‹ Analysis & Projections

Annual Energy Outlook 2014

Release Dates: April 7 - 30, 2014   |  Next Early Release Date: December 2014   |  See schedule

NEMS overview and brief description of cases

The National Energy Modeling System

Projections in the Annual Energy Outlook 2013 (AEO2013) are generated using the National Energy Modeling System (NEMS) [148], 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 also 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 other nongovernment groups, such as the Electric Power Research Institute, Duke University, and Georgia Institute of Technology. In addition, the AEO projections are used by analysts and planners in other government agencies and nongovernment 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 among 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 that are a subset of the 5 Petroleum Administration for Defense Districts (PADDs).

NEMS is organized and implemented as a modular system. 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 the 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, thus achieving an economic equilibrium of supply and demand in the consuming sectors. A solution is reached for each year from 2012 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 impacts and costs of legislation and environmental regulations that affect that sector. NEMS accounts for all energy-related carbon dioxide (CO2) emissions, as well as emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), and mercury from the electricity generation sector.

The version of NEMS used for AEO2013 generally represents current legislation and environmental regulations, including recent government actions for which implementing regulations were available as of September 30, 2012, as discussed in the "Legislation and regulations" section of the AEO. The potential impacts 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, however, are examined in alternative cases included in AEO2013 or in other analysis completed by EIA.

In general, the historical data presented with the AEO2013 projections are based on EIA's Annual Energy Review 2011, published in September 2012 [149]; however, data were taken from multiple sources. In some cases, only partial or preliminary data were available for 2011. Historical numbers are presented for comparison only and may be estimates. Source documents should be consulted for the official data values. Footnotes to the AEO2013 appendix tables indicate the definitions and sources of historical data.

Where possible, the AEO2013 projections for 2012 and 2013 incorporate short-term projections from EIA's September 2012 Short-Term Energy Outlook (STEO) [150]. EIA's views regarding energy use over the 2012 through 2014 period are reported in monthly updates of the STEO [151], which should be considered to supersede information reported for those years in AEO2013.

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.

Macroeconomic Activity Module

The Macroeconomic Activity Module (MAM) provides a set of macroeconomic drivers to the energy modules and receives energy-related indicators from the NEMS energy components as part of the macroeconomic feedback mechanism within NEMS. Key macroeconomic variables used in the energy modules include gross domestic product (GDP), disposable income, value of industrial shipments, new housing starts, sales of new light-duty vehicles (LDVs), interest rates, and employment. Key energy indicators fed back to the MAM include aggregate energy prices and quantities. 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 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. The IEM 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 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 and exogenous assumptions for petroleum products for import and export in the United States. In interacting with the rest of NEMS, the IEM changes Brent and West Texas Intermediate (WTI) prices in response to changes in expected production and consumption of crude oil and other 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, the menu of available equipment, 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—energy-intensive 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 eighth energy-intensive 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. AEO2013 includes an upgraded representation for the aluminum 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 IDM technological change to be modeled endogenously, while using more detailed process 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 industry was upgraded in the Annual Energy Outlook 2012 (AEO2012). For subsequent AEOs other energy-intensive industries will be similarly upgraded.

The bulk chemicals model has been enhanced in several respects: baseline natural gas liquids feedstock data were aligned with Manufacturing Energy Consumption Survey 2006 data; an updated propane pricing mechanism reflecting natural gas price influences was used to allow for price competition between liquefied petroleum gas feedstock and petroleum-based (naphtha) feedstock; and propylene supplied by the refining industry is now specifically accounted for in the LFMM.

Nonmanufacturing models were significantly revised as well. The construction and mining models were augmented to better reflect NEMS assumptions regarding energy efficiencies in (off-road) vehicles and buildings, as well as coal, oil, and natural gas extraction productivity. The agriculture model was similarly augmented in AEO2012. The IDM also includes a generalized representation of CHP. The methodology for CHP systems simulates the utilization of installed CHP systems based on historical utilization rates and is driven by end-use electricity demand. To evaluate the economic benefits of additional CHP capacity, the model also includes an appraisal incorporating historical capacity factors and regional acceptance rates for new CHP facilities.

There are also enhancements to the IDM to account for regulatory changes. This includes the State of California's Global Warming Solutions Act (AB 32) that allows for representation of a cap-and-trade program developed as part of California's greenhouse gas (GHG) emissions reduction goals for 2020. Another regulatory update is included for the handling of National Emissions Standards for Hazardous Air Pollutants for industrial boilers, to address the maximum degree of emission reduction using maximum achievable control technology (MACT).

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 corporate average fuel economy (CAFE) and GHG emissions standards, HDV fuel consumption and GHG emissions standards, and biofuels consumption reflect standards enacted by the National Highway Traffic Safety Administration (NHTSA) and the U.S. Environmental Protection Agency (EPA), as well as provisions in the Energy Independence and Security Act of 2007 (EISA2007).

