New Opportunities for State-Level Feed-in Tariffs: Using a
Revitalized PURPA to Encourage Renewable Energy Development
Through State-Level Feed-In Tariffs Without Federal Preemption
Name: Dylan Borchers
Law School of Attendance: The Ohio State University Moritz College of Law, entering third
year (expected graduation, May 2013)
New Opportunities for State-Level Feed-in Tariffs: Using a
Revitalized PURPA to Encourage Renewable Energy Development
Through State-Level Feed-In Tariffs Without Federal Preemption
I. INTRODUCTION
Development of renewable energy resources in the United States is critical to combating
global climate change, enhancing our national security, and further developing the growing
“green” economy. Many states – whether due to the absence of federal leadership to address
climate change or the desire to attract new jobs – have implemented an array of policies to
promote renewable energy generation within their borders.1 In this way, states are experimenting
with various initiatives that can act as models of renewable energy development policies for
other states and the nation.
To date, however, one policy mechanism to promote renewable energy development has not
been available to the states—the Feed-In Tariff (FIT). FITs are a potential policy approach to
support the development of renewable energy resources. A FIT obligates retail utilities to
purchase electricity from renewable energy generators under standard arrangements specifying
prices, terms, and conditions.2 Depending on the rate, a FIT can increase the competitiveness of
renewable technologies against existing electric power sources.3 In turn, FITs can make a state a
more attractive venue for investment in renewable energy technologies.
Historically, due to federal regulation of the wholesale sale of electricity, states have been
generally foreclosed from implementing FITs. Even in the limited instances where states have
been delegated the authority to set the rates of wholesale sales of electricity, states have not been
1
Examples of policy initiatives states have implemented to encourage renewable energy development include
renewable portfolio standards, tax incentives, and cap-and-trade programs.
2
SCOTT HEMPLING, CAROLYN ELEFANT, KARLYNN CORY & KEVIN PORTER, RENEWABLE ENERGY PRICES IN STATELEVEL FEED-IN TARIFFS: FEDERAL LAW CONSTRAINTS AND POSSIBLE SOLUTIONS (TECHNICAL REPORT NREL/TP6A2-47408) 2 (2010).
3
Id.
1
able to set the rates high enough to support renewable energy development.4 However, two
recent orders by the Federal Energy Regulatory Commission (FERC) have created new
possibilities for states to implement FITs. They have done so by expanding the limited
delegation of authority to states to set rates for wholesale sales of electricity under the Public
Utilities Regulatory Policy Act (PURPA).5 With these orders, states may now be able to
implement FITs at rates high enough to support renewable energy development without being
preempted by federal law.
Part II of this paper first discusses what FITs are and where they are used, before offering an
overview of the federal regulatory scheme that has prevented states from implementing FITs.
Part III of this paper analyzes the recent FERC orders and explores whether and how they create
new opportunities for states to create FITs for renewable energy. Part III then uses Ohio as a case
study for examining the implications of these orders in practice. Finally, the paper concludes
with a call for federal legislative action to provide states greater flexibility to implement FITs
with the purpose of promoting renewable energy development.
II. BACKGROUND – STATES HAVE LITTLE ABILITY TO IMPLEMENT ROBUST FEED-IN TARIFFS
TO SUPPORT RENEWABLE ENERGY GENERATION
A. Feed-In Tariffs as a Potential Policy Mechanism for Encouraging Renewable Energy
Generation
A FIT is a rate-setting policy designed to support the wider use of energy supplied by
technologies that are not otherwise market competitive.6 Broadly, a FIT obligates retail utilities
See 16 U.S.C.A. § 824(d) (West 2012). “The term “sale of electric energy at wholesale” . . . means a sale of
electric energy to any person for resale.”
5
California Pub. Utilities Comm'n S. California Edison Co. Pac. Gas & Elec. Co. San Diego Gas & Elec. Co., 133
FERC ¶ 61059 (Oct. 21, 2010); California Pub. Utilities Comm'n S. California Edison Co. Pac. Gas & Elec. Co.
San Diego Gas & Elec. Co., 133 FERC ¶ 61059 (Oct. 21, 2010).
6
David Grinlinton & Leroy Paddock, Climate Change and the Future of Energy: The Role of Feed-In Tariffs in
Supporting the Expansion of Solar Energy Production, 41 U. TOL. L. REV. 943, 945 (2010) (noting that while energy
4
2
to purchase electricity from renewable energy generators under standard arrangements specifying
prices, terms, and conditions.7 The goal of a FIT is to create a robust and stable market for
renewable energy.8 In the short term, a FIT creates a secure investment for renewable energy
developers.9 In the long term, the industry development spurred by a FIT can lead to lower
overall costs for renewable technologies, which in turn makes renewable energy more market
competitive.10
Although there is no standard legal definition of a FIT, a recent technical report
commissioned by the National Renewable Energy Laboratory (NREL) suggests the following
definition of a state-level FIT designed to support renewable energy:
[A] publically available, legal document, promulgated by a state utility regulatory
commission or through legislation, which obligates an electrical 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 . . . .11
produced by renewable technologies may not be market competitive, the energy supplied by these technologies may
have other benefits, such reduced environmental impacts). See also KARLYNN CORY, TOBY COUTURE & CLAIRE
KREYCIK, FEED-IN TARIFF POLICY: DESIGN, IMPLEMENTATION, AND RPS POLICY INTERACTIONS (TECHNICAL
REPORT NREL/TP-6A2-45549) 2 –5 (2009). This report was commissioned by the NREL, and, in part, identifies
two main methodologies for setting the overall rate that renewable developers receive through FIT policies. The first
is to base the FIT payments “on the levelized cost of renewable energy.” The second is to base the rate on “the value
of that generation to the utility and/or society.” FIT rates may also be fixed or variable with the market price.
7
Grinlinton, supra note 6 at 944.
8
Id.
9
Feed-In Tariffs: Frequently Asked Questions, THE NATIONAL ASSOCIATION OF REGULATORY COMMISSIONERS
(June 2010), http://www.naruc.org/Publications/NARUC%20Feed%20in%20Tariff%20FAQ.pdf.
10
Id.
11
SCOTT HEMPLING, CAROLYN ELEFANT, KARLYNN CORY & KEVIN PORTER, RENEWABLE ENERGY PRICES IN
STATE-LEVEL FEED-IN TARIFFS: FEDERAL LAW CONSTRAINTS AND POSSIBLE SOLUTIONS (TECHNICAL REPORT
NREL/TP-6A2-47408) 2 (2010). This report was commissioned by the NREL to provide legal expertise in response
to requests by state utility commissions and the National Association of Regulatory Utility Commissioners that the
NREL explore how states can lawfully implement FITs. The report was published less than a year before the FERC
orders expanded states’ ability to implement FITs under PURPA. The report concluded that the regulatory
framework generally foreclosed states from implementing FITs at a high enough rate to promote renewable energy
development. Notably, however, the report did identify the possibility of FERC reinterpreting – or clarifying – its
precedent to allow such FITs under PURPA.
3
Typically, the FIT contract between the generator and utility is for a term of ten to twenty
years, with a set rate that covers project costs plus a reasonable rate of return.12 The design of
FIT programs varies depending on the goals of the program the rates set, the technologies
involved, the generator sizes, and the terms of the contract. For example, a FIT may be designed
to encourage small solar power producers by offering solar generators under 100 kilowatts (kW)
a preferential rate that allows for adequate recovery of project costs plus a reasonable rate of
return for a period of fifteen years.
According to some energy policy experts, well-designed FIT programs have some
advantages over other policy mechanisms designed to promote renewable energy, such as
renewable portfolio standards (RPS), net-metering, and up-front rebates.13 One advantage is that
FIT policies may stimulate more rapid development of renewable energy than these other
mechanisms.14 Further, another recent technical report commissioned by NREL found that,
“[e]xperience from Europe is also beginning to demonstrate that properly designed FITs may be
more cost-effective than renewable portfolio standards . . . .”15
The use of FITs to encourage renewable energy generation is widespread in Europe, and
Europe’s experience with FITs offers valuable lessons concerning the costs and benefits of FITs.
