35706 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

1Regulation 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 ¶ 31,091 (Feb. 9, 2000).

2The appendix lists those filing for rehearing and

clarification.

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.

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 He ́bert, 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: • 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. • 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.

• The rule improves the

competitiveness and efficiency of the

interstate pipeline grid by changing

regulations relating to scheduling

procedures, capacity segmentation, and

pipeline penalties.

• 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.

• 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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35707

3Rehearing Requests of Amoco, IPAA, Indicated

Shippers, NGSA, NWIGU, National Association of

Gas Consumers, Process Gas Consumers.

4Rehearing requests of CNG, Great Lakes, KinderMorgan, Koch, Williams.

5On 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.

6Rehearing Requests by Amoco, IPAA, Indicated

Shippers, NGSA, NWIGU, Process Gas Consumers.

7Rehearing Requests by Amoco, IPAA, Indicated

Shippers, Ohio Oil and Gas Association, Process

Gas Consumers.

8The rehearing requests refer to the bundled sales

market as the gray market.

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).

10See 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).

11Associated 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).

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.

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

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.

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

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. Costof-service regulation inhibits the

exercise of the pipeline’s market power

because the pipeline’s rates are limited,

eliminating a monopolist’s incentive to

35708 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

12Rehearing Request of Process Gas Consumers,

at 30.

13Rehearing Requests of Amoco, IPAA, Indicated

Shippers, NGSA.

14Comments 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’’).

15Rehearing Request of IPAA, at 16. For the same

point, see Rehearing Requests by Amoco, Indicated

Shippers, NGSA, Process Gas Consumers.

16Natural Gas Wellhead Decontrol Act of 1989,

Pub. L. No. 101–60, 103 Stat. 157 (1989); Natural

Gas Policy Act, § 601(a)(1), 15 U.S.C. 3431

(Commission jurisdiction does not apply to first

sales of domestic gas).

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 shortterm 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.

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35709

17Those 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. 18Associated 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).

19Order No. 637, 65 FR at 10196, 10174–79, III

FERC Stats. & Regs. Regulations Preambles ¶ 31,091,

at 31,271–74 (figures 6 and 7).

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.

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.

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/offpeak 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 11⁄2 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 offpeak 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 costof-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.

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 longterm 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

35710 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

20Pipeline 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] ¶ 30,950, at

30,562–63 (Aug. 3, 1992). 21 Id. 22Associated 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.

23Henning & 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).

24The data are derived from capacity release data

downloaded from 33 pipeline Internet sites, and the

discount reports filed by the pipelines with the

Commission.

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

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

Studies support the finding that shortterm 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

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 offpeak winter months. Off-peak rates

during the summer months were below

50% of the maximum rate in all three

off-peak periods.

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35711

25The 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.

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 longterm 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.

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

35712 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

26FPC 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).

27Hope, 320 U.S. 591, 602.

28Permian 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).

29Permian 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.

30Permian 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).

31FPC 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).

32Permian Basin Area Rate Cases, 390 U.S. 747,

785, 790 (1968) (Commission permitted to adopt

policies needed to respond to demands of changing

circumstances).

33Hope, 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).

34The 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).

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 shortterm 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

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

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.

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 costof-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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35713

35 734 F.2d 1486, at 1510.

36 734 F.2d 1486, at 1508.

37 10 F.3d 866, 870.

38 996 F.2d 401, 410.

39The 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 ¶ 61,076 (1996),

Koch Gateway Pipeline Company, 85 FERC ¶ 61,013

(1998), reh’g denied, 89 FERC ¶ 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]

¶ 32,520 (July 31, 1996) (final rule never issued);

Proposed Experimental Pilot Program to Relax the

Price Cap for Secondary Market Transactions, 76

FERC ¶ 61,120 (1996) (program terminated).

40Alternatives to Traditional Cost-of-Service

Ratemaking for Natural Gas Pipelines and

Regulation of Negotiated Transportation Services of

Natural Gas Pipelines, 74 FERC ¶ 61,076 (1996).

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

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.

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.

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.

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 costbased 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-ofservice rate ceilings for capacity release

35714 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

41Florida Power & Light Company, 66 FERC

¶ 61,227, at 61,527 (1994), on reh’g 70 FERC

¶ 61,158 (1995). Opportunity costs reflect the cost

to the utility of its next best alternative sale.

