2

Table of Contents

INTRODUCTION ......................................................................................................................................4

NATURAL GAS .......................................................................................................................................4

Historical Consumption and Price....................................................................................................................................................4

Natural Gas Resources.......................................................................................................................................................................10

Natural Gas Delivery..........................................................................................................................................................................13

Forecast Methods .................................................................................................................................................................................14

Forecasts.................................................................................................................................................................................................15

US Wellhead Prices............................................................................................................................................................................... 15

Regional Natural Gas Price Differentials .......................................................................................................................................... 19

Retail Prices............................................................................................................................................................................................ 21

OIL ........................................................................................................................................................24

Historical Consumption and Price..................................................................................................................................................24

Methods ..................................................................................................................................................................................................26

World Crude Oil Price Forecast......................................................................................................................................................27

Consumer Prices..................................................................................................................................................................................29

COAL PRICE FORECASTS....................................................................................................................30

APPENDIX A - FUEL PRICE FORECASTING MODEL ..............................................................................1

Introduction ............................................................................................................................................................................................1

Model Components ...............................................................................................................................................................................1

Natural Gas Model ................................................................................................................................................................................2

Oil Model..................................................................................................................................................................................................5

Coal Model...............................................................................................................................................................................................7

APPENDIX B - DERIVATION OF NATURAL GAS PRICES BY MARKET POINTS AND STATES ...............1

APPENDIX C - FORECAST TABLES FOR U.S. WELLHEAD AND REGIONAL RETAIL NATURAL GAS 

PRICES ...................................................................................................................................................1

APPENDIX D - FORECAST TABLES FOR U.S. WELLHEAD AND REGIONAL MARKET PRICES .............1
3

APPENDIX E - FORECAST TABLES FOR WORLD OIL AND REGIONAL RETAIL OIL PRICES ................1

APPENDIX F - FORECAST TABLES FOR WESTERN MINEMOUTH AND REGIONAL DELIVERED COAL 

PRICES ...................................................................................................................................................1
4

Fuel Price Forecasts

 For the Draft Fifth Power Plan

September 10, 2002

Introduction

Fuel prices affect electricity planning in two primary ways. They influence electricity demand 

because they are substitute sources of energy for space and water heating and some other end-uses as 

well. They also influence electricity supply and price because they are potential fuels for electricity 

generation. Natural gas, in particular, has become the most cost-effective generation fuel when used 

to fire efficient combined-cycle combustion turbines. This second effect will be the primary use of 

the fuel price forecast for the Council’s 5th power plan.

Traditionally, the Council has developed very detailed forecasts of electricity demand using models 

that are driven by economic, fuel price, and technological assumptions. For a number of reasons, the 

Council has chosen to retain many elements of its long-term demand forecasts from the 4th power 

plan, making modifications as needed to reflect significant changes that might affect the long-term 

trend of electricity use. Therefore the fuel price assumptions will not directly drive the demand 

forecasts of this power plan.

The fuel price forecasts will affect the expected absolute and relative cost of alternative sources of 

electricity generation. Through their effects on generation costs, they will also largely determine the 

future expected prices of electricity.

This paper describes draft fuel price assumptions for the Northwest Power Planning Council’s 5th

power plan. Three major sources of fossil fuels are addressed; natural gas, oil, and coal. For each, 

the paper provides some background on historical consumption patterns and prices. This is followed 

by a description of the methods used to forecast fuel prices and the resulting forecasts. Appendices 

provide more detail on the methods and forecasts.

Natural Gas 

Historical Consumption and Price

In 2000, the Pacific Northwest consumed 581 bcf (billion cubic feet) of natural gas. About 45 

percent of this natural gas was used in the industrial sector, which includes electricity generation by 

non-utility power plants. About a quarter of the natural gas use is in the residential sector and about 

17 percent is in the commercial sector. In 2000, electric utilities consumed 83 billion cubic feet of 

natural gas, or about 14 percent of the regional total natural gas consumption. Utility natural gas 

consumption in 2000 was nearly 3 times the amount consumed in 1999, and it remained high in the 

early months of 2001. Clearly, the natural gas use for electricity generation was extraordinary in 

2000 and early 2001 due to the electricity crisis in the West. Generating plants normally used only 
5

during extreme peak electricity needs were operated for much of the winter of 2000-01. However, 

new gas-fired generation has been constructed and planned recently, which will increase normal 

levels of gas use for electricity generation. Natural gas use for electricity generation receives further 

discussion later.

The regional consumption of natural gas has grown rapidly over the last several years. Between 

1986 and 2000 regional natural gas consumption grew 6.8 percent a year, more than doubling natural 

gas consumption over a 14-year period. Figure 1 shows natural gas use by sector since 1976. After 

1986, all sectors grew, but the industrial sector accounted for nearly half of the increase in gas 

consumption and grew at a higher rate than residential and commercial use.

Figure 1 

Pacific Northwest Natural Gas Consumption

0

100

200

300

400

500

600

700

1976197819801982198419861988199019921994199619982000

Billion Cubic Feet

Residential

Commercial

Industry

Electric Utility

Total

Source: Energy Information Administration and NPPC calculations.

The rapid growth in natural gas use since 1986 has coincided with a period of ample natural gas 

supplies and attractive prices coupled with strong economic growth in the region. Figures 2a and 2b 

illustrate the Pacific Northwest natural gas prices and consumption since 1976 for the residential and 

industrial sectors. High natural gas prices and a severe economic downturn in the early to mid1980s kept natural gas consumption low. However, following the deregulation of natural gas prices 

in the late 1980s, prices fell and demand began to grow rapidly. Natural gas displaced oil and other 

industrial fuels for economic and environmental reasons during this time. Higher electricity and oil 

prices for residential consumers combined with lower natural gas prices, made natural gas a more 

attractive heating fuel for homes.
6

Figure 2a

Pacific Northwest Industrial Natural Gas Consumption and Price

0

50

100

150

200

250

300

1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000

Consumption

 (Bcf)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Real Price

 (2000$/MMBtu)

Consumption

Price

Figure 2b

Pacific Northwest Residential Natural Gas Consumption and Price

0

20

40

60

80

100

120

140

1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000

Consumption

 (Bcf)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Real Price

 (2000$/MMBtu)

Consumption

Price

The most significant trend in natural gas markets recently has been the increasing use of natural gas 

for electricity generation. This is a relatively recent trend, but attracts a lot of attention because of 

the expectations of rapid growth in the future. Figure 1 showed that there has been some natural gas 

used for electricity generation by electric utilities since 1988. It increased recently, but is still a 
7

relatively small amount of the total natural gas use in the region. Non-utility electricity generators 

have used additional natural gas, but the data does not allow it to be broken out from overall 

industrial sector natural gas use. Given the level of concern about natural gas supplies, and the 

potential for a greatly increased use for electricity generation, it is worth understanding the current 

and potential role of natural gas in electricity generation.

Natural gas currently accounts for only 9 percent of the region’s electricity generation capacity. In 

terms of average energy generated the share is higher at 14 percent. That is because the 

hydroelectric capacity, which dominates the region’s generating capacity, is limited in its annual 

production by the amount of water available so that its share of average generation is much lower 

than its capacity rating. 

At the end of 1999 there were 37 plants that could generate electricity using natural gas with a 

combined generating capacity of 3,430 megawatts. Over half of this capacity (1,900 megawatts) 

had been built since 1990. Sixty percent of this capacity was owned by electric utilities and twothirds of the capacity is located on the west side of the Cascade Mountains. Many of these plants 

have the ability to burn other fuels such as, wood waste, refinery gas, or oil. 

If all of the plants that have natural gas as their primary fuel were operating, they have the capability 

to burn 668 million cubic feet of natural gas per day. Plants on the West side could burn as much as 

476 million cubic feet per day. For perspective, this can be compared to the total capacity to deliver 

natural gas to the I-5 corridor on a peak day in 2001, which was estimated to be 3,589 million cubic 

feet.1 If operated continuously for a year the region’s gas-fired generators in 1999 could burn 242 

billion cubic feet of natural gas. This compares to an estimated 2001 total regional natural gas 

consumption of 670 billion cubic feet.

However, gas-fired generating plants in the region have not operated for a large part of the year, nor 

have they typically operated during peak natural gas demand events. This is partly due to the fact 

that in most years there is surplus hydroelectricity in the region. For example, utility-owned natural 

gas-fired generating plants in place at the end of 1999 had the capability to burn 141 billion cubic 

feet a year if operated at an 85 percent capacity factor on natural gas. However, as shown in Figure 

1, utilities only consumed 30 billion cubic feet of natural gas in 1999. In other words, utility-owned 

gas-fired generating facilities only consumed 20 percent of their capability in 1999. If the non-utility 

electricity generating capacity were assumed to operate at the same relative rate, they would have 

consumed only 14 billion cubic feet out of the 262 billion cubic feet of total industrial consumption 

in 1999.

In 2000, utility-owned gas-fired generation increased dramatically from 30 billion cubic feet in 1999 

to 83 billion cubic feet. Non-utility generation from natural gas increased as well, but by a smaller 

percentage. This was not a result of additional gas-fired generation capacity being added in 2000. It 

was a response to the energy crisis of 2000 and the extremely high electricity prices that 

accompanied it. Existing gas-fired generation was operated far more intensively than normal.

In 2001 an additional 1,176 megawatts of gas-fired generation was put in service in the region, a 36 

percent increase in gas-fired generation capacity. Another 1,578 megawatts is under construction for 

 

1

 Regional Resource Planning Study, BC Gas Utility Ltd., July 10, 2001.
8

completion in 2002. Although some of the new plants have recently been delayed, new gas-fired 

generation will have a substantial impact on natural gas consumption in the region.

In the past, most natural gas-fired electricity generation in the region has not operated on firm 

natural gas supplies and delivery. By buying interruptible service, the cost of natural gas could be 

reduced substantially. When interruptions came, during peak natural gas demand times, most of the 

plants, even if running, could switch to alternate fuels. Increasingly, new gas-fired generation plants 

are intended to operate at a high capacity factor and are more likely to use firm natural gas supplies 

and transportation.

The use of interruptible demand is a key feature in the ability of the natural gas industry to meet 

peak day demands for its product. Figure 3 illustrates the role of interruptible consumers in meeting 

peak day natural gas demand.2 The use of natural gas storage withdrawal and the injection of 

liquefied natural gas into pipelines are also used to meet peak requirements and help to increase the 

capacity utilization of natural gas pipelines. 

Figure 3

Contributions to Peak Day Natural Gas Supplies

Pipeline

59%

Storage

27%

Interruption

5%

LNG

9%

With a growing share of natural gas demand expected to be firm electricity generation, the share of 

interruptible demand may fall as a percent of total demand. This is likely to increase the value of 

other strategies for meeting peak gas demand such as storage and LNG injection. To the extent that 

increased gas-fired electricity generation turns out to add substantially to highly variable natural gas 

demand, the overall capacity factor of natural gas consumption would decrease. Lower capacity 

factors mean that, in general, the cost of natural gas on a per unit consumed basis could increase as 

fixed capacity costs are spread over a smaller amount of consumption per unit of capacity. This is 

not the only possibility, however. If many new gas-fired generating plants operate at a high capacity 

factor, or if they tend to operate more in the summer, they could have the opposite effect. They 

 

2

 Based on Regional Resource Planning Study, BC Gas Utility Ltd., July 10, 2001.
9

could partly offset the highly seasonal demand of the residential and commercial sectors and raise 

the overall capacity factor of the natural gas system.

In the summer of 2000, the use of natural gas-fired generation changed substantially on the West 

Coast. Poor hydroelectricity supplies and a growing electricity generating capacity shortage caused 

electricity prices to increase by a factor of 10 or more. The extremely high electricity prices made it 

attractive to burn gas for electricity generation; it was very profitable, and the electricity was badly 

needed to meet electricity demand. As a result, the use of natural gas on the West Coast for 

electricity generation increased dramatically. For example, it has been reported that California 

generators consumed 690 billion cubic feet of gas in 2000 compared to a normal consumption of 270 

billion cubic feet.3 Much of this increase in natural gas use began in the summer when natural gas 

use is typically lower and natural gas is injected into storage for use during the next winter heating 

season.

The problem created in natural gas markets may be some indication of the effects of the predicted 

growing natural gas use for electricity generation in the future. In many regions, electricity use 

peaks in the summer. Growing use of natural gas for electricity generation has the potential to 

change the traditional seasonal patterns of natural gas storage and withdrawals. Less than expected 

storage injections in the summer and fall of 2000 led to concerns about natural gas shortages for the 

winter and pushed prices for natural gas to levels not seen since the early 1980s. This problem was 

especially severe in California, and combined with pipeline capacity strains, pushed prices in the 

West to levels several times historical levels.

However, the dramatic increase in the use of natural gas in existing generation plants in 2000 and 

early 2001 clearly had an exaggerated effect on natural gas markets and prices. Due to the sudden 

and severe shortage in electricity supplies and the unprecedented electricity prices, the natural gas 

delivery system in the West was pushed far beyond normal operational patterns. Thus, the impacts 

on natural gas prices were more severe than should be expected from an orderly development of 

additional natural gas demands for electricity generation.

Nearly all new proposed electricity generation capacity is natural gas fired. Although natural gas 

consumption only recently returned to the levels of the early 1970s, substantial growth is now being 

projected due to growing plans for electricity generation. The U.S. Energy Information 

Administration is forecasting a growth in natural gas use of 2.0 percent per year for the next 20 

years.4 Residential, commercial and industrial sector natural gas use is projected to grow modestly 

at a little over 1 percent per year, but natural gas use for electricity generation is projected to grow 

by over 5 percent a year. The EIA forecasts would result in total U.S. natural gas consumption 

increasing from the current level of about 23 trillion cubic feet per year to nearly 34 trillion cubic 

feet in 2020. 

In the Pacific Northwest, complete reliance on natural gas fired generation to meet a projected 

electricity demand growth of 1.5 percent a year for the next 20 years could add 432 billion cubic feet 

of natural gas consumption to the current 540 billion cubic feet per year. This is nearly a doubling of 

natural gas consumption over 20 years. Modest growth in other sectors’ natural gas use could easily 

complete the doubling of natural gas use in the region over the next 20 years. This is not 

 

3 Natural Gas Week, Vol. 17, No. 18 (April 30,2001).

4

 U.S. Energy Information Administration, Annual Energy Outlook 2002.
10

unprecedented since Northwest consumption of natural gas more than doubled in the 13 years 

between 1986 and 2000. However, it will require continued expansion of natural gas supplies, 

pipeline capacity, and other elements of the natural gas delivery system, such as storage.