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 and fuel, 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, known environmental regulations, the expected cost and performance of future generation capacity, expected fuel prices, expected financial parameters, and expected electricity demand 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 AEO2013. The AEO2013 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 AEO2013 Reference case leaves the Clean Air Interstate Rule (CAIR) in effect after the court vacated the Cross-State Air Pollution Rule (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 hazardous air pollutant emissions from coal- and oil-fired steam electric 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 AEO2013 Reference case through a 3-percentage-point increase in the cost of capital, when evaluating investments in new coal-fired power plants, new coal-to-liquids (CTL) plants without carbon capture and storage (CCS), 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 (PV), 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-percent ITC for business investment in solar energy (thermal nonpower uses as well as power uses) and geothermal power (available only to those projects not accepting the production tax credit [PTC] for geothermal power). In addition, the module reflects the increase in the ITC to 30 percent for solar energy systems installed before January 1, 2017. 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, 2012. They provide a credit of up to 2.2 cents per kilowatthour for electricity produced in the first 10 years of plant operation. For AEO2013, new wind plants coming on line before January 1, 2013, are eligible to receive the PTC; other eligible plants must be in service before January 1, 2014. The law was subsequently amended to extend the PTC for wind. The impact of this amendment is considered in the American Taxpayer Relief Act of 2012 case discussed in the "Issues in focus" section of AEO2013. Furthermore, eligible plants of any type will qualify if construction begins prior to the expiration date, regardless of when the plant enters commercial service. This change was made after the completion of AEO2013 and is not reflected in the analysis. As part of ARRA2009, plants eligible for the PTC may instead elect to receive a 30-percent ITC or an equivalent direct grant. AEO2013 also accounts for new renewable energy capacity resulting from state renewable portfolio standard programs, mandates, and goals, as described in Assumptions to the Annual Energy Outlook 2013 [152]

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 formations of sandstone and shale. The framework analyzes cash flow and profitability to compute investment and drilling for each of the supply sources, based on the prices for crude oil and natural gas, the domestic recoverable resource base, and the state of technology. Oil and natural gas production activities are modeled for 12 supply regions, including 6 onshore, 3 offshore, and 3 Alaskan regions.

The Onshore Lower 48 Oil and Gas Supply Submodule evaluates the economics of future exploration and development projects for crude oil and natural gas at the play level. Crude oil resources include conventional, structurally reservoired resources 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 high-permeability carbonate and sandstone, tight gas, shale gas, and coalbed methane.

Domestic crude oil production quantities are used as inputs to the LFMM in NEMS for conversion and blending into refined petroleum products. Supply curves for natural gas are used as inputs to the Natural Gas Transmission and Distribution Module (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 tracks the flows of natural gas and determines the associated capacity expansion requirements in an aggregate pipeline network, connecting the domestic and foreign supply regions with 12 lower 48 U.S. demand regions. The 12 lower 48 regions align with the 9 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. An algorithm is included to project the addition of CNG retail fueling capability. The module also accounts for foreign sources of natural gas, including pipeline imports and exports to Canada and Mexico, as well as LNG imports and exports.

Petroleum 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, natural gas liquids, 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 [153] are reviewed and updated annually.

The module represents refining activities in eight domestic U.S. regions, and a new 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 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 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 percent by volume, 15 percent by volume (E15) in states that lack explicit language capping ethanol volume or oxygen content, and up to 85 percent by volume (E85) for use in flex-fuel vehicles. Crude and refinery product imports are represented by supply curves defined by the NEMS IEM. Products also can be imported from refining region 9 (Maritime Canada/Caribbean). Refinery product exports are provided by the IEM.

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 190 are now in operation, with a total maximum sustainable nameplate capacity of more than 14 billion gallons annually), and they 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 percent—is also a new technology modeled in the LFMM.

Fuels produced by Fischer-Tropsch synthesis and through a pyrolysis process are also modeled in the LFMM, based on their economics relative to 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-and-trade program. The LCFS requires the carbon intensity (amount of greenhouse gases per 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 capacity utilization of mines, mining capacity, labor productivity, and factor input costs (mining equipment, mining labor, and fuel requirements). Projections of U.S. coal distribution are determined by minimizing the cost of coal supplied, given coal demands by region and sector; environmental restrictions; and accounting for minemouth prices, transportation costs, and coal supply contracts. Over the projection horizon, coal transportation costs in the CMM vary in response to changes in the cost of rail investments.

The CMM produces projections of U.S. steam and metallurgical coal exports and imports in the context of world coal trade, determining the pattern of world coal trade flows that minimizes production and transportation costs while meeting a specified set of regional world coal import demands, subject to constraints on export capacities and trade flows. The international coal market component of the module computes trade in 3 types of coal for 17 export regions and 20 import regions. U.S. coal production and distribution are computed for 14 supply regions and 16 demand regions.

