Keyspan-Ravenswood, LLC v. Federal Energy Regulatory Commission

348 F.3d 1053, 358 U.S. App. D.C. 315, 2003 U.S. App. LEXIS 23424

• Court: Court of Appeals for the D.C. Circuit
• Decided: November 18, 2003
• Docket: 02-1115, 02-1125, and 02-1150
• Status: Published

Opinion

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 (“NY- ISO”) 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-Ravens-wood, 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.

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 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 ... 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/kW-year, 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 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 judgment 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 “[ujnless 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 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 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 one-year 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 neutrality]” 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, 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 contin uously 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 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 twelve-month 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 NY-ISO 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 ... 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 adoption 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 Com mission’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, 67 S.Ct. 1575, 91 L.Ed. 1995 (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, 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 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.