Table of Contents

Abstract............................................................................................................................... 1

Summary ............................................................................................................................. 1

Introduction and Background ............................................................................................. 2

Existing Research........................................................................................................ 3

Goal and Scope ........................................................................................................... 4

Methodology ....................................................................................................................... 5

Components of the Estimated Direct Economic Impacts ................................................... 5

Construction................................................................................................................ 5

Financing..................................................................................................................... 6

Operations and Maintenance....................................................................................... 6

Fuel Extraction and Transport .................................................................................... 7

Landowner Revenue ................................................................................................... 7

Property Taxes ............................................................................................................ 8

Sales Tax................................................................................................................... 10

Discount Rate............................................................................................................ 10

State Specifics................................................................................................................... 10

Arizona...................................................................................................................... 11

Colorado.................................................................................................................... 12

Michigan ................................................................................................................... 13

Assumptions...................................................................................................................... 14

Results............................................................................................................................... 17

Individual State Results .................................................................................................... 19

Colorado Results and Specific Sensitivities ............................................................. 20

Sensitivity Analyses.......................................................................................................... 24

Lessons Learned................................................................................................................ 26

Conclusion ........................................................................................................................ 28

Acknowledgments............................................................................................................. 28

References......................................................................................................................... 29

Bibliography ..................................................................................................................... 31

Personal Communication .................................................................................................. 32

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Figure 1. Prediction of annual electricity sales from 1970 – 2025 by the Department of

Energy’s Energy Information Administration (released February 2005) ......... 2

Figure 2. Construction lead time for coal, gas, and wind plants ...................................... 6

Figure 3. Arizona’s coal-producing area. Source: EIA, 1999 ........................................ 11

Figure 4. Arizona’s electricity mix. Source: EIA, 2000................................................. 11

Figure 5. Colorado’s wind resource at 50 meters. Source: NREL, 2004 ....................... 12

Figure 6. Colorado’s electricity mix. Source: EIA, 2000............................................... 12

Figure 7. Michigan’s gas and oil production fields. Source: Michigan Economic

Development Corporation, 2000..................................................................... 13

Figure 8. Michigan’s electricity mix. Source: EIA, 2000 .............................................. 14

Figure 9. Natural gas transmission line capacities. Source: EIA, 2000 ......................... 15

Figure 10. Average weekly coal spot prices ($/ ton) from May 2002 through April 2005.

Source: EIA..................................................................................................... 16

Figure 11. U.S. natural gas spot prices from 2000 to 2006 in $/ thousand cubic feet.

Source: EIA..................................................................................................... 17

Figure 12. Base case scenarios of economic impact from new power plants in Arizona,

Colorado, and Michigan..................................................................................

18

Figure 13. Dollars spent on new electricity generation from coal, gas, and wind in

Arizona............................................................................................................

19

Figure 14. Dollars spent on new electricity generation from coal, gas, and wind in

Colorado.......................................................................................................... 19

Figure 15. Dollars spent on new electricity generation from coal, gas, and wind in

Michigan

......................................................................................................... 20

Figure 16. Colorado vs. out-of-state impacts from new electricity generation................ 21

Figure 17. Direct impact to Colorado economy from a new coal plant, with uncertainty

bars.................................................................................................................. 22

Figure 18. Spending in Colorado for a new natural gas plant, with uncertainty bars ...... 23

Figure 19. Spending in Colorado for a new wind power plant, with uncertainty bars..... 23

Figure 20. Sensitivity scenario: 100% of coal is from Colorado mines........................... 25

Figure 21. Sensitivity scenario: 66% of natural gas is from Colorado............................. 25

Figure 22. Total impacts (in and out-of-state) for a new Colorado coal plant, with and

without a discount rate of 5% ......................................................................... 26

Figure 23. Total impacts (in-state and out-of-state) for a new Colorado coal plant, with

and without a discount rate of 7%................................................................... 26

Table 1. Energy Equivalents .............................................................................................. 3

Table 2. Dollars Spent in Colorado from 270 MW New Energy Output over 20 Years.20

Table 3. Direct Economic Benefits from New Coal Generation ..................................... 22

Table 4. Direct Economic Benefits from New Natural Gas Generation.......................... 22

Table 5. Direct Economic Benefits from New Wind Generation

(635 1.5-MW turbines)

...................................................................................... 23

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Abstract

With increasing concerns about energy independence, job outsourcing, and risks of

global climate change, it is important for policy makers to understand all impacts from

their decisions about energy resources. This paper assesses one aspect of the impacts:

direct economic effects. The paper compares impacts to states from equivalent new

electrical generation from wind, natural gas, and coal. Economic impacts include

materials and labor for construction, operations, maintenance, fuel extraction, and fuel

transport, as well as project financing, property tax, and landowner revenues. We

examine spending on plant construction during construction years, in addition to all other

operational expenditures over a 20-year span. Initial results indicate that adding new

wind power can be more economically effective than adding new gas or coal power and

that a higher percentage of dollars spent on coal and gas will leave the state. For this

report, we interviewed industry representatives and energy experts, in addition to

consulting government documents, models, and existing literature. The methodology for

this research can be adapted to other contexts for determining economic effects of new

power generation in other states and regions.

Summary

This paper compares direct spending in Arizona, Colorado, and Michigan on the new

construction and operation of three types of power plants: wind power, a natural gas

combined-cycle baseload plant, and a coal-fired power plant. We follow the flow of

money for each new plant and measure which dollars would be

spent in Colorado (for example, dollars paid to a Colorado

company to purchase concrete for a plant foundation or dollars

spent on Colorado concrete workers’ salaries). To reach a fair

comparison, spending is calculated based on the same amount of

energy generated by each plant—approximately 2,000,000

megawatt-hours (MWh) per year.

1

This amount of electricity

would be generated by a 270-megawatt (MW) natural gas plant

with an 87% capacity factor. Rated capacities of the coal and wind

plants were adjusted so that they would generate the energy

equivalent to the gas plant. The coal plant would be 280 MW in Arizona and Colorado

but 300 MW in Michigan (VanderVeen 2005).

2

The wind plant capacity will vary in each

state according to the wind regime. The components of each power plant included in this

analysis are parts and labor for construction, operations and maintenance (O&M), fuel

extraction, and fuel transport, in addition to money spent on financing, landowner

royalties, and property taxes.

Research components:

o Construction

o Operations and

maintenance

o Fuel extraction

o Fuel transport

o Land leases

o Financing

o Property taxes

1

In this study, coal, gas, and wind comparisons are based on an equivalent amount of energy produced.

Each resource will produce the equivalent energy from a 270-MW natural gas plant with a capacity factor

of 87%. To equal the output of the gas plant, this means that a coal plant with an 80%-85% capacity factor

will need 280 MW of generating capacity, and wind farms with a capacity factor of 25%-35% will need

680 MW-900 MW. Capacity factors for wind were determined by aggregate data from developers in each

state.

2

According to the assumption in the VanderVeen report for the Michigan Public Service Commission that

a coal plant will have the capacity factor of 80% versus 85% in Colorado and Arizona.

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Of the various impacts to the state economy involved in power generation over 20 years,

each state has varied results that show equivalent generation of wind power will bring the

highest direct economic benefit to the state. Tax revenue (especially for wind plants)

plays a significant role in the benefits to the state’s economies because a larger tax base

makes it possible to provide more funding for public goods, such as parks, roads, and

schools. If power plant owners negotiate a deal with localities in which they build so that

they are exempt from property and sales taxes, the local economy may benefit from some

job creation or fuel sales, but it will not receive what can be very significant property tax

benefits over the life of the plant. As shown in the results, much of the labor force for

plant construction, as well as for operations, is often brought in from outside each state.

When the labor forces for construction or fuel transport come from within the state’s

borders, economic impacts can be considerable, regardless of where the fuel is initially

extracted. Of course, if coal or gas comes from the same state where the power plant is

located, the economy is more likely to benefit from the sale of the fuel.

Results are based on the best available data from industry and government sources.

Examples of uncertainties in the data are represented for each generation technology in

the Results section of this paper. The methodology detailed in this report is useful for

researchers in regions where there are questions about which energy source to build next

and which generation source most benefits the local economy. Results may also help

inform decision-makers who want to maximize benefits to their state by providing an

energy-equivalent method of comparison.

Introduction and Background

In the United States, the need for additional electricity generation continues to increase

due to the growing population and demand from energy consumers. The Department of

Energy predicts that this growth will continue (Figure 1).

Figure 1. Prediction of annual electricity sales from 1970 – 2025 by the Department of

Energy’s Energy Information Administration (released February 2005)

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With a growing focus on domestic power resources for energy independence and the

need for new employment opportunities, it is important for decision-makers to understand

the economic impacts of energy generation sources on their local economy. For example,

when a new power plant is built, laborers will be needed to pour the concrete for the

foundation of the plant. If the workers come from within the state, this new project will

contribute to the state’s economic well-being by paying state residents.

This paper compares the flow of money into and out of states from three potential sources

of new electricity production. We examine the impact of developing three new

hypothetical power plants to produce electricity from coal, natural gas, and wind. We also

explore how much money each new plant would contribute to Colorado’s economy by

adding labor from Colorado, equipment sold in Colorado, landowner payments, and

property taxes. As indicated in Table 1, coal, gas, and wind comparisons will be based on

the amount of energy produced.

3

Table 1. Energy Equivalents

Capacity Factor

Equivalent MW Needed

MWh Produced per Year

Coal

80%-85%

280 - 300

~ 2,084,880

Gas

87%

4

270

~ 2,057,724

Wind

25%-35%

680 - 900 (1.5-MW turbines)

~ 2,084,880

The equivalent megawatts are determined by multiplying the capacity by the capacity

factor by the number of hours in a year. For example:

270MW x 0.87 x 8760 hrs/year = 2,057,724 MWh

.

The results of this study may be used in policy analysis for issues such as potential

renewable portfolio standards and system benefits charges or in decisions based on

maximization of economic benefits to states from their natural resource potential. Results

also indicate how much the specific components of new energy generation will benefit

the states’ economies.

Existing Research

Many informative studies about the impacts of electricity production have been

performed, including an examination of which energy sources create the most jobs or

produce the greatest advantages for consumers or the environment (Madsen et al. 2002;

National Wind Coordinating Committee 1997; Clemmer 2001; Goldberg et al. 2004;

Kaas Pollock and Gagliano, 2004; Regional Economics Applications Laboratory 2001;

Wind Energy Creates 1995). The body of literature about wind’s economic development

impacts and the uncertainty of gas pricing is growing (Wiser and Kahn 1996), as well as

3

Energy from each source is an estimate of potential generation for comparison purposes and is

independent of operational constraints, including those that might be driven by changes in fuel prices.

4

87% is the highest capacity factor given to a natural gas power plant by the Energy Information

Administration. This is used as a basis for comparison. Currently, natural gas prices are too high to make

construction of a baseload natural gas plant economically feasible, but prices of gas and other resources

will vary in the future. This study does not consider costs to consumers, but it should be noted that at

present fuel prices, an 87% capacity factor is unlikely.

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several modeling tools to calculate economic impacts (Goldberg et al., 2004; Costanti

2004). The methodology for this report was initially developed for a paper describing the

economic benefits to Colorado published in the Global WINDPOWER 2004 conference

proceedings (Tegen 2004). But a comparison of multiple states’ resources and their direct

economic impacts from sources of new utility-scale generation has not been conducted.

Unlike other work, this study compares direct impacts specific to statewide economies.

Wherever possible, data were gathered from state-specific energy companies

5

and energy

experts, instead of using national averages and extrapolating costs for each component.

Goal and Scope

The scope of this project is the measure of direct economic impacts from new sources of

electricity. In other words, we calculated how much money will be spent in each state for

salaries, purchasing materials, land revenues, financing, and taxes when new power

plants are built and operated. For each resource, the study compares the following

components of new electricity generation:

•

Materials and labor for construction

•

Materials and labor for O&M

•

Materials and labor for fuel extraction (gas well or coal mining)

•

Materials and labor for fuel transport (including railroads, shipping, and gas

pipelines)

•

Project financing

•

Landowner revenues

•

Property taxes

When analyzing direct economic impacts of coal, we include parts and labor for coal

mining and coal transport (from the mine to the power plant by railroad or ship) under the

fuel component for each state analyzed. For natural gas, we include parts and labor for

gas extraction at the wellhead and parts and labor for gas pipeline costs. This research

does not include indirect or induced effects of energy production (e.g., plant construction

worker’s hotel bills).

6

The new power generation facilities are assumed to be grid

connected. Other assumptions are found in the Assumptions section.