Annual Energy Outlook 2013 cases

Table E1 provides a summary of the cases produced as part of AEO2013. For each case, the table gives the name used in AEO2013, a brief description of the major assumptions underlying the projections, and a reference to the pages in the body of the report and in this appendix where the case is discussed. The text sections following Table E1 describe the various cases in more detail. The Reference case assumptions for each sector are described in Assumptions to the Annual Energy Outlook 2013 [154]. Regional results and other details of the projections are available at website www.eia.gov/forecasts/aeo/tables_ref.cfm#supplement.

Macroeconomic Growth cases

In addition to the AEO2013 Reference case, Low Economic Growth and High Economic Growth cases were developed to reflect the uncertainty in projections of economic growth. The alternative cases are intended to show the effects of alternative growth assumptions on energy market projections. The cases are described as follows:

  • In the Reference case, population grows by 0.9 percent per year, nonfarm employment by 1.0 percent per year, and labor productivity by 1.9 percent per year from 2011 to 2040. Economic output as measured by real GDP increases by 2.5 percent per year from 2011 through 2040, and growth in real disposable income per capita averages 1.4 percent per year.
  • The Low Economic Growth case assumes lower growth rates for population (0.8 percent per year) and labor productivity (1.4 percent per year), resulting in lower nonfarm employment (0.8 percent per 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 percent per year from 2011 through 2040, and growth in real disposable income per capita averages 1.2 percent per year.
  • The High Economic Growth case assumes higher growth rates for population (1.0 percent per year) and labor productivity (2.1 percent per year), resulting in higher nonfarm employment (1.1 percent per 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 (2.9 percent per year) than in the Reference case (2.5 percent). Disposable income per capita grows by 1.6 percent per year, compared with 1.4 percent in the Reference case.

Oil Price cases

For AEO2013, the benchmark oil price is being re-characterized to represent Brent crude oil instead of WTI crude oil. This change is being made to better reflect the marginal price refineries pay for imported light, sweet crude oil, used to produce petroleum products for consumers. EIA will continue to report the WTI price, as it is a critical reference point to for evaluation of growing production in the mid-continent. EIA will also continue to report 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. AEO2013 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 from variation in demand by countries outside the Organization for Economic Cooperation and Development (OECD) for petroleum and other liquid fuels due to different levels of economic growth. The Low and High Oil Price cases also reflect different assumptions about decisions by members of the Organization of the Petroleum Exporting Countries (OPEC) regarding the preferred rate of oil production and about the future finding and development costs and accessibility of conventional structurally reservoired oil resources outside the United States.

  • In the Reference case, real oil prices (in 2011 dollars) rise from $109 per barrel in 2011 to $163 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 maintain their share of the market and will schedule investments in incremental production capacity so that OPEC's oil production will represent between 40 and 43 percent of the world's total petroleum and other liquids production over the projection period.
  • In the Low Oil Price case, crude oil prices are $75 per barrel (2011 dollars) in 2040. The low price results from lower demand for petroleum and other liquid fuels in the non-OECD nations. Lower demand is derived from lower economic growth relative to the Reference case. In this case, GDP growth in the non-OECD countries is lower on average relative to the Reference case in each projection year, beginning in 2013. The OECD projections are affected only by the price impact. On the supply side, OPEC countries increase their oil production to obtain a 49-percent share of total world petroleum and other liquids production in 2040, 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 $237 per barrel (2011 dollars) in 2040. The high prices result from higher demand for petroleum and other liquid fuels in the non-OECD nations. Higher demand is measured by higher economic growth relative to the Reference case. In this case, GDP growth in the non-OECD countries is higher on average relative to the Reference case in each projection year, beginning in 2013. The OECD projections are affected only by the price impact. On the supply side, OPEC countries reduce their market share to between 37 and 40 percent, and oil resources outside the United States are less accessible and/or more costly to produce than in the Reference case.

Buildings sector cases

In addition to the AEO2013 Reference case, three technology-focused cases using the Demand Modules of NEMS were developed to examine the effects of changes in technology.

Residential sector assumptions for the technology-focused cases are as follows:

  • The Integrated 2012 Demand Technology case assumes that all future residential equipment purchases are limited to the range of equipment available in 2012. Existing building shell efficiencies are assumed to be fixed at 2012 levels (no further improvements). For new construction, building shell technology options are constrained to those available in 2012.
  • The Integrated High Demand Technology case assumes that residential advanced equipment is available earlier, at lower costs, and/or at higher efficiencies [155]. Existing building shell efficiencies exhibit 50 percent more improvement than in the Reference case after 2012. For new construction, building shell efficiencies are assumed to meet ENERGY STAR requirements after 2016. Consumers evaluate investments in energy efficiency at a 7-percent real discount rate.
  • The Integrated Best Available Demand Technology case assumes that all future residential equipment purchases are made from a menu of technologies that includes only the most efficient models available in a particular year for each technology class, regardless of cost. Existing building shell efficiencies have twice the improvement of the Reference case after 2012. For new construction, building shell efficiencies are assumed to meet the criteria for the most efficient components after 2012. Consumers evaluate investments in energy efficiency at a 7-percent real discount rate.

