Tom Karier 

Chair 

Washington

Joan M. Dukes 

Vice-Chair 

Oregon

Frank L. Cassidy Jr. 

“Larry” 

Washington 

James A. Yost 

Idaho 

W. Bill Booth 

Idaho

Melinda S. Eden

Oregon 

Bruce A. Measure 

Montana 

Rhonda Whiting 

Montana

DRAFT 

Interim Wholesale Power Price Forecast 

November 19, 2007 

Council Document 2007-20 

851 S.W. Sixth Avenue, Suite 1100 Steve Crow 503-222-5161 

Portland, Oregon 97204-1348 Executive Director 800-452-5161 

www.nwcouncil.org Fax: 503-820-2370
This report describes an interim revision to the wholesale power price forecast of the Northwest 

Power and Conservation Council. This forecast incorporates revised fuel price forecasts, 

estimated renewable resource acquisitions in response to state renewable portfolio standards, 

and resource acquisitions needed to maintain target resource adequacy standards. This forecast 

supersedes the final wholesale power price forecast of the Fifth Power Plan. 

Summary of Findings 

The Council’s interim forecast of Mid-Columbia trading hub electricity prices, levelized for the 

period 2007 through 2026, is $35.50 per megawatt-hour. This is a 9 percent reduction from the 

base case forecast of the Fifth Power Plan (levelized value of $38.90 per megawatt-hour). 

Recently enacted state renewable portfolio standard (RPS) requirements are the biggest reason 

for the difference between these forecasts. 

A comparison of the interim base case forecast and various sensitivity case forecasts is shown in 

the following figure. 

0

10

20

30

40

50

60

70

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

2006$/MWh

Revised EPF Base Case 102307

Revised EPF Low Fuel 102307

Revised EPF High Fuel 102307

Revised EPF High CO2 Tax 102307

Revised EPF Low RPS 102307

Figure 1: Interim energy price forecast base case compared to sensitivity case forecasts

The levelized Mid-Columbia price for the low fuel price case is $29.90 per megawatt-hour, 16 

percent lower than the base case. The levelized Mid-Columbia price for the high fuel price case 

2
is $42.20 per megawatt-hour, 19 percent higher than the base case. The high CO2 tax case 

results in a levelized price of $46.50 per megawatt-hour. 

Background 

The Council prepares and periodically updates a 20-year forecast of wholesale electricity prices 

for the Pacific Northwest. This forecast is used to establish benchmark capacity and energy costs 

for conservation and generating resource assessments for the Council’s power plan. The forecast 

establishes the mean value electricity market price for the Council’s portfolio risk model and for 

the ProCost model used by the Regional Technical Forum to assess the cost-effectiveness of 

conservation measures. The forecasting model,1

 once updated and otherwise set up for the 

forecast, is used to support the analysis of issues related to power system composition and 

operation such as the effectiveness of greenhouse gas control policies. Finally, the Council’s 

price forecast is used by other organizations for assessing resource cost-effectiveness and for 

other purposes. 

The Council’s current wholesale power price forecast was developed following completion of 

the Fifth Power Plan resource portfolio in late 2004. That forecast used the electricity demand 

and fuel price forecast of the Fifth Power Plan as well as that plan’s resource costs and “mean 

resource development” portfolio.2

 Significant changes potentially affecting the price forecast 

have occurred since the development of the final price forecast of the Fifth Power Plan. These 

include unforeseen rapid escalation in the construction cost of many generating resources, 

sustained fuel prices above the medium forecast of the Fifth Power Plan, construction of 

substantial amounts of wind and combined-cycle capacity during a period of regional surplus of 

generating capacity, adoption of ambitious renewable portfolio standards by Oregon and 

Washington, and adoption of pilot regional energy and capacity reserve margin targets by the 

Resource Adequacy Forum. These changes affect future wholesale energy prices and impact the 

conventional use of long-term market prices as a determinant of resource cost-effectiveness. For 

these reasons, it is desirable to revisit the wholesale price forecast prior to beginning work on the 

Sixth Power Plan. 

