Feed-In Tariffs and Implications for Public Power
Justin Wynne
APPA Legal Seminar
Memphis, TN
November 9, 2011
Braun Blaising McLaughlin, P.C.
915 L Street, Suite 1270
Sacramento, CA, 95184
(916) 326-5813
[email protected]
1
I.
INTRODUCTION
More than thirty States have some form of a renewable portfolio standard (“RPS”),
requiring electric utilities to procure a certain minimum amount of electricity from renewable
sources.1 There are a variety of mechanisms that utilities can use to increase the amount of
renewable power in their portfolios. One such mechanism that is becoming increasingly popular
is the use of a feed-in tariff. Feed-in tariffs can be mandated by a state government or can be
adopted by publicly owned utilities (“POUs”). However, because feed-in tariffs set wholesale
power rates, they necessarily implicate issues of federal preemption. This paper provides a
summary of recent Federal Energy Regulatory Commission (“FERC”) decisions that impose
significant restrictions on the acceptable feed-in tariff designs.
II.
OVERVIEW OF FEED-IN TARIFFS
A. Definition of a Feed-In Tariff
The term “feed-in tariff” encompasses a broad spectrum of mechanisms used to support
the development of certain types of resources, primarily renewable resources. In general, a feedin tariff involves a mandate that a utility offer a long-term purchase agreement for the entire
output of an eligible generator.2 Feed-in tariffs also often include guaranteed access to the grid.3
1
See generally, Ivan Gold & Nidhi Thakar, A Survey of State Renewable Portfolio Standards: Square for Round
Climate Change Holes?, 35 Wm. & Mary Envtl. L. & Pol’y Rev. 183 (2010). The following is a list of states that
have a mandatory RPS and the associated goals: Arizona – 15% by 2025; California – 33% by 2020; Colorado –
30% by 2020 for IOUs and 10% by 2020 for POUs; Connecticut – 23% by 2020; Delaware – 20% by 2019;
District of Columbia – 20% by 2020; Florida – 7.5% by 2015; Hawaii – 25% by 2020; Illinois – 25% by 2020;
Iowa – 105 MW goal; Kansas – 20% by 2020; Maine – 30% total and 10% new generation by 2017; Maryland –
20% by 2022; Massachusetts – Existing 7.1% plus 15% new generation by 2020; Michigan – 10% by 2015;
Minnesota – 30% by 2020 for Xcel and 25% by for all others; Missouri – 15% by 2021; Montana – 15% by 2015;
New Hampshire – 23.9% by 2021 and 16% new generation by 2025; New Jersey – 22.5% by 2020; New Mexico –
20% by 2020; Nevada – 18% by 2013 and 25% by 2025; New York – 30% by 2015 and 10% new generation by
2015; North Carolina – 12% by 2021 for IOUs and 10% by 2018 for POUs; Ohio – 12.5% by 2025; Oregon –
25% by 2025 for large entities, 10% by 2025 for small entities, and 5% by 2025 for the smallest entities;
Pennsylvania – 18% by 2020; Road Island – 16% by 2019; Texas – 10,000 MWs by 2025; Washington – 15% by
2020; Wisconsin – 10% by 2015. Id. at 196-204. Seven states also have voluntary RPSs. Id. at 205.
2
A number of different sources provides differing definitions of a feed-in tariff. A recent report provides the
following definition: “a publicly available, legal document, promulgated by a state utility regulatory commission or
2
There are a wide variety of pricing methods, however, most feed-in tariffs fall into one of
two pricing categories: (1) pricing based on the cost of the generation; or (2) pricing based on the
value of the energy.4 Under a program where pricing is based on the cost of the generation, the
fixed price is based on a levelized cost of generation plus a fixed rate of return.5 The cost of
generation can be either technology specific or based on a generic value of renewable energy.6
Under a program where pricing is based on the value of the energy, the pricing is typically based
on the utility’s avoided costs.7 In some cases, the avoided cost is subsidized with a payment for
the renewable attributes of the energy.8
B. Advantages and Disadvantages of Feed-In Tariffs
The primary goal of a feed-in tariff is to stimulate certain types of generation by
providing a stable, long-term source of revenue. The assumption is that this provides investors
with the proper incentives to develop and operate the desired types of generation.9 Another
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..” Scott
Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and Possible
Solutions, January 2010 at 2.
3
Karlynn Cory, Toby Couture, & Claire Kreycik, Feed-In Tariff Policy: Design, Implementation, and RPS Policy
Interactions, March 2009 at 2.
4
Id.
5
Id.
6
Id.
7
Id.
8
Id.
9
See Toby Couture, Claire Kreycik, & Emily Williams, A Policy Maker’s Guide to Feed-In Tariff Policy Design,
July 2010 at 9 (“Experience in Europe is beginning to demonstrate that due to the stable investment environment
created under well-designed FIT policies, renewable energy development and financing can happen more quickly
and often more cost-effectively than under competitive solicitations . . . . In addition, the guaranteed contract terms
enable project developers to finance a larger proportion of the project with debt financing, as opposed to equity,
which puts further downward pressure on the cost of capital . . . . One of the most important elements of FIT design
is the guarantee of reliable revenue streams . . . . This has helped catalyze renewable energy development in
countries such as Germany, where both small and large developers can invest for a profit in renewable energy
technology. And the fact that FIT policies are generally designed to cover the cost of the renewable energy project,
plus a reasonable return, helps ensure that the costs to society of RE development are minimized.”) (internal
citations omitted).
3
primary goal of a feed-in tariff is to stimulate the local economy by incentivizing the
construction of local energy resources.10
The main arguments against feed-in tariffs are that they can lead to increased energy
prices.11 Additionally, they do not address the high upfront costs of developing renewable
energy.12 Guaranteed interconnection policies could lead to resources interconnecting at less
optimal locations than would otherwise be chosen.13 It is also difficult to set the feed-in tariff
payments at the correct level.14 They must be high enough to stimulate new generation but not
so high as to be a windfall for generators.
