Energy & Infrastructure Alert
On July 16, 2020, the Federal Energy Regulatory Commission (“FERC”) issued a final rule that largely adopts FERC’s proposed revisions to its regulations under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Enacted in the late 1970s in response to the energy crisis, PURPA was intended to encourage the development of independent and renewable energy projects and reduce the electric industry’s reliance on traditional fossil fuels. Section 210 of PURPA requires FERC to issue rules requiring electric utilities to purchase energy and capacity from eligible cogeneration and small renewable power projects of 80 megawatts (“MW”) or less, known as “qualifying facilities” or “QFs.” FERC’s rules, in turn, are implemented by state regulatory commissions and non-regulated utilities such as municipal utilities.
As stated in the final rule, there have been sweeping changes in the electric industry since PURPA was first enacted, including the development of centralized wholesale energy and capacity markets, the rise of state renewable portfolio standards, and FERC policies mandating open access to transmission service. Nevertheless, energy project developers continue to rely on the mandatory purchase obligation set forth in PURPA to develop QFs, especially in areas of the United States that lack a centralized market, including large areas of the Pacific Northwest, the Southwest, and the Southeast. However, especially as fuel prices have declined over the last decade, electric utilities within these regions have raised concerns that the requirements of PURPA, as implemented in FERC’s current regulations, are unduly burdensome, requiring utilities to purchase energy and capacity that they do not need at prices they claim are too high.
Under Section 210 of PURPA, an electric utility must offer to purchase a QF’s available electric energy. However, FERC’s current regulations establish a rebuttable presumption that QFs with a generation capacity greater than 20 MW have nondiscriminatory access in certain organized markets managed by a regional transmission organization (“RTO”). Electric utilities operating within wholesale RTO markets, subject to FERC approval, can obtain relief from their mandatory purchase obligations under PURPA as they relate to QFs with a generating capacity in excess of 20 MW. Based on its understanding that QFs smaller than 20 MW have been participating in organized markets, FERC revised the PURPA regulations to lower the capacity threshold for the rebuttable presumption from 20 MW to 5 MW. Accordingly, under the revised PURPA regulations, electric utilities can seek relief from their mandatory purchase obligations with respect to QFs with a capacity in excess of 5 MW. However, utilities will not be relieved from the obligation to purchase energy and capacity from QFs with a capacity that does not exceed 5 MW.
PURPA requires electric utilities to purchase available electric energy from QFs at rates that are just and reasonable, in the public interest, do not discriminate against QFs, and that do not exceed the incremental cost of energy from other suppliers. As set forth in its current PURPA regulations, FERC requires electric utilities to purchase a QF’s available energy and capacity at a price representing the costs that the purchasing electric utility can save—i.e., its “avoided costs”—if the utility were required to generate itself or purchase from another source the same amount of energy or capacity. A QF currently has the option to require a utility to pay an avoided cost rate based on the projected costs of both energy and capacity over the term of the purchase arrangement, or at rates based on avoided energy costs that are calculated at the time of delivery. When FERC adopted its original rules implementing PURPA, it based the requirement that utilities offer fixed avoided energy and capacity rates for the term of the purchase obligation on the understanding that, without assurances of a fixed revenue stream, it would be difficult for QF projects to obtain financing.
The revised PURPA regulations eliminate the requirement that utilities offer avoided cost rates for energy—but not capacity—based on projections of avoided energy costs over the term of the purchase obligation. Accordingly, a QF will no longer have the option of “locking in” a rate for avoided energy costs when it enters into a sales contract or when the state commission imposes a “legally enforceable obligation” (“LEO”) for a utility to purchase power from the QF. Rather, states will have the option to set rates for sales based on the purchasing utility’s avoided energy costs, calculated at the time of delivery. A QF will, however, still be entitled to a fixed avoided cost rate for sales of capacity. While a variable avoided cost energy rate can be viable for cogeneration facilities that use fossil fuels whose costs are likely rise or fall with the purchasing utility’s fuel costs, it may present challenges for wind, solar, geothermal, and other “low variable-cost/high fixed-cost” technologies because they risk receiving lower avoided energy cost rates even though their internal fixed costs are not reduced. Price forecasts could mitigate concerns from financing parties but will not provide the same level of certainty as fixed energy rates currently available under the PURPA regulations.
In addition, states will be allowed to set energy and capacity rates based on a competitive solicitation process conducted pursuant to transparent and non-discriminatory procedures. FERC states that a “primary feature of a transparent and non-discriminatory competitive solicitation is that a utility’s capacity needs are open for bidding to all capacity providers, including QF and non-QF resources, on a level playing field.” Although states will have authority to prescribe detailed criteria for such competitive solicitations, FERC states that they must include, at a minimum, (i) an open and transparent process, (ii) open to all resources that satisfy the purchasing utility’s capacity needs, (iii) solicitations conducted at regular intervals, (iv) oversight by an independent administrator, and (v) certification by the state commission or unregulated utility that it satisfies these criteria.
If a state commission opts to allow QFs to retain their rights to fixed avoided energy cost rates, it can allow such rates to be set based on price forecasts, whether based on forecasted LMP, hub prices, or natural gas prices and heat rates. FERC states that, under this approach, the “fixed energy rate could be a single rate, based on the amortized present value of forecast energy prices, or it could be a series of specified rates that change from year to year (or other periods) in future years. FERC does not prescribe a forecast methodology, but states that it “must meaningfully and reasonably reflect the utility’s avoided costs over time.”
