Introduction
This report presents the major assumptions of the National Energy Modeling
System (NEMS) used to generate the projections in the Annual Energy Outlook
2010 [1] (AEO2010), 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 AEO2010 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 Annual Energy Outlook (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 AEO2010, 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).
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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 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 October 31, 2009, such as the American Recovery and
Reinvestment Act (ARRA) which was enacted in mid-February 2009, the Energy
Improvement and Extension Act of 2008 (EIEA2008) signed iinto law on October
3, 2008; the Food, Conservation, and Energy Act of 2008; the Energy Independence
and Security Act of 2007 (EISA2007), which was signed into law on December
19, 2007; and the cost of compliance with regulations (such as stationary
diesel regulations issued by the U.S. Environmental Protection Agency (EPA)
in July 2006). The AEO2010 models do not represent the Clean Air Mercury
Rule (CAMR), which was vacated and remanded by the D.C. Circuit Court of
the U.S. Court of Appeals on February 8, 2008, but it does represent State
requirements for the reduction of mercury emissions. The AEO2010 reference
case reflects the temporary reinstatement of the NOx and SO2 cap-and-trade
programs included in the Clean Air Interstate Rule (CAIR) [3] due to the
ruling issued by the United States Court of Appeals for the district of
Columbia on December 23, 2008. However, 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 implementing
regulations or appropriation of funds that are not provided or specified
in the legislation itself—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 receives energy-related indicators from
the NEMS energy components as part of the 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, sales of new light-duty vehicles (LDVs), interest rates,
and employment. Key energy indicators fed back to MAM include aggregate
energy prices and costs. The MAM module uses the following models from
IHS Global Insight: 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 Energy Module (IEM) uses assumptions of economic growth
and expectations of future U.S. and world petroleum liquids production
and consumption, by year, to project the interaction of U.S. and international
liquids market. The IEM computes world oil prices, provides a world crude-like
liquids supply curve, generates a worldwide liquids supply/demand balance
for each year of the projection period, and computes initial estimates
of crude oil and light and heavy petroleum product imports for the United
States by Petroleum Allocation Defense District (PADD) regions. The supply-curve
calculations are based on historical market data and a world liquids supply/demand
balance, which is developed from reduced-form models of international liquids
supply and demand, current investment trends in exploration and development,
and long-term resource economics for 221 countries/territories. The liquids
production estimates include both conventional and unconventional supply
recovery technologies.
In the interaction with the rest of NEMS, the IEM changes the world oil
price (WOP), which is defined as the price of foreign light, low sulfur
crude oil delivered to Cushing, Oklahoma, (Petroleum Allocation Defense
District 2) in response to changes in expected crude and product liquids
produced and consumed in the United States.
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 and cost 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 recent regional standards for furnaces,
heat pumps, and central air conditioners agreed to by manufacturers and
environmental interest groups. 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 an increase in the average square footage of both new construction
and existing structures, 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, feedstocks, and raw materials in each of 21 industries, subject
to the delivered prices of energy and the values of macroeconomic variables
representing employment and the value of shipments for each industry. As
noted in the description of the MAM, 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 eight energy-intensive industries, seven are modeled in the Industrial
Demand Module, with energy-consuming components for boiler/steam/cogeneration,
buildings, and process/assembly use of energy. A new bulk chemical model
was implemented for the AEO2010. The new model calculates the production
(in physical units), process shares, and process energy requirements for
26 specific chemicals and four aggregate groups of bulk chemicals. A generalized
representation of cogeneration and a recycling component also are 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 other legislation and legislative proposals specific
to those market segments. The transportation demand module also includes
a component to assess the penetration of alternative-fuel vehicles (AFVs).
EPACT2005 and the Energy Improvement and Extension Act of 2008 (EIEA2008)
are reflected in the assessment of the impacts of tax credits on the purchase
of hybrid gas-electric, alternative-fuel, and fuel-cell vehicles. The corporate
average fuel economy (CAFE) and biofuel representation in the module reflect
standards proposed by the National Highway Traffic Safety Administration
(NHTSA), the Environmental Protection Agency, and provisions in EISA2007.
