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

W. Bill Booth 

Chair 

Idaho

Bruce A. Measure 

Vice-Chair 

Montana

James A. Yost 

Idaho 

Tom Karier 

Washington 

Dick Wallace 

Washington

Rhonda Whiting 

Montana 

Melinda S. Eden

Oregon 

Joan M. Dukes

Oregon 

INTERIM WHOLESALE POWER PRICE 

FORECAST 

MARCH 6, 2008 

Council Document 2008-05 
Interim Wholesale Power Price Forecast 

This report describes an interim revision to the Northwest Power and Conservation Council’s 

wholesale power price forecast. This forecast incorporates revised fuel price forecasts, 

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

resource acquisitions needed to maintain target resource adequacy standards, and revised 

estimates of the future cost of CO2 production. This forecast supersedes the final wholesale 

power price forecast of the Fifth Power Plan. This forecast will be updated as the development 

of the Sixth Plan progresses. 

INTRODUCTION 

The Northwest Power and Conservation Council forecasts regional wholesale power market 

prices as part of its electric power and conservation planning process. The power price forecast 

is a key input to the Council’s portfolio risk model that is used to assess various future resource 

development strategies. The price forecast is also used for preliminary estimates of the costeffectiveness of conservation and generating resources. The price forecast has also been used for 

planning and resource assessment by utilities and other organizations. The wholesale price 

forecast presented in this paper is an interim forecast primarily intended for preliminary analyses 

leading up to the Council’s Sixth Power Plan. The forecast will be revisited as refined 

assessments of demand, generating resource costs, performance, and availability and other 

factors become available during development of the Sixth Power Plan. 

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

period 2007 through 2026, is $39.90 per megawatt-hour (in year 2006 dollars).1

 This is a 2.6 

percent increase from the base case forecast of the Fifth Power Plan (levelized value of $38.90 

per megawatt-hour). A comparison of the interim base case forecast and various sensitivity case 

forecasts is shown in Figure 1. Each sensitivity case varies a single model input. Sensitivity 

cases include: a high CO2 cost case, high and low fuel price cases, and a 75 percent renewable 

portfolio standard (RPS) achievement case. A sensitivity case that eliminated incremental RPS 

resource development was run to illustrate the impact of RPS resource additions on wholesale 

power prices. 

 

1

 All dollar values appearing in this paper are in year 2006 dollars unless otherwise indicated. 
Interim Wholesale Power Price Forecast 

3

Figure 1: Interim base case and sensitivity case forecasts 

0.00

10.00

20.00

30.00

40.00

50.00

Low Fuel Price Case

Low CO2 Price Case

Base Case

75% RPS Achievement Case

High Capital Cost Case

No Incremental RPS Case

High Fuel Price Case

High CO2 Price Case

Levelized 2006$/MWh

An important finding of this paper is that Northwest ratepayers and utilities are likely to see, at 

the same time, declining wholesale power prices and rising retail rates in the near-term. This 

divergence between wholesale power prices and retail electricity rates is the result of the 

renewable portfolio standards (RPS) recently implemented in Montana, Oregon, Washington, 

and many other Western states. 

The mandated addition of large amounts of renewable generating resources to the Western power 

system can be expected to dampen wholesale power prices. As a result, wholesale prices are 

forecast to be insufficient to cover both the construction and operating costs of new renewable 

resources needed to comply with RPS requirements. However, in the retail marketplace, where 

electricity rates are predominately cost-based, the Pacific Northwest will likely see increasing 

rates as the full cost of the new RPS resources, including the capital, construction, and operating 

costs, are included in utility rates. 

Importantly, though wholesale power prices are expected to be relatively low, the Council is not 

recommending that regional utilities plan to rely on wholesale market purchases to meet 

expected load growth. A resource strategy that relies heavily on the wholesale power markets 

can carry significant risk. In the upcoming Sixth Power Plan, the Council will use its portfolio 

risk model to evaluate various resource strategies for the region, and it will adopt a final action 

plan for future resource development. 

The divergent direction of wholesale power prices and retail electricity rates also has important 

implications for the conservation cost-effectiveness analysis. The direct use of the Council’s 

forecasted power prices as “avoided costs” in conservation and generating resource assessments 

may no longer be appropriate for many utilities. This paper discusses a potential new avoidedcost methodology that blends forecast wholesale power prices and the full cost of RPS resource 
Interim Wholesale Power Price Forecast 

4

development to arrive at an overall avoided cost for utilities with RPS obligations. The Council 

intends to consider this issue more fully during development of the Sixth Power Plan. 

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,2

 once updated and otherwise set up for the 

forecast, is also 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 wholesale power price forecast was last fully updated 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 its resource costs and “mean resource 

development” portfolio.3 An update of the Fifth Power Plan forecast incorporating higher nearterm natural gas prices and new resource development through early 2006 was developed for the 

Biennial Monitoring Report of the Fifth Power Plan. Significant changes potentially affecting the 

price forecast have occurred since that review. 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, as well as 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 will follow the 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. 

