Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-02-01125/USCOURTS-caDC-02-01125-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
Orion Power New York GP, Inc.
Petitioner

Document Text:

Notice: This opinion is subject to formal revision before publication in the

Federal Reporter or U.S.App.D.C. Reports. Users are requested to notify

the Clerk of any formal errors in order that corrections may be made

before the bound volumes go to press.

United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued October 7, 2003 Decided November 18, 2003

No. 02-1115

KEYSPAN–RAVENSWOOD, LLC,

PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

CONSOLIDATED EDISON COMPANY OF NEW YORK, INC., ET AL.,

INTERVENORS

Consolidated with

Nos. 02-1125, 02-1150

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

Elaine M. Walsh argued the cause for petitioners. With

her on the briefs were Kenneth M. Simon, M. Eric Eversole,

Mitchell F. Hertz, and Ashley C. Parrish.

 Bills of costs must be filed within 14 days after entry of judgment.

The court looks with disfavor upon motions to file bills of costs out

of time.

USCA Case #02-1125 Document #785554 Filed: 11/18/2003 Page 1 of 13
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Robert H. Solomon, Deputy Solicitor, Federal Energy Regulatory Commission, argued the cause for respondent. On

the brief were Cynthia A. Marlette, General Counsel, Dennis

Lane, Solicitor, and Timm L. Abendroth, Attorney.

Neil H. Butterklee argued the cause and filed the brief for

intervenor Consolidated Edison Company of New York, Inc.

Lawrence G. Malone and Michelle L. Phillips were on the

brief for intervenor Public Service Commission of the State of

New York. Jonathan D. Feinberg entered an appearance.

Before: SENTELLE, RANDOLPH and ROGERS, Circuit Judges.

Opinion for the Court filed by Circuit Judge ROGERS.

ROGERS, Circuit Judge: These consolidated petitions challenge the manner in which the Federal Energy Regulatory

Commission calculated a price cap for the New York City

electric capacity market when it authorized the New York

Independent System Operator (‘‘NYISO’’) to change its pricing methodology. The NYISO was allowed to account for

forced outages by measuring the amount of electric generating capacity available for sale to the system (‘‘UCAP’’) rather

than installed generation capacity (‘‘ICAP’’), and the Commission adjusted the price cap to yield approximately the same

revenues from affected sales at the time of conversion to the

new methodology. At issue is the Commission’s determination that, in shifting to the new methodology, the most recent

twelve months constitute the appropriate period to estimate a

generating unit’s availability for the purpose of recalculating

the price cap. KeySpan–Ravenswood, LLC and Orion Power

New York GP, Inc., both electricity suppliers affected by the

price cap, petition for review of three orders in which the

Commission rejected their position that a longer period of

time was required. We find the Commission did not adequately explain its decision. We therefore grant the petition.

USCA Case #02-1125 Document #785554 Filed: 11/18/2003 Page 2 of 13
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I.

The Commission has capped prices in the New York City

capacity market since 1998, when Consolidated Edison sold

generators serving the city to private energy suppliers, see

Consolidated Edison Company of New York, Inc., 84 FERC

¶ 61,287 (1998). In 2001, the NYISO filed a request to amend

its service tariff so that it could implement a market design

based on a shift in its methodology for measuring electric

generator capacity, see 16 USC § 824d (2003), 18 C.F.R.

§ 35.13 (2003), and requested that the Commission determine

the appropriate translation of the price cap in light of the new

methodology. The proposed translation of the price cap was

to reflect the shift from measuring capacity on the basis of

installed capacity (‘‘ICAP’’) to unforced capacity (‘‘UCAP’’).

The ICAP methodology calculates the amount of capacity a

supplier can sell based on the ideal performance of its generators, whereas the UCAP methodology accounts for the probability that a generating unit will be called upon to produce

energy but will be unable to do so because of ‘‘forced outages,’’ i.e., unforeseen circumstances resulting in a generating

unit’s production of less than maximum net capacity. UCAP

thus requires predicting how often generators will be forced

out of service. The parties agree that, for the purpose of

determining UCAP available for sale, a 12-month rolling

average is appropriate. However, they disagree about what

period the Commission should use to determine UCAP for

the purpose of translating the price cap, which is fixed and

cannot be adjusted as outage rates fluctuate. The relevant

generators in New York City had performed far better in the

immediately preceding two years than in the years before

that, so a 1-year or 2-year history would predict an ‘‘equivalent forced outage rate’’ of 6.92% or 6.59%, respectively,

whereas a 3-year history suggested a much higher rate of

12.58%.