The next update of the power price forecast is expected to follow development of the 

conservation and generating supply curves and the initial demand forecast for the Sixth Power 

Plan. The final Sixth Power Plan power price forecast will be prepared following development 

of the recommended resource portfolio. 

 

1

 The AURORAxmp Electric Market Model, available from EPIS, Inc. 2

 The resource portfolio of the Fifth Power Plan is not deterministic, but rather lays out an inventory of resources 

that would be developed as needed and cost-effective as the future unfolds. Except for the recommendations 

contained in the five-year action plan, there is no single resource development schedule in the Fifth Power Plan. 

The mean level of resource additions, for each year and resource type observed over the 750 futures tested in the 

portfolio risk model, was incorporated into the AURORA model for the final price forecast of the Fifth Power Plan. 

3
Approach and Assumptions 

The Council uses the AURORAxmp Electric Market Model to forecast wholesale electricity 

energy prices for the Pacific Northwest. The forecast is developed in a two-step process. First, 

using AURORAxmp long-term resource optimization logic, a forecast of resource additions and 

retirements is developed. In the second step, the forecasted resource mix is then dispatched on 

an hourly basis to serve forecast loads. The variable cost of the most expensive generating plant 

or increment of load curtailment needed to meet load for each hour of the forecast period 

establishes the forecast price. A more detailed description of the Council’s wholesale electricity 

price forecasting methodology is provided in Appendix C of the Fifth Power Plan. 

The Council recently updated its AURORAxmp software to version 8.4. As a result, this is the 

first time that the Council has implemented the capacity reserve margin capability of 

AURORAxmp.. The capacity reserve margin modeling is an extension of the long-term resource 

optimization logic and, therefore, impacts the first-step of the Council’s electricity price forecast 

process. Prior to this enhancement, the AURORAxmp optimization logic iteratively added new 

resources and retired existing resources based on the resource’s ability to cover its fully allocated 

going-forward costs at forecasted energy market prices. With the new enhancement, the 

AURORAxmp optimization logic not only builds resources to meet target planning reserve 

margins, but also simultaneously produces estimates of the capacity prices needed to achieve or 

maintain the target reserve margin. The resulting forecast of resource additions and retirements 

is now co-optimized for the revenues derived from the capacity prices, as well as hourly energy 

prices. 

The Council updated many of the key inputs used in the AURORAxmp model for the interim 

electricity price forecast. The starting point was the AURORAxmp configuration used in the 

Council’s recent CO2 Footprint Paper. This configuration is essentially the configuration 

described in Appendix C to the Fifth Power Plan, plus an updated inventory of existing WECC 

resources to reflect construction starts announced since adoption of the Fifth Power Plan in 

December 2004. This configuration was then updated to include coal and natural gas price 

forecasts from the Council’s recent Revised Fuel Price Forecast, and new resource capital cost 

estimates from the Council’s Biennial Assessment of the Fifth Power Plan. The schedule of 

resource additions was also updated to include renewable resources needed to fully meet state 

renewable portfolio standard (RPS) requirements. Finally, all of the model’s financial inputs 

were updated to account for recent price inflation and to consistently express the 20-year timeprofile of costs and revenues in constant 2006 dollars. 

Coal Prices

The Council forecast the variable cost of delivered coal for each load-resource zone defined in its 

electricity market model. The delivered coal cost is the sum of the wholesale price of Powder 

River Basin (PRB) coal plus the variable cost of transporting PRB coal to each load-resource 

zone. The Council issued its current forecast of PRB coal prices on September 11, 2007. The 

variable costs of transportation are based on average transportation rates for PRB coal and 

average shipment distances from Wyoming to each load-resource zone. 