APPROACH AND ASSUMPTIONS 

The Council uses the AURORAxmp® Electric Market Model4 to forecast wholesale electricity 

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

 

2

 The AURORAxmp Electric Market Model, available from EPIS, Inc. 3

 The resource portfolio of the Fifth Power Plan is not deterministic, but rather lays out an inventory of costeffective resources that would be developed as needed in the future. 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. 

4

 Available from EPIS, Inc. (www.epis.com). 
Interim Wholesale Power Price Forecast 

5

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, affects 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 a 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 

now depends on the revenues derived from the capacity prices, as well as the 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. Essentially, this is the configuration described in 

Appendix C of the Fifth Power Plan, plus an updated inventory of existing Western Electricity 

Coordinating Council (WECC) area resources to include 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,5

and new resource capital costs estimates from the Council’s biennial assessment of the Fifth 

Power Plan. The schedule of resource additions was also updated to include resources needed to 

fully meet state renewable portfolio standard requirements. Finally, the model’s financial inputs 

were updated to account for recent price inflation and to consistently express the 20-year time 

profile of costs and revenues in constant 2006 dollars. 

Coal Prices 

The Council forecasts the variable cost of delivered coal to 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. 

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 

 

5

 Northwest Power and Conservation Council. Document 2007-14, “Revised Fuel Price Forecasts.” September 

2007. 
Interim Wholesale Power Price Forecast 

6

region averaged 10 mills per ton-mile for 2000-2001.6

 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.7

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 the U.S. Department of Commerce 2002 Commodity Flow Survey.8 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.9 The following table shows the average rail shipment distances and 

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

 

6

 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. 

7

 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. 

8

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

Flow Survey, Wyoming, Issued December 2004. 

9

 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. 
Interim Wholesale Power Price Forecast 

7

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 

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 convert 

natural gas commodity prices into delivered load-resource area prices for AURORAxmp 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 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 the Cascades loadresource area. The resulting Idaho natural gas prices are therefore identical to the western 

Pacific Northwest gas prices. Underlying this 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.10

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

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

 

10 Subsequent to setting up the AURORAxmp model for these price forecasts, the derivation of Idaho natural gas 

prices was again revised to use the Rockies trading hub as a basis. Though not reflected in this forecast, this 

revision is unlikely to substantially affect the results reported in this paper. The new derivation of Idaho prices will 

be used for the development of the Sixth Power Plan. 
Interim Wholesale Power Price Forecast 

8

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

Montana gas price in this study is based on Alberta’s 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 loadresource areas are shown in Figure 2. 

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

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

2007

2008

2009

2010

2011

2012

2013

2014

2015

20162017

2018

2019

2020

2021

2022

20232024

2025

2026

2006$/MMBtu

PNW West/S. ID

PNW East/E. MT

Carbon Dioxide Emission Prices 

In the Fifth Power Plan, the Council’s estimates of the cost of CO2 offsets were guided by the 

CO2 offset experience of Oregon and Washington, the conclusions of a Council-sponsored 

workshop held in May 2003, a June 2003 MIT study of the cost of implementing the proposed 

McCain-Lieberman Climate Stewardship Act, and an August 2003 MIT study of the costs of 

CO2 sequestration. The range of estimates of CO2 control costs from these sources is very wide. 

The Oregon and Washington offset payments were about $0.87 per ton CO2 for Oregon and 

$2.10 per ton CO2 for Washington. The MIT estimates of the costs of compliance with the 

Climate Stewardship Act ranged from zero to $39 per ton CO2 in 2010, $10 to $70 per ton CO2

in 2015, and $13 to $86 per ton CO2 in 2020. The Council workgroup estimated offset credits on 

the international market to range from $5 to 10 per ton CO2 in the 2005 - 2013 timeframe, and 

$20 to $40 per ton CO2 from 2010 - 2025. Finally, the MIT study on the costs of CO2

sequestration estimated costs ranging from $2 to $23 per ton CO2 for various forms of geologic 

sequestration (2000 dollars). 

The Council incorporated this uncertainty into its power system planning by modeling future 

CO2 emissions prices probabilistically. In the Council’s portfolio risk model, future carbon 

emission prices were randomly selected from between zero and $15 per ton if carbon regulation 
Interim Wholesale Power Price Forecast 

9

was enacted between 2008 and 2016; and between zero and $30 per ton if regulation was enacted 

after 2016 (in 2004 dollars). This modeling produced 750 possible future trajectories of CO2

emission prices. 

In subsequent wholesale power price forecasts, the Council used the average of the 750 

trajectories as its base case CO2 emissions price forecast. Base case CO2 emission prices 

gradually increased from zero dollars per ton in 2007 to $7.92 per ton in 2026 (levelized value of 

$3.50 per ton in 2006 dollars). 

In developing the revised base case estimates of future CO2 emission prices for this forecast, 

Council staff considered the range of cap and trade proposals introduced in the 110th Congress. 

Staff considered future adoption of the most restrictive or most lenient proposals to be unlikely. 

