Technical Report

NREL/TP-6A2-47408

January 2010

Renewable Energy Prices in 

State-Level Feed-in Tariffs:

Federal Law Constraints and 

Possible Solutions

Scott Hempling

National Regulatory Research Institute

Silver Spring, Maryland

Carolyn Elefant

The Law Offices of Carolyn Elefant 

Washington, D.C.

Karlynn Cory

National Renewable Energy Laboratory 

Golden, Colorado

Kevin Porter

Exeter Associates, Inc.

Golden, Colorado
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Technical Report

NREL/TP-6A2-47408

January 2010

Renewable Energy Prices in 

State-Level Feed-in Tariffs:

Federal Law Constraints and 

Possible Solutions

Scott Hempling

National Regulatory Research Institute

Silver Spring, Maryland

Carolyn Elefant

The Law Offices of Carolyn Elefant 

Washington, D.C.

Karlynn Cory

National Renewable Energy Laboratory 

Golden, Colorado

Kevin Porter

Exeter Associates, Inc.

Golden, Colorado

Prepared under Task No. PVC9.9720
NOTICE

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iii

Acknowledgments

This work was funded by two programs of the U.S. Department of Energy’s (DOE)

Energy Efficiency and Renewable Energy (EERE) Division. Therefore, the authors wish to thank 

participating staff — Charles Hemmeline of the DOE and Jennifer DeCesaro of Sentech from the

EERE Solar Program, and David Rodgers and Carla Frisch from the EERE Strategic Policy and 

Analysis Program — for providing useful insights and overall direction to this project. The 

authors are also grateful for the guidance and helpful input of the project managers, Robert 

Margolis, Selya Price, Gian Porro, and Thomas Schneider of the National Renewable Energy 

Laboratory (NREL). 

We would also like to thank the individuals who reviewed various drafts of this report, 

particularly James Newcomb, David Kline, Claire Kreycik and David Hurlbut of NREL; Elaine 

Ulrich of the U.S. DOE; Jennifer DeCesaro of Sentech; Lawrence R. Greenfield of the Federal 

Energy Regulatory Commission; Robert C. Grace of Sustainable Energy Advantage; Chad 

Laurent and Wilson Rickerson of Meister Consultants Group; Jason Keyes, Joseph Wiedman, 

and Kevin Fox of the law firm Keyes and Fox; and Ed McNamara and Kurt Janson of the 

Vermont Public Service Board. Finally, we are grateful to Mike Meshek of NREL for providing 

important editorial support.

This report reflects the views of its authors only. It does not necessarily reflect the 

positions of NRRI or any of its funders, constituents, or clients. 
iv

Executive Summary

The Need for Guidance to States

State legislatures and state utility commissions seeking to attract renewable energy

projects are considering arrangements called “feed-in tariffs.” These tariffs would obligate retail 

utilities to purchase electricity from renewable producers under standard arrangements

specifying prices, terms and conditions. This standardization simplifies the purchase process, 

provides revenue certainty to generators, and reduces the cost of financing generating projects. 

States decision makers have encountered arguments that state-level feed-in tariffs are 

preempted by federal law. These arguments arise because the transaction resulting from a feedin tariff is a wholesale sale of electricity, from renewable seller to retail utility. A wholesale sale

of electricity triggers one of two federal statutes—the Public Utility Regulatory Policies Act of 

1978 (PURPA) or the Federal Power Act of 1935 (FPA). Each of these statutes does in fact limit 

the discretion of state-level tariff designers. 

State utility commissions, in conjunction with the National Association of Regulatory 

Utility Commissioners (NARUC), asked the National Renewable Energy Laboratory (NREL) to 

explore how states can lawfully implement feed-in tariffs. In response to that request, NREL

hired the National Regulatory Research Institute (NRRI) to be the lead author of this report and 

to provide the needed legal expertise. NREL participated as a coauthor to clarify the current 

renewable energy policy and markets. This report seeks to reduce the legal uncertainties for 

states contemplating feed-in tariffs by explaining the constraints imposed by federal statutes. 

This report describes the federal constraints, identifies certain transaction categories that are free 

of those constraints, and offers ways for state and federal policymakers to interpret or modify 

existing law to remove or reduce these constraints. This report explains options for how these 

federal statutes could be revised. 

There is no standard, official definition of "feed-in tariff." To facilitate a full vetting of 

federal legal constraints that state lawmakers1 must address, this report creates a broad working 

definition of “state-level feed-in tariff”, as follows: 

a publicly available, legal document, promulgated by a state utility regulatory 

commission or through legislation, which obligates an electric distribution 

utility to purchase electricity from an eligible renewable energy seller at 

specified prices (set sufficiently high to attract to the state the types and 

quantities of renewable energy desired by the state) for a specified duration; 

and which, conversely, entitles the seller to sell to the utility, at those prices for 

 1 While this report focuses on state-level feed-in tariffs, municipally owned power 

systems (most of which are not regulated by state commissions) can also offer these 

tariffs. These are briefly mentioned in the introduction.
v

that duration, without the seller needing to obtain additional regulatory

permission.2

Given this definition, this report comes to the following conclusions: There are paths to 

non-preempted, state-level feed-in tariffs under current federal law. Each “current law” path 

falls into one of three categories, involving varying levels of certainty and effort: 

1. Paths that are available now, with no further action necessary by the Federal 

Energy Regulatory Commission (FERC); 

2. Paths that would become available if FERC clarified or modified its precedents; 

and 

3. Paths that would become available if FERC issued new rules, declaratory orders

or both, to create safe harbors, rebuttable presumptions, or other guidance that 

rendered state-set tariff prices lawful under the FPA. 

Additional paths are possible if Congress amends PURPA or the FPA to remove or reduce 

existing statutory constraints. Detailed discussions involving states, FERC, renewable 

producers, utility buyers, and possibly Congress will be necessary to create a legal context in 

which states can enact or promulgate feed-in tariffs as defined above.

Constraints and Solutions

The definition of feed-in tariff (FIT) used here assumes that the tariff is the result of a 

legal mandate—either by statute directly or by commission direction as authorized by statute. A 

state wishing to create that mandate has two options. First, the state can rely on the utility's 

purchase obligations under PURPA, shaping the state-level requirements to satisfy PURPA's 

constraints. Sellers under this approach need not comply with the Federal Power Act. Second, 

the state can rely on a state statutory mandate independent of PURPA. Sellers under this 

approach must comply with the Federal Power Act, unless FERC has exempted them. A brief 

explanation of each alternative follows.

 2

 The phrase “feed-in tariff” originated with European measures in which the term “feedin” referred to the renewable producer’s right to interconnect with the utility and thus “feed in” 

its output to the electric grid. This report focuses on the pricing of power, not on 

interconnection, because it is the pricing issue that raises specific concerns about constraints of 

federal law on state decision making. This report also assumes that while a state’s legislature 

may have directed the utilities commission to establish tariffs, that legislation will vest the 

responsibility for creating and administering the tariffs with the state utility commission.
vi

Public Utilities Regulatory Policies Act

Since 1978, PURPA has offered certain renewable energy producers and cogenerators a 

way to require utilities to purchase their output. The seller first must receive FERC certification 

as a “qualifying facility” (QF). (FERC rules limit this certification to a subset of renewable 

energy technologies and project sizes.) A QF is exempt from most FPA price regulation (see 

“Federal Power Act” below), but its pricing still is constrained: it can sell only at a price (a) 

established or approved by the state commission or (b) reached through negotiation with the 

utility. That price, if mandated by the state, cannot exceed the utility's "avoided cost." (Prices 

negotiated with the utility can exceed avoided cost.) Avoided cost is the cost the utility would 

have incurred had it self-supplied, or bought from a third party, the products and services (such 

as capacity and energy) it is buying from the QF. The problem for state-level feed-in tariff 

designers is that a utility’s avoided cost is likely to be lower than the price necessary to attract 

and sustain the renewable seller.

For states relying on the PURPA mandate, certain feed-in tariffs are possible without 

any action by FERC or Congress. Currently, a state implements PURPA by establishing an 

avoided cost price, which the utility must offer to QFs. FERC precedent allows states to 

supplement this avoided cost payment (i.e., get the QF compensation exceeding avoided cost), in 

one of three ways: (a) assigning “renewable energy credits,”3 (b) making cash grants or paying 

production-based incentives (funded, for example, by taxpayers through the general budget, or 

by ratepayers through a "system benefits charge"), or (c) establishing a purchase price that 

exceeds avoided cost but granting the purchasing utility a tax credit equal to the excess. FERC 

has found that these forms of supplemental compensation fall outside of its PURPA jurisdiction, 

and therefore are not preempted. This PURPA mandate path is available to QFs of any size, 

but it is not available if the seller is not a QF.

4

Problem: Utilities now can seek exemption from the PURPA purchase requirement. 

Under PURPA amendments enacted in 2005, FERC has exempted some utilities from their 

PURPA obligation to buy power from QFs with capacities greater than 20 MW. If states with 

jurisdiction over these utilities wish to establish feed-in tariffs, they will have to create a 

mandate under state law; and the sellers will need to comply with the Federal Power Act, as 

discussed next.

 

3 As discussed later in this report, renewable energy certificate (REC) market prices may

vary across regions and across time, raising questions about their effectiveness in drawing draw 

long-term investment for renewable energy projects. 

4

 In other words, the power producer must apply to FERC to be certified as a QF.
vii

Federal Power Act

Since 1935, the Federal Power Act has placed in FERC (previously the Federal Power 

Commission) the exclusive authority to regulate "the sale of electric energy at wholesale in 

interstate commerce." The Federal Power Act is a contract-based statute. It is unlawful to make 

a sale at wholesale without a contract, and without FERC approval of that wholesale contract. 

Put more directly, a state-level tariff cannot lawfully command the utility to purchase at the 

state-set price. Under Sections 205 or 206 of the FPA, the seller must prove to FERC, that the 

contract, including its price, is "just and reasonable" and not "unduly discriminatory." To 

receive FERC approval, the wholesale seller must choose one of two procedures: 

"Cost-based rates": The seller signs a contract with the utility buyer, then submits that 

contract to FERC for review. FERC establishes a public proceeding to review the seller's 

cost data (which the seller must make public). FERC must determine that the contract 

price recovers no more than prudent costs plus a reasonable return on equity. The 

process applies on a contract-by-contract basis. 

"Market-based rates": Instead of seeking approval contract-by-contract, the seller seeks 

from FERC a blanket approval to enter contracts at will, at whatever price the seller and 

buyer negotiate. To gain FERC's approval, the seller must submit a detailed technical 

study proving that it has no "market power," i.e., no ability to set and sustain prices above 

competitive (i.e., “just and reasonable”) levels, in the markets in which the seller intends 

to sell. (FERC does not require state-by-state studies, just studies addressing the 

geographic areas in which the seller will sell.) The seller must repeat the market-power 

study every three years, and regularly file other reports, so that FERC can ensure that the 

seller cannot exercise market power to raise prices above "just and reasonable" levels. A 

seller with market-based rate authority can enter contracts without additional FERC 

approval. 

Given the FPA's requirements, a state-level feed-in tariff, as defined above, outside of 

PURPA, is not legally possible in the United States today. It is not possible because the tariff 

cannot produce a lawful transaction by itself; there must be FERC approval of the contract 

resulting from the tariff. That approach, of course, differs fundamentally from the Europeanstyle definition of a feed-in tariff (and from the broad definition introduced above), which 

contemplates a sale resulting from the tariff without the seller needing to obtain any additional 

regulatory approval. Instead, this modified tariff is only the first step. The authors of this report 

reason that if the state redefines the tariff as the retail utility’s offer to buy, there would be no 

lawful sale until (a) the utility and the seller enter into a contract and (b) FERC approves that 

contract.5

 5 An additional jurisdictional wrinkle pertains. The Federal Power Act requirements do 

not apply in Hawaii, Alaska, and most of Texas; while PURPA applies throughout the United 

States (except to the extent FERC has relieved utilities of their PURPA purchase obligation). An 

explanation of the Hawaii-Alaska-Texas exception appears in the main text.

 
viii

But, a clear path to state-level feed-in tariffs, outside of PURPA, would open for small 

QFs if FERC clarified or modified its precedents: FERC has granted an exemption from 

Sections 205 and 206 of the FPA for QFs with capacity of 20 MW and below. These QFs are 

free to sell at wholesale, at any price, without seeking FERC approval. Based on this exemption, 

the report authors reason that states should be able to establish feed-in tariffs for these small 

entities consistent with this report’s broad definitions. Under these tariffs, the seller could 

consummate transactions under the state program without any federal involvement or additional 

steps. Two cautions pertain. First, this path is not available to non-QFs, or QFs exceeding

20 MW. Second, FERC would need to modify or reinterpret existing FERC precedent. This 

precedent states that if the seller is a QF, it is bound by PURPA’s avoided cost cap even if the 

buyer’s obligation to buy arises from state law rather than PURPA. With a change to existing

FERC precedent, sales by QFs with capacity of 20 MW and less would face no federal constraint 

on the state-set price.

Another path opens if FERC creates safe harbors, rebuttable presumptions, or other 

guidance concerning state-set offer prices: One way for FERC to facilitate seller compliance 

with the FPA is to establish "safe harbors," rebuttable presumptions, or other forms of guidance. 

Under this approach, FERC would identify criteria or standards concerning the pricing for

various technologies, project sizes, and geographic markets. If states designed their tariffs to be 

consistent with the FERC guidelines, sellers under those tariffs would be deemed by FERC to 

have complied with the FPA’s requirement that prices be “just and reasonable” and not “unduly 

discriminatory.” Because there is no recent FERC experience with this type of approach, an 

administrative inquiry and rulemaking process (including fact-finding) would be necessary.

Actions by FERC can occur through one of the following procedures: FERC can initiate action 

itself by issuing proposed rulemakings or policy statements; or states and other entities can seek 

FERC action by filing petitions for rulemaking or requests for declaratory orders. Note that 

FERC decisions that set different prices for different sellers must have an evidentiary basis (such 

as cost differences) to withstand an attack that holds that the differences constitute “undue 

discrimination” prohibited by the FPA.

What if the price a state wishes renewable sellers to receive (in order to attract sufficient 

quantities) is above these federally mandated levels? As noted above, FERC’s PURPA

precedent allows states to supplement the avoided cost compensation through renewable energy 

credits, cash payments, and even prices above avoided cost (if the utility payment receives a 

state tax credit equaling the increment above avoided cost). This report argues that this same 

FERC-authorized flexibility is available in the FPA setting.

Retail sales present no preemption problem: Federal law constraints apply only to 

wholesale transactions. Retail transactions fall outside both federal statutes. States are free to 

establish programs allowing renewable generators to sell to retail customers. (These programs 

are not similar to the feed-in tariffs addressed in this report, because they do not create any 

obligation in the retail customer to buy from the generator). This state freedom includes the 

situation where a non-utility sells power to a retail customer who is a participant in a net 

metering program (often called a third-party owned power purchase agreement or third-party 

owned lease). The retail customer's purchases from the non-utility seller cause the retail 
ix

customer's meter to "run backwards," reducing his purchases from the utility. Provided there is 

no "net sale" during a billing cycle—a net sale would occur if the retail customer's purchases 

from the non-utility exceed the customer's usage during a billing cycle—FERC will treat the 

non-utility generator as making only retail sales, not wholesale sales; thus the FPA will not 

apply. FERC explained this reasoning in its Declaratory Order in SunEdison, 129 FERC para. 

61,146 (Nov. 19, 2009).

Congressional Action

Congress could modify PURPA and the FPA to allow states to establish feed-in tariffs 

unconstrained by current federal law. The intent behind such an amendment would be to create 

exceptions from PURPA, the FPA, or both, for renewables sellers in states that promulgate 

tariffs having certain characteristics. The result would be to vest in the sellers an automatic right 

to sell under state programs. This report describes several options in this category.