4
The U.S. Energy Information Administration maintains the Coal Transportation Rate Database. 

The transportation rate for PRB coal shipments to electric utilities located in the Midwest census 

region averaged 10 mills per ton-mile for 2000-2001.3

 In order to protect the confidentiality of 

power producers, the average transportation rate for PRB shipments to electric utilities in the 

West census region was not reported. In its electricity market modeling, the Council used 9.8 

mills per ton-mile as the variable transportation rate for shipping PRB coal to the load-resource 

zones in the West.4

 

To estimate the variable transportation cost of delivering PRB coal to each of the modeled loadresource zones in the West, the variable transportation rate is multiplied by the average rail 

distance between Wyoming and the load-resource zones. The Council used average rail 

shipment distances for shipments originating in Wyoming from the U.S. Department of 

Transportation and U.S. Department of Commerce 2002 Commodity Flow Survey.5

 Coal 

shipments make up 98 percent of the ton-miles of rail transportation originating in Wyoming. 

Finally, the variable transportation cost was adjusted to reflect annual changes in the Council’s 

forecast of diesel fuel prices.6

 The following table shows the average rail shipment distances 

and variable transportation costs for delivering PRB coal to western load-resource zones. 

 

Table 1: Average Shipment Distance and Base Coal Transportation Rate by LoadResource Zone 

Load-Resource Zone

Average Rail 

Shipment 

Distance from 

Wyoming (Miles)

Base 

Transportation 

Rate 

(2006$/MMBtu)

Pacific Northwest - West PNWW 1,263 0.69

Pacific Northwest - East PNWE 1,009 0.55

Idaho ID 465 0.25

Montana MT 411 0.22

California - North CAN 1,233 0.67

California - South CAS 1,233 0.67

Nevada - North NVN 896 0.49

Nevada - South NVS 896 0.49

Wyoming WY 138 0.08

Utah UT 259 0.14

Colorado CO 517 0.28

Arizona AZ 958 0.52

New Mexico NM 762 0.42

British Columbia BC 1,300 0.71

Alberta AB 900 0.49

3

 U.S. Energy Information Administration (EIA), Coal Transportation Rate Database (CTRDB), Table 2.02 Coal 

Field to Census Division: Average Transportation Rates, Distances, and Costs for Contract Coal Shipments to 

Electric Utilities, by Coal Field and Census Division, 1979, 1990, 1999, 2000, 2001. 

4

 This rate reflects the 10 mill per ton-mile rate for Midwest utilities with an adjustment to remove the fixed costs 

associated with rail rolling stock. 

5

 U.S. Department of Transportation and U.S. Department of Commerce, 2002 Economic Census, 2002 Commodity 

Flow Survey, Wyoming, Issued December 2004. 

6

 Annual variable transportation costs are adjusted to reflect 25 percent of the annual change in the Council’s diesel 

fuel forecast. See the Council’s Revised Fuel Price Forecast, September 11, 2007. 

5
Natural Gas Prices

Natural gas prices from the Council’s recently revised fuel price forecast are used for this power 

price forecast. With the exception of Idaho and Montana, the assumptions used to develop loadresource area prices for AURORA are those used for the Fifth Power Plan. The approaches used 

to estimate Idaho and Montana natural gas prices were revised to better reflect the factors 

controlling gas prices in those two states. 

Previously, the Idaho load-resource area price was based on the Rocky Mountain hub price 

adjusted for a distance-based basis differential representing transportation on the Williams 

Northwest pipeline serving southern Idaho. For the current forecast, Idaho natural gas prices are 

based on Sumas hub prices and the basis differential used for the Northwest west of Cascades 

load-resource area. The resulting Idaho natural gas prices are therefore identical to the Pacific 

Northwest West gas prices. Underlying the revised approach is the fact that the Williams 

Northwest pipeline levies a constant “postage stamp” rate, hence prices along the pipeline ought 

not to be sensitive to distance. 

