                  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.

                                        