Utilizing PURPA in Today's Deregulated Wholesale Market

Utilizing PURPA in Today’s Deregulated Wholesale

Market June 5, 2012

12:00-1:30 pm EDT

Peter Richardson, Esq Ken Kaufmann, Esq. Richardson & O’Leary Lovinger Kaufmann LLP

Presented by EUCI

Natural Gas prices have fallen sharply . . .

June 5, 2012 2 Utilizing PURPA in Today’s Deregulated Wholesale Market

Source: U.S. Energy Information Administration, based on North American Electric Reliability Corporation, 2012 Summer Short-‐Term Reliability Assessment.

Summer Reserve Margins are healthy . . . .


BPA can’t give away enough energy . . .


With depressed natural gas prices, meager load growth, ample summer capacity reserves, and seasonal overabundance of energy, some of you may be asking whether PURPA remains relevant to the United States’ energy policy framework.

For the next 90 minutes, we will talk about how PURPA shaped national energy policy during the last 30 years; current legal issues involving PURPA, and Vinally, how PURPA likely will remain relevant in the future.


Overview I.  PURPA 101-‐What is PURPA? (10 min)-‐Peter

II.  How Avoided Costs are calculated (10 min)-‐Ken

III.  PURPA’s Evolution-‐-‐1980 to EPAct’05 (20 min)-‐Peter

IV.  Current PURPA legal issues (20 min)-‐Ken

V.  PURPA Opportunities and Risks Going Forward (15 min)-‐P/K

VI.  Q&A


I. What is PURPA?

•  Public Utilities Regulatory Policies Act of 1978 Pub. L. No. 95-‐617, 92 Stat. 3117)

•  Part of the National Energy Act (Vive pieces of major legislation)

•  Congress’ primary policy objectives: –  Reduce demand on fossil fuels –  Overcome utilities’ reluctance to purchase power from, and sell power to, non-‐utility generators


Obstacles prior to PURPA: Problem: PURPA solution for “Qualifying

Facilities”

Utilities not willing to purchase electric output/pay reasonable price for non-‐utility generation

Each electric utility must offer to purchase available energy and capacity from QFs at just and reasonable, non-‐discriminatory rates.

Utilities charged discriminatorily high rates for back-‐up service to non-‐utility generators

Each electric utility must offer to provide electric service to QFs at just and reasonable, non-‐discriminatory rates.

Non-‐utility generator still subject to extensive state and federal utility regulation

QFs exempted from FPA, PUHCA, and State utility-‐type regulations

I. What is PURPA?


QF defined

Cogeneration Facility Small Power

Production Facility

Not owned by persons primarily engaged in generation or sale of electric power*

or

and

*repealed by EPAct ‘05

I. What is PURPA?


CogeneraHon Facility

•  A facility which produces electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating, or cooling purposes.

•  Policy: Cogeneration facilities use signiVicantly less fuel to produce electricity and steam (or other energy) than would be needed to produce the two separately.

•  No maximum size for PURPA eligibility

•  SpeciVic requirements at 18 CFR §§ 292.202-‐205


I. What is PURPA?

Small Power ProducHon Facility

•  A facility which uses biomass, waste, or renewable resources, including wind, solar energy and water, to produce electric power; which, together with any other facilities located at the same site, has capacity ≤80MW.

•  Policy: Reliance on these sources of energy can reduce the need to consume fossil fuels to generate electric power.

•  SpeciVic requirements at 18 CFR §§ 292.202-‐204


I. What is PURPA?

Ownership limitaHon

•  A small power production facility or cogeneration facility

•  “which is owned by a person not primarily engaged in the generation or sale of electric power, (other than electric power solely from [QFs])”

•  Policy: Congress didn’t want PURPA’s regulatory exemptions to apply to utilities.


I. What is PURPA?

To Whom does PURPA apply? (A) The term "electric utility" means a person or Federal or State agency (including an entity described in section 201(f) of this title) that sells electric energy.

(B) The term "electric utility" includes the Tennessee Valley Authority and each Federal power marketing administration. -‐-‐FPA §3(22), 16 U.S.C. §796(22).

PURPA must-‐buy obligation applies to IOUs, Munis, PUDs, Co-‐Ops, water districts, etc. [unless FERC grants a waiver or excuses utility under §210(m)].


I. What is PURPA?

Purchase Price defined PURPA § 210(b) FERC Implementation (292.101(b)(6)):

Rates: (1) shall be just and reasonable to the

electric consumers of the electric utility and in the public interest, and

(2) Shall not discriminate against cogenerators or small power producers.

