In last month’s issue, professor Steven Ferrey, from Boston’s Suffolk University Law School, outlined in the pages of the Fortnightly how the Federal Power Act (FPA), the filed-rate doctrine, and the U.S. Constitution’s Supremacy Clause raise serious obstacles for state lawmakers or utility regulators in the United States trying to set up a European-style “feed-in” tariff (FIT).
That’s a state-imposed rule that would force retail utilities to buy power at wholesale from renewable or similarly favored green energy suppliers—a regime not appreciably different from the “must-take” purchase obligation imposed on utilities for power produced by qualifying cogeneration facilities (QFs) that was introduced in the United States three decades ago with the 1978 PURPA law. (See “FIT in the USA,” June 2010)
The authors noted how many states today are contemplating their own next-generation feed-in tariffs, going well beyond PURPA, and offered suggestions on what sort of FIT program design might suffice to win a vote of approval from FERC. And in particular, the authors cited a new case now pending at FERC that might well decide whether the FIT model can work in the United States.
The case involves a FIT adopted late last year by the California Public Utilities Commission (CPUC), requiring retail utilities to put together offers to buy power at wholesale from high-efficiency, combined-heat-and-power (CHP) facilities up to 20 MW in capacity. It comes before FERC in the guise of two petitions filed in early May—one by the CPUC, the other by retail utilities who oppose the state commission. Each asks the feds to rule on whether FERC’s exclusive jurisdiction over wholesale electric rates should pre-empt California’s attempt to force utilities to buy green power through a state-implemented feed-in tariff.
By early June, comments and arguments began to trickle in from utilities, regulators, trade groups, and industrial customers, showing little common ground between disparate interest groups. If anything, the answer to the pre-emption question seems more muddled now than when the process started. In fact, only one point seems clear: The real fight, it appears, is over the price the utilities would have to pay for cogenerated power.
The CPUC approved its feed-in tariff for CHP facilities late last year and refined its policy this spring with the addition of certain clarifications (see Decision 10-04-055, Apr. 22, 2010, modifying Decision 09-12-042, Dec. 17, 2009). The two orders were issued to implement California Assembly Bill 1613, the “Waste Heat and Carbon Emissions Reduction Act,” enacted in 2007. Among other points, AB 1613 required retail electric utilities to offer contracts to buy power from CHP systems placed in operation after 2007 that satisfy certain efficiency standards relating to energy conversion rates and emissions of greenhouse gases (GHG). In fact, to qualify under AB 1613, CHP systems must meet a higher overall efficiency standard than that currently required for qualifying cogeneration facilities under PURPA.
And just as important, the utility offer price under the CHP FIT program is based on a concept unique to California known as the market price referent. The MPR operates a little like PURPA’s avoided-cost concept, but not quite. Rather than measure a utility’s actual alternative cost of purchasing or generating its own power, the MPR presumes an opportunity cost for wholesale power that mirrors the hypothetical cost of owning and operating a base-load combined-cycle gas turbine (CCGT) unit, over a 10-, 15- 20- or 25-year period, on the theory that utility resource portfolios shouldn’t produce greater GHG emissions overall than would a portfolio made up entirely of CCGT plants. Moreover, the MPR also includes a price component designed to reflect the likely future cost of GHG emissions-control efforts.
Thus, with its FIT, the CPUC created a sort of state-enabled and “shadow” PURPA program for super- efficient CHP facilities, which pays a higher avoided-cost to qualifying CHP units than would be the case under PURPA’s avoided-cost scheme for ordinary QFs. California’s FIT price is set high enough, in fact, to cover the estimated likely current and future costs of greenhouse-gas compliance at both the state and federal levels.
In essence, the CPUC with its FIT has remade the traditional PURPA cogeneration program, but with a carbon tax thrown in. And it’s this higher price, much more so than constitutional niceties, that riles California’s retail utilities.
According to the CPUC, the justification stems from the different purposes behind PURPA and the California FIT law:
“The primary purpose of AB 1613 [and the CPUC’s FIT implementing orders] is environmental protection, particularly the reduction of GHG emissions. In contrast … the purpose of PURPA [was] to decrease dependency on foreign oil and avoid an energy crisis.” (See Petition of CPUC, FERC Docket EL10-64, filed May 4, 2010.)
Thus, as the CPUC explains, its higher FIT rate naturally reflects the additional costs necessary to meet all the environmental requirements under AB 1613: the GHG and NOx emission standards, the 60-percent energy conversion efficiency standard for CHP facilities, plus an allocation of any more stringent carbon emissions compliance costs mandated by the California Air Resources Board under Assembly Bill 32, California’s Global Warming Solutions Act of 2006, or even by Congress or the U.S. EPA.
