Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-00-01395/USCOURTS-caDC-00-01395-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
Interstate Natural Gas Association of America
Petitioner

Document Text:

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United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued November 29, 2001 Decided April 5, 2002

No. 98-1333

Interstate Natural Gas Association of America,

Petitioner

v.

Federal Energy Regulatory Commission,

Respondent

Missouri Gas Energy,

Division of Southern Union Company, et al.,

Intervenors

Consolidated with

98-1349, 00-1217, 00-1220, 00-1244, 00-1278, 00-1280,

00-1286, 00-1291, 00-1308, 00-1315, 00-1319, 00-1360,

00-1367, 00-1380, 00-1395, 00-1410, 00-1411, 00-1414,

00-1416, 00-1418, 00-1419,

---------

USCA Case #00-1395 Document #669768 Filed: 04/05/2002 Page 1 of 62
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On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

---------

Thomas J. Eastment argued the cause for petitioners

Opposing Lifting of Rate Cap. With him on the briefs were

John P. Elwood, Douglas W. Rasch, Frederick T. Kolb, Stan

Geurin, Paul B. Keeler, Bruce A. Connell, Charles J.

McClees, Jr., Linda Geoghegan, Dena E. Wiggins, Katherine

P. Yarbrough, Edward J. Grenier, Jr., David M. Sweet, John

W. Wilmer, Jr. and Joseph D. Lonardo.

James D. McKinney, Jr. argued the cause for petitioners

Opposing Limitation on Lifting of Rate Cap to Exclude

Pipeline Short-Term Service. With him on the briefs were

John J. Wallbillich, James L. Blasiak, John H. Burnes, Jr.,

Paul I. Korman, B.J. Becker and Paul W. Mallory.

Michael E. McMahon and Henry S. May, Jr. argued the

cause for petitioners and supporting intervenors on Multiple

Issues Related to Segmentation. With them on the briefs

were Joan Dreskin, Robin Nuschler, Kurt L. Krieger, Robert

T. Hall, III, John R. Schaefgen, Jr., James D. McKinney, Jr.,

John J. Wallbillich, James L. Blasiak, John H. Burnes, Jr.,

Paul I. Korman, B.J. Becker, Paul W. Mallory, Brian D.

O'Neill, Bruce W. Neely, David P. Sharo, Merlin E. Remmenga, R. David Hendrickson, Daniel F. Collins, G. Mark

Cook, J. Curtis Moffatt, Susan A. Moore, Rodney E. Gerik,

Steven E. Hellman, Judy M. Johnson, Catherine O'Harra

and Richard D. Avil, Jr.

Frank X. Kelly argued the cause for petitioner Enron

Interstate Pipelines Opposing Change in Capacity Allocation

at Secondary Points. With him on the briefs were Steve

Stojic, Drew J. Fossum and Maria K. Pavlou.

James L. Blasiak argued the cause for petitioners and

intervenors Opposing Changes in Penalties. With him on the

briefs were E. Duncan Getchell, Jr., Brian D. O'Neill, Bruce

W. Neely, David P. Sharo, Merlin E. Remmenga, Kurt L.

Krieger, Robin Nuschler, Rodney E. Gerik, Steven E. HellUSCA Case #00-1395 Document #669768 Filed: 04/05/2002 Page 2 of 62
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man, Mike McMahon, J. Curtis Moffatt, Susan A. Moore,

Joan Dreskin, John H. Burnes, Jr., B.J. Becker, Judy M.

Johnson, Catherine O'Harra, Robert T. Hall, III and John R.

Schaefgen, Jr.

Henry S. May Jr. and Mark K. Lewis argued the cause for

petitioners and intervenor Opposing Limitations on the

Right-Of-First-Refusal. With them on the briefs were

Bruce F. Kiely, Niki Kuckes, Edward J. Grenier, Jr., Barbara K. Heffernan, Debra Ann Palmer, William T. Miller,

Joshua L. Menter, Denise C. Goulet and Jennifer N. Waters.

Catherine O'Harra, Henry S. May, Jr., Judy M. Johnson,

S. Scott Gaille, Rodney E. Gerik, Steven E. Hellman, James

D. McKinney, Jr., John J. Wallbillich, Carl M. Fink, Lee A.

Alexander, Robin Nuschler, Kurt Krieger, John H. Burnes,

Jr., Paul I. Korman, B.J. Becker and Paul W. Mallory were

on the briefs for petitioners and intervenors.

Philip B. Malter argued the cause and filed the briefs for

petitioner on Discount Adjustments.

Thomas J. Eastment argued the cause for petitioners

Opposing New Rate and Service Options. With him on the

briefs were Joshua B. Frank, Douglas W. Rasch, Frederick

T. Kolb, Stan Geurin, Bruce A Connell, Charles J. McClees,

Jr., Linda Geoghegan, David M. Sweet, John W. Wilmer, Jr.,

Joseph D. Lonardo, Denise C. Goulet and Robert S. Tongren.

Christopher J. Barr argued the cause for petitioners and

intervenors Opposing Limitations on Pre-Arranged Releases.

With him on the briefs were C. Brian Meadors, Frank H.

Markle, Barbara K. Heffernan, Debra Ann Palmer and

Denise C. Goulet. Kent D. Murphy and Mary E. Buluss

entered appearances.

Dennis Lane, Solicitor, Federal Energy Regulatory Commission, Andrew K. Soto and Lona T. Perry, Attorneys,

argued the causes and filed the brief for respondent.

Karen A. Hill, Jeffrey M. Petrash, Kenneth T. Maloney

and Edward B. Myers were on the brief for intervenors in

support of Lifting the Rate Cap. Jeffrey L. Futter entered

an appearance.

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Joan Dreskin, Henry S. May, Jr., Judy M. Johnson,

Catherine O'Harra, Rodney E. Gerik, Steven E. Hellman,

James D. McKinney, Jr., John J. Wallbillich, R. David

Hendrickson, Daniel F. Collins, Carl M. Fink, Lee A. Alexander, Robert T. Hall, III, John R. Schaefgen, Jr., Michael

E. McMahon, J. Curtis Moffatt, Susan A. Moore, Frank X.

Kelly, Steve Stojic and Shelley A. Corman were on the brief

for intervenor Interstate Pipeline. Stefan M. Krantz entered

an appearance.

Mark R. Haskell argued the cause for intervenors in

support of respondent on Multiple Issues Related to Segmentation and Changes in Capacity Allocation. With him on the

brief were Peter G. Esposito, Dena E. Wiggins, Katherine P.

Yarbrough and Edward J. Grenier, Jr.

Thomas J. Eastment, Dena E. Wiggins, Katherine P.

Yarbrough, James M. Bushee, Edward J. Grenier, Jr., Kirstin E. Gibbs, Jeffrey M. Petrash, A. Karen Hill, William T.

Miller, John P. Gregg, Joshua L. Menter, Frederick T. Kolb,

Stan Geurin, Bruce A. Connell, Peter G. Esposito, Jennifer

N. Waters, Douglas W. Rasch, Philip B. Malter, David M.

Sweet, John W. Wilmer, Jr., Glenn W. Letham, Denise C.

Goulet, Barbara K. Heffernan, Debra Ann Palmer, Charles

J. McClees Jr., Linda Geoghegan, Bruce F. Kiely, Mark K.

Lewis and Niki Kuckes were on the brief for intervenors

Amoco Production Company, et al. Lois M. Henry, Jennifer

S. Leete, William H. Penniman and Irwin A. Popowsky

entered appearances.

Before: Edwards and Tatel, Circuit Judges, and Williams,

Senior Circuit Judge.

Opinion for the Court filed by Senior Circuit Judge

Williams.

TABLE OF CONTENTS

I. Rate Ceiling Issues 7

A. Waiver of the rate ceilings for short-term

capacity releases by shippers 7

1. Expected range of market rates 10

2. Non-cost factors 13

3. Oversight 15

B. Retention of the rate ceilings for shortterm pipeline releases 16

II. Segmentation 18

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A. General validity 19

B. Specific defects 22

1. Primary point rights in segmented

releases 22

2. Forwardhauls and backhauls to the

same delivery point 25

3. Virtual pooling points 27

4. Reticulated pipelines 28

5. Discounts 30

III. Secondary Point Capacity Allocation 32

IV. Penalties 35

A. INGAA attack on penalty limits 36

B. Attacks on revenue-crediting provisions 40

V. The Right of First Refusal 42

A. Five-year matching cap and "regulatory"

right of first refusal 42

1. Five-year cap 45

2. Right of first refusal trumping tariff

provisions 46

B. Narrowing of the right of first refusal 48

VI. Discount Adjustments 51

VII. Peak/Off-Peak Rates 55

VIII. Limitations on Pre-Arranged Releases 59

Williams, Senior Circuit Judge: The petitioners challenge

the Federal Energy Regulatory Commission's Orders Nos.

637, 637-A, and 637-B, in which the Commission extended its

prior efforts to increase flexibility and competition in the

natural gas industry. See Order No. 637, Regulation of

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

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FERC Stats. & Regs. [Reg. Preambles 1996-2000] (CCH)

p 31,091 (2000) ("Order No. 637"); Order No. 637-A, Order on

Rehearing, Regulation of Short-Term Natural Gas Transportation Services And Regulation of Interstate Natural Gas

Transportation Services, FERC Stats. & Regs. [Reg. Preambles 1996-2000] (CCH) p 31,099 (2000) ("Order No. 637-A");

Order No. 637-B; Order Denying Rehearing, Regulation of

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

92 FERC p 61,602 (2000) ("Order No. 637-B").

We deny the petitions for the most part, with the following

exceptions: we reverse and remand with respect to the fiveyear cap on the mandatory right of first refusal and in part

with respect to the limitations on pre-arranged releases (issues V.A.1 and VIII in the Table of Contents); we remand

without reversing on forwardhauls and backwardhauls to the

same delivery point (issue II.B.2) and on the relation between

the right of first refusal and tariff provisions (issue V.A.2);

and we dismiss the petitions as unripe or for want of standing

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with respect to segmentation of reticulated pipelines and

point discounts, secondary point capacity allocation, and peak/

off-peak rates (issues II.B.4, II.B.5, III and VII).

I. Rate Ceiling Issues

A. Waiver of the rate ceilings for short-term capacity

releases by shippers

The heart of Order No. 637 was the Commission's decision

to lift--for a two-year period--the cost-based rate ceilings

that it previously imposed on short-term "releases" of pipeline capacity by shippers with long-term rights to that capacity. Order No. 637 at 31,263. At the same time the order

retained the ceilings for similar sales by the pipelines themselves. Id. Both aspects are attacked: the experimental

decontrol--by certain shippers (collectively, "Exxon"), the

exclusion of pipelines--by certain pipelines.

The Natural Gas Act ("NGA"), 15 U.S.C. s 717, et seq.,

mandates that all the rates and charges of a natural gas

company for the transportation or sale of natural gas "shall

be just and reasonable." 15 U.S.C. s 717c(a). (It is undisputed for the purposes of this appeal that a shipper reselling

its capacity is a "natural gas company" to that extent and

thus subject to FERC jurisdiction over such resales. E.g.,

Texas Eastern Transmission Corp., 48 FERC p 61,248 at

61,873 (1989); see also Order No. 636-A, Order on Rehearing,

Pipeline Service Obligations and Revisions to Regulations

Governing Self-Implementing Transportation Under Part

284 of the Commission's Regulations, FERC Stats. & Regs.

[Regs. Preambles 1991-1996] (CCH) p 30,950 at 30,551 (1992)

("Order No. 636-A"); United Distrib. Cos. v. FERC, 88 F.3d

1105, 1152 (D.C. Cir. 1996) ("UDC").) In its prior rulemaking

aimed at enhancing competition by unbundling various pipeline services, the Commission recognized that a significant

percentage of pipeline capacity reserved for "firm" service

often went unused. Order No. 636, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's

Regulations, FERC Stats. & Regs. [Regs. Preambles 1991-

1996] (CCH) p 30,939 at 30,398-400 (1992) ("Order No. 636");

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cf. UDC, 88 F.3d at 1149. It granted authority for the

holders to release such capacity, but, concerned that capacity

holders might be able to exercise market power, imposed a

ceiling on what the releasing party could charge. Order No.

636 at 30,418; Order No. 636-A at 30,553. The ceiling was

derived from the Commission's estimate of the maximum

rates necessary for each pipeline to recover its annual cost-ofservice revenue requirement, Order No. 637 at 31,270, which

the Commission simply prorated over the period of each

release, id. at 31,270, 31,271.

As the Commission observed activity in the market under

this arrangement, however, it came to believe that the ceilings probably worked against the shippers they were designed to protect. With the rate ceilings in place, a shipper

looking for short-term capacity on a peak day, and willing to

offer a higher price in order to obtain it, could not legally do

so; this reduced its options for procuring short-term transportation at the times that it needed it most. Order No. 637

at 31,275-76. So the Commission decided to grant a two-year

experimental waiver of the ceilings on releases of firm capacity. For this limited period, "short-term" capacity releases

(defined for these purposes as less than one year) may

proceed at market rates. Order No. 637 at 31,263. Capacity

sales by the pipelines themselves, both short and long-term,

continue subject to the cost-based rate ceilings. Order No.

637-A at 31,572. We here address the claims of the shippers

who object to the experiment itself and the pipelines who

object to their exclusion from its opportunities.

* * *

Framing our consideration of the challenges are (1) the

special deference due agency experiments, (2) the basic premise of the congressional mandate to FERC to regulate the

rates of the interstate gas pipelines, and (3) a set of criteria,

discussed exhaustively in Farmers Union Cent. Exch. v.

