PURPA overhauled

PURPA overhauled

August 19, 2020 | By Robert Shapiro in Washington, DC and Caileen Gamache in Washington, DC

Independent cogeneration and small renewable energy projects — known as "qualifying facilities" or "QFs" — have lost key protections from merchant risks that they have relied on to help secure financing for the past 40 years.

This is one of many takeaways from changes that the Federal Energy Regulatory Commission made in July in how it implements a 1978 law called the Public Utility Regulatory Policies Act or PURPA.

After a four-year period of technical conferences and a proposed rulemaking, FERC issued a final rule on July 16 that substantially revised the PURPA rules for QFs, particularly renewable energy projects. (For additional background, see "PURPA Projects Become More Difficult to Finance" in the October 2019 NewsWire.)

The FERC rules in this area must be followed by the states. However, FERC is now greatly expanding the discretion of states to determine when a project deserves a binding power contract and to decide how that contract should be priced. The new FERC policy also allows potential power purchasers to challenge whether affiliated projects located fewer than 10 miles apart should be considered a single project for purposes of eligibility for PURPA benefits.

PURPA requires utilities to buy electricity from certain power projects, but only projects up to a certain size. If two projects are considered a single project because of overlapping ownership, then they may no longer qualify.

The FERC final rule is subject to rehearing within 30 days, and it may be challenged in court. We anticipate both will occur. The lone Democrat on the commission said in a published dissent that the rule is invalid.

The final rule is in FERC Order No. 872.

Developers and lenders have been asking lots of questions since FERC acted on July 16. A list of the most frequently asked questions — and answers — is at the end of this article.

Background

PURPA exempts independent power projects called QFs from typical utility regulation and requires utilities to buy power from such projects at a fair price.

PURPA required FERC to issue implementing rules that the individual states would then be required to implement. FERC determined that a fair price would be the utility's "avoided cost," or the cost that the utility would otherwise incur to generate the electricity itself or buy it from an alternate source.

FERC gave QFs the option to obtain an avoided-cost rate based on the real-time cost at the time of delivery of the power or to lock in rates when the power contract is signed based on the projected avoided cost of power over the term of the contract.

FERC gave the states considerable latitude in determining the avoided costs of their regulated utilities. Unregulated utilities, like most municipally-owned utilities and electric cooperatives, had to "self-implement" the PURPA rules as well.

Although PURPA has been largely eclipsed by state renewable portfolio standards in 29 states and the District of Columbia that require utilities to deliver a substantial percentage of the electricity they supply from renewable sources, PURPA remains relevant for smaller projects in organized markets served by regional transmission organizations, or RTOs, and in the states that lack an RPS standard. Therefore, the latest rule changes are more likely to affect projects in the non-RPS states.

Floating Prices

Fixed-price power contracts are now discretionary.

FERC has decided that states are only required to fix rates if there is a separate capacity component to the avoided-cost rates. The states have discretion to approve avoided-cost energy rates that vary with the market rates at time of delivery of the energy, even though the utility may be buying electricity under a long-term contract.

To be clear, the new rules allow the states to continue to set fixed avoided-cost rates for energy for the term of the contract if they choose to do so. Parties may also continue to enter into PURPA contracts with terms that vary from the PURPA rules by mutual agreement.

Many intervenors in the FERC proceeding challenged the proposal to make fixed energy rates discretionary at the state level, arguing that floating rates would make project financing difficult, if not impossible. FERC justified the switch to short-term avoided cost rates on the grounds that many non-QF renewable energy projects (mostly those whose sizes exceed the 80-megawatt ceiling for QF eligibility) have been able to sign fixed-rate contracts without having to fall back on a statute ordering utilities to sign.

What FERC ignored is that most of the renewable power purchase agreements today are being signed either by utilities that are under state obligations to comply with state RPS standards or by corporations that are trying to meet internal goals to reduce their carbon footprints or lock in long-term power prices. The utilities in RPS states recognize the value of fixing rates for periods of 20 to 30 years while they are trying to comply with renewable purchase mandates that are increasing over time.

