A - 1

APPENDIX A

Northwest Power Supply Adequacy/Reliability Study – Phase 1 Report

DATA AND ASSUMPTIONS USED FOR THE RESOURCE DEVELOPMENT

FORECAST

Project Financing

The financing assumptions for new generating resources are summarized in Table A.-1. Project

developers are assumed to be unregulated private generating companies. New projects are assumed to be

merchant plants, having long-term power sales agreements for little, if any of plant output when built. Project

financing assumptions are based on the “Unregulated Independent” financing assumptions of the Fourth

Power Plan1. Long-term general inflation rates are reduced from the 3.5 percent used in the Fourth Plan to 2.5

percent to reflect the generally lower inflation rates of the past several years and continuing strong federal

anti-inflation policy. The nominal cost of debt and equity are reduced consistent with the reduction in general

inflation rate. The debt/equity ratio of 80:20 used for the Fourth Plan is reduced to 70:30 to reflect the

increased risk associated with merchant plant development. Finally, an after-tax cost of capital “corporate”

discount rate is used in lieu of the 4.75 percent societal discount rate of the Fourth Power Plan. The corporate

discount rate is intended to represent the discount rate used by plant developers in assessing project

economics.

Table A-1: Base case financing assumptions for new power projects

Return on equity (%/yr) 17.3%

Interest on long-term debt (%/yr, real) 8.7 %

Debt/equity ratio 70/30

Amortization period (yr) 15

Federal income tax rate (%) 34%

State income tax rate (%) 3.7%

Property tax rate (on depreciated value) (%/yr) 1.4%

Insurance rate (on depreciated value) (%/yr) 0.25%

Debt financing fees (%) 2.0%

Discount rate basis Weighted after-tax cost-of -capital

Discount rate (%/yr) 9.0%

General inflation (%/yr) 2.5%

 

1 Northwest Power Planning Council. Fourth Northwest Conservation and Electric Power Plan, Document 96-5 and 96-5A, March

1996 and Addendum to the Fourth Northwest conservation and Electric Power Plan Document 97-7, April 1997.
A - 2

Scheduled Resource Additions and Retirements

We assume that projects currently under construction are completed as scheduled, and that proposed

retirements reported by WSCC2 occur as scheduled. Our assumptions regarding scheduled additions are

shown in Table A.-2; projects assumed to be retired are shown in Table A-3

Table A-2: Scheduled Resource Additions (7/1/99 & later)

Project Fuel/Type Capacity

(MW)

Location Service

Island Cogeneration 1 Natural gas/ Combined cycle combustion

turbine w/cogeneration

250 Elk Falls, BC Aug 2000

Stave Falls (New

powerhouse)

Hydro 90 Stave R., BC Dec 1999

Cobisa-Person Natural gas/ Simple-cycle combustion turbine 140 Albuquerque, NM July 2000

Fort Saskatchewan Natural gas/ Combined cycle combustion

turbine w/cogeneration

120 Fort Saskatchewan Nov 1999

Joffre Cogeneration Natural gas/ Combined cycle combustion

turbine w/cogeneration

450 Joffre, AB Jun 2000

Valmont Natural gas/ Simple-cycle combustion turbine 37 Boulder, CO Jun 2000

Arapahoe Natural gas/ Simple-cycle combustion turbine 74 Denver, CO Jun 2000

Rossdale 11 (Repower) Natural gas/ Combined cycle combustion

turbine

241 Edmonton, AB Jan 2002

Suncor Cogeneration 1 Natural gas/ Combined cycle combustion

turbine w/cogeneration

180 Ft McMurrey, AB Jun 2000

Suncor Cogeneration 2 Natural gas/ Combined cycle combustion

turbine w/cogeneration

180 Ft McMurrey, AB Jun 2001

Klamath Cogeneration Natural gas/ Combined cycle combustion

turbine w/cogeneration

484 Klamath Falls, OR Jun 2001

Sutter Natural gas/ Combined cycle combustion

turbine

500 Yuba City, CA Jun 2001

Los Mendanos Natural gas/ Combined cycle combustion

turbine w/cogeneration

545 Pittburg, CA Jun 2001

South Point Natural gas/ Combined cycle combustion

turbine

545 Bullhead City, AZ Jun 2001

Table A-3: Scheduled Resource Retirements (7/1/99 & later)

Project Fuel/Type Capacity

(MW)

Location Retirement

Whitehorn 1 Fuel oil/ Simple-cycle combustion turbine 61 Point Whitehorn, WA Nov 1999

Valley 3 Natural gas/Boiler-team 163 Sun Valley, CA Jan 2000

Valley 4 Natural gas/Boiler-steam 160 Sun Valley, CA Jan 2000

Vernon IC 1 - 5 Fuel oil/Reciprocating 21 Vernon, CA Jan 2000

Battle River 1 Coal/Boiler-steam 31 Forestburg, AB Oct 1999

Battle River 2 Coal/Boiler-steam 32 Forestburg, AB Oct 1999

Rossdale 8 Natural gas/Boiler-steam 71 Edmonton, AB Dec 1999

 

2

 Western Systems Coordinating Council. Existing Generation and Significant Additions and Changes to Existing facilities 1997 - 2007.

January 1998.
A - 3

Load Growth Forecast

Annual WSCC load growth is assumed to average 1.5 percent, the base case rate estimated for the

Fourth Power Plan and used for the Council’s earlier assessment of future Bonneville costs and revenues3.

For this study, load growth rates are differentiated for individual load-resource areas, based on forecasts

developed by Bonneville for its initial rate case proposal4. The load growth rates used for load-resource areas

not appearing in the Bonneville work are those of the closest equivalent or adjacent areas of the Bonneville

study. The annual load-growth forecasts used for the 15 load-resource areas are shown in Table A-5. The

rates were held constant over the 20-year study period.

Table A-5: Load growth forecasts

Load-Resource Area Annual Load Growth (%)

Western Washington and Oregon 1.52

Northern California 1.06

Southern California 1.06

British Columbia 1.36

Southern Idaho 1.52

Montana 1.52

Wyoming 1.74

Colorado 1.74

New Mexico 1.82

Arizona and southern Nevada 1.82

Utah 1.52

Northern Nevada 1.52

Alberta 1.36

Southwestern Public Service 1.82

Eastern Washington and Oregon and northern Idaho 1.52

Fuel Prices

The AURORA model requires price forecasts for natural gas, coal, nuclear fuel and other fuels used

for production of electric power. Because of the importance of coal and natural gas for electric power

generation, separate price series for individual load-resource areas are provided for these fuels.