As noted by another recent NREL technical report, “[FITs] have resulted in the deployment of
15,000 MW of solar photovoltaic (PV), and 55,000 megawatts (MW) of wind power from 2000
12
Feed-In Tariffs: Frequently Asked Questions, supra note 9.
Grinlinton, supra note 6 at 948.
14
Id.
15
CORY, supra note 6 at 1.
13
4
to 2009 in the European Union.”16 Currently, at least twenty of the European Union’s twentyseven countries use FITs as the primary mechanism to promote renewable energy generation.17
Within Europe, the FIT programs implemented by Germany and Spain to encourage solar
PV development are especially notable.18 Germany’s FIT program offers a twenty-year
guaranteed fixed rate that provides solar PV producers with a long-term profit of approximately
five to seven percent.19 The FITs have been a key driver in the astounding growth in Germany’s
solar PV development.20 In 2011, Germany installed nearly 7 gigawatts (GW) of solar, with
almost 2 GW of that total in the month of December alone.21 The 2011 figure was especially
notable because the government support for solar was reduced by thirteen percent during that
year.22 Despite this cut in subsidies, the amount of solar installation did not decrease, suggesting
that Germany’s solar industry has made significant advances in cost reduction for solar
installation.23 Overall, Germany’s total installed capacity is just below 25 GW.24 In all, roughly
three percent of Germany’s current power supply comes from solar; by 2020, this share is
expected to increase to ten percent.25
TOBY D. COUTURE, KAROLYNN CORY, CLAIRE KREYCIK & EMILY WILLIAMS, A POLICYMAKER’S GUIDE TO FEEDIN TARIFF POLICY DESIGN vii (TECHNICAL REPORT NREL/TP-6A2-44849) V (2010).
17
ARNE KLIEN, ERIK MERKEL, BENJAMIN PFLUGER, ANNE HELD, MARIO RAGWITZ, GUSTAV RESCH & SEBASTIAN
BUSCH, EVALUATION OF DIFFERENT FEED-IN TARIFF DESIGN OPTIONS 7 (2010).
18
Grinlinton, supra note 6 at 949–55.
19
Id. See also COUTURE, supra note 16 at 121 (offering detailed tables of Germany’s FIT payment levels).
20
Grinlinton, supra note 6 at 949.
21
More Solar Power Than Ever Before, GERMAN SOLAR INDUSTRY ASSOCIATION (Jan. 4, 2012),
http://www.solarwirtschaft.de/en/media/singleview/?tx_ttnews%5Byear%5D=2012&tx_ttnews%5Bmonth%5D=01&tx_ttnews%5Bday%5D=04&tx_ttnews%5Btt
_news%5D=14412&cHash=61f51bad3e486607cd4bdb1666a158d1.
22
Id.
23
Id.
24
Germany’s Millionth Solar Power System Goes Into Operation, GERMAN SOLAR INDUSTRY ASSOCIATION (Dec.
17, 2011), http://www.solarwirtschaft.de/en/media/singleview/?tx_ttnews%5Byear%5D=2011&tx_ttnews%5Bmonth%5D=11&tx_ttnews%5Bday%5D=17&tx_ttnews%5Btt
_news%5D=14309&cHash=1b9f0f33f199e17b0da163f8c00ae418.
25
Id.
16
5
Germany’s solar FIT program is also widely considered to be a primary force behind
Germany’s large renewable energy industry.26 Germany’s renewable energy sector currently
employs approximately 300,000 workers, with about 500,000 expected to be employed by
2020.27 Another notable aspect of the German FIT system is the limited cost of the system. It is
estimated that the increased cost to the average consumer’s energy bill has only been four to five
percent.28
Like Germany, Spain also experienced rapid solar power development and deployment
after implementing a FIT in 2007 to encourage solar power generation.29 However, whereas
Germany’s FIT system is often noted for its stability, Spain’s experience with FITs highlights
some of the economic dangers that may come with widespread use of FITs.30 Like Germany,
Spain (1) set rates that covered costs and provided a profit and (2) set a market cap for the
amount of solar production.31 Unlike Germany, Spain (1) established very high FIT rates and (2)
did not create a mechanism to lower the FIT rates if the capacity targets were exceeded or if
there was a sudden reduction in the cost of solar energy.32
High FIT-rate guarantees, combined with the strong Spanish sun, caused the solar PV
market in Spain to boom. However, the structural shortcomings of the FIT program ultimately
brought Spain’s solar market crashing down. Within the first year of the FIT, Spain nearly met
the initial installation target of 400 MW, despite the government’s original estimate that the
26
Grinlinton, supra note 6 at 952.
Christoph H. Stefes, The German Solution: Feed-In Tariffs, NY TIMES (Sept. 21, 2011), available at
http://www.nytimes.com/roomfordebate/2011/09/20/why-isnt-the-us-a-leader-in-green-technology/us-shouldemulate-germanys-renewable-energy-model.
28
Grinlinton, supra note 6 at 952.
29
Id.
30
COUTURE, supra note 16 at 11.
31
Grinlinton, supra note 6 at 953.
32
Paul Voosen, Spain’s Solar Market Crash Offers a Cautionary Tale About Feed-In Tariffs, NY TIMES (Aug. 18,
2009), available at http://www.nytimes.com/gwire/2009/08/18/18greenwire-spains-solar-market-crash-offers-acautionary-88308.html?pagewanted=all.
27
6
target would not be met until 2010.33 In response, the Spanish government increased the cap to
1,200 MW.34 The solar industry in Spain and beyond quickly expanded to meet the increased
demand.35 Unfortunately, taxpayer backlash led the Spanish government to subsequently slash
the tariff rate by thirty percent, causing a dramatic slow-down in the rate of installation.36 Excess
solar panels, originally intended for Spain, flooded the market, causing a worldwide downturn in
the solar market.37 As for Spain, its domestic solar industry lost more than 20,000 jobs.38
Spain’s mixed experience with FITs highlights some of the concerns associated with
FITs. The process of setting the FIT rate is central if a program is to successfully meet its goals.
As shown by Spain’s experience, setting too high a rate may overly distort the market and create
a boom-bust cycle, especially if the high rates are not coupled with cost-containment
mechanisms.39 At the same time, setting a rate that is too low will prevent a FIT program from
meeting its goals.40 Thus, it is critical that rates are established through a detailed and objective
process, with the ability to periodically review and adjust rates in order to respond to the
market.41 In addition, Spain’s experience demonstrates that sporadic and reactionary
governmental intervention severely undercuts the very market stability that FITs seek to
provide.42
Along with the concerns highlighted by Spain’s experience with FITs, other arguments
can be made against the use of FITs as a mechanism to promote renewable energy development.
One argument against using FITs is that they do not directly address the high start-up costs
33
Id.
Id.
35
Id.
36
Id.
37
Grinlinton, supra note 6 at 956.
38
Id.
39
COUTURE, supra note 16 at 106.
40
Grinlinton, supra note 6 at 947.
41
Id.
42
Id.
34
7
associated with renewable energy technologies.43 Rather, these up-front costs are spread over
time. Another concern is that FIT programs could lead renewable energy industries to develop a
reliance on the FITs.44 Related to this concern is that FIT programs remove price competition
between project developers, thus stifling the incentive to innovate and reduce costs.45 Further, it
may be challenging to incorporate FITs into the existing regulatory environment.46 Indeed, this
challenge of incorporating FITs into the current regulatory environment has been – and remains
– a primary obstacle to the implementation of FITs within the United States.
B. Federal Regulation Over the Wholesale Sale of Electricity Generally Prevents States
from Implementing Feed-In Tariffs
In the United States, the authority to regulate electrical energy is divided between the states
and the federal government. By default, the states have jurisdiction over the regulation of
electrical energy unless Congress expressly reserves jurisdiction for FERC.47 In particular, two
statutes govern the FERC’s authority to regulate electrical energy transmission and transactions,
the Federal Power Act (FPA)48 and the Public Utilities Regulatory Policy Act (PURPA).49 Under
this statutory framework, FERC is given the exclusive authority to regulate “the transmission of
energy in interstate commerce” and “the sale of such energy at wholesale in interstate
commerce.”50 In contrast, these federal statutes do not constrain the authority of states to regulate
43
COUTURE, supra note 16 at 12.
