United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued November 17, 2008 Decided January 23, 2009
No. 07-1130
RICHARD BLUMENTHAL, ATTORNEY GENERAL
FOR THE STATE OF CONNECTICUT,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
NEPOOL INDUSTRIAL CUSTOMER COALITION, ET AL.,
INTERVENORS
On Petition for Review of Orders
of the Federal Energy Regulatory Commission
Michael C. Wertheimer, Assistant Attorney General,
Attorney General’s Office of State of Connecticut, argued the
cause for petitioner. With him on the briefs was John S.
Wright, Assistant Attorney General.
Robert A. Weishaar Jr. and Vasiliki Karandrikas were on
the brief for intervenor NEPOOL Industrial Customer
Coalition in support of petitioner.
Jennifer S. Amerkhail, Attorney, Federal Energy
Regulatory Commission, argued the cause for respondent.
2
With her on the brief were Cynthia A. Marlette, General
Counsel, and Robert H. Solomon, Solicitor.
Mark E. Nagle, William R. Derasmo, Anne K. Dailey, and
Kenneth R. Carretta were on the brief for intervenors
Dominion Energy Marketing, Inc., et al. in support of
respondent.
Theodore J. Paradise, Sherry A. Quirk, and Debra A.
Palmer were on the brief for intervenor ISO New England
Inc. in support of respondent.
Before: SENTELLE, Chief Judge, GRIFFITH, Circuit Judge,
and EDWARDS, Senior Circuit Judge.
Opinion for the Court filed by Circuit Judge GRIFFITH.
GRIFFITH, Circuit Judge: The Federal Energy Regulatory
Commission (FERC) rejected Connecticut’s challenge to the
structure of the state’s electricity market. FERC concluded
that the current “hybrid” market, in which some electricity
generators sell power at regulated rates and others at market
rates, is lawful, and that Connecticut’s proposed alternative
would not be. We hold that FERC’s denial of Connecticut’s
complaint was not arbitrary and capricious and thus deny the
petition for review.
I.
A.
Just over a decade ago, the New England electricity
market was highly regulated and relatively uncomplicated.
Generators sold electric energy wholesale at a regulated price
based on the cost of production to entities that transmitted that
3
energy for consumer use. In 1998, the market became less
regulated and more complicated when FERC approved a
proposal by the New England Power Pool—an alliance of
electric utilities—to move the market toward greater
competition. The proposal established ISO New England Inc.
(ISO-NE), a “private, non-profit entity to administer New
England energy markets and operate the region’s bulk power
transmission system,” NSTAR Elec. & Gas Corp. v. FERC,
481 F.3d 794, 796 (D.C. Cir. 2007), and created markets for
the sale of several products provided by generators: energy,
capacity (that is, the option of buying a particular amount of
energy in the future), and ancillary services that ensure the
availability of sufficient electricity at all times to meet
fluctuating levels of demand. Most importantly, under the
new regime, the range of electricity rates is set based on the
market and not on the generators’ costs alone. Individual
generators offer electricity to the market at a particular price.
ISO-NE determines the amount of electricity needed to meet
demand for a particular time period and sets the “market-
clearing price” at which there is no excess demand. This
market-clearing price, which all generators must use, is equal
to the bid price of the least expensive megawatt of power not
needed to meet demand—that is, the next unit of supply that
would be employed if demand were any higher.
Following the 1998 reforms, the New England electricity
market encountered problems with infrastructure weaknesses,
outdated generating units, and insufficient supply to meet
increasing demand. In some areas, including Connecticut, the
resulting transmission constraint often made it difficult to
transmit the available electricity supply to where it was
needed. Additionally, the inability of many high-cost (and
typically older) generating units to earn a profit in the
competitive markets threatened the reliability of the already
overburdened system. These units were needed to maintain a
4
reliable supply of energy during times of high demand, but
were infrequently used because their bids usually exceeded
the market-clearing price during times of low or normal
demand.
To address these problems, in 2002 FERC approved a
new set of operating rules, including Market Rule 1, for New
England. To respond to the problem of transmission
constraint, Market Rule 1 adopted “locational marginal
pricing.” ISO-NE had previously set the market-clearing price
using offers of electricity based only on meeting demand at
the least possible cost. Under locational marginal pricing, the
decision to use a particular offer also depends on the
feasibility of transmitting that power to where it is demanded.
