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Sacramento Municipal Utility District v. Federal Energy Regulatory Commission

July 23, 2010

SACRAMENTO MUNICIPAL UTILITY DISTRICT, PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION, ET AL., INTERVENORS



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

Per curiam.

Argued February 25, 2010

Before: BROWN, GRIFFITH and KAVANAUGH, Circuit Judges.

Following the California energy crisis of 2000-01, the California Independent System Operator (California ISO or the ISO) began the process of redesigning California's electricity market. The Federal Energy Regulatory Commission (FERC or the Commission) issued a series of orders providing guidance on California ISO's proposals. Ultimately, in four orders issued between 2006 and 2008, the Commission approved the ISO's new market design, rejecting the numerous objections lodged by at least sixty-seven intervenors. Four parties-the Sacramento Municipal Utility District (Sacramento), the Imperial Irrigation District (Imperial), the City and County of San Francisco (San Francisco), and the San Diego Gas & Electric Company (San Diego)-now petition for review of these orders. Sacramento and Imperial challenge California ISO's "locational marginal pricing" rate design, arguing in particular that it is unreasonable and unlawful to charge customers for the marginal cost of transmission losses. San Francisco challenges the "local resource adequacy requirement" imposed by California ISO, claiming it deprives San Francisco of the value of a preexisting contract. Finally, San Diego and Sacramento challenge aspects of the financial mechanism California ISO devised to allow customers to hedge against congestion costs. We find no merit to these arguments and therefore deny the petitions for review.

I. Background

A. The Parties

"In 1996, the Commission ordered the national deregulation of electricity transmission services. Order No. 888 required utilities to 'unbundle' their electricity generation and transmission services and to file new 'open access' tariffs-modeled on a pro forma tariff included in the rulemaking-guaranteeing non-discriminatory access to their transmission facilities by competing generators." Sacramento Mun. Util. Dist. v. FERC, 428 F.3d 294, 295-96 (D.C. Cir. 2005) ("Sacramento I") (citing Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (Apr. 24, 1996) ("Order 888")).*fn1 Order 888 also encouraged public utilities "to participate in Independent System Operators ('ISOs')." Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 397 (D.C. Cir. 2004). "An ISO conducts the transmission services and ancillary services for all users of such a system, replacing the conduct of such services by the system owners . . . . FERC deems it crucial that an ISO be independent of the market participants so that decisions of policy, operation, and dispute resolution be free of the discriminatory impetus inherent in the old system." Id. (citing Order 888 at 31,731).

Thus, in 1996, the California legislature chartered California ISO, "a non-profit organization that took over operation (but not ownership) of many transmission facilities" in the state. Sacramento Mun. Utility Dist. v. FERC, 474 F.3d 797, 798 (D.C. Cir. 2007). California ISO maintains a tariff, subject to approval by the Commission, setting forth the terms, conditions, and rates under which it provides electricity service to customers. Sacramento, Imperial, San Francisco, and San Diego are all "load-serving entities," meaning they acquire electricity from California ISO for delivery to end-use consumers. The wholesale rates they pay are dictated by the ISO's tariff.

However, these four petitioners are not all alike. San Diego is a privately-owned utility that became a "participating transmission owner" in California ISO by turning over operational control of its transmission facilities to the ISO. See W. Area Power Admin. v. FERC, 525 F.3d 40, 44 (D.C. Cir. 2008). Thus, California ISO assumed the obligation to honor San Diego's preexisting transmission contracts. By contrast, Sacramento, Imperial, and San Francisco are publicly-owned "non-jurisdictional" utilities that opted not to become participating transmission owners of California ISO. (They are called "non-jurisdictional" because, as governmental entities, they are not subject to FERC's jurisdiction under §§ 205 and 206 of the Federal Power Act, see 16 U.S.C. § 824(f).) Accordingly, they own or co-own certain transmission facilities that are within California ISO's "balancing authority area"*fn2 but are not part of the ISO's grid. These entities retain "transmission ownership rights"- contractual entitlements to use such facilities.

B. The Market Redesign and Technology Upgrade

Proposal "In 2000, wholesale prices for electricity in California increased dramatically and resulted in the now-infamous California energy crisis." Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315, 1317 (D.C. Cir. 2004). This prompted California ISO, at the behest of the Commission, to begin redesigning California's electricity market to avoid any repetition of the 2000-01 crisis. California ISO's "market redesign and technology upgrade" proposal followed. Over the course of six years, the Commission issued more than thirty orders providing guidance to California ISO and its market participants on the various contours of the proposed changes.

The Commission ultimately approved California ISO's revised tariff in four orders issued between 2006 and 2008.*fn3 Three features of this tariff are challenged here: its incorporation of marginal loss charges into locational marginal prices, its local resource adequacy requirement, and its congestion revenue rights mechanism.

