PURPA Tracker

In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA) to encourage electric energy conservation, increase utility efficiency, increase fairness in retail rates for electric consumers, expand the use of hydroelectric production, and conserve the use of natural gas in electric power generation. PURPA was designed to accomplish this by creating a new class of electric generating facilities called “qualifying facilities” (QFs). The act gave QFs special rate and regulatory treatment for power production from non-utility sources, cogeneration facilities, small dams, and other resources that met the specified parameters.  During the last four decades, there have been substantial changes in the electric industry, including a rapid shift away from mostly “vertically integrated” utilities, the development of wholesale energy and capacity markets for most of the country, the adoption of renewable portfolio standards or goals in many states, and FERC policies mandating transmission access to non-utility providers.  Prices for new renewable sources have also fallen over the last decade and several developers have attempted to leverage QF status for new projects – particularly for solar developers.  This has resulted in questions regarding the need to revisit the application of PURPA.

FERC responded to these concerns in late-2019, by issuing a PURPA Notice of Proposed Rule Making (NOPR), primarily examining the four subsets of the act: 1. avoided costs rates; 2. the one-mile rule; 3. the obligation to purchase (rebuttable presumption); 4. the legally enforceable obligation (LEO); and 5. the self-certification of QFs.  Stakeholders submitted comments that represented a broad spectrum of reactions. Some concerned parties expressed issues relating to small generator access to RTO markets, while others questioned FERC’s authority to make the proposed changes. Supporters of the NOPR have largely highlighted the longstanding need to modify the rule in the interest of protecting end-use customers by moving away from long-term fixed prices for renewables.

After reviewing comments, FERC issued Order No. 872, 172 FERC ¶ 61,041on July 29, 2020.  The order revised PURPA in the following ways:

·         Lowers the capacity threshold for the rebuttable presumption from 20 MW to 5 MW

·         Eliminates the requirement that utilities offer avoided cost rates for energy (not capacity) based on projections of avoided energy costs over the term of the purchase obligation. Therefore, the avoided energy costs for a QF will no longer be “locked-in” when the LEO is established. 

·         Requires each state commission to establish objective and reasonable criteria to evaluate the financial viability of a QF prior to entering a legally enforceable obligation or other contract.

·         Introduces a process allowing entities to challenge the status of a proposed QF.

In response to the NOPR and subsequent Order, NRRI has developed the tool below to document the current application of PURPA for each state.  This includes the contract terms, thresholds to be deemed a QF (beyond what is required by FERC), the method used to determine the avoided cost rates for capacity and energy, (Proxy; Peaker; DRR; Market; Competitive Bidding), the avoided cost rate(s) for energy and capacity (where applicable), the amount of existing QF capacity, and recent developments or dockets related to PURPA.

The asterisk (*) indicates that state commissions have reviewed and approved all information. This version was released on August 10, 2020.  NRRI will continue to update this tracker in the coming months with the support of each commission. Please direct any comments or questions to NRRI staff.


Contract Term

Threshold(s) to Qualify

Method (Proxy; Peaker; DRR; Market; Competitive Bidding)

Avoided Cost Rate

QF Capacity

Comments and Recent Developments


Varies by project

200 kW

-  Proxy for coal or NG plant

-  Projected marginal energy costs, based on system dispatch modeling, using marginal spot fuel rates

-  Varies by period (season); updated annually

-  Alabama Power (2020): 2.256-3.449¢/kWh

123 MW

-  Docket #U-5213


Not specified; varies by project

100 KW

-  Proxy, based on: 1. monthly fuel costs attributable to each type of generation by month; 2. resource heat rate curves determined by the Association; 3. actual generation unit loadings for each hour; 4. metered energy deliveries from OF

Varies by utility: $0.02685/kWh to $0.08496/kWh

-  Municipality of Anchorage (2019):  0.04048¢/kWh

-  GVEA (2018): 0.28¢/kWh

30 MW (Railbelt total)

-  GVEA Tariff (2016)

-  TA284-13 (April 2016)

