United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued May 12, 2009 Decided June 23, 2009
No. 07-1375
CONNECTICUT DEPARTMENT OF PUBLIC UTILITY CONTROL,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
NEW ENGLAND POWER POOL PARTICIPANTS COMMITTEE, ET
AL.,
INTERVENORS
Consolidated with 07-1460, 08-1175
On Petitions for Review of Orders
of the Federal Energy Regulatory Commission
Randall L. Speck argued the cause and filed the briefs for
petitioner.
John S. Wright and Michael C. Wertheimer, Assistant
Attorneys General, Attorney General’s Office of State
of Connecticut, Jesse S. Reyes, Assistant Attorney
General, Attorney General’s Office of Commonwealth of
2
Massachusetts, and Lisa C. Fink were on the briefs for
intervenors Richard Blumenthal, Attorney General for the
State of Connecticut, Maine Public Utilities Commission, and
Massachusetts Department of Public Utilities in support of
petitioner. Lisa S. Gast entered an appearance.
James Bradford Ramsay, William H. Smith, Jr., Frank R.
Lindh, Mary F. McKenzie, Christopher E. Clay, Michael A.
Cox, Attorney General, Attorney General’s Office of State of
Michigan, Steven D. Hughey, Michael A. Nickerson, and
Patricia S. Barone, Assistant Attorneys General, David
D'Alessandro, Harvey L. Reiter, Anne Milgram, Attorney
General, Attorney General=s Office of State of New Jersey,
Margaret Comes, Deputy Attorney General, Jonathan D.
Feinberg, Gisele L. Rankin, John A. Levin, and Florence P.
Belser were on the brief of amici curiae National Association
of Regulatory Utility Commissioners et al. in support of
petitioner. Grace D. Reyes and Caroline Vachier, Assistant
Attorney General, Attorney General’s Office of State of New
Jersey, entered appearances.
Nancy H. Rogers, Attorney General, Attorney General's
Office of State of Ohio, and Duane W. Luckey and Thomas W.
McNamee, Assistant Attorneys General, were on the brief for
amicus curiae State of Ohio in support of petitioner.
Samuel Soopper, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on
the brief were Cynthia A. Marlette, General Counsel, and
Robert H. Solomon, Solicitor.
John N. Estes III argued the cause for intervenors New
England Power Pool Participants Committee, et al. With him
on the brief were Scott Phillip Myers, Paul Franklin Wight,
3
James C. Beh, Shay Dvoretzky, Larry F. Eisenstat, George E.
Johnson, and Christopher C. O'Hara.
Sherry A. Quirk and Montina M. Cole were on the brief
for intervenor ISO New England, Inc. in support of
respondent.
Barry S. Spector and Paul M. Flynn were on the brief of
amicus curiae PJM Interconnection, L.L.C. in support of
respondent.
Ashley C. Parrish and David G. Tewksbury were on the
brief for amicus curiae The Electric Power Supply
Association in support of respondent.
Before: TATEL, GARLAND, and GRIFFITH, Circuit Judges.
Opinion for the Court filed by Circuit Judge TATEL.
TATEL, Circuit Judge: Today we address a question we
have twice deferred: whether the Federal Energy Regulatory
Commission has jurisdiction to review something called the
Installed Capacity Requirement (ICR), a key input into the
market-based mechanism that determines transmission tariffs
and end-user costs in the New England bulk power system.
The question is presented here by the Connecticut Department
of Public Utility Control and allied intervenors, all petitioning
for review of various instances where the Commission has
approved or modified the amount of the ICR. Although the
details of this market mechanism are somewhat opaque and
surely complicated, the ultimate legal issue before us reduces
to a clear and simple one: does the Commission’s review of
the ICR constitute direct regulation of electrical generation
facilities? If so, it exceeds the Commission’s authority under
the Federal Power Act; if not, it falls within the Commission’s
4
jurisdiction over practices affecting wholesale rates. Finding
no direct regulation of electrical generation facilities in the
Commission’s review of the ICR, we deny the petitions for
review.
I.
“Capacity” is not electricity itself but the ability to
produce it when necessary. It amounts to a kind of call option
that electricity transmitters purchase from parties—generally,
generators—who can either produce more or consume less
when required. The penultimate and most proximate buyers
of capacity (before the consumers who ultimately shoulder the
costs in their utility bills) are called “load serving entities” or
LSEs—the public utilities that deliver electricity to end users.
The goal is for LSEs to purchase sufficient capacity to easily
meet expected peaks in electricity demand on their
transmission systems.
