Introduction
This report presents the major assumptions of the National Energy Modeling
System (NEMS) used to generate the projections in the Annual Energy Outlook
20081 (AEO2008), including general features of the model structure, assumptions
concerning energy markets, and the key input data and parameters that are
the most significant in formulating the model results. Detailed documentation
of the modeling system is available in a series of documentation reports.2
The National Energy Modeling System
The projections in the AEO2008 were produced with the NEMS, which is developed
and maintained by the Office of Integrated Analysis and Forecasting of
the Energy Information Administration (EIA) to provide projections of domestic
energy-economy markets in the long term and perform policy analyses requested
by decisionmakers in the White House, U.S. Congress, offices within the
Department of Energy, including DOE Program Offices, and other government
agencies. The AEO projections are also used by analysts and planners in
other government agencies and outside organizations.
The time horizon of NEMS is approximately 25 years, the period in which
the structure of the economy and the nature of energy markets are sufficiently
understood that it is possible to represent considerable structural and
regional detail. Because of the diverse nature of energy supply, demand,
and conversion in the United States, NEMS supports regional modeling and
analysis in order to represent the regional differences in energy markets,
to provide policy impacts at the regional level, and to portray transportation
flows. The level of regional detail for the end-use demand modules is the
nine Census divisions. Other regional structures include production and
consumption regions specific to oil, natural gas, and coal supply and distribution,
the North American Electric Reliability Council (NERC) regions and subregions
for electricity, and the Petroleum Administration for Defense Districts
(PADDs) for refineries. Maps illustrating the regional formats used in
each module are included in this report. Only selected regional results
are presented in the AEO2008, which predominately focuses on the national
results. Complete regional and detailed results are available on the EIA
Forecasts and Analyses Home Page. (http://www.eia.gov/oiaf/aeo/index.html)
For each fuel and consuming sector, NEMS balances the energy supply and
demand, accounting for the economic competition between the various energy
fuels and sources. NEMS is organized and implemented as a modular system
(Figure 1). The modules represent each of the fuel supply markets, conversion
sectors, and end-use consumption sectors of the energy system. NEMS also
includes a macroeconomic and an international module. The primary flows
of information between each of these modules are the delivered prices of
energy to the end user and the quantities consumed by product, region,
and sector. The delivered prices of fuel encompass all the activities necessary
to produce, import, and transport fuels to the end user. The information
flows also include other data such as economic activity, domestic production,
and international petroleum supply availability.
The integrating module of NEMS controls the execution of each of the component
modules. To facilitate modularity, the components do not pass information
to each other directly but communicate through a central data storage location.
This modular design provides the capability to execute modules individually,
thus allowing decentralized development of the system and independent analysis
and testing of individual modules. This modularity allows use of the methodology
and level of detail most appropriate for each energy sector. NEMS solves
by calling each supply, conversion, and end-use demand module in sequence
until the delivered prices of energy and the quantities demanded have converged
within tolerance, thus achieving an economic equilibrium of supply and
demand in the consuming sectors. Solution is reached annually through the
projection horizon. Other variables are also evaluated for convergence
such as petroleum product imports, crude oil imports, and several macroeconomic
indicators.
Each NEMS component also represents the impact and cost of Federal legislation
and regulation that affect the sector and reports key emissions. NEMS generally
reflects all current legislation and regulation that are defined sufficiently
to be modeled as of December 31, 2008, such as the Energy Independence
and Security Act of 2007, the Energy Policy Act of 2005, the Working Families
Tax Relief Act of 2004, and the America Jobs Creation Act of 2004, and
the costs of compliance with regulations such as the Mobile Source Air
Toxics rule released by the Environmental Protection Agency on February
9, 2007 that establishes controls on gasoline, passenger vehicles, and
portable fuel containers designed to significantly reduce emissions of
benzene and other hazardous air pollutants. The NEMS components also reflect
selected State legislation and regulations where implementing regulations
are clear. The potential impacts of pending or proposed Federal and State
legislation, regulations, or standards—or of sections of legislation that
have been enacted but that require funds or implementing regulations that
have not been provided or specified—are not reflected in NEMS. A list of
the specific Federal and selected State legislation and regulations included
in the AEO, including how they are incorporated, is provided in Appendix
A.
Component Modules
The component modules of NEMS represent the individual supply, demand,
and conversion sectors of domestic energy markets and also include international
and macroeconomic modules. In general, the modules interact through values
representing the prices of energy delivered to the consuming sectors and
the quantities of end-use energy consumption. This section provides brief
summaries of each of the modules.