Staff identified the “safety valve” price in the Low Carbon Economy Act, put forth by Senators 

Bingaman and Specter, as a reasonable mid-range forecast.11

The Bingaman-Specter legislation would cap CO2 emissions at 2006 levels in 2020 and at 1990 

levels in 2030. These caps are less stringent than those in other proposed legislation introduced 

in the 110th Congress. However, unlike the other proposals, which include generic measures 

designed to release the CO2 emissions cap if the cost of compliance becomes unacceptably high, 

the Bingaman-Specter legislation specifically identifies a cost of compliance that triggers 

regulatory relief. Council staff concluded that the Bingaman-Specter “safety valve” price would 

likely be economically sustainable over the forecast period, and therefore represent a good 

interim base case forecast. 

In the revised base case, CO2 emission prices jump from zero dollars per ton in 2007 to $10.35 

per ton in 2012, and then gradually increase to $14.50 per ton in 2026. The levelized value of 

$7.80 per ton is a 123 percent increase above the previous base case value. The Fifth Power Plan 

average price trajectory is now used as a low CO2 emission price sensitivity case. We also 

model a high CO2 emission price case with a levelized value of $28.00 per ton. The following 

figure compares these three cases. 

 

11 The “safety valve” price (called a “technology accelerator payment” in the Act) is $12 per ton in 2012 and would 

increase at 5 percent above inflation annually. 
Interim Wholesale Power Price Forecast 

10

Figure 3: CO2 emissions prices in base and sensitivity cases 

The Council will further evaluate CO2 emission prices during development of the Sixth Power 

Plan. 

 New Resource Capital Costs 

The real (constant dollar) capital costs of most new generating resource technologies had 

declined on average for many years prior to 2004. These declines were driven by factors 

including technology improvements, production economies, buyer’s markets, and a strong dollar. 

Anticipating continuation of this declines, the Council, in its Fifth Power Plan for most 

generating resources forecast continued real cost reductions based on historical rates of real cost 

de-escalation. 

Beginning in 2004, power plant construction costs began to rise in real dollar terms. This 

increase was first evident in the cost of wind power development. In its 2006 Biennial 

Monitoring Report of the Fifth Power Plan, the Council 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 for construction of wind plants resulting from strong demand. The Council concluded 

that the observed cost increases were likely cyclic and costs would revert to trends identified in 

the Fifth Power Plan unless the adoption of state resource portfolio standards continued to drive 

a strong seller’s market in wind power. At the time, fossil fuel generation technologies appeared 

to be only moderately affected by escalating construction costs. 
Interim Wholesale Power Price Forecast 

11

The base case of this forecast uses the resource capital costs of the biennial monitoring report. 

With the exception of solar photovoltaics, no real reduction in cost is assumed given the 

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. 

Power plant costs have continued to rise in real terms, and have now affected nearly all forms of 

power generation with the exception of solar photovoltaics. The cost of power from capitalintensive options such as coal-fired power generation will be more significantly affected than the 

cost of power from less capital-intensive generation such as natural gas combined-cycle plants. 

This will potentially shift future resource choice compared to that of the base case, and may 

increase the price forecast. For these reasons a high capital cost sensitivity analysis was run. 

The high capital cost case used preliminary resource construction cost estimates for initial 

development of the Sixth Power Plan. High capital cost base year capital costs are compared to 

the base case and Fifth Power Plan assumptions in Table 2. The forecast cost trajectories for the 

high capital cost case are shown in Figure 4. Costs to the left of the vertical bar in the figure are 

based on historical values; those to the right are forecast. Costs are assumed to continue to 

increase in real terms until 2009, level, then decline through 2015 to equilibrium levels about 

30% higher (in real terms) than 2005. Following 2015, costs resume trajectories reflecting the 

technology improvement rates of the Fifth Power Plan.12

The years shown on the horizontal axis of Figure 4 represent the vintage of the cost estimate. 

Construction costs are assumed to be fixed at the beginning of construction, so that the cost of a 

plant of given vintage will depend on the construction period. Thus, a wind project completed in 

2015 is assumed to incur 2014 vintage construction costs (plus any general inflation), reflecting 

the one-year construction period typical of a wind project. In contrast, an IGCC plant completed 

in 2015 is assumed to incur 2011 construction costs because of its four-year construction period. 

Table 2: Overnight base year (2006) capital cost assumptions for new resources 

(2006$/kW) 

Fifth Power 

Plan 

Biennial 

Assessment 

High Capital 

Cost Case 

Gas turbines (aeroderivative) $680 $680 $840 

Gas turbines (frame) $420 $420 $520 

Combined-cycle $590 $590 $730 

Pulverized coal-steam $1,450 $1,450 $1,900 

Integrated gasification 

combined-cycle (without CS)13 $1,620 $1,750 $2,100 

Integrated gasification 

combined-cycle (with 90% CS) $2,090 $2,300 $2,700 

Solar photovoltaics $4,920 $3,288 $5,820 

Wind power $910 $1,500 $1,650 

 

12 An exception is the technology improvement curve for solar photovoltaics. The rate of cost reduction for solar 

photovoltaics is assumed to decline through time in the high capital cost case compared to the constant rate of 

decline assumed for Fifth Power Plan. 