FERC, 734 F.2d 1486 (D.C. Cir. 1984) ("Farmers Union"), for

review of decisions, undertaken by an agency having such a

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mandate, to choose a regime more "lighthanded" than traditional cost-based regulation.

Here of course the two-year waiver is explicitly experimental. As the Commission said, "No matter how good the data

suggesting that a regulatory change should be made, there is

no substitute for reviewing the actual results of a regulatory

action." Order No. 637 at 31,279. For at least 30 years this

court has given special deference to agency development of

such experiments, precisely because of the advantages of data

developed in the real world. See, e.g., Public Serv. Comm'n

v. FPC, 463 F.2d 824, 828 (D.C. Cir. 1972); Paul Mohler,

"Experiments at the FERC--In Search of a Hypothesis," 19

Energy L.J. 281, 300 (1998). The petitioners do not contest

this extra layer of deference.

Second, the basic premise of the NGA is the understanding

that natural gas pipeline transportation is generally a natural

monopoly, see, e.g., UDC, 88 F. 3d at 1122, so that without

regulation the rates of pipeline companies would exceed competitive rates, i.e., ones approximating cost, Elizabethtown

Gas Co. v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993). In

dispensing with cost-based rate ceilings presumptively intended by Congress as a remedy, and supplanting those ceilings

temporarily with market-based rates in a segment of the

pipeline market, the Commission may be seen as facing a

kind of uphill fight. Though the slope faced by FERC is

perhaps uphill, however, it is not the almost vertical escarpment that Exxon seems to suppose. This is not Point du

Hoc.

Third, our decision in Farmers Union, though addressing

oil pipeline regulation under the Hepburn Act, sets out general guidance for our review of FERC's decision to elect more

relaxed ("lighthanded," as we said) regulation than traditional

cost-based ceilings, in the context of a mandate to set "just

and reasonable" rates in an industry generally thought to

have the features of a natural monopoly. 734 F.2d at 1510.

The overarching criterion that we identified was (inevitably)

that any such decision could be justified by "a showing that

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plished" through the proposed changes. Id. To satisfy that

standard, we demanded that the resulting rates be expected

to fall within a "zone of reasonableness, where [they] are

neither less than compensatory nor excessive." Id. at 1502

(internal quotations omitted). While the expected rates'

proximity to cost was a starting point for this inquiry into

reasonableness, id., we were quite explicit that "non-cost

factors may legitimate a departure from a rigid cost-based

approach," id. Finally, we said that FERC must retain some

general oversight over the system, to see if competition in

fact drives rates into the zone of reasonableness "or to check

rates if it does not." Id. at 1509. We now apply this basic

model.

1. Expected range of market rates. As competition normally provides a reasonable assurance that rates will approximate cost, at least over the long pull, Elizabethtown Gas Co.,

10 F.3d at 870, Exxon argues that the Commission's experiment cannot be sustained in the absence of data establishing

the existence of competition. Presumably, for example, a

calculation of Herfindahl-Hirschman indices for the capacity

release market in all origin and destination pairs would do the

job. The Commission has not undertaken such an enterprise.

See, e.g., Order No. 637-A at 31,558.

But the Commission has other evidence. First, since capacity resales were authorized in 1992, the rates for such

releases have on average been somewhat below the maximum

tariff rates, both during off-peak and peak periods. Order

No. 637-A at 31,563 & n.46. Second, the Commission has

data from "the bundled market," i.e., inferences as to transportation values drawn from comparison of the prices for gas

sold at the field with the prices for gas sold in destination

markets. As the Commission points out, if the difference

between field prices and citygate prices in a particular pathway is only $.07, people will not pay more than $.07 for the

unbundled transportation. Order No. 637 at 31,271. Only

during the coldest times of some years has this inferred price

exceeded the capped rate. Order No. 637-A at 31,563 &

nn.47-48. Order No. 637's Figure 6, found at 31,273, which

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we reproduce below, illustrates the pattern the Commission

found.

Figure 6 is not available electronically.

Thus the Commission had a substantial basis for concluding

that the uncapped market price for capacity--which FERC

concedes is likely to exceed the current maximum at certain

times of the year--will be roughly in line (at least annually)

with the cost-based price. Order No. 637-A at 31,563-64.

Of course, one could argue that this demonstrates only that

in the periods where the ceilings are not binding, there is no

problem for them to solve; thus it supplies no justification for

removal of the ceilings for the (peak) periods where they are

binding. But the data represented in the graph above do

support the Commission's view that the capacity release

market enjoys considerable competition. The brief spikes in

moments of extreme exigency are completely consistent with

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competition, reflecting scarcity rather than monopoly. See

Order No. 637-A at 31,595. A surge in the price of candles

during a power outage is no evidence of monopoly in the

candle market.

Moreover, outside the spikes the rates were well below the

regulated price, which in turn is based on the Commission's

estimates of cost. As prices would be above cost in the

absence of competition and yet are not (putting aside the

brief scarcity-related spikes), the Commission's inference of

competition appears well founded.

The Commission also considered two ways in which capacity resellers might exploit or extend such market power as

they may possess--price discrimination and deliberate withholding of capacity to drive up prices--and found that neither

presented much peril. Order No. 637-A at 31,564. FERC

dismissed price discrimination on the grounds that, given the

ease with which capacity can be transferred between shippers, resellers would have no way to prevent arbitrage. See

Order No. 637 at 31,280, 31,282.

As to deliberate withholding of capacity, the Commission

reasoned that this too was not within the power of capacity

holders. If holders of firm capacity do not use or sell all of

their entitlement, the pipelines are required to sell the idle

capacity as interruptible service to any taker at no more than

the maximum rate--which is still applicable to the pipelines.

See Order No. 637 at 31,282. Even though interruptible

service may not be as desirable as firm service, the Commission concluded that it would provide an adequate substitute,

whose availability would place a meaningful check on whatever anti-competitive tendencies the resellers might have. See

Order No. 637-A at 31,565. And because the pipelines continue to be bound by cost-of-service regulations, the agency

suggested that they would have no incentive to collude with

firm shippers to limit available capacity. Id.

Moreover, the availability of the bundled sales mentioned

above (where a holder of capacity buys gas in the field and

sells it in a destination market, with no explicit sale of the

necessary capacity itself) further reduces the possibility that

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the waiver policy would significantly change the firm shippers' ability to increase their rates for capacity releases.

Order No. 637 at 31,276. And, if pipelines should observe

high prices in the secondary market, they will--despite their

capped rates--often have adequate incentives to add capacity,

which they can do even in the relatively short-term by adding

compression. Id. at 31,282.

Thus we think the Commission made a substantial record

for the proposition that market rates would not materially

(considering degree, volume and duration) exceed the "zone of

reasonableness" required by Farmers Union. Any flaws in

its showing must be evaluated, of course, in light both of the

experimental nature of the two-year removal of ceilings and

of the non-cost factors discussed below.

2. Non-cost factors. The Commission pointed to a number of advantages of lifting the ceilings on short-term capacity releases, tending to offset whatever harm the occasional

high rate might entail. We discuss them, concentrating on

the highlights.

First, because the rule applies only to the secondary transportation market, the primary intended beneficiaries of the

NGA--the "captive" shippers, typically operating under firm

contracts--continue to receive whatever benefits the rate

ceilings generally provide. See Order No. 637 at 31,284-85

(alluding to the continued protection of the Commission's

"primary constituency--captive long-term firm capacity holders"). Indeed, these holders actually reap the benefits of

FERC's new rule, in the form of higher payments for their

releases of surplus capacity. See id. at 31,281; see also

Order No. 637-A at 31,562.

Second, the rate ceilings on short-term capacity releases

were fundamentally ineffective. We've already described the

market for bundled gas and transportation, by means of

which a holder of surplus capacity can take advantage of the

real market value of transportation by going into the gas

market itself, buying in an origin market and selling at the

destination. Although all hands recognize that during peaks

the market value of the transportation can far exceed the

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FERC-imposed maximum tariff rate, see Order No. 637 at

31,273-74 & figs. 6-7, neither the Commission, nor any of the

parties, has proposed extending price regulations to cover the

bundled sales market, id. at 31,275.

Third, removal of ceilings facilitates the movement of capacity into the hands of those who value it most highly. See

Order No. 637 at 31,280. With the rate ceilings in place, the

options of a shipper looking for short-term capacity on a peak

day are only to enter a bundled transaction with a holder of

firm capacity (at a price that includes the market value of

transportation), or to "take the gas out of the pipeline and

pay the pipeline's scheduling or overrun penalties," which, the

Commission observed, may "compromise the operational integrity of the pipeline's system." Order No. 637 at 31,276;

see also id. at 31,280. Thus the rate relaxation reduces

transactions costs and increases transparency, helping economic actors make rational decisions for other aspects of their

operations, e.g., decisions on how much firm capacity they

really need, and, for example, for a fuel-switchable industrial

user, whether to use or sell some of its capacity. Id. at

31,276.

It might be argued that these efficiency values are ubiquitous and might justify any deregulation of any rates mandated by Congress to be held at "just and reasonable" levels.

Not so. Cost-based rate regulation of a natural monopoly (if

accurately done--a big "if") is consistent with efficiency. The

special phenomenon here is congestion in the peaks; it is only

the inefficiency produced by rates based solely on the cost of

supply--and in complete disregard of the opportunity cost of

the capacity--that the Commission has set out to remedy.

Compare Order No. 637-A at 31,595 (expressing view that

peak prices simply reflect scarcity rents).

The presence of these non-cost factors here distinguishes

the present case from prior decisions cited by Exxon, see

Farmers Union; Elizabethtown Gas, 10 F.3d 866; Tejas

Power Corp. v. FERC, 908 F.2d 998 (D.C. Cir. 1990), where

we set aside FERC departures from cost-based rate ceilings.

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3. Oversight. As to monitoring and assurance of remedies in the event of insufficient competition, on which Farmers Union set great store, see 734 F.2d at 1509, the Commission identifies three safeguards.

First, release prices and availability must be publicly reported in compliance with FERC's current posting and bidding requirements. This will increase the information available to buyers and, the Commission believed, reduce any ill

effects of market power, while at the same time making it

easier for FERC to identify situations in which shippers were

abusing their market power. Order No. 637 at 31,283; Order

No. 637-A at 31,558. FERC also noted that it retained

jurisdiction under s 5 of the NGA, 15 U.S.C. s 717d, to

entertain complaints and to respond to specific allegations of

market power on a case-by-case basis if necessary. See

Order No. 637 at 31,286 (stating that specific abuses of

market power "can be addressed on an individual basis"); see

also FERC Br. at 54 (citing Transmission Access Policy

Study Group v. FERC, 225 F.3d 667, 689 (D.C. Cir. 2000)

("TAPS"), aff'd sub nom., New York v. FERC, 122 S. Ct. 1012

(2002), ("[I]f [a party] has evidence that the tariff results in

undue discrimination in its individual circumstances, [that

party] remains free to file a petition under FPA s 206 [the

equivalent of NGA s 5] for redress, and FERC will consider

its claim."). Finally, the Commission pointed out that this

mitigation mechanism, however reactive and limited to forward-looking remedies, is complemented by its continued

regulation of pipeline penalty levels, which establish de facto

rate ceilings for release transactions, as would-be purchasers

of capacity would not pay a price greater than the penalty for

overuse of their regular pipeline capacity. See Order No.

637-A at 31,558.

Given the substantial showing that in this context competition has every reasonable prospect of preventing seriously

monopolistic pricing, together with the non-cost advantages

cited by the commission and the experimental nature of this

particular "lighthanded" regulation, we find the Commission's

decision neither a violation of the NGA, nor arbitrary or

capricious.

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B. Retention of the rate ceilings for short-term pipeline

releases

Having been attacked for going too far with its waivers,

FERC is also challenged for not going far enough. A group

of four pipelines argues that the Commission's decision to

retain the price ceilings on pipelines, while removing them

from short-terms resellers of capacity, is discriminatory and

arbitrary and capricious. We do not find the Commission's

gradualism fatally flawed.

We start, of course, from the premise that the Commission

is free to undertake reform one step at a time. Maryland

People's Counsel v. FERC, 761 F.2d 768, 779 (D.C. Cir. 1985).

We can overturn its gradualism only if it truly yields unreasonable discrimination or some other kind of arbitrariness.

In fact the Commission's distinction is not unreasonable.

Despite the absence of Herfindahl-Hirschman indices for nonpipeline capacity holders, there seems every reason to suppose that their ownership of such capacity (in any given

market) is not so concentrated as that of the pipelines themselves--the concentration that prompted Congress to impose

rate regulation in the first place. See FPC v. Texaco, 417

U.S. 380, 398 n.8 (1974). The petitioning pipelines assert that

pipelines hold only about 7% of pipeline transportation capacity, while shippers hold the remaining 93%. This is classic

apples and oranges. The Commission points out that whereas the uncontracted capacity of a pipeline is presumptively

available for the short-term market, no such presumption

makes sense for the non-pipeline capacity holders: they

presumably contracted for the capacity in anticipation of

actually using it.

Second, the Commission made clear that pipelines do have

options for a switch to market rates. A pipeline may sell at

such rates either by demonstrating that there is enough

competition in the short-term market to preclude market

power, or by securing FERC permission for sale of capacity

by auction. The Commission recognized that such auctions

were to a degree hampered by its own regulations, and

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expressed a readiness to waive some of the burdens. See

Order No. 637-A at 31,572; Order No. 637 at 31,295.

