42974 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

1As discussed below, in the NOPR, the

Commission is proposing to eliminate the term

matching cap of the right of first refusal, and is

seeking comments on whether it should encourage

term-differentiated rates.

2Wellhead Decontrol Act, Pub. L. 101–60, 103

Stat. 157 (1989).

3Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing

Transportation; and Regulation of Natural Gas

Pipelines After Partial Wellhead Decontrol, 57 FR

13,267 (April 16, 1992), III FERC Stats. & Regs.

Preambles ¶ 30,939 (April 8, 1992); order on reh’g,

Order No. 636–A, 57 FR 36,128 (August 12, 1992),

III FERC Stats. & Regs. Preambles ¶ 30,950 (August

3, 1992); order on reh’g, Order No. 636–B, 57 FR

57,911 (December 8, 1992), 61 FERC ¶ 61,272

(November 27, 1992); United Distribution

Companies v. FERC, 88 F.3d 1108 (DC Cir. 1996);

cert. denied Associated Gas Distributors v. FERC,

117 S.Ct. 1723 (1997).

4See, e.g., Arthur Andersen & Cambridge Energy

Research Associates, North American Natural Gas

Trends, at pp. 3, 8, 10, 51.

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Ch. I

[Docket No. RM98–12–000]

Regulation of Interstate Natural Gas

Transportation Services

July 29, 1998.

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Notice of inquiry.

SUMMARY: The Federal Energy

Regulatory Commission (Commission) is

issuing this notice of inquiry to seek

comments on its regulatory policies for

interstate natural gas transportation

services in view of the changes that

have taken place in the natural gas

industry in recent years. Specifically,

the Commission is seeking comments on

its pricing policies in the existing longterm market and pricing policies for

new capacity.

DATES: Comments are due November 9,

1998.

ADDRESSES: Comments should be

submitted to the following address:

Federal Energy Regulatory Commission,

888 First Street, NE, Washington DC,

20426.

FOR FURTHER INFORMATION CONTACT:

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.

Notice of Inquiry

In this Notice of Inquiry (NOI), the

Commission is seeking comments on its

regulatory policies for interstate natural

gas transportation services in view of

the changes that have taken place in the

natural gas industry in recent years. The

Commission is concerned that some of

its policies, which were developed for a

highly regulated market, need to be

reexamined in light of the increasingly

competitive natural gas industry. This

NOI is broad in scope, and complements

the Notice of Proposed Rulemaking in

Regulation of Short-Term Gas

Transportation Services, Docket No.

RM98–10–000, (Short-Term

Transportation NOPR or NOPR), issued

today.

In the NOPR, the Commission is

making specific proposals for changes in

its regulation of short-term

transportation services. The NOPR also

addresses several long-term

transportation issues that have a direct

and significant impact on the short-term

transportation policy proposals

contained in the NOPR.1 This NOI

continues the Commission’s review of

its regulatory policies, and seeks

comment on whether fundamental

aspects of its pricing for long-term

service and certificate pricing should be

modified to be more effective in today’s

environment.

In the last several years natural gas

markets have changed dramatically. As

a result of the decontrol of gas prices at

the wellhead by Congress 2 and the

Commission’s restructuring of pipeline

services in Order No. 636,3 gas markets

have evolved from highly regulated

markets to markets largely driven by

competition and market forces.4 Six

years ago, pipelines were gas merchants

and sold delivered gas to customers at

Commission-regulated prices. Today,

shippers can buy gas at the wellhead or

from gas marketers, trade gas among

themselves, and purchase pipeline

capacity from marketers and other

shippers in the secondary market, as

well as from the pipeline. These

changes have benefitted gas consumers

by providing a wider range of options in

pipeline services. These changes also

require that the Commission consider

whether the regulatory policies that

were appropriate in the past, are wellsuited to today’s more competitive

markets.

There are significant differences

between short-term and long-term

transportation, and they have been

affected differently by the unbundling

and restructuring of Order No. 636. The

effects of unbundling have been more

dramatic in the short-term

transportation market, where numerous

competitive alternatives for shippers

have developed. These alternatives

include purchasing capacity from the

pipeline on an interruptible or shortterm firm basis, purchasing capacity

released by firm shippers, or purchasing

delivered gas from a marketer or third

party. This has led the Commission to

propose changes to its regulation of

short-term transportation in the

companion NOPR. There are fewer

alternatives in the long-term

transportation market, and pipelines

therefore retain a greater degree of
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42975

5See Alternatives to Traditional Cost-of-Service

Ratemaking for Natural Gas Pipelines, 70 FERC

¶ 61,139 (1995), 60 FR 8356 (February 14, 1995).

6See e.g., Order No. 636–C, 78 FERC ¶ 61,186,

slip op. at 26 (1997), 62 FR 10204 (March 6, 1997).

As discussed below, the Commission is seeking

comments on whether the trend toward shorterterm contracts is a natural result of competition in

gas commodity and pipeline capacity markets, or is

a consequence of other factors, such as regulatory

policies.

7See ‘‘Future Unsubscribed Capacity,’’ AGA LDC

Caucus, December 1995, p.1.

8See e.g., El Paso Pipeline Company, 72 FERC

¶ 61,083 (1995); Natural Gas Pipeline Company of

America, 71 FERC ¶ 61,391 (1995). See also ‘‘Future

Unsubscribed Capacity,’’ AGA LDC Caucus,

December 1995. As discussed below, the

Commission is seeking comments on the extent to

which capacity turnback is likely to be a problem

in the future.

9The Energy Information Agency (EIA) of the

Department of Energy projects an increase in gas

demand from 22.0 Tcf annually in 1996 to between

29.4 Tcf and 34.5 Tcf annually in 2020.

10E.g., FPC v. Hope Natural Gas, 320 U.S. 591,

610 (1944)(the primary purpose of the NGA is ‘‘to

protect consumers against exploitation at the hands

of natural gas companies.’’); Associated Gas

Distributors v. FERC, 824 F.2d 981, 995 (DC 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.’’)

market power over some customers in

the long-term transportation market.5

The trend in the natural gas industry

since unbundling has been toward

shorter-term contracts.6 This places

greater risks on the pipeline.

