Independent Statistics & Analysis

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U.S. Department of Energy

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Assumptions to the Annual Energy 

Outlook 2014

June 2014
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Introduction

This report presents the major assumptions of the National Energy Modeling System (NEMS) used to generate the projections 

in the Annual Energy Outlook 2014 [1] (AEO2014), 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

Projections in AEO2014 are generated using the NEMS [3], developed and maintained by the Office of Energy Analysis of the 

U.S. Energy Information Administration (EIA). In addition to its use in developing the Annual Energy Outlook (AEO) projections, 

NEMS is used to complete analytical studies for the U.S. Congress, the Executive Office of the President, other offices within 

the U.S. Department of Energy (DOE), and other federal agencies. NEMS is also used by nongovernment groups, such as the 

Electric Power Research Institute, Duke University, and Georgia Institute of Technology. In addition, AEO projections are used by 

analysts and planners in other government agencies and nongovernmental organizations.

The projections in NEMS are developed with the use of a market-based approach, subject to regulations and standards. For 

each fuel and consuming sector, NEMS balances energy supply and demand, accounting for economic competition across 

the various energy fuels and sources. The time horizon of NEMS extends to 2040. To represent regional differences in energy 

markets, the component modules of NEMS function at the regional level: the 9 Census divisions for the end-use demand 

modules; production regions specific to oil, natural gas, and coal supply and distribution; 22 regions and subregions of the 

North American Electric Reliability Corporation for electricity; and 9 refining regions within the 5 Petroleum Administration for 

Defense Districts (PADDs). Complete regional and detailed results are available on the EIA Analyses and Projections Home 

Page (www.eia.gov/analysis/).

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. The modular design also permits the use of the 

methodology and level of detail most appropriate for each energy sector. NEMS executes each of the component modules to 

solve for prices of energy delivered to end users and the quantities consumed, by product, region, and sector. The delivered 

fuel prices encompass all activities necessary to produce, import, and transport fuels to end users. The information flows also 

include such areas as economic activity, domestic production, and international petroleum supply. NEMS calls each supply, 

conversion, and end-use demand module in sequence until the delivered prices of energy and the quantities demanded have 

converged within tolerance, thereby achieving an economic equilibrium of supply and demand in the consuming sectors. A 

solution is reached for each year from 2013 through 2040. Other variables, such as petroleum product imports, crude oil 

imports, and several macroeconomic indicators, also are evaluated for convergence. 

Each NEMS component represents the effects and costs of legislation and environmental regulations that affect that sector. 

NEMS accounts for all combustion-related carbon dioxide (CO2) emissions, as well as emissions of sulfur dioxide (SO2), 

nitrogen oxides (NOx), and mercury from the electricity generation sector.

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.

The version of NEMS used for AEO2014 generally represents current legislation and environmental regulations, including recent 

government actions for which implementing regulations were available as of October 31, 2013, as discussed in the Legislation 

and Regulations section of the AEO. The potential effects of proposed federal and state legislation, regulations, or standards—

or of sections of legislation that have been enacted but require funds or implementing regulations that have not been provided 

or specified—are not reflected in NEMS. Many of the pending provisions are examined, however, in alternative cases included 

in AEO2014 or in other analysis completed by EIA. 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. 

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 3
Introduction

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 prices 

or expenditures for 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 LDVs, interest rates, and employment. Key energy indicators 

fed back to the MAM include aggregate energy prices and costs. The MAM 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 Energy Module

The International Energy Module (IEM) uses assumptions of economic growth and expectations of future U.S. and world 

petroleum and other liquids production and consumption, by year, to project the interaction of U.S. and international petroleum 

and other liquids markets. This module provides a world crude-like liquids supply curve and generates a worldwide oil supply/

demand balance for each year of the projection period. 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 petroleum and other liquids

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Figure 1. National Energy Modeling System

4 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Introduction

supply and demand, current investment trends in exploration and development, and long-term resource economics by country 

and territory. The oil production estimates include both petroleum and other liquids supply recovery technologies. The IEM also 

provides, for each year of the projection period, endogenous assumptions for petroleum products for import and export in the 

United States. The IEM, through interacting with the rest of NEMS, changes North Sea Brent and West Texas Intermediate prices 

in response to changes in expected production and consumption of crude-like liquids in the United States.

Residential and Commercial Demand Modules

The Residential Demand Module projects energy consumption in the residential sector by Census division, housing type, and 

end use, based on delivered energy prices, the menu of equipment available, the availability of renewable sources of energy, 

and changes in the housing stock. The Commercial Demand Module projects energy consumption in the commercial sector by 

Census division, building type, and category of end use, based on delivered prices of energy, availability of renewable sources of 

energy, and changes in commercial floorspace. 

Both modules estimate the equipment stock for the major end-use services, incorporating assessments of advanced 

technologies, representations of renewable energy technologies, and the effects of both building shell and appliance standards. 

The modules also include projections of distributed generation. The Commercial Demand Module also incorporates combined 

heat and power (CHP) technology. Both modules incorporate changes to “normal” heating and cooling degree-days by Census 

division, based on a 30-year historical trend 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 new construction 

and remodeling.

Industrial Demand Module

The Industrial Demand Module (IDM) projects the consumption of energy for heat and power, as well as the consumption 

of feedstocks and raw materials in each of 21 industry groups, subject to the delivered prices of energy and macroeconomic 

estimates of employment and the value of shipments for each industry. As noted in the description of the MAM, the 

representation of industrial activity in NEMS is based on the NAICS. The industries are classified into three groups—energyintensive manufacturing, non-energy-intensive manufacturing, and nonmanufacturing. Seven of eight energy-intensive 

manufacturing industries are modeled in the IDM, including energy-consuming components for boiler/steam/cogeneration, 

buildings, and process/assembly use of energy. Energy demand for petroleum and other liquids refining (the other energyintensive manufacturing industry) is modeled in the Liquid Fuels Market Module (LFMM) as described below, but the projected 

consumption is reported under the industrial totals. 

There are several updates and upgrades in the representations of select industries. AEO2014 includes an upgraded 

representation for the glass industry. Instead of assuming that technological development for a particular process occurs on 

a predetermined or exogenous path based on engineering judgment, these upgrades allow technological change in the glass 

industry to be modeled endogenously, using a more detailed process flow representation. The upgrade allows for explicit 

technological change, and therefore energy intensity, to respond to economic, regulatory, and other conditions. The combined 

cement and lime industries and aluminum industry were upgraded to process flow models in previous AEOs. The iron and steel 

and paper industries will be similarly upgraded in future AEOs.

Model input data associated with energy intensity were aligned with the Manufacturing Energy Consumption Survey 2010 

data. In the bulk chemicals model, behavior of naphtha and ethane prices was modified to better respond to oil price cases. The 

cement model was modified to include multi-channel burners that add flexibility for fuel mix, allowing the use of significant 

amounts of secondary fuels, such as alternative solid fuels including tires, plastics, wood, and waste. The model also includes 

more rapid penetration of energy-efficient grinding. In the food industry, shipments were categorized in more detail, to grain and 

oil seed milling, dairy, animal slaughter, and all other. Changes also were made to the nonmanufacturing data approach. Census, 

U.S. Department of Agriculture, and EIA’s Fuel Oil Kerosene Sales data were used to improve projections of petroleum product 

and natural gas consumption in agriculture, construction, and mining. CHP use is now differentiated by region and industry, 

based on EIA’s updated historical data. 

Transportation Demand Module

The Transportation Demand Module projects consumption of energy by mode and fuel—including petroleum products, 

electricity, methanol, ethanol, compressed natural gas (CNG), liquefied natural gas (LNG), and hydrogen—in the transportation 

sector, subject to delivered energy prices, macroeconomic variables such as GDP, and other factors such as technology adoption. 

The Transportation Demand Module includes legislation and regulations, such as the Energy Policy Act of 2005 (EPACT2005), 

the Energy Improvement and Extension Act of 2008 (EIEA2008), and the American Recovery and Reinvestment Act of 2009 

(ARRA2009), which contain tax credits for the purchase of alternatively fueled vehicles. Representations of LDV CAFE and GHG 

emissions standards, HDV fuel consumption and GHG emissions standards, and biofuels consumption reflect standards enacted 

by NHTSA and the EPA, as well as provisions in the Energy Independence and Security Act of 2007 (EISA2007).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 5
Introduction

The air transportation component of the Transportation Demand Module 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 and travel demand for three aircraft types: regional, narrow-body, and wide-body. 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. 

The Transportation Demand Module projects energy consumption for freight and passenger rail and marine vessels by mode, fuel, 

and census division, subject to macroeconomic variables such as the value and type of industrial shipments.

Electricity Market Module

There are three primary submodules of the Electricity Market Module (EMM)—capacity planning, fuel dispatching, and finance 

and pricing. The capacity expansion submodule uses the stock of existing generation capacity, the 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 types, their operation and maintenance costs and 

performance, 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 determines transmission and pricing of electricity. The finance and 

pricing submodule uses capital costs, fuel costs, macroeconomic parameters, environmental regulations, and load shapes to 

estimate generation costs for each technology. 

All specifically identified options promulgated by the EPA for compliance with the Clean Air Act Amendments of 1990 are 

explicitly represented in the capacity expansion and dispatch decisions. All financial incentives for power generation expansion 

and dispatch specifically identified in EPACT2005 have been implemented. Several States, primarily in the northeast, have 

enacted air emission regulations for CO2 that affect the electricity generation sector, and those regulations are represented in 

AEO2014. The AEO2014 Reference case also imposes a limit on CO2 emissions for specific covered sectors, including the electric 

power sector, in California, as represented in California’s AB 32. The AEO2014 Reference case reinstates the CAIR after the 

court vacated CSAPR in August 2012. CAIR incorporates a cap and trade program for annual emissions of SO2 and annual and 

seasonal emissions of NOx from fossil power plants. Reductions in mercury emissions from coal- and oil-fired power plants also 

are reflected through the inclusion of the Mercury and Air Toxics Standards for power plants, finalized by the EPA on December 

16, 2011. 

Although currently there is no Federal legislation in place that restricts GHG emissions, regulators and the investment community 

have continued to push energy companies to invest in technologies that are less GHG-intensive. The trend is captured in the 

AEO2014 Reference case through a 3-percentage-point increase in the cost of capital, when evaluating investments in new coalfired power plants, new coal-to-liquids (CTL) plants without carbon capture and storage, and pollution control retrofits.

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, and both onshore and offshore 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% 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% for solar energy systems installed before January 1, 2017. 

The extension of the credit to individual homeowners under EIEA2008 is reflected in the Residential and Commercial Demand 

Modules. 

PTCs for wind, geothermal, landfill gas, and some types of hydroelectric and biomass-fueled plants also are represented, based 

on the laws in effect on October 31, 2013. They provide a credit of up to 2.3 cents/kilowatthour (kWh) for electricity produced 

in the first 10 years of plant operation. For AEO2014, new plants under construction before January 1, 2014, are eligible to receive 

the PTC. Furthermore, eligible plants of any type will qualify if construction begins prior to the expiration date, regardless of when 

the plant enters commercial service. As part of ARRA2009, plants eligible for the PTC may instead elect to receive a 30% ITC or 

an equivalent direct grant. AEO2014 also accounts for new renewable energy capacity resulting from state renewable portfolio 

standard programs, mandates, and goals.

6 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Introduction

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 all production techniques, 

including natural gas recovery from coalbeds and low-permeability geologic formations. 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 six onshore, three offshore, and in three Alaska regions.

The Onshore Lower 48 Oil and Gas Supply Submodule evaluates the economics of future exploration and development projects for 

crude oil and natural gas plays. Crude oil resources include structurally reservoired resources (i.e., conventional) as well as highly 

fractured continuous zones, such as the Austin Chalk and Bakken shale formations. Production potential from advanced secondary 

recovery techniques (such as infill drilling, horizontal continuity, and horizontal profile) and enhanced oil recovery (such as CO2

flooding, steam flooding, polymer flooding, and profile modification) are explicitly represented. Natural gas resources include highpermeability carbonate and sandstone, tight gas, shale gas, and coalbed methane.

Domestic crude oil production volumes are used as inputs to the LFMM 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 (NGTDM) for 

determining natural gas wellhead prices and domestic production.

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 balances natural gas supply 

and demand, tracks the flows of natural gas, and determines the associated capacity expansion requirements in an aggregate 

pipeline network, connecting domestic and limited foreign supply sources with 12 lower 48 states regions. 

The 12 lower 48 states regions align with the nine Census divisions, with three subdivided, and Alaska handled separately. The flow 

of natural gas is determined for both a peak and off-peak period in the year, assuming a historically based seasonal distribution of 

natural gas demand. Key components of pipeline and distributor tariffs are included in separate pricing algorithms. The primary 

outputs of the module are delivered natural gas prices by region and sector, supply prices, and realized domestic natural gas 

production. The module also projects natural gas pipeline imports and exports to Canada and Mexico, as well as LNG imports and 

exports.

Liquids Fuels Market Module

The LFMM projects prices of petroleum products, crude oil and product import activity, as well as domestic refinery operations, 

subject to demand for petroleum products, availability and price of imported petroleum, and domestic production of crude oil, 

NGL, and biofuels—ethanol, biodiesel, biomass-to-liquids (BTL), CTL, gas-to-liquids (GTL), and coal-and-biomass-to-liquids 

(CBTL). Costs, performance, and first dates of commercial availability for the advanced liquid fuels technologies [9] are reviewed 

and updated annually. 

The module represents refining activities in eight domestic U.S. regions, and a Maritime Canada/Caribbean refining region 

(created to represent short-haul international refineries that predominantly serve U.S. markets). In order to better represent policy, 

import/export patterns, and biofuels production, the eight U.S. regions were defined by subdividing three of the five U.S. PADDs. 

All nine refining regions are defined below:

Region 1. PADD I – East Coast 

Region 2. PADD II – Interior 

Region 3. PADD II – Great Lakes

Region 4. PADD III – Gulf Coast 

Region 5. PADD III – Interior 

Region 6. PADD IV – Mountain 

Region 7. PADD V – California 

Region 8. PADD V – Other 

Region 9. Maritime Canada/Caribbean 

The LFMM models the costs of automotive fuels, such as conventional and reformulated gasoline, and includes production of 

biofuels for blending in gasoline and diesel. Fuel ethanol and biodiesel are included in the LFMM because they are commonly 

blended into petroleum products. The module allows ethanol blending into gasoline at 10% by volume (E10), 15% by volume 

(E15) in states that lack explicit language capping ethanol volume or oxygen content, and up to 85% by volume (E85) for use in 

flex-fuel vehicles. The module also includes a 16% by volume biobutanol/gasoline blend. Crude oil and refinery product imports 

are represented by supply curves defined by the NEMS IEM. Products also can be imported from refining region nine (Maritime 

Canada/Caribbean). Refinery product exports are represented by demand curves, also provided by the IEM.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 7
Introduction

Capacity expansion of refinery process units and nonpetroleum liquid fuels production facilities is also modeled in the LFMM. 

The model uses current liquid fuels production capacity, the cost and performance of each production unit, expected fuel and 

feedstock costs, expected financial parameters, expected liquid fuels demand, and relevant environmental policies to project the 

optimal mix of new capacity that should be added in the future.

The LFMM includes representation of the renewable fuels standard (RFS) specified in EISA2007, which mandates the use of 

36 billion gallons of ethanol equivalent renewable fuel by 2022. Both domestic and imported biofuels count toward the RFS. 

Domestic ethanol production is modeled for three feedstock categories: corn, cellulosic plant materials, and advanced feedstock 

materials. Starch-based ethanol plants are numerous (more than 175 are now in operation, with a total maximum sustainable 

nameplate capacity of more than 13 billion gallons annually), and are based on a well-known technology that converts starch 

and sugar into ethanol. Ethanol from cellulosic sources is a new technology with only a few small pilot plants in operation. 

Ethanol from advanced feedstocks—produced at ethanol refineries that ferment and distill grains other than corn, and reduce 

GHG emissions by at least 50%—is another new technology modeled in the LFMM. The LFMM also has the capability to 

produce biobutanol from a retrofitted corn ethanol facility, if economically competitive.

Fuels produced by Fischer-Tropsch synthesis and through a pyrolysis process are also modeled in the LFMM, based on their 

economics compared with competing feedstocks and products. The five processes modeled are CTL, CBTL, GTL, BTL, and 

pyrolysis.

Two California-specific policies are also represented in the LFMM: the low carbon fuel standard (LCFS) and the AB 32 cap-andtrade program. The LCFS requires the carbon intensity (amount of greenhouse gases/unit of energy) of transportation fuels 

sold for use in California to decrease according to a schedule published by the California Air Resources Board. California’s AB 

32 cap-and-trade program is established to help California achieve its goal of reducing CO2 emissions to 1990 levels by 2020. 

Working with other NEMS modules (IDM, EMM, and Emissions Policy Module), the LFMM provides emissions allowances and 

actual emissions of CO2 from California refineries, and NEMS provides the mechanism (carbon price) to trade allowances such 

that the total CO2 emissions cap is met.

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 41 separate supply curves—

differentiated by region, mine type, coal rank, and sulfur content. The coal supply curves respond to mining capacity, capacity 

utilization of mines, 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 production and transportation costs while meeting a specified 

set of regional coal import demands, subject to constraints on export capacities and trade flows. The international coal market 

component of the module computes trade in two types of coal (steam and metallurgical) for 17 export regions and 20 import 

regions. U.S. coal production and distribution are computed for 14 supply regions and 16 demand regions.

Annual Energy Outlook 2014 cases

In preparing projections for AEO2014, EIA evaluated a wide range of trends and issues that could have major implications for 

U.S. energy markets between now and 2040. Besides the Reference case, AEO2014 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, population grows by 0.7%/year, nonfarm employment by 0.8%/year, and labor productivity by 1.8%/

year from 2012 to 2040. Economic output as measured by real GDP increases by 2.4%/year from 2012 through 2040, and 

growth in real disposable income per capita averages 1.7%/year.

•	 The Low Economic Growth case assumes lower growth rates for population (0.6%/year) and labor productivity (1.4%/year), 

resulting in lower nonfarm employment (0.7%/year), higher prices and interest rates, and lower growth in industrial output. 

In the Low Economic Growth case, economic output as measured by real GDP increases by 1.9%/year from 2012 through 

2040, and growth in real disposable income per capita averages 1.3%/year. 

8 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Introduction

•	 The High Economic Growth case assumes higher growth rates for population (0.8%/year) and labor productivity (2.0%/year), 

resulting in higher nonfarm employment (1.0%/year). With higher productivity gains and employment growth, inflation and 

interest rates are lower than in the Reference case, and consequently economic output grows at a higher rate (2.8%/year) than 

in the Reference case (2.4%). Real disposable income per capita grows by 1.7%/year, the same as in the Reference case. 

Oil Price Cases – 

The benchmark oil price is the price for Brent crude oil, which better reflects the marginal price paid by refineries for imported 

light, sweet crude oil used to produce petroleum products for consumers. EIA continues to report the WTI price and the Imported 

Refiner Acquisition Cost.

The historical record shows substantial variability in oil prices, and there is arguably even more uncertainty about future prices in 

the long term. AEO2014 considers three oil price cases (Reference, Low Oil Price, and High Oil Price) to allow an assessment of 

alternative views on the future course of oil prices.

The Low and High Oil Price cases reflect a wide range of potential price paths, resulting primarily from variation in demand for 

petroleum and other liquid fuels in non-OECD countries due to different levels of economic growth. The Low and High Oil Price 

cases also reflect different assumptions about decisions by members of OPEC regarding the preferred rate of oil production and 

about the future finding and development costs and accessibility of non-OPEC oil resources.

•	 In the Reference case, real oil prices (in 2012 dollars) rise from $112/barrel in 2012 to $141/barrel in 2040. The Reference case 

represents EIA’s current judgment regarding exploration and development costs and accessibility of oil resources. Compared 

with AEO2013, EIA sees increasing production from non-OPEC countries, particularly the United States. However, EIA 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 oil production will represent between 39% and 44% of the world’s total petroleum and other 

liquids production over the projection period.

•	 In the Low Oil Price case, crude oil prices fall to $70/barrel (2012 dollars) in 2016, remain below $70/barrel through 2023, 

and stay below $75/barrel through 2040. The low price results from lower costs of production and lower demand from China 

and the Middle East compared with the Reference case. Crude oil production from across OPEC rises throughout the projection period in this case, displacing more expensive crude projected in the Reference case (including from the United States). 

Correspondingly, OPEC’s market share of petroleum rises steadily from 40% through 2015 to almost 53% in 2040. In addition, 

in this case, bitumen production in Canada and renewable fuels from Brazil and the United States see decreases in costs, leading to increased production. This keeps the OPEC market share to between 39% and 51% of the total liquids market. With the 

exceptions of China and the Middle East, which see reduced economic growth in this case, the lower prices generally lead to 

higher demand than projected in the Reference case.

•	 In the High Oil Price case, oil prices reach about $204/barrel (2012 dollars) in 2040. The high prices result primarily from 

higher costs of petroleum supply. Fewer structurally reservoired crude oil supplies are developed than in the Reference case, 

leading to increased development of more costly resources, including tight oil and bitumen. Higher prices also lead to significant increases in renewable liquid fuels and coal-to-liquid products as compared with the Reference case. In this case, OPEC’s 

share of world liquids production never exceeds the high of 42% that it reaches in 2012 and drops as low as 37%. The higher 

supply costs depress demand globally through 2028, but stronger growth in non-OECD countries than is projected in the Reference case leads to higher demand than in the Reference case, starting in these countries in 2029, and starting globally in 2037.

In addition to these cases, 25 additional alternative cases presented in Table 1.1 explore the impact of changing key assumptions 

on individual sectors.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 9
Introduction

Case name Description

Reference Real GDP grows at an average annual rate of 2.4% from 2012 to 2040. Crude oil price rise to 

about $141/barrel (2012 dollars) in 2040.

Low Economic Growth Real GDP grows at an average annual rate of 1.9% from 2012 to 2040. Other energy market 

assumptions are the same as in the Reference case.

High Economic Growth Real GDP grows at an average annual rate of 2.8% from 2012 to 2040. Other energy market 

assumptions are the same as in the Reference case.

Low Oil Price Low prices result from a combination of low demand for petroleum and other liquids in the nonOrganization for Economic Cooperative Development (non-OECD) nations and higher global 

supply. Lower demand is measured by lower economic growth compared with the Reference 

case. On the supply side, the Organization of the Petroleum Exporting Countries (OPEC) 

increases its liquids market share to 51%, and the costs of other liquids production technologies 

are lower than in the Reference case. Light, sweet crude oil prices fall to $70/barrel in 2016 

and rise slowly to $75/barrel in 2040.

High Oil Price High prices result from a combination of higher demand for liquid fuels in non-OECD nations 

and lower global supply. Higher demand is measured by higher economic growth compared 

with the Reference case. OPEC market share averages 37% throughout the projection. NonOPEC petroleum production expands more slowly in the short to middle term compared with 

relative to the Reference case. Crude oil prices rise to $204/barrel (2012 dollars) in 2040.

No Sunset Begins with the Reference case and assumes extension of all existing tax credits and policies 

that contain sunset provisions, except those requiring additional funding (e.g., loan guarantee 

programs) and those that involve extensive regulatory analysis, such as CAFE improvements 

and periodic updates of efficiency standards. Also includes extension of the $1.01/gallon 

ethanol subsidy and $1.00/gallon biodiesel subsidy to the end of the projection period.

Extended Policies Begins with the No Sunset case but excludes extension of the ethanol and biofuel subsidies 

that were included in the No Sunset case. Assumes an increase in the capacity limitations on 

the ITC for CHP and extension of the program. The case includes additional rounds of efficiency 

standards for residential and commercial products, as well as new standards for products not 

yet covered; adds multiple rounds of national building codes by 2026; and increases LDV and 

HDV fuel economy standards in the transportation sector.

High Rail LNG Assumes a higher LNG locomotive penetration rate into motive stock such that 100% of 

locomotives are LNG capable by 2037. 

Low Rail LNG Assumes a lower LNG locomotive penetration rate into motive stock, at a 1.0 average annual 

turnover rate for dual-fuel engines that can use up to 80% LNG.

High VMT Assumes higher licensing rates and travel demand for specific age and gender cohorts. Vehicle 

miles traveled per licensed driver in 2012 is 3% higher than in the Reference case, increasing to 

7% higher in 2027, and then declining to 3% above the Reference case in 2040.

Low VMT Assumes lower licensing rates and travel demand for specific age and gender cohorts. Vehicle 

miles traveled per licensed driver is 5% lower than in the Reference case for the full projection. 

Licensing rates stay constant at 2011 levels or decline from 2011 to 2040, specific to gender, 

age, and census division categories.

Accelerated Nuclear Retirements Assumes that all nuclear plants are limited to a 60-year life, uprates are limited to the 0.7 

gigawatts (GW) that have been reported to EIA, and no new additions beyond those planned in 

the Reference case. Nonfuel operating costs for existing nuclear plants are assumed to increase 

by 3%/year after 2013. 

Accelerated Coal Retirements Begins with the AEO2014 High Coal Cost case assumptions and also assumes that nonfuel 

operating costs for existing coal plants increase by 3%/year after 2013

Accelerated nuclear and Coal 

Retirements

Combines the assumptions in the Accelerated Nuclear Retirements and Accelerated Coal 

Retirements cases.

Electricity: Low Nuclear Begins with the Accelerated Nuclear Retirements case and combines with assumptions in the 

High Oil and Gas Resource and the No Sunset cases.

Table 1.1. Summary of AEO2014 cases

10 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Introduction

Table 1.1. Summary of AEO2014 cases (cont.)

Case name Description

Electricity: High Nuclear Assumes that all nuclear plants are life-extended beyond 60 years (except for 4.8 GW of 

announced retirement), and a total of 6.0 GW of uprates. New plants include those under 

construction and plants that have a scheduled U.S. Nuclear Regulatory Commission (NRC) or 

Atomic Safety and Licensing Board hearing.

Renewable Fuels: Low Renewable

Technology Cost

Capital costs for new non-hydro renewable generating technologies are 20% lower than 

Reference case levels through 2040, and biomass feedstocks are 20% less expensive for a 

given resource quantity. Capital costs for new ethanol, biodiesel, pyrolysis, and other BTL 

production technologies are 20% lower than Reference case levels through 2040, and the 

industrial sector assumes a higher rate of recovery for biomass byproducts from industrial 

processes.

Oil and Gas: Low Oil and Gas Resource Estimated ultimate recovery per shale gas, tight gas, and tight oil well is 50% lower than in the 

Reference case. All other resource assumptions remain the same as in the Reference case.

Oil and Gas: High Oil and Gas Resource Estimated ultimate recovery per shale gas, tight gas, and tight oil well is 50% higher and well 

spacing is 50% lower (or the number of wells left to be drilled is 100% higher) than in the 

Reference case. In addition, tight oil resources are added to reflect new plays or the expansion 

of known tight oil plays and the estimated ultimate recovery for tight and shale wells increases 

1%/year to reflect additional technological improvement. Also includes kerogen development, 

tight oil resources in Alaska, and 50% higher undiscovered resources in lower 48 offshore 

states, Alaska, and shale gas in Canada than in the Reference case.

Coal: Low Coal Cost Regional productivity growth rates for coal mining are approximately 2.3 percentage points 

per year higher than in the Reference case, and coal miner wages, mine equipment costs, and 

coal transportation rates are lower than in the Reference case, falling to about 25% below 

the Reference case in 2040. The price change for non-U.S. export supplies is assumed to be 

roughly 10% less than the price change projected for U.S. coal exports.

Coal: High Coal Cost Regional productivity growth rates for coal mining are approximately 2.3 percentage points 

per year lower than in the Reference case, and coal miner wages, mine equipment costs, and 

coal transportation rates are higher than in the Reference case, ranging between 24% and 31% 

above the Reference case in 2040. The price change for non-U.S. export supplies is assumed to 

be roughly 10% less than the price change projected for U.S. coal exports.

Integrated 2013 Demand Technology Assumes that future equipment purchases in the residential and commercial sectors are based 

only on the range of equipment available in 2013. Commercial and existing residential building 

shell efficiency is held constant at 2013 levels. Energy efficiency of new industrial plant and 

equipment is held constant at the 2014 level over the projection period.

Integrated Best Available Demand 

Technology

Assumes that all future equipment purchases in the residential and commercial sectors are 

made from a menu of technologies that includes only the most efficient models available in 

a particular year, regardless of cost. All residential building shells for new construction are 

assumed to be code compliant and built to the most efficient specifications after 2013, and 

existing residential shells have twice the improvement of the Reference case. New and existing 

commercial building shell efficiencies improve 50% more than in the Reference case by 2040. 

Industrial and transportation sector assumptions are the same as in the Reference case.

Integrated High Demand Technology Assumes earlier availability, lower costs, and higher efficiencies for more advanced residential 

and commercial equipment. For new residential construction, building code compliance 

is assumed to improve after 2013, and building shell efficiencies are assumed to meet 

ENERGY STAR requirements by 2023. Existing residential building shells exhibit 50% more 

improvement than in the Reference case after 2013. New and existing commercial building 

shells are assumed to improve 25% more than in the Reference case by 2040. Industrial sector 

assumes earlier availability, lower costs, and higher efficiency for more advanced equipment 

and a more rapid rate of improvement in the recovery of biomass byproducts from industrial 

processes. In the transportation sector, the characteristics of conventional and alternative-fuel 

LDVs reflect more optimistic assumptions about incremental improvements in fuel economy 

and costs, as well as battery electric vehicle costs. Freight trucks are assumed to see more rapid 

improvement in fuel efficiency. More optimistic assumptions for fuel efficiency improvements 

are also made for the air, rail, and shipping sectors.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 11
Introduction

Table 1.1. Summary of AEO2014 cases (cont.)

Case name Description

Energy Savings and Industrial 

Competitiveness Act

Begins with the Reference case and assumes passage of the energy efficiency provisions in 

S. 1392, including appropriation of funds at the levels authorized in the bill. Key provisions 

modeled include improved national building codes for new homes and commercial buildings 

and a rebate program for advanced industrial motor systems, assuming the bill’s passage in 

2014. For new residential construction, building shell efficiencies are assumed to improve by 

15% relative to IECC2009 by 2020, and building code compliance is assumed to improve. 

New commercial building shells are assumed to be 30% more efficient than ASHRAE 90.1-

2004 by 2020.

Low Electricity Demand This case was developed to explore the effects on the electric power sector if growth in sales 

to the grid remained relatively low. Begins with the Best Available Demand Technology case, 

which lowers demand in the building sectors, and also assumes greater improvement in 

industrial motor efficiency.

No GHG Concern No GHG emissions reduction policy is enacted, and market investment decisions are not 

altered in anticipation of such a policy.

GHG10 Applies a price for CO2 emissions throughout the economy, starting at $10 per metric ton in 

2015 and rising by 5%/year through 2040.

GHG25 Applies a fee for CO2 emissions throughout the economy, starting at $25 per metric ton in 

2015 and rising by 5%/year through 2040.

GHG25 and Low Gas Prices Combines GHG25 and High Oil and Gas Resource cases.

Carbon dioxide emissions 

CO2 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 CO2 factor for each fossil fuel. The emissions factors are expressed in millions of metric tons of 

carbon dioxide emitted per quadrillion Btu of energy use, or equivalently, in kilograms of CO2 per million Btu. The adjusted 

emissions factors are multiplied by the energy consumption of the fossil fuel to arrive at the CO2 emissions projections.

For fuel uses of energy, all of the carbon is assumed to be oxidized, so the combustion fraction is equal to 1.0 (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. In calculating CO2 emissions for motor gasoline, the direct emissions from 

renewable blending stock (ethanol) is omitted. Similarly, direct emissions from biodiesel are omitted from reported CO2

emissions.

Any CO2 emitted by biogenic renewable sources, such as biomass and alcohols, is considered balanced by the CO2

sequestration that occurred in its creation. Therefore, following convention, net emissions of CO2 from biogenic renewable 

sources are assumed to be zero in reporting energy-related CO2 emissions; however, to illustrate the potential for these 

emissions in the absence of any offsetting sequestration, as might occur under related land use change, the CO2 emissions 

from biogenic fuel use are calculated and reported separately.

Table 1.2 presents the assumed CO2 coefficients at full combustion, the combustion fractions, and the adjusted CO2 

emission factors used for AEO2014.

12 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Introduction

Table 1.2. Carbon dioxide emission factors

million metric tons carbon dioxide equivalent per quadrillion Btu

Fuel Type

Carbon Dioxide 

Coefficient at

Full Combustion

Combustion

Fraction

Adjusted 

Emission 

Factor

Petroleum

Propane

 Used as fuel 63.07 1.000 63.07

 Used as feedstock 61.07 0.200 12.61

Ethane used as feedstock 59.58 0.200 11.92

Butane used as feedstock 64.94 0.200 12.98

Isobutane used as feedstock 65.08 0.200 13.02

Natural gasoline used as feedstock 66.88 0.300 21.12

Motor gasoline (net of ethanol) 71.26 1.000 71.26

Jet fuel 70.88 1.000 70.88

Distillate fuel (net of biodiesel) 73.15 1.000 73.15

Residual fuel 78.80 1.000 78.80

Asphalt and road oil 75.61 0.000 0.00

Lubricants 74.21 0.500 37.11

Petrochemical feedstocks 71.02 0.410 29.11

Kerosene 72.31 1.000 72.31

Petroleum coke 102.12 0.956 97.60

Petroleum still gas 64.20 1.000 64.20

Other industrial 74.54 1.000 74.54

Coal

Residential and commercial 95.35 1.000 95.35

Metallurgical 93.71 1.000 93.71

Coke 117.81 1.000 117.81

Industrial other 93.98 1.000 93.98

Electric utility1 95.52 1.000 95.52

Natural gas

Used as fuel 53.06 1.000 53.06

Used as feedstock 53.06 0.437 23.21

Biogenic energy sources

Biomass 93.81 1.000 93.81

Biogenic waste 90.64 1.000 90.64

Biofuels heats and coproducts 93.81 1.000 93.81

Ethanol 68.42 1.000 68.42

Biodiesel 72.73 1.000 72.73

Liquids from biomass 73.15 1.000 73.15

Green liquids 73.15 1.000 73.15

1

Emission factors for coal used for electricity generation are specified by coal supply region and types of coal, so the average CO2 content for coal varies 

throughout the projection. The 2009 average was 95.52.

Source: U.S. Energy Information Administration, Monthly Energy Review, August 2013, DOE/EIA-0035(2013/08), (Washington, DC, August 2013).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 13
Introduction

Notes and sources

[1] U.S. Energy Information Administration, Annual Energy Outlook 2014 (AEO2014), DOE/EIA-0383(2014), (Washington, DC, 

April 2014).

[2] NEMS documentation reports are available on the EIA Homepage (www.eia.gov/analysis/model-documentation.cfm).

[3] U.S. Energy Information Administration, The National Energy Modeling System: An Overview 2009, DOE/EIA-0581(2009) 

(Washington, DC, October 2009), http://www.eia.gov/oiaf/aeo/overview.

14 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Macroeconomic Activity Module
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Macroeconomic Activity Module

The Macroeconomic Activity Module (MAM) represents interactions between the U.S. economy and energy markets. The 

rate of growth of the economy, measured by the growth in gross domestic product (GDP), is a key determinant of growth in 

the demand for energy. Associated economic factors, such as interest rates and disposable income, strongly influence various 

elements of the supply and demand for energy. At the same time, reactions to energy markets by the aggregate economy, 

such as a slowdown in economic growth resulting from increasing energy prices, are also reflected in this module. A detailed 

description of the MAM is provided in the EIA publication, Model Documentation Report: Macroeconomic Activity Module 

(MAM) of the National Energy Modeling System, (2013), (Washington, DC, April 10, 2013).

Key assumptions

The output of the U.S. economy, measured by GDP, is expected to increase by 2.4% between 2012 and 2040 in the Reference 

case. Two key factors help explain the growth in GDP: the growth rate of nonfarm employment and the rate of productivity 

change associated with employment. As Table 2.1 indicates, in the Reference case, real GDP grows by 2.5% from 2015-25 and 

2.4% growth for the final fifteen years of the projection. Both the high and low macroeconomic growth cases show roughly 

0.5 percentage point differences in growth as compared to the Reference case. Non-farm employment shows higher growth 

from 2012-2015 and then returns to its long-run trend growth. In the Reference case, nonfarm employment grows by 0.8% 

from 2012 to 2040 as compared to 1.0% and 0.7% in the High Growth and Low Growth cases, respectively. In the Reference 

case, productivity (measured as output per hour in nonfarm businesses) grows by 1.8% from 2012 to 2040; showing slower 

growth than the 2.0% growth experienced during the previous 30 years. Business fixed investment as a share of nominal GDP 

is expected to grow over the last 10 years of the projection. The resulting growth in the capital stock and the technology base of 

that capital stock helps to sustain productivity growth of 1.8% from 2012 to 2040.

The Census Bureau’s middle series population projection is used as a basis for population growth in the AEO2014. Total 

population is expected to grow by 0.7% per year between 2012 and 2040, and the share of population over 65 is expected to 

increase over time. However, the share of the labor force in the population over 65 is also projected to increase in the projection 

period. 

To achieve the Reference case’s long-run 2.4% economic growth, there is an anticipated steady growth in labor productivity. The 

improvement in labor productivity reflects the positive effects of a growing capital stock as well as technological change over 

time. Nonfarm labor productivity is expected to remain between 1.1 and 1.8% for the remainder of the projection period from 

2015 through 2040.

Table 2.1. Growth in gross domestic product, nonfarm employment and productivity

Assumptions 2012-2015 2015-2025 2025-2040 2012-2040 

Real GDP (Billion Chain-Weighted $2005)

 High Growth 3.0% 3.0% 2.5% 2.8%

 Reference 2.6% 2.5% 2.4% 2.4% 

 Low Growth 2.3% 1.7% 2.0% 1.9% 

Nonfarm Employment

 High Growth 2.0% 1.2% 0.7% 1.0%

 Reference 1.7% 0.8% 0.7% 0.8% 

 Low Growth 1.2% 0.7% 0.6% 0.7% 

Productivity

 High Growth 1.1% 2.2% 2.1% 2.0%

 Reference 0.9% 2.0% 1.9% 1.8%

 Low Growth 0.8% 1.5% 1.5% 1.4%

Source: U.S. Energy Information Administration, AEO2014 National Energy Modeling system runs: AEO2014.d102413A, LM2014.d112913A, and HM2014.

d112913A.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 17
Macroeconomic Activity Module

To reflect uncertainty in the projection of U.S. economic growth, the AEO2014 uses High and Low Economic Growth cases to 

project the possible impacts of alternative economic growth assumptions on energy markets. The High Economic Growth case 

incorporates higher population, labor force and productivity growth rates than the Reference case. Due to the higher productivity 

gains, inflation and interest rates are lower than the Reference case. Investment, disposable income and industrial production are 

greater. Economic output is projected to increase by 2.8 percent per year between 2012 and 2040. The Low Economic Growth 

case assumes lower population, labor force, and productivity gains, with resulting higher prices and interest rates and lower 

industrial output growth. In the Low Economic Growth case, economic output is expected to increase by 1.9 percent per year over 

the projection horizon.

18 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
International Energy Module
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International Energy Module

The National Energy Modeling System International Energy Module (IEM) simulates the interaction between U.S. and global 

petroleum markets. It uses assumptions of economic growth and expectations of future U.S. and world crude-like liquids 

production and consumption to estimate the effects of changes in U.S. liquid fuels markets on the international petroleum market. 

For each year of the forecast, the IEM computes Brent and WTI prices, provides a supply curve of world crude-like liquids, and 

generates a worldwide oil supply-demand balance with regional detail. The IEM also provides, for each year of the projection 

period, endogenous and exogenous assumptions for petroleum products for import and export in the United States.

Changes in the oil price (Brent) are computed in response to:

1. The difference between projected U.S. total crude-like liquids production and the expected U.S. total crude-like liquids 

production at the current oil price (estimated using the current oil price and the exogenous U.S. total crude-like liquids supply 

curve for each year). 

and

2. The difference between projected U.S. total crude-like liquids consumption and the expected U.S. total crude-like liquids 

consumption at the current oil price (estimated using the current oil price and the exogenous U.S. total crude-like liquids 

demand curve).

Key assumptions

The level of oil production by OPEC is a key factor influencing the oil price projections incorporated into AEO2014. Non-OPEC 

production, worldwide regional economic growth rates and the associated regional demand for oil are additional factors affecting 

the world oil price.

In the Reference case, real oil prices rise from a $112 per barrel (2012 dollars) in 2013 to $141 per barrel in 2040. The Reference 

case represents EIA’s current judgment regarding exploration and development costs and accessibility of oil resources. It also 

assumes that OPEC producers will choose to increase their share of the market and will schedule investments in incremental 

production capacity so that OPEC’s oil production will represent about 44 percent of the world’s total petroleum and other liquids 

production in 2040 compared with 40% in 2013. In the Low Oil Price case, crude oil prices are $75 per barrel (2012 dollars) in 

2040. In the Low Oil Price case, the low price results from a combination of low demand for petroleum and other liquids in the 

non-OECD nations and higher global supply. Lower demand is measured by lower economic growth relative to the Reference case. 

The OECD projections are affected only by the price impact. On the supply side, OPEC countries increase their oil production to 

obtain a 51% share of total world petroleum and other liquids production, and oil resources outside the United States are 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. In the High Oil Price case, oil prices reach about $204 per barrel (2012 dollars) in 2040. In the High Oil Price case, 

the high prices result from a combination of higher demand for petroleum and other liquid fuels in the non-OECD nations and 

lower global supply. Higher demand is measured by higher economic growth relative to the Reference case. The OECD projections 

are affected only by the price impact. On the supply side, OPEC market share averages 37 percent throughout the projection period 

and oil resources outside the United States are assumed to be less accessible and/or more costly to produce than in the Reference 

case.

OPEC oil production in the Reference case is assumed to increase throughout the projection (Figure 3), at a rate that enables the 

organization to achieve a 44 percent market share of the world’s total petroleum and other liquids in 2040. OPEC is assumed to 

be an important source of additional production because its member nations hold a major portion of the world’s total reserves— 

around 1,200 billion barrels, about 73 percent of the world’s estimated total, at the end of 2013. [1] Despite investment from 

foreign sources, Iraq’s oil production is not assumed to maintain high levels until after 2015 as infrastructure limitations as well as 

security and legislative issues are assumed to slow development for the next five years.

Non-U.S., non-OPEC oil production projections in the AEO2014 are developed in two stages. Projections of liquids production 

before 2015 are based largely on a project-by-project assessment of major fields, including volumes and expected schedules, with 

consideration given to the decline rates of active projects, planned exploration and development activity, and country- specific 

geopolitical situations and fiscal regimes. Incremental production estimates from existing and new fields after 2015 are estimated 

based on country-specific consideration of economics and ultimate technically recoverable resource estimates. The non-OPEC 

production path for the Reference case is shown in Figure 4.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 21
International Energy Module

Figure 2. World oil prices in three cases, 1995-2040

2012 dollars per barrel

Source: U.S. Energy Information Administration. AEO2014, National Energy Modeling System runs REF2014. 

D102413A, HIGHPRICE.D120613A, LOWPRICE.D120613A

Figure 3. OPEC total liquids production in the Reference case, 1995-2040

million barrels per day

OPEC = Organization of Petroleum Exporting Countries.

Source: U.S. Energy Information Administration. AEO2014 National Energy Modeling System run REF2014. 

D102413A.

22 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
International Energy Module

Figure 4 Non-OPEC total liquids production in the Reference case, 1995-2040

million barrels per day

OPEC = Organization of Petroleum Exporting Countries.

Source: U.S. Energy Information Administration. AEO2014 National Energiy Modeling System run REF2014. D102413A.

The non-U.S. oil production projections in the AEO2014 are limited by country-level assumptions regarding technically 

recoverable oil resources. Inputs to these resource estimates include the USGS World Petroleum Assessment of 2000 and oil 

reserves published in the Oil & Gas Journal by PennWell Publishing Company, a summary of which is shown in Table 3.1.

The Reference case growth rates for GDP for various regions in the world are shown in Table 3.2. The GDP growth rate 

assumptions for non-U.S. countries/regions are taken from Oxford Economic Model (October, 2012).

The values for growth in total liquids demand in the International Energy Module, which depend upon the oil price levels as 

well as GDP growth rates, are shown in Table 3.3 for the Reference case by regions.

Table 3.1. Worldwide oil reserves as of January 1, 2013

billion barrels

Region Proved Oil Reserves

 Western Hemisphere 538.0

 Western Europe 10.9

 Asia-Pacific 45.4

 Eastern Europe and Former Soviet Union (F.S.U.) 120.0

 Middle East 797.2

 Africa 127.7

 Total World 1,639.4

 Total OPEC 1,199.7

Source: Pennwell Corporation, Oil and Gas Journal, Vol 111. 12 (Dec. 2, 2013).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 23
International Energy Module

Table 3.2. Average annual real gross domestic product rates, 2010-40 

2005 purchasing power parity weights and prices

Region Average Annual Percentage Change

 OECD 2.22%

 OECD Americas 2.76%

 OECD Europe 1.82%

 OECD Asia 1.59%

 Non-OECD 4.73%

 Non-OECD Europe and Eurasia 3.77%

 Non-OECD Asia 5.44%

 Middle East 2.22%

 Africa 4.62%

 Central and South America 3.28%

 Total World 3.64%

Source: U.S. Energy Information Administration, National Energy Modeling System run REF2014.d102413A.

Table 3.3. Average annual growth rates for total liquids demand in the Reference case, 2010-40

billion barrels

Region Demand Growth

 OECD 0.06%

 OECD Americas 0.14%

 OECD Europe -0.11%

 OECD Asia 0.16%

 Non-OECD 1.84%

 Non-OECD Europe and Eurasia 1.77%

 Non-OECD Asia 2.38%

 Middle East 1.45%

 Africa 1.03%

 Central and South America 1.09%

 Total World 1.01%

Source: U.S. Energy Information Administration, National Energy Modeling System run REF2014.d102413A.

Notes and sources

[1] PennWell Corporation, Oil and Gas Journal, Vol. 111.12 (December 2, 2013).

24 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Residential Demand Module
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Residential Demand Module

The NEMS Residential Demand Module projects future residential sector energy requirements based on projections of the 

number of households and the stock, efficiency, and intensity of energy-consuming equipment. The Residential Demand Module 

projections begin with a base year estimate of the housing stock, the types and numbers of energy-consuming appliances 

servicing the stock, and the “unit energy consumption” (UEC) by appliance (in million Btu per household per year). The projection 

process adds new housing units to the stock, determines the equipment installed in new units, retires existing housing units, 

and retires and replaces appliances. The primary exogenous drivers for the module are housing starts by type (single-family, 

multifamily and mobile homes) and by Census division, and prices for each energy source for each of the nine Census divisions 

(see Figure 5).

The Residential Demand Module also requires projections of available equipment and their installed costs over the projection 

horizon. Over time, equipment efficiency tends to increase because of general technological advances and also because of federal 

and/or state efficiency standards. As energy prices and available equipment change over the projection horizon, the module 

includes projected changes to the type and efficiency of equipment purchased as well as projected changes in the usage intensity 

of the equipment stock.

Figure 5. United States Census Divisions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Pacific

East South Central

South Atlantic

Middle

Atlantic

New

England

West

South

Central

West

North

Central East

North

Central

Mountain

AK

WA

MT

ID WY

NV

UT

CO

AZ

NM

TX

OK

IA

KS MO

IL

IN

KY

TN

MS AL

FL

GA

SC

NC

WV

PA NJ

MD

DE

NY

CT

VT ME

RI

MA

NH

VA

WI

MI

OH

NE

SD

ND MN

AR

LA

OR

CA

HI

Middle Atlantic New England

East North Central

West North Central

Pacific West South Central

East South Central

South Atlantic

Mountain

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 27
Residential Demand Module

The end-use equipment for which stocks are modeled include those major end uses that often span several fuels, such as space 

conditioning (heating and cooling) equipment, water heaters, refrigerators, freezers, dishwashers, clothes washers, cookstoves, 

clothes dryers, light bulbs, furnace fans, as well as several miscellaneous electric loads: televisions and related equipment (settop boxes, home theater systems, DVD players, and video game consoles), computers and related equipment (desktops, laptops, 

monitors, networking equipment), rechargeable electronics, ceiling fans, coffee makers, dehumidifiers, microwaves, pool heaters 

and pumps, home security systems, and portable electric spas. In addition to the modeled end uses previously listed, the average 

energy consumption per household is projected for other electric and nonelectric uses. The fuels represented are distillate fuel 

oil, liquefied petroleum gas, natural gas, kerosene, electricity, wood, geothermal, and solar energy. The module’s output includes 

number of households, equipment stock, average equipment efficiencies, and energy consumed by service, fuel, and geographic 

location. 

One of the implicit assumptions embodied in the residential sector Reference case projections is that, through 2040, there will 

be no radical changes in technology or consumer behavior. No new regulations of efficiency beyond those currently embodied 

in law or new government programs fostering efficiency improvements are assumed. Technologies which have not gained 

widespread acceptance today will generally not achieve significant penetration by 2040. Currently available technologies will 

evolve in both efficiency and cost. In general, future technologies at the same efficiency level will be less expensive, in real dollar 

terms, than those available today. When choosing new or replacement technologies, consumers will behave similarly to the way 

they now behave, and the intensity of end uses will change moderately in response to price changes.

Key assumptions

Housing Stock submodule

An important determinant of future energy consumption is the projected number of households. Base year estimates for 2009 

are derived from the U.S. Energy Information Administration’s (EIA) Residential Energy Consumption Survey (RECS) (Table 

4.1). The projection for occupied households is done separately for each Census division. It is based on the combination of the 

previous year’s surviving stock with projected housing starts provided by the NEMS Macroeconomic Activity Module. The 

Housing Stock submodule assumes a constant survival rate (the percentage of households which are present in the current 

projection year, which were also present in the preceding year) for each type of housing unit: 99.7% for single-family units, 

99.5% for multifamily units, and 96.6% for mobile home units.

Projected fuel consumption is dependent not only on the projected number of housing units, but also on the type and geographic 

distribution of the houses. The intensity of space heating energy use varies greatly across the various climate zones in the United 

States. Also, fuel prevalence varies across the country—oil (distillate) is more frequently used as a heating fuel in the New 

England and Middle Atlantic Census divisions than in the rest of the country, while natural gas dominates in the Midwest. An 

example of differences by housing type is the more prevalent use of liquefied petroleum gas in mobile homes relative to other 

housing types.

Table 4.1. 2009 Households

Census Single-Family Units Multifamily Units Mobile Homes Total Units 

New England 3,374,597 2,052,063 84,437 5,511,097 

Middle Atlantic 9,287,267 5,536,739 435,344 15,259,350

East North Central 13,077,414 4,217,199 558,802 17,853,414

West North Central 6,153,386 1,406,903 503,817 8,064,106

South Atlantic 15,162,865 4,656,262 2,405,757 22,224,884

East South Central 5,480,023 945,846 658,471 7,084,340

West South Central 9,095,440 2,822,348 853,143 12,770,931

Mountain 5,983,945 1,258,517 662,813 7,905,276

Pacific 10,937,616 5,226,838 778,377 16,942,832

United States 78,552,553 28,122,715 6,940,961 113,616,230

Source: U.S. Energy Information Administration, 2009 Residential Energy Consumption Survey.

28 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Residential Demand Module

Technology Choice submodule

The key inputs for the Technology Choice submodule are fuel prices by Census division and characteristics of available equipment 

(installed cost, maintenance cost, efficiency, and equipment life). The Integrating Module of NEMS estimates fuel prices through 

an equilibrium simulation that balances supply and demand and passes the prices to the Residential submodule.

Prices combined with equipment UEC (a function of efficiency) determine the operating costs of equipment. Equipment 

characteristics are exogenous to the model and are modified to reflect both federal standards and anticipated changes in the 

market place. Table 4.2 lists capital costs and efficiency for selected residential appliances for the years 2010 and 2020.

Table 4.2. Installed cost and efficiency ratings of selected equipment

Equipment Type

Relative 

Performance1

2010 Installed 

Cost (2010$)2

2010 

Efficiency3

2020 

Installed 

Cost 

(2010$)2

2020 

Efficiency3

Approximate 

Hurdle Rate

Minimum $4,800 7.7 $4,950 8.2

Electric Heat Pump (heating component) Best $6,708 10.7 $8,125 10.8 25%

Minimum $2,500 0.78 $2,750 0.90

Natural Gas Furnace4 Best $2,625 0.98 $3,750 0.98 15%

Minimum $275 9.8 $295 11.0

Room Air Conditioner Best $455 12.0 $515 13.0 42%

Minimum $3,200 13.7 $3,550 14.0

Central Air Conditioner Best $4,500 21.0 $5,750 24.0 25%

Minimum $500 511 $525 408

Refrigerator5 Best $1,050 342 $1,250 327 10%

Minimum $600 0.90 $675 0.95

Electric Water Heater Best $1,370 2.35 $2,050 2.35 50%

Solar Water Heater6 N/A $5,320 N/A $7,300 N/A 30%

1

Minimum performance refers to the lowest-efficiency equipment available. Best refers to the highest-efficiency equipment available.

2

Installed costs are given in 2010 dollars in the original source document.

3

Efficiency measurements vary by equipment type. Electric heat pumps are based on Heating Seasonal Performance Factor (HSPF); natural gas furnaces 

are based on Annual Fuel Utilization Efficiency (AFUE); central air conditioners are based on Seasonal Energy Efficiency Ratio (SEER); room air conditioners 

are based on Energy Efficiency Ratio (EER); refrigerators are based on kilowatt-hours per year; and water heaters are based on Energy Factor (delivered Btu 

divided by input Btu).

4Values are for northern regions of United States.

5 Reflects refrigerator with top mounted freezer with 20.6 cubic feet nominal volume.

6

Values are for southern regions of United States.

Source: Updated Buildings Sector Appliance and Equipment Costs and Efficiency reports prepared for U.S. Energy Information Administration, Navigant 

Consulting, Inc. and SAIC (2013) www.eia.gov/analysis/studies/buildings/equipcosts/.

Table 4.3 provides the cost and performance parameters for representative distributed generation technologies. The model also 

incorporates endogenous “learning” for the residential distributed generation technologies, allowing for declining technology 

costs as shipments increase. For fuel cell and photovoltaic systems, learning parameter assumptions for the Reference case result 

in a 13%-reduction in capital costs each time the number of units shipped to the buildings sectors (residential and commercial) 

doubles. Capital costs for small wind, a relatively mature technology, only decline 3% with each doubling of shipments.

The Residential Demand Module projects equipment purchases based on a nested choice methodology. The first stage of the 

choice methodology determines the fuel and technology to be used. The equipment choices for cooling and water heating are 

linked to the space heating choice for new construction. Technology and fuel choice for replacement equipment uses a nested 

methodology similar to that for new construction, but includes (in addition to the capital and installation costs of the equipment) 

explicit costs for fuel or technology switching (e.g., costs for installing gas lines if switching from electricity or oil to gas, or costs 

for adding ductwork if switching from electric resistance heat to central heating types). Also, for replacements, there is no linking 

of fuel choice for water heating and cooking as is done for new construction. Technology switching across fuels upon replacement 

is allowed for space heating, air conditioning, water heating, cooking and clothes drying.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 29
Residential Demand Module

Once the fuel and technology choice for a particular end use is determined, the second stage of the choice methodology 

determines efficiency. In any given year, there are several available prototypes of varying efficiency (minimum standard, some 

intermediate levels, and highest efficiency). Efficiency choice is based on a functional form and coefficients which give greater 

or lesser importance to the installed capital cost (first cost) versus the operating cost. Generally, within a technology class, the 

higher the first cost, the lower the operating cost. For new construction, efficiency choices are made based on the costs of both 

the heating and cooling equipment and the building shell characteristics.

Once equipment efficiencies for a technology and fuel are determined, the installed efficiency for its entire stock is calculated.

Appliance Stock submodule

The Appliance Stock submodule is an accounting framework which tracks the quantity and average efficiency of equipment 

by end use, technology, and fuel. It separately tracks equipment requirements for new construction and existing housing units. 

For existing units, this module calculates the number of units which survive from previous years, allows certain end uses to 

further penetrate into the existing housing stock and calculates the total number of units required for replacement and further 

penetration. Air conditioning, dishwashing, and clothes drying are three major end uses not considered to be “fully penetrated.”

Table 4.3. Capital cost and performance parameters of selected residential distributed generation technologies

Technology Type

Year of 

Introduction

Average 

Generating 

Capacity (kWDC)

Electrical 

Efficiency

 Combined 

Efficiency 

(Elec. + 

Thermal 

Installed 

Capital Cost 

(2009 $ per 

kWDC)1

Service 

Life (Years)

Solar Photovoltaic

2010 3.5 0.150 N/A $7,117 30

2015 4.0 0.175 N/A $4,243 30

2025 5.0 0.197 N/A $3,266 30

2035 5.0 0.200 N/A $2,907 30

Fuel Cell

2010 10 0.364 0.893 $14,837 20

2015 10 0.429 0.859 $14,837 20

2025 10 0.456 0.842 $14,837 20

2035 10 0.479 0.828 $14,837 20

Wind

2010 2 0.13 N/A $7,802 30

2015 3 0.13 N/A $6,983 30

2025 3 0.13 N/A $6,234 30

2035 4 0.13 N/A $5,903 30

1

The original source documents presented solar photovoltaic costs in 2008 dollars, fuel cell and wind costs in 2010 dollars.

Source: EIA analysis, as well as technology-specific reports: Solar photovoltaic: Photovoltaic (PV) Cost and Performance Characteristics for Residential and 

Commercial Applications (ICF International, 2010). Fuel cell: Commercial and Industrial CHP Technology Cost and Performance Data Analysis for EIA 

(SENTECH Incorporated, 2010). Wind: The Cost and Performance of Distributed Wind Turbines, 2010-35 (ICF International, 2010).

30 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Residential Demand Module

Once a piece of equipment enters into the stock, an accounting of its remaining life begins. The decay function is based on Weibull 

distribution shape parameters that approximate linear decay functions. The estimated maximum and minimum equipment 

lifetimes used to inform the Weibull shape parameters are shown in Table 4.4. Weibull shapes allow some retirement before the 

listed minimum lifetime, as well as allow some equipment to survive beyond its listed maximum lifetime. It is assumed that, when 

a house is retired from the stock, all of the equipment contained in that house retires as well; i.e., there is no second-hand market 

for this equipment.

Table 4.4. Minimum and maximum life expectancies of equipment

Equipment Minimum Life Maximum Life

Heat Pumps 7 21

Central Forced-Air Furnaces 10 25

Hydronic Space Heaters 20 30

Room Air Conditioners 8 16

Central Air Conditioners 7 21

Gas Water Heaters 4 14

Electric Water Heaters 5 22

Cooking Stoves 16 21

Clothes Dryers 11 20

Refrigerators 7 26

Freezers 11 31

Source: Lawrence Berkeley National Laboratory. Baseline Data for the Residential Sector and Development of a Residential Forecasting Database, May 1994, 

and analysis of RECS 2001 data.

Fuel Consumption submodule

Energy consumption is calculated by multiplying the vintage equipment stocks by their respective UECs. The UECs include 

adjustments for the average efficiency of the stock vintages, short-term price elasticity of demand and “rebound” effects on usage 

(see discussion below), the size of new construction relative to the existing stock, people per household, shell efficiency and 

weather effects (space heating and cooling). The various levels of aggregated consumption (consumption by fuel, by service, etc.) 

are derived from these detailed equipment-specific calculations.

Equipment efficiency

The average energy consumption for most technology types is initially based on estimates derived from RECS 2009. As the stock 

efficiency changes over the projection period, energy consumption decreases in inverse proportion to efficiency. Also, as efficiency 

increases, the efficiency rebound effect (discussed below) will offset some of the reductions in energy consumption by increased 

demand for the end-use service. For example, if the stock average for electric heat pumps is now 10% more efficient than in 2005, 

then all else constant (weather, real energy prices, shell efficiency, etc.), energy consumption per heat pump would average about 

9% less.

Miscellaneous electric loads (MELs)

Unlike the technology choice submodule’s accounting framework, the energy consumption projection of several miscellaneous 

electric loads is characterized by assumed changes in per-unit consumption multiplied by assumed changes in the number of units. 

In this way, stock and UEC concepts are projected, but without the decision-making parameters or investment calculations of the 

technology choice submodule. The UECs of certain MELs may be further modified beyond their input assumption by factors such 

as income, square footage, and/or degree days, where relevant.

Adjusting for the size of housing units

Estimates for the size of each new home built in the projection period vary by type and region, and are determined by a projection 

based on historical data from the U.S. Bureau of the Census [3]. For existing structures, it is assumed that about 1% of households 

that existed in 2009 add about 600 square feet to the heated floor space in each year of the projection period [4]. The energy 

consumption for space heating, air conditioning, and lighting is assumed to increase with the square footage of the structure. This 

results in an increase in the average size of a housing unit from 1,644 to 1,858 square feet from 2009 through 2040.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 31
Residential Demand Module

Adjusting for weather and climate

Weather in any given year always includes short-term deviations from the expected longer-term average (or climate). 

Recognition of the effect of weather on space heating and air conditioning is necessary to avoid inadvertently projecting abnormal 

weather conditions into the future. The residential module adjusts space heating and air conditioning UECs by Census division 

using data on heating and cooling degree-days (HDD and CDD). Short-term projections are informed by the National Oceanic 

and Atmospheric Administration’s (NOAA) 15-month outlook from their Climate Prediction Center[5], which often encompasses 

the first forecast year. Projections of degree days beyond that are informed by a 30-year linear trend of each state’s degree days, 

which are then population-weighted to the Census division level. In this way, the projection accounts for projected population 

migrations across the nation and continues any realized historical changes in degree days at the state level.

Short-term price effect and efficiency rebound

It is assumed that energy consumption for a given end-use service is affected by the marginal cost of providing that service. That 

is, all else equal, a change in the price of a fuel will have an opposite, but less than proportional, effect on fuel consumption. The 

current value for the short-term elasticity parameter for non-electric fuels is -0.15 [6]. This value implies that for a 1% increase 

in the price of a fuel, there will be a corresponding decrease in energy consumption of -0.15%. Changes in equipment efficiency 

also affect the marginal cost of providing a service. For example, a 10% increase in efficiency will reduce the cost of providing the 

end-use service by 10%. Based on the short-term efficiency rebound parameter, the demand for the service will rise by 1.5%(-10% 

multiplied by -0.15). Only space heating, cooling, and lighting are assumed to be affected by both elasticities and the efficiency 

rebound effect. For electricity, the short-term elasticity parameter is set to -0.30 to account for successful deployment of smart 

grid projects funded under the American Recovery and Reinvestment Act of 2009.

Shell efficiency

The shell integrity of the building envelope is an important determinant of the heating and cooling load for each type of 

household. In the NEMS Residential Demand Module, the shell integrity is represented by an index, which changes over time 

to reflect improvements in the building shell. The shell integrity index is dimensioned by vintage of house, type of house, fuel 

type, service (heating and cooling), and Census division. The age, type, location, and type of heating fuel are important factors 

in determining the level of shell integrity. Homes are classified by age as new (post-2009) or existing. Existing homes are 

represented by the most recent RECS survey and are assigned a shell index value based on the mix of homes that exist in the base 

year. The improvement over time in the shell integrity of these homes is a function of two factors—an assumed annual efficiency 

improvement and improvements made when real fuel prices increase. No price-related adjustment is made when fuel prices 

fall. For new construction, building shell efficiency is determined by the relative costs and energy bill savings for several levels of 

heating and cooling equipment, in conjunction with the building shell attributes. The packages represented in NEMS range from 

homes that meet the International Energy Conservation Code (IECC) [7] to homes that are built with the most efficient shell 

components. Shell efficiency in new homes increases over time when energy prices rise, or the cost of more efficient equipment 

falls, all else equal.

Legislation and regulations

American Recovery and Reinvestment Act of 2009 (ARRA09)

The ARRA09 legislation passed in February 2009 provides energy efficiency funding for Federal agencies, State Energy Programs, 

and block grants, as well as a sizable increase in funding for weatherization. To account for the impact of this funding, it is 

assumed that the total funding is aimed at increasing the efficiency of the existing housing stock. The assumptions regarding the 

energy savings for heating and cooling are based on evaluations of the impact of weatherization programs over time. Further,

it is assumed each house requires a $2,600 investment to achieve the heating and cooling energy savings cited in [8] and that 

the efficiency measures last approximately 20 years. Assumptions for funding amounts and timing were revised downward 

and further into the future based on analysis of the weatherization program by the Inspector General of the U.S. Department of 

Energy [9].

The ARRA09 provisions remove the cap on the 30% tax credit for ground-source heat pumps, solar PV, solar thermal water 

heaters, and small wind turbines through 2016. Additionally, the cap for the tax credits for other energy efficiency improvements, 

such as windows and efficient furnaces, was increased to $1,500 through the end of 2010. Several tax credits were extended 

at reduced credit levels through the end of 2011 as part of the Tax Relief, Unemployment Insurance Reauthorization, and Job 

Creation Act of 2010. These tax credits were further extended through the end of 2013 as part of the American Taxpayer Relief 

Act of 2012, but since those tax credits were not in existence during 2012 and thus were not part of consumers’ decision-making 

process, these tax credits were only modeled for 2013, not for 2012.

32 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Residential Demand Module

Successful deployment of smart grid projects based on ARRA09 funding could stimulate more rapid investment in smart grid 

technologies, especially smart meters on buildings and homes, which would make consumers more responsive to electricity 

price changes. To represent this, the price elasticity of demand for residential electricity was increased for the services that have 

the ability to alter energy intensity (e.g., lighting).

Energy Improvement and Extension Act of 2008 (EIEA 2008)

EIEA 2008 extends and amends many of the tax credits that were made available to residential consumers in EPACT 2005. The 

tax credits for energy-efficient equipment can now be claimed through 2016, while the $2,000 cap for solar technologies has 

been removed. Additionally, the tax credit for ground-source (geothermal) heat pumps was increased to $2,000. The production 

tax credits for dishwashers, clothes washers, and refrigerators were extended by one to two years, depending on the efficiency 

level and product. See the EPACT 2005 section below for more details about product coverage.

Energy Independence and Security Act of 2007 (EISA 2007)

EISA 2007 contains several provisions that impact projections of residential energy use. Standards for general service 

incandescent light bulbs are phased in over 2012-2014, with a more restrictive standard specified in 2020. It is estimated that 

these standards require 29% less watts per bulb in the first phase-in, increasing to 67% in 2020. General service incandescent 

bulbs become substandard in the 2012-2014 period and during this time halogen bulbs serve as the incandescent option. 

These halogen bulbs then become substandard in the 2020 specification, reducing general service lighting options to compact 

fluorescent and light-emitting diode (LED) technologies.

Energy Policy Act of 2005 (EPACT05)

The passage of the EPACT05 in August 2005 provides additional minimum efficiency standards for residential equipment and 

provides tax credits to producers and purchasers of energy-efficient equipment and builders of energy-efficient homes. The 

standards contained in EPACT05 include: 190 watt maximum for torchiere lamps in 2006; dehumidifier standards for

2007 and 2012; and ceiling fan light kit standards in 2007. For manufactured homes that are 30% better than the latest code, 

a $1,000 tax credit can be claimed in 2006 and 2007. Likewise, builders of homes that are 50% better than code can claim a 

$2,000 credit over the same period. The builder tax credits and production tax credits are assumed to be passed through to 

the consumer in the form of lower purchase cost. EPACT05 includes production tax credits for energy-efficient refrigerators, 

dishwashers, and clothes washers in 2006 and 2007, with dollar amounts varying by type of appliance and level of efficiency 

met, subject to annual caps. Consumers can claim a 10% tax credit in 2006 and 2007 for several types of appliances specified 

by EPACT05, including: energy-efficient gas, propane, or oil furnaces or boilers, energy-efficient central air conditioners, air and 

ground source heat pumps, hot water heaters, and windows. Lastly, consumers can claim a 30% tax credit in 2006 and 2007 for 

purchases of solar PV, solar water heaters, and fuel cells, subject to a cap.

Residential alternative cases

Technology cases

In addition to the Reference case, the Residential Demand Module contributes alternate assumptions to three side cases 

developed to examine the effect of different assumptions of technology on energy use. These cases are devoted to technology 

assumptions in the demand sectors: the 2013 Demand Technology case, a High Demand Technology case, and a Buildings Best 

Available Technology case.

The 2013 Technology assumptions specify that all future equipment purchases are made based only on equipment available 

in 2013. These cases further assume that existing building shell efficiencies will not improve beyond 2013 levels. The 2013 

Technology assumptions are implemented in the 2013 Integrated Demand Technology case.

The High Technology assumptions include earlier availability, lower costs, and/or higher efficiencies for more advanced 

equipment than the Reference case. Equipment assumptions developed by engineering technology experts reflect the potential 

impact on technology given increased research and development into more advanced technologies [10]. In the High Technology 

cases, compliance efforts are increased after 2013 and all new construction is assumed to meet Energy Star specifications after 

2023. In addition, consumers are assumed to evaluate energy efficiency investments at a discount rate of 7% (in real dollar 

terms). The High Technology assumptions are implemented in the Integrated High Demand Technology case.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 33
Residential Demand Module

The Best Available Demand Technology case assumptions require that all equipment purchases from 2014 forward are based 

on the highest available efficiency in the High Technology case in a particular modeled year, disregarding the economic costs 

of such a case. This case is designed to show how much the choice of the highest-efficiency equipment could affect energy 

consumption. In this case, all new construction is built to the most efficient specifications after 2013. In addition, consumers are 

assumed to evaluate energy efficiency investments at a discount rate of 7%.

Policy cases

The No Sunset case assumes the extension of all existing energy policies and legislation that contain sunset provisions. For the 

residential sector, this primarily involves tax credits for distributed generation and efficient end-use equipment. The Extended 

Policy case assumes additional rounds of appliance standards for most end-use equipment while maintaining the No Sunset tax 

credit assumptions for distributed generation, solar water heaters, and geothermal heat pumps. Standard levels are established 

based on current Energy Star guidelines. The Extended Policy case also adds multiple rounds of building codes by 2028.

Notes and sources

[1] The Model Documentation Report contains additional details concerning model structure and operation. Refer to Energy 

Information Administration, Model Documentation Report: Residential Sector Demand Module of the National Energy Modeling 

System, DOE/EIA-M067(2013), (November 2013). http://www.eia.gov/forecasts/aeo/nems/documentation/residential/pdf/

m067(2013).pdf.

[2] Among the explanations often mentioned for observed high average implicit discount rates are: market failures, (i.e., cases 

where incentives are not properly aligned for markets to result in purchases based on energy economics alone); unmeasured 

technology costs (i.e., extra costs of adoption which are not included or difficult to measure, like employee down-time); 

characteristics of efficient technologies viewed as less desirable than their less-efficient alternatives (such as equipment noise 

levels or lighting quality characteristics); and the risk inherent in making irreversible investment decisions. Examples of market 

failures/barriers include: decision-makers having less than complete information, cases where energy equipment decisions are 

made by parties not responsible for energy bills (e.g., landlord/tenants, builders/ home buyers), discount horizons which are 

truncated (which might be caused by mean occupancy times that are less than the simple payback time and that could possibly 

be classified as an information failure), and lack of appropriate credit vehicles for making efficiency investments. The use of high 

implicit discount rates in NEMS merely recognizes that such rates are typically found to apply to energy-efficiency investments.

