National Rural Electric Cooperative Association 4301 Wilson Boulevard Arlington, VA 22203-1860 April 2003
Table of Contents
I. INTRODUCTION 1
II. WIND POWER FUNDAMENTALS 3
III. WHERE THE WIND BLOWS 6
IV. STATE AND FEDERAL INITIATIVES 9
V. WIND POWER TECHNOLOGY 23
VI. DISTRIBUTION UTILITY ISSUES 30
VII. TRANSMISSION AND THE WHOLESALE MARKET 53
VIII. ISSUES FROM THE CONSUMER PERSPECTIVE 59
IX. WIND ECONOMICS 64
X. RESOURCES 74
I. INTRODUCTION
Consumer and public interest in the use of renewable energy resources is growing.
National Rural Electric Cooperative Association (NRECA) resolution 01-D-3, Support for Fuel
Diversity and a National Energy Policy, urges NRECA to “participate in the development of a
national energy policy, and to encourage all cooperatives to support research and development to
promote the utilization of all existing and new fuels and technologies, including those that utilize
domestic resources.” As of November 2002, nearly 200 NRECA members offer “green power”
programs, including power generated by such technologies as wind, solar, biomass, landfill gas,
as well as green power purchased by cooperatives at wholesale for resale to their consumers. One
renewable energy resource receiving a great deal of attention from rural consumers and public
agencies is wind.
Wind is the fastest-growing form of renewable energy in the United States. For example,
from 1991 to 2002, the production of electricity from wind turbines in the United States has
more than doubled, a growth rate faster than any other form of power generation. Today there are
more than 25,000 MW of wind generation installed worldwide, with more than 4600 MW in the
United States alone. Thirteen U.S. states have more than 20 MW installed, and the number is expected to double by 2010.
This white paper will review the status of wind power today, addressing basic wind power technologies, recent federal and state initiatives, interconnection and transmission issues, potential impacts on distribution cooperatives and generation and transmission cooperatives
(G&Ts), wind energy from the point of view of consumers, and wind energy economics. It is beyond the paper’s scope to evaluate predictions and proposed target goals regarding future wind
1 energy generation. But it is clear that electric cooperatives will increasingly be required to understand and address wind power from technical, consumer, utility, and regulatory points of view.
2 II. WIND POWER FUNDAMENTALS
“Wind power” and “wind energy” are phrases used to describe the process by which wind is
used to generate mechanical power or electricity. Wind turbines convert the kinetic energy in the
wind into mechanical energy; a generator can convert this mechanical energy into electricity.
Wind is a form of solar energy created by the uneven heating of the atmosphere, irregularities
on the earth’s surface, and the rotation of the planet. The economic viability of any wind
generation project is extremely location-sensitive: wind generators are economically efficient
only in precise locations and at specific heights at those locations.
Wind turbines turn in the moving air and power an electric generator, which supplies an electric current. Such turbines are available in a variety of sizes and power ratings. One federal publication defines three applications based on unit size:
• Small generators (400 W-50 kW) are described as appropriate for homes, farms, water
pumps, and telecommunications sites. Rotor diameter sizes range from 3 to 50 feet.
• “Village power” distributed generator systems are rated at 50 to 500 kW. Rotor diameter
sizes range from 30 to 164 feet.
• Central station wind farms produce more than 500 kW. Rotor diameter sizes range from
140 to 295 feet.
Wind energy enjoys certain features that make it an attractive resource to many observers:
• Wind power is often well received by the public as well as by cooperative members and
land owners.
• Wind generation produces no air emissions.
3 • Wind turbines can be located on land that may also be used for grazing or farming.
• Towers and turbines can be constructed in a relatively short time.
• Wind turbine installations can be distributed and thus installed in relatively small
increments on distribution feeders.
• There are no fuel costs.
• Utility scale turbines have accumulated millions of operating hours and represent a well-
proven technology.
• Energy source planning can take advantage of design modularity, since more turbines can
be added relatively easily if the load grows.
• Wind is the lowest-cost non-hydro renewable energy source
• Wind is renewable, in that using it now does not decrease future supply.
But wind energy is not a simple solution to the nation’s or the world’s energy problems. The following potential concerns must be considered when evaluating this technology:
• Good wind sites are often remote, located far from areas of electric power demand, and in
regions with inadequate transmission.
• Increasingly congested transmission grids make it difficult for any generation to
interconnect to the grid without requiring a significant expenditure to upgrade the system
to absorb the added generation.
• Improperly sited, wind turbines may create visual issues, noise issues and may be
hazardous to birds.
• Wind turbines may involve safety hazards, such as ice chunks being thrown by rotor
blades
4 • Wind is intermittent and does not always blow when electricity is needed.
• Current storage options (usually batteries) are expensive. Wind can be used in
conjunction with hydro resources that can act as storage.
• The newest and presumably most efficient wind turbine technology is about three years
old, providing a meager record from which to draw conclusions regarding reliability,
durability, longevity, and maintenance costs.
• Wind energy in general has not yet demonstrated its ability to compete in cost-
effectiveness with fossil fuels.
• Wind energy construction projects are not without risk.
• The lower capacity factor of wind generation results in higher transmission costs per
kWh transmitted.
5 III. WHERE THE WIND BLOWS
The National Renewable Energy Laboratory (NREL) of the Department of Energy has
produced estimates of the electricity that potentially could be generated by wind power and of
the land area available for wind energy. Currently, less than 1% of total electricity consumed in
the United States is generated by wind, but vast areas of the country could be used to harvest wind.
Geographic areas are characterized on a wind power scale from class 1 to class 7, with
each class representing a range of mean wind power density at specified heights above the
ground (see Exhibit 1). Areas designated class 4 or greater are said to be potentially viable
locations for advanced wind turbine technology. The amount of windy land available in power
class 4 and above is approximately 460,000 square kilometers, or about 6% of the total land area
in the contiguous United States (see Exhibit 2). For example, according to some estimates, North
Dakota alone has enough areas ranked class 4 and higher to potentially supply 36% of the total
1990 electricity consumption of the lower 48 states. Furthermore, to provide 20% of the nation’s
electricity, only about 0.6% of the land of the lower 48 states would have to be developed with
wind turbines.1
1 http://www.nrel.gov/wind/potential.html
6 Exhibit 1. Wind Power Classification
Exhibit 2. U.S. Wind Power Classification Map
7 This considerable wind energy potential has not yet been tapped for a variety of reasons, including limited transmission capacity, lack of utility experience, lack of effective state policies, institutional bias, and state of current technology. But during the past decade, improved materials and increased knowledge of wind turbine behavior have led to the development of better equipment. As will be discussed below, the price of electricity produced from wind by these advanced turbines is becoming competitive with conventional sources of power in some applications, particularly where federal or state support is available. However, the economics of wind energy are specific-site dependent, as is true with all energy resources. Saying that only
0.6% of the land mass would be required to generate 20% of U.S. electricity needs may gloss over the fact that the land in question must be located in a windy enough region to warrant development. Placing a wind turbine even a short distance from its ideal location will typically mean reduced energy production from the site.
8 IV. STATE AND FEDERAL INITIATIVES
Both the states and the federal government have expressed significant interest in wind
and other alternative forms of generation and have developed a broad range of programs to encourage exploration of renewable energy resources.
A. Research, Development, and Education Funds
The Department of Energy’s Wind Powering America program supports a national goal
of increasing wind energy’s contribution to the amount of electricity used in the United States to
5% by the year 2020. This represents about 60,000 MW of new, domestically produced power,
the majority of which will be developed in rural parts of the United States. The department also
leads the nation’s investment in wind technology through its research and development (R&D)
program. Since 1978, the program has worked with industry to reduce the cost of wind energy
from 40 cents per kWh to the 4 to 6 cent range today, with a goal of 3 cents per kWh by 2012 in
lower class wind areas. Success in achieving these goals would make wind competitive with
traditional generation in almost every moderate- to high-wind speed area, while mitigating
transmission constraints. The FY 03 budget request for the wind program was approximately $44
million out of a total FY03 renewable energy R&D budget request of $407 million.
B. Direct Support for Investment Costs
On October 23, 2002, Rural Utilities Service (RUS) Administrator Hilda Legg announced
that the RUS Electric Program will make available $200 million in loan guarantees for renewable
electric generation projects. While this will not preclude other energy loan applications, it will
give priority to the first $200 million in renewable applications in FY 2003. The Administrator
9 noted that this action by RUS strongly supports the President’s National Energy Policy to promote the increased use of our nation’s renewable assets.
Other programs exist to directly support the cost of investing in wind energy, both for consumers installing small systems and for manufacturers producing wind technology or acquiring such equipment for use in their own processes. These programs include tax rebates, tax credits, low-interest loans, and grant programs. Twenty-three states have some form of tax incentive, such as exemptions from sales tax on wind energy equipment and property tax incentives that allow jurisdictions to assess wind energy equipment at a special valuation for tax purposes (see Exhibit 3). Indiana, for instance, completely exempts renewable energy devices installed on residential property. Other state tax incentives include accelerated depreciation, production tax credits, and corporate and personal income tax credits.
Seventeen states have loan and/or grant programs to provide support for capital projects.
Seven states offer payment programs funded by system benefit charges collected from rate payers and implemented by private groups, utilities, and other entities to support wind power projects.
10 Exhibit 3. State Wind Power Incentives
Wind Economic and Financial Incentives Legislative, Regulatory, Other Potential Research / (billion Net Outreach kWh) Tax Incentives Financial Incentives Metering RPS Program SBC Disclosure Alabama 0 — — — — — — — Alaska n/a — Loans — — — — — Arizona 10 Sales, corporate, and personal income Loans Yes Yes — — — Arkansas 22 — — Yes — — — — Loans, green power credit, California 59 — Yes Yes Yes Yes — rebates Colorado 481 — — Yes — — — — Connecticut 5 Property, corporate — Yes Yes — — — Delaware 2 — — Yes — — — — District of Columbia — — — — — — — — Florida 0 — — — — — — Yes Georgia 1 — — Yes — — — — Hawaii n/a Personal, corporate — Yes — — — — Idaho 73 Personal Loans Yes — — — — Grants, loans, rebate Illinois 61 Property Yes — Yes Yes Yes program Indiana 0 Property Grants Yes — — — — Iowa 551 Property, sales Loans Yes Yes Yes — — Kansas 1070 — Grants — — Yes — — Kentucky 0 — — — — — — — Louisiana 0 — — — — — — — Maine 56 — — Yes Yes Yes — Yes Maryland 3 — — Yes — — — Yes Massachusetts 25 Sales, property, corporate, personal — Yes Yes Yes Yes Yes Michigan 65 — Incentive payments — — — — — Sales, property, accelerated depreciation, Minnesota 657 Loans Yes Yes — — — production tax credit Mississippi 0 — — — — — — — Missouri 52 — Loans — — — — — Montana 1020 Property, corporate, personal — Yes — — — Yes Nebraska 868 — Loans — — — — — Nevada 50 Property — Yes Yes — — Yes New Hampshire 4 Property — Yes — Yes — Yes New Jersey 10 Sales — Yes Yes — Yes — New Mexico 435 — — Yes — — — — New York 62 — — Yes — Yes Yes Yes North Carolina 7 Income — — — — — — North Dakota 1210 Property, income — Yes — — — — Ohio 4 Corporate and other tax incentives — Yes — — — — Oklahoma 725 — — Yes — — — — Oregon 43 Income, property, business energy tax credit Loans (SELP) Yes — — — — Pennsylvania 45 — Green Energy Fund Yes Yes — — Yes Rhode Island 1 — — Yes — — Yes — South Carolina 1 — — — — — — — South Dakota 1030 Property — — — — — — Tennessee 2 — Loans — — — — — Texas 1190 Property, franchise — Yes Yes — — — Utah 24 Corporate and personal income — Yes — — — — Vermont 5 Sales — Yes — Yes — — Virginia 12 — Loans Yes — — — Yes Washington 33 Corporate — Yes — Yes — Yes West Virginia 5 — — — — — — — Wisconsin 56 Property Grants Yes Yes — Yes — Wyoming 747 — — Yes — — — — United States 10,782 23 17 35 12 10 7 12 Note: RPS = Renewable Portfolio Standards or other mandates; SBC: System Benefit Charges for general support of renewable energies; Disclosure = retailers are required to disclose fuel sources to consumers; SELP = Small Scale Energy Loan Program. Source: American Wind Energy Association, "An Inventory of State Incentives for the US: A State-by-State Survey,” March 2001, available at www.awea.org.