Natural Gas

Natural gas prices are based on a price forecast for the Henry Hub, Louisiana trading hub. The Henry

Hub price is adjusted by basis differential prices to yield prices for two regional supply basins, the Western

Canada Sedimentary Basin (WCSB) (AECO trading hub) and the San Juan supply basin (Ignacio trading

hub). Secondary basis differential prices are applied to the supply basin prices to yield “contract” natural gas

prices for each load-resource area. This contract price represents the fuel price for a baseload plant such as a

new combined-cycle unit. A portion of the contract price is treated as fixed. This is intended to simulate a gas

supply contract with reserved transportation. Gas prices for peaking plants are obtained by adding a peaking

 

3

 (Cite for Bonneville costs and revenues study).

4

Bonneville Power Administration. 2002 Initial Power Rate Proposal: Marginal Cost Analysis Study. August 1999.
A - 4

differential. The resulting peaking gas price represents the generally higher fuel prices that peaking facility

can be expected to pay because of spot market gas consumed during peak load periods. Peaking gas prices

are treated as fully variable.

The long-term natural gas price annual escalation value used for this study is 0.8 percent, unchanged

from that used for the 1998 assessment of Bonneville costs and revenues. However, base year gas prices have

been increased at the recommendation of the study advisory group. The year 2000 price (used as the base

year for long-term escalation for this study) is $2.40/MMBtu, compared to $2.05/MMBtu in the 1998

analysis.

In general, the supply basis and load-resource basis differentials used in this study are projections of

the 10-year basis differential series developed for Bonneville’s 2002 rate proposal. Because of the timeliness

of the Bonneville analysis, we believe that the results of that work should supercede the differentials used in

the 1998 Council study. Further discussion of these differentials is provided in Bonneville’s marginal cost

analysis report.

The Ignacio/Henry Hub basin basis differential is that proposed by Bonneville. This study, however,

uses the AECO trading hub as the basis for northern load-resource areas rather than the Sumas interchange

used in the Bonneville rate case. Our AECO/Henry Hub basis differential is Bonneville’s “Sumas”

differential, reduced by $0.05/MMBtu to reflect the transportation differential between the Sumas

(Washington) interchange and the AECO (Alberta) hub. The AECO/Henry differential declines (i.e., the

AECO price rises) from $ - 0.65/MMBtu in 1997 to $ - 0.30/MMBtu in 2009. This reflects the effect of

pipeline expansions on Midwestern market access to Western Canada Sedimentary Basin gas. For many

years, limited market access resulted in WCSB prices being significantly lower than Henry Hub prices,

providing a price advantage for the Northwest. The negative differential between WCSB and Henry prices

began to contract (i.e. WCSB gas prices began to rise) following the 1998 expansion of the Northern Border

pipeline. The Alliance pipeline, expected to open in 2000, is expected to further strengthen the effect of the

Midwestern market on WCSB prices. Increasingly evident declines in WCSB well productivity may further

reduce the differential.

The choice of supply basin for specific load-resource area price series is based on the price correlation

analysis described in Bonneville’s 2002 Initial Power Rate Proposal. Some adjustments for revised and new

load-resource areas have been made. The Nevada load-resource area, originally congruent with the state

boundary and assigned to the San Juan producing basin by Bonneville, is now limited to northern Nevada.

Because this area is served via the Paiute pipeline from southern Idaho, northern Nevada gas prices are based

on AECO. Prices for the Southwestern Public Service load-resource area, new to this study, are based on the

Ignacio hub, consistent with the adjacent New Mexico load-resource area.

The load-resource area basis differentials are also based on those developed by Bonneville.

Differentials for areas based on AECO are generally increased by $0.05/MMBtu to account for the shift from

Sumas to AECO. One exception is Alberta. Because the AECO hub is located within Alberta, the Alberta

area differential remains at the Bonneville Canada area value of $0.20/MMBtu in 2000. The second

exception is the new “Eastern Washington and Oregon, northern Idaho” area. This area receives the

Bonneville Washington/Oregon differential of $0.25/MMBtu in 2000 because of its proximity to the AECO

hub. The Northern Nevada differential of $0.45/MMBtu in 2000 reflects the indirect gas supply to this area

via the Paiute lateral off the Williams pipeline in Southern Idaho. Differentials for southern California, New

Mexico, Utah and Colorado are unchanged.
A - 5

The resulting gas prices are shown in Table A-6. The table A-6 “contract” gas prices represent the full

delivered cost of fuel for a baseload unit. In modeling unit dispatch, a portion of the contract gas price is

treated as fixed. This portion, $ 0.175/MMBtu, is intended to represent roughly half of the transportation and

other fixed costs of a typical gas supply contract. We assume about half of the gas supply for a baseload

facility will be covered by contract.

Peaking gas prices are the full contract prices for each load-resource area, increased by $0.60/MMBtu.

This represents the price that a peaking facility is expected to pay for spot market gas consumed during peak

load periods. The peaking differential is that recommended by EPIS, the vendor of the AURORA model.

Other Fuels

Coal price forecasts are unchanged from the Council’s 1998 assessment of future Bonneville costs and

revenues. Because of stagnant demand and slow increases in productivity, base case coal prices are assumed

to decline at 1 percent a year, real.

Fuel oil prices are those used for the Councils’ 1998 study of Bonneville costs and revenues. Biomass

fuel prices are those used in the 1998 study. These are from the Fourth Power Plan. The fuel price for

facilities reported as fuelled by refinery gas are based on a 50:50 mix of zero-cost refinery waste gasses and

purchased natural gas. Fuel prices for all nuclear plants except WNP-2 are from the Energy Information

Administration Annual Energy Outlook. WNP-2 fuel prices have been lower than most because of the

availability of fuel stocks from uncompleted projects. For WNP-2 fuel prices, we use the Energy Northwest

long-term budget fuel price forecast 2009. Following 2009, we escalate WNP-2 fuel prices at the rate forecast

by the Energy Information Administration.

