P.1 

OAR Box 1669 

Prepped by Charmelle Mathews 

Document Number: 

106) 11-1-14 

Docket Number: 

A-98-13 

Printed 9/23/2008 9:36:50 AM Sheet 106 of UO 
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Annual Energy Outlook 1999 

Report Contents 

[Report*: DOE/EIA-0383 

(")1 Preface 

MAR " 6 2001 

Page 1 ot 3 

Jl-JT-IH, 

Ann.dl Fnflfffl'Wfirlnnik ]°99 

With Projections to 2020 

(Errata as of 9/9/1999) Th e Annual Energy outlook 1999 {AE099) presents midterm forecasts of 

energy supply, demand, and prices through 2020 prepared by the Energy 

. _^ M Information Administration (EIA). The projections are based on results from 

Preface ElA's National Energy Modeling System (NEMS). 

• Administrator's 

Message 

• Overview 

• Legislation & 

Regulations 

Issues in Focus 

• Market Trends 

• Forecast 

Comparisons 

• Major Assumptions 

for the Forecasts 

" Model Results 

(Appendix Tables) 

" Download Report 

• Acronyms 

• Contacts 

The report begins with an "Overview" summarizing the AE099 reference case. 

The next section, "Legislation and Regulations," describes the assumptions 

made with regard to laws that affect energy markets and discusses evolving 

legislative and regulatory issues. "Issues in Focus" discusses current energy 

issues—the economic decline in East Asia, growth in demand for natural gas, 

vehicle emissions standards, competitive electricity pricing, renewable portfolio 

standards, and carbon emissions. It is followed by the analysis of energy 

market trends. 

The analysis in AE099 focuses primarily on a reference case and four other 

cases that assume higher and lower economic growth and higher and lower 

world oil prices than in the reference case. Forecast tables for these cases are 

provided in Appendixes A through C. Appendixes D and E present a summary 

of the reference case forecasts in units of oil equivalence and household energy 

expenditures. Other cases explore the impacts of varying key assumptions in 

NEMS-^generally, technology penetration. The major results are shown in 

Appendix F. Appendix G briefly describes NEMS and the AE099 assumptions, 

with a summary table of the cases. Appendix H provides tables of energy 

and metric conversion factors. AE099, the detailed assumptions, and ' 

supplementary tables will be available on the EIA Home Page and on CD-ROM. 

The AE099 projections are based on Federal, State, and local laws and 

regulations in effect on July 1,1998. Pending legislation and sections of existing 

legislation for which funds have not been appropriated are not reflected in the 

forecasts. Historical data used forthe AE099 projections were the most current 

available as of July 31,1998, when most 1997 data but only partial 1998 data 

were available. Historical data are presented in this report for comparative 

purposes; documents referenced in the source notes should be consulted for 

official values. The AE099 projections for 1998 and 1999 incorporate the short-

.term projections from the September update of ElA's Short-Term Energy 

Outlook (STEO), Third Quarter 1998. 

The AE099 projections are used by Federal, State, and local governments, 

trade associations, and other planners and decisionmakers in the public and 

private sectors. They are published in accordance with Section 205c of the 

Department of Energy Organization Act of 1977 (Public Law 9591), which 

requires the Administrator of EIA to prepare an annual report that contains 

trends and projections of energy consumption and supply. 

Feedback 

Related Links 

" Assumptions to the 

AEQ99 

The projections in AE099 are not statements of what will happen but of what 

might happen, given the assumptions and methodologies used. The 

projections are business-as-usual trend forecasts, given known technology, 

technological and demographic trends, and current laws and regulations. 

Thus, they provide a policy-neutral reference case that can be used to 

analyze policy initiatives. EIA does not propose, advocate, or speculate on 

future legislative and regulatory changes. All laws are assumed to remain as 

currently enacted; however, the impacts of emerging regulatory changes, 

when defined, are reflected. 

Because energy markets are complex, models are simplified representations 

http://www.eia.doe.gov/oiaf/aeo99/homepage.html 1/2/01 

/ 
Annual Energy Uutlook 1999 Page 2 of 3 

' Interactive Data 

Queries to 

the AE099 

" Supplemental Data 

to the AEQ99 

' NEMS Conference 

• To Forecasting 

Home Page 

" EIA Homepage 

Because energy markets are complex, models are simplified representations 

of energy production and consumption, regulations, and producer and 

consumer behavior. Projections are highly dependent on the data, 

methodologies, model structures, and assumptions used in their development. 

Behavioral characteristics are indicative of real-world tendencies rather than 

representations of specific outcomes. 

Energy market projections are subject to much uncertainty. Many of the 

events that shape energy markets are random and cannot be anticipated, 

including severe weather, political disruptions, strikes, and technological 

breakthroughs. In addition, future developments in technologies, 

demographics, and resources cannot be foreseen with any degree of 

certainty. Many key uncertainties in the AE099 projections are addressed 

through alternative cases. 

EIA has endeavored to make these projections as objective, reliable, and 

useful as possible; however, they should serve as an adjunct to, not a 

substitute for, analytical processes in the examination of policy initiatives. 

Administrator's Message 

As we present the projections in the Annual Energy Outlook 1999 (AE099), it is 

important to clarify what these projections represent. While the reference case 

projections do not hypothesize radical changes in energy markets and energyusing and producing technologies, they do assume continuing market changes 

and improvements in energy technologies, derived from past trends. 

The Energy Information Administration (EIA) endeavors to represent current 

energy market conditions, both domestic and worldwide, and their impacts on 

future energy trends. An important example of such transitory issues is the 

ongoing economic crisis in East Asia, which currently is depressing world oil 

demand and prices and domestic oil production. Another is the continuing 

restructuring of the U.S. electricity industry and the movement to competitive 

pricing of electricity. Both of these topics are featured in AE099, and they are 

included in the reference case projections. 

In addition to the longer-term impacts of current market transitions, the 

reference case projections also include the impacts of a number of potential 

changes in energy markets—most notably, technology. Substantial productivity 

improvements and other technological advances are assumed for the fossil fuel 

supply sectors, in accordance with recent historical trends, accounting in part 

for the decline of coal prices and the relatively modest increases in oil and 

natural gas prices in the projections. The projections also incorporate all new 

and advanced energy-consuming and generating technologies that are 

assumed with a reasonable degree of confidence to be available by 2020. As a 

result, energy intensity—the amount of energy used for each dollar of output in 

the economy—declines by an average of 1 percent a year through 2020. In 

contrast, from 1986 to 1996, energy intensity was essentially flat 

Because the future cannot be known with certainty, it is possible that any of the 

assumptions, including the availability and characteristics of technology, may 

be too optimistic or pessimistic. For that reason, AE099 includes a wide range 

of alternative cases examining the effects of variations in many key 

assumptions. 

As a policy-neutral organization, EIA does not incorporate future changes in 

energy-related legislation, regulation, or policy into its projections. Because of 

this neutrality and the "most likely" nature of the energy trends, the reference 

case projections provide a solid baseline against which a variety of alternative 

policies and assumptions can be analyzed and evaluated. One example of the 

analytical work performed by EIA relative to its reference projections over the 

past several years is the recent report, Impacts of the Kyoto Protocol on U.S. 

Energy Markets and Economic Activity, prepared at the request of the U.S. 

House of Representatives Committee on Science. Other recent work includes: 

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Annual Energy uutiook lyyy Page 3 of 3 

• Analysis of S. 687, the Electric System Public Benefits Protection Act of 

1997, at the request of Senator James M. Jeffords 

• An Analysis ofFERC's Final Environmental Impact Statement for 

Electricity Open Access and Recovery of Stranded Costs, also at the 

request of Senator Jeffords 

• The Impacts on U.S. Energy Markets and the Economy of Reducing Oil 

Imports, for the U.S. General Accounting Office 

• Analysis of Carbon Stabilization Cases, for the U.S. Department of 

Energy, Office of Policy and International Affairs 

• The Impacts of Increased Diesel Penetration in the Transportation 

Sector, for the U.S. Department of Energy, Office of Energy Efficiency 

and Renewable Energy. 

Jay E. Hakes 

Administrator 

Energy Information Administration 

If you would like to received any information relating to any of our reports via e-mail, click on the link labeled 

"Projections ListServ" to Join by entering your e-mail address. 

File last modified: September 9,1999 

URL: http://www.eia.doe.gov/oiaf/aeo99/homepage.html 

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P.5 

Annual Energy Uutlook 1 y99 - Overview Page 1 of6 

Report Contents 

[Report*: DOE/EIA-0383 

(99)] 

> Preface 

Overview 

Key Issues 

A major issue in energy markets today is carbon emissions. Because the Kyoto 

Protocol has not been ratified by the United States and no specific policies for 

carbon reduction have been enacted, such policies are not included in the 

Annual Energy Outlook 1999 {AE099), although the Protocol and ElA's recent 

analysis of its potential impacts are discussed. 

" Administrator's 

Message 

• Overview 

* Legislation & 

Regulations 

• Issues in Focus 

• Market Trends 

" Forecast 

Comparisons 

Economic developments in Asia over the past 18 months have weakened 

worldwide oil demand and lowered world oil prices—a trend that is likely to 

continue for several years and, therefore, is included in the AE099 analysis of 

oil markets and prices. 

As in AE098, the projections in AE099 reflect ongoing changes in the financial 

structure of the U.S. electricity industry and cost reductions that are becoming 

evident with increased competition. A transition to retail competitive pricing is 

assumed in five regions—California, New York, New England, the Mid-Atlantic 

Area Council (Pennsylvania, Delaware, New Jersey, and Maryland), and the 

Mid-America Interconnected Network (Illinois and parts of Wisconsin and 

Missouri). Provisions of the California legislation on stranded cost recovery and 

price caps are also included. In the other regions, stranded cost recovery is 

assumed to be phased out by 2008. No national renewable portfolio standard 

has been passed, but State standards and other programs intended to 

encourage renewables are included as enacted. The new standards for control 

of nitrogen oxide (NOx) emissions by electricity generators are also 

incorporated. 

Prices 

• Major Assumptions 

for the Forecasts 

• Model Results 

(Appendix Tables) 

• Download Report 

• Acronyms 

• Contacts 

Although average world crude oil prices in AE099 are similar to those in 

AE098 by 2020, the projected prices over the next several years are much 

lower (Figure 1). In 2020, the average crude oil price is projected to be $22.73 a 

barrel (in 1997 dollars), compared with $22.78 a barrel in AE098. With the 

economic downturn in many Asian nations and lower expected growth in world 

oil demand, world oil prices are expected to remain low over the next several 

years—as much as about $5.50 a barrel lower than last year's projections in 

2000. 

Figure 1. Fuel price projections. 1997-2020: AEQ98 and AEQ99 compared 

(1997 dollars) [sources] 

After the start of the next decade, world oil demand is expected to rebound. 

Worldwide demand for oil is projected to reach 114.7 million barrels a day in 

2020, only slightly lower than the AE098 projection of 116.6 million barrels a 

day. 

" Feedback 

Related Links 

• Assumptions to the 

AE099 

Through 2020, the relatively low growth of prices even as the demand for oil 

increases reflects continued optimism about the potential growth of production 

in both the Organization of Petroleum Exporting Countries (OPEC) and the nonOPEC nations. Although not increasing as rapidly as in AE098, OPEC oil 

production is expected to reach 58.8 million barrels a day in 2020, nearly 

double the 29.9 million barrels a day in 1997, assuming sufficient capital to 

expand production capacity. Once sanctions are lifted, Iraqi oil production is 

expected to reach 2.5 million barrels a day within 2 years and about 5 million 

barrels a day within a decade. Outside the Persian Gulf, expansion of 

production in the offshore regions of Nigeria and Algeria and in Venezuela 

should make a significant contribution to OPEC production. 

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Annual tnergy uutlook 19yy - Overview Page 2 of6 

' Interactive Data 

Queries to 

the AE099 

• Supplemental Data 

to the AE099 

' NEMS Conference 

• To Forecasting 

Home Page 

• EIA Homepage 

Non-OPEC oil production is expected to increase more rapidly in AE099, 

reaching 55.6 million barrels a day in 2020, compared with 50.4 million barrels a 

day in AE098. Contributing to the growth are a near doubling of production in 

the former Soviet Union by 2020 (primarily in the Caspian Sea oil fields), new 

fields in the North Sea, and increases in the offshore regions of West Africa. 

Mexican oil production will continue to expand, and the rest of Latin America is 

projected to increase production by more than 50 percent, particularly in Brazil 

and Colombia. Lower OPEC production and higher non-OPEC production than 

in AE098 mean that OPEC does not dominate the world oil market until later in 

the forecast and reaches a market share of only 51 percent, compared with 57 

percent in AE098. 

The average wellhead price of natural gas is projected to increase from $2.23 

per thousand cubic feet in 1997 to $2.68 per thousand cubic feet in 2020, an 

average annual growth rate of 0.8 percent. Continued technological 

improvements in the exploration and production of natural gas moderate the 

price increase even as demand grows rapidly. In 2020, the price is higher than 

the $2.59 projected in AE098, primarily because of a lower assessment of the 

recoverable resource base. Average delivered prices decline between 1997 and 

2020 as a result of efficiency improvements in transmission and distribution; 

however, margins are as much as $0.20 to $0.30 per thousand cubic feet higher 

in AE099 than in AE098 in the 2000 to 2010 period, because recent data 

indicate fewer pipeline and distribution cost reductions than previously 

assumed. 

In AE099, the average minemouth price of coal is projected to decline from 

$18.14 per ton in 1997 to $12.74 per ton in 2020, as a result of increasing 

productivity in the industry, more production from lower-cost western mines, 

and competitive pressures on labor costs. Slightly lower production and higher 

productivity, as noted in recent data, lead to a price that is lower than the 

$13.55 in AE098. 

Average electricity prices decline from 6.9 cents per kilowatthour in 1997 to 5.6 

cents per kilowatthour in 2020, the same as in AE098. The restructuring of the 

electricity industry contributes to declining prices throughout the Nation through 

lower operating and maintenance costs, lower administrative costs, and other 

cost reductions. Federal Energy Regulatory Commission actions on open 

access and other regulatory initiatives for competitive markets enacted by some 

State public utility commissions are included in the projections, as are 

renewable portfolio standards and other mandates that have been passed in 

some States. Legislative actions affecting the electricity industry are discussed 

in the "Legislation and Regulations" section of this report, and electricity pricing 

is discussed in "Issues in Focus." 

Consumption 

Total U.S. energy consumption is projected to increase from 94.0 to 119.9 

quadrillion British thermal units (Btu) between 1997 and 2020, an average 

annual increase of 1.1 percent. In 2020, consumption is slightly higher than the 

118.6 quadrillion Btu projected in AE098, with higher commercial, industrial, 

and transportation demand partially offset by lower residential demand. 

Consumption in the residential and commercial sectors is projected to increase 

at average rates of 0.8 and 0.7 percent a year, respectively, led by growth for a 

variety of equipment—telecommunications, computers, and other appliances. 

Residential demand is lower than in AE098—22.9 quadrillion Btu in 2020, 

compared with 23.2 quadrillion Btu, because more efficient building shells in 

new construction offset higher growth in the housing stock. In the commercial 

sector, data from the Commercial Buildings Energy Consumption Survey 1995 

indicate less floorspace but higher energy intensities for some end uses. 

Commercial demand is projected to be 18.1 quadrillion Btu in 2020, 0.6 

quadrillion Btu higher than in AE098, primarily because of higher demand for 

natural gas and electricity. 

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Annual Energy Outlook 1999 - Overview 

Demand in the industrial sector increases at an average of 0.8 percent a year 

and is about 0.6 quadrillion Btu higher in 2020 than in AE098. More rapid 

efficiency improvement in some manufacturing sectors is offset by higher 

energy intensity indicated by the Manufacturing Energy Consumption Survey 

1994. Because the economic downturn in Asia affects the market for U.S. 

exports, manufacturing output and industrial demand are significantly lower 

than in AE098 over the next 10 years, rebounding later in the projections. 

Transportation demand grows on average by 1.7 percent a year and is 0.4 

quadrillion Btu higher in 2020 than in AE098. The introduction of direct-injection 

engines and other advanced automotive technologies improves the efficiency of 

light-duty vehicles, but the improvement is more than offset by higher travel, 

resulting from higher projected personal income. Recent data indicate higher 

load factors and efficiency for aircraft, which are offset by more air travel. 

Freight requirements for both rail and trucks are also higher, primarily because 

of the higher economic growth projected in AE099. 

AE099, like earlier AEOs, incorporates efficiency standards for new energyusing equipment in buildings and for motors mandated by the National 

Appliance Energy Conservation Act of 1987 and the Energy Policy Act of 1992. 

Several alternative cases examine the impact of technology on the projections 

by assuming more and less rapid improvement of energy-efficient technologies 

in the end-use sectors relative to that projected in the reference case. 

Natural gas consumption increases by an average of 1.7 percent a year (Figure 

2). Demand increases in all sectors, but the most rapid growth is for electricity 

generation, which is projected to increase from 3.3 to 9.2 trillion cubic feet 

between 1997 to 2020, excluding cogenerators. Total gas consumption is only 

0.1 trillion cubic feet higher than in AE098 in 2020, with higher demand in the 

commercial and industrial sectors offset by lower demand in the residential and 

electricity generation sectors. 

Figure 2. Energy consumption by fuel, 1970-2020 (quadrillion Btu) [sources] 

Coal consumption increases from 1,030 to 1,275 million tons between 1997 and 

2020, an average annual increase of 0.9 percent. About 90 percent of the coal 

use is for electricity generation, and coal remains the primary fuel for 

generation, although its share of generation declines by 2020. Coal demand in 

2020 is 18 million tons higher than in AE098 because of higher projected 

demand for electricity generation. 

Petroleum demand is projected to grow at an average rate of 1.2 percent a year 

through 2020, led by continued growth for transportation, which accounts for 

about 70 percent of petroleum use in 2020. Increases in travel more than offset 

efficiency increases, and higher economic growth increases freight and 

shipping, and thus petroleum use, through 2020. Compared with AE098, total 

transportation energy demand is slightly higher, with higher projected 

efficiencies for new automobiles and aircraft more than offset by higher travel 

and freight requirements. 

Renewable fuel consumption, including ethanol used for blending in gasoline, 

increases at an average rate of 0.8 percent a year through 2020. About 60 

percent of renewables are used for electricity generation and the rest for 

dispersed heating and cooling, industrial uses, and fuel blending. In 2020, 

renewables are 0.7 quadrillion Btu higher than in AE098, with higher demand 

for electricity generation, industrial uses, and ethanol blending. 

Electricity demand is projected to grow by 1.4 percent a year through 2020. 

^Efficiency gains in the use of electricitypartially offset the growth of new 

electricity-using equipment. Electricity demand is only slightly higher than in 

AE098, because an increase in commercial demand, resulting from more rapid 

growth of office equipment, computers, and other appliances is offset by a 

decrease in industrial demand from efficiency improvements in some 

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Annual Energy Outlook 1999 - Overview Page 4 of 6 

manufacturing industries. 

Energy Intensity 

Energy intensity, measured as energy use per dollar of gross domestic product 

(GDP), has declined since 1970, particularly when energy prices have risen 

rapidly (Figure 3). Between 1970 and 1986, energy intensity declined at an 

average rate of 2.3 percent a year as the economy shifted to less energyintensive industries and more efficient technologies. With moderate price 

increases and the growth of more energy-intensive industries, intensity 

improvements were flat between 1986 and 1996. From 1997 to 2020, intensity 

is projected to improve at an average rate of 1.0 percent a year as efficiency 

gains and structural shifts in the economy offset growth in demand for energy 

services. 

Energy use per person also declined from 1970 through the mid-1980s, then 

increased as energy prices dropped. Per capita energy use is expected to 

remain stable through 2020 and below the high in the early 1970s, as efficiency 

gains offset higher demand for energy services. 

Figure 3. Energy use per capita and per dollar of gross domestic product. 1970-

2020 (index. 1970 = 1) [sources] 

Electricity Generation 

Electricity generation from nuclear power declines significantly over the 

projection period (Figure 4). Of the 99 gigawatts of nuclear capacity available in 

1997, 50 gigawatts are retired, and no new plants are constructed by 2020. 

Nuclear plant retirements are based on analyses of operating costs and the 

costs of life extension compared with the cost of new generating capacity. As a 

result, some plants are retired before the end of their 40-year operating 

licenses. 

Figure 4. Electricity generation by fuel. 1970-2020 (billion kilowatthours) 

f sources] 

Generation from both natural gas and coal is projected to increase through 

2020 to meet growing demand for electricity and offset the decline in nuclear 

power. Coal prices are lower than in AE098, leading to slightly higher coal 

generation, but the share of coal generation declines by 2020 because 

assumptions about electricity industry restructuring favor the construction of 

less capital-intensive and more efficient natural gas generation technologies. 

The naturalgas generation share increases from 14 percent to 33 percent 

between 1997 and 2020. The new NOx standards lead to the installation of 

control technologies at many, plants, with annualized costs of $2 billion, 

compared with $200 billion in annual electricity expenditures. 

Renewable generation, including cogenerators, increases by 0.5 percent a year 

and in 2020 is 11 percent higher than in AE098. Renewable technologies 

penetrate slowly because of the relatively modest increase in natural gas prices 

and the decrease in coal prices. In addition, electricity restructuring tends to 

favor natural gas over coal and baseload renewable technologies. State 

renewable portfolio standards, where enacted, and other programs to 

encourage the development of renewable technologies contnbute to the growth 

of renewable generation. 

Compared with AE098, lower resource costs in the AE099 projections result in 

more biomass generation, and higher capacity factors for hydroelectric and 

-geothermal facilities lead-to higher generation from those technologies. 

Hydropower, currently the largest renewable resource used for generation, 

declines slightly through 2020. Its growth is limited by high capital costs, lack of 

available new sites, reduced Federal investment, and declining public support. 

Generation from other renewable sources— municipal solid waste, solar, and 

wind—increases to levels similar to those in AE098 in 2020. 

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Annual Energy Outlook 1999 - Overview Page 5 of 6 

Production and Imports 

U.S. crude oil production declines at an average rate of 1.1 percent a year 

between 1997 and 2020 to a projected level of 5.0 million barrels a day. 

Advances in oil exploration and production technologies do not offset declining 

resources. Projected oil prices in AE099 are similar to those in AE098 in 2020, 

but are significantly lower earlier in the projection period. Higher domestic oil 

reserves, as indicated by recent data, offset the impact of lower oil prices. 

Production is similar to or higher than that in AE098 through most of the 

forecast. In 2020, the projected production is essentially the same as in AE098. 

Total petroleum production (Figure 5) is shored up by production of natural gas 

plant liquids, which partially offsets the decline in crude oil production. 

Declining production and rising demand lead to increasing petroleum imports 

through 2020 (Figure 6). The share of petroleum consumption met by net 

imports rises from 49 percent in 1997 to 65 percent however, the share is 

higher earlier in the projection period because of lower domestic production. 

Figure 5. Energy production by fuel. 1970-2020 (quadrillion Btu) rsourcesl 

Figure 6. Net energy imports by fuel, 1970-2020 (quadrillion Btu) [sources] 

In AE099, natural gas production is projected to increase from 18.9 trillion cubic 

feet in 1997 to 27.4 trillion cubic feet in 2020, an average rate of 1.6 percent a 

year, to meet most of the rising domestic demand for natural gas. Additional 

supplies of natural gas are provided by imports. Net imports of natural gas, 

primarily from Canada, increase from 2.8 to 5.0 trillion cubic feet between 1997 

and 2020. It is assumed that pipeline capacity from Canada will increase to 

accommodate imports of competitively priced Canadian gas. 

Coal production grows from 1,099 million tons in 1997 to 1,358 million tons in 

2020, an average increase of 0.9 percent a year, to meet rising domestic and 

export demand. Most steam coal exports serve markets for electricity 

generation in Europe and Asia. Metallurgical coal exports to Europe and Asia 

decline. Export demand is lower than in AE098 by 35 million tons because of 

environmental concerns and economic problems in some countries. Because 

lower export demand is only partially offset by higher domestic demand, coal 

production in 2020 is 18 million tons lower than the AE098 projection. 

Total renewable energy production is projected to increase from 6.8 to 8.2 

quadrillion Btu between 1997 and 2020—an average annual increase of 0.8 

percent—with growth in electricity generation from geothermal, biomass, and 

municipal solid waste generation and in industrial biomass and ethanol use. 

Renewable energy production in 2020 is 0.4 quadrillion Btu higher than in 

AE098. More renewables are used for electricity generation, cogeneration, and 

ethanol blending, and AE099 incorporates ethanol production from cellulose 

beginning in 2001, which was not included in AE098. 

Carbon Emissions 

Carbon emissions from energy use are projected to increase by an average of 

1.3 percent a year through 2020, from 1,480 million metric tons in 1997 to 1,790 

million metric tons in 2010 and 1,975 million metric tons in 2020 (Figure 7), due 

to rising energy demand, declining nuclear power, and slow growth of 

renewables. Relative to the 1990 level of 1,346 million metric tons, emissions 

are 33 and 47 percent higher, respectively, in 2010 and 2020. Projected 

emissions in 2020 are higher by 19 million metric tons than in AE098, due to 

-higher energy demand and higher, levelsof-coakfired electricity generation. 

Figure 7. U.S. carbon emissions by sector and fuel. 1990-2020 (million metric 

tons) fsources] 

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Annual Energy Outlook 1999 - Overview Page 6 of 6 

The Climate Change Action Plan (CCAP) was developed to stabilize 

greenhouse gas emissions in 2000 at 1990 levels. AE099 includes CCAP 

provisions, but no new carbon reduction policies are incorporated. Carbon 

emissions and the Kyoto Protocol are discussed in "Issues in Focus." 

Table 1. Summary of results for five cases [sources] 

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File last modified: May 3,1999 

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Page 1 of 1 

8-

6-

4-

3-

AE099 

AE09S 

Average electricity 

(cents per kilowatthour) 

Crude oil 

(dollarsper barrel) 

1997 

3-

3010 3030 

AE09S 

"AE098 

Natumlgas wellhead 

(dollars per thousand cubic feet) 

1997 

35-

30- ( 

15-

10-

5-

3010 3030 

AE098 

AE09S 

Coal minemouth 

(dollars per short ton) 

1997 3010 3030 1997 3010 3020 

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/-viuiuai energy WUUUUK iyyy - issues in focus Page 1 of24 

Issues in Focus 

Report Contents 

The Economic Decline in East Asia 

[Report#:DOE/EIA-0383 

' " " Recent Developments 

>

 Preface 

• Administrator's 

Message 

' Overview 

• Legislation & 

Regulations 

• Issues in Focus 

' Market Trends 

Although this Annual Energy Outlook 1999 (AE099) focuses on the 

determinants of growth for the United States in a midterm (20-year) setting, it is 

also important to consider how near-term events may play out over the long run. 

The recent economic crisis in East Asia illustrates the need to reconcile 

volatility in the short run with the long-run determinants of growth for the world 

and the U.S. economy. 

The economic crisis in East Asia began in the summer of 1997 and continued to 

deepen throughout 1998. Currency markets in Southeast Asia became 

extremely volatile, with Thailand, Malaysia, and Indonesia experiencing sharp 

depreciations first, followed by the Philippines and South Korea. Between the 

end of May 1997 and September 1998, the U.S. dollar rose by 67 percent 

against the Thai baht, nearly 53 percent against the Malaysian ringgit, and more 

than 61 percent against the South Korean won. For most of the East Asian 

countries, however, the exchange rate fluctuations occurred between August 

1997 and the end of March 1998, with currency values relatively stable during 

the summer of 1998 (although at much higher levels against the dollar than in 

January 1997). Indonesia's currency did continue to show volatility, as the 

country tried to accommodate increased financing needs for both economic 

investment and social costs. 