42California Independent System Operator

Corporation, 89 FERC ¶ 61,153, at 61,436 (1999).

43United 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).

44See 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).

45Permian Basin Area Rate Cases, 390 U.S. 747,

787 (1968) (Commission empowered to prescribe

different requirements for different classes of

persons or matters). 46See Figure 1, at 20.

transactions no longer meets the needs

of the market and that a more flexible

approach, relying on competition and

other regulatory controls, was necessary.

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-ofservice 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.

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 shortterm 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.

The Commission did not find, as the

rehearing requests suggest, that shortterm 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 longterm 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.

In short, the static cost-of-service rate

regulation that the Commission has

applied to long-term capacity

commitments is not applicable to shortterm 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 shortterm 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35715

47Order No. 637, 65 FR at 10174–80, figures 5–

7, III FERC Stats. & Regs. Regulations Preambles

¶ 31,091, at 31,271–74, figures 5–7.

48Figure 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

¶ 31,091, at 31,273–74, figure 7.

49 Department of Justice-Federal Trade

Commission, Horizontal Merger Guidelines, ¶ 0.1

(small number of firms can approximate the

performance of a monopolist, by either explicitly or

implicitly coordinating their actions).

50Compare Secondary Market Transactions on

Interstate Natural Gas Pipelines, 77 FERC ¶ 61,183

(1996) with Transwestern Pipeline Company, 78

FERC ¶ 61,200 (1997) (disputes over whether

market power can be exercised over single lateral

on pipeline).

51Rehearing Requests by Amoco, Indicated

Shippers, NGSA.

52 Department of Justice—Federal Trade

Commission, Horizontal Merger Guidelines, ¶ 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).

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.

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 marketbased 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

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, shortterm 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

35716 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

53The pipeline cannot recover any of the

potential profit by raising price because its rates are

capped.

54Process 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 ¶ 61,120 (1996).

55Order No. 637, 65 FR at 10158–60, 101–68 III

FERC Stats. & Regs. Regulations Preambles ¶ 31,091,

at 31,251–52, 31,261.

56For 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.

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.

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 shortterm 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.

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35717

57Pipeline 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] ¶ 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 ¶ 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).

58Atlanta Gas Light, UGI, Keyspan, and

Washington Gas also request clarification of this

point.

59 18 CFR 284.8.

60 18 CFR 284.8(h); Pipeline Service Obligations

and Revisions to Regulations Governing SelfImplementing 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]

¶ 30,950, at 30,553–54 (Aug. 3, 1992).

61Comments by Process Gas Consumers.

62Atlanta Gas Light, UGI, Keyspan, and

Washington Gas also request clarification of this

point.

63 18 CFR 284.8(h).

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.

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

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 shortterm transactions.60

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.

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

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)

35718 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

64 18 CFR 284.8(i) provides that any rollovers or

extensions are subject to the posting and bidding

requirements. 65Under 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. 66Order No. 637, 65 FR at 10182, III FERC Stats.

& Regs. Regulations Preambles ¶ 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] ¶ 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).

67Release 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] ¶ 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’’).

68A 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.

69There 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.

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

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

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.

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 prearranged 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 prearranged 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 prearranged 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.

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

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35719

70Order No. 637, 54 FR at 10186, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,287.

71Panhandle Eastern Pipe Line Company, 91

FERC ¶ 61,037 (2000).

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.

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.

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

35720 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

72See Comments of AGA and INGAA.

73As 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 ¶ 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).

75 497 U.S. 116 (1990).

76United Gas Pipe Line Co. v. Mobile Gas Service

Corp., 350 U.S. 332 (1955).

77Columbia 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).

78As 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).

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

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

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

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.

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 tarifffiling 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.

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35721

80Order No. 637 at 93–106.

81The Commission cited 18 CFR 284.7(c)(3)(i).

82The Commission cited the Rate Design Policy

Statement, 47 FERC ¶ 61,295 at 62,054 (1989).

83Order 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.

84 5 U.S.C. 553(b)(3), (c).

85The 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).

86 Indicated Shippers cite, inter alia, Hudson v.

FAA, 192 F.3d 1031, 1034 (D.C. Cir. 1999).