The primary goal of this research is to provide a careful state-specific comparison of the

money flow from new power generation. Project results are not meant to represent

national averages or economic impacts in other locations. However, strategies and

models for data gathering used in this study will be helpful for others working on similar

projects (see Lessons Learned). It is important to remember that data for this paper were

gathered in early 2005 and that the results presented here reflect these inputs. The

5

Companies include developers, utilities, municipalities, private wind generators, pipeline companies, coal

railroad companies, and energy-equipment companies.

6

Indirect effects are additional economic activities stimulated by direct spending associated with power

plant construction and operations (e.g., hotel revenue from out-of-state workers). Induced impacts are

increases in economic activity associated with increased disposable income created by power plant

constructions, operations, and other power plant spending (e.g., increased spending on clothing due to

increase in family incomes from power plant work salaries).

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purpose of this paper is to introduce a useful methodology. When utilizing this

methodology in the future, inputs should be changed to reflect the most current data

available.

Methodology

The methodology for this project includes a number of data-gathering techniques. In

addition to the aforementioned interviews with analysts, government energy offices, and

industry contacts, we also conducted literature searches. We used the BaseCase database

from Platts, a division of the McGraw-Hill Companies, Inc., and the jobs and economic

development impacts (JEDI) economic development analysis tool for wind projects from

the National Renewable Energy Laboratory (NREL).

7

After sufficient economic data

were gathered for the chosen energy sources, we sent the assumptions to energy experts

for each resource and compiled in a spreadsheet format most useful for comparisons of

each power source.

For each component of the study (e.g., labor for natural gas extraction), we compared the

best-estimate value based on $/kilowatt-hour (kWh).

8

Next, sensitivity analyses were

performed to determine how much higher and how much lower the dollar value could

potentially be. For example, if some industry reports conclude that average annual O&M

costs for natural gas are $15.50/kilowatt (kW, nameplate capacity), but reliable models

report that the same costs are $27/kW, it is necessary to conduct further analysis and

determine high and low ranges around a best-estimate dollar amount. Each component of

this study is represented by a best-estimate cost with a range of uncertainty above and

below it, when applicable. It is necessary to explain each dollar category or “component”

so that the scope, assumptions, and uncertainties are clear when viewing the project

results.

Components of the Estimated Direct Economic Impacts

Construction

For each energy resource, we conducted many interviews to determine prices of new

construction. We assumed that construction would begin in 2005. Interviews were

primarily with industry contacts or from each state’s energy experts. In Michigan, we

relied on experts and the Michigan Public Service Commission’s current reports. The

construction component includes the capital cost of equipment as well as overhead, legal

and permitting costs, and engineering. It also includes the cost of land, except for annual

land-lease payments (e.g., to farmers paid for wind turbines on their land). The

construction phase of a new power plant will vary for each generation technology.

Constructing a coal plant of this size can take 3 to 6 years, whereas natural gas plants

typically take 1.5 to 2 years, and wind plants can take between 6 months and 1 year to

develop. Wind generation of such large size would likely take about 1 year.

7

An easy-to-use tool to analyze potential jobs, economic development, and impacts from wind

development. www.windpoweringamerica.gov/filter_detail.asp?itemid=707

8

Some costs are typically reported in $/kW or $/megawatt, but we used a $/kWh calculation for a fair

comparison.

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1

2

5

20

20

20

Wind

Gas

Coal

Construction

Operation

Figure 2. Construction lead time for coal, gas, and wind plants

Financing

It is unlikely that an in-state bank would finance a utility-scale power plant project. Local

banks are increasingly willing to finance new wind projects, but those projects are usually

much smaller than 280-MW projects (typically 50 MW or less). A variety of financing

techniques exist for power plants, but this study assumes financing by a utility or large

bank. Options for funding a wind project are expanding, and there are examples of

community-financed projects in which community members own the project or team with

larger corporations to fund a wind project. In the latter case, known as the “flip” model, a

corporation owns the wind project for the first 10 years while realizing tax incentives and

then “flips” ownership to the local community. There are many options for funding wind

generation. For this study, whether the project is financed in state and by what amount

are important elements. We assumed that none of the financing for new power generation

would be from within the states, based on interviews with Colorado lenders. Researchers

may choose to use this methodology with the flip model or other community financing

options and learn how in-state benefits are increased.

Operations and Maintenance

O&M spending from a new power plant includes unscheduled but routine maintenance,

preventive maintenance, and costs of scheduled major overhauls. Some O&M estimates

also include property tax and landowner payments, but this study separately examines

those and does not incorporate them under this heading. O&M spending was difficult to

determine for natural gas, whereas the energy community agreed on coal and wind O&M

spending. Dollars spent for natural gas O&M ranged from $7.6/kW to $20/kW. We used

$10-$14, depending on state data, for our average because it is from actual recent power

plant figures (BaseCase). We used actual data from new power plants whenever possible

and spoke with representatives from each energy generation source to determine the

breakdown between parts and labor. In most cases, industry employees agreed that labor

(not materials) is the much larger component of O&M costs (between 70% and 99%).

One developer said labor might only comprise 60%, but most agreed it was a higher

percentage. Variations are reflected in sensitivity analyses.

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Fuel Extraction and Transport

This study includes the extraction of gas and coal from the well or mine and the transport

by pipeline or railroad to the utility’s power plant. We spoke with representatives from

the railroads and pipeline industries to obtain breakdowns of fuel costs (extraction vs.

transport and labor vs. parts). Breakdowns for coal vary greatly. For example, if the coal

is from Colorado, most of the direct dollar outflow for transport will also be by Colorado

laborers, and this makes a significant difference in the results. In Michigan, none of the

coal is from Michigan coal mines, but a large coal transport industry (rail and ship) is

based in Michigan; thus some of the direct expenditures for transporting the imported

coal will benefit Michigan’s economy.

Using this scope of work, wind power has no economic benefits in the category of fuel

extraction because the wind is free. Of course, having zero fuel costs could be viewed as

a cost advantage for utilities and their customers, but this study considers the state

economy’s overall impact from new power generation, not utility or customer costs or

prices.

Landowner Revenue

In this study, landowner revenues for power generation apply only to wind power

development. Studies show that the most common way for utilities to add wind to their

resource portfolios is to purchase generation from private companies instead of owning

and operating wind farms (Wiser and Kahn 1996, p.1). This means that the electric output

from a privately owned wind farm, such as the wind farm in Lamar, Colorado, is sold to

investor-owned utilities (IOUs) under long-term contracts. The company that owns the

wind farm usually leases land for its turbines from rural landowners, who are typically

farmers or ranchers. Wind developments are sited in rural areas for various reasons,

including wind speeds and site selection processes. Annual payments range from $1,500

to $6,000 per wind turbine per year, depending on individual contracts and size of

turbines.

9

Land leases can be structured in several ways. The most common in the wind

industry is to base lease payments on a percentage of gross revenue from wind power

production. Normally, a guaranteed minimum annual payment is included in a lease to

cover periods in which the project may be inoperable (National Wind Coordinating

Committee). Some landowners choose to accept payments per turbine instead of

payments based on gross revenue so that they are assured a set income.

It is possible for a utility to own the entire wind project and make payments to farmers

directly or even to buy the land outright. In another situation, an outside company, either

a utility or non-utility, could purchase land for wind turbines up front and therefore not be

required to make land payments to landowners after the initial payment. These cases are

unlikely but possible.

9

Net landowner revenues: landowners must calculate their cost of lost productivity and subtract it from

their income per turbine. Ranchers are usually not affected because animals can graze among installed

turbines. A Pacific Northwest study shows that farmers gain approximately 85% of their gross revenue

when land loss is figured in.

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For coal and gas plants, power plant owners usually purchase their land and include this

under their construction costs. Much less land is needed for a coal or gas plant than for a

wind farm, considering different technologies and the 25% to 35% assumed capacity

factor for wind compared to much higher capacity factors for fossil-fuel generation.

10

The

larger amount of land required for wind projects benefits rural landowners in the form of

landowner payments. Although wind plants need access to large land areas, they only use

a small fraction for roads, turbine foundations, and electric equipment. More than 90% of

the land used for a wind farm can still be used for crops or grazing.

Property Taxes

As mentioned, wind power requires much more land than either a natural gas or a coal

plant. More than 400 1.5-MW turbines are required to produce the energy equivalent to a

270-MW natural gas plant with a capacity factor of 87%. Utilities and plant owners may

be exempt from property taxes depending on contract negotiations or state incentives.

However, if taxes were collected, tax revenue would be greater from a wind plant than

from a fossil fuel plant due to the increased size of the project.

11

In Colorado, property taxes are paid to counties, and all county property taxes are

assessed by the State Office of Taxation (the State). The State bases assessments on the

value of the utility’s or plant owner’s “business valuation,” or the sum of real property,

personal property, tangible assets, and intangible assets.

12

The State then takes 29% of

the business valuation to be the assessed value of the company. The assessed value is

communicated to each company and county, and property taxes owed to the county are

based on power plant location. For example, if Xcel Energy Corporation were to build a

coal plant in Pueblo County, Colorado, they would negotiate tax rates with Pueblo

County assessors. Counties determine the amount of property taxes based on mill levies,

which are specific to each county but are usually higher in rural areas.

13

Annual county

mill levies range from 3% (La Plata County) to 9.9% (Phillips County).

14

For this

research, we assume 7% in Colorado. Because of the popularity of granting coal and gas

plants exemptions from property tax in Colorado, this study assumes that the coal and gas

plants will pay property taxes all 20 years, but during the first 10 years, they will only be

subject to half of the property tax.

Tax exemption is often automatic for municipally owned utility plants. Tax exemption

can play an important role in new power plant development for investor-owned or

10

Much less land is needed for the actual power generation. However, land impacts are greater when the

entire life cycle of the resource is considered. For example, coal mining sites, including roads and disposal

sites, were not included in the scope of this research.

11

In some states, wind energy projects are exempt from property taxes resulting from increased property

value because of wind plant development (NWCC Wind Energy Series).

12

It is common for utilities to operate in more than one state. In such cases, the Colorado Office of

Taxation assesses companies based on total historic cost (depreciation rate plus net book value of assets)

per county. According to Deb Meyer, State Division of Property Taxation, intangible assets could be for

items like franchising or the worth of a brand name.

13

Mill levies are a specified rate: 1 mill equals 1/10 of a cent ($0.001) per $1 of property value used to

determine the tax or assessment on property. Mill levy taxes are used for things like school districts and

road improvements.

14

Colorado tax information is based on conversations with Mark Walker of the State Office of Taxation.

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privately owned utilities. Non-municipally-owned power plants may be exempt from

property taxes unless they have non-operating properties, such as land that they do not

use. Tax exemption is a great advantage to power plant owners. The utility will often

negotiate a deal for tax exemption or partial tax exemption with counties in which they

locate a power plant.

For example, in Colorado, agreements between Xcel Energy and the City and County of

Pueblo state that, if Xcel builds a power plant there, the company would be forgiven 50%

of the total in property taxes over the next 10 years. The City also agreed to forgive sales-

and-use tax on the construction of the plant in return for a one-time $13 million payment,

which may be used to construct a new building for Pueblo police (Amos 2004). Cities

and counties negotiate deals like this because new plant construction and operations bring

new jobs to the area. However, as results show, much of the construction and operations

labor is brought in from out-of-state. For example, in-state coal plant construction labor

accounts for less than 20% of total labor.

In Michigan, the assessed value, or “State Equalized Value,” is equal to one-half of the

total value for real and personal property. The state’s average tax level applied to the

assessed value is 5% for annual property taxes. Air and water pollution control equipment

on power plants is exempt from property taxes.

Wind plants in Michigan will not be required to pay property taxes until the year 2013.

According to the Michigan Economic Development Corporation, “Alternative-Energy

Personal Property” … is exempt from the collection of personal property taxes. This

exemption includes (1) “Alternative-Energy Systems,” (2) “Alternative-Energy

Vehicles,” (3) the personal property of an “Alternative-Energy Technology Business,”

and (4) the personal property of a business not engaged in alternative-energy technology

that is used solely for the purpose of researching, developing, or manufacturing

“Alternative Energy Technology.” However, it is common for a community to negotiate

“host fees” in lieu of property taxes from $3,000 - $5,000 per turbine per year. After

discussions with a Michigan wind developer about recent projects, we have assumed a

$5,000/turbine/year payment for this study.

In Arizona, the assessed value of a plant is 25% of 80% of the installed project cost. Then

mill levies are applied to this number to determine county property taxes. The average,

and the assumed number for this report, is 7.6%.

Because of specifics of individual project negotiations, taxes for the average new power

plant are difficult to predict accurately. As stated, it is fair to assume that a utility-owned

plant will likely be partially tax exempt in Colorado, but a privately owned power plant

will be required to pay county property tax (Wiser and Kahn 1996). In Michigan, we

safely assume that wind projects will not pay property taxes until 2013. For this project,

we took examples of current power plant tax estimates and average tax payments from

existing plants and applied them to the appropriate size of the new plant. For wind, we

used existing plant data in Colorado and estimates in Arizona, and we based Michigan

assumptions from the Michigan Public Service Capacity Needs Forum.

