North Mountain Nursery

The Annual Energy Outlook 2013 (AEO2013) was prepared by the U. S. Energy Information Administration (EIA), under the direction of John J. Conti (john. [email protected] gov, 202/586-2222), Assistant Administrator of Energy Analysis; Paul D. Holtberg (paul. [email protected] eia. gov, 202/586-1284), Team Leader, Analysis Integration Team, Office of Integrated and International Energy Analysis; Joseph A.

Beamon (joseph. [email protected] gov, 202/586-2025), Director, Office of Electricity, Coal, Nuclear, and Renewables Analysis; Sam A. Napolitano (sam. [email protected] gov, 202/586-0687), Director, Office of Integrated and International Energy Analysis; A. Michael Schaal (michael. [email protected] gov, 202/586-5590), Director, Office of Petroleum, Natural Gas, and Biofuels Analysis; and James T. Turnure (james. [email protected] gov, 202/586-1762), Director, Office of Energy Consumption and Efficiency Analysis.

Complimentary copies are available to certain groups, such as public and academic libraries; Federal, State, local, and foreign governments; EIA survey respondents; and the media. For further information and answers to questions, contact: Office of Communications, EI-40 Forrestal Building, Room 1E-210 1000 Independence Avenue, S. W. Washington, DC 20585 Telephone: 202/586-8800 (24-hour automated information line) E-mail: [email protected] gov Fax: 202/586-0727 Website: www. eia. gov Specific questions about the information in this report may be directed to:

Paul Holtberg (paul. [email protected] gov, 202-586-1284) Dan Skelly (daniel. [email protected] gov, 202-586-2222) Paul Holtberg (paul. [email protected] gov, 202/586-1284) Kay Smith (kay. [email protected] gov, 202/586-1132) William Brown (william. [email protected] gov, 202/586-8181) James O’Sullivan (james. [email protected] gov, 202/586-2728) Linda E. Doman (linda. [email protected] gov, 202/586-1041) Owen Comstock (owen. [email protected] gov, 202/586-4752) Kevin Jarzomski (kevin. [email protected] gov, 202/586-3208) Kelly Perl ([email protected] gov, 202/586-1743) John Maples (john. [email protected] gov, 202/586-1757) Jeff Jones (jeffrey. [email protected] gov, 202/586-2038) Michael Leff (michael. [email protected] gov, 202/586-1297) Lori Aniti (lori. [email protected] gov, 202/586-2867) Laura Martin (laura. [email protected] gov, 202/586-1494) Chris Namovicz (chris. [email protected] gov, 202/586-7120) Philip Budzik (philip. [email protected] gov, 202/586-2847) Katherine Teller (katherine. [email protected] gov, 202/586-6201) Arup Malik (arup. [email protected] ov, 202/586-7713) Mac Statton (mac. [email protected] gov, 202/586-7105) Michael Mellish (michael. [email protected] gov, 202/586-2136) Perry Lindstrom (perry. [email protected] gov, 202/586-0934) The AEO2013 is available on the EIA website at www. eia. gov/forecasts/aeo. Assumptions underlying the projections, tables of regional results, and other detailed results will also be available, at www. eia. gov/forecasts/aeo/assumptions. Model documentation reports for the National Energy Modeling System are available at website www. eia. gov/analysis/model-documentation. cfm and will be updated for the AEO2013 during 2013.

Other contributors to the report include Michelle Adams, Vipin Arora, Joseph Ayoub, Justine Barden, Bruce Bawks, Joseph Benneche, Erin Boedecker, Gwendolyn Bredehoeft, Nicholas Chase, Michael Cole, Jim Diefenderfer, Robert Eynon, Laurie Falter, Mindi Farber-DeAnda, Patrick Farace, Adrian Geagla, Susan Grissom, Peter Gross, James Hewlett, Susan Hicks, Sean Hill, Behjat Hojjati, Patricia Hutchins, Ayaka Jones, Jim Joosten, Diane Kearney, Paul Kondis, Angelina LaRose, Thomas Lee, Tanc Lidderdale, Vishakh Mantri, Elizabeth May, Carrie Milton, Paul Otis, Stefanie Palumbo, David Peterson, Chetha Phang, John Powell, Marie Rinkoski Spangler, Mark Schipper, Elizabeth Sendich, Nancy Slater-Thompson, Robert Smith, John Staub, Russell Tarver, Dana Van Wagener, and Steven Wade. Annual Energy Outlook 2013 With Projections to 2040

April 2013 U. S. Energy Information Administration Office of Integrated and International Energy Analysis U. S. Department of Energy Washington, DC 20585 This publication is on the WEB at: www. eia. gov/forecasts/aeo This report was prepared by the U. S. Energy Information Administration (EIA), the statistical and analytical agency within the U. S. Department of Energy. By law, EIA’s data, analyses, and forecasts are independent of approval by any other officer or employee of the United States Government. The views in this report therefore should not be construed as representing those of the Department of Energy or other Federal agencies. Preface

The Annual Energy Outlook 2013 (AEO2013), prepared by the U. S. Energy Information Administration (EIA), presents long-term projections of energy supply, demand, and prices through 2040, based on results from EIA’s National Energy Modeling System. EIA published an “early release” version of the AEO2013 Reference case in December 2012. The report begins with an “Executive summary” that highlights key aspects of the projections. It is followed by a “Legislation and regulations” section that discusses evolving legislative and regulatory issues, including a summary of recently enacted legislation and regulations, such as: Updated handling of the U. S.

Environmental Protection Agency’s (EPA) National Emissions Standards for Hazardous Air Pollutants for industrial boilers and process heaters [1]; New light-duty vehicle (LDV) greenhouse gas (GHG) and corporate average fuel economy (CAFE) standards for model years 2017 to 2025 [2]; Reinstatement of the Clean Air Interstate Rule (CAIR) [3] after the court’s announcement of intent to vacate the Cross-State Air Pollution Rule (CSAPR) [4]; and Modeling of California’s Assembly Bill 32, the Global Warming Solutions Act (AB 32) [5], which allows for representation of a cap-and-trade program developed as part of California’s GHG reduction goals for 2020.

The “Issues in focus” section contains discussions of selected energy topics, including a discussion of the results in two cases that adopt different assumptions about the future course of existing policies, with one case assuming the elimination of sunset provisions in existing policies and the other case assuming the elimination of the sunset provisions and the extension of a selected group of existing public policies—CAFE standards, appliance standards, and production tax credits. Other discussions include: oil price and production trends in AEO2013; U. S. reliance on imported liquids under a range of cases; competition between coal and natural gas in electric power generation; high and low nuclear scenarios through 2040; and the impact of growth in natural gas liquids production. The “Market trends” section summarizes the projections for energy markets.