Id.
45
Id. at 13. Other disadvantages include near-term upward pressure on electricity prices, difficulty in controlling
overall policy costs, and that FITs may exclude lower-income individuals from participating. See COUTURE, supra
note 12 at 69–104 for a detailed analysis and summary of best practices for FIT policy design and implementation.
The best practices identified include: differentiation of FIT payments according to renewable energy generation
costs, encouragement of innovation and technological change, sliding premiums, guarantee of grid access,
requirement of utility purchase obligation, and robust forecast and reporting requirements.
46
COUTURE, supra note 16 at 12.
47
16 U.S.C.A. § 824(b)(1) (West 2012).
48
16 U.S.C.A. § 791 (West 2012).
49
16 U.S.C.A. § 824 (West 2012).
50
Id.
44
8
retail sales of electricity.51 The focus of this paper concerns FERC jurisdiction over the
wholesale sale of electricity in interstate commerce.
Under the FPA, a “sale of electricity at wholesale” is defined as “a sale of electric energy to
any person for resale.”52 What constitutes interstate commerce is not identified in the statute, but
case law indicates that electrical energy from a renewable energy generator is likely to be
classified as participating in interstate commerce, thus subjecting the facility to FERC
jurisdiction.53 For the purposes of this paper, references to the wholesale sale of electricity will
be presumed to be in interstate commerce unless otherwise stated.
The FPA requires that FERC approve the contracts involving the sale of wholesale electricity
and ensure that such sales are “just and reasonable.”54 At its core, a FIT program involves a sale
of wholesale energy. For instance, a FIT program may involve a renewable generator selling
electricity to a utility at a predetermined rate for subsequent resale to retail customers. This sort
of sale constitutes a wholesale sale of power.
C. PURPA Provides a Limited Exception to Exclusive Federal Control Over Wholesale
Rate-Setting
Although the FPA gives FERC jurisdiction to regulate the sale of wholesale electricity, this
authority is not absolute. Under PURPA, states have limited authority to set rates for the sale of
wholesale electricity.55 This delegation to the states, however, has traditionally been limited in
ways that have prevented states from exercising this authority to implement FIT programs. The
51
HEMPLING, supra note 2 at viii.
16 U.S.C.A. § 824(d) (West 2012).
53
See Fed. Power Comm’n v. Fla. Power & Light Co., 404 U.S. 453 (1972). In an opinion by White, J., expressing
the views of four members of the court, it was held that the Federal Power Commission's (now FERC) jurisdiction
attached if any power of an electric utility company reached another state, or if such company made use of any
power from another state, no matter how small the quantity involved.
54
Id.
55
Id.
52
9
following discussion examines PURPA’s grant of regulatory authority to the states, along with
two significant limitations to this grant of authority.
PURPA was passed in response to the unstable energy climate of the 1970s.56 One of the
purposes of PURPA was to encourage more energy-efficient and environmentally friendly
commercial energy production.57 To help accomplish this goal, PURPA established a new class
of generating facilities that would receive special rate and regulatory treatment.58 Collectively,
these generating facilities were classified as “qualifying facilities” (QFs). There are two types of
QFs: (1) qualifying cogeneration facilities and (2) qualifying small power production facilities. 59
The latter QFs are renewable energy generating facilities with a net capacity of 80 MW or less. 60
There is no size limitation for qualifying cogeneration facilities.61
Prior to the passage of PURPA, QFs seeking to establish interconnected operation with a
utility faced a number of obstacles, including limited selling opportunities, high rates for back-up
services, and burdensome regulatory measures imposed on nontraditional energy facilities.62 In
an effort to respond to the challenges faced by QFs and encourage their development, Section
56
FERC v. Mississippi, 456 U.S. 742, 750 (1982).
Id. at 751.
58
Id.
59
What is a Qualifying Facility?, FERC ( Jan. 13, 2012) , http://www.ferc.gov/industries/electric/gen-info/qualfac/what-is.asp. “A “cogeneration facility” is a generating facility that sequentially produces electricity and another
form of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of
both forms of energy. For example, in addition to the production of electricity, large cogeneration facilities might
provide steam for industrial uses in facilities such as paper mills, refineries, or factories, or for HVAC applications
in commercial or residential buildings. Smaller cogeneration facilities might provide hot water for domestic heating
or other useful applications. In order to be considered a qualifying cogeneration facility, a facility must meet all of
the requirements of 18 C.F.R. §§ 292.203(b) and 292.205 for operation, efficiency and use of energy output, and be
certified as a QF pursuant to 18 C.F.R. § 292.207.”
60
Id. Renewable sources include hydro, wind or solar, biomass, waste, and geothermal resources. There are some
limited exceptions to the 80 MW size limit that apply to certain facilities certified prior to 1995 and designated
under section 3(17)(E) of the Federal Power Act (16 U.S.C. § 796(17)(E), which have no size limitation. In order to
be considered a qualifying small power production facility, a facility must meet all of the requirements of 18 C.F.R.
§§ 292.203(a) , 292.203(c) and 292.204 for size and fuel use, and be certified as a QF pursuant to 18 C.F.R. §
292.207.
61
Id.
62
FERC v. Mississippi, 456 U.S. 742, 751 (1982).
57
10
210 of PURPA required electric utilities to purchase electric energy generated by QFs. 63 Under
PURPA, the states, rather than FERC, are granted the authority to regulate the price of the
wholesale transaction between state-regulated electric utilities and QFs, as long as the rate is no
greater than the utility’s “avoided cost.” 64 The concept of avoided cost is discussed in further
detail below.
In 2005, the scope of PURPA’s purchasing requirement from renewable small power
producers with a capacity less than 80 MW was reduced by the Energy Power Act. Specifically,
the Act modified PURPA by adding a new subsection to Section 210.65 The new subsection in
the statute terminates the obligation that an electric utility purchase electricity from QFs if FERC
finds that the QF has nondiscriminatory access to one of three categories of markets—auctionbased wholesale markets; regional transmission entities with competitive wholesale markets; or
other wholesale markets of “comparable competitive quality.”66 In October 2006, FERC issued
Order No. 688 promulgating the regulations applicable to the Energy Power Act. Specifically,
the final rule found that the QFs within the following regional transmission organizations
63
16 U.S.C.A. § 824a-3 (West). See also 18 C.F.R. § 292.203 (West). Along with meeting the size and fuel-use
criteria, facilities must register with FERC if they are to be considered QFs.
64
Id.
65
Id.
66
16 U.S.C.A. § 824a-3 (West 2012). “After August 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 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 realtime 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).”
11
(RTOs) and independent service organizations (ISOs)67 had nondiscriminatory access to the
wholesale markets: PJM Interconnection (PJM), Midwest Independent Transmission System
Operator, Inc. (Midwest ISO), ISO-New England (ISO-NE), and New York ISO (NYISO).68
Under the FERC order, electric utilities in the PJM, Midwest ISO, ISO-NE, and the NYISO
wholesale markets are eligible for relief from the PURPA-requirement to enter into new
contracts for the purchase of QF electric energy. However, this relief from PURPA is within the
context of two rebuttable presumptions.69 The first rebuttable presumption is that QFs with a net
capacity over 20 MW have nondiscriminatory access to wholesale markets.70 The second
rebuttable presumption is that QFs with a net capacity no greater than 20 MW do not have
nondiscriminatory access to wholesale markets.71
Technically, the PURPA framework, even after the reduction of its scope by the Energy
Power Act, provides states the ability to implement FITs to encourage renewable energy
generation by aligning the eligibility criteria for the FIT with FERC’s rules for certifying QFs
and then setting the tariff rate under the auspices of PURPA. In practice, however, the PURPA
framework has been ineffective as a vehicle through which states can develop a FIT to encourage
renewable energy development. Although states are given the authority to set the rates for sales
of electricity between electric utilities and QFs, PURPA requires that the rates for such purchases
“be just and reasonable to the ratepayers of the utility,” and not to exceed the utility’s “avoided
67
Regional Transmission Organizations (RTO)/Independent System Operators (ISO), FERC (DEC. 29, 2011),
http://www.ferc.gov/industries/electric/indus-act/rto.asp. RTOs and ISO are organizations formed at the direction or
recommendation of FERC. In the areas where a RTO or ISO is established, it coordinates, controls and monitors the
operation of the electrical power system, usually within a single U.S. state, but sometimes encompassing multiple
states.