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Taxes paid on gas wells and for coal mines will not likely increase when 280 to 300 MW

of generation are added to the state’s system mix. New gas wells and coal mines are not

required for this amount of electricity production, so taxes on these items were not

included in this study. If all the coal or gas came from within the state and resulting

extraction efforts were larger, or if the plant were of larger capacity, it is conceivable that

the associated increases in well or mine taxes should be considered.

Sales Tax

We did not separate sales tax in this report. We assume that sales tax is included in the

dollar amount of parts, such as the wind turbine shaft, or of processes, such as the natural

gas plant construction. To calculate sales tax, a researcher would have to obtain

information about which parts of the power plants, fuel extraction, and fuel transport

come from within the state or come from a company with an office within the state so

that the company may charge sales tax. For example, if wind turbine blades were

manufactured in South America or Denmark, but the manufacturing company had an

office in Arizona, the wind farm owner would be required to pay Arizona state sales taxes

for the wind turbine blade. If the Danish company had an office in Wyoming instead of

Arizona, no sales tax would be paid to Arizona. Most companies do not make any of this

sales tax information available. However, future studies may include estimated sales tax

based on state-specific models. For example, Colorado sales tax is 2.9%, and this could

be added (or broken out from existing dollar amounts) to parts purchased in Colorado,

depending on whether the sales tax is assumed to be included.

Discount Rate

For purposes of this research, results are displayed without a discount rate applied.

However, discount rates of 5% and 7% were applied to some results, and direct spending

can easily be calculated with a discount rate of the researcher’s choice. In the Results

section of this report, we show direct impacts without the discount rate, except when

specifically noted. This is due to the wide range of discount rates used by government,

policy makers, and industry.

State Specifics

The Components section of this report above has detailed each area of dollar flow,

including some state specific information (see Property Taxes). The Assumptions section

explains general suppositions for the paper. Some areas of inquiry require individual

explanation for each state’s energy background and attributes, which are in this section.

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Arizona

In Arizona, most of the state’s power comes from imported coal. (Coconino County,

Arizona, has some coal mines, but they supply an electricity generation facility in

Nevada). Coal for a new coal plant would likely come from Wyoming or New Mexico

(Tri-State Generation and Transmission Association, Inc.). The new plant is assumed to

be a sub-critical plant, based on the most recent Arizona coal plant proposals

(Springerville). The coal plant’s capacity factor is assumed to be 85%.

Figure 3. Arizona’s coal-producing area. Source: EIA, 1999

Arizona's Electricity Mix

34%

46%

0%

10%

10%

0%

Nuclear

Coal

Oil

Gas

Hydro

Other renewable

Source: Energy Information Administration, 2000

Figure 4. Arizona’s electricity mix. Source: EIA, 2000

Arizona also imports its natural gas (see the Assumptions section for further aspects and

complications on natural gas). The capacity factor for wind in Arizona is assumed to be

30% for this research, so the wind plant would require 520 1.5-MW turbines to equal 780

MW and generate the necessary amount of electricity.

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Colorado

In Colorado, the coal plant is assumed to be a super-critical plant based on the most

recent proposed coal plant in Colorado (Xcel Energy’s Comanche III coal plant in

Pueblo). Coal will most likely be transported by rail from the Powder River Basin in

Wyoming. The coal plant’s capacity factor is assumed to be 85%.

Colorado has natural gas fields, and this study assumes that 40% of the natural gas for the

new plant comes from within the state’s boarders. Colorado has a considerable wind

resource, as shown by the pink and purple areas (Figure 5).

Figure 5. Colorado’s wind resource at 50 meters. Source: NREL, 2004

Colorado's Electricity Mix

0%

81%

0%

15%

3%

1%

Nuclear

Coal

Oil

Gas

Hydro

Other renewables

Figure 6. Colorado’s electricity mix. Source: EIA, 2000

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Michigan

Like Colorado, Michigan’s power mix relies heavily on coal, with a small amount of

natural gas and almost no wind power. Michigan also imports coal to feed its power

plants.

Michigan does have some natural gas extraction fields, so we assume that 25% of

natural gas used in Michigan comes from Michigan. The multiple in-state pipeline,

railroad, and shipping companies provide direct benefits to the economy. For example, if

the coal is transported from Wyoming, some of the labor and materials for the railroad

cars are from outside Michigan. For the base cases in this study, we assume that 50% of

the natural gas transport labor is based in-state and 60% of the coal transport labor is

based in Michigan. These current estimates are from a report for the Michigan Public

Service Company (VanderVeen 2005).

Figure 7. Michigan’s gas and oil production fields. Source: Michigan Economic

Development Corporation, 2000

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Michigan's Electricity Mix

18%

67%

1%

12%

2%

Nuclear

Coal

Oil

Gas

Renewables

Figure 8. Michigan’s electricity mix. Source: EIA, 2000

Assumptions

Assumptions for this study are based on scenarios that are most probable for building

new energy-generation capacity. It is assumed that energy efficiency and demand-side

management options have been considered earlier in the decision-making process. In this

case, new energy generation is utility-scale and grid connected.

The new wind, coal, or gas power plant would produce approximately 2,000,000 MWh

per year for 20 years, and construction would begin in 2005. Power would be generated

in each state for its ratepayers. We used the most recently proposed coal, gas, and wind

projects in each state to determine our assumptions.

The natural gas plant is assumed to be a baseload combined-cycle plant. It is very

difficult to determine the exact wellhead in a power plant from which natural gas stems

from (Figure 9). Natural gas flows through pipelines and is mixed with gas from many

sources before it arrives at the plant. Interviews with 15 energy analysts and natural gas

industry employees in and around Colorado provided answers that ranged from “most of

our gas is from Wyoming” (Mercatur Energy

) to “80% of the gas should be from

Colorado if the plant is far enough from Colorado’s borders” (Colorado Oil and Gas

Commission). For this study, we assume that none of the gas used in the new power plant

would be from Arizona, 40% of gas is extracted from Colorado’s natural gas wells, and

25% of Michigan’s gas will be from Michigan.

We also assume that the new gas plant would have a capacity factor of 87%. This is

consistent with new efficient gas plants that are currently under construction.

15

However,

at the present (May 2005) high fuel price, some companies choose to only run their gas

peaking plants – not baseload (these plants are too expensive to utilize for electricity

15

Energy Information Administration’s maximum capacity credit assumption. Xcel Energy’s combined-

cycle gas plant in Fort Lupton, Colorado, was rated 86.5% in 2002.

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because of the high gas prices). A report for the Michigan Public Service Commission

assumes that natural gas has a capacity factor of merely 35% due to the heightened fuel

prices (VanderVeen 2005). In this study, we assume that the price of natural gas will

continue to fluctuate but will also be used as a baseload plant when costs for other

generation (e.g., pulverized coal) and construction (steel, etc.) also increase in the future.

One example of the market fluctuation is EIA data, which show that coal prices are also

rising in each region of the country. These rising prices are for spot markets, not long-

term fixed contracts, but they show the upward trend in prices nonetheless. The

methodology for this report can be used with the assumption that resources have a much

lower capacity factor, if required.

We assume that the gas project financing would come from the utility’s regular financial

lending institution (usually a large national or international bank not located within the

state).

Figure 9. Natural gas transmission line capacities. Source: EIA, 2000

Making assumptions about natural gas prices today and for the next 20 years is risky and

will inevitably be somewhat inaccurate. (See Figure 11 for obvious price shifts.)

However, we use the EIA’s assumptions and include high and low scenarios above and

below those predictions. Since the Colorado report (2003 data) (Tegen 2004), prices for

natural gas have continued to rise. The assumptions for natural gas base case prices in

this study range from $35/MWh to $55/MWh, or $5.2/MMBtu to $7.9/MMBtu, to

incorporate a range of prices. Assumed prices are based on data from actual natural gas

plants in each state. Utilities running natural gas plants have long-term contracts for

baseload natural gas, so they are not as vulnerable to spot market fluctuations.

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Figure 10. Average weekly coal spot prices ($/ ton) from May 2002 through April 2005.

Source: EIA

We assume that the capacity factor for wind power will be 30% in Arizona, 35% for the

wind farm installed in Colorado (Milligan, personal communication), and 25% in

Michigan (VanderVeen 2005). We also assume that the landowner revenue paid to a

landowner is a direct benefit to the state’s economy. This study does not try to determine

the next step for dollars brought into the economies by using a multiplier or other

calculations.

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Figure 11. U.S. natural gas spot prices from 2000 to 2006 in $/ thousand cubic feet.

Source: EIA

Results

The results show that benefits to the three state economies from energy resources vary

greatly, depending on specifics of each power plant project and its contracts. For fossil-

fuel-fired power, dollars spent on fuel are a significant benefit

if

the fuel is produced in

state or transported by in-state industry and workers, or both. As expected, results show

that states are positively impacted by new power generation when local labor is used to

install equipment and operate the new energy-generating facility.

Results in all three states show that adding wind facilities will provide a greater economic

benefit to the state economy, due in large part to payments for property taxes. Wind pays

a proportionally larger share in property taxes because more facilities must be erected to

generate equivalent power. Below are state-specific results. Some notable differences are:

•

Prices for fossil fuels are assumed to be higher in Michigan than in the other

states, and capacity factors are lower. This leads to an increase in overall capacity

needed and in dollars spent in Michigan.

•

Based on actual data for proposed new plants, installed cost for a coal plant is

much higher in Arizona ($2000/kW) than in Colorado ($1450/kW), which makes

a considerable difference. Coal benefits Arizona’s economy more than

Colorado’s. This could be due to varying pressures for new environmental

equipment or state policies.

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•

Even though a state may not have natural resources to generate electricity, if it has

a large resource (coal or gas) transportation industry, like Michigan, the economy

can benefit significantly from the imported resource.

Figure 12. Base case scenarios of economic impact from new power plants in Arizona,

Colorado, and Michigan

Direct impacts to state economies from

base case scenarios

$-

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

$700,000,000

$800,000,000

$900,000,000

$1,000,000,000

Arizona

Colorado

Michigan

Coal

Gas

Wind

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Individual State Results

Figure 13. Dollars spent on new electricity generation from coal, gas, and wind in Arizona

Note: The fuel components for coal and natural gas are prices paid by the power plant for fuel.

The contract price listed for wind is the amount the plant owner can charge for the output of the

wind farm and is used to calculate landowner revenue.

Figure 14. Dollars spent on new electricity generation from coal, gas, and wind in Colorado

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Figure 15. Dollars spent on new electricity generation from coal, gas, and wind in Michigan

Colorado Results and Specific Sensitivities

As Figure 14 and Table 2 indicate, the average wind plant would bring more dollars to

the Colorado economy than coal or gas plants, provided that the wind plant hires some in-

state labor and uses some Colorado materials (e.g., concrete). This result is partially due

to the large percentage of in-state workers (20%-46%) for construction, the even larger

percentage of workers during the operations phase (90% in state), and the size of the

project (680 MW versus 270 MW or 280 MW). A large part of the wind spending is also

due to county property taxes. In other states, wind plant owners have negotiated partial

exemptions from taxes, but this has not occurred in Colorado. However, coal and gas

plants have historically been at least partially exempt from property taxes.

Table 2. Dollars Spent in Colorado from 270 MW New Energy Output over 20 Years

Coal

Gas

Wind

Construction

$47,705,000

$24,458,963

$91,392,000

O&M

$90,125,000

$11,054,118 $223,040,000

Fuel

$8,756,496

$210,442,575 $

-

Landowner

Revenue

$

-

$

-

$43,500,000

Taxes

$17,271,121

$8,406,060 $193,228,800

* Construction times vary for each resource: coal 5 years, gas 2 years, wind 1 year

When in-state versus out-of-state spending is calculated, it becomes apparent that a new

gas plant would produce more total spending but that most of the money would be sent

out of state. Each generating source spends more out of state than in Colorado, regardless

of the fuel source or tax negotiation. Figure 16 shows in-state and out-of-state spending

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for new power generation. As previously noted, this project does not examine price

impacts to consumers but considers overall state economies. Clearly, if consumers have

to spend more of their income on electricity, they will have less to spend on other goods

and services. When making an informed decision about new power generation, a

policymaker should include consumer pricing and other issues, along with information

from studies like this one.

