Under the Public Utility Regulatory Policies Act, avoided cost is what a utility would have spent to generate or purchase the next unit of electricity itself, and federal law makes that figure the maximum rate a utility can be required to pay an independent producer for power.1eCFR. 18 CFR 292.101 – Definitions Congress built this pricing standard into PURPA in 1978 to break the traditional utility monopoly over generation and open the grid to small-scale and renewable producers. There is no single national avoided cost number. The rate varies by utility, by state, and by year, because it depends on each utility’s own costs, fuel mix, and expansion plans.
The Statutory Ceiling and Why It Exists
PURPA establishes the avoided cost standard at 16 U.S.C. § 824a-3, directing FERC to write rules requiring utilities to buy electricity from qualifying independent producers and to sell electricity back to them.2Office of the Law Revision Counsel. 16 USC 824a-3 – Cogeneration and Small Power Production The statute caps what producers can receive at the “incremental cost of alternative electric energy,” meaning what the utility would have spent to get equivalent power from another source. That ceiling is a ratepayer protection. Consumers never pay more for independent power than they would have paid for the utility’s own generation.
FERC writes the national rules, but state regulatory commissions do the implementation work. Each state commission sets specific avoided cost rates for the utilities under its jurisdiction, holds hearings, and reviews utility financial data to verify the numbers track real market conditions. A solar developer in one state may see a very different avoided cost rate than one next door, even for an identical facility, because the underlying utility costs differ.
How the Rate Is Calculated
Avoided cost has two components. Energy costs reflect the variable expenses a utility avoids when it buys from a qualifying facility instead of running its own generators, primarily fuel and the operating wear on power plants. Capacity costs reflect the fixed investments a utility avoids in building or upgrading infrastructure to meet peak demand. If buying from an independent producer lets a utility delay or cancel a planned power plant, that deferred construction spending becomes the capacity component of the rate.
State commissions weigh a wide range of factors when setting these rates, including the utility’s existing generation mix, planned expansions, fuel procurement contracts, and the reliability characteristics of the producer’s output.3eCFR. 18 CFR 292.304 – Rates for Purchases Many commissions use a “proxy plant” method, benchmarking the capacity component against the estimated cost of a new high-efficiency natural gas plant. If the utility doesn’t need new capacity for years, the avoided cost rate may include only the energy component. That distinction matters enormously for project developers, who typically need reliable capacity payments to secure financing.
For utilities inside organized wholesale markets run by regional transmission organizations such as PJM or ISO New England, states may base energy rates on locational marginal prices, a market-derived figure that reflects the cost of delivering one additional megawatt to a specific grid point, accounting for generation costs, transmission congestion, and line losses.3eCFR. 18 CFR 292.304 – Rates for Purchases For utilities outside those markets, states can use prices from liquid trading hubs or formulas tied to natural gas indices, so long as the state finds those prices genuinely reflect the utility’s avoided costs.
Who Can Sell at Avoided Cost Rates
Only facilities that earn Qualifying Facility (QF) status under federal regulations can compel a utility to buy their power at avoided cost. The regulations recognize two categories: small power production facilities and cogeneration facilities.4eCFR. 18 CFR 292.203 – General Requirements for Qualification
A small power production facility generates electricity from renewable resources, meaning wind, solar, biomass, waste, or geothermal, and generally cannot exceed 80 megawatts of combined capacity when it sits at the same site as affiliated facilities using the same resource.5eCFR. 18 CFR 292.204 – Criteria for Small Power Production Qualifying Facilities To keep developers from splitting a large project into pieces, FERC treats affiliated facilities within one mile of each other as a single facility. A cogeneration facility produces both electricity and useful thermal energy from a single fuel source and must meet minimum efficiency thresholds set at 18 CFR 292.205 when it burns natural gas or oil.6eCFR. 18 CFR 292.205 – Criteria for Qualifying Cogeneration Facilities
A facility owner obtains QF status by filing FERC Form 556, which sets out the facility’s location, fuel source, ownership, and technical specifications. Self-certification takes effect immediately upon filing, and if no one protests, FERC takes no further action. The alternative is a formal FERC certification order, which provides a stronger legal foundation because the Commission has affirmatively reviewed the facility. A utility is not obligated to begin purchasing from a facility of 500 kilowatts or more until 90 days after it receives notice of QF certification.7eCFR. 18 CFR 292.207 – Procedures for Obtaining Qualifying Status
Fixed Contracts Versus As-Available Pricing
Every qualifying facility has the right to choose between two pricing structures.3eCFR. 18 CFR 292.304 – Rates for Purchases The first is as-available pricing. The producer delivers energy whenever it has power to sell, and the rate is whatever the utility’s avoided cost happens to be at the moment of delivery. No long-term commitment, and no price certainty either. The rate moves with fuel markets and grid conditions.
The second is a legally enforceable obligation, or LEO, a commitment to deliver energy or capacity over a specified term. Under a LEO, the producer can lock in rates based on avoided costs projected at the time the obligation is created, not the time the energy is eventually delivered. This is the option that makes project financing possible. A developer can take a long-term rate projection to a bank and borrow against predictable revenue. FERC has declined to set a minimum or maximum contract length, leaving that to individual states. State-mandated terms have ranged from two years to twenty.