The analysis in AEO2013 focuses primarily on a Reference case, Low and High Economic Growth cases, and Low and High Oil Price cases. Results from a number of other alternative cases also are presented, illustrating uncertainties associated with the Reference case projections for energy demand, supply, and prices. Complete tables for the five primary cases are provided in Appendixes A through C. Major results from many of the alternative cases are provided in Appendix D. Complete tables for all the alternative cases are available on EIA’s website in a table browser at http://www. eia. gov/oiaf/aeo/tablebrowser. AEO2013 projections are based generally on federal, state, and local laws and regulations in effect as of the end of September 2012.

The potential impacts of pending or proposed legislation, regulations, and standards (and sections of existing legislation that require implementing regulations or funds that have not been appropriated) are not reflected in the projections. In certain situations, however, where it is clear that a law or regulation will take effect shortly after the Annual Energy Outlook (AEO) is completed, it may be considered in the projection. AEO2013 is published in accordance with Section 205c of the U. S. Department of Energy (DOE) Organization Act of 1977 (Public Law 95-91), which requires the EIA Administrator to prepare annual reports on trends and projections for energy use and supply. Projections by the U. S.

Energy Information Administration (EIA) are not statements of what will happen but of what might happen, given the assumptions and methodologies used for any particular scenario. The Annual Energy Outlook 2013 (AEO2013) Reference case projection is a business-as-usual trend estimate, given known technology and technological and demographic trends. EIA explores the impacts of alternative assumptions in other scenarios with different macroeconomic growth rates, world oil prices, and rates of technology progress. The main cases in AEO2013 generally assume that current laws and regulations are maintained throughout the projections. Thus, the projections provide policy-neutral baselines that can be used to analyze policy initiatives.

While energy markets are complex, energy models are simplified representations of energy production and consumption, regulations, and producer and consumer behavior. Projections are highly dependent on the data, methodologies, model structures, and assumptions used in their development. Behavioral characteristics are indicative of real-world tendencies rather than representations of specific outcomes. Energy market projections are subject to much uncertainty. Many of the events that shape energy markets are random and cannot be anticipated. In addition, future developments in technologies, demographics, and resources cannot be foreseen with certainty. Many key uncertainties in the AEO2013 projections are addressed through alternative cases. EIA has ndeavored to make these projections as objective, reliable, and useful as possible; however, they should serve as an adjunct to, not a substitute for, a complete and focused analysis of public policy initiatives. ii U. S. Energy Information Administration | Annual Energy Outlook 2013 Updated Annual Energy Outlook 2013 Reference case (April 2013) The AEO2013 Reference case included as part of this complete report, released in April 2013, was updated from the AEO2012 Reference case released in June 2012. The Reference case was updated to reflect new legislation or regulation enacted since that time or to incorporate modeling changes. Major changes made in the Reference case include: • Extension of the projection period through 2040, an additional five years beyond AEO2012. Adoption of a new Liquid Fuels Market Module (LFMM) in place of the Petroleum Market Module used in earlier AEOs provides for more granular and integrated modeling of petroleum refineries and all other types of current and potential future liquid fuels production technologies. This allows more direct analysis and modeling of the regional supply and demand effects involving crude oil and other feedstocks, current and future processes, and marketing to consumers. • A shift to the use of Brent spot price as the reference oil price. AEO2013 also presents the average West Texas Intermediate spot price of light, low-sulfur crude oil delivered in Cushing, Oklahoma, and includes the U. S. nnual average refiners’ acquisition cost of imported crude oil, which is more representative of the average cost of all crude oils used by domestic refiners. • A shift from using regional natural gas wellhead prices to using representative regional natural gas spot prices as the basis of the natural gas supply price. Due to this change, the methodology for estimating the Henry Hub price was revised. • Updated handling of data on flex-fuel vehicles (FFVs) to better reflect consumer preferences and industry response. FFVs are necessary to meet the renewable fuels standard, but the phasing out of CAFE credits for their sale and limited demand from consumers reduce their market penetration. A revised outlook for industrial production to reflect the impacts of increased shale gas production and lower natural gas prices, which result in faster growth for industrial production and energy consumption. The industries affected include, in particular, bulk chemicals and primary metals. • Incorporation of a new aluminum process flow model in the industrial sector, which allows for diffusion of technologies through choices made among known commercial and emerging technologies based on relative capital costs and fuel expenditures and provides for a more realistic representation of the evolution of energy consumption than in previous AEOs. An enhanced industrial chemical model, in several respects: the baseline liquefied petroleum gas (LPG) feedstock data have been aligned with 2006 survey data; use of an updated propane-pricing mechanism that reflects natural gas price influences in order to allow for price competition between LPG feedstock and petroleum-based (naphtha) feedstock; and specific accounting in the Industrial Demand Model for propylene supplied by the LFMM. • Updated handling of the EPA’s National Emissions Standards for Hazardous Air Pollutants for industrial boilers and process heaters to address the maximum degree of emissions reduction using maximum achievable control technology. An industrial capital expenditure and fuel price adjustment for coal and residual fuel has been applied to reflect risk perception about the use of those fuels relative to natural gas. Augmentation of the construction and mining models in the Industrial Demand Model to better reflect AEO2013 assumptions regarding energy efficiencies in off-road vehicles and buildings, as well as the productivity of coal, oil, and natural gas extraction. • Adoption of final model year 2017 to 2025 GHG emissions and CAFE standards for LDVs, which increases the projected fuel economy of new LDVs to 47. 3 mpg in 2025. • Updated handling of the representation of purchase decisions for alternative fuels for heavy-duty vehicles. Market factors used to calculate the relative cost of alternative-fuel vehicles, specifically natural gas, now represent first buyer-user behavior and slightly longer breakeven payback periods, significantly increasing the demand for natural gas fuel in heavy trucks. Updated modeling of LNG export potential, which includes a rudimentary assessment of pricing of natural gas in international markets. • Updated power generation unit costs that capture recent cost declines for some renewable technologies, which tend to lead to greater use of renewable generation, particularly solar technologies. • Reinstatement of CAIR after the court’s announcement of intent to vacate CSAPR. • Modeling of California’s AB 32, that allows for representation of a cap-and-trade program developed as part of California’s GHG reduction goals for 2020. The coordinated regulations include an enforceable GHG cap that will decline over time. AEO2013 reflects all covered sectors, including emissions offsets and allowance allocations. Incorporation of the California Low Carbon Fuel Standard, which requires fuel producers and importers who sell motor gasoline or diesel fuel in California to reduce the carbon intensity of those fuels by 10 percent between 2012 and 2020 through the increased sale of alternative low-carbon fuels. Future analyses using the AEO2013 Reference case will start from the version of the Reference case released with this complete report. U. S. Energy Information Administration | Annual Energy Outlook 2013 iii Endnotes for Preface Links current as of March 2013 1. U. S. Government Printing Office, “Clean Air Act,” 42 U. S. C. 7412 (Washington, DC: 2011), http://www. gpo. gov/fdsys/pkg/ USCODE-2011-title42/pdf/USCODE-2011-title42-chap85-subchapI-partA. pdf. 2.