Direct impacts from new electricity generation in Colorado

a comparison of instate vs. out-of-state money flow s

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

Coal

Gas

Wind

D

o

llar

s

(

m

ill

io

n

s

)

Total instate

Out-of-state

Figure 16. Colorado vs. out-of-state impacts from new electricity generation

The following series of figures and tables show individual energy-generation resources

broken down by component for the Colorado economy. In a forthcoming publication,

these figures will be presented for Arizona and Michigan and will be located in

assumptions sections specific to each state. The figures show direct economic benefits to

the economy from each resource, given the most likely scenario. I-shaped bars represent

uncertainty ranges in the data. Further explanation of sensitivity analyses for particular

energy resources may be found in Sensitivity Scenarios.

Table 3 and Figure 17 show direct economic benefits to Colorado for a coal plant with

sensitivity bars. The biggest range of uncertainty is caused from the plant using Colorado

coal, which is unlikely.

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Table 3. Direct Economic Benefits from New Coal Generation

COAL

Range

% CO* %CO range

Construction labor 25%

$1,450/kW

$1300 -$1800/kW

17%

7%-37%

Construction materials 75%

$1,450/kW

$1300 -$1800/kW

5%

0%-15%

O&M labor 65%-75%

$25/kW

$8 - $27/kW

65%

25%-95%

O&M materials 25%-35%

$25/kW

$8 - $27/kW

63%

60%-93%

Fuel

$14/MWh

$13 - $18/MWh

0%

0%-56%

Mining

40% of fuel

40% - 50%

0%

0%-56%

Railroad

60% of fuel

50% - 60%

10%

0%-10%

*Money spent in Colorado

Direct impact to Colorado economy from a

new coal plant (with sensitivity bars)

-

50,000,000

100,000,000

150,000,000

200,000,000

250,000,000

C

o

n

s

tr

uc

tion

O

&M

F

ue

l

T

a

xe

s

dollars

Figure 17. Direct impact to Colorado economy from a new coal plant, with uncertainty bars

As shown in Tables 4 and 5 and Figures 17 and 18, coal and gas have high uncertainty in

their fuel categories. Almost all of the uncertainty for natural gas is related to gas price

estimates. The price range is from $30/MWh to $55/MWh. Prices as high as the top

scenario ($55/MWh) are unlikely but possible in Colorado power plants’ long-term

contracts. Coal’s uncertainty bar has such a large range because of the chance that 100%

of the coal may come from Colorado, as opposed to the assumed 0%.

Table 4. Direct Economic Benefits from New Natural Gas Generation

GAS

Range

% CO* Range % CO

Construction labor 25%

$595/kW

$550-$800/kW

40%

15%-60%

Construction materials 75%

$595/kW

$550-$800/kW

5%

0%-10%

O&M labor 75%

$10/kW

$8-$19/kW

25%

16%-45%

O&M materials 25%

$10/kW

$8-$19/kW

5%

10%-45%

Fuel

$35/MWh

$30-$55/MWh

40%

10%-66%

Extraction

80% of fuel

-

15%

5%-20%

Pipeline

20% of fuel

-

0%

0%-10%

*Money spent in Colorado

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$-

$50,000,000

$100,000,000

$150,000,000

$200,000,000

$250,000,000

$300,000,000

$350,000,000

C

o

n

s

tr

uc

ti

o

n

O

&

M

Fuel

T

a

x

es

Figure 18. Spending in Colorado for a new natural gas plant, with uncertainty bars

Table 5. Direct Economic Benefits from New Wind Generation (635 1.5-MW turbines)

Wind

Range

% CO* Range % CO

Construction labor 10%

$1,200/kW

$1100-$1500

40% 20%-46%

Construction materials 90%

$1,200/kW

$1100-$1500

8%

6%-10%

O&M labor 70%

$20/kW

$10-$27/kW

90% 80%-99%

O&M materials 30%

$20/kW

$10-$27/kW

20%

5%-33%

Landowner revenue

3.5% of revenue $3000-$5,000

100%

-

Property taxes

1.2% of project

0.9% - 3%

100%

-

*Money spent in Colorado

$-

$100,000,000

$200,000,000

$300,000,000

$400,000,000

$500,000,000

$600,000,000

Construction

O&M

Land payments

Taxes

Figure 19. Spending in Colorado for a new wind power plant, with uncertainty bars

Table 5 and Figure 19 show direct economic impacts for building new wind power. For

wind, the component with the most uncertainty is taxes. Typically, taxes are assumed to

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be between 0.9% and 3% of total installed costs. The large range in dollars per kilowatt

for construction between $1100 and $1500, along with the property tax percentage, leads

to the sizable range in construction results. O&M is considered by some developers to be

60% labor and 40% parts, while most consider that the labor accounts for between 70%-

80%. Landowner revenue can fluctuate between $3,000 and $5,000 per turbine per year

(based on the assumed 1.5-MW turbine size).

The data show significant differences and implications between wind and fossil fuels in

the category of property taxes in all states. Coal and gas plants owned by utilities are

often but not always exempt from property taxes in Colorado, and the utility might

negotiate a deal with local communities by paying for county improvements such as a

library, school, or police station. Such negotiated costs cannot be captured in a study of

average power plant benefits because they are unique to each deal made between the

utility and county. It should be noted that these negotiated donations from utilities would

also benefit communities and, therefore, the Colorado economy. The County presumably

finds the short-term gain of the payment, in addition to jobs created by the new power

plant, worth the exchange for property taxes. However, the utility makes a one-time

payment to the county, whereas property taxes would be collected over the lifetime of a

power plant.

In addition to the consideration of tax exemption, wind plants purchase or lease a

considerably larger piece of property for the same energy output as gas and coal. The

State of Colorado does not base property taxes on the actual amount of space utilized by

wind turbines but by the value of the installed turbines. The installed turbine value is

greater than the value of a gas or coal plant because so many wind turbines are needed to

generate the same amount of electricity. This is significant in rural communities because

the county divides tax revenues to pay for services such as schools and roads. Wind

plants also cause an increase in a landowner’s property values.

Sensitivity Analyses

Following is an exploration of some uncertainty scenarios or sensitivity analyses

discussed above. In the most likely scenario, coal for a new Colorado coal plant will

come from Wyoming. Figure 20 shows a scenario in which all of the coal comes from

Colorado. With everything else remaining equal, coal will not bring as much spending to

Colorado as wind (but more than gas), and spending will be significantly higher than it is

with out-of-state coal.

As mentioned, another uncertainty is the origin of Colorado’s natural gas plants. At the

highest, according to most natural gas experts we spoke with, 66% of the natural gas will

come from Colorado. With everything else remaining in the base case, here are the results

for a higher percentage of gas from within the state.

We mentioned the differences between results without an applied discount rate and a

discount rate of 5% or 7%. In Figures 22 and 23 below, we see the results for Colorado

coal. In forthcoming versions of this paper, we will display other components and

resources with applied discount rates. When a discount rate is applied, the impacts are

naturally smaller.

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Direct impacts to the Colorado economy from new coal,

gas and wind plants (100% Colorado coal)

$-

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

Coal

Gas

Wind

D

o

ll

a

r

s in

m

i

lli

o

n

s

Taxes

Landowner revenue

Fuel

O&M

Construction

Figure 20. Sensitivity scenario: 100% of coal is from Colorado mines

Direct impacts to the Colorado economy from new coal,

gas and wind plants (2/3 of gas from Colorado)

$-

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

Coal

Gas

Wind

D

o

l

l

a

r

s

in

m

ill

io

n

s

Taxes

Landowner revenue

Fuel

O&M

Construction

Figure 21. Sensitivity scenario: 66% of natural gas is from Colorado

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Total coal costs for a new Colorado coal plant

with and without a discount rate of 5%

$0

$200,000,000

$400,000,000

$600,000,000

$800,000,000

$1,000,000,000

$1,200,000,000

$1,400,000,000

Total

NPV

Property taxes

Fuel

Financing

O&M

Construction

Figure 22. Total impacts (in and out-of-state) for a new Colorado coal plant, with and

without a discount rate of 5%

Note that construction and financing in both cases remain relatively unchanged because

construction occurs within the first 5 years, and we assume 10 years for financing.

Total costs from a new Colorado coal plant with

and without a 7% discount rate applied

$0

$200,000,000

$400,000,000

$600,000,000

$800,000,000

$1,000,000,000

$1,200,000,000

$1,400,000,000

Total

NPV

Property taxes

Fuel

Financing

O&M

Construction

Figure 23. Total impacts (in-state and out-of-state) for a new Colorado coal plant, with and

without a discount rate of 7%

Lessons Learned

When conducting a “follow the money” study in other regions, it will be helpful to draw

on lessons from this report to save time and frustration for researchers and interviewees.

Methods detailed here are transferable to other projects that explore economic questions

about which energy resource to build next.

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As with any research project, the first step is to define the required data and obtain

contacts for that information. Local data are almost always preferred, but when it is not

available, national averages may be sufficient. For example, is it important to have

precise railroad data for your state, or can you use national averages? We carefully chose

components of this research and selected the most economically significant benefits to

represent graphically. Unfortunately, many developers consider this type of information

proprietary due to competitive forces in the marketplace. Many costs and benefits of

electricity generation are proprietary and cannot be released. Some dollar values for this

project were indeed confidential and were given to us with the understanding that we

would use aggregate numbers and not mention sources.

Information for labor and equipment costs was obtained through much deliberation from

key industry contacts. In addition, we used JEDI (Goldberg et al. 2004), which was

especially helpful for cost breakdowns. For overall costs of fuel and O&M, we referred to

power plant operating companies and BaseCase. For specific numbers, such as the labor

component of natural gas transport, we spoke with industry representatives (e.g., natural

gas pipeline manufacturers). We obtained manufacturer names by speaking with people

at existing utility power plants. We did not add environmental or political costs and

benefits, which would be much harder to quantify than direct economic benefits. We

recommend including only operations and maintenance costs – not including “all-in,” or

costs such as taxes or landowner revenues, which should be broken out separately.

To obtain financing information, we initially contacted utility employees, who were

generally unable to answer our requests. Eventually, we learned from other energy

experts that financing for all three power sources is most likely an out-of-state impact,

with no money flowing into the Colorado economy. Some small wind projects may be

financed in-state, but usually financing comes from out of state, unless the plants in

question were in New York or Massachusetts, where large lending institutions are

located. We recommend contacting in-state independent banking associations. These

organizations may know about power plant financing. Additionally, municipalities and

electricity cooperatives might have helpful information and/or contacts. See the

Components section of this report for other financing options.

Tax information should be sought first from counties, which is where most property tax is

collected. Obtain mill levies and the procedure by which property taxes are assessed. If

county taxes are assessed by the State, researchers will likely need to combine

information from state assessors with details from county assessors and treasurers. The

Public Utilities Commissions, in this case, did not provide data for any categories

analyzed by this project, but we do recommend interviewing them in case they are able

and willing to help. Researchers working with the Public Service Commission in

Michigan, for example, were extremely helpful.

It is important to remain “resource neutral” when interviewing so that all parties feel

comfortable providing information. It is also crucial to state assumptions early, so that

they are clear in the project results. More important, stating assumptions early will ensure

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that they are clear to researchers throughout the project. Project boundaries and scope are

closely linked to assumptions.

Conclusion

The addition of a new generating facility equivalent to a 270-MW natural gas plant will

have direct economic benefits for a state’s economy. If the fuel of choice is coal or gas,

impacts to the economy may be fewer from coal or gas than if the fuel is wind. But

natural gas also has a significant impact to the economy if a portion of the natural gas

comes from within the state and is transported by state industry. If a big portion of the

labor for coal extraction or coal transportation comes from within the state, then coal will

bring significant spending to the state (however, according to our assumptions, not as

much as wind power would bring for the equivalent amount of energy produced).

Energy planners and the energy industry should consider studies like this when deciding

where to site a power plant and which benefits can be offered to local communities from

the addition of a new power plant. This information is also valuable in making state- or

regional-level policy decisions about energy resources and state-sponsored incentives,

such as renewable portfolio standards or energy incentives.

Additional research is needed on this topic, especially on county and state taxes and on

project financing. It is likely that tax impacts are so specific to each case that they will

have to be evaluated on a case-by-case basis. This study did not include externalities such

as air pollution, effects to the local environment, or payments to the state for black lung

disease. Another study might include such costs. Future work might also address the

difference in consumer rate impacts associated with different plants.

Acknowledgments

This work was funded by the U.S. Department of Energy’s Wind Powering America

program. An earlier version of this paper’s results was displayed in a poster session at the

Global WINDPOWER 2004 Conference in Chicago, Illinois. The author wishes to thank

the energy experts, developers, analysts, power plant owners and operators, railroad

administrators, and the county and state government officials who provided information.

