NRRI

PURPA Tracker

State

RPS Policy[1]

Contract Term

Threshold(s) to Qualify[2]

Method

Avoided Cost Rate

QF Capacity

Energy

Capacity

Existing[3]

Under

Development[4]

AL

N/A

Varies

200 kW AC; must meet the eligibility requirements of Title 18, Part 292 of the Code of Federal Regulation

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

Varies by period (season); updated annually

 

123 MW

900 MW

U-19-010 (3/21/2019):  Self-certifying QF & avoided cost rates.

Docket #U-5213

AK

N/A

Varies

100 kW

 

28¢ per kWh

 

0 MW

 

TA284-13 (April 2016)

RCA Order U-17-053 (2018)

Article 2:  Cogeneration and Small Power Production

AZ

15% by 2025

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

100 kW

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

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

 

225 MW

 

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

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

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

Since 2016, the state’s biggest utilities have filed requests to allow restrictions on initial PPA contracts to two years and renegotiate them to update their avoided costs, to avoid overpaying for power.

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

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

AR

N/A

Not Specified

100 kW

Utility's estimated avoided costs of producing or purchasing electrical energy during the time period

$0.040¢ to $0.055¢ per kWh (2014)

$1,150 per kW (2023 dollars)

29 MW

N/A

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

CA

60% (2030); 100% (2045)

Short-term and long-term as available energy contracts based on market index formula & admin determined heat rate. Long-term firm capacity avoided costs based on market price referent

 

Proxy (fixed cost of CT)

Competitive bidding introduced in 2011

CAISO market rules are also apply

 

 

 

2,000 MW

 

Under the Re-MAT program, PURPA qualifying facilities are placed in a queue on a first-come, first-served basis. Every two months, utilities offer QFs at the head of the queue in their service territories a pre-defined price. QFs that reject the price keep their place in the queue for the next offering.

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

CO

30% (2020); 100% (2050)

 

500 kW – 80 MW

Colorado includes PURPA obligations in state IRP process.

2018 Levelized Contract Price (competitive bid price):

Wind: $29.18 ($19.00)/ MWh

Solar: $41.74 ($22.52)  MWh

 

 

2,200 MW

 

CT*

40% (2030)

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

20 MW - 80 MW

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

Eversource:  18.6¢ per kWh

 

18 MW

80 MW

Docket No. 16-03-08

Docket No. 16-03-08RE01

Docket No. 16-09-26

Connecticut Statutes § 16-243

The Connecticut Public Utilities Regulatory Authority submitted comments in response to the FERC NOPR released late-2019.

DE

25% (2026)

 

 

 

 

 

 

 

 

DC

100% (2032)

 

 

 

 

 

 

 

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

FL

N/A

 

 

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

 

 

 

1,600 MW

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...”

GA

N/A

 

 

Competitive bidding to determine cost of proxy unit

 

 

 

900 MW

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…”

HI

100% (2045)

 

 

 

 

 

 

 

 

ID*

N/A

Varies (see notes below)

No min

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

Depends on method, technology, and contract period.

Depends on method, technology, and contract period.

1,398 MW

11 MW

Contract term note:  20-year limit for SAR-based projects; 2-year limit for IRP-based projects. Thresholds of SAR-based published rates: 100 kW (wind & solar) and 10 MW (monthly basis) for all other resources. 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 Simple CCGT plant as a proxy for capacity payment.

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.

IL

25% (2026)

 

 

 

 

 

 

 

 

IN

10% (2025)

 

 

 

 

 

 

 

 

IA

 

 

 

 

 

 

 

 

 

KS

20% (2020)

 

 

 

 

 

 

 

 

KY

N/A

 

 

 

 

 

 

 

 

LA

N/A

 

 

 

 

 

 

 

 

ME

100% (2050)

 

 

 

 

 

 

 

 

MD

50% (2030)

 

 

 

 

 

 

 

 

MA

35% (2030) (new); 6.7% by 2020 for existing

 

20 MW (max)

Avoided cost based on

hourly market clearing

price for energy, monthly

clearing price for

capacity measured by

NEISO

 

 

 

 

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.

MI*

15% (2021)

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

Varies by utility: 0.00¢ to 1.87¢ per kWh

20 MW

2,500 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.

MN

26.5% (2025) (IOUs only; 31.5% by 2020 for Xcel)

 

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

 

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

0.00¢/kWh

 

 

 

MS

N/A

 

 

 

 

 

 

 

 

MO

15% (2021)

 

 

 

 

 

 

 

 

MT

15% (2015)

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)

N/A

364 MW

2,200

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.

NE

N/A

Varies

Individually determined

Standard Contract

Varies

 

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.

NV

50% (2030)

100% (2050)

 

 

 

 

 

 

 

 

NH

25.2%

(2025)

 

 

 

 

 

 

 

 

NJ

50% (2030)

 

 

 

 

 

 

 

 

NM

80% (2040)

100% by 2045 (IOUs only)

 

 

 

 

 

 

 

 

NY

50% (2030)

 

 

 

 

 

 

 

 

NC

12.5% (2021-IOUs Only)

10 years

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

Standard Contract

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

5,900 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.

ND

10%

(2015)

 

 

 

 

 

 

 

 

OH

12.5%

(2026)

 

 

 

 

 

70 MW

 

 

OK

15%

(2015)

 

 

 

 

 

514 MW

 

 

OR

50%

(2040) (large utilities only)

15 years

3,000 – 10,000 kW

Resource deficiency: proxy (CCCT)

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

 

 

490 MW

3,400

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.

PA

18% (2021)

 

 

 

 

 

925 MW

 

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

RI

38.5% (2035)

 

 

 

 

 

 

 

 

SC

2% (2021)

10 years

100 – 2,000 kW

Peaker method (Duke Carolinas)

2.134¢/kWh

N/A

229

 

6,900

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

SD

10% (2015)

 

 

 

 

 

140 MW

 

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

TN

N/A

 

 

 

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

 

 

 

 

TX

5,880 MW

(2015)

10 years

 

 

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

 

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

2019:  $80/kW (Capacity)

 

 

 

UT

20%

(2025)

Contract duration up to 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”

Rocky Mountain Power 2020 prices vary by technology and season:

1.369¢/kWh – 3.946¢/kWh

 

 

1,200

Regulators have sought shorter QF PPAs

Docket No: 19-035-T07 (06-2019)

VT

75% (2032)

 

 

 

 

 

 

 

 

VA

15% (2025)

 

 

 

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

 

 

 

 

WA*

15%

(2020) 100% (2045)

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)

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.

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.

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.

240 MW

25 MW

Threshold note:  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. – Chapter 480-106 WAC ELECTRIC COMPANIES—PURCHASES OF ELECTRICITY FROM QUALIFYING FACILITIES.

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.

WV

N/A

 

 

 

 

 

 

 

 

WI

10% (2015)

 

 

 

 

 

 

 

 

WY

N/A

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: varies from 1.27¢/kWh to 2.03¢/kWh (depends on resource type and season)

 

 

1,000 MW

 


[1] NC Clean Energy Technology Center – DSIRE Insight.

[2] Maximum threshold is the PURPA-established 80 MW, unless otherwise noted.

[3] Existing Projects:  EIA-860 data filtered by FERC-qualified small power producers; excludes cogeneration facilities.

[4] QF projects under development:  Brattle Report and EIA-860 (2018) proposed FERC-qualified small power producers; excludes cogeneration facilities.