The pipelines make the interesting point that continued

subjection of their short-term rates to FERC ceilings will

skew the prices in the decontrolled market. The Commission's brief writers profess to be "baffl[ed]" by this argument,

but its opinion writers understood the principle perfectly well,

in fact invoking it in another context. See Order No. 637-B

at 61,164 n.8. The basic proposition asserted by the pipelines

(and, as we say, recognized by the Commission) is that where

(1) a portion of the supply of a good or service is subject to

price controls, and (2) demand exceeds (the price-controlled)

supply at the fixed price, the market-clearing price in the

uncontrolled segment will be normally higher than if no price

controls were imposed on any of the supply.

This is so because--unless there is a system of rationing

the price-controlled supply that in some way exactly matches

the would-be buyers' willingness to pay (an improbable scenario)--buyers whose demand would have been completely

foreclosed if the entire market had been uncontrolled will in

fact use up some of the price-controlled supply and thus

(obviously) some of the aggregate supply. In the pricecontrolled segment higher-value demanders will to a degree

be supplanted by lower-value demanders. The presence of

the extra unsatisfied higher-value demand alters the

demand-supply ratio in the uncontrolled market, which will

therefore clear at a higher price than if the entirety were

uncontrolled. For example, consider a good that sells for

$1.25 in an open market. The market is then split and a

ceiling of $1 is set in the controlled sector. As some users of

the controlled supply would only have been willing to pay,

say, $1.10, and thus would have consumed none before, their

usage will displace demanders willing to pay $1.25 or more;

the displaced demanders will drive up the uncontrolled price.

Compare National Regulatory Research Institute, State Regulatory Options for Dealing with Natural Gas Wellhead

Price Deregulation 40-51 (1983).

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This is surely a potential price of gradualism. But distortions of this sort seem likely in any such compromise, and

compromise--going one step at a time--is within the Commission's purview so long as it rests on reasonable distinctions. Here, the distinction between pipelines and other

holders of unused capacity, based on probable likelihood of

wielding market power, seems to us to pass muster.

II. Segmentation

As part of Order No. 636, FERC established two related

policies--segmentation and flexible point rights--that it

thought were important to enhancing the value of firm capacity and to promoting competition in the secondary market

between firm shippers releasing capacity and pipelines, as

well as between releasing shippers themselves. Order No.

636 at 30,428, 30,420-21; see also Order No. 637 at 31,300-01.

Segmentation refers to the ability of firm capacity holders to

subdivide their capacity into separate parts, either for their

own use or for release to replacement shippers. Order No.

637 at 31,303; see also Order No. 637-A at 31,591. Flexible

point rights, on the other hand, enable firm capacity holders

to change the primary receipt or delivery point--the points

with respect to which shippers are guaranteed to have firm

service for their shipments--so that they can receive and

deliver gas to or from any point within their firm capacity

rights. Order No. 637 at 31,301.

Not having included its segmentation policy in any regulations issued as a result of Order No. 636, see Order No. 637

at 31,301, the Commission later found that in the process of

approving individual pipeline restructurings it had not implemented the policy uniformly. See Order No. 637 at 31,301,

31,303. Compare, e.g., Texas Eastern Transmission Corp.,

63 FERC p 61,100 at 61,452 (1993) (segmentation allowed),

with Koch Gateway Pipeline Co., 65 FERC p 61,338 at 62,631

(1993) (no segmentation); see also Order No. 637 at 31,301;

Order No. 637-A at 31,590.

Concerned with this lack of consistency, it responded in

Order No. 637 by codifying a requirement that pipelines

"permit a shipper to make use of the firm capacity for which

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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." Order No. 637 at 31,303; 18

C.F.R. s 284.7(e). It directed each pipeline to make a pro

forma tariff filing showing how it intended to comply with the

new regulation, or explaining why its system's configuration

justified curtailing segmentation rights to ensure operational

integrity. Order No. 637 at 31,304. Moreover, at least in the

context of segmented transactions, limitations on flexibility in

changing primary points would now also have to be based

solely on the operational characteristics of pipeline systems.

Order No. 637-A at 31,595.

Interstate Natural Gas Association of America and several

pipelines (collectively, "INGAA") now challenge the new segmentation rule both on its face and, in the alternative, as it

applies to a number of factual scenarios. We deal first with

the general attack, then with specifics.

A. General validity

Section 5 of the Natural Gas Act requires that when the

Commission seeks to replace an existing rate or practice with

a new one, it must demonstrate by substantial evidence that

the existing rate or practice has become unjust or unreasonable, and that the proposed one is both just and reasonable.

15 U.S.C. s 717d; Western Res., Inc. v. FERC, 9 F.3d 1568,

1580 (D.C. Cir. 1993). INGAA raises both a procedural and a

substantive attack on the adequacy of FERC's findings in the

present orders.

INGAA claims that the Commission must make a detailed

showing "that every pipeline's [existing] tariff [was] unjust

and unreasonable," or that the new policy is "just and reasonable for any pipeline." INGAA Segmentation Br. at 14-15.

But s 5 imposes no such requirement. Our cases have long

held that the Commission may rely on "generic" or "general"

findings of a systemic problem to support imposition of an

industry-wide solution. See TAPS, 225 F.3d at 687-88; Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 & n.36 (D.C.

Cir. 1985). Here, the Commission has made a "generic

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determination" that a pipeline's refusal to permit segmentation where it could "operationally" do so would be unjust and

unreasonable. Order No. 637-A at 31,590. And the Commission explained that it was not making a s 5 determination

that any particular pipeline's tariff was unjust or unreasonable, but that it would defer such an inquiry to individual

compliance proceedings, where the applicable standard would

be operational feasibility. Id. at 31,590-91.

As INGAA correctly points out, the Commission cannot

enact "an industry-wide solution for a problem that exists

only in isolated pockets. In such a case, the disproportion of

remedy to ailment would, at least at some point, become

arbitrary and capricious." INGAA Segmentation Br. at 16

(quoting Associated Gas Distributors v. FERC, 824 F.2d 981,

1019 (D.C. Cir. 1987) ("AGD")). According to INGAA, the

Commission's vague observation that "some pipelines" do not

permit segmentation where it is operationally feasible, Order

No. 637 at 31,301, does not sufficiently illustrate the existence

of an industry-wide anti-competitive practice that the Commission purports to seek to eliminate with its broad rule.

INGAA Segmentation Br. at 16.

INGAA somewhat misinterprets the law when it insists

that a problem must necessarily be widespread to permit a

generic solution. The very quotation from AGD on which

INGAA relies shows that proportionality between the identified problem and the remedy is the key. See also AGD, 824

F.2d at 1019 (holding that the Commission could not rely on

"generic" analysis where it expressly found that only a limited segment of the industry was affected by the problem it

sought to address, while the remedy adopted would necessarily impact other segments).

Here the Commission could reasonably consider the remedy proportional to the identified problem: it requires segmentation only where it is operationally feasible, since in that

situation, the Commission found, the failure to permit segmentation is unjust and unreasonable because it restricts

efficient use of capacity without adequate justification. See

Order No. 637 at 31,304; Order No. 637-A at 31,591.

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Insofar as INGAA makes a general attack on the substance

of the generic finding, it is unconvincing. It says that a

pipeline may resist even operationally feasible segmentation

"for a host of ... contractual, and financial reasons."

INGAA Segmentation Br. at 15-16. This is surely true. But

pipeline contracts are subject to modification by the Commission on findings that their terms are unjust or unreasonable,

and we have long taken the view that the Commission may

use this power to apply "whatever pro-competitive policies

are consistent with the agency's enabling act." AGD, 824

F.2d at 1018. As a general matter, INGAA simply fails to

make the case that the flexibility on which the Commission

insists (subject to operational feasibility concerns) is not

necessary for reasonable pursuit of the Commission's policy

of enhancing competition by increasing the flexibility of capacity releases.

INGAA makes a related claim that by forcing pipelines to

submit pro forma filings, the Commission has impermissibly

shifted onto them the burden of proof that segmentation is

indeed infeasible for a particular pipeline, evading its duty to

carry the burden of supporting any change implemented via

s 5. According to INGAA, the Commission has in essence

required pipelines to make s 4 filings to defend their current

rates; s 4 proceedings presuppose that it is the company that

seeks a rate change and they therefore allocate to the company the burden of justifying new tariffs. See Public Serv.

Comm'n v. FERC, 866 F.2d 487, 488 (D.C. Cir. 1989).

Indeed, certain language in the orders and even in the

Commission's brief supports INGAA's claim. For example,

the Commission at one point says that it will "require the

pipelines to show why their existing tariffs should not be

considered unjust and unreasonable," Order No. 637-A at

31,591, and that "individual pipelines [will have] an opportunity to demonstrate that their own circumstances justify deviation from the general conclusion that segmentation is appropriate," FERC Br. at 101. INGAA's suspicion is also fueled

by the fact that on several previous occasions the Commission

had impermissibly blurred the distinction between s 4 and

s 5, see Western Res., 9 F.3d at 1578 ("We now make it an

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even six" times that the Commission failed to respect this

distinction), or tried to use another section of the NGA to

"trump" its s 5 obligations, see Pub. Serv. Comm'n, 866 F.2d

at 491 (holding that s 16 of the NGA, which grants the

Commission the right to require filings needed to exercise its

powers under the NGA, did not permit FERC to require a

company to make periodic s 4 re-filings).

Nonetheless, the orders contain some express language

supporting the position of the Commission's counsel at oral

argument that FERC will indeed shoulder the burden under

s 5 of the NGA to show the requisite operational feasibility.

See Order No. 637-A at 31,590-91 (suggesting that pro forma

compliance filings are not s 4 filings, and that FERC "will be

acting under Section 5 to implement changes"); Order No.

637-B at 61,165. Given that the character of s 5 is well

established, we feel reasonably confident that the Commission

will hew to its constraints; if not, obviously a judicial remedy

would follow any individualized abuse.

As to the Commission's determination to extract information from pipelines relevant to the practical issues, we see no

violation of the NGA. The Commission has authority under

s 5 to order hearings to determine whether a given pipeline

is in compliance with FERC's rules, 15 U.S.C. s 717d(a), and

under s 10 and s 14 to require pipelines to submit needed

information for making its s 5 decisions, 15 U.S.C. ss 717i &

717m(c). See also Order No. 637-B at 61,165.

B. Specific defects

INGAA contends that, although FERC expressly limited

its new segmentation rule to capacity "for which [the shipper]

has contracted," 18 C.F.R. s 284.7(d), the orders actually

increase shippers' transportation rights beyond their contractual scope, thus amounting to an unlawful abrogation of

contract, and that the orders are otherwise arbitrary and

capricious.

1. Primary point rights in segmented releases. In the

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tween pipeline services and released capacity. Order No.

637-A at 31,594. Take the Commission's own example of a

shipper holding firm capacity between the Gulf of Mexico and

New York. That shipper could release the portion or segment of its firm capacity between the Gulf and Atlanta to a

replacement shipper, permitting the replacement shipper to

use the segment to deliver gas to Atlanta; meanwhile the

releasing shipper would retain its firm capacity between

Atlanta and New York, allowing it to ship gas from Atlanta to

New York. Order No. 637 at 31,301. In this situation, both

the releasing and the replacement shippers need to have the

ability to change their primary receipt and delivery points

from the ones designated in their contracts so as to be able to

effectively make use of the segmented capacity; for instance,

the replacement shipper needs to designate Atlanta as its

primary delivery point, now that it has acquired rights to

capacity in the mainline segment terminating there. If the

replacement shipper were limited to less-than-primary rights

at Atlanta, then the releasing shipper could not compete

effectively with the pipeline as a seller of capacity, because

the pipeline would have the right to sell capacity to the

Atlanta point on a primary basis. See Order No. 637-A at

31,594.

INGAA objects to the Commission's requirement that pipelines automatically grant shippers primary treatment at multiple points, subject only to operational constraints, saying

that such a rule effectively abrogates pre-existing contractual

arrangements--which limit primary rights to specific points--

by endowing shippers with rights they have never bargained

or paid for. Assuming the shippers' rights are so limited,

INGAA claims that the Commission has not met the standard

under s 5 for abrogation of the pipeline's rights. See Permian Basin Area Rate Cases, 390 U.S. 747, 822 (1968) (abrogation permitted "only in circumstances of unequivocal public

necessity").

It is not clear, however, that there are any pre-existing

contract rights to be "abrogated." FERC's policy tying

flexible primary points with segmentation rights dates back

to Order No. 636, which started the restructuring process;

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thus, it presumably governs the currently applicable contracts. In the Order No. 636 restructuring proceedings, the

Commission generally permitted more than one approach by

pipelines to granting shippers flexible point rights, but observed repeatedly that in the segmentation context, flexibility

in point rights was required in order for segmentation to be a

"meaningful option" or a "meaningful mechanism." See, e.g.,

Transwestern Pipeline Co., 62 FERC p 61,090 at 61,658

(1993); Northwest Pipeline Co., 63 FERC p 61,124 at 61,807

(1993). In some instances, the Commission did permit pipelines to limit shippers' flexibility in choosing primary points,

based on pre-existing tariff provisions. For example, in

Transwestern Pipeline, the Commission approved a pipeline

tariff that continued a pre-existing provision limiting a shipper's primary point rights to the same level as its total

mainline contract demand, based on a concern over hoarding

of primary point rights. 62 FERC at 61,659; Order on

Rehearing, 63 FERC p 61,138 at 61,911-12 (1993). But even

then the Commission noted Transwestern's remark that it

had a lot more primary point capacity than mainline capacity,

and so acknowledged that perhaps the restriction would prove

unneeded. Id., 62 FERC at 61,659; 63 FERC at 61,911-12.