13 CS: CO2 separation and compression (excludes the capital cost of CO2 pipeline and storage) 
Interim Wholesale Power Price Forecast 

12

Figure 4: Historic and forecast overnight capital costs for high capital cost case (2006$) 

0

1000

2000

3000

4000

5000

6000

7000

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Vintage of Cost Estimate

Overnight Capital (2006$/kW)

Solar photovoltaics

IGCC (w/ CS)

IGCC (w/o CS)

Supercritical steam coal

Wind

Gas turbine (aeroderivative)

Combined-cycle

Gas turbine (frame)

State Renewable Portfolio Standards 

Renewable resource portfolio standards targeting the development of certain types and amounts 

of resources have been adopted by eight states within the WECC; three (Colorado, Oregon, and 

Washington) since adoption of the Fifth Power Plan. In addition, British Columbia has adopted 

an energy plan with conservation and renewable energy goals equivalent to an aggressive RPS. 

The key characteristics of the state renewable portfolio standards and the B.C. Energy Plan are 

summarized in Table 3. 

As discussed later in this paper, forced development of low variable-cost renewable resources 

can have potentially significant effects on wholesale power prices. Thus, assumptions must be 

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

achieving the targets. For the Fifth Power Plan power price forecast, states that had enacted 

renewable portfolio standards were assumed to meet 75 percent of their target levels of 

renewable resource development.14 Additional resources corresponding to the estimated levels 

of development from the Oregon and Montana system benefit charge programs were also 

included. 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 many RPS states, 100 percent achievement of RPS targets was assumed for the base case of 

this forecast. Furthermore, because of the potentially significant effect of RPS acquisitions on 

wholesale prices, a more thorough assessment of the expected resource development effects of 

the various state RPS efforts was undertaken for this forecast. 

 

14 States with enacted legislation at the time of the Fifth Power Plan include: Arizona, California, Nevada, and New 

Mexico. 
Interim Wholesale Power Price Forecast 

13

Table 3 summarizes the modeling of RPS resource development by state. The right-hand 

column contains the estimated amount of energy from qualifying committed resources (those 

existing and under construction), conservation (in states where conservation is a qualifying RPS 

resource), and the additional resources needed to fully achieve targets in 2025. These 

assumptions are based on the forecast load growth rates of the Fifth Power Plan, and they assume 

that conservation and other resources qualifying for extra credit are developed to the fullest 

extent allowed, and that “off-ramp” provisions are not triggered. A sensitivity analysis assuming 

75 percent achievement of RPS targets was also run. 

Table 3: Renewable portfolio standard targets and resource mix assumptions 

Basic Standard Estimated energy needed for 

full achievement (2025) 

Arizona 15% of IOU sales by 2025 Committed 59 aMW 

Additional 712 aMW 

British 

Columbia 

50% of future needs by 

conservation 

90% of all generation renewable 

Conservation: 1440 aMW 

Committed (post-06): 101 

aMW 

Additional: 1195 aMW 

California 20% of IOU sales by end of 2010 

COUs to recognize legislative intent 

Committed 3670 aMW 

Additional 4406 aMW 

Colorado 20% of IOU sales by 2020 

10% by COU sales 2020 

Committed 509 aMW 

Additional 414 aMW 

Montana 15% of IOU sales by 2015 Committed 54 aMW 

Additional 49 aMW 

New Mexico 20% by 2020 (IOUs) 

10% by 2020 (Coops) 

Committed 71 aMW 

Additional 448 aMW 

Nevada 15% of IOU sales by 2015 (Up to 

25% by conservation) 

Conservation: 284 aMW 

Committed: 232 aMW 

Additional: 565 aMW 

Oregon 

25% of sales by 2025 (large 

utilities) 

10% of sales by 2025 (medium 

utilities) 

5% of sales by 2025 (small utilities) 

Committed: 389 aMW 

Additional: 802 aMW 

Washington 

15% of sales 2020 + cost-effective 

conservation (utilities w/25,000 or 

more customers) 

Conservation: Fifth Power 

Plan 

Committed: 410 aMW 

Additional: 989 aMW 

Total 

Conservation: 1,724+ aMW 

Committed: 5,495 aMW 

Additional: 9,580 aMW 

Windpower Supply Curve 

Full achievement of RPS targets was estimated to result in the development of 25,000 additional 

megawatts of wind by 2025. Because of the magnitude of this development, assumptions 

regarding the cost and amounts of wind power available for development in each load-resource 
Interim Wholesale Power Price Forecast 

14

area were revised using the estimates prepared by the Western Governors’ Association Clean and 

Diversified Energy Initiative Wind Task Force15 (WTF). 

The amount of wind estimated to be available for development for each load-resource area was 

taken as the total from the Class 4, 5, and 6 supply curve blocks of the WTF assessment, less 

committed wind capacity, less the estimated wind capacity needed to support full achievement of 

RPS targets through the study period (assuming that the best resources are the first developed). 

The remaining capacity was assumed to be available for economically driven resource 

development. The WTF report did not include Alberta, British Columbia or Baja California. 

Alberta was assumed to have wind resource development potential equivalent to Montana, and 

BC, wind development potential equivalent to Oregon and Washington combined. Baja 

California was arbitrarily allocated 2,000 megawatts of Class 5 wind. 