Specifically, the long-term risk inherent

in pipeline investment is the risk that

the pipeline owner will not earn enough

revenue during the pipeline’s useful life

to cover the total cost of the pipeline,

including the variable cost of operating

and maintaining it and an acceptable

return on the investment.

In the past, shippers entered into

long-term contracts because under those

market conditions, the price risk to

shippers associated with a long-term

contract, i.e., that the rates would

increase during the term of the contract,

was balanced by the fact that there was

little or no supply risk. In the current

market, however, the number of reliable

alternatives to long-term pipeline

transportation and gas supplies has

increased, resulting in discounting of

short-term transportation, while many

shippers’ own markets have become

uncertain, due to retail unbundling.7

Thus, an imbalance of risk between

pipelines and shippers has developed in

the long-term market, resulting in a bias

toward short-term markets on existing

capacity. This imbalance of risks has led

shippers to be less willing to shoulder

the price risk associated with long-term

contracts.

While the trend in the industry has

been toward shorter contracts, long-term

contracts provide important benefits to

pipelines and customers. Long-term

contracts can provide revenue stability

and reduce financial risks to the

pipeline. This arguably lowers the

pipeline’s capital costs, to the benefit of

its customers. Long-term contracts also

act as an important risk-management

tool for shippers, and ensure that there

will be sufficient capacity available for

release in the short-term market to

provide competition for pipeline

capacity in that market. Further, with

removal of the price cap on short-term

services as proposed in the companion

NOPR published elsewhere in this issue

of the Federal Register, long-term

contracts offer price risk protection for

captive customers.

As the Commission explains in the

NOPR, it is concerned that some of its

regulatory policies result in a bias

toward short-term contracts.

Specifically, the Commission states in

the NOPR that the five-year matching

cap in the right of first refusal and the

use of the same maximum rate for

service under long-term and short-term

contracts result in asymmetry of risk

and provide little incentive for a shipper

to enter into a long-term contract with

a 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 that risk, and

still be guaranteed to receive service

indefinitely, by entering into a shortterm contract with a right of first refusal.

Therefore, the Commission proposes

in the NOPR to eliminate the five-year

term-matching cap from the right of first

refusal, and seeks comments on whether

to encourage term-differentiated rates as

a means of removing impediments to

long-term contracts. Similarly, one

Commission objective in the review

undertaken in this NOI is to assure that

the Commission’s policies do not

provide an artificial disincentive to

long-term contracts, but are neutral with

regard to long-term and short-term

contracts.

The Commission’s review undertaken

in this NOI, however, is broader in

scope, and is also directed at ensuring

that the Commission’s regulatory

policies in general provide the correct

incentives in the context of the realities

of today’s natural gas transportation

market. This task is complicated by the

fact that the realities of this market may

vary from region to region or market to

market, and the Commission’s policies

must be suited to a variety of

circumstances.

For example, when long-term

contracts expire and are not renewed,

capacity turnback may be a problem on

some pipelines or in some markets.8 On

the other hand, it has been projected

that demand for capacity will increase

in the future.9 This indicates that market

conditions may vary from market to

market, and that while, in some

markets, demand may be shrinking, and

capacity turnback may be a

consequence, in other markets, demand

may be growing and expansions of

capacity may be needed. These changes

are likely to occur at the same time and

no single development is likely to

characterize the whole natural gas

market. The Commission wants to

ensure that its policies are not biased

toward either short-term or long-term

service, and provide accurate price

signals and the right incentives for

pipelines to provide optimal

transportation services and construct

facilities that meet future demand, but

do not result in overbuilding and excess

capacity. At the same time, the

Commission wants to assure that its

policies continue to provide appropriate

incentives to producers.

Pricing of Existing Capacity. The

Commission’s statutory responsibility

under the Natural Gas Act is to protect

consumers of natural gas from the

exercise of monopoly power by

pipelines,10 and to assure that rates for

interstate transportation are just and

reasonable. The Commission has

proposed in the NOPR that removal of

the price cap in the short-term

transportation market is consistent with

these statutory responsibilities. The

Commission’s proposals for regulatory

change in the short-term market are

intended to maximize competition in

the short-term market, and at the same

time protect customers from the exercise

of market power.

An important aspect of the regulatory

regime proposed in the NOPR is the

continued use of cost-based ratemaking

in the long-term market as a protection

against the pipelines’ exercise of market

power. If pipelines could charge

unregulated rates in the long-term

market, then that protection would be

eviscerated. Moreover, pipelines

continue to be the only source of longterm transportation capacity, and

without cost-based regulation for longterm transportation, pipelines would

have an incentive to build less than the

optimal amount of capacity in order to

create scarcity, with the goal of driving

up prices and profits. The retention of

cost-based regulation for long-term

transportation protects customers

because it gives pipelines incentives to

build new capacity when it is

warranted, and thus limits the
42976 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

11Transwestern Pipeline Company, 72 FERC ¶

61,085 (1995). Transwestern faced a turn-back of

457,281 MMBtu. Transwestern did not unilaterally

file to increase its rates to reflect the turn-back in

this proceeding. Rather, the right to do so was

reserved by Transwestern as the explicit option in

the event another accommodation could not be

achieved.

12El Paso Natural Gas Company, 72 FERC ¶

61,083 (1995). El Paso faced a total turnback of

approximately 1,300,000 MMcf from PG&E, SoCal

and others.

13Natural Gas Pipeline Company of America, 71

FERC ¶ 61,391 (1995). Although Natural noted that

3.6 Bcf of contracts were due to terminate, its rates

reflected only 600,000 MMBTU of turn-back. See 73

FERC ¶ 61,050 (1995).

pipeline’s ability to profit from

withholding capacity by not building.

The Commission, therefore, is not

extending the proposal to remove the

price cap to the long-term market. The

Commission will retain cost-based

regulation in the long-term

transportation market to protect

shippers against the exercise of market

power by pipelines.