Because local LSEs will experience demand peaks at
different times, and because interconnected LSEs can easily
share excess capacity when necessary, these utilities can
capture considerable efficiencies through cooperative decision
making about how much capacity to buy as a whole and at
what cost. See generally Gainesville Utils. Dep’t v. Fla.
Power Corp., 402 U.S. 515, 518–20 & n.3 (1971) (explaining
reserve capacity efficiencies from interconnection). Indeed,
cooperation may be necessary to avoid a free rider problem,
where some utilities count on the capacity they expect others
to buy in order to support their own reliability. Accordingly
New England has a history of cooperative decision making
about capacity, dating back to the 1971 creation of the New
England Power Pool (NEPOOL), the voluntary association of
all New England public utilities that, subject to Commission
review, set capacity requirements for each individual utility
and administered “deficiency charges” for those that failed to
5
obtain their share. See Municipalities of Groton v. FERC, 587
F.2d 1296, 1300–03 (D.C. Cir. 1978). That role has since
shifted to ISO New England, Inc. (ISO-NE), a regional
transmission organization that administers open access to
transmission facilities in the New England bulk power system
pursuant to the Commission’s deregulatory mandate. See Me.
Pub. Utils. Comm’n v. FERC, 520 F.3d 464, 467–68
& n.2 (D.C. Cir. 2008) (describing ISO-NE); see generally
Transmission Access Policy Study Group v. FERC, 225 F.3d
667 (D.C. Cir. 2000) (affirming Commission’s open access
transmission approach to fostering competition). Despite this
cooperation, however, inefficiencies remained.
Lacking open market mechanisms for setting capacity
prices and quantities, ISO-NE struggled to incentivize
innovation and investment in the capacity market while
simultaneously suppressing costs. In an initial effort to
respond to concerns over short supply, ISO-NE entered into
“Reliability Must-Run” agreements with older and less
efficient generators, pursuant to which ISO-NE paid for their
inefficiencies so as to keep them on line and ensure system
reliability. But the Commission disfavors such agreements
because they “‘suppress market-clearing prices . . . and make
it difficult for new generators to profitably enter the market.’”
Me. Pub. Utils. Comm’n, 520 F.3d at 468 (quoting Devon
Power LLC, 103 F.E.R.C. ¶ 61,082, at 61,270 (2003)).
Responding to these concerns, ISO-NE endeavored to create a
different system with an “administratively-determined
demand curve that would establish the price and quantity of
capacity that must be procured” in the various sub-regions of
the New England grid. Id. (internal quotation marks omitted).
But this too ran into problems: it produced enormous
controversy over the shape of the hypothetical curve. Id. at
468 & n.3 (criticizing the very concept of a “demand curve”
constructed by a central decision maker). In short, these
6
efforts failed to harness the power of competitive markets in
determining the appropriate price of capacity, leading to
inaccurate or inefficient levels of investment in or
compensation for capacity providers.
Enter the Forward Capacity Market, which the
Commission approved as part of a settlement agreement
among New England power system stakeholders on June 16,
2006. See id. at 469. In the Forward Market—the details of
which are at issue here—capacity providers bid for contracts
three years in the future as part of a “descending clock
auction.” Here’s how it works. ISO-NE determines the
Installed Capacity Requirement, or ICR, which represents the
estimated amount of capacity the system as a whole will
require for reliability three years hence. It then announces the
starting price—by agreement, twice the estimated cost of new
entry—and capacity providers state an amount of capacity
they would be willing to offer at that price. If these offerings
exceed the ICR, ISO-NE lowers the offering price, which in
turn lowers the quantity offered in response. This descending
price clock “stops” when the quantity offered equals the ICR,
and that price point becomes the market clearing price. The
capacity charge for each utility in the system is thus its share
of the ICR multiplied by the clearing price.
Bidders in the Forward Market include existing
generators, new entrants who believe they can obtain the
necessary state and municipal permits to construct new
generation, and demand-side resources, including users who
can produce their own power or reduce their demand during
shortages. Their bids commit them to supply the amount they
offer at the clearing price. By using competitive bidding for
future capacity contracts, this system both incentivizes and
accounts for new entry by more efficient generators, while
7
ensuring a price both adequate to support reliability and fair to
consumers.
In Maine Public Utilities Commission v. FERC, we
reviewed a broad settlement among the many parties involved
in New England’s bulk power system and rejected a challenge
to the Commission’s authority to create and review the
operation of the Forward Market. 520 F.3d at 479–80. In so
doing, however, we expressly reserved the question whether
the Commission’s review of the ICR created an independent
jurisdictional problem, emphasizing that another pending
case—this one—presented that very question. Id. at 480.
