
    603 F.3d 996
    SOUTHERN CALIFORNIA EDISON COMPANY, Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent Northern California Power Agency, et al., Intervenors.
    Nos. 05-1327, 08-1384.
    United States Court of Appeals, District of Columbia Circuit.
    Argued April 5, 2010.
    Decided May 4, 2010.
    
      Jennifer L. Key argued the cause for petitioner. With her on the hriefs were Charles G. Cole, Alice E. Loughran, Jennifer Hasbrouck, and Anna J. Valdberg.
    Robert M. Kennedy, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With him on the brief were Thomas R. Sheets, General Counsel, and Robert H. Solomon, Solicitor.
    Ashley C. Parrish argued the cause for intervenors Dynegy Moss Landing, LLC, et al. in support of respondent. With him on the brief were Neil L. Levy, David G. Tewksbury, Michael J. Rustum, Woody N. Peterson, David C. Dickey, and Christopher C. O’Hara. Betsy R. Carr, Gretchen Schott, and Robert C. Fallon entered appearances.
    Before: SENTELLE, Chief Judge, GARLAND, Circuit Judge, and SILBERMAN, Senior Circuit Judge.
   Opinion for the Court filed by Senior Circuit Judge SILBERMAN.

SILBERMAN, Senior Circuit Judge:

FERC approved a tariff filed by the California Independent System Operator (“CAISO”), manager of California’s electric power transmission grid. Southern California Edison petitions for review of that FERC order because the tariff permitted generators of electricity to avoid paying significant retail charges for the energy they used — whether self-generated or not — for their own heating, lighting, air conditioning and office equipment needs, called “station power.” Petitioners assert that FERC, which has undoubted jurisdiction to regulate wholesale sales and transmission charges, has exceeded its authority by insisting that the same method used for calculating transmission charges for station power be used to calculate retail charges.

I

As we explained once before in Niagara Mohawk Power Corp. v. FERC, 452 F.3d 822 (D.C.Cir.2006), involving the New York market, the Commission ordered the unbundling of electric energy markets in Order 888, whereby vertically integrated utilities that owned generation, transmission and distribution facilities and sold them as a package were obliged to sell transmission services separately. They were required to file open access transmission tariffs applicable to both their own electrical transmissions and those provided to independent generators. The order also encouraged the creation of non-profit independent system operators (ISOs) to ensure competitive pricing of transmission services and reduce the market power of the utilities. CASIO is one those ISOs.

Just as in New York, unbundling caused a sea change in California. The three largest investor-owned utilities divested most — but not all — of their generating facilities and now operate primarily as owners of transmission facilities and providers of retail services. The companies that purchased generating facilities from the utilities, by contrast, sell wholesale power. FERC has jurisdiction over wholesale sales and transmission, whereas the states maintain jurisdiction over retail distribution.

Under this new regimen, the generators’ use of “station power” became a contentious issue. Prior to unbundling, utilities which owned and operated the generators would not, of course, charge themselves for the use of station power; they simply subtracted (“netted”) them own use against them gross output. But now, when the generating facilities use station power— even when they get it from their own facilities — it is arguably functionally equivalent to a retail sale falling within the jurisdiction of the states, not FERC. That raises the question of how to calculate properly the charges the utilities can impose on the generators for their use of station power. In other words, what is the appropriate netting period by which it should be determined how much power a generator took for its own station power needs? FERC has the undeniable right to approve the netting methodology to determine how much electricity generators deliver to and take from the grid for transmission purposes, but in both Niagara Mohawk and this case, the FERC-approved tariff required the same methodology for both transmission and local use.