The market-clearing price thus includes the additional cost of
dispatching power that is more expensive but which can be
transmitted to where it is needed. Market Rule 1 also
authorized the use of Reliability-Must-Run (RMR)
agreements to prevent high-cost generators from shutting
down for lack of profitability. An RMR agreement entitles the
generator to recover a full cost-of-service rate rather than the
rate it could obtain on the market. In turn, the generator must
offer all of its capacity into the energy markets at a
predetermined price representing actual marginal cost, and
any revenue from these market sales directly reduces the cost-
based payments made under the RMR agreement. RMR
agreements are available only to those generators that are
unable to supply their needed electricity without the cost-of-
service compensation of the agreements.
Market Rule 1 is a temporary and imperfect solution to
particular problems in the New England electricity market. By
ensuring the availability of sufficient power to meet demand,
Market Rule 1 meets a primary goal of system reliability.
That it does so by interfering with the efficient operation of a
5
purely competitive market is a problem. Recognizing that,
FERC encouraged ISO-NE to develop a new market structure
for New England to achieve the benefits of Market Rule 1
without the drawbacks. After extensive proceedings,
including a settlement agreement between ISO-NE and more
than one hundred interested parties, FERC approved a plan
for a new Forward Capacity Market. See Me. Pub. Utils.
Comm’n v. FERC, 520 F.3d 464 (D.C. Cir. 2008) (affirming
FERC’s approval order). Under the new scheme, ISO-NE will
hold annual capacity auctions three years before the capacity
is needed. The advance time will allow potential new
generators to compete in the auctions and plan for market
entry. The Forward Capacity Market will also continue
locational marginal pricing through separate auctions held in
“capacity zones” that are designated based on relative
transmission constraint.
Because of the three-year lead time, the Forward
Capacity Market will not take effect until June 1, 2010. In the
meantime, FERC has approved several interim measures to
ensure reliability of the electricity system in New England as
a whole and Connecticut specifically. It approved temporary
transition payments to New England generators between
2006, when the Forward Capacity Market was finalized, and
2010, when it will take effect. Additionally, FERC approved
more RMR agreements than anticipated under Market Rule 1.
This proliferation of RMR agreements was prompted by ISO-
NE’s determination in 2003 that all electric generation in
Connecticut is necessary for reliability—meaning all
Connecticut generators satisfy the first half of the RMR
eligibility test. Finally, FERC authorized the use of Peaking
Unit Safe Harbor (PUSH) bidding. PUSH bidding allows
generators in constrained areas that are operating at only 10%
of their capacity to offer supply into the markets at a higher
price than they otherwise could under prevailing market rules.
6
PUSH-eligible units tend to be those that only go into
operation during peak demand periods, and PUSH bidding
was supposed to enable them to earn sufficient revenue from
those periods to stay in the market. In January 2007, however,
FERC eliminated PUSH bidding, finding that it had not
worked as anticipated.
B.
These interim strategies did not meet with universal
support. On September 12, 2005, Connecticut Attorney
General Richard Blumenthal and other interested entities1
filed a complaint against ISO-NE with FERC. The complaint
charged that FERC’s changes to the electricity market
structure in Connecticut violate the requirement of the Federal
Power Act that all rates for the sale of electric energy, and all
rules and regulations affecting those rates, “shall be just and
reasonable,” 16 U.S.C. § 824e(a) (2006). The complainants
argued that what they termed the “hybrid” market—under
which some generators are compensated through RMR
agreements, others receive market rates, and still others (at the
time) operated under PUSH bidding rules—inherently
produces unjust and unreasonable rates.
The complainants’ theory was that high-cost generators,
which generally earn lower revenues in the market because
they cannot match the lower bid prices of more efficient
generators, were opting out of the market and into RMR
agreements that guaranteed they would recoup their costs.
Then, because these units must bid their (necessary) energy
1
Joining the Attorney General in the complaint were the
Connecticut Office of Consumer Counsel, the Connecticut
Municipal Electric Energy Cooperative, and Connecticut Industrial
Energy Consumers.
