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Midwest ISO Transmission Owners v. Federal Energy Regulatory Commission

July 16, 2004


On Petitions for Review of Orders of the Federal Energy Regulatory Commission

Before: Ginsburg, Chief Judge, and Sentelle and Roberts, Circuit Judges.

The opinion of the court was delivered by: Roberts, Circuit Judge

Argued April 23, 2004


1. In the bad old days, utilities were vertically integrated monopolies; electricity generation, transmission, and distribution for a particular geographic area were generally provided by and under the control of a single regulated utility. Sales of those services were "bundled," meaning consumers paid a single price for generation, transmission, and distribution. As the Supreme Court observed, with blithe understatement, "[c]ompetition among utilities was not prevalent." New York v. FERC, 535 U.S. 1, 5 (2002).

In its pathmarking Order No. 888, FERC required utilities that owned transmission facilities to guarantee all market participants non-discriminatory access to those facilities. See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, FERC Stats. & Regs. ¶ 31,036, 31,635-36 (1996) (Order No. 888). That is, FERC required all transmission-owning utilities to provide transmission service for electricity generated by others on the same basis that they provided transmission service for the electricity they themselves generated. To effectuate this introduction of competition, FERC required public utilities to "functionally unbundle" their wholesale generation and transmission services by stating separate rates for each service in a single tariff and offering transmission service under that tariff on an open-access, nondiscriminatory basis. See New York, 535 U.S. at 11; see generally California Indep. Sys. Operator Corp. v. FERC, No. 02-1287, slip op. at 2-4 (D.C. Cir. June 22, 2004).

As the next step toward the goal of a more competitive electricity marketplace, Order No. 888 encouraged -- but did not require -- the development of multi-utility regional transmission organizations (RTOs). The concern was that the segmentation of the transmission grid among different utilities, even if each had functionally unbundled transmission, contributed to inefficiencies that impeded free competition in the market for electric power. Combining the different segments and placing control of the grid in one entity -- an RTO -- was expected to overcome these inefficiencies and promote competition. Order No. 888 at 31,730-32; see also Public Util. Dist. No. 1 of Snohomish County v. FERC, 272 F.3d 607, 610-11 (D.C. Cir. 2001). Better still if the RTO were run by an independent system operator -- an ISO. As envisioned by FERC, an ISO would assume operational control -- but not ownership -- of the transmission facilities owned by its member utilities, thereby "separat[ing] operation of the transmission grid and access to it from economic interests in generation." Order No. 888 at 31,654; see also id. at 31,730-32. The ISO would then provide open access to the regional transmission system to all electricity generators at rates established in "a single, unbundled, grid-wide tariff that applies to all eligible users in a non-discriminatory manner." Id. at 31,731; see also California Indep. Sys. Operator Corp., slip op. at 3-4. FERC called this type of separation of generation and transmission "operational unbundling," a step beyond "functional unbundling." Order No. 888 at 31,654. Although several parties to the 1996 rulemaking had requested that FERC require "operational unbundling" or even divestiture of transmission assets, it was FERC's considered judgment that "the less intrusive functional unbundling approach ... is all that we must require at this time." Id. at 31,655.

By 1999, FERC had come to a less sanguine view of the curative powers of functional unbundling. In FERC's view, inefficiencies in the transmission grid and lingering opportunities for transmission owners to discriminate in their own favor remained obstacles to robust competition in the wholesale electricity market. FERC concluded that these problems could be remedied through the establishment of RTOs, explaining that "better regional coordination in areas such as maintenance of transmission and generation systems and transmission planning and operation" was necessary to address regional reliability concerns and to foster regional competition. See Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089, 30,999 (1999) (Order No. 2000) (codified at 18 C.F.R. § 35.34) (citing Staff Report to FERC on the Causes of Wholesale Electric Pricing Abnormalities in the Midwest During June 1998, at 5-8 (Sept. 22, 1998)). FERC concluded that RTOs would: "(1) improve efficiencies in transmission grid management; (2) impose grid reliability; (3) remove remaining opportunities for discriminatory transmission practices; (4) improve market performance; and (5) facilitate lighter handed regulation." Order No. 2000 at 30,993; Public Util. Dist. No. 1, 272 F.3d at 611. To further encourage RTO development, FERC directed transmission-owning utilities either to participate in an RTO or to explain their refusal to do so. Public Util. Dist. No. 1, 272 F.3d at 612. Importantly, though, Order No. 2000 still did not require utilities to join RTOs; participation remained voluntary. See id. at 616.

