1
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This report summarizes the results of an analysis 

of CO2 production from the Pacifi c Northwest 

power system. It compares 2005 CO2 production to levels in 1990 and to forecast future levels. The 

analysis explores how future growth in CO2 production would be affected by various resource development scenarios and other policies of interest.

Summary of Findings

Following a 2006 staff analysis of the marginal 

carbon dioxide (CO2) effects of conservation called 

for in the Council’s Fifth Power Plan, the Council 

requested additional analysis of the CO2 production 

of the Northwest power system under various future 

resource development scenarios. The scenarios 

included the recommended resource portfolio of the 

Fifth Power Plan (the base case), a low-conservation 

scenario in which the conservation targets of the Fifth 

Power Plan are not achieved, and a high-renewables 

scenario based on state renewable energy portfolio 

standards. A scenario based on the resource acquisition recommendations of utilities’ integrated resource 

plans (IRPs) was dropped following the release of 

several revised utility IRPs that closely matched the 

recommendations of the Fifth Power Plan. In addition, the Council asked for sensitivity analysis of 

several specifi c policies related to hydro system 

operations to understand how related scenarios could 

affect the CO2 production of the power system. The 

analysis does not address CO2 production from other 

sources such as transportation or industrial processes.

The actual CO2 production of the Northwest power 

system in 1990 is estimated to have been about 44 

million tons.1 By 2005, production of CO2 from the 

regional power system rose to an estimated 67 million 

tons. However, 2005, unlike 1990, was a poor water 

year, requiring more than normal operation of CO2 

-producing fossil power generation. Under normal 

water conditions, the CO2 production in 2005 would 

have been about 57 million tons, which is a 29 percent increase over the 1990 level. For perspective, 

the annual CO2 output of a typical 400-megawatt 

coal-fi red power plant is about 3 million tons, and the 

CO2 output of a typical 400-megawatt gas-fi red combined-cycle power plant is about 1.2 million tons.2 

Factors contributing to the increase from 1990 to 

2005 include economic growth, the addition of fossil-fueled generating units, lost hydropower production capability, and retirement of the Trojan nuclear 

plant. The year 1990 is used for comparison because 

1990 has been adopted as a baseline by many climate-change policy proposals, including Washington 

Governor Gregoire’s climate-change executive order, 

Oregon HB 3543, and national legislation proposed 

by Senators Lieberman and Warner.

Due to the large share of hydroelectric generation in the Pacifi c Northwest, CO2 production here is 

much less than that of other regions when compared 

to electricity produced. For example, under normal water conditions, in 2005 the Pacifi c Northwest 

would have produced about 520 pounds of CO2 for 

each megawatt-hour of electricity generated, compared to 900 pounds for the entire Western interconnected power system (WECC). However, because 

the Northwest has essentially the same set of future 

resource options available as other areas of WECC, it 

may be more diffi cult for the Northwest to maintain or 

reduce its average per-megawatt-hour CO2 emission 

rate. In the base case of this study, which assumes 

implementation of the Council’s Fifth Power Plan, the 

WECC CO2 emission rate increases about 3 percent 

to about 920 pounds per megawatt-hour by 2024, 

whereas the Northwest rate, with aggressive development of conservation and renewables also increases 

3 percent to about 530 pounds. 

The future growth rate of annual regional CO2 

production would be even higher if the conservation, wind, and other resource development called 

for in the Council’s Fifth Power Plan were not accomplished. With implementation of the Council’s plan 

in the base case, the annual CO2 production of the 

regional power system in 2024 under normal conditions would be about 67 million tons, an 18 percent 

increase over normal 2005 levels.

This paper explores the diffi culty of reducing CO2 

production from electricity generation by assessing 

the effects of several scenarios on CO2 production. 

The scenarios include some that would increase CO2 

production and some that would decrease it. These 

1 Unless otherwise noted, quantities are expressed as short tons (2,000 pounds) of carbon dioxide.

2 A 400-megawatt pulverized coal-fi red plant of 10,000 Btu/kWh heat rate operating at 80 percent capacity factor will produce about 3 

million tons per year of carbon dioxide. A 400-megawatt combined-cycle plant fueled by natural gas of 7,000 Btu/kWh heat rate operating at 80 percent capacity will produce about 1.2 million tons per year of carbon dioxide.
3

scenarios were selected to develop a “scale-of-effects” sensitivity analysis that includes alternative 

resource development scenarios and hypothetical 

changes to the hydroelectric system. The hydroelectric sensitivity analyses address two hypothetical river 

condition alternatives: “no summer spill” and breaching the four lower Snake River dams. The controversial nature of these two scenarios is recognized, but 

has no relevance in this paper other than the CO2-related data the alternatives generate as a result of their 

respective scenario parameters.

An important fi nding of the analysis is that achieving the renewable portfolio standard goals and eliminating all summer spill would reduce the region’s 

projected growth in power system CO2 production 

by only 75 percent, even if counting the resulting 

net CO2 reduction for the entire WECC. Failure to 

achieve the conservation targets in the Fifth Power 

Plan, or removing the lower Snake River dams and 

replacing the power in a manner consistent with the 

Fifth Power Plan could more than offset the potential 

savings from the scenarios that reduce CO2 production. The effects of these scenarios, positive or negative, on CO2 production are the equivalent of only one 

or two coal-fi red plants, whereas the forecast regional 

CO2 production for 2024 in the Fifth Power Plan case 

exceeds 1990 levels by an amount equivalent to eight 

typical coal-fi red plants.

The fi ndings of this study are depicted in Figure 1 

and compiled in Table 1. Figure 1 depicts changes 

from base case projected CO2 emissions from WECC 

power systems for each of the scenarios. Table 1 

shows the CO2 emissions in 1990, 2005, and projections for 2024 in each scenario, both for the Pacifi c 

Northwest and the WECC as a whole. Changes to 

the 2024 levels are shown in parentheses for each 

scenario.

These results illustrate the diffi culty of actually 

reducing CO2 production with policies that affect only 

new sources of electric generation. CO2 production 

from electricity generation is dominated by existing 

coal-fi red generating plants. To stabilize CO2 production at 2005 levels or to reduce CO2 production to 

1990 levels would require substituting low CO2-producing resources or additional conservation for some 

of these existing coal-fi red power plants. In addition, 

the scenario analysis shows that policy choices that 

are made for purposes other than CO2 reduction 

(in this case fi sh and wildlife policy) can also have 

signifi cant effects on CO2 production; enough effect 

to negate policies such as renewable portfolio standards. Such unintended effects often go unexplored 

in important policy debates that focus narrowly on 

only one objective.