Thus, its practice appears to have been in effect an application of the operational feasibility principle, and this typically

led to tariff rules broadly protecting releasing and replacement shippers' interest in points along their respective segments. See, e.g., Northwest Pipeline, 63 FERC at 61,806-08.

In the restructuring in Texas Eastern Transmission Corp.,

63 FERC p 61,100 (1993), for example, FERC stated its

policy to be:

The releasing and replacement shippers must be treated

as separate shippers with separate contract demands.

Thus, the releasing shipper may reserve primary points

on the unreleased segment up to its capacity entitlement

on that segment, while the replacement shipper simultaneously reserves primary points on the released segment

up to its capacity on that segment.

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Id. at 61,452 (quoted verbatim in Order No. 637 at 31,302).

See also El Paso Natural Gas Co., 62 FERC p 61,311 (1993).

Thus the new segmentation rule represents a continuation of

past policy rather than a break with it, and no further special

showing was required for the continuation of that policy.

2. Forwardhauls and backhauls to the same delivery

point. INGAA also challenges what the Commission viewed

as a clarification of prior policy for the situation where

releasing and replacement shippers, in a combination of forwardhaul and backhaul, make deliveries to a single point in an

amount greater than the shipper's contracted-for capacity at

the delivery point.

First, we need to develop a clear picture of a backhaul

transaction. Suppose a pipeline runs from A to B to C, and

has 10,000 dekatherms of daily capacity, all of which is

contracted for from A to C and of which X holds 1000. X's

market at C declines, and X would like to ship only to B and

to release the 1000 in B-C capacity. X learns of another

possible shipper, Y, who has a right to 1000 dekatherms at C

and would like to sell it at B. Can X release its B-C capacity

to Y, even though the nominal "flow" of Y's intended shipment is against the A to C stream?

So far as mainline capacity is concerned, we understand the

parties to agree that this is permissible. Given that the gas

actually will not and cannot be moved upstream, the deal

appears to force the pipeline to carry an extra 1000 from A to

B (the basic 10,000, plus the 1000 to be delivered at B on

behalf of Y). But because of gas's fungibility the appearance

is false. The pipeline will now deliver 9000 at C, and it will

rely on Y's supply for 1000 of that. As a result, it still need

carry only 10,000 from A to B, where it will dispense 1000 for

X's account and 1000 for Y. On the B-C leg it need carry

only 8000. Thus the transaction does not violate FERC's

rule that segmentation may not result in shipments exceeding

the shippers' contracted-for capacity rights on any segment.

Order No. 637-A at 31,591.

But the parties are in dispute over the delivery point.

Suppose that point B, instead of being the same physical

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delivery facility, were really two nearby points, B1 and B2, the

latter a bit downstream of the former. Both sides agree that

the above transaction would be all right, subject to the

operational feasibility constraint, even though deliveries are

now being made at those two sites that were not specifically

contracted for. But INGAA balks at the original hypothetical

(where both new deliveries are at B), because of the alleged

excess beyond X's contract rights.

Some decisions prior to the present orders suggest that the

Commission too disapproved of such a transaction. In at

least one case the Commission said that such a transaction

produced a fatal "overlap" at the single point of delivery. "A

shipper may segment its capacity rights, but it cannot exceed

its contractual service levels at any point." Iroquois Gas

Trans. Sys., L.P., 78 FERC p 61,135 at 61,523-24 (1997). But

a few years later the Commission allowed what appears to be

substantially similar, a combined "forwardhaul and backwardhaul to a series of 23 meter stations considered as a single

point for nomination purposes," Order No. 637-A at 31,593,

citing Transcontinental Gas Pipe Line Corp., 91 FERC

p 61,031 (2000).

Finding that its prior policy was based on a "metaphysical

distinction" between a single point and two points adjacent to

each other, FERC decided in the present orders that, to

advance its new segmentation policy, it would no longer apply

"prior restrictions" on using forwardhauls and backhauls to

the same point. Order No. 637-A at 31,592-93.

The Commission's characterization of the distinction as

"metaphysical" may in the end be correct, but it is not selfevident: The number of angels that can stand on the head of

one pin seems physically (rather than metaphysically) different from the question how many can stand on two. Although

the Commission observed that the pipelines seeking rehearing had not shown that they faced "any operational problems

in permitting such flexibility," Order No. 637-B at 61,166,

that issue is distinct from the problem of an inadequately

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supported contract modification. Accordingly, we remand

this issue to the Commission so that it can more clearly

confront the question of whether this aspect of the orders can

stand without additional findings.

3. Virtual pooling points. INGAA attacks the Commission's decision that segmentation be permitted at "any transaction points on the pipeline system, including virtual transaction points, such as paper pooling points, as well as at

physical interconnect points." Order No. 637-A at 31,591-92.

It argues that this provision grants rights to certain shippers

that are detrimental to other shippers, and interferes with

how such "virtual" points actually operate.

A "virtual point" is a paper or accounting point that does

not physically exist on a pipeline. One kind of a virtual point

is a "paper pooling point," which is used for administrative

purposes, i.e., to aggregate the receipt of gas from multiple

physical points in a specific geographic area to simplify

accounting.

INGAA reasons that because a paper pooling point does

not physically exist, a shipper cannot purchase the right to

transport gas to or from that point along an identifiable

capacity path: a shipper that segments its capacity in relation

to a paper pooling point could end up flowing gas on overlapping physical segments of the pipeline and thus in excess

of its contracted-for capacity. For instance, if a pipeline runs

from A to B to C to D, and B and C are physical points

included in a single paper pool, then a shipper releasing the

B-D capacity and retaining the A-C capacity would be making an overlapping use of the B-C segment.

In Order No. 637-B the Commission acknowledged such a

possibility, but nevertheless thought that "[t]o the extent such

difficulties [i.e., overlapping] exist, they are more appropriately examined in the compliance filings." Order No. 637-B at

61,165. We understand this to mean that the Commission is

serious in its commitment that it will not apply segmentation

in a way that subjects pipelines to overlapping uses of mainline capacity. Oddly, the Commission's brief writers seem to

have adopted a rather in-your-face approach, declaring flatly

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that "[t]his type of segmentation does not result in the

overlap of capacity and Petitioners have not explained otherwise." FERC Br. at 111.

Despite the brief, we take the Commission at its word--

namely, that in the compliance process it will not apply the

orders in such a way as to violate the precept against forcing

overlaps on a pipeline.

4. Reticulated pipelines. In contrast to linear pipelines, a

reticulated pipeline has a web-like structure. Such pipelines

are typically located in a single geographic area and have

receipt and delivery points interspersed throughout the system. Gas flows are not unidirectional but instead reverse

direction depending on supply and demand. They typically

rely on "displacement" to make deliveries, that is, the substitution of gas at one point for gas received at another point.

In the orders, the Commission recognized that "permitting

segmentation on a reticulated pipeline can result in operational difficulties" because unplanned changes in flow patterns

might threaten their operational integrity. Order No. 637-A

at 31,591; see also Northwest Pipeline, 69 FERC p 61,171 at

61,677 (1994) ("certain offsetting volumes must flow in one

direction in order for customers shipping in the opposite

direction to receive service,"). But it nonetheless said that

these pipelines must "permit segmentation to the maximum

extent possible given the configuration of [the] system," Order No. 637 at 31,304, and must "optimize [their] system[s] to

provide maximum segmentation rights while devising appropriate mechanisms to ensure operational stability," Order No.

637-A at 31,591, a duty that may include "allowing segmentation on straight-line [non-reticulated] portions of the pipeline," Order No. 637-B at 61,165.

INGAA first contends that it is arbitrary and capricious for

FERC to apply the segmentation rule to reticulated pipelines,

because these pipelines have no identifiable capacity paths to

segment, and therefore "segmentation is not possible on

reticulated systems." INGAA Segmentation Br. at 27. But

the Commission's only clear language requiring segmentation

in this context explicitly focused on "straight-line portions of

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the pipeline." Order No. 637-B at 61,165. Insofar as its

other, vaguer language invites extreme interpretation, we

understand it to be qualified as always by the operational

feasibility criterion. As we cannot possibly divine the vague

phrases' operational meaning, the claim is now unripe. See

Abbott Labs. v. Gardner, 387 U.S. 136, 149 (1967) (stating that

to evaluate ripeness, a court must consider "both the fitness

of the issues for judicial decision and the hardship to the

parties of withholding court consideration"), overruled on

other grounds, Califano v. Sanders, 430 U.S. 99 (1977); Rio

Grande Pipeline Co. v. FERC, 178 F.3d 533, 540 (D.C. Cir.

1999) ("[A] case is ripe when it presents a concrete legal

dispute [and] no further factual development is essential to

clarify the issues ... [and] there is no doubt whatever that

the challenged [agency] practice has crystallized sufficiently

for purposes of judicial review.") (internal citation and quotation marks omitted).

The same unripeness applies to INGAA's claims regarding

a special class of reticulated pipelines, those employing "postage stamp" rate structures. In such pipelines, as for first

class mail in the U.S. postal system, the same transportation

rate applies to all transactions. This contrasts with the usual

rate structure for non-reticulated pipelines, and for some

reticulated ones, under which the rate depends on the zones

through which the gas passes. INGAA argues that in this

context segmentation grants shippers extra-contractual rights

and is an unexplained and, therefore, arbitrary and capricious

departure from prior policy.

Order No. 637-A provides that, "[o]n 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." Order No. 637-A at

31,591. The Commission justifies this policy on the ground

that shippers on such pipelines pay "for the use of the entire

pipeline in their rates." Id. Finally, the Order notes that, if

these pipelines find that providing segmentation "would be

more feasible with a redesign of its rates, the pipeline can

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make a Section 4 filing to establish rates that it considers

more consonant with segmentation." Id.

INGAA suggests that under this language the Commission

may intend to allow shippers "to multiply their capacity

rights." INGAA Segmentation Br. at 28. The language is

indeed susceptible of such a reading; taken at the extreme, it

is as if the Post Office, having agreed to carry letters

anywhere for 34 cents, including from New York to San

Francisco, could be obliged to carry one letter from New

York to Chicago, and another from Chicago to San Francisco,

all for one 34-cent stamp. The Commission's allusion to new

filings under s 4 only heightens the impression of overweening agency ambition. Can the Commission contemplate that

it will use s 5 in compliance proceedings to compel costly

changes in pipeline operation, leaving the pipeline to recover

the resulting costs by filing under s 4? But to conjure up

such activities is not to say that the Commission's language

compels them. Until the words are implemented, claims

based on this language are unripe.

5. Discounts. Under typical discount agreements, pipelines agree to provide shippers with services at discounted

rates, but with those rates limited to agreed-upon receipt and

delivery points. Before these orders, the Commission's policy

was that "discounts granted with respect to specific points do

not apply when shippers change points." Order No. 637-A at

31,595. This meant that when a shipper released part of its

capacity, the releasing or replacement shipper was subject to

the non-discounted rate if it exercised its right to designate

different receipt or delivery points. Id.

Some of the Commission's language here appears to contradict the prior view. For example, the Commission said that

"within the path" of a shipper's contract, it "should be permitted to ... segment capacity along that [discounted] capacity

path without incurring additional charges," i.e., without having to pay the non-discounted rate. Order No. 637-A at

31,595. And it said that the reason a discount should apply to

segmented transactions is that, once a long-line pipeline has

discounted transportation to a downstream delivery point, "it

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has foreclosed the possibility of selling that capacity" at a

higher rate to an upstream delivery point. "[T]he discount,

therefore, should apply to all transactions within the capacity

path." Order No. 637-B at 61,167.

Several aspects of discounting are affected here. First, the

Commission refers to discounts granted because of pipeline

"underutiliz[ation]," Order No. 637-A at 31,595. When a

pipeline discounts some capacity from A to C solely for that

reason, presumably the discount is consistent, in the pipeline's view, with the levels of demand in even the most heavily

used segment. Thus the observation quoted above from

Order No. 637-B.

But the Commission also recognized that discounts may be

given because of differing competitive conditions. It said that

pipelines "will still be able to discount transportation to a

particular customer who has competitive options to stimulate

throughput without necessarily offering the same discount to

other customers who are not similarly situated." Order No.

637-B at 61,168. The difference in conditions might be

customer-specific (e.g., a fuel-switchable industrial user) or

segment-specific (e.g., a pipeline might be subject to severe

competition between points A and C, but to little between

points A and B (the latter being an intermediate point

between A and C)).

Finally, of course, the whole capacity release program as a

general matter creates possibilities for arbitrage. If a highelasticity customer is completely free to transfer capacity to a

low-elasticity one, offering price variations not based on cost

becomes a far less tempting pipeline strategy.

But again the issue is unripe, as the orders leave us quite

unclear just what will emerge from all this. Besides the

already quoted commitment to preserve at least some competition-based discounts, the Commission said that "it did not

intend to change the rules regarding selective discounting."

Order No. 637-B at 61,168. We are in no position to assess

the legality of the Commission's intentions, which will only be

revealed in future proceedings.

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III. Secondary Point Capacity Allocation

In Order No. 637-A FERC changed the rule for allocating

mainline capacity leading to secondary delivery points--the

additional points to which a firm shipper may wish to deliver

gas besides its primary delivery location. Order No. 637-A

at 31,597. Because shipments to such secondary points are

normally accorded lower priority than deliveries to primary

points, this service is subordinate to "firm" service during

periods of congestion. Order No. 637 at 31,304-05. In the

past, the Commission's rule governing secondary point capacity allocation during constrained periods was the pro rata

method. Shippers whose primary delivery points were located in the same rate zone--a geographical area treated as a

single point for rate purposes--had equal entitlements to the

capacity needed to reach secondary points in that zone; if

they requested more secondary point capacity than was available, it was allocated pro rata. Id.