11 C. Direct Output-Based Subsidies
To encourage wind energy production, the Energy Policy Act of 1992 included a tax credit for wind energy of 1.5 cents/kWh, adjusted for inflation. The current tax credit is 1.8 cents/kWh and extends for 10 years. Under the terms of the Act, the credit program must be reauthorized every two years. Although the credit enjoys broad bipartisan support, it is frequently included in legislative packages that face problems in approval. The wind energy tax credit extension was included in President George W. Bush’s economic stimulus package, signed in March 2002. The American Wind Energy Association, which lobbied for the bill’s passage, wants to increase the renewal period to five years to avoid the uncertainty and disruption that occur every time the credit is about to expire. In addition to the federal production incentive, several states offer their own incentives. Minnesota, for example, offers a 1.5 cents/kWh production tax credit for projects that are less than 2 MW and meet certain criteria.
While the tax credit for wind energy is a help to investor-owned utilities, rural electric cooperatives and municipal and government power agencies such as the Tennessee Valley
Authority (TVA) are unable to use the credits unless they have taxable income, which is unusual for not-for-profit entities. In recognition of this inequity, Congress included in Section 1212 of the Energy Policy Act of 1992 a provision that allows these entities to receive incentive payments similar to the tax credits (1.5 cents per kWh adjusted for inflation) under a program entitled Renewable Energy Production Incentive (REPI). Unfortunately, this program, which is intended to pay for energy from wind, solar, and biomass, is subject to yearly appropriations and fails to be fully funded. For example, in FY 2002, the Department of Energy estimated that the cost to fully fund the program would total almost $25 million; however, Congress appropriated only $4 million. NRECA and the American Public Power Association have been working
12 diligently to overcome this budget shortfall. To that end, NRECA suggested language that was
included in last year’s Senate Energy Bill that would have allowed cooperatives and municipals
to receive “tradable” tax credits. Cooperatives could use these tax credits to pay down some of
their RUS debt. The bill did not pass but will likely be debated again. Tradable tax credits are
likely to be considered again as well.
Where cooperatives themselves cannot benefit directly from tax incentives, they can still
benefit indirectly by partnering with taxable investors. One large cooperative, for example, is
working with a large investor-owned utility to bring wind to its members. The investor-owned
utility, which can benefit from the tax credits, is building a wind farm and selling all of the wind
farm’s output to the cooperative under a long-term contract. Because the price of power includes
the tax credit, the wind power is competitive with the cost of other resources in the cooperative’s
portfolio. Although this structure allows the tax credits to reduce the cost of power, that benefit is
somewhat offset by the addition of a third party requiring a rate of return on its investment.
D. Renewable Energy Mandates
1. Public Utility Regulatory Policies Act
In 1978, during the midst of an energy crisis, Congress enacted the Public Utility
Regulatory Policies Act2 (PURPA) to encourage the development of alternative energy sources.
The key provision, § 210, requires utilities to interconnect with certain qualifying generating facilities (QFs), sell them backup energy supplies at a just and reasonable rate, and purchase their output at their avoided cost, defined as “the cost to the electric utility of the electric energy which, but for the purchase from the [QF], the utility would generate or purchase from another
2 PURPA, Pub. L. No. 95-617, 92 Stat. 3117 (1978), codified at 16 U.S.C. § 2601 et seq.
13 source.”3 QFs include certain generation facilities that rely on renewable resources, including
wind and solar, and cogeneration facilities meeting specified efficiency requirements. QFs also
have to satisfy ownership requirements limiting the amount of interest that utilities can hold in the generators.4
PURPA has been controversial for many years because of the manner in which some states interpreted the purchase obligation. Many QFs were constructed during the energy crisis, when energy was expensive and state experts were predicting that energy prices would continue to rise rapidly. Accordingly, some states required utilities to enter into long-term power purchase contracts with QFs at extremely high “avoided cost” rates. When the energy crisis ended and generation prices dropped dramatically below earlier predictions, the utilities were locked into high-priced, long-term contracts that did not reflect their true avoided cost.
Because of the high cost of PURPA contracts, utilities and others have sought to repeal
PURPA § 210, and most electric restructuring bills introduced in Congress during the past several years included PURPA reform provisions. The bill that passed the Senate most recently, however, only partially reforms PURPA. It repeals the must-purchase provision for QFs in only those regions of the country that have day-ahead and real-time energy markets. The bill repeals the must-sell obligation in only states that have adopted retail competition. These provisions indicate the resurgence of interest in subsidizing renewable and efficient generation.
3 PURPA, § 210(d). 4 See Federal Power Act, § 3(17) & (18).
14 2. Renewable Portfolio Standards
a) State
Eleven states have Renewable Portfolio Standards (RPS) requiring that a certain percentage of electricity be produced from renewable energy sources, often increasing 1% or so per year to reach a maximum by 2009. Some states have mandates requiring a utility to install a certain amount of wind capacity to achieve a variety of objectives, including stimulating rural economic growth, addressing environmental and public health issues related to traditional generation, strengthening the state and regional energy supply, and helping build a renewable energy future.
b) Federal
Although the federal government does not have a renewable portfolio standard, Congress has considered several proposals to develop such a standard. The proposal in the most recent bill to pass the Senate would require all retail electric suppliers, with the exception of rural electric cooperative and municipal systems, to obtain a certain percentage of the energy that they sell from renewable resources. The percentage would start at 1% in 2005 and rise to 10% by 2019.
E. Antidiscrimination Requirements
1. State
There are some states that prohibit discrimination against renewable resources, including wind. Iowa, for example, prohibits any utility rules that treat differently consumers who install renewable energy sources.
15 2. Federal
Federal law does not have a renewable-specific antidiscrimination provision.
Nevertheless, the Federal Power Act requires that the rates, terms, and conditions of service for
wholesale power sales and transmission be “just and reasonable” and not “unduly discriminatory or preferential.”5 Moreover, the Federal Energy Regulatory Commission (FERC) has recently
sought to interpret this mandate in a way that encourages wind generation. In a recent decision,6
FERC approved a proposal from the California Independent System Operator (Cal ISO)
permitting intermittent generators, such as wind, to avoid imbalance penalties for generating
more or less than they scheduled as long as the over- and underproductions balance out over the course of a month. That approach contrasts with the obligation of all other generators to pay penalties for unscheduled deviations during each five-minute period.
Such approaches have been strongly encouraged by wind interests. They have sought language in federal legislation that would prohibit the imposition of any charges on wind generators for scheduling deviations. They have also sought language that would permit wind generators to purchase firm access to the transmission system but pay for only the actual kWh of energy that they were able to generate and transmit at any particular time. Such an approach would not fully recover the cost of the transmission resource allocated to that generation. The most recent energy bill passed by the Senate includes language that more generally requires transmitting utilities to provide transmission service “in a manner that does not unduly prejudice or disadvantage such generators for characteristics that are inherent to intermittent resources; and
5 See Federal Power Act, §§ 205, 206. 6 California Independent System Operator Corp., 98 FERC 61,327 (2002 FERC LEXIS 562 (March 27, 2002).
16 are beyond the control of such generators.”7 It is, of course, possible that the bill may never be
reported out of conference committee or could be changed dramatically.
F. Utility-Based Subsidies
1. Interconnection Requirements
a) State
A few states, including Texas and New York, have promulgated comprehensive rules for
the interconnection of distributed generation (DG). The New York Public Service Commission
established standards for residential and commercial applications of DG facilities with a capacity
of up to 300 kVA8 operating in parallel with the radial distribution facilities of utilities.9 The
Texas Public Utility Commission established standards for interconnection of DG pursuant to the
state’s recent restructuring law, which guaranteed consumers’ right “to have access to . . . on-site
distributed generation”10 The Texas rule defined “on-site distributed generation” as an electrical
generating facility located at a customer’s point of delivery of 10 MW or less and connected at a
voltage of 60 kV or less.11
Both Texas and New York established uniform interconnection requirements, a standard contract, and a standard application process for interconnection.12 Texas also drafted a standard
7 HR 4, § 208. 8 “kVA,” or kilovolt amp, is roughly equivalent to “kW,” or kilowatt. It is a more accurate description of a unit’s electrical generating capacity. Different source materials and regulations appear to use the terms interchangeably. 9 New York Public Service Commission, Opinion 99-13, “Opinion and Order Adopting Standard Interconnection Requirements for Distributed Generation Units,” Case 94-E-0952 (December 31, 1999), p. 3 (hereinafter “NYPSC 99-13). 10 Senate Bill 7 (SB 7), Act of May 21, 1999, 76th Legislature, Regular Session, chapter 405, 1999 Texas Session Law Service 2543, 2561 (Vernon), to be codified as an amendment to the Public Utility Regulatory Act, Texas Utilities Code Annotated § 39.101(b)(3). 11 Interconnection of On-Site Distributed Generation, 16 Tex. Reg. § 25.211(c)(a) (1999), to be codified at 16 Tex. Admin. Code § 25.211(c)(9) (hereinafter, “PUCT § 25.xx”). 12 See NYPSC 99-13, Appendix A; PUCT § 25.211(c)(6) & (c)(15).
17 Tariff for Interconnection and Parallel Operation of Distributed Generation. The New York
Public Service Commission has also conducted a generic proceeding to look at the costs and
benefits of DG and to examine utility rates for connecting residential DG and providing backup
power. At least 19 other states in most regions other than the upper Northwest and the Great
Plains states are also developing interconnection standards.13
Properly drafted and implemented, interconnection standards can assist all involved by
lowering the cost of interconnection. Neither the utility nor the consumer needs to reinvent the
wheel for every interconnection.
Some parties, however, would like interconnection standards to go further. To encourage
DG, they would like to artificially lower the cost of interconnection for favored generation. For
example, as discussed below, the interconnection process will always require some utility
expenditures, no matter how small the generator. Both Texas and New York permit those who install small generators to escape those costs. Interconnection can, in some instances, require
upgrades of the distribution system so as to integrate the new unit without degrading system
reliability. Some argue that certain generators should not have to pay those upgrade costs.
Interconnection also creates some risk of harm to people, especially utility linemen, and
property. Accordingly, utilities typically require that consumers carry some level of insurance
and indemnify the utility for losses caused by the consumer. Because the cost of insurance can
detract from the economics of small generators, New York has prohibited any insurance
requirement for certain generators.
13 For more information, see http://www.eren.doe.gov/distributedpower/sublvl.asp?item=state.
18 b) Federal
No federal interconnection standards for DG exist today, but that situation is likely to
change. Congress has seen a number of proposals that would give FERC the authority to
establish technical and business standards for the interconnection of generation to the distribution
system. The bill that the Senate most recently passed includes some language on interconnection
but places those provisions in PURPA §§ 113(b) and 115; this means that each state and each
self-regulated cooperative would have to consider whether to adopt those provisions but would not be obligated to do so.
Those provisions would require all utilities to grant consumers with certain DG facilities competitive access to the distribution grid (i.e., retail competition). The provisions would also require utilities to interconnect with any DG that meets state technical standards. Finally, the bill would prohibit the imposition on consumer-generators of any interconnection or standby
charges.