68
FERC Order No. 688 at 8 (reasoning that “[t]hese RTOs are independently administered and offer auction-based
day and real time wholesale markets for the sale of electric energy; and within the regions represented by the RTOs
there is nondiscriminatory access to wholesale markets for long-term sales of capacity and electric energy.”).
69
Id.
70
18 C.F.R. § 292.309.
71
Id.
12
cost.”72 As defined by FERC, “avoided cost” is “the incremental cost of electric energy, capacity,
or both, which, but for the purchase from the QF, such utility would generate itself or purchase
from another source.”73
Most often, a utility’s avoided cost has been interpreted to be equal to the cheapest available
power generally available in the state.74 Under this approach, the utility’s avoided cost did not
vary according to differences in QF technology.75 Instead, the avoided cost was usually based on
the lowest cost of power generated from the state’s general power mix, such as coal or natural
gas.76 Payments based on this interpretation were typically too low to support QFs generating
renewable energy.77 Thus, traditional avoided cost rates inhibited states from implementing
strong FITs to support renewable energy development by using their authority under the PURPA
framework.78
D. Additional Exceptions to Federal Jurisdiction of Wholesale Sales of Electricity:
Where Renewable Energy Feed-In Tariffs Exist in the United States Today
As discussed in the section above, federal preemption concerns and limitations to the states’
authority under PURPA have prevented states from using FITs to encourage renewable energy
development under the PURPA framework. This does not mean that FITs are non-existent in the
72
16 U.S.C.A. § 824a-3 (West 2012); 18 C.F.R. § 292.101.
18 C.F.R. § 292.101.
74
See Southern California Edison, 70 FERC ¶ 61,215 (1995), aff’d on rehearing, 71 FERC ¶ 61,269 (1995). See
also 71 FERC ¶ 62,080. In addition, the avoided cost calculation may not include “environmental adders,” such as
the environmental costs to society, unless such external costs were monetized through policy. “A state . . . may not
set avoided cost rates . . . 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.” But see DANIEL YERGIN, THE QUEST 530 (2011). California was an exception to
generally low avoided cost rates, setting very high rates “on very generous terms.”
75
Id.
76
HEMPLING, supra note 2 at 14.
77
Id.
78
Id.
73
13
United States. Rather, FITs designed to encourage renewable energy development in the United
States exist in a number of contexts where there is not the concern of federal preemption.
Although the FPA gives FERC jurisdiction to regulate the sale of wholesale electricity,
such sales must be within interstate commerce.79 FERC does not regulate wholesale sales in
Alaska, Hawaii, and most of Texas because these electric grids do not cross state lines.80 Free
from federal preemption concerns, the Hawaii Public Utilities Commission, in 2010, established
a FIT to encourage renewable energy development.81 Several renewable technologies are eligible
for the program, under which qualified rates receive a fixed rate over a twenty-year contract.82
The program consists of varying rates for tiers of projects, differentiated by size and
technology.83 Depending on the tier, projects up to 5 MW qualify for the program.84 All together,
the program has an 80 MW cap, though there are sub-caps within each tier and for the various
islands of Hawaii.85
Another exception to FERC’s jurisdiction concerns sales of electricity from a state or
municipality. Section 201(f) of the FPA states that these entities, including “any agency,
authority, or instrumentality [of one or more of these entities] . . . or any corporation which is
wholly owned [by one of more of these entities]” shall be excluded from FERC’s jurisdiction of
79
See supra p. 9.
See Jared M. Fleisher, ERCOT’s Jurisdictional Status: A Legal History and Contemporary Appraisal, 3 TEX. J.
OIL, GAS, AND ENER. L. 5, 8–11 (2008).
81
Hawaii: Incentive/Policies for Renewables & Efficiency, DSIRE,
http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=HI29F (last visited May 28, 2012). The creation
of the feed-in tariff is in accordance with the Hawaii Clean Energy Initiative, and serves to formalize some of the
goals established in 2008. All Hawaii PUC orders pertaining to the feed-in tariff can be found in Docket No. 20080273.
82
Id.
83
Id.
84
Id.
85
Id.
80
14
wholesale sales of electricity.86 As such, a number of municipalities have established FITs to
encourage renewable energy development.
Perhaps the best-known example of a municipally-established FIT is the program
established by the City of Gainesville, Florida. In 2009, the city established a FIT to promote
new solar photovoltaic systems.87 Under this program, the city’s municipal utility, the
Gainesville Regional Utilities (GRU), offers a solar FIT at a predetermined rate for a period of
twenty years.88 The offered fixed rate depends on the size of the system and when the contract
was executed.89 The program is limited to a total capacity of 4 MW per calendar year.90 Because
the GRU is a municipal utility offering the FIT, there is no conflict with federal jurisdiction.
Although the state may not require the utility to offer to purchase electricity at certain rates, a
municipal utility may do so voluntarily.91
Most recently, in April 2012, the Los Angeles City Council and Mayor both approved the
launch of a FIT program.92 The program enables the Los Angeles Department of Water and
Power to buy renewable power from projects up to 3 MW.93 Initially, the program will have a 10
16 U.S.C. § 824(f). “No provision in this subchapter shall apply to, or be deemed to include, the United States, a
State or any political subdivision of a State, an electric cooperative that receives financing under the Rural
Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells less than 4,000,000 megawatt hours of electricity per
year, or any 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.”
87
Megan Rolland, Commission gives its approval to feed-in-tariff for solar power, GAINESVILLE SUN, Feb. 6, 2009,
available at http://www.gainesville.com/article/20090206/ARTICLES/902061014; see also City of Gainesville,
Ordinance 0-08-88.
88
Gainesville Regional Utilities – Solar Feed-In Tariff, DSIRE, Jan. 6, 2012,
http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=FL77F&re=1&ee=1.
89
Id.
90
Solar Fit, GRU, https://www.gru.com/OurCommunity/Environment/GreenEnergy/solar.jsp (last visited Jan. 12,
2012).
91
SCOTT HEMPLING ET AL., RENEWABLE ENERGY PRICES IN STATE-LEVEL FEED-IN TARIFFS: FEDERAL LAW
CONSTRAINTS AND POSSIBLE SOLUTIONS 22 (January 2010).
92
Ucilia Wang, Los Angeles Set to Launch a Feed-In Tariff Program, RENEWABLEENERGYWORLD.COM (APRIL 4,
2012), http://www.renewableenergyworld.com/rea/news/article/2012/04/los-angeles-set-to-launch-a-feed-in-tariffprogram.
93
Id.
86
15
MW cap pilot, which will only include solar projects between 30 kW and 999 kW.94 By 2016,
the program will have a 75 MW cap, with the subsequent possibility of a 150 MW cap,
depending on interest in the program and the city’s budget.95 Currently, Los Angeles is the
largest city in the United States to adopt a FIT.96
Municipalities, free from federal preemption concerns, have been the primary drivers of
renewable energy FITs in the United States. However, states may soon play a larger role in the
use of FITs for renewable energy development. Below, Section III of this paper examines recent
changes to the interpretation of a state’s authority under PURPA, which may now provide states
with the ability to develop their own FIT programs with rates high enough to support renewable
energy development.
