Introduction
This report presents the major assumptions of the National Energy Modeling
System (NEMS) used to generate the projections in the Annual Energy Outlook
20061 (AEO2006), including general features of the model structure, assumptions
concerning energy markets, and the key input data and parameters that are
most significant in formulating the model results. Detailed documentation
of the modeling system is available in a series of documentation reports.2 A synopsis of NEMS, the model components, and the interrelationships of
the modules is presented in The National Energy Modeling System: An Overview3,
which is updated once every few years.
The National Energy Modeling System
The projections in the AEO2006 were produced with the National Energy Modeling
System. NEMS 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, 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 national results are presented
in the AEO2006, with the regional and other detailed results available
on the EIA Forecasting Home Page. (http://www.eia.doe.gov/oiaf/aeo/index.html)
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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 legislation
and environmental regulations that affect the sector and reports key emissions.
NEMS reflects all current legislation and environmental regulations that
are defined sufficiently to be modeled as of October 31, 2005, such as
the Energy Policy Act of 2005 and 1992 the Clean Air Act Amendments (CAAA),
and the costs of compliance with regulations such as the Clean Air Interstate
Rule (CAIR) and Clean Air Mercury Rule (CAMR) both of which were finalized
and published on the U.S. Environmental Protection Agency web page in March
2005 and in the Federal Register in May 2005. The potential impacts of
pending or proposed 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 the sectors. 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 provides a set of essential macroeconomic
drivers to the energy modules and a macroeconomic feedback mechanism within
NEMS. Key macroeconomic variables include gross domestic product (GDP),
industrial output, interest rates, disposable income, prices, new housing
stats, new light duty vehicle sales, and employment. This module uses the
following Global Insight models: 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 forecast regional
economic drivers and a Commercial Floorspace Model to forecast 13 floorspace
types in 9 Census Divisions. The accounting framework for industrial output
uses the North American Industry Classification System (NAICS).
International Module
The International Module represents world oil markets, calculating the
average world oil price and computing supply curves for five categories
of imported crude oil for the Petroleum Market Module (PMM) of NEMS, in
response to changes in U.S. import requirements. In addition, seventeen
international petroleum product supply curves, including curves for oxygenates
and unfinished oils, are also calculated and provided to the PMM. A world
oil supply/demand balance is created, including estimates for 16 oil consumption
regions and 19 oil production regions. The oil production estimates include
both conventional and nonconventional supply recovery technologies.
Residential and Commercial Demand Modules
The Residential Demand Module projects consumption of residential sector
energy 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 consumption of
commercial sector energy by building types 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 effects of both building shell and appliance standards. The commercial
module incorporates combined heat and power (CHP) technology. The modules
also include forecasts of distributed generation. Both modules incorporate
changes to “normal” heating and cooling degree-days by Census division
based on State-level population projections. The Residential Demand Module
projects that the average square footage of both new construction and existing
structures is increasing, based on trends in the size of new construction
and the remodeling of existing homes.
Industrial Demand Module
The Industrial Demand Module forecasts the consumption of energy for heat
and power and for feedstocks and raw materials in each of 18 industry groups,
subject to the delivered prices of energy and macroeconomic variables representing
employment and the value of shipments for each industry. The value of shipments
is based on the NAICS. The industries are classified into three groups—energy-intensive
manufacturing, non-energy-intensive manufacturing, and nonmanufacturing.
Of the eight energy-intensive industries, seven 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 representation
of cogeneration and a recycling component are also included. The use of
energy for petroleum refining is modeled in the Petroleum Market Module,
and the projected consumption is included in the industrial totals.
Transportation Demand Module
The Transportation Demand Module forecasts consumption of transportation
sector fuels, 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 the value of output for industries in the freight sector. Fleet
vehicles are represented separately to allow analysis of CAAA and other
legislative proposals, and the module includes a component to explicitly
assess the penetration of alternative-fuel vehicles. The air transportation
module explicitly represents the industry practice of parking aircraft
to reduce operating costs and the movement of aircraft from the passenger
to cargo markets as aircraft age. For airfreight shipments, the model employs
narrow-body and wide-body aircraft only. The model also uses an infrastructure
constraint that limits air travel growth 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 fuel cost of uranium fuel for
nuclear generation is directly incorporated into the EMM.
All specifically identified CAAA compliance options that have been promulgated
by the U.S. Environmental Protection Agency (EPA) are explicitly represented
in the capacity expansion and dispatch decisions; those that have not been
promulgated are not incorporated (e.g., fine particulate proposal). All
specifically iidenfied Energy Policy Act of 2005 financial incentives for
power generation expansion and dispatch 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 AEO2006.
Renewable Fuels Module
The Renewable Fuels Module (RFM) includes submodules representing natural
resource supply and technology input information for central-station, grid-connected
electricity generation technologies, including hydroelectricity, biomass,
geothermal, landfill gas, solar thermal electricity, solar photovoltaics,
and wind energy. The RFM contains natural resource supply estimates representing
the regional opportunities for renewable energy development. Investment
tax credits for renewable fuels are incorporated, as currently legislated
in the Energy Policy Acts of 1992 and 2005. They provide a 10-percent tax
credit for business investment in solar energy (thermal non-power uses
as well as power uses) and geothermal power. The credits have no expiration
date.
