‹ Analysis & Projections

Annual Energy Outlook 2011

Release Date: April 26, 2011   |  Next Early Release Date: January 23, 2012  |   Report Number: DOE/EIA-0383(2011)

NEMS overview and brief description of cases

The National Energy Modeling System

The projections in the Annual Energy Outlook 2011 (AEO2011) are generated from the National Energy Modeling System (NEMS) [1], developed and maintained by the Office of Energy Analysis (OEA), formerly known as the Office Integrated Analysis and Forecasting (OIAF), of the U.S. Energy Information Administration (EIA) [2]. 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, Georgia Institute of Technology, and OnLocation, Inc. 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 to energy analysis. 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 is the period through 2035, approximately 25 years into the future. In order to represent regional differences in energy markets, the component modules of NEMS function at the regional level: the nine Census divisions for the end-use demand modules; production regions specific to oil, natural gas, and coal supply and distribution; 22 subregions of the North American Electric Reliability Council regions and subregions for electricity [3]; and the 5 Petroleum Administration for Defense Districts (PADDs) for refineries.

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. NEMS also includes delivered prices of energy 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 other data on such areas as economic activity, domestic production, and international petroleum supply.

The Integrating Module 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 structure. 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. The modular design also permits the use of the methodology and level of detail most appropriate for each energy sector. 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 annually through the projection horizon. 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 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 version of NEMS used for AEO2011 represents current legislation and environmental regulations as of January 31, 2011, such as: the October 13, 2010, U.S. Environmental Protection Agency (EPA) waiver that allows the use of E15 in light-duty vehicles (LDVs) built in 2007 or later; EPA guidelines regarding compliance of surface coal mining operations in Appalachia, issued on April 1, 2010; the American Recovery and Reinvestment Act (ARRA), which was enacted in mid-February 2009; the Energy Improvement and Extension Act of 2008 (EIEA2008), signed into law on October 3, 2008; the Food, Conservation, and Energy Act of 2008; and the Energy Independence and Security Act of 2007 (EISA2007), signed into law on December 19, 2007. The AEO2011 models do not represent the Clean Air Mercury Rule, which was vacated and remanded by the D.C. Circuit Court of the U.S. Court of Appeals on February 8, 2008, but it does represent State requirements for reduction of mercury emissions.

The AEO2011 Reference case reflects the temporary reinstatement of the NOX and SO2 cap-and-trade programs included in the Clean Air Interstate Rule (CAIR) as a result of the ruling issued by the United States Court of Appeals for the District of Columbia on December 23, 2008. 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. However, many pending provisions are examined in alternatives cases included in AEO2011 or in other analyses completed by EIA.

In general, the historical data used for the AEO2011 projections are based on EIA's Annual Energy Review 2009, published in August 2010 [4]; however, data were taken from multiple sources. In some cases, only partial or preliminary data were available for 2009. CO2 emissions were calculated by using CO2 coefficients from the EIA report, Emissions of Greenhouse Gases in the United States 2009, published in April 2011 [5]. Historical numbers are presented for comparison only and may be estimates. Source documents should be consulted for the official data values. Footnotes to the AEO2011 appendix tables indicate the definitions and sources of historical data.

The AEO2011 projections for 2010 and 2011 incorporate short-term projections from EIA's October 2010 Short-Term Energy Outlook (STEO). For short-term energy projections, readers are referred to monthly updates of the STEO [6].

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 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 Module

The International Energy Module (IEM) uses assumptions of economic growth and expectations of future U.S. and world petroleum liquids production and consumption, by year, to project the interaction of U.S. and international liquids markets. The IEM computes world oil prices, provides a world crude-like liquids supply curve, generates a worldwide oil supply/demand balance for each year of the projection period, and computes initial estimates of crude oil and light and heavy petroleum product imports to the United States by PADD regions. The supply-curve calculations are based on historical market data and a world oil supply/demand balance, which is developed from reduced-form models of international liquids supply and demand, current investment trends in exploration and development, and long-term resource economics for 221 countries and territories. The oil production estimates include both conventional and unconventional supply recovery technologies.

In interacting with the rest of NEMS, the IEM changes the world oil price—which is defined as the price of foreign light, low-sulfur crude oil delivered to Cushing, Oklahoma (Petroleum Allocation Defense District 2)—in response to changes in expected production and consumption of crude oil and product liquids in the United States.

Residential and Commercial Demand Modules

The Residential Demand Module projects energy consumption in the residential sector by housing type and end use, based on delivered energy prices, the menu of equipment available, the availability and cost of renewable sources of energy, and housing starts. The Commercial Demand Module projects energy consumption in the commercial sector by building type and non-building uses of energy and by category of end use, based on delivered prices of energy, availability of renewable sources of energy, and macroeconomic variables representing interest rates and floorspace construction.

Both modules estimate the equipment stock for the major end-use services, incorporating assessments of advanced technologies, including representations of renewable energy technologies, and the effects of both building shell and appliance standards, including the recent consensus agreement reached between manufacturers and environmental interest groups. The Commercial Demand Module incorporates combined heat and power (CHP) technology. The modules also include projections of distributed generation. Both modules incorporate changes to "normal" heating and cooling degree-days by Census division, based on a 10-year average and on State-level population projections. The Residential Demand Module projects an increase in the average square footage of both new construction and existing structures, based on trends in new construction and remodeling.

