CALPINE CORPORATION, et al., Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent. Cogeneration Association of California, et al., Intervenors.
No. 11-1122.
United States Court of Appeals, District of Columbia Circuit.
Decided Dec. 18, 2012.
Argued Sept. 19, 2012.
702 F.3d 41
Michael Alcantar, Donald E. Brookhyser, Robert C. Fallon, and Brian M. Meloy were on the brief for intervenors Electric Power Supply Association, et al. in support of petitioners.
Robert M. Kennedy, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With him on the brief was Robert H. Solomon, Solicitor.
Jennifer L. Key argued the cause for intervenor Southern California Edison Company. With her on the brief were Charles G. Cole, Jennifer Hasbrouck, and Anna J. Valdberg. Roger E. Collanton and Daniel Shonkwiler entered appearances.
Before: ROGERS and KAVANAUGH, Circuit Judges, and SILBERMAN, Senior Circuit Judge.
Opinion for the Court filed by Senior Circuit Judge SILBERMAN.
SILBERMAN, Senior Circuit Judge:
For the third time, we consider FERC‘s authority to regulate public-utility charges to independent generators for the latter‘s use of “station power” —the electricity necessary to operate a generator‘s requirements for light, heat, air conditioning, etc.
I.
We explained the legal and economic background of the electrical energy market in Niagara Mohawk Power Corp. v. FERC, 452 F.3d 822 (D.C.Cir.2006), and Southern California Edison Co. v. FERC, 603 F.3d 996 (D.C.Cir.2010), but we will again summarize. Generators may procure station power through one of three means: (1) “on-site” self-supply, which redirects some of the station‘s outbound generated electricity for internal use (also called “behind-the-meter” production); (2) “remote” self-supply, in which power is obtained from an affiliated, off-site facility; or (3) “third-party” supply, in which power is drawn off the grid from unaffiliated providers.
Historically, electrical utilities were vertically integrated and typically acted as local monopolies—they owned generation, transmission, and distribution facilities and sold these services as a bundled package in their service areas. Utilities obviously did not charge themselves for the use of station power at their generating facilities; rather, they simply subtracted (“netted“) the energy consumed as station power against their gross output. But in 1996 FERC issued Order 888, which effectively unbundled generating from transmission and distribution services. The Commission accomplished this goal by requiring utilities to file open-access tariffs that offered rates to all customers on an equal basis—basically, utilities could not prefer their own affiliates over independent generators. Order 888 also encouraged the creation of non-profit independent system operators (“ISOs“) to reduce the market power of utilities and ensure competitive rates; the California Independent System Operator (“CAISO“) is one such entity.
Generators have an economic interest in a longer netting interval because it affords a greater opportunity to send power to the grid, which would make up for what is consumed. Utilities, by contrast, would prefer shorter netting intervals to enable higher retail charges against independent generators. A generator is only paid for its net output of energy to the grid, so even when the net output is positive, consumption of station power reduces the amount the generator is paid for its production. But retail rates are higher than wholesale rates, so a generator would rather have its station power netted against the total it delivers at wholesale than pay for station power at retail.
The legal issue that triggered this series of cases is how the authority to set netting intervals for different purposes meshes with the Federal Power Act‘s division of jurisdiction between federal and state authorities. Section 201(b) of the Act gives FERC jurisdiction over the “transmission of electric energy in interstate commerce”1 and the “sale of electric energy at wholesale in interstate commerce,” as well as “all facilities for such transmission or sale.”
FERC approved a tariff establishing an hourly netting period for the Pennsylvania-New Jersey-Maryland energy market and later approved an amendment expanding the netting interval to one month (if a generator‘s net output over a month was positive, then any energy a generator drew from the grid was simply netted against its gross output and no retail charges were permitted). Utility companies raised objections arguing that any third-party provision of station power (and indeed, the generator‘s own production of station power)1 was a retail sale outside of FERC‘s jurisdiction. FERC rejected this position because, in its view, if a generator‘s net output was positive, no sale had occurred.