Commercial sector assumptions for the technology-focused cases are as follows:

  • The Integrated 2012 Demand Technology case assumes that all future commercial equipment purchases are limited to the range of equipment available in 2012. Building shell efficiencies are assumed to be fixed at 2012 levels.
  • The Integrated High Demand Technology case assumes that commercial advanced equipment is available earlier, at lower costs, and/or with higher efficiencies than in the Reference case. Energy efficiency investments are evaluated at a 7-percent real discount rate. For new and existing buildings in 2040, building shell efficiencies are assumed to show 25 percent more improvement than in the Reference case.
  • The Integrated Best Available Demand Technology case assumes that all future commercial equipment purchases are made from a menu of technologies that includes only the most efficient models available in a particular year for each technology class, regardless of cost. Energy efficiency investments are evaluated at a 7-percent real discount rate. For new and existing buildings in 2040, building shell efficiencies are assumed to show 50 percent more improvement than in the Reference case.

The Residential and Commercial Demand Modules of NEMS were also used to complete the Low Renewable Technology Cost case, which is discussed in more detail below, in the renewable fuels cases section. In combination with assumptions for electricity generation from renewable fuels in the electric power sector and industrial sector, this sensitivity case analyzes the impacts of changes in generating technologies that use renewable fuels and in the availability of renewable energy sources. For the Residential and Commercial Demand Modules:

  • The Low Renewable Technology Cost case assumes greater improvements in residential and commercial PV and wind systems than in the Reference case. The assumptions for capital cost estimates are 20 percent below Reference case assumptions from 2013 through 2040.

The No Sunset and Extended Policies cases described below in the cross-cutting integrated cases discussion also include assumptions in the Residential and Commercial Demand Modules of NEMS. The Extended Policies case builds on the No Sunset case and adds multiple rounds of appliance standards and building codes as described below.

  • The No Sunset case assumes that selected federal policies with sunset provisions will be extended indefinitely rather than allowed to sunset as the law currently prescribes. For the residential sector, these extensions include personal tax credits for PV installations, solar water heaters, small wind turbines, and geothermal heat pumps. For the commercial sector, business ITCs for PV installations, solar water heaters, small wind turbines, geothermal heat pumps, and CHP are extended to the end of the projection. The business tax credit for solar technologies remains at the current 30-percent level without reverting to 10 percent as scheduled. On January 1, 2013, the law was modified to reinstate tax credits for energy-efficient homes and selected residential appliances. The tax credits that had expired on December 31, 2011, are now extended through December 31, 2013. This change was made after the completion of AEO2013 and is not reflected in the analysis.
  • The Extended Policies case includes updates to federal appliance standards, as prescribed by the timeline in DOE's multi-year plan, and introduces new standards for products currently not covered by DOE. Efficiency levels for the updated residential appliance standards are based on current ENERGY STAR guidelines. End-use technologies eligible for No Sunset incentives are not subject to new standards. Efficiency levels for updated commercial equipment standards are based on the technology menu from the AEO2013 Reference case and purchasing specifications for federal agencies designated by the Federal Energy Management Program. The case also adds national building codes to reach a 30-percent improvement in 2020 relative to the 2006 International Energy Conservation Code for residential households and to American Society of Heating, Refrigerating, and Air-Conditioning Engineers Standard 90.1-2004 for commercial buildings, with additional rounds of improved codes in 2023 and 2026.

Industrial sector cases

In addition to the AEO2013 Reference case, two technology-focused cases using the IDM of NEMS were developed that examine the effects of less rapid and more rapid technology change and adoption. The energy intensity changes discussed in this section exclude the refining industry, which is modeled separately from the IDM in the LFMM. Different assumptions for the IDM were also used as part of the Integrated Low Renewable Technology Cost case, No Sunset case, and Extended Policies case, but each is structured on a set of the initial industrial assumptions used for the Integrated 2012 Demand Technology case and Integrated High Demand Technology case. The IDM assumptions for the Industrial High Resource case and the Industrial Low Resource case are based only on the Integrated High Demand Technology case. For the industrial sector, assumptions for the two technology-focused cases are as follows:

  • For the Integrated 2012 Demand Technology case, the energy efficiency of new industrial plant and equipment is held constant at the 2013 level over the projection period. Changes in aggregate energy intensity may result both from changing equipment and production efficiency and from changing composition of output within an individual industry. Because all AEO2013 side cases are integrated runs, potential feedback effects from energy market interactions are captured. Hence, the level and composition of overall industrial output varies from the Reference case, and any change in energy intensity in the two technology side cases is attributable to process and efficiency changes and increased use of CHP, as well as changes in the level and composition of overall industrial output.
  • For the Integrated High Demand Technology case, the IDM assumes earlier availability, lower costs, and higher efficiency for more advanced equipment [156] and a more rapid rate of improvement in the recovery of biomass byproducts from industrial processes—i.e., 0.7 percent per year, as compared with 0.4 percent per year in the Reference case. The same assumption is incorporated in the Low Renewable Technology Cost case, which focuses on electricity generation. Although the choice of the 0.7-percent annual rate of improvement in byproduct recovery is an assumption in the High Demand Technology case, it is based on the expectation of higher recovery rates and substantially increased use of CHP in that case. Due to integration with other NEMS modules, potential feedback effects from energy market interactions are captured.