Rates must meet statutory

requirements and should, at the same

time, provide pipelines with the

appropriate incentives to provide

optimal transportation services. Ideally,

these rates should protect customers

from the long-term exercise of market

power by pipelines, provide the

appropriate incentives for new

construction, reasonably ensure the

financial viability of pipelines, and

provide an adequate incentive for

pipelines to operate efficiently. Costbased rates should be determined in an

administratively efficient manner and

should be current, predictable, fair, and

economically rational. The Commission

is evaluating whether its existing

pricing policies meet these goals. One

purpose of this NOI is to obtain public

comment on these objectives and the

adequacy of Commission policy in

achieving these objectives.

The need to re-examine the

Commission’s policies affecting longterm markets is even greater now as the

Commission proposes in the NOPR to

eliminate the price cap on pipeline

short-term firm and interruptible

transportation, and released capacity.

The continued availability of viable

regulated long-term recourse services

will be one of the primary tools for

mitigating the market power of capacity

sellers in the short-term markets. The

extent to which long-term services

mitigate the market power of capacity

sellers will depend on how well these

services meet the existing and future

needs of transportation customers, and

thus are worth being purchased as an

alternative to the short-term market.

Specifically, the Commission’s

current long-term pricing policies may

be deficient by failing sufficiently to

take into consideration long-term

factors, focusing instead on short-term

data such as test period results and the

need to recover each pipeline’s revenue

requirement from its existing customers

each year. This policy focuses on each

pipeline’s individual situation rather

than emphasizing the most efficient

pricing for the market as a whole.

Further, by failing to consider the

relationship of cost-of-service pricing to

the market value of pipeline services,

current regulatory policies often result

in pipelines with dramatically different

cost-of-service rates serving the same

markets. In addition, this pricing policy

assumes that as long as customers

eventually receive refunds, prices can

remain in effect for several years,

subject to refund, without adversely

affecting the customers or the market as

a whole. All these aspects of the

Commission’s cost-of-service regulatory

model may not reflect the realities and

needs of the industry today.

The Commission is interested in

exploring whether the current pricing

policy may have played a role in price

distortions in the California and Chicago

markets and, if it did, whether it could

lead to similar distortions in other

Midwestern and Eastern markets in the

near future. In the California market,

Transwestern Pipeline Company 11 and

El Paso Natural Gas Company (El

Paso) 12 faced significant turnback of

long-term firm capacity at the same time

that Mojave Pipeline Company, Kern

River Gas Transmission Co., and Pacific

Gas Transmission Company (PGT) were

constructing additional pipeline

capacity to serve the California market.

Because of the capacity turnback, El

Paso filed to increase its rates to fully

recover its annual revenue requirement

from its remaining customers. In

addition, El Paso argued for a higher

return on equity because its business

risks had increased. The Commission

accepted this increase, subject to refund.

While El Paso, Transwestern, and the

parties eventually worked out

settlements, the high subject-to-refund

rates remained in effect for a significant

period. Thus, while the parties avoided

the direct ramifications of the

Commission’s current pricing method,

i.e., the shifting of all unrecovered costs

to the captive customers, El Paso

charged high unreviewed rates pending

final resolution before the Commission.

PGT, on the other hand, was fully

contracted under long-term contracts.

Thus, under the Commission’s current

pricing method, PGT was able to have

relatively low rates while still

recovering its Commission-authorized

annual revenue requirement. Having

relatively low rates placed PGT in the

position of receiving requests for

additional service which it had to

refuse. PGT’s solution to this was to

expand its system to meet the additional

demand for service and roll-in the cost

of the expansion into its existing rates

to minimize the rate impact on its

expansion customers.

A similar sequence of events occurred

in the Chicago market with Natural Gas

Pipeline Company’s turn-back rate

filing 13 and the Northern Border

expansion. In both instances, the

Commission’s policies permitted

pipelines unable to retain sufficient

capacity reservations to increase rates to

captive customers, while permitting

fully-booked and low-priced pipelines

to build expensive expansion facilities

that had a higher unit average cost than

the average cost of the existing facilities

serving the market. The Commission is

seeking comments on whether its

policies contributed to these price

distortions, and, if so, whether and how

its policies should be modified to avoid

these types of price distortions in the

future.

As discussed more fully below, the

Commission is seeking comments on

whether a type of cost-based ratemaking

other than its traditional cost-of-service

method may be more appropriate in

today’s market. Specifically, the

Commission seeks comments on

whether index rates or incentive rates

may now be appropriate as the primary

rate-setting methodology. In addition,

the Commission seeks comments on

whether, if traditional cost-of-service

ratemaking is retained, modifications to

the traditional method would result in

improvements. For example, should

there be changes in the straight fixed

variable (SFV) rate design preference,

the discount adjustment policy, or rate

of return policies.

Pricing New Capacity. The

Commission is also reviewing its

policies for pricing of new capacity to

assure that they provide the proper

incentives for pipelines to build or not

build new capacity to meet increased

demand. The Commission seeks

comments on these issues as discussed

below. If price signals are correct, the

problem of overbuilding to attract

customers from other merchants may be

obviated.

I. Pricing Policies in the Existing LongTerm Market

As explained above, the Commission

intends to retain cost-based rate

regulation for long-term transportation.

The traditional cost-of-service rate

regulation currently used by the
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42977

14On the other hand, because pipelines are not

currently required to file rate cases on a regular

basis, they may already have adequate incentives to

cut costs. However, as discussed below, the

Commission is seeking comments on whether it

should require pipelines to undergo periodic rate

review under section 5 of the NGA. Also, in the

NOPR, the Commission is proposing to implement

periodic reviews of the rates, terms, and conditions

of recourse service rates to ensure that they remain

a viable alternative to negotiated terms and

conditions.

15FERC Stats. and Regs., Regulations Preambles,

January 1991-June 1996, ¶ 30,985 (1993).

16Statement of Policy and Request for Comments,

74 FERC ¶ 61,076 (1996), 61 FR 4633 (Feb. 7, 1996).

Commission is one type of cost-based

ratemaking methodology, but there are

other types of cost-based ratemaking,

such as index rates or incentive rates.