87Pacific Gas and Electric Co. v. FERC, 506 F.2d

33, 38 (D.C. Cir. 1974).

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.

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

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/offpeak rate methods. As the Commission

explained, there is more than one

reasonable way to implement peak/offpeak 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 longterm 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.

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/offpeak 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.

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 offpeak 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 shortterm shippers; it creates new duties

because it imposes on the pipeline an

obligation to perform a cost and revenue

study.

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

35722 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

88The 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.

89Order No. 637 at 104.

90See Mojave Pipeline Co., 79 FERC ¶61,347 at

62,482 (1997).

cases and therefore is properly

considered a policy statement.

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/offpeak 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.

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/offpeak 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/offpeak 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/offpeak 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.

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

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35723

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

1996).

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.

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 costbased 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

35724 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

92 Indicated Shippers cite Transcontinental Gas

Pipeline Corp., 78 FERC ¶ 61,057 (1997);

Transcontinental Gas Pipeline Corp., 79 FERC ¶

61,325 (1997).

93Transcontinental Gas Pipe Line Corp., 78 FERC

at 61,209.

94 Indicated Shippers cite Transcontinental Gas

Pipeline Co., 78 FERC at 61,209. 95Order No. 637 at 106.

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:

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

Indicated Shippers argue that the

same reasoning applies in the present

case, and that to the extent that preexisting short-term rates were designed

on the basis of fewer demand units than

will arise upon the adoption of peak/offpeak 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

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 longterm 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.

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 § 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35725

96AGA gives several examples of such service,

e.g., Transco’s Southern Expansion Service which

is available only from November through March.

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/offpeak 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/offpeak 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.

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 longterm 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/offpeak 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 termdifferentiated 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 termdifferentiated 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

35726 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

97Order No. 637 at 107.

98Term-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.

99Process Gas Consumers cites ANR Pipeline Co.,

82 FERC ¶ 61,145 at 61,535 (1998).

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 termdifferentiated 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 termdifferentiated rates just for long-term

services or for both short and long-term

services. Because the use of termdifferentiated 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 termdifferentiated 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.

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 termdifferentiated 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 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 shortterm 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 termdifferentiated 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 timeconsuming or involve a full evidentiary

hearing, and the parties may use that

forum to develop a mutually agreeable

method of implementing termdifferentiated 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 termdifferentiated 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 termdifferentiated 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 termdifferentiated rates for short-term

contracts.

As the Commission acknowledged in

Order No. 637, the use of termdifferentiated 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 termdifferentiated 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 termdifferentiated 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 termdifferentiated 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 longterm 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.

35728 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

100United Distribution Cos. v. FERC, 88 F.3d

1105, 1151–54 (D.C. Cir. 1996).

101Pipelines 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.

102For example, third-party auctions for shortterm 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.

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 marketbased 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 intraday 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

Some third parties indicated in their

comments that compliance with some of

the Commission’s existing regulations

can impede the development of thirdparty auctions. For instance, the

requirement that certain transactions

must be posted on pipeline Internet

sites was identified as a barrier to thirdparty 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 thirdparty 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35729

103Order No. 636–B, 61 FERC ¶ 61,272 at 62,009–

10 (1992); Questar Pipeline Co., 62 FERC ¶ 61,192

at 62,298 (1993).

104Editor’s Note: No text in footnote 104.

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 nonotice 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.

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 § 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

35730 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

105See, e.g., Baltimore Gas and Electric Co., 88

FERC ¶ 61,133, reh’g denied, 89 FERC ¶ 61,150

(1999).

106Pipeline 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] ¶ 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] ¶ 30,950, at 30,559

n.151 (Aug. 3, 1992), Order No. 636–B, 61 FERC

¶ 61,272, at 61,997 (1992).

107Order No. 637, 65 FR at 10195, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,303–

304; 18 CFR 284.7(e).

108Order No. 637, 65 FR at 10196, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,304.

109Wisconsin 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).

110Order No. 637, 65 FR at 10195, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,303–

304.

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

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.

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.

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

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35731

111See Northwest Pipeline Corporation, 69 FERC

¶ 61,171, at 61,677 (1994), 71 FERC ¶ 61,315, at

61,224 (1995) (providing operational controls for

segmented releases that jeopardize system

integrity).