Figure 1: Changes from the base case projected CO2 production 

in alternative scenarios (WECC)
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As perspective, it is useful to understand regional 

CO2 emissions in a global context. In 2005, the 

world production of CO2 from the consumption and 

fl aring of fossil fuels is estimated to have been about 

28,000 million metric tons (30.8 billon short tons). 

The United States accounted for 21 percent of these 

emissions. The U.S. production of CO2 per capita is 

about 5 times the world average, largely refl ecting its 

advanced state of development. However, the U.S. 

production of CO2 relative to its state of development 

as measured by Gross Domestic Product is substantially lower than the world average; about 70 percent 

of the world average.3

Electric power generation accounts for about 40 

percent of the U.S. production of CO2. The electric power share is much lower in the Western U.S., 

however, at about 31 percent, and even lower for the 

Pacifi c Northwest where the 2004 (a fairly normal 

water year) share was 23 percent.

Greenhouse gas reduction targets, such as the 

Western Climate Initiative, typically target all sources 

of greenhouse gas emissions. Carbon dioxide is 

the dominant greenhouse gas. It accounted for 84 

percent of all greenhouse gas emissions in 2005.4 

Sources of CO2 emissions other than electricity generation will need to be reduced to meet greenhouse 

gas reduction targets. For the U.S. as a whole, electricity generation is the largest producer of CO2. It is 

followed closely by the transportation sector, which

accounts for one-third of emissions, and then by the 

industrial sector contributing 18 percent. The residential and commercial sectors combine to account for 10 

percent.

Although electricity generation is the largest source 

of CO2 emissions in the U.S., in the West transportation is the largest. Transportation accounts for 43 

percent of the CO2 emission in the West compared 

to 33 percent in the U.S. as a whole. In the Pacifi c 

Northwest, the transportation share is even larger at 

46 percent.

The diversity of CO2 emission shares should be 

an important consideration in structuring CO2 reduction policies. In the West, with a smaller contribution 

to CO2 emission coming from electricity production, 

other sectors will need to carry a larger burden in 

reaching overall CO2 reduction targets. In addition, 

as discussed later in this paper, the CO2 production 

for electricity generation in the Pacifi c Northwest can 

vary signifi cantly with changing hydroelectric supplies. 

This variability will need to be accounted for in setting CO2 reduction targets and in any cap and trade 

allocation system.

Background

Increasing concerns regarding the impact of CO2 

production from the electric power system on global 

climate and heightened prospects of mandatory 

Table 1: Historical and projected CO2 production and effects of alternative scenarios

 3Data on CO2 emission from energy are from the U.S. Energy Information Administration.

 4U.S. Environmental Protection Agency. EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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controls on the production of CO2, led the Council in 

the summer of 2006 to request a forecast of the CO2 

produced from alternative future resource portfolios. 

Four scenarios were identifi ed: the recommended 

resource portfolio of the Fifth Power Plan (the base 

case), a low-conservation scenario in which the 

conservation targets of the Fifth Power Plan are not 

achieved, a high-renewables scenario based on state 

renewable energy portfolio standards, and a scenario 

based on the resource acquisition recommendations 

of utilities’ integrated resource plans (IRPs). The utility plans scenario was removed from the fi nal paper 

following the release of several revised utility IRPs 

that closely matched the recommendations of the Fifth 

Power Plan. Two additional sets of studies were subsequently requested: 1) the CO2 effects of removing 

the federal dams on the lower Snake River; and 2) 

the CO2 effects of summer spill at the lower Snake 

River and lower Columbia River dams.

The purpose of these alternative scenarios is to 

quantify the sensitivity of results to plausible changes 

in the power system and to some related policies that 

have received attention. No new Council position on 

any of these policies is intended by this analysis, nor 

should any be inferred.

Historical Carbon Dioxide Production of the Northwest Power System

The year 1990 is frequently used as a benchmark 

in policies for the control of greenhouse gases.5 The 

1990 production of carbon dioxide from the Pacifi c 

Northwest power system is estimated to have been 

about 44 million tons, based on electricity production records of that year. Load growth, the addition 

of fossil-fuel generating units, the loss of hydropower 

production capability, and the retirement of the Trojan 

nuclear plant resulted in growing CO2 production over 

the next 15 years. By 2005, the most recent year for 

which electricity production or fuel consumption data 

are available, CO2 production increased 52 percent to 

67 million tons (Figure 2). This is approximately the 

CO2 output of 23 400-megawatt conventional coalfi red power plants, 56 400-megawatt gas-fi red combined-cycle plants or about 11.7 million average U.S. 

passenger vehicles.

The regional CO2 production estimates from 1995 

through 2005 shown in Figure 2 are based on the fuel 

consumption of Northwest power plants as reported to 

the Energy Information Administration (EIA). Because 

fuel consumption data were not available before 

1995, estimates for 1990 through 1995 are based 

on plant electrical output as reported to EIA and staff 

assumptions regarding plant heat rate and fuel type. 

Estimates based on plant electrical production are 

likely somewhat less accurate than estimates based 

on fuel consumption because of multi-fuel plants and 

uncertainties regarding plant heat rates. However, 

the two series of estimates are within 2 percent in the 

“overlap” year of 1995. 

5For example, California Assembly Bill (AB) 32, passed by the legislature and signed by the governor in 2006, calls for enforceable 

emission limits to achieve a reduction in CO2 emissions to the 1990 rate by 2020. Washington Governor Gregoire’s climate-change executive order includes the same target for CO2 reductions. Oregon House Bill 3543, passed by the legislature and signed by Governor 

Kulongoski in August, declares that it is state policy to stabilize CO2 emissions by 2010, reduce them 10 percent below 1990 levels by 

2020, and 75 percent below 1990 levels by 2050.
6

Annual hydropower conditions can greatly affect 

power system CO2 production. Average hydropower 

production in the Northwest is about 16,400 average 

megawatts. As shown by the plot of Northwest hydropower production in Figure 2, the 1990 water year 

was nearly 17,000 average megawatts, slightly better 

than average. Other factors being equal, this would 

have slightly reduced CO2 production that year by 

curtailing thermal plant operation. Conversely, hydro 

production in 2005 was about 13,800 average megawatts, a poor water year. Other factors being equal, 

this would have increased thermal plant dispatch, 

raising CO2 production. The effect of hydropower 

generation on thermal plant generation and CO2 production is shown in Figure 2.7 

If normalized to average hydropower conditions, 

actual generating capacity, and the medium case 

loads and fuel prices of the Fifth Power Plan, the estimated CO2 production in 2005 would have been 57 

million tons, a 29 percent increase over the 1990 rate. 

