility

for each negotiable area of service.

These negotiable deals would be

permitted to be implemented after 10

days prior written notice to firm

shippers and the Commission.109 The

Commission is proposing to permit

these negotiable services to go into

effect at the end of the 10 day notice

period, without action on the notice

filing by the Commission, since the

Commission would have already

generically approved the negotiation of

these items by that pipeline with its

action on the initial filing. Similarly,

other shippers would have had the

opportunity to comment on or oppose

the pipeline’s proposed negotiation of a

particular term or condition of service at

the initial filing stage.

The Commission, however, seeks

comment on whether a shorter advance

notice period, or any advance notice at

all, is necessary for contracts containing

the items identified by the initial filing

as negotiable. Parties should comment

on whether such negotiated contracts

could be self-implementing, becoming
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43011

110 15 U.S.C. 717c (1994).

effective upon the agreement of the

pipeline and the shipper, subject only to

the pipeline filing and posting a

transactional report of the negotiated

deal contemporaneous with the

execution of the contract.

The potentially negotiable category of

terms and conditions of service would

not need to be specifically identified,

but would encompass all other terms

and conditions of service not identified

in the non-negotiable or negotiable

categories. Items would fall into this

category if they had the potential to

have an impact on the service of other

shippers, or had the potential to violate

one of the other guiding principles.

Thus, any negotiation of these

unspecified terms and conditions of

service would require prior notice, an

opportunity for other shippers to

comment, and Commission review of

the particular negotiated transaction

before taking effect. Specifically, the

pipeline would be required to make a

filing under Sections 4(d) and (e) of the

NGA before the negotiated deal could

take effect.110 The 30 days prior written

notice to the Commission and firm

shippers provided by the Section 4

filing would give all other shippers the

opportunity to protest the negotiated

transaction before it takes effect, and the

Commission would have the ability, as

usual, to accept, reject, or suspend the

pipeline’s filing.

The pipeline’s Section 4 filing would

need to contain the essential aspects of

the negotiated agreement, including: the

name of the shipper, any affiliation with

the pipeline, the contract quantity, the

applicable rate(s), the receipt and

delivery points, and a brief description

of the negotiated term or condition of

service with reference to the modified

provision of the recourse tariff or rate

schedule. The filing would also contain

a statement, with any supporting

information, that no material adverse

effects on the benchmark service will

result from the negotiated term or

condition. This statement and

supporting information would create a

rebuttable presumption that the

negotiated transaction will not have any

material adverse effect on the recourse

service. If the presumption is overcome,

the ultimate burden of persuasion

would be on the pipeline to show that

no degradation of the recourse service

would result.

Finally, the Commission is also

proposing to continue the current

practice of allowing pipelines to

negotiate unique services in individual

rate schedules that are then made

available to all customers, since this

method already serves the industry

well.

Although the Commission is

proposing the method for implementing

negotiated services described above, the

Commission would also consider

variations on this method, including the

specific proposal advanced by AGA/

INGAA. In this regard, the Commission

requests comment on whether pipelines

could be given an option of

implementing negotiated terms and

conditions of service without having to

initially file general tariff provisions

defining the scope of permissible or

impermissible negotiation. That is,

could pipelines also be permitted to

negotiate unique deals with individual

shippers that include terms and

conditions that deviate from those in its

existing tariff, by filing each negotiated

contract with 30 days advance notice,

and bypassing the initial tariff filing?

The Commission invites comments

discussing the pros and cons of the

proposed implementation method,

including whether that method

adequately addresses concerns which

have been expressed about the

pipelines’ potential exercise of market

power. Commenters are also invited to

suggest alternative procedures for

implementing negotiated rates and

services.

2. Recourse Service

The recourse service, which would be

available to all shippers, serves as an

alternative to negotiating with the

pipeline, and an important check on the

pipeline’s potential exercise of market

power. Therefore, the Commission must

ensure that the recourse service is

initially, and remains over time, a high

quality service, so that it stays a viable

alternative to negotiated rates and

services. Below, the Commission

presents proposals for initially

establishing a good quality recourse

service, and for maintaining the vitality

of that recourse service in the future.

a. Establishment of Initial Recourse

Service. The Commission proposes to

require that each pipeline’s initial

voluntary filing to implement negotiated

terms and conditions of service define

the components of that pipeline’s

recourse service. Pipelines would be

required to design a recourse service

that is of a high quality and reliability,

and maintains at least the level of

service being offered by the pipeline in

its currently effective tariff. Core

elements of the pipeline’s recourse

service that are not adequately defined

in the tariff, including standard

operating practices, would be identified

by the pipeline or its customers in

conjunction with the filing.

Essentially, this method of

establishing initial recourse service

would require that any pipeline

choosing to implement negotiated terms

and conditions of service submit its

tariff services for review and

modification to establish adequate

recourse service in exchange for the

authorization to negotiate terms and

conditions of service. This proposal

would provide a procedure to address

shippers’ dissatisfaction with some

pipelines’ existing service offerings, and

their concerns that the literal language

of the existing tariffs might permit

pipelines to reduce the quality of

recourse service from that enjoyed

under current operating practice. Thus,

the review and modification of

individual pipelines’ existing tariff

services will help ensure that recourse

service is adequate before any

negotiation of rates or services takes

place.

However, the Commission also seeks

comments on whether using pipelines’

existing tariffs as the initial recourse

service, without requiring new filings,

might be less burdensome on the

industry and the Commission, and

thereby permit pipelines and shippers

to begin negotiating rates and services

sooner than if initial filings to establish

recourse service were required. Parties

should also comment on whether the

existing rates, terms, and conditions in

pipelines’ current tariffs could be

acceptable as initial recourse services,

since they have already been found by

the Commission to be just and

reasonable. In commenting, parties

should evaluate the need for

establishing adequate recourse services

against the ability to implement the

negotiated rates and services policy

without undue delay.

Another option for establishing initial

recourse service would be to have GISB

generically identify basic elements of

service that could not be subject to

negotiation. Designating particular

terms or conditions as non-negotiable

would have the effect of defining some

of the basic terms and conditions of

service that comprise recourse service.

Some commenters have requested that

the Commission generically specify

particular terms or conditions as nonnegotiable. However, GISB is the one

forum where all segments of the

industry are brought together, making

across-the-board consensus on this issue

a possibility. The Commission requests

comments on the feasibility and value of

having GISB define initial recourse

service.

b. Maintaining Vitality of Recourse

Service Over Time. For recourse service

to remain a viable option to negotiated
43012 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

111See proposed § 284.10(c).

112The Commission may need, at some point in

the future, to adopt standards that define recourse

service quality.

service, the overall quality of the

recourse service must continue to meet

shippers’ needs. The Commission is

concerned that over time the quality of

recourse service may deteriorate. By not

updating recourse service to keep pace

with changing markets, technology, and

customer needs, or by maintaining a

low-quality or inferior recourse service,

pipelines could force captive customers

into negotiating the basic services they

need, at premium rates.

Thus, the Commission finds that a

mechanism needs to be established to

review recourse services to ensure they

remain viable alternatives to negotiated

services. Accordingly, the Commission

proposes to implement periodic reviews

of the rates, terms, and conditions of

recourse service.111 As discussed in

more detail below, the Commission

proposes that these periodic reviews

take place on a three-to-five year cycle,

although comment is invited on

proposals for alternative review cycles.

These periodic reviews would provide

the Commission with the opportunity to

examine the range of terms and

conditions included in the recourse

service, and to assess the quality of the

recourse service as a whole.112

The periodic reviews would provide a

forum for the Commission to determine

if certain negotiated services offered by

some pipelines should be offered as

recourse services after some reasonable

time. This would allow captive

customers to obtain the benefits of

service innovation, while at the same

time giving pipelines a reasonable

period of time to profit from their

innovative service offerings before

having to offer the service at a costbased rate. The periodic reviews of

recourse services would also enable

proposed additions or changes to

recourse service to be considered

comprehensively, to help ensure that

the new package of recourse services is

both operationally feasible and cost

effective.

There are several different ways that

the Commission could implement the

periodic reviews of recourse service.

The periodic review could be

undertaken on an individual pipeline

basis, on a regional basis, or on a

national, or generic, basis. The

Commission proposes to establish

recourse services, through the periodic

reviews, for each individual pipeline.