112Citing Tennessee Gas Pipeline Company, 85

FERC ¶ 61,052 (1998), reh’g denied, 86 FERC

¶ 61,290 (1999); Texas Gas Transmission

Corporation, 89 FERC ¶ 61,096 (1999).

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

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.

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.

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

35732 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

113See Texas Gas Transmission Corporation, 89

FERC ¶ 61,096, at 61,274 (1999).

114 Iroquois Gas Transmission System, L.P., 78

FERC ¶ 61,135 (1997) (shipper cannot use same

delivery point for forwardhaul and backhaul in

excess of contract demand).

115Transcontinental Gas Pipe Line Corporation,

91 FERC ¶ 61,031 (2000) (using forwardhaul and

backhaul to series of delivery points does not result

in an overlap).

116Order No. 637, 65 FR at 10194, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,301–

302. Compare Transwestern Pipeline Company, 62

FERC ¶ 61,090, at 61,659, 63 FERC ¶ 61,138, at

61,911–12 (1993); El Paso Natural Gas Company, 62

FERC ¶ 61,311, at 62,982–83 (1993) (permitting

pipelines to continue historic limitations on

primary receipt point rights) with Northwest

Pipeline Corporation, 63 FERC ¶ 61,124, at 61,806–

08 (1993) (not permitting the pipeline to add such

restrictions).

117El Paso Natural Gas Company, 62 FERC

¶ 61,311, at 62,982–83 (1993); Transwestern

Pipeline Company, 62 FERC ¶ 61,090, at 61,659, 63

FERC ¶ 61,138, at 61,911–12 (1993).

118See El Paso Natural Gas Company, 62 FERC

¶ 61,311, at 62,982–83 (1993) (pipelines could

propose methods for limiting the potential for

hoarding).

119Order No. 637, 65 FR at 10194, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091, at 31,301–

302; Texas Eastern Transmission Corporation, 63

FERC ¶ 61,100, at 61,452 (1993); El Paso Natural

Gas Company, 62 FERC ¶ 61,311, at 62,991. See also

Transwestern Pipeline Company, 61 FERC ¶ 61,332,

at 62,232 (1992).

120Order No. 637, 65 FR at 10195–96, III FERC

Stats. & Regs. Regulations Preambles ¶ 31,091, at

31,304.

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

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.

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

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35733

121Even 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.

122El Paso Natural Gas Company, 62 FERC

¶ 61,311, at 62,990–91 (1993); ANR Pipeline

Company, 62 FERC ¶ 61,079, at 61,562–63 (1993).

123See Questar Pipeline Company, 69 FERC

¶ 61,119 (1994) (applying policy to a postage stamp

system).

124On 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.

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

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.

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.

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

35734 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

125Order No. 637, 65 FR at 10196–97, III FERC

Stats. & Regs. Regulations Preambles ¶ 31,091, at

31,304–306. 126See R. Posner, Economic Analysis of Law,

§ 3.1, at 28 (2d ed. 1977) (exclusive property rights

are necessary to promote trading).

127See Tennessee Gas Pipeline Company, 71

FERC ¶ 61,399, at 62,577 (1995) (cases cited

therein). 128See Panhandle Eastern Pipe Line Company, 78

FERC ¶ 61,202, at 61,870–71 (1997) (conditionally

accepting within the path allocation); Northwest

Pipeline Corporation, 67 FERC ¶ 61,095 (1994)

(priority given to shippers moving within primary

path).

be addressed in the pipeline’s

compliance filings.

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.

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

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35735

129Shipper 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 takeaway 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

¶ 31,091, at 31,306–7.

130Under 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.

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

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

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

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

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

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.

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.

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.

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

35736 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

134Order No. 637, 54 FR at 10199, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,310.

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.

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.

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.

Accordingly, the Commission will

amend the first sentence of section

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35737

136Order No. 637, 54 FR at 10199, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,311.

137Standards for Business Practices of Interstate

Natural Gas Pipelines, Order No. 584–G, 63 FR

20072 (Apr. 23, 1998), III FERC Stats. & Regs.

Regulations Preambles ¶ 31,062 (Apr. 16, 1998).

138Standards 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 ¶ 31,062, at 30, 677

(Apr. 16, 1998).

139Http://www.gisb.org/edd.htm (announcing

formation of Expedited Data Development

Subcommittee).

