by Thomas McCann Mullooly and Trevor D. Stiles, Foley & Lardner LLP
During the past year, several orders of the Federal Energy Regulatory Commission (FERC) regarding California’s proposed feed-in tariff program have provided a green light to other states searching for tools to promote renewable energy.
The additional guidance regarding nuanced federal pre-emption issues will make it easier for states to draft feed-in tariff (FIT) proposals that encourage renewable energy and comply with federal law.
Many forms of renewable energy are still relatively early in their developmental cycle compared with more mature technologies such as coal or natural gas. Combined with the current lack of economies of scale, certain renewable energy generators are more expensive than their fossil fuel counterparts, and that slows financing and development.
Governments around the world have attempted to narrow this cost gap and embrace carbon-friendly generation sources by providing policy and incentive support. In the United States, support has ranged from investment and production tax credits to streamlined interconnection procedures to the establishment of renewable portfolio standards. State governments including Hawaii and California have turned to FITs as an additional support mechanism.
FITs come in many forms, but the basic model requires utilities to post a standard contract, the tariff, through which it will purchase electricity generated by eligible renewable sources at fixed prices under predetermined terms and conditions.
FIT prices may adjust with inflation, adjust in relation to wholesale market prices or even stay flat or decline over the course of the contract. By providing a predictable stream of income, FITs attract developers who must demonstrate steady cash flows to secure financing for renewable generation projects.
Because of these advantages, FITs have been adopted around the world–notably in Spain, Germany and the province of Ontario. Governments implementing FITs often see an explosion in renewable generation development.
Until recently, however, FITs have not been proposed widely in the United States. This stems largely from historical energy regulatory policy. In the U.S., energy is regulated at state and federal levels. Generally, states regulate retail sales of electricity, when power is sold directly to end-use customers for consumption. Wholesale sales are generally in FERC’s federal domain, with some exceptions such as setting avoided-cost rates at which utilities buy power from qualifying facilities (QFs).
This causes problems for states wanting to institute FITs. States can set rates at which utilities sell retail power, but how far can they go in setting rates at which utilities buy wholesale power? This regulatory tension prevented states from making serious FIT proposals until recently.
The California Proposal
In 2007, the California legislature passed AB 1613, the California Waste Heat and Carbon Emissions Reduction Act.
AB 1613 required investor-owned electric utilities to purchase electricity generated by eligible combined heat and power (CHP) generators at a price set by the California Public Utilities Commission (CPUC). AB 1613 allowed the CPUC to set standard rates for CHP generators with capacities of less than 20 MW.
Cognizant of the potential regulatory issues, the CPUC submitted a petition for declaratory order to FERC in May 2010.
The petition requested that FERC find that neither the Federal Power Act (FPA) nor the Public Utility Regulatory Policies Act of 1978 (PURPA) pre-empted California’s proposal.
FERC issued its order on the CPUC’s petition July 15, 2010. The order confirmed that FERC’s authority under the FPA “includes the exclusive jurisdiction to regulate the rates, terms and conditions of sales for resale of electric energy in interstate commerce by public utilities.” FERC further found that AB 1613 did not merely establish an offering price by the purchases of power, but rather acted to set rates for wholesale sales in interstate commerce by public utilities, which was pre-empted by the FPA.
FERC continued, however, noting that pursuant to PURPA, a state commission has authority to determine avoided cost rates for QFs. As long as (1) the CHP generators included in the California program were certified as QFs, and (2) the CPUC-set price did not exceed the avoided cost of the purchasing utility, the AB 1613 plan would not be pre-empted by the FPA or PURPA.
Thus, to the extent the AB 1613 proposal attempted to set wholesale rates for power, it was pre-empted by federal law. But to the extent the state’s implementation merely set rates for QF sales below the utility’s actual avoided cost, the plan would be consistent with federal law. So as long as the CHP generators participating in the FIT program were QFs and the rate established by the CPUC did not exceed the utility’s avoided costs, the FIT program would pass federal muster.