The tariff even includes a 10-percent bonus (i.e., an adder to avoided costs under the FIT rule), for purchases from CHP systems located in congested areas, to reflect avoidance or deferral of future upgrades to distribution or transmission networks.
The CPUC claims that FERC’s PURPA case law precedent is now “outdated” since “these mid-1990s decisions were prior to the extensive knowledge of the devastating effects caused by the acceleration of climate change.”
California’s three major retail utilities—Southern California Edison, Pacific Gas & Electric, and San Diego Gas & Electric—believe the CPUC’s FIT intrudes unlawfully on FERC authority. But they also stress how PURPA always has capped the price paid to QFs at avoided cost—what the utility would have had to pay if buying power elsewhere, such as the day-ahead energy price that clears in the market run by the California Independent System Operator. And the utilities say that this lower avoided-cost price cap should apply both for PURPA QFs, as well as for renewable or green power producers selling under a state-mandated FIT operating outside the context of PURPA:
“If states have the right to dictate from whom purchases are made and at what price outside of PURPA, then why has FERC rejected state attempts to dictate a price greater than avoided cost, inside of PURPA?”
And if FERC should OK a FIT tariff at rates above avoided cost, they foresee nothing but trouble:
“One state might ask FERC to allow mandatory purchases at slightly above avoided-cost rates from small renewable generators [and] the next state, with a goal to eliminate all greenhouse gases, might set mandate that all power be purchased from nuclear power plants at a rate three times avoided cost.” (See, Petition of So.Cal.Ed., PG&E, SDG&E, p. 22, filed in FERC Docket EL10-66, May 11, 2010.)
The Edison Electric Institute adds its voice to the mix in comments opposing the CPUC petition. EEI argues that California’s FIT isn’t only unlawful (i.e., pre-empted by federal authority), but that even if not, the price is impermissibly high: “The CPUC admits that it is purposefully adopting a price above the utilities’ short-run avoided cost to compensate for ‘societal benefits,’ thereby acknowledging that the rate exceeeds avoided cost.”
Don’t Ask, Don’t Tell
Case law precedent evolved under PURPA is unequivocal: Power producers need a FERC-authorized agreement to sell power at wholesale at a specific rate unless exempted from the FPA by FERC rule or special legislation, as is the case for exempt wholesale generators, sellers with market-based pricing authority, or QFs certified under PURPA. Absent that, states can’t actually compel a utility buyer or a power-producing seller to execute a purchased power contract at a specific price.
Of course, the states retain authority to regulate or dictate power procurement decisions by retail utilities. State laws mandating renewable portfolio standards serve as the prime example. This retained authority gives rise to the notion of a state-mandated FIT to force utilities to buy renewable or green energy. However, for the state FIT law to stick, it must regulate the buyer—not the seller. The legislative wording must dance around the edges of an actual completed deal; it must effectuate the desired result while appearing not to have forced the parties to execute an actual contract at a stated price. Forcing buyer and seller to sign a contract at a specific price would be tantamount to state regulation of interstate power at wholesale. Instead, the state must be careful to extend regulation only over the utility buyer and its procurement practices.
As California Attorney General (and former Governor) Jerry Brown puts it, the CPUC isn’t setting a rate for the wholesale generator: “Rather, the CPUC is setting a price that the [utility] must offer the generator in order to meet then environmental goals of the state law.
“The generator, he adds, “retains authority to sell at any rate it sees fit and to any buyer, while benefiting from the option to sell to the IOUs at the FIT rate.” (Comments of Attorney General, FERC Docket EL10-64, filed June 2, 2010.)
This dance is aptly described in a technical report issued in January 2010 by the National Renewable Energy Lab:
“Does FERC’s exclusive authority over wholesale sales mean that U.S. law bars state-level feed-in tariffs outside of PURPA? [T]he answer is ‘no,’ provided that the state designs the tariff to be the utility’s offer to buy at a state-specific price.” (See, Scott Hempling, Carolyn Elefant, Karlynn Cory, Kevin Porter, “Renewable Energy prices in State-level Feed-in Tariffs: Federal Law Constraints and Possible Solutions,” NREL/TP-6A2-47408, January 2010.)
But as the NREL report adds, “this analysis is not free from doubt.”
The key precedent is FERC’s 1997 ruling in Midwest Power Systems, Inc. (Docket EL95-51, 78 FERC ¶61067).
