PPL Wallingford Energy LLC v. Federal Energy Regulatory Commission
419 F.3d 1194
D.C. Cir.
2005
Check Treatment
Docket

PPL WALLINGFORD ENERGY LLC and PPL EnergyPlus, LLC, Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent

Nos. 03-1292, 04-1062

United States Court of Appeals, District of Columbia Circuit.

Argued April 18, 2005. Decided Aug. 9, 2005.

419 F.3d 1194

Massachusetts Municipal Wholesale Electric Company, et al., Intervenors.

John Longstreth argued the cause for petitioners. With him on the briefs were Donald A. Kaplan and Sandra E. Rizzo.

David H. Coffman, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With him on the brief were Cynthia A. Marlette, General Counsel, and Dennis Lane, Solicitor.

Before: GINSBURG, Chief Judge, and HENDERSON and GARLAND, Circuit Judges.

Opinion for the Court filed by Circuit Judge GARLAND.

GARLAND, Circuit Judge.

This case raises the question of whether FERC‘s rejection of a PPL-ISO-NE RMR agreement covering CTs in a NEPOOL DCA violates the APA because FERC ignored PPL‘s objections to FERC‘S PUSH and LMP assumptions.1 We conclude that it does. For those not fluent in the language of FERC, a translation follows.

I

Petitioners PPL Wallingford Energy, LLC and PPL EnergyPlus, LLC (collectively, “PPL“) challenge orders of the Federal Energy Regulatory Commission (FERC) that rejected PPL‘s agreement with ISO New England, Inc. (ISO-NE) to provide electric power on a cost-of-service basis. PPL also challenges FERC orders rejecting similar agreements between Devon Power, LLC and ISO New England. Because PPL was not a party to the latter agreements, it lacks standing to challenge the orders that relate to them. PPL does have standing to challenge the orders rejecting its own agreement, however, and we conclude that those orders violate the Administrative Procedure Act (APA). We therefore vacate the orders relating to PPL and remand the case to the Commission for further proceedings.

II

The Federal Power Act gives FERC jurisdiction over the transmission and sale of electric energy at wholesale in interstate commerce. See 16 U.S.C. § 824(b)(1). The Act requires public utilities to file schedules with FERC showing, among other things, the rates they will charge for the transmission or sale of energy. Id. § 824d(c). If, after a hearing, FERC “find[s] that any rate ... collected by any public utility for any transmission or sale subject to [its] jurisdiction ... is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate ... and shall fix the same by order.” Id. § 824e(a).

ISO New England, Inc. is an “independent system operator” that runs the New England electricity market, known as the New England Power Pool (NEPOOL). See

, order on reh‘g,
. It acts as a middleman, matching bids (offers to sell power) by generators with requests from customers. See
, at 62,261, order on reh‘g,
, order on reh‘g,
, order on reh‘g,
.

In 2002, FERC proposed the creation of “standard market designs” (SMDs) to standardize the sale of electric power, with the goal of creating “‘seamless’ wholesale power markets that allow sellers to transact easily across transmission grid boundaries and that allow customers to receive the benefits of lower-cost and more reliable electric supply.”

, ¶ 9 (2002). In response to FERC‘s proposal, ISO New England, along with the NEPOOL Participants Committee, submitted an SMD for the New England region. FERC approved the SMD, with certain modifications not relevant here. See
.

In “chronically constrained” regions identified as “Designated Congestion Areas” (DCAs), the New England SMD created a complex system of compensation for generators under what was known as Market Rule 1. See

. First, the SMD attempted price reduction—“mitigation” in FERC parlance—by setting a price cap “based on the estimated price to recover the annual cost of a new combustion turbine unit (CT) for the region over the number of hours it is expected to operate during the year.”
. This estimated price was known as the “CT Proxy.”
Second, to mitigate the impact of mitigation, under certain circumstances the SMD allowed the highest bid accepted in a particular area to set the price, called the “Locational Marginal Price” (LMP), for all bids accepted in that area. See
.