U. S. Environmental Protection Agency and Department of Transportation, National Highway Traffic Safety Administration, “2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule,” Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www. federalregister. gov/ articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporateaverage-fuel. 3. U. S. Environmental Protection Agency, “Clean Air Interstate Rule (CAIR)” (Washington, DC: December 19, 2012), http://www. epa. gov/cair/index. html#older. 4. U. S.

Environmental Protection Agency, “Fact Sheet: The Cross-State Air Pollution Rule: Reducing the Transport of Fine Particulate Matter and Ozone” (Washington, DC: July 2011), http://www. epa. gov/airtransport/pdfs/CSAPRFactsheet. pdf. 5. California Legislative Information, “Assembly Bill No. 32: California Global Warming Solutions Act of 2006” (Sacramento, CA: September 27, 2006), http://www. leginfo. ca. gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered. pdf. iv U. S. Energy Information Administration | Annual Energy Outlook 2013 Contents Preface ………………………………………………………………………………………………………………………………………………………………………………………

Updated Annual Energy Outlook 2013 Reference case (April 2013)……………………………………………………………………………………………. Executive summary…………………………………………………………………………………………………………………………………………………………………… Legislation and regulations……………………………………………………………………………………………………………………………………………………….. Introduction ……………………………………………………………………………………………………………………………………………………………………… 1.

Greenhouse gas emissions and corporate average fuel economy standards for 2017 and later model year light-duty vehicles………………………………………………………………………………………………………………………………………………………. 2. Recent rulings on the Cross-State Air Pollution Rule and the Clean Air Interstate Rule …………………………………………… 3. NuclearwastedisposalandtheWasteConfidenceRule ………………………………………………………………………………………….. 4. Maximum Achievable Control Technology for industrial boilers ………………………………………………………………………………… 5.

State renewable energy requirements and goals: Update through 2012 …………………………………………………………………… 6. California Assembly Bill 32: Emissions cap-and-trade as part of the Global Warming Solutions Act of 2006 ………….. 7. California low carbon fuel standard …………………………………………………………………………………………………………………………… Issues in focus …………………………………………………………………………………………………………………………………………………………………………..

Introduction ……………………………………………………………………………………………………………………………………………………………………… 1. No Sunset and Extended Policies cases …………………………………………………………………………………………………………………… 2. Oil price and production trends in AEO2013 ……………………………………………………………………………………………………………… 3. U. S. reliance on imported liquid fuels in alternative scenarios ………………………………………………………………………………….. 4.

Competition between coal and natural gas in the electric power sector ……………………………………………………………………. 5. Nuclear power in AEO2013 ……………………………………………………………………………………………………………………………………….. 6. Effect of natural gas liquids growth ……………………………………………………………………………………………………………………………. Market trends ……………………………………………………………………………………………………………………………………….. ………………………………….

Trends in economic activity……………………………………………………………………………………………………………………………………………… Energy trends in the economy…………………………………………………………………………………………………………………………………………. International energy…………………………………………………………………………………………………………………………………………………………. U. S. energy demand ………………………………………………………………………………………………………………………………………………………..

Residential sector energy demand ………………………………………………………………………………………………………………………………….. Commercial sector energy demand ………………………………………………………………………………………………………………………………… Industrial sector energy demand …………………………………………………………………………………………………………………………………….. Transportation sector energy demand ……………………………………………………………………………………………………………………………..

Electricity demand …………………………………………………………………………………………………………………………………………………………… Electricity generation ………………………………………………………………………………………………………………………………………………………. Electricity sales ……………………………………………………………………………………………………………………………………………………………….. Electricity capacity…………………………………………………………… ………………………………………………………………………………………………

Renewable generation …………………………………………………………………………………………………………………………………………………….. Natural gas consumption…………………………………………………………………………………………………………………………………………………. Natural gas prices……………………………………………………………………………………………………………………………………………………………. Natural gas production……………………………………………………………………………………………………………………………………………………..

Natural gas supply …………………………………………………………………………………………………………………………………………………………… Petroleum and other liquids consumption ……………………………………………………………………………………………………………………….. Petroleum and other liquids supply …………………………………………………………………………………………………………………………………. Coal production ………………………………………………………………………………………………………………………………………………………………..

Emissions from energy use …………………………………………………………………………………………………………………………………………….. Comparison with other projections ………………………………………………………………………………………………………………………………………….. 1. Economic growth ……………………………………………………………………………………………………………………………………………………….. 2. Oil prices ……………………………………………………………………………………………………………………………………………………………………. 3.

Total energy consumption………………………………………………………………………………………………………………………………………….. 4. Electricity …………………………………………………………………………………………………………………………………………………………………… 5. Natural gas ………………………………………………………………………………………………………………………………………………………………… 6. Liquid fuels ………………………………………………………………………………………………………………………………………………………………… 7.

Coal……………………………………………………………………………………………………………………………………………………………………………. ii iii 1 7 8 8 10 10 12 13 18 18 23 24 24 30 32 39 44 48 55 56 57 58 59 61 63 65 68 71 72 73 74 75 76 77 78 79 80 81 85 87 91 92 93 93 95 100 103 103 List of acronyms ……………………………………………………………………………………………………………………………………………………………………….. 111 Notes and sources ……………………………………………………………………………………………………………………………………………………………………. 112

U. S. Energy Information Administration | Annual Energy Outlook 2013 v Contents Appendixes A. Reference case………………………………………………………………………………………………………………………………………………………….. B. Economic growth case comparisons …………………………………………………………………………………………………………………………. C. Price case comparisons …………………………………………………………………………………………………………………………………………….. D.