The Commission instead agreed with the position advanced by a group of generators that the station-power netting interval used to determine when to assess transmission fees should be the same period used to calculate when the provision of station power constitutes a retail sale. A “transmission fee” is a fee assessed for the transmission of energy across the electrical grid; it is often called an “access charge” because it is assessed when a party is treated as “accessing” the grid. Netting intervals are used for transmission as well because whether a generator has positive or negative output over a given interval determines what energy is deemed to be transmitted across the grid.
In Niagara Mohawk, we noted that “[p]etitioners’ statutory argument [was] not insubstantial,” that the Commission‘s rationale was “a bit confusing,” and that FERC had not “clearly articulated why [transmission] jurisdiction permits it to determine that no sale of any kind—including a retail sale—takes place when the generator takes station power from the grid.” 452 F.3d at 828. We declined, however, to resolve that question on the merits because of a major concession by the petitioners that FERC had the authority to set an hourly netting interval, just not to expand the interval to one month. Id. Because we saw no principled difference between hourly and monthly netting with regard to FERC‘s jurisdiction, we were able to resolve that case solely on this concession.
But the issue reappeared. Shortly after the Commission‘s orders in the New York market, Duke Energy—a California independent generator—filed a complaint with FERC seeking to compel CAISO to also move from hourly to monthly netting. Southern California Edison—a utility—made the same objection that retail sales were outside of FERC‘s jurisdiction; the Commission again rejected this position, denying that a retail sale took place if a generator was net positive. It ordered CAISO to revise its tariff to conform with the Pennsylvania-New Jersey-Maryland and New York orders, and CAISO amended its tariff to provide for monthly netting.2
Edison responded to the revised tariff by trying an alternative basis to charge for station power. Its new proposal sought to assess direct stranded cost3 and consump-
In Southern California Edison, we considered the jurisdictional question that we had avoided in Niagara Mohawk. Edison—careful to avoid the Niagara Mohawk concession—insisted that it would exceed FERC‘s jurisdiction to set any netting interval regulating “retail sales,” regardless of length. The Commission again purported to rely on its authority over interstate transmission, rather than wholesale jurisdiction, but it failed to demonstrate any real connection between transmission and the netting intervals governing retail sales for use of station power. Instead, it just denied that retail sales were involved. Accordingly, we said:
[W]e do not understand why FERC is empowered to conclude that a retail sale has not taken place unless it can claim the transaction is, instead, a wholesale sale or a transmission. To simply declare that the state lacks jurisdiction because FERC believes no retail sale has taken place really begs the jurisdictional question. Unless a transaction falls within FERC‘s wholesale or transmission authority, it doesn‘t matter how FERC characterizes it.
S. Cal. Edison, 603 F.3d at 1000-01. We also rejected the Commission‘s assertion that allowing different netting periods for transmission charges and retail sales would create a “conflict” for preemption purposes, as well as an argument by intervening generators that inconsistent netting intervals would result in “trapped” energy. Id. at 1001. We therefore vacated and remanded on the basis that FERC‘s approval of the revised tariff exceeded its authority.
The Commission issued a new order on remand, acknowledging that it lacked a jurisdictional basis to determine when the provision of station power constitutes a retail sale and indicating that the netting interval in the CAISO tariff could only govern Commission-jurisdictional transmission charges, not retail charges. A group of California generators—including Calpine, the petitioner in this case—filed requests for rehearing and clarification, but FERC reaffirmed its original order on remand. The Commission explained that this decision was not “an unexplained departure from prior policy, but rather a change compelled by a Court of Appeals’ finding on the scope of our jurisdiction.” Calpine petitioned for review of FERC‘s orders on remand.
II.
