‹ Analysis & Projections

Annual Energy Outlook 2016

Full Release Date: September 15, 2016   |  Next Early Release Date:  January 2017   |  full report

Appendix E

NEMS overview and brief description of cases

The National Energy Modeling System

Projections in the Annual Energy Outlook 2016 (AEO2016) are generated using the National Energy Modeling System (NEMS) [1], developed and maintained by the Office of Energy Analysis of the U.S. Energy Information Administration (EIA). In addition to its use in developing the Annual Energy Outlook (AEO) projections, NEMS is used to complete analytical studies for the U.S. Congress, the Executive Office of the President, other offices within the U.S. Department of Energy, and other federal agencies. NEMS is also used by nongovernment groups, such as the Electric Power Research Institute, Duke University, and Georgia Institute of Technology. In addition, AEO projections are used by analysts and planners in other government agencies and nongovernmental organizations.

The projections in NEMS are developed with the use of a market-based approach, subject to regulations and standards. For each fuel and consuming sector, NEMS balances energy supply and demand, accounting for economic competition across the various energy fuels and sources. The time horizon of NEMS extends to 2040. To represent regional differences in energy markets, the component modules of NEMS function at the regional level: the 9 Census divisions for the end-use demand modules; production regions specific to oil, natural gas, and coal supply and distribution; 22 regions and subregions of the North American Electric Reliability Corporation for electricity; and 9 refining regions that are a subset of the 5 Petroleum Administration for Defense Districts.

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 activities necessary to produce, import, and transport fuels to end users. The information flows also include such areas as economic activity, domestic production, and international petroleum supply. NEMS calls each supply, conversion, and end-use demand module in sequence until the delivered prices of energy and the quantities demanded have converged within tolerance, thereby achieving an economic equilibrium of supply and demand in the consuming sectors. A solution is reached for each year from 2015 through 2040. Other variables, such as petroleum product imports, crude oil imports, and several macroeconomic indicators, also are evaluated for convergence.

Each NEMS component represents the effects and costs of legislation and environmental regulations that affect each sector. NEMS accounts for all energy-related carbon dioxide emissions, as well as emissions of sulfur dioxide, nitrogen oxides, and mercury from the electricity generation sector.

The version of NEMS used for AEO2016 generally represents current legislation and environmental regulations, including recent government actions for which implementing regulations were available as of February 29, 2016, as discussed in the AEO2016 Legislation and Regulations section. The potential effects of proposed federal and state legislation, regulations, or standards—or of sections of legislation that have been enacted but require funds or implementing regulations that have not been provided or specified—are not reflected in NEMS. Many of the pending provisions are examined, however, in alternative cases included in AEO2016 or in other analysis completed by EIA.

In general, the historical data presented with AEO2016 projections are based on various EIA publications [2]; however, data also were taken from multiple non-EIA sources. Historical numbers through the year 2015 are presented for comparison only and may be estimates. Source documents should be consulted for the official data values. Footnotes to AEO2016 appendix tables indicate the definitions and sources of historical data.

Where possible, AEO2016, which was developed during the winter of 2015–16, presents information for 2015, 2016, and 2017 that is consistent with the short-term projections from EIA's February 2016 Short-Term Energy Outlook (STEO) [3]. EIA's views regarding energy use over the 2016 through 2017 period are reported in monthly STEO updates, which should be considered to supersede information reported for those years in AEO2016.

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, disposable income, values 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 Industrial Output Model, and National Employment by Industry Model.

In addition, EIA has constructed a Regional Economic, Industrial Output and Employment by Industry model to project regional economic drivers, and a Commercial Floorspace model to project growth rates in 13 floorspace types in the nine Census divisions. The accounting framework for industrial value of shipments uses the North American Industry Classification System (NAICS).

International Energy Module

The International Energy Module (IEM) uses assumptions about 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 module provides a supply curve for world crude-like liquids 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 assumptions about petroleum products for import and export in the United States. The IEM, through interaction with the rest of NEMS, changes North Sea Brent and West Texas Intermediate prices in response to changes in expected production and consumption of crude-like liquids and petroleum products 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 technology. Both modules incorporate projections of 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.

The investment tax credit (ITC) for renewable fuels, fuel cells, and combined heat and power systems is incorporated, as currently enacted, including a phaseout of the credit for solar energy technologies, followed by a permanent 10% ITC for business investment in solar energy (thermal nonpower uses as well as power uses). The module reflects the recently extended deadline and change in eligibility for the 30% ITC for eligible projects under construction before January 1, 2020. The module additionally captures the ITC phaseout—decreasing the credit for solar projects starting construction in 2020 and 2021 to 26% and 22%, respectively. Commercial projects under construction after 2021 receive a credit equivalent to 10% of capital costs. Tax credits for solar systems purchased by individual homeowners are phased out completely by 2022.

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 Macroeconomic Activity Module, the representation of industrial activity in NEMS is based on the NAICS. The industries are classified into three groups— energy-intensive manufacturing, nonenergy-intensive manufacturing, and nonmanufacturing. Seven of eight energy-intensive manufacturing industries are modeled in the IDM, including energy-consuming components for boiler/steam/cogeneration, buildings, and process/assembly use of energy. Energy demand for petroleum and other liquids refining (the other energy-intensive manufacturing industry) is modeled in the Liquid Fuels Market Module as described below, but the projected consumption is reported under the industrial totals.