Results from side cases …………………………………………………………………………………………………………………………………………….. E. NEMS overview and brief description of cases …………………………………………………………………………………………………………. F. Regional Maps …………………………………………………………………………………………………………………………………………………………… G. Conversion factors …………………………………………………………………………………………………………………………………………………….. 121 161 171 186 209 225 233 Tables Legislation and regulations 1.

HTSAprojectedaveragefleet-wideCAFEcompliancelevelsforpassengercarsandlight-dutytrucks, N modelyears2017-2025,basedonthemodelyear2010baselinefleet ……………………………………………………………………. 9 2. AEO2013 projectedaveragefleet-wideCAFEcompliancelevelsforpassengercarsandlight-dutytrucks, model years 2017-2025 …………………………………………………………………………………………………………………………………………….. 10 3. Renewable portfolio standards in the 30 states and District of Columbia with current mandates …………………………….. 14 Issues in focus 4. Key analyses from “Issues in focus” in recent AEOs …………………………………………………………………………………………………. 5.

Differences in crude oil and natural gas assumptions across three cases ……………………………………………………………….. 6. Differences in transportation demand assumptions across three cases …………………………………………………………………… 7. ProposedadditionsofU. S. ethyleneproductioncapacity,2013-2020 ………………………………………………………………………. Comparison with other projections 8. Comparisonsofaverageannualeconomicgrowthprojections,2011-2040 ………………………………………………………………. 9. Comparisonsofoilpriceprojections,2025,2035,and2040 …………………………………………………………………………………….. 10.

Comparisonsofenergyconsumptionbysectorprojections,2025,2035,and2040 …………………………………………………. 11. Comparisonsofelectricityprojections,2025,2035,and2040………………………………………………………………………………….. 12. Comparisonsofnaturalgasprojections,2025,2035,and2040 ……………………………………………………………………………….. 13. Comparisonsofliquidsprojections,2025,2035,and2040 ………………………………………………………………………………………. 14. Comparisonsofcoalprojections,2025,2035,and2040 ………………………………………………………………………………………….. 4 34 37 50 92 93 94 96 100 104 106 Appendix E E1. Summary of the AEO2013 cases ………………………………………………………………………………………………………………………………. 215 Figures Executive summary 1. NetimportshareofU. S. liquidssupplyintwocases,1970-2040 ……………………………………………………………………………… 2. TotalU. S. naturalgasproduction,consumption,andnetimportsintheReferencecase,1990-2040 ……………………… 3. Electricitygenerationfromcoalandnaturalgasintwocases,2008-2040………………………………………………………………. 4.

Coalandnaturalgasuseintheelectricpowersectorinthreecases,2011,2025,and2040 …………………………………… 5. Energy-relatedcarbondioxideemissionsinfourcases,2000-2040 ………………………………………………………………………… 6. Transportationenergyconsumptionbyfuel,1990-2040 …………………………………………………………………………………………… 7. U. S. drynaturalgasconsumptionbysector,2005-2040 …………………………………………………………………………………………… 8. RenewableenergyshareofU. S. electricitygenerationinfivecases,2000-2040…………………………………………………….. 2 3 4 4 4 5 5 6 Legislation and regulations 9.

ProjectedaveragepassengercarCAFEcompliancetargetsbyvehiclefootprint,modelyears2017-2025 ……………… 9 10. Projectedaveragelight-dutytruckCAFEcompliancetargetsbyvehiclefootprint,modelyears2017-2025 …………….. 9 11. States covered by CAIR limits on emissions of sulfur dioxide and nitrogen oxides …………………………………………………… 11 12. Total renewable generation required for combined state renewable portfolio standards and projected totalachieved,2012-2040 ………………………………………………………………………………………………………………………………………….. 13 Issues in focus 13.

Totalenergyconsumptioninthreecases,2005-2040 ………………………………………………………………….. ………………………….. 14. Consumptionofpetroleumandotherliquidsfortransportationinthreecases,2005-2040 ……………………………………… 15. Renewableelectricitygenerationinthreecases,2005-2040 ……………………………………………………………………………………. 16. Renewableelectricitygenerationintwocases,2012-2040 ………………………………………………………………………………………. 17. Electricitygenerationfromnaturalgasinthreecases,2005-2040 …………………………………………………………………………… vi U. S.

Energy Information Administration | Annual Energy Outlook 2013 26 27 27 28 29 Contents 18. Energy-relatedcarbondioxideemissionsinthreecases,2005-2040 ………………………………………………………………………. 19. Averagedeliveredpricesfornaturalgasinthreecases,2005-2040 ………………………………………………………………………… 20. Averageelectricitypricesinthreecases,2005-2040 ……………………………………………………………………………………………….. 21. AnnualaveragespotpriceforBrentcrudeoilinthreecases,1990-2040 ………………………………………………………………… 22.

Worldpetroleumandotherliquidssupplyinthreecases,1990-2040 ………………………………………………………………………. 23. WorldpetroleumandotherliquidssupplybysourceintheReferencecase,1990-2040………………………………………….. 24. Netimportshareofliquidfuelsinfivecases,2005-2040 ………………………………………………………………………………………….. 25. U. S. carbondioxideemissionsinfivecases,2005-2040 ………………………………………………………………………………………….. 26. AveragedeliveredfuelpricestoelectricpowerplantsintheReferencecase,2008-2040……………………………………….. 27. tioofaveragepermegawatthourfuelcostsfornaturalgascombined-cycleplantstocoal-fired R steamturbinesinfivecases,2008-2040 …………………………………………………………………………………………………………………… 28. Powersectorelectricitygenerationcapacitybyfuelinfivecases,2011and2025 …………………………………………………… 29. Powersectorelectricitygenerationcapacitybyfuelinfivecases,2011and2040 …………………………………………………… 30. Powersectorelectricitygenerationbyfuelinfivecases,2011and2025………………………………………………………………….. 31. Powersectorelectricitygenerationbyfuelinfivecases,2011and2040 …………………………………………………………………. 32.