Industrial Demand Module

The Industrial Demand Module (IDM) projects the consumption of energy for heat and power, feedstocks, and raw materials in each of 21 industries, subject to the delivered prices of energy and the values of macroeconomic variables representing employment and the value of shipments for each industry. As noted in the description of the MAM, the value of shipments is based on NAICS. The industries are classified into three groups—energy-intensive manufacturing, non-energy-intensive manufacturing, and nonmanufacturing. Of the eight energy-intensive industries, seven are modeled in the IDM, with energy-consuming components for boiler/steam/cogeneration, buildings, and process/assembly use of energy. The use of energy for petroleum refining is modeled in the Petroleum Market Module (PMM), as described below, and the projected consumption is included in the industrial totals.

A generalized representation of cogeneration and a recycling component also are included. A new economic calculation for CHP systems was implemented for AEO2011. The evaluation of CHP systems now uses a discount rate, which depends on the 10-year Treasury bill rate plus a risk premium, replacing the previous calculation that used simple payback. Also, the base year of the IDM was updated to 2006 in keeping with an update to EIA's 2006 Manufacturing Energy Consumption Survey [7].

Transportation Demand Module

The Transportation Demand Module projects consumption of fuels in the transportation sector, including petroleum products, electricity, methanol, ethanol, compressed natural gas, and hydrogen, by transportation mode, vehicle vintage, and size class, subject to delivered prices of energy fuels and macroeconomic variables representing disposable personal income, GDP, population, interest rates, and industrial shipments. Fleet vehicles are represented separately to allow analysis of other legislation and legislative proposals specific to those market segments. The Transportation Demand Module also includes a component to assess the penetration of alternative-fuel vehicles. The Energy Policy Act of 2005 (EPACT2005) and EIEA2008 are reflected in the assessment of impacts of tax credits on the purchase of hybrid gas-electric, alternative-fuel, and fuel-cell vehicles. Representations of corporate average fuel economy (CAFE) standards and of biofuel consumption in the module reflect standards enacted by the National Highway Traffic Safety Administration (NHTSA) and EPA, and provisions in EISA2007.

The air transportation component of the Transportation Demand Module explicitly represents air travel in domestic and foreign markets and includes the industry practice of parking aircraft in both domestic and international markets to reduce operating costs, as well as the movement of aging aircraft from passenger to cargo markets. For passenger travel and air freight shipments, the module represents regional fuel use in regional, narrow-body, and wide-body aircraft. An infrastructure constraint, which is also modeled, can potentially limit overall growth in passenger and freight air travel to levels commensurate with industry-projected infrastructure expansion and capacity growth.

Electricity Market Module

There are three primary submodules of the Electricity Market Module—capacity planning, fuel dispatching, and finance and pricing. The capacity expansion submodule uses the stock of existing generation capacity; the menu, cost, and performance of future generation capacity; expected fuel prices; expected financial parameters; expected electricity demand; and expected environmental regulations to project the optimal mix of new generation capacity that should be added in future years. The fuel dispatching submodule uses the existing stock of generation equipment 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 (CAAA90) are explicitly represented in the capacity expansion and dispatch decisions; those that have not been promulgated (e.g., fine particulate proposals) are not incorporated. All financial incentives for power generation expansion and dispatch specifically identified in EPACT2005 have been implemented. Several States, primarily in the Northeast, have recently enacted air emission regulations for CO2 that affect the electricity generation sector, and those regulations are represented in AEO2011. The AEO2011 Reference case reflects the temporary reinstatement of the NOX and SO2 cap-and-trade programs included in the CAIR due to the ruling issued by the United States Court of Appeals for the District of Columbia on December 23, 2008. State regulations on mercury also are reflected in AEO2011.

Although currently there is no Federal legislation in place that restricts greenhouse gas (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 AEO2011 Reference case through a 3-percentage-point increase in the cost of capital when evaluating investments in new coal-fired power plants and new coal-to-liquids (CTL) plants without carbon capture and storage (CCS).

Renewable Fuels Module

The Renewable Fuels Module (RFM) includes submodules representing renewable resource supply and technology input information for central-station, grid-connected electricity generation technologies, including conventional hydroelectricity, biomass (dedicated biomass plants and co-firing in existing coal plants), geothermal, landfill gas, solar thermal electricity, solar photovoltaics (PV), and wind energy. The RFM contains renewable resource supply estimates representing the regional opportunities for renewable energy development. Investment tax credits (ITCs) for renewable fuels are incorporated, as currently enacted, including a permanent 10-percent ITC for business investment in solar energy (thermal nonpower uses as well as power uses) and geothermal power (available only to those projects not accepting the production tax credit [PTC] for geothermal power). In addition, the module reflects the increase in the ITC to 30 percent for solar energy systems installed before January 1, 2017, and the extension of the credit to individual homeowners under EIEA2008.