Montana gas prices, like those of Idaho in earlier forecasts, are based on the Rockies trading hub 

plus a distance-based basis differential. Montana utility staff have indicated that pipeline 

capacity to Montana would require expansion to accommodate any significant increase in gasfired generating capacity and that expansion would likely source Alberta gas. Hence, the 

Montana gas price in this study is based on AECO hub prices plus a basis differential equivalent 

to the basis differential used for the Pacific Northwest East (PNWE) load-resource area (PNWE 

gas prices are also based on the AECO hub because of the Alberta origin of the PGT pipeline 

serving the PNWE area). The revised natural gas prices for the Northwest load-resource areas 

are shown in Figure 2. 

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

2007 2012 2017 2022

2006$/MMBtu

PNW West/S. ID

PNW East/E. MT

Figure 2: Delivered natural gas prices for the Pacific Northwest load-resource areas 

(2006$/MMBtu)

6
New Resource Capital Costs

Prior to adoption of the Fifth Power Plan, the real capital cost of new resources had declined 

more or less continuously over a period of many years, driven by technology improvements, a 

buyer’s market, and a strong dollar. However, beginning in 2004, the capital cost of wind plants 

began to rise in real dollar terms. The Council, in its Biennial Assessment, identified a capital 

cost increase of 20 to 30 percent over the Fifth Power Plan base year costs for wind power. This 

increase was attributed to a weakening dollar, escalation in the price of commodities such as 

copper, steel, and cement used in power plant construction, and a shortage in skilled labor and 

specialized equipment used for construction of wind plants. The Council concluded that the 

observed cost increase was likely a cyclic phenomenon, and that costs would likely revert to 

trends identified in the Fifth Plan, unless the adoption of state resource portfolio standards 

continued to drive a seller’s market in wind power. At the time, fossil generation appeared to be 

only moderately affected by construction cost escalation. 

Power plant construction costs have continued to rise and now appear to have affected all forms 

of power generation. Pending the comprehensive resource assessment scheduled for 

development of the Sixth Power Plan, this forecast will use the resource cost assessment of the 

Biennial Assessment, with the exception of the cost escalation rates. With the exception of solar 

photovoltaics, these have been set to zero given the current uncertainty regarding future price 

trends. The base year (2006) resource construction costs used in this forecast are shown in Table 

2 compared to the equivalent costs of the Fifth Power Plan. 

Table 2: Revised capital costs for new resources (2006$/kW, 2010 service) 

Fifth Plan Biennial Assessment 

Gas turbines (Aeroderivative) $666 $676 

Gas turbines (Frame) $416 $422 

Combined-cycle $585 $591 

Pulverized coal (supercritical) $1449 $1457 

Integrated gasification combined-cycle $1725 $1750 

Solar photovoltaics $3288 $3288 

Wind power $912 $1500 

In addition to the changes in construction costs described above, the heat rates of supercritical 

pulverized coal and coal gasification power plants were revised as described in Appendix F of 

the Biennial Assessment. All new pulverized coal-fired power plants are now assumed to use 

supercritical technology. 

State Renewable Portfolio Standards

Since adoption of the Fifth Power Plan, renewable resource portfolio standards (RPS) have been 

established in Colorado, Oregon, and Washington. Currently, eight states within the WECC 

have RPS (Table 3). To model renewable portfolio standards in AURORA, assumptions must be 

made regarding the types of renewable resources that will be developed, and the success in 

7
achieving the targets. For the Fifth Power Plan power price forecast, RPS states were assumed to 

meet 75 percent of their target levels of renewable resource development. Because of much 

greater public concern regarding greenhouse gas control, expanded initiatives for renewable 

resource development, prospects for even more aggressive RPS in some states, and indications 

that utilities will be able to achieve the initial target levels of development in most RPS states, 

100 percent achievement of RPS targets was assumed for the base case of this forecast. A 

sensitivity analysis assuming 75 percent achievement of RPS targets was also run. Target levels 

of renewable resource development and the assumptions regarding the resource mix for this 

study are shown in Table 3. 