C. Compared to Other Incentives
It is useful to compare feed-in tariffs to other mechanisms that can be used to stimulate
the construction of renewable energy resources. The following descriptions summarize other
popular mechanisms available to utilities.
1. Net Energy Metering
Forty-three states have enacted some form of net energy metering.15 Net energy metering
permits eligible customers to offset their electric utility bill with the electricity produced by a
small scale renewable energy resource installed behind the meter on their property, typically
solar or wind.16 Under most state programs, the utility customer receives a complete kWh to
10
Id. at 11.
Id. at 12.
12
Id.
13
Id. at 13.
14
Karlynn Cory, Toby Couture, & Claire Kreycik, Feed-In Tariff Policy: Design, Implementation, and RPS Policy
Interactions, March 2009 at 2.
15
See Database of State Incentives for Renewables &Efficiency, available at
http://www.dsireusa.org/incentives/index.cfm?EE=1&RE=1&SPV=0&ST=0&searchtype=Net&sh=1.
16
See National Renewable Energy Laboratory, Million Solar Roofs Case Study, DOE/GO-102005-2192, September
2005, (“What is Net Metering?: For those consumers who have their own electricity generating units, net metering
allows for the flow of electricity both to and from the customer through a single meter. With net metering, during
times when the customer’s generation exceeds his or her use, electricity from the customer to the utility offsets
electricity consumed at another time. In effect, the customer is using the excess generation to offset electricity that
11
4
kWh offset of their utility bill. This provides a significant benefit to the customer because they
are essentially paid the full retail rate for the generation of their renewable resource. However,
some programs pay the customer based on a rate set at the utility’s avoided costs. Net energy
metering programs typically include a program cap based on a percentage of the individual
utility’s peak load. For most states this cap falls somewhere between 0.5 and 2 percent. Nearly
every state imposes some form of size restriction on eligible facilities, and these range from 0.1
kW to 2 MWs.17
Under California’s net energy metering law, customer accounts are trued up at the end of
a 12-month cycle.18 If the customer has produced excess electricity, then the customer is paid
according to a rate set by the local governing board of the POU, or the California Public Utilities
Commission (“CPUC”) for the investor owned utilities (“IOUs”).19 However, to be eligible
customers must have their generating unit sized to their consumption level. This makes the
likelihood of excess generation being produced unlikely.
2. Installation Incentives
The most common mechanism for encouraging the development small scale renewable
generation is an incentive payment made on a per installed watt basis. Virtually every state in
the country has some form of installation incentive for some renewable technologies, typically
solar.20 One example is the California Solar Initiative (“CSI”),21 which was enacted in 2006 and
requires publicly owned utilities to establish a solar generation incentive program where the
would have been purchased at the retail rate. Under most state rules, residential, commercial, and industrial
customers are eligible for net metering, but some states restrict eligibility to particular customer classes.”).
17
Some States have much higher size limitations, but only pay customers based on avoided costs rates rather than
the full retail rate.
18
Cal. Pub. Util. Code § 2827(b)(5).
19
Id. § 2827(h)(4)(A).
20
See Generally DSIRE Database of State Incentives for Renewable and Efficiency, available at
http://www.dsireusa.org/.
21
Stats. 2006 ch. 132, SB 1.
5
utility pays a customer $2.80 per installed watt for eligible solar energy systems.22 As with
California’s net energy metering program, in order for the customer to receive this incentive
payment, the solar energy system must be sized to offset the customer’s demand, rather than to
sell excess energy to the utility.23
D. History of Feed-In Tariffs
1. Origins in Europe
Germany adopted the first modern feed-in tariff in 1990, requiring utilities to buy
renewable energy from eligible generators based on a fixed percentage of the retail electricity
price.24 This percentage varied based on the type of resource and the size of in the installation.
These percentages ranged from 65-90 percent.25 In 2000, Germany adopted a new feed-in tariff
pricing model, which set prices according to the cost of generation plus a rate return rather than
retail prices.26 Under this new feed-in tariff, the rate was set based on the year that the project
goes online and then decreases each year over a term of 20 years. The new German program
also expanded access to the program and gave renewable energy generators priority access to the
electric grid.27 This combination of a fixed long-term rate based on the cost of generation plus a
rate of return adder combined with preferential access to the grid is credited with Germany’s
success in increasing its renewable generation. Germany’s renewable energy production as a
share of total energy consumption went from 4.7 percent in 1998 to 17 percent in 2010.28 In
22
Cal. Pub. Util. Code § 387.5(b).
Id. at § 387.5(d)(2).
24
Miguel Mendonca, Feed-in Tariffs: Accelerating the Deployment of Renewable Energy, 2007 at 27.
25
Id. at 28.
26
Id. at 30-31.
27
Id.
28
Federal Ministry for the Environment, Nature Conservation and Nuclear Safety, Renewable Energy Sources in Figures: National and International Development, July 2011,available at http://www.erneuerbare‐
energien.de/files/english/pdf/application/pdf/broschuere_ee_zahlen_en_bf.pdf. 23
6
2010, the average cost of Germany’s feed-in tariff program was 2.3 Euros per household, at a
total cost of 9.4 Billion Euros for the total program for 2010.29
In contrast to Germany, Spain’s feed-in tariff laws are generally viewed as a cautionary
story. In 2007, Spain’s feed-in tariff law was amended to fix prices at a premium above spot
market prices.30 These rates were guaranteed for a period of 25 years.31 However, Spain did not
include a program cap.32 When the global economy faltered in 2007, Spanish investors flocked
to the stable investment opportunity offered by Spain’s feed-in tariff law.33 Spain added 570
MWs of solar in 2007 and 2,760 MWs of solar in 2008.34 Spain’s solar target had only been 400
MWs by 2010.35 In this brief period Spain committed its ratepayers to over $26 billion in
payments to solar generators.36 There was a public backlash, and in 2008, Spain instituted a
program cap into its feed-in tariff law.37
2. Feed-In Tariffs in the United States
As discussed below, the Public Utility Regulatory Policies Act of 1978, mandates
purchases from certain renewable facilities at fixed prices. In a sense, it was the first feed-in
tariff. However, it was not until the successes of the German model that interest in feed-in tariffs
spread to state and local governments. In the last few years, feed-in tariffs have become an
increasing popular option for increasing the development of renewable generation in the United
29
Id. Toby Couture, Claire Kreycik, & Emily Williams, A Policy Maker’s Guide to Feed-In Tariff Policy Design, July
2010 at 10.
