[Federal Register Volume 65, Number 108 (Monday, June 5, 2000)]
[Rules and Regulations]
[Pages 35706-35766]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-13216]



[[Page 35705]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Parts 154, et al.



Regulation of Short-Term Natural Gas Transportation Services, and 
Regulation of Interstate Natural Gas Transportation Services; Final 
Rule

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules 
and Regulations

[[Page 35706]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 154, 161, 250, and 284

[Docket Nos. RM98-10-001, RM98-10-004, RM98-12-001, RM98-12-004; Order 
No. 637-A]


Regulation of Short-Term Natural Gas Transportation Services, and 
Regulation of Interstate Natural Gas Transportation Services

Issued May 19, 2000.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule; order on rehearing.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
issuing an order addressing the requests for rehearing of Order No. 637 
[65 FR 10156, Feb. 25, 2000]. Order No. 637 revised Commission 
regulations to enhance the competitiveness and efficiency of the 
interstate pipeline grid. The order revised Commission pricing policies 
by waiving price ceilings for short-term released capacity for a two 
year period and, permitting pipelines to file for peak/off-peak and 
term differentiated rate structures. It also effected changes in 
regulations relating to scheduling procedures, capacity segmentation, 
pipeline imbalance processes and penalties, pipeline reporting 
requirements, and the right of first refusal. The rehearing order 
largely denies rehearing on these issues, but grants rehearing, in 
part, to make clarifying adjustments to the regulations regarding 
penalties, reporting requirements, and the right of first refusal.

DATES: The amendments to the regulations will become effective July 5, 
2000.

ADDRESSES: Federal Energy Regulatory Commission 888 First Street, N.E., 
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
Robert A. Flanders, Office of Markets, Tariffs, and Rates Federal 
Energy Regulatory Commission, 888 First Street, NE, Washington, DC 
20426, (202) 208-2084

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Adjustments to Rate Policies
    A. Removal of the Rate Ceiling for Capacity Release Transactions
    B. Peak and Off-Peak Rates
    C. Term Differentiated Rates
    D. Voluntary Auctions
II. Improvements to Competition Across the Pipeline Grid
    A. Scheduling Equality
    B. Segmentation and Flexible Point Rights
    C. Imbalance Services, Operational Flow Orders and Penalties
III. Reporting Requirements for Interstate Pipelines
IV. Other Pipeline Service Offerings
    A. The Right of First Refusal
    B. Negotiated Terms and Conditions
V. Miscellaneous Issues
    A. Corrections to Regulations
    B. Filing of Pro Forma Tariff Sheets

Figures

Figure 1--Capacity Release Transactions as Percentage of Maximum 
Rate (Oct. 1996-Feb. 2000)
Figure 2--Interruptible Transportation Rates as Percentage of 
Maximum Rate (Oct. 1996-Feb. 2000)
    Before Commissioners: James J. Hoecker, Chairman; William L. 
Massey, Linda Breathitt, and Curt Hebert, Jr.

Order on Rehearing

    In Order No. 637, issued on February 9, 2000, the Federal Energy 
Regulatory Commission (Commission) issued a final rule that amended 
Part 284 of the Commission's open access regulations to improve the 
efficiency of the market and to provide captive customers with the 
opportunity to reduce their cost of holding long-term pipeline capacity 
while continuing to protect against the exercise of market power.\1\ In 
addition, the Commission instituted a new effort to monitor the changes 
taking place in the market so that the Commission can be prepared to 
continue its reexamination of its current regulatory framework to 
better meet the challenges posed by the growing competitive market. 
Specifically, the final rule made the following changes in the 
Commission's regulatory model:
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    \1\ Regulation of Short-Term Natural Gas Transportation Services 
and Regulation of Interstate Natural Gas Transportation Services, 63 
FR 10156 (Feb. 25, 2000), III FERC Stats. & Regs. Regulations 
Preambles para. 31,091 (Feb. 9, 2000).
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    <bullet> The rule grants a waiver for a limited period of the price 
ceilings for short-term released capacity to enhance the efficiency of 
the market while continuing regulation of pipeline rates and services 
to provide protection against the exercise of market power.
    <bullet> The rule revises the Commission's regulatory approach to 
pipeline pricing by permitting pipelines to propose peak/off-peak and 
term differentiated rate structures. Peak/off-peak rates can better 
accommodate
    rate regulation to the seasonal demands of the market, while term 
differentiated rates can be used to better allocate the underlying risk 
of contracting to both shippers and pipelines.
    <bullet> The rule improves the competitiveness and efficiency of 
the interstate pipeline grid by changing regulations relating to 
scheduling procedures, capacity segmentation, and pipeline penalties.
    <bullet> The rule narrows the right of first refusal to remove 
economic biases in the current rule, while still protecting captive 
customers' ability to resubscribe to long-term capacity.
    <bullet> The rule improves reporting requirements to provide more 
transparent pricing information and to permit more effective monitoring 
for the exercise of market power and undue discrimination.
    Fifty-one requests for rehearing and clarification were filed, 
covering all the major elements of the rule.\2\ As discussed below, the 
Commission largely denies rehearing, but grants rehearing, in part, to 
make clarifying adjustments to the regulations regarding penalties and 
reporting requirements. It also grants rehearing to clarify that 
shippers with a multi-year contract for a service that is not available 
for 12 consecutive months are eligible to exercise the right of first 
refusal.
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    \2\ The appendix lists those filing for rehearing and 
clarification.
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I. Adjustments to Rate Policies

A. Removal of the Rate Ceiling for Capacity Release Transactions

    In Order No. 637, the Commission removed the rate ceiling for 
short-term (less than one year) capacity release transactions for a 
two-year period ending September 30, 2002. In determining that the 
removal of the rate ceiling for short-term capacity release 
transactions was warranted, the Commission examined the interaction of 
its cost-of-service regulations with the actual way in which gas 
markets operate today. Based on this analysis of the market, the 
Commission concluded that the rate ceiling should be removed because 
cost-of-service rate regulation is not well suited to the short-term 
capacity market, the rate ceiling interfered with the efficient 
operation of the market, removal of the rate ceiling for short-term 
capacity would have little effect on the prices paid for capacity 
during peak periods, since shippers can avoid ceiling by making bundled 
sales, and removal of the ceiling would provide short-term shippers 
with an additional transportation option. The Commission found that 
protection against the exercise of market power in the short-term 
capacity release market could be achieved in ways other than

[[Page 35707]]

direct price regulation, including competition from other sellers of 
released capacity, improved reporting, monitoring and complaint 
procedures, and the maintenance of Commission regulation of pipeline 
capacity. In order to review the effects of this change in regulatory 
philosophy, the Commission limited the removal of the price ceiling to 
a two-year period so that the Commission and the industry could obtain 
more complete information about how the change would actually affect 
prices.
    Requests for rehearing have been filed challenging the Commission's 
determination to grant a waiver of the price ceiling for short-term 
capacity release transactions.\3\ In addition, several pipelines 
request rehearing of the determination not to remove rate ceilings on 
their short-term capacity.\4\ As discussed below, the Commission is 
denying rehearing with respect to the waiver of the price ceiling \5\ 
and is denying the request to apply the waiver to pipeline services. 
Others requested rehearing or clarification regarding the way in which 
the regulation would be applied. The Commission will address those 
requests.
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    \3\ Rehearing Requests of Amoco, IPAA, Indicated Shippers, NGSA, 
NWIGU, National Association of Gas Consumers, Process Gas Consumers.
    \4\ Rehearing requests of CNG, Great Lakes, Kinder-Morgan, Koch, 
Williams.
    \5\ On April 20, 2000, Indicated Shippers and Independent 
Petroleum Association of America requested rehearing of the 
Commission's decision to deny their request for a stay of the price 
cap waiver. That request too is denied.
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1. Removal of the Price Ceiling
    The requests for rehearing contend that the removal of the rate 
ceiling for short-term capacity release transactions permits unjust and 
unreasonable rates, because the Commission has not put forward 
sufficient proof that the market for capacity release transactions is 
competitive. They maintain that the Commission improperly found that 
short-term shippers were entitled to less protection against market 
power than long-term shippers. They argue that the Commission legally 
is permitted to relax rate regulation for short-term shippers only when 
the Commission has conducted a market-by-market analysis to show that 
there are sufficient alternative sources of supply, so the resulting 
rates can be considered just and reasonable.\6\ They maintain the 
Commission has not conducted the market analysis of competition that it 
previously required in order to demonstrate a lack of market power and 
that reporting requirements and complaints are not an adequate basis to 
police market power abuses. The rehearing requests further maintain 
that the Commission failed to take into account the ability of 
pipelines to use their affiliates to purchase capacity, in order to 
capture the profits from above maximum rate capacity sales.\7\
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    \6\ Rehearing Requests by Amoco, IPAA, Indicated Shippers, NGSA, 
NWIGU, Process Gas Consumers.
    \7\ Rehearing Requests by Amoco, IPAA, Indicated Shippers, Ohio 
Oil and Gas Association, Process Gas Consumers.
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    Those seeking rehearing also argue that the Commission cannot base 
its determination to release the rate ceiling on the evidence showing 
that releasing shippers can avoid maximum rate regulation by making 
bundled gas sales \8\ with transportation values that exceed the 
maximum rate. They maintain that the Commission should not be permitted 
to justify the removal of the rate ceiling on its own failure to make 
the capacity release system work and its continued tolerance of the 
bundled sales market.
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    \8\ The rehearing requests refer to the bundled sales market as 
the gray market.
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    Under section 4 of the Natural Gas Act (NGA), the Commission's 
responsibility is to ensure that rates are just and reasonable. To be 
sure, that responsibility entails an examination of the potential for 
the exercise of market power.\9\ But rate regulation cannot perfectly 
emulate the prices produced by a competitive market and rate regulation 
frequently reflects a balance between the potential for exercise of 
market power and the need to promote allocative or productive 
efficiency or achieve other regulatory goals.\10\ The Commission's 
current regulatory framework, for instance, has long permitted some 
exercise of market power by pipelines through selective discounting 
below the maximum rate. The justification for permitting this exercise 
of market power is to enhance efficiency by increasing throughput and 
to benefit those captive customers with long-term contracts by 
reducing, in the pipeline's rate case, the amount of the fixed costs 
that otherwise would be recovered through the rates paid by those 
captive customers.\11\
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    \9\ 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).
    \10\ See Environmental Action v. FERC, 996 F.2d 401 (D.C. Cir. 
1993) (recognizing the need to balance efficiency gains from 
unfettered trading with the need to protect against the exercise of 
market power). See also Permian Basin Area Rate Cases, 390 U.S. 747, 
792 (1968) (need to balance interests of investors and the 
protection of the public interest); FPC v. Hope Natural Gas Co., 320 
U.S. 591, 603 (1944) (ratemaking involves the balancing of investor 
and consumer interests).
    \11\ Associated Gas Distributors v. FERC, 824 F.2d 981, 1010-
1012 (D.C. Cir. 1987) (selective discounting permitted to benefit 
captive customers by contributing to payment of fixed costs), cert. 
denied, 485 U.S. 1006 (1988); United Distribution Companies v. FERC, 
88 F.3d 1105, 1141-42 (D.C. Cir. 1996) (affirming Commission's 
determination to permit selective discounting and not requiring 
pipelines to discount); 1 A. Kahn, the Economics of Regulation 131-
33 (1970) (price discrimination one solution to problems of natural 
monopoly and declining costs).
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    In this instance, the Commission has reviewed its regulations in 
light of the actual workings of the gas market. Based on this analysis, 
the Commission decided to make an incremental change to its current 
regulatory framework by creating a two-year waiver of price ceilings 
only for short-term capacity release transactions in the secondary 
market, while retaining rate regulation for primary capacity available 
from the pipeline as well as long-term capacity release transactions. 
The Commission determined that cost-of-service rate ceilings for short-
term capacity release transactions do not approximate competitive 
prices. It further found that maintenance of the rate ceiling reduces 
efficiency, inhibits capacity trading and reduces the dissemination of 
accurate pricing information, limits shippers' capacity options, and 
inequitably allocates the cost of capacity between long-term and short-
term shippers. Rather than continuing a traditional approach to 
regulation, the Commission has opted for a different regulatory 
approach which first, seeks to reduce the potential for the exercise of 
market power and second, employs contemporaneous reporting and 
monitoring along with case-specific enforcement mechanisms to identify 
and correct exercises of market power. The Commission will discuss 
below the various factors that led it to the conclusion that, on 
balance, removal of the price ceiling for short-term capacity release 
transactions will result in just and reasonable rates for all shippers 
and will respond to the rehearing requests in each of these areas.
    a. Cost-of-Service Ratemaking. The Commission found in Order No. 
637 that cost-of-service ratemaking is not well suited to the short-
term capacity release market. The purpose of regulating a pipeline's 
rates is to try to capture the productive efficiency of a natural 
monopoly while imposing limits on the monopolist's ability to exercise 
market power. To achieve this goal, cost-of-service ratemaking limits a 
pipeline's rates to an amount sufficient to recover its revenue 
requirement. Cost-of-service regulation inhibits the exercise of the 
pipeline's market power because the pipeline's rates are limited, 
eliminating a monopolist's incentive to

[[Page 35708]]

withhold capacity (by not constructing facilities) in order to raise 
prices through the creation of scarcity. This rationale for limiting 
rates for pipelines, however, has little applicability to the secondary 
market where releasing shippers do not control the amount of long-term 
capacity that will be built.
    In addition, the static annual rates produced by cost-of-service 
ratemaking bear no relationship to competitive rates that would be 
established in the short-term market, particularly during peak periods. 
The evidence cited in Order No. 637 showing the implicit value of 
transportation in the bundled sales market demonstrates the variability 
of transportation value in the short-term market and the divergence 
between transportation value and cost-of-service rates. In short, 
traditional methods of cost-of-service regulation cannot come close to 
emulating the variability of short-term market prices.
    The rehearing requests do not dispute that the cost-of-service 
ratemaking method is ill-suited to the short-term capacity release 
market, and they do not challenge the Commission's conclusion that no 
method of cost-of-service rate regulation could emulate the prices a 
competitive market would produce. Indeed, they recognize that during 
peak periods, transportation prices in a competitive market could 
exceed the cost-of-service maximum rate.\12\ Despite the recognized 
infirmities of cost-of service regulation as applied to the short-term 
capacity release market, the rehearing requests contend that the 
Commission has no choice other than to continue to use this method of 
regulation unless it conducts a market analysis showing that each 
market performs competitively. As explained below, the Commission has 
concluded that the removal of cost-of-service regulation for short-term 
capacity release transactions is warranted without a full market-by-
market analysis.
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    \12\ Rehearing Request of Process Gas Consumers, at 30.
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    b. Bundled Sales and Transportation. In today's gas market, 
shippers can effectively bundle gas and transportation to make gas 
sales in downstream markets. During peak periods, when transportation 
values exceed maximum ceiling rates, firm shippers can avoid the 
ceiling rates by making bundled sales at delivery points, rather than 
releasing the transportation capacity independently. As a consequence, 
the Commission concluded that the price ceiling does not limit the 
prices paid by shippers in the short-term capacity release market as 
much as it limits their transportation options. Due to the price 
ceiling, many shippers without firm transportation are limited to 
purchasing gas through a bundled sales transaction or simply taking gas 
from the pipeline system and incurring overrun and scheduling 
penalties. The price ceiling in effect denies these shippers the option 
of obtaining transportation capacity (without gas) during peak periods.
    The rehearing requests recognize the existence of the bundled sales 
market and do not challenge the fact that the value of transportation 
in bundled sales transactions can exceed the maximum rate derived from 
cost-of-service regulation. Some suggest that the bundled sales market 
is not a factor at upstream pooling points in the production area, 
constraint points, or at interconnects, although they do not explain 
why bundled sales cannot be made at such points.\13\ In fact, comments 
in this proceeding indicate that production area pricing is governed by 
the same basis differentials as downstream markets.\14\ Those 
requesting rehearing instead argue that the Commission should not allow 
its failure to ``make the capacity release system work, and continued 
tolerance of the grey market'' \15\ justify the removal of the price 
ceilings in the short-term capacity release market.
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    \13\ Rehearing Requests of Amoco, IPAA, Indicated Shippers, 
NGSA.
    \14\ Comments by Koch, at 41-42 (on a production area pipeline, 
``the value of transportation services (both firm and interruptible) 
is driven primarily by the basis differentials that are present 
across its system'').
    \15\ Rehearing Request of IPAA, at 16. For the same point, see 
Rehearing Requests by Amoco, Indicated Shippers, NGSA, Process Gas 
Consumers.
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    The capacity release system was intended to provide an efficient 
method by which shippers could reallocate transportation capacity to 
other shippers in a way that is fair, open, and transparent and that 
would provide good market information about the value of pipeline 
capacity. But the short-term rate ceiling prevents the capacity release 
system from fulfilling these goals during peak periods precisely 
because releasing shippers seek to avoid the rate cap by ignoring the 
capacity release market and bundling the transportation with downstream 
sales. Removal of the rate ceiling on short-term capacity release 
transactions, therefore, will make the capacity release system more, 
not less, viable. It will also serve to make capacity transactions 
during peak periods more transparent, providing good information to all 
shippers about the market value of transportation.
    Nor do those seeking rehearing suggest how the Commission could 
regulate the bundled sales market in ways that would not reduce the 
efficiency of that market and that would be consistent with Congress's 
deregulation of gas sales.\16\ For the Commission to ignore the bundled 
sales market, as the rehearing requests suggest, is to take a 
panglossian perspective, rather than seeing the market as it really 
exists. The Commission has concluded that its regulation will be far 
more effective if it recognizes how business is really done and seeks 
to impose regulatory controls that are consistent with that market, 
rather than continuing to use regulatory methods that are ineffective 
and reduce efficiency. Given the ability of shippers to make bundled 
sales without rate ceilings, removal of the rate ceiling for capacity 
release transactions will have little adverse effect on the 
transportation costs consumers will pay. Rather, lifting of the price 
ceiling adds another capacity option to the market that can increase 
efficiency and the transparency of transactions, and thereby, result in 
lower effective transportation rates.
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    \16\ Natural Gas Wellhead Decontrol Act of 1989, Pub. L. No. 
101-60, 103 Stat. 157 (1989); Natural Gas Policy Act, 
Sec. 601(a)(1), 15 U.S.C. 3431 (Commission jurisdiction does not 
apply to first sales of domestic gas).
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    c. Promotion of Greater Efficiency. Even if the bundled sales 
market were not effective as a substitute for releasing capacity, the 
Commission found in Order No. 637 that the price ceiling on capacity 
release transactions inhibits the efficient allocation of capacity and 
harms short-term shippers. The price ceiling in the long-term market 
serves to protect customers by reducing the pipeline's ability to 
exercise market power either by withholding capacity to raise price or 
by price discriminating and, as a consequence, creates the incentive 
for pipelines to add capacity when demand increases. The pipelines have 
an incentive to increase capacity, because adding capacity is the only 
way the pipeline can increase long-term revenue. In the short-term 
capacity release market, however, a rate ceiling does not provide 
comparable protection.
    Shippers without firm capacity are always at risk of being unable 
to obtain capacity, because the services on which they rely, pipeline 
interruptible or released capacity, may not be available during peak 
periods, or may be available only in limited quantities. Given the 
limited amount of capacity available during peak periods, a rate 
ceiling is of little or no benefit to a short-term shipper; capping the 
price the shipper can pay provides no protection to a

[[Page 35709]]

shipper that, as a result of that ceiling, cannot obtain the capacity 
it needs. The rate ceiling creates an inefficient allocation system 
which operates to prevent the shipper most valuing the capacity from 
being able to obtain it. For example, the rate ceiling results in 
arbitrary allocations of capacity based on queue positions or on a pro 
rata allocation, in which the shipper most needing the capacity may be 
unable to obtain any capacity or the amount of capacity it needs. 
Indeed, the removal of the rate ceiling benefits short-term shippers 
because the shipper placing a high value on the capacity has greater 
assurance of obtaining the capacity it needs than it does under a price 
cap where that shipper may be unable to obtain any capacity.\17\ The 
rate ceiling could have the further effect of actually reducing the 
amount of released capacity available, because price ceilings may make 
the release of capacity uneconomic for some shippers.
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    \17\ Those short-term shippers who currently have a high place 
on the pipeline's queue may prefer the current system, because they 
can obtain capacity at a cheap regulated rate and use it to effect a 
bundled sale at market prices reflecting a higher market value. But 
this is a selective benefit to certain shippers not a benefit to the 
market as a whole.
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    Those requesting rehearing do not contest that the use of price 
ceilings during peak periods can result in an inefficient allocation of 
capacity. Instead, Indicated Shippers maintain that the Commission's 
assertion that removing price ceilings could induce releasing shippers 
to release additional capacity is completely speculative. But the 
Commission's conclusion was not speculation; it was based on sound 
economic theory.\18\ A releasing shipper will hold onto its capacity if 
the amount it receives for the release is less than its opportunity 
cost, the value to the shipper of the next best use of its capacity. 
Thus, a releasing shipper, subject to a rate ceiling, will hold onto 
capacity if the amount it will receive is less than the cost to it of 
using an alternative fuel or storage, or the cost of reducing its use 
of gas through conservation. However, if the releasing shipper can 
obtain the market value for its capacity and that value exceeds the 
value of its next best alternative, it will choose to release that 
capacity, thereby adding to the amount of released capacity to the 
market. The effect of increasing the amount of released capacity 
available in the market will be to reduce the price for transportation, 
because, as the supply of transportation increases, but the demand for 
transportation remains the same, the price of transportation will 
decrease.
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    \18\ Associated Gas Distributors v. FERC, 824 F.2d 981, 1008-09 
(D.C. Cir. 1987) (agency can rely upon generally accepted economic 
theory even without factual evidence to support proposition that 
increased competition will lead to lower prices), cert, denied, 485 
U.S. 1006 (1988); Environmental Action v. FERC, 939 F.2d 1057, 1064 
(D.C. Cir. 1991) (agency entitled to rely upon predictions about the 
market it regulates).
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    Indicated Shippers also contends that in light of pipelines' 
ability to file for peak and off-peak rates, the Commission has not 
explained why additional action is needed to aid long-term shippers in 
defraying the cost of their reservation charges. In the first place, 
the purpose of removing the rate ceiling was not simply to permit firm 
shippers a greater opportunity to defray the cost of their reservation 
charges (although that was one goal). An equally important purpose was 
to help foster an efficient trading market in which capacity would be 
sold to the shipper placing the highest value on obtaining 
transportation service. Particularly during peak periods when capacity 
is most constrained, an efficient market is needed so that a market 
clearing price will provide for the efficient allocation of capacity. 
While permitting pipelines to file for peak and off-peak rates will 
enable pipelines to file for rate structures more in line with the 
value of transportation capacity, the development of peak and off-peak 
rates that remain within a pipeline's cost-of-service may not come 
close to duplicating the rates, particular during peak periods, that a 
competitive market would require to clear efficiently. As the data 
cited in Order No. 637 with respect to the value of transportation 
demonstrates, during peak demand periods the value of transportation in 
an efficient market rises dramatically for short periods to levels that 
would exceed the rates that pipelines could establish through proposals 
for cost-of-service peak/off-peak rates.\19\ For instance, during some 
peak winter periods, the value of transportation was 8-13 times greater 
than the applicable maximum rate for short periods of time, but during 
other winter periods with differing demand conditions the peak period 
rates were only 1\1/2\ to 2 times the maximum rate. Pipelines would not 
propose revenue neutral cost-of-service peak rates coming close to the 
higher levels that occur during peak constraint periods, because they 
could never be sure how frequently those demand conditions would occur 
and if they established peak winter rates at that level, their off-peak 
rates would be so low that in many cases, they would be unable to 
recover their cost-of-service. Moreover, even if pipelines could 
propose peak rates high enough to cover market prices during maximum 
constraint periods, those rates would be far too high for the same time 
period when demand conditions are not as severe. While cost-of-service 
peak and off-peak pricing has a legitimate purpose in the world of 
cost-of-service ratemaking, these rates likely will not approximate the 
efficient rates that a competitive market needs to clear during peak 
periods. In order to create such a efficient market, cost-of-service 
peak and off-peak rates are not sufficient and removal of the rate 
ceiling for capacity release transactions (with the protections adopted 
by the Commission) is necessary to permit efficient pricing.
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    \19\ Order No. 637, 65 FR at 10196, 10174-79, III FERC Stats. & 
Regs. Regulations Preambles para. 31,091, at 31,271-74 (figures 6 
and 7).
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    d. Equitable Allocation of Capacity Costs. The Commission found in 
Order No. 637 that the price ceiling can result in an inequitable 
distribution of costs between long-term firm capacity holders and 
short-term shippers. Indicated Shippers maintain that the Commission 
has no foundation for finding that higher rates during peak periods are 
needed to reapportion cost responsibility between short-term and long-
term shippers. They argue that the Commission failed to take any steps 
in Order No. 637 to ensure that capacity is not withheld during off-
peak periods and, therefore, they maintain market power may be 
exercised during off-peak periods.
    Prior to Order No. 636, and the institution of capacity release, 
pipelines were the only source of interruptible capacity during off-
peak periods. Pipelines could discount selectively, charging maximum 
rates to customers with more inelastic demand and charging discounted 
rates to customers with alternatives, such as dual fuel capability. The 
pipelines' ability to selectively discount benefitted the long-term 
firm capacity holders, because the greater contribution to cost 
recovery provided by interruptible service would reduce firm shippers' 
rates.
    The institution of capacity release in Order No. 636, along with 
flexible receipt and delivery points, placed competitive pressure on 
the pipelines' interruptible service, because a shipper in the short-
term market was given the choice of obtaining capacity from a number of 
releasers, rather than being limited to pipeline interruptible service. 
In fact, during the Order No. 636 proceedings, pipelines were concerned 
that competition from capacity release would so reduce the level and 
prices for interruptible service that they would be unable to recover 
the costs allocated to

[[Page 35710]]

interruptible service.\20\ Accordingly, in restructuring proceedings, 
pipelines reduced the cost responsibility for interruptible service, 
and increased firm shippers' rates. After the institution of capacity 
release, firm shippers could reduce their costs of holding pipeline 
capacity by releasing the capacity they held as well as receiving 
interruptible revenue credits to the extent the pipeline was able to 
sell interruptible service above the costs allocated to that 
service.\21\
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    \20\ 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 30,562-63 (Aug. 3, 1992).
    \21\ Id.
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    With the advent of capacity release, however, the rates for 
capacity release and pipeline interruptible service have fallen well 
below maximum tariff rates, particularly during off-peak periods, as 
would be expected from the addition of numerous firm shippers who are 
now competing with the pipeline to sell capacity during off-peak 
periods. This is well documented. Numerous commenters made the point 
that competition from capacity release transactions has depressed 
short-term rates, particularly during off-peak periods, and has hurt 
long-term shippers by requiring them to bear a greater proportion of 
capacity costs.\22\
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    \22\ Associated Gas Distributors v. FERC, 824 F.2d 981, 1008-
1009 (D.C. Cir. 1987) (agencies do not need to conduct experiments 
to verify predictions that competition will lower prices), cert. 
denied, 485 U.S. 1006 (1988). Comments of AGA I, Arkansas PSC, 
Consolidated Edison, Enron Pipelines, Illinois Commerce Commission, 
INGAA, NARUC, NASUCA, Nisource, Pennsylvania/Ohio Consumer 
Advocates, Pennsylvania PUC, Philadelphia Gas Works, Piedmont/UGI, 
PSC of Wisconsin, PUC of Ohio, and Washington Gas Light.
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    Studies support the finding that short-term rates have fallen well 
below maximum rates. One study, using data from the period 1992-1998, 
has shown that the average rates for released capacity range from 31% 
to 76% of maximum rates in 17 pipeline corridors, with only 5 of the 
corridors exceeding an average rate of 60%.\23\ Commission data from 
capacity release and interruptible transactions also support the 
conclusion that short-term rates fall well below maximum tariff rates. 
The following graphs show the average prices of capacity release 
transactions and discounted pipeline interruptible transportation from 
October 1996 to February 2000, as a percentage of the applicable 
maximum tariff rate.\24\
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    \23\ Henning & Sloan, Analysis of Short-Term Natural Gas 
Markets, 41-45 (Energy and Environmental Analysis, Inc., November 
1998) (the authors conclude that these percentages are somewhat 
overstated insofar as they reflect maximum rate transactions 
mandated by state unbundling programs).
    \24\ The data are derived from capacity release data downloaded 
from 33 pipeline Internet sites, and the discount reports filed by 
the pipelines with the Commission.
---------------------------------------------------------------------------

    The average capacity release rate for all pipelines in the sample 
ranges from 30% to 70% of the pipeline's maximum rate, with the lowest 
average in the off-peak winter months. Off-peak rates during the summer 
months were below 50% of the maximum rate in all three off-peak 
periods.
[GRAPHIC] [TIFF OMITTED] TR05JN00.000


[[Page 35711]]


[GRAPHIC] [TIFF OMITTED] TR05JN00.001

    For discounted interruptible transportation, the average rate 
ranged from the mid-30% to mid-40% of maximum rates.\25\ Removal of the 
rate ceiling, therefore, removes a regulatory bias in the current 
system and will help to create a more equitable distribution of 
capacity costs between short and long-term customers, just as selective 
discounting did before the advent of capacity release. Prior to 
capacity release, pipeline sales of interruptible transportation 
reduced the cost responsibility of long-term shippers, because the 
revenue from interruptible transportation lowered the amount of costs 
allocated to long-term firm shippers. Shippers with inelastic demand 
buying short-term interruptible transportation service were more likely 
to pay maximum rates, because they had fewer capacity alternatives. 
With the advent of capacity release, however, the prices for released 
capacity during the off-peak periods are well below maximum rates and 
the rate ceiling prevents long-term shippers from recovering the value 
of capacity during peak periods. Similarly, pipeline interruptible 
transportation recovers less of the cost-of-service than it did before, 
so long-term shippers are required to shoulder a higher level of cost 
responsibility than they did prior to the institution of capacity 
release.
---------------------------------------------------------------------------

    \25\ The purpose of these data is to compare the rates for 
capacity release and interruptible service to the maximum tariff 
rate. Due to differences in the way in which capacity release and 
interruptible transportation are reported, one can draw no 
conclusion about whether the average rates for capacity release are 
higher or lower than the rates for interruptible service. The 
average capacity release rates include deals at the maximum tariff 
rate, but the average discounted interruptible rate does not include 
maximum rate transactions because prior to Order No. 637, pipelines 
did not include maximum rate interruptible transactions in their 
discount reports. In addition, the capacity release transactions are 
weighted by the volume of the contract demand involved, while the 
interruptible transactions are simple averages, because 
interruptible shippers do not have a contract demand. They can ship 
only as much gas as the pipeline has available.
---------------------------------------------------------------------------

    Removal of the rate ceiling on capacity release transactions, 
therefore, will help restore the previous balance between the cost 
responsibility of long and short-term shippers, but in a way consistent 
with prices in a competitive market. Short-term shippers will continue 
to benefit from lower rates during off-peak periods, but will now face 
more appropriate market rates during peak periods. By the same token, 
long-term customers, which can recover only a small portion of their 
capacity costs through capacity release during off-peak periods, will 
be able to recover a greater proportion of those costs during peak 
periods. As a result of removing the rate ceiling, short-term shippers 
will pay their fair share of capacity costs through the release market 
to reflect their peak period use and long-term captive customers will 
benefit by being better able to defray their costs of holding capacity 
by selling released capacity.
    e. Protection Against the Exercise of Market Power. In Order No. 
637, the Commission concluded that maximum rate regulation may not be 
appropriate for regulating the short-term capacity release market, that 
there are a number of factors which inhibit the ability of releasing 
shippers to exercise market power, and that the Commission can assure 
just and reasonable rates through indirect methods. Competition among 
capacity releasers--enhanced by the Commission's regulations providing 
for flexible receipt and delivery point rights and capacity 
segmentation--provides protection against the exercise of market power. 
This protection is supplemented by public reporting of pricing, along 
with complaint procedures that permit the Commission to monitor and 
respond to complaints about the exercise of market power. In addition, 
the Commission is maintaining regulatory protections against market 
power abuse, including the retention of the Commission's current 
posting and bidding requirements for capacity release transactions, the 
maintenance of

[[Page 35712]]

rate regulation on primary pipeline capacity and on long-term capacity 
release transactions, and the regulation of pipeline penalty levels to 
establish an effective ceiling price for release transactions.
    The crux of the arguments presented by those seeking rehearing is 
that regardless of the limits of maximum rate regulation and the 
inefficiencies created by such rate regulation for the short-term 
capacity release market, the Commission legally must continue to apply 
cost-based ceiling rates in the short-term capacity release market 
unless it conducts a detailed market study showing that there are a 
sufficient number of competing suppliers of capacity to ensure the 
market is competitive. They maintain that without such a market-by-
market study, removal of rate ceilings is not permissible. The 
Commission does not view its authority to choose appropriate regulatory 
methods for implementing the Natural Gas Act to be so limited. The 
Commission will discuss below its legal authority to remove rate 
ceilings and the protections against the exercise of market power that 
will continue to exist.
(1) Legal Justification
    The courts have long recognized that the Commission is not ``bound 
to the use of any single formula or combination of formulas in 
determining rates.'' \26\ ``Under the statutory standard of `just and 
reasonable,' it is the result reached not the method employed which is 
controlling.'' \27\ The courts have recognized that the Commission's 
ratemaking function rates requires a balancing of interests.\28\
---------------------------------------------------------------------------

    \26\ FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944); 
Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C. Cir. 
1993); Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 1501 
(D.C. Cir. 1984).
    \27\ Hope, 320 U.S. 591, 602.
    \28\ Permian Basin Area Rate Cases, 390 U.S. 747, 792 (1968) 
(need to balance interests of investors and the protection of the 
public interest); FPC v. Hope Natural Gas Co., 320 U.S. 591, 603 
(1944) (ratemaking involves the balancing of investor and consumer 
interests); Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 
1502 (D.C. Cir. 1984) (balance of financial interest of regulated 
company and public interests).
---------------------------------------------------------------------------

    They further recognize that the Commission's ratemaking function 
requires the making of ``pragmatic adjustments which may be called for 
by particular circumstances.'' \29\ The Court, for example, recognized 
the difficulties the Commission faced in regulating individual producer 
prices and permitted the Commission to depart from individual producer 
cost-of-service ratemaking to the use of area and national rates.\30\ 
The Court also has found that the Commission has the authority to 
depart from cost-of-service ratemaking for some classes of customers 
and to rely upon methods of indirect regulation to keep rates within 
just and reasonable levels.\31\
---------------------------------------------------------------------------

    \29\ Permian Basin Area Rate Cases, 390 U.S. 747, 777 (1968). 
See FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Hope, 
320 U.S. 591, 602.
    \30\ Permian Basin Area Rate Cases, 390 U.S. 747 (1968) 
(permitting area rates); Mobil Oil Exploration & Producing 
Southeast, Inc. v. United Distribution Companies, 498 U.S. 211 
(1991) (permitting the collapse of prior vintage rates into a single 
national ceiling rate equal to the highest pre-existing ceiling 
rate).
    \31\ FPC v. Texaco, 417 U.S. 380 (1974) (authority to assure 
just and reasonable rates through indirect regulation as opposed to 
direct price regulation); Permian Basin Area Rate Cases, 390 U.S. 
747, 787 (1968) (Commission empowered to prescribe different 
requriements for different classes of persons or matters).
---------------------------------------------------------------------------

    In Order No. 637, the Commission examined the available methods of 
direct rate regulation as well as the operation of the gas marketplace, 
and concluded that direct rate regulation of the short-term release 
market did more harm than good, since shippers can avoid rate 
regulation in the short-term capacity release market by making bundled 
sales and because regulation of short-term rates results in market 
inefficiency, findings the rehearing requests do not significantly 
challenge. In this context, the Commission determined that its existing 
methods of rate regulation needed to be changed to better comport with 
the actual operation of the market.\32\ To respond to the changes in 
the market, the Commission undertook a limited program to improve the 
efficiency of the short-term capacity release market in which rate 
regulation was relaxed for a short period only for short-term capacity 
release transactions. In place of direct rate regulation, the 
Commission is relying on a combination of other factors to ensure rates 
remain just and reasonable, including competition among releasing 
shippers, regulatory changes to enhance competition, posting 
requirements to increase transparency, monitoring and enforcement, and 
the continuation of regulation on pipeline capacity. The Commission 
limited the program to a two-year period, which enables the Commission 
to gather data on market performance which otherwise would be 
unavailable.
---------------------------------------------------------------------------

    \32\ Permian Basin Area Rate Cases, 390 U.S. 747, 785, 790 
(1968) (Commission permitted to adopt policies needed to respond to 
demands of changing circumstances).
---------------------------------------------------------------------------

    The setting of just and reasonable rates is intended to establish a 
reasonable balance between the interests of pipelines and 
consumers.\33\ In this rule, the Commission has retained cost-of-
service regulation for pipelines to assure just and reasonable prices 
for primary pipeline capacity. Since firm shippers can make bundled 
sales without rate ceilings, the current price ceiling on capacity 
release transactions in the secondary market has little impact on final 
consumer prices and, in fact, as explained earlier, lifting the rate 
ceiling may help to reduce such prices by increasing the efficiency and 
transparency of the market. With the market and regulatory protections 
against market power, the lifting of the rate ceiling for short-term 
capacity release transactions is consistent with the Commission's 
statutory authority because it will have limited effect on consumer 
prices and provides protection against unjust and unreasonable prices.
---------------------------------------------------------------------------

    \33\ Hope, 320 U.S. 591, at 603 (ratemaking involves a balance 
of investor and consumer interests); Tejas Power Corporation v. 
FERC, 908 F.2d 998 (D.C. Cir. 1990) (Commission must protect 
interest of consumers); Farmers Union Central Exchange, Inc. v. 
FERC, 734 F.2d 1486, 1502 (D.C. Cir. 1984) (strike a fair balance 
between financial interests of the regulated company and public 
interest).
---------------------------------------------------------------------------

    The cases principally cited in the rehearing requests do not 
preclude the approach adopted by the Commission in Order No. 637.\34\ 
First, these cases concern the lifting of price ceilings for primary 
capacity from a pipeline or regulated utility, not, as is the case 
here, with the relaxation of rate regulation only in the secondary 
market, with rate regulation maintained for primary pipeline capacity. 
Second, they do not indicate, as the rehearing requests contend, that a 
competitive market analysis is a prerequisite for relaxing cost-of-
service rate regulation in the secondary market.
---------------------------------------------------------------------------

    \34\ The cases principally cited in the rehearing requests are 
Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 1509-10 (D.C. 
Cir. 1984), Elizabeth Gas Company v. FERC, 10 F.3d 866 (D.C. Cir. 
1993), Environmental Action v. FERC, 996 F.2d 401 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    Farmers Union did not require a detailed market-by-market study 
before relaxing cost-of-service rate regulation. In Farmers Union, the 
Court found that the Commission had not justified relaxation of cost-
based regulation of oil pipeline companies, because the Commission had 
not shown how its overall regulatory program would ensure that pipeline 
rates remained within the zone of reasonableness. But Farmers Union 
focused on balancing the financial interests of the oil pipelines and 
the relevant public interest and did not focus on regulation of the 
secondary or resale market. Even so, Farmers

[[Page 35713]]

Union recognized that the Commission was not confined to cost-of-
service ratemaking (734 F.2d 1486, at 1501), that non-cost factors 
could play an important role in determining whether rates are just and 
reasonable (734 F.2d 1486, at 1502), that changing circumstances can 
justify an agency in taking a new approach to the determination of just 
and reasonable rates (734 F.2d 1486, at 1503), and that rate regulation 
can be relaxed if the regulatory scheme itself acts as a monitor to 
maintain rates in the zone of reasonableness or to act as a check on 
rates if they are not (734 F.2d 1486, at 1509). The court concluded 
that ``moving from heavy to lighthanded regulation ``can be justified 
by a showing that under current circumstances, the goals and purposes 
of the statute will be accomplished through substantially less 
regulatory oversight.'' \35\
---------------------------------------------------------------------------

    \35\ 734 F.2d 1486, at 1510.
---------------------------------------------------------------------------

    In Order No. 637, the Commission, satisfied the Farmers Union 
criteria. It described in detail the non-cost factors and industry 
changes that justified the relaxation of cost-of-service regulation for 
short-term capacity release transactions. It demonstrated how the 
regulatory scheme, including competition, monitoring, complaint 
procedures, mitigation measures, such as the capacity auction, and the 
continuation of regulation for primary pipeline services, would act as 
a check to ensure that rates remain just and reasonable. For instance, 
unlike Farmers Union, where the Court found the Commission had failed 
to document how market forces would limit rates to just and reasonable 
levels, \36\ the record shows that competition from multiple firm 
shippers has successfully reduced rates, particularly during off-peak 
periods, to well below the maximum regulated rate. The Commission found 
that, given the interaction of all these factors, the goals and 
purposes of the NGA would be accomplished through relaxation of cost-
of-service rates for the short-term capacity release market and greater 
reliance on other regulatory initiatives for controlling the potential 
exercise of market power.
---------------------------------------------------------------------------

    \36\ 734 F.2d 1486, at 1508.
---------------------------------------------------------------------------

    Elizabethtown was the next case in which the court considered 
relaxation of a cost-of-service ratemaking. In Elizabethtown, the court 
affirmed the Commission's determination to replace cost-of-service 
ratemaking for pipeline gas sales with market based pricing, rejecting 
the contention that the Commission is required under the NGA to base 
rates on historic cost-of-service ratemaking principles. The court 
recognized that the use of the Commission's section 5 authority, either 
upon the Commission's own motion or that of a complaint, can assure 
that negotiated rates remain just and reasonable. \37\ As the rehearing 
requests note, in Elizabethtown, the Commission relied on a market 
study as part of its conclusion that market-based rates were just and 
reasonable, but the court did not suggest that such a market study was 
a necessary requirement for permitting market-based rates if other 
factors would keep rates within a just and reasonable range.
---------------------------------------------------------------------------

    \37\ 10 F.3d 866, 870.
---------------------------------------------------------------------------

    Environmental Action continued the movement toward the use of 
lighter handed regulation when needed to achieve other statutory goals. 
In Environmental Action, the Court approved a relaxation of cost-of-
service rate regulation for an electric power pool in order to promote 
more effective capacity trading, even though the Commission did not 
conduct a detailed market analysis of competition. Environmental Action 
admittedly is different than the Commission's action in this 
proceeding, because while the Commission in Environmental Action did 
not rely upon company-by-company cost-of-service analysis to design 
rates, it maintained a cost based rate ceiling based on the 
hypothetical cost of the average company for firm energy, the most 
valuable and expensive service offered in the power pool. The Court 
found that the Commission could relax rate regulation because the 
Commission had struck a reasonable balance between promoting efficiency 
through capacity trading and relying on competition and price 
disclosure as a means of protecting against price gouging and the 
exercise of market power.\38\ In Environmental Action, the Court 
further found that the benefits of free and open trading justified a 
risk of price discrimination against the most captive members of the 
pricing pool. Similarly, the benefits of more efficient and effective 
capacity trading in this instance outweigh any limited potential for 
the exercise of market power during the few periods in which 
transportation value exceeds maximum rates.
---------------------------------------------------------------------------

    \38\ 996 F.2d 401, 410.
---------------------------------------------------------------------------

    In Environmental Action, the Commission did impose a high ceiling 
rate as further protection against the exercise of market power by the 
utilities in the pricing pool. But Environmental Action involved a 
lifting of rate ceilings for all transactions, including those made by 
the utilities. In Order No. 637, in contrast, the Commission has lifted 
the price ceiling only for short-term capacity release transactions, 
while retaining cost-based regulation for pipeline services and long-
term capacity release transactions. The evidence showing large and 
sudden increases in transportation values during peak periods 
demonstrates that the Commission could not design a cost-based short-
term rate ceiling that would emulate short-term market prices and that 
would not interfere with the efficiency of the capacity release market, 
particularly during peak periods when an efficient market is most 
needed. In order to come close to replicating market prices during peak 
periods, any short-term rate ceiling would have to be so high as to 
provide little protection to any shipper. Rather than using a high and 
artificial price ceiling as back-up protection, as in Environmental 
Action, the Commission in this rule retained cost-based regulation of 
pipeline capacity as back-up protection. This approach provides better 
protection to short-term shippers than an artificial price ceiling 
without compromising the efficiency of capacity trading as a price 
ceiling would.
    The rehearing requests further contend that the Commission ignored 
its own precedent in not conducting a detailed market analysis before 
permitting releasing shippers to charge market based rates. \39\ The 
prior proceedings were in a different posture from this rulemaking 
because the proceedings cited all included applications by pipelines to 
remove cost-of-service regulation from their services. Moreover, while 
the Commission has found that a market power study is one method for 
permitting market based rates,\40\ it did not indicate that it was the 
exclusive method or that other regulatory steps could not also be 
justified. In this rulemaking, the Commission examined all relevant 
market factors and fully explained why continuation of cost-of-service 
rate ceilings for capacity release

[[Page 35714]]

transactions no longer meets the needs of the market and that a more 
flexible approach, relying on competition and other regulatory 
controls, was necessary.
---------------------------------------------------------------------------

    \39\ The rehearing requests cite, e.g., 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), 
Koch Gateway Pipeline Company, 85 FERC para. 61,013 (1998), reh'g 
denied, 89 FERC para. 61,046 (1999); Secondary Market Transactions 
on Interstate Natural Gas Pipelines, Notice of Proposed Rulemaking, 
61 FR 41046 (Aug. 7, 1996) FERC Stats. & Regs. Proposed Regulations 
[1988-1998] para. 32,520 (July 31, 1996) (final rule never issued); 
Proposed Experimental Pilot Program to Relax the Price Cap for 
Secondary Market Transactions, 76 FERC para. 61,120 (1996) (program 
terminated).
    \40\ Alternatives to Traditional Cost-of-Service Ratemaking for 
Natural Gas Pipelines and Regulation of Negotiated Transportation 
Services of Natural Gas Pipelines, 74 FERC para. 61,076 (1996).
---------------------------------------------------------------------------

    Indicated Shippers maintain that the Commission's relaxation of 
price ceilings in this case is inconsistent with its policy with 
respect to electric transmission service where Indicated Shippers 
maintain the Commission continues to regulate on a cost-of-service 
basis. In fact, however, the Commission has not limited pricing for 
short-term electric transmission service to embedded cost-of-service 
rates. As the Commission has done in this rule, the Commission has 
recognized that neither historic nor incremental costs are an 
appropriate ceiling for short-term electric transmission services and 
has permitted utilities to sell short-term transmission services at the 
higher of embedded or opportunity cost without a price cap. \41\ With 
respect to reassignments of electric transmission capacity of one year 
or less, the Commission has similarly found that reassignments can be 
made at the reassignor's opportunity cost without an embedded cost or 
incremental price cap.\42\ In this rule, the Commission followed 
essentially the same policy it has applied to electric regulation by 
removing embedded cost price ceilings for short-term capacity releases, 
so that releasing shippers can effectively obtain the opportunity costs 
for capacity. A releasing shipper will be able to sell its capacity for 
a rate that exceeds the value to the shipper of the next best use of 
its capacity. A combination of competition and other regulatory 
controls protect against short-term capacity release rates becoming 
unjust and unreasonable.
---------------------------------------------------------------------------