To the extent that the western United States depends on natural gas for new electricity generation, 

the price of natural gas will be a key determinant of future electricity prices. Economic theory 

suggests that over the long run electric ity prices will be equal to the cost of new sources of supply. 

Natural Gas Resources

Currently, U.S. natural gas supplies are largely domestic, supplemented by substantial imports from 

Canada. In 2001, the United States imported 3.75 trillion cubic feet of natural gas from Canada; 1.1 

trillion cubic feet were imported through Huntington and Kingsgate on the region’s border with 

Canada, with a substantial amount of that gas destined for California markets.

Natural gas is created by natural processes and is widespread. Most current recovery methods 

attempt to exploit natural geologic formations that are able to trap natural gas in concentrated 

pockets. However, natural gas occurs in more dispersed forms as well. Eventually, it is likely to 

become possible to recover natural gas from some of these formations. Coal bed methane is a good 

example. Substantial amounts of natural gas are often associated with coal deposits. In the last 

several years methods have developed, with some government incentives, to extract the natural gas 

from coal formations and this coal bed methane has made substantial contributions to the natural gas 

supplies in the Rocky Mountain area. It now accounts for about 7.5 percent of U.S. natural gas 

production. 5 Expansion of natural gas supplies eventually will have to move into these less 

conventional areas in terms of both geographic structures and locations. As natural gas supplies 

expand into unconventional sources and less accessible areas costs are expected to increase. How

much they increase depends a great deal on technological developments in the exploration and 

recovery field.

The availability of natural gas to meet growing demands is a key issue. Assessing natural gas 

resources is a confusing and difficult exercise. There is no absolute answer to the question of how 

much natural gas there is and how long it will last. Traditionally, the question has been approached 

on a North American basis although Mexico has not traditionally played a large role. With the 

potential for increased use of liquefied natural gas (LNG) imports and exports, the market could 

become international, similar to current oil markets. Meanwhile, it may be instructive to look at 

North American natural gas resource estimates in a fairly traditional way.

There are two main categories of natural gas supplies. “Reserves” refers to natural gas that has been 

discovered and proved producible given current technology and markets. Reserves are developed as 

needed by drilling wells in areas that are expected to hold natural gas producing potential. Reserves 

are often confused with the ultimate potential natural gas “resources”, which is the second category 

of natural gas supplies. Natural gas “resources” are more speculative than reserves. Resource 

estimates are more uncertain. They are based on assessment of geologic structures, not direct 

drilling results. Resource estimates are speculative estimates of natural gas that might be 

developable with known technology and at feasible costs. Reserves are more like the amount of 

natural gas resource that has been developed and is available to be produced within a relatively short 

 

5

 U.S. Geological Survey. “Coal-Bed Methane: Potential and Concerns”. USGS Fact Sheet FS-123-00 (October 2000).
11

period. Reserves should be thought of as an inventory of natural gas to be produced and marketed 

within a few years.

Natural gas reserves have decreased relative to consumption levels since deregulation of natural gas 

supplies and changes in Canadian export policies in the 1980s. Some have taken this decline as an 

indication that we are running out of natural gas. In reality, it is a result of reducing inventory 

holding costs as a response to increased competition. It is similar to the new approaches to other 

kinds of inventory in the modern economy where businesses hold down inventory storage time and 

costs. In Canada, it was also influenced by a change in a rule that required Canada to have a 20-year 

reserve for Canada’s internal natural gas demand before any natural gas could be exported. 

Canadian reserves are now closer to 10 years supply.

So reserves are constantly being consumed and replaced. The relative rates of consumption and 

replacement vary with economic conditions and natural gas prices. During periods of low natural 

gas prices, consumption tends to increase and there is a reduced incentive to develop new reserves. 

Eventually, that leads to falling reserves and creates an upward pressure on prices such as the nation 

experienced recently. With the natural gas industry operating at narrower reserve margins, these 

cyclical patterns might become more severe and lead to growing natural gas price volatility.

Another common error in assessing natural gas supplies is to assume that the estimates of ultimate 

natural gas resources are static. In reality, natural gas resource estimates have shown a tendency to 

increase over time as technology improves and new discoveries are made. To illustrate this point, 

note that in 1964 the Potential Gas Committee, which estimates natural gas resources, estimated 

potential natural gas resources to be 630 trillion cubic feet. By 1996, the nation had consumed more 

than 630 trillion cubic feet of natural gas. If the potential resource were a fixed limit, as many 

interpret it, we would have run out of natural gas by now. Instead the estimated potential remaining 

natural gas resource in 1996, at 1038 trillion cubic feet excluding proved reserves, was actually 

higher than the estimate of what was remaining in 1964 in spite of over 30 years of continuing 

consumption.

The Potential Gas Committee estimated that in 1996 the natural gas reserves and potential resources 

were 1205 trillion cubic feet and noted that at current consumption rates that would be a 63-year 

supply. A little different approach to estimating the years that the current estimated resource would 

last is to look at North American natural gas resource estimates and a predicted growing natural gas 

consumption to see how long those supplies would last. Table 1 shows an estimate of remaining 

natural gas resources. Note that both of these calculations assume that potential natural gas resource 

estimates would not grow over time, as they have historically. 

Figure 4 plots the growth in cumulative natural gas consumption into the future and identifies the 

years when the current resource estimate would be exhausted. The Mexican consumption of natural 

gas and its natural gas resources have been excluded from Figure 4. U.S. and Canadian consumption 

is assumed to grow at 2.0 percent a year. Under these assumptions current estimated resources 

would last about 40 to 50 years. 
12

Table 1

Remaining Natural Gas Resources in North America

(Trillion Cubic Feet)

Already Produced Remaining Reserves Remaining Resources

Lower 48 States 847 166 1078-1548

Alaska 0 0 237

Canada 103 51 559-630

Mexico 34 72 230-250

Total 984 289 2104-2665

However, based on past experience the resource estimates are likely to increase over time in 

unpredictable ways. Some examples of potential changes will give some idea of what the future 

could hold in the longer term for natural gas resources. As in the case of oil, many natural gas 

resources lie outside of North America. Currently estimated conventional natural gas resources 

world wide are 13,000 trillion cubic feet. As natural gas prices increase, the use of liquefied natural 

gas transportation will make these resources increasingly accessible to North America. As noted 

above natural gas occurs throughout nature in many forms. In addition to coal bed methane, there 

are geopressurized brines and gas hydrates.6 The ability to recover such sources is unknown at this 

point, but as new sources of gas are needed in the distant future, new technologies may facilitate 

some use of these resources. Gas hydrates, for example, are estimated to contain from 100,000 to 

300,000,000 trillion cubic feet of natural gas resource.7

Figure 4

Cumulative Natural Gas Production and Resources

Cumulative Production and Resource 

Estimates: at 2 % Demand Growth

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

4000.00

4500.00

5000.00

2000 2010 2020 2030 2040 2050 2060 2070 2080

Trillion Cubic Feet

Proved Reserves - 8 Years

Lower Resource Estimate - 44 Years

Upper Resource Estimate - 52 Years

 

6

 U.S. Geological Survey. “Describing Petroleum Reservoirs of the Future”. USGS Fact Sheet FS-020-97 (January 

1997).

7 U.S. Geological Survey. “Natural Gas Hydrates - Vast Resource, Uncertain Future”. USGS Fact Sheet FS-021-01 

(March 2001)
13

Natural Gas Delivery

Another important consideration in natural gas supply and cost is the capacity to transport the gas 

from the wells to the points of consumption. This involves gathering the gas from wells, processing 

the gas to remove liquids and impurities, moving the gas over long distances on interstate pipelines, 

and finally distribution to individual consumers home and businesses.

The sources of natural gas for the Pacific Northwest are the Western Canada Sedimentary Basin in 

Alberta and Northeast British Columbia and the U.S. Rocky Mountains. Two major interstate 

pipelines deliver natural gas into the Pacific Northwest region from Canada. Williams Northwest 

pipeline brings natural gas from British Columbia producing areas through Sumas, Washington 

where it receives gas from the Duke Westcoast pipeline in Canada. Williams Northwest pipeline 

also brings U.S. Rocky Mountain natural gas into the region from its other end. Thus, Williams 

Northwest is a bi-directional pipline; it delivers gas from both ends toward the middle. The second 

interstate pipeline serving the region is the PG&E Gas Transmission Northwest (GTN) pipeline, 

which brings Alberta supplies through Kingsgate on the Idaho - British Columbia border. Much of 

the gas flowing on the GTN is destined for California. The GTN and William Northwest pipelines 

intersect near Stanfield, Oregon. The natural gas pipeline system serving the Pacific Northwest is 

illustrated in Figure 5

Figure 5

Natural Gas Pipelines Serving the Pacific Northwest

PG&E GTN

Pipeline

To Northern

California

Hermiston

Chehalis

Sumas

From Rocky

Mtn. and San

Juan Basins

From WCSB

Alberta

Seattle

Portland

Kingsgate

Williams Northwest

Pipeline

Williams Northwest Pipeline

PG&E GTN Pipeline

Pipeline Lateral

From WCSB

British Columbia

The development of interstate pipeline capacity is based on the willingness of local distribution 

companies or other shippers of natural gas to subscribe to capacity additions. Historically, local gas 

distribution companies, the regulated utilities that serve core customers’ natural gas demand, have 

owned much of the capacity on interstate pipelines. Because residential and commercial natural gas 

use varies seasonally and with temperatures, there is often pipeline capacity that is available for 
14

resale. Large industrial consumers and others who have some flexibility can acquire this capacity on 

a short term or capacity release basis. Interruptible consumers rely on this type of pipeline capacity, 

and it is typically available except in extremely cold winter days.

Growing natural gas demand results in pipeline capacity expansion as it is needed and as distributors 

or consumers are willing to pay for the capacity on an individual contractual basis. Interstate 

pipeline capacity is not expanded on a speculative basis based on someone’s forecast of natural gas 

demand. Various expansions of pipeline capacity are currently underway on both the Williams 

Northwest and the GTN systems as well as on other pipelines throughout the West. Most of the 

entities committing to these capacity expansions are electricity generators who are securing natural 

gas delivery capacity for proposed new electricity generating plants. Generating plant developers 

indicate that firm pipeline capacity is required in order to get financial backing for a new gas-fired 

combined cycle plant.

Over the long term it should be expected that pipeline capacity will be expanded to deliver the 

necessary natural gas to regional consumers. In the short term, extremely unusual natural gas 

demands can place severe strain on pipeline delivery capacity, which can in turn cause serious 

natural gas price excursions. This was the situation in the West in 2000-2001 when prices in 

California and the Northwest became disconnected from other U.S. prices.

Forecast Methods

Natural gas prices, as well as oil and coal prices, are forecast using an Excel spreadsheet model. The 

model does not address the basic supply and demand issues that underlie energy prices. Instead 

assumptions are made about the basic commodity price trends at a national or international level 

based on analysis of past price trends and market behavior and on forecasts of other organizations 

that specialize in such analyses. The model then converts the commodity price assumptions into 

wholesale prices in the Pacific Northwest and then adds transportation and distribution costs to 

derive estimates of retail prices to various end-use sectors.

Because natural gas is the primary end-use competitor for electricity, and because it is the electricity 

generation fuel of choice at this time, natural gas prices are forecast in more detail than oil and coal 

prices. Residential and commercial sector retail natural gas prices are based on historical retail 

prices compared to wellhead prices. For historical years the difference between wellhead prices and 

retail prices are calculated. For forecast years, the projected difference is added to the wellhead 

price forecast. The differences between retail and wellhead natural gas prices can be projected from 

historical trends, other forecasting models, or judgment.

Gas prices for small industrial gas users that rely on local gas distribution companies to supply their 

gas are forecast in the same manner as residential and commercial users. However, large firm or 

interruptible natural gas consumers, whether industrial or electric utility, must be handled with a 

different method. This is because there is no reliable historical price series for these gas users to 

base a simple markup on. For these customers, the difference between wellhead and end-user prices 

is built up from a set of transportation cost components and regional gas price differentials 

appropriate to the specific type of gas use. 

The components include pipeline capacity costs, pipeline commodity costs, pipeline fuel use, local 

distribution costs, firm gas supply premiums, and regional wellhead price differentials. The latter is 
15

necessary because the driving assumption is a national average wellhead gas price. Wellhead prices 

in British Columbia, Alberta, and the Rocky Mountains gas supply areas, the traditional sources of 

gas for the Pacific Northwest, have historically been lower than national averages. The fuel price 

model and assumptions are described in more detail in Appendix A.

Forecasts

US Wellhead Prices

There are a number of different indicators of US natural gas commodity prices. The Council’s 

analysis utilizes two of these measures. One is the U.S. wellhead price series published by the U.S. 

Energy Information Administration. The other is the Henry Hub cash market price. A link between 

U.S. wellhead prices and the Henry Hub cash price is estimated to relate the two series for the 

Council’s analysis.

Figure 6 shows the history of US wellhead natural gas prices from 1970 to 2001. After the 

deregulation of wellhead natural gas prices around 1986, natural gas prices fell dramatically to the 

$2.00 per million Btu range. Since then, until 2000, natural gas prices varied between $1.60 and 

$2.40 in year 2000 prices. In 2000, natural gas prices shot up, reaching a peak of over $9.00 by 

January 2001 as measured by spot prices at the Henry Hub in Louisiana. Although the 2000 price 

spike created expectations of significantly higher natural gas prices in the future, prices fell rapidly 

during 2001 and by September 2001 had returned to near their post-deregulation average of $2.15 in 

year 2000 prices. Many industry participants believe the lower prices this past winter were due to 

extremely warm temperatures, high natural gas storage inventories, and reduced demand as a result 

of higher prices and an economic slowdown and that there remains an underlying shortage of natural 

gas supplies.8 Indeed, in the spring of 2002 prices firmed up to above $3.00 and futures prices for 

the coming winter reach near $4.00.

The medium forecast of wellhead natural gas prices assumes that prices will average $2.70 in 2002 

in year 2000 dollars. They gradually increase to $3.00 by 2005 as new gas-fired power plants come 

on line. After 2005, prices increase at an average annual rate of 0.5 percent through 2025. The 

growth rate is slightly lower than that assumed in the Council’s fourth power plan, but the forecast 

starts at a much higher level. As a result, the draft 2015 medium forecast is $.68 higher than the 4th

plan forecast. The range of the draft forecast is smaller in 2015 than in the 4th power plan; the low is 

higher and the high is slightly lower. This partly reflects the fact that 2015 is several years closer 

than it was when the 4th power plan forecast was done. 