Rates also must not exceed the incremental cost to the electric utility of alternative electric energy.

Rates must equal the utility’s “full avoided costs”: “the incremental costs to the electric utility of electric energy or capacity or both which, but for the purchase from the QF or QFs, such utility would generate itself or purchase from another source.”

In implemenHng PURPA, FERC opted to require uHliHes to pay the full avoided cost. However, PURPA is not intended to subsidize QFs.


I. What is PURPA?

QF regulatory exempHons

•  Congress authorized FERC to exempt some QFs from parts of the FPA, PUHCA of 1935, and state regulations—FERC exercised this power broadly in 1980: –  FPA: §§ 205, 206 (rate regulation) –  Also exempt from FPA §§203, 204, 208, 301, 302, 304, 305 –  PUHCA: “electric utility company” does not include QFs –  No state regulation of QFs if inconsistent with PURPA

•  Exemptions do not apply to QFs > 30MW except for biomass projects


I. What is PURPA?

Recap

•  PURPA created a new regulatory status called Qualifying Facilities, or QFs

•  QFs have a right to be served by, and sell to electric utilities at the utility’s avoided cost

•  QFs have a right to interconnect and wheel to any electric utility

•  QFs exempt from many federal and state regulations


I. What is PURPA?

II. How are Avoided Costs calculated?

•  PURPA is the only area where States get to regulate wholesale power sales rates

•  States have tried many different approaches.

•  Methods include: –  1. Proxy –  2. Peaker –  3. Partial Displacement, Differential Revenue Requirement

(PDDRR) –  4. Fueled rates –  5. Auction

•  Generic examples follow (every state varies)


Proxy Resource methodology

Avoided Cost := Cost of utility’s next planned resource addition (called the “Proxy Resource”; usually a Combustion Turbine)

Energy cost = f(heat rate, gas price forecast, variable O&M, capacity factor, etc. of the Proxy plant)

Capacity cost = f(plant cost, Vixed O&M, taxes, etc. of the Proxy plant)

II. How Avoided Costs are Calculated


Peaker methodology

Avoided Cost := value of the QF operated as a peaker,

Energy cost = marginal system energy cost (lambda)*QF gen pattern

Capacity cost = f(plant cost, Vixed O&M, taxes, etc.) of least cost capacity (typically a CT)



ParHal Displacement (PDDRR) methodology

Avoided Cost := System revenue requirement (without QF) – System revenue requirement (with QF)

Energy cost = difference in system revenue requirement with and without the (zero cost, must run) QF.

Capacity cost = difference in capacity acquisition costs with and without the QF



Fueled Rates

Avoided Cost := avoided capacity + indexed energy

Energy cost = Vixed component and variable monthly gas index price

Capacity cost = On-‐peak energy paid an avoided capacity cost adder based on avoided capacity



AucHon/RFP Rates

•  Utility issues a Request for Proposals.

•  Selection based on price only or other factors.

•  Successful bidders receive capacity contracts.

•  Unsuccessful bidders may sell energy but not capacity.



Standard Avoided Cost Rates

•  FERC requires for QFs 100 kW and less

•  States may allow standard rates for larger QFs

•  May be based on: –  Replacement cost (Proxy) –  Displacement value (Peaker, PDDRR) –  Other



Avoided Cost methodologies compared:

Proxy Peaker PDRR Standard Fueled Auction

Pro: Simple; transparent

Better match to QF than the Proxy; simpler than PDRR

Theoretically correct; unit speciVic

Simple; low transaction cost

Eliminates risk of fuel price forecast error

Market determines appropriate price

Con: QF might be very different from the proxy unit; timing of QF output not taken into account

Ignores impact of the QF on utility’s marginal cost

Black Box; lack of regulator and QF buy-‐in; time-‐consuming

Risk of oversupply if rate is set too high; Inaccurate if not timely updated

Ratepayers remain exposed to fossil fuel price Vluctuations

Smaller QFs might be non-‐competitive

Basis: Admin. Admin. Admin. Admin. Market index.