' Forecast 

Comparisons 

" Major Assumptions 

for the Forecasts 

" Model Results 

(Appendix Tables) 

" Download Report 

" Acronyms 

• Contacts 

" Feedback 

n _i_.i-._ J i i_i. _ 

The Asian economies affected by the crisis share many characteristics: 

relatively rapid economic growth over the past 3 to 6 years; high domestic 

savings rates; economic expansion sustained by exports rather than domestic 

demand growth; high current account deficits; high inflows of foreign capital 

before the currencies became volatile; and relatively lax financial regulations. 

Early in 1997 their currencies were pegged to the U.S. dollar, and they became 

overvalued when the countries experienced large current account trade deficits. 

In addition, credit was allocated in their financial sectors on non-business 

criteria, and excessive investments were made in real estate, leading to 

inefficient uses of the available capital. When the exchange rates rose loans 

could not be repaid, foreign portfolio capital fled, and Asian firms found it 

difficult to finance needed imports of essential intermediate products. 

Current events have exposed significant vulnerabilities in Asian and other 

developing economies, raising questions about the timing and extent of shortand long-term recovery. Developing economies need to devote much of their 

economic resources to improving infrastructure (education, transportation, and 

communication as well as energy resources) and tend to rely on international 

capital flows to finance much of their investment. But international capital flows, 

especially portfolio investment, are volatile and may have substantial impacts 

on short-term growth. Whether long-run growth is also affected depends on the 

reasons for the financial instability, the underlying economic characteristics of 

the country (such as the skill of the labor force), the domestic savings rate, the 

prospects for traded goods in global competition, and the infrastructure that 

supports the economy. 

In Thailand, Indonesia, and South Korea, the International Monetary Fund (IMF) 

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Annual energy outlook lyyy - Issues in hocus Page 2 of24 

ftt?!3Le{J L1.IKS 

" Assumptions to the 

AE099 

" Interactive Data 

Queries to 

the AE099 

' Supplemental Data 

to the AE099 

' NEMS Conference 

' To Forecasting 

Home Page 

• EIA Homepage 

has agreed to supply capital in exchange for agreement to a set of fiscal and 

monetary policies designed to reduce volatility in financial markets. The policies 

are aimed at decreasing government expenditures, removing some government 

controls over the financial sector, allowing insolvent financial institutions and 

businesses to fail, and allowing more foreign ownership to encourage foreign 

direct investment. The short-run impacts of such policies are likely to be higher 

inflation, lower imports, and reductions in sectors of the economy that are 

sensitive to interest rates (such as construction and investment). One result is 

projected lower economic growth for the next several years. 

The Asian recession is proving to be more severe than anticipated last year 

when AE098 was being prepared. At that time, most analysts thought that the 

Asian crisis would follow the course of the Mexican crisis of 1994, when the 

Mexican economy saw a severe drop in GDP growth in 1995 (6.2 percent), 

followed by positive growth (5.2 percent) in 1996. 

A number of factors have contributed to a deeper recession in Asia than 

originally expected. First, with import demand plunging in many Asian countries, 

intraregional trade, which fueled growth in the early 1990s, has collapsed. The 

Japanese economy— weak at the beginning of the Asian crisis—has not yet 

recovered. In contrast, during Mexico's rapid economic recovery after its 1994 

currency crisis, its main trading partner, the United States, was experiencing 

strong economic growth. Second, high interest rates and weak currencies have 

made it difficult for Asian countries to obtain financing for essential intermediate 

inputs. Without the necessary inputs, many export products cannot be 

produced. Finally, with the collapse of many Asian countries and the absence of 

a Japanese recovery, world export demand has not been sufficient to offset the 

drop in intra-Asian trade. Domestic demand in the Asian countries must recover 

before the intraregional trade can resume its impetus for growth. 

High interest rates, prescribed by the IMF, were expected to cut wasteful 

spending while attracting more capital to the East Asia region. In fact, however, 

investors have been unwilling to channel their money to countries where there 

is a risk of further currency devaluations. Tighter credit has substantially 

reduced domestic demand in the affected countries, but the region's exchange 

rates are still volatile. 

Whether the sharp currency devaluations in East Asia will lead to lower growth 

rates over the next 25 years will depend in large part on the policies enacted in 

response to short-run developments. If the financial reforms enacted make 

financial transactions more transparent, then market conditions will judge the 

efficacy of new investments. Making investment decisions more market-driven 

could lead to potentially higher long-run economic growth, especially given the 

relatively high education levels and savings rates of the labor force. 

Impacts on the World Oil Market 

Over the past 2 years, crude oil prices have dropped by more than 40 percent, 

reflecting a significant world oil surplus. Abundant supply and weak worldwide 

demand, especially among the struggling economies of the Pacific Rim, have 

combined to produce the lowest world oil prices since the early 1970s. 

The timing and magnitude of an expected rebound in demand for oil and in 

world oil prices are the source of much uncertainty in AE099. The reference 

case forecast assumes that real prices for oil rise at an annual rate of almost 6 

percent from 1999 to 2007. After 2007, the reference case oil prices are similar 

to those in the Annual Energy Outlook 1998 (AE098), rising at an annual rate of 

less than 1 percent (Figure 8). Developments that could contribute to delaying 

the return until 2007, as opposed to a more rapid rebound, include the following. 

Figure 8. World oil price projections in the AE098 and AEQ99 reference cases, 

1990-2020 

(1997 dollars per barrel) fsources] 

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Annual Energy Outlook 1999 - Issues in Focus Page 3 of 24 

The Organization of Petroleum Exporting Countries (OPEC) has agreed on 

production cutbacks of about 2.6 million barrels a day in 1998 to counter the 

slow growth in world oil demand and the drop in oil prices. There is much 

skepticism, however, as to whether member nations will strictly adhere to such 

quotas. Prior excursions into quota-setting have resulted in temporary impacts 

on world oil prices, but cutbacks have been difficult to maintain and verify over 

the long term. Many OPEC countries are almost totally dependent on oil export 

revenues for their national income, and production cutbacks are especially 

painful. An additional factor of critical importance to OPEC supply potential is 

the reemergence of Iraq as an oil exporter. The United Nations Security Council 

has agreed to allow Iraq to export oil (for humanitarian reasons) at a rate of 1.6 

million barrels a day. When Iraqi export sanctions are eventually lifted 

(assumed to be after 2000 in the reference case), Iraq could easily expand its 

production capacity to more than 3 million barrels a day by 2005. In addition, 

several non-Persian Gulf OPEC members (Algeria, Nigeria, and Venezuela) 

have active plans to expand their production capacities over the next half-dozen 

years. 

Non-OPEC production potential continues to grow despite the low price 

environment. North Sea production is expected to peak by the middle of 

the next decade at levels that are at least 1 million barrels a day greater than 

current output. Other countries within the Organization for Economic 

Cooperation and Development (OECD) that are expected to register production 

increases within the next decade include Australia, Canada, and Mexico. In 

Latin America, Argentina, Brazil, and Colombia are showing accelerated growth 

in oil production due in part to privatization efforts. Deepwater projects off the 

coast of western Africa and in the South China Sea are not expected to be 

delayed and will start producing significant volumes early in the next century. 

Because subsea oil platforms have to be scheduled so far in advance, most of 

the worldwide deepwater projects are proceeding on schedule even at today's 

prices. 

The bleak economic outlook for several Southeast Asian economies has 

significantly dampened the growth in oil demand for the region, which in recent 

years has accounted for about one-half of the growth in Asia's oil demand. In 

1998 demand is expected to decline, and the timing of its recovery has become 

increasingly uncertain. Other regions whose near-term GDP growth is less 

optimistic than that assumed in AE098 include China, the Former Soviet Union, 

and Japan. Even with lower oil prices, near-term oil demand is expected to 

increase at only about half the rate of the past 5 years (Figure 9). 

Figure 9. Oil demand projections for developing Asia in AEQ98 and AEQ99. 

1990-2020 

(million barrels per day) fsources] 

Impacts on the Demand for U.S. Exports 

In the near term, export demand for U.S. goods and services will suffer as world 

activity slows in response to these near-term volatile events (Figure 10). After 

expansive growth from 1995 through 1997, averaging over 11 percent a year, 

the growth in demand for U.S. exports slowed to less than 1 percent in 1998 

and is expected to average less than 4 percent from 1998 through 2000. Export 

demand is expected to rebound by the year 2000 and sustain a growth rate of 8 

percent a year from 2001 through 2003. 

Figure 10. Projected annual growth in real U.S. exports. 1995-2003 (percent) 

[sources] 

Because only a relatively small portion of U.S. exports goes to those countries 

where current economic disruptions are greatest, current Asian events are not 

expected to have as lasting an effect on the U.S. economy as on the world oil 

market. Nonetheless, compared with AE098, slower growth in exports is 

expected from 1997 through 2010 in the AE099 reference case. The expected 

reduction in export demand is expected to reduce real GDP growth by as much 

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annual energy UUUOOK iyyy - issues in hocus Page 4 of 24 

as a tenth of a percentage point. The relatively lower growth in exports in the 

first 10 years of the forecast results in slower growth in domestic U.S. 

manufacturing relative to last year's expectations. Manufactured goods are 

affected more by export and import trends in the economy than are either 

services or wholesale and retail trade. As exports recover, so does the growth 

rate of manufactured output. 

Responding to Growth in Demand for Natural Gas 

In the AE099 reference case projections, natural gas consumption in 2020 is 

nearly 50 percent higher than the 1997 level of 22.0 trillion cubic feet. In order to 

satisfy the demand projected for 2020, a number of changes will be needed in 

the U.S. natural gas industry, including a significant increase in production and 

considerable expansion of infrastructure. Onshore and offshore production are 

projected to increase by 57 and 14 percent, respectively, and pipeline capacity 

to increase by 32 percent over 1997 levels. Although today's market differs from 

the markets that existed in past periods of significant growth, increases well 

above those projected in AE099 have been realized in the past and the 

industry's past performance gives reason for confidence that the projected 

increases can be accommodated. 

Interregional pipeline capacity increased by 6.9 trillion cubic feet (21 percent) 

over the 7-year period from 1990 (the first year EIA began compiling capacity 

data) to 1997. The driving force behind the expansion was not to meet an 

overall increase in demand perse—the 1997 market of 22.0 trillion cubic feet is 

roughly equivalent in size to the 1972 historical peak of 22.1 trillion cubic feet— 

but instead to provide new access corridors as supply and demand centers 

shifted in a changing market. Similarly, the need for additional pipeline capacity 

projected in AE099 primarily reflects the demand for greater customer access 

to new and expanding supply sources and for supplemental capacity into areas 

of growing demand where peak period utilization is approaching maximum 

available capacity. 

As an example, proposed additional capacity from Canada will bring 

significantly greater volumes of gas to the midwestem marketplace. At the 

same time, several existing pipelines already have the capacity to move large 

volumes of gas from the South Central region to the same area. As capacity 

expansion projects proceed over the next several years, there is a strong 

potential for surplus supply to develop in the Chicago area. As a result, 

pipelines exiting the South Central region that compete with Canadian gas 

could become underutilized. To alleviate the situation, and to address the 

growing demand for natural gas in the Northeast, a number of projects have 

been proposed that would tap into the expanding Chicago hub and redirect 

some of its supplies eastward. 

Much of the new capacity that has been added since 1990 or is to be completed 

by 2000 consists of long-haul pipelines from growing supply areas. By 2000, 

much of the projected new capacity will be able to link with nearby major longhaul pipelines already in operation, so that the primary short-term requirements 

will be for feeder lines to tap into the existing pipelines or compression and 

looping along existing routes where capacity needs to be augmented. 

Compression and looping are much less expensive than laying pipe along new 

routes and usually require less lead time. 

Much of the expansion projected in AE099 before 2001 already is either under 

construction or planned, and more than half the pipeline expansion expected by 

2020 is likely to occur between now and 2000. A number of projects have been 

proposed (although not all of them will actually be built), and substantial 

investment has been made in pipeline expansion. The added capacity will 

provide access to new and expanding production areas, such as Canada and 

the deep offshore, and will accommodate shifts in demand patterns, such as 

new demand for natural gas to replace electricity generation capacity lost as a 

result of nuclear retirements. 

Government policy supports an optimistic outlook for the post-2000 pipeline 

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Annual Energy Outlook 1999 - Issues in Focus Page 5 of 24 

expansion forecast. FERC policy allows the pipelines to assume more risk 

rather than requiring firm contracts to be in place before approving an 

expansion, and the Council on Environmental Quality has recently allocated 

funding to promote interagency cooperation in the review of pipeline permits, 

with the primary intention of speeding up the process. The FERC has 

responded positively to issues raised by the pipeline industry regarding its 

method of determining allowed rates of return by evaluating possible changes in 

the method it uses to calculate returns. Pipelines have claimed that they face 

considerable risk because of increased competition and the threat of capacity 

turnback, and that the 12- to 13-percent average rate of return for pipelines in 

1996 was far lower than the 20-percent rate earned by most public companies 

[17]. 

Another issue that the industry will face in meeting the production forecast is 

supply availability. Uncertainty in estimates of the Nation's natural gas 

resources, both onshore and offshore, has always been an issue in projecting 

production [18\. Despite the fact that offshore production levels in the AE099 

forecast do not exceed current levels until 2003^- suggesting that offshore 

production will not be a problem—there are a number of potential problems 

related to the recovery of natural gas from offshore areas. 

One issue is a potential shortage of offshore rigs and skilled personnel. 

Although the short-term situation has changed with the recent downturn in oil 

prices, every available offshore rig was in use throughout 1997, and the 

construction of new rigs has been limited by uncertainty surrounding their 

demand for the longer term. The lead time for construction of new rigs is 2 to 3 

years, and costs range from $115 million for a 350-foot jack up to $325 million 

for a deepwater semisubmersible [19\. Training is needed to develop a work 

force for offshore production, and because of its cyclical history many people 

are reluctant to enter this work force. 

An additional issue is the need for infrastructure expansion. Infrastructure to 

move natural gas from offshore drilling platforms to the shore will need to 

expand as production grows, and gathering systems for offshore production, the 

costs of which are not known with certainty, need to be developed. Despite the 

problems these issues may present, however, continuing developments in 

offshore technology have improved the prospects for offshore gas production. 

Although there have been some spending cutbacks as a result of current low oil 

prices, investments are being made in all these areas, and technology 

advances are cutting lead times and improving the economics of smaller fields. 

Because of expected growth in natural gas demand, several studies are being 

undertaken to assess what steps the natural gas industry needs to take to 

be able to respond. Former Secretary of Energy Federico Pefta commissioned 

the National Petroleum Council (NPC) to undertake a study of what is needed 

for the industry to be able to respond to demand increases. In addition, the 

Natural Gas Supply Association (NGSA) is working on a report that will analyze 

whether the industry can meet increased demand projections without increasing 

wellhead prices, and the Interstate Natural Gas Association of America 

(INGAA) is working on a study to determine what needs to be done for the 

pipeline industry to meet the needs of a market of 30 trillion cubic feet by 2010 

(2 trillion cubic feet above the AE099 forecast). The key uncertainties 

in satisfying a market of that size are where the demand will occur and whether 

there is enough pipeline capacity to move the gas into growing demand centers. 

The INGAA study addresses the question of whether the pipeline industry can 

provide the expanded infrastructure needed to get the gas to market. One of the 

problems with rapid expansions is the lead time necessary for a pipeline 

project. Barring unforeseen delays, capacity expansion requires a lead time of 

2.5 to 3 years. If an environmental impact statement is required, it can add 

another 3 months to the completion time \20\. 

The pipeline capacity expansion currently underway reflects the industry's 

anticipation of an expanding market Positive steps are also being taken in 

other parts of the industry. Again, despite recent cutbacks resulting from low oil 

prices, investments still are being made in exploration and production, and they 

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Annual Energy Outlook 1999 - Issues in Focus Page 6 of 24 

are expected to continue, largely independent of lower oil prices, as higher gas 

prices provide a positive incentive for investment. In fact, spending on natural 

gas projects increased in the first quarter of 1998 and was unchanged in the 

second quarter \21}. 

The rising levels of demand and prices for natural gas projected in AE099 will 

provide additional economic incentives for the investments in infrastructure, 

rigs, drilling, and manpower development needed to meet the necessary 

increases in gas production. As a result, it is expected that the natural gas 

industry will be in a position to meet the challenge of satisfying the demand 

increases projected. 

Renewable Portfolio Standards 

Federal legislation proposed by Senator Jeffords, Senator Bumpers, and 

Congressman Schaefer include renewable portfolio standard (RPS) provisions 

that are similar to those included in State restructuring plans. Each of the 

Federal bills proposes a renewable credit system as described in "Legislation 

and Regulations". The key differences in the respective RPS'provisions are the 

required renewable share and the renewable technologies that would receive 

credits. The share required by 2020 varies from 4 percent in H.R. 655 

(Schaefer) to 20 percent in S. 687 (Jeffords). Each of the bills allows all 

nonhydroelectric renewable resources to receive credits. S! 237 (Bumpers) also 

provides partial credits to large hydroelectric facilities, greater than 80 

megawatts. 

In March 1998, the Clinton Administration released its Comprehensive 

Electricity Competition Plan [221 and 'n June 1998 the Secretary of Energy 

submitted the Administration's proposed legislation to implement the plan. 

Section 302 of the proposed Comprehensive Electricity Competition Act [231 

calls for the establishment of a Federal RPS. Beginning in 2000, each retail 

electricity supplier would be required to submit to the Secretary of Energy 

renewable energy credits in an amount equal to the required percentage. 

Credits would be earned for each kilowatthour generated from solar, wind, 

geothermal, or biomass plants. The proposed percentage reaches 5.5 percent 

in 2010 and remains there through 2015. Between 2000 and 2010 the required 

percentage is to be determined by the Secretary of Energy, but it would be less 

than 5.5 percent. The following analysis illustrates the potential effects of the 

proposed RPS. For purposes of the analysis, it is assumed that the required 

share would grow linearly from 0 to 5.5 percent between 2000 and 2010 and 

remain at 5.5 percent through 2015, at which time the requirement would be 

eliminated [24\. 

The RPS would have an impact on the types of plants built to meet the growing 

demand for electricity. New wind and biomass plants, and geothermal to a 

lesser extent are expected to make key contributions in meeting the RPS 

(Figure 11). In the reference case, only 9 gigawatts of new renewable plants are 

expected tp be built, because in most situations they are not competitive with 

fossil alternatives. Under the proposed Federal RPS, however, renewable 

technologies would play a larger role. In the Federal RPS sensitivity case, more 

new wind plants are expected to be built in some regions of the country, 

particularly in the Northwest, Southwest, and Upper Midwest 

Figure 11. Renewable electricity generation in two cases, 2020 (billion 

kilowatthours) [sources] 

The United States has vast wind resources in some areas, but many are in 

regions of low demand, and there is some uncertainty about the costs of 

developing them and delivering their power. For example, some of the best 

wind resources are located far from transmission lines and load centers, in 

environmentally sensitive areas, or on terrain that it is not suitable for 

economical construction. 

In terms of biomass, there are significant supplies of relatively low-cost biomass 

that, for the most part, are not currently being used for energy production. The 

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Annual Energy Outlook 1999 - Issues in Focus Page 7 of 24 

low cost of fossil fuels, particularly coal, makes them unattractive. For example, 

there are large amounts of urban wood waste, tree trimmings, construction and 

demolition debris, and discards such as crates and pallets that could be burned 

to produce energy, rather than disposed of in landfills. These materials can be 

burned in standalone facilities, but a less expensive alternative may be to use 

them as a secondary fuel in existing coal-fired plants. Many existing coal plants 

may be able to consume up to 5 percent of their total fuel input as biomass with 

relatively minor modifications, and even higher levels are possible with more 

significant modifications. In this analysis, coal-fired plants are permitted to meet 

up to 5 percent of their fuel needs with biomass if it is economical; however, use 

of the biomass option is limited by the projected low cost of coal. 

Although the required share for renewables is relatively low in the Federal RPS 

sensitivity case, it would nevertheless have an impact on electricity prices 

(Figure 12), which are projected to be almost 2 percent higher in 2010 and 2015 

than they are in 

Figure 12. Change in average U.S. electricity prices in the Federal RPS 

sensitivity case from the reference case. 2000-2020 (percent) [sources] 

the reference case. The impact is less in the later years because renewable 

technologies are expected to become more economical over time, with costs 

declining once they begin to penetrate the market. The price impact almost 

disappears in 2020, when the RPS has ended. The projected price differences 

are relatively small, but they do amount to an added cost to consumers. The 

annual impact varies between $1.4 billion and $3.7 billion a year between 2005 

and 2015, with the average residential electricity bill projected to be about $1 a 

month higher than in the reference case in 2010 (Figure 13). After 2015 the 

impact declines sharply. 

Figure 13. Variation from reference case national electricity costs in the Federal 

RPS sensitivity case, 2005-2020 (billion 1997 dollars) [sources] 

The imposition of the RPS would have a positive effect in reducing emissions. 

Because the new renewable facilities built to comply with the RPS would 

displace output from fossil plants, total emissions would be lower. For example, 

the 5.5 percent RPS reduces electricity sector carbon emissions by 

approximately 23 million metric tons a year between 2010 and 2020 (Figure 14). 

Emissions of nitrogen oxides (NOx) and sulfur dioxide (S02) are not significantly 

reduced, because their levels are explicitly capped, and implementing; the RPS 

would not lead to further reductions. The imposition of the RPS is projected to 

reduce slightly the incremental cost of meeting the NOx and S02 caps. 

Figure 14. Projected U.S. electricity-related carbon emissions in two cases. 

1996-2020 

(million metric tons) fsources] 

Electricity Pricing in a Competitive Environment 

Electricity markets in many parts of the United States are being restructured to 

increase competition. Competitive pressures are affecting the operations of 

electricity generators, even in areas where no formal restructuring legislation 

has been introduced. For example, operating and maintenance costs for 

existing power plants have been falling in recent years, and further reductions 

are anticipated. To reflect this trend, the AE099 reference case assumes a 25-

percent reduction in current nonfuel operating costs in all regions over the next 

10 years. Capital costs and operating efficiencies for new plants are also 

assumed to improve over time in all regions. 

Future investment decisions may also be affected by increasing competition. 

Accordingly, the AE099 reference case assumes higher costs of capital and 

shorter recovery periods. Thus, the reference case forecast incorporates many 

of the expected effects of industry restructuring in all regions, including those 

where competitive pricing legislation or other binding rules have not been 

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Annual Energy Outlook 1999 - Issues in Focus Page 8 of 24 

passed. 

Historically, prices have been set administratively as the average embedded 

costs of producing electricity, including all fuel and operating and maintenance 

costs, as well as recovery of construction costs and a regulated profit. In a 

competitive market, generation prices will vary over time (even hour to hour), 

and will be set in each time period by the operating costs of the most expensive 

plant needed to meet demand at that point in time—the "marginal cost" of 

production. The marginal cost typically includes the fuel and variable operating 

and maintenance costs for the generator. 

During periods of high demand in a competitive market, when the demand for 

electricity approaches the available generating capacity, prices might rise over 

the operating costs of the most expensive generator operating. Such occasional 

price spikes can encourage consumers to reduce their usage so that supply 

and demand are kept in balance. Similarly, prices consistently over the marginal 

operating costs will provide incentives for the construction of new generating 

capacity. 

In AE099, a full competitive pricing sensitivity case assumes that competitive 

pricing will be phased in throughout the United States over 10 years, with full 

competitive pricing based entirely on marginal costs occurring by 2008. 

Currently, marginal operating costs are generally lower than average embedded 

costs, which include the recovery of construction costs on plants that are not 

competitive in today's market. With a gradual shift to full competitive pricing, it is 

assumed that a portion of such costs will be recovered in the competitive price. 

When the uneconomical generators have either been paid for or retired, 

average costs are expected to approach, and possibly fall below, marginal 

costs. In the early years of the forecast, coal-fired units are projected to be used 

most often to set the marginal cost (Figure 15). In the later years, as demand 

increases and most new capacity is gas-fired, the projected marginal unit is 

more often a combined-cycle or turbine unit, and the marginal costs are 

dependent on gas prices. As a result, by 2020, marginal costs are projected to 

be slightly higher than average costs. 

Figure 15. Percentage of time that different plant types set national marginal 

electricity prices, 2000.2010. and 2020 (percent of total) [sources] 

It is worth noting that the areas with the highest electricity prices under 

regulation (New York, New England, and California) were among the first to 

pass legislation allowing competition between electricity suppliers. Because the 

AE099 reference case assumes marginal cost pricing for electricity generation 

in those regions that have enacted restructuring legislation, the regions that 

would expect the largest price declines as a result of competitive pricing are 

assumed to have competitive electricity prices in both the reference and full 

competitive pricing cases. (The reference case assumes a transition to 

competitive pricing in California, New York, the New England States, the MidAtlantic States, and the Mid-America Interconnected Network—Illinois and parts 

of Wisconsin and Missouri.) As a result, the projected differences in national 

average electricity prices between the two cases are relatively modest, ranging 

from 5 percent lower in 2005 to 4 percent higher in 2020 in the full competitive 

pricing case than in the reference case. In 2020, the electricity price in the full 

competitive pricing case is higher than in the reference case because of 

increasing natural gas prices, which affect marginal electricity prices more 

directly than average prices. Detailed results from the full competitive pricing 

case are presented in Appendix F. Table F9. 

The full competitive pricing case also assumes that some consumers will be 

able to respond to time-of-use pricing by altering their demand patterns. 

Through "load-shifting," consumers can reduce usage during a peak period, 

when prices are high and supply is tight, and shift that usage to an off-peak 

period. The net effect is lower peak demand and a flatter demand pattern for the 

year, with less variation between the lowest and highest points. Load shifting 

could also reduce the need for new capacity, because peak demand would be 

lower, so that different types of capacity would be built. In the full competitive 

pricing case, 28 gigawatts less new capacity is projected to be built by 2020 

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Annual Energy Outlook lyyy - Issues in Focus Page 9 of 24 

than in the reference case. Some of the difference results from lower reserve 

margins overall under full competitive pricing (reserve margins are projected to 

be as much as 3 percentage points lower nationally), but a portion is also due to 

the flatter load pattern. 

Sectoral Pricing of Electricity in Competitive Markets 

The emergence of competitive markets for generation in the electricity industry 

has created the potential for a new distribution of costs and benefits among 

classes of utility customers. Traditionally, rates were set by regulators on the 

basis of "embedded costs"—the average cost of producing electricity and 

serving the customer, including both short-run costs such as fuel and long-run 

costs such as plant and capital recovery. Because rates were set to cover all 

costs, including return on capital invested, this was referred to as "rate-ofretum 

regulation." Rates were generally set to reflect average costs rather than the 

more volatile fluctuations in marginal costs. 

Historically, given the large transaction costs associated with real-time pricing, 

average cost pricing was seen as ensuring that revenues would cover total 

costs. Because some activities or investments, such as maintenance of a 

substation, serve multiple customer classes, regulators developed various 

methods of allocating the costs to different customer classes. Typically, both 

fairness and efficiency [251 played a role in setting customer class tariffs [26]. 

The changing nature of the electric utility industry will undoubtedly modify the 

pattern of allocations of costs among customer classes, with market forces 

having a greater role. Although all customers are expected to benefit eventually 

from the introduction of competition in the generation function, the rate and 

degree of such benefits may vary by customer class. Figure 16 shows sectoral 

prices of electricity in the United Kingdom during the period 1988-1996—when 

the electricity industry was privatized and competition was introduced in the 

generation sector—indexed to 1988 prices. Profitability in the regulated market 

was allowed to rise for 2 years before the introduction of competition in 1990. 

Savings from the introduction of competition were realized more quickly by the 

larger customers first 

Figure 16. Real electricity prices in the United Kingdom after deregulation. 