[3] U.S. Bureau of Census, Series C25 Data from various years of publications.

[4] Sources: U.S. Bureau of Census, Annual Housing Survey 2001 and Professional Remodeler, 2002 Home Remodeling Study.

[5] National Oceanic and Atmospheric Administration, National Weather Service, Experimental Monthly Degree Day Forecast, 

http://www.cpc.ncep.noaa.gov/pacdir/DDdir/ddforecast.txt. Explanation of forecast available at http://www. cpc.ncep.noaa.

gov/pacdir/DDdir/N1.html.

[6] See Dahl, Carol, A Survey of Energy Demand Elasticities in Support of the Development of the NEMS, October 1993. 

[7] The IECC established guidelines for builders to meet specific targets concerning energy efficiency with respect to heating 

and cooling load.

[8] Oak Ridge National Laboratory, Estimating the National Effects of the U.S. Department of Energy’s Weatherization 

Assistance Program with State-Level Data: A Metaevaluation Using Studies from 1993 to 2005, September 2005. 

[9] U.S. Department of Energy, Office of Inspector General, Office of Audit Services, Special Report: Progress in Implementing 

the Department of Energy’s Weatherization Assistance Program under the American Recovery and Reinvestment Act, February 

2010.

[10] The high technology assumptions are based on U.S. Energy Information Administration, Technology Forecast UpdatesResidential and Commercial Building Technologies-Advanced Adoption Case (Navigant Consulting, September 2011).

34 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module
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Commercial Demand Module

The NEMS Commercial Sector Demand Module generates projections of commercial sector energy demand through 2040. The 

definition of the commercial sector is consistent with EIA’s State Energy Data System (SEDS). That is, the commercial sector 

includes business establishments that are not engaged in transportation or in manufacturing or other types of industrial activity 

(e.g., agriculture, mining or construction). The bulk of commercial sector energy is consumed within buildings; however, street 

lights, pumps, bridges, and public services are also included if the establishment operating them is considered commercial.

Since most of commercial energy consumption occurs in buildings, the commercial module relies on the data from the EIA 

Commercial Buildings Energy Consumption Survey (CBECS) for characterizing the commercial sector activity mix as well as the 

equipment stock and fuels consumed to provide end use services [1].

The commercial module projects consumption by fuel [2] at the Census division level using prices from the NEMS energy 

supply modules and macroeconomic variables from the NEMS Macroeconomic Activity Module (MAM), as well as external 

data sources (technology characterizations, for example). Energy demands are projected for ten end-use services [3] for 

eleven building categories [4] in each of the nine Census divisions (see Figure 5). The model begins by developing projections 

of floorspace for the 99 building category and Census division combinations. Next, the ten end-use service demands required 

for the projected floorspace are developed. The electricity generation and water and space heating supplied by distributed 

generation and combined heat and power technologies are projected. Technologies are then chosen to meet the projected 

service demands for the seven major end uses. Once technologies are chosen, the energy consumed by the equipment stock 

(both existing and purchased equipment) is developed to meet the projected end-use service demands [5]. Minor end uses are 

modeled in less detail. Annual energy consumption of select miscellaneous end-use loads (MELs) are derived by combining 

existing and projected equipment stock, energy consumption per device, and hours of use where applicable.

Key assumptions

The key assumptions made by the commercial module are presented in terms of the flow of the calculations described above. 

The sections below summarize the assumptions in each of the commercial module submodules: floorspace, service demand, 

distributed generation, technology choice, and end-use consumption. The submodules are executed sequentially in the order 

presented, and the outputs of each submodule become the inputs to subsequently executed submodules. As a result, key 

projection drivers for the floorspace submodule are also key drivers for the service demand submodule, and so on.

Floorspace submodule

Floorspace is projected by starting with the previous year’s stock of floorspace and eliminating a portion to represent the agerelated removal of buildings. Total floorspace is the sum of the surviving floorspace plus new additions to the stock derived from 

the MAM floorspace growth projection [6].

Existing floorspace and attrition

Existing floorspace is based on the estimated floorspace reported in the 2003 Commercial Buildings Energy Consumption 

Survey (Table 5.1). Over time, the 2003 stock is projected to decline as buildings are removed from service (floorspace 

attrition). Floorspace attrition is estimated by a logistic decay function, the shape of which is dependent upon the values of 

two parameters: average building lifetime and gamma. The average building lifetime refers to the median expected lifetime of 

a particular building type. The gamma parameter corresponds to the rate at which buildings retire near their median expected 

lifetime. The current values for the average building lifetime and gamma vary by building type as presented in Table 5.2 [7].

New construction additions to floorspace

The commercial module develops estimates of projected commercial floorspace additions by combining the surviving 

floorspace estimates with the total floorspace projection from MAM. A total NEMS floorspace projection is calculated by 

applying the MAM assumed floorspace growth rate within each Census division and MAM building type to the corresponding 

NEMS Commercial Demand Module’s building types based on the CBECS building type shares. The NEMS surviving floorspace 

from the previous year is then subtracted from the total NEMS floorspace projection for the current year to yield new floorspace 

additions [8].

Service demand submodule

Once the building stock is projected, the Commercial Demand module develops a projection of demand for energy-consuming 

services required for the projected floorspace. The module projects service demands for the following explicit end-use services: 

space heating, space cooling, ventilation, water heating, lighting, cooking, refrigeration, personal computer office equipment, 

and other office equipment [9]. The service demand intensity (SDI) is measured in thousand Btu of end-use service demand 

per square foot and differs across service, Census division, and building type. The SDIs are based on a hybrid engineering and 

statistical approach of CBECS consumption data [10]. Projected service demand is the product of square feet and SDI for all end 

uses across the eleven building categories with adjustments for changes in shell efficiency for space heating and cooling.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 37
Commercial Demand Module

Table 5.1. 2003 Total floorspace by Census Division and principal building activity 

millions of square feet

Assembly Education

Food

Sales

Food

Service

Health

Care Lodging

Large

Office

Small

Office

Merc/

Service Warehouse Other Total

New England 431 299 75 45 48 374 282 320 819 411 351 3,452

Middle 

Atlantic 1,243 1,384 163 127 310 797 1,523 1,065 1,641 1,112 1,177 10,543

East North 

Central 1,355 1,990 218 248 316 549 1,297 1,129 2,148 2,023 1,152 12,424

West North 

Central 772 552 102 206 123 595 219 704 1,045 994 369 5,580

South Atlantic 1,161 2,445 223 433 469 939 1,173 1,065 3,391 1,836 865 13,999

East South 

Central 546 341 67 99 134 368 195 371 985 390 223 3,719

West South 

Central 965 1,198 197 232 235 387 916 501 2,076 1,740 575 9,022

Mountain 411 640 64 32 94 438 230 535 1,087 506 168 4,207

Pacific 809 1,027 146 232 176 649 1,028 915 2,051 1,066 515 8,613

Total United 

States 7,693 9,874 1,255 1,654 1,905 5,096 6,861 6,605 15,242 10,078 5,395 71,658

Note: Totals may not equal sum of components due to independent rounding.

Source: U.S. Energy Information Administration, 2003 Commercial Buildings Energy Consumption Survey Public Use Data.

Table 5.2. Floorspace attrition parameters

Assembly Education

Food

Sales

Food

Service

Health

Care Lodging

Large

Office

Small

Office

Merc/

Service Warehouse Other

Median Expected 

Lifetime (years) 55 62 55 50 55 53 65 58 50 58 60

Gamma 2.2 2.1 2.3 2.0 2.5 2.1 2.0 2.0 2.2 2.0 2.3

Source: U.S. Energy Information Administration, Commercial Buildings Energy Consumption Survey 2003, 1999, 1995, 1992, and 1989 Public Use Data,

1986 Nonresidential Buildings Energy Consumption Survey, McGraw-Hill Construction Dodge Annual Starts - non-residential building starts, Northwest 

Energy Efficiency Alliance, Assessment of the Commercial Building Stock in the Pacific Northwest, KEMA-XENERGY, Inc., March 2004, and public 

information on demolitions.

Shell efficiency

The shell integrity of the building envelope is an important determinant of the heating and cooling loads for each type of 

building. In the NEMS Commercial Demand Module, the shell efficiency is represented by separate building shell heating and 

cooling factors which change over time to reflect improvements in the building shell. The factors, dimensioned by building 

type and Census division, affect the space heating and cooling service demand intensities causing changes in fuel consumed 

for these services as the shell integrity improves. In the AEO2014 Reference case, building shells for new construction built in 

2003 are up to 49% more efficient with respect to heating and up to 30% more efficient with respect to cooling relative to the 

average shell for existing buildings of the same type. Over the projection horizon, new building shells improve in efficiency by 

15.0% relative to their efficiency in 2003. For existing buildings, efficiency is assumed to increase by 6.9% over the 2003 stock 

average. 

Distributed generation and combined heat and power

Program-driven installations of solar photovoltaic systems are based primarily on information from the Interstate Renewable 

Energy Council’s annual report on U.S. solar market trends. Historical data from Form EIA-860, Annual Electric Generator 

Report, are used to derive electricity generation by Census division, building type and fuel. A projection of distributed generation 

and combined heat and power (CHP) of electricity is developed based on the economic returns projected for distributed 

generation and CHP technologies. The model uses a detailed cash-flow approach to estimate the internal rate of return for an 

investment. Penetration assumptions for distributed generation and CHP technologies are a function of the estimated internal 

rate of return relative to purchased electricity. Table 5.3 provides the cost and performance parameters for representative 

distributed generation and CHP technologies.

38 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module

The model also incorporates endogenous “learning” for new distributed generation and CHP technologies, allowing for declining 

technology costs as shipments increase. For fuel cell and photovoltaic systems, parameter assumptions for the AEO2014 

Reference case result in a 13% reduction in capital costs each time the number of units shipped to the buildings sectors (residential 

and commercial) doubles. Doubling the number of microturbines shipped results in a 10% reduction in capital costs and doubling 

the number of distributed wind systems shipped results in a 3% reduction.

Technology Choice Submodule

The technology choice submodule develops projections of the results of the capital purchase decisions for equipment fueled by 

the three major fuels (electricity, natural gas, and distillate fuel). Capital purchase decisions are driven by assumptions concerning 

behavioral rule proportions and time preferences, described below, as well as projected fuel prices, average utilization of 

equipment (the capacity factors), relative technology capital costs, and operating and maintenance (O&M) costs.

Decision types

In each projection year, equipment is potentially purchased for three “decision types.” Equipment must be purchased for newly 

added floorspace and to replace the portion of equipment in existing floorspace that is projected to wear out [11]. Equipment is 

also potentially purchased for retrofitting equipment that has become economically obsolete. The purchase of retrofit equipment 

occurs only if the annual operating costs of a current technology exceed the annualized capital and operating costs of a technology 

available as a retrofit candidate.

Behavioral rules

The commercial module allows the use of three alternate assumptions about equipment choice behavior. These assumptions 

constrain the equipment selections to three choice sets, which are progressively more restrictive. The choice sets vary by decision 

type and building type:

• Unrestricted Choice Behavior - This rule assumes that commercial consumers consider all types of equipment that meet a given 

service, across all fuels, when faced with a capital purchase decision.

• Same Fuel Behavior - This rule restricts the capital purchase decision to the set of technologies that consume the same fuel that 

currently meets the decision maker’s service demand.

• Same Technology Behavior - Under this rule, commercial consumers consider only the available models of the same technology 

and fuel that currently meet service demand, when facing a capital stock decision.

Under any of the above three behavior rules, equipment that meets the service at the lowest annualized lifecycle cost is chosen. 

Table 5.4 illustrates the proportions of floorspace subject to the different behavior rules for space heating technology choices in 

large office buildings.

Time preferences

Commercial building owners’ time preferences regarding current versus future expenditures are assumed to be distributed among 

seven alternate time preference premiums. Adding the risk-adjusted time preference premiums to the 10-year Treasury note rate 

from MAM results in implicit discount rates, also known as hurdle rates, applicable to the assumed proportions of commercial 

floorspace. The effect of the use of this distribution of discount rates is to prevent a single technology from dominating purchase 

decisions in the lifecycle cost comparisons. The distribution used for AEO2014 assigns some floorspace a very high discount or 

hurdle rate to simulate floorspace which will never retrofit existing equipment and which will only purchase equipment with the 

lowest capital cost. Discount rates for the remaining six segments of the distribution get progressively lower, simulating increased 

sensitivity to the fuel costs of the equipment that is purchased. The share of floorspace assigned to each rate in the distribution 

varies by end-use service. Table 5.5 illustrates the distribution of time preference premiums for space heating and lighting in 

2015. The proportion of floorspace assumed for the 0.0 time preference premium represents an estimate of the federally-owned 

commercial floorspace that is subject to purchase decisions in a given year. The federal sector is expected to purchase energyefficient equipment to meet the federal buildings performance standards of the Energy Policy Act of 2005 and the Energy 

Independence and Security Act of 2007 whenever cost-effective. For federal purchase decisions relating to energy conservation, 

cost-effectiveness is determined using a discount rate based on long-term Treasury bond rates, approximated in the commercial 

module by the 10-year Treasury note rate. For lighting, the proportion of floorspace assumed for the 0.0 time preference premium 

is increased to include all federal floorspace starting in 2009 to represent the EISA 2007 provision that all federal buildings be 

equipped with energy-efficient lighting fixtures and bulbs to the maximum extent feasible, including when replacing bulbs in 

existing fixtures.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 39
Commercial Demand Module

Table 5.3. Capital cost and performance parameters of selected commercial distributed generation technologies

Technology Type

Year of 

Introduction

Average 

Generating 

Capacity

 (kWDC)

Electrical 

Efficiency

 Combined 

Efficiency 

(Elec. + 

Thermal)

Installed 

Capital Cost

 (2009 $ per 

kWDC)*

Service 

Life

(Years)

Solar Photovoltaic 2010 30 0.15 N/A $6,410 30

2015 35 0.18 N/A $3,804 30

2025 40 0.20 N/A $2,593 30

2035 45 0.20 N/A $2,446 30

Fuel Cell 2010 300 0.42 0.65 $7,404 20

2015 300 0.49 0.66 $5,019 20

2025 300 0.51 0.69 $4,016 20

2035 300 0.54 0.73 $3,180 20

Natural Gas Engine 2010 334 0.30 0.82 $1,780 20

2015 334 0.31 0.85 $1,630 20

2025 334 0.30 0.87 $1,251 20

2035 334 0.30 0.91 $831 20

Oil-fired Engine 2010 300 0.34 0.73 $1,784 20

2015 300 0.34 0.74 $1,746 20

2025 300 0.35 0.80 $1,669 20

2035 300 0.36 0.78 $1,592 20

Natural Gas Turbine 2010 3510 0.25 0.76 $1,884 20

2015 3510 0.25 0.77 $1,858 20

2025 3510 0.25 0.80 $1,760 20

2035 3510 0.25 0.82 $1,645 20

Natural Gas Microturbine 2010 200 0.32 0.61 $2,414 20

2015 200 0.34 0.67 $2,098 20

2025 200 0.37 0.73 $1,467 20

2035 200 0.41 0.80 $836 20

Wind 2010 32 0.13 N/A $5,243 30

2015 35 0.13 N/A $4,715 30

2025 40 0.13 N/A $3,973 30

2035 50 0.13 N/A $3,627 30

*The original source documents presented solar photovoltaic costs in 2008 dollars, all other technologies in 2010 dollars. Costs for solar photovoltaic, fuel 

cell, microturbine, and wind technologies include learning effects.

Sources: U.S. Energy Information Administration, Commercial and Industrial CHP Technology Cost and Performance Data Analysis for EIA SENTECH, 

Inc., and SAIC, Inc., June 2010, U.S. Energy Information Administration, Photovoltaic (PV) Cost and Performance Characteristics for Residential and 

Commercial Applications Final Report, ICF International, August 2010, and U.S. Energy Information Administration, The Cost and Performance of 

Distributed Wind Turbines, 2010-35 Final Report, ICF International, August 2010.

40 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module

Table 5.4. Assumed behavior rules for choosing space heating equipment in large office buildings

percent

Unrestricted Same Fuel Same Technology Total

New Equipment Decision 21 30 49 100

Replacement Decision 7 31 62 100

Retrofit Decision 1 4 95 100

Source: U.S. Energy Information Administration, Model Documentation Report: Commercial Sector Demand Module of the National Energy Modeling 

System,DOE/EIA-M066(2013) (November 2013).

Table 5.5. Assumed distribution of risk-adjusted time preference premiums for space heating and lighting equipment in 

2015

percent

Time Preference Premium Proportion of Floorspace-Space Heating (2015) Proportion of Floorspace-Lighting (2015)

1000.0 26.5 26.4

100.0 22.6 22.5

45.0 19.6 19.3

25.0 19.2 19.3

15.0 10.5 8.5

6.5 1.3 1.3

0.0 0.3 2.7

-- 100.0 100.0

Source: U.S. Energy Information Administration, Model Documentation Report: Commercial Sector Demand Module of the National Energy Modeling 

System, DOE/EIA-M066(2013) (November 2013).

The distribution of hurdle rates used in the commercial module is also affected by changes in fuel prices. If a fuel’s price rises 

relative to its price in the base year (2003), the nonfinancial portion of each hurdle rate in the distribution decreases to reflect 

an increase in the relative importance of fuel costs, expected in an environment of rising prices. Parameter assumptions for 

AEO2014 result in a 30% reduction in the nonfinancial portion of a hurdle rate if the fuel price doubles. If the risk-adjusted 

time preference premium input by the model user results in a hurdle rate below the assumed financial discount rate for the 

commercial sector – 15% – with base year fuel prices (such as the 0.0 rate given in Table 5.5), no response to increasing fuel 

prices is assumed. 

Technology characterization database

The technology characterization database organizes all relevant technology data by end use, fuel, and Census division. 

Equipment is identified in the database by a technology index as well as a vintage index, the index of the fuel it consumes, 

the index of the service it provides, its initial market share, the Census division index for which the entry under consideration 

applies, its efficiency (or coefficient of performance or efficacy in the case of lighting equipment), installed capital cost per 

unit of service demand satisfied, operating and maintenance cost per unit of service demand satisfied, average service life, 

year of initial availability, and last year available for purchase. Equipment may only be selected to satisfy service demand 

if the year in which the decision is made falls within the window of availability. Equipment acquired prior to the lapse of its 

availability continues to be treated as part of the existing stock and is subject to replacement or retrofitting. This flexibility in 

limiting equipment availability allows the direct modeling of equipment efficiency standards. Table 5.6 provides a sample of the 

technology data for space heating in the New England Census division.

An option has been included to allow endogenous price-induced technological change in the determination of equipment costs 

and availability for the menu of equipment. This concept allows future technologies faster diffusion into the market place if fuel 

prices increase markedly for a sustained period of time. The option was not exercised for the AEO2014 model runs.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 41
Commercial Demand Module

Table 5.6. Capital cost and efficiency ratings of selected commercial space heating equipment1

Equipment Type Vintage Efficiency2

Capital Cost 

(2010$ per MBtu/

hour)3

Maintenance Cost 

(2007$ per MBtu/

hour)3

Service Life 

(Years)

Rooftop Air-Source Heat 

Pump 2003 installed base 3.10 $63.89 $1.39 15

2010 current standard/typical 3.30 $76.67 $1.39 15

2010 high 3.40 $96.67 $1.39 15

2020 typical 3.30 $76.67 $1.39 15

2020 high 3.40 $96/67 $1.39 15

Ground-Source Heat Pump 2003 installed base 3.40 $140.00 $16.80 20

2010 typical 3.50 $140.00 $16.80 20

2007-10 high 4.90 $170.00 $16.80 20

2020 typical 3.50 $140.00 $16.80 20

2020 high 4.90 $170.00 $16.80 20

Electric Boiler 2003 installed base 0.94 $15.64 $0.24 15

2010 typical 0.94 $15.64 $0.24 15

Electric Resistance Heater 2003 installed base 0.98 $21.76 $0.01 18

Natural Gas Heat Pump 2003 installed base (residential type) 1.30 $158.33 $2.50 15

2010 typical (engine-driven rooftop) 1.40 $312.50 $4.58 30

2020 typical (engine-driven rooftop) 1.40 $212.50 $4.58 30

2030 typical (engine-driven rooftop) 1.40 $129.17 $4.58 30

Natural Gas Furnace 2003 installed base 0.71 $9.85 $1.06 17.5

2010 current standard/typical 0.78 $9.84 $0.97 17.5

2010 high 0.80 $10.30 $0.94 17.5

2020 typical 0.78 $9.84 $0.97 17.5

2020 high 0.88 $10.67 $0.66 17.5

2030 typical 0.78 $9.84 $0.97 17.5

2030 high 0.89 $11.88 $0.85 17.5

2035 high 0.91 $12.25 $0.83 17.5

Natural Gas Boiler 2003 installed base 0.73 $20.55 $0.77 25

2010 current standard/typical 0.78 $25.64 $0.72 25

2012 standard 0.80 $25.64 $0.72 25

2012 mid-range 0.89 $28.79 $0.63 25

2010 high 0.97 $38.02 $0.58 25

2020 typical 0.80 $25.00 $0.70 25

2020 high 0.97 $38.02 $0.58 25

2030 typical 0.80 $25.00 $0.70 25

Distillate Oil furnace 2003 installed base 0.76 $13.56 $0.99 18.5

2010 typical 0.80 $13.28 $0.94 18.5

2020 typical 0.80 $13.28 $0.94 18.5

Distillate Oil Boiler 2003 installed base 0.76 $17.54 $0.17 25

2010 current standard 0.81 $18.21 $0.16 25

2010-12 standard 0.82 $18.10 $0.16 25

2010 high 0.87 $25.05 $0.13 25

2020 typical 0.82 $18.10 $0.16 25

2020 high 0.87 $25.05 $0.13 25

*Equipment listed is for the New England Census division, but is also representative of the technology data for the rest of the United States. See the source 

reference below for the complete set of technology data.

2

Efficiency measurements vary by equipment type. Electric rooftop air-source heat pumps, ground source and natural gas heat pumps are rated for heating 

performance using coefficient of performance; natural gas and distillate furnaces and boilers are based on Thermal Efficiency.

Source: U.S. Energy Information Administration, “EIA - Technology Forecast Updates - Residential and Commercial Building Technologies - Reference Case”, 

Navigant Consulting, Inc., October 2011.

42 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module

End-Use Consumption Submodule

The end-use consumption submodule calculates the consumption of each of the three major fuels (electricity, natural gas, and 

distillate fuel oil) for the ten end-use services plus fuel consumption for combined heat and power and district services. For the 

ten end-use services, energy consumption is calculated as the end-use service demand met by a particular type of equipment 

divided by its efficiency and summed over all existing equipment types. This calculation includes dimensions for Census division, 

building type, and fuel. Consumption of the five minor fuels (residual fuel oil, liquefied petroleum gas, motor gasoline, kerosene, 

and coal) is projected based on historical trends.

Equipment efficiency

The average energy consumption of a particular appliance is based initially on estimates derived from the 2003 CBECS. As 

the stock efficiency changes over the model simulation, energy consumption decreases nearly as much as, but not quite 

proportionally to the efficiency increase. The difference is due to the calculation of efficiency using the harmonic average and also 

the efficiency rebound effect discussed below. For example, if on average, electric heat pumps are now 10% more efficient than 

in 2003, then all else constant (weather, real energy prices, shell efficiency, etc.), energy consumption per heat pump would now 

average about 9% less. The Service Demand and Technology Choice Submodules together determine the average efficiency of the 

stocks used in adjusting the initial average energy consumption.

Adjusting for weather and climate

Weather in any given year always includes short-term deviations from the expected longer-term average (or climate). Recognition 

of the effect of weather on space heating and air conditioning is necessary to avoid projecting abnormal weather conditions 

into the future. In the commercial module, proportionate adjustments are made to space heating and air conditioning demand 

by Census division. These adjustments are based on National Oceanic and Atmospheric Administration (NOAA) data for 

Heating Degree Days (HDD) and Cooling Degree Days (CDD). Short-term projections are informed by the National Oceanic and 

Atmospheric Administration’s (NOAA) 15-month outlook from their Climate Prediction Center[12], which often encompasses 

the first forecast year. Projections of degree days beyond that are informed by a 30-year linear trend of each state’s degree days, 

which are then population-weighted to the Census division level. In this way, the projection accounts for projected population 

migrations across the nation and continues any realized historical changes in degree days at the state level. A 10% increase in 

HDD would increase space heating consumption by 10% over what it would have been, while a 10% increase in CDD would 

increase cooling consumption by about 12.5%.

Short-term price effect and efficiency rebound

It is assumed that energy consumption for a given end-use service is affected by the marginal cost of providing that service. That 

is, all else equal, a change in the price of a fuel will have an inverse, but less than proportional, effect on fuel consumption. The 

current value for the short-term price elasticity parameter is -0.25 for all major end uses except refrigeration. A value of -0.1 is 

currently used for commercial refrigeration. A value of -0.05 is currently used for PC and non-PC office equipment and other 

minor uses of electricity. For example, for lighting, this value implies that for a 1.0% increase in the price of a fuel, there will be 

a corresponding decrease in energy consumption of 0.25%. Another way of affecting the marginal cost of providing a service 

is through equipment efficiency. As equipment efficiency changes over time, so will the marginal cost of providing the end-use 

service. For example, a 10% increase in efficiency will reduce the cost of providing the service by 10%. The short-term elasticity 

parameter for efficiency rebound effects is -0.15 for affected end uses; therefore, the demand for the service will rise by 1.5% 

(-10% x -0.15). Currently, all services are affected by the short-term price effect and services affected by efficiency rebound are 

space heating and cooling, water heating, ventilation and lighting.

Legislation and regulations

American Recovery and Reinvestment Act of 2009 (ARRA09)

The ARRA09 legislation passed in February 2009 provides energy efficiency funding for federal agencies, State Energy Programs, 

and block grants. To account for the impact of this funding, states are assumed to adopt and enforce the ASHRAE 90.1-2007 

standard by 2018 for building shell measures, and all public buildings (federal, state, and local) are assumed to use the 10-year 

Treasury note rate for purchase decisions related to both new construction and replacement equipment while stimulus funding 

is available. A percentage of the State Energy Program and Conservation Block Grant funding is assumed to be used for solar 

photovoltaic and small wind turbine installations. Additional stimulus funding is applied to fuel cell installations.

The ARRA09 provisions remove the cap on the 30% Business Investment Tax Credit for wind turbines. The Investment Tax 

Credit is still available for systems installed through 2016. These credits are directly incorporated into the cash-flow approach for 

distributed generation systems.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 43
Commercial Demand Module

Energy Improvement and Extension Act of 2008 (EIEA08)

The EIEA08 legislation passed in October 2008 extends the Business Investment Tax Credit provisions of the Energy Policy Act 

of 2005 and expands the credit to include additional technologies. The Business Investment Tax Credits of 30% for solar energy 

systems and fuel cells and 10% for microturbines are extended through 2016. The cap on the fuel cell credit has been increased 

from $500 to $1,500 per half kilowatt of capacity. The EIEA08 provisions expand the Investment Tax Credit to include a 10% 

credit for CHP systems and ground-source heat pumps and a 30% credit for wind turbines with the wind credit capped at $4,000. 

The expanded credits are available for systems installed through 2016. These credits are directly incorporated into the cash-flow 

approach for distributed generation systems, including CHP, and factored into the installed capital cost assumptions for solar hot 

water heaters and ground-source heat pumps.

Energy Independence and Security Act of 2007 (EISA07)

The EISA07 legislation passed in December 2007 provides standards for specific explicitly modeled commercial equipment. The 

EISA07 requires specific energy-efficiency measures in commercial walk-in coolers and walk-in freezers effective January 1, 2009. 

Incandescent and halogen lamps must meet standards for maximum allowable wattage based on lumen output starting in 2012 

and metal halide lamp fixtures using lamps between 150 and 500 watts are required to have a minimum ballast efficiency ranging 

from 88% to 94%, depending on ballast type, effective January 1, 2009.

The EISA07 requirement for federal buildings to use energy-efficient lighting fixtures and bulbs to the maximum extent possible 

is represented by adjusting the proportion of the commercial sector assumed to use the 10-year Treasury note rate as an implicit 

discount or hurdle rate for lighting.

Energy Policy Act of 2005 (EPACT05)

The passage of the EPACT05 in August 2005 provides additional minimum efficiency standards for commercial equipment. Some 

of the standards for explicitly modeled equipment, effective January 1, 2010, include an Energy Efficiency Rating (EER) ranging 

from 10.8 to 11.2 for small package air conditioning and heating equipment; daily electricity consumption limits by volume for 

commercial refrigerators, freezers, and refrigerator-freezers; and electricity consumption limits per 100 pounds of ice produced 

based on equipment type and capacity for automatic ice makers. The EPACT05 adds standards for medium-base compact 

fluorescent lamps effective January 1, 2006, for ballasts for Energy Saver fluorescent lamps effective in 2009 and 2010, and bans 

the manufacture or import of mercury vapor lamp ballasts effective January 1, 2008.

Several efficiency standards in the EPACT05 pertain to equipment not explicitly represented in the NEMS Commercial Demand 

Module. For low voltage dry-type transformers, effects of the standard are included in estimating the share of projected 

miscellaneous electricity use attributable to transformer losses. For illuminated exit signs, traffic signals, and commercial premise 

spray valves, assumed energy reductions are calculated based on per-unit savings relative to a baseline unit and the estimated 

share of installed units and sales that already meet the standard. Total projected reductions are phased in over time to account for 

stock turnover. Under the EPACT05 standards, illuminated exit signs and traffic signal modules must meet ENERGY STAR program 

requirements as of January 1, 2006. The requirements limit input power demand to 5 watts or less per face for exit signs. Nominal 

wattages for traffic signal modules are limited to 8 to 15 watts, based on module type. Effective January 1, 2007, low voltage drytype distribution transformers are required to meet the National Electrical Manufacturers Association Class I Efficiency Levels 

with minimum efficiency levels ranging from 97% to 98.9% based on output. Commercial pre-rinse spray valves [13] must have a 

maximum flow rate of 1.6 gallons per minute, effective January 1, 2006 with energy reductions attributed to hot water use.

The EPACT05 expands the Business Investment Tax Credit to 30% for solar property installed in 2006 and 2007. Business 

Investment Tax Credits of 30% for fuel cells and 10% for microturbine power plants are also available for property installed in 

2006 and 2007. The EPACT05 tax credit provisions were extended in December 2006 to cover equipment installed in 2008. 

These credits are directly incorporated into the cash-flow approach for distributed generation systems and factored into the 

installed capital cost assumptions for solar hot water heaters.

Energy Policy Act of 1992 (EPACT92)

A key assumption incorporated in the technology selection process is that the equipment efficiency standards described in the 

EPACT92 constrain minimum equipment efficiencies. The effects of standards are modeled by modifying the technology database 

to eliminate equipment that no longer meets minimum efficiency requirements. Some of the EPACT92 standards implemented 

in the module include: gas and oil-fired boilers—minimum combustion efficiency of 0.80 and 0.83, respectively, amended to 

minimum thermal efficiency of 0.80 and 0.81, respectively, in 2012; gas and oil-fired furnaces—minimum thermal efficiency of 

0.80 and 0.81, respectively; electric water heaters—minimum energy factor of 0.85; and gas and oil water heaters—minimum 

thermal efficiency of 0.80 and 0.78, respectively. A fluorescent lamp ballast standard effective in 2005 mandates electronic 

ballasts with a minimum ballast efficacy factor of 1.17 for 4-foot, 2-lamp ballasts and 0.63 for 8-foot, 2-lamp ballasts. Fluorescent 

lamps and incandescent reflector lamb bulbs must meet amended standard levels for minimum average lamp efficacy in 2012. 

Recent updates for commercial refrigeration equipment include maximum energy consumption standards for refrigerated vending 

machines and display cases based on volume.

44 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module

The 10% Business Investment Tax Credit for solar energy property included in EPACT92 is directly incorporated into the 

cash-flow approach for projecting distributed generation by commercial photovoltaic systems. For solar hot water heaters, 

the tax credit is factored into the installed capital cost assumptions used in the technology choice submodule.

Energy efficiency programs

Several energy efficiency programs affect the commercial sector. These programs are designed to stimulate investment in 

more efficient building shells and equipment for heating, cooling, lighting, and miscellaneous end-use loads (MELs). The 

commercial module includes several features that allow projected efficiency to increase in response to voluntary programs 

(e.g., the distribution of risk- adjusted time preference premiums and shell efficiency parameters). Retrofits of equipment 

for space heating, air conditioning and lighting are incorporated in the distribution of premiums given in Table 5.5. Also the 

shell efficiency of new and existing buildings is assumed to increase from 2003 through 2040. Shells for new buildings 

increase in efficiency by 15.0% over this period, while shells for existing buildings increase in efficiency by 6.9%.

Commercial alternative cases

Technology cases

In addition to the AEO2014 Reference case, three side cases were developed to examine the effect of equipment and 

building standards on commercial energy use—a 2013 Demand Technology case, a High Demand Technology case, and a 

Best Available Demand Technology case. These side cases were analyzed in integrated runs with the NEMS demand and 

supply modules and thus include supply responses to the altered commercial consumption patterns of the three cases. 

AEO2014 also analyzed a Low Renewable Technology Cost case.

The 2013 Demand Technology case assumes that all future equipment purchases are made based only on equipment 

available in 2013. This case assumes building shell efficiency to be fixed at 2013 levels. In the High Demand Technology 

case, depending on technology or end use, equipment costs are lower, efficiencies are higher, and equipment is available 

sooner than in the Reference case. Energy efficiency investments are evaluated at 7% real rather than the distribution 

of hurdle rates assumed for the Reference case. Equipment assumptions were developed by engineering technology 

experts, considering the potential impact on technology given increased research and development into more advanced 

technologies. In addition to equipment improvements, building shell efficiencies are assumed to improve 25% more than in 

the Reference case after 2013. Existing building shells, therefore, increase by 8.6% relative to 2003 levels and new building 

shells by 18.8% relative to their efficiency in 2003 by 2040.

The Best Available Demand Technology case assumes that all equipment purchases after 2013 are based on the highest 

available efficiency for each type of technology in the High Demand Technology case in a particular simulation year, 

disregarding the economic costs of such a case. It is designed to show how much the choice of the highest-efficiency 

equipment could affect energy consumption. Shell efficiencies in this case are assumed to improve 50% more than in the 

Reference case after 2013, i.e., existing shells increase by 10.4% relative to 2003 levels and new building shells by 22.5% 

relative to their efficiency in 2003 by 2040.

Fuel shares, where appropriate for a given end use, are allowed to change in the technology cases as the available 

technologies from each technology type compete to serve certain segments of the commercial floorspace market. For 

example, in the Best Available Technology case, the most efficient gas furnace technology competes with the most 

efficient electric heat pump technology. This contrasts with the Reference case, in which a greater number of technologies 

for each fuel with varying efficiencies all compete to serve the heating end use. In general, the fuel choice will be affected 

as the available choices are constrained or expanded, and will thus differ across the cases.

The Low Renewable Cost case, which focuses on electricity generation, incorporates alternative assumptions for non-hydro 

renewable energy technologies in the power sector, the industrial sector, and the buildings sectors, including residential 

and commercial photovoltaic and wind systems. In this case, assumptions regarding non-renewable technologies are not 

changed from the Reference case. It assumes that costs for residential and commercial photovoltaic and wind systems are 

20% below Reference case assumptions beginning in 2014 and continuing through the projection period.

Analysis cases

Three integrated analysis cases were completed for the AEO2014: the No Sunset, Extended Policies, and Energy Savings 

and Industrial Competiveness Act cases. All cases are based upon Reference case assumptions, with additional changes 

made to extend existing tax credits and policies beyond those prescribed by current law.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 45
Commercial Demand Module

In the No Sunset case, the 30% solar photovoltaic investment tax credit (ITC) that is scheduled to revert to a 10% credit in 2016 

is, instead, assumed to be extended indefinitely at 30%. Additional tax credits for the purchase of other renewable and combined 

heat and power equipment, such as ground-source heat pumps and fuel cells, are also assumed to be extended indefinitely as 

opposed to expiring in 2016.

The Extended Policies case adopts the same assumptions as the No Sunset case and includes additional changes. For instance, 

federal equipment efficiency standards are updated at particular intervals consistent with the provisions in the existing law, 

with the levels based on ENERGY STAR specifications, or Federal Energy Management Program (FEMP) purchasing guidelines 

for federal agencies. Standards are also introduced for products that currently are not subject to federal efficiency standards. 

Updated national building energy codes reach 30% improvement in 2020 relative to the American Society of Heating, 

Refrigerating and Air-Conditioning Engineers (ASHRAE) Building Energy Code 90.1-2004 in the commercial sector. Two 

subsequent rounds in 2023 and 2026 each add an assumed 5% incremental improvement to building energy codes.

The equipment standards and building codes assumed for the Extended Policies case are meant to illustrate the potential effects 

of these polices on energy consumption for buildings. No cost-benefit analysis or evaluation of impacts on consumer welfare was 

completed in developing the assumptions. Likewise, no technical feasibility analysis was conducted, although standards were not 

allowed to exceed “maximum technologically feasible” levels described in DOE’s technical support documents.

The Energy Savings and Industrial Competiveness Act case begins with the Reference case and assumes passage of the energy 

efficiency provisions in S. 1392 including appropriation of funds at the levels authorized in the bill. New commercial building 

shells are assumed to be 30% more efficient than ASHRAE 90.1-2004 by 2020.

Notes and sources

[1] U.S. Energy Information Administration, 2003 Commercial Buildings Energy Consumption Survey (CBECS) Public Use

Files, web site www.eia.gov/emeu/cbecs/cbecs2003/public_use_2003/cbecs_pudata2003.html.

[2] The fuels accounted for by the commercial module are electricity, natural gas, distillate fuel oil, residual fuel oil, liquefied 

petroleum gas (LPG), coal, motor gasoline, and kerosene. Current commercial use of biomass (wood, municipal solid waste) is 

also included. In addition to these fuels the use of solar energy is projected based on an exogenous estimate of existing solar 

photovoltaic system installations, projected installations due to state and local incentive programs, and the potential endogenous 

penetration of solar photovoltaic systems and solar thermal water heaters. The use of wind energy is projected based on an 

estimate of existing distributed wind turbines and the potential endogenous penetration of wind turbines in the commercial 

sector.

[3] The end-use services in the commercial module are heating, cooling, water heating, ventilation, cooking, lighting, 

refrigeration, PC and non-PC office equipment and a category denoted “miscellaneous end-use loads (MELs)” to account for all 

other minor end uses.

[4] The 11 building categories are assembly, education, food sales, food services, health care, lodging, large offices, small offices, 

mercantile/services, warehouse, and other.

[5] The detailed documentation of the commercial module contains additional details concerning model structure and operation. 

Refer to U.S. Energy Information Administration, Model Documentation Report: Commercial Sector Demand Module of the 

National Energy Modeling System, DOE/EIA M066(2013), (November 2013).

[6] The commercial floorspace equations of the Macroeconomic Activity Model are estimated using the McGraw-Hill 

Construction Research & Analytics database of historical floorspace estimates. The McGraw-Hill Construction estimate 

for commercial floorspace in the U.S. is approximately 16% lower than the estimate obtained from the CBECS used for the 

Commercial module. See F.W. Dodge, Building Stock Database Methodology and 1991 Results, Construction Statistics and 

Forecasts, F.W. Dodge, McGraw-Hill.

[7] The commercial module performs attrition for 9 vintages of floorspace developed using stock estimates from the previous 5 

CBECS and historical floorspace additions data from McGraw-Hill Construction data.

[8] In the event that the computation of additions produces a negative value for a specific building type, it is assumed to be zero.

[9] “Other office equipment” includes copiers, fax machines, scanners, multi-function devices, data center servers, and other 

miscellaneous office equipment. A tenth category denoted “miscellaneous end-use loads (MELs)” includes equipment such 

as elevators, escalators, medical, and other laboratory equipment, laundry, communications equipment, security equipment, 

transformers, and miscellaneous electrical appliances. Commercial energy consumed outside of buildings and for combined heat 

and power is also included in the “MELs” category.

46 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Commercial Demand Module

Notes and sources (cont.)

[10] Based on 2003 CBECS end-use-level consumption data developed using the methodology described in Estimation of

Energy End-Use Intensities, web site www.eia.doe.gov/emeu/cbecs/tech_end_use.html.

[11] The proportion of equipment retiring is inversely related to the equipment life.

[12] National Oceanic and Atmospheric Administration, National Weather Service, Experimental Monthly Degree Day Forecast, 

http://www.cpc.ncep.noaa.gov/pacdir/DDdir/ddforecast.txt. Explanation of forecast available at http://www. cpc.ncep.noaa.

gov/pacdir/DDdir/N1.html.

[13] Commercial pre-rinse spray valves are handheld devices used to remove food residue from dishes and flatware before 

cleaning.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 47
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Industrial Demand Module
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Industrial Demand Module

The NEMS Industrial Demand Module (IDM) estimates energy consumption by energy source (fuels and feedstocks) 

for 15 manufacturing and 6 non-manufacturing industries. The manufacturing industries are subdivided further into 

the energy- intensive manufacturing industries and non-energy-intensive manufacturing industries (Table 6.1). The 

manufacturing industries are modeled through the use of a detailed process-flow or end-use accounting procedure. The 

non-manufacturing industries are modeled with less detail because processes are simpler and there is less available data. 

The petroleum refining industry is not included in the Industrial Demand Module, as it is simulated separately in the Liquid 

Fuels Market Module (LFMM) of NEMS. The IDM calculates energy consumption for the four Census Regions (see Figure 

5) and disaggregates regional energy consumption to the nine Census Divisions based on fixed shares from the U.S. Energy 

Information Administration (EIA) State Energy Data System [1]. The model base year for the IDM was updated to 2010 for 

AEO2014.

Table 6.1. Industry categories and NAICS codes

Energy-Intensive Manufacturing Non-energy-Intensive Manufacturing Non-Manufacturing

Food products (NAICS 311) Metal-based durables Agricultural crop 

Paper and allied products (NAICS 322) Fabricated metal products (NAICS 332) production (NAICS 111)

Bulk chemicals Machinery (NAICS 333)

 Inorganic (NAICS 32512-

32518)

 Computer and electronic 

 products

(NAICS 334) Other agricultural 

production

(NAICS 112, 

113, 115)

 Organic (NAICS 32511, 

32519)

 Electrical equipment and 

 appliances

(NAICS 335) Coal mining (NAICS 

2121)

 Resins (NAICS 3252) Transportation equipment (NAICS 336)

Oil and gas 

extraction (NAICS 211)

 Agricultural Chemicals (NAICS 3253) Other Metal and other 

non-metallic 

mining

(NAICS 

2122-2123)

Glass and glass products

(NAICS 3272), 

327993 Wood products (NAICS 321)

Cement and Lime

(NAICS 32731, 

32741)

 Plastic and rubber 

 products

(NAICS 326) Construction (NAICS 23)

Iron and steel (NAICS 3311-

3312)

 Balance of manufacturing (NAICS 31-33 

not already 

classified)

Aluminum (NAICS 3313)

NAICS = North American Industry Classification System (2007).

Source: Office of Management and Budget, North American Industry Classification system (NAICS) - United States (Springfield, VA. National 

Technical Information Service).

The energy-intensive manufacturing industries, consisting of food products, paper and allied products, bulk chemicals, glass 

and glass products, cement and lime, iron and steel, and aluminum, are modeled in considerable detail. Each industry is 

modeled as three separate but interrelated components: the Process and Assembly (PA) Component, the Buildings (BLD) 

Component, and the Boiler, Steam, and Cogeneration (BSC) Component. The BSC Component satisfies the steam demand 

from the PA and BLD Components. In some industries, the PA Component produces byproducts that are consumed in the 

BSC Component. For the manufacturing industries, the PA Component is separated into the major production processes 

or end uses. Petroleum refining (NAICS 32411) is modeled in detail in the LFMM of NEMS, and the projected energy 

consumption is reported in the manufacturing total.

Projections of refining energy use, lease and plant fuel, and fuels consumed in cogeneration in the oil and gas extraction 

industry (NAICS 211) are exogenous to the Industrial Demand Module, but endogenous to the NEMS modeling system.

Key assumptions - manufacturing 

The NEMS Industrial Demand Module primarily uses a bottom-up modeling approach. An energy accounting framework 

traces energy flows from fuels to the industry’s output. An important assumption in the development of this system is 

the use of 2010 baseline Unit Energy Consumption (UEC) estimates based on analysis and interpretations of the 2010 

Manufacturing Energy Consumption Survey (MECS) which is conducted by EIA on a four-year survey cycle [2]. The UECs 

represent the energy required to produce one unit of the industry’s output. A unit of output may be defined in terms of 

physical units (e.g., tons of steel) or in dollar value of shipments

. 

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 51
Industrial Demand Module

The Industrial Demand Module depicts the manufacturing industries, except for petroleum refining, with either a detailed 

process flow or end use approach. Generally, industries with homogeneous products use a process flow approach, and those 

with heterogeneous products use an end use approach. Industries that use a process flow approach are paper, glass, cement 

and lime, iron and steel, and aluminum. Industries that use an end-use approach are food, bulk chemicals, the five metal based 

durables industries, wood, plastic and rubber products, and balance of manufacturing. The dominant process technologies 

are characterized by a combination of unit energy consumption estimates and Technology Possibility Curves (TPC). With 

the exception of the cement and lime industries, the aluminum industry, and the glass industry, the TPC depicts the assumed 

average annual rate of change in energy intensity of either a process step or an energy end use (e.g., heating or cooling). The 

TPCs for new and existing plants vary by industry, vintage and process. These assumed rates were developed using professional 

engineering judgments regarding the energy characteristics, year of availability, and rate of market adoptions of new process 

technologies.

For the aluminum, glass, and combined cement and lime industries, energy projections are endogenously derived based on 

data obtained from the technology estimates (e.g., expenditures, energy coefficients, utility needs) in the Consolidated Impacts 

Modeling System (CIMS) database prepared by the Pacific Northwest National Laboratory, as calibrated using inputs from the 

U.S. Geological Survey (USGS) of the U.S. Department of the Interior, Portland Cement Association and MECS 2010 released by 

EIA [3,4,5].

Process/assembly component

The PA Component models each major manufacturing production step or end use for the manufacturing industries. The 

throughput production for each process step is computed, as well as the energy required to produce it. The unit energy 

coefficient (UEC) is defined as the amount of energy to produce a unit of output; it measures the energy intensity of the process 

or end use.

The module distinguishes the UECs by three vintages of capital stock. The amount of energy consumption reflects the 

assumption that new vintage stock will consist of state-of-the-art technologies that have different efficiencies from the existing 

capital stock. Consequently, the amount of energy required to produce a unit of output using new capital stock is often less than 

that required by the existing capital stock. The old vintage consists of capital existing in 2010 and surviving after adjusting for 

assumed retirements each year (Table 6.2). New production capacity is assumed to be added in a given projection year such that 

sufficient surviving and new capacity is available to meet the level of an industry’s output as determined in the NEMS Regional 

Macroeconomic Module. Middle vintage capital is that which is added after 2010 up through the year prior to the current 

projection year.

To simulate technological progress and adoption of more-efficient energy technologies, the UECs are adjusted each projection 

year based on the assumed TPC for each step. The TPCs are derived from assumptions about the relative energy intensity (REI) 

of productive capacity by vintage (new capacity relative to existing stock in a given year) or over time (new or surviving capacity 

in 2040 relative to the 2010 stock). For example, state-of-the-art additions to steel hot rolling capacity in 2010 are assumed 

to require only 80 percent as much energy as does the average existing plant, so the REI for new capacity in 2010 is 0.80 (see 

Table 6.3). Over time, the UECs for new capacity change, and the rate of change is given by the TPC. The UECs of the surviving 

2010 capital stock are also assumed to change over time, but not as rapidly as for new capital stock because of retrofitting. For 

example, with hot rolling, the TPC for new facilities is -0.804% per year, while the TPC for existing facilities is -0.699% per year. 

Table 6.3 provides more examples, including alternative assumptions used to reflect an advanced, “high tech” case.

Table 6.2. Retirement rates

Industry

Retirement Rate 

(percent) Industry

Retirement Rate 

(percent)

Iron and Steel

 Blast Furnace and Basic Steel Products 1.5 Food Products 1.7

 Electric Arc Furnace 1.5 Pulp and Paper 2.3

Coke Oven 2.5 Metal-Based Durables 1.3

Other Steel 2.9 Other Non-intensive Manufacturing 1.3

Bulk Chemicals 1.7

Note: Except for the Blast Furnace and Basic Steel Products Industry, the retirement rate is the same for each process step or end-use within an industry. 

Source: Energy Information Administration, Model Documentation Report: Industrial Sector Demand Module of the National Energy Modeling System, 

(Washington, DC, September 2013).

52 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

For the new submodules cement and lime, aluminum, and glass baseline capacity (as of year 2008 or 2009) is assumed to 

retire at a linear rate over a fixed period of time (20 years). Incremental, or added, capacity is assumed to retire according to a 

logistic survival function. In addition, for the cement industry, retirement of existing wet process kiln technology is assumed to be 

permanent; only dry process kilns can be added to replace retired wet kilns or to satisfy needed additional capacity.

The concepts of REI and TPCs are a means of embodying assumptions regarding new technology adoption in the manufacturing 

industry and the associated change in energy consumption of capital without characterizing individual technologies in detail. The 

approach reflects the assumption that industrial plants will change energy consumption as owners replace old equipment with 

new, sometimes more-efficient equipment, add new capacity, add new products, or upgrade their energy management practices. 

The reasons for the increased efficiency are not likely to be directly attributable to technology choice decisions, changing energy 

prices, or other factors readily subject to modeling. Instead, the module uses the REI and TPC concepts to characterize intensity 

trends for bundles of technologies available for major process steps or end use.

There are two exceptions to the general approach in the PA component. The first is for electric motor technology choice 

implemented for 9 industries to simulate their electric machine drive energy end use. Machine drive electricity consumption in 

the bulk chemicals industry, the food industry, the five metal-based durables industries, wood, plastics and rubber products, and 

balance of manufacturing is calculated by a motor stock model. The beginning stock of motors is modified over the projection 

horizon as motors are added to accommodate growth in shipments for each sector, as motors are retired and replaced, and as 

failed motors are rewound. When an old motor fails, an economic choice is made on whether to repair or replace the motor. 

When a new motor is added, either to accommodate growth or as a replacement, the motor must meet the minimum efficiency 

standard and a premium efficiency motor is also available. Table 6.4 provides the beginning stock efficiency for seven motor size 

groups in each of the three industry groups, as well as efficiencies for EPACT minimum and premium motors [7]. As the motor 

stock changes over the projection horizon, the overall efficiency of the motor population changes as well.

The second exception in the PA component is the Cement and Lime, Aluminum, and glass submodules. The methodology is 

described below.

The addition of the cement and lime submodule, the aluminum submodule, and the glass submodule are among several 

enhancements of the energy-intensive industries within the Industrial Demand Module. Instead of the aggregate energy intensity 

evolving according to TPCs for both new and vintage equipment for the process flows, the new submodules utilize detailed 

technology choice for each process flows. The new modules calculate surviving capacity based on retirement and needed 

capacity based on shipments and surviving capacity. Existing capital equipment retires linearly and new capital equipment retires 

according to a non-linear “S” curve over the useful life of the equipment. The exact shape of the “S” curve can be obtained by 

parameters adjusted by the user. New capital equipment information (capital and operating costs, energy use, and emissions) 

were obtained from the Consolidated Impacts Modeling System (CIMS) database. Each step of the process flow allows for 

multiple technology choices whose fuel type and efficiency are known at the national level, as regional fuel breakouts are fixed 

using available EIA data. 

Combined cement and lime industry

For the cement process flow, each step (raw material grinding, kiln – both rotation and burner, finished grinding) allows for 

multiple technology choices whose fuel type and efficiency are known at the national level, as regional fuel breakouts are fixed 

using available EIA data.

Cement has both dry and wet mill processes. Some technologies are available to both processes, while others are available to 

only one process. The technology choices within each group are:

1. Raw materials grinding: ball mill, roller mill

2. Kilns (rotators): rotary long with preheat, precalcining, and computer control (dry process only), rotary preheat with highefficiency cooler (dry only), rotary preheat, precalcine with efficient cooler (dry process only), rotary wet standard with 

waste heat recovery boiler and cogeneration (wet process only)

3. Kilns (burners): standard fired by natural gas, efficient fired by natural gas, standard fired by oil, efficient fired by oil, 

standard fired by coal, standard fired by petroleum coke, standard fired by hazardous waste, standard fired by residuederived fuel

4. Finished grinders: standard ball mill, finishing ball mill with high-efficiency separator, standard roller mill, finishing roller 

mill with high-efficiency separator

The technology slate in each of these process steps evolves over time and depends on the relative cost of equipment, cost of 

fuel, and fuel efficiency.

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 53
Industrial Demand Module

The base year technology slate is determined from the latest CIMS database and calibrated for the year 2008 with dry and 

wet mill capacity cement fuel use data from the Portland Cement Association, the USGS, and the 2010 MECS. All new cement 

capacity, both for replacement and increased production, is assumed to be dry cement capacity. Existing wet capacity is 

assumed to retire at a linear rate over 20 years with no replacement. Imported clinker, additives, and fly-ash are assumed 

to make constant percentage contributions to the finished product and thus “displace” a certain amount of domestic clinker 

production, and therefore energy use.

Lime shipments are estimated using a fixed percentage of stone, clay and glass shipments. Lime shipments, plus cement 

shipments, are presented together as the consolidated cement and lime output. Energy consumption and technology evolution 

in the lime industry are driven by the same methods implemented for cement, with different, industry-specific equipment 

choices.

Aluminum industry

For the aluminum process flow, each step (alumina production, anode production, and electrolysis for primary aluminum 

production, and melting for secondary production), allows for multiple technology choices whose fuel type and efficiency are 

known, as well as other operating characteristics. Technology shares are known at the national level, with regional fuel breakouts 

based on fixed allocations using available EIA data.

The aluminum industry has both primary and secondary production processes, which vary greatly in their energy demands. 

As such, the extents of these processes are based on the aluminum industry’s projected production and its historical share 

of production processes attenuated by relevant regional energy prices. Therefore, the fraction of total throughput from each 

aluminum production process varies over the model projections. However, it is assumed based on expert judgment that no new 

primary aluminum plants will be built in the U.S. before 2040, although capacity expansion of existing primary smelters may 

occur.

Some technologies are available to both processes, while others are available to only one process. The technology choices within 

each production processing group are:

1. Primary smelting (Hall-Heroult electrolysis cell) is represented as smelting in four pre-bake anode technologies that 

denote standard and retrofitted choices and one inert anode wetted cathode choice.

2. Anode production, used in primary production only, is represented by three natural gas-fired furnaces under various 

configurations in forming and baking pre-bake anodes and the formation of Söderberg anodes. Note that anodes are a 

major requirement for the Hall-Heroult process.

3. Alumina production (Bayer Process) is used in primary production only and selects between existing natural gas facilities 

and those with retrofits.

4. Secondary production selects between two natural gas-fired melters – i.e., a standard and a melter with high efficiency: 

The technology slate in each of these process steps evolves over time and depends on the relative cost of equipment, cost of 

fuel, and fuel efficiency. The base year technology slate is determined from the latest CIMS database and calibrated for the base 

year 2010 MECS and the USGS. All new capacities for aluminum production, both for replacement and increased production 

needs, are now assumed to be either pre-existing primary production or new secondary production, based on historical trend 

data and projected energy prices. Similar to the energy-intensive technology of the cement industry, the lifespan of existing and 

new production capacity is assumed to be 20 and 30 years, respectively. In addition, production that has been idled is allowed 

to re-enter production before new equipment is built.

Glass industry

For the glass process flow, each step of the three glass product processes modeled in the IDM (flat glass, pressed and blown 

glass, glass containers) allows for multiple technology choices whose fuel type and efficiency are known, as well as other 

operating characteristics. 

For flat glass (NAICS 327211) the process steps include batch preparation, furnace, form & finish, and tempering. For pressed 

and blown glass (NAICS 327212), the process steps include preparation, furnace, form & finish, and fire polish. For glass 

containers (NAICS 327213), the process steps include preparation, furnaces, and form & finish. For fiberglass (“mineral wool” 

– NAICS 327993), the process steps include preparation, furnaces, and form & finish. The final category (“glass from glass 

products” – NAICS 327215) was not modeled as a process flow with technology choice but instead endowed with fuel-specific 

UECs which evolved over time via TPC.

54 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Table 6.3. Coefficients for technology possibility curve for manufacturing industries and all industrial scenarios

applies to all fuels unless specified

Industry/Process Unit

Existing Facilities New Facilities

Reference 

REI20401

High 

Tech REI 

20401

Reference 

TPC%2

High 

Tech 

TPC%2

REI 

20103

Reference 

REI20404

High 

Tech REI 

20404

Reference 

TPC%2

High Tech 

TPC%2

Food Products- Milling

Process Heating-Electricity 0.900 0.987 -0.351 -0.045 0.900 0.800 0.875 -0.392 -0.094

Process Heating-Steam 0.810 0.947 -0.701 -0.182 0.900 0.711 0.804 -0.784 -0.375

Process Cooling-Electricity 0.900 0.983 -0.351 -0.057 0.900 0.800 0.873 -0.392 -0.100

Process Cooling-Natural Gas 0.900 0.987 -0.351 -0.045 0.900 0.800 0.875 -0.392 -0.094

Other-Electricity 0.900 0.993 -0.351 -0.024 0.900 0.800 0.875 -0.392 -0.093

Other-Natural Gas 0.950 0.987 -0.171 -0.045 0.950 0.850 0.924 -0.370 -0.094

Food Products-Dairy

Process Heating-Electricity 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Process Heating-Steam 0.930 0.947 -0.242 -0.182 0.950 0.850 0.849 -0.370 -0.375

Process Cooling-Electricity 0.900 0.983 -0.351 -0.057 0.900 0.800 0.873 -0.392 -0.100

Process Cooling-Natural Gas 0.980 0.987 -0.067 0.045 0.970 0.950 0.943 -0.069 -0.094

Other-Electricity 0.930 0.993 -0.242 0.024 0.960 0.850 0.934 -0.405 -0.093

Other-Natural Gas 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Food Products-Animal 

Processing

Process Heating-Electricity 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Process Heating-Steam 0.950 0.947 -0.171 -0.182 0.950 0.900 0.849 -0.180 -0.375

Process Cooling-Electricity 0.930 0.983 -0.242 -0.057 0.950 0.850 0.922 -0.370 -0.100

Process Cooling-Natural Gas 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Other-Electricity 0.950 0.993 -0.171 -0.024 0.980 0.900 0.953 -0.283 -0.093

Other-Natural Gas 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Food Products-Other

Process Heating-Electricity 0.980 0.987 -0.067 0.045 0.970 0.950 0.943 -0.069 -0.094

Process Heating-Steam 0.930 0.947 -0.242 -0.182 0.950 0.850 0.849 -0.370 -0.375

Process Cooling-Electricity 0.930 0.983 -0.242 -0.057 0.950 0.850 0.922 -0.370 -0.100

Process Cooling-Natural Gas 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Other-Electricity NA NA -0.171 -0.024 NA NA NA -0.215 -0.097

Other-Natural Gas 0.980 0.987 -0.067 -0.045 0.970 0.950 0.943 -0.069 -0.094

Paper & Allied Products

Wood Preparation 0.785 0.990 -0.802 -0.033 0.882 0.696 0.990 -0.790 -0.386

Waste Pulping-Electricity 0.934 0.953 -0.228 -0.161 0.936 0.936 0.874 0.000 -0.228

Waste Pulping-Steam 0.872 0.908 -0.456 -0.322 0.936 0.936 0.816 0.000 -0.456

Mechanical Pulping-Electricity 0.794 1.006 -0.767 0.021 0.931 0.613 1.215 -1.380 0.893

Mechanical Pulping-Steam 0.629 1.013 -1.533 0.043 0.931 0.402 1.583 -2.760 1.787

Semi-Chemical-Electricity 0.949 0.983 -0.173 -0.025 0.971 0.929 0.956 -0.149 -0.052

Semi-Chemical-Steam 0.901 0.985 -0.346 -0.051 0.971 0.888 0.941 -0.297 -0.105

Kraft, Sulfite, Misc. Chemicals 0.856 0.928 -0.519 -0.249 0.914 0.807 0.786 -0.415 -0.502

Kraft, Sulfite, Misc ChemicalsSteam 0.731 0.861 -1.037 -0.498 0.914 0.712 0.675 -0.830 -1.004

Bleaching-Electricity 0.773 0.927 -0.853 -0.252 0.878 0.674 0.913 -0.878 0.129

Bleaching-Steam 0.597 0.859 -1.706 -0.504 0.878 0.516 0.949 -1.756 0.259

 Paper Making 0.864 0.830 -0.485 -0.621 0.885 0.851 0.584 -0.132 -1.376

 Paper Making-Steam 0.747 0.687 -0.969 -1.242 0.885 0.818 0.383 -0.264 -2.753

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 55
Industrial Demand Module

Table 6.3. Coefficients for technology possibility curve for industries and all industrial scenarios (cont.)

applies to all fuels unless specified

Industry/Process Unit

Existing Facilities New Facilities

Reference 

REI20401

High 

Tech REI 

20401

Reference 

TPC%2

High 

Tech 

TPC%2

REI 

20103

Reference 

REI20404

High 

Tech REI 

20404

Reference 

TPC%2

High 

Tech 

TPC%2

Iron and Steel

Coke Oven-Electricity 0.932 0.879 -0.233 -0.429 0.902 0.868 0.652 -0.128 -1.216

Coke Oven-Steam 0.869 0.772 -0.467 -0.858 0.902 0.835 0.470 -0.257 -2.152

BF/BPF-Electricity 0.993 0.950 -0.022 -0.172 0.987 0.987 0.882 NA -0.375

BF/BOF-Steam 0.987 0.902 -0.045 -0.345 0.987 0.987 0.787 NA -0.751

EAF-Electricity 0.912 0.901 -0.308 -0.346 0.990 0.825 0.775 -0.606 -0.813

Hot Rolling7 0.810 0.902 -0.699 -0.344 0.800 0.628 0.596 -0.804 -0.978

Hot Rolling-Steam7 0.656 0.813 -1.397 -0.687 0.800 0.492 0.442 -1.608 -1.956

Cold Rolling7 0.709 0.947 -1.141 -0.183 0.924 0.422 0.851 -2.580 -0.273

Cold Rolling-Steam7 0.500 0.896 -2.281 -0.365 0.924 0.189 0.784 -5.160 -0.546

Bulk Chemicals

Process Heating-Electricity 0.893 0.965 -0.376 -0.120 0.900 0.793 0.861 -0.420 -0.149

Process Heating-Steam 0.798 0.866 -0.751 -0.478 0.990 0.699 0.752 -0.840 -0.597

Process Cooling-Electricity 0.867 0.951 -0.476 -0.168 0.850 0.743 0.810 -0.446 -0.159

Process Cooling-Natural Gas 0.893 0.965 -0.376 -0.120 0.900 0.793 0.861 -0.420 -0.149

Electro-Chemicals 0.979 0.993 -0.072 -0.025 0.950 0.843 0.911 -0.396 -0.141

Other-Electricity 0.908 0.967 -0.321 -0.113 0.915 0.803 0.873 -0.434 -0.155

Other-Natural Gas 0.893 0.965 -0.376 -0.120 0.900 0.793 0.861 -0.420 -0.149

Metal-based Durables

Fabricated Metals

Process Heating-Electricity 0.712 0.642 -1.427 -1.468 0.675 0.406 0.329 -1.679 -2.370

Process Cooling-Electricity 0.650 0.576 -1.427 -1.820 0.638 0.371 0.299 -1.784 -2.493

Process Cooling-Natural Gas 0.712 0.642 -1.127 -1.468 0.675 0.406 0.329 -1.679 -2.370

Electro-Chemical Process 0.937 0.887 -0.216 -0.398 0.713 0.441 0.359 -1.586 -2.261

Other-Electricity 0.748 0.681 -0.962 -1.274 0.686 0.406 0.327 -1.737 -2.439

Machinery

 Process-Heating-Electricity 0.712 0.642 -1.427 -1.468 0.675 0.314 0.329 -2.519 -2.370

 Process Cooling-Electricity 0.650 0.576 -1.427 -1.820 0.638 0.283 0.299 -2.676 -2.493

 Process Cooling-Natural Gas 0.712 0.642 -1.127 -1.468 0.675 0.314 0.329 -2.519 -2.370

 Electro-Chemicals 0.937 0.887 -0.216 -0.398 0.713 0.346 0.359 -2.379 -2.251

 Other-Electricity 0.748 0.681 -0.962 -1.274 0.686 0.311 0.327 -2.606 -2.439

Computers and Electronics

Process Heating-Electricity 0.798 0.744 -0.751 -0.979 0.720 0.559 0.504 -0.840 -1.185

Process Cooling-Electricity 0.751 0.693 -0.952 -1.213 0.680 0.520 0.467 -0.892 -1.247

Process Cooling-Natural Gas NA NA -0.751 -0.979 NA NA NA -0.840 -1.185

Electro-Chemical Process 0.958 0.923 -0.144 -0.265 0.760 0.599 0.540 -0.793 -1.130

Other-Electricity 0.824 0.774 -0.641 -0.850 0.732 0.563 0.507 -0.869 -1.219

Electrical Equipment

Process Heating-Electricity 0.798 0.744 -0.751 -0.979 0.720 0.559 0.504 -0.840 -1.185

Process Heating-Steam NA NA -1.502 -3.914 NA NA NA -1.679 -4.740

Process Cooling-Electricity 0.751 0.693 -0.952 -1.213 0.680 0.520 0.467 -0.892 -1.247

Process Cooling-Natural Gas 0.798 0.744 -0.751 -0.979 0.720 0.559 0.504 -0.840 -1.185

Electro-Chemical Process 0.958 0.923 -0.144 -0.265 0.760 0.599 0.540 -0.793 -1.130

Other-Electricity 0.824 0.774 -0.641 -0.850 0.732 0.563 0.507 -0.869 -1.219

56 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Table 6.3. Coefficients for technology possibility curve for all industrial scenarios (cont.)

applies to all fuels unless specified

Industry/Process Unit

Existing Facilities New Facilities

Reference 

REI20401

High 

Tech REI 

20401

Reference 

TPC%2

High 

Tech 

TPC%2

REI 

20103

Reference 

REI20404

High 

Tech REI 

20404

Reference 

TPC%2

High 

Tech 

TPC%2

Transportation Equipment

Process Heating-Electricity 0.854 0.814 -0.526 -0.685 0.765 0.625 0.575 -0.672 -0.948

Process Heating-Steam 0.728 0.435 -1.052 -2.740 0.765 0.510 0.240 -1.343 -3.792

Process Cooling-Electricity 0.818 0.774 -0.666 -0.849 0.723 0.583 0.535 -0.714 -0.997

Process Cooling-Natural Gas 0.854 0.814 -0.526 -0.685 0.765 0.625 0.575 -0.672 -0.948

Electro-Chemical Process 0.970 0.946 -0.101 -0.186 0.808 0.667 0.615 -0.634 -0.904

Other-Electricity 0.874 0.836 -0.449 -0.595 0.778 0.631 0.580 -0.695 -0.975

Other-Non-Intensive Manufacturing

Wood Products

Process Heating-Electricity 0.712 0.654 -1.127 -1.452 0.630 0.379 0.308 -1.679 -2.358

Process Heating-Steam 0.505 0.166 -2.253 -5.807 0.630 0.226 0.032 -3.358 -9.432

Process Cooling-Electricity 0.650 0.579 -1.427 -1.804 0.595 0.347 0.280 -1.784 -2.481

Process Cooling-Natural Gas 0.712 0.645 -1.127 -1.452 0.630 0.379 0.308 -1.679 -2.358

Electro-Chemical Process 0.937 0.969 -0.216 -0.502 0.665 0.412 0.600 -1.586 -0.342

Other-Electricity 0.748 0.875 -0.962 -0.443 0.641 0.379 0.310 -1.737 -2.388

Plastic Products

Process Heating-Electricity 0.798 0.747 -0.751 -0.968 0.675 0.524 0.473 -0.840 -1.179

Process Heating-Steam 0.635 0.306 -1.502 -3.871 0.675 0.406 0.158 -1.679 -4.716

Process Cooling-Electricity 0.751 0.696 -0.952 -1.203 0.638 0.487 0.438 -0.892 -1.241

Process Cooling-Natural Gas 0.798 0.747 -0.751 -0.968 0.675 0.524 0.473 -0.840 -1.179

Electro-Chemical Process 0.958 0.979 -0.144 -0.070 0.713 0.561 0.677 -0.793 -0.171

Other-Electricity 0.824 0.915 -0.641 -0.295 0.686 0.528 0.479 -0.869 -1.194

Balance of Manufacturing

Process Heating-Electricity 0.844 0.804 -0.563 -0.726 0.675 0.551 0.508 -0.672 -0.943

Process Heating-Steam 0.712 0.627 -1.127 -1.546 0.675 0.450 0.292 -1.343 -2.753

Process Cooling-Electricity 0.825 0.762 -0.714 -0.902 0.638 0.514 0.473 -0.714 -0.992

Process Cooling-Natural Gas 0.844 0.804 -0.563 -0.726 0.675 0.551 0.508 -0.672 -0.943

Electro-Chemical Process 0.968 0.984 -0.108 -0.053 0.713 0.589 0.684 -0.634 -0.137

Other Natural Gas 0.844 0.826 -0.563 -0.636 0.675 0.551 0.517 -0.672 -0.883 1

REI 2040 Existing Facilities = Ratio of 2040 energy intensity to average 2010 energy intensity for existing facilities.

2

TPC = annual rate of change between 2010 and 2040.

3

REI 2010 New Facilities = For new facilities, the ratio of state-of-the-art energy intensity to average 2010 energy intensity for existing facilities.

4REI 2040 New Facilities = Ratio of 2040 energy intensity for a new state-of-the-art facility to the average 2010 intensity for existing facilities.

5

REI’s and TPCs apply to virgin and recycled materials.

6

No new plants are likely to be built with these technologies.

7

Net shape casting is projected to reduce the energy requirements for hot and cold rolling rather than for the continuous casting step. 

NA = Not applicable.

BF = Blast furnace. 

BOF = Basic oxygen furnace. 

EAF = Electric arc furnace. 

Source: SAIC, IDM Base Year Update with MECS 2010 Data, unpublished data prepared for the Industrial Team, Office of Energy Consumption and Efficiency 

Analysis, Energy Information Administration, Washington, DC, July 2013.