The air transportation component of the Transportation Demand Module explicitly
represents air travel in domestic and foreign markets and includes the
industry practice of parking aircraft in both domestic and international
markets to reduce operating costs, as well as the movement of aging aircraft
from passenger to cargo markets. For passenger travel and air freight shipments,
the module represents regional fuel use in regional, narrow-body, and wide-body
aircraft. An infrastructure constraint, which is also modeled, can potentially
limit overall growth in passenger and freight air travel to levels commensurate
with industry-projected infrastructure expansion and capacity growth.
Electricity Market Module
There are three primary submodules of the Electricity Market Module —capacity
planning, fuel dispatching, and finance and pricing. The capacity planning
submodule uses the stock of existing generation capacity, the menu, cost
and performance of future generation capacity, expected fuel prices, expected
financial parameters, expected electricity demand, and expected environmental
regulations to project the optimal mix of new generation capacity that
should be added in future years. The fuel dispatching submodule uses the
existing stock of generation equipment, their O&M costs and performance,
the fuel prices to the electricity sector , electricity demand, and all
applicable environmental regulations to determine the least cost way to
meet that demand; the submodule also produces the transmission and pricing
of electricity. The finance and pricing submodule uses the capital costs,
fuel costs, and macroeconomic parameters, environmental regulations, along
with load shapes to estimate the generation costs from each technology.
All specifically identified options promulgated by the EPA for compliance
with the Clean Air Act Amendments of 1990 (CAAA90) 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 for CO2 that affect the electricity generation sector, and those regulations are
represented in AEO2010.
Although currently there is no Federal legislation in place that restricts
greenhouse gas (GHG) emissions, regulators and the investment community
have begun to push energy companies to invest in technologies that are
less GHG-intensive. The trend is captured in the AEO2010 reference case
through a 3-percentage-point increase in the cost of capital when investments
in new coal-fired power plants and new coal-to-liquids (CTL) plants without
carbon capture and sequestration (CCS) are evaluated.
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 (dedicated biomass plants and co-firing in existing coal plants),
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 (ITCs) for renewable fuels are incorporated, as
currently enacted, including a permanent 10-percent ITC for business investment
in solar energy (thermal nonpower uses as well as power uses) and geothermal
power (available only to those projects not accepting the production tax
credit [PTC] for geothermal power). In addition, the module reflects the
increase in the ITC to 30 percent for solar energy systems installed before
January 1, 2017, and the extension of the credit to individual homeowners
under EIEA2008.
PTCs for wind, geothermal, landfill gas, and some types of hydroelectric
and biomass-fueled plants also are represented. They provide a credit of
up to 2.0 cents per kilowatthour for electricity produced in the first
10 years of plant operation. For AEO2010, new wind plants coming on line
before January 1, 2013, are eligible to receive the PTC; other eligible
plants must be in service before January 1, 2014. As part of the ARRA,
plants eligible for the PTC may instead elect to receive a 30 percent ITC
or an equivalent direct grant. AEO2010 also accounts for new renewable
energy capacity resulting from State renewable portfolio standard (RPS)
programs, mandates, and goals.
Oil and Gas Supply Module
The Oil and Gas Supply Module 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 natural gas production activities are modeled for
12 supply regions, including 6 onshore, 3 offshore and 3 Alaskan regions.
Domestic crude oil production quantities, along with crude oil imports,
are used as inputs to the PMM in NEMS for conversion and blending into
refined petroleum products. Supply curves for natural gas are used as inputs
to the Natural Gas Transmission and Distribution Module for determining
natural gas prices and quantities.
Natural Gas Transmission and Distribution Module
The Natural Gas Transmission and Distribution Module 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 U.S. 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. The
module also represents foreign sources of natural gas, including pipeline
imports and exports to Canada and Mexico, and imports and exports of liquefied
natural gas (LNG).
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, and
biomass-to-liquids [BTL]). The module represents refining activities in
the five PADDs, as well as a less detailed representation of refining activities
in the rest of the world. It explicitly models the requirements of EISA2007
and CAAA90 and the costs of automotive fuels, such as conventional and
reformulated gasoline, and includes the production of biofuels for blending
in gasoline and diesel.