FERC also ignored the dramatic reduction in solar and wind electricity prices that has occurred over time. It arguably rebuts the historic claims by certain utilities and state commissions in non-RPS states that fixed prices lead inevitably to prices that exceed the utilities' avoided costs over time.

Under the new FERC policy, there will be a rebuttable presumption in the future that the locational market price, or LMP, in organized markets is the "as-available" avoided cost of utilities.

The commission said that states outside the organized markets can base avoided-cost determinations on a liquid market hub (like Palo Verde or Mid-Columbia) that is used by the particular utility for some of its transactions or use a formula based on a natural-gas index and specified heat rates for a combined-cycle gas-fired power plant.

FERC said that states can also use prices based on the outcome of competitive solicitations as long as the solicitations are open to "all sources" and are not limited, for example, to renewable energy. Any such solicitations must be evaluated by an independent administrator and be conducted at regular intervals.

At bottom, states and utilities that have historically promoted QF facilities will continue to use fixed energy rates in long-term contracts, and states and utilities that have historically discouraged QF facilities will use the new, more flexible rules to limit their purchases to "as-delivered" or "as-available" spot energy rates.

One-Mile Rule

With limited exceptions, PURPA applies only to renewable energy projects that are no larger than 80 megawatts in size. Smaller projects qualify for additional regulatory benefits.

Project capacity is measured by combining renewable generating equipment, such as turbines or solar arrays, with any affiliated equipment that uses the same fuel source at the same "site." Congress authorized FERC to determine what constitutes a "site."

In the past, FERC used a one-mile rule. Equipment within one mile apart has been treated as on the same site; equipment more than one mile apart is considered part of a different project.

The new FERC policy draws three lines. Equipment within one mile apart is on the same site. Equipment 10 or more miles apart is not. There is now a "rebuttable presumption" that equipment in between one and 10 miles apart is on different sites: utilities can challenge the presumption by showing common characteristics between the projects.

Organized Markets

Congress amended PURPA in 2005 to allow FERC to exempt utilities in organized markets from the mandatory purchase obligation.

FERC used this authority to exempt utilities in areas with competitive spot markets, like PJM, ERCOT, CAISO, MISO, NYISO and the New England ISO, from having to buy electricity from projects that are larger than 20 megawatts in size.

FERC decided that requiring smaller projects to comply with complicated RTOs rules for electricity sales would be both too expensive and too burdensome, depriving small projects of nondiscriminatory access to such markets.

Under the new policy, utilities in organized markets will no longer have to buy electricity from projects that are more than five megawatts in size. This was a compromise. FERC had originally proposed to reduce the figure from 20 megawatts to one megawatt.

FERC kept the 20-megawatt standard for cogeneration facilities on the theory that electricity generated at such facilities is a byproduct of making steam for an industrial use, and owners of cogeneration facilities might not be as familiar with energy markets and the technical requirements for electricity sales.

FERC said it will consider proposals to terminate the mandatory purchase obligation for individual utilities operating outside organized markets run by RTOs.

FERC said it might be possible for such a utility to demonstrate that it is in a workably competitive market by demonstrating that it uses market hubs or competitive solicitations to buy and sell electricity. The utility would have to demonstrate that the particular market is of comparable quality to the real-time and day-ahead markets that exist in most RTOs.

Commercial Viability

PURPA required utilities to enter into a "legally enforceable obligation" to buy electricity from qualifying facilities, a phrase FERC never clearly defined. Its meaning has led to many disputes at the state level.

The new policy requires the avoided-cost price for electricity to be established when the legally enforceable obligation is established, but FERC has left wide discretion to the states to determine when that occurs.

An independent generator seeking a power purchase agreement or other "legally enforceable obligation" must demonstrate commercial viability and a financial commitment to construction of its project pursuant to objective and reasonable state-determined criteria.

FERC made clear that "the states have flexibility as to what constitutes an acceptable showing of commercial viability and financial commitment, albeit subject to the criteria being objective and reasonable."

