[Federal Register Volume 63, Number 154 (Tuesday, August 11, 1998)]
[Proposed Rules]
[Pages 42982-43023]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-20998]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 161, 250, and 284
[Docket No. RM98-10-000]
Regulation of Short-Term Natural Gas Transportation Services
July 29, 1998.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
proposing an integrated package of revisions to its regulations
governing interstate natural gas pipelines to reflect the changes in
the market for short-term transportation services on pipelines. Under
the proposed approach, cost-based regulation would be eliminated for
short-term transportation and replaced by regulatory policies intended
to maximize competition in the short-term transportation market,
mitigate the ability of firms to exercise residual monopoly power, and
provide opportunities for greater flexibility in the provision of
pipeline services. The proposed changes include initiatives to revise
pipeline scheduling procedures, receipt and delivery point policies,
and penalty policies, to require pipelines to auction short-term
capacity, to improve the Commission's reporting requirements, to permit
pipelines to negotiate rates and terms of services, and to revise
certain rate and certificate policies that affect competition.
DATES: Comments are due November 9, 1998.
[[Page 42983]]
ADDRESSES: Federal Energy Regulatory Commission, 888 First Street, NE,
Washington DC, 20426.
FOR FURTHER INFORMATION CONTACT:
Michael Goldenberg, Office of the General Counsel, Federal Energy
Regulatory Commission, 888 First Street, NE, Washington, DC 20426.
(202) 208-2294
Erica Yanoff, Office of the General Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426. (202) 208-0708
Ingrid Olson, Office of the General Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426. (202) 208-2015.
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission also provides all
interested persons an opportunity to inspect or copy the contents of
this document during normal business hours in the Public Reference Room
at 888 First Street, NE, Room 2A, Washington, DC 20426.
The Commission Issuance Posting System (CIPS) provides access to
the texts of formal documents issued by the Commission. CIPS can be
accessed via Internet through FERC's Homepage (http://www.ferc.fed.us)
using the CIPS Link or the Energy Information Online icon. The full
text of this document will be available on CIPS in ASCII and
WordPerfect 6.1 format. CIPS is also available through the Commission's
electronic bulletin board service at no charge to the user and may be
accessed using a personal computer with a modem by dialing 202-208-
1397, if dialing locally, or 1-800-856-3920, if dialing long distance.
To access CIPS, set your communications software to 19200, 14400,
12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex, no parity, 8
data bits and 1 stop bit. User assistance is available at 202-208-2474
or by E-mail to [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.
Table of Contents
I. Reexamination of the Transportation Market
A. The Developing Short-term Market
B. Implications for Commission Regulatory Policies of the
Changing Nature of Short-term Markets
II. Proposed Change in Regulatory Approach
A. A Different Model for Regulating the Short-term Market
B. Legal Basis for the Proposed Regulatory Change
C. Interrelated Proposals for Regulatory Change
III. Creating Greater Competition Among Short-term Service
Offerings
A. Nomination Equality
B. Segmentation and Flexibility of Receipt and Delivery Points
C. Capacity Auctions
D. Information Reporting and Remedies for the Exercise of
Market Power
IV. Penalties and Operational Flow Orders
A. Pipelines Should Provide, on a Timely Basis, as Much
Imbalance and Overrun Information as Possible
B. Transportation Penalties Must Be Necessary and Appropriate
to Protect System Operations
C. Pipelines Must Provide Services, to the Extent Operationally
Feasible, That Facilitate Imbalance Management
D. Pipelines Must Adopt Incentives and Procedures That Minimize
the Use and Adverse Impact of OFOs
V. Negotiated Rates and Services
A. Guiding Principles
B. Implementation of the Negotiated Rates and Services Policy
VI. Long-term Services
A. The Interaction Between Long-term and Short-term Services
B. Specific Impediments to Long-term Contracts
C. New Capacity Certificate Issues
VII. Reorganization of Part 284 Regulations
VIII. Information Collection Statement
IX. Environmental Analysis
X. Regulatory Flexibility Act Certification
XI. Comment Procedures
Notice of Proposed Rulemaking
Five years have passed since Congress, in the Wellhead Decontrol
Act, completed the decontrol of natural gas prices. Six years ago the
Commission, in Order No. 636, unbundled the purchase of gas from the
purchase of gas transportation. Since then, the natural gas market has
changed from a largely regulated market to one increasingly driven by
market forces. In order to continue to fulfill its statutory duties to
ensure just and reasonable rates in the rapidly evolving gas market of
today, the Commission has engaged in a comprehensive, critical
examination of the regulatory assumptions and procedures that it has
been using to determine whether other regulatory approaches would
better fit the needs of this changing marketplace.
Since Order No. 636, the natural gas marketplace has fundamentally
changed. Active short-term markets have begun to develop. Shippers are
trading gas at market centers on a daily or sometimes an intra-day
basis with prices varying from day-to-day. Prior to Order No. 636, the
majority of contracts were long-term with less price volatility. As
local distribution companies (LDCs) unbundle the gas commodity from
transportation, new players, such as electric cogenerators, industrial
end-users, and small businesses (such as restaurants) are entering the
gas marketplace with gas and transportation needs different from those
of the LDCs that previously transported and sold the majority of gas.
Increasingly, LDC unbundling is even bringing homeowners into the gas
marketplace. These new entrants often use marketers or other
facilitators to arrange for their gas supplies on a delivered basis.
The use of transportation capacity also has changed. Before Order
No. 636, shippers could acquire transportation only from the pipeline.
They could buy gas from the pipeline at the city-gate either on a
short-term or long-term basis, acquire long-term firm capacity from the
pipelines, often with 20-year contracts, or purchase short-term
interruptible capacity. In today's market, shippers have additional
options. They can acquire capacity from other firm capacity holders
through the capacity release market. They also can obtain capacity
indirectly by purchasing gas bundled with transportation from
producers, marketers, or aggregators for one delivered price (often
called a gray market sale).
The changes in the short-term market have caused the Commission to
closely examine its regulatory structure to see whether it provides a
good fit with the developing short-term market. The Commission has
received comments on the impact of these changes through a number of
proceedings, among them a prior Notice of Proposed Rulemaking (NOPR) on
the secondary market,\1\ a request for comments on whether pipelines
should be permitted to
[[Page 42984]]
negotiate terms of service,\2\ and an industry conference on issues and
priorities in the gas industry.\3\
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\1\ Secondary Market Transactions on Interstate Natural Gas
Pipelines, Notice of Proposed Rulemaking, 61 FR 41046 (Aug. 7,
1996), IV FERC Stats. & Regs. Proposed Regulations para. 32,520
(Jul. 31, 1996).
\2\ Alternatives to Traditional Cost-of-Service Ratemaking for
Natural Gas Pipelines, and Regulation of Negotiated Transportation
Services of Natural Gas Pipelines, 61 FR 4633 (Feb. 7, 1996), 74
FERC para. 61,076, at 61,242 (1996).
\3\ Issues and Priorities for the Natural Gas Industry, PL97-1-
000 (conference held May 29-30, 1997).
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Upon review of the changes in the market and the comments it has
received, the Commission is concerned that its current regulatory
approach, which relies on a constant maximum rate in the short-term
market, may not be the best approach in light of the variability in
pricing in the short-term market. Due to the variability in
transportation value, the current approach may not provide the best
protection against the exercise of market power during peak and off-
peak periods. Or, the protection it does provide may come at the
expense of a more efficient capacity market during peak periods, when
shippers are most in need of a market that works efficiently.
The Commission recognizes that despite all the competitive
improvements in the short-term market, the short-term market still may
not be fully competitive. Thus, the Commission must continue to have a
regulatory presence in the short-term market to protect against the
exercise of market power and undue discrimination.
The Commission is, therefore, proposing in this NOPR a different
approach for regulating the short-term transportation market which is
designed to permit the market to function efficiently while continuing
to protect shippers against the exercise of market power. This approach
has a number of objectives. It is designed to improve competition in
short-term markets by facilitating the trading of capacity, so that
shippers will have a larger number of capacity alternatives from which
to choose. By expanding options, it seeks to help reduce the number of
captive customers. Additionally, it seeks to provide the opportunity
for greater flexibility in pipeline contracting practices so that
pipelines can design services that better meet the needs of existing
and new players in the gas marketplace.
The proposal uses different regulatory structures for short-term
and long-term markets. Long-term transportation prices (i.e.,
transportation of one-year or longer) would continue to be regulated
under a cost-based regulatory regime to protect against the exercise of
pipeline monopoly power. For short-term transportation services,
however, cost-based regulation would be eliminated. In its place, the
Commission proposes to regulate the short-term market through
regulatory policies that are intended to maximize competition in the
short-term transportation market, to mitigate the ability of firms to
exercise residual monopoly power, and to improve the ability of market
participants and the Commission to monitor the market for exercises of
monopoly power or undue discrimination. The goal of this approach to
the short-term market is to ensure that the Commission's regulatory
policy does not inhibit competitive market forces from creating
efficient capacity markets, while still providing captive customers and
others with protection against the exercise of market power in the
transportation market.
Specifically, to maximize competition (which is the best protection
against the exercise of market power) the Commission is proposing in
this NOPR to revise pipeline nomination and scheduling procedures, and
flexible receipt and delivery point policies so that capacity release
can compete on a more equal footing with pipeline capacity. To further
mitigate the exercise of market power and the potential for undue
discrimination, the Commission is proposing to require that all short-
term capacity be sold through capacity auctions. To improve shippers'
and the Commission's ability to monitor the marketplace the Commission
is proposing changes to its reporting requirements. To improve
competition across the pipeline grid, the Commission is making
proposals to change pipeline penalty procedures so that penalties,
although necessary to deter conduct inimical to system operations, do
not unnecessarily limit shippers' competitive alternatives.
At the same time, the Commission recognizes that changes in the
short-term market also influence shippers' decisions in the long-term
market. For example, the value of long-term capacity lies in the
guarantee of capacity at a relatively stable price as compared with
buying capacity at the more volatile short-term price. Long-term
contracts, therefore, are a means by which shippers and pipelines can
manage the risks inherent in the short-term market.
To foster greater innovation in pipeline services and to permit
pipelines and shippers to better allocate the risks of long-term
contracts, the Commission is proposing to allow pipelines' greater
flexibility in negotiating contracts with individual shippers, subject
to criteria that will protect captive customers against the risk of
undue discrimination. Further, to create a more efficient marketplace,
regulatory policies should not affect the allocation of risk between
acquiring short-term or long-term capacity. As part of this integrated
package, therefore, the Commission is proposing changes to some of its
policies governing long-term contracts to ensure that these policies do
not unfairly bias shippers' contracting decisions. The Commission also
is considering whether changes to its policies regarding authorization
for new construction are needed so that these policies do not
unnecessarily limit competition.
The Commission recognizes that the impact on the long-term market
of the changes in the short-term market go beyond the proposals
outlined above. Therefore, in a Notice of Inquiry (NOI) issued
contemporaneously with this NOPR, the Commission asks for additional
comment on the future direction of its policies for pricing of long-
term capacity.
I. Reexamination of the Transportation Market
A. The Developing Short-term Market
Natural gas markets have developed rapidly since wellhead price
deregulation and unbundling of pipeline merchant and transportation
services. In many ways, the gas market performs very well, without the
loss of reliability that many feared when Order No. 636 was being
contemplated.\4\
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\4\ See Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation Under Part
284 and Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, Order No. 636, 57 FR 13267, FERC Stats. & Regs.
Regulations Preambles [Jan. 1991-June 1996] para. 30,939, at 30,408
(Apr. 8, 1992), Order No. 636-A, 57 FR 36128 (Aug. 12, 1992), FERC
Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] para.
30,950, at 30,570 (Aug. 3, 1992) (concerns about providing
transportation service equal in reliability to bundled sales
service).
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Gas commodity markets have arisen, along with market mechanisms to
enable consumers to manage price risk for the gas.\5\ There are monthly
and growing daily spot markets for gas supplies which enable shippers
not only to buy their own gas supplies at the wellhead, but to trade
gas among themselves on a daily or even more frequent basis. Many of
these spot markets are organized around market centers that facilitate
trading of gas across pipelines as well as providing a variety of new
services, such as storage, wheeling, parking, lending, electronic gas
trading, and tracking of gas title
[[Page 42985]]
transfers.\6\ Active forward markets also have developed to enable gas
consumers to hedge against price risk. The New York Mercantile Exchange
(NYMEX) launched its natural gas futures contract in 1992, and it is
very heavily traded.
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\5\ See S. Walsh, A Hot (and Cold) New Investment Opportunity,
Washington Post, July 4, 1998, C12 (Business) (discussing
development of new weather derivative to enable companies to hedge
against abnormal weather patterns).
\6\ Department of Energy/Energy Information Administration, Pub.
No. DOE/EIA-0560(96), Natural Gas 1996 Issues and Trends, Chapter,
The Emergence of Natural Gas Market Centers (1996).
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Along with the development of a more liquid commodity market,
shippers' transportation options have expanded. In the past, shippers
could purchase capacity only from the pipeline and had, for the most
part, only two transportation choices: long-term firm capacity or
interruptible service. Pipeline offerings have expanded as well, with
pipelines offering short-term firm transportation service, pooling,\7\
hub services,\8\ parking and loan services,\9\ and both short-term and
long-term storage services.\10\
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\7\ See Standards For Business Practices Of Interstate Natural
Gas Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC
Stats. & Regs. Regulations Preambles para. 31,038 (Jul. 17, 1996)
(requiring pipelines to provide pooling services).
\8\ See Moss Bluff Hub Partners, 80 FERC para. 61,181 (1997)
(firm storage and interruptible hub services); Egan Hub Partners,
L.P., 77 FERC para. 61,016 (1996) firm storage and interruptible hub
services).
\9\ See Mojave Pipeline Company, 79 FERC para. 61,347 (1997);
Colorado Interstate Gas Company, 83 FERC para. 61,273 (1998).
\10\ See Koch Gateway Pipeline Company, 66 FERC para. 61,385
(1994) (firm and interruptible storage); New York State Electric Gas
Corporation, 81 FERC para. 61,020 (1997) (issuing certificate).
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Non-traditional players also have entered the capacity market, so
that today firm shippers holding pipeline capacity include electric
utilities (21% of total pipeline firm capacity), industrial end-users
(5%), marketers (17%), pipelines (7%), and others, including producers
(6%) in addition to the traditional LDCs (44%). While many of these
shippers still hold pipeline contracts longer than a year, short-term
firm contracts are rising in significance. Among the shipper groups,
marketers are the largest users of short-term capacity, with over
three-quarters of the total.\11\
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\11\ Department of Energy/Energy Information Administration,
Pub. No. DOE/EIA-0618(98), Deliverability on the Interstate Natural
Gas Pipeline System 88-89 (1998).
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In today's market, shippers also have the added option of buying
firm capacity released by other shippers in a variety of ways (such as
on a fixed, or volumetric basis, or with other release conditions,
including provisions for handling capacity recalls). Since its
inception in 1992, capacity release transactions have been growing
dramatically.\12\ For instance, the amount of capacity held by
replacement shippers for the 12 month period ending March 1997, totaled
7.4 quadrillion Btu, a 22% percent increase over the previous 12 month
period and almost double the level for the 12 months ending March
1995.\13\ While the amount of capacity held by replacement shippers
declined during the heating season, EIA reports it still represents a
sizable amount.\14\ Despite the growing use of released capacity,
interruptible pipeline service also continues to be a viable service
option, maintaining a relatively constant share of throughput.\15\ As
in the case of released capacity, EIA reports that interruptible
service is available during the heating season.\16\
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\12\ Id. at 82 (representing about 16% of the gas delivered for
market).
\13\ Id. at 83.
\14\ Id. at 85-86 (2,960 trillion Btu from November to March
1996-97).
\15\ Id. at 85 (about 16% of total throughput for the 12 months
ending March 31, 1997).
\16\ Id. at 87 (2,000 TBtu moved during heating season).
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In addition to acquiring capacity from pipelines and releasing
shippers, purchasers in the short-term market have other capacity
options. Implicit in the Commission's decision to unbundle the gas
commodity from transportation was a recognition that the market would
develop so that customers who did not want to assume the responsibility
of purchasing or transporting their own gas could purchase delivered
gas from marketers or third parties with the marketer providing all or
a portion of the needed transportation, for example to a nearby market
center.\17\ Capacity rights holders can now sell gas as a commodity in
downstream markets at market-based prices.
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\17\ See Order No. 636, FERC Stats. & Regs. Regulations
Preambles [Jan. 1991-June 1996] para. 30,939, at 30,410.
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Further, as a result of Commission initiatives, the gas industry,
through the Gas Industry Standards Board (GISB), has developed
standards that make it easier to move and trade gas on individual
pipeline systems and across pipeline systems.\18\ These standards
establish a daily, along with an intra-day, nomination schedule which
permit shippers to adjust their nominations to conform to changes in
weather and other circumstances. The Commission recently adopted GISB
standards providing for three intra-day nomination opportunities.\19\
These standards also significantly enhance shipper flexibility, for
example, by giving shippers the ability to aggregate gas supplies from
numerous sources in a pipeline pool for nomination purposes and by
allowing shippers to assign priority rankings to gas packages.
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\18\ Standards For Business Practices Of Interstate Natural Gas
Pipelines, Order No. 587, 61 FR 39053 (Jul. 26, 1996), III FERC
Stats. & Regs. Regulations Preambles para. 31,038 (Jul. 17, 1996),
Order No. 587-B, 62 FR 5521 (Feb. 6, 1997), III FERC Stats. & Regs.
Regulations Preambles para. 31,046 (Jan. 30, 1997), Order No. 587-C,
62 FR 10684 (Mar. 10, 1997), III FERC Stats. & Regs. Regulations
Preambles para. 31,050 (Mar. 4, 1997), Order No. 587-G, 63 FR 20072
(Apr. 23, 1998), III FERC Stats. & Regs. Regulations Preambles para.
31,062 (Apr. 16, 1998).
\19\ Standards For Business Practices Of Interstate Natural Gas
Pipelines, Order No. 587-H, 63 FR 39509 (Jul. 23, 1998), 84 FERC
para. 61,031 (July 15, 1998).
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These changes, operating together, have changed the character of
short-term markets. Five years ago, most gas was purchased during bid
week under monthly contracts and transportation was arranged at the
same time on a monthly basis. Transactions occurring outside of bid
week were unusual and were referred to as the aftermarket. Today, daily
markets for gas and capacity are developing rapidly. Shippers now trade
gas on a daily or even an intra-day basis at various market centers and
pipeline interconnect points or at pipeline pooling points. For
example, at pipeline interconnect points or at pools, there may be
repeated sales of the same gas between producers and marketers before
the gas is scheduled for transportation. As described in a recent
proceeding, shippers can use pooling to effectuate gas exchanges (pool
to pool transfers) as a means of enhancing supply and pricing options
and of market hedging.\20\ For example, a shipper may buy gas from a
pool as insurance against a change in its system requirements and then
sell that gas to another pool if the load does not develop in its
market.
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\20\ El Paso Natural Gas Company, 81 FERC para. 61,174, at
61,760 (1997) (approving a limit on pool to pool transfers because
pipeline could not handle the volume of transactions under new
scheduling timeline).
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Shippers also can take advantage of trading opportunities by making
daily or intra-day changes to their gas nominations to react quickly to
changing weather, changing prices or supply sources, or other
circumstances. For instance, a shipper that loses a supply source can
submit an intra-day nomination to change its receipt point for gas so
that it can purchase gas from an alternate supply source. The reports
in trade publications of daily gas prices at delivered markets are
further evidence of the increasing scope of the developing short-term
market.\21\
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\21\ See, e.g., Gas Daily, March 2, 1998, at 1-2; Natural Gas
Intelligence, Jan. 5, 1998, at 4; Natural Gas Week, Jan. 12, 1998,
at 12, 17, 20-21.
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The developing gas market, however, is in some respects still in
its infancy and there are still impediments, both regulatory and non-
regulatory, to the
[[Page 42986]]
development of a well-functioning market. Price information, which is
crucial to a well-developed market, could be improved. While the
Commission requires the posting of information on capacity release
transactions, posting of pipeline discount transactions occurs well
after-the-fact and cannot be used by shippers to make daily market
decisions. Moreover, it is difficult for shippers to obtain accurate
information about delivered gas transactions or the value of
transportation inherent in such transactions. Shippers are left to
personal communication or trade publications to determine prices at
receipt and delivery points. Acquiring market information through
personal communication is time consuming and expensive, particularly
for small customers who would have difficulty canvassing a large enough
number of sources to obtain sufficient market information. Each trade
publication uses different reporting methods. Some mix long and short-
term transactions and some report price ranges while others report
averages, and most do not report quantities traded.
Also, capacity markets are fragmented. Different regulatory rules
apply to pipeline sales of interruptible and firm capacity, capacity
obtained through release transactions, and capacity used as part of
delivered gas transactions. For example, the nomination and scheduling
procedures and rate regulation differ among pipeline capacity, released
capacity, and delivered gas transactions. In addition, different rights
may apply depending on the type of capacity a shipper tries to acquire.
Shippers purchasing released capacity from certain firm shippers may
have to rely on alternate receipt or delivery points, and the use of
such points are sometimes restricted by pipelines' tariffs.
All of these factors increase the shippers' transaction costs by
increasing the difficulty and risk of doing business in the short-term
market. Absent good price and capacity information, shippers cannot
easily compare capacity alternatives or obtain full, comparable
information about the alternatives available at any time. This inhibits
their ability to make informed decisions about acquiring gas and
capacity and prevents them from finding the best gas and capacity deals
available. These costs may be particularly meaningful for small
customers, who do not have the time and resources to unearth, through
personal contacts, the information they need to make informed choices.
In the developing short-term market, market forces impact regulated
services. The growing emphasis on daily transactions means that
customers are more concerned with the daily price of transportation
capacity. For example, many short-term decisions are based on the
delivered price for gas (including transportation) on a daily basis.
Often narrow differences in delivered prices may affect shippers'
decisions.
The existence of a market price for gas at all points along the
pipeline grid has created a market-driven value for transportation
between receipt and delivery points. In effect, the implicit value of
transportation between two such points is the spot price of gas at the
delivery point minus the spot price of gas at the receipt point.
This market driven value can fluctuate widely on a daily basis. As
shown in the following example, many such valuations remain near zero
for long periods of time, only to rise during periods of peak demand.
On this illustration, the market-driven value of transportation
represents the difference between the spot price for gas at the
upstream hub in Louisiana and the delivered price for gas in the New
York downstream market. In other words, the price for delivered gas in
the downstream New York market reflects the spot price for gas at the
upstream hub plus the value of the transportation needed to deliver the
gas to the downstream market. The market value of transportation can
then be compared with the cost-based, regulated maximum interruptible
rates for the three pipelines transporting from Louisiana to New York
(represented by the dotted lines).\22\
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\22\ The source for the spot price data is the Gas Daily Weekly
Weighted Average Prices ($/MMBtu). The source for the maximum
interruptible tariff rate is from PIPELINE Grid published by the
Petroleum Information Corporation Logistics Solution. The range of
tariff rates includes the interruptible rates from Columbia Gas
Transmission Corporation ($.45/MMBtu), Tennessee Gas Pipeline
Company ($.57/MMBtu), and Transcontinental Gas Pipe Line Corporation
($.44/MMBtu).
BILLING CODE 6717-01-P
[[Page 4*ERR58*2987]]
[GRAPHIC] [TIFF OMITTED] TP11AU98.000
BILLING CODE 6717-01-C
This illustrates that the value of transportation during the peak
winter period of 1995-1996 rose to $10/MMBtu (20 times the maximum
daily tariff rates of between $.44 and $.57/MMBtu) and during the 1996-
1997 winter to over $1/MMBtu (2 times the maximum tariff rate). During
non-peak periods, the value of transportation was uniformly below the
maximum daily tariff rate. While the illustration may not portray
precise transportation values,\23\ it nonetheless does provide a
picture of the fluctuation in transportation values over time.
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\23\ For instance, gas from markets other than Louisiana may
have affected delivered prices in New York, and the data contain
unexplained anomalies, such as transportation values of less than 0,
indicating that the price of gas was lower in New York than at the
receipt point in Louisiana. During that time, either no gas moved
from Louisiana to New York or, if gas did move, the markets were not
clearing properly or the price data were not accurate.
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The fluctuation of transportation values raises questions about
whether the Commission's current rate policies are attuned to the
realities of the developing short-term market. The Commission currently
establishes a daily maximum rate for pipeline services and capacity
release by taking the pipelines' annual rate and converting it to a
daily rate (by dividing the yearly rate by 365). But this single rate
does not reflect the variability of daily pricing in the short-term
market. While the $10 value during the 1995-1996 may not be repeated,
transportation values during the next winter were double the maximum
rate.
These data on delivered prices, and derived transportation values,
do not establish either the presence or absence of market power.
Delivered markets for gas can, and probably do, coexist with the
continued exercise of market power over transportation. Pricing by a
pipeline with market power would exhibit the same pricing variability
as shown in the illustration, with higher prices during periods when
demand is greatest. Also, even though prices during off-peak periods
are below the maximum rate, that does not guarantee that market power
cannot be exercised.
The existence of a delivered market does not, in and of itself,
establish that the market is operating efficiently. Regulatory
impediments, such as poorly designed penalty structures or the maximum
rate cap, may create transaction costs, reducing market efficiency and
raising prices. The price
[[Page 42988]]
cap, for instance, can create a disincentive for firm capacity holders
to make capacity available for release during peak periods, because the
capacity holder is unable to realize the market value for its capacity.
This can create a less efficient market by depriving other shippers of
the ability to obtain capacity when they place a greater value on the
capacity than the shipper holding it.\24\ The buyer's alternative is to
try and purchase delivered gas. But the market for delivered gas may
not be as efficient as giving the buyer the added option of purchasing
transportation capacity in an open and transparent market in which the
buyer can decide for itself whether it obtains greater value by
purchasing delivered gas or using its own gas contracts and obtaining
transportation separately.
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\24\ See Mary L. Barcella, How Commodity Markets Drive Gas
Pipeline Values, Public Utilities Fortnightly, Feb. 1, 1998, 24, 25
(price cap limits shippers' incentive to release capacity and can
result in shutting out other shippers needing capacity).
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In sum, the short-term market is changing, with greater emphasis on
daily transactions and daily prices for the gas commodity both at
origin and delivered markets which vary with demand. The constant
maximum rate approach to regulation does not appear to fit well in this
new fast-paced market and may result in a less efficient market, with
increased transaction costs. Yet, market power over transportation
continues to exist and must be addressed.
B. Implications for Commission Regulatory Policies of the Changing
Nature of Short-term Markets
The development of active commodity markets at both ends of the
pipeline poses a significant challenge to the Commission's traditional
method of rate regulation. The current maximum rate provides some
regulatory protection for shippers during peak periods, because it
prevents pipelines from exercising monopoly power at least to the
extent that shippers cannot be charged prices above the maximum rate.
Even during off-peak periods, the maximum rate provides some protection
because it protects some shippers against discriminatory prices that
might otherwise exceed the cap. During off-peak periods, some shippers
still place a high value on moving gas, and the price cap limits the
price such shippers can be forced to pay. Moreover, the Commission
permits pipelines to price discriminate (at prices below the maximum
rate) during off-peak periods to provide benefits to captive customers
who hold long-term firm contracts. The added revenue the pipeline
generates by selectively discounting helps to reduce the reservation
charges owed by the captive firm shippers.\25\
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\25\ During off-peak periods, the pipeline can price
discriminate by offering discounts to some customers that are
greater than those offered to other customers. This practice brings
in more revenue than the pipeline would earn if it could only charge
the same price to all customers. The additional revenue benefits the
firm capacity holders because, in the pipelines' rate case, the
increased revenue reduces the reservation charges firm shippers
might otherwise pay. See Associated Gas Distributors v. FERC (D.C.
Cir. 1987) (selective discounting by a monopolist justified on
equitable grounds because it would reduce captive customers'
contributions to fixed costs).
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As the short-term market continues to grow, maximum rate regulation
in the short-term market may become an increasingly more ineffective
method of regulating the short-term market. Maximum rate regulation may
not provide shippers with the most effective protection against the
exercise of market power. Moreover, the protection it does provide may
come at too great a cost in efficiency.
The rate cap may, for instance, result in misallocation of capacity
where those shippers placing the greatest value on the capacity are
unable to obtain it. During peak periods, pipelines can only sell
capacity which is not under contract or used by those shippers holding
firm capacity. Thus, a pipeline may have little capacity to sell on a
peak day. Even if the pipeline did have capacity to sell, a particular
shipper placing the highest value on the capacity may be unable to
obtain that capacity. Under current Commission rules, when demand for
capacity exceeds the supply available, and all shippers bid the maximum
rate, the pipeline awards its capacity using a queue based on contract
execution date or on a pro rata basis. In either case, the shipper
placing the greatest value on the capacity may not obtain capacity or
not obtain as much capacity as it needs and for which it is willing to
pay.
