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Parties Involved:
Richard Blumenthal
Intervenor for Petitioner
Connecticut Department of Public Utility Control
Petitioner
Federal Energy Regulatory Commission
Respondent
State of Ohio
Amicus Curiae for Petitioner

Document Text:

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 

USCA Case #08-1175 Document #1186743 Filed: 06/23/2009 Page 1 of 15
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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, 

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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 

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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 

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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 

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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 

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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 

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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 

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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.” 

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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 

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that state, or at particular locations within that 

state, the Commission’s regulation of ISONE’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 

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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 

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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 

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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 

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an interconnected bulk power system affect FERCjurisdictional 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. 

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