ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 1

Table of Contents

Executive Summary .......................................................................................................... 3

Wind Energy: Introduction .............................................................................................. 7

Drivers of Wind Energy Development ............................................................................. 10

Environmental Benefits............................................................................................... 10

Advances in Generator Technology ............................................................................ 11

Government Initiatives................................................................................................ 11

Regulatory Policy Regarding Avoided Cost Pricing ................................................. 11

State Renewable Portfolio Standards (RPS) ............................................................. 13

State Renewable Energy Credits (REC) ................................................................... 15

Production Tax Credits (PTC) ................................................................................ 15

Challenges to Future Wind Energy Development ............................................................. 16

Impacts of Wind Development .................................................................................... 16

Siting and Permitting .................................................................................................. 17

Project Financing ........................................................................................................ 18

Transmission Issues .................................................................................................... 19

Available Transmission Capacity (ATC) .................................................................. 20

Rate Pancaking ...................................................................................................... 24

Losses .................................................................................................................... 25

Imbalance Charges ................................................................................................. 25

Transmission Planning ............................................................................................ 25

Interconnection .......................................................................................................... 26

Capacity Credits......................................................................................................... 26

Conclusion ..................................................................................................................... 29

Appendix 1: Conditional-Firm Service Tariff Product ...................................................... 30

Appendix 2: Renewable Portfolio Standards by State ...................................................... 32

Appendix 3: RPS mechanisms by state ............................................................................ 33

Appendix 4: New Projects announced since PTC renewal ............................................... 34

ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 3

Executive Summary

Wind ener ind energy, while a relatively new market entrant, is the fastest growing electricity generation

technology in the world today. Favorable public attitude, increasingly attractive economics

and technological advances are combining to drive industry development. To date, wind has

gained limited market acceptance primarily due to unique operational characteristics that do

not allow wind generators to fully optimize their output in the current environment.

The evolution toward regionalized electricity markets, combined with technological innovation

lowering the unit cost of wind generated electricity, has allowed wind generators to operate

in a “merchant” role. In many regions of the country, wind generation now has the ability to

compete with thermal resources. However, due to remoteness from load, transmission remains

a concern that affects its competitiveness.

While there has been significant progress towards integrating wind resources into suppliers’

and loads’ portfolios, some challenges result from the terms and conditions of transmission

service required by utilities subject to the jurisdiction of the Federal Energy Regulatory

Commission (FERC).

Staff makes the following key findings from this study:

There are a number of public policy

factors, both at the state and federal factors, both at the state and federal

level, currently driving the development level, currently driving the development

of wind ener of wind energy.

Wind energy development is currently

aided by the environmental benefits

associated with energy production from clean,

renewable resources. State Renewable Portfolio

Standards and State Renewable Energy Credits

place requirements upon load serving entities to

procure certain amounts of their energy from

renewable resources. The federal government

has also reauthorized the Production Tax Credit

for parties that engage in the development of

renewable energy resources.

Wind project developers confront Wind project developers confront

several hurdles in obtaining financing for several hurdles in obtaining financing for

wind projects under current market wind projects under current market

conditions. conditions.

Projecting revenues for wind generation

is more difficult than for typical

generation sources due to higher variability of

production. Given difficulties associated with

projecting merchant revenue streams for wind

projects, financings have typically required power

purchase agreements for the full output of the

facilities. Overlooked in most early power project

finance deals, transmission issues (e.g., the

intermittent nature and distance from load) have

become a focus as investors recognize the
4 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

importance of transmission service to project

completion and economics.

The operational challenges facing competitive

electricity suppliers ( electricity suppliers (e.g., available transmission, , available transmission,

pancaked rates, and capacity value recognition) pancaked rates, and capacity value recognition)

increase for wind generation. increase for wind generation.

Wind generation is unable to maximize its use

of reserved transmission capacity due to its

intermittent nature. When purchasing firm

transmission, a wind generator pays more for

that transmission (on a per unit basis) when

accounting for its low capacity factor. Also,

because wind resources are only optimum in

specific locations, wind generation does not have

similar site selection flexibility as thermal

resources and may incur multiple transmission

charges when delivering to load. Finally,

because wind generation is not recognized as

having a capacity value in certain markets, wind

generators lose value in those markets.

Current open access pro forma tariff provisions

place challenges on wind gener place challenges on wind generation’s ability to

compete in electricity markets. compete in electricity markets.

These challenges take the form of industry

standard approaches to the calculation of

transmission losses, the scheduling rules that

result in imbalance penalties, and the reservation

of transmission service. In addition, the

interconnection issues, currently addressed in

Order No. 2003-A, are being addressed through

separate technical discussions and are not

addressed in detail here.

Development of regional transmission

organizations (RTOs) and independent system

operators (ISOs) are one approach to treating

wind generation on an equal basis. wind generation on an equal basis.

Commission-approved RTOs and ISOs may

remove many of the challenges that wind

generation faces. RTOs and ISOs effectively

remove pancaked rates, allow for scheduling

flexibility and create real-time imbalance

markets. These centralized markets reduce

imbalance penalties, optimize transmission

capability through region-wide dispatch, and

provide for independent regional planning to

expedite grid expansion.

Outside of RTOs and I Os and ISOs, ther SOs, there are nove l 

approaches that can be considered to overcome

the challenges that traditional regulatory rules

place upon wind generators. place upon wind generators.

Transmission services that allow for the unique

operational characteristics of wind energy such

as conditional firm, curtailable firm, priority nonfirm, and hourly firm may offer wind generators

increased certainty for gaining access to the

transmission grid. Measures can also be taken

to reduce the impact of imbalance penalties and

innovative methods can be developed to allow

wind resources to contribute to regional reserve

requirements and capacity markets.

Experience from the natural gas industry can also

be applied in developing alternatives to the

traditional transmission services under the open

access rules. access rules.

Individual pipeline companies offer various nontraditional services that may serve as conceptual

models in the development of non-standard

transmission services. Under small customer rate

schedules, for example, customers schedule and

pay for transmission service on a volumetric

basis, limited only by maximum daily volumes

established for the service. These services usually

allow for no-notice variations in scheduled

quantities.

The Commission can facilitate change through

proposed modifications to its pro forma open

access transmission tariff. access transmission tariff.

Change often requires balance. Proper

consideration must be given to minimize the

negative effects that the current pro forma

transmission tariff may have on certain market

segments. In order to provide the proper forum

to adequately address the issues that may result

in regulatory reform, Staff recommends using a

part of the December 1, 2004 technical

conference to determine the appropriate vehicle

to facilitate change, if such change is deemed

necessary.
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 5

Comments concerning this report may be filed

in Docket No. AD04-13-000.

For information about this report please contact:

Matthew Deal (202) 502-6363

Christopher Thomas (202) 502-8412

Carol Brotman White (202) 502-6338

Staff Briefing Paper: Assessing the State of Wind

Energy in Wholesale Electricity Markets

Disclaimer: This Report contains analyses,

presentations and conclusions that may be based

on or derived from the data sources cited, but do

not necessarily reflect the positions or

recommendations of the data providers.

Images courtesy of DOE/NREL, the National

Renewable Energy Laboratory. All rights and

permissions belong to DOE/NREL.
6 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 7

Policymakers across the U.S. Policymakers across the U.S. are increasingly interested in developing renewable sources

of energy in order to reap the potential environmental benefits, diversify the country’s

generation portfolio, and decrease the Nation’s dependence on foreign sources for energy.

Wind energy, as evidenced by its recent growth, has been the greatest beneficiary of Federal

and State-mandated programs for the development of renewable energy. As a complement

to the Commission’s efforts in Order 2003-A,1 Staff undertook a study of wind energy

development. This paper represents Staff’s initial thoughts with regard to issues facing wind

development and offers several reforms to further the development of wind energy in wholesale

markets.

Since 1980, modern advanced technology wind turbines have grown in size from 55 KW to

as large as 4.5 MW. Wind farms recently receiving large financings tend to include 100 or

more 1.0-1.65 MW turbines; smaller turbines are generally used on rural wind farms across

the country while the larger turbines are being evaluated for off-shore projects. Because wind

farms consist of multiple, small-megawatt turbines, the project size may be more readily

customized to meet incremental demand than fossil fuel-fired counterparts.

Wind power has been the fastest growing power source in the world, achieving a 28 percent

annual growth rate in the U.S. for the time period 1991 to 2003. The U.S. has tremendous

wind resources.2

 As shown in Table 1 on the next page, of the top twenty states with the most

potential for wind generation development, California and Texas lead in the construction of

new wind power, followed by Minnesota and Iowa. Despite having an abundance of desirable

sites for wind generation, the Dakotas have installed little wind due primarily to the remoteness

of their windy areas from load centers, necessitating major transmission additions, and the

siting and associated cost allocation issues.