The Commission is reviewing its current

cost-of-service ratemaking methodology

to determine whether changes to that

methodology could result in better price

signals and contracts which would

strengthen the long-term market.

First, the Commission is considering

whether cost-based ratemaking options,

other than the traditional cost-of-service

model, would be more appropriate in

today’s market. As discussed below, the

Commission is considering several types

of index rates, that are based on factors

other than only the pipeline’s costs and

volumes, such as the supply and

demand characteristics of the market

being served. Second, the Commission

is considering whether, if traditional

cost-of-service regulation is retained,

modifications to the current

methodology would result in improved

rate regulation. Specifically, the

Commission is considering whether it

should reevaluate its preference for

SFV, whether it should change its

current discount adjustment policy,

whether it should adopt a policy that

shippers with long-term firm contracts

should be guaranteed fixed rates, and

whether the Commission should allow

pipelines to recover any of the costs

associated with unsubscribed capacity.

The Commission seeks comment on

the specific pricing options discussed

below, as well as other aspects of its

current rate policies not specifically

discussed here that commenters believe

may aid in the Commission’s

deliberations. In addition, the

Commission seeks comment on whether

the trend toward shorter-term contracts

is a natural consequence of competition

in natural gas markets, including state

retail unbundling programs, or whether

it is contributed to in part by the

Commission’s pricing policies. In

addition, the Commission seeks

comment on whether there is a

substantial basis for its concern that

movement away from long-term

contracting will have negative

consequences.

A. Other Cost-Based Options

1. Index Rates

Index rates may be more responsive to

changes in economic conditions, and

may provide incentives for pipelines to

cut costs and be efficient because they

will not have to share those benefits as

a result of a rate case.14 Index or

benchmark adjustments to effective

rates can avoid much of the regulatory

costs and delay involved in resolving

cost-of-service, throughput, and

capacity issues in a general rate case,

although they require data collection

and analysis to establish the index or

benchmark adjustment. Also, to the

extent that current conditions in the gas

industry result in a pipeline’s inability

to recover its cost-of-service,

establishing rates based upon an index

or benchmark may be of value. There

are a number of ratemaking

methodologies based upon an index.

In Order No. 561,15 the Commission

adopted an index method of ratemaking

for oil pipelines that uses the producer

price index for finished goods and an

industry cost-based efficiency

adjustment to modify existing just and

reasonable rates. The oil rule retains a

traditional cost-of-service option for

special circumstances. The Commission

requests comments on whether a similar

method for establishing index rates

could be used for gas transportation

rates, and whether any of the other

types of indexes discussed in Order No.

561 should be considered. Specifically,

the Commission seeks comments on

whether there are differences in the gas

industry that make use of such an index

to set gas pipeline rates inappropriate,

and whether it is significant that the

makeup of the entities holding capacity

on gas pipelines may be changing to

more closely resemble oil pipelines, i.e.,

more capacity held by pipeline

affiliates. Also, the Commission seeks

comments as to what rates should be

utilized from which index or benchmark

adjustments would be made.

Another possible index methodology

would be one based upon the existing

percent of the end-use price that

transportation represents in selected

competitive markets. Under this type of

methodology, once the transportation

percentage was determined, the

allowable transportation rate would

fluctuate with the end-use price in

competitive markets, but the percentage

itself rarely would be altered. Because

there are differing transportation costs

for pipelines in the same markets,

implementation of this method might be

difficult, and the Commission seeks

comments on the feasibility and benefits

of such a methodology.

Another index methodology would be

to establish a rate per 100 miles based

upon current construction costs. The

index would adjust rates to reflect

changes in the costs of construction.

One issue here is whether the index

should reflect the greatly varying costs

of old, largely depreciated pipelines and

new pipelines. Several separate rates

could be established for different

broadly-defined vintage categories. Such

an approach could be administratively

difficult, and could lead to widely

differing rates for pipelines in the same

geographic area, and again the

Commission seeks comments on the

feasibility and benefits of such an

approach. The Commission is also

interested in receiving other indexing

proposals.

2. Incentive and Performance Rates

The Commission has long had an

interest in performance-based and

incentive regulation. The Commission

invites comment on the adoption of

performance-based or incentive

regulation in light of the gas market

developments since implementation of

Order No. 636. Incentive rate proposals

are intended to result in better service

options at lower rates for consumers

while providing regulated companies

with the opportunity to a fair return.

Incentive regulation is not intended for

competitive markets. It is intended for

markets where the continued existence

of market power prevents the

Commission from implementing lighthanded regulation without harm to

consumers. The Commission continues

to believe that incentive rate

mechanisms have potential to benefit

both natural gas companies and

consumers by fostering an environment

where regulated companies that retain

market power can achieve greater

pricing efficiency and cost-effectiveness.

In the January 31, 1996 policy

statement,16 the Commission adopted

new criteria for evaluating incentive rate

proposals. Under this policy, incentive

proposals must explicitly state the

incentive performance standards, the

mechanism for sharing benefits with

customers, and a method for evaluating

performance under the proposal, as well

as state the specific term during which

the incentive program would operate.

Although no pipeline has proposed

incentive regulation since the

Commission modified the requirements

in the policy statement on alternatives

to cost-of-service regulation, the
42978 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

17 82 FERC ¶ 61,289 (1998). See also the

discussion in section II, infra.

Commission would like to reopen

discussion on whether these alternatives

might provide a more equitable sharing

of cost savings, enhanced incentives for

productive efficiency, or greater pricing

flexibility to respond to new

competitive realities.

At the outset, the Commission seeks

comment on whether a performancebased incentive program is appropriate

given the conditions of today’s natural

gas market, and why pipelines have not

proposed an incentive rates program?

Does the incentive rate program

outlined in the Policy Statement

provide an adequate frame work for

pipelines to propose incentive rates?

Should the Commission simply impose

incentive rates of its own design? Is the

current ability of pipelines to retain cost

savings by simply avoiding a Section 4

rate case an adequate incentive to cut

costs and innovate services? Does the

cost structure of interstate pipelines

lend itself to incentive/performance

regulation? Is state experience with

incentive/performance rates instructive

given the fundamental differences in the

cost structure of State regulated utilities

compared to interstate pipelines,

specifically the lack of purchased gas

costs for interstate pipelines?