140Order No. 637, 54 FR at 10199, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,310.

141 Id.

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.

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 preexisting 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.

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

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

35738 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

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.

144 18 CFR 284.402 (1999).

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 ¶ 31,091 at 31,317. IMGA Request for

Rehearing at 10.

146Order No. 637, 54 FR at 10200, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,312.

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 thirdparty 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

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

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.

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.’’

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 KinderMorgan 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35739

147E.g., Comments of Shell Energy Services

Company, L.L.C. at 17, Florida Cities at 7–8, and

American Forest & Paper Association at 43.

148See, e.g., NorAm Gas Transmission Company,

79 FERC ¶ 61,126, at 61,546–47 (1997); Southern

Natural Gas Company, 80 FERC ¶ 61,233, at 61,890

(1997) Northern Natural Gas Company, 77 FERC

¶ 61,282 (1997); Panhandle Eastern Pipe Line

Company, 78 FERC ¶ 61,202 (1997); Northwest

Pipeline Company, 71 FERC ¶ 61,315 (1995). The

Commission determined the validity of the claims

made in these cases by conducting its own analysis

of the pipelines’ tariffs.

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 welldefined, 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.

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. KinderMorgan 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

35740 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

149Order No. 637, 54 FR at 10201, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,314

150E.g., Northern Natural Gas Company, 77 FERC

¶61,282 at 62,236 (1997); Panhandle Eastern Pipe

Line Company, 78 FERC ¶61,202 at 61,876–77

(1997), reh’g denied, 82 FERC ¶61,163 (1998); and

Williams Natural Gas Company, 78 FERC ¶61,342

(1997).

151Order No. 637, 54 FR at 10201, III FERC Stats.

& Regs. Regulations Preambles ¶31,091 at 31,314–

15.

152E.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 ¶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.

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 nonpeak 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.

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

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35741

154Request for Rehearing of Kinder-Morgan at 11,

quoting Order No. 637, 54 FR at 10201, III FERC

Stats. & Regs. Regulations Preambles ¶31,091 at

31,314.

155Request for Rehearing of Kinder-Morgan at 8.

156 Kinder-Morgan relies on the following

statement by the Commission, but misinterprets it:

155Request for Rehearing of Kinder-Morgan at 8.

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 ¶ 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.

157Order No. 637, 54 FR at 10202, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,091 at 31,317

(emphasis added).

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.

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. KinderMorgan 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 noncritical 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.

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.

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 noncritical 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.

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

35742 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

158The 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 ¶ 31,091 at 31,315.

159Requests for Rehearing of Industrials,

Keyspan, Koch, and Tejas. 160Request for Rehearing of Industrials at 72.

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.

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35743

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

162Order No. 637, 65 FR at 10184, III FERC Stats.

& Regs. Regulations Preambles ¶ 30,091 at 31,283.

163For 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 ¶ 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.

for 90 days, and to archive this

information for a period of three years

after the 90-day period expires.161

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:

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.

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 selfregulating.

35744 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

164Requests for Rehearing of Columbia Gulf,

Dynegy, NEMA, Williston Basin, and Cibola.

165Request for Rehearing of Dynegy at 20 and

Request for Rehearing of NEMA at 9.

166 15 U.S.C. 717(c) (1994).

167 Id. (emphasis added).

168Part 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.

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.

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

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:

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35745

169Natural Gas Pipeline Co. of America, 55 FERC

¶ 61,416 at 62,245–46 (1991); and El Paso Natural

Gas Co., 57 FERC ¶ 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).

170Requests for Rehearing of Cibola, Dynegy,

NEMA, Koch, INGAA and Enron.

171 GISB Capacity Release Standard 5.3.2 (GISB

Version 1.3, July 31, 1998). 172 15 U.S.C. 717(c)

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.

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.

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

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.

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.

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

35746 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

173Revisions 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. ¶ 31,026

(1995).

174Revisions 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. ¶ 31,032 at 31,551

(1996) (emphasis added).

175Order No. 637, 65 FR at 10207, III FERC Stats.

& Regs. Regulations Preambles ¶ 30,091, at 31,326.

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.

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35747

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

177Many 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.

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.

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.

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

35748 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

178Request for Rehearing of Cibola at 5–7.

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).

180Request for Rehearing of Enron at 8–9.