The No Sunset and Extended Policies cases described below in the cross-cutting integrated cases discussion also include assumptions in the IDM of NEMS. The Extended Policies case builds on the No Sunset case and modifies selected industrial assumptions as follows:

  • The No Sunset case and Extended Policies case include an assumption for CHP that extends the existing ITC for industrial CHP through the end of the projection period. Additionally, the Extended Policies case includes an increase in the capacity limitations on the ITC by increasing the cap on CHP equipment from 15 megawatts to 25 megawatts and eliminating the system-wide cap of 50 megawatts. These assumptions are based on the current proposals in H.R. 2750 and H.R. 2784 of the 112th Congress. The decline in natural gas prices related to increased domestics shale gas production is addressed in two cases, which assumer higher and lower shale gas resources than projected in the Reference case.

Transportation sector cases

In addition to the AEO2013 Reference case, the NEMS Transportation Demand Module was used as part of four AEO2013 side cases.

The Transportation Demand Module was used to examine the effects of advanced technology costs and efficiency improvement for technology adoption and vehicle fuel economy as part of the Integrated High Demand Technology case [157]. For the Integrated High Demand Technology case, the characteristics of conventional and alternative-fuel LDVs reflect more optimistic assumptions about incremental improvements in fuel economy and costs. In the freight truck sector, the Integrated High Demand Technology case assumes more rapid incremental improvement in fuel efficiency and lower costs for engine and emissions control technologies. More optimistic assumptions for fuel efficiency improvements are also made for the air, rail, and shipping sectors.

The Transportation Demand Module was used to examine the effects of an extension to the LDV GHG Emissions and CAFE Standards beyond 2025 as part of the Extended Policies case. The joint EPA and NHTSA CAFE Standards were increased after 2025, at an average annual rate of 1.4 percent through 2040, for a combined average LDV fuel economy of 57.7 miles per gallon in 2040.

Assumptions in the NEMS Transportation Demand Module were also modified for the Low/No Net Imports case. This case examines the effects of decreased VMT on the LDV transportation sector. It includes more optimistic assumptions about improvements in LDV fuel economy and reductions in LDV technology costs, lower VMT, an extension of the LDV CAFE standards beyond 2025 at an average annual rate of 1.4 percent through 2040, expanded market availability of LNG/CNG fuels for heavy-duty trucks, rail, and marine. It uses the assumptions from the optimistic battery case (AEO2012) for electric vehicle battery and drivetrain costs.

In the High Net Imports case, the assumptions used in the NEMS Transportation Demand Module were adjusted to incorporate a more pessimistic outlook. This case assumes lower improvement in LDV fuel economy (driven by limits on technology improvement and non-enforcement of CAFE standards), higher VMT, no change in LNG/CNG market availability, and no change in biofuel market penetration from the Reference case.

Electricity sector cases

In addition to the Reference case, several integrated cases with alternative electric power assumptions were developed to support discussions in the "Issues in focus" section of AEO2013. Three alternative cases were run for nuclear power plants, to address uncertainties about the operating lives of existing reactors and the potential for new nuclear capacity and capacity uprates at existing plants. These cases are discussed in the "Issues in focus" article, "Nuclear power through 2040."

Nuclear cases

  • The Low Nuclear case assumes that reactors will not receive a second license renewal, so that all existing nuclear plants are retired within 60 years of operation. The reported retirement at Oyster Creek occurs as currently planned, at the end of 2019. Also, Kewaunee is retired at the end of 2014, based on an announcement by Dominion Resources in late 2012 stating their intention to retire the unit in the next few years. Additionally, two units that are currently out of service are assumed to be permanently shut down in the Low Nuclear case. San Onofre 2 and Crystal River 3 currently are not operating, but they are assumed to be returned to service in 2015 in the Reference case. In the Low Nuclear case they are retired in 2013. In the Reference case, existing plants are assumed to run as long as they continue to be economic, implicitly assuming that a second 20-year license renewal would occur for most plants that reach 60 years of operation before 2040. The Low Nuclear case was run to analyze the impact of additional nuclear retirements. In this case, no plants receive license extensions beyond 60 years, and 45 gigawatts of nuclear capacity is assumed to be retired by 2040. The Low Nuclear case assumes that no new nuclear capacity will be added throughout the projection, excluding capacity already planned or under construction. It also assumes that only those capacity uprates already reported to EIA (1.3 gigawatts) will be completed. The Reference case assumes additional uprates based on NRC surveys and industry reports.
  • The High Nuclear case assumes that all existing nuclear units will receive a second license renewal and operate beyond 60 years (excluding one announced retirement). In the Reference case, beyond the announced retirement of Oyster Creek, an additional 6.5 gigawatts of nuclear capacity is assumed to be retired through 2040, reflecting uncertainty about the impacts and/or costs of future aging. The High Nuclear case was run to provide a more optimistic outlook, with all licenses renewed and all plants continuing to operate economically beyond 60 years. The High Nuclear case also assumes that additional planned nuclear capacity is completed, based on combined license applications issued by the NRC and where an NRC or Atomic Safety and Licensing Board hearing has been scheduled. The Reference case assumes that 5.5 gigawatts of planned capacity are added, compared with 13.3 gigawatts of planned capacity additions in the High Nuclear case.
  • The Small Modular Reactor case assumes that new advanced nuclear plants built after 2025 will be based on a smaller modular design rather than the larger AP1000 design used in the Reference case. The overnight costs are assumed to be the same as in the Reference case, but the construction lead time is reduced from 6 years to 3 years for the smaller design. The fixed operating and maintenance costs are assumed to be higher for the smaller design. To account for the time necessary for design certification, the first available online date for the small reactors is assumed to be 2025.