Assuming incentive and performance

rates are appropriate, the Commission

seeks comment on whether maximum

rates should be based on individual

pipeline costs exclusively or whether, in

an era of growing competition, aggregate

industry-wide measures should also be

included. The Commission also seeks

comment on what performance-based

measures might be used to modify

pipeline rates of return and how the

rates of return should reflect

performance. Commenters should also

note whether any proposed

performance-based or incentive

regulation would require changes to

currently reported data or additional

market-monitoring requirements.

3. Financial Implications of Other CostBased Options

In considering the alternative

ratemaking methodologies discussed

above, the Commission is interested in

obtaining comments on the financial

impact these alternative methodologies

may have on the pipelines. One such

implication is the effect on regulatory

assets. A regulatory asset is established

when companies are provided with

assurances that it is probable that they

will be able to recover the deferred costs

through future rates. Normally, absent a

regulatory decision to allow out-ofperiod recovery of costs, the amounts

would have to be expensed in the

period incurred.

If some or all of the industry moves

away from setting rates on the basis of

jurisdictional pipelines specific costs,

accounting standards require companies

to eliminate from their financial

statements all assets recognized solely

due to the actions of regulators. Another

impact of departing from cost-of-service

ratemaking is that no more regulatory

assets and liabilities can be created.

Instead companies will have to include

in net income any expenses/losses

incurred and revenues/gains realized in

the periods in which they occur.

In light of the above, the Commission

seeks information on the following:

What difficulties will companies

encounter as a result of writing off

regulatory assets (i.e., difficulty in

paying out its dividends, obtaining new

financing, meeting bond coverage

requirements)? Can a rate transition

plan be devised that would avoid the

write-off? What impacts do companies

foresee of no longer being able to use

special regulatory accounting principles

(i.e., the anticipated write-offs of

regulatory assets and impairments

losses for fixed assets)? How will the

Commission’s proposals for the shortterm market affect pipelines’ return or

financial condition?

B. Market-Based Rates for Turnback

Capacity

Another approach to ratemaking

would be for the Commission to retain

cost-based ratemaking as the general

rule in long-term markets, but authorize

market-based rates in certain

circumstances, specifically, in the case

of turnback capacity. A concern raised

by the existence of turnback capacity is

how the costs of such capacity can be

recovered. One way of pricing turnback

capacity would be to establish a twostep process where the capacity would

be first offered for sale by the pipeline.

If the pipeline could not market the

capacity, the capacity could be deemed

excess to the market’s need and allowed

to be priced in the future using marketbased pricing principles.

The rationale would be that all

existing and potential customers would

first have an opportunity to acquire the

capacity at a Commission-established

cost-based rate, and further, that a

pipeline could not be deemed to have

market power over capacity that it

cannot sell. As part of this approach, the

pipeline would be denied the right to

raise the price of its remaining

contracted capacity to compensate it for

any potential cost underrecovery

associated with the capacity being

priced on a market basis. While initially

the capacity would be sold at a discount

rate, if at all, this approach would

provide pipelines with the opportunity

to recover some, or possibly all, of the

losses associated with the turnback

capacity because, when market

conditions changed and there was a

demand for the capacity, the pipeline

could continue to charge market-based

rates for the capacity.

The Commission seeks comments on

this proposal and suggestions for its

implementation. Specifically, the

Commission seeks comments on how

long a pipeline should be permitted to

charge market-based rates after a change

in market conditions. Should the

Commission reexamine the market

power issue after one contract term, or

after one or two years, or some other

period? The Commission also seeks

comments on the financial implications

of this ratemaking option, and whether

the financial implications are the same

as those discussed in the preceding

section.

C. Cost-of-Service Options

In the companion NOPR, the

Commission is proposing to remove the

price cap in the short-term market and,

therefore, there is the need to provide

mitigation of potential or actual market

power of capacity sellers. As explained

above, the Commission believes that the

best method of mitigation is to provide

Commission-regulated recourse rates to

all shippers who desire such rate

protection. The Commission is

reevaluating the adequacy of the

traditional cost-of-service ratemaking as

a means of providing such recourse

rates. Under the Commission’s

traditional cost-of-service ratemaking,

the pipeline’s rates are based on that

pipeline’s costs and the shippers’ usage

patterns. Thus, the level of each

pipeline’s rates is determined in part by

the pipeline’s costs, the timing of its

recovery, and the level of usage of the

pipeline. The Commission seeks

comments on whether its traditional

cost-of-service method continues to be

appropriate for natural gas

transportation services, and if so,

whether the modifications discussed

below, either individually or in

combination, could result in more

efficient and effective regulation.

One possible modification of the

current system would be to use the

highest available cost-based incremental

rate as the system Part 284 open access

rate for new customers. In PG&E, 17 the

Commission determined that when

turnback capacity, permanent capacity

release, and new expansion capacity

become available on a system with
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42979

18 In the NOPR, the Commission is proposing to

implement periodic reviews of the rates, terms, and

conditions of recourse service rates to ensure that

they remain a viable alternative to negotiated terms

and conditions. The review discussed here in this

NOI would be broader in nature, and the

Commission envisions that this review could

involve review of all the pipeline data relevant in

a section 4 rate case.

19Petition of the Public Service Commission of

the State of New York for Rulemaking Proceeding

Regarding Rate Design for Interstate Natural Gas

Pipelines, Docket No. RM98–11–000.