Additionally, this work would not have been possible without generous help from

Michael Milligan of NREL, Brian Parsons of NREL, Marshall Goldberg, Steve Clemmer,

Rich VanderVeen, Kerry Battel, Peter Curtiss, Ron Lehr, John Nielson, Randy Udall,

Dale Osborn, Craig Cox, and Paul Komor. Finally, the author thanks Larry Flowers of

NREL for his support of this work.

28

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References

Amos, J. “Xcel Tax Credits Total $33 Million.”

The Pueblo Chieftain.

Pueblo, Colorado,

February 19, 2004.

Clemmer, S. (2001).

Strong Winds: Opportunities for Rural Economic Development

Blow Across Nebraska.

Cambridge, MA: Union of Concerned Scientists, February 2001.

Costanti, M. (2004).

Quantifying the Economic Development Impacts of Wind Power in

Six Rural Montana Counties Using NREL’s JEDI Model.

NREL/SR-500-36414. Golden,

CO: National Renewable Energy Laboratory.

Goldberg, M.; Sinclair, K; Milligan, M. (March 2004.) “Job and Economic Development

Impact (JEDI) Model: A User-Friendly tool to Calculate Economic Impacts from Wind

Projects.” Prepared for Global WINDPOWER 2004, March 28-31, 2004. NREL/CP-500-

35953. Golden, CO: National Renewable Energy Laboratory, 12 pp.

Kaas Pollock, L.; Gagliano, T.

Tax and Landowner Revenue from Wind Projects

.

Legisbrief Vol. 12, No. 5, Denver, CO: National Conference on State Legislatures.

January 2004.

Madsen, T.; Bonin, S.; Baker, M. (2002).

Wind Energy: Powering Economic

Development for Colorado

. Denver, Colorado: Colorado Public Interest Research

Foundation, November 2002

.

National Wind Coordinating Committee. (1997).

The Effect of Wind Energy Development

on State and Local Economies

, Wind Energy Series No. 5, accessed April 13, 2006 at

www.nationalwind.org/publications/wes/wes05.htm

Regional Economics Applications Laboratory.

Job Jolt: The Economic Impacts of

Repowering the Midwest: The Clean Energy Development Plan for the Heartland

.

Chicago, IL: Environmental Law and Policy Center, 2001. Accessed April 13, 2006 at

www.repowermidwest.org/Job%20Jolt/JJfinal.pdf

Tegen, S. (May 2004). “A Comparison of Statewide Economic Impacts of New

Generation from Wind, Coal, and Natural Gas in Colorado.” Prepared for the American

Wind Energy Association’s WINDPOWER Conference, May 2004. NREL/CP-500-

38154. Golden, CO: National Renewable Energy Laboratory, 34 pp.

VanderVeen, R.F.

Michigan Economic Impacts of Wind Energy Compared with Coal and

Natural Gas.

For the Michigan Public Service Commission. April 2005.

“Wind Energy Creates Jobs, Power in East Kern.”

Land and Progress,

Fall 1995.

29

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Wiser, R.; Kahn, E. (1996).

Alternative Windpower Ownership Structures: Financing

Terms and Project Costs

. LBNL-38921.

Berkeley, California: Lawrence Berkeley

National Laboratory.

30

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Bibliography

Acker, T.L.; Williams, S.N.; Duque, E.P.N. (September 2004). “Evaluating the Most

Promising Sites for Wind Energy Development in Arizona USA.” Prepared for the 8

th

World Renewable Energy Congress, September 2004. Working Paper Series 05-09.

Flagstaff, AZ: Northern Arizona University, 5 pp.

Bird, L.; Parsons, B.; Gagliano, T.; Brown, M.; Wiser, R., Bolinger, M. (2003).

Policies

and Market Factors Driving Wind Power Development in the United States.

NREL/TP-

620-34599. Golden, CO: National Renewable Energy Laboratory.

Boschee, Pam (ed.)

As the pendulum swings: Riding high on the boom – Operating

performance 2001-2002

. Industry report for Energy Ventures Analysis, Inc. November

2002, pp. 21-225.

Colorado Tax Law from the Colorado Constitution “Uniform Taxation and Exemption,”

Article X, Section 3 (1B).

http://i2i.org/Publications/ColoradoConstitution/cnart10.htm#Section%203

Darmstadter, J.

Productivity Change in U.S. Coal Mining.

www.rff.org/Documents/RFF-DP-97-40.pdf

. Washington, DC: Resources for the Future,

July 1997.

Energy Information Agency. Electric Power Annual 2000, Volume 1.

www.eia.doe.gov/cneaf/electricity/epav1/epav1_sum.html

Jacobsen, M.Z.; Masters, G.M. “Exploiting Wind Versus Coal.”

Science

, Vol. 293,

August 2001; p.1438.

Laitner, S; Goldberg, M.

Colorado’s Energy Future: Energy Efficiency and Renewable

Energy Technologies as an Economic Development Strategy.

A report for the U.S.

Department of Energy, Denver Support Office and Golden Field Office. Golden, CO.

April 1996.

Northwest Economics Associates.

Assessing the Economic Development Impacts of Wind

Power Final Report.

For National Wind Coordinating Committee, February 2003.

31

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Personal Communication

Some personal communication for this research is considered confidential.

Agencies,

companies, and organizations allowed the author to use their data in aggregate only. In

some cases, the author is able to list company or organization names, but not employee

names. Personal communication for this project included data and advice from the

following:

Andy Wyatt, Prowers County Assessor

Aquila Networks

Basin Electric Power Cooperative

Boulder County Treasurer’s Office

Colorado Mining Association

Colorado Oil and Gas Commission

Colorado Rural Electric Association

Craig Cox

Dale Osborn, DISGEN Systems

Energy Intelligence Group, Inc. for pipeline capacity information

EnXco, Inc.

La Plata County Assessor’s and Treasurer’s Offices

Mark Walker, State Division of Taxation

Marshall Goldberg, MRG & Associates

Michael Milligan, National Renewable Energy Laboratory

Deb Meyer, Colorado Office of Taxation, State Division of Property Taxation

Peter Curtiss, Curtiss Engineering

Platts Energy Consulting, a Division of McGraw-Hill

Prowers County Assessor’s Office

Ryan Wiser, Lawrence Berkeley Laboratories

Steve Clemmer, Union of Concerned Scientists

Susan Innis, Western Resource Advocates

Susan Norman Williams, Northern Arizona University

Tri-State Generation and Transmission Association, Inc.

Troy Gagliano, National Conference on State Legislatures

Weld County Treasurer

Xcel Energy’s power plant operators

32

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F1147-E(12/2004)

REPORT DOCUMENTATION PAGE

Form Approved

OMB No. 0704-0188

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources,

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a

currently valid OMB control number.

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE

(DD-MM-YYYY)

May 2006

2. REPORT TYPE

Technical Report

3. DATES COVERED

(From - To)

5a. CONTRACT NUMBER

DE-AC36-99-GO10337

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Comparing Statewide Economic Impacts of New Generation from

Wind, Coal, and Natural Gas in Arizona, Colorado, and Michigan

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/TP-500-37720

5e. TASK NUMBER

WER5 6103

6. AUTHOR(S)

S. Tegen

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

8. PERFORMING ORGANIZATION

REPORT NUMBER

NREL/TP-500-37720

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

11. SPONSORING/MONITORING

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12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service

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13. SUPPLEMENTARY NOTES

14. ABSTRACT

(Maximum 200 Words)

With increasing concerns about energy independence, job outsourcing, and risks of global climate change, it is

important for policy makers to understand all impacts from their decisions about energy resources. This paper

assesses one aspect of the impacts: direct economic effects. The paper compares impacts to states from equivalent

new electrical generation from wind, natural gas, and coal. Economic impacts include materials and labor for

construction, operations, maintenance, fuel extraction, and fuel transport, as well as project financing, property tax,

and landowner revenues. We examine spending on plant construction during construction years, in addition to all

other operational expenditures over a 20-year span. Initial results indicate that adding new wind power can be more

economically effective than adding new gas or coal power and that a higher percentage of dollars spent on coal and

gas will leave the state. For this report, we interviewed industry representatives and energy experts, in addition to

consulting government documents, models, and existing literature. The methodology for this research can be

adapted to other contexts for determining economic effects of new power generation in other states and regions.

15. SUBJECT TERMS

wind energy; economic development; economic impacts; coal; natural gas; Arizona; Michigan; Colorado; power

plants

16. SECURITY CLASSIFICATION OF:

19a. NAME OF RESPONSIBLE PERSON

a. REPORT

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b. ABSTRACT

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c. THIS PAGE

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17. LIMITATION

OF ABSTRACT

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Include area code)

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Prescribed by ANSI Std. Z39.18

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????????????

Opportunities

for

rural

economic

development

blow across Nebraska

S

TEVEN

C

LEMMER

????????????

Opportunities for rural economic development

blow across Nebraska

S

TEVEN

C

LEMMER

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Opportunities for Rural Economic Development

Blow Across Nebraska

S

TEVEN

C

LEMMER

Union of Concerned Scientists

February 2001

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© 2001 Union of Concerned Scientists

All rights reserved

Steven Clemmer

is a senior analyst in the UCS Clean Energy

Program.

The Union of Concerned Scientists is a partnership of citizens and

scientists working to preserve our health, protect our safety, and

enhance our quality of life. Since 1969, we’ve used rigorous

scientific analysis, innovative policy development, and tenacious

citizen advocacy to advance practical solutions for the

environment.

The UCS Clean Energy Program examines the benefits and costs

of the country’s energy use and promotes energy solutions that are

sustainable both environmentally and economically.

More information about UCS and the Clean Energy Program is

available at the UCS site on the World Wide Web, at

www.ucsusa.org/energy.

The full text of this report is available on the UCS website

(www.ucsusa.org/publications)

or may be obtained from

UCS Publications

2 Brattle Square

Cambridge, MA 02238-9105

Or email

pubs@ucsusa.org

or call 617-547-5552.

Printed on recycled paper

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Figures

iv

Tables

v

Acknowledgements

vii

Executive Summary

ix

1. Introduction

1

2. Wind Power Development in the United States

4

State Policies and Wind Development

5

Wind Power and Economic Development

6

3. Wind Power in Nebraska

9

4. Methodology and Assumptions

13

Wind Power Costs in Nebraska

13

The Avoided Costs of Wind Power

16

Cost of Producing 10 Percent of Nebraska’s Electricity

from Wind Power

19

Estimating Economic Impacts

21

5. Potential Economic Impacts of Wind Development

in Nebraska

23

Construction and Manufacturing Impacts

24

Operation and Maintenance

25

Uncertainties

27

6. Conclusions

29

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1. Nebraska’s Wind Resources and Monitoring Sites

10

2. Median Income in Nebraska’s Most Windy Counties

11

3. Poverty Rate in Nebraska’s Most Windy Counties

11

4. Population is Declining in Most Windy Counties,

While the State Population Grows

12

5. Wind Power Capacity under an RPS of 10 Percent by 2012

in Nebraska and Displaced Capacity from New Natural

Gas Plants

20

6. New Jobs from the Construction and Operation of Wind

Projects under the RPS vs. an Equivalent Amount of

Electricity from Natural Gas and Coal

25

7. Additional Earnings from the Construction and Operation

of Wind Projects under the RPS vs. an Equivalent Amount

of Electricity from Natural Gas and Coal

26

8. Additional Gross State Product from the Construction and

Operation of Wind Projects under the RPS vs. an Equivalent

Amount of Electricity from Natural Gas and Coal

27

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Strong Winds

v

??????

1. Wind Technology Cost and Performance Projections

for a 50 MW Windfarm

16

2. Avoided Costs of Wind Power

18

3. The Incremental Cost of Providing 10 Percent of Nebraska’s

Electricity from Wind Power by 2013 vs. an Equivalent

Amount of Electricity from Natural Gas and Coal

21

4. Economic Impacts of Providing 10 Percent of Nebraska’s

Electricity with Wind Power in 2012 vs. an Equivalent

Amount of Electricity from Natural Gas and Coal

23

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????????????????

The author would like to thank Kate Allen, Marshall Goldberg,

Skip Laitner, Ben Paulos, Jeff Willis, and Tom Wind for their

assistance in providing information and review for this report.

We are grateful to the Energy Foundation for their support of this

work. The Union of Concerned Scientists is solely responsible for

its contents.

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Executive Summary

In recent years, wind power development and use has expanded rapidly in the United States

and around the world. This trend is expected to continue, especially in the Midwest. While

Nebraska has among the best wind energy resources in the nation, the state currently lags

behind its neighbors in developing wind power.

The Union of Concerned Scientists analyzed the potential economic benefits and costs of

expanding wind power in Nebraska. We found that the total net benefits to the state economy

of developing wind power instead of coal and natural gas are nearly $15 million per year

over a 20-year period. We based our analysis on a policy goal of generating 10 percent of

Nebraska’s electricity from wind power by the year 2012. This policy goal is achieved

through the implementation of a renewable portfolio standard (RPS). An RPS requires

electricity suppliers to sell a set amount of renewable energy to their customers. Meeting the

10 percent goal would result in 800 megawatts of wind capacity installed in the state by

2012.