Because the current PURPA regulations provide QFs with the option for fixed rates, some state commissions have sought to limit the terms of their QF contracts so that the QF rate could be adjusted under a new contract. For example, Idaho has implemented a maximum two-year term for QF contracts. In response, QF developers and their trade groups requested that FERC establish a minimum contract length. FERC declined to do so, stating that it is within a state’s discretion to set appropriate contract lengths in a way that accurately calculates avoided costs. However, in its comments to FERC, the Idaho Public Utilities Commission stated that the implementation of variable avoided cost energy rates would allow states to consider longer-term contracts without putting ratepayers at risk.
The current PURPA regulations do not specify when or how a LEO is created. As a result, states have implemented a wide range of criteria regarding the establishment of a LEO. For example, some states require that a QF demonstrate that it has site control or construction permits in order to obtain a LEO.
As revised, FERC’s PURPA regulations require state commissions to establish objective and reasonable criteria to evaluate a QF’s viability and financial commitment to construct before the QF is entitled to a contract or other LEO. States will have flexibility to determine their own criteria, but FERC suggests that reasonable criteria could include confirmation that the QF owner (i) has taken meaningful steps to obtain site control, (ii) has applied for all local permitting and zoning approvals (and paid all related fees), and (iii) has applied for interconnection. In response to concerns that implementation of these factors could be problematic for QFs that have not yet obtained financing, FERC stated that it is “raising the bar to prevent speculative QFs from obtaining LEOs,” but it “is not establishing a barrier for financially committed developers seeking to develop commercially viable QFs.” FERC clarified that a state cannot require a QF to obtain a power purchase agreement or financing as proof of financial commitment.
Owners of renewable energy projects seeking certification as QFs must demonstrate to FERC that the project does not or will not have a net power production capacity greater than 80 MW. Under the current PURPA regulations, a QF must aggregate its own net power production capacity with the net power production capacities of any affiliated QF of the same resource type (e.g., solar or wind) within a one-mile radius. If the aggregate capacity of a renewable project and its affiliates within a one-mile radius exceeds 80 MW, the projects are not eligible for QF certification.
In recent years, utilities have complained to FERC that developers have “gamed” the one-mile rule by breaking up larger than 80 MW projects and locating affiliated QFs just outside the one-mile radius. In response, FERC revised the PURPA regulations to create a rebuttable presumption that projects located more than one mile but less than 10 miles from another affiliated project of the same resource type are not located on the same site and, therefore, should not be aggregated for purposes of determining QF eligibility. As discussed below, the revised PURPA regulations provide an opportunity for entities, including purchasing utilities, to rebut this presumption by filing a protest in response to a QF certification or recertification. In addition, the revised PURPA regulations provide that projects located at least 10 miles apart are deemed to be located on separate sites and, therefore, their capacities should not be aggregated under any circumstances.
A project can obtain QF status by filing with FERC either a self-certification or an application for certification by FERC. Most developers choose to self-certify because self-certifications are deemed effective upon filing. In either case, if a QF fails to conform to any material facts or representations presented in its filings to FERC, its QF status will be revoked. Accordingly, QF owners must submit filings to recertify their projects after any material changes, including with respect to technology, generation capacity, or upstream ownership. However, the current PURPA regulations do not specify a process for an entity to challenge a QF self-certification or self-recertification. Accordingly, the only way for an entity to currently challenge a QF self-certification or self-recertification is by filing a petition for declaratory order, which requires payment of a filing fee in excess of $30,000.
Under the revised regulations, purchasing electric utilities and other entities can file protests in response to a new QF certification or recertification presenting substantive changes that is filed on behalf of a renewable project on or after the effective date of the FERC order. Such protests can challenge the QF status of a renewable project by asserting that the project is located at the same site as an affiliated QF of the same resource type that is located more than one but less than 10 miles away, and that the projects’ aggregate capacity exceeds the 80 MW threshold for renewable QFs.
FERC has suggested physical and ownership factors that could be presented in a protest or defense for determining whether two affiliated projects that are located within one but less than 10 miles away should be deemed to be located on the same site. Physical factors include common infrastructure, property ownership, interconnection agreements, control facilities, access and easements, interconnection facilities, collector systems, step-up transformers, points of interconnection, fuel source, off-take arrangements, permits, property leases, and connections to the grid. Ownership factors include common ownership, control, operation, or maintenance by the same or affiliated entities; selling to the same electric utility; using common debt or equity financing; construction by the same entity within 12 months; sharing engineering or procurement contracts; managing a power sales agreement for a similar affiliated facility; and achieving commercial operation within 12 months of an affiliated project, as specified in a power sales contract.
If FERC determines that two or more affiliated QFs of the same resource type that are located within 10 miles of each other should be deemed to be located at the same site, then the capacities of the projects must be aggregated. If the aggregate capacity of a renewable QF and its affiliates exceeds 80 MW, then the projects would be deemed ineligible for QF status. However, third parties cannot protest certifications or recertifications filed on or before the effective date of the FERC order. In addition, owners of projects seeking QF status will be able to provide information in their applications, self-certifications, or recertifications to preemptively defend against any anticipated challenges. If a purchasing utility or other entity files a protest in response to a new QF certification or recertification, the QF owner will have an opportunity to respond.
The revised PURPA regulations could present challenges to the development of QFs that rely on the mandatory purchase obligation set forth in PURPA. As stated above, developing a QF in a state that allows variable avoided cost energy rates could limit financing opportunities. In addition, the new 10-mile rule and the ability of purchasing utilities and other entities to challenge whether two or more renewable QFs are located on the same site may cause developers and owners of such QFs to revise their development plans or sell off existing or planned QF projects. However, the revised regulations will not affect existing QFs or QF contracts as long as there are no substantial changes in the operation or ownership of the QF that require recertification.
The revised PURPA regulations are set to become effective 120 days after publication of FERC’s order in the federal register. Accordingly, assuming publication occurs within a month, the revised regulations are set to become effective before the end of 2020. Requests for rehearing or clarification of FERC’s order are due by Monday, August 17.