31
Claire Kreycik, Toby Couture, and Karlynn Cory, Innovative Feed‐In Tariff Designs that Limit Policy Costs, NREL/TP‐6A20‐50225, June 2011, at 5. 32
Id. 33
Id. 34
Id. at 4. 35
Id. 36
Paul Voosen, Spain’s Solar Market Crash Offers Cautionary Tale About Feed‐In Tariffs, New York Times, August 18, 2009. 37
Claire Kreycik, Toby Couture, and Karlynn Cory, Innovative Feed‐In Tariff Designs that Limit Policy Costs, NREL/TP‐6A20‐50225, June 2011, at 4. 30
7
States. This section provides a brief description of some of the feed-in tariff programs currently
in place in the United States.
(i.) Florida
Possibly the most well known feed-in tariff in the United States is the one offered by the
Gainesville Regional Utilities (“GRU”) in Florida. The GRU feed-in tariff is a solar specific
program where the payment is based on the cost of the generation, set at fixed rate of $0.32/kWh
over the contract term for eligible systems installed in 2009 and 2010.38 The fixed contract price
decreases each year thereafter.39 The contract term is set at 20 years and there is a program limit
of 4 MWs of installed capacity per year.40 The GRU feed-in tariff gained notoriety because it
was the first significant renewable feed-in tariff in the country. Additionally, it is one of the
most aggressive, having pricing similar to the European model.
(ii.) California
California has two statewide feed-in tariff requirements. The first is Assembly Bill
(“AB”) 1613, which requires that California utilities offer a standard tariff to qualifying
combined heat and power generators. The requirements of AB 1613 are discussed more fully
below. The second statewide feed-in tariff was created by Senate Bill (“SB”) 32 in 2009.41 SB
32 requires all of the State’s IOUs and all electric POUs in the state with more than 75,000
customers to adopt a standard tariff available to eligible renewable generation at a rate that
reflects every kWh on a time-of-delivery basis.42 To be eligible for the feed-in-tariff, an electric
generation facility must: (1) have an effective capacity less than or equal to 3 MWs; (2) be
38
Gainesville Regional Utilities Ordinance No. 0-08-88, Section 2. Free standing solar installations (non-building
or non-pavement mounted) receive a lower contract price. Id.
39
Id.
40
Id.
41
Stats. 2009, Ch. 328, SB 32 (2009).
42
Cal. Pub. Util. Code §§ 387.6, 399.20.
8
interconnected and operate in parallel with the electrical and transmission and distribution grid;
(3) be strategically located and interconnected to the electrical transmission and distribution grid
in a manner that optimizes the deliverability of electricity generated at the facility to load
centers; and (4) be an eligible renewable resource under California law.43 There is a statewide
program cap of 750 MWs.44
The Sacramento Municipal Utilities District (“SMUD”) approved its renewable feed-in
tariff in September of 2009.45 SMUD offers two different feed-in tariffs, one is directed at
compliance with SB 32 and is only open to eligible renewable resources (3MWs or less), with a
program cap of 32 MWs.46 SMUD’s other feed-in tariff is open to larger renewable resources
and CHP generators.47 SMUD’s SB 32 feed-in tariff is offered on a first come, first serve basis
with the option of 10, 15, or 20 year terms.48 A generator that qualifies for SMUD’s SB 32 feedin tariff locks in it rates for the entire contract term. 49 The rates are based on SMUD’s avoided
costs.50 Toward this end, they are divided into three seasons: winter, spring, and summer.51
Within each season there are different rates depending on whether the electricity is delivered
during a peak time or off peak time.52 Additionally, there are super peak rates during the winter
and summer periods.53
In setting its rates based on avoided costs, SMUD considered the following factors: (1)
market energy price; (2) ancillary services; (3) generation capacity; (4) transmission; (5) sub
43
Id. §§387.6(b), 399.20, 399.20(b).
Id. §§387.6(e), 399.20, 399.20(f)(1).
45
Sacramento Municipal Utility District Resolution No. 8-04.
46
Id.
47
Id.
48
Id.
49
Id.
50
Id.
51
SMUD Feed-In Tariff for Distributed Generation (FIT), available at http://www.smud.org/en/business/raterequirements/Documents/FIT-Pricing.pdf.
52
Id.
53
Id.
44
9
transmission capacity; (6) avoided greenhouse gas mitigation; and (7) risk avoidance from future
natural gas price increases.54 SMUD’s 2010 average annual rate for a 20 year contract was
$0.0957.55 SMUD’s 32 MW program cap was reached in just 19 days.
The City of Anaheim approved its feed-in tariff in November of 2010. Under SB 32,
Anaheim’s program cap is roughly 8 MWs.56 Similar to SMUD, Anaheim allows the generator
to choose between a 10, 15, or 20 year contract term.57 Anaheim’s annual rate is based on the
California Independent System Operator’s (“CAISO”) South of Path 15 Generation Hub price
plus the average premium paid in the Western Electricity Coordinating Council (“WECC”)
region for delivered renewable energy.58 This price is then adjusted based on the season
(winter/summer) and the time of delivery (on-peak, mid-peak, off-peak).59
(iii.) Washington
Washington State adopted a feed-in tariff program with fixed price incentive payment
based on the technology type.60 These prices range from $0.12/kWh to $0.54/kWh.61 The
annual payment to a generator is limited at $2000, significantly restricting the size of resource
that could fully benefit from the program.62 Additionally, the payments end in 2014.63
Washington pays for these incentives through offsetting the participating utility’s state tax
liability.64 However, Washington’s program is voluntary for utilities.65
54
Sacramento Municipal Utility District Resolution No. 8-04, Sections 13.3.13.4.
