United States Court of Appeals
         FOR THE DISTRICT OF COLUMBIA CIRCUIT



Argued September 19, 2012         Decided December 18, 2012

                        No. 11-1122

              CALPINE CORPORATION, ET AL.,
                      PETITIONERS

                             v.

       FEDERAL ENERGY REGULATORY COMMISSION,
                    RESPONDENT

    COGENERATION ASSOCIATION OF CALIFORNIA, ET AL.,
                    INTERVENORS


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


    Ashley C. Parrish argued the cause for petitioners. With
him on the briefs were Neil L. Levy, David G. Tewksbury, and
Stephanie L. Lim.

    Michael Alcantar, Donald E. Brookhyser, Robert C. Fallon,
and Brian M. Meloy were on the brief for intervenors Electric
Power Supply Association, et al. in support of petitioners.

     Robert M. Kennedy, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on the
brief was Robert H. Solomon, Solicitor.
                                2

    Jennifer L. Key argued the cause for intervenor Southern
California Edison Company. With her on the brief were Charles
G. Cole, Jennifer Hasbrouck, and Anna J. Valdberg. Roger E.
Collanton and Daniel Shonkwiler entered appearances.

    Before: ROGERS and KAVANAUGH, Circuit Judges, and
SILBERMAN, Senior Circuit Judge.

    Opinion for the Court filed by Senior Circuit Judge
SILBERMAN.

      SILBERMAN, Senior Circuit Judge: For the third time, we
consider FERC’s authority to regulate public-utility charges to
independent generators for the latter’s use of “station power” —
the electricity necessary to operate a generator’s requirements
for light, heat, air conditioning, etc. FERC now concludes that
it lacks this authority, and we affirm.

                                I.

     We explained the legal and economic background of the
electrical energy market in Niagara Mohawk Corp. v. FERC,
452 F.3d 822 (D.C. Cir. 2006), and Southern California Edison
Co. v. FERC, 603 F.3d 996 (D.C. Cir. 2010), but we will again
summarize. Generators may procure station power through one
of three means: (1) “on-site” self-supply, which redirects some
of the station’s outbound generated electricity for internal use
(also called “behind-the-meter” production); (2) “remote” self-
supply, in which power is obtained from an affiliated, off-site
facility; or (3) “third-party” supply, in which power is drawn off
the grid from unaffiliated providers.

    Historically, electrical utilities were vertically integrated
and typically acted as local monopolies — they owned
generation, transmission, and distribution facilities and sold
                                 3

these services as a bundled package in their service areas.
Utilities obviously did not charge themselves for the use of
station power at their generating facilities; rather, they simply
subtracted (“netted”) the energy consumed as station power
against their gross output. But in 1996 FERC issued Order 888,
which effectively unbundled generating from transmission and
distribution services. The Commission accomplished this goal
by requiring utilities to file open-access tariffs that offered rates
to all customers on an equal basis — basically, utilities could not
prefer their own affiliates over independent generators. Order
888 also encouraged the creation of non-profit independent
system operators (“ISOs”) to reduce the market power of
utilities and ensure competitive rates; the California Independent
System Operator (“CAISO”) is one such entity.

      Order 888 was successful in causing major utilities
nationwide to divest most of their generating facilities, but it
raised questions as to how independent generators would be
charged for their use of station power.                 Under what
circumstances could a generator be charged retail rates for either
drawing from the grid or self-supplying its station power?
FERC answered this question by devising “netting intervals.”
If a generator’s net output (total output to the grid minus station
power use) is positive over a fixed period, then the generator is
not charged retail rates for its consumption. But if the generator
uses more power than it sends, it is deemed to have obtained the
shortfall in a retail sale from a third party (i.e., a utility).