PTCs for wind, geothermal, landfill gas, and some types of hydroelectric and biomass-fueled plants also are represented. They provide a credit of up to 2.1 cents per kilowatthour for electricity produced in the first 10 years of plant operation. For AEO2011, new wind plants coming on line before January 1, 2013, are eligible to receive the PTC; other eligible plants must be in service before January 1, 2014. As part of the ARRA, plants eligible for the PTC may instead elect to receive a 30-percent ITC or an equivalent direct grant. AEO2011 also accounts for new renewable energy capacity resulting from State renewable portfolio standard (RPS) programs, mandates, and goals, as described in Assumptions to the Annual Energy Outlook 2011 [8].

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 are divided into known plays and undiscovered plays, including 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 are divided into known producing plays, known developing plays, and undiscovered plays in high-permeability carbonate and sandstone, tight gas, shale gas, and coalbed methane.

Domestic crude oil production quantities are used as inputs to the PMM in NEMS for conversion and blending into refined petroleum products. Supply curves for natural gas are used as inputs to the Natural Gas Transmission and Distribution Module (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 U.S. lower 48 demand regions. The 12 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 compressed natural gas 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 liquefied natural gas (LNG) imports and exports.

Petroleum Market Module

The PMM projects prices of petroleum products, crude oil and product import activity, and 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, and biomass-to-liquids (BTL), CTL, and gas-to-liquids (GTL) production. Costs, performance, and first dates of commercial availability for the advanced alternative liquids technologies [9] are reviewed and updated annually.

The module represents refining activities in the five PADDs, as well as a less detailed representation of refining activities in the rest of the world. It 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 PMM, because they are commonly blended into petroleum products. The module allows ethanol blending into gasoline at 10 percent or less by volume (E10), 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.

The PMM includes representation of the Renewable Fuels Standard (RFS) included in EISA2007, which mandates the use of 36 billion gallons of renewable fuel by 2022. Both domestic and imported ethanol count toward the RFS. Domestic ethanol production is modeled for three feedstock categories: corn, cellulosic plant materials, and advanced feedstock materials. Corn-based ethanol plants are numerous (more than 180 are now in operation, with a total operating production capacity of more than 13 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.

Fuels produced by gasification and Fischer-Tropsch synthesis and through a pyrolysis process are also modeled in the PMM, based on their economics relative to competing feedstocks and products. The five processes modeled are CTL, GTL, BTL, coal and biomass to liquids, and pyrolysis.

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 2011 cases

Table E1 provides a summary of the cases produced as part of AEO2011. For each case, the table gives the name used in AEO2011, a brief description of the major assumptions underlying the projections, the mode in which the case was run in NEMS (either fully integrated, partially integrated, or standalone), 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. The Reference case assumptions for each sector are described in Assumptions to the Annual Energy Outlook 2011 [10]. Regional results and other details of the projections are available at website www.eia.gov/oiaf/aeo/supplement.

Macroeconomic Growth cases

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 2.0 percent per year from 2009 to 2035. Economic output as measured by real GDP increases by 2.7 percent per year from 2009 through 2035, and growth in real disposable income per capita averages 1.6 percent per year.
  • The Low Economic Growth case assumes lower growth rates for population (0.6 percent per year) and labor productivity (1.6 percent per year), resulting in lower nonfarm employment (0.7 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 2.1 percent per year from 2009 through 2035, and growth in real disposable income per capita averages 1.5 percent per year.
  • The High Economic Growth case assumes higher growth rates for population (1.2 percent per year) and labor productivity (2.4 percent per year), resulting in higher nonfarm employment (1.4 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 (3.2 percent per year) than in the Reference case (2.7 percent). Disposable income per capita grows by 1.63 percent per year, compared with 1.57 percent in the Reference case.
Oil Price cases

The world oil price in AEO2011 is defined as the average price of light, low-sulfur crude oil delivered in Cushing, Oklahoma, and is similar to the price for light, sweet crude oil traded on the New York Mercantile Exchange. AEO2011 also includes a projection of the U.S. annual average refiners' acquisition cost of imported crude oil, which is more representative of the average cost of all crude oils used by domestic refiners.

The historical record shows substantial variability in world oil prices, and there is arguably even more uncertainty about future prices in the long term. AEO2011 considers five oil price cases (Reference, Low Oil Price, Traditional Low Oil Price, High Oil Price, and Traditional High Oil Price) to allow an assessment of alternative views on the course of future oil prices. The Low Oil Price case and Traditional Low Oil Price case use the same price path, as do the High Oil Price case and Traditional High Oil Price.

The Low and High Oil Price cases reflect a wide range of potential price paths, resulting from variation in demand for countries outside the organization for Economic Cooperation and Development (OECD) for liquid fuels due to different levels of economic growth. The Traditional Low and Traditional High Oil Price cases define the same wide range of potential price paths, but they 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 oil resources outside the United States. Because the Low, Traditional Low, High, and Traditional High Oil Price cases are not fully integrated with a world economic model, the impact of world oil prices on international economies is not accounted for directly.