Table 2 shows actual US wellhead prices for 1999, 2000, and 2001, annual forecasts for 2002 to 

2005, and forecasts in five-year intervals after 2005. The last row of Table 2 shows that average 

annual growth rate of real wellhead prices from 2005 to 2025. Figure 7 shows the forecast range 

compared to historical prices.

 

8

 Natural Gas Advisory Committee, February 28, 2002
16

Figure 6

History US Wellhead Natural Gas Prices

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000

2000$ per MMBtu

NGPA

FERC

436

FERC

500

NYMEX

FERC

636

NEPAct

The reader should not be lured into complacency by the smooth appearance of these forecasted 

prices. Future natural gas prices are not expected to follow a smooth pattern as reflected in the 

forecasts; they will be cyclically volatile, but the forecasts only reflect expected averages. There is, 

in fact, reason to expect increased volatility in natural gas prices because competition has narrowed 

reserve margins in the industry making prices more vulnerable to changes in demand due to weather 

or other influences.9 The consequences of price volatility, and ways to mitigate it impacts, will be 

addressed in the part of the power plan that addresses risk and uncertainty in regional resource 

planning.

The low case forecast reflects a situation where improved technology allows expanded natural gas 

supplies to occur with relatively moderate real price increase. Sources of natural gas would continue 

to be primarily from traditional natural gas sources. Low oil prices provide strong competition in the 

industrial boiler fuel market to help keep natural gas prices low. Continuing declines in coal prices 

coupled with improved environmental controls may moderate the growth in natural gas reliance for 

electricity generation.

The high case reflects a scenario with less successful conventional natural gas supply expansion. In 

the high case, higher prices would mean a growing role for frontier supply areas and liquefied 

natural gas imports. High prices of oil and slower progress on environmental mitigation of the 

effects of burning coal leave natural gas in a state of higher demand growth. 

 

9

 Natural Gas Advisory Committee, February 29, 2002
17

Table 2

US Wellhead Natural Gas Prices

(2000$ per million Btu)

Year Low Medlo Medium Medhi High

1999 2.17 2.17 2.17 2.17 2.17

2000 3.60 3.60 3.60 3.60 3.60

2001 3.90 3.95 4.00 4.05 4.10

2002 2.35 2.45 2.70 2.80 2.90

2003 2.80 3.00 3.20 3.35 3.50

2004 2.70 2.90 3.10 3.25 3.30

2005 2.50 2.80 3.00 3.15 3.24

2010 2.30 2.60 3.00 3.20 3.40

2015 2.40 2.70 3.15 3.35 3.60

2020 2.50 2.90 3.20 3.50 3.80

2025 2.60 3.00 3.30 3.60 4.00

2005-25 

Growth 

Rate

0.20 0.35 0.48 0.67 1.06

Figure 8 compares the draft range of natural gas price forecasts to forecasts by some other 

organizations. A forecast range in the U.S. Energy Information Administration’s (EIA) Annual 

Energy Outlook 2002 generally falls between our medium-low and high cases. The EIA’s low to 

high range is based on different levels of economic growth rather than on natural gas market factors 

directly. A forecast by the Gas Research Institute falls near our low case in 2015, but increases to 

near the medium-low case by 2020. A recent draft forecast of natural gas prices by the California 

Energy Commission resembles our high case. Finally, a forecast by DRI-WEFA falls between our 

medium and medium-high cases.
18

Figure 7

US Wellhead Prices: History and Forecast

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

197319761979198219851988199119941997200020032006200920122015201820212024

2000$ Per MMBtu

History

$2.60 

$3.00 

$3.30 

$3.60 

$4.00 

1993-99 Average = $ 2.11 

Average 2005-25 Medium Forecast = $ 3.13

Figure 8

Comparison of Natural Gas Price Forecasts

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

1995 2000 2005 2010 2015 2020 2025

2000$/MMBtu

History

Low

Medlo

Medium

Medhi

High

EIA-Ref

EIA-Low

EIA-High

DRI-WEFA

GRI

CEC

ICF
19

Regional Natural Gas Price Differentials

As noted above, for Aurora model analysis of electricity supplies and pricing, a forecast of Henry 

Hub cash market prices is used as the US commodity price. Figure 9 shows the difference between 

the Henry Hub price of natural gas and the US wellhead price from 1989 to late 2001. Excluding the 

most extreme values, the difference averaged $0.12 per million Btu. To forecast Henry Hub prices, 

$.12 is added to the US wellhead natural gas price.

Figure 9

Difference Between Henry Hub and US Wellhead Natural Gas Prices

-1.00

-0.50

0.00

0.50

1.00

1.50

2.00

2.50

3.00

Jan-89Jan-90Jan-91Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01

2000$ / MMBtu

Natural gas commodity prices in the Pacific Northwest have typically been lower than the national 

prices. During the 1990’s Canadian natural gas prices delivered to the Washington border at Sumas 

averaged $.52 per million Btu less than the national market index at Henry Hub, Louisiana. Prices at 

the Canadian border at Kingsgate have averaged about $.10 lower than the Washington border price 

at Sumas. As shown in Figure 10, however, these regional price differentials have been extremely 

volatile. Figure 10 shows monthly regional price differentials from Henry Hub to Sumas and 

Kingsgate during the 1990s. Occasionally, regional natural gas prices have even been above Henry 

Hub prices. In December of 2000, they were dramatically so, reflecting regional pipeline constraints 

caused, in part, by the electricity crisis in the West and the sudden increase in the use of natural gas 

to generate electricity. The average differentials above exclude the extreme values in the winter of 

1995-96 and 2000-01.

In addition to Canadian natural gas supplies through Sumas and Kingsgate, the Pacific Northwest 

receives natural gas supplies from the Rocky Mountain supply area on Williams Northwest Pipeline. 

Thus, Rocky Mountain natural gas supplies also play an important role in setting natural gas prices 

in the region. However, because of the direct competition among the various natural gas sources in 

the region, Rocky Mountain prices have generally tended to be similar to Canadian prices delivered 

into the region. For purposes of this forecast we rely on the Canadian pricing points to derive some 
20

regional gas price estimates, with the understanding that Rocky Mountain natural gas does play an 

important role as well.

Figure 10

Canadian Gas Price Differentials from Henry Hub

-6.00

-4.00

-2.00

0.00

2.00

4.00

6.00

8.00

10.00

Jan-89Jan-90Jan-91Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01

2000$ / MMBtu

Sumas Basis

Kingsgate Basis

Average $ - .53

Average $ - .62

For purposes of forecasting regional natural gas prices, a liquid pricing point in Alberta called the 

AECO-C hub is used as a focal point for regional natural gas prices. AECO-C prices have averaged 

$.72 per million Btu (2000 dollars) less than Henry Hub prices in recent years. Prices at other points 

in the Northwest are estimated relative to AECO-C. The emerging natural gas pricing point in 

British Columbia is Station 2 in Northeastern British Columbia. It is assumed that on average 

Station 2 prices will be $.10 per million Btu higher than at AECO-C. However, these differentials 

are expected to be seasonal with prices being the same during the summer season and Station 2 

being $.20 higher during the winter. There is disagreement about the extent to which Station 2 

might replace Sumas as the liquid pricing point for British Columbia natural gas and about the likely 

price differential between AECO-C and Station 2. In general, the price differential should not be 

larger that the cost of transporting natural gas from Alberta to Northeast British Columbia, which is 

about $.20.

There is uncertainty also about the future natural gas price differential between the AECO-C hub and 

the Henry Hub. In the forecasts, this differential is varied among the forecast cases. The forecasts 

assume that the basis differential will decrease from historical averages. This assumption reflects 

expected growth in pipeline capacity to further integrate the Rocky Mountain and Western Canada 

Sedimentary Basin natural gas supplies into the national market. However, distances to markets and 

relatively low cost natural gas supplies in the West are expected to cause a continuing differential 

between national prices and Pacific Northwest prices as measured at AECO-C. Table 3 shows the 

assumptions for the five forecast cases. Appendix C shows annual natural gas price forecasts at the 

US wellhead, AECO-C and Station2 for each forecast case.
21

Table 3

Price Differentials Between the AECO-C and Henry Hub 

Forecast Case 2000 $ per Million Btu

Low $ - .60

Medium Low $ - .55

Medium $ - .45

Medium High $ - .30

High $ - .20

Retail Prices

The prices paid by regional consumers of natural gas are forecast based on the U.S. and Canadian 

commodity prices described in the previous section. The exact method depends on the consuming 

sector being considered and will be explained below.

Figure 11 shows the regional retail natural gas price forecasts for end-use sectors compared to the 

U.S. wellhead price forecast for the medium case. The residential and commercial forecasts are 

based on historical differences between regional retail and U.S. wellhead prices. Industrial price 

forecasts are a weighted average of three different price estimates; direct-purchase firm gas, directpurchase interruptible gas, and local distribution company-served industrial customers. Directpuchase gas is gas supply that is purchased directly by industrial customers instead of from local gas 

distribution companies (LDCs). The ability for industrial users to purchase natural gas directly in 

the market began with natural gas deregulation in the mid-1980s. The effect on industrial prices is 

apparent in Figure 11, where the average industrial price moves toward the utility and wellhead price 

and away from the utility served residential and commercial prices during the 1980s. The 

differences between U.S. wellhead and regional retail prices are discussed further below.

Figure 11

Retail and Wellhead Prices History and Medium Forecast

0.00

2.00

4.00

6.00

8.00

10.00

12.00

198019841988199219962000200420082012201620202024

2000$ / MMBtu

Industry

Residences

Commercial

Utility

Wellhead
22

Residential and commercial sector prices are based on observed differences from U.S. wellhead 

natural gas prices between 1989 and 2000. Figure 12 shows that these differences declined during 

the 1980s. Since then, the differences have leveled off. The forecast assumes a $4.25 difference for 

residential and a $3.25 difference for commercial. These differences are held constant over the 

forecast period and across forecast cases.

As noted above, the industrial price shown in Figure 11 is a blended price. The prices of the three 

components are derived in different ways. The LDC-provided prices are developed in the same way 

as residential and commercial prices. The forecast addition to U.S. wellhead prices to estimate onsystem retail prices starts at about $1.70, but, unlike the residential and commercial adders, declines 

gradually over time. It does not, however, vary among forecast cases.

Figure 12

Difference Between Regional Retail Natural Gas Prices and US Wellhead Prices

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

19801982198419861988199019921994199619982000

2000$ / MMBtu

Residential

Commercial

Directly-purchased industrial natural gas prices are built up from wellhead prices using estimates of 

the various components of gas supply and transportation costs. These components are described in 

detail in the Appendix A, but Table 4 shows an example of industrial directly-purchased regional 

price estimation for 2010 in the medium case forecast. The example is a large, high-capacity-factor, 

industrial consumer. For electricity generators, natural gas and transportation costs are assumed to 

be different on the west and east side of the Cascade Mountains. There is no distinction applied to 

the industrial price forecasts; they are calculated using west-side costs. 

There is some disagreement whether a consumer who buys natural gas supplies on a firm basis 

would generally pay a premium for firm supplies. In this forecast, it is assumed that there is no 

premium. It is assumed that a large capacity factor industrial consumer would likely pay a 

negotiated rate for gas transportation by the local distribution utility and there is no differential 

assumed for firm versus interruptible distribution service for such customers. This may only be the 

case for a customer with a potential to bypass the local distribution company, but the assumption 

about LDC transport cost only applies to industrial consumers and the forecast of industrial 
23

electricity demand in the 5th power plan will not be directly affected. Electricity generation costs are 

based on assumed direct connect to interstate pipelines.

To combine the components into a blended price it is assumed that 30 percent of industrial natural 

gas consumption is purchased from the local distribution utility. The remaining 70 percent is 

purchased directly by industrial consumers. 90 percent of these direct purchases are assumed to be 

interruptible. It is assumed that a consumer that doesn’t hold firm pipeline capacity will acquire 

released capacity or short-term firm capacity. As can be seen in Figure 11, the average difference 

between the US wellhead price and the blended industrial users’ price is small compared to the 

residential and commercial sectors. It is important to remember that the differences include a 

negative adjustment of $.35 for the Station 2 to Henry Hub commodity price differential described in 

the previous section.

Table 4a

Estimation of 2010 Industrial Firm and Interruptible Direct-Purchase Natural Gas Cost

(2000 $ / MMBtu)

Price Components Price 

Adjustments

Firm Interruptible

Henry Hub Price $ 3.12 $3.12

Station 2 Price Differential $ - .35 2.77 2.77

In Kind Fuel Cost + 3.72% 2.88 2.88

Firm Pipeline Capacity (Rolled-in) + .45 3.33

Interruptible Pipeline Capacity + .34 3.22

Pipeline Commodity Charge $ + .04 3.37 3.26

Firm Supply Premium $ + 0.0 3.37

LDC Distribution Cost + .20 $ 3.57 $ 3.46

Natural gas prices for electricity generators reflect the assumption that all electricity generators will 

buy their gas directly from suppliers rather than the local utility and that generators will receive their 

gas supplies directly from interstate pipelines. Like industrial direct purchases, these purchases can 

be made on a firm or interruptible basis. In the draft forecast, it is assumed that all electric generator 

gas purchases are made on a firm transportation basis. Electric generator natural gas prices are 

calculated both in terms of average cost per million Btu, and in terms of fixed and variable natural 

gas costs. Again these assumptions are detailed in Appendix A. Table 5a shows an example of the 

calculation of natural gas costs for a new generating plant on the west side of the Cascade 

Mountians. Table 5b shows the same derivation for a plant on the east side of the Cascade 

Mountains. The examples are for the year 2010 in the medium forecast case. Appendix D shows 

annual natural gas price forecasts for the US wellhead and retail prices for the residential, 

commercial, industrial and utility sectors for each forecast case. In addition, Appendix C shows 

similar information for electricity generators of the west and east side of the Cascade Mountains.
24

Table 5a

Estimation of West-Side Electric Generator Firm and Interruptible Natural Gas Cost

(2000 $ / MMBtu)

Price Components Price 

Adjustments

Firm Interruptible

Henry-Hub Price $ 3.12 $ 3.12

Station 2 Price Differential $ - .35 2.77 2.77

In-Kind Fuel Charge + 3.72% 2.88 2.88

Firm Pipeline Capacity (Incremental) $ + .61 3.48

Interruptible Pipeline Capacity $ + .34 3.22

Pipeline Commodity Charge $ + .04 3.53 3.26

Firm Supply Premium $ + .00 3.53

Table 5b

Estimation of East-Side Electric Generator Firm and Interruptible Natural Gas Cost

(2000 $ / MMBtu)

Price Components Price 

Adjustments

Firm Interruptible

Henry Hub Price $ 3.12 $ 3.12

AECO Price Differential $ - .45 2.67 2.67

In-Kind Fuel Charge + 2.8% 2.75 2.75

Firm Pipeline Capacity (Incremental) $ + .40 3.15

Interruptible Pipeline Capacity $ + .23 2.98

Pipeline Commodity Charge $ + .01 3.16 2.99

Firm Supply Premium $ + .00 3.16

Inputs to the Aurora model are configured differently, but they are based on the same underlying 

U.S. wellhead price forecast. Adjustment factors from US wellhead prices to Aurora market area 

prices are described in Appendix B. 