The PMM in NEMS represents regulations that limit the sulfur content of
all nonroad and locomotive/marine diesel to 15 parts per million (ppm)
by mid-2012. The module also reflects the renewable fuels standard (RFS)
in EISA2007 that requires the use of 36 billion gallons per year of biofuels
by 2022 if achievable, with corn ethanol credits limited to 15 billion
gallons per year [4] Demand growth and regulatory changes necessitate capacity
expansion for refinery processing units. U.S. end-use prices are based
on the marginal costs of production, plus markups representing the costs
of product marketing, importing, transportation, and distribution, as well
as applicable State and Federal taxes [5]. Refinery capacity expansion
at existing sites is permitted in each of the 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 or less by volume (E10) and up to 85 percent by
volume (E85) for use in flex-fueled vehicles. Although E15 is currently
being considered for certification as a viable motor fuel by the EPA, its
use in light duty vehicles has not been approved and thus is not modeled
in the AEO2010. In addition, the level of allowable non-E85 ethanol blending
in California has been raised from 5.7 percent to 10 percent in recent
regulatory changes [6] that have set a framework for E10 emissions standards
starting in year 2010.
Ethanol is produced primarily in the Midwest from corn or other starchy
crops, and in the future it may be produced from cellulosic material, such
as switchgrass , poplar, and crop residues. Biodiesel (diesel-like fuel
made in a transesterification process) is produced from seed oil, imported
palm oil, animal fats, or yellow grease (primarily, recycled cooking oil).
Renewable or “green” diesel is also modeled as a blending component in
petroleum diesel. Unlike the more common biodiesel, renewable diesel is
made by hydrogenation of vegetable oils or tallow and is completely fungible
with petroleum diesel. Imports and limited exports of these biofuels are
modeled in the PMM.
Fuels produced by gasification and Fischer-Tropsch synthesis are also 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 supplies and water sources, where liquid products
and surplus electricity could also be distributed to nearby demand regions.
In addition, a hybrid coal-biomass-to-liquids (CBTL) process was implemented
in the AEO2010, resulting in a production level of 380 million gallons
per year (MMGY) (the biomass-to-liquid part) by 2023.GTL facilities may
be built in Alaska, but they 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 residues and forestry waste. Because 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 region and sector, environmental restrictions, and accounting
for minemouth prices, transportation costs, and coal supply contracts.
Over the projection horizon, coal transportation costs in the CMM vary
in response to changes in the cost of rail investments.
The CMM produces projections of U.S. steam and metallurgical coal exports
and imports in the context of world coal trade, determining 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 regions and 20 import regions. U.S. coal production and distribution
are computed for 14 supply regions and 16 demand regions.
Cases for the Annual Energy Outlook 2010
In preparing projections for the AEO2010, EIA evaluated a wide range of
trends and issues that could have major implications for U.S. energy markets
between now and 2035. Besides the reference case, the AEO2010 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 2008 through 2035, supported by a 1.5 percent
per year growth in productivity in nonfarm business and a 0.6 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 AEO2010, 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 increase quickly after the recession
ends, reaching $95 per barrel in 2015 ($105 per barrel in nominal terms),
as growth in world oil demand rebounds and investment in production capacity
lags this expansion in demand. After 2015, real prices rise gradually
as demand continues to grow and higher cost supplies are brought to market.
In 2035, the average real price of crude oil is $133 per barrel in 2008
dollars, or about $224 per barrel in nominal dollars. The reference case
represents EIA’s current judgment regarding exploration and development
costs and accessibility of oil resources outside the United States. It
also assumes that OPEC producers will choose to maintain their share of
the market and will schedule investments in incremental production capacity
so that OPEC's conventional oil production will represent about 40 percent
of the world's total liquids production. The low and high price cases
define a wide range of potential price paths, which in 2035 span from about
$50 to over $200 per barrel in real dollars. These cases reflect differences
in the assumptions about access to energy resources, production costs,
and changes in OPEC behavior. The low price case assumes that OPEC countries
will increase their conventional oil production to obtain a 47 percent
share of total world liquids production, and that oil resources outside
the U.S. will be more accessible and/or less costly to produce (as a result
of technology advances, more attractive fiscal regimes, or both) than in
the Reference case. With these assumptions, conventional oil production
outside the U.S. is higher in the Low Oil Price case than in the Reference
case. The high price case assumes that OPEC countries will reduce their
production from the current rate, sacrificing market share as global liquids
production increases, and that oil resources outside the United States
will be less accessible and/or more costly 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 1.1 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. Previously, a small fraction
of the carbon content of the fuel was assumed to remain unoxidized. The
carbon 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 1.2 presents the assumed
carbon dioxide coefficients at full combustion, the combustion fractions,
and the adjusted carbon dioxide emission factors used for AEO2009.
Introduction Tables 
Introduction Notes |