On a parallel track, FERC is in the process of developing interconnection standards for
both large generators and so-called “small” generators of 20 MW and smaller.14 The commission
intends those standards to apply not only to any generation interconnected at transmission
voltage but also to any generation interconnected at distribution voltage that will sell power into
the wholesale market. The large-generator standards focus on the process of interconnection
costs. The small-generator standards also address the technical requirements for interconnection
to distribution systems. Both the small- and large-generator interconnection rules would require
jurisdictional utilities to interconnect generation with their systems pursuant to the standardized
14 Federal Energy Regulatory Commission Notice of Proposed Rulemaking on Standardization of Generation Interconnection Agreements and Procedures, Dkt. No. RM02-01-000 (April 24, 2002); Federal Energy Regulatory Commission Advanced Notice of Proposed Rulemaking on Standardization of Small Generator Interconnection Agreements and Procedures, Dkt. No. RM02-12-000 (August 26, 2002).
19 procedures and contracts. Non-jurisdictional utilities could be subject to the rules under
“reciprocity” requirements — that is, if the non-jurisdictional utility seeks transmission service from a jurisdictional utility, it could be required in exchange to provide service in compliance with FERC rules. NRECA is firmly opposing expansion of FERC’s jurisdiction over interconnection of generation to distribution facilities, as well as a broad interpretation of
FERC’s reciprocity requirements.
2. Net Metering
Net metering rules generally provide that consumers with certain self-generation capabilities should have a meter that rolls forward when the customer consumes power from the grid and rolls backward when the customer exports power to the grid. If the cooperative supplying service to that consumer does not have a demand charge that accurately reflects its fixed costs of service, net metering allows the self-generating consumer to evade some or most of the fixed costs required to serve that consumer. In effect, the cooperative’s other consumers subsidize the self-generating consumer.
a) State
At least 35 states have adopted net metering rules to date, and several others are considering doing so now. In two of those states, the rule covers only solar. In all of those states, if consumers use more energy than they have generated over the course of a billing period, they pay for only the net energy that they have imported from the system. However, state net metering rules vary widely in those situations in which a consumer generates more than they have used over the course of a billing period. Some states prohibit any payment to consumers for net
20 exports.15 Some states require net credits to be rolled over to the next month, generally up to one year.16 Others states require utilities to pay consumers “avoided cost” (as under PURPA) for net
exports at the end of a billing period or at the end of a year.17
The range of technologies and applications entitled to benefit from net metering also
differs widely from state to state. Many states, including Connecticut, Illinois, and Montana,
limit net metering to only renewable technologies.18 Others include QFs under PURPA. Most
states have size limits on the units that qualify for net metering; for example, Colorado, Nevada,
and New York all limit qualifying units to no larger than 10 kW.19 At the other end of the
spectrum, because of its energy crisis, California adopted a temporary rule requiring net metering
for certain generators up to 1 MW in capacity.20
Some states have also imposed a limit on the total number of consumers, or total capacity of consumer-owned generation, for which any utility has to provide net metering service. Illinois,
New York, and Washington all limit net metering to 0.1% of the utility’s historic peak load.21
Many states adopted net metering as a way of implementing PURPA’s requirement that
utilities buy the output of qualifying small power production facilities. Other states adopted net
metering because it provides a simple, easily administered way of compensating consumers for
their generation, particularly when the customer is unsophisticated, the unit is small, and the
output of the unit cannot closely track the customer’s demand, as with wind and solar energy.
Yet other states have adopted net metering to subsidize the use of environmentally friendly
renewable technologies.
15 See www.awea.org/policy/documents/nm-table0105.PDF. 16 Ibid. 17 Ibid. 18 Ibid. 19 Ibid. 20 Ibid. 21 Ibid.
21 b) Federal
The federal government does not have a net metering mandate, although several
proposals to create such a mandate have come before Congress. The most recent Senate energy
bill included a net metering provision, but it is inserted into § 111(d) of PURPA, which requires states and nonstate regulated cooperatives only to consider whether it would be appropriate to adopt net metering requirements, rather than obligating them to do so.
The net metering program that states and self-regulated cooperatives would have to consider is quite broad. It would apply to residential generators of up to 10 kW powered by wind energy, solar energy, or fuel cells, and to commercial generators of up to 500 kW using renewable generation, fuel cells, and combined heat and power units. No limits would be placed on the amount of capacity that any utility would be required to net meter or on the credits that a consumer could accumulate.
22 V. WIND POWER TECHNOLOGY
Today’s wind turbine technology ranges in size from 20 Watts to over 2 MW (turbines rated >2 MW are designed primarily for offshore applications).
Distributed wind generation typically refers to applications consisting of a single turbine or small clusters of turbines (two to five machines). The term “small wind systems” typically refers to units rated at 50 kW or less. Intermediate-sized wind turbines, rated between 50 and 250 kW, are primarily used for village power or “small-scale” distributed wind applications, including providing power to medium- to large-scale commercial loads. Large wind turbines, ranging in size from 250 kW to 2.5 MW, may be used in distributed or central station wind farm applications. (See Exhibit 4.)
Exhibit 4. Wind Turbine Size and Application
Intermediate Small (≤50 kW) Homes (51-250 kW) Farms Village Power Remote Applications (e.g., Distributed Power Water Pumping, Telecommunications, Icemaking)
Large (251 kW-2.5 MW) Central Station Wind Farms Distributed Power
23 Most modern wind turbines are horizontal axis wind turbines (HAWTs). A HAWT has its blades (rotor) rotating about an axis that is parallel to the ground, while a vertical axis wind
turbine has its blades rotating about an axis perpendicular to the ground. (See Exhibit 5.) Each
type has its advantages and disadvantages; however, only a couple of vertical axis machines are
still being produced today, and most have not been installed in commercial applications.22
Because wind speed increases with height above ground level, the primary advantage of a
HAWT is its ability to take advantage of the increased power available in the wind through the use of ever-increasing tower heights.23 Winds at higher elevations are also less turbulent,
reducing fatigue loading. For farmland and other open, untreed areas, the wind speed increases
by about 12% for every doubling in elevation.24
22 A 20-kW vertical axis wind turbine manufactured by Terra Moya Aqua, Inc., a Wyoming company, was recently installed at Curt Gowdy State Park, located about 24 miles west of Cheyenne. 23 The amount of power available in the wind is determined by the equation P = ½ d A v3, where d = air density, A = the cross-sectional area in square feet swept by the rotor blades, and v = the wind speed in miles per hour. 24 Canadian Wind Energy Association, Wind Energy: Basic Information.
24 Exhibit 5. Types of Wind Turbines
Horizontal
Vertical
Exhibit 6 shows the rated power, rotor diameter, and rotor control method used by the manufacturers that are active in the U.S. market today.
25 Exhibit 6. Wind Turbine Model Specifications
Rated Rotor Power Diameter Tower Height Manufacturer/Model (kW) (m) Rotor Control (m) Vestas-American Wind Technology, Inc. North Palm Springs, CA (760) 329-5400 660 47 Variable pitch 40-65 Vestas V47
Vestas V80 1800 80 Variable pitch 60, 67, 78
NEG Micon North Palm Springs, CA (760) 251-5461 900 52.2 Stall 72 NEG Micon NM52
NEG Micon NM72 1500 72 Stall 70, 80
Nordex USA, Inc. Grand Prairie, TX 800 50 Stall 46, 50, 70 (972) 660-8888
Nordex N60, N62/1300 kW 1300 60, 62 Stall 60, 69
Nordex N90/2300 kW 2300 90 Variable pitch 80, 100, 105
Nordex N80/2500 kW 2500 80 Variable pitch 60, 80, 100, 105 GE Wind Energy Tehachapi, CA (661) 823-6700 1500 70.5 Variable pitch 65, 80 GE 1.5s
GE 1.5sl 1500 77 Variable pitch 65-100
Mitsubishi Power Systems Lake Mary, FL (407) 688-6100 600 45 Variable pitch 40, 45, 50 MWT-600
Mitsubishi MWT-1000 1000 56 Variable pitch 60
26 Most horizontal wind turbines have three blades, although two- and one-bladed designs are in operation (see Exhibit 7). To govern power output and limit blade stress in high winds, modern wind turbines employ stall (fixed pitch) or variable pitch control. Stall control relies specifically on the profile of the wind turbine’s blades, whereas variable pitch control “feathers” or changes the orientation of the blades with respect to the angle of attack of the wind. Although variable pitch control introduces additional mechanical complexity, it increases the collection efficiency of the rotor. HAWTs may be oriented upwind (i.e., with the hub facing into the direction of the prevailing wind) or downwind. Most wind turbines today are oriented upwind to eliminate the problem of tower shadow and the associated loss of energy (the wind above the hub height of the turbine nacelle is less turbulent than the wind passing behind the tower), which accentuates cyclic loads on the turbine blades. While the upwind orientation eliminates this problem to a large extent, it also introduces additional mechanical complexity into the machine design in order to keep the rotor positioned into the wind via a yaw motor.
Exhibit 7. Major Wind Turbine Components
27 All machines share certain characteristics such as cut-in, rated, and cut-out wind speeds.25
Exhibit 8 shows the idealized power curve for a modern wind turbine.
Exhibit 8. Idealized Power Curve for a Wind Turbine
The cut-in speed is the minimum wind speed at which the blades will turn and generate
usable power. For example, the Nordex N60/1300 kW wind turbine has a cut-in wind speed of 7
to 9 mph. At wind speeds between cut-in and rated wind speed, wind turbine output increases as
the speed of the wind increases. Rated speed is the minimum wind speed at which the turbine
will generate its rated power; for example, the Nordex N60/1300 will not generate 1300 kW until the wind reaches a speed of 33.5 mph. Above the rated wind speed, the output of the machine may fluctuate around rated power, decrease, or even increase. At very high wind speeds, wind turbines will shut down to prevent damage to the machine; for example, the Nordex N60/1300 will cut out when the wind reaches a speed of 56 mph. All modern wind turbines can survive maximum wind speeds well in excess of 100 mph.
25 New York State Energy Office, New York State Wind Energy Handbook, July 1982.
28 Most wind turbines produce alternating current using induction generators. Since the
turbines must be synchronized with the utility line, they will not produce electricity if utility
power becomes unavailable. Given the slow rotational speed of modern wind blades (12 to 23 rpm), most wind turbines (except direct-drive) have a gearbox to increase the rotation of the rotor to speeds necessary for generator operation. Wind turbines employ a combination of aerodynamic and mechanical braking to stop the turbine in high winds or in the event of a loss of
the utility grid.
One U.S. manufacturer offers a turbine that includes a dynamic VAR compensator for
maintaining good voltage. This may prove advantageous when connecting to a distribution
feeder.
29 VI. DISTRIBUTION UTILITY ISSUES
Wind generation installed on the distribution system can have a number of significant physical, business, economic, and legal implications for distribution cooperatives and their facilities. Most of those impacts are the same as those caused by any generator, but wind’s intermittent nature does raise some unique issues. In addition, a smaller wind generator (25 kW or less) installed primarily to serve load at the site where it is installed will have very different impacts on the distribution system than those of larger wind turbines (250 kW and above) installed individually or as part of a wind farm.
A. Interconnection
1. Physical Impacts
As with any generator interconnected with the distribution system, wind turbines can affect the safety and reliability of the distribution system. The cooperative and the consumer will need to work together to study the impacts of a particular installation and to install any protective equipment and possibly system upgrades required.
a) Safety
The first concern of any cooperative is the safety of its employees, its members, and the general public. Cooperatives will need confirmation that any generation installed in parallel with the distribution system has the appropriate disconnection devices to ensure that when the distribution system faults or is taken down for maintenance, the generator does not continue to export — or back-feed — power onto the grid. Such disconnection devices typically must be visible, lockable, and accessible by utility personnel. Otherwise, there is a risk that utility
30 personnel or others who come in contact with a line they believe to be “cold” will be
electrocuted by energy back-fed onto the system by the consumer’s generator.
b) Reliability
Any generator operated in parallel with the distribution grid can affect the operation of
the grid, even if it does not directly export power onto the grid. Depending on the size and the
nature of the generator, and the size and stability of the distribution system, any generator could
affect the system’s voltage and frequency; contribute to the system’s fault current; or inject
harmonics onto the system. Those effects could damage utility equipment, damage other
consumers’ electronics and manufacturing equipment, or even cause the circuit to collapse.