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 57
Industrial Demand Module

Table 6.4. Cost and performance parameters for industrial motor choice model

Industrial Sector 

Horsepower Range

2002 Stock 

Efficiency (%)

Premium 

Efficiency (%)

Premium

Cost

(2002$) 

Food

1-5 hp 81.3 89.2 601

6 - 20 hp 87.1 92.5 1,338

21 - 50 hp 90.1 93.8 2,585

51 - 100 hp 92.7 95.3 6,290

101 - 200 hp 93.5 95.2 11,430

201 - 500 hp 93.8 95.4 29,991

> 500 hp 93.0 96.2 36,176

Bulk Chemicals

1-5 hp 82.0 89.4 601

6 - 20 hp 87.4 92.6 1,338

21 - 50 hp 90.4 93.9 2,585

51 - 100 hp 92.4 95.4 6,290

101 - 200 hp 93.5 95.3 11,430

201 - 500 hp 93.3 95.5 29,991

> 500 hp 93.2 96.2 36,176

Metal-Based Durablesa

1-5 hp 81.9 89.2 601

6-20 hp 87.0 92.5 1,338

21-50 hp 89.9 93.9 2,585

51-100 hp 92.0 95.3 6,290

101-200 hp 93.5 95.2 11,430

201-500 hp 93.7 95.4 29,991

>500 hp 93.0 96.2 36,176

Balance of Manufacturingb

1-5 hp 83.0 89.2 601

6-20 hp 88.3 92.5 1,338

21-50 hp 90.3 93.9 2,585

51-100 hp 92.7 95.3 6,290

101-200 hp 94.3 95.2 11,430

201-500 hp 94.2 95.4 29,991

>500 hp 92.9 96.2 36,176

a

The metal-based durables group includes five sectors that are modeled separately: Fabricated Metals; 

Machinery; Computers and Electronics; Electrical Equipment; and Transportation Equipment.

b

The balance of manufacturing group includes three sectors that are modeled separately: Wood Products; 

Plastic and Rubber Products; and All Other Manufacturing.

Source: U.S. Energy Information Administration, Model Documentation Report, Industrial Sector Demand Module of the National Energy Modeling System, 

(Washington, DC, September 2013).

Note: The efficiencies listed in this table are operating efficiencies based on average part-loads. Because the average part-load is not the same for all 

industries, the listed efficiencies for the different motor sizes vary across industries.

58 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Below is a summary list of technologies used in the glass sub-module. Not all of the technologies below are available to all 

processes.

1. The preparation step (collection, grinding, and mixing of raw materials including cullet) uses either a standard set of grinders/

motors or an advanced set that is computer-controlled.

2. The furnaces, which melt the glass, are air-fueled or oxy-fueled burners which employ natural gas. Electric boosting furnace 

technology is also available. Direct electric (or Joule) heating is available for fiberglass production.

3. The form & finish process is done for all glass products and the technologies can be selected from high-pressure gas-fired 

computer controlled or basic technology. 

4. There is no known technology choice for the tempering step (flat glass) or the polish (blown glass). Placeholders for more 

efficient future technology choices were implemented, but their introduction into these processes was rather limited.

As with the other sub-modules, the technology slate in each of these process steps evolves over time and depends on the relative 

cost of equipment, cost of fuel, and fuel efficiency. Oxy-fueled burners were added as a retrofit to the burner technologies, and 

their additive impact is determined by the relative price of natural gas vs. electricity.

Petrochemical feedstock requirement

This subroutine estimates feedstock requirements for the major petrochemical intermediates such as ethylene, propylene, and 

butadiene. The primary feedstocks used to produce these chemicals are natural gas liquids (NGL) (ethane, propane, butane) and 

petrochemical (oil-based) feedstocks (gas oil, naphtha) [6]. Biomass is a potential raw material source, but it is assumed that 

there will be no biomass-based capacity over the projection period because of economic barriers. The type of feedstock not only 

determines the source of feedstock but also the energy for heat and power requirements to produce the chemicals.

To determine the relative amounts of feedstock (NGL or oil-based) baseline intensities, feedstock consumption intensities are 

derived from the 2010 MECS. Feedstock consumption of both types grows or declines with organic chemicals shipment value. 

It should be noted that there is no change in the feedstock intensity over time, i.e., all feedstock TPCs are assumed to be zero. 

Unlike most other processes represented in manufacturing PA components, chemical yields are governed by basic chemical 

stoichiometry which allows for specific yields under set conditions of pressure and temperature. For the projected LPG feedstock 

quantities, a further subdivision is made into refinery-produced propylene and ethane. All ethane produced by the NEMS Oil 

and Gas Supply Module is absorbed by the chemical model. The remaining balance of LPG feedstock requirement is a mixture of 

pentanes plus, butane, and propane.

Buildings component 

The total buildings energy demand by industry for each region is a function of regional industrial employment and output. Building 

energy consumption was estimated for building lighting, HVAC (heating, ventilation, and air conditioning), facility support, and 

on-site transportation. Space heating was further divided to estimate the amount provided by direct combustion of fossil fuels and 

that provided by steam (Table 6.5). Energy consumption in the BLD Component for an industry is estimated based on regional 

employment and output growth for that industry using the 2010 MECS as a basis. 

Boiler, steam, and cogeneration component

The steam demand and byproducts from the PA and BLD Components are passed to the BSC Component, which applies a heat 

rate and a fuel share equation (Table 6.6) to the boiler steam requirements to compute the required energy consumption.

The boiler fuel shares apply only to the fuels that are used in boilers for steam-only applications. Fuel use for the portion of the 

steam demand associated with combined heat and power (CHP) is described in the next section. Some fuel switching for the 

remainder of the boiler fuel use is assumed and is calculated with a logit-sharing equation where fuels shares are a function of fuel 

prices. The equation is calibrated to 2010 so that the 2010 fuel shares are produced for the relative prices that prevailed in

2010.

The byproduct fuels, production of which is estimated in the PA Component, are assumed to be consumed without regard to price, 

independent of purchased fuels. The boiler fuel share equations and calculations are based on the 2010 MECS and information 

from the Council of Industrial Boiler Owners. [8]

Combined heat and power

CHP plants, which are designed to produce both electricity and useful heat, have been used in the industrial sector for many years. 

The CHP estimates in the module are based on the assumption that the historical relationship between industrial steam demand 

and CHP will continue in the future, and that the rate of additional CHP penetration will depend on the economics of retrofitting 

CHP plants to replace steam generated from existing non-CHP boilers. The technical potential for CHP is primarily based on 

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 59
Industrial Demand Module

supplying thermal requirements (i.e., matching thermal loads). Capacity additions are then determined by the interaction of 

CHP investment payback periods (with the time-value of money included) derived using operating hours reported in EIA’s 

published statistics, market penetration rates for investments with those payback periods, and regional deployment for these 

systems as characterized by the “collaboration coefficients” in Table 6.8. Assumed installed costs for the CHP systems are 

given in Table 6.7.

Table 6.5. 2010 Building component energy consumption 

trillion Btu

Industry

Building Use and Energy Source

Region

Lighting 

Electricity 

Consumption

HVAC 

Electricity 

Consumption

HVAC 

Natural Gas 

Consumption

HVAC

Steam 

Consumption

Facility

Support

Total

Consumption

Onsite 

Transportation 

Total 

Consumption

Food Products 1 2.1 2.1 3.3 2.1 1.7 0.9

2 9.7 9.7 14.8 4.9 7.4 0.9

3 6.8 6.8 8.7 5.5 4.4 1.6

4 3.5 3.5 7.4 4.7 3.8 3.0

Paper & Allied Products 1 1.2 1.3 2.8 0.0 0.3 0.9

2 3.7 4.0 3.3 0.0 0.3 0.9

3 6.8 7.4 7.1 0.0 0.7 2.0

4 3.2 3.4 2.2 0.0 0.3 0.9

Bulk Chemicals 1 0.8 1.0 3.7 0.0 2.8 5.2

2 2.9 3.5 5.8 0.0 3.9 5.6

3 7.7 9.3 15.0 0.0 9.0 9.7

4 0.9 1.0 3.7 0.0 2.8 5.0

Glass & Glass Products 1 0.4 0.5 3.8 0.0 3.2 3.4

2 0.7 0.9 4.1 0.0 3.3 3.4

3 0.9 1.2 4.5 0.0 3.4 3.5

4 0.3 0.4 3.4 0.0 3.1 3.4

Cement 1 0.1 0.1 0.6 0.0 0.6 1.1

2 0.3 0.3 0.6 0.0 0.6 1.1

3 0.4 0.4 0.7 0.0 0.7 1.1

4 0.2 0.2 0.5 0.0 0.5 0.6

Iron and Steel 1 0.8 0.8 1.9 0.0 0.7 0.6

2 2.7 2.7 8.7 0.0 1.9 2.4

3 3.1 3.1 3.6 0.0 1.0 1.7

4 0.4 0.4 1.0 0.0 0.6 0.6

Aluminum 1 0.2 0.2 0.5 0.0 0.2 0.2

2 0.8 0.8 1.0 0.0 0.3 0.3

3 0.8 0.8 2.6 0.0 0.7 0.8

4 0.3 0.3 0.4 0.0 0.1 0.2

Metal-Based Durables 

 Fabricated Products 1 1.8 1.5 5.1 2.9 0.6 1.4

2 6.6 5.6 16.3 9.1 1.2 1.5

3 5.2 4.4 8.8 5.0 0.8 1.7

4 1.4 1.2 2.6 1.5 0.2 0.3

Machinery 1 1.6 2.3 4.2 0.7 0.2 0.2

2 4.8 6.8 20.7 3.6 0.9 0.9

3 3.1 4.3 8.6 1.5 0.5 0.7

4 0.6 0.8 0.5 0.1 0.1 0.2

Computers & Electronic Products 1 2.2 5.6 4.2 2.5 0.9 0.8

2 2.0 4.0 4.4 2.7 0.9 0.8

3 4.2 10.5 4.4 2.7 0.9 0.8

4 4.1 10.2 9.4 5.7 1.2 0.8

Transportation Equipment 1 1.6 2.0 4.8 0.4 0.6 0.2

2 10.5 13.1 23.1 2.1 2.0 1.2

3 6.1 7.6 10.1 0.9 1.1 0.8

4 2.5 3.1 3.9 0.4 0.3 0.2

Electrical Equipment 1 0.7 1.0 1.7 1.3 0.5 0.5

2 1.1 1.6 2.6 2.1 0.4 0.4

3 2.1 3.1 4.0 3.1 0.6 0.4

4 0.2 0.3 0.1 0.1 0.1 0.4

Other Non-Intensive Manufacturing 

Wood Products 1 0.2 0.2 0.8 2.5 0.5 0.4

2 0.6 0.5 1.6 4.9 0.7 1.7

3 2.4 1.8 2.7 8.4 0.7 2.1

4 0.8 0.6 1.3 4.0 0.3 4.2

60 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Table 6.5. 2010 Building component energy consumption (cont.) 

trillion Btu

Industry

Building Use and Energy Source

Region

Lighting 

Electricity 

Consumption

HVAC 

Electricity 

Consumption

HVAC 

Natural Gas 

Consumption

HVAC

Steam 

Consumption

Facility

Support

Total

Consumption

Onsite 

Transportation 

Total 

Consumption

Plastic Products 1 0.8 0.9 1.8 0.0 0.2 0.3

2 4.5 5.6 7.7 0.0 0.5 0.7

3 5.5 6.8 10.3 0.0 0.7 0.8

4 2.5 3.0 2.1 0.0 0.2 0.2

Balance of Manufacturing 1 5.5 9.1 13.4 0.0 0.0 1.2

2 10.5 17.4 20.6 0.0 0.0 2.1

3 15.7 26.0 28.1 0.0 0.0 3.4

4 4.5 7.5 9.5 0.0 0.0 0.8

HVAC = Heating, Ventilation, Air Conditioning.

Source: SAIC, IDM Base Year Update with MECS 2010 Data, unpublished data prepared for the Industrial Team, Office of Energy Consumption and Efficiency Analysis, Energy Information Administration, Washington, DC, July 

2013.

Table 6.6. 2010 Boiler fuel component and logit parameter 

trillion Btu

Region Alpha Natural Gas Coal Oil Renewables

Food Products 1 -2.0 33 1 3 1

2 -2.0 147 131 3 31

3 -2.0 85 14 6 31

4 -2.0 74 18 3 8

Paper & Allied Products 1 -2.0 44 44 8 122

2 -2.0 55 55 9 97

3 -2.0 113 81 45 898

4 -2.0 35 16 2 108

Bulk Chemicals 1 -2.0 17 0 55 0

2 -2.0 164 43 17 0

3 -2.0 705 18 56 0

4 -2.0 21 44 6 0

Glass & Glass Products 1 -2.0 1 0 2 1

2 -2.0 1 0 2 1

3 -2.0 1 0 2 1

4 -2.0 0 0 2 1

Cement 1 -2.0 0 0 0 1

2 -2.0 0 0 0 5

3 -2.0 0 0 0 3

4 -2.0 0 0 0 1

Iron & Steel 1 -2.0 4 6 16 0

2 -2.0 24 0 64 0

3 -2.0 9 0 14 0

4 -2.0 2 0 0 0

Aluminum 1 -2.0 1 0 0 0

2 -2.0 3 0 0 1

3 -2.0 8 0 1 1

4 -2.0 1 0 0 0

Metal-Based Durables 

 Fabricated Metal Products 1 -2.0 4 0 0 0

2 -2.0 12 0 0 0

3 -2.0 6 0 0 0

4 -2.0 2 0 0 0

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 61
Industrial Demand Module

Table 6.6. 2010 Boiler fuel component and logit parameter (cont.) 

trillion Btu

Region Alpha Natural Gas Coal Oil Renewables

Machinery 1 -2.0 1 0 0 1

2 -2.0 4 0 1 1

3 -2.0 2 0 0 0

4 -2.0 0 0 0 0

Computers & electronic Products 1 -2.0 3 0 1 0

2 -2.0 3 0 1 0

3 -2.0 3 0 1 0

4 -2.0 7 0 1 0

Electrical Equipment 1 -2.0 1 0 1 0

2 -2.0 2 0 0 0

3 -2.0 3 0 0 0

4 -2.0 0 0 0 0

Transportation Equipment 1 -2.0 3 8 2 1

2 -2.0 17 -5 1 3

3 -2.0 7 1 2 1

4 -2.0 3 0 0 0

Other Non-Intensive Manufacturing

 Wood Produts 1 -2.0 0 0 1 79

2 -2.0 1 0 2 31

3 -2.0 4 0 2 188

4 -2.0 2 0 2 54

Plastic Products 1 -2.0 3 2 1 0

2 -2.0 16 0 0 0

3 -2.0 21 0 1 0

4 -2.0 4 0 0 0

Balance of Manufacturing 1 -2.0 35 -10 3 1

2 -2.0 54 29 37 5

3 -2.0 74 42 118 10

4 -2.0 25 7 0 1

Alpha: User-specified.

Source: U.S. Energy Information Administration, Model Documentation Report, Industral Sector Demand Module of the National Energy Modeling 

System, (publication pending) (Washington, DC 2013).

Table 6.7. Cost characteristics of industrial CHP systems

System

Size Kilowatts 

(KW)

Installed Cost 

(2005$ per KWh)1

Reference 2010 Reference 2040 High Tech 2040

Engine 1000 1440 576 535

2000 1260 396 354

Gas turbine 3510 1719 1496 1450

5670 1152 1023 1006

14990 982 869 869

25000 987 860 860

40000 875 830 830

Combined cycle 100000 723 684 668

1

Costs are given in 2005 dollars in original source document.

Source: U.S. Energy Information Administration, Model Documentation Report, Industrial Sector Demand Module of the National Energy Modeling

System, (Washington, DC, September 2013).

62 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Table 6.8. Regional collaboration coefficients for CHP deployment

Census Region Collaboration Coefficient

Northeast 1.46

Midwest 1.34

South 0.33

West 1.06

Source: Calculated from American Council for an Energy-Efficient Economy, “Challenges Facing Combined Heat and Power Today: A 

State-by-State Assessment,” September 2011, website: www.aceee.org/research-report/ie111 and Energy Information Administration, 

Office of Energy Analysis.

Key assumptions - non-manufacturing

The non-manufacturing sector consists of three industries: agriculture, mining and construction. These industries all use 

electricity, natural gas, diesel fuel, and gasoline. The mining industry also uses coal, natural gas liquids (NGL), and residual fuel 

oil, and the construction industry also uses other petroleum in the form of asphalt and road oil. Except for oil and gas extraction, 

almost all of the energy use in the nonmanufacturing sector takes place in the process and assembly step. Oil and gas extraction 

uses a significant amount of residual fuel oil in the BSC component. Table 6.9 shows the baseline unit energy consumption values 

for the nonmanufacturing subsectors in 2010.

Table 6.9 2010 UECs for nonmanufacturing 

Unit Energy Consumption (UEC) in thousand Btu/2005$)

Industry/Process UEC 2010 

Agriculture

 Crop Production

 Buildings 1.82

 Vehicles 2.21

 Irrigation 0.70

 Other Agricultural Production

 Buildings 0.64

 Vehicles 1.01

 Irrigation 0.27

Construction 1.65

Mining

 Coal 6.97

 Oil & Gas Extraction 1.74

 Metal/Non-metal 8.97

Sources: Calculations based on EIA’s State Energy Data System (SEDS), EIA’s Fuel Oil and Kerosene Survey (FOKS), USDA’s Agriculture 

Research Management Survey (ARMS), and Department of Commerce’s Economic Census, Construction and Mining Series. See Note and 

sources page notes [1], [9], [10], [11], [12] for complete citations.

Unlike the manufacturing sector, the non-manufacturing sector does not have a single source of data for energy consumption 

estimates. Instead, UECs for the non-manufacturing sector are derived from various sources of data collected by a number of 

government agencies. Furthermore, unlike the majority of manufacturing industries displayed in Table 6.3, the TPCs for nonmanufacturing are not “fixed” in that they are dynamic and evolve over time. This evolution depends on output from other 

modules such as building and transportation equipment efficiencies which are employed in the agriculture and construction 

models as well as oil & gas well and coal mine productivity which is employed in the mining model.

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 63
Industrial Demand Module

Nonmanufacturing data was revised using EIA and Census Bureau sources to provide more realistic projections of diesel and 

gasoline for off road vehicle use, allocate natural gas and hydrocarbon gas liquids (HGL) use, and electricity. Sources used are 

EIA’s Fuel Oil and Kerosene Sales (FOKS) [9] for distillate consumption, Agricultural Resource Management Survey (ARMS)

[10] and the Census Bureau’s Census of Mining [11] and Census of Construction. [12] Combining these sources, there is now 

more consumption of distillate and less consumption of motor gasoline. Also, the use of hydrocarbon gas liquids (HGL) is now 

accounted for in the agriculture and especially the construction industries. Nonmanufacturing consumption is no longer dictated 

solely by the SEDS – MECS difference as it has been in previous years.

Agriculture

U.S. agriculture consists of three major sub-sectors: 

•	 crop production, which is dependent primarily on regional environments and crops demanded; 

•	 animal production, which is largely dependent on food demands and feed accessibility; 

•	 all remaining agricultural activities, which are primarily composed of forestry and logging. 

These sub-industries have historically been tightly coupled due to competing use of land area. For example, crops produced for 

animal feed cannot be consumed by humans; forests provide the feedstock of the paper and wood industries but in turn do not 

allow the growth of crops or limit or prevent grazing of animals.

However, energy consumption in these industries is tied to specialized equipment, which often determines the fuel requirement 

with little flexibility. Within each of these sub-industries the key energy-using equipment can be broken into three major 

categories: off-road vehicles, buildings, and other equipment, which is primarily irrigation equipment for crop production. 

Agriculture TPCs are calculated within the NEMS model by further subdividing consumption in each sub-industry based on 

the equipment in which the energy is used: off-road vehicles, which are trucks, tractors, and other specialty vehicles; buildings, 

which require lighting and temperature control; and other equipment, which covers a variety of both common (e.g., pumps) and 

specialty (e.g. cotton gins) equipment used in all the various types of agricultural production. Thus, changes in efficiencies in 

heavy and medium-duty vehicles from the Transportation Sector Module and changes in lighting and heating efficiencies from 

the Commercial Sector Demand Module are used to dynamically modify the agriculture TPCs.

Baseline energy consumption data for the two agriculture sectors (crops and other agriculture) is based on data from the 

Census of Agriculture and a special tabulation from the National Agricultural Statistics Service (USDA-NASS). Expenditures for 

four energy sources are collected from crop farms and livestock farms as part of the Agricultural Resource Management Survey 

(ARMS). These data are converted from dollar expenditures to energy quantities using fuel prices from NASS and EIA.

Mining

The mining sector is comprised of three sectors: coal mining, and metal and nonmetal mining, and oil and gas extraction, Energy 

use is based on what equipment is used at the mine and onsite vehicles used. All mines use extraction equipment and lighting, 

but only coal and metal and nonmetal mines use grinding and ventilation. As with the agriculture module described above, TPCs 

are influenced by efficiency changes in buildings and transportation equipment.

Coal mining production is obtained from Coal Market Module (CMM). Currently, it is assumed that 70 percent of the coal is 

mined at the surface and the rest is mined underground. As these shares evolve, however, so does the energy consumed since 

surface mines use less energy overall than underground mining. Moreover, the energy consumed for coal mining depends on coal 

mine productivity which is also obtained from the CMM. Diesel and electricity are the predominant fuels used in coal mining. 

Electricity used for coal grinding is calculated using the raw grinding process step from the cement sub-module. In metal and 

non-metal mining, energy use is similar to coal mining. Output used for metal and non-metal mining is derived from the Macro 

Analysis Module’s (MAM) variable for “other” mining which also provides the shares of each.

For oil and natural gas extraction, production is derived from the OGSM module. Energy use depends upon the fuel extracted as 

well as whether the well is conventional, or unconventional, e.g. extraction from tight and shale formations, percentage of dry 

wells, and well depth.

Construction

Construction uses diesel fuel, gasoline, electricity and natural gas as energy sources. Construction also uses asphalt and road 

oil as a nonfuel energy source. Asphalt and road oil use is tied to state and local government real investment in highways and 

streets, and this investment is derived from the MAM. TPCs for diesel and gasoline fuels are directly tied to the Transportation 

Sector Module’s heavy and medium duty vehicle efficiency projections. For non-vehicular construction equipment, TPCs are a 

weighted average of vehicular TPCs and highway investment.

64 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

Legislation and regulations

Energy Improvement and Extension Act of 2008

Under EIEA2008 Title I, “Energy Production Incentives,” Section 103 provides an Investment Tax Credit (ITC) for qualifying 

Combined Heat and Power (CHP) systems placed in service before January 1, 2017. Systems with up to 15 megawatts of electrical 

capacity qualify for an ITC up to 10 percent of the installed cost. For systems between 15 and 50 megawatts, the percentage 

tax credit declines linearly with the capacity, from 10 percent to 3 percent. To qualify, systems must exceed 60-percent fuel 

efficiency, with a minimum of 20 percent each for useful thermal and electrical energy produced. The provision was modeled in 

AEO2012 by adjusting the assumed capital cost of industrial CHP systems to reflect the applicable credit.

The Energy Independence and Security Act of 2007

Under EISA2007, the motor efficiency standards established under the Energy Policy Act of 1992 (EPACT) are superseded for 

purchases made after 2011. Section 313 of EISA2007 increases or creates minimum efficiency standards for newly manufactured 

and imported, general purpose electric motors. The efficiency standards are raised for general purpose, integral-horsepower 

induction motors with the exception of fire pump motors. Minimum standards were created for seven types of poly-phase, 

integral-horsepower induction motors and NEMA design “B” motors (201-500 horsepower) that were not previously covered 

by EPACT standards. The industrial module’s motor efficiency assumptions reflect the EISA2007 efficiency standards for new 

motors added after 2011.

Energy Policy Act of 1992 (EPACT)

EPACT contains several implications for the industrial module. These implications concern efficiency standards for boilers, 

furnaces, and electric motors. The industrial module uses heat rates of at least 1.25 (80 percent efficiency) and 1.22 (82 percent 

efficiency) for gas and oil burners, respectively. These efficiencies meet the EPACT standards. EPACT mandates minimum 

efficiencies for all motors up to 200 horsepower purchased after 1998. The choices offered in the motor efficiency assumptions 

are all at least as efficient as the EPACT minimums.

Clean Air Act Amendments of 1990 (CAAA90)

The CAAA90 contains numerous provisions that affect industrial facilities. Three major categories of such provisions are 

as follows: process emissions, emissions related to hazardous or toxic substances, and SO2 emissions. Process emissions 

requirements were specified for numerous industries and/or activities (40 CFR 60). Similarly, 40 CFR 63 requires limitations 

on almost 200 specific hazardous or toxic substances. These specific requirements are not explicitly represented in the NEMS 

industrial model because they are not directly related to energy consumption projections.

Section 406 of the CAAA90 requires the U.S. Environmental Protection Agency (EPA) to regulate industrial SO2 emissions 

at such time that total industrial SO2 emissions exceed 5.6 million tons per year (42 USC 7651). Since industrial coal use, 

the main source of SO2 emissions, has been declining, EPA does not anticipate that specific industrial SO2 regulations will be 

required (Environmental Protection Agency, National Air Pollutant Emission Trends: 1990-1998, EPA-454/R-00-002, March 

2000, Chapter 4). Further, since industrial coal use is not projected to increase, the industrial cap is not expected be a factor in 

industrial energy consumption projections. (Emissions due to coal-to-liquids CHP plants are included with the electric power 

sector because they are subject to the separate emission limits of large electricity generating plants.) 

Maximum Achievable Control Technology for Industrial Boilers (Boiler MACT)

Section 112 of the Clean Air Act (CAA) requires the regulation of air toxics through implementation of the National Standards for 

Hazardous Air Pollutants (NESHAP) for industrial, commercial, and institutional boilers. The final regulations, known as Boiler 

MACT, are modeled in the AEO2014. Pollutants covered by Boiler MACT include the hazardous air pollutants (HAP), hydrogen 

chloride (HCI), mercury (HG), dioxin/furan, carbon monoxide (CO),and particulate matter (PM). Generally, industries comply 

with the Boiler MACT regulations by including regular maintenance and tune-ups for smaller facilities and emission limits and 

performance tests for larger facilities. Boiler MACT is modeled as an upgrade cost in the Macroeconomic Activity Module 

(MAM). These upgrade costs are classified as “nonproductive costs” which are not associated with efficiency improvements. 

The effect of these costs in the MAM is a reduction in shipments coming into the Industrial Demand Module.

California Assembly Bill 32: Emissions cap-and-trade as part of the Global Warming Solutions Act of 2006 

(AB32)

AB32 established a comprehensive, multi-year program to reduce Green House Gas (GHG) emissions in California, including a 

cap-and-trade program. In addition to the cap-and-trade program, AB32 also authorizes the low carbon fuel standard (LCFS); 

energy efficiency goals and programs in transportation, buildings; and industry; combined heat and power goals; and renewable 

portfolio standards.

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 65
Industrial Demand Module

For AEO2014, the cap-and-trade provisions were modeled for industrial facilities, refineries, and fuel providers. GHG emissions 

include both non-CO2 and specific non-CO2 GHG emissions. The allowance price, representing the incremental cost of 

complying with AB32 cap-and-trade, is modeled in the NEMS Electricity Market Module via a region specific emissions 

constraint. This allowance price, when added to market fuel prices, results in higher effective fuel prices in the demand sectors. 

Limited banking and borrowing, as well as a price containment reserve and offsets, have been modeled in the NEMS. AB32 

is not modeled explicitly in the Industrial Module, but enters the module implicitly through higher effective fuel prices and 

macroeconomic effects of higher prices, all of which affect energy demand and emissions.

Industrial alternative cases

Technology cases

The Integrated High Demand Technology case inputs assume earlier availability, lower costs, and higher efficiency of more 

advanced equipment, based on engineering judgments and research compiled by Focis Associates in a 2005 study for EIA [13]. 

The Integrated High Demand Technology case inputs also assume that the rate at which biomass byproducts will be recovered 

from industrial processes 0.7 percent per year, as opposed to 0.4 percent per year in the Reference case. The availability of 

additional biomass leads to an increase in biomass-based cogeneration. Changes in aggregate energy intensity can result both 

from changing equipment and production efficiency and from changes in the composition of industrial output.

The Integrated 2013 Demand Technology case inputs hold the energy efficiency of industrial plant and equipment constant at 

the 2014 level over the projection period.

The IDM is used as part of the Low Renewable Technology Cost case. In this case, costs for non-hydropower renewable 

generating technologies are 20 percent lower than Reference case levels through 2040.

 Resource Cases

Two resource cases are used in AEO2014. The Industrial High Resource Case is a combination of High Economic Growth, High 

Oil & Gas Resource, and Industrial High Technology cases. The Industrial Low Resource Case is a combination of Low Economic 

Growth and Low Oil & Gas Resource cases. The intent is to examine the impact on industrial output, the mix of production, and 

energy consumption of changes in the level of oil and natural gas. 

In the Industrial High Resource Case, Higher oil and natural gas production drive more rapid growth in industrial output and 

change in mix of production by industry when compared with the Reference case. The impact of the greater oil and natural gas 

production are wide-spread and increase the probability of realizing the higher level of economic growth reflected in the High 

Economic Growth case and of achieving the technological advancements of the High Industrial Technology case.

In the Industrial Low Resource case oil and natural gas production is lower and prices higher than in the Reference Case, resulting 

in slower growth in industrial output. The lower oil and natural gas production levels result in a slower advance in the U.S. 

economy when compared with the Reference Case.

Additional Cases 

The Low Electricity Demand Case 

The Low Electricity Demand case uses the assumptions in the Best Available Technology case for the residential and commercial 

sectors and increases motor efficiency assumptions in the IDM to produce projections with zero electricity demand growth. 

This case assumes that all future equipment purchases in the residential and commercial sectors are made from a menu of 

technologies that includes only the most efficient models available in a particular year, regardless of cost. In the Low Electricity 

Demand case, industrial sector motor model input values were adjusted to increase the system savings values for pumps, fans 

and air compressors relative to the Reference case. This adjustment lowers total motor electricity consumption by slightly less 

than 20%. Although technically plausible, this decrease in motor adjustment is not intended to be a likely representation of 

motor development.

66 U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014
Industrial Demand Module

ESICA case

Senate bill S. 1392, The Energy Savings and Industrial Competitiveness Act of 2013 (ESICA) [14], was introduced in July 

2013 containing provisions for building energy codes, industrial energy efficiency, federal agencies and budget offsets. 

EIA examined two key provisions of the proposed legislation assuming appropriation of the funding authorized in the bill: 

the adoption of updated building energy codes for residential and commercial buildings, and a rebate program for energyefficient electric motors. Other provisions require further specification by federal agencies or Congress or address a level of 

detail beyond that modeled in NEMS. Amendments have been introduced that may have energy impacts, but they are not 

part of the bill as of this writing and are not considered in this analysis. Of the two analyzed provisions, the updated building 

codes has a small effect on energy consumption and CO2 emissions, and the industrial motors rebate program has virtually 

no effect. The analysis assumes that states will take advantage of incentives offered to implement the updated codes, and 

that once in place the codes are persistently effective over time.

Notes and sources

[1] U.S. Energy Information Administration, State Energy Data System, based on energy consumption by State through 2011, 

as downloaded in August, 2013, from www.eia.gov/state/seds/.

[2] U. S. Energy Information Administration, Manufacturing Energy Consumption Survey 2010, website 

http://www.eia.gov/consumption/manufacturing/index.cfm .

[3] Roop, Joseph M. “The Industrial Sector in CIMS-US,” Pacific Northwest National Laboratory, 28th Industrial Energy 

Technology Conference, May, 2006.

[4] Portland Cement Association, U.S. and Canadian Portland Cement Industry Plant Information Summary, cement data was 

made available under a non-disclosure agreement, website www.cement.org/.

[5] U.S. Department of the Interior, U.S. Geological Survey, Minerals Yearbook, cement data was made available under a nondisclosure agreement, website www.minerals.usgs.gov/minerals/pubs/commodity/cement/.

[6] In NEMS, hydrocarbon gas liquids (HGL), which are comprised of natural gas liquids (NGL) and olefins is reported as 

Liquefied Petroleum Gas (LPG).

[7] U.S., Department of Energy(2007). Motor Master+ 4.0 software database; available at updated link 

www1.eere. energy.gov/manufacturing/tech_deployment/software_motormaster.html.

[8] Personal correspondence with the Council of Industrial Boiler Owners.

[9] U.S. Energy Information Administration, Fuel Oil and Kerosene Survey (FOKS), 

http://www.eia.gov/dnav/pet/pet_cons_821usea_dcu_nus_a.htm.

[10] Agriculture Research Management Survey (ARMS), United Stataes Dept. of Agriculture, Economic Research Service, 

http://www.ers.usda.gov/data-products/arms-farm-financial-and-crop-production-practices.aspx#.UxcWZ_ldWCm. 

[11] 2007 Economic Census, Construction Summary Series, http://factfinder2.census.gov/faces/tableservices/jsf/pages/

productview.xhtml?pid=ECN_2007_US_23SG01&prodType=table.

[12] 2007 Economic Census, Mining Industry Series, http://factfinder2.census.gov/faces/tableservices/jsf/pages/

productview.xhtml?pid=ECN_2007_US_21I1&prodType=table.

[13] U.S. Energy Information Administration, Industrial Technology and Data Analysis Supporting the NEMS Industrial Model 

(Focis Associates, October 2005).

[14] U.S. Congress, “Energy Savings and Industrial Competitiveness Act of 2013, S. 1392, 

http://beta.congress.gov/bill/113th-congress/senate-bill/1392?q={%22search%22:[%22S.%201392%22]}

U.S. Energy Information Administration | Assumptions to the Energy Outlook 2014 67
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Transportation Demand Module 
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Transportation Demand Module

The NEMS Transportation Demand Module estimates transportation energy consumption across the nine Census Divisions 

(see Figure 5) and over ten fuel types. Each fuel type is modeled according to fuel-specific and associated technology attributes 

applicable by transportation mode. Total transportation energy consumption is the sum of energy use in eight transport modes: 

light-duty vehicles (cars and light trucks), commercial light trucks (8,501-10,000 pounds gross vehicle weight), freight trucks 

(>10,000 pounds gross vehicle weight), buses, freight and passenger aircraft, freight and passenger rail, maritime freight 

shipping, and miscellaneous transport such as recreational boating. Light-duty vehicle fuel consumption is further subdivided 

into personal usage and commercial fleet consumption. 

Key assumptions 

Light-duty vehicle assumptions 

The light-duty vehicle Manufacturers Technology Choice Component (MTCC) includes 86 advanced technology input 

assumptions specific to cars and light trucks (Tables 7.1 and 7.2) that include incremental fuel economy improvement, 

incremental cost, incremental weight change, first year of introduction, and fractional horsepower change.

The vehicle sales share module holds the share of vehicle sales by manufacturers constant within a vehicle size class at 2010 

levels based on National Highway Traffic Safety Administration (NHTSA) data [1]. Environmental Protection Agency (EPA) size 

class sales shares are projected as a function of income per capita, fuel prices, and average predicted vehicle prices based on 

endogenous calculations within the MTCC [2].

The MTCC utilizes 86 technologies for each size class and manufacturer based on the cost-effectiveness of each technology 

and an initial year of availability. A discounted stream of fuel savings is calculated for each technology that is compared to the 

marginal cost to determine cost-effectiveness and market penetration. The fuel economy module assumes the following: 

•	 The financial parameters used to determine technology economic effectiveness are evaluated based on the need to improve 

fuel economy to meet CAFE standards versus consumer willingness to pay for fuel economy improvement beyond those 

minimum requirements.

•	 Fuel economy standards for light-duty vehicles reflect current law through model year 2025, according to NHTSA model year 

2011 final rulemaking, joint EPA and NHTSA rulemaking for 2012 through 2016, and joint EPA and NHTSA rulemaking for 2017 

through 2025. CAFE standards enacted for model years 2022 through 2025 will undergo a midterm evaluation by NHTSA and 

could be subject to change. For model years 2026 through 2040, fuel economy standards are held constant at model year 

2025 levels with fuel economy improvements still possible based on continued improvements in economic effectiveness.

•	 Expected future fuel prices are calculated based on an extrapolation of the growth rate between a five-year moving average of 

fuel price 3 years and 4 years prior to the present year. This assumption is founded upon an assumed lead time of 3 to 4 years 

to significantly modify the vehicles offered by a manufacturer.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 71
Transportation Demand Module

Table 7.1. Standard technology matrix for cars1

Fuel

Efficiency

Change %

Incremental 

Cost 2000$

Incremental Cost

($/UnitWt.)

Absolute 

Incremental Weight 

(Lbs.)

Per Unit 

Incremental 

Weight (Lbs./

UnitWt.)

Introduction YearHorsepower

Change %

Unit Body Construction 4.0 99.91 0.00 0 -6 1980 0

Mass Reduction I 1.0 0.00 0.06 0 -1.5 2005 0

Mass Reduction II 2.6 0.00 0.14 0 -3.5 2009 0

Mass Reduction III 5.4 0.00 0.42 0 -10 2011 0

Mass Reduction IV 8.4 0.00 0.62 0 -15 2099 0

Mass Reduction V 11.6 0.00 0.72 0 -20 2099 0

Aerodynamics I 2.4 48.17 0.00 0 0.5 2000 0

Aerodynamics II 4.9 203.29 0.00 0 1 2011 0

6 Speed Manual 2.2 255.59 0.00 20 0 1995 0

Aggressive Shift Logic I 2.5 32.44 0.00 0 0 1999 0

Aggressive Shift Logic II 6.7 27.18 0.00 0 0 2017 0

Early Torque Converter Lockup 0.5 29.49 0.00 0 0 2002 0

High Efficiency Gearbox 1.6 200.63 0.00 0 0 2017 0

5 Speed Automatic 1.4 103.91 0.00 20 0 1995 0

6 Speed Automatic 2.2 270.05 0.00 30 0 2003 0

7 Speed Automatic 5.1 401.04 0.00 40 0 2009 0

8 Speed Automatic 8.0 532.83 0.00 50 0 2010 0

Dual Clutch Automated Manual 5.5 56.75 0.00 -10 0 2004 0

CVT 8.4 250.98 0.00 -25 0 1998 0

Low Friction Lubricants 0.7 3.20 0.00 0 0 2003 0

Engine Friction Reduction I-4 cyl 2.0 47.16 0.00 0 0 2000 1.25

Engine Friction Reduction I-6 cyl 2.6 71.14 0.00 0 0 2000 1.25

Engine Friction Reduction I-8 cyl 2.8 94.32 0.00 0 0 2000 1.25

Engine Friction Reduction II-4 cyl 3.6 100.71 0.00 0 0 2017 2.25

Engine Friction Reduction II-6 cyl 4.7 147.87 0.00 0 0 2017 2.25

Engine Friction Reduction II-8 cyl 5.1 195.03 0.00 0 0 2017 2.25

Cylinder Deactivation-6 cyl 6.5 187.06 0.00 10 0 2004 0

Cylinder Deactivation-8 cyl 6.9 209.97 0.00 10 0 2004 0

VVT I-OHV Intake Cam Phasing-6 cyl 2.6 43.90 0.00 20 0 2051 1.25

VVT I-OHV Intake Cam Phasing-8 cyl 2.7 43.90 0.00 30 0 2051 1.25

VVT I-OHC Intake Cam Phasing-4 cyl 2.1 43.90 0.00 10 0 1993 1.25

VVT I-OHC Intake Cam Phasing-6 cyl 2.6 88.76 0.00 20 0 1993 1.25

VVT I-OHC Intake Cam Phasing-8 cyl 2.7 88.76 0.00 30 0 1993 1.25

VVT II-OHV Coupled Cam Phasing-6 cyl 5.4 43.90 0.00 20 0 2009 1.25

VVT II-OHV Coupled Cam Phasing-8 cyl 5.8 43.90 0.00 30 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-4 cyl 4.3 43.90 0.00 10 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-6 cyl 5.4 88.76 0.00 20 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-8 cyl 5.8 88.76 0.00 30 0 2009 1.25

VVT III-OHV Dual Cam Phasing-6 cyl 5.4 99.26 0.00 25 0 2051 1.56

VVT III-OHV Dual Cam Phasing-8 cyl 5.8 99.26 0.00 37.5 0 2051 1.56

VVT III-OHC Dual Cam Phasing-4 cyl 4.3 90.67 0.00 12.5 0 2009 1.56

VVT III-OHC Dual Cam Phasing-6 cyl 5.4 195.65 0.00 25 0 2009 1.56

VVT III-OHC Dual Cam Phasing-8 cyl 5.8 195.65 0.00 37.5 0 2009 1.56

VVL I-OHV Discrete-6 cyl 5.5 225.24 0.00 40 0 2000 2.5

VVL I-OHV Discrete-8 cyl 5.9 322.59 0.00 50 0 2000 2.5

VVL I-OHC Discrete-4 cyl 4.3 155.57 0.00 25 0 2000 2.5

VVL I-OHC Discrete-6 cyl 5.5 225.24 0.00 40 0 2000 2.5

VVL I-OHC Discrete-8 cyl 5.9 322.59 0.00 50 0 2000 2.5

VVL II-OHV Continuous-6 cyl 7.0 1150.07 0.00 40 0 2011 2.5

VVL II-OHV Continuous-8 cyl 7.5 1256.96 0.00 50 0 2011 2.5

VVL II-OHC Continuous-4 cyl 5.4 232.88 0.00 25 0 2011 2.5

VVL II-OHC Continuous-6 cyl 7.0 427.58 0.00 40 0 2011 2.5

VVL II-OHC Continuous-8 cyl 7.5 466.71 0.00 50 0 2011 2.5

Stoichiometric GDI-4 cyl 1.5 264.37 0.00 20 0 2006 2.5

Stoichiometric GDI-6 cyl 1.5 397.99 0.00 30 0 2006 2.5

Stoichiometric GDI-8 cyl 1.5 478.16 0.00 40 0 2006 2.5

OHV to DOHC TBDS-I4 21.6 1383.90 0.00 -100 0 2009 3.75

OHV to DOHC TBDS I-V6 20.2 2096.84 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-I4 21.6 827.47 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-V6 20.2 1605.80 0.00 -100 0 2009 3.75

DOHC TBDS I-I3 17.5 915.28 0.00 -100 0 2009 3.75

DOHC TBDS I-I4 21.6 747.30 0.00 -100 0 2009 3.75

DOHC TBDS I-V6 20.2 1530.88 0.00 -100 0 2009 3.75

72 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.1. Standard technology matrix for cars1 (cont.)

Fuel

Efficiency

Change %

Incremental 

Cost 2000$

Incremental Cost

($/UnitWt.)

Absolute 

Incremental Weight 

(Lbs.)

Per Unit 

Incremental 

Weight (Lbs./

UnitWt.)

Introduction YearHorsepower

Change %

OHV to DOHC TBDS II-I4 26.3 1586.36 0.00 -100 0 2012 3.75

OHV to DOHC TBDS II-V6 24.5 2445.33 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-I4 26.3 1046.15 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-V6 24.5 1968.59 0.00 -100 0 2012 3.75

DOHC TBDS II-I3 21.2 1130.47 0.00 -100 0 2012 3.75

DOHC TBDS II-I4 26.3 968.31 0.00 -100 0 2012 3.75

DOHC TBDS II-V6 24.5 1895.85 0.00 -100 0 2012 3.75

OHV to DOHC TBDS III-I4 (from V6) 32.6 2031.83 0.00 -100 0 2017 3.75

OHV to DOHC TBDS III-I4 (from V8) 30.7 1601.81 0.00 -200 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V6) 32.6 1565.84 0.00 -100 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V8) 30.7 1380.40 0.00 -200 0 2017 3.75

DOHC TBDS III-I3 (from I4) 27.1 1634.58 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V6) 32.6 1498.70 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V8) 30.7 1302.07 0.00 -200 0 2017 3.75

Electric Power Steering 1.3 107.15 0.00 0 0 2004 0

Improved Accessories I 0.7 87.49 0.00 0 0 2005 0

12V Micro Hybrid w/EPS and IACC 7.0 640.24 0.00 45 0 2005 0

Improved Accessories II 2.5 128.69 0.00 0 0 2012 0

Mild Hybrid w/EPS and IACC II 11.0 2902.00 0.00 80 0 2012 -2.5

Tires I 2.0 5.60 0.00 -12 0 2005 0

Tires II 4.0 58.35 0.00 -15 0 2017 0

Low Drag Brakes 0.8 59.15 0.00 0 0 2000 0

Secondary Axle Disconnect 1.3 96.34 0.00 0 -1 2012 0 1 Fractional changes refer to the percentage change from the base technology.

Sources: U.S. Energy Information Administration, Energy and Environment Analysis, Documentation of Technology included in the NEMS Fuel Economy 

Model for Passenger Cars and Light Trucks (September, 2002). 

National Research Council, Effectiveness and Impact of Corporate Average Fuel Economy (CAFE) Standards (Copyright 2002). 

National Highway Traffic Safety Administration, Corporate Average Fuel Economy for MY 2011-2015 Passenger Cars and Light Trucks (April 2008). 

U.S. Environmental Protection Agency, Interim Report: New Powertrain Technologies and Their Projected Costs (October 2005).

Environmental Protection Agency and Department of Transportation National Highway Traffic Safety Administration, “2017 and Later Model Year Light-Duty 

Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule,” Federal Register Vol. 77, No. 199, October 15, 2012. 40 CFR 

Parts 85, 86, 600, 49 CFR Parts 523, 531, 533, et al. and 600.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 73
Transportation Demand Module

Table 7.2. Standard technology matrix for light trucks1

Fuel

Efficiency

Change %

Incremental 

Cost 2000$

Incremental Cost

($/UnitWt.)

Absolute 

Incremental Weight 

(Lbs.)

Per Unit 

Incremental Weight

(Lbs./

UnitWt.)

Introduction YearHorsepower

Change %

Unit Body Construction 4.0 100.00 0.00 0 -6 1980 0

Mass Reduction I 1.0 0.00 0.06 0 -1.5 2005 0

Mass Reduction II 2.6 0.00 0.14 0 -7.5 2009 0

Mass Reduction III 5.4 0.00 0.42 0 -10 2011 0

Mass Reduction IV 8.4 0.00 0.62 0 -15 2016 0

Mass Reduction V 11.6 0.00 0.72 0 -20 2020 0

Aerodynamics I 2.4 48.17 0.00 0 0.5 2000 0

Aerodynamics II 4.9 203.29 0.00 0 1 2011 0

6 Speed Manual 2.0 255.59 0.00 20 0 1995 0

Aggressive Shift Logic I 2.3 32.44 0.00 0 0 1999 0

Aggressive Shift Logic II 6.3 27.18 0.00 0 0 2017 0

Early Torque Converter Lockup 0.5 29.49 0.00 0 0 2002 0

High Efficiency Gearbox 1.6 200.63 0.00 0 0 2017 0

5 Speed Automatic 1.3 103.91 0.00 20 0 1995 0

6 Speed Automatic 2.0 270.05 0.00 30 0 2003 0

7 Speed Automatic 5.0 401.04 0.00 40 0 2009 0

8 Speed Automatic 8.0 532.83 0.00 50 0 2014 0

Dual Clutch Automated Manual 4.9 182.24 0.00 -10 0 2004 0

CVT 7.8 250.98 0.00 -25 0 1998 0

Low Friction Lubricants 0.7 3.20 0.00 0 0 2003 0

Engine Friction Reduction I-4 cyl 2.0 47.16 0.00 0 0 2000 1.25

Engine Friction Reduction I-6 cyl 2.6 71.14 0.00 0 0 2000 1.25

Engine Friction Reduction I-8 cyl 2.5 94.32 0.00 0 0 2000 1.25

Engine Friction Reduction II-4 cyl 3.6 100.71 0.00 0 0 2017 2.25

Engine Friction Reduction II-6 cyl 4.7 147.87 0.00 0 0 2017 2.25

Engine Friction Reduction II-8 cyl 4.4 195.03 0.00 0 0 2017 2.25

Cylinder Deactivation-6 cyl 6.4 187.06 0.00 10 0 2004 0

Cylinder Deactivation-8 cyl 6.0 209.97 0.00 10 0 2004 0

VVT I-OHV Intake Cam Phasing-6 cyl 2.6 43.90 0.00 20 0 2051 1.25

VVT I-OHV Intake Cam Phasing-8 cyl 2.5 43.90 0.00 30 0 2051 1.25

VVT I-OHC Intake Cam Phasing-4 cyl 2.1 43.90 0.00 10 0 1993 1.25

VVT I-OHC Intake Cam Phasing-6 cyl 2.6 88.76 0.00 20 0 1993 1.25

VVT I-OHC Intake Cam Phasing-8 cyl 2.5 88.76 0.00 30 0 1993 1.25

VVT II-OHV Coupled Cam Phasing-6 cyl 5.4 43.90 0.00 20 0 2009 1.25

VVT II-OHV Coupled Cam Phasing-8 cyl 5.1 43.90 0.00 30 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-4 cyl 4.3 43.90 0.00 10 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-6 cyl 5.4 88.76 0.00 20 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-8 cyl 5.1 88.76 0.00 30 0 2009 1.25

VVT III-OHV Dual Cam Phasing-6 cyl 5.4 99.26 0.00 25 0 2051 1.56

VVT III-OHV Dual Cam Phasing-8 cyl 5.1 99.26 0.00 37.5 0 2051 1.56

VVT III-OHC Dual Cam Phasing-4 cyl 4.3 90.67 0.00 12.5 0 2009 1.56

VVT III-OHC Dual Cam Phasing-6 cyl 5.4 195.65 0.00 25 0 2009 1.56

VVT III-OHC Dual Cam Phasing-8 cyl 5.1 195.65 0.00 37.5 0 2009 1.56

VVL I-OHV Discrete-6 cyl 5.5 225.24 0.00 40 0 2000 2.5

VVL I-OHV Discrete-8 cyl 5.2 322.59 0.00 50 0 2000 2.5

VVL I-OHC Discrete-4 cyl 4.2 155.57 0.00 25 0 2000 2.5

VVL I-OHC Discrete-6 cyl 5.5 225.24 0.00 40 0 2000 2.5

VVL I-OHC Discrete-8 cyl 5.2 322.59 0.00 50 0 2000 2.5

VVL II-OHV Continuous-6 cyl 7.0 1150.07 0.00 40 0 2011 2.5

VVL II-OHV Continuous-8 cyl 6.5 1256.96 0.00 50 0 2011 2.5

VVL II-OHC Continuous-4 cyl 5.3 232.88 0.00 25 0 2011 2.5

VVL II-OHC Continuous-6 cyl 7.0 427.58 0.00 40 0 2011 2.5

VVL II-OHC Continuous-8 cyl 6.5 466.71 0.00 50 0 2011 2.5

Stoichiometric GDI-4 cyl 1.5 264.37 0.00 20 0 2006 2.5

Stoichiometric GDI-6 cyl 1.5 397.99 0.00 30 0 2006 2.5

Stoichiometric GDI-8 cyl 1.5 478.16 0.00 40 0 2006 2.5

OHV to DOHC TBDS-I4 21.6 1383.90 0.00 -100 0 2009 3.75

OHV to DOHC TBDS I-V6 20.2 2096.84 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-I4 21.6 827.47 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-V6 20.2 1605.80 0.00 -100 0 2009 3.75

DOHC TBDS I-I3 17.5 915.28 0.00 -100 0 2009 3.75

DOHC TBDS I-I4 21.6 747.30 0.00 -100 0 2009 3.75

DOHC TBDS I-V6 20.2 1530.88 0.00 -100 0 2009 3.75

74 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.2. Standard technology matrix for light trucks1 (cont.)

Fuel

Efficiency

Change %

Incremental 

Cost 2000$

Incremental Cost

($/UnitWt.)

Absolute 

Incremental Weight 

(Lbs.)

Per Unit 

Incremental Weight

(Lbs./

UnitWt.)

Introduction YearHorsepower

Change %

OHV to DOHC TBDS II-I4 26.3 1586.36 0.00 -100 0 2012 3.75

OHV to DOHC TBDS II-V6 24.5 2445.33 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-I4 26.3 1046.15 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-V6 24.5 1968.59 0.00 -100 0 2012 3.75

DOHC TBDS II-I3 21.2 1130.47 0.00 -100 0 2012 3.75

DOHC TBDS II-I4 26.3 968.31 0.00 -100 0 2012 3.75

DOHC TBDS II-V6 24.5 1895.85 0.00 -100 0 2012 3.75

OHV to DOHC TBDS III-I4 (from V6) 32.6 2031.83 0.00 -100 0 2017 3.75

OHV to DOHC TBDS III-I4 (from V8) 30.7 1601.81 0.00 -200 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V6) 32.6 1565.84 0.00 -100 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V8) 30.7 1380.40 0.00 -200 0 2017 3.75

DOHC TBDS III-I3 (from I4) 27.1 1634.58 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V6) 32.6 1498.70 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V8) 30.7 1302.07 0.00 -200 0 2017 3.75

Electric Power Steering 1.0 107.15 0.00 0 0 2004 0

Improved Accessories I 0.7 87.49 0.00 0 0 2005 0

12V Micro Hybrid w/EPS and IACC 6.7 697.79 0.00 45 0 2005 0

Improved Accessories II 2.4 128.69 0.00 0 0 2012 0

Mild Hybrid w/EPS and IACC II 10.6 2902.00 0.00 80 0 2012 -2.5

Tires I 2.0 5.60 0.00 -12 0 2005 0

Tires II 4.0 58.35 0.00 -15 0 2017 0

Low Drag Brakes 0.8 59.15 0.00 0 0 2000 0

Secondary Axle Disconnect 1.4 96.34 0.00 0 -1 2012 0 1

Fractional changes refer to the percentage change from the base technology.

Sources: U.S. Energy Information Administration, Energy and Environment Analysis, Documentation of Technology included in the NEMS Fuel Economy Model 

for Passenger Cars and Light Trucks (September, 2002). 

National Research Council, Effectiveness and Impact of Corporate Average Fuel Economy (CAFE) Standards (Copyright 2002). 

National Highway Traffic Safety Administration, Corporate Average Fuel Economy for MY 2011-2015 Passenger Cars and Light Trucks (April 2008). 

U.S. Environmental Protection Agency, Interim Report: New Powertrain Technologies and Their Projected Costs (October 2005).

Environmental Protection Agency and Department of Transportation National Highway Traffic Safety Administration, “2017 and Later Model Year Light-Duty 

Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule,” Federal Register Vol. 77, No. 199, October 15, 2012. 40 CFR 

Parts 85, 86, 600, 49 CFR Parts 523, 531, 533, et al. and 600.

Degradation factors are used to convert new vehicle tested fuel economy values to “on-road” fuel economy values (Table 7.3). 

The degradation factors represent adjustments made to tested fuel economy values to account for the difference between fuel 

economy performance realized in the CAFE test procedure and fuel economy realized under normal driving conditions.

Table 7.3. Car and light truck degradation factors

2005 2010 2015 2020 2030 2040

Cars 79.8 81.7 81.7 81.7 81.7 81.7

Light Trucks 80.6 80.0 80.0 80.0 80.0 80.0

Source: U.S. Energy Information Administration, Transportation Sector Modules of the National Energy Modeling System, Model Documentation 2014, 

DOE/EIA-M070(2014), (Washington, DC, 2012).

Commercial light-duty fleet assumptions 

The Transportation Demand Module separates commercial light-duty fleets into three types: business, government, and utility. 

Based on these classifications, commercial light-duty fleet vehicles vary in survival rates and duration of in-fleet use before sale 

for use as personal vehicles. The average length of time passenger cars are kept before being sold for personal use is 3 years for 

business use, 6 years for government use, and 5 years for utility use. Of total automobile sales to fleets in 2009, 75.1% are used 

in business fleets, 9.6% in government fleets, and 15.3% in utility fleets. Of total light truck sales to fleets in 2009, 47.3% are 

used in business fleets, 15.1% in government fleets, and 37.6% in utility fleets [3]. Both the automobile and light truck shares by 

fleet type are held constant from 2009 through 2040. In 2009, 18.2% of all automobiles sold and 16.9% of all light trucks sold 

were for fleet use. The share of total automobile and light truck sales slowly declines over the forecast period based on historic 

trends.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 75
Transportation Demand Module

Alternative-fuel shares of fleet vehicle sales by fleet type are held constant at 2005 levels (Table 7.4). Size class sales shares of 

vehicles are also held constant at 2005 levels (Table 7.5) [4]. Individual sales shares of new vehicles purchased by technology 

type are assumed to remain relatively constant for utility, government, and business fleets using the previous 5-year average 

(Table 7.6) [5].

Annual vehicle miles traveled (VMT) per vehicle by fleet type stays constant over the projection period based on the Oak Ridge 

National Laboratory fleet data.

Fleet fuel economy for both conventional and alternative-fuel vehicles is assumed to be the same as the personal new vehicle 

fuel economy and is subdivided into six EPA size classes for cars and light trucks.

Table 7.4. Percent of fleet alternative fuel vehicles by fleet type by size class, 2005

Mini Subcompact Compact Midsize Large 2-Seater

Car

Business 0.0 10.5 10.7 42.7 36.1 0.0

Government 0.0 2.8 40.0 2.8 54.4 0.0

Utility 0.0 7.9 34.7 12.3 45.1 0.0

SM Pk LG Pk SM Van LG Van SM Util LG Util

Light Truck

Business 7.9 35.1 7.9 26.8 5.5 16.8

Government 6.7 50.8 28.4 4.6 1.6 7.8

Utility 8.2 52.1 6.0 32.7 0.3 0.7

Source: U.S. Energy Information Administration, “Archive--Alternative Transportation Fuels (ATF) and Alternative Fueled Vehicles (AFV),” http://

www.eia.gov/cneaf/alternate/page/aftables/afvtransfuel_II.html #in use.

Table 7.5. Commercial fleet size class shares by fleet and vehicle type, 2005

percentage

Fleet Type by Size Class Automobiles Light Trucks

Business Fleet

Mini 3.1 2.5

Subcompact 23.4 8.4

Compact 26.6 23.3

Midsize 36.2 8.1

Large 9.9 14.2

2-seater 0.8 43.6

Government Fleet

Mini 0.2 6.7

Subcompact 4.6 43.6

Compact 20.6 10.4

Midsize 28.6 17.1

Large 46.0 3.8

2-seater 0.0 18.4

Utility Fleet

Mini 1.5 7.3

Subcompact 12.5 38.7

Compact 10.0 11.8

Midsize 59.2 18.9

Large 16.4 7.2

2-seater 0.4 16.1

Source: Oak Ridge National Laboratory, “Fleet Characteristics and Data Issues,” Stacy Davis and Lorena Truett, final report prepared for the Department 

of Energy, Energy Information Administration, Office of Energy Analysis, (Oak Ridge, TN, January 2003). 

76 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.6. Share of new vehicle purchases by fleet type and technology type, 2009

percentage

Technology Business Government Utility

Cars

Gasoline 99.10 72.78 95.52

Ethanol Flex 0.46 26.20 2.11

Electric 0.00 0.02 0.07

CNG/LNG Bi-Fuel 0.14 0.56 1.08

LPG Bi-Fuel 0.16 0.11 0.40

CNG/LNG 0.08 0.33 0.63

LPG 0.08 0.01 0.19

Light Trucks

Gasoline 71.71 59.46 98.22

Ethanol Flex 16.29 35.09 0.49

Electric 0.04 0.07 0.05

CNG/LNG Bi-Fuel 1.28 2.29 0.51

LPG Bi-Fuel 7.93 2.55 0.31

CNG/LNG 1.54 0.49 0.24

LPG 1.22 0.05 0.18

Sources: U.S. Energy Information Administration, Archive - Alternative Transportation Fuels (ATF) and Alternative Fueled Vehicles (AFV), http://

www.eia.gov/renewable/afv/archive/index.cfm.

The light commercial truck component

The Light Commercial Truck Component of the NEMS Transportation Model represents light trucks that have an 8,501 to 10,000 

pound gross vehicle weight rating (Class 2B vehicles). These vehicles are assumed to be used primarily for commercial purposes. 

The component implements a twenty-year stock model that estimates vehicle stocks, travel, fuel economy, and energy use by 

vintage. Historic vehicle sales and stock data, which constitute the baseline from which the projection is made, are taken from 

an Oak Ridge National Laboratory study [6]. The distribution of vehicles by vintage, and vehicle scrappage rates are derived 

from R.L. Polk & Co. registration data [7],[8]. Vehicle travel by vintage was constructed using vintage distribution curves and 

estimates of average annual travel by vehicle [9],[10]. 

The growth in light commercial truck VMT is a function of industrial output for agriculture, mining, construction, total 

manufacturing, utilities, and personal travel. The overall growth in VMT reflects a weighted average based on the distribution of 

total light commercial truck VMT by sector. Projected fuel efficiencies are assumed to increase at the same annual growth rate 

as conventional gasoline light-duty trucks (≤8,500 pounds gross vehicle weight).

Consumer vehicle choice assumptions

The Consumer Vehicle Choice Component (CVCC) utilizes a nested multinomial logit (NMNL) model that predicts sales shares 

based on relevant vehicle and fuel attributes. The nesting structure first predicts the probability of fuel choice for multi-fuel 

vehicles within a technology set. The second level nesting predicts penetration among similar technologies within a technology 

set (e.g., gasoline versus diesel hybrids). The third level choice determines market share among the different technology sets 

[11]. The technology sets include:

•	 Conventional fuel capable (gasoline, diesel, bi-fuel compressed natural gas (CNG) and liquefied natural gas (LNG), bi-fuel 

liquefied petroleum gas (LPG), and flex-fuel),

•	 Hybrid (gasoline and diesel),

•	 Plug-in hybrid (10-mile all-electric range and 40-mile all-electric range)

•	 Dedicated alternative fuel (CNG, LNG, and LPG),

•	 Fuel cell (gasoline, methanol, and hydrogen), and

•	 Electric battery powered (100-mile range and 200-mile range) [12]

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 77
Transportation Demand Module

The vehicle attributes considered in the choice algorithm include: vehicle price, maintenance cost, battery replacement cost, 

range, multi-fuel capability, home refueling capability, fuel economy, acceleration and luggage space. With the exceptions of 

maintenance cost, battery replacement cost, and luggage space, vehicle attributes are determined endogenously [13]. Battery 

costs for plug-in hybrid electric and all-electric vehicles are based on a production-based function over several technology 

phase periods. The fuel attributes used in market share estimation include availability and price. Vehicle attributes vary by 

six EPA size classes for cars and light trucks and fuel availability varies by Census division. The NMNL model coefficients were 

developed to reflect purchase decisions for size classes, cars and light trucks separately. 

Where applicable, CVCC fuel-efficient technology attributes are calculated relative to conventional gasoline miles per gallon. 

It is assumed that many fuel efficiency improvements in conventional vehicles will be transferred to alternative-fuel vehicles. 

Specific individual alternative-fuel technological improvemens are also dependent upon the CVCC technology type, cost, 

research and development, and availability over time. Make and model availability estimates are assumed according to a logistic 

curve based on the initial technology introduction date and current offerings. Coefficients summarizing consumer valuation of 

vehicle attributes were derived from assumed economic valuation compared to vehicle price elasticities. Initial CVCC vehicle 

sales shares are calibrated to data from R.L. Polk & Co., fleet data from Bobit Publishing Company, and sales data from Wards 

Auto [14]. A fuel-switching algorithm based on the relative fuel prices for alternative fuels compared to gasoline is used to 

determine the percentage of total fuel consumption represented by alternative fuels in bi-fuel and flex-fuel alcohol vehicles.

Freight truck assumptions

The freight truck module estimates vehicle stocks, travel, fuel efficiency, and energy use for three size classes of trucks: lightmedium (Class 3), heavy-medium (Classes 4-6), and heavy (Classes 7-8). The three size classes are further broken down into 

13 subclasses for fuel economy classification purposes (Table 7.7). These subclasses include two breakouts for light-medium 

size class, including pickup/van and vocational, one breakout for heavy-medium, including vocational, and ten breakouts for 

heavy. The ten subclasses parse the heavy size class into class 7 or class 8, day cab or sleeper cab, and low, mid or high roof. 

Within the size classes, the stock model structure is designed to cover 34 vehicle vintages and to estimate energy use by 

four fuel types: diesel, gasoline, LPG, and natural gas (CNG and LNG). Fuel consumption estimates are reported regionally (by 

Census Division) according to the distillate fuel shares from the State Energy Data System [15]. The technology input data 

are specific to the different types of trucks and include the year of introduction, incremental fuel efficiency improvement, and 

capital cost (Table 7.8).

Table 7.7. Vehicle technology category for technology matrix for freight trucks

Vehicle category Class Type Roof1

1 3 Pickup and Van -

2 3 Vocational -

3 4-6 Vocational -

4 7-8 Vocational -

5 7 Tractor - day cab low

6 7 Tractor - day cab mid

7 7 Tractor - day cab high

8 8 Tractor - day cab low

9 8 Tractor - day cab mid

10 8 Tractor - day cab high

11 8 Tractor - sleeper cab low

12 8 Tractor - sleeper cab mid

13 8 Tractor - sleeper cab high

1

Applies to Class 7 and 8 day and sleeper cabs only.

78 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.8. Standard technology matrix for freight trucks

Technology Type

Vehicle 

Category

Introduction 

Year

Capital Costs

(2009$)

Incremental 

Fuel 

Economy 

Improvement 

(%)

Aerodynamics I: streamlined bumper, grill, windshield, roof 1 2010 58 1.5

Aerodynamics I: conventional features; general aerodynamic shape, removal of

classic non-aerodynamic features 5,8,11 1995 1000 4.1

Aerodynamics I 7,10,13 1995 1000 4.6

Aerodynamics II: SmartWay features; streamlined shape, bumper grill, hood,

mirrors, side fuel tank and roof fairings, side gap extenders 

5, 8 2004 1126 1.5

Aerodynamics II 7,10 2004 1126 3.1

Aerodynamics II 11 2004 1155 4.2

Aerodynamics II 13 2004 1506 4.2

Aerodynamics III: underbody airflow, down exhaust, lowered ride height 7 2014 2303 4.2

Aerodynamics III 10 2014 0 0

Aerodynamics III 13 2014 2675 5.8

Aerodynamics IV: skirts, boat tails, nose cone, vortex stabilizer, pneumatic

blowing 5-13 1995 5500 13.0

Tires I: low rolling resistance 1 2010 7 1.5

Tires I 2,3 2010 162 2.6

Tires I 4, 8-13 2010 194 2.0

Tires I 5-7 2010 130 2.0

Tires II: super singles 5-13 2000 150 5.3

Tires III: single wide tires on trailer 5-13 2000 800 3.1

Weight Reduction I 1 2010 127 1.6

Weight Reduction I: aluminum dual tires or super singles 5-13 2010 650 1.0

Weight Reduction II: weight reduction 15% 3-13 2018 6200 3.0

Weight Reduction III: weight reduction 20% 3-13 2022 11000 3.5

Accessories I: Electric/electrohydraulic improvements; electric power steering or

electrohydraulic power steering 1 2010 115 1.5

Accessories II: Improved accessories; electrified water, oil, fuel injection, power

steering pump, aircompressor 1 2010 93 1.5

Accessories III: Auxiliary Power Unit 11-13 2000 5400 5.8

Transmission I: 8-speed Automatic from 6-speed automatic 1 2000 280 1.7

Transmission II: 6-Manual from 4-speed automatic 1 1995 150 1.0

Transmission III: Automated Manual Transmission 2-13 2000 5000 3.5

Diesel Engine I: aftertreatment improvements 1 2010 119 4.0

Diesel Engine I 2 2010 117 2.6

Diesel Engine II: low friction lubricants 1-13 2005 4 0.5

Diesel Engine III: variable valve actuation 2 2010 0 1.0

Diesel Engine III 3-13 2005 300 1.0

Diesel Engine IV: engine friction reduction, low tension piston rings, roller cam

followers, piston skirt design, improved crankshaft design and bearings; coating 1-2 2010 116 1.0

Diesel Engine IV: engine friction reduction, improved bearings to allow lower 

viscosity oil 3-13 2010 250 1.0

Diesel Engine V: improved turbo efficiency 2-13 2010 18 1.5

Diesel Engine VI: improved water, oil, fuel pump; pistons; valve train friction 

reduction 2 2010 213 1.3

Diesel Engine VI 3, 5-8 2010 186 1.3

Diesel Engine VI: improved water, oil, and fuel pump; pistons 4, 9-13 2010 150 1.3

Diesel Engine VII: improved cylinder head, fuel rail and injector, EGR cooler 2 2010 42 4.7

Diesel Engine VII 3-13 2010 31 4.7

Diesel Engine VIII: turbo mechanical compounding 5-13 2017 1000 3.9

Diesel Engine IX: low temperature EGR, improved turbochargers 1 2010 184 5.0

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 79
Transportation Demand Module

Table 7.8. Standard technology matrix for freight trucks (cont.)

Technology Type

Vehicle 

Category

Introduction 

Year

Capital Costs

(2009$)

Incremental Fuel 

Economy 

Improvement 

(%)

Diesel Engine X: sequential downsizing/turbocharging 5-13 2010 1200 2.5

Diesel Engine XI: waste heat recovery, Organic Rankine Cycle (bottoming cycle) 3-13 2019 10000 8.0

Diesel Engine XII: electric turbo compounding 4-13 2020 8000 7.6

Gasoline Engine I: low friction lubricants 1-13 2010 4 0.5

Gasoline Engine II: coupled cam phasing 2-4 2010 46 2.6

Gasoline Engine III: engine friction reduction; low tension piston rings, roller cam 

followers, piston skirt design, improved crankshaft design and bearings; coating 1-2 2010 116 2.0

Gasoline III 3-4 2010 95 2.0

Gasoline Engine IV: stoichiometric gasoline direct injection V8 1 2006 481 1.5

Gasoline Engine IV 2 2010 481 1.5

Gasoline Engine IV 3-4 2014 450 1.5

Gasoline Engine V: turbocharging and downsizing SGDI V8 to V6 1-4 2006 1743 2.1 

Gasoline Engine VI: lean burn GDI 1-4 2020 750 13.0 

Gasoline Engine VII: HCCI 1-4 2030 685 12.0 

Hybrid System I: 42V engine off at idle 1-2 2005 1500 7.0 

Hybrid System I 3-4 2005 1500 4.5 

Hybrid System II: dual mode hybrid 1-2 2008 12000 25.0 

Hybrid System II: electric, ePTO, or hydraulic 3-4 2009 26667 30.0 

Hybrid System II: 4 kWh battery, 50 kW motor generator 5-13 2012 26000 5.5 

Sources: Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles, U.S. Environmental 

Protection Agency and U.S. Department of Transportation, Final Rules, Federal Register, Vol. 76, No. 179, (September 2011). 

Final Rulemaking to Establish Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles, 

Regulatory Impact Analysis, U.S. Environmental Protection Agency and U.S. Department of Transportation, (August 2011). 

Reducing Heavy-Duty Long Haul Combination Truck Fuel Consumption and CO2 Emissions, Final Report, TIAX, LLC. (October 2009). 

Update of Technology Information for Forecasting Heavy-Duty On-Road Vehicle Fuel Economy, Final Report, ICF International, Prepared for the U.S. Energy 

Information Administration, (August 2010). 

Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, National Research Council of the National Academy 

of Sciences, (2010).

The freight module uses projections of industrial output to estimate growth in freight truck travel. Regional heavy-duty freight 

truck vehicle travel is determined using a ton-mile per dollar of industrial output measure that is converted to freight vehicle miles 

traveled using shares developed from the CFS [16]. Freight truck ton-miles, by Census division and industrial commodity, and 

historical truck vehicle miles traveled are developed using Department of Transportation and Federal Highway Administration 

data [17],[18]. 