To further soften the impact of mitigation, the SMD also allowed certain seldom-used generator units needed to assure system reliability to “be classified as Reliability-Must-Run (RMR) units.” These are units that “must be run“—i.e., that ISO New England can compel to run “during certain periods to alleviate transmission congestion.”

. This designation entitled the generator to apply for an “RMR Cost-of-Service Agreement” if the unit could not recover its costs under the CT Proxy mechanism and would otherwise be shut down.
. An RMR agreement provides monthly payments to enable the unit to recover its costs plus a reasonable return on investment. See
. In its order upholding the SMD, FERC confirmed that “ISO-NE has the authority to negotiate individual RMR agreements as are required to maintain and/or improve system reliability.”
. FERC further stated that “such agreements are to be filed with the Commission in accordance with the Commission‘s rules and regulations, and, as such, may be subject to the review of the Commission.”

PPL built a generating station consisting of five natural gas combustion turbines in the southwest Connecticut DCA, from which it began selling power in December 2001. The units were relatively high-cost “peaking” units, intended to run only during times of peak demand or system need. On January 16, 2003, PPL submitted a request for FERC approval of an RMR agreement negotiated with ISO New England to cover four of the five units. While the RMR request was pending, PPL filed an application with ISO New England to temporarily deactivate the four units for economic reasons. The deactivation application was denied, on the ground that the units were necessary for reliability purposes, and PPL was required to continue operating the units regardless of economic considerations. In February 2003, Devon Power, LLC and three affiliated entities (collectively, “Devon“) submitted a similar request for FERC approval of four RMR agreements for their Connecticut units.

FERC ruled on Devon‘s RMR request first, denying it in an April 25 order that significantly changed the existing compensation scheme. First, it found that “RMR contracts suppress market-clearing prices, increase uplift payments, and make it difficult for new generators to profitably enter the market,” and that “extensive use of RMR contracts undermines effective market performance.”

(Devon Order). Fearing that it would face a proliferation of RMR agreements, the Commission held that such agreements “should be a last resort.”
Second, FERC decided to revise Market Rule 1, pursuant to Section 206 of the Federal Power Act, 16 U.S.C. § 824e.
. The revision entailed the elimination of the CT Proxy standard, because “[u]nits that produce energy in substantially fewer hours, such as the [Devon] units, are not likely to be able to recover all of their fixed costs under the current CT Proxy.”

In place of CT Proxy, FERC adopted a new methodology called Peaking Unit Safe Harbor (PUSH) bidding.

. The PUSH methodology gave a generator that had operated at ten percent or less of capacity during 2002 a “safe harbor” bid price based on the sum of its units’ variable-cost and fixed-cost components. The fixed-cost component for 2003 was calculated by dividing a unit‘s annual fixed costs (including a reasonable return on investment) by the number of megawatt hours the unit supplied in 2002. The PUSH price would therefore allow the generator to recover its costs in 2003 if the generator ran for the same number of hours (and had the same costs) as it did in 2002. The goal of PUSH bidding was “to provide a market mechanism for high cost, seldom run units to recover their fixed costs.”
FERC maintained that replacing RMR agreements with PUSH bidding “changed only the form in which [generators] will be able to recover their fixed and variable costs, i.e., use of a safe harbor bid within the market rather than an RMR contract.”
FERC further decided that the revised “Market Rule shall provide that the energy bids of peaking units are eligible to determine LMP“—which meant that those units’ PUSH bids could set the LMP, thereby serving as the sales price for all power sold in the area during the time period

FERC declared that it would “direct ISO-NE to make compliance filings to reflect these changes in Market Rule 1.”

The changes were only intended, however, as a temporary solution. As initially contemplated, they were to last until June 1, 2004, when a new system, called LICAP, would be implemented.
FERC has since pushed back LICAP‘s implementation date to the beginning of 2006.
.

In response to the Devon Order, many industry members submitted requests for rehearing and clarification.