This approach is likely to provide the

best match of customers’ service needs

with the operational capabilities of

individual pipelines. Establishing

recourse services individually, for each

pipeline, would also allow rate issues to

be treated simultaneously with service

issues.

The Commission proposes that

pipelines offering negotiated terms and

conditions of service file information

with the Commission every three to five

years that will ensure the viability of the

pipeline’s recourse service. The

information proposed to be filed is

intended to give the Commission

adequate information to determine

whether and how to modify the

pipeline’s recourse rates and service to

keep pace with market conditions.

The information would need to be

filed for each type of negotiated

service—the negotiated services that

take effect on shortened notice and the

transactions subject to 30 days notice.

The filing would include data on the

names and types of shippers negotiating

the contracts, the terms negotiated, the

contract demand, and volumes moved

under the contracts.

In addition, to permit a comparison to

the pipeline’s current recourse service,

the pipeline would have to provide

aggregate data for each category of

negotiated service, and for the recourse

service. The aggregate data would

include information on total contract

demand, aggregate volumes, and

revenues for the negotiated contracts

and the recourse service.

Commenters are requested to address

the adequacy of the information

required in the proposal, including

whether more detailed information is

necessary, and are encouraged to

suggest other information that might

better permit the Commission to review

negotiated rates and services.

The Commission is still considering,

as an alternative to the pipeline-specific

review of recourse service, requiring the

periodic recourse service reviews to be

made on a regional basis, before any

individual pipeline-specific adjustments

are made. On the one hand, the

establishment of recourse services on a

regional basis, so that the recourse

services offered by all pipelines in a

given region would be as nearly

equivalent as possible given operational

differences among pipelines, could

result in greater standardization of

pipeline services and practices, thereby

enhancing competition and tradability

of capacity. It could also lower

transaction costs for customers. In

addition, a regional approach may be

less burdensome on shippers because

they would need to participate in fewer

proceedings. On the other hand, it may

be difficult to develop recourse services

for all pipelines in a region, since a

regional approach would not facilitate

the tailoring of services to the

operational capabilities of specific

pipelines.

The Commission seeks comment on

the different ways that the Commission

could implement the periodic reviews

of recourse service, including comment

on the merits of establishing recourse

service on a regional basis through

regional reviews. Parties may discuss

the advantages and disadvantages of

each approach, and how a regional

approach might be performed.

3. The Release of Negotiated Capacity

To enhance the tradability of capacity

under negotiated service contracts, the

Commission is contemplating requiring

pipelines to include in their tariffs a

provision that allows, but does not

require, a negotiated service to revert to

a standard form of service when it is

offered for release. This should make it

easier for the customer under a

negotiated service contract to release its

capacity. This is because a negotiated

service agreement may contain

provisions tailored to a customer’s

needs which render the service

undesirable to other shippers with

different needs. This provision could

apply either to all negotiated services, or

only to those that represent an

enhancement over the standard service.

The provision could also be structured

such that any negotiated term or

condition of service which the

replacement shipper desires would

remain in the contract.

In the case where a releasing shipper

negotiates enhanced, more flexible, or

‘‘better’’ services than the standard

service, the releasing shipper

presumably would be compensated for

reselling capacity as if it was standard

service, regardless of what it paid for the

capacity. If negotiated services are

below the standard level included in the

tariff provision, the releasing shipper

might be required to pay the difference

between the negotiated rate and the

standard rate before reselling its service

as standard service. In both cases,

reversion of a negotiated service to a

standard form of service would be

allowed only when operationally

feasible, and only when requested by

the releasing shipper.

The Commission requests comment

on this potential method for helping

ensure that negotiated capacity remains

tradable, particularly on the feasibility

of implementing such a requirement.

Commenters should address how

critical establishing this reversion

requirement is to permitting the release

of capacity under a negotiated contract,

how difficult it would be to define what
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43013

113See Tennessee Gas Pipeline Company, 77

FERC at 61,877 (requiring the pipeline to file

specific information to enable shippers to

determine if they are similarly situated to particular

negotiated rate customers), see also, Iroquois Gas

Transmission System, L.P. CP96–687–000, 79 FERC

¶ 61,394 at 62.693 (1997), reh’g denied, 82 FERC

¶ 61,086 (1998) (rejecting proposal to discount

service to expansion shippers as unduly

discriminatory against existing shippers).

114NorAm Gas Transmission Company, 75 FERC

¶ 61,091, order on reh’g, 77 FERC ¶ 61,011 (1996)

(NorAm).

115Northwest Pipeline Corporation, 79 FERC

¶ 61,416, 62,754 (1997).

service is of a higher or lower quality

than the standard level of service, and

to what extent operational difficulties in

permitting the reversion to a standard

form of service might limit the overall

value of this approach.

4. Negotiation of Rates and Services

With Affiliates

As stated previously, the Commission

proposes to permit the negotiation of

rates and services where similarly

situated shippers have rights to the

same negotiated deal. The Commission

is considering whether additional

protections are required to protect

against unduly preferential treatment in

favor of pipeline marketing affiliates or

whether the Commission’s existing

marketing affiliate rules provide

adequate protections. Therefore, the

Commission proposes to permit

pipelines to negotiate terms and

conditions of service with their

marketing affiliates so long as all other

similarly situated shippers are offered

the same rates and services. Consistent

with prior precedent, the Commission

proposes to establish a rebuttable

presumption that all shippers receiving

the same type of service, using the same

pipeline facilities, are similarly

situated.113 The pipeline could rebut the

presumption by showing that a

particular shipper or group of shippers

is not similarly situated with its affiliate

in order to justify not offering the same

negotiated deal to non-affiliated

shippers.

The Commission seeks comments on

whether the above proposal provides

adequate protection against undue

discrimination. For example, should the

Commission consider stronger

protections, such as precluding the

negotiation of rates and services with

marketing affiliates as unduly

preferential unless all other shippers are

offered the same rates and services?

Alternatively, could robust monitoring

be adequate to discourage and prevent

pipelines from giving undue preference

to their affiliates eliminating the need

for stronger protections? If so, what

types of information would the

Commission need to gather to meet its

monitoring objectives, and how

burdensome would it be to provide this

information? Is some other form of

protection better suited to the

Commission’s purpose of ensuring

against undue discrimination?

Commenters are invited to respond to

these issues and may raise any related

issues not presented here.

5. Negotiation of Capacity Release and

Flexible Point Rights

The Commission is considering

whether the rights to release capacity

and to flexible receipt and delivery

points should be included among the

terms or conditions of service that could

not be changed by negotiation. Capacity

release is a fundamental element of the

increasingly competitive natural gas

capacity market. It creates competition

between firm capacity holders and the

pipeline in what otherwise may be a

monopoly capacity market.

Under a negotiated rates and services

policy, both pipelines and shippers may

find it easy and advantageous to

negotiate the relinquishment of such

rights. Pipelines may find it in their

interest to negotiate services without

capacity release rights to reduce

competition for their interruptible and

short-term firm services. Shippers, also,

may wish to relinquish capacity release

rights for a price break, particularly if

they do not plan to utilize their release

rights. Shippers who give up capacity

release rights will no longer be potential

sellers of capacity. Those who give up

flexible receipt and delivery points may

severely limit their participation in the

secondary market. Thus, surrender of

these rights could have a clear and

direct impact upon competition from

the release market and the pipeline’s

ability to exercise market power.

The Commission requests comment

on whether precluding the negotiation

of rights to capacity release and flexible

points is necessary to ensure that firm

shippers can continue to release

capacity and trade with others behind

secondary points, and thereby remain

competitors in the short-term capacity

market. Commenters should address the

likelihood, and extent to which, they

expect these rights to be a primary

subject of negotiations between

pipelines and shippers, and the extent

to which restricting the negotiation of

such rights might limit the range of

possible negotiated deals. Commenters

also should consider whether the

Commission should implement this

restriction as an initial protection that

could be relaxed in the future as more

experience is gained with the negotiated

rates and services policy.

6. Future Cost Allocation Issues

The Commission shares concerns,

voiced by potential recourse shippers in

the comments filed in Docket No.

RM95–7–000, regarding the effect that

the negotiation of rates and services

might have on recourse shippers’ rates.

The main concern is that pipelines

entering into negotiated deals that result

in reduced revenue streams might seek

to recover the revenue shortfall by

raising recourse rates in future rate

cases. Such cost-shifting could crosssubsidize negotiated services, and

pipelines could try to keep revenues

that exceed recourse rate caps, while

shifting revenue shortfalls to recourse

ratepayers.