A - 7

Table A-6: Fuel prices ($/MMBtu)

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

No. 1 Fuel Oil 5.00 5.03 5.05 5.08 5.10 5.13 5.15 5.18 5.20 5.23 5.26 5.28 5.31 5.33 5.36 5.39 5.42 5.44 5.47 5.50 5.52

No. 2 Fuel Oil 4.50 4.52 4.55 4.57 4.59 4.61 4.64 4.66 4.68 4.71 4.73 4.75 4.78 4.80 4.83 4.85 4.87 4.90 4.92 4.95 4.97

Henry Hub NG 2.53 2.04 2.38 2.40 2.42 2.44 2.46 2.48 2.50 2.52 2.54 2.56 2.58 2.60 2.62 2.64 2.66 2.68 2.70 2.73 2.75

WCSB (AECO) NG 2.13 1.69 2.28 2.30 2.32 2.34 2.37 2.39 2.41 2.43 2.46 2.47 2.50 2.52 2.54 2.56 2.58 2.60 2.62 2.65 2.67

San Juan (Ignacio) NG 2.33 1.84 2.18 2.20 2.22 2.24 2.26 2.28 2.30 2.32 2.34 2.36 2.38 2.40 2.42 2.44 2.46 2.48 2.50 2.53 2.55

AB Contract NG 2.08 1.64 2.23 2.25 2.27 2.29 2.32 2.34 2.36 2.38 2.41 2.42 2.45 2.47 2.49 2.51 2.53 2.55 2.57 2.60 2.62

AZ & S. NV Contract NG 2.68 2.19 2.53 2.55 2.56 2.58 2.60 2.62 2.63 2.65 2.67 2.68 2.70 2.72 2.74 2.76 2.78 2.80 2.82 2.85 2.87

BC Contract NG 2.13 1.69 2.28 2.30 2.32 2.34 2.37 2.39 2.41 2.43 2.46 2.47 2.50 2.52 2.54 2.56 2.58 2.60 2.62 2.65 2.67

CO Contract NG 2.63 2.14 2.48 2.50 2.51 2.53 2.55 2.57 2.58 2.60 2.62 2.63 2.65 2.67 2.69 2.71 2.73 2.75 2.77 2.80 2.82

E. OR, WA & N. ID Contract NG 2.13 1.69 2.28 2.30 2.32 2.34 2.37 2.39 2.41 2.43 2.46 2.47 2.50 2.52 2.54 2.56 2.58 2.60 2.62 2.65 2.67

MT Contract NG 2.18 1.74 2.33 2.35 2.37 2.39 2.42 2.44 2.46 2.48 2.51 2.52 2.55 2.57 2.59 2.61 2.63 2.65 2.67 2.70 2.72

N. CA Contract NG 2.48 2.04 2.63 2.65 2.67 2.69 2.72 2.74 2.76 2.78 2.81 2.82 2.85 2.87 2.89 2.91 2.93 2.95 2.97 3.00 3.02

N. NV Contract NG 2.33 1.89 2.48 2.50 2.52 2.54 2.57 2.59 2.61 2.63 2.66 2.67 2.70 2.72 2.74 2.76 2.78 2.80 2.82 2.85 2.87

NM & SWPS Contract NG 2.63 2.14 2.48 2.50 2.51 2.53 2.55 2.57 2.58 2.60 2.62 2.63 2.65 2.67 2.69 2.71 2.73 2.75 2.77 2.80 2.82

S. CA Contract NG 2.73 2.24 2.58 2.60 2.61 2.63 2.65 2.67 2.68 2.70 2.72 2.73 2.75 2.77 2.79 2.81 2.83 2.85 2.87 2.90 2.92

S. ID Contract NG 2.18 1.74 2.33 2.35 2.37 2.39 2.42 2.44 2.46 2.48 2.51 2.52 2.55 2.57 2.59 2.61 2.63 2.65 2.67 2.70 2.72

UT Contract NG 2.63 2.14 2.48 2.50 2.51 2.53 2.55 2.57 2.58 2.60 2.62 2.63 2.65 2.67 2.69 2.71 2.73 2.75 2.77 2.80 2.82

W. OR & WA Contract NG 2.18 1.74 2.33 2.35 2.37 2.39 2.42 2.44 2.46 2.48 2.51 2.52 2.55 2.57 2.59 2.61 2.63 2.65 2.67 2.70 2.72

WY Contract NG 2.23 1.79 2.38 2.40 2.42 2.44 2.47 2.49 2.51 2.53 2.56 2.57 2.60 2.62 2.64 2.66 2.68 2.70 2.72 2.75 2.77

AB Peaking NG 2.68 2.24 2.83 2.85 2.87 2.89 2.92 2.94 2.96 2.98 3.01 3.02 3.05 3.07 3.09 3.11 3.13 3.15 3.17 3.20 3.22

AZ & S. NV Peaking NG 3.28 2.79 3.13 3.15 3.16 3.18 3.20 3.22 3.23 3.25 3.27 3.28 3.30 3.32 3.34 3.36 3.38 3.40 3.42 3.45 3.47

BC Peaking NG 2.73 2.29 2.88 2.90 2.92 2.94 2.97 2.99 3.01 3.03 3.06 3.07 3.10 3.12 3.14 3.16 3.18 3.20 3.22 3.25 3.27

CO Peaking NG 3.23 2.74 3.08 3.10 3.11 3.13 3.15 3.17 3.18 3.20 3.22 3.23 3.25 3.27 3.29 3.31 3.33 3.35 3.37 3.40 3.42

E. OR, WA & N. ID Peaking NG 2.73 2.29 2.88 2.90 2.92 2.94 2.97 2.99 3.01 3.03 3.06 3.07 3.10 3.12 3.14 3.16 3.18 3.20 3.22 3.25 3.27

MT Peaking NG 2.78 2.34 2.93 2.95 2.97 2.99 3.02 3.04 3.06 3.08 3.11 3.12 3.15 3.17 3.19 3.21 3.23 3.25 3.27 3.30 3.32

N. CA Peaking NG 3.08 2.64 3.23 3.25 3.27 3.29 3.32 3.34 3.36 3.38 3.41 3.42 3.45 3.47 3.49 3.51 3.53 3.55 3.57 3.60 3.62

N. NV Peaking NG 2.93 2.49 3.08 3.10 3.12 3.14 3.17 3.19 3.21 3.23 3.26 3.27 3.30 3.32 3.34 3.36 3.38 3.40 3.42 3.45 3.47

NM & SWPS Peaking NG 3.23 2.74 3.08 3.10 3.11 3.13 3.15 3.17 3.18 3.20 3.22 3.23 3.25 3.27 3.29 3.31 3.33 3.35 3.37 3.40 3.42