New jobs and economic activity would be created directly from building, operating, and

maintaining wind facilities, as well as indirectly from local business supplying goods and

services to support those activities. We found that developing 800 megawatts of wind

capacity would, on net, create more jobs, earnings, and growth in gross state product than

developing natural gas and coal facilities to produce an equivalent amount of electricity. For

example, in 2012, the year the RPS goal is reached, there are 360 more jobs, $8 million more

in earnings, and $35 million more in gross state product. We found that wind projects

generate roughly 2.4 times more jobs during construction and 1.5 times more jobs from

ongoing operation and maintenance than do coal and natural gas plants.

Making a long-term commitment to develop wind power could help spur development and

expansion of businesses that manufacture wind turbines and related components in Nebraska.

We found that if half of the turbines and related components and all of the towers that are

needed to meet the 10 percent goal were manufactured in Nebraska, an additional 250 jobs,

$15 million in earnings, and $44 million in gross state product would be supported each year

over the 10-year period. Additional jobs and economic activity that could result from

exporting equipment to other states are not included in these estimates.

The analysis shows that wind power could be an important source of rural economic

development in Nebraska. We found that farmers and landowners would be receiving

$2.2 million in lease payments by 2012, assuming $2,000 per year for each wind turbine

installed on their land. Wind projects could also generate property tax revenues worth an

estimated $5.2 million by 2012, assuming private developers own half of the projects.

These benefits are most likely to accrue to the areas of the state that need them the most.

Median income levels in Nebraska’s ten windiest counties are, on average, 21 percent below

the state average, and poverty rates are higher than the state average in all but one of the

windiest counties. Moreover, while the state’s population is projected to grow 14 percent

between 1990 and 2010, population in the ten windiest counties is projected to decline by

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9 percent on average during the same period. This problem is particularly severe in Sheridan,

Keya Paha, and Scotts Bluff counties, where the population is projected to decline by 20 to

25 percent. The economic opportunity that wind power development provides has the

potential to offset this trend.

The two most important variables affecting the cost of wind power are ownership and the

availability of federal incentives. Our base case scenario assumed that Nebraska’s public

utilities would own half of the projects and private developers would own the other half, and

that federal incentives for wind power are available through 2006. Under this scenario, we

estimated that generating 10 percent of the state’s electricity with wind power instead of coal

and natural gas would cost an additional $3.5 million per year over a 20-year period or

roughly 7 cents per month on a typical household electric bill (using 500 kWh per month).

Under a high-cost scenario in which private developers own all of the projects and federal

incentives are not available, the typical household would pay an extra 59 cents per month in

2012. Under a low-cost scenario in which Nebraska’s public utilities owned all of the

projects and federal incentives are available through 2006, the typical household would save

about 20 cents per month in 2012.

By taking advantage of its as yet untapped wind resources, Nebraska will be taking an

important step toward reducing its reliance on expensive, aging nuclear power plants and

dirty coal plants that pollute the air and jeopardize the health of all Nebraskans. By starting

on this path now, the people of Nebraska can prepare themselves for the expected shortfall in

electricity generating capacity by relying on a clean source of power that is not subject to the

volatility of fuel markets.

Nebraska has a powerful opportunity to become a national leader in wind energy

development just as it has with ethanol production. States like Iowa, Minnesota, and Texas

are demonstrating that progressive state policies are key to fostering the growth of wind

power. This report shows that Nebraska can make a significant commitment to develop wind

power and maintain its low electricity rates, while providing net benefits to the state’s

economy and environment. Implementing a renewable portfolio standard in Nebraska could

help spur development of new industries, offer a new cash crop to farmers, and provide an

important source of jobs and income to rural communities.

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Introduction

The wind power industry is expanding rapidly all over the world. With an average annual growth

rate of 32 percent since 1995, wind power is the fastest growing energy source on the planet. In

2000, new wind power investments reached $4.6 billion. By 2004, global wind capacity is

projected to more than triple, and new wind power investments are projected to rise to

$7.6 billion.

1

Wind power is also booming in the United States. Between June 1998 and June 1999, nearly

$1 billion in wind turbines were installed in the United States— enough to power over 400,000

homes. US wind capacity is expected to double by the end of 2001, providing an estimated

$2.5 billion in new investment.

2

While wind power currently provides 0.1 percent of the

country’s power, the Department of Energy’s “Wind Powering America” initiative has set a goal

of producing 5 percent of the nation’s electricity from wind by 2020. DOE projects to achieve

this goal will add $60 billion in capital investment in rural America, provide $1.2 billion in new

income for farmers and rural landowners, and create 80,000 new jobs during the next 20 years.

Until recently, wind power was concentrated in California. Now large-scale turbines can be

found in more than half of the states. Farming regions in Minnesota and Iowa have emerged as

major wind power growth areas, followed by Texas, Wyoming, Colorado, and Wisconsin. By the

end of the year, the Northwest and Nevada will be home to the world’s two largest wind

projects.

3

State and federal policies have been the main driver for wind development in most

states. Wind power is also growing as a result of technology improvements, cost reductions, high

natural gas prices, and environmental concerns.

Nebraska has some of the best wind resources in the country. Yet it is lagging far behind its

neighbors in developing wind power. So far, only four large wind turbines have been built in the

state, providing 0.03 percent of its electricity. Moreover, Nebraska has not made a significant

future commitment to harness its wind potential.

Electricity generation in Nebraska is dominated by large coal and nuclear plants, which produce

enormous environmental and public health effects and risks. Coal is responsible for a host of ills,

including acid rain, smog, global warming, and mercury contamination of lakes. In 1998,

Nebraska spent about $113 million on imported coal to produce 64 percent of the electricity

generated in the state, exporting dollars and jobs in the process.

In 1998, nuclear plants produced 29 percent of the electricity generated in Nebraska. Nuclear

plants produce tons of highly radioactive waste, which must be stored safely for tens of

thousands of years. But nuclear power is slowly declining, mostly due to economic and safety

1

BTM Consult ApS, online at

www.btm.dk/overheads/wmu99/sld001.htm.

2

Brian Parsons, National Renewable Energy Laboratory, presentation at the

Harvesting Clean Energy

Conference,

Spokane, WA, January 29, 2001.

3

See “New Wind Plants in Northwest, Nevada to be World’s Largest,” American Wind Energy Association,

January 25, 2001, online at

www.awea.org/news/news010125nwn.html.

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problems. A 1997 study listed Nebraska’s

Cooper and Fort Calhoun plants as among the

least

competitive plants in the country.

4

Unlike other parts of the country, Nebraska has

sufficient electricity generating capacity to meet

its needs. In fact, Nebraska is a net exporter of

electricity. However, as the demand for

electricity continues to grow and as the state’s

aging coal and nuclear plants approach

retirement, new electricity supplies will be

needed to provide clean, reliable and affordable

power.

Nebraska’s 1997–2016 Integrated Resource Plan

indicates that the state could face a generating

capacity shortfall as early as 2005, when the

contract with out-of-state utilities for a share of

Cooper Nuclear Station’s power expires.

5

Assuming the contract is renewed or the power is sold

to another electricity provider, the report indicates that the state could still face a capacity

shortfall by 2008. The deficit grows to nearly 1,600 megawatts (MW) or 25 percent of the state’s

electricity needs by 2014, when the plant is scheduled to retire. A report by the North American

Electricity Reliability Council (NERC) predicts that the regional power pool that includes

Nebraska may need over 5,000 MW of new generating capacity by 2006, which is about the total

amount of electricity capacity currently used in Nebraska.

6

Nebraska is facing an important choice. It can continue to rely on imported fossil fuels and

expensive, aging nuclear plants, or it can invest in wind power and other clean homegrown

renewable electricity resources. Given Nebraska’s enormous wind and biomass resources, the

state could generate enough power to meet a significant portion of its own needs and could

export power from these resources to other states as well.

Beyond meeting its energy supply needs, wind power could provide an important boost for

Nebraska’s economy. Nebraska’s best wind resources are generally located in rural areas that

could benefit from new jobs and income. In September 2000, at the Nebraska Wind Energy

Forum in Lincoln, Governor Johanns suggested that wind power could provide a new

opportunity to grow the state’s economy, just as ethanol production has done (see box). He noted

that state policies had been instrumental in making Nebraska a national leader in ethanol

production.

4

Washington International Energy Group,

Nuclear Power Plants and Implications of Early Shutdowns for Natural

Gas Demand

, January 1997.

5

Nebraska Power Association,

Statewide Integrated Resource Planning Coordination Report (1997–2016)

, October

1996.

6

NERC 1999–2008 Reliability Assessment at page 71.

Until recently, few had mentioned Nebraska’s

wind resources as a way to grow the state’s

economy, and provide solid benefits to ag

producers. Once I started looking at the

numbers and what other states are doing, I

think we may have a tremendous opportunity

to build a new export industry just as we’ve

done with ethanol…The regional wind-to-

electricity story is not much different from the

development of Nebraska’s ethanol plants. We

were far behind other states in ethanol

production, but in six years we moved from an

also-ran to a national leader in ethanol

production because we established state

policies and incentives that made converting

corn to ethanol a state economic development

goal.

— Excerpts from Governor Johanns’ welcoming

remarks at the Nebraska Wind Energy Forum in

Lincoln, September 20, 2000.

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Strong Winds

3

Wind power is already stimulating economic development in several states. For example, wind

developers are paying farmers and landowners in Iowa and Minnesota about $2,000 per year for

each turbine installed on their land. These royalty payments can provide a stable supplement to a

farmer’s income, helping to counteract the swings in commodity prices. Wind development is

also creating new jobs in manufacturing, construction, operation, and maintenance of wind

turbines. In addition, private wind development is providing an important source of tax revenue

for many rural communities.

In this report, the Union of Concerned Scientists estimates the cost and potential economic

benefits of developing wind power in Nebraska. The impacts are based on generating 10 percent

of Nebraska’s electricity from wind power by 2012, as proposed in a bill introduced in the

Nebraska Legislature on January 16, 2001, by Senator Preister (LB 645). In addition to

estimating the potential statewide economic impacts of wind development, we also identify the

areas of the state that are most likely to benefit from wind development. Finally, we highlight

some of the economic benefits of wind development in other states that have adopted policies to

promote wind power.

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Wind Power Development in the United States

Several factors are fueling the growth of wind power in the United States. Among these are

technology improvements, declining cost, environmental and public health concerns, utility

green pricing, and federal incentives.

Since 1980, the cost of wind power has fallen by 80 to 90 percent, as a result of technology

improvements and economies of scale in manufacturing and installation. Wind energy experts

project that the cost will decline further in the future, as discussed later in the report.

While the cost of wind power is declining, the cost of natural gas— the fuel of choice for new

power plants— has suddenly increased. Natural gas prices have doubled over the past year, while

national spot market prices have quadrupled. Homeowners can expect to pay 70 percent more, on

average, for gas this winter than they paid last year, and the increase in gas use for electricity

generation will likely keep prices high for at least the next few years.

7

In contrast, the cost of wind power is relatively stable and predictable over a long period of time.

This is because most of the cost is in the initial capital investment, while the fuel (the wind) is

free. An increasing number of electricity providers have become interested in purchasing wind

power to provide insurance against volatile gas prices.

Environmental and public health concerns are also driving wind development growth. The

electricity industry is the single largest source of air pollution in the United States. Power plants

are responsible for over two-thirds of the sulfur dioxide emissions that produce acid rain, a

quarter of the smog-forming emissions, 40 percent of the heat-trapping emissions that cause

global warming. They are also the largest source of mercury emissions. One study found that by

2007, an estimated 30,000 people will die prematurely in the United States from coal plant soot.

8

In contrast, wind power does not produce air emissions, generate solid, toxic, or radioactive

waste, or use water. Therefore, wind power can help reduce both the cost of health care and the

cost of complying with environmental regulations. It can also provide insurance against more

stringent environmental requirements in the future.

Some wind development has resulted from voluntary customer purchases of green power. More

than 190 electric utilities in the United States are now offering a wind power product to their

customers, supporting an estimated 60 MW of new development.

9

Lincoln Electric Systems’ two

large wind turbines are supported through a green-pricing program.

7

See Bradley Keoun, “U.S. Natural Gas Costs Seen Even Higher Next Winter, AGA Says”

Bloomberg News

,

February 1, 2000; and EIA,

Short-term Energy Outlook

, December 2000, online at

www.eia.doe.gov.

