allowing the Commission to issue "general, prospective, and conditional" abandonment approvals under s 7(b)
How later courts described this case
- allowing the Commission to issue "general, prospective, and conditional" abandonment approvals under s 7(b)
- abroga- tion permitted "only in circumstances of unequivocal public necessity"
- 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"
- standing where plaintiff "will have to take significant and costly compliance measures or risk criminal prosecution"
Written by the judges who cited it.
The opinion
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,
---------
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. Rem-
menga, 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. Hell-
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., Bar-
bara 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 Com-
mission, 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.
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. Alex-
ander, 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 Segmen-
tation 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., Kir-
stin 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 short-
term pipeline releases 16
II. Segmentation 18
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 Reg-
ulation of Interstate Natural Gas Transportation Services,
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 Trans-
portation Services And Regulation of Interstate Natural Gas
Transportation Services, FERC Stats. & Regs. [Reg. Pream-
bles 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 Reg-
ulation 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 five-
year cap on the mandatory right of first refusal and in part
with respect to the limitations on pre-arranged releases (is-
sues 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
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 pipe-
line capacity by shippers with long-term rights to that capaci-
ty. Order No. 637 at 31,263. At the same time the order
retained the ceilings for similar sales by the pipelines them-
selves. 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 undis-
puted 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 pipe-
line services, the Commission recognized that a significant
percentage of pipeline capacity reserved for "firm" service
often went unused. Order No. 636, Pipeline Service Obli-
gations and Revisions to Regulations Governing Self-Imple-
menting 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");
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-of-
service 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 ceil-
ings probably worked against the shippers they were de-
signed 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 trans-
portation 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 capaci-
ty. 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 prem-
ise 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
mandate, to choose a regime more "lighthanded" than tradi-
tional cost-based regulation.
Here of course the two-year waiver is explicitly experimen-
tal. 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 com-
petitive 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 intend-
ed 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 escarp-
ment 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 gener-
al 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
... the goals and purposes of the statute will be accom-
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 nor-
mally provides a reasonable assurance that rates will approxi-
mate cost, at least over the long pull, Elizabethtown Gas Co.,
10 F.3d at 870, Exxon argues that the Commission's experi-
ment 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 ca-
pacity 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 trans-
portation 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 path-
way 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
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
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 capaci-
ty resellers might exploit or extend such market power as
they may possess--price discrimination and deliberate with-
holding 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 ship-
pers, 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 Commis-
sion concluded that it would provide an adequate substitute,
whose availability would place a meaningful check on whatev-
er anti-competitive tendencies the resellers might have. See
Order No. 637-A at 31,565. And because the pipelines con-
tinue 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
the waiver policy would significantly change the firm ship-
pers' 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 num-
ber of advantages of lifting the ceilings on short-term capaci-
ty 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 trans-
portation 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 hold-
ers"). 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
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 ca-
pacity 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 in-
tegrity 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 eco-
nomic 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 ubiqui-
tous and might justify any deregulation of any rates mandat-
ed 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.
3. Oversight. As to monitoring and assurance of reme-
dies in the event of insufficient competition, on which Farm-
ers Union set great store, see 734 F.2d at 1509, the Commis-
sion identifies three safeguards.
First, release prices and availability must be publicly re-
ported in compliance with FERC's current posting and bid-
ding requirements. This will increase the information avail-
able 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 for-
ward-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 competi-
tion 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.
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 unrea-
sonable discrimination or some other kind of arbitrariness.
In fact the Commission's distinction is not unreasonable.
Despite the absence of Herfindahl-Hirschman indices for non-
pipeline capacity holders, there seems every reason to sup-
pose that their ownership of such capacity (in any given
market) is not so concentrated as that of the pipelines them-
selves--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 capaci-
ty, while shippers hold the remaining 93%. This is classic
apples and oranges. The Commission points out that where-
as 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
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 Commis-
sion'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 sce-
nario)--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 price-
controlled 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 Reg-
ulatory Options for Dealing with Natural Gas Wellhead
Price Deregulation 40-51 (1983).
This is surely a potential price of gradualism. But distor-
tions of this sort seem likely in any such compromise, and
compromise--going one step at a time--is within the Com-
mission's purview so long as it rests on reasonable distinc-
tions. 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 capaci-
ty 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 regula-
tions 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 imple-
mented 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
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 segmen-
tation 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 seg-
mentation 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 unreason-
able, 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 reason-
able 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; Wis-
consin Gas Co. v. FERC, 770 F.2d 1144, 1166 & n.36 (D.C.
Cir. 1985). Here, the Commission has made a "generic
determination" that a pipeline's refusal to permit segmenta-
tion where it could "operationally" do so would be unjust and
unreasonable. Order No. 637-A at 31,590. And the Commis-
sion explained that it was not making a s 5 determination
that any particular pipeline's tariff was unjust or unreason-
able, 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 Com-
mission 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 identi-
fied 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 limit-
ed segment of the industry was affected by the problem it
sought to address, while the remedy adopted would necessari-
ly impact other segments).