Fuel economy of new freight trucks is dependent on the market penetration of advanced technology components [19]. For the 

advanced technology components, market penetration is determined as a function of technology type, cost-effectiveness, and 

introduction year. Cost-effectiveness is calculated as a function of fuel price, vehicle travel, fuel economy improvement, and 

incremental capital cost.

Heavy truck freight travel is estimated by class size and fuel type based on matching projected freight travel demand (measured 

by industrial output) to the travel supplied by the current fleet. Travel by vintage and size class is then adjusted so that total travel 

meets total demand.

Initial heavy vehicle travel, by vintage and size class, is derived by EIA using Vehicle Inventory and Use Survey (VIUS) data [20]. 

Initial freight truck stocks by vintage are obtained from R. L. Polk & Co. and are distributed by fuel type using VIUS data. Vehicle 

scrappage rates are also estimated by EIA using R. L. Polk & Co. data.

Freight rail assumptions

The freight rail module uses the industrial output by NAICS code measured in real 2005 dollars and a ton-mile per dollar 

output measure to determine rail ton-miles by Census division and commodity [21]. Coal production from the NEMS Coal 

Market Module is used to adjust coal-based rail travel. Freight rail historical ton-miles are developed from U.S. Department 

of Transportation data [22]. Initial freight rail efficiencies are based on historic data taken from the U.S. Department of 

Transportation [23]. The distribution of rail fuel consumption by fuel type is based on the cost-effectiveness of LNG as compared 

to diesel considering fuel costs and incremental locomotive costs [24]. Initial regional freight rail consumption estimates are 

distributed according to the State Energy Data System [25].

80 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Domestic and international shipping assumptions

Similar to the previous sub-module, the domestic freight shipping module uses the industrial output by NAICS code measured 

in real 2005 dollars and a ton-mile per dollar ouitput measure to determine domestic marine ton-miles by Census division and 

industrial commodity to develop domestic marine travel [26], [27].

The freight adjustment coefficients (used to convert dollars to volume equivalents) are based on historical data. Domestic 

shipping efficiencies are taken from the Transportation Energy Data Book [28]. The energy consumption in the international 

shipping module is a function of the total level of imports and exports. The distribution of domestic and international shipping 

fuel consumption by fuel type is based on historical data through 2012 and allows for LNG as a marine fuel starting in 2013 based 

on fuel economics [29]. Initial regional domestic shipping consumption estimates are distributed according to the residual oil 

regional shares in the State Energy Data System [30]. 

The air model

The air model is a 13-region world demand and supply model (Table 7.9). For each region, demand is computed for domestic 

travel (both takeoff and landing occur in the same region) and international travel (either takeoff or landing is in the region but 

not both). Once the demand for aircraft is determined, the stock efficiency module moves aircraft between regions to satisfy the 

projected demand for air travel.

Table 7.9. Thirteen regions for the world model

Region Number Region Major Countries in Region

1 United States United States

2 Canada Canada

3 Central America Mexico

4 South America Brazil

5 Europe France, Germany

6 Africa S. Africa

7 Middle East Egypt

8 Russia Russia

9 China China

10 Northeast Asia Japan, Korea

11 Southeast Asia Vietnam

12 Southwest Asia India

13 Oceania Australia, New Zealand

Source: Jet Information Services, 2009 World Jet Inventory, data tables (2009)

Air travel demand assumptions

The air travel demand module calculates the domestic and international per-capita revenue passenger miles (RPM-PC) for each 

region. Domestic and international revenue passenger miles are based on the historical data in Table 7.10 [31], per-capita income 

for the United States, per-capita GDP for the non-U.S. regions, and ticket prices. The revenue ton miles of air freight for the United 

States are based on merchandise exports, gross domestic product, and fuel cost. For the non-U.S. regions, revenue ton miles are 

based on GDP growth in the region [32].

Airport capacity constraints based on the Federal Aviation Administration (FAA) Airport Capacity Benchmark Report 2004 

are incorporated into the air travel demand module using airport capacity measures [33]. Airport capacity is defined by the 

maximum number of flights per hour airports can routinely handle, the amount of time airports operate at optimal capacity, and 

passenger load factors. Capacity expansion is expected to be delayed due to the economic environment and fuel costs. 

Aircraft stock/efficiency assumptions

The aircraft stock and efficiency module consists of a world regional stock model of wide body, narrow body, and regional jets by 

vintage. Total aircraft supply for a given year is based on the initial supply of aircraft for model year 2009, new passenger aircraft 

sales, and the survival rate by vintage (Table 7.11) [34]. New passenger aircrft sales are a function of revenue passenger miles and 

gross domestic product.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 81
Transportation Demand Module

Table 7.10. 2010 Regional population, GDP, per capita GDP, domestic and international RPM and per-capita RPM

Region

Population

(million) GDP (2006$) GDP_PC

United States 310.8 13,088 42,106.0

Canada 34.1 1,239 36,383.8

Central America 197.3 2,025 10,262.7

South America 393.1 3,993 10,158.3

Europe 607.9 15,367 25,280.1

Africa 931.9 2,636 2,829.1

Middle East 298.7 3,083 10,318.7

Russia 278.6 2,843 10,203.4

China 1,347.3 9,577 7,108.2

Northeast Asia 200.6 5,024 25,045.1

Southeast Asia 627.9 3,752 5,975.7

Southwest Asia 1,629.3 4,971 3,015.2

Oceania 27.9 909 32,641.2

Region RPM (billion) RPM_PC (thousand)

Domestic

United States 564.8 1,816.9

Canada 27.1 795.0

Central America 20.1 101.8

South America 70.7 179.9

Europe 399.4 657.0

Africa 31.0 33.2

Middle East 47.8 159.9

Russia 32.8 117.7

China 208.0 154.4

Northeast Asia 44.5 221.8

Southeast Asia 81.0 129.0

Southwest Asia 30.4 18.7

Oceania 50.0 1,795.2

International

United States 244.2 785.7

Canada 53.1 1,559.8

Central America 63.7 322.9

South America 49.8 126.7

Europe 378.3 622.4

Africa 59.2 64.5

Middle East 113.5 380.0

Russia 31.0 111.1

China 90.9 67.5

Northeast Asia 93.0 463.5

Southwest Asia 132.9 211.6

Southwest Asia 49.5 30.4

Oceania 44.0 1,579.9

Source: Global Insight 2006 chain-weighted dollars, Boeing Current Market Outlook 2009.

82 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.11. 2010 Regional passenger and cargo aircraft supply

Aircraft Type New

Age of Aircraft (years)

1-10 11-20 21-30 >30 Total

Passenger

Narrow Body

United States 98 1456 1397 680 185 3816 

Canada 5 144 80 17 13 259 

Central America 12 173 46 74 58 363 

South America 42 279 138 146 109 714 

Europe 204 1630 953 191 20 2998 

Africa 22 148 149 162 106 587 

Middle East 60 215 160 58 36 529 

Russia 14 202 372 283 215 1086 

China 168 847 282 11 1 1309 

Northeast Asia 22 149 109 7 4 291 

Southeast Asia 83 239 201 120 28 671 

Southwest Asia 27 224 46 43 7 347 

Oceania 14 165 49 2 0 230 

Wide Body

United States 9 201 294 129 18 651 

Canada 0 30 32 22 0 84 

Central America 0 9 7 8 0 24 

South America 3 43 43 6 2 97 

Europe 36 345 368 53 9 811 

Africa 2 57 43 35 12 149 

Middle East 36 236 145 70 11 498 

Russia 4 20 83 51 0 158 

China 22 132 11 3 4 0 271 

Northeast Asia 17 146 158 23 0 344 

Southeast Asia 21 204 166 18 7 416 

Southwest Asia 3 51 32 23 4 113 

Oceania 7 56 55 8 0 126 

Regional Jets

United States 35 1774 487 49 9 2354 

Canada 8 132 118 72 25 355 

Central America 5 85 61 18 0 169 

South America 32 94 11 3 31 3 273 

Europe 84 669 638 106 0 1497 

Africa 24 106 124 59 13 326 

Middle East 15 86 83 10 3 197 

Russia 1 73 79 71 3 227

China 18 112 15 1 0 146

Northeast Asia 8 56 5 0 0 69

Southeast Asia 18 78 90 41 7 234

Southwest Asia 7 53 27 5 3 95

Oceania 6 98 91 42 0 237

Cargo

Narrow Body

United States 0 0 76 106 218 400

Canada 0 0 4 8 21 33

Central America 0 2 2 5 8 17

South America 0 0 3 17 42 62

Europe 0 0 24 68 10 102

Africa 0 0 4 13 57 74

Middle East 0 0 2 5 6 13

Russia 0 5 2 2 8 17

China 0 2 20 16 1 39

Northeast Asia 0 0 0 0 0 0

Southeast Asia 0 0 1 8 14 23

Southwest Asia 0 0 2 10 5 17

Oceania 0 0 0 10 3 13

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 83
Transportation Demand Module

Table 7.11. 2009 Regional passenger and cargo aircraft supply (cont.)

Age of Aircraft (years)

Aircraft Type New 1-10 11-20 21-30 >30 Total

Wide Body

United States 14 86 227 184 102 613 

Canada 0 0 0 3 4 7 

Central America 0 2 1 3 4 10 

South America 0 8 2 7 7 24 

Europe 5 32 52 54 8 151 

Africa 0 0 2 1 1 4 

Middle East 4 10 18 18 5 55 

Russia 0 5 9 5 0 19 

China 9 35 36 11 0 91 

Northeast Asia 0 30 19 4 0 53 

Southeast Asia 0 32 18 4 0 54 

Southwest Asia 0 0 5 4 1 10 

Oceania 0 0 0 0 0 0 

Regional Jets

United States 0 0 22 3 0 25 

Canada 0 0 0 7 0 7

Central America 0 0 4 1 0 5 

South America 0 0 0 4 0 4 

Europe 0 2 55 40 0 97 

Africa 0 0 0 5 1 6 

Middle East 0 0 0 0 0 0 

Russia 0 0 1 0 0 1 

China 0 0 0 0 0 0 

Northeast Asia 0 0 0 0 0 0 

Southeast Asia 0 0 2 3 0 5 

Southwest Asia 0 0 1 0 0 1 

Oceania 0 0 1 3 0 4 

Survival Curve (fraction) New 5 10 20 40

Narrow Body 1.000 0.9998 0.9994 0.9970 0.8000 

Wide Body 1.000 0.9983 0.9961 0.9870 0.7900 

Regional Jets 1.000 0.9971 0.9950 0.9830 0.7800 

Source: Jet Information Services, 2009 World Jet Inventory (2009).

Wide and narrow body planes over 25 years of age are placed as cargo jets according to a cargo percentage varying from 50% of 

25-year-old planes to 100% of those aircraft 30 years and older. The available seat-miles per plane, which measure the carrying 

capacity of the airplanes by aircraft type, increase gradually over time. Domestic and international travel are combined into a 

single regional demand for seat-miles and passed to the Aircraft Fleet Efficiency Component, which adjusts the initial aircraft 

stock to meet that demand. For each region, starting with the United States, the initial stock is adjusted by moving aircraft 

between regions.

Technological availability, economic viability, and efficiency characteristics of new aircraft are assumed to grow at a fixed rate. 

Fuel-efficiency of new aircraft acquisitions represents an improvement over the stock efficiency of surviving airplanes. Generic 

sets of new technologies (Table 7.12) are introduced in different years and with a set of improved efficiencies over the base year 

(2007). Regional shares of all types of aircraft fuel use are assumed to be constant and are consistent with the State Energy Data 

System estimate of regional jet fuel shares.

Table 7.12. Standard technology matrix for air travel

Technology Introduction Year Fractional Efficiency Improvement Jet Fuel Trigger Price (1987$/gallon)

Technology #1 2008 0.03 1.34

Technology #2 2014 0.07 1.34

Technology #3 2020 0.11 1.34

Technology #4 2025 0.15 1.34

Technology #5 2018 0.20 1.34

Technology #6 2018 0.00 1.34

Source: Jet Information Services, 2009 World Jet Inventory, data tables (2009)

84 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Legislation and regulations

Light-Duty Vehicle Combined Corporate Average Fuel Economy (CAFE) Standards

The AEO2014 Reference case includes the attribute-based CAFE standards for LDVs for Model Year (MY) 2011, the joint attributebased CAFE and vehicle GHG emissions standards for MY 2012 through MY 2016 and for MY 2017 through 2025. CAFE standards 

are then held constant in subsequent model years, although the fuel economy of new LDVs continues to rise modestly over time.

Heavy-Duty Vehicle Combined Corporate Average Fuel Economy Standards

On September 15, 2011, EPA and NHTSA jointly announced a final rule, called the HD National Program [35], which for the first 

time establishes greenhouse gas (GHG) emissions and fuel consumption standards for on-road heavy-duty trucks and their 

engines. The AEO2014 Reference case incorporates the new standards for heavy-duty vehicles (HDVs) with gross vehicle weight 

rating (GVWR) above 8,500 pounds (Classes 2b through 8). The HD National Program standards begin for MY 2014 vehicles and 

engines and are fully phased in by MY 2018. AEO2014 models standard compliance among 13 HDV regulatory classifications that 

represent the discrete vehicle categories set forth in the rule.

Energy Independence and Security Act of 2007 (EISA2007)

A fuel economy credit trading program is established based on EISA2007. Currently, CAFE credits earned by manufacturers can be 

banked for up to 3 years and can only be applied to the fleet (car or light truck) from which the credit was earned. Starting in model 

year 2011, the credit trading program allows manufacturers whose automobiles exceed the minimum fuel economy standards to 

earn credits that can be sold to other manufacturers whose automobiles fail to achieve the prescribed standards. The credit trading 

program is designed to ensure that the total oil savings associated with manufacturers that exceed the prescribed standards are 

preserved when credits are sold to manufacturers that fail to achieve the prescribed standards.

While the credit trading program began in 2011, EISA2007 allows manufacturers to apply credits earned to any of the three 

model years prior to the model year the credits are earned, and to any of the five model years after the credits are earned. The 

transfer of credits within a manufacturer’s fleet is limited to specific maximums. For model years 2011 through 2013, the maximum 

transfer is 1.0 mpg; for model years 2014 through 2017, the maximum transfer is 1.5 mpg; and for model years 2018 and later, the 

maximum credit transfer is 2.0 mpg. NEMS currently allows for sensitivity analysis of CAFE credit banking by manufacturer fleet, 

but does not model the trading of credits across manufacturers. AEO2014 does not consider trading of credits since this would 

require significant modifications to NEMS and detailed technology cost and efficiency data by manufacturer, which are not readily 

available.

The CAFE credits specified under the Alternative Motor Fuels Act (AMFA) through 2019 are extended. Prior to passage of this 

Act, the CAFE credits under AMFA were scheduled to expire after model year 2010. Currently, 1.2 mpg is the maximum CAFE 

credit that can be earned from selling alternative fueled vehicles. EISA2007 extends the 1.2 mpg credit maximum through 2014 

and reduces the maximum by 0.2 mpg for each following year until it is phased out by model year 2020. NEMS does model CAFE 

credits earned from alternative fuel vehicle sales.

American Recovery and Reinvestment Act of 2009 and Energy Improvement and Extension Act of 2008

ARRA Title I, Section 1141, modified the EIEA2008 Title II, Section 205, tax credit for the purchase of new, qualified plug-in 

electric drive motor vehicles. According to the legislation, a qualified plug-in electric drive motor vehicle must draw propulsion 

from a traction battery with at least 4 kWh of capacity and be propelled to a significant extent by an electric motor which draws 

electricity from a battery that is capable of being recharged from an external source of electricity.

The tax credit for the purchase of a plug-in electric vehicle is $2,500, plus, starting at a battery capacity of 5 kWh, an additional 

$417 per kWh battery credit up to a maximum of $7,500 per vehicle. The tax credit eligibility and phase-out are specific to an 

individual vehicle manufacturer. The credits are phased out once a manufacturer’s cumulative sales of qualified vehicles reach 

200,000. The phaseout period begins two calendar quarters after the first date in which a manufacturer’s sales reach the 

cumulative sales maximum after December 31, 2009. The credit is reduced to 50% of the total value for the first two calendar 

quarters of the phase-out period and then to 25% for the third and fourth calendar quarters before being phased out entirely 

thereafter. The credit applies to vehicles with a gross vehicle weight rating of less than 14,000 pounds.

ARRA also allows a tax credit of 10% against the cost of a qualified electric vehicle with a battery capacity of at least 4 kWh 

subject to the same phase-out rules as above. The tax credits for qualified plug-in electric drive motor vehicles and electric 

vehicles are included in AEO2014.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 85
Transportation Demand Module

Energy Policy Act of 1992 (EPACT)

Fleet alternative-fuel vehicle sales necessary to meet the EPACT regulations are derived based on the mandates as they currently 

stand and the Commercial Fleet Vehicle Module calculations. Total projected AFV sales are divided into fleets by government, 

business, and fuel providers (Table 7.13).

Table 7.13. EPACT legislative mandates for AFV purchases by fleet type and year

percent

Year Federal State Fuel Providers Electric Utilities

2005 75 75 70 90

Source: U.S. Energy Information Administraiton, Energy Efficiency and Renewable Energy (Washington, DC, 2005), www1.eere.energy.gov/vehicles and 

fuels/epact/state/statutes_regulations.,html.

Because the commercial fleet model operates on three fleet type representations (business, government, and utility), the 

federal and state mandates are weighted by fleet vehicle stocks to create a composite mandate for both. The same combining 

methodology is used to create a composite mandate for electric utilities and fuel providers based on fleet vehicle stocks [36].

Low-Emission Vehicle Program (LEVP)

The LEVP was originally passed into legislation in 1990 in the State of California. It began as the implementation of a 

voluntary opt-in pilot program under the purview of Clean Air Act Amendments of 1990 (CAAA90), which included a provision 

that other states could opt in to the California program to achieve lower emissions levels than would otherwise be achieved 

through CAAA90. Fourteen states have elected to adopt the California LEVP.

The LEVP is an emissions-based policy, setting sales mandates for six categories of low-emission vehicles: low-emission vehicles 

(LEVs), ultra-low-emission vehicles (ULEVs), super-ultra-low-emission vehicles (SULEVs), partial zero-emission vehicles 

(PZEVs), advanced technology partial zero-emission vehicles (AT-PZEVs), and zero-emission vehicles (ZEVs). The LEVP requires 

that in 2005, 10% of a manufacturer’s sales are ZEVs or equivalent ZEV earned credits, increasing to 11% in 2009, 12% in 2012, 

14% in 2015, and 16% in 2018 where it remains constant thereafter. In August 2004, California Air Resources Board (CARB) 

enacted further amendments to the LEVP that place a greater emphasis on emissions reductions from PZEVs and AT-PZEVs 

and requires that manufacturers produce a minimum number of fuel cell and electric vehicles. In addition, manufacturers are 

allowed to adopt alternative compliance requirements for ZEV sales that are based on cumulative fuel cell vehicle sales targets 

for vehicles sold in all states participating in California’s LEVP. Under the alternative compliance requirements, ZEV credits can 

also be earned by selling battery electric vehicles. Currently, all manufacturers have opted to adhere to the alternative compliance 

requirements. The mandate still includes phase-in multipliers for pure ZEVs and allows 20% of the sales requirement to be met 

with AT-PZEVs and 60% of the requirement to be met with PZEVs. AT-PZEVs and PZEVs are allowed 0.2 credits per vehicle. EIA 

assumes that credit allowances for PZEVs will be met with conventional vehicle technology, hybrid vehicles will be sold to meet 

the AT-PZEV allowances, and hydrogen fuel cell vehicles will be sold to meet the pure ZEV requirements under the alternative 

compliance path.

Transportation alternative case

Integrated High Technology case

In the Integrated High Technology case for cars and light trucks, the conventional fuel-saving technology characteristics are 

based on NHTSA and EPA values [37]. Tables 7.14 and 7.15 summarize the high technology matrices for cars and light trucks. 

Table 7.16 reflects the high technology case assumptions for freight trucks. These reflect optimistic values, with respect to 

efficiency improvement and capital cost, for advanced technologies [38-41]. For the air module, the Integrated High Technology 

case reflects earlier introduction years for the new aircraft technologies and a greater penetration share (Table 7.17).

86 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.14. High technology matrix for cars

Fuel 

Efficiency 

Change %

Incremental 

Cost 2000$

Incremental 

Cost ($/

UnitWt.)

Absolute 

Incremental 

Weight 

(Lbs.)

Per Unit 

Incremental 

Weight 

(Lbs./

UnitWt.)

Introduction 

Year

Horsepower 

Change %

Unit Body Construction 4.4 89.92 0.00 0 -6 1980 0

Mass Reduction I 1.1 0.00 0.06 0 -1.5 2005 0

Mass Reduction II 2.9 0.00 0.13 0 -3.5 2009 0

Mass Reduction III 5.9 0.00 0.37 0 -10 2011 0

Mass Reduction IV 9.2 0.00 0.56 0 -15 2099 0

Mass Reduction V 12.8 0.00 0.65 0 -20 2099 0

Aerodynamics I 2.6 43.35 0.00 0 0.5 2000 0

Aerodynamics II 5.4 182.96 0.00 0 1 2011 0

6 Speed Manual 2.4 230.03 0.00 20 0 1995 0

Aggressive Shift Logic I 2.8 29.20 0.00 0 0 1999 0

Aggressive Shift Logic II 7.4 24.46 0.00 0 0 2017 0

Early Torque Converter Lockup 0.6 26.54 0.00 0 0 2002 0

High Efficiency Gearbox 1.8 180.56 0.00 0 0 2017 0

5 Speed Automatic 1.5 93.52 0.00 20 0 1995 0

6 Speed Automatic 2.4 243.05 0.00 30 0 2003 0

7 Speed Automatic 5.6 360.93 0.00 40 0 2009 0

8 Speed Automatic 8.8 479.55 0.00 50 0 2010 0

Dual Clutch Automated Manual 6.1 51.08 0.00 -10 0 2004 0

CVT 9.2 225.88 0.00 -25 0 1998 0

Low Friction Lubricants 0.8 2.88 0.00 0 0 2003 0

Engine Friction Reduction I-4 cyl 2.2 42.44 0.00 0 0 2000 1.25

Engine Friction Reduction I-6 cyl 2.9 64.02 0.00 0 0 2000 1.25

Engine Friction Reduction I-8 cyl 3.1 84.89 0.00 0 0 2000 1.25

Engine Friction Reduction II-4 cyl 4.0 90.64 0.00 0 0 2017 2.25

Engine Friction Reduction II-6 cyl 5.2 133.08 0.00 0 0 2017 2.25

Engine Friction Reduction II-8 cyl 5.6 175.53 0.00 0 0 2017 2.25

Cylinder Deactivation-6 cyl 7.2 168.36 0.00 10 0 2004 0

Cylinder Deactivation-8 cyl 7.6 188.97 0.00 10 0 2004 0

VVT I-OHV Intake Cam Phasing-6 cyl 2.9 39.51 0.00 20 0 2051 1.25

VVT I-OHV Intake Cam Phasing-8 cyl 3.0 39.51 0.00 30 0 2051 1.25

VVT I-OHC Intake Cam Phasing-4 cyl 2.3 39.51 0.00 10 0 1993 1.25

VVT I-OHC Intake Cam Phasing-6 cyl 2.9 79.88 0.00 20 0 1993 1.25

VVT I-OHC Intake Cam Phasing-8 cyl 3.0 79.88 0.00 30 0 1993 1.25

VVT II-OHV Coupled Cam Phasing-6 cyl 5.9 39.51 0.00 20 0 2009 1.25

VVT II-OHV Coupled Cam Phasing-8 cyl 6.4 39.51 0.00 30 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-4 cyl 4.7 39.51 0.00 10 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-6 cyl 5.9 79.88 0.00 20 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-8 cyl 6.4 79.88 0.00 30 0 2009 1.25

VVT III-OHV Dual Cam Phasing-6 cyl 5.9 89.33 0.00 25 0 2051 1.56

VVT III-OHV Dual Cam Phasing-8 cyl 6.4 89.33 0.00 37.5 0 2051 1.56

VVT III-OHC Dual Cam Phasing-4 cyl 4.7 81.60 0.00 12.5 0 2009 1.56

VVT III-OHC Dual Cam Phasing-6 cyl 5.9 176.09 0.00 25 0 2009 1.56

VVT III-OHC Dual Cam Phasing-8 cyl 6.4 176.09 0.00 37.5 0 2009 1.56

VVL I-OHV Discrete-6 cyl 6.1 202.72 0.00 40 0 2000 2.5

VVL I-OHV Discrete-8 cyl 6.5 290.33 0.00 50 0 2000 2.5

VVL I-OHC Discrete-4 cyl 4.7 140.01 0.00 25 0 2000 2.5

VVL I-OHC Discrete-6 cyl 6.1 202.72 0.00 40 0 2000 2.5

VVL I-OHC Discrete-8 cyl 6.5 290.33 0.00 50 0 2000 2.5

VVL II-OHV Continuous-6 cyl 7.7 1035.06 0.00 40 0 2011 2.5

VVL II-OHV Continuous-8 cyl 8.3 1131.26 0.00 50 0 2011 2.5

VVL II-OHC Continuous-4 cyl 5.9 209.59 0.00 25 0 2011 2.5

VVL II-OHC Continuous-6 cyl 7.7 384.82 0.00 40 0 2011 2.5

VVL II-OHC Continuous-8 cyl 8.3 420.04 0.00 50 0 2011 2.5

Stoichiometric GDI-4 cyl 1.7 237.93 0.00 20 0 2006 2.5

Stoichiometric GDI-6 cyl 1.7 358.19 0.00 30 0 2006 2.5

Stoichiometric GDI-8 cyl 1.7 430.34 0.00 40 0 2006 2.5

OHV to DOHC TBDS-I4 23.8 1245.51 0.00 -100 0 2009 3.75

OHV to DOHC TBDS I-V6 22.2 1887.16 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-I4 23.8 744.73 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-V6 22.2 1445.22 0.00 -100 0 2009 3.75

DOHC TBDS I-I3 19.3 823.75 0.00 -100 0 2009 3.75

DOHC TBDS I-I4 23.8 672.57 0.00 -100 0 2009 3.75

DOHC TBDS I-V6 22.2 1377.79 0.00 -100 0 2009 3.75

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 87
Transportation Demand Module

Table 7.14. High technology matrix for cars (cont.)

Fuel 

Efficiency 

Change %

Incremental 

Cost 2000$

Incremental 

Cost ($/

UnitWt.)

Absolute 

Incremental 

Weight 

(Lbs.)

Per Unit 

Incremental 

Weight 

(Lbs./

UnitWt.)

Introduction 

Year

Horsepower 

Change %

OHV to DOHC TBDS II-I4 28.9 1427.73 0.00 -100 0 2012 3.75

OHV to DOHC TBDS II-V6 27.0 2200.80 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-I4 28.9 941.53 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-V6 27.0 1771.73 0.00 -100 0 2012 3.75

DOHC TBDS II-I3 23.3 1017.42 0.00 -100 0 2012 3.75

DOHC TBDS II-I4 28.9 871.48 0.00 -100 0 2012 3.75

DOHC TBDS II-V6 27.0 1706.27 0.00 -100 0 2012 3.75

OHV to DOHC TBDS III-I4 (from V6) 35.9 1828.65 0.00 -100 0 2017 3.75

OHV to DOHC TBDS III-I4 (from V8) 33.8 1441.63 0.00 -200 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V6) 35.9 1409.25 0.00 -100 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V8) 33.8 1242.36 0.00 -200 0 2017 3.75

DOHC TBDS III-I3 (from I4) 29.8 1471.12 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V6) 35.9 1348.83 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V8) 33.8 1171.86 0.00 -200 0 2017 3.75

Electric Power Steering 1.4 96.44 0.00 0 0 2004 0

Improved Accessories I 0.8 78.74 0.00 0 0 2005 0

12V Micro Hybrid w/EPS and IACC 7.7 576.22 0.00 45 0 2005 0

Improved Accessories II 2.8 115.82 0.00 0 0 2012 0

Mild Hybrid w/EPS and IACC II 12.1 2611.80 0.00 80 0 2012 -2.5

Tires I 2.2 5.04 0.00 -12 0 2005 0

Tires II 4.4 52.51 0.00 -15 0 2017 0

Low Drag Brakes 0.9 53.23 0.00 0 0 2000 0

Secondary Axle Disconnect 1.4 86.70 0.00 0 -1 2012 0

Sources: Energy and Environmental Analysis, Documentation of Technology included in the NEMS Fuel Economy Model for Passenger Cars and Light Trucks 

(September, 2002). 

National Research Council, Effectiveness and Impact of Corporate Average Fuel Economy (CAFE) Standards (Copyright 2002). 

National Highway Traffic Safety Administration, Corporate Average Fuel Economy for MY 2011-2015 Passenger Cars and Light Trucks (April 2008). 

U.S. Environmental Protection Agency, Interim Report: New Powertrain Technologies and Their Projected Costs (October 2005).

Environmental Protection Agency and Department of Transportation National Highway Traffic Safety Administration, “2017 and Later Model Year Light-Duty 

Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule,” Federal Register Vol. 77, No. 199, October 15, 2012. 40 CFR 

Parts 85, 86, 600, 49 CFR Parts 523, 531, 533, et al. and 600.

Table 7.15. High technology matrix for light trucks

Fuel 

Efficiency 

Change %

Incremental 

Cost 2000$

Incremental 

Cost ($/

UnitWt.)

Absolute 

Incremental 

Weight 

(Lbs.)

Per Unit 

Incremental 

Weight 

(Lbs./

UnitWt.)

Introduction 

Year

Horsepower 

Change %

Unit Body Construction 4.4 90.00 0.00 0 -6 1980 0

Mass Reduction I 1.1 0.00 0.06 0 -1.5 2005 0

Mass Reduction II 2.9 0.00 0.13 0 -7.5 2009 0

Mass Reduction III 5.9 0.00 0.37 0 -10 2011 0

Mass Reduction IV 9.2 0.00 0.56 0 -15 2016 0

Mass Reduction V 12.8 0.00 0.65 0 -20 2020 0

Aerodynamics I 2.6 43.35 0.00 0 0.5 2000 0

Aerodynamics II 5.4 182.96 0.00 0 1 2011 0

6 Speed Manual 2.2 230.03 0.00 20 0 1995 0

Aggressive Shift Logic I 2.5 29.20 0.00 0 0 1999 0

Aggressive Shift Logic II 6.9 24.46 0.00 0 0 2017 0

Early Torque Converter Lockup 0.6 26.54 0.00 0 0 2002 0

High Efficiency Gearbox 1.8 180.56 0.00 0 0 2017 0

5 Speed Automatic 1.5 93.52 0.00 20 0 1995 0

6 Speed Automatic 2.2 243.05 0.00 30 0 2003 0

7 Speed Automatic 5.5 360.93 0.00 40 0 2009 0

8 Speed Automatic 8.8 479.55 0.00 50 0 2014 0

Dual Clutch Automated Manual 5.4 164.02 0.00 -10 0 2004 0

CVT 8.6 225.88 0.00 -25 0 1998 0

Low Friction Lubricants 0.8 2.88 0.00 0 0 2003 0

Engine Friction Reduction I-4 cyl 2.2 42.44 0.00 0 0 2000 1.25

Engine Friction Reduction I-6 cyl 2.9 64.02 0.00 0 0 2000 1.25

Engine Friction Reduction I-8 cyl 2.8 84.89 0.00 0 0 2000 1.25

Engine Friction Reduction II-4 cyl 4.0 90.64 0.00 0 0 2017 2.25

Engine Friction Reduction II-6 cyl 5.2 133.08 0.00 0 0 2017 2.25

Engine Friction Reduction II-8 cyl 4.8 175.53 0.00 0 0 2017 2.25

88 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.15. High technology matrix for light trucks (cont.)

Fuel 

Efficiency 

Change %

Incremental 

Cost 2000$

Incremental 

Cost ($/

UnitWt.)

Absolute 

Incremental 

Weight (Lbs.)

Per Unit 

Incremental 

Weight 

(Lbs./

UnitWt.)

Introduction 

Year

Horsepower 

Change %

Cylinder Deactivation-6 cyl 7.0 168.36 0.00 10 0 2004 0

Cylinder Deactivation-8 cyl 6.6 188.97 0.00 10 0 2004 0

VVT I-OHV Intake Cam Phasing-6 cyl 2.9 39.51 0.00 20 0 2051 1.25

VVT I-OHV Intake Cam Phasing-8 cyl 2.8 39.51 0.00 30 0 2051 1.25

VVT I-OHC Intake Cam Phasing-4 cyl 2.3 39.51 0.00 10 0 1993 1.25

VVT I-OHC Intake Cam Phasing-6 cyl 2.9 79.88 0.00 20 0 1993 1.25

VVT I-OHC Intake Cam Phasing-8 cyl 2.8 79.88 0.00 30 0 1993 1.25

VVT II-OHV Coupled Cam Phasing-6 cyl 5.9 39.51 0.00 20 0 2009 1.25

VVT II-OHV Coupled Cam Phasing-8 cyl 5.6 39.51 0.00 30 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-4 cyl 4.7 39.51 0.00 10 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-6 cyl 5.9 79.88 0.00 20 0 2009 1.25

VVT II-OHC Coupled Cam Phasing-8 cyl 5.6 79.88 0.00 30 0 2009 1.25

VVT III-OHV Dual Cam Phasing-6 cyl 5.9 89.33 0.00 25 0 2051 1.56

VVT III-OHV Dual Cam Phasing-8 cyl 5.6 89.33 0.00 37.5 0 2051 1.56

VVT III-OHC Dual Cam Phasing-4 cyl 4.7 81.60 0.00 12.5 0 2009 1.56

VVT III-OHC Dual Cam Phasing-6 cyl 5.9 176.09 0.00 25 0 2009 1.56

VVT III-OHC Dual Cam Phasing-8 cyl 5.6 176.09 0.00 37.5 0 2009 1.56

VVL I-OHV Discrete-6 cyl 6.1 202.72 0.00 40 0 2000 2.5

VVL I-OHV Discrete-8 cyl 5.7 290.33 0.00 50 0 2000 2.5

VVL I-OHC Discrete-4 cyl 4.6 140.01 0.00 25 0 2000 2.5

VVL I-OHC Discrete-6 cyl 6.1 202.72 0.00 40 0 2000 2.5

VVL I-OHC Discrete-8 cyl 5.7 290.33 0.00 50 0 2000 2.5

VVL II-OHV Continuous-6 cyl 7.7 1035.06 0.00 40 0 2011 2.5

VVL II-OHV Continuous-8 cyl 7.2 1131.26 0.00 50 0 2011 2.5

VVL II-OHC Continuous-4 cyl 5.8 209.59 0.00 25 0 2011 2.5

VVL II-OHC Continuous-6 cyl 7.7 384.82 0.00 40 0 2011 2.5

VVL II-OHC Continuous-8 cyl 7.2 420.04 0.00 50 0 2011 2.5

Stoichiometric GDI-4 cyl 1.7 237.93 0.00 20 0 2006 2.5

Stoichiometric GDI-6 cyl 1.7 358.19 0.00 30 0 2006 2.5

Stoichiometric GDI-8 cyl 1.7 430.34 0.00 40 0 2006 2.5

OHV to DOHC TBDS-I4 23.8 1245.51 0.00 -100 0 2009 3.75

OHV to DOHC TBDS I-V6 22.2 1887.16 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-I4 23.8 744.73 0.00 -100 0 2009 3.75

SOHC to DOHC TBDS I-V6 22.2 1445.22 0.00 -100 0 2009 3.75

DOHC TBDS I-I3 19.3 823.75 0.00 -100 0 2009 3.75

DOHC TBDS I-I4 23.8 672.57 0.00 -100 0 2009 3.75

DOHC TBDS I-V6 22.2 1377.79 0.00 -100 0 2009 3.75

OHV to DOHC TBDS II-I4 28.9 1427.73 0.00 -100 0 2012 3.75

OHV to DOHC TBDS II-V6 27.0 2200.80 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-I4 28.9 941.53 0.00 -100 0 2012 3.75

SOHC to DOHC TBDS II-V6 27.0 1771.73 0.00 -100 0 2012 3.75

DOHC TBDS II-I3 23.3 1017.42 0.00 -100 0 2012 3.75

DOHC TBDS II-I4 28.9 871.48 0.00 -100 0 2012 3.75

DOHC TBDS II-V6 27.0 1706.27 0.00 -100 0 2012 3.75

OHV to DOHC TBDS III-I4 (from V6) 35.9 1828.65 0.00 -100 0 2017 3.75

OHV to DOHC TBDS III-I4 (from V8) 33.8 1441.63 0.00 -200 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V6) 35.9 1409.25 0.00 -100 0 2017 3.75

SOHC to DOHC TBDS III-I4 (from V8) 33.8 1242.36 0.00 -200 0 2017 3.75

DOHC TBDS III-I3 (from I4) 29.8 1471.12 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V6) 35.9 1348.83 0.00 -100 0 2017 3.75

DOHC TBDS III-I4 (from V8) 33.8 1171.86 0.00 -200 0 2017 3.75

Electric Power Steering 1.1 96.44 0.00 0 0 2004 0

Improved Accessories I 0.8 78.74 0.00 0 0 2005 0

12V Micro Hybrid w/EPS and IACC 7.4 628.01 0.00 45 0 2005 0

Improved Accessories II 2.6 115.82 0.00 0 0 2012 0

Mild Hybrid w/EPS and IACC II 11.7 2611.80 0.00 80 0 2012 -2.5

Tires I 2.2 5.04 0.00 -12 0 2005 0

Tires II 4.4 52.51 0.00 -15 0 2017 0

Low Drag Brakes 0.9 53.23 0.00 0 0 2000 0

Secondary Axle Disconnect 1.5 86.70 0.00 0 -1 2012 0

Sources: Energy and Environmental Analysis, Documentation of Technology included in the NEMS Fuel Economy Model for Passenger Cars and Light Trucks 

(September, 2002). 

National Research Council, Effectiveness and Impact of Corporate Average Fuel Economy (CAFE) Standards (Copyright 2002). 

National Highway Traffic Safety Administration, Corporate Average Fuel Economy for MY 2011-2015 Passenger Cars and Light Trucks (April 2008). 

U.S. Environmental Protection Agency, Interim Report: New Powertrain Technologies and Their Projected Costs (October 2005).

Environmental Protection Agency and Department of Transportation National Highway Traffic Safety Administration, “2017 and Later Model Year Light-Duty 

Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule,” Federal Register Vol. 77, No. 199, October 15, 2012. 40 CFR 

Parts 85, 86, 600, 49 CFR Parts 523, 531, 533, et al. and 600. 

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 89
Transportation Demand Module

Table 7.16. High technology matrix for freight trucks

Technology Type

Vehicle 

Category

Capital Costs

(2009$)

Incremental Fuel 

Economy 

Improvement 

(%)

Aerodynamics I: streamlined bumper, grill, windshield, roof 1 53 2.0 

Aerodynamics I: conventional features; general aerodynamic shape, removal of classic non-aerodynamic features 5, 8, 11 900 4.5 

Aerodynamics I 7,10, 13 900 5.1 

Aerodynamics II: SmartWay features; streamlined shape, bumper grill, hood, mirrors, side fuel tank and roof fairings, 

side gap extenders 5, 8 997 2.0 

Aerodynamics II 7,10 997 4.0 

Aerodynamics II 11 1040 5.0 

Aerodynamics II 13 1355 5.0 

Aerodynamics III: underbody airflow, down exhaust, lowered ride height 7 1552 5.0

Aerodynamics III 13 1803 7.0

Aerodynamics IV: skirts, boat tails, nose cone, vortex stabilizer, pneumatic blowing 5-13 4950 14.0

Tires I: low rolling resistance 1 6 2.0

Tires I 2,3 110 3.0

Tires I 4 131 2.2

Tires I 5-7 114 2.2

Tires I 8-13 172 2.2

Tires II: super singles 5-13 140 6.2

Tires III: single wide tires on trailer 5-13 720 3.4

Weight Reduction I 1 116 1.8

Weight Reduction I: aluminum dual tires or super singles 5-13 580 1.1

Weight Reduction II: weight reduction 15% 3-13 5580 3.3

Weight Reduction III: weight reduction 20% 3-13 9900 3.9

Accessories I: Electric/electrohydraulic improvements; electric power steering or electrohydraulic power steering 1 105 2.0

Accessories II: Improved accessories; electrified water, oil, fuel injection, power steering pump, aircompressor 1 85 2.0

Accessories III: Auxiliary Power Unit 11-13 4834 6.4

Transmission I: 8-speed Automatic from 6-speed automatic 1 248 1.9

Transmission II: 6-Manual from 4-speed automatic 1 135 1.1

Transmission III: Automated Manual Transmission 2-13 4500 3.9

Diesel Engine I: aftertreatment improvements 1 109 5.0

Diesel Engine I 2 109 4.0

Diesel Engine II: low friction lubricants 1-13 3 1.0

Diesel Engine III: variable valve actuation 2 0 1.1

Diesel Engine III 3-13 270 1.1

Diesel Engine IV: engine friction reduction, low tension piston rings, roller cam followers, piston skirt design, 

improved crankshaft design and bearings; coating 1-2 111 2.0

Diesel Engine IV: engine friction reduction, improved bearings to allow lower viscosity oil 3-13 225 2.0

Diesel Engine V: improved turbo efficiency 2-13 15 2.0

Diesel Engine VI: improved water, oil, fuel pump; pistons; valve train friction reduction 2 192 2.0

Diesel Engine VI 3, 5-7 167 2.0 

Diesel Engine VI: improved water, oil, fuel pump; pistons 4, 8-13 135 2.0

Diesel Engine VII: improved cylinder head, fuel rail and injector, EGR cooler 2 36 7.0

Diesel Engine VII 3-13 26 7.0

Diesel Engine VIII: turbo mechanical compounding 5-13 900 5.0

Diesel Engine IX: low temperature EGR, improved turbochargers 1 166 6.0

Diesel Engine X: sequential downsizing/turbocharging 5-13 1080 2.8

Diesel Engine XI: waste heat recovery, Organic Ranking Cycle (bottoming cycle) 3-13 9000 8.8

Diesel Engine XII: electric turbo compounding 4-13 7200 10.0

Gasoline Engine I: low friction lubricants 1-13 3 0.6

Gasoline Engine II: coupled cam phasing 2-4 43 4.0

Gasoline Engine III: engine friction reduction; low tension piston rings, roller cam followers, piston skirt design, 

improved crankshaft design and bearings; coating 1 111 3.0

Gasoline III 2 104 3.0

Gasoline III 3-4 86 3.0

Gasoline Engine IV: stoichiometric gasoline direct injection V8 1-2 425 2.0

Gasoline Engine IV 3-4 430 2.0

Gasoline Engine V: turbocharging and downsizing SGDI V8 to V6 1-4 1569 2.2

Gasoline Engine VI: lean burn GDI 1-4 675 14.0

Gasoline Engine VII: HCCI 1-4 617 14.0

Hybrid System I: 42V engine off at idle 1-2 1350 7.7

Hybrid System I 3-4 1350 5.0

Hybrid System II: dual mode hybrid 1-2 10800 27.5

Hybrid System II: electric, ePTO, or hydraulic 3-4 24000 33.0

Hybrid System II: 4 kWh battery, 50 kW motor generator 5-13 24000 6.0

Sources: Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles, U.S. Environmental Protection Agency and U.S. Department of Transportation, 

Final Rules, Federal Register, Vol. 76, No. 179, (September 2011). 

Final Rulemaking to Establish Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles, Regulatory Impact Analysis, U.S. Environmental 

Protection Agency and U.S. Department of Transportation, (August 2011). 

Reducing Heavy-Duty Long Haul Combination Truck Fuel Consumption and CO2 Emissions, Final Report, TIAX, LLC. (October 2009). 

Update of Technology Information for Forecasting Heavy-Duty On-Road Vehicle Fuel Economy, Final Report, ICF International, Prepared for the U.S. Energy Information Administration, (August 2010). 

Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, National Research Council of the National Academy of Sciences, (2010).

90 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Transportation Demand Module

Table 7.17. High technology matrix for air travel

Technology Introduction Year Fractional Efficiency Improvement Jet Fuel Trigger Price (1987$ per gallon)

Technology #1 2008 0.03 1.34

Technology #2 2014 0.07 1.34

Technology #3 2020 0.11 1.34

Technology #4 2025 0.15 1.34

Technology #5 2018 0.22 1.34

Technology #6 2018 0.10 1.34

Technology #7 2025 0.04 1.00

Technology #8 2020 0.05 1.34

Sources: Jet Information Services, 2009 World Jet Inventory, data tables (2009). 

Energy Information Administration, Transportation Sector Model of the National Energy Modeling System, Model Documentation 2014, DOE/

EIA-M070(2014), (Washington, DC, 2014).

Notes and sources

[1] U.S. Department of Transportation, National Highway Traffic Safety Administration, “Summary of Fuel Economy Performance,” 

(Washington, DC, December 2009). 

[2] Goldberg, Pinelopi Koujianou, “Product Differentiation and Oligopoly In International Markets: The Case of The U.S. 

Automobile Industry,” Econometrica, Vol. 63, No.4 (July, 1995), 891-951.

[3] Oak Ridge National Laboratory, “Fleet Characteristics and Data Issues,” Stacy Davis and Lorena Truett, final report prepared for 

the Department of Energy, Energy Information Administration, Office of Energy Analysis, (Oak Ridge, TN, January 2003). 

[4] Bobit Publishing Company, The Fleet Fact Book, various issues (Redondo Beach, California). 

[5] Bobit Publishing Company, Note 4.

[6] Davis, Stacy C., Lorena F. Truett, “Investigation of Class 2B Trucks (Vehicles of 8,500 to 10,000 LBS GVWR),” Oak

Ridge National Laboratory, ORNL/TM-2002/49, March 2002. 

[7] Davis, Stacy C., Lorena F. Truett, op.cit., Note 6.

[8] Greenspan, Alan, and Darrel Cohen, “Motor Vehicle Stocks, Scrappage, and Sales,” Federal Reserve Board

(Washington, DC, October 30, 1996). 

[9] Oak Ridge National Laboratory, Transportation Energy Data Book: 31st Edition (Oak Ridge, TN, 2012). 

[10] Davis, Stacy C., Lorena F. Truett, op.cit., Note 6.

[11] Greene, David L. and S.M. Chin, “Alternative Fuels and Vehicles (AFV) Model Changes,” Center for Transportation

Analysis, Oak Ridge National Laboratory, (Oak Ridge, TN, November 14, 2000).

[12] U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, prepared by Interlaboratory

Working Group, Scenarios of U.S. Carbon Reductions: Potential Impacts of Energy Technologies by 2010 and Beyond, (Washington, 

DC, 1998).

[13] Energy and Environmental Analysis, Inc., Updates to the Fuel Economy Model (FEM) and Advanced Technology

Vehicle (ATV) Module of the National Energy Modeling System (NEMS) Transportation Model, Prepared for the Energy

Information Administration (EIA), (Arlington, VA, October 23, 2000).

[14] WardsAuto, “U.S. Vehicle Sales by Vehicle Type and Source, 1931-2013, http://wardsauto.com/keydata/historical/

UsaSa01summary.

[15] U.S. Energy Information Administration, State Energy Data System 2009.

[16] U.S. Department of Transportation and U.S. Census Bureau, “Commodity Flow Survey” (2009, 2002, 1997).

[17] U.S. Department of Transportation, National Transportation Statistics (1995-2009).

[18] U.S. Department of Transportation, Federal Highway Administration, Highway Statistics (1995-2011).

[19] Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and

Vehicles, U.S. Environmental Protection Agency and U.S. Department of Transportation, Final Rules, Federal Register, Vol.

76, No. 179, (September 2011).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 91
Transportation Demand Module

Notes and sources (cont.)

[20] U.S. Department of Commerce, Bureau of the Census, “Vehicle Inventory and Use Survey,” ECO2TV (Washington, DC, 

December 2009).

[21] U.S. Department of Transportation, op. cit. Note 16. 

[22] U.S. Department of Transportation, Surface Transportation Board, Annual Reports (R-1) (1995-2011).

[23] U.S. Department of Transportation, op. cit. Note 22.

[24] U.S. Department of Transportation, Federal Railroad Administration, “1989 Carload Waybill Statistics; Territorial 

Distribution, Traffic and Revenue by Commodity Classes,” (September 1991 and prior issues). 

[25] U.S. Energy Information Administration, op. cit., Note 15.

[26] U.S. Army Corps of Engineers, Waterborne Commerce of the United States, (Waterborne Statistics Center: New

Orleans, LA, 1993).

[27] U.S. Department of Transportation,, op. cit., Note 16. 

[28] Oak Ridge National Lab, op. cit., Note 9. 

[29] U.S. Army Corps of Engineers, op. cit., Note 27. 

[30] U.S. Energy Information Administration, op. cit., Note 15.

[31] U.S. Department of Transportation, Research and Innovative Technology Administration, Bureau of Transportation Statistics, 

Air Carrier Summary Data (Form 41, Schedules T-1 and T-2), (2011) http://www.transtats.bts.gov/DataIndex. asp; link: Air Carrier 

Summary Data (Form 41 and 298C Summary Data). 

[32] U.S. Department of Transportation, Research and Innovative Technology Administration, Bureau of Transportation

Statistics, op. cit., Note 28.

[33] U.S. Department of Transportation, Federal Aviation Administration, Airport Capacity Benchmark Report, 2004 (2004). 

[34] Jet Information Services Inc., World Jet Inventory: Year-End 2009 (December 2009). 

[35] Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and

Vehicles, U.S. Environmental Protection Agency and U.S. Department of Transportation, Final Rules, Federal Register, Vol. 76, 

No. 179 (September 2011).

[36] Energy Information Administration, op. cit., Note 14.

[37] Energy and Environmental Analysis, Inc., “Documentation of Technologies Included in the NEMS Fuel Economy Model for 

Passenger Cars and Light Trucks,” Prepared for the U.S. Energy Information Administration (Arlington, VA, September 30, 2002).

[38] Final Rulemaking to Establish Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and 

Heavy-Duty Engines and Vehicles, Regulatory Impact Analysis, U.S. Environmental Protection Agency and U.S. Department of 

Transportation (August 2011).

[39] Reducing Heavy-Duty Long Haul Combination Truck Fuel Consumption and CO2 Emissions, Final Report, TIAX, LLC 

(October 2009).

[40] Update of Technology Information for Forecasting Heavy-Duty On-Road Vehicle Fuel Economy, Final Report, ICF 

International, Prepared for the U.S. Energy Information Administration (August 2010).

[41] Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, National Research 

Council of the National Academy of Sciences (2010).

92 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Electricity Market Module

The NEMS Electricity Market Module (EMM) represents the capacity planning, dispatching, and pricing of electricity. It is 

composed of four submodules— electricity load and demand, electricity capacity planning, electricity fuel dispatching, and 

electricity finance and pricing. It includes nonutility capacity and generation, and electricity transmission and trade. A detailed 

description of the EMM is provided in the EIA publication, Electricity Market Module of the National Energy Modeling System 

2014, DOE/EIA-M068(2014).

Based on fuel prices and electricity demands provided by the other modules of NEMS, the EMM determines the most 

economical way to supply electricity, within environmental and operational constraints. There are assumptions about the 

operations of the electricity sector and the costs of various options in each of the EMM submodules. This section describes 

the model parameters and assumptions used in the EMM. It includes a discussion of legislation and regulations that are 

incorporated in the EMM, as well as information about the climate change action plan. The various electricity side cases are also 

described.

EMM regions 

The supply regions used in the EMM are based on the North American Electric Reliability Corporation regions and subregions 

shown in Figure 6.

Figure 6. Electricity Market Model Supply Regions

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 95
Electricity Market Module

Model parameters and assumptions 

Generating capacity types 

The capacity types represented in the EMM are shown in Table 8.1.

Table 8.1. Generating capacity types represented in the Electricity Market Module

Capacity Type

Existing coal steam plants1

High Sulfur Pulverized Coal with Wet Flue Gas Desulfurization

Advanced Coal - Integrated Coal Gasification Combined Cycle (IGCC)

IGCC with Carbon Sequestration

Oil/Gas Steam - Oil/Gas Steam Turbine

Combined Cycle - Conventional Gas/Oil Combined Cycle Combustion Turbine

Advanced Combined Cycle - Advanced Gas/Oil Combined Cycle Combustion Turbine

Advanced Combined Cycle with carbon sequestration

Combustion Turbine - Conventional Combustion Turbine

Advanced Combustion Turbine - Steam Injected Gas Turbine

Molten Carbonate Fuel Cell

Conventional Nuclear

Advanced Nuclear - Advanced Light Water Reactor

Generic Distributed Generation - Baseload

Generic Distributed Generation - Peak

Conventional Hydropower - Hydraulic Turbine

Pumped Storage - Hydraulic Turbine Reversible

Geothermal

Municipal Solid Waste

Biomass - Fluidized Bed

Solar Thermal - Central Tower

Solar Photovoltaic - Fixed Tilt

Wind

Wind Offshore

1

The EMM represents 32 different types of existing coal steam plants, based on the different possible configuration of NOx, particulate and SO2

emission control devices, as well as future options for controlling mercury and carbon.

Source: U.S. Energy Information Administration.

New generating plant characteristics 

The cost and performance characteristics of new generating technologies are inputs to the electricity capacity planning 

submodule (Table 8.2). These characteristics are used in combination with fuel prices from the NEMS fuel supply modules and 

foresight on fuel prices, to compare options when new capacity is needed. Heat rates for new fossil-fueled technologies are 

assumed to decline linearly through 2025.

For AEO2013, EIA commissioned an external consultant to update current cost estimates for utility-scale electric generating 

plants [1]. This report used a consistent methodology, similar to the one used to develop the estimates for AEO2011 and 

AEO2012, but accounted for more recent data and experience. Because the costs from the report were assumed to be consistent 

with plants that would be ordered in 2012, for AEO2014 the initial costs were adjusted to account for learning from capacity built 

during 2012. A cost adjustment factor, based on the producer price index for metals and metal products, allows the overnight 

costs to fall in the future if this index drops, or rise further if it increases.

The overnight costs shown in Table 8.2 represent the estimated cost of building a plant in a typical region of the country. 

Differences in plant costs due to regional distinctions are calculated by applying regional multipliers. Regional multipliers by 

technology are also based on regional cost estimates developed by the consultant. The regional variations account for multiple 

96 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Electricity Market Module

Table 8.2. Cost and performance characteristics of new central station electricity generating technologies

Technology

Online

Year1

Size

(MW)

Lead 

time

(years)

Base 

Overnight 

Cost in 

2013

(2012 $/kW)

Contingency Factors

Total 

Overnight

Cost in 20134

(2012 $/kW)

Variable

O&M5

(2012 $/

mWh)

Fixed

O&M

(2012$/

kW/yr.)

Heatrate6

in 2013

(Btu/

kWh)

nth-ofa-kind 

Heatrate 

(Btu/

kWh

Project 

Contingency

Factor2

Technological

Optimism

Factor3

Scrubbed Coal New 2017 1300 4 2,734 1.07 1.00 2,925 4.47 31.18 8,800 8,740

Integrated CoalGasification Comb 

Cycle (IGCC) 2017 1200 4 3,525 1.07 1.00 3,771 7.22 51.39 8,700 7,450

IGCC with Carbon 

sequestion 2017 520 4 5,958 1.07 1.03 6,567 8.45 72.84 10,700 8,307

Conv Gas/Oil Comb 

Cycle 2016 620 3 871 1.05 1.00 915 3.60 13.17 7,050 6,800

Adv Gas/Oil Comb 

Cycle (CC) 2016 400 3 945 1.08 1.00 1,021 3.27 15.37 6,430 6,333

Adv CC with carbon 

sequestration 2017 340 3 1,856 1.08 1.04 2,084 6.78 31.79 7,525 7,493

Conv Comb Turbine8 2015 85 2 924 1.05 1.00 971 15.45 7.34 10,817 10,450

Adv Comb Turbine 2015 210 2 641 1.05 1.00 673 10.37 7.04 9,750 8,550

Fuel Cells 2016 10 3 6,099 1.05 1.10 7,044 42.99 0.00 9,500 6,960

Adv Nuclear 2019 2234 6 4,763 1.10 1.05 5,501 2.14 93.28 10,464 10,464

Distributed 

Generation - Base 2016 2 3 1,414 1.05 1.00 1,485 7.76 17.45 9,027 8,900

Distributed 

Generation - Peak 2015 1 2 1,698 1.05 1.00 1,783 7.76 17.45 10,029 9,880

Biomass 2017 50 4 3,590 1.07 1.02 3,919 5.26 105.64 13,500 13,500

Geothermal7,9 2016 50 4 2,375 1.05 1.00 2,494 0.00 112.92 9,716 9,716

Muncipal Solid Waste 2014 50 3 7,751 1.07 1.00 8,294 8.75 392.81 18,000 18,000

Conventional 

Hydropower9 2017 500 4 2,213 1.10 1.00 2,435 2.65 14.83 9,716 9,716

Wind 2014 100 3 2,061 1.07 1.00 2,205 0.00 39.55 9,716 9,716

Wind Offshore 2017 400 4 4,503 1.10 1.25 6,192 0.00 74.00 9,716 9,716

Solar Thermal7 2016 100 3 4,715 1.07 1.00 5,045 0.00 67.26 9,716 9,716

Photovoltaic7,10 2015 150 2 3,394 1.05 1.00 3,564 0.00 24.69 9,716 9,716 1 Online year represents the first year that a new unit could be completed, given an order date of 2013. For wind, geothermal and landfill gas, the online year was 

moved earlier to acknowledge both market activity already occurring as well as the incentive for certain types of projects to develop at an accelerated rate in order 

to qualify for the Production Tax Credit. 

2

A contingency allowance is defined by the American Association of Cost Engineers as the “specific provision for unforeseeable elements of costs within a defined 

project scope; particularly important where previous experience has shown that unforeseeable events which will increase costs are likely to occur.”

3

The technological optimism factor is applied to the first four units of a new, unproven design; it reflects the demonstrated tendency to underestimate actual costs 

for a first-of-a-kind unit.

4Overnight capital cost including contingency factors, excluding regional multipliers and learning effects. Interest charges are also excluded. These represent costs 

of new projects initiated in 2013. 

5

O&M = Operations and maintenance.

6

For hydro, wind, solar and geothermal technologies, the heatrate shown represents the average heatrate for conventional thermal generation as of 2012.  This 

is used for purposes of calculating primary energy consumption displaced for these resources, and does not imply an estimate of their actual energy conversion 

efficiency.

7

Capital costs are shown before investment tax credits are applied. 

8

Combustion turbine units can be built by the model prior to 2015 if necessary to meet a given region’s reserve margin.

9

Because geothermal and hydro cost and performance characteristics are specific for each site, the table entries represent the cost of the least expensive plant 

that could be built in the Northwest Power Pool region, where most of the proposed sites are located.

10Costs and capacities are expressed in terms of net AC power available to the grid for the installed capacity. 

Sources: For the AEO2014 cycle, EIA continues to use the previously developed cost estimates for utility-scale electric generating plants, updated by external 

consultants for AEO2013. This report can be found at http://www.eia.gov/forecasts/capitalcost/. The costs were assumed to be consistent with plants that would 

be ordered in 2012, and learning from capacity built in 2012 has been applied in the initial costs above. Site-specific costs for geothermal were provided by the 

National Renewable Energy Laboratory, “Updated U.S. Geothermal Supply Curve,” February 2010.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 97
Electricity Market Module

factors, such as differences in terrain, weather, population, and labor wages. The base overnight cost is multiplied by a 

project contingency factor and a technological optimism factor (described later in this chapter), resulting in the total 

construction cost for the first-of-a-kind unit used for the capacity choice decision.

Technological optimism and learning 

Overnight costs for each technology are calculated as a function of regional construction parameters, project contingency, 

and technological optimism and learning factors.

The technological optimism factor represents the demonstrated tendency to underestimate actual costs for a first-of-akind, unproven technology. As experience is gained (after building four units) the technological optimism factor is gradually 

reduced to 1.0.

The learning function in NEMS is determined at a component level. Each new technology is broken into its major 

components, and each component is identified as revolutionary, evolutionary or mature. Different learning rates 

are assumed for each component, based on the level of experience with the design component (Table 8.3). Where 

technologies use similar components, these components learn at the same rate as these units are built. For example, it is 

assumed that the underlying turbine generator for a combustion turbine, combined cycle and integrated coal-gasification 

combined cycle unit is basically the same. Therefore construction of any of these technologies would contribute to learning 

reductions for the turbine component.

The learning function, OC, has the nonlinear form:

 OC(C) = a*C-b,

where C is the cumulative capacity for the technology component.

Table 8.3. Learning parameters for new generating technology components

Technology Component

Period 1

Learning Rate 

(LR1)

Period 2

Learning Rate 

(LR2)

Period 3

Learning Rate 

(LR3)

Period 1

Doublings

Period 2

Doublings

Minimum Total

Learning by 2035

Pulverized Coal - - 1% - - 5%

Combustion Turbine - conventional - - 1% - - 5%

Combustion Turbine - advanced - 10% 1% - 5 10%

HRSG1 - - 1% - - 5%

Gasifier - 10% 1% - 5 10%

Carbon Capture/Sequestration 20% 10% 1% 3 5 20%

Balance of Plant - IGCC - - 1% - - 5%

Balance of Plant - Turbine - - 1% - - 5%

Balance of Plant - Combined Cycle - - 1% - - 5%

Fuel Cell 20% 10% 1% 3 5 20%

Advanced Nuclear 5% 3% 1% 3 5 10%

Fuel prep - Biomass - 10% 1% - 5 10%

Distributed Generation - Base - 5% 1% - 5 10%

Distributed Generation - Peak - 5% 1% - 5 10%

Geothermal - 8% 1% - 5 10%

Municipal Solid Waste - - 1% - - 5%

Hydropower - - 1% - - 5%

Wind - - 1% - - 5%

Wind Offshore 20% 10% 1% 3 5 20%

Solar Thermal 20% 10% 1% 3 5 10%

Solar PV - Module - 10% 1% - 5 10%

Balance of Plant - Solar PV - 10% 1% - 5 10%

1

HRSG = Heat Recovery Steam Generator

Note: Please see the text for a description of the methodology for learning in the Electricity Market Module.

Source: U.S. Energy Information Administration, Office of Electricity, Coal, Nuclear and Renewables Analysis.

The progress ratio (pr) is defined by speed of learning (e.g., how much costs decline for every doubling of capacity). 

The reduction in capital cost for every doubling of cumulative capacity (LR) is an exogenous parameter input for each 

component (Table 8.3). The progress ratio and LR are related by:

 pr = 2-b = (1 - LR)

98 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Electricity Market Module

The parameter “b” is calculated from the second equality above (b =-(ln(1-LR)/ln(2))). The parameter “a” is computed from 

initial conditions, i.e.

 a =OC(C0)/Co -b

where C0 is the initial cumulative capacity. Once the rates of learning (LR) and the cumulative capacity (C0) are known for 

each interval, the parameters (a and b) can be computed. Three learning steps were developed to reflect different stages of 

learning as a new design is introduced into the market. New designs with a significant amount of untested technology will see 

high rates of learning initially, while more conventional designs will not have as much learning potential. Costs of all design 

components are adjusted to reflect a minimal amount of learning, even if new capacity additions are not projected. This 

represents cost reductions due to future international development or increased research and development.

Once the learning rates by component are calculated, a weighted average learning factor is calculated for each technology. 

The weights are based on the share of the initial cost estimate that is attributable to each component (Table 8.4). For 

technologies that do not share components, this weighted average learning rate is calculated exogenously, and input as a 

single component.

These technologies may still have a mix of revolutionary components and more mature components, but it is not necessary 

to include this detail in the model unless capacity from multiple technologies would contribute to the component learning. 

In the case of the solar PV technology, it is assumed that the module component accounts for 50% of the cost, and that the 

balance of system components accounts for the remaining 50%. Because the amount of end-use PV capacity (existing and 

projected) is significant relative to total solar PV capacity, and because the technology of the module component is common 

across the end-use and electric power sectors, the calculation of the learning factor for the PV module component also takes 

into account capacity built in the residential and commercial sectors.

Table 8.5 shows the capacity credit toward component learning for the various technologies. It was assumed that for all 

combined-cycle technologies, the turbine unit contributed two-thirds of the capacity, and the steam unit one-third. Therefore, 

building one gigawatt of gas combined cycle would contribute 0.67 gigawatts (GW) toward turbine learning, and 0.33 GW 

toward steam learning. Components that do not contribute to the capacity of the plant, such as the balance of plant category, 

receive 100% capacity credit for any capacity built with that component. For example, when calculating capacity for the 

“Balance of plant - CC” component, all combined cycle capacity would be counted 100%, both conventional and advanced.

Table 8.4. Component cost weights for new technologies

Technology

Pulverized 

Coal

Combustion

Turbineconventional

Combustion

Turbineadvanced HRSG Gasifier

Carbon

Capture/

Sequestration

Balance

of PlantIGCC

Balance 

of

PlantTurbine

Balance 

of

PlantCombined

Cycle

Fuel 

Prep

Biomass

Integrated

Coal-Gasification 

Comb Cycle (IGCC) 0% 0% 15% 20% 41% 0% 24% 0% 0% 0%

IGCCwith carbon 

sequestration 0% 0% 10% 15% 30% 30% 15% 0% 0% 0%

Conv Gas/Oil Comb 

Cycle 0% 30% 0% 40% 0% 0% 0% 0% 30% 0%

Adv Gas/Oil Comb 

Cycle (CC) 0% 0% 30% 40% 0% 0% 0% 0% 30% 0%

Adv CC with carbon 

sequestration 0% 0% 20% 25% 0% 40% 0% 0% 15% 0%

Conv Comb Turbine 0% 50% 0% 0% 0% 0% 0% 50% 0% 0%

Adv Comb Turbine 0% 0% 50% 0% 0% 0% 0% 50% 0% 0%

Biomass 50% 0% 0% 0% 0% 0% 0% 0% 0% 50%

Note: All unlisted technologies have a 100% weight with the corresponding component. Components are not broken out for all technologies unless there 

is overlap with other technologies.

HRSG = Heat Recovery Steam Generator.

Source: Market-Based Advanced Coal Power Systems, May 1999, DOE/FE-0400.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 99
Electricity Market Module

Table 8.5. Component capacity weights for new technologies

Technology

Pulverized 

Coal

Combustion

Turbineconventional

Combustion

Turbineadvanced HRSG Gasifier

Carbon

Capture/

Sequestration

Balance

of PlantIGCC

Balance 

of PlantTurbine

Balance of

PlantCombined

Cycle

Fuel 

Prep

Biomass

Integrated

Coal-Gasification Comb 

Cycle (IGCC) 0% 0% 67% 33% 100% 0% 100% 0% 0% 0%

IGCC with Carbon 

sequestration 0% 0% 67% 33% 100% 100% 100% 0% 0% 0%

Conv Gas/Oil Comb Cycle 0% 67% 0% 33% 0% 0% 0% 0% 100% 0%

Adv Gas/Oil Comb Cycle 

(CC) 0% 0% 67% 33% 0% 0% 0% 0% 100% 0%

Adv CC with carbon 

sequestration 0% 0% 67% 33% 0% 100% 0% 0% 100% 0%

Conv Comb Turbine 0% 100% 0% 0% 0% 0% 0% 100% 0% 0%

Adv Comb Turbine 0% 0% 100% 0% 0% 0% 0% 100% 0% 0%

Biomass 50% 0% 0% 0% 0% 0% 0% 0% 0% 100%

HRSG = Heat Recovery Steam Generator.

Source: U.S. Energy Information Administration, Office of Electricity, Coal, Nuclear and Renewables Analysis.

Distributed generation 

Distributed generation is modeled in the end-use sectors (as described in the appropriate chapters) as well as in the EMM. 

This section describes the representation of distributed generation in the EMM only. Two generic distributed technologies are 

modeled. The first technology represents peaking capacity (capacity that has relatively high operating costs and is operated 

when demand levels are at their highest). The second generic technology for distributed generation represents base load capacity 

(capacity that is operated on a continuous basis under a variety of demand levels). See Table 8.2 for costs and performance 

assumptions. It is assumed that these plants reduce the costs of transmission upgrades that would otherwise be needed. 

Demand storage 

The EMM includes the option to build a new demand storage technology to simulate load shifting, through programs such as 

smart meters. This is modeled as a new technology build, but with operating characteristics similar to pumped storage. The 

technology is able to decrease the load in peak slices, but must generate to replace that demand in other time slices. There is an 

input factor that identifies the amount of replacement generation needed, where a factor of less than 1.0 can be used to represent 

peak shaving rather than purely shifting the load to other time periods. This plant type is limited to operating only in the peak load 

slices, and for AEO2014, it is assumed that this capacity is limited to 3.5% of peak demand on average in 2040, with limits varying 

from 2.2% to 6.8% of peak across the regions.

Representation of electricity demand 

The annual electricity demand projections from the NEMS demand modules are converted into load duration curves for each 

of the EMM regions (based on North American Electric Reliability Corporation regions and subregions) using historical hourly 

load data. The load duration curve in the EMM is made up of 9 time slices. First, the load data is split into three seasons (winter - 

December through March, summer - June through September, and fall/spring). Within each season the load data is sorted from 

high to low, and three load segments are created - a peak segment representing the top 1% of the load, and then two off-peak 

segments representing the next 49% and 50%, respectively. The seasons were defined to account for seasonal variation in supply 

availability.

Reserve margins—the percentage of capacity in excess of peak demand required to adequately maintain reliability during 

unforeseeable outages—are established for each region by its governing body – public utility commission, NERC region or 

Independent System Operators (ISOs)/Regional Transmission Operators (RTOs). The reserve margin values from the AEO2014

Reference case are set based on these regional Reference Margins reported to NERC and range from 14% to 17% [2].

Operating reserves

In addition to the planning reserve margin requirement, system operators typically require a specific level of operating reserves – 

generators available within a short period of time to meet demand in case a generator goes down or there is another disruption to 

supply. These reserves can be provided through plants that are already operating but not at full capacity (spinning reserves) 

100 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
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as well as through capacity not currently operating but that can be brought online quickly (non-spinning reserves). This is 

particularly important as more intermittent generators are added to the grid, because technologies like wind and solar have 

uncertain availability that can be difficult to predict. For AEO2014, the capacity and dispatch submodules of the EMM were 

both updated to include explicit constraints requiring spinning reserves in each load slice. The amount of spinning reserves 

required is computed as a percentage of the load height of the slice plus a percentage of the distance between the load of the 

slice and the seasonal peak. An additional requirement is calculated that is a percentage of the intermittent capacity available 

in that time period to reflect the greater uncertainty associated with the availability of intermittent resources. All technologies 

except for storage, intermittents and distributed generation can be used to meet spinning reserves. Different operating modes 

are developed for each technology type to allow the model to choose between operating a plant to maximize generation versus 

contributing to spinning reserves, or a combination of both. Minimum levels of generation are required if a plant is contributing to 

spinning reserves, and vary by plant type, with plant types typically associated with baseload operation having higher minimums 

than those that can more operate more flexibly to meet intermediate or peak demand.