Powersectorelectricitygenerationfromcoalandnaturalgasintwocases,2008-2040 …………………………………………. 33. atioofaveragepermegawatthourfuelcostsfornaturalgascombined-cycleplantstocoal-fired R steamturbinesintheSERCsoutheastsubregioninfivecases,2008-2040 …………………………………………………………….. 34. atioofaveragepermegawatthourfuelcostsfornaturalgascombined-cycleplantstocoal-fired R steamturbinesintheRFCwestsubregioninfivecases,2008-2040 ……………………………………………………………………….. 35. Nuclearcapacityadditionsinfivecases,2011-2040 …………………………………………………………………………………………………. 36.

Electricitygenerationfromnaturalgasinthreecases,2005-2040 …………………………………………………………………………… 37. Carbondioxideemissionsfromelectricitygenerationinthreecases,2005-2040 ……………………………………………………. 38. Levelizedcostsofnuclearelectricitygenerationintwocases,2025 ………………………………………………………………….. ……. 39. U. S. productionofnaturalgasliquidsbytype,2005-2012 ………………………………………………………………………………………… 40. U. S. importsandexportsofpropane/propylene,2005-2012 …………………………………………………………………………………….. 41. U. S.

BrentcrudeoilandHenryHubnaturalgasspotmarketpricesinthreecases,2005-2040………………………………. 42. U. S. productionofdrynaturalgasandnaturalgasplantliquidsinthreecases,2005-2040 …………………………………….. 43. U. S. netexportsofliquefiedpetroleumgasesinthreecases,2011-2040…………………………………………………………………. 29 30 30 31 31 31 37 39 40 41 41 41 42 42 43 43 44 47 47 48 48 49 49 50 50 51 56 56 57 57 57 58 58 59 59 60 60 61 61 62 62 63 63 64 64 65 65 66 66 67 67 68 68 69 69 70 Market trends 44. AverageannualgrowthratesofrealGDP,laborforce,andproductivityinthreecases,2011-2040 …………………………. 45.

Averageannualgrowthratesforrealoutputanditsmajorcomponentsinthreecases,2011-2040 …………………………. 46. Sectoralcompositionofindustrialshipments,annualgrowthratesinthreecases,2011-2040 ………………………………… 47. Energyend-useexpendituresasashareofgrossdomesticproduct,1970-2040 …………………………………………………….. 48. Energyend-useexpendituresasashareofgrossoutput,1987-2040 ………………………………………………………………………. 49. Brentcrudeoilspotpricesinthreecases,1990-2040 ………………………………………………………………………………………………. 50.

Worldpetroleumandotherliquidsconsumptionbyregioninthreecases,2011and2040 ………………………………………. 51. Worldproductionofliquidsfrombiomass,coal,andnaturalgasinthreecases,2011and2040……………………………… 52. Energyusepercapitaandperdollarofgrossdomesticproduct,1980-2040 …………………………………………………………… 53. Primaryenergyusebyend-usesector,2011-2040 …………………………………………………………………………………………………… 54. Primaryenergyusebyfuel,1980-2040 …………………………………………………………………………………………………………………….. 55.

Residentialdeliveredenergyintensityinfourcases,2005-2040 ………………………………………………………………………………. 56. ChangeinresidentialelectricityconsumptionforselectedendusesintheReferencecase,2011-2040 …………………. 57. Changeinresidentialdeliveredenergyconsumptionforselectedendusesinfourcases,2011-2040 …………………….. 58. Residentialsectoradoptionofrenewableenergytechnologiesintwocases,2005-2040 ………………………………………… 59. Commercialdeliveredenergyintensityinfourcases,2005-2040 …………………………………………………………………………….. 60.

Energyintensityofselectedcommercialelectricenduses,2011and2040 ……………………………………………………………… 61. Efficiencygainsforselectedcommercialequipmentinthreecases,2040 ……………………………………………………………….. 62. Additionstoelectricitygenerationcapacityinthecommercialsectorintwocases,2011-2040 ……………………………….. 63. Industrialdeliveredenergyconsumptionbyapplication,2011-2040 …………………………………………………………………………. 64. Industrialenergyconsumptionbyfuel,2011,2025,and2040 …………………………………………………………………………………… 65.

Cumulativegrowthinvalueofshipmentsfromenergy-intensiveindustriesinthreecases,2011-2040 ……………………. 66. Changeindeliveredenergyconsumptionforenergy-intensiveindustriesinthreecases,2011-2040………………………. 67. umulativegrowthinvalueofshipmentsfromenergy-intensiveindustries,2011 -2040,2011-2025, C and 2025-2040…………………………………………………………………………………………………………………………………………………………… 68. Cumulativegrowthinvalueofshipmentsfromnon-energy-intensiveindustriesinthreecases,2011-2040 …………….. 69. Changeindeliveredenergyconsumptionfornon-energy-intensiveindustriesinthreecases,2011-2040 ………………. 70.

Deliveredenergyconsumptionfortransportationbymode,2011and2040…………………………………………………………….. 71. Averagefueleconomyofnewlight-dutyvehicles,1980-2040 ………………………………………………………………………………….. 72. Vehiclemilestraveledperlicenseddriver,1970-2040 ………………………………………………………………………………………………. 73. Salesoflight-dutyvehiclesusingnon-gasolinetechnologiesbytype,2011,2025,and2040 ………………………………….. U. S. Energy Information Administration | Annual Energy Outlook 2013 vii Contents 74.

Naturalgasconsumptioninthetransportationsector,1995-2040 ……………………………………………………………………………. 75. U. S. electricitydemandgrowth,1950-2040 ………………………………………………………………………………………………………………. 76. Electricitygenerationbyfuel,2011,2025,and2040 …………………………………………………………………………………………………. 77. Electricitygenerationcapacityadditionsbyfueltype,includingcombinedheatandpower,2012-2040…………………… 78. Additionstoelectricitygeneratingcapacity,1985-2040 ………………………………………………………………….. ……………………….. 79.

Electricitysalesandpowersectorgeneratingcapacity,1949-2040………………………………………………………………………….. 80. Levelizedelectricitycostsfornewpowerplants,excludingsubsidies,2020and2040 …………………………………………….. 81. ElectricitygeneratingcapacityatU. S. nuclearpowerplantsinthreecases,2011,2025,and2040…………………………. 82. Renewableelectricitygenerationcapacitybyenergysource,includingend-usecapacity,2011-2040…………………….. 83. Renewableelectricitygenerationbytype,includingend-usegeneration,2008-2040 …………………………………………….. 84.

