Regulation of Interstate Natural Gas Transportation Services

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 long-term 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

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at 888 First Street, NE, Room 2A, Washington, DC 20426.

The Commission Issuance Posting System (CIPS) provides access to

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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.

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\1\ As 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.

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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 well-suited

to today's more competitive markets.

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\2\ Wellhead Decontrol Act, Pub. L. 101-60, 103 Stat. 157

(1989).

\3\ Pipeline 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 para. 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 para. 30,950

(August 3, 1992); order on reh'g, Order No. 636-B, 57 FR 57,911

(December 8, 1992), 61 FERC para. 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).

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

Associates, North American Natural Gas Trends, at pp. 3, 8, 10, 51.

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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 short-term 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

[[Page 42975]]

market power over some customers in the long-term transportation

market.5

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\5\ See Alternatives to Traditional Cost-of-Service Ratemaking

for Natural Gas Pipelines, 70 FERC para. 61,139 (1995), 60 FR 8356

(February 14, 1995).

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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.

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\6\ See e.g., Order No. 636-C, 78 FERC para. 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 shorter-

term 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.

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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.

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\7\ See ``Future Unsubscribed Capacity,'' AGA LDC Caucus,

December 1995, p.1.

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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

short-term 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.

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\8\ See e.g., El Paso Pipeline Company, 72 FERC para. 61,083

(1995); Natural Gas Pipeline Company of America, 71 FERC para.

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.

\9\ The 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.

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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.

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\10\ E.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.'')

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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 long-term transportation capacity, and without

cost-based regulation for long-term 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

[[Page 42976]]

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. Cost-based 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 long-

term 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.

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\11\ Transwestern Pipeline Company, 72 FERC para. 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.

\12\ El Paso Natural Gas Company, 72 FERC para. 61,083 (1995).

El Paso faced a total turnback of approximately 1,300,000 MMcf from

PG&E, SoCal and others.

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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.

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\13\ Natural Gas Pipeline Company of America, 71 FERC para.

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 para. 61,050 (1995).

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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 Long-Term 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

[[Page 42977]]

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.

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\14\ On 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.

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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.

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\15\ FERC Stats. and Regs., Regulations Preambles, January 1991-

June 1996, para. 30,985 (1993).

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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

light-handed 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.

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\16\ Statement of Policy and Request for Comments, 74 FERC para.

61,076 (1996), 61 FR 4633 (Feb. 7, 1996).

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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

[[Page 42978]]

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

performance-based 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 Cost-Based 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-of-period 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 short-term

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

two-step 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 market-based 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

[[Page 42979]]

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.

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\17\ 82 FERC para. 61,289 (1998). See also the discussion in

section II, infra.

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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 long-term 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-of-service 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.

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\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.

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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 short-term contracts and

capacity turnback. Shippers may be unwilling to sign long-term

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.

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\19\ Petition 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.

\20\ Specifically, 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.

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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

[[Page 42980]]

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 non-bypassable 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 system-by-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.

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\21\ See e.g., Pacific Gas & Electric Co., 77 FERC para. 61,204

at 61,794&n.5 (1996); Order No. 888, slip op. at 271.

\22\ See e.g., New England Power Pool, 83 FERC para. 61,045,

slip op. at 22-25 (1998).

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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\

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\23\ The 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.

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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.

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\24\ See the discussion in the companion NOPR.

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A well-balanced policy could help avoid creation of new capacity

with unbalanced risks and returns. A well-coordinated 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

[[Page 42981]]

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\

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\25\ 71 FERC para. 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.

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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.

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

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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 Long-Term 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.

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\28\ See e.g., Memphis Light, Gas and Water Division v. FPC, 504

F.2d 225 (D.C. Cir. 1974).

\29\ Tennessee Gas Pipeline Company, et al., 55 FERC para.

61,484 (1991), approving depreciation rate based on the length of

the contract with the shippers for whom the facilities were

constructed.

\30\ Of course, as noted above, the depreciation rate may be

reviewed and changed in subsequent rate cases.

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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

[[Page 42982]]

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?

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\31\ See 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).

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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 E-Mail to

[email protected] 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 E-Mail to acknowledge receipt. Questions or comments on electronic

filing using Internet E-Mail should be directed to Marvin Rosenberg at

202-208-1283, E-Mail address [email protected].

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