Market



Summary: •  Administratively Determined Avoided Costs:

•  Used initially because of lack of established market •  Use continued because smaller QFs not competitive in an all-‐

source bidding •  Can be harmful if rates set too high

•  Auction-‐based pricing •  May yield lower prices for ratepayer •  May be impracticable for small suppliers

•  Today most states use: •  Competitive procurement for large facilities •  Administratively determined, or managed competition, for

small QFs



III. PURPA evoluHon milestones

•  Early years of success and excess

•  Energy Policy Act of 1992 and Southern Cal Edison

•  Energy Policy Act of 2005

•  CPUC decision 133 FERC ¶ 61,059 (2010)


Early PURPA capacity installed exceeded expectaHons

•  In 1980, FERC predicted 2,636 MW of installed QF capacity by 1985; actual total in 1985 estimated at 12,120 MW.

•  California IOUs scrapped plans for 22 coal plants •  In some cases, QF response to standard rates was overwhelming: •  New York: $60/MWh price Vloor led to massive oversupply and subsequent buyout of 14 QF contracts totaling $3.9 billion and 23% of Niagara Mohawk equity

•  California: Standard Offer 4 (SO4) contract—more than 16,000 MW subscribed in 15 months

III. PURPA evolution milestones


Energy Policy Act of 1992

•  PURPA demonstrated the likely feasibility of competitive wholesale generation market

•  EPAct ‘92 expanded some of the beneVits of PURPA to non-‐ QFs •  created Exempt Wholesale Generator

•  exempt from PUHCA of 1935 •  Allowed to sell output under market based rate tariff

•  authorized Open Access •  FERC implemented with Order 888 and its progeny



So. Cal Edison-‐70 FERC ¶61,215 (1995)

•  California IOUs challenged: •  CPUC order to exclude non-‐QFs from their RFPs (QF bids at $66 over non-‐QF bids at $40)

•  CPUC order to pay QFs an “environmental adder” based on their lack of harm to air quality

•  FERC (concerned about stranded costs) agreed with the IOUs: •  In determining the avoided cost rate, the electric utility must take into account all sources including non-‐QFs

•  Adders violate PURPA if they exceed avoided cost



So. Cal Edison-‐ctd.

•  “Congress . . . Did not in any way limit the sources to be considered. The consequence is that regardless of whether the State regulatory authority determines the cost administratively, through competitive solicitation (bidding) or some combination thereof, it must in its process reVlect prices available from all sources able to sell to the utility whose avoided cost is being determined.”

•  “[If O]nly QFs were then permitted to bid against the benchmark, such a procedure could not properly determine avoided costs because it excluded potential sources of capacity from which utilities could purchase, in contravention of the requirements of Section 210 of PURPA and our regulations.”



Low gas prices in the ’90s limited PURPA growth

June 5, 2012 Utilizing PURPA in Today’s Deregulated Wholesale Market 31


Comparison between QFs and EWGs circa 1995

QF EWG

Right to Sell at Avoided Cost: X Right to wheel to another utility: X X Exempt from utility-‐like regulation: X X Sales price: ≈CCCT price ≈CCCT price



During the mid-‐1990s, avoided costs for EWGs largely were derived from the cost of CCCT or SCT. QFs largely could not Vinance their projects at such avoided costs until gas prices rose and the capital cost of renewables fell.

Backdrop to Energy Policy Act of 2005

•  Gas prices tripled from 1999-‐2005

•  RECs, PTCs, Accelerated Depreciation subsidize cost of renewable projects

•  Large scale wind turbine technology maturing

•  Open Access to transmission largely accomplished

•  Wind developers, and other QFs, have Vinance-‐able projects; market barriers that prompted enactment of FERC largely remedied by Open Access



EPAct ’05 rolled back PURPA privileges:

•  New restrictions to limit “PURPA machines”

•  Repeal of prohibition on utility ownership

•  Repeal of PUHCA

•  Partial repeal of FPA §205 and §206 exemption

•  New § 210(m) requires FERC to excuse purchase obligation if there is access to a sufSiciently competitive market for QFs to sell its power.



EPAct ‘05 created new PURPA §210(m):

§210(m) is a BIG DEAL, made bigger by FERC’s election to implement via rulemaking rather than case by case.

No utility purchase obligation if the Commission Vinds that the [QF] has nondiscriminatory access to: •  (1) [independently administered, auction-‐based day ahead

and real time wholesale markets and wholesale markets for long-‐term sales of capacity and energy] or •  e.g. Midwest ISO, PJM, ISO-‐NE, NYISO

•  (2) [RTO with competitive wholesale markets] or •  (3) wholesale markets that are comparable to (1) or (2).