There are several AEO2016 updates and upgrades in the representations of selected industries, including upgraded representations for the iron and steel and paper industries. Instead of assuming that technological development for a particular process occurs on a predetermined or exogenous path based on engineering judgment, these upgrades allow technological change in the iron and steel and paper industries to be modeled endogenously, using a more detailed representation of technology choices. The upgrade allows for explicit technological change, and therefore energy intensity, to respond to economic, regulatory, and other conditions. To model technology choices more accurately, the paper industry shipments have been broken out into pulp and paper mills, paperboard containers, and other paper. For iron and steel and for paper, steam use is modeled in the process/assembly step. All manufacturing industries except cement and lime, aluminum, and glass are benchmarked to the Manufacturing Energy Consumption Survey 2010. The combined cement and lime industries, aluminum industry, and glass industry were upgraded to technology choice models in previous editions of the Annual Energy Outlook.

Transportation Demand Module

The Transportation Demand Module projects consumption of energy by mode and fuel—including petroleum products, electricity, methanol, ethanol, compressed natural gas, liquefied natural gas, and hydrogen—in the transportation sector, subject to delivered energy prices, macroeconomic variables such as gross domestic product, and other factors such as technology adoption and consumer behavior. 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, and the American Recovery and Reinvestment Act of 2009—which contain tax credits for the purchase of alternatively fueled vehicles. Representations of corporate average fuel economy and greenhouse gas (GHG) emissions standards for LDVs, heavy-duty vehicle (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 and the California Air Resources Board Zero Emissions Vehicle Program.

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 also 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. Freight ton-miles and efficiency also are projected in the model. Legislation such as the International Convention for the Prevention of Pollution from Ships is also included.

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. This submodule also determines interregional trading and costs of electricity generation. The finance and pricing submodule uses capital costs, fuel and operating costs, macroeconomic parameters, environmental regulations, and load shapes to estimate retail prices by sector for generation, transmission, and distribution services.

All specifically identified options promulgated by 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 carbon dioxide (CO2) that affect the electricity generation sector, and those regulations are represented in AEO2016. The AEO2016 Reference case also imposes a limit on CO2 emissions for specific covered sectors, including the electric power sector in California as represented in California Assembly Bill 32, the Global Warming Solutions Act of 2006 (AB 32). The AEO2016 Reference case includes the Cross-State Air Pollution Rule (CSAPR), using the original emissions budgets and revised implementation schedule, after the rule was reinstated in late 2014. CSAPR is intended to reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) from power plants in the eastern half of the United States by imposing state-level caps on emissions and facilitating a limited interstate cap-and-trade program. 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 EPA in December 2011.

In August 2015, EPA released final rules under the Clean Air Act Sections 111(b) and 111(d) setting carbon pollution standards for new, modified, and reconstructed power plants and for existing fossil-fired plants. The requirements for new power plants are represented in the Reference case by allowing new technologies to be built only if they can meet the standards of 1,000 pounds CO2 per megawatthour (MWh) for natural gas combined cycle plants, and 1,400 pounds CO2/MWh for coal-fired plants, based on adjusted gross generation. EPA’s Clean Power Plan (CPP) establishes emissions standards for existing power plants and provides many alternative ways for states to demonstrate compliance, as discussed in the AEO2016 Legislation and Regulations section. The Reference case assumes that the CPP is met through regional mass-based goals, implemented at the 22 EMM region level. The Supreme Court has stayed enforcement of the CPP pending resolution of ongoing litigation, but as of this writing no lower court has either affirmed or vacated the rule. The AEO2016 also includes a case that assumes no CPP rule is in force.

Because regulators and the investment community have continued to push energy companies to invest in technologies that are less GHG-intensive, there is considerable financial risk associated with major investments in long-lived power plants with relatively higher rates of carbon dioxide emissions. The trend is captured in the AEO2016 Reference case through a 3-percentagepoint 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. Although any new coal-fired plants are assumed to be compliant with CAA 111(b), they would capture only 30% of CO2 emissions; thus, they still would be considered high emitters relative to other sources and would face potential financial risk.

Renewable Fuels Module

The Renewable Fuels Module (RFM) includes submodules representing renewable resource supply and technology input information for central-station, grid-connected electricity generation technologies, including conventional hydroelectricity, biomass (dedicated biomass plants and co-firing in existing coal plants), geothermal, landfill gas, solar thermal electricity, solar photovoltaics, and both onshore and offshore wind energy. The RFM includes renewable resource supply estimates representing the regional opportunities for renewable energy development.

The ITC for renewable fuels, as currently enacted, is incorporated in the RFM and reflect the recently extended deadline and change in eligibility for the 30% ITC for qualified projects under construction before January 1, 2020. The module additionally captures the ITC phaseout—decreasing to 26% and then 22%—for projects starting construction in 2020 and 2021, respectively. After 2021, all solar (thermal nonpower uses as well as power uses) receive a permanent credit equivalent to 10% of capital costs, regardless of the year in which their construction commenced. Tax credits pertaining to individual homeowners and businesses are reflected separately in the Residential and Commercial Demand Modules.

The recently enacted production tax credit (PTC) for wind, geothermal, biomass-fueled (open-loop biomass is assumed to be the dominant source), landfill gas, and certain types of hydroelectric plants also are represented in the RFM. For wind projects, the tax credit retains its full value of 2.3 cents/kilowatthour (kWh) through 2016. The PTC phaseout begins in January 2017 with a stepdown schedule as follows:

  • Wind projects under construction after 2016, but before the end of 2017, receive a credit equal to 80% of the current PTC value.
  • Wind projects under construction in 2018 receive a credit equal to 60% of the current value.
  • Wind projects under construction after 2018, but before the end of 2019, receive a credit equal to 40% of the current value.