This is the value used for comparison in this paper.

The Base Case - The Fifth Power 

Plan’s Portfolio

The recommended resource portfolio of the Fifth 

Power Plan was used as the base case for all studies. 

Because the recommended resource portfolio 

of the Fifth Power Plan is defi ned in terms of “option 

by” dates rather than in-service dates, assumptions 

must be made to translate the portfolio into the fi xed 

resource schedule needed for the AURORATM 

model.8 For this work, the “mean value resource development” schedule of the preferred resource portfolio of the Fifth Power Plan was represented in AURORA. The resulting resource development schedule 

was then tested against the Resource Adequacy 

Forum’s recently proposed pilot capacity adequacy 

standard, using the capacity addition mode of the 

AURORA model. The resulting resource development 

schedule, illustrated in Figure 3 and enumer0

10

20

30

40

50

60

70

80

1990 1992 1994 1996 1998 2000 2002 2004 2006

Annual CO2 Production (MMtCO2)

0

5000

10000

15000

20000

25000

Annual Energy Production (aMW)

CO2 - Based on fuel consumption

CO2 - Based on generation

Hydro Generation

Fossil generation

Figure 2: Historical CO2 and energy production of the Northwest power system6

6Estimated CO2 production from 1995 through 2005 is based on power plant fuel consumption as reported to the U.S. Energy Information Administration (EIA). Fuel consumption information before 1995 is not readily available. CO2 production for these years was 

based on reported generation and estimated plant heat rates. As evident in Figure 1, the two methods result in reasonably consistent 

estimates for the overlap year of 1995. Incomplete reporting of generation for the increasing amount of non-utility power plant capacity makes comparisons less reliable for subsequent years. Estimates are based on all utility-owned power plants and non-utility plants 

selling under contract to utilities. Included in the defi nition of “Northwest” are the Jim Bridger plant in Wyoming and the Idaho Power 

share of the North Valmy plant in Nevada. The output of this capacity is dedicated to Northwest loads.

 7In Figure 1, it is evident that Northwest thermal generation does not decline as much as Northwest hydro generation increases in 

above average water years, e.g. 1994 - 1997. This is likely due to the fact that the abundant hydropower of good water years creates 

a regional energy surplus that can be sold out of the region where it displaces thermal generation, which often consists of older, less 

effi cient gas-fi red units. 

8The use of the AURORA model in preparing these forecasts is described in the Appendix A of this paper. 
7

ated in Appendix B, contains additional simple-cycle 

gas turbine capacity needed to maintain the proposed 

Northwest pilot capacity reserve standards. The 

schedule also contains several recently constructed 

wind projects not included in the resource portfolio of 

the Fifth Power Plan, so it includes a somewhat larger 

amount of wind capacity by 2024 than the original 

Fifth Plan portfolio. The AURORA capacity expansion 

run was also used to defi ne resource additions and

retirements for WECC areas outside the Northwest.

Forecast CO2 production of the Northwest power 

system for 2005-24 is compared to historical production in Figure 4. The forecast is normalized to 

average hydro, fuel prices, and loads, leading to the 

difference between actual and forecast values for the 

low water year 2005. Annual CO2 production under 

average conditions is forecast to increase from 57 

million tons in 2005 to 67 million tons in 2024. This 

represents an 18 percent increase over the planning 

period of the Fifth Power Plan, an average annual 

rate increase of 0.8 percent. The forecast annual rate 

0

2000

4000

6000

8000

10000

12000

14000

16000

2005 2010 2015 2020

Capacity (MW)

Wind

NG Combined-cycle

NG Gas turbines

Coal

Conservation

Figure 3: Base case Northwest resource development

Figure 4: Forecast and historical CO2 production of the Northwest power system

0

10

20

30

40

50

60

70

80

1990 1995 2000 2005 2010 2015 2020 2025

CO2 Production (MMtCO2)

Historical

Base case (Average conditions)
8

of 67 million tons in 2024 represents an increase of 

51 percent over the historical annual rate of 44 million tons in 1990. The forecast average annual rate 

of increased CO2 production of 0.8 percent for the 

planning period of the Fifth Power Plan is half of the 

2 percent average rate for 1990 - 2004 (2004 normalized). 

Figure 5 compares forecast annual CO2 production for the Northwest and the WECC as a whole. In 

2005, the normalized annual CO2 production by the 

Northwest power system represented 15 percent 

of the total WECC production. Because of its high 

proportion of hydropower, aggressive development of 

conservation, and recent additions of wind power and 

other non-hydro renewable resources, the Northwest 

enjoys a much lower per-kilowatt-hour CO2 production rate than WECC as a whole (0.52 lb/kWh vs. 0.90 

lb/kWh in 2005). The forecast average annual growth 

rate for WECC as a whole is 1.7 percent, compared 

to 0.8 percent for the Northwest, so that by 2024, the 

production in the Northwest will have declined to 13 

percent of the total WECC production. Because these 

estimates do not include the possible effects of the 

renewable portfolio standards in place in many Western states (including the Northwest states), the future 

growth of CO2 production for WECC may be less than 

forecast here. 

Figure 6 illustrates the source of CO2 production in the Northwest in the base case forecast. By 

2024, and assuming no retirements of existing thermal plants, 79 percent of Northwest power system 

CO2 production will be from existing coal-fi red power 

plants, 4 percent from new coal-fi red plants, 9 percent 

from existing gas-fi red plants, and 7 percent from new 

gas-fi red power plants. Though the aggressive acquisition of conservation and renewable resources called 

for in the Fifth Power Plan will hold the rate of growth 

in Northwest CO2 production to half the growth rate 

experienced from 1990 through 2004, serious efforts 

to reduce or even stabilize CO2 production beyond 

2005 will likely require replacing existing coal-fi red 

power plants with low CO2-emitting resources.