UHliHes excused from PURPA must-‐buy obligaHon

•  PURPA must-‐buy obligation excused for QFs > 20 MW in: –  Midwest ISO (Describe areal extent) –  PJM –  ISO-‐NE –  NYISO –  SPP –  Cal ISO

•  Utilities in at least 26 states already affected

•  In other regions, and for QFs under 20MW, PURPA must-‐buy obligation remains



PURPA advantages acer EPAct ’05 apply mainly to QFs under 20 MW

QF (under 20MW)

QF (over 20MW, with access to market)

Non-QF generator

Right to sell to utility

X

Right to interconnect/ wheel

X X X

Exempt from FPA 205/206

X*

Sale price Administrative* Market based/IRP Market *exceptions may apply



California Public U4li4es Commission (July 15, 2010 Order) 132 FERC ¶ 61,047 •  California PUC adopted competitive procurement program for CHP facilities ≤ 20 MW meeting speciVied efViciency and environmental standards that excluded non-‐renewables. IOUs challenged because this was contrary to FERC’s holding in So Cal Edison that all eligible sources be considered. CPUC petitioned FERC for guidance.

•  FERC declared that: •  State’s only authority to set wholesale rates is PURPA. Therefore:

•  Bidders must be QFs: •  Price must not exceed the avoided cost of the utility.

•  FERC invited CPUC to seek further guidance on setting QF rates. June 5, 2012 38 Utilizing PURPA in Today’s Deregulated Wholesale Market


California Public U4li4es Commission 133 FERC ¶ 61,059 (October 21, 2010)

•  CPUC accepted FERC’s invitation and sought clariVication on:

•  (1) whether, in determining QF rates, it could exclude resources that did not satisfy state law procurement requirements (e.g. carbon emitting resources), and

•  (2) whether it could include a pricing adder for CHP facilities sited where they will cause the utility to avoid or postpone transmission upgrades.

•  FERC found that: •  CPUC need not consider sources not eligible to sell to the utilities, and

•  CPUC may take into account actual procurement requirements, and resulting costs, imposed on utilities in California.



California’s Distributed GeneraHon (DG) Feed-‐in Tariff

•  FERC’s Order on ClariVication (“ClariSication Order”) effectively overruled So.Cal Edison. •  Utilities still cannot pay more than full avoided cost; •  however “avoided cost” may include actual, non-‐power costs, and need not consider alternative sources that are not eligible under state’s procurement rules.

•  This order gives states great new Vlexibility to use PURPA to help utilities achieve RPS and other state procurement mandates.

IV. Current PURPA legal issues-California


IV. Current PURPA legal issues

A.  Incremental Transmission Costs in Oregon

B. Administrative Avoided Cost Rates in Idaho

C.  California’s Distributed Generation Feed-‐in Tariff


A. Incremental Transmission Costs in Oregon

•  In the PaciVic Northwest, IOUs rely on BPA-‐owned transmission to interconnect their systems.

•  QFs sited at remote locations on an IOU’s system may exceed local load.

•  IOU must buy a wheel from BPA to move the excess QF generation to load elsewhere on its system.

•  The cost of the wheel is not modeled in the administratively determined avoided cost rate.


IV. Current PURPA legal issues-Oregon

A. Incremental Transmission Costs in Oregon-‐ ctd

•  Are these incremental transmission costs paid by the utility to BPA directly assignable to the QF? •  Pro:

•  Not included in administrative Avoided Cost methodology. •  Costs are certain and quantiViable.

•  Con: •  Savings in avoided transmission offsets additional wheeling

costs; or •  Direct assignment of these costs will undercut a primary

objective of standard rates: transparent, efVicient negotiations.



A. Incremental Transmission Costs in Oregon-‐ ctd

•  Administrative Avoided Cost determinations can’t account for every factor in setting costs (some are unknown or de minimis).

•  FERC has said that: •  (1) states have wide latitude in determining avoided costs, but

•  (2) rates that exceed avoided cost are void ab initio!

•  Regardless the outcome, the new order/tariff should include a process for PUC review (prior to signing of new QF contracts) if unanticipated facts come to light.



B. AdministraHve Avoided Cost Rates in Idaho

•  Idaho PUC (IPUC) established standard avoided cost rates for projects 10aMW and less (≈ 25MW nameplate wind QF).

•  Did not anticipate that developers would develop large sites in clusters of 10 aMW QFs (“dis-‐aggregation”). •  Dis-‐aggretation effectively made the published rate the Vloor price

for Idaho utility RFPs •  Resulted in exponential growth in Idaho QF wind

•  IPUC suspended standard rates for wind and solar QFs over 100 kW while it investigated reasonableness of the administrative methodologies.