The Commission illustrates the issue with the following

diagram:

Diagram not available electronically.

Order No. 637-B at 31,597. On the facts given, the old rule

gave shippers 1 and 2 equal rights to the mainline capacity

needed to ship to B, with their entitlements being inferior to

shipper 3's.

In Order No. 637-B, however, the Commission concluded

that a different approach would better assure allocation of the

capacity to the shipper valuing it most highly. Under its new

"within-the-path" rule, all shippers for whom the point is

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within their capacity path--that is, the shippers whose primary delivery points are downstream of the point at which

secondary rights are sought--receive preference over shippers for whom the point is not in their capacity path. In the

example above, then, shipper 2 would have a straightforward

priority over shipper 1, though even shipper 2 would be

subordinate to shipper 3. Order No. 637-B at 31,597. The

Commission's theory was that the priority for shipper 2 would

reduce transaction costs and, by establishing shipper 2 as a

more vital competitor (with shipper 3) as a source of capacity,

would enhance competition.

Two interstate pipelines owned by Enron (collectively, "Enron") now challenge the new rule for allocating capacity at

secondary points on a number of grounds. We do not reach

those issues because Enron has not made an adequate showing that it is aggrieved by FERC's ruling. As it lacks both

statutory and constitutional standing to bring this petition, we

dismiss it for lack of jurisdiction.

The NGA requires, as a precondition to judicial review, that

a party be "aggrieved" by the order in question, 15 U.S.C.

s 717r(b); El Paso Natural Gas Co. v. FERC, 50 F.3d 23, 26

(D.C. Cir. 1995), and all parties trying to invoke the jurisdiction of federal courts must satisfy Article III's requirements

of constitutional standing. "Common to both of these thresholds is the requirement that petitioners establish, at a minimum, 'injury in fact' to a protected interest." Shell Oil Co. v.

FERC, 47 F.3d 1186, 1200 (D.C. Cir. 1995). To show "injury

in fact," a litigant must allege harm that is both "concrete and

particularized" and "actual or imminent, not conjectural or

hypothetical." Lujan v. Defenders of Wildlife, 504 U.S. 555,

559-61 (1992).

Enron is a pipeline, not a shipper, so no injury leaps to the

eye. But it proposes two theories of injury, one based on the

effect of the rule on competition, the other on administrative

burdens generated by the rule. Neither is persuasive.

First Enron suggests the new method will diminish competition in the supply of capacity by decreasing the number of

possible suppliers. The reduced competition would cause

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higher gas prices in end-use markets, reducing overall gas

consumption, and thereby reducing pipeline throughput.

Where a claimed injury stems from changes in levels of

competition, this court ordinarily requires claimants to show

that "a challenged agency action ... will almost surely cause

[them] to lose business." El Paso, 50 F.3d at 27 (emphasis

supplied); see also D.E.K. Energy Co. v. FERC, 248 F.3d

1192, 1195 (D.C. Cir. 2001). Enron relies on a simple account

under which "eliminating competitors reduces competition."

Enron Repl. Br. at 5; Enron Br. at 11. Everything else

being equal, that is likely a sound assumption. But the

Commission here thought--and Enron has not shown the

contrary--that matters were more complex.

The Commission's stated rationale for adopting its new

method was that the pro rata method "does not provide for

the most efficient use of mainline capacity or promote capacity release because it creates uncertainty as to how much

mainline capacity any shipper seeking to use secondary points

will receive." Order No. 637-A at 31,597. As a result the

secondary rights were not tradable, and there was no effective competitor to the primary rights holder as a seller of

secondary rights. Id. By comparison, under the within-thepath method, the fewer shippers to whom secondary rights

would be awarded would hold--and thus be able to offer in

the market--a useful entitlement to service. Id. In FERC's

opinion, this increase in certainty of entitlement would actually improve competition. Id.

We need not pass on the ultimate merits of the Commission's reasoning to say that Enron's contrary theory fails to

show the requisite probability of harm. Basically, the showing is far too conjectural to establish "a substantial (if unquantifiable) probability of injury," D.E.K. Energy, 248 F.3d

at 1195, as demanded by El Paso's "almost surely" test.

Alternatively, Enron claims that that the company will

incur "significant expense" in implementing the new method

because it must modify its computer systems "in order to

accommodate multiple levels of secondary point priorities."

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tute an injury-in-fact, Enron's argument here rests solely on

a conclusory, vague and unsupported assertion of cost increases. See Enron Repl. Br. at 3. Compare Virginia v.

American Booksellers Ass'n, Inc., 484 U.S. 383, 392 (1988)

(standing where plaintiff "will have to take significant and

costly compliance measures or risk criminal prosecution");

see also id. at 389, 391 (detailing steps needed for compliance). Thus we dismiss the petition for want of jurisdiction.

IV. Penalties

Order No. 637 changed the rules governing what pipelines

may do when shippers overrun their transportation entitlements (by shipping more gas than they have contracted for)

or create physical imbalances in the pipeline system (for

example, by withdrawing more--or less--gas from the system than they have tendered). Previously, in the interests of

deterrence, see Order No. 636 at 30,424, pipelines were

allowed to enforce their contractual rights by imposing appropriate penalties, that is, charges that "reflect[ed] more than

simply the costs incurred as a result of the [shipper's] conduct," Order No. 637-A at 31,610; cf. id. at 31,608; Order No.

637-B at 61,171. The penalties were enforceable whether or

not the offending shipper's behavior caused any actual harm

to the pipeline's system or threatened its reliability. See,

e.g., Natural Gas Pipeline Co., 63 FERC p 61,293 at 63,052

(1993).

Order No. 637 sharply restricted pipelines' ability to assess

penalties. FERC amended its regulations to provide:

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.

18 C.F.R. s 284.12(c)(2)(v); Order No. 637 at 31,314. As

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ties for non-critical days [days when the pipeline is not

expected to operate at or near full capacity] or higher tolerances and lower penalties for non-critical as opposed to

critical days." Order No. 637 at 31,317. In addition, the rule

denies pipelines the right to retain revenues from penalties,

instead requiring them to credit them to shippers. Id. at

31,309.

In addition, Order No. 637 required pipelines to provide

"imbalance management services," such as parking (i.e., temporary storage) and lending of gas, and greater information

about the imbalance status of a shipper and the system as a

whole, in order to give shippers positive incentives--in lieu of

penalties--to manage or prevent imbalances. Order No. 637

at 31,309; 18 C.F.R. s 284.12(c)(2)(iii). The Order also allowed pipelines to retain revenues generated from these

imbalance management services until the pipeline's next rate

case, as would be true for other new pipeline services initiated between rate filings. Order No. 637 at 31,310. Thus it

used carrots with the pipelines to encourage them to use

carrots with their customers.

We deal here with a basic attack on FERC's policy change,

as well as specific claims relating to the treatment of revenues from such penalties as remain and to the new imbalance

services.

A. INGAA attack on penalty limits

INGAA and several pipelines (again collectively, "INGAA")

claim that in adopting its new penalty rule the Commission

did not make the required s 5 findings or exercise reasoned

decisionmaking, and that the new rule unlawfully infringes on

pipelines' ability to enforce their contractual rights.

When FERC seeks affirmatively to displace a pipeline's

existing rates or tariff provisions, the previously stated requirements of s 5 of the NGA apply. But there is no

requirement that FERC use the "magic words" of s 5 itself,

Rhode Island Consumers' Council v. Fed. Power Comm'n,

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504 F.2d 203, 213 n.19 (D.C. Cir. 1974), and indeed one would

search the relevant portions of Order No. 637 in vain for

words such as "just" or "unjust."

But the Commission did find that the existing penalty

system was "not the most efficient system of maintaining

pipeline reliability," and that it "skewed" the market choices

that shippers and pipelines would otherwise make. Order

No. 637 at 31,306-07. As we understand the core of the

Commission's analysis, it was that excessive pipeline penalties, and skimpy pipeline "tolerances" (i.e., allowances for

contract excesses that would not generate penalties), made

shippers unduly gun-shy. Excessive disincentives led them to

oversubscribe to firm pipeline capacity, or underuse their

entitlements, in order to assure a decent safety margin.

Order No. 637 at 31,308; Order No. 637-A at 31,607 &

nn.150, 152. Such consequences would seem to follow excessive penalties virtually as a matter of definition, but in

addition there was testimony as to the behavior of prudent

shippers. See, e.g., id. at 31,607 n. 152. And in fact INGAA

does not even try to dispute that the pre-existing penalties

produced these results.

Aside from being concerned with the adverse effects of the

penalties, the Commission also concluded that the prior regime was ineffective in fulfilling what was supposed to be its

"intended purpose," Order No. 637-A at 31,608--deterring

shipper conduct that actually threatened the integrity of the

pipeline system at critical times. Order No. 637 at 31,308;

Order No. 637-A at 31,598, 31,607 & n.152. Because the

penalty levels were disconnected from threats to reliability,

they did not offer incentives in any way calibrated to those

threats. Indeed, penalties were evidently often higher on

systems where and at times when extra gas posed no threat

to reliability at all, than on systems with such threats.

It was thus the Commission's conclusion that it should

henceforth tie the imposition of penalties to behavior actually

causing a threat to system integrity. Order No. 637 at

31,308. And, to eliminate market distortions caused by "the

use of penalties as a substitute for obtaining services," id. at

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31,314, the Commission believed that it was necessary for

pipelines (or third parties) to directly provide shippers with

the service flexibility they had been obtaining indirectly via

their responses to the penalty regime; thus the requirement

of separate imbalance management services at cost-based

pricing. Id. at 31,309. Finally, the Commission's new rules

on disposition of the revenues--disallowing pipeline retention

of penalties but allowing retention of the proceeds of new

balancing services--obviously reinforced its basic policy judgment.

We are not altogether clear why the Commission's response to excess penalties was to bar all penalties not directed to threats to reliability, and otherwise to switch to "carrots." One might suppose that the most obvious response to

excessive penalties would be to place ceilings on them--

calibrated to the damage inflicted by the penalized behavior,

whether it took the form of a threat to reliability or not. This

option is not discussed, and petitioners neither suggest it nor

fault the Commission for its failure to consider it. Perhaps

the answer is that in fact there are no injuries other than the

ones to system reliability. That in turn would seem to

depend on the actual treatment of--and incentives facing--

shippers who overrun their contract entitlements under circumstances posing no threat to reliability.

In fact, the Commission's limits on penalties (as they are

understood in this regulatory regime) appear to leave potential contract breaches covered by appropriate sanctions.

When a shipper incurs a contract overrun, it must still pay for

the interruptible service it has used for the surplus. Order

637-B at 61,172. Moreover, as was conceded by INGAA's

counsel at oral argument--and confirmed by Commission

counsel--FERC's current open access rules require a pipeline

to make its spare capacity available to any shipper who

desires it, at the interruptible rate. Tr. Oral Arg. at 106-07.

Thus, a shipper that overruns its contract and suddenly seeks

additional service is apparently treated (apart from penalties)

just the same as any unscheduled interruptible shipper.

"The capacity that a shipper would obtain by means of an

unauthorized overrun is not firm service, but is interruptible

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service that is subject to bumping and is limited by the

capacity available at the time." Order No. 637-B at 61,171.

Indeed, the firm shipper that overruns its entitlement in a

non-peak time may be worse off than a garden-variety interruptible shipper, as the latter may enjoy discounts evidently

unavailable to the overrunning customer. Tr. Oral Arg. at

108.

Likewise, a shipper who runs an imbalance must either

make-up or pay for the gas he took. Order No. 637-B at

61,171-72. Although the record seems not to explain what

price will govern such a transaction, we were told at oral

argument that the offending shipper might be obliged to pay

a higher price than a user with similar needs who chooses

instead to take advantage of the imbalance management

services or avoids creating an imbalance altogether by purchasing excess gas from another shipper. Tr. Oral Arg. at

111.

Thus, even with penalties now largely gone, pipelines are

no more forced to provide extra-contractual services under

the new rule than they were under the old one. What has

changed is merely the remedy for breach. Nor are pipelines

turned into "common carriers" required to provide service to

anyone regardless of whether they have a contract; their

duties in this respect are set out in the previously adopted

open access rules.

The rules governing shippers who exceed their contract

entitlement also answer another concern of INGAA's: that

because of the limited availability of penalties, shippers will

not contract and pay for an adequate level of firm service but

instead will simply overrun their contract capacity as needed.

In fact, in non-peak times such shippers will do no better than

interruptible shippers (and perhaps worse, because of the

discount issue). And since overruns during peak times can

still trigger penalties, shippers who need guaranteed service

should not be tempted to contract for less capacity than what

they expect to need. Order No. 637-B at 61,171.

INGAA also accuses FERC of failing to engage in reasoned

decisionmaking because of what INGAA perceives as a logical

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disconnect between FERC's stated goal--elimination of the

inefficiencies of the pre-existing penalty system--and

FERC's adoption of carrots as the cure. INGAA suggests

that the pipelines' mandated proffer of imbalance services is

hardly equivalent to penalties, for on non-critical days, when

penalties are not an option, shippers will have no incentive to

use or pay for imbalance services. As they will continue to

engage in creating overruns and imbalances, the Commission's rule is internally inconsistent and will not further

FERC's stated goals.