The rates of recourse shippers should

not be adversely affected by the

pipelines’ negotiations of service with

other parties. Only the negotiating

parties should bear the risks and

rewards of their negotiated contracts. In

fact, the Commission has previously

addressed this issue in the negotiated

rates context by prohibiting a pipeline

from making any adjustment to its

recourse rates to account for its failure

to recover costs from a negotiated rate

shipper,114 absent some showing of

benefit to recourse shippers.115

At the same time, the Commission is

concerned that if discount-type

adjustments for negotiated services are

similarly prohibited in future rate cases,

pipelines might be deterred from

negotiating rates and services. Pipelines

might favor the discounting of service

fees over the negotiation of creative

alternatives, since the Commission’s

discounting policies permit the recovery

of revenue shortfalls. These lost

negotiated agreements may have

resulted in the pipeline obtaining a

higher total revenue stream than it

would have by entering into a

discounted deal, and may have

mitigated the losses associated with the

level of discounting reflected in current

rates. All customers may benefit to the

extent that some shippers stay on the

system or take longer term contracts as

a result of the ability to negotiate rates

and services.

Therefore, the Commission is

considering examining all rate issues

associated with negotiated rates and

services in future rate cases, including

the treatment of revenue shortfalls and

excess revenues, and whether

corresponding rate adjustments are

appropriate. This would be a change

from the policy stated in NorAm of

prohibiting, per se, discount-type

adjustments for negotiated rate

agreements as a means of ensuring costs
43014 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

116Symposium on Process and Reform:

Commission Complaint Procedures. See Notice of

Conference issued March 10, 1998 in Docket No.

PL98–4–000, 63 FR 12800 (March 16, 1998).

117Regulation of Interstate Natural Gas

Transportation Services, Docket No. RM98–12–000.

are not shifted to recourse rate

customers. This approach may also

permit the Commission to consider any

additional cost allocation issues that

might arise from any new facilities that

may have been built to provide the

negotiated service. However, the burden

of justifying the benefit of specific

negotiated deals would be on the

pipeline. In this respect, the

Commission seeks comment on what

type of showing pipelines would have

to make in order to show that specific

negotiated deals merited an adjustment

to recourse rates.

Finally, the examination of all rate

issues associated with negotiated terms

and conditions in future rate cases may

also provide the Commission with the

opportunity to fully explore the benefits

and/or harm to the recourse shippers

from the negotiated rates and services

policy. To the extent that these are

unknowns at this point, the Commission

needs to have a fair amount of flexibility

to decide how revenues and costs

associated with negotiated services

should be treated in future rate cases.

The Commission solicits comment on

the above proposal, including comment

on the extent to which this approach

may lead pipelines to attempt to shift

risks to captive ratepayers, and the

proposal’s potential impact on the

ratemaking process.

An alternative would be to prohibit

any adjustments to recourse rates due to

revenue shortfalls resulting from

negotiated rates and services. This

approach would prevent pipelines from

shifting the risks of negotiated deals to

recourse ratepayers. On the other hand,

if the pipeline were required to absorb

any revenue shortfalls from negotiated

deals, the pipeline should probably

have a corresponding right to retain any

excess revenues resulting from

negotiated rates, thus eliminating the

possibility that recourse shippers would

benefit from negotiated deals other than

through improved recourse service.

The Commission seeks comment on

the advantages and disadvantages of this

alternative proposal to prohibit rate

adjustments to recourse rates for

revenue shortfalls. Commenters should

include discussion on the extent to

which prohibiting rate adjustments

might discourage pipelines from

entering into negotiated deals, and

whether, and/or to what extent,

prohibiting rate adjustments is

inconsistent with the Commission’s

existing discount policy.

7. Reporting, Monitoring, and

Complaint Procedures

The implementation of stringent

reporting requirements and active

monitoring will be necessary to ensure

the success of a negotiated rates and

services policy. Such reporting and

monitoring will be critical for the

Commission to be able to detect and

deter the exercise of market power, for

customers to identify undue

discrimination in the provision of

services and to support their legitimate

complaints, and for the Commission to

ensure compliance with the guiding

principles of the negotiated rates and

services policy.

The Commission is proposing to add

to the data that pipelines currently are

required to report under the Index of

Customers. Such additional information

will be aimed at capturing the existence

of similarly situated customers and any

affiliate relationship between the

capacity holder and the customer in a

negotiated transaction.

Specifically, the Commission

proposes to require pipelines to

identify, in the Index of Customers, each

contract that contains negotiated rates

and services. Pipelines would only be

required to flag contracts with

negotiated rates and services through a

‘‘yes/no’’ indicator and contract number

for each customer and contract. The

Commission is not proposing to require

pipelines to delineate the terms of

specific contracts in the Index of

Customers. Such delineation might pose

a significant burden on the pipelines,

without a substantial countervailing

benefit.

In addition, the Commission is

proposing to require other information

in the Index of Customers and/or the

proposed monthly transaction reports to

assist in monitoring a pipeline’s market

power. This includes information on

receipt points, delivery points,

segments, affiliate relationships, and

contract numbers. Such information

will enable shippers and the

Commission to evaluate whether

specific shippers or transactions are

‘‘similarly situated’’ for purposes of

assessing undue discrimination or

preference under a negotiated contract.

Further, the Commission proposes to

conduct compliance audits or studies of

specific pipelines’ compliance with the

principles. Compliance audits or studies

may provide the necessary detail about

specific services offered, and their

effects on the customers in individual

cases, to allow case-by-case review of

complaints, the early detection of

problems, and sua sponte Commission

action. Such audits also could provide

constructive feedback to both the

industry and the Commission, and may

improve overall compliance. The

Commission seeks comments on the

utility of compliance audits.

Finally, an effective complaint

procedure is necessary to resolve and

discourage abuses of the negotiated rates

and services policy. To this end, the

Commission recently held a public

conference in Docket No. PL98–4–000,

to aid in the process of evaluating and

improving its complaint procedures,116

and is contemporaneously issuing a

separate NOPR to revise the complaint

process in Docket No. RM98–13–000.

AGA/INGAA’s negotiated terms and

conditions proposal recommends that

an expedited and effective complaint

procedure allow for the remedy of

retroactive relief in the event a customer

proves that the pipeline willfully and

knowingly made a material

misrepresentation in its initial filing of

a negotiated term or condition, which

resulted in material harm to the

customer. Such relief would only be

available in the context of the negotiated

terms and conditions policy, and would

not be permitted to be used as precedent

for any other matter under any statute

administered by the Commission.

Parties may also comment on this

proposal in the separate rulemaking

proceeding in Docket No. RM98–13–

000.

VI. Long-Term Services

The proposals made in this NOPR for

the short-term capacity market will

necessarily impact the long-term

market. Further, without a vibrant

market for long-term capacity, the

benefits of the short-term market

proposals cannot be realized. If the

Commission adopts a new regulatory

approach for short-term transportation,

there must be viable, regulated longterm services available to mitigate any

market power of capacity sellers. The

Commission is issuing a companion

Notice of Inquiry 117 to consider

whether changes should be made in its

policies with regard to long-term

markets. However, the Commission is

concerned that some of its current

regulatory policies may result in a bias

toward short-term contracts, which

could weaken the long-term market and

undermine the proposals set forth in

this NOPR.

Therefore, the Commission is

addressing in this NOPR, several longterm transportation rate and certificate

issues that have a direct and significant

impact on the short-term transportation

policy proposals contained in this

NOPR. Specifically, the Commission is
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43015

118The Commission would not necessarily

approve a request for increased rates. See, e.g., El

Paso Natural Gas Company, 72 FERC ¶ 61,083 at

61,441–42 (1995); and Natural Gas Pipeline Co., 73

FERC ¶ 61,050 at 61,128–30 (1995).

119Pipelines might also try to increase their sale

of interruptible transportation as another means of

recovering their costs of service. Shippers, however,

would only take this capacity when they need it,

and not year round in most cases.

proposing to modify the right of first

refusal by eliminating the term

matching cap. Further, the Commission

is considering changes to its policies

with regard to term-differentiated rates

and negotiated terms and conditions in

long-term contracts. In addition, the

Commission is seeking comments on its

policies for certification of new

capacity.