7
supplies into the market at marginal cost, the market-clearing
price was set based on the cost of service for these high-cost
units. Low-cost generators, on the other hand, continued to
collect market-based rates, reaping excessive rewards because
of the difference between their marginal costs and the inflated
market-clearing price. PUSH bidding exacerbated the
problem by further inflating the market-clearing price in much
the same way RMR agreements did. As a result, according to
Connecticut, “electric consumers in Connecticut are forced to
pay the higher of either cost-of-service rates under RMR
agreements or market-based rates for electricity.” Blumenthal
v. ISO New England, Inc. (Blumenthal I), 117 F.E.R.C.
¶ 61,038, at 61,167 (2006).
Connecticut’s theory was that the electricity market must
either be fully competitive or fully regulated. Therefore, it
asked FERC to amend Market Rule 1 to require that all
generators designated necessary for reliability—that is, under
ISO-NE’s 2003 decision, every generator in Connecticut—
apply for an RMR agreement. This relief would effectively
return the Connecticut market to the fully regulated system
that prevailed before ISO-NE was established.
FERC denied Connecticut’s complaint. See Blumenthal I,
117 F.E.R.C. ¶ 61,038. It determined that Connecticut had not
met its burden of proving that the system under Market Rule 1
is unjust and unreasonable and that its proposed solution
would be just and reasonable. Among the complainants, only
Attorney General Blumenthal filed an application for
rehearing. Blumenthal contested FERC’s failure to afford
Connecticut an evidentiary hearing on its complaint; FERC’s
failure to make a finding that the Connecticut electricity
markets are workably competitive; FERC’s failure to respond
to the argument that the Commission was required to make
such a finding; and FERC’s determination that existing rates
8
are just and reasonable. FERC denied Connecticut’s
application for rehearing, defended the procedural regularity
of its contested order, and reaffirmed its substantive
conclusions. See Blumenthal v. ISO New England, Inc.
(Blumenthal II), 118 F.E.R.C. ¶ 61,205 (2007).
Connecticut filed a timely petition for review with this
court. We have jurisdiction under 16 U.S.C. § 825l(b).2
II.
Connecticut argues that FERC unreasonably denied its
complaint. As the complainant in an action under § 824e,
Connecticut bore “the burden of proof to show that [the] rate,
charge, classification, rule, regulation, practice, or contract is
unjust [or] unreasonable.” 16 U.S.C. § 824e(b). Additionally,
as the advocate of a change in practice, Connecticut was
required to prove “that its proposed changes are just and
reasonable.” Atl. City Elec. Co. v. FERC, 295 F.3d 1, 10 (D.C.
Cir. 2002); see also La. Pub. Serv. Comm’n v. Entergy Corp.,
123 F.E.R.C. ¶ 61,188, ¶ 31 (2008). FERC denied the
2
Intervenors Dominion Energy Marketing, Inc., et al. argue that
Connecticut’s petition is an improper collateral attack on FERC’s
previous orders authorizing Market Rule 1, particular RMR
agreements, and PUSH bidding. As they point out, we lack
jurisdiction to consider an untimely collateral attack on an order
that “gave sufficient notice of the rule to which [petitioner] now
objects.” S. Co. Servs., Inc. v. FERC, 416 F.3d 39, 44 (D.C. Cir.
2005). But no previous order gave sufficient notice of the
cumulative effect of all the orders, as well as the factual
developments on which Connecticut’s petition depends, such as the
unanticipated proliferation of RMR agreements. For that reason, we
conclude that the petition for review is not an untimely collateral
attack.
9
complaint after finding that Connecticut had satisfied neither
burden.
We review FERC’s order to determine whether it is
“arbitrary, capricious, an abuse of discretion, or otherwise not
in accordance with law.” 5 U.S.C. § 706(2)(A) (2000). To
withstand review under this standard, FERC must have
“examine[d] the relevant data and articulate[d] a satisfactory
explanation for its action including a ‘rational connection
between the facts found and the choice made.’” Motor Vehicle
Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983) (citation omitted). “[T]he breadth and complexity of
the Commission’s responsibilities demand that it be given
every reasonable opportunity to formulate methods of
regulation appropriate for the solution of its intensely
practical difficulties.” In re Permian Basin Area Rate Cases,
390 U.S. 747, 790 (1968). In particular, “[t]he statutory
requirement that rates be ‘just and reasonable’ is obviously
incapable of precise judicial definition, and we afford great
deference to the Commission in its rate decisions.” Morgan
Stanley Capital Group Inc. v. Pub. Util. Dist. No. 1, 128 S.