Here the Commission could reasonably consider the reme-
dy proportional to the identified problem: it requires segmen-
tation only where it is operationally feasible, since in that
situation, the Commission found, the failure to permit seg-
mentation 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.
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 Commis-
sion 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 ca-
pacity 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 compa-
ny 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 opportuni-
ty to demonstrate that their own circumstances justify devia-
tion from the general conclusion that segmentation is appro-
priate," 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
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 informa-
tion 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 contrac-
tual 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
Commission's view, segmentation must be coupled with flexi-
ble point rights in order to create effective competition be-
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 seg-
ment 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 pipe-
lines automatically grant shippers primary treatment at mul-
tiple 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 Permi-
an Basin Area Rate Cases, 390 U.S. 747, 822 (1968) (abroga-
tion 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;
thus, it presumably governs the currently applicable con-
tracts. In the Order No. 636 restructuring proceedings, the
Commission generally permitted more than one approach by
pipelines to granting shippers flexible point rights, but ob-
served 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 pipe-
lines 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 ship-
per'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 applica-
tion of the operational feasibility principle, and this typically
led to tariff rules broadly protecting releasing and replace-
ment shippers' interest in points along their respective seg-
ments. 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 simulta-
neously reserves primary points on the released segment
up to its capacity on that segment.
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 for-
wardhaul 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 ship-
ment 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
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 backwar-
dhaul 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 self-
evident: The number of angels that can stand on the head of
one pin seems physically (rather than metaphysically) differ-
ent from the question how many can stand on two. Although
the Commission observed that the pipelines seeking rehear-
ing 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
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 Commis-
sion's decision that segmentation be permitted at "any trans-
action points on the pipeline system, including virtual transac-
tion 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 over-
lapping 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 mak-
ing 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 appropriate-
ly 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 main-
line capacity. Oddly, the Commission's brief writers seem to
have adopted a rather in-your-face approach, declaring flatly
that "[t]his type of segmentation does not result in the
overlap of capacity and Petitioners have not explained other-
wise." 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 sys-
tem. 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 substi-
tution 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 operation-
al 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," Or-
der No. 637 at 31,304, and must "optimize [their] system[s] to
provide maximum segmentation rights while devising appro-
priate mechanisms to ensure operational stability," Order No.
637-A at 31,591, a duty that may include "allowing segmenta-
tion on straight-line [non-reticulated] portions of the pipe-
line," 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
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 quota-
tion marks omitted).
The same unripeness applies to INGAA's claims regarding
a special class of reticulated pipelines, those employing "post-
age 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 continu-
ing 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
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 overween-
ing 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, pipe-
lines 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 contra-
dict the prior view. For example, the Commission said that
"within the path" of a shipper's contract, it "should be permit-
ted to ... segment capacity along that [discounted] capacity
path without incurring additional charges," i.e., without hav-
ing 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
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 pipe-
line'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 high-
elasticity 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 compe-
tition-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.
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 capaci-
ty allocation during constrained periods was the pro rata
method. Shippers whose primary delivery points were locat-
ed 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 avail-
able, 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
within their capacity path--that is, the shippers whose pri-
mary delivery points are downstream of the point at which
secondary rights are sought--receive preference over ship-
pers 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, "En-
ron") 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 show-
ing 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 jurisdic-
tion of federal courts must satisfy Article III's requirements
of constitutional standing. "Common to both of these thresh-
olds is the requirement that petitioners establish, at a mini-
mum, '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 compe-
tition in the supply of capacity by decreasing the number of
possible suppliers. The reduced competition would cause
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 capaci-
ty 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 effec-
tive competitor to the primary rights holder as a seller of
secondary rights. Id. By comparison, under the within-the-
path 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 actual-
ly improve competition. Id.
We need not pass on the ultimate merits of the Commis-
sion's reasoning to say that Enron's contrary theory fails to
show the requisite probability of harm. Basically, the show-
ing is far too conjectural to establish "a substantial (if un-
quantifiable) 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."
Enron Repl. Br. at 3. While compliance costs often consti-
tute an injury-in-fact, Enron's argument here rests solely on
a conclusory, vague and unsupported assertion of cost in-
creases. 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 compli-
ance). 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 entitle-
ments (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 sys-
tem 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 appro-
priate penalties, that is, charges that "reflect[ed] more than
simply the costs incurred as a result of the [shipper's] con-
duct," 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 transpor-
tation 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
FERC said, "This requirement may result in either no penal-
ties for non-critical days [days when the pipeline is not
expected to operate at or near full capacity] or higher toler-
ances 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., tem-
porary 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 al-
lowed 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 initi-
ated 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 reve-
nues 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 re-
quirements 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,
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 penal-
ties, 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 exces-
sive 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 re-
gime 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
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 judg-
ment.
We are not altogether clear why the Commission's re-
sponse to excess penalties was to bar all penalties not direct-
ed to threats to reliability, and otherwise to switch to "car-
rots." 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 cir-
cumstances posing no threat to reliability.