1988-1996 (index. 1988 = 1.0) [sources] 

Initially only the largest customers in the United Kingdom, those with peak loads 

of more than 1 megawatt (approximately the size of 500 households), had a 

choice of suppliers. These customers were referred to as non-franchise 

customers, and they had the choice of any of the 12 Regional Electricity 

Companies (RECs), or other independent generating companies. Franchise 

customers, primarily residential and small commercial/were required to 

purchase electricity through their local RECs. The franchise threshold was 

lowered to 100 kilowatts in 1994, and all customers were to have choice of 

suppliers by the end of 1998. 

In general, over this time, small consumers have seen only modest price 

reductions. As the franchise limitations were removed, first large and then 

medium industrial customers received greater benefits, although there was a 

good deal of variation in the experience of industrial customers. Some very 

large industrial customers, participants in the "qualifying industrial customer 

scheme" (QUICS) program before privatization, initially saw price increases and 

have received relatively little benefit from the competitive market [27]. As shown 

in Figure 16, even after a transition period, it is likely that the effect of 

deregulation will vary by customer class. 

As markets are restructured, firms have incentives to change their pricing to 

meet specialized demands. An example is the U.S. natural gas market for 

transmission services, where restructuring resulted in a wider array of options 

for some customers. In particular, those customers with more flexibility in their 

transmission and distribution requirements were in a position to reduce their 

overall price of service. Those users, primarily large industrial consumers, 

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Annual Energy Outlook 1999 - Issues in Focus Page 10 of 24 

benefited most from the restructured natural gas market [28\. Figure 17 shows 

the transmission and distribution markup (the difference between the wellhead 

and end-use prices of natural gas) by sector from 1985 to 1996, indexed to 

1985. As shown, the average price of transmission and distribution for industrial 

users declined significantly more (on a percentage basis) than that for 

residential users. 

Figure 17. Index of real U.S. natural gas transmission and distribution markups 

by end-use sector. 1985-1996 (index, 1985 = 1.0) [sources] 

Traditionally, an electric utility was granted an exclusive franchise over its 

territory and served as a regulated monopoly. Because customers are easily 

identified by demand level and have different price elasticities of demand, a 

utility can charge different prices to different customers. In a regulated 

monopoly, there is no inherent requirement that prices equal long-run average 

costs. In order for the revenue requirements of the utility to be met, some price 

differentials must be established. That is, if every customer class were charged 

its incremental cost of service, a utility might not cover its total costs. Allocation 

of such costs over and above the incremental costs are decided by regulators. 

Such allocations, translated into rates, result in different prices per kilowatthour 

for different customers. Such differences are inherent in traditional rate 

development [29]. 

Given the traditional market structure of a regulated monopoly, efficiency 

considerations encourage the adoption of a pricing approach whereby classes 

of customers with inelastic demands pay a higher markup over marginal cost 

than those with more elastic demands __[. However, the goal of equity leads 

policymakers to set prices that are seen as fair and reasonable. This goal can 

lead regulators to deviate from the economically optimal pricing methodology so 

as to avoid imposing "unreasonably" high prices on groups with inelastic 

demands. Thus, regulated sectoral pricing deviates from economically optimal 

pricing, because both equity and efficiency are important in setting rates. 

Figure 18 compares actual prices of electricity by customer class in 1996 with 

an estimate of what such prices would look like if the costs were allocated in an 

economically optimal (market-based) manner. The results indicate that current 

industrial and commercial prices are largely higher and current residential 

prices are lower than the prices associated with the economically optimal 

solution. Significant changes may occur when there is a restructured electricity 

generation market. Figure 19 compares the generation price by customer class 

in the full competition case, in which generation is assumed to be priced on a 

marginal cost basis. It is also assumed that, through the function of an 

independent system operator (ISO) or other market structure, the generation 

component of price at any one time will be equal for all customers. That is, the 

difference between the average yearly price of the generation component of 

electricity for different customer classes depends only on the fraction of annual 

electricity requirements purchased during high-priced periods. With these 

assumptions, the average annual generation prices are nearly equal for the 

different customer classes. 

Figure 18. Actual 1997 electricity prices by sector and calculated prices with 

optimal pricing (1997 mills per kilowatthour) [sources] 

Figure 19. Generation component of electricity prices by end-use sector. 1999-

2020 

(1997 mills per kilowatthour) [sources] 

The reason that sectoral generation prices are nearly equivalent is illustrated by 

the representative price-duration curve shown in Figure 20, depicting the 

ranked hourly price of electricity from the most expensive to the least expensive 

hour. The key feature of the graph is that the price-duration curve is relatively 

flat on a per-kilowatthour basis. A flat curve shows that, except for a limited 

number of peak hours, the price of generating electricity is relatively constant. 

Therefore, in a fully competitive market, the generation price is similar for all 

customer classes. 

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Figure 20. Electricity generation price duration curve for the New England 

region (1997 mills per kilowatthour) [sources] 

Although both transmission and distribution are assumed to be regulated, there 

is reason to believe that the unbundling of generation from transmission and 

distribution may provide medium and large consumers with a greater ability to 

obtain price concessions from the operator of the distribution system. 

Specifically, under the new market structure, some consumers may have the 

ability to bypass the distribution system at relatively low cost by connecting 

directly to the transmission system or building an on-site generator. 

Concessionary pricing, i.e., changes in the allocation of fixed costs among the 

customer classes, may be necessary to retain such customers. 

Figure 21 compares the industrial price in the reference case with that in the 

fully competitive case, including concessionary pricing of transmission and 

distribution. As a counterpoint, another projection is shown, based on the 

assumption that industrial customers would be unable to obtain any additional 

concessions from the operators of the transmission and distribution system (no 

concessionary pricing). If average generation prices by customer class tend to 

converge, it is possible that industrial prices could rise significantly above the 

reference case price without reallocation of costs within the regulated 

transmission and distribution sector. Prices would be modestly higher than 

those in the reference case if such reallocation occurred. 

Figure 21. U.S. industrial electricity prices under three fixed cost allocation 

options. 1999-2020 (1997 mills per kilowatthour) fsourcesl 

Figure 22 compares national sectoral prices in the fully competitive market case 

with those in the reference case. Given that similar efficiency improvements are 

assumed in the reference and full competition cases, it is not surprising that the 

price paths are similar. However, this analysis assumes that, if pricing is 

nondiscriminatory in the generation market, larger customers will nonetheless 

maintain their ability to achieve lower rates through market pressures on the 

remaining regulated portions of the industry. 

Figure 22. U.S. electricity prices by end-use sector in the reference and full 

competition cases. 1999-2020 (1997 mills per kilowatthour) fsourcesl 

Although the approach toward analyzing sectoral prices represents an advance 

over previous EIA analyses, a great deal of uncertainty remains. Clearly, the 

precise market structures that evolve will have a significant effect on pnce, as 

will the extent and speed at which new technologies, as well as market forces, 

influence the ratemaking process. Moreover, the validity of these projections 

depends on the consistency between ElA's assumptions about market 

structures and their actual performance. Finally, any assumptions about 

regulators' behavior are subject to changes in the overall regulatory 

environment. 

Gasoline Sulfur Reduction 

In early 1999, the U.S. Environmental Protection Agency (EPA) is expected to 

propose tighter restrictions on the amount of sulfur allowed in gasoline. 

Because gasoline sulfur and automotive emissions are linked, the proposal will 

be issued in conjunction with the new "Tier 2" vehicle exhaust emissions 

standards that would take effect between model years 2004 and 2007 (see 

"Legislation and Regulations,"). Sulfur reduces the effectiveness of the catalyst 

used in the emissions control systems of advanced technology engines, 

increasing their emissions of hydrocarbons, carbon monoxide, and NOx. As a 

result, gasoline with significantly reduced sulfur levels will be required for the 

control systems to work property and meet the new Tier 2 standards. 

The EPA has been considering lowering the average annual sulfur content of 

gasoline to between 150 and 30 parts per million (ppm), from the existing 

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standard of 1,000 ppm. The current national average gasoline sulfur content is 

340 ppm [37]. The existing limit for all gasoline in California is an annual 

average of 30 ppm, with a cap of 80 ppm, or a flat (unaveraged) limit of 40 ppm. 

Discussions of California-like sulfur limits may be framed in terms of a "30 ppm" 

or a "40 ppm" limit, but for all intents and purposes, the two are the same. 

A joint study by the EPA and the U.S. Department of Energy (DOE) put 

preliminary sulfur reduction costs for East Coast and Gulf Coast refiners at 5.1 

to 8.0 cents a gallon for 40 ppm gasoline and 1.1 to 1.8 cents a gallon for 150 

ppm gasoline. A study sponsored by the American Automobile Manufacturers 

Association estimated the cost of reducing sulfur to 40 ppm at 5.5 cents a 

gallon for refiners in the eastern half of the country. Another study sponsored by 

the American Petroleum Institute (API) estimated the costs of sulfur reduction at 

5.1 cents a gallon for 40 ppm gasoline and 2.7 cents a gallon for 150 ppm 

gasoline [32\. 

Although there is a broad consensus that gasoline sulfur must be reduced, the 

level of reduction and the application of the requirement have been intensely 

debated. In addition to determining the appropriate sulfur level, the EPA is 

considering whether to make sulfur reduction a national or regional 

requirement. The range of sulfur reduction options under consideration by the 

EPA is bounded by proposals from two groups: automakers—the American 

Automobile Manufacturers Association and the Association of International 

Automobile Manufacturers—and gasoline producers—the American Petroleum 

Institute (API) and the National Petrochemical and Refiners Association 

(NPRA). AE099 includes the two proposals as alternative cases to explore their 

potential impacts on the long-term projections of gasoline supply and prices. 

The automakers propose to reduce the average allowable sulfur content of 

gasoline in the United States to 40 ppm, which is equivalent to the current 

standard in the State of California. The API/NPRA submitted a less stringent 

regional proposal in which all gasoline in Federal reformulated gasoline'areas, 

in 23 States, and in East Texas would meet an annual average of 150 ppm [33\; 

gasoline in California would continue to meet the State's gasoline requirements, 

including the 40 ppm annual average sulfur limit; and gasoline in all other parts 

of the country would have an annual average of 300 ppm. API/NPRA proposes 

further sulfur reductions by 2010 in areas that require year-round NOx control. 

The areas of coverage and the level of sulfur reductions would be determined 

by an EPA study. In the API/NPRA analysis case, all the areas required to use 

150 ppm gasoline in 2004 were assumed to require further reductions to 40 

ppm by 2010. 

As expected, the price impact is greater in the case based on the automakers' 

proposal (which is a more severe, nationwide plan) than in the API/NPRA case. 

Both cases assume that the additional costs associated with sulfur reductions 

would be passed on to consumers. Relative to the AE099 reference case, the 

API/NPRA scenario increases the average price of gasoline by 1.3 cents a 

gallon in 2004 and by 4.9 cents a gallon in 2010. The automakers' scenario 

increases the price by 8.3 cents a gallon in 2004 and 6.8 cents in 2010. The 

API/NPRA scenario increases total consumer spending for gasoline by $1.8 

billion in 2004 relative to the AE099 reference case and by $7.6 billion in 2010. 

In the automakers' scenario, the corresponding increases are $11.7 billion in 

2004 and $10.5 billion in 2010. In both cases, the price increases reflect 

investments in sulfur reduction processes at refineries, as well as changes in 

the selection of refinery inputs. 

Before 2010, the cost of sulfur reduction is lower in the API/NPRA scenario 

because sulfur reduction to the 300 and 150 ppm levels can be achieved largely 

by adjustments in refinery processes. On the other hand, sulfur reduction to the 

40 ppm level, reflected in the automakers' scenario and after 2010 in the 

API/NPRA scenario, can only be achieved by more costly refinery upgrades, 

including naphtha hydrotreating, gas oil desulfurization, alkylation, and 

hydrogen units. 

An interesting feature of both scenarios is that they lead to a projected increase 

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Annual Energy Outlook 1999 - Issues in Focus Page 13 of 24 

in domestic production of gasoline and blending components relative to the 

reference case projections, with a corresponding reduction in projected imports. 

On the other hand, the reductions in imports of gasoline and blending 

components are more than offset by increased requirements for crude oil 

imports. The net result is that imports represent the same share of total 

projected petroleum requirements in the API/NPRA scenario as in the AE099 

reference case and a slightly higher percentage in the automakers' scenario. 

The Kyoto Protocol and Carbon Emissions 

Greenhouse Gas Emissions and the Framework Convention 

The greenhouse effect is a natural process by which some of the radiant heat 

from the sun is captured in the lower atmosphere of the Earth, thus maintaining 

the temperature of the Earth's surface. The gases that help capture the heat, 

called "greenhouse gases," include water vapor, carbon dioxide, methane, 

nitrous oxide, and a variety of manufactured chemicals. Some are emitted from 

natural sources; others result from anthropogenic, or human, activities. Over the 

past several decades, rising concentrations of greenhouse gases have been 

detected in the Earth's atmosphere, and it has been suggested that this may 

lead to an increase in the average temperature of the Earth's surface and 

consequently to detrimental effects. 

In 1988, the Intergovernmental Panel on Climate Change (IPCC) was 

established by the World Meteorological Organization and the United Nations 

Environment Programme to assess the scientific, technical, and socioeconomic 

information in the field of climate change. The most recent report of the IPCC 

concluded that: "Our ability to quantify the human influence on global climate is 

currently limited because the expected signal is still emerging from the noise of 

natural variability, and because there are uncertainties in key factors. These 

include the magnitude and patterns of long term natural variability and the timeevolving pattern of forcing by, and response to, changes in concentrations of 

greenhouse gases and aerosols, and land surface changes. Nevertheless, the 

balance of evidence suggests that there is a discernible human influence on 

global climate" [34]. 

Following a series of negotiating sessions, the text of the Framework 

Convention on Climate Change was adopted at the United Nations on May 9, 

1992, and opened for signature at Rio de Janeiro, Brazil, on June 4. The 

objective of the Framework Convention was to"... achieve... stabilization of 

the greenhouse gas concentrations in the atmosphere at a level that would 

prevent dangerous anthropogenic interference with the climate system." The 

signatories agreed to formulate programs to mitigate climate change. 

Furthermore, the developed country signatories agreed to adopt national 

policies to return anthropogenic emissions of greenhouse gases to their 1990 

levels. The Convention excludes chlorofluorocarbons (CFCs) and 

hydrochlorofluorocarbons (HCFCs), greenhouse gases that are deemed to 

cause damage to the Earth's stratospheric ozone and are controlled by the 

1987 Montreal Protocol on Substances that Deplete the Ozone Layer. 

Responding to the Framework Convention, on April 21,1993, President Clinton 

called upon the United States to stabilize greenhouse gas emissions by 2000 at 

1990 levels. Specific steps to achieve U.S. stabilization were enumerated in the 

Climate Change Action Plan (CCAP) [35L published in October 1993, which 

consists of a series of 44 actions to reduce greenhouse gas emissions. These 

actions include voluntary programs, industry partnerships, 

government incentives, research and development regulatory programs, 

including energy efficiency standards, and forestry actions. Greenhouse gases 

affected by these actions include carbon dioxide, methane, nitrous oxide, 

hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). At the time CCAP 

was developed, the Administration estimated that the actions in CCAP would 

reduce the total net emissions [36[ of these greenhouse gases to 1990 levels by 

2000. 

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In addition to the climate-related actions of CCAP, the Energy Policy Act of 

1992 (EPACT), Section 1605(a), provided for an annual inventory of U.S. 

greenhouse gas emissions, which is contained in the EIA publication series, 

Emissions of Greenhouse Gases in the United States [37J. Also, Section 1605 

(b) of EPACT established the Voluntary Reporting Program, permitting 

corporations, government agencies, households, and voluntary organizations to 

report to EIA on actions that have reduced or avoided emissions of greenhouse 

gases. The results of the Voluntary Reporting Program are reported annually by 

EIA, most recently in Mitigating Greenhouse Gas Emissions: Voluntary 

Reporting 1996 [38\. Entities providing data to the Voluntary Reporting Program 

include some participants in government-sponsored voluntary programs, such 

as the Climate Wise and Climate Challenge programs, which are cosponsored 

by the EPA and DOE to foster reductions in greenhouse gas emissions by 

industry and electricity generators. 

The Kyoto Protocol 

The Framework Convention established the Conference of the Parties to 

"review the implementation of the Convention and ... make, within its mandate, 

the decisions necessary to promote the effective implementation." The first and 

second Conference of the Parties in 1995 and 1996 agreed to address the 

issue of greenhouse gas emissions for the period beyond 2000 and negotiate 

quantified emission limitations and reductions for the third Conference of the 

Parties. On December 1 through 11,1997, representatives from more than 160 

countries met in Kyoto, Japan, to negotiate binding limits for greenhouse gas 

emissions for developed nations. In the resulting Kyoto Protocol, emissions 

targets were established for these nations, the Annex I countries [39J, relative to 

their emissions in 1990, to achieve an overall reduction of about 5.2 percent 

[40]-

The individual targets for the Annex I countries range from an 8-percent 

reduction for the European Union (EU) (or its individual member states) to a 10-

percent increase allowed for Iceland. Australia and Norway are also allowed 

increases of 8 and 1 percent respectively, while New Zealand, the Russian 

Federation, and the Ukraine are held to their 1990 levels. Other Eastern 

European countries undergoing transition to a market economy have reduction 

targets of between 5 and 8 percent The reduction targets for Canada and 

Japan are 6 percent and for the United States 7 percent Non-Annex I countries 

have no targets under the Protocol, although the Protocol reaffirms the 

commitments of the Framework Convention by all parties to formulate and 

implement climate change mitigation and adaptation programs. 

The greenhouse gases covered by the Protocol are carbon dioxide, methane, 

nitrous oxide, hydrofiuorocarbons, perfluorocarbons, and sulfur hexafiuoride 

[41]. The aggregate target is established using the carbon dioxide equivalent of 

each of the greenhouse gases. For the three synthetic greenhouse gases, 

countries have the option of using 1995 as the base year. Sources of emissions 

include energy combustion, fugitive emissions from fuels, industrial processes, 

solvents, agriculture, and waste management and disposal. The Protocol does 

not prescribe specific actions to be taken but lists a number of potential actions, 

including energy efficiency improvements, enhancement of carbon-absorbing 

sinks, such as forests and other vegetation, research and development of 

sequestration technologies, phasing out of fiscal incentives and subsidies that 

may inhibit the goal of emissions reductions, and reduction of methane 

emissions in waste management and in energy production, distribution, and 

transportation. 

The targets must be achieved on average over the commitment period 2008 to 

2012, the first commitment period. Each country can average its emissions over 

that 5-year period to establish compliance, smoothing out short-term 

fluctuations that might occur due to economic cycles or extreme weather 

patterns. Countries must have made demonstrable progress by 2005, but no 

targets are established for the period after 2012 (although lower targets may be 

set by future Conferences of the Parties). Banking—carrying over of unused 

allowances from one commitment period to the next—is allowed; however, the 

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borrowing of emissions allowances from a future commitment period is not 

permitted. 

Several provisions of the Protocol allow for some flexibility in meeting the 

emissions targets. Net changes in emissions by direct anthropogenic land-use 

changes and forestry activities will also be used in meeting the commitment; 

however, they are limited to afforestation, reforestation, and deforestation since 

1990. Emissions trading among the Annex I countries is permitted. According to 

ElA's International Energy Outlook 1998 (IEQ98) [42], the amount of carbon 

that may be available for trade from the Annex I countries of the former Soviet 

Union as a result of the economic decline in those countries in the 1990s is 

estimated at 165 million metric tons in 2010. Also, additional carbon permits 

may be available. Joint implementation projects are allowed among the Annex I 

countries, allowing a nation to take emissions credits for projects that reduce 

emissions or enhance emissions-absorbing sinks, such as forests and other 

vegetation, in other Annex I countries. It is specifically indicated that trading and 

joint implementation are supplemental to domestic actions. 

The Protocol also establishes a Clean Development Mechanism (CDM), under 

which Annex I countries can earn credits for projects that reduce emissions in 

non-Annex I countries provided that the projects lead to measurable, long-term 

benefits. Reductions from such projects undertaken from 2000 until the first 

commitment period can be used to assist with compliance in the first 

commitment period. This provision calls for the establishment of an executive 

board to oversee the projects. In addition, an unspecified share of the proceeds 

from the project activities must be used to cover administrative expenses and to 

assist with adaptation in countries that are particularly vulnerable to climate 

change. 

Annex I countries, such as the EU, may create a bubble or umbrella to meet the 

total commitment of all the member nations. In a bubble, countries agree to 

meet the total commitment jointly by allocating a share to each member. In an 

umbrella arrangement, the total reduction of all member nations is met 

collectively through the trading of emissions rights. There is potential interest in 

the United States entering into an umbrella trading arrangement. 

The Protocol became open for signature on March 16,1998, for a one-year 

period. It enters into force 90 days following the acceptance by 55 Parties, 

including Annex I countries accounting for at least 55 percent of the 1990 

carbon dioxide emissions from Annex I nations. Signature by the United States 

would need to be followed by Senate ratification. As of September 29,1998, 57 

countries had signed the Protocol, including 26 Annex I nations that accounted 

for about 38 percent of Annex I carbon emissions in 1990. 

In 1990, total greenhouse gas emissions in the United States were 1,633 million 

metric tons carbon equivalent. Of this total, 1,346 million metric tons, or 82 

percent, was due to carbon emissions from the combustion of energy fuels. By 

1997, total U.S. greenhouse gas emissions had risen to 1,791 million metric 

tons carbon equivalent, of which 83 percent or 1,480 million metric tons, were 

carbon emissions from energy combustion. EIA now projects that energyrelated carbon emissions will reach 1,790 million metric tons in 2010, 33 

percent above the 1990 level, increasing to 1,975 million metric tons in 2020. 

Because energy-related carbon emissions constitute such a large percentage of 

the total greenhouse gas emissions, any action or policy to reduce emissions 

will affect U.S. energy markets; however, there are a number of factors outside 

the domestic energy market that influence emissions and may offset the 

impacts on domestic energy. 

To put U.S. emissions in a global perspective, the United States produced 

about 24 percent of the worldwide energy-related carbon emissions in 1996, 

which totaled 6.0 billion metric tons, according to IE098. Although carbon 

emissions continue to increase in the United States and other industrialized 

countries, they are increasing at a much more rapid rate in the developing 

countries of Asia, the Middle East, Africa, and Central and South America. As a 

result, global carbon emissions from energy are expected to increase at an 

average annual rate of 2.4 percent from 1996 through 2010, reaching 8.3 billion 

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metric tons, to which the United States is expected to contribute about 22 

percent. 

EIA Analysis of the Kyoto Protocol 

At the request of the U.S. House of Representatives Committee on Science, 

EIA performed an analysis of the Kyoto Protocol in the summer of 1998, 

focusing on the impacts of the Protocol on U.S. energy prices, energy use, and 

the economy in the 2008 to 2012 time frame. The analysis was published in 

Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity 

[43]. The request specified that the analysis use the same methodologies and 

assumptions as the AE098 [44], with no changes in policy, regulatory actions, 

or funding for energy and environmental programs. The Committee indicated 

that no new nuclear plants should be allowed, although economic life 

extensions of nuclear plants should be permitted. Construction of new nuclear 

plants, variations in economic growth, and different assumptions concerning 

technology characteristics were all to be analyzed as sensitivities to the target 

cases. 

The EIA analysis assumes that the Government would hold an auction of 

carbon permits. The cost of the permits is reflected in energy prices, and the 

revenues collected from the permits are recycled either to individuals by means 

of an income tax rebate or to individuals and businesses through a social 

security tax rebate. 

The Protocol includes a number of international provisions, including 

international emissions trading, joint implementation projects, and CDM, which 

may reduce the cost of compliance; however, guidelines for the provisions must 

be resolved at future meetings of the Conferences of the Parties. (The fourth 

Conference was underway in Buenos Aires, Argentina, at the time AE099 went 

to press.) In addition, rules and guidelines forthe accounting of emissions and 

sinks from activities related to agriculture, land use, and forestry activities must 

be developed. The specific guidelines may have a significant impact on the 

level of reductions from other sources that a country must undertake. 

Reductions in the other greenhouse gases may also offset the reductions 

required from carbon dioxide. A fact sheet issued by the U.S. Department of 

State on January 15,1998, discussing the Protocol, estimated that the method 

of accounting for sinks and the flexibility to use 1995 as the base year for the 

synthetic greenhouse gases may reduce the U.S. target for energy-related 

carbon emissions to 3 percent below 1990 levels_[45L. 

Because of these uncertainties concerning the final implementation of the 

Protocol, ElA's analysis includes cases with a range of reductions for energyrelated carbon emissions within the United States in order to analyze the 

energy and economic impacts of achieving those reductions on the U.S. energy 

system and the economy. The cases assume that the reductions needed to 

meet the target of 7 percent below the 1990 emissions level that are not 

obtained from domestic energy-related reductions would come from some 

combination of forestry and agricultural sinks, offsets from other greenhouse 

gases, international trading, and other international activities. For example, the 

cases with the least stringent reductions in energy-related carbon emissions 

implicitly assume considerable international actions. 

The analysis includes six carbon emissions reduction cases, plus a reference 

case, defined as follows: 

• Reference Case (33 Percent above 1990 Levels). This case represents 

the reference projections of energy markets and carbon emissions 

without any enforced reductions, in order to compare the energy market 

impacts in the reduction cases with a reference case. Although this case 

is based on the reference case from AE098, there are small differences 

in order to permit additional flexibility in response to higher energy prices 

or to include certain analyses previously done offline directly within the 

modeling framework, such as nuclear plant life extension and generating 

plant retirements. Also, some assumptions are modified to reflect more 

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recent assessments of technological improvements and costs. As a 

result of these modifications, energy-related carbon emissions in 2010 

are slightly reduced from the AE098 reference case level of 1,803 million 

metric tons to 1,791 million metric tons. 

• 24 Percent above 1990 Levels (1990+24%). This case assumes that 

carbon emissions can increase to an average of 1,670 million metric tons 

between 2008 and 2012, 24 percent above the 1990 levels. Compared to 

the average emissions in the reference case, carbon emissions are 

reduced by an average of 122 million metric tons during the commitment 

period. 

• 14 Percent Above 1990 Levels (1990+14%). This case assumes that 

carbon emissions average 1,539 between 2008 and 2012, approximately 

at the level estimated for 1998 in AE098,1,533 million metric tons. This 

target is 14 percent above 1990 levels and represents an average annual 

reduction of 253 million metric tons from the reference case. 

• 

• 

9 Percent Above 1990 Levels (1990+9%). This case assumes that 

energy-related carbon emissions can increase to an average of 1,467 

million metric tons between 2008 and 2012, 9 percent above 1990 levels, 

an average annual reduction of 325 million metric tons from the 

reference case. 

Stabilization at 1990 Levels (1990). This case assumes that carbon 

emissions reach an average of 1,345 million metric tons during the 

commitment period of 2008 through 2012, stabilizing approximately at 

the 1990 level of 1,346 million metric tons. This is an average annual 

reduction of 447 million metric tons from the reference case. 

3 Percent Below 1990 Levels (1990-3%). This case assumes that 

energy-related carbon emissions are reduced to an average of 1,307 

million metric tons between 2008 and 2012, an average annual reduction 

of 485 million metric tons from the reference case projections. 

7 Percent Below 1990 Levels (1990-7%). Energy-related carbon 

emissions are reduced from the level of 1,346 million metric tons in 1990 

to an average of 1,250 million metric tons in the commitment period, 

2008 to 2012. Compared to the reference case, this is an average annual 

reduction of 542 million metric tons of energy-related carbon emissions 

during that period. This case essentially assumes that the 7-percent 

target in the Kyoto Protocol must be shared evenly by all emitting 

sources, with no net offsets for energy-related carbon emissions from 

sinks, other greenhouse gases, or international activities. 