Eligibility is extended for 2 years, until January 1, 2017, with no phase-down in value for other PTC-eligible technologies. Geothermal facilities receive the full 2.3 cents/kWh, while other technologies (including open-loop biomass, certain waste energy facilities, incremental hydroelectric, marine, and tidal) receive a half-value credit of 1.2 cents/kWh. The credits are adjusted annually for inflation and are claimed during the first 10 years of a plant’s operation. In addition, new geothermal facilities continue to receive a 10% ITC after the PTC expires because they were previously eligible for the 10% ITC.

While current legislation allows-PTC eligible technologies the option to claim the ITC in lieu of the PTC (subject to the same PTC phaseout schedule), EIA assigns the most economically beneficial tax credit option, based on analyst judgment. AEO2016 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 2016 [4].

Oil and Gas Supply Module

The Oil and Gas Supply Module represents domestic crude oil and natural gas supply within an integrated framework that captures the interrelationships among the various sources of supply—onshore, offshore, and Alaska—by all production techniques, including natural gas recovery from coalbeds and low-permeability geologic formations. The framework analyzes cash flow and profitability to compute investment and drilling for each of the supply sources, based on the prices for crude oil and natural gas, the domestic recoverable resource base, and the state of technology. Oil and natural gas production activities are modeled for 12 supply regions, including six onshore, three offshore, and in three Alaska regions.

The Onshore Lower 48 Oil and Gas Supply Submodule evaluates the economics of future exploration and development projects for crude oil and natural gas plays. Crude oil resources include structurally reservoired resources (i.e., conventional) as well as highly fractured continuous zones, such as the Austin Chalk and Bakken shale formations. Production potential from advanced secondary recovery techniques (such as infill drilling, horizontal continuity, and horizontal profile) and enhanced oil recovery (such as CO2 flooding, steam flooding, polymer flooding, and profile modification) are explicitly represented. Natural gas resources include highpermeability carbonate and sandstone, tight gas, shale gas, and coalbed methane.

Domestic crude oil production volumes are used as inputs to the Liquid Fuels Market Module (LFMM) for conversion and blending into refined petroleum products. Supply curves for natural gas are used as inputs to the Natural Gas Transmission and Distribution Module (NGTDM) for determining natural gas wellhead prices and domestic production.

Natural Gas Transmission and Distribution Module

The Natural Gas Transmission and Distribution Module (NGTDM) models the transmission, distribution, and pricing of natural gas, subject to end-use demand for natural gas, the availability of domestic natural gas, and natural gas traded on the international market. The module balances natural gas supply and demand, tracks the flows of natural gas, and determines the associated capacity expansion requirements in an aggregate pipeline network, connecting domestic and limited foreign supply sources with 12 regions in the Lower 48 states. The 12 regions align with the 9 Census divisions (with 3 subdivided). Alaska is handled separately.

The flow of natural gas is determined for both a peak and an off-peak period in the year, assuming a historically based seasonal distribution of natural gas demand. Key components of pipeline and distributor tariffs are included in separate pricing algorithms. The primary outputs of the module are delivered natural gas prices by region and sector, supply prices, and realized domestic natural gas production. The module also projects natural gas pipeline imports and exports to Canada and Mexico, as well as liquefied natural gas imports and exports.

Liquid Fuels Market Module

The Liquid Fuels Market Module (LFMM) projects prices of petroleum products, crude oil and product import/export activity, and domestic refinery operations, subject to demand for petroleum products, availability and price of imported petroleum, environmental regulations, 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 [5] are reviewed and updated annually.

The module represents refining activities in eight U.S. regions and a Maritime Canada/Caribbean refining region (created to represent short-haul international refineries that predominantly serve U.S. markets). For better representation of policy, import/export patterns, and biofuels production, the eight U.S. regions are defined by subdividing three of the five U.S. Petroleum Administration for Defense Districts. The nine refining regions are defined below:

Region 1. PADD I – East Coast Region 2. PADD II – Midwest - inland Region 3. PADD II – Midwest - lakes Region 4. PADD III – Gulf Coast - gulf Region 5. PADD III – Gulf Coast - inland Region 6. PADD IV – Rocky Mountain Region 7. PADD V – West Coast - California Region 8. PADD V – West Coast - other Region 9. Maritime Canada/Caribbean.

The LFMM models the costs of producing automotive fuels, such as conventional and reformulated gasoline, and includes production of biofuels for blending in gasoline and diesel. Fuel ethanol and biodiesel are included in the LFMM because they are commonly blended into petroleum products. The module allows ethanol blending into gasoline at 10% by volume, 15% by volume in states that lack explicit language capping ethanol volume or oxygen content, and up to 85% by volume for use in flexfuel vehicles. The module also includes a 16% (by volume) biobutanol/gasoline blend. Crude oil and refinery product imports are represented by supply curves defined by the NEMS IEM. Products also can be imported from refining Region 9 (Maritime Canada/Caribbean). Refinery product exports are represented by demand curves, also provided by the IEM. Crude exports from the United States also are represented.

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 the Energy Independence and Security Act of 2007, 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. Corn ethanol plants, which are numerous (responsible for 98% of total ethanol produced in the U.S.), 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, which are produced at ethanol refineries that ferment and distill grains other than corn and reduce greenhouse gas emissions by at least 50%, is another new technology modeled in the LFMM. The LFMM also has the capability to model production of biobutanol from a retrofitted corn ethanol facility, if economically competitive.