     Generators have an economic interest in a longer netting
interval because it affords a greater opportunity to send power
to the grid, which would make up for what is consumed.
Utilities, by contrast, would prefer shorter netting intervals to
enable higher retail charges against independent generators. A
generator is only paid for its net output of energy to the grid, so
even when the net output is positive, consumption of station
                                  4

power reduces the amount the generator is paid for its
production. But retail rates are higher than wholesale rates, so
a generator would rather have its station power netted against
the total it delivers at wholesale than pay for station power at
retail.

     The legal issue that triggered this series of cases is how the
authority to set netting intervals for different purposes meshes
with the Federal Power Act’s division of jurisdiction between
federal and state authorities. Section 201(b) of the Act gives
FERC jurisdiction over the “transmission of electric energy in
interstate commerce” and the “sale of electric energy at
wholesale in interstate commerce,” as well as “all facilities for
such transmission or sale.” 16 U.S.C. § 824(b)(1). States,
however, retain jurisdiction over “any other sale of electric
energy” and “facilities used in local distribution” of electricity.
Id.

     FERC approved a tariff establishing an hourly netting
period for the Pennsylvania-New Jersey-Maryland energy
market and later approved an amendment expanding the netting
interval to one month (if a generator’s net output over a month
was positive, then any energy a generator drew from the grid
was simply netted against its gross output and no retail charges
were permitted). Utility companies raised objections arguing
that any third-party provision of station power (and indeed, the
generator’s own production of station power)1 was a retail sale
outside of FERC’s jurisdiction. FERC rejected this position
because, in its view, if a generator’s net output was positive, no
sale had occurred.


     1
       In their view, an independent generator could be charged retail
rates even if all of its station power was produced on site. In that
respect it would be treated like a manufacturer that attempted to
bypass the local monopoly by generating its own electrical power.
                                 5

     The Commission instead agreed with the position advanced
by a group of generators — that the station-power netting
interval used to determine when to assess transmission fees
should be the same period used to calculate when the provision
of station power constitutes a retail sale. A “transmission fee”
is a fee assessed for the transmission of energy across the
electrical grid; it is often called an “access charge” because it is
assessed when a party is treated as “accessing” the grid. Netting
intervals are used for transmission as well because whether a
generator has positive or negative output over a given interval
determines what energy is deemed to be transmitted across the
grid.

     FERC accordingly approved a one-month netting period for
both transmission and station power in a tariff filed by the New
York ISO, which led New York utilities and the New York state
regulator to petition for review in this Court, raising the same
jurisdictional objection as the utilities in the prior case. FERC
defended its authority to determine when retail sales occur on
the basis of its jurisdiction over interstate transmission. A group
of generators, as intervenors, contended that the Commission
needed to set a uniform netting period to protect them from
unfair discrimination by utilities because utility-owned
generators, of course, would not be assessed retail charges by
the utilities themselves.

     In Niagara Mohawk, we noted that “[p]etitioners’ statutory
argument [was] not insubstantial,” that the Commission’s
rationale was “a bit confusing,” and that FERC had not “clearly
articulated why [transmission] jurisdiction permits it to
determine that no sale of any kind — including a retail sale —
takes place when the generator takes station power from the
grid.” 452 F.3d at 828. We declined, however, to resolve that
question on the merits because of a major concession by the
petitioners — that FERC had the authority to set an hourly
                                      6

netting interval, just not to expand the interval to one month. Id.
Because we saw no principled difference between hourly and
monthly netting with regard to FERC’s jurisdiction, we were
able to resolve that case solely on this concession.

     But the issue reappeared. Shortly after the Commission’s
orders in the New York market, Duke Energy — a California
independent generator — filed a complaint with FERC seeking
to compel CAISO to also move from hourly to monthly netting.
Southern California Edison — a utility — made the same
objection that retail sales were outside of FERC’s jurisdiction;
the Commission again rejected this position, denying that a retail
sale took place if a generator was net positive. It ordered
CAISO to revise its tariff to conform with the Pennsylvania-
New Jersey-Maryland and New York orders, and CAISO
amended its tariff to provide for monthly netting.2



