FERC Rebuffs Wind Developers
The tensions between federal and state energy regulation were dramatically highlighted by a Federal Energy Regulatory Commission order in July that its transmission pricing policies require wind developers to pay the cost of two new transmission lines to bring electricity from the Tehachapi area to the Southern California Edison grid.
Southern California Edison had asked FERC to let it “roll in” the costs of the lines so that they would be borne by all users of the grid as part of the rates the utility charges transmission customers. FERC regulates rates for transmission on the interstate grid. The two transmission lines in question are a new 26.1-mile 500-kilovolt line and a separate 9.4-mile 220-kilovolt line. They are part of the Antelope Transmission Project, which is intended to tap 4,000 megawatts of potential wind generation in Tehachapi, California.
The Tehachapi area is near Edwards Air Force base and is California’s largest wind resource area. Developers have already applied to connect 1,100 megawatts of new wind farms in the Tehachapi area to the grid. That is good news for California, which in 2002 enacted legislation requiring California utilities to supply 20% of their power from renewable fuels by 2017; Governor Schwarzenegger and the California Public Utilities Commission later moved up the date to 2010.
While there is plenty of viable wind in Tehachapi, the existing transmission lines lack the capacity to move the power to nearby Los Angeles or other parts of the state.
The California Public Utilities Commission granted “certificates of convenience and necessity” for transmission line construction after concluding that new lines are needed in the Tehachapi area. Edison, the utility that serves the Tehachapi region, then asked the CPUC for permission to build the Tehachapi lines, as well as two other 500-kv lines that the utility calls the “Antelope project.” Unlike the Tehachapi lines, the two other Antelope lines are not “radial” lines used solely to deliver power from a generator to the grid. Instead, they are part of a “looped” transmission system where energy flows in both directions. They will be used to serve load and increase transfer capacity from existing generators, as well as facilitate imports into the grid from Tehachapi.
FERC policy on “network upgrades”— or improvements that must be made to the grid to accommodate additional electricity — has been favorable to generators. A generator must pay the costs of the “direct intertie” that connects his or her plant to the grid, but utilities are supposed to collect the costs of network upgrades in the transmission rates charged all grid users, even if the upgrades are needed only to accommodate power from the generator.
This cost allocation approach, called “rolled-in pricing,” has historically been used by FERC because it views the transmission grid as an integrated system, rather than a collection of discrete wires, that functions as a network to permit multi-directional power flows to occur and thereby to facilitate transactions throughout the grid to occur. A corollary of FERC’s policy is that it fights against utilities’ attempts to include the costs of facilities that are used for other functions, such as generation, out of the transmission rate base, so as not to force transmission customers to subsidize individual generators (including the utility’s own generation) through transmission charges.
The costs of radial lines, that do not function as part of an integrated system, but instead serve only one or an identifiable universe of persons, are not rolled in along with the rest of the costs of the transmission system. Instead, these costs are “directly assigned” to the generator connecting a plant to the grid. FERC’s pricing policies follow this dichotomy, dividing the universe transmission facilities into “interconnection facilities,” which are “sole use” facilities “necessary to .. . interconnect the Generating Facility to the .. . Transmission System,” and network upgrades, which are improvements to the transmission grid necessary to accommodate the import of power from a generator.
The California legislature apparently recognized a problem with the FERC approach. The costs of a transmission line used solely to transmit power from new wind projects to the grid could be allocated to the wind developers, thereby threatening the viability of projects needed to satisfy the state’s renewable portfolio standard requirements. Therefore, the legislature directed the CPUC to require utilities to which renewable power projects will be connected to try to recover the interconnection costs through general transmission rates, at least in cases where the CPUC concludes a transmission line provides broad benefits to the entire grid and is needed to reach the goals the state has set for itself in the renewable portfolio standard. The CPUC was also directed to defend these positions before FERC, and to allow recovery in a utility’s retail rates of any costs for new transmission facilities that FERC does not allow to be folded into the rates for transmission.
The plan to fold the cost of the Tehachapi lines into general transmission rates ran into opposition from several California wholesale power users. The Transmission Agency of Northern California, the California Department of Water Resources and several California cities with municipal utilities opposed Edison’s proposal. They argued that the plan would result in “distorted generation siting policies,” since generators using the trunkline will be able to locate anywhere “regardless of the costs of needed transmission, because such costs will be borne by users of the entire grid, rather than load that is served by the generation.”