    \41\ Florida Power & Light Company, 66 FERC para. 61,227, at 
61,527 (1994), on reh'g 70 FERC para. 61,158 (1995). Opportunity 
costs reflect the cost to the utility of its next best alternative 
sale.
    \42\ California Independent System Operator Corporation, 89 FERC 
para. 61,153, at 61,436 (1999).
---------------------------------------------------------------------------

    Those requesting rehearing further contest what they term the 
Commission's determination that shippers in the short-term capacity 
release market are not entitled to protection. They maintain that 
short-term shippers may be captive to particular pipelines and that, in 
any event, all shippers are entitled to protection under the Natural 
Gas Act.
    In Order No. 637, the Commission recognized that its principal 
responsibility is to protect captive customers holding long-term 
contracts.\43\ Short-term customers, even if connected to only one 
pipeline, are not captive since given the nature of interruptible and 
short-term release services they do not have to pay for service when 
they want to use alternatives and have no guarantee that the pipeline 
will provide service when they want it. Prior to Order No. 636, the use 
of 100% load factor interruptible rates and selective discounting, 
maximized the revenue from short-term shippers and reduced the costs 
borne by captive firm customers. \44\ Lifting of the price ceiling for 
short-term capacity release transactions restores the balance between 
short and long-term shippers, but in a way more consonant with 
competitive pricing. Short-term shippers that currently pay lower 
prices during off-peak periods as a result of competition created by 
capacity release will now face appropriate rates for peak period 
capacity when capacity is most in demand and prices in a competitive 
market would be higher to properly allocate the capacity. At the same 
time, this will enable releasing shippers to derive greater revenue for 
short-term releases during peak periods to help offset the low rates 
they receive during off-peak periods.
---------------------------------------------------------------------------

    \43\ United Distribution Companies v. FERC, 88 F.3d 1105, 1123 
(D.C. Cir. 1996) (Commission's prime constituency is captive 
customers vulnerable to the pipeline's market power). See Maryland 
People's Counsel v. FERC, 761 F.2d 780, 781 (D.C. Cir. 1985); 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).
    \44\ See Associated Gas Distributors v. FERC, 824 F.2d 981, 1011 
(D.C. Cir. 1987) (selective discounting benefits captive customers 
by making a contribution to fixed costs); Mobil Oil Co. v. FERC, 886 
F.2d 1023 (8th Cir. 1989) (100% load factor interruptible rates 
ensure that interruptible service pays the cost of providing that 
service); Elizabethtown Gas. Co. v. FERC, 10 F.3d 866, 871-72 (D.C. 
Cir. 1993) (affirming use of 100% load factor interruptible rates); 
Orange and Rockland Utilities, Inc. v. FERC, 905 F.2d 425, 427-29 
(D.C. Cir. 1990) (affirming use of 100% load factor interruptible 
rates).
---------------------------------------------------------------------------

    The Commission did not find, as the rehearing requests suggest, 
that short-term shippers are not entitled to any protection. It found 
only that just and reasonable regulation of customers in the short-term 
market needs to be tailored to the realities of that market.\45\ Short-
term customers, by the very nature of the service for which they are 
contracting, expressly take the risk that they may have to forgo the 
use of gas entirely if short-term capacity is not available when they 
need it. As the country learned very well during the period of price 
controls on interstate gas, customers receive little benefit from 
regulated prices if they are unable to acquire the gas or 
transportation service when they need it. Short-term customers will 
receive more protection if they can obtain capacity when they need it, 
even by paying higher prices, than if they are unable to obtain the 
capacity they need when they are willing to pay the market price for 
such capacity. Short-term customers desiring greater price security can 
purchase long-term capacity at a regulated rate from the pipeline. Even 
if capacity is not immediately available, the pipeline has the 
incentive to construct new capacity when shippers are willing to pay 
for the cost of construction, and the Commission is committed to 
reviewing closely a pipeline's decision to refuse to construct capacity 
when the customer is willing to pay the costs.
---------------------------------------------------------------------------

    \45\ Permian Basin Area Rate Cases, 390 U.S. 747, 787 (1968) 
(Commission empowered to prescribe different requirements for 
different classes of persons or matters).
---------------------------------------------------------------------------

    In short, the static cost-of-service rate regulation that the 
Commission has applied to long-term capacity commitments is not 
applicable to short-term released capacity. The Commission, therefore, 
has decided to try a more flexible regulatory approach to the short-
term release market that does not rely upon artificial pricing 
ceilings, but instead relies on competition and other regulatory 
controls to minimize the ability to exercise market power as well as 
relying on enforcement proceedings to control the abuse of market power 
if it should occur. Such a regulatory approach is better geared to the 
needs of the short-term market than the maintenance of static, 
regulated prices that bear little relationship to market realities, 
that distort shipper's options, and that contribute to a less efficient 
market.
    The Commission will discuss below the protections against the 
exercise of market power that justify the removal of the rate ceiling 
for short-term capacity release transactions.
(2) Protections Against the Exercise of Market Power
    Competition from Releasing Shippers, Monitoring, and Enforcement. 
The availability of capacity from alternative firm capacity holders, as 
well as the pipeline, constitutes a strong protection against the 
exercise of market power by any one holder of firm capacity. Capacity 
release has become an ever more vibrant part of the gas marketplace 
since Order No. 636. By permitting releasing shippers to use secondary 
points and to segment their capacity, capacity buyers have the ability 
to choose among numerous alternative suppliers of capacity. Indeed, as 
shown above,\46\ competition in the capacity release markets already 
has been successful in keeping, on average, the rates for released 
capacity below the

[[Page 35715]]

maximum rates during both peak and off-peak periods, demonstrating that 
competition will significantly limit releasing shippers' ability to 
exercise market power during peak periods even without a price ceiling. 
Further, the data cited in Order No. 637 from the bundled sales market 
show that in a market without price ceilings, competition has generally 
maintained the value of transportation at rates below the current 
maximum ceiling rate.\47\ The data show that the only time rates 
increase above the cost-based maximum ceiling rate is during peak 
demand periods, when higher prices are needed to effectively allocate 
capacity.\48\ Thus, the evidence does not provide a basis for the fear 
of those seeking rehearing that removal of price ceilings will lead to 
the ability of shippers to sustain price increases above cost-based 
rates.
---------------------------------------------------------------------------

    \46\ See Figure 1, at 20.
    \47\ Order No. 637, 65 FR at 10174-80, figures 5-7, III FERC 
Stats. & Regs. Regulations Preambles para. 31,091, at 31,271-74, 
figures 5-7.
    \48\ Figure 7, for example, shows that the value of 
transportation during January 2,000 rose only during the time period 
when temperatures turned colder. Order No. 637, 65 FR at 10178-79, 
figure 7, III FERC Stats. & Regs. Regulations Preambles para. 
31,091, at 31,273-74, figure 7.
---------------------------------------------------------------------------

    The competition among multiple capacity holders and the pipelines 
to sell capacity has, at the very least, significantly lessened the 
potential for the exercise of market power by releasing shippers, so 
that case-by-case review of allegations of market power is appropriate 
and far less disruptive to the overall workings of the market than 
application of static cost-based regulation that does not comport with 
the way in which short-term markets operate. The Commission has revised 
its reporting and internal monitoring capability as well as its 
complaint procedures to better enable it and the industry to monitor 
the marketplace and conduct case-by-case review of allegations of 
abuses of market power in the release market.
    Regulated Pipeline Alternatives. In this rule, the Commission only 
took an interim step to improve efficiency by removing the rate ceiling 
for short-term capacity release transactions. It decided not to change 
the existing regulation of pipelines to provide additional protection 
against the exercise of market power in the short-term capacity release 
market. Market power can be exercised in two basic ways, through 
withholding of capacity and price discrimination. Firm shippers cannot 
successfully withhold capacity from the market, because any capacity 
they do not use is available from the pipeline as interruptible service 
at a cost-based rate. Shippers also can purchase long-term firm 
capacity from the pipeline at a regulated rate. In addition, the 
Commission continues to regulate pipeline penalty levels in the short-
term market which effectively establishes a rate ceiling for capacity 
release transactions. A shipper will not pay more for capacity than the 
penalty it would pay if it simply shipped gas in excess of its contract 
rights.
    In traditional market analysis, one looks at the number and market 
shares of potential alternative suppliers and other factors such as 
barriers to entry to determine whether competition between those 
suppliers is sufficient to prevent explicit or tacit collusion to 
reduce output in order to raise price.\49\ If a large enough number of 
firms are in competition for buyers' business, buyers, when faced with 
an effort to raise price by any one firm, will have alternative 
suppliers who have an incentive to increase their own sales (and hence 
total output) by charging a lower price. While the Commission has used 
competitive market analysis to determine whether to permit market-based 
rates, such an analysis is time consuming, difficult and is not subject 
to slide rule precision. Disputes frequently arise over issues, such as 
product and geographic market definition, the existence of barriers to 
entry, and the number and market positions of alternative suppliers 
needed to protect against market power. When the Commission previously 
instituted a pilot program attempting to use market analysis to relax 
price ceilings in the short-term market, disputes over all these issues 
arose.\50\
---------------------------------------------------------------------------

    \49\ Department of Justice-Federal Trade Commission, Horizontal 
Merger Guidelines, para. 0.1 (small number of firms can approximate 
the performance of a monopolist, by either explicitly or implicitly 
coordinating their actions).
    \50\ Compare Secondary Market Transactions on Interstate Natural 
Gas Pipelines, 77 FERC para. 61,183 (1996) with Transwestern 
Pipeline Company, 78 FERC para. 61,200 (1997) (disputes over whether 
market power can be exercised over single lateral on pipeline).
---------------------------------------------------------------------------

    While market analysis looks principally at market structure and 
barriers to entry in an attempt to discern whether firms will have 
incentives to reduce output to raise price, the Commission's 
regulations protect against the exercise of market power by directly 
limiting the withholding of available transportation capacity through 
the requirement that pipelines sell all available capacity at a 
regulated rate. There is only a fixed amount of capacity in the short-
term capacity market. Any capacity not sold or used by a firm shipper 
is, by definition, available from the pipeline as interruptible or 
short-term firm capacity. In these circumstances, if firm shippers 
attempt to exercise market power by raising price above the regulated 
rate, buyers can acquire the capacity from the pipeline at the 
regulated rate. Because no capacity can be withheld from the market 
above the regulated maximum rate and buyers can always obtain capacity 
from the pipeline on a non-discriminatory basis, market power cannot be 
exercised when rates exceed the cost-of-service price ceiling, and 
consequently the resulting price is the competitive price needed to 
equate supply and demand and allocate the available capacity. The 
requirement that a pipeline sell its capacity at the regulated maximum 
rate prevents tacit collusion between the pipeline and the shipper to 
withhold capacity to raise price above the ceiling rate, and 
effectively limits the releasing shipper's ability to exercise market 
power at prices above the ceiling rate.
    Short-Term Pipeline Capacity. Those requesting rehearing contend 
that maintenance of rate regulation for pipeline interruptible capacity 
is insufficient to restrain market power in the capacity release market 
because pipeline interruptible capacity is not an adequate substitute 
for firm released capacity given its lower priority.\51\ In many cases, 
releasing shippers impose recall rights on released capacity, so it is, 
in effect, an interruptible service. Moreover, pipeline interruptible 
capacity does not need to be identical to released capacity to be a 
good substitute, sufficient to restrain the exercise of market 
power.\52\ In this case, there is, in effect, only one product, 
pipeline capacity, and several ways to obtain it, firm released 
capacity, short-term firm and interruptible capacity from the pipeline. 
These methods of obtaining capacity directly compete with each other: 
any firm capacity not released is available as interruptible 
transportation from the pipeline. Even though interruptible capacity is 
of lower priority than firm released capacity, the requirement that the 
pipeline sell all of its interruptible transportation at the maximum 
rate inhibits a releasing shipper's ability to exercise market power, 
because the releasing shipper cannot withhold capacity from the market. 
If the releasing shipper does not

[[Page 35716]]

use its capacity (attempts to withhold capacity), that capacity becomes 
available as interruptible service which the pipeline must sell at a 
just and reasonable rate. The pipeline also is required to sell short-
term firm service to the extent all of its firm service is not fully 
subscribed. Since the pipeline is required to sell all of its available 
capacity at the maximum rate, it cannot collude with the releasing 
shipper to withhold capacity from the market.
---------------------------------------------------------------------------

    \51\ Rehearing Requests by Amoco, Indicated Shippers, NGSA.
    \52\ Department of Justice--Federal Trade Commission, Horizontal 
Merger Guidelines, para. 1.11 (inquiry is whether alternative 
products would inhibit the ability of a monopolist of a single 
product to sustain a price rise); U.S. v. E.I. Dupont De Nemours & 
Co., 351 U.S. 377 (1956) (product market determined by cross-
elasticity of demand between different products).
---------------------------------------------------------------------------

    Long-Term Pipeline Capacity. Amoco and Indicated Shippers maintain 
that the ability to purchase long-term capacity from the pipeline at 
just and reasonable rates is not a reasonable protection against market 
power. They maintain that the pipeline may not have long-term capacity 
available and that short-term prices may only be high on a sporadic 
basis, not sufficient to induce the pipeline to build additional 
capacity.
    Maintaining cost-of-service regulation on long-term pipeline 
capacity provides protection against the exercise of market power by 
releasing shippers in the short-term market in two ways. On pipelines 
with unsubscribed firm capacity, the availability of capacity from the 
pipeline provides an alternative, at a regulated rate, to buying short-
term capacity from releasing shippers. Even when pipelines are fully 
subscribed, the pipelines' ability to construct additional capacity 
will discipline the ability of releasing shippers to sustain rates in 
the short-term market above the marginal cost of construction. If 
prices in the short-term capacity release market generate revenues that 
would be above the cost of constructing new capacity, the pipeline can 
capture such potential profits only by adding capacity to serve the 
demand.\53\ The pipelines' ability and incentive to undertake such 
construction reduces the incentive for releasing shippers' to attempt 
to raise prices above the marginal cost of new construction. In many 
cases, capacity can be added quickly simply by adding compression to 
the system.
---------------------------------------------------------------------------

    \53\ The pipeline cannot recover any of the potential profit by 
raising price because its rates are capped.
---------------------------------------------------------------------------

    The rehearing requests suggest that short-term prices may only 
sporadically exceed the maximum rate so that the rise in price is not 
sufficient to attract new pipeline investment. But if prices rise only 
sporadically, the price change is most likely due to an increase in 
demand relative to supply, creating scarcity rents, rather than the 
sustained exercise of market power. In any event, the sporadic nature 
of such increases suggests that, even if market power is present, any 
harm from removing the rate ceiling would be relatively minor, since it 
would occur only during those short periods when prices exceed the 
maximum rate. Any possible harm from short-term higher prices is 
outweighed by the greater efficiency created by a more effective 
capacity trading market that would permit those short-term shippers who 
most urgently need capacity during peak periods to have a better 
opportunity to obtain capacity. As discussed above, if short-term 
prices rise frequently enough to make the construction of additional 
pipeline capacity profitable, the pipeline will have the incentive to 
build that capacity, which provides short-term shippers with an 
additional capacity option.
    Process Gas Consumers suggest that long-term capacity may not be a 
viable alternative for industrial firms because, unlike marketers and 
LDCs, who are in the gas business, industrial firms' principal business 
is not gas and their ability to purchase long-term transportation 
contracts is often inhibited by business planning cycles of five years 
or less. But those are the kinds of choices shippers have to make as 
the gas market becomes more competitive. If shippers want price 
security, they need to share the risks of new construction with the 
pipelines; they cannot require that pipelines fully absorb all those 
risks. Shippers that are unwilling to undertake that commitment can 
purchase gas from marketers or can choose to participate in the short-
term market, with full recognition of the price fluctuations inherent 
in that choice. Moreover, the point here is not that any one class of 
customer would or would not subscribe to new construction. If short-
term prices produce revenues high higher than the cost of new 
construction, the pipeline has the incentive to construct new capacity 
to capture additional revenue, and shippers who see the profit 
potential in obtaining that capacity will subscribe, because they can 
resell that capacity for more than it costs them.
    Process Gas Consumers also argue that the Commission has failed to 
give sufficient credence to its contention that LDCs control access to 
the points behind their citygates and, therefore, can obviate any 
benefits of competitive access to that point. It contends that in the 
past, the Commission proposed to require that LDCs provide open access 
service before they could benefit from removal of the price 
ceilings.\54\ It further contends that alternative capacity suppliers 
may not be meaningful alternatives to obtaining capacity from the LDC, 
because using secondary receipt and delivery points is not the 
equivalent of using primary points.
---------------------------------------------------------------------------

    \54\ Process Gas Consumers cites to Secondary Market 
Transactions on Interstate Natural Gas Pipelines, Proposed 
Experimental Pilot Program to Relax the Price Cap for Secondary 
Market Transactions, 76 FERC para. 61,120 (1996).
---------------------------------------------------------------------------

    In the first place, as shown in Order No. 637, over 80% of all 
industrial sales are now unbundled and unbundling programs are 
accelerating.\55\ Thus, the need for the Commission to impose its own 
requirements for open access service has diminished. Second, the 
ability of an LDC to exercise market power over pipeline capacity is 
limited because, if it tries to withhold capacity, that capacity 
becomes available from other releasing shippers or from the pipeline at 
a regulated rate. If an LDC holding primary firm rights attempts to 
exercise market power by withholding capacity, that would make the use 
of its points available to shippers buying capacity from other 
releasing shippers or from the pipeline.\56\ If Process Gas Consumers 
is arguing that LDCs can exercise market power over their intrastate 
facilities by refusing to schedule gas for a shipper behind the city-
gate, state regulatory agencies have primary responsibility for 
policing LDC activity over their own facilities. Moreover, any refusal 
by an LDC to schedule gas on behalf of a shipper would be readily 
apparent and, if such an abuse relates to interstate transportation, 
the Commission can remedy such problems through individual case 
procedures. There is no need to retain the price ceiling for the entire 
class of LDC shippers based only on speculation about whether some LDCs 
will refuse to schedule capacity when any such abuses can be addressed 
in individual cases.
---------------------------------------------------------------------------

    \55\ Order No. 637, 65 FR at 10158-60, 101-68 III FERC Stats. & 
Regs. Regulations Preambles para. 31,091, at 31,251-52, 31,261.
    \56\ For example, if one capacity holder has firm primary point 
capacity of 100 MMBtu and does not use 50 MMBtu of that capacity, 
other shippers can schedule delivereis to the same point using 
secondary delivery point rights or interruptible service. This makes 
it difficult for the shipper holding the primary delivery point 
rights to withhold capacity.
---------------------------------------------------------------------------

    The National Association of Gas Consumers maintains that lifting of 
the price ceiling could lead to speculative pricing. As explained in 
Order No. 637, however, high prices during peak periods are a 
legitimate reaction to supply and demand forces. As long as capacity is 
not being withheld from the market, high prices during peak periods are 
the competitive response to market conditions and will result in a more

[[Page 35717]]

efficient allocation of capacity to those valuing it the most. Indeed, 
it is the current price regulated system that can create the more 
inefficient system and be the most harmful to gas consumers, because 
regulated rates during peak periods may prevent those shippers who most 
need capacity to serve their customers from obtaining capacity when 
they need it most. As shown by the period of rate regulation of 
wellhead prices, the maintenance of regulated rates that do not fit 
with market conditions can harm consumers by distorting price signals 
and thereby inhibiting the efficient allocation of resources. In any 
event, removal of rate regulation for capacity release transactions 
will have limited effect on pricing behavior, since there is no rate 
ceiling for bundled gas transactions and firms can speculate in the gas 
market. Rather than exacerbating pricing problems during peak periods, 
the lifting of rate ceilings on capacity release transactions should 
help to provide shippers with more options for dealing with those 
problems.
    Amoco and Indicated Shippers maintain that the Commission has not 
provided adequate protection against capacity withholding when the 
market rate falls below the regulated maximum rate for pipeline 
capacity. They argue that at rates below the maximum rate, the pipeline 
is under no obligation to sell all available capacity which could 
permit capacity withholding.
    This complaint is unrelated to the regulatory changes in Order No. 
637. The Commission made no regulatory changes with respect to its 
policy regarding pipeline and release rates that are below the maximum 
rate. As shown above, the competition between firm shippers and the 
pipelines already has significantly limited the ability of releasing 
shippers to withhold capacity and to selectively discount during the 
off-peak period when rates are below the maximum rate. Moreover, 
Commission policy since Order No. 636 has been to permit pipelines and 
releasing shippers to refuse to discount.\57\ The Commission has not 
changed that policy here. The regulatory changes in this rule, 
therefore, result in no additional harm to short-term shippers when 
rates are below the maximum rate and promise greater efficiency and 
options for shippers during peak periods.
---------------------------------------------------------------------------

    \57\ 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 30,629 (Aug. 3, 1992) (pipelines are not 
required to discount or accept bids at less than the maximum rate), 
636-B, 61 FERC para. 61,272, at 62,027-28 (pipelines not required to 
discount transportation rate), aff'd, United Distribution Companies 
v. FERC, 88 F.3d 1105, 1141-42 (D.C. Cir. 1996).
---------------------------------------------------------------------------

    Mitigation Measures. Amoco, IPAA, and Indicated Shippers contend 
the Commission erred when it relaxed price ceilings, because it failed 
to adopt further measures to mitigate the exercise of market power. 
Amoco contends the fundamental error in Order No. 637 was the failure 
to require an auction, as proposed in the NOPR, to ensure capacity is 
allocated in an unbiased manner to promote competition while mitigating 
market power. Indicated Shippers contend the Commission erred by not 
eliminating the exemption from the posting and bidding requirements for 
pre-arranged deals for greater than one month at or above the maximum 
lawful rate and by not revising its regulations to restrict releasing 
shippers' ability to impose recall conditions. AGA and a number of LDCs 
also request clarification as to whether the exemption for releases at 
the maximum rate continues to apply.\58\
---------------------------------------------------------------------------

    \58\ Atlanta Gas Light, UGI, Keyspan, and Washington Gas also 
request clarification of this point.
---------------------------------------------------------------------------

    With respect to Amoco's argument, the Commission, in fact, will 
continue to require bidding for capacity release transactions, which 
is, in effect, a form of capacity auction. Since Order No. 636, the 
Commission has required posting and bidding for capacity release 
transactions as protection against the potential for undue 
discrimination and the exercise of market power in the capacity release 
market.\59\ Under Commission regulations, all capacity releases for 
more than 31 days and all rollovers of releases of 31 days or less are 
subject to the bidding process. In Order No. 636, the Commission 
permitted an exemption from the bidding process for short-term releases 
of less than a month, because of a concern at that time that the 
pipeline's auction process could be too administratively cumbersome for 
short-term transactions.\60\
---------------------------------------------------------------------------

    \59\ 18 CFR 284.8.
    \60\ 18 CFR 284.8(h); 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 30,553-54 (Aug. 3, 1992).
---------------------------------------------------------------------------

    As explained in Order No. 637, electronic commerce is growing, 
particularly in the gas industry, and may well represent the future, 
but the comments in this rulemaking, including comments by those 
seeking rehearing,\61\ maintain that the electronic capabilities of 
some pipelines today still do not permit a mandatory requirement for a 
daily auction and that a daily auction might well create administrative 
difficulties of its own. Although the Commission strongly encourages 
both pipelines and third parties to begin gaining experience with the 
use of electronic auctions as a means of allocating available capacity, 
the Commission determined, based on the rulemaking comments, that it 
was not the time to impose an across-the-board requirement for a 
mandatory daily auction. Nonetheless, the pre-existing posting and 
bidding requirements for capacity release will continue to promote fair 
and equitable capacity allocation and inhibit the exercise of market 
power, because any transactions of longer than a month are subject to 
the auction and transactions of less than a month (while initially 
exempt) will be subject to the auction if they are continued or rolled 
over.
---------------------------------------------------------------------------

    \61\ Comments by Process Gas Consumers.
---------------------------------------------------------------------------

    Indicated Shippers contend the Commission should have eliminated 
the provision (contained in the current regulations) that exempts from 
the bidding requirements pre-arranged capacity release transactions at 
the maximum rate. Indicated Shippers argue that maintaining this 
exemption prevents non-affiliate replacement shippers from fairly 
competing in an open capacity market. AGA and a number of LDCs contend 
in their clarification requests that the exemption from posting and 
bidding for releases at the maximum rate continues to apply.\62\
---------------------------------------------------------------------------

    \62\ Atlanta Gas Light, UGI, Keyspan, and Washington Gas also 
request clarification of this point.
---------------------------------------------------------------------------

    Although there is apparently confusion on this point, the 
Commission did eliminate this exemption in Order No. 637. Section 
284.8(h) of the regulations contains an exemption from the posting and 
bidding requirements for capacity release transactions at the ``maximum 
tariff rate applicable to the release.'' \63\ Since the maximum tariff 
rate is no longer applicable to short-term capacity release 
transactions, the exemption does not apply as long as the rate ceilings 
are waived. Nevertheless, to ensure the regulations are clear, the 
Commission will add the following to section 284.8 (i) of the 
regulations: ``The provision of paragraph (h)(1) of this section 
providing an exemption from the posting and bidding requirements for 
transactions at the applicable maximum tariff rate for pipeline 
services will not apply as long as the waiver of the rate ceiling is in 
effect.'' Section 284.8 (i)

[[Page 35718]]

already contains a provision specifying that posting and bidding will 
apply to any rollovers or continuations of capacity release deals of 31 
days or less.\64\
---------------------------------------------------------------------------

    \63\ 18 CFR 284.8(h).
    \64\ 18 CFR 284.8(i) provides that any rollovers or extensions 
are subject to the posting and bidding requirements.
---------------------------------------------------------------------------

    Thus, under the Commission regulations, all capacity release 
transactions of more than 31 days will be subject to the posting and 
bidding requirements. For transactions of 31 days or less, shippers can 
enter into prearranged deals that are not subject to the posting and 
bidding requirements. But all rollovers or continuation of such deals 
will be subject to posting and bidding.\65\
---------------------------------------------------------------------------

    \65\ Under section 284.8(h)(2), a shipper can enter into another 
short-term (31 days or less) release to the same replacement shipper 
without posting and bidding if 28 days have passed since the 
previous release to that shipper.
---------------------------------------------------------------------------

    UGI and Atlanta Gas Light seek rehearing of the decision to 
eliminate the maximum rate exemption from the posting and bidding 
requirements, claiming that continuing the exemption is important to 
their retail unbundling initiatives at the state level.
    In Order No. 637, the Commission specifically continued the 
existing posting and bidding requirements for capacity release 
transactions to ensure that capacity is equally available to all 
shippers and to protect against undue discrimination and the exercise 
of market power.\66\ Permitting releases at or above the maximum rate 
to be exempt from the posting and bidding requirements would defeat the 
very purpose of requiring posting and bidding by enabling releasing 
shippers to consummate pre-arranged transactions with certain shippers 
without giving other shippers an opportunity to compete for the 
capacity. The original justification for exempting pre-arranged deals 
at the maximum rate was that, as long as a rate ceiling was in effect, 
no other shipper could beat the pre-arranged deal and bidding and 
posting requirements would be superfluous.\67\ When the maximum rate 
ceiling is lifted, posting and bidding becomes necessary to protect 
against undue discrimination and to ensure that capacity is properly 
allocated to the shipper placing the greatest value on the capacity.
---------------------------------------------------------------------------

    \66\ Order No. 637, 65 FR at 10182, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,279. See 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 30,555 
(Aug. 3, 1992) (posting and bidding needed to give all parties an 
opportunity to obtain capacity by bidding the highest rate).
    \67\ Release of Firm Capacity on Interstate Natural Gas 
Pipelines, Order No. 577, 60 FR 16979 (Apr. 4, 1995), FERC Stats. & 
Regs. Regulations Preambles [Jan. 1991-June 1996] para. 31,017, at 
31,316 (Mar. 29, 1995) (``when the pre-arranged deal is at the 
maximum rate, no other shipper can make a better bid for that 
capacity'').
---------------------------------------------------------------------------

    The imposition of posting and bidding will not prevent LDCs from 
entering into pre-arranged deals under state unbundling programs, as 
the clarification and rehearing requests suggest. LDCs can still enter 
into pre-arranged transactions of less than one year and the pre-
arranged shipper is guaranteed to receive the capacity as long as it is 
willing to match the highest rate bid for that capacity. LDCs also can 
enter into pre-arranged deals exempt from the posting and bidding 
requirements by entering into a pre-arranged release for one year or 
more at the maximum rate.
    In individual cases where an LDC considers a further exemption from 
the posting and bidding requirement essential to further a state retail 
unbundling program, it may request the Commission to waive the 
regulation, permitting the LDC to consummate pre-arranged deals at the 
pipeline's maximum tariff rate without having those transactions 
subject to competitive posting and bidding. If the LDC seeks such a 
waiver, it must be prepared to have all of its capacity release 
transactions and any re-releases of that capacity limited to the 
applicable maximum rate for pipeline capacity. The LDC should not be 
able to sell to some shippers without a rate ceiling, protecting other 
favored shippers from the bidding process. All such waiver applications 
must either be filed jointly with the appropriate state regulatory 
authority or must include a verified statement by that authority 
stating why the request is necessary to promote a legitimate state 
goal.
    Indicated Shippers also contend the Commission should eliminate the 
right of releasing shippers to impose recall conditions on 
releases.\68\ They maintain that releasing shippers can abuse their 
recall rights by recalling the capacity from third parties and then 
reselling it at higher prices, while not recalling capacity from 
affiliates. The Commission sees no basis for prohibiting releasing 
shippers from imposing recall rights. Recall rights add capacity to the 
release market by enabling shippers to release capacity when they do 
not need it, and then recall the capacity when necessary for their 
needs. Without the ability to impose recall rights, releasing shippers 
may be reluctant to release capacity out of concern that weather 
patterns will change. If replacement shippers are concerned about abuse 
of the recall process in the scenario envisaged by Indicated Shippers, 
they can refuse to enter into recallable release transactions unless 
the releasing shipper guarantees that, if a recall is exercised, it 
will not be able to resell that capacity. Allegations concerning abuse 
of recall conditions also can be examined by the Commission through the 
complaint process.
---------------------------------------------------------------------------

    \68\ A recall condition is a term in the release that enables 
the releasing shipper to use the capacity in certain circumstances, 
for example, if the temperature drops to a point where the releasing 
shipper needs the capacity to serve its own customers.
---------------------------------------------------------------------------

    Potential Affiliate Abuse: Amoco, Process Gas Consumers, NGSA, and 
Ohio Oil and Gas Association contend that removing the price ceiling 
for released capacity provides an opportunity for affiliate abuse 
because it creates an incentive for the pipeline corporate entity to 
transfer capacity from the pipeline to its affiliate, which is not 
subject to the price ceiling.
    Pipelines cannot simply transfer capacity to an affiliate. 
Pipelines are required to allocate their capacity on a non-
discriminatory basis and must sell the capacity to the shipper bidding 
the highest net present value for the capacity. Thus, if unaffiliated 
shippers project that profits can be made by selling short-term 
capacity above the price ceiling, they can bid against the affiliate to 
obtain capacity from the pipeline.\69\
---------------------------------------------------------------------------

    \69\ There may be little incentive for the affiliate to inflate 
the net present value of its bid, for example, by increasing the 
contract duration. The unaffiliated shipper would be willing to bid 
a net present value up to its expectation of the value of the 
capacity. If the affiliate obtains the capacity by bidding a higher 
net present value, the corporate entity loses the opportunity to 
obtain the revenue the unaffiliated shipper would have paid. As long 
as the expected future value of the capacity does not exceed the 
amount bid by the unaffiliated shipper, the corporate entity cannot 
expect to recoup the revenue it would have received from the 
unaffiliated shipper.
---------------------------------------------------------------------------

    Moreover, as the Commission explained in Order No. 637, the removal 
of the rate ceiling effects little change from the market today because 
pipeline affiliates are currently able to make bundled gas sales where 
the transportation component of the transaction is not subject to the 
rate ceiling. Removal of the rate ceiling, coupled with the reporting 
requirements, therefore, may make these transactions more transparent, 
because affiliates will have a greater incentive to release 
transportation and pipelines must post such transactions. The rate 
ceiling on pipeline capacity also will continue to protect against the 
exercise

[[Page 35719]]

of market power in the event capacity is held by a pipeline affiliate. 
The pipeline affiliate, like any other firm shipper, will be unable to 
withhold capacity and exercise market power because, if the affiliate 
refuses to sell released capacity, buyers can obtain that capacity as 
interruptible transportation at a just and reasonable rate from the 
pipeline.
    Amoco suggests that a pipeline and an affiliate or partner could 
conspire to withhold capacity through a number of artifices: nominating 
gas into the pipeline but not delivering it; purchasing park and loan 
services at a low rate; moving gas to market area storage or line pack; 
or having the affiliate use the unreliability of interruptible service 
as a threat to induce the buyer to purchase released capacity at a 
higher than competitive price. NGSA similarly contends that a firm 
shipper can create artificial periods of peak demand by nominating, but 
not using just enough capacity to drive up demand for capacity while 
decreasing the availability of interruptible transportation.
    All of these techniques would be costly to implement, costs which 
would limit the incentive to attempt them. The pipeline's sale of 
parking and loan service at a lower than market rate costs the pipeline 
the opportunity cost of selling that service to someone else. 
Nominating gas, but not taking delivery, could result in scheduling or 
imbalance penalties, and to the extent that capacity is not used, the 
pipeline would still have the obligation to sell the unused capacity as 
interruptible or short-term firm service. Moving gas to storage or line 
pack when it is not truly needed results in costs to the shipper for 
the gas and transportation and the consequent reduction in storage and 
line pack flexibility. No protection against market power can be 
considered absolute; even the market analysis advocated by those 
seeking rehearing cannot perfectly predict whether market power may be 
exercised. But the benefits of removing the rate ceiling here outweigh 
the limited potential for the exercise of market power inherent in 
these scenarios. Further, the Commission stands ready to investigate 
complaints about such abusive practices.
    In Order No. 637, the Commission recognized that affiliate 
transactions could be troublesome in one respect: where the affiliate 
holds large quantities of pipeline capacity and the pipeline determines 
not to construct new capacity in order to increase scarcity rents for 
the affiliate.\70\ The Commission found that this situation exists 
today, with affiliates able to make bundled sales to reap scarcity 
rents, but there seems little indication that profits from scarcity 
exceed those that can be earned by the pipeline from new construction, 
since pipeline construction applications have not noticeably declined. 
Because of the possibility of such affiliate abuse, however, the 
Commission will be particularly sensitive to complaints that pipelines, 
on which affiliates hold large blocks of capacity, are refusing to 
undertake construction projects when demand exists and will be prepared 
to take remedial measures in cases where such concerns are established.
---------------------------------------------------------------------------

    \70\ Order No. 637, 54 FR at 10186, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,287.
---------------------------------------------------------------------------

    Process Gas Consumers and NGSA maintain that the Commission's 
reliance on historic construction information ignores the current trend 
toward greater concentration in the industry and the concentration of 
pipeline capacity in the hands of affiliates. As a result, NGSA 
contends that the Commission should condition the removal of the price 
ceiling for pipeline affiliates on the pipeline's including a tariff 
provision requiring it to put in interconnections and to construct 
capacity when requested by customers willing to pay the costs of 
construction.
    NGSA's concern with interconnections already has been addressed by 
the Commission. The Commission's policy requires pipelines to provide 
interconnects to any shipper that constructs, or pays for construction 
of, the facilities needed for the interconnection, as long as the 
interconnection does not adversely affect pipeline operations, violate 
applicable environmental or safety regulations, or violate right-of-way 
agreements.\71\ With respect to refusals to build additional mainline 
capacity, the Commission can take remedial action when warranted. Among 
the potential remedies that could be considered would be limiting the 
rates at which the affiliate can release capacity, limiting the amount 
of capacity the affiliate can hold, prohibiting the affiliate from 
holding capacity on its related pipeline, or, as NGSA suggests, 
conditioning the affiliate's continued right to exceed the price 
ceiling on the pipeline's agreement to construct capacity for which the 
shipper is willing to pay.
---------------------------------------------------------------------------

    \71\ Panhandle Eastern Pipe Line Company, 91 FERC para. 61,037 
(2000).
---------------------------------------------------------------------------

    More Limited Experiment. Recognizing the value of experimental 
programs, Process Gas Consumers contends that if the Commission chooses 
to proceed with an experiment in lifting price ceilings, it should 
narrow the scope of the experiment to select markets where competition 
appears to be the most robust and to place some form of ceiling on the 
prices that can be charged.
    The Commission sees little value in further limiting the scope of 
the waiver. First, as discussed above, the Commission has concluded 
that there are sufficient protections to go forward with the relaxation 
of the price ceiling for short-term capacity release transactions in 
all markets. Second, the Commission finds that limiting the program in 
these ways will eliminate information that is needed to evaluate the 
effects of price cap removal and is otherwise infeasible. The impact of 
removing price ceilings will occur principally in markets where, due to 
weather conditions, demand increases and capacity becomes scarce. Such 
markets cannot be anticipated in advance, so that a geographic or other 
limitation may yield little useful information by the end of the two-
year period. Limiting the waiver only to those markets that are already 
presumed to be competitive similarly will provide little information on 
how markets across the board behave. Such a limitation would be 
tantamount to conducting an experiment with only a control group, 
excluding those markets whose performance is most important to monitor. 
To evaluate the waiver, the Commission needs to be able to examine the 
effects of removing the price ceiling on all markets, both those which 
may appear competitive and those with higher concentration ratios.
2. Price Ceiling for Pipeline Capacity
    CNG, Great Lakes, Kinder-Morgan, Koch, and Williams contend the 
Commission erred in not removing rate regulation for pipeline short-
term services. They maintain that if the market is workably competitive 
enough to permit lifting of the price ceiling for capacity release 
transactions, it also should be sufficiently competitive to lift the 
price ceiling for pipeline short-term services. Kinder-Morgan and Koch 
maintain the regulation of pipeline services is not justified as a 
protection against withholding of capacity by releasing shippers 
because firm shippers can manipulate the nomination process to withhold 
capacity.
    The Commission in this rule determined to make only incremental 
changes in its regulatory policies to promote efficiency, establishing 
an ongoing process to consider whether more fundamental changes should 
be adopted. Since unbundling, the regulation of pipeline services has 
been the basic protection against the potential exercise of market 
power over

[[Page 35720]]

transportation service, and in making incremental changes to its 
current regulatory system, the Commission chose not to disturb this 
traditional protection. The Commission, therefore, waived the price 
ceiling only for capacity release transactions, as urged by a number of 
commenters, including pipelines, who contended that removal of rate 
ceilings for capacity release transactions is a first step toward the 
goal of revising regulatory policy to enhance efficiency.\72\
---------------------------------------------------------------------------

    \72\ See Comments of AGA and INGAA.
---------------------------------------------------------------------------

    In addition, pipelines do have avenues for lifting price ceilings 
for their short-term services. In Order No. 637, the Commission stated 
that pipelines could lift price ceilings for their capacity if they 
implement an auction process that protects against the exercise of 
market power. They also can file for market based rates under the 
Commission's Alternative Rate Design Policy if they can demonstrate 
that sufficient competition exists in the short-term market so that the 
removal of rate regulation for all short-term services will not permit 
the exercise of market power.
3. Implementation of the Waiver
    Several rehearing requests seek rehearing or clarification 
regarding the way in which the waiver of the rate ceiling for short-
term release transactions will be applied.
    a. Refund Requirement. IPAA and Indicated Shippers contend that the 
Commission should impose a refund requirement in the event the 
Commission or a reviewing court concludes the removal of rate ceilings 
for short-term released capacity is unlawful. The imposition of a 
refund requirement would run counter to the purpose of waiving the rate 
ceiling. One of the reasons for lifting the rate ceiling was to give 
releasing shippers an incentive to move transactions from the opaque 
bundled sales market to the transparent capacity release market, so 
that the Commission can obtain useful data about the effect of lifting 
the price cap during the two-year waiver period. If releasing shippers 
know they are subject to a potential refund requirement, they will be 
less likely to use capacity release as opposed to making bundled 
sales.\73\ Moreover, an across-the-board refund condition is not 
necessary because, should the Commission determine in an individual 
case that a releasing shipper has abused its market power, the 
Commission has the authority under section 16 of the NGA to take 
appropriate remedial action that can include remedies to prevent unjust 
enrichment.\74\
---------------------------------------------------------------------------

    \73\ As pointed out in Order No. 637, a shipper may be willing 
to release its capacity where the price it can obtain for the 
released capacity exceeds the cost of its alternatives, such as 
using an alternative fuel or LNG. Order No. 637, 65 FR at 10181, III 
FERC Stats. & Regs. Regulations Preambles para. 31,091, at 31,277. 
If the releasing shipper is not certain that it will be permitted to 
retain funds above the maximum rate, it may be less likely to 
release the capacity or may decide to make a bundled sale instead.
    \74\ 15 U.S.C. 717o; Mesa Petroleum Co. v. FERC, 441 F.2d 182, 
186-88 (5th Cir. 1971); Coastal Oil & Gas Corporation v. FERC, 782 
F.2d 1249 (5th Cir. 1986).
---------------------------------------------------------------------------

    b. Compliance with Reporting Requirements. NGSA and Indicated 
Shippers contend the Commission erred in lifting the price ceiling 
before pipelines comply with the tariff and reporting requirements 
established in Order No. 637. They contend that the tariff changes, 
such as enhancing segmentation, and the reporting requirements are 
intended to enhance competition and permit better monitoring of the 
marketplace, and, accordingly, they maintain the waiver of the rate 
ceiling should be postponed until these enhancements are in place.
    The Commission finds no reason to delay removal of the price 
ceiling to await pipeline compliance with other aspects of Order No. 
637, particularly given the efficiency benefits identified in Order No. 
637 that open capacity trading will bring. The revised reporting 
requirements primarily are to obtain more information about pipeline 
capacity and to make the reporting of pipeline transactions conform 
with the existing reporting requirements for capacity release 
transactions. The reporting requirements related to capacity release 
transactions essentially are the same as they were before, and will 
provide information about capacity release transactions sufficient to 
permit the industry and the Commission to monitor these transactions. 
Although the compliance filings with respect to segmentation are 
designed to improve the current system, many pipelines already permit 
segmentation on their systems and the rule contains sufficient other 
protections against the exercise of market power that implementation of 
the rate ceiling waiver need not wait for implementation of enhanced 
segmentation.
    c. Tariff Requirement. Process Gas Consumers maintains the 
Commission's relaxation of the price cap violates section 4 of the NGA 
under the principles established in Maislin Industries, U.S., Inc. v. 
Primary Steel, Inc.,\75\ because the rates for capacity release 
transactions will not be on file prior to the rate being collected. The 
Commission finds no violation of the requirements of section 4 of the 
NGA. Unlike Maislin, which involved a statute providing for common 
carriage, section 4 of the Natural Gas Act envisions that 
individualized contracts will be used to establish rates for the sale 
of gas,\76\ and such contracts can become effective even before the 
rates are filed with the Commission.\77\
---------------------------------------------------------------------------

    \75\ 497 U.S. 116 (1990).
    \76\ United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 
U.S. 332 (1955).
    \77\ Columbia Gas Transmission Corp. v. FERC, 895 F.2d 791 (D.C. 
Cir. 1990), City of Piqua v. FERC, 610 F.2d 950 (D.C. Cir. 1979) 
(individual contracts can take effect even prior to filing with the 
Commission).
---------------------------------------------------------------------------

    The Commission is complying with the filing and notice requirements 
of section 4 by requiring the pipelines to file tariffs setting forth 
the conditions of capacity release and specifying that the rates for 
capacity release transactions will be established by contract between 
the releasing and replacement shippers. The Commission further is 
satisfying these requirements by requiring the posting of the rates on 
Internet web sites no later than the first nomination for service under 
an agreement.\78\ Section 4 of the NGA provides that the Commission can 
establish the ``rules and regulations'' for how rate schedules will be 
filed, and that the Commission can waive the advance 30 day filing 
requirement and, in so doing, specify ``the time when they shall take 
effect and the manner in which they shall be filed and published.'' 
\79\ Using modern electronic methods to provide fast and effective 
dissemination of rates to the public using computers satisfies the 
statutory goal of open posting of rates.
---------------------------------------------------------------------------

    \78\ As discussed below, the Commission is granting rehearing 
and revising its transactional reporting regulations to require 
posting no later than the first nomination for service.
    \79\ 15 U.S.C. 717c (c)-(d).
---------------------------------------------------------------------------

    d. Effective Date. Columbia Gas and Enron request clarification 
that the removal of the price ceiling does not take effect until the 
Commission has accepted tariff changes to remove pipeline tariff 
provisions inconsistent with the removal of the price ceiling. The 
Commission denies the request. Under Order No. 637, the rate ceiling 
was removed from capacity release transactions on the day the 
regulation (section 284.8 (i)) became effective, March 26, 2000. To 
reduce the tariff-filing burden on pipelines, the Commission provided 
them with a period of up to 180 days to remove potentially inconsistent 
tariff provisions, but that grace period did not change the effective 
date of the regulation.