     2
        Under CAISO’s revised tariff, if a generator’s net output (total
output to the grid minus station-power consumption) is positive over
a month, it is deemed to have engaged in on-site self-supply and is not
assessed transmission or retail charges. When the station power
demand of a unit exceeds its output, but the shortfall is covered by the
aggregate net output from other facilities of the same generator, the
generator is deemed to have engaged in remote self-supply. CAISO
would then assess a transmission access charge against the generator
(because transmission is deemed to be used in moving the station
power between different facilities), but the generator would not pay
retail rates to the utilities (because the generator is still treated as self-
supplying). If, on the other hand, the generator’s units collectively
withdraw more station power from the grid than they supply during
the netting interval, then the generator is deemed to have purchased
the amount of the deficiency in a third-party retail sale. Under those
conditions, CAISO would assess a transmission charge against the
utility, but the utility would then bill the generator under the applicable
retail tariff.
                                  7

     Edison responded to the revised tariff by trying an
alternative basis to charge for station power. Its new proposal
sought to assess direct stranded cost3 and consumption charges
against net-positive generators in lieu of retail charges. But
FERC issued further orders precluding Edison from imposing
even these charges, finding that they would prevent the
generators from taking full advantage of the tariff’s netting
provisions. Edison then petitioned for review in this Court.

     In Southern California Edison, we considered the
jurisdictional question that we had avoided in Niagara Mohawk.
Edison — careful to avoid the Niagara concession — insisted
that it would exceed FERC’s jurisdiction to set any netting
interval regulating “retail sales,” regardless of length. The
Commission again purported to rely on its authority over
interstate transmission, rather than wholesale jurisdiction, but it
failed to demonstrate any real connection between transmission
and the netting intervals governing retail sales for use of station
power. Instead, it just denied that retail sales were involved.
Accordingly, we said:

          [W]e do not understand why FERC is empowered to
          conclude that a retail sale has not taken place unless it
          can claim the transaction is, instead, a wholesale sale
          or a transmission. To simply declare that the state lacks
          jurisdiction because FERC believes no retail sale has



      The tariff’s general policy toward transmission fees is therefore
to charge the shipper. In third-party retail sales, the utility ships
energy to the generator, so the utility pays the access charge. But in
the case of remote self-supply, the generator is shipping energy to
itself (between facilities), so the generator pays the access charge.
     3
        “Stranded costs” are those costs associated with the
restructuring of the electric industry following Order 888.
                                8

         taken place really begs the jurisdictional question.
         Unless a transaction falls within FERC’s wholesale or
         transmission authority, it doesn’t matter how FERC
         characterizes it.

S. Cal. Edison, 603 F.3d at 1000-01. We also rejected the
Commission’s assertion that allowing different netting periods
for transmission charges and retail sales would create a
“conflict” for preemption purposes, as well as an argument by
intervening generators that inconsistent netting intervals would
result in “trapped” energy. Id. at 1001. We therefore vacated
and remanded on the basis that FERC’s approval of the revised
tariff exceeded its authority.

     The Commission issued a new order on remand,
acknowledging that it lacked a jurisdictional basis to determine
when the provision of station power constitutes a retail sale and
indicating that the netting interval in the CAISO tariff could
only govern Commission-jurisdictional transmission charges,
not retail charges. A group of California generators —
including Calpine, the petitioner in this case — filed requests for
rehearing and clarification, but FERC reaffirmed its original
order on remand. The Commission explained that this decision
was not “an unexplained departure from prior policy, but rather
a change compelled by a Court of Appeals’ finding on the scope
of our jurisdiction.” Calpine petitioned for review of FERC’s
orders on remand.

                                II.

     Calpine’s argument on appeal is that the Commission over-
read our decision in Southern California Edison and failed to
consider alternate bases for its initial approval of the tariff. In
Calpine’s view, Southern California Edison held only that the
Commission had failed to adequately explain its jurisdiction and
                                 9

that FERC, indeed, has authority under both its transmission and
wholesale jurisdiction to set netting intervals for retail sales. As
such, the orders on remand were an arbitrary and capricious
departure from the netting-interval policies established in the
Pennsylvania-New Jersey-Maryland and New York orders.
FERC maintains that we definitively rejected the transmission-
jurisdiction argument and that previous Commission decisions
disclaimed reliance on wholesale jurisdiction as a basis to
regulate third-party provision of station power.