* * *

This report is solely a legal analysis that responds to NARUC’s and NREL's requests. It 

is not an endorsement of state-level feed-in tariffs or of any of the alternative paths or statutory 

amendments described here. 
x

Table of Contents

Acknowledgments .................................................................................................. iii

Executive Summary ............................................................................................... iv

The Need for Guidance to States............................................................................................... iv

Constraints and Solutions ........................................................................................................... v

Public Utilities Regulatory Policies Act............................................................................ vi

Federal Power Act ............................................................................................................ vii

Congressional Action......................................................................................................... ix

Introduction..............................................................................................................1

A. Renewable Energy Feed-in Tariffs in Context ................................................................... 1

B. The Problem of Federal Preemption................................................................................... 1

C. State-level Feed-in Tariff Defined...................................................................................... 2

D. Organization of this Report................................................................................................. 3

I. State-Level Tariffs Based on a PURPA Mandate ..........................................5

A. PURPA Overview: A utility must buy capacity and energy from "qualifying facilities," 

priced at the utility's avoided cost....................................................................................... 5

B. PURPA Administration: FERC grants QF status; states determine avoided cost and 

administer the utility's purchase obligation ........................................................................ 6

1. FERC determines QF status ......................................................................................... 6

2. State determines the utility's avoided cost.................................................................... 7

C. PURPA Shrinkage: FERC has exempted some utilities from PURPA's purchase 

obligation .......................................................................................................................... 10

D. Compensation for PURPA Sellers: States can—with care—grant renewable sellers 

compensation exceeding the utility's avoided cost ........................................................... 13

1. Renewable energy credits awarded to the renewable seller....................................... 14

2. Tax credits awarded to the utility purchaser .............................................................. 16

3. Payments to the renewable seller from other sources ................................................ 18

4. The problem of avoided cost variability..................................................................... 18

5. Can the state set different PURPA prices for different technologies? ....................... 19

E. Application of PURPA concepts to state feed-in tariffs: Summary of the three steps..... 19

II. State-Level Tariffs Based on a State Law Mandate ....................................21

A. Federal Power Act Overview: FERC has exclusive jurisdiction to set wholesale rates.. 22

B. To avoid FPA preemption, states must fashion their feed-in tariffs as offers to purchase, 

but even then legal uncertainty exists............................................................................... 23

1. FPA Background: FERC's preemptive authority over wholesale sales..................... 23

2. State authority to require offers to purchase is not preempted if FERC clarifies or 

adjusts its existing precedent ...................................................................................... 24

3. FERC preemption precedent needs clarification and/or adjustment .......................... 26

4. Conclusions on the state role in wholesale price-setting............................................ 28
xi

C. In the FPA context, the state can set different sales offer prices for different

technologies...................................................................................................................... 29

D. Once states establish feed-in tariffs, sellers still must obtain FERC permission to sell... 29

1. Contract-by-contract approval (cost-based rates)....................................................... 30

2. Blanket advance approval (market-based rates)......................................................... 30

3. Supplemental compensation from the state ................................................................ 32

4. Must the seller in a state law-based regime still comply with PURPA's avoided cost 

cap? ............................................................................................................................. 32

E. Exemptions from FPA review for QFs sized 20 MW and below if FERC clarifies and/or 

adjusts its precedent.......................................................................................................... 36

F. Safe Harbors, Presumptions and other Forms of Guidance: FERC can facilitate sellers' 

compliance with the Federal Power Act........................................................................... 37

III. Amendments to Current Federal Statutes....................................................41

A. The House-Passed American Clean Energy and Security Act ......................................... 41

B. Four Conceptual Federal Legislative Options.................................................................. 43

IV. Related Questions............................................................................................44

A. What price-setting methods are available to state designers of feed-in tariffs? ............... 44

B. Does the applicability of the FPA or PURPA change if the seller's delivery to the buyer 

occurs at a distribution facility rather than a transmission facility? ................................. 44

C. Do the federal statutes apply to renewable sales to retail customers?.............................. 45

Conclusions.............................................................................................................46

Appendix A: Overview of Preemption Analysis .................................................48

Appendix B: PURPA Exemptions and Termination of Mandatory Purchase 

Provisions—Statutes and Regulations.................................................................50

List of Figures

Figure 1. Can a state order its utilities to file “feed-in tariffs”? Two paths to nonpreemption .................................................................................................................... 40
1

Introduction

A. Renewable Energy Feed-in Tariffs in Context

The desire to diversify electric generation sources has occupied policymakers since 1978, 

when Congress passed the Public Utility Regulatory Policies Act (PURPA). Aimed at reducing 

the nation's dependence on fossil fuels, Section 210 of PURPA6 directed retail utilities to 

purchase capacity and energy from "qualifying facilities," defined as either cogenerators or small 

non-fossil generators. Since the late 1990s, some states have promulgated renewable portfolio 

standards (RPS), which require retail utilities to procure a prescribed percentage of their 

electricity needs from renewable sources.7 A third state-level effort is "net metering," which 

allows a customer's meter to "run backwards" if they self-generate renewable energy. 

Many states are now exploring a fourth concept, the "feed-in tariff." As currently used in 

Europe, this type of tariff creates a continuing obligation in the local utility to buy eligible 

renewable producers' output at standardized rates typically reflective of generation costs and 

under standard terms and conditions. As of January 2010, California, Hawaii, Oregon, and 

Vermont had authorized or required renewable energy feed-in tariff programs.

8

B. The Problem of Federal Preemption

By this report’s working definition, a state-level feed-in tariff is a mandate—a mandate 

from the state to the utility to buy wholesale electricity from renewable sellers at standard prices, 

terms and conditions. States wishing to enact this mandate have encountered legal uncertainty 

because wholesale sales of electricity are subject to one of two federal statutes: PURPA or the 

Federal Power Act of 1935 (FPA). Under certain circumstances, each of these federal statutes 

"preempts" state statutes and regulations.9

 6

 16 U.S.C. sec. 824a-3.

 

7 Wiser, Ryan and Galen Barbose, 2008. Renewable Portfolio Standards in the United 

States: A Status Report with Data Through 2007, Lawrence Berkeley National Laboratory 

technical report LBNL-154E, April. http://eetd.lbl.gov/ea/EMS/reports/lbnl-154e-revised.pdf.

8 “Renewable Energy Tariffs in Europe and Elsewhere,” Excel spreadsheet assembled 

by Paul Gipe to capture tariffs for different technologies in different countries, states and 

provinces, updated December 2009, found at http://www.windworks.org/FeedLaws/RenewableTariffs.xls, accessed December 13, 2009; “Tariff Watch: the 

latest photovoltaic tariff news from regions worldwide,” Photovoltaics International’s website 

“PV Tech,” found at http://www.pv-tech.org/tariff_watch/, accessed December 13, 2009; and 

PHOTON International website, found at www.photon-international.com, accessed December 

13, 2009.

9

 A short tutorial on preemption appears in Appendix A.
2

This report seeks to reduce legal uncertainties for states contemplating feed-in tariffs. 

This report explains the constraints federal statutes place on state-mandated feed-in tariffs. It 

then describes actions available to policymakers wishing to create more certain paths for these 

state initiatives. Those actions fall into the following categories: 

1. State legislatures and state commissions can design tariffs within existing

federal legal boundaries.

2. On its own, or in response to requests for rulemakings or declaratory 

orders, the Federal Energy Regulatory Commission (FERC) can (a) clarify

its precedents to eliminate certain constraints, and/or (b) create procedures 

that simplify and standardize renewable sellers' obligations under one or 

both federal statutes. 

3. Congress can amend FPA and/or PURPA to diminish or eliminate certain 

constraints.

C. State-level Feed-in Tariff Defined

There is no standard, official definition of state-level feed-in tariff. This report uses the 

following definition, designed to illustrate the full range of interactions with federal law: 

a publicly available, legal document, promulgated by a state utility regulatory 

commission or through legislation, which obligates an electric distribution utility 

to purchase electricity from an eligible renewable energy seller at specified prices 

(set sufficiently high to attract to the state the types and quantities of renewable 

energy desired by the state) for a specified duration; and which, conversely, 

entitles the seller to sell to the utility, at those prices for that duration, without the 

seller needing to obtain additional regulatory permission.

This broad definition reflects states’ wishes both to eliminate the legal uncertainty 

associated with state rate-setting and to reduce seller and buyer transaction costs (such as 

cost of FERC filings and proceedings).

While this report focuses on state-level feed-in tariffs, they do not make up the 

full universe of tariff possibilities. Municipally owned power systems (like municipally

owned utilities, most of which are not regulated by state commissions) can offer these 

tariffs as well. Although municipal power systems are not subject to the Federal Power 

Act10

 10 Section 201(f) provides:

and thus can sell power at wholesale outside of FERC jurisdiction, under PURPA 

No provision in this Part [16 U.S.C. sec. 824 et seq.] shall apply to, or be deemed to 

include, the United States, a State or any political subdivision of a State, or any 
3

they must act in roles similar to both a state commission (setting mandatory PURPA 

purchase prices at avoided) and a purchasing utility (obligated to purchase from QFs at 

avoided cost).11 Thus, the analyses in this report apply to municipal power systems 

similarly to how they apply to state commissions and how they apply to renewable 

producers. A municipal power system can offer a feed-in tariff, but if that tariff relies on 

the municipal’s PURPA obligation it must comply with FERC’s PURPA rules. And if 

that tariff relies not on the PURPA purchase obligation but on a municipal power 

system’s self obligation to make purchases, or a state-imposed obligation to make 

purchases, the seller will need address FPA obligations (unless the seller has an 

exemption from the FPA).

D. Organization of this Report

There are, at present, two alternatives paths by which states can implement a feed-in 

tariff consistently with federal law." Part I explains how the state can rely on the utility’s 

PURPA purchase obligation. Part II describes how states can rely on state law independent of 

PURPA (but that is still subject to the FPA). In Figure 1 at the end of Part II, the authors provide 

a single-page summary of the existing path for non-preemption under PURPA and the path for 

non-preemption under state law (if FERC changes existing precedent). 

To understand each path, one must understand how they interrelate. If the state relies on 

the PURPA option, the sellers must comply with PURPA's "avoided cost" price cap—and 

compliance will exempt the sellers from rate regulation under the FPA. If, instead, the state 

relies on state law, this report argues that sellers will be exempt from PURPA's "avoided cost" 

cap, but FERC precedent does not share this view. (Clarification from FERC, either on its own 

initiative or in response to a request from states or others, would make this non-PURPA path 

available with more certainty. FERC will need to revisit and reverse these rulings, either under 

its own order or by request from a filing party, for exemption via the state law option to take

effect.) Sellers who take this route then must comply with FERC’s rate regulation under the 

FPA.

 

agency, authority, or instrumentality of any one or more of the foregoing, or any 

corporation which is wholly owned, directly or indirectly, by any one or more of the 

foregoing, or any officer, agent, or employee of any of the foregoing acting as such 

in the course of his official duty, unless such provision makes specific reference 

thereto.

11 PURPA creates a category called “nonregulated utility,” defined by PURPA Section 

3(9) PURPA, 16 U.S.C. § 2602(9), to be a utility not regulated by the state, such as a stateowned, municipally owned or cooperatively owned entity. The nonregulated utility has the 

PURPA obligation to purchase QF capacity and energy, and also has the obligation to establish 

the avoided cost prices. 16 U.S.C. § 824a-3(f)(2).
4

Under both the PURPA option and the state law option, this report describes alternative 

paths for avoiding or limiting the preemptive effect, clarifies necessary revisions to existing 

precedent as well as describes procedure innovations. For example:

Under the PURPA option and existing law, states can grant QF sellers incremental 

compensation above avoided cost, provided that this incremental compensation takes the 

form of cash grants, renewable energy credits, tax credits, and/or production-based 

incentive payments; or the state may set the rate above avoided cost as long as it issues a 

tax credit equal to the increment above avoided cost. This option is now available to 

states without any further action by FERC.

Under the FPA options, additional action is required of FERC. FERC could create "safe 

harbors," presumptions or other guidance that allows for state-established “offer price 

caps” for various technologies, projects and regions. If these offer price caps were 

adopted in state feed-in tariffs, they would allow sellers to comply with the FPA without 

having to obtain contract-by-contract approval. This option will require a FERC 

investigation and decision, through rulemaking, declaratory orders, or both.

Another option could exist under the FPA if existing FERC precedent is clarified and/or 

adjusted. FERC has exempted from the FPA those PURPA-certified "qualifying 

facilities" with capacity of 20 MW and less. This exemption, this report argues, creates a 

path by which state feed-in tariffs can use prices chosen by the state without federal 

preemption. For this path to be clear, however, FERC precedent requires clarification 

and/or adjustment.

Part III describes the generic ways in which Congress could modify PURPA or FPA to 

reduce or eliminate their preemption reach over state-level feed-in tariffs.

Part IV addresses certain miscellaneous questions on price-setting methods.
5

I. State-Level Tariffs Based on a PURPA Mandate

PURPA creates for retail utilities an obligation to buy capacity and energy from certain 

types of facilities. The statute makes state utility regulatory commissions responsible for 

administering that obligation with respect to retail utilities over which the state commission has 

jurisdiction. States can use the utility's PURPA obligation as a legal vehicle for creating feed-in 

tariffs. By relying on PURPA, they need not enact a separate state law.

This section (Part I) provides the background necessary to understand how to design 

state-level feed-in tariffs within PURPA's constraints. It explains that:

a. PURPA requires each utility to buy capacity and energy from FERC-certified 

"qualifying facilities.” The sales price can be established either (a) by state 

commissions, in which case the price must equal the utility’s “avoided cost” or 

(b) through utility-QF negotiations, in which case the price may exceed avoided 

cost. 

b. PURPA administration is split between FERC (which grants QF status) and states 

(which determine avoided cost and administer the utility's purchase obligation). 

c. In 2005, Congress authorized FERC to exempt utilities from PURPA QF 

purchase obligations if they are located where QFs have reasonable opportunities 

to sell into wholesale markets because of the availability of transmission access or 

RTO-organized markets. FERC has issued regulations governing the ability of 

utilities to request this PURPA exemption and has clarified that the utility is still 

obligated to purchase from QFs with a capacity of 20 MW and less. FERC has 

granted this exemption to most requesting utilities. 

d. FERC allows states to supplement a QF's avoided cost compensation (e.g.,

through cash grants, renewable energy credits, tax credits and/or productionbased incentive payments) as long as the supplement does not take the form of 

mandatory utility payments for power to the QF. 

After providing this background, Part I summarizes NRRI guidance to states in how to design 

feed-in tariffs consistent with PURPA's constraints.

A. PURPA Overview: A utility must buy capacity and energy from "qualifying 

facilities," priced at the utility's avoided cost

Congress enacted Section 210 of PURPA to encourage the development of cogeneration 

and small power production, and to overcome utilities' traditional reluctance to purchase power 

from non-traditional entities.12

 12 FERC v. Mississippi, 456 U.S. 742, 750 (1982).

 The statute requires each retail utility to purchase capacity and 

energy from "qualifying facilities" (QFs) at a price equal to the utility’s avoided cost. 
6

In addition to granting QFs a right to sell to utilities, Section 210 and the associated 

FERC rules provide QFs another benefit: exemption from traditional rate regulation, by states 

under state law and by FERC under the Federal Power Act.13 A QF selling at a utility's avoided 

cost rate under PURPA thus has no obligation to demonstrate, to the states or to FERC, the 

reasonableness of its own costs.14 

B. PURPA Administration: FERC grants QF status; states determine avoided 

cost and administer the utility's purchase obligation

In administering PURPA, the FERC and state commissions play distinct roles. FERC 

determines whether a generator meets the requirements for QF status. Each state commission 

must establish the avoided cost for the retail utilities subject to that state commission's 

jurisdiction.15 Here are the basics:

1. FERC determines QF status

Under PURPA, two types of facilities are eligible for QF status: “small power

production” facilities and “cogeneration facilities.”16 16 U.S.C. 824a-3(a). A small power 

production facility is a generating facility with capacity of 80 MW or less whose primary energy 

source is renewable energy (hydro, wind or solar), biomass, waste or geothermal resources. 16 

U.S.C. 796(17)(A). Solar, wind, waste or geothermal facilities that were certified as QFs before 

1995 are not subject to the 80 MW-or-less size requirement. 16 U.S.C. 796(17)(E).

To become a QF, a small power production facility must meet the size and fuel

requirements set out in FERC’s regulations. 18 C.F.R. 292.203(a). 

Size requirements: Solar, wind, waste, or geothermal facilities certified as QFs before 

1995 are not subject to any size limitations. For all other small power production facilities, the 

power production capacity, either on its own or in combination with the capacity of other small 

 13 18 C.F.R. sec. 292.601(c). More detail on this exemption from FPA regulation 

appears in the discussion of the FPA, at Part II.E below.

14 Wholesale sales of electricity outside of PURPA are subject to the Federal Power Act, 

which requires sellers to prove to FERC the reasonableness of their prices. Part II below 

discusses FPA regulation. 

15 When the retail utility is a “nonregulated utility,” the obligation to establish the 

avoided cost prices lies with that entity. 16 U.S.C. § 824a-3(f)(2). As defined by PURPA 

Section 3(9) PURPA, 16 U.S.C. § 2602(9), a “nonregulated utility” is a utility not regulated by 

the state, such as a state-owned, municipally owned or cooperatively owned entity.

16 Because state feed-in tariffs will apply to renewables, the size and fuel requirements 

applied to cogeneration facilities as set forth in 18 C.F.R. 292.203(b), 292.205 and 292.207 are 

not discussed here.
7

power production facilities (using the same energy resource, owned by the same person or its 

affiliates and located at the same site), may not exceed 80 MW. 18 C.F.R. 292.204(a). 

Fuel requirements: A small power production facility’s primary energy source must be 

biomass, waste, renewable resources (wind, solar, hydro), geothermal resources, or any 

combination thereof. Seventy-five percent or more of the total energy input must be from one of 

these sources, with the exception of biomass, which may comprise 50 percent of the total input

(while the other 50% can be from non-QF qualified fuels, including fossil fuels). 18 C.F.R. 

292.204(b).17

QFs can self-certify; a small power production facility meeting the size and fuel 

requirements, who files with FERC a notice of self-certification along with a Form 556, becomes

entitled to PURPA’s benefits without the need for FERC action. 18 C.F.R. 292.207(a). 

Alternatively, the owner of a small power production facility meeting the size and fuel 

requirements for QF status may file an application for FERC certification that the facility is a 

qualifying facility. 18 C.F.R. 292.207(b). FERC may revoke QF status for either self-certified or 

FERC-approved QFs if the facility fails to conform to any of the FERC's qualifying facility size 

and fuel criteria. 18 C.F.R. 292.207(d).

2. State determines the utility's avoided cost

"Avoided costs" is shorthand for the statutory phrase, "incremental cost of alternative 

energy," defined by statute to mean "the cost to the electric utility of the electric energy which, 

but for the purchase from such cogenerator or small power producer, such utility would generate 

or purchase from another source."18 Avoided cost has two components—capacity and energy—

because PURPA obligates the utility to buy both products from the QF to the extent the utility 

can avoid capacity and energy costs by doing so. 

FERC’s regulations allow the QF to choose between an avoided cost price (a) that varies 

over the life of the contract (as the utility’s avoided cost varies) or (b) that the state commission 

 17 A "primary energy source" means the fuel or fuels used for the generation of electric 

energy. 16 U.S.C. § 796(17)(B). Section 292.204(b) of FERC's regulations provide that:

(i) the primary energy source of the facility must be biomass, waste, renewable resources, 

geothermal resources, or any combination thereof, and 75 percent or more of the total 

energy input must be from these sources.

(ii) Any primary energy source, which on the basis of its energy content, is 50 percent or 

more biomass shall be considered biomass.