181 Id. at 9.

182Request for Rehearing of Amoco at 62.

183 Id.

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.

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

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.

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.

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: KinderMorgan requests the Commission to

delete the requirement that pipelines

report the contract number of each

transportation transaction. KinderMorgan 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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35749

184 Id.

185 18 CFR 284.12(c)(3)(v) (3 year archiving

requirement); 18 CFR 250.16(d) (3 year requirement

for maintaining discount information).

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.

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

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

35750 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

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

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

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

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

190Request 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).

191 Kinder Morgan Interstate Gas Transmission

LLC, et al., 90 FERC ¶ 61,310 (March 29, 2000)

(Kinder Morgan) and Amoco v. Natural Gas

Pipeline Company of America, 82 FERC ¶ 61,038

(1998); reh’g denied, 82 FERC ¶ 61,300 (1998); and

reh’g granted, in part, 83 FERC ¶ 61,197 (1999).

192 90 FERC ¶ 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.

193Tenneco Gas Company v. FERC, 969 F.2d

1187 at 1205 (1992).

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.

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

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

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

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35751

194The 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.

195See Requests for Rehearing of CNGT, Enron,

INGAA, Williams, Williston Basin, and Koch.

196Allegheny Power Services Corp. et al., 84

FERC ¶ 61,131 at 61,714 (1998).

197Reporting Interstate Natural Gas Pipeline

Marketing Affiliates on the Internet, III FERC Stats.

& Regs. Regulations Preambles ¶ 31,064 (July 30,

1998), 63 FR 43075 (Aug. 12, 1998).

198 III FERC Stats. & Regs. Regulations Preambles

¶ 31,064 at 30,715.

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.

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.

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.

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 threeday 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

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.

35752 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

200Request for Rehearing of Enron at 10.

201Amoco, 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.

202See 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 ¶ 31,067, at

30,737–46 (Sept. 29, 1998).

Service outages must posted when

required.

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.

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.

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.

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.

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35753

203Coastal, CNGT, Enron, INGAA, KinderMorgan, Koch, Tejas, Williams, and Williston

Basin.

204Request for Rehearing of Kinder Morgan at 39

and Request for Rehearing of Williams at 11.

205Request 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.

206Request for Rehearing of Williston Basin at

14–16.

207 18 CFR 284.221.

208Requests 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.

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.

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

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.

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

35754 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

209Order No. 637 at 216–18.

210E.g., Keyspan Brooklyn Union, National Fuel,

New England Gas Distributors, and Minnegasco.

211AGA gives several examples of such service,

e.g., Transco’s Southern Expansion Service which

is available only from November through March.

212Minnegasco 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.

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

214Minnesota 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 costbased 12-month service. (Check this).

clarifies Order No. 637 as provided

below.

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.

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.

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.

These petitioners further argue that

there is no legal justification for

eliminating ROFR protection for multiyear 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.

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

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 longterm captive customers at the expiration

of their contracts. If a customer is

paying the maximum rate under a multiyear 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 shortterm 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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35755

215Process Gas Consumers cite Order No. 636 at

30,448.

216Process 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 longterm 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.

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

218The 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.

219Process Gas Consumers cite Alternative Rates

Policy Statement at 61,235.

220E.g., Koch Gateway Pipeline Co., 74 FERC ¶

61,088 at 61,280 (1996).

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.

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.

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.

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

35756 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

221 Id.

222See, e.g., Williston Basin Interstate Pipeline

Co., 85 FERC ¶ 61,247 (1998); Southern Natural Gas

Co., 67 FERC ¶ 61,155 at 61,456 n.8 (1994).

223UDC, 88 F.3d at 1140.

224 Id. at 1142.

225Enron states that pipelines with current longterm 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.

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.

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.

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

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 reexecuting 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 longterm contracts.

Koch agrees with the determination in

Order No. 637 that the ROFR should not

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35757

226 Docket No. PL99–3–000, FERC ¶ 61,227

(1999), reh’g, 90 FERC ¶ 61,128 (2000). 227The Commission cited several examples given

on rehearing of the Certificate Policy Statement of

such a mechanism.

228UGI 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.

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

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.

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

35758 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

229UMDG v. FERC, 732 F.2d 202, 212 (D.C. CIR.

1984); Norwood v. FERC, 587 F.2d 1306, 1310 (Cir.