S. CA Peaking NG 3.33 2.84 3.18 3.20 3.21 3.23 3.25 3.27 3.28 3.30 3.32 3.33 3.35 3.37 3.39 3.41 3.43 3.45 3.47 3.50 3.52

S. ID Peaking NG 2.78 2.34 2.93 2.95 2.97 2.99 3.02 3.04 3.06 3.08 3.11 3.12 3.15 3.17 3.19 3.21 3.23 3.25 3.27 3.30 3.32

UT Peaking NG 3.23 2.74 3.08 3.10 3.11 3.13 3.15 3.17 3.18 3.20 3.22 3.23 3.25 3.27 3.29 3.31 3.33 3.35 3.37 3.40 3.42

W. OR & WA Peaking NG 2.78 2.34 2.93 2.95 2.97 2.99 3.02 3.04 3.06 3.08 3.11 3.12 3.15 3.17 3.19 3.21 3.23 3.25 3.27 3.30 3.32

WY Peaking NG 2.83 2.39 2.98 3.00 3.02 3.04 3.07 3.09 3.11 3.13 3.16 3.17 3.20 3.22 3.24 3.26 3.28 3.30 3.32 3.35 3.37

Nuclear Fuel - WNP-2 0.28 0.29 0.29 0.30 0.31 0.32 0.33 0.34 0.34 0.35 0.36 0.37 0.38 0.39 0.40 0.41 0.42 0.43 0.44 0.46 0.47

Nuclear Fuel - Other WSCC 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45

Refuse -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50 -3.50

Wood Waste 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65 0.65

Biogas 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Refinery Gas 0.85 0.86 0.86 0.87 0.88 0.88 0.89 0.90 0.91 0.91 0.92 0.93 0.94 0.94 0.95 0.96 0.97 0.97 0.98 0.99 1.00

AB Coal 0.80 0.79 0.78 0.78 0.77 0.76 0.75 0.75 0.74 0.73 0.72 0.72 0.71 0.70 0.69 0.69 0.68 0.67 0.67 0.66 0.65

AZ & S. NV Coal 1.19 1.18 1.17 1.15 1.14 1.13 1.12 1.11 1.10 1.09 1.08 1.07 1.05 1.04 1.03 1.02 1.01 1.00 0.99 0.98 0.97

BC Coal 0.80 0.79 0.78 0.78 0.77 0.76 0.75 0.75 0.74 0.73 0.72 0.72 0.71 0.70 0.69 0.69 0.68 0.67 0.67 0.66 0.65

CO Coal 0.83 0.82 0.81 0.81 0.80 0.79 0.78 0.77 0.77 0.76 0.75 0.74 0.74 0.73 0.72 0.71 0.71 0.70 0.69 0.69 0.68

ID Coal 1.20 1.19 1.18 1.16 1.15 1.14 1.13 1.12 1.11 1.10 1.09 1.07 1.06 1.05 1.04 1.03 1.02 1.01 1.00 0.99 0.98

MT Coal 0.80 0.79 0.78 0.78 0.77 0.76 0.75 0.75 0.74 0.73 0.72 0.72 0.71 0.70 0.69 0.69 0.68 0.67 0.67 0.66 0.65

N. CA Coal 1.45 1.44 1.42 1.41 1.39 1.38 1.37 1.35 1.34 1.32 1.31 1.30 1.29 1.27 1.26 1.25 1.23 1.22 1.21 1.20 1.19

N. NV Coal 1.21 1.20 1.19 1.17 1.16 1.15 1.14 1.13 1.12 1.11 1.09 1.08 1.07 1.06 1.05 1.04 1.03 1.02 1.01 1.00 0.99
A - 8

NM & SWPS Coal 1.00 0.99 0.98 0.97 0.96 0.95 0.94 0.93 0.92 0.91 0.90 0.90 0.89 0.88 0.87 0.86 0.85 0.84 0.83 0.83 0.82

OR, WA & N. ID Coal 1.14 1.13 1.12 1.11 1.10 1.08 1.07 1.06 1.05 1.04 1.03 1.02 1.01 1.00 0.99 0.98 0.97 0.96 0.95 0.94 0.93

S. CA Coal 1.45 1.44 1.43 1.41 1.40 1.39 1.38 1.37 1.36 1.35 1.34 1.32 1.31 1.30 1.29 1.28 1.27 1.26 1.25 1.24 1.23

UT Coal 0.85 0.84 0.83 0.82 0.82 0.81 0.80 0.79 0.78 0.78 0.77 0.76 0.75 0.75 0.74 0.73 0.72 0.72 0.71 0.70 0.70

WY Coal 0.76 0.75 0.74 0.74 0.73 0.72 0.72 0.71 0.70 0.69 0.69 0.68 0.67 0.67 0.66 0.65 0.65 0.64 0.63 0.63 0.62
A - 9

New Resource Alternatives

To model the future electricity supply system, AURORA adds new increments of generating capacity

when the net present value cost of adding a new resource is less than the net present market value of the

output of the resource. A selection of new resources is provided from which the AURORA selects capacity

additions. The generating resource options considered for this study are the following:

• Natural gas-fired combined-cycle combustion turbine power plants

• Natural gas-fired simple-cycle combustion turbine power plants

• Pressurized fluidized bed combustion coal-fired combined cycle plants

• Central-station solar photovoltaic power plants

• Central-station wind-turbine arrays

Significant market penetration of distributed generation technologies such as packaged fuel cell or

microturbine cogeneration units could begin before the end of the decade. Because of modeling limitations,

distributed generating technologies could not explicitly be considered for this study. Because the period of

interest is early to mid-decade, we do not believe that distributed generation potential would significantly

affect the conclusions of this study.