In almost all circumstances, these effects can be mitigated or prevented with appropriate
protective devices, operating protocols, and power conditioning equipment. The question usually
is not whether the problems can be fixed but how much it will cost to do so and who will pay
those costs. The most extreme case — a generator large enough to overwhelm a circuit — could
require running a dedicated radial line to the nearest high-voltage transmission line. Such situations might include the installation of a three-phase generator on a site served by a single- phase distribution line; a large generator, such as a 1-MW wind turbine, on a long radial distribution line; or a large number of generators of any size along a feeder, as might be seen with a wind farm.
In this context, it is important to recognize that the nature of wind generation — which is dependent on the rising and falling winds — leads to more reliability problems than most forms of generation, which typically will have a more consistent and controllable output. The
Cooperative Research Network (CRN) and other organizations are studying those impacts so that they can be more easily addressed.
31 2. Interconnection Rules
To address both the safety and the reliability effects of consumer-owned generation, distribution cooperatives will need to develop technical interconnection rules. Those rules should dictate the necessary performance characteristics for generators interconnected for parallel operation with the system; should describe the types of tests that generators will need to pass to demonstrate that the generators meet those performance characteristics; and should govern the protective equipment, such as disconnect switches, that generators will need to install. The rules should also cover the types of studies that the cooperative will need to perform to determine whether the system will be able to accept the new generation in its current configuration, and if not, the system upgrades that will be required.
The starting point for developing those rules will be the Institute for Electrical and
Electronics Engineers (IEEE) interconnection guidelines and standards. The IEEE has already adopted P 929, recommended guidelines for interconnecting photovoltaic generators to the distribution system.26 The IEEE is in the process of developing P 1547, standards for interconnecting all DG up to 10 MW to the distribution system.27 These guidelines and standards are not detailed rules but rather general principles that each cooperative will have to apply to their own system. To assist in that process, NRECA has funded the development of an
Application Guide that provides rules of thumb and other recommendations on how to implement P 1547.28
26 IEEE P 929-2000, Recommended Practice For Utility Interface of Photovoltaic Systems 27 IEEE P 1547/D08, Draft Standard for Interconnecting Distributed Resources With Electric Power Systems, available at technet.nreca.org/pdf/distgen/P1547StdDraft08.pdf. 28 See , http://www.nreca.org/leg_reg/DGToolKit/DGApplicationGuide-Final.pdf.
32 3. Business and Economic Impacts of Interconnection
The availability of DG, and farmers’ interest in leasing space on their land for large wind
farms, can impose new expectations on distribution cooperatives. Consumer-owners will
approach distribution cooperatives with requests to interconnect generation to the distribution
system. They may also want the distribution cooperative to purchase the output of their
generators or to wheel the generation across the distribution system to other consumers or to the
transmission grid. Each of those requests can have significant consequences for the cooperative.
a) Interconnection Requests
Increasingly, cooperatives will face strong consumer pressure to permit interconnection.
DG need not operate in parallel to the distribution system, and in fact, most consumer generation
does not. Most DG today consists of backup generators that operate only when the grid is down.
Many consumers, however, want to be able to run their generation in parallel in order to meet
certain operational or economic goals. They may want to be able to move more smoothly
from grid power to their own generation and back to prevent interruptions to manufacturing
processes. They may want to sell excess power. Or they may want to supply only a portion of
their demand, without fully replacing grid power. This last scenario may be particularly likely for
consumers that install intermittent generation such as solar or wind turbines for their own use. If
the wind fluctuates, or a cloud passes over, they will not want their lights to flicker or dim.
Moreover, wind energy is not confined to DG; the interconnection could be to a wind farm,
which will serve no purpose without access to the grid. Farmers, or the wind developers with
whom they contract, will insist on interconnection.
33 (1) Obligation to Interconnect
In some cases, cooperatives may have a legal obligation to interconnect. If the generator
is a QF under PURPA, the cooperative will be obligated not only to interconnect but also to purchase the output of the generator at the cooperative’s “avoided cost.”29 If the generator intends to sell at wholesale, the cooperative may be obligated to interconnect under Section 210 of the Federal Power Act.30 The cooperative may also be required to interconnect with certain
consumer-generators under state law. Even where there is no legal obligation to interconnect,
however, consumer pressure to supply such interconnection could be extremely strong and thus
provide an independent reason to interconnect.
(2) Interconnection Processes
Addressing interconnection requests could require significant resources at the cooperative. Some states have already adopted detailed procedures with tight deadlines for responding to and implementing interconnection requests. FERC is in the process of developing procedures and deadlines for interconnection of all generators that intend to sell at wholesale, even if they are interconnected at the distribution level. Even in the absence of state or federal mandates, cooperatives will want to develop interconnection procedures of their own to ensure that interconnections are handled efficiently and fairly.
Most procedures start by requiring the designation of an individual responsible for responding to such requests and ensuring that they are processed appropriately. The procedures then require that the utility have a defined and orderly process by which consumers apply for
29 PURPA, § 210, 16 USC 824a-3. As discussed below, if the consumer does not choose to sell to the cooperative, the cooperative may be required to wheel the generator’s output to another consumer under 205 or 211 of the Federal Power Act. 30 Federal Power Act, § 210, 16 USC 824i.
34 interconnection; the utility reviews the interconnection request; and the utility conducts any
required system studies to determine whether system upgrades will be required for
interconnection. If upgrades are required, the consumer will have to sign a contract agreeing to
pay for upgrade costs, and upgrades will have to be performed in accordance with specific
schedules. If upgrades are not required, then the consumer will be required to sign an
interconnection contract and installation of the generation can continue. The procedures will also
govern the testing of the facility and the interconnection equipment before the interconnection is
energized.
To accomplish all of these steps, cooperatives will need to develop appropriate
procedures or become familiar with any state or federally mandated procedures; draft an
interconnection application and interconnection contracts; and create system study, upgrade, and
testing protocols. To assist in that process, NRECA, CFC, ECO, and CRN have jointly funded
the development of a DG Interconnection Tool Kit that includes a model application and model
contracts that cooperatives can adapt to meet their own needs.31
Cooperatives will also need to have available, or have access to, the staff required to
perform any required system studies, system upgrades, and testing. That could be a burden for
many small cooperatives, particularly if they are faced with a large number of requests or even a
few complicated interconnections. The burden could be even greater if the generation community is successful in its efforts before FERC to impose strict timelines for interconnection and liquidated damages for those utilities that fail to meet the deadlines.
31 See www.nreca.org/leg_reg/dgtoolkit.
35 b) Interconnection Costs
The interconnection of generation can be quite costly for cooperatives. Even a simple interconnection will require some staff time to review the application and to conduct a commissioning test. A more complicated interconnection — like that required for a large wind farm — could require substantial engineering time for various system studies and large capital investment in system upgrades.
As part of their interconnection rules, cooperatives will need to assign interconnection costs appropriately. Under the traditional principle of service at cost, the consumer that requests the interconnect should pay the resulting costs. There are legislative and regulatory efforts under way, however, to shift some or all of those costs to the system. Under some state rules, utilities may not charge consumers for the costs required to interconnect smaller units to the distribution system. Depending on the state, “small” could mean 10 kW or even 30 kW. At the federal level, generators have argued for a similar rule protecting small generators from interconnection costs, with “small” defined as anything up to 20 MW. At this point, it does not appear that FERC will approve that cost shift, but approval is possible. To prevent further pressure to shift costs from generators to utilities, cooperatives will want to be certain that the charges they impose for interconnection are well supported and fair.
B. Costs of Cooperative Services to the Consumer
A few consumers who install generation choose to disconnect from the system and rely entirely on their own resources. There is a risk that such consumers, particularly larger consumers with special service requirements, could strand the investment that the cooperative has made in the past to serve the consumer’s load. For that reason, some utilities charge consumers who install their own generation an “exit fee” to recover the stranded costs. Some
36 have argued, however, that many exit fees are set at a level intended more to discourage
consumer-owned generation than to recover true stranded costs. Those parties oppose the
imposition of any exit fee
In most cases, consumers who install generation will continue to rely on the system for
some portion of their load on an ongoing basis, and their entire load on a backup basis, when
their own generation is not operating. Those consumers typically impose a much greater cost on their utility than would be recovered under a standard retail service tariff.
Most distribution tariffs include a very small monthly fixed charge that covers little more than the cost of reading the consumer’s meter and sending a bill. The rest of the fixed and incremental costs of serving the consumer are recovered through an incremental (per kWh) charge. That works for most consumers because the incremental charge is set far enough above the incremental cost of service to recover the average fixed costs for consumers within the particular rate class at issue.
That tariff does not work, however, for the consumer-generator. The distribution cooperative incurs fixed costs to serve that consumer based on the need to have adequate distribution facilities and generation capacity in place to meet the consumer’s maximum load at system peak, but because it operates its own generation, the consumer pays for very few kWhs.
For that reason, most utilities will charge consumer-generators a “standby” or “backup” service charge intended to recover the fixed costs of the system that would not otherwise be recovered by the standard tariff. Others adopt a new tariff for consumer-generators with a large fixed monthly charge to cover fixed costs and a much smaller incremental rate to cover the utility’s incremental costs.
37 Both of these approaches face substantial political opposition because they are seen as
“barriers” to DG. Some argue that, as with exit fees, utilities have set the fixed charges too high
— at a level intended to discourage consumer generation rather than to recover fixed costs.
Others oppose even cost-based backup charges in an effort to subsidize consumer generation.
One means of recovering costs while attracting less opposition is to give consumers the option to choose the level of standby service they wish. For example, emergency standby service at peak could be very expensive, while standby service scheduled with the utility in advance at off-peak hours for maintenance could be much less expensive. Such adjustments, however, might be much more difficult for a consumer that relies on a wind turbine to serve their load.
Because of the unpredictability of wind, those consumers may rely heavily on standby service and could need it at any time of day during any season. They cannot be certain that the wind will blow during system peak. For instance, in the Midwest, windspeeds may often be low during hot humid summer peaking periods. During those times, the cost of providing power supply is usually high and the available wind generation is low.
C. Purchasing Excess Generation
Most consumer-generators will rarely export significant power to the grid. They may
operate their generation only in isolation, or their generators’ maximum output may be less than
the consumers’ minimum load. Other consumers install generation with the intention of
generating more than they consume and selling the excess. Some, such as those who install wind
farms, intend to sell the entire net output of their generation. Those who do export power will
have to either sell their output to their distribution cooperative or wheel the energy across the
distribution cooperative’s facilities to another customer.
38 1. Cooperative Purchases of Excess Generation
If cooperatives purchase the output of their members’ generators, they and their members
can structure the power purchases in many ways. Each approach can have different cost impacts and different regulatory impacts. Some may be easier to adopt physically or politically than others. As cooperatives consider how to pay for generation, they should consider their contracts with their G&T or other power suppliers, their existing rate structures, any state regulatory requirements, federal regulatory implications of the approaches they are considering, the cooperative’s energy requirements, and the cooperative’s other power supply options.
a) Net Metering
Net metering is only one way to account and pay for consumer generation, but it is politically popular. As discussed above, over 35 states have net metering requirements that obligate utilities to purchase consumer generation, though not all of those rules apply to cooperatives. Net metering requirements generally call for consumers with certain self- generation capabilities to have a meter that rolls forward when the customer consumes power from the grid and rolls backwards when the customer exports power to the grid. If the consumer uses more energy over the course of a billing period than they have generated, they pay only for the net energy that they have imported from the system. Depending on the program, if the consumer generates more than they have used over the course of a billing period, they may be able to roll credits over to the next month, up to one year; they may be paid “avoided costs” for the net excess generation; or they may not be paid at all.
Most utilities are concerned about net metering policies because they require utilities to pay consumers the retail price for wholesale power, which represents an even greater subsidy
39 than the “avoided cost” price required by PURPA. As a result, net metering raises the cost of power for all of the other consumers on the system. Moreover, the policies require utilities to pay high costs for what is often low-value power. Power from wind and photovoltaic systems is intermittent and cannot be scheduled or dispatched reliably to meet system requirements. Power from these generators, particularly wind generators, may not be available at times of system peak.