For those utilities opting to join an RTO, Order No. 2000 retained a flexible approach, allowing the RTOs to employ a variety of ownership and operational structures, so long as the RTO established that it had certain required characteristics and functional capabilities. Id. at 611. FERC required, inter alia, that an RTO be regional in scope, 18 C.F.R. § 35.34(j)(2); "have operational authority for all transmission facilities under its control," id. § 35.34(j)(3); "be the only provider of transmission service over the facilities under its control," id. § 35.34(k)(1)(i); and "have the sole authority to receive, evaluate, and approve or deny all requests for transmission service," id. Thus, whatever its structure, once a utility made the decision to surrender operational control of its transmission facilities to an RTO, any transmissions across those facilities were subject to the control of that RTO.

2. In January 1998 (more than a year before Order No. 2000), several transmission-owning utilities in the Midwest sought FERC's approval for the transfer of operational control of their transmission facilities to an ISO known as Midwest ISO (MISO), which would be organized as a nonprofit, non-stock corporation. See Midwest Indep. Transmission Sys. Operator, Inc., 84 FERC ¶ 61,231, 62,138-39 (1998) ( MISO Initial Approval ). MISO would link up the transmission lines of the member transmission-owning utilities (MISO Owners) into a single interconnected grid stretching across the northern border of the U.S. from Michigan to eastern Montana, and reaching as far south as Kansas City, Missouri and Louisville, Kentucky. Under the MISO proposal, the MISO Owners would retain ownership of and physically operate and maintain their transmission facilities, subject to MISO's instructions. MISO would have functional control of the transmission system, with responsibility for calculating available transmission capability; receiving, approving, and scheduling transmission service requests; and providing or arranging for ancillary services under the tariff. MISO would also serve as the system security coordinator for the MISO Owners.

The MISO Owners concurrently applied for approval of MISO's open access transmission tariff. See id. at 62,166. Under the tariff, all customers would pay a single rate to use the entire MISO transmission system, based on the volume of power the customer carried on the system. The MISO Owners did not, however, propose to bring all of their own transmission loads immediately under that new open access tariff. Several of the MISO Owners were required to provide bundled retail service (generation and transmission) to consumers at rates frozen by state legislation, state regulatory agencies, or legal settlements. The MISO Owners proposed that such bundled retail loads be brought under the MISO tariff at the end of a six-year transition period, unless the state regulatory authorities unbundled those loads sooner. See id. at 62,167. Also, some MISO Owners had pre-existing bilateral agreements with other utilities to provide wholesale transmission service at fixed rates. The MISO Owners proposed that loads under such grandfathered agreements also remain outside of the tariff until the end of the transition period. Thus, only new wholesale and unbundled retail transmission loads would be immediately subject to the MISO tariff.

The MISO tariff included several mechanisms to recover the costs associated with running MISO. Relevant to this proceeding are Schedule 1 and Schedule 10. Under Schedule 1 of the tariff, MISO customers paid a charge for "Scheduling, System Control and Dispatch Service." MISO Open Access Transmission Tariff, Original Sheet No. 117. This charge covers MISO's primary value-added service -- management of the transmission grid. This Scheduling, System Control and Dispatch Service charge, though, was to be paid by the transmission customer directly to the MISO Owner providing transmission service; at least at first, it was not to be paid to MISO. Id.

Schedule 10 of the MISO tariff, the ISO Cost Adder, was designed to recover MISO administrative costs -- the "costs associated with running the ISO that are not recovered under Schedule 1." MISO Open Access Transmission Tariff, Original Sheet No. 136. Those costs included "costs associated with the Security Center, including capital costs and expenses, and administering the Tariff." Id. The Cost Adder was to be levied on a per megawatt basis and was calculated monthly by dividing MISO's eligible budgeted costs by the expected eligible transmission load. So, for example, if MISO's expected eligible costs for June 2004 were $100,000, and MISO anticipated one million megawatts of eligible load for that same month, under Schedule 10, MISO would levy a Cost Adder of 10 cents per megawatt on the eligible transmission load. The Cost Adder, though, was capped at 15 cents per megawatt,*fn1 with any unrecovered costs to be financed by MISO and deferred to the end of the six-year transition period, when the debt would be repaid on a five-year amortization schedule through a surcharge to all MISO customers. Id. Sheet Nos. 136-37.

Critically, the MISO tariff provided that only those transmission loads subject to the tariff rates would pay the ISO Cost Adder. Transmissions under state-mandated bundled retail plans and grandfathered agreements thus were not subject to the Cost Adder; only new ...

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