The cost and performance assumptions for the new generating resource options considered in this

study are summarized in Table A-7.
A - 10

Table A-7: Base case cost and performance assumptions for new generating resource options

 (1997 base year except as noted)

Natural Gas

(Combined-cycle

Natural Gas (Simplecycle)Coal Solar Wind

Technology 250 MW class

industrial-grade

combined-cycle power

plant

160 MW class

industrial-grade simplecycle power plant

340 MW pressurized

fluidized bed

combustion power

plant

100 MW fixed flat-plate

photovoltaic plant

50 MW wind turbine

generator arrays

Fuel Natural gas with partial

firm transportation and

backup fuel oil supply

Spot market natural

gas and backup fuel oil

supply

Coal Solar Wind

Availability (thermal units)

Capacity factor (renewables)

92 % 87 % 80 % 21 % (CA, WA, OR, ID)

22 % WY

23 % (CO, NM)

25 % (AZ, UT, NV)

35 % (high plains)

24 % (basin & range)

30 % (Pacific coast)

Heat Rate (Btu/kWh) a 7167 10630 8425 -- --

Heat rate improvement (20-yr ave., %/yr) -0.5% -0.8 % -0.5 % -- --

Capital cost b, including grid interconnection

($/kW)

$583 $333 $1395 $3400 $ 960 (high plains)

$1380 (Basin & range)

$1125 (Pacific coast)

Capital cost escalation (20-yr ave., real, %/yr) -0.5% -0.8 % -0.5 % -8.0 % -2.8 %

Fixed operating cost c ($/kW/yr) $18 $12 $39 $8 $25 (high plains)

$47 (basin & range)

$32 (Pacific coast)

Variable operating cost (mills/kWh) 0.8 0.1 1.0 0.8 3.1 (high plains)

3.5 (basin & range)

3.5 (Pacific coast)

Operating cost escalation (20-yr ave., real,

%/yr)

-1.5% -1.8 % -1.5 % 0.0 % -3.8 % (fixed)

-1.1 % (variable)

Development & construction lead time (months) 24/24 24/12 36/36 24/12 24/12

Development & construction annual cash flow

(%/yr)

1/1/59/39 1.5/1.5/97 1/1/3/25/45/25 1/1/98 1/1/98

Service life (years) 30 30 30 30 30

__________________________

a

Equipment seeing service in 1997.

b

 “Overnight” capital cost (excludes financing costs, escalation and interest incurred during construction).

c

 Exclusive of property taxes and insurance. See financial assumptions, Table A-1.
A - 11

Combined-cycle Combustion Turbine Power Plants

The gas combustion turbine-combined cycle power plant using natural gas fuel is the technology of

choice for new base load capacity throughout North America for economic and environmental reasons.

Relatively low and stable gas prices and low-cost, efficient, reliable and environmentally clean gas turbinecombined cycle technology have lead to easily sited and quickly constructed power plants. At current gas

prices, these plants are capable of producing power at lifecycle costs of about 2.5 cents per kilowatt hour.

Unlike pure steam-cycle plants, gas turbines have not approached practical efficiency limits. Continuing

demand for more efficient and lower cost gas turbines for both transportation and stationary applications is

expected to encourage continued improvement of this technology. This should maintain the competitive

position of gas turbine-combined cycle power plants, even in the face of moderate increases in natural gas

prices.

Our combined-cycle combustion turbine power plant study assumptions are based on 250-megawatt

class industrial units5. This class of combustion turbine is the predominant machine currently employed for

power plants intended for baseload duty. No cogeneration load or credit is assumed, though cogeneration units

are not uncommon in practice.

Capital Cost

The capital cost of new combined-cycle plants is based on the reported cost of the Clark Public

Utilities River Road power plant in Vancouver, Washington. River Road, a 248-megawatt General Electric

107FA combined-cycle power plant, entered service in late 1997. The River Road construction cost was

adjusted as described below to arrive at a representative plant cost for each of the load and resource

geographic areas considered in the Aurora model.

Combined-cycle power plant development cost estimates for a group of prospective Northwest sites

was prepared for the Fourth Power Plan6. These estimates were intended to capture the effects of site-specific

conditions, and possible economies of scale at sites capable of accommodating multiple units. Because one of

these sites was Vancouver, the subsequent availability of the River Road cost information allowed the Fourth

Plan estimates to be calibrated using actual cost experience.

The calibrated site development cost estimates were increased by 2.7 percent to represent the

estimated average degradation of capacity over the life of the plant, yielding “lifetime average” capital costs.

The result, $546/kW (1997 dollars) is assumed to be representative of the cost of developing new combined

cycle plants in the Northwest under market conditions prevailing during the mid-1990’s.

Gas turbine vendors and the power plant construction industry were encountering slack market

conditions when the River Road plant was constructed. For this reason, the estimate was increased by 10

percent to $601/kW to represent base case (equilibrium market) conditions thought more typical of the 20 year

study period.

 

5

 250 MW has been the nominal capacity of plants having “1x1” (one gas turbine, one steam turbine) configuration using gas turbines

such as General Electric 7FA machines. Other configurations may have greater output. In addition, recent performance improvements

have lead to 1x1 ratings considerably in excess of 250 megawatts.

6

 The development of this factor is further described in Appendix F of the Fourth Northwest Conservation and Electric

Power Plan. The factor used here is the difference between the estimated cost of developing a single unit combinedcycle power plant at a Vancouver, WA site (the location of the actual River Road plant) and the average estimated cost

of developing units at the “Group 1” set of sites identified in the Fourth Plan. The Group 1 sites are those sites for which

construction permits were currently held or being sought at the time the Fourth Plan was in preparation. Group 1 sites

could accommodate from one to four 250 MM class units.
A - 12

Further adjustments for regional price differentials and elevation effects were made to arrive at

combined-cycle capital cost estimates for specific load and resource areas. The regional price indices shown

in the second column of Table A-8 are assumed to decline linearly from the 1997 values of Table 2 to a

uniform 100 by 2015. Because the output of a gas turbine is sensitive to ambient air density, capital costs

were further adjusted for the effect of elevation on atmospheric density, as shown in the third column of Table

A-8.

The resulting capital costs were used for the Council’s 1998 assessment of Bonneville cost and

revenues. Since that study, powerplant development activity has significantly increased. Turbine delivery

lead times from order are reported to be three years. An equilibrium or even a seller’s market now exists.

While reported power plant development costs have increased in response to the more active market, it does

not appear that costs have increased to the levels expected under equilibrium market conditions in the 1998

study. For this reason, the 1998 base case overnight capital cost assumption has been reduced 3 percent, to

$583 dollars per kilowatt capacity (1997 dollars) for purposes of this study.