     Since Edison, as we noted, did not make the same
concession as the petitioners in Niagara Mohawk, we were
obliged to confront the jurisdictional issue squarely, and we
rejected the Commission’s position as “rather arbitrary and
unprincipled — certainly as a jurisdictional standard.” S. Cal.
Edison, 603 F.3d at 1000. Calpine focuses on our statement that
“we do not understand why FERC is empowered to conclude
that a retail sale has not taken place unless it can claim the
transaction is, instead, a wholesale sale or a transmission,” id.,
as an indication that we were not actually reaching a definitive
holding, but simply requesting a more detailed explanation from
the Commission. Yet the above line is immediately followed by
our conclusion that FERC’s position “begs the jurisdictional
question,” id. at 1000-01, and that “[u]nless a transaction falls
within FERC’s wholesale or transmission authority, it doesn’t
matter how FERC characterizes it,” id. at 1001; see also id.
(“FERC’s order does not just sideswipe state jurisdiction; it
attacks it frontally.”). Indeed, the whole point of this decision
— the issue briefed and argued on appeal — was whether
FERC’s approval of the revised tariff exceeded its transmission
jurisdiction.

     Our opinion was, of course, limited to the arguments raised
before us; it is axiomatic that agency decisions may not be
affirmed on grounds not actually relied upon by the agency. See
                                 10

SEC v. Chenery Corp., 318 U.S. 80, 87-88 (1943). Calpine is
therefore correct that Southern California Edison did not
specifically preclude FERC from asserting alternate bases for
jurisdiction upon remand — either with some other theory to
connect its jurisdiction over transmission to the generator’s
station power, or as Calpine primarily argues, by relying on
FERC’s jurisdiction over wholesale. Our opinion did note that
we failed to see any strong basis for jurisdiction on this latter
basis, S. Cal. Edison, 603 F.3d at 999 n.5, but FERC had not
relied on its wholesale jurisdiction, so it is fair to say we did not
decide this question. Admittedly, therefore, FERC exaggerates
the impact of our prior decision. It was certainly open to FERC
to consider petitioners’ alternate bases for jurisdiction. FERC’s
response to petitioners’ new arguments is terse, to be sure, but
we think those arguments are difficult to understand and
ultimately fallacious.

     To take a step back, petitioners’ asserted injury is
essentially that independent generators are discriminated against
compared to the few remaining integrated utilities — those that
maintain their own generating capacity — and that this
discrimination undermines the effectiveness of Order 888’s
effort to unbundle the power industry to achieve a competitive
market for energy generation. Discrimination allegedly occurs,
as we noted, because the integrated utilities do not pay for
station power — they simply take it from their own generator —
whereas the independent generators must, under certain
circumstances, pay a retail charge for their own station power.
(Petitioners make no distinction between generators that take
station power from the grid or supply it themselves from either
their own remote location or “behind the meter.”)

    One difficulty we see with petitioners’ argument is that the
length of a netting period for station power shouldn’t matter
except to measure the degree of a generator’s alleged damage.
                                11

According to petitioners’ logic, any retail charge for station
power imposed on independent generators is inherently
discriminatory. Yet petitioners implicitly concede that a
monthly netting period is acceptable, which undermines their
asserted principle. In that respect, petitioners’ position
approaches the concession the generators made in Niagara
Mohawk. To be sure, petitioners were careful at oral argument
to insist that their legal argument is that FERC’s jurisdiction
preempts state regulation, and indeed, claimed that they would
be making that argument even if FERC’s netting interval were
the same as or worse than the state’s netting interval. But if
FERC’s failure to assert jurisdiction had no real economic
impact on Calpine, any injury would almost certainly be the sort
of “conjectural” or “hypothetical” injury insufficient to establish
Article III standing. Lujan v. Defenders of Wildlife, 504 U.S.
555, 560 (1992) (quoting Whitmore v. Arkansas, 495 U.S. 149,
155 (1990)) (internal quotation marks omitted).