The shipper's other alternative is to try to obtain capacity from
firm capacity holders, but in this market the price cap may not provide
much protection to the purchasing shipper. The price cap applies to
released capacity. But, the price cap has little effect on delivered
gas transactions, in which the transportation value may exceed the
maximum rate.
There is little hard empiric evidence on how extensive the
delivered market is, but the existence of delivered gas transactions
during peak periods suggests that, due to the price cap, capacity
holders with available capacity will choose to use that capacity to
make delivered transactions, where the profit opportunity is greater,
rather than releasing the capacity, where the price is capped. In
addition, a pending proceeding raises the question whether shippers
have developed other methods for avoiding the maximum rate that are
difficult to detect and prevent on a systematic basis.26
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\26\ Consumers Energy Company, 82 FERC ] 61,284 (1997). See
Inside FERC's Gas Market Report, December 1, 1995, at 14 (discussing
various methods of avoiding the price cap).
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Attempting to regulate the transportation component of delivered
gas transactions would be difficult. But even if this market could be
effectively regulated, it is not clear that such regulation would be
beneficial. If capacity transactions could not occur above the price
cap, then, as described above, capacity would not be allocated
efficiently; those customers most needing gas during peak periods would
be unable to obtain the gas they need and the market would not clear
efficiently.
In addition, as described earlier, the price cap may reduce the
efficiency of the delivered gas market itself by raising transaction
costs, thus resulting in higher delivered prices. Because unbundled
sales of capacity by releasing shippers cannot be made above the
maximum rate, the market may not operate in as open, transparent, or
efficient a manner as is possible. Information for delivered gas is not
publicly posted and shippers relying on word of mouth may not be able
to easily locate all available sources of transportation. The
difficulty of locating potential sellers and obtaining accurate price
information may lead some customers to pay higher than necessary
prices. 27 For instance, during the winter of 1996 when gas
prices rose dramatically, while the market worked well to prevent
shortages and ensure that customers received gas, it could have worked
more efficiently. According to the trade press, the delivered prices
for gas in Chicago on the same day ranged from $20.50 to $46.00 per
MMBtu.28 In an efficient market, one would not expect such a
wide differential in prices, but would expect transactions in the same
market to clear at roughly similar prices. The Commission seeks input
from the industry on whether the price cap creates transaction costs
and prevents
[[Page 42989]]
the development of an efficient short-term market.
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\27\ For example, in the automobile market, the time and expense
of comparison shopping may result in some customers paying higher
prices than others.
\28\ See Gas Daily, February 2, 1996, at 1.
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Maximum rate regulation may have an unintended effect by reducing
the capacity available during peak periods, the time at which the
industry would most benefit from having as much pipeline capacity
available as is possible. As a result of the maximum rate cap, firm
capacity holders may not find it sufficiently profitable to make their
capacity available. It may be that due to state restrictions not all
local distribution companies (LDCs) may be able to make delivered gas
transactions off-system. Thus, they may not make capacity available
during peak periods if they cannot receive the market price for their
capacity.
For instance, an LDC might have a peak shaving capability (storage
or liquified natural gas (LNG)) that costs more to operate than the
maximum transportation rate. The LDC might be willing to release its
transportation capacity and use the peak shaving device instead if the
price it could receive for pipeline transportation exceeded its cost to
operate the peak shaving device. By using its peak shaving device
instead of transportation, the shipper would be expanding the amount of
transportation capacity available for resale during a peak period. But
if the price cap prevented the shipper from obtaining a price higher
than the cost of turning on the peak shaving device, and the shipper
could not sell the gas on a delivered basis, the shipper would use its
transportation capacity, thus depriving other shippers (without peak
shaving) of the opportunity to acquire needed transportation capacity.
Thus, maximum rate regulation may actually reduce the amount of
pipeline capacity available for sale during peak periods. A restriction
on the amount of available capacity would cause peak period prices to
be higher than they would be without the cap. Comments should address
whether the price cap has these effects and whether it does
significantly limit the amount of capacity available in the short-term
market.
Maximum rate regulation during peak periods also may increase
shipper imbalances and penalties. During peak periods, penalties affect
the value of transportation.29 In a cold snap, a shipper may
be willing to pay a penalty for overrunning its contract demand to
obtain the gas it needs. If that shipper faced a $100/MMBtu penalty, it
might be willing to pay any amount for capacity up to $100 to avoid the
penalty. For example, if the value of capacity in an efficient market
were $80, the shipper willing to pay a $100 penalty would be better off
by $20 if it obtained capacity instead. But, as described above, the
price cap may reduce the efficiency of the marketplace, limiting the
shipper's ability to obtain the capacity it needs. The shipper,
therefore, may choose to overrun its contract demand and pay the
penalty. In this situation, the price cap may result in increasing
shipper imbalances, thereby increasing the penalty revenue paid to
pipelines, and perhaps decreasing the reliability of the system.
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\29\ See Industry Surveys the Damage as Winter's Strength Runs
Out, Natural Gas Intelligence, April 22, 1996, at 1, 4 (penalties
started to be a real factor in determining the price of gas in the
Midwest).
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During off-peak periods, the maximum rate cap does not affect the
efficiency of the market because market values do not appear to reach
the maximum rate ceiling. The rate cap, however, may not provide
sufficient protection against the exercise of market power. During off-
peak periods, pipelines and releasing shippers are not required to sell
available capacity at prices less than the maximum rate.30
By limiting the supply of capacity during off-peak periods, pipelines
or releasing shippers may be able to charge monopoly prices because
even a monopoly price may be less than the daily maximum rate. Since
pipelines are permitted to price discriminate at rates below the
maximum rate, they may charge shippers, at least those without other
choices, higher prices than would prevail in an efficient competitive
market. Although the Commission has permitted pipelines to price
discriminate by discounting below the maximum rate, it may be that the
benefits for captive customers holding long-term transportation
contracts come at too great a cost to other shippers or that the
benefits even to captive customers no longer warrant continuation of
this policy.
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\30\ See El Paso Natural Gas Company, 83 FERC para. 61,286
(1998) (pipeline not required to discount below the maximum rate);
Southern California Edison Company v. Southern California Gas
Company, 79 FERC para. 61,157 (1997), reh'g denied, 80 FERC para.
61,390 (1997) (no requirement that pipelines or shippers offer
discounts below the maximum rate).
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In summary, the interface between the regulated and unregulated
sectors of the gas industry has become much more complicated in the
last five years. Regulatory policies that worked well in one market
setting may not work as well today. For this reason, the Commission is
reassessing its current policies and proposing changes.
II. Proposed Change in Regulatory Approach
The Commission's regulatory policies must be attuned to the
realities of the market it is regulating. As became clear during the
period when wellhead prices were regulated, consumers receive little
benefit from artificially low regulated prices if such prices distort
the market and create shortages so consumers cannot acquire gas when
they most need it.31 Moreover, in fashioning regulatory
policies, it must be recognized that market power varies over a
continuum between perfect competition at one end of the continuum and a
single firm monopoly with impenetrable entry barriers at the other.
Thus, a regulatory approach appropriate for pure monopoly markets may
not be the best method for regulating the markets where market power,
while not absent, may be partially disciplined by market forces.
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\31\ See Transcontinental Gas Pipe Line Corporation v. State Oil
and Gas Board, 474 U.S. 409, 420 (1986) (Natural Gas Act's
artificial pricing scheme is a major cause of imbalance between
supply and demand); Atlantic Refining Company v. Public Service
Commission of N.Y., 360 U.S. 378, 388 (1959) (rate regulation should
ensure reasonable rates consistent with the maintenance of adequate
service).
---------------------------------------------------------------------------
The changes to the short-term market raise the question of whether
the Commission needs to change its regulatory philosophy. Prior to
unbundling, maximum rate regulation in the short-term market was more
effective, because the short-term market essentially was limited to the
pipelines' interruptible transportation service.
However, as the short-term market continues to develop, the
continuation of maximum rate regulation in the short-term market may
become increasingly troublesome. First, maximum rate regulation, by its
very nature, inefficiently allocates capacity because those shippers
placing the greatest value on capacity may not be able to obtain it.
Therefore, during peak periods, when the market is under the most
stress, the rate cap may result in a less efficient and more opaque
market in which shippers cannot acquire capacity they need or must pay
higher prices for delivered gas than would have prevailed in a more
efficient short-term market. Second, maximum rate regulation may not be
the most effective tool for preventing the exercise of market power,
particularly for transactions during off-peak periods. Thus, while the
ostensible goal of Commission regulatory policy is to protect shippers
against the exercise of monopoly power by the pipelines, the current
system of maximum rate regulation may no longer be the best method for
meeting this goal.
[[Page 42990]]
A. A Different Model for Regulating the Short-term Market
To respond to the emerging short-term market, the Commission is
proposing in this NOPR a change in regulatory focus to better reflect
the way in which short-term gas markets function and to do a better job
of protecting against the exercise of market power and helping to
foster a more competitive commodity market. The Commission, however,
recognizes that the ability to exercise market power still exists in
the short-term market and, therefore, any regulatory approach it adopts
must continue to provide effective protection against the exercise of
market power.
To do this, there are several criteria that a regulatory approach
must satisfy. It should maximize efficient competition among releasing
shippers and between releasing shippers and the pipelines, because
competition and efficient markets are the best overall protection
against the exercise of market power. It should include policies that
will mitigate any residual market power and monitor for its continued
exercise. It should fairly balance the interests of those customers
that purchase long-term capacity and those who choose to acquire
transportation in the short-term market. And, it should promote
innovation in service offerings to attract new customers.
The Commission believes its statutory objectives can better be met
by a regulatory model that recognizes the distinction between short-
term and long-term markets. Therefore, in the short-term transportation
market, the Commission proposes to replace the reliance on maximum rate
regulation 32 with a regulatory approach focusing on
creating competitive alternatives for shippers, developing policies to
mitigate residual market power, and monitoring the marketplace for the
exercise of market power. In the long-term transportation market, the
Commission proposes to continue to rely upon regulated cost-based rates
to protect against the exercise of monopoly power by the pipelines.
Price regulation for the long-term transportation market will ensure
continued protection for captive customers with long-term contracts
with the pipeline. It will also help discipline the potential exercise
of market power in the short-term market by enabling shippers to
purchase long-term capacity at regulated rates.
---------------------------------------------------------------------------
\32\ Minimum rates would be retained.
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The Commission fully recognizes that pipelines still possess
monopoly power in the transportation market as a result of economies of
scale and barriers to entry. This is particularly true in the long-term
market where the pipeline may be the only source of capacity. The
Commission also recognizes that simply because competition exists for
the gas commodity at receipt and delivery points on the grid does not
mean that the transportation between all points is necessarily fully
competitive.
On the other hand, in the short-term market, the Commission's
capacity release and flexible receipt and delivery point policies,
together with other market changes such as pooling, hub and market
center services, and storage services, have increased the competitive
alternatives available to buyers of capacity. While these measures have
not resulted in effective competition everywhere throughout the
pipeline grid, it cannot be disputed that they have increased the level
of competition and reduced the ability of pipelines to exercise
monopoly power. Thus, while a regulatory presence is still needed in
the short-term transportation market, the Commission may not need to
continue to regulate this market as if each pipeline was still a single
firm monopoly.
At the same time the Commission is proposing to eliminate maximum
rate regulation in the short-term market, it is proposing several
initiatives in this NOPR to maximize competition in the short-term
market, minimize the potential for the exercise of market power, and
monitor the marketplace for the continuing exercise of market power. To
maximize the extent of competition, the Commission is proposing a
number of measures to create more efficient competition among capacity
offerings so that shippers will have more choice in obtaining capacity.
The Commission is proposing to create more uniform nominating
procedures for released capacity so that it can better compete with
capacity from the pipelines and delivered gas transactions. The
Commission further is requesting comment on whether changes in
regulatory policy are needed to maximize shippers' ability to segment
their capacity to provide greater competitive alternatives. To further
improve competition in the short-term market across the pipeline grid,
the Commission is suggesting potential methods of reforming penalty
procedures to ensure that different penalty processes across pipelines
do not limit shippers' flexibility in using capacity or otherwise
distort shippers' decisions about how best to use capacity.
As an additional measure to mitigate potential market power, the
Commission is proposing the use of capacity auctions for all short-term
capacity. A properly designed capacity auction can protect against the
exercise of market power by limiting the ability to withhold capacity
and to engage in price discrimination.
To monitor the marketplace, the Commission is proposing to
establish reporting requirements to provide capacity and pricing
information to all shippers. This information will have the further
benefit of making competition more efficient by providing the pricing
information that a competitive market needs for shippers to make
informed decisions about their capacity purchases. All of these
proposals are addressed in more detail in Parts III and IV of this
NOPR.
In addition to these proposals for monitoring the short-term
market, the Commission proposes to conduct a generic review of the
operation of the short-term market without a price cap after two winter
heating seasons.
Because the proposed regulatory approach differs between short-term
and long-term services, there is a need to define the period
encompassed by each. The Commission is proposing to define short-term
transactions as all transactions of less than one year. The Commission
has traditionally drawn the line between long-term and short-term
transactions at one year.\33\ A term of one year corresponds with
naturally repeating weather and planning cycles for production,
transportation, and storage. A term of one year also corresponds with
the period used to calculate long-term rates.
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\33\ 18 CFR 284.221(d)(2) (right of first refusal applies to
contracts with a term of one year or more); Pipeline Service
Obligations and Revisions to Regulations Governing Self-Implementing
Transportation Under Part 284 of the Commission's Regulations, Order
No. 636-A, 57 FR 36128 (Aug. 12, 1992), FERC Stats. & Regs.
Regulations Preambles [Jan. 1991-June 1996] para. 30,950, at 30,627
(Aug. 3, 1992).
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The Commission, however, requests comment on whether a shorter
period, such as five months, should be used. If a period of less than
one year were chosen, it could either be a discrete period (e.g.,
November through March) or could refer to any transaction with a term
of less than the chosen period. A five month period, for instance,
would generally correspond to the length of time of the heating
season.\34\ The use of a period of less than one year could reduce the
outlay that any shipper would have to make in order to buy
[[Page 42991]]
capacity at cost-based rates to avoid the potential exercise of market
power. \35\
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\34\ In defining short-term for the purposes of capacity release
transactions, the industry, through the Gas Industry Standards
Board, defined short-term releases as releases of less than five
months. 18 CFR 284.10(b)(1)(v), Capacity Release Related Standards
5.3.2.
\35\ For instance, under a five month definition, the maximum
charge a shipper would have to incur to purchase long-term capacity
would be the current monthly rate times five.
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B. Legal Basis for the Proposed Regulatory Change
The Commission's statutory responsibility under the Natural Gas Act
(NGA) is to establish rates that are just and reasonable and that
protect consumers of natural gas from the exercise of monopoly power by
pipelines.\36\ In addition, the Commission has the obligation, under
the Wellhead Decontrol Act, to structure its regulatory framework to
``improve [the] competitive structure [of the natural gas industry] in
order to maximize the benefits of [wellhead] decontrol.'' \37\
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\36\ FPC v. Hope Natural Gas Co., 320 U.S. 591, 610 (1944);
Associated Gas Distributors v. FERC, 824 F.2d 981, 995 (D.C. Cir.
1987), cert. denied, 485 U.S. 1006 (1988) (``The Natural Gas Act has
the fundamental purpose of protecting interstate gas consumers from
pipelines' monopoly power.'').
\37\ Natural Gas Decontrol Act of 1989, H.R. Rep. No. 101-29,
101st Cong., 1st Sess., at 6 (1989); Pipeline Service Obligations
and Revisions to Regulations Governing Self-Implementing
Transportation Under Part 284 of the Commission's Regulations, Order
No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs.
Regulations Preambles [Jan. 1991-June 1996] para. 30,939, at 30,932
(Apr. 8, 1992).
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The courts have recognized that the Commission needs to be able to
develop flexible pricing programs that accommodate its regulation to
the needs of the marketplace. The Commission is not bound to ``use any
single pricing formula'' in determining just and reasonable rates,\38\
and cost-based regulation can be relaxed when the overall ``regulatory
scheme'' ensures that rates are within a zone of reasonableness.\39\
The case law makes clear that flexible rate regulation is permissible
as long as, on balance, the benefits of the program outweigh the
potential risks, and the Commission takes reasonable measures to
protect against the exercise of market power, even though not every
transaction would be free of market power.\40\ In Environmental Action
v. FERC, the court approved a flexible pricing program, which fostered
efficient trading of energy and transmission service, even though the
program created a risk that market power could be exercised over
captive customers. Given the benefits of effective trading and the
protections adopted by the Commission to limit the potential exercise
of market power, the court concluded that the Commission acted
reasonably in approving the program despite the potential risks.\41\
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\38\ Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C.
Cir. 1993) (approving market-based rates).
\39\ See Farmers Union Central Exchange v. FERC, 734 F.2d 1486,
1509-10 (D.C. Cir. 1984).
\40\ Environmental Action v. FERC, 996 F.2d 401, 408, 411 (D.C.
Cir. 1993) (approving flexible pricing program to permit efficient
trading of electric power).
\41\ As the court stated:
We acknowledge that the flexible pricing that fosters trading
among members of the Pool also permits price discrimination
especially against captive utilities. Yet, given the benefits of
this trading, the limited number of captive members, and the
provisions for monitoring transactions and remedying any abuses of
market power, we do not find that the Commission acted arbitrarily
when it approved the use of flexible prices despite their admitted
risk.
996 F.2d at 411.
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The Commission believes the model it is proposing satisfies the
Commission's statutory obligations by achieving the appropriate balance
between the benefits to be garnered from efficient trading in the
short-term market and the protection needed against the exercise of
market power. As discussed earlier, removing maximum rate regulation
from the short-term market provides significant benefits by allowing
markets to efficiently allocate capacity in an environment in which
cost-based solutions do not accommodate the volatile price changes in
the industry.
The potential risk of this approach is that it could give pipelines
or shippers greater latitude to exercise market power during peak
periods. Although competition clearly has increased in the short-term
market, the Commission is not making a finding that the short-term
market is sufficiently competitive to satisfy its traditional market
power analysis. Nor is the Commission making a finding that the
proposals in this NOPR will necessarily create a fully competitive
market. Rather, as discussed below, the proposed approach in this NOPR
is intended to place effective limits on the ability of pipelines and
shippers to exercise market power by enhancing competitive options in
the short-term market, mitigating market power by limiting the ability
to withhold capacity and price discriminate, and monitoring the
marketplace.
The proposed approach should provide benefits to all shippers--both
those holding long-term capacity, and those purchasing short-term
capacity. Long-term capacity holders would still be protected by the
cost-based rate in the long-term market and would benefit by being able
to realize the value of their long-term capacity. Shippers relying on
the short-term market would not be unreasonably harmed since the
proposals in the NOPR are designed to protect them against the
withholding of capacity and price discrimination, both during peak and
off-peak periods. At the same time, short-term shippers would benefit
because the proposals would help to create a more efficient marketplace
during peak periods, with capacity allocated to those valuing it most,
prices undistorted by regulatory allocation priorities, clearer price
signals, and more open, transparent, and efficient capacity
allocations. These benefits are fully described below.
The approach proposed here also appears better suited than other
potential approaches for responding to the changing dynamics of the
short-term market. The Commission, however, requests comment on whether
this proposal is the best approach for protecting against market power
given the realities of the short-term market. Commenters should address
whether the Commission should seek evidence to determine whether it can
make a finding that the market is competitive or pursue other
regulatory approaches.
1. Protection Against the Exercise of Market Power by Pipelines and
Shippers
The Commission's primary responsibility is to protect against the
exercise of monopoly power by pipelines. Even under the current maximum
rate approach, such protection is not absolute. Pipelines are able to
price discriminate below the existing price cap.
The approach proposed here seeks to control the pipelines' exercise
of monopoly power in a different way, by enhancing the competition from
firm shippers releasing capacity, by requiring pipeline capacity to be
sold through an auction that limits the ability to withhold capacity,
and by monitoring the marketplace for evidence of the exercise of
monopoly power. Moreover, the proposed approach would reduce the
ability of pipelines to withhold future capacity (by not expanding
their systems) in order to increase price and earn a supra-competitive
rate of return. If pipelines sought to limit capacity in order to earn
high returns on short-term transactions, shippers could purchase long-
term capacity at cost-based rates and capture the profit opportunities
in the short-term market for themselves by releasing the capacity.
Further, any revenues from short-term sales would be accounted for in
the pipeline's next rate case ensuring that the long-term benefits of
increased revenue from sales of short-term capacity go to the long-term
firm capacity holders. The Commission also could act under section 5 of
the NGA in cases where monitoring revealed that
[[Page 42992]]
the market rate is not just and reasonable.\42\
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\42\ See Elizabethtown, 10 F.3d at 870 (Commission can use its
section 5 authority to assure that market-based rates are just and
reasonable); Environmental Action, 996 F.2d at 411 (emphasizing
provisions for monitoring market-based rates to protect against
exercise of market power).
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The approach proposed here also can be expected to limit the
exercise of market power by firm capacity holders. Releasing shippers
face competition from other releasing shippers and from the sale of
pipeline firm and interruptible service. Firm capacity holders should
not be able to withhold capacity to raise price, because if they do not
use their capacity it then becomes available either as interruptible or
short-term firm capacity from the pipeline. The proposed auction would
then require the pipeline to sell that capacity at a market-determined
price. The auction also would limit the ability of firm capacity
holders to unduly discriminate. Moreover, the pipelines' ability to
build additional capacity is a final protection against releasing
shippers' exercise of market power. If the pipeline observes shippers
earning high returns from constrained capacity, the pipelines have
every incentive to try to capture those returns by building additional
capacity to satisfy that demand.
2. Protection for Shippers Relying on Long-term and Short-term
Capacity
While the Commission has an obligation to consider the interests of
all shippers, its paramount obligation is to protect long-term firm
capacity holders that cannot risk going without long-term
capacity.43 Interruptible or short-term shippers, by
definition, take the risk that they may be unable to acquire
capacity.44 The proposed regulatory model would protect
those shippers holding long-term capacity, while at the same time not
putting short-term shippers at unreasonable risk and perhaps even
providing them with benefits.
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\43\ See Maryland People's Counsel v. FERC, 761 F.2d 768 (D.C.
Cir. 1985); Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C.
Cir. 1985) (remanding special marketing program because it excluded
core captive customers); Environmental Action, 761 F.2d at 411
(permitting flexible pricing program even though there was some
possibility of discrimination against captive utilities).
\44\ See American Gas Association v. FERC, 912 F.2d 1496, 1518
(D.C. Cir. 1990). The court remanded the Commission's decision to
permit pre-granted abandonment of all long-term contracts, because
of a concern about the pipeline's ability to exercise monopoly
market power over long-term capacity holders. The court, however,
found that holders of interruptible and short-term services did not
need similar protection against the exercise of pipeline monopoly
power.
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Under the proposed approach, shippers holding long-term capacity
would continue to receive the traditional protection accorded them
because long-term capacity would still be subject to cost-based
regulation. Indeed, removal of the price cap for short-term
transactions should benefit long-term capacity holders, because it
would permit them to recover more of their reservation charges during
peak periods. For those shippers holding long-term contracts that are
unable to sell delivered gas, the price cap currently limits their
ability to recover their reservation charges by releasing capacity
during peak periods when capacity is valuable. On the other hand,
during off-peak periods, competition from other releasers or the
pipeline may limit a shipper's ability to recover its reservation
charges. At the same time, interruptible or short-term shippers benefit
from the competition during off-peak periods because they pay prices
lower than what the pipeline charged when it was the sole supplier of
capacity. Thus, removal of the rate cap would permit long-term firm
capacity holders to realize the full value of their transportation
capacity during both peak and off-peak periods.
Even if a long-term firm capacity holder is unable to release its
own capacity during a peak period, it may benefit if the pipeline can
charge competitive rates for peak period capacity. In the pipeline's
next rate case, the revenue received from such sales would be used to
reduce the reservation charges for firm customers.
Nonetheless, the Commission expects that the proposed regulatory
model would not put shippers in the short-term market at unreasonable
risk and may even benefit them. These shippers would have the option of
buying long-term capacity at regulated cost-based rates, which should
help to limit the potential exercise of market power in the short-term
market. Pipelines would continue to be required to sell long-term
capacity to anyone offering the maximum rate regardless of the rates
bid for short-term capacity. Further, to ensure that long-term capacity
is available, the Commission would examine closely pipeline refusals to
construct taps requested by customers as well as pipeline refusals to
construct new capacity when demand for new construction exists.
This model also should work to the benefit of short-term customers
during both off-peak and peak periods. During peak periods, the price
cap offers only limited protection against the exercise of market
power, and may actually create inefficiency which reduces short-term
shippers' ability to obtain capacity when they need it. During peak
periods, when capacity is constrained, short-term customers currently
run a significant risk that they may be unable to obtain capacity from
the pipeline even if they place the highest value on that capacity. If
they instead seek to acquire capacity through a delivered gas
transaction, they receive little protection against the exercise of
market power and the price for such gas may be higher than it would be
in a more efficient market. By removing the price cap, but at the same
time offering initiatives for enhancing competition among capacity
alternatives, the approach proposed in this NOPR should be more
effective than the current system in creating a transparent and
efficient short-term market in which shippers, even on peak, can
acquire gas and capacity at efficient market-clearing prices.
During off-peak periods, the rate cap provides little protection
against the exercise of market power, because pipelines and shippers
are not required to sell capacity at rates below the maximum rate. The
proposals for increasing competition and the auction ought to limit the
pipelines' ability to exercise market power or price discriminate so
all short-term shippers would be paying prices closer to a competitive
level.
3. Alternative Approaches for Regulating the Short-Term Transportation
Market
The approach proposed in this NOPR appears better suited than other
possible methods of dealing with the dynamics of the short-term
transportation market.
An alternative approach would be to continue the current maximum
rate system, but allow pipelines and firm capacity holders to seek
removal of the cap in the short-term market upon a demonstration that
they cannot exercise market power. In effect, this approach presumes
market power is present and requires the parties to try to predict,
through market concentration data or other approaches, whether market
power will be exercised if the rate cap is removed. This is essentially
the approach the Commission uses with respect to market power in its
Alternative Rate Design policy, which focuses on the exercise of market
power in the long-term market for pipeline capacity.45
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\45\ Alternatives to Traditional Cost-of-Service Ratemaking for
Natural Gas Pipelines, and Regulation of Negotiated Transportation
Services of Natural Gas Pipelines, 61 FR 4633 (Feb. 7, 1996), 74
FERC para. 61,076 (1996).
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The approach of screening for market power is certainly a possible
alternative, but it would move the Commission in a direction very
different from the one
[[Page 42993]]
proposed here. The approach proposed here does not rely on a finding of
a lack of market power, relying instead on regulatory measures to
reduce or limit the exercise of market power.
The market power screen, in contrast, would require the Commission
to make a finding of lack of market power in each relevant market. This
not only could be a time consuming and daunting task to undertake on an
industry-wide basis, but it might have to be repeated periodically as
contracts expire or the competitive circumstances on individual
pipelines change. The market power screen approach also was developed
to isolate market power in circumstances in which the pipeline is the
sole source of capacity, and it, therefore, imposes a relatively heavy
evidentiary burden on pipelines seeking market-based rates. Such a
screen may not be discriminating enough or the most appropriate means
of dealing with market power in the short-term market where more
competition is clearly present. The use of the traditional market power
screen, therefore, might suggest the presence of market power in areas
that ought to be found reasonably competitive.
Moreover, in cases where the concentration data do not satisfy the
market power screen, the market analysis approach would continue to
rely on maximum rate regulation which, as discussed earlier, may not be
very effective in protecting against market power in the short-term
market and also promotes more inefficient short-term markets. The
Commission, however, requests comment on whether a modified version of
the market power screen could and should be developed for the short-
term market that would be easier to administer and could determine
whether market power is a significant problem.
Another cost-of-service option would be to attempt to develop a
cost-based, seasonal rate design that would better approximate pricing
activity that would occur during peak and off-peak periods. But price
swings can be very large on a daily, weekly, or monthly basis, making
the development of a rate structure that would accurately reflect
competitive market conditions particularly difficult. Moreover, if the
price cap is raised high enough to accommodate peak period competitive
prices, this approach is little different than simply removing the rate
cap, since it would afford firms with market power substantial latitude
to exercise that power at prices below the price cap.46
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\46\ See Environmental Action, 996 F.2d 401 (approving a
flexible pricing program for an electric power pool with a rate
ceiling based on the most valuable and expensive transportation
service).