Macroeconomic Activity Module
The Macroeconomic Activity Module (MAM) provides a set of macroeconomic
drivers to the energy modules, and there is a macroeconomic feedback mechanism
within NEMS. Key macroeconomic variables used in the energy modules include
gross domestic product (GDP), disposable income, value of industrial shipments,
new housing starts, new light-duty vehicle sales, interest rates, and employment.
The module uses the following models from Global Insight, Inc. (GII): Macroeconomic
Model of the U.S. Economy, National Industry Model, and National Employment
Model. In addition, EIA has constructed a Regional Economic and Industry
Model to project regional economic drivers and a Commercial Floorspace
Model to project 13 floorspace types in 9 Census divisions. The accounting
framework for industrial value of shipments uses the North American Industry
Classification System (NAICS).
International Module
The International Module represents the response of world oil markets (supply
and demand) to assumed world oil prices. The results/outputs of the module
are a set of crude oil and product supply curves that are available to
U.S. markets for each case/scenario analyzed. The petroleum import supply
curves are made available to U.S. markets through the Petroleum Market
Module (PMM) of NEMS in the form of 5 categories of imported crude oil
and 17 international petroleum products, including supply curves for oxygenates
and unfinished oils. The supply-curve calculations are based on historical
market data and a world oil supply/demand balance, which is developed from
reduced form models of international liquids supply and demand (new to AEO2008), current investment trends in exploration and development, and
long-term resource economics for 221 countries/territories. The oil production
estimates include both conventional and unconventional supply recovery
technologies.
Residential and Commercial Demand Modules
The Residential Demand Module projects energy consumption in the residential
sector by housing type and end use, based on delivered energy prices, the
menu of equipment available, the availability of renewable sources of energy,
and housing starts. The Commercial Demand Module projects energy consumption
in the commercial sector by building type and nonbuilding uses of energy
and by category of end use, based on delivered prices of energy, availability
of renewable sources of energy, and macroeconomic variables representing
interest rates and floorspace construction.
Both modules estimate the equipment stock for the major end-use services,
incorporating assessments of advanced technologies, including representations
of renewable energy technologies and the effects of both building shell
and appliance standards, including the recently enacted provisions of the
EISA2007. The Commercial Demand Module incorporates combined heat and power
(CHP) technology. The modules also include projections of distributed generation.
Both modules incorporate changes to “normal” heating and cooling degree-days
by Census division, based on a 10-year average and on State-level population
projections. The Residential Demand Module projects that the average square
footage of both new construction and existing structures increase based
on trends in the size of new construction and the remodeling of existing
homes.
Industrial Demand Module
The Industrial Demand Module projects the consumption of energy for heat
and power and for feedstocks and raw materials in each of 21 industries,
subject to the delivered prices of energy and macroeconomic variables representing
employment and the value of shipments for each industry. As noted in the
description of the Macroeconomic Activity Module, the value of shipments
is based on NAICS. The industries are classified into three groups—energy-intensive
manufacturing, non-energy-intensive manufacturing, and nonmanufacturing.
Of the 8 energy-intensive industries, 7 are modeled in the Industrial Demand
Module, with components for boiler/steam/cogeneration, buildings, and process/assembly
use of energy. Bulk chemicals are further disaggregated to organic, inorganic,
resins, and agricultural chemicals. A generalized representation of cogeneration
and a recycling component are also included. The use of energy for petroleum
refining is modeled in the PMM, and the projected consumption is included
in the industrial totals.
Transportation Demand Module
The Transportation Demand Module projects consumption of fuels in the transportation
sector, including petroleum products, electricity, methanol, ethanol, compressed
natural gas, and hydrogen, by transportation mode, vehicle vintage, and
size class, subject to delivered prices of energy fuels and macroeconomic
variables representing disposable personal income, GDP, population, interest
rates, and industrial shipments. Fleet vehicles are represented separately
to allow analysis of the Energy Policy Act of 1992 (EPACT1992) and other
legislation and legislative proposals. EPACT2005 is used to assess the
impact of tax credits on the purchase of hybrid gas-electric, alternative-fuel,
and fuel-cell vehicles. The module also includes a component to assess
the penetration of alternative-fuel vehicles. The CAFE and biofuel representation
in the module reflect the provisions in the EISA2007.
The air transportation component explicitly represents air travel in domestic
and non U.S. markets and includes the industry practice of parking aircraft
in both domestic and international markets to reduce operating costs and
the movement of aircraft from passenger to cargo markets as aircraft ages.3
For air freight shipments, the model represents regional fuel use in narrow-body
and wide-body aircraft. An infrastructure constraint limits overall growth
in passenger and freight air travel to levels commensurate with industry-projected
infrastructure expansion and capacity growth.