Regionalnonhydropowerrenewableelectricitygeneration,includingend-usegeneration,2011and2040 …………….. 85. Naturalgasconsumptionbysector,1990-2040 ………………………………………………………………………………………………………… 86. AnnualaverageHenryHubspotnaturalgasprices,1990-2040 ………………………………………………………………………………. 87. RatioofBrentcrudeoilpricetoHenryHubspotnaturalgaspriceinenergy-equivalentterms,1990-2040 …………….. 88. AnnualaverageHenryHubspotpricesfornaturalgasinfivecases,1990-2040 …………………………………………………….. 89. TotalU. S. aturalgasproduction,consumption,andnetimports,1990-2040 ………………………………………………………….. 90. TotalU. S. naturalgasproductioninthreeoilpricecases,1990-2040………………………………………………………………………. 91. Naturalgasproductionbysource,1990-2040…………………………………………………………………………………………………………… 92. U. S. netimportsofnaturalgasbysource,1990-2040 ………………………………………………………………………………………………. 93. Consumptionofpetroleumandotherliquidsbysector,1990-2040 ………………………………………………………………………….. 94. U. S. roductionofpetroleumandotherliquidsbysource,2011-2040 ………………………………………………………………………. 95. TotalU. S. crudeoilproductioninthreeresourcecases,1990-2040 ………………………………………………………………………… 96. Domesticcrudeoilproductionbysource,2000-2040 ……………………………………………………………………………………………….. 97. TotalU. S. tightoilproductionbygeologicformation,2008-2040………………………………………………………………………………. 98. APIgravityofU. S. domesticandimportedcrudeoilsupplies,1990-2040 ……………………………………………………………….. 99. NetimportshareofU. S. etroleumandotherliquidsconsumptioninthreeoilpricecases,1990-2040 ………………….. 100. EISA2007RFScreditsearnedinselectedyears,2011-2040 ……………………………………………………………………………………. 101. Consumptionofadvancedrenewablefuels,2011-2040 ……………………………………………………………………………………………. 102. U. S. motorgasolineanddieselfuelconsumption,2000-2040 ………………………………………………………………………………….. 103. U. S. refinerygasoline-to-dieselproductionratioandcrackspread,2008-2040 ……………………………………………………….. 104.

Coalproductionbyregion,1970-2040 ………………………………………………………………………………………………………………………. 105. U. S. totalcoalproductioninsixcases,2011,2020,and2040 ………………………………………………………………………………….. 106. Averageannualminemouthcoalpricesbyregion,1990-2040 …………………………………………………………………………………. 107. Cumulativecoal-firedgeneratingcapacityadditionsandenvironmentalretrofitsintwocases,2012-2040 ……………… 108. U. S. energy-relatedcarbondioxideemissionsbysectorandfuel,2005and2040…………………………………………………… 109.

Sulfurdioxideemissionsfromelectricitygeneration,1990-2040 ……………………………………………………………………………… 110. Nitrogenoxidesemissionsfromelectricitygeneration,1990-2040 …………………………………………………………………………… 111. Energy-relatedcarbondioxideemissionsintwocaseswiththreelevelsofemissionsfees,2000-2040………………….. 112. Naturalgas-firedelectricitygenerationinsixCO2feecases,2000-2040…………………………………………………………………. 70 71 71 72 72 73 73 74 74 75 75 76 76 77 77 78 78 79 79 80 80 81 81 82 82 83 83 84 84 85 85 86 86 87 87 88 88 89 89 225 227 228 229 230 231 232 Comparison with other projections F1.

UnitedStatesCensusDivisions ………………………………………………………………………………………………………………………………… F2. lectricitymarketmoduleregions ……………………………………………………………………………………………………………………………… E F3. Liquidfuelsmarketmoduleregions …………………………………………………………………………………………………………………………… F4. ilandgassupplymodelregions ……………………………………………………………………………………………………………………………… O F5. turalgastransmissionanddistributionmodelregions ………………………………………………………………………………………….. N F6. oalsupplyregions …………………………………………………………………………………………………………………………………………………… C F7. oaldemandregions ……………………………………………………………………………………………………………………………………….. ………. C viii U. S. Energy Information Administration | Annual Energy Outlook 2013 Executive summary Executive summary The projections in the U. S.

Energy Information Administration’s Annual Energy Outlook 2013 (AEO2013) focus on the factors that shape the U. S. energy system over the long term. Under the assumption that current laws and regulations remain unchanged throughout the projections, the AEO2013 Reference case provides a basis for examination and discussion of energy production, consumption, technology, and market trends and the direction they may take in the future. AEO2013 also includes alternative cases (see Appendix E, Table E1), which explore important areas of uncertainty for markets, technologies, and policies in the U. S. energy economy. Many of the implications of the alternative cases are discussed in the Issues in focus section of AEO2013.

Key results highlighted in the AEO2013 Reference and alternative cases include: • Continued strong growth in domestic crude oil production over the next decade—largely as a result of rising production from tight formations—and increased domestic production of natural gas; • The potential for even stronger growth in domestic crude oil production under alternative conditions; • Evolving natural gas markets that spur increased use of natural gas for electric power generation and transportation and an expanding natural gas export market; • A decline in motor gasoline consumption over the projection period, reflecting the effects of more stringent corporate average fuel economy (CAFE) standards, as well as growth in diesel fuel consumption and increased use of natural gas to power heavyduty vehicles; and • Low electricity demand growth, and continued increases in electricity generation capacity fueled by natural gas and renewable energy, which when combined with environmental regulations put pressure on coal use in the electric power sector. In some cases, coal’s share of total electricity generation falls below the natural gas share through the end of the projection period. Oil production, particularly from tight oil plays, rises over the next decade, leading to a reduction in net import dependence Crude oil production has increased since 2008, reversing a decline that began in 1986. From 5. 0 million barrels per day in 2008, U. S. crude oil production increased to 6. 5 million barrels per day in 2012.