III. NEW OPPORTUNITIES FOR STATE-LEVEL FEED-IN TARIFFS
Although the traditional approach to calculating a utility’s avoided cost prevented states from
implementing FIT programs with strong enough rates to support renewable energy development,
two recent FERC orders change the way avoided cost may be calculated. This reinterpretation of
the meaning of avoided cost opens the door for states to implement FITs under PURPA at
sufficient rates to support renewable energy generation. The first subsection below provides an
overview of the FERC orders and how the avoided cost calculation under PURPA has been
expanded. This analysis is then followed by an overview of how states could use the expanded
interpretation to implement FITs to support renewable energy generation. The second subsection
below examines what the reinterpretation could mean for Ohio.
94
Id.
Id.
96
Los Angeles Approves CLEAN L.A. Solar FIT Program, SOLAR FEEDS (April 15, 2012),
http://www.solarfeeds.com/los-angeles-approves-clean-l-a-solar-fit-program/.
95
16
A. Recent Federal Energy Regulatory Commission Orders Expand State Options to Support
Renewable Energy Development Through the Use of FITs
In 2007, California’s legislature passed the “Waste Heat and Carbon Emissions Reduction
Act” (AB 1613).97 This legislation required regulated electric utilities in California to purchase
electricity generated by combined heat and power generating facilities (CHP) of 20 MW or less
at a price set by the California Public Utilities Commission (CPUC).98 The CPUC required the
electric utilities to submit ten-year standard purchase contracts, or FITs, for qualifying CHP
generators.99
The California utilities affected by the legislation and CPUC implementation challenged the
program’s validity before the FERC. Specifically, the utilities argued that CPUC’s actions were
preempted by FERC’s exclusive jurisdiction to regulate the wholesale sale of electricity.100 On
July 15, 2010, FERC issued a declaratory order on the CPUC FIT program. FERC ruled that the
FPA preempted CPUC from establishing rates for the utilities’ purchases of electricity unless the
selling generators qualified as QFs under PURPA, in which case the rates could not exceed the
purchasing utility’s avoided cost.101
The initial FERC order appeared to limit CPUC’s authority to set rates for the purchase of
power from the CHPs. However, CPUC requested that FERC consider whether CPUC could
establish different avoided cost levels for different types of QFs depending on the characteristics
of the generator. On October 21, 2010, FERC issued a clarification order finding that when a
state uses its authority under PURPA to require a utility to purchase a certain amount of energy
97
2007 Cal. Legis. Serv. Ch. 713 (A.B. 1613).
Id.
99
Order Instituting Rulemaking on the Commission’s Own Motion into Combined Heat and Power Pursuant to
Assembly Bill 1613, California Public Utilities Commission, Rulemaking 08-06-024, Dec. 17, 2009.
100
California Pub. Utilities Comm'n S. California Edison Co. Pac. Gas & Elec. Co. San Diego Gas & Elec. Co.,
132 FERC ¶ 61047 (July 15, 2010).
101
Id.
98
17
from generators with certain characteristics, the avoided cost rates can reflect prices available to
generators with those characteristics.102 Thus, FERC determined that “the concept of a multitiered avoided cost rate structure can be consistent with the avoided cost rate requirements set
forth in PURPA and our regulations.”103
On January 20, 2011, FERC denied the petition by the California utilities for a rehearing and
confirmed that the concept of a multi-tiered avoided cost system is permissible.104 Due to the
significant departure from the traditional view of avoided cost, a portion of FERC’s January 20,
2011 order warrants review:
Because avoided cost rates are defined in terms of costs that an electric utility
avoids by purchasing from a QF, and because a state may determine what
particular capacity is being avoided, the state may rely on the cost of such avoided
capacity to determine the avoided cost rate. Thus, the avoided cost rate may take
into account the cost of electric energy from the generators being avoided, e.g.,
generators with certain characteristics. . . . [W]here a state requires a utility to
procure energy from generators with certain characteristics, generators with those
characteristics constitute the sources that are relevant to the determination of the
utility’s avoided cost for that procurement requirement. Thus, the guidance
proved by the Commission in this proceeding simply reflects the reality that states
have the authority to dictate the generation resources from which utilities may
procure electric energy. . . . And while in theory a utility might have a cheaper
source of capacity and/or energy available to the electric utility to it, in calculating
an avoided cost rate a state may properly look at the actual [renewable] sources of
capacity and/or energy available to the electric utility, rather than at some
theoretical source, which is not permitted by state law, that may be cheaper.105
The October 21, 2010 and January 20, 2011 FERC orders expanding the interpretation of
avoided cost under PURPA provide a path for states to create multiple tiers of differentiated
avoided cost rates for renewables—as long as the program is implemented under PURPA and
the sellers are QFs. By allowing a multi-tiered avoided cost system based on generators with
102
California Public Utilities Commission, 133 FERC ¶ 61,059 (October 21, 2010).
Id. at ¶ 61,266.
104
California Public Utilities Commission, 134 FERC ¶ 61,044 (January 20, 2011).
105
Id. at ¶61,160.
103
18
certain characteristics, the avoided cost rate paid to a type of renewable generator is based on the
market price of that type of renewable energy, and not on the price of a different, cheaper source
of power from the state’s general energy mix, such as natural gas or coal. Thus, states can now
use their authority under PURPA to implement FITs with avoided cost rates that are high enough
to support renewable generators.
For example, a state could specify that electric utilities have to purchase five percent of
energy from wind generators under 20MW. Here, the avoided cost rate would be based on the
price of the cheapest wind power produced by generators under 20 MW instead of the price of
the cheapest power generally available in the market. Note though, that the purchasing utilities
would only have to pay the differentiated rate until they meet the statutory requirement, after
which the avoided cost rate would revert back to price of the cheapest power available generally
in the state.
The extent of the differentiation of the avoided cost rates would depend on the number of
purchase requirements specified by the state, but the potential combinations are limitless. In the
example above, the differentiated avoided cost rate might be sufficient to support some wind
generators but not others because the differentiated avoided cost rate would be based on the
cheapest power produced by any wind generator less than 20 MW. This rate might only be high
enough to support generators above a certain size, within the 20 MW threshold, that can take
advantage of economies of scale. Therefore, a state might want to enable differentiated avoided
cost rates that better support renewable generators of various sizes. Nothing in the FERC orders
allowing differentiated avoided cost rates inhibits states from requiring utilities to purchase from
QFs with certain source and size characteristics. For example, a state could require electric
utilities to purchase 50 MW of electricity from solar PV systems with 1 to 5 MW of capacity and
19
25 MW of electricity from solar PV systems with 1 to 100 kW of capacity.106 The avoided cost
rate would be based not only on the price of solar power, but also on the price of solar power
generated by systems of a certain size. In this way, states can narrowly tailor the QF purchase
requirements under the PURPA framework to implement FITs that can effectively support
renewable energy generators targeted for development within that state.
Overall, the recent FERC orders provide states with a roadmap on how to implement FITs
that are compliant with the FPA and PURPA. These orders enable states to establish avoided cost
rates sufficient to promote renewable energy development by permitting differentiated avoided
cost calculations. In order to implement a multi-tiered avoided cost structure, statutory language
at the state level must require that electric utilities purchase a specified amount of energy from
generators with certain characteristics that are eligible for QF status under PURPA.
B. The Energy Policy Act’s Elimination of the Mandatory Purchase Obligation: A Potential
Barrier, but Not a Deal-Breaker to State-Level Feed-in Tariffs Under the PURPA
Framework
Even if a state meets the requirements necessary to enable a differentiated avoided cost
structure, the extent to which a state is able to implement a FIT program may still be limited by
the Energy Power Act’s reduction of the scope of PURPA’s mandatory purchase obligation from
QFs with nondiscriminatory access to the market. As discussed in Part C of Section II, the
Energy Policy Act of 2005 revised PURPA to enable the termination of the mandatory power
purchase obligation to purchase electric energy from QFs by electric utilities if FERC finds that
the QFs have nondiscriminatory access to markets. This elimination, as also discussed, of the
purchase obligation applies within the context of two rebuttable presumptions: 1) that QFs with a
106
Jennifer Gleason, Adopting State Feed-In Tariff Laws without Preemption (Jan. 2012),
http://www.elaw.org/system/files/fed.preemption.jan19.2012.pdf.