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Of the regulatory options available, the proposed regulatory model
appears to create the best balance between achieving the Commission's
objectives of preventing the exercise of market power and creating a
regulatory environment that fosters a competitive, efficient commodity
market that is fair to all shippers. This approach would free the
short-term market from regulatory impediments that prevent the market
from responding to the competitive supply and demand forces that may
result in competitive prices exceeding the price cap. At the same time,
the proposals to increase competition in the short-term market should
help to keep the prices for most transactions within reasonable levels.
Because firm shippers would be better able to release capacity in
competition with the pipelines, the pipelines' ability to exercise
market power would be limited. At the same time, firm shippers' ability
to exercise market power would be restrained because, if they tried to
withhold capacity to raise prices, the pipelines would be required to
sell that capacity at market clearing prices. The proposed auction also
would restrain the ability of both pipelines and firm shippers to
exercise market power and to unduly discriminate in the allocation of
capacity. Further, the overall scheme of the proposal limits the
pipelines' ability to charge monopoly prices because shippers can
discipline the pipelines' exercise of market power by purchasing long-
term capacity at cost-based levels.
C. Interrelated Proposals for Regulatory Change
The principal focus of the regulatory changes proposed in this NOPR
is on improving efficiency and competition in the short-term
transportation market. Yet, the regulation of long-term transportation
service is an integral part of the Commission's proposal because
continued regulation of long-term services is an important back-stop to
protect against the pipelines' exercise of market power. Long-term and
short-term transportation services are linked in other ways since the
value of purchasing long-term capacity lies in its ability to insure
shippers against the risk of price swings in the short-term market.
Thus, the changing nature of short-term markets has a concomitant
effect on how shippers use the long-term market and, likewise, actions
affecting long-term contracts can affect the short-term market. For
example, if a pipeline can attract more shippers to its system, the
long-term rate will be reduced, which, in turn, would limit the ability
of pipelines to raise price in the short-term market. On the other
hand, policies discouraging shippers from entering long-term contracts
could reduce the extent of competition in the short-term market.
Because of the relationship between short-term and long-term services,
the Commission also is proposing in this NOPR initiatives to improve
competition and innovation in the market for long-term services and to
ensure that its regulatory policies in the long-term market do not bias
shippers' purchasing decisions.
The Commission is proposing to give pipelines more flexibility in
negotiating rates and terms of service with individual shippers.
Allowing greater flexibility in contract terms for long-term service
can be an important element in the allocation of risk between pipelines
and potential customers. Permitting negotiation of services will
provide an incentive for pipelines to innovate and create additional
value in transportation service.\47\ Also, negotiated rates and
services may permit the pipelines to attract new customers, which would
reduce reservation charges for existing customers.
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\47\ In unregulated and even in regulated industries, sellers
often create innovative service options for individual customers
while still providing a basic service to all. For instance,
telecommunication firms provide specialized services for small and
large businesses while still providing standard service to the
public.
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On the other hand, allowing the pipelines to negotiate individual
terms of service creates the possibility of discrimination against
captive customers as well as a risk that such terms could degrade
competition in the short-term market by limiting the range of capacity
alternatives available to shippers. To fully realize the benefits from
negotiated services while reducing the risks, the Commission is
proposing to permit pipelines and shippers to enter into contracts for
negotiated services, while also proposing criteria to protect against
the risks of undue discrimination or impairment of the competitiveness
of the short-term market.
Further, to ensure that contracting decisions are made efficiently,
regulatory policies should not unfairly bias shippers' contracting
decisions. Some Commission policies, like the right of first refusal,
may well create an asymmetry in the risks facing pipelines and capacity
purchasers and bias shippers towards shorter term contracts. The
Commission, therefore, is proposing certain changes in regulatory
policy to
[[Page 42994]]
eliminate provisions that may tilt shipper decisions towards the
purchase of short-term capacity.
The construction of new capacity also affects competition in the
short-term market. For instance, the ability of shippers to purchase
long-term capacity at cost-based rates is a protection against the
exercise of market power in the short-term market. The Commission is,
therefore, considering changes in certificate policy so that these
policies do not unnecessarily inhibit competition.
In addition, to better reflect the changing nature of services in
the short-term market and to consolidate pipeline reporting
requirements under Part 284, the Commission is proposing to reorganize
Part 284 to put the regulations into a more logical order.\48\
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\48\ The references in this NOPR to proposed regulatory changes
are to the new regulatory sections. References to existing
regulations are to the existing regulatory framework.
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III. Creating Greater Competition Among Short-Term Service
Offerings
Increasing competition is the best antidote to market power. As
long as buyers have good alternative sources of capacity, no seller can
exercise market power, because any attempt to raise price above the
competitive level will result in the buyer moving to another
seller.\49\ Prior to Order No. 636, the pipeline was the only source of
both long-term and short-term capacity. The Commission's establishment,
in Order No. 636, of the capacity release mechanism has significantly
increased competition on most pipelines both between the pipeline and
shippers and among shippers themselves.
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\49\ Market power can be exercised in two ways. A holder of
capacity may withhold capacity from the market to drive up the price
that all shippers pay for the remaining capacity, or it can price
discriminate by charging captive customers more than those customers
with more alternatives. In either case, however, competition will
prevent the exercise of market power.
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But there remain means of enhancing competition and improving the
substitutability of capacity alternatives. Three such improvements are
to make nomination and scheduling procedures more uniform for all
short-term services; provide shippers with a greater ability to segment
capacity and use alternate receipt and delivery points so
transportation alternatives are more comparable; and employ auctions
for all capacity to limit the ability of pipelines or shippers to
withhold capacity or discriminate. In addition, the Commission is
proposing changes to its reporting requirements to ensure that
comparable information about pipeline and release transactions is
provided. Improved information enables shippers to make more informed
capacity choices while it also permits the Commission and the industry
to monitor transactions for the potential exercise of market power in
the event the Commission's efforts to mitigate market power are not
successful. The Commission is committed to take appropriate and timely
action in individual cases to deal with the exercise of market power.
To this end, the Commission is in the process of considering
improvements to its procedures for handling complaints.\50\
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\50\ See Compliant Procedures, Docket No. RM98-13-000 (issued
contemporaneously with this NOPR).
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A. Nomination Equality
In order to foster a more competitive short-term market, all forms
of transportation--pipeline interruptible and short-term firm capacity,
released capacity, and delivered sales transactions--must be able to
compete on as equal a basis as possible. While there are obviously
differences in rights associated with the different types of capacity,
the Commission is concerned that differences in nomination and
scheduling procedures for capacity release inhibit the ability of
capacity release transactions to compete with pipeline capacity. The
Commission, however, requests comment on whether the existing
differences in nomination and scheduling procedures for capacity
release transactions reflect important differences in the nature of the
services that should be preserved.
Under current regulations, pipelines can sell their interruptible
and short-term services at any time and shippers can schedule such
services at the earliest available nomination opportunity. Similarly,
capacity holders making delivered sales can nominate and schedule at
every available opportunity. In contrast, nomination and scheduling
opportunities under capacity release transactions currently are
significantly circumscribed.
Under Commission regulations, shippers currently submit their daily
nominations at 11:30 a.m. to take effect at 9 a.m. the next gas day.
Pipelines presently are required to provide shippers at least one
intra-day nomination change after the 11:30 a.m. nomination, although
many pipelines provide additional intra-day nomination opportunities.
While a pipeline may sell interruptible or short-term firm service and
permit the recipient of that service to submit a nomination at the
earliest available nomination opportunity, shippers consummating a
release transaction must do so prior to 9 a.m. and can only submit a
nomination at 11:30 a.m. for the next gas day. They cannot consummate a
release transaction later than 9 a.m., nor can the replacement shipper
utilize an intra-day nomination opportunity to submit a nomination for
the current gas day.
The disparate treatment of capacity release transactions, if left
uncorrected, promises to become even more severe as a result of the
industry's agreement to enhance intra-day nomination opportunities. In
a final rule issued on July 15, 1998,51 the Commission
adopted the consensus agreement of the Gas Industry Standards Board
(GISB) to expand shippers' intra-day nomination opportunities by
establishing three synchronized intra-day nomination periods across the
grid. Under the industry's schedule, the three synchronization times
are 6 p.m. (for the next gas day), 10 a.m. and 5 p.m. (for the current
gas day). A shipper obtaining short-term firm or interruptible capacity
from the pipeline, or making a delivered sales transaction, will be
able to submit a nomination at any of these intra-day nomination
opportunities. Significantly, however, a replacement shipper cannot
acquire released capacity immediately prior to these intra-day
nomination times and nominate at these times. The replacement shipper
must consummate a capacity release deal by 9 a.m. and must wait a full
day before it can flow gas under the release transaction.
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\51\ Standards For Business Practices Of Interstate Natural Gas
Pipelines, Final Rule, 63 FR 39509 (July 23, 1998), 84 FERC para.
61,031 (Jul. 15, 1998).
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In order to place capacity release transactions on a more equal
footing with pipeline services, the Commission is proposing, in
proposed section 284.13(c)(1)(ii), that pipelines provide purchasers of
released capacity, like shippers purchasing capacity from the pipeline,
with the opportunity to submit a nomination at the first available
opportunity after consummation of the deal. This will enable shippers,
for instance, to acquire released capacity at any of the nomination or
intra-day nomination synchronization times and nominate gas coincident
with their acquisition of capacity.
In some cases, pipelines currently require replacement shippers to
pass a credit-worthiness check and execute contracts prior to
nominating. Under the proposed regulation, such requirements could not
prevent a replacement shipper from nominating when it completes the
release transaction. Proposed section 284.13(c)(1)(ii) would provide
that a pipeline that requires the replacement shipper to enter into a
contract must
[[Page 42995]]
issue the contract within one hour of submission of the transaction
52 and that the requirement for contracting must not inhibit
the ability to submit a nomination at the time the transaction is
complete.
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\52\ The current regulations require pipelines to issue
contracts within one hour. 18 CFR 284.10(b)(1)(v), Capacity Release
Related Standards 5.3.2.
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Pipelines have available several procedures which they can use to
protect themselves against the credit risk of the replacement shipper.
The pipelines can institute procedures under which replacement shippers
receive pre-approval of their credit-worthiness or receive a master
contract, like those used for interruptible shippers, permitting the
replacement shipper to nominate under that contract at any
time.53 For replacement shippers that do not have a master
contract, the pipeline could provide a contract number for nominating
as soon as the pipeline is notified of the release transaction. For
replacement shippers that have not received pre-approved credit, the
releasing shipper may agree to be liable for any usage charges incurred
by the replacement shipper while the pipeline conducts the credit-
worthiness check.54
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\53\ The Commission previously issued a proposed rule suggesting
that pipelines use pre-approved credit-worthiness procedures for
replacement shippers. Secondary Market Transactions on Interstate
Natural Gas Pipelines, Notice of Proposed Rulemaking, 61 FR 41046
(Aug. 7, 1996), IV FERC Stats. & Regs. Proposed Regulations para.
32,520 (Jul. 31, 1996). In the comments on the proposal, the
pipelines, in general, did not object to the use of pre-approval for
credit-worthiness or master contracts. Tenneco Energy objected only
to the use of master contracts, arguing that because capacity
release is a firm service, the pipeline needs prior notice of the
specific terms of the release including the firm transportation
quantity, the zones of the release, and the rights to primary and
secondary points.
\54\ Releasing shippers already are responsible for all
reservation charges under the Commission's capacity release
regulations. 18 CFR 284.243(f).
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B. Segmentation and Flexibility of Receipt and Delivery Points
1. Background
In Order No. 636, the Commission established two principles that
are important to creating efficient competition between holders of
capacity and the pipelines: segmentation of capacity and the ability of
shippers to use alternative receipt and delivery points. Segmentation
refers to the ability of firm capacity holders to subdivide their
capacity into segments to enhance the value of the capacity and the
capacity holders' ability to compete with the pipeline. In the example
used in Order No. 636, a shipper holding firm capacity from a primary
receipt point in the Gulf of Mexico to primary delivery points in New
York could release that capacity to a replacement shipper moving gas
from the Gulf to Atlanta while the New York releasing shipper could
inject gas downstream of Atlanta and use the remainder of the capacity
to deliver the gas to New York. In order for such a transaction to
work, both the releasing and replacement shippers need the right to
change their receipt and delivery points from the primary points in
their contract to use other available points.
Without the ability to segment and use alternate points, the New
York releasing shipper in the example would not be an effective
competitor to another shipper holding firm primary point capacity at
Atlanta. The ability to segment capacity and use alternate points,
therefore, provides a potential replacement shipper who wants to ship
to Atlanta with additional capacity options. It can buy from the
releasing shipper holding primary point capacity in Atlanta or from the
New York releasing shipper or any other shipper holding capacity
downstream of Atlanta.
However, under current Commission policies, the ability of the
releasing shipper in New York to compete with the pipeline or with the
shipper in Atlanta may be limited. Under the Commission's current
policies, the releasing shipper in New York only has a secondary
delivery point right at Atlanta, which is inferior to the primary point
right of the releasing shipper holding primary point rights at Atlanta.
In other words, if the pipeline is unable to make both deliveries to
Atlanta, the shipper with the primary right at Atlanta will be given
delivery priority over the releasing shipper in New York or the
replacement shipper buying capacity from the New York shipper, each of
which only has secondary point rights at Atlanta. To the extent that
this is a possibility, capacity from the releasing shipper in New York
is not equal in quality or fully competitive with the capacity from the
shipper holding primary point rights at Atlanta.
Receipt and delivery point flexibility is not applied consistently
across pipelines, and pipelines do not treat different types of
segmentation similarly. During the restructuring proceedings mandated
by Order No. 636, the Commission permitted certain pipelines to adopt
tariff provisions under which releasing shippers would lose their
rights to primary receipt or delivery points if replacement shippers
changed primary points under the release.55 The Commission
permitted such restrictions where the pipelines had pre-existing tariff
provisions that did not permit shippers' primary receipt and delivery
point CD rights to exceed their mainline rights. To prevent the
possible loss of primary point rights, the releasing shipper would have
to include a condition in the release prohibiting the replacement
shipper from changing primary points. The Commission, however, sought
to minimize the effect of this restriction on segmented releases by
adopting a policy for segmented releases under which:
\55\ See Transwestern Pipeline Company, 62 FERC at 61,659, 63
FERC at 61,911-12 (1993); El Paso Natural Gas Company, 62 FERC para.
61,311, at 62,982-83 (1993).
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the releasing and replacement shippers must be treated as
separate shippers with separate contract demands. Thus, the
releasing shipper may reserve primary points on the unreleased
segment up to its capacity entitlement on that segment, while the
replacement shipper simultaneously reserves primary points on the
released segment up to its capacity on that segment.56
\56\ Texas Eastern Transmission Corporation, 63 FERC para.
61,100, at 61,452 (1993). El Paso Natural Gas Company, 62 FERC para.
63,311, at 62,991. See also Transwestern Pipeline Company, 61 FERC
para. 61,332, at 62,232 (1992).
Under this policy [hereinafter referred to as the Texas Eastern/El
Paso policy], the releasing shipper could protect its delivery point
rights by choosing Atlanta as its primary receipt point and New York as
its primary delivery point, while the replacement shipper designate its
primary receipt point as the Gulf and Atlanta as its primary delivery
point. However, it is not clear whether all pipelines adhere to this
policy.57
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\57\ See Colorado Interstate Gas Company FERC Gas Tariff, First
Revised Volume No. 1, Third Revised Sheet No. 254 (replacement
shippers are not permitted to change primary points and can nominate
only the original primary or at secondary points).
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Even on those pipelines following the Texas Eastern/El Paso policy,
replacement shippers face limitations on their ability to change
primary receipt and delivery points.58 However, even at the
time the Commission permitted those pipelines with pre-existing tariff
restrictions on receipt and delivery point rights to continue such
restrictions, it was skeptical about the justifications for imposing
such limits.59 In fact, the Commission rejected applications
to impose similar
[[Page 42996]]
restrictions by pipelines without pre-existing
restrictions.60 In these cases, the Commission required
pipelines to permit replacement shippers to change primary points
without releasing shippers losing their right to return to their
original primary point at the end of the release. As the Commission
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explained in Northwest:
\58\ For example, if the replacement shipper seeks to change its
primary receipt point right from the Gulf to another point, then the
releasing New York shipper might lose the ability to return to its
primary Gulf receipt point at the end of the release.
\59\ See Transwestern Pipeline Company, 62 FERC at 61,659, 63
FERC at 61,911-12 (1993); El Paso Natural Gas Company, 62 FERC para.
61,311, at 62,982-83 (1993).
\60\ See Northwest Pipeline Company, 63 FERC para. 61,124, at
61,806-08 n.72 (1993).
Northwest's restriction on replacement shippers' ability to
designate primary receipt or delivery points different from those of
the releasing shipper unless the releasing shipper agrees to
relinquish the original primary point could operate to limit or
impair capacity release transactions. A releasing shipper may be
unwilling to enter into a short term release if, in so doing, it
loses priority to its primary receipt and delivery points for the
remainder of a 20 year contract. Replacement shippers may be
reluctant to bid on mainline capacity if they cannot be assured of
receipt and delivery point capacity at available points (not subject
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to bumping by shippers coming later in time).61
\61\ Northwest Pipeline Company, 63 FERC para. 61,124, at 61,807
(1993). See also Questar Pipeline Company, 62 FERC para. 61,192, at
62,306 (1993).
Under both the Texas Eastern/El Paso and Northwest policies,
replacement shippers can change primary points only if the new point is
available and is not fully subscribed. In addition, shippers can only
change to available points that are within the capacity path for which
they paid. Pipelines, therefore, are not required to permit shippers to
change primary points if doing so would mean that the pipeline's
mainline capacity would be oversubscribed.
During the restructuring proceedings, the Commission addressed
segmentation only in the context of release transactions. It did not
address whether a shipper could segment capacity, for instance, by
delivering gas to Atlanta and then shipping to New York for its own
use. It is not clear whether pipelines permit such transactions. Even
if pipelines do permit the segmented transaction, the shipper may be
unable to designate both Atlanta and New York as primary delivery
points.
In the Commission's NOPR on secondary market transactions
(Secondary Market NOPR),62 the Commission requested comment
on whether it needed to provide more flexibility for shippers and
replacement shippers to change primary points. Most shippers supported
providing more flexibility, arguing that a shipper using capacity on a
secondary basis within the primary path has the same rights afforded
transportation between primary points. The pipelines, however, opposed
increased flexibility, arguing that allowing releasing shippers to
return to previously vacated points would require the pipeline to hold
otherwise available capacity in reserve for shippers without collecting
reservation charges for that capacity.
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\62\ Secondary Market Transactions on Interstate Natural Gas
Pipelines, Notice of Proposed Rulemaking, 61 FR 41046 (Aug. 7,
1996), IV FERC Stats. & Regs. Proposed Regulations para. 32,520
(Jul. 31, 1996).
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2. Is There a Need To Revise Policies To Improve Competition Between
Primary and Alternate Point Capacity?
Shippers' rights to segment and use receipt and delivery points
clearly differ across pipelines. In today's gas market, shippers are
acquiring capacity from multiple sources and need the ability to use
their capacity more flexibly. The issue is whether, in operation, the
current system fairly allocates capacity so no changes need to be made
to the policies or whether changes are necessary to maximize the extent
of competition in the short-term market. The concerns involve two
interrelated areas: segmentation policy, including priorities for
primary and secondary points, and the confirmation process between
pipelines and between pipelines and other entities, such as LDCs.
The first concern, as discussed above, is whether on some
pipelines, replacement shippers may be unable to use certain receipt or
delivery points as primary points under segmented release transactions
and whether this significantly limits shippers' flexibility or raises
transaction costs. These limitations would be more severe on pipelines
that do not follow the Texas Eastern/El Paso policy by permitting both
releasing shippers and replacement shippers on segmented releases to
hold primary point capacity equal to their contract demand.
On some pipelines, delivery or receipt point priorities may be used
to determine priorities over constrained mainline capacity even if both
shippers have equal firm rights over the constrained mainline. For
example, if pipelines are unable to schedule competing firm
nominations, the pipelines may give higher priority to shippers moving
between primary firm points over shippers moving to secondary points
even if both sets of shippers have equal firm rights past the area that
has become constrained.63 It is not clear how frequently
pipelines use receipt or delivery point priority to allocate mainline
capacity in the event of constraints or whether the use of such an
allocation policy significantly limits shippers' flexibility.
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\63\ See El Paso Natural Gas Company, 81 FERC para. 61,174
(1997) (because the pipeline does not assign receipt point rights,
it effectively allocates constrained mainline capacity based on
whether customers are nominating to primary or secondary delivery
points).
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Second, confirmation practices may affect the allocation of primary
and secondary capacity at interconnects between two pipelines (which
includes interconnects between interstate and intrastate pipelines and
interstate pipelines and local distribution companies). Suppose there
are two shippers with firm capacity on pipeline A that covers an
interconnect with pipeline B, but shipper 1 holds the interconnect as a
primary delivery point and shipper 2 as a secondary delivery point.
Further, suppose there is insufficient capacity to effect both
deliveries and shipper 1 holds only interruptible capacity on pipeline
B, while shipper 2 holds firm capacity on pipeline B.
BILLING CODE 6717-01-P
[GRAPHIC] [TIFF OMITTED] TP11AU98.001
[[Page 42997]]
BILLING CODE 6717-01-C
Shipper 1: Pipeline A--Firm Primary at Delivery Point; Pipeline B--
Interruptible at Receipt Point
Shipper 2: Pipeline A--Firm Secondary at Delivery Point; Pipeline B--
Firm Secondary at Receipt Point
If both pipelines independently allocate capacity according to their
tariff-based priorities before seeking confirmation, neither shipper
would be able to flow, even though shipper 2 has firm capacity on both
pipelines.64
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\64\ Pipeline A would allocate the delivery point right to
shipper 1, whose primary firm right has priority over shipper 2's
secondary firm right. Pipeline B would allocate the receipt point
right to shipper 2, whose firm capacity right has priority over
shipper 1's interruptible capacity. Thus, the capacity allocations
would not match and neither would be confirmed.
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In some contexts, however, gas flows may be determined by the
decision of the downstream party as to which gas it will
accept.65 If that were the case in the above example,
shipper 2 would flow gas because it had the priority right on
downstream pipeline B.
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\65\ See, e.g., Southwest Gas Corporation v. El Paso Natural Gas
Company, 63 FERC para. 61,111 (1993) (finding that allocation of
delivery point rights had not abrogated Southwest's delivery point
priority since Southwest controlled the capacity to take gas away
from the delivery point). This case would seem to suggest that the
confirmation by the LDC takes precedence over upstream primary or
secondary delivery point rights.
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The confirmation practices of pipelines in this situation are not
specified in Commission regulations or pipeline tariffs. Thus, the
result in this situation is not predictable, which may raise the costs
of doing business.
The Commission is seeking comment on whether the current system
works efficiently or whether changes to the current practices are
needed. The comments should focus on: (1) How the current system works,
particularly with respect to any differences between interconnections
between pipelines and interconnections between pipelines and LDCs; (2)
whether the current system impedes efficient competition and
flexibility or raises transaction costs, and if so, whether the problem
results from current Commission policies, from a failure to understand
and adhere to those policies, or from a lack of uniform application of
Commission policies; and (3) whether changes in policies would help to
enhance competition and reduce the ability of pipelines or shippers to
exercise market power. To help focus comments, the Commission will lay
out below some options which commenters can consider. The first set of
options deal with segmentation and receipt and delivery point priority
issues, while the second deals with issues relating to pipeline
confirmation procedures.
First, the current system under which receipt and delivery point
priorities are determined on a pipeline-by-pipeline basis could
continue. This option would be appropriate if current policies do not
unfairly restrict competition or if non-uniform rules are necessary due
to pipelines' differing operational capabilities.
Second, all pipelines could be required to conform to the Texas
Eastern/El Paso requirement that, in a segmented release, both
releasing shippers and replacement shippers can designate available
primary receipt and delivery point capacity rights equal to their
contract demand. This would help to increase efficient competition by
giving buyers a better opportunity to substitute capacity acquired
through segmented releases for pipeline capacity or capacity provided
by a shipper with primary point capacity.
Third, to further expand the extent of efficient competition, all
pipelines could be required to adhere to the Northwest approach under
which replacement shippers could change primary point rights to any
available point without the releasing shippers losing their right to
return to their initial primary point at the end of the release. The
pipeline could still sell the vacated point to another shipper during
the term of the release. The Northwest policy also could be extended
beyond release situations to permit a shipper to segment its own
capacity. As described earlier, a shipper with firm capacity with a
primary receipt point in the Gulf of Mexico and a primary delivery
point to New York would be able to deliver gas to Atlanta as a primary
delivery point, while choosing a receipt point downstream of Atlanta as
a primary receipt point for making a delivery to New York as a primary
delivery point.
Fourth, pipelines could be required to provide all shippers with
firm capacity rights over the mainline with equal rights to flow gas
past a mainline constraint point.66 This would increase
shipper capacity options by giving released capacity flowing to
secondary points priority at a mainline constraint point along the
shipper's path equal to pipeline capacity or released capacity flowing
to primary points.
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\66\ See, e.g., Northwest Pipeline Company, 67 FERC para. 61,095
(1994) (mainline constraints allocated according to path rights
rather than point rights). As this case illustrates, even on web or
displacement systems, capacity path rights may be defined.
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This principle could be expanded so that all shippers with firm
capacity would have equal rights to receive or deliver gas at all
points along their path. This would provide a shipper moving to a
secondary delivery point along its path rights to deliver at that point
equal to shippers buying pipeline capacity or shippers buying released
capacity which have that point as a primary delivery point. Such an
approach would ensure that all capacity along the mainline path would
compete equally, giving shippers seeking capacity more capacity
alternatives from which to choose. A possible conflict might arise if
the receipt or delivery point could not accommodate all the receipts or
deliveries sought by the shippers. It is not clear how frequently such
a problem would occur.
Fifth, a monetary value could be developed for all receipt and
delivery points so that shippers could choose to pay for additional
primary point rights, especially those outside their contract path.
Under this approach, shippers would be able to buy unsubscribed primary
receipt and delivery point rights independent of mainline
transportation. One issue under this approach would be to determine a
value for additional receipt and delivery point rights. One option is
to take a strictly cost-based approach in which the pipelines would
have to establish the cost of making or receiving deliveries. Another
might be to conduct an auction for all available points.
The previous options deal with ways of enhancing the ability of
shippers with mainline capacity at secondary points to compete with
capacity from the pipeline or other shippers at primary points, but do
not address confirmation practices across interconnect points. One
possible approach would be for the pipelines to seek to confirm all
transactions before they apply tariff-based priority rules, and to
require that, in the confirmation process, pipelines must seek to
maximize the flow of firm transportation across an interconnect. Thus,
in the example given above, shipper 2 holding firm capacity on both the
upstream and downstream pipeline would get priority over shipper 1,
since shipper 1 holds only interruptible transportation on the
downstream pipeline.67/ Another potential option would be
for priority through pipeline interconnect points to be determined
based on which shipper has the take-away capacity on the downstream
pipeline. The Commission requests comment on these options as well as
the submission of other proposals for handling confirmations that would
create greater substitutability between primary and secondary releases
and lower the associated transactions costs
[[Page 42998]]
while still fairly allocating capacity among shippers.
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\67\ See text accompanying note 64, supra.
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C. Capacity Auctions
Auctions are often used as effective methods of selling goods and
services. A well-structured auction can assure that pipeline capacity
is allocated to the party placing the greatest value on the capacity
and can assure fairness in the allocation process by preventing price
discrimination or favoritism by the capacity seller. An auction
provides customers with equal opportunities to acquire capacity,
preventing the pipeline or releasing shipper from treating different
bidders differently. Auctions also have value because they provide the
market with accurate information on the value of capacity.
If a market is perfectly competitive with a sufficiently large
number of capacity holders, and equal access to market information, an
auction would not be necessary to limit the exercise of market power,
because market power would not be present. But, even in that case, an
auction may help reduce the transaction costs of trading capacity. Any
attempt to charge more than a competitive price would result in the
potential buyer looking elsewhere for capacity.
The current regulations seek to protect against pipeline exercise
of market power by requiring pipelines to sell capacity when they have
received an offer at the maximum tariff rate. This requirement prevents
the pipelines from withholding capacity at the maximum rate in order to
raise prices. The current regulations, however, do not require
pipelines to sell capacity at a discounted rate. Thus, pipelines may be
able to exercise market power at rates below the maximum rate because
the pipeline is not obligated to sell capacity (can withhold capacity)
at less than the maximum rate.