In each of the carbon reduction cases, the target is achieved on average for 

each of the years in the first commitment period, 2008 through 2012 (Rgure 

23). Because the Protocol does not specify any targets beyond the first 

commitment period, the target is assumed to hold constant from 2013 through 

2020, the end of the forecast horizon, although more stringent requirements 

may be set by future Conferences of the Parties. The target is assumed to be 

phased in over a 3-year period, beginning in 2005, because the Protocol 

indicates that demonstrable progress toward reducing emissions must be 

shown by 2005. This allows energy markets to begin adjustments to meet the 

reduction targets in the absence of complete foresight. In the analysis, some 

carbon reductions occur before 2005 because of capacity expansion decisions 

by electricity generators that incorporate the future increases in energy prices. 

Figure 23. U.S. carbon emissions in seven Kyoto Protocol analysis cases. 

1990-2020 (million metric tons) fsourcesl 

There are three ways to reduce energy-related carbon emissions: reducing the 

demand for energy services, adopting more energy-efficient equipment, and 

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shifting to noncarbon or less carbon-intensive fuels. To reduce emissions, the 

price of carbon permits is applied to each of the fuels at its point of consumption 

relative to its carbon content. Electricity does not directly receive a carbon price; 

however, the fossil fuels used for generation receive the price, and this cost, as 

well as the increased cost of investment in generation plants, is reflected in the 

delivered price of electricity. 

In the analysis, the carbon prices represent the marginal cost of reducing 

carbon emissions to the specified level, reflecting the price the United States 

would be willing to pay in order to purchase carbon permits domestically. 

Because the study does not include an analysis of trade and other flexible 

mechanisms to reduce carbon emissions internationally, the carbon prices do 

not represent the international market-clearing price of carbon permits or the 

price other countries would be willing to pay for permits. 

Because of its representation of technology, NEMS captures the most 

significant factors that influence the turnover of energy-using and producing 

equipment and the choice of new technologies. Thus, it is well-suited for the 

analysis of the transitional impacts of policies designed to influence the 

choice of energy-consuming technologies, as new equipment is needed to meet 

growing demand for energy services or to replace retired equipment. Many 

sectors of NEMS include explicit treatment of individual technologies and their 

characteristics, such as initial cost, operating cost, date of commercial 

availability, efficiency, and other characteristics specific to the sector. Higher 

energy prices induce more rapid adoption of more efficient or advanced 

technologies because consumers have more incentive to purchase them. In 

addition, for new generating technologies, the electricity sector accounts for 

technological optimism in the capital costs of first-of-a-kind plants; and several 

sectors, including the generation sector, account for a decline in the costs as 

experience with the technologies is gained. 

Energy Market and Macroeconomic Analysis. The analysis indicates that 

significant changes in the mix of energy fuels, as well as higher energy 

efficiency and lower consumption, will be needed for the required reductions. To 

induce the changes, the price of energy will increase: Some of the most 

significant results from the analysis are as follows: 

• The cost of the Kyoto Protocol will depend on the amount of permits that 

can be purchased on the international market and on cost-effective 

projects to reduce emissions or develop carbon-absorbing sinks in other 

countries. Domestic actions to reduce other greenhouse gases covered 

by the Protocol and to develop sinks may also serve to reduce the costs. 

• The carbon price necessary to reduce U.S.' energy-related carbon 

emissions to the required level ranges from $67 to $348 per metric ton 

(1996 dollars) in 2010. In the more stringent reduction cases, the carbon 

price falls by 2020 as more efficient and lower-carbon technologies 

become economically available and penetrate later in the forecast 

horizon (Figure 24). 

Figure 24. Carbon prices in six Kyoto Protocol analysis cases. 1996-2020 (1996 

dollars per metric ton) [sources] 

• Higher energy prices and their impact on the broader U.S. economy will 

encourage consumers to reduce energy consumption by reducing the 

demand for energy services and purchasing more efficient equipment. 

However, consumption will increase later with a growing economy and 

lower carbon prices. Shifts from more to less carbon-intensive fuels also 

occur. 

• Because coal is the most carbon-intensive of the fossil fuels, the price of 

coal will rise dramatically, and coal use will be sharply curtailed, 

particularly for electricity generation. If the carbon price increases to its 

highest level, the use of coal for generation may nearly disappear by 

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Annual Energy Outlook lyyy - Issues in hocus Page 19 of 24 

2020 in the more stringent reduction cases. Shrinking domestic and 

international markets will lead to sharply reduced coal production and 

employment. 

• Coal-fired electricity generation will be replaced by generation from 

natural gas and renewables and also by the continued operation of many 

existing nuclear plants. Increases in natural gas generation will more 

than offset reductions in natural gas use by residential, commercial, and 

industrial consumers. As a result, the natural gas industry will expand 

production and distribution services (Figure 25). 

Figure 25. Projected fuel shares of U.S. energy consumption in two Kyoto 

Protocol analysis cases. 2010 (percent) [sources] 

• Renewable generation will also increase as more of the technologies 

become economical in light of higher fossil fuel prices. Renewables could 

capture as much as a 22-percent share of the generation market by 

2020, with more than half supplied by nonhydroelectric renewable 

generation in the more stringent cases. Within the energy industry, 

increased employment in the natural gas and renewables industries 

could offset some reductions in coal employment. 

• Nuclear generation's decline will slow as it becomes economical under 

higher carbon prices to extend the operating lives of existing plants 

rather than retire them. 

• Petroleum consumption will be lower than expected in the reference 

case but will likely remain above current levels. Although petroleum 

consumption is lower, the petroleum share of total energy consumption is 

higher than in the reference case, because the total is lower. The 

majority of petroleum is used for transportation, where there are limited 

economically attractive options for shifting to less carbon-intensive fuels. 

• Recycling carbon revenues back to consumers will offset some of the 

negative impacts on the economy. The economy will continue to grow; 

however, the growth in the gross domestic product (GDP) could be lower 

than reference case levels during the transition period. As carbon prices 

decline and the economy adjusts, GDP will rebound by 2020 to about the 

level it would have been in the absence of a carbon reduction program 

(Figures 26 and 27). 

• The loss in GDP, plus the funds used to purchase permits internationally, 

represents the total cost to the economy. Over the first compliance r 

period, from 2008 to 2012, the total cost ranges from an annual average 

of $77 billion (1992 dollars) to almost four times that amount, depending 

on the required carbon reductions and how the revenues are recycled to 

the economy. This is relative to a total economy of $7 trillion in 1996, 

which is expected to grow to $9.5 trillion in 2010 and $11 trillion in 2020. 

Figure 26. Annual GDP growth rates in four Kyoto Protocol analysis cases. 

2005-2010 (percent) [sources! 

Figure 27. Annual GDP growth rates in four Kyoto Protocol analysis cases. 

2005-2020 (percent) [sources] 

Sensitivity Cases. The analysis includes several sensitivity cases to examine 

factors that may affect energy demand and carbon emissions over the next 20 

years, including economic growth, the rate of improvement of technology, and 

nuclear power. With the exception of the nuclear sensitivity case, the sensitivity 

cases were analyzed relative to the 1990+9% case. Because each of the 

sensitivity cases is constrained to the same level of carbon emissions as the 

case to which it is compared, the primary impact is on the carbon price required 

to meet the emissions target. 

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Annual energy uutiook iyyy - issues in hocus Page 20 of 24 

• Macroeconomic Growth. The assumed rate of economic growth has a 

significant impact on projected energy demand and carbon emissions. 

The reference and carbon reduction cases in the analysis assume an 

average growth rate of 1.9 percent a year between 1996 and 2020, and 

higher and lower growth rates of 2.4 and 1.3 percent a year are analyzed 

as sensitivities. Higher growth results in higher manufacturing output and 

income, increasing the demand for energy services and resulting in 

higher energy demand and carbon emissions. Converse trends hold for 

the lower economic growth case. 

• Because higher growth increases energy consumption, carbon prices 

must be higher to attain a given carbon emissions target. In the high 

growth case, the carbon price in 2010 is $215 per metric ton, $52 per 

metric ton higher than the reference case carbon price of $163 per metric 

ton (Figure 28). In the low growth case, the carbon price in 2010 is $128 

per metric ton. Total energy consumption in 2010 is higher and lower by 

2.2 quadrillion Btu with higher and lower growth, relative to the 1990+9% 

case with reference economic growth. 

Figure 28. Projected carbon prices in four Kyoto Protocol sensitivity analysis 

cases. 2010 (1996 dollars per metric ton) [sources] 

• Technological Progress. High technology assumptions were developed 

by technology experts for the end-use sectors—residential, commercial, 

industrial, and transportation—considering the potential impacts of 

increased research and development for more advanced technologies 

• 

• 

The revised assumptions include earlier years of introduction, lower 

costs, high maximum market potential, and higher efficiencies than 

assumed in the reference case. For the electricity generation sector, the 

cost and efficiencies of advanced fossil-fired and renewable generating 

technologies are assumed to improve from reference case values. The 

low technology case assumes that all future equipment choices are 

made from the end-use equipment available in 1998, with building shell 

and industrial plant efficiencies frozen at 1998 levels, and no new 

advanced fossil-fired generating technologies are assumed. 

Because faster technology development makes advanced energyefficient and low-carbon technologies more economically attractive, the 

carbon prices required to meet carbon reduction levels are significantly 

reduced. Conversely, slower technology improvement requires higher 

carbon prices. With high technology assumptions, the carbon price in 

2010 is $121 per metric ton, compared to the carbon price of $163 per 

metric ton with the reference technology assumptions. With the low 

technology assumptions, the carbon price increases to $243 per metric 

ton in 2010. 

• Nuclear Power. In the reference case, nuclear generation declines 

because 52 percent of the total nuclear capacity available in 1996 is 

retired by 2020. A number of units are retired before the end of their 40-

year operating licenses, based on industry announcements and analysis 

of the age and operating costs of the units. In the carbon reduction 

cases, life extension of the plants can occur, if economical, and there is 

an increasing incentive to invest in nuclear plant refurbishment with 

higher carbon prices; however, these cases do not allow the construction 

of new nuclear power plants. A nuclear power sensitivity case examines 

the effects of allowing new plants to be constructed if they are 

economical. Because nuclear plants still are not competitive with fossil 

and renewable plants in the 1990+9% case, this sensitivity case is 

analyzed against the 1990-3% case. In addition to allowing new nuclear 

plants, the higher costs assumed in the reference case for the first few 

advanced nuclear plants are reduced in this case. 

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Annual Energy Outlook 1999 - Issues in Focus Page 21 of 24 

• Relative to the 1990-3% case, 1 gigawatt of new nuclear capacity is 

added by 2010 in the nuclear power sensitivity case, and 41 gigawatts, 

representing about 68 new plants of 600 megawatts each, are added by 

2020. Because most of the impact from the new nuclear plants comes 

after the commitment period of 2008 through 2012, there is little impact 

on carbon prices and energy markets in 2010. By 2020, however, carbon 

prices are $199 per metric ton with the assumption of new nuclear 

plants, compared to $240 per metric ton in the 1990-3% case with the 

reference nuclear assumptions. 

Carbon Emissions in AE099 

Reference Case 

In the AE099 reference case, carbon emissions from energy consumption are 

expected to reach 1,585 million metric tons in 2000,18 percent above the 1990 

level of 1,346 million metric tons. The projected emissions continue to rise to 

1,790 million metric tons in 2010 and 1,975 million metric tons in 2020, 33 

percent and 47 percent above the 1990 levels, respectively (Figure 29). Total 

emissions increase at an average annual rate of 1.3 percent between 1997 and 

2020, and per capita emissions also increase at an average rate of 0.4 percent. 

Throughout the projection period, carbon emissions rise, because continued 

economic growth and moderate increases in energy prices are expected to lead 

to increasing energy consumption. Emissions rise at a faster rate than total 

energy consumption, which increases at an average annual rate of 1.1 percent, 

for two primary reasons. First, approximately 51 percent of nuclear generating 

capacity, which is carbon free, is retired by 2020 and no new nuclear plants are 

constructed. Second, moderate increases in the price of natural gas and 

decreases in the price of coal lead to slow growth in renewables. 

In 2020, electricity generation accounts for 38 percent of all carbon emissions, 

increasing from 36 percent in 1997. The increasing share of carbon emissions 

from generation results, in part, from the 1.4-percent annual growth rate in 

electricity consumption. Of the new capacity required to meet electricity demand 

growth and to replace the loss of nuclear capacity, about 9 percent is fueled 

with coal and 88 percent with natural gas. 

Figure 29. U.S. carbon emissions by sector and fuel. 1990-2020 (million metric 

tons) [sources] 

Energy consumption and carbon emissions for transportation grow the fastest 

of all the end-use sectors because of increased travel and the slow 

improvement in fuel efficiency in the reference case. Between 1997 and 2020, 

both transportation demand and emissions grow at an average annual rate of 

1.7 percent, and in 2020 the transportation sector accounts for 35 percent of all 

carbon emissions. The average efficiency of the light-duty vehicle fleet—cars, 

light trucks, vans, and sport-utility vehicles—increases at an average annual 

rate of only 0.2 percent between 1997 and 2020. Over the same period, vehiclemiles traveled by light-duty vehicles increase by 1.6 percent a year, faster than 

the growth rate forthe over-age-16 population (0.9 percent a year). Growth in 

both air and freight travel, at average rates of 3.8 percent and 1.8 percent a 

year, also contribute to the increase in emissions from the transportation sector. 

Emissions from both the residential and commercial sectors grow by 1.2 

percent a year, contributing 19 percent and 16 percent of carbon emissions in 

2020 (including emissions from the generation of electricity used in each 

sector). Continued growth in energy service demand, particularly in electricityusing equipment and appliances, results in the emissions increases, offset 

somewhat by efficiency improvements in both sectors. Industrial sector 

emissions increase by only 0.9 percent a year through 2020 and account for 30 

percent of the emissions in 2020 (including emissions from electricity 

generation for the sector). The relatively low growth rate results from efficiency 

improvements and a shift to less energy-intensive industries. 

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Annual energy uutiooK 1 yyy - issues in hocus Page 22 of 24 

By fuel, petroleum products are the leading source of energy-related carbon 

emissions because of the continuing growth of the transportation sector, which 

is heavily dependent on petroleum. About 42 percent of all emissions, or 823 

million metric tons of the total of 1,975 million metric tons in 2020, are from 

petroleum products, and about 81 percent of the petroleum emissions are from 

transportation uses. 

Coal is the second leading source of carbon emissions at about 34 percent, or 

676 million metric tons, in 2020. Coal has the highest carbon content of all the 

fossil fuels and remains the predominant source of electricity generation. By 

2020, the share of coal-fired generation, excluding cogeneration, declines 

slightly from its 1997 level of 56 percent but still accounts for 52 percent of all 

generation. About 90 percent of coal emissions in 2020 result from electricity 

generation. 

Natural gas consumption for both electricity generation and direct end uses 

grows the fastest of all the fossil fuels—at a rate of 1.7 percent a year through 

2020. Natural gas has a relatively low carbon content relative to other fossil 

fuels (only about half that of coal), and thus carbon emissions from natural gas 

use are projected to be just 475 million metric tons in 2020, about 24 percent of 

the total. 

Macroeconomic Growth 

The assumed rate of economic growth has a strong impact on the projection of 

energy consumption and, therefore, carbon emissions. In AE099, the high 

economic growth case includes higher growth in population, the labor force, and 

labor productivity, resulting in higher industrial output, lower inflation, and lower 

interest rates. As a result, GDP increases at an average rate of 2.6 percent a 

year from 1997 to 2020, compared with a growth rate of 2.1 percent a year in 

the reference case. 

With higher macroeconomic growth, energy demand grows faster, as higher 

manufacturing output and higher income increase the demand for energy 

services. Total energy consumption in the high economic growth case is 129.4 

quadrillion Btu in 2020, compared with 119.9 quadrillion Btu in the reference 

case. As a result of the higher consumption, carbon emissions are 2,124 million 

metric tons, or 8 percent higher than the reference case level of 1,975 million 

metric tons in 2020. 

Assumptions of lower growth in population, the labor force, and labor 

productivity result in an average annual growth rate of 1.5 percent in the low 

economic growth case through 2020. With lower economic growth, energy 

consumption in 2020 is reduced from 119.9 quadrillion Btu to 110.5 quadrillion 

Btu, and carbon emissions are 1,826 million metric tons, or 8 percent, lower 

than in the reference case. 

Total energy intensity, measured as primary energy consumption per dollar of 

GDP, improves at a faster rate in the higher economic growth case, partially 

offsetting the changes in energy consumption caused by the higher growth 

assumptions. With more rapid growth in energy consumption, there is greater 

opportunity to turn over and improve the stock of energy-using technologies, 

increasing the overall efficiency of the capital stock. Aggregate energy intensity 

in the high economic growth case decreases at a rate of 1.2 percent a year from 

1997 through 2020, compared with 1.0 percent in the reference case and 0.8 

percent in tne low economic growth case. 

Technology Improvement 

The AE099 reference case includes continued improvements in technology for 

both energy consumption and production—improvements in building shell 

efficiencies for both new and existing buildings; efficiency improvements for 

new appliances and transportation vehicles; productivity improvements for coal 

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Annual Energy Outlook 1999 - Issues in Focus Page 23 of 24 

production; and improvements in the exploration and development costs, finding 

rates, and success rates for oil and gas production. As a result of continued 

improvements in the efficiency of end-use and electricity generation 

technologies, total energy intensity in the reference case declines at an average 

annual rate of 1.0 percent between 1997 and 2020. 

The projected decline in energy intensity is considerably less than that 

experienced during the 1970s and early 1980s, when energy intensity declined, 

on average, by 2.3 percent a year. Approximately half of that decline can be 

attributed to structural shifts in the economy—shifts to service industries and 

other less energy-intensive industries; however, the rest resulted from the use 

of more energy-efficient equipment. During those years there were periods of 

rapid escalation in energy prices, encouraging some of the efficiency 

improvements. Then, as energy prices moderated, the improvement in energy 

intensity moderated. Between 1986 and 1996, energy intensity was relatively 

flat 

Regulatory programs have contributed to some of the past improvements in 

energy efficiency, including the Corporate Average Fuel Economy standards for 

light-duty vehicles and standards for motors and energy-using equipment in 

buildings in the Energy Policy Act of 1992 and the National Appliance Energy 

Conservation Act of 1987. In keeping with the general practice of incorporating 

only current policy and regulations, the reference case of AE099 assumes no 

new efficiency standards. Only current standards or approved new standards 

with specified levels are included. 

Technology improvements in energy-consuming equipment could reduce 

energy consumption and energy-related carbon emissions to levels below those 

in the reference case. Conversely, slower improvements could increase both 

consumption and emissions. AE099 presents a range of alternative cases that 

vary key assumptions about technology improvement and penetration. 

In the end-use demand sectors, experts in technology engineering were 

consulted to derive high technology assumptions, considering the potential 

impacts of increased research and development for more advanced 

technologies. The revised assumptions included earlier years of introduction, 

lower costs, higher maximum market potential, and higher efficiencies than in 

the reference case, it is possible that further technology improvements could 

occur if there were a very aggressive research and development effort For the 

electricity generation sector, the cost and efficiencies of advanced fossil-fired 

generating technologies were assumed to improve from reference case values 

[47\. 

The low technology case assumes that all future equipment choices are from 

the equipment and vehicles available in 1999, with new building shell and 

industrial plant efficiencies frozen at 1999 levels. New generating technologies 

are assumed not to improve over time. Aggregate efficiencies still improve over 

the forecast period as new equipment is chosen to replace older stock and the 

capital stock expands. Also, building shell efficiencies improve with price 

increases. 

In the high technology case, with the high technology assumptions of all four 

end-use demand sectors and the electncity generation sector combined, 

aggregate energy intensity declines at an average of 1.3 percent a year from 

1997 to 2020, compared with 1.0 percent a year in the reference case (Figure 

30). In the 1999 technology case, the average decline is only 0.8 percent a year 

through 2020. Total energy consumption increases to 111.9 quadrillion Btu in 

2020 in the high technology case, compared with 119.9 quadrillion Btu in the 

reference case (Figure 31), but increases to 126.6 quadnllion Btu in the 1999 

technology case. 

Figure 30. U.S. energy intensity in three cases. 1997-2020 (thousand Btu per 

dollar GDP) [sources] 

Figure 31. U.S. energy consumption in three cases. 1997-2020 (guadrillion Btu) 

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Annual energy UUUOOK lyyy - issues in hocus hage 24 ot 24 

[sources] 

The lower energy consumption in the high technology case lowers carbon 

emissions from 1,975 million metric tons in the reference case in 2020 to 1,848 

million metric tons (Figure 32). In the 1999 technology case, emissions increase 

to 2,105 million metric tons in 2020. About 30 percent, or 38 million metric tons, 

of the reduction in carbon emissions in the high technology case compared to 

the reference case results from lower electricity demand and generation. An 

additional 51 million metric tons of the reduction, or 40 percent, results from 

shifts to more efficient or alternative-fueled vehicles in the transportation sector. 

Figure 32. U.S. carbon emissions in three cases. 1997-2020 (million metric 

tons) fsourcesl 

The high technology assumptions themselves do not guarantee acceptance and 

penetration in the market. Technologies must still be cost-effective as judged by 

the consumers, and penetration can be slowed by the relative turnover of the 

capital stock. In order to encourage more rapid penetration of advanced 

technologies, to reduce energy consumption or carbon emissions, it is likely that 

either market policies (for example, higher energy prices) or non-market 

policies (for example, new standards) may be required. 

If you would like to received any information relating to any of our reports via e-mail, click on the link labeled 

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File last modified: May 3,1999 

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Need Help Now? 

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P.36 

Annual Energy Outlook 1999 - Market Trend Page 1 of2 

Report Contents 

[Report*: DOE/EIA-0383 

(99)] 

Market Trends 

Economic 

Activity 

International 

Oil Markets 

Energy 

Demand Electricity 

Oil & 

Natural 

Gas 

Coal Emissions 

Preface 

• Administrator's 

Message 

• Overview 

" Legislation & 

Regulations 

" Issues in Focus 

" Market Trends 

• Forecast 

Comparisons 

• Major Assumptions 

for the Forecasts 

' Model Results 

(Appendix Tables) 

• Download Report 

• Acronyms 

• Contacts 

11 he projections in AE099 are not statements of what will 

happen but of what might happen, given the assumptions 

and methodologies used. The projections are business-asusual trend forecasts, given known technology, 

technological and demographic trends, and current laws 

and regulations. Thus, they provide a policy-neutral 

reference case that can be used to analyze policy 

initiatives. EIA does not propose, advocate, or speculate 

on future legislative and regulatory changes. All laws are 

assumed to remain as currently enacted; however, the 

impacts of emerging regulatory changes, when defined, 

are reflected. 

Because energy markets are complex, models are 

simplified representations of energy production and 

consumption, regulations, and producer and consumer 

behavior. Projections are highly dependent on the data, 

methodologies, model structures, 

and assumptions used in their development. Behavioral 

characteristics are indicative of real-world tendencies 

rather than representations of specific outcomes. 

Energy market projections are subject to much uncertainty. 

Many of the events that shape energy markets are random 

and cannot be anticipated, including severe weather, 

political disruptions, strikes, and technological 

breakthroughs. In addition, future developments in 

technologies, demographics, and resources cannot be 

foreseen with any degree of certainty. Many key 

uncertainties in the AE099 projections are addressed 

through alternative cases. 

EIA has endeavored to make these projections as 

objective, reliable, and useful as possible; however, they 

should serve as an adjunct to, not a substitute for, 

analytical processes in the examination of policy initiatives. 

Feedback 

Related Links 

• Assumptions to the 

AEQ99 

' Interactive Data 

Queries to 

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Annual Energy Outlook 1999 - Market Trend Page 2 of 2 

the AEQ99 

' Supplemental Data 

to the AEQ99 

* NEMS Conference 

" To Forecasting 

Home Page 

• EIA Homepage 

If you would like to received any information relating to any of our reports via e-mail, click on the link labeled 

"Projections ListServ" to Join by entering your e-mail address. 

File last modified: May 3,1999 

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Annual energy uutiooK iyyy - MarKet irend - Economic Activity & International Oil Mar.. Page 1 of 5 

Report Contents 

[Report#:DOE/EIA-0383 

(99)] 

Market Trends - Key Assumption; 

Trends in Economic Activity 

AE099 Projects Strong Growth for U.S. Gross Domestic Product 

Preface Figure 33. Average annual real growth rates of economic factors, 1997-2020 

(percent) [sources] 

• Administrator's 

Message 

" Overview 

" Legislation & 

Regulations 

• Issues in Focus 

• Market Trends 

• Forecast 

Comparisons 

" Major Assumptions 

for the Forecasts 

The output of the Nation's economy, measured by gross domestic product 

(GDP), is projected to increase by 2.1 percent a year between 1997 and 2020 

(with GDP based on 1992 chain-weighted dollars) (Figure 33), slightly higher 

than the 1.8-percent growth projected in AE098 for the same period. The 

projected growth rate for the labor force is similar to last year's forecast through 

2020; however, in the AE099 projection, productivity growth is 1.3 percent a 

year, up from 1.1 percent a year in AE098. 

The projected rate of growth in GDP slows in the latter half of the forecast 

period as the expansion of the labor force slows, but increases in labor 

productivity moderate the effects of lower labor force growth. Total population 

growth remains fairly constant after 2000; the slowing growth in the size of the 

labor force results instead from the increasing size of the population over 65 

years old after 2000. As more people retire from the work force, and as life 

expectancy rises, the labor force participation rate (labor force divided by adult 

population) declines. Thus, from 2010 to 2015, labor force growth slows to 0.5 

percent, and from 2015 to 2020 it falls to 0.3 percent a year. Labor force 

productivity growth, however, remains above 1 percent a year throughout each 

of the 5-year periods. In addition, the labor force participation rate—the 

percentage of the population over 16 years of age actually holding or looking for 

employment—peaks in 2007 and then begins to decline as "baby boom" cohorts 

begin to retire. 

Manufacturing Production Is Expected To Grow by 2 Percent a Year 

• Model Results 

(Appendix Tables) 

• Download Report 

Acronyms 

• Contacts 

" Feedback 

The projected growth rate for manufacturing production is 2.0 percent a year, 

slightly lower than the 2.1-percent annual growth projected for the aggregate 

economy. Energy-intensive industries, however, are projected to grow more 

slowly than non-energy-intensive industries (1.2 percent and 2.3 percent annual 

growth, respectively) [48\, due in part to rising real energy prices. 

The electronic equipment and industrial machinery sectors lead the expected 

growth in manufacturing, as semiconductors and computers find broader 

applications (Figure 34). The rubber and miscellaneous plastic products sector 

is expected to grow faster than manufacturing as a whole, with plastics 

continuing to penetrate new markets as well. Higher growth is expected for the 

wholesale trade and services sectors than for the manufacturing sector, as in 

last year's forecast 

Figure 34. Sectoral composition of GDP growth. 1997-2020 (percent per year) 

fsourcesl 

Related Links Economic Growth Cases 

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" Assumptions to the 

AE099 

Interactive Data 

Queries to 

the AE099 

" Supplemental Data 

to the AE099 

• NEMS Conference 

High and Low Growth Cases Show Effects of Economic Assumptions 

To reflect the uncertainty in forecasts of economic growth, AE099 includes high 

and low economic growth cases in addition to the reference case (Figure 35). 

The high and low growth cases show the effects of alternative growth 

assumptions on energy markets. The three economic growth cases are based 

on macroeconomic forecasts prepared by DRI/ McGraw-Hill (DRI) [49\. The DRI 

forecast used in generating the AE099 reference case is the August 1998 trend 

growth scenario, adjusted to incorporate the world oil price assumptions used in 

the AE099 reference case. The AE099 high and low economic growth cases 

are based on the optimistic and pessimistic growth projections prepared by DRI 

in February 1998. With these changes incorporated, the DRI projections are 

used as the starting point for the macroeconomic forecasts in the National 

Energy Modeling System (NEMS) simulations for AE099. 