In large part this is answered by our earlier discussion of

the incentives faced by shippers under the new regime; the

Commission appears to have successfully rebutted INGAA's

prediction that the curtailment of penalties would harm any

pipeline interest that deserved protection. That the Commission's hope and expectation of a flourishing market in balancing-related services may prove unwarranted does not undermine that essential conclusion.

Thus the Commission made generic findings in support of

its action under s 5, see TAPS, 225 F.3d at 687-88, which

were backed by substantial evidence, and its conclusions met

the standard for reasoned decisionmaking.

B. Attacks on revenue-crediting provisions

On one hand a group of pipelines (not joined by INGAA)

attack the Commission's requirement that they flow penalty

revenues to non-offending shippers, and on the other several

shippers and state consumer advocates argue that the pipelines should not be allowed to retain the revenues from the

new imbalance services. Neither attack is well conceived.

The pipelines claim that (1) the Commission did not find

that previously approved tariffs and settlements, which imposed no such refunding mechanism, were unjust and unreasonable; and (2) the Commission justified the refund requirement "as an incentive for pipelines not to impose penalties,"

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ly apply only when shipper conduct threatens system reliability.

The first argument appears erroneously to assume that

"magic words" are required under s 5; as we've said, they

are not. And as we've already explained, the Commission's

discussion of penalties in Order No. 637 reflects compliance

with s 5. In substance the Commission's finding of unsound

incentives, see Order No. 637 at 31,316, amounts to a finding

that the prior method was unjust and unreasonable.

The pipelines' critique of the Commission's rationale misconceives its purpose. FERC's goal here was not to discourage pipelines from imposing penalties at all but rather to

motivate them "to impose only necessary and appropriate

penalties," and to develop non-penalty mechanisms to deal

with imbalance problems. Order No. 637 at 31,316. Requiring refunds of penalty proceeds simply removes an incentive

to impose unnecessary penalties. See Order No. 637 at

31,316 (stating that FERC was "requiring penalty revenue

crediting not so much for the purpose of preventing penalties

from becoming a profit center, but more for the purpose of

eliminating any financial incentives on the part of pipelines to

impose penalties that would naturally hinder the pipelines'

movement toward reliance on the provision of imbalance

services....").

On the other side, the shippers first object to pipeline

retention of revenues from imbalance services on the theory

that because Order No. 637 requires pipelines to develop such

services in any event, no financial incentive is necessary. But

the directive to develop such services is not inherently selfexecutable. Unless the Commission were ready to take on a

large new program for micromanagement of pipelines, it

makes complete sense for it to rely on positive incentives

instead of punitive measures to promote compliance. Besides, as the Commission explained, its decision on this point

is entirely consistent with its current general policy of allowing pipelines to retain revenues from "a new service initiated

between rate cases." Id. at 31,310.

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Finally the shippers assert that the Commission's policy

here is inconsistent with two recent Commission decisions

requiring pipelines to share new-service revenues with shippers, citing Trunkline Gas Co., 79 FERC p 61,326 at 62,427-

28 (1997), and Columbia Gas Transmission Corp., 64 FERC

p 61,365 at 63,530 (1993). But these cases involved sharing

interruptible service revenues under conditions where the

Commission believed there was a substantial risk of overrecovery by the pipelines in question. The petitioners have not

shown that any such conditions obtain here.

V. The Right of First Refusal

As part of its long-running effort to devise balanced rules

to protect long-term capacity holders from abandonment of

service when their transportation contracts with pipelines

expire, FERC also made changes to its "right of first refusal"

rules. In some respects, it narrowed those rights, limiting

their benefit to long-term shippers paying the maximum tariff

rate. In other ways, it expanded them, allowing incumbent

shippers to exercise the right of first refusal by bidding for a

mere five-year term. This contrasted with the 20-year term

that it had set in Order No. 636, which gave the pipelines

considerably more stability and which, in UDC, 88 F.3d at

1140-41, we found inadequately justified. Again, the agency's

actions have been challenged from both sides, as going too far

and not far enough.

A. Five-year matching cap and "regulatory" right of first

refusal

Section 7(b) of the Natural Gas Act generally prohibits

"natural-gas compan[ies]" from ceasing to provide service to

their existing customers unless, after "due hearing," FERC

finds "that the present or future public convenience or necessity permit such abandonment." 15 U.S.C. s 717f(b). Seeking to streamline the regulatory process, the Commission in

Order No. 436 attempted to dispense with these individualized hearings by giving pipelines broad prospective authority

to refuse shippers continued service on the expiration of their

contracts (in the absence of a contractual right of renewal).

See American Gas Ass'n v. FERC, 912 F.2d 1496, 1513-14

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(D.C. Cir. 1990) ("AGA"). Under this mechanism, the Commission makes ex ante generic findings of public convenience

and necessity, and issues a blanket certificate that allows a

pipeline to terminate service at the end of the shipper's

contract term. See 18 C.F.R. s 284.221(d); cf. Mobil Oil

Exploration & Producing Southeast, Inc. v. United Distrib.

Cos., 498 U.S. 211, 227 (1991) (allowing the Commission to

issue "general, prospective, and conditional" abandonment

approvals under s 7(b)).

When this court addressed the merits of the issue in AGA,

we remanded the rule for lack of an adequate explanation of

how it could be squared with the Commission's basic duty to

protect gas customers from "pipeline exercise of monopoly

power." AGA, 912 F.2d at 1518. But we noted that all

parties recognized that such a procedure made sense for at

least some transactions, most notably interruptible services

and short-term contracts. See id.

In Order No. 636, the Commission responded to AGA and

modified its earlier approach by supplementing pre-granted

abandonment authority with a right of first refusal for those

shippers the Commission considered to be captive and thus in

need of protection--those operating under a firm contract

longer than one year. Order No. 636 at 30,446-48. The right

entitled a protected shipper with an expiring contract to

retain its service from the pipeline under a new contract by

matching the rate and duration offered by the highest competing bid--up to the maximum "just and reasonable" rate

approved by FERC. On reconsideration, the Commission

also adopted a 20-year cap on the length of the term that

existing shippers may be required to match. Order No. 636-

A at 30,631.

On review, though we generally upheld pre-granted abandonment as supplemented with the right of first refusal, see

UDC, 88 F. 3d at 1140, we thought that the 20-year cap was

not justified by the record and remanded it for further

explanation. Id. at 1140-41. We expressed concern that

contract duration could become a surrogate for price (which,

of course, is capped), thereby allowing new customers to

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outbid existing ones by offering longer terms than they would

in a truly competitive market. Id. at 1140. In addition, while

FERC had picked 20 years in reliance on actual contracts, we

questioned whether the subset of contracts relied on--involving the construction of new facilities--was properly representative. Id. at 1141. But because the selection of any duration for the matching cap would be "necessarily somewhat

arbitrary," we said we would "defer to the Commission's

expertise if it provides substantial evidence to support its

choice and responds to substantial criticisms of that figure."

Id. at 1141 n.45.

On remand, FERC decided to reduce the 20-year cap to

one of five years, pointing to what it perceived as the current

industry trend in favor of shorter term shipping contracts.

Order No. 636-C, Order on Remand, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's

Regulations, 78 FERC p 61,186 at 61,773-74 (1997) ("Order

No. 636-C"). Despite objections from the pipelines, FERC

summarily affirmed its decision in Order No. 636-D, Order on

Rehearing, Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing Transportation

Under Part 284 of the Commission's Regulations, 83 FERC

p 61,210 at 61,925 (1998).

In Order No. 637 the Commission again confirmed the fiveyear period. See id. at 31,339. And it made clear that right

of first refusal "includes the right of the existing shipper to

elect to retain a volumetric portion of its capacity subject to

the right of first refusal, and permit the pipeline's pregranted

abandonment to apply to the remainder of the service." Id.

at 31,341. Moreover, it said that the "regulatory" right of

first refusal (i.e., the right supplied by this Commission

mandate) was a minimum right, usable by an eligible shipper

regardless of whether its contract provides a comparable

right (by means, for example, of an "evergreen" clause), and

that the shipper might exercise the regulatory right for part

of the contract volume and any contract right for the rest.

Id.; Order No. 637-A at 31,647. It also specified, most

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clearly in Order No. 637-A, that the right trumped any

inconsistent provision in a pipeline's tariff.

A group of interstate gas pipelines, led by INGAA (collectively "INGAA"), attack both retention of the five-year period

and the Commission's explicit statement that the right of first

refusal applies regardless of tariff provisions.

1. Five-year cap. In selecting a five-year cap on remand

from UDC, the Commission gave little indication of why it

thought that this new figure would appropriately balance the

protection of captive customers with the furtherance of market values (putting capacity in the hands of those who value it

most). It relied entirely on the fact that five years was about

the median length of all contracts of one year or longer

between January 1, 1995 and October 1, 1996. See Order No.

636-C at 61,774, 61,792. This contrasted with average durations of about 10 years in the period from April 8, 1992 to

October 1, 1996.

Before confirming the five-year figure, the Commission

itself raised doubt about its wisdom. In Order No. 636-D, it

acknowledged that "the pipelines have raised legitimate concerns about the practical effects of the five year term matching cap on the restructured market as it continues to evolve."

Order No. 636-D at 61,926. At that point the Commission

decided to defer a final decision about the length of the cap

until "a new gas policy initiative" (which proved to be Order

No. 637), because at the time it had "no information concerning current conditions in the natural gas industry." Order

No. 636-D at 61,926. In its NOPR for Order No. 637, FERC

raised what it perceived were further problems with the fiveyear term, suggesting that it "provides a disincentive for an

existing shipper to enter into a contract of more than five

years, and results in a bias toward short-term contracts."

Notice of Proposed Rulemaking, Regulation of Short-Term

Natural Gas Transportation Services, FERC Stats. & Regs.

[Proposed Regulations 1988-1998] (CCH) p 32,533 at 33,486

(1998). The Commission apparently was concerned that the

cap would foster an "imbalance of risks between pipelines and

existing shippers," allowing shippers indefinite control over

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pipelines' capacity, but giving the pipelines no corresponding

protection. Id. at 33,486-87. Thus, it suggested, elimination

of the cap would "foster efficient competition." Id. at 33,-

487. Moreover, as the pipeline petitioners point out, an

artificial, regulation-induced shift toward shorter contracts

increases risk for the pipelines; this tends to raise their costs

of capital and thus the overall cost of pipeline transportation.

And, they note, it is odd--or at least requires explanation--

why FERC should choose a median to function as a ceiling.

But when FERC ultimately elected to retain the five-year

period, it addressed none of the difficulties that it (or the

pipelines) had previously invoked. Instead, it simply referred

back to Order No. 636-C's evidence about median contract

lengths and remarked that "[n]one of the commenters presented evidence to support the conclusion that a five year

contract is atypical in the current market." Order No. 637 at

31,339; see also Order No. 637-A at 31,664 (concluding

simply that there "is no evidentiary basis at this time for

changing the 5-year matching cap"). Thus the only evidence

supporting FERC's final decision to choose a five-year cap

was the original record--which on the Commission's own view

was incomplete. There is neither an affirmative explanation

for the selection of five years, nor a response to its own or the

pipelines' objections.

We therefore vacate the five-year cap and remand the issue

back to the agency. The Commission may appear to be, visA-vis the court, like mankind to the gods: As flies to wanton

boys, they kill us for their sport. Pick 20 years, and get

reversed for failing to explain the length; pick five, and get

reversed for failing to explain the brevity. But our acknowledgment of the difficulty of the policy choice, see UDC, 18

F.3d at 1141 n.45, is fully intended. The record simply lacks

indicators of the Commission's seriously tackling that choice.

2. Right of first refusal trumping tariff provisions. Pipeline counsel accuse the Commission of wrongfully creating a

"regulatory" right of first refusal in Order No. 637. We think

their claim can better be comprehended as saying that the

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Commission in that order transformed its requirement of a

right of first refusal, ensconced in the Commission's regulations since April of 1992, see Order No. 636 at 30,446-48; see

also s 284.221(d)(2)(ii), into a self-executing requirement.

That is, their argument is comprehensible only as a claim that

before Order No. 637 the right of first refusal had legal effect

only to the extent that it was expressly embodied in a pipeline

tariff. In fact, Order No. 637 and Order No. 637-A appear to

be the Commission's first express articulations of the idea

that the regulatory right of first refusal trumps tariff provisions. The first declares that eligible shippers have "the

right of first refusal as provided in the Commission's regulations," Order No. 637 at 31,341, and the second expressly says

that the regulatory right of first refusal is effective "regardless of the terms of any tariff," Order No. 637-A at 31,646-47.

The Commission says this was old hat, pointing to its

statement back in August 1992, in the Order No. 636 series,

when it said that shippers were assured the right to continued service "even if the parties do not include an evergreen

or rollover clause in their contract." Order No. 636-A at

30,628. But the language makes no mention of tariffs, and

thus appears not inconsistent with a view that tariff language,

mandated by the Commission's regulations, is necessary to

effect the right, or at least that inconsistent tariff language

trumps. More confusing is the Commission's decision in

Algonquin Gas Transmission Co., 94 FERC p 61,383 (2001).

There it first pointed to the language quoted above from

Order No. 637, see 94 FERC at 62,439; then, when its

attention was called to contradictions between the regulatory

right of first refusal as it conceived it, and the pipelines' tariff

provisions (which had been approved as "just and reasonable"), it said that the solution was proceedings under s 5 of

the NGA to consider forward-looking modification of the

tariffs, see id. at 62,446. Were the regulatory right selfexecuting, we do not understand why s 5 proceedings would

be needed. The Commission's brief on the issue sheds no

light.

Accordingly, though not vacating this aspect of Order No.