Fuels produced by Fischer-Tropsch synthesis or through a pyrolysis process also are modeled in the LFMM, based on their economics in comparison with competing feedstocks and products. The five processes modeled are CTL, CBTL, GTL, BTL, and pyrolysis. Two California-specific policies also are represented in the LFMM: the Low Carbon Fuel Standard (LCFS) and the Assembly Bill 32, the Global Warming Solutions Act of 2006 (AB 32), cap-and-trade program. The LCFS requires the carbon intensity of transportation fuels sold for use in California (the amount of greenhouse gases emitted per unit of energy) 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 (Industrial Demand Module, EMM, and Emissions Policy Module), the LFMM provides emissions allowances and actual emissions of CO2 from California refineries, and NEMS provides the mechanism (carbon price) to trade allowances such that the total CO2 emissions cap is met.

Coal Market Module

The Coal Market Module (CMM) simulates mining, transportation, and pricing of coal, subject to end-use demand for coal differentiated by heat and sulfur content. U.S. coal production is represented in the CMM by 41 separate supply curves—differentiated by region, mine type, coal rank, and sulfur content. The coal supply curves respond to mining capacity, capacity utilization of mines, labor productivity, and factor input costs (mining equipment, mining labor, and fuel requirements). Projections of U.S. coal distribution are determined by minimizing the cost of coal supplied, given coal demands by region and sector; environmental restrictions; and accounting for minemouth prices, transportation costs, and coal supply contracts. Over the projection horizon, coal transportation costs in the CMM vary in response to changes in the cost of rail investments.

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

Annual Energy Outlook 2014 cases

Table E1 provides a summary of the cases produced as part of AEO2016. For each case, the table gives the name used in AEO2016, 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 2016. Regional results and other details of the projections are available at http://www.eia.gov/forecasts/aeo/tables_ref.cfm#supplement.