To obtain a LEO, a facility must show “commercial viability and financial commitment to construct” under objective criteria set by the state commission.8eCFR. 18 CFR Part 292 – Regulations Under Sections 201 and 210 of PURPA FERC added that requirement in Order 872 to keep speculative projects from locking in favorable rates before they have any realistic prospect of being built.
The Mandatory Purchase Obligation and Its Exemptions
Under PURPA’s core mandate, a utility must purchase all energy and capacity that a qualifying facility makes available.2Office of the Law Revision Counsel. 16 USC 824a-3 – Cogeneration and Small Power Production The utility cannot refuse because it already has surplus generation or would prefer to build its own plant. The obligation exists even when the utility doesn’t want or need the power. Utilities must also provide QFs with supplementary, backup, maintenance, and interruptible power at rates that don’t discriminate against the facility compared to other customers with similar characteristics.9eCFR. 18 CFR 292.305 – Rates for Sales
The Energy Policy Act of 2005 opened a significant exemption. A utility can now apply to FERC for relief from the purchase obligation if the QF has nondiscriminatory access to competitive wholesale markets, meaning the producer has a real alternative buyer and doesn’t actually need the guaranteed sale.10Office of the Law Revision Counsel. 16 USC 824a-3 – Cogeneration and Small Power Production The regulations identify MISO, PJM, ISO New England, NYISO, and ERCOT as markets that presumptively satisfy this standard.11eCFR. 18 CFR 292.309 – Termination of Obligation to Purchase from Qualifying Facilities
Presumptions run differently depending on facility type and size. Small power production facilities of 5 MW or less are presumed to lack market access, so the utility must still buy their power. Those above 5 MW in an organized market region are presumed to have access, so the utility can seek an exemption, though the producer can rebut that presumption by showing barriers to interconnection or other obstacles. Cogeneration facilities use a higher threshold, with the no-market-access presumption extending up to 20 MW.11eCFR. 18 CFR 292.309 – Termination of Obligation to Purchase from Qualifying Facilities For producers outside organized market territories, the mandatory purchase obligation generally still applies regardless of size.
What FERC Order 872 Changed
FERC issued Order 872 in July 2020, the most significant overhaul of PURPA’s implementing regulations in decades.12Federal Energy Regulatory Commission. Qualifying Facility Rates and Requirements Implementation Issues Under PURPA – Order No. 872 The order responded to complaints that fixed-rate contracts were producing payments well above actual avoided costs, particularly in markets where energy prices had fallen substantially after contracts were signed. The revisions apply only to new contracts. Existing agreements are undisturbed.
The most consequential change gives states authority to require that energy rates in QF contracts fluctuate with the utility’s actual avoided costs at the time of delivery, rather than remaining fixed for the contract term. Capacity rates can still be fixed.12Federal Energy Regulatory Commission. Qualifying Facility Rates and Requirements Implementation Issues Under PURPA – Order No. 872 A producer signing a new contract in a state that exercises this option will know its capacity payments in advance but will see its energy payments rise and fall with market conditions. That shifts meaningful market risk onto the producer side and can complicate financing.
Order 872 also lowered the rebuttable presumption threshold for small power production facilities from 20 MW to 5 MW, making it easier for utilities in organized markets to shed the purchase obligation for mid-sized projects. And it added the commercial viability requirement for legally enforceable obligations. States retain broad flexibility in how they implement each change, so the practical effect varies by jurisdiction.
Interconnection Costs Are Separate
Getting a qualifying facility physically connected to the grid costs money, and those costs fall on the producer. Federal regulations define interconnection costs as the reasonable expenses for connection, switching, metering, transmission, distribution, and safety equipment that the utility incurs specifically because of the QF, measured as the amount exceeding what the utility would have spent generating equivalent power itself.13eCFR. 18 CFR Part 292 Subpart A – General Provisions These costs are explicitly excluded from the avoided cost calculation. A utility cannot reduce a producer’s energy payments to recoup grid connection expenses. They are a separate line item, and unexpected upgrade requirements on the utility side can add substantial costs and delays.
Disputes and State Filings
When a dispute arises over avoided cost calculations or contract terms, the producer must first raise the issue with its state regulatory commission, which holds primary authority over rate implementation. If the state process fails to resolve the matter, the producer can petition FERC or file in federal court to challenge whether the state’s approach complies with PURPA. The statute lays out this layered review at 16 U.S.C. § 824a-3(g) and (h).2Office of the Law Revision Counsel. 16 USC 824a-3 – Cogeneration and Small Power Production
Utilities are required to publish their avoided cost projections at regular intervals, typically every two years, including data on expected fuel costs and future generation needs. Those filings give developers the financial information they need to evaluate whether a new project pencils out, and they create a public record against which rate disputes can be measured. A utility that fails to make these filings, or that publishes numbers inconsistent with its actual planning data, faces enforcement action from its state commission.