The Commission published notice of the NYISO tariff

filing, see New York Independent System Operator, Inc.;

Notice of Filing, 66 Fed. Reg. 37,663 (July 19, 2001), and

received comment on the appropriate way to translate the

price cap. The higher the predicted forced outage rate, the

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higher the price cap necessary to offset the corresponding

drop in available capacity from ICAP to UCAP. Electricity

retailers (as well as the City) wanted the more current forced

outage data to be used, because that would result in a lower

price cap, and lower costs to consumers. Petitioners called

upon the Commission to look at a longer period of data

preceding their acquisition of the relevant generators, which

would have resulted in a higher cap, arguing that they should

be allowed to reap the benefits of reliability investments they

had made, and that the maintenance cycles of generators

necessitate use of a multi-year average to smooth out anomalies. Each charged that translating the price cap using the

other’s methodology would result in a windfall to the other.

In the first order on review, the Commission authorized the

NYISO to change its methodology for measuring available

electric capacity to UCAP, and determined to use only the

past twelve months of data as a predictor of future outage

rates. Order Accepting Tariff Revisions and Directing

Translation of the In–City Price Cap (‘‘Order’’), 96 FERC

¶ 61,251 (2001). The Commission explained that the purpose

of the order was simply to translate the price cap, not to

change it, that the ‘‘translation TTT must be revenue neutral,’’

and that any arguments about changing the effective price

cap were ‘‘beyond the scope of this proceeding.’’ Id. at

61,994. The New York Commission had urged use of only

twelve months of forced outage data to ensure that ‘‘suppliers

do not derive financial benefits solely as a result of a change

of methodology.’’ Id. at 61,992. In its Order, the Commission rejected use of outage data from the period prior to the

divestiture, which would have resulted in a $126.14/kW-year

price cap, as compared to the pre-translation cap of $105/kWyear, stating that the translation ‘‘must be based on operating

data from the most recent 12 months, as they reflect a more

current outage rate.’’ Id. at 61,994. The Commission rejected petitioners’ argument that a price cap that incorporated

post-divestiture outage data would confiscate investments

they had made since acquiring the facilities in question,

observing that the price cap was set before the divestiture

and potential purchasers ‘‘were afforded an opportunity to

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adjust their bids for the generation being divested by the

amount necessary to compensate them for effects of mitigation measures.’’ Id.

Petitioners sought rehearing, renewing their confiscation

argument and arguing additionally that using only twelve

months of data is less accurate than a longer period of at

least five years because of year-to-year anomalies that

smooth out across several years. Prior to denying rehearing

the Commission requested that the NYISO supply data on

the outage rates using a 1, 2, or 3-year period. In the second

order on review, the Commission restated its reasons for

using only twelve months of data and made two additional

points: (1) the petitioners had misread its Order as changing

the in-city price cap, and (2) a 12-month period of forced

outage data is used throughout the state for calculating the

amount of UCAP available for sale. Order on Rehearing, 98

FERC ¶ 61,180, 61,665–66 (2002). Petitioner Orion sought

rehearing. In the third order on review, the Commission

denied rehearing as it had already dealt with Orion’s arguments, and stated that NYISO data for 24 months indicated

no significant change from the twelve month average forced

outage rate and that the 36 month data were not ‘‘relevant to

the time period during which [petitioners] had operational

authority.’’ Order on Rehearing, 99 FERC ¶ 61,072, 61,335

(2002).

II.

On review, petitioners principally contend that the Commission never explained why their substantial objections to the

twelve month data limitation are wrong, and that the Commission’s statement that twelve months of data are most

current begs the question by failing to justify why this limited

period is better than a longer period for reflecting the most

accurate prediction of usable capacity. They do not challenge

the inclusion of post-divestiture data in the calculation of the

forced outage rate, as they initially had before of the Commission, only the failure to include forced outage data from a

longer time period. The Commission responds that its judgUSCA Case #02-1125 Document #785554 Filed: 11/18/2003 Page 5 of 13
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ment on this ‘‘rate design’’ is entitled to deference, because it

involves balancing interests at the core of its regulatory

function, that the Commission appropriately adhered to the

principle of revenue neutrality in the conversion from ICAP

to UCAP, and that the petitioners’ position is patently unreasonable as capacity revenues (and rate payer costs) would

increase substantially at the time of the UCAP conversion

over what would have been expected had the ICAP methodology been retained.