SMUD Feed-In Tariff for Distributed Generation (FIT), available at http://www.smud.org/en/business/raterequirements/Documents/FIT-Pricing.pdf.
56
City of Anaheim Public Utilities, Feed-In Tariff Guidelines, ver. 1.0, available at
http://www.anaheim.net/utilities/FIT/Guidelines.pdf.
57
Id.
58
Id.
59
Id.
60
Toby Coture &Karlynn Cory, State Clean Energy Policies Analysis (SCEPA) Project: An Analysis of Renewable
Energy Feed-In Tariffs, Technical Report, NREL/TP-6A2-45551, June 2009 at 13.
61
Id.
62
Id.
63
Id.
64
Id.
55
10
(iv.) Other States
The states of Vermont, Maine, and Hawaii have all adopted some form of Feed-in Tariff
requirement.66 Additionally, a number of municipal utilities have adopted feed-in tariffs without
any statewide statutory or regulatory obligation, including utilities in Wisconsin and Oregon.67
These programs vary greatly and utilize a variety of payment structures.
III.
FERC JURISDICTION
A. Summary of FERC Jurisdiction
1. The Federal Power Act
The Federal Power Act (“FPA”) grants FERC exclusive jurisdiction over “the
transmission of electric energy in interstate commerce” and “all sales of electric energy at
wholesale in interstate commerce not expressly exempted by the Act itself . . . .”68 The focus of
this paper will be on FERC’s jurisdiction as it relates to wholesale sales. Proposed rates for the
sale of electricity in interstate commerce by a “public utility” are subject to FERC review to
determine that they are “just and reasonable” and not unduly discriminatory or preferential.69 A
sale at wholesale is defined as: “a sale of electric energy to any person for resale.”70 Electricity
is transmitted “in interstate commerce” if it is “transmitted from a State and consumed at any
point outside thereof; but only insofar as such transmission takes place within the United
States.”71
65
Id.
Toby Couture, Claire Kreycik, & Emily Williams, A Policy Maker’s Guide to Feed-In Tariff Policy Design, July
2010 at 16.
67
Toby Coture &Karlynn Cory, State Clean Energy Policies Analysis (SCEPA) Project: An Analysis of Renewable
Energy Feed-In Tariffs, Technical Report, NREL/TP-6A2-45551, June 2009 at 9, 14.
68
Federal Power Comm’n v. Southern Cal. Edison, 376 U.S. 205, 209 (1964); 16 U.S.C. 824(a)-(b).
69
16 U.S.C. § 824d(a),(b).
70
16 U.S.C. § 824(d).
71
16 U.S.C. § 824(c).
66
11
The courts have taken an extremely broad interpretation of “interstate commerce.” In
FPC v. Florida Power & Light, the Supreme Court held that a utility, Florida Power and Light,
that had no direct connections to any out-of-state utility and that made no sales to out-of-state
utilities was nevertheless still under the jurisdiction of the Federal Power Commission (FERC’s
predecessor).72 The Supreme Court’s holding was based on the expert testimony provided by the
Federal Power Commission that power from Florida Power and Light “comingled” with out-ofstate power in a bus at the interconnection with a neighboring utility.73 In Justice Douglas’s
dissent, he noted that the majority’s approach meant that “every privately owned interconnected
facility in the United States (except for those isolated in Texas) is within the [Federal Power
Commission]'s jurisdiction.”74
2.The PURPA Exception
There are a variety exceptions to the FERC’s exclusive jurisdiction over wholesale sales
in interstate commerce. A key exception is the Public Utility Regulatory Policies Act of 1978
(“PURPA”). PURPA was enacted in response the energy crisis caused by the Middle East Oil
embargo in the early 1970s.75 Under PURPA, retail utilities are required to purchase capacity
and energy from qualifying facilities (“QFs”).76 A QF is defined as either a small power
production facility or a cogeneration facility.77 Small power production facilities are generating
facilities with capacities of 80 MWs or less where the primary energy source is renewable.78
72
FPC v. Florida Power & Light, 404 U.S. 453 (1972) (
Id. at 461-62.
74
Id. at 471.
75
See Michael D. Hornstein & J.S. Gebhart Stoermer, The Energy Policy Act of 2005: PURPA Reform, The
Amendments and Their Implications, 27 Energy L. J. 25, 25-26 (2006).
76
See FERC v. Mississippi, 456 U.S. 742, 750 (1982) (Ҥ 210(a) directs FERC, in consultation with state regulatory
authorities, to promulgate ‘such rules as it determines necessary to encourage cogeneration and small power
production,’ including rules requiring utilities to offer to sell electricity to, and purchase electricity from, qualifying
cogeneration and small power production facilities.”).
77
16 U.S.C. § 796(17),(18).
78
Id. § 796(17).