The WTF supply curve costs were scaled to the wind power cost estimate appearing in the 

Council’s biennial monitoring report. The midpoint cost of the Class 6 supply block for Oregon 

(Appendix A of the WTF report) was assumed to correspond to the biennial monitoring report 

estimate. The midpoint costs of the WTF Class 5 and Class 4 wind power supply curve blocks 

for Oregon were then scaled to the revised Class 6 value. The resulting costs were then assumed 

to apply to the respective supply curve blocks for all load-resource areas (this simplifying 

assumption will be revisited). 

Planning Reserve Margin 

The AURORAxmp model provides the capability to perform 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. 

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 , which has 6 load-resource 

zones; and (2) the California Independent System Operator (CAISO), which has 2 load-resource 

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

the CAISO 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. 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. 

 

15 Western Governors’ Association. Clean and Diversified Energy Initiative Wind Task Force Report. March 2006. 
Interim Wholesale Power Price Forecast 

15

These reserve margin targets cannot, however, be put directly into 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 winter reserve margin targets are 

based on consideration of the highest average demand for a three-day 18-hour sustained 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 multiplehour capacity reserve margin targets to an equivalent single-hour target. Adjustments were also 

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

independent power producer 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 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 

toward 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 and 30 percent of 

nameplate capacity, respectively. 

CO2 Performance Standards 

The three West Coast states have established CO2 performance standards limiting the CO2

emissions of new baseload resources acquired by purchase or by long-term contract to 1,100 lbs. 

of CO2 per megawatt-hour (approximately the CO2 output of a very efficient natural gas fueled 

simple-cycle gas turbine). Additionally, the BC Energy Plan requires any new interconnected 

fossil fuel generation in the province to have zero net greenhouse gas emissions. 

The BC Energy Plan requirement was approximated in AURORAxmp by limiting new coal-fired 

resource options within the B.C. load-resource area to integrated gasification combined-cycle 

(IGCC) plants with CO2 separation and sequestration.16 The state performance standards are 

more difficult to simulate because source-load paths are not explicitly modeled in AURORAxmp. 

The state performance standards were approximated by limiting new coal-fired resource options 

within the California, Oregon, and Washington load-resource areas to IGCC plants with CO2

separation and sequestration and by constraining new conventional coal resource options in other 

areas to amounts sufficient only to meet native load. In addition, new conventional coal was 

precluded in Idaho because of the current moratorium on conventional coal development in that 

state. The Montana policy that new coal plants capture and sequester 50 percent of CO2

emissions was not incorporated in this study. However, none of the runs showed new 

economically driven resource development in the Pacific Northwest. 

 

16 Because the cost and performance estimates for the technology have not yet been developed by Council staff, new 

combined-cycle units available to the B.C. load-resource area did not include CO2 separation and sequestration. 
Interim Wholesale Power Price Forecast 

16

FINDINGS 

Base Case 

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

$39.90 per megawatt-hour. In Figure 5, the current interim base case forecast is compared to the 

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

base case of the biennial assessment (levelized value of $38.80 per megawatt-hour), and the 

previous draft interim forecast (levelized value of $35.50 per megawatt-hour). 

Figure 5: Interim wholesale power price forecast compared to previous forecasts 

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Interim Final Forecast

Early in the planning period, the prices of the current interim base case forecast are lower than 

the prices of the previous forecasts, due largely to the effect of RPS resource additions. State 

RPS requirements are expected to dampen future wholesale power market prices due to the 

addition of significant amounts of wind and other low variable-cost renewable resources to the 

power system. 

 In competitive wholesale power markets, generating resources are typically brought on-line in 

order of their variable operating costs. In other words, resources with low variable operating 

costs are dispatched before higher cost resources (with some exceptions due to operational 

limitations). For example, hydro generation will be brought on-line before coal-fired or natural 

gas-fired generation. Wind will operate regardless of price when the wind blows. The market 

price is determined by the operating cost of the last, or most expensive, generating unit needed to 

meet demand. The addition of RPS resources, with their low operating costs, will displace 

higher variable cost resources, primarily natural gas, and is expected to result in lower variable 

cost resources, such as coal, clearing the wholesale market and setting the market price during 

many hours of the year. 
Interim Wholesale Power Price Forecast 

17

In 2012, the relative position of the current interim base case forecast switches as higher CO2

prices drive the current forecast of wholesale power prices higher than previous forecasts. 

Wholesale power prices are expected to steadily increase after 2012 due to escalation of CO2

prices and increasing natural gas prices. 

The annual average prices shown in Figure 5 conceal the underlying seasonal, daily, and hourly 

price patterns. The monthly average prices shown in Figure 6 reveal seasonal variation due to 

stream flow runoff in the spring and higher, temperature-driven loads in the summer and winter. 

Figure 6: Forecast Mid-Columbia average monthly wholesale power prices 

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Wholesale power prices also vary 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 assessing 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. 