18 16 U.S.C. 824a-3(d).
8

estimates upfront at the time the QF creates a “legally enforceable obligation” with the utility.19

The QF creates this obligation by demonstrating its willingness and ability to sell. Estimates of 

future costs never track with reality, of course. FERC has determined, however, that a variation 

of actual avoided costs from the original estimates does not invalidate the originally determined 

avoided cost price.20

PURPA’s avoided cost cap applies only to prices mandated by the state. A QF can 

negotiate with a utility to sell some or all of its output to a utility at market-based rates, which 

can exceed avoided cost.21

 19 FERC’s rules, at 18 C.F.R. § 292.304(e), require states to take into account the 

following factors, to the extent practicable: 

 A negotiated rate means the utility is volunteering to purchase, 

(1) Data regarding the utility’s cost structure and plans to add capacity; 

(2) “The availability of capacity or energy from a qualifying facility during daily and 

seasonal peak periods, including:” 

(i) The ability of the utility to dispatch the qualifying facility; 

(ii) The reliability of the QF; 

(iii) Contract terms; 

(iv) The extent to which scheduled outages of the qualifying facility can be 

coordinated with scheduled outages of the utility’s facilities; 

(v) The usefulness of energy and capacity supplied from a qualifying facility 

during system emergencies; 

(vi) The individual and aggregate value of energy and capacity from QFs on the 

electric utility’s system; 

(vii) The smaller capacity increments and the shorter lead times available with 

additions of capacity from QFs. 

(3) The relationship of the availability of energy or capacity from the QF to the ability of 

the electric utility to avoid costs, including the deferral of capacity additions and the 

reduction of fossil fuel use. 

(4) “The costs or savings resulting from variations in line losses from those that would 

have existed in the absence of purchases from a qualifying facility, if the purchasing 

electric utility generated an equivalent amount of energy itself or purchased an equivalent 

amount of electric energy or capacity.”

20 18 C.F.R. § 292.304(b)(5) provides: “In the case in which rates for purchases are 

based upon estimates of avoided costs over the specific term of the contract or other legally 

enforceable obligation, the rates for such purchases do not violate this subpart if the rates for 

such purchases differ from avoided costs at the time of delivery.” See also New York State Elec. 

& Gas Corp., 71 FERC 61,027 (1995) (declining to find contract in violation of PURPA where 

rates based on avoided costs at time contract obligation was incurred exceed avoided cost).

21 See Order No. 697-A, Market Based Rates for Wholesale Sales of Electric Energy, 

Capacity and Ancillary Services by Public Utilities, 123 FERC para. 61,055, 2008 FERC LEXIS 

788 at *548 (allowing QFs to make sales at market-based rates, and holding that certain QFs are 
9

whereas the premise of a feed-in tariff is that the state is mandating both the purchase and the 

price. Still, the opportunity for a negotiated PURPA price to exceed avoided cost suggests a path 

for a state that declines to adopt a mandatory feed-in tariff but that wants renewable sellers to 

receive compensation above avoided cost. The state could issue a rule committing utilities to

negotiate above-avoided-cost prices consistent with commission guidelines that also guarantees 

rate recovery of the resulting costs. 

FERC has imposed two important restrictions on the states' avoided cost price-setting

practices: (a) if the state uses a competitive bidding process to establish avoided cost, the 

bidding cannot exclude non-QFs; and (b) avoided cost cannot include “externality adders.” 

FERC announced these two restrictions in its 1995 Southern California Edison decision.22 In 

the case before FERC, the California Public Utilities Commission (California PUC) had 

established a three-step process by which utilities would carry out their PURPA obligations. 

First, utilities had to file a resource plan identifying potential resource additions. Based on these 

plans, the California PUC determined what new resources the utilities would add. Second, using 

cost data supplied by the utilities, the California PUC determined the utility’s avoidable resource 

additions (i.e., the additions the utility would have made but for its purchases from QFs), and 

then determined “benchmark prices” for those avoidable additions. Third, the California PUC

required utilities to conduct a QF-only bidding process for each avoidable resource. As the 

policy was originally established, for each avoided resource, the utility had to enter into a 

standard contract with each QF whose bid came in below that resource’s benchmark price. The 

winning bidders would receive the price bid by the second lowest bidder with respect to each 

avoided resource. Certain winning bidders would receive additional payments to reflect the 

assumed value to society of reduced air emissions.

In Southern California Edison, FERC held that the absence of non-QFs from the bidding 

process would produce rates exceeding avoided costs, in violation of PURPA. FERC also found 

that the “avoided cost” price could not include “environmental adders,” i.e., a state's view of the 

cost to society from the environmental effects of electricity production. Southern California 

Edison, 71 FERC at 62,080. FERC subsequently has made clear that when externalities become 

"monetized" (i.e., internalized by the utility as actual costs) they can be properly included in the 

avoided cost calculation. Monetization occurs through policy mechanisms such as emission tax 

or cap and trade regimes, which raise the utility's power purchase costs.23

 

exempt from market-based rate approval under criteria of 18 C.F.R. 292.601(c)(1). The concept 

of market-based rates is discussed at Part II.D.2 below.

22 Southern California Edison decision. 70 FERC para. 61,215 (1995), aff'd on 

rehearing, 71 FERC para. 61,269 (1995).

23 FERC explained (71 FERC at 62,080):

“Thus, in setting avoided cost rates, a state may only account for costs which 

actually would be incurred by utilities. A state may, through state action, 

influence what costs are incurred by the utility. Thus, accounting for 
10

Conclusion: If a state relies on PURPA as the legal basis for the feed-in tariff, and if the 

state uses competitive bidding to determine avoided cost price, the state must allow QFs and 

non-QFs to participate in the bidding. As put forward in the Federal Power Act section (Part II

below), if FERC clarifies and/or adjusts its precedent the state can avoid this restriction by 

relying on a state law mandate rather than PURPA as the basis for requiring utilities to purchase 

renewable power. 

C. PURPA Shrinkage: FERC has exempted some utilities from PURPA's 

purchase obligation

The Energy Policy Act of 2005 (EPAct) amended PURPA by authorizing FERC to 

exempt an electric utility from its PURPA obligation to buy from a QF if the QF has

“nondiscriminatory access” to at least one of three things:

 “(A) (i) independently administered, auction-based day ahead and real time 

wholesale markets for the sale of electric energy; and (ii) wholesale markets for 

long-term sales of capacity and electric energy; or”

 “(B) (i) transmission and interconnection services that are provided by a 

Commission-approved regional transmission entity and administered pursuant to 

an open access transmission tariff that affords nondiscriminatory treatment to all 

customers; and (ii) competitive wholesale markets that provide a meaningful 

opportunity to sell capacity, including long-term and short-term sales, and electric 

energy, including long-term, short-term and real-time sales, to buyers other than 

the utility to which the qualifying facility is interconnected. In determining 

whether a meaningful opportunity to sell exists, the Commission shall consider, 

among other factors, evidence of transactions within the relevant market; or”

 “(C) wholesale markets for the sale of capacity and electric energy that are, at a 

 

environmental costs may be part of a state's approach to encouraging renewable 

generation. For example, a state may impose a tax or other charge on all 

generation produced by a particular fuel, and thus increase the costs that would be 

incurred by utilities in building and operating plants that use that fuel. 

Conversely, a state may also subsidize certain types of generation, for instance 

wind, or other renewables, through, e.g., tax credits.”

“A state, however, may not set avoided cost rates or otherwise adjust the bids of 

potential suppliers by imposing environmental adders or subtractors that are not 

based on real costs that would be incurred by utilities. Such practices would result 

in rates which exceed the incremental cost to the electric utility and are 

prohibited.”
11

minimum, of comparable competitive quality as markets described in subparagraphs (A) 

and (B).”24

A utility seeking to terminate its purchase obligation may file an application with FERC 

on a service territory-wide basis. 18 C.F.R. § 292.310. For purposes of evaluating these utility 

applications, FERC has created three “rebuttable presumptions.”25 There is a rebuttable 

presumption that:

1. In markets operated by the Midwest Independent Transmission System Operator 

(MISO), PJM Interconnection, ISO-New England, the New York Independent 

System Operator (NYISO) and the Electric Reliability Council of Texas 

(ERCOT), QFs with a net capacity of greater than 20 megawatts have nondiscriminatory access and that utilities in these markets should be relieved of their 

purchase obligations. 18 C.F.R. § 309(e), (f)).

2. In all markets, QFs with a net capacity of greater than 20 MW have 

nondiscriminatory access to markets if they are eligible for service under a FERCapproved open access transmission tariff or a “reciprocity” tariff filed by nonjurisdictional transmission owners. 18 C.F.R. § 309(c).

3. Small QFs (with net capacity of 20 MW or less) do not have non-discriminatory 

access to any wholesale electric markets. 18 C.F.R. § 309(d)(1).

26

 24 16 U.S.C 824a-3(m)(1)(A)-(C); see also the FERC regulations implementing EPAct 

changes to PURPA, 18 C.F.R. 292.309 (2009). Because of the importance of this regulation to 

states contemplating feed-in tariffs, the full regulation appears in Appendix B.

25 A “rebuttable presumption” places the burden of producing contrary evidence on the 

person opposing the presumption. This means that unless an opponent offers contrary evidence 

(i.e., “rebuts” the presumption), the presumption is deemed true and the entity receives the 

benefits of the presumption. 

26 A QF (or an intervenor) may rebut the presumptions described in paragraphs 1 and 2 

above by showing either that it has certain operational characteristics that effectively prevent it 

from participating in the market or that it lacks access because of transmission constraints. 18 

C.F.R. 292.309(a)(3)(c)(establishing criteria for rebutting presumption that QF has 

nondiscriminatory access where eligible for open access tariff); 18 C.F.R. 292.309(e)(1)-(2) and 

(f)(1)-(2)(establishing criteria for rebutting presumption that QF has non-discriminatory access 

in MISO, NYISO, PJM, ISO-New England and ERCOT markets).

When a utility makes an application to terminate its mandatory purchase obligation, 

FERC must notice the application and allow public comment, during which time a state 

commission or any other interested party may object to a utility’s termination request. 18 C.F.R. 

292.310(a) (requiring notice of application to terminate mandatory purchase obligation).
12

A state intending to rely on PURPA for its feed-in tariff first must determine if its utilities 

have obtained a FERC exemption.27 If PURPA still applies and there is not a FERC exemption, 

the state can proceed. However, if the PURPA mandate does not apply to the QF’s host utility,28

and if there is no other utility the QF can “tag” with a purchase obligation (as explained in the 

next paragraph), then PURPA cannot be used. Instead, (a) the state must create its own legal 

mandate to purchase from renewables, and (b) Sections 205 and 206 of the Federal Power Act 

(i.e., the provisions requiring that rates be just and reasonable) will apply to the renewable seller 

(unless FERC has exempted the seller because its capacity is 20 MW or less). This non-PURPA 

route is explained in Part II below. 

Where a QF’s host utility has obtained this FERC exemption, it is not clear to what 

extent the QF can require other utilities to buy its power. FERC’s PURPA regulations

(unchanged by the EPAct 2005 amendment) allow a QF to have the host utility transmit the QF’s 

output to other utilities, which then would have the PURPA purchase obligation. Specifically, 

18 C.F.R. sec. 292.303(d) states that 

"[A]n electric utility which would otherwise be obligated to purchase energy or 

capacity from such qualifying facility may transmit the energy or capacity to any 

 

27 Here is a sampling of FERC decisions: “Order granting application to terminate 

purchase obligation and denying late intervention” in Duke Energy Shared Services, Inc. et al.,

119 FERC ¶ 61,146 (May 17, 2007); “Order Granting in Part and Denying in Part Application” 

in Xcel Energy Services, Inc, Southwestern Public Service Company, Oklahoma Gas and 

Electric Company et al., 122 FERC ¶61,048 (January 22, 2008); “Order granting application to 

terminate purchase obligation” in American Electric Power Services Corp et al., 120 FERC ¶ 

61,052 (July 18, 2007) (filed on behalf of certain operating companies, which in sum are referred 

to as AEP East. AEP East is made up of: Appalachian Power Company, Columbus Southern 

Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport 

Power Company, Ohio Power Company, and Wheeling Power Company); “Order granting 

application to terminate purchase obligation in Virginia Electric and Power Company, 124 

FERC ¶ 61,045 (July 17, 2008); “Letter order accepting PPL Electric Utilities Corp's 7/22/09 

filing of an Application for Authorization to Terminate the Mandatory Purchase Obligation from 

Qualifying Facilities with Net Capacity Over Twenty Megawatts on a Service-Territory-wide 

Basis,” Docket No. QM09-6 (October 14, 2009). This list will likely expand as more utilities 

apply for the exemption.

Note the citation of Southwestern Public Service Company above “denying in part” a 

utility’s application to terminate the purchase obligation. In it, FERC denied Xcel Energy's 

request to terminate its mandatory purchase obligation where a wind-qualified facility rebutted 

the presumption of a competitive market by offering specific evidence of transmission 

constraints that precluded it from accessing third-party purchasers. 122 FERC para. 61,048 at 

61326.

28 “Host utility” means the utility in whose service territory the QF project is located.
13

other electric utility. Any electric utility to which such energy or capacity is 

transmitted shall purchase such energy or capacity under this subpart as if the 

qualifying facility were supplying energy or capacity directly to such electric 

utility." 

There are several uncertainties about how this provision will operate. First, the host utility’s 

duty to transmit to another utility, making this second utility obligated to purchase the QF’s 

power, exists only if the host utility is "otherwise obligated to purchase." If FERC, pursuant to 

the 2005 statutory amendment, has terminated the host utility’s purchase obligation, the host 

utility might argue that it is no longer "otherwise obligated." That reasoning creates doubt as to 

whether the QF can rely on this regulation to “tag” the second utility. (FERC could (a) accept 

the utility’s argument, (b) condition the exemption from the purchase obligation on the utility’s 

continuing to have the transmission obligation, or (c) interpret the “otherwise obligated” phrase 

to mean that the utility was obligated but for the 2005 amendment and therefore is still 

obligated). Second, since every utility has an obligation to transmit power under FERC Order 

888, the relevance of this provision is unclear. Note also that in the context of a regional 

transmission organization (RTO), FERC’s Order 2000 requires the RTO to provide transmission 

throughout its multi-utility territory at a single rate. That obligation makes it possible that the 

QF located in the RTO’s territory could require a purchase from any utility that has not received 

from FERC an exemption from the PURPA purchase obligation. FERC clarification of these 

points would be useful.

The exemption from PURPA is not guaranteed by statute; it depends on factual findings 

made by FERC. A state can protest a utility's exemption request, challenge a FERC decision in 

court, and/or petition FERC to eliminate an exemption already granted. Further, FERC has an 

obligation to modify or remove a previously granted exemption if the market facts vary from 

those on which FERC originally relied. See 18 C.F.R. §292.311 (describing procedure for 

reinstating obligation to purchase).

One might argue that Congress, in authorizing FERC to exempt utilities from their 

PURPA purchase obligations, intended the broad result of preempting any state law that 

mandated a utility purchase. The 2005 statute does not support this argument. The U.S. 

Supreme Court has stated repeatedly that it will find preemption only if Congress had made its 

intent clear.29 Here, Congress confined its clarity to relieving utilities of their PURPA 

obligations. 

D. Compensation for PURPA Sellers: States can—with care—grant renewable 

sellers compensation exceeding the utility's avoided cost

Although this report discusses multiple uncertainties concerning a state’s ability to 

promulgate a feed-in tariff, the state’s path is clear with one category of transactions: A tariff 

 29 Pacific Gas & Elec. Co. v. State Energy Resources Conservation & Development 

Comm’n, 461 U.S. 190 (1983); Rice v. Santa Fe Elevator Corp., 331 U.S. 218 (1947).
14

established under PURPA, where the state supplements the avoided cost payment with 

compensation in a form FERC has already approved, is free from federal preemption.

A utility's avoided cost will likely fall below the compensation necessary to attract 

renewable producers of the type, quality, and quantity desired by most states. The reason is 

straightforward: Absent a renewables mandate, the utility would procure non-renewable power 

(sometimes called "generic power"), whose price is usually lower than renewable power. 

There are solutions, however. States basing their feed-in tariffs on the PURPA mandate 

(which imposes the avoided cost price cap unless the price is negotiated) can lawfully grant 

renewable energy generators compensation exceeding avoided cost. The key to accomplishing 

this objective is that this compensation not be part of the price that the utility pays for purchasing 

power under the PURPA mandate. FERC decisions make at least three alternatives available.30

1. Renewable energy credits awarded to the renewable seller31

A renewable energy credit or certificate (REC), also known as a “green tag,” is a tradable

commodity representing proof that a unit of electricity (e.g., 1 MWh) was generated from an 

eligible renewable energy resource. Some states that require utilities to purchase renewable 

energy have created REC-ownership tracking systems to document a utility's compliance with 

that purchase mandate. Businesses and individuals might also buy RECs to meet company or 

personal environmental goals. A REC entitles its owner to assert that it has produced or 

purchased renewable energy in the amount, and from the resource, stated by the certificate. 

Legal rights associated with the REC include the right to sell it within the rules of the tracking 

system and the ability to demonstrate compliance with a renewable purchase mandate.

Where a REC has financial value, it offers states one way to compensate renewable 

generators above utility avoided cost. To do so, the state would take two steps. First, acting 

under PURPA, the state would establish the tariff’s mandatory offer price for power at the 

utility's avoided cost. Then, the state could award RECs to each renewable project owner for all

MWh produced. The renewable owner can sell the REC to others, either with or separately from 

the energy produced. 

 30 These same options will apply in the Federal Power Act, as explained in Part II below. 

If the state is basing the utility's obligation to purchase on state law rather than PURPA, the 

seller must receive FPA approval for the sale. If the compensation deemed by the state as 

necessary to attract the seller exceeds FERC's view of just and reasonable prices, it is believed—

although there is no FERC precedent on this point, one way or the other—that the state is free to 

grant that extra compensation through these same non-rate means.