A. The Interaction Between Long-Term

and Short-Term Services

Long-term contracts provide

important benefits to pipelines and

customers. Long-term contracts provide

stability, and can reduce financial risks

to the pipeline, lowering their capital

costs, to the benefit of all the pipeline’s

customers. In addition, encouraging

long-term contracts ensures that there

will be sufficient capacity available for

release in the secondary market in order

to maintain the vibrant competition

between sales of capacity in the primary

and secondary market which exists

today.

The Commission has proposed that

the removal of the price cap in the

short-term transportation market,

coupled with other changes proposed

for the short-term market, would be

consistent with the Commission’s

statutory responsibilities. These

proposals, in combination with one

another, should foster a more

competitive environment, while at the

same time, providing a check against

any monopoly power abuses. The

rationale for modifying the approach to

short-term markets does not apply to the

long-term market, however. In the longterm market, there are no effective

substitutes for long-term pipeline

service, unlike the short-term capacity

products of interruptible, short-term

firm, and capacity release. Therefore,

even if the Commission decides to adopt

a different regulatory approach for

short-term transactions, there will

continue to be a need for the

Commission to regulate the terms and

conditions of service for long-term

transportation to protect shippers

against the exercise of monopoly power

by pipelines. The Commission’s

regulation, however, should not provide

artificial disincentives for long-term

contracts, but should be neutral with

regard to long-term and short-term

contracts.

The Commission is concerned that

some of its current regulatory policies

result in a bias toward short-term

contracts. These policies include the

term matching cap in the right of first

refusal and the use of the same

maximum rate for service under shortterm and long-term contracts. Under

these conditions, financial risks and

rewards are not linked, i.e., there is risk

asymmetry, favoring short-term

contracts, and there is little incentive for

a shipper to enter into a long-term

contract with the pipeline. If a shipper

enters into a long-term contract, it runs

the risk that its rates will increase

during the term of that contract. It can

avoid this risk, and still be guaranteed

that it can receive service indefinitely

by entering into a short-term contract

with a right of first refusal. The

customer knows that it need never pay

more than the regulated cost-of-service

maximum rate to buy service from the

pipeline, regardless of whether it is

pursuant to a long-term or a short-term

contract. If market conditions are

relatively weak at the end of the current

contract, the customer may be able to

bargain with the pipeline to get a

discount or to obtain service more

cheaply through the secondary market

or on another pipeline. Where capacity

holders have firm rights to capacity that

is valued above the cost-of-service rate,

they will likely hold onto that capacity.

Current contract holders will exercise

their right of first refusal when market

conditions are weak. Other things being

equal, the customer should want a

shorter-term contract.

The pipeline faces the other side of

the bargain. The bias toward short-term

contracts and the current asymmetry of

risk may have negative economic

consequences to the pipelines, and for

example, may be a factor in causing

capacity turn-back and the discounting

of rates for long-term contracts.

Customers may take only relatively

short-term contracts and only when the

value meets or exceeds the rate. The

proposed removal of the price cap in the

short-term market could move some

customers toward longer-term contracts

to avoid price uncertainties and

potential jumps in the short-term prices.

On the other hand, however, removal of

the price cap could move other

customers toward the short-term market

because they could always count on

being able to secure capacity there at

some price. Cost recovery problems

resulting from a weak long-term

transportation market could be a

possibility for pipelines, even if the

price cap were removed, given the

biases toward short-term contracts.

Without changes in the Commission

policies that contribute to this bias, the

Commission’s goals for the short-term

market could be undermined because

pipelines would have an incentive to

undermine short-term markets in order

to be more confident of their ability to

recover their costs over the long term.

A pipeline with cost recovery

problems could try to alleviate the

problem in one of several ways, each of

which would have adverse

consequences on the short-term market.

First, to try to recover their revenues,

pipelines could attempt to raise the

charges to remaining long-term

customers. They are unlikely to be able

to recover their costs in this manner.

Even if successful in raising rates to

remaining customers,118 this action

could cause additional customers to

leave the pipeline, leaving the pipeline

and the remaining customers in an even

worse financial situation.

In addition, a pipeline with a cost

recovery problem would feel pressure to

eliminate alternatives that enable

shippers to turn back capacity.119 If

pipelines can make the secondary

market less viable, by withholding

capacity and/or price discrimination,

they would have more captive

customers from whom to recover their

costs. This would undermine short-term

markets and reduce efficiency because

shippers’ capacity could not be

reallocated to those who value it more.

It would also give pipelines greater

opportunity to exercise market power,

further decreasing efficiency, and

making it easier for a pipeline to

maintain a policy of discrimination

between customers. Thus, by having a

negative impact on the pipeline’s

financial stability, the bias in favor of

short-term markets would provide

incentives for the pipelines to

undermine the short-term market.

B. Specific Impediments to Long-term

Contracts

There are a number of artificial

impediments to long-term contracts on

existing pipelines. These result in lower

risks to shippers for short-term contracts

available for the same maximum rates as

the long-term contracts, thereby

artificially discouraging long-term

contracts. One way to help restore

balance is to remove these artificial

impediments to long-term contracts.

1. The Right of First Refusal

In Order No. 636, the Commission

authorized pre-granted abandonment of

long-term firm contracts, subject to the

right of first refusal for the existing
43016 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

120 18 CFR 284.221(d).

121Order No. 636 capped the matching term at 20

years.

122 88 F.3d 1105, 1139 (D.C. Cir. 1996), cert.

denied, 117 S. Ct. 1723 (1997).

123The term matching cap is not set forth in the

regulations, and, therefore, no revision to 18 CFR

284.221(d) is necessary.

124The proceding section of this NOPR discusses

the role of negotiated terms and conditions in the

short-term market.

shipper.120 Pursuant to the right of first

refusal, the existing shipper can retain

service by matching the rate and length

of service of a competing bid. The rate

is capped by the pipeline’s maximum

tariff rate, and, in Order No. 636–C, the

Commission limited the requirement

that the existing shipper must match the

length of the contract term of a

competing bid to a contract length of

five years.121 On rehearing of Order No.

636–C, the pipelines argued that this

five-year matching cap interferes with

market forces; and, because of the fiveyear cap, it is unlikely that any existing

shipper will renew its contract for more

than five years. While the Commission

concluded that the record in the Order

No. 636 proceeding supported the fiveyear cap, the Commission recognized

there are legitimate concerns about the

practical effects of the five-year

matching cap on the restructured market

as it continues to evolve.

The right of first refusal with the fiveyear 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 shortterm contracts. As a practical matter, the

right of first refusal with the five-year

cap gives current customers the

incentive to opt for as short a contract

term as possible so that, at contract

expiration, they can reassess the value

of the capacity and decide if it is in their

interest to keep it. If pipeline capacity

is relatively valuable, there are likely to

be other shippers interested in longterm contracts, but the existing shipper

will exercise its right of first refusal and

retain the capacity for a five-year term.

On the other hand, if the market value

of long term capacity is low, the existing

shipper can terminate the contract with

no obligation to the pipeline. In these

circumstances, there is no reason for a

shipper with a right of first refusal to

enter into a long-term contract because

it can use a series of short-term

contracts to obtain long-term service,

and wait and see how the market

develops.

This results in an imbalance of risks

between pipelines and existing

shippers. The pipeline is obligated to

provide service for the shipper

indefinitely, as long as it exercises its

right of first refusal, while the shipper

has no corresponding long-term

obligation to the pipeline. Elimination

of the five-year cap from the right of first

refusal would remove a significant

factor in the risk asymmetry discussed

above. Without a limitation on the

contract length that must be matched by

the existing shipper, an existing shipper

who wants to be assured of access to

capacity for the long term would have

to match the highest rate bid up to the

maximum cost-based, for the capacity

for the duration of the contract bid, and

thus share with the pipeline some of the

risks associated with the long-term

commitment.

Elimination of the cap limiting the

contract length that the existing shipper

must match also would foster efficient

competition, as encouraged by Order

No. 636. This cap tends to protect

existing shippers from competition and

give them control over pipeline

capacity. Without the cap, the term of a

contract will be determined by market

forces, rather than by the limitation

established by the Commission.