73
12
State commissions and local governing boards are tasked with administering this obligation,
including setting the rates at which retail utilities must make these purchases.79
PURPA requires that any rate established under PURPA cannot exceed “the incremental
cost to the electric utility of alternative electric energy,” typically referred to as “avoided
costs.”80 PURPA defines avoided costs as “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.”81
A key limitation on a regulatory authority’s ability to set “avoided costs” is that avoided
costs cannot include “externality adders.”82 The key FERC decision on this subject is Southern
California Edison,83 which dealt with the CPUC’s PURPA avoided costs methodology. The
CPUC’s program required jurisdictional utilities to conduct a QF-only bidding process and
certain QFs were awarded additional payments based on the value of the reduced air emissions.84
FERC rejected both of these policies, hold that excluding non-QFs from the bidding process
would cause the contract prices to exceed the utilities’ avoided costs and that avoided costs could
not include environmental adders.85 On rehearing, FERC clarified that:
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 environmental costs may be
part of a state’s approach to encouraging renewable generation. . . . A state,
however, may not set avoided cost rates or otherwise adjust the bids of potential
79
See Mississippi, 456 at 750 (“Pursuant to this statutory authorization, FERC has adopted regulations relating to
purchases and sales of electricity to and from cogeneration and small power facilities. See 18 CFR pt. 292 (1980);
45 Fed.Reg. 12214-12237 (1980). These afford state regulatory authorities and nonregulated utilities latitude in
determining the manner in which the regulations are to be implemented. Thus, a state commission may comply with
the statutory requirements by issuing regulations, by resolving disputes on a case-by-case basis, or by taking any
other action reasonably designed to give effect to FERC's rules.”).
80
16 U.S.C. § 824a-3(b).
81
Id. § 824a-3(d).
82
Scott Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and
Possible Solutions, January 2010 at 9.
83
70 FERC 61,215 (1995), aff’d on rehearing, 71 FERC 61,269 (1995).
84
Id. at 61,666.
85
Id. at 61,677.
13
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.”86
An additional limitation on a regulatory authority’s ability to rely on PURPA is that
PURPA permits electric utilities to obtain an exemption for the purchase obligation. There is a
presumption that QFs with a capacity greater than 20 MWs located in the MISO, ISO-New
England, NYISO, or ERCOT are presumed to have non discriminatory access and utilities are
not obligated to purchase from them.87 Additionally, QFs with a generating capacity greater than
20 MWs that are eligible for service under a FERC-approved open access transmission tariff or a
“reciprocity” tariff filed by a non-jurisdictional transmission owner are subject to the same
presumption.88 A regulatory authority would need to be aware of this limitation in determining
whether it could rely on PURPA.
3.Application to POUs
FERC’s authority to set rates for wholesale transactions in interstate commerce, in
specifically limited in statute to “public utilities.”89 As described in Bonneville Power
Administration v. FERC, municipal utilities do not fall within the definition of a “public utility,”
and are therefore exempt from FERC’s ratemaking and refund authority.90 As clarified in
Transmission Agency of Northern California v. FERC, FERC’s jurisdiction is not based on the
“nature of the transactions,” but rather, the “identities of the sellers.”91 This distinction is
important because it means that FERC may still exercise jurisdiction over wholesale rates
charged by a non-POU generator, even if those sales are made to an exempt municipal utility.
86
Southern California Edison, 71 FERC 61,269 at 62, 080.
18 C.F.R. § 309 (e), (f)
88
Id. § 309(c).
89
16 U.S.C. 824e.
90
Bonneville Power Administration v. F.E.R.C., 422, F.3d 908, 925 (9th Cir. 2005).
91
Transmission Agency of N. California v. F.E.R.C., 495 F.3d 663, 674 (D.C. Cir. 2007) (“FERC's authority is
based on the identities of the sellers, rather than the nature of the transactions.”).
87
14
Unlike the general provisions of the FPA, PURPA is applicable to “electric utilities” rather
than to “public utilities.”92 Municipal utilities fall within the definition of “electric utilities” and
thus are subject to the requirements of PURPA discussed above.93
B. NREL Report
The National Renewable Energy Laboratory (“NREL”) has commissioned several reports
on the issue of feed-in tariffs. In January of 2010, NREL released a report titled, Renewable
Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and Possible Solutions.94
This report was prepared at the request of the National Association of Regulatory
Commissioners.95 The report concludes that a feed-in tariff implicates federal law because it
mandates that a utility purchase wholesale electricity at standard rates.96 From this conclusion,
the report determines that there are two options for a regulator seeking to create a feed-in tariff
policy: (1) create a feed-in tariff that complies with PURPA; or (2) create a feed-in tariff that
requires that a utility only “offer” a certain standard contract that complies with the FPA’s
restrictions on rates.97 Under the second option, the generator would be obligated to register its
rate with FERC.98
The Report also discusses the issue of municipal utilities. Consistent with the discussion
above, it concludes that even though municipal power systems are not subject to the FPA, under
PURPA municipal utilities act in the same capacity as state commissions, and would, therefore,
92
16 U.S.C. 824a-3.
16 U.S.C. § 796(22) (“The term “electric utility” means a person or Federal or State agency (including an entity
described in section 824(f) of this title) that sells electric energy.”).
94
Scott Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and
Possible Solutions, January 2010.
95
Id. at iv.
96
Id. at 1.
97
Id. at 5-40.
98
Id. at 21.
93
15
be held to the same standards in the developing feed-in tariffs under PURPA.99 Additionally,
even though sales of wholesale power by POUs are not subject to the FPA, wholesales by an
independent generator to a POU do fall within the FPA.
1. Feed-In Tariffs that Comply with PURPA
A key limitation for a feed-in tariff adopted pursuant to PURPA is the limited options for
pricing. The limitation imposed by “avoided costs” would likely inhibit the effectiveness of the
feed-in tariff because avoided costs rates are arguably too low to spur significant investment. To
solve this problem, the NREL Report identifies three methods that a regulatory authority could
potentially use in a PURPA program to provide renewable generators with payments in excess of
avoided costs: (1) award renewable energy credits (“RECs”) to the generator; (2) award a tax
credit to the utility; and (3) provide payments from other sources.
(i.) Renewable Energy Credits
The first option is to award RECs to the generator.100 A REC is a tradable commodity
representing the renewable attributes of one MWh of renewable generation. Several states
permit utilities to purchase RECs as a mechanism for complying with an RPS obligation. RECs
have a clear market value and there is a growing demand for RECs. Under a feed-in tariff, a
generator could obtain a standard contract set at the utility’s avoided costs and additionally be
the owner of the RECs generated and sold to the utility. The generator could either sell the REC
on the market, or negotiate a price with the utility. Both the SMUD and Anaheim feed-in tariffs
require that the generator sell any RECs associated with the generation to the relevant utility.