Table 3: Renewable portfolio standard basic targets and resource mix assumptions 

Basic Standard (load-based) Assumed Mix 

Arizona 15% by 2025 33% biomass 

67% solar PV 

California 20% by end of 2010 75% biomass (N. CA) 

50% geothermal (S. CA) 

25% solar PV (S. CA) 

25% wind 

Colorado 20% by 2020 (IOUs) 

10% by 2020 (COUs) 

33% biomass 

67% wind 

Montana 15% by 2015 10% biomass 

90% wind 

New Mexico 20% by 2020 (IOUs) 

10% by 2020 (Co-ops) 

33% biomass 

67% wind 

Nevada 15% by 2015 100% geothermal (N. NV) 

50% geothermal (S. NV) 

50% solar (S. NV) 

Oregon 25% by 2025 (large utilities) 20% biomass 

80% wind 

Washington 15% BY 2020 15% biomass 

85% wind 

Planning Reserve Margin

The AURORAxmp model provides the capability to perform optimized long-term system 

expansion studies to achieve and maintain planning reserve margin targets. The studies provide 

an optimized build-out of system resources and estimates of annual capacity prices needed for 

the marginal capacity resources to economically supply capacity to the system. 

AURORAxmp requires planning reserve margin targets to be based on the single highest hour of 

demand during the year. Reserve margin targets can be set at both the load-resource zone and 

operating pool level and the optimization logic can be set to either meet or exceed the target or to 

minimize the deviation from the target. 

8
The Council has configured AURORAxmp to simulate power plant dispatch in 18 load-resource 

zones that make up the WECC electric reliability area. Planning reserve margin targets are 

specified for two operating pools: (1) the Pacific Northwest region that comprises 6 loadresource zones; and (2) the California Independent System Operator (CA ISO) that comprises 2 

load-resource zones. The remaining 10 load-resource zones were given individual reserve 

margin targets. For the CA ISO and 10 stand-alone zones, the planning reserve margin target 

was set at 15 percent. All of the planning reserve margin targets were set as minimums that are 

to be met or exceeded in the long-term system expansion studies. 

For the Pacific Northwest, the Council configured AURORAxmp to reflect the capacity standard 

of the Pacific Northwest Power Supply Adequacy Forum (Adequacy Forum). The Adequacy 

Forum has determined that reserve margin targets of 25 percent in winter and 19 percent in 

summer correspond to an overall system loss-of-load probability of 5 percent. 

These reserve margin targets cannot, however, be directly used in AURORAxmp. The Adequacy 

Forum targets reflect a specific set of resource and load assumptions that cannot be easily 

replicated in AURORAxmp. For example, the Adequacy Forum reserve margin targets are based 

on consideration of the highest average demand for a 50-hour peak period, while the 

AURORAxmp targets are based on consideration of the single highest hour of demand. 

For electricity price forecasting purposes, the Council converted the Adequacy Forum’s 

multiple-hour capacity reserve margin targets to a single-hour target. Adjustments were also 

made to reflect consistent treatment of spot market imports, hydro conditions and flexibility, and 

Independent Power Producer (IPP) generation. The converted single-hour capacity reserve 

margin for the Northwest is 18 percent. 

Conversion of the Adequacy Forum’s capacity reserve margin targets does not reflect a change 

in adequacy standards. Both the Adequacy Forum’s targets and the targets used in AURORAxmp

reflect an overall loss-of-load probability of 5 percent for the Northwest. 

AURORAxmp also provides the capability to set the contribution that each resource can make 

towards meeting the reserve margin target. The Council configured the model to limit the singlehour capacity contribution of Pacific Northwest hydro resources to 88 percent of nameplate 

capacity. The limit for wind and solar power resources was set at 15 percent of nameplate 

capacity. 

Base Case and Sensitivity Case Forecasts

This interim wholesale power price forecast includes a base case forecast and several alternative 

cases which test the sensitivity of the base forecast to changes in input assumptions. The base 

case and all of the sensitivity cases include the revised capital costs from the Biennial 

Assessment of the Fifth Plan. These fixed costs impact the long-term forecast of resource 

additions and retirements and the associated capacity prices for each of the cases. 