•  Between time IOUs sought relief and time IPUC suspended rates, nearly 600 MW of new wind QFs sought to obligate IOUs under the standard rates.


IV. Current PURPA legal issues-Idaho

B. AdministraHve Avoided Cost Rates in Idaho

•  After suspension of standard rates, Idaho Power’s project speciVic administrative methodology also exhibited suspect results. •  Between June 8, 2011 and March 9, 2012, Idaho Power

submitted and the Idaho PUC approved Vive QF PPAs comprising 83 MW of new capacity.

•  In each case the IPUC staff recommended disapproval of the PPAs because it believed that the avoided cost pricing methodology resulted in prices that were excessive.

•  Requests for PPAs with project speciVic rates poured in.

•  On March 21, 2012, the IPUC ordered Idaho Power to refer all PPAs to it prior to execution pending completion of the IPUC’s investigation.



Recent QF contracts with Idaho Power Company


Source: Aff. of Randy Allphin, Idaho PUC Case No. GNR-‐E-‐11-‐03 June 5, 2012 47 Utilizing PURPA in Today’s Deregulated Wholesale Market

Suspected causes of erroneous avoided cost price determinaHons idenHfied by IPUC staff:

•  Outdated fuel price forecast

•  Outdated choice of Proxy Resource

•  Outdated assumptions regarding capacity needs

•  Outdated cost of capital assumption

•  Failure to capture integration costs of non-‐dispatchable QFs (except for wind)



Errors in AdministraHve Avoided Cost determinaHons are inevitable.

•  Inputs are outdated the day after they are made.

•  E.g. the 2010 natural gas price forecast:

•  Tariff/Orders need to be written with safeguards to limit unintended consequences of PURPA implementation.



$/mmBtu (2010)

2010 2011 2012 2013 2014 2015 2016 2017 2018

3/16/10 4.56 4.86 5.19 5.48 5.79 6.11 6.22 6.32 6.44

8/30/11 3.93 4.05 4.18 4.28 4.37 4.47 4.58 4.7 4.58

Safeguards for Standard Rate Pricing:

•  Preset cap on MW between price updates

•  Stair-‐step Avoided Cost schedule

•  Limit QF’s ability to participate in RFP and standard price programs

•  Limit size of QF eligible for standard rates

•  Empower utility to refer “gamers” to Commission

•  PUC reasonableness review at time of execution

•  Prompt PUC suspension of rates when needed



C. California’s Distributed GeneraHon Feed-‐in Tariff

•  On May 24, 2012, California PUC adopted ALJ’s decision implementing a distributed generation Feed-‐in Tariff required by California’s legislature. Decision 12-‐05-‐035.

•  The Feed-‐in Tariff (FiT) fulVils state law requiring utilities to purchase 750 MW from generators 3MW or less located at strategic locations on the electric distribution system.

•  CPUC relies on FERC Clari]ication Order in establishing a framework for setting FiT rates that are both market-‐based and focused to meet the speciVic requirements of the legislature.



C. California’s Distributed GeneraHon Feed-‐in Tariff-‐ ctd.

California Public Utilities Commission relied on the FERC ClariVication Order to implement its DG Feed-‐in Tariff

In [the FERC ClariVication Order], FERC clariVied that the state has a wide degree of latitude in setting avoided cost, can utilize a multi-‐tiered avoided cost rate structure, and that this approach is consistent with the avoided cost requirements set forth in Section 210 of PURPA. FERC also clariSied that state procurement obligations can be considered when calculating avoided cost, and it speciVically overruled its prior holding from SoCal Edison to the extent its current determination was inconsistent with that clariVication.

-‐-‐California Public Utilities Commission, Decision 12-‐05-‐035 at 11 (emphasis added; internal citations omitted).



C. California’s DG Feed-‐in Tariff-‐ctd.

•  PUC §399.11 et seq. declares a state goal to develop eligible renewable energy resources 3MW or less at strategic locations on the grid.

•  CPUC opted not to use the gas-‐based Market Price Referent (MPR) because legislation did not so require.

•  CPUC decided to base the price on market price of renewables, Vinding that a healthy market existed.