[[Page 35721]]

B. Peak and Off-Peak Rates

    Order No. 637 provides that pipelines may institute value-based 
peak/off-peak rates for all short-term services as one possible method 
of promoting allocative efficiency that is consistent with the goal of 
protecting customers from monopoly power.\80\ Short-term services are 
defined to include short-term firm and interruptible service and multi-
year seasonal contracts. Implementation of peak/off-peak rates can 
promote several important policy goals. Specifically, peak/off-peak 
rates could remove one of the biases favoring short-term contracts, 
reduce the need for discounts and reliance on discount adjustments, and 
increase efficiency in short-term markets by allowing prices to better 
reflect demand during peak periods. Order No. 637 provides that in 
implementing peak/off-peak rates, the pipeline must stay within its 
annual revenue requirement and, thus, any increases in rates at peak 
must be offset by decreases in off-peak rates.
---------------------------------------------------------------------------

    \80\ Order No. 637 at 93-106.
---------------------------------------------------------------------------

    The discussion of peak/off-peak rates in Order No. 637 was a 
statement of policy and not a rule that imposed any requirements on 
pipelines or changed current Commission regulations. As the Commission 
explained, the current regulations \81\ and Commission precedent 
already recognized that peak/off-peak rates have a role in the 
ratemaking process.\82\
---------------------------------------------------------------------------

    \81\ The Commission cited 18 CFR 284.7(c)(3)(i).
    \82\ The Commission cited the Rate Design Policy Statement, 47 
FERC para. 61,295 at 62,054 (1989).
---------------------------------------------------------------------------

    The policies adopted in Order No. 637 are intended to facilitate 
the implementation of peak/off-peak rates with a flexible policy that 
will permit the use of a wide variety of peak/off-peak rate methods. As 
the Commission explained, there is more than one reasonable way to 
implement peak/off-peak rates based on value of service concepts, and 
some methods may work better for certain systems than others. 
Therefore, the Commission did not adopt any one method of developing 
peak/off-peak rates, but left the details of the implementation of 
peak/off-peak rates to individual pipelines.
    Order No. 637 permits pipelines to implement peak/off-peak rates 
through limited section 4 pro forma tariff filings subject to several 
conditions.\83\ First, if the pipeline seeks to implement seasonal 
rates in a limited section 4 filing, it must include in its proposal a 
revenue sharing mechanism that will provide for at least an equal 
sharing of any increased revenues with its long-term customers. In 
addition, Order No. 637 provides that after 12 months experience with 
peak/off-peak rates, the pipeline must prepare a cost and revenue study 
and file the study with the Commission within 15 months. Based on the 
cost and revenue study, the Commission will determine whether any rate 
adjustments are necessary to the long-term rates, and may order such 
adjustments prospectively.
---------------------------------------------------------------------------

    \83\ Order No. 637 provides that the pro forma filing would be 
noticed with comments due in 21 days, rather than the 12 days 
permitted for tariff filings, and the Commission would act on the 
proposal within 60 days.
---------------------------------------------------------------------------

    AGA, Keyspan, New England, UGI, Amoco, IPAA, Indicated Shippers, 
Process Gas Consumers, NGSA, NAGC, NASUCA, INGAA, CNG, Coastal 
Companies, Columbia, Enron, Kinder Morgan, Koch, and The Williams 
Companies (TWC) seek rehearing or clarification of this portion of 
Order No. 637. Indicated Shippers argue that the Commission's policy 
statement fails to comply with the Administrative Procedure Act. 
Several shipper groups argue that the Commission should require 
pipelines to implement peak/off-peak rates in a full section 4 
proceeding, while the pipelines argue that the limited section 4 
procedures established by the Commission are too burdensome. The LDCs 
ask the Commission to clarify the application of peak/off-peak rates to 
captive customers.
1. Compliance With the Administrative Procedure Act
    Indicated Shippers argue that insofar as Order No. 637 establishes 
specific mechanisms for the implementation of peak/off-peak rates, it 
is not a policy statement, but is a substantive rule, and that the 
Commission erred in promulgating this final rule without complying with 
the notice and comment requirements of the Administrative Procedure Act 
(APA).\84\ Indicated Shippers state that the Commission's statement 
that peak/off-peak rates are allowable under the Commission's 
regulations may qualify as a policy statement or interpretive rule that 
is exempt from the notice and comment requirements of the APA,\85\ but 
mechanisms applicable to the filings to implement peak/off-peak rates 
are substantive requirements of general applicability that must be 
subject to notice and comment.
---------------------------------------------------------------------------

    \84\ 5 U.S.C. 553(b)(3), (c).
    \85\ The notice and comment requirements of the APA are not 
applicable to ``interpretive rules, general statements of agency 
policy, or rules of agency organization, procedure, or practice. * * 
*'' 5 U.S.C. 553(b)(3)(A).
---------------------------------------------------------------------------

    Indicated Shippers argue that under the APA, a policy statement is 
``only supposed to indicate an agency's inclination or leaning, [and 
is] not in any way binding on the agency.'' \86\ Indicated Shippers 
argue that the pro forma tariff filing, the revenue-sharing mechanism, 
and the cost and revenue study, do not meet the criteria for a policy 
statement because they are binding on the agency and the pipelines. 
Further, Indicated Shippers argue that the Commission has created new 
rights and duties for pipelines choosing to implement peak and off-peak 
rates. According to Indicated Shippers, Order No. 637 creates new 
rights because pipelines and long-term shippers will reap the benefits 
of sharing increased revenues from short-term shippers; it creates new 
duties because it imposes on the pipeline an obligation to perform a 
cost and revenue study.
---------------------------------------------------------------------------

    \86\ Indicated Shippers cite, inter alia, Hudson v. FAA, 192 
F.3d 1031, 1034 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    Further, Indicated Shippers state that the pro forma tariff filing 
and the revenue sharing mechanism fundamentally change the allocation 
of costs between short-term and long-term shippers, effectively 
increase pipeline rates, and allow pipelines to retain 50 percent of 
the increased rates even though this increases their allowable rate of 
return. Indicated Shippers argue that none of these mechanisms were 
mentioned in the NOPR, and therefore the parties did not have an 
opportunity to comment on them. Indicated Shippers argue that the 
Commission must provide another notice and comment period on the 
mechanisms identified in the Rule, including the pro forma tariff 
filing, the revenue crediting mechanism, and the cost and revenue 
study.
    As explained in Order No. 637, peak/off-peak rates are currently 
available as a ratemaking methodology under the Commission's 
regulations and prior decisions. Nothing in Order No. 637 imposes any 
requirements on the pipelines--the decision to implement peak/off-peak 
rates is entirely voluntary--or changes Commission regulations. Thus, 
Order No. 637 does not promulgate substantive rules that establish a 
``standard course of action which has the force of law.'' \87\ The 
Commission did not establish a method of developing peak/off-peak 
rates, but left this and other issues such as the revenue sharing 
mechanism to be resolved in the individual proceedings. The Commission 
did give guidance and direction on how peak/off-peak rates could be 
implemented in the individual

[[Page 35722]]

cases and therefore is properly considered a policy statement.
---------------------------------------------------------------------------

    \87\ Pacific Gas and Electric Co. v. FERC, 506 F.2d 33, 38 (D.C. 
Cir. 1974).
---------------------------------------------------------------------------

    Indicated Shippers recognize that the discussion of peak/off-peak 
rates as a voluntary method of promoting allocative efficiency is 
properly considered a policy statement, but attempt to distinguish the 
revenue sharing mechanism as a separate matter that creates new rights 
and duties. However, the revenue sharing mechanism does not create a 
``right'' to additional revenues. As the Commission explained in Order 
No. 637, the voluntary implementation of peak/off-peak rates, as 
currently permitted under Commission policy, could lead to increased 
revenues.\88\ The Commission has found here, as a matter of policy, 
that a revenue sharing mechanism is necessary to provide for an 
equitable division of those revenues as part of the implementation of 
peak/off-peak rates in a limited section 4 filing.
---------------------------------------------------------------------------

    \88\ The Commission explained that because the price cap would 
be higher in the peak, and the pipeline might see little reduction 
in off-peak revenues because market prices are usually below the 
maximim rate, this could lead to increased reveues.
---------------------------------------------------------------------------

    The Commission has the discretion to direct the conduct of its 
proceedings. It is within that discretion for the Commission to 
conclude that it will use a limited section 4 rather than a full 
section 4 proceeding to implement peak rates and to require pipelines 
to submit a cost and revenue study.
    In any event, Indicated Shippers and the other petitioners have had 
an opportunity to submit their views on the use of a pro forma tariff 
filing, the revenue sharing mechanism, and the cost and revenue study. 
These issues and the petitioners' substantive arguments about the 
appropriate mechanisms for implementing peak/off-peak rates are fully 
discussed below. Thus, the parties have been given a full opportunity 
to comment on the use of peak/off-peak rates and the appropriate method 
for implementing these rates. Nothing more could be accomplished 
through an additional notice and comment period.
2. Implementation Procedures
    Since the implementation of peak/off-peak rates is likely to result 
in a revenue increase for the pipeline if all other rates remain the 
same, traditionally, the Commission would require the pipeline to file 
a general section 4 rate case to implement peak/off-peak rates. 
However, as the Commission explained in Order No. 637,\89\ the 
traditional methods are ill-suited to this context because the rate 
methodology relies on a historical test period to project future 
throughput for each service, and there is no historical experience with 
peak/off-peak pricing. The Commission also pointed out that using 
general rate cases to implement peak/off-peak rates could be time 
consuming. Moreover, because the seasonal rate will be derived from the 
annual revenue requirement, there should be no factual issues involved 
in computing the rate that would require investigation or analysis. 
Therefore, the Commission concluded that pipelines may implement peak-
off peak rates in a limited section 4 proceeding, subject to the 
conditions that the pipeline implement as part of its filing a revenue 
sharing mechanism and file a cost and revenue study within 15 months of 
the implementation of peak/off-peak rates.
---------------------------------------------------------------------------

    \89\ Order No. 637 at 104.
---------------------------------------------------------------------------

    a. The Option of a Limited Section 4 Filing. Indicated Shippers, 
IPAA, and NGSA argue that the Commission has not justified use of a pro 
forma tariff filing to implement peak/off-peak rates, and that peak/
off-peak rates must be implemented in a full section 4 proceeding. They 
argue that the concerns that lead the Commission to require that term-
differentiated rates must be implemented in a full section 4 proceeding 
apply to peak/off-peak rates as well. They assert that in both cases 
the change in rate method will affect other elements that affect the 
rates of all shippers, and in each case, the change will have an effect 
on throughput, demand units, discount levels and pipeline revenues. 
INGAA, on the other hand, asserts that arguments that rates for short-
term services must be established in a full section 4 rate case fail to 
consider that implementation through a settlement or pro forma filing 
will reduce the level of discount adjustments in future rate cases, and 
that the possibility of sharing revenues will benefit long-term 
customers immediately.
    A limited section 4 filing with the safeguards imposed by the 
Commission is an appropriate vehicle for implementing peak/off-peak 
rates. As the Commission explained in Order No. 637, the peak/off-peak 
rates will be derived from the pipeline's annual revenue requirement, 
and there should be no factual issues involved in computing the rates 
that require investigation or analysis in a full section 4 proceeding. 
Under the current method, the pipelines' rates have been derived by 
recovering the annual revenue requirement uniformly throughout the 
year. With peak/off-peak rates, the rates will be derived from the 
annual revenue requirement using one of several methods of measuring 
value at peak and off-peak. This does not require an investigation of 
all the pipeline's costs and rates in a full section 4 proceeding. 
Moreover, a meaningful review of rates under the current methodology 
requires one year of historical experience. The process here permits 
the pipeline to get that experience and then allows the Commission to 
review the results with a cost and revenue study, making any necessary 
prospective adjustments.
    Moreover, a meaningful review of rates under the current 
methodology requires one year of historical experience in order to 
predict future costs and volumes. The limited section 4 process adopted 
by the Commission obtains the data from that experience and permits the 
Commission to review the results with a cost and revenue study, 
allowing prospective adjustments. The use of a limited section 4 
proceeding to implement peak/off-peak rates is similar to a situation 
where a pipeline initiates new services and the Commission permits 
implementation of the new services in a limited section 4 proceeding in 
part because there is no historical experience available.\90\
---------------------------------------------------------------------------

    \90\ See Mojave Pipeline Co., 79 FERC para.61,347 at 62,482 
(1997).
---------------------------------------------------------------------------

    Indicated Shippers, IPAA, and NGSA also argue that implementation 
of peak/off-peak rates should be conditioned on a pipeline filing a 
full section 4 proceeding in the future. Indicated Shippers and NGSA 
state that because some pipeline rates are already stale, 
implementation of seasonal rates increases the need or rate review. 
NGSA states that revenue crediting is not a long-term fix for pipeline 
rates, and only through a requirement that a pipeline at least 
periodically submit a rate case can the Commission fulfill its 
responsibility to ensure cost-based rates that approximate a pipeline's 
cost-based revenue requirement.
    Under section 4 of the NGA, the Commission is required to ensure 
that rate changes proposed by the pipelines are just and reasonable, 
and under section 5, if the Commission finds after a hearing that the 
existing rate is unjust or unreasonable, it must establish the just and 
reasonable rate for the future. The Commission's authority under these 
two sections provides adequate means for ensuring that pipeline rates 
are just and reasonable. A requirement that pipelines file periodic 
rate cases is not part of the statutory scheme. The Commission imposed 
a three-year review requirement as part of its purchased gas adjustment 
(PGA) scheme--in exchange for the benefit of being able to track 
changes in purchased

[[Page 35723]]

gas costs which were then rapidly increasing, the pipelines agreed to a 
reexamination of all their costs and revenues at three year intervals. 
Seasonal rates are not analogous to the implementation of the PGA. 
Seasonal rates do not change the pipeline's existing cost of service or 
revenue requirement; rather they constitute a change in rate design 
used to recover the pipeline's existing cost of service. Thus, they are 
more analogous to the Commission's direction to the pipelines in Order 
No. 636 to implement the SFV rate design, and the court upheld the 
Commission's decision not to require periodic rate review in that 
context.\91\ The authority provided the Commission under sections 4 and 
5 of the NGA is adequate to enable the Commission to fulfill its 
responsibility to ensure that rates are just and reasonable, and a 
mandatory periodic rate review is not necessary at this time. Under the 
procedures established by the Commission, the cost and revenue study 
will provide a basis for determining whether the rates are stale, and, 
if so, the Commission would institute a section 5 proceeding to address 
the issue.
---------------------------------------------------------------------------

    \91\ UDC v. FERC, 88 F.3d 1105, 1176 (D.C. Cir. 1996).
---------------------------------------------------------------------------

    Indicated Shippers also argue that the pro forma tariff procedures 
would shift the burden of proof to ratepayers and eliminate the refund 
provision. Indicated Shippers state that under the pro forma procedures 
established by the Commission, the pipeline would have the burden of 
proof only with respect to whether the particular method proposed by 
the pipeline is just and reasonable, and that if ratepayers want to 
challenge aspects of the rates filed other than the peak/off-peak 
method itself, then such issues must be raised in a section 5 
proceeding. Indicated Shippers give an example of an argument that the 
peak/off-peak rates will reduce the pipeline's need to discount and 
therefore the design units should be increased, and assert that the 
burden of proof would be on the shipper and not the pipeline under the 
procedure established by the Commission.
    Order No. 637 specifically provides that the pipeline will have the 
burden of proving that its proposed method of implementing peak/off-
peak rates is just and reasonable. As discussed above, the Commission 
has determined that, if the pipeline meets the conditions set forth in 
Order No. 637, it may implement peak/off-peak rates through a limited 
section 4 proceeding. Therefore, the pipeline's burden will be limited 
to showing that its proposed method is just and reasonable. The 
specific issues involved in this determination will be established in 
the individual cases. The pipeline will have the burden of proof 
regarding any changes it proposes in the limited section 4 proceeding. 
Because the tariff filing is pro forma, any other issues raised under 
section 5 can be resolved before the tariff sheets go into effect, so 
there should be no issue of refunds.
    Order No. 637 provides that under the pro forma filing procedure, 
the filing would be noticed with comments due in 21 days, rather than 
the 12 days permitted for tariff filings, and the Commission would take 
action within 60 days. Several petitioners ask the Commission to modify 
its time table for processing pro forma tariff filings. UGI asserts 
that given the complexity of the filings, the current schedule is too 
compressed and asks the Commission to modify the schedule to allow 30 
days for comment and 120 days for Commission action. Process Gas 
Consumers ask the Commission to give parties 45 days to comment and the 
Commission 90 days to act on the filing in order to provide time for a 
technical conference in each case. Process Gas Consumers state that the 
Commission should require a technical conference to give the parties a 
chance to raise concerns and possibly resolve issues prior to the 
filing of substantive comments.
    The Commission has extended the comment period from the 12 days 
permitted for a tariff filing to 21 days to provide the parties with an 
additional time to analyze the pipeline's proposals. This extended 
period should be adequate to enable the parties to analyze and present 
their views on the pipeline's proposals. If adjustments are necessary, 
or if it appears that a technical conference would be beneficial in a 
particular case, the Commission can address these concerns in the 
individual proceedings.
    b. Revenue Sharing. The implementation of peak/off-peak rates could 
lead to higher pipeline revenues from short-term services since a 
pipeline could reduce off-peak period price caps so that they would be 
close to recent discount history, and correspondingly increase peak 
period price caps. The Commission indicated in Order No. 637 that the 
process for implementing peak/off-peak rates must take into account any 
increased revenues. Therefore, if the pipeline seeks to implement 
seasonal rates in a limited section 4 filing, it must include in its 
proposal a revenue sharing mechanism that will provide for at least an 
equal sharing of any increased revenues with its long-term customers. 
Order No. 637 indicated the Commission's view that the revenue sharing 
should be limited to long-term customers and explained that under the 
current cost-of-service rate methodology, underpricing short-term peak 
capacity results in long-term customers paying higher rates because a 
greater share of the pipeline's costs is recovered from long-term 
customers.
    Indicated Shippers argue that the revenue sharing mechanism is 
unjust and unreasonable and will result in a windfall to the pipelines, 
and further that it will serve as a disincentive for the pipelines to 
file section 4 rate cases. Indicated Shippers and NGSA argue that the 
Commission provided no basis for permitting pipelines to retain up to 
50 percent of the excess revenues, and NGSA states that Order No. 637 
is internally inconsistent because, on the one hand it justifies 
seasonal rates by stating that the pipeline's overall recovery will be 
limited to their cost-based annual revenue requirement, and on the 
other hand, permits the pipelines to retain up to 50 percent of the 
excess revenues. Indicated Shippers and NGSA assert there is no need to 
give pipelines an incentive to file seasonal rates since pipelines have 
proposed and want seasonal rates. NGSA and NASUCA argue that the 
Commission has given no justification for departing from the 90/10 
split it used in restructuring.
    Kinder Morgan, on the other hand, argues that the level of revenue 
sharing should be fully subject to negotiation and not limited by any 
predetermined rules such as a minimum level of revenue sharing.
    The Commission has not required a 50/50 sharing of excess revenues, 
but indicated that the pipeline should include in its filing a 
mechanism that will provide for at least an equal sharing of any 
increased revenues with its customers. The Commission and the parties 
can work out the details of the revenue crediting mechanism in 
individual pipeline proceedings. In particular, the Commission 
suggested that the pipelines and their customers try to negotiate an 
equitable sharing mechanism pending the filing of the cost and revenue 
study required by Order No. 637. As the Commission explained in Order 
No. 637, the revenue sharing method should be fair to the pipelines and 
the customers, and pipelines are encouraged to work with their 
customers to develop a method that has wide support. When the pipeline 
files its cost and revenue study, the Commission can determine whether 
any changes to the long-term customers' rates are necessary. In the 
interim, a

[[Page 35724]]

revenue sharing mechanism agreed upon by the parties provides an 
equitable temporary solution. Indicated Shippers and NGSA also argue 
that excess revenues should be shared by all customers, not just long-
term customers. Indicated Shippers assert that the Commission's 
concerns for long-term shippers are misplaced because the Commission 
considered only the risks of long-term service without considering the 
benefits of long-term service that makes it superior to short-term 
service. Indicated Shippers state that on many fully-subscribed 
pipelines, short-term service is the only service available.
    Further, Indicated Shippers state that in the past where increased 
revenues attributable to increased demand units are to be credited to 
shippers, the Commission has held that revenues should be credited to 
all shippers.\92\ Indicated Shippers quote the Commission's rationale 
for deciding that IT revenues should be credited to all shippers:
---------------------------------------------------------------------------

    \92\ Indicated Shippers cite Transcontinental Gas Pipeline 
Corp., 78 FERC para. 61,057 (1997); Transcontinental Gas Pipeline 
Corp., 79 FERC para. 61,325 (1997).

    Since the purpose of interruptible revenue credits was to 
protect the pipeline's customers from too low an allocation to 
interruptible service, it follows that the customers who receive the 
credits should be the customers harmed by the erroneously low 
allocation. An allocation of too little costs to interruptible 
services cause both the firm and interruptible maximum rates to be 
too high.\93\
---------------------------------------------------------------------------

    \93\ Transcontinental Gas Pipe Line Corp., 78 FERC at 61,209.

    Indicated Shippers argue that the same reasoning applies in the 
present case, and that to the extent that pre-existing short-term rates 
were designed on the basis of fewer demand units than will arise upon 
the adoption of peak/off-peak rates, both the existing long-term and 
short-term rates are too high. Accordingly, Indicated Shippers argue, 
all shippers should be eligible to share in the increased revenues 
attributable to peak/off-peak rates, and the only customer excluded 
should be discount shippers whose discounts more than offset the 
understatement of design units underlying existing rates.\94\
---------------------------------------------------------------------------

    \94\ Indicated Shippers cite Transcontinental Gas Pipeline Co., 
78 FERC at 61,209.
---------------------------------------------------------------------------

    NGSA similarly argues it is appropriate to credit excess revenues 
to all shippers because, until a pipeline's next rate case, revenue 
crediting acts as a substitute for adopting new discount adjustments 
(i.e., lowering maximum rates), which will benefit all shippers, both 
short-term and long-term. Further, NGSA states that the Commission 
should not allow any credit to be paid to any pipeline affiliate.
    NASUCA, on the other hand, argues that all revenues should be 
credited back to long-term firm shippers. NASUCA asserts that since the 
Commission has not departed from SFV, long-term shippers pay all the 
pipeline's fixed costs, and therefore they should receive the revenue 
offset.
    It is appropriate to limit the revenue sharing to long-term 
customers. Crediting of excess revenues from peak/off-peak rates is not 
analogous to crediting of IT revenues during restructuring. In the case 
of IT revenues, as Indicated Shippers point out, the crediting was 
intended to protect the pipeline's customers that would be harmed by 
too low an allocation to interruptible service. Too low an allocation 
to interruptible service would result in all the customers' rates being 
too high. That is because the maximum interruptible rate was a load 
factor derivative of the firm rate, and not a rate separately designed 
based on the costs allocated to interruptible service. Here, in 
contrast, a primary purpose of peak/off-peak rates is to lower the 
share of the pipeline's costs that are paid by long term shippers as a 
result of short-term shippers obtaining peak service at less than the 
market rate for that service. In these circumstances, a credit to long-
term customers only is appropriate.
    Amoco and Dynegy ask the Commission to clarify that pipelines will 
not share revenues under this requirement with affiliates, negotiated 
rate customers, or customers receiving a discount. At present, the 
Commission is not persuaded that affiliates that are long-term 
customers should be treated any differently from other long-term firm 
customers for purposes of revenue crediting. However, the parties may 
address this issue in the individual proceedings. Also, as an initial 
matter, the Commission believes that it may be appropriate for 
customers receiving a discount to share in any revenues to the extent 
that the credit would reduce their rate below the discount level. 
However, this issue may also be addressed in the individual 
proceedings. On the other hand, negotiated rate shippers have already 
negotiated the rate they will pay, and therefore will not share in the 
revenues.
    Koch asks the Commission to clarify that in a situation where the 
pipeline offers both seasonal and non-seasonal rates, and the revenues 
generated from the seasonal services are greater than the costs 
allocated to those services, but the total revenues from both seasonal 
and non-seasonal services are less than the costs allocated to both the 
services, the pipeline should not be required to share a portion of the 
excess revenues from its seasonal services with its long-term shippers. 
Koch states that in this example the pipeline has not earned its 
revenue requirement, and if revenue sharing were required, the pipeline 
would be in a worse position than if it had not offered the seasonal 
service. Koch asks the Commission to clarify that the revenue sharing 
mechanism applies only when the revenues collected from all of its 
transportation services exceed the total revenue requirement.
    Order No. 637 stated that the pipeline is not required to share 
revenues if there are none, and that a pipeline will not be required to 
share excess revenues if it demonstrates that its total revenues from 
peak/off-peak rates were less than the costs allocated to the relevant 
services in its last rate case.\95\ The appropriate method for 
determining the level of revenues to be credited can be decided in the 
individual proceedings.
---------------------------------------------------------------------------

    \95\ Order No. 637 at 106.
---------------------------------------------------------------------------

    c. Cost and Revenue Study. A pipeline that implements peak/off-peak 
rates through a limited section 4 proceeding after 12 months of 
experience with peak/off-peak rates, will need to prepare a cost and 
revenue study and file the study pursuant to the format prescribed in 
Sec. 154.313 of the Commission's regulations within 15 months of 
implementing peak/off-peak rates. Based on the results of the study, 
the Commission will determine whether any rate adjustments are 
necessary to the long-term rates and, if so, order adjustments 
prospectively.
    Process Gas Consumers agree that the cost and revenue study is a 
necessary part of the implementation of seasonal rates, but ask the 
Commission to clarify that interested parties may participate in the 
review process involving the study, and that the parties must have 
access to the information used by the pipeline to compile its study, 
and be privy to data requested by Staff in its review of the study. In 
addition, Process Gas Consumers request the Commission to clarify that 
pipelines must eliminate the discount adjustment as part of their 
individual cost/revenue study.
    The Commission clarifies that interested parties may participate in 
the review process of the cost and revenue study. Procedures can be 
adopted in the individual cases to provide that these parties have 
access to the information necessary for their participation. A pipeline 
is not required to eliminate its discount adjustment at the time it 
files the cost and revenue study, but the issue of whether a change 
should be

[[Page 35725]]

made in the pipeline's discount adjustment may be considered in the 
individual proceedings.
    INGAA, CNG, Coastal Companies, Columbia, Enron, Koch, Kinder 
Morgan, and TWC argue that the cost revenue study would be overly 
burdensome to the pipelines and should either be eliminated or strictly 
limited to costs and revenues associated with peak/off-peak rates. 
These petitioners assert that the requirement for this study could 
discourage pipelines from filing for peak/off-peak rates. If the study 
is retained, the pipelines argue that the Commission should not require 
a full cost and revenue study, but should limit its scope to a review 
of the revenues associated with the new services compared to revenues 
from standard rates, as well as data regarding revenue crediting. They 
assert that the filing should not be an occasion to examine the 
pipeline's costs or long-term rates that are unaffected by the peak/
off-peak initiative.
    The Commission does not intend to discourage pipelines from using 
peak/off-peak rates, and has structured the implementation process so 
that pipelines are not required to file a full section 4 proceeding in 
order to implement peak/off-peak rates. If the pipeline uses the 
limited section 4 procedure, it will be necessary to assure that the 
pipeline does not overrecover its cost of service. In order to make 
this determination, the Commission will look at all the services 
offered by the pipeline, including the interplay of short-term and 
long-term services, and therefore a cost and revenue study as provided 
by section 154.313 of the Commission's regulations is appropriate.
    Coastal Companies state that if the Commission continues to require 
a cost and revenue study, it should not require that it be filed within 
15 months if the pipeline files a rate case in that period and seeks in 
the rate case to implement peak/off-peak rate. The Commission clarifies 
that the requirement to file a cost and revenue study applies if the 
pipeline chooses to implement peak/off peak rates through the pro forma 
filing procedures outlined in Order No. 637, not if the pipeline 
implements peak/off-peak rates in a general section 4 rate proceeding.
    Koch states that requiring the filing of the cost and revenue study 
after 15 months would not be effective given what the Commission is 
trying to determine, and that it would be more appropriate for this 
study to be made after two winters as the Commission required with 
regard to the capacity release proposal. In addition, Koch states that 
pipelines should be able to offset over-recoveries received in one year 
against under-recoveries in another year. The Commission has determined 
that requiring the study after one year of experience strikes the 
appropriate balance between the need to obtain useful representative 
information and acting expeditiously.
3. Peak/Off-Peak Rates for Multi-Year Seasonal Contracts
    AGA, Keyspan, NAGC, and New England urge the Commission to rule on 
rehearing that pipelines cannot implement value-based seasonal rates 
for multi-year seasonal services purchased by customers without 
meaningful alternatives. These petitioners assert that the Commission's 
finding that multi-year seasonal contracts are more like short-term 
contracts is unsupported with regard to essential multi-year services 
purchased by captive customers. These petitioners argue, as they do 
with regard to the applicability of the right of first refusal (ROFR) 
to these contracts, that the services provided under many of these 
seasonal contracts, often storage and related transportation, are 
available from the pipeline only for specific months,\96\ and are not 
offered for a full year. They assert that these long-term contracts for 
seasonal service are not the product of negotiations in which the LDCs 
used leverage to avoid purchasing services on an annual basis. Instead, 
they assert, the pipelines offered the services for limited periods of 
the year, and the LDCs are dependent on these contracts to meet their 
peak demands.
---------------------------------------------------------------------------

    \96\ AGA gives several examples of such service, e.g., Transco's 
Southern Expansion Service which is available only from November 
through March.
---------------------------------------------------------------------------

    These petitioners argue that since one of the benefits of seasonal 
rates cited by the Commission is that they will reduce costs to captive 
customers, the Commission should not let them be a vehicle to shift 
costs to captive customers. These petitioners assert that the rates for 
their seasonal long-term contracts were established in section 4 
proceedings and already recover the full cost of providing the service. 
Keyspan argues that it would be unlawful to change these rates in a 
limited section 4 proceeding.
    As also discussed below with regard to the ROFR, some multi-year 
seasonal contracts of captive LDC's have characteristics that are more 
similar to long-term service than to short-term contracts. These 
captive customers contract with the pipelines for the peaking service 
necessary for the LDCs to serve their customers during the winter 
heating season over a period of years. These services, often storage 
and related transportation, are offered by the pipeline only on a 
partial year basis, and the LDCs take the services on the basis that 
they are offered by the pipeline. In these circumstances, the shippers 
are different from non-captive shippers taking short-term service at 
peak periods with no long-term contractual relationship with the 
pipeline. It was not the Commission's intent that the limited section 4 
filings would result in increased costs to long-term captive customers, 
and the mechanisms for implementing peak rates on the individual 
pipelines must be consistent with the Commission's goals. Issues 
concerning the appropriate allocation of costs to long-term peak/off-
peak are more appropriately addressed in a general section 4 rate case.
4. Other Matters
    a. Resolution by Settlement. INGAA and Kinder Morgan ask the 
Commission to clarify that peak/off peak and term-differentiated rates 
may be implemented through settlements, and that nothing in Order No. 
637 affects the ability of pipelines and their customers to negotiate 
peak/off-peak and term differentiated rates that do not interfere with 
existing settlement provisions. Kinder Morgan asks the Commission to 
clarify that peak/off-peak and term-differentiated rates may be 
implemented through settlements that can deviate from the conditions 
set forth in Order No. 637. The Commission clarifies that its 
discussion of peak/off-peak rates and term-differentiated rates does 
not limit the parties' ability to settle rate cases.
    b. Future Discounts. Koch asks the Commission to clarify whether 
offering peak/off-peak rates will affect its ability to seek a discount 
adjustment in its next rate case. Koch states that it does not appear 
that peak/off-peak rates would have a positive effect on revenues or 
reduce the annual level of discounting on its system. If Koch decides 
not to implement seasonal rates and that choice will reduce its ability 
to use a discount adjustment in future rates cases, then Koch needs to 
factor that risk into its decision, since the discount adjustment is 
critically important to Koch's long-term financial viability. Koch is 
concerned that the election not to implement seasonal rates will bar it 
from seeking a discount adjustment in future rate cases.
    The Commission clarifies that implementation of peak/off-peak rates 
is voluntary on the part of the pipeline. A pipeline's decision not to 
implement peak/off-peak rates will not affect the

[[Page 35726]]

pipeline's ability to seek a discount adjustment in its next rate case.

C. Term Differentiated Rates

    Term-differentiated rates, i.e., rates that differentiate among 
shippers based on the length of their contract, should be available to 
the pipeline as one of several methods that could be used to price 
capacity more efficiently. In Order No. 637, the Commission explained 
that term-differentiated rates would match price more closely with 
risk-adjusted value, and could result in a rate structure that prices 
capacity held for a longer term at a lower rate than capacity held for 
a shorter term.\97\ As explained in Order No. 637, term-differentiated 
rates would more accurately reflect in the price of service the 
relative levels of risk that pipelines must face when selling service 
for a shorter period than for a longer period, as well as the higher 
risks that customers face when they purchase service for a longer 
period of time.
    The Commission in Order No. 637 also explained that like peak/off-
peak rates, term-differentiated rates would be cost-based, just and 
reasonable rates because the Commission will limit the rates in the 
aggregate to produce the pipeline's annual revenue requirement. The 
Commission recognized that there are various methods that could be used 
to develop reasonable term differentiated rates, and some methods might 
be more appropriate on certain pipelines than on others. Therefore, the 
Commission did not adopt a generic formula for implementation of term-
differentiated rates, but indicated that it would allow the pipelines 
and the customers to work out the details of the methodologies in 
specific rate proceedings.
    Order No. 637 also provides that a pipeline may propose term-
differentiated rates just for long-term services or for both short and 
long-term services. Because the use of term-differentiated rates for 
short-term services may enhance the potential for price discrimination, 
particularly during off-peak periods, by increasing the rate caps that 
would apply to short-term service acquired in off-peak periods, the 
Commission made clear that a pipeline proposing term-differentiated 
rates for short-term services will need to explain fully the basis and 
justification for the price differentials. Further, because term-
differentiated rates have a much greater potential for affecting the 
rates of all customers than peak/off-peak rates,\98\ the Commission 
required that the general reallocation of revenue responsibility among 
customer classes must be done through rate changes for all customers 
simultaneously in the section 4 rate filing in which the pipeline seeks 
to implement term-differentiated rates. Requests for rehearing or 
clarification of this portion of Order No. 637 were filed by Amoco, 
Keyspan, Process Gas Consumers, INGAA, CNG, Coastal Companies, Kinder 
Morgan and Koch. The requests for rehearing are discussed below.
    Process Gas Consumers argue that the Commission violated its own 
rules and acted arbitrarily and capriciously in granting pipelines 
permission to file for term-differentiated rates without undertaking 
further generic review and definition of the proper principles to guide 
the filings. Process Gas Consumers state that the Commission's 
regulations preclude pipelines from differentiating among shippers 
based upon contract term. Process Gas Consumers quote 18 CFR 
284.7(b)(1) and 284.9(b) which provide that pipelines offering Part 284 
firm and interruptible service must ``provide such service without 
undue discrimination, or preference in the quality of service provided, 
the duration of the service, the categories, prices, or volumes of 
natural gas to be transported, customer classification, or undue 
discrimination or preference of any kind.'' (emphasis added by Process 
Gas Consumers). Process Gas Consumers argue that term-differentiated 
rates would differentiate among shippers taking the same service based 
upon their duration of service, and that this is prohibited by the 
regulations. Further, Process Gas Consumers argue that under the 
current regulations the Commission has not permitted such a rate design 
change \99\ and has failed to explain its reasons for departing from 
the regulations.
---------------------------------------------------------------------------

    \97\ Order No. 637 at 107.
    \98\ Term-differentiated rates would raise the maximum tariff 
rates for some customers, and there should be a decrease in the 
maximum tariff rates for long-term customers.
    \99\ Process Gas Consumers cites ANR Pipeline Co., 82 FERC para. 
61,145 at 61,535 (1998).
---------------------------------------------------------------------------

    The portions of the regulations quoted by Process Gas Consumers do 
not prohibit charging a different rate for contracts of differing 
lengths. Instead, they provide that a pipeline cannot engage in undue 
discrimination in certain areas, including duration of service. Thus, 
if the capacity is available, and the shipper requests service at the 
maximum rate, then the pipeline must provide the service without regard 
to the length of the service requested. Moreover, charging a different 
rate for long-term service than for short-term service does not 
constitute undue discrimination because the different characteristics 
of long-term and short-term service justify rate differentials. As 
explained in Order No. 637, a shorter term contract is riskier for the 
pipeline, and a higher rate would compensate the pipeline for this 
additional risk. A shorter term contract provides greater flexibility 
and less risk to the shipper, and a higher rate would recognize and 
require payment for these benefits.
    Process Gas Consumers argue that the Commission should reverse its 
decision and initiate further generic proceedings to provide guidance 
as to the proper boundaries for term-differentiated rates. Process Gas 
Consumers argue that the Commission's decision to shift the evolution 
of term-differentiated rates to individual pipeline cases does not 
constitute reasoned decisionmaking or a fair procedural setting for 
this evolution. Process Gas Consumers argue that while the Commission 
can set policy in individual cases, it may not encourage a departure 
from its current regulations without guidance or further regulatory 
action. Industrial argue that the Commission's decision to proceed in 
this fashion fails to protect consumers from the unjust and 
unreasonable rates and discriminatory behavior that Order No. 637's 
encouragement of term-differentiated rates invites.
    As explained above, the Commission does not accept the premise of 
Process Gas Consumers' argument, i.e., that term differentiated rates 
are unjust, unreasonable, and discriminatory. Moreover, as Process Gas 
Consumers recognize, the Commission can develop policy in adjudications 
as well as in rulemakings. As the Commission explained, there are a 
number of methods that could be used to develop reasonable term-
differentiated rates, and some methods might be more appropriate on 
certain pipelines than on others. In these circumstances, it is 
preferable to allow the pipelines and the customers to work out the 
details of the methodologies in specific rate proceedings, rather than 
to try to discuss and analyze all of the possibilities in a generic 
proceeding. However, this does not mean that there are no parameters or 
standards that a proposal must meet, or that individual adjudications 
will not protect consumers from unjust and unreasonable rates and 
discriminatory behavior. All methods for developing term-differentiated 
rates must meet the NGA requirements that rates must be just and 
reasonable and not unduly discriminatory. These standards can more 
easily be applied to specific

[[Page 35727]]

pipeline proposals in a section 4 proceeding than to theoretical 
generic principles.
    Further, Process Gas Consumers argue, without guidance in a generic 
proceeding, the Commission risks substantial harm to the development of 
dynamic markets that depend on short-term transactions. Process Gas 
Consumers provides a list of types of proposals that should be 
prohibited by the Commission, e.g., proposals that would allow 
pipelines to exercise market power over short-term market participants, 
proposals for ``outrageously high'' one-day rates. However, the 
Commission will assure in the individual section 4 proceedings that the 
specific proposal will not have adverse market consequences and that 
the rates proposed are not unreasonable. Process Gas Consumers have 
provided no reason why shippers cannot be protected and just and 
reasonable rates developed in individual section 4 proceedings.
    INGAA, CNG, Coastal Companies, Kinder Morgan, and Koch argue that 
the Commission should not require pipelines to file a general section 4 
rate case to implement term-differentiated rates. They argue that the 
procedures established by the Commission for implementing peak/off-peak 
rates are also appropriate here. They argue that the requirement of a 
full section 4 proceeding will make term-differentiated rates less 
attractive to pipelines and the option may go unused.
    The Commission has attempted to balance the desire for expeditious 
implementation of the voluntary rate options with the need to assure 
that the statutory standards are met. While the Commission has 
concluded that a limited section 4 proceeding can accommodate both 
considerations in the implementation of peak/off-peak rates, the 
Commission has concluded for the reasons set forth in Order No. 637, 
that term-differentiated rates must be proposed in a section 4 
proceeding. This does not necessarily mean that the proceeding must be 
lengthy and time-consuming or involve a full evidentiary hearing, and 
the parties may use that forum to develop a mutually agreeable method 
of implementing term-differentiated rates. Properly designing term-
differentiated rates could be very complicated and would affect all the 
pipeline's rates to ensure that rates stay within the pipeline's 
revenue requirement. This cannot be done in a limited section 4 
proceeding. The Commission does not intend to discourage pipelines from 
proposing term-differentiated rates, but has determined that a section 
4 proceeding is necessary.
    Amoco argues that the Commission erred in failing to limit a 
pipeline's rate flexibility options to either seasonal rates or term-
differentiated rates, but not both in the short-term market. Amoco 
argues that pipelines should not be permitted to superimpose term-
differentiated rates on seasonal rates, such that the maximum short-
term rate would exceed the expected seasonal market value, else the 
result would be to effectuate market-based rates without a showing of a 
lack of market power. Amoco argues that this would eliminate the 
primary market mitigation mechanism relied on by the Commission in 
permitting market-based capacity release rates, i.e., that just and 
reasonable cost-based pipeline rates will serve as a good alternative 
to unregulated capacity release rates.
    Further, Amoco argues that term-differentiated rates are intended 
to adjust rates on the basis of demonstrable term risk, and this 
rationale does not apply in the short-term market where implementation 
of seasonal rates will allow pipelines to structure their rates to 
capture seasonal value differences within a cost of service framework. 
Amoco argues that there should be an absolute prohibition against term-
differentiated rates for short-term contracts.
    As the Commission acknowledged in Order No. 637, the use of term-
differentiated rates for short-term services may enhance the potential 
for price discrimination, particularly during off-peak periods, by 
increasing the rate caps that would apply to short-term service 
acquired in off-peak periods. The Commission made clear that these 
proposals will be carefully scrutinized, and a pipeline proposing term-
differentiated rates for short-term services will need to explain fully 
the basis and justification for the price differentials. If the 
pipeline chooses to implement both peak rates and term-differentiated 
rates, the proposal will be implemented in a full section 4 proceeding 
and the Commission and the parties will be able to address the impacts 
of the proposal. The Commission will not preclude a pipelines from 
proposing both rate methodologies.
    Amoco also states that the Commission should clarify that term-
differentiated rates should be designed only within rate of return 
``zone of reasonableness'' parameters to reflect the differential risk 
associated with varying contract durations. For example, Amoco states 
that if a ROE zone of reasonableness ranges from 10% to 14%, a longer 
term contract of 10 years or longer would have a 10% ROE imputed and a 
short term contract of one year would have a 14% ROE imputed. 
Otherwise, Amoco argues, pipelines can use their market power to coerce 
captive customers into purchasing capacity either at excessive rates or 
for excessive terms. Amoco's suggestion may be one reasonable method of 
designing term-differentiated rates which can be considered in the 
individual proceedings, but the Commission will not limit the parties 
to this one method. Pipelines and their customers may devise other 
methods that protect shippers from unreasonable rates or contract 
terms.
    Amoco is also concerned about affiliate abuse which it says is 
increased in the term-differentiated rate structure. Amoco states that 
there must be limitations on the imputed contract term available for an 
affiliate. The Commission will not establish a limit on the contract 
term available for affiliates, but this is an issue that the parties 
may address in a section 4 proceeding.
    Keyspan asks the Commission to clarify that pipelines that are 
subject to Commission-approved settlements that prohibit increases to 
rates for seasonal services for some period are not entitled to 
increase those seasonal rates until the specified period in the 
settlement expires, and that pipelines cannot implement term-
differentiated rates during rate moratorium period. INGAA asks the 
Commission to clarify that nothing in Order No. 637 affects the ability 
of pipelines and their customers to negotiate term-differentiated rates 
that do not interfere with existing settlements. The Commission cannot 
rule on specific settlement provisions, but the Commission clarifies 
that parties continue to be bound by their settlements, and nothing in 
Order No. 637 changes existing settlements. Further, nothing in this 
rule limits the parties' ability to negotiate future settlements.
    Keyspan also asks the Commission to clarify that any term-
differentiated rates proposed by the pipelines must differentiate on 
the basis of the contract term regardless of the remaining life of the 
contract, i.e., if a pipeline has different rates for contracts of ten, 
five, and three years, a customer with three years remaining on a ten-
year contract should be charged the ten-year rate for the remaining 
three years. The Commission clarifies that its intent was to have a 
long-term rate apply to a long-term contract for the duration of that 
contract, and not to have that contract charged a shorter-term rate in 
the later years of the contract.

[[Page 35728]]

D. Voluntary Auctions

    Recognizing the increasing use of electronic commerce to create 
efficient markets, the Commission in Order No. 637 encouraged both 
pipelines and third parties to develop capacity auctions, and provided 
basic principles for the design of transparent, verifiable, and non-
discriminatory auctions. The Commission also indicated that an 
appropriately designed auction may be a means by which a pipeline could 
sell all or some of its capacity without a price cap so long as the 
auction was designed in such a way as to protect against the pipeline's 
ability to withhold capacity and exercise market power. The Commission 
set out some general criteria for accomplishing these goals, one of 
which was a statement that all capacity available at the time of the 
auction would have to be included in the auction.
    Koch requests clarification that a pipeline can engage in limited 
auctions without a price ceiling by auctioning only capacity between 
select points in the auctions. Koch claims that such an auction would 
prevent the exercise of market power because the pipeline would be 
unable to withhold any capacity between the designated points.
    While the Commission would have to examine any such auction 
proposal in detail before it could determine whether it would 
adequately protect against the exercise of market power, Koch's 
proposal for selective auctions does not appear sufficient. Under 
Koch's proposal, the pipeline could select only capacity between 
certain points to include in the auction at a particular time, while 
reserving the right to sell capacity between those points outside the 
auction process at other times as well as to sell capacity between 
other points outside of the auction process. In a fair auction process, 
the pipeline should not be able to choose the auction format only for 
those markets or at those times where it could benefit, while reserving 
its right to selectively discount at other times or for other markets.
    Process Gas Consumers contends the Commission should not permit 
market-based rates through auctions, or at least should provide 
detailed guidance in advance about the showing the seller of capacity 
must make to justify the lifting of price caps. They further seek 
clarification concerning the process to be used by a pipeline to 
propose an auction, particularly about the rights of shippers to 
participate in that process, clarification that auctions can only take 
place upon reasonable notice and during normal business hours, and 
clarification that combined gas and capacity auctions by third parties 
would be subject to Commission regulation.
    Auctions can be methods by which pipelines can sell capacity 
without a rate ceiling if the auction format adequately protects 
against the exercise of market power by preventing withholding of 
available capacity and price discrimination. There may be many 
different ways of achieving this result, and the Commission cannot 
specify in advance all the necessary criteria. Given the Commission's 
and the industry's lack of experience with auctions, it is important to 
encourage innovation in auction design, rather than having the 
Commission insist on a design that may not be the most effective or 
efficient. One of the Commission's principles for a fair auction design 
is that such an auction must be open to all potential bidders on a non-
discriminatory basis, which would include notice of when the auctions 
will take place. But the Commission will not generically require that 
all auctions take place during normal business hours, as requested by 
Process Gas Consumers. Given the intra-day nomination schedule adopted 
by the Commission, some auction designs may want to include after hour 
auctions. Questions concerning the timing of auctions must be evaluated 
in individual applications.
    Pipelines contemplating proposing auctions would be well advised to 
review their plans with their customers as a way of resolving potential 
problems and creating a more efficient design prior to filing the 
proposal with the Commission. Shippers, of course will have to the 
right to fully participate in any auction proceeding initiated by a 
pipeline filing.
    The Commission has authority to regulate the reallocation by 
shippers of transportation capacity.\100\ Depending on how an auction 
is organized, and whether waiver of Commission regulatory requirements 
is requested, Commission regulatory oversight may or may not be 
necessary. Third-parties currently can auction released capacity 
without regulatory oversight by the Commission as long as the results 
of those auctions comply with the Commission's capacity release 
regulations, particularly the requirement for posting and bidding on 
Internet sites authorized by pipelines. In these cases, the third-party 
auctions are merely ways for shippers to enter into pre-arranged 
releases of capacity.\101\ As long as those pre-arranged releases 
comply with Commission requirements, i.e., are transmitted to the 
pipeline for posting on pipeline Internet sites and bidding (when 
necessary) is allowed, no further oversight is needed.\102\
---------------------------------------------------------------------------

    \100\ United Distribution Cos. v. FERC, 88 F.3d 1105, 1151-54 
(D.C. Cir. 1996).
    \101\ Pipelines can, and have, used third-parties to satisfy the 
posting and bidding obligations for their systems. Third-parties, in 
this context, refer to parties conducting auctions not under the 
auspices of the pipeline.
    \102\ For example, third-party auctions for short-term released 
capacity (31 days or less) can be conducted without complying with 
the requirements for posting and bidding on pipeline Internet sites, 
because short-term releases are exempt from the Commission's posting 
and bidding requirements.
---------------------------------------------------------------------------

    Some third parties indicated in their comments that compliance with 
some of the Commission's existing regulations can impede the 
development of third-party auctions. For instance, the requirement that 
certain transactions must be posted on pipeline Internet sites was 
identified as a barrier to third-party auctions because it would 
require a double posting of capacity (once in the auction and once on 
the pipeline's Internet site) and would render the results of the 
auction less certain. In those cases in which a shipper or third-party 
finds that a current Commission regulatory requirement impedes the 
development of an efficient auction, the Commission encourages shippers 
or third-parties to propose an alternate method for satisfying the goal 
of the requirement. For example, to satisfy the requirement that prices 
be disclosed on a pipeline's Internet web site, the pipeline could be 
required to maintain a link on its web site to the web site of the 
third-party auctioneer. The Commission cannot proscribe, in the 
abstract, criteria for such proposals. Third-parties should have the 
freedom to develop and propose innovative solutions to such problems.

