On July 15th, the interstate electricity regulators at the Federal Energy Regulatory Commission (FERC) issued a ruling with ramifications for feed-in tariffs in the United States.

A feed-in tariff, in its common form, is a requirement for utilities to buy wholesale electricity under a fixed-price contract. That's electricity delivered to the grid for resale to other utility customers, as opposed to retail electricity that is used on-site; this approach lowers the consumer's utility bill through mechanisms like net metering. This market mechanism is popular in Europe; FERC's recent ruling provides clarity regarding just what states can and can't do when it comes to feed-in tariffs here in the U.S.

The history behind FERC's recent decision starts in 2007, when the California Legislature passed AB 1613, which established a feed-in tariff program for small combined heat and power systems in the state.  As the California Public Utilities Commission began implementing the new law, some investor owned utilities objected on the basis that the state does not have the jurisdiction to mandate this kind of program.  Their argument: the Federal Power Act gives FERC exclusive authority over wholesale electricity sales in interstate commerce, and states are pre-empted from setting wholesale power rates that exceed utility avoided cost.  This is not a new issue -- energy practitioners have been confronting it for a long time.

The CPUC then petitioned FERC for a Declaratory Order to clarify the subject, and the utilities responded with a petition of their own.  Multiple organizations, including the Interstate Renewable Energy Council, SEIA, CalSEIA, the Solar Alliance and Vote Solar, intervened with arguments for more flexibility.

The decision? From the summary:

"FERC affirmed in its order that its 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 also explained that the role of States in setting wholesale rates is limited to determining "avoided cost" rates for qualifying facilities pursuant to PURPA.

FERC thus found that the CPUC's decision under AB 1613, including the CPUC-set price, would be consistent with these federal laws as long as it satisfies certain requirements:

●     The CHP generators must be QFs pursuant to PURPA.

●     The CPUC-set price must not exceed the avoided cost of the purchasing utility."

In other words, state legislatures and regulators are restricted in their ability to mandate premium, fixed-price requirements. 

What does this mean going forward? While this decision clearly limits feed-in tariff options, it does not preclude effective wholesale distributed generation programs. When the issue came up in a recent, similar proceeding -- the CPUC's effort to expand the renewable feed-in tariff program under AB 1969 (R.08-08-009) -- parties were required to file legal briefs on this subject. Here are a few policy approaches that fall within state's price-setting authority:

●     Set the feed-in tariff price at utilities' avoided cost

●     Establish a more targeted requirement (e.g., solar PV systems from 1MW to 10 MW) and let the market set the price

●     Set a price at avoided cost, and cover the marginal gap to a workable price with a tax benefit or renewable energy credit from a public benefit fund.

There are a few real-world examples of feed-in tariffs that use this approach.  The Sacramento Municipal Utilities District recently issued a feed-in tariff priced on their time-differentiated avoided cost of generation (modeled on expected PV output, it comes out to a levelized rate of about 14 cents per kWh).  All 100 MW of the available contract capacity was immediately sold out, principally in 5 MW chunks (note that similar programs eligible for only smaller sytems have proven less effective).

Another take on this approach comes from California's SB 32. Passed in 2009, it is a fixed-price feed-in tariff that attempts to raise the 'avoided cost' by capturing as much value associated with distributed generation as possible (avoided transmission and distribution upgrades, etc.). 

The downside to using the avoided cost approach, of course, is that these costs can vary widely, are the subject of much contention, and there is no guarantee that the final price will be sufficient to deploy renewables.

Which brings us to another option: mandate the desired outcome, and let the market set the price.  The CPUC has proposed a 1 GW pilot program, called the 'reverse auction mechanism' (RAM), which elegantly deals with the problem by guaranteeing a market instead of guaranteeing a price.  Utilities would be required to do multiple annual solicitations for systems from 1MW to 10 MW in size, and the best price wins.  All parties to the proceeding seem to agree that this approach is jurisdictionally compliant.  We are currently waiting on the Administrative Law Judge assigned to the matter to issue his proposed decision.

We have some real-world examples of logic behind this market approach. For the past several years, Southern California Edison has had a voluntary Renewable Standard Offer program, consisting of a fixed-price offer to buy renewable energy from systems under 20 MW in size, with the price set at the Market Price Referent ('MPR' is calculated annually by the CPUC; it's the 20-year levelized cost of energy of a combined-cycle natural gas plant, meant to represent the next marginal unit of generation).  In 2009, SCE contracted for 140 MW of PV.  It's a great story -- here are significant amounts of solar purchased below the cost of fossil fuels.

The big question, though, is whether this pricing will work in the future. Natural gas prices have plummeted, and the MPR went down about 20% this year.  Is the new 'avoided cost' price enough to deploy solar?  This could pose a significant problem.

To address this concern, SCE recently announced that it will change its pricing approach going forward.  Instead of pricing solar based on the cost of natural gas, they will price solar based on the cost of solar as bid.  In order to make sure that the bids are viable and not aspirational phantom projects, the program requires development security of $20/kW and project development timelines.  To reduce parasitic transactional costs and help developers line-up financing ahead of time, the program uses standard, non-negotiable contracts.  In order to drive projects that can come on-line quickly and don't need new transmission, this policy is only applicable to projects under 20 MW.  (Note that SCE also has a similar program for rooftop PV systems that are 1MW to 2 MW in size.  On July 27, it released the results of the first solicitation: 60 MW of projects throughout its service territory.)

This market-based approach is FERC-compliant, captures the latest in solar's cost reductions and delivers that value to ratepayers, and helps drive down solar's costs by sending helpful market signals throughout the solar value chain. Think of it as the next generation of the feed-in tariff: FIT 2.0.

So, even though the FERC decision clearly restricts states' feed-in tariff authority, it is important to recognize that there are still ways of designing successful programs for procuring wholesale distributed generation. 


Adam Browning is the Executive Director of the Vote Solar Initiative, a non-profit organization working to combat climate change and foster economic opportunity by bringing solar energy into the mainstream throughout the U.S. He cofounded the organization in 2002.

To see the full text of the documents cited in this article, go to http://elibrary.ferc.gov/idmws/search/fercgensearch.asp  and enter EL10-64 as the docket number.

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