Oil

Historical Consumption and Price

Oil products are playing a decreasing role in both electricity generation and in residential and 

commercial space heating in the Pacific Northwest. Figure 13 shows that both distillate and residual 

oil consumption have generally been declining in all sectors since the mid-1970s. 

To a large extent, declining oil consumption reflects growing natural gas use. Some increases in oil 

consumption are evident during the mid-1980s when natural gas prices were high. Substitution 

possibilities between natural gas and oil use in large industrial applications is a key feature of fuel 

markets. The substitution of oil for natural gas, for example, played an important role during 2001 

in reducing high natural gas prices. In the Pacific Northwest, the displacement of industrial residual 

oil use is particularly dramatic as shown in Figure 13.
25

Figure 13

Historical Oil Consumption in the Pacific Northwest

0

2000

4000

6000

8000

10000

12000

14000

16000

197619781980198219841986198819901992199419961998

1000 Barrels

Residential Distillate

Commercial Distillate

Industrial Distillate

Commercial Residual

Industrial Residual

In general, the price of oil products is determined by the world price of crude oil. Figure 14 shows 

crude oil prices from 1978 to 2000 compared to refiner prices for residual oil and distillate oil. The 

differences are relatively stable with residual oil being priced lower than crude oil and distillate oil 

higher. On average, during this time period distillate oil was priced $1.00 per million Btu higher 

than crude oil. Residual oil was on average priced $.80 lower than crude oil. (Prices are in nominal 

dollars.) Retail prices of oil products follow very similar patterns, but at different levels.

Figure 14

Comparison of Crude Oil and Refiner Product Prices

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

197819801982198419861988199019921994199619982000

Nominal $ / MMBtu

Crude

Distillate

Residual
26

Methods

The forecasts of oil prices are based on assumptions about the future world price of crude oil. 

Refiner prices of distillate and residual oil are derived from formulas relating product prices to crude 

oil prices and refining costs. The formulas are based on a conceptual model of refinery costs and 

assume profit maximizing decisions by refiners regarding the mix of distillate and residual oil 

production. Appendix A describes this model in more detail.

Although the refinery model is very simple, and the refining cost estimates and energy penalties 

have not been changed since the early days of the Council’s planning, the ability of the equations to 

simulate historical prices remains good. Figures 15a and 15b show a comparison of predicted 

residual oil and distillate oil prices, respectively, based on actual world crude oil prices to actual 

prices from 1978 to 2000. The equations appear to be predicting well, especially after the mid1980s.

Forecasts of retail oil prices to the end-use sectors are based on historical differences between the 

refiner price estimates for residual and distillate oil and actual retail prices. These markups are 

assumed constant over time and across alternative forecast cases.

Figure 15a

Comparison of Forecast and Actual Residual Oil Prices

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

197819801982198419861988199019921994199619982000

2000$ / MMBtu

Estimate

Actual
27

Figure 15b

Comparison of Forecast and Actual Distillate Oil Prices

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

197819801982198419861988199019921994199619982000

2000$ / MMBtu

Estimate

Actual

World Crude Oil Price Forecast

The situation in world oil markets is very different from natural gas markets. Oil is much more of a 

world market than natural gas due to the easier transportability of oil. The world’s proved reserves 

of oil are about 1000 billion barrels. World consumption of oil in 2000 was 27 billion barrels. 

(Based on BP and USGS data on web.) Oil reserves are dominated by the Middle East, which has 

65 percent of the world’s proven reserves. The Middle East’s reserves can be produced at low cost, 

but the middle eastern countries and their partners in the Organization of Petroleum Exporting 

Countries (OPEC) attempt to limit production so that world oil prices remain in the range of $20 to 

$30 per barrel. Proven oil reserves in the Middle East are 80 times the actual production rate in 

2000. As a result, world oil prices are likely to depend on OPEC actions for the duration of the 

forecast period. 

Although fluctuating world oil demand, Middleeast conflicts, and lapses in OPEC production 

discipline will result in volatile oil prices over time, we have assumed a range of stable average

prices in the forecast. Figure 16 shows historical world oil prices and the five forecast cases.

Since the mid 1980s, world oil prices have averaged $21 a barrel in year $2000 prices. However, 

they varied from a low of $12.49 per barrel in 1998 to $27.69 in 2000. During 2001 prices fell back 

to near $20. Table 6 shows world oil price forecasts for individual years between 2000 and 2005 

and in five-year increments thereafter. The forecasts all have moderate real oil price growth after 

2005, reflecting a growing need to invest to increase production capacity over time. Generally, it is 

assumed that lower prices in the early years of the forecast will require greater rates of price increase 

over time as costs of investment in capacity expansion are a larger share of price. That is,near-term 

higher prices could support future capacity investments with less price increase over time.
28

Figure 16

World Oil Price: History and Forecasts

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

197319761979198219851988199119941997200020032006200920122015201820212024

2000$/Barrel

History

Low

Medlo

Medium

Medhi

High

Table 6

World Oil Price Forecasts

(2000$ per MMBtu)

Low MediumLowMedium MediumHighHigh

2000 27.69 27.69 27.69 27.69 27.69

2001 21.00 22.00 23.00 24.00 25.00

2002 21.00 22.00 22.00 24.00 26.00

2003 20.00 21.00 22.00 24.00 29.00

2004 18.00 21.00 22.00 24.00 30.00

2005 16.00 19.00 22.00 25.00 30.00

2010 16.70 19.50 22.50 25.50 30.50

2015 17.40 20.00 23.00 26.00 31.00

2020 18.20 20.50 23.50 26.50 31.50

2025 19.00 21.00 24.00 27.00 32.00

The assumptions about future oil prices are based on observation and analysis of historical prices 

and on comparisons among forecasts made by other organizations that put substantial resources into 

analysis of future price trends. Figure 17 shows world oil prices for 1990, 1995 and 2000 compared 

to the forecast range and a range of other forecasts. The U.S. Energy Information Administration 

(EIA) is the source of the summary of other forecasts.10 Figure 17 shows EIA’s forecast range and 

the average of 8 other forecasts that EIA compared to their own forecast. EIA’s reference case 

forecast falls just above our medium case. EIA’s range is also very similar our low to high range. 

 

10 U.S. Energy Information Administration, Annual Energy Outlook 2002.
29

The average of the 8 other forecasts falls along our medium-low forecast until 2015 and then moves 

a little higher for 2020.

These forecasts of world oil prices are very similar to those in the Council’s 4th power plan. 

Appendix E contains tables of annual forecasts for world oil prices and sectoral retail oil prices for 

each forecast case.

Figure 17

Comparison to Other World Oil Price Forecasts

0

5

10

15

20

25

30

35

1990 1995 2000 2005 2010 2015 2020

History

Low

Medlo

Medium

Medhi

High

EIA02-R

EIA02-H

EIA902-L

8 Others

Consumer Prices

Using the methods described earlier, world oil price forecasts are converted to refiner prices of 

residual oil and distillate oil. Figure 18 shows the forecast relationship among these products for the 

medium case. A set of markups is used to derive forecasts of retail prices for various products to end 

use sectors. These retail markups, shown in Table 7, are generally assumed constant over time and 

across forecast cases. The markups are based on historical average price relationships during the 

1980s and 1990s.
30

Figure 18

Refiner Prices of Residual and Distillate Oil Compared to World Crude Oil Price

(Medium Case)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

2000200220042006200820102012201420162018202020222024

2000$/MMBtu

World Oil

Residual Oil

Distillate Oil

Table 7

Retail Markup Assumptions for Oil Products and Sectors

INDUSTRIAL SECTOR

 Residual Oil Over Refinery $ .24

 Distillate Oil Over Refinery $ 1.00

UTILITY SECTOR

 Residual Oil Over Refinery $ .24

 Distillate Oil Over Refinery $ .46

COMMERCIAL SECTOR

 Residual Oil Over Industrial $ .05

 Distillate Oil Over Industrial $ -.42

RESIDENTIAL SECTOR

 Distillate Oil Over Industrial $ 1.98

Coal Price Forecasts

Coal prices play little role in determining regional electricity demand. There are not many end uses 

where coal and electricity substitute for one another and coal consumption is relatively minor in the 

Pacific Northwest in any case. Coal as a percent of total industrial fuel purchases in the region in 

1999 was 0.7 percent compared to 6.1 percent for the US as a whole. Coal is also a relatively minor 

electricity generation fuel in the region compared to the US. In 1999, coal accounted for 14 percent

of regional utility fuel purchases compared to 55 percent for the nation. Only Montana had a coal 

generation share similar to the US for electricity generation.
31

Nevertheless, coal may be important alternative as an electricity generation fuel in the future. The 

trade-off is that while coal is a plentiful and relatively inexpensive domestic energy source, it also 

has substantial environmental impacts both during extraction and burning. Thus its future may 

depend on technological progress in emissions controls and policies with regard to air quality and 

global warming.

Coal resources, like natural gas, are measured in many different forms. The EIA reports several of 

these.11 One measure is “demonstrated reserve base”, which measures coal more likely to be mined 

based on seam thickness and depth. EIA estimates that the 1997 U.S. demonstrated reserve base of 

coal is 508 billion short tons. Only 275 billion short tons of these resources are considered 

“recoverable” due to inaccessibility or losses in the mining process. This is a large supply of coal 

relative to the current production of about 1 billion short tons a year.

About half of the demonstrated reserve base of coal, 240 billion short tons is located in the West. 

Western coal production has been growing due to several advantages that it has over Appalachian 

and Interior deposits. Western coal is cheaper to mine due to its relatively shallow depths and thick 

seams. More important recently is that Western Coal is lower in sulfur content. Use of low sulfur 

coal supplies has been an attractive way to help utilities meet increased restrictions on SO2 

emissions under the 1990 Clean Air Act Amendments that took effect on January 1, 2000. The other 

characteristic that distinguishes most Western coal from Eastern and interior supplies is its Btu 

content. Western coal is predominately sub bituminous coal with average heat contents of about 17 

million Btus per short ton. In contrast, Appalachian and Interior coal tends to be predominately 

higher grade bituminous coal with heat rates averaging about 24 million Btus per short ton.

Western coal production in 2000 was 510.7 million short tons. Two thirds of that production came 

from Wyoming, 338.9 million short tons. The second largest state producer was Montana at 38.4 

million tons. Colorado, New Mexico, North Dakota and Utah produced between 26 and 31 million 

short tons each and Arizona produced about 13 million short tons.

Productivity increases have been rapid, especially in Western coal mines. As a result, minemouth 

coal prices have decreased over time. In constant dollars, Western minemouth coal prices declined 

by nearly 6 percent per year between 1985 and 2000. 

The price of delivered coal is very dependent on transportation distances and costs. In addition, 

delivered costs may have very different time trends from minemouth costs due to long-term coal 

supply contracts. Figure 19 shows Pacific Northwest delivered industrial and utility sector coal 

prices from 1976 to 1999.12 Coal prices increased during the late 1970s with other energy prices, but 

since the early 1980s have declined steadily. On average, regional industrial coal prices decreased at 

an annual rate of 3.2 percent between 1980 and 1999. Regional utility coal prices have followed a

similar pattern of decline, although utility prices were delayed a few years in following industrial 

prices downward. This may have been due to longer-term coal contracts for the coal-fired 

generation plants in the region.

 

11 U.S. Energy Information Administration, U.S. Coal Reserves: 1997 Update, February 1999.

12 U.S. Energy Information Administration
32

Figure 19

Pacific Northwest Industrial and Utility Historical Coal Price Trends

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

197619781980198219841986198819901992199419961998

2000$ per MMBtu

Industrial

Utility

Forecasts of coal prices follow a very simple method. Different constant rates of price decline for 

Western minemouth coal prices are assumed for the five forecast cases. The assumptions are shown 

in Table 8. In all cases, coal prices are assumed to decline more slowly than they did during the 

previous 15 years.

Table 8

Assumed Western Minemouth Coal Price Growth Rates

Forecast Case Average Annual 

Rate of Growth

Low - 1.5 %

Medium Low - 1.1 %

Medium - 0.8 %

Medium High - 0.5 %

High +0.1 %

Delivered prices to Pacific Northwest industries and utilities are estimated by applying fixed 

markups from Western minemouth prices to delivered prices. Transportation costs are significant 

for coal. States that are farther away from the mines tend to have significantly higher delivered coal 

costs. Montana and Wyoming delivered costs, however, can be quite close to the minemouth price. 

Some coal-fired electricity generating plants are located at the mine and have little, if any, 

transportation cost. In more distant states, like Washington, the delivered cost can be more than 3 

times the minemouth price. Table 9 shows the additions to western minemouth coal prices for the 

states in the West and the 2010 medium forecast of coal prices that result. Appendix F contains 

annual forecasts of coal prices for each of the forecast cases.
33

Table 9

Derivation of State Electricity Generator Coal Prices, 2010 Medium Forecast

(2000 Dollars per Million Btu)

Markup from Mine Price Forecast

Western Minemouth $ 0.47

Washington $ + 1.04 1.51

Oregon + .53 1.00

Idaho + .45 .92

Montana + .20 .67

Utah + .65 1.12

Wyoming + .28 .75

Colorado + .50 .97

New Mexico + .87 1.34

Arizona + .84 1.31

Nevada +.89 1.36
A - 1

Appendix A - Fuel Price Forecasting Model

Introduction

This Appendix describes the fuel price forecasting model that was used for the Council’s 2001, or 5th

power plan. The model consists of several worksheets linked together in an EXCEL “workbook”. 

The Excel model is in Q:\TM\FUEL\MODF\FUELMOD02.

The model includes forecasts of natural gas, oil and coal prices. Retail fuel prices for the various 

demand sectors are derived from the forecasts of basic energy commodity prices, that is, the world 

price of oil, the average wellhead price of natural gas, and western minemouth coal prices. These 

energy prices are forecast by several organizations that specialize in energy market forecasting. 

Thus basic energy price trends can be compared to a variety of forecasts which helps define a range 

of possible futures based on much more detailed modeling and analysis than the Council has the 

resources to accomplish alone. The prices of oil, natural gas, and coal, are not explicitly linked to 

one another. Rather, the relationships should be considered by the analyst in developing fuel price 

scenarios. 