FERC has explicitly approved the use of RECs as a mechanism for making payments over the
avoided cost rate, holding that RECs “exist outside the confines of PURPA. . . . States, in
99
Id. at 2.
Scott Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and
Possible Solutions, January 2010 at 14.
100
16
creating RECs have the power to determine who owns the REC in the initial instance and how
they may be sold or traded. . . .”101
The key downside of this option is that the price of RECs in the open market is fairly low
and unstable, and therefore, this pricing mechanism may not provide compensation at a level and
stability sufficient to properly incentivize the development of new renewable generation.
(ii.)Tax Credits
A second option for setting compensation levels above avoided costs is state regulatory
authorities can set the purchase price above avoided cost, if the state then provides tax credits to
the utility in an amount that equals the amount paid in excess of avoided costs.102 This option
obviously has little applicability to a publicly owned electric utility that seeks to develop its own
feed-in tariff.
(iii.) Payments from Other Sources
A third option recommended by the NREL Report is to provide funding from other
sources. FERC has clarified that “a state may choose to grant loans, subsidies or tax credits to
particular facilities on environmental or other policy grounds.”103 Such an option would likely
include payments generated by a systems benefits charge. Supplementing a feed-in tariff with
funds from a system benefits fund would likely be a viable option for a POU.
2. Feed-In Tariffs that Do Not Comply with PURPA
If a regulatory authority chose not to rely on its PURPA authority, then the feed-in tariff
would need to comply with the FPA. Under the FPA, FERC has the exclusive jurisdiction over
101
American Ref-Fuel Co, 105 FERC 61,004 (2003) at ¶ 23.
Scott Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and
Possible Solutions, January 2010 at 16 (citing CGE Fulton, 70 FERC 61,290, reconsideration denied, 71 FERC
61,232 (1995).
103
CGE Fulton, 70 FERC 61,290 at 61,844.
102
17
all wholesale sales made in interstate commerce.104 FERC is obligated to ensure that all rates are
just and reasonable and not unduly discriminatory.105 The NREL Report makes an extensive
argument that while the FPA clearly preempts a state’s authority to mandate wholesale sales, a
state would still be able to require utilities to “make offers to purchase at a specified rate.”106
The basis for this argument is that simply because the tariff requires utilities to offer a certain
contract price and term, this does not establish the actual contract price.107 FERC would still
need to approve the contract for it to be valid.108 However, the NREL Report acknowledges that
FERC’s precedent on this issue is unclear and would require clarification.109 As discussed
below, FERC ultimately rejects this argument.
The NREL Report goes on to argue that FERC precedent requires that the contract prices
established under a program subject to the FPA still need to comply with the avoided cost
principles applicable in the context of PURPA, described above. In Connecticut Light and
Power Co. FERC held that if states “mandate rates above avoided cost for a particular class of
power suppliers (i.e. QFs) [it would run] counter to Congress’ and [FERC’s] current policies
which strongly favor competition among all bulk power suppliers.”110 The NREL Report argues
that FERC should change this precedent and permit contract rates that exceed avoided costs.111
C. Recent FERC Decisions on Feed-In Tariffs
Subsequent to the release of the NREL Report, FERC directly addressed these matters in
a proceeding initiated by the CPUC. The origin of the FERC proceeding was the passage of
104
16 U.S.C. 824(a)-(b); Mississippi Power & Light Co. v. Moore, 487 U.S. 354, 371 (1998) (“FERC has exclusive
authority to determine the reasonableness of wholesale rates.”).
105
16 U.S.C. 824d(a),(b).
106
Scott Hempling, et al., Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and
Possible Solutions, January 2010 at 23.
107
Id.
108
Id. at 25.
109
Id. at 26.
110
70 FERC 61,012 at 61,029 (1995).
111
Hempling at 26.
18
California’s AB 1613 (2007).112 AB 1613 directs the CPUC to establish a standard tariff for
combined heat and power (“CHP”) generators to sell excess electricity to the investor owned
utilities (“IOUs”). To be eligible, the CHP generators must: (1) have generating capacities of 20
MWs or less; (2) use a time of use meter; (3) meet certain efficiency requirements; (4) be
interconnected to and operate in parallel with the grid; and (5) be sized to meet onsite load.113
In July of 2008, the CPUC initiated a rulemaking to implement AB 1613.114 This
proceeding lasted over a year, and on December 17, 2009, the CPUC issued Decision (“D.”) 0912-042. In this decision, the CPUC created two standard tariffs, one for CHP systems sized up to
5 MWs and one for CHP systems sized up to 20 MWs.115 California’s IOUs filed motions for
rehearing of the decision partially on the grounds that the CPUC’s price formula was preempted
by the FPA. The CPUC denied the motions of the IOUs, and in anticipation that this process
would be moving to the federal level, the CPUC filed a petition for declaratory order on this
issue with FERC a few days later.116 The California IOUs filed a separate petition for
declaratory order at FERC arguing that the CPUC’s decision was preemption argument. 117
These two proceedings were ultimately consolidated.
1. FERC’s July 15, 2010 Order on Petitions for Declaratory Order
In the CPUC’s petition for declaratory order, the CPUC makes two primary arguments as
to why its AB 1613 program does not implicate FERC jurisdiction. One of the CPUC’s
arguments essentially breaks down to: FERC precedent on this issue is outdated because it
112
Stats 2007, Ch. 713, AB 1613 (2007).
Cal. Pub. Util. Code 2840.2(a)-(b).
114
Order Instituting Rulemaking on the Commission’s Own Motion into combined heat and power Pursuant to
Assembly Bill 1613, July 1, 2008.
115
D.09-12-042 at 5.
116
Petition of the Public Utilities Commission of the State of California for Declaratory Order and for Exemption
from Paying Filing Fees, Docket EL10-64-000, filed May 4, 2010.