637 or Order No. 637-A, we remand to the Commission for it

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to explain its current position, and, to the extent that language in the orders under review is legally unsustainable, to

modify it.

B. Narrowing of the right of first refusal

At the same time that the Commission expanded the degree of protection offered by right of first refusal by decreasing the maximum term that a protected shipper might be

required to match, it also narrowed the right's scope in

certain respects. Specifically, Order No. 637 denied the right

to all shippers operating under discounted rate contracts, i.e.,

contracts with rates below the maximum approved by FERC.

It also excluded "negotiated rate" contracts, i.e., ones whose

terms differ in some respect from simple application of

FERC-approved tariffs, and whose rates may fall below, at,

or above the FERC-approved maximum rate. (Both parties

assume the existence of contracts with rates above the FERC

ceiling, but neither explains how such a contract would even

be lawful.) Order No. 637 at 31,337; Order No. 637-A at

31,631-35. The order grandfathered "[e]xisting" discounted

contracts, so as to protect expectations based on the prior

rule. Order No. 637 at 31,341-42.

In support of this modification the Commission offered two

general grounds. First, it portrayed the amendment as

driven by the right of first refusal's "original purpose" to

protect "long-term captive customers from the pipeline's monopoly power." Order No. 637 at 31,337. "If the customer is

truly captive," the Commission reasoned, "it is likely that its

contract will be at the maximum rate." Id. And shippers

who have alternatives in the marketplace, as typically evidenced by their ability to negotiate discounts below the "just

and reasonable" rate, do not need this type of regulatory

protection.

Second, because the right of first refusal necessarily creates a disincentive for a shipper to enter into long-term

contracts with the pipeline, and thus tends to saddle the

pipeline with an unshared and uncompensated long-term investment risk, see id. at 31,336, the Commission also thought

that limiting the right of first refusal to those shippers paying

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the maximum rates was needed to "better balance the risks

between the shipper and the pipeline," id. at 31,337.

Petitioners objecting to the change assert that it is not

supported by substantial evidence in the record, because the

agency relied virtually entirely on its own supposition that

"truly captive" shippers are "likely" to be paying maximum

rates. Furthermore, they say, the Commission rejected their

examples to the contrary, which indicated that pipelines do

sometimes offer discounted or negotiated rates to captive

shippers.

The FERC order indeed cited no studies or data. But its

conclusions seem largely true by definition. Rate ceilings are

set at the Commission's estimate of cost, thus roughly paralleling what would occur in a competitive market. The rates

protect shippers whose choices are, by hypothesis, so limited

that otherwise they would be ready to pay supra-competitive

rates. If they are paying even less than the cost-based rates,

it appears a fair inference that they have better choices than

are supposed by the system of agency-controlled rates.

Or so one would think in the absence of specific, compelling

rebuttal evidence. What petitioners offer can hardly be

called compelling, given the Commission's need to devise

rules of general application. To be sure, their comments

listed several situations in which, they claimed, pipelines

might offer long-term shippers discounted rate contracts even

where they had market power. For instance, a discount may

be given "in consideration of entering into a settlement of a

rate case or complaint proceeding," or "for an agreement of

the shipper to shift to a less desirable or underutilized receipt

point," or "to sign a longer contract, or to take an additional

volume," or when a shipper is captive only for a part of his

total load, or "to assist [an] industrial customer during times

of financial troubles in order to keep the facility viable," or "in

response to a perceived competitive threat from the proposed

construction of a new pipeline." Order No. 637-A at 31,633 &

n.218. Most of these appear to be cases that any shipper

aware of FERC's rule can readily avoid; this should be all

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affected shippers, as the rule applies only to contracts entered after its adoption.

Petitioners in fact offer us no reasons to believe that their

counter-examples are anything more than sporadic exceptions

to the general rule on which FERC relied. Generalizations

are not automatically rendered invalid by examples to the

contrary--the Commission is plainly entitled to respond with

a general solution to general findings of a systematic condition or problem, rather than proceed with a case-by-case

approach. AGD, 824 F.2d at 1008 (stating that when FERC

acts under its rulemaking authority to promulgate generic

rate criteria, it is not required to adduce "empirical data for

every proposition on which the selection depends"); TAPS,

225 F.3d at 687-88 (approving FERC's open access rules on

the basis of "general findings of systemic monopoly conditions

and the resulting potential for anti-competitive behavior, rather than evidence of monopoly and undue discrimination on the

part of individual utilities"). As petitioners have presented

no data on how widespread the occurrence of discounting

unrelated to market power is, they fail to undermine FERC's

conclusion that "generally [ ] discounts are given to obtain or

retain load that the pipeline could not transport at the

maximum rate because of competition." Order No. 637-A at

31,633 (emphasis added). Further, nothing they say suggests

that shippers on notice of the rule will be unable to avoid its

consequences and enjoy the right of first refusal--so long as

they are willing to pay the price.

As to FERC's second argument, relating to the balancing

of risk, petitioners say only that they can see no problem in a

pipeline being required to provide continuing service at maximum rates. Br. of Petitioners Opposing Limitations on the

Right of First Refusal at 11. But the Commission apparently

was persuaded by pipeline commenters, who asserted that the

prior regime "place[d] disproportionate risks on the pipelines

because the pipeline must bear the risk of standing ready to

serve the existing shipper indefinitely, while the shipper has

no such obligation." Order No. 637 at 31,336. This seems

clear to us: We see how the Commission could find imbalance

where one party, even though ready to commit itself to only a

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relatively short term (one year), thereby secures a perpetual

right to service. FERC clearly believed that limiting the

right of first refusal to maximum rate contracts was a fair

means of apportioning the risk, so that those customers who

place a premium on the assured continuity of service must

now pay for that protection by foregoing discounts, to which,

of course, they have no regulatory entitlement. Order No.

637-A at 31,634.

Petitioners finally object that a discounted or negotiated

rate is determined at the outset of the contract and thus has

no relationship to the market the long-term shipper faces at

its end. This seems to be beside the point. The risk that

market conditions would change always exists--the only issue

is how it should be divided. Under the new rules, any longterm shipper who wants the benefits of a right of first refusal

can secure them by simply choosing to take service under the

standard just and reasonable rates set by FERC. The same

goes for negotiated rates--all shippers are entitled to service

under the generally applicable maximum tariffs, and pipelines

cannot require captive customers to enter into negotiated rate

agreements. Order No. 637-B at 61,173. No captive shipper

is thus deprived of regulatory protection--all of them have

the entitlement to place themselves within the protected class

by simply paying agency-approved, cost-based rates. As

these are designed around existing levels of pipeline risk,

they presumably include something approximating the necessary premium for the long-term rights these customers prefer.

VI. Discount Adjustments

Standard FERC ratemaking, in its most simple form,

involves projecting a "revenue requirement" for service on

the pipeline's facilities and dividing the sum by projected

"throughput." The quotient is a maximum unit rate. Although both the revenue requirement and throughput are

largely based on past experience, both figures are projections.

Where it is expected that some service will be sold at a

discount from the maximum rate, there is obviously a problem with assuming that throughput--itself enhanced by disUSCA Case #00-1395 Document #669768 Filed: 04/05/2002 Page 51 of 62
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counts--will, when multiplied by the maximum rate, yield the

revenue requirement. FERC's solution to the problem has

been to make an offsetting downward adjustment in projected

throughput. Interstate Natural Gas Pipeline Rate Design, et

al., 47 FERC p 61,295 (1989) ("Policy Statement"), Order on

Rehearing, 48 FERC p 61,122 (1989) ("Policy Statement Rehearing"). In the rulemaking, and citing expert testimony in

other proceedings, various shipper interests headed by Illinois Municipal Gas Agency ("IMGA") attacked this policy. In

the end FERC elected to do nothing on the subject; though

not rejecting the petitioners' claims on the merits, it concluded that the issue was better left to another day. IMGA and

associated petitioners attack this decision not to act.

Apart from the simple arithmetic described above, the

theory underlying FERC's discount adjustment is as follows:

By selectively discounting its services (at least so long as

charging prices above marginal cost), a pipeline could increase actual throughput by attracting additional, non-captive

customers; as the fixed costs of service will be spread over

more units, captive customers themselves will benefit in the

end. See Policy Statement Rehearing at 61,449.

IMGA and kindred opponents of the policy see it in an

entirely different light. They argue that the demand for

pipeline service is largely inelastic in the aggregate; as a

result the rate discounts do not produce an overall increase in

throughput but merely shift it around among pipelines. This

is most plausible in the case of "gas-on-gas" competition,

which does not involve luring any end-users away from

competing fuels such as oil. The upshot is that the competitive customers enjoy a decrease in rates and, the captives,

instead of enjoying the supposed benefit, actually experience

higher rates as the aggregate contribution of the competitive

customers is reduced.

Over the last eight years, and despite the efforts of captive

customers such as those represented by IMGA, FERC has

declined to rule on the issue in any kind of a comprehensive

manner. Some of its conduct is suggestive of a shell game.

Thus, in resisting an IMGA petition for mandamus, see In re

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Illinois Municipal Gas Agency, No. 98-1347, 1998 WL

846667 (D.C. Cir. Nov. 24, 1998), FERC pointed to the fact

that in its then-ongoing rulemaking proceedings, which were

to eventually culminate in the order before us, the Commission was specifically considering whether it should change the

policy. See Notice of Inquiry, Regulation of Interstate Natural Gas Transportation Services, IV FERC Stats & Regs.

[Notices] (CCH) p 35,533 at 35,744 (July 29, 1998). But when

the order finally emerged, it contained no ruling on the

matter, except for yet another promise to consider the arguments sometime in the indefinite future. Order No. 637 at

31,267.

IMGA and others here petition on the ground that FERC's

continuation of the discount adjustment policy is unsupported

by substantial evidence. But this frames the issue imprecisely. The policy originates in past decisions; FERC did not

here decide to continue it, in the sense of confronting the

substance and making an affirmative decision; it decided only

that it would defer substantive treatment to a different--and

necessarily later--context. In essence, then, the claim is of a

violation of the APA's mandate that an agency decide matters

"within a reasonable time," 5 U.S.C. s 555(b), and calls on us

to "compel agency action unlawfully withheld or unreasonably

delayed," id. at s 706(1). Our review is highly deferential.

See, e.g., In re Barr Laboratories, 930 F.2d 72, 74 (D.C. Cir.

1991).

The case is anomalous among wrongful delay cases in that

every ratemaking where the policy is applied presents an

opportunity for challenge and lawsuit by a party aggrieved by

its continuation--parties whose name is legion if petitioners

are correct. In fact, since 1993, the discounting practice has

been challenged on at least four separate occasions. See,

e.g., Southern Natural Gas, 65 FERC p 61,347 at 62,830

(1993); order on reh'g, 65 FERC p 61,348 at 62,843 (1993);

Regulation of Negotiated Transp. Svs. of Natural Gas Pipelines, 74 FERC p 61,076 (1996), clarified, 74 FERC p 61,194

(1996); Tennessee Gas Pipeline Co., 76 FERC p 61,224

(1996), modified, 77 FERC p 61,215 (1996), reh'g denied, 81

FERC p 61,207 (1997); Panhandle Eastern Pipeline Co., 78

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FERC p 61,011 (1997), reh'g denied, 81 FERC p 61,234 at

61,973 (1997). In none of these cases, however, did aggrieved

parties seek judicial review of the policy's continued application.

An agency undoubtedly enjoys broad discretion to determine its own procedures, Mobil Oil Exploration & Producing

Southeast, Inc., v. United Distrib. Cos., 498 U.S. 211, 230

(1991), including whether to act by a generic rulemaking or

by case-by-case adjudication, NLRB v. Bell Aerospace Co.,

416 U.S. 267, 293 (1974). But here FERC's arguments in

justification of deferring the issue make reliance on individual

pipeline ratemaking inappropriate--except perhaps as a palliative. Indeed, the Commission itself stressed some points

strongly suggesting the advantage of treating the issue in a

generic rulemaking format.

First, the Commission pointed out, Order No. 637 itself

comprised a policy statement inviting pipelines to institute

differentiated peak/off-peak rates. Order No. 637 at 31,263,

31,264, 31,288. Not only would such differentiated rates tend

to optimize the allocation of pipeline capacity, id. at 31,288,

but they would "reduc[e] the need to make discount adjustments," id. By its own terms, however, this point is only a

partial answer. On this issue Order No. 637 is only a policy

statement, see Part VII, infra, and does not immediately

introduce any seasonally differentiated rates. And even the

Commission sees seasonal differentiation only as "reducing,"

not extinguishing, the practice of discounted rates.

Second, the Commission explicitly treated the discount

adjustment problem as linked to a host of other issues, to be

examined together,

including the use of negotiated terms and conditions of

service, changes to SFV [straight fixed variable] rate

design, whether to permit discount adjustments, whether

to adopt rate reviews or refreshers, and whether to

permit more market-based rates.

Id. at 31,267. Though obviously comprehensive policymaking is to be desired--it is one of the supposed benefits of

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delegations to such an agency as FERC--the Commission

risks letting the best be the enemy of the good. If the

consequences of the discount adjustment are as drastic as

petitioners claim, involving a tilt of billions of dollars of costs,

see IMGA Br. at 15, then endless deferral of substantive

consideration is hard to justify. This is especially true where

the customer class burdened by the tilt--the captives--is

exactly the class that is the primary intended beneficiary of

the regulatory system. See UDC, 88 F.3d at 1123.

