United States Court of Appeals
           FOR THE DISTRICT OF COLUMBIA CIRCUIT



Argued April 18, 2005                   Decided August 9, 2005

                          No. 03-1292

            PPL WALLINGFORD ENERGY LLC AND
                 PPL ENERGYPLUS, LLC,
                      PETITIONERS

                               v.

         FEDERAL ENERGY REGULATORY COMMISSION,
                      RESPONDENT

      MASSACHUSETTS MUNICIPAL WHOLESALE ELECTRIC
                   COMPANY, ET AL.,
                     INTERVENORS


                        Consolidated with
                           04-1062


            On Petitions for Review of Orders of the
            Federal Energy Regulatory Commission


     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
                                   2

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.




    1
        See FERC Br. at x (“Glossary”).
                                 3

                                 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 New England
Power Pool, 79 F.E.R.C. ¶ 61,374 (1997), order on reh’g, 85
F.E.R.C. ¶ 61,242 (1998). It acts as a middleman, matching bids
(offers to sell power) by generators with requests from
customers. See New England Power Pool & ISO New England,
Inc., 100 F.E.R.C. ¶ 61,287, at 62,261, order on reh’g, 101
F.E.R.C. ¶ 61,344 (2002), order on reh’g, 103 F.E.R.C. ¶
61,304, order on reh’g, 105 F.E.R.C. ¶ 61,211 (2003).

     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.” Remedying
Undue Discrimination Through Open Access Transmission
Service & Standard Electricity Market Design, Notice of
Proposed Rulemaking, 100 F.E.R.C. ¶ 61,138, ¶ 9 (2002). In
response to FERC’s proposal, ISO New England, along with the
                                4

NEPOOL Participants Committee, submitted an SMD for the
New England region. FERC approved the SMD, with certain
modifications not relevant here. See New England Power Pool,
100 F.E.R.C. ¶ 61,287.

      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 id. at 62,262.
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.” Devon Power LLC, 103 F.E.R.C. ¶
61,082, at 61,267 n.3 (2003). This estimated price was known
as the “CT Proxy.” Id. 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 New England Power Pool, 100 F.E.R.C. ¶ 61,287,
at 62,271.

     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.” Id. at 62,262. 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.
Id. at 62,263. An RMR agreement provides monthly payments
to enable the unit to recover its costs plus a reasonable return on
investment. See PSEG Power Connecticut, LLC, 110 F.E.R.C.
¶ 61,020, ¶ 30 (2005). In its order upholding the SMD, FERC
                                5

confirmed that “ISO-NE has the authority to negotiate individual
RMR agreements as are required to maintain and/or improve
system reliability.” New England Power Pool, 100 F.E.R.C. ¶
61,287, at 62,268. 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.” Id.

      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 Power LLC, 103
F.E.R.C. ¶ 61,082, at 61,270 (2003) (Devon Order). Fearing
that it would face a proliferation of RMR agreements, the
                                6

Commission held that such agreements “should be a last resort.”
Id. Second, FERC decided to revise Market Rule 1, pursuant to
Section 206 of the Federal Power Act, 16 U.S.C. § 824e. Id. at
61,271. 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.”
Id.

     In place of CT Proxy, FERC adopted a new methodology
called Peaking Unit Safe Harbor (PUSH) bidding. Id. at 61,274.
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.” Id.
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.” Id.
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. Id.

    FERC declared that it would “direct ISO-NE to make
compliance filings to reflect these changes in Market Rule 1.”
Id. The changes were only intended, however, as a temporary
                                7

solution. As initially contemplated, they were to last until June
1, 2004, when a new system, called LICAP, would be
implemented. Id. FERC has since pushed back LICAP’s
implementation date to the beginning of 2006. Devon Power
LLC, 110 F.E.R.C. ¶ 61,315, ¶ 27 (2005).

     In response to the Devon Order, many industry members
submitted requests for rehearing and clarification. Devon Power
Co., 104 F.E.R.C. ¶ 61,123, at 61,414 (2003) (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.” Id. at 61,416.

     On May 16, 2003, FERC rejected PPL’s own RMR
agreement “[o]n the basis of the rationale developed in Devon.”
PPL Wallingford Energy LLC, 103 F.E.R.C. ¶ 61,185, at 61,716
(2003). 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. Id. PPL requested
rehearing and clarification, contending (inter alia) that the PUSH
mechanism denied it a reasonable opportunity to recover its
costs. See PPL Wallingford Energy LLC, 105 F.E.R.C. ¶
61,324, at 62,522-23 (2003). FERC denied PPL’s requests for
rehearing and clarification, again relying on the Devon orders.
Id. 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
                               8

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., Wabash Valley Power
Ass’n, Inc. v. FERC, 268 F.3d 1105, 1112 (D.C. Cir. 2001).
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 Shell
Oil Co. v. FERC, 47 F.3d 1186, 1203 (D.C. Cir. 1995). 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. Sea-Land Serv., Inc. v. DOT, 137 F.3d
640, 648 (D.C. Cir. 1998) (“[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
                               9

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.’”
Motor Vehicle Mfrs. Ass’n of the United States, Inc. v. State
Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (quoting
Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168
(1962)). An agency’s “failure to respond meaningfully” to
objections raised by a party renders its decision arbitrary and
capricious. Canadian Ass’n of Petroleum Producers v. FERC,
254 F.3d 289, 299 (D.C. Cir. 2001); see Public Serv. Comm’n v.
FERC, 397 F.3d 1004, 1008 (D.C. Cir. 2005). We have stressed
that “[u]nless the [agency] answers objections that on their face
seem legitimate, its decision can hardly be classified as
reasoned.” Canadian Ass’n, 254 F.3d at 299; see Tesoro Alaska
Petroleum Co. v. FERC, 234 F.3d 1286, 1294 (D.C. Cir. 2000).

     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.” PPL Wallingford Energy
LLC, 103 F.E.R.C. ¶ 61,185, at 61,716. 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.” Devon Order on Reh’g, 104 F.E.R.C. ¶
61,123, at 61,416. Indeed, a goal of PUSH bidding was “to
provide a market mechanism for high cost, seldom run units to
recover their fixed costs.” Devon Order, 103 F.E.R.C. ¶ 61,082,
at 61,271. 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.
                                 10

FERC’s orders failed “to respond meaningfully,” Canadian
Ass’n, 254 F.3d at 299, 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. Id. at 9.

     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
Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 10 (D.C. Cir.
2002). “In order to make any change in an existing rate or
practice” under section 206 of the Federal Power Act, “FERC


     2
      Because that failure is sufficient to require vacatur of the PPL
orders, we have no occasion to consider PPL’s other challenges.
                               11

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.” Id. at 10 (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.” Devon Order, 103 F.E.R.C. ¶
61,082, at 61,271. 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.” Devon Order on Reh’g,
104 F.E.R.C. ¶ 61,123, at 61,423.

     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 id. at 7-8 & n.17. 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, id. at 5, and as
evidence it submitted an expert study showing that PUSH
                                    12

bidding would permit the PPL units to recover only thirty
percent of their fixed costs, id. at 7, Attach. A.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.”
Canadian Ass’n, 254 F.3d at 299.

                                     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.




     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.