When this issue was initially before us in 2007, we remanded
to the Commission so that it could explain the statutory basis
for its jurisdiction to review the ICR. See Conn. Dep’t of
Pub. Util. Control v. FERC, 484 F.3d 558, 560–61 (D.C.
Cir. 2007). On remand, the Commission explained its view
that “ISO-NE’s ICRs have a significant and direct effect on
jurisdictional rates and services, [and] therefore fall within
the Commission’s jurisdiction.” ISO New England, Inc., 122
F.E.R.C. ¶ 61,144, at 61,763 (2008). The case now returns to
us for review, having been consolidated with other petitions
presenting the same issue.
Notwithstanding our approval of the Forward Market in
Maine Public Utilities Commission, petitioners argue that the
Commission’s authority to approve or modify the ICR as part
of its review of ISO-NE’s transmission tariffs exceeds its
jurisdiction under the Federal Power Act. In their view, any
movement upward in the Installed Capacity Requirement
requires installing capacity, and under section 201 of the
Federal Power Act, the Commission “shall not have
jurisdiction . . . over facilities used for the generation of
electric energy.” 16 U.S.C. § 824(b)(1). The Commission
responds by emphasizing its broad power over practices
8
affecting wholesale rates, see 16 U.S.C. § 824e(a), and by
arguing that the effect of the ICR on new generation capacity
is sufficiently incidental to avoid section 201’s bar. We
afford Chevron deference to the Commission’s assertion of
jurisdiction. Okla. Natural Gas Co. v. FERC, 28 F.3d 1281,
1283–84 (D.C. Cir. 1994); see also Chevron U.S.A. v. Natural
Res. Def. Council, 467 U.S. 837, 842–43 (1984).
II.
A twin pair of concessions radically simplifies the legal
question before us. Petitioners concede that the Commission
may “determine[] just and reasonable capacity charges,”
Petrs.’ Reply Br. 28, and that it may set those charges so as to
incentivize the procurement or creation of additional capacity
to ensure system reliability, id. at 28–29. For its part,
the Commission concedes that while it has broad power
over practices affecting ISO-NE’s transmission tariffs,
“Connecticut is obviously correct that the [Act] prohibit[s] the
Commission from directly regulating generating facilities.”
Respt.’s Br. 22. Rephrased to fit the standard of review, these
concessions leave only one question: does setting the ICR
represent the kind of direct regulation of generation facilities
plainly forbidden by section 201? The answer is no. Our
precedent is substantially on point, and we think the
controversy stems in large part from the fact that the ICR is
woefully misnamed.
The “Installed Capacity Requirement” is misnamed
because increasing it doesn’t actually “require” anyone to
“install” any new “capacity” at all. State and municipal
authorities retain the right to forbid new entrants from
providing new capacity, to require retirement of existing
generators, to limit new construction to more expensive,
environmentally-friendly units, or to take any other action in
their role as regulators of generation facilities without direct
9
interference from the Commission. Of course, those choices
affect the pool of bidders in the Forward Market, which in
turn affects the market clearing price for capacity. And in an
extreme situation where local regulators utterly refused to
allow creation of any new capacity to offset increases in the
ICR, the price would rise towards the initial offering price of
two times the cost of new entry. But this is all quite natural: if
consumer-constituents of state commissions prefer to forbid
the construction of new power plants, they will appropriately
bear the costs of that decision, including paying more for
system reliability from older and less efficient units. Thus,
we think the ICR is better understood not as a capacity
requirement but as something more like a peak demand
estimate—perhaps, in FERC-speak, a PDE—and the purpose
of the Forward Market is only to locate the price at which
market incentives will be sufficient to meet that expected
demand. Because petitioners concede that ISO-NE and the
Commission could directly set the price of capacity at this
level precisely to incentivize procurement of resources
adequate to meet their estimate of peak demand, see Petrs.’
Reply Br. 28–29, and because this estimate necessarily affects
prices but not necessarily new capacity construction, we see
no direct regulation of generation facilities in violation of
section 201.
This brings us to our precedent, which explains
petitioners’ seemingly surprising—but in fact unavoidable—
concession. In Municipalities of Groton v. FERC, we
sustained the Commission’s jurisdiction to review the
“deficiency charges” that NEPOOL charged as ISO-NE’s
predecessor when member utilities failed to live up to their
share of NEPOOL’s reliability requirement. See 587 F.2d at
1300–03. We did so despite the fact that “the purpose behind
the deficiency charge” was “to motivate participants to
develop sufficient capacity to meet their load requirements.”
