FERC decision on CPUC CHP feed-in tariff

July 16th, 2010
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On Thursday, the Federal Energy Regulatory Commission (FERC) issued a decision with ramifications for feed-in tariffs in the United States.

Here’s the history.  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 implemented it, some investor owned utilities objected on the basis that the state does not have jurisdiction.  Their argument: the Federal Power Act gives FERC exclusive authority over wholesale sales in interstate commerce, and states are pre-empted from setting wholesale power rates that exceed utility avoided cost.  This is essentially the same issue that was raised in the CPUC’s administrative proceeding to expand the feed-in tariff program under AB 1969, as described here (more background here).

The CPUC then petitioned FERC for a Declaratory Order on the subject, and the utilities responded with a petition of their own.  Multiple organizations, including VSI, intervened with arguments for more flexibility (if you want all the docs, click here and enter EL10-64 as the docket number).

The decision?  Here’s a link–wonks should really read the whole thing.  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.”

What does this mean?

The decision essentially reaffirms the approaches described in the linked Grist article.  The options are:

-Set a price at utilities’ avoided cost
-Establish a more targeted requirement (say, PV systems from 1-10 MW) and let the market set the price
-Set a price at avoided cost, and cover the marginal gap to a workable price with tax or REC from a public benefit fund.

In California, SB 32 addresses the issue by trying to raise the ‘avoided cost’ by capturing as much value associated with DG as possible (avoided T+D, etc).  This was the approach we originally took in the CA FiT proceeding (R.08-08-009).  The downside is that there is no guarantee that the final price will be sufficient to deploy renewables.

Another option is to fine-tune the desired outcome, and let the market set the price.  The CPUC has proposed a 1 GW pilot program, called the ‘reverse auction mechanism’, or ‘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 1-10 MW in size, and best price wins.  Even SCE agrees this is jurisdictionally compliant.   We are still waiting on the Administrative Law Judge assigned to the matter to issue his proposed decision.

In short, while the FERC decision restricts state flexibility, there are ways of designing successful programs for procuring wholesale distributed generation.

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