On-peak: Mon-Sat, Hrs 7 - 22 

Off-peak: All other hours 
Interim Wholesale Power Price Forecast 

18

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

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All of the wholesale power price forecasts presented in this paper are developed using 

fundamental economic drivers under “normal” or average conditions. For example, hydro 

electric generation is modeled using “average” stream flow conditions and retail electricity 

demand is based on “normal” temperatures. This type of market modeling does not adequately 

reflect the likely episodic price excursions that will occur due to deviations in hydro conditions 

and temperatures. The Council’s portfolio risk model is specifically designed to account for 

many of the risks associated with volatile wholesale power markets. The following figure 

compares the “normal” 2007 power prices of the current interim forecast to actual wholesale 

market prices during 2004 through 2007. 

Seg 1: Mon-Fri, Hrs 9 - 18 

Seg 2: Mon-Fri, Hrs 5-8; Sat-Sun, Hrs 5-22 

Seg 3: Mon-Fri, Hrs 1-4, 23-24 

Seg 4: Sat-Sun, Hrs 1-4, 23&24
Interim Wholesale Power Price Forecast 

19

Figure 8: Comparison of forecast and actual Mid-Columbia wholesale power prices 

Resource Additions and Reserve Margins 

For each wholesale power price forecast presented in this paper, there is an underlying forecast 

of the resource mix for the WECC area. Figure 9 presents the total WECC resource mix 

underlying the base case power price forecast (Note that this and the following two figures show 

dispatched energy rather than installed capacity). Natural gas, coal, and hydro-electric 

generating resources account for the majority of the dispatched energy over the planning period. 

The amount of coal-fired generation begins to increase after 2020 as both traditional coal-fired 

and coal-gasification plants are added to the system to meet demand and begin to displace higher 

variable-cost natural gas-fired generation. 

Figure 10 shows the energy output of incremental resources added to the system over the 

planning period. The forecast is for RPS resources and market-driven wind and natural gas-fired 

resources to meet WECC demand growth through 2015. After 2020, market-driven coal-fired 

resources provide significant amounts of energy. 

 
Interim Wholesale Power Price Forecast 

20

Figure 9: Forecast WECC resource mix based on dispatched energy 

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Biogas

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Figure 10: Forecast WECC incremental resource mix based on dispatched energy 

The forecast resource mix for the Pacific Northwest reflects the dominance of hydroelectric 

generation and the expanding impact of wind generation (see Figure 11). By the end of the 

planning period, the share of energy from wind resources is expected to nearly match that of 

natural gas-fired resources. Under “normal” hydro conditions, the Pacific Northwest can expect 

to be a net exporter of energy over the entire planning period. In 2008, the region’s net exports 
Interim Wholesale Power Price Forecast 

21

are estimated to be 3,406 annual average megawatts (MWa). With the addition of incremental 

RPS resources, the net exports are forecast to increase to 4,485 MWa in 2021, and then to 

gradually decline to 3,044 MWa in 2026, as the regional resource surplus declines and less 

energy is exported to other regions. 

The Pacific Northwest Power Supply Adequacy Forum measures the load-resource balance of 

the region on the basis of resource capability and critical stream flow conditions when 

determining energy and economic adequacy. In 2008, the region’s energy surplus on a resource 

capability and critical steam flow basis is estimated to be approximately 5,100 annual average 

megawatts. This surplus is forecast to gradually decline to approximately 4,100 annual average 

megawatts in 2026. Recent resource development in the Pacific Northwest, and our forecast of 

RPS development, appear to be sufficient to satisfy the adequacy forum’s energy and economic 

adequacy targets over the entire planning period. 

Figure 11: Forecast Northwest resource mix based on dispatched energy 

Figure 12 shows the forecast of installed wind capacity in the Pacific Northwest. The region is 

expected to exceed 6,000 MW of installed wind capacity in 2022 (an amount consistent with the 

recommendations of the Fifth Power Plan). 
Interim Wholesale Power Price Forecast 

22

Figure 12: Forecast Northwest installed wind capacity 

The following figure shows the annual peak hour reserve margin for the Pacific Northwest from 

the base case price forecast. 

 Figure 13: Forecast Pacific Northwest Annual Peak-hour Capacity Reserve Margin 

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Peak Hour Reserve Margin (%)

Forecast Margin

Target Margin

The reserve margins are well above the system reliability capacity target of 18 percent over the 

entire the planning period. The long-term optimization logic of AURORAxmp does not add any 
Interim Wholesale Power Price Forecast 

23

new resources in the Pacific Northwest during the planning period. This result reflects the 

current surplus of existing capacity in the region augmented by the forced addition of RPS 

resource capacity over the planning period. The Northwest Wind Integration Forum is currently 

investigating the capacity value of wind. A capacity value of wind below the 15 percent used in 

these forecasts might create a need for new resources in excess of those added to meet RPS 

targets. 

Finally, it should be noted that AURORAxmp does add 532 natural gas simple-cycle units to the 

WECC resource mix over the planning period. These additions add 35,555 megawatts of 

installed capacity. These resources are primarily added in California and other WECC areas 

outside the Pacific Northwest to maintain capacity reserves. These units are infrequently 

operated due to higher operating cost and therefore do not show prominently in Figures 8 and 9. 