19).

230APGA cites the Policy Statement, 88 FERC at

61, 746–47.

231APGA cites 88 FERC at 61,746.

232APGA cites 88 FERC at 61,746.

233 88 FERC at 61,746.

234Order Clarifying Statement of Policy, 90 FERC

¶ 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.

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.

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.

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.

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

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35759

237APGA cites Order No. 888–B, 81 FERC

¶ 61,248 at 62,085 (1997).

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.

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

35760 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

238 81 FERC at 62,085.

239 81 FERC at 62,085 n.90.

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

241 90 FERC ¶ 61,128 (2000).

242ConEd, Keyspan, National Fuel, and New

England.

243AGA 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

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 flowbased 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.

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35761

the existing shipper match the bid for zone 5 shorthaul, plus the maximum system-wide maximum

rate for the haul across zones 1–4.

244AGA 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.

245As the Commission stated in Williams Natural

Gas Company, 65 FERC ¶ 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.’’

246AGA cites Order No. 636–A, FERC Stats. &

Regs. [Regulations Preambles 1991–1996] ¶ 31,950

at 30,635 (1992).

247 81 FERC ¶ 61,350 at 62,627–28 (Williams I),

reh’g, 83 FERC ¶ 61,052 (Williams II) (1997).

248 76 FERC ¶ 61,022 at 61,128–29 (1999).

249 88 FERC ¶ 61,155, reh’g denied, 88 FERC

¶ 61,295 (1999). See also Texas Eastern

Transmission Corp., 88 FERC ¶ 61,167, reh’g

denied, 88 FERC ¶ 61,291 (1999).

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 preexisting 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.

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.

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.

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

35762 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

250Williams, 81 FERC ¶ 61,350 at 62,627 n.20.

251 170 F.3d 197 (D.C. CIR. 1999).

252 Keyspan cites Order No. 636, FERC Stats and

Regs. (1991–1996) ¶ 30,939 at 30,451–52 (1992).

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.

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.

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

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 35763

253 761 F.2d 768, 770 (D.C. Cir. 1985) (MPCI).

254 761 F.2d 780, 781 (D.C. Cir. 1985) (MCPII).

255See Tennessee Gas Pipeline Co., 91 FERC

¶ 61,053 (2000).

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.

court’s decision in Maryland Peoples

Counsel v. FERC253 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.

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 longhaul, 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

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 fiveyear 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.

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 fiveyear 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 fiveyear 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

35764 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

257UDC, 88 F.3d at 1140.

258Regulation of Short-Term Natural Gas

Transportation Services 91 FERC ¶ 61,020 (2000).

259 18 CFR 154.4.

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.

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, § 284.13. But the reports

concerning bypass of LDC facilities

required under subpart B (§ 284.106)

were not included in § 284.13,

remaining in § 284.106. Prior to Order

No. 637, subpart G pipelines were

required to file bypass reports, because

§ 284.223(b) contained a cross-reference

requiring subpart G pipelines to comply

with each of the reporting requirements

in § 284.106, which included the bypass

reports. However, in Order No. 637,

§ 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 § 284.13(f), so that the preexisting 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.

Pipelines should file the electronic

pro forma tariff sheets through Internet

E-Mail to 637FASTR@ferc.fed.us 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 EMail filing should be directed to Lorena

Finger at 202–208–1222, or by E-Mail to

lorena.finger@ferc.fed.us, or to Albert

Rogers at 202–208–0078 or by E-Mail to

albert.rogers@ferc.fed.us.

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.

Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations 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 § 284.8, paragraph (i) is revised

to read as follows:

§ 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 § 284.12, the first sentence of

paragraph (c)(2)(iii) and paragraph

(c)(2)(v) are revised to read as follows:

§ 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 § 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:

§ 284.13 Reporting requirements for

interstate pipelines.

* * * * *

(b) * * *

(1) For pipeline firm service and for

release transactions under § 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 § 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.

§ 284.106 [Removed and reserved]

5. Section 284.106 is removed and

reserved.

6. In § 284.221, paragraph (d)(2)(ii) is

revised to read as follows:

§ 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

§ 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.

35766 Federal Register / Vol. 65, No. 108 / Monday, June 5, 2000 / Rules and Regulations

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, wellreasoned 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