31 Scott Hempling, the main author of this report, provided legal analysis for this section. 

Information about renewable energy certificates and their markets was primarily written by 

Karlynn Cory and Kevin Porter, with input from Robert C. Grace of Sustainable Energy 

Advantage.
15

This extra compensation does not violate PURPA's avoided cost standard. In American 

Ref-Fuel Co.,

32 FERC found that RECs are not part of the PURPA-mandated compensation from 

utility to QF; the avoided cost rate compensates the QF for capacity and energy, but not for 

renewable attributes. From this basis, FERC reasoned: 

"If avoided cost rates are not intended to compensate a QF for more than capacity 

and energy, it follows that other attributes associated with the facilities [such as 

renewable attributes] are separate from, and may be sold separately from the 

capacity and energy...."

"... RECs are created by the States. They exist outside the confines of PURPA. 

PURPA thus does not address the ownership of REC.... States, in creating RECs 

have the power to determine who owns the REC in the initial instance and how 

they may be sold or traded; it is not an issue controlled by PURPA." 

American Ref-Fuel Co., 105 FERC para. 61,004 (2003) at para. 23.

FERC thus found that states have unrestricted authority (that is, unrestricted by federal 

law) to create RECs, to establish their value by determining procedures for their purchases and 

sales, and to assign these value-laden RECs to renewable generators (or others). None of these 

options represents “an issue controlled by PURPA.” In this respect, RECs resemble the tax 

credits and cash payments that FERC views as distinct from avoided cost payments and outside 

FERC’s legal domain. (See Part I.D.2 immediately below). Because the REC is not part of the 

price of the PURPA-mandated purchase of power, the REC compensation to QFs would not 

violate PURPA's avoided cost cap, even if the utility’s REC purchase is “bundled” with its 

avoided cost PURPA power purchase. The key is that the utility’s obligation to buy RECs 

(which is outside PURPA’s domain) be stated separately from the utility’s obligation to buy 

power (which is within PURPA’s domain, and thus must be capped at avoided cost). 

If REC prices are determined by market forces, it is not certain that the sum of the 

PURPA avoided cost compensation and market-based REC compensation will produce revenue 

sufficient in quantity and predictability to attract the desired types and quantities of renewable 

sellers. Further, different technologies will require different levels of compensation, so fungible 

RECs whose prices are set by market forces would pose a challenge to implementing tariffs 

whose prices differ by technology. 

One possible solution — briefly mentioned here and not fully explored — is for states to 

create a class of REC in conjunction with state FIT policies. The state may be able to order the 

utility to buy such RECs at a price established as the difference between the target compensation 

for the seller and the utility’s avoided cost under PURPA. This state-set REC price may vary 

 32 105 FERC ¶ 61,004, at P23 (2003), request for reh’g denied, 107 FERC ¶ 61,006 (2004), 

appeal dismissed, Xcel Energy Servs., Inc. v. FERC, 407 F.3d 1242 (D.C. Cir. 2005).
16

with the technology (and perhaps project size) because different projects will have different 

costs. In considering this option, several issues merit consideration:

• In some contexts, RECs are fungible: RECs from one renewable source will be 

valued the same as from another renewable source. Yet in others, REC prices 

from generators within in the same state or region may differ based on their type. 

For example, many states have established distinct renewable portfolio standard 

‘tiers’ or classes with differing eligibility and for which REC price caps and 

prevailing prices may differ.33

• REC prices have been most typically dictated by market dynamics or competitive 

procurements. They may vary within and across regions, and over time. Some 

RECs are transacted long-term, others short-term; sometimes bundled with energy 

and/or capacity, other times unbundled. 

• For states with an RPS that includes a fixed alternative compliance payment 

(ACP), interactions between the state-set REC prices and the ACP must be 

explored.

It is beyond the scope of this report to fully assess whether the sum of the PURPA 

avoided cost compensation plus REC compensation will be sufficient for renewable energy 

development. Future studies, guided by the legal parameters set forth in the present report, 

should focus on ways for states to align REC compensation with sellers’ needs.

2. Tax credits awarded to the utility purchaser

FERC allows a state to set a PURPA purchase price exceeding avoided cost, if the state 

then grants the purchasing utility a tax credit equal to the excess. CGE Fulton34

FERC rejected the utility's challenge, because the tax credit meant that "the effective rate 

is intended to be equal to—and not above—the electric utility's avoided cost." FERC explained: 

involved an 

Illinois state law implementing PURPA. The law required utilities to purchase power from a

PURPA-qualified municipal waste burning facilities at rates equal to the retail rate charged by 

the utility to the municipality owning the facility. That rate exceeded the utility's avoided cost. 

The statute also provided a monthly tax credit to the utility for amounts paid above avoided cost.

"[W]e note that there is no question that a state could provide tax credits (and/or 

direct cash subsidies for that matter) to certain types of sellers of electric energy, 

including QFs or certain types of QFs, without violating section 210 of 

PURPA....By providing a tax credit to the purchasing electric utility, the Illinois 

Legislature effectively capped the rate paid by the electric utility at its avoided 

 33 In some states, solar technologies or distributed projects are separated into their own 

tier in the RPS, and the project costs and penalty prices are higher than they are for other RECs.

34 70 FERC para. 61,290, reconsideration denied, 71 FERC para. 61,232 (1995).
17

cost, while providing additional taxpayer-funded benefits to a category of QFs. 

Under Illinois' scheme, amounts above avoided cost are paid by taxpayers, not by 

the purchasing utility or its ratepayers."

FERC elaborated in its Order on Rehearing: 

"[H]ere the purchasing utility is not required to pay in excess of avoided cost. 

That a state may choose to grant loans, subsidies or tax credits to particular 

facilities on environmental or other policy grounds is not inconsistent with 

PURPA."

A state's ability to supplement the avoided cost price is not confined to tax credits 

awarded to the purchasing utility. Loans, subsidies—and, of course, REC assignments—are all 

lawful means of supplementing the seller's compensation.

The CGE Fulton approach is necessary only if the state is relying on PURPA as the legal 

basis for compelling a utility to buy renewable power. If state law establishes a distinct, 

non-PURPA mandate for the utility to offer to buy from the renewable entity, and if FERC

clarifies and/or adjusts its precedent, the state may set whatever offer price it wishes, without 

PURPA preemption. In that context, however, the FPA applies and requires the seller to show 

that its sales price is “just and reasonable.” The FPA, unlike PURPA, preempts a state from 

commanding a purchase at a specified price. As explained in Part II.B below, under the FPA the 

state can only order its utility to offer to buy; any resulting contract must go to FERC for 

approval.

Tax credit caution: To comply with PURPA’s avoided cost cap, the Illinois statute in 

CGE Fulton provided a monthly tax credit to the utility for purchase payments exceeding the 

utility’s avoided cost.35

 35 Two other nuances, according to FERC: (1) "[T]he electric utility is excused from its 

obligation to purchase electricity at the above rate if the tax credits would exceed, on a monthly 

basis, the utility's estimated taxes." and (2) "[O]nce the facility has paid in full its capital costs or 

indebtedness incurred in developing and implementing the project, the facility is required to 

reimburse the Illinois state treasury for the tax credits."

What if the state tax liability is lower than the increment of the state-set 

price above the utility’s avoided cost? In that situation, there would be a PURPA violation, 

because the tax credit would not fully reimburse the utility for its payments above avoided cost. 

A utility’s low tax liability thus restricts the viability of the CGE Fulton solution. If the credit 

necessary to make the net utility payment equal to avoided cost exceeds the utility's tax liability, 

one solution is to make the tax credit refundable; meaning, the state writes a check to the utility 

for the excess amount. This adjustment would require state legislation.

The Illinois statute relieves the utility of its obligation to purchase at that statutory rates 

(i.e., the average amount per kilowatt-hour paid by the unit local government in which the 

electricity generating facilities are located) when the tax credits would exceed the utility's tax 

liability for a given month. 220 ILCS 5/8-403.1(d).
18

3. Payments to the renewable seller from other sources

In CGE Fulton, FERC stated that "a state may choose to grant loans, subsidies or tax 

credits to particular facilities on environmental or other policy grounds" without violating 

PURPA. This general statement opens many doors for a state seeking to grant the seller 

compensation exceeding utility avoided cost. Tax credits to the seller, cash payments emanating 

from "system benefit charge" revenues, cash payments flowing from general tax revenues

(upfront or production based), funding from any source—all these options are available to the 

state when relying on PURPA as the mandate for utility purchases. 36

Part II below will note that the same options will apply in the Federal Power Act 

scenario. If the state is acting outside PURPA (and thus under state law) so that the seller must 

receive FPA approval for the sale, and if the compensation deemed by the state as necessary to 

attract the seller exceeds FERC's view of just and reasonable prices, the state is free to award 

that extra compensation through these non-rate means. However, this application of non-rate 

compensation has not been specifically applied to FPA by FERC.

4. The problem of avoided cost variability

A utility's avoided cost varies with the utility's needs and with market circumstances. If 

the utility brings on a new major capacity addition, its avoided capacity cost will drop. If the 

cost of fuel drops, so will the utility's avoided energy cost. Conversely, if a planned project is 

cancelled or the cost of fuel increases, the utility’s avoided energy cost will increase. Today, 

states address these realities by periodically changing the utility's official avoided cost rate. As 

noted in Part I.B.2 above, FERC’s regulations address this concern by allowing a QF to lock in 

an avoided cost estimate upfront, determined by the state at the time of the QF’s “legally 

enforceable obligation,” thereby setting a fixed price for the life of the contract. 

If a QF chooses the option of variable avoided cost payments, this variability poses a 

challenge to the feed-in tariff designer who wishes to establish a reliable revenue stream over the 

renewable project's life. They can solve the problem with a two-part approach made possible by 

the FERC's decisions in American Ref-Fuel and CGE Fulton. By combining (a) a generic power 

price, equal to avoided cost, paid by the utility, with (b) incremental compensation to the QF, 

separately funded (such as a state-required utility purchase of the REC, or system benefit charge 

revenue), where the size of the compensation varies inversely to periodic changes in the utility's 

avoided cost, the state eliminates the awkwardness. The sum of the avoided cost compensation 

and the incremental compensation—each of which will vary in opposite directions—will be a 

stable stream of income to the renewable seller. 

 36 Although “system benefit charge” revenues come from ratepayers, their use here 

would not violate PURPA’s avoided cost cap because they are not part of the mandatory rate 

paid by the utility to the QF.
19

5. Can the state set different PURPA prices for different technologies?

Under PURPA, the power sales price, if mandated by the state, must equal the utility's 

avoided cost. Avoided cost is the cost the utility would incur had it supplied its needs by means 

other than buying from the QF. As a general principle, that utility's avoided cost does not vary 

with differences in QF technology.

37 If a state wishes to compensate different technologies at 

different amounts, it can do so by varying the state grants, production-based incentives, or tax 

credits that supplement the utility's avoided cost payment.

E. Application of PURPA concepts to state feed-in tariffs: Summary of the 

three steps

A state seeking to use the PURPA mandate as the context for its feed-in tariffs, must take 

the following steps:

1. Determine whether FERC has exempted its utilities from a PURPA must-buy 

obligation. See Part I.C above.

2. Align the eligibility criteria for the feed-in tariff with FERC's rules for certifying QFs. 

See Part I.B.1 above.

3. Establish a process for granting the seller compensation in excess of avoided cost, in a 

manner that complies with PURPA. See Part I.D above. The options for setting seller 

compensation are: 

a. The state can declare that the seller's production includes two distinct 

goods: generic power and a REC. The price set under the feed-in tariff 

would reflect the utility's avoided cost of procuring generic power. The 

state then would award the seller the value of the REC, calculated by the 

state to equal the compensation gap. The award of REC value to the seller 

could occur through several means: (a) the state awards the REC directly 

to the seller (who then can sell it on the market); (b) the state could pay 

the seller for the REC, using taxpayer funds or system benefit charge 

funds; or (c) the state could command the utility to buy the REC from the 

seller (then allow the utility to recover the cost from ratepayers).

b. The state can set the purchase prices at a level exceeding avoided cost but 

give the utility a tax credit for the difference.

 37 Note, however, that FERC rules state that a utility’s avoided cost rates “may 

differentiate among qualifying facilities using various technologies on the basis of the supply 

characteristics of the different technologies.” 18 C.F.R. § 292.304(c)(3)(ii).
20

c. The state can award the seller a grant or loan (either upfront or 

production-based), paid for with taxpayer funds of system benefits charge 

funds.
21

II. State-Level Tariffs Based on a State Law Mandate

In this category of transactions, the utility's obligation to file a feed-in tariff arises from a 

state statute rather than PURPA. The state legislature enacts a statute requiring its utilities (or 

authorizing the state commission to require the utilities) to buy capacity and energy, and possibly 

RECs, from defined categories of sellers. The statute makes no reference to PURPA. For states 

whose utilities have received from FERC a PURPA exemption (see Part I.C above), a state law 

mandate is their only option. 

Because this category of transactions involves wholesale sales outside of PURPA, it 

implicates the Federal Power Act. The FPA vests in FERC exclusive jurisdiction over all 

wholesale sales in interstate commerce (unless those sales are subject to PURPA). FERC has a 

statutory obligation to ensure the prices for these transactions are “just and reasonable” and not

“unduly discriminatory.” To prove justness and reasonableness, the seller has two options: seek 

FERC approval of a specific “cost-based” price on a contract-by-contract basis (i.e., a price 

designed to cover the seller’s prudent costs plus a reasonable return on equity); or seek FERC’s 

approval of “market-based rate authority” (i.e., the right to charge any price—which FERC will 

grant only if the seller proves it has no market power). FERC has no statutory ability to 

supplement “just and reasonable” prices to ensure attractiveness to renewable sellers. As with 

PURPA (see Part I.D above) it is presumed that states can supplement the FERC-approved 

prices, such as with RECs and cash grants and above-market prices accompanied by tax credits 

for the purchasing utilities (although FERC has not clarified this specifically).

Part II explains how the Federal Power Act affects states seeking to design feed-in tariffs, 

and sellers seeking to sell under those tariffs. FERC clarification and/or adjustments to its 

precedent will be required. Although the FPA grants FERC exclusive jurisdiction over wholesale 

sales, this report argues that a state can establish feed-in tariffs, free of FPA preemption, if those 

tariffs play a limited role: establishing a utility's offer to buy power at a state-specified rate, 

subject to ultimate FERC approval. A seller choosing to accept that offer then must (a) enter 

into a contract with the purchasing utility and (b) obtain FERC authorization of that contract, 

before a sale can lawfully occur. This report explains that FERC modification of its precedent is 

necessary for this option to be free of legal risk.

After explaining these FPA fundamentals, Part II describes the sellers’ obligation to 

obtain FERC’s permission to sell. They must choose either (a) contract-by-contract "cost-based" 

review or (b) advance, blanket permission under FERC's "market-based rate" program. Because 

FERC consideration under the FPA of state-mandated offer prices is a new concept, both options 

involve uncertainties.

In addition, FERC has exempted PURPA QFs under 20 MW from its FPA review. This 

exemption creates a means for states to enact more traditional feed-in tariffs for that category of 

sellers; but this option also is uncertain without FERC clarification. 

Part II concludes with recommendations on how FERC could modify its procedures, if it 

chooses to facilitate state-level feed-in tariffs. 
22

A. Federal Power Act Overview: FERC has exclusive jurisdiction to set 

wholesale rates

Since 1935, the Federal Power Act has placed in the Federal Energy Regulatory 

Commission (previously the Federal Power Commission) the exclusive authority to regulate "the 

sale of electric energy at wholesale in interstate commerce."38 It is unlawful to make a sale at 

wholesale without proving to FERC that the price is "just and reasonable" and not "unduly 

discriminatory." 

FERC's authority includes the exclusive authority to set the rates for these wholesale 

sales.39

 38 Section 201 of the FPA provides: 

 FPA Section 205 thus directs FERC to review and ensure the justness and 

reasonableness of:

(a) It is hereby declared that the business of transmitting and selling electric 

energy for ultimate distribution for the public is affected with a public interest, 

and that Federal regulation of that part of such business which consists of the 

transmission of electric energy in interstate commerce and the sale of such energy 

at wholesale in interstate commerce is necessary in the public interest, such 

Federal regulation, however, to extend only to those matters which are not subject 

to regulation by the states.

(b)(1) The provisions of this Part shall apply to the transmission of electric energy 

in interstate commerce and to the sale of electric energy at wholesale in interstate 

commerce. 

In Federal Power Act law, the term "interstate commerce" has a technical meaning. 

Under precedent unchanged (and undisputed) since the early 1970s, all wholesale transactions 

within the interconnected grid, even if the contractual origin and destination are within a single 

state, are within "interstate commerce" and therefore subject to FERC's jurisdiction. See FPC v. 

Florida Power & Light Co., 404 U.S. 453, 454-55 (1972) (recognizing that electrons from 

intrastate sale in Florida move in interstate commerce because of commingling of intrastate and 

interstate power at point of interconnection with out-of-state utility). Thus, a sale by a wind 

generating plant in Nevada to a utility located in Nevada is in "interstate commerce." 

The Federal Power Act does not apply to Hawaii, Alaska, and most of Texas because these areas 

are not connected to the interstate electric grid. (That is why the Hawaii Public Utilities

Commission, which one of the authors advised, could promulgate a feed-in tariff order without 

considering FPA issues.) PURPA, in contrast, applies to all states, except to the extent where 

FERC, acting under authority granted by Congress in 2005, has exempted utilities from their 

PURPA purchase obligations.

