The Federal Energy Regulatory Commission proposed in mid-January to remove the obligation of US utilities to purchase electricity from “qualifying facilities” in four key regions of the country.

Utilities had been required by a 1978 law called the Public Utility Regulatory Policies Act, or “PURPA,” to buy electricity from two types of power plants at the “avoided cost” the utility would have to pay to generate the electricity itself. The two types of power plants are “cogeneration” facilities that produce two useful forms of energy from a single fuel, like electricity and steam produced by burning coal or natural gas, and power plants of up to 80 megawatts in size that burn renewable or waste fuels. These two types of power plants are called “qualifying facilities.”

The new Energy Policy Act, enacted last August, gave FERC the authority to terminate a utility’s obligation to buy electricity from qualifying facilities in workably competitive regional markets.

The FERC proposal does not affect existing QF contracts or QF contracts entered into with utilities before the rulemaking becomes final. Comments on the proposed rulemaking were due February 27, 2006.

What Regions Are Affected

FERC determined that each of the four regions — the mid-Atlantic states, much of the Midwest, New England and New York or, more technically, those regions containing the regional transmission groups PJM, MISO, ISO-New England and ISO-New York — met one of three alternative statutory tests for a FERC determination that the utility’s purchase obligation can be lifted. At the same time, the agency noted that other utilities or regional transmission organizations, including the California ISO and the Southwest Power Pool, are free to seek to eliminate the mandatory purchase obligation on a case-by-case basis by making an application to FERC.

It seems that FERC is eager to do what it can to eliminate the mandatory purchase obligation.

The Energy Policy Act did not direct FERC to issue any rules or make any immediate findings about competitive markets or the elimination of obligations. Rather, the law seems to contemplate that utilities would file an application to end the mandatory purchase obligation and that FERC would rule on the application. FERC’s decision to let the world know about its thoughts on competitive marketplaces is a clear signal that it wishes to unwind a key component of PURPA as soon as possible.

Although the timing seems a bit accelerated, the action itself seems to reflect the views of Congress as embodied in the law. On the one hand, Congress used the law to encourage renewables with production tax credits. On the other hand, it largely gutted PURPA, the statute that created and encouraged the renewable power industry. The message seems to be that Congress wants to encourage renewables under the tax laws, just as it did for the nuclear powered and coal-fired industry, but wants to eliminate market incentives that might give renewables a competitive advantage over fossil-fueled competitors. Congress appears to be leaving it to individual states to create a new type of mandatory purchase obligation in the form of renewable portfolio standards — called “RPS” for short — for the regulated utilities in those states. About half the states have been filling the federal vacuum with RPS mandates of differing magnitudes.

FERC determined that, once a QF contract expires in a part of the country where it has lifted the mandatory purchase requirement, the purchasing utility will not be required to enter into a new or extended contract with the QF. This is a major issue in California. The California Public Utilities Commission (“CPUC”) has recently directed the regulated utilities to sign extensions of expiring QF contracts for up to five years, pending the conclusion of a new avoided cost pricing proceeding. Pacific Gas and Electric Company has argued before the CPUC that the California ISO satisfies the test for a regionally competitive market, and a near-term FERC filing by PG&E to push the point would not be a surprise.

FERC disagreed with the view of “some” that the grant of QF status means that electric utilities have an “obligation to purchase from that QF in perpetuity.” This view of “some” apparently comes from the grandfather clause in the new law that says that the law does not “affect the rights or remedies of any party under any contract or obligation in effect . . . on the date of enactment . . . to purchase electric energy or capacity from . . . a qualifying cogeneration facility or qualifying small power production facility (emphasis added).”

It can be argued that utilities had an obligation to purchase from existing QFs on the date of enactment of the new law, even without a contract, due to PURPA’s general requirement that utilities must offer to purchase QF energy. On this theory, the utilities in regions where FERC has lifted the purchase requirement would only be permitted to refuse to purchase QF energy from new QFs; that is, from entities that became QFs after the date of enactment. This interpretation would appear to be at odds with the portion of the new law that eliminates a utility’s obligation to sign a new contract with any QF, without distinction between old and new, upon an appropriate commission finding of regional competitiveness.

How the Test Was Met

The commission stated that each of the four regions met the following two-pronged test: QFs had “nondiscriminatory access to (i) independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy.”

It is not difficult to understand why FERC found that the first test was satisfied. MISO, PJM, ISO-New England and ISO- New York all have operating real-time and day-ahead markets. The crucial issue is whether QFs have access to long-term sales in the wholesale markets. In each instance, FERC rested its determination of long-term sales availability on the fact that “bilateral contracts exist” in those markets. That’s it, ladies and gentlemen. While it may be possible for FERC to demonstrate empirically that QFs have access to long-term sales in those markets, the mere assertion of the existence of an unspecified number of bilateral contracts in that market would not seem to form a rational basis for the commission’s conclusion. For example, FERC did not even attempt to determine if any QFs had long-term contracts in the region, or if so, whether they all pre-dated the creation of the regional transmission organization or day-ahead markets. Responses to the rulemaking are certain to attack this conclusion.