• To Forecasting 

Home Page 

Figure 35. Average annual real growth rates of economic factors in three cases. 

1997-2020 (percent) 

[sources] 

• EIA Homepage The high economic growth case incorporates higher growth rates for population, 

labor force, and labor productivity. With higher productivity gains, inflation and 

interest rates are lower than in the reference case, and economic output grows 

by 2.6 percent a year. GDP per capita grows by 1.6 percent a year, compared 

with 1.3 percent in the reference case. The low economic growth case assumes 

lower growth rates for population, labor force, and productivity, resulting in 

higher prices, higher interest rates, and lower industrial output growth. In the 

low growth case, economic output increases by 1.5 percent a year from 1997 

through 2020, and growth in GDP per capita slows to 0.9 percent a year. 

Long-Term Trend Indicates Slowing GDP Growth 

Figure 36. Annual GDP growth rate for the preceding 20 years. 1970-2020 

(percent) [sources] 

Figure 36 shows the trend in the moving 20-year annual growth rate for GDP, 

including projections for three AE099 cases. The value for each year is 

calculated as the annual growth rate over the preceding 20 years. The 20-year 

average shows major long-term trends in GDP growth by smoothing more 

volatile year-to-year changes (although the increase shown for 2000-2002 

reflects the slow and negative growth of 1980-1982). The overall trend is 

downward, reflecting lower rates of capital accumulation during the 1970s and 

1980s, lower labor force growth rates, and shifts in the demographic makeup of 

the population. In addition, annual GDP growth has fluctuated considerably 

around the trend. The high and low growth cases capture the potential for 

different paths of long-term output growth. 

One reason for the variability of the forecasts is the composition of economic 

output, reflected by growth rates of consumption and investment relative to the 

overall GDP growth for the aggregate economy. In the reference case, 

consumption grows by 2.3 percent a year, while investment grows at a robust 

3.0 percent. In the high growth case, growth in investment increases to 3.8 

percent a year. Higher investment rates lead to faster capital accumulation and 

higher productivity gains, which, coupled with higher labor force growth, yield 

faster aggregate economic growth than in the reference case. In the low growth 

case, annual growth in investment expenditures slows to 2.1 percent. With the 

labor force also growing more slowly, aggregate economic growth slows 

considerably. 

International Oil Markets 

Gradually Rising Oil Prices Are Projected 

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Just as the historical record shows substantial variability in world oil prices, 

there is considerable uncertainty about future prices. Three AE099 cases with 

different price paths allow an assessment of alternative views on the course of 

future oil prices (Figure 37). For the reference case, prices rise by about 0.9 

percent a year, reaching $22.73 in constant 1997 dollars in 2020. In nominal 

dollars, the reference case price exceeds $43 in 2020. The low price case has 

prices rising, after the current price slump, to $14.57 by 2005 and remaining at 

about that level out to 2020. The high price case has a price rise of about 2.5 

percent a year out to 2015 and then remains at $29.35 out to 2020. The leveling 

off at about $29.35 in the high price case is due to the market penetration of 

alternative energy supplies that could become economically viable at that price. 

Figure 37. World oil prices in three cases. 1970-2020 (1997 dollars per barrel) 

[sources] 

All three price cases are similar to the price projections in AE098 beyond 2005, 

reflecting considerable optimism about the potential for worldwide petroleum 

supply, even in the face of the substantial expected increase in demand. 

Production from countries outside OPEC is expected to show a steady 

increase, reaching almost 47 million barrels per day by the turn of the century 

and increasing gradually thereafter to more than 55 million barrels per day by 

2020. 

Total worldwide demand for oil is expected to reach nearly 115 million barrels 

per day by 2020. Developing countries in Asia show the largest growth in 

demand, averaging almost 4 percent a year. 

Outlook for World Oil Supplies Is Optimistic 

Figure 38. OPEC oil production in three cases. 1970-2020 (million barrels per 

day) [sources] 

The three price cases are based on alternative assumptions about oil 

production levels in OPEC nations: higher production in the low price case and 

lower production in the high price case. With its vast store of readily accessible 

oil reserves, OPEC— primarily the Persian Gulf nations-ns expected to be the 

principal source of marginal supply to meet future incremental demand. 

By 2000, OPEC supply in the reference case is over 30 million barrels per day, 

consistent with announced plans for OPEC capacity expansion [5QI By 2020, 

OPEC production is almost 59 million barrels per day (almost twice its 1997 

production) in the reference case, over 51 million in the high case,, and over 71 

million in the low case (Figure 38). Worldwide demand for oil varies across the 

price cases in response to the price paths. Total world demand for oil ranges 

from 124.4 million barrels per day in the low price case to 109.1 in the high 

price case. 

This variation reflects uncertainty about the prospects for future production from 

the Persian Gulf region. The expansion of productive capacity will require major 

capital investments, which could depend on the availability and acceptability of 

foreign investments. Iraq is assumed to continue selling oil only at sanctionallowed volumes for the remainder of this decade. Recent discoveries offshore 

of Algeria and Nigeria as well as Venezuela's aggressive capacity expansion 

plans will more than accommodate increasing demand in the absence of Iraq's 

full return to the oil market. 

Continued Production Gains Are Seen for Non-OPEC Oil Suppliers 

Figure 39. Non-OPEC oil production in three cases. 1970-2020 (million barrels 

per day) [sources] 

The growth and diversity in non-OPEC oil supply have shown surprising 

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Annual Energy Outlook 1999 - Market Irend - Economic Activity & International Oil Mar.. Page 4 of 5 

resilience even in the low price environment of this decade. Although OPEC 

producers will certainly benefit from the projected growth in oil demand, 

significant competition is expected from non-OPEC suppliers. Countries in the 

Organization for Economic Cooperation and Development (OECD) that are 

expected to register production increases over the next decade include North 

Sea producers, Australia, Canada, and Mexico. In Latin America, Colombia, 

Brazil, and Argentina are showing accelerated growth in oil production, due in 

part to privatization efforts. Deepwater projects off the coast of western Africa 

and in the South China Sea will start producing significant volumes of oil early 

in the next century. In addition, much of the increase in non-OPEC supply over 

the next decade is expected to come from the former Soviet Union, and political 

uncertainty appears to be the only potential barrier to the development of vast 

oil resources in the Caspian Basin. 

In the AE099 reference case, non-OPEC supply is projected to reach almost 55 

million barrels per day by 2010 and remain at about that level through 2020 

(Figure 39). In the low oil price case, non-OPEC supply grows to less than 53 

million barrels per day by 2020, whereas in the high oil price case it reaches 

more than 57 million barrels per day by the end of the forecast period. 

Persian Gulf Share of World Oil Supply Increases in All the AE099 Cases 

Figure 40. Persian Gulf share of worldwide oil exports. 1965-2020 (percent) 

[sources] 

Considering the world market in oil exports, the historical peak for Persian Gulf 

exports (as a percent of world oil exports) occurred in 1974, when they made up 

more than two-thirds of the oil traded in world markets (Figure 40). The most 

recent historical low for Persian Gulf oil exports came in 1985 as a result of 

more than a decade of high oil prices, which led to significant reductions in 

worldwide petroleum consumption. Less than 40 percent of the oil traded in 

1985 came from Persian Gulf suppliers. Following the 1985 oil price collapse, 

the Persian Gulf export percentage has been steadily increasing. For the first 

time since the early 1980s, Persian Gulf producers are expected to account for 

more than 50 percent of worldwide trade. This is expected to occur before the 

end of this decade. 

In the reference case, the Persian Gulf share of total exports is expected to 

exceed 51 percent shortly after the turn of the century and gradually increase to 

over 64 percent by the year 2020. In the AE099 low oil price case, the Persian 

Gulf share of worldwide petroleum exports is expected to reach almost 52 

percent shortly after the turn of the century and steadily increase to almost 72 

percent by 2020. While all Persian Gulf producers are expected to increase 

their oil production capacity significantly over the forecast period, both Saudi 

Arabia and Iraq are expected to more than double their current production 

capacity levels. 

' Crude Oil, Light Product Imports Are Expected To Increase 

Figure 41. U.S. gross petroleum imports by source. 1997-2020 (million barrels 

per day) [sources] 

In the reference case, total U.S. gross oil imports increase from 10.2 million 

barrels per day in 1997 to 16.3 million in 2020 (Figure 41). Crude oil accounts 

for most of the increase in imports through 2000, whereas imports of petroleum 

products make up a larger share of the increase after 2000. Product imports 

increase more rapidly, as U.S. production stabilizes and U.S. refineries lack the 

capacity to process a larger quantity of imported crude oil. 

By 2010, OPEC accounts for more than 45 percent of total projected U.S. 

petroleum imports. After 2010, the OPEC share increases gradually, to more 

than 46 percent in 2020. The Persian Gulf share of U.S. imports from OPEC 

increases from about 39 percent in 1997 to almost 50 percent in 2020. Crude oil 

imports from the North Sea increase slightly through 2010, then level off as 

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Annual Energy Outlook 1999 - Market Trend - Economic Activity & International Oil Mar.. Page 5 of 5 

North Sea production ebbs. Significant imports of petroleum from Canada and 

Mexico continue, and West Coast refiners are expected to import crude oil from 

the Far East to replace the modest volumes of Alaskan crude oil that will be 

exported. 

Imports of light products are expected to more than double by 2020, to nearly 

3.0 million barrels per day. Most of the projected increase is from refiners in the 

Caribbean Basin and the Middle East, where refining capacity is expected to 

expand significantly. Vigorous growth in demand for lighter petroleum products 

in developing countries means that U.S. refiners are likely to import smaller 

volumes of light, low-sulfur crude oils. 

Refining Capacity Is Projected To Grow Worldwide 

Figure 42. Worldwide refining capacity by region. 1997 and 2020 (million barrels 

per day) fsourcesl 

Worldwide crude oil distillation capacity was 76.1 million barrels per day at the 

beginning of 1997. To meet the growth in international oil demand in the 

reference case, worldwide refining capacity is expected to increase by more 

than two-thirds—to more than 127 million barrels per day—by 2020. Substantial 

growth in distillation capacity is expected in the Middle East, Central and South 

America, and the Asia/Pacific region (Figure 42). 

The Asia/Pacific region has been the fastest growing refining center in the 

1990s. It has recently passed Western Europe as the world's second largest 

refining center and, in terms of distillation capacity, is expected to surpass the 

United States by 2010. While not adding significantly to their distillation 

capacity, refiners in the United States and Europe have tended to improve 

product quality and enhance the usefulness of heavier oils through investment 

in downstream capacity. 

Future investments in the refinery operations of developing countries must 

include configurations that are more advanced than those currently in operation. 

Their refineries will be called upon to meet increased worldwide demand for 

lighter products, to upgrade residual fuel, to supply transportation fuels with 

reduced lead, and to supply both distillate and residual fuels with decreased 

sulfur levels. An additional burden on new refineries will be the need to supply 

lighter products from crude oils whose quality is expected to deteriorate over 

the forecast period. 

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P.43 

Annual Energy Outlook 1 yyy - Market 1 rend , Energy Demand Page 1 of 11 

Market Trends - Energy Demand 

Report: Contenti 

Primary and Delivered Energy Use Show Similar Growth Rates 

[Report*: DOE/EIA-0383 

(")J Figure 43. Primary and delivered energy consumption, excluding transportation 

use. 1970-2020 (quadrillion Btu) fsourcesl 

>

 Preface 

* Administrator's 

Message 

Net energy delivered to consumers represents only a part of total primary 

energy consumption. Primary consumption includes energy losses associated 

with the generation, transmission, and distribution of electricity, which are 

allocated to the end-use sectors (residential, commercial, and industrial) in 

proportion to each sector's share of electricity use [51]. 

' Overview 

• Legislation & 

Regulations 

' Issues in Focus 

" Market Trends 

" Forecast 

Comparisons 

How energy consumption is measured has become more important over time, 

as reliance on electricity has expanded. In 1970 electricity accounted for only 

12 percent of energy delivered to the end-use sectors, excluding transportation. 

Since then, the growth in electricity use for applications such as space 

conditioning, consumer appliances, telecommunication equipment, and 

industrial machinery has resulted in greater divergence between total and 

delivered energy consumption (Figure 43). This trend is expected to stabilize 

over the forecast horizon, as more efficient generating technologies offset 

increased demand for electricity. Projected primary energy consumption and 

delivered energy consumption grow by 0.8 percent and 0.9 percent a year, 

respectively, excluding transportation use. 

At the end-use sectoral level, tracking of primary energy consumption is 

necessary to link specific policies with overall goals. Carbon emissions, for 

example, are closely correlated with total energy consumption. In the 

development of carbon stabilization policies, growth rates for primary energy 

consumption may be more important than those for delivered energy. 

• Major Assumptions 

for the Forecasts 

" Model Results 

(Appendix Tables) 

• Download Report 

• Acronyms 

• Contacts 

Projected GDP Growth Exceeds Growth in Energy Use 

Figure 44. Energy use per capita and per dollar of gross domestic product, 

1970-2020 (index, 1970 = 1) [sources] 

Energy intensity, both as measured by primary energy consumption per dollar 

of GDP and as measured on a per capita basis, declined between 1970 and the 

mid-1980s (Figure 44). While the overall GDP-based energy intensity of the 

economy is projected to continue declining between 1997 and 2020, the decline 

is not expected to be as rapid as it was in the earlier period, as a result of 

relatively stable projected energy prices and increased use of electricity-based 

energy services. As electricity claims a greater share of energy use, projected 

consumption per dollar of GDP declines at a slower rate, because electricity 

use contributes both end-use consumption and energy losses to total energy 

consumption. Between 1997 and 2020, GDP is estimated to increase by 61 

percent, compared with a 27-percent increase in primary energy use. 

• Feedback 

r» t j f • * i 

In the AE099 forecast, the demand for energy services increases markedly 

over current levels. The average home in 2020 is expected to be 4 percent 

larger and to rely more heavily on electricity-based technologies. Annual 

highway travel and air travel per capita in 2020 are expected to be 20 and 95 

percent higher, respectively, than their current levels. Growth in demand for 

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Mimuai energy UUUOOK. iyyy - iviaricet irena , Energy Demand Page 2 of 

•Keiateo ums 

" Assumptions to the 

AE099 

" Interactive Data 

Queries to 

the AEQ99 

• Supplemental Data 

to the AE099 

NEMS Conference 

• To Forecasting 

Home Page 

EIA Homepage 

energy services notwithstanding, primary energy intensity on a per capita basis 

will remain essentially static through 2020, with efficiency improvements in 

many end-use energy applications making it possible to provide higher levels of 

service without significant increases in energy use per capita. 

Transportation Petroleum Use Leads the Rise in Energy Consumption 

Figure 45. Primary energy use by fuel, 1970-2020 (guadrillion Btu) [sources] 

Petroleum products, mainly for transportation, claim the greatest share of 

primary energy consumption in the AE099 forecast (Figure 45). Growth in 

energy demand in the transportation sector, which averaged 2.0 percent a year 

during the 1970s, was diminished in the 1980s by rising fuel prices and by new 

Federal vehicle efficiency standards, which led to an unprecedented 2.1-

percent annual increase in average vehicle fuel economy. In the AE099 

forecast, fuel economy gains slow as a result of stable fuel prices and the 

absence of new legislative mandates. A growing population and increased 

travel per capita lead to increases in demand for gasoline throughout the 

forecast. 

Increased competition and technological advances in electricity generation and 

distribution are expected to reduce the real cost of electricity. Despite low 

projected prices, however, growth in electricity use is slower than the rapid 

growth seen in the 1970s. End-use demand for natural gas grows at a slightly 

slower rate than overall energy demand, in contrast to the recent trend of more 

rapid growth in the use of gas as the industry was deregulated. Natural gas is 

projected to meet 19.9 percent of all end-use energy demand requirements in 

2020. 

End-use demand for renewable energy from sources such as wood, wood 

wastes, and ethanol increases by 1.2 percent a year. The use of geothermal 

and solar thermal energy in buildings increases by about 3.6 percent a year but 

does not exceed 1 percent of energy consumption for space and water heating. 

Residential and Commercial Energy Use Is Expected To Increase 

Modestly 

Figure 46. Primary energy use by sector, 1970-2020 (guadrillion Btu) fsources] 

Primary energy use in the reference case is projected to reach 120 quadrillion 

Btu by 2020,27 percent higher than the 1997 level. In the early 1980s, as 

energy prices rose, sectoral energy consumption grew relatively little (Figure 

46). Between 1985 and 1997, however, stable energy prices contributed to a 

marked increase in sectoral energy consumption. 

In the forecast, energy demand in the residential and commercial sectors grows 

at about the same rate as population. Demand for energy in the transportation 

sector grows more rapidly, driven by estimates of increased per capita travel 

and slower fuel efficiency gains. Assumed efficiency gains in the industrial 

sector are projected to cause the demand for primary energy to grow more 

slowly than GDP. 

To help bracket the uncertainty inherent in any long-term forecast, alternative 

assumptions were used to highlight the sensitivity of the AE099 forecast to 

different oil price and economic growth paths. At the consumer level, oil prices 

primarily affect the demand for transportation fuels. Oil use for transportation in 

the high world oil price case is 4.2 percent lower than in the low world oil price 

case in 2020, as consumer choices favor more fuel-efficient vehicles and a 

slightly reduced demand for travel services. Varying economic growth affects 

overall energy demand in each of the end-use sectors to a greater extent [52]. 

By 2020, high economic growth assumptions result in a 17-percent increase in 

total annual energy use over its projected level in the low growth case. 

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Annual Jbnergy uutiook l yyy - Market 1 rend , Energy Demand Page 3 of 11 

Residential Sector Energy Demand 

Electricity Dominates the Expected Increase in Residential Energy Use 

Figure 47. Residential primary energy consumption by fuel, 1970-2020 (percent 

of total) [sources] 

Residential energy consumption is projected to increase by more than 20 

percent overall between 1997 and 2020. Most (87 percent) of the growth in total 

energy use is related to increased use of electricity. Sustained growth in 

housing in the South, where almost all new homes use central air conditioning, 

is an important component of the national trend, along with the penetration of 

consumer electronics, such as home office equipment and security systems 

(Figure 47). 

While its share declines slightly, natural gas use in the residential sector is 

projected to grow by 0.6 percent a year through 2020. Natural gas prices to 

residential customers decline in the forecast and are lower than the prices of 

other fuels, such as heating oil. The number of homes heated by natural gas 

increases more than the number heated by electricity and oil. Distillate fuel and 

liquefied petroleum gas (LPG) use are projected to fall, with the number of 

homes using these fuels for space heating applications expected to decrease 

over time. 

Newly built homes are, on average, larger than the existing stock, with 

correspondingly greater needs for heating, cooling, and lighting. Under current 

building codes and appliance standards, however, energy use per square foot 

is typically lower for new construction than for the existing stock. Further 

reductions in residential energy use per square foot could result from additional 

gains in equipment efficiency and more stringent building codes, requiring more 

insulation, better windows, and more efficient building designs. 

Efficiency Improvements Could Slow the Growth in Energy Use for 

Heating 

Figure 48. Residential primary energy consumption by end use. 1990.1997. 

2010. and 2020 (quadrillion Btu) [sources] 

Energy use for space heating, the most energy-intensive end use in the 

residential sector, grew by 2.5 percent a year from 1990 to 1997 (Figure 48). 

Future growth should be slowed by higher equipment efficiency and tighter 

building codes. Building shell efficiency gains are projected to cut space heating 

demand in new homes by over 25 percent per household in 2020 relative to the 

demand in 1997. 

A variety of appliances are now subject to minimum efficiency standards, 

including heat pumps, air conditioners, furnaces, refrigerators, and water 

heaters. Current standards for a typical residential refrigerator limit electricity 

use to 690 kilowatthours a year, and revised standards are expected to reduce 

consumption by another 30 percent by 2002. Energy use for refrigeration has 

declined by 4.4 percent annually since 1990 and is projected to decline by 

about 2.0 percent a year through 2020, as older, less efficient refrigerators are 

replaced with newer models. 

The "all other" category, which includes smaller appliances such as personal 

computers, dishwashers, clothes washers, and dryers, has grown by more than 

6 percent a year since 1990 (Figure 48) and now accounts for 30 percent of 

residential energy use. It is projected to account for 40 percent in 2020, as 

small electric appliances continue to penetrate the market. The promotion of 

voluntary standards, both within and outside the appliance industry, is expected 

to forestall even larger increases. Even so, the "all other" category is expected 

to exceed other components of residential demand by 2020. 

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Annual Energy Outlook lyyy - Market trend , Energy Demand Page 4 of 11 

Higher Efficiency, Lower Energy Intensity Are Expected for Appliances 

Figure 49. Efficiency indicators for selected residential appliances. 1998 and 

2020 (index. 1998 stock efficiency =1) fsourcesl 

The AE099 reference case projects an increase in the stock efficiency of 

residential appliances, as stock turnover and technology advances in most enduse services combine to reduce residential energy intensity over time. For most 

appliances covered by the National Appliance Energy Conservation Act of 

1987, the most recent Federal efficiency standards are higher than the 1998 

stock, ensuring an increase in stock efficiency (Figure 49) without any 

additional new standards. Future updates to the Federal standards could have a 

significant effect on residential energy consumption, but they are not included in 

the reference case. Proposed rules for new efficiency standards for clothes 

washers and water heaters are expected to be announced by March 1999, and 

several other product announcements are expected by spring 2000. 

For almost all end-use services, technologies now exist that can significantly 

curtail future energy demand if they are purchased by consumers. The most 

efficient technologies can provide significant long-run savings in energy bills, 

but their higher purchase costs tend to restrict their market penetration. For 

example, condensing technology for natural gas furnaces, which reclaims heat 

from exhaust gases, can raise efficiency by more than 20 percent over the 

current standard; and variable-speed compressors for air conditioners and 

refrigerators can increase their efficiency by 50 percent or more. In contrast, 

there is little room for efficiency improvements in electric resistance water 

heaters, because the technology is approaching its thermal limit. 

Commercial Sector Energy Demand 

Little Change Is Projected for Commercial Energy Fuel Mix 

Figure 50. Commercial nonrenewable primary energy consumption by fuel. 

1970-2020 (percent of total) fsourcesl 

Projected energy use trends in the commercial sector show stable shares for all 

fuels, with growth in overall consumption slowing from its pace over the past 

two decades (Figure 50). Slow growth (0.7 percent a year) is expected in the 

commercial sector, for two reasons. Commercial floorspace is projected to grow 

by only 0.8 percent a year between 1997 and 2020, compared with an average 

of 1.5 percent a year over the past two decades. Lower growth in floorspace 

reflects the slowing population growth expected after 2000. Additionally, energy 

consumption per square foot is projected to decline by 0.1 percent a year, as a 

result of efficiency standards, voluntary government programs aimed at 

improving efficiency, and other technology improvements. 

Electricity accounts for nearly three-fourths of commercial primary energy 

consumption throughout the forecast. Expected efficiency gains in electric 

equipment are offset by continuing penetration of new technologies and greater 

use of office equipment. Natural gas accounts for 22 percent of commercial 

energy consumption in 1997 and maintains that share throughout the forecast. 

Distillate fuel oil makes up only 3 percent of commercial demand in 1997, down 

from 6 percent in the years before deregulation of the natural gas industry. The 

fuel share projected for distillate drops to 2 percent in 2020, as natural gas 

continues to compete for space and water heating uses. With stable prices 

projected for conventional fuels, no appreciable growth in the share of 

renewable energy in the commercial sector is anticipated. 

New Energy Uses Lead Projected Growth in Commercial Demand 

Figure 51. Commercial primary energy consumption by end use. 1997 and 2020 

(guadrillion Btu) fsourcesl 

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•rtjiuutu iiucigy v. ULIOUK. iyyy - mantel irena , tnergy uemana Page 5 of 11 

Through 2020, lighting remains the most important individual end use in the 

commercial sector [53]. Energy use for lighting declines slightly in the forecast 

as more energy-efficient lighting equipment and more efficient generating 

technologies are adopted. Efficiency also improves for space heating, space 

cooling, and water heating, moderating the growth in overall commercial sector 

energy demand. Increasing building shell efficiency, which affects the energy 

required for space heating and cooling, contributes to the trend (Figure 51). 

The highest growth rates are expected for end uses that have not yet saturated 

the commercial market. Energy use for personal computers grows by 2.7 

percent a year and for other office equipment, such as fax machines and 

copiers, by about 2.1 percent a year. The growth in electricity use for office 

equipment reflects a trend toward more powerful equipment, the response to a 

projected decline in real electricity prices, and an increase in the market for 

commercial electronic equipment. Natural gas use for such miscellaneous uses 

as cooking, district heating, and self-generated electricity is expected to grow by 

1.1 percent a year. New telecommunications technologies and medical imaging 

equipment increase electricity demand in the "all other enduse category, which 

also includes ventilation, refrigeration, minor fuel consumption, service station 

equipment, and vending machines. Growth in the "all other" category is 

expected to slow somewhat in later years as emerging technologies achieve 

greater market penetration. 

Industrial Sector Energy Demand 

Increasing Share of Natural Gas Use Is Projected for Industry 

Figure 52. Industrial primary energy consumption by fuel. 1970-2020 

(guadrillion Btu per year) fsourcesl 

From 1970 to 1986, with demand for coking coal reduced by declines in steel 

production and natural gas use falling as a result of end-use restrictions and 

curtailments, electricity's share of industrial energy use increased from 23 

percent to 35 percent. The natural gas share fell from 33 percent to 25 percent, 

and coal's share fell from 16 percent to 10 percent. After 1986, natural gas 

began to recover its share as end-use regulations were lifted and supplies 

became more certain and less costly. The AE099 projections of plentiful 

supplies and stable prices allow natural gas to increase its current share of 

industrial energy consumption. 

Primary energy use in the industrial sector—which includes the agriculture, 

mining, and construction industries in addition to traditional manufacturing— 

increases by 0.8 percent a year in the forecast (Figure 52). Electricity (for 

machine drive and some production processes) and natural gas (given its ease 

of handling) are the major energy sources for the industrial sector. Industrial 

delivered electricity use is projected to increase by 29.8 percent, as Competition 

in the generation market keeps electricity prices low. Relatively low prices are 

also projected for natural gas, resulting in consumption that is 26.2 percent over 

its 1997 level by 2020. Industrial petroleum use grows by 23.2 percent over the 

same period. Coal use increases slowly, by 0.4 percent a year, as new 

steelmaking technologies continue to reduce demand for metallurgical coal, 

offsetting the modest growth in coal use for boiler fuel and as a substitute for 

coke in traditional steelmaking. 

Manufacturing Heat and Power Dominate Industrial Energy Use 

Figure 53. Industrial primary energy consumption by industry category. 1990-

2020 (guadrillion Btu per year) fsources] 

More than two-thirds of all the energy consumed in the industrial sector is used 

to provide heat and power for manufacturing; the remainder is approximately 

equally distributed among nonmanufacturing heat and power and consumption 

as feedstocks (raw materials) and other miscellaneous uses (Figure 53). 

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Annual Energy Outlook 1999 - Market Trend , Energy Demand Page 6 of 

Petroleum refining, chemicals, and pulp and paper are the largest end-use 

consumers of energy for heat and power in the manufacturing sector. These 

three energy-intensive industries used 8.7 quadrillion Btu in 1997. The major 

fuels used in petroleum refineries are still gas, natural gas, and petroleum coke. 

In the chemical industry, natural gas accounts for two-thirds of the energy 

consumed for heat and power. The pulp and paper industry uses the most 

renewables, in the form of wood and spent liquor. 