The court reviews whether the Commission engaged in

reasoned decisionmaking under the arbitrary and capricious

standard, which requires the Commission to ‘‘respond meaningfully to the evidence,’’ for ‘‘[u]nless an agency answers

objections that on their face appear legitimate, its decision

can hardly be said to be reasoned,’’ Tesoro Ala. Petroleum

Co. v. FERC, 234 F.3d 1286, 1294 (D.C. Cir. 2000). The

underlying question, on which the reasonableness of the

Commission’s decision to use twelve months of data to translate the price cap turns, is why the forced outage rates for the

1-year and 2-year periods are so much lower than those using

data averaged across 3 years or longer. The rate effectively

doubles from a 2-year to a 3-year average, and the parties

have suggested different explanations for why the rates vary

so much.

Petitioners contend that the variance is due in large part to

the maintenance cycles of generating units. Repair work

forces generators out of service, and major repairs that take a

generator offline for extended periods of time do not happen

every year. Therefore, a year in which major maintenance is

done will reflect an artificially high forced outage rate, and a

year in which no major maintenance is done will reflect an

artificially low forced outage rate. The consequence of this

theory is that, assuming the generators in the relevant market are on somewhat similar maintenance cycles, the average

of several years (long enough for a generating unit’s full

maintenance cycle) is required to get an accurate prediction

of how often generators are forced offline, and using 12

months of data risks under- or over-estimating the forced

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outage rate, depending on when in the cycle the calculation is

made.

Evidence in the record also suggests that the variance

might be attributable to repairs and upgrades made by

petitioners since acquiring the relevant generating units from

Consolidated Edison in 1999. Petitioners initially argued

before the Commission that they had made significant improvements to the generators they had acquired. The consequence of this theory is that post-1999 forced outage rates

may be better indicators of future outage rates because they

reflect the physical state of the electric plants as they are

today, rather than as they were before substantial maintenance and repair work was done. However, the predictive

usefulness of such data might depend on the extent to which

any investments yielded permanent efficiency gains, as opposed to front-loading maintenance schedules bound to recur

in a few years.

Further, the record contains evidence suggesting that the

difference in the outage rates may be a product of changed

market circumstances. Before deregulation, there was arguably less of a regulatory incentive for Consolidated Edison to

keep surplus capacity available when energy demands were

being met, whereas the new owners now have a market

incentive to keep capacity continuously available to maximize

the amount they can sell. The New York Public Service

Commission, for instance, argued to the Commission that the

regulatory structure before the divestiture caused data on

outages to be kept differently, so pre-1999 data are ‘‘stale.’’

The consequence of this theory is that data on forced outages

before 1999 are of little value in predicting future outage

rates.

These explanations are not logically inconsistent with each

other, and it may be that each is partly responsible for the

swing, or that one explains the variance in full and the others

are completely wrong. Or another explanation may account

for near-doubling of the forced outage rates between the 2-

year and 3-year averages. It matters which explanation is

adopted by the Commission. If the maintenance cycle causes

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the forced outage rates to vary as petitioners contend, the

Commission has translated the price cap in a way that

deprives them of anticipated revenue streams at the time of

purchase of the in-city generators. Because the amount of

capacity that the suppliers are actually allowed to sell is

recalculated continuously (on a 12-month rolling average), the

petitioners point out that if the forced outage rates swing up

again, they will not be able to sell enough capacity to bring in

the same revenues they had under the previous ICAP system

(i.e. the transition will not have been ‘‘revenue neutral’’). If

this explanation for the variations is plausible, then the

Commission’s decision to only use one year of data looks

arbitrary. The level of the price cap would, as petitioners

argue, depend entirely on whether it is set at a time when the

maintenance cycle is at a high point or a low point, and that

timing bears no relationship to the purpose of the cap itself.

The Commission cannot reasonably base its judgment on a

criterion if that criterion bears ‘‘no relationship to the underlying regulatory problem,’’ see ALLTEL Corp. v. FCC, 838

F.2d 551, 559 (D.C. Cir. 1988) (quoting Home Box Office, Inc.

v. FCC, 567 F.2d 9, 60 (D.C. Cir. 1977)).