Ct. 2733, 2738 (2008).
A.
The first question is whether FERC acted unreasonably in
concluding that Connecticut had not shown that existing rates,
rules, and practices are unjust and unreasonable. Connecticut
offers three arguments to show that it did. First, it contends
that FERC was required to determine that the state electricity
market as a whole is “workably competitive”—that is, that no
generator can exercise market power—before allowing any
generator to collect market-based rates. Second, Connecticut
asserts that FERC unreasonably rejected its evidence that
generators collecting market rates earned windfall profits.
10
Finally, Connecticut argues that FERC unreasonably
concluded that the hybrid nature of the market is not
inherently unjust and unreasonable. Connecticut is wrong on
all counts.
“Workably Competitive Market” Finding
Connecticut argues that this court’s precedent required
FERC to determine that the state electricity market as a whole
is workably competitive before it could conclude that it is just
and reasonable for any generator to receive market-based
rates. Connecticut further asserts that the market is not
workably competitive.
We have never held that FERC must establish the
competitiveness of an entire market before permitting any
participant to charge market-based rates. We have required
that, before FERC approves an individual seller’s use of
market-based pricing in lieu of cost-of-service regulation, it
must determine that “the seller and its affiliates do not have,
or adequately have mitigated, market power in the generation
and transmission of [electric] energy, and cannot erect other
barriers to entry by potential competitors.” La. Energy &
Power Auth. v. FERC, 141 F.3d 364, 365 (D.C. Cir. 1998);
see also Consumers Energy Co. v. FERC, 367 F.3d 915, 922–
23 (D.C. Cir. 2004); Elizabethtown Gas Co. v. FERC, 10 F.3d
866, 871 (D.C. Cir. 1993); Tejas Power Corp. v. FERC, 908
F.2d 998, 1004 (D.C. Cir. 1990). In other words, what matters
is whether an individual seller is able to exercise
anticompetitive market power, not whether the market as a
whole is structurally competitive.
As FERC explained, it satisfied this obligation when it
originally granted Connecticut generators market-based rate
authority in 1998. FERC determined that no seller exercised
11
market power at that time, and that if future transmission
constraints created the opportunity for market power, the
mitigation measures put in place by the New England Power
Pool proposal were adequate. See New England Power Pool,
85 F.E.R.C. ¶ 61,379, at 62,477–78 (1998); see also
Blumenthal II, 118 F.E.R.C. ¶ 61,205, at 61,931–32 & n.38.
Connecticut argues that FERC was required to revisit this
determination because the hybrid market structure enables
high-cost generators to “extract” RMR agreements or PUSH-
bidding eligibility by threatening to withhold supply. As
FERC explained, however, Connecticut has offered no
evidence of such threats. See Blumenthal II, 118 F.E.R.C.
¶ 61,205, at 61,932. Moreover, Connecticut has not explained
how a hypothetical exercise of market power by a generator
seeking cost-based compensation under an RMR agreement
would be relevant to the market power exercised by a
generator seeking to charge market-based rates—the relevant
inquiry under our precedent.
Because Connecticut offered no such evidence or
explanation, FERC reasonably relied on its continuing
oversight of the market to guard against potential abuses of
market power. FERC requires ISO-NE to file quarterly and
annual reports assessing the competitiveness of the market
based on transactional data reflecting the behavior of each
market participant. See, e.g., ISO NEW ENGLAND INC., 2007
ANNUAL MARKETS REPORT 152–76 (2008) (collecting and
analyzing data to assess market conditions for previous year).
Connecticut, citing two decisions of the Ninth Circuit, argues
that this oversight is inadequate. We disagree. Regular reports
based on “transaction-specific data” are precisely what the
Ninth Circuit held sufficient to comply with FERC’s
oversight obligations. California ex rel. Lockyer v. FERC, 383
F.3d 1006, 1014 (9th Cir. 2004). By contrast, both we and the
12
Ninth Circuit have held that FERC violates its oversight duty
when it imposes no reporting requirements on generators and
instead resorts to “largely undocumented reliance on market
forces as the principal means of rate regulation.” Farmers
Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 1508 (D.C.