On top of FERC's own stress on the case for comprehensive treatment, there are other points against sloughing the

issue off to individual ratemakings. Such proceedings could

well lead to inequities as a result of competition between

pipelines denied the adjustment and ones still able to practice

it. Although FERC could conceivably adopt some mechanism

to handle such effects (such as, for example, starting s 5

proceedings against pipelines competing with one denied the

right to adjust), this appears at best awkward, leaving comprehensive treatment markedly superior.

In the end, however, we must deny the petition. The

Commission's reasons for treating the issue in a new rulemaking with closely related issues are sound, even though

tarnished a bit by the extensive prior delay. And the availability of individual ratemakings as a venue, though markedly

inferior, is nonetheless a kind of safety valve. As time drags

on, however, Commission failure to address the issue on the

merits will virtually set it up for a successful claim for undue

delay under Telecommunications Research & Action Center

v. FCC & United States, 750 F.2d 70 (D.C. Cir. 1984).

VII. Peak/Off-Peak Rates

In Order No. 637 FERC announced that it would permit

pipelines to charge seasonally variable rates for short-term

transportation service instead of the previously required uniform tariffs based on the average cost of providing service.

Order No. 637 at 31,287. Demand for natural gas is strongest in the winter heating season, and the Commission thought

that allowing prices to better reflect the differing peak and

off-peak values of capacity would promote allocative efficiency

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and reduce the need for discounts. Id. at 31,287-88; Order

No. 637-A at 31,574. But it didn't commit itself to any one

formula for these variations, leaving it instead up to individual

pipelines to propose methods, either in general s 4 rate cases

or in limited, pro forma tariff filings. Order No. 637 at

31,290. Further, pipelines taking the latter route--where

FERC's inquiry will be limited in scope to the question of

whether the proposed peak/off-peak methodology (as opposed

to the rates themselves) is just and reasonable, Order No.

637-A at 31,578--were requested to include in their proposals

a mechanism for sharing any resulting extra revenues with

their long-term customers on a basis of at least equality. Id.

at 31,292. The Commission also directed such pipelines to

file a cost and revenue study within fifteen months of implementing a peak/off-peak regime, so as to enable the Commission to determine if further rate adjustments are necessary.

Id.

A group of petitioners headed by Exxon Mobil Corporation

(collectively, "Exxon") now fault both the authorization of

limited s 4 proceedings and the revenue-crediting mechanism

as failing to comply with the APA's notice and comment

requirements. In addition, Exxon contends that (a) limited

s 4 proceedings fail to satisfy FERC's obligation under the

NGA to ensure that the actual pipeline rates (and not only

the methodology used for deriving them) are just and reasonable; and (b) the exclusion of short-term shippers from the

revenue-sharing arrangement is arbitrary and capricious.

FERC contends that its entire discussion of seasonal rates

here represents only a policy statement and therefore is

neither binding on any party nor ripe for judicial review. We

agree.

There is a "strong norm" against our reviewing "tentative

agency positions," American Gas Ass'n v. FERC, 888 F.2d

136, 151-52 (D.C. Cir. 1989), of which, of course, a policy

statement is a prime example. In the orders under review,

FERC explicitly casts the discussion of the peak/off-peak

rates option as a policy statement rather than as "a rule that

imposes any requirements on pipelines or changes current

Commission regulations." Order No. 637 at 31,289; see also

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Order No. 637-A at 31,576. Exxon disputes this characterization, saying that insofar as Order No. 637 establishes

specific procedures that pipelines must follow in implementing the rates, it is really a substantive rule. We think that

the Commission has the better argument.

The distinction between substantive rule and policy statement is said to turn largely on whether the agency position is

one of "present binding effect," i.e., whether it "constrains the

agency's discretion." McLouth Steel Products Corp. v.

Thomas, 838 F.2d 1317, 1320 (D.C. Cir. 1988); see also

Community Nutrition Institute v. Young, 818 F.2d 943, 946

& n.4 (D.C. Cir. 1987). The agency's characterization, and its

actual past applications of its statement (if any), are the key

factors. McLouth, 838 F.2d at 1320; Community Nutrition,

818 F.2d at 946.

Here the Commission has contemporaneously characterized the policy as not encompassing an intent to issue any

substantive rules on limitations on s 4 proceedings or on

revenue-sharing schemes. Cf. Molycorp, Inc. v. EPA, 197

F.3d 543, 546 (D.C. Cir. 1999) (focusing on whether agency

intends to bind itself). Such a characterization comes at a

price to the Commission; in applying the policy, it will not be

able simply to stand on its duty to follow its rules. Compare

American Mining Congress v. Mine Safety & Health Admin., 995 F.2d 1106, 1111 (D.C. Cir. 1993) (explaining that if

the agency succeeds in labeling a rule interpretive and thus

shielded from judicial review at the outset, the rule will

remain open to full scrutiny when agency action implementing

the rule is challenged), with Grid Radio v. FCC, 278 F.3d

1314, 1320 (D.C. Cir. 2002) (stating that an agency "need not

reevaluate well-worn policy arguments each time it implements an existing [formal] rule in a narrow adjudicatory

proceeding"). And if there have so far been any applications

of the Commission's policy, neither side has seen fit to bring

it to our attention. So there is no basis here for any claim

that the Commission has actually treated the policy with the

de facto inflexibility of a binding norm. Compare McLouth,

838 F.2d at 1321.

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To be sure, Exxon correctly argues that the effect of a

nominal "policy" disclaimer can still be negated under

McLouth when an agency appears to undermine its professed

flexibility by using imperative language--words such as "will"

or "must." Exxon Br. at 7 (citing McLouth, 838 F.2d at

1320-21). To this effect, Exxon contends that FERC's decision to allow pro forma tariff filing and its requirement for

pipelines to share excess revenues in a certain way ("the

pipeline must include in its proposal a revenue sharing mechanism," Order No. 637 at 31,292 (emphasis added)) do not

meet the criteria for a policy statement. Id. But given the

Commission's broad discretion to direct the conduct of its

proceedings, Vermont Yankee Nuclear Power Corp. v. Natural Resources Defense Council, Inc., 435 U.S. 519, 524-25, 543

(1978), and its insistent characterization of the statement as

mere policy, we reject the suggestion that these expressions

establish a meaningful "right" for a pipeline to secure approval of variable rate proposals in limited s 4 proceedings. See

also Order No. 637-A at 31,576 (emphasizing Commission

discretion over the conduct of its proceedings). Likewise,

insistence that pipelines submit particular types of revenuesharing proposals doesn't give anyone a "right" to additional

revenues, id. at 31,575; the Commission, obviously, is entitled

to request from the applicants any information it thinks may

be helpful in deciding on their applications. We thus agree

with the Commission that its discussion of pro forma filings

and revenue-sharing proposals was meant to merely give

"guidance and direction [to pipelines] on how peak/off-peak

rates could be implemented in the individual cases." Id. at

31,575.

Apart from the implications of classifying the statement as

merely one of policy, general concepts militate against viewing petitioners' claims as ripe. Following Toilet Goods Ass'n

v. Gardner, 387 U.S. 158, 164 (1967), we have often postponed

review for want of ripeness where "(1) delay would permit

better review of the issues while (2) causing no significant

hardship to the parties." Northern Indiana Public Service

Co. v. FERC, 954 F.2d 736, 738 (D.C. Cir. 1992). Both of

these criteria favor postponing review.

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Because the Commission adopted no particular method of

setting peak/off-peak rates but "left the details of the implementation" to be worked out in individual pipeline proceedings, Order No. 637-A at 31,574, we have no record on which

to evaluate the nature--or indeed the existence--of Exxon's

conceivable injury. See Tennessee Gas Pipeline Co. v.

FERC, 972 F.2d 376, 382 (D.C. Cir. 1992) ("Whether any ...

pipeline serving the petitioner will actually file the tariffs

necessary to participate in this program, or assuming one

does, the nature of any injury that the petitioner may in fact

suffer, remains to be seen."); cf. American Gas Ass'n, 888

F.2d at 152.

Nor does Exxon even try to show how continued uncertainty over the legality of the Commission's policy would harm it

or affect its day-to-day primary activities. Unless and until a

particular pipeline chooses to implement peak/off-peak rates,

and gets Commission approval, Exxon faces no actual or

imminent injury. With this in mind, Exxon's reliance on

ANR Pipeline Co. v. FERC, 771 F.2d 507 (D.C. Cir. 1985),

Exxon Repl. Br. at 4-5, is misplaced. Quite apart from the

fact that the court addressed only a concern about standing, it

was certain that the carrier would file the rate increase that

was implied by the contested order's methodological change.

ANR, 771 F.2d at 516. And whereas in ANR the court

thought that the petitioner will "likely be bound by the

Commission's order in any subsequent filing," id., here

FERC's disclaimer of a "substantive rule" status of the

challenged provisions means that neither the agency nor

Exxon will be bound by them in any future proceedings.

This court will remain free to re-examine FERC's policies "in

another context if and when [Exxon's] claims become justiciable." Shell Oil Co. v. FERC, 47 F.3d 1186, 1202 n.32 (D.C.

Cir. 1995).

Accordingly, Exxon's claims are unripe and its petition is

dismissed.

VIII. Limitations on Pre-Arranged Releases

Under the capacity-release regime initiated by Order No.

636, see Section I, supra, firm customers releasing short-term

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capacity were generally required to auction it off to the

highest bidder by posting the terms and conditions of such

releases on pipeline electronic bulletin boards. Order No. 636

at 30,418-21; see generally 18 C.F.R. s 284.8(c)-(e) (describing posting and bidding requirements). FERC permitted an

exemption for so-called pre-arranged deals, however, allowing

firm transportation customers to release capacity rights to a

specific, pre-selected short-term shipper of their choice without prior posting and bidding, so long as the release was

made at the maximum applicable tariff rate. 18 C.F.R.

s 284.8(h). Given a pre-arranged sale at the ceiling rate,

bidding and posting would have been largely an exercise in

futility.

But with the elimination of the price ceiling for short-term

capacity releases in Order No. 637, the general case for such

an exemption was undermined. Order No. 637-A at 31,568-

69. The Commission believed that once a market price was

permissible and the ceiling rates moot, posting and bidding

was as necessary for maximum-price releases as for any

others: to "protect against undue discrimination and to ensure that capacity is properly allocated" to the shipper for

which it was most valuable. Id. at 31,569.

Although abolishing the exemption, FERC provided a waiver procedure, primarily in the interest of a special class of

capacity releasers. The former exemption for releases at the

ceiling rate had been heavily relied upon by local distribution

companies ("LDCs") in states that sought to carry the unbundling process all the way down to the retail level. The idea of

such programs has been to enable residential and small

commercial customers, who had been traditionally served by

LDCs making gas sales bundled with transportation, instead

to secure gas through new competitive marketers, typically

relying on the LDCs for transportation. Order No. 637 at

31,250, 31,261. To this end, these states have encouraged or

required their LDCs to pre-arrange releases of portions of

their firm transportation rights to the independent marketers

at the pipeline's maximum rates. See Request of Keyspan

Gas East Corp. and the Brooklyn Union Gas Co. for Rehearing and/or Clarification at 25; Order No. 637 at 31,261.

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So that such transactions might persist, the Commission

provided that LDCs might seek Commission consent for

making releases at the maximum rate that would have been

applicable absent FERC's present experimental policy. But

to avail itself of such a waiver procedure, FERC said, the

applicant "must be prepared to have all of its capacity release

transactions ... limited to the applicable maximum rate."

Id. at 31,569 (emphasis added).

The petitioners here appear to seek a blanket exemption

from bidding and posting for "maximum-price" releases prearranged under "state choice" plans. Their basic argument is

that the ultimate end-users under such transactions are the

same core, captive users for whom the LDC originally acquired the capacity under a long-term contract. They do not

believe that states should be put to a choice of foregoing the

benefits of retail unbundling, or, alternatively, of exposing

such core end-users to the risk of having to pay a transportation rate higher than the prior legal maximum, presumably

the one provided under the contract originally entered into

for their benefit. Short of a blanket exemption, they seek a

broadening of FERC's conditions for waiver.

We cannot find the refusal of a blanket exemption arbitrary

or capricious. At most petitioners have shown that the

absence of such an exemption may undermine some state

regulatory efforts. At the time Order No. 637 was adopted,

11 states evidently had unbundling programs, with another

nine and the District of Columbia experimenting with pilot

programs. Order No. 637 at 31,261. Absent a showing that

these programs are so structured as largely to moot FERC's

concern with potential discrimination, or that the achievements of these programs are enough to offset whatever such

risk may remain, FERC's caution appears reasonable.

But we agree with petitioners that FERC has failed to

support its rule conditioning any waiver on the applicant's

being "prepared to have all of its capacity release transactions ... limited to the applicable maximum rate." Order

No. 637-A at 31,569 (emphasis added). FERC imposed the

condition to be sure that an LDC exempted from the posting

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and bidding rules could not "protect[ ] other favored shippers

from the bidding process." Id. But the Commission's brief

writers recognize that the Commission failed to make a case

for insistence that the LDC commit to making all releases at

the maximum rate. The Commission's requirements of state

regulatory endorsement of the plan seems to give FERC an

avenue by which to verify that those authorities have addressed the discrimination risk, so much so that in its brief

here, FERC, rather than truly defending its insistence on the

releasing LDC's commitment to do "all" releases at the

maximum rate, instead argues that the language " 'must be

prepared to accept' ... differs greatly from mandatory language such as, 'must accept.' " FERC Br. at 75. Accordingly, we reverse and remand for the Commission to review the

matter and reframe the waiver conditions in terms that more

aptly capture an intent apparently less Procrustean than what

it expressed.

* * *

The petitions for review are denied except as noted above.

So ordered.

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