Whitepaper on wind power

8/14/2019 Whitepaper on wind power

1/78

National Rural Electric Cooperative Association4301 Wilson Boulevard

Arlington, VA 22203-1860April 2003


2/78


3/78

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


4/78

1

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 papers scope to evaluate predictions and proposed target goals regarding future wind


5/78

2

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.


6/78

3

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 earths 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.


7/78

4

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 nations or the worlds 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


8/78

5

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.


9/78

6

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 nations

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


10/78

7

Exhibit 1. Wind Power Classification

Exhibit 2. U.S. Wind Power Classification Map


11/78

8

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.


12/78

9

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 Energys Wind Powering America program supports a national goal

of increasing wind energys 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 nations 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


13/78

10

noted that this action by RUS strongly supports the Presidents National Energy Policy to

promote the increased use of our nations 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.


14/78

11

Exhibit 3. State Wind Power Incentives

Economic and Financial Incentives Legislative, Regulatory, OtherWindPotential(billionkWh) Tax Incentives Financial Incentives

NetMetering RPS

Research /OutreachProgram SBC Disclosure

Alabama 0 Alaska n/a Loans

Arizona 10 Sales, corporate, and personal income Loans Yes Yes

Arkansas 22 Yes

California 59 Loans, green power credit,

rebatesYes Yes Yes Yes

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

Illinois 61 PropertyGrants, loans, rebate

programYes Yes Yes Yes

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 YesMaryland 3 Yes Yes

Massachusetts 25 Sales, property, corporate, personal Yes Yes Yes Yes YesMichigan 65 Incentive payments

Minnesota 657Sales, property, accelerated depreciation,

production tax creditLoans Yes Yes

Mississippi 0 Missouri 52 Loans Montana 1020 Property, corporate, personal Yes Yes

Nebraska 868 Loans

Nevada 50 Property Yes Yes YesNew Hampshire 4 Property Yes Yes YesNew Jersey 10 Sales Yes Yes Yes New Mexico 435 Yes

New York 62 Yes Yes Yes YesNorth 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 YesRhode 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 YesWashington 33 Corporate Yes Yes YesWest 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 = retailersare 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, availableat www.awea.org.


15/78

12

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. Bushs economic stimulus package, signed

in March 2002. The American Wind Energy Association, which lobbied for the bills 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


16/78

13

diligently to overcome this budget shortfall. To that end, NRECA suggested language that was

included in last years 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

farms 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 cooperatives

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.


17/78

14

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).


18/78

15

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.


19/78

16

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).


20/78

17

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

states recent restructuring law, which guaranteed consumers right to have access to . . . on-site

distributed generation10 The Texas rule defined on-site distributed generation as an electrical

generating facility located at a customers 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 units

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 InterconnectionRequirements for Distributed Generation Units, Case 94-E-0952 (December 31, 1999), p. 3 (hereinafter NYPSC99-13).10 Senate Bill 7 (SB 7), Act of May 21, 1999, 76th Legislature, Regular Session, chapter 405, 1999 Texas SessionLaw Service 2543, 2561 (Vernon), to be codified as an amendment to the Public Utility Regulatory Act, TexasUtilities 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).


21/78

18

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.


22/78

19

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 GenerationInterconnection Agreements and Procedures, Dkt. No. RM02-01-000 (April 24, 2002); Federal Energy RegulatoryCommission Advanced Notice of Proposed Rulemaking on Standardization of Small Generator InterconnectionAgreements and Procedures, Dkt. No. RM02-12-000 (August 26, 2002).


23/78

20

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 FERCs jurisdiction over

interconnection of generation to distribution facilities, as well as a broad interpretation of

FERCs 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 cooperatives 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


24/78

21

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 utilitys historic peak load.21

Many states adopted net metering as a way of implementing PURPAs 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 customers 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.


25/78

22

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.


26/78

23

V. WIND POWER TECHNOLOGY

Todays 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

Small (50 kW)Homes

Farms

Remote Applications (e.g.,

Water Pumping,

Telecommunications,

Icemaking)

Intermediate

(51-250 kW)Village PowerDistributed Power

Large (251 kW-2.5 MW)Central Station Wind Farms

Distributed Power


27/78

24

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 recentlyinstalled 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 = 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.