II. Improvements to Competition Across the Pipeline Grid

A. Scheduling Equality

    In Order No. 637, the Commission adopted the proposal set forth in 
the NOPR to amend the Commission's regulations to include a new section 
284.12(c)(1)(ii) to require pipelines to provide purchasers of released 
capacity the same ability to submit a nomination at the first available 
opportunity after consummation of the deal as shippers purchasing 
capacity from the pipeline. This will enable shippers to acquire 
released capacity at any of the nomination or intra-day nomination 
times, and nominate gas coincident with their acquisition of capacity. 
By enabling released capacity to compete on a comparable basis with 
pipeline capacity, the new section of the

[[Page 35729]]

regulations will foster a more competitive short-term market. Also, in 
Order No. 637, the Commission explained the basis for its policy that 
the shipper must have title to the gas being transported, and concluded 
that no changes in this policy are appropriate at this time. Niagara 
Mohawk, NGSA, Scana Energy Marketing, Tejas, TWC, and Williston seek 
clarification or rehearing of this portion of Order No. 637.
    Williston seeks rehearing of the Commission's regulation requiring 
nominations for capacity release transactions to be on an equal footing 
with shippers purchasing capacity directly from the pipeline. Williston 
argues that there must be differences in the nomination and scheduling 
of capacity release and the nomination and scheduling of pipeline 
capacity because additional time is required to evaluate capacity 
release transactions due to possible conditions the releasing shipper 
may impose on the acquiring shipper. Williston states that the time 
required by the pipeline to evaluate such conditions and the potential 
operational impact requires that the existing timing difference in the 
nomination and scheduling process.
    Williston does not explain what conditions and operational 
considerations could need to be evaluated. The replacement shipper will 
take the service under the same contract, subject to the same 
conditions as the releasing shipper and, therefore, will have the same 
operational impact on the system. There should be no change in 
conditions or impact for the pipeline to evaluate.
    In addition, Williston asserts that the provision of such a service 
will not be cost effective on its system because Williston would be 
required to expend significant money and manhours on new electronic 
contracting software. Williston states that it has had 13 capacity 
releases in the last three years, and this number of releases does not 
justify the Commission's imposition of this requirement on Williston. 
Williston argues that the offering of nomination opportunities for 
capacity release equal to nomination opportunities for shippers 
purchasing capacity should be on a best efforts or optional basis on 
pipelines with significant capacity release.
    As explained in Order No. 637, the Commission adopted the new 
regulation requiring equality in scheduling in order to enable released 
capacity to compete on a comparable basis with pipeline capacity. This 
furthers the Commission's goal of enhancing competition and improving 
efficiency across the grid. In order for the requirement to have this 
effect it must apply to all pipelines and all capacity release 
transactions.
    Scana seeks clarification, or in the alternative, rehearing, that 
the pipelines must provide replacement shippers with the same no-notice 
scheduling rights as held by releasing shippers. Scana asserts that 
some pipelines have placed restrictions in their tariffs on the release 
of no-notice transportation, such that a shipper may release no-notice 
transportation, but the replacement shipper receives FT capacity 
without no-notice scheduling rights. Scana further asserts that other 
pipelines do not restrict release of no-notice service, but instead 
impose artificial restrictions on the scheduling flexibility after 
release. Scana argues that, consistent with the Commission's purpose of 
achieving scheduling equality between releasing and replacement 
shippers, the Commission must clarify that Order No. 637's mandate for 
scheduling equality among releasing and replacement shippers is 
intended to cover no-notice scheduling rights and contingency ranking.
    The Commission has held that the pipeline must permit shippers to 
release their no-notice service as no-notice service.\103\ Further, if 
the pipeline permits shippers to receive no-notice service at flexible 
delivery points, it must permit the no-notice shipper to release that 
capacity with similar flexible delivery points.\104\ However, if the 
pipeline does not permit its no-notice shippers flexible delivery point 
rights, it is not required to provide flexible delivery points to the 
replacement shipper. There should be no operational reason why the 
pipeline should limit the release of no-notice service or place 
restrictions on the released service that do not apply to the releasing 
shipper. Since the shipper releasing the no-notice capacity is not able 
to use it, the pipeline will not be providing any more no-notice 
service than it contracted to provide.
---------------------------------------------------------------------------

    \103\ Order No. 636-B, 61 FERC para. 61,272 at 62,009-10 (1992); 
Questar Pipeline Co., 62 FERC para. 61,192 at 62,298 (1993).
    \104\ Editor's Note: No text in footnote 104.
---------------------------------------------------------------------------

    TWC and Tejas ask the Commission to clarify the relationship 
between new section 284.12(c)(1)(ii) and the approved GISB Standards, 
including the GISB Standard timelines for capacity release as set forth 
in GISB Standard 5.3.2. The Commission clarifies that new section 
284.12(c)(1)(ii) supplants GISB Standard 5.3.2, to the extent that they 
are inconsistent. Thus, the capacity release nomination requirements 
are contained in the new regulation, and GISB Standard 5.3.2 now 
applies only to the bidding process. It is not necessary for the 
Commission to delay implementation of its new nomination requirements 
until GISB acts to amend section 5.3.2.
    Tejas quotes the discussion in Order No. 637 as providing that 
under new regulation Sec. 284.12(c)(1)(ii), the pipeline must 
``approve'' a contract within an hour. Tejas asks the Commission to 
clarify whether the Commission means ``issuance'' or ``approval,'' and 
whether issuance or approval of the contract means that it has been 
executed by both parties.
    The text of the regulation states that the pipeline must ``issue'' 
the contract within an hour and the Commission clarifies that the 
requirement is to issue the contract, rather than approve the contract. 
Issuance of the contract does not mean that it has been executed by 
both parties.
    Tejas also observes that GISB Standard 5.3.2 defines short-term 
releases as those with a duration of less than 5 months, and in Order 
No. 637, the Commission defines short-term releases as those extending 
for less than one year. Tejas asks the Commission to clarify which of 
the two definitions will apply to short-term releases.
    The bidding requirements of GISB Standard 5.3.2 apply to capacity 
releases of more than five months. In Order No. 637, the Commission 
waived, for a two year period, the rate ceiling for capacity releases 
of less than one year. Neither of these provisions defines a short-term 
release for other purposes, and they are not inconsistent.
    NGSA states that although the Commission established scheduling 
equality between capacity release shippers and others holding firm 
capacity, and recognized the efficacy of master agreements in achieving 
scheduling equality, it did not require use of a master agreement. NGSA 
asserts that master agreements are the only means to achieve scheduling 
equality, and therefore the Commission should require them.
    The Commission recognizes that master agreements are a good way to 
achieve scheduling equality, but as explained in Order No. 637, there 
are other methods as well. The Commission will not mandate any one 
method, but will leave this to be resolved by the pipelines and 
shippers.
    Finally, Niagara Mohawk requests that the Commission clarify that 
it will be receptive to requests for waiver of the shipper must have 
title policy where the applicant demonstrates that the waiver

[[Page 35730]]

will not result in undue discrimination or the inefficient allocation 
of capacity. Parties may apply for a waiver of the policy and, as in 
the past, the Commission will consider the waiver based on the specific 
circumstances of the request.\105\
---------------------------------------------------------------------------

    \105\ See, e.g., Baltimore Gas and Electric Co., 88 FERC para. 
61,133, reh'g denied, 89 FERC para. 61,150 (1999).
---------------------------------------------------------------------------

B. Segmentation and Flexible Point Rights

    In Order No. 636, the Commission established two related policies--
flexible point rights and segmentation--that were designed to provide 
firm shippers with the flexibility to use their capacity and to enhance 
competition between shippers and between shippers and the 
pipeline.\106\ Flexible point rights refer to the rights of firm 
shippers to change receipt or delivery points so they can receive and 
deliver gas to any point within the firm capacity rights for which they 
pay. Segmentation refers to the ability of firm capacity holders to 
subdivide their capacity into segments and to use the segments for 
different capacity transactions.
---------------------------------------------------------------------------

    \106\ 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 30,428, 30,420-21 (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 30,559 n.151 (Aug. 
3, 1992), Order No. 636-B, 61 FERC para. 61,272, at 61,997 (1992).
---------------------------------------------------------------------------

    The requirement to permit segmentation originally was not included 
in the Commission's regulations, but was implemented through pipeline 
restructuring filings. The Commission found that capacity segmentation 
was not being implemented uniformly across the pipeline grid. Some 
pipelines did not permit segmentation at all, others placed 
restrictions on the ability to segment for release, and others did not 
permit shippers to segment capacity for their own use.
    In Order No. 637, the Commission responded to the inconsistent 
application of segmentation rights by adopting a regulation requiring 
pipelines to permit a shipper ``to make use of the firm capacity for 
which it has contracted by segmenting that capacity into separate parts 
for its own use or for the purpose of releasing that capacity to 
replacement shippers to the extent such segmentation is operationally 
feasible.'' \107\ Each pipeline is required to make a pro forma tariff 
filing demonstrating how it intends to comply with the regulation, by 
revising its tariff, explaining why its existing tariff meets the 
requirements, or explaining why the operational configuration of its 
system does not permit segmentation.
---------------------------------------------------------------------------

    \107\ Order No. 637, 65 FR at 10195, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,303-304; 18 CFR 284.7(e).
---------------------------------------------------------------------------

    In Order No. 637, the Commission also concluded that no regulatory 
changes were needed to be made with respect to the relative scheduling 
priorities of shippers using secondary points depending on whether they 
were shipping within or outside their capacity path.\108\
---------------------------------------------------------------------------

    \108\ Order No. 637, 65 FR at 10196, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,304.
---------------------------------------------------------------------------

    Rehearing and clarification requests were filed with respect to 
both the segmentation and path priority determinations.
1. Segmentation
    Rehearing and clarification requests were received regarding the 
adoption of the segmentation regulation and the requirements of the 
regulation. In addition, rehearing and clarification requests were 
filed concerning the extent to which earlier Commission policies will 
apply to segmented releases and the manner in which pipelines are to 
implement the requirement. These are discussed below.
    a. Adoption and Requirements of the Regulation. Legal 
Justification. Koch maintains the Commission's generic segmentation 
policy violates sections 4 and 5 of the NGA. It contends the 
requirement violates section 5, because the Commission has not found 
that an existing tariff provision is unlawful and that the Commission-
imposed modification of the tariff is just and reasonable. Koch 
maintains the Commission's action in requiring a pipeline compliance 
filing is not justifiable under section 4 of the NGA, because Koch has 
not voluntarily submitted a proposed tariff change and the Commission 
cannot under section 4 place the burden on the pipeline of justifying 
that segmentation is inappropriate.
    The Commission's action is an appropriate use of its authority 
under section 5 of the NGA. In Order No. 637, the Commission made a 
generic determination that the failure of a pipeline to permit 
segmentation would be unjust and unreasonable if the pipeline could 
operationally permit segmentation.\109\ Under Order No. 636, the firm 
transportation capacity held by shippers was to include the same 
flexibility the pipeline enjoyed when it provided bundled sales 
service, and the ability to use capacity flexibly, through the use of 
flexible point rights and segmentation, was part of the flexibility 
enjoyed by pipelines. Further, as the Commission found in Order No. 
637, segmentation increases the number of capacity alternatives and so 
improves competition, and also is important in facilitating the 
development of market centers and liquid gas trading points.\110\ Based 
on these findings, the Commission determined that pipelines that 
operationally can permit segmentation, but do not, would be acting in 
an unjust and unreasonable manner.
---------------------------------------------------------------------------

    \109\ Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166-67 (D.C. 
Cir. 1985) (Commission can make generalized determinations that 
particular practices are unjust and unreasonable through 
rulemaking).
    \110\ Order No. 637, 65 FR at 10195, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,303-304.
---------------------------------------------------------------------------

    While Order No. 637 announced the Commission's segmentation policy, 
it did not make a section 5 determination that any particular 
pipeline's tariff is, in fact, unjust and unreasonable. Any such 
determination will be made in the individual pipeline compliance 
proceedings. The Commission had reason to believe, based on the 
comments and its own analysis of pipeline tariffs, that some pipelines 
are not permitting shippers to segment capacity, both for the shipper's 
own use and for capacity release transactions, to the extent 
operationally feasible on their systems. The Commission, therefore, 
required pipelines to make pro forma filings to establish whether their 
current tariffs are just and reasonable. The requirement for pipelines 
to make pro forma compliance filings is not, as Koch characterizes it, 
a requirement that pipelines make a section 4 filing. Rather, the pro 
forma filings require the pipelines to show why their existing tariffs 
should not be considered unjust and unreasonable. If the Commission 
finds changes are warranted, it will be acting under section 5 to 
implement such changes.
    Non-Operational Barriers to Segmentation. CNG and Columbia Gas 
contend the inquiry into segmentation should not be limited to whether 
segmentation is ``operationally feasible,'' because non-operational 
problems, such as rate design, administrative complexity, or potential 
legal barriers can inhibit the ability of a pipeline to offer 
segmentation. They maintain that such problems can be particularly 
difficult for reticulated pipelines where shipper paths are not easily 
defined. CNG contends that such changes can be made only through a full 
section 4 rate filing that would include the identification of multiple 
paths, a redesign of services, and an elimination

[[Page 35731]]

of postage stamp (one rate for the entire system) rate structures.
    The Commission will not eliminate the ``operationally feasible'' 
requirement from the regulation. The goal in permitting shippers to 
segment capacity is to enable firm shippers to use the capacity for 
which they have contracted as flexibly as possible without infringing 
on the legitimate rights of other shippers. In the case of a 
reticulated pipeline charging a postage stamp rate, firm shippers are 
paying for the use of the entire pipeline in their rates. The pipeline, 
therefore, has the obligation to optimize the system so that firm 
shippers can make the most effective use of the capacity for which they 
pay. On reticulated pipelines with postage stamp rate structures, where 
shippers have no specifically defined paths, the pipeline should permit 
firm shippers to use all points on the system and to use or release 
segments of capacity between any two points, while continuing to use 
other segments of capacity.
    The Commission recognizes that permitting segmentation on a 
reticulated pipeline can result in operational difficulties if 
replacement shippers flow gas at different points than the existing 
shippers. But that is not a reason for the pipeline to refuse to 
provide the ability to segment. Instead, the pipeline needs to optimize 
its system to provide maximum segmentation rights while devising 
appropriate mechanisms to ensure operational stability. Displacement 
pipelines with postage stamp rate structures have been able to permit 
segmentation with operational rules to protect system integrity.\111\
---------------------------------------------------------------------------

    \111\ See Northwest Pipeline Corporation, 69 FERC para. 61,171, 
at 61,677 (1994), 71 FERC para. 61,315, at 61,224 (1995) (providing 
operational controls for segmented releases that jeopardize system 
integrity).
---------------------------------------------------------------------------

    On reticulated systems with zone rates, segmentation can be limited 
to the zones for which the shipper pays. If a pipeline currently using 
a postage stamp rate structure finds that providing segmentation or 
defining capacity paths would be more feasible with a redesign of its 
rates, the pipeline can make a section 4 filing to establish rates that 
it considers more consonant with segmentation.
    b. Compliance Filings and Implementation. Overlapping capacity 
segments. Coastal, INGAA, Kinder Morgan, and Williston request 
clarification that the Commission will adhere to its current policy of 
not permitting shippers to use segmentation to release overlapping 
capacity segments.\112\ National Fuel Distribution also seeks 
clarification that shippers can segment capacity at market centers or 
other non-physical transaction points on the pipeline's system.
---------------------------------------------------------------------------

    \112\ Citing Tennessee Gas Pipeline Company, 85 FERC para. 
61,052 (1998), reh'g denied, 86 FERC para. 61,290 (1999); Texas Gas 
Transmission Corporation, 89 FERC para. 61,096 (1999).
---------------------------------------------------------------------------

    Capacity segmentation refers to the ability of shippers to divide 
their capacity into individual segments with each segment equal to the 
contract demand of the original contract. As a general matter, 
pipelines are not required to permit segmentation in a situation where 
the nominations by a shipper or a combination of releasing and 
replacement shippers exceed the contract demand of the underlying 
contract on any segment. The Commission further clarifies, as National 
Fuel Distribution requests, that shippers can divide their capacity 
through segmented releases at any transaction points on the pipeline 
system, including virtual transaction points, such as paper pooling 
points, as well as at physical interconnect points, such as market 
centers.
    To help avoid inconsistent application of the Commission's flexible 
receipt and delivery point policy and the segmentation policy, the 
following example will provide clarification as to how those policies 
should operate. In this example, a shipper has a contract for 10,000 
Dth per day from receipt point at A to delivery point B.
[GRAPHIC] [TIFF OMITTED] TR05JN00.002

    The shipper has the flexibility to segment capacity throughout 
zones 1-3 (point M through point S), so long as the combined 
nominations of it and replacement shippers do not exceed the mainline 
contract demand of 10,000 Dth. The shipper has the right to segment 
outside of its path because it is paying the full rates for zones 1-3 
and, therefore, has the right to use all points within the zones for 
which it pays. Thus, the shipper could nominate and ship 10,000 Dth 
from point M to point P, while at the same time nominate and ship 
another 10,000 Dth from point P to point S. But the shipper could not 
nominate 10,000 Dth from point M to point Q and nominate 10,000 Dth 
from point P to point S, because that would result in 20,000 Dth 
nominated in segment P-Q.
    The shipper also could release 10,000 Dth of capacity from point P 
to point B, while retaining 10,000 Dth of capacity from point A to 
point P for its own use. The releasing shipper could then nominate and 
ship 10,000 Dth from point A to point P, while the replacement shipper 
could nominate and ship 10,000 Dth from point P to point B.
    Segmentation would also permit the releasing and replacement 
shippers to use overlapping segments so long as their combined 
nominations in a segment do not exceed 10,000 Dth. For instance, the 
releasing shipper could nominate and ship 5,000 Dth from point A to 
point Q, while the replacement

[[Page 35732]]

shipper nominates and ships 5,000 Dth from point O to point B even 
though the segments overlap in segment O-Q. Both nominations would be 
accepted because the combined nomination over segment O-Q would not 
exceed 10,000 Dth. However, if both shippers sought to nominate the 
full 10,000 Dth in one or more pipeline segments, the pipeline could 
limit the nominations to 10,000 Dth in those segments. The pipeline 
should have a default tariff provision detailing how nominations from 
releasing and replacement shippers will be handled in the event that 
they exceed the contract demand, and releasing shippers also can 
include provisions for handling overlapping nominations in their 
release conditions.\113\
---------------------------------------------------------------------------

    \113\ See Texas Gas Transmission Corporation, 89 FERC para. 
61,096, at 61,274 (1999).
---------------------------------------------------------------------------

    Both the releasing and replacement shippers also would retain the 
flexibility to use their capacity fully to make backhauls. Thus, the 
shipper could deliver 10,000 Dth from point A to point B using forward 
haul capacity and 10,000 Dth from point S to point B using a backhaul, 
because there is no overlap over the mainline.
    This may require a change by some pipelines with respect to their 
tariffs regarding backhauls. The Commission's policy on the use of 
forwardhauls and backhauls to the same point in excess of contract 
demand has been in the process of change. While the Commission found in 
1997 that a shipper cannot use the same delivery point for a 
forwardhaul and backhaul in excess of contract demand,\114\ the 
Commission recently found that a forwardhaul and backhaul to a series 
of 23 meter stations considered as a single point for nomination 
purposes did not result in a capacity overlap even though the total 
amount received by the shipper exceeded contract demand.\115\ In order 
to promote shippers' ability to use their capacity as flexibly as 
possible, the Commission has determined that prior restrictions on 
shippers' use of forwardhauls and backhauls to the same point should 
not be followed. Shippers' segmentation rights should not depend upon 
metaphysical distinctions between delivery to a single point or to two 
points adjacent to each other. In both situations, shippers should be 
permitted to use a forwardhaul and a backhaul to deliver gas as long as 
the mainline contract demand is not exceeded and they can take delivery 
of the gas.
---------------------------------------------------------------------------

    \114\ Iroquois Gas Transmission System, L.P., 78 FERC para. 
61,135 (1997) (shipper cannot use same delivery point for 
forwardhaul and backhaul in excess of contract demand).
    \115\ Transcontinental Gas Pipe Line Corporation, 91 FERC para. 
61,031 (2000) (using forwardhaul and backhaul to series of delivery 
points does not result in an overlap).
---------------------------------------------------------------------------

    Segmentation and primary point rights. Several rehearing requests 
relate to the relation between segmentation and primary point rights. 
El Paso and Enron maintain segmentation should be considered separately 
from primary point rights and should not result in shippers being able 
to use segmentation to increase primary point rights beyond those 
covered in their contracts. Kinder Morgan claims that if shippers 
change their primary point rights in segmenting capacity for their own 
use, the shippers do not have the right to revert to their original 
primary points without the consent of the pipeline. Kinder Morgan and 
INGAA seek clarification that pipelines can resell capacity at primary 
points vacated by releasing or replacement shippers. In contrast, 
National Fuel Distribution maintains that shippers should be permitted 
to segment capacity and retain their primary priority in both segments.
    The Commission cannot clarify the role of primary receipt points on 
a generic basis, but will need to examine the issues raised in the 
pipelines' compliance filings. In Order No. 637, the Commission 
explained that in the past it had adopted different policies on the 
issue of whether pipelines could restrict replacement shippers' ability 
to choose new primary points depending on whether pipelines had 
historic tariff provisions that limited primary point rights to the 
same level as the shipper's mainline contract demand.\116\ Although the 
Commission accepted tariff filings during Order No. 636 that continued 
historic limitations on the number of primary receipt and delivery 
points, the Commission questioned whether it continued to be 
appropriate for pipelines to limit receipt and delivery point 
quantities to the shipper's contract demand.\117\ The Commission 
concluded that a pipeline's overly restrictive allocation of primary 
point rights to existing shippers could restrict the ability of 
shippers to use their capacity flexibly. But the Commission did not 
impose a blanket prohibition on all limits to a firm shipper's ability 
to choose primary receipt and delivery points. The Commission 
recognized that pipelines might need to impose some restrictions on 
primary point rights, as appropriate to the circumstances of their 
systems, to prevent hoarding of capacity by some shippers to the 
detriment of others.\118\ Moreover, even when the Commission did permit 
continuation of tariff provisions that limited primary point rights to 
contract demand, the Commission adopted a policy (Texas Eastern/El Paso 
policy) which permitted both releasing and replacement shippers in 
segmented releases to choose separate primary point rights that did not 
exceed each shipper's contract demand.\119\
---------------------------------------------------------------------------

    \116\ Order No. 637, 65 FR at 10194, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,301-302. Compare 
Transwestern Pipeline Company, 62 FERC para. 61,090, at 61,659, 63 
FERC para. 61,138, at 61,911-12 (1993); El Paso Natural Gas Company, 
62 FERC para. 61,311, at 62,982-83 (1993) (permitting pipelines to 
continue historic limitations on primary receipt point rights) with 
Northwest Pipeline Corporation, 63 FERC para. 61,124, at 61,806-08 
(1993) (not permitting the pipeline to add such restrictions).
    \117\ El Paso Natural Gas Company, 62 FERC para. 61,311, at 
62,982-83 (1993); Transwestern Pipeline Company, 62 FERC para. 
61,090, at 61,659, 63 FERC para. 61,138, at 61,911-12 (1993).
    \118\ See El Paso Natural Gas Company, 62 FERC para. 61,311, at 
62,982-83 (1993) (pipelines could propose methods for limiting the 
potential for hoarding).
    \119\ Order No. 637, 65 FR at 10194, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,301-302; Texas Eastern 
Transmission Corporation, 63 FERC para. 61,100, at 61,452 (1993); El 
Paso Natural Gas Company, 62 FERC para. 61,311, at 62,991. See also 
Transwestern Pipeline Company, 61 FERC para. 61,332, at 62,232 
(1992).
---------------------------------------------------------------------------

    Permitting flexibility in the selection of primary points in 
segmented releases can be important to creating effective competition 
between pipeline services and released capacity. If replacement 
shippers were limited to the use of segmented points on a secondary 
basis, as some of the rehearing requests suggest, the pipeline would 
still retain the right to sell that receipt point on a primary basis. 
The ability to sell points on a primary basis would provide the 
pipeline with a competitive advantage over segmented release 
transactions. In order to equalize competition between pipeline and 
released capacity, pipelines need to permit shippers greater 
flexibility in selecting primary points than they have in the past.
    Because the Commission has not reviewed receipt and delivery point 
restrictions since Order No. 636 and restrictions on segmentation and 
point rights can limit effective competition, pipelines should not be 
able to continue to rely upon their historic tariff practices dating 
back to the days of merchant service, but need to justify restrictions 
on shippers' ability to use additional primary points in segmented 
transactions and any deviation from the Texas Eastern/El Paso 
policy.\120\ For example, on a fully subscribed pipeline where receipt 
point capacity exceeds mainline capacity fivefold, the pipeline can 
seemingly permit shippers to select primary receipt point rights well 
in excess of their mainline contract

[[Page 35733]]

demand, since the pipeline has no capacity left to sell and, therefore, 
needs to reserve no receipt point capacity in order to sell 
unsubscribed capacity.\121\
---------------------------------------------------------------------------

    \120\ Order No. 637, 65 FR at 10195-96, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,304.
    \121\ Even if the pipeline is not fully subscribed, it could 
protect its ability to sell available mainline capacity by reserving 
an appropriate percentage of the receipt or delivery point capacity 
to be associated with the unsubscribed mainline capacity.
---------------------------------------------------------------------------

    El Paso contends that providing shippers with the right to select 
multiple delivery point rights along a path could detrimentally affect 
the rights of existing shippers. It provides an example in which a 
lateral off the mainline can support only 100 Dth of capacity and a 
shipper at the terminus of the lateral (Delivery Point B) already has 
primary point capacity of 100 Dth on the lateral. El Paso maintains 
that if another shipper with a primary delivery point (Delivery Point 
A) can subscribe to an upstream point on the lateral (Delivery Point C) 
on a primary basis, the downstream shipper on the lateral could lose 
its primary point priority.
[GRAPHIC] [TIFF OMITTED] TR05JN00.003

    This argument misapprehends Commission policy. The new shipper 
could not obtain a primary delivery point at Delivery Point C, because 
no capacity on the lateral is available at that point; the lateral 
capacity is fully subscribed. In order for shippers to obtain primary 
points, the mainline capacity to that point must be available. Thus, 
the shipper with a primary delivery point at Delivery Point A could 
obtain another primary delivery point at Delivery Point D, because the 
shipper has sufficient mainline capacity to deliver to that point. As 
pointed out previously, the selection of this new delivery point would 
not increase the shipper's mainline contract demand. It would only 
permit the shipper to choose to deliver to Delivery Point A or Delivery 
Point D on a primary basis.
    The resolution of issues relating to the allocation of primary 
point rights in segmented transactions will have to be addressed in 
each pipeline's compliance filing. Pipelines will have to include 
justifications, based on the operational characteristics of their 
systems, for restrictions on the extent to which shippers and 
replacement shippers can change primary points or can revert back to 
the original points at the end of a release or segmented transaction.
    Point discounts. Kinder Morgan and Koch request clarification that 
in implementing segmentation, the Commission will continue its current 
policy under which discounts granted with respect to specific points do 
not apply when the shippers change points. They contend that if a 
shipper seeks to use different points as part of a segmentation 
transaction, the shipper will not be entitled to continue its discount.
    This issue also needs to be considered in the pipelines' compliance 
filings. In the restructuring proceedings to implement Order No. 636, 
the Commission's policy was to permit pipelines to limit a shipper's 
discount to particular receipt and delivery points. A shipper with a 
discount contract to particular points would be subject to the 
pipeline's maximum rate if it, or a replacement shipper, chose to 
exercise its right to use flexible receipt or delivery points.\122\ The 
justification for this policy was that market conditions may vary on a 
pipeline, and the pipeline, therefore, should be permitted to structure 
its discounts to meet the prevailing market conditions.
---------------------------------------------------------------------------

    \122\ El Paso Natural Gas Company, 62 FERC para. 61,311, at 
62,990-91 (1993); ANR Pipeline Company, 62 FERC para. 61,079, at 
61,562-63 (1993).
---------------------------------------------------------------------------

    The Commission still recognizes that pipelines may have 
underutilized segments of their pipelines for which they may need to 
offer discounts in order to increase throughput and that such discounts 
should not necessarily entitle shippers to move gas in more highly 
utilized portions of the pipeline, where the pipeline can obtain the 
maximum rate for transportation service. This would occur particularly 
on pipelines with postage stamp rate systems where the same maximum 
rate applies throughout the system, even though utilization patterns 
may differ across the system, as well as for pipelines with large zones 
where utilization may differ within a zone.\123\ What is less clear, 
however, is whether the Commission's previous policy should continue to 
be applied for segmented transactions that occur within the path of the 
shipper's transportation contract. Once the pipeline has decided that a 
discount is needed to stimulate throughput in a section of the 
pipeline, that shipper should be permitted to use flexible point rights 
and segment capacity along that capacity path without incurring 
additional charges.\124\ The Commission recognizes that not all 
pipelines follow straight-line paths and, therefore, in order for some 
pipelines to implement segmentation, restrictions on segmentation for 
discounted contracts may be necessary. These issues should

[[Page 35734]]

be addressed in the pipeline's compliance filings.
---------------------------------------------------------------------------

    \123\ See Questar Pipeline Company, 69 FERC para. 61,119 (1994) 
(applying policy to a postage stamp system).
    \124\ On a long-line pipeline, for instance, once the pipeline 
has discounted transportation to a downstream delivery point, it has 
foreclosed the possibility of selling that same capacity at a higher 
rate to an upstream delivery point. The discount, therefore, should 
apply to all transactions within the capacity path.
---------------------------------------------------------------------------

    c. Implementation. El Paso requests clarification that the ability 
of shippers to segment through the nomination process applies only to 
shippers segmenting for their own use, not to shippers seeking to make 
a segmented capacity release transaction. El Paso maintains that 
allowing capacity release transactions through the nomination process 
would by-pass the bidding and posting procedures that apply to capacity 
release transactions. The Commission agrees that shippers subject to 
the posting and bidding requirements for capacity release transactions 
cannot avoid those requirements by designating a transaction as a 
segmented transaction.
    El Paso and Kinder Morgan ask clarification concerning the 
implementation of the requirement that shippers be given the ability to 
segment capacity for their own use through the nomination process, 
without having to use the capacity release process to effectuate 
segmentation. El Paso asks that pipelines be able to implement shipper 
segmentation in different ways depending on the configuration of their 
existing computer system. Kinder Morgan asks that it be permitted to 
continue to use its capacity release mechanism to effectuate shipper 
segmentation for its own use until it can revise its computer systems 
to accommodate this process through the nomination process.
    The Commission will expect pipelines to permit shippers to schedule 
segmented transactions for their own use in as efficient manner as 
possible through the nomination process and to revise their computer 
systems to permit such nominations as soon as is feasible. Until such 
computer revisions are made, pipelines should permit segmented 
transactions in the most efficient method feasible given their current 
computer configurations.

2. Mainline Priority at Secondary Points Within the Path

    In Order No. 637, the Commission did not adopt a specific policy 
with respect to assigning priority over mainline capacity among 
shippers using secondary points when they pay the same rate for 
transportation within a zone.\125\ Dynegy, National Energy Marketers, 
and NGSA contend the Commission should accord a higher priority to 
shippers seeking to use mainline capacity to reach secondary points 
within their capacity path than shippers seeking to use mainline 
capacity outside of their path. Dynegy and National Energy Marketers 
contend that according a shipper using a secondary point within its 
path a higher priority would help alleviate confusion with respect to 
state unbundling programs in which state officials are requiring 
marketers to hold primary firm capacity, rather than permitting them to 
use secondary capacity, because of concerns about reliability. Giving 
greater priority to shippers within their primary path, they assert, 
will alleviate the concerns about the reliability of secondary point 
transactions during constraint periods when pipelines limit deliveries. 
Dynegy maintains that, under the current system, it can often 
effectuate a delivery, but at a higher cost, by scheduling primary firm 
capacity and then purchasing an interruptible back-haul service to 
reach the secondary upstream point.
---------------------------------------------------------------------------

    \125\ Order No. 637, 65 FR at 10196-97, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091, at 31,304-306.
---------------------------------------------------------------------------

    The Commission's goal in expanding segmentation and flexible point 
rights is to strengthen competition in the transportation market. As 
pointed out in Order No. 637, capacity allocation is most efficient 
when capacity is allocated to the shipper placing the highest value on 
obtaining the capacity. In order to provide for efficient allocation of 
capacity, shippers must have rights to capacity and be able to trade 
capacity so that the party placing the highest value can obtain 
it.\126\
---------------------------------------------------------------------------

    \126\ See R. Posner, Economic Analysis of Law, Sec. 3.1, at 28 
(2d ed. 1977) (exclusive property rights are necessary to promote 
trading).
---------------------------------------------------------------------------

    In the situation presented by the rehearing requests, two shippers 
paying the same rate for capacity in a zone seek to use a secondary 
delivery point which is upstream of one shipper and downstream of the 
other. In the example below, shippers 1 and 2 pay the same rate for 
10,000 Dth/d of capacity in the zone, with primary points at A and C 
respectively, and both shippers seek to deliver gas to point B. The 
pipeline is sized such that 30,000 Dth/d can be delivered to point A, 
20,000 Dth/d to point B, and 10,000 Dth/d to point C.
[GRAPHIC] [TIFF OMITTED] TR05JN00.004

    The Commission's prior policy was to allocate mainline capacity 
using secondary points on a pro rata basis among shippers seeking to 
use those secondary points,\127\ although some pipelines had been 
permitted to implement a within-the-path allocation methodology.\128\ 
The justification for pro rata allocation was that two customers paying 
the same rate should receive the same priority of service to secondary 
points.
---------------------------------------------------------------------------

    \127\ See Tennessee Gas Pipeline Company, 71 FERC para. 61,399, 
at 62,577 (1995) (cases cited therein).
    \128\ See Panhandle Eastern Pipe Line Company, 78 FERC para. 
61,202, at 61,870-71 (1997) (conditionally accepting within the path 
allocation); Northwest Pipeline Corporation, 67 FERC para. 61,095 
(1994) (priority given to shippers moving within primary path).
---------------------------------------------------------------------------

    The Commission, however, is concerned that providing all shippers 
in a zone with equal scheduling rights to secondary points does not 
provide for the most efficient use of mainline capacity or promote 
capacity release

[[Page 35735]]

because it creates uncertainty as to how much mainline capacity any 
shipper seeking to use secondary points will receive. Under pro rata 
allocation, neither shipper 1 nor shipper 2 has guaranteed rights to 
the mainline capacity for purposes of making deliveries to point B and, 
therefore, neither can trade those rights In addition, a shipper 
holding primary point capacity at point B (shipper 3) has a competitive 
advantage over either shipper 1 or shipper 2 in selling its capacity, 
since it can guarantee mainline capacity to point B and neither of the 
other two shippers can make a similar guarantee. As Dynegy and NEM 
point out, some state unbundling programs require shippers to obtain 
primary point capacity from the shipper at B in order to ensure that 
deliveries can be made.
    The Commission, therefore, has determined to change its allocation 
policy to the within-the-path approach in order to improve competition. 
Under the within-the-path allocation approach, shipper 2 would have a 
higher priority than shipper 1 to use mainline capacity to reach 
secondary points within its capacity path. By using within-the-path 
priority, shipper 2 has a firm right to mainline capacity to delivery 
point B and, therefore, becomes a more effective competitor to the 
shipper holding primary point capacity at point B. Shippers needing 
capacity to point B now have a choice of buying mainline capacity from 
shipper 2 or shipper 3. Under this policy, shipper 2 would have primary 
mainline rights to ship to or beyond point B, but would have secondary 
rights to make deliveries at point B (unless shipper 2 is permitted to 
select B as an additional primary point as discussed previously).\129\
---------------------------------------------------------------------------

    \129\ Shipper 2's ability to deliver gas using point B as a 
delivery point would depend on whether it has capacity on the 
downstream side of point B to take gas from the system. Providing 
for such take-away rights at city-gate points would be within the 
province of the state regulatory authority regulating the LDC at 
that point. With respect to priority at pipeline interconnects, the 
Commission, in Order No. 637, stated that such priority would be 
determined by pipeline confirmation rules, but that a shipper that 
has obtained firm capacity on both sides of the interconnect 
generally should have priority over a shipper that is using 
interruptible transportation on one of the pipelines, regardless of 
whether the firm shipper is using a secondary or primary point. See 
Order No. 637, 65 FR at 10197, III FERC Stats. & Regs. Regulations 
Preambles para. 31,091, at 31,306-7.
---------------------------------------------------------------------------

    The Commission recognizes that because the pipeline in the example 
has a large rate zone that is not divided at constraint points, shipper 
1 (the upstream shipper) pays the same rate as shipper 2 and receives 
less valuable rights under the within-the-path allocation. But it is 
not possible to allocate mainline capacity downstream of point A to 
shipper 1, because shipper 2 (with primary point rights at C) could 
preempt shipper 1's use of any capacity beyond point A by shipping gas 
to its primary point at C. Thus, the only method of creating tradable 
capacity rights is to give shipper 2 priority rights to all capacity 
upstream of its delivery point at C.\130\
---------------------------------------------------------------------------

    \130\ Under within-the-path allocation, if shipper 1 values the 
capacity to point B more than shipper 2, it can purchase the 
capacity from shipper 2. This would ensure that the capacity is 
allocated efficiently to the highest valued user.
---------------------------------------------------------------------------

    The Commission therefore finds that the use of within-the-path 
priority better promotes efficient allocation of capacity and improves 
competition as compared with pro rata allocation and, accordingly, each 
pipeline must use the within-the-path allocation method in its 
compliance filing, unless it can demonstrate that such an approach is 
operationally infeasible or leads to anticompetitive outcomes on its 
system. The Commission encourages pipelines to look closely at their 
zone boundaries and to develop more efficient methods of allocating 
capacity based on price, so that capacity initially is allocated to the 
shipper placing the highest value on obtaining that capacity.

C. Imbalance Services, Operational Flow Orders and Penalties

    In Order No. 637, the Commission determined that while OFOs and 
penalties can be important tools to correct and deter shipper behavior 
that threatens the reliability of the pipeline system, the current 
system of OFOs and penalties is not the most efficient system of 
maintaining pipeline reliability in the short-term market. The manner 
in which pipelines impose OFOs and penalties often restricts shippers' 
abilities to effectively use their transportation capacity. For 
example, OFOs can limit the ability of shippers to respond to prices in 
the market, undermining the fluidity of the commodity market.
    The Commission also determined that Commission-authorized penalties 
provide an opportunity for shippers to engage in a form of penalty 
arbitrage, both across pipeline systems, and within a single pipeline 
system. Arbitrage activity imposes higher costs on all shippers on the 
system, and at peak, also may imperil systemwide reliability and 
trigger OFOs and emergency penalties. Further, many pipelines have 
responded to arbitrage on their systems by imposing stricter imbalance 
tolerances and higher penalties, which, in turn, often operate to limit 
and distort market forces.
    Given the existence of arbitrage on and across pipeline systems, 
the Commission concluded that shippers are using penalties as a means 
to indirectly gain flexibility with respect to obtaining gas supplies 
and transportation capacity. Therefore, because the penalty system 
encourages shippers to engage in behavior that may be harmful to the 
system as a way to obtain needed flexibility, the Commission shifted 
its policy away from one that fosters the use of OFOs and penalties, to 
a ``service-oriented'' policy that gives shippers other options to 
obtain flexibility and relies on penalties only when necessary to 
protect system integrity. Specifically, Order No. 637 established three 
general policies designed to help give shippers positive incentives to 
use the pipeline appropriately to avoid the need for penalties and 
OFOs.
    First, Order No. 637 required pipelines to provide separate 
imbalance management services, like park and loan service, to give 
shippers flexibility, directly.\131\ The Commission explained that the 
imbalance management services, together with the provision of greater 
information about the imbalance status of shippers and the system, will 
give shippers a greater ability to remain in balance in the first 
instance, and thereby avoid penalties.
---------------------------------------------------------------------------

    \131\ 18 CFR 284.12(c)(2)(iii).
---------------------------------------------------------------------------

    Second, Order No. 637 required pipelines to establish incentives 
and procedures to minimize the use of OFOs.\132\ The Commission 
required each pipeline to revise its tariff to include a number of 
pipeline specific standards for the issuance of OFOs.
---------------------------------------------------------------------------

    \132\ 18 CFR 284.12(c)(2)(iv).
---------------------------------------------------------------------------

    Third, Order No. 637 required pipelines to include in their tariffs 
only those penalty structures and levels that are necessary and 
appropriate to protect the system.\133\ The Commission also required 
pipelines to credit the revenues from penalties and OFOs to shippers to 
eliminate the pipelines' financial incentive to impose penalties and 
OFOs.
---------------------------------------------------------------------------

    \133\ 18 CFR 284.12(c)(2)(v).
---------------------------------------------------------------------------

    Finally, Order No. 637 required each pipeline to either propose in 
its compliance filing pro forma changes to its tariff to implement the 
new requirements, or explain how its existing tariff and operating 
practices are already consistent with the new requirements.
    The rehearing applicants seek rehearing and/or clarification of 
various aspects of each of the three new provisions. However, the 
petitioners do

[[Page 35736]]

not oppose the core requirement that pipelines provide imbalance 
management services, but primarily seek rehearing of the new OFO and 
penalty provisions. Below, the Commission further details each of the 
new provisions and addresses the rehearing arguments related to each.
1. Imbalance Management
    New section 284.12(c)(2)(iii) is an important component of the 
Commission's new policy focus to use positive incentives to achieve 
shipper behavior, rather than penalties or OFOs. In that section, the 
Commission established the policy that pipelines must provide to 
shippers, to the extent operationally practicable, imbalance management 
services, such as park and loan service, swing on storage service, or 
imbalance netting and trading. Pipelines will be permitted to retain 
the revenues from the new imbalance management services initiated 
between rate cases. As part of this requirement to provide imbalance 
management services, the Commission encouraged pipelines to design 
imbalance management services that would give shippers a built-in 
incentive to utilize the service, and to develop financial inducements 
for shippers to remain in balance or avoid behavior that is harmful to 
the system. In addition, the Commission stated in Order No. 637 that 
pipelines will not be permitted to implement the new imbalance services 
until they also implement imbalance netting and trading on their 
systems.
    Rehearing requests were filed concerning the retention by pipelines 
of the revenue from imbalance management services between rate cases, 
and the applicability of the imbalance management service requirement 
to pipelines that do not impose imbalance penalties or OFOs. A number 
of requests for clarification of the requirement to offer imbalance 
management services were also filed. These are discussed below.
    a. Retention of Imbalance Management Service Revenue Between Rate 
Cases. NASUCA and Penn./Ohio Advocate jointly, and Amoco argue that the 
Commission erred by allowing pipelines to retain the revenues from the 
new imbalance management services between rate cases. They argue that, 
since pipelines control the timing of rate cases and have no obligation 
to file a rate case, this policy could provide the pipeline with 
windfall profits at the expense of long-term shippers who pay 100 
percent of the costs of the facilities used to provide those services.
    NASUCA and Penn./Ohio Advocate argue that the Commission's general 
policy of permitting retention of revenues between rate cases should 
not apply here because the new services are being required as a remedy 
to existing unreasonable practices and procedures (i.e. gaming on 
pipeline systems), and pipelines should not be able to retain the 
benefits from such remedies. NASUCA and Penn./Ohio Advocate request 
that the Commission require pipelines to credit all of the imbalance 
management service revenues to firm shippers. Alternatively, they 
propose that the revenues be shared between the pipeline and long-term 
firm shippers, perhaps providing pipelines with a 10 percent share to 
encourage the pipelines to provide the services.
    Amoco argues that if a pipeline's penalty free imbalance tolerance 
is set at an unreasonably low level, the retention of the imbalance 
management services revenues could result in significant windfalls. 
Amoco requests that pipelines not be permitted to retain imbalance 
service revenues, but be required to implement either an annual rate 
recalculation or a tracker mechanism to ensure that the pipeline does 
not overrecover its costs. Amoco also seeks clarification that 
pipelines will not be permitted to reduce or eliminate existing 
imbalance tolerance levels to levels that effectively force utilization 
of the new services.
    As the Commission stated in Order No. 637, ``[i]n order to give 
pipelines an incentive to develop these new imbalance management 
services, the Commission is not changing its current policy that 
pipelines may retain the revenues from a new service initiated between 
rate cases.'' \134\ The Commission has decided not to change that 
policy in the context of the new imbalance management services being 
required here.
---------------------------------------------------------------------------

    \134\ Order No. 637, 54 FR at 10199, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,310.
---------------------------------------------------------------------------

    In requiring that pipelines offer imbalance management services to 
the extent operationally practicable, the Commission's goal, as stated 
in Order No. 637, is for pipelines to provide as many different 
imbalance management services as the pipeline can operationally, and to 
develop innovative imbalance management services that might not 
currently exist. It is important for pipelines to have an incentive to 
develop, create, and offer such new imbalance management services. The 
pipelines' retention of 100 percent of the revenues between rate cases 
provides an incentive for pipelines to offer imbalance management 
services and ensures that the use of imbalance management services will 
supplant the need for penalties. Allowing pipelines to retain only a de 
minimus share of the revenues will not provide an adequate incentive to 
develop and provide the services.
    In response to Amoco's concern, pipelines will not be permitted to 
arbitrarily reduce or eliminate imbalance tolerance levels and increase 
penalty levels in an effort to force shippers to use imbalance 
management services, since the Commission is requiring pipelines to 
implement and justify reasonable tolerance and penalty levels. All such 
proposed changes will be reviewed by the Commission comprehensively 
along with all of the pipeline's imbalance management services to 
ensure that the impact of the services and penalties work together to 
achieve the Commission's policy objectives.
    b. Who Must Comply. Michigan Gas Storage argues that the Commission 
should not require pipelines that do not impose OFOs or collect 
imbalance penalties to provide imbalance management services or 
information on shippers' and the systems' imbalance status.\135\ 
Michigan Gas Storage asserts that because the purpose of requiring 
imbalance management services is to minimize the imposition of OFOs and 
penalties, there would be no apparent purpose served by requiring 
pipelines that neither impose OFOs or collect imbalance penalties to 
provide imbalance management services or imbalance status information.
    The Commission agrees with Michigan Gas Storage that if a 
pipeline's tariff does not include OFO provisions and imbalance penalty 
provisions, it need not provide imbalance management services or 
information on imbalance status. The Commission's goal in requiring 
pipelines to provide imbalance management services and greater 
information regarding imbalances is to enable shippers to avoid 
imbalances so that they will not incur penalties or be subject to an 
OFO. If a pipeline has no authority to issue OFOs or to assess 
penalties for either imbalances or OFO violations, then a shipper has 
no need for imbalance management services, and there is no need to 
require pipelines to offer such services. Pipelines that do not impose 
OFOs or collect penalties apparently do not have problems with shipper 
imbalances.
---------------------------------------------------------------------------