The base case electricity price forecast uses the Council’s revised medium coal and medium 

natural gas price forecasts and the schedule of resource additions needed to fully achieve state 

RPS requirements. Post-Fifth Power Plan resource additions, plus the schedule of RPS resource 

9
additions, fully replace the final portfolio of resource additions of the Fifth Power Plan used in 

prior Council configurations of AURORAxmp. Other base case assumptions are consistent with 

those used in the Fifth Power Plan. 

The sensitivity analysis starts with the base case assumptions and changes a single model input. 

Sensitivity cases include high and low fuel price cases, a high CO2 tax case, and a low RPS 

achievement case. The low RPS achievement case assumes 75 percent of state RPS targets are 

met. 

The CO2 tax case uses the maximum CO2 tax trajectory from the Fifth Plan. The following 

figure compares the CO2 tax trajectories of the base case and high CO2 tax case. 

0

5

10

15

20

25

30

35

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

2006$/short ton

High CO2 Taxes

Base CO2 Taxes

Figure 3: Base and high CO2 tax cases 

10
Findings 

Energy price forecast 

The forecast Mid-Columbia trading hub price, levelized for the period 2007 through 2026, is 

$35.50 per megawatt-hour. In the following figure, the current forecast is compared to the base 

case forecast of the Fifth Power Plan (levelized value of $38.90 per megawatt-hour) and the base 

case of the Biennial Assessment (levelized value of $38.80 per megawatthour).

0

10

20

30

40

50

60

70

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

2006$/MWh

5th Plan Final Base 120704 (Mid-C)

Biennial Assessment Base case 090606 (Mid-C)

Revised EPF Base Case 102307

Figure 4: Interim energy price forecast base case compared to previous base case forecasts 

The interim forecast prices decline from 2007 highs as new renewable resources with relatively 

low variable operating costs are added to the system to meet state RPS requirements. 

The low variable cost of resources added to satisfy state RPS requirements are the biggest reason 

for the difference between the interim base forecast and the previous base forecasts. The 

following figure shows the annual energy output of RPS and other planned new resources for the 

period 2007 and 2026. 

11
 

0

500

1,000

1,500

2,000

2,500

3,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

MWa

RPS Renewables

New/Planned Renewables

New/Planned NG

Figure 5: Forecast energy output of Pacific Northwest resource additions 2007-26

Annual average prices conceal likely episodic price excursions due to natural gas price volatility 

or deviations from average hydro conditions. They also conceal important seasonal and time-ofday price variation. The monthly average prices shown in the following table reveal the seasonal 

and time-of-day variation. 

12
0

10

20

30

40

50

60

70

2007_01

2008_01

2009_01

2010_01

2011_01

2012_01

2013_01

2014_01

2015_01

2016_01

2017_01

2018_01

2019_01

2020_01

2021_01

2022_01

2023_01

2024_01

2025_01

2026_01

2006$/MWh

NPPC On-peak

NPPC Off-peak

Average

Figure 6: Forecast Mid-Columbia average monthly energy prices

The spread between on-peak and off-peak prices, which averages nearly $15 per megawatt-hour 

over the forecast period, appears to be larger than that experienced in recent history. The 

Council will continue to investigate this result and provide an explanation in the final version of 

this paper. 

The value of power varies by time of day and day of week because the marginal power plant 

changes with load. Gas-fired power plants with relatively high variable costs are typically on the 

margin during heavier load hours, whereas coal-fired plants with lower variable costs are 

frequently on the margin during nighttime and weekend low load hours. The Council and the 

Regional Technical Forum use four load segments for assessment of the cost-effectiveness of 

conservation measures--many of which are most effective at specific times of day. Figure 7 

shows the levelized base case price forecast for the four load segments. 