Fossil fuel-fired and nuclear steam plant retirement 

Fossil-fired steam plant retirements and nuclear retirements are calculated endogenously within the model. Generating units 

are assumed to retire when it is no longer economical to continue running them. Each year, the model determines whether 

the market price of electricity is sufficient to support the continued operation of existing plant generators. A generating unit is 

assumed to retire if the expected revenues from the generator are not sufficient to cover the annual going-forward costs and if 

the overall cost of producing electricity can be lowered by building new replacement capacity. The going-forward costs include 

fuel, operations and maintenance costs and annual capital additions, which are unit-specific and based on historical data. The 

average capital additions for existing plants are $8 per kilowatt (kW) for oil and gas steam plants, $17 per kW for coal plants 

and $22 per kW for nuclear plants (in 2012 dollars). These costs are added to the estimated costs at existing plants regardless 

of their age. Beyond 30 years of age an additional $7 per kW capital charge for fossil plants and $33 per kW charge for nuclear 

plants is included in the retirement decision to reflect further investment to address the impacts of aging. Age-related cost 

increases are attributed to capital expenditures for major repairs or retrofits, decreases in plant performance, and/or increases in 

maintenance costs to mitigate the effects of aging.

EIA assumes all retirements reported as planned during the next ten years on the Form EIA-860 will occur. Additionally, the 

AEO2014 nuclear projection assumes a decrease of 5.7 GW by 2020 in several regions where existing nuclear units appear at 

risk of early closure due to a combination of high operating costs and low electricity prices.

Biomass co-firing

Coal-fired power plants are assumed to co-fire with biomass fuel if it is economical. Co-firing requires a capital investment for 

boiler modifications and fuel handling. This expenditure is assumed to be $285 per kW of biomass capacity. A coal-fired unit 

modified to allow co-firing can generate up to 15% of the total output using biomass fuel, assuming sufficient residue supplies 

are available.

Nuclear uprates

The AEO2014 nuclear power projection assumes capacity increases at existing units. Nuclear plant operators can increase the 

rated capacity at plants through power uprates, which are license amendments that must be approved by the U.S. Nuclear 

Regulatory Commission (NRC). Uprates can vary from small (less than 2%) increases in capacity, which require very little 

capital investment or plant modification, to extended uprates of 15-20%, requiring significant modifications. Recently, several 

companies have canceled previously planned extended uprates due to lower demand projections and low electricity prices 

[3]. AEO2014 assumes that only those uprates reported to EIA as planned modifications on the Form EIA-860 will take place 

in the Reference case, representing 0.7 GW of additional capacity. In the High Nuclear case (discussed in more detail later in 

this chapter), it is assumed that most plants with remaining uprate potential will implement uprates, with a total of 6.0 GW 

throughout the projection.

Interregional electricity trade

Both firm and economy electricity transactions among utilities in different regions are represented within the EMM. In general, 

firm power transactions involve the trading of capacity and energy to help another region satisfy its reserve margin requirement, 

while economy transactions involve energy transactions motivated by the marginal generation costs of different regions. The 

flow of power from region to region is constrained by the existing and planned capacity limits as reported in the NERC and 

Western Electricity Coordinating Council Summer and Winter Assessment of Reliability of Bulk Electricity Supply in North 

America, as well as information obtained from the Open Access Same-Time Information System (OASIS). Known firm power 

contracts are compiled from NERC’s Electricity Supply and Demand Database as well as information provided in the 2013 

Summer and Winter Assessments and individual ISO reports. They are locked in for the term of the contract. Contracts that are

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 101
Electricity Market Module

scheduled to expire by 2018 are assumed not to be renewed. Because there is no information available about expiration 

dates for contracts that go beyond 2018, they are assumed to be phased out linearly over 10 years. The EMM includes an 

option to add interregional transmission capacity. In some cases it may be more economical to build generating capacity in 

a neighboring region, but additional costs to expand the transmission grid will be incurred as well. Explicitly expanding the 

interregional transmission capacity may also make the transmission line available for additional economy trade.

Economy transactions are determined in the dispatching submodule by comparing the marginal generating costs of 

adjacent regions in each time slice. If one region has less expensive generating resources available in a given time period 

(adjusting for transmission losses and transmission capacity limits) than another region, the regions are assumed to 

exchange power.

International electricity trade

Two components of international firm power trade are represented in the EMM—existing and planned transactions, 

and unplanned transactions. Data on existing and planned transactions are compiled from NERC’s Electricity Supply 

and Demand Database and Canada’s National Energy Board. Unplanned firm power trade is represented by competing 

Canadian supply with U.S. domestic supply options. Canadian supply is represented via supply curves using cost data 

from the Department of Energy report, “Northern Lights: The Economic and Practical Potential of Imported Power from 

Canada” (DOE/PE-0079). International economy trade is determined endogenously based on surplus energy expected to 

be available from Canada by region in each time slice. Canadian surplus energy was determined using Canadian electricity 

supply and demand projections from the MAPLE-C model developed for Natural Resources Canada.

Electricity pricing

Electricity pricing is projected for 22 electricity market regions in AEO2014 for fully competitive, partially competitive and 

fully regulated supply regions. The price of electricity to the consumer comprises the price of generation, transmission, 

and distribution, including applicable taxes. Transmission and distribution are considered to remain regulated in the AEO; 

that is, the price of transmission and distribution is based on the average cost to build, operate and maintain these systems 

using a cost of service regulation model. The price of electricity in the regulated regions consists of the average cost of 

generation, transmission, and distribution for each customer class. In the competitive regions, the energy component 

of price is based on marginal cost, which is defined as the cost of the last (or most expensive) unit dispatched. The 

competitive generation price includes the marginal cost (fuel and variable operations and maintenance costs), taxes, and 

a capacity payment. The capacity payment is calculated as a combination of levelized costs for combustion turbines and 

the marginal value of capacity calculated within the EMM. The capacity payment is calculated for all competitive regions 

and should be viewed as a proxy for additional capital recovery that must be procured from customers rather than the 

representation of a specific market. The capacity payment also includes the costs associated with meeting the spinning 

reserves requirement discussed earlier. The total cost for meeting both constraints in a given region is calculated within 

the EMM, and allocated to the sectors based on their contribution to overall peak demand. The price of electricity in the 

regions with a competitive generation market consists of the competitive cost of generation summed with the average 

costs of transmission and distribution. The price for mixed regions reflects a load-weighted average of the competitive 

price and the regulated price, based on the percent of electricity load in the region subject to deregulation. In competitively 

supplied regions, a transition period is assumed to occur (usually over a 10-year period) from the effective date of 

restructuring, with a gradual shift to marginal cost pricing.

The Reference case assumes a transition to full competitive pricing in the three New York regions and in the ReliabilityFirst 

Corporation/East region, and a 97% transition to competitive pricing in New England (Vermont being the only 

fully-regulated state in that region). Six regions fully regulate their electricity supply, including the Florida Reliability 

Coordinating Council, three of the SERC Reliability Corporation subregions - Southeastern (SRSE), Central (SRCE) and 

Virginia-Carolina (SRVC) - Southwest Power Pool Regional Entity/North (SPNO), and the Western Electricity Coordinating 

Council/Rockies (RMPA). The Texas Reliability Entity, which in the past was considered fully competitive by 2010, is 

now only 88% competitive, since many cooperatives have declined to become competitive or allow competitive energy 

to be sold to their customers. California returned to almost fully regulated pricing in 2002, after beginning a transition 

to competition in 1998, with only 7% competitive supply sold currently in the Western Electricity Coordinating Council 

(WECC)/California region. All other regions reflect a mix of both competitive and regulated prices.

102 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Electricity Market Module

There have been ongoing changes to pricing structures for ratepayers in competitive states since the inception of retail 

competition. The AEO has incorporated these changes as they have been incorporated into utility tariffs. These have included 

transition period rate reductions and freezes instituted by various states, and surcharges in California relating to the 2000-

2001 energy crisis in the state. Since price freezes for most customers have ended or will end in the next year or two, a 

large survey of utility tariffs found that many costs related to the transition to competition were now explicitly added to the 

distribution portion and sometimes the transmission portion of the customer bill, regardless of whether or not the customer 

bought generation service from a competitive or regulated supplier. There are some unexpected costs relating to unforeseen 

events. For instance, as a result of volatile fuel markets, state regulators have had a hard time enticing retail suppliers to offer 

competitive supply to residential and smaller commercial and industrial customers. They have often resorted to procuring the 

energy themselves through auction or competitive bids, or have allowed distribution utilities to procure the energy on the open 

market for their customers for a fee.

For AEO2014, typical charges that all customers must pay on the distribution portion of their bill (depending on where they 

reside) include: transition charges (including persistent stranded costs), public benefits charges (usually for efficiency and 

renewable energy programs), administrative costs of energy procurement, and nuclear decommissioning costs. Costs added to 

the transmission portion of the bill include the Federally Mandated Congestion Charges (FMCC), a bill pass-through associated 

with the Federal Energy Regulatory Commission passage of Standard Market Design (SMD) to enhance reliability of the 

transmission grid and control congestion. Additional costs not included in historical data sets have been added in adjustment 

factors to the transmission and distribution operations and maintenance costs, which impact the cost of both competitive and 

regulated electricity supply. Since most of these costs, such as transition costs, are temporary in nature, they are gradually 

phased out throughout the projection. Regions found to have these added costs include the Northeast Power Coordinating 

Council/New England and New York regions, the ReliabilityFirst Corporation/East and West regions, and the WECC/California 

region.

Fuel price expectations 

Capacity planning decisions in the EMM are based on a life cycle cost analysis over a 30-year period. This requires foresight 

assumptions for fuel prices. Expected prices for coal, natural gas and oil are derived using rational expectations, or ‘perfect 

foresight.’ In this approach, expectations for future years are defined by the realized solution values for these years in a prior 

run. The expectations for the world oil price and natural gas wellhead price are set using the resulting prices from a prior run. 

The markups to the delivered fuel prices are calculated based on the markups from the previous year within a NEMS run. Coal 

prices are determined using the same coal supply curves developed in the Coal Market Module. The supply curves produce 

prices at different levels of coal production, as a function of labor productivity, and costs and utilization of mines. Expectations 

for each supply curve are developed in the EMM based on the actual demand changes from the prior run throughout the 

projection horizon, resulting in updated mining utilization and different supply curves.

The perfect foresight approach generates an internally consistent scenario for which the formation of expectations is consistent 

with the projections realized in the model. The NEMS model involves iterative cycling of runs until the expected values and 

realized values for variables converge between cycles.

Nuclear fuel prices

Nuclear fuel prices are calculated through an offline analysis which determines the delivered price to generators in mills per 

kilowatthour. To produce reactor-grade uranium, the uranium (U308) must first be mined, and then sent through a conversion 

process to prepare for enrichment. The enrichment process takes the fuel to a given purity of U-235, typically 3-5% for 

commercial reactors in the United States. Finally, the fabrication process prepares the enriched uranium for use in a specific 

type of reactor core. The price of each of the processes is determined, and the prices are summed to get the final price of the 

delivered fuel. The one mill per kilowatthour charge that is assessed on nuclear generation to go to DOE’s Nuclear Waste Fund 

is also included in the final nuclear price. The analysis uses forecasts from Energy Resources International for the underlying 

uranium prices.

Legislation and regulations

Clean Air Act Amendments of 1990 (CAAA90) and Clean Air Interstate Rule (CAIR)

Currently, regulation of SO2 and NOX emissions is administered under the Clean Air Interstate Rule (CAIR), and AEO2014 

assumes that CAIR remains a binding regulation throughout the projection period. CAIR was initially promulgated in 2005, but 

has been challenged in court several times. The Cross-State Air Pollution Rule (CSAPR) was released by EPA in July 2011 and 

was intended to replace CAIR, but it was vacated by the U.S. Court of Appeals for the District of Columbia Circuit, and CAIR 

was reinstated.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 103
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CAIR covers all fossil-fueled power plants greater than 25 megawatts in 27 states and the District of Columbia. There are annual 

emissions caps for SO2 and NOX and different states fall under each cap, as shown in the map in Figure 7, although all are in the 

eastern half of the United States. The caps for SO2 and NOX were set to allow states to achieve their National Ambient Air Quality 

Standards (NAAQS) for particulate matter (impacted by SO2 levels) and ground level ozone (impacted by NOX). Allowances can 

be traded among all participants in the CAAA90 Title IV program, not just those in CAIR states; however allowances are traded at 

a discount in non-CAIR states. AEO2014 represents emissions trading in both the CAIR and non-CAIR regions, as specified by the 

regulation, and includes banking of allowances consistent with CAIR’s provisions.

As specified in CAAA90, EPA developed a two-phase nitrogen oxide (NOx) program, with the first set of standards for existing 

coal plants applied in 1996 while the second set was implemented in 2000. Dry bottom wall-fired, and tangential-fired boilers, 

the most common boiler types, are referred to as Group 1 Boilers, and were required to make significant reductions beginning 

in 1996 and further reductions in 2000. Relative to their uncontrolled emission rates, which range roughly between 0.6 and 

1.0 pounds per million Btu, they are required to make reductions between 25 and 50% to meet the Phase I limits and further 

reductions to meet the Phase II limits. The EPA did not impose limits on existing oil and gas plants, but some states have 

instituted additional NOx regulations. All new fossil units are required to meet current standards. In pounds per million Btu, these 

limits are 0.11 for conventional coal, 0.02 for advanced coal, 0.02 for combined cycle, and 0.08 for combustion turbines. These 

NOx limits are incorporated in EMM.

Table 8.6 shows the average capital costs for environmental control equipment utilized by NEMS for existing coal plants as 

retrofit options in order to remove sulfur dioxide (SO2), nitrogen oxides (NOx), mercury and/or hydrogen chloride (HCl). In the 

EMM, plant-specific costs are calculated based on the size of the unit and other operating characteristics. The table reflects the 

capacity-weighted averages of all plants falling into each size category. FGD units are assumed to remove 95% of the SO2, while 

SCR units are assumed to remove 90% of the NOx. The EMM also includes an option to install a dry sorbent injection (DSI) 

system, which is assumed to remove 70% of the SO2. However, the DSI option is only available under the mercury and air toxics 

rule discussed in the next section, as its primary benefit is for reducing hydrogen chloride (HCl).

Figure 7. States covered by the Clean Air Interstate Rule

Source: U.S. Environmental Protection Agency, Clean Air Interstate Rule—Where You Live (Washington, DC, July 31, 2012), 

website http://www.epa.gov/cair/where.html.

104 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
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Mercury regulation

The Mercury and Air Toxics Standards (MATS) were finalized in December 2011 to fulfill EPA’s requirement to regulate 

mercury emissions from power plants. MATS also regulates other hazardous air pollutants (HAPS) such as hydrogen chloride 

(HCl) and fine particulate matter (PM2.5). MATS applies to coal- and oil-fired power plants with a nameplate capacity 

greater than 25 megawatts. The standards are scheduled to take effect in 2015, but allow for a one-year waiver to comply, 

and require that all qualifying units achieve the maximum achievable control technology (MACT) for each of the three 

covered pollutants. For AEO2014, EIA assumes that all coal-fired generating units with a capacity greater than 25 megawatts 

will comply with the rule beginning in 2016, due to the large number of plants requesting the one-year extension. All power 

plants are required to reduce their mercury emissions to 90% below their uncontrolled emissions levels.

Because the EMM does not explicitly model HCl or PM2.5, specific control technologies are assumed to be used to achieve 

compliance. In order to meet the HCl requirement, units must have either flue gas desulfurization (FGD) scrubbers or dry 

sorbent injection (DSI) systems in order to continue operating. A full fabric filter (FF) is also required to meet the PM2.5 

limits and to improve the effectiveness of the DSI technology. When plants alter their configuration by adding equipment 

such as an SCR to remove NOx or an SO2 scrubber, removal of mercury is often a resulting cobenefit. The EMM considers 

all combinations of controls and may choose to add NOX or SO2 controls purely to lower mercury if it is economic to do so. 

Plants can also add activated carbon injection systems specifically designed to remove mercury. Activated carbon can be 

injected in front of existing particulate control devices or a supplemental fabric filter can be added with activated carbon 

injection capability.

The equipment to inject activated carbon in front of an existing particulate control device is assumed to cost approximately 

$6 (2012 dollars) per kilowatt of capacity [4]. The costs of a supplemental fabric filter with activated carbon injection (often 

referred as a COPAC unit) are calculated by unit, with average costs shown in Table 8.6. The amount of activated carbon 

required to meet a given percentage removal target is given by the following equations [5].

For a unit with a cold side electrostatic precipitator (CSE), using subbituminous coal, and simple activated carbon injection:

• Hg Removal (%) = 65 - (65.286 / (ACI + 1.026))

For a unit with a CSE, using bituminous coal, and simple activated carbon injection:

• Hg Removal (%) = 100 - (469.379 / (ACI + 7.169))

For a unit with a CSE, and a supplemental fabric filter with activated carbon injection:

• Hg Removal (%) = 100 - (28.049 / (ACI + 0.428))

For a unit with a hot side electrostatic precipitator (HSE) or other particulate control, and a supplemental fabric filter with 

activated carbon injection:

• Hg Removal (%) = 100 - (43.068 / (ACI + 0.421))

ACI = activated carbon injection rate in pounds per million actual cubic feet of flue gas.

Table 8.6. Coal plant retrofit costs

2012 dollars per kW

Coal Plant Size (MW)

FGD Capital Costs ($/

kW)

SCR Capital Costs ($/

kW)

DSI Capital Costs ($/

kW)

FF Capital 

Costs

<100 896 417 189 258

100 - 299 635 270 94 192

300 - 499 502 217 50 163

500 - 699 444 200 37 147

>=700 399 183 31 135

Documentation for EPA Base Case v4.10 using the Integrated Planning Model, August 2010, EPA Contract EP-W-08-018, Appendices to 

Chapter 5.

Power plant mercury emissions assumptions

The EMM represents 35 coal plant configurations and assigns a mercury emissions modification factor (EMF) to each 

configuration. Each configuration represents different combinations of boiler types, particulate control devices, sulfur dioxide 

(SO2) control devices, nitrogen oxide (NOx) control devices, and mercury control devices. An EMF represents the amount of 

mercury that was in the fuel that remains after passing through all the plant’s systems. For example, an EMF of 0.60 means 

that 40% of the mercury that was in the fuel is removed by various parts of the plant. Table 8.7 provides the assumed EMFs 

for existing coal plant configurations without mercury-specific controls.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 105
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Table 8.7. Mercury emission modification factors

Configuration EIA EMFs EPA EMFs

SO2 Control Particulate Control

NOx

Control Bit Coal Sub Coal Lignite Coal Bit Coal Sub Coal Lignite Coal

None BH -- 0.11 0.27 0.27 0.11 0.26 1.00

Wet BH None 0.05 0.27 0.27 0.03 0.27 1.00

Wet BH SCR 0.10 0.27 0.27 0.10 0.15 0.56

Dry BH -- 0.05 0.75 0.75 0.50 0.75 1.00

None CSE -- 0.64 0.97 0.97 0.64 0.97 1.00

Wet CSE None 0.34 0.73 0.73 0.34 0.84 0.56

Wet CSE SCR 0.10 0.73 0.73 0.10 0.34 0.56

Dry CSE -- 0.64 0.65 0.65 0.64 0.65 1.00

None HSE/Oth -- 0.90 0.94 0.94 0.90 0.94 1.00

Wet HSE/Oth None 0.58 0.80 0.80 0.58 0.80 1.00

Wet HSE/Oth SCR 0.42 0.76 0.76 0.10 0.75 1.00

Dry HSE/Oth -- 0.60 0.85 0.85 0.60 0.85 1.00

Notes: SO2 Controls - Wet = Wet Scrubber and Dry = Dry Scrubber, Particulate Controls, BH - fabric filter/baghouse. CSE = cold side electrostatic 

precipitator, HSE = hot side electrostatic precipitator, NOx Controls, SCR = selective catalytic reduction, 

— = not applicable, Bit = bituminous coal, Sub = subbituminous coal. The NOx control system is not assumed to enhance mercury removal unless a wet 

scrubber is present, so it is left blank in such configurations. Sources: EPA, EMFs. www.epa.gov/clearskies/technical.html. EIA EMFs not from EPA: Lignite 

EMFs, Mercury Control Technologies for Coal-Fired Power Plants, presented by the Office of Fossil Energy on July 8, 2003. Bituminous coal mercury removal 

for a Wet/HSE/Oth/SCR configured plant, Table EMF1, Analysis of Mercury Control Cost and Performance, Office of Fossil Energy & National Energy 

Technology Laboratory, U.S. Department of Energy, January 2003, Washington, DC.

Planned SO2 Scrubber and NOx control equipment additions

EIA assumes that all planned retrofits, as reported on the Form EIA-860, will occur as currently scheduled. For AEO2014, this 

includes 16.9 GW of planned SO2 scrubbers (Table 8.8) and 10.2 GW of planned selective catalytic reduction (SCR).

Carbon capture and sequestration retrofits

Although a federal greenhouse gas program is not assumed in the AEO2014 Reference case, the EMM includes the option of 

retrofitting existing coal plants for carbon capture and sequestration (CCS). This option is important when considering alternate 

scenarios that do constrain carbon emissions. The modeling structure for CCS retrofits within the EMM was developed by the 

National Energy Technology Laboratory[6] and uses a generic model of retrofit costs as a function of basic plant characteristics 

(such as heatrate). The costs have been adjusted to be consistent with costs of new CCS technologies. The CCS retrofits are 

assumed to remove 90% of the carbon input. The addition of the CCS equipment results in a capacity derate of around 30% and 

reduced efficiency of 43% at the existing coal plant. The costs depend on the size and efficiency of the plant, with the capital 

costs averaging $1,635 per kilowatt, and ranging from $1,193 to $2,255 per kilowatt. It was assumed that only plants greater than 

500 megawatts and with heat rates below 12,000 Btu per kilowatthour would be considered for CCS retrofits.

State air emissions regulation

AEO2014 continues to model the Northeast Regional Greenhouse Gas Initiative (RGGI), which applies to fossil-fuel powered 

plants over 25 megawatts in the Northeastern United States. The State of New Jersey withdrew from the program at the 

end of 2011, leaving nine states in the accord. The rule caps CO2 emissions from covered electricity generating facilities and 

requires that they account for each ton of CO2 emitted with an allowance purchased at auction. Because the baseline and 

projected emissions were calculated before the economic recession that began in 2008, the actual emissions in the first years 

of the program have been less than the cap, leading to excess allowances and allowance prices at the floor price. As a result, 

in February 2013 program officials announced a tightening of the cap starting in 2014. AEO2014 applies these revised targets, 

which reflect a cap that is 45% of the original target for 2014.

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The California Assembly Bill 32 (AB 32), the Global Warming Solutions Act of 2006, authorized the California Air Resources 

Board (CARB) to set California’s GHG reduction goals for 2020 and establish a comprehensive, multi-year program to reduce 

GHG emissions in California. As one of the major initiatives for AB 32, CARB designed a cap-and-trade program that started 

on January 1, 2012, with the enforceable compliance obligations beginning in 2013 for the electric power sector and industrial 

facilities. Fuel providers must comply starting in 2015. The AB32 cap-and-trade provisions are incorporated in AEO2014 through 

an emission constraint in the EMM that also accounts for the emissions determined by the other sectors. Within the power sector, 

emissions from plants owned by California utilities but located out of state as well as emissions from electricity imports into 

California count toward the emission cap, and estimates of these emissions are included in the EMM constraint. An allowance 

price is calculated and added to fuel prices for the affected sectors. Limited banking and borrowing of allowances as well as 

an allowance reserve and offsets have been modeled, as specified in the Bill, providing some compliance flexibility and cost 

containment.

Table 8.8. Planned SO2 scrubber additions by EMM region

Gigawatts

Texas Reliability Entity 0.0

Florida Reliability Coordinating Council 0.0

Midwest Reliability Council - East 1.5

Midwest Reliability Council - West 2.2

Northeast Power Coordinating Council/New England 0.0

Northeast Power Coordinating Council/NYC-Westchester 0.0

Northeast Power Coordinating Council/Long Island 0.0

Northeast Power Coordinating Council/Upstate 0.0

ReliabilityFirst Corporation/East 0.0

ReliabilityFirst Corporation/Michigan 2.8

ReliabilityFirst Corporation/West 3.7

SERC Reliability Corporation/Delta 0.0

SERC Reliability Corporation/Gateway 2.2

SERC Reliability Corporation/Southeastern 3.6

SERC Reliability Corporation/Central 0.0

SERC Reliability Corporation/Virginia-Carolina 0.0

Southwest Power Pool/North 1.0

Southwest Power Pool/South 0.0

Western Electricity Coordinating Council/Southwest 0.0

Western Electricity Coordinating Council/California 0.0

Western Electricity Coordinating Council/Northwest Power Pool Area 0.0

Western Electricity Coordinating Council/Rockies 0.0

Total 16.9

Source: U.S. Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.”

Energy Policy Acts of 1992 (EPACT92) and 2005 (EPACT05) 

The provisions of EPACT92 include revised licensing procedures for nuclear plants and the creation of exempt wholesale 

generators (EWGs). EPACT92 also implemented a permanent 10% investment tax credit for geothermal and solar facilities, 

and introduced a production tax credit for eligible renewable technologies (subsequently extended and expanded). EPACT05 

provides a 20% investment tax credit for Integrated Coal-Gasification Combined Cycle capacity and a 15% investment tax credit 

for other advanced coal technologies. These credits are limited to 3 GW in both cases. These credits have been fully allocated 

and are not assumed to be available for new, unplanned capacity built within the EMM. EPACT05 also contains a production tax 

credit (PTC) of 1.8 cents (nominal) per kWh for new nuclear capacity beginning operation by 2020. This PTC is specified for the 

first 8 years of operation, is limited to $125 million annually, and is limited to 6 GW of new capacity. However, this credit may be 

shared to additional units if more than 6 GW are under construction by January 1, 2014. EPACT05 extended the PTC for qualifying 

renewable facilities by 2 years, or December 31, 2007. It also repealed the Public Utility Holding Company Act (PUHCA).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 107
Electricity Market Module

Energy Improvement and Extension Act 2008 (EIEA2008) 

EIEA2008 extended the investment tax credit of 30% through 2016 for solar and fuel cell facilities. After 2016, the tax credit for 

solar facilities reverts back to the 10% level set by EPACT92.

American Recovery and Reinvestment Act (ARRA) 

Updated tax credits for Renewables 

ARRA extended the expiration date for the PTC to January 1, 2013, for wind and January 1, 2014, for all other eligible renewable 

resources. In addition, ARRA allows companies to choose an investment tax credit (ITC) of 30% in lieu of the PTC and allows for 

a grant in lieu of this credit to be funded by the U.S. Treasury. For some technologies, such as wind, the full PTC would appear to 

be more valuable than the 30% ITC; however, the difference can be small. Qualitative factors, such as the lack of partners with 

sufficient tax liability, may cause companies to favor the ITC grant option. AEO2014 generally assumes that renewable electricity 

projects will claim the more favorable tax credit or grant option available to them.

Loan guarantees for renewables

ARRA provided $6 billion to pay the cost of guarantees for loans authorized by the Energy Policy Act of 2005. While most 

renewable projects which started construction prior to September 30, 2011 are potentially eligible for these loan guarantees, the 

application and approval of guarantees for specific projects is a highly discretionary process, and has thus far been limited. While 

AEO2014 includes projects that have received loan guarantees under this authority, it does not assume automatic award of the 

loans to potentially eligible technologies.

Support for CCS

ARRA provided $3.4 billion for additional research and development on fossil energy technologies. A portion of this funding 

is expected to be used to fund projects under the Clean Coal Power Initiative program, focusing on projects that capture and 

sequester greenhouse gases. To reflect the impact of this provision, AEO2014 Reference case assumes that an additional 1 GW of 

coal capacity with CCS will be stimulated by 2018.

Smart grid expenditures

ARRA provides $4.5 billion for smart grid demonstration projects. While somewhat difficult to define, smart grid technologies 

generally include a wide array of measurement, communications, and control equipment employed throughout the transmission 

and distribution system that will enable real-time monitoring of the production, flow, and use of power from the generator to the 

consumer. Among other things, these smart grid technologies are expected to enable more efficient use of the transmission and 

distribution grid, lower line losses, facilitate greater use of renewables, and provide information to utilities and their customers 

that will lead to greater investment in energy efficiency and reduced peak load demands. The funds provided will not fund a 

widespread implementation of smart grid technologies, but could stimulate more rapid investment than would otherwise occur.

Several changes were made throughout NEMS to represent the impacts of the smart grid funding provided in ARRA. In the 

electricity module, it was assumed that line losses would fall slightly, peak loads would fall as customers shifted their usage 

patterns, and customers would be more responsive to pricing signals. Historically, line losses, expressed as the percentage of 

electricity lost, have been falling for many years as utilities make investments to replace aging or failing equipment.

Smart grid technologies also have the potential to reduce peak demand through the increased deployment of demand response 

programs. In AEO2014, it is assumed that the Federal expenditures on smart grid technologies will stimulate efforts that reduce 

peak demand from what they otherwise would be, with the amount of total peak load reduction growing from 2.2% initially 

to 3.5% by 2040, although the shifts vary by region. Load is shifted to offpeak hours, so net energy consumed remains largely 

constant.

American Taxpayer Relief Act of 2012 (ATRA)

Passed in January 2012, the impacts of ATRA were included in a side case of AEO2013 and are now reflected in the Reference 

case of AEO2014. ATRA extended the expiration date of the wind production tax credit by one year, and redefined the criteria for 

all qualifying projects to be based on ‘under construction’ by December 31, 2013 rather than placed in service by that same date, 

effectively extending the credit for the length of the typical construction period.

FERC Orders 888 and 889 

FERC issued two related rules (Orders 888 and 889) designed to bring low-cost power to consumers through competition, ensure 

continued reliability in the industry, and provide for open and equitable transmission services by owners of these facilities. 

108 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Electricity Market Module

Specifically, Order 888 requires open access to the transmission grid currently owned and operated by utilities. The transmission 

owners must file nondiscriminatory tariffs that offer other suppliers the same services that the owners provide for themselves.

Order 888 also allows these utilities to recover stranded costs (investments in generating assets that are unrecoverable due to 

consumers selecting another supplier). Order 889 requires utilities to implement standards of conduct and an Open Access SameTime Information System (OASIS) through which utilities and non-utilities can receive information regarding the transmission 

system. As a result, utilities have functionally or physically unbundled their marketing functions from their transmission functions.

These orders are represented in EMM by assuming that all generators in a given region are able to satisfy load requirements 

anywhere within the region. Similarly, it is assumed that transactions between regions will occur if the cost differentials between 

them make such transactions economical.

Electricity alternative cases 

Accelerated Retirement cases

For AEO2014, three alternate cases were run to examine the impacts of potentially large amounts of retirements of baseload coal 

and nuclear plants on the electric power sector. In recent years, a combination of low natural gas prices, high retrofit or repair 

costs and uncertain environmental legislation have led to an increase in announced retirements of coal and nuclear plants.

These scenarios are discussed in an Issues in Focus article in the full AEO2014 report.

• The Accelerated Nuclear Retirement case assumes that reactors will not receive a second license renewal, therefore all existing 

plants are retired within 60 years of operation. Non-fuel operating costs at existing nuclear plants are assumed to increase 

by 3% per year after 2013. The 4.8 GW of announced retirements remain as in the Reference case, along with the decrease 

of 5.7 GW of nuclear capacity by 2020 to reflect plants at risk of early closure in specific regions. In this case an additional 

37.4 GW of nuclear capacity is retired by 2040, relative to the Reference case. The Accelerated Nuclear Retirement case also 

assumes that no new nuclear capacity will be added throughout the projection, with the exception of capacity already under 

construction.

• The Accelerated Coal Retirement case includes the assumptions used for the High Coal Cost case, including lower productivity 

and higher costs associated with mining and transportation rates. (This case is described in more detail in the Coal chapter 

of this report). By 2040, delivered coal prices are more than 60% higher in the Accelerated Coal Retirement case than the 

Reference case. This case also assumes that non-fuel operating costs at existing coal plants increase by 3% per year after 2013.

• The Accelerated Coal and Nuclear Retirement case combines the assumptions of the Accelerated Coal Retirement and 

Accelerated Nuclear Retirement cases.

Nuclear Alternative cases

For AEO2014, two alternate cases were run for nuclear power plants to address uncertainties about the operating lives of existing 

reactors, the potential for new nuclear capacity, and capacity uprates at existing plants. 

• The Low Nuclear case combines the Accelerated Nuclear Retirement case with the High Oil and Gas Resource case and the 

No Sunset case. (All case descriptions can be found in Table 1.1 of this report). This combines more pessimistic assumptions 

regarding nuclear costs and lifetimes with more favorable conditions for natural gas-fired and renewable technologies, so that 

the impacts on the power sector can be viewed under an outlook where output from nuclear power is greatly reduced. 

• The High Nuclear case assumes that all existing nuclear units will receive a second license renewal and operate beyond 60 

years (excluding 4.8 GW of announced retirements). In the Reference case, beyond the announced retirements an additional 

decrease of 5.7 GW of nuclear capacity is assumed to be retired by 2020. The High Nuclear case was run to provide a more 

optimistic outlook where all licenses are renewed and all plants are assumed to find it economic to continue operating beyond 

60 years. The High Nuclear case also assumes additional planned nuclear capacity is completed based on combined license 

(COL) applications with the NRC and whether an Atomic Safety and Licensing Board hearing has been scheduled for a COL. 

The High Nuclear case assumes 12.6 GW of planned capacity additions, as compared with the 5.5 GW of planned capacity 

additions in the Reference case. Finally, the High Nuclear case assumes a total of 6.0 GW of uprates at existing plants, 

reflecting an assumption that most plants with remaining uprate potential will elect to perform such uprates.

Flat Electricity Demand case

For AEO2014, a case was developed combining technology and efficiency improvements across the end use demand sectors to 

create a case that projects retail sales to the grid to be relatively flat at current levels. This case was developed to analyze the 

impacts on the power sector capacity and generation requirements under an extreme scenario of no demand growth. The Flat 

Electricity Demand case uses the assumptions in the Best Available Technology case for the residential and commercial sectors. 

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 109
Electricity Market Module

Flat Electricity Demand case

For AEO2014, a case was developed combining technology and efficiency improvements across the end use demand sectors to 

create a case that projects retail sales to the grid to be relatively flat at current levels. This case was developed to analyze the 

impacts on the power sector capacity and generation requirements under an extreme scenario of no demand growth. The Flat 

Electricity Demand case uses the assumptions in the Best Available Technology case for the residential and commercial sectors. 

Notes and sources

[1] Review of Power Plant Cost and Performance Assumptions for NEMS, Science Applications International Corporation, April 

2013. 

[2] “Exelon Cancels Power Uprates for Lasalle, Limerick,” June 12, 2013, 

http://www.platts.com/latest-news/electric-power/washington/exelon-cancels-power-uprates-for-lasalle-limerick-21152061. 

[3] North American Electric Reliability Corporation, 2013 Summer Reliability Assessment (Atlanta, GA: May 2013), 

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2013SRA_Final.pdf .

[4] These costs were developed using the National Energy Technology Laboratory Mercury Control Performance and Cost Model, 

1998.

[5] U.S. Department of Energy, Analysis of Mercury Control Cost and Performance, Office of Fossil Energy & National

Energy Technology Laboratory, January 2003.

[6] Retrofitting Coal-Fired Power Plants for Carbon Dioxide Capture and Sequestration - Exploratory Testing of NEMS for

Integrated Assessments, DOE/NETL-2008/1309, P.A. Geisbrecht, January 18, 2009.

110 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module
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Oil and Gas Supply Module

The NEMS Oil and Gas Supply Module (OGSM) constitutes a comprehensive framework with which to analyze crude oil and 

natural gas exploration and development on a regional basis (Figure 8). The OGSM is organized into 4 submodules: Onshore 

Lower 48 Oil and Gas Supply Submodule, Offshore Oil and Gas Supply Submodule, Oil Shale Supply Submodule [1], and Alaska 

Oil and Gas Supply Submodule. A detailed description of the OGSM is provided in the EIA publication, Oil and Gas Supply 

Module of the National Energy Modeling System: Model Documentation 2013, DOE/EIA-m063(2013), (Washington, DC, 

2013). The OGSM provides crude oil and natural gas short-term supply parameters to both the Natural Gas Transmission and 

Distribution Module and the Petroleum Market Module. The OGSM simulates the activity of numerous firms that produce oil 

and natural gas from domestic fields throughout the United States.

OGSM encompasses domestic crude oil and natural gas supply by several recovery techniques and sources. Crude oil recovery 

includes improved oil recovery processes such as water flooding, infill drilling, and horizontal drilling, as well as enhanced oil 

recovery processes such as CO2 flooding, steam flooding, and polymer flooding. Recovery from highly fractured, continuous 

zones (e.g. Austin chalk and Bakken shale formations) is also included. Natural gas supply includes resources from lowpermeability tight sand formations, shale formations, coalbed methane, and other sources.

Key assumptions

Domestic oil and natural gas technically recoverable resources

The outlook for domestic crude oil production is highly dependent upon the production profile of individual wells over time, 

the cost of drilling and operating those wells, and the revenues generated by those wells. Every year EIA re-estimates initial 

production (IP) rates and production decline curves, which determine estimated ultimate recovery (EUR) per well and total 

technically recoverable resources (TRR) [2].

Figure 8. Oil and Gas Supply Model regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 113
Oil and Gas Supply Module

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is the remaining 

technically recoverable resource, consisting of proved reserves [3] and unproved resources [4]. Estimates of TRR are highly 

uncertain, particularly in emerging plays where few wells have been drilled. Early estimates tend to vary and shift significantly 

over time as new geological information is gained through additional drilling, as long-term productivity is clarified for existing 

wells, and as the productivity of new wells increases with technology improvements and better management practices. TRR 

estimates used by EIA for each AEO are based on the latest available well production data and on information from other federal 

and state governmental agencies, industry, and academia. Published estimates in Tables 9.1 and 9.2 reflect the removal of 

intervening reserve additions and production between the date of the latest available assessment and January 1, 2012.

The resources presented in the tables in this chapter are the starting values for the model. Technology improvements in the 

model add to the unproved TTR, which can be converted to reserves and finally production. The tables in this chapter do not 

include these increases in TRR.

Table 9.1. Technically recoverable U.S. crude oil resources as of January 1, 2012

billion barrels

Proved Reserves Unproved Resources

Total Technically 

Recoverable Resources

Lower 48 Onshore 20 126 145

 Northeast 0 2 3

 Gulf Coast 3 32 35

 Midcontinent 2 13 15

 Southwest 6 41 48

 Rocky Mountain 5 28 33

 West Coast 3 10 13

Lower 48 Offshore 5 50 55

 Gulf (currently available) 5 37 42

 Eastern/Central Gulf (unavailable until 2022) 0 4 4

 Pacific 1 6 6

 Atlantic 0 2 2

Alaska (Onshore and Offshore) 4 34 38

Total U.S. 29 209 238

Note: Crude oil resources include lease condensates but do not include natural gas plant liquids or kerogen (oil shale). Resources in areas where drilling is 

officially prohibited are not included in this table. The estimate of 7.3 billion barrels of crude oil resources in the Northern Atlantic, Northern and Central Pacific, 

and within a 50-mile buffer off the Mid-and Southern Atlantic OCS is also excluded from the technically recoverable volumes because leasing is not expected in 

these areas by 2040.

Source: Onshore and State Offshore - U.S. Energy Information Administration; Alaska - U.S. Geological Survey (USGS); Federal (Outer Continental Shelf) 

Offshore - Bureau of Ocean Energy Management (formerly the Minerals Management Service); Proved Reserves - U.S. Energy Information Administration. Table 

values reflect removal of intervening reserve additions between the date of the latest available assessment and January 1, 2012.

Table 9.2. Technically recoverable U.S. dry natural gas resources as of January 1, 2012

trillion cubic feet

Proved 

Reserves

Unproved 

Resources

Total Technically 

Recoverable Resources

Lower 48 Onshore Non-Associated Natural Gas 285 1,189 1,474

 Tight Gas 71 365 436

 Northeast 1 37 37

 Gulf Coast 14 167 182

 Midcontinent 7 14 22

 Southwest 9 35 44

 Rocky Mountain 40 111 151

 West Coast 0 0 0

 Shale Gas 122 489 611

 Northeast 32 221 253

 Gulf Coast 31 138 169

 Midcontinent 26 48 74

 Southwest 34 35 68

 Rocky Mountain 0 35 35

 West Coast 0 12 12

114 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

Table 9.2. Technically recoverable U.S. dry natural gas resources as of January 1, 2012 (cont.)

trillion cubic feet

Proved 

Reserves

Unproved 

Resources

Total Technically 

Recoverable 

Resources

 Coalbed Methane 17 120 136

 Northeast 2 4 6

 Gulf Coast 1 2 3

 Midcontinent 1 38 39

 Southwest 1 6 6

 Rocky Mountain 13 59 72

 West Coast 0 10 10

 Other 75 216 291

 Northeast 11 29 40

 Gulf Coast 18 101 119

 Midcontinent 19 25 44

 Southwest 4 32 36

 Rocky Mountain 22 17 40

 West Coast 1 12 12

Lower 48 Onshore Associated-Dissolved Gas 27 162 189

 Northeast 0 1 2

 Gulf Coast 3 32 35

 Midcontinent 3 11 15

 Southwest 11 60 72

 Rocky Mountain 6 49 55

 West Coast 2 8 11

Lower 48 Offshore 13 309 322

 Gulf (currently available) 12 255 267

 Eastern/Central Gulf (unavailable until 2022) 0 21 21

 Pacific 1 9 10

 Atlantic 0 24 24

Alaska (Onshore and Offshore) 10 271 281

Total U.S. 334 1,932 2,266

Note: Resources in other areas where drilling is officially prohibited are not included. The estimate of 32.9 trillion cubic feet of natural gas resources in the 

Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the Mid-and Southern Atlantic OCS is also excluded from the technically 

recoverable volumes because leasing is not expected in these areas by 2040. 

Source: Onshore and State Offshore - U.S. Energy Information Administration; Alaska - U.S. Geological Survey (USGS); Federal (Outer Continental Shelf) 

Offshore - Bureau of Ocean Energy Management (formerly the Minerals Management Service); Proved Reserves - U.S. Energy Information Administration. Table 

values reflect removal of intervening reserve additions between the date of the latest available assessment and January 1, 2012.

The remaining unproved TRR for a continuous-type shale gas or tight oil area is the product of (1) area with potential, (2) well 

spacing (wells per square mile), and (3) EUR per well. The play-level unproved technically recoverable resource assumptions 

for tight oil, shale gas, tight gas, and coalbed methane are summarized in Tables 9.3-9.4. The model uses a distribution of EUR 

per well in each play and often in sub-play areas. Table 9.5 provides an example of the distribution of EUR per well for each 

of the Bakken areas. The Bakken is subdivided into five areas: Central Basin, Eastern Transitional, Elm Coulee-Billings Nose, 

Nesson-Little Knife, and Northwest Transitional [5]. Because of the significant variation in well productivity within an area, the 

wells in each Bakken area are further delineated by county. This level of detail is provided for select plays in Appendix 2.C of 

the AEO2014 Documentation for the OGSM. The USGS periodically publishes tight and shale resource assessments that are 

used as a guide for selection of key parameters in the calculation of the TRR used in the AEO. The USGS seeks to assess the 

recoverability of shale gas and tight oil based on the wells drilled and technologies deployed at the time of the assessment.

The AEO TRRs incorporate current drilling, completion, and recovery techniques, requiring adjustments to some of the 

assumptions used by the USGS to generate their TRR estimates, as well as the inclusion of shale gas and tight oil resources not 

yet assessed by the USGS. If well production data are available, EIA analyzes the decline curve of producing wells to calculate 

the expected EUR per well from future drilling.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 115
Oil and Gas Supply Module

The underlying resource for the Reference case is uncertain, particularly as exploration and development of tight oil continues to 

move into areas with little to no production history. Many wells drilled in tight or shale formations using the latest technologies 

have less than two years of production history so the impact of recent technological advancement on the estimate of future 

recovery cannot be fully ascertained. Uncertainty also extends to areal extent of formations and the number of layers that could be 

drilled within formations. Two alternative resource cases are discussed at the end of this chapter.

Focus on Monterey/Santos play resources

While technically recoverable resources (TRR) is a useful concept, changes in play-level TRR estimates do not necessarily have 

significant implications for projected oil and natural gas production, which are heavily influenced by economic considerations that 

do not enter into the estimation of TRR. Importantly, projected oil production from the Monterey play is not a material part of the 

U.S. oil production outlook in either AEO2013 or AEO2014, and was largely unaffected by the change in TRR estimates between 

the 2013 and 2014 editions of the AEO. EIA estimates U.S. total crude oil production averaged 8.3 million barrels/day in April 

2014. In the AEO2014 Reference case, economically recoverable oil from the Monterey averaged 57,000 barrels/day between 

2010 and 2040, and in the AEO2013 the same play’s estimated production averaged 14,000 barrels/day. The difference in 

production between the AEO2013 and AEO2014 is a result of data updates for currently producing wells which were not previously 

linked to the Monterey play and include both conventionally-reservoired and continuous-type shale areas of the play. Clearly, 

there is not a proportional relationship between TRR and production estimates – economics matters, and the Monterey play faces 

significant economic challenges regardless of the TRR estimate.

This year EIA’s estimate for total proved and unproved U.S. technically recoverable oil resources increased 5.4 billion barrels to 

238 billion barrels, even with a reduction of the Monterey/Santos shale play estimate of unproved technically recoverable tight oil 

resources from 13.7 billion barrels to 0.6 billion barrels. Proved reserves in EIA’s U.S. Crude Oil and Natural Gas Proved Reserves 

report for the Monterey/Santos shale play are withheld to avoid disclosure of individual company data. However, estimates of 

proved reserves in NEMS are 0.4 billion barrels, which result in 1 billion barrels of total TRR.

Key factors driving the adjustment included new geology information from a U. S. Geological Survey review of the Monterey shale 

and a lack of production growth relative to other shale plays like the Bakken and Eagle Ford. Geologically, the thermally mature 

area is 90% smaller than previously thought and is in a tectonically active area which has created significant natural fractures that 

have allowed oil to leave the source rock and accumulate in the overlying conventional oil fields, such as Elk Hills, Cat Canyon and 

Elwood South (offshore). Data also indicate the Monterey play is not over pressured and thus lacks the gas drive found in highly 

productive tight oil plays like the Bakken and Eagle Ford. The number of wells per square mile was revised down from 16 to 6 to 

represent horizontal wells instead of vertical wells. TRR estimates will likely continue to evolve over time as technology advances, 

and as additional geologic information and results from drilling activity provide a basis for further updates.

Lower 48 onshore

The Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) is a play-level model used to analyze crude oil and natural 

gas supply from onshore lower 48 sources. The methodology includes a comprehensive assessment method for determining 

the relative economics of various prospects based on financial considerations, the nature of the resource, and the available 

technologies. The general methodology relies on a detailed economic analysis of potential projects in known fields, enhanced oil 

recovery projects, and undiscovered resources. The projects which are economically viable are developed subject to the availability 

of resource development constraints which simulate the existing and expected infrastructure of the oil and gas industries. For 

crude oil projects, advanced secondary or improved oil recovery techniques (e.g. infill drilling and horizontal drilling) and enhanced 

oil recovery (e.g. CO2 flooding, steam flooding, and polymer flooding) processes are explicitly represented. For natural gas projects, 

the OLOGSS represents supply from shale formations, tight sands formations, coalbed methane, and other sources.

The OLOGSS evaluates the economics of future crude oil and natural gas exploration and development from the perspective of 

an operator making an investment decision. An important aspect of the economic calculation concerns the tax treatment. Tax 

provisions vary with the type of producer (major, large independent, or small independent). For AEO2014, the economics of 

potential projects reflect the tax treatment provided by current laws for large independent producers. Relevant tax provisions are 

assumed unchanged over the life of the investment. Costs are assumed constant over the investment life but vary across region, 

fuel, and process type. Operating losses incurred in the initial investment period are carried forward and used against revenues 

generated by the project in later years.

116 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

Table 9.3. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of January 1, 2012)

Average EUR

Technically Recoverable 

Resources

Region Basin Play

Area with 

Potential1

(mi2)

Average 

Well 

Spacing 

(wells/

mi2)

Crude Oil2

(MMbbl/

well)

Natural 

Gas 

(Bcf/well)

Crude Oil 

(Bbbls)

Dry Natural 

Gas 

(Tcf)

NGPL

(Bbls)

1-East Appalachian Clinton-Medina 24,298 8.0 0.002 0.060 0.5 11.7 0.0

1-East Appalachian Devonian 46,109 7.6 0.000 0.058 0.0 20.8 0.3

1-East Appalachian Marcellus Foldbelt 869 4.3 0.000 0.315 0.0 1.2 0.0

1-East Appalachian Marcellus Interior 16,688 4.3 0.001 1.589 0.0 113.9 3.1

1-East Appalachian Marcellus Western 2,684 5.5 0.000 0.257 0.0 3.8 0.2

1-East Appalachian Tuscarora 255 8.0 0.000 2.172 0.0 4.4 0.0

1-East Appalachian Utica-Gas Zone Core 11,407 4.3 0.000 0.602 0.0 29.3 0.1

1-East Appalachian Utica-Gas Zone Extension 15,089 4.3 0.000 0.125 0.0 8.1 0.0

1-East Appalachian Utica-Oil Zone Core 2,303 2.6 0.094 0.081 0.6 0.5 0.0

1-East Appalachian Utica-Oil-Zone Extension 3,861 2.6 0.041 0.041 0.4 0.4 0.0

1-East Illinois New Albany 3,028 8.0 0.000 1.721 0.0 41.7 7.5

1-East Michigan Antrim Shale 12,178 8.0 0.000 0.157 0.0 15.3 2.8

1-East Michigan Berea Sand 7,116 8.0 0.000 0.143 0.0 8.1 0.1

2-Gulf Coast Black Warrior Floyd-Neal/Conasauga 1,402 2.0 0.000 1.520 0.0 4.3 0.0

2-Gulf Coast TX-LA-MS Salt Cotton Valley 8,645 12.0 0.009 1.472 0.9 152.7 0.0

2-Gulf Coast TX-LA-MS Salt Haynesville-Bossier-LA 1,895 6.0 0.001 3.709 0.0 42.2 0.0

2-Gulf Coast TX-LA-MS Salt Haynesville-Bossier-LA 1,524 6.0 0.001 3.138 0.0 28.7 0.0

2-Gulf Coast Western Gulf Austin Chalk-Giddings 2,573 8.0 0.051 0.050 1.0 1.0 0.1

2-Gulf Coast Western Gulf Austin Chalk-Giddings 10,025 7.1 0.095 0.048 6.6 3.3 0.2

2-Gulf Coast Western Gulf Buda 8,669 4.0 0.106 0.070 3.7 2.4 0.0

2-Gulf Coast Western Gulf Eagle Ford-Dry Zone 2,172 6.0 0.097 1.786 1.3 23.3 0.0

2-Gulf Coast Western Gulf Eagle Ford-Oil Zone 5,423 6.0 0.101 0.212 3.3 6.9 0.1

2-Gulf Coast Western Gulf Eagle Ford-Wet Zone 3,569 6.0 0.223 1.405 4.8 30.1 0.6

2-Gulf Coast Western Gulf Olmos 5,404 4.0 0.006 1.093 0.1 23.6 0.0

2-Gulf Coast Western Gulf Pearsall 1,196 6.0 0.000 1.090 0.0 7.8 0.0

2-Gulf Coast Western Gulf Tuscaloosa 7,171 4.0 0.102 0.019 2.9 0.6 0.0

2-Gulf Coast Western Gulf Vicksburg 329 8.0 0.016 1.473 0.0 3.9 0.1

2-Gulf Coast Western Gulf Wilcox Lobo 897 8.0 0.000 1.404 0.0 10.1 0.3

2-Gulf Coast Western Gulf Woodbine 1,357 4.0 0.104 0.054 0.6 0.3 0.0

3-Midcontinent Anadarko Cana Woodford-Dry Zone 771 4.0 0.004 1.309 0.0 4.0 0.0

3-Midcontinent Anadarko Cana Woodford-Oil Zone 459 6.0 0.033 0.415 0.1 1.1 0.0

3-Midcontinent Anadarko Cana Woodford-Wet Zone 1,039 4.0 0.018 1.175 0.1 4.9 0.4

3-Midcontinent Anadarko Cleveland 667 4.0 0.046 0.394 0.1 1.1 0.0

3-Midcontinent Anadarko Granite Wash 3,234 4.0 0.043 0.948 0.6 12.3 0.7

3-Midcontinent Anadarko Red Fork 432 4.0 0.007 0.593 0.0 1.0 0.1

3-Midcontinent Arkoma Caney 797 4.0 0.000 0.330 0.0 1.1 0.0

3-Midcontinent Arkoma Fayetteville-Central 2,132 8.0 0.000 1.444 0.0 24.6 0.0

3-Midcontinent Arkoma Fayetteville-West 772 8.0 0.000 0.843 0.0 5.2 0.0

3-Midcontinent Arkoma Woodford-Arkoma 592 8.0 0.002 1.422 0.0 6.7 0.6

3-Midcontinent Black Warrior Chattanooga 204 8.0 0.000 0.970 0.0 1.6 0.0

4-Southwest Fort Worth Barnett-Core 383 8.0 0.001 1.615 0.0 5.0 0.2

4-Southwest Fort Worth Barnett-North 1,604 8.0 0.002 0.627 0.0 8.0 0.3

4-Southwest Fort Worth Barnett-South 4,738 8.0 0.001 0.192 0.0 7.3 0.3

4-Southwest Permian Abo 2,518 4.0 0.001 0.182 1.0 1.8 0.1

4-Southwest Permian Avalon/BoneSpring 6,221 4.0 0.080 0.000 2.0 0.0 0.0

4-Southwest Permian Barnett-Woodford 2,616 4.0 0.002 1.513 0.0 15.8 2.2

4-Southwest Permian Canyon 6,519 8.0 0.001 0.209 0.1 10.9 0.0

4-Southwest Permian Spraberry 12,530 6.0 0.108 0.113 8.1 8.5 0.8

4-Southweest Permian Wolfcamp 12,588 4.0 0.068 0.217 3.4 10.9 0.9

5-Rocky Mountain Denver Muddy 3,945 16.0 0.000 0.182 0.0 11.5 0.0

5-Rocky Mountain Denver Niobrara 7,463 5.0 0.012 0.073 0.4 2.7 0.1

5-Rocky Mountain Greater Green River Hilliard-Baxter-Mancos 4,472 8.0 0.000 0.293 0.0 10.5 0.5

5-Rocky Mountain Greater Green River Tight Oil Plays 1,366 5.8 0.112 0.015 0.9 0.1 0.0

5-Rocky Mountain Montana Thrust Belt Tight Oil Plays 2,401 2.3 0.111 0.075 0.6 0.4 0.0

5-Rocky Mountain North Central Montana Bowdoin-greenhorn 461 4.0 0.000 0.151 0.0 0.3 0.0

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 117
Oil and Gas Supply Module

Table 9.3. U.S. unproved technically recoverable tight/shale oil and gas resources by play (as of January 1, 2012) (cont.)

Average EUR

Technically Recoverable 

Resources

Region Basin Play

Area with 

Potential1

(mi2)

Average 

Well 

Spacing 

(wells/

mi2)

Crude Oil2

(MMbbl/

well)

Natural 

Gas 

(Bcf/well)

Crude Oil 

(Bbbl)

Dry Natural 

Gas 

(Tcf)

NGPL

(Bbbl)

5-Rocky Mountain Paradox Fractured Interbed 1,171 1.6 0.543 0.434 1.0 0.8 0.0

5-Rocky Mountain Powder River Tight Oil Plays 19,684 3.0 0.035 0.040 2.1 2.4 0.1

5-Rocky Mountain San Juan Dakota 1,826 8.0 0.000 0.416 0.0 6.1 0.0

5-Rocky Mountain San Juan Lewis 1,481 3.0 0.000 2.200 0.0 9.8 0.0

5-Rocky Mountain San Juan Mesaverde 1,039 12.0 0.002 0.464 0.0 5.8 0.0

5-Rocky Mountain San Juan Pictured Cliffs 101 4.0 0.000 0.397 0.0 0.2 0.0

5-Rocky Mountain Southwestern Wyoming Fort Union-Fox Hills 1,889 8.0 0.003 1.047 0.0 15.8 0.0

5-Rocky Mountain Southwestern Wyoming Frontier 2,828 8.0 0.009 0.273 0.2 6.2 0.0

5-Rocky Mountain Southwestern Wyoming Lance 2,316 8.0 0.015 1.012 0.3 18.7 3.4

5-Rocky Mountain Southwestern Wyoming Lewis 3,893 8.0 0.000 0.248 0.0 7.7 0.2

5-Rocky Mountain Southwestern Wyoming Tight Oil Plays 1,669 5.8 0.111 0.015 1.1 0.1 0.0

5-Rocky Mountain Uinta-Piceance Iles-Mesaverde 4,264 8.0 0.000 0.502 0.0 17.1 0.0

5-Rocky Mountain Uinta-Piceance Mancos 1,543 8.0 0.000 0.880 0.0 10.9 0.0

5-Rocky Mountain Uinta-Piceance Tight Oil Plays 85 16.0 0.050 0.111 0.1 0.2 0.0

5-Rocky Mountain Uinta-Piceance Wasatch-Mesaverde 2,208 8.0 0.025 0.463 0.4 8.2 0.0

5-Rocky Mountain Uinta-Piceance Williams Fork 1,674 10.0 0.001 0.456 0.0 7.6 0.0

5-Rocky Mountain Williston Bakken Central 4,215 2.0 0.131 0.112 1.1 0.9 0.1

5-Rocky Mountain Williston Bakken Eastern 2,629 2.0 0.212 0.102 1.1 0.5 0.0

5-Rocky Mountain Williston Bakken Elm Coulee-Billings 1,946 2.0 0.130 0.090 0.5 0.4 0.0

5-Rocky Mountain Williston Bakken Nesson-Little Knife 2,935 2.0 0.202 0.169 1.2 1.0 0.1

5-Rocky Mountain Williston Bakken Northwest 2,869 2.0 0.063 0.019 0.4 0.1 0.0

5-Rocky Mountain Williston Bakken Three Forks 17,652 2.5 0.133 0.092 5.0 3.4 0.3

5-Rocky Mountain Williston Gammon 3,836 2.0 0.000 0.440 0.0 3.4 0.0

5-Rocky Mountain Williston Judith River-Eagle 1,582 4.0 0.000 0.158 0.0 1.0 0.0

5-Rocky Mountain Wind River Mesaverde/Frontier Shallow 713 8.0 0.008 0.768 0.0 4.4 0.2

6-West Coast Columbia Basin Centered 1,091 8.0 0.000 1.400 0.0 12.2 0.0

6-West Coast San Joaquin/Los Angeles Monterey/Santos 192 6.4 0.451 0.502 0.6 0.6 0.0

Total Tight/Shale 59.2 903.2 27.6

EUR = estimated ultimate recovery; NGPL=Natural Gas Plant Liquids

1

 Area of play that is expected to have unproved technically recoverable resources remaining.

2

 Includes lease condensates..

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.4. U.S. unproved technically recoverable coalbed methane resources by play (as of January 1, 2012)

Region Basin Play

Average EUR Technically Recoverable Resources

Area with 

Potential 1

(mi2)

Average Well 

Spacing 

(wells/mi2)

Crude Oil2

(MMbbl/well)

Natural Gas 

(Tcf/well)

Crude Oil 

(Bbbl)

Natural 

Gas (Tcf)

NGPL 

(Bbbl)

1-East Appalachian Central Basin 1,302 8 0.000 0.176 0.0 1.8 0.0

1-East Appalachian North Appalachian Basin - High 361 12 0.000 0.125 0.0 0.5 0.0

1-East Appalachian North Appalachian Basin - Mid Low 493 12 0.000 0.080 0.0 0.5 0.0

1-East Illinois Central Basin 1,277 8 0.000 0.120 0.0 1.2 0.0

2-Gulf Coast Black Warrior Extention Area 148 8 0.000 0.080 0.0 0.1 0.0

2-Gulf Coast Black Warrior Main Area 694 12 0.000 0.206 0.0 1.7 0.0

2-Gulf Coast Cahaba Cahaba Coal Field 264 8 0.000 0.179 0.0 0.4 0.0

3-Midcontinent Forest City Central Basin 23,110 8 0.022 0.172 4.0 31.8 0.0

3-Midcontinent Midcontinent Arkoma 2,718 8 0.000 0.216 0.0 4.7 0.0

3-Midcontinent Midcontinent Cherokee 3,436 8 0.000 0.065 0.0 1.8 0.0

4-Southwest Raton Southern 1,925 8 0.000 0.375 0.0 5.8 0.0

5-Rocky Mountain Greater Green River Deep 1,620 4 0.000 0.600 0.0 3.9 0.0

5-Rocky Mountain Greater Green River Shallow 644 8 0.000 0.204 0.0 1.1 0.0

5-Rocky Mountain Piceance Deep 1,534 4 0.000 0.600 0.0 3.7 0.0

5-Rocky Mountain Piceance Divide Creek 135 8 0.000 0.179 0.0 0.2 0.0

5-Rocky Mountain Piceance Shallow 1,865 4 0.000 0.299 0.0 2.2 0.0

5-Rocky Mountain Piceance White River Dome 201 8 0.000 0.410 0.0 0.7 0.0

5-Rocky Mountain Powder River Big George/Lower fort Union 1,570 16 0.000 0.260 0.0 6.5 0.0

5-Rocky Mountain Powder River Wasatch 206 8 0.000 0.056 0.0 0.1 0.0

5-Rocky Mountain Powder River Wyodak/Upper Fort Union 6,162 20 0.000 0.136 0.0 16.8 0.0

118 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

Table 9.4. U.S. unproved technically recoverable coalbed methane resources by play (as of January 1, 2012) (cont.)

Region Basin Play

Average EUR Technically Recoverable Resources

Area with 

Potential 1

(mi2)

Average Well 

Spacing 

(wells/mi2)

Crude Oil2

(MMbbl/

well)

Natural Gas 

(Tcf/well)

Crude Oil 

(Bbbl)

Natural 

Gas (Tcf)

NGPL 

(Bbbl)

5-Rocky Mountain Raton Northern 343 8 0.000 0.350 0.0 1.0 0.0

5-Rocky Mountain Raton Purgatoire River 174 8 0.000 0.311 0.0 0.4 0.0

5-Rocky Mountain San Juan Fairway NM 169 4 0.000 1.142 0.0 0.8 0.0

5-Rocky Mountain San Juan North Basin 1,353 4 0.000 0.280 0.0 1.5 0.0

5-Rocky Mountain San Juan North Basin CO 1,673 4 0.000 1.515 0.0 10.1 0.0

5-Rocky Mountain San Juan South Basin 1,030 4 0.000 0.199 0.0 0.8 0.0

5-Rocky Mountain San Juan South Menefee NM 373 5 0.000 0.095 0.0 0.2 0.0

5-Rocky Mountain Uinta Ferron 227 8 0.000 0.776 0.0 1.4 0.0

5-Rocky Mountain Uinta Sego 341 4 0.000 0.306 0.0 0.4 0.0

5-Rocky Mountain Wind River Mesaverde 416 2 0.000 2.051 0.0 1.7 0.0

5-Rocky Mountain Wyoming Thrust Belt All Plays 5.200 2 0.000 0.454 0.0 5.4 0.0

6-West Coast Western Washington Bellingham 441 2 0.000 2.391 0.0 2.1 0.0

6-West Coast Western Washington Southern Puget Lowlands 1.102 2 0.000 0.687 0.0 1.5 0.0

6-West Coast Western Washington Western Cascade Mountains 2.152 2 0.000 1.559 0.0 6.7 0.0

Total Coalbed Methane 4.0 119.5 0.0

EUR = estimated ultimate recovery; NGPL = Natural Gas Plant Liquids.

1

 Area of play that is expected to have unproved technically recoverable resources remaining. 

2

 Includes lease condensates. 

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.5. Distribution of crude oil EURs in the Bakken

Play Name State County

Number of 

potential wells

EUR

(Mbbl/well)

Bakken Central Basin MT Daniels 112 73

Bakken Central Basin MT McCone 313 73

Bakken Central Basin MT Richland 2,967 84

Bakken Central Basin MT Roosevelt 673 74

Bakken Central Basin MT Sheridan 443 29

Bakken Central Basin ND Divide 11 176

Bakken Central Basin ND Dunn 72 224

Bakken Central Basin ND McKenzie 2,182 203

Bakken Central Basin ND Williams 1,657 181

Bakken Eastern Transitional ND Burke 1,379 100

Bakken Eastern Transitional ND Divide 586 130

Bakken Eastern Transitional ND Dunn 1,050 286

Bakken Eastern Transitional ND Hettinger 4 256

Bakken Eastern Transitional ND McLean 507 194

Bakken Eastern Transitional ND Mercer 135 13

Bakken Eastern Transitional ND Mountrail 1,346 327

Bakken Eastern Transitional ND Stark 194 256

Bakken Eastern Transitional ND Ward 57 188

Bakken Elm Coulee-Billings Nose MT McCone 67 132

Bakken Elm Coulee-Billings Nose MT Richland 1,704 148

Bakken Elm Coulee-Billings Nose ND Billings 772 62

Bakken Elm Coulee-Billings Nose ND Golden Valley 125 239

Bakken Elm Coulee-Billings Nose ND McKenzie 1,224 136

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 119
Oil and Gas Supply Module

Table 9.5. Distribution of crude oil EURs in the Bakken (cont.)

Play Name State County

Number of 

potential wells

EUR

(Mbbl/well)

Bakken Nesson-Little Knife ND Billings 578 86

Bakken Nesson-Little Knife ND Burke 319 152

Bakken Nesson-Little Knife ND Divide 572 115

Bakken Nesson-Little Knife ND Dunn 1,245 261

Bakken Nesson-Little Knife ND Hettinger 55 235

Bakken Nesson-Little Knife ND McKenzie 786 299

Bakken Nesson-Little Knife ND Mountrail 304 340

Bakken Nesson-Little Knife ND Slope 86 235

Bakken Nesson-Little Knife ND Stark 1,048 129

Bakken Nesson-Little Knife ND Williams 876 215

Bakken Northwest Transitional MT Daniels 1,550 50

Bakken Northwest Transitional MT McCone 97 50

Bakken Northwest Transitional MT Roosevelt 787 50

Bakken Northwest Transitional MT Sheridan 1,716 50

Bakken Northwest Transitional MT Valley 604 50

Bakken Northwest Transitional ND Divide 627 95

Bakken Northwest Transitional ND Williams 356 141

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Technology advances, including improved drilling and completion practices, as well as advanced production and processing 

operations, are explicitly modeled to determine the direct impacts on supply, reserves, and various economic parameters. The 

success of the technology program is measured by estimating the probability that the technology development program will be 

successfully completed. It reflects the pace at which technology performance improves and the probability that the technology 

project will meet the program goals. There are four possible curves which represent the adoption of the technology: convex, 

concave, sigmoid/logistic and linear. The convex curve corresponds to rapid initial market penetration followed by slow market 

penetration. The concave curve corresponds to slow initial market penetration followed by rapid market penetration. The 

sigmoid/ logistic curve represents a slow initial adoption rate followed by rapid increase in adoption and then slow adoption 

again as the market becomes saturated. The linear curve represents a constant rate of market penetration, and may be used 

when no other predictions can be made.

The market penetration curve is a function of the relative economic attractiveness of the technology instead of being a timedependent function. A technology will not be implemented unless the benefits through increased production or cost reductions 

are greater than the cost to apply the technology. As a result, the market penetration curve provides a limiting value on 

commercialization instead of a specific penetration path. In addition to the curve, the implementation probability captures the 

fact that not all technologies that have been proven in the lab are able to be successfully implemented in the field.

CO2 enhanced oil recovery

For CO2 miscible flooding, the OLOGSS incorporates both industrial and natural sources of CO2. The industrial sources of CO2

are:

•	 Hydrogen plants

•	 Ammonia plants

•	 Ethanol plants

•	 Cement plants

•	 Refineries (hydrogen)

•	 Fossil fuel power plants

•	 Natural gas processing

•	 Coal/biomass to liquids (CBTL)

The CO2 available from fossil fuel power plants and CBTL, as well as the cost of the CO2, are determined in the Electricity 

Market Module and the Liquid Fuels Market Module, respectively. Technology and market constraints prevent the total volumes 

of CO2 from the other industrial sources (Table 9.6) from becoming immediately available. The development of the CO2 market 

is divided into two periods: 1) development phase and 2) market acceptance phase. During the development phase, the required 

capture equipment is developed, pipelines and compressors are constructed, and no CO2 is available. During the market 

120 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

acceptance phase, the capture technology is being widely implemented and volumes of CO2 first become available. The number 

of years in each development period is shown in Table 9.7. CO2 is available from planned Carbon Sequestration and Storage (CSS) 

power plants funded by American Recovery and Reinvestment Act of 2009 (ARRA) starting in 2016.

Table 9.6. Maximum volume of CO2 available

OGSM Region Natural Hydrogen Ammonia Ethanol Cement

Refineries 

(hydrogen)

Natural Gas 

Processing

East 0 3 0 52 94 17 23

Gulf Coast 292 0 78 0 86 114 114

Midcontinent 16 0 0 175 48 1 0

Southwest 657 0 0 68 74 0 0

Rocky Mountains 80 0 3 23 35 78 18

West Coast 0 0 0 4 48 93 40

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.7. CO2 availability assumptions

Source Type Development Phase (years) Market Acceptance Phase (years) Ultimate Market Acceptance

Natural 1 10 100%

Hydrogen 4 10 100%

Ammonia 2 10 100%

Ethanol 4 10 100%

Cement 7 10 100%

Refineries (hydrogen) 4 10 100%

Natural Gas Processing 2 10 100%

Source: U.S. Energy Information Administration, Office of Energy Analysis.

The cost of CO2 from natural sources is a function of the oil price. For industrial sources of CO2, the cost to the producer includes 

the cost to capture, compress to pipeline pressure, and transport to the project site via pipeline within the region (Table 9.8). Interregional transportation costs add $0.40 per Mcf for every region crossed.

Table 9.8. Industrial CO2 capture and transportation costs by region

$/Mcf

OGSM Region Hydrogen Ammonia Ethanol Cement Refineries (hydrogen) Natural Gas Processing

East $2.44 $2.10 $2.23 $4.29 $2.44 $1.92

Gulf Coast $1.94 $2.10 $2.23 $4.29 $1.94 $1.92

Midcontinent $2.07 $2.10 $2.23 $4.29 $2.07 $1.92

Southwest $2.02 $2.10 $2.23 $4.29 $2.02 $1.92

Rocky Mountains $2.03 $2.10 $2.23 $4.29 $2.03 $1.92

West Coast $2.01 $2.10 $2.23 $4.29 $2.01 $1.92

Source: U.S. Energy Information Administration. Office of Energy Analysis.

Lower 48 offshore

Most of the Lower 48 offshore oil and gas production comes from the deepwater of the Gulf of Mexico (GOM). Production from 

currently producing fields and industry-announced discoveries largely determines the short-term oil and natural gas production 

projection.

For currently producing fields, a 20% exponential decline is assumed for production except for natural gas production from fields 

in shallow water, which uses a 30% exponential decline. Fields that began production after 2008 are assumed to remain at their 

peak production level for 2 years before declining.