Sensitivity Cases 

This interim wholesale power price forecast includes several alternative cases which test the 

sensitivity of the base forecast to changes in input assumptions. 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 achievement of state RPS targets. A sensitivity case that 

eliminated incremental RPS resource development was run to illustrate the impact of RPS 

resource additions on wholesale power prices. 

 A comparison of the interim base case power price forecast to the sensitivity case forecasts is 

shown in the following figure. 

Figure 14: Interim base case and sensitivity case wholesale power price forecasts 

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2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

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High CO2 Price Case

75% RPS Achievement Case

Low Fuel Price Case

High Fuel Price Case

No Incremental RPS Case

High Capital Cost Case

Low CO2 Price Case
Interim Wholesale Power Price Forecast 

24

The impact of high CO2 prices on Mid-Columbia wholesale power prices is significant. The 

levelized price for the high CO2 price case is $52.30 per megawatt-hour, 31 percent higher than 

the base case. 

West-wide CO2 production is only moderately affected by the revised base case CO2 price 

assumptions, but significantly reduced in the high CO2 price sensitivity case. Figure 15 

compares base case and sensitivity case annual WECC-wide CO2 production (note truncated 

vertical axis). Differences in CO2 production are negligible during the period 2007 through 

2011. 

However, in the base case scenario, WECC CO2 production begins to grow after 2012. The base 

case forecast of 511 million tons of CO2 production from WECC resources in 2024 is 20 million 

tons lower than the 5th Plan Portfolio forecast from the recent CO2 Footprint Paper. This 

reduction is attributable to the updated RPS modeling and the higher assumed CO2 prices. 

Figure 15: Interim base case and sensitivity case CO2 production forecasts (WECC) 

(Note: scale of left axis begins at 300 million tons of CO2 production) 

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CO2 Production (Million Tons)

High CO2 Price Case

Interim Base Case 

75% RPS Achievement Case

High Fuel Price Case

Low Fuel Price Case

5th Plan Base Case

High Capital Cost Case

Low CO2 Price Case

No Incremental RPS Case

The low CO2 price case used the mean value CO2 prices from the Fifth Power Plan (see Figure 

3). This sensitivity case isolates the impact of the increase in base case CO2 prices and also 

provides a good indication of combined impact of the other changes to the AURORAxmp model 

since the Fifth Power Plan. The levelized wholesale power price of the low CO2 price case is 

$37.40 per megawatt-hour, compared to the base case value of $39.90 per megawatt-hour. In 

other words, increasing the base case CO2 price forecast raised the levelized wholesale power 

price forecast by $2.50 per megawatt-hour. The low CO2 price case also had a lower levelized 

price than both the Fifth Power Plan forecast ($38.90 per megawatt-hour) and the Biennial 

Assessment forecast ($38.80 per megawatt-hour). These differences, despite higher forecast 
Interim Wholesale Power Price Forecast 

25

prices for natural gas and coal, can be attributed to the resource development that occurred 

during 2005-2007 and the development needed to achieve state RPS targets. 

The seventy-five percent RPS achievement case had only a minor impact on wholesale power 

prices (levelized price of $40.20 per megawatt-hour). In contrast, eliminating all incremental 

RPS resource development raised the levelized price by $1.70 to $41.60 per megawatt-hour. The 

larger reduction in RPS resource development had a larger impact on wholesale power prices 

because it resulted in resources with higher variable operating costs setting hourly marketclearing prices. 

 The high fuel price case had a levelized wholesale power price of $48.10 per megawatt-hour, an 

$8.20 increase from the base case value. In general, higher natural gas prices result in higher 

wholesale power prices and more CO2 production. The increase in CO2 production is the result 

of a reduced dispatch of natural gas-fired units and an increased dispatch of traditional coal-fired 

units. However, whereas an increase in natural gas prices will always impact wholesale power 

prices (because they change the variable operating cost of the gas-fired units), a change in CO2

production will only occur if the change in natural gas prices is large enough to result in a 

different resource clearing the wholesale market. 

The low fuel price case had a levelized price of $31.20 per megawatt-hour, an $8.70 reduction 

from the base case value. Lower natural gas prices tend to lower overall CO2 production by 

increasing the dispatch of gas-fired units and lowering the dispatch of coal-fired units. 

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 the region’s energy and capacity needs. Additional 

thermal capacity may eventually be needed for integration of intermittent renewable resources. 

The high capital cost case had a significant impact on the forecast mix of incremental resources 

added to the WECC area over the planning period (see Figure 16). Capital-intensive 

conventional coal-fired resources become relatively more costly and are no longer included in 

the incremental resource mix. Coal-gasification resources, also capital-intensive are reduced to a 

small increment at the end of the forecast period. Compared to the base case incremental 

resource mix (see Figure 10), the high capital cost case shows a 16,247 average megawatt 

reduction in energy from these resource types in 2026. This energy output is replaced in the high 

capital cost case with 5,763 average megawatts of additional output from incremental natural 

gas-fired resources. Though the capital cost of new natural gas resources are higher than in the 

base case, the increase is not as significant as for the coal resources because of the relatively 

small contribution of capital costs to the overall cost of power from a natural gas-fired power 

plant. Incremental wind and RPS resources replace 4,045 average megawatts. The remaining 

6,439 average megawatts of energy in 2026 are replaced by relying more heavily on currently 

operating resources. 