-  RCA Order U-17-053 (2018)

-  -  Docket R-13-002 – PURPA Regulations

-  Applicable Regulations: 3 AAC 50.750 – 3 AAC 50.820  - Cogeneration and Small Power Production

-  Article 2: Cogeneration and Small Power Production


18 years for nameplate capacity over 100 kw (APS, TEP)

100 kW (For QFs less than that, which are capable of delivering Firm Capacity, a provision shall be included in any such contract for payment of a reasonable credit of not less than 10% of the standard rate)

-  Long-term avoided cost methodology established by the Commission (takes into account market conditions)

-  PPA

-  Varies by project; long-term avoided cost methodology (established by the Commission)

-  TEP (2020) Renewables: 2.138-2.474¢/kWh

-  TEP (2020) Cogeneration:  2.135-2.955¢/kWh

- UNS Electric (2020) Renewables:  2.428-3.030¢/kWh

- UNS Electric (2020) Cogeneration:  2.135-2.955¢/kWh

225 MW

-  Arizona Public Service Co. (12/2019): E-01345A-16-0272

-  Amendment Related to DOCKET NO(S). E-01345A-16-0272

-  Tucson Electric (12/2019): E-01933A-17-0360

-  UNS Electric (12/2019): E-04204A-18-0087

-  Historically, PURPA projects were infrequent; ample coal-fired generation has kept AC rates low.

-  ACC submitted comments in response to the FERC NOPR released late-2019


-  At least 1 year for cogeneration (Entergy)

100 kW – 20 MW

-  Market-based (using MISO settlement data to develop monthly avoided cost rates)

-  Varies by period (season)

-  Entergy (2019):  2.521-3.493¢/kWh

-  Entergy (2019) capacity: $0.0/kW (under a long-term contract subject to approval of Commission)

29 MW

-  FERC approved Entergy request to terminate requirement to enter into new power purchase obligations or contracts to purchase electric energy and capacity from QFs with a net capacity in excess of 20 MW. Docket No. QM14-3-000 (2016)


-  Up to 7 years for existing QFs (Optional, As-available, SOCs Pending and ? 20 MW)

-  Up to 12 years for new QFs (SOCs Pending and ? 20 MW)

-  ReMAT and BioMAT: 10, 15 or 20 years

20 MW Max for New PURPA SOCs and ? 20 MW PURPA SOCs

-  Optional As-Available: See CPUC Decisions 10-12-035 and 07-09-040

- ReMAT: See Cal. Pub. Util. Code 399.20

-  BioMAT: Bioenergy renewable generators less than 5 MW in size per Decision 14-12-081

-  New SOCs (Pending) and BioMAT: Market

-  PURPA SOCs ? 20 MW: Proxy (fixed cost of CT)

-  Optional As-Available: Proxy (cost of CCGT)

-  Competitive bidding introduced in 2011

-  Under Re-MAT program, QFs are placed in a queue; every 2 months, utilities offered QFs at the head of queue at a pre-defined price. QFs that reject the price keep their place in the queue for next offering

-  PG&E (2020): 2.2361-3.5005¢/kWh

-  SCE (2020): 2.1547-3.6015¢/kWh

-  SDG&E (2020): 1.6274- 3.5600¢/kWh

-  Capacity:  As-available capacity price for 2020: $59.83/kW per year (CPUC Decision Nos. 10-12-035 and 07-09-040)

-  For new SOCs (Pending), prices specific to each facility; energy is based on LMP; capacity is based on Resource Adequacy prices

-  See ReMAT Program Information by Utility: PG&E; SCE; SDG&E

-  New SOCs (Pending): 126.2 MW

-  Optional As-Available: 146.35 MW

-  ReMAT: 493.6 MW

-  BioMAT: 250 MW


-  The CPUC submitted comments in response to the FERC NOPR released late-2019

-  Decision 20-05-006. Utility Standard Offer Contracts pending CPUC review

-  Decision10-12-035 adopted a QF and Combined Heat and Power Settlement Agreement

-  CPUC Decision 10-12-035 adopted a QF and Combined Heat and Power Settlement Agreement

-  In accordance with a federal court injunction, the Commission suspended the ReMAT program on December 15, 2017.