In markets where market power is present, an auction that limits
capacity withholding can be an effective method of limiting the
exercise of market power and creating a more efficient market. In
today's market, during peak periods, the price cap may restrict
shippers' ability to obtain capacity from the pipelines or may result
in shippers paying a higher price than necessary for delivered gas
either because releasing shippers exercise market power or because the
market simply is not transparent enough for potential buyers to be able
to locate and negotiate with alternative capacity sources. During off-
peak periods, shippers similarly may have to pay more than necessary to
obtain capacity if pipelines or releasing shippers can withhold
capacity or price discriminate. Placing all available capacity in an
auction would help ensure that shippers will pay lower prices both
during peak and off-peak periods, because the auction process helps to
ensure that prices reflect competitive market forces rather than
resulting from the exercise of market power or shippers' inability to
obtain accurate market information.
1. Proposed Auction Requirement
To help prevent the exercise of market power, the Commission is
proposing, in revised Sec. 284.10(c)(5), to require all available
short-term pipeline firm and interruptible capacity and released
capacity to be allocated through an auction process. The proposed
auction requirement applies to all sales of short-term pipeline
capacity, both interruptible and firm, and released capacity. Thus, all
capacity sold for a term of less than a year (or whatever other time
period is chosen to define short-term capacity) would be sold through
an auction process. Using an auction process for all capacity, during
both peak and off-peak periods, is necessary to limit the exercise of
market power and to allow the market to determine the value of
capacity.
The Commission is proposing that pipelines adhere to the following
principles in designing an auction:
all available short-term capacity must be sold through an
auction;
daily capacity from the pipeline must be allocated based
on the auction without the establishment of a reserve or minimum bid
price;
all eligible shippers must be permitted to bid with no
favoritism shown to pipeline affiliates or other shippers;
the procedures and rules for each auction, including the
auction schedule, must be disclosed in the pipeline's tariff in advance
of the auction and must be applied in each auction;
capacity must be allocated based on established criteria
and parameters known in advance to all bidders and the same criteria
and parameters must apply to pipeline and released capacity;
68 and
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\68\ See 18 CFR 284.10(b)(1)(v), Capacity Release Related
Standards 5.3.3 and 7.3.14 (three methods for valuing bids, highest
rate, net revenue, and net present value).
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shippers must be able to validate that the auction was run
properly either through the posting of information sufficient to permit
them to validate that the winners were selected appropriately or
through the use of other mechanisms, such as an independent third-
party, which will validate the results.
The requirement of an auction for short-term capacity still leaves
the question of whether to retain the current bidding procedure for
long-term capacity release transactions.69 Pipelines are not
subject to any auction or bidding requirements in selling long-term
capacity. To ensure comparability, the Commission, therefore, proposes
to permit shippers to release capacity on a long-term basis without
going through a bidding process. As is the case for the pipelines, no
sales of long-term capacity can exceed the pipeline's maximum rate.
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\69\ See CFR 284.243(e).
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The proposal for auctions of capacity raises issues about auction
design that will be discussed below. The first issue is whether to
permit pipelines or releasing shippers to establish a reserve or
minimum price below which they are not obligated to sell capacity. The
second is how to design the auction to work most efficiently.
2. Reserve Prices
The Commission is proposing two different auction methodologies for
pipeline capacity. For capacity sold for one day, the Commission is
proposing a daily auction in which pipelines cannot establish a reserve
price. Pipelines would not be required to sell below the minimum rate
(variable cost) in their tariffs. For auctions of longer than one day,
pipelines would be permitted to establish reserve prices.
Prohibiting pipelines from establishing a reserve price would limit
their ability to withhold capacity. Requiring pipelines to auction
their daily capacity, without a reserve price, should be sufficient to
prevent them from withholding capacity for longer short-term
transactions, for instance, a deal for three months' worth of capacity.
The pipeline should not be able to demand a monopoly price for three
months' worth of capacity because shippers would not pay that price. A
shipper would pay only the amount that it would expect to have to pay
if it purchased the capacity in the daily auction plus a premium for
the insurance value of locking-in the capacity and price for a set
period of time.
For capacity available for periods of longer than one day,
pipelines could establish reserve prices. Pipelines may have a
legitimate basis for believing that the market value for their capacity
on a single day is less than what the capacity will be worth at a later
date or if the capacity ultimately was sold on a longer-term basis.
The auctions of pipeline capacity would work in the following
manner. When a pipeline has firm capacity
[[Page 42999]]
available for more than one day, for instance six months beginning on
July 1, the pipeline could establish a reserve price for the six month
block of capacity. If that capacity was not sold by June 30, the
pipeline would have to sell the capacity for July 1 through the auction
process for that day. The pipeline, however, could continue the reserve
price for shippers willing to bid on the six month (less one day) block
of capacity. This process would continue until the capacity is sold.
The daily auction also would apply to available pipeline storage
capacity. But comments should address whether a daily auction for
storage capacity is practical, whether different rules should apply to
storage capacity, and whether storage capacity needs to be included in
the daily auction to prevent capacity withholding.
The Commission is proposing that all short-term releases of
capacity by firm shippers take place through the auction to ensure that
capacity is allocated on a non-discriminatory basis to the purchaser
placing the greatest value on the capacity. Releasing shippers would be
permitted to place reserve prices on their capacity, because they have
a legitimate basis for retaining capacity for their own use. For
instance, firm shippers may need to reserve capacity to meet
unanticipated weather changes, to replace depleted storage, or to
change to a substitute supply to ensure reliable service. Moreover,
firm capacity holders should not be able to withhold capacity because,
under the proposal, if a firm capacity holder does not nominate (use)
its capacity, the pipeline would be required to sell the unnominated
capacity as interruptible or short-term firm capacity through the
auction.
The Commission, however, requests comment on a number of aspects of
its proposed approach to reserve prices. Commenters should address
whether requiring pipelines to sell capacity at the bid price for only
one day is sufficient to limit the pipeline's ability to withhold
capacity. Commenters should address the question of the price at which
capacity should be sold. For example, should all shippers pay the
market-clearing price (lowest price necessary to get capacity)
70 or should each shipper pay the price it bids?
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\70\ The market clearing price is the price at which all
available capacity is sold and no shipper bidding that price or
higher would be denied capacity.
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Commenters also should address whether the proposed requirement to
sell pipeline daily capacity without a reserve price could cause cost-
recovery problems for some pipelines. If shippers on a pipeline where
capacity is not sufficiently constrained relied exclusively on the
daily auction, the revenue received may be insufficient to cover the
pipeline's costs allocated to interruptible and short-term firm
capacity.71 The daily auction without a reserve price also
may affect the ability of pipelines to resubscribe firm capacity at
maximum rates as contracts expire, which could cause cost recovery
problems. If the pipeline is expected to be uncongested, shippers may
prefer to rely on the daily auction rather than resubscribing to firm
capacity.
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\71\ Pipelines are generally considered to be natural monopolies
because they have very large fixed costs, with significant economies
of scale. Thus, it is less expensive to have one pipeline provide
service than to have two or more pipelines compete over the same
route. However, when a natural monopolist is at the efficient size,
where the cost of producing one additional unit (marginal cost)
equals the price that a customer is willing to pay (demand), that
price is not sufficient to cover the average costs of the firm. See
R. Posner, Economic Analysis of the Law, 251-264 (2d ed. 1977).
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On the other hand, it may be that most pipelines are sufficiently
constrained so that the daily auction requirement will not limit their
ability to recover their costs.72 The proposal to limit the
requirement to sell capacity without a reserve price to one day may
itself reduce the risk to pipeline cost recovery. Some shippers may be
unwilling to take the risk of not having firm capacity.
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\72\ Many pipelines, however, may be at less than efficient size
and, therefore, be sufficiently congested that they will be able to
recover their costs.
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In addition, on some pipelines, the requirement for a daily auction
may give large customers greater leverage over pipelines in negotiating
renewal contracts. When a large customer's firm contract expires, it
may well decide not to renew that contract and to submit low bids for
capacity in the daily auction. If the purchaser is the principal, if
not the only, shipper for a large block of pipeline capacity, it could
be reasonably confident that it would not be outbid by other shippers.
There are potential approaches to address these kinds of cost
recovery problems if they materialize, without rejecting the benefits
of an auction process. One set of possibilities is for pipelines to
charge a fixed access charge to all customers using its system to
recover fixed costs or a volumetric usage charge designed to recover
the fixed costs of the system. These are similar to methods that are
being considered in connection with congestion pricing in the electric
industry.73
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\73\ These options are discussed in the NOI on long-term
services which is being issued contemporaneously with this NOPR.
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Another alternative is to allow the pipeline to set a reserve price
in the daily auction that is above variable costs, but below the
current maximum rate. In effect, this would be a minimum price floor
below which the pipeline would not have to sell. The price floor could
be established by using the dollar amounts associated with specified
cost-of-service elements, such as rate of return, or could be
established at a percentage of the maximum rate. This approach would
still provide shippers with protection against the exercise of market
power and would prevent the pipeline from discriminating in the prices
it charges to specific customers while permitting the pipeline a
reasonable opportunity to recover its fixed costs. However, preventing
the pipelines from price discriminating may still result in cost
recovery problems.
Another approach would be to limit the auction only to transactions
above the maximum rate (as converted to a daily rate). The current
regulations require a pipeline to sell capacity at the maximum rate to
all shippers, thus preventing the pipeline from withholding capacity at
the maximum rate to derive a higher price. A requirement that pipelines
must auction capacity at the market clearing price, whenever such
prices exceed the maximum rate, would continue the protection in the
current regulations. It would protect against the pipelines'
withholding capacity to raise price and would prevent them from price
discriminating between shippers, because all shippers would pay the
market clearing price. It also would help to ensure that the pipelines'
opportunity to recover their cost-of-service is not impaired. However,
such an approach would not help to constrain the pipelines' ability to
exercise market power at prices below the existing cap.
Commenters should address the merits of the potential methods for
dealing with situations in which the requirement to sell capacity
without a reserve price would result in cost recovery problems for
pipelines. Commenters also should address whether solutions should be
determined on a pipeline by pipeline basis or whether there needs to be
a uniform approach applicable to all pipelines.
3. Auction Design
The Commission recognizes the need for the auction to work quickly
and efficiently.74 Shippers buying capacity
[[Page 43000]]
not only want the ability to consummate deals quickly, they also want
the assurance they can acquire capacity in sufficient time to finalize
their gas supply arrangements. The current system, which takes four
hours, and must be completed the day prior to nominations,75
is inadequate to meet the needs of the market.
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\74\ Shippers have complained that the Commission's current
bidding process for capacity release is too cumbersome and slow. See
Secondary Market NOPR, IV FERC Stats. & Regs. Proposed Regulations
at 33,244.
\75\ 18 CFR 284.10(b)(1)(v) (1997), Capacity Release Related
Standards 5.3.2.
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An electronic auction, designed properly, can be efficient and can
operate faster than the current process of sending facsimiles and using
telephones to arrange deals. Electronic auctions used for trading
stocks and other commodities demonstrate this efficiency.
There are a variety of auction formats that would meet the
Commission's criteria as well as provide the speed the market requires.
The Commission ultimately would decide on the proper auction format. It
could do so either through this rulemaking, through a subsequent
proceeding, or by reviewing proposals on a pipeline-by-pipeline basis,
and it requests comment on which approach would be preferable. To
assist the Commission in evaluating potential auction formats, comments
should focus on the details of how the auction or multiple auctions
should be conducted and on whether a uniform auction format should be
applied to all pipelines.
For example, different auction formats could be used for intra-day,
daily, monthly, and longer auctions.76 Auctions for capacity
of one day or less could be held as part of each intra-day nomination
opportunity or could be held continuously, every hour during the
business day. Consideration also should be given to establishing
standardized parameters for recall or other conditions in order to
facilitate trading for daily or intra-day capacity. To further expedite
the daily auction, it could be integrated with the nomination process
using a computerized auction process.
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\76\ The Commission's current regulations, for instance, provide
for longer posting and bidding periods for transactions of five
months or longer than for shorter-term transactions. 18 CFR
284.10(b)(1)(v), Capacity Release Related Standards 5.3.2.
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To accomplish such integration, releasing shippers could submit
nominations establishing the minimum or reserve price or prices at
which they would be willing to sell some or all of their capacity. For
capacity the shipper wanted to use, it could establish a very high
reserve price while for capacity it clearly wanted to release it could
establish a zero reserve price. Bidders would submit nominations with
the price they are willing to pay. Pipelines would be required to offer
the released capacity along with their own available capacity. The
pipeline would then apply Commission-approved procedures to determine a
market clearing price and all bidders submitting bids above this price
would be automatically scheduled.
Auctions for periods longer than a day could use a different
format, while auctions of monthly capacity could employ posting and
bidding periods that would coincide with the industry's monthly gas
purchasing cycle. Longer posting and bidding times might be needed for
auctions of greater than one month.
The Commission also requests comment on whether alternatives to the
comprehensive auction described above would be sufficient to protect
against the exercise of market power. One possibility would be only to
require pipelines to sell available interruptible capacity to the
highest bidder. While such an approach would not cover capacity
releases or sales of pipeline firm capacity, it may be sufficient to
ensure that capacity is not withheld from the market to raise price.
For instance, it would protect against the incentives present in a
duopoly or oligopolistic market in which firm shippers and the pipeline
recognize a mutual interest in withholding capacity. If the releasing
shipper tried to withhold capacity by not releasing it, the pipeline,
under this option, would be forced to sell the resulting interruptible
capacity to the highest bidder. Pipelines already are generally
required to allocate interruptible capacity based on price when they
are unable to satisfy all nominations for interruptible service at the
maximum rate.\77\ While this proposal would expand the requirement to
all transactions, it could be implemented using the same process.
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\77\ See Sea Robin Pipeline Company, 81 FERC para. 61,041, at
61,225 (1997); Pacific Gas Transmission Company, 76 FERC para.61,258
(1996).
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The information the Commission is proposing to require pipelines to
provide is intended to enable the market to effectively monitor
transactions. Indeed, the knowledge that information will be provided
to the market should itself act as a check against anticompetitive
transactions.
D. Information Reporting and Remedies for the Exercise of Market
Power
1. Reporting Requirements
In creating a competitive marketplace, information plays a crucial
role. Equal access to relevant information is necessary for shippers to
make informed decisions about capacity purchases and for markets to
perform efficiently. Market information also is needed so that the
Commission and shippers can monitor transactions to determine if market
power is being exercised.
The information needed by the market, both for decision-making and
monitoring purposes, falls into three general categories: information
on capacity availability, information on the structure of the market,
and information on capacity transactions, such as rates, contract
duration, and contract terms. Information on the amount of capacity
available at receipt and delivery points and on mainline segments as
well as on the daily amount of capacity that pipelines schedule at
these points will help shippers structure gas transactions and cast
light on whether shippers or the pipeline may be withholding capacity.
To assess market structure, shippers and the Commission need to know
who holds or controls capacity on each portion of the pipeline system
so they can determine the number of potential sources of capacity.
Transactional information provides price transparency so shippers can
make informed purchasing decisions as well as permitting both shippers
and the Commission to monitor actual transactions for evidence of the
possible exercise of market power.
The current regulations already require the posting of much of the
needed information. The proposals here would require expansion of these
current reporting requirements, but such expansion appears justified to
give shippers the information they need both for competitive and
monitoring purposes. Moreover, in some cases, the proposals are
designed to ensure that the same information is provided for competing
types of capacity. For instance, detailed information on capacity
release transactions, including the releasing and replacement shipper
names, the rate paid, and points covered by the release are already
being posted at the time of the transaction.78 In contrast,
pipelines are only required to file limited information on their
discount transactions well after the transaction has taken
place.79
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\78\ 18 CFR 284.10(b) (1)(v), Capacity Release Related Standards
5.4.1, 5.4.3.
\79\ 18 CFR 284.7(c) (6).
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[[Page 43001]]
a. Information on Available Capacity. For capacity availability,
the current regulations require posting of information about the amount
of operationally available capacity at points and on the
mainline.80 But, in order to effectively determine whether
capacity is being withheld, information also is needed to show the
total design capacity of the point or segment and the amount scheduled
on a daily basis. The Commission proposes in proposed section 284.14(d)
to add this information to the posting requirements.
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\80\ 18 CFR 284.8(b) (3); 18 CFR 284.10(b) (1) (iv) (1997),
Electronic Delivery Mechanism Related Standards 4.3.6; 18 CFR
284.10(b) (1) (v), Capacity Release Related Standards 5.4.13.
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The Commission also proposes, in proposed Sec. 284.14(d) to require
pipelines to post information on planned and actual maintenance or
system outages that would reduce the amount of capacity available.
While some pipelines currently post such information, it is not
currently a Commission requirement. Shippers can better make decisions
about their use of capacity if they know whether the available capacity
will be reduced on a particular day. Such information will also help in
monitoring capacity withholding by revealing reasons for reductions in
scheduled quantities.
b. Information on Market Structure. With respect to the structure
of the marketplace, pipelines currently file with the Commission, and
post on their Internet web sites, an Index of Customers, which (under
Sec. 284.106(c)(3) of the regulations, new Sec. 284.14(b)) provides
information on the names of shippers holding firm capacity, the amount
of capacity they hold, and the duration of their contracts. But the
Index of Customers does not provide information on the capacity path
held by the shipper, so the data cannot be used to determine which
shippers can compete in providing capacity on segments of the pipeline.
The Commission, therefore, proposes to add a requirement, in proposed
section 284.14(b), to include in the Index of Customers the receipt and
delivery points held under the contract, the zones or segments in which
the capacity is held, and the shipper's contract number. The contract
number is needed on the Index of Customers as well as on the report of
capacity release transactions so capacity can be traced through release
transactions to reveal how much total capacity each shipper holds.
Since the current capacity release requirements do not include the
contract number, the Commission is proposing to require that the number
be provided.
In addition, to permit effective monitoring of the capacity held on
pipelines, it is necessary to know affiliate relationships, which may
affect the amount of capacity held by a single parent entity. The
Commission, therefore, proposes to add a requirement in proposed
section 284.14(b) that pipelines disclose in the Index of Customers any
affiliate relationship between the pipeline and the holder of capacity
and any affiliate relationship between holders of capacity.
Additionally, the Commission would require disclosure of affiliate
transactions in capacity release transactions.81
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\81\ Some pipelines now require disclosure of affiliate
transactions for capacity release transactions. 18 CFR 284.10(b) (1)
(v), Capacity Release Related Standards 5.4.3. This requirement
would become mandatory for all pipelines under this proposal.
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The Commission also is proposing to expand its affiliate
regulations to provide more information to permit monitoring and self-
policing of affiliate transactions. The Commission is proposing to add
a new section 161.3(i) and revise section 284.286(c) to require
pipelines to post on their web sites organizational charts, and job
descriptions, including the names of senior employees,82 for
the pipeline, its marketing affiliates, and gas sales operating
units.83 The pipeline would not be required to include
employees whose duties are purely clerical or those who do not have
access to information concerning the processing or administration of
requests for service (such as employees who operate or repair the
pipeline facilities). The Commission also is proposing to include in
the Internet posting the list of the operating personnel and facilities
shared by the interstate pipeline and its marketing affiliate or gas
sales operating unit. The pipelines currently provide this information
in their tariffs, under Sec. 250.16(b)(1), and this requirement will
make all affiliate information easily available on the Internet. The
Commission has adopted a similar requirement in the electric industry
to help monitor, and protect against, improper communications between
transmission and wholesale merchant function employees.84/
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\82\ Senior employee would be defined as an employee who
supervises non-clerical employees engaged in transmission/
reliability or gas marketing functions.
\83\ Contemporaneously with this NOPR, the Commission is issuing
a final rule adding a requirement to 18 CFR 161.3 requiring
pipelines to post the names and addresses of their marketing
affiliates on their web sites. Reporting Interstate Natural Gas
Pipleline Marketing Affiliates on the Internet, Docket No. RM98-7-
000. For the NOPR, see Reporting Interstate Natural Gas Pipeline
Marketing Affiliates on the Internet, Notice of Proposed Rulemaing,
63 FR 27526 (May 19, 1998), IV FERC Stats. & Regs. Proposed
Regulations para. 32,530 (May 13, 1998). Should the Commission adopt
the regulations proposed in this NOPR, the changes could be
consolidated with the requirement for posting affiliate names and
addresses.
\84\ American Electric Power Service Corporation, 83 FERC para.
61,357 (1998).
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In addition, in the current market, shippers may be using agents or
asset managers to manage their capacity and such managers may be given
wide latitude over the way in which capacity is used. The Commission,
therefore, is proposing to add a requirement in Sec. 284.14(b) that
pipelines disclose such agents or asset managers when they control 20%
or more of capacity in a pipeline rate zone, as well as the rights of
the agent or asset manager with respect to managing the transportation
service. This information would help to show the degree of control over
pipeline capacity that an agent or asset manager may exercise.
c. Transactional Information. Pipelines already provide
transactional information for their own capacity transactions and for
capacity release transactions, although the type of information and the
manner of accessing it differ. For capacity release transactions,
pipelines provide via the Internet the names of the releasing and
acquiring shippers, the price, the receipt and delivery points under
the deal, the quantity of capacity traded, and the duration of the
deal.\85\ This information is posted immediately upon consummation of
the transaction. The information provided about pipeline transactions
is not as complete, nor is it as timely or as easy to access. Pipeline
discount reports are filed, but not posted, 15 days after the close of
the billing period applicable to the transaction and include only the
rate paid and the maximum rate, but do not include any information on
volumes, the receipt and delivery points under the transaction, or the
duration of the deal.\86\
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\85\ 18 CFR 284.10(b)(1)(v), Capacity Release Related Standards
5.4.1, 5.4.3.
\86\ 18 CFR 284.7(c)(6).
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To assure parity of transactional information, the Commission
proposes, as described, to require the pipelines to provide the same
information about their transactions as is currently provided about
capacity release transactions. The Commission recognizes that some
pipelines and shippers have previously expressed concern about posting
information on shipper names to preserve
[[Page 43002]]
confidentiality. However, shipper names currently are posted for
capacity release transactions and the Commission is unable to see how
other shippers can effectively monitor transactions for favoritism if
names are not provided.
In many cases, much of the transactional information would be
provided in a properly designed, transparent short-term capacity
auction. To ensure that the information is provided, the Commission is
proposing to add a new section, 284.14(c), that would require pipelines
to post on their Internet web site, and provide downloadable files of,
transactional information about their own capacity transactions and
released capacity transactions. For firm service, the Commission
proposes that the pipelines provide contemporaneously with the
execution of the contract, the same information already posted for
capacity release transactions: the parties to the contract; the
contract number for the shipper receiving service and for the releasing
shipper; the rate charged under each contract; the duration of the
contract; the receipt and delivery points and mainline segments covered
by the contract; the contract quantity; any special terms and
conditions applicable to the contract; and any affiliate relationship
between the pipeline and the shipper or between the releasing and
replacement shipper. For interruptible transportation, the following
information on a daily basis would be required: the name of the
shipper; the rate charged; the receipt and delivery points and mainline
segments over which the shipper is entitled to nominate gas; the
quantity of gas the shipper is entitled to nominate; and any affiliate
relationship between the shipper and the pipeline.
2. Remedies if the Exercise of Market Power Is Found
While the Commission's proposals should enhance efficient
competition and mitigate market power, the Commission is committed to
take remedial action when pipelines or shippers exercise market power.
Because the facts of each such case would be different, it is difficult
to describe in advance the type of remedy the Commission would impose
if market power is being exercised, and not all remedies would be
appropriate in every case. As a general matter, the Commission's
preference would be to use a structural remedy that would enhance
efficient competition. Examples of such remedies would include revising
contractual provisions that inhibit competition, strengthening the
capacity auction requirement, requiring pipelines to build taps to
increase access to capacity, or conducting auctions to determine
whether sufficient demand exists for additional construction. Another
potential remedy would be to use a benchmark for regulating price
increases based on price changes in comparable competitive markets.\87\
Reimposition of some form of price cap also would be a possible option
if other available remedies are not adequate. Commenters should address
the potential remedies suggested here as well as suggest other possible
remedies.
---------------------------------------------------------------------------
\87\ See Buckeye Pipe Line Company, 53 FERC para. 61,473, at
62,683 (1991) (basing price changes in non-competitive markets on
the changes in competitive markets).
---------------------------------------------------------------------------
IV. Penalties and Operational Flow Orders
A major goal of the changes proposed in this NOPR is to improve
competition in the short-term market both to improve the efficiency of
the market and to protect against the potential exercise of market
power. To improve efficiency and competition across the pipeline grid,
the Commission previously has adopted standards, promulgated by GISB,
as well as the Commission's own standards governing business practices
and electronic communication. But these standards have only partially
addressed the effect that pipeline operational flow orders, tolerances,
and penalties have on competition across the pipeline grid.
Penalties and operational flow orders (OFOs) are necessary tools to
deter shipper behavior that threaten the integrity of the pipeline
system. At the same time, they have a significant effect on efficiency
and competition by restricting shippers' abilities to effectively use
their transportation capacity. As just one example of the interrelation
between penalties and the short-term market, penalty levels can affect
the value of capacity in the short-term market; shippers needing gas
might be willing to buy transportation capacity at any rate less than
the penalty they would have to pay if, for instance, they overran their
contract entitlement. In this section, the Commission considers reforms
to its policies for regulating OFOs and transportation penalties to
ensure that they can continue in their legitimate role of protecting
pipeline integrity, while not unnecessarily limiting or restricting
competition in the marketplace.
These policies have their origin in the regulatory reforms
instituted by the Commission in Order No. 636. To promote competition
in the sales and transportation markets, Order No. 636 required that
pipelines unbundle sales and transportation services. The bundled sales
service provided considerable flexibility for the pipeline in how it
would meet the requirements of its customers, particularly on peak
days. In the implementation of Order No. 636, the Commission was
particularly concerned that the unbundled transportation services be as
reliable as the bundled sales service the pipelines previously
provided.
To address that concern, the Commission accorded each pipeline
considerable discretion and authority to operate its system to ensure
its reliability, particularly during peak and emergency times. One
important tool the Commission has sanctioned is the use by pipelines of
OFOs that can restrict service or require shippers to take particular
actions. As examples, Commission-sanctioned OFOs can: reduce or
eliminate tolerances for imbalances or contract overruns; institute
severe penalties; restrict intra-day nominations; restrict or eliminate
the use of secondary receipt and delivery points; and restrict firm
storage withdrawals and eliminate interruptible storage withdrawals.
Another means the Commission has provided pipelines to protect
system reliability is the approval of tariff penalties designed to
deter shippers from creating imbalances or from overrunning contract
entitlements. The Commission has approved particularly high penalties,
with little or no tolerance for imbalances or overruns, applicable
during peak or emergency periods to protect pipeline reliability. The
Commission also has approved penalties, usually at lower dollar levels
and greater tolerances, applicable during non-peak times to help ensure
that shipper imbalances or overruns do not create emergency conditions
on a pipeline that could have been prevented or minimized.
The Commission believes that a review of present policies and
pipeline practices in these areas is appropriate as part of the new
approach to pipeline regulation proposed in this NOPR-- and
particularly its objective of promoting competition in the short-term
market.
On initial review, it appears that some pipeline practices and
Commission policies regarding penalties can inhibit competition not
only with respect to transportation, but also in the sale of natural
gas. For example, an OFO that eliminates a secondary receipt point for
a shipper may eliminate the shipper's access to alternate suppliers
with the lowest priced gas or force the shipper to
[[Page 43003]]
points where it has no purchase or sales agreements. An OFO that limits
or eliminates a shipper's storage withdrawals may require the shipper
to purchase more costly gas on the spot market if the OFO allows the
shipper to shift to new points. The longer OFOs are in effect, the more
restrictive they become. Across all customers, OFOs may fragment
markets by making it impossible for many potential sales of gas or
transportation services to take place.
High penalties on contract overruns or imbalances as well as low or
no tolerances during peak periods may also operate to limit and distort
market forces. For example, not all shippers have immediate access to
metering information on their imbalances or even the volumes of gas
they receive at their delivery points. This lack of information may
adversely affect shippers in several ways. For example, to avoid
overrun and/or imbalance penalties, shippers may not maximize use of
pipeline transportation, and shippers may contract for more
transportation capacity than they need. Also, the lack of information
on imbalances and delivered volumes may inhibit shippers from trading
imbalances or transportation capacity that could alleviate or prevent
system operational problems.
The presence of severe penalties/tolerances during peak or
emergency periods also may preclude other uses of market forces that
could alleviate or prevent system operational problems. For example, a
shipper that delivers more gas than nominated into a pipeline when the
pipeline is short of gas would help to maintain system integrity. Yet,
under most currently approved tariff provisions, the shipper could be
penalized for doing so.