Production tax credits for wind, geothermal, landfill gas, and some types
of hydroelectric and biomass-fueled plants are also represented. These
provide a tax credit of up to 1.9 cents per kilowatt-hour tax credit for
electricity produced in the first 10 years of plant operation. New plants
that come online before January 1, 2008 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
between the various sources of supply: onshore, offshore, and Alaska by
both conventional and nonconventional techniques, including gas recovery
from coalbeds and low-permeability formations of sandstone and shale. This
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 at a level
of 12 supply regions, including 3 offshore and 3 Alaskan regions. This
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 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 regional expansions of domestic regasification
capacity are represented, based on the projected regional costs associated
with gas supply, liquefaction, transportation, regasification, and world
natural gas market conditions.
Natural Gas Transmission and Distribution Module
The 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 in an aggregate, domestic pipeline
network, connecting the domestic and foreign supply regions with 12 demand
regions. This capability allows the analysis of impacts of regional capacity
constraints in the interstate natural gas pipeline network and the identification
of pipeline capacity expansion requirements. The flow of gas is determined
for both peak and off-peak periods in the year. Key components of pipeline
and distributor tariffs are included in the pricing algorithms.
Petroleum Market Module
The Petroleum Market Module (PMM) forecasts 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 alcohol and biodiesel fuels. The
module represents refining activities in the five PADDs. The module uses
the same crude oil types as the International Module. It explicitly models
the requirements of CAAA and the costs of automotive fuels, such as conventional
and reformulated gasoline, and includes biofuels production for blending
in gasoline and diesel. AEO2006 reflects State legislation that bans or
limits the use of the gasoline blending component methyl tertiary butyl
ether (MTBE) in Arizona, California, Colorado, Connecticut, Illinois, Indiana,
Iowa, Kansas, Kentucky, Maine, Michigan, Minnesota, Missouri, Montana,
Nebraska, New Hampshire, New Jersey, New York, North Carolina, Ohio, Rhode
Island, South Dakota, Vermont, Washington, and Wisconsin. Furthermore,
MTBE is assumed to phase out by the end of 2008 as a result of EPACT2005,
which allows refiners to discontinue use of oxygenates in reformulated
gasoline, and on the concern over MTBE’s impact on surface water and groundwater
resources.
The nationwide phase-in of gasoline with an annual average sulfur content
of 30 ppm between 2005 and 2007, the diesel regulations that limit the
sulfur content to 15 ppm in highway diesel starting mid-2006 and in all
nonroad and locomotive/marine diesel by mid-2012, and the renewable fuels
standard of 7.5 billion gallons by 2012, are represented in AEO2006. Growth
in demand and costs of the regulations lead to capacity expansion for refinery-processing
units, assuming a financing ratio of 60-percent equity and 40-percent debt,
with a hurdle rate and an after-tax return on investment at about 9 percent.
End-use prices are based on the marginal costs of production, plus markups
representing product and distribution costs, and State and Federal taxes.
Refinery capacity expansion at existing sites may occur in all five refining
regions modeled.
Fuel ethanol and biodiesel are included in PMM because they are commonly
blended into petroleum products. The PMM assumes that ethanol will be
blended into gasoline at up to 10 percent by volume or into E85 at up
to 85 percent by volume, depending on relative market economics. Ethanol
is produced primarily in the Midwest from corn or other starchy crops,
and it is expected to be produced from cellulosic material in other regions
in the future. Biodiesel is produced from soybean oil or yellow grease,
which is primarily recycled cooking oil. Both soybean oil and yellow grease
biodiesel are assumed to be blended into highway diesel.
Coal Market Module
The Coal Market Module (CMM) simulates mining, and transportation, and
pricing of coal, subject to the end-use demand for coal differentiated
by heat, sulfur, and mercury content. U.S. coal production is represented
in the CMM using 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 in the CMM through
the use of a linear programming algorithm that determines the least-cost
supplies of coal for a given set of coal demands by demand region and sector,
accounting for transportation costs, existing coal supply contracts, and
sulfur and mercury allowance costs. Over the forecast horizon, coal transportation
costs in the CMM are projected to vary in response to changes in railroad
productivity and the user cost of rail transportation equipment.
The CMM produces projections of U.S. steam and metallurgical coal exports
and imports, in the context of world coal trade. The CMM’s linear programming
algorithm determines the pattern of world coal trade flows that minimizes
the production and transportation costs of meeting a pre-specified set
of regional world coal import demands, subject to constraints on export
capacities and trade flows.
U.S. coal production and distribution are computer for 154 supply and
14 demand regions. The international coal market component of the module
computes trade in 3 types of coal for 16 export and 20 import regions.