20
net capacity over 20 MW have nondiscriminatory access to wholesale markets;107 and 2) that
QFs with a net capacity no greater than 20 MW do not have nondiscriminatory access to
wholesale markets.108 Thus, for states in the PJM, Midwest ISO, ISO-NE, and NYISO, the
potential elimination of PURPA’s mandatory purchase obligation could undercut the purpose of
a FIT. Indeed, why go through the effort of enacting legislation to enable a differentiated avoided
cost structure if the electric utilities can simply apply for an exemption to the mandatory
purchase obligation?
Although the electric utilities within the PJM, Midwest ISO, ISO-NE, and NYISO may seek
the elimination of PURPA’s mandatory purchase obligation, recent cases suggest that FERC will
closely examine whether the QFs at issue actually have nondiscriminatory access to the
wholesale market. For instance, three recent cases – The Detroit Edison Company, New York
State Electric & Gas Corporation and Rochester Gas and Electric Corporation, and Public
Service Company of New Hampshire – highlight some of the factors FERC examines when
determining whether to grant a utility’s request for relief from the mandatory purchase
obligation.109
In The Detroit Edison Company, the utility Detroit Edison petitioned FERC seeking
termination of the obligation to enter into new power purchase obligations from QFs with net
capacity in excess of 20 MW on a service territory-wide basis for its interconnected system
under the control of the Midwest ISO.110 FERC granted Detroit Edison’s request to terminate the
mandatory purchase obligation pursuant to section 210(m) of PURPA with respect to all QFs
107
18 C.F.R. § 292.309.
Id.
109
The Detroit Edison Co., 131 FERC ¶ 61039 (Apr. 15, 2010); New York State Elec. & Gas Corp. & Rochester Gas
& Elec. Corp., 130 FERC ¶ 61216 (Mar. 18, 2010); Pub. Serv. Co. of New Hampshire, 131 FERC ¶ 61027 (Apr. 15,
2010).
110
The Detroit Edison Co., 131 FERC ¶ 61039, 61251 (Apr. 15, 2010).
108
21
larger than 20 MW net capacity.111 In granting the utility’s request for relief, FERC specifically
noted that the utility had provided notice to all QFs affected, that existing interconnection
agreements between the QFs and the utility would not be disrupted, and that only one of the
affected QFs had even attempted to rebut the presumption that they had nondiscriminatory
access to the wholesale market.112
Similarly, in New York State Electric & Gas Corporation and Rochester Gas and Electric
Corporation, two utilities sought the termination of the purchase obligations from QFs with net
capacity in excess of 20 MW on a service territory-wide basis for its interconnected system
under the control of the NYISO.113 However, unlike FERC’s decision in The Detroit Edison
Company, FERC only granted partial relief from the purchase obligation.114 Cornell University,
the owner and operator of an approximately 40 MW cogeneration facility located on its campus,
filed a protest to rebut the presumption that it had nondiscriminatory access to the wholesale
market.115 In its decision, FERC denied the request for relief by the utilities as applied to the
Cornell cogeneration facility.116 FERC noted that the presumptions were not final
determinations, and that there may be circumstances unique to a particular QF that interferes
with the QF's nondiscriminatory access.117 Here, FERC noted that Cornell's cogeneration facility
serves its campus steam load, which is “highly variable,” depending on local weather conditions,
resulting in electric output that is, “on a daily basis, highly variable and unpredictable.”118 This
variable output, FERC explained, exposed Cornell to penalties for its under-generation compared
111
Id. at 61252.
Id. at 61253.
113
New York State Elec. & Gas Corp. & Rochester Gas & Elec. Corp., 130 FERC ¶ 61216, 61981 (Mar. 18, 2010).
114
Id.
115
Id. at 61982.
116
Id.
117
Id. at 61983.
118
Id.
112
22
to its bids in the NYISO day-ahead market.119 It also denied Cornell compensation for overgeneration because NYISO's markets tie participation to power offered into the market the day
before.120 FERC concluded that these factors “effectively denied [Cornell] nondiscriminatory
access to NYISO's markets,” therefore the utilities were not relieved of their obligation to
purchase power from the facility.121
The two cases above involve utilities seeking termination of the mandatory purchase
obligation from QFs with a net capacity in excess of 20 MW, in which case there is a rebuttable
presumption that the QFs have nondiscriminatory access to the wholesale market. In Public
Service Company of New Hampshire, FERC considered the utility’s request to terminate the
purchase obligation for QFs in excess of 20 MW net capacity, as well as those QFs with a net
capacity below 20 MW in its service territory within the ISO-NE.122 FERC, finding that the QFs
larger than 20 MW net capacity had nondiscriminatory access to the wholesale market and
granted the utility’s request.123 However, FERC denied the request as it pertained to QFs with
less than 20 MW net capacity.124 FERC explained that the utility failed to rebut the presumption
that QFs with less than 20 MW net capacity lack nondiscriminatory access to the market. 125 The
utility had attempted to rebut this presumption by highlighting a number of QFs under 20 MW
that allegedly had full access to the market.126 This, however, was inadequate. FERC instead
pointed out that in order for a utility to rebut the presumption that QFs less than 20 MW do not
have nondiscriminatory access to the market, an electric utility must demonstrate
119
New York State Elec. & Gas Corp. & Rochester Gas & Elec. Corp., 130 FERC ¶ 61216, 61984 (Mar. 18, 2010).
Id.
121
Id.
122
Pub. Serv. Co. of New Hampshire, 131 FERC ¶ 61027, 61182 (Apr. 15, 2010).
123
Id. at 61184.
124
Id.
125
Id.
126
Id.
120
23
nondiscriminatory market access “with regard to each small QF.” 127 Merely showing that some
QFs had nondiscriminatory access was not enough.
These cases suggest that FERC may be cautious when faced with eliminating the mandatory
purchase obligation. In instances where the request for relief is granted for QFs larger than 20
MW, Public Service Company of New Hampshire demonstrates that FERC may still preserve the
purchase obligation for QFs with a net capacity less than 20 MW.128 The decisions by FERC in
The Detroit Edison Company and New York State Electric & Gas Corporation and Rochester
Gas and Electric Corporation, further suggest that utilities may choose to only seek relief from
the obligation to purchase power from QFs larger than 20 MW, and not pursue relief from the
obligation to purchase from smaller QFs.129 Indeed, since a utility must show that “each small
QF” has nondiscriminatory access, rather than generally demonstrating market access, it may not
be cost-effective for a utility to seek relief from the obligation to purchase from every single
small QF.
Given these considerations, states located in the PJM, Midwest ISO, ISO-NE, and NYISO
may still find it worthwhile to implement a FIT program to encourage renewable energy
development. This may especially be the case for states seeking to use a FIT to spur small-scale
renewable distributed generation because the FERC cases suggest that there is a good chance that
the purchase obligation would remain intact. The subsection below uses Ohio as a case study to
examine how the various factors discussed in the sections above may be at play when a state
seeks to use the recent FERC orders to implement FITs to support renewable energy
development. The example below will first analyze Ohio’s policy renewable energy policy
127
Id. at 61184.
Pub. Serv. Co. of New Hampshire, 131 FERC ¶ 61027, 61185 (Apr. 15, 2010).
129
The Detroit Edison Co., 131 FERC ¶ 61039 (Apr. 15, 2010); New York State Elec. & Gas Corp. & Rochester Gas
& Elec. Corp., 130 FERC ¶ 61216 (Mar. 18, 2010).
128
24
objectives and whether the state’s current statutory language could be used to implement a multitiered avoided cost structure. In addition, the example below will suggest how a limited, targeted
FIT might best advance the Ohio’s renewable energy objectives and best limit the risk that the
state’s electric utilities would be relieved of the purchase obligation.