0

100

200

300

400

500

600

2005 2010 2015 2020

Carbon Dioxide (MMt)

WECC

Pacific Northwest

Figure 5: Forecast WECC and Northwest power system CO2 production
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Alternative Resource

Development

The CO2 production of two scenarios of alternative future resource development was forecast and 

compared to the base case forecast described earlier. 

The Northwest resource-development assumptions 

for each scenario are described below. Resourcedevelopment assumptions for WECC areas outside 

of the Northwest are the same as the base case. The 

impacts of all of the scenarios analyzed in this paper 

are assessed under average water conditions.

Alternative resource-development scenarios

A low-conservation scenario assumes that only 70 

percent of the long-term conservation goals of the 

Fifth Power Plan are met by 2024. A resource portfolio (the “status quo” portfolio) representing this situation, developed during preparation of the Fifth Power 

Plan, was adopted for this scenario. As shown in 

Figure 7, this portfolio includes 800 fewer megawatts 

of conservation, 200 fewer megawatts of wind, and 

275 fewer megawatts of simple-cycle capacity compared to the base case.9 An additional 275 megawatts of coal and 610 megawatts of combined-cycle 

capacity make up for the energy and capacity of the 

unachieved conservation, wind, and gas turbine capacity.

A high-renewables scenario approximates full 

achievement of the Montana, Oregon, and Washington renewable portfolio standards (RPS). This 

scenario also includes a hypothetical RPS for Idaho, 

generally comparable to those adopted by the other 

states but with a lag of several years. Although these 

additional renewable resources were not found to 

be cost-effective in the Council’s Fifth Power Plan, 

their acquisition has been mandated by many states, 

including Montana, Washington, and Oregon. Renewable-resource acquisitions to meet RPS goals 

are modeled as a combination of wind and biomass 

in the approximate proportions of wind currently being developed compared to other renewable energy 

resources. Though some geothermal, hydropower, 

solar, and marine energy resources are expected 

to be developed in response to renewable portfolio 

standards, the wind and biomass assumed for this 

scenario adequately represent the performance of 

the expected mix of intermittent and fi rm renewable 

energy resources for this purpose. The conservation-acquisition targets of the Fifth Power Plan were 

also assumed to be met. New coal-fi red generation 

is excluded from this scenario. As shown in Figure 7, 

the high-renewables scenario includes an additional 

500 megawatts of biomass, 1,600 megawatts of wind, 

0

10

20

30

40

50

60

70

80

2005 2010 2015 2020

(MMtpy CO2)

New gas

Existing gas

New Coal

Existing coal

Other

Figure 6: Sources of Northwest power system CO2 production

9In Figure 7 and following fi gures, column sections above the zero line represent resource capacity in excess of the amounts included 

in the base case, and column sections below the zero line represent resource capacity less than included in the base case. Conservation energy savings are shown as equivalent capacity.
10

and 370 megawatts of gas turbines compared to the 

base case. The peaking capacity and energy balance 

of the base case was maintained by eliminating the 

425 megawatts of new coal in the base case.

Effects of alternative resource-development 

scenarios

The production of CO2 is a function of the fuel and 

effi ciency of resources dispatched to meet load. Alternative resource mixes will lead to changes in dispatch 

because of differing variable costs of operation and 

physical operating characteristics. Net changes for 

the entire WECC must be evaluated because of the 

effects of Northwest resources on resource dispatch 

in interconnected areas. A comparison of the average annual change in energy production by type of 

resource for 2015-24 for the two alternative resourcedevelopment scenarios compared to the base case is 

illustrated in Figure 8.

-2000

-1000

0

1000

2000

3000

4000

5000

Low Conservation High Renewables

Capacity (MW)

NGGT

Hydro

NGCC

Coal

Geothermal

Biomass

NGCG

Wind

Conservation

Figure 7: Incremental 2005-24 capacity compared to the base case

-1000

-800

-600

-400

-200

0

200

400

600

800

1000

Low Conservation High Renewables

Energy (MW)

Natural gas

Hydro

Coal

Biomass

Geothermal

Wind

Conservation

Figure 8: Average annual change in resource output vs. base case (WECC, 2015-24)
11

Low Conservation

Additional energy from coal (370 average megawatts) and natural gas (560 average megawatts) 

substitute for the reduced conservation of the lowconservation scenario. By 2024, annual CO2 production from Northwest sources would be 71 million tons 

per year (MMtpy), 4.4 million tons greater than the 

base case and a 61 percent increase over the 1990 

rate. Annual net CO2 production for 2024 across the 

entire WECC system would increase 5.2 million tons 

compared to the base case, nearly the equivalent of 

two typical 400-megawatt coal-fi red power plants. By 

2024, this scenario includes about 770 fewer average 

megawatts of conservation than the base case. Each 

average megawatt of unachieved conservation would 

increase average net annual CO2 production by about 

6,700 tons per year.

Wholesale power prices are forecast to be higher 

on average in the low-conservation scenario compared to the base case. Higher prices result from the 

dispatch of higher variable-cost resources, such as 

gas turbines to serve the additional load resulting from 

lower conservation achievement.

High Renewables

Additional energy from wind (310 average megawatts) and biomass (300 average megawatts) in 

the high-renewables scenario would reduce energy 

production from coal by 370 average megawatts and 

natural gas by 220 average megawatts. By 2024, annual CO2 production from Northwest sources would 

be 63 MMtpy, 4.2 million tons less than the base case. 

Although this would reduce the 2005-24 growth of 

CO2 production rates by 44 percent, the resulting rate 

still represents a 41 percent increase over the 1990 

rate. Annual net CO2 production for 2024 across the 

entire WECC system would decline 5.1 million tons 

compared to the base case.

Wholesale power prices are forecast to be slightly 

lower on average in the high-renewables scenario 

compared to the base case. Lower prices result from 

the displacement of high variable-cost resources, 

such as gas turbines by the additional low variablecost renewable resources of this scenario.

Removal of the Lower Snake River 

Hydroelectric Projects

Analysis of breaching the four federal hydroelectric 

projects on the lower Snake River10 indicates the 

loss (on average under current river operations) of 

about 1,020 average megawatts of carbon-free energy and 2,650 megawatts of sustained peaking capacity. The impact of this loss on the production of CO2 

depends on the nature of the replacement resources. 

The resource replacement depends on the particular 

resource-development strategy, as illustrated in the 

resource-development scenarios described earlier.