•  FiT uses Renewable Auction Mechanism (RAM) Program prices as starting price for FiT

•  Adjusts the RAM to account for differences in pricing from the RAM Program (“Re-‐MAT”) •  10, 15, or 20 year term •  Baseload, peaking as-‐available, and non-‐peaking as-‐available




•  Re-‐MAT starting price based on weighted average of PG&E’s, SCE’s, and SDG&E’s highest executed contract resulting from the RAM auction held November, 2011. •  Adjustments for: •  Time of delivery •  Up to every two months, based on QF response to offer.

•  Available allotment allocated equally among baseload, peaking as-‐available, and non-‐peaking as-‐available.




•  Other FiT selection criteria: •  “Strategically located”—QF must interconnect to the distribution system and cost no more than $300,000 for necessary system upgrades.

•  Only one project per seller per parcel or contiguous parcel

•  QFs eligible for FiT program are not eligible for RAM Program




•  FiT program also has “viability” criteria: •  Interconnection feasibility •  Legal control of proposed site •  Prior experience in at least one similar project •  Online date <= 24 months •  No seller may contract for more than 10MW system-‐wide

•  Participation capped by statute at 750 MW. •  Cap includes publicly owned utilities, too.




•  DG FiT may be a template for other states to follow.

•  Question: can PUCs in states without RPS adopt speciVic procurement requirements?



DG FiT learns many lessons from the past: Cap on total MW procurement ✔ Market-‐based Avoided Cost ✔ Automatic Avoided Cost adjustment mechanism ✔ Anti-‐dis-‐aggregation rules ✔ Limit eligibility to other programs ✔ Utility authority to deny eligibility (w/ CPUC review) ✔

V. PURPA opportuniHes and risks

going forward


We must learn from the past:

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

1975 1980 1985 1990 1995 2000 2005 2010 2015 Year

Capacity (MW) under Contract

SDG&E

IPC

A

B

C

E

D

V. Future PURPA opportunities and risks


PURPA opportuniHes and risks going forward-‐-‐ RISKS:

QF development may increase cost of developing renewables: •  Avoided cost can be too high

–  Some existing QFs can earn an appropriate return at a rate less than what new QFs require

–  Auction/RFP will capture some of this potential savings whereas other methods do not

•  Resulting in excess, overpriced, supply •  At locations where it is not needed •  Resulting in large rate increases, lost opportunities,

and regulatory crisis



PURPA opportuniHes and risks going forward-‐-‐OPPORTUNITIES

•  Continued promotion of cogeneration and renewable energy

•  Targeting of speciVic state policy objectives (e.g. Ca CHP)

•  Promotion of community scale energy projects

•  Caveat: •  Must be QFs •  Does not apply if utility excused from purchase obligation under 210(m)



VI. QuesHons &

Answers


Closing Remarks—Ken Kaufmann

•  PURPA was not intended to be a subsidy. Implementation schemes that result in a QF making more than an appropriate rate of return do so at the expense of ratepayers (and possibly the Commissions that let such abuses occur).

•  Avoided cost for large QFs best determined by RFP (or auction)

•  Standard rates/administrative rates may be appropriate for small QFs •  In furtherance of State policy objectives, and •  With proper safeguards against abuse •  Where standard rates remain, there may be good opportunities for DG, solar,

biogas digesters, and existing small QFs renewing expired contracts

  CPUC’s FiT program is a promising example of how PURPA can further State policy objectives without exposing ratepayers to undue risks. I expect other states will soon follow California in establishing differentiated, market-‐based, QF rates designed to further State energy procurement policies.


Closing Remarks—Peter Richardson •  In my view PURPA works best when it obviates the need for a utility to construct

its own resource. Buying PURPA power allows the utility to avoid fuel cost risk, construction risk, and operation risk, and it allows the utility to add resources in a non-‐lumpy incremental manner. Unlike with a utility-‐owned resource, the ratepayers do not pay a QF when it is off line, whereas a ratebased unit is embedded in rates whether or not it is off-‐line.

•  While PURPA rates should never exceed a utility’s actual avoided costs, they should not be set below that level in order to assure that these resources are brought on line and not lost. Setting avoided cost rates artiVicially low actually costs the ratepayers in the end because with artiVicially low avoided cost rates QF project are less likely to be build and utilities will be encouraged to build and ratebase their own projects.

•  In large parts of the country where competitive markets do not exist, PURPA remains relevant and viable. Unfortunately with the great recession and rock bottom natural gas prices, I see a long period of very little activity in the Vield.


www.lklaw.com

P: (503) 230-‐7715 F: (503) 972-‐2921

Ken Kaufmann ([email protected])


Utilizing PURPA in Today's Deregulated Wholesale Market

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