In a series of orders involving the Pennsylvania-New Jersey-Maryland electricity market and the New York electricity market, FERC set forth its policies relating to station power procurement and delivery. FERC first approved a tariff filed by the independent operator of the Pennsylvania-New Jersey-Maryland market allowing generators to net the station power it consumed against the station power it supplied on an hourly basis. As we explained in Niagara Mohawk, 452 F.3d at 825, under that tariff, generators that pulled station power off the grid for fifty minutes but supplied in excess of that amount in the next ten minutes would be deemed to have supplied the net amount to the grid and consumed nothing. FERC later accepted a modification of the tariff that changed the netting period from one hour to one month. As should be apparent, if a generator is permitted to net its power use against its power output on a monthly basis, as opposed to an hourly basis, its costs will be lower — we are led to believe considerably lower — because a generator could often produce enough power in a month to totally avoid any retail charges, but that is more difficult if the netting period is only an hour. FERC rejected arguments that the provision of station power constituted retail sales outside its jurisdiction on the ground that when a generator is net positive over a month no sale has taken place. FERC later approved a one-month netting period in a tariff filed by the New York ISO.

In 2004, shortly after FERC issued its orders in the Pennsylvania-New Jersey-Maryland and New York markets, Duke Energy, an independent generator in California filed a complaint asking FERC to compel the CAISO to switch from a one-hour netting interval to a monthly interval. The generator also asked that FERC preempt any state-authorized retail charges for generators that are net positive for a month. Edison, the petitioner here, objected, arguing that FERC lacked jurisdiction over retail energy sales. FERC, however, determined that the CAI-SO tariff did not conform to its station power policies as set forth in the Pennsylvania-New Jersey-Maryland and New York orders. It ordered CAISO to revise its tariff and added that because a one month netting interval had become a standard, FERC would require strong justification for any other netting interval. Edison unsuccessfully sought rehearing and then sought review in this court. We held that petition in abeyance pending FERC approval of a revised CAISO tariff, which it later did.

Edison again sought rehearing of FERC’s approval of the revised tariff, but in the interim, proposed to alter its retail tariff on file with the California Public Utilities Commission. This time Edison proposed to assess stranded cost or consumption charges rather than retail delivery charges on what it regarded as net positive generators. Edison contended that the state could allow it to assess such charges even if FERC determines that no sale had taken place. But the generators asked FERC to reject that approach as well in its response to Edison’s rehearing petition.

FERC again denied rehearing, relying on its jurisdiction over the transmission of station power. It also rejected Edison’s alternative argument that it could charge generators even though they were net positive for a month for stranded costs or consumption charges. According to the Commission, such charges would impair the ability of generators to utilize the netting provisions of CAISO’s tariff and would force them to pay “for fictitious energy purchases, when they are, in fact, self-supplying.” FERC relied on our decision in Niagara Mohawk — which was issued while the rehearing request was pending before the Commission — in which we denied a challenge to the one-month netting period approved by FERC for the New York market. When petitioners sought review of this order, it was consolidated with the first petition initially held in abeyance.

II

The issue before us is stark. Petitioners assert that FERC, by insisting that the netting period it approved to calculate energy delivered to and taken from the grid by generators for transmission charges must also govern charges the utilities seek to impose for the generator’s own use of power, has exceeded its jurisdiction.

It should be noted that although FERC insists that it can determine that no retail sale has taken place (or that a consumption charge is legitimate) it does not rest on its wholesale jurisdiction but rather only on its jurisdiction over transmission. Its primary justification in both its order and before us is our own opinion in Niagara Mohawk where, to be sure, we rejected a similar argument presented by New York utilities and the New York State Public Service Commission. But we think FERC overreads that case. We noted then that “[pjetitioner’s statutory argument is not insubstantial,” that the Commission’s rationale is “a bit confusing,” and, perhaps even more skeptically, “that the Commission has not clearly articulated why [its jurisdiction over interstate transmission] permits it to determine that no sale of any kind — including a retail sale — takes place.” 452 F.3d at 828. Indeed that troubling case was resolved based on a concession petitioners made — not made by petitioners here. In Niagara Mohawk, it was conceded that FERC could, within its authority, dictate an hourly netting period for retail sales; petitioners only objected to the tariff’s monthly netting period. We could discern no principled basis for distinguishing those two periods as it related to FERC’s jurisdiction. If the Commission could legally require an hourly netting period for retail sales it seemed analytically impossible to challenge a monthly netting period on jurisdictional grounds.