A major use of energy in the nonmanufacturing industries is for diesel-powered 

off-road equipment, such as mine excavation equipment, farm tractors, and 

bulldozers. The construction industry uses asphalt and road oil for paving and 

roofing. By 2020, nonmanufacturing output is projected to be 40.9 percent 

higher and delivered energy consumption (including asphalt and road oil) 38.3 

percent higher than their 1997 levels. Total feedstock use is expected to 

increase by 19.8 percent Natural gas is the fastest growing feedstock, 

increasing by 23.4 percent between 1997 and 2020. 

Changing Industrial Output Leads the Decline in Energy Intensity 

Figure 54. Industrial delivered energy intensity by component. 1990-2020 

(index. 1997 = 1) fsources] 

Changes in industrial energy intensity (consumption per unit of output) can be 

separated into two effects. One component reflects underlying increases in 

equipment and production efficiencies; the other arises from structural changes 

in the composition of manufacturing output. Since 1970, the use of more 

energy-efficient technologies, combined with relatively low growth in the energyintensive industries, has moderated growth in industrial energy consumption. 

Thus, despite a 44percent increase in industrial output, total energy use in the 

sector has grown by only 12 percent since 1977. These basic trends are 

expected to continue. 

The share of total industrial output attributed to the energy-intensive industries 

falls from 23 percent to 19 percent from 1997 to 2020. Thus, even if no specific 

industry experienced a decline in intensity, aggregate industrial intensity would 

decline. Figure 54 shows projected changes in energy intensity due to structural 

effects and efficiency effects separately [54]. Over the forecast period, industrial 

delivered energy intensity drops by 19 percent, and the changing composition 

of industrial output alone results in approximately a 15-percent drop. Thus, 

more than two-thirds of the change in delivered energy intensity for the sector is 

attributable to structural shifts and the remainder to changes in energy intensity 

associated with increases in equipment and production efficiencies. 

Transportation Sector Energy Demand 

Low Prices Are Projected To Boost Gasoline Consumption 

Figure 55. Transportation energy consumption by fuel. 1975.1997. and 2020 

(guadrillion Btu) fsourcesl 

By 2020, total energy demand for transportation is expected to be 36.9 

quadrillion Btu, compared with 25.0 quadrillion Btu in 1997 (Figure 55). 

Petroleum products dominate energy use in the sector. Motor gasoline use, 

increasing by 1.2 percent a year in the reference case, makes up more than half 

of transportation energy demand. Alternative fuels are projected to displace 

about 500,000 barrels of oil equivalent a day [55] by 2020 (about 5 percent of 

light-duty vehicle fuel consumption), in response to current environmental and 

energy legislation intended to reduce oil use. Gasoline's share of demand is 

sustained, however, by low projected gasoline prices and slower fuel efficiency 

gains in conventional light-duty vehicles (cars, vans, pickup trucks, and utility 

vehicles) than was achieved during the 1980s. 

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Annual energy WUUOOK iyyy - Market irena , tnergy Demand Page 7 of 11 

Assumed industrial output growth of 1.9 percent a year through 2020 leads to 

an increase in freight transport, with a corresponding increase in diesel use of 

1.5 percent a year. Economic growth and low projected jet fuel prices yield a 

3.8-percent annual increase in air travel, causing jet fuel use to increase by 2.8 

percent a year. 

In the forecast, energy prices directly affect the level of oil use through travel 

costs and average vehicle fuel efficiency. Most of the projected price sensitivity 

is seen as variations in motor gasoline use in light-duty vehicles, because the 

stock of light-duty vehicles turns over more rapidly than the stock for other 

modes of travel. In the high oil price case, gasoline use increases by only 1.1 

percent a year, compared with 1.4 percent a year in the low oil price case. 

Fuel Efficiency Grows, Despite Increasing Vehicle Horsepower 

Figure 56. Transportation stock fuel efficiency bv mode. 1997-2020 (index. 

1997 = 1) fsources] 

Projected fuel efficiency improves at a slower rate through 2020 than in the 

1980s (Figure 56), with light-duty vehicle efficiency standards assumed to stay 

at current levels. Projected low fuel prices and higher personal income [__. 

increase the demand for larger, more powerful vehicles. Average horsepower 

for new cars in 2020 is 63 percent above the 1997 level (Table 3), but the use of 

advanced technologies and materials keeps new vehicle fuel economy from 

declining. New advanced technologies, such as gasoline fuel cells and direct 

fuel injection and electric hybrids for both gasoline and diesel engines, are 

projected to boost fuel economy levels gradually through 2020, by about 1 to 2 

miles per gallon. 

From 1990 to 1997, the horsepower of compact sport utility vehicles (medium 

light trucks) increased faster than that of standard sport utility vehicles (large 

light trucks)—3.0 percent vs. 2.6 percent a year. If it continues, this trend will 

lead to higher horsepower for medium than for large light trucks by 2020. 

Table 3 - New car and light truck horsepower ratings and market shares. 

1990-2020 fsourcesl 

Electric Vehicles Are Projected To Gain AFV Market Share 

Sales of alternative-fuel vehicles (AFVs) as a result of legislative mandates at 

the Federal level—under the Energy Policy Act of 1992 (EPACT)—and at the 

State level—under the Low Emission Vehicle Program (LEVP)—-are expected 

to reach about 0.64 million units in 2020 (Figure 57). AFV acquisitions 

mandated for fleets under EPACT, predominantly fueled by compressed natural 

gas (CNG) or liquefied petroleum gas, represent the earliest legislated sales. 

Vehicles that use gaseous fuels continue to capture a large share of the AFV 

market through 2020 (Table 4). 

Figure 57. Alternative-fuel vehicle sales bv type of demand. 1997-2020 

(thousand vehicles sold) fsourcesl 

Implementation of LEVP regulations is assumed to begin in 2003 for California, 

Massachusetts, and New York. LEVP legislated sales are expected to total 

292,000 units in 2020, boosting electric vehicles to about 25 percent of AFV 

sales. Market-driven sales [57] exceed mandated sales of AFVs by 2000 as a 

result of AFV corporate average fuel economy (CAFE) credits available to auto 

manufacturers under the Alternative Motor Fuels Act. 

AFVs Are Projected at 8 Percent of All Vehicle Sales in 2020 

Figure 58. Alternative-fuel light-duty vehicle sales by fuel type, 1997-2020 

(thousand vehicles sold) [sources] 

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Annual Energy Outlook 1999 - Market Trend , Energy Demand Page 8 of 11 

In the reference case, total AFV sales reach approximately 1.21 million units, or 

8.1 percent of all vehicle sales, in 2020 (Figure 58). The use of light-duty AFVs 

is expected to reduce carbon emissions by 1 million metric tons of carbon by 

2020. Vehicles that use gaseous fuels are already being sold by manufacturers 

at prices $3,000 to $4,000 above those for gasoline vehicles. Their limited 

range (about two-thirds that of gasoline vehicles) makes them good candidates 

for centrally fueled fleet applications. Because the large fuel tanks required to 

maintain vehicle range restrict both trunk and passenger space, the market 

potential for gaseous fuel AFVs for private use is limited to larger vehicles. 

Electric vehicles are currently being developed by several automobile 

manufacturers, but large numbers of sales are not expected until LEVP 

mandates begin. Sales of dedicated electric vehicles—98 percent of which 

originate from LEVP mandates—are projected to reach nearly 299,000 units in 

2020. 

Table 4 - Shares of the alternative-fuel light-duty vehicle market bv technology 

type. 2020 (percent) fsourcesl 

"Flex fuel" vehicles, which can use any combination of ethanol, methanol, and 

gasoline, are expected to make up 23 percent of AFV sales in 2020. The range, 

fuel efficiency, and performance of these vehicles are similar to those of 

conventional gasoline vehicles, and their incremental production cost is 

currently less than $500, although manufacturers are now selling them at cost 

to meet CAFE standards. Cellulosic ethanol is expected to displace corn-based 

ethanol by 2001, resulting in lower fuel costs for flex-fuel vehicles. 

Energy Demand in Alternative Technology Cases 

New Efficient Technologies Could Save Energy in All Sectors 

Figure 59. Variation from reference case primary energy use by sector in two 

alternative technology cases. 2010.2015. and 2020 (guadrillion Btu) fsourcesj 

The availability and market penetration of new, more efficient technologies are 

uncertain. Alternative cases for each sector, based on a range of assumptions 

about technological progress, show the effects of the assumptions (Figure 59). 

The alternative cases assume that current equipment and building standards 

are met but do not include feedback effects on energy prices or on economic 

growth. 

For the residential and commercial sectors, the 1999 technology case holds 

equipment and building shell efficiencies at 1999 levels. The best available 

technology case assumes that the most energy-efficient equipment and best 

residential building shells available are chosen for new construction each year 

regardless of cost, and that efficiencies of existing residential and all 

commercial building shells improve from their reference case levels. The high 

technology case assumes earlier availability, lower costs, and higher 

efficiencies for more advanced technologies than in the reference case. 

The 1999 technology cases for the industrial and transportation sectors and the 

high technology case for the industrial sector use the same assumptions used 

for the buildings sector. The high technology case for the transportation sector 

includes reduced costs for advanced technologies and improved efficiencies, 

comparable to those assumed in a recent Department of Energy (DOE) 

interlaboratory study for air, rail, marine, and freight travel and provided by the 

DOE Office of Energy Efficiency and Renewable Energy and American Council 

for an Energy-Efficient Economy for light-duty vehicles [58]. 

Potential Efficiency Gains Are Significant for Residential Users 

Figure 60. Variation from reference case primary residential energy use in three 

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Annual Energy Outlook iy99 - Market trend , Energy Demand Page 9 of 11 

alternative cases. 2000-2020 (quadrillion Btu) [sources] 

The AE099 reference case forecast includes the projected effects of several 

different policies aimed at increasing residential end-use efficiency. Examples 

include minimum efficiency standards and voluntary energy savings programs 

designed to promote energy efficiency through innovations in manufacturing, 

building, and mortgage financing. In the 1999 technology case, which assumes 

no further increases in the efficiency of equipment or building shells beyond that 

available in 1999, 7.4 percent more energy would be required in 2020 (Figure 

60). 

In the best available technology case, assuming that the most energy-efficient 

technology considered is always chosen regardless of cost, energy use is 25.4 

percent lower than in the reference case in 2020, and household primary 

energy use is 30.5 percent lower than in the 1999 technology case in 2020. 

The high technology case does not constrain consumer choices. Instead, the 

most energy-efficient technologies are assumed to be available earlier, with 

lower costs and higher efficiencies. The consumer discount rates used to 

determine the purchased efficiency of all residential appliances in the high 

technology case do not vary from those used in the reference case; that is, 

consumers value efficiency equally across the two cases. Energy savings in 

this case relative to the reference case reach 10.8 percent in 2020; however, 

the savings are not as great as those in the best available technology case. 

Investment Costs Could Outstrip Residential Energy Cost Savings 

Figure 61. Cost and investment changes for selected residential appliances in 

the best available technology case. 2000-2020 (billion 1998 dollars) fsources] 

Figure 62. Present value of investment and savings for residential appliances in 

the best available technology case. 2000-2020 (billion 1998 dollars) fsources] 

In the best available technology case, which requires the purchase of the most 

efficient equipment available, residential energy expenditures are lower but 

capital investment costs are higher (Figures 61 and 62). This case captures the 

effects of installing the most efficient (usually the most expensive) equipment at 

reference case turnover rates, regardless of economic considerations. An 

incremental investment of $137 billion [59] reduces residential delivered energy 

use by more than 22 quadrillion Btu—saving consumers more than $71 billion 

in energy expenditures—through 2020. Water heating and space conditioning 

show the greatest potential for savings, but at a substantial investment cost. In 

place of conventional technologies, such as electric resistance water heaters, 

natural gas and electric heat pump water heaters, and horizontal-axis washing 

machines can substantially cut the amount of energy needed to provide hot 

water services. 

AE099 Reference Case Includes Gains in Commercial Energy Efficiency 

Figure 63. Variation from reference case primary commercial energy use in 

three alternative cases. 2000-2020 (quadrillion Btu) fsourcesl 

The AE099 reference case incorporates efficiency improvements for 

commercial equipment and building shells, contributing to a decline in 

commercial energy intensity of 0.1 percent a year over the forecast. The 1999 

technology case assumes that future equipment and building shells will be no 

more efficient than those available in 1999. The high technology case assumes 

earlier availability, lower costs, and higher efficiencies for more advanced 

equipment than in the reference case. In addition, building shells are assumed 

to improve at a faster rate then in the reference case. In comparison, the best 

available technology case assumes that only the most efficient technologies 

considered in AE099 will be chosen, regardless of cost, and that building shells 

will improve at the same rate assumed in the high technology case. 

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Annual Energy Outlook 1999 - Market Trend , Energy Demand Page 10 of 

Energy use in the 1999 technology case is 2.3 percent higher than in the 

reference case by 2020 (Figure 63), with commercial primary energy intensity 

stable through 2020. In the high technology case there is an additional 3.0-

percent energy savings in 2020, and primary energy intensity falls by 0.2 

percent a year from 1997 to 2020. Allowing the purchase of only the most 

efficient equipment in the best available technology case yields energy use that 

is 11.0 percent lower than energy use in the reference case by 2020. 

Commercial primary energy intensity declines more rapidly in this case than in 

the high technology case, by 0.6 percent a year. 

Trends in Energy Intensity Vary by 50 Percent in Alternative Cases 

Figure 64. Industrial primary energy intensity in two alternative technology 

cases. 1990-2020 (index. 1997 = 1) fsourcesl 

Projected efficiency gains in both energy-intensive and non-energy-intensive 

industries provide improvement in energy intensity. The growth in machinery 

and equipment production, driven primarily by investment and export-related 

demand, is a key factor: these less energy-intensive industries grow 48 percent 

faster than the industrial average (2.8 percent vs. 1.9 percent a year). 

In the high technology case, 3.4 quadrillion Btu less energy is used in 2020 than 

for the same level of output in the reference case. Industrial primary energy 

intensity declines by 1.4 percent a year through 2020 in this case, compared 

with a 1.0-percent annual decline in the reference case (Figure 64). While the 

individual industry intensities decline about twice as rapidly in the high 

technology case as in the reference case, the aggregate intensity falls less 

rapidly, because the composition of industrial output is the same in the two 

cases. 

In the 1999 technology case, industry consumes 0.9 quadrillion Btu more 

energy in 2020 than in the reference case. Energy efficiency remains at the 

level achieved in 1999 new plants, but average efficiency still improves as old 

plants are retired. Aggregate industrial energy intensity declines by 0.9 percent 

a year because of reduced efficiency gains and changes in industrial structure. 

The composition of industrial output accounts for 86 percent of the change in 

aggregate industrial energy intensity, compared with 77 percent in the reference 

case. 

More Improvement in Fuel Efficiency Is Possible for Transportation Uses 

Figure 65. Changes in key components of the transportation sector in two 

alternative cases. 2020 (percent change from reference case) fsourcesl 

Two alternative cases are examined to bracket the potential impacts of 

technology improvements in the transportation sector. The 1999 technology 

case holds new fuel efficiencies for light-duty vehicles, freight trucks, and 

aircraft at 1999 levels throughout the forecast, resulting in average stock 

efficiencies for light-duty vehicles that are as much as 8.4 percent lower than 

those in the reference case in 2020. As a result, fuel use in 2020 is 2.8 

quadrillion Btu (7.5 percent) higher than in the reference case (Figure 65). The 

increase in fuel use is attributable primarily to light-duty vehicles (55 percent of 

the total increase), followed by aircraft (17 percent) and freight trucks (16 

percent). 

The high technology case assumes cost and performance criteria provided by 

the DOE Office of Energy Efficiency and Renewable Energy and American 

Council for an Energy-Efficient Economy for light-duty vehicles, and from the 

efficiency case of the recent interlaboratory study [60] for air, freight, marine, 

and rail travel, including high-efficiency advanced light-duty diesel vehicles; 

electric, electric hybrid, and fuel cell light-duty vehicles with higher efficiencies 

and earlier introduction dates; advanced drag reduction, reduced vehicle 

weights, and advanced diesel engines for freight trucks, with shorter market 

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Annual Energy Outlook 1999 - Market Trend , Energy Demand . Page 11 of 11 

penetration times and lower cost-effectiveness criteria; and aircraft with higher 

fuel efficiency. In the high technology case, total fuel consumption for the 

transportation sector is 2.9 quadrillion Btu (7.9 percent) lower than the 

reference case level in 2020. 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 1 of 10 

Market Trends - Oil 6£ Natural Gas 

Report Contents 

Oil and Gas Prices 

[Report#:DOE/EIA-0383 

' '' Petroleum Use Grows, But Projected Prices Show Only Modest Increases 

>

 Preface 

• Administrator's 

Message 

" Overview 

• Legislation & 

Regulations 

• Issues in Focus 

" Market Trends 

Because domestic prices for crude oil are determined largely by the 

international market, the current decline in world oil prices causes wellhead 

prices for crude oil in the lower 48 States to drop considerably in 1998 in all 

cases, followed by an increase through the rest of the forecast, regaining 1997 

levels in 2003 in the reference case. Wellhead prices are projected to fall by 0.7 

percent a year from 1997 to 2020 in the low world oil price case, and to grow by 

1.3 and 2.4 percent a year in the reference and high price cases, respectively 

(Figure 84). 

Figure 84. Lower 48 crude oil wellhead prices. 1970-2020 (1997 dollars per 

barrel) fsourcesl 

U.S. petroleum consumption continues to rise in all the AE099 cases (Figure 

85). Total petroleum product supplied ranges from 22.5 million barrels per day 

in the low economic growth case to 26.8 million in the high growth case, as 

compared with 18.6 million in 1997. 

Figure 85. U.S. petroleum consumption in five cases. 1970-2020 (million barrels 

per day) [sources] 

• Forecast 

Comparisons 

• Major Assumptions 

for the Forecasts 

" Model Results 

(Appendix Tables) 

• Download Report 

" Acronyms 

• Contacts 

" Feedback 

_ * « * 

Growing Demand Leads to Rising Natural Gas Prices 

Wellhead prices for natural gas in the lower 48 States increase by 0.1, 0.8, and 

1.4 percent a year in the low economic growth, reference, and high economic 

growth cases, respectively (Figure 86). The increases reflect rising demand for 

natural gas and its impact on the natural progression of the discovery process 

from larger and more profitable fields to smaller, less economical ones. Price 

increases also reflect more production from higher cost sources, such as 

unconventional gas recovery. Lower 48 unconventional gas production grows 

by 2.7 percent a year in the reference case, compared with 2.2-percent annual 

growth for conventional sources. Although the sources of production change, 

technically recoverable resources (Table 6) remain more than adequate overall 

to meet the production increases. 

Table 6. Technically recoverable U.S. oil and gas resources as of January 1. 

1997 fsourcesl 

Figure 86. Lower 48 natural gas wellhead prices. 1970-2020 (1997 dollars per 

thousand cubic feet) fsources] 

Demand for natural gas rises in all three cases. In the low economic growth 

case, the increase is gradual, and the price increases attributable to the rising 

demand are nearly overshadowed by the beneficial impacts of technological 

progress on the discovery process. In the reference and high growth cases, 

however, the impacts of technological progress only moderate the resulting 

price increases. 

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Annual Energy Outlook tyyy - Market Irend - Oil and (jas Prices Page 2 of 10 

Keiated LIHKS 

" Assumptions to the 

AEQ99 

Oil and Gas Reserve Additions 

Increased Drilling Activity Is Expected in the AE099 Projections 

" Interactive Data 

Queries to 

the AEQ99 

' Supplemental Data 

to the AEQ99 

NEMS Conference 

• To Forecasting 

Home Page 

" EIA Homepage 

Both exploratory and developmental drilling increase in the forecast With rising 

prices and declining drilling costs, crude oil and natural gas well completions 

increase on average by 1.7 and 3.1 percent a year in the low and high oil price 

cases, respectively, compared with 2.4 percent in the reference case (Figure 

87). Changes in world oil price assumptions have a more pronounced effect on 

projected oil drilling than on gas drilling (Table 7). 

Figure 87. Successful new lower 48 natural gas and oil wells in three cases, 

1970-2020 (thousand successful wells) fsources] 

The productivity of natural gas drilling does not decline as much as that of oil 

drilling, in part because total recoverable gas resources are more abundant 

than oil resources. At the projected production levels, however, recoverable 

resources of conventional natural gas decline rapidly in some areas, particularly 

in the onshore Southwest and offshore Gulf of Mexico regions. In the final 

analysis, the future overall productivity of both oil and gas drilling is necessarily 

uncertain, given the uncertainty associated with such factors as the extent of 

the Nation's oil and gas resources [62]. 

Table 7. Natural gas and crude oil drilling in three cases. 1997-2020 

(thousands of successful wells) fsources] 

Oil Production Is Projected To Exceed Reserve Additions 

For most of the past two decades, lower 48 production of both oil and natural 

gas has exceeded reserve additions. The recent reversal of that pattern for 

natural gas is projected to continue through 2013, even with expected increases 

in demand, primarily for electricity generation. The relatively high levels of 

annual gas reserve additions through 2020 reflect increased drilling as a result 

of higher prices, as well as productivity gains from technological improvements 

comparable to those of recent years, affecting both exploration and 

development (Figure 88). Consequently, almost 60 percent of the lower 48 

nonassociated natural gas resources expected to be technically recoverable 

from conventional sources are projected to be discovered by 2020. In contrast, 

despite varying patterns of lower 48 oil reserve additions (Figure 89), total lower 

48 crude oil production exceeds total reserve additions over the forecast period 

in all cases. 

Figure 88. Lower 48 natural gas reserve additions in three cases. 1970-2020 

(trillion cubic feet) fsourcesl 

Natural Gas Production and Imports 

Most Natural Gas Production Is Expected From Conventional Sources 

Figure 89. Lower 48 crude oil reserve additions in three cases. 1970-2020 

(billion barrels) fsources] 

The continuing increase in domestic natural gas production in the forecast 

comes primarily from lower 48 onshore nonassociated (NA) sources (Figure 

90). Conventional onshore production, which accounted for 39.2 percent of total 

U.S. domestic production in 1997, increases in share to 45.0 percent of the total 

in 2020. Unconventional sources also increase in share, and gas from offshore 

wells in the Gulf of Mexico contributes significantly to production. The 

innovative use of cost-saving technology and the expected mid-term 

continuation of recent huge finds, particularly in the deep waters of the Gulf of 

Mexico, support this projection. 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 3 of 10 

Figure 90. Natural gas production by source, 1970-2020 (trillion cubic feet) 

fsources] 

Natural gas production from Alaska grows by 2.3 percent a year in the forecast 

Currently, all production is either consumed in the State, reinjected, or exported 

to Japan as liquefied natural gas (LNG). Alaskan gas is not expected to be 

transported to the lower 48 States, because the projected lower 48 prices are 

not high enough in the forecast period to support the required transport system. 

Expected Alaskan natural gas production does not include gas from the North 

Slope, which primarily is being reinjected to support oil production. In the future, 

North Slope gas may be marketed as LNG to Pacific Rim markets [63]. 

Production of associated/dissolved (AD) natural gas from lower 48 crude oil 

reservoirs generally declines, following the expected pattern of domestic crude 

oil production. AD gas accounts for 7.6 percent of total lower 48 production in 

2020, compared with 13.9 percent in 1997. 

Net Imports of Natural Gas Are Projected To Increase 

Net natural gas imports are expected to grow in the forecast (Figure 91) from 

12.9 percent of total gas consumption in 1997 to 15.5 percent in 2020. Most of 

the increase is attributable to imports from Canada, which are projected to grow 

substantially as considerable new pipeline capacity comes on line. While most 

of the new capacity provides access to supplies from western Canada through 

the Midwest, new capacity is also expected to provide access to eastern 

supplies, including gas from Sable Island in the offshore Atlantic f64]. 

Figure 91. Natural gas production, consumption, and imports. 1970-2020 

(trillion cubic feet) fsourcesl 

Mexico has a considerable natural gas resource base, but there is uncertainty 

as to whether its indigenous production can be increased sufficiently to satisfy 

rising demand. Since 1984, U.S. natural gas trade with Mexico has consisted 

primarily of exports. That trend is expected to continue throughout the forecast, 

with exports increasing as mandated conversion of power plants from heavy 

fuel oil to natural gas gains momentum, in compliance with Mexico's new 

environmental regulations. 

LNG provides another source of gas imports; however, given the projected low 

natural gas prices in the lower 48 markets, LNG is not expected to grow beyond 

a regionally significant source of U.S. supply. LNG imports into Everett, 

Massachusetts, and Lake Charies, Louisiana, are projected to increase over the 

forecast reaching a level of 0.29 trillion cubic feet in 2020, compared with 0.02 

trillion cubic feet in 1997 [651. 

Natural Gas Consumption 

Natural Gas Use Grows Strongly in All the AE099 Cases 

Natural gas consumption increases from 1997 to 2020 in all the AE099 cases 

(Figure 92). Domestic consumption ranges from 29.5 trillion cubic feet per year 

in the low economic growth case to 34.8 trillion in the high growth case in 2020, 

as compared with 22.0 trillion cubic feet in 1997. Growth is seen in all end-use 

sectors, with more than half of the growth resulting from rising demand for 

electricity, including industrial cogeneration. 

Figure 92. Natural gas consumption in five cases. 1970-2020 (trillion cubic feet) 

fsources] 

Natural gas consumption in the electricity generation sector (excluding 

cogeneration) grows steadily throughout the forecast In the reference case it 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 4 of 10 

nearly triples, from 3.3 trillion cubic feet a year in 1997 to 9.2 trillion cubic feet in 

2020. Restructuring of the electric utility industry is expected to open up new 

opportunities for gas-fired generation. In addition, growth is spurred by 

increased utilization of existing gas-fired power plants in the forecast and the 

addition of new turbines and combined-cycle facilities, which are less capitalintensive than coal, nuclear, or renewable electricity generation plants. Although 

projected coal prices to the electricity generation sector fall throughout the 

forecast, the natural gas share of new capacity is nearly 10 times the coal 

share. Lower capital costs and projected improvements in gas turbine heat 

rates make the overall cost of gas-generated electricity per 

kilowatthour competitive with the cost of electricity from new coal-burning 

generators. 

Rising Gas Demand Is Expected To Prompt Pipeline Expansions 

Demand for natural gas is projected to outstrip existing pipeline capacity. 

Expansion of interstate capacity (Figure 93) will be needed to provide access to 

new supplies and to serve expanding markets. Expansion is projected to 

proceed at a rate of 1.2 percent a year through the forecast. The greatest 

increases are projected along the corridors that move Canadian and Gulf Coast 

supplies to markets in the eastern half of the United States. Natural gas 

deliverability is also augmented by new storage capacity which is projected to 

increase in most regions over the forecast period. In several regions, growth in 

new pipeline construction is tempered by higher utilization of existing pipeline 

capacity (Figure 94). 

Figure 93. Pipeline capacity expansion by Census division. 1997-2020 (billion 

cubic feet per day) fsources] 

Figure 94. Pipeline capacity utilization by Census division. 1997 and 2020 

(percent) fsources] 

Natural Gas Prices 

Residential, Commercial Gas Prices Are Projected To Decline 

While consumer prices to the industrial, electricity, and transportation sectors 

generally increase throughout the forecast period, prices to the residential and 

commercial sectors decline (Figure 95). The decreases reflect declining 

distribution margins to these sectors due to anticipated efficiency improvements 

in an increasingly competitive market. In the industrial sector, a modest 

decrease in margins is overshadowed by an increase in wellhead prices, and 

the overall trend is a slight rise in prices. In the electricity generation sector, 

increases in pipeline margins and wellhead prices combine to yield an average 

0.8-percent annual rise in end-use prices. The declines in the residential and 

commercial sectors overshadow the increases in other sectors, yielding a 0.3-

percent drop in national average end-use prices. 