1. Locational Marginal Pricing

California ISO proposed to use "locational marginal pricing" (LMP) to set wholesale electricity prices. With an LMP-based rate structure, prices are designed to reflect the least-cost of meeting an incremental megawatt-hour of demand at each location on the grid, and thus prices vary based on location and time. Each LMP consists of three components: (i) the cost of generation; (ii) the cost of congestion; and (iii) the cost of transmission losses. See First Market Redesign Order ¶ 50. The first component refers basically to the baseline cost of serving load*fn4 anywhere on the system in the absence of congestion and transmission losses. Id. With respect to the second component, we have explained:

LMP . . . incorporates the cost of congestion into the price of energy. Under the LMP system, [an ISO] takes into account the limits on available transmission capacity when determining the price of energy at each node in its transmission grid. This results in higher energy prices at nodes that require the use of congested transmission lines and lower prices in less congested areas. . . . LMP [therefore] . . . giv[es] market participants incentives to avoid congestion-causing transactions [and] is also more economically efficient: scarce transmission capacity is allocated to those who value it most instead of being physically rationed.

Wis. Pub. Power, Inc. v. FERC, 493 F.3d 239, 250-51 (D.C. Cir. 2007). The third component, transmission losses, refer[s] to the amount of electric energy lost when electricity flows across a transmission system: it is a function of the square of the amount of the current flowing on the wire and of the resistance it encounters. In general, the current on a given transmission line remains a constant, and the loss associated with a single transmission of electricity is primarily a function of the distance the electricity is transmitted. [An ISO] must deliver to the electricity customer the entire amount contracted for, regardless of the inevitable loss, so a transmission customer [i.e., a load-serving entity] . . . generally compensates [the ISO] for lost energy either by providing more energy at the injection point than the electricity customer receives at the withdrawal point, or by providing energy in-kind to the transmitting utility.

Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 1, 2 (D.C. Cir. 2002) (citation omitted). In other words, unless the load-serving entity self-supplies sufficient electricity to make up for the amount lost during transmission, it must compensate the ISO for the losses.

Transmission losses can be calculated on either an "average" or a "marginal" basis. If transmission losses are simply averaged system-wide and allocated to all load-serving entities pro rata, "cross-subsidies" result: "parties that schedule[] long-distance transmissions pa[y] too little, while those that schedule[] shorter transmissions pa[y] too much." Wis. Pub. Power, 493 F.3d at 252. Marginal loss pricing, by contrast, "recovers transmission losses on a transaction-bytransaction basis by . . . treat[ing] every transmission as if it were the last (marginal) transmission on the system. This pricing scheme sends more efficient signals to market participants, but because transmission losses increase with the amount of current in the system, treating every transmission as the marginal transmission produces revenue in excess of actual losses." Id.

California ISO proposed to incorporate the marginal cost of transmission losses into LMPs, arguing this was "necessary to assure least-cost dispatch and establish nodal prices that accurately reflect the cost of supplying the load at each node."

First Market Redesign Order ¶ 66 (footnote omitted). The ISO acknowledged that revenue collection would exceed losses and therefore proposed to credit excess revenues back to loadserving entities on a pro rata basis by reducing the cost of each megawatt hour purchased by a proportionate amount of the excess revenues. See id. ¶¶ 67-68.

Finally, California ISO proposed to create several zones, called "load aggregation points." Within each zone, the ISO proposed to calculate an average zonal price based upon the weighted average of the nodal LMPs within the zone.

Suppliers would continue to be paid the precise LMP at a given node, but consumers would pay the aggregated price of their zone. California ISO contended that using zonal pricing for load-for a transition period-would protect consumers in congested areas from the sudden increase in costs that otherwise would result from the switch to an LMP-based market.

The Commission approved California ISO's adoption of LMP, finding it would "promote efficient use of the transmission grid, promote the use of the lowest-cost generation, provide for transparent price signals, and enable transmission grid operators to operate the grid more reliably."

First Market Redesign Order ¶ 63. The Commission accepted the ISO's proposal to "reflect marginal losses in its calculation of LMP, because doing so sends more accurate price signals and assures least-cost dispatch." Id. ¶ 90.

Sacramento and Imperial challenge the Commission's approval of California ISO's proposal to include marginal loss charges in LMPs. They argue the Commission's finding that marginal loss charges would "necessarily" lower costs was in conflict with the Commission's previous orders and lacked substantial evidence. Sacramento also challenges the Commission's finding that marginal loss charges would result in transmission service equivalent or superior to that offered under FERC's pro forma tariff. Imperial challenges the Commission's finding that marginal loss charges would lead to "just and reasonable" rates and further argues the Commission exceeded its statutory jurisdiction by authorizing the ISO to assess marginal loss charges to transactions in which Imperial uses its transmission ownership rights.