39 Miss. Power & Light Co. v. Miss. ex rel. Moore, 487 U.S. 354, 371, 108 S. Ct. 2428, 

2439 (1988) (describing FERC's "exclusive authority to determine the reasonableness of 
23

"all rates and charges made, demanded or received by a public utility [either 

through a rate schedule or contract] for or in connection with the sale of electric 

energy subject to the jurisdiction of the Commission."40

Where rates for wholesale transactions are unjust, unreasonable, or unduly discriminatory, 

Section 206 of the FPA requires FERC to determine and re-set wholesale rates itself.41

B. To avoid FPA preemption, states must fashion their feed-in tariffs as offers to 

purchase, but even then legal uncertainty exists

Although FERC has exclusive jurisdiction over wholesale sales, states have jurisdiction 

over wholesale purchases by retail utilities. This federal-state jurisdictional relationship allows 

states to command their retail utilities to make offers to purchase at a specified rate, subject to 

FERC's ultimate authority to review and approve the terms of any sale that results when a seller 

accepts the utility’s offer. The ensuing discussion will describe FERC pronouncements that

require clarification and/or adjustment, if states are to be able to design tariffs that suit their 

needs while avoiding FPA preemption.

1. FPA Background: FERC's preemptive authority over wholesale sales

The Federal Power Act forces market entities to conduct transactions within contracts

that are under FERC jurisdiction. In other words, it is unlawful to sell at wholesale without a 

FERC-authorized contract.42

This legal fact means that a state-level tariff that relies on state law (and not PURPA), by 

itself, cannot give life to a transaction. This conclusion highlights the fundamental difference 

between U.S. law and the typical European-style feed-in tariff. The latter tariff contains the full 

 Only FERC can establish the rates, terms and conditions for a 

wholesale sale. There is no lawful transaction until FERC approves it. 

 

wholesale rates"); FPC v. S. Cal. Edison Co., 376 U.S. 205, 215216, 84S. Ct. 644, 651 (1964) 

("Congress meant to draw a bright line easily ascertained, between state and federal jurisdiction . 

. . . This was done in the Power Act by making FPC jurisdiction plenary and extending it to all

wholesale sales in interstate commerce except those which Congress has made explicitly subject 

to regulation by the States.").

40 16 U.S.C. sec. 824d(a).

41 16 U.S.C. sec. 824e.

42 Part II.D below explains that sellers can obtain FERC authorization in two alternative 

ways: on a contract-by-contract basis, whereby the seller submits each contract for approval 

(known as cost-based regulation); or on a pre-approval, blanket basis, whereby the seller 

receives advance approval to enter into contracts at will without the need for further review 

(known as market-based regulation).
24

set of rights and responsibilities: any eligible seller has a right to sell, merely by connecting with 

the purchasing utility and complying with the tariff terms. Under the FPA, the state-level tariff 

can be only the first step in a process that culminates in FERC approval of a contract. 

Further, a state-level tariff cannot lawfully command the utility to purchase at the 

state-set price. What if FERC, reviewing a state-mandated purchase, were to find the state-set 

price unjust and unreasonable, and require a different price? The utility then would be in an 

unworkable position: it could not simultaneously comply with the state's command to buy at one 

price and FERC's command that the contract have a different price. To avoid this position of 

impossibility, Congress has made FERC's price-setting authority preemptive of states.43 

2. State authority to require offers to purchase is not preempted if 

FERC clarifies or adjusts its existing precedent

Does FERC's exclusive authority over wholesale sales mean that U.S. law bars state-level 

feed-in tariffs outside of PURPA? This subsection argues that the answer is "no," provided that 

the state designs the tariff to be the utility's offer to buy at a state-specified price. This analysis is 

not free from doubt; the subsequent subsection describes FERC precedent that will require 

clarification or modification to remove legal uncertainty.

In this FPA context, it is necessary first to distinguish a "tariff" from a "contract," or 

more specifically, a state-jurisdictional tariff from a FERC-jurisdictional contract. In the context 

of utility purchases, a tariff creates a general legal obligation to buy the products described in the 

tariff, under the terms and conditions set forth in the tariff, from any seller made eligible by the 

tariff. Under this tariff description, the tariff itself does not establish a contract, i.e., a mutual 

obligation to buy and sell. Accompanying the tariff, therefore, is a standard contract, sometimes 

called a service agreement. That contract would state the names of the buyer and seller, the 

seller's characteristics, and other information necessary under state law to establish a contract, 

and would reference the tariff as the source of the rates, terms and conditions applicable to the 

contract. In the context of FPA-jurisdictional agreements, the contract would become effective 

only upon FERC's authorization.

If the state-mandated tariff is merely an offer to buy, it does not, by itself, purport to 

establish a wholesale price or complete a wholesale contract. It is an offer only. The seller, on 

accepting that offer, would enter into a contract with the retail utility. That contract is a 

FERC-jurisdictional contract, meaning it has legal force only if FERC allows it. The state-level 

feed-in tariff starts the contractual process, but there is no transaction until FERC approves the 

contract. 

Under this approach, the state tariff remains several steps removed from FERC's 

exclusive jurisdiction over the wholesale sale. The seller and FERC, not the state, determine 

whether a transaction will occur, because there is no transaction unless the seller enters a 

contract with the utility and obtains FERC authorization of that contract. While the state sets the 

 43 See Appendix A for an explanation of "conflict preemption."
25

offer price, there is no contract price until the seller accepts the buyer’s offer and obtains 

FERC’s approval to sell at that price.44 

Because the state's feed-in tariff is merely an offer to buy, FERC jurisdiction to 

determine the lawfulness of the consummated transaction is unaffected. FERC will review the 

contract for consistency with the FPA's requirement that wholesale contracts be just and 

reasonable and not unduly discriminatory. FERC has full discretion to disapprove the contract

or condition its approval on modifications, including the rates. The state has taken no action to 

interfere with this discretion. The state has only directed its retail utilities to have on file, at the 

state commission, a tariff that offers to buy power at a specified rate. That tariff is merely a 

means by which the state guides the purchasing decisions of its retail utilities.45 And, if FERC 

conditions its approval on modifications to the contract, the parties need not accept those 

modifications; the standard terms set forth in the state-mandated offer can leave the utility free to 

withdraw its offer. 

By characterizing (and designing) the feed-in tariff as state regulation of the utility's 

purchasing practices, the state action would fall within a legal area long protected from 

preemption by the FERC and the courts. FERC has stated: "The Commission has consistently 

recognized that wholesale ratemaking does not, as a general matter, determine whether a 

purchaser has prudently chosen from among available supply options."46

FERC has elaborated as follows: 

 44 Cf. Commonwealth of Massachusetts v. United States, 729 F.2d 886 (1st Cir. 1984) 

(finding that FPA preempted state commission from directing a retail-utility-as-wholesale-seller 

to make a filing a FERC; Section 205 of FPA envisions voluntary rate filings at FERC by 

wholesale sellers).

45 It is the prospect of FERC review and modification that concerns advocates of feed-in 

tariffs, where the purpose is to guarantee sellers a known revenue stream, which drives down 

financing costs and transaction costs and, through that certainty, encourages development of 

competitive markets for manufacture and installation.

46 Cent. Vt. Pub. Serv. Corp., 84 FERC 61,194 (1998). See also Philadelphia Elec. Co., 

15 F.E.R.C. 61,264 (1981) ("[W]e did not mean by this order [accepting a wholesale contract] to 

prejudge, for our own purposes or those of the respective state commissions, a determination of 

the prudence of either party in entering into this transaction"); Southern Company Services, Inc., 

26 F.E.R.C. 61,360 (1984) ("[T]he Commission is not empowered to disapprove or modify a 

power sales agreement on the grounds that the buyer may not be making the best possible deal . . 

. . [T]he question of the prudence of a utility's power purchases is properly an issue in the 

buying utility's rate case where it seeks to pass the costs of its purchased power on to its 

ratepayers"); Southern. Co. Services, Inc., 20 F.E.R.C. 61,332 (1982)(same); Minn. Power & 

Light Co. and Northern States Power Co., 43 F.E.R.C 61,104 at 61,34243, reh'g denied, 43 

F.E.R.C. 61,502, order denying reconsideration, 44 F.E.R.C. 61,302 (1988); Palisades 

Generating Co., 48 F.E.R.C. 61,144 at 61,574 and n.10 (1989).
26

"As a general matter, states have broad powers under state law to direct the 

planning and resource decisions of utilities under their jurisdiction. States may, 

for example, order utilities to build renewable generators themselves or deny 

certification of other types of facilities if state law so permits. They also, 

assuming state law permits, may order utilities to purchase renewable generation.

States also may seek to encourage renewable or other types of resources through 

their tax structure or by giving direct subsidies.47

3. FERC preemption precedent needs clarification and/or adjustment

In several cases, FERC has found that state laws establishing purchase prices for 

wholesale transactions were preempted by the Federal Power Act. These cases do not explicitly 

preclude state-level feed-in tariffs, which are designed as offers. There is, arguably, an essential 

legal boundary between (a) the state ordering the utility to offer to buy at a state-set price and (b) 

the state ordering the utility to enter into a contract at a state-set price. This report argues that 

only the latter are preempted. In the two FERC cases described below, the state attempted to set 

the contract price by requiring the utility to enter into a contract at that price; in neither case did 

the state require the utility merely to offer to buy at a state-specified price. There is, however, no 

FERC precedent affirming this distinction. Until FERC creates that precedent, there will be 

uncertainty about the lawfulness of state feed-in tariffs outside of PURPA, even if those tariffs 

are framed as offers subject to final FERC approval.

a. Connecticut Light & Power: A Connecticut statute required retail utilities to 

purchase electric energy generated by a resource recovery facility, owned or operated by or for 

the benefit of a municipality, at the same rate the utility charges the municipality for retail

electricity. Applying the statute, the Connecticut Department of Public Utility Control (DPUC) 

ordered the utility to enter into a contract at that price. 

FERC viewed the state statute as setting a rate for wholesale sales, thus entering FERC's 

exclusive domain. As FERC stated: "[T]he Municipal Rate Statute at issue here cannot be 

applied to require particular rates for sales from facilities that are not QFs but are sales by public 

utilities at wholesale in interstate commerce because the rates for such sales are subject to 

exclusive Commission jurisdiction."48

By commanding the utility to buy wholesale power at a state-set price, the statute placed 

the utility in an impossible position: it would be unable to comply simultaneously with the rate 

set by the Connecticut DPUC and a different rate set by FERC. This potential for conflict means 

that the FPA must preempt the state statute. 

 47 Southern California Edison Co., 71 FERC para. 61,269 (1995).

48 Conn. Light & Power, 70 FERC para. 61,012 (text accompanying n.60) (emphasis 

added).
27

This potential for conflict disappears if the feed-in tariff is a state-mandated offer to buy 

at the state-approved price rather than a command to enter into a contract at that price. If a 

renewable seller accepts the offered rate and FERC changes the rate in approving the contract, 

the utility does not risk noncompliance with the state requirements. The utility meets its state 

obligation by offering to buy at the state established price; it meets its FERC obligation by 

purchasing at whatever rate FERC approves. This offer approach makes the state-level tariff 

very different from a European-style tariff, however, and constitutes a departure from the 

working definition set forth at the beginning of this report. 

b. Midwest Power Systems: In Midwest Power Systems,

49 FERC considered 

whether the FPA preempted an Iowa statute similar to the Connecticut statute. The statute 

authorized the Iowa Utilities Board to (a) order Iowa electric utilities to enter into contracts to 

purchase electricity from a class of alternative facilities defined by statute and (b) set rates for 

these transactions.

FERC reasoned that the FPA did not preempt a state law ordering utilities to purchase 

from state-designated facilities. As in Connecticut Light & Power, however, FERC held that the 

FPA preempted the Iowa Utilities Board's orders to the extent they set rates for wholesale 

transactions. For the same reasons discussed above, a state-mandated offer, rather than a 

state-mandated transaction, should not be preempted. Neither Connecticut Light & Power nor 

Midwest speaks to this distinction. 

c. Consolidated Edison v. Public Service Commission of New York: In 1981, 

New York passed a law prescribing a minimum purchase price of 6 cents/kWh for electricity 

purchased by utilities from either a PURPA-certified QF, or a state-certified entity. The New 

York Commission ordered ConEd to offer to purchase electric energy from these entities at the 

statutory price. The New York Court of Appeals (the state's highest court) invalidated the 

statute.50 The Court framed the issue as:

"whether Part II of the Federal Power Act (FPA) preempts the [public service 

commission, or PSC] from compelling utilities to offer to purchase power from 

facilities that qualify only under the [state] Public Service Law. This court holds 

that it does."51

According to the Court, the New York Commission offered this reasoning (paraphrased by the 

Court): 

 49 78 FERC para. 61,067 (1997).

50 Consolidated Edison Comp. of New York v. Pub. Serv. Comm. of New York, 63 N.Y.2d 

424, 472 N.E.2d 981 (1984).

51 Consolidated Edison, 63 N.Y. 2d at 438, 472 N.E.2d at 987.
28

"The FPA only concerns regulations of sales and therefore, only the seller. 

Thus... the PSC’s attempt to regulate a utility's purchase rate is merely a 

permissible regulation of the purchaser which Congress intended to leave to the 

States."52

The court rejected the New York Commission's distinction between a purchase and a sale: 

"While facially appealing, the argument distinguishing the admittedly preempted 

regulation of sellers of wholesale electricity (on-site generators) from purchasers 

in the same transactions (the utilities) is upon closer examination, untenable. 

Such a distinction would simply achieve indirectly that which is not permitted 

directly (see Northern Gas Co. v. Kansas Comm., 372 U.S. 84, 91-93). In 

Northern Gas Co., a State's attempt to require interstate pipeline companies to 

purchase gas ratably from local, State wells was rejected as an indirect attempt to 

impermissibly regulate wholesale prices of natural gas in interstate commerce, 

which could seriously impair FERC's ability to regulate in the field.53

It would clarify matters further for FERC to state that a state-mandated offer does not 

"achieve indirectly that which is not permitted directly" because the offer does not limit FERC's 

decision-making discretion. That clarification would reduce uncertainty for those outside New 

York concerned that their state courts might follow the New York court. Clarification also 

would allow New York to reconsider this issue should the question arise again in New York 

courts.

4. Conclusions on the state role in wholesale price-setting

This report has reasoned that a state relying on state law rather than PURPA (and 

therefore bound to take into account the FPA's preemptive intent) can take one of two actions: 

1. The state can require the utility to offer to purchase at a state-set price, but the 

purchase is not executed until the contract is approved by FERC.

2. The state can require the utility to purchase, at a price set by FERC. 

What the state cannot do is require the utility to purchase at a state-set price X, a practice 

common to European-style feed-in tariffs. This third approach compels the utility to take an 

action (purchase at a state-set price) which FERC might forbid (by requiring a different price). 

A common error is to assert that because courts (and FERC) have emphasized the states' 

non-preempted role in guiding utility procurement, that this role includes an opportunity to 

require contracts at particular prices. It does not. Only FERC can set wholesale prices. The 

states can guide utility offers, and they can penalize or reward utility procurement decisions, but 

they cannot command wholesale contracts into existence. Only FERC can allow contracts to go 

 52 Id. at 439, 472 N.E.2d at 987.

53 Id. at 440, 472 N.E.2d at 988.
29

into effect and then only after ensuring that the prices are just and reasonable. As already 

explained, FERC will find a contract price just and reasonable if, in the cost-based setting, the 

price recovers reasonable costs and reasonable profit; and in the market-based setting, if the 

seller has no market power. If a state believes that the FERC treatment leaves the seller with 

insufficient compensation, the state can supplement the price using the techniques described in 

Part I.D above (cash grants, renewable energy credits, tax credits and/or production-based 

incentive payments).

C. In the FPA context, the state can set different sales offer prices for different 

technologies

FPA Sections 205 and 206 require that wholesale rates be just and reasonable and not 

unduly discriminatory or preferential. The statutory concern is discrimination by the seller (not 

the buyer), because the FPA regulates sales (not purchases); its purpose is to protect buyers (not 

sellers). See Public Systems v. FERC, 606 F.2d 973, 979, n.27 (D.C. Cir. 1979) (the Federal 

Power Act is a consumer protection statute). A utility buyer that offers to pay different prices for 

different products does not trigger any statutory concern. FERC will view each seller on its 

individual merits, i.e., whether the price reflects reasonable cost (under cost based pricing); or, 

whether the seller has market power (under market-based pricing). Since costs differ among 

technologies, it is natural to have different prices in the cost-based pricing world. There is 

nothing new here; generating plants based on gas, coal and nuclear sell at different prices when 

they sell under the cost-based rate regime.

D. Once states establish feed-in tariffs, sellers still must obtain FERC 

permission to sell

If one views the state-level feed-in tariff as the utility's offer to buy at the state-set price, 

the seller must take certain actions to convert that offer into a transaction that complies with the 

Federal Power Act. There can be no sale at wholesale without FERC approval. Under present 

FERC practices, there are two distinct paths available to the seller: contract-by-contract 

approval and blanket advance approval.
30

1. Contract-by-contract approval (cost-based rates)

Under this approach, the seller executes a service agreement with the buying utility, and 

then submits that agreement to FERC for approval. (The form of the service agreement could be 

part of the standard tariff.) For these agreements, FERC usually examines whether the rate 

reflects prudent costs and a reasonable rate of return. The seller must supply its cost information 

publicly. FERC issues a public notice of the seller's application. If there is no opposing 

intervenor, approval occurs within a few months. If there is opposition, the proceeding could 

involve either paper proceedings (parties file comments) or formal hearings before an 

administrative law judge (witnesses file testimony and appear for cross-examination) at FERC's 

discretion. These proceedings can take up to a year or more, during which time FERC can 

authorize sales to occur at the initially proposed price, but that are subject to refund should 

FERC ultimately order a lower price. 

2. Blanket advance approval (market-based rates)

FERC will grant a seller advance approval to sell at any price it can negotiate, without 

the need for contract-by-contract review, if the seller proves that it lacks "market power" or that 

it has adequately "mitigated" any market power it does have.54 FERC reasons that the absence 

of market power means that competitive forces will keep rates just and reasonable and not 

unduly discriminatory as required by the FPA.55 A seller that obtains this blanket approval does 

not need FERC permission for each contract. 