     Petitioners also seem to overlook the economic fact that the
integrated utilities hardly furnish themselves station power for
free; they “pay” an opportunity cost, and because the utilities
typically sell power to retail customers, that cost may well be the
retail price. Of course, an independent generator procuring its
own power either from a remote location or from behind the
meter is also incurring an opportunity cost — the wholesale
price (which is lower than the retail price). But as counsel
implied at oral argument, if the generator is also charged a retail
price for that station power, it would seem it is at a competitive
disadvantage because it suffers, in a sense, a “double charge.”
Ironically, then, independent generators might have a strange
incentive to draw station power from the grid instead of
producing it on site, because at least then they would forego the
opportunity cost (even if they still paid retail rates). In that
situation, there might not be a significant economic difference
between independent generators and the integrated utilities.
                                12

     Nevertheless, assuming arguendo that the independent
generators are at something of a competitive disadvantage,
petitioners are unable to explain how FERC’s limited authority
can be employed to remedy its concern. Petitioners make no
real further attempt to connect FERC’s jurisdiction over
transmission to state netting rules (understandably in light of our
prior opinion); instead, their focus is on FERC’s wholesale
jurisdiction.

     The Commission concluded on remand, however, that its
own prior decisions had already rejected its wholesale
jurisdiction as a basis for regulating station power. In PJM
Interconnection, LLC, 94 FERC ¶ 61,251 (2001) (“PJM II”), the
Commission specifically confronted the question of whether it
had wholesale jurisdiction over the third-party provision of
station power. FERC held that when station power is acquired
in such a manner, “the energy being sold is not sold for resale,
and therefore it is not a transaction which we can regulate under
the [Federal Power Act].” Id. at 61,891. FERC likewise held
that when a generator self-supplies, either on-site or remotely,
“there is no sale (for end use or otherwise),” id., so no means of
procuring station power could plausibly be construed as a sale
for end use subject to FERC’s wholesale jurisdiction.

     PJM II also rejected the claim that the third-party provision
of station power was within FERC’s jurisdiction because it
“affects or relates” to wholesale services. That station power
was a necessary input to energy production did not constitute a
sufficient “nexus” with wholesale transactions to justify the
assertion of jurisdiction. Id. at 61,894; see also City of
Cleveland, Ohio v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985)
(“[T]here is an infinitude of practices affecting rates and service.
The statutory directive must reasonably be read to require the
recitation of only those practices that affect rates and service
significantly, that are realistically susceptible of specification,
                                 13

and that are not so generally understood in any contractual
arrangement as to render recitation superfluous.”). The
Commission reiterated its reasons for rejecting wholesale
jurisdiction in this context in PJM Interconnection, LLC, 95
FERC ¶ 61,333, at 62,186-87 (2001) (“PJM III”).

     Despite this authority, Calpine claims that it presents
arguments for wholesale jurisdiction that FERC has not yet
considered. Petitioners insist they are not relying on the station-
power-as-necessary-input rationale rejected in the PJM cases,
but rather on the notion that “there is a direct mathematical
relationship between the amount of generator-supplied energy
available for sale at wholesale and the amount of energy used
for station power.” In Calpine’s view, the amount of consumed
energy that may be netted against gross power directly
determines how much energy is deemed available for sale at
wholesale, so a netting interval is really just a regulation of the
wholesale market.

     Calpine offers the hypothetical of a generator that consumes
1 MWh of station power each day over the course of a 30-day
month and then produces 100 MWh on the last day (all other
days the generator is inactive). Under the tariff’s monthly
netting, the generator would be deemed to have self-supplied the
full 30 MWh, so it would be assessed neither transmission nor
retail charges. The station power would be netted against its
gross output (100 MWh), so the generator would receive
compensation at wholesale for 70 MWh (though all 100 MWh
would actually be sold in real time upon being produced).

