[Federal Register Volume 63, Number 154 (Tuesday, August 11, 1998)]
[Proposed Rules]
[Pages 42974-42982]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-20996]



[[Page 42973]]

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Part IV





Department of Energy





_______________________________________________________________________



Federal Energy Regulatory Commission



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18 CFR Ch. I and Parts 161, 250, 284



Regulation of Interstate and Short-Term Natural Gas Transportation 
Services; Proposed Rules

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

[[Page 42974]]



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.

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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 
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 [email protected].
    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 [email protected].
    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.
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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

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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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \24\ See the discussion in the companion NOPR.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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

    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