On the other hand, if the variance is a product of the

changed market structure and recordkeeping, the forced outage rate over the next few years will likely be the same as it

has been in the past year, and pre-divestiture data are of

limited usefulness. Thus, a UCAP price cap based on a oneyear forced outage rate ought to keep revenue fairly identical

to what it was under the old ICAP system. If true, the

Commission accomplished its stated goal of ‘‘revenue neutral[ity]’’ adequately. Similarly, if physical improvements to

the generators explain the lower forced outage rate over the

past two years, then post-improvement figures would seem to

be a more accurate predictor of future outage rates than a

multi-year average that factors in pre-divestiture data, depending on the extent to which those physical improvements

represent permanent efficiency gains as opposed to simply

front-loading maintenance work bound to recur in a few

years. Although petitioners argued to the Commission that if

their investments are what caused the outage rates to fall,

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then using post-divestiture data has the effect of penalizing

them for improving the reliability of their generators, on

review they do not challenge the Commission’s decision to

include recent data in the calculation of the forced outage

rates, only the decision not to account for a longer time

frame.

It is obviously not the role of the court to decide why the

forced outage rates recently dropped. However, the petitioners contend the Commission did not adequately respond to

their argument that the maintenance cycle theory is correct.

The Commission’s treatment of petitioners’ objections was

quite curt. The Commission essentially relied on two reasons: (1) The twelve-month data are ‘‘more current,’’ and

reflect the time over which the current owners ‘‘had operational authority;’’ and (2) The twelve-month data are also

what are used statewide to calculate how much capacity a

generator has available for sale. The second rationale is

somewhat of a nonsequitur: the sales allowance is continuously recalculated while the price cap is not — precisely petitioners’ point that as the maintenance cycle swings, future recalculations may cause the sales allowance to drop but the price

cap will be too low to compensate for the drop. As to the

first rationale, the Commission’s statement that the past 12

months was during the period in which the petitioners had

‘‘operational authority,’’ see Order on Rehearing, 99 FERC

¶ 61,072 at 61,335, appears to be a nod to either the ‘‘physical

improvements’’ explanation or the ‘‘market structure’’ explanation for the drastic change in the equivalent forced outage

rates between 1998-1999 and 1999-2000. The Commission’s

implication seems to be that something about deregulation

and divestiture has caused a permanent improvement in

efficiency, and that the forced outage rates will not rise to

pre-1999 levels again. This may be the case, but the Commission did not explain whether it had adopted this theory,

and if so, why.

The record evidence might support the notion that new

market conditions or the changed physical state of the generating units make pre-divestiture forced outage data unreliable. Consolidated Edison submitted the affidavit of Robert

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B. Stoddard claiming that when it managed the generators at

issue, it had an incentive to shut down units whose output was

not needed, and that those shutdowns (which private owners

do not do because they want to maximize the capacity available for sale) artificially raised the forced outage rate for

those years. Further, petitioners submitted to the Commission that they had invested in reliability improvements since

acquiring the facilities, lending plausibility to the theory that

the recent drop in the forced outage rates is due, at least in

part, to their improvements. Yet despite record evidence of

both theories, the Commission did not explain which, or what

other theory, it was adopting, thereby denying petitioners the

chance to respond to its reasoning.

On review, the Commission maintains that its orders make

clear that its choice among contending price cap translation

proposals was guided by the revenue neutrality principle, by

an effort to reflect current rather than stale outage conditions, and by a desire to achieve consistency in UCAP treatment throughout the state. However, in the orders on review, the Commission did not respond to the petitioners’

argument and evidence that the maintenance cycle makes

twelve months too short for predicting future outage rates

accurately. Rather, the Commission stated only that twelvemonth data are more ‘‘current’’ and mirror the data used to

calculate the sales-allowance, see Order on Rehearing, 99

FERC at 61,335-36, even after receiving data from the NYISO that revealed the large jump from 6.59% to 12.58%

between the two-year and three-year average. The Commission stated that it ‘‘considered [the petitioners’] viewpoint and

TTT disagreed.’’ Id. at 61,336. From all the court can tell

there may be good reasons to disagree with petitioners’

maintenance-cycle theory, and why more recent data are

better predictors of future outage rates, but the Commission

did not supply them. The NYISO asserted in its answer to

petitioners’ request for rehearing, and the Public Service

Commission of New York contends as intervenor before the

court, that even the one-year average is composed of enough

generators that variance due to maintenance cycles is averaged out. Nothing in the Commission’s orders reflects adopUSCA Case #02-1125 Document #785554 Filed: 11/18/2003 Page 10 of 13
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tion of this line of reasoning. There also is an assertion by

the New York Public Service Commission that Consolidated

Edison, which ran the facilities until 1999, recorded forced

outages differently than under current rules but this does not

appear as the Commission’s explanation in the orders on

review.