  • In the Reference case, real world oil prices rise from a low of $78 per barrel (2009 dollars) in 2010 to $95 per barrel in 2015, then increase more slowly to $125 per barrel in 2035. The Reference case represents EIA's current judgment regarding exploration and development costs and accessibility of oil resources outside the United States. It also assumes that OPEC producers will choose to maintain their share of the market and will schedule investments in incremental production capacity so that OPEC's conventional oil production will represent about 42 percent of the world's total liquids production.
  • In the Low Oil Price case, world crude oil prices are only $50 per barrel (2009 dollars) in 2035, compared with $125 per barrel in the Reference case. In the Low Oil Price case, the low price results from lower demand for 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 is reduced by 1.5 percentage points in each projection year beginning in 2015 relative to Reference case. The OECD projections are only affected by the price impact.
  • In the Traditional Low Oil Price case, the OPEC countries increase their conventional oil production to obtain a 52-percent share of total world liquids production, and oil resources outside the U.S. 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. With these assumptions, conventional oil production outside the United States is higher in the Traditional Low Oil Price case than in the Reference case. Prices are the same as in the Low Oil Price case.
  • In the High Oil Price case, world oil prices reach about $200 per barrel (2009 dollars) in 2035. In the High Oil Price case, the high prices result from higher demand for 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 region is raised by 1.0 percentage points relative to Reference case in each projection year, starting in 2015. The OECD projections are only affected by the price impact.
  • In the Traditional High Oil Price case, OPEC countries are assumed to reduce their production from the current rate, sacrificing market share, and oil resources outside the United States are assumed to be less accessible and/or more costly to produce than in the Reference case. Prices are the same as in the High Oil Price case.
Buildings Sector cases

In addition to the AEO2011 Reference case, three standalone technology-focused cases using the Residential and Commercial Demand Modules of NEMS were developed to examine the effects of changes in equipment and building shell efficiencies. Residential and commercial sector assumptions for the 2010 Technology case and the High Technology case are also used in the appropriate Integrated Technology cases.

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

  • The 2010 Technology case assumes that all future equipment purchases are based only on the range of equipment available in 2010. Existing building shell efficiencies are assumed to be fixed at 2010 levels (no further improvements). For new construction, building shell technology options are constrained to those available in 2010.
  • The High Technology case assumes earlier availability, lower costs, and higher efficiencies for more advanced equipment [11]. For new construction, building shell efficiencies are assumed to meet ENERGY STAR requirements after 2015. Consumers evaluate investments in energy efficiency at a 7-percent real discount rate.
  • The Best Available Technology case assumes that all future equipment purchases are made from a menu of technologies that includes only the most efficient models available in a particular year for each fuel, regardless of cost. For new construction, building shell efficiencies are assumed to meet the criteria for the most efficient components after 2010.
Commercial sector assumptions for the three technology-focused cases are as follows:

  • The 2010 Technology case assumes that all future equipment purchases are based only on the range of equipment available in 2010. Building shell efficiencies are assumed to be fixed at 2010 levels.
  • The High Technology case assumes earlier availability, lower costs, and/or higher efficiencies for more advanced equipment than in the Reference case [12]. Energy efficiency investments are evaluated at a 7-percent real discount rate. Building shell efficiencies for new and existing buildings in 2035 are assumed to be 17.4 percent and 7.5 percent higher, respectively, than their 2003 levels—a 25-percent improvement relative to the Reference case.
  • The Best Available Technology case assumes that all future equipment purchases are made from a menu of technologies that includes only the most efficient models available in a particular year for each fuel, regardless of cost. Building shell efficiencies for new and existing buildings in 2035 are assumed to be 20.8 percent and 9.0 percent higher, respectively, than their 2003 values—a 50-percent improvement relative to the Reference case.

The Residential and Commercial Demand Modules of NEMS were also used to complete the High and Low Renewable Technology Cost cases, which are 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, these sensitivity cases analyze 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 result in capital cost estimates that are 20 percent below Reference case assumptions in 2011 and decline to at least 40 percent lower than Reference case costs in 2035.
  • The High Renewable Technology Cost case assumes that costs and performance levels for residential and commercial PV and wind systems remain constant at 2010 levels through 2035.
  • 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. In the two cases described below, those standards and codes are examined on their own. Essentially, these cases are similar to the Extended Policies case, but without the tax-credit extension assumptions of the No Sunset case.

    • The Expanded Standards case includes updates to appliance standards, as prescribed by the timeline in DOE's multiyear 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. Efficiency levels for updated commercial equipment standards are based on the technology menu from the AEO2011 Reference case and FEMP-designated purchasing specifications for Federal agencies.
    • The Expanded Standards and Codes case begins with the Expanded Standards case and adds national building codes to reach 30-percent improvement relative to the IECC 2006 for residential households and ASHRAE 90.1-2004 for commercial buildings by 2020, with additional rounds of improved codes in 2023 and 2026.
    Industrial Sector cases

    In addition to the AEO2011 Reference case, two standalone cases using the IDM of NEMS were developed to examine the effects of less rapid and more rapid technology change and adoption. Because they are standalone cases, the energy intensity changes discussed in this section exclude the refining industry. Energy use in the refining industry is estimated as part of the PMM in NEMS. Different assumptions for the IDM were also used as part of the Integrated Low and High Renewable Technology Cost cases, Integrated Technology cases, No Sunset case, and Extended Policies case. For the industrial sector:

    • The 2010 Technology case holds the energy efficiency of new plant and equipment constant at the 2010 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 the level and composition of overall industrial output are assumed to be the same as in the Reference, 2010 Technology, and High Technology cases, the change in energy intensity in the two technology side cases is attributable to process and efficiency changes and increased use of CHP.
    • The High Technology case assumes earlier availability, lower costs, and higher efficiency for more advanced equipment [13] and a more rapid rate of improvement in the recovery of biomass byproducts from industrial processes (0.7 percent per year, as compared with 0.4 percent per year in the Reference case). The same assumption is incorporated in the integrated 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 Technology case, it is based on the expectation of higher recovery rates and substantially increased use of CHP in that case.

    The 2010 Technology and High Technology cases were run with only the IDM, rather than in fully integrated NEMS runs. Consequently, no potential feedback effects from energy market interactions are captured, and energy consumption and production in the refining industry, which are modeled in the PMM, are excluded.

    • The No Sunset and Extended Policies cases include an assumption for CHP that extends the existing industrial CHP ITC through the end of the forecast. Additionally, the Extended Policies case includes expansion of the ITC for all industrial CHP capacities and raises the maximum credit that can be claimed. These assumptions are based on the current proposals in S. 1639 and H.R. 4751.
    Transportation Sector cases

    In addition to the AEO2011 Reference case, two standalone cases using the NEMS Transportation Demand Module were developed to examine the effects of advanced technology costs and efficiency improvement on technology adoption and vehicle fuel economy [14]. For the transportation sector:

    • In the Low Technology case, the characteristics of conventional technologies, advanced technologies, and alternative-fuel LDVs, heavy-duty vehicles, and aircraft reflect more pessimistic assumptions about cost and efficiency improvements achieved over the projection. More pessimistic assumptions for fuel efficiency improvement are also reflected in the rail and shipping sectors.
    • In the High 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 High Technology case assumes more rapid incremental improvement in fuel efficiency for engine and emissions control technologies. More optimistic assumptions for fuel efficiency improvements are also made for the air, rail, and shipping sectors.

    The Low and High Technology cases were run with only the Transportation Demand Module rather than as fully integrated NEMS runs. Consequently, no potential macroeconomic feedback related to vehicles costs or travel demand was captured, nor were changes in fuel prices incorporated.

    Three additional integrated cases were developed to examine the potential energy impacts associated with the implementation of stricter fuel economy standards for LDVs and heavy-duty trucks, including:

    • A CAFE 3% Growth case that examines the impact of increasing fuel economy standards by 3 percent annually for model years 2017 through 2025, reaching a combined standard of 46 miles per gallon for new LDVs by 2025. The standards are held constant beyond model year 2025.
    • A CAFE 6% Growth case that examines the impact of increasing fuel economy standards by 6 percent annually for model years 2017 through 2025, reaching a combined standard of 59 miles per gallon for new LDVs by 2025. The standards are held constant beyond model year 2025.
    • A Heavy-Duty Vehicle Fuel Economy Standards case that simulates the expected fuel economy impact of the fuel economy standards for heavy-duty vehicles (Class 2b through Class 8) for model years 2014 through 2018 proposed by the EPA and the NHTSA.
    Electricity Sector cases

    In addition to the Reference case, several integrated cases with alternative electric power assumptions were developed to analyze uncertainties about the future costs and performance of new generating technologies. Two of the cases examine alternative assumptions for nuclear power technologies, and two examine alternative assumptions for fossil fuel technologies. Reference case values for technology characteristics are determined in consultation with industry and government specialists; however, there is always uncertainty surrounding the major component costs. The electricity cases analyze what could happen if costs of new plants were either lower or higher than assumed in the Reference case. The cases are fully integrated to allow feedback between the potential shifts in fuel consumption and fuel prices.

    Nuclear Technology Cost cases
    • The cost assumptions for the Low Nuclear Cost case reflect a 20-percent reduction in the capital and operating costs for advanced nuclear technology in 2011, relative to the Reference case, and fall to 40 percent below the Reference case in 2035. The Reference case projects a 35-percent reduction in the capital costs of nuclear power plants from 2011 to 2035; the Low Nuclear Cost case assumes a 51-percent reduction from 2011 to 2035.
    • The High Nuclear Cost case assumes that capital costs for advanced nuclear technology remain fixed at the 2011 levels assumed in the Reference case. The capital costs are still tied to key commodity price indices, but no cost improvement from "learning-by-doing" effects is assumed.
    Fossil Technology Cost cases
    • In the Low Fossil Technology Cost case, capital costs and operating costs for all coal- and natural-gas-fired generating technologies are assumed to start 20 percent lower than Reference case levels and fall to 40 percent lower than Reference case levels in 2035. Because learning in the Reference case reduces costs with manufacturing experience, costs in the Low Fossil Technology Cost case are reduced by 43 to 58 percent between 2011 and 2035, depending on the technology.
    • In the High Fossil Technology Cost case, capital costs for all coal- and natural-gas-fired generating technologies remain fixed at the 2011 values assumed in the Reference case. Costs are still adjusted year to year by the Commodity Price Index, but no learning-related cost reductions are assumed.