On June 26, 2020, the Commission issued an Assigned Commissioner’s and Assigned Administrative Law Judge’s Ruling to seek comment on proposed modifications to resume the ReMAT program, including a Staff proposal to use administratively determined prices by product category with a time-of-delivery adjustment.


Varies; QF is awarded contract under the Electric Resource Planning (ERP) process

500 kW

-  PURPA obligations included in state Electric Resource Planning (ERP) (AKA IRP) process

-  Competitive bidding option

-  Several small power producers have been awarded contracts through competitive bidding

2018 Levelized Contract Price (competitive bid price):

-  Wind: $29.18 ($19.00)/ MWh

-  Solar: $41.74 ($22.52) MWh

-  Xcel (2018): 10.7¢/kWh

Black Hills Energy (2020): 0.02810¢/kWh

2,200 MW (existing)


0.6 MW (under development by SDG&E)

-  Decision C18-1045

-  Black Hills Energy Avoided Cost Motion for Alternative Form of Notice



Pursuant to tariff or as to be determined pursuant to regulatory amendment

20 MW

ISO-NE Real-Time Market Price or as to be determined pursuant to regulatory amendment

-  Eversource (2018): 18.6¢ per kWh

-  Based on the ISO-NE market clearing price (See FERC Order No. 25,920 at 90 (July 1, 2016)

18 MW

-  Docket No. 16-03-08

-  Docket No. 16-03-08RE01

-  Docket No. 16-09-26

-  Connecticut Statutes § 16-243

-  PURA submitted comments in response to the FERC NOPR released late-2019


Not specified

1 MW

-  Based on each gas utility’s gas service rate (GSR) or gas commodity rate (GCR);

applied for the 3-year planning period

-  Avoided capacity cost from MEA study includes PJM capacity costs and transmission & distribution avoided capacity costs

-  PJM wholesale energy market rates

-  Delmarva Power (Year 2020 in 2016 dollars): $63.90/MWh (Residential) $70.28/MWh (Commercial)

-  Delmarva Power Capacity: $118.57/kW



Washington DC



Proxy –



-  DC PCS submitted comments in response to the FERC NOPR released late-2019




Proxy – utilities’ next avoided unit (ten year site plan)



-  20190079-EQ (7/15/2019): Duke Energy Corp., amending PURPA standard offer contract

-  20190088-EQ (6/3/2019): “Avoided Cost- shall be equal to the costs avoided by the Company's respective Full Requirements Wholesale Customers...”


Two options for Georgia Power: 1. Fixed Annual Capacity Payments; 2. Market Based Capacity Payments

Certification required for QFs larger than 1 MW (through self-certification or application to FERC).

-  GPSC Docket No. 4822: establishes methodology for capacity and energy payments to QFs pursuant to PURPA based on the peaker methodology

-  QF’s seeking a contract for capacity and/or energy for a fixed term and a fixed price, GPSC requires QFs to participate in RFPs

-  Process for executing an interconnection agreement and QF contract runs parallel

-  GPSC Docket No. 19279: approved proxy unit methodology for eligible QF contracts

-  GPSC Docket No. 16573 – (Green Energy Docket) – Requires Georgia Power to file annual solar AC determination

-  GPSC Rule § 515-3-4-.04(3): RFP procedures and related exceptions (QFs up to 30 MW in size are exempt from the RFP requirement)

Georgia Power ( (2020):

-  Solar: $30.73 MWh

-  Peak Season: Peak: $32.46 per MWh

-  Peak Season Off-Peak: $25.54 per MWh

-  Annual All Hours: $26.56 per MWh

- Capacity: $0.00 per year


-  Georgia Power (Document Filing #181568)

-  GPSC Docket No. 19279 – Approved the proxy unit methodology for eligible QFs contracts

-  No. 42310, -11, (7/29/2019): DG rates set at 5% below avoided cost

-  No. 42311 (7/29/2019): “…reevaluate and update as appropriate the avoided cost methodology used in Docket 4822, over the next year…”





Maui Electric (2018):  15.0¢/kWh




Varies; contract term note: 20-year limit for SAR-based projects; 2-year limit for IRP-based projects.