Renewable generation cases

In addition to the AEO2013 Reference case, EIA developed a case with alternative assumptions about renewable generation technologies and policies to examine the effects of more aggressive improvement in the costs of renewable technologies.

  • In the Low Renewable Technology Cost case, the levelized costs of new nonhydropower renewable generating technologies are assumed to be 20 percent below Reference case assumptions from 2013 through 2040. In general, lower costs are represented by reducing the capital costs of new plant construction. Biomass fuel supplies also are assumed to be 20 percent less expensive than in the Reference case for the same resource quantities. Assumptions for other generating technologies are unchanged from those in the Reference case. In the Low Renewable Technology Cost case, the rate of improvement in recovery of biomass byproducts from industrial processes also is increased.
  • In the No Sunset case and the Extended Policies case, expiring federal tax credits targeting renewable electricity are assumed to be permanently extended. This applies to the PTC, which is a tax credit of 2.2 cents per kilowatthour available for the first 10 years of production by new generators using wind, geothermal, and certain biomass fuels, or a tax credit of 1.1 cents per kilowatthour available for the first 10 years of production by new generators using geothermal energy, certain hydroelectric technologies, and biomass fuels not eligible for the full credit of 2.2 cents per kilowatthour. This tax credit had been scheduled to expire on December 31, 2012 for wind and 1 year later for other eligible technologies. The same schedule applies to the 30-percent ITC, which is available to new solar installations through December 31, 2016, and may also be claimed in lieu of the PTC for eligible technologies, expiring concurrently with the PTC (described above). On January 1, 2013, the law was modified to extend the expiration date for wind by one full year and to allow new plants using any eligible technology to qualify if they were under construction by the deadline—not actually in commercial service by the deadline, as was previously required. However, this change occurred too late to allow for inclusion in this report.

Oil and gas supply cases

The sensitivity of the AEO2013 projections to changes in assumptions regarding technically recoverable domestic crude oil and natural gas resources is examined in two cases. These cases do not represent a confidence interval for 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. Assumptions associated with these cases are described below.

  • In the Low Oil and Gas Resource case, the EUR per tight oil, tight gas, and shale gas well is assumed to be 50 percent lower than in the Reference case, increasing the per-unit cost of developing the resource. The total unproved technically recoverable resource (TRR) of crude oil is decreased to 168 billion barrels, and the natural gas resource is decreased to 1,500 trillion cubic feet, as compared with unproved resource estimates of 197 billion barrels of crude oil and 2,022 trillion cubic feet of natural gas in the Reference case as of January 1, 2011.
  • In the High Oil and Gas Resource case, the resource assumptions are adjusted to give continued increase in domestic crude oil production after 2020, reaching over 10 million barrels per day. This case includes: (1) 100 percent higher EUR per tight oil, tight gas, and shale gas well than in the Reference case and a maximum well spacing of 40 acres, to reflect the possibility that additional layers of low-permeability zones are identified and developed, compared with well spacing that ranges from 20 to 406 acres with an average of 100 acres in the Reference case; (2) kerogen development reaching 135,000 barrels per day in 2025; (3) tight oil development in Alaska increasing the total Alaska TRR by 1.9 billion barrels; and (4) 50 percent higher technically recoverable undiscovered resources in Alaska and the offshore lower 48 states than in the Reference case. Additionally, a few offshore Alaska fields are assumed to be discovered and thus developed earlier than in the Reference case. Given the higher natural gas resource in this case, the maximum penetration rate for GTL was increased to 10 percent per year, compared to a rate of 5 percent per year in the Reference case.

Liquids market cases

Two sensitivity cases have been designed to analyze petroleum imports in the United States. Assumptions associated with these cases are described below.