Furthermore, net meters also allow customers to underpay the fixed costs they impose on the system. A utility has to install sufficient facilities to meet the peak requirement of the consumer and recover the costs of those facilities through a kWh charge. When the net meter rolls backwards, it understates the total energy used by the consumer and thus understates the consumer’s impact on the fixed costs of the system. It also understates the consumer’s total share of other fixed charges borne by all consumers, such as taxes, stranded costs, transition costs, and public benefits charges.
Perhaps the greatest concern with dispatchable generators, such as gas- and diesel-fueled units, is that the net meters can be deliberately or inadvertently gamed. Consumers can take power from the system at peak times when it costs the utility the most to provide it, and then roll their meters backwards by generating power at nonpeak times, when the utility has little need for it. Of course, deliberate gaming is not as much of an issue with wind generators.
Despite all of these drawbacks, some cooperatives provide net metering voluntarily for some of their consumers. As mentioned above, net metering may be the cheapest and easiest way to account for very small intermittent generators. It may cost more, for example, to install a second meter and to adopt more complicated accounting procedures than it would cost to net meter a 100-W rooftop solar panel. Also, because net metering is easier for consumers, some
40 cooperatives would rather lose a little money on a few small generators in order to make
consumers happy. Finally, some cooperatives are willing to net meter renewable generators such
as solar and wind in order to encourage the development of green power.
The key with net metering is to adopt an appropriately limited program so that the value
the cooperative seeks to provide through net metering and the subsidy cost of the program are
balanced. A net metering program appropriate to renewable generators of 10 kW and below
would not, for example, be appropriate for a commercial wind farm installing a number of 1-
MW wind turbines.
b) Crediting Behind the Meter — Net Billing
Another approach by which some cooperatives account for and pay for consumer
generation is called crediting behind the meter or “net billing.” Net billing differs significantly from net metering in that the cooperative measures the customer’s net exports to the system separately from the customer’s net imports — through the use of two meters or a single more sophisticated meter. Net billing is similar to net metering in that consumers are paid for their generation exports with bill credits. In other words, the cooperative nets dollars rather than kWhs.
This approach has several advantages over net metering. First, because the cooperative measures the consumer’s actual net generation exports, the cooperative can pay the consumer a different rate for the energy it receives from the consumer than the rate the consumer pays for energy, delivery, operation and maintenance, administrative & general, etc when it takes power from the cooperative. That is, the cooperative does not have to pay the full retail rate for the consumer’s generation. The cooperative can set the rate it pays for consumer generation based on
41 its avoided cost, a market index, or any other reasonable basis. As a result, the cooperative need
not subsidize the consumer generation.
Second, because the full amount of the energy the consumer takes from the cooperative is
still measured, the consumer will again pay a more equitable share of its fixed costs of the
system. As part of the rate it pays for the energy it receives, the consumer will be paying whatever portion of system fixed costs are incorporated into the cooperative’s kWh rate. Of
course, if the consumer continues to rely on the cooperative to be available to serve its full load,
some backup or other fixed charge may be required to ensure that the consumer pays all of the
costs it imposes on the cooperative.
Finally, the cooperative can record the times at which the consumer imports and exports
power, which allows the cooperative to pay a rate that is better correlated to the actual value of
the energy to the cooperative. The rate could be directly tied to the hourly market rate at the time
the energy is exported, or the cooperative could adopt different rates for on-peak and off-peak
generation. That approach would help prevent both cost shifting and gaming by the consumer-
generator.
Crediting behind the meter, or net billing, also has one key advantage over arrangements
in which the cooperative pays consumer-generators cash for their output. FERC has jurisdiction
under the Federal Power Act over any person who makes sales at wholesale in interstate
commerce.32 That would include consumer-generators who sell for resale energy produced by
generators interconnected at distribution voltage.33 To sell their output, those consumer-
generators would have to meet numerous filing requirements at FERC — an enormous burden
32 Federal Power Act, § 201.16 USC 824. 33 See, e.g., Orange & Rockland Utilities, Inc., 42 FERC 61,012 (1988); Public Service Co. of Colorado, 88 FERC 61,056 (1999); InPower Marketing Corp., 90 FERC 61,329 (2000); Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States, 94 FERC 61,272 (2001); Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States, 96 FERC 61,155 (2001).
42 for the average homeowner or small business. Alternatively, the entity that purchases energy
from those consumers could make many of the filings on behalf of the consumers.34 Even so, that
could still be a burden on smaller cooperatives. FERC has said, however, that it has jurisdiction
over neither net metering nor, by implication, any other business arrangement in which a utility
provides its own consumers credits for generation located behind the retail meter. FERC
characterized such arrangements as “retail” and thus beyond FERC’s control.35 By structuring
power-purchase agreements as retail credits for behind-the-meter generation, cooperatives may
be able to protect their consumers from FERC jurisdiction.
Because of these advantages, cooperatives may want to consider using a net billing approach rather than net metering or other bilateral approaches to purchase consumer-owned
generation. It is important to recognize, however, that even this approach is probably useful for only limited classes of consumer-generators. Net metering may still be more economical for very
small generators. Furthermore, crediting will not work for independent power producers and
consumers who generate far more power than they consume over the course of a year. Those
generators will never receive adequate value from bill credits.
c) Bilateral Contracts
Independent power producers and consumers that install far more generation than they
require have made the decision to enter the power supply business. The cooperative will need to
deal with them at arm’s length just as with any other business with which it contracts. Unless a
state law regulates the deal, or the generator qualifies under PURPA § 210, the cooperative is
under no obligation to purchase the output of such generators. The cooperative can consider the
generator as just another power supply option in its portfolio and can contract with the generator
34 Ibid. 35 MidAmerican Energy Co., 94 FERC 61,340 (2001).
43 or not, accordingly. The advantage of bilateral contracts over net metering or crediting arrangements is that they permit arrangements for much larger purchases of power and they permit much more individualized arrangements that most accurately reflect the value of the deal to the generator and to the cooperative. In such instances, the cooperative may provide wheeling of the power from the generator to the grid, or another consumer on the cooperative’s system.
2. The All-Requirements Contract
More than half of all distribution cooperatives receive power from a G&T cooperative under an all-requirements contract. The contract provides that the G&T will meet all of the power needs of its member distribution cooperatives and that those distribution cooperatives will purchase all of their requirements from the G&T. The terms of the contract prohibit distribution cooperatives from building their own generation or acquiring it from sources other than the
G&T, including those of their consumers that own generation.
That is not, however, an absolute bar to cooperatives purchasing the output of consumer-
owned generation. First, it is possible for G&Ts to purchase the output of generation located on
their member systems. Second, several G&Ts are experimenting with programs that allow
distribution cooperatives to acquire some power from their consumers. A few G&Ts have
worked with their members and the RUS to provide some measure of flexibility in the contract
that allows the distribution cooperatives to purchase 5% or 10% of their energy from sources
other than the G&T, including consumer-owned generation. Others have developed load or
demand response programs that allow distribution cooperatives to encourage DG or to purchase the output of DG as a means of reducing the system’s peak demand. The key here is being creative enough to find means of meeting systemwide needs within the context of the existing
relationships.
44 D. Wheeling Excess Generation
If the cooperative does not purchase the output of generation located at a consumer’s site, that energy will need to be transmitted, or wheeled, across the distribution system and then across the transmission system to another purchaser. Most cooperatives have never had to address that issue before. The obligation to wheel has several important physical and regulatory impacts beyond those that arise simply with interconnection.
1. Physical Implications of Wheeling
Simply because a generator of a particular size and variety can safely and reliably interconnect with the distribution system does not mean that the distribution system can safely or reliably accept exports from that generator. The distribution system has largely been designed to transmit power in one direction: from substation to load. The protective devices on the distribution systems, such as reclosers, are generally designed to operate in only one direction. If power flows in the other direction on the system these devices may not be able to function properly, putting the safe and reliable operation of the entire system at risk.
As a result, a cooperative will have to conduct very different studies before interconnecting with a 50-KW generator that will not export power than it will before interconnecting with an identical generator installed to sell power to the grid. The cooperative may also have to make much more significant and expensive upgrades to the distribution system in the latter case. For example, the cooperative might have to replace all of the unidirectional protective equipment on a particular circuit with more expensive bidirectional equipment. Or, in the worst case, it may need to run a new dedicated radial line for the new generator.
45 2. Regulatory Impacts
Just as FERC has jurisdiction over any person or entity that sells power at wholesale, it also has jurisdiction over anyone that owns or operates facilities that transmit power in interstate commerce. While transmission in interstate commerce has not been precisely defined, it is clear that FERC has a very broad reach. To qualify, facilities do not have to operate at transmission voltage or cross state lines. In fact, with two exceptions, FERC is likely to assert jurisdiction over any distribution line over which someone makes a wholesale sale.36 The first exception covers facilities in Hawaii, Alaska, and the Electric Reliability Council of Texas, which are not interconnected with the rest of the country and thus do not operate in interstate commerce. The second exception applies to facilities owned by municipal utilities, TVA, federal power marketing administrations, and cooperatives that have outstanding financing from the RUS.
This means that any distribution cooperative that has bought out of its RUS loans can become a FERC jurisdictional public utility, subject to regulation under the Federal Power Act, if any consumer on the cooperative’s distribution system chooses to install generation for sale at wholesale. With that new status, the distribution cooperative will be required to file a tariff at
FERC under which it agrees to provide transmission service for any interested party under rates, terms, and conditions determined by FERC. It also means that the cooperative will be required to conform to the generation interconnection rules that FERC is drafting now. In addition, the distribution cooperative will need to submit certain information to FERC every year, obtain
FERC approval of its financing activities, and meet a variety of other regulatory obligations.
A distribution cooperative that still has outstanding RUS financing would not be a public utility but would still be required to interconnect with and wheel power for any generator that
36 Access Energy Cooperative, 100 FERC 61,242 (2002)
46 builds on the cooperative’s system. Section 211 of the Federal Power Act provides that any
transmitting utility — which would include distribution cooperatives — would be required to
wheel power for any person generating electric energy for sale for resale. The process under
Section 211, however, is much more protective than that applied to public utilities.
Reciprocity is a requirement established by FERC Order No. 888 that allows a public
utility transmission provider to refuse transmission service to a nonjurisdictional transmission
provider (like a municipal or an RUS-borrowing cooperative) unless the nonjurisdictional
provider agrees to provide service to the public utility under similar terms and conditions of service that the public utility is required to provide.
47 CASE STUDY
Bridger Valley Electric Association, Inc. (BVEA) serves approximately 5,550 member- owned meters in southwestern Wyoming and northern Utah. Because it has retired all debt owed to the RUS and provides certain delivery service that FERC considers transmission service to the
Western Area Power Administration (WAPA), the cooperative is deemed a FERC jurisdictional public utility under the Federal Power Act.
BVEA obtained its waiver of Order Nos. 888 and 889 on the grounds that its transmission facilities are limited and discrete. It operates 180 miles of 69-kV line. Its system peak load is approximately 16 MW. Its facilities are not integrated with the regional transmission grid, are radial in nature, and are used to serve BVEA’s widely dispersed distribution customers. BVEA does not operate its own control area; rather, its facilities are in the Eastern control area of
PacifiCorp, Inc. Nor is BVEA a member of the Western Electricity Coordinating Council
(WECC). BVEA has a staff of 24, who deal almost exclusively with providing distribution service to BVEA’s member-owners.
In late April 2002, a wind generator requested interconnection to the cooperative’s facilities for a proposed wind farm in southwestern Wyoming whose output could be as much as
130 MW. Because interconnection service is a component of transmission service under FERC
Order No. 888, BVEA was advised by counsel that it would now have to file an Open Access
Transmission Tariff (OATT) with the Commission, despite the waiver the cooperative had previously received.