In that case, FERC reviewed orders issued pursuant to state law by the Iowa Utilities Board that had directed Midwest Power (now known as MidAmerican Energy) to buy wholesale power, renewable and other so-called “alternative energy production facilities” at a rate of 6 cents per kWh ($60/MWh), rather than the 1.5-cent rate that Midwest was paying to PURPA QFs under a FERC-sanctioned avoided-cost rate.
Importantly, the “alternative” energy sellers needn’t have qualified as PURPA QFs to receive the 6-cent sales rate guaranteed by the Iowa state law, though some likely could’ve won PURPA certification.
Even so, FERC ruled that the 6-cent FIT was pre-empted as unlawful as to any Iowa alternative facility that, in principle, could’ve qualified under PURPA, if it had taken the trouble to do so.
For FERC, the principle was key—that payments to QFs, whether or not their status is known, must be capped at the PURPA-tested avoided-cost rates. It wasn’t crucial for policymaking purposes to identify which facility was which.
Today, in the California case, the Midwest Power rule still governs. Thus, both the California legislature and the CPUC took care in implementing the CHP feed-in tariff to emphasize that the authority and justification for the policy didn’t depend on PURPA, even though it was likely (as in the 1997 Midwest Power case) that most, if not all, of the CHP units meeting the FIT efficiency standard could’ve qualified as well under the lesser PURPA standard.
This don’t-ask, don’t-tell aspect of the CPUC’s FIT policy leads to an inherent contradiction. First, in order to defend FIT offer payments that exceed traditional PURPA avoided costs, the CPUC must argue that its FIT statute and program stand completely independent of PURPA. But at the same time, the CPUC certainly can’t admit that the state statute or implementing tariff run counter to the general principles that Congress and FERC have outlined and refined in the 30 years of PURPA’s existence. In opposing the California policy and arguing for federal preemption, EEI noted the contradictions inherent in the CPUC’s position in comments it filed June 3 in Docket EL10-64:
“The CPUC seeks to avoid these constraints by not invoking PURPA—for good reason because PURPA would not authorize the CPUC’s action …
“Here, in the CPUC decision, the CPUC has made no attempt to justify its methodology as avoided cost. Rather, the CPUC has stated that it is not acting under PURPA, and the eligible generators need not even obtain QF status. …
“Nor has the CPUC explained why the resulting rate differed from the one set in its own PURPA avoided cost proceeding … [T]he CPUC admits that it is purposefully adopting a price above the utilities’ short-run avoided cost to compensate for ‘societal benefits,’ thereby acknowledging that the rate exceeds avoided cost. It is not surprising, therefore, that the CPUC disclaims any intent to act under PURPA.”
What Really Matters
Defending the state’s proposed FIT, Attorney General Brown characterizes the measure as a health and safety law, adopted under state police power to safeguard the public health of California’s citizens from the effects of climate change, and so should be presumed lawful—not to be preempted absent “a clear and manifest purpose” expressed by Congress.
Moreover, Brown appears to believe that the greenhouse climate threat has changed the game, so that PURPA and FERC must change in response:
“California’s efforts to address global warming are changing the market in which an IOU purchases power,” writes Brown. These efforts, he notes, “have set California on a path that relies on cleaner power.
“As a result, incremental alternative energy increasingly does not come from fossil-fuel-based generators. What really matters is the avoided cost of alternative renewable energy and highly efficient sources. PURPA’s language and intent and FERC’s regulations governing avoided-cost rate setting are sufficiently flexible to accommodate … state law requirements for energy efficiency, renewable portfolio standards, and reduction of greenhouse gas emissions” (Comments of AG, pp. 12-13).
Representing the FIT Coalition, a California-based group that advocates renewable energy, distributed generation, and FITs, Attorney Tamlyn Hunt argues that the higher-than-PURPA avoided-cost payments prescribed by California’s proposed FIT shouldn’t be questioned, since the concept of the CCGT market price referent already has been accepted as the pricing benchmark for green energy that California utilities already must purchase under the state’s accelerated renewable portfolio standard.
“Importantly,” writes Hunt, “the MPR includes a ‘greenhouse-gas adder,’ which represents the likely cost of greenhouse-gas compliance at the state and federal levels, once these regulations are in place …
“[I]t is the price by which contracts are judged to be de facto reasonable.
“To our knowledge, the utilities have never argued to the CPUC or in other venues that this adder constituted an unauthorized assertion of jurisdiction by the CPUC.”