Call it an un-FIT decision: A new ruling from FERC in Re: California Public Utilities Commission issued on October 21, 2010 clarifies, by inaction, that feed-in tariffs are a verboten mechanism for states seeking to encourage renewables. But the decision is a blockbuster nonetheless, because though it doesn’t endorse feed-in tariffs (FITs), it lays out an alternate path that may open the door for more favorable pricing schemes for marine renewables. That’s because the FERC ruling repealed a longstanding precedent, Southern California Edison, which had severely restricted states’ ability to set rates under the Public Utility Regulatory Policies Act in a manner that was favorable to renewables.
Let’s back up a bit. The CPUC case originated back in June, when both the CPUC and three California utilities sought a declaratory order from FERC on whether the CPUC’s feed-in tariff rates for Combined Heat and Power (CHP) facilities were preempted by the Federal Power Act (FPA). In July 2010, FERC said yes, the FPA does preempt states from setting feed-in tariffs, but states can still use PURPA to set rates. (See this Powerpoint presentation for more details.
The CPUC appealed the ruling, and agreed to rely on PURPA as the basis for its feed-in tariff. But it requested clarification on whether it could include an adder in PURPA rates to reflect not just power costs avoided, but transmission costs as well. On rehearing, FERC went on to describe how states could apply PURPA – and in so doing, opened the door for more flexibility.
For those unfamiliar with PURPA or FERC’s earlier orders on PURPA, here’s a more detailed explanation. By way of background, PURPA is a federal law that obligates utilities to purchase power from “qualifying facilities” (QFs). Certain types of cogeneration as well as small renewables of 80 MW or less are considered QFs, and may self-certify through a simple FERC process.
Although generally, states are preempted from setting wholesale rates, PURPA is an exception. Under PURPA, states may set rates for QFs, so long as those rates do not exceed the utility’s avoided costs. Avoided costs means “means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” (18 CFR sec. 292.101(6).
Up until the FERC’s recent decision, avoided cost rates were generally never high enough to provide real incentives for renewables, as a feed-in rate would. This is because FERC’s 1995 ruling in Southern California Edison held that utilities needed to consider the cost of all power – fossil fuel and renewable – in determining avoided cost rates. This ruling had the effect of depressing avoided cost prices since non-renewables are much less expensive than renewables. FERC’s recent order first “re-interprets” its early ruling; FERC effectively says that “what we really meant in Southern California Edison” is that avoided costs must be based on the cost of all power available to the utility. So if a state imposes a procurement requirement directing a utility to purchase a certain percentage of its supply from renewables, non-renewables are “not available” for purposes of that procurement, and as such, need not be considered in avoided cost calculation. FERC engaged in a little bit of fiction here, since as a practical matter, everyone in the industry essentially understood Southern California Edison as basically banning avoided cost rate setting based on renewables-only. In any event, FERC also added that it was expressly overruled Southern California Edison.
In addition, FERC clarified that a state can split a procurement into several components, with separate standard offer contracts and separately calculated avoided cost rates for each segment of the procurement. What this seems to suggest is that a utility might be able to conduct procurements for different types or classes of renewables with different avoided cost rates for each.
Finally, FERC also noted that states can include “adders” in avoided cost rates to reflect transmission cost savings due to avoidance of another power source. But FERC would not say whether the CPUC’s 10% adder was an accurate reflection of transmission costs, and suggested that states would need to show evidence to support any adders.
So what does FERC’s decision mean for marine renewables, and states?
First, states now have more flexibility to use PURPA in such as way to set rates for renewables that are more likely to encourage development. Rates must still reflect avoided costs, but avoided costs will be higher if states can set them with reference to other renewables, as opposed to all available fuel sources. States can also implement QF rates through standard offer contracts, thus retaining some of the simplicity that makes feed-in tariffs so attractive.
Marine renewables are eligible for QF status, so they can obtain the benefits of state rates. Of course, most states are unlikely to set a “marine renewables only” avoided cost rates. Even so, an all renewables avoided cost rate will still be more generous than one which includes non-renewables in the calculus.
The FERC decision is not without its drawbacks, however. FERC’s decision is that it comes at a time when utilities now have the opportunity under EPAct 2005 and FERC regulations to seek an exemption from the PURPA mandatory purchase option. Several utilities have already successfully obtained an exemption. So what happens if a utility obtains an exemption from the mandatory purchase option? Would it still be required to purchase renewables at the preferential avoided cost rate? We know that states have the power, independent of PURPA, to compel utilities to procure renewables. So if a utility is exempt from PURPA, a state can still compel the purchase under state law. But if the state does compel the purchase under state law, does it still have the authority to force the utility to buy at the more favorable avoided cost rates? I would say no, though I’m not sure that the answer is necessarily clear cut. But in light of FERC’s decision, utilities may become more aggressive in attempting to terminate their PURPA obligations.
Because utilities can terminate their PURPA obligations, there’s still a need for a non-PURPA mechanism for states to offer incentive rates to encourage renewables development. Back in July, there was some talk about the possibility of Renewable Energy Standard Offer (RESO) contracts, where states would set a rate for a class of contracts and seek approval for the rate at FERC, thereby neutralizing the preemption questions. It’s unclear whether FERC will remain receptive to the RESO solution given that it’s already granted some relief by removing restrictions on PURPA avoided cost based pricing.
Moreover, the RESO solution will need to come from states. For now, the CPUC seems content to push PURPA as far as it can before revisiting the feed-in solution. And other states are not even bothering with the FERC route. Vermont, for example, found that its feed-in program did not conflict with federal law and declined to seek declaratory relief at FERC. Of course, Vermont’s ruling would not stop utilities or other opponents of the feed-in program from going to FERC themselves.
Bottom line: despite a positive FERC ruling for renewables, we haven’t seen the last of the legal disputes over feed-in tariffs just yet. Stay tuned.