BVEA is a small utility as the Commission defines that term (3-4) and as a practical matter will have great difficulty implementing certain provisions of the Notice of Proposed
Regulation’s (NOPR’s) proposed Interconnection Procedures (IPs) and Interconnection
48 Agreement (IA) unless they are modified to take into account the needs of small distribution
utilities. For example:
Network Resource Interconnection Service. The proposed regulation contemplates transmission providers offering two types of interconnection service: Energy Resource
Interconnection Service, and Network Resource Interconnection Service. The latter would require the Transmission Provider to study the facility interconnection to determine, under a
variety of “severely stressed conditions,” whether the “full output” of the Generator Facility
could be “delivered to the aggregate of load on the Transmission Provider’s Transmission
System, consistent with the Transmission Provider’s reliability criteria and procedures.” The
proposed IA states that “this approach assumes that some portion of existing Network Resources
are displaced by the output of the Generator’s Facility.”
For a small utility with a limited transmission system such as BVEA, providing this type of
service is virtually impossible. There are no other Network Resources located on the BVEA system to displace; in fact, the only generator on the system is the 13 MW Fontenelle hydro facility operated by WAPA. BVEA takes its full power supply requirement from off-system sources, primarily from Deseret Generation & Transmission Co-operative, Inc. Nor could BVEA
consider delivering the output of the wind farm that seeks to interconnect with its system to the
“aggregate of the load” on its system, as the output of the projected wind farm far exceeds its
total native load. In short, providing Network Resources Interconnection Service is simply not
possible for BVEA, given its small size and the substantial limitations of its system. BVEA will
do its best to provide interconnection service and delivery service to requested interfaces with the
transmission facilities of other, larger utilities, and that is all that it can do.
49 Study Provisions. The proposed rule requires the Transmission Provider to conduct a
complicated series of studies. BVEA does not have personnel with the expertise to conduct such studies and would even have difficulty managing an outside consultant hired to undertake this work. Given the relatively simple nature of BVEA’s system, such studies may well fall into the category of overkill in any event. Moreover, BVEA does not have access to WECC’s Base Case transmission analyses, which are necessary to determine the potential impact of a generator interconnecting with BVEA’s system on neighboring transmission providers.
Liquidated Damages. Under the proposed IA, the Transmission Provider can be liable for
liquidated damages to the Generator if it is unable to complete the Transmission Provider
Interconnection Facilities by the in-service date. BVEA, as a small, member-owned distribution
cooperative, is in no position to pay such damages to a Generator. While it can commit to use its
best efforts to interconnect a Generator in accordance with good utility practice, it cannot be
responsible for events beyond its control, and it cannot pay liquidated damages without
endangering the continued provision of distribution service to its member-owners. BVEA is a
distribution utility first, and a Transmission Provider (a distant) second.
Definition of a Small Generator. The proposed IPs define a “Small Generator” as “units 20
MW and below or aggregations of interconnecting Facilities at a single Point of Interconnection
totaling 20 MW and below.” Given that BVEA’s current system peak is 16 MW, a generator of
20 MW or even 1 MW could have a very substantial adverse effect on BVEA’s system, and
would have to be studied and evaluated carefully; therefore, the use of expedited procedures
would not be appropriate. BVEA believes that no generator over 1 MW should be considered
small, at least when interconnected to a system with characteristics similar to or as small as
BVEA.
50 Applicability of IA and IPs to Distribution Level Connections. The Commission
proposes to apply the IA and IPs “when a generator interconnects to the Transmission Provider’s
transmission system or makes wholesale sales in interstate commerce at either the transmission
or distribution voltage level.” Because BVEA is already committed to purchase its full power
supply requirements from other sources, any generator hooking up to its system will in all
likelihood be selling the output of its facilities at wholesale and using BVEA’s system to wheel
its power to the integrated transmission grid. BVEA believes that it is inappropriate for the
Commission to require adherence to the IA and IPs for such interconnections, because BVEA
will be unable to provide service from its facilities in accordance with all of the proposed
provisions of the IA and IPs. BVEA also fears that providing interconnection service under the
onerous terms of the IA and IPs from its facilities could substantially increase costs to BVEA’s
member-owners.
BVEA has many other concerns with specific provisions of the proposed rule, all
stemming from the Commission’s failure to recognize that its regulations will not only apply to large public utilities, but increasingly to small cooperative public utilities such as BVEA. The
Commission states in its NOPR that “[t]he regulations proposed here impose requirements only on interstate transmission providers, which are not small businesses,” and thus certifies that “the proposed regulations will not have a significant adverse impact on a substantial number of small
entities.” This, however, is not correct. A substantial number of small rural electric distribution
cooperatives are now “public utilities” within the meaning of the Federal Power Act. Any one of
them could be served with an interconnection request at any time, as BVEA has been. If so, then
they will have to comply with the IA and the IPs, and compliance will be difficult and expensive,
if not simply impossible.
51 KEY LESSONS FOR DISTRIBUTION COOPERATIVES
Educate yourself about DG and wind generation. What DG or wind generation do you already have on your system? What is the interest level of your members with respect to DG and wind? What benefits could your cooperative receive from a properly structured and operated DG or wind program? What issues must be addressed? Typically these involve safety, reliability, affordability, or cost causation.
Educate your consumers about the true costs and benefits of DG and wind. The high level of interest that many cooperatives are seeing in their membership with respect to DG and wind may spring from misconceptions about the money to be made from investments in generation.
By helping their members do their due diligence, cooperatives can improve relations with their members and increase the likelihood that any DG or wind investments on their systems are economical for both the consumer and the cooperative as a whole.
Be prepared before the first consumer comes in to request an interconnection. Have in place technical interconnection rules, interconnection applications and contracts, and tariff rates for consumer generators. All of these should be discussed with and developed in conjunction with your G&T.
52 VII. TRANSMISSION AND THE WHOLESALE MARKET
While there may be many small wind generators in the 50 kW and smaller range interconnecting with distribution facilities, most wind farms and large wind generators in range of 600 kW and above will have to interconnect at the transmission level. Even those larger units that may interconnect at lower voltages will likely need to wheel power across the interstate transmission grid to reach load. Those transactions will have distinct implications for cooperative systems.
A. Grid Implications
Wind generation development in the United States has progressed to a point where some individual wind plants and projects have reached the size of a single medium-to-large conventional generating plant. Some anecdotal evidence indicates that at this size, wind projects do have impacts on system operating and control strategies. The fluctuating output of the wind plant, along with the potential loss of that resource due to a transmission system event, must be taken into consideration in the overall equation for deploying and controlling other generating plants in the control area.
The intermittent and mostly uncontrollable nature of wind generation introduces new variables into the power system control problem. Because wind generation on a significant scale
(relative to the bulk electric power system) is relatively new, general historical operating experience is lacking. Most previous evaluations have sought to determine the wind generation penetration level below which no impacts would be expected.
Recently, NREL initiated an effort to monitor the long-term output of several wind plants. Also, NRECA’s CRN is supporting an effort by the Utility Wind Interest Group (UWIG)
53 and others to conduct a quantitative investigation into the impacts of large wind generation
resources on bulk power system operation and scheduling functions. The work is to be based on
actual case studies, use conventional utility analyses and software tools, and develop alternative
approaches and methodologies as needed. UWIG is also initiating a parallel effort that will focus
on distribution systems, which often have limited resources for analyzing the potential impacts of
wind generation on their systems. The proposed development will result in two basic categories
of tools — information resources and a set of engineering software application tools. Several
groups are supporting this effort, and CRN will be contacted about participating for the benefit of
cooperatives.
B. Economic Implications of Wind Resources Locations
A review of Exhibit 2, the map showing where the nation’s best wind resources are
located, quickly shows the greatest drawback to wind energy: The best wind resources are
located in areas with the lowest electricity load and these areas also frequently have low existing
costs and retail rates. For that reason, they are also located in areas with little available
transmission capacity.
North Dakota, for example, has the best or second best wind resources in the country.
Unfortunately, however, North Dakota’s rural population is declining and overall energy demand growth is minimal. Moreover, the utilities that serve the majority of North Dakota’s consumers
have a surplus of inexpensive coal generation. North Dakota does not need new generation
resources for its own purposes.
The nearest market for new generation resources built in North Dakota would be the
growing loads in the Minneapolis and Chicago metropolitan areas. But the transmission facilities
to export power from North Dakota are already congested. These facilities might have enough
54 remaining capacity to move a small amount of additional generation east; however, the transmission capacity required to allow construction of hundreds of megawatts of new generation in North Dakota, let alone the many gigawatts of generation that would theoretically be possible given the native wind resources, simply does not exist.
The same problem can be observed in Texas. Due to the enactment of a renewable portfolio standard in Texas and the availability of good wind resources, several large wind farms have been built in West Texas. The windy areas of that state, however, have very little energy demand. Much of the energy generated by the new wind farms must be transmitted from the west to the load centers in the east: Dallas, Fort Worth, and Houston. Unfortunately, as in the north, existing transmission resources are inadequate to move all of the energy that the wind turbines can generate. One generator has actually had to derate the capacity of its existing wind units because it could not acquire the transmission capacity needed to move their energy to load.
While the obvious solution would be to build additional transmission facilities from areas with wind capacity to areas that need the power, such efforts could be slow, difficult, and expensive. As the Department of Energy recently explained, the nation as a whole is building far less transmission than it needs to meet existing and future needs.37
One challenge is NIMBYism (Not in My Back Yard). Many people do not want to see new transmission facilities built through their communities, due to concerns about effects on property values, visual pollution, and perceived health implications of electromagnetic fields
(EMF). These problems are exacerbated when transmission facilities are being built to move power from a neighboring state on one side to a neighboring state on the other side. Why,
Minnesota residents ask, should they have to accept the cost of siting a transmission line that moves power from North Dakota to Illinois without benefiting anyone in Minnesota?
37 United States Department of Energy, National Transmission Grid Study, May 2002.
55 Another challenge is determining who should pay for the cost of the new transmission
lines. Under “license plate” pricing as the Mid-American Independent System Operator’s rate
structure is designed today, consumers pay only for those transmission facilities built in the
territory served by the utilities in their “zone.” Thus, Basin Electric Power Co-op consumers pay
for lines built by Basin, and Commonwealth Edison consumers pay for lines built by Com Ed.
As a result, Basin consumers would pay most of the cost for facilities required to permit
independent wind generators in North Dakota to sell power to Com Ed consumers in Chicago,
but those Basin consumers would receive little or no benefit in return for their investment.
Under “Postage Stamp” pricing - “one price for all users” - transmission users pay a
charge based upon the overall system revenue requirements. The participating transmission
owners recover their actual costs and respective rates of return from the revenue pool. This
concept seems more conducive to future transmission construction, however, it could involve
cost shifting. Users with current low rates may experience their costs rising to the average system
cost, while high rate user costs would drop to the average cost. This approach would eliminate
“pancaking” of costs resulting from wheeling power across more than one control area in a North
American Electric Reliability Council region.
An alternative approach, now being debated before FERC, would require the independent
power producer to pay the cost of transmission required for the generator to serve load outside of
the region in which they build their generation. Generators, however, have strongly — and so far, successfully — opposed that approach. They argue that requiring them to pay for the
transmission facilities would discourage investment in much-needed generation and unfairly
disadvantage competitive energy suppliers. FERC will decide this issue in its Interconnection
and Standard Market Design rulemakings.
56 C. Economic Implications of Wind’s Intermittency
Transmission providers and wholesale consumers today expect that generators who make
a commitment to transmit or deliver energy at a particular time will actually transmit or deliver
that power. Accordingly, transmission providers, transmission markets, and wholesale
transmission consumers typically penalize generators who fail to meet their commitments by delivering more or less than the amount of power scheduled.
These penalties for scheduling deviations are intended to serve several purposes: to provide incentives to accurately schedule; to provide disincentives for those who might wish to game the system; to compensate those responsible for “balancing” the system for the cost of ramping other generators up and down to make up for the deviation; and to help maintain the reliability of the system by providing resources upon which the system can reasonably expect to be available when needed.
Because of wind’s intermittent nature, wind units often cannot avoid deviations from even the most carefully made schedule. When the wind blows harder than expected, wind units will generate more than expected, and when the wind is calm, wind units will generate less than
expected. Unless wind generators also operate dispatchable units to balance their own output, they are likely to incur substantial penalties for scheduling deviations.