1

 In Order 2003-A, the Commission generally recognized that certain standard interconnection provisions could

disadvantage generators relying on non-synchronous technology, namely wind generation. In order to avoid further

exacerbating the obstacles that wind generation currently faces, the Commission allowed several deviations to the

interconnection standards to accommodate newer technologies, such as wind generators. See, Standardization of Generator

Interconnection Agreements and Procedures, Order No. 2003, 68 Fed. Reg. 49,845 (2003), FERC Stats. & Regs.,

Regulations Preambles ¶ 31,146 (2003) (Order No. 2003), order on reh’g, 69 Fed. Reg. 15,932 (2004), FERC Stats & Regs.,

Regulations Preambles ¶ 31,160 (2004) (Order No. 2003-A), reh’g pending. 2 http://www.nrel.gov/wind/wind_map.html. Wind resources require a minimum annual average wind speed of at least 11

to 13 miles per hour for any prospective site to be considered viable. For a specific location, annual average wind speed is

used to calculate the amount of energy in the wind blowing through a wind turbine’s rotor per square meter of area. The

energy available in the wind is then assigned a wind power class from 1 to 7. State officials and developers use this

information to find the best areas for wind development. Sites in wind power class 3 or higher are candidates for wind farm

development. Class 2 sites or higher offer possibilities for adding small wind generators.

Wind Energy: Introduction
8 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Table 1: able 1: Wind and the Lower 48 States

Source: FERC analysis, derived from data in: Platts PowerDat, American Wind Energy Association (AWEA) website. As of

September 2004.

Top 20 States for Wind Potential Top 20 States by Installed Wind Capacity [12/03]

Rank State KWh Rank State MW % of total % of total Total MW

(Billion) Installed

1 North Dakota 1,210 1 California 2043 4.4% 46,157

2 Texas 1,190 2 Texas 1293 1.7% 77,842

3 Kansas 1,070 3 Minnesota 563 6.4% 8,749

4 South Dakota 1,030 4 Iowa 471 5.4% 8,723

5 Montana 1,020 5 Wyoming 285 4.5% 6,277

6 Nebraska 868 6 Oregon 259 2.1% 12,096

7 Wyoming 747 7 Washington 244 0.9% 25,892

8 Oklahoma 725 8 Colorado 223 2.5% 8,833

9 Minnesota 657 9 New Mexico 207 3.8% 5,489

10 Iowa 551 10 Oklahoma 176 1.2% 14,855

11 Colorado 481 11 Pennsylvania 129 0.5% 27,055

12 New Mexico 435 12 Kansas 114 1.2% 9,204

13 Idaho 73 13 North Dakota 66 1.4% 4,753

14 Michigan 65 14 West Virginia 66 0.4% 16,017

15 New York 62 15 Wisconsin 53 0.4% 12,373

16 Illinois 61 16 Illinois 50 0.2% 28,438

17 California 59 17 New York 49 0.2% 28,671

18 Wisconsin 58 18 South Dakota 44 1.6% 2,825

19 Maine 56 19 Nebraska 14 0.3% 5,138

20 Missouri 52 20 Vermont 6 1.2% 515

U.S. Total 6,375 0.9% 708,318

As shown in Figure 1 on the next page, many of

the best resource areas are located far from load

centers and in areas of the country outside of

centralized markets. In addition, it is estimated

that the area between 5 and 50 nautical miles off

the coast of the U.S. contains roughly 907 GW of

wind potential.3 While fossil fuel-fired

counterparts locate near load centers to avoid

transmission constraints, wind resources must be

sited where the wind blows. Nationally, strong

wind sites are located an average distance of 500

miles from major metropolitan centers; to even

connect with the grid, wind generators must

invest in transmission interconnections of over 10

miles.4

3

 W. Musial & S. Butterfield, “Future for Offshore Wind Energy in the United States.” June 2004.

4 National Renewable Energy Laboratory.
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 9

Figure 1: Figure 1: United States Wind Resource Map

Source: U.S. Department of Energy, National Renewable Energy Laboratory

Although wind turbines generally have high

availability factors (most manufacturers now

guarantee 97 percent), their capacity factors, or

usage rates, tend to be low (ranging from 25 to

40 percent) due to natural variability of the wind.5

Wind generation is an intermittent electricity

resource; much like other intermittent generators

such as solar energy, or run-of-river hydro, wind

output is controlled by natural variability rather

than dispatched based on load or markets. Also

like other intermittent resources, wind

generation’s availability rarely conforms to the

peaks and valleys of customer demand, i.e., it

cannot freely be ramped up or down but is

constrained by the availability of the wind.

5 The capacity factor of an individual generator or of an entire wind farm is the actual energy generated during a given

period divided by its maximum output, if the turbine were running at its rated power during all 8760 hours of the year.

Capacity factors for wind resources theoretically vary from 0 to 100 percent, but on average are 25 to 40 percent.
10 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Over the past decade, Over the past decade, a heightened awareness of the environmental impacts of fossil generation

and increases in fossil fuel prices has led to the increased demand for clean renewable resources.

Today, wind project developers benefit from strong environmental demand, decreasing costs

from technological advances, and government initiatives including states with renewable

portfolio standards and recently extended federal production tax credits.

Environmental Benefits

Unlike conventional power plants running on

coal, oil, or natural gas, wind generation relies

upon a renewable, abundant and free fuel to

produce clean energy. It has no harmful air

emissions, does not consume or pollute water, and

does not produce greenhouse gases that contribute

to global climate change.6 Shifting a significant

fraction of global energy demand from carbonintensive fossil fuels to modern renewable energy

technologies such as wind power could have

important environmental and economic benefits.

The most important environmental advantages

may be reduced impacts on human health locally,

declining risk of acid deposition and land

degradation regionally, and decreased risk of

climate change globally. Reduced dependencies

on fossil fuels could help mitigate future price

increases and free-up the fuel sources for

alternative uses.

As illustrated in Table 2, it is estimated that every

MWh of electricity generated by a wind turbine

offsets the equivalent of 1,100 to 2,200 pounds of

carbon dioxide, depending upon the type of fuel

used to generate the electricity. Based on the

national average fuel mix, wind energy also offsets

up to 15 pounds of sulfur and nitrogen oxides and

particulates, 3.5 ounces of trace metals, and more

than 440 pounds of solid waste from fossil-fueled

generation.7

Table 2: able 2: Comparative Air Emissions of e Air Emissions of Wind and Other Fuels

Source: American Wind Energy Association

Fuel CO2 Emitted per SO2 Emitted per NOx Emitted per

KWh generated (lbs.) KWh generated (lbs.) KWh generated (lbs.)

Coal 2.13 0.0134 0.0076

Natural Gas 1.03 0.000007 0.0018

Oil 1.56 0.0112 0.0021

Wind 0 0 0

6 Comparative Air Emissions of Wind and other Fuels. Wind Energy Fact Sheet. American Wind Energy Association.

7

 Wind Energy. EPA Website. January 2000.

http://yosemite.epa.gov/oar/globalwarming.nsf/uniqueKeyLookup/SHSU5BWK

54/$file/windenergy.pdf?OpenElement Accessed July 2004.

Drivers of Wind Energy Development
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 11

Advances in Gener ances in Generator Technology

Advances in technology which have resulted in

increased turbine sizes have enhanced wind

project economics. Coupled with various

government initiatives, advances have allowed

the unit cost of wind generation to fall

dramatically.8

 The cost per KWh has fallen by

between 60 percent and 80 percent, with capital

costs decreasing from $2,000 per installed KW

to between $800 and $1,100

today (and anticipated to fall 25

percent further by 2010).9

Large wind projects are now

competitive with new coal-fired

generation on an installed

capacity cost basis, but are still

substantially more expensive than

new gas-fired generation

capacity. American Electric

Power’s Desert Sky required total debt and equity

investment of just over $1,100/KW compared to

an estimated $700/KW for financing of gas-fired

combined cycled capacity. 10,11 All-in variable and

fixed costs for wind generation have declined from

30¢/KWh in 1980 to between about 2.5 – 4.0¢/

KWh today, once available tax and other

incentives are factored in.12 At current rates,

wind is competitive with today’s gas generation,

which assuming even a potential $6.00/mmBtu

gas price, would cost 5.5¢/KWh, including both

fuel and capital costs.13 As demand for wind

turbines increases, additional economies of scale

in the manufacturing process may decrease

turbine costs further.14

Government Initiatives

Regulatory Policy Regarding Avoided

Cost Pricing

Wind development has relied upon and benefited

from the Public Utility Regulatory Policies Act of

1978 (PURPA)15 and the avoided cost pricing

principles contained therein. State regulatory

authorities have been implementing PURPA

programs since 1980 in order to

encourage the development of

cogeneration and small power

production facilities. Many wind

installations around the country

benefit from the provisions

contained in PURPA.

Congress is considering rescission

of PURPA as a part of pending

energy legislation. The provisions

contained in PURPA are beneficial to the

continued expansion of wind energy. If energy

legislation is passed and the rescission of PURPA

remains a piece of that legislation, the wind

industry will need to find more innovative methods

in which to continue being a viable provider of

energy. The ways in which PURPA affects the

wind industry are characterized below.

Section 210(b) requires electric utilities to

purchase electric energy from Qualifying

Facilities (QFs) at rates that are (1) just and

reasonable to the electric consumers of the electric

utility and in the public interest, (2)

nondiscriminatory with respect to QFs, and (3)

8

 AWEA, Fair Transmission Access for Wind: A Brief Discussion of Priority Issues, http://www.awea.org/policy/

documents/transmission.PDF, Accessed November 2003. 9

 “Spot Picking,” Project Power Finance Report, September 2004.