13
$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

All hours NPPC Segment 1 NPPC Segment 2 NPPC Segment 3 NPPC Segment 4

Levelized 2006$/MWh

Seg 1 : M-F Hr 9 - 18

Seg 2: M-F Hr 5 - 8; 19 - 22; Sa & Su 5 - 22

Seg 3: M-F Hrs 1 -4; 23 & 24

Seg 4: Sa & Su Hrs 1 - 4; 23 & 24

Figure 7: Forecast Mid-Columbia levelized energy prices by load segment

Sensitivities 

In all of the Council’s sensitivity cases the future resource mix of the Pacific Northwest is 

invariant with respect to forecast electricity prices. This is a direct result of the level of 

renewable resources being added to the system to meet state RPS requirements. This, combined 

with recent construction, appears to satisfy all energy and capacity needs, at least on a regional 

basis (additional thermal capacity may eventually be needed for integration of intermittent 

renewable resources). The forecast annual average energy prices for the base and sensitivity 

cases are plotted in the following figure. 

14
0

10

20

30

40

50

60

70

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

2006$/MWh

Revised EPF Base Case 102307

Revised EPF Low Fuel 102307

Revised EPF High Fuel 102307

Revised EPF High CO2 Tax 102307

Revised EPF Low RPS 102307

Figure 8: Interim energy price forecast base case compared to sensitivity case forecasts

The levelized Mid-Columbia price for the low fuel price case is $29.90 per megawatt-hour, 16 

percent lower than the base case. The levelized Mid-Columbia price for the high fuel price case 

is $42.20 per megawatt-hour, 19 percent higher than the base case. 

The high CO2 tax case results in a levelized price of $46.50 per megawatt-hour. 

The levelized price for the low RPS case is $34.90 per megawatt-hour. This is 2 percent lower 

than the base case which assumes full achievement of RPS requirements. The reason for this 

difference is not currently understood. The Council will continue to investigate this result and 

provide an explanation in the final version of this paper. 

15
Capacity Price Forecast 

The following figure shows the simulated annual peak-demand-hour reserve margin for the 

Pacific Northwest from the base case price forecast. 

0

5

10

15

20

25

30

35

40

45

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Percent

Figure 9: Forecast Pacific Northwest Annual Peak-hour Capacity Reserve Margin 

The reserve margins are well above the capacity target of 18 percent for most of the planning 

period. This result reflects the current surplus position in the region and the addition of RPS 

resources over the planning period. The long-term optimization logic of AURORAxmp does not 

add any new resources to this part of the system during the planning period. 

The following chart shows the nameplate capacity of RPS resources and other new or planned 

resources for the period 2007 through 2026. 

16
0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

MW

RPS Renewables

New/Planned Renewables

New/Planned NG

Figure 10: Forecast Nameplate Capacity of Pacific Northwest Resource Additions 2007-26 

In the Council’s configuration of AURORAxmp, the capacity contribution of wind resources is set 

at 15 percent. Recent experience in the Pacific Northwest suggests that the capacity contribution 

of wind may be dramatically lower. 

Preliminary sensitivity analysis using a wind capacity contribution value of 5 percent resulted in 

new resource development in the Pacific Northwest during the period 2027 through 2031. This 

is the five-year period added to the end of the forecast period to improve long-term resource 

optimization. The resource development consisted of 300 megawatts of new wind resources, 

100 megawatts of solar resources, and 1,450 megawatts of natural gas peaking resources. The 

Northwest Wind Integration Forum is currently investigating the capacity value of wind. The 

Council will continue to analyze the impact of this capacity contribution on long-term resource 

development in the Sixth Power Plan. 

AURORAxmp not only builds resources to maintain operating pool and load-resource zone 

capacity reserve margin targets, it also provides estimates of the annual capacity prices needed 

for the marginal capacity resources to economically supply capacity to the system. The 

AURORAxmp capacity prices represent the payment that would be necessary to allow the 

marginal capacity resource to recover its total costs for the operating year. In other words, the 

capacity prices represent the above-energy-market cost of the marginal capacity resource. 