In UDC v. FERC,122 the Court stated

that for a finding of public convenience

and necessity for pre-granted

abandonment, the Commission must

make appropriate findings that existing

market conditions and regulatory

structures protect customers from

pipelines’ market power. The Court

found that the right of first refusal

mechanism with a cap on contract

length was one adequate means of

protecting customers from pipeline

market power. In response to the Court’s

concern that the Commission had failed

to justify a twenty-year cap, the

Commission adopted the five-year cap

in Order No. 636–C. However,

conditions in the market have changed

substantially since the issuance of Order

No. 636, and the five-year cap has not

worked well in the restructured market.

As discussed above, it has led to

asymmetry of risk and a bias toward

short-term contracts. Therefore, the

Commission is proposing to eliminate

the term matching cap from the right of

first refusal and is seeking comments on

this proposal.123

The Commission is also considering

whether, in view of the changed market

conditions, the right of first refusal

should be eliminated entirely. Since

restructuring, increased competition in

both the commodity and capacity

markets now affords customers greater

protections from market power. Small

LDCs no longer have to hold capacity on

the pipeline in order to receive gas, and

can buy gas delivered from marketers or

can obtain capacity in the secondary

market. In fact, many LDCs have chosen

not to hold capacity on pipelines.

Therefore, changed conditions suggest

that the right of first refusal may no

longer be needed to protect the

customers it was originally intended to

protect. The Commission is seeking

comments on eliminating the right of

first refusal, as well as other options,

such as changing the length of the term

matching cap or permitting the

pipelines and the customers to negotiate

for a right of first refusal.

2. Term-Differentiated Maximum Rates

Another method of reducing risk

asymmetry and strengthening the longterm market would be to encourage

contracts that contain lower maximum

rates for longer-term service than for

short-term service in recognition of the

value of long-term contracts in limiting

the pipeline’s risk. As explained above,

a short-term contract is riskier for the

pipeline, and a higher short-term

contract rate would compensate

pipelines for the additional risk they

take when entering short-term contracts.

Conversely, a short-term contract

provides greater flexibility and less risk

to the shipper, and the higher short-term

rate would recognize, and require

payment for, these benefits.

The Commission is seeking comments

on whether and how term-differentiated

maximum rates should be encouraged,

and, if so, how the rate differential

should vary with contract term. For

example, should there be only two

contract length categories, or should

there be more? How would the

appropriate contract length categories be

determined? How should the rate

differentials between term categories be

set? Could a market mechanism be

developed for determining the

appropriate differentials?

Negotiation may be a primary way of

addressing the sharing of risk between

the parties, to ensure that parties can

contract to minimize the total cost of

that risk. Negotiation of rates and

services is a possible solution to some

of the problems discussed above. The

limitations discussed in the preceding

section124 should keep negotiations

from hurting the fungibility of the

capacity in the short-term market,

increasing the pipelines’ (or their

affiliates’’) ability to exercise market

power, and otherwise hurting third

parties.

C. New Capacity Certificate Issues

The Commission’s proposed changes

in the short-term market also create a

need to review its policies for
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43017

125 In the NOI, the Commission discusses price

distortions in the California and Chicago markets,

where several pipelines were facing significant

turnback of long-term capacity, while other

pipelines were constructing additional capacity to

serve those markets.

126 2 FPC 29 (1939).

127For purposes of evaluating applications for

new construction, a long term is a term of at least

10 years. See e.g., Texas Eastern Transmission

Corp., 82 FERC ¶61,238 (March 11, 1998).

128 ‘‘Generally, as it has evolved, the minimum

level of firm commitment that the Commission has

determined to be sufficient for a new onshore

facility has been 25 percent of the proposed

project’s capacity.’’ Id. at 61,916.

129But see 18 CFR 157.100–157.106 (Applicants

for an optional expedited certificate under Subpart

E of Part 157 may receive a certificate to construct

for others for new service without any requirement

to show specific market demand; however, the rates

for service provided through such facilities will be

designed to impose the economic risks of the

project entirely on the applicant).

130See, e.g., Granite State Gas Transmission, 83

FERC ¶61,194 (1998). The Commission authorized

a new liquefied natural gas (LNG) facility after

comparing services to be provided by the proposed

facility with similar services that might be offered

by employing alternative facilities. Although

employing existing facilities could result in

diminished adverse environmental impacts, the

Commission authorized the proposed project,

finding the service made available by the new LNG

facility would provide specific advantages over the

alternatives.

131As discussed in the NOI, in the Pricing Policy

for New and Existing Facilities Constructed by

Interstate Natural Gas Pipelines, 71 FERC ¶61,241

(1995), the Commission adopted a presumption in

favor of rolled-in rates when the rate increase to

existing customers from rolling in the new facilities

in 5 percent or less, and the pipeline makes a

showing of system benefits.

certificating new capacity and services.

As explained above, the removal of the

price cap in the short-term market

requires that viable regulated services be

available in the long-term market to

mitigate any market power of capacity

sellers. The Commission’s certificate

policies are critical to assuring that

pipelines construct the optimal amount

of capacity to meet demand in the longterm market. Therefore, the Commission

is reviewing its certificate policies to

determine whether these policies

should be modified to meet current

market conditions and needs,

particularly in light of the proposed

changes in the short-term market.

The Commission’s objective in this

review is to assure that its policy is

well-balanced so that facilities are

constructed where demand warrants

construction, while at the same time

guarding against additional construction

that is not necessary to meet any

increase in demand for capacity and

that could result in excess capacity and

the problems of unsubscribed capacity.

The Commission also seeks to assure

that its policies will not result in

building new capacity in markets where

existing facilities are not fully

subscribed because this could create

false price signals and weaken the longterm transportation market.125

Under the policy set forth in Kansas

Pipe Line & Gas Company (Kansas Pipe

Line),126 the Commission required an

applicant seeking an NGA section 7

certificate for authority to construct and

operate new facilities to show customer

commitments sufficient to justify the

proposed project. In order to

demonstrate the need for a new project,

an applicant was required to submit

market studies of the customers and

area to be served, and contracts showing

long-term commitments for 100 percent

of the proposed facility’s capacity. This

approach made it unlikely that too

much capacity would be built.

Under the current policy, an applicant

for a traditional section 7 certificate

must submit precedent agreements for

long-term firm service 127 for a

substantial amount of the new facility’s

capacity.128 Where an applicant is not

able to provide evidence of long-term

commitments for firm service for at least

25 percent of a proposed facility’s

capacity, the Commission will typically

place the applicant at risk for

unrecovered costs attributable to the

unsubscribed capacity.129 This at-risk

condition is intended to discourage

overbuilding and assure that the

pipeline’s other customers are not

compelled to pay for costs associated

with unused capacity.

In considering evidence of market

demand, the Commission gives equal

weight to precedent agreements between

an applicant and its affiliates and an

applicant and unrelated third parties.

Further, the Commission has not sought

to assess whether these customer

commitments indicate a genuine growth

in market demand necessitating

additional gas supplies, or reflect a

desire to access separate supply sources

for unchanging quantities of gas, or

represent efforts to obtain reduced

transportation charges for shipping

identical gas volumes. Before Order No.

636, new projects were typically

intended to bring gas to unserved or

clearly under-served markets.

Increasingly, new projects are designed

to compete for market share by offering

alternatives to customers in established

markets.

The Commission seeks to assure that

its policies strike the proper balance

between the enhancement of

competitive alternatives and the

possibility of over building. The

Commission wants to assure that its

policies serve to maximize competitive

alternatives, while at the same time

protect against overbuilding,

unnecessary disruption of the

environment, and unneeded exercise of

eminent domain over private property.

Specifically, the Commission seeks

comments on whether proposed projects

that will establish a new right-of-way in

order to compete for existing market

share should be subject to the same

considerations as projects that will cut

a new right-of-way in order to extend

gas service to a frontier market area. In

conjunction with this reassessment of

project need, the Commission is

considering how best to balance

demonstrated market demand against

potential adverse environmental

impacts and private property rights in

weighing whether a project is required

by the public convenience and

necessity.130

One option would be for the

Commission to authorize all

applications that at a minimum meet the

regulatory requirements, then let the

market pick winners and losers.

Another would be for the Commission

to select a single project to serve a given

market and exclude all other

competitors. Another possible option

would be for the Commission to

approve an environmentally acceptable

right-of-way and let potential builders

compete for a certificate.

The Commission requests comments

on these three options, as well as

comments on the following questions:

(1) Should the Commission look behind

the precedent agreement or contracts

presented as evidence of market

demand to assess independently the

market’s need for additional gas service?