Cases for the Annual Energy Outlook 2006
In preparing projections for the AEO2006, 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 AEO2006 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 3.0 percent from 2003 through 2030, supported by a 2.3 percent
per year growth in productivity in nonfarm business and a 0.8 percent per
year growth in nonfarm employment. In the high economic growth case, real
GDP is projected to increase by 3.5 percent per year, with productivity
and nonfarm employment growing at 2.7 percent and 1.4 percent per year,
respectively. In the low economic growth case, the average annual growth
in GDP, productivity and nonfarm employment is 2.4, 1.8 and 0.7 percent,
respectively.
•
Price Cases – The world oil price in AEO2006 is represented by the average
U.S. refiner’s acquisition costs of imported low-sulfur light crude oil,
in order to be more consistent with prices typically reported in the media.
The low-sulfur light crude oil price is similar to the West Texas Intermediate
(WTI) crude oil price. In the reference case, world oil prices moderate
from current levels through 2015, before beginning to rise, reaching $57
per barrel in 2030 (in real 2004 dollars). The reference case represents
EIA’s current judgment regarding the expected behavior of OPEC producers
in the long term, adjusting production to keep world oil prices in a range
of $40 to $50 per barrel, in keeping with OPEC’s stated goal of keeping
potential competitors from eroding its market share. The low and high
world oil price cases define a wide range of potential price paths, which
in 2030 span from $34 to $96 per barrel. These cases reflect differences
in the assumptions about world energy resource availability and production
costs, not 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, 27 additional alternative cases presented
in Table 1 explore the impacts 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. As another example, the higher electricity demand side case
results in higher electricity prices due to the need to add additional
capacity to the grid. If this were a fully integrated run, the demand for
electricity would be reduced as a result of higher prices, thus moderating
somewhat the higher demand. 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.
All projections are generally based on Federal, State, and local laws and
regulations in effect on or before October 31, 2005. The potential impacts
of pending or proposed legislation, regulations, and standards—of sections
of legislation that have been enacted but that require implementing regulations
or appropriation of funds that are not provided or specified in the legislation
itself—are not reflected in the projections. Examples of Federal and
State legislation that is included are the Energy Policy Act of
2005, which, among other actions, includes mandatory energy conservation
standards, creates numerous business and public tax credits for energy
efficient appliances, hybrid vehicles, small biodiesel producers, and new
nuclear capacity, creates a renewable fuels standard, eliminates the oxygen
content requirement for Federal Reformulated Gasoline, extends royalty
relief for offshore oil and natural gas producers, and extends and expands the production tax credit for electricity generated from renewable
fuels; the Military Construction Appropriations Act of 2005, which contains
provisions to support construction of the Alaska natural gas pipeline,
including Federal loan guarantees during construction; the Working Families
Tax Relief Act of 2004, which includes an extension of the 1.8-cent PTC
for wind and closed-loop biomass to December 31, 2005; tax deductions for
qualified clean-fuel and electric vehicles; and changes in the rules governing
oil and gas well depletion; the American Jobs Creation Act of 2004, which
includes incentives and tax credits for biodiesel fuels, a modified depreciation
schedule for the Alaska natural gas pipeline, and an expansion of the 1.8-cent
renewable energy production tax credit (PTC) to include geothermal and
solar generation technologies; the Maritime Security Act of 2002, which
amended the Deepwater Port Act of 1974 to include offshore natural gas
facilities; State renewable portfolio standards, including the California
renewable portfolio standards passed on September 12, 2002; State of Alaska’s
Right-Of-Way Leasing Act Amendments of 2001, which prohibit leases across
State land for a “northern” or “over-the-top” natural gas pipeline route
running east from the North Slope to Canada’s MacKenzie River Valley; the
Outer Continental Shelf Deep Water Royalty Relief Act of 1995 and subsequent
provisions on royalty relief for new leases issued after November 2000
on a lease-by-lease basis; the Omnibus Budget Reconciliation Act of 1993,
which added 4.3 cents per gallon to the Federal tax on highway fuels; the
Energy Policy Act of 1992 (EPACT1992); the Clean Air Act Amendments of
1990 (CAAA90), which include new standards for motor gasoline and diesel
fuel and for heavy-duty vehicle emissions; the National Appliance Energy
Conservation Act of 1987; and State programs for restructuring of the electricity
industry.
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 dioxide
emission factor for each fossil fuel. The emissions factors are expressed
in millions of metric tons carbon equivalent of carbon dioxide emitted
per quadrillion Btu of energy use, or equivalently, in kilograms carbon
equivalent of carbon dioxide per million Btu. The adjusted emissions factors
are multiplied by the energy consumption of that fossil fuel to arrive
at the carbon dioxide emissions projections.
For fuel uses of energy, the combustion fractions are assumed to be 0.99
for liquid fuels and 0.995 for gaseous fuels. 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 emissions
from renewable blending stock (ethanol) is omitted.
Table 2 presents the carbon dioxide coefficients at full combustion, the
combustion fractions, and the adjusted carbon dioxide emission factors
used for AEO2006.
Introduction Tables
Introduction Notes |