To obtain approval, the seller must submit a technical analysis addressing multiple FERC 

"screening" tests.56 The seller has the burden of proof. The generation market power test, for 

example, requires a seller to pass two screens. The “pivotal supplier screen” assesses whether 

the supplier controls an amount of capacity that is "pivotal"—indispensable to the market—

because it exceeds the difference between the market's available capacity and the market's 

demand. A supplier who controls indispensable capacity could raise and sustain its price above 

just and reasonable levels; that is why it would fail this screen. A seller fails the “market share 

screen” if its share of total market capacity exceeds 20 percent.57

 54 FERC has defined market power as a seller's ability to "significantly influence price in 

the market by withholding service and excluding competitors for a significant period of time." 

 An applicant seller that fails 

Citizens Power & Light Corp., 48 FERC 61,210 at 61,777 (1989) (granting approval to power 

marketer for market based rates).

55 California v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004) (finding that market based 

rates are lawful, based on prior finding of lack of market power and post-approval reporting 

requirements).

56 18 C.F.R. 35.37.

57 18 C.F.R. 35.37(a)(2).
31

either screen can offer alternative evidence that it lacks market power. A seller that received 

market pricing approval (after passing the screens) must submit a new market test every three 

years, along with other reports that enable FERC to verify that no factual changes have caused 

the seller to gain market power. 

Even small sellers can have market power, if for example, (a) the geographic market is 

constrained because of transmission shortages (meaning buyers have limited access to alternative 

supplies) and/or (b) the state's tariff has defined the product so narrowly that the seller has a high 

market share or is "pivotal." If the seller has market power, FERC will deny blanket approval. 

The seller still can sell, but its price will be subject to FERC's cost-based pricing review 

procedures on a contract-by-contract basis. FERC will cap the price—either on a cost basis or at 

the level FERC believes is the proper market price. 

While a detailed description of FERC's market power tests falls outside the scope of this 

report, policymakers should be alert to a number of uncertainties for renewable sellers. First, 

where the state sets the offer price without regard to competitive forces, opponents can argue that 

the price fails the FPA’s just and reasonable requirement. (For that reason, some have proposed 

competitive bidding procedures as a way to establish the feed-in tariff prices.) Second, consider 

a state-set tariff requiring the utility to offer different prices for different power sources. It is not 

clear how FERC will define the "market" for purposes of determining whether a seller has 

market power. If FERC uses a narrow tariff definition of the product (e.g., “solar power” as 

opposed to “all power”), and if there are few sellers willing and able to sell solar, the screening 

tests could cause a failure for the solar seller seeking blanket permission to sell at market-based 

rates.

Here is a variation on the same problem: Assume the state commission has declared that 

the retail utility must purchase a specified quantity of wind power by a specified date. Suppose 

further that this mandatory purchase quantity exceeds the available supply. That fact means that 

each supplier is indispensable to the state's goals. An indispensable supplier is a supplier with 

market power. FERC thus will be concerned about the reasonableness of the price. It is true that 

the state commission will have constrained the seller's market power by fixing the offer price 

(rather than having allowed the seller to extract a higher price by withholding its supply). But,

the state-set offer price itself could exceed the price that would prevail if there were surplus 

supply because the state would have set the price high enough to attract the limited number of 

willing sellers. In this context, FERC could find market power and thus disapprove the sale 

price even though the state commission was willing to have its consumers pay the price.

One more complicating factor: Some states with renewable purchase obligations allow 

the utility to make an “alternative compliance payment” (ACP) in lieu of purchasing from a 

renewable seller.58

 58 See Part I.D.1 above for an explanation of “alternative compliance payment.”

 Before FERC makes a finding of seller market power, it would need to take 

into account the price-disciplining effect of the buyer’s option. The seller will not be able to 

raise its price above the ACP level and still make a sale.
32

This uncertainty about the lawfulness of the sales price raises this question: are there 

other ways to ensure the justness and reasonableness of market prices in the context of statemandated feed-in tariffs? One possibility is for FERC to consider cost-based safe harbors, 

presumptions, or other guidance as a way to clarify the circumstances under which renewable 

sellers can sell. See Part II.F below.

3. Supplemental compensation from the state

A seller whose application to FERC (either for cost-based prices or market-based prices) 

is rejected must limit its price to the FERC-approved cost-based price. If this compensation is 

insufficient, the seller could seek from the state any of the types of supplemental compensation 

described in the PURPA discussion at Part I.D above (i.e., cash grants, RECs, tax credits for the 

purchasing utility, or production-based incentive payments). The same FERC reasoning that 

allowed these supplements in addition to avoided cost (because the supplements are not 

“controlled by PURPA,” see American Ref-Fuels above) should apply in this FPA context as 

well. Because FERC has not expressly established that the PURPA mechanisms described in 

Part I.D are available under the FPA, states and practitioners should consider asking FERC to 

confirm this point.

4. Must the seller in a state law-based regime still comply with PURPA's 

avoided cost cap?

This subsection argues that when the utility's purchase obligation arises from state law 

rather than PURPA, PURPA's avoided cost cap does not apply because PURPA does not apply. 

FERC precedent, however, is at odds with this conclusion. After discussing the arguments for, 

and FERC’s precedents against, this conclusion, the authors of this report suggest ways for 

FERC to re-interpret or modify its precedent to facilitate state-level tariffs. If FERC maintains 

its precedents, states still can grant sellers compensation exceeding avoided cost through the 

means described in Part I.D above (although FERC clarification would be useful on this point).

a. Alternative interpretation: PURPA language does not support the application 

of the avoided cost cap to a state-law based, non-PURPA regime: However, FERC precedent 

does not agree with this alternative interpretation. Section 210(b)(1) of PURPA, 16 U.S.C. sec. 

824a-3(b)(1), states (emphasis added): 

"The rules prescribed under subsection (a) [requiring utilities to purchase from 

QFs] shall insure that in requiring any electric utility to offer to purchase electric 

energy from any [QF], the rates for such purchase shall be just and reasonable...."

. . . 

"No such rule prescribed under subsection (a) shall provide for a rate which 

exceeds the incremental cost to the electric utility of alternative electric energy.”
33

The italicized language indicates that the prohibition against above-avoided cost rates applies to 

prices set pursuant to the mandate of "subsection (a)", i.e., Section 210(a) of PURPA. That 

provision requires FERC to issue rules requiring utilities to buy from QFs. When the "requiring" 

law is not PURPA, i.e., when the requirement flows from state law, the language, by its terms, 

does not apply. 

That an entity happens to be a QF does not affect this reasoning provided that the utility’s 

obligation to buy comes from state law rather than PURPA. Nothing in PURPA’s statutory 

language or history conflicts with this conclusion or suggests that an entity's QF status deprives 

it of non-PURPA, state law privileges. But, FERC precedent comes to the opposite conclusion, 

as discussed next. 

b. FERC's precedent: Connecticut Light & Power Co., 70 FERC para. 61,012 

(1995), order denying reconsideration, 71 FERC para. 61,035 (1995), involved a state statute 

requiring utilities to buy power from municipal resource recovery facilities “at the same rate that 

the utility charges the municipality for electricity.”

Addressing the utility's challenge to the statute, FERC found that when the seller is not a 

QF, the FPA preempts on the grounds that the statute sets wholesale rates, which is FERC's 

exclusive domain.59 And if the seller is a QF, FERC reasoned, PURPA preempts to the extent 

the statute authorizes rates above avoided costs. FERC then confronted directly the question 

whether a state law that required utility purchases independent of PURPA could authorize prices 

above avoided cost:

"We recognize that the Commission seems to have suggested, in 1980, in the 

preamble to its regulations, that, notwithstanding PURPA's clear mandate, the 

states could exercise state authority independent of PURPA to impose a rate 

exceeding avoided cost:"

The Commission then quoted two paragraphs from that 1980 Preamble:

"The Commission has become aware that several States have enacted legislation 

requiring electric utilities in that State to purchase the electrical output of 

facilities which may be qualifying facilities under the Commission's rules at rates 

which may differ from the rates required under the Commission's rules 

implementing section 210 of PURPA."

"The Commission has set the rate for purchases at a level which it believes 

appropriate to encourage cogeneration and small power production, as required 

by section 210 of PURPA. While the rules prescribed under section 210 of 

PURPA are subject to the statutory parameters, the States are free, under their 

own authority, to enact laws or regulations providing for rates which would result 

 59 Part II.B.3 discussed this aspect of the case.
34

in even greater encouragement of these technologies. However, State laws or 

regulations which would provide rates lower than the federal standards would fail 

to provide the requisite encouragement of these technologies, and must yield to 

federal law. If a State program were to provide that electric utilities must 

purchase power from certain types of facilities, among which are included 

"qualifying facilities," at a rate higher than that provided by these rules, a 

qualifying facility might seek to obtain the benefits of that State program. In such 

a case, however, the higher rates would be based on State authority to establish 

such rates, and not on the Commission's rules."60

FERC then, in its CL&P order (at n.45) distanced itself from its 1980 statements:

"This [Preamble] language is, in fact, ambiguous. First, as the Commission 

expressly acknowledged, the ability of a QF to obtain rates in excess of avoided 

cost depends on the state's authority independent of PURPA and this 

Commission's regulations to set such rates. This language leaves unaddressed and 

undecided whether and when states may, in fact, have authority to set such rates. 

Second, in language that immediately precedes the language quoted above, the 

Commission explained that section 210(b) of PURPA provides that "in requiring 

any electric utility to purchase electric energy from a [QF], the Commission must 

ensure that the rates. . . not exceed the incremental cost of alternative electric 

energy (the costs of energy to the utility, which, but for the purchase, the utility 

would generate itself or purchase from other source)." Id. There is obvious 

inconsistency in the Commission seemingly simultaneously deciding that states 

both may (in the language quoted in the text) and may not (in the immediately 

preceding language) require rates in excess of avoided cost." 

FERC then added (at text accompanying n.46): 

"However, the Commission did not provide any rationale to support this statement 

or any legal analysis. We cannot ascertain at this date any legal basis under 

which states have independent authority to prescribe rates for sales by QFs at 

wholesale that exceed the avoided cost cap contained in PURPA. Moreover, for 

states to mandate rates above avoided cost for a particular class of power 

suppliers (i.e., QFs) also runs counter to Congress' and the Commission's current 

policies which strongly favor competition among all bulk power suppliers." 

In other words, in Connecticut, FERC clearly stated that a state law could not require utilities to 

purchase wholesale power at prices above avoided costs, even if that state requirement was 

established independent of PURPA.

In Midwest Power Systems, Inc., 78 FERC para. 61,067 (1997), FERC followed its

Connecticut Light & Power decision. An Iowa statute required utilities to purchase power from 

 60 FERC Stats. & Regs., Regulations Preambles 1977-1981 at 30,875. 
35

state-defined "alternate energy production facilities," at rates set by the Iowa Board. The statute 

stated that the facilities could be either QFs or non-QFs. The Iowa Board ordered a utility to 

enter into contracts with two wind suppliers at rates in excess of the utility’s avoided cost. The 

two wind suppliers were not QFs; they had neither self-certified as QFs nor sought QF 

certification from FERC. FERC found that PURPA did not preempt the state from enacting laws 

to compel utilities to purchase from renewable suppliers. But as in Connecticut Light & Power, 

"the orders of the Iowa Board are preempted to the extent that they require rates to QFs in excess 

of the purchasing utilities' avoided cost, and to the extent that they set rates for the wholesale 

sales of electric energy by public utilities."

The Commission continued:

"We do not agree with the intervenors' efforts to distinguish the Connecticut case 

from the instant case on the basis that the Iowa statute was adopted independently 

of PURPA. The conclusions reached in the Connecticut case are not dependent 

on whether the facilities are QFs or whether the state is invoking its obligations 

under PURPA. Even if the alternative facilities at issue are not QFs, the orders of 

the Iowa Board implementing the Iowa statute are preempted by federal law to the 

extent they set rates for wholesale sales by public utilities of electric energy in 

interstate commerce."

The last sentence of this passage implies that in the case of a state mandate based on state law, 

the preempting statute is the FPA (which addresses "rates for wholesale sales by public utilities 

of electric energy in interstate commerce"). However, elsewhere in Midwest, FERC finds that

PURPA applies and preempts a price exceeding avoided cost, in the case of a state statute

mandating the purchase. 

If a state’s utilities have received a FERC exemption from their PURPA purchase 

obligation, could there still be a PURPA avoided cap on a state-mandated offer? Where 

FERC has exempted a utility from its PURPA purchase obligation (as discussed at Part I.C 

above), a state seeking to implement feed-in tariffs will need to turn to its own statutory 

authority to mandate utility purchases.

61

 61 Recall from Part I.C that FERC regulations allow the QF to “tag” utilities other than 

the QF’s host utility with a PURPA purchase obligation, should that host utility have received a 

FERC exemption from the purchase obligation. The paragraph in the text assumes that a state 

has determined that these remaining QF options are insufficient outlets to produce the desired 

amount of renewable energy. 

 At the same time, some entities eligible to sell under 

these state feed-in tariff programs might want to retain QF status so as to obtain 

PURPA-mandated interconnection rights (if they viewed these rights as preferable to the 

interconnection rights available under the FPA), or to avoid FPA price regulation (as explained 

in the next subsection, FERC has exempted QFs 20 MW and below from price regulation under 

FPA Sections 205 and 206). In these situations, i.e., where there is no PURPA utility purchase 

obligation, FERC’s CL&P and Midwest precedents, (i.e., applying PURPA’s avoided cap even 

when the purchase obligation comes from state law) should not apply. However, FERC has not 
36

addressed this question in the context of a utility exempted from the PURPA purchase 

obligation. It would be useful if FERC clarified that its CL&P and Midwest precedents do not 

apply to QF sales to utilities under state law where FERC has exempted the utility from its 

PURPA purchase obligation. This clarification would ensure that states could set offer prices 

exceeding avoided cost. However, the seller still would have to obtain FERC permission under 

the FPA. 

E. Exemptions from FPA review for QFs sized 20 MW and below if FERC 

clarifies and/or adjusts its precedent

PURPA directed FERC to prescribe rules under which QFs are “exempted in whole or 

part from the Federal Power Act” if FERC determines such exemption is necessary to encourage 

cogeneration and small power production. 16 U.S.C. 824a-3(e). In Order No. 697-A,62

“All sales of energy or capacity made by QFs 20 MW or smaller are exempt from 

section 205. Sales from a QF larger than 20 MW are exempt from section 205 

only if those sales are made pursuant to a state regulatory authority’s 

implementation of PURPA, or if those sales are made pursuant to a contract 

executed on or before March 17, 2006 (unless the sale is from a qualifying small 

power production facility with a power production capacity which exceeds 30 

MW, if such facility uses any primary energy source other than geothermal 

resources, in which case the sale is not exempt).”

FERC 

described the circumstances under which QF sales are exempt from Section 205:

63

If FERC adjusts its precedents, QFs 20 MW and below could sell under state feed-in 

tariffs free of FPA review: If FPA Sections 205 and 206 do not apply to sales by QFs sized 20 

MW and below, states should be able to create feed-in tariffs (framed as offers to buy and rooted 

in state law rather than PURPA) for these sellers, where no seller need obtain contract approval 

from FERC or comply with PURPA’s avoided cost cap. This result would make the state feed-in 

tariff like the European-style model—where the transaction can occur by virtue of the tariff 

alone, without any further regulatory approval. 

 62 Market Based Rates For Wholesale Sales Of Electric Energy, Capacity And Ancillary 

Services By Public Utilities, Order No. 697, 119 FERC 61,295 (Jun. 21, 2007), order on 

rehearing and clarification, Order No. 697A, 123 FERC 61,055, 2008 FERC LEXIS 788 at 

*548 (Apr. 21, 2008)(describing exemptions from Section 205 in the context of explaining 

process by which QFs can seek market based rates); Revised Regulations Governing Small 

Power Production and Cogeneration Facilities, Order No. 671, 115 FERC 61,097, order on 

rehearing, Order No. 671-A, 115 FERC 61,225 (2006) at text and n.17 (explaining that “20 MW 

threshold strikes a reasonable balance by protecting the smallest facilities while ensuring that 

sales by larger QFs are subject to Commission oversight” and further, is consistent with the

20 MW size limit for small generating facilities found in Order No. 2006 (Standardization of 

Small Generator Interconnection Agreements and Procedures)).

63 Order 697-A is codified in FERC regulations as 18 C.F.R. 292.601. See Appendix B.
37

The foregoing analysis faces real uncertainty, however, because of the FERC’s

Connecticut Light & Power and Midwest Power cases. Those cases, as explained above, hold 

that if an entity has QF status, FERC will apply PURPA's avoided cost cap even if the utility's 

obligation to purchase arises from state law rather than PURPA. It would be helpful for FERC 

to clarify whether QF status caps the utility’s purchase obligation at the avoided cost when the 

purchase obligation is a state law obligation rather than a PURPA obligation. A finding of no 

cap, in the context of a state law mandate, would be logical because it would put the QF in the 

same position as non-QFs in terms of ability to sell outside of PURPA (i.e., being free from the 

avoided cost constraint). 

F. Safe Harbors, Presumptions and other Forms of Guidance: FERC can 

facilitate sellers' compliance with the Federal Power Act

State commissions and sellers will find the FPA requirements inconsistent with a 

European-style tariff in which the tariff alone both invites and consummates a transaction 

without the need for further regulatory review. Part II.A above explained that the FPA requires 

the price of all wholesale sales to be "just and reasonable." In FERC's cost-based practices, a 

just and reasonable rate is one that allows recovery of prudent costs plus a reasonable return. In 

FERC's market-based rate practices, a just and reasonable rate is any rate charged by a seller that 

FERC has determined lacks market power. This subsection discusses ways to modify current 

FPA procedures so that state-level feed-in tariffs resemble the European model more.

Based on an investigation of cost parameters, FERC could establish safe harbors, 

rebuttable presumptions, or other forms of guidance such that state-mandated offer prices 

consistent with these pronouncements would constitute "just and reasonable" prices for the 

defined products, project sizes, and geographic regions. FERC then would issue a rule stating 

that a wholesale sale under a state-set tariff consistent with those safe harbors and other guidance 

automatically complies with the FPA. 