Calpine‘s argument on appeal is that the Commission over-read our decision in Southern California Edison and failed to consider alternate bases for its initial approval of the tariff. In Calpine‘s view, Southern California Edison held only that the Commission had failed to adequately explain its jurisdiction and that FERC, indeed, has authority under both its transmission and wholesale jurisdiction to set netting intervals for retail sales. As such, the orders on remand were an arbitrary and capricious departure from the netting-interval policies established in the Pennsylvania-New Jersey-Maryland and New York orders. FERC maintains that we definitively rejected the transmission-jurisdiction argument and that previous Commission decisions disclaimed reliance on wholesale jurisdiction as a basis to regulate third-party provision of station power.
Our opinion was, of course, limited to the arguments raised before us; it is axiomatic that agency decisions may not be affirmed on grounds not actually relied upon by the agency. See SEC v. Chenery Corp., 318 U.S. 80, 87-88, 63 S.Ct. 454, 87 L.Ed. 626 (1943). Calpine is therefore correct that Southern California Edison did not specifically preclude FERC from asserting alternate bases for jurisdiction upon remand—either with some other theory to connect its jurisdiction over transmission to the generator‘s station power, or as Calpine primarily argues, by relying on FERC‘s jurisdiction over wholesale. Our opinion did note that we failed to see any strong basis for jurisdiction on this latter basis, S. Cal. Edison, 603 F.3d at 999 n. 5, but FERC had not relied on its wholesale jurisdiction, so it is fair to say we did not decide this question. Admittedly, therefore, FERC exaggerates the impact of our prior decision. It was certainly open to FERC to consider petitioners’ alternate bases for jurisdiction. FERC‘s response to petitioners’ new arguments is terse, to be sure, but we think those arguments are difficult to understand and ultimately fallacious.
To take a step back, petitioners’ asserted injury is essentially that independent generators are discriminated against compared to the few remaining integrated utilities—those that maintain their own generating capacity—and that this discrimination undermines the effectiveness of Order 888‘s effort to unbundle the power industry to achieve a competitive market for energy generation. Discrimination allegedly occurs, as we noted, because the integrated utilities do not pay for station power—they simply take it from their own generator—whereas the independent generators must, under certain circumstances, pay a retail charge for their own station power. (Petitioners make no distinction between generators that take station power from the grid or supply it themselves from either their own remote location or “behind the meter.“)
One difficulty we see with petitioners’ argument is that the length of a netting period for station power shouldn‘t matter except to measure the degree of a generator‘s alleged damage. According to petitioners’ logic, any retail charge for station power imposed on independent generators is inherently discriminatory. Yet petitioners implicitly concede that a monthly netting period is acceptable, which undermines their asserted principle. In that respect, petitioners’ position approaches
Petitioners also seem to overlook the economic fact that the integrated utilities hardly furnish themselves station power for free; they “pay” an opportunity cost, and because the utilities typically sell power to retail customers, that cost may well be the retail price. Of course, an independent generator procuring its own power either from a remote location or from behind the meter is also incurring an opportunity cost—the wholesale price (which is lower than the retail price). But as counsel implied at oral argument, if the generator is also charged a retail price for that station power, it would seem it is at a competitive disadvantage because it suffers, in a sense, a “double charge.” Ironically, then, independent generators might have a strange incentive to draw station power from the grid instead of producing it on site, because at least then they would forego the opportunity cost (even if they still paid retail rates). In that situation, there might not be a significant economic difference between independent generators and the integrated utilities.
Nevertheless, assuming arguendo that the independent generators are at something of a competitive disadvantage, petitioners are unable to explain how FERC‘s limited authority can be employed to remedy its concern. Petitioners make no real further attempt to connect FERC‘s jurisdiction over transmission to state netting rules (understandably in light of our prior opinion); instead, their focus is on FERC‘s wholesale jurisdiction.
The Commission concluded on remand, however, that its own prior decisions had already rejected its wholesale jurisdiction as a basis for regulating station power. In PJM Interconnection, LLC, 94 FERC ¶ 61,251 (2001) (“PJM II“), the Commission specifically confronted the question of whether it had wholesale jurisdiction over the third-party provision of station power. FERC held that when station power is acquired in such a manner, “the energy being sold is not sold for resale, and therefore it is not a transaction which we can regulate under the [Federal Power Act].” Id. at 61,891. FERC likewise held that when a generator self-supplies, either onsite or remotely, “there is no sale (for end use or otherwise),” id., so no means of procuring station power could plausibly be construed as a sale for end use subject to FERC‘s wholesale jurisdiction.