10 “Americas Renewables Deal of the Year,” Project Finance Magazine, March 2003.

11 FERC Staff analysis based on gas-fired financing information collected from public sources.

12 New Mexico Energy, Minerals, and Natural Resources Department, Energy Conservation and Management Division,

Wind Energy, http://www.emnrd.state.nm.us/ecmd/html/wind.htm, Accessed November 2003. 13 “Not Just Tilting Anymore” Wall Street Journal, October 14, 2004, based on interview with Ryan Wiser, Lawrence

Berkeley National Laboratory. 14 Technology standardization can reduce investor perception of uncertainty of future performance as track records are

established. Parallels to gas turbine manufacture can be drawn in regards to technology risk but also to level of and faith in

manufacturer performance guarantees. 15 16 U.S.C. §824a-3, 796(17-22) (1982).
12 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

not in excess of “the incremental cost to the electric

utility of alternative electric energy.” Section

210(d) of PURPA defines the incremental cost of

alternate energy 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.”16

This statutory definition is supplemented by the

Commission’s regulations, which requires a utility

to pay nothing more than its “avoided costs” for

purchases from new QF capacity in the absence

of a negotiated rate.17 “Avoided costs” are

defined by the regulations as the incremental costs

to an electric utility of electric energy or capacity

or both which, but for the purchase from the QF

or QFs, such utility would generate itself or

purchase from another source.18

The avoided costs of electric utilities can include

both energy and capacity costs. Energy costs are

the variable costs associated with the incremental

production of electric energy. They represent the

cost of fuel, and some operating and maintenance

expenses. Capacity costs are the costs associated

with providing the capability to meet the demand

for electric energy. Capacity costs may be

incurred by a utility in order to build generating

facilities, institute conservation and load

management programs, or purchase power on the

wholesale market. Under the Commission’s

current regulations, capacity payments need to

be made when, and only when, the purchase or

construction of capacity will be avoided by the

purchasing electric utility as a result of its

purchase of QF power.

16 16 U.S.C. §824a-3(d) (1982).

17 18 CFR §292.304 (a) (2003). State regulatory authorities and nonregulated electric utilities can set lower rates for QF

capacity built before the enactment of PURPA. 18 CFR §292.304 (b) (1987). The Commission’s regulations also allow the

QF and the purchasing utility to negotiate a rate which differs from the rate otherwise required by the Commission’s

regulations. 18 CFR §292.301 (b) (1987). 18 18 CFR §292.101 (b)(6) (2003).

However, if a utility needs capacity, and would

be building capacity itself or purchasing capacity

from another wholesale source, it must first offer

to buy such capacity from QFs. Utilities are not

permitted to withhold purchasing from QFs any

portion of their capacity needs, provided that QFs

are offering power that is comparable to the

capacity that the utility would otherwise obtain

from alternative sources. Furthermore, in
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 13

American Ref-Fuel Co., et al., the Commission

granted a petition for declaratory order finding

that PURPA contracts for the sale of QF capacity

do not convey renewable energy credits or similar

tradeable certificates to the purchasing utility

absent agreement among the parties.19

Under section 210 of PURPA, an electric utility’s

ratepayers are intended to be at least indifferent,

in terms of the rates they pay, as to the source of

power. In other words, the ratepayer is not to

pay any more for power because the utility has

purchased power from a QF rather than

generating the power itself or purchasing power

from another wholesale source. This is the

purpose underlying the incremental cost ceiling

on the rates utilities have to offer to purchase QF

power.20 The Commission’s regulations, in order

to maximize the incentives for QFs, provide that

the rates for purchases from QFs, absent

negotiations, are to be at the statutory ceiling.

Thus, the avoided cost rate is neither more than

nor less than the price the utility would have paid

for comparable power from other sources,

including other wholesale sources.

It is the above stated principles contained in

PURPA that assist the wind industry, as well as

other alternative energy sources, in maintaining

a foothold within the energy industry. If the

provisions contained in PURPA are removed from

the Commission’s rules and regulations, many of

the QFs that supply cost effective energy will be

left without an assured method in which to

generate revenues and thus may be forced to exit

the market once existing contracts expire. Thus,

the possible rescission of PURPA has the potential

to affect the future of the wind industry.

State Renewable Portfolio Standards (RPS) State Renewable Portfolio Standards (RPS)

Together, advances in wind turbine technology

and fossil fuel-related supply and environmental

concerns have led to the growing existence of

green marketing programs and State-mandated

RPS, driving utilities across the country and

around the world to increase the amount of wind

in the mix of energy resources.21

As shown in Figure 2 on the next page, nineteen

states have enacted RPS. An RPS reflects a state’s

commitment to add renewables to the mix of

generation, generally at levels which increase

yearly and which apply to all retail electricity

suppliers. The duration of an RPS and the goal

or percentage of renewables required to be in

each supplier’s generation portfolio vary widely.

A few RPS programs specify not only an overall

renewables portfolio percentage, but also

percentages of the total which must be met by

particular fuel types, such as wind or solar. Some

states which have already achieved their initial

goals are considering raising them by amending

their RPS. Developing and implementing these

RPS initiatives have aided in the development of

renewable energy.

Appendices 2 & 3 provide further information

regarding the current RPS programs in the U.S.

19 See, American Ref-Fuel Co., et al., 105 FERC ¶ 61,004 (2003), reh’g denied, 107 FERC ¶ 61,016 (2004), sub nom.

Xcel Energy Services Inc. v. FERC D.C. Cir. No. 04-1182 (D.C. Cir. filed Jun. 14, 2004). 20 See Conference Report on PURPA, H.R. Rep. No. 1750, 95th Cong., 2nd Sess. 98, reprinted in 1978 U.S. Code

Cong. & Ad. News 7797, 7832, and in FERC Statutes and Regulations ¶5151 , at p. 5106. The full avoided cost rate

applies to purchases from new capacity, i.e., capacity built after November 9, 1978. Rates for purchases from old capacity,

i.e., capacity built before November 9, 1978, may be set below avoided cost if the state commission or nonregulated utility

determines that a lower rate is consistentwith section 292.304(a) of the regulations. See 18 CFR §292.304 (b)(3) (1987). 21 Green marketing takes advantage of electric consumers’ willingness to pay for products that provide environmental,

health or other public benefits. Market research indicates that a significant number of electric customers claim a willingness

to pay a premium in order to buy “green” electric service. By providing customers with a choice in the type of generation, it

is possible to create a voluntary market for renewables.
14 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

• Nine States enacted or amended Renewable

Portfolio Standards (RPS) in 2004.*

• Colorado voters passed first RPS by ballot in

November 2004. November 2004.

• Pennsylvania’s “RPS” consists of separate

agreements between the PUC and each utility.

• Definition of renewable resource varies by State, Definition of renewable resource varies by State,

although all include wind and solar.

• Many States are considering raising goals. Many States are considering raising goals.

Figure 2: Renewable Portfolio Standards in 19 States

Source: FERC analysis, derived from data in: Edison Electric Institute’s State Restructuring Service; DSIRE Database of

State Incentives for Renewable Energy, http://www.dsireusa.org/; State PUC websites; Trade press.

Notes: *Arizona, Colorado, Hawaii, Maryland, Nevada,

New Jersey, New York, Pennsylvania, and Rhode

Island enacted or amended a RPS in 2004.

** Minnesota’s RPS is a non-mandated objective,

requiring that utilities make a “good faith effort” to

meet the goals (except for a mandate for XCel Energy

to develop 1,125 MW of wind power by 12/31/2010.

*** Illinois has a “renewables portfolio goal” without

verification or credit trading. While

  Maine has the highest RPS standard in the U.S., but

the 30% is less than is already in use there.

** ***Pennsylvania’s alternative portfolio standard was

passed on 11/20 and is pending before the governor.
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 15

State Renewable Energy Credits (REC) State Renewable Energy Credits (REC)

Many, but not all, of the states with an RPS have

established Renewable Energy Credit (REC)

programs, which give retail suppliers flexibility

regarding compliance with an RPS. REC

programs involve the trading of energy credits

rather than the physical commodity and typically

resemble tradable emissions credits.

Production oduction Tax Credits (PTC)

Federal production tax credits (PTC) have also

been important in promoting wind generation

projects. Currently the PTC, as renewed in

October 2004, provides a credit of 1.8¢/KWh

produced for ten years from the date a facility is

put into operation. To qualify, a wind facility

must be operational before the PTC expires in

December 2005. 

The Federal PTC has contributed to periods of

intense wind development. In periods when there

is no PTC, potential developers are reluctant to

commit resources to the planning and

construction of new capacity. AWEA estimates

that $3 billion of wind energy projects were on

hold, awaiting the most recent PTC extension.

Appendix 4 lists the wind developments

announced since the renewal of the PTC.
16 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Even with the advances Even with the advances in wind development, wind generation is a relatively new entrant

to markets that were not designed specifically for intermittent energy sources or for generation

sited remotely from load centers. As such, wind generation faces several challenges to achieve

widespread acceptance, including siting and permitting issues, financing issues, and

transmission policies that are currently designed for generating units that are more centrally

located and able to be dispatched. Solving issues facing wind generation may not only

encourage investment in this clean generation source, but may also result in lower prices to

customers, particularly if natural gas prices remain at or above current levels.