Resource replacement

Three possible approaches to replacing the reduced hydroelectric output of the dams were considered. These were: replacement with market purchases, replacement with natural gas resources, and 

replacement with conservation and renewable energy 

resources and natural gas capacity. The results of 

the second approach are reported because they are 

considered the most consistent with the base case 

and the Fifth Power Plan. Replacement with market purchases would compromise system adequacy 

and reliability by reducing the amount of resource 

available to meet load. Replacement of the power 

lost by breaching the lower Snake River dams by 

increased acquisition of conservation and renewable 

energy could, at least in the near term, delay some of 

the CO2 impacts of dam breaching. However, tying the increased development of conservation and 

renewables to dam breaching is misleading. If additional conservation and renewables are available 

and desirable, they should be pursued as part of a 

regional strategy to reduce CO2 emissions. Thus, 

the effects of changes in renewable development and 

conservation achievements have been addressed in 

the resource-development scenarios discussed earlier. Removal of the lower Snake River dams will not 

make additional CO2-free energy resources available 

to meet future load growth or retire any existing coal 

plants. More than 1,000 megawatts of emission-free 

generation eventually will have to be replaced unless the supplies of renewables and conservation are 

considered unlimited. Given the diffi culty of reducing 

CO2 emissions, discarding existing CO2-free power 

sources has to be considered counterproductive

The lower Snake projects were assumed to ter10The projects are Ice Harbor, Lower Monumental, Little Goose, and Lower Granite.
12

minate production on December 31, 2014, and replacement resources were assumed to commence 

operation on January 1, 2015. This permitted the 

development of 10-year (2015-24) averages consistent with the other studies of this analysis. Resourcedevelopment assumptions for WECC areas outside of 

the Northwest were held constant. 

The analysis assumes that the average energy 

output of the projects is replaced by natural gas-fi red 

combined-cycle plants. The balance of the sustained 

peaking capacity of the projects is replaced by natural 

gas-fi red simple-cycle gas turbines. The combined 

capacity of three combined-cycle units (1,830 megawatts) and 18 simple-cycle gas turbine units (846 

megawatts) slightly exceeds the sustained peaking 

capacity of the four hydro projects. The analysis did 

not address replacement of ancillary services such 

as regulation, load following, and power factor control 

provided by the projects. 

Effects of lower Snake dam replacement

When the operation of the changed power system 

is simulated, the lost hydro energy is replaced with the 

additional production of 170 average megawatts from 

existing coal-fi red units and about 810 average megawatts from new and existing natural gas units. By 

2024, annual CO2 production from Northwest sources 

would be 70 MMtpy, 3.6 million tons greater than the 

base case and a 59 percent increase over the 1990 

rate. Annual CO2 production for 2024 across the 

entire WECC system would increase 4.4 million tons 

compared to the base case.

A modest increase in wholesale power prices is 

forecast, resulting from replacement of the hydro 

energy with higher variable-cost thermal energy. 

Signifi cant capital expenditures would be incurred 

for replacement resources and costs associated with 

dam removal, which would increase cost-based utility 

electricity prices. System reliability should be relatively unaffected because of the capacity value and energy capability of the replacement resources. While 

the supply of ancillary services should be unaffected 

because of the replacement capacity, ancillary service 

prices may increase because of the higher operating 

costs of the replacement thermal resources. 

Summer Spill Operations

The summer spill program at the lower Snake 

River and lower Columbia River hydroelectric projects 

is intended to facilitate the downstream migration of 

anadromous fi sh. The original summer spill requirements date to the 1990s and were incorporated in 

the 2000 Biological Opinion (BiOp). The 2004 BiOp 

incorporated the summer spill operation of the 2000 

BiOp with minor changes. In 2005 and subsequent 

years, summer spill was increased further by court 

order (Preliminary Injunctive Relief Operation). The 

base case (the Fifth Power Plan portfolio) is based 

on 2004 BiOp operations, and thereby represents an 

intermediate level of summer spill.

This study estimates the CO2 production impacts 

of the two summer spill regimes by comparing the 

average Western system dispatch and net CO2 

production for no summer spill operation and court-ordered summer spill operation to the average Western 

system dispatch and net CO2 production of the base 

case (2004 BiOp). The comparison in all scenarios is 

average dispatch and CO2 production for the period 

2015-24.

The base case is as described earlier and includes 

summer spill operation as called for in the 2004 Biological Opinion.

The no summer spill scenario is based on the 

energy shape and output of the hydropower system 

without summer spill at the lower Snake River and 

Columbia River projects. In all other respects, the 

scenario is identical to the base case. About 550 

average megawatts of hydropower energy would be 

gained under this operation compared to the base 

case.

The additional court-ordered spill scenario is based 

on the energy shape and output of the hydropower 

system under 2006 court-ordered spill operation. In 

all other respects, the scenario is identical to the base 

case. About 360 average megawatts of hydropower 

energy are lost under this operation compared to the 

base case.

No summer spill

In the no summer spill scenario, the additional hydro energy would displace about 190 average megawatts from coal-fi red power plants and about 330 

average megawatts from natural gas power plants 

(Figure 9). This would reduce average annual CO2 

production for 2024 from Northwest sources by 1.1 

million tons compared to the base case (2004 BiOp). 

By 2024, 66 MMtpy of CO2 would be produced di-
13

rectly from Northwest sources, a 48 percent increase 

over the 1990 rate. Annual CO2 production for 2024 

across the entire WECC system would decrease 2.4 

million tons compared to the base case.

Court-ordered spill

About 20 average megawatts from coal-fi red power 

plants and about 360 average megawatts from gasfi red power plants are needed to compensate for the 

lost hydro energy of the court-ordered spill scenario. 

This increases average annual CO2 production for 

2024 from Northwest sources by 0.5 million tons 

compared to the base case (2004 BiOp). By 2024, 

67 MMtpy of CO2 would be produced directly from 

Northwest sources, a 52 percent increase over the 

1990 rate. Annual CO2 production for 2024 across 

the entire WECC system increases 1.5 million tons 

compared to the base case.

The overall effect of court-ordered spill compared 

to no summer spill operation within the Northwest is 

to increase the average annual CO2 production for 

2015-24 by 2.1 million tons. For WECC as a whole, 

court-ordered spill increases average annual CO2 

production 5.2 million tons compared to no summer 

spill operation.