Macroeconomic growth cases

In addition to the AEO2016 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 0.7%/year, nonfarm employment by 0.7%/year, and productivity by 1.7%/ year from 2015 to 2040. Economic output as measured by real GDP increases by 2.2%/year from 2015 through 2040, and growth in real disposable income per capita averages 1.7%/year.
  • The Low Economic Growth case assumes lower growth rates for population (0.6%/year) and productivity (1.3%/year), resulting in lower growth in nonfarm employment (0.6%/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 1.6%/year from 2015 through 2040, and growth in real disposable income per capita averages 1.4%/year.
  • The High Economic Growth case assumes higher growth rates for population (0.8%/year) and productivity (2.0%/year), resulting in higher nonfarm employment (1.0%/year). With higher productivity gains and employment growth, inflation and interest rates are lower than in the Reference case, and consequently economic output grows at a higher rate (2.8%/year) than in the Reference case (2.2%/year). Real disposable income per capita grows by 2.0%/year.
Table E1. Summary of the AEO2016 cases
Case name Description Reference in text Reference in Appendix E
Reference Real gross domestic product (GDP) grows at an average annual rate of 2.2% from 2015 to 2040. Brent crude oil prices rise to about $136/barrel (b) (2015 dollars) in 2040. Complete projection tables in Appendix A. -- --
Low Economic Growth Real GDP grows at an average annual rate of 1.6% from 2015 to 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables in Appendix B. p. MT-2 p. E-6
High Economic Growth Real GDP grows at an average annual rate of 2.8% from 2015 to 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables in Appendix B. p. MT-2 p. E-6
Low Oil Price Low prices result from a combination of relatively low demand for petroleum and other liquids in the non-Organization for Economic Cooperative Development (non-OECD) nations and higher global supply. Lower demand occurs as a result of several factors: economic growth that is relatively slow compared with history; reduced consumption from the adoption of more efficient technologies, extension of the corporate average fuel economy (CAFE) standards, less travel demand, and increased natural gas or electricity use; efficiency improvement in nonmanufacturing in non-OECD countries; and industrial fuel switching from liquid to natural gas feedstocks for producing methanol and ammonia. On the supply side, both Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC producers face lower costs of production for both crude oil and other liquids production technologies. However, lower-cost supply from OPEC producers eventually begins to crowd out supply from relatively more expensive non-OPEC sources. OPEC’s market share of liquids production rises steadily from 39% in 2015 to 43% in 2020 and 47% in 2040. Light, sweet crude oil prices fall to an average of $35/b (2015 dollars) in 2016, remain below $50/b through 2030, and stay below $75/b through 2040. Partial projection tables in Appendix C. p. MT-3 p. E-8
High Oil Price High prices result from a lack of global investment in the oil sector, eventually inducing higher production from non-OPEC producers relative to the Reference case. Higher prices stimulate increased supply from resource that are more expensive to produce—such as tight oil and bitumen, as well as increased production of renewable and synthetic fuels, compared with the Reference case. Increased non-OPEC production crowds out OPEC oil, and OPEC’s share of world liquids production decreases, never exceeding the 41% reached in 2012 and dropping to 34% by the end of the projection. On the demand side, higher economic growth than in the Reference case, particularly in non-OECD countries, leads to increased demand: non-OECD consumers demand greater personal mobility and consumption of goods. There are also fewer efficiency gains throughout the industrial sector, and growing fuel needs in the nonmanufacturing sector continue to be met with liquid fuels, especially in response to policy shifts that force liquids to replace coal for chemical feedstock. Crude oil prices are about $230/b (2015 dollars) in 2040. Partial projection tables in Appendix C. p. MT-3 p. E-9
Extended Policies The Extended Policies case begins with the Reference case and assumes extension of all existing tax credits (full credit values prior to phaseout are extended where phaseouts are scheduled) and policies that contain sunset provisions, except those requiring additional funding (e.g., loan guarantee programs). It also assumes an increase in capacity limitations on the investment tax credit (ITC) for combined heat and power, and extension of the program. The case includes an additional round of efficiency standards for residential and commercial products, as well as new standards for products not yet covered; adds multiple rounds of national building codes by 2034; and increases LDV and HDV fuel economy standards in the transportation sector. This case also includes the extension of EPA’s Clean Power Plan regulations that reduce carbon dioxide emissions from electric power generation after 2030. Partial projection tables in Appendix D. p. IF-22 p. E-9
Oil and Gas: Low Oil and Gas Resource and Technology Estimated ultimate recovery per shale gas, tight gas, and tight oil well in the United States and undiscovered resources in Alaska and the offshore lower 48 states are 50% lower than in the Reference case. Rates of technological improvement that reduce costs and increase productivity in the United States are also 50% lower than in the Reference case. All other assumptions remain the same as in the Reference case. Partial projection tables in Appendix D. p. MT-29 p. E-11
Oil and Gas: High Oil and Gas Resource and Technology Estimated ultimate recovery per shale gas, tight gas, and tight oil well in the United States, and undiscovered resources in Alaska and the offshore lower 48 states, are 50% higher than in the Reference case. Rates of technological improvement that reduce costs and increase productivity in the United States are also 50% higher than in the Reference case. In addition, tight oil and shale gas resources are added to reflect new plays or the expansion of known plays. All other assumptions remain the same as in the Reference case. Partial projection tables in Appendix D. p. MT-29 p. E-11
Electricity: No CPP Assumes that the Clean Power Plan (CPP) is not enforced, and that no federal requirements are in place to reduce carbon dioxide emissions from existing power plants. p. IF-3 p. E-10
Electricity: CPP Rate Assumes that CPP compliance is met through regional rate-based (pounds/ MWh) standards that, on average, affect all generation within the region. p. IF-3 p. E-10
Electricity: CPP Interregional Trading Assumes that CPP compliance is met through regional mass-based caps, including new sources, and allows trading of carbon allowances between regions within the Eastern Interconnect and within the Western Interconnect. p. IF-3 p. E-10
Electricity: CPP Extended Assumes that the CPP CO2 emissions targets continue to decline after 2030, reaching a 45% reduction below 2005 levels in 2040. p. IF-4 p. E-10
Electricity: CPP Hybrid Assumes that regions can vary their CPP compliance method, with the Northeast and CA regions choosing mass-based caps and the remaining regions using average rate-based standards. p. IF-4  p. E-10 
Electricity: CPP Allocation to Generators Assumes the same CPP compliance as in the Reference case, except that the carbon allowances are allocated to generators instead of being allocated to load entities, resulting in higher retail price impacts. p. IF-4 p. E-10
Energy Efficiency Case for Manufacturing Industries with Technology Choice Assuming Reference case prices and economic conditions, examines the effects of more aggressive adoption of energy-efficient technologies and rapid improvement in energy intensity on manufacturers in five industries (cement and lime, aluminum, glass, iron and steel, and paper). p. IF-36 p. E-9
Industrial Efficiency Low Incentive Uses a price on CO2 emissions as a proxy for higher energy costs, as a way to increase energy efficiency in all industries except refining. A CO2 price is phased in gradually, starting in 2018, reaches $12.50/metric ton in 2023, and increases by 5% per year thereafter. p. IF-35 p. E-9
Industrial Efficiency High Incentive As in the Industrial Efficiency Low Incentive case, with the only difference being that the CO2 price is $35.00/metric ton in 2023. p. IF-35 p. E-9
Phase 2 Standards Assumes improvements to medium- and heavy-duty vehicle technologies while increasing the number of technologies from 37 to 70. Restructures the current 13 vehicle size classes and incorporates an additional size class, bringing the total to 14 size classes. p. IF-16 p. E-10
 

Oil price cases

The benchmark oil price in AEO2016 is based on spot prices for North Sea Brent crude oil, which is an international standard for light sweet crude oil. The West Texas Intermediate (WTI) spot price is generally lower than the North Sea Brent price. EIA expects the price spread between Brent and WTI in the Reference, Low Oil Price, and High Oil Price cases to range between $0/b and $10/b and will continue to report WTI prices—a critical reference point for the value of growing production in the U.S. Midcontinent—as well as the imported refiner acquisition cost for crude oil. The December 2015 decision by the U.S. Congress to remove restrictions on U.S. crude oil exports also has the potential to narrow the spread between the Brent price and the price of domestic production streams under certain cases involving high levels of U.S. crude oil production [6].

The historical record shows substantial variability in oil prices, and there is arguably even more uncertainty about future prices in the long term. AEO2016 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 global demand and supply of petroleum and other liquid fuels. The Low Oil Price case assumes conditions under which global liquids demand is low and supply is high; the High Oil Price case assumes the opposite. Both cases illustrate situations in which the shifts in global supply and demand are offsetting, so that liquids consumption is close to Reference case levels, but prices are substantially different.