117
Southern California Edison Co., Pacific Gas & Electric Co., & San Diego Gas & Electric Co., Petition for
Declaratory Order, Docket No. EL10-66-000, filed May 11, 2010.
113
19
occurred during the 1990’s, which was before we were aware of the seriousness of climate
change.118 The CPUC cites to no direct authority to support such a legal argument, and FERC
ultimately rejected it.
The CPUC’s primary argument essentially followed the recommendation of the NREL
Report discussed above and focused on the distinction between “purchases” and “offers.” The
CPUC argued that it did not set wholesale prices in its AB 1613 program, but instead merely
required CPUC-jurisdictional utilities to “offer a certain price to encourage CHP systems to be
constructed.”119
FERC expressly rejected the CPUC’s argument that it is only establishing an “offering
price” and not regulating purchases.120 Instead, FERC held that “the CPUC’s AB 1613
Decisions constitute impermissible wholesale rate-setting by the CPUC.”121 However, FERC did
provide a path for CPUC to avoid federal preemption of its AB 1613 program: “to the extent the
CHP generators that can take part in the AB 1613 program obtain QF status, the CPUC’s AB
1613 feed-in tariff is not preempted by the FPA, PURPA or Commission regulations, subject to
certain requirements . . . .”122 FERC clarified that, in order to conform its AB 1613 program to
PURPA: “(1) the CHP generators from which the CPUC is requiring the [IOUs] to purchase
energy and capacity are QFs pursuant to PURPA; and (2) the rate established by the CPUC does
not exceed the avoided cost of the purchasing utility.”123 FERC did not extend its analysis to the
CPUC’s rate because no parties raised this issue and FERC determined that there was an
inadequate record for such a finding. FERC also clarified that if a CHP generator was not a QF,
118
CPUC Petition at 29.
Id. at 32-33.
120
132 FERC 61,047 at ¶ 64.
121
Id.
122
Id. at ¶ 65.
123
Id. at ¶ 67.
119
20
then that generator would need to file its rates with FERC in compliance with the FPA and
demonstrate that its rates are “just, reasonable and not unduly discriminatory or preferential.”124
FERC also took the opportunity to address what it viewed as confusion over the
exemptions applicable to small QFs. FERC explained that even though some smaller QFs may
be exempt from FPA sections 205 and 206 requirements (regarding rates and refunds), this does
not mean that the CPUC may set wholesale rates at a level that exceeds avoided costs for those
QFs.125
(i.) Applicability to Public Power
The California Municipal Utilities Association (“CMUA”) filed comments in this
proceeding arguing that FERC should limit its decision so that it did not implicate nonjurisdictional utilities. FERC responded with a clarification that “for those facilities and sellers
that are neither QFs nor public utilities selling at wholesale, but may, for example, be states or
their subdivision, agencies, authorities, or instrumentalities, rates for such sales are not within
[FERC’s] authority.”126 However, it is important to note the limited applicability of this
exemption in the context of designing a feed-in tariff. While a municipal utility’s wholesale
sales to another entity would not be subject to FERC jurisdiction, sales from a generator falling
within that same municipal utility’s feed-in tariff program to the municipal utility would be
subject for FERC FPA jurisdiction.
(ii.)Applicability to Distributed Generation
SMUD filed comments in this proceeding arguing that FERC should “avoid
unnecessarily addressing whether distribution-level feed-in tariffs, and related sales for resale
124
Id. at ¶ 69.
Id. at ¶ 70.
126
132 FERC 61,047 at ¶ 71.
125
21
from facilities connected to distribution systems, are subject to [FERC’s] jurisdiction.”127
SMUD argued that such an interpretation is consistent with FPA section 201(b)(1), which
excludes from FERC jurisdiction those facilities that are used in local distribution and the
unbundled retail service that occurs over those facilities.128 SMUD also pointed to the seven
factor test to distinguish between local distribution facilities and FERC-jurisdictional facilities
that FERC formulated in Order No. 888.129 Extending this argument, SMUD concluded that
“even a sale for resale over distribution facilities does not implicate [FERC] jurisdiction.”130
SMUD warned of the practical implications, arguing that a FERC exertion of jurisdiction would
“bring within [FERC’s] regulatory reach literally millions of homeowners, farmers or businesses
using rooftop solar panels or small wind turbines who sell power to their local utility, other than
on a net-metering basis. 131
FERC rejected SMUD’s arguments, holding: “The FPA grants [FERC] exclusive
jurisdiction to regulate sales for resale of electric energy and transmission in interstate commerce
by public utilities. [FERC’s] FPA authority to regulate sales for resale of electric energy and
transmission in interstate commerce by public utilities is not dependent on the location of
generation or transmission facilities, but rather on the definition of, as particularly relevant here,
wholesale sales contained in the FPA.”132 This holding has serious implications because it
brings into FERC’s jurisdiction all feed-in tariffs. This includes programs targeted incentivizing
roof-top solar for residential and small commercial customers. One complication is for net
127
Amendment to Motion to Intervene of the Sacramento Municipal Utilities District, June 10, 2010 at 2.
Id.
129
Id. at 3.
130
Id.
131
Id. at 5.
132
132 FERC 61,047 at ¶ 72.
128
22
energy metering programs where the customer is paid for excess generation, such as California’s
program discussed above.
2. FERC’s October 21, 2010 Clarification Order
In response to the July 15 FERC Order, the CPUC determined that it would reexamine
implementing AB 1613 pursuant to its PURPA authority.133 However, the CPUC needed
additional clarification from FERC before it could take this step. Toward this end, the CPUC
filed a Request for Clarification or Rehearing seeking clarification: (1) “whether the CPUC can
require retail utilities to offer different contracts that include different factors in the avoided cost
calculation in order to promote development of more efficient CHP facilities”; and (2) “whether
‘full avoided cost’ need not be the lowest possible avoided cost and should properly take into
account real limitations on ‘alternate’ sources of energy imposed by state law.”134
FERC responded directly to the CPUC’s request, providing that a “multi-tiered avoided
cost rate structure” can be consistent with PURPA.135 However, FERC went well beyond the
scope of the request made by the CPUC and provided a sweeping response. In discussing the
applicability of state requirements to determining avoided costs, FERC stated: “where a state
requires a utility to procure a certain percentage of 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.”136 FERC went on
to clarify that “a state may appropriately recognize procurement segmentation by making
separate avoided cost calculations.”137
133
Request for Clarification or, in the Alternative, Request for Rehearing of the Public Utilities Commission of the
State of California, August 16, 2010, at 1.