-600

-400

-200

0

200

400

600

No summer spill Court-ordered spill

Energy (aMW)

Hydro

Natural gas

Coal

Figure 9: Average annual change in resource output vs. base scenario (WECC, 2015-24o

Sensitivity Cases

Comments on the draft of this analysis requested 

sensitivity cases on some of the basic assumptions 

used in all of the scenarios. These included the effects of higher CO2 costs, higher fuel prices, and 

wind variability.

Higher CO2 costs

All scenarios investigated in this study included the 

mean value CO2 prices from the portfolio risk assessment of the Fifth Power Plan. This price, representing a carbon tax or the cost of carbon allowances 

under a cap and trade system, appears in 2009 and 

gradually rises to about $9.00 per short ton of CO2 by 

2024 (2006 dollars). A sensitivity case with doubled 

CO2 price was run to explore the possible effect of 

increased CO2 price on resource dispatch and CO2 

production. The resource mix was held constant for 

this case, so the impacts of the higher CO2 prices 

are generally limited to shifting from coal to natural 

gas fueled plants. Higher power prices might also 

induce demand response and load curtailment.

With doubled CO2 prices, WECC-wide dispatch 

of coal declined 9 percent, with the difference largely 

met with increased dispatch of natural gas plants. A 

slight increase in demand response was also observed. Northwest CO2 production in 2024 does 

not signifi cantly change from the base case, but for 

WECC in its entirety, 2024 CO2 production declined 9 

million tons.
14

Higher fuel costs

All scenarios investigated in this study were based 

on the medium case fuel price forecast of the Fifth 

Power Plan. Current forecasts of fuel prices, including the recent revision of the Council’s fuel price 

forecast, are generally higher than earlier forecasts, 

including that of the Fifth Plan. Though the Council’s 

revised fuel price forecast had not been adopted 

when the base case analysis was under development, 

a sensitivity analysis was run using the medium-high 

fuel price forecast case of the Fifth Power Plan. North 

American wellhead gas prices in the Fifth Power Plan 

medium-high fuel price forecast are $5.20/MMBtu in 

2024, compared to $4.60/MMBtu in the medium case 

(2006 dollars). The equivalent western mine mouth 

coal prices are $0.67 and $0.59 per MMBtu. The 

resource mix was held constant for this case, so the 

impacts of the higher fuel prices are generally limited 

to shifting between natural gas and coal. As in the 

higher CO2 price case, higher power prices might 

also induce demand response and load curtailment.

For WECC as a whole, the overall dispatch of coal 

and natural gas plants was essentially unchanged in 

the medium-high fuel price case. A slight increase in 

demand response was observed, as was increased 

dispatch of geothermal plants (geothermal plants are 

modeled as dispatchable with a variable fuel cost). 

Higher fuel prices did not signifi cantly affect CO2 production in the Northwest or for WECC as a whole.

Windpower volatility and intermittency

Wind is currently modeled in AURORA with a fl at 

energy output equivalent to annual capacity factor. A 

sensitivity case in which the hourly intermittency of 

wind was modeled using historic hourly output of several geographically diverse Northwest wind projects 

resulted in an insignifi cant change in CO2 production. 

Further testing of the impact of hourly intermittency 

may be desirable as more extensive actual and synthetic wind output data becomes available from the 

Northwest Wind Integration Action Plan. 

Though hourly wind volatility did not signifi cantly affect CO2 production in this sensitivity case, it is possible that sub-hourly wind volatility might impact CO2 

production. In the later years of the study period, 

increasing loads and higher levels of wind penetration may increase the demand for regulation and load 

following services beyond the capability of the hydro 

system to provide these services. Fossil resources 

such as simple-cycle gas turbines may be called upon 

to provide regulation and load following, which would 

increase CO2 production. 

Achieving Signifi cant Reductions 

in CO2 Production 

The fi ndings described in this paper illustrate the 

diffi culty of reducing CO2 production to rates considered necessary for climate stabilization. Current 

rates of conservation acquisition, and policies such 

as renewable portfolio standards mandating acquisition of low carbon resources, will help reduce growth 

of CO2 production. However, as discussed earlier, 

these activities are likely to be insuffi cient to maintain 

current levels of CO2 production, much less to reduce 

CO2 production to levels sought by greenhouse gas 

control policies. Achieving these goals will require 

deep cuts in the CO2 production from existing fossil plants or equivalent offsets from other sectors or 

geographic areas.

To give some perspective to the challenge of meeting proposed CO2 reduction targets, we have calculated the amount of CO2 emissions that would need 

to be reduced from the base case (Fifth Power Plan) 

forecast for 2020. Two cases are illustrated to give 

some perspective on the size of the challenge. One 

is the Western Climate Initiative (WCI) target of reducing CO2 emissions to 15 percent below 2005 levels 

by 2020. Another is to reach 1990 levels by 2020, 

which is both Washington’s target and the target in 

the proposed Lieberman-Warner “America’s Climate 

Security Act.”

Assuming the Northwest power system met similar 

percentage reductions in its 2020 CO2 emissions, 

what is the magnitude of the reduction in terms of 

million tons per year and how can that be put into 

perspective?

Taking the WCI target fi rst, the required reductions 

would depend on how the 2005 CO2 emissions were 

determined. As illustrated earlier, 2005 was a poor 

water year. Actual CO2 production from the power 

system was estimated to be 67 million tons per year. 

The WCI target, if based on actual emissions, would 

be 57 million tons per year. To reduce the base case 

forecast of CO2 production in 2020, which is 65 million tons, down to actual 2005 levels would require a 

reduction of 7 million tons of CO2. However, if based 

on normal hydro conditions, the WCI target would 

be 48 million tons per year. Achieving a WCI target 
15

based on normal hydro would require a reduction of 

17 million tons.

One way to put this into perspective is to calculate 

how much coal capacity would have to be replaced 

with a carbon-free source or with conservation, as 

shown in Table 2. More existing capacity than indicated in the table would require replacement if a portion 

of the replacement resource were low-carbon, such 

as coal gasifi cation plants with partial CO2 separation 

and sequestration. Further analysis would be needed 

to estimate the amount of replacement capacity 

needed, as this depends on the CO2 and economic 

characteristics of the replacement resources. 

A multipronged effort is required for the industry to 

cost-effectively achieve the goals of greenhouse gas 

control policies.13 This effort must include the following elements:

• Reduction in demand through more aggressive 

improvements in end-use effi ciency.

• Shifting new resource acquisitions to low-carbon 

resources.

