Connecticut Department of Public Utility Control v. Federal Energy Regulatory Commission

569 F.3d 477, 386 U.S. App. D.C. 320, 2009 U.S. App. LEXIS 13349, 2009 WL 1754607

• Court: Court of Appeals for the D.C. Circuit
• Decided: June 23, 2009
• Docket: 07-1375, 07-1460, 08-1175
• Status: Published

Opinion

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 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, 91 S.Ct. 1592, 29 L.Ed.2d 74 (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 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 Com mission disfavors such agreements because they “ ‘suppress marketTclearing 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 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 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 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, 104 S.Ct. 2778, 81 L.Ed.2d 694 (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] prohibits] 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 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 NE-POOL 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.” 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 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 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 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” NE-POOL 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 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 (D.C.Cir.1987), 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 “[cjapacity 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 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.