Moreover, Commission-authorized penalties may provide an
opportunity for shippers to engage in a form of penalty arbitrage. For
example, during the 1995-96 winter there was a shortage of natural gas
to serve Chicago markets. Shippers reacted by intentionally overrunning
contract entitlements on those pipelines and LDCs that had the lowest
penalties for contract overruns. 88 In that situation,
penalties appeared to have skewed choices shippers might otherwise have
made. The consequence was that pipelines in the Chicago area appear to
have entered into bidding wars for the highest overrun/imbalance
penalties, with penalties for large variances running as high as $200/
dth.89
---------------------------------------------------------------------------
\88\ See Industry Surveys the Damage as Winter's Strength Runs
Out, Natural Gas Intelligence, April 22, 1996, at 1; Freezer Burn,
Gas Daily's NG, April 1996, at 30.
\89\ See Panhandle Eastern Pipeline Company, 78 FERC para.
61,202, at 61,876 (1997)(penalties ranging from $25 per Dth for
variances of 5-10% to $200 for variances over 50%).
---------------------------------------------------------------------------
The fluctuation of transportation values also supports a
reexamination of Commission policies on OFOs and penalties. As
discussed earlier, the value of transportation varies widely. For
example, as shown on the earlier graph, during the winter of 1996-1997,
the value of capacity was double the maximum rate, while during the
winter of 1995-1996, spikes occurred on several occasions to much
higher levels, with the highest value reaching $10/MMBtu.90
---------------------------------------------------------------------------
\90\ See text accompanying note 22, infra.
---------------------------------------------------------------------------
The fluctuation in short-term transportation values during peak
periods suggests the need to increase opportunities, as much as
practicable, for shippers to obtain transportation services at the
lowest competitive price during such times. Yet, the pipelines' current
OFO and penalty structures may restrict shippers' options more than is
necessary.
Current pipeline tariff provisions for remedying monthly imbalances
of a shipper--often described as ``cash-outs''-- also appear to inhibit
market forces and may be otherwise unfair. Under these provisions,
shippers are allowed to cash-out net monthly imbalances using an
average monthly price. That procedure invites shippers to game the
system within the month. For example, a shipper may take more than it
delivers when gas prices are high and deliver more than it takes when
gas prices are low. At peak, such behavior may imperil system-wide
reliability and unnecessarily trigger OFOs and emergency penalties that
restrict or eliminate market forces. Such gaming also promotes
inefficient use of pipeline capacity. For example, to the extent gaming
is substantial on a pipeline, the pipeline is likely to react by
imposing stricter imbalance tolerances and higher penalties. Moreover,
gaming by some shippers is subsidized by other shippers. A pipeline's
tolerance and penalty levels are often a function of the amount of
storage it has retained; a pipeline with more storage can tolerate
greater imbalances. But all shippers pay for storage in their firm
rates. Accordingly, if a pipeline reduces tolerances and raises
penalties due to the behavior of some shippers, the firm shippers lose
the flexibility for which they are paying.
The apparent problems associated with current OFO and penalty
tariff provisions suggest the need to reorient policy away from
penalties and towards promoting the opportunities for shippers to avoid
penalties and to prevent penalty situations, particularly by allowing
shippers to avail themselves of remedies that the marketplace can
provide. Such remedies would include the trading of imbalances, the
provision of timely information about system imbalances so shippers can
better anticipate adverse operational conditions and avoid possible
penalties, and no harm no foul rules under which shippers will not be
penalized for actions that help maintain the operational integrity of
the pipeline system. Stated in other terms, while there may always be a
need for penalties and OFOs, the adoption of policies that promote the
opportunity for shippers to avoid penalties and prevent penalty
situations, particularly by reliance on market forces, may be the most
efficient means of ensuring the reliability of a pipeline's system
operations. Towards this end, the Commission, in Order No. 587-G,
recently required pipelines to permit shippers to offset imbalances
across their own contracts and to trade imbalances with other
shippers.91
---------------------------------------------------------------------------
\91\ Standards For Business Practices Of Interstate Natural Gas
Pipelines, Order No. 587-G, 63 FR 20072 (Apr. 23, 1998), III FERC
Stats. & Regs. Regulations Preambles para. 31,062 (Apr. 16, 1998).
---------------------------------------------------------------------------
Accordingly, the Commission proposes to revise section 284.13 of
its regulations to establish the following policies. First, the
Commission proposes to require each pipeline to provide, on a timely
basis, as much information as possible about the imbalance and overrun
status of each shipper and the imbalance of its system as a whole. The
adoption of this policy is a critical first step to enhancing the
opportunities of a shipper to avoid penalties and help prevent penalty
situations. Second, to ensure greater shipper flexibility, the
Commission proposes to require that pipelines have in place only those
transportation penalties that are necessary and appropriate to protect
system operations. Third, the Commission proposes to require that
pipelines provide services, to the extent operationally feasible, that
facilitate a shipper's ability to manage imbalances, which will also
help the shipper avoid penalties and prevent penalty situations.
Finally, the Commission proposes to require pipelines to adopt
incentives and procedures that will minimize the use and potential
negative impact of OFOs.
As discussed below, the Commission solicits comments on these
proposed policies. The Commission also invites
[[Page 43004]]
comments on its assessment, set forth above, of current OFO and penalty
tariff provisions on which the proposed policies are based.
Specifically, the Commission solicits comments on how well these
current tariff provisions protect the integrity of system operations,
the extent to which such provisions have created the problems discussed
above, and whether changes to such tariff provisions are warranted.
A. Pipelines Should Provide, on a Timely Basis, as Much Imbalance and
Overrun Information as Possible
The Commission proposes to require each pipeline to provide, on a
timely basis, as much information as possible about the imbalance and
overrun status of each shipper and the imbalance of its system as a
whole. Providing such information is a critical first step to a new
Commission approach to penalties. To begin with, such information, by
itself, would help shippers avoid overruns and imbalances. Moreover,
providing each shipper with information on the precise level of its
deliveries and imbalances would help the shipper maximize the use of
its transportation rights on the pipeline system. Such information
could also allow the pipelines to reduce the level of penalty-free
tolerances and so reduce system costs (e.g., storage capacity to
provide such tolerances). Finally, such information together with
information on system imbalances would facilitate trading of imbalances
and capacity or other self-help measures that in turn could alleviate
or prevent conditions that imperil system integrity.
Under the proposed regulation, Sec. 284.13(c)(2)(iv), the pipeline
would not be required to install real time meters. The burden on the
pipeline would be limited to distributing on a timely basis--i.e., so
that the shipper has a reasonable opportunity to avoid penalties--the
information the pipeline currently has on deliveries and imbalances at
each shipper's delivery point as well as system imbalances. The
pipeline would be required to establish a system that notifies each
shipper individually of the imbalance/delivery information that the
pipeline possesses or to give shippers access to such information via
the Internet. The pipeline could post relevant system imbalance
information more generally. The obligation that such information be
provided on a timely basis would vary from pipeline to pipeline,
depending on the pipeline's penalties. For example, a pipeline that
imposes imbalance penalties only on a monthly basis would have a
different obligation to provide imbalance information to its shippers
than a pipeline that imposes daily imbalance penalties.
During technical conferences in individual cases, relating to
proposals by pipelines to institute or increase penalties, many
pipelines have provided assurances that they were moving toward better
metering on their system. On the other hand, customers have complained
of the imposition of penalties because existing metering equipment was
insufficient to provide them with timely information on deliveries and
imbalances. An important question raised by the proposed policy is the
manner in which, if at all, the Commission should address the situation
in which a shipper has receipt or delivery points at which there is not
the type of metering and related equipment that would provide the
shipper with timely information on its deliveries and imbalances. The
Commission sets forth below two options and solicits comment on them.
One option, which would be a departure from the proposed policy set
forth above, is to require the pipeline to install the equipment that
would provide all shippers with timely information on imbalances and
deliveries. Important questions that should be addressed when
considering this option are, first, the extent to which such equipment
is not in place today and, second, the extent to which the shippers
without such equipment desire the information that would be provided.
For example, the Commission is aware that marketers and producers have
voiced complaints about the lack of timely information on deliveries
and imbalances. Those complaints suggest that there may be more of a
problem in obtaining timely information at receipt points than at
delivery points.
A closely related and critical question is the cost of purchasing
and installing the equipment that will provide timely information.
Those costs must be compared in some manner to the benefits of
providing the equipment. The question of costs raises a host of other
related questions. For example, who should pay for the equipment--the
pipeline (who could recover the costs in generally applicable rates) or
the shipper? Is it appropriate to require all shippers to have access
to such information? For example, it may be cost effective only for
large shippers. Should the Commission require the metering needed to
provide timely information only at those receipt/delivery points where
the gas volumes are large enough to cover the equipment costs, and
exempt the remaining receipt/delivery points? If so, what alternatives
are appropriate for receipt/delivery points of small shippers to
provide some parity of treatment?
A second option would be to forbid a pipeline from imposing a
penalty for an overrun/imbalance that does not threaten system
reliability unless the pipeline has metering equipment to measure the
imbalance/overrun and notifies the shipper in a timely manner of the
imbalance/overrun. The intent of this option is to give a pipeline an
incentive to install only the metering equipment associated with
imbalances or overruns that may imperil system integrity. The option
also would prevent penalties that a shipper would have been in a better
position to avoid with timely information.
This option also raises the question of who should bear the costs
of the enhanced metering and related facilities. Another relevant
concern is the extent to which the option could be implemented--is
there an objective basis to determine which penalties are required, and
in what situations, to prevent realistic threats to a pipeline's system
integrity?
The Commission solicits comments on its proposal, the alternative
options, and the related questions. The Commission also solicits other
alternative proposals that commenters believe merit consideration.
B. Transportation Penalties Must Be Necessary and Appropriate to
Protect System Operations
The Commission proposes to require that pipelines have in place
only those transportation penalties that are necessary and appropriate
to protect system operations. The Commission has authorized extremely
high overrun and imbalance penalties for several pipelines on the basis
that doing so was required to protect system integrity.92
The Commission questions whether there is necessarily a connection
between the high level of penalties that have been authorized and the
level that is necessary to ensure system reliability. Also, the
Commission is aware that some pipelines have penalties that are at the
same level during peak and non-peak periods and may be imposed
regardless of whether the pipeline is faced with emergency
conditions.93 In light of these considerations, the
Commission solicits comments on
[[Page 43005]]
whether currently effective penalties are the most appropriate and
effective penalties to protect system operations. The Commission also
solicits comments on the specific criteria the Commission should rely
on in determining what penalty provisions would be the most appropriate
and effective.
---------------------------------------------------------------------------
\92\ See Northern Natural Gas Company, 77 FERC para. 61,282, at
62,236 (1997); Panhandle Eastern Pipeline Company, 78 FERC para.
61,202, at 61,876-77 (1997), reh'g denied, 82 FERC para. 61,163
(1998).
\93\ See Tennessee Gas Pipeline Company, 81 FERC para. 61,266,
at 62,312; reh'g denied, 83 FERC para. 61,063, at 61,335 (1998)
(contrasting a penalty based on spot pricing which varies penalty
levels in response to market conditions with other pipelines with
fixed penalty levels).
---------------------------------------------------------------------------
There are many specific options the Commission may pursue in this
area on which comments are requested. One option would be to require,
on an industry-wide basis, penalties that are not set at specific
dollar levels, but instead reflect the varying gas commodity prices
that are available to the shipper--for example, a regional index plus
an adder. The use of such indices could allow a more effective
deterrence based on current market conditions. For example, a penalty
based on commodity prices might eliminate a recurrence of the situation
during the 1995-96 winter in the Chicago market where shippers sought
to overrun contract entitlements on the pipeline system with the lowest
stated dollar penalty.
A related option is for the Commission to establish procedures that
would allow all segments of the natural gas industry to form a
consensus, to the extent practicable, on penalty tariff provisions that
could be uniform either on a national or regional basis. Such
provisions could:
define the particular penalties and to whom they would
apply;
implement cash-out provisions on all pipelines;
set tolerance levels;
determine the time periods when the penalties would be
applicable;
define the time periods to notify shippers of penalties;
and
allow make-up and/or trading of imbalances.
A prominent concern underlying this option is to eliminate the
gaming where a shipper shifts capacity use among pipelines to overrun
its rights on the pipeline that has the lowest level of penalties.
Setting uniform standards for penalty provisions should reduce this
gaming problem and the incentive for a pipeline to adopt ever more
onerous penalty provisions to avoid having the least onerous penalties
in an area or region.
Another objective underlying this option is to eliminate the
adverse effects on competition that are caused by the fact that penalty
provisions vary from pipeline to pipeline. Such variation gives rise to
administrative costs and uncertainty and acts as a disincentive for
shippers seeking alternative suppliers of gas and transportation
services.
The Commission has successfully prompted, by adopting
recommendations of GISB, the standardization of many of the operating
rules of interstate pipelines to enhance competition. In that regard,
the Commission stresses that the intent of this option is not to
determine standardized penalty provisions as part of the rulemaking,
but rather to initiate a process in which a consensus may be achieved.
The Commission solicits comment on whether the industry could develop
such standards through GISB or whether the Commission would need to
establish its own process for developing the standards.
A variant of the last option is to establish procedures that would
also include state representatives that could facilitate the
coordination of (a) penalty provisions used by interstate pipelines
with (b) penalty provisions that are used by state regulated entities--
LDCs, Hinshaw and intrastate pipelines. The Commission believes that
such coordination would better address the problem of gaming as well as
enhance competition in both the sales and transportation of natural
gas. State regulators are particularly invited to comment on the
desirability of this option as well as to suggest procedures to
implement it.
In addressing the proposals to develop a consensus process,
commenters should provide their views on the practical extent to which
certain types of penalty provisions can be standardized. For example,
it may be impractical to adopt particular levels of penalties or
tolerances on a national or even regional basis, given the different
operational characteristics of each pipeline. The Commission also seeks
alternative proposals to developing a consensus process that would
address the goals, described above, of eliminating gaming and the
administrative costs and uncertainty that arise due to the fact that
penalty provisions vary from pipeline to pipeline.
Another option would be to provide an automatic credit to shippers
for a significant portion of the imbalance or contract overrun penalty
revenues a pipeline collects. Such a credit would not be provided to
those shippers that incurred the imbalance or overrun penalty. Current
Commission policy is not to provide an automatic credit, but to take
such penalty revenues into account in a rate case to develop a
pipeline's revenue requirement. Customers of pipelines have often
complained that such an approach is inappropriate when pipelines are no
longer required to file rate cases on a periodic basis. Those customers
argue that to the extent the penalty revenues are not reflected in
rates, penalty provisions act as a profit center for pipelines.
Crediting penalty revenues would eliminate an incentive for pipelines
to propose unnecessarily high levels of penalties or provisions that
unduly restrict the transportation rights of a shipper.
The Commission invites comments on the extent to which there is a
need to provide an automatic credit of penalty revenues. The Commission
is particularly interested in comments on the extent to which penalties
are, or are not, a significant source of pipeline revenues. The
Commission is also concerned that the crediting of penalty revenues to
specific non-offending shippers may be difficult to implement. The
Commission seeks comments on whether such crediting can be implemented
without substantial administrative cost. The Commission also solicits
proposals for a specific mechanism for crediting penalty revenues.
Another option on which the Commission solicits comments is the
desirability of revising the manner in which a shipper's cash-out
payment is determined. As discussed, current cash-out procedures
establish a payment based on the average price of gas for a given
month, which has induced shippers in some instances to game the
pipeline system to take advantage of changes in the price of natural
gas. A revision that could eliminate such gaming would be to require
the pipeline to provide a running imbalance of each shipper for each
day of the month. The imbalance would be defined not in volumes, but in
imbalance revenues, which would be the product of the shipper's volumes
of imbalance that particular day times that day's gas index price. One
concern this option raises is whether it would require pipelines to
install additional or enhanced meters and, if so, whether the costs of
doing so would outweigh the benefits of resolving the problems
associated with the gaming of the system.
The Commission solicits comments on its proposal, the alternative
options, and the related questions. The Commission also solicits other
alternative proposals that commenters believe merit consideration.
C. Pipelines Must Provide Services, to the Extent Operationally
Feasible, That Facilitate Imbalance Management
An expansion of the number of imbalance management services would
reduce the need for penalties and the imposition of unnecessary
penalties.
[[Page 43006]]
The Commission has recently taken a first step in this direction in
Order No. 587-G 94 when it required pipelines, inter alia,
to
---------------------------------------------------------------------------
\94\ Standards For Business Practices Of Interstate Natural Gas
Pipelines, Order No. 587-G, 63 FR 20072 (Apr. 23, 1998), III FERC
Stats. & Regs. Regulations Preambles para. 31,062 (Apr. 16, 1998).
---------------------------------------------------------------------------
allow firm shippers to revise nominations during the day
(thereby reducing the probability of imbalances caused by inaccurate
nominations);
enter into operational balancing agreements at all
pipeline to pipeline interconnections;
permit shippers to offset imbalances across contracts and
trade imbalances amongst themselves when such imbalances have similar
operational impact on the pipeline's system; and
provide notice of OFOs and other critical notices by
posting the notice on their Internet web sites, which would be
accessible to shippers nationwide and by notifying the affected
customers directly.
In this section the Commission proposes to require pipelines to
revise their tariffs to expand the number of imbalance management
services and opportunities available to shippers. Parking (temporary
storage) and lending (temporary loan of gas) are currently offered by
several, but not all, pipelines and allow shippers to avoid imbalances.
Under the proposal, a pipeline would be required to provide such
services if operationally practicable. In addition, a pipeline would be
required to revise or eliminate any tariff provision that gives undue
preference to its storage or balancing services over such services that
are provided by a third party. In response to the tariff filing,
parties could protest the proposals and propose alternatives for
Commission consideration.
The Commission solicits comments on whether more specific
requirements or additional initiatives would be appropriate. One
prominent area of inquiry is the manner and extent to which the
Commission should encourage the availability of parking and lending as
well as alternative services. Some incentives are already provided for
in this NOPR. For example, because parking and lending are short-term
services, providers of such services would not be subject to a rate
cap. The Commission could also facilitate the use of third-party
storage by specifically requiring that a pipeline's transportation
charges for long-term services related to injection and withdrawal of
gas that comes from third party storage must be the same as the charges
that apply for long-term services when the gas comes from the
pipeline's own storage facilities.
The Commission could also adopt policies that promote individual
shipper actions that alleviate system imbalances or operational
constraints. For example, the Commission has recently established a
``no harm, no foul'' policy that would permit beneficial imbalances to
escape penalties.95 Such a policy is especially important in
emergency or peak periods, when a shipper's imbalance can run in the
opposite direction from the conditions adversely affecting the
pipeline. A shipper with such a beneficial imbalance (one that runs in
the opposite direction of the imbalance that adversely affects the
pipeline system) is aiding rather than adversely affecting the system
at a critical time. For example, a shipper might be taking less than it
nominated on a pipeline that was suffering from significant overtakes
of gas. This policy prohibits a pipeline from penalizing a shipper to
the extent that such ``good'' behavior can be tracked.
---------------------------------------------------------------------------
\95\ Panhandle Pipe Line Co., 82 FERC para. 61,163, at 61,600-
601
---------------------------------------------------------------------------
A variation of a ``no harm, no foul'' policy would be to go beyond
immunizing a shipper running a beneficial imbalance from penalties, and
to reward such shippers especially during emergency time periods. On
the other hand, in Order No. 587-G the Commission has required
pipelines to permit shippers to net imbalances across contracts and
trade imbalances with other shippers. In light of these requirements,
would rewarding shippers running beneficial imbalances provide
significant additional benefit?
The Commission solicits comments on its proposal, the alternative
options, and the related questions. The Commission also solicits other
alternative proposals that commenters believe merit consideration.
D. Pipelines Must Adopt Incentives and Procedures That Minimize the Use
and Adverse Impact of OFOs
Finally, the Commission proposes to require each pipeline to adopt
incentives and procedures that minimize the use and adverse impact of
OFOs. The imposition of OFOs may severely restrict the purchase and
transportation alternatives available to a customer during peak
periods, precisely when such alternatives are critically needed to
enhance the opportunities of a shipper to purchase such services at the
lowest competitive prices. Under current practice, pipelines have
incentives to favor OFOs as the first option, not the last resort. The
pipeline is likely to err on the side of using an OFO, because it bears
the risk that if it does not, curtailment of load may result that could
in turn precipitate strong public disapproval and law suits from firm
customers. In contrast, shippers--not pipelines--bear the costs that
result from imposition of OFOs. A pipeline could also prefer OFOs
because it would limit or eliminate a shipper's option to purchase
transportation that would be in lieu of transportation services
provided by that pipeline. In technical conferences, shippers have
complained that OFOs have been issued too frequently, for too long, and
were larger in scope than required to protect the integrity of system
operations.96
---------------------------------------------------------------------------
\96\ See, e.g., NorAm Gas Transmission Company, 79 FERC para.
61,126, at 61,546-47 (1997); Southern Natural Gas Company, 80 FERC
para. 61,233, at 61,890 (1997) Northern Natural Gas Company, 77 FERC
para. 61,282 (1997); Panhandle Eastern Pipeline Company, 78 FERC
para. 61,202 (1997); Northwest Pipeline Company, 71 FERC para.
61,315 (1995).
---------------------------------------------------------------------------
In light of these considerations, it is appropriate to review
existing pipeline tariffs to ensure that the resort to, and adverse
impact of, OFOs are reduced to the maximum extent practicable. The
Commission therefore proposes to require each pipeline to revise its
tariff to the extent necessary to:
state clear standards, based on objective operational
conditions, for when OFOs begin and end; 97
---------------------------------------------------------------------------
\97\ For example, if a pipeline anticipates an OFO will be in
effect until weather conditions change, it would aid shippers'
planning to so advise them.
---------------------------------------------------------------------------
require the pipeline to post, as soon as available,
information about the status of operational variables that determine
when an OFO will begin and end; 98
---------------------------------------------------------------------------
\98\ For example, if an OFO will remain in effect until repairs
are completed on a compressor, the pipeline should be required to
update shippers on the status of the repairs.
---------------------------------------------------------------------------
state the steps and order of operational remedies that
will be followed before an OFO is issued to assure that the OFO has the
most limited application practicable and to limit the consequences of
its imposition; 99
---------------------------------------------------------------------------
\99\ For example, one requirement would be that a pipeline
provide as much advance warning as possible of the conditions that
may create an OFO and the specific OFO itself that would allow
customers to respond to such conditions and/or prepare alternative
arrangements in the event the OFO is implemented.
---------------------------------------------------------------------------
set standards for different levels or degrees of severity
of OFOs to correspond to different degrees of system emergencies the
pipeline may confront; 100 and
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\100\ For example, a $100 OFO penalty may be appropriated in
severe cases, whereas a $25 OFO penalty may be appropriate in
others.
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establish reporting requirements that provide information
after OFOs are
[[Page 43007]]
issued on the factors that caused the OFO to be issued and then lifted.
In response to the tariff filing, parties could protest the
proposals and propose alternatives for Commission consideration.
The Commission requests comments on the proposal set forth above.
The Commission is particularly interested in comments on the extent to
which current OFOs have created significant problems and, if so, the
specific problems that were created.
The Commission also solicits comments on additional or alternative
options. One such option would be to use financial incentives based on
the past OFO experiences of a pipeline to minimize future imposition of
OFOs. For example, a pipeline that never issues OFOs could be allowed
to retain a portion of cash-out penalties, which under current
Commission policy would be automatically credited to its customers.
Conversely, a pipeline that frequently issues OFOs could be required to
rebate a portion of the customer's reservation charges if it does not
fix within a reasonable time the operational problems that give rise to
frequent OFOs. The Commission solicits comments on the adequacy of such
incentives and also solicits alternative incentives.
Another option would be to require automatic crediting of OFO
penalties, even if the Commission retains its current policy of not
requiring pipelines to credit most penalty revenues. As discussed,
currently pipelines have incentive to impose OFOs as a first reaction
to a system operational problem. Requiring the automatic crediting of
OFO penalties would at least eliminate one potential incentive.
Another option is for the Commission to institute a program that
monitors on a periodic basis the frequency of impositions by each
regulated pipeline of OFOs. If the Commission determines that an
individual pipeline frequently issues OFOs, the Commission could audit
the pipeline's operations or establish a proceeding to determine if
changes should be made to the pipeline's tariff.
The Commission solicits comments on its proposal, the alternative
options, and the related questions. The Commission also solicits other
alternative proposals that commenters believe merit consideration.
V. Negotiated Rates and Services
Two of the objectives of the regulatory changes proposed in this
NOPR are to promote greater innovation in service offerings, and to
increase the value of long-term capacity as protection against price
swings in the short-term market. As explained below, allowing the
negotiation of rates and services can provide the flexibility necessary
to foster service innovation. The negotiation of rates and services
also has the ability to increase the attractiveness of long-term
capacity, so that biases toward short-term capacity are weakened. In
this manner, negotiated rates and services can help achieve the
Commission's goal of creating a more neutral regulatory policy with
respect to short-term and long-term capacity.
Permitting pipelines to negotiate the terms and conditions of
service with their customers can have several beneficial effects.
First, permitting negotiated terms and conditions of service may spur
innovation and creativity in the services provided, and keep natural
gas transportation service from becoming stagnant. Traditional
regulation does not always allow for innovation and gives regulated
companies little incentive to be creative or to innovate. For example,
conventional tariff procedures may inhibit the development of
innovative services, since the need for such services may be immediate
and may arise quickly. Therefore, presently, neither pipelines,
customers, nor regulators know with certainty what innovations are
feasible, or would be worth their cost.
A policy that permits pipelines to negotiate rates and terms of
services together may give pipelines more incentive to innovate by
allowing pipelines to charge more for innovations that customers value
more. Also, the ability to negotiate rates and services may stimulate
pipelines to offer service innovations that are relatively costless to
provide, something they may have had little incentive to do under cost-
based rates. These innovations should ultimately improve the quality of
the pipelines' other tariff services, if pipelines are given incentives
to maintain and upgrade these services, as well.
Second, while the negotiation of service may be useful for short-
term services, its most significant use may be as a valuable risk
management tool for pipelines and customers with respect to long-term
contracts.
When a customer enters into a long-term contract, it must undertake
a number of risks. It must bear the general market risk that the value
of capacity may decrease in time, so that the customer could have
acquired the capacity for a lower rate later, or the risk that the
pipeline will experience a decrease in system throughput, which would
drive the maximum regulated rate up. The customer must bear the
regulatory risk that the rates for the capacity that it has committed
to under the firm contract will increase due to, for example, the
rolling-in of the costs of new capacity construction, or other general
rate increases. The customer must also bear the customer-specific risk
that its own need for capacity might fluctuate or disappear.
When these risks are too high for a customer, at the given rates
for long-term and short-term capacity, the customer may be unwilling to
hold long-term capacity contracts. In the past, shippers accepted some
regulatory price risk in return for little or no gas supply risk. Now,
however, shippers appear less willing to shoulder the price risks
associated with long-term contracts as a result of the increased
attractiveness of short-term contracts, the presence of regulatory
disincentives to long-term contracts, such as the right of first
refusal, and the uncertainty of potential business impacts of state
retail open-access programs. The movement away from long-term contracts
increases the pipeline's risk that it will not earn enough revenues
during the pipeline's useful life to cover its total cost and an
acceptable return on the investment in the pipeline.
Allowing pipelines and shippers to negotiate terms and conditions
of service, as well as rates, may permit greater flexibility in the
allocation of the shipper's risk inherent in long-term capacity
contracts. Such negotiation of rates and services could permit the
parties to negotiate more flexible contracts for higher rates. Other
options for negotiation could include lower rates for longer contract
terms, differing rates for the right to reopen the contract in
specified contingencies, or varying rates for different payment
schedules.
Thus, a negotiated rates and services policy may give parties the
ability to negotiate terms that will reduce the shipper's risk in
entering into a long-term contract, thereby increasing a shipper's
willingness to execute long-term contracts and encouraging greater
long-term contracting, generally. This, in turn, raises a third benefit
of allowing negotiated terms and conditions of service. As the value of
long-term contracts increases, and more long-term contracts are
executed, problems of capacity turnback may be alleviated. Negotiated
rates and services may give pipelines the ability to attract new
customers and keep existing customers as long-term contracts expire,
helping to ensure that pipelines are able to recover their long-term
investment costs. Such negotiation is especially important as
[[Page 43008]]
markets increasingly define the value of capacity.
Further, certain additional, indirect benefits can result from
permitting negotiated services. A policy favorable to negotiated
services may facilitate the unbundling of LDC services at the state
level, thereby extending customer choice to more retail markets
nationwide. It may also position the gas industry to be a viable
competitor of the increasingly competitive electric industry for end
use customers.