FERC said a generator might show commercial viability by showing that it is in the process of completing at least some key steps. For example, it has site control adequate to build the project at the proposed location, and it filed an interconnection application with the local utility or grid operator.

FERC said states can require the generator to show that it has submitted applications and paid the filing fees for all necessary local permitting and zoning approvals.

As to "financial commitment," FERC was less specific. It said that "demonstrating the required financial commitment does not require a demonstration of having obtained financing."

Once again, states and utilities that historically have encouraged QF development can be expected to take a lighter hand in establishing conditions before a qualifying facility is entitled to a "legally enforceable obligation" than states and utilities that have historically opposed QF development.

FERC declined to decide whether utilities must offer a minimum contract length. This will be left to the states to decide.

Common Questions

Project developers and lenders have been asking lots of questions since FERC acted. Here are the most common questions.

1. My solar project QFs are each 70 megawatts in size, and they are nine miles apart. Are they no longer QFs?

A: The new rules only apply prospectively, and FERC will not permit any "disturbance" of QF certifications filed before the effective date of Order No. 872. If the projects file to re-certify QF status due to a substantive change, they will remain separate projects under a rebuttable presumption that they are at separate sites, but their status will become vulnerable to challenge and potential revocation. A project will retain QF status, even if challenged, until FERC finds the project does not qualify as a QF.

2. How is the distance between two sets of wind turbines or solar arrays measured?

A: The distance is measured from the edge of the closest "electrical generating equipment." Inverters are considered "electrical generating equipment," but other assets such as substations and transformers are not. For a wind farm, the relevant point is the edge of a wind facility tower and not the wingspan of the turbine blades.

FERC is revising its Form 556 for QF status to require geographic coordinates of these points so that it can check the distance between the applicant and any affiliated QFs using the same resource located less than 10 miles away.

3. Should we expect to have to defend all of our future QF filings?

A: Yes, for renewable energy projects that would be more than 80 megawatts in size if combined with an affiliated project using the same resource more than one, but less than 10, miles away.

A utility that is required to buy electricity from a project may want to terminate the obligation by arguing that other turbines or solar arrays more than one mile, but less than 10 miles, away are part of the same project.

Any interested party may file a request for a declaratory order challenging the QF status of a project. (There is a filing fee.) This was true under the old rules, but now there is a better chance of disqualifying a project.

The filing fee is now waived for challenges that are made within 30 days after a project files for initial certification or re-certification of QF status.

FERC's regulations will continue to state that a QF that "fails to conform with any material facts or representations" of its last FERC Form 556 QF filing may not rely on its QF status.

Under the new policy, only those re-certifications that report "substantive" changes are subject to challenge. Importantly, FERC views a change of 10% or more direct or indirect equity interest in a QF as a "substantive" change, irrespective of the fact that ownership is not an element of QF eligibility.

The revised FERC Form 556 will include space to make a defensive argument as to why the project should not be aggregated with affiliated projects located less than 10 miles away. Some industry participants estimated this may require an additional 90 to 120 hours to prepare the FERC Form 556.

4. Does the one-to-10 mile rule also govern whether a QF qualifies for regulatory exemptions?

A: Yes.

A major benefit of QF status is broad exemption from utility regulation under the Federal Power Act, the Public Utility Holding Company Act and state utility laws.

For many renewable energy projects, these exemptions apply only if the project is 30 megawatts or less in size (and additional exemptions are available if a project is 20 megawatts or less in size). Historically, FERC has relied upon the one-mile rule to determine whether a project qualifies. It will continue to do so under the new policy.

However, projects located more than one mile apart will be presumed to be located on separate sites so that their capacities will not be aggregated, unless and until a protest is filed and FERC finds they are located on the same site. If a protest is filed, it may be prudent for the project to start planning to comply with public utility regulations if there is a significant risk it may lose exemptions.

5. Does the one-to-10 mile rule apply to the five-megawatt presumption for determining whether a project lacks meaningful access to competitive markets?

A: No.