8

Clean Air Task Force,

Death, Disease and Dirty Power: Mortality and Health Damage Due to Air Pollution from

Power Plants

, November 2000, based on Abt Associates, “Health Impacts Analysis” report, online at

http://cta.policy.net/fact/mortality/mortalitystudy.vtml.

9

Ed Holt and Associates, “A Quick Overview of Utility Green Pricing Programs,” presentation to the Nebraska

Wind Energy Forum, Lincoln, Nebraska, September 20, 2000.

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Federal policy has also provided an important stimulus for wind development. The federal

production tax credit (PTC) and renewable energy production incentive (REPI) for public power

provides 1.5 cents per kilowatt-hour (adjusted for inflation) for 10 years. The PTC and REPI

were enacted to allow wind to compete on a more equal basis with fossil fuels and nuclear

power, which continue to receive billions of dollars in federal subsidies each year. Nebraska

public utilities are eligible to apply for REPI funds for any wind projects they develop.

State Policies and Wind Development

While these factors have contributed to the growth of wind power, the majority of US wind

development has occurred in states that have adopted supportive policies and created long-term

markets for renewable energy. In California, tax incentives and favorable long-term contracts for

renewables led to the birth of the modern wind industry in the early 1980s.

In the past few years, several states have made new commitments to develop renewable energy.

Twelve states have adopted minimum renewable electricity requirements. Fourteen states have

adopted renewable electricity funds, totaling about $3.7 billion by 2012. We estimate that these

new laws will, together, result in 8,550 MW of new renewable power between 1998 and 2012—

an increase of 63 percent over 1997 levels— as well as supporting 7,800 MW of existing

renewables.

10

This development will provide enough clean power to meet the entire electricity

needs of 5.6 million homes and reduce carbon dioxide— the main greenhouse gas implicated in

global warming— as much as taking 4 million cars off the road or planting 1.2 billion trees.

These new commitments have already led to large-scale wind development in Minnesota, Iowa,

Wisconsin, and Texas. The policies adopted in those states are described below.

Minnesota.

Minnesota is the second largest producer of wind power and the ninth windiest state

in the nation. Minnesota’s wind development stems from the 1994 “Prairie Island Settlement.”

The Minnesota Legislature passed a law allowing Xcel Energy (formerly Northern States Power)

to temporarily store nuclear waste at its Prairie Island nuclear plant on the Mississippi River. In

exchange, Xcel Energy was required to install or purchase 425 MW of wind power and 125 MW

of biomass power by 2002 and an additional 400 MW of wind by 2012. Under the requirement,

wind and biomass would provide about 5 percent of the state’s electricity in 2012. In addition,

the law requires Xcel to contribute $500,000 per year for each cask storing nuclear waste into a

fund to support new renewable energy projects. The fund will eventually provide up to

$8.5 million per year. To date, 272 MW of wind power has been installed in Minnesota and

another 164 MW has been proposed or is under development.

Iowa.

Iowa is the third largest producer of wind power and the tenth windiest state in the nation.

Iowa’s wind farm developments stem mostly from the Alternate Energy Production law of 1983.

In an effort to promote development of local resources and to implement the federal Public

Utility Regulatory Policy Act, the legislature required the state’s investor-owned utilities to

generate or purchase about 2 percent of their power from renewable resources. The utilities

fought the law for almost 15 years, appealing to both the Iowa Supreme Court and the Federal

10

These figures are based on an update to Steve Clemmer, Ben Paulos and Alan Nogee,

Clean Power Surge:

Ranking the States

, Union of Concerned Scientists, April 2000.

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Energy Regulatory Commission before finally complying.

11

Two large projects near Storm Lake

and Clear Lake totaling about 240 MW are supplying enough power to meet the needs of about

63,000 homes. While this development is sufficient to meet the utilities’ requirement under the

AEP law, two private wind developers are planning on building two new wind farms totaling

180 MW this year.

12

Developers have already made agreements with 40 landowners to lease

space for the turbines.

Wisconsin.

Wisconsin is the nation’s seventh largest producer of wind power, despite being

ranked eighteenth in terms of its wind energy potential. To address power shortages in the

summer of 1998, the Wisconsin Legislature passed a law requiring utilities to develop more

power plants, including 50 MW of new renewables. The four investor-owned utilities affected by

the law relied mostly on wind power to meet their renewables requirement. In 1999, Wisconsin

also adopted a renewable portfolio standard (RPS) and renewable energy fund under its

Reliability 2000 legislation. The RPS requires every electric utility in the state to provide

2.2 percent of its electricity sales from renewable energy by 2011, which could lead to an

estimated 300 MW of new renewables. The renewable energy fund will provide about

$2.8 million through 2008 for customer-owned renewable energy technologies.

Texas.

Texas is the fourth largest producer of wind power and has the second best wind resource

potential in the United States. In 1999, Governor George W. Bush signed into law a RPS

requiring 2,000 MW of new renewables by 2009. The RPS has led to a flurry of new wind

development. Over 730 MW of new wind development is currently planned, adding to the

188 MW already operating. Texas officials have said that the goal may be reached seven years

ahead of schedule and only two and a half years after the legislation was passed.

13

Wind Power and Economic Development

Wind power is providing important economic benefits in a number of states. The direct

economic benefits include new jobs and income from construction, operation and maintenance;

manufacturing of wind turbines and related components; payments to landowners; and tax

revenues. Examples of these benefits are discussed below. Indirect benefits also result as

expenditures for and income from these activities ripple through the local economy. Other

economic benefits can result from reducing energy imports, improving air quality, reducing

health care costs, and increasing tourism.

Construction, Operation, and Maintenance Jobs.

In Lake Benton, Minnesota, construction of

over 200 MW of wind power over a two-year period employed about 150 construction workers,

as well as 22 people to operate and maintain the plant. The facility is now the second largest

employer in town, after the school district, according to Jim Nichols, Lake Benton’s economic

development director. Iowa’s 240 MW of large-scale wind development created an estimated

200 short-term construction jobs and 40 long-term operation and maintenance jobs at an average

wage of $16 per hour.

11

Bentham Paulos, “Light at the End of the Wind Tunnel in Iowa,”

Windpower Monthly

, December 1999.

12

“Energy Companies Plan 2 Wind Farms in Iowa,” Associated Press, January 14, 2001.

13

“Texas Utilities Power Ahead on Meeting Renewable Energy Goal,” American Wind Energy Association press

release, August 31, 2000, online at

www.awea.org.

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Manufacturing Jobs.

The recent growth in wind development in the Midwest has attracted new

businesses to the region to manufacture wind turbines and related components. For example, in

1999, LM Glasfiber, a Danish manufacturer of wind turbine blades, opened a plant in Grand

Forks, North Dakota, that employs 130 local people at a starting salary of roughly $10 per hour

with benefits.

14

The new jobs are equivalent to 20 percent of the total jobs in the state’s lignite

coal industry. NEG Micon, a Danish wind turbine manufacturer, recently opened a plant in

Champaign, Illinois, that employs over 30 people. It also located its US headquarters in Rolling

Meadows, Illinois.

15

In June 2000, Vestas, another Danish company and the world’s leading

manufacturer of wind turbines, announced plans to open their US headquarters and build their

first American turbine manufacturing plant in Pueblo, Colorado. It would employ over

600 people.

A few businesses in Nebraska have already benefited from wind development. When Enron

Wind built the two-turbine Springview project, they hired Daniels Manufacturing, a local family-

owned metal fabricating business in Ainsworth that specializes in making farm implements, to

design and fabricate custom parts for the towers. The design of the parts was so successful that

Enron Wind subsequently offered Daniels a contract to make the parts for an additional

300 towers in Minnesota and Iowa.

16

Valmont Industries, a leading manufacturer of center-pivot

irrigation systems headquartered in Omaha, was involved in the construction of some of the

turbines in Iowa and Texas and recently began development of a new support structure for wind

turbines.

Landowner Revenues.

Wind developers typically pay landowners around $2,000 per year over

a 30-year period for each turbine installed on their land, or roughly 2–3 percent of the project’s

annual revenue. Large wind turbines use only about a quarter acre of land, including access

roads, so farmers can continue to plant crops and graze livestock right up to the base of the

turbines. In a good year, it would take 20 acres of corn or 100 acres of rangeland to produce the

same amount of income as a single wind turbine.

17

Iowa’s wind farms are paying royalties to

115 landowners totaling $640,000 per year. At the Foote Creek wind facility in Carbon County,

Wyoming (the heart of coal country), landowners receive $140,000 in lease payments annually.

Tax Revenues.

Wind development can also generate significant property, sales, and income

revenues for rural communities. For example, a 20 MW wind farm in Kewaunee County,

Wisconsin, will result in annual property tax payments of $200,000 to the county, equivalent to

50 percent of their annual budget.

18

Iowa’s wind farms are generating an estimated $2 million

per year in property taxes. Wind developers typically pay 1–3 percent of the project’s value

annually in property taxes.

19

The extent to which wind power development in Nebraska would

14

Sam Black, “130 Jobs Blow into GF,”

Grand Forks Herald

, December 8, 1998.

15

Peter Kendall, “High Tech Windmills Churning up Hope,”

Chicago Tribune

, March 2, 1999.

16

Nebraska Wind Energy Task Force Report to Governor Johanns, January 25, 2001.

17

This assumes $100/acre for corn and $20/acre for producing beef on rangeland.

18

Michael Vickerman, RENEW Wisconsin, personal communication, 1999.

19

Matthew Brown and Johanna Woelfel,

Tax and Landowner Revenues from Wind Power Development

, National

Conference of State Legislators, State Legislative Report, April 2000.

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generate tax revenues will depend on whether the project is owned by public or private entities.

This is discussed in more detail later in the report.

Net Economic Benefits.

Several studies have shown that investments in wind and other

renewable energy sources can generate more jobs and income than investments in conventional

power plants. For example, the New York State Energy Research and Development Authority

estimates wind energy produces 27 percent more jobs per kilowatt-hour than coal plants and

66 percent more jobs than natural gas plants. A 1995 study by the Wisconsin Energy Bureau

found that investing in 800 MW of renewables (including 200 MW of wind) by 2010 would

create 3,300 more jobs, $81 million in higher disposable income, and a $165 million increase in

gross state product, compared with investing in coal and natural gas power plants.

20

The

additional income from renewables is equivalent to a benefit of 2 cents per kilowatt-hour for the

state.

20

Steven Clemmer, Wisconsin Energy Bureau,

Fueling Wisconsin’s Economy with Renewable Energy,

1995.

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Wind Power in Nebraska

Nebraska has four large-scale wind turbines currently operating in the state, representing 2.8

MW of capacity. Lincoln Electric Systems owns two 660 kW turbines near Lincoln, which are

supported through a green-pricing program. The output from the first turbine was fully

subscribed in about two months, leading LES to install a second turbine.

21

The Nebraska Public

Power District and several other utilities are collaborating with the Electric Power Research

Institute and the US Department of Energy (DOE) on a demonstration project near Springview,

consisting of two 750 kW turbines.

Nebraska’s installed wind capacity is modest considering the state’s excellent wind resources

and the progress made in other states. Nebraska is the sixth windiest state in the nation,

according to a DOE study.

22

A 1993 study by the Union of Concerned Scientists,

Powering the

Midwest

, found that Nebraska has sufficient wind resources to theoretically produce 26 times its

1998 electricity use, though transmission constraints would limit the potential far below this

level.

23

To better understand the state’s wind potential, the Nebraska legislature, the Nebraska Power

Association, and the state energy office reached an agreement in 1994 to complete a state wind

resource assessment. During the next four years, data collected from eight sites around the state

identified average wind speeds ranging from 14.4 to 16.4 miles per hour at 40 meters above the

ground.

24

The results were largely consistent with the estimates made in

Powering the Midwest.

The sites with the best resources are located in the north-central part of the state near Valentine,

Springview, and Stuart, and in the southwestern part of the state near Imperial. However, many

other areas of the state are likely to have sufficient wind resources to support wind power

development.

The Nebraska wind resource map developed in

Powering the Midwest

is shown in Figure 1,

along with the wind monitoring sites. This map groups areas according to their predicted average

annual wind speeds. Most utility-scale wind plants are being installed in class 4, 5, and above

areas, but projected improvements in wind technology should make class 3 areas attractive in the

future.

25

Smaller wind turbines for residential and farm applications are designed to run in lower

class 2 and class 3 wind speeds.

21

Al J. Laukaitis,. “LES Harnesses Renewable Energy Blowin’ in the Wind,”

Lincoln Journal Star

, December 14,

1998.

22

D. L. Elliott, L. L. Wendell, and G. L. Gower,

An Assessment of the Available Windy Land Area and Wind Energy

Potential in the Contiguous United States

, Northwest Laboratory, Richland, Washington, 1991, PNL-7789. Selected

results from the study are available online at

www.eren.doe.gov/wind.