Table A-8: Load and Resource Area Cost Adjustments

Load & Resource Area Regional price Indices

(1997, declines to zero by

2015)

Elevation–related Cost

Indices (Gas and wind

turbine technologies)

Western Oregon & Washington 100 102

Northern California 105 102

Southern California 105 102

British Columbia 105 110

Southern Idaho 100 110

Montana 100 119

Wyoming 102 119

Colorado 102 119

New Mexico 102 119

Arizona and southern Nevada 102 110

Utah 100 119

Northern Nevada 105 110

Alberta 105 119

Southwestern Public Services 102 119

Eastern Washington and Oregon and northern Idaho 100 102

Commercially available gas turbine power plants have not approached practical limits of cost or

thermodynamic efficiency. The cost of future plants is expected to decline over time as design, materials and

manufacturing processes improve. Other factors equal, increases in specific power increase the power

available from a machine of given physical size. This leads to per-unit-output capital cost reductions.

Forecast future improvements in the specific power of gas turbine combined-cycle plants were used to

estimate future cost reductions resulting from technology improvements7.

Because the advanced materials and manufacturing processes needed to increase specific power may

be more expensive than conventional materials and processes it is unlikely that future cost reduction will be in

direct proportion to improvements in specific power. Optimistic, expected and pessimistic forecasts of the

rate of future improvement in the specific power rating of gas turbines prepared for this study are shown in

Figure A-1. Fifty, 30 and 10 percent of the forecast increases in specific power were assumed to translate into

capital cost reductions for the low, base and high cases,

 

7

 Specific power is the power output of a turbine per unit mass of working fluid passing through the machine (e.g. kW/lb).
A - 13

Figure A-1: Historical and forecast specific power and capital costs for combined-cycle gas turbine power plants

respectively.

0

250

500

750

1000

1250

1500

1970 1980 1990 2000 2010 2020 2030 2040

Commercial Deployment

Specific Power (kJ/kg)

Capital Cost ($/kW)

Historic increase in specific power

Optimistic forecast of specific power

Base forecast of specific power

Pessimistic forecast of specific power

Forecast capital cost - High market

Forecast capital cost - Base case

Forecast capital cost - Low market

Operation and maintenance cost

The 1997 base year fixed and variable operating and maintenance (O&M) costs are based on 1995

estimates prepared for the Fourth Power Plan. The Fourth Power Plan fixed O&M costs were adjusted to the

1997 base year of this study using three factors. These include 1995 - 97 general inflation, the combinedcycle capital cost reduction forecast described above, and a operation and maintenance cost reduction factor of

2.5 percent annually, developed by the Energy Information Administration8 to account for observed

reductions in O&M attributable to increased competitive pressure. The resulting fixed O&M costs were

further adjusted by the regional price and elevation indices of Table A-8 to yield specific fixed O&M costs for

each load and resource area. Variable O&M costs were similarly derived from Fourth Power Plan estimates

except that elevation adjustments were not taken.

The fixed operating and maintenance costs of future plants are assumed to decline in proportion to the

capital cost technology improvement indices of Figure A-1 and the EIA competitive pressure cost reduction

factor (the latter through 2004). Variable O&M costs are assumed to continue to decline through 2004 by the

competitive pressure cost reduction factor.

 

8

 Energy Information Administration 1998 Annual Energy Outlook.
A - 14

Heat Rate

Combined-cycle plant heat rates are based on the measured “new and clean” performance of the River

Road plant. This value was derated to account for expected average performance degradation over the life of

a plant. This yielded a lifetime average heat rate typical of 1995-vintage equipment.

Commercially available gas turbine combined-cycle plants have not approached feasible

thermodynamic efficiency limits, and continued improvement in heat rate is expected9. Optimistic, expected

and pessimistic forecasts of heat rate improvements were developed, based on historic efficiency

improvements and theoretically achievable efficiency (Figure A-2).

Figure A-2: Historical and forecast specific heat for combined-cycle gas turbine power plants

5000

6000

7000

8000

9000

10000

11000

1960 1970 1980 1990 2000 2010 2020 2030 2040

Commercial deployment

Heat Rate, lifetime average, higher heating value (Btu/kWh)

Historic

Base forecast

Optimistic forecast

Pessimistic forecast

Ultimate achievable efficiency

Simple-cycle Combustion Turbine Power Plants

Simple-cycle combustion turbine power plant assumptions are based on 160-megawatt class industrial

units (e.g., General Electric Frame 7 machines). These plants are expected to operate primarily as peaking

units. The majority of simple-cycle units currently being developed in North America are of this class.

 

9Chiesa, Paolo, et. al. 1993. "Predicting the ultimate performance of advanced power cycles based on

very high temperature gas turbine engines". Presented at the International Gas Turbine and Aeroengine

Congress and Exposition, Cincinnati, OH, May 24 - 27, 1993.
A - 15

Capital Cost

The capital costs of new simple-cycle gas turbines are based on equipment-only gas turbine generator

set budgetary package prices appearing in the Gas Turbine World 1998-99 Handbook10. Handbook prices are

developed through discussions with architect/engineering firms, project developers and original equipment

manufacturers. These package prices are FOB factory and include a gas turbine, electric generator, starting

system, skid, enclosure, inlet filter, silencer and controls. Not included are substations, switchyards, gas

supply facilities, backup fuel storage facilities, administrative buildings, special emission controls, foundations

and civil works. Also not included are engineering, construction management and owner’s costs.

Per kilowatt turnkey project costs were estimated by averaging the equipment costs of the General

Electric 7FA and the Siemans V84-3A. gas turbine generators. The ABB GT24, another machine of this type,

was not included because only one of these machines was in service in the US at the time and price

information may be distorted by the price incentives frequently offered by equipment manufacturers to place

first-of-a-kind machines. For the base market case these prices were increased by a 10 percent market

equilibrium adjustment to account for the slack market conditions of the past several years.

Gas Turbine World estimates that balance-of-plant costs range from 60 to 100 percent of gas turbine

generator set costs. We assumed that on average balance-of-plant costs would be 80 percent of equipment

costs. Simple-cycle units are assumed to be constructed in pairs to obtain additional operating flexibility and

economies of scale. Based in earlier Bonneville studies, the cost of a second unit is estimated to be 75 percent

of a first unit. The resulting cost of a two-unit plant, derated by 2.6 percent to account for inlet, exhaust and

auxiliary equipment losses and further derated to account for average lifecycle output degradation, is

$333/kW.

Simple-cycle combustion turbine costs for the specific load and resource areas were obtained by

adjusting the general capital cost values by regional price and elevation indices of Table A-8.