C. From Theory to Application: Ohio as a Case Study Examining How States Could Use
Their New Authority Under the FERC Orders
Renewable energy project development is becoming an increasingly important sector of
Ohio’s economy.130 It may then be worthwhile for Ohio to examine the use of FITs to further
accelerate the growth of its renewable energy sector. Further, Ohio is located within the PJM, the
world’s largest competitive wholesale electricity market in the world.131 Thus Ohio is, as it is so
often, a useful gauge for examining policies and practices that could have national implications.
However, any effort to capitalize on the recent FERC orders and implement a FIT program in
Ohio will face a few significant challenges. First, the extent to which Ohio is able to implement a
FIT under PURPA is limited by the Energy Policy Act. Second, as currently written, the state’s
Renewable Portfolio Standard (RPS) does not provide the authority for the Public Utilities
Commission of Ohio (PUCO) to implement a FIT under PURPA. Thus, any attempt to
implement a FIT program in Ohio would require changes by the Ohio Legislature.
130
See MARK MURO, JONATHAN ROTHWELL & DEVASHREE SAHA, SIZING THE CLEAN ECONOMY: A NATIONAL AND
REGIONAL GREEN JOBS ASSESSMENT 51, BROOKINGS INSTITUTE (2011). A recent paper by the Brookings Institute
ranked Ohio as 6th in the nation in terms of jobs in the “clean economy.” See also, Keith Schneider, Midwest
Emerges as Center for Clean Energy, N.Y. TIMES, Nov. 30, 2010, available at
http://www.nytimes.com/2010/12/01/business/energy-environment/01solarcell.html. Toledo has become a national
leader in solar energy research and development.
131
PJM Real Time Economic Demand Response Program, PJM, http://www.pjm.com/~/media/markets-ops/dsr/dsrbrochure.ashx (last visited May 29, 2012).
25
Ohio’s electric utilities and QFs are located within the PJM.132 The PJM was determined by
FERC to meet the criteria of having nondiscriminatory access to wholesale markets. 133 Any FIT
program implemented by Ohio under its PURPA authority would be limited in scope due to the
Energy Policy Act’s termination of the purchase requirement by electric utilities from QFs over
20 MW in areas where QFs have nondiscriminatory access to wholesale markets. QFs with a
capacity over 20 MW would need to demonstrate to FERC, in the event of a utility petition for
relief from the purchase obligation, that they do not actually have nondiscriminatory access to
the wholesale market.134 Further, although a FIT program implemented by Ohio under PURPA
could require electric utilities to purchase power from QFs with a capacity less than 20 MW, the
obligation to purchase from these QFs would be terminated if the electric utilities could
demonstrate to FERC that the QFs had nondiscriminatory access to wholesale markets.135
For Ohio to implement a FIT program under its PURPA authority, additional legislation
would need to be passed to trigger the state’s wholesale rate-setting authority under PURPA and
give the PUCO statutory authority to set differentiated avoided cost rates. In 2008, Ohio adopted
a RPS that required electric utilities to provide twenty-five percent of their retail electricity
supply from advanced energy sources by 2025.136 Half of this amount, twelve and a half percent,
must come from renewable resources.137 Further, at least fifty percent of the renewable energy
132
Regional Transmission Organizations (RTO)/Independent System Operators, FERC (Dec. 29, 2011),
http://www.ferc.gov/industries/electric/indus-act/rto.asp.
133
18 C.F.R. § 292.309(e).
134
Id.
135
Id.
136
Ohio Rev. Code Ann. §§ 4928.64, 4928.01 (West 2012). “Advanced energy resource” includes clean coal
technology, advanced nuclear energy technology, and fuels cells.
137
Id. “‘Renewable energy resource’ means solar photovoltaic or solar thermal energy, wind energy, power
produced by a hydroelectric facility, geothermal energy, fuel derived from solid wastes . . . through fractionation,
biological decomposition, or other process that does not principally involve combustion, biomass energy,
biologically derived methane gas, or energy derived from non-treated by-products of the pulping process or wood
manufacturing process, including bark, wood chips, sawdust, and lignin in spent pulping liquors. ‘Renewable energy
resource’ includes, but is not limited to, any fuel cell used in the generation of electricity, including, but not limited
to, a proton exchange membrane fuel cell, phosphoric acid fuel cell, molten carbonate fuel cell, or solid oxide fuel
26
requirement must be met by in-state facilities; the remaining fifty percent may be met by
resources that can be shown to be deliverable into the state.138 The RPS also contains a specific
benchmark of one half percent solar power by 2025.139 Utilities must meet annual benchmarks
for both the renewable energy requirement and the solar carve-out.140 Failure to meet these
benchmarks may result in financial penalties.141
As currently written, Ohio’s RPS does not authorize the use of FITs under PURPA. First, the
RPS does not require that the energy come from QFs under 20 MW. Further, regulated utilities
may comply with the RPS requirement through the procurement of Renewable Energy Credits
(RECs) rather than through direct purchases of power from renewable sources. 142 Therefore, the
RPS does not constitute the express statutory requirement to purchase renewable energy that
would be required to implement a FIT.143
This is not to say that a FIT program would be incompatible with Ohio’s RPS. The
differences between the two mechanisms – a RPS mandates the amount of customer demand that
must be met with renewables, whereas a FIT program promotes supply development – may be
complementary. Within a RPS framework, narrowly tailored FIT policies can be used to meet
RPS targets.144 For example, FIT policies can provide the investment security needed in order to
cell; wind turbine located in the state's territorial waters of Lake Erie; methane gas emitted from an abandoned coal
mine; storage facility that will promote the better utilization of a renewable energy resource that primarily generates
off peak; or distributed generation system used by a customer to generate electricity from any such energy.”
138
Ohio Rev. Code Ann. §§ 4928.64 (West 2012).
139
Id.
140
Id.
141
Id. In some circumstances, a utility failing to meet the benchmarks may be fully or partially relieved from the
penalties by requesting that the PUCO make a force majeure determination that the utility had made a good faith
effort to comply.
142
Id. Ohio’s RPS only requires that “an electric services company shall provide a portion of its electricity supply
for retail consumers in this state from alternative energy resources . . . .” This is not a direct purchase requirement;
rather regulated utilities can meet their obligations through the acquisition of RECs.
143
See infra p. 17.
144
See CORY, supra note 6 at 9.
27
ensure that enough supply will be available.145 Because FIT policies can complement the
overarching goals of a RPS, Ohio may benefit from a limited FIT program. In particular, the
solar-carve out within Ohio’s RPS may be ripe for a narrowly tailored FIT.
Since the implementation of the RPS, Ohio’s regulated electric utility companies have
generally been able to meet the annual non-solar benchmarks. However, some electric utilities
have struggled to meet the solar benchmark requirements.146 Frequently, the electric utilities
failing to comply with the solar benchmarks cited a lack of existing solar generation in Ohio.147
The limited supply of solar generation in Ohio is demonstrated by the fact that the Ohio
utilities failing to meet the overall solar benchmark were often able to acquire sufficient out-ofstate solar resources.148 It is also demonstrated by the market price for solar-RECs (SRECs). For
example, the 2011 cost of a SREC from Pennsylvania was between $20-100.149 In contrast, the
2011 cost of a SREC from Ohio was between $300-375.150 Although many factors can affect the
price of SRECs, market supply is often a primary driver behind SREC prices.151
A limited FIT program to increase Ohio-generator solar power could help address the
difficulties that some electric utilities have had in meeting RPS in-state solar benchmarks by
encouraging in-state solar generation. This would increase the supply of SRECs generated instate, thereby lowering the high cost of market SRECs. In addition, the increase in solar energy
145
Grinlinton, supra note 6 at 948.
See Dan Gearino, Solar Energy is a Rising Start in Ohio, THE COLUMBUS DISPATCH, July 18, 2010, available at
http://www.dispatch.com/content/stories/business/2010/07/18/brightening-outlook.html.
147
Il2011 WL 2160207 (Ohio P.U.C.).
148
Id.
149
Flett Exchange: Pennsylvania SRECs, FLETT EXCHANGE, http://markets.flettexchange.com/pennsylvania-srec/
(last visited Jan. 10, 2012).