PJM II also rejected the claim that the third-party provision of station power was within FERC‘s jurisdiction because it “affects or relates” to wholesale services. That station power was a necessary input to energy production did not constitute a sufficient “nexus” with wholesale transactions to justify the assertion of jurisdiction. Id. at 61,894; see also City of Cleveland, Ohio v. FERC, 773 F.2d 1368, 1376 (D.C.Cir.1985) (“[T]here is an infinitude of practices affecting rates and service. The statutory directive must reasonably be read to require the recitation of only those
Despite this authority, Calpine claims that it presents arguments for wholesale jurisdiction that FERC has not yet considered. Petitioners insist they are not relying on the station-power-as-necessary-input rationale rejected in the PJM cases, but rather on the notion that “there is a direct mathematical relationship between the amount of generator-supplied energy available for sale at wholesale and the amount of energy used for station power.” In Calpine‘s view, the amount of consumed energy that may be netted against gross power directly determines how much energy is deemed available for sale at wholesale, so a netting interval is really just a regulation of the wholesale market.
Calpine offers the hypothetical of a generator that consumes 1 MWh of station power each day over the course of a 30-day month and then produces 100 MWh on the last day (all other days the generator is inactive). Under the tariff‘s monthly netting, the generator would be deemed to have self-supplied the full 30 MWh, so it would be assessed neither transmission nor retail charges. The station power would be netted against its gross output (100 MWh), so the generator would receive compensation at wholesale for 70 MWh (though all 100 MWh would actually be sold in real time upon being produced).
But suppose (as is the case) that FERC lacks jurisdiction to set netting intervals for retail charges and that a state established hourly netting for this purpose. Under this system, the generator would be able to net only 1 MWh against its gross output (that is, the 1 MWh used on the last day of the month when the full 100 MWh were produced), so the generator would then pay retail charges on the remaining 29 MWh of station power. A “trapped energy” problem arises, according to Calpine, because the generator would be permitted to sell only 70 MWh at wholesale. In other words, the generator would have to pay retail costs for the 29 MWh, but that energy would still be netted against the generator‘s gross output and thus reduce its total compensation. According to petitioner, this “trapped energy” creates a conflict between state and federal law that warrants preemption of any contrary state regulations.
As the Commission points out, we already considered and rejected a conflicts claim in Southern California Edison:
It is, of course, true that under differing netting periods FERC can conclude that no transmission for station power took place in a month in which California would recognize retail sales of that power, but that is hardly a conflict. As we have noted, in an unbundled market, transmission and power are procured through separate transactions. And, as we recognized in Niagara Mohawk, the netting periods for power and transmission need not be the same.4
It is true that different netting regimes may determine how much a generator earns at wholesale—as we have explained, a generator would prefer to avoid retail charges entirely and receive wholesale compensation only for net output, rather than be paid for its entire gross output but then pay retail charges on station power (because retail rates are higher than wholesale rates). But the netting interval does not determine how much energy is actually available at wholesale. As Calpine itself acknowledges, “because electric energy generally cannot be stored, even for a second, generators are permitted to sell the energy they produce in real time at prevailing market rates.” The netting interval is, in essence, a kind of billing convention that determines (at the end of the month) how much a generator will be assessed for transmission and retail charges. While it does have an impact on the value of the generator‘s wholesale output, it does not affect the actual amount of that output.