The assumed field size and year of initial production of the major announced deepwater discoveries that were not brought into 

production by 2012 are shown in Table 9.9. A field that is announced as an oil field is assumed to be 100% oil and a field that is 

announced as a gas field is assumed to be 100% gas. If a field is expected to produce both oil and gas, 70% is assumed to be oil 

and 30% is assumed to be gas.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 121
Oil and Gas Supply Module

Production is assumed to:

•	 ramp up to a peak level in 2 to 4 years depending on the size of the field,

•	 remain at the peak level until the ratio of cumulative production to initial resource reaches 20% for oil and 30% for natural gas, 

and

•	 then decline at an exponential rate of 20-30%.

The discovery of new fields (based on BOEM’S field size distribution) is assumed to follow historical patterns. Production 

from these fields is assumed to follow the same profile as the announced discoveries (as described in the previous paragraph). 

Advances in technology for the various activities associated with crude oil and natural gas exploration, development, and 

production can have a profound impact on the costs associated with these activities. The specific technology levers and values 

for the offshore are presented in Table 9.10.

Leasing is assumed to be available in 2018 in the Mid-and South Atlantic, in 2023 in the South Pacific, and after 2035 in the 

North Atlantic, Florida straits, Pacific Northwest, and North and Central California.

Table 9.9. Assumed size and initial production year of major announced deepwater discoveries

Field/Project Name Block

Water Depth 

(feet) Year of Discovery Field Size Class

Field Size 

(MMBOE)

Start Year of 

Production

Gotcha AC865 7,844 2006 13 182 2014

Axe DC004 5,831 2010 12 89 2015

Dalmation DC048 5,876 2008 12 89 2015

Vicksburg DC353 7,457 2009 14 372 2019

Cardamom GB427 2,720 2010 13 182 2015

Bushwood GB463 2,700 2009 13 182 2015

Danny II GB506 2,800 2012 12 89 2013

Ozona GB515 3,000 2008 11 45 2013

Winter GB605 3,400 2009 11 45 2015

Entrada GB782 4,690 2000 14 372 2014

Clipper CG299 3,452 2005 11 45 2013

Samurai GC432 3,400 2009 12 89 2017

Pony GC468 3,497 2006 14 372 2015

Knotty Head GC512 3,557 2005 14 372 2014

Caesar GC683 4,457 2006 11 45 2013

West Tonga GC726 4,674 2007 12 89 2013

Heidelberg GC859 5,000 2009 13 182 2014

Tiber KC102 4,132 2009 15 691 2016

Kaskida KC292 5,860 2006 15 691 2016

Moccasin KC736 6,759 2011 13 182 2018

Buckskin KC872 6,920 2009 13 182 2018

Lucius KC875 7,168 2009 13 182 2014

Hadrian North KC919 7,000 2010 14 372 2020

Hadrian South KC964 7,586 2009 13 182 2016

Diamond LL370 9,975 2008 11 45 2018

Cheyenne East LL400 9,200 2010 9 12 2013

Mandy MC199 2,478 2010 13 182 2013

Appomattox MC392 7,217 2009 15 691 2019

Santiago MC519 6,526 2011 12 89 2013

122 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

Table 9.9. Assumed size and initial production year of major announced deepwater discoveries (cont.)

Field/Project Name Block

Water Depth 

(feet) Year of Discovery Field Size Class

Field Size 

(MMBOE)

Start Year of 

Production

Isabella MC562 6,535 2007 11 45 2013

Santa Cruz MC563 6,515 2009 12 89 2013

Tubular Bells MC725 4,334 2003 12 89 2014

Anduin West MC754 2,696 2008 11 45 2015

Deimos South MC762 3,122 2010 12 89 2015

Kodiak MC771 4,986 2008 13 182 2013

West Boreas MC792 3,112 2004 12 89 2016

Freedom MC948 6,095 2008 15 691 2014

Vito MC984 4,038 2009 13 182 2016

Big Foot WR029 5,235 2005 12 89 2014

Shenandoah WR052 5,750 2009 13 182 2017

Stones WR508 9,556 2005 12 89 2014

Julia WR627 7,087 2007 12 89 2014

st. Malo WR678 7,036 2003 14 372 2014

Jack WR759 6,963 2004 14 372 2014

Hal WR848 7,657 2008 11 45 2019

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.10. Offshore exploration and production technology levels

Technology Level

Total Improvement over 30 

years (%)

Exploration success rates 30

Delay to commence first exploration and between 15

Exploration & development drilling costs 30

Operating cost 30

Time to construct production facility 15

Production facility construction costs 30

Initial constant production rate 15

Decline rate 0

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Alaska crude oil production

Projected Alaska oil production includes both existing producing fields and undiscovered fields that are expected to exist, based 

upon the region’s geology. The existing fields category includes the expansion fields around the Prudhoe Bay and Alpine Fields for 

which companies have already announced development schedules. Projected North Slope oil production also includes the initiation 

of oil production in the Point Thomson Field in 2016. Alaska crude oil production from the undiscovered fields is determined by the 

estimates of available resources in undeveloped areas and the net present value of the cash flow calculated for these undiscovered 

fields based on the expected capital and operating costs, and on the projected prices.

The discovery of new Alaskan oil fields is determined by the number of new wildcat exploration wells drilled each year and by 

the average wildcat success rate. The North Slope and South-Central wildcat well success rates are based on the success rates 

reported to the Alaska Oil and Gas Conservation Commission for the period of 1977 through 2008.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 123
Oil and Gas Supply Module

New wildcat exploration drilling rates are determined differently for the North Slope and South-Central Alaska. North 

Slope wildcat well drilling rates were found to be reasonably well correlated with prevailing West Texas Intermediate 

crude oil prices. Consequently, an ordinary least squares statistical regression was employed to develop an equation that 

specifies North Slope wildcat exploration well drilling rates as a function of prevailing West Texas Intermediate crude oil 

prices. In contrast, South-Central wildcat well drilling rates were found to be uncorrelated to crude oil prices or any other 

criterion. However, South-Central wildcat well drilling rates on average equaled just over three wells per year during the 

1977 through 2008 period, so three South-Central wildcat exploration wells are assumed to be drilled every year in the 

future.

On the North Slope, the proportion of wildcat exploration wells drilled onshore relative to those drilled offshore is 

assumed to change over time. Initially, only a small proportion of all the North Slope wildcat exploration wells are drilled 

offshore. However, over time, the offshore proportion increases linearly, so that after 20 years, 50% of the North Slope 

wildcat wells are drilled onshore and 50% are drilled offshore. The 50/50 onshore/offshore wildcat well apportionment 

remains constant through the remainder of the projection in recognition of the fact that offshore North Slope wells and 

fields are considerably more expensive to drill and develop, thereby providing an incentive to continue drilling onshore 

wildcat wells even though the expected onshore field size is considerably smaller than the oil fields expected to be 

discovered offshore.

The size of the new oil fields discovered by wildcat exploration drilling is based on the expected field sizes of the 

undiscovered Alaska oil resource base, as determined by the U.S. Geological Survey for the onshore and state offshore 

regions of Alaska, and by the Bureau of Ocean Energy Management (BOEM) (formerly known as the U.S. Minerals 

Management Service) for the federal offshore regions of Alaska. It is assumed that the largest undiscovered oil fields 

will be found and developed first and in preference to the small and midsize undiscovered fields. As the exploration and 

discovery process proceeds and as the largest oil fields are discovered and developed, the discovery and development 

process proceeds to find and develop the next largest set of oil fields. This large to small discovery and development 

process is predicated on the fact that developing new infrastructure in Alaska, particularly on the North Slope, is an 

expensive undertaking and that the largest fields enjoy economies of scale, which make them more profitable and less 

risky to develop than the smaller fields.

Oil and gas exploration and production currently are not permitted in the Arctic National Wildlife Refuge. The projections 

for Alaska oil and gas production assume that this prohibition remains in effect throughout the projection period.

Three uncertainties are associated with the Alaska oil projections: 

•	 whether the heavy oil deposits located on the North Slope, which exceed 20 billion barrels of oil-in-place, will be 

producible in the foreseeable future at recovery rates exceeding a few percent. 

•	 the oil production potential of the North Slope shale formations is unknown at this time. 

•	 the North Slope offshore oil resource potential, especially in the Chukchi Sea, is untested.

In June 2011, Alyeska Pipeline Service Company released a report regarding potential operational problems that might 

occur as Trans-Alaska Pipeline System (TAPS) throughput declines from the current production levels.[6] Although 

the onset of TAPS low flow problems could begin at around 550,000 barrels per day (bbl/d), absent any mitigation, the 

severity of the TAPS operational problems is expected to increase significantly as throughput declines. As the types and 

severity of problems multiply, the investment required to mitigate those problems is expected to increase significantly. 

Because of the many and diverse operational problems expected to occur below 350,000 bbl/d of throughput, 

considerable investment might be required to keep the pipeline operational below this threshold. Thus, North Slope fields 

are assumed to be shut down, plugged, and abandoned when the following two conditions are simultaneously satisfied: 

1) TAPS throughput would have to be at or below 350,000 bbl/d and two) total North Slope oil production revenues 

would have to be at or below $5.0 billion per year.

Legislation and regulations

The Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58) gave the Secretary of the Interior the authority 

to suspend royalty requirements on new production from qualifying leases and required that royalty payments be waived 

automatically on new leases sold in the five years following its November 28, 1995 enactment. The volume of production 

on which no royalties were due for the five years was assumed to be 17.5 million barrels of oil equivalent (BOE) in water 

depths of 200 to 400 meters, 52.5 million BOE in water depths of 400 to 800 meters, and 87.5 million BOE in water 

depths greater than 800 meters. In any year during which the arithmetic average of the closing prices on the New York 

Mercantile Exchange for light sweet crude oil exceeded $28 per barrel or for natural gas exceeded $3.50 per million Btu, 

any production of crude oil or natural gas was subject to royalties at the lease-stipulated royalty rate. Although automatic

124 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Oil and Gas Supply Module

relief expired on November 28, 2000, the act provided the Minerals Management Service (MMS) the authority to include royalty 

suspensions as a feature of leases sold in the future. In September 2000, the MMS issued a set of proposed rules and regulations 

that provide a framework for continuing deep water royalty relief on a lease-by-lease basis. In the model it is assumed that relief 

will be granted at roughly the same levels as provided during the first five years of the Act.

Section 345 of the Energy Policy Act of 2005 provides royalty relief for oil and gas production in water depths greater than 400 

meters in the Gulf of Mexico from any oil or gas lease sale occurring within five years after enactment. The minimum volumes of 

production with suspended royalty payments are:

 (1) 5,000,000 BOE for each lease in water depths of 400 to 800 meters; 

 (2) 9,000,000 BOE for each lease in water depths of 800 to 1,600 meters;

 (3) 12,000,000 BOE for each lease in water depths of 1,600 to 2,000 meters; and

 (4) 16,000,000 BOE for each lease in water depths greater than 2,000 meters.

The water depth categories specified in Section 345 were adjusted to be consistent with the depth categories in the Offshore 

Oil and Gas Supply Submodule. The suspension volumes are 5,000,000 BOE for leases in water depths of 400 to 800 meters; 

9,000,000 BOE for leases in water depths of 800 to 1,600 meters; 12,000,000 BOE for leases in water depths of 1,600 to 2,400 

meters; and 16,000,000 for leases in water depths greater than 2,400 meters. Examination of the resources available at 2,000 

to 2,400 meters showed that the differences between the depths used in the model and those specified in the bill would not 

materially affect the model result.

The MMS published its final rule on the “Oil and Gas and Sulphur Operations in the Outer Continental Shelf Relief or Reduction 

in Royalty Rates Deep Gas Provisions” on January 26, 2004, effective March 1, 2004. The rule grants royalty relief for natural 

gas production from wells drilled to 15,000 feet or deeper on leases issued before January 1, 2001, in the shallow waters (less 

than 200 meters) of the Gulf of Mexico. Production of gas from the completed deep well must begin before five years after the 

effective date of the final rule. The minimum volume of production with suspended royalty payments is 15 billion cubic feet for 

wells drilled to at least 15,000 feet and 25 billion cubic feet for wells drilled to more than 18,000 feet. In addition, unsuccessful 

wells drilled to a depth of at least 18,000 feet would receive a royalty credit for 5 billion cubic feet of natural gas. The ruling also 

grants royalty suspension for volumes of not less than 35 billion cubic feet from ultra-deep wells on leases issued before January 

1, 2001.

Section 354 of the Energy Policy Act of 2005 established a competitive program to provide grants for cost-shared projects 

to enhance oil and natural gas recovery through CO2 injection, while at the same time sequestering CO2 produced from the 

combustion of fossil fuels in power plants and large industrial processes.

From 1982 through 2008, Congress did not appropriate funds needed by the MMS to conduct leasing activities on portions of 

the federal Outer Continental Shelf (OCS) and thus effectively prohibited leasing. Further, a separate Executive ban in effect since 

1990 prohibited leasing through 2012 on the OCS, with the exception of the Western Gulf of Mexico and portions of the Central 

and Eastern Gulf of Mexico. When combined, these actions prohibited drilling in most offshore regions, including areas along the 

Atlantic and Pacific coasts, the eastern Gulf of Mexico, and portions of the central Gulf of Mexico. In 2006, the Gulf of Mexico 

Energy Security Act imposed yet a third ban on drilling through 2022 on tracts in the Eastern Gulf of Mexico that are within 125 

miles of Florida, east of a dividing line known as the Military Mission Line, and in the Central Gulf of Mexico within 100 miles of 

Florida.

On July 14, 2008, President Bush lifted the Executive ban and urged Congress to remove the Congressional ban. On September 

30, 2008, Congress allowed the Congressional ban to expire. Although the ban through 2022 on areas in the Eastern and Central 

Gulf of Mexico remains in place, the lifting of the Executive and Congressional bans removed regulatory obstacles to development 

of the Atlantic and Pacific OCS.

Oil and gas supply alternative cases

Tight oil and shale gas resource cases

Estimates of technically recoverable tight/shale crude oil and natural gas resources are particularly uncertain and change over 

time as new information is gained through drilling, production, and technology experimentation. Over the last decade, as more 

tight/shale formations have gone into production, the estimate of technically recoverable tight oil and shale gas resources has 

increased. However, these increases in technically recoverable resources embody many assumptions that might not prove to 

betrue over the long term and over the entire tight/shale formation. For example, these resource estimates assume that crude oil 

and natural gas production rates achieved in a limited portion of the formation are representative of the entire formation, even 

though neighboring well production rates can vary by as much as a factor of three within the same play. Moreover, the tight/ 

shale formation can vary significantly across the petroleum basin with respect to depth, thickness, porosity, carbon content, pore

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 125
Oil and Gas Supply Module

pressure, clay content, thermal maturity, and water content. Additionally, technological improvements and innovations may allow 

development of crude oil and natural gas resources that have not been identified yet, and thus are not included in the Reference 

case.

Two cases were developed with alternate crude oil and natural gas resource assumptions. These cases do not represent an upper 

and lower bound on future domestic oil and natural gas supply but rather provide a framework to examine the impact of higher 

and lower domestic supply on energy demand, imports, and prices (see ‘Issues in Focus’ articles).

High Oil and Gas Resource case. This case is designed to address what might happen if domestic crude oil production continued to 

increase, reaching over 13 million barrels per day by 2035. This case includes: 

•	 50% higher EUR per tight oil, tight gas, and shale gas well than in the reference case; 

•	 50% lower acre well spacing for tight and shale formations (minimum of 40 acres per well) than in the Reference case as well 

as additional unidentified tight oil resources to reflect the possibility that additional layers or new areas of low-permeability 

zones are identified and developed; 

•	 diminishing returns on the EUR once drilling levels in a county exceed the number of potential wells assumed in the Reference 

case to reflect the increased probability that wells begin to interfere with one another at greater drilling density; 

•	 long term technology improvement trends beyond what is assumed in the Reference case, represented as a 1% annual increase 

in the estimated ultimate recovery for tight oil, tight gas, and shale gas wells; 

•	 kerogen development reaching 135,000 bbl/d by 2025; 

•	 tight oil development in Alaska increasing the total Alaska TRR by 1.9 billion barrels; and 

•	 50% higher technically recoverable undiscovered resources in Alaska and the offshore Lower 48 States than in the Reference 

case. A few offshore Alaska fields are assumed to be discovered and thus developed earlier than in the Reference case. 

The total unproved technically recoverable resources are 401 billion barrels of crude oil and 3,349 trillion cubic feet compared 

to 209 billion barrels of crude oil and 1,932 trillion cubic feet of dry natural gas in the Reference case. Proved reserves of oil and 

natural gas are the same in all three cases; 29 billion barrels of crude oil and 334 trillion cubic feet of dry natural gas. 

Low Oil and Gas Resource case. In this case, the EUR per tight oil, tight gas, and shale gas well is assumed to be 50% lower than in 

the Reference case, increasing the per-unit cost of developing the resource. The total unproved technically recoverable crude oil 

resource is decreased to 180 billion barrels and the natural gas resource is decreased to 1480 trillion cubic feet, compared to 209 

billion barrels of crude oil and 1,932 trillion cubic feet of natural gas assumed in the Reference case.

Notes and sources

[1] The current development of tight oil plays has shifted industry focus and investment away from the development of U.S. oil 

shale (kerogen) resources. Considerable technological development is required prior to the large-scale in-situ production of 

oil shale being economically feasible. Consequently, the Oil Shale Supply Submodule assumes that large-scale in-situ oil shale 

production is not commercially feasible prior to 2040.

[2] Technically recoverable resources are resources in accumulations producible using current recovery technology but without 

reference to economic profitability.

[3] Proved reserves are the estimated quantities that analysis of geological and engineering data demonstrates with reasonable 

certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

[4] Unproved resources include resources that have been confirmed by exploratory drilling and undiscovered resources, which 

are located outside oil and gas fields in which the presence of resources has been confirmed by exploratory drilling; they include 

resources from undiscovered pools within confirmed fields when they occur as unrelated accumulations controlled by distinctly 

separate structural features or stratigraphic conditions.

[5] The Bakken areas are consistent with the USGS Bakken formation assessment units shown in Figure 1 of Fact Sheet 2013-

3013, Assessment of Undiscovered Oil Resources in the Bakken and Three Forks Formations, Williston Basin Province, Montana, 

North Dakota, and South Dakota, 2013 at http://pubs.usgs.gov/fs/2013/3013/fs2013-3013.pdf.

[6] Alyeska Pipeline Service Company, Low Flow Impact Study, Final Report, June 15, 2011, Anchorage, Alaska, at 

www.alyeska- pipe.com/Inthenews/LowFlow/LoFIS_Summary_Report_P6%2027_FullReport.pdf.

126 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Natural Gas Transmission and 

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Natural Gas Transmission and Distribution Module

The NEMS Natural Gas Transmission and Distribution Module (NGTDM) derives domestic natural gas production, wellhead 

and border prices, end-use prices, and flows of natural gas through a regional interstate representative pipeline network, for 

both a peak (December through March) and off-peak period during each projection year. These are derived by solving for 

the market equilibrium across the three main components of the natural gas market: the supply component, the demand 

component, and the transmission and distribution network that links them. Natural gas flow patterns are a function of the 

pattern in the previous year, coupled with the relative prices of the supply options available to bring gas to market centers 

within each of the NGTDM regions (Figure 9). The major assumptions used within the NGTDM are grouped into four general 

categories. They relate to (1) structural components of the model, (2) capacity expansion and pricing of transmission and 

distribution services, (3) Arctic pipelines, and (4) imports and exports. A complete listing of NGTDM assumptions and in-depth 

methodology descriptions are presented in Model Documentation: Natural Gas Transmission and Distribution Module of the 

National Energy Modeling System, Model Documentation 2013, DOE/EIA-M062(2013) (Washington, DC, 2013).

Figure 8. Oil and Gas Supply Model regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

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Natural Gas Transmission and Distribution Module

Key assumptions

Structural components

The primary and secondary region-to-region flows represented in the model are shown in Figure 9. Primary flows are determined, 

along with nonassociated gas production levels, as the model equilibrates supply and demand. Associated-dissolved gas 

production is determined in the Oil and Gas Supply Module (OGSM). Secondary flows are established before the equilibration 

process and are generally set exogenously. In the Northeast, where secondary flows are expected to grow significantly, 

secondary flows are endogenously set based on price differentials between sending and receiving regions. Liquefied natural 

gas (LNG) imports and domestically-produced natural gas exports are also not directly part of the equilibration process, but 

are set at the beginning of each NEMS iteration in response to the price from the previous iteration and projected future prices, 

respectively. LNG re-exports are set exogenously to the model. Flows and production levels are determined for each season, 

linked by seasonal storage. When required, annual quantities (e.g., consumption levels) are split into peak and off-peak values 

based on historical averages. When multiple regions are contained in a Census Division, regional end-use consumption levels 

are approximated using historical average shares. Pipeline and storage capacity are added as warranted by the relative volumes 

and prices. Regional pipeline fuel and lease and plant fuel consumption are established by applying an historically based factor to 

the flow of gas through a region and the production in a region, respectively. Prices within the network, including at the borders 

and the wellhead, are largely determined during the equilibration process. Delivered prices for each sector are set by adding an 

endogenously estimated markup (generally a distributor tariff) to the regional representative city gate price. Supply curves and 

electric generator gas consumption are provided by other NEMS modules for subregions of the NGTDM regions, reflective of 

how their internal regions overlap with the NGTDM regions.

Capacity expansion and pricing of transmission and distribution

For the first two projection years, announced pipeline and storage capacity expansions (that are deemed highly likely to occur) 

are used to establish limits on flows and seasonal storage in the model. Subsequently, pipeline and storage capacity is added 

when increases in consumption, coupled with an anticipated price increase, warrant such additions (i.e., flow is allowed to 

exceed current capacity if the demand still exists given an assumed increased tariff). Once it is determined that an expansion will 

occur, the associated capital costs are applied in the revenue requirement calculations in future years. Capital costs are assumed 

based on average costs of recent comparable expansions for compressors, looping, and new pipeline.

It is assumed that pipeline and local distribution companies build and subscribe to a portfolio of interstate pipeline and storage 

capacity to serve a region-specific colder-than-normal winter demand level, currently set at 30% above the daily average. 

Maximum pipeline capacity utilization in the peak period is set at 99%. In the off-peak period, the maximum is assumed to vary 

between 75 and 99% of the design capacity. The overall level and profile of consumption, as well as the availability and price of 

supplies, generally cause realized pipeline utilization levels to be lower than the maximum.

Pricing of services

Transport rates between regions are set for the purposes of determining natural gas flows through the representative pipeline 

network based on historical observed differentials between regional spot prices. Ultimately regional city gate prices reflect the 

addition of reservation charges along each of the connecting routes and within a region. Per unit pipeline reservation charges are 

initially based on a regulated cost-of-service calculation and an assumed flow rate, and are dynamically adjusted based on the 

realized utilization rate. Reservation rates for interstate pipeline services (both between NGTDM regions and within a region) are 

calculated assuming that the costs of new pipeline capacity will be rolled into the existing rate base.

For the industrial and electric generator sectors delivered natural gas prices are based on regional prices which do not directly 

include any pipeline reservation fees, (i.e., spot prices), with an added markup based on averaged or econometrically estimated 

historical values. For the residential and commercial customers delivered natural gas prices are based on regional city gate 

prices with an added econometrically estimated distributor markup. The distributor tariffs are projected using econometrically 

estimated equations, primarily in response to changes in consumption levels. Historically based differentials are used to 

establish separate prices for energy-intensive and non-energy-intensive industrial customers. Prices are originally set on a 

seasonal basis and are averaged with quantity-weights to derived annual prices.

The natural gas vehicle sector is segregated into compressed natural gas (CNG) and liquefied natural gas (LNG) at private 

refueling stations (fleets) and at public retail stations. The distributor markup for natural gas delivered via pipeline to a CNG 

station is based off historical data for the sector. A retail markup and motor fuel (excise) taxes are added to set the final retail 

price. The excise taxes applied and the value and assumptions behind the retail markups assumed are shown in Table 10.1. The 

price for delivered dry natural gas to a liquefaction plant is approximated by using the price to electric generators. The price for 

LNG is therefore set to the price to electric generators, plus the assumed price to liquefy and transport the LNG, the retail price 

markup at the station, and the excise taxes. The values for these components and the primary assumptions behind them are 

shown in Table 10.1. The table shows the national average State excise tax, while in the model these taxes vary by region.

130 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Natural Gas Transmission and Distribution Module

Table 10.1. Assumptions related to CNG and LNG fuel prices

Year CNG CNG LNG LNG

fleet retail fleet retail

Retail markup after dry gas pipeline delivery, with no excise tax (2010$/dge) 0.80 0.93 1.39 1.58

 Capacity (dge/day) 1600 1100 4000 4000

 Usage (percent of capacity) 80 60 80 60

 Capital cost (million 2010$) 80 0.5 1.0 1.0

 Capital recovery (years) 5 10 5 10

 Weighted average cost of capital (rate) 0.10 0.15 0.10 0.15

 Operating cost (2010$/dge) 0.34 0.51 0.41 0.59

 Charge for liquefying and delivering LNG (2010$/dge) -- -- 0.75 0.75

Federal excise tax (nominal$/dge) 0.21 0.21 0.42 0.42

State excise tax (nominal$/dge) 0.15 0.15 0.24 0.24

Fuel loss for liquefying and delivering LNG (percent of input volumes) -- -- 10 10

Fuel loss at station (percent of input volumes) 0.5 0.5 1.0 2.0

Source: U.S. Energy Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis, U.S. Tax Code and State Tax Codes.

Prices for natural gas to fuel ships are set at the same rate as for vehicles less state motor fuel taxes. For trains both federal 

and state motor fuels taxes are not included in the price. In addition, the retail markup above the cost of dry gas for LNG for rail 

was assumed at $0.90 (2010$ per diesel gallon equivalent (dge)) (compared to $1.39/dge for fleet vehicles as shown in Table 

10.1), with the assumption that liquefaction would occur at the refueling point and cost $0.53/dge (compared to $0.75/dge for 

vehicles), operating costs would be $0.21/dge (compared to $0.41/dge for fleet vehicles), and capital cost recovery for additional 

equipment beyond the liquefiers would be $0.16/dge (compared to $0.23/dge for fleet vehicles, not shown in table).

Pipelines from arctic areas into Alberta

The outlook for natural gas production from the North Slope of Alaska is affected strongly by its extreme distance from 

the necessary infrastructure to transport it to major commercial markets. At present there are three basic options for 

commercializing the natural gas that has been produced in association with the Prudhoe Bay oil fields and reinjected in the oil 

wells to maintain pressure, and is therefore relatively low-cost to recover: build a pipeline to the Lower 48 states via Alberta, 

produce and transport the natural gas as liquid fuel in a gas-to-liquid (GTL) plant, or pipe the natural gas to a seaport, liquefy 

and ship it overseas. The GTL option was not considered for AEO2014. Which, if any, of the other two options that is determined 

within the model to be economically viable first is assumed to have primary access to the proved, low-cost, reserves on the 

North Slope and preclude the economic viability of the other option. The assumptions associated with the LNG option are 

provided in a later section. The primary assumptions associated with estimating the cost of North Slope Alaskan gas to Alberta, 

as well as for Mackenzie Delta gas from Canada’s Northwest Territories to Alberta, are shown in Table 10.2. A calculation is 

performed to estimate a regulated, levelized tariff for each pipeline. Additional items are added to account for the wellhead price, 

treatment costs, pipeline fuel costs, and a risk premium to reflect the potential impact on the market price if the pipeline comes 

on line.

To assess the market value of Alaskan and Mackenzie Valley gas against the Lower 48 market, a price differential of $0.76 (2012 

dollars per Mcf) is assumed between the price in Alberta and the average Lower 48 wellhead price. The resulting cost of Alaska 

gas, relative to the Lower 48 wellhead price, is approximately $8.20 (2012 dollars per Mcf), with some variation across the 

projection due to changes in gross domestic product. Construction of an Alaska-to-Alberta pipeline is projected to commence 

if the assumed total costs for Alaska gas in the Lower 48 states exceed the average Lower 48 gas price in each of the previous 

two years, on average over the previous five years (with greater weight applied to more recent years), and as expected to average 

over the next three years. An adjustment is made if prices were declining over the previous five years. Once the assumed fouryear construction period is complete, expansion can occur if the price exceeds the initial trigger price by $6.99 (2012 dollars 

per Mcf). Supplies to fill an expanded pipeline are assumed to require new gas wells. When the Alaska-to-Alberta pipeline is 

built in the model, additional pipeline capacity is added to bring the gas across the border into the United States. For accounting 

purposes, the model assumes that all of the Alaska gas will be consumed in the United States and that sufficient economical 

supplies are available at the North Slope to fill the pipeline over the depreciation period.

Natural gas production from the Mackenzie Delta is assumed to be sufficient to fill a pipeline over the projection period should 

one be built connecting the area to markets in the south in the United States and Canada. The basic methodology used to 

represent the decision to build a Mackenzie pipeline is similar to the process used for an Alaska-to-Lower 48 pipeline, using the 

primary assumed parameters listed in Table 10.2.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 131
Natural Gas Transmission and Distribution Module

Table 10.2. Primary assumptions for natural gas pipelines from Alaska and Mackenzie delta into Alberta, 

Canada

Alaska to Alberta Mackenzie Delta to Alberta

Initial flow into Alberta 3.8 billion cubic feet per day 1.1 billion cubic feet per day

Expansion potential 22% 58%

Initial capitalization $37.5 billion (2012 dollars) $11.2 billion (2012 dollars)

Cost of Debt (premium over 10-year treasury note yield) 0.75% 0.0%

Cost of equity (premium over 10-year treasury note yield) 6.5% 7.5%

Debt fraction 70% 60%

Depreciation period 20 years 20 years

Minimum wellhead price (including treatment and fuel costs) $3.70 (2012 dollars per Mcf) $4.39 (2012 dollars per Mcf)

Expected price reduction $1.05 (2012 dollars per Mcf) $0.06 (2012 dollars per Mcf)

Construction period 4 years 4 years

Planning period 5 years 2 years

Earliest start year 2021 2018

Source: U.S. Energy Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis. Alaska pipeline cost data are based 

on Federal Energy Regulatory Commission, Docket PF09-11-001, “Open Season Plan Documents Submitted in Connection with Request for 

Commission Approval of Detailed Plan for Conducting an Open Season,” submitted by TransCanada Alaska Company LLC on January 29, 

2010, Volume III of III, Appendix C, Exhibit J – Recourse Rate Output, various pages. Note that the capital cost figure is the arithmetic average 

of the two $30.7 and$40.4 2009 billion dollars capital cost estimates that include the mainline gas pipeline and the gas treatment plant, but 

which exclude the gas field line from Point Thomson to the gas treatment plant. National Energy Board of Canada, “Mackenzie Gas Project 

– Hearing Order GH-1-2004, Supplemental Information – Project Update 2007,” dated May 15, 2007; National Energy Board of Canada, 

“Mackenzie Gas Project – Project Cost Estimate and Schedule Update,” dated March 12, 2007; Canada Revenue Agency, “T2 Corporation 

Income Tax Guide 2006,” T4012(E) Rev. 07. National Energy Board of Canada, “Application for Approval of the Development Plan for Taglu 

Field - Project Description,” submitted by Imperial Oil Resources Ltd., TDPA-P1, August 2004; National Energy Board of Canada, “Application 

for Approval of the Development Plan for Niglintgak Field - Project Description,” submitted by Shell Canada Ltd., NDPA-P1, August 2004; and 

National Energy Board of Canada, “Application for Approval of the Development Plan for Parsons Lake Field - Project Description.”

Supplemental natural gas

The projection for supplemental gas supply is identified for three separate categories: pipeline quality synthetic natural gas 

(SNG) from coal or coal-to-gas (CTG), SNG from liquids, and other supplemental supplies (propane-air, coke oven gas, refinery 

gas, biomass air, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural gas). The third 

category, other supplemental supplies, are held at a constant level of 7.0 billion cubic feet per year throughout the projection 

because this level is consistent with historical data and it is not believed to change significantly in the context of a Reference 

case. SNG from liquid hydrocarbons in Hawaii is assumed to continue over the projection at the average historical level of 

2.6 billion cubic feet per year. SNG production from coal at the currently operating Great Plains Coal Gasification Plant is also 

assumed to continue through the projection period at an average historical level of 52.1 billion cubic feet per year. It is assumed 

that additional CTG facilities will be built if and when natural gas prices are high enough to make them economic. One CTG 

facility is assumed capable of processing 6,040 tons of bituminous coal per day, with a production capacity of 0.1 billion cubic 

feet per day of synthetic fuel and approximately 100 megawatts of capacity for electricity cogeneration sold to the grid. A CTG 

facility of this size is assumed to cost nearly $1 billion in initial capital investment (2012 dollars). CTG facilities are assumed 

to be built near existing coal mines. All NGTDM regions are considered potential locations for CTG facilities except for New 

England. Synthetic gas products from CTG facilities are assumed to be competitive when natural gas prices rise above the cost 

of CTG production (adjusted for credits from the sale of cogenerated electricity). It is assumed that CTG facilities will not be 

built before 2015.

132 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Natural Gas Transmission and Distribution Module

Natural gas imports and exports

U.S. natural gas trade with Mexico is determined endogenously based on various assumptions about the natural gas market 

in Mexico. Natural gas consumption levels in Mexico are set exogenously based on projections from the International Energy 

Outlook 2013 and are provided in Table 10.3, along with initially assumed Mexico natural gas production and LNG import levels 

targeted for markets in Mexico. Adjustments to production are made endogenously within the model to reflect a response to 

price fluctuations within the market and reflect laws concerning foreign investment at the time of the projection. Domestic 

production is assumed to be supplemented by LNG from receiving terminals constructed on both the east and west coasts of 

Mexico. Maximum LNG import volumes targeted for markets in Mexico are set exogenously and will be realized if endogenously 

determined LNG imports into North America are sufficient. The difference between production plus LNG imports and 

consumption in Mexico in any year is assumed to be either imported from, or exported to, the United States.

Similarly to Mexico, Canada is modeled through a combination of exogenously and endogenously specified components. 

Canadian production, U.S. import flows from Canada, and U.S. export flows to Canada are determined endogenously within the 

model. Canadian natural gas production in Eastern Canada, consumption, and LNG exports are set exogenously in the model 

and are shown in Table 10.4. Production from conventional and tight formations in the Western Canadian Sedimentary Basin 

(WCSB) is calculated endogenously to the model using annual supply curves based on beginning-of-year proved reserves and an 

estimated production-to-reserve ratio. Reserve additions are set equal to the product of successful natural gas wells and a finding 

rate (both based on an econometric estimation). The initial coalbed methane, shale gas, and conventional WCSB economically 

recoverable unproved resource base estimates assumed in the model are 45 trillion cubic feet, 90 trillion cubic feet, and 127 

trillion cubic feet, respectively, all as of 2011. [1] Potential production from tight formations was approximated by increasing the 

conventional resource level by 2.35% annually. Production from coalbed and shale sources is established based on an assumed 

production path which varies in response to the level of remaining resources and the solution price in the previous projection 

year. LNG imports to Canada are set in conjunction with the LNG import volumes for the Lower 48 states.

Table 10.3. Exogenously specified Mexico natural gas consumption, production, and LNG imports

billion cubic feet per year

Consumption Initial Dry Production Initial LNG Imports

2015 2,615 1,587 145

2020 3,134 1,575 475

2025 3,868 1,562 835

2030 4,599 1,725 915

2035 5,389 2,098 815

2040 6,224 2,678 585

Source: U.S. Energy Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis, based on U.S. Energy Information 

Administration, International Energy Outlook 2013 DOE/EIA-0484(2013). 

Note: Excludes any LNG imported to Mexico for export to the United States.

Table 10.4. Exogenously specified Canada natural gas consumption, production, and LNG exports and supply

billion cubic feet per year

Year Consumption Production Eastern Canada LNG Exports

2015 3.075 156 0

2020 3,570 150 255

2025 3,999 165 771

2030 4,305 114 1,022

2035 4,581 74 1,228

2040 4,870 54 1,603

Source: Consumption - U.S. Energy Information Administration. International Energy Outlook 2013, DOE/EIA-0484(2013); Production - Energy

Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis. LNG exports - U.S. Energy Information Administration. 

International Energy Outlook 2013, DOE/EIA-0484(2013).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 133
Natural Gas Transmission and Distribution Module

LNG imports to the United States and Canada are determined endogenously within the model using Atlantic/Pacific and peak/

off-peak supply curves derived from model results generated by EIA’s International Natural Gas Model (INGM). Prices from 

the previous model iteration are used to establish the total level of U.S./Canada LNG imports in the peak and off-peak period 

and in the Atlantic and Pacific regions. First, assumed LNG imports which are consumed in Mexico are subtracted (presuming 

the volumes are sufficient). Then, the remaining levels are allocated to the model regions based on last year’s import levels, the 

available regasification capacity, and the relative prices. Regasification capacity is limited to facilities currently in existence and 

those already under construction, which is fully sufficient to accommodate import levels projected by the model. 

LNG exports of domestically produced natural gas from the Lower 48 states and Alaska are set endogenously in the model. 

The model assesses the relative economics of a generic project in operation over the next 20 years in each viable coastal region 

by comparing a model-generated estimate of the expected market price in Europe and Asia over the next 20 years against the 

expected price of natural gas in each coastal region plus assumed charges for liquefaction, shipping, and regasification (shown 

in Table 10.5). A present value of the differential is set using a discount rate of 10%. The model limits the annual liquefaction 

capacity builds to three trains a year, at 200 billion cubic feet per train. When the evaluation is made, the region showing the 

greatest positive economic potential, if any, is selected as the location for adding capacity. A new project is assumed to consist 

of two trains and is phased in over a two-year period, partially to reflect a mid year project start-up. Once a facility is built, it is 

assumed to operate at its design capacity throughout the projection period unless the competing price in Asia or Europe falls 

below the delivered price of U.S. LNG in the region, excluding assumed reservation charges (i.e., “sunk” costs) for liquefaction. 

Other constraining assumptions are considered, such as earliest start year and maximum export volumes. Any existing facilities 

or ones under construction are set exogenously to the model, which for AEO2014 include the two trains under construction at 

Sabine Pass (at 1.1 Bcf per day starting in mid-2016). The projected market price of LNG in Europe (National Balancing Point) and 

Asia (Japan) is based on the assumed values shown in Table 10.6, projected Brent oil prices, and the level of North American 

LNG exports. Annual U.S. exports of liquefied natural gas (LNG) to Japan via Alaska’s existing Kenai facility are assumed to 

cease in 2012. LNG re-exports are assumed to stay at 8 billion cubic feet per year throughout the projection period.

Table 10.5. Charges related to LNG exports

2010 dollars per million Btu

South Atlantic West South Central Washington/Oregon Alaska

Liquefaction & Pipe Fee 3.30 3.00 4.10 7.00

Shipping to Europe 0.98 1.28 3.86 3.65

Shipping to Asia 2.63 2.55 1.15 0.90

Regasification 0.10 0.10 0.10 0.10

Fuel charge (percent)* 15 15 15 15

*Percent increase in market price of natural gas charged by liquefaction facility to cover fuel-related expenses, largely fuel used 

in the liquefaction process.

Source: U.S. Energy Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis.

Table 10.6. International natural gas volume drivers for world LNG Europe and Asia market price 

projections

billion cubic feet

Flexible LNG*

Consumption 

OECD Europe

Consumption 

Japan

Consumption 

S. Korea

Consumption 

China

Production 

China

2015 4,362 19,714 4,318 1,532 5,615 3,806

2020 5,821 20,378 4,583 1,657 7,752 4,242

2025 7,273 20,774 4,937 1,858 10,270 5,165

2030 8,577 22,052 5,143 1,968 13,041 6,702

2035 10,097 23,183 5,233 2,291 15,634 8,500

2040 11,452 24,478 5,242 2,502 17,498 10,119

*Flexible LNG is a baseline projection of the volumes of LNG sold in the spot market or effectively available for sale at flexible 

destinations. 

Source: U.S. Energy Information Administration, International Energy Outlook 2013, DOE/ EIA-0484(2013) and U.S. Energy 

Information Administration, Office of Petroleum, Natural Gas, and Biofuels Analysis.

134 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Natural Gas Transmission and Distribution Module

Legislation and regulations

The methodology for setting reservation fees for transportation services is initially based on a regulated rate calculation, but 

is ultimately consistent with FERC’s alternative ratemaking and capacity release position in that it allows some flexibility in 

the rates pipelines ultimately charge. The methodology is market-based in that rates for transportation services will respond 

positively to increased demand for services while rates will decline should the demand for services decline.

Section 116 of the Military Construction Appropriations and Emergency Hurricane Supplemental Appropriations Act, 2005 

(Public Law 108-324) gives the Secretary of Energy the authority to issue Federal loan guarantees for an Alaska natural gas 

transportation project, including the Canadian portion, that would carry natural gas from northern Alaska, through the Canadian 

border south of 68 degrees north latitude, into Canada, and to the Lower 48 states. This authority would expire 2 years after the 

final certificate of public convenience and necessity is issued. In aggregate, the loan guarantee would not exceed: (1) 80% of 

total capital costs (including interest during construction); (2) $18 billion (indexed for inflation at the time of enactment); or (3) 

a term of 30 years. The Act also promotes streamlined permitting and environmental review, an expedited court review process, 

and protection of rights-of-way for the pipeline. The assumed costs of borrowing money for the pipeline were reduced to reflect 

the decreased risk as a result of the loan guarantee.

Section 706 of the American Jobs Creation Act of 2004 (Public Law 108-357) provided a 7-year cost-of-investment recovery 

period for the Alaska natural gas pipeline, as opposed to the previously allowed 15-year recovery period, for tax purposes. The 

provision is effective for property placed in service after 2013 (or treated as such) and is assumed to have minimal impact on the 

decision to build the pipeline.

Section 707 of the American Jobs Creation Act extended the 15-percent tax credit previously applied to costs related to 

enhanced oil recovery to construction costs for a gas treatment plant that supplies natural gas to a 2 trillion Btu per day pipeline, 

lies in Northern Alaska, and produces carbon dioxide for injection into hydrocarbon-bearing geological formations. A gas 

treatment plant on the North Slope that feeds gas into an Alaska pipeline to Canada is expected to satisfy this requirement. The 

provision is effective for costs incurred after 2004. The impact of this tax credit is assumed to be factored into the cost estimates 

filed by the participating companies.

Section 312 of the Energy Policy Act of 2005 authorizes the Federal Energy Regulatory Commission (FERC) to allow natural 

gas storage facilities to charge market-based rates if it was believed that they would not exert market power. Storage rates are 

allowed to vary in the model from regulation-based rates, depending on market conditions.

Notes and sources

[1] Coalbed, shale gas, and tight sands unproved resource based on the National Energy Board of Canada’s “Canada’s Energy 

Future: Energy supply and demand projections to 2035,” November 2011.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 135
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Liquid Fuels Market Module
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Liquid Fuels Market Module

The NEMS Liquid Fuels Market Module (LFMM) projects petroleum product prices and sources of supply for meeting 

petroleum product demand. The sources of supply include crude oil (both domestic and imported), petroleum product imports, 

unfinished oil imports, other refinery inputs (including alcohols, ethers, esters, corn, biomass, and coal), natural gas plant liquids 

production, and refinery processing gain. In addition, the LFMM projects capacity expansion and fuel consumption at domestic 

refineries.

The LFMM contains a linear programming (LP) representation of U.S. petroleum refining activities, biofuels production 

activities, and other non-petroleum liquid fuels production activity in eight domestic U.S. regions, as well as refining activity 

in the non-U.S. Maritime Canada/Caribbean refining region (created to represent short-haul international refineries that 

predominantly serve U.S. markets). In order to better represent policy, import/export patterns, and biofuels production, the 

eight U.S. regions were defined by subdividing three of the five Petroleum Administration for Defense Districts (PADDs) (Figure 

10). The LP model also represents crude import supply curves, petroleum product import and export curves, biodiesel import 

supply curves, and advanced ethanol import supply curves from Brazil. The nine LFMM regions and import/export curves are 

connected in the LP via crude and product transit links. In order to interact with other NEMS modules with different regional 

representations, certain LFMM inputs and outputs are converted from sub-PADD regions to other regional structures and vice 

versa. The linear programming results are used to determine end-use product prices for each Census Division (shown in Figure 

5) using the assumptions and methods described below.

Figure 10. Liquid Fuels Market Module Regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 139
Liquid Fuels Market Module

Key assumptions

Product types and specifications

The LFMM models refinery production of the products shown in Table 11.1.

The costs of producing different formulations of gasoline and diesel fuel that are required by state and federal regulations are 

determined within the LP representation of refineries by incorporating the specifications and demands for these fuels. The LFMM 

assumes that the specifications for these fuels will remain the same as currently specified.

Table 11.1. Petroleum product categories

Product Category Specific Products

Motor Gasoline Conventional, Reformulated (including CARB gasoline)

Jet Fuel Kerosene-type

Distillates Kerosene, Heating Oil, Low-Sulfur, Ultra-Low-Sulfur and CARB Diesel

Residual Fuels Low-Sulfur, High-Sulfur

Liquefied Petroleum Gases Ethane, Propane, Propylene, normal- and iso-Butane

Petrochemical Feedstock Petrochemical Naphtha, Petrochemical Gas Oil, Aromatics

Others

Lubricating Products and Waxes, Asphalt/Road Oil, Still Gas

Petroleum Coke, Special Naphthas, Aviation Gasoline

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Motor gasoline specifications and market shares

The LFMM models the production and distribution of two different types of gasoline: conventional and reformulated (Phase 2). 

The following specifications are included in the LFMM to differentiate between conventional and reformulated gasoline blends 

(Table 11.2): Reid vapor pressure (RVP), benzene content, aromatic content, sulfur content, olefins content, and the percent 

evaporated at 200 and 300 degrees Fahrenheit (E200 and E300).

Table 11.2. Year-round gasoline specifications by Petroleum Administration for Defense District (PADD)

PADD/Type

Reid Vapor

Pressure

(Max PSI)

Aromatics 

Volume

Percent 

(Max)

Benzene

Volume

Percent

(Max)

2007 Sulfur

PPM

(Max)

Olefin Volume

Percent

(Max)

Percent 

Evaporated

at 200o (Min)

Percent 

Evaporated

at 300o (Min)

Conventional

PADD I 10.11 24.23 0.62 22.4 10.8 45.9 81.7

PADD II 10.11 24.23 0.62 22.4 10.8 45.9 81.7

PADD III 10.11 24.23 0.62 22.4 10.8 45.9 81.7

PADD IV 10.11 24.23 0.62 22.4 10.8 45.9 81.7

PADD V 10.11 24.23 0.62 22.4 10.8 45.9 81.7

Reformulated

PADD I 8.8 21.0 0.62 23.8 10.36 54.0 81.7

PADD II 8.8 21.0 0.62 23.8 10.36 54.0 81.7

PADD III 8.8 21.0 0.62 23.8 10.36 54.0 81.7

PADD IV 8.8 21.0 0.62 23.8 10.36 54.0 81.7

PADD V

Nonattainment 8.8 21.0 0.62 23.8 10.36 54.0 81.7

CARB (attainment) 7.7 23.12 0.58 10.0 6.29 42.9 86.3

Max = maximum, Min.= minimum, PADD = Petroleum Administration for Defense District. PPM = parts per million by weight, PSI = pounds per square inch.

Benzene volume percent changed to 0.62 for all regions and types in 2011 to meet the MSAT2 ruling.

Source: U.S. Energy Information Administration, Office of Energy Analysis. Derived using U.S. EPA’s Complex Model, and updated with U.S. EPA’s gasoline 

projection survey “Fuel Trends Report: Gasoline 1995-2005”, January 2008, EPA420-R-08-002 (http://www.epa.gov/otaq/regs/fuels/fueltrends.htm).

140 U.S. Energy Information Administration | Assumptiions to the Annual Energy Outlook 2014
Liquid Fuels Market Module

Reformulated gasoline must meet the Complex Model II compliance standards, which cannot exceed average 1990 levels of 

toxic and nitrogen oxide emissions [1]. Reformulated gasoline has been required in many areas in the United States since 

January 1995. In 1998, EPA began certifying reformulated gasoline using the “Complex Model,” which allows refiners to specify 

reformulated gasoline based on emissions reductions from their companies’ respective 1990 baselines or EPA’s 1990 baseline. 

The LFMM reflects “Phase 2” reformulated gasoline requirements which began in 2000. The LFMM uses a set of specifications 

that meet the “Complex Model” requirements, but it does not attempt to determine the optimal specifications that meet the 

“Complex Model.” 

Cellulosic biomass feedstock supplies and costs are provided by the NEMS Renewable Fuels Model. Initial capital costs for 

biomass cellulosic ethanol were obtained from a research project reviewing cost estimates from multiple sources [2]. Operating 

costs and credits for excess electricity generated at biomass ethanol plants were obtained from a survey of literature [3].

Corn supply prices are estimated from the USDA baseline projections to 2019 [4]. Operating costs of corn ethanol plants 

are obtained from USDA survey of ethanol plant costs [5]. Energy requirements are obtained from a study of carbon dioxide 

emissions associated with ethanol production [6].

AEO2014 assumes a minimum 10% blend of ethanol in domestically consumed motor gasoline. Federal reformulated gasoline 

(RFG) and conventional gasoline can be blended with up to 15% ethanol (E15) in light-duty vehicles of model year 2001 and 

newer. Reformulated and conventional gasoline can also be blended with 16% biobutanol. Actual levels will depend on the 

ethanol and biobutanol blending value and relative cost-competitiveness with other gasoline blending components. In addition, 

current state regulation along with marketplace constraints limit the full penetration of E15 in the projection. EISA2007 defines a 

requirements schedule for having renewable fuels blended into transportation fuels by 2022.

Reid Vapor Pressure (RVP) limitations are effective during summer months, which are defined differently by consuming regions. 

In addition, different RVP specifications apply within each PADD. The LFMM assumes that these variations in RVP are captured 

in the annual average specifications, which are based on summertime RVP limits, wintertime estimates, and seasonal weights.

Within the LFMM, total gasoline demand is disaggregated into demand for conventional and reformulated gasoline by applying 

assumptions about the annual market shares for each type. In AEO2014 the annual market shares for each region reflect actual 

2010 market shares and are held constant throughout the projection. (See Table 11.3 for AEO2014 market share assumptions.)

Table 11.3. Market share for gasoline types by Census Division

Gasoline

Type/Year

New 

England

Middle 

Atlantic

East

North

Central

West

North

Central

South

Atlantic

East

South

Central

West

South

Central Mountain Pacific

Conventional Gasoline 18 41 81 88 81 95 72 86 25

Reformulated Gasoline 82 59 19 12 19 5 28 14 75

Source: U.S. Energy Information Administration, Office of Energy Analysis. Derived from EIA-782C, “Monthly Report of Prime Supplier Sales of 

Petroleum Products Sold for Local Consumption,” January-December 2010.

As of January 2007, Oxygenated Gasoline is included within Conventional Gasoline.

Diesel fuel specifications and market shares

In order to account for ultra-low-sulfur diesel (ULSD) regulations related to the Clean Air Act Amendments of 1990 (CAAA90), 

ULSD is differentiated from other distillates. In NEMS, the California portion of the Pacific Region (Census Division 9) is required 

to meet CARB standards. Both Federal and CARB standards currently limit sulfur to 15 parts per million (ppm). AEO2014 

incorporates the ULSD regulation finalized in December 2000. ULSD is highway diesel.

Demand for highway-grade diesel is assumed to be equivalent to the total transportation distillate demand. Over the past few 

years, highway-grade diesel supplies have nearly matched total transportation distillate sales, although some highway-grade 

diesel has gone to non-transportation uses such as construction and agriculture.

AEO2014 incorporates the “nonroad, locomotive, and marine” (NRLM) diesel regulation finalized in May 2004 for large refiners 

and importers. The final NRLM rule established a new ULSD limit of 15 ppm for nonroad diesel by mid-2010. For locomotive and 

marine diesel, the rule established an ULSD limit of 15 ppm in mid-2012.

End-Use product prices

End-use petroleum product prices are based on marginal costs of production plus production-related fixed costs plus distribution 

costs and taxes. The marginal costs of production are determined within the LP and represent variable costs of production, 

including additional costs for meeting reformulated fuels provisions of CAAA90. Environmental costs associated with controlling 

pollution at refineries are implicitly assumed in the annual update of the refinery investment costs for the processing units.

The costs of distributing and marketing petroleum products are represented by adding product-specific distribution costs to the 

marginal refinery production costs (product wholesale prices). The distribution costs are derived from a set of base distribution 

markups (Table 11.4).

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 141
Liquid Fuels Market Module

Table 11.4. Petroleum product end-use markups by sector and Census Division

2012 dollars per gallon

Sector/Product

Census Division

New

England

Middle

Atlantic

East

North

Central

West

North

Central

South

Atlantic

East

South

Central

West

South

Central Mountain Pacific

Residential Sector

Distillate Fuel Oil 0.59 0.69 0.43 0.21 0.58 0.24 0.16 0.38 0.43

Kerosene 0.19 0.77 0.63 0.64 0.68 0.59 0.66 0.79 0.00

Liquefied Petroleum Gases 1.16 1.22 0.63 0.42 1.15 0.99 0.98 0.82 1.07

Commercial Sector

Distillate Fuel Oil 0.27 0.22 0.13 0.08 0.14 0.09 0.11 0.06 -0.03

Gasoline 0.16 0.16 0.15 0.14 0.14 0.16 0.15 0.19 0.20

Kerosene 0.18 0.78 0.63 0.64 0.75 0.69 0.55 1.05 0.00

Liquefied Petroleum Gases 0.42 0.66 0.42 0.42 0.55 0.52 0.56 0.47 0.36

Low-Sulfur Residual Fuel Oil1 0.14 -0.07 -0.13 -0.36 -0.02 -0.03 -0.03 0.00 0.00

Utility Sector

Distillate Fuel Oil 0.02 0.05 0.11 0.08 0.02 0.09 0.10 0.19 0.13

Residual Fuel Oil1 -0.38 -0.11 0.78 0.65 -0.07 -0.35 -0.60 0.00 0.00

Transportation Sector

Distillate Fuel Oil 0.56 0.55 0.51 0.50 0.45 0.51 0.52 0.47 0.62

E852 0.15 0.14 0.12 0.11 0.12 0.13 0.10 0.16 0.15

Gasoline 0.19 0.18 0.15 0.14 0.15 0.16 0.12 0.20 0.19

High-Sulfur Residual Fuel Oil1 0.18 -0.03 -0.19 -0.63 -0.23 -0.42 -0.47 0.00 0.52

Jet Fuel 0.03 -0.03 0.01 0.01 0.00 0.05 0.03 0.01 -0.03

Liquefied Petroleum Gases 0.37 0.71 0.91 0.91 0.68 0.95 0.99 0.82 0.79

Industrial Sector

Asphalt and Road Oil 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Distillate Fuel Oil 0.18 0.20 0.22 0.23 0.14 0.17 0.16 0.10 0.03

Gasoline 0.19 0.17 0.15 0.14 0.15 0.17 0.15 0.19 0.20

Kerosene 0.00 0.09 0.00 0.03 0.03 0.02 0.01 0.41 0.00

Liquefied Petroleum Gases 0.76 0.97 0.63 0.63 0.63 0.54 0.21 0.52 0.70

Low-Sulfur Residual Fuel Oil1 0.07 -0.08 0.90 0.75 0.35 -0.01 0.08 -0.09 0.21

1

Negative values indicate that average end-use sales prices were less than wholesale prices. This often occurs with residual fuel which is produced as a 

byproduct when crude oil is refined to make higher-value products like gasoline and heating oil.

2

E85 refers to a blend of 85% ethanol (renewable) and 15 % motor gasoline (non-renewable). To address cold starting issues, the percentage of

ethanol varies seasonally. The annual average ethanol content of 74% is used.

Sources: Markups based on data from Energy Information Administration (EIA), Form EIA-782A, Refiners’/Gas Plant Operators’ Monthly Petroleum Product 

Sales Report; EIA, Form EIA-782B, Resellers’/Retailers’ Monthly Petroleum Report Product Sales Report; Form FERC-423, Monthly Report of Cost and Quality of 

Fuels for Electric Plants prior to 2008; Form EIA-923, Power Plant Operations Report starting in 2008; EIA Form EIA-759 Monthly Power Plant Report; EIA, State 

Energy Data Report 2010, Consumption (June 2012); EIA, State Energy Data 2010: Prices and Expenditures (June 2012).

State and federal taxes are also added to transportation fuels to determine final end-use prices (Tables 11.5 and 11.6). Recent 

tax trend analysis indicates that state taxes increase at the rate of inflation; therefore, state taxes are held constant in real terms 

throughout the projection. This assumption is extended to local taxes which are assumed to average 1% of motor gasoline prices 

[7]. Federal taxes are assumed to remain at current levels in accordance with the overall AEO2014 assumption of current laws and 

regulations. Federal taxes are not held constant but deflated as follows:

 Federal Tax product, year = Current Federal Tax product /GDP Deflator year

142 U.S. Energy Information Administration | Assumptiions to the Annual Energy Outlook 2014
Liquid Fuels Market Module

Table 11.5. State and local taxes on petroleum transportation fuels by Census Division, as of May 2011

2012 dollars per gallon

Year/Product

Census Division

New

England

Middle

Atlantic

East

North

Central

West

North

Central

South

Atlantic

East

South

Central

West

South

Central Mountain Pacific

Gasoline1 0.46 0.42 0.40 0.40 0.36 0.37 0.37 0.39 0.39

Diesel 0.98 0.33 0.23 0.23 0.22 0.19 0.19 0.23 0.32

Liquefied Petroleum Gases 0.14 0.14 0.19 0.21 0.20 0.19 0.15 0.16 0.06

E852 0.22 0.23 0.18 0.17 0.15 0.16 0.15 0.17 0.27

Jet Fuel 0.07 0.06 0.00 0.04 0.08 0.08 0.03 0.05 0.03

1

Tax also applies to gasoline consumed in the commercial and industrial sectors.

2

E85 refers to a blend of 85% ethanol (renewable) and 15% motor gasoline (non-renewable). To address cold starting issues, the percentage of ethanol varies 

seasonally. The annual average ethanol content of 74% is used.

Source: “Compilation of United States Fuel Taxes, Inspection, Fees and Environmental Taxes and Fees,” Defense Energy Support Center, Editions 2011-09, 

May 18, 2011).

Table 11.6 Federal taxes, as of October 2011

nominal dollars per gallon

Product Tax

Gasoline 0.184

Diesel 0.244

Jet Fuel 0.04

E851 0.20

1

74% ethanol and 26% gasoline.

Sources: Omnibus Budget Reconciliation Act of 1993 (H.R. 2264); Tax Payer Relief Act of 1997 (PL 105-34), Clean Fuels Report (Washington, DC, April 1998) 

and Energy Policy Act of 2005 (PL 109-58). IRS Internal Revenue Bulletin 2006-43 available on the web at www.irs.gov/pub/irs-irbs/irb06-43.pdf.

Crude oil quality

In the LFMM, the quality of crude oil is characterized by average gravity and sulfur levels. Both domestic and imported crude oil 

are divided into nine categories as defined by the ranges of gravity and sulfur shown in Table 11.7.

A “composite” crude oil with the appropriate yields and qualities is developed for each category by averaging the characteristics 

of specific crude oil streams in the category. In the LFMM, the domestic and foreign categories are the same, and the composite 

crudes for each category are derived from both domestic and foreign crude characteristics. For domestic crude oil, estimates 

of total regional production are made first, then shared out to each of the nine categories based on their API gravity and sulfur 

content. For imported crude oil, a separate supply curve is provided (by the IEM) for each category.

Table 11.7. Crude oil specifications

Crude Oil Categories Sulfur (%) Gravity (degrees API)

Light Sweet <0.3 >35

Light Sour 0.3-1.1 >35

Medium Medium Sour 0.3-1.1 27-35

Medium Sour 1.1-2.6 27-35

Heavy Sweet 0.3-1.1 <27

Heavy Sour >2.6 <27

California 1.1-2.6 <27

Syncrude <0.3 27-35

DilBit/SynBit >2.6 <27

Source: Memorandum “Composite Crude Oils for the LFMM”, March 11, 2011, to Less Goudarzi, OnLocation, Inc, from Dave Hirshfeld, 

MathPro Inc. submitted to U.S. Energy Information Administration, Office of Energy Analysis, under contract number DT0001767, Oil and 

Gas Supply Module Development. Converted to ranges by OnLocation, Inc and EIA, 2011.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 143
Liquid Fuels Market Module

Capacity expansion

The LFMM allows for capacity expansion of all processing unit types including atmospheric distillation, vacuum distillation, 

hydrotreating, coking, fluid catalytic cracking, hydrocracking, and alkylation. Capacity expansion occurs by processing unit, 

starting from regional capacities established using historical data.

Expansion occurs in LFMM when the value received from the additional product sales exceeds the investment and operating 

costs of the new unit. The investment costs assume a financing ratio of 60% equity and 40% debt, with a hurdle rate and an 

after-tax return on investment of about 9%. The LFMM models capacity expansion using a three-period planning approach 

similar to that used in the NEMS Electricity Market Module (EMM). The first two periods contain a single planning year (current 

year and next year, respectively), and the third period represents a net present value of the next 19 years in the projection. The 

second and third planning periods work together to establish an economic plan for capacity expansion for the next NEMS model 

year. In period 2, product demands and legislative requirements must be met exactly. Period 3 acts like a leverage in the capacity 

expansion decision for period 2, and is controlled by the discount rate assumptions. Larger discount rates increase the relative 

impacts from early periods and decrease the impacts of the later periods. The LFMM has the option to use multiple discount 

rates for the NPV calculation to represent various categories of risk. For AEO2014, the LFMM uses an 18% discount rate. 

Capacity expansion is also modeled for production of corn and cellulosic ethanol, biobutanol, biomass pyrolysis oil, biodiesel, 

renewable diesel, coal-to-liquids, gas-to-liquids, and biomass-to-liquids. All process unit capacity that is expected to begin 

operating in the future is added to existing capacities in their respective start year. The retirement and replacement of existing 

refining capacity due to economics or life is not explicitly represented in the LFMM.

Non-petroleum fuel technology characteristics

The LFMM explicitly models a number of liquid fuels technologies that do not require petroleum feedstock. These technologies 

produce both fuel-grade products for blending with traditional petroleum products, and alternative feedstock for the traditional 

petroleum refinery (Table 11.8).

Table 11.8 Alternative fuel technology product type

Technology Product Type

Biochemical

Corn Ethanol Fuel Grade

Advanced Grain Ethanol Fuel Grade

Cellulosic Ethanol Fuel Grade

Biobutanol Fuel Grade

Thermochemical Catalytic

Methyl Ester Biodiesel Fuel Grade

Non-Ester Renewable Diesel Fuel Grade

Pyrolysis Fuel Grade

Thermochemical Fischer-Tropsch

Gas-to-Liquids (GTL) Fuel Grade/Refinery Feed

Coal-to-Liquids (CTL) Fuel Grade/Refinery Feed

Biomass-to-Liquids (BTL) Fuel Grade/Refinery Feed

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Estimates of capital and operating costs corresponding to specified nameplate capacities for these technologies are shown 

in Table 11.9. The cost data are defined assuming a 2020 base year, and are deflated to 2012 dollars using the GDP deflator in 

NEMS. 

Overnight Capital Cost is defined as the anticipated cost for a standard size commercial-scale plant. Since some components 

of technologies have not yet been proven at a commercial scale, a technology optimism factor is applied to the assumed firstof-a-kind capital cost, a multiplier that increases the first-of-a-kind plant cost (e.g., 1.25). The multiplier is an estimate of the 

underestimated construction errors (redos) and underestimated costs in building the first full-scale commercial plant. As 

experience is gained (after building the first 4 units), the technological optimism factor is gradually reduced to 1.0.

144 U.S. Energy Information Administration | Assumptiions to the Annual Energy Outlook 2014
Liquid Fuels Market Module

As a new technology matures, the capital cost is expected to decline, reflecting the principle of “learn by doing” and 

manufacturing experience. This principle is implemented in the LFMM similar to the methodology used in the EMM. The 

learning occurs in three phases. The first phase is represented by the linear phase out of optimism (and some revolutionary 

learning) over the first four plants (such that the optimism factor for the fifth and later plant is 1.0). The non-linear learning 

function shown above is used for the second (up to 32 plants built) and third (beyond 32 plants) phases..

Each technology was assessed to determine the mix of technological maturity of each component (revolutionary/evolutionary 

or mature). This was used to define what percent (m) of the cost would decline slowly (slow for mature) versus quickly (fast for 

evolutionary/revolutionary) due to learning. Next, for each learning category (fast and slow), a rate of learning (f) is assumed 

(i.e., a percent reduction in overnight capital cost for every doubling of cumulative capacity). 

The overall learning factor is the weighted combination of the fast and slow learning factors (OC), weighted by the percentage 

that each component represents of the technology. Model parameters are shown in Table 11.10.

Non-petroleum fuels market dynamics

In the LFMM, overnight capital costs are amortized and then added to variable and fixed costs in order to provide a cost of 

production [8]. As a result of this inclusion of capital cost in the cost of production, a given technology’s production cost has the 

potential to become more or less attractive relative to other technologies as plants are built.

While cost of production defines a basis for comparison, market competition is often defined by the required feedstock. For 

example, technologies requiring greases and oils (biodiesel and renewable diesel) compete with each other for that feedstock, 

limiting the overall market share of each technology. As a consequence of this and the Renewable Fuels Standard, cellulosic 

ethanol and Biomass-to-Liquids (BTL) technologies, which include Fischer-Tropsch and Pyrolysis, compete directly with each 

other. By contrast, technologies like Gas-to-Liquids and Coal-to-Liquids compete more directly with petroleum fuels, since their 

feedstocks are more similar to petroleum, and their fuels do not count toward RFS requirements.

The learning function has the nonlinear form:

 OC(C) = a*C-b, 

where C is the cumulative capacity (or number of standard-sized units) for each technology component and OC represents the 

overnight capital cost expected with cumulative capacity C of the technology.

The learning function in NEMS is determined at a component level. Each new technology is broken into its major components, 

and each component is identified as revolutionary, evolutionary or mature. Different learning rates are assumed for each 

component, based on the level of construction experience with the component. In the case of the LFMM, the second and third 

phases of a technology will have only evolutionary/revolutionary (fast) and mature (slower) learning components, depending on 

the mix (percent) of new and mature processes that compose a particular technology.

The progress ratio (pr) is related by the speed of learning or learning rate (LR) (e.g., how much costs decline for every doubling 

of capacity). The reduction in capital cost for every doubling of cumulative capacity (LR) is an exogenous input parameter for 

each component. The progress ratio and LR are related by:

 pr = 2-b = (1 - LR) .

The parameter “b” is calculated from the second half of the equality above:

 b =-(ln(1-LR)/ln(2)).

The parameter “a” is computed from initial overnight cost and capacity conditions of the nonlinear learning curve.

 a = OC(C0)/Co-b

Note that Co is the cumulative capacity or number of units built as of the beginning of the current time period/year. 

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 145
Liquid Fuels Market Module

Table 11.9. Non-petroleum fuel technology characteristics1

US Gulf Coast

AEO2014 2020 Basis 

(2012$)

Online 

Year

Nameplate 

Capacity2

Base 

Overnight 

Capital

Contingency

 Factors3,4

Total 

Overnight 

Capital5

Feedstock 

Cost6

Non--

Feedstock 

O&M7

Thermal 

Efficiency8

barrels/day $/daily barrel Project Optimism

$/daily 

barrel

$/daily 

barrel

$/daily 

barrel

Energy 

%

Biochemical

Corn Ethanol - 6,800 $18,200 3% 0% $18,700 $69 $16 49%

Advanced Grain Ethanol 2014 3,400 $43,400 3% 0% $44,700 $73 $16 49%

Cellulosic Ethanol 2013 4,400 $114,000 10% 20% $150,500 $11 $16 28%

Biobutanol (retrofit of corn 

ethanol plant) 2015 6,500 $9,500 10% 20% $12,540 $87 $0 62%

Thermochemical Catalytic

Methyl Ester Biodiesel (FAME) - 1,200 $19,700 3% 0% $20,300 $192 $29 21%

Non-Ester Renewable Diesel 

(NERD) - 2,100 $28,000 10% 0% $30,800 $187 $20 21% 

Pyrolysis 2013 5,200 $232,000 10% 20% $306,230 $14 $20 60%

Thermochemical Fisher-Tropsch

Gas–to-Liquids (GTL)9 2018 48,000 $126,000 10% 10% $152,500 $60 $18 55% 

Coal-to-Liquids (CTL) 2018 48,000 $150,000 10% 15% $189,800 $45 $15 49%

Biomass-to-Liquids (BTL) 2020 6,000 $262,000 10% 20% $345,800 $34 $16 45%

1

This table is based on the AEO2014 Reference case projections for year 2020. 2

 For all processes except corn ethanol and FAME biodiesel, annual capacity refers to the capacity of one plant as defined in the Liquid Fuels Market Module 

of NEMS. For corn ethanol and FAME biodiesel, annual capacity is the most common plant size as of 2013.

3

Contingency is defined by the American Association of Cost Engineers as a “specific provision for unforeseeable elements in costs within a defined project 

scope; particularly important where previous experience has shown that unforeseeable events which will increase costs are likely to occur.”

4The technology optimism factor is applied to the first four units of an unproven design, reflecting a demonstrated tendency to underestimate costs for a 

first-of-a-kind unit.

5

Total Overnight cost including contingency factors, excluding regional multipliers, learning effects, and interest charges.

6

Feedstock costs include cost of materials being converted to liquid fuels.

7

Non-feedstock operating and maintenance (O&M) costs include labor cost and other variable costs.

8

A soybean oil mass yield of 20% is assumed in the crush facility in order to compute yield. Efficiency is defined as the heat content of the liquid products 

divided by the heat content of the feedstock.

9

While these costs are for a Gulf Coast facility, the costs in other regions, particularly Alaska, are expected to be much higher.

Sources: The values shown in this table are developed by the Energy Information Administration, Office of Analysis, PNGBA, from analysis of reports and 

discussions with various sources from industry, government, and the Department of Energy Fuel Offices and National Laboratories. They are meant to 

represent the cost and performance of typical plants under normal operating conditions for each technology. Key sources reviewed are listed in “Notes and 

Sources” at the end of the chapter.

146 U.S. Energy Information Administration | Assumptiions to the Annual Energy Outlook 2014
Liquid Fuels Market Module

Table 11.10. Non-petroleum fuel technology learning parameters

Cumulative Plants (k)

Phase 1

1st of a Kind

 Phase 2

5th of a Kind

 Phase 3

32nd of a Kind

Technology Type Optimism Fast1 slow1 Fast1 Slow1

Cellulosic Ethanol

Optimism Factor and 

Revolutionary Learning 1.25 1.0 1.0 1.0 1.0

Learning Type Fraction (m) -- 33% 67% 33% 67%

Learning Rate (f) -- 0.25 0.10 0.10 0.05

Pyrolysis

Optimism Factor and 

Revolutionary Learning 1.25 1.0 1.0 1.0 1.0

Learning Type Fraction (m) -- 33% 67% 33% 67%

Learning Rate (f) -- 0.25 1.0.10 0.10 0.05

Biomass-to-Liquids (BTL)

Optimism Factor and 

Revolutionary Learning 1.25 1.0 1.0 1.0 1.0

Learning Type Fraction (m) -- 15% 85% 15% 85%

Learning Rate (f) -- 0.10 0.01 0.10 0.01

Coal-to-Liquids (CTL)

Optimism Factor and 

Revolutionary Learning 1.25 1.0 1.0 1.0 1.0

Learning Type Fraction (m) -- 15% 85% 15% 85%

Learning Rate (f) -- 0.10 0.01 0.10 0.01

Gas-to-Liquids (GTL)

Optimism Factor and 

Revolutionary Learning 1.25 1.0 1.0 1.0 1.0

Learning Type Fraction (m) -- 10% 90% 10% 90%

Learning Rate (f) -- 0.10 0.01 0.10 0.01

1

Fast = evolutionary/revolutionary learning; slow = mature learning.