  • In the Low/No Net Imports case, changes were made to various NEMS modeling assumptions that, in comparison with the AEO2013 reference case, resulted in higher domestic production of crude oil and natural gas, lower domestic liquid fuels demand, and higher domestic production of nonpetroleum liquids. The methodology used to achieve higher domestic crude production is the same as that used in the High Oil and Gas Resource case (described in the "Oil and gas supply cases" section above). Domestic liquid fuels demand was reduced by changes made in the Transportation Demand Module. As described in the "Transportation sector cases" section, this included the use of more optimistic assumptions about improvements in LDV fuel economy and reductions in LDV technology costs; lower VMT due to changes in consumer behavior; an extension of the LDV CAFE standards beyond 2025 at an average annual rate of 1.4 percent through 2040; expanded market availability of LNG/CNG fuels for heavy-duty trucks, rail, and marine; and use of assumptions from the optimistic battery case (AEO2012) for electric vehicle battery and drivetrain costs. Within the LFMM, the assumption for market penetration of biomass pyrolysis oils, CTL, and BTL production was more optimistic. Also, initial assumptions associated with E85 availability and maximum penetration of E15 were set to be more optimistic, such that E85 availability was nearly three times the Reference case level in 2040, and E15 penetration was about 15 percent higher by 2040.
  • In the High Net Imports case, changes were made in two NEMS modules to reduce domestic crude oil production and increase domestic demand for liquid fuels, as compared with the Reference case. The methodology used to achieve lower domestic crude production is the same as that used in the Low Oil and Gas Resource case described above. An increase in domestic liquids fuels demand was achieved by assuming lower improvement in vehicle efficiency (driven by limits on technology improvement and non-enforcement of CAFE standards and resulting in a lower number of alternatively fueled vehicles, including hybrid, plug-in hybrid, and battery electric vehicles); higher VMT; no change in LNG/CNG market availability; no change in GTL penetration; and no change in biofuel market penetration compared with the Reference case.

Coal market cases

Two alternative coal cost cases examine the impacts on U.S. coal supply, demand, distribution, and prices that result from alternative assumptions about mining productivity, labor costs, mine equipment costs, and coal transportation rates. The alternative productivity and cost assumptions are applied in every year from 2013 through 2040. For the coal cost cases, adjustments to the Reference case assumptions for coal mining productivity are based on variation in the average annual productivity growth of 2.5 percent observed since 2000 for mines in Wyoming's Powder River Basin and 2.4 percent for other coal-producing regions. Transportation rates are lowered (in the Low Coal Cost case) or raised (in the High Coal Cost case) from Reference case levels to achieve a 25-percent change in rates relative to the Reference case in 2040. 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.

  • In the Low Coal Cost case, the average annual growth rates for coal mining productivity are higher than those in the Reference case and are applied at the supply curve level. As an example, the average annual productivity growth rate for Wyoming's Southern Powder River Basin supply curve is increased from -1.6 percent in the Reference case for the years 2013 through 2040 to 0.9 percent in the Low Coal Cost case. Coal mining wages, mine equipment costs, and other mine supply costs all are assumed to be about 25 percent lower in 2040 in real terms in the Low Coal Cost case than in the Reference case. Coal transportation rates, excluding the impact of fuel surcharges, are assumed to be 25 percent lower in 2040.
  • In the High Coal Cost case, the average annual productivity growth rates for coal mining are lower than those in the Reference case and are applied as described in the Low Coal Cost case. Coal mining wages, mine equipment costs, and other mine supply costs in 2040 are assumed to be about 32 percent higher than in the Reference case, and coal transportation rates in 2040 are assumed to be 25 percent higher.

Additional data on productivity, wage, mine equipment cost, and coal transportation rate assumptions for the Reference and alternative coal cost cases are shown in Appendix D.

Cross-cutting integrated cases

A series of cross-cutting integrated cases are used in AEO2013 to analyze specific cases with broader sectoral impacts. For example, three integrated technology progress cases analyze the impacts of faster and slower technology improvement in the demand sector (partially described in the sector-specific sections above). In addition, seven cases were run with alternative assumptions about expectations of future regulation of GHG emissions.

Integrated technology cases

In the demand sectors (residential, commercial, industrial, and transportation), technology improvement typically means greater efficiency and/or reduced technology cost. Three alternative demand technology cases—Integrated 2012 Demand Technology, Integrated Best Available Demand Technology, and Integrated High Demand Technology cases—are used in AEO2013 to examine the potential impacts of variation in the rate of technology improvement in the end-use demand sectors, independent of any offsetting impacts of variations in technology improvement in the supply/conversion sectors. Assumptions for each end-use sector are described in the sector-specific sections above.

No Sunset case

In addition to the AEO2013 Reference case a No Sunset case was run, assuming that selected federal policies with sunset provisions—such as the PTC, ITC, and tax credits for renewable and CHP equipment in the buildings and industrial sectors—will be extended indefinitely rather than allowed to sunset as the law currently prescribes. Specific assumptions for each end-use sector and for renewables are described in the sector-specific sections above.