    Additional details about annual capital costs, operating and maintenance costs, plant efficiencies, and other factors used in the Low and High Fossil Technology Cost cases are provided in Assumptions to the Annual Energy Outlook 2011 [15].

    Electricity Plant Capital Cost cases

    Costs to build new power plants have risen dramatically in the past few years, driven primarily by significant increases in the costs of construction-related materials, such as cement, iron, steel and copper. For the AEO2011 Reference case, initial overnight costs for all technologies were updated to be consistent with cost estimates for 2010. A cost adjustment factor based on the projected producer price index for metals and metal products is also applied throughout the projection, allowing overnight costs to fall in the future if the index drops or to rise if the index increases. Although there is significant correlation between commodity prices and power plant costs, there may be other factors influencing future costs that increase the uncertainties surrounding the future costs of building new power plants. For AEO2011, two additional cost cases were run that focus on the uncertainties of future plant construction costs. These cases use exogenous assumptions for the annual adjustment factors, rather than linking to the metals price index. The cases are discussed in the Issues in focus article, "Electricity Plant Cost Uncertainties."

    • In the Frozen Plant Capital Costs case, base overnight costs for all new electric generating technologies are assumed to be frozen at 2015 levels. Cost decreases due to learning can still occur. In this case, costs do decline slightly over the projection, but by 2035 are roughly 25 percent above Reference case costs for the same year.
    • In the Decreasing Plant Capital Costs case, base overnight costs for all new electricity generating technologies are assumed to fall more rapidly than in the Reference case. The base overnight costs are assumed to be 20 percent below the Reference case, through a reduction in the annual cost index. Costs are also assumed to decline more rapidly, so that by 2035 the cost factor is 40 percentage points below the Reference case value.
    Electricity Environmental Regulation cases

    Over the next few years, electricity generators will have to begin steps to comply with a large number of new environmental regulations currently in various stages of promulgation. The AEO2011 Reference case does not include regulations that are still under development. However, the Issues in focus article "Power sector environmental regulations on the horizon" discusses the status of the different rules and examines potential impacts through a number of cases.

    • The Transport Rule Mercury MACT 5 case assumes that the Air Transport Rule limits on SO2 and NOX and a 90-percent mercury MACT (maximum achievable control technology) are enacted. A 5-year recovery period for investments in environmental control projects is assumed.
    • The Transport Rule Mercury MACT 20 case assumes the same rules as above, but a 20-year recovery period for investments in environmental control projects is assumed.
    • The Retrofit Required 5 case represents stringent requirements for reductions in airborne emissions from coal-fired power plants. It assumes that utility boilers fall under the MACT rule, which requires all plants to install FGD scrubbers by 2020 in order to comply with acid gas reduction requirements. It also requires that all plants install selective catalytic reduction (SCR) in order to meet future NOX and ozone emission reduction requirements. If the investment in an FGD and SCR is not economical, the plant is retired. Investments in retrofits are assumed to be recovered over a 5-year period.
    • The Retrofit Required 20 case assumes the same requirements as above, but investments in retrofits are assumed to be recovered over a 20-year period.
    • The Low Gas Price Retrofit Required 5 case is identical to the Retrofit Required 5 case but adds an assumption of increased availability domestic shale availability and utilization rate, as in the High Shale EUR case. Increased access to natural gas lowers the natural gas prices paid by the electric power sector.
    • The Low Gas Price Retrofit Required 20 case is identical to the Low Gas Price Retrofit Required 5 case, but investments in retrofits are assumed to be recovered over a 20-year period.
    Renewable Fuels cases

    In addition to the AEO2011 Reference case, two integrated cases with alternative assumptions about renewable fuels were developed to examine the effects of less aggressive and more aggressive improvement in the cost of renewable technologies. The cases are as follows:

    • In the Low Renewable Technology Cost case, the levelized costs of energy resources for generating technologies using renewable resources are assumed to start at 20 percent below Reference case assumptions in 2011 and decline to 40 percent below the Reference case costs for the same resources in 2035. In general, lower costs are represented by reducing the capital costs of new plant construction. Biomass fuel supplies also are assumed to be 40 percent less expensive than in the Reference case for the same resource quantities used in the Reference case. 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 is also increased.
    • In the High Renewable Technology Cost case, capital costs, operating and maintenance costs, and performance levels for wind, solar, biomass, geothermal and renewable liquid fuel technologies are assumed to remain constant at 2011 levels through 2035. Costs are still tied to key commodity price indexes, but no cost improvement from "learning-by-doing" effects is assumed. Although biomass prices are not changed from the Reference case, this case assumes that dedicated energy crops (also known as "closed-loop" biomass fuel supply) do not become available.
  • Oil and Gas Supply cases

    The sensitivity of the AEO2011 projections to changes in the assumed rates of technological progress in oil and natural gas supply are examined in two cases:

    • In the Slow Technology case, parameters representing the effects of technological progress on production rates, exploration and development costs, and success rates for conventional and unconventional oil and natural gas drilling are 50 percent less optimistic than those in the Reference case. Key Canadian supply parameters also are modified to simulate the assumed impacts of slow oil and natural gas technology penetration on Canadian supply potential. All other parameters in the model are kept at the Reference case values.
    • In the Rapid Technology case, parameters representing the effects of technological progress on production rates, exploration and development costs, and success rates for conventional and unconventional oil and natural gas drilling in the Reference case are improved by 50 percent. Key supply parameters for Canadian oil and natural gas also are modified to simulate the assumed impacts of more rapid oil and natural gas technology penetration on Canadian supply potential. All other parameters in the model are kept at Reference case values, including technology parameters for other modules, parameters affecting foreign oil supply, and assumptions about imports and exports of LNG and natural gas trade between the United States and Mexico. Specific detail by region and fuel category is provided in Assumptions to the Annual Energy Outlook 2011 [16].

    Seven additional cases examine key uncertainties affecting exploration and development of offshore and shale gas resources and their impacts on future domestic natural gas supply.

    • In the Reduced OCS Access case, no new lease sales occur in the Eastern Gulf of Mexico, Pacific, Atlantic, and Alaska OCS through 2035.
    • In the High OCS Resource case, oil and natural gas resources in undeveloped areas of the OCS (namely the Pacific, Eastern Gulf of Mexico, Atlantic, and Alaska) are assumed to be 3 times higher than in the Reference case.
      In the High OCS Costs case, the costs of exploration and development of oil and natural gas resources in the OCS are assumed to be 30 percent higher than in the Reference case.
    • In the Low Shale EUR case, the estimated ultimately recovery (EUR) per 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 shale gas resource is decreased to 423 trillion cubic feet.
    • In the High Shale EUR case, the EUR per shale gas well is assumed to be 50 percent higher than in the Reference case, decreasing the per-unit cost of developing the resource. The total unproved technically recoverable shale gas resource is increased from 827 trillion cubic feet in the Reference case to 1,230 trillion cubic feet.
    • In the Low Shale Recoverability case, the total unproved technically recoverable shale gas resource base is the same as in the Low Shale EUR case (423 trillion cubic feet), but instead of decreasing the EUR per well, the estimate of the number of wells that need to be drilled to fully recover the shale gas in each play is assumed to be 50 percent lower than in the Reference case. This means that the per-unit cost of developing the resource is the same as in the Reference case.
    • In the High Shale Recoverability case, the total unproved technically recoverable shale gas resource base is the same as in the High Shale EUR case (1,230 trillion cubic feet), but instead of increasing the EUR per well, the estimate of the number of wells that need to be drilled to fully recover the shale gas in each play is assumed to be 50 percent higher than in the Reference case. This means that the per-unit cost of developing the resource is the same as in 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 2011 through 2035. 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 2.7 percent observed since 2000. 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 2035. 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 growth rate for Wyoming's Southern Powder River Basin supply curve is increased from -0.5 percent in the Reference case for the years 2011 through 2035 to 2.2 percent in the Low Coal Cost case. Coal mining wages, mine equipment costs, and other mine supply costs all are assumed to be about 22 percent lower in 2035 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 2035.
    • 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 2035 are assumed to be about 28 percent higher than in the Reference case, and coal transportation rates in 2035 are assumed to be 25 percent higher.

    Additional details of the productivity, wage, mine equipment cost, and coal transportation rate assumptions for the Reference and alternative coal cost cases are provided in Appendix D.

    Cross-cutting integrated cases

    In addition to the sector-specific cases described above, a series of cross-cutting integrated cases are used in AEO2011 to analyze specific cases with broader sectoral impacts. For example, two integrated technology progress cases combine the assumptions from the other technology progress cases to analyze the broader impacts of more rapid and slower technology improvement rates. In addition, two cases also were run with alternative assumptions about expectations of future regulation of GHG emissions.

    Integrated technology cases

    The Integrated 2010 Technology case combines the assumptions from the Residential, Commercial, and Industrial 2010 Technology cases and the Electricity High Fossil Technology Cost, High Renewable Technology Cost, and High Nuclear Cost cases. The Integrated High Technology case combines the assumptions from the Residential, Commercial, and Industrial High Technology cases and the Electricity Low Fossil Technology Cost, Low Renewable Technology Cost, and Low Nuclear Cost cases.

    Greenhouse gas cases

    Although currently no Federal cap-and-trade legislation or carbon allowance pricintg for CO2 emissions is in place in the United States, the EPA announced a proposal in September 2009 to regulate emissions under the CAAA90. Under the proposal, industrial facilities with emission over 25,000 metric tons per year would be required to obtain permits that would demonstrate they are using the best practices and technologies to minimize GHG emissions. The rule also proposes new CAAA90 thresholds for permits to new or existing industrial facilities for GHG emissions under the New Source Review (NSR) and Title V operating permits programs. As a result, regulators and the investment community are beginning to push energy companies to invest in less GHG-intensive technologies. To reflect the market reaction to potential future GHG regulation, a 3-percentage-point increase is assumed in the cost of capital for investments in new coal-fired power plants without CCS and new CTL plants without CCS in the Reference case and all other AEO2011 cases except the No GHG Concern and GHG Price Economywide cases. Those assumptions affect cost evaluations for the construction of new capacity but not the actual operating costs when a new plant begins operation.