In contrast to determining eligibility for QF status, which focuses on whether facilities are located at the same "site," the determination of whether a QF has meaningful access to a competitive market focuses on the QF itself.

However, under the new policy, the fact that affiliated facilities are nearby may be relevant when evaluating whether a QF has nondiscriminatory access to a competitive market in a FERC section 210(m) proceeding. That is a proceeding to determine whether a utility may terminate its mandatory purchase obligation.

6. If two sets of affiliated wind turbines or solar arrays are within 10 miles of each other, how will FERC decide whether they are located at the same "site"?

A: The determination will be fact based, and no one fact or factors will be determinative. FERC said it will take into account physical characteristics such as the following:

infrastructure, property ownership, property leases, control facilities, access and easements, interconnection agreements, interconnection facilities up to the point of interconnection to the distribution or transmission system, collector systems or facilities, points of interconnection, motive force or fuel source, off-take arrangements, connections to the electrical grid, evidence of shared control systems, common permitting and land leasing, and shared step-up transformers.

FERC said it will also look at the degree of common ownership and other characteristics such as the following:

whether the facilities in question are . . . owned or controlled by the same person(s) or affiliated persons(s), operated and maintained by the same or affiliated entity(ies), selling to the same electric utility, using common debt or equity financing, constructed by the same entity within 12 months, managing a power sales agreement executed within 12 months of a similar and affiliated small power production qualifying facility in the same location, placed into service within 12 months of an affiliated small power production QF project's commercial operation date as specified in the power sales agreement, or sharing engineering or procurement contracts.

The burden of proof that the projects are at the same site is on the utility or other person protesting separate treatment.

7. Do solar rooftop companies that have been tracking distance for purposes of the one-mile rule, mostly to determine whether to file a FERC Form 556, now need to track 10-mile distance?

A: No. FERC did not change the standard and, in fact, it confirmed the one-mile rule still applies for determining whether to file a FERC Form 556.

If FERC determines that rooftop installations located more than one, but less than 10, miles apart are on the same site, then the one-megawatt threshold for filing will need to be re-evaluated.

As an aside, FERC adopted a new re-certification policy for rooftop solar. Any re-certifications should be filed on a quarterly basis, within 45 days after the end of the calendar quarter.

8. The power purchase agreements for two wind farms owned by the same company require the projects to maintain QF status throughout the PPA terms. Each project is 50 megawatts. The projects are nine miles apart. Are they at risk of losing their PPAs?

A: Not unless there is a substantive change in the projects that requires re-certification in the future. The new rules apply prospectively. Even if the projects are re-certified, they will be protected by a rebuttable presumption unless and until FERC determines they are located on the same site.

Many utility PPAs with renewable energy projects require that QF status be maintained. The specific language used in the contract is important. For example, the contract may include a "change-in-law" provision that applies in this situation.

9. The PPA for an 18-megawatt solar facility in MISO terminates if the utility is no longer obligated to purchase power from QFs. Will the PPA terminate?

A: Probably not. Utilities in MISO must purchase from QFs that are up to 20 megawatts in size, unless they can prove the QF has nondiscriminatory access to the MISO market. The size threshold has been reduced to five megawatts under the new policy. The new policy will only apply prospectively, and it "does not permit disturbance of existing contracts or [legally enforceable obligations] or existing facility certifications."

The specific terms of the PPA should be reviewed to determine whether there are any other relevant provisions.

10. Is there anything a lender or equity investor should include to protect its interests in a loan or investment agreement currently under negotiation?

A: If the project is not in an organized market and has a PPA that requires it to be a QF, then the lender should consider whether to ask the sponsor to represent and covenant that the project is not, and will not be, located within 10 miles of an affiliated QF using the same resource if the two projects combined would exceed 80 megawatts in size.

For projects in organized markets, some investors rely on the mandatory purchase obligation of utilities to gain comfort with the "tail" risk after the PPA terminates. If the project is greater than five megawatts in size, then that mandatory purchase obligation should no longer be relied upon.