Richard BLUMENTHAL, Attorney General for the State of Connecticut, Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent NEPOOL Industrial Customer Coalition, et al., Intervenors, 384 U.S. App. D.C. 222

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 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 reliable supply of energy during times of high demand, but were infrequently used because them 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 eost-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 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 Foiward 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.

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 entities 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 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 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. § 825(b). 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 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, 103 S.Ct. 2856, 77 L.Ed.2d 443 (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, 88 S.Ct. 1344, 20 L.Ed.2d 312 (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, — U.S. -, 128 S.Ct. 2733, 2738, 171 L.Ed.2d 607 (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. 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 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 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, — U.S. -, 128 S.Ct. 2733, 171 L.Ed.2d 607 (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, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974); see also In re Permian Basin, 390 U.S. at 796-98, 88 S.Ct. 1344 (explaining that there is not one reasonable rate but rather a “zone of reasonableness”); Fed. Power Comm’n v.

Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (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 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 eost-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-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. 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, 88 S.Ct. 1344.

The Connecticut electricity market presents “intensely practical difficulties” demanding a solution from FERC, id. at 790, 88 S.Ct. 1344, 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 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 superi- or 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. . 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. .

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.