Electricity Market Module
The Electricity Market Module (EMM) represents generation, transmission,
and pricing of electricity, subject to delivered prices for coal, petroleum
products, natural gas, and biofuels; costs of generation by all generation
plants, including capital costs; macroeconomic variables for costs of capital
and domestic investment; enforced environmental emissions laws and regulations;
and electricity load shapes and demand. There are three primary submodules—capacity
planning, fuel dispatching, and finance and pricing. Nonutility generation,
distributed generation, and transmission and trade are modeled in the planning
and dispatching submodules. The levelized cost of uranium fuel for nuclear
generation is incorporated directly in the EMM.
All specifically identified CAAA90 compliance options that have been promulgated
by the EPA are explicitly represented in the capacity expansion and dispatch
decisions; those that have not been promulgated (e.g., fine particulate
proposals) are not incorporated. All financial incentives for power generation
expansion and dispatch specifically identified in EPACT2005 have been implemented.
Several States, primarily in the Northeast, have recently enacted air emission
regulations that affect the electricity generation sector. Where firm State
compliance plans have been announced, regulations are represented in AEO2008.
Renewable Fuels Module
The Renewable Fuels Module (RFM) includes submodules representing renewable
resource supply and technology input information for central-station, grid-connected
electricity generation technologies, including conventional hydroelectricity,
biomass (wood, energy crops, and biomass co-firing), geothermal, landfill
gas, solar thermal electricity, solar photovoltaics (PV), and wind energy.
The RFM contains renewable resource supply estimates representing the regional
opportunities for renewable energy development. Investment tax credits
for renewable fuels are incorporated, as currently legislated in EPACT1992
and EPACT2005. EPACT1992 provides a 10-percent tax credit for business
investment in solar energy (thermal non-power uses as well as power uses)
and geothermal power; those credits have no expiration date. EPACT2005
increases the tax credit to 30 percent for solar energy systems installed
before January 1, 2009.
Production tax credits for wind, geothermal, landfill gas, and some types
of hydroelectric and biomass-fueled plants are also represented. They provide
a tax credit of up to 1.9 cents per kilowatthour for electricity produced
in the first 10 years of plant operation. For AEO2008, new plants coming
on line before January 1, 2009, are eligible to receive the credit.
Oil and Gas Supply Module
The Oil and Gas Supply Module (OGSM) represents domestic crude oil and
natural gas supply within an integrated framework that captures the interrelationships
among the various sources of supply: onshore, offshore, and Alaska by both
conventional and unconventional techniques, including natural gas recovery
from coalbeds and low-permeability formations of sandstone and shale. The
framework analyzes cash flow and profitability to compute investment and
drilling for each of the supply sources, based on the prices for crude
oil and natural gas, the domestic recoverable resource base, and the state
of technology. Oil and gas production functions are computed for 12 supply
regions, including 3 offshore and 3 Alaskan regions. The module also represents
foreign sources of natural gas, including pipeline imports and exports
to Canada and Mexico, and liquefied natural gas (LNG) imports and exports.
Crude oil production quantities are input to the Petroleum Market Module
(PMM) in NEMS for conversion and blending into refined petroleum products.
Supply curves for natural gas are input to the Natural Gas Transmission
and Distribution Module (NGTDM) for use in determining natural gas prices
and quantities. International LNG supply sources and options for construction
of new regasification terminals in Canada, Mexico, and the United States
as well as expansions of existing U.S. regasification terminals are represented,
based on the projected regional costs associated with international natural
gas supply, liquefaction, transportation, and regasification and world
natural gas market conditions.
Natural Gas Transmission and Distribution Module
The Natural Gas Transmission and Distribution Module (NGTDM) represents
the transmission, distribution, and pricing of natural gas, subject to
end-use demand for natural gas and the availability of domestic natural
gas and natural gas traded on the international market. The module tracks
the flows of natural gas and determines the associated capacity expansion
requirements in an aggregate pipeline network, connecting the domestic
and foreign supply regions with 12 demand regions. The flow of natural
gas is determined for both a peak and off-peak period in the year. Key
components of pipeline and distributor tariffs are included in separate
pricing algorithms.