23

This is based on class 4 wind resources and higher. Michael Brower et al,

Powering the Midwest: Renewable

Electricity for the Economy and the Environment

, Union of Concerned Scientists, 1993.

24

Nebraska Wind Energy Site Data Study: Final Report

, prepared by Global Energy Concepts, Inc. for the Nebraska

Power Association, May 1999.

25

Wind classes are defined by a range of wind power densities at a given height above the ground and relate to a

range of wind speeds. Wind power density is expressed in watts per square meter of swept rotor area, or the area

perpendicular to the wind flow. A class 5 wind class has a wind power density of 500–600 watts per square meter

and reflects wind speeds of 16.8 to 17.9 miles per hour at 50 meters above the ground.

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Figure 1. Nebraska’s Wind Resources and Monitoring Sites

Kimball

Rushv lle

Valentine

Springview

Stuart

Winnebago

Wahoo

Imperial

Source: UCS, Powering the Midwest, 1993.

Nebraska’s best wind resources tend to be located in rural areas that are in need of new sources

of jobs and income. For example, median income is 21 percent lower in the state’s ten windiest

counties (based on the UCS wind map) than the statewide average, as shown in Figure 2. The

poverty rate is also higher than the state average in all but one of the state’s most windy counties,

as shown in Figure 3. In addition, while the state’s population is projected to grow 14 percent

between 1990 and 2010, population in the windy counties is projected to decline by 9 percent on

average during the same period, as Figure 4 shows. This problem is particularly severe in

Sheridan, Keya Paha, and Scotts Bluff counties, where the population is projected to decline by

20–25 percent.

26

New jobs and income from wind development could help keep people in the

community.

26

This information, which appears in the Nebraska Wind Energy Task Force’s January 2001 report to Governor

Johanns, was originally prepared by the author for a presentation given at Nebraska’s Wind Energy Forum in

Lincoln in September 2000.

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Figure 2. Median Income in Nebraska’s Most Windy Counties

0

5,000

10,000 15,000 20,000 25,000 30,000 35,000

Keya Paha

Boyd

Brown

Sheridan

Rock

Dundy

Banner

Holt

Scotts Bluff

Kimball

Cheyenne

State Average

$/year

Windy counties

21% lower than

state average

Figure 3. Poverty Rate in Nebraska’s Most Windy Counties

0%

2%

4%

6%

8%

10% 12%

14% 16%

18%

Sheridan

Keya Paha

Scotts Bluff

Rock

Brown

Holt

Boyd

Banner

Cheyenne

Dundy

Kimball

State Average

Poverty Rate

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Figure 4. Population is Declining in Most Windy Counties,

While the State Population Grows

-30% -25% -20% -15% -10% -5%

0%

5%

10%

15%

20%

Rock

Keya Paha

Dundy

Boyd

Brown

Banner

Holt

Sheridan

Cheyenne

Kimball

Scotts Bluff

State Average

Population Growth (1990-2010)

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Methodology and Assumptions

We estimated the potential economic impacts of developing wind power in Nebraska based on

the following four steps. First, we calculated current and projected costs of developing wind

power in Nebraska. Second, we estimated the market value or “avoided costs” of developing

wind power in Nebraska, based on the conventional generation wind power would displace.

Third, we calculated the total cost and displacement effects of producing 10 percent of the

electricity used in Nebraska with wind power by 2012 to meet the RPS proposed in LB 645.

Finally, we applied the expenditures for wind and conventional generating technologies to an

input-output model of Nebraska’s economy to calculate economic impacts. Each of these steps is

described in more detail below.

Wind Power Costs in Nebraska

The cost of developing wind power in Nebraska will depend on several variables, including the

size and ownership of projects, financing costs, and the availability of federal incentives and

excess transmission capacity. Our assumptions for capital and operation and maintenance costs,

capacity factor, federal incentives, transmission costs, ownership and financing, and property

taxes are discussed below and summarized in Table 1.

Capital and Operation and Maintenance Costs.

Our assumptions for the current costs of

building and operating wind projects were based on information from recent projects installed in

the Midwest. We assumed a gradual decline in capital and operation and maintenance (O&M)

costs and a steady increase in efficiency and production of wind projects over a 20-year period

based on trends from a 1997 study by the Electric Power Research Institute (EPRI) and the US

Department of Energy (DOE).

27

The study predicts a decline in capital costs largely due to

increasing production volumes over time and a decline in O&M costs from economies of scale

from large turbines and taller towers. We assumed a typical project size of 50 MW to achieve

greater economies of scale in construction and volume purchases of wind turbines from

manufacturers. While smaller projects or clusters of small projects could be developed in

Nebraska, they are likely to be more expensive. For example, the 1.5 MW Springview project

had a fairly high capital cost of $1,377/kW. The EPRI/DOE study estimates that a 10 MW

project would cost about 20 percent more than a 50 MW project and a 100 MW project would

cost about 5 percent less.

Capacity Factor.

Capacity factor is the ratio between the amount of electrical energy produced

by a generating unit during a given period of time and the amount of electrical energy that could

have been produced at continuous full-power operation during the same period.

28

For the year

2000, we assumed a capacity factor of 37 percent based on the long-term projection for the

Springview project, as calculated by Global Energy Concepts for the EPRI/DOE Wind Turbine

27

Electric Power Research Institute and US Department of Energy,

Renewable Energy Technology

Characterizations

, December 1997, online at

www.eren.doe.gov/utilities/techchar.html

.

28

Energy Information Administration,

Annual Energy Review 1998

.

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Verification Program.

29

They based this projection on data from Nebraska’s four-year wind

monitoring study and two years of actual operating data. In 2000, the Springview turbines

operated at a 38.6 percent capacity factor. Springview was assumed to represent a typical site for

wind development in Nebraska. The state’s wind monitoring study recorded higher wind speeds

at two of the six sites with wind resources suitable for commercial development. We assumed,

based on projections from the EPRI/DOE study, that capacity factors would increase over time

due to taller towers, larger rotors, increased efficiency, and a reduction in losses due to weather,

blade soiling, control and turbulence, line losses, and other factors.

Federal Incentives.

Two federal incentives are available to encourage wind power development.

A Production Tax Credit (PTC), currently worth 1.7 cents per kWh for the first 10 years of a

project’s operating life and adjusted annually for inflation, is available to private wind

developers. The Renewable Energy Production Incentive (REPI) is an equivalent payment that

public utilities can apply for on an annual basis for the first 10 years of a project’s life. Funding

for the REPI is subject to annual appropriations by Congress, which makes its long-term

availability more uncertain. Since funding for the PTC basically comes from a reduction in taxes

that are paid to the US Treasury, its availability is virtually guaranteed once a project is built.

While these incentives are scheduled to expire at the end of 2001, there appears to be broad

bipartisan support from key members of Congress and the Bush administration to extend the

incentives for at least five years. Thus, for this analysis, we assumed that the PTC and REPI

would be extended for five years.

The amounts shown in Table 1 represent the value of the incentives spread out over a 20-year

period to make this value comparable with the annualized value of other costs. The value of the

PTC is higher than the REPI payment because private developers can receive additional tax

benefits from the tax credit. The PTC is actually worth about 2.4 cents per kWh for the first

10 years to private developers with sufficient tax liability.

30

Transmission Costs.

Transmission capacity in Nebraska and the Midwest is limited, particularly

in rural areas where the best wind resources often exist. While existing and proposed wind

projects in Iowa and Minnesota have required relatively modest new investments in

transmission, any significant new development in those areas is likely to require new or

upgraded transmission lines to get the wind power to demand centers. The situation is likely to

be similar in Nebraska. For this analysis, we assumed that 150 MW of wind power could be

added in Nebraska without incurring additional transmission costs beyond interconnection to the

existing transmission system. These costs are included in the capital cost estimates above. For

wind power capacity additions above the first 150 MW, we assumed that new transmission lines,

substations, and collection systems would cost $120 per kW.

31

29

H. Rhodes, J. VandenBoshe, T. McCoy, and A. Compton, Global Energy Concepts, and Brian Smith, National

Renewable Energy Lab,

Comparison of Projections to Actual Performance in the DOE-EPRI Wind Turbine

Verification Program

, Presented at the Windpower 2000 Conference in Palm Springs, Calif., May 2000.

30

For more information on this topic see Wiser and Kahn,

Alternative Windpower Ownership Structures: Financing

Terms and Project Costs

, May 1996, p. 36.

31

This cost estimate was based on a very simple analysis completed for this report by Thomas A. Wind, PE, Wind

Utility Consulting, Jefferson, Iowa. The estimate includes the cost of installing 180 miles of 345 kV transmission

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Ownership and Financing

. Our analysis considered three possible ownership scenarios:

•

100 percent public

•

100 percent private

•

50 percent public/50 percent private

Table 1 shows the estimated cost of developing wind power in Nebraska for both public and

private ownership. For publicly owned facilities, we assumed 100 percent tax-exempt bond

financing at a 6.5 percent interest rate, with cost recovery over a 20-year period.

32

For privately

owned facilities, we applied the same financing assumptions as in the EPRI/DOE study for a

generating company using balance sheet or corporate finance, where debt and equity investors

hold claim to a diversified pool of corporate assets.

33

Florida Power and Light, the largest wind

developer in the United States, uses this form of financing.

Financing costs have a significant impact on the cost of wind power, as Table 1 shows. This is

because wind power is a capital-intensive technology, with low operating costs. Based on our

financing assumptions, publicly financed facilities are between 53 and 65 percent less expensive

than privately financed projects. The higher value the PTC provides for private facilities helps

offset some of the cost advantage of publicly financed projects. The level of funding available

for the REPI incentive, on the other hand, is less certain, as discussed above. Without the REPI

payment, we estimated that publicly financed projects would be as much as 15 percent less

expensive than privately financed projects with the PTC.

34

Property Taxes.

The extent to which wind development in Nebraska would generate property

tax revenues will depend on who owns the project. In Nebraska, all electricity is from publicly

owned entities. Public power in the state is subject to a unique taxing structure. Public power

districts pay 5 percent of annual gross revenue derived from retail electricity sales that includes

an amount equal to the 1957 payment in lieu of taxes. Under this structure, wind projects would

not be subject to property tax payments. However, wind projects owned by municipal utilities

would contribute to the tax local base. Private wind development in rural areas would pay

property taxes at an average statewide rate of about 1.5 percent of the project’s assessed value.

35

Property taxes are included in O&M costs.

line and associated substation equipment in North Central Nebraska to connect approximately 650 MW of wind

power to the existing electric grid.

32

This is the same interest rate used for financing wind projects in the Nebraska Power Association’s

1997– 2016

Integrated Resource Plan

, 1996.

33

EPRI/DOE, 1997, p. 7-1. A typical generating company capital structure consists of 35 percent debt at a 7.5

percent annual return and 65 percent equity at a 13 percent return. We have assumed that all costs are recovered over

a 20-year period.

34

Ryan Wiser and Edward Kahn, 1996.

Alternative Windpower Ownership Structures: Financing Terms and

Project Costs

, Lawrence Berkeley National Laboratory, Berkeley, Calif.

35

Kate Allen, legislative aide to Senator Don Preister, personal communication, January 2001.

ELECTRONIC FILING, RECEIVED, CLERK'S OFFICE, JANUARY 5, 2007

* * * * * PC #7 * * * * *

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16

U

NION OF

C

ONCERNED

S

CIENTISTS

Total Cost of Wind Power

. Our estimate of 3.8 cents per kWh in 2000 for the total cost of

privately owned wind projects (over a 20-year period) is within the range of costs of existing

projects in the Midwest. For example, the large projects near Alta, Iowa, and Lake Benton,

Minnesota, are reportedly producing power for 3 to 5 cents per kWh. Florida Power and Light

recently proposed a 100 MW wind project for Hancock County, Iowa, that is expected to

generate electricity at 2.8 cents per kWh over a 20-year period.

36

All reported costs include the

production tax credit.

Table 1. Wind Technology Cost and Performance Projections for a 50 MW Wind Farm

2000

2005

2010

2015

2020

Hub Height (m)

65

70

80

85

90

Rotor Diameter (m)

50

55

55

55

55

Capital cost ($/kW)

1,100

939

810

726

660

O&M Cost (¢/kWh)

0.8

0.65

0.5

0.45

0.4

Capacity factor (%)

37.0

38.6

42.1

43.1

43.2

Total

Cost

without

Incentives & Transmission

Public Ownership (¢/kWh)

3.3

2.7

2.1

1.9

1.7

Private Ownership (¢/kWh)

5.2

4.2

3.3

2.9

2.6

REPI (¢/kWh)

(1.0)

(1.0)

0

0

0

PTC (¢/kWh)

(1.4)

(1.4)

0

0

0