The cost of future plants is assumed to decline over time with improvements to design, materials and

manufacturing. Forecast future improvements in combustion turbine specific power was used as a proxy for

technology improvement, as described for combined-cycle units. Ultimate, historical and forecast

improvements in simple-cycle combustion turbine specific power are shown in Figure A-3 along with our

forecast reduction in capital cost.

 

10 Gas Turbine World 1998-99 Handbook. Pequot Publications, Fairfield, Connetticut.
A - 16

Figure A-3: Historical and forecast specific heat and capital costs for simple-cycle gas turbine-generators

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

1300

1400

1500

1960 1970 1980 1990 2000 2010 2020 2030 2040

Commercial Deployment

Specific Power (kJ/kg)

Capital Cost ($/kW)

Ultimate technical potential (kJ/kg)

Historic Specific Power

Specific power - Pessimistic forecast

Specific power - Base forecast

Specific power - Optimistic forecast

Capital cost - Pessimistic forecast

Capital cost - Base forecast

Capital cost - Optimistic forecast

O&M cost

Operating and maintenance cost estimates are based on estimates for 80 megawatt-class simple-cycle

units prepared for the Fourth Power Plan. The fixed operating and maintenance cost for 160 megawatt units

was estimated by scaling the per kilowatt 80 megawatt-class estimates by the ratio of the capital costs.

Variable operating costs were assumed to be the same for both classes of plants. The resulting estimates were

further adjusted as described for combined-cycle units.

Heat Rate

Simple-cycle combustion turbine heat rates are based on nominal lower heat rate values reported in

the Gas Turbine World 1998-99 Handbook for the General Electric 7FA and the Siemans V84-3A. gas

turbine generators. The higher heat rate nominal average was increased by 1.11 to yield an higher heating

value heat rate. This value was derated for inlet, exhaust and auxiliary losses to yield a net heat rate of 10411

Btu/kWh. This “new and clean” value was further derated by 2.1 percent to yield a lifetime average value of

10630 Btu/kWh.

Plants delivered at future dates are assumed to benefit from improved technology. Three heat rate

improvement forecasts are based on pessimistic, expected and optimistic forecasts of combustion turbine

thermal efficiency improvements. Historical and forecast heat rates are shown in Figure A-4.
A - 17

Figure A-4: Historical and forecast specific heat and capital costs for simple-cycle gas turbine-generators

7000

8000

9000

10000

11000

12000

13000

14000

15000

1960 1970 1980 1990 2000 2010 2020 2030 2040

Commercial Deployment

Heat Rate, lifetime average, higher heating value (Btu/kWh)

Historic

Base forecast

Optimistic forecast

Pessimistic forecast

Ultimate achievable efficiency

Coal-fired Power Plants

Coal is the energy source for approximately 23 percent of the generating capacity of the WSCC

region. Coal resources are abundant and widespread within the WSCC. Major deposits are located in

Alberta, Montana, Wyoming, Utah, Colorado, Arizona and New Mexico. Most of these deposits occur as

thick, shallow seams, and can be produced at low cost using surface mining methods. Coal could supply the

electric needs of the WSCC region for several hundred years or more. The principal uncertainties facing

future development of coal-fired power plants is the cost of competing natural-gas fired combined-cycle

power generation and the effects of possible efforts to control production of carbon dioxide, a greenhouse gas.

Coal-fired electric power generating technologies considered for resource additions in this study

included pulverized coal-fired steam-electric plants and pressurized fluidized bed combustion power plants.

The pulverized coal-fired steam-electric plant is a mature power generating technology in use

throughout the west. It is a pure steam cycle and has attained its maximum practical efficiency at subcritical

steam pressures. Supercritical steam pressures would require costly materials to ensure reliable operation. At

this time it appears to be more economical to develop alternatives employing the inherently more efficient

gas-turbine combined cycle than to attempt to improve the efficiency of pure steam-electric technology.

A promising alternative to steam-electric coal technology is the pressurized fluidized bed combustion

(PFBC) combined-cycle power plant. In this technology, coal is combusted in a pressurized furnace. The

pressurized gaseous products of combustion are cleaned and used to power a gas turbine-generator. Steam,

produced both in the pressurized boiler and from the hot exhaust of the gas turbine powers a steam turbinegenerator. PFBC technology offers the advantages of higher thermodynamic efficiency, more compact size,

more opportunity for factory fabrication and lower cost compliance with air emission criteria. PFBC

technology is being demonstrated at several plants and is expected to be commercially available in the early

2000s. The representative PFBC technology used for the study is a single 340 megawatt unit, available for

commercial service in 2005.
A - 18

Earlier resource addition studies using AURORA suggested that new coal resources would not be

selected in the early years of the study, if at all. As modeled for this study PFBC plants, once commercially

available, are economically superior to conventional coal-fired steam power plants. Conventional coal-fired

power plants were thereafter omitted the set of new resource options used for this study.

Capital Cost

The capital cost for PFBC coal technology are based on 1995 estimates prepared for the Fourth

Power Plan. The Fourth Power Plan estimate was adjusted to the 1997 base year of this study using the 1995

- 97 general inflation and the combined-cycle capital cost reduction forecast described earlier. The resulting

cost was further adjusted by the regional price and elevation indices of Table A-8 to yield specific costs for

each load and resource area. (because PFBC plants utilize gas-turbine combined-cycle technology, we assume

that the technological improvement indices developed for natural gas-fired combined-cycle plants would also

apply to PFBC plants). The resulting base year capital cost is $1395/kW.

The technology improvement cost indices developed for gas-turbine combined-cycle plants were used

to derive the cost of future PFBC plants.

Operating costs

Operating and maintenance cost assumptions for coal technologies were derived from those

developed for the Fourth Power Plan as described for natural gas-fired power plants.

Heat rate

Heat rate assumptions for PFBC coal technologies were derived from those developed for the Fourth

Power Plan as described for natural gas-fired power plants

Solar Power Plants

Very high quality solar resources are found in Nevada, Utah and Arizona. Good quality resources are

found in the adjacent states. Electrical loads in the southern portion of the WSCC region are strongly affected

by irrigation and air conditioning. This results in strong daily and seasonal coincidence of solar resource and

electrical loads. Continued decline in the cost of photovoltaic module costs may eventually lead to the

development of plants for bulk power production.