Figure 95. Natural gas end-use prices by sector. 1970-2020 (1997 dollars per 

thousand cubic feet) fsourcesl 

Compared with their rise and decline over the 19701997 period, transmission 

and distribution revenues in the natural gas industry are relatively stable in the 

forecast declining slightly through 2010, when they begin a gradual increase 

(Table 8). Declines in margins are balanced by higher volumes. 

Table 8. Transmission and distribution revenues and margins. 1970-2020 

[sources] 

Lower Distribution Costs Are Projected for Natural Gas 

With distribution margins declining, the wellhead shares of end-use prices 

generally increase in the forecast (Figure 96). The greatest impact is in the 

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Annual Energy uutiook 1 yyy - Market trend - Oil and Gas Prices Page 5 of 10 

residential and commercial markets, where most customers purchase gas 

through local distribution companies (LDCs). In the electricity generation sector, 

which has a relatively stable share, the majority of customers do not purchase 

from distributors. 

Figure 96. Wellhead share of natural gas end-use prices by sector. 1970-2020 

(percent) [sources] 

Changes have been seen historically in all components of end-use prices 

(Table 9). Pipeline margins decreased between 1985 and 1997 with industry 

restructuring. On average, modest decreases are projected to continue through 

the forecast period, despite the cost of interstate pipeline expansion. Although 

LDC margins in the residential and commercial sectors have seen little or no 

decrease since 1985, efficiency improvements and other impacts of 

restructuring are exerting downward pressure on distribution costs, and reduced 

margins are projected for these sectors. 

Table 9. Components of residential and commercial natural gas end-use prices. 

1985-2020 (1997 dollars per thousand cubic feet) [sources] 

Oil and Gas Alternative Technology Cases 

Technology Advances Could Boost Oil and Gas Reserve Additions 

Figure 97. Lower 48 crude oil and natural gas end-of-vear reserves in three 

cases. 1997-2020 (quadrillion Btu) fsources] 

In the forecast, major advances in data acquisition, data processing, and the 

display and integration of seismic date with other geologic data—combined with 

lower cost computer power and experience gained with new techniques— 

continue to put downward pressure on costs while significantly improving 

finding and success rates. Effective use of improved exploration and production 

technologies to aid in the discovery and development of resources— 

particularly, unconventional gas and offshore deepwater fields—will be needed 

if new reserves are to replace those depleted by production. 

Alternative cases were used to assess the sensitivity of the projections to 

changes in success rates, exploration and development costs, and finding rates 

as a result of technological progress. The assumed technology improvement 

rates were increased and decreased by approximately 50 percent in the rapid 

and slow technology cases, which were run as fully integrated model runs. All 

other parameters in the model were kept at their reference case values, 

including technology parameters for other modules, parameters affecting 

foreign oil supply, and assumptions about foreign natural gas trade. 

Although gas reserves become a slightly larger share of the total in the 

reference case, total hydrocarbon reserve additions offset production, keeping 

total reserves essentially constant throughout the projection period (Figure 97). 

By 2020, reserves are 16.6 percent higher in the rapid technology case than in 

the reference case and 10.9 percent lower in the slow technology case. 

Projected Gas Prices Strongly Depend on Technology Assumptions 

The natural gas price projections are highly sensitive to changes in the 

assumptions about technological progress (Figure 98). Lower 48 wellhead 

prices increase at an average annual rate of 1.3 percent in the slow technology 

case, compared with only 0.8 percent in the reference case, over the projection 

period. In the rapid technology case, average natural gas wellhead prices are 

higher than the 1997 level by at most 3.5 percent, and by 2020 they are back to 

the 1997 price of $2.23 per thousand cubic feet. 

Figure 98. Lower 48 natural gas wellhead prices in three cases. 1970-2020 

(1997 dollars per thousand cubic feet) fsourcesl 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 6 of 10 

Through 2000, both price and production levels for lower 48 oil and natural gas 

are almost identical in the reference case and the two technological progress 

cases. By 2020, however, natural gas prices are 11.6 percent higher (at $2.99 

per thousand cubic feet) in the slow technology case and 16.8 percent lower (at 

$2.23 per thousand cubic feet) in the rapid technology case than in the 

reference case ($2.68 per thousand cubic feet). 

Unlike natural gas, lower 48 average wellhead prices for crude oil do not vary 

significantly across the technology cases. In 2020, crude oil prices are 25 cents 

lower in the rapid technology case and 6 cents higher in the slow technology 

case than the reference case price of $21.73 per barrel. Domestic oil prices are 

determined largely by the international market; changes in U.S. oil production 

do not constitute a significant volume relative to the global market. 

Technology Progress Could Boost Natural Gas Market Share 

Changes in production in the alternative technology cases reflect the benefits of 

lower costs and higher finding rates for conventionally recoverable gas, as well 

as an array of technological enhancements for unconventional gas recovery. 

The changes in supply lead to price changes that affect new investment in all 

types of gas-fired technologies, especially in the industrial and electricity 

generation sectors. Rapid technology improvements yield benefits in the form of 

both lower prices and increased production to meet higher consumption 

requirements (Figure 99). 

Figure 99. Lower 48 natural gas production in three cases. 1997-2020 (trillion 

cubic feet) fsourcesl 

In the rapid technology case/the natural gas share of fossil fuel inputs to 

electricity generation facilities in 2020 is 24.6 percent, compared with 22.2 

percent in the slow technology case. The higher level of gas consumption 

comes largely at the expense of coal. There is little additional displacement of 

petroleum products in the rapid technology case, because natural gas captures 

the bulk of the dual-fired boiler market in the reference case. In contrast, in the 

slow technology case, natural gas loses market share to both coal and 

petroleum products in the electricity generation sector. 

Production from unconventional gas resources (tight sands, shales, and 

coalbeds) is particularly responsive to changes in the assumed levels of 

technological progress. In the rapid technology case, the unconventional gas 

share of total lower 48 natural gas production in 2020 is projected to be 33.5 

percent compared with 25.2 percent in the reference case and 19.3 percent in 

the slow technology case. 

Oil Production Shows Less Change With Technology Assumptions 

The projections for domestic oil production also are sensitive to changes in the 

technological progress assumptions (Figure 100). In comparison with the 

projected lower 48 production level of 4.5 million barrels per day in 2020 in the 

reference case, oil production increases to 5.2 million barrels per day in the 

rapid technology case and decreases to 4.6 million in the slow technology case. 

Figure 100. Lower 48 crude oil production in three cases. 1997-2020 (million 

barrels per day) fsources] 

Given the assumption that changes in the levels of technology affect only U.S. 

oil producers, total oil supply adjusts to the variations in technological progress 

assumptions primarily through changes in imports of crude oil and other 

petroleum products. Net imports range from a low of 11.7 million barrels per day 

in the rapid technology case to a high of 12.4 million barrels per day in the slow 

technology case. 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 7 of 10 

Global trade in natural gas has not grown to the same extent as petroleum 

trade. Because opportunities for gas trade between the United States and 

countries outside North America are limited, changes in U.S. gas production are 

determined more by the market conditions in North America than by the 

international market. 

Oil Production and Consumption 

Continued Decline Is Projected for Conventional Oil Production 

Projected domestic crude oil production continues its historic decline throughout 

the forecast (Figure 101), declining by 1.1 percent a year, from 6.5 million 

barrels per day in 1997 to 5.0 million barrels per day in 2020 [66], Conventional 

onshore production in the lower 48 States, which accounted for 49.1 percent of 

total U.S. crude oil production in 1997, is also projected to decrease at an 

average annual rate of 0.9 percent over the forecast. 

Figure 101. Crude oil production by source. 1970-2020 (million barrels per day) 

[sources] 

Crude oil production from Alaska is expected to decline at an average annual 

rate of 4.1 percent between 1997 and 2020. The overall decrease in Alaska's oil 

production results from a continuing decline in production from most of its oil 

fields and, in particular, from Prudhoe Bay, the largest producing field, which 

historically has accounted for more than 60 percent of total Alaskan production. 

Offshore production generally increases in the forecast through 2008 and then 

drops below current levels in 2020, resulting in an overall decrease of 

0.7 percent a year. Technological advances and lower costs for deep 

exploration and production in the Gulf of Mexico contribute to the increase in 

the early years of the forecast 

Production from enhanced oil recovery (EOR) [67], which becomes less 

profitable as oil prices fall, slows through 2003 and then increases along with 

world oil prices through the remainder of the forecast. 

Declining Domestic Oil Supply Leads to Growing Imports 

Domestic petroleum supply declines in all the AE099 cases (Figure 102), as 

U.S. crude oil production falls off. In the low price case, domestic supply drops 

from its 1997 level of 9.4 million barrels per day to 7.6 million barrels per day in 

2020. In the high price case, domestic supply declines only slightly, to 9.3 

million barrels per day in 2020. 

Figure 102. Petroleum supply, consumption, and imports. 1970-2020 (million 

barrels per day) fsourcesl 

The greatest variation in petroleum consumption levels is seen across the 

economic growth cases, with an increase of 8.2 million barrels per day over the 

1997 level in the high growth case, compared with an increase of only 3.9 

million barrels per day in the low growth case. 

Additional petroleum imports will be needed to fill the widening gap between 

supply and consumption. The greatest gap between supply and consumption is 

seen in the low worid oil price case and the smallest in the low economic growth 

case. The projections for net petroleum imports in 2020 range from a high of 

18.4 million barrels per day in the low oil price case—more than double the 

1997 level of 9.2 million barrels per day—to a low of 14.3 million barrels per day 

in the low growth case. The value of petroleum imports in 2020 ranges from 

$99.7 billion in the low price case to $158.1 billion in the high price case. Total 

annual U.S. expenditures for petroleum imports, which reached a historical 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 8 of 10 

peak of $140 billion (in 1997 dollars) in 1980 [68], were $60.9 billion in 1997. 

Petroleum Imports and Refining 

Imports Are Projected To Meet About Two-Thirds of U.S. Oil Demand 

In 1997, net imports of petroleum climbed to a record 49 percent of domestic 

petroleum consumption. Continued dependence on petroleum imports is 

projected, reaching 65 percent in 2020 in the reference case (Figure 103). The 

corresponding import shares of total consumption in 2020 are 61 percent in the 

high oil price case and 71 percent in the low price case. 

Figure 103. Share of U.S. petroleum consumption supplied by net imports. 

1970-2020 (percent) fsources] 

Although crude oil is expected to continue as the major component of petroleum 

imports, refined products represent a growing share. More imports will be 

needed as growth in demand for refined products exceeds the expansion of 

domestic refining capacity. Refined products make up 20 percent of net 

petroleum imports in 2020 in the low economic growth case and 29 percent in 

the high growth case, as compared with their 11-percent share in 1997 

(Table 10). 

Table 10. Petroleum consumption and net imports. 1997 and 2020 (million 

barrels per day) [sources] 

Modest Increases Are Projected for U.S. Refining Capacity 

Falling demand for petroleum and the deregulation of the domestic refining 

industry in the 1980s led to 13 years of decline in U.S. refinery capacity [69]. 

That trend was broken in 1995 by a capacity increase of 0.5 million barrels per 

day over a 2-year period. Financial and legal considerations make it unlikely 

that new refineries will be built in the United States, but additions at existing 

refineries are expected to increase total U.S. refining capacity in all the AE099 

cases (Figure 104). 

Figure 104. Domestic refining capacity. 1975-2020 (million barrels per day) 

fsources] 

Distillation capacity is projected to grow from the 1997 level of 16.0 million 

barrels per day to 17.3 million in 2020 in the low economic growth case and 

18.7 million in the high growth case, as refining capacity exceeds the 1981 peak 

of 18.6 million barrels per day. Refining capacity is projected to expand on the 

East, West, and Gulf coasts. Existing refineries will continue to be utilized 

intensively throughout the forecast, in a range from 93 to 96 percent of design 

capacity. In comparison, the 1997 utilization rate was 95 percent, well above 

the rates of the 1980s and early 1990s. 

Domestic refineries will produce a slightly higher yield of heating oil and jet fuel 

in 2020 in response to growing demand for those products. In 2020, heating oil 

is projected to represent 9 percent of production and jet fuel 13 percent, 

compared with 7 percent and 9 percent, respectively, in 1997. 

Refined Petroleum Products 

More Petroleum Use by Industry and for Transportation Is Projected 

U.S. petroleum consumption is projected to increase by 6.0 million barrels per 

day between 1997 and 2020Jn the reference case, 3.9 million in the low 

economic growth case, and 8.2 million in the high growth case (Figure 105). AH 

the cases show growth in petroleum consumption in the transportation and 

industrial sectors and, with the exception of the low world oil price case, slight 

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Annual Energy Outlook 1999 - Market Trend - Oil and Gas Prices Page 9 of 10 

declines in residential, commercial, and electric utility oil use. 

Figure 105. Change in petroleum consumption by sector in five cases, 1997-

2020 (million barrels per day) fsourcesl 

Most of the increase in petroleum consumption occurs in the transportation 

sector, which accounted for about 65 percent of U.S. petroleum use in 1997. 

That share grows to 69 percent in the low oil price case and 72 percent in the 

low economic growth case in 2020. Gasoline accounts for about 45 percent of 

the projected growth in total petroleum consumption, jet fuel 24 percent, diesel 

fuel 4 percent, and heating oil 9 percent. All these fuels are "light products," 

which are more difficult to produce than such heavier products as asphalt and 

residual fuel oil. 

A shift in consumption patterns is expected within the transportation sector. 

Gasoline, which in 1997 represented 65 percent of the petroleum consumed for 

transportation, shrinks to a 61-percent share in 2020, as alternative fuels 

penetrate transportation markets. The jet fuel share rises from 13 percent in 

1997 to 17 percent as air travel increases substantially. The share for diesel 

declines from 18 percent to 14 percent. With the emergence of biomass-based 

ethanol, the use of ethanol to boost octane or oxygen in gasoline increases 

from about 80,000 barrels per day in 1997 to 180,000 barrels per day in 2020. 

Higher Processing Costs Are Expected for Gasoline and Jet Fuel 

Refined product prices are determined by crude oil costs, refining process costs 

(including refiner profits), marketing costs, and taxes (Figure 106). In the 

AE099 projections, crude oil costs continue to make the greatest contribution to 

product prices, and marketing costs remain stable, but the contributions of 

processing costs and taxes change considerably. 

Figure 106. Components of refined product costs. 1997 and 2020 (1997 dollars 

per gallon) fsourcesl 

The processing costs for gasoline and jet fuel increase by 6 cents and 7 cents 

per gallon, respectively, between 1997 and 2020. For the most part, the 

increases can be attributed to the growth in demand for these products. A small 

portion of the increases can be attributed to investments related to compliance 

with refinery emissions, health, and safety regulations, which add 1 to 3 cents 

per gallon to the processing costs of light products (gasoline, distillate, jet fuel, 

kerosene, and liquefied petroleum gases). 

Whereas processing costs tend to increase refined product prices, assumptions 

about Federal taxes tend to slow the growth of motor fuels prices. In keeping 

with the AE099 assumption of current laws and legislation, Federal motor fuels 

taxes are assumed to remain at nominal 1997 levels throughout the forecast. 

Federal taxes have actually been raised sporadically in the past. State motor 

fuels taxes are assumed to keep up with inflation, as they have in the past. The 

net impact of these assumptions is a decrease in Federal taxes between 1997 

and 2020—9 cents per gallon for gasoline, 11 cents for diesel fuel, and 2 cents 

for jet fuel. 

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Forecast Comparisons 

^3 
Forecast Comparisons 

Three other organizations — DRI/McGraw-Hill 

(DRI), the WEFA Group (WEFA), and the Gas 

Research Institute (GRI) — also produce comprehensive energy projections with a time horizon 

similar to that of AE099. The most recent projections from these organizations (DRI, April 1998; 

WEFA, 1998; GRI, August 1998) and others that 

concentrate on petroleum, natural gas, and international oil markets are compared with the AE099 

projections in this section. 

Economic Growth 

Differences in long-run economic forecasts can be 

traced primarily to different views of the major 

supply-side determinants of growth: labor force and 

productivity change. Other forecasts are presented 

in Table 12. The WEFA forecast shows the highest 

economic growth compared to the AE099 and DRI 

reference cases, including higher growth rates for 

the labor force. The AE099 long-run forecast of 

economic growth is higher than the AE098 forecast 

by 0.2 percent, when compared on a similar basis, 

with a projected annual growth rate for GDP of 1.8 

percent from 1997 to 2020. 

Table 12. Forecasts of economic growth, 1997-2020 

Average annual percentage growth 

Forecast 

AE099 

Low growth 

Reference 

High growth 

DRI 

Low 

Reference 

High 

WEFA 

Low 

Reference 

High 

Real GDP 

1.5 

2.1 

2.6 

1.8 

2.1 

2.3 

1.9 

2.3 

2.6 

Labor force 

0.5 

0.8 

1.0 

0.5 

0.8 

1.0 

0.9 

1.1 

1.3 

Productivity 

1.0 

1.3 

1.6 

1.3 

1.3 

1.3 

1.0 

1.2 

1.3 

In the 1998 Economic Report of the President, real 

GDP growth of 2.3 percent a year between 1997 and 

2005 was projected. AE099 projects annual growth 

of 2.5 percent over the same period. 

World Oil Prices 

Comparisons with other oil price forecasts—including the, International Energy Agency (IEA), Petroleum Economics Ltd. 0?EL), Petroleum Industry 

Research Associates, Inc. 0?DRA), Natural Resources Canada (NRCan), and BT Alex Brown 

(BTAB)—are shown in Table 13 (IEA, 1996; PEL, 

February 1998; PIRA, October 1997; NRCan, April 

1997; BTAB, September 1998). With the exception 

of IEA in 2005 and PEL, the range between the 

AE099 low and high world oil price cases spans the 

range of other published forecasts beyond 2005. 

Table 13. Forecasts of world oil prices, 2000-2020 

1997 dollars per barrel 

Forecast 2000 2005 2010 2015 2020 

AE099 reference 

AE099 high price 

AE099 low price 

DRI 

IEA1 

IEA2 

PEL 

PIRA 

WEFA 

GRI 

NRCan 

BTAB 

NA = not available. 

13.97 

17.90 

10.25 

15.55 

18.49 

18.49 

15.57 

20.00 

18.27 

17.16 

20.76 

11.71 

19.25 

24.53 

14.57 

16.94 

27.19 

18.49 

14.21 

19.00 

19.04 

16.86 

20.76 

16.61 

21.30 

27.33 

14.57 

19.06 

27.19 

18.49 

13.37 

19.60 

19.75 

16.81 

20.76 

16.30 

21.91 

29.14 

14.57 

21.44 

NA 

NA, 

12.93 

NA 

20.52. 

17.02 

20.76 

15.89 

22.73 

29.35 

14.57 

24.13 

NA 

NA 

NA 

NA 

21.32 

NA 

20.76 

NA 

Total Energy Consumption 

The AE099 forecast of end-use sector energy 

consumption over the next two decades shows far 

less volatility than has occurred historically. 

Between 1974 and 1984, volatile world oil markets 

dampened domestic oil consumption. Consumers 

switched to electricity-based technologies in the 

buildings sector, while in the transportation sector 

new car fuel efficiency nearly doubled. Natural gas 

use declined as a result of high prices and limitations on new gas hookups. Between 1984 and 1995, 

however, both petroleum and natural gas consumption rebounded, bolstered by plentiful supplies and 

declining real energy prices. As a consequence, new 

car fuel efficiency in 1995 was less than 2 miles per 

gallon higher than in 1984, and natural gas use 

(residential, commercial, and industrial) was almost 

25 percent higher than it was in 1984. 

Given potentially different assumptions about, for 

example, technological developments over the next 

20 years, the forecasts from DRI, GRI, and WEFA 

have remarkable similarities to those in AE099. 

Electricity is expected to remain the fastest growing 

source of delivered energy (Table 14), although its 

rate of growth is down sharply from historical rates 

in each of the forecasts, because many traditional 

88 Energy Information Administration / Annual Energy Outlook 1999 

cA 
Forecast Comparisons 

Table 14. Forecasts of average annual growth rates 

for energy consumption (percent) 

History Projections 

Energy use 

1974-1984-

1984 1996 

AE099 DRI GRI WEFA 

(1997- (1997- (1997- (1997-

2020) 2020) 2015) 2020) 

Petroleum* 

Natural gas* 

Coal* 

Electricity 

Delivered energy 

Electricity losses 

Primary energy 

•0.1 

•1.7 

•3.0 

3.0 

•0.4 

2.5 

0.2 

1.4 

2.3 

•1.5 

2.6 

1.9 

2.0 

2.0 

1.3 

0.9 

0.4 

1.4 

1.2 

0.6 

1.1 

1.2 

0.8 

•0.7 

1.4 

1.1 

0.7 

1.0 

1.1 

1.4 

-0.4 

1.8 

1.2 

1.0 

1.2 

1.3 

0.8 

0.2 

1.7 

1.2 

0.9 

1.1 

'Excludes consumption by electric utilities. 

uses of electricity (such as for air conditioning) 

approach saturation while average equipment 

efficiencies rise. Petroleum consumption grows at 

the same rate as in recent history. Consumption 

growth for the remaining fuels slows as a result of 

moderating economic growth, fuel switching, and 

increased end-use efficiency. 

Residential and Commercial Sectors 

Growth rates in energy demand for the residential 

and commercial sectors are expected to decrease by 

more than 60 percent from the rates between 1984 

and 1996, largely because of projected lower growth 

in population, housing starts, commercial floorspace 

additions, and colder winter weather in 1996. Other 

contributing factors include increasing energy 

efficiency due to technical innovations and legislated standards; voluntary government efficiency 

programs; and reduced opportunities for additional 

market penetration of such end uses as air 

conditioning. 

Differing views on the growth of new uses for energy 

contribute to variations among the forecasts. By 

fuel, electricity (excluding generation and transmission losses) remains the fastest growing energy 

source for both sectors across all forecasts (Table 

15). Natural gas use also grows but at lower rates, 

and petroleum use continues to fall. 

Industrial Sector 

In all the forecasts, the industrial sector shows 

slower growth in primary energy consumption than 

Table 15. Forecasts of average annual growth 

residential and commercial energy demand 

(percent) 

History Projections 

AE099 DRI GRI WEFA 

1984- (1997- (1997- (1997- (1997-

Forecast 1996 2020) 2020) 2015) 2020) 

Residential 

Petroleum 

Natural gas 

Electricity 

Delivered energy 

Electricity losses 

Primary energy 

0.6 

1.2 

2.8 

2.1 

2.2 

2.1 

•1.2 

0.6 

1.6 

0.8 

0.8 

0.8 

•0.6 

0.8 

1.1 

0.7 

0.3 

0.5 

•1.2 

0.7 

1.7 

0.7 

0.9 

0.8 

•0.5 

0.7 

1.9 

1.0 

1.1 

1.1 

Commercial 

Petroleum 

Natural gas 

Electricity 

Delivered energy 

Electricity losses 

Primary energy 

•3.9 

1.9 

3.3 

1.5 

2.7 

2.1 

•1.3 

0.7 

1.4 

0.9 

0.6 

0.7 

•0.9 

0.5 

1.4 

0.8 

0.7 

0.8 

•2.9 

1.0 

1.6 

1.0 

0.8 

0.9 

•0.6 

0.6 

1.6 

1.0 

0.8 

0.9 

it did between 1984 and 1996 (Table 16). The decline 

is attributable to lower growth for GDP and manufacturing output. In addition, there has been a 

continuing shift in the industrial output mix toward 

less energy-intensive products. The growth rates in 

the industrial sector for different fuels between 1984 

and 1996 reflect a shift from petroleum products and 

coal to a greater reliance on natural gas and electricity. Natural gas use grows more slowly than in 

recent history across the forecasts, because much of 

the potential for fuel switching was realized during 

the 1980s. A key uncertainty in industrial coal forecasts is the environmental acceptability of coal as a 

boiler fuel. 

Table 16. Forecasts of average annual growth in 

industrial energy demand (percent) 

History ' Projections 

Forecast 

Petroleum 

Natural gas 

Coal 

Electricity 

Delivered energy 

Electricity losses 

Primary energy 

1984-

1996 

1.2 

2.5 

•1.3 

1.7 

2.1 

1.2 

1.9 

AE099 

(1997-

2020) 

0.9 

1.0 

0.4 

1.1 

1.0 

0.3 

0.8 

DRI 

(1997-

2020) 

0.7 

0.8 

0.2 

1.7 

0.8 

0.9 

0.8 

GRI 

(1997-

2015) 

1.2 

1.7 

0.0 

2.3 

1.4 

2.4 

1.6 

WEFA 

(1997-

2020) 

1.5 

0.8 

0.0 

1.5 

1.1 

1.6 

1.2 

Energy Information Administration / Annual Energy Outlook 1999 89 

6T 
Forecast Comparisons 

Transportatio n Secto r 

Overall fuel consumption in the transportation 

sector is expected to grow more slowly than in the 

recent past in each of the alternative forecasts 

(Table 17). All the forecasts anticipate continued 

rapid growth in air travel as well as significant 

increases in aircraft efficiency, while growth in 

light-duty vehicle travel slows considerably. 

Table 17. Forecasts of average annual growth 

transportation energy demand (percent) 

m 

Forecast 

Motor gasoline 

Diesel fuel 

Jet fuel 

Residual fuel 

All energy 

Car and light 

truck travel 

Air travel 

(revenue 

passenger-miles) 

Average new car 

fuel efficiency 

Gasoline prices 

History 

1974- 1984-

1984 1995 

0.1 

4.5 

1.9 

1.4 

0.9 

2.8 

7.0 

4.5 

1.8 

NA = not available. 

Electricity 

AE099 

(1997-

2020) 

Consumption 

1.4 

2.8 

2.4 

0.7 

1.8 

1.2 

1.5 

2.8 

2.4 

1.7 

Key indicators 

2.8 

5.0 

0.5 

-3.1 

1.6 

3.1 

0.6 

0.3 

Projections 

DRI 

(1997-

2020) 

1.3 

1.0 

2.4' 

2.4 

1.5 

2.1 

3.4 

0.5 

0.5 

GRI 

(1997-

2015) 

0.5 

1.9 

2.3 

3.3 

1.4 

1.4 

2.8 

0.9 

-0.1 

WEFA 

(1997-

2020) 

0.8 

1.3 

3.0 

2.6 

1.4 

NA 

NA 

NA 

0.1 

Comparison across forecasts shows slight variation 

in projected electricity sales (Table 18). Sales 

projections for 2020 range from 1,349 billion kilowatthours (DRI) to 1,635 billion kilowatthours 

(WEFA) for the residential sector, as compared with 

the AE099 reference case value of 1,557 billion kilowatthours. The forecasts for total electricity sales in 

2020 range from 4,279 billion kilowatthours (DRT) to 

4,581 billion kilowatthours O^EFA). All the projections for total electricity sales in 2020 fall within 

the range of the AE099 low and high economic 

growth cases (4,013 and 4,687 billion kilowatthours, 

respectively). Different assumptions governing 

expected economic activity, coupled with diversity in 

the estimation of penetration rates for energyefficient technologies, are the primary reasons for 

variation among the forecasts. 

All the forecasts compared here agree that stable 

fuel prices and slow growth in electricity demand 

relative to GDP growth will tend to keep the price of 

electricity stable—or declining in real terms—until 

2020. 

Both the DRI and GRI forecasts assume that the 

electric power industry will be fully restructured, 

resulting in average electricity prices that approach 

long-run marginal costs. AE099 also assumes that 

competitive pressures will grow and continue to 

push prices down until the later years of the 

projections. AE099 also assumes that increased 

competition in the electric power industry will lead 

to lower operating and maintenance costs, lower 

general and administrative costs, early retirement 

of inefficient generating units, and other cost reductions. Further, in the DRI forecast, it is assumed 

that time-of-use electricity rates will cause some 

flattening of electricity demand flower peak period 

sales relative to average sales), resulting in better 

utilization of capacity and capital cost savings. 