The Commission contends that elsewhere in our opinion we rested on more than petitioner’s concession, but that is not so. We did say that Order 888 “did not buttress petitioner’s jurisdictional argument,” just because FERC interpreted it as treating large industrial consumers who took their power directly from generators as subject to retail sales charges. Id. at 829. But that is the opposite situation from the case before us. By allowing the states to impose retail charges on end users who were ostensibly taking wholesale purchases, FERC was allowing states to prevent the bypassing of utilities (in order to permit utilities to recover stranded costs) by regulating in an area that FERC arguably could have reserved for itself.

Still FERC (and the intervenor) assert that whatever we said in Niagara Mohawk, we could not have rested on petitioner’s concession because we were under an independent obligation to determine FERC’s jurisdiction. In support of that rather extraordinary claim — it is not the more familiar argument that a court has an independent duty to determine its jurisdiction — the Commission relies on Columbia Gas Transmission Corp. v. FERC, 404 F.3d 459 (D.C.Cir.2005). That is quite a reach. In that case FERC argued that it had jurisdiction to enforce a tariff filing covering “gathering facilities,” over which FERC ostensibly lacked jurisdiction, because no one had objected to the filing. We rejected that argument pointing out that FERC could not obtain jurisdiction merely because a party had failed to raise a jurisdictional objection at the time of the filing. Id. at 462-63. The parties’ “waiver” could not confer jurisdiction on FERC. The petitioner in that case did ultimately object to FERC’s jurisdiction before the Commission and, more importantly, did so in our court. A party can and does waive any argument not presented in our court except those going to our own jurisdiction or similar structural issues and a concession is analogous to a waiver. The Columbia Gas case is, thus, obviously inapposite.

In this case, by contrast to Niagara Mohawk, petitioners have consistently maintained that FERC has no authority to set any netting period to determine whether a retail sale occurs or to determine whether the utilities are othexwise permitted to impose consumption charges. We therefore must consider FERC’s (and intervenor’s) arguments independent of Niagara Mohawk. The Commission claims that it is not encroaching on California’s jurisdiction over retail sales because no retail sale has taken place if in a month a generator delivers more electricity to the grid than it takes. But it might be asked why a month, rather than a longer period, during which it would be even less likely for a generator to be regarded as net negative. Ironically, FERC’s one month netting period to determine whether a retail sale took place implicitly concedes (somewhat analogous to petitioner’s concession in Niagara Mohawk) whether a retail sale occurs depends, in its view, on the length of the netting period, which seems rather arbitrary and unprincipled— certainly as a jurisdictional standard.

Perhaps of even greater difficulty, we 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. And, of course, FERC’s assertion doesn’t ever purport to answer petitioner’s argument that the utilities are, in any event, entitled to impose a consumption charge.

The Commission appears to alternatively assert that to recognize the utilities’ right to use a different netting period for generators use of station power as a retail sale under state law would cause a conflict with FERC’s different netting period for transmission. That is a familiar sort of preemption argument, but we do not see the conflict. After all FERC has succeeded through its unbundling initiative in creating separate markets for wholesale sales, transmission, and retail sales and distribution. Why should different pricing techniques cause a conflict? The Commission relies on Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477 (D.C.Cir.2009) and Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C.Cir.2007), but we think those cases do not support FERC because the impact on state jurisdiction in both cases was indirect and incidental.