While the Commission recognizes the important benefits that would
result from a negotiated rates and services policy, the Commission is
also mindful that significant, although probably manageable, concerns
exist in permitting negotiated services. Pipelines will exercise market
power if they can. The concept of negotiated rates and services--under
which shippers and pipelines would be able to negotiate rates or
service terms and conditions that deviate from those in the pipeline's
otherwise applicable tariff--relies on the theory that shippers would
be able to choose a ``recourse'' rate or service from the pipeline's
tariff as an alternative to negotiating with the pipeline. In this way,
the recourse service would act as a check on the exercise of the
pipeline's market power. Nevertheless, the negotiation of rates and
services, by its nature, gives pipelines the ability to treat customers
differently, and thereby could facilitate a pipeline's ability to
segregate customers and exercise market power.
A pipeline with market power might be able to force captive
customers to pay for unwanted terms or conditions of service by
bundling them with desired services, or to pay for basic services at
premium prices. The Commission is concerned that permitting the
negotiation of service could give pipelines an incentive to degrade the
quality of recourse services in order to sell other services on a
negotiated basis.
Another way pipelines could exercise their market power with
negotiated services is by unduly discriminating against certain
customers. Some level of discrimination, or differentiation, among
customers is inherent to the concept of negotiating differing rates and
terms of service. However, the Commission is concerned that pipelines
could give undue preference to affiliates or other customers in the
offering of negotiated services.
Further, the Commission is keenly aware of the natural tension that
exists between allowing negotiated rates and services, on the one hand,
and ensuring the tradability of capacity, on the other hand. The
negotiation of terms and conditions of service could make capacity less
tradable and deter the Commission's goal of promoting competition in
capacity markets.
Many of these concerns were raised in response to the Commission's
``Request for Comments on Alternative Pricing Methods'' in Docket No.
RM95-6-000.101/ These concerns were part of the reason that
the Commission was reluctant, in its subsequent ``Statement of Policy
and Request for Comments'' in Docket Nos. RM95-6-000 and RM95-7-000, to
allow the full range of negotiation, and therefore, declined to permit
the negotiation of terms and conditions of service as part of its
negotiated rates policy at that time.102/ However, since
then, the Commission has had the benefit of the additional industry
comments filed in Docket No. RM95-7-000, and has undertaken a thorough
review of its natural gas policies. The Commission now recognizes that
the concept of negotiated rates and services, taken together with the
other proposals in this document, has the potential to improve the
Commission's regulatory framework for natural gas pipelines.
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\101\ / Alternatives to Traditional Cost-of-Service Ratemaking
for Natural Gas Pipelines, 60 FR 8356 (Feb. 14, 1995), 70 FERC ]
61,139 (1995).
\102\ / Alternatives to Traditional Cost-of-Service Ratemaking
for Natural Gas Pipelines, and Regulation of Negotiated
Transportation Services of Natural Gas Pipelines, 61 FR 4633 (Feb.
7, 1996), 74 FERC para. 61,076 (1996).
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Given the above concerns, the Commission concludes that the
benefits to increased service innovation and long-term contracting that
can result from the negotiation of terms and conditions of service,
together with rates, are valuable, but only if they do not come at the
expense of the interests of recourse ratepayers, or hinder the
development of competitive markets.
Accordingly, the Commission proposes to implement a policy
permitting the negotiation of rates, terms, and conditions of service
for transportation services that will be governed by a set of guiding
principles designed to protect recourse and captive customers from the
exercise of market power, prevent undue discrimination and preference,
and foster competition in the interstate capacity
markets.103 These proposed guiding principles, as described
below, will provide limits and conditions on the negotiation of rates
and services that should minimize the risk of potential harm to
recourse shippers and capacity markets, and thereby help ensure that
the benefits of the negotiated rates and services policy outweigh such
risks.
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\103\ See Sec. 284.11 of the proposed regulations.
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The Commission is seeking comment on whether to permit the
negotiation of services in the short-term market. As the short-term
market develops, it can be argued that the benefits of negotiated
services are especially important to the short-term market, provided
that such negotiation does not impair the tradability of short-term
capacity. A number of expected benefits to the market may flow from
allowing the negotiation of short-term services. Short-term peak market
conditions arguably require a maximum amount of flexibility and
customization for shippers. On the other hand, the Commission has not
resolved how the negotiation of short-term rates and services could be
coordinated with the capacity auction process proposed in this NOPR.
Typically, auctions involve the trading of standardized products and
services, whereas negotiated services may not be sufficiently tradable.
The Commission proposes to address this issue in the final rule,
and seeks analysis and comment on the alternatives of whether to permit
or prohibit the negotiation of terms and conditions of service in the
short-term market. Should the negotiation of services be reserved for
the long-term market? Can negotiation of services be accomplished in
combination with the auction process? What effect would the negotiation
of short-term services have on the tradability of short-term capacity?
What are the benefits to the marketplace of permitting negotiation in
the short-term market?
In addition, while the Commission is proposing in this NOPR to
permit negotiated rates, terms, and conditions of service under the
principles below, the Commission also proposes to conduct a generic
review of the negotiated services after they have been in effect for
two winter heating seasons.
A. Guiding Principles
The Commission is proposing to permit the negotiation of any rate,
or term or condition of service for transportation services to the
extent :
It does not result in undue discrimination or preference;
It does not degrade the quality of existing services;
It does not hinder the release of capacity, or otherwise
significantly reduce competition;
Pipelines do not require customers to take negotiated
transportation services tied with any unwanted sales, storage, or
gathering services provided
[[Page 43009]]
by the pipeline, its affiliates, or upstream or downstream entities;
and
The terms of the negotiated transactions are made publicly
available.
These general guiding principles will provide the boundaries within
which the industry may conduct negotiations of rates and services, and
will be applied on a case-by-case basis. They will also give the
Commission, and the industry, a basic foundation for evaluating future
negotiated deals that cannot be envisioned currently. Establishing more
specific or restrictive guidelines could limit, in the future, the
degree of innovation that potentially could be achieved.
Further, the Commission proposes that if a pipeline violates any of
these proposed guiding principles, the Commission would revoke that
pipeline's authority to negotiate rates and services. Establishment of
this penalty up-front for violating the guidelines of the negotiated
rates and services policy should serve as an incentive for compliance.
In addition, the traditional remedies available under the NGA would
also be available to the Commission to use.
Each of the proposed guiding principles is discussed more fully
below.
1. No Undue Discrimination or Preference
The Commission is particularly concerned that the negotiation of
rates and services does not violate the statutory prohibition against
undue discrimination and preference in the NGA.104 The very
nature of negotiated rates and services is to provide some customers
rates and services that differ from those provided to others. However,
the negotiation of rates and services under the proposed policy cannot
be unduly discriminatory or preferential. Practically speaking, under
existing undue discrimination standards, this would require that
``similarly situated'' shippers have rights to the same negotiated
deal. The cases in which the Commission has applied the ``similarly
situated'' standard in the past provide some guidance on the meaning of
``similarly situated'' shippers.105
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\104\ See Section 4(b) of the NGA. 15 U.S. C. 717c (1994).
\105\ See Tennessee Gas Pipeline Company, 77 FERC para. 61,877
(1996) (requiring the pipeline to file specific information to
enable shippers to determine if they are similarly situated to
particular negotiated rate customers, including the type of service,
the receipt and delivery points applicable to the service, and the
volume of gas to be transported); and Standards of Conduct and
Reporting Requirements for Transportation and Affiliate
Transactions, 59 FR 32885 (June 27, 1994), FERC Stats. & Regs. para.
30,997 at 31,067-68 (1994) (Order No. 566) (requiring pipelines to
post particular information on their EBBs regarding affiliate
discounts, including quantity and point data, to enable non-
affiliates to determine if they are entitled to a similar discount).
See also, Iroquois Gas Transmission System, L.P., 79 FERC para.
61,394 (1997), reh'g denied, 82 FERC para. 61,086 (1998) (holding
that the pipeline may not charge new expansion shippers and existing
shippers different rates, based on findings that differences between
each shipper group stemming from the time when each group came on
the system, such as differences in receipt and delivery points or
available competitive alternatives, were insufficient to justify
disparate treatment); and El Paso Natural Gas Company, 62 FERC para.
61,311 at 62,990-91 (1993), followed in ANR Pipeline Company, 66
FERC para. 61,340 at 62,130-31 (1994) and Questar Pipeline Company
v. PacifiCorp, 70 FERC para. 61,328 at 62,009 (1995) (shippers
holding discounted rate contracts between certain primary points do
not have the right to use alternate points at the discounted rate,
since the market conditions may not be the same at the primary and
alternate points).
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Nevertheless, the Commission recognizes that clear guidelines, or
standards, on what constitutes undue discrimination or preference in
negotiating rates and services may need to be established before any
negotiation takes place so that the industry can abide by this
principle. Such up-front standards could provide guidance to pipelines
and shippers about acceptable negotiation practices, eliminating
confusion about what does and does not constitute permissible conduct,
and could minimize the risk of discrimination occurring before
standards emerge from a case-by-case complaint and review process. The
standards may also be critical to effective monitoring and enforcement.
While the Commission is considering developing such generic undue
discrimination guidelines, such standards could prove difficult to
craft, since undue discrimination findings usually depend on specific
facts and often are subject to widely varied and subjective
interpretation. Thus, the Commission seeks comment on the need for, and
feasibility of, its developing clear standards on what constitutes
undue discrimination or preference before negotiations are permitted to
occur. The Commission further requests commenters to discuss what
should be the standards for undue discrimination, including whether the
``similarly situated'' standard should continue to be used, and if so,
how that term should be defined.
2. No Degradation of the Quality of Existing Services
A core concern of captive customers, shared by the Commission, is
the effect a negotiated rates and services policy could have on the
quality of service that recourse shippers receive. Permitting the
negotiation of particular terms and conditions of service might, in a
direct way, adversely affect the quality of one or many recourse
shippers' service. For example, negotiations to loosen a pipeline's
imbalance provision for some shippers may force the tightening of
allowed tolerances for others.
Therefore, the Commission proposes to permit the negotiation of
rates and services as long as the quality of service for recourse
shippers is not diminished or degraded. The Commission's objective in
proposing this principle is to prevent pipelines from negotiating
services at the expense of service quality for recourse shippers.
3. No Impairment of the Tradability of Capacity
The negotiation of terms and conditions of service could impair or
reduce competition in capacity markets. This may happen either because
service may become defined so differently that capacity is no longer
fungible, or because customers voluntarily give up the rights that make
trading possible in exchange for a rate reduction. This, in turn, could
diminish the degree of competition in capacity markets generally, or in
some specific markets.
Therefore, to guard against this, the Commission proposes to permit
the negotiation of rates and services as long as such negotiation does
not impair tradability of capacity, result in a significantly greater
concentration of sellers in capacity markets, or otherwise
significantly reduce existing competition. Since the full range of
innovation that might occur under the negotiated rates and services
policy cannot be known at this time, it may be that shippers will be
able to develop negotiated services that do not impair the tradability
of capacity. To help enable shippers to release negotiated services,
mechanisms may be developed which allow negotiated service to revert to
standard service at the releasing shipper's option when released to
another shipper.106
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\106\ This is discussed more fully below.
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4. No Unwanted Tying Arrangements
One of the Commission's objectives in Order No. 636 was to prevent
the exercise of market power over transportation from being extended to
the sale of natural gas, through the tying of the two different
services. The negotiation of terms and conditions of service can raise
new issues in this regard. Permitting pipelines to negotiate
individualized services may prompt pipelines to require customers to
take packages of service, either from the pipeline, its affiliate, or
another entity,
[[Page 43010]]
that include both transportation and sales services that are currently
available separately. Similar concerns arise from attempts to bundle
transportation with unwanted storage or gathering services. Allowing
pipelines to force customers to take tied services could adversely
affect commodity markets that are currently competitive, or competition
between sellers of capacity, and could lead to increased preferences
for affiliates.
Therefore, the Commission proposes that a pipeline may not require
that a negotiated transportation service be tied with any unwanted
sales service or other services provided by the pipeline, its
affiliate, or by any upstream or downstream entity, unless that service
is necessary to the provision of the negotiated transportation service.
While the Commission does not envision that the tying of gathering or
sales service to the transportation service would be necessary to the
transportation service, there may be instances where storage service
could be a prerequisite for the pipeline's ability to provide the
negotiated transportation service.
5. Transparency of Negotiated Transactions
The Commission proposes to require that the essential elements of
negotiated transactions, including price, be transparent to the public
and the Commission. The full disclosure of the terms of the negotiated
transactions is critical to the ability of shippers and the Commission
to detect, and deter, the exercise of market power and undue
discrimination and preference. The transparency of negotiated
arrangements also enables shippers to make informed purchasing
decisions.
The need for transparency has guided the Commission's development
of the proposed procedures for implementing a negotiated rates and
services policy. Thus, as discussed infra, the Commission is proposing
to require pipelines to file with the Commission and serve on firm
shippers, written notice of all essential information about a
negotiated transaction prior to the transaction taking effect. The
Commission is also proposing to increase its existing reporting
requirements.
B. Implementation of the Negotiated Rates and Services Policy
1. Procedural Mechanism
The American Gas Association (AGA), on behalf of itself and the
Interstate Natural Gas Association of America (INGAA), proposed to the
Commission, by letter dated May 4, 1998, a method for implementing a
negotiated services policy. AGA/INGAA's proposed method would entail
each pipeline making an initial ``benchmark'' filing, prior to its
first negotiation of service, that would (a) set forth certain terms or
conditions of service that could not be negotiated absent 30 days prior
notice, and (b) establish a high standard for quality and reliability
of recourse service, as well as better define essential elements of the
pipeline's tariff. Then, after Commission approval of the initial
benchmark filing, the pipeline would be able to implement, after 10
days prior notice, negotiated deals containing items not identified in
the initial filing as requiring 30 days prior notice. The Pipeline
Transportation Customer Coalition (Coalition), comprised of end users,
marketers, producers, and municipal distributors, filed with the
Commission a letter opposing AGA/INGAA's negotiated services proposal
and more broadly, the concept of negotiated services.\107\
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\107\ See June 17, 1998 letter of the Pipeline Transportation
Customer Coalitation filed in Docket No. PL97-1-000.
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As discussed above, the negotiation of rates and services can serve
a valuable role in the Commission's proposed new regulatory approach.
While the Commission acknowledges the potential risk of harm to
competitive markets and recourse shippers, that risk appears to be
manageable. Therefore, the Commission is proposing a method for
implementing negotiated services that has some similarity to aspects of
AGA/INGAA's proposed method.
The Commission is proposing to require a pipeline interested in
negotiating terms and conditions of service to make an initial filing
requesting authority to negotiate rates and services on its system.
This initial filing would accomplish two equally important functions.
First, it would define and establish a high quality recourse
service.\108\ Second, the initial filing would establish the parameters
of permissible and impermissible negotiation for that pipeline in
advance of any negotiation of service or implementation of negotiated
services. This would be accomplished by the pipeline identifying
categories of non-negotiable, negotiable, and potentially negotiable
terms or conditions of service, as described in more detail below. The
Commission would closely scrutinize the proposed categories of terms
and conditions of service, particularly the terms and conditions of
service included within the negotiable category, to ensure consistency
with the proposed guiding principles. For example, the Commission would
analyze whether the negotiation of the negotiable items could adversely
affect the quality of other services or the tradability of capacity,
and whether additional terms and conditions should be included in the
non-negotiable category. Interested parties would have the opportunity
to comment on and protest any aspect of the initial filing, and the
Commission would carefully consider all such comments and protests.
Only after such review, and Commission approval of the initial filing,
would the pipeline be permitted to begin negotiations and implement
negotiated services. In addition, after the Commission approved the
initial filing, the pipeline would be required to include the
categories of terms and conditions of service in its tariff.
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\108\ Further discussion of this aspect of the proposal is
included in the discussion below on the establishment of initial
recourse service.
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The non-negotiable category of terms and conditions of service
would include certain terms and conditions of service that could never
be negotiated, and thus, would be per se non-negotiable. A pipeline
might include in this category terms or conditions that, by their
nature, would directly affect the services of other shippers (e.g.,
force majeure, higher curtailment, or generic OFOs provisions).
The negotiable category of terms and conditions of service would
include particular items that the pipeline would be permitted to
negotiate, at its and its customers' discretion. A pipeline could
include permissible ranges of flexibility for each negotiable area of
service. These negotiable deals would be permitted to be implemented
after 10 days prior written notice to firm shippers and the
Commission.\109\ The Commission is proposing to permit these negotiable
services to go into effect at the end of the 10 day notice period,
without action on the notice filing by the Commission, since the
Commission would have already generically approved the negotiation of
these items by that pipeline with its action on the initial filing.
Similarly, other shippers would have had the opportunity to comment on
or oppose the pipeline's proposed negotiation of a particular term or
condition of service at the initial filing stage.
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\109\ See 18 CFR 385.2007 (1998).
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The Commission, however, seeks comment on whether a shorter advance
notice period, or any advance notice at all, is necessary for contracts
containing the items identified by the initial filing as negotiable.
Parties should comment on whether such negotiated contracts could be
self-implementing, becoming
[[Page 43011]]
effective upon the agreement of the pipeline and the shipper, subject
only to the pipeline filing and posting a transactional report of the
negotiated deal contemporaneous with the execution of the contract.
The potentially negotiable category of terms and conditions of
service would not need to be specifically identified, but would
encompass all other terms and conditions of service not identified in
the non-negotiable or negotiable categories. Items would fall into this
category if they had the potential to have an impact on the service of
other shippers, or had the potential to violate one of the other
guiding principles. Thus, any negotiation of these unspecified terms
and conditions of service would require prior notice, an opportunity
for other shippers to comment, and Commission review of the particular
negotiated transaction before taking effect. Specifically, the pipeline
would be required to make a filing under Sections 4(d) and (e) of the
NGA before the negotiated deal could take effect.\110\ The 30 days
prior written notice to the Commission and firm shippers provided by
the Section 4 filing would give all other shippers the opportunity to
protest the negotiated transaction before it takes effect, and the
Commission would have the ability, as usual, to accept, reject, or
suspend the pipeline's filing.
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\110\ 15 U.S.C. 717c (1994).
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The pipeline's Section 4 filing would need to contain the essential
aspects of the negotiated agreement, including: the name of the
shipper, any affiliation with the pipeline, the contract quantity, the
applicable rate(s), the receipt and delivery points, and a brief
description of the negotiated term or condition of service with
reference to the modified provision of the recourse tariff or rate
schedule. The filing would also contain a statement, with any
supporting information, that no material adverse effects on the
benchmark service will result from the negotiated term or condition.
This statement and supporting information would create a rebuttable
presumption that the negotiated transaction will not have any material
adverse effect on the recourse service. If the presumption is overcome,
the ultimate burden of persuasion would be on the pipeline to show that
no degradation of the recourse service would result.
Finally, the Commission is also proposing to continue the current
practice of allowing pipelines to negotiate unique services in
individual rate schedules that are then made available to all
customers, since this method already serves the industry well.
Although the Commission is proposing the method for implementing
negotiated services described above, the Commission would also consider
variations on this method, including the specific proposal advanced by
AGA/INGAA. In this regard, the Commission requests comment on whether
pipelines could be given an option of implementing negotiated terms and
conditions of service without having to initially file general tariff
provisions defining the scope of permissible or impermissible
negotiation. That is, could pipelines also be permitted to negotiate
unique deals with individual shippers that include terms and conditions
that deviate from those in its existing tariff, by filing each
negotiated contract with 30 days advance notice, and bypassing the
initial tariff filing? The Commission invites comments discussing the
pros and cons of the proposed implementation method, including whether
that method adequately addresses concerns which have been expressed
about the pipelines' potential exercise of market power. Commenters are
also invited to suggest alternative procedures for implementing
negotiated rates and services.
2. Recourse Service
The recourse service, which would be available to all shippers,
serves as an alternative to negotiating with the pipeline, and an
important check on the pipeline's potential exercise of market power.
Therefore, the Commission must ensure that the recourse service is
initially, and remains over time, a high quality service, so that it
stays a viable alternative to negotiated rates and services. Below, the
Commission presents proposals for initially establishing a good quality
recourse service, and for maintaining the vitality of that recourse
service in the future.
a. Establishment of Initial Recourse Service. The Commission
proposes to require that each pipeline's initial voluntary filing to
implement negotiated terms and conditions of service define the
components of that pipeline's recourse service. Pipelines would be
required to design a recourse service that is of a high quality and
reliability, and maintains at least the level of service being offered
by the pipeline in its currently effective tariff. Core elements of the
pipeline's recourse service that are not adequately defined in the
tariff, including standard operating practices, would be identified by
the pipeline or its customers in conjunction with the filing.
Essentially, this method of establishing initial recourse service
would require that any pipeline choosing to implement negotiated terms
and conditions of service submit its tariff services for review and
modification to establish adequate recourse service in exchange for the
authorization to negotiate terms and conditions of service. This
proposal would provide a procedure to address shippers' dissatisfaction
with some pipelines' existing service offerings, and their concerns
that the literal language of the existing tariffs might permit
pipelines to reduce the quality of recourse service from that enjoyed
under current operating practice. Thus, the review and modification of
individual pipelines' existing tariff services will help ensure that
recourse service is adequate before any negotiation of rates or
services takes place.
However, the Commission also seeks comments on whether using
pipelines' existing tariffs as the initial recourse service, without
requiring new filings, might be less burdensome on the industry and the
Commission, and thereby permit pipelines and shippers to begin
negotiating rates and services sooner than if initial filings to
establish recourse service were required. Parties should also comment
on whether the existing rates, terms, and conditions in pipelines'
current tariffs could be acceptable as initial recourse services, since
they have already been found by the Commission to be just and
reasonable. In commenting, parties should evaluate the need for
establishing adequate recourse services against the ability to
implement the negotiated rates and services policy without undue delay.
Another option for establishing initial recourse service would be
to have GISB generically identify basic elements of service that could
not be subject to negotiation. Designating particular terms or
conditions as non-negotiable would have the effect of defining some of
the basic terms and conditions of service that comprise recourse
service. Some commenters have requested that the Commission generically
specify particular terms or conditions as non-negotiable. However, GISB
is the one forum where all segments of the industry are brought
together, making across-the-board consensus on this issue a
possibility. The Commission requests comments on the feasibility and
value of having GISB define initial recourse service.
b. Maintaining Vitality of Recourse Service Over Time. For recourse
service to remain a viable option to negotiated
[[Page 43012]]
service, the overall quality of the recourse service must continue to
meet shippers' needs. The Commission is concerned that over time the
quality of recourse service may deteriorate. By not updating recourse
service to keep pace with changing markets, technology, and customer
needs, or by maintaining a low-quality or inferior recourse service,
pipelines could force captive customers into negotiating the basic
services they need, at premium rates.
Thus, the Commission finds that a mechanism needs to be established
to review recourse services to ensure they remain viable alternatives
to negotiated services. Accordingly, the Commission proposes to
implement periodic reviews of the rates, terms, and conditions of
recourse service.\111\ As discussed in more detail below, the
Commission proposes that these periodic reviews take place on a three-
to-five year cycle, although comment is invited on proposals for
alternative review cycles. These periodic reviews would provide the
Commission with the opportunity to examine the range of terms and
conditions included in the recourse service, and to assess the quality
of the recourse service as a whole.\112\
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\111\ See proposed Sec. 284.10(c).
\112\ The Commission may need, at some point in the future, to
adopt standards that define recourse service quality.
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The periodic reviews would provide a forum for the Commission to
determine if certain negotiated services offered by some pipelines
should be offered as recourse services after some reasonable time. This
would allow captive customers to obtain the benefits of service
innovation, while at the same time giving pipelines a reasonable period
of time to profit from their innovative service offerings before having
to offer the service at a cost-based rate. The periodic reviews of
recourse services would also enable proposed additions or changes to
recourse service to be considered comprehensively, to help ensure that
the new package of recourse services is both operationally feasible and
cost effective.
There are several different ways that the Commission could
implement the periodic reviews of recourse service. The periodic review
could be undertaken on an individual pipeline basis, on a regional
basis, or on a national, or generic, basis. The Commission proposes to
establish recourse services, through the periodic reviews, for each
individual pipeline. This approach is likely to provide the best match
of customers' service needs with the operational capabilities of
individual pipelines. Establishing recourse services individually, for
each pipeline, would also allow rate issues to be treated
simultaneously with service issues.
The Commission proposes that pipelines offering negotiated terms
and conditions of service file information with the Commission every
three to five years that will ensure the viability of the pipeline's
recourse service. The information proposed to be filed is intended to
give the Commission adequate information to determine whether and how
to modify the pipeline's recourse rates and service to keep pace with
market conditions.
The information would need to be filed for each type of negotiated
service--the negotiated services that take effect on shortened notice
and the transactions subject to 30 days notice. The filing would
include data on the names and types of shippers negotiating the
contracts, the terms negotiated, the contract demand, and volumes moved
under the contracts.
In addition, to permit a comparison to the pipeline's current
recourse service, the pipeline would have to provide aggregate data for
each category of negotiated service, and for the recourse service. The
aggregate data would include information on total contract demand,
aggregate volumes, and revenues for the negotiated contracts and the
recourse service.
Commenters are requested to address the adequacy of the information
required in the proposal, including whether more detailed information
is necessary, and are encouraged to suggest other information that
might better permit the Commission to review negotiated rates and
services.
The Commission is still considering, as an alternative to the
pipeline-specific review of recourse service, requiring the periodic
recourse service reviews to be made on a regional basis, before any
individual pipeline-specific adjustments are made. On the one hand, the
establishment of recourse services on a regional basis, so that the
recourse services offered by all pipelines in a given region would be
as nearly equivalent as possible given operational differences among
pipelines, could result in greater standardization of pipeline services
and practices, thereby enhancing competition and tradability of
capacity. It could also lower transaction costs for customers. In
addition, a regional approach may be less burdensome on shippers
because they would need to participate in fewer proceedings. On the
other hand, it may be difficult to develop recourse services for all
pipelines in a region, since a regional approach would not facilitate
the tailoring of services to the operational capabilities of specific
pipelines.
The Commission seeks comment on the different ways that the
Commission could implement the periodic reviews of recourse service,
including comment on the merits of establishing recourse service on a
regional basis through regional reviews. Parties may discuss the
advantages and disadvantages of each approach, and how a regional
approach might be performed.
3. The Release of Negotiated Capacity
To enhance the tradability of capacity under negotiated service
contracts, the Commission is contemplating requiring pipelines to
include in their tariffs a provision that allows, but does not require,
a negotiated service to revert to a standard form of service when it is
offered for release. This should make it easier for the customer under
a negotiated service contract to release its capacity. This is because
a negotiated service agreement may contain provisions tailored to a
customer's needs which render the service undesirable to other shippers
with different needs. This provision could apply either to all
negotiated services, or only to those that represent an enhancement
over the standard service. The provision could also be structured such
that any negotiated term or condition of service which the replacement
shipper desires would remain in the contract.
In the case where a releasing shipper negotiates enhanced, more
flexible, or ``better'' services than the standard service, the
releasing shipper presumably would be compensated for reselling
capacity as if it was standard service, regardless of what it paid for
the capacity. If negotiated services are below the standard level
included in the tariff provision, the releasing shipper might be
required to pay the difference between the negotiated rate and the
standard rate before reselling its service as standard service. In both
cases, reversion of a negotiated service to a standard form of service
would be allowed only when operationally feasible, and only when
requested by the releasing shipper.
The Commission requests comment on this potential method for
helping ensure that negotiated capacity remains tradable, particularly
on the feasibility of implementing such a requirement. Commenters
should address how critical establishing this reversion requirement is
to permitting the release of capacity under a negotiated contract, how
difficult it would be to define what
[[Page 43013]]
service is of a higher or lower quality than the standard level of
service, and to what extent operational difficulties in permitting the
reversion to a standard form of service might limit the overall value
of this approach.
4. Negotiation of Rates and Services With Affiliates
As stated previously, the Commission proposes to permit the
negotiation of rates and services where similarly situated shippers
have rights to the same negotiated deal. The Commission is considering
whether additional protections are required to protect against unduly
preferential treatment in favor of pipeline marketing affiliates or
whether the Commission's existing marketing affiliate rules provide
adequate protections. Therefore, the Commission proposes to permit
pipelines to negotiate terms and conditions of service with their
marketing affiliates so long as all other similarly situated shippers
are offered the same rates and services. Consistent with prior
precedent, the Commission proposes to establish a rebuttable
presumption that all shippers receiving the same type of service, using
the same pipeline facilities, are similarly situated.\113\ The pipeline
could rebut the presumption by showing that a particular shipper or
group of shippers is not similarly situated with its affiliate in order
to justify not offering the same negotiated deal to non-affiliated
shippers.