Extended Policies case

In the Extended Policies case, assumptions for tax credit extensions are the same as in the No Sunset case described above. Further, updates to federal appliance efficiency standards are assumed to occur at regular intervals, and new standards for products not currently covered by DOE are assumed to be introduced. Finally, fuel economy standards for LDVs, including both passenger cars and light-duty trucks, are assumed to continue increasing after 2025. Specific assumptions for each end-use sector and for renewables are described in the sector-specific sections above.

Greenhouse gas cases

Given concerns about climate change and possible future policy actions to limit GHG emissions, regulators and the investment community are beginning to push energy companies to invest in technologies that are less GHG-intensive. To reflect the market's current reaction to potential future GHG regulation, a 3-percentage-point increase in the cost of capital is assumed for investments in new coal-fired power plants without CCS and for all capital investment projects at existing coal-fired power plants in the Reference case and all other AEO2013 cases except the No GHG Concern case, GHG10 case, GHG15 case, GHG25 case, GHG10 and Low Gas Prices case, GHG15 and Low Gas Prices case, and GHG25 and Low Gas Prices case. Those assumptions affect cost evaluations for the construction of new capacity but not the actual operating costs when a new plant begins operation.

The seven alternative GHG cases are used to provide a range of potential outcomes, from no concern about future GHG legislation to the imposition of a specific economywide carbon emissions price, as well as an examination of the impact of a combination of specific economywide carbon emissions prices and low natural gas prices. AEO2013 includes six economywide CO2 price cases, combining three levels of carbon prices with two alternative gas price projections. In the GHG10 case and GHG10 and Low Gas Prices case, the carbon emissions price is set at $10 per metric ton CO2 in 2014. In the GHG15 case and GHG15 and Low Gas Prices case, the carbon emissions price is set at $15 per metric ton CO2 in 2014. In the GHG25 case and GHG25 and Low Gas Prices case, the price is set at $25 per metric ton CO2 in 2014. In all cases the price begins to rise in 2014 at 5 percent per year. The GHG10, GHG15, and GHG25 cases use the Reference case assumptions regarding oil and gas resource availability. The GHG10 and Low Gas Prices case, GHG15 and Low Gas Prices case, and GHG25 and Low Gas Prices case use the assumptions from the High Oil and Gas Resource case, as described above in the "Oil and gas supply" section. The GHG cases are intended to measure the sensitivity of the AEO2013 projections to a range of implicit or explicit valuations of CO2. At the time AEO2013 was completed, no legislation including a GHG price was pending; however, the EPA is developing technology-based CO2 standards for new coal-fired power plants. In the GHG cases for AEO2013, no assumptions are made with regard to offsets, policies to promote CCS, or specific policies to mitigate impacts in selected sectors.

The No GHG Concern case was run without any adjustment for concern about potential GHG regulations (without the 3-percentage-point increase in the cost of capital). In the No GHG Concern case, the same cost of capital is used to evaluate all new capacity builds, regardless of type.

Endnotes for Appendix E

148. U.S. Energy Information Administration, The National Energy Modeling System: An Overview 2009, DOE/EIA-0581(2009) (Washington, DC: October 2009), website www.eia.gov/oiaf/aeo/overview.

149. U.S. Energy Information Administration, Annual Energy Review 2011, DOE/EIA-0384(2011) (Washington, DC: September 2012), website www.eia.gov/aer.

150. U.S. Energy Information Administration, Short-Term Energy Outlook September 2012 (Washington, DC: September 2012), website www.eia.gov/forecasts/steo/archives/Sep12.pdf. Portions of the preliminary information were also used to initialize the NEMS Liquids Fuels Market Module projection.

151. U.S. Energy Information Administration, "Short-Term Energy Outlook" (Washington, DC: January 2013), website www.eia.gov/forecasts/steo/outlook.cfm.

152. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2013, DOE/EIA-0554(2013) (Washington, DC: April 2013), website www.eia.gov/forecasts/aeo/assumptions.

153. Alternative other liquids technologies include all biofuels technologies plus CTL and GTL.

154. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2013, DOE/EIA-0554(2013) (Washington, DC: April 2013), website www.eia.gov/forecasts/aeo/assumptions.

155. High technology assumptions for the buildings sector are based on U.S. Energy Information Administration, EIA—Technology Forecast Updates—Residential and Commercial Building Technologies—Advanced Case (Navigant Consulting, Inc. with SAIC, September 2011), and EIA—Technology Forecast Updates—Residential and Commercial Building Technologies—Advanced Case (Navigant Consulting, Inc. with SAIC, November 2012).

156. These assumptions are based in part on U.S. Energy Information Administration, Industrial Technology and Data Analysis Supporting the NEMS Industrial Model (FOCIS Associates, October 2005).

157. U.S. Energy Information Administration, Documentation of Technologies Included in the NEMS Fuel Economy Model for Passenger Cars and Light Trucks (Energy and Environmental Analysis, September 2003)