(2) Should the Commission apply a

different standard to precedent

agreements or contracts with affiliates

than with non-affiliates? For example,

should a proposal supported by affiliate

agreements have to show a higher

percentage of contracted-for capacity

than a proposal supported by nonaffiliate agreements, or, should all

proposed projects be required to show a

minimum percent of non-affiliate

support? (3) Are precedent agreements

primarily with affiliates sufficient to

meet the statutory requirement that

construction must be required by the

public convenience and necessity, and,

if so, (4) Should the Commission permit

rolled-in rate treatment for facilities

built to serve a pipeline affiliate? 131 (5)

Should the Commission, in an effort to

check overbuilding and capacity

turnback, take a harder look at proposals

that are designed to compete for existing

market share rather than bring service to

a new customer base, and what

particular criteria should be applied in
43018 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

132See, 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); 18 CFR

284.12 (filing of capacity).

looking at competitive applications

versus new market applications? (6)

Should the Commission encourage prefiling resolution of landowner issues by

subjecting proposed projects to a

diminished degree of scrutiny where the

project sponsor is able to demonstrate it

has obtained all necessary right-of-way

authority? (7) Should a different

standard be applied to project sponsors

who do not plan to use either federal or

state-granted rights of eminent domain

to acquire right-of-way?

The parties may also address other

questions concerning certification issues

in general, including: (1) What should

the Commission do to provide for the

infrastructure to serve future increased

demand for capacity? (2) How can

pipelines deal with the potential for not

recovering new construction costs?

Should the Commission address, at the

certificate issuance stage, the issue of a

pipeline’s responsibility for future cost

under-recovery once its initial contracts

expire? Assuming no adverse

environmental impacts, should a

pipeline be allowed to build if it does

not accept the responsibility for all of

the cost not covered by its initial

contracts? What, if anything, should the

Commission do to ensure rate certainty

for customers and pipelines? Can or

should this include guarantees against

future rolling-in of costly expansions,

future changes in O&M expenses, or any

other future changes? (3) Should the

Commission reassess the balance

between risk and return? Is there really

more risk for a pipeline with short-term

contracts, or will shippers continue to

make short-term deals for the life of the

pipeline that cover the pipeline’s costof-service? Is any of the risk

unnecessary, and can it be eliminated

without imposing additional costs? How

should rates be determined after

contracts expire? Should the

Commission establish different pricing

based on contract term? (4) What are the

advantages (or disadvantages) of

allowing pipelines and customers to

negotiate pre-construction risk and

return-sharing agreements, and what

actions should the Commission take if

pipelines and customers do not agree on

the allocation of risk and return? (5) To

what extent should the policies on new

construction and existing pipelines

match? (6) How does retail unbundling

and open access affect all of these

issues?

VII. Reorganization of Part 284

Regulations

Commission proposes to reorganize

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.

Because capacity release has become an

integral part of the short-term market,

the Commission is proposing to move

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 sections 284.7 (firm service),

284.8 (release of firm service), and 284.9

(interruptible service)).

In addition, reporting and filing

requirements for pipeline Part 284

services are presently scattered

throughout Part 284. For example, the

Index of Customers and storage reports

are presently located in subpart B,

section 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, section 284.223.

Other reporting requirements are

located throughout various substantive

provisions of Part 284.132 The

Commission is proposing to collect

these requirements into one new section

(proposed § 284.14) 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.

To aid commenters’ review of the new

regulatory format, the following would

be 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 Negotiated rates and services.

284.12 Environmental compliance.

284.13 Standards for pipeline business

operations and communications.

284.14 Reporting requirements for interstate

pipelines.

The Commission recognizes that such

changes may occasion the need for

cross-reference changes in other

sections of Part 284 as well as other

parts of the regulations. The

Commission would make such nonsubstantive changes in the final rule,

and commenters should point out

regulatory sections where such changes

are needed.

VIII. Information Collection Statement

The following collections of

information would be affected by this

proposed rule and have been submitted

to the Office of Management and Budget

(OMB) for review under Section 3507(d)

of the Paperwork Reduction Act of 1995,

44 U.S.C. 3507(d). The Commission

solicits comments on the Commission’s

need for this information, whether the

information will have practical utility,

the accuracy of the provided burden

estimates, ways to enhance the quality,

utility, and clarity of the information to

be collected, and any suggested methods

for minimizing respondents’s burden,

including the use of automated

information techniques. The burden

estimate in this proposed rule includes

the cost for pipelines to comply with the

Commission’s proposed regulations

concerning short-term natural gas

transportation services. The following

burden estimates reflect only the

incremental costs of complying with the

proposed new and revised standards

intended to implement the

Commission’s regulations. The burden

estimates include start up and on-going

costs.

Estimated Annual Burden: The

estimated annual burden associated

with this NOPR is shown below.

Affected data collection Number of respondents

Number of responses

per respondent

Estimated burden

hours per response

Total annual burden hours

FERC–545 ........................................................ 100 2.0 97.800 19,560

FERC–549B ...................................................... 100 446.5 1.526 68,136

FERC–592 ........................................................ 74 1.0 7.000 518

Total ........................................................... ................................ ................................................ ................................ 88,214
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43019

133 5 CFR 1320.11.

134Order No. 486, Regulations Implementing the

National Environmental Policy Act, 52 FR 47897

(Dec. 17, 1987), FERC Stats, & Regs. Preambles

1986–1990 ¶30,783 (1987).

135 18 CFR 380.4.

136 See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5),

380.4(a)(27). 137 5 U.S.C. 601–612.

The estimated number of reporting

hours attributable to the requirements

proposed herein are expected to total

88,214 hours and are included in the

above annual burden estimates.

Information Collection Costs: The

Commission seeks comments on the

estimated cost to comply with these

requirements. It has projected average

annualized costs for all respondents to

be the following:

[In dollars]

Estimated data collection costs FERC–545 FERC–549B FERC–592 Total

Annualized Capital/Startup Costs ..................................................................... 842,061 168,412 0 1,010,473

Annualized Costs (Operations & Maintenance) ............................................... 187,359 3,417,506 27,262 3,632,127

Total Annualized Costs ............................................................................. $1,029,420 3,585,918 27,262 4,642,600

The OMB regulations require OMB to

approve certain information collection

requirements imposed by agency

rule.133 Accordingly, pursuant to OMB

regulations, the Commission is

providing notice of its proposed

information collections to OMB.

Titles: FERC–545, Gas Pipeline Rates:

Rate Change (Non-Formal); FERC–549B,

Gas Pipeline Rates: Capacity

Information (a proposed new title); and

FERC–592, Marketing Affiliates of

Interstate Pipelines.

Action: Proposed Data Collections.

OMB Control Numbers: 1902–0154;

1902–0169; and 1902–0157,

respectively. The respondent shall not

be penalized for failure to respond to

these information collections unless the

collection of information displays a

valid OMB control number.

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.

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

Commission’s Office of Pipeline

Regulation will use the data to monitor

the market place to correct problems

and minimize the exercise of market

power. Additionally, the industry itself

will use the information to make more

informed choices from among

alternative capacity sources and to

monitor the marketplace. The

Commission’s determination of burden

involves among other things, an

examination of adequacy of design, cost,

reliability, and redundancy of the

information to be required. These

requirements conform to the

Commission’s plan for efficient

information collection, communication,

and management within the natural gas

pipeline industry.

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:

michael.miller@ferc.fed.us]

For submitting comments concerning

the collections of information(s) and the

associated burden estimate(s), please

send your comments to the contact

listed above and to the Office of

Management and Budget, Office of

Information and Regulatory Affairs,

Washington, DC, 20503. [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.134 The Commission has

categorically excluded certain actions

from these requirements as not having a

significant effect on the human

environment.135 The actions proposed to

be 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.136

Therefore, an environmental assessment

is unnecessary and has not been

prepared in this rulemaking.

X. Regulatory Flexibility Act

Certification

The Regulatory Flexibility Act of 1980

(RFA) 137 generally requires a

description and analysis of final rules

that will have significant economic

impact on a substantial number of small

entities. The proposed regulations

would impose requirements on

interstate pipelines, which generally are

not small businesses. Accordingly,

pursuant to section 605(b) of the RFA,

the Commission proposes to certify that

the regulations proposed herein will not

have a significant adverse impact on a

substantial number of small entities.