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\113\ See Tennessee Gas Pipeline Company, 77 FERC at 61,877
(requiring the pipeline to file specific information to enable
shippers to determine if they are similarly situated to particular
negotiated rate customers), see also, Iroquois Gas Transmission
System, L.P. CP96-687-000, 79 FERC para. 61,394 at 62.693 (1997),
reh'g denied, 82 FERC para. 61,086 (1998) (rejecting proposal to
discount service to expansion shippers as unduly discriminatory
against existing shippers).
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The Commission seeks comments on whether the above proposal
provides adequate protection against undue discrimination. For example,
should the Commission consider stronger protections, such as precluding
the negotiation of rates and services with marketing affiliates as
unduly preferential unless all other shippers are offered the same
rates and services? Alternatively, could robust monitoring be adequate
to discourage and prevent pipelines from giving undue preference to
their affiliates eliminating the need for stronger protections? If so,
what types of information would the Commission need to gather to meet
its monitoring objectives, and how burdensome would it be to provide
this information? Is some other form of protection better suited to the
Commission's purpose of ensuring against undue discrimination?
Commenters are invited to respond to these issues and may raise any
related issues not presented here.
5. Negotiation of Capacity Release and Flexible Point Rights
The Commission is considering whether the rights to release
capacity and to flexible receipt and delivery points should be included
among the terms or conditions of service that could not be changed by
negotiation. Capacity release is a fundamental element of the
increasingly competitive natural gas capacity market. It creates
competition between firm capacity holders and the pipeline in what
otherwise may be a monopoly capacity market.
Under a negotiated rates and services policy, both pipelines and
shippers may find it easy and advantageous to negotiate the
relinquishment of such rights. Pipelines may find it in their interest
to negotiate services without capacity release rights to reduce
competition for their interruptible and short-term firm services.
Shippers, also, may wish to relinquish capacity release rights for a
price break, particularly if they do not plan to utilize their release
rights. Shippers who give up capacity release rights will no longer be
potential sellers of capacity. Those who give up flexible receipt and
delivery points may severely limit their participation in the secondary
market. Thus, surrender of these rights could have a clear and direct
impact upon competition from the release market and the pipeline's
ability to exercise market power.
The Commission requests comment on whether precluding the
negotiation of rights to capacity release and flexible points is
necessary to ensure that firm shippers can continue to release capacity
and trade with others behind secondary points, and thereby remain
competitors in the short-term capacity market. Commenters should
address the likelihood, and extent to which, they expect these rights
to be a primary subject of negotiations between pipelines and shippers,
and the extent to which restricting the negotiation of such rights
might limit the range of possible negotiated deals. Commenters also
should consider whether the Commission should implement this
restriction as an initial protection that could be relaxed in the
future as more experience is gained with the negotiated rates and
services policy.
6. Future Cost Allocation Issues
The Commission shares concerns, voiced by potential recourse
shippers in the comments filed in Docket No. RM95-7-000, regarding the
effect that the negotiation of rates and services might have on
recourse shippers' rates. The main concern is that pipelines entering
into negotiated deals that result in reduced revenue streams might seek
to recover the revenue shortfall by raising recourse rates in future
rate cases. Such cost-shifting could cross-subsidize negotiated
services, and pipelines could try to keep revenues that exceed recourse
rate caps, while shifting revenue shortfalls to recourse ratepayers.
The rates of recourse shippers should not be adversely affected by
the pipelines' negotiations of service with other parties. Only the
negotiating parties should bear the risks and rewards of their
negotiated contracts. In fact, the Commission has previously addressed
this issue in the negotiated rates context by prohibiting a pipeline
from making any adjustment to its recourse rates to account for its
failure to recover costs from a negotiated rate shipper,\114\ absent
some showing of benefit to recourse shippers.\115\
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\114\ NorAm Gas Transmission Company, 75 FERC para. 61,091,
order on reh'g, 77 FERC para. 61,011 (1996) (NorAm).
\115\ Northwest Pipeline Corporation, 79 FERC para. 61,416,
62,754 (1997).
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At the same time, the Commission is concerned that if discount-type
adjustments for negotiated services are similarly prohibited in future
rate cases, pipelines might be deterred from negotiating rates and
services. Pipelines might favor the discounting of service fees over
the negotiation of creative alternatives, since the Commission's
discounting policies permit the recovery of revenue shortfalls. These
lost negotiated agreements may have resulted in the pipeline obtaining
a higher total revenue stream than it would have by entering into a
discounted deal, and may have mitigated the losses associated with the
level of discounting reflected in current rates. All customers may
benefit to the extent that some shippers stay on the system or take
longer term contracts as a result of the ability to negotiate rates and
services.
Therefore, the Commission is considering examining all rate issues
associated with negotiated rates and services in future rate cases,
including the treatment of revenue shortfalls and excess revenues, and
whether corresponding rate adjustments are appropriate. This would be a
change from the policy stated in NorAm of prohibiting, per se,
discount-type adjustments for negotiated rate agreements as a means of
ensuring costs
[[Page 43014]]
are not shifted to recourse rate customers. This approach may also
permit the Commission to consider any additional cost allocation issues
that might arise from any new facilities that may have been built to
provide the negotiated service. However, the burden of justifying the
benefit of specific negotiated deals would be on the pipeline. In this
respect, the Commission seeks comment on what type of showing pipelines
would have to make in order to show that specific negotiated deals
merited an adjustment to recourse rates.
Finally, the examination of all rate issues associated with
negotiated terms and conditions in future rate cases may also provide
the Commission with the opportunity to fully explore the benefits and/
or harm to the recourse shippers from the negotiated rates and services
policy. To the extent that these are unknowns at this point, the
Commission needs to have a fair amount of flexibility to decide how
revenues and costs associated with negotiated services should be
treated in future rate cases. The Commission solicits comment on the
above proposal, including comment on the extent to which this approach
may lead pipelines to attempt to shift risks to captive ratepayers, and
the proposal's potential impact on the ratemaking process.
An alternative would be to prohibit any adjustments to recourse
rates due to revenue shortfalls resulting from negotiated rates and
services. This approach would prevent pipelines from shifting the risks
of negotiated deals to recourse ratepayers. On the other hand, if the
pipeline were required to absorb any revenue shortfalls from negotiated
deals, the pipeline should probably have a corresponding right to
retain any excess revenues resulting from negotiated rates, thus
eliminating the possibility that recourse shippers would benefit from
negotiated deals other than through improved recourse service.
The Commission seeks comment on the advantages and disadvantages of
this alternative proposal to prohibit rate adjustments to recourse
rates for revenue shortfalls. Commenters should include discussion on
the extent to which prohibiting rate adjustments might discourage
pipelines from entering into negotiated deals, and whether, and/or to
what extent, prohibiting rate adjustments is inconsistent with the
Commission's existing discount policy.
7. Reporting, Monitoring, and Complaint Procedures
The implementation of stringent reporting requirements and active
monitoring will be necessary to ensure the success of a negotiated
rates and services policy. Such reporting and monitoring will be
critical for the Commission to be able to detect and deter the exercise
of market power, for customers to identify undue discrimination in the
provision of services and to support their legitimate complaints, and
for the Commission to ensure compliance with the guiding principles of
the negotiated rates and services policy.
The Commission is proposing to add to the data that pipelines
currently are required to report under the Index of Customers. Such
additional information will be aimed at capturing the existence of
similarly situated customers and any affiliate relationship between the
capacity holder and the customer in a negotiated transaction.
Specifically, the Commission proposes to require pipelines to
identify, in the Index of Customers, each contract that contains
negotiated rates and services. Pipelines would only be required to flag
contracts with negotiated rates and services through a ``yes/no''
indicator and contract number for each customer and contract. The
Commission is not proposing to require pipelines to delineate the terms
of specific contracts in the Index of Customers. Such delineation might
pose a significant burden on the pipelines, without a substantial
countervailing benefit.
In addition, the Commission is proposing to require other
information in the Index of Customers and/or the proposed monthly
transaction reports to assist in monitoring a pipeline's market power.
This includes information on receipt points, delivery points, segments,
affiliate relationships, and contract numbers. Such information will
enable shippers and the Commission to evaluate whether specific
shippers or transactions are ``similarly situated'' for purposes of
assessing undue discrimination or preference under a negotiated
contract.
Further, the Commission proposes to conduct compliance audits or
studies of specific pipelines' compliance with the principles.
Compliance audits or studies may provide the necessary detail about
specific services offered, and their effects on the customers in
individual cases, to allow case-by-case review of complaints, the early
detection of problems, and sua sponte Commission action. Such audits
also could provide constructive feedback to both the industry and the
Commission, and may improve overall compliance. The Commission seeks
comments on the utility of compliance audits.
Finally, an effective complaint procedure is necessary to resolve
and discourage abuses of the negotiated rates and services policy. To
this end, the Commission recently held a public conference in Docket
No. PL98-4-000, to aid in the process of evaluating and improving its
complaint procedures,\116\ and is contemporaneously issuing a separate
NOPR to revise the complaint process in Docket No. RM98-13-000.
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\116\ Symposium on Process and Reform: Commission Complaint
Procedures. See Notice of Conference issued March 10, 1998 in Docket
No. PL98-4-000, 63 FR 12800 (March 16, 1998).
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AGA/INGAA's negotiated terms and conditions proposal recommends
that an expedited and effective complaint procedure allow for the
remedy of retroactive relief in the event a customer proves that the
pipeline willfully and knowingly made a material misrepresentation in
its initial filing of a negotiated term or condition, which resulted in
material harm to the customer. Such relief would only be available in
the context of the negotiated terms and conditions policy, and would
not be permitted to be used as precedent for any other matter under any
statute administered by the Commission. Parties may also comment on
this proposal in the separate rulemaking proceeding in Docket No. RM98-
13-000.
VI. Long-Term Services
The proposals made in this NOPR for the short-term capacity market
will necessarily impact the long-term market. Further, without a
vibrant market for long-term capacity, the benefits of the short-term
market proposals cannot be realized. If the Commission adopts a new
regulatory approach for short-term transportation, there must be
viable, regulated long-term services available to mitigate any market
power of capacity sellers. The Commission is issuing a companion Notice
of Inquiry \117\ to consider whether changes should be made in its
policies with regard to long-term markets. However, the Commission is
concerned that some of its current regulatory policies may result in a
bias toward short-term contracts, which could weaken the long-term
market and undermine the proposals set forth in this NOPR.
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\117\ Regulation of Interstate Natural Gas Transportation
Services, Docket No. RM98-12-000.
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Therefore, the Commission is addressing in this NOPR, several long-
term transportation rate and certificate issues that have a direct and
significant impact on the short-term transportation policy proposals
contained in this NOPR. Specifically, the Commission is
[[Page 43015]]
proposing to modify the right of first refusal by eliminating the term
matching cap. Further, the Commission is considering changes to its
policies with regard to term-differentiated rates and negotiated terms
and conditions in long-term contracts. In addition, the Commission is
seeking comments on its policies for certification of new capacity.
A. The Interaction Between Long-Term and Short-Term Services
Long-term contracts provide important benefits to pipelines and
customers. Long-term contracts provide stability, and can reduce
financial risks to the pipeline, lowering their capital costs, to the
benefit of all the pipeline's customers. In addition, encouraging long-
term contracts ensures that there will be sufficient capacity available
for release in the secondary market in order to maintain the vibrant
competition between sales of capacity in the primary and secondary
market which exists today.
The Commission has proposed that the removal of the price cap in
the short-term transportation market, coupled with other changes
proposed for the short-term market, would be consistent with the
Commission's statutory responsibilities. These proposals, in
combination with one another, should foster a more competitive
environment, while at the same time, providing a check against any
monopoly power abuses. The rationale for modifying the approach to
short-term markets does not apply to the long-term market, however. In
the long-term market, there are no effective substitutes for long-term
pipeline service, unlike the short-term capacity products of
interruptible, short-term firm, and capacity release. Therefore, even
if the Commission decides to adopt a different regulatory approach for
short-term transactions, there will continue to be a need for the
Commission to regulate the terms and conditions of service for long-
term transportation to protect shippers against the exercise of
monopoly power by pipelines. The Commission's regulation, however,
should not provide artificial disincentives for long-term contracts,
but should be neutral with regard to long-term and short-term
contracts.
The Commission is concerned that some of its current regulatory
policies result in a bias toward short-term contracts. These policies
include the term matching cap in the right of first refusal and the use
of the same maximum rate for service under short-term and long-term
contracts. Under these conditions, financial risks and rewards are not
linked, i.e., there is risk asymmetry, favoring short-term contracts,
and there is little incentive for a shipper to enter into a long-term
contract with the pipeline. If a shipper enters into a long-term
contract, it runs the risk that its rates will increase during the term
of that contract. It can avoid this risk, and still be guaranteed that
it can receive service indefinitely by entering into a short-term
contract with a right of first refusal. The customer knows that it need
never pay more than the regulated cost-of-service maximum rate to buy
service from the pipeline, regardless of whether it is pursuant to a
long-term or a short-term contract. If market conditions are relatively
weak at the end of the current contract, the customer may be able to
bargain with the pipeline to get a discount or to obtain service more
cheaply through the secondary market or on another pipeline. Where
capacity holders have firm rights to capacity that is valued above the
cost-of-service rate, they will likely hold onto that capacity. Current
contract holders will exercise their right of first refusal when market
conditions are weak. Other things being equal, the customer should want
a shorter-term contract.
The pipeline faces the other side of the bargain. The bias toward
short-term contracts and the current asymmetry of risk may have
negative economic consequences to the pipelines, and for example, may
be a factor in causing capacity turn-back and the discounting of rates
for long-term contracts. Customers may take only relatively short-term
contracts and only when the value meets or exceeds the rate. The
proposed removal of the price cap in the short-term market could move
some customers toward longer-term contracts to avoid price
uncertainties and potential jumps in the short-term prices. On the
other hand, however, removal of the price cap could move other
customers toward the short-term market because they could always count
on being able to secure capacity there at some price. Cost recovery
problems resulting from a weak long-term transportation market could be
a possibility for pipelines, even if the price cap were removed, given
the biases toward short-term contracts. Without changes in the
Commission policies that contribute to this bias, the Commission's
goals for the short-term market could be undermined because pipelines
would have an incentive to undermine short-term markets in order to be
more confident of their ability to recover their costs over the long
term.
A pipeline with cost recovery problems could try to alleviate the
problem in one of several ways, each of which would have adverse
consequences on the short-term market. First, to try to recover their
revenues, pipelines could attempt to raise the charges to remaining
long-term customers. They are unlikely to be able to recover their
costs in this manner. Even if successful in raising rates to remaining
customers,\118\ this action could cause additional customers to leave
the pipeline, leaving the pipeline and the remaining customers in an
even worse financial situation.
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\118\ The Commission would not necessarily approve a request for
increased rates. See, e.g., El Paso Natural Gas Company, 72 FERC
para. 61,083 at 61,441-42 (1995); and Natural Gas Pipeline Co., 73
FERC para. 61,050 at 61,128-30 (1995).
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In addition, a pipeline with a cost recovery problem would feel
pressure to eliminate alternatives that enable shippers to turn back
capacity.\119\ If pipelines can make the secondary market less viable,
by withholding capacity and/or price discrimination, they would have
more captive customers from whom to recover their costs. This would
undermine short-term markets and reduce efficiency because shippers'
capacity could not be reallocated to those who value it more. It would
also give pipelines greater opportunity to exercise market power,
further decreasing efficiency, and making it easier for a pipeline to
maintain a policy of discrimination between customers. Thus, by having
a negative impact on the pipeline's financial stability, the bias in
favor of short-term markets would provide incentives for the pipelines
to undermine the short-term market.
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\119\ Pipelines might also try to increase their sale of
interruptible transportation as another means of recovering their
costs of service. Shippers, however, would only take this capacity
when they need it, and not year round in most cases.
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B. Specific Impediments to Long-term Contracts
There are a number of artificial impediments to long-term contracts
on existing pipelines. These result in lower risks to shippers for
short-term contracts available for the same maximum rates as the long-
term contracts, thereby artificially discouraging long-term contracts.
One way to help restore balance is to remove these artificial
impediments to long-term contracts.
1. The Right of First Refusal
In Order No. 636, the Commission authorized pre-granted abandonment
of long-term firm contracts, subject to the right of first refusal for
the existing
[[Page 43016]]
shipper.\120\ Pursuant to the right of first refusal, the existing
shipper can retain service by matching the rate and length of service
of a competing bid. The rate is capped by the pipeline's maximum tariff
rate, and, in Order No. 636-C, the Commission limited the requirement
that the existing shipper must match the length of the contract term of
a competing bid to a contract length of five years.\121\ On rehearing
of Order No. 636-C, the pipelines argued that this five-year matching
cap interferes with market forces; and, because of the five-year cap,
it is unlikely that any existing shipper will renew its contract for
more than five years. While the Commission concluded that the record in
the Order No. 636 proceeding supported the five-year cap, the
Commission recognized there are legitimate concerns about the practical
effects of the five-year matching cap on the restructured market as it
continues to evolve.
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\120\ 18 CFR 284.221(d).
\121\ Order No. 636 capped the matching term at 20 years.
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The right of first refusal with the five-year matching cap provides
a disincentive for an existing shipper to enter into a contract of more
than five years, and results in a bias toward short-term contracts. As
a practical matter, the right of first refusal with the five-year cap
gives current customers the incentive to opt for as short a contract
term as possible so that, at contract expiration, they can reassess the
value of the capacity and decide if it is in their interest to keep it.
If pipeline capacity is relatively valuable, there are likely to be
other shippers interested in long-term contracts, but the existing
shipper will exercise its right of first refusal and retain the
capacity for a five-year term. On the other hand, if the market value
of long term capacity is low, the existing shipper can terminate the
contract with no obligation to the pipeline. In these circumstances,
there is no reason for a shipper with a right of first refusal to enter
into a long-term contract because it can use a series of short-term
contracts to obtain long-term service, and wait and see how the market
develops.
This results in an imbalance of risks between pipelines and
existing shippers. The pipeline is obligated to provide service for the
shipper indefinitely, as long as it exercises its right of first
refusal, while the shipper has no corresponding long-term obligation to
the pipeline. Elimination of the five-year cap from the right of first
refusal would remove a significant factor in the risk asymmetry
discussed above. Without a limitation on the contract length that must
be matched by the existing shipper, an existing shipper who wants to be
assured of access to capacity for the long term would have to match the
highest rate bid up to the maximum cost-based, for the capacity for the
duration of the contract bid, and thus share with the pipeline some of
the risks associated with the long-term commitment.
Elimination of the cap limiting the contract length that the
existing shipper must match also would foster efficient competition, as
encouraged by Order No. 636. This cap tends to protect existing
shippers from competition and give them control over pipeline capacity.
Without the cap, the term of a contract will be determined by market
forces, rather than by the limitation established by the Commission.
In UDC v. FERC,\122\ the Court stated that for a finding of public
convenience and necessity for pre-granted abandonment, the Commission
must make appropriate findings that existing market conditions and
regulatory structures protect customers from pipelines' market power.
The Court found that the right of first refusal mechanism with a cap on
contract length was one adequate means of protecting customers from
pipeline market power. In response to the Court's concern that the
Commission had failed to justify a twenty-year cap, the Commission
adopted the five-year cap in Order No. 636-C. However, conditions in
the market have changed substantially since the issuance of Order No.
636, and the five-year cap has not worked well in the restructured
market. As discussed above, it has led to asymmetry of risk and a bias
toward short-term contracts. Therefore, the Commission is proposing to
eliminate the term matching cap from the right of first refusal and is
seeking comments on this proposal.\123\
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\122\ 88 F.3d 1105, 1139 (D.C. Cir. 1996), cert. denied, 117 S.
Ct. 1723 (1997).
\123\ The term matching cap is not set forth in the regulations,
and, therefore, no revision to 18 CFR 284.221(d) is necessary.
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The Commission is also considering whether, in view of the changed
market conditions, the right of first refusal should be eliminated
entirely. Since restructuring, increased competition in both the
commodity and capacity markets now affords customers greater
protections from market power. Small LDCs no longer have to hold
capacity on the pipeline in order to receive gas, and can buy gas
delivered from marketers or can obtain capacity in the secondary
market. In fact, many LDCs have chosen not to hold capacity on
pipelines. Therefore, changed conditions suggest that the right of
first refusal may no longer be needed to protect the customers it was
originally intended to protect. The Commission is seeking comments on
eliminating the right of first refusal, as well as other options, such
as changing the length of the term matching cap or permitting the
pipelines and the customers to negotiate for a right of first refusal.
2. Term-Differentiated Maximum Rates
Another method of reducing risk asymmetry and strengthening the
long-term market would be to encourage contracts that contain lower
maximum rates for longer-term service than for short-term service in
recognition of the value of long-term contracts in limiting the
pipeline's risk. As explained above, a short-term contract is riskier
for the pipeline, and a higher short-term contract rate would
compensate pipelines for the additional risk they take when entering
short-term contracts. Conversely, a short-term contract provides
greater flexibility and less risk to the shipper, and the higher short-
term rate would recognize, and require payment for, these benefits.
The Commission is seeking comments on whether and how term-
differentiated maximum rates should be encouraged, and, if so, how the
rate differential should vary with contract term. For example, should
there be only two contract length categories, or should there be more?
How would the appropriate contract length categories be determined? How
should the rate differentials between term categories be set? Could a
market mechanism be developed for determining the appropriate
differentials?
Negotiation may be a primary way of addressing the sharing of risk
between the parties, to ensure that parties can contract to minimize
the total cost of that risk. Negotiation of rates and services is a
possible solution to some of the problems discussed above. The
limitations discussed in the preceding section\124\ should keep
negotiations from hurting the fungibility of the capacity in the short-
term market, increasing the pipelines' (or their affiliates'') ability
to exercise market power, and otherwise hurting third parties.
---------------------------------------------------------------------------
\124\ The proceding section of this NOPR discusses the role of
negotiated terms and conditions in the short-term market.
---------------------------------------------------------------------------
C. New Capacity Certificate Issues
The Commission's proposed changes in the short-term market also
create a need to review its policies for
[[Page 43017]]
certificating new capacity and services. As explained above, the
removal of the price cap in the short-term market requires that viable
regulated services be available in the long-term market to mitigate any
market power of capacity sellers. The Commission's certificate policies
are critical to assuring that pipelines construct the optimal amount of
capacity to meet demand in the long-term market. Therefore, the
Commission is reviewing its certificate policies to determine whether
these policies should be modified to meet current market conditions and
needs, particularly in light of the proposed changes in the short-term
market.
The Commission's objective in this review is to assure that its
policy is well-balanced so that facilities are constructed where demand
warrants construction, while at the same time guarding against
additional construction that is not necessary to meet any increase in
demand for capacity and that could result in excess capacity and the
problems of unsubscribed capacity. The Commission also seeks to assure
that its policies will not result in building new capacity in markets
where existing facilities are not fully subscribed because this could
create false price signals and weaken the long-term transportation
market.\125\
---------------------------------------------------------------------------
\125\ In the NOI, the Commission discusses price distortions in
the California and Chicago markets, where several pipelines were
facing significant turnback of long-term capacity, while other
pipelines were constructing additional capacity to serve those
markets.
---------------------------------------------------------------------------
Under the policy set forth in Kansas Pipe Line & Gas Company
(Kansas Pipe Line),126 the Commission required an applicant
seeking an NGA section 7 certificate for authority to construct and
operate new facilities to show customer commitments sufficient to
justify the proposed project. In order to demonstrate the need for a
new project, an applicant was required to submit market studies of the
customers and area to be served, and contracts showing long-term
commitments for 100 percent of the proposed facility's capacity. This
approach made it unlikely that too much capacity would be built.
---------------------------------------------------------------------------
\126\ 2 FPC 29 (1939).
---------------------------------------------------------------------------
Under the current policy, an applicant for a traditional section 7
certificate must submit precedent agreements for long-term firm service
\127\ for a substantial amount of the new facility's capacity.\128\
Where an applicant is not able to provide evidence of long-term
commitments for firm service for at least 25 percent of a proposed
facility's capacity, the Commission will typically place the applicant
at risk for unrecovered costs attributable to the unsubscribed
capacity.\129\ This at-risk condition is intended to discourage
overbuilding and assure that the pipeline's other customers are not
compelled to pay for costs associated with unused capacity.
---------------------------------------------------------------------------
\127\ For purposes of evaluating applications for new
construction, a long term is a term of at least 10 years. See e.g.,
Texas Eastern Transmission Corp., 82 FERC para.61,238 (March 11,
1998).
\128\ ``Generally, as it has evolved, the minimum level of firm
commitment that the Commission has determined to be sufficient for a
new onshore facility has been 25 percent of the proposed project's
capacity.'' Id. at 61,916.
\129\ But see 18 CFR 157.100-157.106 (Applicants for an optional
expedited certificate under Subpart E of Part 157 may receive a
certificate to construct for others for new service without any
requirement to show specific market demand; however, the rates for
service provided through such facilities will be designed to impose
the economic risks of the project entirely on the applicant).
---------------------------------------------------------------------------
In considering evidence of market demand, the Commission gives
equal weight to precedent agreements between an applicant and its
affiliates and an applicant and unrelated third parties. Further, the
Commission has not sought to assess whether these customer commitments
indicate a genuine growth in market demand necessitating additional gas
supplies, or reflect a desire to access separate supply sources for
unchanging quantities of gas, or represent efforts to obtain reduced
transportation charges for shipping identical gas volumes. Before Order
No. 636, new projects were typically intended to bring gas to unserved
or clearly under-served markets. Increasingly, new projects are
designed to compete for market share by offering alternatives to
customers in established markets.
The Commission seeks to assure that its policies strike the proper
balance between the enhancement of competitive alternatives and the
possibility of over building. The Commission wants to assure that its
policies serve to maximize competitive alternatives, while at the same
time protect against overbuilding, unnecessary disruption of the
environment, and unneeded exercise of eminent domain over private
property. Specifically, the Commission seeks comments on whether
proposed projects that will establish a new right-of-way in order to
compete for existing market share should be subject to the same
considerations as projects that will cut a new right-of-way in order to
extend gas service to a frontier market area. In conjunction with this
reassessment of project need, the Commission is considering how best to
balance demonstrated market demand against potential adverse
environmental impacts and private property rights in weighing whether a
project is required by the public convenience and
necessity.130
---------------------------------------------------------------------------
\130\ See, e.g., Granite State Gas Transmission, 83 FERC
para.61,194 (1998). The Commission authorized a new liquefied
natural gas (LNG) facility after comparing services to be provided
by the proposed facility with similar services that might be offered
by employing alternative facilities. Although employing existing
facilities could result in diminished adverse environmental impacts,
the Commission authorized the proposed project, finding the service
made available by the new LNG facility would provide specific
advantages over the alternatives.
---------------------------------------------------------------------------
One option would be for the Commission to authorize all
applications that at a minimum meet the regulatory requirements, then
let the market pick winners and losers. Another would be for the
Commission to select a single project to serve a given market and
exclude all other competitors. Another possible option would be for the
Commission to approve an environmentally acceptable right-of-way and
let potential builders compete for a certificate.
The Commission requests comments on these three options, as well as
comments on the following questions: (1) Should the Commission look
behind the precedent agreement or contracts presented as evidence of
market demand to assess independently the market's need for additional
gas service? (2) Should the Commission apply a different standard to
precedent agreements or contracts with affiliates than with non-
affiliates? For example, should a proposal supported by affiliate
agreements have to show a higher percentage of contracted-for capacity
than a proposal supported by non-affiliate agreements, or, should all
proposed projects be required to show a minimum percent of non-
affiliate support? (3) Are precedent agreements primarily with
affiliates sufficient to meet the statutory requirement that
construction must be required by the public convenience and necessity,
and, if so, (4) Should the Commission permit rolled-in rate treatment
for facilities built to serve a pipeline affiliate? 131 (5)
Should the Commission, in an effort to check overbuilding and capacity
turnback, take a harder look at proposals that are designed to compete
for existing market share rather than bring service to a new customer
base, and what particular criteria should be applied in
[[Page 43018]]
looking at competitive applications versus new market applications? (6)
Should the Commission encourage pre-filing resolution of landowner
issues by subjecting proposed projects to a diminished degree of
scrutiny where the project sponsor is able to demonstrate it has
obtained all necessary right-of-way authority? (7) Should a different
standard be applied to project sponsors who do not plan to use either
federal or state-granted rights of eminent domain to acquire right-of-
way?
---------------------------------------------------------------------------
\131\As discussed in the NOI, in the Pricing Policy for New and
Existing Facilities Constructed by Interstate Natural Gas Pipelines,
71 FERC para.61,241 (1995), the Commission adopted a presumption in
favor of rolled-in rates when the rate increase to existing
customers from rolling in the new facilities in 5 percent or less,
and the pipeline makes a showing of system benefits.