  • In the Reference case, real oil prices (2015 dollars) fall from $52/b in 2015 to a low of $37/b in 2016, before rising steadily to $136/b in 2040. The Reference case represents a trend projection for both oil supply and demand. Global supply increases through the medium-term (although it does slow from 2020–25) and is limited by geopolitical constraints rather than by resource availability. Global petroleum and other liquids consumption increases steadily throughout the Reference case, in part because of an increase in the number of vehicles across the world, which is offset somewhat by improvements in LDV and HDV fuel economy in developing countries, as well as increased natural gas use for transportation in most regions. Economic growth is steady over the projection period, and there is some substitution away from liquids fuels in the industrial sector.
  • In the Low Oil Price case, crude oil prices fall to an average of $35/b (2015 dollars) in 2016, remain below $50/b through 2030, and stay below $75/b through 2040. Relatively low demand compared to the Reference case occurs as a result of several factors: economic growth that is relatively slow compared to history; reduced consumption in developed countries resulting from the adoption of more efficient technologies, extended CAFE standards, less travel demand, and increased use of natural gas or electricity; efficiency improvement in nonmanufacturing industries in the non-OECD countries; and industrial fuel switching from liquids to natural gas feedstocks for production of methanol and ammonia. Low oil prices also result from lower costs of production and relatively abundant supply from both OPEC and non-OPEC producers. However, lower-cost supply from OPEC producers eventually begins to crowd out supply from relatively more expensive non-OPEC sources. In the Low Oil Price case, OPEC’s market share of liquids production rises steadily from 39% in 2015 to 43% in 2020 and to 47% in 2040.
  • In the High Oil Price case, oil prices average about $230/b (2015 dollars) in 2040. A lack of global investment in the oil sector is the primary cause of higher prices, which eventually lead to higher production from non-OPEC producers relative to the Reference case. Higher prices stimulate increased supply of more costly resources, including tight oil and bitumen, and also lead to significant increases in production of renewable liquid fuels as well as GTL and CTL compared with the Reference case. Increased non-OPEC production crowds out OPEC oil, and OPEC’s share of world liquids production decreases, never exceeding the 41% share reached in 2012 and dropping to 34% in 2040. The main reason for increased demand in the High Oil Price case is higher economic growth, particularly in developing countries, than in the Reference case. In the developing countries, consumers demand greater personal mobility and more consumption of goods. There are fewer efficiency gains in the industrial sector, while growing demand for fuel in the non-manufacturing sector continues to be met with liquid fuels, and policy shifts result in the replacement of chemical feedstocks by coal.

Buildings sector cases

The Extended Policies case includes assumptions in the NEMS Residential and Commercial Demand Modules. The Extended Policies case extends federal incentives that have a specific sunset date in current law and adds an additional round of appliance standards and multiple rounds of building codes, as described below.

  • The Extended Policies case assumes that selected federal policies with sunset provisions are extended indefinitely at current levels rather than being allowed to sunset as the law currently prescribes. For the residential sector, personal tax credits are extended at the 30% level through 2040 for solar photovoltaics installations, solar water heaters, small wind turbines, and geothermal heat pumps. For residential solar equipment, tax credits are extended at the 30% level instead of being phased out completely as specified by current law. For the commercial sector, the ITC for solar technologies, small wind turbines, geothermal heat pumps, and combined heat and power is extended at the 30% level through 2040. The business tax credit for solar technologies remains at the 30% level through 2040 instead of being phased down to 10%. The Extended Policies case includes updates to federal appliance standards, as prescribed by the timeline in the Department of Energy’s (DOE) 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 or “mid-level” efficiencies where ENERGY STAR guidelines are not available. Enduse technologies eligible for extended incentives are not subject to new standards. Efficiency levels for updated commercial equipment standards are based on the technology menu from the AEO2016 Reference case and purchasing specifications for federal agencies designated by the Federal Energy Management Program. The Extended Policies case also adds two additional rounds of improved national building codes with implementation beginning in 2025 and 2034, each phased in over nine years.

Industrial sector cases

In addition to the AEO2016 Reference case, three technology-focused cases were developed, using the Industrial Demand Module (IDM) to examine the effects of less rapid and more rapid technology change and adoption in the industrial sector. The energy intensity changes discussed in this section exclude the refining industry, which is modeled separately from the IDM in the Liquid Fuels Market Module. The technology cases are described as follows:

  • The Energy Efficiency Case for Manufacturing Industries with Technology Choice case examines the effects of efficiency improvements made over time by manufacturers in the five process flow industries (cement and lime, aluminum, glass, iron and steel, and paper), which can change the mix of technologies chosen relative to the Reference Case. Prices and economic conditions are the same as in the Reference case. The energy efficiency increases are based on research by Lawrence Berkeley National Laboratory related to best practice energy intensity [7], and on Bandwidth Analysis by DOE [8]. This case includes more aggressive adoption of energy-efficient technologies and more rapid improvement in the energy intensity of some future technology choices that currently are not being used.
  • The Industrial Efficiency Low Incentive case examines the effects of a price on carbon emissions on energy efficiency in the industrial sector. This case includes all industries in the industrial sector except refining. It assumes a price on CO2 emissions, as a proxy for higher energy costs, stimulating an increase in energy efficiency. The CO2 price is phased in gradually, starting in 2018, rises to $12.50/metric ton in 2023, and thereafter increases by 5%/year through 2040. The higher energy costs create an incentive to reduce fuel costs by increasing the efficiencies of existing technologies, adopting more energy efficient technologies, and switching to less carbon-intensive fuels.
  • The Industrial Efficiency High Incentive case uses the same approach as the Industrial Efficiency Low Incentive case but assumes a higher price on CO2 emissions, starting in 2018, increasing gradually to $35.00/metric ton in 2023, and increasing thereafter increases by 5%/year. The higher energy costs increase the incentive to increase efficiency and use less carbonintensive fuels, leading to greater efficiency improvement than in the Reference and Industrial Efficiency Low Incentive cases.
  • The Extended Policies case described below is a cross-cutting integrated case that involves making changes in a number of NEMS models. The Extended Policies case modifies selected industrial assumptions from the Reference case, assuming that the existing 10% Investment Tax Credit (ITC) for industrial CHP is extended through 2040, modifying capacity limitations on the ITC by increasing the cap on CHP equipment from 15 MW to 25 MW, and eliminating the system-wide cap of 50 MW. These assumptions are based on the proposals made in H.R. 2750 and H.R. 2784 of the 112th Congress.