Owners of wind generation and wind proponents have argued that these penalties discriminate unfairly against wind, making it harder for wind to compete economically. They have proposed policies that would require the system to provide balancing service at no cost by prohibiting the imposition of penalties for scheduling deviations. They have also proposed policies that would give them firm access to the transmission system but require them to pay for only the actual generation that they transmit — that is, firm service at nonfirm prices. Again,
57 such policies are, in effect, a subsidy to wind generators since the full cost of service or risk is not being carried by those generators.
As discussed above, FERC has approved the California ISO’s adoption of a tariff that moves in the direction sought by wind proponents.38 Whereas most generators in the California
ISO power market must maintain balance on a five-minute basis, wind generators pay no scheduling deviation penalties as long as they achieve balance averaged over a one-month period.39 This policy means that someone else on the system must provide balancing service for the wind generators on a real-time basis without compensation.
Some flexibility for wind generators may be appropriate. There is no need to penalize
“gaming,” as wind deviations are generally inadvertent, especially if — as in California — schedules are developed by a Regional Transmission Organization (RTO) or other entity independent of the generator. But, even where the wind generator does not game, the scheduling deviations can impose costs on whoever is responsible for balancing the system. The wind generator should be responsible for those actual costs.
38 California ISO, et al., 98 FERC 61,327 (2002). 39 Ibid.
58 VIII. ISSUES FROM THE CONSUMER PERSPECTIVE
According to the American Wind Energy Association, “the best candidates for a small wind system are rural homes and businesses with at least an acre of property and utility bills that average $150 per month or more.” The Department of Energy says that, “depending on your wind resource, a small wind energy system can lower your electricity bill by 50% to 90%, help you avoid the high costs of having utility power lines extended to remote locations, prevent power interruptions, and it is nonpolluting.”40
Agriculture has been under increased stress in recent decades. Farmers will find appealing reports of income up to $3000 per MW per year for leasing their land to large wind generators. Because only a few acres are required for the towers, transformers, and maintenance access, wind energy systems have very little negative impact on the farming operation.
Furthermore, consumers are told that if their turbines cannot provide enough energy to meet their needs, the utility will make up the difference, and when their wind systems produce more electricity than they need, they can sell the excess to the utility. Combine these features with subsidies like buy-down programs, net metering, and tax exemptions, as discussed in
Chapter IV, and it is easy to see why there is a growing interest in wind energy among cooperative members. However, while there are attractive aspects to wind generation, consumers must do their homework before embarking on this or any other investment that involves risk. The cooperative also needs to be prepared to explain the relative fixed costs involved in providing supplemental and backup service and how charges for those services might apply to the consumer.
40 Small Wind Electric Systems, A U.S. Consumer’s Guide, available at http://www.eren.doe.gov/wind.
59 A. Zoning Issues
Before investing in a wind energy system, a consumer should research potential
obstacles. Many zoning ordinances, for instance, have a height limit of 35 feet in residentially
zoned areas. In most cases, a height limit of 35 feet makes the application of small wind turbines
impractical. The American Wind Energy Association says, “A wind system should be installed
on a tower at least 60 feet [high] for the smallest units and 80 feet for a home-sized unit.”
B. Avian Issues
While studies have shown that bird kills from turbine impacts are far fewer than those related to vehicles, buildings and windows, power lines, communication towers, and felines, the impact of
wind turbines on birds remains an issue during the project approval process. Much of the
literature suggests that proper siting studies that take into account bird migratory patterns can lead to satisfactory solutions to this problem. In addition, on larger units, newer technology uses large turbine blades, which rotate at a relatively low speed and thus present a much lower risk to birds than earlier turbine designs. However, it is important to keep avian issues in mind when considering the purchase of a wind generator. For instance, serious problems might arise from violations of the Migratory Bird Treaty Act or the Endangered Species Act, or both, if even one bird from a protected species is killed.
In 1992, the Department of Energy directed NREL, a DOE laboratory, to begin a coordinated research effort into these matters. NREL is working with environmental groups, utilities, government agencies, university researchers, consumer advocates, utility regulators,
government officials, and the wind industry to address this issue. Extensive information on this
research program is available at www.nrel.gov/wind/avian.html.
60 C. Aesthetic Issues
Because the noise level for most modern residential wind turbines is around 52 to 55
decibels, no noisier than an average refrigerator, noise should generally not be a problem. A
more difficult aesthetic issue is the visual impact. Neighbors may complain if a turbine blocks
their view. It is a good idea to discuss these concerns before investing.
D. Safety Issues
The American Wind Energy Association indicates that in 20 years of operation, the wind
industry has recorded only one death. “Blade throws were common in the industry’s early years,
but are unheard of today because of better turbine design and engineering. Ice throw, while it can
occur, is of little danger because of setbacks typically required to minimize noise.”41 Wind
turbines are likely covered by local government (town, county, or state) electrical codes and must comply. See Chapter VI for a discussion of other safety issues.
E. Cost Issues
There are two main cost components to consider in the initial decision to buy: capital outlays required to get the system up and running, and annual operating expenses. A critical factor discussed earlier is capacity utilization. After the consumer has purchased and installed the
turbine, it is too late to realize that the investment cannot be recovered because the wind does not
blow enough. Costs are discussed in detail in Chapter IX.
1. Capital Costs
The cost of the turbine is the main capital cost, but the purchaser must also remember to
include the cost of the tower, delivery, installation, interconnection, and metering. The average
home system will likely be 5 to 15 kW. The cost for such systems ranges between $2500 and
41 AWEA Frequently Asked Questions, available at http://www.awea.org/pubs/documents/FAQ2002%20- %20web.PDF.
61 $3000/kW installed. Thus, an average system of this size would cost about $27,000. There could be significant interconnection costs if the distribution or transmission system to which the generator is interconnected needs to be upgraded.
Most utilities require consumers to sign an interconnection agreement, and several states have established standards for interconnection (see Chapter VI). Running a distribution power line from a remote site to the grid can be very costly depending on voltage, terrain, and other factors. Even when distance is not an issue, transmission capacity may be.
2. Annual Operating Costs
The costs of operation and maintenance are probably the most significant expenses a wind system operator must consider. These costs are estimated to be about 1.3 cents per kWh
(including taxes, insurance, and lease payments) for larger turbines (over 1 MW) and can be substantially higher (2.5 to 4.5 cents per kWh) for smaller turbines.
To purchase a wind system, most consumers will need some type of financing. Based on the example above, most consumers would finance their purchase using a first or second mortgage on their home. Based on the example shown under the Capital Costs heading, a wind system costing $27,000, financed at 8% for 20 years, would cost about $2000/year in interest in the early years.
Liability insurance may have to be factored into the annual operating costs. “some utilities require small wind turbine owners to maintain liability insurance in amounts of $1 million or more. Utilities consider these requirements necessary to protect them from liabilities for facilities they do not own and have no control over. Others consider the insurance requirements excessive and unduly burdensome.”42 Utilities may also require the consumer to
42 Small Wind Electric Systems, A U.S. Consumer’s Guide, available at http://www.eren.doe.gov/wind.
62 indemnify them for losses caused by the consumer. Consumers should be aware of these
possibilities and investigate local requirements.
The consumer must also consider the cost of standby or backup service if the system will
be connected to the grid (see Chapter VI).
F. Technical Issues
The intermittent nature of wind power may cause problems such as voltage regulation
and flicker. These problems can be accentuated when plants are located in remote areas, which is
frequently the case, and connected to the grid by transmission plant originally designed to serve
only native load. These matters are covered in more detail in Chapter VII.
G. Fairness Issues
As discussed in detail in Chapter IV, 35 states have adopted net metering, and several
others are considering doing so. In each of those states, if consumers use more energy than they
generate, they pay for only the net energy that they have taken from the system. The problem for
cooperatives arises when the time comes to compensate the owner of a wind generator for their generation. In particular, when net metering requires the cooperative to purchase the wind power at the consumer’s full retail price, the other cooperative members must bear the differential costs between the normal wholesale price and the retail price, even though the power provided may frequently come at a time of day when it is not needed. Thus, through cost shifting, the owner of
the generation receives a benefit at the expense of the other members.
63 IX. WIND ECONOMICS
The cost of wind energy continues to drop as wind turbine technology and associated equipment improve. In the energy crisis of the 1970s, utilities received major government subsidies to encourage the installation of wind power. Unfortunately, the existing wind turbine technologies could not support the increased production; consequently, most of the first-of-a-kind wind turbines that were installed failed. Failures ranged from blade problems to tower fatigue cracking, as well as electrical and control system unreliability. To make matters worse, the subsidies covered the installation of wind turbines, not electricity production, so the failed wind turbines still received the subsidy.
A. Technology Improvements
The nation and the wind turbine industry have now had more than 20 years to improve the technology. Present wind turbine subsidies are based upon electricity production, not equipment installation. New wind turbines being installed in wind farms are very large. A typical
650-kW unit has rotors that measure about 155 feet (approximately 50 meters) — more than half the length of a football field — and towers 215 feet tall. Foundations for these units require holes
30 feet deep and 14 feet in diameter. Manufacturers are actively involved in design and testing for wind turbines in the 2 to 4 MW size. Europe is testing a 5-MW turbine, and plans are under way at NREL to begin preliminary work on a 10-MW unit.
Wind turbines now have an availability exceeding 90%. Production capacity factors will always be dependent on location and wind velocities, but many wind turbines are producing capacity factors over 30%. A typical wind farm can be installed in a remote location within a two-year period, although building adequate transmission capacity to transport the electricity to load centers could take a much longer time.
64 As the technology improves and factory production increases, the cost of wind power
continues to drop. In 1980, wind energy cost about 25 cents/ per kWh. NREL reports that the cost of energy in 1991 from large wind farms (50 MW) ranged from 7.5 cents in high-wind areas to 11 cents/kWh at sites in moderate-wind areas. This same report estimates that for units coming on line in 2002, costs will range between 3.5 and 5.2 cents/kWh; by 2005, NREL projects wind energy costs will average 2 to 3 cents/kWh. The study, which was conducted in the year 2000 and is for a large wind farm, assumes a rapid decrease in costs of future turbine technology. The current cost for wind turbine installation of large wind farms is approximately $900 to $1000 per kW. For smaller installations, the cost for wind turbines is $1200 to $1300 per kW. Small units for individual farms or businesses (10-kW turbines) could run as high as $3000 per kW.
B. Green Pricing
Another source of income for wind turbine energy is “green pricing.” Renewable energy,
or “green power,” is increasing in popularity. Nationally, many consumers have indicated that they would be interested in purchasing energy from a source that is clean for the environment.
Recognizing that renewable energy is usually more costly than conventional electricity from
coal, gas, and nuclear plants, many customers are willing to pay a premium for the electricity.
Utilities using renewable energy frequently market that energy in blocks of 100 kWh, charging
premiums of between $2.50 and $3.00, depending on the system and its costs.
Recently, two 2.6-MW wind turbine projects were installed in the Midwest. The higher
cost of electricity from the project (in comparison to the current grid available price) was
recovered through green pricing. In this case, the premium was established before the project
was completed at 3 cents per kWh for a 100-kWh block. However, upon completion of the
projects within projected budgets, the premium is being revised to 2.5 cents/kWh for a 100-kWh
65 monthly block. Derivation of this premium is based upon the project cost of $3 million and the
projected turbine life of 20 years. Assuming a 30% capacity factor, the project should produce approximately 6800 MWh per year. The cost of money is estimated to be 7.25%. The derivation of this premium is explained below. Credit is taken for the sale of electricity at spot market value due to its intermittent generation.
Capital cost recovery 4.2 cents/kWh
Operation and maintenance 0.8 cents/kWh
Miscellaneous/taxes, etc. 0.5 cents/kWh
Total cost 5.5 cents/kWh
REPI credits 1.2* cents/kWh
Sell to grid, interruptible 1.3 cents/kWh
Green power premium 3.0 cents/kWh
*The current REPI recovery is approximately 1.8 cents/kWh but is for only 10 years. The
premium is levelized over a 20-year life of plant.