XI. Comment Procedures

The Commission invites interested

persons to submit written comments on

the matters and issues proposed in this

notice to be adopted, including any

related matters or alternative proposals

that commenters may wish to discuss.

An original and 14 copies of comments

must be filed with the Commission no

later than November 9, 1998. Comments

should be submitted to the Office of the

Secretary, Federal Energy Regulatory

Commission, 888 First Street, NE,

Washington, DC 20426, and should refer

to Docket No. RM98–10–000. All

written comments will be placed in the

Commission’s public files and will be

available for inspection in the

Commission’s Public Reference Room at

888 First Street, NE, Washington, DC

20426, during regular business hours.

Additionally, comments should be

submitted electronically. Commenters

are encouraged to file comments using

Internet E-Mail. Comments should be

submitted through the Internet by EMail to comment.rm@ferc.fed.us in the
43020 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

following format: on the subject line,

specify Docket No. RM98–10–000; in

the body of the E-Mail message, specify

the name of the filing entity and the

name, telephone number and E-Mail

address of a contact person; and attach

the comment in WordPerfect 6.1 or

lower format or in ASCII format as an

attachment to the E-Mail message. The

Commission will send a reply to the EMail to acknowledge receipt. Questions

or comments on electronic filing using

Internet E-Mail should be directed to

Marvin Rosenberg at 202–208–1283, EMail address

marvin.rosenberg@ferc.fed.us.

Commenters also can submit

comments on computer diskette in

WordPerfect 6.1 or lower format or in

ASCII format, with the name of the filer

and Docket No. RM98–10–000 on the

outside of the diskette.

List of Subjects

18 CFR Part 161

Natural gas, Reporting and

recordkeeping requirements.

18 CFR Part 250

Natural gas, Reporting and

recordkeeping requirements.

CFR Part 284

Continental shelf, Incorporation by

reference, Natural gas, Reporting and

recordkeeping requirements.

By direction of the Commission.

David P. Boergers,

Acting Secretary.

In consideration of the foregoing, the

Commission proposes to amend part

161, part 250, and part 284, chapter I,

title 18, Code of Federal Regulations, as

set forth below.

PART 161—STANDARDS OF

CONDUCT FOR INTERSTATE

PIPELINES WITH MARKETING

AFFILIATES

1. 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.

2. In § 161.3, paragraphs (i) through

(k) are renumbered (j) through (l) and

paragraph (i) is added to read as follows:

§ 161.3 Standards of conduct

* * * * *

(i) A pipeline must post the following

information concerning its affiliates on

its Internet web site complying with

§ 284.13 of this chapter and update the

information within three business days

of any change, posting the date on

which the information was updated.

(1) A complete list of operating

personnel and facilities shared by the

pipeline and its marketing affiliates.

(2) Comprehensive organizational

charts and job descriptions for its

employees and the employees of its

marketing affiliates identifying which

employees are engaged in transportation

and which are engaged in sales or

marketing, and clearly showing the

chain of command. The job descriptions

need not include employees whose jobs

are purely clerical or those without

responsibility or access to information

concerning the processing or

administration of requests for

transportation service. Each job

description must include: the

employee’s title, duties and status as an

operating or non-operating employee;

and in the case of a senior employee

(i.e., any employee who supervises nonclerical employees), the employee’s

name.

* * * * *

3. In § 161.3(h)(2), revise all

references to ‘‘284.10(a)’’ to read

‘‘284.13’’ and remove the words

‘‘Electronic Bulletin Board, operated

pursuant to’’ and add, in their place, the

words ‘‘Internet Web site complying

with’’.

PART 250—FORMS

4. 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.

5. In § 250.16, paragraph (b)(1) is

removed, paragraph (b)(2) is

redesignated as (b)(1), and paragraph

(b)(2) is reserved.

§ 250.16 [Amended]

6. In § 250.16(c)(2), revise all

references to ‘‘284.10(a)’’ to read

‘‘284.13’’ and remove the words

‘‘Electronic Bulletin Board, operated

pursuant to’’ and add, in their place, the

words’’ Internet Web site complying

with’’.

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.

§ 284.12 [Removed]

8(a) Part 284 is amended by removing

§ 284.12.

8(b) 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 ......................................... 284.13

284.11 ......................................... 284.12

9. In newly redesignated § 284.7,

paragraph (b)(3) is removed and

paragraph (b)(4) is redesignated as

paragraph (b)(3).

10. Part 284 is amended by adding

§ 284.8 to read as follows:

§ 284.8 Release of firm transportation

service.

(a) An interstate pipeline that offers

transportation service on a firm basis

under subparts B or G of this part must

include in its tariff a mechanism for

firm shippers to release firm capacity to

the pipeline for resale by the pipeline

on a firm basis.

(b) To the extent necessary, a firm

shipper on an interstate pipeline that

offers transportation service on a firm

basis under subpart B or G of this part

is granted a limited-jurisdiction blanket

certificate of public convenience and

necessity pursuant to section 7 of the

Natural Gas Act solely for the purpose

of releasing firm capacity pursuant to

this section.

(c) The pipeline must enter into a

contract with the replacement shipper

purchasing the capacity. Unless

otherwise agreed by the pipeline, the

contract of the shipper releasing

capacity will remain in full force and

effect, with the net proceeds from any

resale to a replacement shipper credited

to the releasing shipper’s reservation

charge.

(d) Releases of capacity for a period of

less than one year must conform to the

requirements of the auction established

under § 284.10(c)(5) of this part.

(e) Releases of capacity of one year or

more must comply with the following

requirements.

(1) A shipper may arrange for a

replacement shipper to obtain its

released capacity from the pipeline. The

releasing and replacement shippers or

an authorized agent must notify the

pipeline of the terms and conditions of

the release.

(2) A shipper may post any capacity

it has available on the pipeline’s

Internet site and may authorize the

pipeline to accept bids for such

capacity. A releasing shipper posting

capacity for bid must notify the pipeline

of the terms and conditions under

which it will release its capacity.
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43021

(3) For releases of capacity of one year

or more, the rate may not exceed the

maximum rate in the pipeline’s tariff.

§ 284.9 [Amended]

11. In § 284.9, paragraph (b)(3) is

removed and paragraph (b)(4) is

redesignated paragraph as (b)(3).

12. In newly redesignated § 284.10,

paragraphs (c)(5) and (c)(6) are revised,

and paragraph (c)(7) is added to read as

follows.

§ 284.10 Rates.

* * * * *

(c) * * *

(5) Rates for short-term transportation

services. For transportation contracts of

less than one year for pipeline firm and

interruptible service and for capacity

released pursuant to § 284.8 of this part,

the rates will be determined in the

following manner.

(i) Minimum rate. The minimum rate

charged for such service may not be

lower than the minimum rate in the

pipeline’s tariff.

(ii) Capacity auction. The rate charged

for any transaction at or above the

minimum rate will be determined by an

auction that conforms to the following

requirements:

(A) All available short-term capacity

must be sold through an auction;

(B) Daily capacity from the pipeline

must be sold through an auction

without the establishment of a reserve

or minimum bid price;

(C) All eligible shippers must be

permitted to bid with no favoritism

shown to pipeline affiliates or other

shippers;

(D) The procedures and rules for each

auction, including the auction schedule,

must be disclosed in the pipeline’s tariff

in advance of the auction and must be

applied to each auction;

(E) Capacity must be allocated based

on established criteria and parameters

known in advance to all bidders and the

same criteria and parameters must apply

to pipeline and released capacity;

(F) Shippers must be able to validate

that the auction was run properly either

through the posting of information

sufficient to permit them to validate that

the winners were selected appropriately

or through the use of other mechanisms,

such as an independent third-party,

which will validate the results.

(6) Rates for long-term transportation

services. (i) Except as provided in

section (ii) of this paragraph and

§ 284.11 of this part, for transportation

contracts of one year or longer for

pipeline firm and interruptible service,

the pipeline may charge an individual

customer a rate that is neither greater

than the maximum rate nor less than the

minimum rate on file for that service.

(ii) The pipeline may not file a revised

or new rate designed to recover costs

not recovered under rates previously in

effect.

(7) Rates involving marketing

affiliates. If a pipeline does not hold a

blanket certificate under subpart G of

this part, it may not charge, in a

transaction involving its marketing

affiliate, a rate that is lower than the

highest rate it charges in any transaction

not involving its marketing affiliate.