    \135\ In new section 281.12(c)(2)(v), concerning penalties, 
pipelines are required to provide shippers with information on their 
imbalance and overrun status.
---------------------------------------------------------------------------

    Accordingly, the Commission will amend the first sentence of 
section

[[Page 35737]]

284.12(c)(iii) to state: ``A pipeline with imbalance penalty provisions 
in its tariff must provide, to the extent operationally practicable, 
parking and lending or other services that facilitate the ability of 
its shippers to manage transportation imbalances.'' Similarly, the 
Commission will amend the last sentence of section 284.12(c)(v) to 
provide: ``A pipeline with penalty provisions in its tariff must 
provide to shippers, 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.'' However, if a pipeline that does 
not have such provisions in its tariff at any time decides to include 
OFO or imbalance penalty provisions in its tariff, then such pipeline 
must comply with sections 284.12(c)(iii) and (v).
    c. Requests for Clarification. (1) Imbalance Netting and Trading. 
In Order No. 637, the Commission stated the following with respect to 
imbalance netting and trading:

    However, pipelines will not be permitted to implement the new 
imbalance services until they also implement imbalance netting and 
trading on their systems. Pipelines should not expect shippers to 
purchase new services until the shippers can determine whether 
imbalance trading will be adequate for their needs. Thus, the 
implementation of the new imbalance management services must 
coincide with the implementation of imbalance netting and trading. 
Since GISB has already approved business practice standards for 
netting and trading, pipelines should be able to implement imbalance 
netting and trading at the same time that they implement the new 
imbalance management services.\136\

    Northern Distributor Group (NDG) requests clarification in two 
respects of the Commission's directive in Order No. 637 that pipelines 
implement imbalance netting and trading at the same time that they 
implement the new imbalance management services. First, NDG asserts 
that it is unclear whether the Commission established the Order No. 637 
compliance filing date as the date certain by which pipelines must 
implement imbalance netting and trading, or whether the pipeline's 
obligation to implement imbalance netting and trading is dependent on 
whether the pipeline chooses to implement imbalance management 
services. NDG requests the Commission to clarify that regardless of 
whether a pipeline chooses to offer new imbalance management services 
on its designated compliance date, it must nevertheless offer imbalance 
netting and trading on that date. Second, NDG seeks clarification that 
a pipeline's implementation of imbalance netting and trading must be 
consistent with the GISB-approved netting and trading business 
practices.
---------------------------------------------------------------------------

    \136\ Order No. 637, 54 FR at 10199, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,311.
---------------------------------------------------------------------------

    In Order No. 637, the Commission determined that pipelines would be 
required to offer their shippers imbalance services. The Commission, 
however, determined that it would be unreasonable to expect shippers to 
purchase the new services unless the shippers first had an opportunity 
to evaluate whether imbalance trading would be sufficient for their 
needs. The Commission, therefore, imposed a moratorium on approving 
pipeline filings to establish imbalance services unless the pipeline 
has, or has proposed, an imbalance trading mechanism.
    With respect to the pipeline's obligations to make compliance 
filings under Order No. 637, all pipelines are required to make pro 
forma compliance filings to establish the imbalance services they 
propose to comply with the Commission's regulation. Those services, 
however, will not be implemented until the Commission has reviewed the 
proposal and established an effective date. The Commission will not do 
so unless the pipeline has a pre-existing imbalance trading mechanism 
or one that will take effect at the same time as the imbalance 
services.
    The Northern Distributor Group requests clarification as to when 
pipelines will be required to implement imbalance trading. In Order No. 
587-G,\137\ the Commission adopted a regulation requiring pipelines to 
implement imbalance trading, but deferred implementation of this 
regulation until GISB has developed the necessary standards. Although 
GISB initially had projected that such standards could be developed by 
June 30, 1998,\138\ it has taken far longer to develop the necessary 
standards. GISB's Executive Committee has approved business practice 
standards for imbalance trading and GISB has now established an 
Expedited Data Development Subcommittee to develop the standards 
relating to the use of EDI for communication.\139\ The Commission fully 
expects those standards to be approved quickly and, at that point, all 
pipelines will be obliged to implement those standards expeditiously. 
At the time when the imbalance trading standards are implemented, 
pipelines will be required to implement the imbalance services.
---------------------------------------------------------------------------

    \137\ Standards for Business Practices of Interstate Natural Gas 
Pipelines, Order No. 584-G, 63 FR 20072 (Apr. 23, 1998), III FERC 
Stats. & Regs. Regulations Preambles para. 31,062 (Apr. 16, 1998).
    \138\ Standards for Business Practices of Interstate Natural Gas 
Pipelines, Order No. 587-G, 63 FR 20072, 20081 (Apr. 23, 1998), III 
FERC Stats. & Regs. Regulations Preambles para. 31,062, at 30, 677 
(Apr. 16, 1998).
    \139\ Http://www.gisb.org/edd.htm (announcing formation of 
Expedited Data Development Subcommittee).
---------------------------------------------------------------------------

    For a pipeline that wishes to implement imbalance services and 
imbalance trading at an earlier date, the pipeline should comply with 
the business practice standards already passed by GISB's Executive 
Committee. But the pipelines need only provide for imbalance trading on 
their Internet web sites. They do not need to establish EDI 
communication until GISB has approved the relevant technical standards 
for EDI.
    (2) Third-Party Imbalance Management Services. New section 
284.12(c)(iii) requiring pipelines to offer imbalance management 
services to its shippers also requires pipelines to provide their 
shippers with the opportunity to obtain imbalance management services 
from third-party providers. In describing section 284.12(c)(iii) in 
Order No. 637, the Commission stated that ``under this policy, 
pipelines will not be permitted to give undue preference to their own 
storage or balancing services over such services that are provided by a 
third party.'' \140\ The Commission then stated, ``The Commission is 
requiring pipelines to include these imbalance management services as 
part of their tariffs.'' \141\
---------------------------------------------------------------------------

    \140\ Order No. 637, 54 FR at 10199, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,310.
    \141\ Id.
---------------------------------------------------------------------------

    Koch is confused by the latter sentence quoted above. Koch states 
that if the Commission is requiring pipelines to permit third parties, 
within the scope of the pipeline's existing tariff provisions, to 
provide imbalance services, then it has no objection to the proposed 
changes. However, Koch objects if the Commission is requiring Koch to 
draft tariff provisions to implement services that third parties want 
to have included in Koch's tariff or to allow third parties the right 
to seek changes to Koch's tariff, outside the statutory requirements of 
section 5.
    The Commission's intent was to require pipelines to include their 
own imbalance management services as part of their tariffs, not the 
third party's imbalance management service. However, the Commission 
expects the pipelines' tariffs to be crafted so that the pipeline will 
not unduly discriminate against shippers using other providers, or give 
undue preference to its own imbalance management services. For

[[Page 35738]]

example, the pipeline's tariff should not contain unnecessary 
restrictions that prevent third-party imbalance providers from 
competing with the pipeline.
    Both Koch and Kinder-Morgan request clarification with respect to 
how imbalance management services by third parties will be provided and 
whether such third-party providers will be subject to the Commission's 
NGA jurisdiction. They request the Commission to clarify that the 
third-party providers will be subject to the same statutory 
requirements and standards for providing services in interstate 
commerce that pipelines are subject to, such as open-access 
requirements or the requirements of Order No. 497. Otherwise, argues 
Kinder-Morgan, pipelines will be at a significant competitive 
disadvantage. Kinder-Morgan argues that to the extent third-party 
services are provided, a number of conditions must apply.\142\ In 
addition, Kinder-Morgan requests the Commission to identify who will be 
responsible if third-party providers of imbalance services fail to 
provide the necessary balancing, and that it should not be the pipeline 
that is the ``balancer of last resort.'' \143\
---------------------------------------------------------------------------

    \142\ Kinder-Morgan states that such conditions include, for 
example, Commission approval of the service prior to commencement, 
contractual privity between the third-party provider and the 
pipeline, and the availability of bi-directional flow at the 
delivery and/or receipt points involved. Request for Rehearing of 
Kinder-Morgan at 22.
    \143\ Id. at 23.
---------------------------------------------------------------------------

    To the extent that the third-party providers are performing the 
interstate transportation of natural gas, as defined in the NGA, in 
their provision of imbalance management services, they will be engaging 
in a jurisdictional activity. However, a third-party provider may be 
able to provide imbalance management services that do not involve the 
interstate transportation of gas. Whether a third-party provider is 
performing jurisdictional transportation service is dependent on the 
characteristics of the particular imbalance management service being 
provided. For example, an imbalance management service provided by a 
third-party may consist simply of the sale of gas to make up an 
underdelivery. To the extent that the gas sale is a first sale, it 
would not be jurisdictional, and for jurisdictional gas sales, the 
Commission has already granted a blanket certificate to make sales for 
resale at negotiated rates.\144\
---------------------------------------------------------------------------

    \144\ 18 CFR 284.402 (1999).
---------------------------------------------------------------------------

    The Commission will not require that the conditions which Kinder-
Morgan lists be attached to the provision of third-party imbalance 
management services. However, in their compliance filings, pipelines 
may include proposed tariff provisions for coordinating with third-
party providers of imbalance services if such requirements are needed 
for operational purposes. Further, in the event a pipeline faces 
sufficient competition for imbalance management services from third 
party providers, the pipeline may be able to justify a request for 
market-based rates for that service.
    (3) Clarification of Specific Phrases and Terms. Under section 
284.12(c)(2)(iii), a pipeline must provide imbalance management 
services ``to the extent operationally practicable.'' Amoco requests 
the Commission to clarify that phrase. Amoco argues that under such 
discretionary language, a pipeline could refuse to comply on the basis 
of an assertion that such services are not operationally practicable. 
Amoco asserts that either the burden of proof should be placed on the 
pipeline to support such a claim, or the language should be eliminated.
    The Commission agrees with Amoco that the burden of proof is on the 
pipeline to support a claim of operational impracticability. The 
pipeline must provide sufficient evidence demonstrating why the 
provision of imbalance management services is ``operationally 
impracticable.''
    IMGA states its belief that Order No. 637 intended the term 
``imbalance'' to apply to both physical and scheduling imbalances,\145\ 
and requests the Commission to clarify that the use of the term 
``imbalance'' throughout Order No. 637 encompasses both physical and 
scheduling imbalances. If the Commission did not intend for the term 
``imbalances'' to refer to both types of imbalances, IMGA requests the 
Commission to indicate which type of imbalance it meant each time the 
Commission used the term in the preamble of Order No. 637. The 
Commission confirms that the term ``imbalance'' was intended to apply 
to both physical and scheduling imbalances.
---------------------------------------------------------------------------

    \145\ IMGA cites the Commission's discussion in Order No. 637 
defining penalties as including penalties for physical and 
scheduling imbalances at 54 FR at 10197, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,317. IMGA Request for 
Rehearing at 10.
---------------------------------------------------------------------------

2. Operational Flow Orders
    In Order No. 637, the Commission found that 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.'' 
\146\ Thus, new section 284.12(c)(2)(iv) establishes the principle that 
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.''
---------------------------------------------------------------------------

    \146\ Order No. 637, 54 FR at 10200, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,312.
---------------------------------------------------------------------------

    To implement this principle, the Commission required pipelines to 
revise their tariffs to adopt objective standards and procedures for 
the use of OFOs. Specifically, the Commission required each pipeline's 
tariff to: (1) State clear, individualized standards, based on 
objective operational conditions, for when OFOs begin and end; (2) 
require the pipeline to post information about the status of 
operational variables that determine when an OFO will begin and end, 
(3) state the steps and order of operational remedies that will be 
followed before an OFO is issued; (4) set forth standards for different 
levels or degrees of severity of OFOs to correspond to different 
degrees of system emergencies the pipeline may confront; and (5) 
establish reporting requirements that provide information after OFOs 
are issued on the factors that caused the OFO to be issued and then 
lifted.
    On rehearing, only Koch and Kinder-Morgan take issue with OFO 
requirements imposed by Order No. 637. These arguments are discussed 
below.
    a. Legal Authority and Need for OFO Standards and Procedures. Koch 
and Kinder-Morgan argue that the OFO provisions (as well as the penalty 
provisions discussed in the next section) violate section 5 of the NGA 
because the Commission has not made the requisite finding under section 
5 that the existing OFO procedures are unjust, unreasonable, and unduly 
discriminatory. They assert that the Commission has departed without 
justification from the existing OFO policy established in Order No. 636 
that OFOs are appropriate tools to deter harmful shipper conduct, and 
therefore, necessary for the pipeline to ensure system integrity in an 
open-access environment. Specifically, Koch and Kinder-Morgan assert 
that there is no record evidence supporting the Commission's finding 
that OFOs inhibit shipper flexibility, interfere with the fluidity of 
the commodity market, are a source of revenue, or are issued too 
frequently. Koch also disputes the Commission's decision to require all 
pipelines to revise their OFO

[[Page 35739]]

procedures and standards instead of targeting only pipelines that are 
in fact issuing unnecessary OFOs. In addition, Keyspan requests 
clarification that if a pipeline proposes no change in its compliance 
filing, the Commission will act to make changes only when it is able to 
make the required section 5 findings.
    In requiring pipelines to take actions to minimize the use and 
adverse impacts of OFOs, and to include objective pipeline-specific 
standards for the use of OFOs, the goal of the Commission is to enable 
pipelines to continue to use OFOs to protect pipeline integrity, 
without unnecessarily limiting or restricting competition in the 
market. The intent of the Commission is not to ban or restrict the use 
of OFOs so that pipelines may not impose OFOs when they are necessary 
to ensure system reliability. Rather, the new OFO policy and tariff 
requirements are designed to address the manner or way in which OFOs 
are being designed and imposed. The Commission seeks to ensure that 
they are being imposed only to the extent necessary to protect system 
reliability, and thus, that shippers are not needlessly restricted. In 
other words, the Commission is seeking ways for pipelines to use the 
proper mix of OFOs and positive financial incentives so that shippers 
can have as much flexibility as possible without causing operational 
problems that threaten reliability.
    Therefore, the Commission has not departed from its existing policy 
that OFOs are appropriate tools for ensuring system integrity and 
reliability, and consequently need not find under section 5 that OFOs, 
per se, are unjust and unreasonable. Rather, the Commission has made a 
generic determination that the manner in which a pipeline imposes OFOs, 
or a pipeline's existing procedures or guidelines for its use of OFOs, 
may be unjust and unreasonable if the pipeline's issuance of an OFO 
unnecessarily restricts shippers' flexibility or is not well-defined, 
or if the OFOs are issued too frequently or stay in effect too long for 
the purpose of maintaining system reliability.
    The Commission's findings that some pipelines are issuing OFOs that 
may be unnecessary for system reliability purposes, and that the manner 
in which some pipelines impose OFOs may unnecessarily restrict shipper 
flexibility, are based on adequate evidence. The Commission concluded 
from the comments to the NOPR,\147\ and the Commission staff's own 
independent analysis of pipeline OFO tariff provisions, as well as the 
record in the cases cited in Order No. 637, \148\ that the design and 
imposition of OFOs are not always tailored to ensure OFOs are imposed 
to preserve the integrity of system operations. For instance, the 
comments, tariff provisions, and cases revealed that OFO tariff 
provisions are not well defined, permit OFOs to be issued too 
frequently and to stay in effect too long, and do not give adequate 
warnings to shippers. All of this evidence provided the Commission with 
a reasonable basis upon which to require all pipelines to make a pro 
forma tariff filing to rejustify their current OFO provisions as just 
and reasonable.
---------------------------------------------------------------------------

    \147\ E.g., Comments of Shell Energy Services Company, L.L.C. at 
17, Florida Cities at 7-8, and American Forest & Paper Association 
at 43.
    \148\ 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 Pipe Line Company, 78 FERC 
para. 61,202 (1997); Northwest Pipeline Company, 71 FERC para. 
61,315 (1995). The Commission determined the validity of the claims 
made in these cases by conducting its own analysis of the pipelines' 
tariffs.
---------------------------------------------------------------------------

    Thus, the Commission has not yet made a section 5 determination 
that any particular pipeline's tariff regarding OFOs is, in fact, 
unjust and unreasonable. Any such section 5 determination will be made 
in the individual pipeline compliance filings. Such filings give 
individual pipelines, like Koch, the opportunity to show why their 
existing tariffs should not be considered unjust and unreasonable and 
that their tariffs are already in compliance with Order No. 637. In 
response to Keyspan, if the Commission finds that changes in a 
particular pipeline's tariff are warranted, the Commission will act 
under section 5 to implement such changes. Accordingly, the new OFO 
regulation does not violate section 5 of the NGA, and the Commission 
has acted within its authority.
    b. The Reasonableness of the OFO Standards and Procedures. Kinder-
Morgan and Koch argue that the Commission has not imposed a just and 
reasonable remedy to the allegedly unlawful existing OFO procedures. 
They argue that the new OFO procedures take away the pipelines' ability 
to manage their systems and jeopardize the provision of reliable 
service to customers. Kinder Morgan asserts that in situations where 
OFOs are issued, the concern should be whether deliveries to all 
customers can be maintained, not whether one shipper is unable to 
reduce its gas prices by a few pennies.
    As the Commission stated above, the new OFO policy and requirement 
to establish OFO standards does not ban the use of OFOs and thereby 
remove pipelines' ability to control their systems. The Commission 
agrees that the reliability of service to all customers should be of 
greater concern than the reduction in one shipper's flexibility, where 
system reliability is a genuine or legitimate concern.
    Kinder Morgan specifically argues the requirement, that pipelines 
set forth clear pipeline-specific standards based on objective 
operational conditions for when OFOs will begin and end, unduly 
constrains pipelines because it assumes both static conditions and 
perfect foresight. Kinder-Morgan asserts that operating conditions 
change over time, and the pipeline cannot predict all possible 
operating conditions that would justify issuance of an OFO. Kinder-
Morgan also maintains the OFO tool should not be restricted because 
OFOs are particularly important to pipelines that have no storage or 
only limited storage, since they have no ability to absorb imbalances 
and counteract adverse operating conditions. Similarly, Koch requests 
clarification that the OFO policy to be implemented will be tailored 
specifically to meet Koch's operational needs, rather than those of 
some other pipeline.
    Kinder-Morgan misinterprets what the Commission is requiring. The 
Commission expects pipelines to formulate the pipeline-specific OFO 
standards based on their reasonable expectation of potential operating 
conditions. The Commission is not prohibiting a pipeline from issuing 
an OFO until a particular predesignated operating condition actually 
occurs. The pipelines may build flexibility into the standards and 
procedures so that OFOs may be issued based on expectations or in 
anticipation of particular operating conditions. This flexibility is 
only limited by the need to draft standards that will give shippers 
clear notice of the instances when an OFO could be issued. The 
particular OFO standards applicable to each pipeline can be developed 
in the individual compliance filing proceedings, where the 
reasonableness of the standards can be determined in the context of the 
pipeline's complete imbalance management, penalty and OFO scheme. 
Further, the Commission clarifies that it is not requiring a set of 
rigid OFO standards invariant to the particular needs of individual 
pipelines. The Commission will permit considerable variation in the 
tariff provisions to enable pipelines to tailor OFO standards to fit 
the operational parameters of their

[[Page 35740]]

particular systems, such as the lack of storage facilities.
3. Penalties
    New section 284.12(c)(2)(v) establishes three key principles. 
First, it provides that ``[a] pipeline may include in its tariff 
transportation penalties only to the extent necessary to prevent the 
impairment of reliable service.'' The Commission recognized in Order 
No. 637 that unnecessarily high penalties have been imposed in the 
past, and that the penalties on some pipelines are at the same level 
during peak and non-peak periods, when the potential for the impairment 
of reliability may differ. The Commission stated that ``[n]on-critical 
day penalties, or penalties imposed during off-peak periods, may not be 
the most appropriate and effective to protect system operations.'' 
\149\ Therefore, the Commission explained that it is requiring 
pipelines to narrowly design penalties to deter only conduct that is 
actually harmful to the system. The Commission directed all pipelines 
in their compliance filings to either explain or justify their current 
penalty levels and structures under this standard, or revise them to be 
consistent with this principle.
---------------------------------------------------------------------------

    \149\ Order No. 637, 54 FR at 10201, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,314
---------------------------------------------------------------------------

    The second principle established by this regulation is that 
pipelines must credit to firm shippers all revenues from all penalties, 
net of costs, including imbalance, overrun, cash-out, and OFO 
penalties. The Commission determined that the elimination of the 
pipelines' economic incentive to use and impose penalties was necessary 
to shift pipelines to the use of non-penalty mechanism to solve and 
prevent operational problems. The Commission did not prescribe on a 
generic basis the details of the revenue crediting mechanism, including 
which shippers will receive the penalty revenue credits, but instead 
will permit each pipeline to formulate an appropriate method for 
implementing penalty revenue crediting on its system. However, the 
Commission did indicate that, ideally, penalty revenues should be 
credited only to non-offending shippers.
    The third principle established by the new regulation is pipelines 
must provide to shippers, 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.
    On rehearing, the petitioners argue that the new penalty policy 
violates section 5 of the NGA and is unsupported by concerns regarding 
penalty arbitrage, restrictions on shipper flexibility, and penalties 
being a source of revenue. The rehearing applicants also argue that the 
Commission erred by limiting the use of penalties ``only to the extent 
necessary to prevent the impairment of reliable service,'' and by 
requiring the crediting of penalty revenues. In addition, several 
applicants request clarification of the revenue crediting requirement 
and what constitutes a penalty. Finally, one petitioner requests the 
Commission to implement a ``no-harm, no-foul'' policy.
    a. Legal Authority and Need for New Penalty Policy. As they argue 
with respect to OFOs, Kinder-Morgan and Koch argue that the new penalty 
provision violates section 5 of the NGA because the Commission has not 
found existing penalties unjust and unreasonable. They assert that the 
Commission has departed without justification from the existing policy 
that recognizes that penalties are an appropriate tool to deter shipper 
misconduct. Kinder-Morgan and Koch argue that the Commission's findings 
that penalties encourage arbitrage and are a source of revenue are 
unsupported, and do not justify the Commission's remedy of limiting or 
eliminating the use of penalties.
    The Commission acknowledges that penalties are an appropriate tool 
to protect system reliability. In Order No. 637, the Commission did not 
find the use of penalties, per se, to be an inappropriate method of 
protecting system integrity. The Commission did find, however, that (a) 
penalties, as currently designed and applied, are not always being used 
to ensure system reliability, and (b) penalties may not be the most 
appropriate way to preserve system reliability. The Commission found 
that there could be other ways for pipelines to ensure reliability, 
that did not involve the use of a negative deterrent.
    Specifically, the Commission determined that the use of imbalance 
management services would be a better way to keep shippers from 
engaging in behavior that could adversely affect system reliability, 
especially since penalties provide the opportunity for arbitrage 
behavior. Thus, the Commission shifted its policy away from penalties 
and towards imbalance management services. Yet, the Commission 
nevertheless recognized that penalties could still be a valid mechanism 
to ensure system integrity, if penalty levels and structures were 
better designed to meet that purpose. Therefore, the Commission did not 
``eliminate penalties altogether,'' as Kinder-Morgan seems to believe, 
but rather, redefined their role. Thus, the new penalty policy does not 
violate section 5 of the NGA because the Commission has not abandoned 
its existing penalty policy recognizing penalties as an important tool 
to protect system reliability; the Commission has shifted its policy 
focus to place less reliance on penalties.
    The Commission's determinations that changes to the design and 
application of pipelines' penalty levels and structures are necessary, 
and the penalty system may not be the best way to ensure system 
reliability, are adequately supported. The fact that arbitrage is 
occurring and that penalties provide the opportunity for shippers to 
engage in arbitrage is well documented by a number of cases in which 
pipelines sought higher overrun and imbalance penalties and lower 
tolerances specifically in response to arbitrage activity on their 
systems.\150\ The Commission agrees with Kinder-Morgan that the 
existence of arbitrage does not justify the elimination of penalties; 
the Commission is not eliminating penalties. However, the fact that 
arbitrage is occurring not only across pipeline systems but within 
pipeline systems demands that pipelines revise the level and structure 
of their penalty provisions to minimize the opportunity for arbitrage. 
For example, as the Commission stated in Order No. 637, pipelines may 
be able to change their imbalance cash-out procedures or methods to 
eliminate the incentives for shippers to borrow gas from the pipeline 
because the cash-out price is less than the market price for gas.\151\
---------------------------------------------------------------------------

    \150\ E.g., Northern Natural Gas Company, 77 FERC para.61,282 at 
62,236 (1997); Panhandle Eastern Pipe Line Company, 78 FERC 
para.61,202 at 61,876-77 (1997), reh'g denied, 82 FERC para.61,163 
(1998); and Williams Natural Gas Company, 78 FERC para.61,342 
(1997).
    \151\ Order No. 637, 54 FR at 10201, III FERC Stats. & Regs. 
Regulations Preambles para.31,091 at 31,314-15.
---------------------------------------------------------------------------

    The Commission also determined after review of the comments to the 
NOPR that high penalties and low or no tolerances can operate to 
restrict shipper flexibility and distort market forces and are not 
effective in deterring harmful conduct and protecting system 
reliability.\152\ Further, the penalty tariff

[[Page 35741]]

provisions proposed by the pipelines in the penalty cases cited above, 
led the Commission to conclude that penalty provisions needed to be 
better crafted and defined, and better tailored to address potential 
harm to system reliability.
---------------------------------------------------------------------------

    \152\ E.g., Comments of Dynegy, Chapter 6 and Appendix B; 
Comments of Proliance Energy, LLC at 4-5. In Appendix B of Dynegy's 
comments, Dynegy provided a review of the significant penalty cases 
in the recent past, and its assessment of current penalty and OFO 
tariff provisions. In one of the cases cited by Dynegy, Williams 
Natural Gas Company, 78 FERC para.61,342 at 62,462 (1997), the 
parties argued that the high contract overrun penalties being sought 
would prompt responsible shippers to oversubscribe to transportation 
capacity solely to provide a safety margin, rather than deter 
harmful conduct.
---------------------------------------------------------------------------

    Thus, as the Commission similarly explained with respect to the new 
OFO policy, supra, the Commission has not yet made a section 5 
determination that any particular pipeline's penalty provisions is, in 
fact, unjust and unreasonable. Any section 5 determination will be made 
in the individual pipeline compliance filings, and such determinations 
will be made on specific findings that the existing penalty provisions 
are unjust and unreasonable, and the replacement provisions are just 
and reasonable.
    b. Limitation of Penalties Only to the Extent Necessary to Prevent 
the Impairment Of Reliable Service. Kinder-Morgan and CNGT object to 
the Commission's limitation on the use of penalties ``only to the 
extent necessary to prevent the impairment of reliable service.'' \153\ 
CNGT argues that the limitation allowing penalties only to the extent 
necessary to prevent the impairment of reliable service is overly 
restrictive because system reliability is only one purpose of 
penalties. CNGT argues that penalties also serve to enforce contractual 
rights, obligations, and limitations, and to discourage penalty 
arbitrage.
    Further, Kinder-Morgan and Keyspan raise questions about whether 
the requirement that penalties must be necessary to prevent the 
impairment of reliable service prohibits pipelines from issuing 
penalties during non-critical periods. Kinder-Morgan takes issue with 
what it believes is the Commission's assumption underlying this 
provision--that penalties simply are ``not required.'' \154\ Kinder-
Morgan argues that pipelines may need penalties to maintain system 
integrity during non-critical periods, as well as during critical 
periods. Conversely, the Industrials request the Commission to require 
pipelines to use a ``no harm/no foul'' mechanism, unless the pipeline 
is operationally constrained from doing so.
---------------------------------------------------------------------------

    \154\ Request for Rehearing of Kinder-Morgan at 11, quoting 
Order No. 637, 54 FR at 10201, III FERC Stats. & Regs. Regulations 
Preambles para.31,091 at 31,314.
---------------------------------------------------------------------------

    The Commission denies the requests to change the requirement that 
penalties be justified solely on the basis of system reliability. The 
pipelines themselves recognize that ``the fundamental purpose of 
penalties and OFOs is to protect the reliability of service to all 
shippers * * * '' \155\ It was precisely this purpose that the 
Commission recognized in Order No. 636, when it permitted pipelines to 
develop and utilize OFOs and penalties as system management tools. 
Thus, the requirement that pipelines impose penalties ``only to the 
extent necessary to prevent the impairment of reliable service'' simply 
reflects a formalized requirement that pipelines use penalties 
exclusively for their intended purpose. The Commission is not 
permitting pipelines to impose penalties for other purposes, such as 
the enforcement of contractual obligations, where unrelated to system 
reliability. The Commission has determined that shippers should be 
given the flexibility to exceed contractual limitations, unless such 
action jeopardizes system reliability and integrity. For example, if a 
shipper overruns its contractual entitlement, and its action does not 
affect the reliability of the pipeline's service, there is no reason 
for the pipeline to charge a penalty. Of course, however, the pipeline 
may charge the shipper for the additional transportation service.
---------------------------------------------------------------------------

    \155\ Request for Rehearing of Kinder-Morgan at 8.
---------------------------------------------------------------------------

    The question whether penalties may be imposed during non-critical 
periods needs to be determined in the pipelines' compliance filing 
proceedings and cannot be decided in the abstract. Contrary to Kinder-
Morgan's statement, the Commission did not find that penalties are 
``not required.'' \156\ The Commission reiterates that penalties may be 
required, especially during critical periods when system reliability is 
most in jeopardy. With respect to penalties during non-critical 
periods, the Commission stated, ``[u]nder the regulations adopted in 
this rule, pipelines will only be able to impose penalties to the 
extent necessary. This requirement may result in either no penalties 
for non-critical days or higher tolerances and lower penalties for non-
critical as opposed to critical days.'' \157\ The Commission will 
examine such issues in the individual compliance filing proceedings, 
where the Commission can evaluate how the proposed imbalance management 
services, OFO provisions, and penalty structures all work together, as 
an overall program of system management.
---------------------------------------------------------------------------

    \156\ Kinder-Morgan relies on the following statement by the 
Commission, but misinterprets it: ``First, penalties are not 
required, but to the extent that a pipeline assesses penalties, they 
must be limited to only those transportation situations that are 
necessary and appropriate to protect against system reliability 
problems.'' Order No. 637, 54 FR at 10201, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,314. This first clause of 
the statement was intended to clarify that the Commission was not 
requiring pipelines to include penalties in their tariffs or to 
impose penalties on their shippers, and was not an affirmative 
finding on the merits that penalties are not required.
    \157\ Order No. 637, 54 FR at 10202, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,317 (emphasis added).
---------------------------------------------------------------------------

    c. Crediting of Penalty Revenues. Only Koch and CNGT seek rehearing 
of the Commission's decision to require pipelines to credit penalty and 
OFO revenues, net of costs, to shippers. Koch argues that crediting the 
penalty and OFO revenues weakens the deterrent function of penalties, 
which are designed and have been implemented to deter abusive shipper 
behavior. Koch maintains that there is nothing inherently wrong with 
shippers being punished for their inappropriate actions. Koch asserts 
that requiring the penalty revenue to go back to the shippers, 
offending or not, is unwarranted because they have not assumed any of 
the risks that warrants receipt of such compensation. Koch states that 
penalties are designed to compensate pipelines for the risks they face 
from a shipper that is outside the parameter of the pipeline's tariff. 
Koch also claims that the Commission's concern about penalties being 
profit centers for pipelines is not applicable on all pipelines. Koch 
states that it has received virtually no penalty revenue since its 
Order No. 636 tariff became effective.
    CNGT seeks rehearing of the requirement to credit penalty revenues 
if the Commission continues to strictly limit penalties to reliability 
needs.
    The goal of the Commission's new policy on penalties is to 
encourage pipelines to rely less on penalties and more on non-penalty 
mechanisms to manage their systems, such as imbalance management 
services, and to design and impose only necessary and appropriate 
penalties. Allowing pipelines to retain the revenues from penalties 
provides pipelines with a financial incentive to impose penalties where 
they may not be required to ensure system reliability, or to set 
penalties at inappropriate levels. It also can discourage pipelines 
from developing the other, non-penalty mechanisms that might give 
shippers positive incentives to control their imbalances. Therefore, 
the Commission must require the crediting of penalty and OFO revenue to 
eliminate the financial incentive that retention of penalty revenue 
provides the pipeline. Only by removing this incentive will pipelines 
begin to rely on other management techniques and use penalties less. 
Thus, the Commission

[[Page 35742]]

reemphasizes that the crediting of penalty and OFO revenues to firm 
shippers is necessary to eliminate the pipelines' incentive to utilize 
penalties.
    The Commission recognizes that penalties serve a deterrent 
function. The deterrent function is a legitimate function where the 
penalty is narrowly designed to protect the integrity of the system. 
The crediting of penalty revenues arguably will weaken the deterrent 
function, as Koch maintains, only to the extent significant revenue is 
credited back to the offending shippers. While the Commission is not 
requiring that the revenue be credited exclusively to non-offending 
shippers, the Commission's objective is that where possible, pipelines 
should credit the revenue only to non-offending shippers.\158\ Further, 
while Koch is correct that there is nothing inherently wrong with using 
a punishment such as a penalty as a deterrent, the Commission has 
determined that a more effective and less restrictive way for pipelines 
to maintain control of their systems is for pipelines to rely on 
services and incentives that enable and encourage shippers to behave 
appropriately without the threat of punishment.
---------------------------------------------------------------------------

    \158\ The Commission stated in Order No. 637 that ``[i]deally, 
penalty revenues should be credited only to non-offending 
shippers.'' Order No. 637, 54 FR at 10201, III FERC Stats. & Regs. 
Regulations Preambles para. 31,091 at 31,315.
---------------------------------------------------------------------------

    Several pipelines request clarification of the revenue crediting 
requirement. Coastal requests the Commission to clarify that a 
pipeline's responsibility to credit penalty revenues is net of any 
costs incurred (i.e. demand credits to customers whose service was 
curtailed) or revenues foregone by pipeline as a result of the actions 
which resulted in penalty being assessed. Similarly, Tejas requests the 
Commission to clarify that OBA charges may be netted against any 
penalty revenue. In addition, Paiute requests clarification that under 
the cost netting exclusion, it will be permitted to retain scheduling 
penalty revenues that it assesses to its shippers during Northwest 
Pipeline Corporation's Declared Entitlement Periods because the 
Northwest penalties assessed Paiute during Declared Entitlement Periods 
represent a cost to Paiute. Finally, Enron requests clarification that 
the revenue crediting mechanisms take into account penalty revenues 
included in developing underlying rates. Enron maintains that until a 
pipeline's next general rate case, crediting should only be required 
with respect to net penalty proceeds that exceed any amounts included 
in developing existing rates (whether through an allocation or though 
the inclusion of representative penalty levels). Otherwise, states 
Enron, the double counting of penalty revenues would result.
    These issues may depend on the facts of individual cases. Pipelines 
that seek to net out costs incurred as a result of a shipper's actions 
that caused the penalty to be assessed must demonstrate that the 
shipper's conduct in fact caused such costs. Similarly, pipelines 
seeking to offset penalty revenues included in developing underlying 
rates should include in their compliance filings a detailed description 
of how penalty revenues were included in designing their rates. The 
Commission will consider these matters, along with other factors, to 
determine the appropriate revenue crediting in each case.
    Coastal requests the Commission to allow pipelines to establish a 
surcharge mechanism in their tariffs to impose surcharges on customers 
who receive penalty credits to allow the pipelines to recover those 
credits if additional costs are found attributable to the penalty event 
after the refund is made. The Commission will not allow pipelines to 
establish a surcharge mechanism to recoup revenue credits from firm 
customers to recover additional costs discovered after-the-fact. The 
Commission expects pipelines to build into their revenue crediting 
mechanisms a reasonable amount of time in which to accurately determine 
the true level of costs and revenues before actually crediting the 
revenues.
    Koch asks for clarification in a number of respects on how to 
implement revenue crediting on its system. The Commission is not 
requiring any particular revenue crediting mechanism; pipelines may 
propose whatever implementation mechanism is best for their systems. 
The Commission will address any questions regarding the implementation 
of revenue crediting in the individual pipeline compliance proceedings.
    d. Other Requests for Clarifications. A number of rehearing 
applicants request clarification with respect to what constitutes a 
``penalty.'' \159\ For example, the Industrials seek clarification that 
Order No. 637 applies to all operational limits that have punitive or 
disciplinary effects and to any tariff provision that may trigger an 
additional charge or punitive action to shippers. Tejas seeks 
clarification whether a tiered cash-out program constitutes a penalty, 
and Koch questions whether unauthorized gas overrun charges are 
penalties. Keyspan requests clarification whether pipelines are 
required to explain all penalties, or just imbalance penalties.
---------------------------------------------------------------------------

    \159\ Requests for Rehearing of Industrials, Keyspan, Koch, and 
Tejas.
---------------------------------------------------------------------------

    The Commission considers a penalty to be any charge imposed by the 
pipeline on a shipper that is designed to deter shippers from engaging 
in certain conduct and reflects more than simply the costs incurred as 
a result of the conduct. Thus, the term ``penalty'' was intended to 
encompass more than just imbalance penalties, and includes, for 
example, scheduling, OFO, and unauthorized overrun penalties, as well.
    While a tiered cash-out program is a penalty mechanism, a cash-out 
mechanism that only requires the shipper to reimburse for the cost of 
gas provided by the pipeline is not a penalty. However, some shippers 
allege that certain pipelines' cash-out mechanisms operate as 
penalties.\160\ Therefore, the Commission expects pipelines to include 
in their pro forma compliance filings their cash-out provisions, in 
addition to their provisions for imbalance management services, netting 
and trading, OFOs and penalties. The Commission cannot evaluate the 
components of a pipeline's system management program, such as the cash-
out mechanism, in isolation. The Commission must consider the imbalance 
services, and netting and trading, OFO, and penalty provisions together 
to evaluate how they function together in light of the pipeline's 
characteristics. This evaluation will occur in the individual 
compliance filing proceedings.
---------------------------------------------------------------------------

    \160\ Request for Rehearing of Industrials at 72.
---------------------------------------------------------------------------

III. Reporting Requirements for Interstate Pipelines

A. Transactional Information

    To equalize the reporting requirements for capacity release 
transactions and pipeline transactions, and to simplify the overall 
reporting system, Order No. 637 required pipelines to report the same 
transactional information about both their own firm and interruptible 
transactions, and their released capacity transactions, and established 
a single, new reporting requirement for this transactional information. 
Section 284.13(b)(1) requires the pipeline to post transactional 
information on its Internet web site contemporaneously with the 
execution or revision of a contract for firm service. For interruptible 
transportation, section 284.13(b) requires pipelines to post the 
information on a daily basis. Further, pipelines are required to keep 
this firm and interruptible transactional information available on 
their web sites

[[Page 35743]]

for 90 days, and to archive this information for a period of three 
years after the 90-day period expires.\161\
---------------------------------------------------------------------------

    \161\ 18 CFR 284.12(c)(3)(v).
---------------------------------------------------------------------------

    Rehearing requests have been filed concerning the new transactional 
reporting requirements on two main grounds `` confidentiality and 
burden. With respect to confidentiality, as described more fully below, 
the rehearing applicants, largely marketers, essentially argue that the 
information in the new transactional reports is commercially sensitive 
information, which if disclosed publicly and, particularly, 
contemporaneously with the transaction, will cause competitive harm to 
shippers. With respect to burden, the pipeline applicants maintain that 
the magnitude of the information required to be reported is burdensome 
to the pipelines. In addition, rehearing applicants seek revision or 
clarification of certain of the specific transactional data elements.
    The reporting of detailed transactional information is necessary to 
provide shippers with price transparency for informed decisionmaking, 
and the Commission and shippers with the ability to monitor 
transactions for undue discrimination and preference. The need for more 
informed decisionmaking capabilities and the ability to monitor for 
undue discrimination arises because the Commission is making changes in 
the way it regulates the natural gas industry, fostering competition 
where it can and moving toward lighter-handed regulation where it can. 
Specifically, the Commission is removing the rate cap from short-term 
capacity releases, and thus will be relying on competitive forces, as 
well as some regulatory controls, to protect against the exercise of 
market power. As a result, it becomes increasingly important to provide 
good transactional information to facilitate competition for pipeline 
capacity and between pipeline capacity and released capacity, and to 
monitor the market for potential undue discrimination or preference.
    The disclosure of greater information regarding capacity 
transactions is necessary to achieve these dual goals of fostering 
competition and market monitoring. To foster competition, it is not 
sufficient merely to ensure there are multiple competitors, there also 
needs to be good information to enable buyers to make informed choices 
among the competitors. As the Commission explained in Order No. 637 
\162\ in discussing the removal of the short-term capacity release rate 
ceiling:

    \162\ Order No. 637, 65 FR at 10184, III FERC Stats. & Regs. 
Regulations Preambles para. 30,091 at 31,283.
---------------------------------------------------------------------------

    Difficulty in obtaining information can reduce competition 
because buyers may not be aware of potential alternatives and cannot 
compare prices between those alternatives. The reporting 
requirements will expand shippers' knowledge of alternative capacity 
offerings by providing more information about the capacity available 
from the pipeline as well as those shippers holding capacity that is 
potentially available for release. The reporting requirements 
further will provide shippers with more accurate information about 
the value of capacity over particular pipeline corridors so that 
shippers can make more informed choices about the prices of capacity 
they may wish to purchase.

In addition, requiring detailed information about pipeline transactions 
to be reported, where very little had previously been required, will 
increase and improve competition by equalizing the information 
available to the market for capacity release transactions and pipeline 
transactions. Since pipeline capacity and released capacity now compete 
head-to-head, shippers must have the same information about both. 
Further, the reporting of increased information on pipeline 
transactions is important to enable pipeline service pricing to 
discipline capacity release pricing, acting as a check on any market 
power in the secondary market.
    Reporting of data associated with capacity transactions is also 
critical to monitoring the market for undue discrimination or 
preference. The more detailed transactional information that is made 
available to market participants and the Commission, the better able 
both shippers and the Commission will be to identify situations in 
which market power is being abused, and the information will enable the 
Commission to tailor specific remedies. Moreover, the reporting of 
detailed transactional information is necessary not only for the 
monitoring of the current market for abuses of market power, but also 
for the Commission to assess the need for further regulatory reforms in 
the future.
    As discussed further below, because of the importance of detailed 
transactional information for market monitoring and informed 
decisionmaking, the Commission generally is denying the rehearing 
requests that object to the new transactional reporting requirements on 
the basis of confidentiality and burden. However, the Commission is 
granting rehearing of the requirement that the firm transactional data 
must be posted contemporaneously with contract execution. The 
Commission is adjusting the timing of disclosure to require firm and 
interruptible transactional data to be posted no later than the first 
nomination for service.
1. Confidentiality
    a. Need for Transactional Information. Columbia Gulf argues that 
the Commission has not justified the need for requiring the disclosure 
of confidential information. Columbia Gulf asserts that the 
Commission's finding that disclosure of detailed transactional 
information is necessary to provide shippers with improved 
decisionmaking and monitoring abilities is unsupported.\163\ Columbia 
Gulf also questions why the Commission is requiring the detailed 
transactional information in light of the fact that natural gas 
commodity costs are already publicly available and widely scrutinized, 
and the industry itself, through GISB, has already determined the 
information that needs to be posted.
---------------------------------------------------------------------------

    \163\ For example, Columbia Gulf disputes the Commission's 
statement that ``[s]hippers need to know the price paid for capacity 
over a particular path to enable them to decide, for instance, how 
much to offer for the specific capacity they seek.'' Order No. 637, 
65 FR at 10206, III FERC Stats. & Regs. Regulations Preambles para. 
30,091, at 31,324. Request for Rehearing of Columbia Gulf at 5. 
Williston Basin also disputes this point. Request for Rehearing of 
Williston Basin at 7.
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    As the Commission explained above, the reporting of detailed 
transactional information is necessary because the Commission is 
modifying its method of regulating the natural gas industry by 
replacing traditional regulatory controls, such as the price cap on 
short-term capacity releases, with competition. Thus, greater 
transactional information is necessary to ensure that competition 
flourishes, and that market power and undue discrimination remain in 
check in the new competitive environment. To the extent that Columbia 
Gulf maintains that improved decisionmaking and market monitoring can 
occur without requiring greater information, the Commission finds it 
axiomatic that greater, more complete and detailed information about 
transactions will greatly improve shippers' ability to make informed 
decisions, and both the shippers' and the Commission's ability to 
monitor the market.
    Further, while natural gas commodity costs are publicly available, 
as Columbia Gulf notes, information about transportation transactions, 
particularly transportation prices, is necessary to effectively 
evaluate the information about gas prices. Finally, the Commission will 
not defer to GISB with respect to the information that the industry 
needs. GISB is not a regulatory body and the market is not self-
regulating.

[[Page 35744]]

    b. Competitive Harm. Several marketers and two pipelines seek 
rehearing of the Commission's decision to require pipelines to publicly 
post data about their capacity transactions, such as shipper names, 
individual contract numbers, and receipt and delivery points.\164\ They 
argue that such data are confidential information, and if publicly 
disclosed, will create unfair competition and competitive harm.
---------------------------------------------------------------------------

    \164\ Requests for Rehearing of Columbia Gulf, Dynegy, NEMA, 
Williston Basin, and Cibola.
---------------------------------------------------------------------------

    For example, Columbia Gulf argues that marketing strategies for 
both pipelines and shippers would be revealed, and bundled sales 
activity would increase, resulting in decreased price transparency and 
competition. Dynegy and NEMA argue that by tracking chain of title from 
individual contract number and receipt and delivery points, shippers 
will be able to learn immediately of other shippers' supply sources and 
markets. They argue that the knowledge of other shippers' supply 
sources and markets and the rates shippers pay for transportation will 
enable shippers to undercut one another's transactions. Thus, Dynegy 
and NEMA argue that the disclosure of the transactional information 
will seriously threaten the continued development of competitive gas 
markets and pose great risks to gas marketers whose business relies on 
fashioning creative packages of services at competitive prices.\165\
---------------------------------------------------------------------------

    \165\ Request for Rehearing of Dynegy at 20 and Request for 
Rehearing of NEMA at 9.
---------------------------------------------------------------------------

    Williston Basin argues that the posting of the transactional 
information will enable shippers to know their competitors' supply and 
markets, and what other shippers are paying, which might prevent 
Williston Basin from being able to negotiate the best price for the 
services it offers. In addition, some rehearing applicants, most 
notably Columbia Gulf and Williston Basin, assert that the Commission 
in Order No. 637 has failed to balance the benefits of disclosure of 
confidential information against the harm that would be caused by 
divulging the commercially sensitive information.
    Most of the rehearing applicants objecting to the new transactional 
reporting requirements on the basis of confidentiality request that the 
Commission either exclude the commercially sensitive data from that 
required to be reported, allow pipelines to file the transactional 
information only with the Commission under protected status, or delay 
the posting of the information so it is not required to be posted 
contemporaneously with the execution of the contract.
    The Commission remains unpersuaded that the information in the 
transactional reports is commercially sensitive data that are entitled 
to confidential treatment. Section 4 of the Natural Gas Act and the 
NGA's general statutory scheme clearly contemplates full disclosure of 
contractual terms and prices, as a means of preventing undue 
discrimination. Section 4(b) of the NGA provides that no natural-gas 
company may, with respect to any jurisdictional transportation or sale 
of natural gas, ``make or grant any undue preference or advantage to 
any person or subject any person to any undue prejudice or 
disadvantage,'' or ``maintain any unreasonable difference in rates, 
charges, service, facilities, or in any other respect, * * *'' \166\ 
The immediately following section, section 4(c),\167\ sets forth the 
means for ensuring that such undue discrimination or preference does 
not occur:
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    \166\ 15 U.S.C. 717(c) (1994).
    \167\ Id. (emphasis added).