The Commission contends that the petitioners cannot claim

hardship from the new price cap because they knew about the

price cap when they purchased the relevant generating units

in 1999. This appears to be responsive to petitioners’ argument before the Commission that post-divestiture forced outage data should be disregarded so as not to penalize them for

investing in improved efficiency, but not to the question of

whether the Commission effectively lowered the price cap in a

proceeding the stated purpose of which was to translate it.

Intervenor Consolidated Edison’s contention that petitioners

lack standing because they did not challenge the ‘‘revenue

neutrality’’ principle before the Commission relies upon the

same misunderstanding; petitioners’ contention is that the

Commission’s methodology actually lowered the price cap,

and therefore did not comport with the Commission’s stated

goal of revenue neutrality.

In its brief on review the Commission also maintains that it

is sensible to use only twelve months data to predict the

future outage rate for price cap purposes because only twelve

months of data are used to calculate how much ‘‘UCAP’’ each

supplier has available for sale. Thus the amount suppliers

are allowed to sell will be reduced by the exact amount that

the price cap is increased. Other than the cryptic statement

that a 12-month period ‘‘ensures that the UCAP conversion

terms are consistent throughout the New York State,’’ Order

on Rehearing, 98 FERC ¶ 61,180 at 61,666, the Commission

did not adopt this rationale, however, and ‘‘post hoc salvage

operations of counsel’’ cannot overcome the inadequacy of the

Commission’s explanation. Florida Power & Light Co. v.

FERC, 85 F.3d 684, 689 (D.C. Cir. 1996), see generally SEC v.

Chenery Corp., 332 U.S. 194, 196-97 (1947). In any event, the

perfection of such a translation is hardly obvious: the price

cap remains at a fixed level until the Commission changes it,

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while the amount of UCAP that sellers are allowed to sell

keeps changing and can go up or down based on a 12-month

rolling average. If the petitioners are correct that the Commission set the price cap when the forced outage rates were

below-average in their cycle, petitioners will not always have

as much UCAP available as they did the month of the

translation, and will lose revenue in the long run. The

question is whether the Commission used data that accurately

predict forced outage rates in the future, rather than simply

data that reflect those rates during the month of translation.

If not, the Commission has changed the price cap without the

requisite inquiry into whether the new rate is just and

reasonable, see 16 U.S.C. §§ 824d(a), (b); 18 C.F.R. § 35.13.

Consolidated Edison maintains that because the price cap’s

purpose is simply to prevent the improper exercise of market

power (rather than to guarantee any particular revenue

stream to petitioners), it would not matter even if the petitioners are correct that the Commission chose a value that

does not fairly predict future outage rages: the price cap is

there to protect consumers, not guarantee a revenue stream.

This appears to be an argument that the validity of the price

cap translation does not depend on its effect on petitioners’

revenues. The scope of the Commission’s order was to

translate the price cap, not to change it, and it explained its

translation on that basis, referring to any change in the cap

as being ‘‘beyond the scope of this proceeding.’’ Order at

61,994. If the translated price cap was supposed to be

determined by consumer-protection rationales rather than on

the old price cap, petitioners presumably would have introduced different evidence before the Commission, such as, for

example, evidence about the market structure and their own

price-setting market power. In any event, the Commission

relied nowhere in its orders on the rationale suggested by

Consolidated Edison.

For these reasons, we hold that the Commission did not

adequately explain why twelve months of historical data

would accurately reflect outage rates for use in translating

the price cap from ICAP to UCAP, nor why the two periods — the amount suppliers are allowed to sell and the

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amount the price cap is increased — must be based on the

same twelve months of data. It may be justifiable, for

purposes of establishing revenue neutrality, that the period

used to predict the availability of capacity should commence

with the petitioners’ acquisition of the equipment because

they are likely to be more efficient and therefore have

increased revenues, but that was not explained in the orders

on review. Although the petitioners did not specify in their

petitions that the five to seven year period they requested be

the most recent five to seven years (as opposed to the five to

seven years preceding divestiture), their rehearing request

can be construed in that fashion, and the Commission did not

explain why it was denying rehearing or state that the

petition did not adequately ask for relevant periods. Petitioners presented a serious argument that a period long

enough to account for generators’ maintenance cycle should

have been employed to calculate the forced outage rate to be

factored into the translated price cap, and the Commission

neither responded nor based its decision on a procedural

default. On remand, petitioners can, if the Commission

deems it relevant, present evidence regarding the timing of

their generators’ maintenance cycles, to the extent it bears

upon whether a 12-month period sufficiently smooths out the

fleet-wide average of forced outages. Accordingly, we vacate

the orders and remand the cases to the Commission.

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