(Devon Order on Reh‘g). PPL was among the industry intervenors. Rejecting the intervenors’ arguments to the contrary, FERC maintained that “the PUSH bid mechanism gives a generator a reasonable opportunity to recover its costs.”
.

On May 16, 2003, FERC rejected PPL‘s own RMR agreement “[o]n the basis of the rationale developed in Devon.”

. RMR agreements, FERC said, could be used only as a “last resort,” and consequently PPL would have to rely on the new PUSH system for compensation.
PPL requested rehearing and clarification, contending (inter alia) that the PUSH mechanism denied it a reasonable opportunity to recover its costs. See
. FERC denied PPL‘s requests for rehearing and clarification, again relying on the Devon orders.
PPL now petitions for review of FERC‘s orders in both the Devon and PPL proceedings.

III

Before we address PPL‘s substantive claims, we must consider whether it has standing to challenge the FERC orders that it has asked us to review. The Federal Power Act provides that “[a]ny party to a proceeding ... aggrieved by an order issued by the Commission in such proceeding may obtain a review of such order” in this court. 16 U.S.C. § 825l(b). A party is “aggrieved” if it satisfies the usual constitutional and prudential standing requirements, which include a showing of concrete, redressable injury. See, e.g.,

. There is no doubt that PPL has suffered an injury from, and therefore has standing to challenge, the orders that rejected its own RMR agreement. The injury is illusory, however, in the context of the orders that rejected the Devon agreements—agreements to which PPL was not a party.

PPL admits that it does not seek to reverse FERC‘s denial of the Devon agreements. See Pet‘rs Reply Br. at 8 n. 7. Rather, it wishes only to challenge the reasoning of the Devon orders as later applied to deny its own agreement. See Oral Arg. Tape at 12:19–12:40. But PPL is free to challenge that reasoning in the context of the denial of its agreement, regardless of whether the reasoning became agency precedent in another case. See

. Indeed, that is the challenge we consider in Part IV. As a consequence, PPL suffers no injury from its inability to challenge the orders denying the Devon agreements. See Oral Arg. Tape at 12:19–12:40 (concession by PPL counsel that, if PPL is allowed to attack the Devon rationale in its own proceeding, it is not “aggrieved in any way by not being able to challenge what happened to Devon“); cf.
(“[M]ere precedential effect within an agency is not, alone, enough to create Article III standing, no matter how foreseeable the future litigation.“). Accordingly, PPL lacks standing to challenge the Devon orders.

IV

We now turn to PPL‘s contention that the orders denying its RMR agreement violated the Administrative Procedure Act because they are “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 5 U.S.C. § 706(2)(A). To survive review under the “arbitrary and capricious” standard, an agency must “examine the relevant data and articulate a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made.‘”

(quoting
). An agency‘s “failure to respond meaningfully” to objections raised by a party renders its decision arbitrary and capricious.
; see
. We have stressed that “[u]nless the [agency] answers objections that on their face seem legitimate, its decision can hardly be classified as reasoned.”
; see
.

In rejecting PPL‘s proposed RMR agreement, the Commission said it was acting on “the basis of the rationale developed in Devon, and [in accordance] with the market modifications made in that order.”

. One of the premises of Devon was that the new methodology it announced, PUSH bidding, would provide “a generator a reasonable opportunity to recover its costs.”
. Indeed, a goal of PUSH bidding was “to provide a market mechanism for high cost, seldom run units to recover their fixed costs.”
. In its pleadings before the Commission, PPL challenged that premise by attacking two of its underlying assumptions, as well as FERC‘s alleged failure to honor its commitment to permit RMR agreements as a last resort. FERC‘s orders failed “to respond meaningfully,”
, to PPL‘s three objections.2

First, in concluding that an eligible unit could recover its costs under PUSH bidding, FERC relied on the fact that the PUSH bid price was based on the sum of the unit‘s variable costs and fixed costs, and that the latter was calculated by dividing the unit‘s fixed costs by the number of megawatt hours it supplied in 2002. Thus, a unit that ran as often in 2003 as in 2002 could recover all of its costs. PPL, however, challenged the assumption that its units would indeed run as often in 2003 as they had in 2002, pointing out that rising natural gas prices (and hence increased generation prices) would reduce demand for PPL‘s gas-fired generators. Pet. for Reh‘g at 7-9 (June 16, 2003). In particular, PPL argued that the sixty percent increase in gas prices between 2002 and 2003 would permit non-gas-fired units to compete more effectively against it, and that PPL‘s units would therefore run for fewer hours.