These changes in resource mix impact both wholesale power prices and CO2 production. The 

high capital cost case had a levelized wholesale power price of $41.30 per megawatt-hour, a 

$1.40 increase over the base case value (see Figure 1). With less reliance on incremental coalfired resources, the high capital cost case shows lower CO2 production than the base case, 

however, annual CO2 production continues to increase over the planning period (see Figure 15). 
Interim Wholesale Power Price Forecast 

26

Figure 16: Forecast WECC incremental resource mix of the high capital cost case 

 based on dispatched energy 

CONCLUSIONS 

This is the first time that the Council’s power price forecast has included the impact of renewable 

portfolio standards (RPS) recently implemented in Montana, Oregon, Washington, and many 

other western states. The mandated addition of large amounts of renewable generating resources 

to the western power system is forecast to dampen wholesale power prices in the near term. In 

the long-term, regulation of carbon dioxide emissions offsets the dampening effect of the RPS 

additions and is expected to significantly increase wholesale power prices. 

 The Council’s forecast pegs wholesale power prices below levels where independent developers 

can expect to recover the full costs of constructing and operating the new renewable generating 

resources by selling power into the wholesale spot market. An important implication of this 

result is that Northwest ratepayers and utility regulators are likely to see, at the same time, 

declining wholesale power prices and rising retail rates. 

In the Northwest, retail electricity rates are predominately cost-based rates. The electricity rates 

of both consumer-owned and investor-owned utilities are administratively set to recover the 

expected cost of providing service. Therefore, unlike the forecast near-term competitive 

wholesale power market prices, utilities’ retail electricity rates can be expected to reflect the full 

capital cost associated with construction of the new RPS resources, as well as the cost of 

operating the resources. 

The divergent direction of wholesale power prices and retail electricity rates can create strong 

incentives for utilities and their customers to rely more heavily on the short-term wholesale 
Interim Wholesale Power Price Forecast 

27

power markets for their energy needs. However, as the region saw during the western electricity 

crisis of 2000-01, there can be significant risk associated with this strategy. 

Another important implication of a growing divergence between wholesale and retail prices is 

that direct use of the Council’s forecasted power prices as “avoided costs” in conservation and 

generating resource assessments may not be appropriate in all cases. The cost of future resource 

development, measured in dollars per megawatt-hour (or cents per kilowatt-hour) is often 

referred to as an avoidable cost or more commonly as an “avoided cost.” By comparing the cost 

of specific conservation measures or generating resources to the region’s “avoided cost,” the 

Council and others have evaluated the cost-effectiveness of pursuing these resources. In the past, 

the Council used its wholesale power price forecast as its best estimate of the region’s future 

resource development cost. 

The region may need a different methodology for estimating its avoided cost not only because of 

the divergence between wholesale power prices and retail electricity rates, but also because the 

terms and conditions of the region’s RPS statues make it difficult to consider conservation a full 

alternative to RPS resource development. For example, under Washington’s 15 percent 

renewable by 2020 target, every megawatt-hour of conservation only avoids 0.15 megawatthours of RPS resource development. In other words, the RPS avoidance rate of conservation is 

15 percent. In Washington, and many other RPS states, conservation can be expected to 

primarily result in utility surplus sales or avoided purchases in the wholesale power market. A 

utility facing an unfilled 15 percent RPS mandate will see an avoided cost comprised of 15 

percent of the full cost of the least-cost available qualifying RPS resource plus 85 percent of the 

forecast wholesale power market prices. 

The following chart illustrates this blending of forecast wholesale power prices and the full cost 

of RPS resource development to arrive at an overall avoided cost.17 Avoided costs are shown for 

the four load segments used in the Council’s assessment of the cost-effectiveness of conservation 

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

 

17 The blending is 20 percent of the full cost of a wind resource in 2020, and 80 percent of the forecast wholesale 

power market prices. 
Interim Wholesale Power Price Forecast 

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Figure 17: Potential “blended” avoided cost methodology 

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"Blended" Avoided Costs

Annual Levelized Cost of Wind in 2020

Avoided costs can be expected to differ for different utilities. For a utility that expects to be 

resource sufficient after complying with state RPS requirements, avoided costs are largely 

determined by the rate at which the RPS resource additions are avoidable by pursuing 

conservation. As indicated above, under most state RPS statues conservation and renewable 

resource development do not compete on an equal basis. For a surplus utility that does not face a 

state RPS requirement, avoided costs would equal forecasted wholesale power market prices. 

This is the cost of avoided purchases or the value of surplus sales in the wholesale power market. 

For a utility that expects to be resource deficient, avoided costs are determined by the full cost of 

its expected resource expansion. This is the case for a utility that does not face a state RPS 

requirement or a utility that is deficit after complying with a state RPS requirement. 

The Council intends to more fully address avoided cost issues and the role of conservation in 

reducing the region’s carbon emissions in its upcoming Sixth Power Plan. 

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q:\sixthplan\electricprices\papers\interimpowerpriceforecast.doc