2. Resource Adequacy Requirements

"Resource adequacy is the availability of an adequate supply of generation or demand responsive resources to support safe and reliable operation of the transmission grid." First Market Redesign Order ¶ 3 n.2. The Commission explained that "ensur[ing] that all load serving entities procure adequate generation capacity to serve their load . . . is critical to maintaining reliability and ensuring that wholesale prices remain just and reasonable. Further, . . . resource adequacy requirements . . . will lessen the likelihood of price spikes occurring during periods of high demand." Id. ¶ 4. As part of its market redesign proposal, California ISO proposed to impose on load-serving entities two types of resource adequacy requirements: "system" requirements and "local" requirements. System resource adequacy requirements are set by state authorities and aim to ensure there is sufficient generation in the entire California ISO balancing authority area to serve the ISO's aggregate load. Local resource adequacy requirements are imposed on entities that serve load in constrained areas-known as "local capacity areas" or "load pockets"-where the transmission capability is insufficient to reliably serve 100% of the load without relying on generation capacity that is physically located within that area. California ISO proposed to perform an annual technical study to calculate the minimum amount of generation capacity that must be available within each local capacity area. Then, responsibility for acquiring the necessary local resources would be allocated to the applicable load-serving entities in accordance with each entity's share of load.

San Francisco contended it should be permitted to satisfy its local resource adequacy requirement with resources it could import from outside the load pocket it serves, pursuant to a preexisting firm transmission contract. California ISO refused, explaining that the local requirement could only be satisfied with resources physically situated within the load pocket. FERC sided with the ISO. San Francisco petitions for review, arguing FERC's decision arbitrarily and capriciously abrogated its contractual rights.

3. Congestion Revenue Rights

As noted above, LMP incorporates the cost of congestion into the price of energy. To provide a measure of protection for customers desiring to hedge against the price uncertainty that can result from fluctuations in congestion, California ISO proposed a system of "congestion revenue rights" (CRRs).

Congestion revenue rights are financial instruments that entitle their holders to be paid the congestion costs associated with transmitting a given quantity of electricity between two specified points. A party planning a transmission can thus hedge its exposure to congestion costs by acquiring a corresponding [congestion revenue right]. At the time of the transmission, the party will pay [the ISO] the applicable congestion costs, but will then receive the same amount back from [the ISO] in its capacity as the holder of the [congestion revenue right]. Wis. Pub. Power, Inc., 493 F.3d at 251 (citation omitted).

California ISO proposed to offer two types of congestion revenue rights: short-term (with terms of less than one year) and long-term (with ten-year terms). Both would be "obligation" rather than "option" rights. Obligation rights entitle the holder to a payment when congestion is in the direction of the congestion revenue right-that is, when the price at the withdrawal point is higher than the price at the generation point-but require the holder to make a payment to the ISO when congestion is in the opposite direction. Option rights, by contrast, entitle the holder to be paid but never require the holder to make a payment.

California ISO proposed to allocate congestion revenue rights among load-serving entities according to an annual four-tier nomination process. For the allocation of short-term congestion revenue rights in Tiers 1 and 2 in the initial year, the ISO proposed to require that "nominations for CRR allocations . . . be source verified," meaning that load-serving entities would be required to "demonstrate that, during a historical reference period, the [load-serving entity] had an entitlement to receive energy from the nominated sources to serve its demand." First Market Redesign Order ¶ 712. The ISO explained that "basing the CRR allocation on a period that has already occurred avoids the potential for the allocation process to distort incentives to contract for energy."

Id. California ISO proposed to use April 2006 to March 2007 as the historical reference period. San Diego objected, arguing that its transmission usage during this timeframe was unusually low and that the ISO's proposal would unjustifiably cause San Diego to enter the congestion revenue right allocation process with a substantial deficit of rights on which to hedge its existing procurement decisions.

California ISO proposed to allow load-serving entities to convert the short-term rights they received in Tiers 1 and 2 into long-term rights in the long term tier (Tier LT). Initially, the ISO proposed to allow entities to convert 50% of their adjusted load metric (a calculation that measures an entity's exposure to congestion costs) into long-term rights. But in response to San Diego's objection, the Commission held that no more than 20% of an entity's adjusted load metric may be nominated for long-term rights-although the percentage increases 10% annually in subsequent years until it reaches 50%.

In Tier 3 (actually the fourth tier), California ISO proposed to allow any load-serving entity to request any congestion revenue right. If demand exceeds the rights available, then every entity receives a pro rata share of the remaining rights. Finally, the ISO proposed to auction off any congestion revenue rights that remain after the four-tier process. Of course, at any stage in the process, load-serving entities are free to buy or sell congestion revenue rights through bilateral transactions with other market participants.

Every year after the initial year, the same tiered nomination process is repeated, except allocations no longer are source verified. Instead, load-serving entities that previously have received short-term congestion revenue rights either can renew them or ...


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