Impacts of Wind Development Impacts of Wind Development

While there are environmental benefits to wind

generation, there are also adverse environmental

impacts that must be addressed when siting a

wind farm. For example, the potential impact of

wind turbines on birds including resident,

breeding, and migrating species has frequently

been a concern at both proposed and existing

wind power sites. Birds have been

reported killed at wind power plants

in various locales around the world.

Avian fatalities are typically

confined mainly to areas where large

numbers of birds congregate or

migrate, or where protected species

are affected. This could encompass

quite a few locations, however,

because some of the traits that

characterize a good wind site also happen to be

attractive to birds. For example, mountain passes

are frequently windy because they provide a

channel for winds passing over a mountain range;

for precisely the same reason, they are often the

preferred routes for migratory birds.

If preliminary research indicates that a wind

project is unlikely to seriously affect bird

populations, further studies may be needed to

verify this conclusion. These could include

Challenges to Future Wind Energy Development

monitoring baseline bird populations and behavior

before the wind project begins, then

simultaneously observing both a control area and

the wind site during construction and initial

operation. In certain cases, operational monitoring

might have to continue for years.

For existing wind plants where bird conflicts are

already a concern, the immediate task is to

develop and implement practical

ways to reduce the number of bird

deaths and injuries. Research is

being carried out to determine which

strategies are most effective in

different situations. Proposals

include changing the color of wind

turbine blades, eliminating places on

towers where birds are likely to

perch, and using radar to alert wind

project operators to the imminent

passage of large flocks of birds so that parts of

the wind plant can be shut down. Deaths from

high-voltage transmission lines and equipment

can be avoided by methods such as discouraging

perching near uninsulated wires.

Additionally, wind turbines, out of necessity, are

highly visible structures. Modern wind turbine

towers stand 100 to 160 feet above the ground,

excluding the blade rotor, which may be up to

130 feet in diameter. Turbines are often deployed
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 17

in arrays of a dozen or more machines on

prominent ridges or hilltops in order to maximize

the performance of each turbine.

However, steps can be taken to reduce the number

of complaints by making wind turbines less

obtrusive and more pleasing to the eye. For

example, tubular towers are less offensive than

lattice towers, and partly for this reason they now

are preferred by most wind developers. Also,

taking steps to avoid scarring the land is

important, as is eliminating unnecessary clutter

by burying transmission lines and hiding buildings

and other structures behind ridges or vegetation.

There have also been complaints regarding noise

generated from turbine blades. Those affected

by the noise generated by wind turbines typically

live within a few miles of a large wind power

plant or within several hundred feet of a small

plant or individual turbine. Although the noise at

these distances is not great – a 300-kilowatt

turbine typically produces less noise at 400 feet

than does light traffic 100 feet away — it

nevertheless is sufficient to be heard indoors and

may be especially disturbing in the middle of the

night when traffic and household sounds are

diminished.22

Significant progress has been made in reducing

turbine noise since the first machines were installed

in the early 1980s. The larger machines now on

the market generate less noise (per unit of energy

output) than the smaller machines they replaced.

Overall, wind turbine noise is now, in general, a

minor concern to communities near wind projects

under development today. With proper attention

to setback distances and sound-reduction

engineering, fewer residents will likely be affected.

Siting and Permitting

Not unlike the siting of other generation, wind

development can arouse community and

environmental concerns. Additionally, with the

remote location of the wind resource, accessibility

to and cost of transmission are issues in any siting

decision. The siting of wind resources includes

several steps including extensive locational

assessment to measure wind availability,

environmental impacts, and economic feasibility;

contract negotiations for easements, construction,

maintenance, and off-take; and lengthy regulatory

filings to gain necessary approvals from federal,

state, and local agencies as well as from the

public.23

In typical wind projects, small development firms

do much of the initial development, performing

initial site selection and preliminary analysis from

self-generated funds and some “sweat” equity

with the hope of high returns. For small projects

(<12 MW24), small developers may complete

development themselves for self-generation or in

partnership with local utilities in a position to sign

off-take agreements to fulfill renewables

standards or corporate strategic goals. At times,

they bring on additional equity investors who

value tax credits.25

22 Wind Energy Environmental Issues. National Wind Coordinating Committee Wind Energy Series No. 2. January

1997.23 Derived from American Wind Energy Association Fact Sheet; 10 Steps in Building a Wind Farm. Downloaded from

www.awea.org, October 1, 2004; www.awea.org/pubs/factsheets/10stwf_fs.PDF.

24 Based on Wind Industry classifications - http://www.windustry.org/opportunities/project_types.htm 25 Over 1400 MW of wind power projects have been announced or put back on track since the most recent PTC

extension, with 1000-2000 MW announced as advanced stage, likely, or in development, which demonstrates the importance

of the PTC. Although the renewal was approved in October 2004, only 480 MW of wind generation are expected to be

completed by the end of the year compared with almost 1,700 MW of additions in 2003. GE Wind Energy has already

received contracts for 750 MW of turbines for 2004-05, and another 750 MW of commitments; valued together, these

represent $1.3 billion in new wind development.
18 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

However, more often, once the project is more

defined, small developers will sell a majority of

the project to a strongly-capitalized codevelopment partner such as Florida Power and

Light (FPL), American Electric Power (AEP), or

Zilkha Renewable Energy, among others. These

larger strategic developers have greater financial

resources and legal and technical expertise to

address detailed costs, finance complexity, tax

advantages, and risks of wind power

development and can leverage their own balance

sheets to lower project costs.

Project Financing

Wind project developers confront several hurdles

of process and perception in financing wind

projects under current electric and financial

market conditions. New wind projects must

obtain debt and equity funds. In the past few

years, many lenders to the traditional fossil

generation sector have suffered from

underperforming loans, and some have

reluctantly exchanged their debt for equity in

plants. In many regions, weak margins on the

sale of power, and surplus generation capacity

have depressed the value of recently built and

financed generation.

While liquidity has increased and financing terms

are returning to more favorable levels for

sponsors, debt and equity investors continue to

require extensive due diligence before providing

funding. Only a limited number of lenders –

primarily European banks that funded many

European wind developments – have extensive

experience with wind generation finance. For

new sources of capital, developers must illustrate

that risks, whether real or perceived, are

understandable and manageable.

Projecting revenues for wind generation is harder

than for typical generation sources because of

higher variability of production. The variability

26 Windletter – The Monthly Newsletter of the American Wind Energy Association, Volume 22, Issue No. 5 – May

2003, page 2.

of production is highly dependent on wind speed

– a 2 mph difference can change the economics

of a facility significantly. For example, according

to the American Wind

Energy Association, a

change in wind speed

from 16 to 18.07 mph

would result in a 144

percent increase in

output and a 25 percent

reduction in cost per

MWh.26 While wind

speed measurement

technology is

improving, wind speeds

will continue to vary by

season, month, day, and

even hour. Extensive

new evaluations have

revealed seasonal and annual patterns such that

annual generation falls within +/-10 percent of

predicted annual production.

Given difficulties associated with projecting

merchant revenue streams for wind projects,

financings have typically required “must take as

available” power purchase agreements for the

full output of the facilities with creditworthy

counter parties to mitigate production and price

risk and make lenders comfortable with energy

revenue forecasts to support debt. On the

demand side, load serving entities have been

encouraged by RPS to enter such long-term

contracts for wind generation to meet their

regulated requirements and hedge long-term

price risk.

Even with an energy contract, PTCs are

important to project revenues and investment.

There is an active financial equity market for

projects with tax credits in the U.S. for investors

that have familiarity with investing in tax credits

from Section 29 (synfuel) and Section 8 (low

income housing) credits. Commercial and
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 19

investment banks, insurance companies and

private equity funds ascribe value to the credits

because they are willing to undertake the

associated risk. As long as the project produces

energy the ensuing tax credits shield taxable

income that need not be associated with the

project itself.27 In recent deals, lenders have also

been willing to lend money against credits as PTC

revenues have been leveraged along with the

Power Purchase Agreement (PPA) revenues. From

a lender perspective PTCs bear less credit risk

than PPA revenues because their counterpart is

essentially the federal government.

Transmission Issues

Operationally, wind plants have much lower

capacity factors than conventional thermal

facilities and their output is quite variable -

typically deviating quite significantly from their

pre-arranged schedule. As a result of this, the

effective transmission charges for wind

generators are typically much higher than those

faced by conventional thermal plants, yet these

differences vary significantly on a region-byregion basis. These factors are important

components in the calculation of traditional

transmission rates.

As shown below in Figure 3, these differences are

not consistent between various power systems

and differing transmission rate designs can have

considerable impact on wind generators. Some

utilities have agreements with alternative fuel

generators that can significantly mitigate the

pricing impact faced by the wind facilities.

Additionally, the rate differentials for wind plants

vary significantly between RTO and non-RTO

regions.