No min


Thresholds of SAR-based published rates: 100 kW (wind & solar) and 10 MW (monthly basis) for all other resources.

SAR method: CCGT (proxy for capacity payment) NG price forecast for energy payment)


IRP method uses hourly marginal price (single cost model run) or Portfolios With and Without a QF (double production cost model runs) to determine energy payment and uses CCGT plant as a proxy for capacity payment.

Depends on method, year, technology, and contract period; listed annually by utility:

-  Avista (2020)

-  Idaho Power (2020)

-  PacifiCorp (2020)

1,398 MW

-  Order No. 33357 where contract length is reduced to 2 years for IRP-based projects and Order No. 34350 to update the natural gas forecast used in the SAR model.

-  Order No. 28423

-  Case No. GNR-E-99-1

-  Case No. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03

-  Rocky Mountain Power - Avoided Costs Rates.

-  The Idaho Public Utilities Commission and Idaho Governor submitted separate comments in response to the FERC NOPR released late-2019.


Standard Contract and Wholesale Market Rates


Utility-filed rate with four rating periods (summer peak, summer off-peak, winter peak, and winter off-peak)

Varies by utility, season, and peak vs. non-peak periods; see Table 3-5; 2019 rates below:

-  Ameren: 2.254¢-3.804¢

-  ComEd: 2.288¢-3.348¢

-  MidAmerican: 1.620¢-3.220¢

-  Mt. Carmel: 4.491¢


-  220 ILCS 5/8-403.1















































BG&E (2018): 12.9¢ per kW

Delmarva:  14.2¢ per kWh






20 MW (max)

Based on

hourly market clearing

price for energy, monthly

clearing price for

capacity measured by


National Grid (2018): 22.8¢/kWh


-  220 CMR: Dept. of Public Utilities

-  The Massachusetts Department of Public Utilities and Massachusetts Attorney General submitted separate comments in response to the FERC NOPR released late-2019.


Varies by utility (10 to 15 years for Consumers Energy)

Varies by utility (100 to 2,000 kW)

Standard Offer: 550 kW – 2,000 kW

-  Competitive procurement

-  Any remaining capacity needs can be met by QFs at avoided cost rates set by the highest accepted bid (Varies by utility)

Varies by utility: 2.52¢ to 4.425¢ per kWh


Capacity: Varies by utility: 0.00¢ to 1.87¢ per kWh

20 MW

-  Consumers Energy (06/2019): U-18090

-  DTE (09/2019): U-18091

-  Alpena Power Company (12/2018): U-18089

-  Indiana Michigan Power Company (03/2019): U-18092

-  Northern States Power Company (12/2018): U-18093

-  Upper Peninsula Power Company (02/2020): U-18094

-  Upper Michigan Energy Resources Corporation (12/2018): U-18095

-  The Michigan Public Service Commission submitted comments in response to the FERC NOPR released late-2019.


No set term (See Subd. 6)

-  Cooperatives must compensate QFs less than 40 kW (Minnesota State Statute 216B.164, subdivision 3)

-  1 MW for public

-  100kW for municipals and cooperatives

-  Negotiated PPAs are required between the thresholds above (below 20 MW).

-  Statutes and Rules

-  .018640¢ – .11964¢/kWh for public utility distributed generation rates

-  Size Limits and QF Rates

-  Varies (See Subd. 3)

-  Net metering under 40kW (averages out what the retail rate would be and allows for offsetting kWh either paid at the retail rate or some other agreed upon rate)

-  Great River Energy: 0.01714¢/kWh – 0.0276¢/kWh (varies by season and on-/off-peak)

-  Capacity:  Varies by utility; GRE: 0.00¢/kWh


-  See Minn. Stat. 216B.164 and Minn. Rules Ch. 7835.