28/78

25

Exhibit 5. Types of Wind Turbines

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.

Horizontal

Vertical


29/78

26

Exhibit 6. Wind Turbine Model Specifications

Manufacturer/Model

Rated

Power

(kW)

Rotor

Diameter

(m) Rotor Control

Tower Height

(m)

Vestas-American WindTechnology, Inc.North Palm Springs, CA(760) 329-5400Vestas V47

660 47 Variable pitch 40-65

Vestas V80 1800 80 Variable pitch 60, 67, 78

NEG MiconNorth Palm Springs, CA(760) 251-5461NEG Micon NM52

900 52.2 Stall 72

NEG MiconNM72 1500 72 Stall 70, 80

Nordex USA, Inc.Grand Prairie, TX(972) 660-8888

800 50 Stall 46, 50, 70

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 EnergyTehachapi, CA(661) 823-6700GE 1.5s

1500 70.5 Variable pitch 65, 80

GE 1.5sl 1500 77 Variable pitch 65-100

Mitsubishi Power Systems

Lake Mary, FL(407) 688-6100MWT-600

600 45 Variable pitch 40, 45, 50

Mitsubishi MWT-1000 1000 56 Variable pitch 60


30/78

27

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 turbines 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


31/78

28

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.


32/78

29

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.


33/78

30

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 winds

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


34/78

31

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 consumers 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 systems voltage and frequency; contribute to the systems 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.


35/78

32

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 Systems27 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.


36/78

33

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.


37/78

34

(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 cooperatives 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 generators output to another consumer under 205 or 211 of theFederal Power Act.30 Federal Power Act, 210, 16 USC 824i.


38/78


39/78

36

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 consumers load. For that reason, some utilities charge

consumers who install their own generation an exit fee to recover the stranded costs. Some


40/78

37

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 consumers 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 consumers 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

utilitys incremental costs.


41/78

38

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 rarelyexport 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 cooperatives facilities to another customer.


42/78

39

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

cooperatives energy requirements, and the cooperatives 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


43/78

40

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

consumers impact on the fixed costs of the system. It also understates the consumers 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


44/78

41

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 customers net exports to the system

separately from the customers 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 consumers 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

consumers generation. The cooperative can set the rate it pays for consumer generation based on


45/78

42

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 cooperatives 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 FERC61,056 (1999); InPower Marketing Corp., 90 FERC 61,329 (2000); Removing Obstacles to Increased ElectricGeneration and Natural Gas Supply in the Western United States, 94 FERC 61,272 (2001); Removing Obstacles toIncreased Electric Generation and Natural Gas Supply in the Western United States, 96 FERC 61,155 (2001).


46/78

43

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 FERCs 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 arms 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).


47/78

44

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 cooperatives 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 systems peak demand. The key here is being

creative enough to find means of meeting systemwide needs within the context of the existing

relationships.


48/78

45

D. Wheeling Excess Generation

If the cooperative does not purchase the output of generation located at a consumers 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.


49/78

46

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 cooperatives 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)


50/78

47

builds on the cooperatives 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.


51/78


52/78

49

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 Providers Transmission

System, consistent with the Transmission Providers 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 Generators 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.


53/78

50

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 BVEAs system, such studies may well fall into the

category of overkill in any event. Moreover, BVEA does not have access to WECCs Base Case

transmission analyses, which are necessary to determine the potential impact of a generator

interconnecting with BVEAs 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 BVEAs current system peak is 16 MW, a generator of

20 MW or even 1 MW could have a very substantial adverse effect on BVEAs 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.


54/78


55/78

52

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.


56/78

53

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, NRECAs CRN is supporting an effort by the Utility Wind Interest Group (UWIG)


57/78

54

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 nations 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 Dakotas rural population is declining and overall energy demand

growth is minimal. Moreover, the utilities that serve the majority of North Dakotas 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

Documents

Whitepaper on wind power