In fact, the Commission's limits on penalties (as they are
understood in this regulatory regime) appear to leave poten-
tial 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
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 inter-
ruptible 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 pur-
chasing 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
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 Commis-
sion'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 Commis-
sion's hope and expectation of a flourishing market in balanc-
ing-related services may prove unwarranted does not under-
mine 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 pipe-
lines 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 im-
posed no such refunding mechanism, were unjust and unrea-
sonable; and (2) the Commission justified the refund require-
ment "as an incentive for pipelines not to impose penalties,"
whereas pipelines should actually be given incentives to im-
pose the penalties allowed by the new rule, as they necessari-
ly apply only when shipper conduct threatens system reliabili-
ty.
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 mis-
conceives its purpose. FERC's goal here was not to discour-
age 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. Requir-
ing 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 self-
executable. 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. Be-
sides, as the Commission explained, its decision on this point
is entirely consistent with its current general policy of allow-
ing pipelines to retain revenues from "a new service initiated
between rate cases." Id. at 31,310.
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 ship-
pers, 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 overre-
covery 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 neces-
sity permit such abandonment." 15 U.S.C. s 717f(b). Seek-
ing to streamline the regulatory process, the Commission in
Order No. 436 attempted to dispense with these individual-
ized 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
(D.C. Cir. 1990) ("AGA"). Under this mechanism, the Com-
mission 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 com-
peting 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 aban-
donment 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
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--involv-
ing the construction of new facilities--was properly represen-
tative. Id. at 1141. But because the selection of any dura-
tion 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 Obli-
gations and Revisions to Regulations Governing Self-Imple-
menting 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 five-
year 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
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 (collec-
tively "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 mar-
ket 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 dura-
tions 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 con-
cerns about the practical effects of the five year term match-
ing 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 concern-
ing 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 five-
year 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
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 pre-
sented 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, vis-
A-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 acknowl-
edgment 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. Pipe-
line 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
Commission in that order transformed its requirement of a
right of first refusal, ensconced in the Commission's regula-
tions 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 provi-
sions. The first declares that eligible shippers have "the
right of first refusal as provided in the Commission's regula-
tions," Order No. 637 at 31,341, and the second expressly says
that the regulatory right of first refusal is effective "regard-
less 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 contin-
ued 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 reason-
able"), 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 self-
executing, 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
to explain its current position, and, to the extent that lan-
guage 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 de-
gree of protection offered by right of first refusal by decreas-
ing 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 mo-
nopoly 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 evi-
denced 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 cre-
ates 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 in-
vestment risk, see id. at 31,336, the Commission also thought
that limiting the right of first refusal to those shippers paying
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 paral-
leling 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
affected shippers, as the rule applies only to contracts en-
tered 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 condi-
tion 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, rath-
er 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 maxi-
mum 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
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 long-
term 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 neces-
sary premium for the long-term rights these customers pre-
fer.
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. Al-
though 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 prob-
lem with assuming that throughput--itself enhanced by dis-
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 Re-
hearing"). In the rulemaking, and citing expert testimony in
other proceedings, various shipper interests headed by Illi-
nois 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 conclud-
ed 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 in-
crease 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 competi-
tive 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
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 Commis-
sion was specifically considering whether it should change the
policy. See Notice of Inquiry, Regulation of Interstate Natu-
ral 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 argu-
ments 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 imprecise-
ly. 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 Pipe-
lines, 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
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 applica-
tion.
An agency undoubtedly enjoys broad discretion to deter-
mine 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 palli-
ative. 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 adjust-
ments," 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 policy-
making is to be desired--it is one of the supposed benefits of
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 comprehen-
sive 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 com-
prehensive treatment markedly superior.
In the end, however, we must deny the petition. The
Commission's reasons for treating the issue in a new rule-
making with closely related issues are sound, even though
tarnished a bit by the extensive prior delay. And the avail-
ability 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 uni-
form tariffs based on the average cost of providing service.
Order No. 637 at 31,287. Demand for natural gas is strong-
est 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
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 imple-
menting a peak/off-peak regime, so as to enable the Commis-
sion 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 reason-
able; 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
Order No. 637-A at 31,576. Exxon disputes this character-
ization, saying that insofar as Order No. 637 establishes
specific procedures that pipelines must follow in implement-
ing the rates, it is really a substantive rule. We think that
the Commission has the better argument.
The distinction between substantive rule and policy state-
ment 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 character-
ized 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 Ad-
min., 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 imple-
ments 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.
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 deci-
sion 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 mech-
anism," 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. Natu-
ral 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 approv-
al 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 revenue-
sharing 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 view-
ing 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.
Because the Commission adopted no particular method of
setting peak/off-peak rates but "left the details of the imple-
mentation" to be worked out in individual pipeline proceed-
ings, 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 uncertain-
ty 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 justicia-
ble." 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
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) (describ-
ing 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 with-
out 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 en-
sure 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 waiv-
er 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 unbun-
dling 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 Rehear-
ing and/or Clarification at 25; Order No. 637 at 31,261.
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 pre-
arranged 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 ac-
quired 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 transporta-
tion 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 achieve-
ments 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 transac-
tions ... 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
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 ad-
dressed 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 lan-
guage such as, 'must accept.' " FERC Br. at 75. According-
ly, 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.