Figure 3: Cost Comparison of e 3: Cost Comparison of Transmission for ansmission for Wind vs. CCGT Plants

Source: FERC analysis, derived from data in OATT Tariffs, NREL, CAISO, PacifiCorp, FERC OMTR, FERC OMOI

Note: Calculations based on OATT tariff schedules; 55 percent capacity factor for CCGT and 38 percent capacity factor for

wind; scheduling imbalance error of 1 percent for CCGT and 20 percent for wind; $50/MWh average system price for

power; CAISO rate based on SCE TAC rate.

27 “Spot Picking”, Project Finance September 2004, pp. 13-16.

-

2

4

6

8

10

12

14

16

18

Idaho Pwr Wind

Idaho Power

BPA Wind

BPA

PAC Wind

PAC

PGE Wind

PGE

Avista Wind

Avista

APS Wind

APS

CAISO Wind

CAISO

$/MWh

Losses Transmission Other Ancillary Svcs Imbalances
20 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Available ailable Transmission Capacity (ATC)

A fundamental problem facing wind generators

is the lack of long-term firm available

transmission capacity (ATC) over many key

interfaces, even though operational data show

that many of these interfaces are congested for

no more than twenty to fifty hours per year. This

means that there would be adequate capacity

available to move wind output in many hours,

but no way of securing long-term firm

transmission service needed to attract financing.28

Under current capacity-based reservation rules,

wind generators typically must acquire long-term

firm transmission for the maximum output of the

facility even though actual use of the reserved

capacity is much less. Due to this, wind

developers face higher costs relative to other

transmission users who may more efficiently use

the transmission capacity.29 Thus, wind

generators are required to reserve more

transmission capacity than necessary (and pay

for the unused capacity). Although the Order No.

888 pro forma tariff permits a customer to sell or

transfer surplus capacity under an agreement,

wind generators argue that, without an active

secondary market, the wind generator receives

little to no value for its surplus firm transmission.30

The choice between the standard long-term firm

point-to-point transmission service in excess of

what they need, and non-firm point-to-point

transmission service that is less than what they

28 This is because a “firm” request by a wind generator is considered by the transmission provider the same as a firm

request from a thermal generator, for example, that may be expected to generate at consistently high capacity factors.

Therefore, instead of determining whether surplus ATC may be available for a wind project given its intermittent nature and

low average capacity factor, the transmission provider is required to evaluate a customer’s request for firm service on the

basis that ATC must be available all the time at 100 percent of the customer’s request for firm service. 29 Under the Order No. 888 pro forma OATT, only long-term agreements in excess of one year are subject to rollover

rights under Section 2.2 (Reservation Priority for Existing Firm Service Customers). Accordingly, in order to ensure the

availability of capacity to transmit energy as it is generated for the life of the project, the generator must reserve the maximum

required capacity on a long-term basis. Otherwise there is no guarantee of availability. See, 18 CFR Part 35. 30 While Section 23 of the pro forma OATT allows a transmission customer to sell or assign all or part of its reserved

transmission services, it is unlikely that wind generators can accurately forecast over continuous terms (e.g., one week) in

order to capture value of foregone transmission.

require and with no guarantee of availability, puts

wind resources in a difficult competitive position.

The reservation charges for firm point-to-point

transmission are akin to take-or-pay charges,

meaning generators must reserve transmission

capacity in advance and pay for that capacity

regardless of how much energy is actually

scheduled and transmitted. In addition, non-firm

service is only available under pro forma tariffs

for periods of up to one year. Wind generators

that require 10 or 15-year contracts for

transmission will not be able to make use of nonfirm service in order to obtain financing.

RTO and ISO tariffs are generally able to

overcome this problem through the provision of

transmission service in concert with centrallydispatched energy markets. Under these tariffs,

most customers take regional, or network,

transmission service rather than point-to-point

service. Because this transmission service is billed

based on the amount of service taken, rather than

on a reserved amount of service, a wind generator

(or customer of wind resource) avoids

transmission payments based on reservation

amounts.

Nevertheless, even under the pro forma tariff,

there are alternatives that can be considered in

order to remedy the problem of uneconomic longterm firm point-to-point transmission service.

These alternatives may include hourly firm pointto-point and curtailable, or “conditional,” firm

point-to-point transmission service. These
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 21

products may offer the wind generator more

certainty for gaining access to the grid and would

assist in securing financing for the construction

of new generation. These new services are not

part of the Order No. 888 pro forma tariff, and,

thus, they are not widely available throughout

the industry. These newly proposed transmission

products offer the possibility of increased grid

access for wind generation.

One alternative to the industry standard,

capacity-based transmission access fees could be

a commodity charge for service to small and/or

low load-factor customers. Such a charge could

be billed as service is scheduled and used up to a

specified reservation level (essentially, simulating

an energy-based access fee by substituting the

effective capacity of an intermittent generator

into the generally applicable capacity-based fee).31

This approach may be best suited for facilities

that have an operational history. However, a

proxy effective capacity rate could be applicable,

especially where the facility is within a

geographic area that has known resource

characteristics and the facility’s production can

be reasonably estimated. Although not a true

energy-based tariff, such an arrangement could

partially address issues facing wind energy.32

A variation to this approach may be for the

intermittent generator to reserve firm

transmission capacity equivalent to the unit’s

effective capacity, and use available non-firm

transmission if output is more than the effective

capacity. Problems may arise if the financing used

for the intermittent facility requires a certain level

of energy production that involves transmission

to the purchasing party, and if the certainty of

this transmission service affects the likelihood of

a loan default. A lender may require an

intermittent generator to reserve firm

transmission capacity to ensure power delivery.

In addition, users of non-firm transmission may

be curtailed if congestion exists on the

transmission system, or may be displaced by

transmission customers that desire firm

transmission or non-firm transmission of greater

length. In these situations, the intermittent

31 The effective capacity would account for the operational differences inherent in wind generation in order to determine

an appropriate capacity factor as an input to the access fee calculation. For example, access fees could be calculated based

upon an effective capacity rating of 30 percent, a reasonable estimate of a wind farm’s production capabilities. 33 A policy question would be whether this should be offered as an incentive only to wind generators or should it be

made available to all low-load factor customers.
22 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

generator that is using non-firm transmission

service would have the right to match longer-term

non-firm service before being displaced.

An example of the process in which market

participants are developing alternatives to the

current Order No. 888 tariff services is the Rocky

Mountain Area Transmission Study (RMATS).33

In the RMATS region there is no firm ATC on

transmission paths, even while actual physical

congestion occurs for less than 20 to 50 hours

per year.34 RMATS is seeking to test if there is

any physical capacity on certain paths in the

current system that could be utilized to move

significant amounts of wind energy. The goal of

the RMATS is to demonstrate the value of

removing institutional impediments to support

additional wholesale competition.

The work done in

RMATS has led to the

development of

conditional-firm and

priority non-firm

transmission services.

The conditional-firm

transmission product

would be for firm

service during a defined

period of the year and

conditional-firm service

for the balance of the

year. Conditional-firm service would be curtailed

prior to firm service, but after all non-firm service.

This priority of curtailment combined with a clear

understanding of the curtailment risk during the

33 The purpose of the study is to identify in an open and public process, potential generation projects in the Rocky

Mountain sub-region and the electric transmission needed to support these projects. 34 See, Rocky Mountain Area Transmission Study Final Report. September 2004. 35 Docket No. ER04-567-000.

36 Although short-term firm service does not guarantee access to the grid for all hours, it may be possible for the

generator to combine short-term and long-term service to reduce its costs as compared to acquiring only long-term firm

service. 37 See, Southern Company Services, Inc., 100 FERC ¶ 61,314 (2002); Duke Energy Corporation, 88 FERC ¶ 61,184

(1999), order on reh’g, 89 FERC 61, 190 (1999).

conditional months will give generators and

utilities more confidence in their ability to move

power to loads. In addition, the development of

a priority non-firm transmission tariff product in

which the customer would agree to be curtailed

when operations were constrained could also

benefit wind generators. A more detailed

explanation of these services appears in Appendix

1.

The Commission has accepted various novel

transmission products, in electric as well as gas

markets, which may provide the wind industry

with a working model for the development of

further transmission services. For example, El

Paso Electric Company filed revisions to its open

access transmission tariff to provide hourly firm

point-to-point transmission service.35 Hourly

firm transmission service has the potential to free

up transmission capacity that otherwise would

not be available. By purchasing an hourly firm

transmission service, wind generators have the

opportunity to acquire transmission for only the

periods in which they are able to generate

electricity, thereby lowering the embedded costs

of providing energy.36

The Commission has also accepted a recallable

firm transmission service that provides customers

with additional transmission service options and

enhanced flexibility.37 Under the recallable firm

transmission service, a transmission provider may

offer, on a first-come, first-served basis, firm

transmission service under an OATT on a

comparable basis. The transmission provider will

retain the right to recall all or a portion of the
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 23

reserved transmission capacity, subject to a

reasonable notification period. The terms of

service are negotiated to include the delivery and

receipt points, the price structure, the amount of

capacity subject to recall, the length of the recall

period, and the length of time that a customer

must respond to a recall notice. This form of firm

service would have the characteristics of longterm firm point-to-point with regard to

reservation for periods greater than one year and

the opportunity for a level of rollover rights.