Therefore, as we understand Calpine‘s hypothetical, if the generator pays for 29 MWh at retail, it would receive compensation at wholesale for 99 MWh (the last day‘s net output under an hourly netting interval), rather than just the 70 MWh they would have been paid for under monthly netting. Indeed, the Commission addressed this exact problem in its order denying rehearing and noted that “[m]ovants acknowledge ... that ‘energy payments to the generator would be calculated based on the full 100 MW-hours,’ subject to netting adjustments for other charges assessed by the CAISO during the relevant billing interval.”5
Calpine repeatedly characterizes the revised tariff as determining how much of a generator‘s output is allocated as self-supplied station power. The “allocation of power” concept is clearly an attempt to fit this case under our decision in Entergy Services, Inc. v. FERC, 400 F.3d 5 (D.C.Cir.2005). That case concerned a utility‘s practice of first allocating a generator‘s output to its scheduled transactions, with the remainder allocated to its “host load“—generally, an industrial customer—and then, if the generator‘s output was insufficient to serve its host load, supplying the shortfall under a retail tariff. FERC directed the utility to cease this “discriminatory allocation methodology” and refund charges assessed under retail rates. Id. at 6.
That situation—where utilities were treating wholesale transactions as retail sales—is worlds apart from the present case, which deals with FERC‘s authority to regulate truly local charges. As our analysis thus far should make clear, the tariff‘s netting interval does not “allocate power” between energy consumed as station power and energy available at wholesale; it simply determines under what conditions generators will be assessed transmission and retail charges for their use of station power. This question is one of cost, not allocation of power. While the regulation of transmission charges is undoubtedly within FERC‘s jurisdiction, retail charges are not.
In sum, we think the Commission‘s jurisdictional determination was not arbitrary or capricious. But even assuming it was reasonable, Calpine maintains that FERC improperly failed to consider the effect that its orders would have on the justness and reasonableness of CAISO‘s tariff. Petitioners argue that the generators would not have participated in the voluntary station-power program had they known that FERC‘s netting interval would not govern retail sales. The tariff is voluntary and generators may deregister at any time, but Calpine suggests that generators could be retroactively charged under California retail tariffs during the time in which the revised tariff was in effect. In light of these concerns, petitioners argue that the Commission‘s refusal to reevaluate the revised tariff on remand was itself arbitrary and capricious.
The generators’ concerns in this regard may be understandable, but the Commission was not required to address them in this particular proceeding. First, Edison appealed FERC‘s extension of its station-power policies to California in August 2005 (seven months before the station-power revisions took effect), sought authorization in 2006 to impose retail and other load-based charges on generators under the revised tariff, and filed tariffs in 2009 specifying that retail charges might be assessed if the Commission‘s orders were overturned on appeal. The generators were therefore on notice that they could be assessed retail charges for station power depending on the outcome of this litigation.
Second, and more importantly, the generators have alternative means of alleviating any potential grievances stemming from retroactive charges. As Calpine itself acknowledges, it has the option to seek relief directly from the California Public Utility Commission. And if Calpine believes that the retroactive assessment of retail chargers is unjust and unreasonable in violation of the Federal Power Act, it can petition FERC for relief at that time. The Commission correctly noted that its task on remand was “limited to implementation of the jurisdictional findings of the Court of Appeals.” Its failure to reevaluate the justness and reasonableness of the tariff revisions in this proceeding, therefore, was not arbitrary and capricious.
Calpine‘s petition for review is denied, and the Commission‘s orders on remand are affirmed.
So ordered.
Notes
The tariff‘s general policy toward transmission fees is therefore to charge the shipper. In third-party retail sales, the utility ships energy to the generator, so the utility pays the access charge. But in the case of remote self-supply, the generator is shipping energy to itself (between facilities), so the generator pays the access charge.
While the facts of Nantahala are intricate, the key distinction is that the state order in that case effected an actual conflict with FERC-jurisdictional wholesale regulations—the state used different figures for the same calculation, effectively concluding that “the FERC-approved wholesale rates [were] unreasonable.” Id. at 966, 106 S.Ct. 2349. Though the state was ultimately setting retail rates, those rates were based on an allocation of power (for wholesale) directly at odds with FERC‘s order. There is no such conflict here, because different netting intervals may be used to assess retail and transmission charges, and such differences affect only the value of energy at wholesale, not its allocation between users.