-  2020 rates (excluding CSG rates) are available in Docket No. 20-9.


















25 years (solar) Different terms depending on generation type: hydro: 24 years; wind: 23 years; thermal: 35 years.

100 kW – 3,000 kW

-  Competitive procurement

-  LEOs effectively contingent on winning RFP

-  Two proxy-based rates: (1) rate based on avoided costs or coal-fired plant as proxy or (2) wind only QF rate available using wind plant as proxy.

-  July 2019-June 2020: $49.01/MWh (escalating energy rate); $23.79/MWh (partially levelized escalating energy rate)

-  NorthWestern Energy (2020)

364 MW

-  April 2019: MT Court reverted contract length back to 25 years; ruled LEO standard no longer requires IAs or signed PPAs for small renewables.

-  November 2017: MPSC issued emergency order reducing contract lengths for small renewables from 25 to 15 years; cut rates for renewable projects up to 3 MW from $66/MWh (est. in 2012) to $31/MWh.

-  A Montana PSC Commissioner submitted comments in response to the FERC NOPR released late-2019.



Individually determined

Standard Contract


355 MW

-  No IOUs in Nebraska. Rates determined by individual utilities. Ex. Omaha Public Power offers standard contract up to 1 MW with an average rate around $0.0375/kWh.

-  The Nebraska Power Review Board submitted comments in response to the FERC NOPR released late-2019.

New Hampshire



-  Based on ISO-NE real-time energy market prices

Varies; 2020:

Non-Solar: $28.36/MWh (2.836¢/kWh)

Solar PV: $25.83/MWh (2.583¢/kWh)


Eversource (2018): 19.2¢ / kWh


Capacity:  Varies; 2020: $7.5/kW-month (90$/kWh/year)



New Jersey



Locational Marginal Price (LMP) in PJM

Varies; 2020 Average Hourly Rate (Jan-Apr): 16.5¢-21.6¢


Jersey Central Power & Light (2018):  13.6¢/kWh



New Mexico




El Paso (2018): 10.7¢ per kWh






New York




PSE&G (2018):  21.3¢/kWh





North Carolina

10 years

1,000 kW (will decrease to 100 kW once an aggregate of 100 MW of QFs receive contracts)

-  Competitive bidding process to solicit up to 2.7 GW from larger projects (-  1 MW) under a 20-year term.

-  Peaker as an option

-  DRR as an option

Competitive procurement:

-  45 month procurement

-  Long-term PPAs

-  30% limit on utility-owned assets

-  Managed by independent administrator

4,016 MW

-  NC Public Utilities Act – Article 1. General Provisions

-  July 2017, HB 589:

-  Reduced term from 15 years to 10 years

-  Set capacity limit of 1 MW (up to a total of 100 MW)

-  Created competitive solicitation process

-  The North Carolina Public Utilities Commission – Public Staff and North Carolina Attorney General submitted comments in response to the FERC NOPR released late-2019.

-  DOCKET NO. E-100, SUB 158: Biennial Determination of Avoided Cost

Rates for Electric Utility Purchases from

Qualifying Facilities – 2018

North Dakota

Black Hills:  20 years


-  Proxy

-  Black Hills uses a production cost model to determine the hourly costs of economically serving its system load over the 20 year QF contract period



-  Black Hills Testimony (2019)






70 MW







514 MW



15 years

3,000 – 10,000 kW

-  Resource deficiency: proxy (CCCT)

-  Resource sufficiency: energy-only, market-based QFs available

Varies by utility:

-  Idaho Power Company (2020)

-  PacifiCorp (2020)

-  Portland General Electric (2020)


490 MW

-  Shifted from adjudicatory procedures to rulemaking as the means to implement PURPA

-  The North Carolina Public Utilities Commission – Public Staff and North Carolina Attorney General submitted comments in response to the FERC NOPR released late-2019.






925 MW

-  The Public Utility Commission of Oregon submitted comments in response to the FERC NOPR released late-2019.