Source: U.S. Energy Information Administration.

Biofuels supply

Supply functions for corn, non-corn grain, and cellulosic biomass feedstocks are provided on an annual basis through 2040 for 

the production of ethanol (blended into transportation fuel). Supply functions for soy oil, other seed-based oils, and grease are 

provided on an annual basis through 2040 for the production of biodiesel and renewable diesel.

•	 Potential RFS target reductions by EPA are provided exogenously to NEMS.

•	 Corn feedstock supplies and costs are provided exogenously to NEMS. Feedstock costs reflect credits for co-products 

(livestock feed, corn oil, etc.). Feedstock supplies and costs reflect the competition between corn and its co-products and 

alternative crops, such as soybeans and their co-products.

•	 Biodiesel and renewable diesel feedstock supplies and costs are provided exogenously to NEMS. 

•	 Cellulosic (biomass) feedstock supply and costs are provided by the Renewable Fuels Module in NEMS. To model the 

Renewable Fuels Standard in EISA2007, several assumptions were required.

•	 The penetration of cellulosic ethanol into the market is limited before 2020 to several planned projects with aggregate 

nameplate capacity of approximately 185 million gallons per year. Planned capacity through 2019 for Pyrolysis and Biomass-toLiquids processes is approximately 110 million gallons per year.

•	 Methyl ester biodiesel production contributes 1.5 credits towards the advanced mandate.

•	 Renewable diesel fuel and cellulosic diesel fuel, including that from Pyrolysis oil, and Fischer-Tropsch diesel contribute 1.7 

credits toward the cellulosic mandate.

•	 Cellulosic drop-in gasoline contributes 1.54 credits toward the cellulosic mandate.

•	 Imported Brazilian sugarcane ethanol counts towards the advanced renewable mandate.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 147
Liquid Fuels Market Module

•	 Separate biofuel waivers can be activated for each of the four RFS fuel categories.

•	 Biodiesel and BTL diesel are assumed to be compatible with diesel engines without significant infrastructure modification 

(either vehicles or delivery infrastructure).

•	 Ethanol is assumed to be consumed as E10, E15 or E85, with no intermediate blends. The cost of placing E85 pumps at the 

most economic stations is spread over diesel and gasoline.

•	 To accommodate the ethanol requirements in particular, transportation modes are expanded or upgraded for E10, E15 and E85, 

and it is assumed that most ethanol originates from the Midwest, with nominal transportation costs of a few cents per gallon.

•	 For E85 dispensing stations, it is assumed the average cost of a retrofit and new station is about $152,700 per station (2012 

dollars). Interregional transportation is assumed to be by rail, ship, barge, and truck, and the associated costs are included in 

the LFMM.

Non-petroleum fossil fuel supply

Gas-to-liquids (GTL) facilities convert natural gas into distillates, and are assumed to be built if the prices for lower-sulfur 

distillates reach a high enough level to make them economic. The earliest start date for a GTL facility is set at 2018.

It is also assumed that coal-to-liquids (CTL) facilities will be built when low-sulfur distillate prices are high enough to make them 

economic. A 48,000-barrel-per-day CTL facility is assumed to cost over $7 billion in initial capital investment (2012 dollars). 

These facilities could be built near existing refineries. For the East Coast, potential CTL facilities could be built near the Delaware 

River basin; for the Central region, near the Illinois River basin or near Billings, Montana; and for the West Coast, in the vicinity of 

Puget Sound in Washington State. It is further assumed that CTL facilities can only be built after 2018.

Combined heat and power (CHP)

Electricity consumption at the refinery and other liquid fuels production facilities is a function of the throughput of each unit. 

Sources of electricity consist of refinery power generation, utility purchases, and CHP from other liquid fuels producers (including 

cellulosic/advanced ethanol, coal and biomass to liquids). Power generators and CHP plants are modeled in the LFMM linear 

program as separate units, and are allowed to compete along with purchased electricity. Operating characteristics for these 

electricity producers are based on historical parameters and available data. Sales to the grid or own-use decisions are made on 

an economic basis within the LP solution. The price for electricity sales to the grid is set to the marginal energy price for baseload 

generation (provided by the EMM).

Short-term methodology

Petroleum balance and price information for 2013 and 2014 are projected at the U.S. level in the Short-Term Energy Outlook, 

(STEO). The LFMM adopts the STEO results for 2013 and 2014, using regional estimates derived from the national STEO 

projections.

Legislation and regulation

The Tax Payer Relief Act of 1997 reduced excise taxes on liquefied petroleum gases and methanol produced from natural gas. The 

reductions set taxes on these products equal to the Federal gasoline tax on a Btu basis.

Title II of CAAA90 established regulations for oxygenated and reformulated gasoline and on-highway diesel fuel. These are 

explicitly modeled in the LFMM. Reformulated gasoline represented in the LFMM meets the requirements of Phase 2 of the 

Complex Model, except in the Pacific region where it meets CARB 3 specifications.

AEO2014 reflects “Tier 2” Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements which requires that the 

average annual sulfur content of all gasoline used in the United States be 30 ppm.

AEO2014 reflects Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements. All highway 

diesel is required to contain no more than 15 ppm sulfur at the pump.

AEO2014 reflects nonroad locomotive and marine (NRLM) diesel requirements that nonroad diesel supplies contain no more 

than 15 ppm sulfur. For locomotive and marine diesel, the action establishes a NRLM limit of 15 ppm in mid-2012.

AEO2014 represents major provisions in the Energy Policy Act of 2005 (EPACT05) concerning the petroleum industry, including 

removal of the oxygenate requirement in RFG.

148 U.S. Energy Information Administration | Assumptiions to the Annual Energy Outlook 2014
Liquid Fuels Market Module

AEO2014 includes provisions outlined in the Energy Independence and Security Act of 2007 (EISA2007) concerning the 

petroleum industry, including a Renewable Fuels Standard (RFS) increasing total U.S. consumption of renewable fuels. In order 

to account for the possibility that RFS targets might be unattainable at reasonable cost, LFMM includes a provision for purchase 

of waivers. The price of a cellulosic waiver is specified in EISA2007. The non-cellulosic LFMM RFS waivers function as maximum 

allowed RIN prices. LFMM also assumes that EPA will reduce RFS targets as allowed by the EISA2007 statute.

AEO2014 includes the EPA Mobil Source Air Toxics (MSAT 2) rule which includes the requirement that all gasoline products 

(including reformulated and conventional gasoline) produced at a refinery during a calendar year will need to contain no more than 

0.62 percent benzene by volume. This does not include gasoline produced or sold in California, which is already covered by the 

current California Phase 3 Reformulated Gasoline Program.

AEO2014 includes California’s Low Carbon Fuel Standard which aims to reduce the Carbon Intensity (CI) of gasoline and diesel 

fuels in that state by about 10% respectively from 2012 through 2020.

AEO2014 incorporates the cap-and-trade program within the California Assembly Bill (AB 32), the Global Warming Solutions Act 

of 2006. The program started January 1, 2012, with enforceable compliance obligations beginning in 2013. Petroleum refineries 

are given allowances (calculated in the LFMM) in the cap-and-trade system based on the volumetric output of aviation gasoline, 

motor gasoline, kerosene-type jet fuel, distillate fuel oil, renewable liquid fuels and asphalt. Suppliers of RBOB and Distillate Fuel 

Oil #1 and #2 are required to comply starting in 2015 if the emissions from full combustion of these products are greater than or 

equal to 25,000 metric tons CO2 equivalent (MTCO2e) in any year 2011-2014.

AEO2014 includes mandates passed in 2010 by Connecticut, Maine, New York, and New Jersey that aim to lower the sulfur 

content of all heating oil to ultra-low-sulfur diesel over different time schedules. It also includes transition to a 2% biodiesel 

content in the case of Maine and Connecticut.

Due to the uncertainty surrounding compliance options, AEO2014 did not include any explicit modeling treatment of the 

International Maritime Organization’s “MARPOL Annex 6” rule covering cleaner marine fuels and ocean ship engine emissions.

The AEO2014 Reference Case does not include proposed but not yet enacted extensions of the $1.00-per-gallon biodiesel excise 

tax credit or the $1.01-per-gallon cellulosic biofuels production tax credit.

Notes and sources

 [1] Federal Register, U.S. Environmental Protection Agency, 40 CFR Part 80, Regulation of Fuels and Fuel Additives: Standards for 

Reformulated and Conventional Gasoline, Rules and Regulations, p. 7800, (Washington, DC, February 1994).

[2] Marano, John, “Alternative Fuels Technology Profile: Cellulosic Ethanol”, March 2008. 

[3] Ibid.

[4] U.S. Department of Agriculture, “USDA Agricultural Baseline Projections to 2019,” February 2009, 

www.ers.usda.gov/publications/oce-usda-agricultural-projections/oce-2010-1.aspx.

[5] Shapouri, Hosein and Gallagher, Paul. USDA’s 2002 Ethanol Cost-of-Production Survey, July 2005.

[6] U.S. Department of Agriculture. 2008 Energy Balance for the Corn-Ethanol Industry, June 2010.

[7] American Petroleum Institute, How Much We Pay for Gasoline: 1996 Annual Review, May 1997.

[8] Economic lifetime is 20 years for cellulosic ethanol, biomass Fischer-Tropsch, and Pyrolysis Oil. Required rate of return is calculated using a 60:40 debt-to-equity ratio and the capital asset pricing model for the cost of equity.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 149
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Coal Market Module
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Coal Market Module

The NEMS Coal Market Module (CMM) provides projections of U.S. coal production, consumption, exports, imports, 

distribution, and prices. The CMM comprises three functional areas: coal production, coal distribution, and coal exports. A 

detailed description of the CMM is provided in the EIA publication, Coal Market Module of the National Energy Modeling 

System 2014, DOE/EIA-M060(2014) (Washington, DC, 2014).

Key assumptions

Coal production

The coal production submodule of the CMM generates a different set of supply curves for the CMM for each year of the 

projection. Combinations of 14 supply regions, nine coal types (unique groupings of thermal grade and sulfur content), and two 

mine types (underground and surface), result in 41 separate supply curves. Supply curves are constructed using an econometric 

formulation that relates the minemouth prices of coal for the supply regions and coal types to a set of independent variables. 

The independent variables include: capacity utilization of mines, mining capacity, labor productivity, the user cost of capital of 

mining equipment, the cost of factor inputs (labor and fuel), and other mine supply costs.

The key assumptions underlying the coal production modeling are:

•	 As capacity utilization increases, higher minemouth prices for a given supply curve are projected. The opportunity to add 

capacity is allowed within the modeling framework if capacity utilization rises to a pre-determined level, typically in the 80% 

range. Likewise, if capacity utilization falls, mining capacity may be retired. The amount of capacity that can be added or 

retired in a given year depends on the level of capacity utilization, the supply region, and the mining process (underground or 

surface). The volume of capacity expansion permitted in a projection year is based upon historical patterns of capacity additions.

•	 Between 1980 and 2000, U.S. coal mining productivity increased at an average rate of 6.6% per year, from 1.93 to 6.99 short 

tons per miner per hour. The major factors underlying these gains were interfuel price competition, structural change in 

the industry, and technological improvements in coal mining [1]. Since 2000, however, growth in overall U.S. coal mining 

productivity has been negative, declining at a rate of 2.4% per year to 5.19 short tons per miner-hour in 2012. By region, productivity in all but one (Alaska/Washington) of the coal producing basins represented in the CMM has declined some during 

the past 12 years. In the Central Appalachian coal basin, which has been mined extensively, productivity declined by 52% 

between 2000 and 2012, corresponding to an average decline of 5.9% per year. While productivity declines have been more 

moderate at the highly productive mines in Wyoming’s Powder River Basin, coal mining productivity in this region still fell by 

32% between 2000 and 2012 corresponding to an average rate of decline of 3.1% per year. Of the coal producing regions, the 

Eastern Interior has shown the best overall performance with coal mining productivity declining by only 9% between 2000 

and 2012, or 0.8% per year. The Eastern Interior region, which has a substantial amount of thick, underground-minable coal 

reserves, is currently experiencing a resurgence in coal mining activity with several coal companies either opening or in the 

process of opening new, highly-productive longwall mines.

•	 Over the projection period, labor productivity is expected to decline in most coal supply regions, reflecting the trend of the 

previous decade. Higher stripping ratios and the added labor needed to maintain more extensive underground mines offset 

productivity gains achieved from improved equipment, automation, and technology. Productivity in some areas of the East is 

projected to decline as operations move from mature coalfields to marginal reserve areas. Regulatory restrictions on surface 

mines and fragmentation of underground reserves limit the benefits that can be achieved by Appalachian producers from 

economies of scale.

•	 In the CMM, different rates of productivity improvement are assumed for each of the 41 coal supply curves used to represent 

U.S. coal supply. These estimates are based on recent historical data and expectations regarding the penetration and impact 

of new coal mining technologies. Data on labor productivity are provided on a quarterly and annual basis by individual coal 

mines and preparation plants on the U.S. Department of Labor, Mine Safety and Health Administration’s Form 7000-2, 

“Quarterly Mine Employment and Coal Production Report,” and the U.S. Energy Information Administration’s Form EIA-7A, 

“Coal Production and Preparation Report”. In the Reference case, overall U.S. coal mining labor productivity declines at rate 

of 1.2% per year between 2012 and 2040. Reference case projections of coal mining productivity by region are provided in 

Table 12.1.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 153
Coal Market Module

Table 12.1. Coal mining productivity by region

short tons per miner hour

Supply Region 2012 2020 2025 2030 2035 2040

Average Annual 

Growth 12-40

Northern Appalachia 3.08 2.60 2.46 2.31 2.22 2.13 -1.3%

Central Appalachia 2.01 1.34 1.12 0.93 0.85 0.77 -3.4%

Southern Appalachia 1.68 1.33 1.22 1.12 1.05 0.99 -1.9%

Eastern Interior 4.29 4.39 4.38 4.40 4.39 4.39 0.1%

Western Interior 2.20 1.68 1.50 1.34 1.25 1.15 -2.3%

Gulf Lignite 6.93 6.14 5.84 5.55 5.36 5.18 -1.0%

Dakota Lignite 11.56 10.24 9.74 9.26 8.94 8.64 -1.0%

Western Montana 14.50 11.52 11.45 11.02 10.36 9.98 -1.3%

Wyoming, Northern Powder River Basin 29.17 24.01 22.15 20.43 19.33 18.29 -1.7%

Wyoming, Southern Powder River Basin 32.30 26.59 24.53 22.63 21.41 20.26 -1.7%

Western Wyoming 6.73 6.03 5.68 5.05 4.48 4.29 -1.6%

Rocky Mountain 5.50 4.09 3.62 3.20 2.97 2.74 -2.5%

Arizona/New Mexico 7.93 7.72 7.57 6.87 6.69 6.56 -0.7%

Alaska/Washington 5.98 6.35 6.51 6.67 6.77 6.88 0.5%

U.S. Average 5.19 4.64 4.35 4.02 3.81 3.68 -1.2%

Source: U.S. Energy Information Administration, AEO2014 National Energy Modeling System run REF2014.D102413A.

•	 In the AEO2014 Reference case, the wage rate for U.S. coal miners increases by 0.9% per year and mine equipment costs 

are assumed to remain constant in 2012 dollars (i.e., increase at the general rate of inflation) over the projection period.

Coal distribution

The coal distribution submodule of the CMM determines the least-cost (minemouth price plus transportation cost) supplies of 

coal by supply region for a given set of coal demands in each demand sector using a linear programming algorithm. Production 

and distribution are computed for 14 supply (Figure 11) and 16 demand regions (Figure 12) for 49 demand subsectors.

The projected levels of coal-to-liquids, industrial steam, coking, and commercial/institutional coal demand are provided by 

the liquid fuel market, industrial, and commercial demand modules, respectively; electricity coal demands are projected by 

the Electricity Market Module (EMM) coal imports and coal exports are projected by the CMM based on non-U.S. supply 

availability, endogenously determined U.S. import demand, and exogenously determined world coal import demands (nonU.S.).

The key assumptions underlying the coal distribution modeling are:

•	 Base-year (2012) transportation costs are estimates of average transportation costs for each origin-destination pair without differentiation by transportation mode (rail, truck, barge, and conveyor). These costs are computed as the difference 

between the average delivered price for a demand region (by sector and for export) and the average minemouth price for 

a supply curve. Delivered price data are from Form EIA-3, “Quarterly Coal Consumption and Quality Report, Manufacturing and Transformation/Processing Coal Plants and Commercial and Institutional Coal Users”, Form EIA-5, Quarterly Coal 

Consumption and Quality Report, Coke Plants”, Form EIA-923, “Power Plant Operations Report”, and the U.S. Bureau of the 

Census, “Monthly Report EM-545”. Minemouth price data are from Form EIA-7A, “Coal Production and Preparation Report”.

•	 For the electricity sector only, a two-tier transportation rate structure is used for those regions which, in response to rising 

demands or changes in demands, may expand their market share beyond historical levels. The first-tier rate is representative of the historical average transportation rate. The second-tier transportation rate is used to capture the higher cost of 

expanded shipping distances in large demand regions. The second tier is also used to capture costs associated with the use 

of subbituminous coal at units that were not originally designed for its use. This cost is estimated at $0.10 per million Btu 

(2000 dollars) [2].

154 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

Figure 11. Coal Supply Regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 155
Coal Market Module

•	 Coal transportation costs, both first- and second-tier rates, are modified over time by two regional (east and west) transportation indices. The indices, calculated econometrically, are measures of the change in average transportation rates for 

coal shipments on a tonnage basis, which occurs between successive years for coal shipments. An east index is used for 

coal originating from coal supply regions located east of the Mississippi River while a west index is used for coal originating from coal supply regions located west of the Mississippi River. The east index is a function of railroad productivity, 

the user cost of capital for railroad equipment, and national average diesel fuel price. The user cost of capital for railroad 

equipment is calculated from the producer price index (PPI) for railroad equipment, and accounts for the opportunity cost 

of money used to purchase equipment, depreciation occurring as a result of use of the equipment (assumed at 10%), 

less any capital gain associated with the worth of the equipment. In calculating the user cost of capital, three percentage 

points are added to the cost of borrowing in order to account for the possibility that a national level program to regulate greenhouse gas emissions may be implemented in the future. The west index is a function of railroad productivity, 

investment, and the western share of national coal consumption. The indices are universally applied to all domestic coal 

transportation movements within the CMM. In the AEO2014 Reference case, both eastern and western coal transportation rates are projected to remain near their 2012 levels in 2012 dollars.

Figure 12. Coal Demand Regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

156 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

•	 For the projection period, the explanatory variables are assumed to have varying impacts on the calculation of the indices. For 

the west, investment is the analogous variable to the user cost of capital of railroad equipment. The investment value and the 

PPI for rail equipment, which is used to derive the user cost of capital, increase with an increase in national ton-miles (total 

tons of coal shipped multiplied by the average distance). Increases in investment (west) or the user cost of capital for railroad equipment (east) cause projected transportation rates to increase. For both the east and the west, any related financial 

savings due to productivity improvements are assumed to be retained by the railroads and are not passed on to shippers in 

the form of lower transportation rates. For that reason, transportation productivity is held flat for the projection period for 

both regions. For the projection period, diesel fuel is removed from the equation for the east in order to avoid double-counting 

the influence of diesel fuel costs with the impact of the fuel surcharge program. The transportation rate indices for seven 

AEO2014 cases are shown in Table 12.2.

Table 12.2. Transportation rate multipliers

constant dollar index, 2012=1.000

Scenario Region: 2012 2020 2025 2030 2035 2040

Reference Case East 1.0000 1.0224 1.0121 1.0086 1.0074 1.0083

West 1.0000 1.0051 1.0140 1.0117 1.0036 0.9964

Low Oil Price East 1.0000 1.0182 1.0091 1.0045 1.0003 1.0053

West 1.0000 1.0125 1.0250 1.0303 1.0177 1.0148

High Oil Price East 1.0000 1.0360 1.0175 1.0122 1.0137 1.0156

West 1.0000 0.9943 1.0038 1.0002 0.9944 1.0025

Low Economic Growth East 1.0000 1.0294 1.0195 1.0186 1.0214 1.0028

West 1.0000 1.0008 1.0043 1.0019 0.9952 0.9857

High Economic Growth East 1.0000 1.0177 1.0076 1.0036 1.0027 1.0037

West 1.0000 1.0141 1.0229 1.0223 1.0152 1.0053

Low Coal Cost East 1.0000 0.9600 0.9000 0.8500 0.8000 0.7600

West 1.0000 0.9400 0.9000 0.8500 0.8000 0.7500

High Coal Cost East 1.0000 1.0900 1.1200 1.1700 1.2100 1.2600

West 1.0000 1.0700 1.1300 1.1700 1.2100 1.2500

Source: Projections: U.S. Energy Information Administration, National Energy Modeling System runs REF2014.D102413A, LOWPRICE.D120613A, HIGHPRICE.

D120613A, LOWMACRO.D112913A, HIGHMACRO.D112913A, LCCST14.D120413A, and HCCST14.D120413A. Based on methodology described in Coal Market 

Module of the National Energy Modeling System 2014, DOE/EIA-M060(2014) (Washington, DC, 2014).

•	 Major coal rail carriers have implemented fuel surcharge programs in which higher transportation fuel costs have been passed 

on to shippers. While the programs vary in their design, the Surface Transportation Board (STB), the regulatory body with 

limited authority to oversee rate disputes, recommended that the railroads agree to develop some consistencies among their 

disparate programs and likewise recommended closely linking the charges to actual fuel use. The STB cited the use of a 

mileage-based program as one means to more closely estimate actual fuel expenses.

•	 For AEO2014, representation of a fuel surcharge program is included in the coal transportation costs. For the west, the methodology is based on BNSF Railway Company’s mileage-based program. The surcharge becomes effective when the projected 

nominal distillate price to the transportation sector exceeds $1.25 per gallon. For every $0.06 per gallon increase above $1.25, 

a $0.01 per carload mile is charged. For the east, the methodology is based on CSX Transportation’s mileage-based program. 

The surcharge becomes effective when the projected nominal distillate price to the transportation sector exceeds $2.00 per 

gallon. For every $0.04 per gallon increase above $2.00, a $0.01 per carload mile is charged. The number of tons per carload 

and the number of miles vary with each supply and demand region combination and are a pre-determined model input. The 

final calculated surcharge (in constant dollars per ton) is added to the escalator-adjusted transportation rate. For every projection year, it is assumed that 100% of all coal shipments are subject to the surcharge program.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 157
Coal Market Module

•	 Coal contracts in the CMM represent a minimum quantity of a specific electricity coal demand that must be met by a unique 

coal supply source prior to consideration of any alternative sources of supply. Base-year (2012) coal contracts between coal 

producers and electricity generators are estimated on the basis of receipts data reported by generators on the Form EIA-923, 

“Power Plant Operations Report”. Coal contracts are specified by CMM supply region, coal type, demand region, and whether 

or not a unit has flue gas desulfurization equipment. Coal contract quantities are reduced over time on the basis of contract 

duration data from information reported on the Form EIA-923, “Power Plant Operations Report”, historical patterns of coal use, 

and information obtained from various coal and electric power industry publications and reports. 

•	 Coal-to-liquids (CTL) facilities are assumed to be economic when low-sulfur distillate prices reach high enough levels. These 

plants are assumed to be co-production facilities with generation capacity of 832 megawatts (MW) (295 MW for the grid 

and 537 MW to support the conversion process) and the capability of producing 48,000 barrels of liquid fuels per day. The 

technology assumed is similar to an integrated gasification combined cycle, first converting the coal feedstock to gas, and 

then subsequently converting the syngas to liquid hydrocarbons using the Fisher-Tropsch process. Of the total amount of coal 

consumed at each plant, 40% of the energy input is retained in the product with the remaining energy used for conversion and 

for the production of power sold to the grid. For AEO2014, coal-biomass-to-liquids (CBTL) are not modeled. CTL facilities 

produce paraffinic naptha used in plastics production and blendable naptha used in motor gasoline (together about 28% of the 

total by volume) and distillate fuel oil (about 72%).

Coal imports and exports

Coal imports and exports are modeled as part of the CMM’s linear program that provides annual projections of U.S. steam and 

metallurgical coal exports, in the context of world coal trade. The CMM projects steam and metallurgical coal trade flows from 17 

coal-exporting regions of the world to 20 import regions for two coal types (steam and metallurgical). It includes five U.S. export 

regions and four U.S. import regions. The linear program determines the pattern of world coal trade flows that minimizes the 

production and transportation costs of meeting U.S. import demand and a pre-specified set of regional coal import demands. It 

does this subject to constraints on export capacity and trade flows.

The key assumptions underlying coal export modeling are:

•	 Coal buyers (importing regions) tend to spread their purchases among several suppliers in order to reduce the impact of 

potential supply disruptions, even though this may add to their purchase costs. Similarly, producers choose not to rely on any 

one buyer and instead endeavor to diversify their sales.

•	 Coking coal is treated as homogeneous. The model does not address quality parameters that define coking coals. The values 

of these quality parameters are defined within small ranges and affect world coking coal flows very little. 

The data inputs for coal trade modeling are:

•	 World steam and metallurgical coal import demands for the AEO2014 cases (Tables 12.3 and 12.4). U.S. coal exports are 

determined, in part, by these estimates of world coal import demand. 

•	 Step-function coal export supply curves for all non-U.S. supply regions. The curves provide estimates of export prices per metric ton, inclusive of minemouth and inland freight costs, as well as the capacities for each of the supply steps.

•	 Ocean transportation rates (in dollars per metric ton) for feasible coal shipments between international supply regions and international demand regions. The rates take into account typical vessel sizes and route distances in thousands of nautical miles 

between supply and demand regions.

Coal quality

Each year the values of base year coal production; heat, sulfur, and mercury content; and carbon dioxide emission factors for 

each coal source in CMM are calibrated to survey data. Surveys used for this purpose are the Form EIA-923, a survey of the 

origin, cost and quality of fossil fuels delivered to generating facilities, the Form EIA-3, which records the origin, cost, and quality 

of coal delivered to U.S. manufacturers, transformation and processing plants, and commercial and institutional users, and the 

Form EIA-5, which records the origin, cost and quality of coal delivered to domestic coke plants. Estimates of coal quality for the 

export sector are based on coal quality data collected on EIA surveys for domestic shipments. Mercury content data for coal by 

supply region and coal type, in units of pounds of mercury per trillion Btu, shown in Table 12.5, were derived from shipment-level 

data reported by electricity generators to the U.S. Environmental Protection Agency in its 1999 Information Collection Request. 

Carbon dioxide emission factors for each coal type, based on data published by the U.S. Environmental Protection Agency, are 

shown in Table 12.5 in units of pounds of carbon dioxide emitted per million Btu [3].

158 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

Table 12.3. World steam coal import demand by import region1

million metric tons of coal equivalent

2012 2020 2025 2030 2035 2040

The Americas 30.8 29.3 28.7 29.4 32.2 32.9

 United States2 6.4 0.8 0.4 0.0 0.8 0.0

 Canada 3.5 2.0 1.2 0.7 0.7 0.7

 Mexico 6.0 6.6 6.5 7.1 7.5 7.5

 South America 14.9 19.9 20.6 21.6 23.2 24.7

Europe 165.9 188.5 185.8 181.7 176.7 172.6

 Scandinavia 8.2 6.6 5.9 5.0 4.6 4.1

 U.K./Ireland 36.0 29.2 26.4 24.6 22.8 20.1

 Germany/Austria/Poland 39.3 38.8 37.8 36.8 35.8 34.8

 Other NW Europe 15.4 21.6 20.5 19.5 18.5 17.5

 Iberia 17.5 17.3 16.9 16.9 15.7 14.0

 Italy 14.3 22.8 21.9 20.1 18.2 16.4

 Med/E Europe 35.2 52.2 56.4 58.8 61.1 65.7

Asia 561.0 626.6 684.5 739.1 795.9 849.0

 Japan 94.2 94.3 93.5 92.2 90.6 88.0

 East Asia 123.9 129.0 134.4 136.5 144.5 149.9

 China/Hong Kong 189.0 212.8 236.3 258.1 272.2 286.2

 ASEAN 44.1 60.0 79.3 94.9 113.0 131.2

 Indian Sub 109.8 130.5 141.0 157.4 175.6 193.7

TOTAL 757.7 844.4 899.0 950.2 1,004.8 1,054.5

1

Import Regions: United States: East Coast, Gulf Coast, Northern Interior, Non-Contiguous; Canada: Eastern, Interior; South America: Argentina, Brazil, 

Chile, Puerto Rico; Scandinavia: Denmark, Finland, Norway, Sweden; Other NW Europe: Belgium, France, Luxembourg, Netherlands; Iberia: Portugal, Spain; 

Med/E Europe: Algeria, Bulgaria, Croatia, Egypt, Greece, Israel, Malta, Morocco, Romania, Tunisia,

Turkey; East Asia: North Korea, South Korea, Taiwan; ASEAN: Malaysia, Philippines, Thailand, Vietnam; Indian Sub: Bangladesh, India, Iran, Pakistan, Sri 

Lanka.

2

Excludes imports to Puerto Rico and the U.S. Virgin Islands.

Notes: One “metric ton of coal equivalent” equals 27.78 million Btu. Totals may not equal sum of components due to independent rounding. 

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 159
Coal Market Module

Table 12.4. World metallurgical coal import demand by import region1

million metric tons of coal equivalent

2012 2020 2025 2030 2035 2040

The Americas 21.6 31.0 34.0 37.0 41.0 47.1

 United States2 1.0 1.0 1.0 1.0 1.0 1.0

 Canada 4.5 3.9 3.9 3.7 3.6 3.5

 Mexico 1.0 1.5 1.5 1.5 1.5 3.1

 South America 15.1 24.6 27.7 30.8 34.9 39.5

Europe 57.1 62.1 60.9 59.9 59.8 59.8

 Scandinavia 2.9 2.7 2.7 2.7 2.7 2.7

 U.K./Ireland 5.6 6.0 6.0 6.0 6.0 6.0

 Germany/Austria/Poland 10.4 13.2 12.2 11.2 11.2 11.2

 Other NW Europe 13.1 14.7 14.5 14.4 14.2 14.1

 Iberia 2.2 3.9 3.8 3.8 3.6 3.5

 Italy 7.1 7.4 7.3 7.2 7.3 7.3

 Med/E Europe 15.8 14.2 14.4 14.6 14.8 15.0

Asia 193.9 240.3 256.7 266.3 274.0 280.0

 Japan 70.5 79.0 77.2 74.8 71.9 67.1

 East Asia 36.0 41.2 43.3 45.5 47.1 48.8

 China/Hong Kong 52.0 60.9 63.0 65.0 67.2 69.5

 ASEAN3 0.0 0.0 0.0 0.0 0.0 0.0

 Indian Sub 35.4 59.2 73.2 81.0 87.8 94.6

TOTAL 272.6 333.4 351.6 363.2 374.8 386.9

1

 Import Regions: United States: East Coast, Gulf Coast, Northern Interior, Non-Contiguous; Canada: Eastern, Interior; South America: Argentina, Brazil, Chile, 

Puerto Rico; Scandinavia: Denmark, Finland, Norway, Sweden; Other NW Europe: Belgium, France, Luxembourg, Netherlands; Iberia: Portugal, Spain; Med/E 

Europe: Algeria, Bulgaria, Croatia, Egypt, Greece, Israel, Malta, Morocco, Romania, Tunisia, Turkey; East Asia: North Korea, South Korea, Taiwan; ASEAN: 

Malaysia, Philippines, Thailand, Vietnam; Indian Sub: Bangladesh, India, Iran, Pakistan, Sri Lanka.

2

 Excludes imports to Puerto Rico and the U.S. Virgin Islands.

3

 Malaysia, Philippines, Thailand, and Vietnam are not expected to import significant amounts of metallurgical coal in the projection.

Notes: One “metric ton of coal equivalent” equals 27.78 million Btu. Totals may not equal sum of components due to independent rounding.

Legislation and regulations

The AEO2014 is based on current laws and regulations in effect before September 30, 2013. The Mercury Air Toxics Standard 

MATS), finalized in December 2011, is included in the AEO2014 Reference case as is the Clean Air Interstate Rule (CAIR). MATS 

sets emissions limits for mercury, other heavy metals, and acid gases from coal and oil power plants that are 25 MW or greater. 

Since generators are expected to request one-year extensions for compliance, MATS is assumed to be fully in place by 2016 rather 

than 2015 as stated in the regulation.

CAIR is a cap-and-trade program that regulates sulfur dioxide and nitrous oxide (NOx) emissions from fossil-fueled power plants 

with a nameplate capacity greater than 25 MW in 27 states and the District of Columbia. Initial implementation of CAIR for NOX

occurred in 2009 and for SO2 in 2010, with both caps subject to further tightening in 2015. The AEO2014 includes trading and 

banking of allowances consistent with CAIR’s provisions. States covered by CAIR can trade allowances amongst themselves or 

with non-CAIR states participating in the Clean Air Act Amendment Title IV program. Non-CAIR state allowances are considered 

less valuable than CAIR state allowances and are traded at a discounted rate. 

160 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

Table 12.5. Production, heat content, sulfur, mercury and carbon dioxide emission factors by coal type and region

Coal Supply Region States

Coal Rank and Sulfur 

Level Mine Type

2012 

Production 

(million 

short tons)

Heat Content 

(million Btu 

per short ton)

Sulfur 

Content 

(pounds per 

million Btu)

Mercury 

Content 

(pounds per 

trillion Btu)

CO2

(pounds per 

million Btu)

Northern Appalachia

PA, OH, MD, 

WV (North) Metallurgical Underground 22.4 26.30 0.88 N/A 204.7

Mid-Sulfur 

Bituminous All 31.5 25.19 1.39 11.17 204.7

High-Sulfur 

Bituminous All 71.8 24.67 2.76 11.67 204.7

Waste Coal (Gob 

and Culm) Surface 11.0 11.60 3.65 63.90 204.7

Central Appalachia

KY (East), WV 

(South), VA, TN 

(North) Metallurgical Underground 54.9 26.30 0.62 N/A 206.4

Low-Sulfur 

Bituminous All 10.2 24.72 0.54 5.61 206.4

Mid-Sulfur 

Bituminous All 82.8 24.66 0.95 7.58 206.4

Southern Appalachia AL, TN (South) Metallurgical Underground 12.2 26.30 0.46 N/A 204.7

Low-Sulfur 

Bituminous All 0.2 26.20 0.50 3.87 204.7

Mid-Sulfur 

Bituminous All 7.0 24.43 1.37 10.15 204.7

East Interior

IL, IN, KY(West), 

MS

Mid-Sulfur 

Bituminous All 7.5 22.51 1.21 5.60 203.1

High-Sulfur 

Bituminous All 120.0 22.75 2.66 6.35 203.1

Mid-Sulfur Lignite Surface 3.0 10.36 0.96 14.11 216.5

West Interior

IA, MO, KS, AR, 

OK, TX (Bit)

High-Sulfur 

Bituminous Surface 1.6 21.25 1.44 21.55 202.8

Gulf Lignite TX (Lig), LA Mid-Sulfur Lignite Surface 36.8 13.46 1.26 14.11 212.6

High-Sulfur Lignite Surface 11.4 11.99 2.65 15.28 212.6

Dakota Lignite ND, MT (Lig) Mid-Sulfur Lignite Surface 27.8 13.21 1.29 8.38 219.3

Western Montana MT (Bit & Sub)

Low-Sulfur

Bituminous Underground 5.7 19.81 0.50 5.06 215.5

Low-Sulfur 

Subbituminous Surface 14.7 18.10 0.38 5.06 215.5

Mid-Sulfur 

Subbituminous Surface 16.0 17.25 0.77 5.47 215.5

Wyoming, 

Northern PRB

WY (Northern 

Powder River 

Basin

Low-Sulfur 

Subbituminous Surface 150.9 6.84 0.38 7.08 214.3

Mid-Sulfur 

Subbituminous Surface 2.4 16.22 0.68 7.55 214.3

Wyoming, 

Southern PRB

WY (Southern 

Powder River 

Basin)

Low-Sulfur 

Subbituminous Surface 235.0 17.63 0.28 5.22 214.3

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 161
Coal Market Module

Table 12.5. Production, heat content, sulfur, mercury and carbon dioxide emission factors by coal type and region (cont)

Coal Supply Region States

Coal Rank and Sulfur 

Level Mine Type

2012 

Production 

(million 

short tons

Heat Content 

(million Btu 

per Short 

ton)

Sulfur 

Content 

(pounds per 

million Btu)

Mercury 

Content 

(pounds 

per trillion 

Btu)

CO2

(pounds per 

million Btu)

Western Wyoming

WY (Other basins, 

excluding Powder 

River Basin)

Low-Sulfur 

Subbituminous Underground 4.6 18.87 0.63 2.19 214.3

Low-Sulfur 

Subbituminous Surface 3.5 19.02 0.49 4.06 214.3

Mid-Sulfur 

Subbituminous Surface 4.9 19.54 0.79 4.35 214.3

Rocky Mountain CO, UT Metallurgical Underground 0.1 26.30 0.43 N/A 209.6

Low-Sulfur 

Bituminous Underground 40.0 22.74 0.51 3.82 209.6

Low-Sulfur 

Subbituminous Surface 5.5 19.93 0.51 2.04 212.8

Southwest AZ, NM

Low-Sulfur 

Bituminous Surface 7.6 24.54 0.56 4.66 207.1

Mid-Sulfur 

Subbituminous Surface 17.4 17.98

 

0.91 7.18 209.2

Mid-Sulfur 

Bituminous Underground 5.0 19.07 0.79 7.18 207.1

Northwest WA, AK

Low-Sulfur 

Subbituminous Surface 2.1 16.02 0.29 6.99 216.1

N/A = not available.

Source: U.S. Energy Information Administration, Form EIA-3, “Quarterly Coal Consumption and Quality Report, Manufacturing and Transformation/Processing 

Coal Plants and Commercial and Institutional Coal Users”; Form EIA-5, “Quarterly Coal Consumption and Quality Report, Coke Plants”; Form EIA-7A, “Coal 

Production and Preparation Report”, and Form EIA-923, “Power Plant Operations Report”. U.S. Department of Commerce, Bureau of the Census, “Monthly Report 

EM-545.” U.S. Environmental Protection Agency, Emission Standards Division, Information Collection Request for Electric Utility Steam Generating Unit,

Mercury Emissions Information Collection Effort (Research Triangle Park, NC, 1999). U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2008, ANNEX 2 Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion, EPA 430-R-10-006 (Washington, 

DC, April 2010), Table A-37, http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html.

The Energy Improvement and Extension Act of 2008 (EIEA) and Title IV, under Energy and Water Development, of the American 

Recovery and Revitalization Act of 2009 (ARRA), together, are assumed to result in the development of about 1 gigawatt of coalfired generating capacity with carbon capture and sequestration by the end of 2018.

EIEA was passed in October 2008 as part of the Emergency Economic Stabilization Act of 2008. Subtitle B provides investment 

tax credits for various projects sequestering CO2. Subtitle B of EIEA, which extends the payment of current coal excise taxes for 

the Black Lung Disability Trust Fund program of $1.10 per ton on underground-mined coal and $0.55 per ton on surface-mined 

coal from 2013 to 2018, is also represented in the AEO2014. Prior to the enactment of EIEA, contribution rates for the Black Lung 

Disability Trust Fund were to be reduced in 2014 to $0.50 per ton on underground-mined coal and to $0.25 per ton on surfacemined coal. Lignite production is not subject to the Black Lung Disability Trust Fund program’s coal excise taxes. 

Title IV under ARRA provides $3.4 billion for additional research and development on fossil energy technologies. This includes 

$800 million to fund projects under the Clean Coal Power Initiative (CCPI) program, focusing on projects that capture and 

sequester greenhouse gases or use captured carbon dioxide for enhanced oil recovery (EOR). The Hydrogen Energy California 

(HECA) project in Kern County, California and the Texas Clean Energy Project (TCEP) in Penwell, Texas include efforts to use 

captured carbon dioxide for EOR.

Title XVII of the Energy Policy Act of 2005 (EPACT2005) authorized loan guarantees for projects that avoid, reduce, or sequester 

greenhouse gasses. EPACT05 also provided a 20% investment tax credit for Integrated Coal-Gasification Combined Cycle (IGCC) 

capacity and a 15% investment tax credit for other advanced coal technologies. EIEA allocated an additional $1.25 billion in 

investment tax credits for IGCC and other advanced coal-based generation technologies. For the AEO2014, all of the EPACT 2005 

and EIEA investment tax credits are assumed to have been fully allocated and, therefore, not available for new, unplanned capacity 

builds in the NEMS Electricity Market Module.

162 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

Beginning in 2008, electricity generating units of 25 megawatts or greater were required to hold an allowance for each ton 

of CO2 emitted in nine Northeastern States as part of the Regional Greenhouse Gas Initiative (RGGI). The States currently 

participating in RGGI include Connecticut, Maine, Maryland, Massachusetts, Rhode Island, Vermont, New York, New Hampshire, 

and Delaware. RGGI is modeled in AEO2014 as an emissions reduction program for the Central Atlantic region. In the AEO2014, 

the impact on coal use is generally small, as the CO2 allowance price remains relatively low in the projections. 

The AEO2014 includes a representation of California Assembly Bill 32 (AB32), the California Global Warming Solutions Act of 

2006, which authorized the California Air Resources Board (CARB) to set California’s overall GHG emissions reduction goal to 

its 1990 level by 2020 and establish a comprehensive, multi-year program to reduce GHG emissions in California, including a 

cap-and-trade program. The cap-and-trade program features an enforceable cap on GHG emissions that will decline over time. 

In the AEO2014, an allowance price, representing the incremental cost of complying with AB32 cap-and-trade, is modeled in 

the NEMS Electricity Market Module via a region-specific emissions constraint. This allowance price increases the effective 

delivered price of coal, reducing its ability to compete with other generating sources such as natural gas which emits less CO2

per unit of electricity produced. 

In accordance with California Senate Bill 1368 (SB 1368), which established a greenhouse gas emission performance standard for 

electricity generation, the AEO2014 prohibits builds of new coal-fired generating capacity without carbon capture and storage 

(CCS) for satisfying electricity demand in California. SB 1368 limits the generating emissions rate for all power plants that 

California utilities build, invest in, or sign a long-term contract with to be no more than 1,100 pounds of CO2 per megawatthour, 

which is the approximate emissions rate for a new natural gas combined-cycle power plant [4].

Coal alternative cases

Coal Cost cases

In the Reference case, coal mine labor productivity is assumed to decline on average by 1.2% per year from 2012 to 2040. Miner 

wage rates increase by about 0.9% per year, and mine equipment costs remain constant in 2012 dollars. Eastern and western 

coal transportation rates are projected to remain near their 2012 levels in 2012 dollars.

In two alternative coal cost cases, productivity, average miner wages, equipment cost, and transportation rate assumptions were 

modified for 2014 through 2040 in order to examine the impacts on U.S. coal supply, demand, distribution, and prices. The key 

modeling assumptions for the alternative Coal Cost cases and Reference case are shown in Table 12.6. 

In the Low Coal Cost case, coal mine labor productivity is assumed to increase at an average rate of 1.0% per year from 2012 to 

2040. Coal mining wages, mine equipment costs, and other mine supply costs all are assumed to be about 24% lower (in 2012 

dollars) in 2040 in the Low Coal Cost case than in the Reference case. Coal transportation rates, excluding the impact of fuel 

surcharges, are assumed to be approximately 25% lower by 2040. In the international coal market, the price change for nonU.S. export supplies (e.g., coal exported to the international market from ports in Australia) is assumed to be roughly 10% less 

than the price change projected for U.S. coal exports.

In the High Coal Cost case, coal mine labor productivity is assumed to decline at an average rate of 4.0% per year from 2012 to 

2040. Coal miner wages, mine equipment costs, and other mine supply costs all are assumed to be about 31% higher in 2040 

in real terms in the High Coal Cost case than in the Reference case. Compared to the Reference case, coal transportation rates 

are assumed to be approximately 25% higher by 2040. In the international coal market, the price change for non-U.S. export 

supplies is assumed to be roughly 10% less than the price change projected for U.S. coal exports. The low and high coal cost 

cases represent fully integrated NEMS runs, with feedback from the Macroeconomic Activity, International, supply, conversion, 

and end-use demand modules.

No Greenhouse Gas Concern case

In the Reference case, to reflect the market reaction to potential future GHG regulation, a 3-percentage-point increase in the 

cost of capital for investments in new coal-fired power and coal-to-liquids plants without carbon capture and sequestration 

technology is assumed. These assumptions affect cost evaluations for the construction of new capacity but not the actual 

operating costs for new existing plants. This adjustment was first implemented for AEO2009. Beginning with AEO2012, a 

3-percentage-point increase in the cost of capital for investments in retrofits at existing coal plants is also applied for emission 

control equipment (excluding CCS). The No GHG concern case excludes the 3-percentage point increase in the cost of capital.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 163
Coal Market Module

Table 12.6. Key modeling assumptions for AEO2014 reference and coal cost cases

constant dollar index, 2012=1.000, unless otherwise noted

2012 2020 2040 Growth Rate, 2012-2040

Low 

Cost Reference

High 

Cost

Low 

Cost Reference

High 

Cost

Low 

Cost Reference

High 

Cost

Cost Indices

Transportation Rte Multipliers

Eastern Railroads 1.000 0.960 1.022 1.090 0.760 1.008 1.260 -1.0% 0.0% 0.8%

Western Railroad 1.000 0.940 1.005 1.070 0.750 0.996 1.250 -1.0% 0.0% 0.8%

Mine Equipment Costs

Underground 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Surface 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Other Mine Supply Costs

East of the 

Mississippi: 

 All Mines 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

West of the 

Mississippi: 

 Underground 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

West of the 

Mississippi: 

 Surface 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Coal Mining Labor 

Productivity

(short tons per miner 

per hour) 1.000 5.52 4.64 3.85 6.89 3.68 1.68 1.0% -1.2% -4.0%

Average Coal Miner 

Wage

(2012 dollars per year) 80,450 87,295 93,666 100,431 79,835 104,525 136,440 0.0% 0.9% 1.9%

Sources: 2012 data based on: U.S. Energy Information Administration (EIA), Annual Coal Report 2012, DOE/EIA-0584(2012) 

(Washington, DC, December 2013); and U.S. Department of Labor, Bureau of Labor Statistics, Quarterly Census of Employment 

and Wages: Coal Mining, Series ID : ENUUS0005052121; Projections: EIA, AEO2014 National Energy Modeling System runs 

LCCST14.D120413A, REF2014.D102413A, and HCCST14.D120413A.

Notes and sources

[1] Flynn, Edward J., “Impact of Technological Change and Productivity on The Coal Market,” U.S. Energy Information 

Administration (Washington, DC, October 2000), http://www.eia.gov/oiaf/analysispaper/pdf/coal.pdf; and U.S. Energy 

Information Administration, The U.S. Coal Industry, 1970-1990: Two Decades of Change, DOE/EIA-0559 (Washington, DC, 

November 1992).

[2] The estimated cost of switching to subbituminous coal, $0.10 per million Btu (2000 dollars), was derived by Energy 

Ventures Analysis, Inc. and was recommended for use in the CMM as part of an Independent Expert Review of the Annual 

Energy Outlook 2002’s Powder River Basin production and transportation rates. Barbaro, Ralph and Schwartz,Seth, Review of 

the Annual Energy Outlook 2002 Reference Case Forecast for PRB Coal, prepared for the Energy Information Administration 

(Arlington, VA: Energy Ventures Analysis, Inc., August 2002).

[3] U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008, Annex 2 

Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion, EPA 430-R-10-006 (Washington, DC, April 

2010), Table A-37, http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html.

[4] California Energy Commission, SB 1368 Emission Performance Standards, http://www.energy.ca.gov/emission_standards/

index.html.

164 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Renewable Fuels Module
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Renewable Fuels Module

The NEMS Renewable Fuels Module (RFM) provides natural resources supply and technology input information 

for projections of new central-station U.S. electricity generating capacity using renewable energy resources. The 

RFM has seven submodules representing various renewable energy sources: biomass, geothermal, conventional 

hydroelectricity, landfill gas, solar thermal, solar photovoltaics, and wind [1].

Some renewables, such as landfill gas (LFG) from municipal solid waste (MSW) and other biomass materials, 

are fuels in the conventional sense of the word, while others, such as water, wind, and solar radiation, are energy 

sources that do not involve the production or consumption of a fuel. Commercial market penetration of renewable 

technologies varies widely. 

The submodules of the RFM interact primarily with the Electricity Market Module (EMM). Because of the high 

level of integration with the EMM, the final outputs (levels of consumption and market penetration over time) for 

renewable energy technologies are largely dependent upon the EMM. Because some types of biomass fuel can 

be used for either electricity generation or for the production of liquid fuels, such as ethanol, there is also some 

interaction with the Liquid Fuels Market Module (LFMM), which contains additional representation of some 

biomass feedstocks that are used primarily for liquid fuels production.

Projections for residential and commercial grid-connected photovoltaic systems are developed in the end-use 

demand modules and not in the RFM; see the Distributed Generation and Combined Heat and Power description 

in the “Commercial Demand Module” and “Residential Demand Module” sections of the report. Descriptions 

for biomass energy production in industrial settings, such as the pulp and paper industries, can be found in the 

“Industrial Demand Module” section of the report. 

Key assumptions 

Nonelectric renewable energy uses 

In addition to projections for renewable energy used in central station electricity generation, AEO2014 contains 

projections of nonelectric renewable energy consumption for industrial and residential wood heating, solar 

residential and commercial hot water heating, biofuels blending in transportation fuels, and residential and 

commercial geothermal (ground-source) heat pumps. Assumptions for these projections are found in the 

Residential, Commercial, Industrial, and Liquid Fuels Market Module (LFMM) sections of this report. Additional 

minor renewable energy applications occurring outside energy markets, such as direct solar thermal industrial 

applications or direct lighting, off-grid electricity generation, and heat from geothermal resources used directly (e.g., 

district heating and greenhouses) are not included in the projections. 

Electric power generation 

The RFM considers only grid-connected central station electricity generation systems. The RFM submodules that 

interact with the EMM are the central station grid-connected biomass, geothermal, conventional hydroelectricity, 

landfill gas, solar (thermal and photovoltaic), and wind submodules, which provide specific data or estimates that 

characterize the respective resource. A set of technology cost and performance values is provided directly to the 

EMM and is central to the build and dispatch decisions of the EMM. The technology cost and performance values 

are summarized in Table 8.2 in the chapter discussing the EMM.

Capital costs 

Capital costs for renewable technologies are affected by several factors. Capital costs for technology to exploit 

some resources, especially geothermal, hydroelectric, and wind power resources, are assumed to be dependent on 

the quality, accessibility, and/or other site-specific factors in the areas with exploitable resources. These factors 

can include additional costs associated with reduced resource quality; need to build or upgrade transmission 

capacity from remote resource areas to load centers; or local impediments to permitting, equipment transport, and 

construction in good resource areas due to siting issues, inadequate infrastructure, or rough terrain.

Short-term cost adjustment factors increase technology capital costs as a result of a rapid U.S. buildup in a single 

year, reflecting limitations on the infrastructure (for example, limits on manufacturing, resource assessment, and 

construction expertise) to accommodate unexpected demand growth. These factors, which are applied to all new 

electric generation capacity, are a function of past production rates and are further described in The Electricity Market 

Module of the National Energy Modeling System: Model Documentation Report, available at 

www.eia.gov/forecasts/aeo/nems/documentation/electricity/pdf/m068(2013).pdf.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 177
Renewable Fuels Module

Also assumed to affect all new capacity types are costs associated with construction commodities. Through much 

of the period from 2000 to 2008, the installed cost for most new plants was observed to increase. Although several 

factors contributed to this cost escalation, some of which may be more or less important to specific types of new 

capacity, much of the overall cost increase was correlated with increases in the cost of construction materials, such 

as bulk metals, specialty metals, and concrete. Capital costs are specifically linked to the projections for the metals 

producer price index found in the Macroeconomic Module of NEMS. Independent of the other two factors, capital 

costs for all electric generation technologies, including renewable technologies, are assumed to decline as a function 

of growth in installed capacity for each technology.

For a description of NEMS algorithms lowering generating technologies’ capital costs as more units enter service 

(learning), see “Technological Optimism and Learning” in the EMM chapter of this report. A detailed description 

of the RFM is provided in the EIA publication, Renewable Fuels Module of the National Energy Modeling System, Model 

Documentation 2013, DOE/EIA-M069(2013) Washington, DC, 2013. To access please see www.eia.gov/forecasts/

aeo/nems/documentation/renewable/pdf/m069(2013).pdf.

Solar Electric Submodule

Background

The Solar Electric Submodule currently includes both solar thermal (also referred to as “concentrating solar power” or 

CSP) and photovoltaic (PV) technologies. The representative solar thermal technology assumed for cost estimation 

is a 100-megawatt central-receiver tower without integrated energy storage, while the representative solar PV 

technology is a 150-megawatt array of flat plate PV modules using single-axis tracking. PV is assumed available 

in all EMM regions, while CSP is available only in the Western regions with the arid atmospheric conditions that 

result in the most cost-effective capture of direct sunlight. Cost estimates for both technologies are based on a 

report by SAIC entitled “EOP III Task 1606, Subtask 3 – Review OF Power Plant Cost and Performance Assumptions 

for NEMS: Technology Documentation Report,” published in 2013, http://www.eia.gov/forecasts/capitalcost/pdf/

updated_capcost.pdf. Technology-specific performance characteristics are obtained from information provided by 

the National Renewable Energy Laboratory (NREL). 

Assumptions 

• NEMS represents the Energy Policy Act of 1992 (EPACT92) permanent 10% investment tax credit (ITC) for solar 

electric power generation by tax-paying entities. In addition, the current 30% ITC, scheduled to expire at the end 

of 2016, is also represented to qualifying new capacity installations.

• Existing capacity and planned capacity additions are based on EIA survey data from the Form EIA-860, “Annual 

Electric Generator Report” and Form EIA-860M, “Monthly Update to the Annual Electric Generator Report.” 

Planned capacity additions under construction or having all regulatory approvals and having an expected completion date prior to the expiration of the 30% ITC were included in the model’s planned capacity additions, according 

to respondents’ planned completion dates.

• Capacity factors for solar technologies are assumed to vary by time of day and season of the year, such that nine 

separate capacity factors are provided for each modeled region, three for time of day and for each of three broad 

seasonal groups (summer, winter, and spring/fall). Regional capacity factors vary from national averages based on 

climate and latitude. 

• Solar resources are well in excess of conceivable demand for new capacity; energy supplies are considered unlimited within regions (at specified daily, seasonal, and regional capacity factors). Therefore, solar resources are 

not estimated in NEMS. In the regions where CSP technology is not modeled, the level of direct, normal insolation 

(the kind needed for that technology) is assumed to be insufficient to make that technology commercially viable 

through the projection horizon. 

Wind-Electric Power Submodule

Background

Because of limits to windy land areas, wind is considered a finite resource, so the submodule calculates maximum 

available capacity by Electricity Market Module Supply Regions. The minimum economically viable average wind 

speed is about 15 mph at a hub-height of 80 meters (m), and wind speeds are categorized by annual average wind 

speed based on a classification system originally from the Pacific Northwest Laboratory (see http://rredc.nrel.gov/

wind/pubs/atlas/tables/1-1T.html). The RFM tracks wind capacity (megawatts) by resource quality and costs

178 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Renewable Fuels Module

within a region, and moves to the next best wind resource when one category is exhausted. Wind resource data 

on the amount and quality of wind per EMM region come from the National Renewable Energy Laboratory [2]. 

The technological performance, cost, and other wind data used in NEMS are based on a report by SAIC entitled 

“EOP III Task 1606, Subtask 3 – Review of Power Plant Cost and Performance Assumptions for NEMS: Technology 

Documentation Report”, published in 2013. To access, please see http://www.eia.gov/forecasts/capitalcost/. 

Maximum wind capacity, capacity factors, and incentives are provided to the EMM for capacity planning and dispatch 

decisions. These form the basis on which the EMM decides how much power generation capacity is available from 

wind energy. The fossil-fuel heat rate equivalents for wind are used for energy consumption calculation purposes only. 

Assumptions 

• Only grid-connected (utility and nonutility) generation is included. Projections for distributed wind generation are 

included in the commercial and residential modules. 

• In the wind submodule, wind supply costs are affected by three modeling measures addressing: (1) average wind 

speed, (2) distance from existing transmission lines, and (3) resource degradation, transmission network upgrade 

costs, and market factors 

• Available wind resource is reduced by excluding all windy lands not suited for the installation of wind turbines because of: excessive terrain slope (greater than 20%); reservation of land for non-intrusive uses (such as National 

Parks, wildlife refuges, and so forth); inherent incompatibility with existing land uses (such as urban areas, areas 

surrounding airports and water bodies, including offshore locations); insufficient contiguous windy land to support 

a viable wind plant (less than 5 square kilometers of windy land in a 100-square-kilometer area). Half of the wind 

resource located on military reservations, U.S. Forest Service land, state forested land, and all non-ridge-crest forest areas is excluded from the available resource base to account for the uncertain ability to site projects at such 

locations. These assumptions are detailed in the Draft Final Report to EIA titled “Incorporation of Existing Validated 

Wind Data into NEMS,” November 2003.

• Capital costs for wind technologies are assumed to increase in response to (1) declining natural resource quality, 

such as terrain slope, terrain roughness, terrain accessibility, wind turbulence, wind variability, or other natural resource factors, as the best sites are utilized, (2) increasing cost of upgrading existing local and network distribution 

and transmission lines to accommodate growing quantities of remote wind power, and (3) market conditions, such 

as the increasing costs of alternative land uses, including aesthetic or environmental reasons. Capital costs are left 

unchanged for some initial share, then increased by 10%, 25%, 50%, and finally 100%, to represent the aggregation 

of these factors.

• Proportions of total wind resources in each category vary by EMM region. For all EMM regions combined, about 1% 

of windy land (107 GW of 11,600 GW in total resource) is available with no cost increase, 3.4% (390 GW) is available with a 10% cost increase, 2% (240 GW) is available with a 25% cost increase, and over 90% is available with a 

50% or 100% cost increase. 

• Depending on the EMM region, the cost of competing fuels, and other factors, wind plants can be built to meet system capacity requirements or as a “fuel saver” to displace generation from existing capacity. For wind to penetrate 

as a fuel saver, its total capital and fixed operations and maintenance costs minus applicable subsidies must be less 

than the variable operating costs, including fuel, of the existing (non-wind) capacity. When competing in the new 

capacity market, wind is assigned a capacity credit that declines based on its estimated contribution to regional reliability requirements.

• Because of downwind turbulence and other aerodynamic effects, the model assumes an average spacing between 

turbine rows of 5 rotor diameters and a lateral spacing between turbines of 10 rotor diameters. This spacing requirement determines the amount of power that can be generated from wind resources, about 6.5 megawatts per square 

kilometer of windy land, and is factored into requests for generating capacity by the EMM.

• Capacity factors for each wind class are calculated as a function of overall wind market growth. The capacity factors 

are assumed to be limited to about 50% for a typical Class 6 site. As better wind resources are depleted, capacity 

factors are assumed to go down, corresponding with the use of less-desirable sites. By 2040, the typical wind plant 

build will have a somewhat lower capacity factor than those found in the best wind resource areas. Capacity factors 

in the Reference case increase to about 40% in the best wind class resulting from taller towers, more reliable equipment, and advanced technologies, although, as noted, these may not represent the best available sites because of 

other site-specific factors.

• AEO2014 allows plants constructed through 2013 to claim the federal Production Tax Credit (PTC), a 2.3-cent-perkilowatt-hour tax incentive for wind that was initially set to expire for wind only on December 31, 2013. Wind plants 

are assumed to depreciate capital expenses using the Modified Accelerated Cost Recovery Schedule with a 5-year 

tax life.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 179
Renewable Fuels Module

Offshore wind resources are represented as a separate technology from onshore wind resources. Offshore resources 

are modeled with a similar model structure as onshore wind. However, because of the unique challenges of offshore 

construction and the somewhat different resource quality, the assumptions with regard to capital cost, learning-bydoing cost reductions, and variation of resource exploitation costs and performance differ significantly from onshore 

wind.

• Like onshore resources, offshore resources are assumed to have an upwardly sloping supply curve, in part influenced by the same factors that determine the onshore supply curve (such as distance to load centers, environmental or aesthetic concerns, variable terrain/seabed) but also explicitly by water depth. 

• Because of the more difficult maintenance challenge offshore, performance for a given annual average wind power 

density level is assumed to be somewhat reduced by reduced turbine availability. Offsetting this, however, is the 

availability of resource areas with higher overall power density than is assumed available onshore. Capacity factors 

for offshore are limited to be about 50% for a Class 7 site. 

• Cost reductions in the offshore technology result in part from learning reductions in onshore wind technology as 

well as from cost reductions unique to offshore installations, such as foundation design and construction techniques. Because offshore technology is significantly less mature than onshore wind technology, offshore-specific 

technology learning occurs at a somewhat faster rate than on-shore technology. A technological optimism factor 

(see EMM documentation: www.eia.gov/forecasts/aeo/nems/documentation/electricity/pdf/m068(2013).pdf) is 

included for offshore wind to account for the substantial cost of establishing the unique construction infrastructure 

required for this technology.

Geothermal-Electric Power Submodule

Background

Beginning in AEO2011, all geothermal supply curve data come from the National Renewable Energy Laboratory’s 

updated U.S. geothermal supply curve assessment. The report, released in February 2010, assigns cost estimates to 

the U.S. Geological Survey’s (USGS) 2008 geothermal resource assessment. Some data from the 2006 report, “The 

Future of Geothermal Energy,” prepared by the Massachusetts Institute of Technology, were also incorporated into 

the NREL report; however, this would be more relevant to deep, dry, and unknown geothermal resources, something 

which EIA did not include in its supply curve. NREL took the USGS data and used the Geothermal Electricity 

Technology Evaluation Model (GETEM), an Excel-based techno-economic systems analysis tool, to estimate the costs 

[3]. Only resources with temperatures above 110 degrees Celsius were considered. There are approximately 125 

of these known, hydrothermal resources which EIA used in its supply curve. Each of these sites also has what NREL 

classified as “near-field enhanced geothermal energy system potential” which are in areas around the identified site 

that lack the permeability of fluids that are present in the hydrothermal potential. Therefore, there are 250 total points 

on the supply curve since each of the 125 hydrothermal sites has corresponding enhanced geothermal system (EGS) 

potential.

In the past, EIA cost estimates were broken down into cost-specific components. Unfortunately, this level of detail 

was not available in the NREL data. A site-specific capital cost and fixed operations and maintenance cost were 

provided. Both types of technology, both flash and binary, are also included with capacity factors ranging from 90% to 

95%. While the source of the data was changed beginning in AEO2011, the site-by-site matrix input that acts as the 

supply curve has been retained.

Assumptions 

• Existing and identified planned capacity data are obtained directly by the EMM from Form EIA-860 and Form EIA860M.

• The permanent investment tax credit of 10% available in all projection years, based on EPACT92, applies to all geothermal capital costs, except through December 2013 when the 2.3-cent production tax credit is available to this 

technology and is assumed chosen instead. Projects that have begun construction and are beyond the exploratory 

drilling phase by that date are eligible for this production tax credit.

• Plants are not assumed to retire unless their retirement is reported to EIA. The Geysers units are not assumed to 

retire but instead are assigned the 35% capacity factors reported to EIA reflecting their reduced performance in 

recent years.

180 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Renewable Fuels Module

Biomass Electric Power Submodule 

Background 

Biomass consumed for electricity generation is modeled in two parts in NEMS. Capacity in the wood products and 

paper industries, the so-called captive capacity, is included in the Industrial Demand Module as cogeneration. 

Generation in the electricity sector is represented in the EMM. Fuel costs are calculated in NEMS and passed to 

EMM, while capital and operating costs and performance characteristics are assumed as shown in Table 8.2. Fuel 

costs are provided in sets of regional supply schedules. Projections for ethanol are produced by the LFMM, with the 

quantities of biomass consumed for ethanol decremented from, and prices obtained from, the EMM regional supply 

schedules.

Assumptions 

• Existing and planned capacity data are obtained from Form EIA-860 and Form EIA-860M. 

• The conversion technology represented is an 80-MW dedicated combustion plant. The cost estimates for this 

technology are based on a report by SAIC entitled “EOP III Task 1606, Subtask 3 – Review of Power Plant Cost and 

Performance Assumptions for NEMS: Technology Documentation Report,” published in 2013, http://www.eia.

gov/forecasts/capitalcost/pdf/updated_capcost.pdf.

• Biomass co-firing can occur up to a maximum of 15% of fuel used in coal-fired generating plants.

Fuel supply schedules are a composite of four fuel types: forestry materials, wood residues, agricultural residues, 

and energy crops. Feedstock potential from agricultural residues and dedicated energy crops are calculated from 

a version of the Policy Analysis (POLYSYS) agricultural model that uses the same oil prices as the rest of NEMS. 

Forestry residues are calculated from inventories conducted by the U.S. Forest Service and Oak Ridge National 

Laboratory. The forestry materials component is made up of logging residues, rough rotten salvageable dead 

wood, and excess small pole trees [4]. The wood residue component consists of primary mill residues, silvicultural 

trimmings, and urban wood such as pallets, construction waste, and demolition debris that are not otherwise used 

[5]. Agricultural residues are wheat straw, corn stover, and a number of other major agricultural crops [6]. Energy 

crop data are for hybrid poplar, willow, and switchgrass grown on existing cropland. POLYSYS assumes that the 

additional cropland needed for energy crops will displace existing pasturelands. The lands in the Conservation 

Reserve Program are preserved [7]. The maximum amount of resources from forestry is fixed based on U.S. BillionTon Update by Oak Ridge National Laboratory [4]. Urban wood waste is determined dynamically based on activity 

in the industry sectors that produce usable biomass feedstocks. Agricultural resource (agricultural residues and 

energy crops) supply is determined dynamically, and supplies available within the model at any point in time may 

not reflect the maximum potential for that region. For 2035, supplies of 833.3 trillion Btu from all sectors could be 

available given prevailing demand in the AEO2014 Reference case.

Landfill-Gas-to-Electricity Submodule 

Background 

Landfill-gas-to-electricity capacity competes with other technologies using supply curves that are based on the 

amount of “high,” “low,” and “very low” methane-producing landfills located in each EMM region. An average cost 

of electricity for each type of landfill is calculated using gas collection system and electricity generator costs and 

characteristics developed by EPA’s “Energy Project Landfill Gas Utilization Software” (E-PLUS) [8].

Assumptions 

• Gross domestic product (GDP) and population are used as the drivers in an econometric equation that establishes the supply of landfill gas. 

• Recycling is assumed to account for 50% of the waste stream in 2010 (consistent with EPA’s recycling goals).

• The waste stream is characterized into three categories: readily, moderately, and slowly decomposable material.

• Emission parameters are the same as those used in calculating historical methane emissions in EIA’s Emissions of 

Greenhouse Gases in the United States 2003 [9].

• The ratio of “high,” “low,” and “very low” methane production sites to total methane production is calculated from 

data obtained for 156 operating landfills contained in the Government Advisory Associates METH2000 database 

[10].

• Cost-of-electricity for each site was calculated by assuming each site to be a 100-acre by 50-foot deep landfill 

and by applying methane emission factors for “high,” “low,” and “very low” methane-emitting wastes.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 181
Renewable Fuels Module

Conventional hydroelectricity 

The conventional hydroelectricity submodule represents U.S. potential for new conventional hydroelectric capacity 

of 1 megawatt or greater from new dams, existing dams without hydroelectricity, and from adding capacity at 

existing hydroelectric dams. Summary hydroelectric potential is derived from reported lists of potential new sites 

assembled from Federal Energy Regulatory Commission (FERC) license applications and other survey information, 

plus estimates of capital and other costs prepared by the Idaho National Engineering and Environmental Laboratory 

(INEEL) [11]. Annual performance estimates (capacity factors) were taken from the generally lower but site-specific 

FERC estimates rather than from the general estimates prepared by INEEL, and only sites with estimated costs of 10 

cents per kilowatthour or lower are included in the supply. Pumped storage hydro, considered a nonrenewable storage 

medium for fossil and nuclear power, is not included in the supply; moreover, the supply does not consider offshore 

or in-stream hydro, efficiency or operational improvements without capital additions, or additional potential from 

refurbishing existing hydroelectric capacity.

In the hydroelectricity submodule, sites are first arrayed by NEMS region from least to highest cost per kilowatthour. 

For any year’s capacity decisions, only those hydroelectric sites whose estimated levelized costs per kilowatthour are 

equal to or less than an EMM-determined avoided cost (the least cost of other technology choices determined in the 

previous decision cycle) are submitted. Next, the array of below-avoided-cost sites is parceled into three increasing 

cost groups, with each group characterized by the average capacity-weighted cost and performance of its component 

sites. Finally, the EMM receives from the conventional hydroelectricity submodule the three increasing-cost quantities 

of potential capacity for each region, providing the number of megawatts potential along with their capacity-weighted 

average overnight capital cost, operations and maintenance cost, and average capacity factor. After choosing from 

the supply, the EMM informs the hydroelectricity submodule, which decrements available regional potential in 

preparation for the next capacity decision cycle.

Legislation and regulations

Renewable electricity tax credits

The RFM includes the investment and energy production tax credits codified in EPACT92 as amended. The 

investment tax credit established by EPACT92 provides a credit to Federal income tax liability worth 10% of initial 

investment cost for a solar, geothermal, or qualifying biomass facility. This credit was raised to 30% through 2016 for 

some solar projects and extended to residential projects. This change is reflected in the RFM, Commercial Demand 

Module, and Residential Demand Module. The production tax credit, as established by EPACT92, applied to wind and 

certain biomass facilities. As amended, it provides a 2.3-cent tax credit for every kilowatthour of electricity produced 

for the first 10 years of operation for a wind facility, constructed by December 31, 2013. The value of the credit, 

originally 1.5 cents, is adjusted annually for inflation. With the various amendments, the production tax credit is 

available for electricity produced from qualifying geothermal, animal waste, certain small-scale hydroelectric, landfill 

gas, municipal solid waste, and additional biomass resources. Wind, poultry litter, geothermal, and “closed loop” 

[12] biomass resources receive a 2.3-cent tax credit for the first 10 years of facility operations. All other renewable 

resources receive a 1.1 cent (that is, one-half the value of the credit for other resources) tax credit for the first 10 years 

of facility operations. EIA assumes that biomass facilities obtaining the PTC will use “open-loop” fuels, as “closedloop” fuels are assumed to be unavailable and/or too expensive for widespread use during the period that the tax 

credit is available. The investment and production tax credits are exclusive of one another, and thus may not both be 

claimed for the same geothermal facility (which is eligible to receive either).