134
Id. at 5.
135
Order Granting Clarification and Dismissing Rehearing, EL10-64-001, EL10-66-001, October 21, 2010 at ¶20.
136
Id. at ¶ 27
137
Id. at footnote 53.
23
FERC’s ruling differs from the previously accepted interpretation of avoided cost
precedent, primarily SoCal Edison, 71 FERC 61,269 (1995). SoCal Edison had been interpreted
as requiring avoided costs to be based on “all sources.” To be exceedingly clear, FERC stated
“To the extent that our decision in this order . . . can be read as inconsistent with the discussion
in SoCal Edison, we are overruling SoCal Edison’s broader language on this issue.”138
A second issue raised by the CPUC was whether its proposed 10 percent price adder for
CHP systems located in transmission-constrained areas would be permissible under PURPA.139
FERC clarified that it has previously stated that avoided cost rates cannot include a price bonus
purely to provide an incentive for the environmental attributes of the resource.140 However, if
there are real costs that would be incurred by a utility, then those costs may be reflected in the
avoided cost calculation.141 Therefore, FERC concluded that if the CPUC’s 10 percent adder
was based on “an actual determination of the expected costs of upgrades to the distribution or
transmission system that the QFs will permit the purchasing utility to avoid, such an ‘adder’ or
‘bonus’ would constitute an actual avoided cost determination and would be consistent with
PURPA and [FERC’s] regulations.”142
3. FERC’s January 20, 2011 Order Denying Rehearing
California’s IOUs objected strongly to FERC’s October 21 Order and filed a request for
rehearing.143 The IOUs argued that multi-tiered avoided cost rate structures violate PURPA,
FERC regulations, and case law.144 Specifically, they argued that permitting states to exclude
138
Id. at 30.
CPUC Request for Rehearing at 3.
140
Order at ¶ 31.
141
Id.
142
Id.
143
Petition of Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas and
Electric Company for Rehearing, or, in the Alternative, Reconsideration, Partial Vacatur, or Clarification, November
22, 2010.
144
Id. at 3.
139
24
cheaper forms of energy from the avoided cost calculation would violate PURPA’s customer
indifference requirement.145 The IOUs argued that such a result was inconsistent with FERC’s
interpretation of PURPA in SoCal Edison: “The intention was to make ratepayers indifferent as
to whether the utility used more traditional sources of power or the newly-encouraged
alternatives.”146
FERC rejected the IOUs’ interpretation of SoCal Edison, arguing that “[i]t would be
illogical to read SoCal Edison as authorizing consideration, for purposes of determining a
utility’s avoided costs, of sources that are, in fact, not able to sell to that utility.”147 FERC denied
the IOUs’ request for rehearing, bringing this proceeding to an end.
IV.
IMPLICATIONS FOR PUBLIC POWER
The recent FERC orders have made it clear that a POU’s feed-in tariff program is subject
to FERC jurisdiction, even for feed-in tariffs directed at small scale distributed generation.
FERC has also made it clear that if a regulatory authority wants to set wholesale rate pursuant to
a feed-in tariff its only option is pursuant to its PURPA authority. FERC expressly rejected the
NREL Report’s argument that a regulatory authority could escape preemption by only mandating
that the utility “offer” certain contract terms.
However, despite these restrictions, the FERC Clarification Order outlined broad
authority for a POU to set the avoided costs. Rather that adopting a single avoided cost
applicable to the utility, a POU may adopt several tiers of avoided costs based on the
characteristics of the QF, if those characteristics are mandated by state law. This means that if
the state has an RPS, the POU can adopt an avoided cost for RPS-eligible resources.
Additionally, the avoided costs may include a location adder if it reflects actual savings. This
145
Id. at 3-4.
Id. at 20 (citing SoCal Edison, 71 FERC 61,269 at 62,079-80) (emphasis in original).
147
Order Denying Rehearing at ¶ 33.
146
25
may prove particularly useful for small scale renewable resources that are located near load. A
POU that is considering a feed-in tariff or that has an existing feed-in tariff must carefully
consider whether its pricing mechanism complies with the requirements of PURPA as described
by FERC.
Beyond the issue of pricing, there are other requirements that must be considered when
enacting a feed-in tariff pursuant to PURPA. PURPA and FERC regulations require that QFs
that have a net power production capacity greater than 1 MW must register with FERC to be an
eligible QF.148 Registration requires the QF to complete and electronically file Form No. 556.149
QFs with a net power production capacity of 1MW or less are exempt from the registration
requirement. Additionally, there are a number of voluntary standards which must be considered
as part of a program adopted pursuant to PURPA.150
V.
CONCLUSION
Feed-in tariffs provide an effective mechanism to increase a utility’s renewable energy
procurement. A number of states and POUs have already adopted feed-in tariff policies.
However, FERC has recently clarified that a state or POU may only adopt a feed-in tariff policy
pursuant to its PURPA authority. Any POU considering adopting a feed-in tariff must carefully
review the limitations of PURPA. While PURPA limits the pricing structure that can be used in
a feed-in tariff, the state governments and POU governing boards are given wide discretion.
148
FERC Order 732 at ¶ 15. Id. Form No. 556 is available at http://www.ferc.gov/docs‐filing/forms/form‐556/form‐556.pdf. 150
16 U.S.C. § 2621, 2623. 149
26