13. Part 284 is amended by adding

§ 284.11 to read as follows.

§ 284.11 Negotiated rates and services.

(a) Authority. An interstate pipeline

that provides transportation service

under subparts B or G of this part may

negotiate with shippers the rates, or

terms and conditions of service, in any

contract, provided the pipeline offers all

shippers recourse to transportation

service under its generally applicable

transportation tariff as an alternative to

negotiated service.

(b) Limitations on negotiations.

Pipelines cannot negotiate rates and

services that:

(1) result in undue discrimination or

preference;

(2) degrade the quality of existing

services;

(3) hinder the release of capacity or

otherwise significantly reduce

competition; or

(4) require customers, as a condition

of obtaining negotiated rates or services,

to purchase sales, storage, or gathering

services provided by the pipeline, its

affiliates, or upstream or downstream

entities that are unnecessary to the

provision of the negotiated service.

(c) Review of recourse service.

Pipelines must file (every 3 or 5 years)

the following information regarding

negotiated rates and terms of service

and recourse service.

(1) For each negotiated transaction,

the pipeline must file, for each calendar

year, by category of negotiated

transaction (transactions taking effect on

shortened notice and transactions

subject to 30 days notice) the following:

the name of the shipper, the shipper’s

designation (e.g., marketer, producer,

LDC, end-user), the contract number,

the docket number under which the

contract was filed with the Commission,

the type of service (e.g., firm or

interruptible transportation or storage),

the contract demand, the rate, and the

volume. For transactions taking effect

under shortened notice, the pipeline

must include an indication of the tariff

categories under which the contract was

negotiated. For transactions subject to

thirty days notice, the pipeline must

include a short description of the terms

and conditions negotiated.

(2) For each year, for each category of

negotiated service and for recourse

services, by rate schedule, the pipeline

must file data showing aggregate

contract demand, aggregate volumes,

and aggregate revenue.

14. In newly redesignated § 284.13,

paragraphs (c)(1)(ii) and (c)(2)(iii)

through (v) are added and paragraph

(b)(1)(v) is revised to read as follows.

§ 284.13 Standards for pipeline business

operations and communications.

* * * * *

(b) * * *

(1) * * *

(v) Capacity Release Related

Standards (Version 1.2,

July 31, 1997), with the exception of

Standard 5.3.2.

(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 of submission

of the transaction, but the requirement

for contracting must not inhibit the

ability to submit a nomination at the

time the transaction is complete.

(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

must provide such services without

undue discrimination or preference of

any kind against third parties that seek

to provide similar services to the

shippers of the pipeline.

(iv) Penalties. A pipeline may include

in its tariff transportation penalties only

to the extent necessary for system

operations. A pipeline must provide, 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.

(v) 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
43022 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

will enable shippers to minimize the

adverse impacts of these measures.

* * * * *

15. Part 284 is amended by adding

§ 284.14 to read as follows:

§ 284.14 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, where

applicable.

(b) Index of customers. (1) On the first

business day of each calendar quarter,

subsequent to the initial

implementation of this provision, an

interstate pipeline must provide for

electronic dissemination of an index of

all its firm transportation and storage

customers under contract as of the first

day of the calendar quarter. Electronic

dissemination will be by placing a file,

adhering to the requirements set forth

by the Commission, on the pipeline’s

Internet web site, pursuant to section

284.13 of this part, in a format which

can be downloaded. The pipeline must

also submit the electronic file to the

Commission.

(2) Until an interstate pipeline is in

compliance with the reporting

requirements of this paragraph, the

pipeline must comply with the index of

customer requirements applicable to

transportation and sales under part 157,

set forth under § 154.111(b) and (c) of

this chapter.

(3) For each customer receiving firm

transportation or storage service, the

index must include the information

listed below:

(i) The full legal name of the

customer;

(ii) The rate schedule number of the

service being provided;

(iii) The contract number;

(iv) The contract effective date;

(v) The contract expiration date;

(vi) For transportation service,

maximum daily contract quantity

(specify unit of measurement);

(vii) For storage service, maximum

storage quantity (specify unit of

measurement);

(viii) The receipt and delivery points

and the zones or segments in which the

capacity is held;

(ix) An indication as to whether the

contract includes negotiated rates or

terms and conditions;

(x) Any affiliate relationship between

the pipeline and the customer or any

affiliate relationships between contract

holders;

(xi) The name of any agent or asset

manager managing 20% or more of the

transportation service in a pipeline rate

zone and the agent’s and asset

manager’s rights with respect to

managing the transportation service.

(4) The information included in the

quarterly index must be available on the

pipeline’s web site until the next

quarterly index is established.

(5) The requirements of this section

do not apply to contracts which relate

solely to the release of capacity under

§ 284.8, unless the release is permanent.

(6) The requirements for the

electronic index can be obtained at the

Federal Energy Regulatory Commission,

Division of Information Services, Public

Reference and Files Maintenance

Branch, Washington, DC 20426.

(c) 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 section

284.13 of this part.

(1) For pipeline firm service, whether

provided by the pipeline or from release

transactions under section 284.8 of this

part, the pipeline must post,

contemporaneously with the execution

of a contract for service:

(i) The full legal name of the shipper

receiving service under the contract and

the full legal name 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 duration of the contract;

(v) The receipt and delivery points

and mainline segments covered by the

contract;

(vi) The contract quantity or the

volumetric quantity under a volumetric

release;

(vii) Any special terms and conditions

applicable to the contract; and

(viii) 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 of the shipper;

(ii) The rate charged;

(iii) The receipt and delivery points

and mainline segments over which the

shipper is entitled to nominate gas;

(iv) The quantity of gas the shipper is

entitled to nominate;

(v) Whether the shipper is affiliated

with the pipeline.

(d) Available capacity. (1) An

interstate pipeline must provide on its

Internet web site and in downloadable

file formats, in conformity with section

284.13 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

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;

(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;

and

(6) The related docket numbers in

which the interstate pipeline reported

storage related injection/withdrawal

transportation services.

16. In § 284.106, paragraph (c) is

removed and paragraph (b) is revised to

read as follows:
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 43023

§ 284.106 Reporting requirements

* * * * *

(b) An interstate pipeline providing

transportation service under this

subpart must comply with the reporting

requirements of § 284.14 of this part.

§ 284.223 [Amended]

17. In § 284.223, paragraph (b) is

removed and reserved.

18. Subpart H is revised to read as

follows:

Subpart H—Assignment of Capacity on

Upstream Interstate Pipelines

§ 284.241. Upstream interstate pipelines.

An interstate pipeline that offers

transportation service on a firm basis

under subpart B or G of this part must

offer without undue discrimination to

assign to its firm shippers its firm

transportation capacity, including

contract storage, on all upstream

pipelines, whether the firm capacity is

authorized under part 284 or part 157.

An upstream pipeline is authorized and

required to permit a downstream

pipeline to assign its firm capacity to

the downstream pipeline’s firm

shippers.

§§ 284.10, 284.123, 284.221, 284.261,

284.263, 284.266, and 284.286 [Amended]

19. §§ 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. Revise all references to ‘‘§ 284.7’’ to

read ‘‘§ 284.10’’ in the following places:

1. Section 284.221(d)(2)(ii);

2. Section 284.261;

3. Section 284.263; and

4. Sections 284.266(a)(1) and (a)(2).

B. Revise all references to ‘‘§§ 284.8–

284.13’’ to read ‘‘§§ 284.7–284.9 and

§§ 284.11–284.14’’ in the following

places:

1. Section 284.261; and

2. Section 284.263.

C. Revise all references to ‘‘§ 284.8(d)’’

to read ‘‘§ 284.7(d)’’ in newly

redesignated §§ 284.10(c)(1) and (c)(2).

D. Revise all references to ‘‘§§ 284.8’’

to read ‘‘§§ 284.7’’ in § 284.123 (b)(1).

E. Revise all references to

‘‘§§ 284.8(b)(2)’’ to read ‘‘§§ 284.7(b)(2)’’

in § 284.286(b).

F. Remove the words ‘‘§§ 161.3(c), (e),

(f), (g), and (h)’’ and add, in its place,

the words ‘‘§§ 161.3(c), (e), (f), (g), (h),

and (i)’’ in section 284.286(c).

[FR Doc. 98–20998 Filed 8–10–98; 8:45 am]

BILLING CODE 6717–01–P