Petroleum Market Module
The Petroleum Market Module (PMM) projects prices of petroleum products,
crude oil and product import activity, and domestic refinery operations
(including fuel consumption), subject to the demand for petroleum products,
the availability and price of imported petroleum, and the domestic production
of crude oil, natural gas liquids, and biofuels (ethanol, biodiesel, biobutanol,
etc.). The module represents refining activities in the five PADDs. It
explicitly models the requirements of the EISA2007, the CAAA90, and the
costs of automotive fuels, such as conventional and reformulated gasoline,
and includes biofuels production for blending in gasoline and diesel
AEO2008 represents regulations that limit the sulfur content of all non-road
and locomotive/marine diesel to 15 ppm by mid-2012. The module also reflects
the renewable fuels standard (RFS) in the EISA2007 that requires the use
of 36 billion gallons per year of biofuels by 2022 with corn ethanol limited
to 15 billon gallons per year. Demand growth and regulatory changes necessitate
capacity expansion for refinery processing units. End-use prices are based
on the marginal costs of production, plus markups representing product
marketing and distribution costs and State and Federal taxes.4 Refinery
capacity expansion at existing sites is permitted in all five refining
regions modeled.
Fuel ethanol and biodiesel are included in the PMM, because they are commonly
blended into petroleum products. The module allows ethanol blending into
gasoline at 10 percent by volume or less (E10), as well as E85, a blend
of up to 85 percent ethanol by volume. Ethanol is produced primarily in
the Midwest from corn or other starchy crops, and may also be produced
from cellulosic material, such as switchgrass and poplar, in the future.
Biodiesel is produced from seed oil, imported palm oil, animal fats, or
yellow grease (primarily, recycled cooking oil).
Both domestic and imported ethanol count toward the RFS. Domestic ethanol
production is modeled from two feedstocks: corn and cellulosic materials.
Corn-based ethanol plants are numerous (more than 100 in operation, producing
more than 5 billion gallons annually) and are based on a well-known technology
that converts sugar into ethanol. Ethanol from cellulosic sources is a
new technology with no pilot plants in operation. However, the U.S. Department
of Energy has awarded grants (up to $385 million) in 2007 to construct
capacity totaling 147 million gallons per year. AEO2008 assumes that this
capacity will be operational in 2012. Imported ethanol may be produced
from cane sugar or bagasse, the cellulosic byproduct of sugar milling.
The sources of ethanol are modeled to compete on an economic basis and
to meet the EISA2007 renewable fuels mandate.
Fuels produced by gasification and Fischer-Tropsch synthesis are modeled
in the PMM, based on their economics relative to competing feedstocks and
products. The three processes modeled are coal-to-liquids (CTL), gas-to-liquids
(GTL), and biomass-to-liquids (BTL). CTL facilities are likely to be built
at locations close to coal supply and water sources, where liquid products
and surplus electricity could also be distributed to nearby demand regions.
GTL facilities may be built in Alaska but would compete with the Alaska
Natural Gas Transportation System for available natural gas resources.
BTL facilities are likely to be built where there are large supplies of
biomass such as crop residue and forestry waste. Since the BTL process
uses cellulosic feedstocks, it is also modeled as a choice to meet the
EISA2007 cellulosic biofuels requirement.
Coal Market Module
The Coal Market Module (CMM) simulates mining, transportation, and pricing
of coal, subject to end-use demand for coal differentiated by heat and
sulfur content. U.S. coal production is represented in the CMM by 40 separate
supply curves—differentiated by region, mine type, coal rank, and sulfur
content. The coal supply curves include a response to capacity utilization
of mines, mining capacity, labor productivity, and factor input costs (mining
equipment, mining labor, and fuel requirements). Projections of U.S. coal
distribution are determined by minimizing the cost of coal supplied, given
coal demands by demand region and sector, accounting for minemouth prices,
transportation costs, existing coal supply contracts, and sulfur and mercury
allowance costs. Over the projection horizon, coal transportation costs
in the CMM are projected to vary in response to changes in railroad productivity
and the cost of rail transportation equipment and diesel fuel.
The CMM produces projections of U.S. steam and metallurgical coal exports
and imports, in the context of world coal trade. The CMM determines the
pattern of world coal trade flows that minimizes the production and transportation
costs of meeting a specified set of regional world coal import demands,
subject to constraints on export capacities and trade flows. The international
coal market component of the module computes trade in 3 types of coal for
17 export and 20 import regions. U.S. coal production and distribution
are computed for 14 supply and 14 demand regions.