Transportation sector cases

In addition to the AEO2016 Reference case, the NEMS Transportation Demand Module was used as part of two AEO2016 alternative cases.

In the Extended Policies case, the Transportation Demand Module was used to examine the effects of extending LDV GHG emissions and CAFE standards beyond 2025, with the joint EPA/NHTSA CAFE Standards increasing after 2025, at an average annual rate of 1.3% through 2040, to a combined average LDV fuel economy compliance of 56.8 mpg in 2040. As part of the Extended Policies case, the Transportation Demand Module was also used to examine the effects of extending the HDV fuel efficiency and GHG emissions standards to reflect requirements under the Phase 2 Standards proposal. The regulations are currently specified for model years 2014 through 2018. The Extended Policies case includes a modest increase in fuel consumption and GHG emissions standards for 13 HDV size classes.

Assumptions in the NEMS Transportation Demand Module were modified for the Phase 2 Standards case, which examines the effects of the EPA/NHTSA jointly proposed GHG emissions and fuel efficiency standards for medium- and heavy-duty vehicles. The Phase 2 Standards case includes assumptions of improved technology options for medium- and heavy-duty vehicles by replacing and increasing the number of technologies from 37 to 70. The Phase 2 Standards case also includes restructured and updated vehicle size classes that increase the size classes from 13 to 14.

Electricity sector cases

While the Reference case includes one potential implementation of the CPP, there are uncertainties related to the options that states will use to comply with the rule. The rule is also being challenged in court, and the Supreme Court has stayed enforcement of the rule until legal challenges are resolved. To date, the rule has not been vacated or affirmed by any lower court ruling. Therefore, several integrated cases assuming alternate paths to meeting the CPP were developed to support discussions in the Market Trends and Issues in Focus section of AEO2016. A case was also developed assuming that the CPP is not implemented. The Issues in Focus article, "Effects of the Clean Power Plan," discusses the impacts of the CPP under different implementations relative to the mass-based standards assumed in the Reference case, and relative to the case without any CPP enforcement.

Clean Power Plan cases

  • The No CPP case assumes that the CPP is completely vacated and is not enforced, implying that states have no federal requirement to reduce CO2 emissions from existing power plants. There are no constraints imposed in the electricity model to reach regional rate-based or mass-based carbon dioxide targets (other than programs already in place, such as the Regional Greenhouse Gas Initiative (RGGI) and AB 32. There is no incentive for incremental energy efficiency in the end-use demand modules.
  • The CPP Rate case assumes that all regions choose to comply with the CPP by meeting average rate-based emissions goals (pounds/MWh) within each Electricity Market Module region, without cooperation across regions. That is, each region has a specific average emission rate that must be met by the affected generation in the region.
  • The CPP Interregional Trading case assumes that all regions choose to meet mass-based goals, covering existing and new sources (as in the Reference case), but with trading of carbon allowances between regions within the Eastern and Western Interconnects. In this case, regions that reduce emissions more than needed to meet their own regional caps may trade their excess allowances with other regions, allowing those regions to emit more than their caps.
  • The CPP Extended case further reduces the CO2 targets after 2030 instead of maintaining a constant standard. This case assumes that the mass-based limits in 2030, which will result in power sector CO2 emissions that are about 35% below 2005 levels, continue to decline linearly to achieve a 45% reduction below 2005 levels in 2040. The post-2030 reductions are applied using the same rate of decline for each state.
  • The CPP Hybrid case assumes that regions in which programs enforcing carbon caps are already in place (RGGI in the Northeast [9] and AB 32 in California) comply with the CPP through a mass-based goal, but that states in other regions implement the CPP using a rate-based approach. This case assumes no interregional trading for CPP compliance.
  • The CPP Allocation to Generators case assumes that all regions meet mass-based caps including new sources (as in the Reference case), but that the carbon allowances are freely allocated to generators, rather than to load-serving entities. In this case, it is assumed that generators in competitive regions will continue to include the value of allowances in their operating costs and, as a result, that marginal generation costs will reflect the costs of allowances. The Reference case assumes that the allowances are allocated to load-serving entities, which then refund the revenue from the allowance sales to consumers through lower distribution prices. The CPP Allocation to Generators case assumes no reduction in distribution costs, resulting in prices that are higher than those in the Reference case and showing the impact of allowance allocation alternatives on retail prices.

Extended Policies case

The Reference case includes the CPP, which under current regulations is phased in over the 2022–30 period, and assumes that states comply by setting mass-based compliance strategies that cover both existing and new electric generators. The Extended Policies case assumes a further reduction in CO2 targets after 2030. The mass-based limits, which in the Reference case result in power sector CO2 emissions that are 35% below 2005 levels in 2030, are assumed to continue declining linearly to 45% below 2005 levels in 2040.

Renewable fuels cases

AEO2016 also includes an Extended Policies case to examine the effects of indefinite extension of expiring federal tax credits for renewable electricity generation plants. In the Extended Policies case, the full tax credit of 2.3 cents/kWh (adjusted annually for inflation) is extended permanently beyond 2017 for new wind and geothermal generators and is available for the first 10 years of production. A tax credit of 1.1 cents/kWh, also available for the first 10 years of production, is extended indefinitely to new generators using landfill gas, certain hydroelectric technologies, and biomass fuels. (Open-loop biomass is assumed to be the predominant source of biomass fuel over the projection period.) Furthermore, this case maintains the permanent availability of the 30% ITC (the ITC’s value prior to phaseout) for new generators using solar energy.