Rhode Island







South Carolina

10 years (currently under commission review)

-  1 MW min. at a single-metered location or aggregated across multiple-metered locations (reduced from 5 MW in 2019)

-  QFs - 1 MW must compete for a competitive solicitation


Peaker method (Duke Carolinas)

-  Dominion Energy:  $27.51/MWh-$32.52/MWh (varies by season and peak/off-peak periods

-  Duke Energy Carolinas: $29/MWh

-  Duke Energy Progress: $32/MWh

-  229 MW existing

-  81 MW under development

-  Energy Freedom Act signed into law in May 2019; directs utilities to offer minimum contract length of 10 years.

-  DOCKET NO. 2019-184-E - South Carolina Energy Freedom Act (H.3659)

South Dakota

10 years



-  Black Hills Energy: 0.0274¢/kWh-0.0524¢/kWh


140 MW

-  The South Dakota Public Utilities Commission submitted comments in response to the FERC NOPR released late-2019.





TVA offers qualifying facilities contracts in which avoided cost rates are updated monthly




10 years



-  2019: $58.02/MWh (Energy – Summer, Weighted Avg.)


-  2019: $39.75/MWh (Energy – Winter Weighted Avg.)


-  Oncor (2018):  12.0¢/kWh



Capacity (2019): $80/kW





15 years

-  Schedule 37 applies to Utah-located cogeneration QFs (1,000 kW or less)

-  Small power production QFs (3,000 kW or less)

-  Proxy/ Partial Displacement

-  Differential Revenue Requirement (“PDDRR”

Varies by technology and season:

-  Rocky Mountain Power (2020): 1.369¢/kWh-3.946¢/kWh


-  Regulators have sought shorter QF PPAs

-  Docket No: 19-035-T07 (06-2019)










? 20 MW

-  Short-term market-based rates

Virginia Electric and Power Company offers QF short-term market-based rates




Varies; New QF: 15 years from LEO date but not less than 12 year min from operational date. Existing QFs: 10 year min. New rule eliminates need to negotiate contracts for QFs <5 MW

[<]5 MW for standard offer contract [5-80 MW for negotiated PURPA contract] (see note below)


Each utility shall file and obtain commission approval of its avoided cost rate methodology for QFs with capacity greater than five megawatts. QF developers proposing projects with a design capacity 5 MW or less may choose to receive a purchase price for power that is set forth in such standard tariff.

-  Methodology for standard avoided cost rates for small (<5 MW) QFs set in rule

-  Each utility shall file and obtain commission approval of its avoided cost rate methodology for QFs with capacity greater than five MW

-  Capacity: Standard offer: based on projected fixed cost of the next planned capacity addition identified in the succeeding 20 years; ?5 MW: tariff option; - 5 MW: must receive commission approval of method used


-  Based on the utility's current forecast of market prices for the next 20 years.

-  Utility may incorporate daily and seasonal peak and off-peak period prices, by year; rates for individual utilities: PacifiCorp (2020); Puget Sound Energy (2019) Avista (2020)

240 MW

-  The UTC regulates only the investor-owned utilities in Washington. The majority of the state is served by consumer-owned utilities that offer their own PURPA rates.

-  June 2019: Adopted rule WAC 480-106 (DOCKET U-161024; GENERAL ORDER R-597) requires regulated utilities to publish standard avoided cost rates for both energy and capacity, and also requires utilities to provide standardized contracts for generators with 5 MW of capacity or less.


West Virginia









-  Northern States Power Company (Xcel Energy): 100 kW

-  Wisconsin Electric Power Company (We Energies) 300 kW

-  Madison Gas and Electric: 100 kW

-  Wisconsin Public Service Corporation: 20 kW






20 years

Rocky Mountain Power has two threshold requirements:

-  +1,000 kW and historic or

projected annual capacity factor of 70% or below, or

-  Average monthly energy of +10,000 kW and a annual capacity factor of +70%


-  Rocky Mountain Power: 1.27-2.03¢/kWh (depends on resource type and season)

-  High Plains Power, Inc.: $1.807¢/kWh