The October Order
The CPUC sought clarification of the July 15, 2010, order and raised two major issues. First, whether the CPUC’s proposed multitiered avoided-cost rate structure based on resource type would comply with FERC’s avoided-cost requirements; and second, whether the state could consider items such as congestion and avoided transmission costs in evaluating the appropriate avoided cost rate.
In its Oct. 21, 2010, order, FERC affirmed its previous rulings that a state has wide latitude to set avoided cost rates and to require utilities to procure a certain percentage of energy from renewable resources.
Because neither action individually was pre-empted by federal law, combining the two into one regulatory mechanism also passed federal scrutiny.
Thus, California could evaluate avoided cost with reference to a particular class of generators. This allowed California’s proposal–with its multitiered structure based on the type of generation resource–to pass federal muster as essentially a combination of RPS and QF avoided-cost measures.
The second issue raised by the CPUC was whether the avoided-cost rates it set could include a bonus for CHP systems in transmission-constrained areas to reflect the avoided costs of distribution upgrades, transmission upgrades or both that otherwise would be needed. California sought a determination of whether full avoided cost could be higher than the cheapest avoided cost by considering and including nongeneration externalities into the avoided-cost price.
FERC determined that a proposed avoided-cost rate could not include a bonus or adder to compensate for additional externalities that resulted in a rate higher than actual avoided costs. But FERC did confirm that state commissions have flexibility in determining what externalities are appropriately included in the calculation of avoided costs.
According to FERC, “If the environmental costs are real costs that would be incurred by utilities, then they may be accounted for in a determination of avoided-cost rates,” and a state commission could include “an actual determination of the expected costs of upgrades to the distribution or transmission system that the QFs will permit the purchasing utility to avoid.”
A state commission cannot simply tack a cost adder onto the already-calculated avoided costs to make FIT prices more competitive. A state commission could, however, consider whether environmental, transmission or distribution costs should be included within the full avoided cost of the utility.
Finally, FERC noted that states could provide for renewable energy certificates or other similar credits to make the economics of renewable energy more attractive. These types of RPS programs also would not be pre-empted by federal regulatory law.
Order Denying Rehearing
Several California utilities sought rehearing of FERC’s order. On Jan. 20, FERC issued its Order Denying Rehearing in which FERC reiterated its October order: The FPA provides FERC the exclusive jurisdiction to regulate sales for resale of power in interstate commerce by utilities. States, however, consistent with PURPA and FERC’s regulations, have the authority to dictate a utility’s actual purchase decisions. Because the avoided-cost rates to be paid to a QF under PURPA are defined in costs that a utility avoids by purchasing from a QF and because the state determines what type of power must be procured, “the state may rely on the cost of such avoided capacity to determine the avoided-cost rate.”
By reiterating its previous order and clarifying these points, FERC provided further certainty to states seeking to develop FITs.
There continues to be interest in the United States in creating renewable energy policies that reduce reliance on carbon fuels. Renewable mandates and subsidies generated some controversy in the recent elections. The issue was put most succinctly before voters in California’s Proposition 23, which would have suspended implementation of California’s carbon-reduction law. The defeat of Proposition 23 has been taken by some as a signal that renewable energy policies, even where they result in additional cost pressures on electricity, will continue as an important element of the nation’s energy policy. FITs likely will be considered for adoption in other states.
FERC’s recent orders clarify the regulatory landscape regarding federal pre-emption of state FIT proposals. Legislators and regulators must remain vigilant to comply with federal rules governing wholesale sales, but states can achieve the policy outcomes they want by combining renewable resource mandates with careful determinations of QF avoided cost pricing for FITs.
Coupled with revenue from renewable energy certificates, such FIT programs can provide states with a mechanism by which to provide developers the incentive of a predictable income stream and encourage renewable generation development.
Thomas McCann Mullooly is a partner at Foley & Lardner LLP and the vice chairman of its national energy industry team. Reach him at 414-297-5566 or email@example.com.
Trevor D. Stiles is an associate at Foley & Lardner LLP and a member of the firm’s energy industry team and environmental regulation practice. Reach him at 414-319-7346 or firstname.lastname@example.org.