Oil and natural gas supply cases

The sensitivity of the AEO2016 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 effects of higher and lower domestic supply on energy demand, imports, and prices. Assumptions associated with the two cases are described below.

  • In the Low Oil and Gas Resource and Technology case, the estimated ultimate recovery per tight oil, tight gas, or shale gas well in the United States and undiscovered resources in Alaska and the offshore lower 48 states are assumed to be 50% lower than in the Reference case. Rates of technology improvement that reduce costs and increase productivity in the United States also are 50% lower than in the Reference case. These assumptions increase the per-unit cost of crude oil and natural gas development in the United States. The total unproved technically recoverable resource of crude oil is decreased to 150 billion barrels, and the natural gas resource is decreased to 1,303 trillion cubic feet (Tcf), as compared with unproved resource estimates of 238 billion barrels of crude oil and 2,136 Tcf of natural gas as of January 1, 2014, in the Reference case.
  • In the High Oil and Gas Resource and Technology case, the resource assumptions are adjusted to allow a continued increase in domestic crude oil production through 2040, to 18 million barrels per day (b/d) compared with 11 million b/d in the Reference case. This case includes: (1) 50% higher estimated ultimate recovery per tight oil, tight gas, or shale gas well, as well as additional unidentified tight oil and shale gas resources to reflect the possibility that additional layers or new areas of low-permeability zones will be identified and developed; (2) diminishing returns on the estimated ultimate recovery once drilling levels in a county exceed the number of potential wells assumed in the Reference case, to reflect well interference at greater drilling density; (3) 50% higher assumed rates of technological improvement that reduce costs and increase productivity in the United States relative to the Reference case; and (4) 50% higher technically recoverable undiscovered resources in Alaska and the offshore lower 48 states than in the Reference case. The total unproved technically recoverable resource of crude oil increases to 385 billion barrels, and the natural gas resource increases to 3,109 Tcf as compared with unproved resource estimates of 238 billion barrels of crude oil and 2,136 Tcf of natural gas in the Reference case as of the start of 2014.

Extended Policies case

In addition to the AEO2016 Reference case, the AEO2016 Extended Policies case assumes the extension of all existing tax credits and policies that contain sunset provisions at current levels, except those requiring additional funding (e.g., loan guarantee programs). The Extended Policies case also assumes an increase in the capacity limitations on the ITC for CHP, and extension of the program. It includes an additional round of federal efficiency standards for residential and commercial products, as well as new standards for products not yet covered; adds multiple rounds of national building codes by 2034; and increases LDV and HDV fuel economy standards in the transportation sector. The Extended Policies case also assumes continued tightening of EPA's Clean Power Plan regulations that reduce carbon dioxide emissions from electric power generation after 2030. Specific assumptions for each end-use sector and for renewables are described in the sector-specific sections above.

 

Endnotes

  1. U.S. Energy Information Administration, The National Energy Modeling System: An Overview 2009, DOE/EIA-0581(2009) (Washington, DC: October 2009), http://www.eia.gov/forecasts/aeo/nems/overview/pdf/0581(2009).pdf.
  2. Selected EIA publications used for data sources include: Short-Term Energy Outlook, Monthly Energy Review, Natural Gas Annual, Natural Gas Monthly, Electric Power Monthly, Electric Power Annual, Annual Coal Report, Petroleum Supply Annual, and Quarterly Coal Report, as well as EIA surveys.
  3. U.S. Energy Information Administration, Short-Term Energy Outlook (Washington, DC: February 2016), http://www.eia.gov/forecasts/steo/outlook.cfm.
  4. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2016, DOE/EIA-0554(2016) (Washington, DC: forthcoming Fall 2016), http://www.eia.gov/forecasts/aeo/assumptions.
  5. U.S. Energy Information Administration, Effects of Removing Restrictions on U.S. Crude Oil Exports (Washington, DC: September 2015), http://www.eia.gov/analysis/requests/crude-exports/.
  6. U.S. Energy Information Administration, Effects of Removing Restrictions on U.S. Crude Oil Exports (Washington, DC: September 2015), http://www.eia.gov/analysis/requests/crude-exports/.
  7. E. Worrell, L. Price, M. Neelis, C. Galitsky, and Z. Nan, World Best Practice Energy Intensity Values for Selected Industrial Sectors, LBNL-62806, Rev. 2 (Ernest Orlando Lawrence Berkeley National Laboratory, Berkeley, CA: February 2008), https://eaei.lbl.gov/sites/all/files/industrial_best_practice_en.pdf.
  8. D.M. Rue, J. Servaites, and W. Wolfe, Final Report: Industrial Glass Bandwidth Analysis (Gas Technology Institute, Des Plains, IL: August 2007, http://www.energy.gov/sites/prod/files/2013/11/f4/industrial_bandwidth.pdf.
  9. The CPP Hybrid case assumes that the New York and New England electricity regions use mass-based compliance. Delaware and Maryland are also members of RGGI; however, those states are part of a larger electricity modeling region including states that are not part of RGGI, and they represent a relatively small share of the overall region's emissions. Because CPP compliance is modeled by electricity model region, not by state, the CPP Hybrid case assumes that the region that includes Delaware and Maryland complies by using a rate-based approach.