 It is helpful to think of the AURORAxmp capacity price calculation as occurring in a simplified 

progression of steps: 

17
1) Estimate the annual operating profit and peak-hour capacity contribution for each 

resource in an operating pool or zone. 

2) Rank the resources from most profitable to least profitable and calculate the operating 

pool or zone’s cumulative peak-hour capacity. 

3) Identify the single highest hour of demand for the operating pool or zone and add the 

applicable capacity reserve margin to establish the capacity target for the pool or zone. 

4) Identify the least profitable resource that provides capacity to meet the capacity target on 

the peak-hour of the year. This is the marginal capacity resource. 

5) If the marginal capacity resource has a negative operating profit for the year, then set this 

amount as the capacity price for the operating pool or zone. If the marginal capacity 

resource has a positive operating profit for the year, then set the capacity price to zero. 

The capacity price is the payment amount necessary to make the marginal capacity resource 

whole for the operating year. 

The following figure shows the estimated capacity prices for each of the load-resource zones in 

the Pacific Northwest region from the base case forecast. The average of the load-resource zone 

prices is an estimate of the overall pool prices. Capacity prices for the Northwest Power Pool are 

estimated to remain at zero through 2013 and then to increase to nearly $17 per kW-year by 

2026. 

0

5

10

15

20

25

30

35

40

45

50

55

60

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

2006$/kW-yr

PNW - Eastside North

PNW - Idaho South

PNW - Montana

PNW - Westside North

PNW - Westside South

PNW - Eastside South

PNW - Power Pool

Figure 11: Interim Capacity Price Forecast for the Northwest Region 

18
Interpretation and Recommendations 

Given the current surplus load-resource balance in the Pacific Northwest and the expected 

addition of renewable resources to achieve state RPS requirements, the region can expect lower 

wholesale electricity prices in the future. Adding significant amounts of wind and other 

renewable resources with low variable costs to the Pacific Northwest resource mix should result 

in lower-cost resources clearing the market, and setting market prices, during many hours of the 

year. These lower market-clearing prices will not, however, reflect the capital and other fixed 

costs associated with bringing the RPS resources on-line. These costs will presumably need to 

be covered in bi-lateral contracts or through utility rate base. 

The Council’s interim long-term power price forecasts reflect these market fundamentals. The 

forecasted energy and capacity prices are insufficient to cover the total cost of the marginal 

qualifying RPS resource. Because of this, the conventional use of long-term market prices as a 

determinant of resource cost-effectiveness needs to be revisited. In the future, at times when 

state RPS requirements are driving new resource additions, the avoidable resource will normally 

be the fully allocated cost of the marginal qualifying RPS resource. However, there may be 

periods when regulation and load-following capacity is needed to integrate wind and other 

intermittent renewable resources. The least-cost resource providing these services may be the 

marginal new resource at these times. 

The fully-allocated cost of the “generic” new renewable resources assumed to be developed to 

meet state renewable portfolio standards in this forecast are illustrated in Figure 12. Though the 

fully allocated cost of generic biomass and geothermal resources are lower than that of wind, the 

former are typically limited in availability so wind power is expected to set the “RPS avoided 

cost.” The costs of actual projects will, of course, vary, sometimes widely from the generic 

resource costs used in this forecast. 

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$0

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2007 2012 2017 2022

Levelized Energy Cost (2006$/MWh)

Wind

Biomass

Geothermal

Figure 12: Annual levelized fully allocated RPS renewable resource cost (2006$/MWh) 

The value of the marginal resource at times RPS requirements are satisfied, or when integration 

services are required, consists of its energy market value, its capacity value, and the value of any 

intra-hour ancillary services it may provide. These intra-hour ancillary services, for example, 

regulation and load-following services, are likely to increase in value as more RPS wind 

resources are added to the regional resource mix. 

The Council will continue to explore these issues during development of it upcoming Sixth 

Power Plan. 

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p:\mw\ww\electricity price forecast nov07.doc 

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