Retail prices are estimated by adding cost components to the basic energy commodity prices. Where 

possible these additional costs, or markups, are based on historical relationships among energy costs 

to various sectors. Thus, the basic driving forces in the fuel price model are world oil price 

forecasts, wellhead natural gas price forecasts, coal price growth rates, and markups to retail prices 

in various end-use sectors . 

The degree of detail devoted to each fuel depends on its relative importance to electricity planning. 

For example, natural gas is a very important determinant of both electricity demand and the cost of 

electricity generation from gas-fired plants. As a result, the natural gas forecasting approach is 

significantly more detailed than oil or coal. Oil plays a smaller role in competition with electricity 

use and in electricity generation and receives less attention. Coal plays little role in determining 

electricity demand and is treated very briefly in the model using assumed annual growth rates. 

Model Components

Historical retail data for each fuel are kept on separate Excel files called OIL.XLS, GAS.XLS, and 

COAL.XLS. These spreadsheets contain historical retail price data by state and consuming sector 

from the “State Energy Price and Expenditure Report” compiled by the U.S. Energy Information 

Administration (EIA). In addition, they contain consumption data from the “State Energy Data 

Report”, also published by EIA. The spreadsheets convert the prices to real 2000 dollars and 

calculate consumption weighted average regional prices for each end-use sector. 

Forecasts of world oil prices and natural gas wellhead prices are developed in the WOPFC and 

NGFC are tabs, respectively, in the FUELMOD02 Excel Workbook. They take historical data 

consistent with the historical fuel price worksheets described in the previous paragraph and merge it 

with forecasts in five year intervals. The worksheet interpolates between the five year forecasts to 

get annual values. These tabs also contain previous Council forecasts and forecasts by other 

organizations for comparison purposes.
A - 2

MAIN contains the forecasts of basic oil and gas commodity prices calculated in WOPFC and 

NGFC for a specific forecast case and any other scenario dependent assumptions and parameters. It 

also compares the model estimates of industrial residual oil prices, interruptible gas prices, and coal 

prices. Wellhead gas prices feed into the gas price model and world oil prices feed into the oil price 

model. MAIN contains the scenario controls and variables for the entire model. The varying 

scenario assumptions and their cell locations are as follows:

Scenario Name B2

Wellhead Natural Gas Price B30:B54

World Oil Price C30:C54

LDC Firm Distribution Charge E9:E54

Regional Wellhead Differential F9:F54

Real Growth Rate of Incremental Pipeline Costs D60

Coal Price Growth Rate D61

Firm Natural Gas Supply Share D62

The separate tabs in FUELMOD02 are described at the end of this appendix in a section entitled 

Model Components, which is a printout of the first tab (“DOC”) in the model. The model structure 

is described in more detail below.

Natural Gas Model

The natural gas price forecasting component is far more detailed than the oil or coal components. 

This is not only because natural gas is currently the strongest competitor to electricity, but also 

because of the lack of reliable historical price information for large industrial and electric utility gas 

purchases. 

There are four separate worksheets for natural gas price forecasts by sector; INDUST which contains 

industrial sector forecasts, NWUTIL which contains electricity generator forecasts, RES_COM 

which contains residential and commercial forecasts, and SWEG which contains Southwest electric 

utility gas prices. A separate worksheet, COMPONENTS, supports the industrial and electricity 

generator forecasts by calculating the various components of cost that are incurred between the 

wellhead and the end user. The worksheet GASSUM is simply a report that summarizes the natural 

gas price forecasts. The tabs 00$NWUtil, NG West, and Aurora report different components of the 

natural gas price forecast. In particular, NG West and Aurora include natural gas price forecasts for 

other pricing points in the western US.

Residential and commercial sector gas prices are based on historical retail prices compared to U.S. 

wellhead prices. For historical years the difference between wellhead prices and retail prices are 

calculated. For forecast years, the projected difference is added to the wellhead price forecast. The 

differences, or markup, can be projected from historical trends, other forecasting models, or 

judgement.

Gas prices for small industrial gas users that rely on local gas distribution companies to supply their 

gas are forecast in the same manner as residential and commercial users. However, large firm or 

interruptible customers, whether industrial or electricity generators, must be handled with a different 

method. This is because there is no reliable historical price series for these gas users to base a 
A - 3

simple markup on. For these customers, the difference between wellhead and end user prices is built 

up from a set of transportation cost components appropriate to the specific type of gas use. These 

components are developed in the worksheet COMPONENTS.

The components include pipeline capacity costs, pipeline commodity costs, pipeline fuel use, local 

distribution costs, firm gas supply premiums, and regional wellhead price differences. The latter is 

necessary because the driving assumption is a U.S. average wellhead gas price. Wellhead prices in 

British Columbia, Alberta, and the Rocky Mountains gas supply areas, the traditional sources of gas 

for the Pacific Northwest, have historically been lower than national averages.

Tables A-1 and A-2 show the various transportation components, their column location in the 

COMPONENTS worksheet, and the current value or range of values in the model. Table A-1 

applies to a large natural gas consumer on the west side of the Cascades and Table A-2 applies to the 

same kind of consumer on the east side

Table A-1

West-Side Cost Components for Calculating Delivered Natural Gas Prices.

Cost Comp onent Components

Column

Constant Costs

(2000$/MMBtu)

Scenario Variant

L ML M MH H

U.S. Wellhead to Henry Hub C9 $ +.12

Henry Hub to AECO D - .60 - .55 - .45 - .30 - .20

AECO to Station 2 * E + .10

Pipeline Capacity Cost

 Firm Rolled-In F + .45

 Firm Incremental H +.60 in 2004 + growth -0.1 0.1 0.3 0.5 0.7

 Released Capacity Cost * J + .34

Pipeline Commodity Cost L + .04

Pipeline In -Kind Fuel Cost * F61 + 3.72 %

LDC Distribution Cost N + .20

Firm Supply Premium O + 0.0

* Summer and winter values are different from the averages show here

The resource planning models require utility gas prices in terms of their fixed and variable 

components. Variable costs include wellhead prices adjusted for regional differences, pipeline fuel 

costs, and pipeline commodity charges. These are cost that can be avoided if electricity is not 

generated. In addition, some portion of the pipeline capacity charge may be avoided through resale 

in the capacity release market. The share of firm pipeline capacity costs that can be recovered by 

resale in the capacity release market is a parameter in the model and is currently assumed to equal 

.10. For example, if it were not possible to recover any pipeline capacity costs then they become 

fixed costs. The other potentially fixed cost is any premium that must be paid to secure firm gas 

supply, but this is currently assumed to be zero. Fixed costs are expressed in dollars per kilowatt per 

year, instead of dollars per million Btu.
A - 4

Table A-2

East-Side Cost Components for Calculating Delivered Natural Gas Prices.

Cost Component Components

Column

Constant Costs

(2000$/MMBtu)

Scenario Variant

L ML M MH H

U.S. Wellhead to Henry Hub C9 $ +.12

Henry Hub to AECO D - .60 - .55 - .45 - .30 - .20

Pipeline Capacity Cost

 Firm Rolled-In G + .29

 Firm Incremental I +.40 in 2006 + growth -0.1 0.1 0.3 0.5 0.7

 Released Capacity Cost * K + .23

Pipeline Commodity Cost M + .01

Pipeline In -Kind Fuel Cost * F62 + 2.80 %

LDC Distribution Cost N + .20

Firm Supply Premium O + 0.0

* Summer and winter values are different from the averages show here
A - 5

Oil Model

The oil price forecasting model first estimates the refiner price of distillate and residual oil based on 

the assumed world price for crude oil. This is done using a very simple model of refinery 

economics.13 Retail prices of oil products for the industrial, residential, and commercial sectors are 

then calculated by adding markups based on the historical difference between calculated refiner 

wholesale prices and actual retail prices.

The simple model of refiner economics considers the cost of crude oil, the cost of refining crude oil 

into heavy and light oil products, and the value of those products in the market. It assumes that 

refiners will decide on their production mix so that their profits will be maximized. That is, the 

difference between the revenue received from sale of products and the costs of crude oil and refining 

it into products will be maximized.

The underlying assumptions are as follows:

Refining costs:

Simple refining 

- $2.15 per barrel in 2000 dollars.

- Saudi light yields 47 % heavy oil.

- 3 percent energy penalty.

Complex refining

- $5.38 per barrel in 2000 dollars.

- yield 100 percent light oil.

- 12 percent energy penalty, about 6-8 percent above simple 

refining.

Desulpherization

- $3.91 per barrel in 2000 dollars.

- 4 to - 8 percent energy penalty.

- Assumed not to be necessary in NW.

Profit Equations:

Simple refinery

Revenue = .47H + .53L

Cost = C + .03C + 2.15

Profit = (.47H + .53L) - (C + .03C + 2.15)

Where: .47 is residual oil output share.

.53 is distillate oil output share.

H is residual oil wholesale price.

L is distillate oil wholesale price.

C is cost of crude oil

 

13This refinery model evolved from the old Council fuel price forecasting method developed by Energy Analysis and 

Planning, Inc. That company has evolved into Economic Insight Inc.
A - 6

.03 is the energy penalty for simple refining.

2.15 is the refining cost per barrel.

Complex refinery

Revenue = L

Cost = C + .12C + 5.38

Profit = L - (C + .12C + 5.38)

Equilibrium Condition: Profit from heavy products equals profit from light 

products at the margin.

.47H + .53L - C - .03C - 2.15 = L - C - .12C - 5.38

Solve for product prices:

.47H + .53L - L = .03C - .12C - 5.38 + 2.15

.47(H - L) = -.09C - 3.23

(H - L) = -.1915C - 6.8723

Using L = C + .12C + 5.38 gives

 H = -.1915C - 6.8723 + C + .12C + 5.38

 H = .9285C - 1.5133 (Equation for residual oil price as 

 a function of crude oil price.)

The simple refinery model thus gives the estimates of residual oil (heavy) and distillate oil (light) 

prices based on the assumed crude oil prices. Distillate wholesale prices equals 112 percent of the 

crude oil price plus $5.38 (in 2000 dollars) per barrel. Residual oil wholesales price equals 93 

percent of the crude oil price less $1.51 

Historically based markups are added to get retail prices for residual and distillate oil for the 

commercial, industrial and utility sectors. The two oil products prices are then consumption 

weighted to get an average oil price for the sector. The residential sector does not use residual oil so 

only a distillate retail price is calculated.
A - 7

Coal Model

The coal model is a very simple approach. Average Western minemouth coal prices are forecast by 

applying assumed, scenario specific, growth rates to a base year level. Regional utility and industry 

prices, and state-specific utility prices are forecast based on time- invariant differentials from 

western the minemouth prices.
A - 8

MODEL COMPONENTS

(Tabs in the Excel Workbook)

DOC -- Describes files in the forecast model

NGFC -- Contains historical prices and the forecast range of wellhead

 gas prices. Scenarios are to be copied into MAIN for each case.

 Contains GDP deflators for converting historical to study

 year dollars.

WOPFC -

-

Contains historical prices and the forecast range of world oil

 prices. Scenarios are to be copied into MAIN for each case.

MAIN -- Contains drivers for forecast model and includes scenario

 varient values. (Avg. wellhead, world oil, GNP deflators etc.

 Displays boiler fuel relative gas, oil, coal prices

Basis -- Contains regional basis differential assumptions for each scenario

 To be copied into MAIN for each scenario.

MARKUP -- Combines the various components of pipeline and distribution

 cost, regional wellhead price difference, and other add-ons to

 the wellhead gas price. These adders are used in the INDUST

 and NWUTIL sheets.

INDUST -- Industrial gas price model, linked to MAIN wellhead

 Large interruptible, Avg. transport, through LDC & Mixed

NWUTIL -- PNW Utility gas price model, linked to MAIN wellhead

 Interruptible and Firm burner-tip

RES_COM -- Residential & Commercial gas price model, linked to MAIN

 wellhead prices by retail price differences.

00$ NWUtil Shows derivation of West-side and East-side Firm utility gas prices

NG West Develops forecasts of natural gas prices at major Western pricing 

points

Aurora Develops fixed and variable natural gas prices for Aurora Model

pricing points in the WECC

SWEG -- Southwest Electric Generation gas price, linked to MAIN wellhead

 price forecast.
A - 9

GASSUM -- Summary table for gas price forecasts, linked to the individual

 sector worksheets.

OILMOD -- Estimates retail oil prices for all sectors, linked to MAIN

 world oil price forecasts.

OilSum -- Summary of retail oil price forecasts for residual and distillate

 in both midyear 2000 $ and Jan 2000$.

COALMOD -- Forecasts industrial coal prices based on exogenous growth rate 

 read from MAIN.

Tables Develops tables to be included in forecast documents

FUELS -- Puts the fuel price forecasts in the format needed for input to

 demand forecasting models, converts to 1980 $

Export -- File to be exported for demand model inputs.
B - 1

Appendix B - Derivation of Natural Gas Prices by Market Points 

and States

Table B-1 shows the assumed relationships between wellhead price forecasts and various pric ing 

points in the West for the medium forecast in 2002. These price differential estimates are used to 

derive natural gas price inputs to the Aurora electricity pricing model.

Table B-1

The only component of the basis differential column in the table that changes with forecast scenarios 

is the basis differential between Henry Hub and AECO and Station 2. The assumed Henry Hub to 

AECO differentials are shown below. The AECO basis differential is assumed, on average, to be $ 

.10 more negative than the Station 2 differential. In more detailed work we assume that the Station 2 

Medium Basis Delivery 2002

Differential Cost Estimated

Price

Wellhead $2.70

$0.12

Henry Hub $2.82

AECO ($0.45) $2.37

East-side PNW $0.40 $2.77

Northern CA $0.63 $3.00

Station 2 $0.10 $2.47

Sumas $0.22 $2.69

West-side PNW $0.59 $3.06

San Juan ($0.26) $2.56

CO $0.36 $2.92

Rockies ($0.40) $2.42

UT $0.35 $2.77

WY $0.40 $2.82

MT $0.33 $2.75

ID $0.35 $2.77

N. NV $0.69 $3.11

Permian ($0.17) $2.65

CA Border $0.33 $2.98

Southern CA $0.05 $3.03

AZ $0.32 $2.97

NM $0.24 $2.89

S. NV $0.33 $2.98
B - 2

price will be $ .20 higher than AECO in winter, and about equal in summer. Some of the 

components of the northwest delivery costs also vary by forecast scenario and by season.