---------------------------------------------------------------------------
The parties may also address other questions concerning
certification issues in general, including: (1) What should the
Commission do to provide for the infrastructure to serve future
increased demand for capacity? (2) How can pipelines deal with the
potential for not recovering new construction costs? Should the
Commission address, at the certificate issuance stage, the issue of a
pipeline's responsibility for future cost under-recovery once its
initial contracts expire? Assuming no adverse environmental impacts,
should a pipeline be allowed to build if it does not accept the
responsibility for all of the cost not covered by its initial
contracts? What, if anything, should the Commission do to ensure rate
certainty for customers and pipelines? Can or should this include
guarantees against future rolling-in of costly expansions, future
changes in O&M expenses, or any other future changes? (3) Should the
Commission reassess the balance between risk and return? Is there
really more risk for a pipeline with short-term contracts, or will
shippers continue to make short-term deals for the life of the pipeline
that cover the pipeline's cost-of-service? Is any of the risk
unnecessary, and can it be eliminated without imposing additional
costs? How should rates be determined after contracts expire? Should
the Commission establish different pricing based on contract term? (4)
What are the advantages (or disadvantages) of allowing pipelines and
customers to negotiate pre-construction risk and return-sharing
agreements, and what actions should the Commission take if pipelines
and customers do not agree on the allocation of risk and return? (5) To
what extent should the policies on new construction and existing
pipelines match? (6) How does retail unbundling and open access affect
all of these issues?
VII. Reorganization of Part 284 Regulations
Commission proposes to reorganize certain portions of its Part 284
regulations to better reflect the nature of services in the short-term
market and to consolidate its Part 284 reporting and filing
requirements in a single section. Because capacity release has become
an integral part of the short-term market, the Commission is proposing
to move its capacity release regulations from subpart H of Part 284 to
the same location in its regulations as pipeline firm and interruptible
service (newly designated sections 284.7 (firm service), 284.8 (release
of firm service), and 284.9 (interruptible service)).
In addition, reporting and filing requirements for pipeline Part
284 services are presently scattered throughout Part 284. For example,
the Index of Customers and storage reports are presently located in
subpart B, section 284.106, which deals with interstate pipelines
performing transportation service under the Natural Gas Policy Act
(NGPA). But these regulations are then applied to interstate pipelines
performing open access services in subpart G, section 284.223. Other
reporting requirements are located throughout various substantive
provisions of Part 284.132 The Commission is proposing to
collect these requirements into one new section (proposed Sec. 284.14)
applicable to interstate pipelines transporting gas under Subpart B
(transportation under section 311 of the NGPA) and Subpart G (open
access transportation under the NGA). Reporting requirements specific
to Subpart B pipelines (by-pass reports) remain in Subpart B.
---------------------------------------------------------------------------
\132\ See, e.g., 18 CFR 284.8 (b) (3) and 284.9 (b) (3)
(requirements to provide information on available capacity); 284.7
(c) (6) (discount reports); 18 CFR 284.12 (filing of capacity).
---------------------------------------------------------------------------
To aid commenters' review of the new regulatory format, the
following would be the new outline for subpart A of Part 284.
284.1 Definitions.
284.2 Refunds and interest.
284.3 Jurisdiction under the Natural Gas Act.
284.4 Reporting.
284.5 Further terms and conditions.
284.6 Rate interpretations.
284.7 Firm transportation service.
284.8 Release of firm transportation service.
284.9 Interruptible transportation service.
284.10 Rates.
284.11 Negotiated rates and services.
284.12 Environmental compliance.
284.13 Standards for pipeline business operations and
communications.
284.14 Reporting requirements for interstate pipelines.
The Commission recognizes that such changes may occasion the need
for cross-reference changes in other sections of Part 284 as well as
other parts of the regulations. The Commission would make such non-
substantive changes in the final rule, and commenters should point out
regulatory sections where such changes are needed.
VIII. Information Collection Statement
The following collections of information would be affected by this
proposed rule and have been submitted to the Office of Management and
Budget (OMB) for review under Section 3507(d) of the Paperwork
Reduction Act of 1995, 44 U.S.C. 3507(d). The Commission solicits
comments on the Commission's need for this information, whether the
information will have practical utility, the accuracy of the provided
burden estimates, ways to enhance the quality, utility, and clarity of
the information to be collected, and any suggested methods for
minimizing respondents's burden, including the use of automated
information techniques. The burden estimate in this proposed rule
includes the cost for pipelines to comply with the Commission's
proposed regulations concerning short-term natural gas transportation
services. The following burden estimates reflect only the incremental
costs of complying with the proposed new and revised standards intended
to implement the Commission's regulations. The burden estimates include
start up and on-going costs.
Estimated Annual Burden: The estimated annual burden associated
with this NOPR is shown below.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of Number of responses per Estimated burden Total annual
Affected data collection respondents respondent hours per response burden hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC-545....................................................... 100 2.0 97.800 19,560
FERC-549B...................................................... 100 446.5 1.526 68,136
FERC-592....................................................... 74 1.0 7.000 518
----------------------------------------------------------------------------------------
Total...................................................... .................. ........................... .................. 88,214
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 43019]]
The estimated number of reporting hours attributable to the
requirements proposed herein are expected to total
88,214 hours and are included in the
above annual burden estimates.
Information Collection Costs: The Commission seeks comments on the
estimated cost to comply with these requirements. It has projected
average annualized costs for all respondents to be the following:
[In dollars]
----------------------------------------------------------------------------------------------------------------
Estimated data collection costs FERC-545 FERC-549B FERC-592 Total
----------------------------------------------------------------------------------------------------------------
Annualized Capital/Startup Costs................ 842,061 168,412 0 1,010,473
Annualized Costs (Operations & Maintenance)..... 187,359 3,417,506 27,262 3,632,127
---------------------------------------------------------------
Total Annualized Costs...................... $1,029,420 3,585,918 27,262 4,642,600
----------------------------------------------------------------------------------------------------------------
The OMB regulations require OMB to approve certain information
collection requirements imposed by agency rule.\133\ Accordingly,
pursuant to OMB regulations, the Commission is providing notice of its
proposed information collections to OMB.
---------------------------------------------------------------------------
\133\ 5 CFR 1320.11.
---------------------------------------------------------------------------
Titles: FERC-545, Gas Pipeline Rates: Rate Change (Non-Formal);
FERC-549B, Gas Pipeline Rates: Capacity Information (a proposed new
title); and FERC-592, Marketing Affiliates of Interstate Pipelines.
Action: Proposed Data Collections.
OMB Control Numbers: 1902-0154; 1902-0169; and 1902-0157,
respectively. The respondent shall not be penalized for failure to
respond to these information collections unless the collection of
information displays a valid OMB control number.
Respondents: Business or other for profit, including small
businesses.
Frequency of Responses: On occasion.
Necessity of Information: The proposed rule seeks to establish
reporting requirements that will provide information needed for the
market to operate more efficiently and for shippers and the Commission
to effectively monitor transactions for undue discrimination and the
exercise of market power.
Internal Review: The Commission has assured itself, by means of its
internal review, that there is specific, objective support for the
burden estimates associated with the information collection
requirements. The Commission's Office of Pipeline Regulation will use
the data to monitor the market place to correct problems and minimize
the exercise of market power. Additionally, the industry itself will
use the information to make more informed choices from among
alternative capacity sources and to monitor the marketplace. The
Commission's determination of burden involves among other things, an
examination of adequacy of design, cost, reliability, and redundancy of
the information to be required. These requirements conform to the
Commission's plan for efficient information collection, communication,
and management within the natural gas pipeline industry.
Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426, [Attention:
Michael Miller, Office of the Chief Information Officer, Phone:
(202)208-1415, fax: (202)273-0873, e-mail: michael.miller@ferc.fed.us]
For submitting comments concerning the collections of
information(s) and the associated burden estimate(s), please send your
comments to the contact listed above and to the Office of Management
and Budget, Office of Information and Regulatory Affairs, Washington,
DC, 20503. [Attention: Desk Officer for the Federal Energy Regulatory
Commission, phone: (202)395-3087, fax: (202)395-7285.
IX. Environmental Analysis
The Commission is required to prepare an Environmental Assessment
or an Environmental Impact Statement for any action that may have a
significant adverse effect on the human environment.134 The
Commission has categorically excluded certain actions from these
requirements as not having a significant effect on the human
environment.135 The actions proposed to be taken here fall
within categorical exclusions in the Commission's regulations for rules
that are clarifying, corrective, or procedural, for information
gathering, analysis, and dissemination, and for sales, exchange, and
transportation of natural gas that requires no construction of
facilities.136 Therefore, an environmental assessment is
unnecessary and has not been prepared in this rulemaking.
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\134\ Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats, &
Regs. Preambles 1986-1990 para.30,783 (1987).
\135\ 18 CFR 380.4.
\136\ See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 380.4(a)(27).
---------------------------------------------------------------------------
X. Regulatory Flexibility Act Certification
The Regulatory Flexibility Act of 1980 (RFA) 137
generally requires a description and analysis of final rules that will
have significant economic impact on a substantial number of small
entities. The proposed regulations would impose requirements on
interstate pipelines, which generally are not small businesses.
Accordingly, pursuant to section 605(b) of the RFA, the Commission
proposes to certify that the regulations proposed herein will not have
a significant adverse impact on a substantial number of small entities.
---------------------------------------------------------------------------
\137\ 5 U.S.C. 601-612.
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XI. Comment Procedures
The Commission invites interested persons to submit written
comments on the matters and issues proposed in this notice to be
adopted, including any related matters or alternative proposals that
commenters may wish to discuss. An original and 14 copies of comments
must be filed with the Commission no later than November 9, 1998.
Comments should be submitted to the Office of the Secretary, Federal
Energy Regulatory Commission, 888 First Street, NE, Washington, DC
20426, and should refer to Docket No. RM98-10-000. All written comments
will be placed in the Commission's public files and will be available
for inspection in the Commission's Public Reference Room at 888 First
Street, NE, Washington, DC 20426, during regular business hours.
Additionally, comments should be submitted electronically.
Commenters are encouraged to file comments using Internet E-Mail.
Comments should be submitted through the Internet by E-Mail to
comment.rm@ferc.fed.us in the
[[Page 43020]]
following format: on the subject line, specify Docket No. RM98-10-000;
in the body of the E-Mail message, specify the name of the filing
entity and the name, telephone number and E-Mail address of a contact
person; and attach the comment in WordPerfect 6.1 or lower
format or in ASCII format as an attachment to the E-Mail message. The
Commission will send a reply to the 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
marvin.rosenberg@ferc.fed.us.
Commenters also can submit comments on computer diskette in
WordPerfect 6.1 or lower format or in ASCII format, with the
name of the filer and Docket No. RM98-10-000 on the outside of the
diskette.
List of Subjects
18 CFR Part 161
Natural gas, Reporting and recordkeeping requirements.
18 CFR Part 250
Natural gas, Reporting and recordkeeping requirements.
CFR Part 284
Continental shelf, Incorporation by reference, Natural gas,
Reporting and recordkeeping requirements.
By direction of the Commission.
David P. Boergers,
Acting Secretary.
In consideration of the foregoing, the Commission proposes to amend
part 161, part 250, and part 284, chapter I, title 18, Code of Federal
Regulations, as set forth below.
PART 161--STANDARDS OF CONDUCT FOR INTERSTATE PIPELINES WITH
MARKETING AFFILIATES
1. The authority citation for Part 161 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
2. In Sec. 161.3, paragraphs (i) through (k) are renumbered (j)
through (l) and paragraph (i) is added to read as follows:
Sec. 161.3 Standards of conduct
* * * * *
(i) A pipeline must post the following information concerning its
affiliates on its Internet web site complying with Sec. 284.13 of this
chapter and update the information within three business days of any
change, posting the date on which the information was updated.
(1) A complete list of operating personnel and facilities shared by
the pipeline and its marketing affiliates.
(2) Comprehensive organizational charts and job descriptions for
its employees and the employees of its marketing affiliates identifying
which employees are engaged in transportation and which are engaged in
sales or marketing, and clearly showing the chain of command. The job
descriptions need not include employees whose jobs are purely clerical
or those without responsibility or access to information concerning the
processing or administration of requests for transportation service.
Each job description must include: the employee's title, duties and
status as an operating or non-operating employee; and in the case of a
senior employee (i.e., any employee who supervises non-clerical
employees), the employee's name.
* * * * *
3. In Sec. 161.3(h)(2), revise all references to ``284.10(a)'' to
read ``284.13'' and remove the words ``Electronic Bulletin Board,
operated pursuant to'' and add, in their place, the words ``Internet
Web site complying with''.
PART 250--FORMS
4. The authority citation for part 250 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
5. In Sec. 250.16, paragraph (b)(1) is removed, paragraph (b)(2) is
redesignated as (b)(1), and paragraph (b)(2) is reserved.
Sec. 250.16 [Amended]
6. In Sec. 250.16(c)(2), revise all references to ``284.10(a)'' to
read ``284.13'' and remove the words ``Electronic Bulletin Board,
operated pursuant to'' and add, in their place, the words'' Internet
Web site complying with''.
PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE
NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
7. The authority citation for part 284 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C 7101-7532; 43
U.S.C 1331-1356.
Sec. 284.12 [Removed]
8(a) Part 284 is amended by removing Sec. 284.12.
8(b) Part 284 is amended by redesignating the sections as set forth
in the following redesignation table:
------------------------------------------------------------------------
New
Old section section
------------------------------------------------------------------------
284.7....................................................... 284.10
284.8....................................................... 284.7
284.10...................................................... 284.13
284.11...................................................... 284.12
------------------------------------------------------------------------
9. In newly redesignated Sec. 284.7, paragraph (b)(3) is removed
and paragraph (b)(4) is redesignated as paragraph (b)(3).
10. Part 284 is amended by adding Sec. 284.8 to read as follows:
Sec. 284.8 Release of firm transportation service.
(a) An interstate pipeline that offers transportation service on a
firm basis under subparts B or G of this part must include in its
tariff a mechanism for firm shippers to release firm capacity to the
pipeline for resale by the pipeline on a firm basis.
(b) To the extent necessary, a firm shipper on an interstate
pipeline that offers transportation service on a firm basis under
subpart B or G of this part is granted a limited-jurisdiction blanket
certificate of public convenience and necessity pursuant to section 7
of the Natural Gas Act solely for the purpose of releasing firm
capacity pursuant to this section.
(c) The pipeline must enter into a contract with the replacement
shipper purchasing the capacity. Unless otherwise agreed by the
pipeline, the contract of the shipper releasing capacity will remain in
full force and effect, with the net proceeds from any resale to a
replacement shipper credited to the releasing shipper's reservation
charge.
(d) Releases of capacity for a period of less than one year must
conform to the requirements of the auction established under
Sec. 284.10(c)(5) of this part.
(e) Releases of capacity of one year or more must comply with the
following requirements.
(1) A shipper may arrange for a replacement shipper to obtain its
released capacity from the pipeline. The releasing and replacement
shippers or an authorized agent must notify the pipeline of the terms
and conditions of the release.
(2) A shipper may post any capacity it has available on the
pipeline's Internet site and may authorize the pipeline to accept bids
for such capacity. A releasing shipper posting capacity for bid must
notify the pipeline of the terms and conditions under which it will
release its capacity.
[[Page 43021]]
(3) For releases of capacity of one year or more, the rate may not
exceed the maximum rate in the pipeline's tariff.
Sec. 284.9 [Amended]
11. In Sec. 284.9, paragraph (b)(3) is removed and paragraph (b)(4)
is redesignated paragraph as (b)(3).
12. In newly redesignated Sec. 284.10, paragraphs (c)(5) and (c)(6)
are revised, and paragraph (c)(7) is added to read as follows.
Sec. 284.10 Rates.
* * * * *
(c) * * *
(5) Rates for short-term transportation services. For
transportation contracts of less than one year for pipeline firm and
interruptible service and for capacity released pursuant to Sec. 284.8
of this part, the rates will be determined in the following manner.
(i) Minimum rate. The minimum rate charged for such service may not
be lower than the minimum rate in the pipeline's tariff.
(ii) Capacity auction. The rate charged for any transaction at or
above the minimum rate will be determined by an auction that conforms
to the following requirements:
(A) All available short-term capacity must be sold through an
auction;
(B) Daily capacity from the pipeline must be sold through an
auction without the establishment of a reserve or minimum bid price;
(C) All eligible shippers must be permitted to bid with no
favoritism shown to pipeline affiliates or other shippers;
(D) The procedures and rules for each auction, including the
auction schedule, must be disclosed in the pipeline's tariff in advance
of the auction and must be applied to each auction;
(E) Capacity must be allocated based on established criteria and
parameters known in advance to all bidders and the same criteria and
parameters must apply to pipeline and released capacity;
(F) Shippers must be able to validate that the auction was run
properly either through the posting of information sufficient to permit
them to validate that the winners were selected appropriately or
through the use of other mechanisms, such as an independent third-
party, which will validate the results.
(6) Rates for long-term transportation services. (i) Except as
provided in section (ii) of this paragraph and Sec. 284.11 of this
part, for transportation contracts of one year or longer for pipeline
firm and interruptible service, the pipeline may charge an individual
customer a rate that is neither greater than the maximum rate nor less
than the minimum rate on file for that service.
(ii) The pipeline may not file a revised or new rate designed to
recover costs not recovered under rates previously in effect.
(7) Rates involving marketing affiliates. If a pipeline does not
hold a blanket certificate under subpart G of this part, it may not
charge, in a transaction involving its marketing affiliate, a rate that
is lower than the highest rate it charges in any transaction not
involving its marketing affiliate.
13. Part 284 is amended by adding Sec. 284.11 to read as follows.
Sec. 284.11 Negotiated rates and services.
(a) Authority. An interstate pipeline that provides transportation
service under subparts B or G of this part may negotiate with shippers
the rates, or terms and conditions of service, in any contract,
provided the pipeline offers all shippers recourse to transportation
service under its generally applicable transportation tariff as an
alternative to negotiated service.
(b) Limitations on negotiations. Pipelines cannot negotiate rates
and services that:
(1) result in undue discrimination or preference;
(2) degrade the quality of existing services;
(3) hinder the release of capacity or otherwise significantly
reduce competition; or
(4) require customers, as a condition of obtaining negotiated rates
or services, to purchase sales, storage, or gathering services provided
by the pipeline, its affiliates, or upstream or downstream entities
that are unnecessary to the provision of the negotiated service.
(c) Review of recourse service. Pipelines must file (every 3 or 5
years) the following information regarding negotiated rates and terms
of service and recourse service.
(1) For each negotiated transaction, the pipeline must file, for
each calendar year, by category of negotiated transaction (transactions
taking effect on shortened notice and transactions subject to 30 days
notice) the following: the name of the shipper, the shipper's
designation (e.g., marketer, producer, LDC, end-user), the contract
number, the docket number under which the contract was filed with the
Commission, the type of service (e.g., firm or interruptible
transportation or storage), the contract demand, the rate, and the
volume. For transactions taking effect under shortened notice, the
pipeline must include an indication of the tariff categories under
which the contract was negotiated. For transactions subject to thirty
days notice, the pipeline must include a short description of the terms
and conditions negotiated.
(2) For each year, for each category of negotiated service and for
recourse services, by rate schedule, the pipeline must file data
showing aggregate contract demand, aggregate volumes, and aggregate
revenue.
14. In newly redesignated Sec. 284.13, paragraphs (c)(1)(ii) and
(c)(2)(iii) through (v) are added and paragraph (b)(1)(v) is revised to
read as follows.
Sec. 284.13 Standards for pipeline business operations and
communications.
* * * * *
(b) * * *
(1) * * *
(v) Capacity Release Related Standards (Version 1.2,
July 31, 1997), with the exception of Standard 5.3.2.
(c) * * *
(1) * * *
(ii) Capacity release nominations. Pipelines must permit shippers
acquiring released capacity to submit a nomination at the earliest
available nomination opportunity after the acquisition of capacity. If
the pipeline requires the replacement shipper to enter into a contract,
the contract must be issued within one hour of submission of the
transaction, but the requirement for contracting must not inhibit the
ability to submit a nomination at the time the transaction is complete.
(2) * * *
(iii) Imbalance management. A pipeline must provide, to the extent
operationally practicable, parking and lending or other services that
facilitate the ability of its shippers to manage transportation
imbalances. A pipeline must provide such services without undue
discrimination or preference of any kind against third parties that
seek to provide similar services to the shippers of the pipeline.
(iv) Penalties. A pipeline may include in its tariff transportation
penalties only to the extent necessary for system operations. A
pipeline must provide, on a timely basis, as much information as
possible about the imbalance and overrun status of each shipper and the
imbalance of the pipeline's system.
(v) Operational flow orders. A pipeline must take all reasonable
actions to minimize the issuance and adverse impacts of operational
flow orders (OFOs) or other measures taken to respond to adverse
operational events on its system. A pipeline must set forth in its
tariff clear standards for when such measures will begin and end and
must provide timely information that
[[Page 43022]]
will enable shippers to minimize the adverse impacts of these measures.
* * * * *
15. Part 284 is amended by adding Sec. 284.14 to read as follows:
Sec. 284.14 Reporting requirements for interstate pipelines.
An interstate pipeline that provides transportation service under
subparts B or G of this part must comply with the following reporting
requirements.
(a) Cross references. The pipeline must comply with the
requirements in part 161, part 250, and part 260, where applicable.
(b) Index of customers. (1) On the first business day of each
calendar quarter, subsequent to the initial implementation of this
provision, an interstate pipeline must provide for electronic
dissemination of an index of all its firm transportation and storage
customers under contract as of the first day of the calendar quarter.
Electronic dissemination will be by placing a file, adhering to the
requirements set forth by the Commission, on the pipeline's Internet
web site, pursuant to section 284.13 of this part, in a format which
can be downloaded. The pipeline must also submit the electronic file to
the Commission.
(2) Until an interstate pipeline is in compliance with the
reporting requirements of this paragraph, the pipeline must comply with
the index of customer requirements applicable to transportation and
sales under part 157, set forth under Sec. 154.111(b) and (c) of this
chapter.
(3) For each customer receiving firm transportation or storage
service, the index must include the information listed below:
(i) The full legal name of the customer;
(ii) The rate schedule number of the service being provided;
(iii) The contract number;
(iv) The contract effective date;
(v) The contract expiration date;
(vi) For transportation service, maximum daily contract quantity
(specify unit of measurement);
(vii) For storage service, maximum storage quantity (specify unit
of measurement);
(viii) The receipt and delivery points and the zones or segments in
which the capacity is held;
(ix) An indication as to whether the contract includes negotiated
rates or terms and conditions;
(x) Any affiliate relationship between the pipeline and the
customer or any affiliate relationships between contract holders;
(xi) The name of any agent or asset manager managing 20% or more of
the transportation service in a pipeline rate zone and the agent's and
asset manager's rights with respect to managing the transportation
service.
(4) The information included in the quarterly index must be
available on the pipeline's web site until the next quarterly index is
established.
(5) The requirements of this section do not apply to contracts
which relate solely to the release of capacity under Sec. 284.8, unless
the release is permanent.
(6) The requirements for the electronic index can be obtained at
the Federal Energy Regulatory Commission, Division of Information
Services, Public Reference and Files Maintenance Branch, Washington, DC
20426.
(c) Reports on firm and interruptible services. An interstate
pipeline must post the following information on its Internet web site,
and provide the information in downloadable file formats, in conformity
with section 284.13 of this part.
(1) For pipeline firm service, whether provided by the pipeline or
from release transactions under section 284.8 of this part, the
pipeline must post, contemporaneously with the execution of a contract
for service:
(i) The full legal name of the shipper receiving service under the
contract and the full legal name of the releasing shipper if a capacity
release is involved or an indication that the pipeline is the seller of
transportation capacity;
(ii) The contract number for the shipper receiving service under
the contract, and, in addition, for released transactions, the contract
number of the releasing shipper's contract;
(iii) The rate charged under each contract;
(iv) The duration of the contract;
(v) The receipt and delivery points and mainline segments covered
by the contract;
(vi) The contract quantity or the volumetric quantity under a
volumetric release;
(vii) Any special terms and conditions applicable to the contract;
and
(viii) Whether there is an affiliate relationship between the
pipeline and the shipper or between the releasing and replacement
shipper.
(2) For pipeline interruptible service, the pipeline must post on a
daily basis:
(i) The full legal name of the shipper;
(ii) The rate charged;
(iii) The receipt and delivery points and mainline segments over
which the shipper is entitled to nominate gas;
(iv) The quantity of gas the shipper is entitled to nominate;
(v) Whether the shipper is affiliated with the pipeline.
(d) Available capacity. (1) An interstate pipeline must provide on
its Internet web site and in downloadable file formats, in conformity
with section 284.13 of this part, equal and timely access to
information relevant to the availability of all transportation
services, including, but not limited to, the availability of capacity
at receipt points, on the mainline, at delivery points, and in storage
fields, whether the capacity is available directly from the pipeline or
through capacity release, the total design capacity of each point or
segment on the system, the amount scheduled at each point or segment on
a daily basis, and all planned and actual service outages or reductions
in service capacity.
(2) An interstate pipeline must make an annual filing by March 1 of
each year showing the estimated peak day capacity of the pipeline's
system, and the estimated storage capacity and maximum daily delivery
capability of storage facilities under reasonably representative
operating assumptions and the respective assignments of that capacity
to the various firm services provided by the pipeline.
(e) Semi-annual storage report. Within 30 days of the end of each
complete storage injection and withdrawal season, the interstate
pipeline must file with the Commission a report of storage activity.
The report must be signed under oath by a senior official, consist of
an original and five conformed copies, and contain a summary of storage
injection and withdrawal activities to include the following:
(1) The identity of each customer injecting gas into storage and/or
withdrawing gas from storage, identifying any affiliation with the
interstate pipeline;
(2) The rate schedule under which the storage injection or
withdrawal service was performed;
(3) The maximum storage quantity and maximum daily withdrawal
quantity applicable to each storage customer;
(4) For each storage customer, the volume of gas (in dekatherms)
injected into and/or withdrawn from storage during the period;
(5) The unit charge and total revenues received during the
injection/withdrawal period from each storage customer, noting the
extent of any discounts permitted during the period; and
(6) The related docket numbers in which the interstate pipeline
reported storage related injection/withdrawal transportation services.
16. In Sec. 284.106, paragraph (c) is removed and paragraph (b) is
revised to read as follows:
[[Page 43023]]
Sec. 284.106 Reporting requirements
* * * * *
(b) An interstate pipeline providing transportation service under
this subpart must comply with the reporting requirements of Sec. 284.14
of this part.
Sec. 284.223 [Amended]
17. In Sec. 284.223, paragraph (b) is removed and reserved.
18. Subpart H is revised to read as follows:
Subpart H--Assignment of Capacity on Upstream Interstate Pipelines
Sec. 284.241. Upstream interstate pipelines.
An interstate pipeline that offers transportation service on a firm
basis under subpart B or G of this part must offer without undue
discrimination to assign to its firm shippers its firm transportation
capacity, including contract storage, on all upstream pipelines,
whether the firm capacity is authorized under part 284 or part 157. An
upstream pipeline is authorized and required to permit a downstream
pipeline to assign its firm capacity to the downstream pipeline's firm
shippers.
Secs. 284.10, 284.123, 284.221, 284.261, 284.263, 284.266, and
284.286 [Amended]
19. Secs. 284.10, 284.123, 284.221, 284.261, 284.263, 284.266, and
284.286 [Amended]
In addition to the amendments set forth above, in 18 CFR part 284,
the following nomenclature changes are made:
A. Revise all references to ``Sec. 284.7'' to read ``Sec. 284.10''
in the following places:
1. Section 284.221(d)(2)(ii);
2. Section 284.261;
3. Section 284.263; and
4. Sections 284.266(a)(1) and (a)(2).
B. Revise all references to ``Secs. 284.8-284.13'' to read
``Secs. 284.7-284.9 and Secs. 284.11-284.14'' in the following places:
1. Section 284.261; and
2. Section 284.263.
C. Revise all references to ``Sec. 284.8(d)'' to read
``Sec. 284.7(d)'' in newly redesignated Secs. 284.10(c)(1) and (c)(2).
D. Revise all references to ``Secs. 284.8'' to read ``Secs. 284.7''
in Sec. 284.123 (b)(1).
E. Revise all references to ``Secs. 284.8(b)(2)'' to read
``Secs. 284.7(b)(2)'' in Sec. 284.286(b).
F. Remove the words ``Secs. 161.3(c), (e), (f), (g), and (h)'' and
add, in its place, the words ``Secs. 161.3(c), (e), (f), (g), (h), and
(i)'' in section 284.286(c).
[FR Doc. 98-20998 Filed 8-10-98; 8:45 am]
BILLING CODE 6717-01-P