C. Installed Cost Estimates
Project costs typically include development, engineering, equipment procurement and
delivery, and construction pricing. Development costs include contract negotiations for the sale
of the electricity generated by the project, financing fees and interest during construction, site permits, meteorological studies and data acquisition, environmental and geotechnical studies, micrositing, and public reporting. Engineering costs include preconstruction, construction, and postconstruction engineering of roadways, foundations, electrical facilities, and operation and
66 maintenance facilities. Engineering costs also include site surveying, preparation of drawings, and utility engineer inspections/approvals. Equipment procurement and delivery costs include the turbines, towers, transformers, underground distribution cable to substation, interconnection equipment, and Supervisory Control and Data Acquisition (SCADA) system.
Construction costs include tower and turbine erection, plant startup and commissioning,
Federal Aviation Administration (FAA) lighting, permanent meteorological tower installation, project management and administration, general conditions (e.g., storage containers, security, and fuel), bonding, and out-of-pocket/subsistence expenses. Construction costs also include all civil/structural and electrical facilities, including installation of the underground distribution and interconnection to the local substation and standard utility protection, metering and SCADA equipment.
Exhibit 9 shows that equipment procurement and delivery account for approximately
70% of the cost of a 40-MW project. Construction costs are the second largest category of costs, at approximately 27%, with development and engineering costs totaling approximately 3%.
Exhibit 9. Breakdown of Project Costs for a 40-MW Wind Project
1.0%
27.4% Equipment Development Construction 69.8% Engineering
1.8%
67 Exhibit 10 shows that equipment delivery and procurement costs increase as a percentage
of total installed costs as project size increases. Likewise, construction costs decrease as a
percentage of total installed costs as project size increases.
Exhibit 10. Breakdown of Representative Project Cost Estimates
Percentage of Total Installed Cost Installed Cost
MW Development Engineering Equipment Construction ($/kW)
10 4.5 2.1 55.7 37.7 1200
20 3.2 1.7 61.8 33.4 1129
40 1.8 1.0 69.8 27.4 1062
60 1.4 0.9 72.6 25.1 1025
80 1.2 0.9 74.0 23.9 1000
100 1.1 0.9 74.9 23.1 980
Exhibit 11 shows high-, medium-, and low-wind project cost estimates as a function of
project size based on a review of project announcements and costs published in the literature.
Exhibit 11 shows that project costs decrease as project size increases, the knee of the curve being around 30 MW. Under 30 MW, the cost of wind turbine procurement and delivery is higher because of the smaller order quantities, and largely fixed development and engineering costs have to be spread over fewer MW of installed capacity. Above 40 MW, project costs start to level off between $900 and $1050/kW (medium estimate). In general, total installed costs are expected to be within the ranges shown in Exhibit 11, although site-specific factors may result in
68 actual costs outside these ranges (particularly for projects smaller than 50 MW). Such factors
include interconnection requirements, the need for system upgrades, soil characteristics
(foundation design), crane mobilization and demobilization, and weather (construction schedule).
Exhibit 11. Total Installed Cost Estimates as a Function of a Project Size
2000
High Cost Estimate 1500
1000 Medium
Low 500 Installed Cost ($/kW)
0 0 50 100 150 200 250 300
Plant Size (MW)
D. Operation and Maintenance Costs
Operation and maintenance (O&M) costs include operations staff labor, facilities
maintenance, spare parts, consumables, wind turbine repair and contingencies, maintenance reserve additions, electricity consumption charges, substation O&M, interconnection maintenance, interconnection metering and telecommunications, fuel and vehicle maintenance, tools and safety equipment, site security, office utilities and supplies, meteorological tower maintenance, and wind plant control system maintenance. Experience shows that maintenance costs are generally very low while the turbines are new but increase as the turbines age. O&M
69 costs are estimated to be in the range of $14,000 to $15,000/MW/year over the first two to three
years of the turbine’s operation, or approximately 0.53 to 0.57 cents/kWh for a 100-MW project
operating at a capacity factor of 30%. O&M costs are assumed to increase with inflation over the
life of the project.
Twenty-year cumulative O&M costs range from 0.65 to 0.9 cents/kWh, with the lower cost range attributable to large turbines (larger than 1 MW) with integral cranes.43 Long-term
O&M cost drivers are generally associated with the repair or replacement of gearboxes,
generators, and yaw systems. The cost for cranes is a major concern for large wind turbines,
leading to 40% of total O&M costs over 20 years.
Wind turbine manufacturers typically offer a 95% availability and power curve warranty,
assuming that they provide O&M services under an operating agreement with the project owner.
Wind turbine manufacturers do not provide any type of warranty absent such a service
agreement, since they have no control over service personnel (e.g., a significant amount of
potential up-time could be lost before service personnel attend to and/or reset a turbine fault).
Service agreements typically include all parts and labor for a period of two years, with three- to
five-year options also available. Some manufacturers do provide availability and power curve
warranties for acceptable service providers other than themselves, while others have indicated
that a parts warranty absent a service agreement is also negotiable. In general, wind project
financiers (e.g., commercial banks) prefer or require that the manufacturer of the turbines
continue to be involved in the operation of the project during an initial warranty period.
43 W. A. Vachon, “Long-term O&M Costs of Wind Turbines Based on Failure Rates and Repair Costs,” paper presented at Windpower 2002, June 2-5, 2002, Portland, OR.
70 E. Non-Operating Expenses
Non-operating expenses include land lease payments, local taxes, and insurance. Land lease payments are assumed to provide local landowners with an annual income up to approximately $3000 per MW for turbines installed on their property. One common land lease model provides for a payment of 2% of the receipts from the sale of electricity generated by each turbine. The 2% payment sometimes increases to 4% after 15 years. Assuming a property tax rate of 0.8% of total installed costs and an insurance rate of 0.5% of total installed costs, total non-operating expenses for a 100-MW project operating at a capacity factor of 30% can equal
0.65 cents/kWh.
One cooperative in Alaska was attracted to wind, in part, for economic development purposes. The cooperative has been able to provide a number of jobs and construction partnerships that have been beneficial to the community.
Exhibit 12 lists electric cooperatives that currently offer their members a wind energy choice.
71 Exhibit 12. Electric Cooperatives Offering Members a Wind Energy Choice
Capacity Plant
Cooperative Plant Owner Plant Name State Units (MW) On Line Relationship
Alaska Village EC Kotzebue Electric Wales Wind Energy Project AK 2 0.1 2000 Purchases output from project
Owns and operates Prairiewinds and
Basin Electric Basin Electric Prairiewinds/Chamberlain SD 2 2.6 2001 markets the portion of power not used by
East River to other RECs
Markets one third of Chandler output Dairyland Power Great River Energy Chandler Hills MN 9 6 1998-2001 through EnPower's "Evergreen" program
Markets Prairiewinds' power in eastern SD East River Electric Basin Electric Prairiewinds/Chamberlain SD 2 2.6 2001 and western MN
Has an agreement with BPA to purchase a
small block of power from the Idaho Falls
and Packwood hydroelectric facilities and Flathead Electric Co-op Flathead Electric Co-op MT the Foote Creek wind facility; uses EFP
(Environmentally Friendly Power) program
to market power to members
Owns, operates, and markets the power to
Great River Energy Great River Energy Chandler Hills MN 9 6 1998-2001 members as Wellspring Renewable Energy
Program
Purchases 5 MW of wind power and offers
Holy Cross Energy Contracts for wind power it to its customers as part of a green energy
program
Kotzebue Electric Kotzebue Electric Kotzebue Wind Energy AK 10 0.5 1997-1999 Owns and operates
Washington RECA started Last Mile Co-op
in 2001 to bring power to remote areas. It is Last Mile Electric Co-op Last Mile Electric Co-op Nespelem Valley WA 2001 made up of 11 cooperatives, 2 munis, 2
PUDs, and 4 nonutilities.
This cooperative purchases environmentally
preferred power from Bonneville. 2 small hydro and Foot Midstate Electric Co-op BPA WY Customers can purchase 100-kWh blocks Creek Wind with a minimum purchase requirement of
two blocks for an added charge on their bill.
72 Owns and operates the wind turbine and
markets the power to cooperative and
Minnkota Power Co-op Minnkota Power Co-op Infinity ND 0.9 2002 municipal member systems in eastern ND
and northwestern MN under the Infinity
Wind Energy program
Orcas sells members green energy in 100-
kWh blocks at a 3.5 cents/kWh premium
over the 5.6 cents they normally pay. Two
Orcas Power & Light BPA WA 78 cents goes to BPA to pay for its green
premium, and the other 1.5 goes into a fund
that rewards customers who put in green
generation.
Members of Tri-State can buy wind power
from Tri-State and offer it to customers as
part of a green energy program. About half
Platte River and Terra the members participate. Tri-State has 2 Tri-State G&T Assn. 1.66 Moya Aqua contracts: Platte River Power Authority
Wind, which has one 660-kW unit, and
Terra Moya Aqua, which is building a 4-unit
1-mW project.
Yampa customers can buy green power in
Yampa Valley PSC of Colorado Ponnequin Wind Facility CO 100-kWh blocks for an added charge on
their electric bill.
Under development
Alaska Village Alaska Village Electric Kotzebue/Selawik AK 4 0.264 2002 Electric Cooperative Cooperative
Great River Energy Buffalo Ridge MN 21 2002 Will receive the output
Approved in 2001 for a $1 million federal Washington Electric VT grant to develop a wind energy project
73 X. RESOURCES
The following Web sites and references are a few of the many wind energy resources available on the Internet. These resources offer a wealth of data on the technical and economic aspects of modern wind generation.
A. Useful Web Sites
These references are provided for the convenience of NRECA members. NRECA is not responsible for the content of these sites. Inclusion in this report is not meant to imply an endorsement by NRECA.
1. American Wind Energy Association (AWEA) — www.awea.org
At this site one can access information on utility-scale and small wind systems, publications, and frequently asked questions about wind energy, standards, and projects. The
AWEA Web site contains comprehensive links to Web sites of many other participants in the wind industry.
2. Utility Wind Interest Group (UWIG) — www.uwig.org
UWIG is a nonprofit corporation whose mission is to accelerate the appropriate integration of wind power for utility applications through the coordinated efforts and actions of its members in collaboration with industry stakeholders, including federal agencies, trade associations, and Electric Power Research Institute. Membership is open to utilities and other entities that have an interest in wind generation.
3. Danish Wind Turbine Manufacturers Association — www.windpower.dk
This site offers more than 100 pages of useful information and tools, including calculators on wind resources, wind turbine technology, and the economics and environmental aspects of wind energy.
74 4. National Renewable Energy Laboratory — www.nrel.gov
This is a U.S. Department of Energy source for data on renewable energy resources.
Itoffers publications and photos. Look for the Wind Energy Resource Atlas of the United States
at http://rredc.nrel.gov/wind/pubs/atlas.
5. National Wind Coordinating Committee — www.nationalwind.org
This site offers access to publications addressing wind energy/bird interactions,
distributed wind power applications, green power marketing, wind energy facility permits,
transmission issues, and costs. The committee’s Permitting of Wind Energy Facilities: A
Handbook, published in March 1998, was cited as a valuable resource by survey participants.
B. Useful Books
1. Wind Energy Basics (A Real Goods Solar Living Book)
Paul Gipe, Chelsea Green Publishing Co., White River Junction, VT, 1999. The book is
a guide to small and micro wind systems.
2. Wind Energy Comes of Age
Paul Gipe, John Wiley & Sons, Inc., New York, 1995. This is a thorough assessment of
wind technology and the economics and politics of generating electricity with wind.
3. Wind Resource Assessment Handbook
National Renewable Energy Laboratory, 1997. NICH Report No. SR-440-22223. Search
the NREL publications database at www.nrel.gov/publications. Fundamentals for conducting a
successful wind monitoring program, prepared by AWS Scientific, Albany, NY.
75