Basis Differential, Henry Hub to Sumas

Low $ -.60

Medium Low $ -.55

Medium $ -.45

Medium High $ -.30

High $ -.20

Over time, it is assumed that there may be some real increase in pipeline capacity costs. These 

changes vary across the forecast cases as noted in Table A-1 of Appendix A.
C - 1

Appendix C - Forecast Tables for U.S. Wellhead and Regional 

Market Prices

Table C - Medium

Regional Electricity Generation Natural Gas Prices

(2000$ Per MMBtu)

Medium Case

U.S. AECO Station 2 West-Side East-Side

Wellhead Price Price Delivered Delivered

Year Price

2000 3.60 3.37 3.47 4.09 3.77

2001 4.03 4.05 4.15 4.80 4.50

2002 2.70 2.37 2.47 3.06 2.77

2003 3.20 2.87 2.97 3.57 3.28

2004 3.10 2.77 2.87 3.52 3.18

2005 3.00 2.67 2.77 3.42 3.08

2006 3.00 2.67 2.77 3.52 3.16

2007 3.00 2.67 2.77 3.52 3.16

2008 3.00 2.67 2.77 3.52 3.16

2009 3.00 2.67 2.77 3.52 3.16

2010 3.00 2.67 2.77 3.52 3.16

2011 3.03 2.70 2.80 3.56 3.19

2012 3.06 2.73 2.83 3.59 3.22

2013 3.09 2.76 2.86 3.62 3.26

2014 3.12 2.79 2.89 3.66 3.29

2015 3.15 2.82 2.92 3.69 3.32

2016 3.16 2.83 2.93 3.70 3.33

2017 3.17 2.84 2.94 3.71 3.35

2018 3.18 2.85 2.95 3.73 3.36

2019 3.19 2.86 2.96 3.74 3.37

2020 3.20 2.87 2.97 3.75 3.38

2021 3.22 2.89 2.99 3.77 3.40

2022 3.24 2.91 3.01 3.80 3.42

2023 3.26 2.93 3.03 3.82 3.44

2024 3.28 2.95 3.05 3.84 3.47

2025 3.30 2.97 3.07 3.86 3.49
C - 2

Table C - Low

Regional Electricity Generation Natural Gas Prices

(2000$ Per MMBtu)

Low Case

U.S. AECO Station 2 West-Side East-Side

Wellhead Price Price Delivered Delivered

Year Price

2000 3.60 3.37 3.47 4.09 3.77

2001 4.03 4.05 4.15 4.80 4.50

2002 2.35 1.87 1.97 2.54 2.25

2003 2.80 2.32 2.42 3.00 2.72

2004 2.70 2.22 2.32 2.95 2.61

2005 2.50 2.02 2.12 2.74 2.41

2006 2.46 1.98 2.08 2.80 2.45

2007 2.42 1.94 2.04 2.76 2.40

2008 2.38 1.90 2.00 2.71 2.36

2009 2.34 1.86 1.96 2.67 2.32

2010 2.30 1.82 1.92 2.63 2.28

2011 2.32 1.84 1.94 2.65 2.30

2012 2.34 1.86 1.96 2.67 2.32

2013 2.36 1.88 1.98 2.69 2.34

2014 2.38 1.90 2.00 2.71 2.36

2015 2.40 1.92 2.02 2.73 2.38

2016 2.42 1.94 2.04 2.75 2.40

2017 2.44 1.96 2.06 2.77 2.42

2018 2.46 1.98 2.08 2.79 2.44

2019 2.48 2.00 2.10 2.81 2.46

2020 2.50 2.02 2.12 2.83 2.48

2021 2.52 2.04 2.14 2.85 2.50

2022 2.54 2.06 2.16 2.87 2.52

2023 2.56 2.08 2.18 2.89 2.54

2024 2.58 2.10 2.20 2.91 2.56

2025 2.60 2.12 2.22 2.93 2.58
C - 3

Table C - Medium-Low

Regional Electricity Generation Natural Gas Prices

(2000$ Per MMBtu)

Medium Low Case

U.S. AECO Station 2 West-Side East-Side

Wellhead Price Price Delivered Delivered

Year Price

2000 3.60 3.37 3.47 4.09 3.77

2001 4.03 4.05 4.15 4.80 4.50

2002 2.45 2.02 2.12 2.69 2.41

2003 3.00 2.57 2.67 3.26 2.97

2004 2.90 2.47 2.57 3.21 2.87

2005 2.80 2.37 2.47 3.11 2.77

2006 2.76 2.33 2.43 3.16 2.81

2007 2.72 2.29 2.39 3.12 2.76

2008 2.68 2.25 2.35 3.08 2.72

2009 2.64 2.21 2.31 3.04 2.68

2010 2.60 2.17 2.27 3.00 2.64

2011 2.62 2.19 2.29 3.02 2.66

2012 2.64 2.21 2.31 3.04 2.69

2013 2.66 2.23 2.33 3.06 2.71

2014 2.68 2.25 2.35 3.09 2.73

2015 2.70 2.27 2.37 3.11 2.75

2016 2.74 2.31 2.41 3.15 2.79

2017 2.78 2.35 2.45 3.19 2.83

2018 2.82 2.39 2.49 3.23 2.87

2019 2.86 2.43 2.53 3.27 2.91

2020 2.90 2.47 2.57 3.32 2.96

2021 2.92 2.49 2.59 3.34 2.98

2022 2.94 2.51 2.61 3.36 3.00

2023 2.96 2.53 2.63 3.38 3.02

2024 2.98 2.55 2.65 3.40 3.04

2025 3.00 2.57 2.67 3.42 3.06
C - 4

Table C - Medium-High

Regional Electricity Generation Natural Gas Prices

(2000$ Per MMBtu)

Medium High Case

U.S. AECO Station 2 West-Side East-Side

Wellhead Price Price Delivered Delivered

Year Price

2000 3.60 3.37 3.47 4.09 3.77

2001 4.03 4.05 4.15 4.80 4.50

2002 2.80 2.62 2.72 3.32 3.03

2003 3.35 3.17 3.27 3.89 3.59

2004 3.25 3.07 3.17 3.83 3.49

2005 3.15 2.97 3.07 3.73 3.39

2006 3.16 2.98 3.08 3.84 3.48

2007 3.17 2.99 3.09 3.85 3.49

2008 3.18 3.00 3.10 3.87 3.50

2009 3.19 3.01 3.11 3.88 3.51

2010 3.20 3.02 3.12 3.89 3.53

2011 3.23 3.05 3.15 3.93 3.56

2012 3.26 3.08 3.18 3.96 3.59

2013 3.29 3.11 3.21 3.99 3.62

2014 3.32 3.14 3.24 4.03 3.66

2015 3.35 3.17 3.27 4.06 3.69

2016 3.38 3.20 3.30 4.10 3.72

2017 3.41 3.23 3.33 4.13 3.75

2018 3.44 3.26 3.36 4.17 3.79

2019 3.47 3.29 3.39 4.20 3.82

2020 3.50 3.32 3.42 4.24 3.85

2021 3.52 3.34 3.44 4.26 3.88

2022 3.54 3.36 3.46 4.28 3.90

2023 3.56 3.38 3.48 4.31 3.92

2024 3.58 3.40 3.50 4.33 3.95

2025 3.60 3.42 3.52 4.36 3.97
C - 5

Table C - High

Regional Electricity Generation Natural Gas Prices

(2000$ Per MMBtu)

High Case

U.S. AECO Station 2 West-Side East-Side

Wellhead Price Price Delivered Delivered

Year Price

2000 3.60 3.37 3.47 4.09 3.77

2001 4.03 4.05 4.15 4.80 4.50

2002 2.90 2.82 2.92 3.52 3.23

2003 3.50 3.42 3.52 4.15 3.85

2004 3.30 3.22 3.32 3.99 3.64

2005 3.24 3.16 3.26 3.93 3.58

2006 3.27 3.19 3.29 4.06 3.69

2007 3.30 3.22 3.32 4.10 3.73

2008 3.34 3.26 3.36 4.13 3.76

2009 3.37 3.29 3.39 4.17 3.80

2010 3.40 3.32 3.42 4.21 3.84

2011 3.44 3.36 3.46 4.25 3.88

2012 3.48 3.40 3.50 4.30 3.92

2013 3.52 3.44 3.54 4.35 3.97

2014 3.56 3.48 3.58 4.39 4.01

2015 3.60 3.52 3.62 4.44 4.06

2016 3.64 3.56 3.66 4.48 4.10

2017 3.68 3.60 3.70 4.53 4.14

2018 3.72 3.64 3.74 4.58 4.19

2019 3.76 3.68 3.78 4.62 4.23

2020 3.80 3.72 3.82 4.67 4.28

2021 3.84 3.76 3.86 4.71 4.32

2022 3.88 3.80 3.90 4.76 4.37

2023 3.92 3.84 3.94 4.81 4.41

2024 3.96 3.88 3.98 4.85 4.45

2025 4.00 3.92 4.02 4.90 4.50
D - 1

Appendix D - Forecast Tables for U.S. Wellhead and Regional 

Retail Natural Gas Prices

Table D - Medium 

Pacific Northwest Retail Natural Gas Prices

(2000$ Per MMBtu)

Medium Case Regional Retail Natural Gas Prices

U.S.

Wellhead Residential Commercial Industrial Utility

Year Price Average Average

2000 3.60 7.09 5.95 4.26 3.93

2001 4.03 8.38 6.68 5.04 4.64

2002 2.70 6.95 5.95 3.53 2.90

2003 3.20 7.45 6.45 4.04 3.42

2004 3.10 7.35 6.35 3.94 3.33

2005 3.00 7.25 6.25 3.83 3.23

2006 3.00 7.25 6.25 3.83 3.27

2007 3.00 7.25 6.25 3.83 3.27

2008 3.00 7.25 6.25 3.83 3.27

2009 3.00 7.25 6.25 3.83 3.27

2010 3.00 7.25 6.25 3.83 3.27

2011 3.03 7.28 6.28 3.86 3.31

2012 3.06 7.31 6.31 3.89 3.34

2013 3.09 7.34 6.34 3.91 3.37

2014 3.12 7.37 6.37 3.94 3.40

2015 3.15 7.40 6.40 3.97 3.43

2016 3.16 7.41 6.41 3.98 3.44

2017 3.17 7.42 6.42 3.99 3.46

2018 3.18 7.43 6.43 4.00 3.47

2019 3.19 7.44 6.44 4.01 3.48

2020 3.20 7.45 6.45 4.02 3.49

2021 3.22 7.47 6.47 4.04 3.51

2022 3.24 7.49 6.49 4.06 3.53

2023 3.26 7.51 6.51 4.08 3.55

2024 3.28 7.53 6.53 4.10 3.58

2025 3.30 7.55 6.55 4.12 3.60
D - 2

Table D - Low 

Pacific Northwest Retail Natural Gas Prices

(2000$ Per MMBtu)

Low Case Regional Retail Natural Gas Prices

U.S.

Wellhead Residential Commercial Industrial Utility

Year Price Average Average

2000 3.60 7.09 5.95 4.26 3.93

2001 4.03 8.38 6.68 5.04 4.64

2002 2.35 6.60 5.60 3.06 2.39

2003 2.80 7.05 6.05 3.52 2.85

2004 2.70 6.95 5.95 3.42 2.76

2005 2.50 6.75 5.75 3.21 2.56

2006 2.46 6.71 5.71 3.17 2.56

2007 2.42 6.67 5.67 3.12 2.52

2008 2.38 6.63 5.63 3.08 2.47

2009 2.34 6.59 5.59 3.04 2.43

2010 2.30 6.55 5.55 3.00 2.39

2011 2.32 6.57 5.57 3.02 2.41

2012 2.34 6.59 5.59 3.04 2.43

2013 2.36 6.61 5.61 3.06 2.45

2014 2.38 6.63 5.63 3.08 2.47

2015 2.40 6.65 5.65 3.10 2.49

2016 2.42 6.67 5.67 3.11 2.51

2017 2.44 6.69 5.69 3.13 2.53

2018 2.46 6.71 5.71 3.15 2.56

2019 2.48 6.73 5.73 3.17 2.58

2020 2.50 6.75 5.75 3.19 2.60

2021 2.52 6.77 5.77 3.21 2.62

2022 2.54 6.79 5.79 3.23 2.64

2023 2.56 6.81 5.81 3.25 2.66

2024 2.58 6.83 5.83 3.27 2.68

2025 2.60 6.85 5.85 3.29 2.70
D - 3

Table D - Medium-Low 

Pacific Northwest Retail Natural Gas Prices

(2000$ Per MMBtu)

Medium Low Case Regional Retail Natural Gas Prices

U.S.

Wellhead Residential Commercial Industrial Utility

Year Price Average Average

2000 3.60 7.09 5.95 4.26 3.93

2001 4.03 8.38 6.68 5.04 4.64

2002 2.45 6.70 5.70 3.20 2.54

2003 3.00 7.25 6.25 3.76 3.11

2004 2.90 7.15 6.15 3.66 3.02

2005 2.80 7.05 6.05 3.56 2.92

2006 2.76 7.01 6.01 3.51 2.92

2007 2.72 6.97 5.97 3.47 2.88

2008 2.68 6.93 5.93 3.43 2.84

2009 2.64 6.89 5.89 3.38 2.80

2010 2.60 6.85 5.85 3.34 2.76

2011 2.62 6.87 5.87 3.36 2.78

2012 2.64 6.89 5.89 3.38 2.80

2013 2.66 6.91 5.91 3.40 2.82

2014 2.68 6.93 5.93 3.42 2.84

2015 2.70 6.95 5.95 3.44 2.86

2016 2.74 6.99 5.99 3.48 2.90

2017 2.78 7.03 6.03 3.52 2.94

2018 2.82 7.07 6.07 3.56 2.98

2019 2.86 7.11 6.11 3.60 3.03

2020 2.90 7.15 6.15 3.64 3.07

2021 2.92 7.17 6.17 3.66 3.09

2022 2.94 7.19 6.19 3.68 3.11

2023 2.96 7.21 6.21 3.70 3.13

2024 2.98 7.23 6.23 3.72 3.15

2025 3.00 7.25 6.25 3.73 3.17
D - 4

Table D - Medium-High 

Pacific Northwest Retail Natural Gas Prices

(2000$ Per MMBtu)

Medium High Case Regional Retail Natural Gas Prices

U.S.