In the Connecticut case, petitioners challenged the Commission’s authority to approve the “installed capacity requirement,” under its wholesale and transmission jurisdiction, a mechanism in the New England independent service operator’s tariff that sets the amount of capacity that must be maintained to ensure reliable operation of the bulk power system. The petitioners in that case argued that this constituted a de facto regulation of generation facilities, a matter exempted from the Commission’s jurisdiction. We rejected the argument, explaining that even though a higher “installed capacity requirement” may provide a market incentive for the construction of additional generation facilities, it was not an impermissible direct regulation of generation facilities. 569 F.3d at 481-82 (emphasis added). And in Nat’l Ass’n of Regulatory Util. Comm’rs, petitioners argued that the Commission could not regulate facilities that were jointly owned by private firms and states because the Federal Power Act exempts states from federal regulation. We easily rejected that challenge noting that the argument offered by petitioners could allow utilities to escape regulation by simply partnering with a nonjurisdictional co-owner. We approved FERC’s conclusion that it could regulate “notwithstanding incidental effects on nonjurisdictional entities.” 475 F.3d at 1281 (emphasis added). Here by contrast FERC’s order does not just sideswipe state jurisdiction; it attacks it frontally.

Intervenors, a group of independent generators asserting a conflict theory not advanced by FERC, claim that inconsistent methods of netting will result in generator’s costs being “trapped.” They draw upon a Supreme Court case, Nantahala Power and Light Co. v. Thornburg, 476 U.S. 953, 106 S.Ct. 2349, 90 L.Ed.2d 943 (1986). There a utility bought power wholesale from the TVA and sold it at retail in North Carolina. The North Carolina PUC calculated the utilities costs differently (lower) than did FERC in setting the wholesale rate with the result that the utility could not recover its wholesale costs at retail — power would have to have sold at a loss. It was in that sense that the Supreme Court held utilities costs were “trapped” and FERC’s wholesale rate regulation would be undermined; therefore the state’s cost calculation was preempted. We do not see any such claim in this case, but, in any event, FERC did not rely on this rationale in any of the orders under review, so we could not affirm on this basis under SEC v. Chenery Corp., 318 U.S. 80, 87-88, 63 S.Ct. 454, 87 L.Ed. 626 (1943), even if we thought it meritorious.

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. 452 F.3d at 830. In that regard, petitioners point out that CAISO’s tariff uses an hourly netting period for certain “transmission-related services.” It is thus possible for a generator to incur “transmission-related service” charges while not having to pay for transmission itself, which under FERC’s logic, would also seem to be a conflict, yet FERC did not object to that portion of the tariff.

The Commission is rather obviously concerned about the competitive position of the independent generators vis-a-vis those utilities who still maintain their own generator capacity. Indeed, that appears to be the underlying policy reason that drives FERC’s opinions. But FERC has yet to explain why that general concern can be grounds to preempt the state’s authority to set the netting period for station power— i.e., the pricing mechanism — in the retail market or to allow utilities to impose consumption charges.

Accordingly we vacate and remand for further proceedings consistent with this opinion.

So ordered. 
      
      . See PJM Interconnection, LLC, 94 FERC ¶ 61,251 at 61,891-92 (2001), reh'g denied, 95 FERC ¶ 61,333 (2001).
     
      
      
        . See Nine Mile Point Nuclear Station LLC v. Niagara Mohawk Power Corp., 105 FERC 1161,336 (2003).
     
      
      . Duke Energy Moss Landing LLC v. Cal. Indep. Sys. Operator Corp., 109 FERC ¶ 61,170 (2004).
     
      
      . See Cal. Indep. Sys. Operator Corp., 125 FERC ¶ 61,072 (2008).
     
      
      . That is not to suggest that we see any stronger basis for FERC to rest on that ground.
     
      
      . We also concluded that FERC's refusal to extend that fiction to New York's generators was not unreasonable. Id. at 829.
     
      
      . FERC argues that the petitioners in this case made the same concession as the Niagara Mohawk petitioners by failing to object to a portion of the tariff allowing "Permitled Netting.” But the "Permitted Netting” provision does not impose a netting period for retail sales and so is unlike the issue conceded by the Niagara Mohawk petitioners.
     