• Reducing the CO2 production of existing fossil 

generation through effi ciency improvements, carbon 

capture and sequestration, and substituting low-carbon baseload generating capacity.

• Marketing and credit transfer mechanisms to help 

secure CO2 reductions in other economic sectors 

and geographic areas where cost-effective.

In short, achieving greenhouse gas control targets economically requires broadening cost-effective 

resource planning and acquisition to consider a global 

scope of CO2-reduction options. 

While developing mechanisms to facilitate cost-effective global CO2 reduction lies largely outside the 

control of the Northwest power industry, the following 

options can be cultivated within the industry:

Expand the supply of cost-effective energy-effi ciency measures: An expanded inventory of 

end-use effi ciency options will reduce the growth in 

demand for electricity, thereby reducing CO2 production from generating resources. Historically, conservation has been among the most cost-effective and 

abundant of new resource options. New conservation 

opportunities have continued to unfold even as older 

opportunities are developed. Production of CO2 

from power generation can be reduced by aggressive 

implementation of existing conservation measures 

and development of new measures with a focus on 

those most effective during the hours that CO2 -intensive generating resources are on the margin. 

Existing low-carbon generating resources: The 

effi ciency, energy output, and operating life of existing 

low-carbon resources can be improved. For example, 

each percentage point increase in the capacity factor 

of Columbia Generating Station will offset approximately 0.05 million tons of CO2 per year.14 Opportunities to improve the effi ciency and capacity, and 

extend the life of the region’s existing biomass, hydropower, and nuclear resources can be explored and 

pursued where cost-effective.

New renewable generation: Expanding the supply 

and improving the cost-effectiveness of new renewable resources involves concurrent efforts: First, the 

Policy 2020 Target 

(MMtCO2) 

Reduction

Needed

(MMtCO2)11

Equivalent

Coal

Capacity

(MW)

WCI - 15% below actual 2005 by 2020 57 7 910

WCI - 15% below normal 2005 by 2020 50 17 2330

WA - 1990 by 202012 44 21 2780

OR - 10% below 1990 by 2020 40 25 3300

Table 2: CO2 reductions from base case (Fifth Power Plan) forecast to achieve various 2020 policy targets

11Reduction from base case (Fifth Power Plan) 2020 forecast. 12Also the target of the proposed Lieberman-Warner America’s Climate Security Act. 13A recent study by the Electric Power Research Institute provides a very useful illustration of the challenge to signifi cantly reduce 

power system CO2 emissions. See EPRI, “The Power To Reduce CO2 Emissions: The Full Portfolio,” August 2007.

14Based on an average systemwide marginal CO2 production rate of 0.9 lb/kWh as estimated by the Council (“Power System Marginal 

CO2 Production Factors,” Northwest Power and Conservation Council, April 2006). 
16

supply of regulation, load following, shaping, and 

storage capability needed for integrating intermittent 

resources such as wind, tidal currents, wave, and 

solar need to be expanded through the development 

of improved methods of marketing and transferring 

these services within the existing system. Because 

the supply of these services will eventually need to 

be augmented, options for supplying these services, 

including generation, storage, and load-side proposals such as plug-in hybrid vehicles need to be better 

understood. Secondly, the capacity of the existing 

transmission system to serve new renewable resources needs to be expanded by developing products 

such as a conditional-fi rm service that more effectively 

utilizes the existing transmission capacity. New transmission will be needed to serve increasing amounts 

of remote renewable capacity and to improve the 

geographic diversity of wind and other intermittent 

renewable resources. Mechanisms are needed to 

facilitate planning, fi nancing, and construction of 

new transmission, including “merchant” transmission 

primarily serving new resources. Finally, new renewable resources and technologies, including wave and 

tidal current power production, low temperature and 

engineered geothermal resources, dedicated energy 

crops, and more effi cient biomass technologies need 

to be developed.

New fossil generation: Even with aggressive conservation measures and an expanded supply of 

renewable resources, new, lower-carbon fossil generation may be the most cost-effective source of baseload power. Moreover, gas turbines may be needed 

to augment the supply of integration services for intermittent renewable resources. Improving the effi ciency 

of conventional gas turbine and pulverized-coal power 

plants, and commercializing coal gasifi cation and 

other advanced coal technologies will extend fuel supplies and lower CO2 production at the source. 

Carbon capture and sequestration: CO2 capture 

technology suitable for coal gasifi cation plants is 

commercially available. However, while technically 

feasible, CO2 capture for conventional and advanced 

coal-steam plants and gas turbine plants is at the 

early demonstration stage. Development and commercialization of CO2 capture technology for all forms 

of fossil generation need to be accelerated to provide 

options for both new and retrofi t applications. 

Bulk CO2 transportation and sequestration has 

been demonstrated for depleted oil and gas reservoirs. While some oil and gas reservoirs are present 

in Montana, a greater potential in the Northwest are 

the basalt fl ows of the Columbia Basin and Snake 

River Plain. Additional Northwest potential may be 

available in deep coal seams, carbonate saline aquifers, oceanic storage, and soil carbon sequestration 

in croplands, grazing lands, and forests. Work needs 

to proceed on investigating and fi eld-testing promising 

sequestration options for the Northwest.

New nuclear generation: A new generation of nuclear plants could provide bulk quantities of carbon-free 

baseload power. Approximately 30 new nuclear units 

are proposed for construction in the United States. 

The license application for the fi rst two has recently 

been fi led with the Nuclear Regulatory Commission 

and license applications for additional units are expected in 2008. While the fi rst new units completed 

are likely to be located in the Southeast (a region with 

less favorable renewable resource potential than the 

Northwest) and not be completed until 2014-15, new 

nuclear plants may become attractive to the Northwest once new units are successfully operating and 

resolution of the spent fuel disposal issue is achieved. 

Appendix A: Methodology and 

Analytical Issues

The CO2 production of each scenario was forecast using the AURORAxmpTM Electric Market Model. 

Though primarily used to forecast wholesale electricity 

prices, AURORA is also capable of forecasting pollutant emissions and CO2 production resulting from 

system operation. AURORA forecasts power prices 

by simulating the economic dispatch of individual 

generating units as needed to meet system load. 

Fuel consumption is tracked because fuel prices are 

a major component of the variable cost of electricity 

production with which plant dispatch is evaluated and 

power prices determined.