10
Id. at 1302. Indeed, we held it “sufficient for jurisdictional
purposes that the deficiency charge affects the fee that a
participant pays for power and reserve service, irrespective of
the objective underlying that charge.” Id. Petitioners are thus
compelled to concede that the Commission may directly
establish prices for capacity—or much the same, prices for
failing to acquire enough capacity—even for the express
purpose of incentivizing construction of new generation
facilities. That the Commission may do so directly would
seem to include the power to do so indirectly by setting a
target for capacity demand and using a market mechanism to
locate the price appropriate to that quantity.
In fact, LSEs have various means of responding to the
incentives produced by increases in the ICR short of building
new capacity. Public regulators aren’t even confined to a
choice between allowing construction of new capacity or
paying escalating costs. They may also seek capacity from
interconnected utilities outside the New England power
system or “demand response” contracts where users are
compensated for committing to use less electricity during
shortages. See ISO New England, 120 F.E.R.C. ¶ 61,234, at
61,978 (2007). The Commission explained:
‘capacity’ . . . is the product, and electrical
generating capacity is one means, but not the
only means, of producing that product. [An]
LSE could fulfill its capacity obligation to
ISO-NE by constructing new electrical
generating capacity but it could also add 50
MW of demand response and 50 MW of
capacity contracts (from inside or outside the
state), or any mix of the above. If a state
wishes to place controls on the amount or type
of electrical generating capacity built within
11
that state, or at particular locations within that
state, the Commission’s regulation of ISO-
NE’s calculation of ICR does not prevent it
from doing so. The capacity requirement that
ISO-NE places on an individual LSE may be a
factor in a state’s ultimate determination as to
how much electrical generating capacity is
built, and where and by whom. These are not,
however, the same determinations . . . .
Id. (footnotes omitted). Given this, petitioners’ observation
that public utilities have overwhelmingly responded to
increases in the ICR by choosing to allow construction of new
facilities over other alternatives has little relevance. See
Petrs.’ Opening Br. 36–37. This bare fact demonstrates only
that this option may be the cheapest, easiest, or most palatable
of the choices presented. In current market contexts,
constructing new generation facilities in response to a higher
ICR may even feel like an imperative. But petitioners have
posited no source for that feeling other than internalization of
the true costs of the alternatives, which is not only a
requirement for efficient market outcomes, but, again,
something the Commission may concededly pursue.
Petitioners also appear to argue that the Commission has
exceeded its jurisdiction not by directly compelling
construction of new generation facilities, but by compelling
LSEs to acquire a particular amount of capacity. This
argument fails for three interconnected reasons.
First, nothing in the Federal Power Act expressly
proscribes requiring LSEs to pay for a certain amount of
capacity. Section 201 prohibits the Commission from
regulating generation facilities but says nothing about its
power to review the capacity requirements that an entity like
12
ISO-NE imposes on member LSEs. Petitioners thus invoke
other provisions to support their argument that the
Commission lacks jurisdiction to compel LSEs to buy
specified amounts of capacity. These include section 207,
which allows the Commission, “upon complaint of a State
commission, . . . [to] determine the proper, adequate, or
sufficient service” required from an interstate utility and to
“fix the same by its order,” 16 U.S.C. § 824f, and section 215,
a reliability provision whose savings clause states that “[t]his
section does not authorize . . . the Commission . . . to set and
enforce compliance with standards for adequacy or safety of
electric facilities or services,” 16 U.S.C. § 824o(i)(2). Neither
section, however, unambiguously prohibits the Commission
from requiring LSEs to obtain adequate capacity. Section 207
actually grants authority to the Commission, and even if the
clause “upon complaint of a State commission” is read as
“only upon complaint of a State commission,” this section
seems to be about energy itself rather than capacity, see
§ 824f (“[T]he Commission shall have no authority to compel
. . . the public utility to sell or exchange energy when to do so
would impair its ability to render adequate service to its
customers.” (emphasis added)). Nor does anything in section
215(i) prohibit the Commission from requiring capacity
purchases—as a savings clause, it deals only with the
authority that section provides rather than what the Act as a
whole forbids, see § 824o(i).
Second, even if sections 207 and 215 clearly prohibited
the Commission from requiring LSEs to obtain a particular
amount of capacity, this isn’t the authority the Commission
claims. Instead, the Commission claims authority to review
the capacity charges that ISO-NE imposes on member utilities
to ensure they are just and reasonable. Because the ICR
impacts those charges in two ways—by affecting the market
clearing price for capacity in the Forward Market and by
13
affecting the size of each LSE’s proportionate share of the
ICR—the Commission claims authority to review it as an
integral determinant of the transmission tariffs within its
jurisdiction. Petitioners point to nothing in the record to
suggest that the Commission seeks authority to set a
reliability requirement rather than to ensure that the capacity
charges actually imposed by ISO-NE are fair to suppliers and
consumers. That reasonable concerns about system adequacy
might factor into the fairness of those charges is precisely
what brings them within the heartland of the Commission’s
section 206 jurisdiction, see § 824e(a).