Cir. 1984) (footnote omitted); see also Pub. Util. Dist. No. 1
v. FERC, 471 F.3d 1053, 1082 (9th Cir. 2006) (holding that
FERC could not defer to bilateral energy contract without
adopting any monitoring mechanism), aff’d, 128 S. Ct. 2733
(2008). The detailed reports filed by ISO-NE suffice to ensure
the continued competitiveness of the New England electricity
market. FERC was entitled to rely on those reports in
response to Connecticut’s bare allegations of anticompetitive
behavior.
Evidence of “Windfall Profits”
Connecticut next argues that FERC unreasonably rejected
its “direct verified evidence” that rates under the hybrid
market structure are unjust and unreasonable. Br. for Pet’r at
28. This evidence consists of two charts Connecticut
presented to FERC, one estimating the returns earned by three
market-rate generators between September 2004 and
September 2005, and one estimating the returns those three
plants would earn in 2006. The estimated returns varied from
44% to 257%. Connecticut argues that these estimates of
“grossly excessive” returns are prima facie evidence of unjust
and unreasonable rates.
The Supreme Court has repeatedly rejected the argument
“that there is only one just and reasonable rate possible . . .
and that this rate must be based entirely on some concept of
cost plus a reasonable rate of return.” Mobil Oil Corp. v. Fed.
Power Comm’n, 417 U.S. 283, 316 (1974); see also In re
Permian Basin, 390 U.S. at 796–98 (explaining that there is
13
not one reasonable rate but rather a “zone of
reasonableness”); Fed. Power Comm’n v. Hope Natural Gas
Co., 320 U.S. 591, 602 (1944) (noting that “the Commission
was not bound to the use of any single formula or
combination of formulae in determining rates”); Me. Pub.
Utils., 520 F.3d at 471 (“The Supreme Court has disavowed
the notion that rates must depend on historical costs and has
held that rates may be determined by a variety of formulae.”).
In particular, as FERC points out, market rates are expected
and permitted to be higher than marginal costs during times of
scarce supply, such as the twelve-month period shown on
Connecticut’s second chart. See Edison Mission Energy, Inc.
v. FERC, 394 F.3d 964, 968–69 (D.C. Cir. 2005); Interstate
Natural Gas Ass’n v. FERC, 285 F.3d 18, 32 (D.C. Cir. 2002)
(approving full deregulation of market despite spikes in price
during times of “extreme exigency”); see also Oral Arg.
Recording at 10:20–10:38 (counsel for FERC noting that the
period shown reflected a spike in gas prices following
Hurricane Katrina). At the same time that they reflect existing
scarcity, these high rates also serve a critical signaling
function: encouraging new development that will increase
supply. In fact, we recently vacated FERC’s approval of a
price-mitigation rule because it would have impaired this
price-signaling function. See Edison Mission, 394 F.3d at 969
(noting that although the rule might do some good, “the
Commission gave no reason to suppose that it does not also
wreak substantial harm—in curtailing price increments
attributable to genuine scarcity that could be cured only by
attracting new sources of supply”).
Thus, even if Connecticut’s estimates were correct,
FERC reasonably declined to consider them prima facie
evidence of unjust and unreasonable rates. But FERC also
explained that the estimates in the charts are not correct.
Rather, they are based on “numerous assumptions about the
14
actual cost-of-service values for the highlighted units,”
including the assumption that the average market-clearing
price in 2006 would be $90 per megawatt-hour; in fact, the
average was $70 per megawatt-hour. Blumenthal I, 117
F.E.R.C. ¶ 61,038, at 61,180. FERC’s refusal to treat the
charts as prima facie evidence of unjust rates was therefore
eminently reasonable.
Hybrid Market “Inherently Unjust and Unreasonable”
Connecticut’s argument to FERC rested most heavily on
its contention that the hybrid electricity market, in which
some generators receive market-based rates and some receive
cost-based rates, is inherently unjust and unreasonable. In
Connecticut’s view, generators can select whichever system
will provide them the most benefit: “Because generators
effectively have a choice to elect the ‘higher of’ either cost-
of-service or market compensation, rates are by definition
higher than they would be under either a fully competitive or
fully regulated market.” Br. for Pet’r at 31.
But this conclusion is not self-evident, as Connecticut
contends. As FERC explained in its orders, generators cannot
opt into and out of cost-based compensation depending on the
prevailing market prices. A generator must demonstrate
financial need before it can receive an RMR agreement or, in
the past, PUSH-bidding authorization. Moreover, an RMR
agreement remains in effect until the implementation of the
Forward Capacity Market and may only be canceled by ISO-
NE. Connecticut’s argument that generators can act
strategically to reap the highest possible rewards is not borne
out by the record evidence.