In the gas industry, Northern Natural Gas

Company (Northern Natural) offers a volumetric

firm transmission service for which it charges a

volumetric rate based on a shipper’s projected

load factor with a minimum term of one year.38

A shipper must maintain its projected market

share from Northern Natural, i.e., it cannot use

Northern Natural as a swing supplier. The

volumetric service allows a shipper to “pay as it

goes” and to shift some weather-related risks to

the pipeline. For example, if a winter is warmer

than expected and a shipper’s demand is reduced,

its overall payment would be lower than if it had

purchased firm service and paid monthly

reservation charges. On the other hand, if the

winter were colder than normal and the shipper’s

demand were higher, it would pay more overall.

This type of service could be applied to electric

transmission service through the development of

firm point-to-point service based upon an estimate

of the capacity factor of a generation plant.

Rather than an intermittent resource reserving

transmission capacity based upon its peak or

contract output, it can reserve annual transmission

service based on its projected capacity factor,

adjusted annually. Any over-use from each year’s

designated capacity would be paid by the

generator through non-firm service.

38 See, Northern Natural Gas Company, FERC Gas Tariff, Fifth Revised Volume No. 1, Eighteenth Revised Sheet No.

54; ANR Gas Pipeline Company, FERC Gas Tariff, Second Revised Volume No. 1, Substitute Second Revised Sheet No. 37. 39 Id.

Many pipelines, including Northern Natural and

ANR Pipeline Company (ANR), also offer a

limited firm transportation service.39 Limited

firm service is firm service up to 20 days per

month. Typically, there is no minimum term, and

shippers pay two-part rates for the service derived

from the monthly firm service rates, converted

into a daily charge. The pipeline can choose not

to schedule the service, in whole or in part, on

any day, for any reason, up to 10 days per month.

Service for more than the maximum number of

days per month must be done under a separate

contract and rate schedule.

An identical form of service can be applied to

open access transmission. A transmission owner

that experiences predictable monthly patterns can

offer service for a specified number of days per

month. Alternatively, longer periods, such as

specific months per year can be offered on those

transmission systems that experience significant

peaks in either summer or winter, but have excess

capacity during the shoulder months. Thus, the

service offering could be calculated as seasonal

rates and only available for specific periods per

year.

It is important to note that any type of new

transmission service created to accommodate

wind will impact other market participants. For

example, conditional firm service or priority nonfirm service will affect traditional firm and nonfirm service by changing the process in which

customers are curtailed. This may cut into the

flexibility enjoyed by existing customers, who

may have a sense of entitlement to such flexibility,

seeing it as part of the service they have

contracted and paid for. The effects of these

services must be closely examined to ensure that

one class of customer does not subsidize another

class.
24 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Rate Pancaking

Except for transactions within the ISO/RTOs now

in place, transmission customers are faced with

additional charges for every utility border they

cross. This pancaking of access fees may be even

more acute for wind. Such duplicative charges

can restrict the area in which wind can be

economically secured, particularly since wind is

so often located in remote areas away from

major load centers.

The emergence of RTOs and ISOs in certain areas

of the country has assisted in alleviating the

problem of rate panacking; however, the problem

remains in the areas where RTO/ISO

development has slowed or stalled due to the

inability to collapse multiple systems into one

independently managed regional transmission

system.

To overcome this, utilities may choose to work

together to eliminate the payment of multiple

charges for transmission. This has occurred

within ISOs/RTOs and is being explored outside

as well.40 The Commission has encouraged the

elimination of pancaked rates for transmission

services within a regional transmission system

and supports transition periods for moving to a

system of non-pancaked rates. While initially

expressing a preference for “postage stamp”

rates (a single, uniform, average rate across all

utilities in the regional transmission system), the

Commission permitted “license plate” rates (a

rate for service that would vary based on the

zone where the power was delivered), because it

avoids rate averaging and allows a utility to

maintain its existing rate for deliveries on its

system, license plate rates minimize cost shifts.

Under such a rate design, upgrades built on one

40 Rocky Mountain Area Transmission Study Final Report. September 2004.

41 California Independent System Operator Corp. 107 FERC ¶ 61,274 (2004). order on reh’g 108 FERC ¶ 61,254

(2004).

utility’s system would be paid for by that utility’s

load through the load ratio share.

Losses

Transmission losses are generally a function of

distance and, therefore, are of greater importance

to remote resources. The Commission has stated

a preference for energy prices and the associated

transmission usage charges based on marginal

costs, in order to promote economic efficiency.

Any protocol that results in greater loss charges

based on distance, such as marginal losses, may

discourage wind resource development more than

other technologies.

The Commission, in regions, is moving toward a

marginal cost transmission pricing policy. The

Commission believes that moving toward a

marginal cost pricing approach will lead to an

efficient, least-cost dispatch for energy. When

prices at each location reflect the full marginal

cost of delivery (i.e., energy, congestion and

losses), customers can make efficient choices

among suppliers at different locations. To the

extent that a marginal cost approach for

transmission disadvantages remote resources, the

Commission has allowed State entities along with

interested market participants to offer proposals

to counter any negative impact of marginal losses

on wind and other remote resources.41
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 25

Imbalance Charges

An additional delivery issue for wind energy is

how imbalance charges are imposed under the

pro forma tariff. Imbalance charges were

developed in order to ensure that generators’

actual hourly output matched their scheduled

amounts. These imbalance charges work to

enhance reliability, encourage accurate

scheduling and discourage gaming. However, this

type of energy imbalance penalty is particularly

punitive to intermittent resources, as they have

greater difficulty predicting scheduled amounts

and even less control over their dispatchability.42

Since wind is not completely unpredictable on a

day-ahead basis, it is possible for some wind

capacity to be scheduled on such a basis.

Statistical methods can be used to commit wind

energy in advance. For example, the prior day’s

wind or the prior hour’s wind can be used to

estimate the wind speed, and hence the capacity

available for the next period.

Centralized markets are often able to address this

issue, both with respect to substituting real-time

energy markets for imbalance penalties and with

respect to novel tariff provisions. A potential

solution outside of centralized markets is for

individual transmission operators to allow

generators the flexibility to schedule closer to realtime. The ability of wind generators to predict

their output increases dramatically in the hour

preceding the delivery hour. It is conceivable that

intermittent resource schedule adjustments would

represent negligible changes in overall system

conditions and therefore not greatly affect system

reliability.

The Commission-approved California

Independent System Operator (CAISO)

Participating Intermittent Resources Program

(PIRP) exempting wind from hourly imbalance

penalties and substituting monthly netting of

imbalances in return for centralized wind delivery

forecasting is an example of the type of tariff

reforms that could facilitate wind development.43

The CAISO’s voluntary PIRP, was created to

accommodate projected growth of wind

generation attributable to California’s renewable

supply requirements. Under the PIRP, the CAISO

forecasts and schedules wind output, and nets any

imbalances over the course of a month.

Transmission Planning

Given that wind is a remote resource,

transmission planning is especially important for

wind. Also, while transmission expansion is a

time intensive process, wind farms can move from

paper to production in a relatively short period

of time. This mismatch often leaves wind farm

development waiting for transmission expansion

to catch up.

The emergence of RTOs and ISOs has assisted in

broadening transmission planning and expansion

into regional efforts. Rather than performing

expansion on a utility-by-utility basis, an

independent entity can be charged with the

responsibility of expanding the grid in an efficient

manner. Regional entities are better equipped to

represent interests of the region’s various market

participants and expand the transmission grid in

an economically efficient manner. However,

RTOs and ISOs are not the only way to

accomplish regional planning and cost allocation.

42 Under Schedule 4 of the OATT, the Transmission Provider establishes penalties for energy imbalances exceeding +/-

1.5 percent of the scheduled transaction. The Commission however, has allowed more flexible deviation bands of +/- 10

percent for open access retail service under the OATT due to a customer’s inability to accurately forecast load and submit

accurate schedules. Similar flexibility could be incorporated into the OATT for transmission service involving wind

generation. 43 California Independent System Operator Corp., 98 FERC ¶61,327, order on compliance filing, 99 FERC ¶ 61,309

(2002).
26 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

For example, the RMATS process is addressing

these issues by attempting to determine efficient

ways in which to expand the grid on a regional

basis.

Interconnection

Order No. 2003,44 issued by the Commission on

July 24, 2003, requires all public utilities that own,

control, or operate facilities for transmitting

electric energy in interstate commerce to (1) file

revised open access transmission tariffs

containing Commission-adopted

standard generator interconnection

procedures and a standard

interconnection agreement, and (2)

provide interconnection service to

electric generating facilities having a

capacity of more than twenty

megawatts. While Order No. 2003

recognized that it would not resolve all

issues that may arise, the single,

uniformly applicable set of procedures

and agreements it sets forth to govern

the process of interconnecting large

generators to a Transmission Provider’s

Transmission System will play a crucial role in

bringing much-needed generation into national

energy markets to meet the growing needs of

electricity customers.

In Order Nos. 2003 and 2003-A, the Commission

generally recognized that certain standard

provisions contained in the standard

interconnection procedures and agreement could

disadvantage generators relying on nonsynchronous technology, namely wind

44 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 68 Fed. Reg. 49,845

(2003), FERC Stats. & Regs., Regulations Preambles ¶ 31,146 (2003) (Order No. 2003), order on reh’g, 69 Fed. Reg.