20Specifically, New York states that the SFV rate

design shields high cost pipelines from competition

from low-cost pipelines because it provides for the

collection of fixed costs through the demand charge

regardless of throughput. In addition, New York

states, as long-term contracts expire, the high

reservation charge under the SFV rate design may

reduce the marketability unsubscribed turnback

capacity. New York argues that permitting parties

to negotiate rates that deviate from SFV, while

requiring recourse rates to be based on SFV, creates

an unjustified rate disparity between customer

groups, and allows pipelines to exercise market

power over captive customers. Further, New York

asserts that a move away from SFV may reduce the

need for discounting, and would also discourage

inflated equity ratios. New York states that

Commission rate design policies should be

harmonized with state retail access initiatives, and

that it is concerned that SFV reservation charges

may discourage the entrance of new suppliers to the

retail markets.

incremental rates for similar services,

the pipeline and the releasor may price

the capacity at the incremental rate. In

the PG&E case, the rate for the

incremental facilities would ‘‘roll

down’’ over time as more shippers were

subject to the incremental rate. The

basis for this decision is that a price

found just and reasonable for one set of

customers is just and reasonable for all

subsequent customers receiving the

same service.

The Commission seeks comment on

whether the highest available cost-based

incremental rate should be used as the

system Part 284 open access rate for

new customers, consistent with the

rationale of PG&E. This policy would

encourage customers to negotiate longterm contracts to ensure that their rates

become ‘‘locked in’’ over the long term.

Comments should also consider the

revenue implications of such a policy.

In particular, should the higher revenue

from the new contracts at the

incremental rate be used to offset the

costs of unsubscribed capacity on other

parts of the system? Or, should the

pipeline be allowed to keep the high

revenues garnered from the new

contracts during the period between rate

case filings?

Another ratemaking option would be

to establish a maximum rate equal to the

pipeline’s cost-of-service divided by its

capacity, or some fraction thereof, for

example, 80 percent. This methodology

would have the advantages of protecting

captive customers from paying for

extensive discounts to other customers,

retaining an incentive for pipelines to

add customers, and eliminating rate

case gaming over throughput and billing

determinants. On the other hand, the

difficulties in establishing the cost-ofservice and the capacity of the pipeline

would still remain, and it may be very

difficult for some pipelines to recover

their costs under this methodology if the

capacity fraction is too high. The

Commission seeks comment on this

approach.

The Commission also seeks comment

on the role of periodic rate review in the

ratemaking process. The recourse rates

are a mitigation measure for the removal

of the price cap in the short-term

market, and the Commission is

concerned that the recourse rate could

become ‘‘stale’’ and not an adequate

alternative to short-term rates. Under

current Commission policy, the filing of

a rate case is at the discretion of the

pipeline. This policy allows the

pipelines to time the filing of a rate case

to coincide with a test period that

maximizes the benefits to the pipeline

of a rate increase filing. It can be argued

that the period between rate cases

represents an opportunity for pipelines

to collect what are, in effect, incentive

rates. The pipeline has the incentive to

cut costs and operate more efficiently as

well as to increase throughput over the

level on which the rates are based. If it

does so, it can reap the benefits of the

additional revenue without sharing it

with its customers. With pipelines no

longer required to come to the

Commission for a periodic rate review,

the period where a pipeline can operate

this way is at the option of the pipeline.

The Commission seeks comments on

whether it should require that pipelines

undergo periodic rate review under

section 5 of the NGA, and if so, how

such a requirement should be

implemented.18 Parties may comment

on whether Section 5 proceedings can

realistically be expected to operate as a

substitute for Section 4 proceedings,

and whether the collection of Form No.

2 or other data in such a way that the

Commission could quickly and

routinely identify large cost-of-service

and billing determinant discrepancies

would facilitate review.

The Commission also seeks comments

on whether it should reevaluate its

preference for a straight fixed variable

(SFV) rate design. Under SFV rates, all

the fixed costs of the pipeline service

are recovered in the reservation charge.

The usage charge recovers only the

variable costs. While SFV rates have

furthered the Commission’s goal of

achieving a national transportation grid,

SFV has had other effects that may have

contributed to the trend toward shortterm contracts and capacity turnback.

Shippers may be unwilling to sign longterm contracts when such contracts

require a commitment to pay large

reservation charges for a long period of

time. This reluctance may be greater in

this time of transition when LDCs are

unsure how retail unbundling will affect

their future capacity needs. Shippers

may be unsure whether they can recover

the majority of their costs in the release

market. Thus, SFV rates may encourage

some shippers to opt for short-term

contracts to cover only peak periods,

weakening long-term markets and thus

the mitigation power such long-term

markets are expected to provide to

recourse shippers. The Commission

seeks comments on how well SFV suits

the needs of the market and whether it

is unduly hampering the marketability

of long-term firm contracts.

On June 26, 1998, the Public Service

Commission of the State of New York

(New York) filed a petition 19 asking the

Commission to institute a rulemaking

proceeding to determine whether

changes in natural gas markets require

the Commission to revisit its preference

for the SFV rate design, and, if so, what

changes in Commission policy are

appropriate. New York advocates a shift

away from SFV, and asserts that such a

shift would promote development of a

competitive transportation market. New

York does not propose any particular

alternative to SFV, but recommends that

the Commission require pipelines to

employ a rate design that recovers some

or all of their fixed costs in the usage

component of the two-part rate. The

concerns raised by New York 20 are

similar to the issues raised by the

Commission’s discussion above. These

issues should be discussed by

commenters in this docket.

The Commission is also seeking

comments on whether it should change

its current discount adjustment policy.

The discount adjustment permits

pipelines to shift revenue recovery from

discounted transportation to customers

who do not receive discounts. The

Commission seeks comments on

whether discount adjustments unfairly

affect captive customers, and generally

create unnecessary rate uncertainty for

non-discounted customers. Parties may

address whether permitting discount

adjustments will be consistent with

negotiated rates and terms and

conditions; what would be a reasonable

limit on a pipeline’s ability to recover

discounts; whether an absolute

prohibition on recovering discounts

would be fair, workable, and efficient;

and what other types of rate
42980 Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules

21See e.g., Pacific Gas & Electric Co., 77 FERC ¶

61,204 at 61,794&n.5 (1996); Order No. 888, slip op.

at 271.

22See e.g., New England Power Pool, 83 FERC ¶

61,045, slip op. at 22–25 (1998).

23The Energy Information Agency (EIA) of the

Department of Energy projects an increase in gas

demand from 22.0 Tcf annually in 1996 to between

29.4 Tcf and 34.5 Tcf annually in 2020.

24See the discussion in the companion NOPR.

mechanisms could be substituted for the

current discount adjustment to improve

the current practice.