CO2 production was calculated using the following emission factors: natural gas 117 lb/MMBtu, fuel 

oil 166 lb/MMBtu, coal 212 lb/MMBtu, and petroleum 

coke 225 lb/MMBtu. Complete conversion of fuel 

carbon to CO2 was assumed. Biomass fuels, including municipal solid waste, are assumed to produce no 

net CO2. While some of the combustible content of 

municipal solid waste fuels is of petroleum or nonclosed carbon cycle derivation, the small consumption 

of municipal solid waste for power production in the 
17

Northwest has a negligible effect on net CO2 production. The CO2 output of fossil-fueled cogeneration 

units is based on “fuel charged to power” heat

rates—the portion of fuel consumption attributable to 

electricity production. 

With the exception of a sensitivity analysis on 

water conditions, described later, this work was based 

on 50-year average hydropower conditions, the medium-case fuel price forecasts, and the medium-case 

load growth forecasts of the Fifth Power Plan. As a 

result, the CO2 production forecasts are representative of long-term averages (to the extent that forecast 

fuel prices and demand are realized). Actual CO2 

production will vary from the average depending on 

hydropower conditions, actual fuel prices, and actual 

loads. As illustrated earlier in Figure 2, CO2 production is sensitive to hydropower conditions, including 

runoff patterns. In general, hydropower displaces 

more thermal energy in good water years than in poor. 

Heavy spring runoff may displace coal-fi red power 

plants during light springtime load periods, whereas 

delayed runoff may displace natural gas combined-cycle plants during heavier early summer loads. While 

economically benefi cial because of the higher cost of 

natural gas, the later runoff would have less impact on 

CO2 production because of the lower carbon content 

of natural gas and the higher thermal effi ciency of 

combined-cycle plants.

A question has been raised regarding the symmetry of the incremental effects on CO2 production of 

good and poor hydropower years of equal probability. 

If incremental CO2 production effects are not symmetrical, the estimates reported here may be biased, 

as they are based on average water conditions.

A comparable effect has been observed, and is 

adjusted for, in the Council’s electricity price forecasting. While time did not permit comprehensive testing, 

a limited comparison of forecast CO2 production in 

a very good water year to that of a very poor water 

year indicated a slight increase in the incremental 

CO2 production for the poor water year compared to 

the good water year. While further analysis would be 

required to confi rm the consistency and magnitude 

of this effect, if true, the CO2 production estimates 

reported in this paper would tend to be slightly low.

The geographic scope of the analysis is the WECC 

interconnected system. Northwest resource development and operational decisions result in operational 

effects outside the Northwest because of transmission interconnections and Westwide markets. For 

this reason, CO2 production results are reported on 

a WECC basis. “Northwest” results, where reported, 

include the CO2 production of units physically located 

within the four Northwest states, plus the production 

from large thermal units outside the region dedicated 

to serving Northwest loads. These include the Jim 

Bridger plant in Wyoming and the Idaho Power share 

of the North Valmy plant in Nevada.

The net changes in CO2 production estimated in 

this study are the direct effects of power plant fuel 

consumption. Secondary impacts, not assessed here, 

may be present (e.g., CO2 from diesel oil combustion 

for the rail transportation of additional coal).

Price elasticity may result in reduction of demand 

due to higher prices caused by carbon taxes, highercost low carbon resources, cost of CO2 allocations, 

or other factors associated with climate change and 

policies addressing climate change. While the evaluation of this is beyond the scope of the current study, 

price elasticity will be considered in the Sixth Power 

Plan. 

California, Oregon, and Washington have adopted 

policies prohibiting the long-term acquisition by utilities of resources or resource output where the associated CO2 production exceeds certain defi ned levels 

(generally exceeding the CO2 production of a natural 

gas-fi red combined-cycle plant). Partial account 

of these carbon content policies is included in current analysis by permitting no new conventional coal 

plants to be located in California, Oregon or Washington when using the AURORAxmp capacity expansion 

feature. However, because AURORAxmp does not 

permit differentiation by resource type of economic 

inter-regional transfers, there appears to be no effective method of modeling carbon content policies.

Suffi cient simple or combined-cycle gas turbine capacity was added in each scenario to maintain the pilot capacity reserve targets of the Resource Adequacy 

Forum. (The capacity value of wind power was set at 

15 percent for these assessments.) This gas turbine 

capacity would also provide “system fl exibility” suitable for integrating intermittent resources. However, it 

will not be possible to accurately estimate the amount 

of fl exibility augmentation needed to accommodate 

the intermittent resources of these portfolios until the 

capability of the existing system to provide intermittent 

resource integration is better understood. Estimates 

of the intermittent resource integration capability of 

the existing system are being refi ned as part of the 

Northwest Wind Integration Action Plan. The needed 

capacity composition of future resource portfolios can 
18

be refi ned as better estimates of the capabilities of 

the existing system (and likely fl exibility demands of 

future intermittent resources) become available. This 

information may also support estimates of the likely 

CO2 production resulting from possible operation of 

fossil capacity for intermittent resource integration 

purposes. 

Appendix B

Conservation 

(aMW) 

Coal 

(MW)

Gas

(MW)

Hydro Wind

(MW)

Other

(MW)

2005 96 178 (SC) 300 (26) Oil 

2006 

136

109 (PC) 47 (SC) 14 Hyd 

(26) Hyd 487 

10 Geo 

12 Bio 

2007 

139

 745 (CC) 2 Hyd 

(29) Hyd 440 

 20 Bio 

(32) Oil 

2008 147 650 (CC) (23) Hyd 

2009 150 (23) Hyd

2010 159 (23) Hyd

2011 161 (23) Hyd 100 

2012 169 (23) Hyd 900 

2013 172 (23) Hyd 400 

2014 176 (23) Hyd 600 

2015 378 (23) Hyd 300 

2016 185 425 (IGCC) (23) Hyd 1200 

2017 105 (23) Hyd 600 

2018 93 (23) Hyd 400 

2019 89 184 (SC) (23) Hyd 200 

2020 86 610 (CC) (23) Hyd 100 

2021 85 644 (SC) (23) Hyd 300 

2022 84 (23) Hyd 100 

2023 86 276 (SC) (23) Hyd 100 

2024 85 276 (SC) (23) Hyd 900 

Table B1: Pacifi c Northwest resource development schedule for the base case (MW)15

15Values in brackets are retirements.
19
20

851 S.W. Sxith Avenue, Suite 1100

Portland, Oregon 97204

800-452-5161

www.nwcouncil.org