      But suppose (as is the case) that FERC lacks jurisdiction to
set netting intervals for retail charges and that a state established
hourly netting for this purpose. Under this system, the generator
would be able to net only 1 MWh against its gross output (that
is, the 1 MWh used on the last day of the month when the full
                                 14

100 MWh were produced), so the generator would then pay
retail charges on the remaining 29 MWh of station power. A
“trapped energy” problem arises, according to Calpine, because
the generator would be permitted to sell only 70 MWh at
wholesale. In other words, the generator would have to pay
retail costs for the 29 MWh, but that energy would still be netted
against the generator’s gross output and thus reduce its total
compensation. According to petitioner, this “trapped energy”
creates a conflict between state and federal law that warrants
preemption of any contrary state regulations.

     As the Commission points out, we already considered and
rejected a conflicts claim in Southern California Edison:

         It is, of course, true that under differing netting periods
         FERC can conclude that no transmission for station
         power took place in a month in which California would
         recognize retail sales of that power, but that is hardly
         a conflict. As we have noted, in an unbundled market,
         transmission and power are procured through separate
         transactions. And, as we recognized in Niagara
         Mohawk, the netting periods for power and
         transmission need not be the same.4

    4
       Calpine attempts to bolster its conflicts theory by relying on
Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953 (1986).
That case concerned a FERC wholesale-rate proceeding allocating
power between two affiliated generators and the TVA; FERC
determined how much power the generators were entitled to receive
from the TVA, and the generators’ subsequent wholesale sales were
governed by FERC-filed rates. Id. at 955-56. The Supreme Court
held that FERC’s order preempted a state-commission order that used
a different allocation of power between the generators and the TVA
for the purpose of assessing retail charges. Id. at 955.

    While the facts of Nantahala are intricate, the key distinction is
                                  15

603 F.3d at 1002. Moreover, Calpine’s theory of “trapped
energy” relies on the fundamental misconception that the netting
interval determines how much energy is available for sale at
wholesale.

     It is true that different netting regimes may determine how
much a generator earns at wholesale — as we have explained,
a generator would prefer to avoid retail charges entirely and
receive wholesale compensation only for net output, rather than
be paid for its entire gross output but then pay retail charges on
station power (because retail rates are higher than wholesale
rates). But the netting interval does not determine how much
energy is actually available at wholesale. As Calpine itself
acknowledges, “because electric energy generally cannot be
stored, even for a second, generators are permitted to sell the
energy they produce in real time at prevailing market rates.”
The netting interval is, in essence, a kind of billing convention
that determines (at the end of the month) how much a generator
will be assessed for transmission and retail charges. While it
does have an impact on the value of the generator’s wholesale
output, it does not affect the actual amount of that output.

    Therefore, as we understand Calpine’s hypothetical, if the
generator pays for 29 MWh at retail, it would receive



that the state order in that case effected an actual conflict with FERC-
jurisdictional wholesale regulations — the state used different figures
for the same calculation, effectively concluding that “the FERC-
approved wholesale rates [were] unreasonable.” Id. at 966. Though
the state was ultimately setting retail rates, those rates were based on
an allocation of power (for wholesale) directly at odds with FERC’s
order. There is no such conflict here, because different netting
intervals may be used to assess retail and transmission charges, and
such differences affect only the value of energy at wholesale, not its
allocation between users.
                                 16

compensation at wholesale for 99 MWh (the last day’s net
output under an hourly netting interval), rather than just the 70
MWh they would have been paid for under monthly netting.
Indeed, the Commission addressed this exact problem in its
order denying rehearing and noted that “[m]ovants acknowledge
. . . that ‘energy payments to the generator would be calculated
based on the full 100 MW-hours,’ subject to netting adjustments
for other charges assessed by the CAISO during the relevant
billing interval.”5