Third, even if these statutory provisions could be read to
prohibit the Commission from requiring LSEs to make
adequate capacity purchases, and even if that is what the
Commission is doing, this particular camel has long
since entered—indeed, ransacked—the tent. Again, three
decades ago in Municipalities of Groton, we sustained the
Commission’s assertion of jurisdiction over “deficiency
charges” NEPOOL imposed on member LSEs that came
up short on their capacity requirements. See 587 F.2d
at 1300–03. There, the Commission determined that the
deficiency charges, which escalated in both amount and rate
based on the proportion by which an LSE fell short, unduly
discriminated against smaller entities, which would tend to
miss by a greater relative proportion if they missed at all. See
id. at 1302–03. We thought it irrelevant that the deficiency
charges were “designed as an incentive” for the purchase
or construction of adequate capacity so long as the
charges affected transmission rates otherwise within the
Commission’s jurisdiction. Id. at 1302. To be sure,
Municipalities of Groton dealt with a different issue—how to
calculate the deficiency charge rather than the capacity
requirement below which the deficiency charge kicked in.
But that distinction makes no difference. For one thing, the
14
ICR does affect the rate of the capacity charge: by changing
the clearing price in the Forward Market, it affects not only
each LSE’s share of the ICR, but also the price point
paid for capacity. Moreover, while the size of the capacity
requirement was not directly implicated in Municipalities of
Groton, it would be odd if the Commission could determine
that the rate of the deficiency charge was unfair but could say
nothing about a capacity requirement triggering those charges
at levels grossly unfair to suppliers or consumers.
Mississippi Industries v. FERC is similarly fatal to
petitioners’ argument. See 808 F.2d 1525, vacated in part on
other grounds, 822 F.2d 1104 (D.C. Cir. 1987). There we
held that the Commission’s authority over practices affecting
rates allowed it to review the allocation of capacity costs
among the various entities in the Middle South Utilities
system. See id. at 1540–45. We emphasized that “[c]apacity
costs are a large component of wholesale rates,” and agreed
with the Commission that, “in light of the [Middle South
system’s] integrated planning for generating capability on a
system basis,” the Commission could appropriately reallocate
those costs among the Middle South companies to prevent
unfairness to particular consumers. Id. at 1541. Petitioners
think that Mississippi Industries is irrelevant because the
Middle South system involved a level of integration unknown
in New England. But even if the level of integration at issue
in Mississippi Industries was unusual at the time or remains
unusual today, “integrated planning . . . on a system basis,” id.
at 1541 (emphasis omitted), is a long-standing feature of the
New England bulk power system, at least as far as capacity
decisions are concerned. See, e.g., Municipalities of Groton,
587 F.2d at 1300–03. Thus, Mississippi Industries, together
with Municipalities of Groton, teaches that there is nothing
special about capacity decisions that places them beyond the
Commission’s jurisdiction. Where capacity decisions about
15
an interconnected bulk power system affect FERC-
jurisdictional transmission rates for that system without
directly implicating generation facilities, they come within the
Commission’s authority.
Finally, petitioners argue that the ICR has no effect on
FERC-jurisdictional rates at all because, as a matter of
economic theory, the supply of capacity is actually perfectly
elastic and hence fixed at the long run cost of new entry. As
petitioners candidly conceded at oral argument, this may be
true in the theoretical world of economics textbooks, but is
almost certainly false in the real world outside them. Oral
Arg. Tr. 10–13. And even granting the hypothesis that the
market clearing price will equal the average cost of entry for
the mix of suppliers capable of providing capacity over the
relevant three-year run, the point of an auction mechanism
like the Forward Market is to use a best approximation of
demand and the power of competitive bidding to help locate
that price. Clairvoyant commissioners would have no need
for such a useful pricing device, but the real world decision
makers who use the Forward Market do so precisely for its
ability to evaluate prices. Thus, even if all the ICR did was
help to find the right price, it would still amount to a
“practice . . . affecting” rates. § 824e(a).
III.
Determination of the ICR affects rates within the
Commission’s jurisdiction and, in evaluating whether that
determination is just and reasonable, the Commission neither
regulates generation facilities in violation of section 201 nor
runs afoul of any other provision of the Federal Power Act.
The petitions for review are accordingly denied.
So ordered.