150
Flett Exchange: Ohio SRECs, FLETT EXCHANGE, http://markets.flettexchange.com/ohio-srec/ (last visited Jan.
10, 2012).
151
See Renewable Energy Credits: Why Have New Jersey SREC Prices Plummeted?, ENTER SOLAR (Aug. 19, 2011),
http://www.entersolar.com/nj-srecs-supply-and-demand/; Daniel Yonkin, Why Spot SREC Prices Have Dropped in
PA & Adjacent Markets, RENEWABLE ENERGY WORLD.COM (April, 1 2011),
http://www.renewableenergyworld.com/rea/blog/post/2011/03/why-spot-srec-prices-have-dropped-in-pa-adjacentmarkets.
146
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project development could also be beneficial to Ohio’s growing and increasingly important solar
industry.152 Because the RPS in-state solar benchmarks are relatively low, a complementary FIT
program could also be relatively small in scope. Such a targeted and limited FIT program would
avoid the market disruptions and high costs associated with poorly designed and overly
aggressive FIT policies.153
Because Ohio is within the PJM, any FIT program developed by the state under the auspices
of PURPA faces the risk that the utilities will seek and be granted the termination of the purchase
obligation. However, as examined in Section III, Part B of this paper, FERC may be cautious in
its determination of whether to terminate the purchase obligation between the utility and QF.
Since the passage of the Energy Policy Act, only two of Ohio’s electric utilities have applied to
FERC for the termination of the purchase obligation.154 Both applications only sought relief from
the obligation to purchase power from QFs with a net capacity greater than 20 MW.155
Granted, an increase in renewable energy development activity due to the implementation of
a FIT program could motivate the remaining Ohio electric utilities to also seek relief from the
purchase obligation. However, this risk could be mitigated. First, the state FIT program could be
limited to QFs with a net capacity less than 20 MW. By limiting the FIT’s application to smaller
QFs, the electric utilities would have to affirmatively demonstrate that each QF has
nondiscriminatory access to the market. This burden, coupled with moderate program caps and
tariff rates, may be enough dissuade the utilities from incurring the costs of seeking relief from
the obligation to purchase power from small QFs. Thus, a limited FIT, perhaps to target Ohio’s
solar power objectives, could be both a feasible and worthwhile policy mechanism for Ohio.
152
See Dan Gearino, supra note 103.
See infra pp. 5–8.
154
See FERC eLibrary, FERC, http://elibrary.ferc.gov/idmws/search/advResults.asp (last visited May 28, 2012).
155
Id.
153
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IV. CONCLUSION: CONGRESS SHOULD GRANT STATES ADDITIONAL REGULATORY FLEXIBILITY
AND AUTHORITY TO INCENTIVIZE QUALIFYING FACILITIES
The recent FERC orders reinterpreting the meaning of avoided cost opened the door for
states to use their authority under PURPA to implement FITs with avoided cost rates that are
high enough to support renewable generators.156 However, as the case study above demonstrates,
the process of harnessing this authority in order to implement renewable energy FITs can be
arduous. Not only is precise statutory language required to trigger the authority to set
differentiated avoided cost rates, but many states would also be subject to the risk of the
termination of the purchase obligation. Therefore, although the recent FERC orders present
intriguing possibilities for state-level renewable FITs, the nuanced legal and policy navigation
required to implement such FITs pose barriers to state policymaking flexibility—barriers that are
perhaps unnecessary.
Rather, Congress should legislatively grant states complete rate-setting authority for
purchases of electricity from QFs. This jurisdictional carve-out to states would liberate them
from the constraints of ensuring that rates are set at the avoided cost. Indeed, the core of this
paper derives from the fact that the meaning of avoided cost has been a consistent source of
confusion and litigation. Granting the states clear authority to set rates would eliminate this
source of uncertainty.
There are a number of advantages to granting states greater authority and autonomy to set
rates within the PURPA framework. First, states would have increased regulatory flexibility to
experiment, if a particular state so chooses, with various FITs to encourage certain types of
renewable energy development. Such experimentation will allow states to learn from each other
156
See supra, p. 18.
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through the exchange of best practices, as well as provide insight to policymakers at the federal
level. Indeed, such an approach embodies Justice Brandeis’ notion of states acting as a
“laboratory” of economic experiment:
There must be power in the states and the nation to [remold], through
experimentation, our economic practices and institutions to meet changing social
and economic needs. . . . It is one of the happy incidents of the federal system that
a single courageous state may, if its citizens choose, serve as a laboratory; and try
novel social and economic experiments without risk to the rest of the country.157
In addition to the policy lessons and innovations that can be gleaned from greater state
authority within the PURPA framework, the deficit of federal leadership concerning a national
long-term renewable energy policy begs for, to an extent, greater latitude for states. Further, in
context of FITs, state-level FITs may be preferable to a federal-level FIT.158 There are legitimate
ideological and economic differences of opinion concerning whether FITs are appropriate as a
policy mechanism to promote renewable energy.159 Also, as discussed in Section I, Part A, of
this paper, FITs can be problematic if not properly designed.160 A state-empowered approach
would thus permit FIT policy experimentation without, as Justice Brandeis observed, “. . . risk to
the rest of the country.”161
There are potential objections to granting states complete rate-setting authority for purchases
of electricity from QFs. Without the limitation of staying within the meaning of avoided cost
when setting the rates for purchases of electricity from QFs, states could technically permit
157
New State Ice Co. v. Liebmann, 285 U.S. 262, 311 (1932) (Brandeis, J., dissenting).
See H.R. 6401: Renewable Energy Jobs and Security Act, http://www.govtrack.us/congress/bill.xpd?bill=h1106401 (last visited May 10, 2012). This proposed legislation would have implemented FITs, would have granted ratemaking authority to FERC instead of states. The legislation failed to reach a vote.
159
See CLEAN Sweep: Feed-in Tariff Rates Build Stable Clean Energy Markets and Boos Local Economy, THINK
PROGRESS (Mar. 20, 2012), http://thinkprogress.org/climate/2012/03/20/446766/clean-sweep-feed-in-tariffs-buildstable-clean-energy-markets-and-boost-local-economies/?mobile=nc. See also John Entine, Feed-in Tariffs: Solar
Energy Bubble About to Burst, AMERICAN ENTERPRISE INSTITUTE (May 5, 2010), http://www.aei.org/article/energyand-the-environment/alternative-energy/solar/feed-in-tariffs-solar-energy-bubble-is-fit-to-burst/.
160
See supra, pp. 7–8.
161
New State Ice, 285 U.S. at 311(Brandeis, J., dissenting).
158
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dramatic cost increases. However, this risk is easily mitigated. First, at the federal level, any
Congressional authorization for states to have broader rate-setting authority can be limited to
QFs of a certain size. For example, states could be authorized to only set rates above the avoided
cost for purchase of electricity produced by QFs with a net capacity less than 10 MW.162 This
would enable states to promote distributed generation of renewables through FITs while also
mitigating the extent to which a poorly designed FIT could negatively affect the broader market.
Second, the states themselves are likely to be the most effective means of ensuring that FITassociated costs do not, over the long-term, become too costly because state lawmakers will
ultimately face the political consequences for FIT associated costs that a state’s voters deem to
be too high.
The United States faces difficult choices as it seeks to move to cleaner energy sources. While
FITs are unlikely to be a policy silver-bullet, the costs and benefits of FITs deserve to be closely
examined. Because of the recent FERC orders, regardless of whether Congress eventually
expands state authority, states now have the legal means to implement FITs to encourage
renewable energy development through their rate-setting authority under the PURPA framework.
Let the experiment begin.
162
See S. 1491: PURPA Plus Act, http:govtrack.us/congress/bills/112/s1491/text (last visited May 25, 2012). This
proposed legislation would allow states to set rates that exceed the incremental cost of alternative electric energy for
purchases from any QF of not more than 2 MW net capacity. This legislation has been introduced to committee but
not voted on.
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