     Calpine repeatedly characterizes the revised tariff as
determining how much of a generator’s output is allocated as
self-supplied station power. The “allocation of power” concept
is clearly an attempt to fit this case under our decision in
Entergy Services, Inc. v. FERC, 400 F.3d 5 (D.C. Cir. 2005).
That case concerned a utility’s practice of first allocating a
generator’s output to its scheduled transactions, with the
remainder allocated to its “host load” — generally, an industrial
customer — and then, if the generator’s output was insufficient
to serve its host load, supplying the shortfall under a retail tariff.
FERC directed the utility to cease this “discriminatory allocation
methodology” and refund charges assessed under retail rates.
Id. at 6.

     Although the order in Entergy seemed to touch on retail
charges, we determined that FERC had not exceeded its
jurisdiction, because “[t]he rates at issue related to what Entergy
should have considered as wholesale service provided by
Entergy to [the generators], which is clearly within the


     5
       At oral argument, counsel for petitioners appeared to again
concede this point. The exact numbers differed from those used in
Calpine’s brief, but counsel seemed to acknowledge that the generator
would receive compensation for the full 99 MWh — the net output
delivered to the grid over the applicable netting interval.
                               17

Commission’s regulatory jurisdiction.” Id. at 8. In other words,
the transaction for which the utility was charging retail rates
was, in fact, a wholesale service, so FERC had wholesale
jurisdiction over the utility’s allocation of power.

     That situation — where utilities were treating wholesale
transactions as retail sales — is worlds apart from the present
case, which deals with FERC’s authority to regulate truly local
charges. As our analysis thus far should make clear, the tariff’s
netting interval does not “allocate power” between energy
consumed as station power and energy available at wholesale;
it simply determines under what conditions generators will be
assessed transmission and retail charges for their use of station
power. This question is one of cost, not allocation of power.
While the regulation of transmission charges is undoubtedly
within FERC’s jurisdiction, retail charges are not.

     In sum, we think the Commission’s jurisdictional
determination was not arbitrary or capricious. But even
assuming it was reasonable, Calpine maintains that FERC
improperly failed to consider the effect that its orders would
have on the justness and reasonableness of CAISO’s tariff.
Petitioners argue that the generators would not have participated
in the voluntary station-power program had they known that
FERC’s netting interval would not govern retail sales. The tariff
is voluntary and generators may deregister at any time, but
Calpine suggests that generators could be retroactively charged
under California retail tariffs during the time in which the
revised tariff was in effect. In light of these concerns,
petitioners argue that the Commission’s refusal to reevaluate the
revised tariff on remand was itself arbitrary and capricious.

    The generators’ concerns in this regard may be
understandable, but the Commission was not required to
address them in this particular proceeding. First, Edison
                                18

appealed FERC’s extension of its station-power policies to
California in August 2005 (seven months before the station-
power revisions took effect), sought authorization in 2006 to
impose retail and other load-based charges on generators under
the revised tariff, and filed tariffs in 2009 specifying that retail
charges might be assessed if the Commission’s orders were
overturned on appeal. The generators were therefore on notice
that they could be assessed retail charges for station power
depending on the outcome of this litigation.

     Second, and more importantly, the generators have
alternative means of alleviating any potential grievances
stemming from retroactive charges.           As Calpine itself
acknowledges, it has the option to seek relief directly from the
California Public Utility Commission. And if Calpine believes
that the retroactive assessment of retail chargers is unjust and
unreasonable in violation of the Federal Power Act, it can
petition FERC for relief at that time. The Commission correctly
noted that its task on remand was “limited to implementation of
the jurisdictional findings of the Court of Appeals.” Its failure
to reevaluate the justness and reasonableness of the tariff
revisions in this proceeding, therefore, was not arbitrary and
capricious.

   Calpine’s petition for review is denied, and the
Commission’s orders on remand are affirmed.

                                                       So ordered.