15,932 (2004), FERC Stats & Regs., Regulations Preambles ¶ 31,160 (2004) (Order No. 2003-A), reh’g pending. 45 See Order No. 2003-A at P 407, n. 85. 46 Id. 47 Id.

generation.45 In order to avoid further

exacerbating the obstacles that wind generation

currently faces, the Commission, in Order No.

2003-A, clarified several of the interconnection

standards to accommodate newer technologies,

such as wind generators.46 Additionally, in Order

No. 2003-A the Commission added a new blank

Appendix G to its standard generator

interconnection agreement to serve “as a

placeholder for inclusion of requirements specific

to newer technologies.”47

Recently, wind industry representatives

have proposed that the Commission

consider including in Appendix G a

national “grid code” applicable to the

interconnection of large wind

generators. The proposed “grid code”

contains point of interconnection

technical standards and more flexible

interconnection queuing and study

procedures. The Commission held a

technical conference on this proposal on

September 24, 2004, and accepted posttechnical conference comments from

interested parties. The Commission will likely

issue a Notice of Proposed Rulemaking (NOPR)

regarding Appendix G in the near future.

Capacity Credits

Wind advocates contend that wind generators

can provide capacity value (and not just energy)

to the system. Others suggest that, due to the

inability to instantly dispatch a wind generator,

wind generators have no capacity value and

should not count toward reserve margins.
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 27

In order to ensure electric reliability, Load Serving

Entities (LSEs), ISOs and RTOs collect outage

data to determine the probability that a generator

will be available to deliver electricity when

needed.48 Operators use this outage data to

calculate the probability that generating capacity

will be insufficient to meet load and reserve

requirements. This calculation results in the loss

of load probability (LOLP).49 By utilizing the

LOLP a model can be developed to calculate the

Effective Load Carrying Capability (ELCC) of a

generator. The ELCC is the increase in system

peak that can be supported by the generator,

maintaining a target reliability level.50 It is

reasonable to apply these models to wind

generation in order to determine the ELCC and

therefore assign a particular capacity value to

each respective generating unit (or farm). Results

vary by location, but capacity credits using ELCC

models are often in the range of 20 percent of

nameplate capacity. In lieu of studies, some

regions use historical output during summer

months.

One significant drawback is that methods such

as ELCC require significant data. Typically, one

year of load and wind output data is required,

and multiple years are preferred, to capture the

variability in wind output and load. In light of

this deficiency operators may choose to apply

other techniques that approximate ELCC with

less effort and reduced data requirements. Such

48 To capture year-by-year variation in outages, multiple years of outage data may be required for a particular generator.

For newer technologies or generators without that level of data, some utilities and RTOs will aggregate the outage data by

generator technology to determine a generator technology “class average.” 49 An industry standard is to keep Loss of Load Expectation (LOLE, based on the LOLP calculations) to one day in 10

years.50 For example, if a system has a LOLE of 1 day in 10 years, the ELCC is the increase in system peak that could be

supported at the same reliability level after adding a wind power plant. ELCC calculations are based on hourly LOLP

calculations for at least one year, meaning that the LOLP and the load-carrying capability of a generator are measured during

peak and off-peak hours. 51 The California Public Utilities Commission, as part of its resource adequacy proceeding, is developing a methodology

to allow LSE’s to utilize wind resources to meet reserve requirements.

methods include measuring a generator’s capacity

contribution at system peak or during peak and

off-peak periods. These estimates may be further

adjusted by a generator’s forced outage rate and

by a generating plant’s internal plant energy

consumption.

Certain regions, such as PJM Interconnection,

LLC (PJM), ISO-New England (ISO-NE), and

New York Independent System Operator

(NYISO), have adopted policies that allow wind

generation to participate in the market as a

capacity resource.51 This has enabled wind

resources to contribute to grid reliability while

earning an additional revenue stream increasing

the economic viability of the wind farm.
28 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

In PJM wind generators are eligible to receive a

capacity credit.52 For wind projects in operation

for three years or more, after adjusting the wind

generator’s nameplate capacity by the equivalent

forced outage rate of a wind generator, PJM

determines the capacity credit by measuring the

capacity factor of a wind generator delivering

energy during the hours of 3 to 6 p.m., from June

1 through August 31. The capacity credit is a

rolling three-year average, with the most recent

year’s data replacing the oldest year’s data. This

methodology applies to wind projects that have

been operating for three years or more.

For new projects that lack sufficient data, PJM

uses a class average, defined as the annual

average capacity factor of all wind projects in

PJM during the 3-6 p.m. hours from June through

August. Operating data for an individual wind

plant replaces the wind class average when such

data are available.

Both ISO-NE and the NYISO allow wind projects

over 1 MW in capacity to qualify for a capacity

credit in each respective territory. Wind

generators can submit the results of a four-hour

sustained maximum output test, for both summer

and winter. The results of the tests are the wind

generator’s initial capacity credit in ISO-NE and

the NYISO. Both ISOs adjust the capacity credit

monthly based on data submitted by the generator

on actual generation and maintenance hours the

previous month.

52 PJM approved a proposal from a working group in April 2003, with the effective date of June 1, 2003 (PJM 2003c).
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 29

The installation of The installation of 100,000 MW of wind power by 2020 – comprising approximately six

percent of the U.S. electricity supply – is attainable.53 The United States faces many challenges

as it prepares to meet its future energy needs. Electricity supply crises, volatile natural gas

and gasoline prices, and heightened concerns about the security of the domestic energy

infrastructure and of foreign sources of supply are all elements of the energy policy challenge.

As the United States seeks to become less dependent on fossil fuels as an energy source, more

priority has been given to renewable energy. Wind energy has the potential to be an important

part of the diverse energy portfolio that is needed for a stable, reliable energy sector in the

United States.

The movement to address issues related to the wind industry is currently gaining momentum.

The accommodations in Order No. 2003 to address the interconnection needs of wind

generation highlight this fact. Nevertheless, certain transmission tariff provisions may create

barriers for innovative technologies that do not operate with the same characteristics as current

thermal resources.

Staff recommends that the Commission undertake technical discussions in order for the energy

industry to inform the Commission and each other on the changes necessary for competitive

integration of new resources. Through these discussions participants would be able to discuss

whether changing the market structure would essentially remove the need for technological

innovation in order to overcome regulatory hurdles and compete

effectively in the market. Through these conferences, the Commission

could use its experience to further electric competition and to identify

consensus on policy initiatives necessary to institute change if those

changes are unable to come about through the natural evolution of

the electric industry.

53 Presentation of Deputy Secretary of Energy, Kyle McSlarrow, at Global Windpower 2004, Chicago, March 24, 2004.

Conclusion
30 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Appendix 1: Appendix 1: Conditional-Firm Service Tariff Product54

The conditional-firm transmission product would be for firm service during a defined period of the

year and conditional-firm service for the balance of the year. Conditional-firm would be curtailed

prior to firm service, but after all non-firm service. This priority of curtailment combined with a clear

understanding of the curtailment risk during the conditional months will give generators and utilities

more confidence in their ability to move power to loads.

The Conditional-Firm Service would have the following characteristics:

· Conditional-firm service would be offered to customers when ATC to meet a long-term firm

request is not available for the full amount of the request for twelve months of the year.

· Conditional-firm service would be offered for the same duration as long-term firm.

· Conditional-firm service would be a combination of firm service for a set number of months of

the year with service curtailment for the remainder of the year.

· This transmission service would be curtailed after all non-firm service but prior to firm service

and would be subject to curtailment only as necessary to maintain system reliability and not for

economic or other non-reliability reasons.

· Customers purchasing conditional-firm service would be given detailed information about

curtailment risk, i.e. the hours of likely curtailment, during conditional service months of the

year in advance of their commitment.

· Customers purchasing conditional-firm service have a right to retain their original queue status.

· This service would be appropriately priced relative to long-term firm service, reflecting its higher

potential for curtailment.

Priority Non-Firm Service Tariff Product

Point to point transmission service is defined in

OATT-compliant tariffs as either firm or nonfirm. NERC and tagging processes have defined

seven levels of firmness for point-to-point service:

1-redirect from secondary points on the system,

2-hourly non-firm, 3-daily non-firm, 4-weekly

non-firm, 5-monthly non-firm, 6-network service

from secondary non-Network resources, and 7-

firm. These categories allow transmission

operators to curtail by level of firmness. The

priority non-firm transmission tariff product

54 Rocky Mountain Area Transmission Study Final Report. September 2004 pp5-14.

would essentially be a new “category 5.5”

service, available long term, in which the customer

would agree to be curtailed when the operations

were constrained.

The requirements associated with network

service (priority 6) and the fact that non-firm

service is not available for periods longer than

one year is an impediment for new intermittent

generators to procure financing. Yet there is

transmission capacity available on most paths in

many hours of the year. A Priority Non-Firm

transmission product could enable generators to
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 31

use this capacity. This product would have a lower

priority than firm service, and would therefore

be subject to curtailment before any firm

curtailment. A level 5.5 priority would also be

curtailed prior to curtailment of a secondary

network resource, but would receive priority over

all other non-firm service. Because Non-Firm

Point-To-Point Transmission Service applies to

non-network loads and resources, a long-term

product would be useful for either merchant wind

plants or for entities that don’t have a network

agreement in place.