FERC also declared that the requirement of nondiscriminatory access to long-term sales in the wholesale market does not require a finding that there is a competitive market for such sales. This conclusion also has its weaknesses. In FPC v. Conway Corp. in 1976, the US Supreme Court found that competitive impacts of a utility’s decision on rates was a factor in determining whether its actions were unduly discriminatory.

Interestingly, FERC made no mention of the ERCOT system and whether ERCOT met this competitive test. In 2001, FERC denied a request by the Texas Public Utility Commission to waive the mandatory purchase obligation in Texas. Utilities in ERCOT are free to file an application under the new law to eliminate the mandatory purchase obligation.

Workable Competition

By naming four regions and not others, FERC was in essence declaring that other regions would have trouble meeting the first test on a generic basis, but would have to satisfy FERC, if at all, on a case-by-case basis, by meeting one of two other tests for workably competitive markets.

In the second test, there must be an approved regional transmission entity with open transmission access and competitive markets that provide a meaningful opportunity for short and long-term sales of capacity. In the third test, there must be wholesale markets for the sale of capacity and energy that are at least of comparable competitive quality as the markets described in the first two tests.

FERC asked for responses to a number of questions related to these tests. One is whether there are any circumstances in which a QF’s rights to service under an open access transmission tariff, or ”OATT,” would be an insufficient showing of nondiscriminatory transmission access. It would seem, at first blush, that a utility with little or no available transmission capacity for short-term or long-term transmission in peak periods would make service under an OATT problematic. FERC also sought advice on whether non-jurisdictional utilities, like municipal and cooperative utilities, that file reciprocity transmission tariffs — which is a FERC condition to allow the municipality or coop to receive OATT service from a regulated utility — satisfy the nondiscriminatory access requirement.

Another question FERC asked is whether the second test’s “meaningful opportunity”-for-short-or-long-term-sales requirement would be met outside of regional transmission markets “if there is a demonstration that an organized power procurement process exists in which QFs can participate (albeit not an auction-based process).” FERC made no attempt to explain what an “organized power procurement process” is that would not involve some sort of auction. Would it have to be nondiscriminatory? Would there have to be a level playing field if the host utility is allowed to sell power to itself or build a rate-based plant? Is FERC suggesting that the so-called Edgar standards for a utility’s affiliate purchases be loosened?

FERC also sought comments on whether certain small renewable QFs, and perhaps certain small cogeneration facilities, may be so unique that the mandatory purchase obligation should remain in effect for them, and, if so, how small the QFs would have to be.

Mandatory Purchase Obligation


Once the mandatory purchase obligation has been removed, the law provides that it can be reinstated by the commission if a QF applies to FERC and can make a factual showing that there has been a material change in circumstances warranting relief. This right has been added to the proposed rules.

In addition, the commission proposed to incorporate into its regulations language from the Energy Policy Act that gives the commission the right to terminate a utility’s obligation to sell electricity to a QF if there are competing retail suppliers willing and able to sell energy to QFs and the utility is not required to sell electric energy in its service territory. As in the case of the mandatory purchase obligation, FERC has the power to reinstate the utility’s obligation to sell energy to a QF upon a QF filing and a factual showing that the basis for the termination of service no longer exists.

Passthrough Payment Protection

Ironically, in addressing the one component of the new PURPA section that actually suggests that FERC issue regulations to carry out the will of Congress, FERC has chosen not to do anything yet. The new law contains a provision that directs FERC to issue and enforce regulations to ensure that a utility recovers all prudently-incurred costs associated with a QF purchase under the contract. This provision was intended to codify case law that has held that state commissions cannot disallow the pass through to a utility’s ratepayers of QF payments made by the utility if they were made at or below the utility’s avoided costs at the time the purchase obligation was established.

This issue is important not only to purchasing utilities, but also to QFs whose contracts contain so-called “regulatory-out” clauses.

Regulatory-out clauses permit the purchasing utility to reduce payments to QFs to the extent that the utility cannot pass through the QF payment to the utility’s retail customers. Since issuance of the Freehold Cogeneration decision in 1995 by a US appeals court, which held that such pass through of payments was required by federal law, states have generally refrained from challenging the pass through of QF payments in retail rates, although a few have made statements that suggest that a future challenge may be in the offing. In the proposed rulemaking, FERC concluded that no regulations on this issue “were necessary at this time,” but sought comments about the need for such a regulation.