    Two alternative GHG cases are used to provide a range of other potential outcomes, from no concern about future GHG legislation to the imposition of a specific economy-wide carbon allowance price. In the GHG Price Economywide case, an economy-wide carbon allowance price is examined. The price begins at $25 per metric ton CO2 in 2013 and rises to $75 per metric ton CO2 in 2035 (2009 dollars). This trajectory is consistent with the cost containment provisions in both the Kerry-Lieberman and Waxman-Markey GHG legislation. No assumptions are made for offsets, bonus allowances for CCS, or specific allocation of allowances in these cases.

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

    CO2 Availability cases

    Two alternative CO2 availability cases are used to provide sensitivity analysis of oil production from CO2-EOR, depending on the availability of relatively inexpensive CO2 both with a carbon price and without one. The Low EOR case assumes that industrial CO2 available from CTL and BTL plants is reduced by 50 percent from the Reference case. The Low EOR/GHG Price Economywide case assumes that the CO2 availability is reduced and a carbon price exists that provides incentives for emitters to install carbon capture capabilities.

    No Sunset case

    In addition to the AEO2011 Reference case, a case was run assuming that selected policies with sunset provisions like the PTC, ITC, and tax credits for energy-efficient equipment in the buildings and industrial sectors will be extended indefinitely rather than allowed to sunset as the law currently prescribes.

    For the residential sector, these extensions include: (a) personal tax credits for selected end-use equipment, including furnaces, heat pumps, and central air conditioning; (b) personal tax credits for PV installations, solar water heaters, small wind turbines, and geothermal heat pumps; (c) manufacturer tax credits for refrigerators, dishwashers, and clothes washers, passed on to consumers at 100 percent of the tax credit value.

    For the commercial sector, business ITCs for solar photovoltaic 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.

    In the industrial sector, the existing ITC for industrial CHP, which currently ends in 2016, is extended to 2035.

    For the refinery sector, blending credits are extended; the $1.00 per gallon biodiesel tax credit is extended; the $0.54 per gallon imported ethanol tariff is extended; and the $1.01 per gallon cellulosic biofuels PTC is extended.

    For renewables, the PTC of 2.1 cents per kilowatthour (or 30 percent for wind, geothermal, biomass, hydroelectric, and landfill gas resources), which currently are set to expire at the end of 2012 for wind and 2013 for other eligible resources, are extended to 2035; and the 30-percent solar power ITC, which currently is scheduled to revert to 10 percent, is extended indefinitely.

    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 introduced. Finally, proposed rules by the NHTSA and EPA for national tailpipe CO2-equivalent emissions and fuel economy standards for LDVs, including both passenger cars and light-duty trucks, are harmonized and incorporated in this case.

    Updates to appliance standards are assumed to occur as prescribed by the timeline in DOE's multiyear plan, and new standards for products currently not covered by DOE are introduced by 2019. The efficiency levels chosen for the updated residential appliance standards are based on current ENERGY STAR guidelines.

    The efficiency levels chosen for updated commercial equipment standards are based on the technology menu from the AEO2011 Reference case and either FEMP-designated purchasing specifications for Federal agencies or ENERGY STAR guidelines. National building codes are added to reach 30-percent improvement relative to IECC 2006 for residential households and ASHRAE 90.1-2004 for commercial buildings by 2020, with additional rounds of improvements in 2023 and 2026.

    In the industrial sector, tax credits are further extended to cover all systems sizes rather than applying only to systems under 50 megawatts, and the maximum credit (cap) is increased from $15,000 to $25,000 per system. These extensions are consistent with previously proposed legislation (S. 1639) or pending legislation (H.R. 4751).

    For transportation, the Extended Policies case assumes that the standards are further increased, so that the minimum fuel economy standard achieved by LDVs increases to 45.6 miles per gallon in 2035.

    E15 cases

    Two alternative E15 cases were established to reflect the potential variability in consumer demand for E15, which depends on multiple factors and ultimately affects the conversion rate of gasoline stations from E10 to E15.

    • In the Low E15 Penetration case, the infrastructure and regulatory barriers to E15 adoption are more pronounced, and penetration of E15 in all demand regions grows at a slower rate, reaching a lower maximum level than in the Reference case
    • In the High E15 Penetration case, E15 adoption occurs at a faster rate and reaches a higher overall level than in the Reference case. Any State that currently has laws or regulations that prohibit the use of ethanol blends above 10 percent or gasoline with an oxygenate content in excess of 3.5 percent is assumed to remove those restrictions by 2015. In addition, E15 penetration rises to 99 percent of the potential maximum level in all regions by 2020, indicating that infrastructure or regulatory barriers do not inhibit the use of E15 in gasoline markets.
Reference Case Tables