While we are not aware of a comprehensive estimate of solar development potential for area within

WSCC, we assumed that several thousand megawatts of capacity could be sited within any of the loadresource areas. However, to expedite model operation, we assumed that large-scale central-station

photovoltaic development is not likely in the Western Washington and Oregon, British Columbia, Montana or

Alberta load-resource areas within the twenty-year period of this assessment. In general, these areas exhibit

poor load-solar resource coincidence.

The solar power plant assumptions used for this study are based on the estimates for 100 megawatt

central-station photovoltaic plant prepared for the Fourth Power Plan. Photovoltaics were chosen as the

representative solar technology because the technology is commercially available, current costs are known

and cost trends are evident. Other solar technologies that might achieve significant market penetration during

the study period include rooftop and other distributed photovoltaic applications and solar thermal technologies

such as power towers and Stirling dish power plants.
A - 19

These assumptions were considered preliminary. The intent was to refine these estimates if significant

amounts of central-station photovoltaic capacity was selected for development during any of the model runs.

Because significant development of photovoltaic resources did not occur in these studies, these initial

estimates were not modified.

Capital Cost

Capital costs were based on estimates prepared for the Fourth Power Plan, and include the estimated

cost of typical interconnection to the main grid. The Fourth Power Plan estimate was adjusted to the 1997

base year of this study using the 1995 - 97 general inflation and the photovoltaic technology capital cost

reduction forecast developed for the Fourth Plan. The resulting cost was further adjusted by the regional price

indices of Table A-8. The resulting base year cost is $3400/kW.

Photovoltaic system costs are expected to continue to decline as the technology improves and as

manufacturing capacity expands. The cost of future year development was calculated by extending the Fourth

Plan photovoltaic cost escalator through the study period.

Operating and Maintenance Costs

Operating and maintenance costs were based on estimates prepared for the Fourth Power Plan. Costs

were adjusted to 1997 dollars, but otherwise held constant in real terms over the study period.

Energy Production

Annual average capacity factors were based on performance estimates appearing in the Fourth Power

Plan for a photovoltaic plant sited at Whitehorse Ranch in southeastern Oregon, a good solar resource area.

The average annual capacity factor of this plant was estimated to be 21%. Annual average capacity factors for

other areas were assumed to be in proportion to the best average annual solar irradiation of the area in

question. The monthly shape factors for Whitehorse Ranch were used for all other areas.

Wind Power Plants

The wind resource of each load-resource area was characterized as one of three general types

identified in previous Council assessments of Pacific Northwest wind resources. “High Plains” resources are

typical of the high-elevation Great Plains east of the Rocky Mountains. These areas possess abundant very

high-quality wind resources, but are generally distant from major load centers. Examples include Medicine

Bow area of Wyoming and the Blackfoot area of north-central Montana. “Pacific Coast” resources are

scattered, but of high quality and relatively close to load centers. Examples include Altamont in the Bay Area,

the Columbia River Gorge and Cape Flattery of Washington’s Olympic Peninsula. “Basin & Range” wind

resources occur on ridges running perpendicular to prevailing winds. These can be of fairly high quality, but

are of limited extent and generally distant from load centers. Examples include Albion Butte in southern

Idaho and Pueblo Ridge on the Oregon/Nevada border.

Each of the 12 Aurora areas were characterized by the wind resource type appearing to be most

representative of the area (Table A-9).

Table A-9: Load and resource area wind resource assumptions
A - 20

Aurora Load & Resource Area Wind Resource Type Annual Capacity Factor Monthly Shape

Factor

Western Oregon & Washington Pacific Coast 30 % Cape Flattery, WA

Northern California Pacific Coast 30 % Flat

Southern California Pacific Coast 30 % Flat

British Columbia High Plains 35 % Horse Heaven, WA

Southern Idaho Basin & Range 24 % Albion Butte, ID

Montana High Plains 35 % Blackfoot, MT

Wyoming High Plains 35 % Blackfoot, MT

Colorado High Plains 35 % Flat

New Mexico High Plains 35 % Flat

Arizona and southern Nevada Basin & Range 24 % Flat

Utah Basin & Range 24 % Albion Butte, ID

Northern Nevada Basin & Range 24 % Pueblo, OR

Alberta High Plains 35 % Blackfoot, MT

Southwest Public Services High Plains 35 % Flat

Eastern Washington and Oregon

and northern Idaho

Pacific Coast 30 % Horse Heaven, WA

Capital Cost

Base year overnight capital costs of wind power plants are based on estimates prepared for the Fourth

Power Plan. In the Fourth Power Plan, wind power development costs were estimated for 48 promising wind

resource areas in the Northwest for which good resource and geographic data is available. The Fourth Plan

estimates include permitting, engineering, equipment, erection, overhead costs for wind farm development

and interconnection to the main grid. Though these estimates are several years old, they remain consistent

with current wind farm development costs. A representative development cost for each of the three types of

wind resources (“Pacific coast”, “basin and range” and “high plains”) was obtained by averaging the

development cost estimates for several Northwest resource areas of the respective type. The resulting

estimates were adjusted to the 1997 base year considering general inflation and a wind technology cost

reduction forecast prepared for the Fourth Power Plan. The resulting costs were further adjusted by the

regional price and elevation indices of Table A-8 to yield wind resource capital costs for each load and

resource area.

O&M cost

The base year fixed and variable O&M costs are based on estimates prepared for the Fourth Power

Plan. Operating and maintenance costs for the three types of wind resources were derived using the approach

described for capital costs. The resulting costs were adjusted to the 1997 base year using historical general

inflation, the Fourth Power Plan wind technology cost reduction forecast and EIA O&M cost reduction factor

described earlier. The resulting fixed O&M costs were further adjusted by the regional price and elevation

indices of Table A-8 to yield specific fixed O&M costs for each load and resource area. Variable O&M costs

were adjusted by the regional price indices only.

Capacity Factor

Representative capacity factors were calculated for each of the three types of wind resources by

averaging the estimated capacity factors for the Pacific Northwest sites chosen to characterize each type of

resource. The Fourth Power plan capacity factor estimates are based on annual average wind speeds and

performance curves of representative 1995 wind turbine technology. Correction is made for elevation, and in-
A - 21

farm and grid interconnection losses. The resulting annual average capacity factors are 30 percent for Pacific

coast resources, 24 percent for basin and range resources and 35 percent for high plains resources. Monthly

shape factors were applied to areas where records from representative wind resource areas were available

(Table A-9). Constant annual output was assumed for other areas.

Future improvement in wind turbine yields is captured in the capital and operating cost technology

improvement indices described above.

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