The Commission seeks comments on

other specific possible modifications to

its cost-of-service ratemaking, as well as

any other areas that could be

reexamined, including the affect of the

various options on a pipeline’s ability to

achieve a reasonable rate of return.

D. Other Pricing Issues

Several other aspects of the

Commission’s rate regulation in the

long-term market are under review

regardless of whether the Commission

adopts any of the options discussed

above. The Commission also seeks

comments on whether it should

consider changes in the policies

discussed below.

1. Fixed Rates for Firm Contracts

Currently, long-term firm contracts

usually do not equate to fixed rates, and

this tends to discourage long-term

contracting, weakening the long-term

market. Absent a fixed-rate contract,

firm shippers are offered long-term

commitments with price uncertainty.

Rates can increase during the term of

the contract due to increased costs,

including increases in the pipeline’s

operating costs, rate of return, or

diminished demand for capacity. Rates

can also increase if expensive new

capacity is rolled into the existing rate

base without sufficient increases in

throughput to offset the cost of the

facilities. Currently, with few

exceptions, shippers cannot reduce their

firm capacity holdings until their

contracts expire, even if the price

charged for that capacity increases

substantially.

The possibility that rates can increase

unpredictably during the contract term

creates risk. This undermines the value

of long-term contracts as a way to

mitigate future price risk and

discourages long-term contracts. While

pipelines are permitted to negotiate

customer-specific rates under the

Commission’s negotiated rate program,

it is unclear whether this program

provides workable rate certainty or

whether this opportunity is available on

all pipelines.

In the companion NOPR, the

Commission is proposing to allow

pipelines and shippers to negotiate

terms and conditions of service within

certain limits. The Commission requests

comments on whether this service

flexibility, coupled with existing

authority to negotiate rates addresses

this concern. Also, the Commission

seeks comments on whether the

Commission should adopt a policy that

with firm contracts shippers should

have fixed rates. Specifically, the

Commission is seeking comments on

what changes to the cost-of-service

should be reflected in rates for existing

firm contracts, i.e., whether changes in

physical plant, taxes, operations and

maintenance expenses, and related

items should be allowed to affect firm

contract rates. The Commission is also

seeking comments on whether, in the

alternative, this should be left as a

contracting matter between the pipeline

and its customers. The Commission is

also considering whether it should

allow existing pipelines that negotiate

fixed-rate, long-term contracts to shift

future cost increases to other customers,

and seeks comments on this issue as

well.

Another option would be to permit

shippers to reduce their firm capacity if

the pipeline increased the reservation

charge or, if the Commission moves

away from the SFV rate design, any part

of the rate. Comments should address

pipeline cost recovery issues as well as

the rate impact of these proposals.

2. Costs Associated with Unsubscribed

Capacity

Even if the Commission changes its

regulatory policies for short-term and

long-term transportation, there may be

cases where the rates will not recover

the embedded costs of the pipelines’

facilities. The Commission seeks

comments on whether it should allow

pipelines to recover some or all of these

costs, and if so, what approach to adopt.

As discussed above, one approach

would be to authorize market-based

rates for unsubscribed capacity. Another

method could be to follow the lead of

the electric industry and impose a nonbypassable access charge on

transportation customers.21 This charge

would be independent of the volumes

the shipper placed on the system or

grid. This could be applied on a systemby-system basis, or on a grid basis.

Another method would be to institute a

volumetric usage charge designed to

recover the fixed costs of the system.

This would be similar to ‘‘uplift

charges’’ as discussed in the electric ISO

filings. 22 A third possible method

would be to allow pipelines to bank

costs, such as depreciation expenses, for

future recovery. A fourth possible

method would be to permit pipelines to

design rates based on less than the total

pipeline capacity.

The comments should address these

options, and any others, as well as how,

as a practical matter, these methods

could be implemented. In addition, the

Commission is seeking comments on

whether capacity turnback is a

significant problem in long-term

transportation markets, and whether it

is likely to be a problem in the future,

particularly in light of some projections

for the growth of the gas market. 23

II. Pricing Policies for New Capacity

Some of the discussion above would

apply to new capacity as well as to

existing capacity. There are, however,

issues unique to the pricing of new

capacity, and new capacity presents an

opportunity for pipelines and customers

to balance appropriately the risks

associated with the cost of new

facilities. Problems resulting from

asymmetry of risk between shippers and

pipelines in the long-term

transportation market 24 that can lead to

a bias favoring short-term contracts can

be avoided with regard to new pipeline

capacity if the issue of allocation of risk

is resolved properly before the pipeline

is built. The best time to settle the

allocation of risk for the costs of new

capacity is before construction, and it is

crucial to allocate risk and potential

rewards at that time. Those who bear

the risks should stand to receive the

rewards for the risks taken.

A well-balanced policy could help

avoid creation of new capacity with

unbalanced risks and returns. A wellcoordinated certification and pricing

policy should also provide proper

incentives for pipelines to invest in new

facilities that are needed to meet

increased demand, and avoid problems

of excess capacity that may be caused by

construction of facilities to compete for

existing market share. In addition,

pricing and certification policies should

provide incentives to producers so that

sufficient quantities of gas will be

produced, and to consumers of gas, so

that the choice of gas is an economically

viable option. The proper incentives to

all the parties in the gas market will

benefit the market as a whole. For these

reasons, the Commission seeks

comments on certain issues specifically

related to the pricing of new capacity.

A. Risk Allocation

The Commission is seeking comments

on whether and how to encourage

pipelines and customers to negotiate

pre-construction risk and return-sharing
Federal Register / Vol. 63, No. 154 /Tuesday, August 11, 1998 / Proposed Rules 42981

25 71 FERC ¶ 61,241 (May 31, 1995).

26 In the discussion of New Capacity Certification

Issues above, the Commission has raised the

question of whether this policy should apply where

the facility is constructed to serve an affiliate.

27PG&E Transmission, 82 FERC ¶ 61,289 (1998).