Cases for the Annual Energy Outlook 2008
In preparing projections for the AEO2008, EIA evaluated a wide range of
trends and issues that could have major implications for U.S. energy markets
between now and 2030. Besides the reference case, the AEO2008 presents
detailed results for four alternative cases that differ from each other
due to fundamental assumptions concerning the domestic economy and world
oil market conditions. These alternative cases include the following:
-
Economic Growth - In the reference case, real GDP grows at an average
annual rate of 2.4 percent from 2006 through 2030, supported by a 1.9 percent
per year growth in productivity in nonfarm business and a 0.9 percent per
year growth in nonfarm employment. In the high economic growth case, real
GDP is projected to increase by 3.0 percent per year, with productivity
and nonfarm employment growing at 2.4 percent and 1.2 percent per year,
respectively. In the low economic growth case, the average annual growth
in GDP, productivity and nonfarm employment is 1.8, 1.5 and 0.5 percent,
respectively.
- Price Cases – For purposes of the AEO2008, the world oil price is defined
by the price of light, low-sulfur crude oil delivered in Cushing, Oklahoma.
In the reference case, world oil prices decline gradually from current
levels to $57 per barrel in 2016 ($68 per barrel in nominal terms), as
expanded investment in exploration and development brings new supplies
to world markets. After 2016, real prices begin to rise as demand continues
to grow and higher cost supplies are brought to market. In 2030, the average
real price of crude oil is $70 per barrel in 2006 dollars, or about $113
per barrel in nominal dollars. The reference case represents EIA’s current
judgment about the most likely behavior of key OPEC members in the mid
term. In the projection, OPEC countries increase production at a rate
that keeps their market share of world liquids production at approximately
40 percent through 2030. The low and high price cases define a wide range
of potential price paths, which in 2030 span from $43 to $117 per barrel
in real dollars. These cases reflect differences in the assumptions about
world energy resource availability, production costs, and changes in OPEC
behavior. The low price case assumes greater world crude oil and natural
gas resources that are less expensive to produce and a future market where
all oil and natural gas production becomes more competitive and plentiful
than the reference case. The high price cases assumes that world crude
oil and natural gas resources, including OPEC’s, are lower and require
greater cost to produce than assumed in the reference case.
In addition to these four cases, and the reference case, 31 additional
alternative cases presented in Table 1 that explore the impact of changing
key assumptions on individual sectors.
Many of the side cases were designed to examine the impacts of varying
key assumptions for individual modules or a subset of the NEMS modules,
and thus the full market consequences, such as the consumption or price
impacts, are not captured. In a fully integrated run, the impacts would
tend to narrow the range of the differences from the reference case. For
example, the best available technology side case in the residential demand
assumes that all future equipment purchases are made from a selection of
the most efficient technologies available in a particular year. In a fully
integrated NEMS run, the lower resulting fuel consumption would have the
effect of lowering the market prices of those fuels with the concomitant
impact of increasing economic growth, thus stimulating some additional
consumption. The results of single model or partially integrated cases
should be considered the maximum range of the impacts that could occur
with the assumptions defined for the case.
Carbon Dioxide Emissions
Carbon dioxide emissions from energy use are dependent on the carbon content
of the fossil fuel, the fraction of the fuel consumed in combustion, and
the consumption of that fuel. The product of the carbon content at full
combustion and the combustion fraction yields an adjusted carbon emission
factor for each fossil fuel. The emissions factors are expressed in millions
of metric tons carbon dioxide emitted per quadrillion Btu of energy use,
or equivalently, in kilograms carbon dioxide per million Btu. The adjusted
emissions factors are multiplied by the energy consumption of the fossil
fuel to arrive at the carbon dioxide emissions projections.
For fuel uses of energy, the combustion fractions are assumed to be 1.00
in keeping with international conventions.5 Previously, a small fraction
of the carbon content of the fuel was assumed to remain unoxidized. The
carbon dioxide in nonfuel use of energy, such as for asphalt and petrochemical
feedstocks, is assumed to be sequestered in the product and not released
to the atmosphere. For energy categories that are mixes of fuel and nonfuel
uses, the combustion fractions are based on the proportion of fuel use.
Any carbon dioxide emitted by biogenic renewable sources, such as biomass
and alcohols, is considered balanced by the carbon dioxide sequestration
that occurred in its creation. Therefore, following convention, net emissions
of carbon dioxide from biogenic renewable sources are taken as zero, and
no emission coefficient is reported. In calculating carbon dioxide emissions
for motor gasoline, the direct emissions from renewable blending stock
(ethanol) is omitted. Similarly, direct emissions from biodiesel are omitted
from reported carbon dioxide emissions. Table 2 presents the assumed carbon
dioxide coefficients at full combustion, the combustion fractions, and
the adjusted carbon dioxide emission factors used for AEO2008.
Introduction Notes |