Because costs will vary by regions, will change over time, and will vary by scale, 

ownership and other factors, it is worth considering several possible processes by which FERC 

could establish these guidelines. One approach would be for individual states to seek a FERC 

ruling declaring that their state’s proposed tariff prices to be just and reasonable, thereby 

relieving sellers of an obligation to seek FERC approval of contracts entered into under those 

tariffs. Another approach would be for FERC to establish prices for a particular region if there 

was a commonality of cost experience within that region.

If designed well, the FERC safe harbors and guidance would not be preemptive of state 

efforts. Either approach would obviate contract-by-contract approvals under the FERC’s 

cost-based rate procedures as well as market power screening under FERC’s market-based rate 

procedures. States would be free to establish higher prices for utility offers (provided they were 

offers, not commands to enter into contracts—see Part II.B above), subject to the seller's 

obligation to seek FERC approval for the resulting contract. Some routine filings by the seller 
38

still might be necessary to comply with the 1935-era filing provisions of the Federal Power Act, 

but the filing requirements could be minimal. 

Some might question this approach on the grounds that renewable prices exceeding

generic market prices are inherently unjust and unreasonable. In other words, some might argue 

that the pricing does not comport with FERC precedent for determining just and reasonable 

pricing because it would neither be the result of competitive market forces nor be based on a 

contract-by-contract review of costs. One response is as follows: In the context of cost-based 

regulation, FERC sets prices based on reasonable cost. That a nuclear power plant’s embedded 

cost exceeds that of a natural gas plant does not make the former’s wholesale price unreasonable. 

The same reasoning applies to a situation in which renewable seller’s price exceeds that of a 

non-renewable seller. As long as the price for the given product is based on its reasonable cost, 

that product's higher price compared to other higher-cost products is not fatal to its lawfulness. 

FERC presently has two distinct pricing regimes: cost-based and market-based. While 

evaluation of market prices takes into account cost-based benchmarks and vice versa, FERC has 

never said that one type of benchmark is binding on the other. Very different prices for 

electricity co-exist today, all under the “just and reasonable” umbrella. Further, even if FERC 

were to find particular price levels unjust and unreasonable, the state can limit the required 

purchase payment price to the FERC-determined just and reasonable level and then supplement 

that price with state-jurisdictional cash payments, RECs, tax credits or performance-based 

incentive payments (as discussed in the PURPA context in Part I.D above, which should be 

applicable in the FPA context, as described in Part II. D. 3.).

Because there is no recent FERC experience with this type of approach, an administrative 

inquiry and rulemaking process would be necessary.64 From a procedural perspective, 

consideration of this safe harbor/rebuttable presumption approach can be initiated by:

1. FERC—who would initiate a rulemaking proceeding aimed at declaring safe 

harbor price ranges for various sizes, technologies and geographic areas;

2. A renewable seller or group of sellers—who would submit a request for a 

FERC determination of safe harbor prices; or

3. A state commission or group of state commissions—who would petition FERC 

to (a) initiate a generic proceeding on safe harbors for the nation, a region, or a 

group of utilities within a particular state and (b) find that a specified set of prices 

for sales from particular types of projects to utilities satisfy FERC's standards for 

either cost-based pricing or market-based pricing.

 64 In another era, FERC’s predecessor, the Federal Power Commission, seeking to 

reduce the delays and workload associated with setting rates company by company, established 

“area rates” for natural gas sales by producers. A producer located in a particular area could sell 

at those rates without having to demonstrate that its costs justified the rates. Legal challenges to 

the FPC’s approach took many years and culminated in a U.S. Supreme Court decision 

upholding the FPC’s authority. See Permian Basin Area Rate Cases, 390 U.S. 747 (1968).
39

In addition to establishing cost-based safe harbors, it would be helpful to renewable 

energy developers and state policy makers for FERC to clarify how its market power tests would 

apply to renewable generators under various circumstances. The types of questions that can 

arise include: 

1. How will FERC determine the product market boundaries when a state has 

mandated utility purchases of specific quantities of specific types of power (e.g. 

solar, wind, hydroelectric)?

2. Will FERC view state-authorized "alternative compliance payments" as 

disciplines on the market prices?

3. How will FERC determine geographic market boundaries for different types of 

renewable sellers?

4. Where a seller fails one or both of the market power screens (e.g., pivotal supplier 

test and market share test), what mitigation actions will FERC require or 

authorize?

Figure 1 provides a single-page summary of the existing path for non-preemption under 

PURPA and the path for non-preemption under state law (if FERC changes existing precedent).
40

Figure 1. Can a state order its utilities to file “feed-in tariffs”? Two paths to non-preemption
41

III. Amendments to Current Federal Statutes

Up to this point, this report has discussed current federal law: the conditions under which 

it prevents states from promulgating feed-in tariffs that, by themselves and without any federal 

review, could entitle sellers to sell wholesale renewable power at rates sufficiently high to attract 

state-desired technologies. Part III looks at possible amendments to federal law that would 

achieve this objective.65 First, a provision in the American Clean Energy and Security Act is 

addressed as passed by the U.S. House of Representatives in June 2009. Then, four conceptual 

legislative options are discussed that could clarify the role of renewable energy feed-in tariffs in 

the United States.

A. The House-Passed American Clean Energy and Security Act

On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy 

and Security Act.66 Section 102, entitled "Clarifying State Authority to Adopt Renewable 

Energy Incentives," drafted as an amendment to PURPA, provides: 

"Notwithstanding any other provision of this Act [PURPA] or the Federal Power 

Act, a State legislature or regulatory authority may set the rates for a sale of 

electric energy by a facility generating electric energy from renewable energy 

sources pursuant to a State-approved production incentive program under which 

the facility voluntarily sells electric energy. For purposes of this subsection, 

State-approved production incentive program means a requirement imposed 

pursuant to State law, or by a State regulatory authority acting within its authority 

under State law, that an electric utility purchase renewable energy (as defined in 

section 609 of this Act) at a specified rate."67 

The Energy and Commerce Committee's section-by-section summary explains that the 

proposed language is meant to remove a perceived barrier to implementing feed-in tariff and 

production incentive programs:

"[N]otwithstanding any provision to the contrary in [PURPA], any state may 

establish rates to be paid by state-regulated utilities intended to provide incentives 

 65 The authors of this report do not necessarily support these amendments or their 

underlying purpose. Our assignment is to analyze the terrain, not advocate for an outcome. 

66 American Clean Energy and Security Act, H.R. 2454, 111th Cong. (2009) available at 

http://www.govtrack.us/congress/billtext.xpd?bill=h111-2454 (last visited November 29, 2009). 

67 Section 609 of PURPA defines renewable energy as including: wind; ocean waves; 

biomass; solar; landfill gas; incremental hydropower; livestock methane; or, geothermal energy. 

Section 609 is codified at 7 U.S.C. 918c(a)(3)(4) (relating to issuance of rural and remote 

communities electrification grants).
42

for development of renewable energy. In the past, some have interpreted PURPA 

to bar such incentive rates to the extent they exceed the avoided cost of power a 

utility could generate or procure from any other source, denying states the ability 

to account for the additional benefits of renewable energy.”68

Therefore, it appears that the goal of this provision is to eliminate the PURPA and FPA 

preemptive effects discussed in this report. However, there is need for care and additional 

clarification in interpreting this provision's effect on each of the two statutes. Specifically: 

PURPA: The proposed language had not adequately addressed PURPA’s two main 

features: its utility obligation to purchase and its avoided cost cap. While it is clear that the 

proposed language would free states to set prices above avoided cost, it is not clear whether the 

purchase mandate accompanying those prices would be a PURPA mandate or a state law 

mandate. It appears, at the least, that the provision would allow a state to establish a state law 

purchase mandate and set prices above avoided cost—a result that would overrule Connecticut 

Light & Power and Midwest Energy. (Recall that Part II.B.3 above expressed concern that 

FERC appeared to bar, on PURPA preemption grounds, state-set offer prices grounded in state 

law rather than PURPA).

FPA: If the provision’s intent is to free the seller from the FPA as well as from PURPA,

it is not clear it has achieved this goal. To do so, it would allow states to set rates for wholesale 

sales by renewable energy facilities, an activity that the FPA currently vests in FERC 

exclusively. A seller under a state program would not need to seek FERC permission to sell, 

whether at cost-based prices or at market prices. The seller would be free, rather, to enter into 

any arrangement at any price. A state then can design a feed-in tariff like a European tariff, 

where the tariff itself, without any further regulatory action, creates simultaneously a utility duty 

to buy and a seller right to sell. It is not clear from the language whether the sellers would have 

to place their contracts—with the state-set rates—on file at FERC, as is required today of 

wholesale sales by entities that have not received market-based rate authority. 

The language, in short, does not make clear whether the provision intends to (a) exempt 

the seller from having to comply with either federal statute in any way or, alternatively, (b) 

maintain the seller's obligation to comply with the statute but free the state to set the prices 

without preemption.

 68 Committee on Energy and Commerce, 111th Cong., The American Clean Energy and 

Security Act (H.R. 2454): Section-By-Section (Jul. 14, 2009) available at http://energycommerce

.house.gov/Press_111/20090720/hr2454_sections mmary.pdf.
43

B. Four Conceptual Federal Legislative Options

Four major categories of federal legislative action could provide, to varying degrees, 

additional clarity regarding the implementation of feed-in tariffs at the state level. Critically, 

more than one legislative option could be implemented simultaneously. Each of these categories 

of action presents opportunities but involves limitations. Congress could:

1. (a) Maintain the present PURPA features of the retail utility's obligation to buy under 

PURPA and the state's obligation to set the PURPA prices but (b) lift the avoided cost cap for 

specified renewable technologies and sizes. Under a variation of this approach, Congress could 

reverse its EPAct 2005 amendment, which authorized FERC to exempt utilities from their 

purchase obligation upon a finding that QFs had competitive market options. (See Part I.C 

above).

2. Maintain renewable sellers' obligation to comply with all FPA contract-submission 

requirements (for non-QFs, operating outside of PURPA) but also provide that rates established 

by states pursuant to state-level feed-in tariffs (or production incentives) are deemed to satisfy 

the just and reasonable requirement.

3. Exempt renewable sellers (non-QFs, operating outside of PURPA) from the FPA 

entirely (meaning, no filing requirements, no rate approval requirements) for sales made 

pursuant to state-established, feed-in tariff programs.

4. Authorize (or direct) FERC to act in the three manners described above, under defined 

circumstances. Congress would spell out FERC's range of discretion or obligation.

In each of these alternatives, Congress could fine-tune its amendment by (a) specifying 

certain technologies, sizes, and quantities, (b) by capping the prices (or authorizing FERC to), or 

(c) by specifying a sunset date.
44

IV. Related Questions

In the course of peer review of this report, several questions arose that apply generally, 

and thus do not have a specific logical place in the document. These are discussed below.

A. What price-setting methods are available to state designers of feed-in tariffs?

Designers of feed in tariffs must answer this question: What price will attract renewable 

energy sellers at a desired quantity and diversity? There are a number of pricing options,

69

including: (a) cost-based (the price recovers the typical cost of the technology at issue plus a 

reasonable profit); (b) value-based (the price reflects the value placed by the state's citizens on 

the power, where "value" can reflect the benefits of a cleaner environment, and/or a diverse 

power supply, among other objectives); and (c) market-based (the price is based on a 

competition among similar projects). There also are hybrid approaches, such as allowing rates to 

fluctuate with market prices subject to price floors, price ceilings or both, so as to increase 

revenue certainty for project owners sufficient to attract financing. Each of these options has the 

potential to exceed the utility's avoided cost (as required by PURPA) and/or the FERC's view of 

"just and reasonable” (as required by the Federal Power Act). It is the potential for this 

deviation—between the state-desired rate and the rate required by one or both federal laws—that 

requires care in addressing the intersection between state and federal law. 

What about market-based auctions and other forms of competitive bidding? In the 

context of renewable energy policy, auctions and bidding play two possible roles. One role is to 

determine winners: who gets to sell to the utility. A state could use this "select-the-winner" 

approach to pick suppliers under a renewable portfolio regime. This approach differs from a 

feed-in tariff, which does not select winners; in a European-style feed-in tariff, every eligible 

entity has a right to sell. The second role is to determine price: The auction or bidding process 

discovers a price that otherwise would be set administratively. This price then can become the 

price used in a feed-in tariff. Analysis of the advantages and disadvantages of these options lies 

outside this report's scope. Under either option, the same jurisdictional questions and constraints 

arise: PURPA and the FPA play the same roles regardless of the price-setting method used. 

B. Does the applicability of the FPA or PURPA change if the seller's delivery to 

the buyer occurs at a distribution facility rather than a transmission facility?

The answer is "no." FERC's wholesale sales jurisdiction does not vary with the facility 

over which the transaction occurs. 

The FPA grants FERC exclusive jurisdiction over wholesale sales, even if those sales 

occur within the same state (except for Alaska, Hawaii and most of Texas). Wholesale sales are 

sales for resale. "Wholesale" is a commercial concept, not a physical concept. Wholesale sales 

 69 As described in Grace, Robert, W. Rickerson, K. Porter, J. DeCesaro, K. Corfee, M. 

Wingate and J. Lesser (KEMA), Exploring Feed-in Tariffs for California. California Energy 

Commission. Publication number: CEC-300-2008-003-F (November 2008).
45

can take place over distribution systems exclusively, transmission systems exclusively, or both.70

As with the wholesale transactions under the FPA, the application of PURPA does not 

differ with whether the transaction occurs over distribution or transmission facilities. 

C. Do the federal statutes apply to renewable sales to retail customers?

Retail electricity sales trigger none of the issues discussed in this report. The federal law 

constraints addressed here apply only to wholesale transactions. Retail transactions fall outside 

both federal statutes. States are free to establish programs allowing renewable generators to sell 

to retail customers. (These programs are not like the feed-in tariffs addressed in this report, 

because they do not create any obligation in the retail customer to buy from the generator). This 

state freedom includes the situation where a non-utility (e.g., 3rd party system owner) sells power 

to a retail customer who is a participant in a net metering program. The retail customer's 

purchases from the non-utility seller cause the retail customer's meter to "run backwards," 

reducing his purchases from the utility. Provided there is no "net sale" during a billing cycle (a 

net sale would occur if the retail customer's purchases from the non-utility exceed the customer's 

usage during a billing cycle), FERC will treat the non-utility generator as making only retail 

sales, not wholesale sales; thus the FPA will not apply. FERC explained this reasoning in its 

Declaratory Order in SunEdison, 129 FERC para. 61,146 (Nov. 19, 2009).

 70 See DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005) (noting that wholesale 

sales can take place over distribution facilities). 

For readers interested in even more Federal Power Act detail, FERC’s Order No. 888 

established a seven-part test for determining whether facilities are transmission or distribution. 

The seven factors are: (1) Local distribution facilities are normally in close proximity to retail 

customers; (2) Local distribution facilities are primarily radial in character; (3) Power flows into 

local distribution systems; it rarely, if ever, flows out; (4) When power enters a local distribution 

system, it is not reconsigned or transported on to some other market; (5) Power entering a local 

distribution system is consumed in a comparatively restricted geographical area; (6) Meters are 

based at the transmission/local distribution interface to measure flows in the local distribution 

system; and (7) Local distribution systems will be of reduced voltage. Promoting Wholesale 

Competition Through Open Access Non-Discriminatory Transmission Services by Public 

Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 

888, FERC Stats. & Regs. ¶ 31,036 at 31,981 (1996), order on reh’g, Order No. 888-A, FERC 

Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on 

reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission 

Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. 

FERC, 535 U.S. 1 (2002).
46

Conclusions

Not surprisingly, statutes enacted in 1935 (FPA) and 1978 (PURPA) do not apply neatly 

to market situations and feed-in tariff policy proposals in 2010. This report has described the 

complexities and uncertainties, and it has proposed options for their revision. 

States seeking to mandate utility purchases of renewable power through a feed-in tariff 

can rely on PURPA or, provided FERC clarifies certain precedents, on state law. Each approach 

faces constraints arising from federal law; each approach has alternative paths. 

States that rely on PURPA have a clear, non-preempted path for implementing feed-in 

tariff policies. They can craft a two-part payment where (1) power is paid for at the utility’s 

avoided cost and where (2) additional payment is made through supplemental means (cash 

grants, RECs, tax credits and/or production-based incentive payments). States that rely on the 

FPA may also be able to rely on this two-part payment approach, although FERC has not rules 

on the legality of that approach. Importantly, this option is only available to certified QFs (which 

have the option of self-certifying with FERC).

States that rely on state law (and are subject to the FPA) require FERC clarification of

certain precedents before a clear, non-preempted path for feed-in tariff policies is available. A 

change in FERC precedent could clarify that state-law utility obligations to purchase renewable 

energy from entities with QF status (20 MW or smaller) are not subject to the PURPA avoided 

cost cap or subject to FPA filing requirements. If changed, this clarification would allow statelaw feed-in tariff programs similar to those found in Europe: states could mandate utilities to 

purchase renewable energy at payments higher than utility avoided cost from entities with QF

status (20 MW or below) without additional steps or actions. Without a change in existing 

FERC precedents, the only options that exist are to apply to FERC for (1) contract-by-contract 

approval that the rate reflects prudent costs and a reasonable rate of return (i.e. cost-based rates), 

or (2) blanket advance approval for sellers that lack or mitigate market power (i.e. market-based 

rates).