Edison asked FERC to create an exception to its policy of assigning the costs of “sole use” interconnection facilities to generators. The exception would apply to high-voltage trunklines that will be used to connect large concentrations of renewable power plants in a limited geographic area in a state with a renewable portfolio standard. The state commission or “independent system operator” or “regional transmission organization” that operates the grid must have determined that the new transmission lines or upgrades are necessary to meet the state’s policy objectives. Both the CPUC and the California Energy Commission supported the Edison position.
Edison argued that renewable energy developers have no choice except to locate their projects where the resource is found and do not have the same flexibility as other generators about location.
Edison also asked FERC to let it fold the costs of the Antelope project into its transmission rates, whether or not the full increment of forecasted wind generation used to justify the other upgrades actually develops. It is possible that the anticipated demand will not materialize, and then Edison would have installed transmission facilities with more capacity than is needed. In that scenario, under FERC’s traditional utility ratemaking policies, utilities may recover only 50% of the costs of equipment that is abandoned or cancelled. Edison argued this policy is an obstacle to investing in the Tehachapi trunkline because it does not have signed interconnection agreements yet with developers that would subscribe to all of the available capacity.
FERC rejected the Edison proposal on July 1. It declined Edison’s invitation to create a third category of transmission facilities — new high voltage trunk transmission lines necessary to interconnect large concentrations of potential renewable resources located at a reasonable distance from the existing grid. Instead, FERC stuck to its “fish or fowl” world view, holding that since the Tehachapi line would be a “sole use” facility that will not operate in parallel with existing transmission facilities, it is not a network upgrade and, therefore, is not eligible for rolled in rate treatment.
It appears that FERC was swayed by the argument that since the Tehachapi line would function as a line for connecting power plants to the grid, shifting its costs to all users of the transmission grid would be inconsistent with the principle of functional separation of transmission from generation, which is at the core of FERC’s open-access, pro-competition paradigm for the utility industry. If generator A who is trying to compete in, for example, the Oregon market, must bear the costs of wind generation in Tehachapi, while generator B, a competitor located in Oregon, does not, improper price signals can occur. Moreover, if FERC were to tailor its transmission pricing policies to favor development of whatever generation that state favors, then there would no longer be a national policy on transmission pricing. The interstate transmission system could become weighed down with the equivalent of toll booths at every state line.
However, FERC could have established a policy that applied to California utilities but not to those in other states. FERC distinguishes in Order No. 2003, which establishes uniform requirements for utilities to interconnect with generators, between utilities where an independent grid operator — for example, an RTO or ISO — has operational control of the grid, and utilities that operate their own grids. Independent grid operators are allowed to deviate from the standard interconnection pricing policies “to meet their regional needs.”
On the same day that FERC turned down the Edison proposal, it determined in another case that the governing board of the California ISO now satisfies the independence requirement. As a consequence, FERC could have evaluated Edison’s request under that more flexible standard. Had it done so, instead of mechanically applying its sole-use-facilities-are-not-rolled-in approach, FERC could have acknowledged that California has unique opportunities to satisfy the laudable policy goals it has established, and that since the development of renewable resources is a statewide goal, it is reasonable for the costs of expanding the grid to permit resource development to be shared by all users of the California grid. Further, FERC could have recognized the fact that in many instances, the transmission “network” includes transmission lines used primarily, if not exclusively, to supply power from generating plants that were previously owned by California utilities, as well as transmission lines from the nuclear and hydroelectric plants that California utilities continue to own and operate.
Somewhat inconsistently, FERC granted Edison’s request that it be allowed to recover 100% of the costs of the non-sole use portions of the Antelope project, even if these facilities are abandoned or cancelled. FERC said that Edison is carrying out an order from the CPUC rather than following a course of action developed by company management and that Edison faces greater-than-normal risks because its ability to use the transmission lines depends on decisions by wind developers. FERC could have used this same rationale to roll in the costs of the Tehachapi transmission line.
The outgoing FERC chairman, Pat Wood, dissented from the commission decision on the Tehachapi lines. He argued that trunkline facilities are distinguishable from sole-use lines because they serve multiple generation developers and their multiple customers, and they provide access to significant and diverse supplies of energy that provide benefits to all users of the grid.
The wind developers in this case will do okay. California enacted a backup plan to let Edison fold costs of the Tehachapi lines into retail rates if FERC refused to let them be included in transmission rates. Developers in other states may not be as fortunate.