Wellhead Residential Commercial Industrial Utility

Year Price Average Average

2000 3.60 7.09 5.95 4.26 3.93

2001 4.03 8.38 6.68 5.04 4.64

2002 2.80 7.05 6.05 3.74 3.16

2003 3.35 7.60 6.60 4.30 3.73

2004 3.25 7.50 6.50 4.20 3.64

2005 3.15 7.40 6.40 4.10 3.54

2006 3.16 7.41 6.41 4.11 3.59

2007 3.17 7.42 6.42 4.11 3.60

2008 3.18 7.43 6.43 4.12 3.62

2009 3.19 7.44 6.44 4.13 3.63

2010 3.20 7.45 6.45 4.14 3.64

2011 3.23 7.48 6.48 4.17 3.67

2012 3.26 7.51 6.51 4.20 3.70

2013 3.29 7.54 6.54 4.23 3.73

2014 3.32 7.57 6.57 4.26 3.77

2015 3.35 7.60 6.60 4.29 3.80

2016 3.38 7.63 6.63 4.32 3.83

2017 3.41 7.66 6.66 4.35 3.86

2018 3.44 7.69 6.69 4.38 3.90

2019 3.47 7.72 6.72 4.41 3.93

2020 3.50 7.75 6.75 4.44 3.96

2021 3.52 7.77 6.77 4.46 3.98

2022 3.54 7.79 6.79 4.47 4.01

2023 3.56 7.81 6.81 4.49 4.03

2024 3.58 7.83 6.83 4.51 4.05

2025 3.60 7.85 6.85 4.53 4.07
D - 5

Table D - High 

Pacific Northwest Retail Natural Gas Prices

(2000$ Per MMBtu)

High Case Regional Retail Natural Gas Prices

U.S.

Wellhead Residential Commercial Industrial Utility

Year Price Average Average

2000 3.60 7.09 5.95 4.26 3.93

2001 4.03 8.38 6.68 5.04 4.64

2002 2.90 7.15 6.15 3.92 3.37

2003 3.50 7.75 6.75 4.53 3.99

2004 3.30 7.55 6.55 4.32 3.80

2005 3.24 7.49 6.49 4.26 3.73

2006 3.27 7.52 6.52 4.29 3.81

2007 3.30 7.55 6.55 4.32 3.85

2008 3.34 7.59 6.59 4.36 3.88

2009 3.37 7.62 6.62 4.39 3.92

2010 3.40 7.65 6.65 4.42 3.95

2011 3.44 7.69 6.69 4.46 3.99

2012 3.48 7.73 6.73 4.50 4.04

2013 3.52 7.77 6.77 4.54 4.08

2014 3.56 7.81 6.81 4.58 4.12

2015 3.60 7.85 6.85 4.62 4.17

2016 3.64 7.89 6.89 4.66 4.21

2017 3.68 7.93 6.93 4.70 4.25

2018 3.72 7.97 6.97 4.74 4.30

2019 3.76 8.01 7.01 4.78 4.34

2020 3.80 8.05 7.05 4.82 4.38

2021 3.84 8.09 7.09 4.86 4.43

2022 3.88 8.13 7.13 4.90 4.47

2023 3.92 8.17 7.17 4.94 4.51

2024 3.96 8.21 7.21 4.98 4.56

2025 4.00 8.25 7.25 5.02 4.60
E - 1

Appendix E - Forecast Tables for World Oil and Regional Retail Oil Prices

Table E - Medium

Retail Oil Price Forecast

Medium Case Industrial Industrial Average Commercial Commercial Average Average Utility Utility

World Oil Residual Distillate Industrial Residual Distillate Commercial Residential Residual Distillate

Year Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price

(00$/Bbl.) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu)

2000 27.69 4.09 7.25 7.06 4.14 6.83 6.70 9.23 4.09 6.71

2001 23.00 3.40 6.35 6.17 3.45 5.93 5.81 8.33 3.40 5.81

2002 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2003 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2004 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2005 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2006 22.10 3.26 6.17 6.00 3.31 5.75 5.64 8.15 3.26 5.63

2007 22.20 3.28 6.19 6.02 3.33 5.77 5.65 8.17 3.28 5.65

2008 22.30 3.29 6.21 6.04 3.34 5.79 5.67 8.19 3.29 5.67

2009 22.40 3.31 6.23 6.06 3.36 5.81 5.69 8.21 3.31 5.69

2010 22.50 3.32 6.25 6.08 3.37 5.83 5.71 8.23 3.32 5.71

2011 22.60 3.34 6.27 6.10 3.39 5.85 5.73 8.25 3.34 5.73

2012 22.70 3.35 6.29 6.12 3.40 5.87 5.75 8.27 3.35 5.75

2013 22.80 3.37 6.31 6.13 3.42 5.89 5.77 8.29 3.37 5.77

2014 22.90 3.38 6.33 6.15 3.43 5.91 5.79 8.31 3.38 5.79

2015 23.00 3.40 6.35 6.17 3.45 5.93 5.81 8.33 3.40 5.81

2016 23.10 3.41 6.36 6.19 3.46 5.94 5.83 8.34 3.41 5.82

2017 23.20 3.43 6.38 6.21 3.48 5.96 5.85 8.36 3.43 5.84

2018 23.30 3.44 6.40 6.23 3.49 5.98 5.86 8.38 3.44 5.86

2019 23.40 3.46 6.42 6.25 3.51 6.00 5.88 8.40 3.46 5.88

2020 23.50 3.47 6.44 6.27 3.52 6.02 5.90 8.42 3.47 5.90

2021 23.60 3.48 6.46 6.29 3.53 6.04 5.92 8.44 3.48 5.92

2022 23.70 3.50 6.48 6.30 3.55 6.06 5.94 8.46 3.50 5.94

2023 23.80 3.51 6.50 6.32 3.56 6.08 5.96 8.48 3.51 5.96

2024 23.90 3.53 6.52 6.34 3.58 6.10 5.98 8.50 3.53 5.98

2025 24.00 3.54 6.54 6.36 3.59 6.12 6.00 8.52 3.54 6.00
E - 2

Table E - Low

Retail Oil Price Forecast

Low Case Industrial Industrial Average Commercial Commercial Average Average Utility Utility

World Oil Residual Distillate Industrial Residual Distillate Commercial Residential Residual Distillate

Year Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price

(00$/Bbl.) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu)

2000 27.69 4.09 7.25 7.06 4.14 6.83 6.70 9.23 4.09 6.71

2001 21.00 3.10 5.96 5.79 3.15 5.54 5.43 7.94 3.10 5.42

2002 21.00 3.10 5.96 5.79 3.15 5.54 5.43 7.94 3.10 5.42

2003 20.00 2.95 5.77 5.60 3.00 5.35 5.24 7.75 2.95 5.23

2004 18.00 2.66 5.38 5.22 2.71 4.96 4.86 7.36 2.66 4.84

2005 16.00 2.36 5.00 4.84 2.41 4.58 4.48 6.98 2.36 4.46

2006 16.14 2.38 5.03 4.87 2.43 4.61 4.50 7.01 2.38 4.49

2007 16.28 2.40 5.05 4.90 2.45 4.63 4.53 7.03 2.40 4.51

2008 16.42 2.42 5.08 4.92 2.47 4.66 4.56 7.06 2.42 4.54

2009 16.56 2.44 5.11 4.95 2.49 4.69 4.58 7.09 2.44 4.57

2010 16.70 2.47 5.13 4.98 2.52 4.71 4.61 7.11 2.47 4.59

2011 16.84 2.49 5.16 5.00 2.54 4.74 4.64 7.14 2.49 4.62

2012 16.98 2.51 5.19 5.03 2.56 4.77 4.66 7.17 2.51 4.65

2013 17.12 2.53 5.21 5.06 2.58 4.79 4.69 7.19 2.53 4.67

2014 17.26 2.55 5.24 5.08 2.60 4.82 4.72 7.22 2.55 4.70

2015 17.40 2.57 5.27 5.11 2.62 4.85 4.74 7.25 2.57 4.73

2016 17.56 2.59 5.30 5.14 2.64 4.88 4.77 7.28 2.59 4.76

2017 17.72 2.62 5.33 5.17 2.67 4.91 4.80 7.31 2.62 4.79

2018 17.88 2.64 5.36 5.20 2.69 4.94 4.83 7.34 2.64 4.82

2019 18.04 2.66 5.39 5.23 2.71 4.97 4.86 7.37 2.66 4.85

2020 18.20 2.69 5.42 5.26 2.74 5.00 4.89 7.40 2.69 4.88

2021 18.36 2.71 5.45 5.29 2.76 5.03 4.92 7.43 2.71 4.91

2022 18.52 2.73 5.48 5.32 2.78 5.06 4.95 7.46 2.73 4.94

2023 18.68 2.76 5.51 5.35 2.81 5.09 4.99 7.49 2.76 4.97

2024 18.84 2.78 5.55 5.38 2.83 5.13 5.02 7.53 2.78 5.01

2025 19.00 2.81 5.58 5.41 2.86 5.16 5.05 7.56 2.81 5.04
E - 3

Table E - Medium-Low

Retail Oil Price Forecast

Medium Low Case Industrial Industrial Average Commercial Commercial Average Average Utility Utility

World Oil Residual Distillate Industrial Residual Distillate Commercial Residential Residual Distillate

Year Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price

(00$/Bbl.) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu)

2000 27.69 4.09 7.25 7.06 4.14 6.83 6.70 9.23 4.09 6.71

2001 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2002 22.00 3.25 6.15 5.98 3.30 5.73 5.62 8.13 3.25 5.61

2003 21.00 3.10 5.96 5.79 3.15 5.54 5.43 7.94 3.10 5.42

2004 21.00 3.10 5.96 5.79 3.15 5.54 5.43 7.94 3.10 5.42

2005 19.00 2.81 5.58 5.41 2.86 5.16 5.05 7.56 2.81 5.04

2006 19.10 2.82 5.60 5.43 2.87 5.18 5.07 7.58 2.82 5.06

2007 19.20 2.83 5.61 5.45 2.88 5.19 5.08 7.59 2.83 5.07

2008 19.30 2.85 5.63 5.47 2.90 5.21 5.10 7.61 2.85 5.09

2009 19.40 2.86 5.65 5.49 2.91 5.23 5.12 7.63 2.86 5.11

2010 19.50 2.88 5.67 5.51 2.93 5.25 5.14 7.65 2.88 5.13

2011 19.60 2.89 5.69 5.53 2.94 5.27 5.16 7.67 2.89 5.15

2012 19.70 2.91 5.71 5.55 2.96 5.29 5.18 7.69 2.91 5.17

2013 19.80 2.92 5.73 5.57 2.97 5.31 5.20 7.71 2.92 5.19

2014 19.90 2.94 5.75 5.58 2.99 5.33 5.22 7.73 2.94 5.21

2015 20.00 2.95 5.77 5.60 3.00 5.35 5.24 7.75 2.95 5.23

2016 20.10 2.97 5.79 5.62 3.02 5.37 5.26 7.77 2.97 5.25

2017 20.20 2.98 5.81 5.64 3.03 5.39 5.27 7.79 2.98 5.27

2018 20.30 3.00 5.83 5.66 3.05 5.41 5.29 7.81 3.00 5.29

2019 20.40 3.01 5.85 5.68 3.06 5.43 5.31 7.83 3.01 5.31

2020 20.50 3.03 5.87 5.70 3.08 5.45 5.33 7.85 3.03 5.33

2021 20.60 3.04 5.88 5.72 3.09 5.46 5.35 7.86 3.04 5.34

2022 20.70 3.06 5.90 5.74 3.11 5.48 5.37 7.88 3.06 5.36

2023 20.80 3.07 5.92 5.75 3.12 5.50 5.39 7.90 3.07 5.38

2024 20.90 3.09 5.94 5.77 3.14 5.52 5.41 7.92 3.09 5.40

2025 21.00 3.10 5.96 5.79 3.15 5.54 5.43 7.94 3.10 5.42
E - 4

Table E - Medium-High

Retail Oil Price Forecast

Medium High Case Industrial Industrial Average Commercial Commercial Average Average Utility Utility

World Oil Residual Distillate Industrial Residual Distillate Commercial Residential Residual Distillate

Year Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price

(00$/Bbl.) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu)

2000 27.69 4.09 7.25 7.06 4.14 6.83 6.70 9.23 4.09 6.71

2001 24.00 3.54 6.54 6.36 3.59 6.12 6.00 8.52 3.54 6.00

2002 24.00 3.54 6.54 6.36 3.59 6.12 6.00 8.52 3.54 6.00

2003 24.00 3.54 6.54 6.36 3.59 6.12 6.00 8.52 3.54 6.00

2004 24.00 3.54 6.54 6.36 3.59 6.12 6.00 8.52 3.54 6.00

2005 25.00 3.69 6.73 6.55 3.74 6.31 6.19 8.71 3.69 6.19

2006 25.10 3.71 6.75 6.57 3.76 6.33 6.21 8.73 3.71 6.21

2007 25.20 3.72 6.77 6.59 3.77 6.35 6.23 8.75 3.72 6.23

2008 25.30 3.74 6.79 6.61 3.79 6.37 6.24 8.77 3.74 6.25

2009 25.40 3.75 6.81 6.63 3.80 6.39 6.26 8.79 3.75 6.27

2010 25.50 3.77 6.83 6.65 3.82 6.41 6.28 8.81 3.77 6.29

2011 25.60 3.78 6.85 6.67 3.83 6.43 6.30 8.83 3.78 6.31

2012 25.70 3.79 6.86 6.68 3.84 6.44 6.32 8.84 3.79 6.32

2013 25.80 3.81 6.88 6.70 3.86 6.46 6.34 8.86 3.81 6.34

2014 25.90 3.82 6.90 6.72 3.87 6.48 6.36 8.88 3.82 6.36

2015 26.00 3.84 6.92 6.74 3.89 6.50 6.38 8.90 3.84 6.38

2016 26.10 3.85 6.94 6.76 3.90 6.52 6.40 8.92 3.85 6.40

2017 26.20 3.87 6.96 6.78 3.92 6.54 6.42 8.94 3.87 6.42

2018 26.30 3.88 6.98 6.80 3.93 6.56 6.43 8.96 3.88 6.44

2019 26.40 3.90 7.00 6.82 3.95 6.58 6.45 8.98 3.90 6.46

2020 26.50 3.91 7.02 6.84 3.96 6.60 6.47 9.00 3.91 6.48

2021 26.60 3.93 7.04 6.86 3.98 6.62 6.49 9.02 3.93 6.50

2022 26.70 3.94 7.06 6.87 3.99 6.64 6.51 9.04 3.94 6.52

2023 26.80 3.96 7.08 6.89 4.01 6.66 6.53 9.06 3.96 6.54

2024 26.90 3.97 7.10 6.91 4.02 6.68 6.55 9.08 3.97 6.56

2025 27.00 3.99 7.12 6.93 4.04 6.70 6.57 9.10 3.99 6.58
E - 5

Table E - High

Retail Oil Price Forecast

High Case Industrial Industrial Average Commercial Commercial Average Average Utility Utility