The American Taxpayer Relief Act passed in January of 2012 extends the wind PTC expiration date until December 31, 

2013. In addition, it modifies the requirement for all fuels that plants be operational by the expiration date to allow any 

plant under construction by the expiration date to qualify. This update has been included in the AEO2014 Reference 

case.

State RPS programs 

EIA represents various state-level policies generally referred to as Renewable Portfolio Standards (RPS). These 

policies vary significantly among states, but typically require the addition of renewable generation to meet a specified 

share of state-wide generation. Any non-discretionary limitations on meeting the generation or capacity target 

are modeled to the extent possible. However, because of the complexity of the various requirements, the regional 

target aggregation, and the nature of some of the limitations, the measurement of compliance is assumed to be 

approximate.

182 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Renewable Fuels Module

Regional renewable generation targets were estimated using the renewable generation targets in each state within the 

region. In many cases, regional boundaries intersect State boundaries; in these cases state requirements were divided 

among relevant regions based on sales. Using State-level RPS compliance schedules and are preliminary estimates 

of projected sales growth, EIA estimated the amount of renewable generation required in each state within a region. 

Required generation in each state was then summed to the regional level for each year, and a regional renewable 

generation share of total sales was determined, as shown in Table 13.1.

Only targets with established enforcement provisions or established state funding mechanisms were included in 

the calculation; Non-enforceable goals were not included. Compliance enforcement provisions vary significantly 

among states and most states have established procedures for waiving compliance through the use of “alternative 

compliance” payments, penalty payments, discretionary regulatory waivers, or retail price impact limits. Because of 

the variety of mechanisms, even within a given electricity market region, these limits are not modeled.

Alternative renewable case 

Low Renewable Cost case

The Low Renewable Cost case examines the effect of reducing renewable technology capital costs by 20% below 

Reference case values throughout the projection period.

For wind, biomass, LFG, geothermal, and solar technologies, this cost reduction is achieved by a applying a 20% 

reduction in the base overnight capital costs assumed in the Reference case. For geothermal and hydro, the capital 

cost of each individual site that is modeled is reduced by 20% compared to the Reference case. Biomass prices 

are also assumed to be reduced 20% for a given quantity of fuel supplied. Other assumptions within NEMS are 

unchanged from the Reference case.

For the Low Renewable Cost case, demand-side improvements are also assumed in the renewable energy technology 

options of residential demand, commercial demand, industrial demand, and LFMM modules. Details on these 

assumptions can be found in the corresponding sections of this report.

Table 13.1. Aggregate regional renewable portfolio standard requirements (percentage share of total values)

Region1 2020 2030 2040

Texas Reliability Entity 4.4% 4.4% 4.4%

Midwest Reliability Council - East 10.0% 10.0% 10.0%

Midwest Reliability Council - West 10.3% 11.4% 11.4%

Northeast Power Coordinating Council - Northeast 14.3% 14.6% 14.6%

Northeast Power Coordinating Council - NYC/Westchester 24.6% 24.6% 24.6%

Northeast Power Coordinating Council - Long Island 24.6% 24.6% 24.6%

Northeast Power Coordinating Council - Upstate NY 24.4% 24.5% 24.5%

ReliabilityFirst Corporation - East 13.6% 14.8% 14.8%

ReliabilityFirst Corporation - Michigan 10.0% 10.0% 10.0%

ReliabilityFirst Corporation - West 7.1% 9.3% 9.3%

SERC Reliability Corporation - Delta 0.6% 0.6% 0.6%

SERC Reliability Corporation - Gateway 11.2% 15.8% 15.8%

SERC Reliability Corporation - Central 0.0% 0.1% 0.1%

SERC Reliability Corporation - Virginia/Carolina 5.0% 5.5% 5.5%

Southwest Power Pool - North 11.9% 13.2% 13.2%

Southwest Power Pool - South 2.1% 2.2% 2.2%

Western Electricity Coordinating Council - Southwest 9.4% 11.1% 11.1%

Western Electricity Coordinating Council - California 33.0% 33.0% 33.0%

Western Electricity Coordinating Council - Northwest 10.1% 11.0% 11.0%

Western Electricity Coordinating Council - Rockies 23.3% 23.3% 23.3%

1

 See chapter on the Electricity Market Module for a map of the electricity market module supply regions.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 183
Renewable Fuels Module

Notes and sources

[1] For a comprehensive description of each submodule, see U.S. Energy Information Administration, Office of 

Integrated Analysis and Forecasting, Model Documentation, Renewable Fuels Module of the National Energy 

Modeling System, DOE/EIA-M069(2013), (Washington, DC, August 2013), 

http://www.eia.gov/forecasts/aeo/nems/documentation/renewable/pdf/m069(2013).pdf.

[2] Revising the Long Term Multipliers in NEMS: Quantifying the Incremental Transmission Costs Due to Wind Power, 

Report to EIA from Princeton Energy Resources International, LLC. May 2007.

[3] The one exception applies to the Salton Sea resource area. For that site, EIA used cost estimates provided by 

R.W. Beck, Inc. rather than NREL.

[4] U.S. Department of Energy. U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts Industry. 

August 2011.

[5] Ibid.

[6] De la Torre Ugarte, D. “Biomass and bioenergy applications of the POLYSYS modeling framework” Biomass and

Bioenergy 18 (2000): 291-308.

[7] Ibid.

[8] U.S. Environmental Protection Agency, Atmospheric Pollution Prevention Division, Energy Project Landfill Gas

Utilization Software (E-PLUS) Version 1.0, EPA-430-B-97-006 (Washington, DC, January 1997).

[9] U.S. Energy Information Administration, “Emissions of Greenhouse Gases in the United States 2003,” DOE/EIA0573(2003) (Washington, DC, December 2004), www.eia.gov/oiaf/1605/archive/gg04rpt/index.html. 

[10] Governmental Advisory Associates, Inc., METH2000 Database, Westport, CT, January 25, 2000.

[11] Douglas G. Hall, Richard T. Hunt, Kelly S. Reeves, and Greg R. Carroll, Idaho National Engineering and 

Environmental Laboratory, “Estimation of Economic Parameters of U.S. Hydropower Resources” INEEL/EXT-03-

00662 (Idaho Falls, Idaho, June 2003), http://www1.eere.energy.gov/water/pdfs/doewater-00662.pdf

[12] Closed-loop biomass are crops produced explicitly for energy production. Open-loop biomass are generally 

wastes or residues that are a byproduct of some other process, such as crops grown for food, forestry, landscaping, 

or wood milling.

184 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Appendix A: Handling of federal 

and selected state legislation and 

regulation in the AEO
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Appendix A

Legislation Brief description AEO handling Basis

Residential sector

A. National Appliance Energy Conservation 

Act of 1987

Requires Secretary of Energy 

to set minimum efficiency 

standards for 10 appliance 

categories with periodic 

updates

Included for categories 

represented in the AEO 

residential sector forecast.

Public Law 100-12.

 a. Room air conditioners Sets standards for room air 

conditioners in 2014.

Require new purchases of 

room air conditioners to meet 

the standard.

Federal Register Notice 

of Final Rulemaking.

 b. Central air conditioners and heat

 pumps

Sets standards for central air 

conditioners in 2015.

Require new purchases of 

other air conditioners to meet 

the standard.

Federal Register Notice 

of Final Rulemaking.

 c. Water heaters Sets standards for water 

heaters in 2015.

Require new purchases of 

water heaters to meet the 

standard.

Federal Register Notice 

of Final Rulemaking.

 d. Refrigerators and freezers Sets standards for refrigerators 

and freezers in 2014.

Require new purchases of 

refrigerators/freezers to meet 

the standard.

Federal Register Notice 

of Final Rulemaking.

 e. Dishwashers Sets standards for dishwasher 

in 2010.

Require new purchases of 

dishwashers to meet the 

standard.

Federal Register Notice 

of Final Rulemaking.

 f. Fluorescent lamp ballasts Sets standards for fluorescent 

lamp ballasts in 2005.

Require new purchases of 

fluorescent lamp ballasts to 

meet the standard.

Federal Register Notice 

of Final Rulemaking.

 g. Clothes washers Sets standards for clothes 

washers in 2011.

Require new purchases of 

clothes washers to meet the 

standard.

Federal Register Notice 

of Final Rulemaking.

 h. Furnaces Sets standards for furnaces in 

2013.

Require new purchases of 

furnaces to meet the standard.

Federal Register Notice 

of Final Rulemaking.

 i. Clothes dryers Sets standards for clothes 

dryers in 2015.

Require new purchases of 

clothes dryers to meet the 

standard.

Federal Register Notice 

of Final Rulemaking.

 j. Boilers Sets standards for boilers in 

2012.

Require new purchases of 

boilers to meet the standard.

Federal Register Notice 

of Final Rulemaking.

B. Energy Policy Act of 1992 (EPACT1992) Public Law 102-486

 a. Building codes For the IECC 2006, specifies 

whole house efficiency 

minimums.

Assumes that all states adopt 

the IECC 2006 code by 2017.

Trend of states 

adoption to codes, 

allowing for lead times 

for enforcement and 

builder compliance.

 b. Various lighting types Sets standards for various 

lightig types in 2012.

Require new purchases of 

various lighting types to meet 

the standards.

Federal Register Notice 

of Final Rulemaking.

C. Energy Policy Act of 2005 (EPACT2005) Public Law 109-58.

 a. Torchiere lamp standard Sets standard for torchiere 

lamps in 2006.

Requires new purchases of 

torchiere bulbs to meet the 

standard.

Federal Register Notice 

of Final Rulemaking.

 b. Compact fluorescent lamp standard Sets standard for fluorescent 

lamps in 20006.

Requires new purchases of 

compact fluorescent bulbs to 

meet the standard.

Federal Register Notice 

of Final Rulemaking.

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 187
Appendix A

Legislation Brief description AEO handling Basis

 c. Ceiling fan light kit standard Sets standard for ceiling 

fans and ceiling fan light 

kits in 2007.

Reduce lighting electricity 

consumption by appropriate 

amount.

Number of ceiling fan 

shipments and estimated 

kWh savings per unit 

determine overall savings.

 d. Dehumidifier standard Sets standard for 

dehumidifiers in 2012.

Reduce dehumidfier 

electricity consumption by 

appropriate amount.

Number of dehumidifier

shipments and estimated 

kWh savings per unit 

determine overall savings.

 e. Energy-efficient equipment tax credit Purchasers of certain 

energy-efficient equipment 

can claim tax credits in 

2006 and 2007.

Reduce cost of applicable

equipment by specified 

amount.

 f. New home tax credit Builders receive $1000 or

$2000 tax credit if they 

build homes 30 or 50 

percent better than code in 

2006 and 2007.

Reduce shell package cost 

for these homes by specified 

amount.

Cost reductions to 

consumers are assumed 

to be 100 percent of the 

builder’s tax credit.

 g. Energy-efficient appliance tax credit Producers of energyefficient refrigerators, 

dishwashers, and clothes 

washers receive tax 

credits for each unit they 

produce that meets certain 

efficiency specifications

Assume the cost savings are 

passed on to the consumer, 

reducing the price of the 

appliance by the specified

amount.

Cost reductions to 

consumers are assumed 

to be 100 percent of the 

producer’s tax credit.

D. Energy Independence and Security Act of 2007 (EISA 2007) Public Law 110-140.

a. General service incandescent lamp 

 standard

Require less wattage for 

bulbs in 2012-2014 and 

2020.

Reduce wattage for new 

bulbs by 28 percent in 2013 

and 67 percent in 2020.

Federal Register Notice of 

Final Rulemaking.

b. External power supply standard Sets standards for external 

power supplies in 2008.

Reduce external power 

supply electricity 

consumption by

appropriate amount.

Number of shipments and

estimated kWh savings 

per unit determine overall 

savings.

c. Manufactured housing code Require manufactured 

homes to meet latest IECC 

in 2011.

Require that all 

manufactured homes 

shipped after 2011 meet the 

IECC 2006

EISA 2007.

E. Energy Improvement and Extension Act of 2008 (EIEA 2008) Public Law 110-343.

a. Energy-efficient equipment tax credit Purchasers of certain 

energy-efficient equipment 

can claim tax credits 

through 2016.

Reduce the cost of 

applicable equipment by 

specified amount.

EIEA 2008.

b. Energy-efficient appliance tax credit Producers of energyefficient refrigerators, 

clothes washers, and 

dishwashers receive tax 

credits for each unit they 

produce that meets certain 

efficiency specifications, 

subject to an annual cap.

Assume the cost savings are 

passed on to the consumer, 

reducing the price of the 

appliance by the specified

amount.

Cost reductions to consumer 

are assumed to be 100 

percent of the producer’s tax 

credit.

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Legislation Brief description AEO handling Basis

F. American Recovery and Reinvestment Act of 2009 Public Law 111-5.

 a. Energy-efficient equip-

 ment tax credit

Increases cap to $1500 of energyefficient equipment specified 

under Section C(d) above. 

Removes cap for PV, wind, and 

ground-source heat pumps

Reduce the cost of applicable

equipment by specified amount.

EPACT 2005 and ARRA 

2009.

 b. Weatherization and State

 Energy Programs

Increases funding for 

weatherization and other 

programs to increase the energy 

efficiency of existing housing 

stock.

Apply annual funding amount to

existing housing retrofits. Savings for 

heating and cooling based on $2600 

per home investment as specified in 

weatherization program

evaluation.

ARRA 2009.

G. Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 Public Law 111-312.

 a. Energy-efficient 

 equipment tax credit

Extends tax credits for some 

energy-efficient equipment, 

generally to EISA 2007 amounts.

Reduce the cost of applicable 

equipment by specified amount.

Commercial sector

A. National Appliance Energy 

Conservation Act of 1987

Requires Secretary of Energy to 

set minimum efficiency standards 

for 10 appliance categories.

Included for categories represented 

in the AEO commercial sector 

forecast.

 a. Room air conditioners Current standard of 9.8 EER 

increasing to 10.9 CEER in 2014.

Federal Register Notice of 

Final Rulemaking.

 b. Other residential-size 

 air conditioners (<5.4 

 tons)

10 SEER before 2006 for central air 

conditioning and heat pumps; 13 

SEER in 2006; 14 SEER in 2015.

Federal Register Notice of 

Final Rulemaking.

 c. Fluorescent lamp 

 ballasts

Current standard of 0.90 power 

factor and minimum efficacy factor 

for F40 and F96 lamps based on 

lamp size and wattage, increasing 

to higher efficacy factor in 2005 

that limits purchases to electronic 

ballasts.

Federal Register Notice of 

Final Rulemaking.

B. Energy Policy Act of 1992 (EPACT92)

 a. Building codes Incorporated in commercial building 

shell assumptions. Efficiency of new 

relative to existing shell represented 

in shell efficiency indices. Assumes 

shell efficiency improves 6.9 and 

15.0 percent by 2040 for existing 

buildings and new construction, 

respectively.

Based on Science 

Applications International 

Corporation commercial 

shell indices for 2003 

developed for EIA in 2008 

and 2011.

 b. Window labeling Designed to help consumers 

determine which windows are 

more energy efficient.

Incorporated in commercial building 

shell assumptions. Efficiency of new 

relative to existing shell represented 

by shell efficiency indices. Assume 

shell efficiency improves 6.9 and 

15.0 percent by 2040 for existing 

buildings and new construction, 

respectively.

Based on Science 

Applications International 

Corporation commercial 

shell indices for 2003 

developed for EIA in 2008 

and 2011.

 c. Commercial furnaces 

 and boilers

Gas-fired furnaces and boilers: 

Current standard is 0.80% thermal 

efficiency. Oil furnaces and boilers: 

Current standard is 0.81% thermal 

efficiency for furnaces, 0.83% 

thermal efficiency for boilers.

Public Law 102-486: 

EPACT92. Federal Register 

Notice of Final Rulemaking.

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Legislation Brief description AEO handling Basis

 d. Commercial air 

 conditioners and heat 

 pumps

Air-cooled air conditioners and heat 

pumps less than 135,000 

Btu: 2001 standard of 8.9 EER. 

Air-cooled air conditioners and heat 

pumps greater than 135,000 Btu: 

2001 standard of 8.5 EER.

Public Law 102-486: 

EPACT92.

 e. Commercial water heaters Natural gas and oil: EPACT 

standard 0.78-percent thermal 

efficiency increasing to 80-percent 

thermal efficiency for gas units in 

2003.

Public Law 102-486: 

EPACT92. Federal 

Register Notice of Final 

Rulemaking.

 f. Lamps Incandescent: 16.9 lumens per 

watt. Fluorescent 75 and 80 lumens 

per watt for 4-and 8-foot lamps, 

respectively.

 g. Electric motors Specifies minimum efficiency 

levels for a variety of motor 

types and sizes.

End-use services modeled at the 

equipment level. Motors 

contained in new equipment 

must meet the standards.

Public Law 102-486: 

EPACT92.

 h. Federal energy management Requires federal agencies to 

reduce energy consumption 

20 percent by 2000 relative 

to 1995.

Superseded by Executive Order 

13123, EPACT05, and EISA07.

Superseded by Executive 

Order 13123.

 i. Business investment energy 

 credit

Provides a permanent 

10-percent investment tax 

credit for solar property.

Tax credit incorporated in cash 

flow for solar generation systems. 

Investment cost reduced 10 percent 

for solar water heaters.

Public Law 102-486: 

EPACT92

C. Executive Order 13123. Greening 

the Government Through Efficient 

Energy Management

Requires federal agencies to 

reduce energy consumption 

30 percent by 2005 and 35 

percent by 2010 relative to 

1985 through life-cycle costeffective energy measures.

Superseded by EPACT05 and 

EISA07.

Superseded by EPACT05 

and EISA07.

D. Energy Policy Act of 2005 (EPACT05)

 a. Commercial package air 

 conditioners and heat 

 pumps

Sets minimum efficiency 

levels in 2010.

Air-cooled air conditioners/heat 

pumps less than 135,000 Btu: 

standard of 11.2/11.0 EER and 

heating COP of 3.3. Air-cooled air 

conditioners/heat pumps greater 

than 135,000 Btu: standard of 

11.0/10.6 EER and heating COP of 

3.2.

Public Law 109-58: 

EPACT05.

 b. Commercial refrigerators, 

 freezers, and automatic 

 icemakers

Sets minimum efficiency 

levels in 2010.

Set standard by level of 

improvement above stock average 

efficiency in 2003.

Public Law 190-58: 

EPACT05.

 c. Lamp ballasts Bans manufacture or import 

of mercury vapor lamp 

ballasts in 2008. Sets 

minimum efficacy level for 

T12 energy saver ballasts in 

2009 and 2010 based on 

application.

Remove mercury vapor lighting 

system from technology choice 

menu in 2008. Set minimum 

efficacy of T12 ballasts at 

specified standard levels.

Public Law 102-58: 

EPACT05.

 d. Compact fluorescent lamps Sets standard for medium 

base lamps at ENERGY STAR 

requirements in 2006.

Set efficacy level of compact 

fluorescent lamps at required level.

Public Law 109-58: 

EPACT05.

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Legislation Brief description AEO handling Basis

 e. Illuminated exit signs and 

 traffic signals

Set standards at ENERGY 

STAR requirements in 2006.

Reduce miscellaneous electricity 

consumption by appropriate 

amount.

Number of shipments, 

share of shipments that 

currently meet standard, 

and estimated kWh 

savings per unit determine 

overall savings.

 f. Distribution transformers Sets standard as National 

Electrical Manufacturers 

Association Class I Efficiency 

levels in 2007, with an update 

effective in 2016

Effects of the standard are 

included in estimating the share 

of miscellaneous electricity 

consumption attributable to 

transformer losses.

Public Law 109-58: 

EPACT05.

 g. Pre-rinse spray valves Sets maximum flow rate to 1.6 

gallons per minute in 2006.

Reduce energy use for water 

heating by appropriate amount.

Number of shipments, 

share of shipments that 

currently meet standard, 

and estimated kWh 

savings per unit determine 

overall savings.

 h. Federal energy management Requires federal agencies to 

reduce energy consumption 

20 percent by 2015 relative to 

2003 through life-cycle costeffective energy measures.

The federal “share” of the 

commercial sector uses the 

10-year Treasury note rate as 

a discount rate in equipment 

purchase decisions as opposed 

to adding risk premiums to the 

10-year Treasury note rate to 

develop discount rates for other 

commercial decisions

Public law 109-58: 

EPACT05. Superseded by 

EISA07.

 i. Business investment tax credit

 for fuel cells and microturbines

Provides a 30-percent 

investment tax credit for 

fuel cells and a 10-percent 

investment tax credit for 

microturbines installed in 

2006 through 2008.

Tax credit incorporated in 

cash flow for fuel cells and 

microturbines.

Public Law 109-58: 

EPACT05. Extended 

through 2008 by Public 

Law 109-432. Extended 

through 2016 by EIEA08.

 j. Business solar investment tax 

 credit

Provides a 30-percent 

investment tax credit for solar 

property installed in 2006 

through 2008.

Tax credit incorporated in cash 

flow for solar generation systems. 

Investment cost reduced 30 

percent for solar water heaters.

Public Law 109-58: 

EPACT05. Extended 

through 2008 by Public 

Law 109-432. Extended 

through 2016 by EIEA08.

E. Energy Independence and Security Act of 2007 (EISA07)

 a. Commercial walk-in coolers 

 and walk-in freezers

Requires use of specific 

energy efficiency measures in 

equipment manufactured in or 

after 2009.

Set standard by equivalent level of 

improvement above stock average 

efficiency in 2003.

Public Law 110-140: 

EISA07.

 b. Incandescent and halogen 

 lamps

Sets maximum allowable 

wattage based on lumen 

output starting in 2012.

Remove incandescent and 

halogen general service lighting 

systems that do not meet 

standard from technology choice 

menu in 2012.

Public Law 110-140: 

EISA07.

 c. Metal halide lamp ballasts Sets minimum efficiency levels 

for metal halide lamp ballasts 

starting in 2009.

Remove metal halide lighting 

systems that do not meet 

standard fromtechnology choice 

menu in 2009. Set minimum 

system efficiency to include 

specified standard levels for 

ballasts -ranging from 88 to 94 

percent based on ballast type.

Public Law 110-140: 

EISA07.

d. Federal use of energy-efficient 

 lighting

Requires use of energyefficient lighting fixtures and 

bulbs in federal buildings to 

the maximum extent possible 

starting in 2009.

Increase proportion of sector 

using 10 year treasury note rate 

for lighting purchase decisions 

to represent all existing and new 

federal floorspace in 2009.

Public Law 110-140: 

EISA07.

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Legislation Brief description AEO handling Basis

e. Federal energy 

 management

Requires federal agencies to 

reduce energy consumption per 

square foot 30 percent by 2015 

relative to 2003 through life-cycle 

cost-effective energy measures.

The federal “share” of the commercial 

sector uses the 10-year Treasury note 

rate as a discount rate in equipment 

purchase decisions as opposed to 

adding risk premiums to the 10-year 

Treasury note rate to develop discount 

rates for other commercial decisions.

Public Law 110-140: 

EISA07.

F. Energy Improvement and Extension Act of 2008 (EIEA08)

a. Business solar 

 investment tax credit

Extends the EPACT05 30-percent 

investment tax credit for solar 

property through 2016.

Tax credit incorporated in cash flow for 

solar generation systems. Investment 

cost reduced 30 percent for solar water 

heaters.

Public Law 110-343: 

EIEA08.

b. Business investment tax 

 credit for fuel cells and 

 microturbines

Extends the EPACT05 30-percent 

investment tax credit for fuel cells 

and 10-percent investment tax 

credit for microturbines through 

2016.

Tax credit incorporated in cash flow for 

fuel cells and microturbines.

Public Law 110-343: 

EIEA08

c. Business investment tax 

 credit for CHP systems

Provides a 10-percent investment 

tax credit for CHP systems 

installed in 2009 through 2016

Tax credit incorporated in cash flow for 

CHP systems.

Public Law 110-343: 

EIEA08.

d. Business investment tax 

 credit for small wind 

 turbines

Provides a 30-percent investment 

tax credit for wind turbines 

installed in 2009 through 2016.

Tax credit incorporated in cash flow for 

wind turbine generation systems.

Public Law 110-343: 

EIEA08.

e. Business investment tax 

 credit for geothermal 

 heat pumps

Provides a 10-percent investment 

tax credit for geothermal heat 

pump systems installed in 2009 

through 2016.

Investment cost for geothermal heat 

pump systems reduced 10 percent.

Public Law 110-343: 

EIEA08.

G. American Recovery and Reinvestment Act of 2009 (ARRA09)

a. Business investment tax 

 credit for small wind 

 turbines

Removes the cap on the EIEA08 

30-percent investment tax credit 

for wind turbines through 2016.

Tax credit incorporated in cash flow for 

wind turbine generation systems.

Public Law 111-5: ARRA09.

b. Stimulus funding to 

 federal agencies

Provides funding for efficiency 

improvement in federal 

buildings and facilities.

Increase the proportion of sector using 

the 10-year Treasury note rate for 

purchase decisions to include all existing 

and new federal floorspace in years 

stimulus funding is available to account 

for new, replacement, and retrofit 

projects. Assume some funding is used 

for solar generation, small wind turbine, 

and fuel cell installations.

Public Law 111-5: ARRA09.

c. State Energy Program 

 funding and energy 

 efficiency and 

 conservation block 

 grants

Provides grants for state and local 

governments for energy efficiency 

and renewable energy purposes. 

State Energy Program funding 

conditioned on enactment of new 

building codes.

Increase the proportion of sector using 

the 10-year Treasury note rate for 

purchase decisions to include all public 

buildings in years stimulus funding is 

available. Increase new building shell 

efficiency to 10 percent better than 

2003 by 2018 for improved building 

codes. Assume some funding is used 

for solar generation and small wind 

turbine systems.

Public Law 111-5: ARRA09.

d. Funding for smart grid 

 projects

Provides funding for smart grid 

demonstration projects.

Assume smart grid technologies cause 

consumers to become more responsive 

to electricity price changes by increasing 

the price elasticity of demand for certain 

end uses.

Public Law 111-5; ARRA09.

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Legislation Brief description AEO handling Basis

Industrial sector

A. Energy Policy Act of 1992 (EPACT92)

 a. Motor efficiency standards Specifies minimum efficiency

levels for a variety of motor

types and sizes.

New motors must meet the

standards.

Standard specified in

EPACT92. 10 CFR 431.

 b. Boiler efficiency standards Specifies minimum combustion 

efficiency for package boilers 

larger than 300,000 Btu/hr. 

Natural Gas boilers: 80 

percent, oil boilers: 83 

percent.

All package boilers are assumed 

to meet the efficiency standards. 

While the standards do not apply 

to field-erected boilers, which are 

typically used in steam-intensive 

industries, we assume they meet 

the standard in the AEO.

Standard specified in

EPACT92. 10 CFR 431.

B. Clean Air Act Amendments (CAAA90)

 a. Process emissions Numerous process emissions

requirements for specified

industries and/or activities.

Not modeled because they are 

not directly related to energy 

projections.

CAAA90, 40 CFR 60.

 b. Emissions related to hazardous/

 toxic substances

Numerous emissions

requirements relative to

hazardous and/or toxic

substances.

Not modeled because they are 

not directly related to energy 

projections.

CAAA90, 40 CFR 60.

 c. Industrial SO2 emissions Sets annual limit for industrial

SO2 emissions at 5.6 million

tons. If limit is reached,

specific regulations could be

implemented.

Industrial SO2 emissions 

are not projected to reach 

the limit (Source: EPA, 

National Air Pollutant 

Emissions Trends:1990-1998, 

EPA-454/R-00-002, March 

2000, p. 4-3.)

CAAA90, Section 406 

(42 USC 7651)

 d. Industrial boiler hazardous air 

 pollutants

Requires industrial boilers and 

process heaters to conduct 

periodic tune-ups or meet 

emissions limits on HAPs to 

comply with the Maximum 

Achieveable Control 

Technology (MACT) Floor. 

Regulations finalized December 

2012.

Costs of compliance that are not 

offset by efficiency gains (nonrecoverable costs) modeled as 

an additional capital cost in the 

Macroeconomic Activity Module 

(MAM) based on proposed 

regulations as of September 2012.

U.S. Environmental 

Protection Agency, 

National Emissions 

Standards for Hazardous 

Air Pollutants for 

Industrial, Commercial, 

and Institutional Boilers, 

Major Source (40 CFR 

63, Subpart DDDDD) and 

Area Source (40 CFR 63 

Part JJJJJJ)

 e. Emissions from stationary diesel

 engines

Requires engine

manufacturers to meet the

same emission standards as

nonroad diesel engines. Fully 

effective in 2011.

New stationary engines 

meet the standards.

40 CFR Parts 60, 85, 89, 

94,

1039, 1065, and 1068.

C. Energy Policy Act of 2005 (EPACT05)

 a. Physical energy intensity Voluntary commitments to

reduce physical energy

intensity by 2.5 percent

annually for 2007-2016.

Not modeled because

participation is voluntary;

actual reductions will depend

on future, unknown

commitments.

EPACT2005, Section 106 

(42 USC 15811)

 b. Mineral components of cement of 

 concrete

Increase in mineral component 

of federally procured cement or 

concrete.

Not modeled. EPACT2005, Section 108 

(42 USC 6966).

 c. Tax credits for coke oven Provides a tax credit of $3.00

per barrel oil equuivalent, 

limited to 4000 barrels per 

day average. Applies to most 

producers of coal coke or coke 

gas.

Not modeled because no 

impact on U.S. coke plant activity 

is anticipated.

EPACT2005, Section 1321 

(29 USC 29).

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Legislation Brief description AEO handling Basis

D. The Energy Independence and Security Act of 2007 (EISA2007)

 a. Motor efficiency standards Supersedes EPACT1992 Efficiency 

Standards no later than 2011.

Motor purchases must meet the 

EPAct1992 standards through 

2010; afterwards purchases must 

meet the EISA2007 standards.

EISA2007

E. The Energy Improvement and Extension Act of 2008 (EISA2008)

 a. Combined heat and power 

 tax incentive

Provides an investment tax credit for 

up to 15 megawatts of capacity in 

combined heat and power systems of 50 

megawatts or less through 2016

Costs of systems adjusted to 

reflect the credit.

EIEA2008, Title I, Sec. 103

Transportation sector

A. Energy Policy Act of 1992 

(EPACT92)

Increases the number of alternative 

fuel vehicles and alternative fuel use in 

federal, state, and fuel provided fleets.

Assumes federal, state and 

fuel provided fleets meet the 

mandated sales requirements.

Energy Policy Act of 1992, 

Public Law 102-486-Oct. 24, 

1992.

B. Low Emission Vehicle 

Program (LEVP)

The Clean Air Act provides California 

the authority to set vehicle criteria 

emission standards that exceed federal 

standards. A part of that program 

mandates the sale of zero-emission 

vehicles by manufacturers, other 

nonattainment states are given the 

option of opting into the federal or 

California emission standards.

Incorporates the LEVP program 

as amended on August 4, 2005. 

Assumes California, Connecticut, 

Maine, Massachusetts, New 

Jersey, New York, Rhode 

island, Vermont, Oregon, and 

Washington adopt the LEVP 

program as amended August 4, 

2005 and that the proposed 

sales requirements for hybrid, 

electric, and fuel cell vehicles are 

met.

Section 177 of the Clean Air 

Act, 42 U.S.C. sec. 7507 

(1976) and CARB, California 

Exhaust Emissions Standards 

and Test Procedures for 

Passenger Cars, Light-Duty 

Trucks, and Medium-Duty 

Vehicles, August 4, 2005.

C. Corporate Average Fuel 

Economy (CAFE) Standard for 

Light Duty Vehicles

Requires manufacturers to produce 

vehicles that meet a minimum federal 

average fuel economy standard, 

promulgated jointly for model years 

2012-2016 and 2017-2025 with an 

average greenhouse emissions standard; 

cars and light trucks are regulated 

separately.

CAFE standards are increased 

for model years 2011 through 

2016 to meet the final CAFE 

rulemakings for model year 2011 

and 2012 to 2016, respectively. 

CAFE standards are increased for 

model years 2017 to 2025 to meet 

final CAFE joint rulemakings for 

model year 2017 to 2022 and to 

meet augural CAFE standards for 

model year 2023 to 2025, which 

will undergo a midterm evaluation 

to finalize. CAFE standards are 

held constant through the end of 

the projection.

Energy Policy Conservation 

Act of 1975; Title 49 United 

States code, Chapter 329; 

Energy Independence and 

Security Act of 2007, Title 

1, Section 102; Average 

Fuel Economy Standards 

Passenger Cars and Light 

Trucks Model Year 2011; 

Federal Register, Vol. 74, No. 

59, March 2009; Light-Duty 

Vehicle Greenhouse Gas 

Emission Standards and 

Corporate Average Fuel 

Economy Standards, Final 

Rule, Federal Register, Vol. 

75, No. 88, May 2010; 2017 

and Later Model Year LightDuty Vehicle Greenhouse 

Gas Emissions and Corporate 

Average Fuel Economy 

Standards Federal Register, 

Vol. 77, No. 199, October 

2012.

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D. Electric, Hybrid, and 

Alternative Fuel Vehicle Tax 

Incentives

Federal tax incentives are provided 

to encourage the purchase of electric, 

hybrid and or alternative fuel vehicles. 

For example, tax incentives for hybrid 

vehicles in the form of a $2,000 income 

tax deduction.

Incorporates the federal tax 

incentives for hybrid and 

electric vehicles.

IRS Technical Publication 535; 

Business Expenses.

E. Plug-in Hybrid Vehicle Tax 

Credit

EIEA2008 grants a tax credit of $2,500 

for PHEVs with at least 4kWh of 

battery capacity, with larger batteries 

earning an additional $417 per kWh up to 

a maximum of $7,500 for light-duty 

PHEVs. The credit will apply until 250,000 

eligible PHEVs are sold or until 2015, 

whichever comes first.

Incorporates the federal tax 

credits for PHEVs.

Energy Improvement and

Extension Act of 2008, H.R.6049.

F. State Electric, Hybrid, and 

Alternative Fuel Vehicle 

Tax and Other Incentives

Approximately 20 states provide tax 

and other incentives to encourage 

the purchase of electric, hybrid and/

or alternative fuel vehicles. The tax 

incentives are in the form of income 

reductions, tax credits, and exemptions. 

Other incentives include use of HOV 

lanes and exemptions from emissions 

inspections and licensing fees. The 

incentives offered and the mix varies by 

state. For example, Georgia offers a tax 

credit of $5,000 for electric vehicles and 

Oklahoma offers a tax credit of $1,500 for 

hybrid and alternative fuel vehicles.

Does not incorporate state 

tax and other incentives for 

hybrid, electric, and other 

alternative fuel vehicles.

State laws in Arizona, Arkansas, 

California, Colorado, Delaware, 

Florida, Georgia, Iowa, Kansas, 

Louisiana, Maine, Maryland, 

Michigan, New Hampshire, New 

York, Oklahoma, Pennsylvania,

Utah, Virginia, and Washington.

G. HD National Program; 

Greenhouse Gas Emissions 

and Fuel Consumption 

Standards for Heavy-Duty 

Vehicles

Requires on-road heavy-duty vehicle 

manufacturers to produce vehicles 

that meet a minimum federal average 

greenhouse gas emission standard, 

issued by the EPA, for model years 2014-

2018. NHTSA established voluntary fuel 

consumption standards for MY 2014-

2015, and mandatory fuel consumption 

standards for MY 2016 and beyond for onroad heavy-duty trucks and their engines; 

vocational and combination engines are 

regulated separately.

HD National program 

standards begin for MY 2014 

as set by the GHG emissions 

portion of the rule with the 

assumption that the vehicles 

comply with the voluntary 

portion of the rule for fuel 

consumption. The model 

allows for both the engine 

and chassis technologies to 

meet the standards.

Section 202 of the Clean Air 

Act; Title 49 United States 

code, Chapter 32902[k]; Energy 

Independence and Security Act 

of 2007, Title 1, Section 102; 

Federal Register, Vol. 76, No. 179, 

September 2011.

Electric power generation

A. Clean Air Act Amendments 

of 1990 (CAAA90)

Established a national limit on electricity 

generator emissions of sulfur dioxide to 

be achieved through a cap-and-trade 

program.

Sulfur dioxide cap and trade 

program is explicitly 

modeled, choosing the 

optimal mix of options 

for meeting the national 

emissions cap.

Clean Air Act Amendments 

of 1990, Title IV, Sections 401 

through 406, Sulfur Dioxide 

Reduction Program, 42 U.S.C. 

7651a through 7651e.

Set boiler-type-specific nitrogen oxide 

emissions limits for electricity generators.

Assumes each boiler installs 

the options necessary to 

comply with their nitrogen 

oxide emissions limit.

Clean Air Act Amendments 

of 1990, Title IV, Sections 

407, Nitrogen Oxide Emission 

Reduction Program, 42 U.S.C. 

7651f.

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Legislation Brief description AEO handling Basis

Requires the EPA to establish national 

ambient air quality standards 

(NAAQS). In 1997, EPA set new 

standards for ground level ozone and 

fine particulates. EPA is currently 

determining which areas of the ountry 

are not in compliance with the new 

standards. Area designations were 

made in December 2004. States 

submitted their compliance plans, and 

have until 2009-2014 to bring all areas 

into compliance.

These standards are not 

explicitly represented, but the 

Clean Air Interstate Rule is 

incorporated (described below) 

and was developed to help 

states meet their NAAQS.

Clean Air Act Amendment of 

1990, Title I, Sections 108 and 

109, National Ambient Air Quality 

Standards for Ozone, 40 CFR 

Part 50, Federal Register, Vol 68, 

No 3, January 8, 2003. National 

Ambient Air Quality Standards

for Particulate Matter, 40 CFR Part 

50, Federal Register, Vol. 62, No. 

138, July 18, 1997.

B. Clean Air Interstate Rule 

(CAIR)

CAIR imposes a two-phased limit on 

emissions of sulfur dioxide and/or 

nitrogen oxide from electric generators 

in 27 states and the District of 

Columbia.

Cap and trade programs for SO2

and NOx are modeled explicitly, 

allowing the model to choose 

the best method for meeting the 

emission caps.

Federal Register, Vol. 70, No. 91

(May 12, 2005), 40 CFR Parts 51, 

72, 73, 74, 77, 78 and 96.

C. Mercury and Air Toxics 

Standards (MATS)

MATS sets standards to reduce air 

pollution from coal and oil-fired power 

plants greater than 25 megawatts. 

The rule requires plants achieve 

the maximum achievable control 

technology for mercury, hydrogen 

chloride (HCl) and fine particulate 

matter (PM 2.5).

The EMM assumes that all 

coal-fired generating plants 

above 25 megawatts will comply 

beginning in 2016. Plants are 

assumed to reduce mercury 

emissions by 90 percent relative 

to uncontrolled levels. Because 

the EMM does not model HCl or 

PM 2.5 explicitly, to meet those 

requirements, coal plants are 

required to install either an FGD 

or a dry sorbent injection system 

including a full fabric filter.

Environmental Protection 

Agency, “Mercury and Air Toxics 

Standards,” website epa.gov/mats.

D. Energy Policy Act of 1992 

(EPACT92)

Created a class of generators referred 

to as exempt wholesale generators 

(EWGs), exempt from PUHCA as long 

as they sell wholesale power.

Represents the development 

of Exempt Wholesale 

Generators (EWGs) or what 

are now referred to as 

independent power producers 

(IPPs) in all regions.

Energy Policy Act of 1992, Title 

VII, Electricity, Subtitle A, Exempt 

Wholesale Generators.

E. The Public Utility Holding 

Company Act of 1935 

(PUHCA)

PUHCA is a federal statue which was 

enacted to legislate against abusive 

practices in the utility industry. The 

act grants power to the U.S. Securities 

and Exchange Commission (SEC) 

to oversee and outlaw large holding 

companies which might otherwise 

control the provision of electrical 

service to large regions of the country. 

It gives the SEC power to approve or 

deny mergers and acquisitions and, if 

necessary, force utility companies to 

dispose of assets or change business 

practices if the company’s structure of 

activities are not deemed to be in the 

public interest.

It is assumed that holding 

companies act competitively 

and do not use their regulated 

power businesses to crosssubsidize their unregulated 

businesses.

Public Utility Holding Company

Act of 1936.

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Appendix A

Legislation Brief description AEO handling Basis

F. FERC Orders 888 and 889 FERC has issued two related rules: 

Orders 888 and 889, designed to 

bring low-cost power to consumers 

through competition, ensure 

continued reliability in the industry, 

and provide for open and equitable 

transmission services by owners of 

these facilities. Specifically, Order 

888 requires open access to the 

transmission grid currently owned and 

operated by utilities. The transmission 

owners must file nondiscriminatory 

tariffs that offer other suppliers the 

same services that the owners provide 

for themselves. Order 888 also allows 

these utilities to recover stranded costs 

(investments in generating assets that 

are unrecoverable due to consumers 

selecting another supplier). Order 

889 requires utilities to implement 

standards of conduct and a Open 

Access Same-time Information System 

(OASIS) through which utilities and 

non-utilities can receive information 

regarding the transmission system. 

Consequently, utilities are expected 

to functionally or physically unbundle 

their marketing functions from their 

transmission functions.

These orders are represented in 

the forecast by assuming that all 

generators in a given region are 

able to satisfy load requirements 

anywhere within the region. 

Similarly, it is assumed that 

transactions between regions 

will occur if the cost differentials 

between them make it economic 

to do so.

Promoting Wholesale Competition 

Through Open Access, NonDiscriminatory Transmission 

Services by Public Utilities; Public 

Utilities and Transmitting Utilities, 

ORDER NO. 888 (Issued April 

24, 1996), 18 CFR Parts 35 and 

385, Docket Nos. RM95-8-000 

and RM94-7-001. Open Access 

Same-Time Information System 

(formerly Real-Time Information 

Networks) and Standards of 

Conduct, ORDER NO. 889, 

(Issued April 24, 1996), 18 CFR 

Part 37, Docket No. RM95-9-000.

G. New Source Review (NSR) On August 28, 2003, the EPA issued 

a final rule defining certain power 

plant and industrial facility activities 

as routine maintenance, repair and 

replacement, which are not subject to 

new source review (NSR). As stated 

by EPA, these changes provide a 

category of equipment replacement 

activities that are not subject to Major 

NSR requirements under the routine 

maintenance, repair and replacement 

(RMRR) exclusion.[1] Essentially this 

means that power plants and industrial 

facilities engaging in RMRR activities 

will not have to get preconstruction 

approval from the state or EPA and 

will not have to install best available 

emissions control technologies 

that might be required if NSR were 

triggered.

It is assumed that coal plants will 

be able to increase their output 

as electricity demand increases. 

Their maximum capacity factor 

is set at 75 percent. No increases 

in the capacity of existing plants 

is assumed. If further analysis 

shows that capacity uprates may 

result from the NSR rule, they 

will be incorporated in future 

AEOs. However, at this time, 

the NSR rule is being contested 

in the courts.

EPA, 40 CFR Parts 51 and 

52, Deterioration (PSD) and 

Non-Replacement Provision 

of the Vol. 68, No. 207, page 

61248, Prevention of Significant 

Attainment New Source Review 

(NSR): Equipment Routine 

Maintenance, Repair and 

Replacement Exclusion; Final 

Rule, Federal Register, October 27, 

2003.

H. State RPS Laws, Mandates,

and Goals

Several states have enacted laws 

requiring that a certain percentage 

of their generation come from 

qualifying renewable sources.

The AEO reference case 

represents the Renewable 

Portfolio Standard (RPS) or

substantively similar laws from 

29 states and the District of 

Columbia. As described in the

The states with RPS or other 

mandates providing quantified 

projections are detailed in the 

Legislation and Regulations 

section of this report.

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 197
Appendix A

Legislation Brief description AEO handling Basis

Renewable Fuels Module chapter of 

this document,

mandatory targets from the 

various states are aggregated at 

the regional level, and achievement 

of nondiscretionary compliance 

criteria is evaluated for each region.

I. Regional and State Air 

Emissions Regulations

The Northeast Regional Greenhouse Gas 

Initiative (RGGI) applies to fossil-fueled 

power plants over 25 megawatts in the 

Northeastern United States. The state of 

NJ withdrew in 2011, leaving 9 states in the 

program. The rule caps CO2 emissions and 

requires they account for CO2 emitted with 

allowances purchased at auction.

In February 2013, program officials 

announced a tightening of the cap 

beginning in 2014.

The impact of RGGI is included 

in the EMM, making adjustments 

when needed to estimate the 

emissions caps at the regional 

level used in NEMS. AEO2014 

incorporates the revised target 

beginning in 2014.

Regional Greenhouse Gas Initiative 

Model rule, www.rggi.org

The California Assembly Bill 32 (AB32) 

sets GHG reduction goals for 2020 for 

California. A cap-and-trade program was 

designed to enforce the caps. The capand-trade program applies to multiple 

economic sectors including electric power 

plants, large industrial facilities, suppliers 

of transportation fuel and suppliers of 

natural gas. Emissions resulting from 

electricity generated outside California but 

consumed in the state are also subject to 

the cap.

The EMM models the cap-andtrade program explicitly for CO2

for California through an emission 

constraint that accounts for 

emissions from the other sectors. 

Limited banking and borrowing of 

allowances as well as an allowance 

reserve and offsets are incorporated 

as specified in the Bill.

California Code of Regulations, 

Subchapter 10 Climate Change, Article 

5, Sections 95800 to 96023, Title 

17, “California Cap on Greenhouse 

Gas Emissions and MarketBased Compliance Mechanisms,” 

(Sacramento, CA: July 2011).

J. Energy Policy Act of 2005 Extended and substantially 

expanded and modified the Production 

Tax Credit, originally created by

EPACT1992.

EPACT2005 also adds a PTC for up 

to 6,000 megawatts of new nuclear 

capacity and a 

$1.3 billion investment tax credit 

for new or repowered coal-fired 

power projects. The tax credits 

for renewables, nuclear and coal 

projects are explicitly modeled as 

specified in the law and subsequent 

amendments. Because the tax 

ccredits for new coal projects have 

been fully allocated, the EMM does 

not assume future coal capacity will 

receive any tax credits.

Energy Policy Act of 2005, Sections 

1301, 1306, and 1307

K. American Recovery and

Reinvestment Act of 2009

Extends the Production Tax Credit (PTC) 

to wind facilities constructed by December 

31, 2012 and to other eligible renewable 

facilities constructed by December 31, 

2013. Allows PTC-eligible facilities 

to claim a 30-percent investment tax 

credit (ITC) instead of the PTC. Projects 

starting construction by the end of 2010 

(subsequently extended to the end of 

2011) may elect to take a cash grant equal 

to the value of the 30-percent ITC instead 

of either tax credit. 

The extensions of the PTC 

and 30-percent ITC are represented 

in the AEO

reference case as specified 

in the law. The AEO does not 

distinguish between the 

effects of the 30-percent ITC and 

the equivalent cash grant, and 

the cash grant is not specifically 

modeled.

American Recovery and Reinvestment 

Act of 2009, Division B, Title I, Sec. 

1101, 1102, and 1603.

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Appendix A

Legislation Brief description AEO handling Basis

ARRA provided $6 billion to pay 

the cost of guarantees for loans 

authorized by the Energy Policy 

Act of 2005. The purpose of these 

loan guarantees is to stimulate the 

deployment of conventional renewable 

and transmission technologies and 

innovative biofuels technologies. 

However, to qualify, eligible projects 

must be under construction by 

September 30, 2011.

AEO2013 includes projects that 

have received loan guarantees 

under this authority, but does 

not assume automatic award of 

the loans to potentially eligible 

technologies.

American Recovery and 

Reinvestment Act of 2009, 

Title IV, “Energy and Water 

Development”, Section 406.

ARRA provides $4.5 billion for smart 

grid demonstration projects. These 

generally include a wide array of 

measurement, communications, and 

control equipment employed throughout the transmission and distribution 

system that will enable real-time 

monitoring of the production, flow, 

and use of power from generator to 

consumer.

In the electricity module, it was

assumed that line losses would

fall slightly, peak loads would

fall as customers shifted their

usage patterns, and customers

would be more responsive to

pricing signals.

American Recovery and 

Reinvestment Act of 2009, 

Title IV, “Energy and Water 

Development”, Section 405.

ARRA provides $800 million to fund 

projects under the Clean Coal Power 

Initiative program focusing on capture 

and sequestration of greenhouse gases.

It was assumed that one gigawatt 

of new coal with sequestration 

capacity would come online by 

2018.

American Recovery and 

Reinvestment Act of 2009, 

Title IV, “Energy and Water

Development”

L. American Taxpayer Relief 

Act of 2012 (ATRA)

ATRA was passed on January 1, 

2013 and included several provisions 

extending tax credits to the energy 

sector. Most significantly, it extended 

the PTC for wind by one year, and 

redefined the criteria for all qualifying 

projects to be based on ‘under 

construction’ by December 31, 2013 

rather than in service by that same date, 

thus extending the credit for length of 

the typical construction period.

AEO2014 explicity models the 

revised dates for these tax credits.

American Taxpayer Relief Act of 

2012, P.L. 112-240, Sections 401 

through 412.

M. Nuclear Waste Confidence 

Rule

The U.S. Nuclear Regulatory 

Commission (NRC) Waste Confidence 

Rule originally determined that spent 

nuclear fuel can be safely stored 

onsite for 30 years without significant 

environmental impacts. A 2010 

update amended this part of the rule 

to extend to 60 years. In June 2012, 

the U.S. Court of Appeals for the 

District of Columbia Circuit struck 

down the 2010 amendment, and the 

NRC subsequently issued an order 

that suspended actions related to 

issuance of operating licenses and 

renewals until the rule is revised.

Plants that have not yet submitted 

license renewal applications 

or new units that have not yet 

received an operating license 

may be delayed by the 2012 

order. However, because the NRC 

expects to resolve the issues 

with the rule within two years, 

the AEO2014 assumes that the 

issuance of new operating licenses 

or license renewals will not be 

affected, as they occur further out 

in the forecast.

Federal Register, Vol. 49, No. 171

(1984), Vol. 55, No. 181 (1990), Vol. 

75, No. 246 (2010), U.S. Nuclear 

Regulatory Commission, “CLI-12-16, 

Memorandum and Order” (August 

7, 2012).

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 199
Appendix A

Oil and gas supply

A. The Outer Continental Shelf 

Deep Water Royalty Relief 

Act (DWRRA)

Mandates that all tracts offered by 

November 22, 2000, in deep water in 

certain areas of the Gulf of Mexico 

must be offered under the new bidding 

system permitted by the DWRRA. 

The Secretary of the Interior must offer 

such tracts with a specific minimum 

royalty suspension volume based on 

water depth.

Incorporates royalty rates based 

on water depth.

43 U.S.C. SS 1331-1356 (2002).

B. Energy Policy and 

Conservation Act 

Amendments of 2000

Required the USGS to inventory oil and 

gas resources beneath federal lands.

To date, the Rocky Mountain oil 

and gas resource inventory has 

been completed by the USGS. 

The results of this inventory 

have been incorporated in the 

technically recoverable oil and 

gas resource volumes used for the 

Rocky Mountain region.

Scientific Inventory of Onshore 

Federal Lands: Oil and Gas 

Resources and Reserves and 

the Extent and Nature of 

Restrictions or Impediments 

to their Development: The 

Paradox/San Juan, Uinta/

Piceance, Greater Green River, 

and Powder River Basins and the 

Montana Thrust Belt. Prepared 

by the Departments of Interior, 

Agriculture and Energy, January 

2003.

C. Section 29 Tax Credit for

Nonconventional Fuels

The Alternative Fuel Production Credit 

(Section 29 of the IRC) applies to 

qualified nonconventional fuels from 

wells drilled or facilities placed in 

service between January 1, 1980, and 

December 31, 1992. Gas production 

from qualifying wells could receive a $3 

(1979 constant dollars) per barrel of oil 

equivalent credit on volumes produced 

through December 31, 2002. The 

qualified fuels are: oil produced from 

shale and tar sands; gas from 

geopressurized brine, Devonian 

shale, coal seams, tight formations, 

and biomass; liquid, gaseous, or solid 

synthetic fuels produced from coal; fuel 

from qualified processed formations or 

biomass; and steam from agricultural 

products.

The Section 29 Tax Credit 

expired on December 31, 2002, 

and it is not considered in new 

production decisions. However, 

the effect of these credits 

is implicitly included in the 

parameters that are derived from 

historical data reflecting such 

credits.

Alternative Fuel Production 

Credit (Section 29 of the 

Internal Revenue Code), initially 

established in the Windfall Profit 

Tax of 1980.

D. Energy Policy Act of 2005. Established a program to provide 

grants to enhance oil and gas 

recovery through CO2 injection.

Additional oil resources were 

added to account for increased 

use of CO2-enhanced oil recovery.

Title III, Section 354 of the 

Energy Policy Act of 2005.

Natural gas transmission and distribution

A. Alaska Natural Gas 

Pipeline Act, Sections 

101-116 of the Military 

Construction Hurricane 

Supplemental 

Appropriations Act, 2005.

Disallows approval for a pipeline to

enter Canada via Alaska north of 68 

degrees latitude. Also, provides 

federal guarantees for loans and other 

debt obligations assigned to infrastructure in the United States or Canada 

related to any natural gas pipeline 

Assumes the pipeline construction 

cost estimate for the “southern” 

Alaska pipeline route in projecting 

when an Alaska gas pipeline would 

be profitable to build. With more 

recent increases in cost estimates, 

well beyond $18 billion, the loan 

guarantee is assumed to have 

a minimal impact on the build 

decision.

P.L. 108-324.

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Appendix A

Legislation Brief description AEO handling Basis

system that carries Alaska natural gas 

to the border between Alaska and

Canada south of 68 degrees north 

latitude. This authority would expire 2 

years after the final certificate of public 

convenience and necessity is issued. The 

guarantee will not exceed 1) 80 percent 

of the total capital costs (including 

interest during construction), 2) $18 

billion (indexed for inflation at the time of 

enactment), or 3) a term of 30 years.

B. American Jobs Creation 

Act of 2004, Sections 

706 and 707.

Provides a 7-year cost-of-investment 

recovery period for the Alaska natural 

gas pipeline, as opposed to the currently 

allowed 15-year recovery period, for 

tax purposes. The provision would be 

effective for property placed in service 

after 2013, or treated as such. Effectively 

extends the 15-percent tax credit 

currently applied to costs related to 

enhanced oil recovery to construction 

costs for a gas treatment plant on the 

North Slope that would feed gas into an 

Alaska pipeline to Canada.

The change in the recovery 

period is assumed to have a 

minimal impact on the decision 

to build the pipeline. The 

assumed treatment costs are 

based on company estimates 

made after these tax provisions 

were enacted.

P.L. 108-357.

C. Pipeline Safety, Regulatory 

Certainty, and Job Creation 

Act of 2011 and other 

previous laws and regulations 

on pipeline safety.

Provides for enhanced safety, reliability 

and environmental protection in the 

transportation of energy products by 

pipeline.

Costs associated with previously 

imposed pipeline safety laws are 

assumed to already be reflected 

in historical capital and operating 

cost data used in the model. 

Any additional costs associated 

with more recent legislation are 

assumed to be a small percentage 

of total pipeline costs and are 

partially offset by benefits gained 

through reducing pipeline leakage.

P.L. 112-90, 125 Stat. 1904

D. Energy Policy Act of 2005. Allowed natural gas storage

facilities to charge market-based

rates if it was believed they would not 

exert market power.

Storage rates are allowed to vary 

from regulation-based rates 

depending on market conditions.

Title III, Section 312 of the Energy 

Policy Act of 2005.

E. Federal Motor Fuels Excise 

Taxes for Compressed 

Natural Gas and Liquefied 

Natural Gas in Vehicles

Taxes are levied on each gallon or 

gasoline-gallon equivalent of natural gas.

Federal motor fuels excise taxes 

on natural gas fuel for vehicles 

are included in retail prices and 

are assumed to be extended 

indefinitely at current nominal 

rates.

26 USC 4041.

F. State Motor Fuels Taxes for 

Compressed Natural Gas 

and Liquefied Natural Gas 

in Vehicles

Taxes are levied on each gallon, gasolinegallon equivalent, or diesel-gallon 

equivalent of natural gas.

State motor fuels excise taxes 

on natural gas fuel for vehicles 

are included in retail prices and 

are assumed to be extended 

indefinitely at current nominal 

rates.

Determined by review of existing 

state laws.

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 201
Appendix A

Liquid Fuels Market

Legislation Brief description AEO handling Basics

A Ultra-Low-Sulfur Diesel 

(ULSD) regulations under 

the Clean Air Act 

Amendment of 1990

80 percent of highway diesel pool must 

contain 15 ppm sulfur or less starting in 

fall 2006. By mid-2010, all highway diesel 

must be 15 ppm or less. All nonroad, 

locomotive, and marine diesel fuel 

produced must contain less than 500 ppm 

starting mid-2007. By mid-2010 nonroad 

diesel must contain less than 15 ppm. 

Locomotive and marine diesel must 

contain less than 15 ppm by mid-2012.

Reflected in diesel specifications. 40 CFR Parts 69, 80, 86, 89, 94, 

1039, 1048, 1065, and 1068.

B. Mobile Source Air Toxics

(MSAT) Controls Under 

the Clean Air Act 

Amendment of 1990

Establishes a list of 21 substances emitted 

from motor vehicles and known to cause 

serious human health effects, particularly 

benzene, formaldehyde, 1.3 butadiene, 

acetaldehyde, diesel exhaust organic 

gases, and diesel particulate matter. 

Establishes anti-backsliding and antidumping rules for gasoline.

Modeled by updating gasoline 

specifications to most current 

EPA gasoline survey data (2005) 

representing anti-backsliding 

requirements.

40 CFR Parts 60 and 86.

C. Low-Sulfur Gasoline 

Regulations Under the 

Clean Air Act Amendment 

of 1990

Gasoline must contain an average 

of 30 ppm sulfur or less by 2006. Small 

refiners may be permitted to delay 

compliance until 2008.

Reflected in gasoline specifications. 40 CFR Parts 80, 85 and 86.

D. MTBE Bans in 25 states 23 states ban the use of MTBE in gasoline 

by 2007.

Ethanol assumed to be the oxygenate of choice in RFG where MTBE 

is banned

State laws 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.

E. Regional Clean Fuel 

Formulations

States with air quality problems can 

specify alternative gasoline or diesel 

formulations with EPA’s permission. 

California has long had authority to set its 

own fuel standards.

Reflected in PADD-level gasoline 

and diesel specifications.

State implementation plans

required by the Clean Air Act

Amendments of 1990, as

approved by EPA.

F. Federal Motor Fuels Excise 

Taxes

Taxes are levied on each gallon of 

transportation fuels to fund infrastructure 

and general revenue. These taxes are set 

to expire at various times in the future but 

are expected to be renewed, as they have 

been in the past.

Gasoline, diesel, and ethanol blend 

tax rates are included in end-use 

prices and are assumed to be 

extended indefinitely at current 

nominal rates.

26 USC 4041 Extended by

American Jobs Creation Act of 

2004

G. State Motor Fuel Taxes Taxes are levied on each gallon of 

transportation fuels. The assumption 

that state taxes will increase at the rate 

of inflation supports an implied need for 

additional highway revenues as driving 

increases.

Gasoline and diesel rates are 

included in end-use prices and 

are assumed to be extended 

indefinitely in real terms (to keep 

pace with inflation).

Determined by review of existing 

state laws performed semiannually by EIA’s Office of Energy 

Statistics.

H. Diesel Excise Taxes Phases out the 4.3 cents excise tax 

on railroads between 2005 and 2007.

Modeled by phasing out. American Jobs Creation Act of 

2004, Section 241.

202 U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014
Appendix A

Legislation Brief description AEO handling Basis

I. Energy Policy Act of 2005 (EPACT05)

 a. Ethanol/biodiesel tax

 credit

Petroleum product blenders 

may claim tax credits for blending 

ethanol into gasoline and for 

blending biodiesel into diesel fuel 

or heating oil. The credits may be 

claimed against the federal motor 

fuels excise tax or the income tax. 

Most recent tax credits are $1.01 

per gallon of cellulosic ethanol, 

and $1.00 per gallon of biodiesel. 

Both tax credits expire after 2013.

The tax credits are applied against 

the production costs of the products 

into which they are blended. Ethanol 

is used in gasoline and E85. Biodiesel 

is assumed to be blended into 

highway diesel, and nonroad diesel or 

heating oil.

26 USC 40, and 26 USC 

6426. Tax credits extended 

through December 31, 2013.

 b. Renewable Fuels Standard

 (RFS)

This section has largely been 

redefined by EISA07 (see below); 

however, EPA rulemaking 

completed for this law was 

assumed to contain guiding 

principles of the rules and 

administration of EISA07.

Energy Policy Act of 2005, 

Section 1501.

 c. Elimination of oxygen 

 content requirement in 

 reformulated gasoline 

Removes the 2% oxygen requirement for reformulated gasoline 

(RFG) nationwide.

Oxygenate waiver already an 

option of the model. MTBE was 

phased out in 2006 resulting from 

the petroleum industry’s decision

to discontinue use. 

Energy Policy Act of 2005, 

Section 1504.

 d. Coal gasification provisions Investment tax credit program for 

qualifying advanced clean coal 

projects including Coal-to- Liquids 

Projects.

Two CTL units are available to 

build with lower capital costs 

reflecting the provision’s funding.

Energy Policy Act of 2005, 

Section 1307.

J. Energy Independence and Security Act of 2007 (EISA07)

 a. Renewable Fuels Standard 

 (RFS)

Requires the use of 36 billion 

gallons of ethanol per year by 

2022, with corn ethanol limited 

to 15 billion gallons. Any other 

biofuel may be used to fulfill the 

balance of the mandate, but the 

balance must include 16 billion 

gallons per year of cellulosic 

biofuel by 2022 and 1 billion 

gallons per year of biodiesel by 

2012.

The RFS is included in AEO2014, 

however it is assumed that the 

schedule for cellulosic biofuel is 

adjusted downward consistent with 

waiver provisions contained in the 

law.

K. State Heating Oil Mandates A number of Northeastern states 

passed legislation that reduces 

the maximum sulfur content of 

heating oil to between 15 and 

50 ppm in different phases 

through 2016.

All state regulations included as 

legislated in AEO2014. 2013 EIA 

heating oil consumption data is 

used to calculate respective state 

Census Division shares for new 

consumption of low sulfur diesel 

as heating oil.

Vermont Energy Act of 2011, 

Maine State Legislature 

HP1160, NJ State Department 

of Environmental Protection, 

Amendment N.J.A.C. 7:27-

9.2, New York State Senate 

Bill S1145C.

L. California Low Carbon Fuel 

Standard (LCFS)

California passed legislation 

which is designed to reduce the 

Carbon Intensity (CI) of motor 

gasoline and diesel fuels sold in 

California by 10 percent between 

2012 and 2020 through the 

increased sale of alternative 

“low-carbon” fuels.

The LCFS is included in AEO2014

as legislated for gasoline and 

diesel fuel sold in California, and

for other regulated fuels. 

California Air Resources 

Board, “Final Regulation 

Order: Subarticle 7. Low 

Carbon Fuel Standard.”

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 203
Appendix A

Legislation Brief description AEO handling Basis

M. California Assembly Bill 32 (AB32) The California Assembly Bill 32 

(AB32), the Global Warming 

Solutions Act of 2006, authorized 

the California Air Resources Board 

(CARB) to set GHG reduction 

goals for 2020 for California. A 

cap-and-trade program was 

designed to enforce the caps. The 

cap-and-trade program applies 

to multiple economic sectors 

including electric power plants, 

large industrial facilities, suppliers 

of transportation fuel and suppliers 

of natural gas. Emissions resulting 

from electricity generated outside 

California but consumed in the 

State are also subject to the cap.

The AB32 cap-and-trade was 

more fully implemented in 

AEO2013, adding industrial 

facilities, refineries, fuel 

providers, and non-CO2 GHG 

emissions to the representation 

already in the electrical power 

sector of NEMS. Also, limited 

banking and borrowing, as well 

as an allowance reserve and 

offset purchases, were modeled, 

providing some compliance 

flexibility and cost containment.

California Code of 

Regulations, Subchapter 10 

Climate Change, Article 5, 

Sections 95800 to 96023, 

Title 17, “California Cap on 

Greenhouse Gas Emissions 

and Market-Based 

Compliance Mechanisms,” 

(Sacramento, CA: July 

2011).

N. EPA ETS Waiver EPA approved two waivers for 

the use of ethanol motor 

gasoline blends of up to 15 

percent in vehicles 2001 and 

newer.

These two waivers were 

included and modeled in 

AEO2013 based on forecasted 

vehicle fleets and potential 

infrastructure and liability 

setbacks.

EPA–HQ–OAR–2009–0211; 

FRL–9215–5, EPA–HQ–

OAR–2009–0211; FRL–

9258–6.

Source: U.S. Energy Information Administration, Office of Energy Analysis.

204 U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014
Abbreviations
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Abbreviations

Abbreviations:

AB: Assembly Bill

AB32: California Assembly Bill 32

ACI: Activated carbon injection

AEO: Annual Energy Outlook

AEO2012: Annual Energy Outlook 2012 

AFUE: Average Fuel Use Efficiency

ANWR: Artic National Wildlife Refuge

ARRA2009: American Recovery and Reinvestment Act of 2009

ASHRAE: American Society of Heating Refrigerating, and Air-Conditioning Engineers

Blue Chip: Blue Chip Consensus

BTL: Biomass-to-liquids

Btu: British Thermal Unit

CAFE: Corporate Average Fuel Economy

CAIR: Clean Air Interstate Rule

CARB: California Air Resources Board

CBECS: Commercial Building Energy Consumption Survey

CBO: Congressional Budget Office

CBTL: Coal- and biomass-to-liquids

CCS: Carbon capture and storage

CFR: Code of Federal Regulations

CHP: Combined heat and power

CI: Carbon intensity

CMM: Coal Market Module

CNG: Compressed natural gas

CO2: Carbon dioxide

CO

2-EOR: Carbon dioxide-enhanced oil recovery

CSAPR: Cross-State Air Pollution Rule

CTL: Coal-to-liquids

DG: Distributed generation 

DGE: Diesel gallon equivalent

DOE: U.S. Department of Energy

DOT: Department of Transportation

DSI: Direct sorbent injection

DWRRA: Deep Water Royalty Relief Act

E10: Motor gasoline blend containing up to 10 percent ethanol

E15: Motor gasoline blend containing up to 15 percent ethanol

E85: Motor fuel containing up to 85 percent ethanol

EERE: Energy Efficiency and Renewable Energy

EER: Energy Efficient Ratio

EIA: U.S. Energy Information Administration

EIEA2008: Energy Improvement and Extension Act of 2008

EISA2007: Energy Independence and Security Act of 2007

EOR: Enhanced oil recovery

EPA: U.S. Environmental Protection Agency

EPACT92: Energy Polic y Act of 1992

EPACT05: Energy Policy Act of 2005

EUR: Estimated ultimate recovery

EV: Electric vehicle

EVA: Energy Ventures Analysis

EWGs: Exempt Wholesale Generators

FFV: Flex-fuel vehicle

FEMP: Federal Energy Management Program

FERC: Federal Energy Regulatory Commission

FGD: Flue gas desulfurization

HDV: Heavy-duty Vehicles

HERS: Home Energy System Rating

HVAC: Heating, Ventilation, and Air Conditioning 

GDP: Gross domestic procduct

GHG: Greenhouse Gases

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Abbreviations

Abbreviations:

GTL: Gas-to-liquids

GVWR: Gross vehicle weight rating

HAP: Hazardous air pollutant

HB: House Bill

HCI: Hydrogen chloride

HD: Heavy-duty

HDV: Heavy-duty vehicle

HERS: Home Energy System Rating

HEV: Hybrid electric vehicle

Hg: Mercury

HVAC: Heating Ventilation, and Air Conditioning

ICE: Internal combustion engine

IDM: Industrial Demand Module

IEA: International Energy Agency

IECC2006: 2006 International Energy Conversion Code

IEM: International Energy Module

IHSGI: IHS Global Insight

INFORUM: Interindustry Forecasting Project at the University of Maryland

IOU: Investor-owned utility

IREC: Interstate Renewable Energy Council

ITC: Investment Tax Credit

kWh: Kilowatthour

LBNL: Lawrence Berkeley National Laboratory

LCFS: Low Carbon Fuel Standard

LDV: Light-duty vehicle

LED: Light-emitting diode

LFMM: Liquid Fuels Market Module

LNG: Liquefied natural gas

MARAD: Maritime Administration

MATS: Mercury and Air Toxics Standards

MAM: Macroeconomic Activity Module

MCF: Thousand Cubic Feet

MEF: Modified Energy Factor

mmt: Million metric tons

MMTCO2e: Million metric tons carbon dioxide equivalent

mpg: Miles per gallon

MSAT: Mobile Source Air Toxics

MSRP: Manufacturer’s suggested retail price

MTBE: Methyl Tertiary-Butyl Ether

MY: Model year

NAICS: North American Industry Classification System

NEMS: National Energy Modeling System

NERC: North American Electric Reliability Corportion

NGL: Natural gas liquids

NGPL: Natural gas plant liquids

NGTDM: Natural Gas Transmission and Distribution Module

NGV: Natural gas vehicle

NHTSA: National Highway Traffic Safety Administration

NOx: Nitrogen oxides

NRC: U.S. Nuclear Regulatory Commission

OASIS: Open Access Same-Time Information System

OECD: Organization for Economic Cooperation and Development

OMB: Office of Management and Budget

OPEC: Organization of the Petroleum Exporting Countries

P&G: Purvin & Gertz

PADD: Petroleum Administration for Defense District

PCs: Personal computers

PHEV: Plug-in Hybrid Electric Vehicles

208 U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014
Abbreviations

Abbreviations:

P.L.: Public Law

PM: Particulate matter

PM25: Particulate matter less than 2.5 microns diameter

PMM: Petroleum Market Module

PPM: Parts Per Million

PTC: Production tax credit

PUHCA: Public Utility Holding Company Act of 1935

PV: Solar photovoltaic

RAC: U.S. Refiner Acquisition Cost

RECS: Residential Enegy Consumption Survey

RFM: Renewable Fuels Module

RFS: Renewable fuel standard

RGGI: Regional Greenhouse Gas Initiative

RPS: Renewable portfolio standard

SB: Senate Bill

SCR: Selective catalytic reduction

SEER: Strategic Energy and Economic Research, Inc.

SEIA: Solar Energy Industries Association

SNCR: Selective noncatalytic reduction

SO2: Sulfur dioxide

STEO: Short-Term Energy Outlook

TAPS: Trans-Alaska Pipeline System

TRR: Technically recoverable resource

UEC: Unit energy consumption

USLD: Ultra-Low-Sulfur Diesel

U.S.C.: United States Code

UPS: Uninterruptible power supply

USGS: United States Geological’s Survey

VIUS: Vehicle Inventory and Use Survey

VMT: Vehicle miles traveled

WTI: West Texas Intermediate

ZEV: Zero Emission Vehicle

U.S. Energy Information Administration | Petroleum Marketing Monthly January 2014 209