Likewise, Connecticut’s assertion that bids from
generators with RMR contracts artificially inflate the market-
15
clearing price fails to account for the restrictions imposed by
those contracts. A generator operating under an RMR
agreement must bid all of its available supply into the market
at its marginal cost. Contrary to Connecticut’s argument,
FERC explained that this requirement actually serves to lower
the market-clearing price. See Blumenthal I, 117 F.E.R.C.
¶ 61,038, at 61,177. Connecticut neither acknowledges the
bidding requirement nor contradicts FERC’s explanation of
its effects.
Connecticut also offers no information about the actual
prevailing electricity rates and no meaningful analysis of
whether those rates are just and reasonable. By contrast,
FERC thoroughly explained the difficulties posed by the New
England electricity market and the reasons for its response to
the problems. In regulating that market, FERC must contend
with transmission constraint, insufficient supply to meet high
demand, and outdated generation facilities and transmission
infrastructure. It encouraged the successful development of
the new Forward Capacity Market, which will address many
of these problems. Until that market can take effect, however,
FERC reasonably chose to employ interim measures to ensure
system reliability and to spur development and improvements.
RMR agreements keep necessary generation facilities in
operation, while the high returns earned by low-cost
generators charging market rates provide an incentive for the
development of new generation facilities as well as increased
efficiency on the part of existing generators. Furthermore,
higher prices are likely to affect consumers’ behavior,
reducing the strain on the system created by high demand. At
the same time, price caps and mitigation rules remain in place
to protect against anticompetitive behavior and excessive
rates.
16
FERC acknowledges the imperfections of these interim
solutions. But its defense of employing them in the period
before the Forward Capacity Market takes effect is thoroughly
reasoned and supported. Congress has entrusted the regulation
of the electricity industry to FERC, not to the courts. “A
presumption of validity therefore attaches to each exercise of
the Commission’s expertise.” In re Permian Basin, 390 U.S.
at 767. The Connecticut electricity market presents “intensely
practical difficulties” demanding a solution from FERC, id. at
790, and the Commission must be given the latitude to
balance the competing considerations and decide on the best
resolution. We defer to FERC’s reasonable approach here,
particularly in light of a complaint based on little more than
conjecture.
B.
To prevail on its complaint, Connecticut would have had
to prove not only that the existing market structure is unjust
and unreasonable, but also that its proposed alternative—a
requirement for all Connecticut generators to apply for RMR
agreements—would be just and reasonable. See Atl. City Elec.
Co., 295 F.3d at 10. This it has not done.
Connecticut makes little attempt to prove that it satisfied
its burden on this issue. It alleges that if the existing market
structure is unjust and unreasonable, mandating regulated,
cost-based compensation is “the only alternative method for
compensating generators.” Reply Br. for Pet’r at 26. This is a
facially flawed contention, given that another alternative—the
Forward Capacity Market—has met our approval and is being
put into place.
Strangely, Connecticut argues that if we were persuaded
that the existing market is unjust and unreasonable, we should
17
remand this matter for FERC to consider whether
Connecticut’s proposed alternative is just and reasonable. See
id. at 27. But FERC has already determined it is not. See
Blumenthal II, 118 F.E.R.C. ¶ 61,205, at 61,934; Blumenthal
I, 117 F.E.R.C. ¶ 61,038, at 61,181. Furthermore, FERC’s
rejection of Connecticut’s proposal was not arbitrary or
capricious. As FERC explained, the proposal would
unreasonably “restrain legitimate market revenues earned by
some generators” without a finding that those generators are
exercising market power, Blumenthal I, 117 F.E.R.C.
¶ 61,038, at 61,175, and would stifle the necessary price-
signaling function served by market-based rates, id. at 61,180.
FERC reasonably concluded that the current market structure
is the superior interim solution to ensure the workability of
the Connecticut electric power markets until the Forward
Capacity Market takes effect in 2010.
III.
For the foregoing reasons, we hold that FERC’s denial of
Connecticut’s complaint was neither arbitrary nor capricious.
Accordingly, Connecticut’s petition for review is
Denied.