Improvements in advanced crude oil production technologies continues to lift domestic supply, with domestic production of crude oil increasing in the Reference case before declining gradually beginning in 2020 for the remainder of the projection period. The projected growth results largely from a significant increase in onshore crude oil production, particularly from shale and other tight formations, which has been spurred by technological advances and relatively high oil prices. Tight oil development is still at an early stage, and the outlook is highly uncertain. In some of the AEO2013 alternative cases, tight oil production and total U. S. crude oil production are significantly above their levels in the Reference case. The net import share of U. S. etroleum and other liquids consumption (including crude oil, petroleum liquids, and liquids derived from nonpetroleum sources) grew steadily from the mid-1980s to 2005 but has fallen in every year since then (Figure 1). In the Reference case, U. S. net imports of petroleum and other liquids decline through 2019, while still providing approximately one-third of total U. S. supply. The net import share of U. S. petroleum and other liquids consumption continues to decline in the Reference case, falling to 34 percent in 2019 before increasing to 37 percent in 2040. Figure 1. Net import share of U. S. liquids supply in two cases, 1970-2040 (million barrels per day) 25 History Consumption Net imports 2005 2011 Projections Net exports (8% in 2040) 0 15 60% 45% 37% 10 Domestic supply Low/No Net Imports Reference 5 The U. S. could become a net exporter of liquid fuels under certain conditions. An article in the Issues in focus section considers four cases that examine the impacts of various assumptions about U. S. dependence on imported liquids. Two cases (Low Oil and Gas Resource and High Oil and Gas Resource) vary only the supply assumptions, and two cases (Low/No Net Imports and High Net Imports) vary both the supply and demand assumptions. The different assumptions in the four cases generate wide variation from the liquid fuels import dependence values in the AEO2013 Reference case.

In the Low/No Net Imports case, the United States ends its reliance on net imports of liquid fuels in the mid-2030s, with net exports rising to 8 percent of total U. S. liquid fuel production in 2040. In contrast, in the High Net Imports case, net petroleum import dependence is above 44 percent in 2040, which is higher than the Reference case level of 37 percent but still well below the 2005 level of 60 percent. While other combinations of assumptions or unforeseen technology breakthroughs might produce a comparable outcome, the assumptions in the Low/No Imports case illustrate the magnitude and type of changes that would be 0 1970 1980 1990 2000 2010 2020 2030 2040 2 U. S.

Energy Information Administration | Annual Energy Outlook 2013 Executive summary required for the United States to end its reliance on net imports of liquid fuels, which began after World War II and has continued to the present day. Some of the assumptions in the Low/No Net Imports case, such as increased fuel economy for light-duty vehicles (LDVs) after 2025 and wider access to offshore resources, could be influenced by possible future energy policies. However, other assumptions in this case, such as the greater availability of onshore technically recoverable oil and natural gas resources, depend on geological outcomes that cannot be influenced by policy measures.

In addition, economic trends, consumer preferences and behaviors, and technological factors also may be unaffected, or only modestly affected, by policy measures. In the High Oil and Gas Resource case, changes due to the supply assumptions alone cause net import dependence to decline to 7 percent in 2040, with U. S. crude oil production rising to 10. 2 million barrels per day in 2040, or 4. 1 million barrels per day above the Reference case level. Tight oil production accounts for more than 77 percent (or 3. 2 million barrels per day) of the difference in production between the two cases. Production of natural gas plant liquids in the United States also exceeds the Reference case level.

One of the most uncertain aspects of this analysis is the potential effect of different scenarios on the global market for liquid fuels, which is highly integrated. Strategic choices made by leading oil-exporting countries could result in U. S. price and quantity changes that differ significantly from those presented here. Moreover, regardless of how much the United States reduces its reliance on imported liquids, consumer prices will not be insulated from global oil prices if current policies and regulations remain in effect and world markets for delivery continue to be competitive. The United States becomes a net exporter of natural gas U. S. dry natural gas production increases 1. percent per year throughout the Reference case projection, outpacing domestic consumption by 2019 and spurring net exports of natural gas (Figure 2). Higher volumes of shale gas production are central to higher total production volumes and a transition to net exports. As domestic supply has increased in recent years, natural gas prices have declined, making the United States a less attractive market for imported natural gas and more attractive for export. U. S. net exports of natural gas grow to 3. 6 trillion cubic feet in 2040 in the Reference case. Most of the projected growth in U. S. exports consists of pipeline exports to Mexico, which increase steadily as growing volumes of imported natural gas from the United States fill the widening gap between Mexico’s production and consumption.

Declining natural gas imports from Canada also contribute to the growth in U. S. net exports. Net U. S. imports of natural gas from Canada decline sharply from 2016 to 2022, then stabilize somewhat before dropping off again in the final years of the projection, as continued growth in domestic production mitigates the need for imports. Continued low levels of liquefied natural gas (LNG) imports in the projection period, combined with increased U. S. exports of domestically sourced LNG, position the United States as a net exporter of LNG by 2016. U. S. exports of domestically sourced LNG (excluding exports from the existing Kenai facility in Alaska) begin in 2016 and rise to a level of 1. trillion cubic feet per year in 2027. One-half of the U. S. exports of LNG originate from the Lower 48 states and the other half from Alaska. The prospects for exports are highly uncertain, however, depending on many factors that are difficult to gauge, such as the development of new production capacity in foreign countries, particularly from deepwater reservoirs, shale gas deposits, and the Arctic. In addition, future U. S. exports of LNG depend on a number of other factors, including the speed and extent of price convergence in global natural gas markets and the extent to which natural gas competes with liquids in domestic and international markets.

Figure 2. Total U. S. natural gas production, consumption, and net imports in the Reference case, 1990-2040 (trillion cubic feet) 40 History 2011 Projections Netexports,2040(12%) Total production Total consumption In the High Oil and Gas Resource case, with more optimistic resource assumptions, U. S. LNG exports grow to more than 4 trillion cubic feet in 2040. Most of the additional exports originate from the Lower 48 states. Coal’s share of electric power generation falls over the projection period Although coal is expected to continue its important role in U. S. electricity generation, there are many uncertainties that could affect future outcomes.

Chief among them are the relationship between coal and natural gas prices and the potential for policies aimed at reducing greenhouse gas (GHG) emissions. In 2012, natural gas prices were low enough for a few months for power companies to run natural gas-fired generation plants more economically than coal plants in many areas. During those months, coal and natural gas were nearly tied in providing the largest share of total electricity generation, something that had never happened before. In the Reference case, existing coal plants recapture some of the market they recently lost to natural gas plants because natural gas prices 3 30 Netimports,2011(8%) 20 10 Net imports 0 10 1990 2000 2010 2020 2030 2040 U. S. Energy Information Administration | Annual Energy Outlook 2013 Executive summary rise more rapidly than coal prices. However, the rise in coal-fired generation is not sufficient for coal to maintain its generation share, which falls to 35 percent by 2040 as the share of generation from natural gas rises to 30 percent. In the alternative High Oil and Natural Gas Resource case, with much lower natural gas prices, natural gas supplants coal as the top source of electricity generation (Figure 3). In this case, coal accounts for only 27 percent of total generation in 2040, while natural gas accounts for 43 percent.