.

FERC failed to respond directly to PPL‘s point about the change in gas prices and the consequent reduction in run hours. Instead, the Commission simply asserted that PPL had failed to suggest an alternative to PUSH methodology. In fact, PPL did suggest several alternatives, including continued use of RMR agreements, at least when PUSH bidding resulted in under-recovery of costs. See Pet. for Reh‘g at 28-31 (listing proposed modifications of PUSH bidding). Moreover, it was not PPL‘s burden to present alternatives; it was the Commission‘s burden to prove the reasonableness of its change in methodology. See

. “In order to make any change in an existing rate or practice” under section 206 of the Federal Power Act, “FERC must first prove that the existing rates or practices are ‘unjust, unreasonable, unduly discriminatory or preferential.’ ... Then FERC must show that its proposed changes are just and reasonable.”
(quoting 16 U.S.C. § 824e(a)).

Second, in further support of its conclusion that the PUSH mechanism would provide seldom-used units with an opportunity to recover their costs, FERC relied on the assumption that “the energy bids of peaking units” would be “eligible to determine LMP.”

. This meant that all generating units in the region would receive the highest accepted PUSH price for their power, and hence that it was possible for a unit to receive substantially more than its own PUSH bid. Thus, to the extent that the LMP was set by older, more expensive generators than PPL‘s, PPL could recover revenues higher than its costs even if its units operated for fewer hours in 2003 than 2002. In FERC‘s view, there was thus an “equal risk that eligible units may under-recover or over-recover their costs.”
.

PPL, however, pointed out that FERC‘s assumption regarding LMP was in error. ISO New England, it noted, had “confirmed that it does not intend to allow PUSH eligible units operating at their low operating limits to set LMP.” Pet. for Reh‘g at 32; see

. And if PUSH bids could not set the LMP, there was no support for FERC‘s premise that the risk of under-recovery was balanced by the possibility of over-recovery. FERC failed to respond to this objection in any way.

Finally, FERC had said in Devon that it would permit the use of RMR agreements as a “last resort” when PUSH bidding would not permit a generator to recover its costs. PPL contended that it met the “last resort” standard,

, and as evidence it submitted an expert study showing that PUSH bidding would permit the PPL units to recover only thirty percent of their fixed costs,
.3 Once again, FERC‘s orders contained no response. Indeed, they did not address PPL‘s evidence at all. In light of the Commission‘s failure to “answer[] objections that on their face seem legitimate, its decision can hardly be classified as reasoned.”
.

V

Although we dismiss for lack of standing PPL‘s petition challenging the Devon orders, we grant PPL‘s petition to review the orders rejecting its own proposed agreement, vacate those orders as arbitrary and capricious, and remand the case for further proceedings consistent with this opinion.

So ordered.

Notes

1
See FERC Br. at x (“Glossary“).
2
Because that failure is sufficient to require vacatur of the PPL orders, we have no occasion to consider PPL‘s other challenges.
3
This analysis was confirmed by a report filed by ISO New England prior to the date FERC issued its PPL decision. The report found that PUSH bidders recovered only about thirty-five percent of their fixed costs under the PUSH system. See ISO New England, Inc., A Review of Peaking Unit Safe Harbor (PUSH) Implementation and Results 1, 29 (Dec. 4, 2003) (J.A. 361, 389). FERC contends that we should not consider the ISO report because it was filed only in the Devon docket. Because we find the PPL orders arbitrary and capricious without reference to the ISO report, we need not decide whether the fact that it was filed it in a different, albeit closely related, docket removes it from our purview.