The distribution of sales among sectors affects the 

mix of capacity types needed to satisfy sectoral demand. Although the AE099 mix of capacity among 

fuels is similar to those in the other forecasts, small 

differences in sectoral demands across the forecasts 

lead to significant changes in capacity mix. For 

example, growth in the residential sector, coupled 

with an oversupply of baseload capacity, results in a 

need for more peaking and intermediate capacity 

than baseload capacity. Consequently, generators 

are expected to plan for more combustion turbine 

and fuel cell technology than coal, oil, or gas steam 

capacity. 

90 Energy Information Administration / Annual Energy Outlook 1999 

Lett 
P.68 

Forecast Comparisons 

Table 18. Comparison of electricity forecasts (billion kilowatthours, 

Projection 

Average end-use price 

(1997 cents per kilowatthour) 

Residential 

Commercial 

Industrial 

Net energy for load 

Coal 

Oil 

Natural gas 

Nuclear 

Hydroelectric/other ° 

Nonutility sales to grid b 

Net imports 

Electricity sales 

Residential 

Commercial/other e 

Industrial 

Capability (gigawatts) ** 

Coal 

Oil and gas 

Nuclear 

Hydroelectric/other a 

Average end-use price 

(1997 cents per kilowatthour) 

Residential 

Commercial 

Industrial 

Net energy for load 

Coal 

Oil 

Natural gas 

Nuclear 

Hydroelectric/other 9 

Nonutility sales to grid b 

Net imports 

Electricity sales 

Residential 

Commercial/other c 

Industrial 

Capability (gigawatts) *« 

Coal 

Oil and gas 

Nuclear 

Hydroelectric/other " 

Reference 

5.8 

7.3 

6.2 

3.8 

4,415 

2.151 

26 

1,213 

419 

400 

180 

27 

4,113 

1,446 

1,387 

1,280 

977 

326 

470 

56 

124 

5.6 

7.1 

6.0 

3.6 

4,661 

2,298 

24 

1,349 

359 

419 

184 

27 

4,345 

1,557 

1,448 

1,339 

1,033 

343 

514 

49 

127 

AE099 

Low 

economic 

growth 

High 

economic 

growth 

2015 

5.4 

6.7 

5.6 

3.5 

4,153 

2.081 

23 

1,047 

411 

394 

170 

27 

3,875 

1,389 

1,345 

1,141 

927 

320 

429 

55 

123 

6.3 

7.9 

6.8 

4.1 

4,680 

2,225 

26 

1,353 

419 

412 

189 

27 

4,355 

1,506 

1,425 

1,423 

1,028 

336 

510 

56 

126 

2020 

5.1 

6.4 

5.3 

3.3 

4,289 

2,139 

20 

1,191 

342 

406 

171 

27 

4,013 

1,478 

1,389 

1,146 

963 

328 

465 

46 

124 

6.1 

7.7 

6.6 

4.0 

5,037 

2,497 

25 

1,474 

373 

444 

197 

27 

4,687 

1,637 

1,505 

1,544 

1,105 

366 

557 

51 

132 

except where noted) 

WEFA 

5.76 

7.10 

6.29 

3.82 

4,573 

2,243 

48 

1,187 

479 

351 

223 

42 

4,213 

1,488 

1,365 

1,360 

937 

356 

392 

65 

124 

5.56 

6.84 

6.04 

3.70 

4,974 

2,472 

49 

1,463 

372 

351 

223 

44 

4,581 

1,635 

1,479 

1,467 

1,008 

389 

446 

48 

124 

Other forecasts 

GRI 

5.30 

6.90 

6.20 

3.10 

4,733 

2,563 

32 

1,099 

453 

407 

168 

39 

4,350 

1,456 

1,363 

1,532 

881 

372 

345 

64 

123 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

DRI 

5.40 

6.80 

5.80 

3.80 

4,639 

2,428 

121 

1,022 

582 

444 

NA 

38 

4,062 

1,285 

1,338 

1,440 

972 

403 

359 

93 

117 

5.30 

6.60 

5.70 

3.70 

4,883 

2,638 

130 

1,084 

549 

443 

NA 

86 

4,279 

1,349 

1,897 

1,534 

1,013 

428 

380 

87 

117 

""Other" includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, other biomass, solar and wind 

power, plus a small quantity of petroleum coke. For nonutility generators, "other" also includes waste heat, blast furnace gas, and coke 

oven gas. 

*For AE099, includes only net sales from cogeneration; for the other forecasts, also includes nonutility sales to the grid. 

"Other'' includes sales of electricity to government, railways, and street lighting authorities. 

d

For DRI, "capability" represents nameplate capacity, for the others, "capability" represents net summer capability. 

'GRI generating capability includes only central utility and independent power producer capacity. It does not include cogeneration 

capacity in the commercial and industrial sectors, which would add another 60 gigawatts. 

Sources: AE099: AE099 National Energy Modeling System, runs AEO99B.D100198A (reference case), LMAC99.D100198A (low 

economic growth case), and HMAC99.D100198A (high economic growth case). WEFA: The WEFA Group, US. Power Outlook (1998). 

GRI: Gas Research Institute, GRI Baseline Projection of U.S. Energy Supply and Demand, 1999 Edition (August 1998). 

DRI: DRI/McGraw-Hill, World Energy Service: U.S. Outlook (April 1998). 

Energy Information Administration / Annual Energy Outlook 1999 91 

i__I 
Forecast Comparisons 

Natural Gas 

The diversity among published forecasts of natural 

gas prices, production, consumption, and imports 

(Table 19) indicates the uncertainty of future 

market trends. Because the forecasts depend 

heavily on the underlying assumptions that shape 

them, the assumptions should be considered when 

different projections are compared. The forecasts for 

total natural gas consumption in 2015 vary from a 

high of 32.99 trillion cubic feet in the AE099 high 

economic growth case to a low of 28.43 trillion cubic 

feet in the low economic growth case. The variation 

in the 2020 projections is even greater, with the 

higher projection only 16 percent above the lower 

projection in 2015 but 22 percent above the lower 

projection in 2020. The high projection for 2020 is 

34.81 trillion cubic feet in the AE099 high economic 

growth case, compared with a low of 28.58 trillion 

cubic feet in the DRI forecast. 

The American Gas Association (AGA) forecast (July 

1998) for growth in residential consumption relative 

to historical levels is significantly higher than the 

others, whereas the DRI and WEFA forecasts of 

growth in commercial consumption lag behind the 

rest, even by 2020. GRI is the most optimistic about 

the future of industrial consumption, in both 

absolute and percentage growth terms. By a large 

margin, all forecasters expect the greatest growth to 

be in the electricity generator sector, with WEFA 

leading the pack. The DRI growth rate for generator 

consumption of natural gas through 2020 is less 

than one-third of WEFA's forecast (although it 

should be noted that DRI includes cogenerators in 

this category). 

The projections of average lower 48 natural gas wellhead prices in 2015 in the AE099 high economic 

growth and reference cases are higher than the 

other forecasts, with the lowest price across all 

forecasts coming from WEFA, at 15 percent below 

the AE099 reference case and 3 percent below the 

low economic growth case. By 2020 the wellhead 

price forecasts from DRI and WEFA fall within the 

range of the AE099 cases, with DRI above the 

AE099 reference case and WEFA below. Excluding 

the AE099 low economic growth case, the 2015 

residential and commercial prices are highest for 

GRI and lowest for AGA, with a differential between 

the two of $0.79 and $0.97 (13 and 19 percent), 

respectively, for the two sectors fliowever, the AGA 

prices do not include some State and local taxes). 

The industrial (and to a lesser extent the electricity 

generator) sectoral prices are difficult to compare in 

absolute terms because of differences in definitions 

across the forecasting groups. For 2015, the AE099 

reference case, DRI, and WEFA forecast slight 

growth in industrial prices, GRI a slight decline, and 

AGA a more significant decline. From 2015 to 2020 

the DRI forecast for the industrial price increases 

more significantly than the others, which show more 

moderate growth or a slight decline (in the AE099 

low economic growth case). 

There are significant differences in the projected 

growth rates for natural gas prices to electricity 

generators. GRI, WEFA, and AGA project a slight 

decline through 2015, whereas DRI projects slight 

growth and AE099 more significant growth, 

especially in the high economic growth case. 

Through 2020, the DRI forecast for gas prices to 

electricity generators rises more rapidly, coming 

close to the AE099 reference case forecast, with the 

WEFA and EIA forecasts showing only moderate or 

no growth. 

92 Energy Information Administration / Annual Energy Outlook 1999 
P.70 

Forecast Comparisons 

Table 19. Comparison of natural gas forecasts (trillion cubic feet, except where noted) 

Projection 

Lower 48 wellhead price 

(1997 dollars per thousand cubic feet) 

Dry gas productionb 

Net imports 

Consumption 

Residential 

Commercial11 

Industrial11 

Electricity generators f 

Other * 

End-use prices 

(1997 dollars per thousand cubic feet) 

Residential 

Commerciald 

Industriald 

Electricity generators f 

Lower 48 wellhead price 

(1997 dollars per thousand cubic feet) 

Dry gas production11 

Net imports 

Consumption 

Residential 

Commercial'1 

Industriald 

Electricity generators f 

Other* 

End-use prices 

(1997 dollars per thousand cubic feet) 

Residential 

Commerciald 

Industrial11 

Electricity generators 1 

Reference 

2.62 

26.11 

4.78 

30.81 

5.61 

3.86 

9.87 

8.42 

3.05 

5.95 

5.22 

3.32 

3.24 

2.68 

27.35 

5.02 

32.30 

5.77 

3.88 

10.24 

9.16 

3.24 

5.91 

5.24 

3.40 

3.31 

AE099 

Low 

economic 

growth 

2015 

2.29 

23.97 

4.54 

28.43 

5.31 

3.73 

9.20 

7.33 

2.85 

5.78 

4.96 

2.95 

2.91 

2020 

2.29 

24.93 

4.69 

29.53 

5.40 

3.72 

9.30 

8.12 

3.00 

5.72 

4.93 

2.93 

2.90 

High 

economic 

growth 

2.91 

28.01 

5.07 

32.99 

5.90 

3.97 

10.55 

9.34 

3.23 

6.11 

5.47 

3.65 

3.52 

3.09 

29.62 

5.26 

34.81 

6.13 

4.04 

11.17 

10.00 

3.48 

6.14 

5.56 

3.87 

3.71 

WEFA 

2.23 

24.83 

5.14 

30.12 

5.70 

3.51 

9.92 

8.52 

2.47 

6.21 

5.38 

3.58> 

2.67 

2.36 

26.70 

5.31 

32.18 

5.92 

3.63 

10.15 

9.83 

2.65 

6.13 

5.33 

3.68' 

2.76 

Other forecasts 

GRI 

2.36° 

27.31 

3.51" 

31.28 

5.66 

3.91 

12.95 

7.19 

1.59>> 

6.71 

5.72 

2.93 

2.61 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

DRI 

2.52 

23.47 

5.20 

28.51 

5.79 

3.55' 

8.99' 

7.55 d 

2.64 

6.61 

5.69 

3.73J 

2.93 

2.82 

23.33 

5.41 

28.58 

6.00 

3.53' 

8.99' 

7.40d 

2.67 

6.85 

5.93 

4.01] 

3.23 

AGA 

2.31" 

26.75 

4.15 

30.99 

6.23 

4.01 

10.84 

6.77 

3.14 

5.92' 

4.75' 

2.76<•* 

2.61' 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

"First purchase price or field acquisition price, because severance taxes and gathering charges are included. 

'Does not include supplemental fuels. 

Includes supplemental fuels. 

''includes gas consumed in cogeneration. 

•Does not include cogenerators. 

Includes independent power producers and does not include cogenerators. 

Includes lease and plant fuels and pipeline fuel. 

^Includes only transportation use. 

'Does not include certain State and local taxes levied on customers. 

•ton-system sales or system gas (i.e., does not include gas delivered for the account of others). 

*Volume-weighted average of "system" gas and "transportation" gas. 

NA = Not available. 

Note: Assumed conversion factors: electricity generators, 1,022 Btu per cubic foot; other end-use sectors, 1,029 Btu per cubic foot; not 

imports, 1,022 Btu per cubic foot; production and other consumption, 1,028 Btu per cubic foot. 

Sources: AE099-. AE099 National Energy Modeling System, runs AEO99B.D100198A (reference case), LMAC99.D100198A (low 

economic growth case), and HMAC99.D100198A (high economic growth case). WEFA: The WEFA Group, Natural Gas Outlook (1998). 

GRI: Gas Research Institute, GRI Baseline Projection of U.S. Energy Supply and Demand, 1999 Edition (August 1998). 

DRI: DRI/McGraw-Hill, WorW Energy Service: U.S. Outlook (April 1998). AGA: American Gas Association, 1998 AGA-TERA Base Case 

(July 1998). 

Energy Information Administration / Annual Energy Outlook 1999 93 

(A 
Forecast Comparisons 

P.71 

Petroleu m 

Projected prices for crude oil in the AE099 low and 

high oil price cases bound the 2010 and 2020 

projections in five other petroleum forecasts 

(Table 20)—-the AE099 reference case, WEFA, GRI, 

DRI, and the Independent Petroleum Association of 

America (IPAA) (April 1998). Comparisons with 

GRI and IPAA forecasts, which do not extend to 

2020, apply only to 2010. The AE099 reference case 

oil price projection for 2010 is $1.55 above that of 

WEFA, $2.54 above that of DRI, and $3.80 above 

that of GRI. By 2020 the AE099 reference case oil 

price falls between the two other forecasts—$1.41 

above WEFA and $0.95 below DRI. 

The AE099 reference case projection for domestic oil 

production in 2010 falls between the WEFA and DRI 

projections but is 0.50 million barrels per day short 

of the GRI and IPAA projections. The GRI projection 

reflects natural gas liquids (NGL) production, which 

is higher than in any other case, while IPAA reflects 

the second highest production of both crude oil and 

NGL. As a result, the GRI and IPAA projections of 

total domestic production in 2010 are slightly higher 

than even the AE099 high oil price case. The AE099 

reference case projection for 2020 is comparable to 

the DRI and WEFA forecasts. All three projections 

are bounded by the AE099 low and high oil price 

cases. 

The three AE099 cases reflect relatively high 

projections for petroleum demand in 2010. The low 

oil price and reference case projections are higher 

than the four other cases, and the high oil price 

projection is higher than the IPAA, GRI, and WEFA 

forecasts. Demand growth in AE099 is relatively 

slow between 2010 and 2020, and by 2020 the 

AE099 projections are comparable to the DRI and 

WEFA forecasts. 

Net petroleum imports in the AE099 reference and 

low price cases are well above the levels of the other 

forecasts. The projected percentage of petroleum 

consumption from imports, which is an indicator of 

the relative direction of production, net imports, and 

consumption, is also highest in the AE099 low oil 

price case, followed by the reference case. For 2010 

the import share of consumption ranges from 53 

percent (IPAA) to 65 percent in the AE099 low oil 

price case. The low IPAA import share reflects 

stronger domestic production than in the other 

forecasts. The relatively high import share in the 

AE099 low oil price case reflects the lowest 

production and highest consumption projections. 

For 2020 the import shares range from 61 percent 

in the WEFA and AE099 high oil price cases to 

71 percent in the low price case. The WEFA and 

AE099 high oil price cases have the lowest import 

shares for different reasons; projected consumption 

is relatively high in the WEFA case, whereas 

production is high and demand is low in the AE099 

high oil price case. Although the AE099 reference 

case and DRI have similar import shares at 65 and 

64 percent, respectively, they have different import 

pictures. The AE099 reference case reflects net 

crude oil imports that are 1.96 million barrels per 

day higher than in the DRI forecast and petroleum 

product imports that are 1.61 million barrels per 

day lower than DRI. The different split between 

crude oil and product imports reflects a greater 

capacity for refining petroleum products in the 

AE099 reference case. 

94 Energy Information Administration /Annual Energy Outlook 1999 

70 
Forecast Comparisons 

Table 20. Comparison of petroleum forecasts (million barrels per day, except where noted) 

Projection 

AE099 

Reference 

Low 

world oil 

price 

High 

world oil 

price 

Other forecasts 

WEFA GRI DRI IPAA 

2010 

World oil price 

(1997 dollars per barrel) 21.30 14.57 27.33 19.75 17.50' 18.76 NA 

Crude oil and NGL production 

Crude oil 

Natural gas liquids 

Total net imports 

Crude oil 

Petroleum products 

Petroleum demand 

Motor gasoline 

Jet fuel 

Distillate fuel 

Residual fuel 

Other 

Import share of product supplied 

(percent) 

World oil price 

(1997 dollars per barrel) 

Crude oil and NGL production 

Crude oil 

Natural gas liquids 

Total net imports 

Crude oil 

Petroleum products 

Petroleum demand 

Motor gasoline 

Jet fuel 

Distillate fuel 

Residual fuel 

Other 

. Import share of product supplied 

(percent) 

7.74 

5.59 

2.15 

13.70 

10.97 

2.73 

22.69 

10.01 

2.46 

3.99 

0.72 

5.51 

60 

22.73 

7.41 

4.96 

2.45 

15.97 

11.97 

4.00 

24.66 

10.69 

3.03 

4.28 

0.83 

5.82 

65 

7.07 

4.96 

2.11 

15.46 

11.76 

3.70 

23.60 

10.20 

2.48 

4.11 

1.08 

5.72 

65 

14.57 

6.53 

4.12 

2.41 

18.35 

13.13 

5.22 

25.95 

11.01 

3.08 

4.47 

1.24 

6.15 

71 

8.22 

6.06 

2.16 

12.62 

10.05 

2.57 

22.13 

9.77 

2.44 

3.93 

0.66 

5.33 

57 

2020 

29.35 

7.94 

5.48 

2.46 

14.63 

11.50 

3.13 

23.96 

10.40 

2.96 

4.21 

0.78 

5.62 

61 

7.63 

5.44 

2.19 

12.06 

9.79 

2.27 

21.83 

8.74 

2.31 

4.03 

0.93 

5.82 

55 

21.32 

7.40 

4.90 

2.49 

15.19 

10.95 

4.24 

24.80 

9.61 

3.13 

4.39 

1.04 

6.64 

61 

8.24 

5.56 

2.68 

NA 

NA 

NA 

21.46 

8.72 

2.24 

3.98 

1.07 

5.45 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

7.99 

5.69>> 

2.30 

13.25 

9.92 

3.34 

22.15 

10.03 

2.32 

3.97 

0.98 

5.45 

58 

23.68 

7.42 

S.l&> 

2.24 

15.61 

10.01 

5.61 

24.57 

10.73 

2.76 

4.19 

0.92 

5.97 

64 

8.26 

5.95 

2.31 

11.57 

NA 

NA 

21.98 

9.46 

2.17 

4.14 

0.95 

5.26 

53 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

"Composite of U.S. refiners' acquisition cost. 

''Includes shale and other. 

NA = Not available. 

Sources: AE099-. AE099 National Energy Modeling System, runs AEO99B.D100198A (reference case), LWOP99.D100298B (low 

world oil price case), and HWOP99.D100298B (high world oil price case). WEFA: The WEFA Group, U.S. Energy Outlook (1998). GRI: 

Gas Research Institute, GRI Baseline Projection of U.S. Energy Supply and Demand, 1999 Edition (August 1998). DRI: DRl/McGrawHill, World Energy Service: U.S. Outlook (April 1998). IPAA: Independent Petroleum Association of America, IPAA Supply and Demand 

Committee Long-Run Report (April 1998). 

Energy Information Administration / Annual Energy Outlook 1999 95 

IL 
Forecast Comparisons 

P.73 

Coal 

Coal forecasts, by WEFA and DRI are similar to the 

AE099 projections (Table 21). Consumption by 

electricity generators in 2015 falls within the range 

spanned by the AE099 low economic growth, 

reference, and high economic growth cases (1,073 

to 1,148 million tons). Coal consumption in 2015 

at domestic coking plants is slightly higher in both 

the WEFA (26 million tons) and DRI (24 million 

tons) forecasts than in AE099 (21 to 22 million 

tons), reflecting the expectation that the replacement of coke-based steelmaking with electric arc 

technology, less coke-intensive methods with 

pulverized coal injection, and advanced non-cokebased methods will proceed more gradually than 

projected in AE099. WEFA and DRI project 

industrial/other coal consumption in 2015 at values 

that tend toward the lower end of the AE099 range: 

73 and 88 million tons, respectively. The AE099 

range is from 77 through 86 to 94 million tons. The 

difference is largely attributable to differing views of 

consumption for cogeneration. 

Total domestic demand ranges from 1,200 million 

tons (WEFA) to 1,247 million tons (DRI), whereas 

AE099 ranges from 1,172 to 1,263 million tons. The 

WEFA forecast has an optimistic outlook for net coal 

exports, showing 103 million tons, while DRI has 79 

million tons and AE099 has 84 million tons in 2015. 

The difference stems from different views of the 

competitiveness of U.S. mines in a world market 

where competitors with low labor costs and undeveloped resources are further aided by the persistent 

strength of the dollar in international markets. 

Production forecasts follow from the differences in 

projected demand, with WEFA suggesting 1,300 

million tons in 2015 and DRI 1,327 million tons. 

AE099 brackets these values by projecting 1,253 

(low economic growth case), 1,294 (reference case) 

and 1,346 million tons (high economic growth case). 

Although the coal production and consumption 

values are similar, WEFA forecasts minemouth and 

delivered prices that are about 6 to 10 cents per 

million Btu higher than those in AE099, while 

DRI's delivered price (DRI does not forecast 

minemouth prices) is another 8 cents per million 

Btu above WEFA's. Coal's price advantage relative 

to natural gas at existing steam boilers may exceed 

20 cents per million Btu, so that smaller price 

differences have little effect on the quantity 

demanded. The different price forecasts arise from 

different expectations of labor productivity improvements in mining and from the different market 

shares projected for the very low cost, low-sulfur 

coals of the Powder River Basin. 

In 2020, WEFA and DRI project production totals 

that lie between those forecast for the reference and 

high economic growth cases in AE099, stemming 

from a different view of total demand and interfuel 

competition. However, the entire range is bracketed 

by the AE099 high and low growth cases, with 

projected production of 1,281 and 1,447 million tons, 

respectively. WEFA and DRI again have slightly 

higher coking coal consumption, although their 

industrial consumption forecasts compare closely 

with the AE099 low growth and reference cases. 

Differences in net exports follow the pattern established in 2015, with AE099 and DRI projecting 86 

and 80 million tons, respectively, and WEFA 119 

million tons. Again, delivered prices are as much as 

14 (WEFA) to 20 (DRI) cents per million Btu above 

the AE099 prices, but they have little effect on 

demand. Other than the differences in export 

tonnage and in minemouth and delivered prices, 

the AE099 values do not differ significantly from 

the WEFA and DRI forecasts. 

The GRI / Hill & Associates coal forecast (March 

1998) describes a different future, especially after 

2005 [74]. Although the potential impact of U.S. 

implementation of the Kyoto Protocol on greenhouse 

gas emissions is specifically excluded, the authors 

incorporate the economic burdens that they project 

would be placed on coal consumption by full implementation of the proposals contained in the Clean 

Air Power Initiative, which would severely restrict 

emissions of particulates. The resulting forecast 

shows production growing as in the other forecasts 

until 2006. It declines to 957 million tons in 2015 

(AE099 ranges from 1,253 to 1,346 million tons in 

2015). By 2020, coal production has fallen to 938 

million tons, while that in the other forecasts rises to 

between 1,281 and 1,447 million tons. 

All elements of the GRI/Hill forecast are equally 

pessimistic. Net exports are projected at 59 million 

tons in 2015 and 56 million tons in 2020—about half 

the WEFA level. Domestic coking coal consumption 

falls to 19 million tons in 2015 and 16 million tons in 

96 Energy Information Administration / Annual Energy Outlook 1999 

73 
P.74 

Forecast Comparisons 

2020. And industrial coal consumption is only 67 

million tons in 2015 and 65 million tons in 2020 

(all sectors of domestic consumption are similarly 

depressed by the Clean Air Power Initiative). 

These low consumption levels are reached in spite of 

low delivered prices to the electricity sector: 95 cents 

per million Btu in 2015 and 92 cents per million Btu 

in 2020. The other forecasts range from 96 cents 

(AE099 low growth case) to 114 cents (DRI) per 

million Btu in 2015, and from 90 to 110 cents per 

million Btu in 2020 (again, the AE099 low growth 

case and DRI). The implication is that even if 

efficient production, vigorous competition, and 

declining real transportation costs keep coal's 

delivered prices low and declining, the costs of 

compliance with the Clean Air Power Initiative will 

blunt its competitive edge. 

Table 21. Comparison of coal forecasts (million short tons, except where noted) 

Projection 

Production 

Consumption by sector 

Electricity generation' 

Coking plants 

Industrial /other 

Total 

Net coal exports 

Minemouth price 

(1997 dollars per short ton) 

(1997 dollars per million Btu) 

Average delivered price, electricity 

(1997 dollars per short ton) 

(1997 dollars per million Btu) 

Production 

Consumption by sector 

Electricity generation" 

Coking plants 

Industrial /other 

Total 

Net coal exports 

Minemouth price 

(1997 dollars per short ton) 

(1997 dollars per million Btu) 

Average delivered price, electricity 

(1997 dollars per short ton) 

(1997 dollars per million Btu) 

Reference 

1,294 

1,103 

22 

86 

1,211 

84 

13.21 

0.63 

20.03 

0.99 

1,358 

1,166 

20 

89 

1,275 

86 

12.74 

0.62 

18.77 

0.93 

AE099 

Low 

economic 

growth 

2015 

1,253 

1,073 

22 

77 

1,172 

84 

12.98 

0.62 

19.44 

0.96 

2020 

1,281 

1,098 

20 

76 

1,195 

86 

12.47 

0.60 

18.03 

0.90 

High 

economic 

growth 

1,346 

1,148 

21 

94 

1,263 

84 

13.39 

0.64 

20.53 

1.01 

1,447 

1,242 

19 

102 

1,363 

86 

12.89 

0.62 

19.33 

0.96 

( 

WEFA 

1,300 

1,100 

26 

73 

1,200 

103 

15.13 

0.70 

21.78 

1.06 

1,368 

1,199 

24 

76 

1,299 

119 

14.95 

0.69 

21.42 

1.04 

Other forecasts 

GRUHill 

957 

801 

19 

67 

887 

59 

NA 

NA 

18.98 

0.95 

938 

789 

16 

65 

870 

56 

NA 

NA 

18.19 

0.92 

DRI 

1,327 

1.136 

24 

88 

1,247 

79 

NA 

NA 

23.33 

1.14 

1,389 

1,196 

21 

88 

1,305 

80 

NA 

NA 

22.52 

1.10 

" The DRI and AE099 forecasts for electricity generation include nonutility generators. Consumption by Industrial cogenerators is 

Included in industrial consumption. The WEFA values for electricity consumption have been adjusted by including consumption by 

nonutility generators (11.2 million tons In 2015 and 2020). 

NA = Not available. 

Btu = BriUsh thermal unit 

Sources: AE099: AE099 National Energy Modeling System, runs AEO99B.D100198A (reference case), LMAC99.D100198A (low 

economic growth case), and HMAC99.D100198A (high economic growth case). WEFA: The WEFA Group. U.S. Energy Outlook (1998). 

GRI/HiU: Gas Research Institute, Final Report, Coal Demand and Price Projections. Vol. I. GRI-98/0053.1 (March 1998). 

DRI: DRI/McGraw-Hill. Worid Energy Service: U.S. Outlook (April 1998). 

Energy Information Administration / Annual Energy Outlook 1999 97 

73