    Under such rules and regulations as the Commission may 
prescribe, every natural-gas company shall file with the Commission, 
within such time * * * and in such form as the Commission may 
designate, and shall keep open in convenient form and place for 
public inspection, schedules showing all rates and charges for any 
transportation or sale subject to the jurisdiction of the 
Commission, and the classifications, practices, and regulations 
affecting such rates and charges, together with all contracts which 
in any manner affect or relate to such rates, charges, 
---------------------------------------------------------------------------
classifications, and services.

    Although the NGA gives the Commission some discretion with respect 
to how to provide for the disclosure of rate schedules and contracts, 
clearly the public disclosure of rate schedules and related contracts, 
in some manner, is required.
    Under new section 284.13(b) of the regulations, the Commission is 
requiring pipelines to post the following data: the name and 
identification number of the shipper receiving service under the 
contract, the contract number, the rate charged under each contract, 
the maximum rate, the duration of the contract, the receipt and 
delivery points and zones or segments covered by the contract, the 
contract quantity or volumetric quantity, special terms and conditions 
applicable to a capacity release and special details pertaining to a 
transportation contract, and whether there is an affiliate relationship 
between the pipeline and the shipper or between the releasing and 
replacement shipper. As is evident, the transactional information the 
Commission is requiring to be reported, and that those requesting 
rehearing want to remain confidential, is for the most part information 
that either is an inherent part of, or included in, the very 
transportation contracts the NGA requires to be disclosed. The 
affiliate relationship is the only piece of information required that 
may not necessarily be reflected in the contract. However, those 
requesting rehearing do not argue that that particular data element is 
commercially sensitive data.
    Therefore, as the Commission held in Order No. 637, the posting of 
the transactional information is entirely consistent with the NGA's 
statutory framework intending for contracts to be publicly disclosed. 
Significantly, no party on rehearing has taken issue with the 
Commission's view of these statutory requirements.
    Further, the full disclosure of all of the key contractual 
information--shipper name, contract number, contract quantity, rate 
charged, and receipt and delivery points--is consistent with the 
Commission's policy direction toward transparency in the market. The 
Commission has determined that the disclosure of information, rather 
than its concealment, will best help the market to function more 
efficiently and competitively, to the ultimate benefit of natural gas 
consumers.
    The rehearing applicants allege that competitive harm will result, 
generally to individual firms, from the public disclosure of the 
transactional information. However, the Commission is unconvinced that 
the disclosure will result in competitive harm substantial enough to 
outweigh the pro-competitive and market monitoring purposes for which 
both the NGA and the Commission require the information to be 
disclosed.\168\ The pipelines, those from whom the information would be 
obtained, do not explain precisely how competition will be harmed. 
Columbia Gulf tersely states that the marketing strategies of pipelines 
and shippers would be revealed. Williston Basin essentially argues that 
it will become

[[Page 35745]]

more difficult for it to negotiate the best price for its services. The 
marketers, Dynegy and NEMA, focus on potential competitive disadvantage 
from the perspective of a service provider, but do not consider the 
benefits that they may realize as pipeline customers from the 
availability of transactional information. Thus, while disclosure of 
the transactional information may cause some commercial disadvantage to 
individual entities, it will benefit the market as a whole, by 
improving efficiency and competition. Buyers of services need good 
information in order to make good choices among competing capacity 
offerings. Without the provision of such information, competition 
suffers.
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    \168\ Part of the standard, as relevant here, for determining 
whether information is privileged or confidential employed under the 
Freedom of Information Act (5 U.S.C. 552), as amended by the 
Electronic Freedom of Information Act Amendments of 1996, 5 U.S.C.A. 
552 (West Supp. 1997), and followed by the Commission when 
evaluating requests for confidential treatment, is whether the 
disclosure of the information is likely ``to cause substantial harm 
to the competitive position of the person from whom the information 
was obtained.'' National Parks and Conservation Ass'n v. Morton, 498 
F.2d 765, 770 (D.C. Cir. 1974). See section 388.112 of the 
Commission's regulations, governing requests for privileged 
treatment. 18 CFR 388.112.
---------------------------------------------------------------------------

    Further, pipelines have been required to post for capacity release 
transactions virtually all of the information that they must now post 
regarding their own capacity transactions. However, no competitive harm 
has been alleged from the disclosure of the capacity release 
transactional data. Nor do any of the rehearing applicants argue that 
pipeline transactions require greater confidentiality than capacity 
release transactions.
    The Commission recognizes that previously, during the time when 
pipelines were still natural gas merchants, the Commission allowed 
pipelines' negotiated gas sales rates to remain confidential from 
unregulated competitors.\169\ The Commission recognized that in 
situations where pipelines were competing with other entities that were 
not required to disclose the same data, the pipelines could be 
commercially disadvantaged. Thus, to minimize such potential harm, the 
Commission made an accommodation with respect to the disclosure of the 
data. However, here, the Commission is requiring the disclosure of the 
same information for all segments of the industry. Therefore, there is 
no need in this instance for the Commission to make the same compromise 
with respect to public disclosure. Nevertheless, some of the 
competitive disadvantages that the rehearing applicants foresee will be 
tempered by the Commission's elimination, below, of the requirement 
that the transactional information must be posted contemporaneously 
with contract execution.
---------------------------------------------------------------------------

    \169\ Natural Gas Pipeline Co. of America, 55 FERC para. 61,416 
at 62,245-46 (1991); and El Paso Natural Gas Co., 57 FERC para. 
61,273 at 61,881-82 (1991) (permitting negotiated gas sales rates to 
remain confidential from unregulated competitors in the context of 
gas inventory charge settlements).
---------------------------------------------------------------------------

    In sum, the Commission remains unclear precisely how either the 
pipelines, marketers, or the market as a whole will be substantially 
harmed by the disclosure of the transactional information. On the other 
hand, the Commission is convinced that to foster a competitive market, 
shippers need good information about their capacity alternatives. 
Accordingly, the Commission will neither eliminate any of the required 
information from the transactional report, nor confer confidential 
status on the information to be provided, on the basis of the 
allegations about potential competitive harm made here.
    c. Timing of the Posting of Transactional Information. Section 
284.13(b)(1) provides that pipelines must post the firm transactional 
information ``contemporaneously with the execution or revision of a 
contract for service.'' Several rehearing requests contend the 
Commission erred in requiring that the transactional information for 
firm transactions must be posted contemporaneously with contract 
execution.\170\
---------------------------------------------------------------------------

    \170\ Requests for Rehearing of Cibola, Dynegy, NEMA, Koch, 
INGAA and Enron.
---------------------------------------------------------------------------

    INGAA and Enron maintain that the requirement to post transactional 
information contemporaneously with contract execution puts pipeline 
services at a disadvantage compared to prearranged deals for released 
capacity. They point out that prearranged deals must be posted one hour 
prior to the first nomination deadline on the day before gas flows, 
well after the prearranged deals are executed.\171\ Therefore, they 
request the transactional information required in section 284.13(b)(1) 
to be posted on the same timeline as prearranged deals.
---------------------------------------------------------------------------

    \171\ GISB Capacity Release Standard 5.3.2 (GISB Version 1.3, 
July 31, 1998).
---------------------------------------------------------------------------

    Cibola, Dynegy, and NEMA contend that immediate posting, 
contemporaneous with contract execution, is not necessary for the 
purpose of monitoring for undue discrimination, and that the Commission 
has failed to adequately consider the adverse competitive consequences 
of contemporaneous reporting of firm capacity transactions. Dynegy and 
NEMA argue the Commission should require that the posting not occur 
until at least one week after service under the contract begins. Koch 
requests that the Commission require the transactional information to 
be posted within 24 hours of gas flow, consistent with Koch's current 
posting of discounts on its Internet website.
    Conversely, Amoco argues that the Commission should reject any 
requests to delay the posting of the transactional information. Amoco 
argues that data must be filed contemporaneously with contract 
execution to have the desired mitigative and informational effects.
    The statutory scheme of the NGA contemplates that pipelines cannot 
revise their rates schedules and charges until they provide the 
Commission with 30 days advance notice of the proposed change.\172\ 
Most of the Commission's filing requirements reflect this statutory 
scheme, and require notice prior to the institution of service, rather 
than with respect to the execution of the contract. The Commission 
recognizes that contract execution may occur at a variety of different 
times in relation to when service takes effect. In some cases, the 
execution of a contract could occur significantly in advance of the 
commencement of service under the contract and in other cases it could 
occur after service commences.
---------------------------------------------------------------------------

    \172\ 15 U.S.C. 717(c)
---------------------------------------------------------------------------

    To establish a consistent standard for transactional reporting, the 
Commission will not use the contract execution date to trigger the 
reporting of information. The Commission will grant rehearing and 
change sections 284.13(b)(1) and (2) to require the transactional 
information for both firm and interruptible service to be posted no 
later than the first nomination for service under the agreement. This 
modification also will minimize the potential for harm that some 
rehearing applicants, such as Dynegy and NEMA, have argued could result 
from disclosure well in advance of service.
    The reporting of interruptible service needs to be somewhat 
different than that for firm service, because of differences in the 
form of contracting. Unlike firm service where the shippers' contract 
reflects the rate paid, shippers obtaining interruptible service 
frequently execute pro forma master contracts for interruptible service 
either at the maximum rate or without a specified rate. Shippers may 
not nominate under these master contracts for a period of time and 
often portions of those contracts, such as rate and other conditions, 
are modified by subsequent agreements between the pipeline and the 
shipper on a daily or monthly basis. For instance, a pipeline and 
shipper may agree to provide interruptible service for a particular 
month at discounted rate and that agreement may not be continued the 
next month. Therefore, with respect to interruptible service, the 
Commission is requiring a daily posting no later than the first 
nomination under an agreement for interruptible service. Any time a 
rate or other condition of the interruptible

[[Page 35746]]

agreement changes the pipeline must post the change.
    With these changes, the Commission will have achieved comparability 
between the reporting requirements for pipeline transactions and the 
reporting requirements for capacity release transactions, as INGAA and 
Enron request. The Commission is requiring the transactional reports 
for pipeline firm and interruptible transactions and capacity release 
transactions to be posted according to the same time frame previously 
used for capacity release service--no later than the first nomination 
for service.
    Postponing the time for posting of firm contracts may result in 
somewhat later disclosure of some contractual commitments. But the 
effects of such a delay on shippers' ability to obtain information 
about available capacity will be mitigated by other reporting 
requirements. Under section 284.13 (d), the pipeline is required to 
post all available firm capacity on its system. Once the pipeline 
enters into a contract committing firm capacity, the pipeline must 
amend its posting to reflect the fact that this capacity is no longer 
available, even if it does not immediately disclose who the purchaser 
is. On balance, the Commission finds that requiring posting no later 
than the first nomination under the change is more consistent with its 
general reporting requirements, creates parity between pipeline and 
capacity release transactions, and will still provide the Commission 
and the public with sufficient information about firm pipeline 
contracts and capacity release transactions.
    Finally, the Commission will not impose a later posting deadline 
for the transactional information, as some rehearing requesters have 
urged. First, posting no later than the deadline for service 
nominations is more consistent with the Commission's general regulatory 
scheme, as discussed above. And second, the transactional information 
is necessary for timely, informed decisionmaking; therefore, delaying 
the posting of the transactional report until after service commenced 
would limit the value of the transactional information for its intended 
purpose of current decisionmaking.
    d. Consistency With Prior Policy. Columbia Gulf asserts that the 
new transactional reporting requirements reflect an unexplained change 
in Commission precedent and policy because the Commission previously 
concluded in Order No. 581 \173\ that the same information now included 
in the transactional reports did not need to be included in the 
discount report and the Index of Customers. Columbia Gulf states that 
in Order No. 581 the Commission specifically found that it did not need 
to require pipelines to report the same level of transportation 
information that is posted for capacity release transactions in order 
to compare pipeline transactions with capacity release transactions 
because the benefit from such comparison would be outweighed by the 
risk of harm to pipelines and LDCs from the release of the commercially 
sensitive data. Columbia Gulf also states that in Order No. 581, the 
Commission determined that it could satisfy its obligations under the 
NGA without requiring the reporting of the additional information.
---------------------------------------------------------------------------

    \173\ Revisions to Uniform System of Accounts, Forms, 
Statements, and Reporting Requirements for Natural Gas Companies, 60 
Fed. Reg. 53019 (October 11, 1995), III FERC Stats. & Regs. para. 
31,026 (1995).
---------------------------------------------------------------------------

    As Columbia Gulf points out, at the time of Order No. 581, in 1995, 
the Commission found that virtually the same transactional information 
(e.g. receipt and delivery points) did not need to be reported in the 
Index of Customers and discount report, because the risk of harm from 
the release of the information outweighed the benefit that would be 
obtained from the proposed use of the information. In Order No. 637, 
the Commission has changed its policy focus and reporting objectives 
from those that existed at the time of Order No. 581, and as a result, 
now strikes the balance differently.
    One of the primary goals of the Order No. 581 rulemaking was to 
simplify and streamline the Commission's reporting requirements and to 
reduce the reporting burden on pipelines. The reporting requirements 
had not been updated in the ten years after the issuance of Order No. 
436 in 1985, and contained numerous outdated and unnecessary 
provisions. Also, Order No. 581 was issued at a time when pipelines 
filed rate cases more frequently than they do today. The Commission's 
focus at the time was directed toward accumulating a large amount of 
information through rate case filings. Thus, the Commission determined 
in Order No. 581 that the inclusion of the additional information in 
the discount report and Index of Customers was unnecessary to further 
the Commission's existing regulatory policies.
    However, the regulatory context of the Commission is now different 
than it was at the time of Order No. 581, and thus, requires different 
information to be reported. The Commission's waiver of the rate cap for 
capacity release transactions now necessitates that additional 
transactional information must be reported for the new purposes of 
facilitating informed decisionmaking and effective market monitoring. 
The additional information is especially necessary because pipelines 
now file rate cases only sporadically, if at all.
    Tellingly, part of the language of Order No. 581-A relied upon and 
cited by Columbia Gulf, makes clear that the Commission's consideration 
at that time of whether to supplement the existing reporting 
requirements with additional information was based on industry 
conditions at the time: ``The Commission found [in Order No. 581] that 
many items, such as the receipt and delivery points, extended beyond 
that which the Commission needs to receive from pipelines on a regular 
basis to regulate the natural gas industry today.'' \174\ In short, in 
the year 2000, the Commission has reconsidered its reporting needs and 
determined that better information is now needed both to promote a 
competitive market and to promote effective monitoring of that market.
---------------------------------------------------------------------------

    \174\ Revisions to Uniform System of Accounts, Forms, 
Statements, and Reporting Requirements for Natural Gas Companies, 61 
Fed. Reg. 8860 (March 6, 1996), III FERC Stats. & Regs. para. 31,032 
at 31,551 (1996) (emphasis added).
---------------------------------------------------------------------------

    e. Burden. Columbia Gulf argues that the transactional reporting 
requirements impose an undue burden on interstate pipelines. Columbia 
Gulf disagrees with the Commission's statement in the Final Rule that 
the amount of new information is ``not an extensive amount of 
information compared to what is already provided.'' \175\ It maintains 
that six new categories of information is a significant burden given 
that the preexisting Index of Customers required only five categories 
of information, and the discount report, only four categories. Columbia 
Gulf further asserts that the inclusion of receipt and delivery points 
or zones or segments in which capacity is held under contract creates 
an undue administrative burden on pipelines because many contracts 
contain multiple receipt and delivery points, which combine to create 
many transportation paths.
---------------------------------------------------------------------------

    \175\ Order No. 637, 65 FR at 10207, III FERC Stats. & Regs. 
Regulations Preambles para. 30,091, at 31,326.
---------------------------------------------------------------------------

    Williams and Williston Basin, also, argue that the posting of 
transactional information will be burdensome. Williams alleges that 
contrary to the Commission's finding, for some information such as the 
affiliate relationship between releasing and

[[Page 35747]]

replacement shippers and special details pertaining to a pipeline 
transportation contract, it is not just a simple matter of developing a 
method of displaying the data, because either the data are not 
routinely maintained, or are maintained manually. Williston Basin 
maintains that the Commission is wrong that it will not be difficult 
for pipelines to adapt their already existing capacity release data 
sets to apply to pipeline transactions. Williston Basin asserts that 
its capacity release data sets are not readily adaptable, but will 
involve extensive programming that will be an expensive and onerous 
task.
    The new transactional reporting requirements will impose some 
additional burden on pipelines. While Columbia Gulf is correct that the 
Commission is creating new categories of information, the new 
information is already collected, in one form or another, by the 
pipeline. All of it is information that the pipeline already has in its 
possession, and thus, the transactional reporting requirements do not 
impose an additional burden on the pipelines to collect information.
    Although the Commission acknowledges that the task of creating new 
formats for displaying the information on the pipelines' Internet web 
sites will be involved for some pipelines, nevertheless, it is a one-
time reprogramming burden that, once completed, will enable the 
required data to be posted automatically. As such, the level of posting 
burden should not vary with the quantity of data to be posted under 
each data element. The Commission finds that the benefits achieved from 
the ongoing disclosure of the transactional information far outweigh 
the one-time burden of establishing the electronic reporting formats.
    In addition, the interruptible transaction reporting burden should 
not be excessively burdensome because the Commission did not require 
actual transactional data to be posted daily, such as the quantity 
actually shipped and the receipt and delivery points actually used. The 
rate for interruptible service is a volumetric rate, under which a 
shipper may or may not ship at all. Thus, as explained more fully in 
the next section below, the Commission in Order No. 637 required that 
pipelines post only the quantity the shipper is entitled to ship, and 
not the amount actually flowing each time service is nominated under 
the interruptible service agreement. Therefore, a transaction for 
interruptible service on a monthly basis could be initially posted, and 
assuming it was not changed, could remain posted for the month without 
needing to be reposted on a daily basis.
    f. Miscellaneous Requests for Rehearing and Clarification.
    Transactional Reports for Interruptible Services: The report for 
interruptible transactions established by Order No. 637 requires 
pipelines to post on a daily basis, among other things, ``the quantity 
of gas the shipper is entitled to transport,'' and ``the receipt and 
delivery points and zones or segments covered by the contract over 
which the shipper is entitled to transport gas.'' \176\ Great Lakes 
requests the Commission to require the new interruptible reporting 
requirements to provide for the reporting of actual service data, 
rather than the contractual quantities and points agreed to by the 
pipeline.
---------------------------------------------------------------------------

    \176\ 18 CFR 284.13(b)(2)(iv) and (v).
---------------------------------------------------------------------------

    Great Lakes argues that the contractual data Order No. 637 requires 
will not provide the current pricing information that the Commission 
has determined shippers need. Great Lakes states that on the discount 
report, pipelines were only required to report discounts that were 
actually assessed a shipper for interruptible transportation service, 
and were not required to report discounts that were agreed to by the 
pipeline, but never utilized by the shipper. Great Lakes also argues 
that because interruptible contracts often list all points on the 
system as primary points available for interruptible service 
nominations by the shipper, it is not clear what maximum or charged 
rate to reflect on the pipeline's report. It further states that only 
those points where interruptible service is available on the system on 
a given day are actually available to that interruptible shipper.
    The Commission's requirements for posting information about 
interruptible transactions are designed to provide information similar 
to that provided for firm service. For firm service, the Commission is 
requiring the posting of the rate the shipper pays, the volumes the 
shipper is eligible to ship under the contract, and the points included 
in the contract. The Commission is not requiring that pipelines provide 
actual quantities shipped or points used on a daily basis for firm 
transactions.
    Interruptible service, by nature, is different than firm service, 
and the process of arranging interruptible service transactions differs 
from firm contracting. Interruptible shippers do not sign contracts 
with specific contract demand limitations, as firm shippers do. 
Interruptible customers frequently sign pro forma or master contracts 
with the pipelines that do not specify a rate or that permit the 
interruptible rate to vary and that lists all receipt and delivery 
points on the system. The pipeline and the shipper may then reach 
agreement on a monthly or daily basis as to the rate to be paid for the 
month and the quantity and receipt or delivery points to which that 
rate applies.\177\ For instance, the pipeline and shipper may reach 
agreement that for a discount rate of $0.50/Dth the shipper can 
nominate up to 10,000 Dth/day between certain receipt and delivery 
points.
---------------------------------------------------------------------------

    \177\ Many pipelines, for example, allocate interruptible 
capacity based on rate paid and allow interruptible shippers to 
increase their rate in order to obtain a greater allocation of 
interruptible service.
---------------------------------------------------------------------------

    In order to create parity between the reports for firm and 
interruptible service, the Commission, therefore, is requiring that, 
for interruptible service, pipelines post on a daily basis prior to the 
first nomination under such an agreement, the rate the interruptible 
shipper is being charged, the quantities the shipper is eligible to 
ship, or the pipeline is willing to ship, at that rate and the receipt 
or delivery points between which the rate is applicable. It is the 
terms of the subsidiary agreement between the pipeline and the shipper, 
not the master contract that must be posted. Under this approach, the 
pipeline could post the interruptible agreement on the first of the 
month and simply leave that posting as long as the rate or other 
aspects of the agreement have not changed. But once those agreements 
have changed, the pipeline would have to repost the transaction.
    Because the Commission is not requiring the posting of daily 
throughput for firm service, it has determined not to require daily 
posting of throughput for interruptible service. The information 
required under this regulation will be sufficient to enable the 
Commission and shippers to monitor interruptible transactions. 
Pipelines will be required to post interruptible transactions whenever 
a rate or volume commitment changes, and other shippers can use such 
information to determine whether there has been undue discrimination in 
the awarding of interruptible service.
    The Commission further is revising the interruptible reporting 
requirements to eliminate confusion over precisely what points or rates 
are to be reflected on the posting. The regulation now reads ``the 
receipt and delivery points and zones or segments covered by the 
contract over which the shipper is entitled to transport gas.'' This 
language implies that the receipt or delivery points should be those in 
the master contract, rather than the points in the

[[Page 35748]]

subsequent agreement to provide interruptible service. Section 
284.13(b)(2)(iv) will be revised to require the posting of the receipt 
and delivery points over which the shipper is entitled to transport gas 
at the rate charged to make clear that the pipeline should post the 
receipt and delivery points in each individual agreement to provide 
interruptible service, not simply the receipt and delivery points in 
the master contract. It may be that some interruptible agreements 
permit shipment using all receipt or delivery points on the pipeline 
system and that is the information that should be posted. In other 
cases, however, interruptible transportation at a particular rate may 
be limited to certain receipt and delivery points in which case the 
posting should only include the limited points in the agreement.
    Scope of the Transactional Reporting Obligation: Cibola requests 
clarification that the transactional reporting requirements do not 
apply to existing pipeline capacity transactions that have remaining 
terms of one year or more.\178\ Cibola argues that requiring public 
disclosure of the price and terms of transactions negotiated at various 
times in the past will not serve the Commission's price transparency 
goals. Cibola further argues that requiring the details of existing 
long-term transactions to be posted will fundamentally alter the 
business and competitive risks that the parties understood they would 
face when they initially entered into the transactions.
---------------------------------------------------------------------------

    \178\ Request for Rehearing of Cibola at 5-7.
---------------------------------------------------------------------------

    The Commission agrees with Cibola that requiring the posting of 
pre-existing pipeline and capacity release transactions in the 
transactional reports is unnecessary, and was not the Commission's 
intent in Order No. 637. The transactional reporting requirement, both 
for pipeline and capacity release transactions, is prospective only as 
of the September 1, 2000 implementation date. The Commission clarifies 
that for all new firm contracts that are executed after September 1, 
2000, and existing contracts that are revised after that date, and for 
interruptible transactions taking place after that date, pipelines are 
required to post a transactional report no later than the first 
nomination for service under the new or revised contract. This is 
consistent with the Commission's regulation requiring that 
transactional reports only be posted for 90 days at which point the 
information is archived for a three year period and made available upon 
request.\179\
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    \179\ 18 CFR 284.13(b) (90 day posting); 18 CFR 284.12(c)(3)(v) 
(three year archiving requirement); 18 CFR 284.12(b)(v) (Capacity 
Release Standard 5.3.20 provides that historical data be made 
available within the Commission's archival periods).
---------------------------------------------------------------------------

    Historical information on pipeline transactions and capacity 
release transactions is available through other reporting requirements. 
The Index of Customers provides information about existing pipeline 
contracts. As discussed above, historical capacity release transactions 
have already been posted, and the posted information is required to be 
made available by the pipeline.
    Enron requests that the Commission clarify that the requirement 
that the pipeline post transactional information for revised contracts 
does not extend to shipper-initiated primary receipt and delivery point 
revisions within an effective contract.\180\ Enron asserts that 
requiring a new posting for each point change is redundant with other 
reports and will clutter the web sites.
---------------------------------------------------------------------------

    \180\ Request for Rehearing of Enron at 8-9.
---------------------------------------------------------------------------

    In the Commission's view, posting of primary receipt and delivery 
point changes is necessary so that other shippers can monitor those 
changes for undue preference or discrimination. Thus, the Commission 
will not change the requirement that amended contracts be posted.
    Enron also argues that pipelines should not be required to post 
contracts during a pending certificate proceeding, but only for 
capacity that is in service.\181\ Enron argues that the Commission 
already has established practices for requiring the disclosure of 
contracts in the certificate process, and that there is no benefit from 
requiring expansion contracts to be included in the firm transactional 
reports.
---------------------------------------------------------------------------

    \181\ Id. at 9.
---------------------------------------------------------------------------

    The Commission will not exempt expansion contracts from the 
transactional reporting requirement. However, since the Commission has 
revised the requirement that the transactional information be posted 
contemporaneously with contract execution to requiring posting no later 
than the first nomination for service, the reporting of expansion 
contracts should not be problematic.
    Modifications to Transactional Reporting Data Elements: Kinder-
Morgan requests the Commission to delete the requirement that pipelines 
report the contract number of each transportation transaction. Kinder-
Morgan states that the contact number enables the shipper to gain 
access to the pipeline's system for the purpose of making nominations, 
raising the prospect that one party could submit nominations using the 
contract number of another shipper, and thereby obtain transportation 
using someone else's capacity. The solution here is not for the 
Commission to eliminate the contract number, which is necessary for 
analytic purposes, but for the pipelines to establish computer security 
measures, such as the use of PINs or some other security features to 
protect their internal computer systems.
    Amoco requests the Commission to make three revisions to the 
regulatory text of section 284.13(b)(1) and (2). First, Amoco requests 
section 284.13(b)(1)(iii), referencing the rate charged under each 
contract, to be revised to state ``the rate charged under the contract 
and whether the rate is a negotiated rate.'' \182\ Amoco maintains that 
the purpose of its proposed change is to put all parties on notice in 
future rate cases as to whether the pipeline can seek a discount 
adjustment regarding the transaction. Section 284.13(b)(1)(viii) 
requires the posting of, ``special terms and conditions applicable to a 
capacity release and special details pertaining to a pipeline 
transportation contract.'' To clarify that negotiated rates must be 
disclosed, the Commission is revising the regulation to include a 
requirement that the pipeline disclose whether the contract is a 
negotiated rate. Negotiated rates also will be identified in the Index 
of Customers.
---------------------------------------------------------------------------

    \182\ Request for Rehearing of Amoco at 62.
---------------------------------------------------------------------------

    The second change Amoco requests is that the phrase ``special terms 
and conditions'' in section 284.13(b)(1)(iii) be revised to read 
``special terms and conditions, including all aspects in which the 
contract deviates from the pipeline's tariff,'' so that it will not be 
up to the reporting entity to decide what constitutes a special term or 
condition.\183\ The Commission agrees that including such a change will 
identify any transactions that deviate from the pipeline's tariff and 
will revise sections 284.13(b)(1)(vii) and 284.13(b)(2)(6) to require 
the disclosure of all aspects in which agreements deviate from the 
pipeline's tariff.
---------------------------------------------------------------------------

    \183\ Id.
---------------------------------------------------------------------------

    Amoco's third request is to modify the language, ``special details 
pertaining to a pipeline transportation contract'' in section 
284.13(b)(1)(viii) and the similar language in section 284.13(b)(2) 
governing interruptible transactional reporting, by adding the 
following explanatory language from the preamble of Order No. 637 to 
the regulatory text to eliminate any confusion: ``Under this 
requirement, a pipeline must report any special conditions attached to 
a discounted transportation contract, such as requirements for volume

[[Page 35749]]

commitments to obtain the discount.'' \184\ Also, Koch requests the 
phrase to be limited to terms and conditions from negotiated rates 
contracts that are already filed with the Commission, but have not been 
made available by other means.
---------------------------------------------------------------------------

    \184\ Id.
---------------------------------------------------------------------------

    The Commission agrees with Amoco that additional clarification is 
worthwhile and will add the following language to the requirements to 
post special details pertaining to the contract, ``including conditions 
attached to a discounted transportation contract,'' to provide 
additional clarification. However, there may be other special details 
pertaining to the contract that would need to be posted as well. Thus, 
the Commission denies Koch's request to limit the special details 
reported to terms and conditions from negotiated rate contracts. The 
Commission seeks more than just conditions attached to negotiated rates 
contracts. For instance, a key purpose of this data element is to 
obtain discount conditions, and thereby correct a deficiency in the 
existing discount report.
    Requests for Additional Data and Filing Requirements: IPAA requests 
the Commission to require pipelines to submit and post in addition to 
the data required under the new reporting requirements, information 
regarding the capacity actually used in each capacity release 
transaction. IPAA argues that for prearranged capacity release 
transactions to be completely transparent, shippers need enough 
information to determine whether even after a nomination and 
confirmation is made any gas actually moved. IPAA also requests that 
the Commission impose a transactional reporting requirement on capacity 
holders comparable to the pipeline's transactional reporting 
obligation, that would also include nominations, confirmations, and 
actual capacity used. IPAA asserts that the Commission must have 
adequate information to ensure that any available capacity is both 
offered and used.
    The Commission does not find it necessary to report the quantity of 
gas moved on a daily basis under firm pipeline contracts or capacity 
release contracts. The Commission did not previously require detailed 
information about quantities nominated for capacity release 
transactions and it is not evident why such information is necessary to 
effectively monitor such transactions for undue discrimination. The 
information that is most important for monitoring is the rate and 
contract conditions upon which the shipper acquired the capacity, not 
whether the shipper decided to use it on a particular day. Shippers may 
frequently acquire capacity, but, depending on weather and other 
conditions, determine that they do not need to use some or all of that 
capacity everyday. Their decision not to use capacity they have 
acquired does not necessarily indicate anticompetitive activity. Given 
the limited value of such information, the added burden of requiring 
the posting is not warranted.
    In addition, the Commission sees no basis for imposing a reporting 
obligation on capacity holders similar to the pipelines' transactional 
reporting requirement. Such information would largely duplicate the 
capacity release information that the pipelines are required to submit 
under the new transactional reporting requirements.
    Amoco requests the Commission to require pipelines to make a 
simultaneous electronic filing with the Commission when they post the 
data on their Internet web sites. Amoco argues that this is consistent 
with the filing requirements of section 4(d) of the NGA, and will 
encourage the filing of accurate data. The Commission finds it 
unnecessary to require a simultaneous electronic filing with the 
Commission. As discussed earlier, the NGA gives the Commission 
discretion in determining the timing and manner for filing and notice, 
and the Commission has determined that the requirements of section 4 
for public dissemination of rates and terms and conditions are better 
met by the posting of the rates and other transactional data on 
pipeline Internet web sites than by the filing and maintenance of the 
information by the Commission. Simultaneous electronic filing with the 
Commission is not necessary for the Commission to obtain the 
information it requires to monitor the market, since the Commission can 
download the files from the Internet postings and the pipeline's are 
required to maintain records of such information that the Commission 
may obtain if necessary.\185\
---------------------------------------------------------------------------

    \185\ 18 CFR 284.12(c)(3)(v) (3 year archiving requirement); 18 
CFR 250.16(d) (3 year requirement for maintaining discount 
information).
---------------------------------------------------------------------------

    Amoco also requests certain changes to the annual Form 2 reporting. 
The Commission did not provide notice to the industry that Form 2 could 
potentially be revised. As a result, modifications to the Form 2 go 
beyond the scope of this rulemaking proceeding.
    As stated in Order No. 637, the Commission is committed to 
reviewing all of its reporting requirements on an on-going basis and as 
part of its dialog with the industry. While the Commission cannot now 
see the need to expand the reporting requirements, as those requesting 
rehearing suggest, the Commission will be able to evaluate whether such 
additional information is needed as the Commission staff and the 
industry work with and review the information received under the 
current requirements.

B. Information on Market Structure

    In Order No. 637 the Commission explained that information on 
market structure enables the Commission to know who holds or controls 
capacity on each portion of the pipeline system, so potential sources 
of capacity can be identified, and shippers and the Commission can 
monitor for undue discrimination or preference. To give shippers a more 
useful picture of market structure, Order No. 637 expanded two of the 
Commission's pre-existing reporting requirements that provided 
information on market structure--the Index of Customers and the 
affiliate regulations.
1. Index of Customers
    Prior to Order No. 637, section 284.106(c)(3) of the regulations 
required pipelines to file an Index of Customers with the Commission, 
on the first business day of each calendar quarter, and to post the 
Index on their Internet web sites. The Index provides the names of 
shippers holding firm capacity, the amount of capacity held, the 
applicable rate schedule, and the contract effective and expiration 
dates. Order No. 637 added the following new information requirements 
to the existing Index of Customers: the receipt and delivery points 
held under the contract and the zones or segments in which the capacity 
is held; the common transaction point codes; the contract number; a 
shipper identification number, such as DUNS; an indication whether the 
contract includes negotiated rates; the names of any agents or asset 
managers that control capacity in a pipeline rate zone; and any 
affiliate relationship between the pipeline and the holder of capacity.
    Amoco requests the Commission also to require the rate charged and 
the maximum contract rate to be included in the Index of Customers. 
Amoco argues that such information is relevant not only for the 
purposes of the daily transactional report, but also for the purpose of 
the Index of Customers.
    The Commission disagrees, and will not add the maximum contract 
rate and actual rate charged to the Index of Customers. The purpose of 
the Index of Customers is to reveal the structure, or make-up, of the 
market for transportation capacity on a periodic

[[Page 35750]]

basis, to enable the Commission to assess the degree of competition on 
a pipeline or pipeline segments, and to detect potentially 
anticompetitive market dominance. Essentially, the Index of Customers 
shows who holds capacity on given pipeline, how much capacity is held 
by each shipper, where the capacity is held, the total amount of 
capacity held by a parent entity, and whether and the degree to which a 
pipeline's capacity is controlled by another entity, such as an asset 
manager. Price information is not directly relevant to the reason for 
requiring the index: to determine who and how much capacity shippers 
hold on the pipeline. Moreover, the rate charged and maximum contract 
rate are already obtained through the transactional reports.
2. Affiliate Regulations
    In Order No. 637, the Commission expanded its affiliate regulations 
to permit monitoring and self-policing of affiliate transactions. The 
Commission revised section 161.3(l) of the standards of conduct for 
interstate pipelines specifically to require pipelines with marketing 
affiliates or sales operating units to post certain information 
concerning their affiliates on their Internet web sites, and to update 
the information within three business days of any change. Under new 
section 161.3(l)(2), pipelines must post, and update within three 
business days of any change, a complete list of the names of operating 
personnel and facilities shared by the interstate pipeline and its 
marketing affiliate,\186\ and comprehensive organizational charts 
showing several different types of information.
---------------------------------------------------------------------------

    \186\ 18 CFR 161(l)(2)(i).
---------------------------------------------------------------------------

    First, the organizational charts must show the organizational 
structure of the parent corporation and the relative position within 
the corporate structure of the pipeline and all marketing 
affiliates.\187\
---------------------------------------------------------------------------

    \187\ 18 CFR 161.3(l)(2)(ii)(A).
---------------------------------------------------------------------------

    Second, the organizational charts must show business units, job 
titles, job descriptions, and chain of command for all positions within 
the pipeline, including officers and directors, with the exception of 
clerical, maintenance, and field positions. The job titles and 
descriptions must include the employee's title, duties, and an 
indication whether the employee is involved in transportation or gas 
sales. In addition, the pipeline must also include the names of 
supervisory employees who manage non-clerical employees involved in 
transportation or gas sales.\188\
---------------------------------------------------------------------------

    \188\ 18 CFR 161.3(l)(2)(ii)(B).
---------------------------------------------------------------------------

    Third, the organizational charts must indicate, for all employees 
shared by the pipeline and a marketing affiliate, the business unit or 
sub-unit within the marketing affiliate organizational structure in 
which the shared employee is located, the employee's name, the 
employee's job title, and job description within the marketing 
affiliate, and the employee's position within the chain of command of 
the marketing affiliate.\189\
---------------------------------------------------------------------------

    \189\ 18 CFR 161.3(l)(2)(ii)(C).
---------------------------------------------------------------------------

    Tejas seeks rehearing of the requirement for pipelines to post and 
update organizational charts showing the organizational structure of 
the parent corporation and the relative position within the corporate 
structure of the pipeline and all marketing affiliates, under section 
161.3(l)(2)(ii)(A), and the business units, job titles, job 
descriptions, and chain of command for all positions within the 
pipeline, under section 161.3(l)(2)(ii)(B).\190\ Tejas argues the 
Commission has not demonstrated that such information is needed to 
deter undue discrimination and preference and to help the market 
monitor affiliate transactions. Tejas maintains that these reporting 
requirements will simply clutter pipeline web sites with voluminous, 
irrelevant information, and will create a substantial posting and 
updating burden, especially for small pipelines such as Tejas.
---------------------------------------------------------------------------

    \190\ Request for Rehearing of Tejas at 6-8. Tejas does not seek 
rehearing of the new posting requirements applicable to employees 
shared by a pipeline and a marketing affiliate in section 
161.3(l)(2)(ii)(C).
---------------------------------------------------------------------------

    Posting detailed organizational charts will provide shippers and 
the Commission with current information regarding whether pipeline 
personnel are separated from marketing affiliate personnel to the 
maximum extent practicable. Posting such information allows shippers 
and the Commission to monitor whether employees with access to 
transportation and/or non-affiliated shipper information are shared 
with the pipeline's marketing affiliate(s).
    The Commission finds the posting of such information to be 
important. The requirements adopted here are similar to those adopted 
with respect to electric marketers and are necessary to permit 
monitoring of affiliate relationships. The Commission's pre-existing 
requirement in section 250.16(b)(1), that a pipeline maintain in its 
tariff a complete list of shared operating personnel and facilities, 
and update that list on a quarterly basis, has not been completely 
effective in achieving pipelines' complete disclosure of shared 
operating employees. Pipelines have not always disclosed the sharing of 
operating employees with their marketing affiliates.\191\ For example, 
in Kinder Morgan, the pipeline admitted that it had not disclosed that 
it shared operating employees with its marketing affiliates.\192\ 
Posting of organizational information, including job descriptions and 
the chain of command, will deter undue discrimination because such 
information permits shippers to know which employees are involved in 
pipeline transportation functions and have access to their commercially 
sensitive information. Such transparency will serve to counter the 
economic incentive to share information between pipelines and their 
marketing affiliates.\193\ Moreover, the posting requirements are not 
onerous. The posting requirements do not apply to clerical, 
maintenance, and field employees because these employees would not 
receive information concerning the processing or administration of 
requests for transportation service.
---------------------------------------------------------------------------

    \191\ Kinder Morgan Interstate Gas Transmission LLC, et al., 90 
FERC para. 61,310 (March 29, 2000) (Kinder Morgan) and Amoco v. 
Natural Gas Pipeline Company of America, 82 FERC para. 61,038 
(1998); reh'g denied, 82 FERC para. 61,300 (1998); and reh'g 
granted, in part, 83 FERC para. 61,197 (1999).
    \192\ 90 FERC para. 61,310 at 62,009. Although Kinder Morgan 
concerned a settlement, the pipeline stipulated to certain facts 
concerning the pipeline's relations with its marketing affiliates. 
See Settlement Agreement at 6-7.
    \193\ Tenneco Gas Company v. FERC, 969 F.2d 1187 at 1205 (1992).
---------------------------------------------------------------------------

    Tejas argues that posting organizational charts will ``clutter'' 
its web site with voluminous and irrelevant information. However, 
electric utilities have been subject to similar posting requirements 
since 1997, and their web sites, for the most part, appear to be well 
organized and uncluttered. This appears to be an issue of web site 
design rather than substantive policy.
    Williams requests the Commission to eliminate the organizational 
charts for the pipeline under section 161.3(l)(2)(ii)(B), while INGAA 
requests the Commission to modify that section to require pipelines to 
post just the title and function of non-shared employees, rather than 
detailed job descriptions and the employees' names. Williams and INGAA 
argue that the fact that the Commission has adopted a similar 
requirement for electric utilities is inadequate justification for 
imposing this reporting burden on pipelines because there are distinct 
and fundamental differences between the two types of utilities. They 
assert that pipelines do not provide a commodity

[[Page 35751]]

sales service similar to electric retail service, and that pipeline 
operations are not intertwined between a wholesale transmission service 
and a retail commodity service. INGAA argues that the differences 
between completely unbundled natural gas pipelines and vertically 
integrated electric utilities suggest that details about non-shared 
employees are unnecessary in the natural gas pipeline industry, and 
that, therefore, pipelines ought to be subject to less stringent 
reporting of non-shared employees and facilities. Williams further 
argues that unlike the information in paragraphs A and C of section 
161.3(l)(2)(ii), the information in paragraph B does not relate to both 
the pipeline and its marketing affiliate, but is related solely to the 
pipeline.
    Although it is true there is more vertical integration among 
electric utilities than among natural gas pipelines, it is also true 
that most pipelines continue to have marketing affiliates that are 
involved in transportation transactions on the pipelines' system. For 
this reason, it is important to require information to be reported on 
all non-clerical employees, whether shared or non-shared, so the 
Commission can better monitor for affiliate preferences by making its 
own independent determination which employees are shared and which are 
not shared. The posting requirements will also allow shippers to 
identify by name (with respect to supervisors) and job description 
those who have access to transportation information, enabling them to 
determine whether pipelines have accurately revealed shared 
transportation employees.
    Accordingly, the posting requirements help shippers and the 
Commission to monitor and detect anticompetitive abuses.\194\ The 
potential for such anticompetitive abuse continues whenever a pipeline 
conducts transportation transactions with its marketing affiliate(s). 
With the elimination of the capacity release price cap, it is 
especially important for the Commission to be vigilant to dealings 
between pipelines and their affiliates.
---------------------------------------------------------------------------

    \194\ The Standards of Conduct and posting requirements only 
apply if the pipeline conducts transportation transactions with its 
marketing affiliate(s), including those in which a marketing 
affiliate is involved.
---------------------------------------------------------------------------

    In addition, a number of pipelines argue that the Commission should 
eliminate the requirement that pipelines update the information 
required to be posted by section 161.3(l) within three business days of 
any change.\195\ They assert that because growing corporations in 
today's business world are in constant states of evolution, three days 
is an inadequate amount of time in which to update the postings of the 
extensive and ever-changing information that is now required. They 
argue that the three-day updating requirement could result in daily 
updating, and thus, become unduly burdensome, and would be a waste of 
resources. CNGT and Enron add that the comparable requirements for the 
electric industry do not include this three-day updating requirement. 
Additionally, Enron urges that the updating of the information within 
three days of changes is an unreasonable time frame because information 
on corporate organizational changes is often kept confidential until 
employees are briefed, and once the changes are public, memoranda 
documenting and implementing the changes take additional time.
---------------------------------------------------------------------------

    \195\ See Requests for Rehearing of CNGT, Enron, INGAA, 
Williams, Williston Basin, and Koch.
---------------------------------------------------------------------------

    All of the pipelines raising this issue request that the Commission 
instead require the affiliate information to be updated on the first 
business day of each quarter. Further, CNGT and INGAA argue that if the 
three-day updating requirement is retained, it should be limited to the 
information concerning shared operating employees under section 
161.3(l)(2)(ii)(C), while the information on non-shared employees 
required in section 161.3(l)(2)(ii)(B) should be updated quarterly.
    The Commission has decided not to alter the requirement to post 
changes to the posted affiliate information within three business days 
of the change. In order to provide accurate information regarding a 
pipeline's management and organization for purposes of monitoring 
pipelines' compliance with the standards of conduct, it is essential 
for such information to be current. For this reason, a quarterly 
updating of affiliate information is inadequate.
    In the Commission's view, the three-day updating requirement is not 
burdensome or unreasonable. In fact, the requirement to post changes 
three business days after they occur is less strict than the 
requirement for electric utilities to post changes ``as changes 
occur.'' \196\ Enron's argument that the three-day posting requirement 
is burdensome was first considered and rejected in Reporting Interstate 
Natural Gas Pipeline Marketing Affiliates on the Internet \197\ with 
regard to posting the names and addresses of marketing affiliates in 
existing section 161.3(l) (now section 161.3(l)(1)). In that order, the 
Commission agreed with Enron that the pace of markets today is brisk. 
However, the Commission noted that because of the dynamic nature of 
markets, unduly discriminatory actions must be corrected quickly if the 
correction is to be meaningful.\198\
---------------------------------------------------------------------------

    \196\ Allegheny Power Services Corp. et al., 84 FERC para. 
61,131 at 61,714 (1998).
    \197\ Reporting Interstate Natural Gas Pipeline Marketing 
Affiliates on the Internet, III FERC Stats. & Regs. Regulations 
Preambles para. 31,064 (July 30, 1998), 63 FR 43075 (Aug. 12, 1998).
    \198\ III FERC Stats. & Regs. Regulations Preambles para. 31,064 
at 30,715.
---------------------------------------------------------------------------

    Moreover, a pipeline must consider the application of the standards 
of conduct to a proposed organizational change before it makes such 
changes. Posting information regarding the transfer three days after 
such organizational changes have occurred is a ministerial act. 
However, in response to Enron, the Commission will modify the language 
of section 161.3(l)(1) and (2) to require that pipelines update the 
information ``within three business days of any change taking effect.'' 
This will clarify that the Commission does not intend for pipelines to 
post changes prior to the effective date of the change.

C. Information on Available Capacity

    In Order No. 637, the Commission expanded the requirement in 
existing section 284.8(b)(3) of the Commission's regulations for 
pipelines to report information on available capacity. Under that 
regulation, pipelines were required to post on their Internet web sites 
information about the amount of operationally available capacity at 
receipt and delivery points, on the mainline, in storage fields, and 
whether the capacity is available directly from the pipeline or through 
capacity release.\199\ In new section 284.13(d)(1), the Commission 
continued to require pipelines to provide this information (via posting 
on the pipelines' Internet web sites), and added the following 
information on capacity availability to the information that was 
already collected: the total design capacity of each point or segment 
on the system; the amount of capacity scheduled at each point or 
segment on a daily basis; and information on planned and actual service 
outages that would reduce the amount of capacity available. The 
Commission required the information on available and scheduled capacity 
to be posted daily, and the information on design capacity to be posted 
one time (and thereafter maintained on the web site), and then updated 
as necessary.

