Challenges and Opportunities for QFs, Part IV
by Laurel W. Glassman
The Energy Policy Act of 2005 created a number of challenges for qualifying facilities, but there remain significant-and unique-benefits and opportunities for them. In the first three parts of this series, we explored the regulatory changes that are impacting the qualifying facility industry, the technical operating requirements for new cogeneration QFs, and the new technical operating standards for cogeneration QFs-the “Productive and Beneficial Standard” and the “Fundamental Use Standard.” In this final part, we take a look at options and opportunities available for developers and the elimination of the utility ownership restriction.
A qualifying facility owned by FortisUS Energy. The Philadelphia facility is located on the Indian River near the village of Philadelphia in Jefferson County, New York. Photo courtesy of Fortis US.
Evidentally, contrary to rumors of the demise of the qualifying facility industry, it’s likely to grow.
Passing QF muster
Certain types of new cogeneration facilities will not be able to meet the more stringent new QF standards. For example, cogeneration facilities designed for the principal purpose of selling electricity at wholesale and only a small amount of steam to a greenhouse will no longer pass QF muster. The new standards, however, will by no means deal a fatal blow to the cogeneration QF industry. Developers may need to refocus their attention on opportunities that may be available to lease or purchase existing industrial cogeneration facilities or to replace those facilities with new on-site cogeneration facilities.
Developers may also wish to focus on smaller facilities because FERC has created a rebuttable presumption that both the Productive and Beneficial Standard and the Fundamental Use Standard are met with respect to cogeneration facilities that are 5 MW or smaller in size. In the preamble to the final rules, FERC stated that it was creating the presumption “because it is our experience that . . . smaller cogeneration facilities are designed to meet the thermal needs of the facility’s steam host and any electrical output available for sale is a byproduct of the thermal process.” This is somewhat obtuse, since only bottoming-cycle cogeneration facilities produce electricity as a byproduct of the thermal process. It is doubtful that FERC intended to convey the idea that small topping-cycle cogeneration facilities would not meet the new standards.
At the same time, existing cogeneration QFs must be cautious about making substantial changes to their technical operating characteristics. In the preamble to the new final QF regulations, FERC established a rebuttable presumption that an “existing” cogeneration QF does not become a “new” cogeneration QF simply because it files for recertification. However, FERC warned that “changes to an existing cogeneration facility could be so great (such as an increase in capacity from 50 MW to 350 MW) that what an applicant is claiming to be an existing facility should, in fact, be considered a “Ëœnew’ cogeneration facility at the same site.”
In light of FERC’s acknowledgment in the preamble that its mission is still to “encourage cogeneration,” FERC may be sending a message that changes in the technical operating characteristics of a facility that are not extensive would not cause a facility to lose QF status. In the future, this could well be a battleground for QFs and purchasing utilities.
Utility ownership restriction eliminated
Under the old Public Utility Regulatory Policies Act of 1978 regulatory program, a QF could not be owned primarily by an electric utility, electric utility holding company, or any combination thereof. This requirement was the subject of multiple rulemaking proceedings and a vast number of adjudicatory proceedings plumbing the depths of the term “primarily owned.” In essence, the regulations and case law established that QFs could not be more than 50 percent “owned” by electric utility interests, and “ownership” was determined with reference to equity interest and voting control.
EPAct 2005 directed the elimination of the utility ownership restriction. Elimination of the utility ownership requirement means, of course, that QFs can now be owned entirely by electric utility interests. Prior to making ownership changes involving such interests, however, existing QFs are strongly advised to review their power purchase agreements to be certain that those agreements do not bind them to follow the old ownership rule.
In addition, elimination of the utility ownership requirement means that QFs selling electric energy other than electric energy they produce (or purchase and resell from other QFs) will no longer trigger loss of QF status. That being said, FERC has made it clear that “any non-QF electric energy sold by a QF must be sold pursuant to the FPA,” meaning that a QF seeking to sell non-QF electric energy at wholesale must obtain prior FERC authorization pursuant to Section 205 of the Federal Power Act before engaging in such sales. Implicitly, this requirement applies to non-QF power sold by QFs that are 20 MW or less in size and therefore exempt under the new regulations.
Elimination of key exemptions from the FPA
Although not required to do so by the EPAct, FERC decided to eliminate certain exemptions from the FPA that most QFs had enjoyed under the old regulatory regime. In particular, FERC eliminated the exemptions from Sections 205 and 206 of the FPA that had previously been available to all cogeneration QFs and to small power production QFs sized at 30 MW or below. This exemption enabled QFs to make wholesale sales in interstate commerce without having to obtain prior FERC rate approval or having a rate schedule on file. Under the new regime, with respect to wholesale power sales under new contracts, QFs larger than 20 MW will now need to obtain market-based rate authorization from FERC or justify a given contract rate on a cost basis.
The new regulations provide an exception for new QF contracts under which sales are “made pursuant to a state regulatory authority’s implementation of PURPA.” What this means is that a QF selling electricity at an avoided cost rate established by a state regulatory authority to implement PURPA, whether or not the sale is made under a bilateral contract (including contracts at market-based rates), is not required to comply with Section 205 or 206 of the FPA. Unhappily, FERC has not provided any guidance as to how to determine whether a particular sale is made pursuant to a state regulatory authority’s implementation of PURPA. This may well cause significant problems for as-yet-to-be-developed QFs that secured power sales contracts prior to enactment of EPAct 2005.
[Editor’s note: This is the final part of a four-part series. To read Parts I, II and III, please visit www.elp.com -“Current Issue” – “Issue Archives” for January/February, March/April and May/June 2007.]
Laurel Glassman practices in the energy, infrastructure and project finance group at White & Case, LLP, resident in the firm’s Washington, D.C., office. She has more than 30 years of experience representing clients before the Federal Energy Regulatory Commission and has also represented clients before state public utility commissions and in federal courts. She routinely provides advice on complex qualifying facility issues and has published extensively on developments in the qualifying facilities sector.