28See e.g., Memphis Light, Gas and Water

Division v. FPC, 504 F.2d 225 (D.C. Cir. 1974).

29Tennessee Gas Pipeline Company, et al., 55

FERC ¶ 61,484 (1991), approving depreciation rate

based on the length of the contract with the

shippers for whom the facilities were constructed.

30Of course, as noted above, the depreciation rate

may be reviewed and changed in subsequent rate

cases.

agreements. Customers could commit to

life-of-the-facilities contracts, fairly

short-term contracts, or anything in

between. Short-term contracts involve

greater risks for the pipeline as to total

cost recovery of the new facilities, and

this should be reflected in the parties’

contract. Pre-construction negotiations

and resulting contracts should

appropriately and specifically balance

risks and return regarding such matters

as what price should be paid for early

contract termination and cost collection

if the term of the contract is less than

the life of the facilities.

However, if pipelines and customers

do not agree on the allocation of risk

and return, the Commission seeks

comments on whether it should decide

the issue before construction, and not

change the risk allocation in later rate

cases unless extraordinary

circumstances exist, or not approve the

construction. Specifically, the

Commission seeks comments on what

action, if any, the Commission should

take to ensure rate and contract

certainty for customers and pipelines.

Should this include guarantees against

future rolling-in of costly expansions,

future changes in O&M expenses, or any

other future changes? The Commission

is also seeking comments on the

advantages (or disadvantages) of

allowing pipelines and customers to

negotiate pre-construction risk and

return-sharing agreements.

B. Rate Treatment for New Capacity

The Commission’s pricing policy,

Pricing Policy For New and Existing

Facilities Constructed by Interstate

Natural Gas Pipelines (Pricing Policy

Statement), 25 is intended to minimize

pre-construction risk by providing

pipelines and their customers with as

much up-front assurance as possible

about how new capacity will be priced

so they can make informed decisions

about the amount of capacity to build

and to buy. In the Pricing Policy

Statement, the Commission adopted a

presumption in favor of rolled-in rates

when the rate increase to existing

customers from rolling-in the new

facilities is 5 percent or less and the

pipeline makes a showing of system

benefits. 26

In PG&E Transmission, Northwest

Corporation (PG&E), 27 the Commission

announced a new policy for rate

treatment of permanently released

capacity, and new expansion capacity.

Prior to the PG&E order, each of these

types of capacity was subject to different

pricing policies. Turnback capacity was

usually priced at the system Part 284

rate. Release capacity was priced at the

maximum stated rate for the released

service. New expansion capacity was

priced pursuant to the Pricing Policy

Statement, either rolled-in or

incremental depending on a variety of

factors, including the 5 percent impact

test. However, in PG&E, the

Commission determined that when

permanently released capacity, and new

expansion capacity become available on

a system with incremental rates for

similar services, the pipeline and

releasor may price the capacity at the

incremental rate. The rationale of that

decision can also apply to turned back

capacity.

This policy has significant

implications for long-term pricing. First,

PG&E has created a uniform pricing

approach for unsubscribed and

unwanted capacity. Second, the pricing

level chosen by the Commission is a

form of replacement cost, or incremental

cost pricing. This approach effectively

limits the pricing differences between

generations of customers to the term of

their contracts. The rates for new

capacity and services establish the

higher rate; over a period of time, the

system rate effectively rolls into and

decreases the higher rate. Older

services’ rates are stabilized to reflect

the deals that were struck at the time.

As the contracts gradually expire and

the lower cost pre-expansion capacity is

included in the new system (formerly

incremental) rate, that rate will decline,

eventually becoming the rolled-in rate if

no other expansions occur.

The Commission also seeks comments

on the interrelationship of its at-risk

policy and the PG&E policy. Although

the PG&E policy provides clear market

benefits, it may raise other issues with

respect to incrementally-priced, at-risk

pipelines. By permitting pipelines to

charge new or renewing shippers on

existing pipeline facilities the higher

incremental rate, it could be argued that

the pipelines are being permitted to

place some of the economic risks of the

new facilities onto those new or

renewing shippers. In other words, if

the new incrementally-priced facilities

are underutilized, the pipeline would be

permitted to mitigate its unrecovered

costs through the rates charged to the

new or renewing shippers on the

existing pipeline.

On the other hand, there are benefits

to the PG&E policy. One benefit is that

it creates a strong incentive for

customers to sign long-term contracts.

Only through long-term contracts could

customers be assured of locking-in the

pricing associated with a given vintage

of pipeline capacity. Once their

contracts expire, customers would need

to reacquire capacity at a potentially

newer and higher priced vintage. The

Commission seeks comments on

whether the Commission’s PG&E policy

should be applied to at-risk pipelines.

C. The Effects of Depreciation on LongTerm Pricing

An appropriate depreciation rate for

new facilities is established as part of

the initial rate in a certificate case, and

is, therefore, generally an issue related

to new capacity, although a depreciation

rate may be reviewed and changed in a

later rate case.

In the past, within the context of a

highly regulated environment, the

Commission based the utility assets’

economic depreciable life on the

physical life of the asset, and

recommended the straight line method

of depreciation for allocating the assets’

costs to periods benefitted. As changes

in the industry occurred, it was evident

that other factors, such as obsolescence

due to new processes and techniques,

environmental constraints, and

competing markets were driving the

determination of the economic

depreciable life of pipeline facilities,

and the Commission based the

depreciable life on the useful life of the

asset.28 More recently, in initial rate

cases for newly constructed facilities,

the Commission has tended to equate

economic life to the terms of the

pipelines’ long-term transportation

contracts in setting depreciation rates

for initial rates in the certificate

process.29 In this scenario, the life of the

new facility is established by the

contract term so that the new plant

would be fully depreciated by the end

of the contract.30 This method, however,

is not used in section 4 rate cases.

The physical lives of pipeline

facilities can be over 40 years, and the

economic lives as approved by the

Commission in individual cases have

generally been at least 20–25 years.

However, current contracted terms may

be as short as 10 years. Where the

depreciation rate is based on contract

term, initial customers ultimately pay

the entire asset’s costs in higher rates

over a shorter period of time, even
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.