[[Page 35752]]

Service outages must posted when required.
---------------------------------------------------------------------------

    \199\ 18 CFR 284.8(b)(3); 18 CFR 284.10(b)(1)(iv), Electronic 
Delivery Mechanism Related Standards 4.3.6; 18 CFR 284.10(b)(1)(v), 
Capacity Release Related Standards 5.4.13.
---------------------------------------------------------------------------

    Enron requests the Commission to eliminate the requirement that 
pipelines post design capacity for each point or segment.\200\ Enron 
argues that the development and maintenance of meaningful design 
numbers would require the investment of a large amount of resources, 
and that shippers would not gain any additional useful information that 
they do not already receive from the posting of operationally available 
capacity. Enron explains that because pipelines do not operate under 
static conditions, the capacity of a point depends not only on the 
meter capacity of the point, but also on the location of other points 
on a lateral, the pressures at which the lateral is being operated, and 
the location and direction of actual gas flows. Enron states that for 
these reasons, GISB recently considered and declined to add design 
capacity to the available capacity posting.
---------------------------------------------------------------------------

    \200\ Request for Rehearing of Enron at 10.
---------------------------------------------------------------------------

    The Commission will not eliminate the requirement that pipelines 
post design capacity for each point or segment. Design capacity 
information for points and segments will provide shippers with a 
picture of capacity distribution on the pipeline when operated under 
design conditions, and will enable shippers to better understand the 
relationship between design, scheduled, and operationally available 
capacity. The Commission recognizes that design capacity may not be 
available at all times due to variable operating conditions. However, 
the reporting of this information will provide a useful benchmark from 
which to evaluate operationally available capacity. Further, the 
Commission clarifies that it will be sufficient for pipelines to post 
the point and segment capacity used for system design and peak 
operation studies; such information should be readily available to the 
pipeline. Pipelines are free, however, to explain in their postings of 
operationally available capacity under section 284.13(d) why design 
capacity may not be available.
    NGSA requests clarification that all information regarding capacity 
usage that a pipeline has access to should be made publically available 
on a real-time basis, whenever feasible. In particular, NGSA requests 
that where operationally feasible, a pipeline should report on a real-
time basis for each point on its system--especially for constraint or 
other critical points `` the design capacity (i.e., total available 
capacity before subscriptions) for that point, the capacity actually 
scheduled for that point, and actual physical flows through the 
point.\201\ NGSA argues that only with this information can shippers 
know how much of unused capacity is actually unused but subscribed 
capacity that can be taken back by firm capacity holders at either the 
second or third nomination cycles. At a minimum, asserts NGSA, the 
Commission should require that pipelines post available design and 
scheduled capacity not only after the normal or ``timely'' cycle (11:30 
a.m. on the day before flow day), but also after the 6:00 p.m. evening 
cycle, and where operationally feasible, after the two intra-day 
cycles. NGSA maintains that reporting available capacity only after the 
normal cycle is of limited value because available capacity often 
changes substantially as a result of the evening cycle. Amoco, however, 
requests that the Commission require the posting of capacity 
information on an ongoing basis, as the data become available to the 
pipeline.
---------------------------------------------------------------------------

    \201\ Amoco, also, requests that the Commission require 
pipelines to post data on available capacity, as well as flow data, 
at constraint points and bottlenecks on the mainline.
---------------------------------------------------------------------------

    The current regulations require the posting of available and 
scheduled capacity on a daily basis. The Commission finds merit in the 
argument that shippers need to know the level of available and 
scheduled capacity before each of the four intraday nomination 
opportunities in order to respond to nomination opportunities during 
the gas day. Therefore, the Commission will grant rehearing, and revise 
section 284.13(d)(1) to require that pipelines post the available and 
scheduled capacity information when they provide scheduling information 
to their shippers. This will permit the shippers to use this 
information to help in planning their nominations for the next 
nomination opportunity. Since pipelines must compute these capacity 
figures in the normal course of scheduling service requests for the 
four daily nomination cycles, there should be little additional burden 
in posting the data. However, the Commission will not require actual 
flow data to be reported because the information on available and 
scheduled quantities would appear sufficient to show the usage of the 
system. Moreover, actual flow data will not be able to help shippers 
nominate because it would be reported after the fact, not before 
nominations.
    In response to NGSA and Amoco regarding the reporting of data at 
constraint points and bottlenecks, the Commission clarifies that under 
section 284.13(d)(1), pipelines are required to post information on 
available capacity, total design capacity, and scheduled capacity at 
all points, which should reasonably provide such information with 
respect to constraint points and bottlenecks. Pipelines, though, do not 
need to identify which points are constrained. However, as stated 
above, the Commission is not requiring the reporting of actual flow 
data at any point, constrained or otherwise, and denies Amoco's and 
NGSA's request for such flow data.

C. Implementation

    The Final Rule requires pipelines to implement the new data 
reporting requirements by September 1, 2000. The Commission recognized 
in the Final Rule that the industry, through the Gas Industry Standards 
Board (GISB), is in the process of developing and improving standards 
for providing currently required information both on pipeline web sites 
and through downloadable file formats, using Electronic Data 
Interchange ASCX12 (EDI) formats.\202\ The Commission further 
recognized that GISB will need to develop standards for the new 
reporting requirements (including pipeline firm and interruptible 
transportation transactions, design capacity, constraint information, 
and scheduled capacity) both for the presentation of the information on 
pipeline web sites, and the provision of the information in Electronic 
Data Interchange ASCX12 (EDI) or ASCII file formats, but that it may 
not be possible for GISB to complete the process of standardization in 
time for the September 1, 2000 implementation date.
---------------------------------------------------------------------------

    \202\ See Standards For Business Practices Of Interstate Natural 
Gas Pipelines, Order No. 587-I, 63 FR 53565, 53569-75 (Oct. 6, 
1998), III FERC Stats. & Regs. Regulations Preambles para. 31,067, 
at 30,737-46 (Sept. 29, 1998).
---------------------------------------------------------------------------

    Therefore, while the Commission encouraged GISB to work toward 
completing the standardization process prior to September 1, 2000, the 
Commission required pipelines to provide the new reporting information 
in non-standardized formats in the event GISB was unable to develop the 
datasets in time for the September 1, 2000 implementation. However, the 
Commission did not require that pipelines develop individual EDI file 
formats for the information during the period when GISB is developing 
the standards. Rather, the Commission required that pipelines only post 
the information on their web sites and provide flat ASCII file 
downloads for the relevant information. Pipelines, though, must 
continue to post the capacity release data in the existing EDI formats.

[[Page 35753]]

    A number of rehearing requests ask that the Commission defer the 
September 1, 2000 implementation date until after GISB has completed 
the process of establishing uniform national standards for collecting 
and displaying both the existing and new reporting information, so that 
pipelines may comply with the new reporting requirements and the GISB 
standards at the same time.\203\ They argue that deferring the 
implementation of the new reporting requirements to coincide with the 
implementation of the GISB standards will eliminate the duplicative 
effort that otherwise will be required to make pipeline-specific 
changes to comply with Order No. 637, and then more changes to comply 
with the industry-wide GISB standards. They assert that requiring 
compliance twice will be expensive and wasteful of resources. In 
addition, Coastal maintains that deferring the implementation date will 
result in more user-friendly data presentations than will the numerous 
individual pipeline presentations, in various formats, developed to 
comply with Order No. 637.
---------------------------------------------------------------------------

    \203\ Coastal, CNGT, Enron, INGAA, Kinder-Morgan, Koch, Tejas, 
Williams, and Williston Basin.
---------------------------------------------------------------------------

    Thus, the rehearing requesters either argue that the Commission 
should defer the implementation of the Order No. 637 reporting 
requirements until GISB publishes the uniform standards, or delay 
implementation until compliance with the GISB standards is possible. 
Some argue that the Commission should defer the implementation date 
until four months after the GISB standards are adopted.\204\ Still 
others suggest that implementation should be deferred until either GISB 
develops the standard formats, or if GISB is unable to do so, the 
Commission itself develops the uniform standards.\205\ In addition, 
Williston Basin argues that the Commission either must extend the 
implementation date or not require the reporting requirements to be 
standardized.\206\
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    \204\ Request for Rehearing of Kinder Morgan at 39 and Request 
for Rehearing of Williams at 11.
    \205\ Request for Rehearing of Koch at 59 and Request for 
Rehearing of CNGT at 26. CNGT asserts that the Commission should 
establish a standardized format for the new reporting requirements 
by July 1, 2000, if the Commission expects pipelines to meet a 
September 1, 2000 deadline.
    \206\ Request for Rehearing of Williston Basin at 14-16.
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    In Order No. 637, the Commission has not required pipelines to 
develop EDI file formats for the new reporting requirements prior to 
GISB's issuance of the reporting standards. However, the Commission 
will not defer the implementation date for the posting of the 
information on pipeline web sites until after GISB acts. The 
information in the new reporting requirements needs to be available to 
the Commission and the market by September 1, 2000, to enable the 
Commission and market participants to begin to receive information 
about pipeline services prior to the start of the winter heating 
season.
    The Commission recognizes that standardization of the reporting 
requirements is important to the industry, and is important to the 
Commission, as well. However, GISB is a private organization that is 
not required to act in accordance with the Commission's timetables, and 
thus, may not act in time to meet the Commission's implementation 
deadline. The Commission has minimized the potential for duplicative 
costs by requiring only that the information be posted on Internet web 
sites and in downloadable files, but not requiring pipelines to provide 
the data in EDI format until GISB's standardization is complete. Should 
GISB be unable to complete the standards necessary for posting the 
information on Internet web sites before September 1, 2000, the 
potential costs to the pipelines of having to reformat that information 
should not be great, particularly since they will be able to use 
whatever standards GISB has developed by that time. In any event, the 
information being required is of sufficient importance for the industry 
and for Commission monitoring of the market that the need for the 
information outweighs the costs of having to make minor changes to 
pipeline web sites at a later date. The Commission, therefore, will not 
make the implementation date dependent on GISB's actions. The 
Commission, however, encourages pipelines to work expeditiously with 
GISB to finish developing the standards in advance of the time for 
implementation of the Order No. 637 reporting requirements, which will 
eliminate any potential for duplicative development costs.
    Finally, Great Lakes requests that the Commission confirm that 
pipelines will be able to recover the substantial costs that will be 
incurred in complying with the expanded reporting requirements of Order 
No. 637 in their next section 4 rate case. The costs may be recoverable 
in a rate case if they meet the Commission's standards for cost 
recovery. The Commission cannot make a generic ruling on this issue, 
since it is not aware of the nature of the costs for which recovery may 
be sought. The issue of the recovery of Order No. 637 compliance costs, 
like any other expense item, is an issue that may be raised in each 
pipeline's subsequent rate case, and if so, will be decided there.

IV. Other Pipeline Service Offerings

A. The Right of First Refusal

    In Order No. 637, the Commission retained the right of first 
refusal (ROFR) \207\ with the five-year matching cap, but narrowed the 
scope of the right. The Commission changed its policy so that in the 
future the right of first refusal will apply only to maximum rate 
contracts for 12 or more consecutive months of service. Existing 
discounted contracts were grandfathered so that the ROFR will apply to 
current discounted contracts, but will not apply when the contracts are 
reexecuted unless they are at the maximum rate.
---------------------------------------------------------------------------

    \207\ 18 CFR 284.221.
---------------------------------------------------------------------------

    The Commission also indicated that the maximum rate that a shipper 
must meet when exercising its right of first refusal may be, in certain 
limited circumstances where an incremental rate exists on the system, a 
rate that is higher than the historic maximum rate. Further, the 
Commission decided that it would not enhance the right of first refusal 
by allowing it to be exercised for a geographic portion of the existing 
contract. The Commission, however, did not change its preexisting 
policy that the right of first refusal can be exercised by a shipper 
for a volumetric portion of its capacity. The Commission also clarified 
that the right of first refusal as provided by the Commission's 
regulations, is an exercise of the Commission's authority under section 
7(b) of the NGA and is not dependent on the contract between the 
pipeline and the shipper.
    A number of parties have requested rehearing of this portion of 
Order No. 637.\208\ As discussed below, the Commission has concluded 
that generally the ROFR should be limited to maximum rate contracts for 
12 or more consecutive months of service, but an exception to this rule 
is appropriate for certain seasonal contracts. Therefore, the 
Commission modifies Order No. 637 to provide that the ROFR will apply 
to multi-year seasonal contracts at the maximum rate for services not 
offered by the pipeline for a full 12 months. The requests for 
rehearing on the other ROFR issues are denied for the reasons discussed 
below. The Commission also

[[Page 35754]]

clarifies Order No. 637 as provided below.
---------------------------------------------------------------------------

    \208\ Requests for rehearing on these issues were filed by AGA; 
APGA; Arkansas Gas Consumers; ConEd; Florida Cities; FPL Energy; 
Great Lakes; INGAA; Keyspan; Koch Gateway; Minnesota; New England 
Gas Distributors; NASUCA; National Fuel; Process Gas Consumers; 
Minnegasco; Texas Eastern; UGI Utilities; Washington Gas; The 
Williams Companies; and WDG.
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1. Contract Length
    In Order No. 637, the Commission changed its policy so that in the 
future, the right of first refusal will apply only to maximum rate 
contracts for 12 or more consecutive months of service.\209\ The 
Commission stated that it will be the term of the service, not the term 
of the contract, that will determine whether the right of first refusal 
will apply. The Commission reasoned that the purpose of the right of 
first refusal is to protect long-term captive customers, and that 
seasonal service is short-term service, even if the contract providing 
for the service is of a duration of more than a year. AGA, several LDCs 
\210\ and the Minnesota Department of Commerce (Minnesota) seek 
rehearing on this issue.
---------------------------------------------------------------------------

    \209\ Order No. 637 at 216-18.
    \210\ E.g., Keyspan Brooklyn Union, National Fuel, New England 
Gas Distributors, and Minnegasco.
---------------------------------------------------------------------------

    These petitioners argue there is no record evidence to support the 
Commission's conclusion that all shippers taking partial year service 
have competitive options. They assert the fact that a contract is for 
less than a full year of service does not in itself imply that the 
customer has sufficient competitive alternatives. The petitioners 
maintain that the services provided under many of these contracts, 
often storage and related transportation, are available from the 
pipeline only for specific months,\211\ and are not offered for a full 
year. For example, Keyspan states that its long-term contracts for 
seasonal service are not the product of negotiations in which the 
Keyspan companies were able to use leverage to avoid purchasing 
services on an annual basis. Instead, Keyspan asserts, the pipelines 
offered the services for limited periods of the year, and the Keyspan 
companies are dependent on these contracts to meet their peak demands.
---------------------------------------------------------------------------

    \211\ AGA gives several examples of such service, e.g., 
Transco's Southern Expansion Service which is available only from 
November through March.
---------------------------------------------------------------------------

    In addition, Minnegasco complains that the Commission's ruling 
elevates the form of the contract above the substance and, as a result, 
there will be only one acceptable model of contracting in order for a 
captive customer to preserve its right of first refusal.\212\ 
Minnegasco argues that this denies parties the contractual flexibility 
that is allegedly a benefit of open access.
---------------------------------------------------------------------------

    \212\ Minnegasco gives several examples: if it has two contracts 
with a pipeline, one for 12 consecutive months of baseload capacity 
each year of the multi-year contract and a second agreement with 
that pipeline for 5 months of winter heating capacity for each 
heating season of the multi-year contract, it interprets Order No. 
637 as stating that the contract for the heating season capacity 
would not have ROFR protection. If, on the other hand, it had one 
contract with the pipeline for 12 consecutive months of baseload 
capacity, but with increased capacity for the 5-month winter period, 
the contract would have ROFR protection. Also, Minnegasco states, if 
it had a contract with a different pipeline for the increased 
heating season capacity, that contract would not have ROFR 
protection. Minnegasco asserts that these differences are of form, 
not substance.
---------------------------------------------------------------------------

    These petitioners further argue that there is no legal 
justification for eliminating ROFR protection for multi-year seasonal 
contracts. Keyspan argues that there is nothing in section 7(b) of the 
NGA or the court's decision in United Distribution Companies v. FERC 
(UDC) \213\ that permits the Commission to apply a different standard 
in considering the abandonment of critically needed seasonal contracts 
than would be applied to necessary year round contracts. New England 
asserts that Order No. 637 sets forth no record support for the 
conclusion that partial year shippers can rely on the market to protect 
them from the exercise of market power. New England argues that the 
Commission's decision is also procedurally defective because the NOPR 
did not contain such a proposal, and therefore interested parties did 
not have an opportunity to comment on the issue.
---------------------------------------------------------------------------

    \213\ 88 F.3d 1105 (D.C. Cir. 1996).
---------------------------------------------------------------------------

    These petitioners ask the Commission to modify or clarify its 
ruling and provide protection for pipeline customers that have multi-
year contracts for pipeline service offered for less than 12 months. 
AGA asks the Commission to clarify that service under rate schedules 
that only provide partial-year service at maximum rates have ROFR 
protection. Minnesota also asks the Commission to allow the ROFR to 
apply to multi-year seasonal contracts for shippers currently paying 
rates that reflect the full cost of service.\214\
---------------------------------------------------------------------------

    \214\ Minnesota states that Northern Natural Company (Northern) 
supplies 89 percent of Minnesota's imported gas, and that the 
pipeline is capacity constrained. Minnesota also states that 
Northern Natural was given Commission approval to implement seasonal 
rates that are designed to reflect the full cost of service. Docket 
No. RP98-203. Minnesota states that the Commission's altered ROFR 
policy treats Minnesota shippers holding cost-based seasonal 
capacity on Northern differently from Minnesota shippers holding 
cost-based 12-month service. (Check this).
---------------------------------------------------------------------------

    The Commission will grant the clarification requested by the 
petitioners, and provide that the ROFR will apply to multi-year 
seasonal contracts at the maximum rate for services not offered by the 
pipeline for a full 12 months. This is consistent with the purpose of 
the ROFR to protect long-term captive customers at the expiration of 
their contracts. If a customer is paying the maximum rate under a 
multi-year contract for a service that is offered by the pipeline on a 
seasonal basis only then, as the petitioners have pointed out, it is 
the pipeline that has determined the duration of the service. The 
shipper needing the service has no alternative but to accept what the 
pipeline offers. In addition, the LDC petitioners state that these 
multi-year winter-only contracts provide firm transportation service, 
often from storage, at critical times during the heating season. The 
LDCs generally have no pipeline alternatives to this service and this 
service is necessary to enable them to meet their service obligations. 
Thus, the contracts are similar to long-term contracts because the 
customers contract for this peaking service over a number of years, and 
the customers do not have significant alternatives to these pipeline 
contracts. They are not similar to the typical short-term contract 
where the shipper is not a captive customer, has other service options, 
and is not subject to the pipeline's market power. In these 
circumstances the customer relying on the service and paying the 
maximum rate should have the protection of the ROFR. Long-term maximum 
rate contracts with increased CDs for seasons of peak demand meet the 
standards for ROFR protection and therefore are covered by the ROFR.
2. Discounted Contracts
    In Order No. 637, the Commission narrowed the scope of the ROFR to 
apply only to maximum rate contracts. The Commission explained that 
limiting the ROFR to maximum rate contracts is consistent with the 
original purpose of the ROFR to protect long-term captive customers 
from the pipeline's monopoly power. The Commission reasoned that if a 
customer is truly captive and has no alternatives for service, it is 
likely that the contract will be at the maximum rate. The Commission 
stated its intent that with this modification, captive customers will 
still be able to receive their historical service as long as they pay 
the maximum rate. However, the Commission also stated that if a 
customer has sufficient alternatives that it can negotiate a rate below 
the just and reasonable maximum tariff level, it should not have the 
protection afforded by the right of first refusal, and the pipeline 
should be able to negotiate with other interested shippers. The 
Commission grandfathered existing discounted contracts and provided 
that the ROFR will apply to these contracts, but will not apply to 
future contracts that are not at the maximum rate. The

[[Page 35755]]

Commission found that limiting the ROFR to maximum rate contracts 
strikes the appropriate balance between the need to protect captive 
customers and the need to better balance the risks between the shipper 
and the pipeline.
    APGA, National Fuel, Minnegasco, WDG, Process Gas Consumers, FPL 
Energy, Arkansas Gas, and Enron seek rehearing on this issue. These 
parties argue that limiting the ROFR to maximum rate contracts is 
contrary to section 7(b) of the NGA and challenge the factual basis for 
the limitation.
    The limitation of the ROFR to maximum rate contracts as provided in 
Order No. 637 is fully consistent with the statutory requirements and 
the Commission's regulatory policies. Under section 4 of the NGA, a 
shipper is entitled to protection from unjust and unreasonable rates, 
and under section 7(b) of the NGA, a shipper is entitled to protection 
from the pipeline's exercise of monopoly power through the refusal of 
service at the end of the contract term. The Commission's rate 
regulation assures that the rates charged by the pipeline are just and 
reasonable, and the ROFR protects captive customer from an exercise of 
the pipeline's market power at contract termination. Contrary to the 
suggestions of the petitioners, limiting the application of the ROFR to 
maximum rate contracts does not dilute either of these protections. 
Captive customers are guaranteed confirmed service at the just and 
reasonable Commission-approved tariff rate. What is not guaranteed is 
service below the just and reasonable rate. The limitation is 
consistent with the Commission's goal of promoting competition while 
protecting captive customers from pipeline market power, and the 
Commission's need to balance financial risks between pipelines and 
shippers.
    Several petitioners argue that the Commission's decision is 
contrary to section 7(b) of the NGA because section 7(b) does not state 
that only captive or maximum rate customers are entitled to protection, 
and the Commission in the past has emphasized that the ROFR is intended 
to protect all existing customers, not just some subcategory of 
them.\215\ Process Gas Consumers assert that in Order No. 636-C, the 
Commission did not limit the ROFR to captive non-discounted shippers, 
and that the Court in UDC did not limit the ROFR to captive customers 
and did not indicate that ``captive'' means solely maximum rate non-
discounted shippers.\216\ Process Gas Consumers argue that the new 
limitation is unjustified.
---------------------------------------------------------------------------

    \215\ Process Gas Consumers cite Order No. 636 at 30,448.
    \216\ Process Gas Consumers cite a portion of the Court's 
decision where the Court states that ``even a captive customer 
served by a single pipeline can exercise its right of first refusal 
and retain its long-term firm transportation service against rival 
bidders.'' UDC at 1140. Process Gas Consumers state that the Court's 
use of the word ``even'' implies that the Court was not limiting the 
ROFR protection to captive customers.
---------------------------------------------------------------------------

    Section 7 (b) is designed to ``protect gas customers from pipeline 
exercise of monopoly power through refusal of service at the end of a 
contract period.'' \217\ The ROFR, by the terms of the regulation, is 
available to all shippers willing to pay the maximum rate and is not 
limited to captive customers. The Commission's regulation protects 
shippers from the exercise of market power in two ways: by capping the 
maximum rate the pipeline can charge and by giving shippers a ROFR at 
contract termination.
---------------------------------------------------------------------------

    \217\ AGA II, 912 F.2d at 1518.
---------------------------------------------------------------------------

    The petitioners also argue that the Commission's conclusion that a 
shipper that has been able to negotiate a discount with the pipeline is 
not a captive customer is erroneous. They assert that pipelines give 
discounts to customers, including captive customers, for a variety of 
reasons unrelated to competition. For example, these petitioners state 
that a discount may be given in consideration of entering into a 
settlement of a rate case or a complaint proceeding, for an agreement 
of the shipper to shift to a less desirable or underutilized receipt 
point, to sign a longer contract, or to take an additional volume.\218\ 
In these circumstances, they assert, the fact that the shipper pays a 
discounted rate does not mean that it is not captive or that it has 
market alternatives for service. Further, Process Gas Consumers point 
to the Alternative Rates Policy Statement, under which the Commission 
requires a pipeline to show that its shippers have four or five ``good 
alternatives'' as one aspect of demonstrating that it lacks market 
power,\219\ and argue that a discount from one pipeline is not the same 
as four or five good alternatives. WDG argues that absent a finding, on 
a customer-specific basis, that each shipper with a discounted contract 
has meaningful choices at the time of the contract termination, the 
Commission must continue to provide such shippers with the continued 
protection of the ROFR.
---------------------------------------------------------------------------

    \218\ The petitioners give other examples of situations where a 
captive customer may receive a discounted rate. For example, APGA 
states that a captive customer may be given a discount where the 
captive customer has a non-captive retail customer; Minnegasco 
states that a customer may be captive for 95 percent of its load and 
the pipeline may be willing to negotiate a discount to retain the 
entire load; WDG states that a pipeline may give a discount to a 
captive customer in response to a perceived competitive threat from 
the proposed construction of a new pipeline, and defeat the 
introduction of the new alternative. If the existing pipeline is 
successful in keeping the proposed alternative from entering the 
market, WDG argues, the captive customer whose last contract was at 
a discounted rate will still be a captive; Arkansas Gas states that 
captive customers may receive discounts as an incentive for an 
industrial customer to expand its facilities, as an incentive to 
take service at facilities with competitve options, or to assist 
industrial customers during times of financial troubles in order to 
keep the facility viable.
    \219\ Process Gas Consumers cite Alternative Rates Policy 
Statement at 61,235.
---------------------------------------------------------------------------

    Further, several of the petitioners argue, because a discount or 
negotiated rate is determined at the outset of the contract, it has no 
relationship to the market that the long-term shipper faces at the end 
of the contract. They argue that the Commission provided no reason for 
equating market conditions at the outset of the contract with those at 
the end of the contract, and that conditions could change and affect 
the shippers' ability to obtain capacity at the end of the contract. 
The petitioners assert that the Commission must make certain that a 
captive customer will be afforded the assurance of continued service if 
the customer is willing to pay the maximum rate for the service in the 
future, regardless of whether the customer was able to negotiate a 
discount in the past.
    These petitioners assert that the result of the Commission's ruling 
is that captive customers will be forced to forgo any opportunity for a 
discount, and will have to pay the maximum rate in order to retain a 
ROFR even if the market rate on a pipeline is lower than the maximum 
rate. Therefore, they argue, the Commission is guaranteeing that LDCs 
with a supplier of last resort obligation, or those that are physically 
connected to only specific pipelines, will not have an opportunity to 
obtain a contract at the market rate.
    Although the petitioners assert that pipelines give discounts for a 
variety of reasons, generally, discounts are given to obtain or retain 
load that the pipeline could not transport at the maximum rate because 
of competition. The Commission has held that to the extent that a 
pipeline was required during the test period in a section 4 rate case 
to give discounts either to attract or retain load, the pipeline is not 
required to design its rates on the assumption that the discounted 
volumes would flow at maximum rates.\220\ The Commission has explained 
that discounts given to meet competition benefit all customers by

[[Page 35756]]

allowing a pipeline to maximize its throughput and thus spread fixed 
cost recovery over more units of service.\221\ Thus, the customers that 
receive discounts under the Commission's discount policy, are generally 
the customers whose business would have gone to another service 
provider unless the pipeline granted the discount, i.e., customers with 
alternatives. If discounts are given for other reasons,\222\ for 
example, if a discount is given for a short-haul, then it may be that 
the rate for the short-haul is not properly designed. If a rate for a 
service is too high, the shipper can file a complaint under section 5 
of the NGA. The maximum approved rate for any service is a just and 
reasonable rate, and no customer is harmed by paying a just and 
reasonable rate.
---------------------------------------------------------------------------

    \220\ E.g., Koch Gateway Pipeline Co., 74 FERC para. 61,088 at 
61,280 (1996).
    \221\ Id.
    \222\ See, e.g., Williston Basin Interstate Pipeline Co., 85 
FERC para. 61,247 (1998); Southern Natural Gas Co., 67 FERC para. 
61,155 at 61,456 n.8 (1994).
---------------------------------------------------------------------------

    Moreover, the ROFR's protection has always been related to the 
customer's payment of the maximum rate as a condition to exercising the 
ROFR. Pipelines are never required to discount their rates, and no 
customer is entitled to a discount. In finding that the ROFR afforded 
the necessary section 7(b) protection, the court in UDC stated, ``[i]f 
the existing customer is willing to pay the maximum approved rate, then 
the right of first refusal mechanism ensures that the pipeline may not 
abandon the certificated service.'' \223\ The court also observed 
``[t]he 7(b) abandonment provisions protect customers against loss of 
service only if the customer is willing to pay the maximum rate 
approved in a rate proceeding.\224\ Since the ROFR was first created 
and reviewed by the court in UDC, what has changed is that pipelines 
have been granting more discounts to long-term firm shippers in 
circumstances never intended under the Commission's discount policy. 
Many of these rate adjustments should have been handled in other ways 
in section 4 or 5 rate cases.
---------------------------------------------------------------------------

    \223\ UDC, 88 F.3d at 1140.
    \224\ Id. at 1142.
---------------------------------------------------------------------------

    Pipelines' rates are cost-based and are capped at a maximum just 
and reasonable level. No shipper is harmed by paying a just and 
reasonable rate for the service it receives. A shipper may, of course, 
negotiate with the pipeline for a discounted rate. However, if the 
shipper has the leverage, either through the availability of 
alternatives to the pipeline's service or for some other reason, to 
obtain a discount, it should compete with other shippers for the 
capacity without a preference.
    Thus, the limitation of the ROFR to maximum rate contracts leaves 
in place the basic protections afforded by the statute--the shipper is 
guaranteed that it will pay no more than a just and reasonable rate for 
the service it receives, and if the shipper pays the maximum just and 
reasonable rate, it is guaranteed that it can retain that service at 
the end of its contract. The Commission's limitation of the ROFR to 
maximum rate contracts is consistent with the statute and the purpose 
of the ROFR.
    Order No. 637 also states that because the ROFR will apply only to 
maximum rate contracts, there will be no ROFR for negotiated rate 
contracts. FPL Energy argues that the Commission erred in failing to 
consider the impact of this ruling on pipeline laterals, and that the 
Commission must make an exception for this type of service. FPL Energy 
states that it expects to take pipeline service across laterals built 
by the pipeline to its electric generating plant. FPL Energy states 
that once such a transportation arrangement is consummated, it will be 
exposed to the full market power of the pipeline to which it is 
connected, regardless of whether the Commission considers the rate to 
be negotiated.
    New England does not object to denial of ROFR protection to 
customers paying a discounted rate, but asks the Commission to clarify 
that a negotiated rate shipper is denied ROFR protection only if the 
negotiated rate is less than the tariff maximum rate.
    A negotiated rate is not the equivalent of the maximum tariff rate 
for the service, regardless of whether the negotiated rate is higher or 
lower than the maximum tariff rate, and therefore the ROFR will not 
apply to these contracts. The Commission permits negotiated rate 
contracts as an alternative to service under the Commission-approved 
generally applicable just and reasonable tariffs, but the regulatory 
right of first refusal does not apply to these negotiated contracts. 
Shippers who are able to negotiate a rate different than the maximum 
tariff rate generally have alternatives to service on the pipeline. 
However, in any event, if a shipper wants to have the benefits of the 
ROFR so as to have a preference for continued service on the pipeline 
over other customers at the expiration of its contract, it should take 
its service under the maximum just and reasonable tariff rate. If the 
shipper negotiates its rate, then it must compete equally with other 
shippers for the capacity at the end of its contract. In the example 
given by FPL, it is not likely that there would be any other shippers 
bidding for service over the lateral to its electric generating plant, 
and the pipeline is required to provide service at the maximum rate. 
The shipper is therefore protected in these circumstances.
    FPL asks the Commission to define several terms including ``maximum 
rate,'' and ``negotiated rate,'' and specify what type of contracts 
fall within or without the revised ROFR's protection. ``Maximum rate'' 
refers to the maximum tariff rate for a particular service. A 
``negotiated rate'' is a rate agreed to by the pipeline and a customer 
under the Commission's negotiated rate policy. As explained in Order 
No. 637 and as modified above, the ROFR will apply to maximum rate 
contracts for 12 or more consecutive months of service and to multi-
year seasonal contracts for services offered by the pipeline only on a 
seasonal basis.
    Enron argues that the Commission erred in grandfathering existing 
discounted contracts. Enron argues that it is unnecessary to allow 
these shippers to exercise their ROFR because the Commission has 
already concluded that these shippers are not the captive customers for 
which the right was created. Further, Enron argues that continuation of 
the right, even for just a few years, keeps the pipelines from putting 
the capacity in the hand of shippers that value it most.\225\
---------------------------------------------------------------------------

    \225\ Enron states that pipelines with current long-term 
discounted contracts cannot sell the long-term capacity they expect 
to become available, but must stand ready to continue serving the 
existing shippers until they either exercise their right of first 
refusal or allow them to lapse. Enron states that while the discount 
shipper may be required to bid up to the maximum rate at the 
contract expiration date, it need not presently declare its 
intention. Enron states that a pipeline in these circumstances is 
precluded from offering capacity to new shippers who require a 
current commitment to plan for incremental gas demand, and that 
these shippers may look elsewhere to fill their capacity needs.
---------------------------------------------------------------------------

    The Commission's determination that the ROFR should not apply to 
discounted contracts is a change from the Commission's past policy. 
Grandfathering current contracts executed by the parties with a 
regulatory right of first refusal is fair, and gives the parties notice 
of the new limitations on the ROFR prior to re-executing their 
contracts. It is within the Commission's discretion to apply this 
policy prospectively to contracts executed after the effective date of 
Order No. 637, and the Commission concludes that it is a reasonable 
balance to grandfather existing discounted long-term contracts.
    Koch agrees with the determination in Order No. 637 that the ROFR 
should not

[[Page 35757]]

apply to discounted contracts, but seeks clarification as to the date 
that the regulatory right of first refusal will apply to discounted 
contracts. Koch suggests that the Commission clarify that any 
discounted contract that was entered into for a year or more after 
March 1, 2000 would not qualify for the right of first refusal. In 
response to Koch's request, the Commission clarifies that the ROFR will 
not apply to any discounted contracts entered into after the effective 
date of Order No. 637.
3. ROFR Pricing Policy
    In Order No. 637, the Commission explained that, consistent with 
the holding in the Policy Statement concerning Certification of New 
Interstate Natural Gas Pipeline Facilities (Certificate Policy 
Statement),\226\ the maximum rate that the existing shipper must meet 
in order to exercise its right of first refusal may be higher than its 
current rate in certain very limited circumstances, i.e., where a 
shipper has a right of first refusal on a pipeline that has vintages of 
capacity and thus charges different prices for the same service under 
incremental pricing, the pipeline is full, and a competing shipper bids 
a rate for the capacity that is above the existing shipper's current 
maximum rate. In addition, in order to charge a higher rate than the 
previous maximum rate, the pipeline must have in place an approved 
mechanism for reallocating costs between the historic and incremental 
rates so all rates remain within the pipeline's cost of service.\227\
---------------------------------------------------------------------------

    \226\ Docket No. PL99-3-000, FERC para. 61,227 (1999), reh'g, 90 
FERC para. 61,128 (2000).
    \227\ The Commission cited several examples given on rehearing 
of the Certificate Policy Statement of such a mechanism.
---------------------------------------------------------------------------

    As the Commission explained in Order No. 637, a higher maximum rate 
is appropriate when the system is fully booked and there is at least 
one bid above the existing rate, because in those circumstances, there 
would be insufficient capacity to satisfy all the demands for service 
on the system. When insufficient capacity exists, a higher matching 
rate will improve the efficiency and fairness of capacity allocation, 
within the limits of cost of service ratemaking, by allowing new 
shippers who place greater value on obtaining capacity than the 
existing shipper to compete for the limited capacity that is available.
    In Order No. 637, the Commission explained that under this pricing 
policy, an existing captive customer is protected against the exercise 
of market power by the pipeline because the pipeline cannot insist on 
the shipper paying a higher rate unless its expansion is fully 
subscribed and there is another bid for capacity at a rate above the 
vintage maximum rate charged the existing shipper. These conditions 
ensure that the pipeline is unable to use its market power over captive 
customers to withhold capacity from the market to raise price. Price 
will exceed the current maximum rate charged the existing shipper only 
when a higher price is needed to allocate scarce capacity.
    The Commission's ROFR pricing policy was set forth in the 
Certificate Policy Statement. Because Order No. 637 made other changes 
to the ROFR mechanism, the Commission discussed the interaction of 
these changes with the new ROFR pricing policy. However, nothing in 
Order No. 637 changes anything in the Certificate Policy Statement. The 
Commission merely reiterated the change to the ROFR pricing policy in 
order to clarify how all the changes related to the ROFR work together.
    AGA, APGA, ConEd, Florida Cities, Keyspan, National Fuel, New 
England Distributors, UGI, Process Gas Consumers, and NASUCA seek 
rehearing or clarification of the Commission's ruling. The petitioners 
generally argue that the ROFR pricing policy is inconsistent with the 
NGA and Commission policy and regulations. Several petitioners ask the 
Commission to clarify how the policy will work in specific factual 
situations.
    a. Consistency with Statute and Regulations. Several of the 
petitioners argue on rehearing that charging a higher maximum rate than 
the shipper's previous maximum rate is unlawful under section 4 of the 
NGA. APGA and Keyspan argue that the increased maximum rate would be 
unjust and unreasonable since it would require shippers to pay for 
capacity that was not built to serve them and therefore, the necessary 
cost causation link is missing. Similarly, UGI argues that the 
Commission's regulations are designed to match cost recovery with cost 
incurrence, and that the rate that a shipper pays for retaining 
capacity must be related to the character and reliability of the 
service received, and cannot be escalated on an arbitrary basis to the 
value that some other shipper receives from an unrelated service. UGI 
asks the Commission to clarify that the maximum recourse rate that a 
shipper must match is a rate for a like or a comparable incremental 
service.\228\ NASUCA argues that ROFR customers are not similarly 
situated to new customers because they impose no new construction 
demands on the system.
---------------------------------------------------------------------------

    \228\ UGI argues that there is no justification for a policy 
that requires an LDC seeking to retain its market area service to 
match the incremental rate paid by a power generator on a lateral 
line located 2000 miles upstream of the LDC's city gate.
---------------------------------------------------------------------------

    The higher maximum rate paid by a shipper exercising its right of 
first refusal is not unjust or unreasonable under section 4 of the NGA. 
The new maximum rate will be established by a mechanism approved by the 
Commission to assure a just and reasonable result. As explained in the 
Policy Statement, the Commission will review the proposed mechanisms 
and determine how well they achieve capacity pricing that permits as 
efficient an allocation of capacity as is possible under cost-of-
service ratemaking, protection against exercise of market power by the 
pipeline, protection against overrecovery of the pipeline's revenue 
requirement, and equity of treatment between shippers with expiring 
contracts and new shippers seeking the same service. The Commission 
will assure in the individual proceedings that the pipeline has a 
mechanism to establish just and reasonable higher maximum rate prior to 
implementation.
    Further, it is not the case that existing shippers do not cause the 
need for expansion. As the court stated in Southeastern Michigan Gas 
Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir. 1998), ``[b]ecause every 
shipper is economically marginal the costs of increased demand may 
equitably be attributed to every user, regardless of when it first 
contracted with the pipeline.'' The Commission has concluded that 
existing shippers should not pay a rate that reflects expansion costs 
during the term of their contract, not because they did not cause the 
need for the expansion, but because these shippers sign long-term 
contracts with the expectation that increases in their rates will be 
related to the costs and usage of the system for which they subscribe. 
Raising the rates of these existing shippers during the term of their 
long-term contracts to include expansion costs reduces rate certainty 
and increases contractual risk, and the Commission has determined that 
their contracts should protect them from this risk. However, when the 
contracts expire and the existing shipper seeks to retain its service, 
it is just as much a cause of the need to expand as a new shipper 
seeking service for the first time. Under the Certificate Policy 
Statement, in order to determine whether an expansion is required, a 
pipeline seeking a certificate for new construction is directed to ask 
its current customers whether they are prepared to release their 
capacity. A

[[Page 35758]]

decision on the part of the existing customers not to release their 
capacity is a cause of a need to expand the capacity.
    The ROFR pricing policy applies where the pipeline charges 
different rates for the same service under incremental pricing. 
Therefore, as requested by UGI, the Commission clarifies that the 
maximum recourse rate that a shipper must match is a rate for a like or 
a comparable incremental service.
    Several petitioners also argue that the ROFR pricing policy will 
result in rate discrimination. APGA states that there is no basis on 
which to distinguish between the circumstances of a pipeline with and 
without incremental rates, and the ROFR should apply to each the same 
way. APGA argues that the roll-up policy fosters different pricing 
treatment for pre-existing captive shippers on different pipelines 
solely as a function of whether the pipeline in question has 
incremental capacity and this price difference is unlawful under the 
section 4 NGA proscription against unduly discriminatory pricing and 
preferential treatment.
    It has been the practice under Commission ratemaking policies to 
set individual pipeline rates based on each pipeline's different costs, 
and maximum rates have differed on pipelines as a result of these 
different costs. The result here is the same. APGA's argument suggests 
that the Commission should establish uniform national rates, but that 
is not required by the NGA.
    New England argues that the policy is discriminatory because 
shippers taking the same service will have their contracts expire at 
different times, and shippers whose contracts expire earlier would face 
a rate increase while others continue to take the same service at the 
same rate. Similarly, Process Gas Consumers state that this approach is 
discriminatory because similarly situated shippers may be subjected to 
very different maximum rates for the same service for no reason other 
than the timing of their contract expiration dates and the mechanics of 
the process used to set the new matching rate.
    It is not necessarily true that all companies should pay the same 
prices for the same goods or services regardless of when they contract 
for the goods or services, or when their contract expires. In an 
unregulated market, a firm may be able to lock-in a low price for goods 
or services when demand is weak relative to the available supply, while 
another firm contracting for the same goods or services at a later time 
when supply and demand conditions change may pay a higher price. 
Shippers who enter into long-term contracts are guaranteed the rate 
provided for by the contract, but there is no guarantee that they will 
have the same rate for that service after their contract expires. The 
courts have recognized that different contracts can justify rate 
differences.\229\ However, once the contract expires, there is no basis 
for distinguishing between customers receiving the same service.
---------------------------------------------------------------------------

    \229\ UMDG v. FERC, 732 F.2d 202, 212 (D.C. CIR. 1984); Norwood 
v. FERC, 587 F.2d 1306, 1310 (Cir. 19).
---------------------------------------------------------------------------

    Section 4 of the NGA prohibits a pipeline from affording different 
treatment to similarly situated shippers on its system. When there are 
different rates in effect on the system for historical customers and 
new customers for the same service, this rate difference raises 
concerns about discrimination under the NGA. There is no valid economic 
reason why the pipeline should charge these customers a different rate, 
and the ROFR pricing policy will tend to lessen price disparities on 
the system by moving toward a system-wide uniform maximum rate.
    b. Consistency with Commission Policy. AGA, APGA, Florida Cites, 
Process Gas Consumers, Keyspan, NASUCA, and New England argue that the 
ROFR pricing policy as applied to captive customers is inconsistent 
with the Certificate Policy Statement and other established Commission 
policy. They assert that one of the main goals of the Certificate 
Policy Statement is to assure that the pipeline must be prepared to 
support the project financially without relying on subsidies from 
existing customers.\230\ They argue that requiring captive customers to 
pay the highest incremental rate on the pipeline is inconsistent with 
this goal because the captive customers will subsidize expansion 
projects at the end of their contract terms.
---------------------------------------------------------------------------

    \230\ APGA cites the Policy Statement, 88 FERC at 61, 746-47.
---------------------------------------------------------------------------

    Further, they assert that the Certificate Policy Statement provides 
that existing customers should not have to bear the risk of cost 
overruns of pipeline expansion projects, but that these risks should be 
apportioned by contract between the pipeline and expansion 
shippers.\231\ They assert that the ROFR pricing policy is inconsistent 
with this goal because existing captive customers will be required in 
the future to bear the risks associated with new pipeline projects. In 
addition, they assert, the Certificate Policy Statement provides that 
existing customers should not have to pay for a project that does not 
serve them,\232\ and that the ROFR pricing policy conflicts with this 
goal because captive customers would underwrite expansion projects that 
were not built to serve them. In addition, they argue requiring 
subsidization by captive customers conflicts with the goal of sending 
accurate pricing signals to new shippers.
---------------------------------------------------------------------------

    \231\ APGA cites 88 FERC at 61,746.
    \232\ APGA cites 88 FERC at 61,746.
---------------------------------------------------------------------------

    Contrary to the suggestion of these petitioners, the ROFR pricing 
policy is not inconsistent with the Certificate Policy Statement, but 
is an integral part of the policy and works to accomplish its goals. As 
the Commission explained in the Certificate Policy Statement, a 
requirement that the new project must be financially viable without 
subsidies does not eliminate the possibility that in some instances, 
the project costs should be rolled into the rates of the existing 
customers.\233\ Existing shippers should not subsidize any new 
construction projects during the term of their contracts.\234\ However, 
where the pipeline charges different rates for the same service under 
incremental pricing and the pipeline is fully booked,\235\ requiring 
the customer to match the highest competing bid up to the maximum rate 
sends efficient price signals to existing customers whose contracts are 
expiring as well as to expansion customers.\236\
---------------------------------------------------------------------------

    \233\ 88 FERC at 61,746.
    \234\ Order Clarifying Statement of Policy, 90 FERC para. 61,128 
(slip op. at 12) (2000).
    \235\ In addition, as explained above, the pipeline must have an 
approved mechanism to implement the ROFR pricing policy.
    \236\ Id.
---------------------------------------------------------------------------

    The ROFR pricing policy leaves the pipeline at risk for any 
underutilized expansion capacity because the higher rate can only be 
charged to historical shippers if the facility is fully booked and 
there is a bid above the old vintage rate. Further, as the Commission 
stated in the Certificate Policy Statement, in pipeline contracts for 
newly constructed facilities, the pipeline should not rely on standard 
Memphis Clauses to deal with the risk of cost overruns, but should 
reach a contractual agreement with the new shippers concerning who will 
bear the risks of cost overruns. Therefore, responsibility for cost 
overruns should be resolved among the pipeline and the expansion 
shippers before construction, and cost overruns should not be included 
in general rate increases that could affect the rates of the existing 
shippers.
    AGA, APGA, Process Gas Consumers, and Keyspan are concerned that 
``gaming'' by the pipelines can defeat the goals of the Certificate 
Policy Statement. They argue that pipelines