Because of the multiple legal uncertainties discussed in this report, participants in this 

policymaking area should consider discussing with FERC informal steps leading to a rulemaking 

proceeding. Those seeking this action would identify their goals, explain the legal uncertainties 

impeding those goals, and offer suggestions for removing the uncertainties. A useful outcome to 

this process would be a series of FERC pronouncements that: 

(a) Clarify the law on PURPA preemption and FPA preemption in the various feed-in 

tariff scenarios discussed in this report; 

(b) Create processes for establishing cost-based safe harbors for various technologies, 

project sizes, and geographic areas, where these safe harbors applied in both the PURPA and 

FPA context;
47

(c) Create a process by which sellers under feed-in tariffs could obtain findings of no 

market power; and 

(d) Evaluate the effects of these modifications after several years.

There are multiple procedural paths to such a FERC rule: workshops, notices of inquiry, 

notices of proposed rulemaking, and requests for declaratory orders on generic issues or on statespecific or region-specific tariffs. An informal set of conversations on the multiple questions 

raised by this report would be a useful start.

Finally, Congress always has the authority to revise federal law. While the language in 

the House-passed American Clean Energy and Security Act of 2009 (see Part III.A above) leaves 

several key points unclear, Congress could choose to revisit the language and clarify the unclear 

points described in this report
48

Appendix A:

Overview of Preemption Analysis

The preemption doctrine derives from the Supremacy Clause of the Constitution,

71 which 

provides: 

"This Constitution, and the Laws of the United States which shall be made in 

Pursuance thereof; and all Treaties made, or which shall be made, under the 

Authority of the United States, shall be the supreme Law of the Land; and the 

Judges in every State shall be bound thereby, any Thing in the Constitution or 

Laws of any State to the contrary notwithstanding." 

The United States Supreme Court has summarized the concept:

"The Supremacy Clause provides Congress with the power to preempt state law. 

Preemption occurs when Congress, in enacting a federal statute, expresses a clear 

intent to preempt state law, when there is outright or actual conflict between 

federal and state law, where compliance with both federal and state law is in 

effect physically impossible, where there is implicit in federal law a barrier to 

state regulation, where Congress has legislated comprehensively, thus occupying 

an entire field of regulation and leaving no room for the States to supplement 

federal law, or where the state law stands as an obstacle to the accomplishment 

and execution of the full objectives of Congress.72

Preemption analysis of a federal statute consists of a structured, multi-step inquiry. The 

analysis begins with an examination of Congressional intent.73 Congress’s intent is discerned 

from the language of the statute, with the assumption that the ordinary meaning of the language 

accurately expresses the legislative purpose.74 Absent clarity in legislative language, preemption 

analysis next examines the statute's overall framework and legislative history for evidence 

regarding Congress’ intent to preempt.75

 71 U.S. Const. art. VI, Paragraph 2.

72 Louisiana. Pub. Serv. Comm n. v. FCC, 476 U.S. 355, 368-69 (1986). 

73 Medtronic Inc. v. Lohr, 518 U.S. 470, 485-486 (1996) ("The purpose of Congress is 

the ultimate touchstone in every preemption case.”).

74 Park n Fly, Inc. v Dollar Park & Fly Inc., 469 U.S. 189, 194, 105 S. Ct. 658, 661 

(1985).

75 Auburn Hous. Auth. v. Martinez, 277 F.3d 138, 144 (2d Cir. 2002).
49

If Congress intended to occupy an entire field of regulation, federal law overrides state 

law, irrespective of any actual conflict.76

Alternatively, preemption analysis might conclude that Congress did not intend to 

displace state regulation entirely. Where Congress has thus intended shared federal-state 

regulatory responsibility, preemption occurs only where state law actually conflicts with federal 

law.77 A conflict occurs where either (1) compliance with both the federal and state laws is 

physically impossible, e.g., where compliance with the state law causes a violation of federal 

law;78 or (2) state law poses an "obstacle" to Congress's purpose.79

 76 See, e.g., Rice v. Santa Fe Elevator Corp., 331 U.S. 218, 67 S. Ct. 1146 (1947) 

(finding that the Warehouse Act preempted a state statute, even where no actual conflicts 

existed, since Congress intended to eliminate dual state-federal regulatory system and assume 

jurisdiction over entire storage scheme.

In situations where federal 

and state authority conflict, state law must give way. 

77 La. Pub. Serv. Comm n. v. FCC, 476 U.S. at 368-69.

78 Florida Lime & Avocado Growers, Inc. v. Paul, 373 U.S. 132, 142143, 83 S. Ct. 

1210, 1217-18 (1963) ("A holding of federal exclusion of state law is inescapable and requires 

no inquiry into congressional design where compliance with both federal and state regulations is 

a physical impossibility for one engaged in interstate commerce.").

79 Hines v. Davidowitz, 312 U.S. 52, 67 (1941) ("Our primary function is to determine 

whether [a state law] stands as an obstacle to the accomplishment and execution of the full 

purposes and objectives of Congress.").
50

Appendix B:

PURPA Exemptions and Termination of Mandatory Purchase Provisions—

Statutes and Regulations

PURPA, as amended by EPAct 2005: Termination of mandatory purchase and sale 

requirements, 16 U.S.C. 824a-3(m):

(m) Termination of mandatory purchase and sale requirements.

 (1) Obligation to purchase. After the date of enactment of this subsection [enacted Aug. 

8, 2005], no electric utility shall be required to enter into a new contract or obligation to 

purchase electric energy from a qualifying cogeneration facility or a qualifying small 

power production facility under this section if the Commission finds that the qualifying 

cogeneration facility or qualifying small power production facility has nondiscriminatory 

access to—

 (A) (i) independently administered, auction-based day ahead and real time wholesale 

markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of 

capacity and electric energy; or

 (B) (i) transmission and interconnection services that are provided by a Commissionapproved regional transmission entity and administered pursuant to an open access 

transmission tariff that affords nondiscriminatory treatment to all customers; and (ii) 

competitive wholesale markets that provide a meaningful opportunity to sell capacity, 

including long-term and short-term sales, and electric energy, including long-term, shortterm and real-time sales, to buyers other than the utility to which the qualifying facility is 

interconnected. In determining whether a meaningful opportunity to sell exists, the 

Commission shall consider, among other factors, evidence of transactions within the 

relevant market; or

 (C) wholesale markets for the sale of capacity and electric energy that are, at a 

minimum, of comparable competitive quality as markets described in subparagraphs (A) 

and (B).

 (2) Revised purchase and sale obligation for new facilities.

 (A) After the date of enactment of this subsection [enacted Aug. 8, 2005], no electric 

utility shall be required pursuant to this section to enter into a new contract or obligation 

to purchase from or sell electric energy to a facility that is not an existing qualifying 

cogeneration facility unless the facility meets the criteria for qualifying cogeneration 

facilities established by the Commission pursuant to the rulemaking required by 

subsection (n).
51

 (B) For the purposes of this paragraph, the term "existing qualifying cogeneration 

facility" means a facility that—

 (i) was a qualifying cogeneration facility on the date of enactment of subsection (m) 

[enacted Aug. 8, 2005]; or

 (ii) had filed with the Commission a notice of self-certification, self recertification 

or an application for Commission certification under 18 CFR 292.207 prior to the date on 

which the Commission issues the final rule required by subsection (n).

 (3) Commission review. Any electric utility may file an application with the 

Commission for relief from the mandatory purchase obligation pursuant to this 

subsection on a service territory-wide basis. Such application shall set forth the factual 

basis upon which relief is requested and describe why the conditions set forth in 

subparagraph (A), (B), or (C) of paragraph (1) of this subsection have been met. After 

notice, including sufficient notice to potentially affected qualifying cogeneration facilities

and qualifying small power production facilities, and an opportunity for comment, the 

Commission shall make a final determination within 90 days of such application 

regarding whether the conditions set forth in subparagraph (A), (B), or (C) of paragraph 

(1) have been met.

 (4) Reinstatement of obligation to purchase. At any time after the Commission makes a 

finding under paragraph (3) relieving an electric utility of its obligation to purchase 

electric energy, a qualifying cogeneration facility, a qualifying small power production 

facility, a State agency, or any other affected person may apply to the Commission for an 

order reinstating the electric utility's obligation to purchase electric energy under this 

section. Such application shall set forth the factual basis upon which the application is 

based and describe why the conditions set forth in subparagraph (A), (B), or (C) of 

paragraph (1) of this subsection are no longer met. After notice, including sufficient 

notice to potentially affected utilities, and opportunity for comment, the Commission 

shall issue an order within 90 days of such application reinstating the electric utility's 

obligation to purchase electric energy under this section if the Commission finds that the 

conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1) which relieved the 

obligation to purchase, are no longer met.

 (5) Obligation to sell. After the date of enactment of this subsection [enacted Aug. 8, 

2005], no electric utility shall be required to enter into a new contract or obligation to sell 

electric energy to a qualifying cogeneration facility or a qualifying small power 

production facility under this section if the Commission finds that—

 (A) competing retail electric suppliers are willing and able to sell and deliver electric 

energy to the qualifying cogeneration facility or qualifying small power production 

facility; and
52

 (B) the electric utility is not required by State law to sell electric energy in its service 

territory.

FERC Regulations re: termination of obligation to purchase (18 C.F.R. § 309)

§ 292.309 Termination of obligation to purchase from qualifying facilities.

(a) After August 8, 2005, an electric utility shall not be required, under this part, to enter 

into a new contract or obligation to purchase electric energy from a qualifying 

cogeneration facility or a qualifying small power production facility if the Commission 

finds that the qualifying cogeneration facility or qualifying small power facility 

production has nondiscriminatory access to:

(1)(i) Independently administered, auction-based day ahead and real time wholesale 

markets for the sale of electric energy; and

(ii) Wholesale markets for long-term sales of capacity and electric energy; or

(2)(i) Transmission and interconnection services that are provided by a Commissionapproved regional transmission entity and administered pursuant to an open access 

transmission tariff that affords nondiscriminatory treatment to all customers; and

(ii) Competitive wholesale markets that provide a meaningful opportunity to sell 

capacity, including long-term and short-term sales, and electric energy, including longterm, short-term and real-time sales, to buyers other than the utility to which the 

qualifying facility is interconnected. In determining whether a meaningful opportunity to 

sell exists, the Commission shall consider, among other factors, evidence of transactions 

within the relevant market; or

(3) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, 

of comparable competitive quality as markets described in paragraphs (a)(1) and (a)(2) of 

this section.

(b) For purposes of §292.309(a), a renewal of a contract that expires by its own terms is a 

“new contract or obligation” without a continuing obligation to purchase under an 

expired contract.

(c) For purposes of §292.309(a)(1), (2) and (3), with the exception of paragraph (d) of 

this section, there is a rebuttable presumption that a qualifying facility has 

nondiscriminatory access to the market if it is eligible for service under a Commissionapproved open access transmission tariff or Commission-filed reciprocity tariff, and 

Commission-approved interconnection rules. If the Commission determines that a market 

meets the criteria of §292.309(a)(1), (2) or (3), and if a qualifying facility in the relevant 

market is eligible for service under a Commission-approved open access transmission 

tariff or Commission-filed reciprocity tariff, a qualifying facility may seek to rebut the 

presumption of access to the market by demonstrating, inter alia, that it does not have 

access to the market because of operational characteristics or transmission constraints.
53

(d)(1) For purposes of §292.309(a)(1), (2), and (3), there is a rebuttable presumption that 

a qualifying facility with a capacity at or below 20 megawatts does not have 

nondiscriminatory access to the market.

(2) For purposes of implementing paragraph (d)(1) of this section, the Commission will 

not be bound by the one-mile standard set forth in §292.204(a)(2).

(e) Midwest Independent Transmission System Operator (Midwest ISO), PJM 

Interconnection, L.L.C. (PJM), ISO New England, Inc. (ISO–NE), and New York 

Independent System Operator (NYISO) qualify as markets described in §292.309(a)(1)(i) 

and (ii), and there is a rebuttable presumption that qualifying facilities with a capacity 

greater than 20 megawatts have nondiscriminatory access to those markets through 

Commission-approved open access transmission tariffs and interconnection rules, and 

that electric utilities that are members of such regional transmission organizations or 

independent system operators (RTO/ISOs) should be relieved of the obligation to 

purchase electric energy from the qualifying facilities. A qualifying facility may seek to 

rebut this presumption by demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively prevent 

the qualifying facility's participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. The 

qualifying facility may show that it is located in an area where persistent transmission 

constraints in effect cause the qualifying facility not to have access to markets outside a 

persistently congested area to sell the qualifying facility output or capacity.

(f) The Electric Reliability Council of Texas (ERCOT) qualifies as a market described in 

§292.309(a)(3), and there is a rebuttable presumption that qualifying facilities with a 

capacity greater than 20 megawatts have nondiscriminatory access to that market through 

Public Utility Commission of Texas (PUCT) approved open access protocols, and that 

electric utilities that operate within ERCOT should be relieved of the obligation to 

purchase electric energy from the qualifying facilities. A qualifying facility may seek to 

rebut this presumption by demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively prevent 

the qualifying facility's participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. The 

qualifying facility may show that it is located in an area where persistent transmission 

constraints in effect cause the qualifying facility not to have access to markets outside a 

persistently congested area to sell the qualifying facility output or capacity.

(g) The California Independent System Operator and Southwest Power Pool, Inc. satisfy 

the criteria of §292.309(a)(2)(i).

(h) No electric utility shall be required, under this part, to enter into a new contract or 

obligation to purchase from or sell electric energy to a facility that is not an existing 
54

qualifying cogeneration facility unless the facility meets the criteria for new qualifying 

cogeneration facilities established by the Commission in §292.205.

(i) For purposes of §292.309(h), an “existing qualifying cogeneration facility” is a facility 

that:

(1) Was a qualifying cogeneration facility on or before August 8, 2005; or

(2) Had filed with the Commission a notice of self-certification or self-recertification, or 

an application for Commission certification, under §292.207 prior to February 2, 2006.

(j) For purposes of §292.309(h), a “new qualifying cogeneration facility” is a facility that 

satisfies the criteria for qualifying cogeneration facilities pursuant to §292.205.

[Order 688, 71 FR 64372, Nov. 1, 2006; 71 FR 75662, Dec. 18, 2006]

Exemptions from Section 205 of FPA

§ 292.601 Exemption to qualifying facilities from the Federal Power Act.

(a) Applicability. This section applies to qualifying facilities, other than those described 

in paragraph (b) of this section.

(b) Exclusion. This section does not apply to a qualifying small power production facility 

with a power production capacity that exceeds 30 megawatts, if such facility uses any 

primary energy source other than geothermal resources.

(c) General rule. Any qualifying facility described in paragraph (a) of this section shall 

be exempt from all sections of the Federal Power Act, except:

(1) Sections 205 and 206; however, sales of energy or capacity made by qualifying 

facilities 20 MW or smaller, or made pursuant to a contract executed on or before March 

17, 2006 or made pursuant to a state regulatory authority's implementation of section 210 

the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a–1, shall be exempt 

from scrutiny under sections 205 and 206;

(2) Section 1–18, and 21–30;

(3) Sections 202(c), 210, 211, 212, 213, 214, 215, 220, 221 and 222;

(4) Sections 305(c); and

(5) Any necessary enforcement provision of part III of the Federal Power Act (including 

but not limited to sections 306, 307, 308, 309, 314, 315, 316 and 316A) with regard to the

sections listed in paragraphs (c)(1), (2), (3) and (4) of this section.

(Energy Security Act, Pub. L. 96–294, 94 Stat. 611 (1980) Public Utility Regulatory 

Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy Supply and Environmental 
55

Coordination Act, 15 U.S.C. 791, et seq., Federal Power Act, as amended, 16 U.S.C. 792 

et seq., Department of Energy Organization Act, 42 U.S.C. 7101, et seq. ; E.O. 12009, 42 

FR 46267)

[Order 135, 46 FR 19232, Mar. 30, 1981, as amended by Order 569, 59 FR 40470, Aug. 

9, 1994; Order 671, 71 FR 7868, Feb. 15, 2006; 72 FR 29063, May 24, 2007]
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1. REPORT DATE (DD-MM-YYYY)

January 2010

2. REPORT TYPE

Technical Report

3. DATES COVERED (From - To)

4. TITLE AND SUBTITLE

Renewable Energy Prices in State-Level Feed-in Tariffs: Federal 

Law Constraints and Possible Solutions

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

Scott Hempling, Carolyn Elefant, Karlynn Cory, Kevin Porter

5d. PROJECT NUMBER

NREL/TP-6A2-47408

5e. TASK NUMBER

PVC9.9720

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

8. PERFORMING ORGANIZATION

REPORT NUMBER

NREL/TP-6A2-47408

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S)

NREL

11. SPONSORING/MONITORING

AGENCY REPORT NUMBER

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National Technical Information Service

U.S. Department of Commerce

5285 Port Royal Road

Springfield, VA 22161

13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

State legislatures and state utility commissions trying to attract renewable energy projects are considering feed-in 

tariffs, which obligate retail utilities to purchase electricity from renewable producers under standard arrangements 

specifying prices, terms, and conditions. The use of feed-in tariffs simplifies the purchase process, provides revenue 

certainty to generators, and reduces the cost of financing generating projects. However, some argue that federal 

law—including the Public Utility Regulatory Policies Act of 1978 (PURPA) and the Federal Power Act of 1935 

(FPA)—constrain state-level feed-in tariffs. This report seeks to reduce the legal uncertainties for states 

contemplating feed-in tariffs by explaining the constraints imposed by federal statutes. It describes the federal 

constraints, identifies transaction categories that are free of those constraints, and offers ways for state and federal 

policymakers to interpret or modify existing law to remove or reduce these constraints. This report proposes ways to 

revise these federal statutes. It creates a broad working definition of a state-level feed-in tariff. Given this definition, 

this report concludes there are paths to non-preempted, state-level feed-in tariffs under current federal law.

15. SUBJECT TERMS

feed-in tariffs; FIT; renewable electricity; renewable energy; electricity sales; electricity purchases; financing 

electricity generating projects; states; state legislatures; state utility commissions; state policymakers; federal law; 

federal statutes; the Public Utility Regulatory Policies Act of 1978; PURPA; Federal Power Act of 1935; FPA

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OF ABSTRACT

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