World Oil Residual Distillate Industrial Residual Distillate Commercial Residential Residual Distillate

Year Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price Oil Price

(00$/Bbl.) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu) (00$/MMBtu)

2000 27.69 4.09 7.25 7.06 4.14 6.83 6.70 9.23 4.09 6.71

2001 25.00 3.69 6.73 6.55 3.74 6.31 6.19 8.71 3.69 6.19

2002 26.00 3.84 6.92 6.74 3.89 6.50 6.38 8.90 3.84 6.38

2003 29.00 4.28 7.50 7.31 4.33 7.08 6.95 9.48 4.28 6.96

2004 30.00 4.43 7.69 7.50 4.48 7.27 7.14 9.67 4.43 7.15

2005 30.00 4.43 7.69 7.50 4.48 7.27 7.14 9.67 4.43 7.15

2006 30.10 4.44 7.71 7.52 4.49 7.29 7.16 9.69 4.44 7.17

2007 30.20 4.46 7.73 7.54 4.51 7.31 7.18 9.71 4.46 7.19

2008 30.30 4.47 7.75 7.56 4.52 7.33 7.20 9.73 4.47 7.21

2009 30.40 4.49 7.77 7.58 4.54 7.35 7.21 9.75 4.49 7.23

2010 30.50 4.50 7.79 7.59 4.55 7.37 7.23 9.77 4.50 7.25

2011 30.60 4.52 7.81 7.61 4.57 7.39 7.25 9.79 4.52 7.27

2012 30.70 4.53 7.83 7.63 4.58 7.41 7.27 9.81 4.53 7.29

2013 30.80 4.55 7.85 7.65 4.60 7.43 7.29 9.83 4.55 7.31

2014 30.90 4.56 7.86 7.67 4.61 7.44 7.31 9.84 4.56 7.32

2015 31.00 4.58 7.88 7.69 4.63 7.46 7.33 9.86 4.58 7.34

2016 31.10 4.59 7.90 7.71 4.64 7.48 7.35 9.88 4.59 7.36

2017 31.20 4.61 7.92 7.73 4.66 7.50 7.37 9.90 4.61 7.38

2018 31.30 4.62 7.94 7.75 4.67 7.52 7.39 9.92 4.62 7.40

2019 31.40 4.64 7.96 7.77 4.69 7.54 7.40 9.94 4.64 7.42

2020 31.50 4.65 7.98 7.78 4.70 7.56 7.42 9.96 4.65 7.44

2021 31.60 4.67 8.00 7.80 4.72 7.58 7.44 9.98 4.67 7.46

2022 31.70 4.68 8.02 7.82 4.73 7.60 7.46 10.00 4.68 7.48

2023 31.80 4.70 8.04 7.84 4.75 7.62 7.48 10.02 4.70 7.50

2024 31.90 4.71 8.06 7.86 4.76 7.64 7.50 10.04 4.71 7.52

2025 32.00 4.73 8.08 7.88 4.78 7.66 7.52 10.06 4.73 7.54
F - 1

Appendix F - Forecast Tables for Western Minemouth and 

Regional Delivered Coal Prices

Table F - Medium

Coal Price Forecasts

(2000$ Per MMBtu)

Medium Case Selected State Electricity Generation Coal Prices 

Western Regional

Year Minmouth Industrial

Price Price Washington Oregon Montana Idaho Utah Wyoming

2000 0.51 2.11 1.65 1.09 0.71 0.00 1.39 0.81

2001 0.51 2.11 1.55 1.04 0.71 0.96 1.16 0.79

2002 0.51 2.11 1.55 1.04 0.71 0.96 1.15 0.79

2003 0.50 2.10 1.54 1.03 0.70 0.95 1.15 0.78

2004 0.50 2.10 1.54 1.03 0.70 0.95 1.14 0.78

2005 0.49 2.09 1.54 1.03 0.69 0.94 1.14 0.77

2006 0.49 2.09 1.53 1.02 0.69 0.94 1.14 0.77

2007 0.49 2.09 1.53 1.02 0.69 0.94 1.13 0.77

2008 0.48 2.08 1.52 1.01 0.68 0.93 1.13 0.76

2009 0.48 2.08 1.52 1.01 0.68 0.93 1.12 0.76

2010 0.47 2.07 1.52 1.01 0.67 0.92 1.12 0.75

2011 0.47 2.07 1.51 1.00 0.67 0.92 1.12 0.75

2012 0.47 2.07 1.51 1.00 0.67 0.92 1.11 0.75

2013 0.46 2.06 1.50 1.00 0.66 0.91 1.11 0.74

2014 0.46 2.06 1.50 0.99 0.66 0.91 1.10 0.74

2015 0.46 2.06 1.50 0.99 0.66 0.91 1.10 0.74

2016 0.45 2.05 1.49 0.98 0.65 0.90 1.10 0.73

2017 0.45 2.05 1.49 0.98 0.65 0.90 1.09 0.73

2018 0.44 2.04 1.49 0.98 0.64 0.89 1.09 0.72

2019 0.44 2.04 1.48 0.97 0.64 0.89 1.09 0.72

2020 0.44 2.04 1.48 0.97 0.64 0.89 1.08 0.72

2021 0.43 2.03 1.48 0.97 0.63 0.88 1.08 0.71

2022 0.43 2.03 1.47 0.96 0.63 0.88 1.08 0.71

2023 0.43 2.03 1.47 0.96 0.63 0.88 1.07 0.71

2024 0.42 2.02 1.47 0.96 0.62 0.87 1.07 0.70

2025 0.42 2.02 1.46 0.95 0.62 0.87 1.07 0.70
F - 2

Table F - Low

Coal Price Forecasts

(2000$ Per MMBtu)

Low Case Selected State Electricity Generation Coal Prices 

Western Regional

Year Minmouth Industrial

Price Price Washington Oregon Montana Idaho Utah Wyoming

2000 0.51 2.11 1.65 1.09 0.71 0.00 1.39 0.81

2001 0.51 2.11 1.55 1.04 0.71 0.96 1.15 0.79

2002 0.50 2.10 1.54 1.03 0.70 0.95 1.14 0.78

2003 0.49 2.09 1.53 1.02 0.69 0.94 1.14 0.77

2004 0.48 2.08 1.53 1.02 0.68 0.93 1.13 0.76

2005 0.48 2.08 1.52 1.01 0.68 0.93 1.12 0.76

2006 0.47 2.07 1.51 1.00 0.67 0.92 1.11 0.75

2007 0.46 2.06 1.50 0.99 0.66 0.91 1.11 0.74

2008 0.46 2.06 1.50 0.99 0.66 0.91 1.10 0.74

2009 0.45 2.05 1.49 0.98 0.65 0.90 1.09 0.73

2010 0.44 2.04 1.48 0.97 0.64 0.89 1.09 0.72

2011 0.43 2.03 1.48 0.97 0.63 0.88 1.08 0.71

2012 0.43 2.03 1.47 0.96 0.63 0.88 1.07 0.71

2013 0.42 2.02 1.46 0.95 0.62 0.87 1.07 0.70

2014 0.42 2.02 1.46 0.95 0.62 0.87 1.06 0.70

2015 0.41 2.01 1.45 0.94 0.61 0.86 1.06 0.69

2016 0.40 2.00 1.45 0.94 0.60 0.85 1.05 0.68

2017 0.40 2.00 1.44 0.93 0.60 0.85 1.04 0.68

2018 0.39 1.99 1.43 0.92 0.59 0.84 1.04 0.67

2019 0.39 1.99 1.43 0.92 0.59 0.84 1.03 0.67

2020 0.38 1.98 1.42 0.91 0.58 0.83 1.03 0.66

2021 0.37 1.97 1.42 0.91 0.57 0.82 1.02 0.65

2022 0.37 1.97 1.41 0.90 0.57 0.82 1.01 0.65

2023 0.36 1.96 1.40 0.90 0.56 0.81 1.01 0.64

2024 0.36 1.96 1.40 0.89 0.56 0.81 1.00 0.64

2025 0.35 1.95 1.39 0.88 0.55 0.80 1.00 0.63
F - 3

Table F - Medium-Low

Coal Price Forecasts

(2000$ Per MMBtu)

Medium Low Case Selected State Electricity Generation Coal Prices 

Western Regional

Year Minmouth Industrial

Price Price Washington Oregon Montana Idaho Utah Wyoming

2000 0.51 2.11 1.65 1.09 0.71 0.00 1.39 0.81

2001 0.51 2.11 1.55 1.04 0.71 0.96 1.15 0.79

2002 0.50 2.10 1.54 1.04 0.70 0.95 1.15 0.78

2003 0.50 2.10 1.54 1.03 0.70 0.95 1.14 0.78

2004 0.49 2.09 1.53 1.02 0.69 0.94 1.14 0.77

2005 0.49 2.09 1.53 1.02 0.69 0.94 1.13 0.77

2006 0.48 2.08 1.52 1.01 0.68 0.93 1.13 0.76

2007 0.48 2.08 1.52 1.01 0.68 0.93 1.12 0.76

2008 0.47 2.07 1.51 1.00 0.67 0.92 1.12 0.75

2009 0.46 2.06 1.51 1.00 0.66 0.91 1.11 0.74

2010 0.46 2.06 1.50 0.99 0.66 0.91 1.11 0.74

2011 0.45 2.05 1.50 0.99 0.65 0.90 1.10 0.73

2012 0.45 2.05 1.49 0.98 0.65 0.90 1.10 0.73

2013 0.44 2.04 1.49 0.98 0.64 0.89 1.09 0.72

2014 0.44 2.04 1.48 0.97 0.64 0.89 1.09 0.72

2015 0.44 2.04 1.48 0.97 0.64 0.89 1.08 0.72

2016 0.43 2.03 1.47 0.96 0.63 0.88 1.08 0.71

2017 0.43 2.03 1.47 0.96 0.63 0.88 1.07 0.71

2018 0.42 2.02 1.46 0.95 0.62 0.87 1.07 0.70

2019 0.42 2.02 1.46 0.95 0.62 0.87 1.06 0.70

2020 0.41 2.01 1.45 0.94 0.61 0.86 1.06 0.69

2021 0.41 2.01 1.45 0.94 0.61 0.86 1.05 0.69

2022 0.40 2.00 1.44 0.94 0.60 0.85 1.05 0.68

2023 0.40 2.00 1.44 0.93 0.60 0.85 1.04 0.68

2024 0.39 1.99 1.44 0.93 0.59 0.84 1.04 0.67

2025 0.39 1.99 1.43 0.92 0.59 0.84 1.04 0.67
F - 4

Table F - Medium-High

Coal Price Forecasts

(2000$ Per MMBtu)

Medium High Case Selected State Electricity Generation Coal Prices 

Western Regional

Year Minmouth Industrial

Price Price Washington Oregon Montana Idaho Utah Wyoming

2000 0.51 2.11 1.65 1.09 0.71 0.00 1.39 0.81

2001 0.51 2.11 1.55 1.04 0.71 0.96 1.16 0.79

2002 0.51 2.11 1.55 1.04 0.71 0.96 1.15 0.79

2003 0.51 2.11 1.55 1.04 0.71 0.96 1.15 0.79

2004 0.50 2.10 1.55 1.04 0.70 0.95 1.15 0.78

2005 0.50 2.10 1.54 1.03 0.70 0.95 1.15 0.78

2006 0.50 2.10 1.54 1.03 0.70 0.95 1.14 0.78

2007 0.50 2.10 1.54 1.03 0.70 0.95 1.14 0.78

2008 0.49 2.09 1.54 1.03 0.69 0.94 1.14 0.77

2009 0.49 2.09 1.53 1.02 0.69 0.94 1.14 0.77

2010 0.49 2.09 1.53 1.02 0.69 0.94 1.13 0.77

2011 0.49 2.09 1.53 1.02 0.69 0.94 1.13 0.77

2012 0.48 2.08 1.53 1.02 0.68 0.93 1.13 0.76

2013 0.48 2.08 1.52 1.01 0.68 0.93 1.13 0.76

2014 0.48 2.08 1.52 1.01 0.68 0.93 1.12 0.76

2015 0.48 2.08 1.52 1.01 0.68 0.93 1.12 0.76

2016 0.47 2.07 1.52 1.01 0.67 0.92 1.12 0.75

2017 0.47 2.07 1.51 1.00 0.67 0.92 1.12 0.75

2018 0.47 2.07 1.51 1.00 0.67 0.92 1.12 0.75

2019 0.47 2.07 1.51 1.00 0.67 0.92 1.11 0.75

2020 0.46 2.06 1.51 1.00 0.66 0.91 1.11 0.74

2021 0.46 2.06 1.50 0.99 0.66 0.91 1.11 0.74

2022 0.46 2.06 1.50 0.99 0.66 0.91 1.11 0.74

2023 0.46 2.06 1.50 0.99 0.66 0.91 1.10 0.74

2024 0.46 2.06 1.50 0.99 0.66 0.91 1.10 0.74

2025 0.45 2.05 1.50 0.99 0.65 0.90 1.10 0.73
F - 5

Table F - High

Coal Price Forecasts

(2000$ Per MMBtu)

High Case Selected State Electricity Generation Coal Prices 

Western Regional

Year Minmouth Industrial

Price Price Washington Oregon Montana Idaho Utah Wyoming

2000 0.51 2.11 1.65 1.09 0.71 0.00 1.39 0.81

2001 0.51 2.11 1.56 1.05 0.71 0.96 1.16 0.79

2002 0.51 2.11 1.56 1.05 0.71 0.96 1.16 0.79

2003 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2004 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2005 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2006 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2007 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2008 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2009 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2010 0.52 2.12 1.56 1.05 0.72 0.97 1.16 0.80

2011 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2012 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2013 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2014 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2015 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2016 0.52 2.12 1.56 1.05 0.72 0.97 1.17 0.80

2017 0.52 2.12 1.56 1.06 0.72 0.97 1.17 0.80

2018 0.52 2.12 1.57 1.06 0.72 0.97 1.17 0.80

2019 0.52 2.12 1.57 1.06 0.72 0.97 1.17 0.80

2020 0.52 2.12 1.57 1.06 0.72 0.97 1.17 0.80

2021 0.52 2.12 1.57 1.06 0.72 0.97 1.17 0.80

2022 0.52 2.12 1.57 1.06 0.72 0.97 1.17 0.80

2023 0.53 2.13 1.57 1.06 0.73 0.98 1.17 0.81

2024 0.53 2.13 1.57 1.06 0.73 0.98 1.17 0.81

2025 0.53 2.13 1.57 1.06 0.73 0.98 1.17 0.81

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