[[Page 35759]]

will be able to manipulate the timing of system expansions and contract 
expirations so as to subvert the Commission's goals with respect to 
approval and pricing for new pipeline facilities, and take advantage of 
the forced subsidies by captive customers. Further, Process Gas 
Consumers state that the pipeline can manipulate the process by 
considering only expansions that would raise rates and ignore those 
that should cause rates to decrease.
    The concerns that pipeline's will ``game'' the system by scheduling 
expansions to coincide with contract expirations are without 
foundation. In order to implement a higher rate than the old maximum 
rate, the pipelines must implement a mechanism that reallocates costs 
between existing and expansion shippers without changing the pipeline's 
overall revenue requirement. The pipeline therefore obtains no 
additional revenue from implementing the higher maximum rate, and there 
is no incentive to game the system. Further, under the new construction 
policies, the pipeline must be prepared initially to finance the 
expansion project without subsidization from existing shippers. The 
circumstances where a higher maximum rate could be implemented are very 
limited and it would be quite risky for a pipeline to base a decision 
to expand its facilities on a prediction that these circumstances might 
be met. Moreover, the method chosen by the Commission for implementing 
this new pricing policy gives the Commission the ability to review any 
rate change mechanisms before they can take effect and gives existing 
shippers the ability to raise any concerns about gaming.
    Process Gas Consumers' concern that the pipeline could manipulate 
the process by considering only expansions that would raise rates and 
ignore those that should cause rates to decrease is also without 
foundation. In the Certificate Policy Statement, the Commission 
recognized that while incremental pricing will usually avoid subsidies 
for the new project, the situation may be different in the case of 
inexpensive expansability that is made possible by earlier costly 
construction. In that instance, because the existing customers bear the 
cost of the earlier more costly construction in their rates, 
incremental pricing could result in a subsidy to the new customers. 
This issue of rate treatment for cheap expansability must be resolved 
in each individual proceeding before construction. This will protect 
the existing shippers where the new shippers benefit from the prior 
construction.
    APGA also argues that the ROFR pricing policy is inconsistent with 
Order No. 637's stated goal of reducing revenue responsibility of 
captive customers because this policy could result in huge rate 
increases to captive customers at the end of their contracts. It is 
also inconsistent, APGA argues, with the rationale of the ROFR to 
protect captive customers at the end of the term of their contract. 
Process Gas Consumers also argue that the new policy violates the 
spirit of the ROFR derived from the NGA because the ROFR requires that 
a shipper match the highest rate being offered for that shipper's 
capacity under that shipper's existing rate schedule, not some number 
contrived from the rates paid by other shippers resulting from other 
expansions or other shippers' decisions.
    Contrary to AGPA's assertion, the ROFR pricing policy will not 
result in huge increases to captive customers at the end of their 
contracts. Rates will increase only in very limited situations, i.e., 
where the pipeline has vintages of capacity and charges different 
prices for the same service under incremental pricing; the pipeline is 
full; a competing shipper bids a rate for the capacity that is above 
the existing shipper's current maximum rate; and the pipeline has in 
place an approved mechanism for reallocating costs between the historic 
and incremental rates. Rates will increase only to the level that 
another new shipper is willing to pay for the service.
    The policy is not inconsistent with the purpose of the ROFR. The 
purpose of the ROFR is met because the existing customer is still 
protected against the exercise of market power by the pipeline since 
the pipeline cannot insist on the shipper paying a higher rate unless 
its expansion is fully subscribed and there is another bid for capacity 
at a rate above the vintage maximum rate charged the existing shipper. 
Any bid that the existing customer must meet to retain its service will 
be a just and reasonable rate. These conditions ensure that the 
pipeline is unable to use its market power over captive customers to 
withhold capacity from the market to raise price. Price will exceed the 
current maximum rate charged the existing shipper only when a higher 
price is needed to allocate scarce capacity. While existing pipelines 
have been filing certificate applications to expand their facilities, 
the expansion proposals concentrate in certain regions. There is no 
reason to expect that they would all result in expansions that would 
justify increasing the maximum rate for historic customers.
    In addition, APGA asserts that the ROFR pricing policy is 
anticompetitive because a customer whose contract expires soon will not 
be able to compete with another customer whose contract does not expire 
for a number of years. APGA asserts that the Commission's rationale for 
the ROFR pricing policy, i.e., that it will promote efficiency and 
fairness of capacity allocation, is erroneous because captive customers 
have no alternatives and therefore will be forced to pay the higher 
rate. Similarly, Keyspan asserts that, contrary to the Commission's 
suggestion, this policy will not create allocative efficiency, but will 
require captive customers to pay higher rates when their contracts 
expire so that incremental customers may pay less.
    APGA's concern that shippers with longer term contracts will have a 
competitive advantage over shippers with shorter term contracts is 
speculative. Further, awarding capacity to the shipper who values it 
the most does in fact promote allocative efficiency, and, as explained 
above, the only time that a shipper will have to bid a higher rate at 
the contract expiration is when the pipeline is fully booked and there 
is another bid for the capacity.
    In addition, APGA argues that the new ROFR pricing policy is 
directly inconsistent with the ROFR policy adopted for the electric 
industry in Order No. 888. APGA states that in Order No. 888-B, the 
Commission specifically held that the maximum rate that an electric 
transmission customer had to meet under the ROFR should not reflect any 
costs for incremental expansions that occurred during the term of the 
customer's contract that was expiring because ``the right of first 
refusal is predicated on an existing customer continuing to use its 
transmission rights in the existing transmission system.'' \237\ APGA 
asserts that this same rationale applies to the right of first refusal 
for captive gas transportation customers since these customers have no 
choice but to continue to use the existing capacity and thus should pay 
the rate applicable to that capacity. APGA states that the Commission 
has failed to justify the implementation of conflicting ROFR policies 
under its two enabling statutes which embody the same public interest 
standard.
---------------------------------------------------------------------------

    \237\ APGA cites Order No. 888-B, 81 FERC para. 61,248 at 62,085 
(1997).
---------------------------------------------------------------------------

    The Commission's policy is consistent with Order No. 888 and with 
the portion of Order No. 888-B quoted by AGPA. Order No. 888-B provides 
that the maximum rate that an existing customer

[[Page 35760]]

must pay to exercise its right of first refusal is ``the just and 
reasonable transmission rate on file at the time the customer exercises 
its right of first refusal'' \238\ and, further, that depending on the 
rate design on file for the existing capacity, ``a customer exercising 
its right of first refusal could face an average embedded cost-based 
rate, an incremental cost-based rate, a flow-based rate, a zonal rate, 
or any other rate design that the Commission may have approved under 
section 205 of the FPA.'' \239\ Thus, the electric customer exercising 
its ROFR is not guaranteed that it can continue service at its old 
maximum rate, but may be required to meet a bid up to the maximum 
system rate on file, just as the gas customer is required to do.
---------------------------------------------------------------------------

    \238\ 81 FERC at 62,085.
    \239\ 81 FERC at 62,085 n.90.
---------------------------------------------------------------------------

    New England argues that the policy is unfair because it ignores the 
fact that the existing shipper has supported the pipeline for many 
years through a series of long-term contracts for service. Now that 
these facilities are heavily depreciated, New England asserts that 
these customers should be permitted to receive service on these 
facilities that they funded. New England states that the new policy 
will negate settlements that are in place on certain pipelines. For 
example, New England states, on both the Tennessee and Algonquin 
systems, New England LDCs contracted for incremental services and paid 
incremental rates; by settlement, New England agreed to pay the 
incremental rate for a given period and gradually roll-in the costs of 
the facilities over time. Now that the rates are largely rolled-in, New 
England asserts, it will be denied the benefits of lower rates. New 
England states that having paid the higher rates for many years, it 
would be unfair to require these shippers to match a new incremental 
rate when the contract covering these facilities expires.
    As explained below, in order to implement a higher maximum rate, 
the pipeline must have in place a mechanism that allocates costs 
between historic and incremental rates. Procedures for approving such a 
mechanism will allow interested petitioners to participate, and 
settlements can be taken into account in determining whether a 
particular method is just and reasonable on a particular pipeline.
4. Implementation Mechanism
    In Order No. 637, the Commission gave pipelines the option of 
proposing an implementation mechanism either in a full section 4 rate 
case or through the filing of pro forma tariff sheets which would 
provide the Commission and the parties with an opportunity to review 
the proposal prior to implementation. Several petitioners argue that 
permitting the mechanism to be implemented in a limited section 4 
proceeding does not afford sufficient protections to assure that the 
rates will be just and reasonable. Process Gas Consumers state that the 
Commission generally restricts use of a limited section 4 proceeding to 
instances where pipelines are filing for trackers, true-ups and other 
minor changes, and that a pipeline seeking to raise its transportation 
rates is required to file a general section 4 rate case. In contrast, 
Process Gas Consumers state that this proposal would allow a pipeline 
to increase the existing shipper's base rate without a balanced 
opportunity to submit the rate increase to the full scrutiny of section 
4 to determine whether the rate is just and reasonable. Process Gas 
Consumers state that this procedure will not consider the cost savings 
from intervening pipeline depreciation, cost-cutting, or other 
efficiencies or additional revenues the pipeline may be receiving from 
new services or other load-enhancing initiatives. Process Gas Consumers 
argue that the Commission must require that if a pipeline believes that 
its expansion benefits other shippers to the extent that they should 
pay for them, such a case and decision should be made in a full section 
4 case to review the merits of roll-in, not through some backdoor 
easing in of higher maximum rates that will selectively penalize some 
shippers.
    A full section 4 rate proceeding is one of the options a pipeline 
may use to implement a mechanism, but the Commission will not require 
it. As the Commission explained in the Order Clarifying Statement of 
Policy, a full section 4 proceeding can be a cumbersome way to 
implement this mechanism because it examines cost and revenue items and 
other issues unrelated to the more limited cost allocation and rate 
design changes needed to readjust rates at contract expiration. 
Pipelines, therefore, can also establish the reallocation mechanism by 
filing pro forma tariff sheets which will provide the Commission and 
the parties sufficient opportunity to review the proposals. Once the 
review is completed, the pipeline can implement the mechanism through a 
limited section 4 filing.
5. Grandfathering of Existing Contracts
    Several of the petitioners \240\ argue that if the Commission does 
not reverse its ROFR pricing policy, it should allow each historical 
shipper on an incrementally priced pipeline the opportunity, upon 
expiration of its contract, to elect an extension term without exposure 
to roll-up. They argue it is unfair to apply the policy to existing 
contracts without a grandfather provision because the existing 
contracts were entered in reliance on a ROFR that required shippers to 
match the maximum rate for the existing service. They argue that had 
the new policy been in effect at the time the current contracts were 
executed, they would have signed a longer-term contract.
---------------------------------------------------------------------------

    \240\ E.g., ConEd, Florida Cities, New England.
---------------------------------------------------------------------------

    As the Commission explained in its Order Clarifying Statement of 
Policy,\241\ it is not appropriate to give existing customers one 
opportunity to renew their contracts at their existing maximum rate. 
Where there is insufficient capacity to satisfy all demands for 
capacity, an efficient system of capacity allocation would award the 
capacity to the shipper placing the greatest value on obtaining the 
capacity. A one-time mandatory renewal would conflict with that policy 
by permitting the existing shipper to continue service at a rate less 
than the highest bid.
---------------------------------------------------------------------------

    \241\ 90 FERC para. 61,128 (2000).
---------------------------------------------------------------------------

6. Clarification
    AGA and several other petitioners \242\ present various fact 
scenarios and ask the Commission to explain how the ROFR will operate 
in these situations. One question posed by these examples is if there 
is a maximum incremental rate in effect on a system, but none of the 
incremental shippers are paying the maximum rate, does the shipper 
exercising its ROFR have to match a bid above the highest rate actually 
being paid, or can the shipper retain its capacity by paying the 
highest rate being paid by an incremental shipper. Other scenarios pose 
questions concerning what depreciation rate should be used to calculate 
the incremental rate that must be matched by the existing shipper, 
whether the rate is affected if the Commission places the pipeline at 
risk for underrecovery of costs, how the policy will apply on a zoned 
system,\243\ how the pricing policy

[[Page 35761]]

will operate if a new shipper bids for a portion of the available 
capacity,\244\ and whether a different result should occur if the 
expansion shipper is an affiliate of the pipeline. In addition, the 
petitioners ask what incremental rate will be the maximum rate on 
pipelines with more than one such rate and how will increased revenues 
paid by pre-existing shippers be credited back to incremental shippers. 
Keyspan asks the Commission to clarify if a shipper's contract expires 
in the year 2001, and is subject to the ROFR, and there is a bid in 
excess of the pre-expansion rate such that the shipper must match that 
bid, will a shipper whose contract is for the same basic capacity but 
expires in 2002 have to match what was paid in 2001 if there are no 
competing bids, or can the shipper utilizing its ROFR in 2002 simply 
match the pre-existing rate.
---------------------------------------------------------------------------

    \242\ ConEd, Keyspan, National Fuel, and New England.
    \243\ AGA gives an example where a shipper has long-haul 
capacity on zones 1-5 of a zoned system, and an incremental rate is 
in effect on zone 5 and asks, if, at the conclusion of the contract, 
another potential shipper bids on zone five capacity, must the 
existing shipper match the bid for zone 5 short-haul, plus the 
maximum system-wide maximum rate for the haul across zones 1-4.
    \244\ AGA posits a situation where a new potential shipper seeks 
10,000 Dth per day of capacity on incremental facilities bearing an 
incremental rate, and at the same time, 50,000 Dth per day is 
expiring under contracts containing the regulatory right of first 
refusal, and asks whether the holders of all 50,000 Dth per day must 
match the incremental rate offered by the potential shipper.
---------------------------------------------------------------------------

    National Fuel Gas Distribution asks the Commission to clarify that 
if a shipper is expected to pay a higher rate, it must only be in the 
instances where the other shipper is receiving the same service. 
Distribution states that a shipper may be paying a higher rate on a 
lateral built specifically for that shipper, but this should not impact 
a long-haul shipper's cost.
    New England states that the proposal will be difficult to 
implement. New England states that it will not always be a simple 
matter to determine whether a pipeline is full--the fact that there is 
a competing bid does not necessarily means that the system is full--if 
the competing bidder is a new shipper, it may simply mean that the 
``old'' capacity held by the existing shipper is a better deal for the 
new shipper.
    The fact patterns presented by the petitioners are complicated, and 
the Commission concludes that it will be preferable to address complex 
factual situations if and when they arise in the individual pipeline 
proceedings to implement the ROFR pricing policy. Moreover, many of the 
questions do not have generic application but are specific to the 
particular factual circumstances on a particular pipeline system. The 
implementation mechanism chosen by the Commission will permit the 
Commission and the parties to consider all the relevant facts in the 
specific context before applying the general pricing policy. Some of 
the issues raised by the petitioners, however, can be clarified here. 
Thus, the Commission clarifies that the existing shipper must match the 
highest bid incremental rate up to the maximum incremental being paid 
on the system. If there is a factual question as to whether there is 
sufficient capacity to satisfy demand on a particular pipeline, that 
issue can be addressed in the individual proceeding.
7. Geographical Segmentation
    In Order No. 637, the Commission stated that it would not enhance 
the right of first refusal by holding that it can be exercised for a 
geographic portion of the existing contract, as requested by several 
petitioners. The Commission explained that the purpose of the right of 
first refusal is to protect the captive customer's historical service, 
and therefore it should apply only when the existing shipper is seeking 
to contract for its historical capacity. The Commission further 
explained that the right of first refusal is a limited right and was 
never intended to permit shippers to increase or change their 
service.\245\ It is intended to be a means of defense against pipeline 
market power, not a mechanism to award an existing shipper a preference 
over a new shipper for a different service.
---------------------------------------------------------------------------

    \245\ As the Commission stated in Williams Natural Gas Company, 
65 FERC para. 61,221 at 62,013 (1993), ``the character of the 
service being provided under the expiring contract cannot be changed 
through use of the right of first refusal.''
---------------------------------------------------------------------------

    A shipper that can terminate a geographic portion of its historical 
service must have alternatives in the market that can substitute for 
its historical service, and therefore the Commission has concluded as a 
matter of policy that such a shipper does not require the protection of 
the ROFR. Further, as the Commission stated in Order No. 637, 
permitting the exercise of the ROFR for a geographic portion of the 
historical capacity could leave the capacity unused, and thus burden 
the pipeline and its other customers with the unused capacity. 
Therefore, the Commission concluded that maintaining the current policy 
and not expanding the right of first refusal strikes the appropriate 
balance between protecting the historic service of the captive customer 
and not burdening the pipeline and its other customers with unused 
capacity. AGA, Keyspan, Koch, and New England seek rehearing of the 
Commission's decision on this issue.
    The petitioners argue that while the Commission has characterized 
its decision as a refusal to enhance the ROFR, current Commission 
policy permits exercise of the ROFR for a geographic portion of the 
capacity. They argue that Order No. 636-A provides that the ROFR 
applies to a ``portion'' of the pipeline's capacity without restricting 
the definition of ``portion,'' \246\ and that subsequently, in Williams 
Natural Gas Co.\247\ the Commission applied this policy to permit a 
shipper to exercise its right of first refusal to retain its market 
area and storage area portion of a service agreement, but not the 
production area capacity. Keyspan states that Order No. 637 is also 
inconsistent with the Commission's reasoning in Tennessee Gas Pipeline 
Co.,\248\ where the Commission held that because the pipeline's tariff 
did not require shippers to take transportation in both the production 
and market area, customers renewing their contracts could choose not to 
take production area capacity. These petitioners argue that the 
Commission has failed to provide an adequate basis for its departure 
from its prior holdings.
---------------------------------------------------------------------------

    \246\ AGA cites Order No. 636-A, FERC Stats. & Regs. 
[Regulations Preambles 1991-1996] para. 31,950 at 30,635 (1992).
    \247\ 81 FERC para. 61,350 at 62,627-28 (Williams I), reh'g, 83 
FERC para. 61,052 (Williams II) (1997).
    \248\ 76 FERC para. 61,022 at 61,128-29 (1999).
---------------------------------------------------------------------------

    The Commission's decision is not a departure from its prior 
holdings. While, as the parties point out, Order No. 636 provides that 
the ROFR applies to a ``portion'' of the pipeline's capacity without 
defining the word ``portion,'' the Commission's subsequent decisions 
interpreting the scope of the term ``portion'' have defined ``portion'' 
to include a volumetric portion of the capacity, but have decline to 
extend the definition to include a geographic potion. Thus, in 
Transcontinental Gas Pipeline Co.\249\ the Commission explained that 
the question of whether the ROFR should apply to a geographic portion 
of the capacity is a different question from whether it should apply to 
a volumetric portion of the capacity, and raises different policy 
concerns. Upon further consideration of these policy issues, the 
Commission determined in Order No. 637 that extending the ROFR to allow 
it to be exercised for a geographic portion of the capacity would not 
be consistent with its original purpose. As the Commission explained in 
Order No. 637, the ROFR is intended to protect captive customers and 
their historic capacity against the pipeline's exercise of market 
power, and is not intended to give existing shippers an advantage over 
other customers

[[Page 35762]]

seeking new or different service from the pipeline. The Williams 
decision is not to the contrary. In Williams the Commission addressed a 
specific factual situation where no-notice service on the pipeline had 
separate transportation and storage components. In Williams, the 
Commission limited its holding to a situation where service was 
provided in the production area and the market area under different 
rates schedules, and the Commission expressly stated that it ``does not 
reach the issue of the existing shippers' ability to bid for different 
volumes of capacity in different zones under the same rate schedule.'' 
\250\ Thus, the Commission's decision in that case was not a generic 
holding, but was based on the specific service characteristics of the 
pipeline.
---------------------------------------------------------------------------

    \249\ 88 FERC para. 61,155, reh'g denied, 88 FERC para. 61,295 
(1999). See also Texas Eastern Transmission Corp., 88 FERC para. 
61,167, reh'g denied, 88 FERC para. 61,291 (1999).
    \250\ Williams, 81 FERC para. 61,350 at 62,627 n.20.
---------------------------------------------------------------------------

    Because of the potential impact on pipeline recovery, the 
Commission will not make a generic finding that shippers may exercise 
their ROFR for a geographic portion of its capacity. The determination 
whether this result is justified in a particular case will depend on 
the specific facts, as was the case in Williams and Tennessee.
    The petitioners challenge the accuracy of the Commission's 
statement that a shipper that can terminate a geographic portion of its 
historical service must have alternatives in the marketplace that can 
substitute for its historical service and therefore is not a captive 
customer that requires the right of first refusal. They assert that a 
customer seeking to retain a portion of its service is in all 
likelihood a captive customer with respect to the portion of the 
service it seeks to retain, and that if the pipeline can use its 
monopoly power in the market area to require a shipper to purchase 
capacity in the production area, the shipper really does not have 
alternatives. New England states that because the Commission's factual 
conclusion is inaccurate, the decision to deny ROFR protection to 
customers seeking to take a geographic portion of their current 
capacity does not meet the standard set forth by the UDC court--it does 
not adequately protect captive customers from the exercise of pipeline 
market power.
    The petitioners also state that the Commission's concerns about 
unused capacity do not justify its decision. AGA asserts that these 
concerns are speculative because projections for increased gas usage 
over the next decade suggest that capacity turnback by LDCs may not 
create significant problems for interstate pipelines, and that if 
unsubscribed capacity does result, there are effective policies for 
addressing turnback capacity generally and in individual pipeline 
proceedings. Keyspan states that the Commission does not explain why it 
is appropriate for captive customers, rather than the pipeline, to bear 
this burden. In addition, Keyspan states that the court's decision in 
Municipal Defense Group v. FERC (MDG) \251\ cited by the Commission 
does not support its decision on geographical segmentation. Keyspan 
states that in that case the court decided that customers competing for 
new capacity must do so on an equal basis, while here the customers 
seeking to use the ROFR are not seeking new capacity; they are seeking 
capacity to which they have a right under section 7(b) of the NGA. In 
addition, Keyspan states that the Commission has held that third 
parties can submit a bid for a portion of a customer's capacity that is 
subject to the ROFR.\252\ Keyspan argues that to the extent that third 
parties can bid for a geographic portion of a customer's capacity, the 
existing customer cannot be said to be competing with a third party on 
a level playing filed as was the case in MDG.
---------------------------------------------------------------------------

    \251\ 170 F.3d 197 (D.C. CIR. 1999).
    \252\ Keyspan cites Order No. 636, FERC Stats and Regs. (1991-
1996) para. 30,939 at 30,451-52 (1992).
---------------------------------------------------------------------------

    These arguments ignore the fact that the ROFR is intended to 
protect the historic service of captive customers from the pipeline's 
exercise of market power. It is not intended to give existing shippers 
an advantage over other shippers in bidding for a different or new 
service. What the petitioners seek on rehearing is a preference to 
obtain pipeline service over other shippers where that service is 
limited and is of high value, and at the same time obtain the ability 
to change the character of their historic service by eliminating 
geographic segments that are of less value. The ROFR allows the captive 
customer to keep its historic capacity, but only when the customer bids 
for that capacity. If a customer with a ROFR decides that it wants to 
change its historic service and compete with other shippers, it can 
always do so, but it cannot retain the ROFR to give it a competitive 
advantage over other shippers in these circumstances. Moreover, if a 
third party bids for a portion of their capacity, they may exercise 
their ROFR to retain the capacity and thus, contrary to Keyspan's 
argument, the existing customer has an advantage over the third party 
bidder.
    The petitioners also argue that the same rationale that the 
Commission used in determining that a customer can exercise its ROFR 
for a volumetric potion of the customer's capacity applies with regard 
to a geographic portion of the capacity. They assert that the 
Commission acknowledged that the purpose of allowing the existing 
capacity holder to exercise its ROFR to retain a volumetric portion of 
its capacity was to ensure against the inefficient or unnecessary 
holding of capacity at the expiration of the contract. They assert that 
the Commission has failed to provide a persuasive rationale for 
requiring the inefficient retention of capacity on a geographic basis.
    However, there are different considerations involved in permitting 
a shipper to take a geographical portion of its capacity. Allowing 
shippers to ``cherry pick'' the most desirable segments of their 
historic capacity is far more likely to leave the pipeline with 
stranded capacity than permitting a customer to take a volumetric 
portion for the entire length of the haul. Further, it gives the 
shipper with the ROFR a competitive advantage over other shippers, 
while allowing a shipper to take a volumetric portion of the capacity 
merely allows the customer to adjust its volume of capacity under 
contract to meet a changing demand.
    The petitioners also argue that Order No. 637 is inconsistent with 
the Commission's policy of fostering competition. They state that 
allowing shippers to exercise their right of first refusal for a 
geographic portion of the capacity will promote market centers and 
liquid gas trading points, and facilitate the development of a 
competitive market that the Commission hopes to achieve in this order. 
Koch argues that it is anticompetitive to allow pipelines to require 
that shippers in the market area must hold capacity in the production 
area, and this limits customer's choices and the competitors ability to 
serve customers on these lines.
    Koch acknowledges that it would be inappropriate to allow a 
customer to carve out a small, discrete portion of its capacity and 
exercise its right of first refusal on only that portion, but that it 
is different to allow a customer to exercise its right of first refusal 
for a pipeline's market area facilities so that it could select the 
production area facilities of another pipeline. Koch and Keyspan argue 
that this change would allow customers to benefit from wellhead 
competition and bring all the benefits of competition to parties that 
historically have been subject to the market power of the longline 
pipelines. Keyspan argues that the Commission's failure to afford 
captive customers the same choices as customers with alternatives is 
unduly discriminatory and cannot be reconciled with the

[[Page 35763]]

court's decision in Maryland Peoples Counsel v. FERC \253\ and Maryland 
Peoples Counsel v. FERC.\254\ Keyspan states that in those decisions, 
the court held that the Commission could not adequately explain its 
decision to exclude captive customers from the benefits of certain 
pipeline programs, and that therefore the programs were unduly 
discriminatory. Similarly, Keyspan argues, in this case, the Commission 
has failed to explain its decision to refuse to afford captive 
customers the ability to exercise their ROFR rights to choose to renew 
only certain geographic portions of their contracts even though such 
alternatives are available to customers with competitive options.
---------------------------------------------------------------------------

    \253\ 761 F.2d 768, 770 (D.C. Cir. 1985) (MPCI).
    \254\ 761 F.2d 780, 781 (D.C. Cir. 1985) (MCPII).
---------------------------------------------------------------------------

    Koch states that, contrary to the Commission's assertion, this 
would not change the type of service that the shipper is receiving. 
Koch states that the only change would be to the primary receipt 
points, and that all other aspects would remain the same, including the 
type of service and contract term. Keyspan also states that on a long-
line system, transportation typically can be purchased on an individual 
zone basis and, as a result, permitting customers to exercise their 
ROFR on a geographic basis does not permit shippers to change their 
existing service. Koch states that if the service the customer is 
purchasing is a production area to market area service, then it is an 
anti-competitive tying arrangement that the Commission should eliminate 
independent of its right of first refusal policy.
    Koch states that, not only does this policy cause an inefficient 
allocation of capacity, it also sends garbled price signals regarding 
the construction of new capacity and the corresponding value of that 
new capacity. Koch states that this distorted information will lead to 
overbuilding of capacity by the wrong pipeline, which will eventually 
lead to stranded costs. If the Commission does not grant rehearing on 
this point, Koch asks that the Commission direct the pipelines to amend 
their tariffs to provide that a customer can lose its ROFR only if 
another customer agrees to pay a rate that has a higher net present 
value for the original long haul than the customer is willing to pay 
for the short haul.
    Shippers with a ROFR have the same rights to bid on geographic 
portions of a system, and not on other portions of the system, such as 
the production area, as any other shipper. Thus, this is not similar to 
Maryland Peoples' Counsel where captive customers were denied a benefit 
that was provided to non-captive customers. However, when bidding for a 
geographical portion of its capacity, the existing customer must 
compete with other shippers on an equal basis, and not have an 
advantage through the ROFR. If another bidder creates a greater net 
present value by bidding for a long-haul, then that bidder should 
receive the capacity. If the customer with the ROFR produces the 
highest net present value with a bid for less than the full length of 
haul, then it may be able to get the capacity. This benefits the system 
as a whole and most customers because it brings more revenue to the 
system, and the Commission has consistently allowed pipelines to 
allocate their capacity on that basis.\255\
---------------------------------------------------------------------------

    \255\ See Tennessee Gas Pipeline Co., 91 FERC para. 61,053 
(2000).
---------------------------------------------------------------------------

    Texas Eastern seeks clarification, or in the alternative, rehearing 
of the Commission's discussion in Order No. 637 of the shippers' right 
to exercise its ROFR for a volumetric portion of its capacity. Texas 
Eastern asks the Commission to clarify that its customers do not have 
the right to unilaterally terminate portions of their agreements unless 
Texas Eastern has provided notice of termination because that is the 
way Texas Eastern's approved tariff operates. National Fuel raises the 
same issue with regard to Texas Eastern's tariff and asks the 
Commission to clarify that where a tariff is inconsistent with the 
shipper's right to reduce its volumetric capacity, the pipeline should 
be required to file tariff language consistent with the Commission's 
clarification.
    The Commission will not address any tariff-specific issues in this 
proceeding. However, the Commission has held that the regulatory right 
of first refusal permits the capacity holder to elect to retain a 
volumetric portion of its capacity, regardless of the terms of any 
tariff. If there are any issues regarding a specific tariff provision, 
they may be addressed in the individual compliance filings.
8. Five-Year Cap
    In Order No. 637, the Commission stated that it would not change 
the length of the term matching cap at this time. In Order No. 636-C, 
the Commission had determined a five-year matching cap was appropriate 
given the evidence in that record of the industry trends in contract 
length, and none of the petitioners in this proceeding presented 
evidence to show that a five-year contract is atypical in the current 
market.
    On rehearing, INGAA, Great Lakes, and The Williams Companies argue 
that the Commission should remove the term matching cap. These 
petitioners argue that there is evidence showing adverse consequences 
of the five-year cap,\256\ and that the five-year cap continues a 
fundamental imbalance in the risks assumed by a pipeline and shipper.
---------------------------------------------------------------------------

    \256\ INGAA argues that it could result in substantial turnback 
capacity due to the ROFR's bias toward one-year contracts. Great 
Lakes argues that the five-year matching cap places an unnecessary 
stranded capacity risk on the pipeline because it cannot sell, 
combine with other capacity becoming available, or reduce the need 
for incremental expansions by utilizing the excising shipper's 
capacity until the shipper rejects its ROFR.
---------------------------------------------------------------------------

    INGAA argues it is illogical and unsupportable to retain the term 
matching cap on the basis that it is the median length of long-term 
contracts entered into since January 1, 1995. INGAA states that this 
treats half of all renewal contracts entered into since January 1, 1995 
as unreasonable, when in fact the market has determined that contracts 
having terms longer than five years are necessary or appropriate based 
on commercial considerations. INGAA argues that the Commission should 
lift the cap and permit market forces to determine what length of 
contract an existing shipper must match.
    TWC and Great Lakes assert that shippers that have competitive 
alternatives do hold maximum rate firm contracts with rights of first 
refusal, and TWC argues that the Commission should conclude that the 
five-year matching cap will not apply unless the shipper makes a 
positive showing that it is a captive customer and has no available 
alternatives. In addition, Great Lakes asserts that removal of the 
five-year cap does not create any unreasonable disadvantages for the 
existing shipper because if there are no other bidders, the existing 
shipper can renew its contact for any period, and if there are bidders, 
it can renew its contract by matching whatever term another shipper is 
willing to offer. Finally, Great Lakes argues that the Commission's 
retention of the five-year cap is inconsistent with its decision on 
ROFR incremental pricing. Great Lakes argues that since it is 
appropriate to subject a renewing shipper to market forces with regard 
to price, it is also appropriate to subject renewing shippers to market 
forces with regard to contract term.
    The Commission adopted the five-year matching cap in Order No. 636-
C in response to the Court's remand of the 20-year matching cap in UDC. 
In UDC, the court approved of the concept of a term-matching limitation 
``as a rational

[[Page 35764]]

means of emulating a competitive market for allocating firm 
transportation capacity,'' \257\ but found that the Commission had 
failed to justify a 20-year matching cap. Thus, eliminating the term-
matching cap as requested by the parties is not consistent with the 
Court's opinion in UDC. As the Commission explained in Order No. 637, 
there is no evidentiary basis at this time for changing the 5-year 
matching cap. The pipelines are not disadvantaged by the term-matching 
cap because it merely substitutes for the section 7(b) requirement that 
the pipeline obtain permission prior to abandoning service.
---------------------------------------------------------------------------

    \257\ UDC, 88 F.3d at 1140.
---------------------------------------------------------------------------

B. Negotiated Terms and Conditions

    In Order No. 637, the Commission determined not to move forward at 
this time with pre-approved negotiated terms and conditions of service. 
The Commission explained that pipelines have been able to create open 
access tariff-based services with enhanced flexibility for scheduling 
and handling imbalances without having to negotiate terms and 
conditions of service with individual shippers, and, therefore, it is 
not clear that pre-approved negotiated terms and conditions of service 
are necessary. Further, the Commission explained that the negotiation 
of terms and conditions of service is directly related to the question 
of whether the Commission needs to revise its regulatory policy to 
accommodate a dual market structure in which some shippers with 
sufficient alternatives want to negotiate terms and conditions of 
service while other shippers remain captive, still subject to the 
pipeline's market power. Thus, the Commission concluded that the 
development of a two-track regulatory model requires further study of 
the interrelation between various aspects of Commission regulatory 
policy. TWC, Amoco, NGSA, INGAA, and CNG have asked for rehearing or 
clarification of this portion of Order No. 637.
    TWC asserts that it is concerned that the Commission's existing 
procedures for implementing new rate schedules and non-conforming 
contracts are too slow and cumbersome to respond to the needs of the 
marketplace, and argues that the Commission should grant rehearing and 
permit negotiated rates and terms and conditions of service. However, 
as explained above, in Order No. 637, the Commission exercised its 
discretion to defer further consideration of this issue because it 
raises other policy questions that are not the subject of this 
proceeding. There is no basis for granting rehearing of this decision, 
and TWC's request for rehearing is denied.
    Amoco and NGSA ask the Commission to further clarify the 
distinction between negotiated rates and negotiated terms and 
conditions, and how it will treat capacity turnback issues. INGAA and 
CNG urge the Commission to move forward with allowing negotiated terms 
and conditions as soon and feasible, and, in the interim, to be 
responsive to innovative service offerings that may be filed within the 
existing regulatory framework.
    In Order No. 637, the Commission explained that it is not possible 
to formulate generic definitions applicable to all potential 
situations, but generally the Commission considers negotiated terms and 
conditions to be related to operational conditions of transportation 
service while negotiated rates would include the price, the term of 
service, the receipt and delivery points, and the quantity. A 
negotiated rate would not include conditions or activities related to 
the transportation of gas on the pipeline, such as scheduling, 
imbalances, or operational obligations, such as OFOs. The Commission 
will not further define the terms in this proceeding, but will consider 
specific issues, including capacity turnback issues, in response to the 
service offerings filed in individual pipeline proceedings.

V. Miscellaneous Issues

A. Corrections to Regulations

    In Order No. 637, the Commission sought to consolidate its 
reporting requirements for pipelines providing open access service 
under subpart B (transportation under section 311 of the NGPA) and 
subpart G (open access transportation under the NGA) in a single 
section, Sec. 284.13. But the reports concerning bypass of LDC 
facilities required under subpart B (Sec. 284.106) were not included in 
Sec. 284.13, remaining in Sec. 284.106. Prior to Order No. 637, subpart 
G pipelines were required to file bypass reports, because 
Sec. 284.223(b) contained a cross-reference requiring subpart G 
pipelines to comply with each of the reporting requirements in 
Sec. 284.106, which included the bypass reports. However, in Order No. 
637, Sec. 284.223(b) was removed, with the unintended effect of 
eliminating the existing requirement that subpart G pipelines file 
bypass reports. To correct this error, the Commission is revising the 
regulations to include the bypass reports in Sec. 284.13(f), so that 
the pre-existing requirement for both subpart B and subpart G pipelines 
to file bypass reports will be maintained.

B. Filing of Pro Forma Tariff Sheets

    The Commission's April 12, 2000 order \258\ established a schedule 
for pipelines to file the pro forma tariff sheets necessary to comply 
with the regulations governing scheduling, segmentation, and penalties. 
Pipelines making pro forma tariff filings in response to this order 
must make these filings as new RP dockets and should file the pro forma 
tariff sheets on paper as well as electronically as provided in section 
154.4 of the Commission's regulations.\259\ To reduce the burden 
required to convert the pro forma tariff sheets to final sheets, the 
pro forma sheets should be filed as if they are proposed revisions of 
sheets in the existing tariff volume (with changes identified as 
provided in Section 154.201 of the Commission's regulations) with the 
words Pro Forma before the volume name, e.g., Fourth Revised Sheet No. 
150, FERC Gas Tariff, Pro Forma Third Revised Volume No. 1. For the 
electronically filed tariff sheets, Pro Forma should be inserted at the 
beginning of the name field (VolumeID) in the Tariff Volume Record, 
i.e., the TF02 record. When the pipeline files the final tariff sheets, 
it need only remove the phrase pro forma for any unchanged sheets.
---------------------------------------------------------------------------

    \258\ Regulation of Short-Term Natural Gas Transportation 
Services 91 FERC para. 61,020 (2000).
    \259\ 18 CFR 154.4.
---------------------------------------------------------------------------

    Pipelines should file the electronic pro forma tariff sheets 
through Internet E-Mail to <a href="/cdn-cgi/l/email-protection#3a0c090d7c7b696e687a5c5f4859145c5f5e144f49"><span class="__cf_email__" data-cfemail="faccc9cdbcbba9aea8ba9c9f8899d49c9f9ed48f89">[email protected]</span></a> in the following 
format: on the subject line, specify the name of the filing entity; in 
the body of the E-Mail, specify the name, telephone number, and E-Mail 
address of a contact person; the pro forma tariff sheets should be 
attached to the E-Mail message. The Commission will send a reply to the 
E-Mail to acknowledge receipt. Questions about E-Mail filing should be 
directed to Lorena Finger at 202-208-1222, or by E-Mail to 
<a href="/cdn-cgi/l/email-protection#c4a8abb6a1aaa5eaa2adaaa3a1b684a2a1b6a7eaa2a1a0eab1b7"><span class="__cf_email__" data-cfemail="c4a8abb6a1aaa5eaa2adaaa3a1b684a2a1b6a7eaa2a1a0eab1b7">[email protected]</span></a>, or to Albert Rogers at 202-208-0078 or by E-
Mail to <a href="/cdn-cgi/l/email-protection#60010c020512144e120f0705121320060512034e0605044e1513"><span class="__cf_email__" data-cfemail="11707d737463653f637e7674636251777463723f7774753f6462">[email protected]</span></a>.
    Pipelines unable to file using Internet E-Mail must file the pro 
forma tariffs on diskette along with the paper filing and must label 
the diskette as containing pro forma tariff sheets.

VI. Effective Date

    The amendments to the Commission's regulations adopted in this 
order will become effective July 5, 2000.

[[Page 35765]]

List of Subjects in 18 CFR Part 284

    Continental shelf; Incorporation by reference; Natural gas; 
Reporting and recordkeeping requirements.

    By the Commission. Commissioner Massey concurred with a separate 
statement attached.
Linwood A. Watson, Jr.,
Acting Secretary.

    In consideration of the foregoing, the Commission amends Part 284, 
Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE 
NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES

    1. 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.

    2. In Sec. 284.8, paragraph (i) is revised to read as follows:


Sec. 284.8  Release of firm transportation service.

* * * * *
    (i) Waiver of maximum rate ceiling. Until September 30, 2002, the 
maximum rate ceiling does not apply to capacity release transactions of 
less than one year. The provision of paragraph (h)(1) of this section 
providing an exemption from the posting and bidding requirements for 
transactions at the applicable maximum tariff rate for pipeline 
services will not apply as long as the waiver of the rate ceiling is in 
effect. With respect to releases of 31 days or less under paragraph (h) 
of this section, the requirements of paragraph (h)(2) of this section 
will apply to all such releases regardless of the rate charged.

    3. In Sec. 284.12, the first sentence of paragraph (c)(2)(iii) and 
paragraph (c)(2)(v) are revised to read as follows:


Sec. 284.12  Standards for pipeline business operations and 
communications.

* * * * *
    (c) * * *
    (2) * * *
    (iii) Imbalance management. A pipeline with imbalance penalty 
provisions in its tariff must provide, to the extent operationally 
practicable, parking and lending or other services that facilitate the 
ability of its shippers to manage transportation imbalances. * * *
* * * * *
    (v) Penalties. A pipeline may include in its tariff transportation 
penalties only to the extent necessary to prevent the impairment of 
reliable service. Pipelines may not retain net penalty revenues, but 
must credit them to shippers in a manner to be prescribed in the 
pipeline's tariff. A pipeline with penalty provisions in its tariff 
must provide to shippers, 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.
* * * * *

    4. In Sec. 284.13, paragraphs (b)(1) introductory text, 
(b)(1)(viii), (b)(2) introductory text, b(2)(iv), (b)(2)(vi), and 
paragraph (d)(1) are revised, and paragraph (f) is added, to read as 
follows:


Sec. 284.13  Reporting requirements for interstate pipelines.

* * * * *
    (b) * * *
    (1) For pipeline firm service and for release transactions under 
Sec. 284.8, the pipeline must post with respect to each contract, or 
revision of a contract for service, the following information no later 
than the first nomination under a transaction:
* * * * *
    (viii) Special terms and conditions applicable to a capacity 
release transaction, including all aspects in which the contract 
deviates from the pipeline's tariff, and special details pertaining to 
a pipeline transportation contract, including whether the contract is a 
negotiated rate contract, conditions applicable to a discounted 
transportation contract, and all aspects in which the contract deviates 
from the pipeline's tariff.
* * * * *
    (2) For pipeline interruptible service, the pipeline must post on a 
daily basis no later than the first nomination for service under an 
interruptible agreement, the following information:
* * * * *
    (iv) The receipt and delivery points covered between which the 
shipper is entitled to transport gas at the rate charged, including the 
industry common code for each point, zone, or segment;
* * * * *
    (vi) Special details pertaining to the agreement, including 
conditions applicable to a discounted transportation contract and all 
aspects in which the agreement deviates from the pipeline's tariff.
* * * * *
    (d) * * *
    (1) An interstate pipeline must provide on its Internet web site 
and in downloadable file formats, in conformity with Sec. 284.12 of 
this part, equal and timely access to information relevant to the 
availability of all transportation services whenever capacity is 
scheduled, 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 
whenever capacity is scheduled, and all planned and actual service 
outages or reductions in service capacity.
* * * * *
    (f) Notice of bypass. An interstate pipeline that provides 
transportation (except storage) to a customer that is located in the 
service area of a local distribution company and will not be delivering 
the customer's gas to that local distribution company, must file with 
the Commission, within thirty days after commencing such 
transportation, a statement that the interstate pipeline has notified 
the local distribution company and the local distribution company's 
appropriate regulatory agency in writing of the proposed transportation 
prior to commencement.


Sec. 284.106  [Removed and reserved]

    5. Section 284.106 is removed and reserved.
    6. In Sec. 284.221, paragraph (d)(2)(ii) is revised to read as 
follows:


Sec. 284.221  General rule; transportation by interstate pipelines on 
behalf of others.

* * * * *
    (d) * * *
    (2) * * *
    (ii) Gives notice that it wants to continue its transportation 
arrangement and will match the longest term and highest rate for its 
firm service, up to the applicable maximum rate under Sec. 284.10, 
offered to the pipeline during the period established in the pipeline's 
tariff for receiving such offers by any other person desiring firm 
capacity, and executes a contract matching the terms of any such offer. 
To be eligible to exercise this right of first refusal, the firm 
shipper's contract must be for service for twelve consecutive months or 
more at the applicable maximum rate for that service, except that a 
contract for more than one year, for a service which is not available 
for 12 consecutive months, would be subject to the right of first 
refusal.
* * * * *

    Note: The following appendix will not appear in the Code of 
Federal Regulations.


[[Page 35766]]



Appendix

Rehearing Requests Filed in Docket Nos. RM98-10-000 and RM98-12-000

REHEARING REQUEST AND ABBREVIATION

American Gas Association--AGA
American Public Gas Association--APGA
Amoco Energy Trading Corporation and Amoco Production Company--Amoco
Arkansas Gas Consumers--Arkansas Gas Consumers
Atlanta Gas Light Company--Atlanta or AGLC
Cibola Energy Services Corporation--Cibola
CNG Transmission Corporation--CNG
Coastal Companies--Coastal
Columbia Gas Transmission Corporation--Columbia Gas
Columbia Gulf Transmission Co.--Columbia Gulf
Consolidated Edison Company of New York, Inc. and Orange and 
Rockland Utilities Inc.--ConEd or Con Edison
Dynegy Inc.--Dynegy
El Paso Energy Corporation Interstate Pipelines--El Paso
Enron Interstate Pipelines--Enron
Florida Cities--Florida Cities
FPL Energy, Inc.--FPL Energy
Great Lakes Gas Transmission Limited Partnership-- Great Lakes
Illinois Municipal Gas Agency--IMGA or Illinois Municipal Gas Agency
Independent Oil and Gas Association of West Virginia--IOGA of WV
Independent Petroleum Association of America--IPAA
Indicated Shippers--Indicated Shippers
Interstate Natural Gas Association of America--INGAA
Keyspan Gas East Corporation and the Brooklyn Union Gas Company--
Keyspan
Kinder Morgan Pipelines--Kinder Morgan
Koch Gateway Pipeline Company--Koch
Michigan Gas Storage Company--MGS or Michigan Gas Storage
Minnesota Department of Commerce--MDOC or Minnesota
National Association of State Utility Consumer Advocates, Ohio 
Office of the Consumers Counsel, Pennsylvania Office of Consumer 
Advocate--NASUCA
National Energy Marketers Association--NEM
National Association of Gas Consumers--NAGC
National Fuel Gas Distribution Corporation--National Fuel 
Distribution
Natural Gas Supply Association--NGSA
New England Gas Distributors--New England
Niagara Mohawk Energy, Inc.--NM Energy
Northwest Industrial Gas Users--NWIGU
Ohio Oil & Gas Association--OOGA
Paiute Pipeline Company--Paiute
Process Gas Consumers Group (American Iron and Steel Institute, 
Georgia Industrial Group, American Forest and Paper Association 
ALCOA, Inc. and United States Gypsum Company)--Process Gas Consumers 
or Industrials
Reliant Energy Gas Transmission Company and Mississippi River 
Transmission Corporation--Reliant
Reliant Energy Minnegasco--Minnegasco
Scana Energy Marketing, Inc.--Scana
Tejas Offshore Pipelines, LLC--Tejas
Texas Eastern Transmission Corporation--Texas Eastern
UGI Utilities, Inc.--UGI
Washington Gas Light Company--Washington Gas
Williams Companies, Inc.--Williams
Williston Basin Interstate Pipeline Company--Williston
Wisconsin Distribution Group--WDG

    MASSEY, Commissioner, concurring:
    One aspect of today's order that I would regard as a retreat 
from Order No. 637 is the change in the time at which pipelines must 
file transactional reports. Today's order would alter the timing of 
the contemporaneous posting of transactional information, from 
contract execution to first nomination prior to gas flow. 
Ostensibly, this is being done to achieve comparability between the 
reporting requirements for pipeline transactions and those for 
capacity release transactions, which was one of the stated 
objectives of Order No. 637. With this change, however, one can 
still regard the pipeline transactional filing requirements as 
contemporaneous if one is referring to the first nomination prior to 
gas flow. Nevertheless, I would have preferred not to make this 
change.
    On balance, however, this is a solid, well-reasoned order that 
retains the character of the original order in most respects.

William L. Massey,
Commissioner.

[FR Doc. 00-13216 Filed 6-2-00; 8:45 am]
BILLING CODE 6717-01-P


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