The Long-Term Priority Non-Firm Point-To-Point Transmission Service Product would have the

following characteristics:

· Long-Term Priority Non-Firm service would be offered to customers when there is sufficient

capacity available in most hours of the year.

· Long-Term Non-Firm would be offered for a period of up to ten years.

· The curtailment priority would mean that the transmission service would be curtailed after nonfirm priorities 1-5 but prior to secondary service, priority 6 and firm service, priority 7.

· Customers purchasing long-term non-firm service would be given detailed information about

curtailment risk in advance of their commitment.

· Customers purchasing long-term non-firm service would have a right to retain their original

queue status.

· Pricing for this service would be based on proportionate use of the system.
32 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Appendix 2: Appendix 2: Renewable Portfolio Standards by State

State Status Date First Goal End Goal Required Location?

Arizona Enacted Amended 1996 • Mar-01 0.2% in ’01 1.1% over Arizonaexcept solar

2007-20012

California Enacted Sep-02 * 20% by ,17 No

Colorado Ballot initiative Nov-04 3% by ’07 10% by 2015; Colorado 1.25% credit

of which 4% solar

Connecticut Connecticut Enacted Amended Apr-98’99, ’03 6.5% by ’03 10% by 2010 NEPOOL, NY, PJM (if RPS)

Hawaii Enacted Amended 2001Jun-04 7% by ’03; 20% by ’20 Hawaii

8% by ’04

Illinois Enacted Jun-01 5% by ’10 15% by ’20 Illinois

Iowa Enacted Re-Enacted Iowa 19831991 105 MW 2% by 2011 IA or contractual

obligation

Maine EnactedAmended 19992003 * 30% by ’00 Maritimes control area

Maryland Enacted Apr-04 3.5% by ’06 9.5% by ’18 PJM Maryland

Massachusetts Enacted Regulations 19992002 1% by 2003 4% by 2009 No

Minnesota Enacted Amended 20012003 1% by ’05 10% by 2015 + No

1% biomass

Nevada Enacted(2nd law) Jun-01Apr-04 5% by’03 & ’04 15% by ’13 of NV or dedicated

which 5% solar transmission line

New Jersey Enacted Amended 1999Apr-04 6.5% by ‘08 of 6.5% by ’08 PJM: generated or

which 90 MW solar by ‘08 delivered into

New Mexico Enacted Dec-02 5% in ’06 10% by 2011 No

New York Enacted ork Sep-04 2006: add 0.94% 25% by 2013 NS

= ~ 3700 MW

Pennsylvania Enacted 1999 5.7% by ’07 18% by 2020 PJM

Re-enacted Nov ’04

Rhode Island Enacted Jun-04 3% ’07 16% by ’19 NEPOOL

Texas Enacted 1999 400 MW by ’02 2000 MW by Texas

’09- ’19

Wisconsin Enacted Amended Apr-98 Oct-99 0.5% by ’01 2.2% by 2011 WI or contract path to WI

Sources: Sources FERC analysis, derived from data in: DSIRE Database of State Incentives for Renewable Energy; State PUCs, Energy

Information Administration, DOE; Edison Electric Institute; Lawrence Berkeley National Laboratory; The Wall Street Journal;

interviews, trade press* unable to obtain complete information by publication time (11/16/04)NS= No Standard Set * 
ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS 33

Appendix 3: Appendix 3: RPS Mechanisms by State

WindState State supportive Tracking & Renewable RPS- Government Green

Renewable State Funds Verification Energy Credits applicable Power Purchase

 Energy Funds or Programs System? (REC) Sectors Programs ****

Arizona no no q Arizona uasi no regulated utilities 1 Local

California yes yes yes no California retail sellers 3 local

Colorado no Colorado no** planned planned retail sellers customers 2 Local

 => 40K

Connecticut Connecticut yes yes * yes Connecticut regulated utilities 1 State

Hawaii no * * no regulated u Hawaii tilities no

Illinois yes yes no no regulated u Illinois tilities 1 State1 Local

Iowa no yes no no 2 Iowa IOUs, based on peak load no

Maine no no * yes Maine regulated utilities 1 State

Maryland yes yes pl Maryland anned yes retail sellers 1 State

Massachusetts yes yes yes yes Massachusetts regulated utility 1 State 1 Local

Minnesota yes yes * yes Minnesota good faith effort; no

Xcel mandate

Nevada * * * yes retail sellers no Nevada

New Jersey yes yes yes yes New Jersey IOUs 1 State

New Mexico * * yes yes regulated u New Mexico tilities being studied

New York yes yes planned * regul ork ated utilities 1 State

Pennsylvania yes yes pl Pennsylvania anned * competitive default suppliers 1 State

Rhode Island yes yes Rhode Island * * retail sellers 1 State

Texas yes yes yes yes exas retail sellers no

Wisconsin yes yes yes yes regulated u Wisconsin tilities 1 Local

Sources: Sources FERC analysis, derived from data in: DSIRE Database of State Incentives for Renewable Energy; State PUCs, Energy

Information Administration, DOE; Edison Electric Institute; Lawrence Berkeley National Laboratory; The Wall Street Journal;

interviews, trade press Note: Some States have created Clean Energy Funds to support early-stage R&D of clean energy

technologies. Wind and Solar have received the majority of these funds. Non-RPS States with Clean Energy Funds include:

Delaware, Ohio, Oregon, and Montana* unable to obtain complete information by publication time (11/16/04)** Colorado’s RPS * 

gives utilities extra incentive on their rate of return for renewables; other states have similar programs.***Mandate requires

retail sellers to offer green-pricing programs; Choice indicates programs exist for retail customers. These also exist in many nonRPS States****State or local governments that have passed laws requiring a certain amount of power be purchased from

renewable sources.
34 FEDERAL ENERGY REGULATORY COMMISSION STAFF BRIEFING PAPER

Appendix 4: Appendix 4: New Projects Announced Since PTC Renewal New Projects Announced Since PTC Renewal

Date State Project Name Developer Date(est) Size Power Usage/ RPSAnnounced Installed (MW) Other eligible

Jul-04 OK Weatherford FPL Enegy 2005 106.5 waited for PTC extension; no

Wind EC 20-year PPA

Sep-04 CO TBA Xcel Energy TBD up to asked Colorado PSC to yes

500 accelerate RFP process

to take advantage of credit

Sep-04 IA Blairsburg enXco; Clipper 2004 310 MidAmerican buying output yes

Wind Power from two farms; will bring

it to 12% renewables

Sep-04 IA Storm Lake enXco; Clipper 2005 * > 80% sold under long- yes

Wind Power term PPAs to MidAmerican

Oct-04 W.V. Liberty Gap: U.S. Wind Force 2005 79 talks with 4 potential no

Franklin Ridge off-takers

Oct-04 VA Liberty Gap-Phase II U.S. Wind Force 2006 100 in talks with 4 potential no

off-takers; more MW may be

added later

Oct-04 IA TBA Alliant Energy 2005 130 will be added under PPAs yes

with PTC extention

Oct-04 WI TBA Alliant Energy 2005 100 will be added under PPAs yes

with PTC extention

Oct-04 NB Ainsworth Nebraska Public 2005 60 Omaha PPD will purchase no

Power District 10 MW; Renewable Energy

Systems will build

Oct-04 MN Trimont PPM Energy 2005 100 15 year PPA with Great River yes

Energy, a co-op

Oct-04 OR Klondike II PPM Energy 2005 75 announced shortly; no

fully permitted

Oct-04 MD Roth Rock Synergics Wind 2005 40 n/a yes

Energy

Oct-04 AZ Sunshine Wind Park Foresight 2005 60 Seeking a PPA with APS yes

Energy Sunshine

Oct-04 TX Callahan Divide FPL Energy 1Q 2005 114 FPL will B-O-O; output sold yes

under long-term contract

Oct-04 TX Wildorado Cielo Wind 2005 160 Xcel Energy: long-term PPAs yes

Power

Oct-04 NM San Juan Mesa Padoma Wind 2005 120 Xcel Energy: long-term PPAs yes

Power

Oct-04 NM Tucumcari Cielo Wind 2004-05 80 Xcel Energy: contracted for yes

Power all output to meet NM RPS

Oct-04 SD Rolling Thunder Clipper 200-300 3,000 still in negotiations; plans no

Windpower MW/2-3 yrs to stage over several years

Nov-04 WI multi six developers * ~400 4 Wisconsin utilities contracted yes

to purchase output from farms

constructed in /05

Nov-04 CA Kumeyaay Superior * 50 San Diego G&E: 10-year yes

Renewable Energy PPA for entire output

Note: projects FERC was aware as of 11/15/04Definitions: B-O-O, Build-Own-Operate; PPA, Power Purchase Agreement

Sources: Sources FERC analysis, derived from data in: DSIRE Database of State Incentives for Renewable Energy; State PUCs, Energy

Information Administration, DOE; Edison Electric Institute; Lawrence Berkeley National Laboratory; The Wall Street Journal;

interviews, trade press