However, while natural gas generation in the power sector surpasses coal generation in 2016 in this case, more coal energy than natural gas energy is used for power generation until 2035 because of the higher average thermal efficiency of the natural gas-fired generating units. Coal use for electric power generation falls to 14. 7 quadrillion Btu in 2040 in the High Oil and Natural Gas Resource case (compared with 18. 7 quadrillion Btu in the Reference case), while natural gas use rises to 15. 1 quadrillion Btu in the same year (Figure 4). Natural gas use for electricity generation is 9. 7 quadrillion Btu in 2040 in the Reference case. Coal’s generation share and the associated carbon dioxide (CO2) emissions could be further reduced if policies aimed at reducing GHG emissions were enacted (Figure 5).

For example, in the GHG15 case, which assumes a fee on CO2 emissions that starts at $15 per metric ton in 2014 and increases by 5 percent per year through 2040, coal’s share of total generation falls to 13 percent in 2040. Energy-related CO2 emissions also fall sharply in the GHG15 case, to levels that are 10 percent, 15 percent, and 24 percent lower than projected in the Reference case in 2020, 2030, and 2040, respectively. In 2040, energy-related CO2 emissions in the GHG15 case are 28 percent lower than the 2005 total. In the GHG15 case, coal use in the electric power sector falls to only Figure 3. Electricity generation from coal and 6. 1 quadrillion Btu in 2040, a decline of about two-thirds from natural gas in two cases, 2008-2040 the 2011 level.

While natural gas use in the electric power (billion kilowatthours) sector initially displaces coal use in this case, reaching more Projections 2011 than 10 quadrillion Btu in 2016, it falls to 8. 8 quadrillion Btu in 2,500 2040 as growth in renewable and nuclear generation offsets Reference natural gas use later in the projection period. 2,000 1,500 Coal With more efficient light-duty vehicles, motor gasoline consumption declines while diesel fuel use grows, even as more natural gas is used in heavyduty vehicles High Oil and Gas Resource 1,000 Natural gas 500 0 2008 2015 2020 2025 2030 2035 2040 The AEO2013 Reference case incorporates the GHG and CAFE standards for LDVs [6] through the 2025 model year.

The increase in vehicle efficiency reduces LDV energy use from 16. 1 quadrillion Btu in 2011 to 14. 0 quadrillion Btu in 2025, predominantly motor gasoline (Figure 6). LDV energy use continues to decline through 2036, then levels off until 2039 as growth in population and vehicle miles traveled offsets more modest improvement in fuel efficiency. Figure 4. Coal and natural gas use in the electric power sector in three cases, 2011, 2025, and 2040 (quadrillion Btu) Reference Figure 5. Energy-related carbon dioxide emissions in four cases, 2000-2040 (million metric tons) 6,000 5,500 History 2011 Projections High Oil and Gas Resource Reference 2011 2025 040 High Oil and Gas Resource 2011 2025 5,000 4,500 GHG15 2040 2011 2025 2040 0 5 10 15 20 Coal Natural gas 4,000 0 2000 HighResource,$15fee Reference,$15fee 2010 2020 2030 2040 4 U. S. Energy Information Administration | Annual Energy Outlook 2013 Executive summary Furthermore, the improved economics of natural gas as a fuel for heavy-duty vehicles result in increased use that offsets a portion of diesel fuel consumption. The use of petroleum-based diesel fuel is also reduced by growing consumption of diesel produced with gas-to-liquids (GTL) technology. Natural gas use in vehicles (including natural gas used in the production of GTL) totals 1. trillion cubic feet in 2040 in the Reference case, displacing 0. 7 million barrels per day of other motor fuels [7]. Diesel fuel use nonetheless increases at a relatively strong rate, with freight travel demand supported by increasing industrial production. Natural gas consumption grows in industrial and electric power sectors as domestic production also serves an expanding export market Relatively low natural gas prices, maintained by growing shale gas production, spur increased use in the industrial and electric power sectors, particularly over the next decade. In the Reference case, natural gas use in the industrial sector increases by 16 percent, from 6. 8 trillion cubic feet per year in 2011 to 7. trillion cubic feet per year in 2025. After 2025, the growth of natural gas consumption in the industrial sector slows, while total U. S. consumption continues to grow (Figure 7). This additional growth is mostly for use in the electric power sector. Although natural gas continues to capture a growing share of total electricity generation, natural gas consumption by power plants does not increase as sharply as generation because new plants are very efficient (needing less fuel per unit of power output). The natural gas share of generation rose from 16 percent of generation in 2000 to 24 percent in 2011 and increases to 27 percent in 2025 and 30 percent in 2040.

Natural gas use in the residential and commercial sectors remains nearly constant, as increasing end-use demand is balanced by increasing end-use efficiency. Natural gas consumption also grows in other markets in the Reference case, including heavy-duty freight transportation (trucking) and as a feedstock for GTL production of diesel and other fuels. Those uses account for 6 percent of total U. S. natural gas consumption in 2040, as compared with almost nothing in 2011. Natural gas use in the electric power sector grows even more sharply in the High Oil and Natural Gas Resource case, as the natural gas share of electricity generation grows to 39 percent, reaching 14. trillion cubic feet in 2040, more than 55 percent greater than in the Reference case. Industrial sector natural gas consumption growth is also stronger in this case, with growth continuing after 2025 and reaching 13. 0 trillion cubic feet in 2040 (compared to 10. 5 trillion cubic feet in 2040 in the Reference case). Much of the industrial growth in the High Oil and Natural Gas Resource case is associated with natural gas use for GTL production and increased lease and plant use in natural gas production. Renewable fuel use grows at a faster rate than fossil fuel use The share of U. S. electricity generation from renewable energy grows from 13 percent in 2011 to 16 percent in 2040 in the Reference case.

Electricity generation from solar and, to a lesser extent, wind energy sources grows as their costs decline, making them more economical in the later years of the projection. However, the rate of growth in renewable electricity generation is sensitive to several factors, including natural gas prices and the possible implementation of policies to reduce GHG emissions. If future natural gas prices are lower than projected in the Reference case, as illustrated in the High Oil and Gas Resource case, the share of renewable generation would grow more slowly, to only 14 percent in 2040. Alternatively, if broad-based policies to reduce GHG emissions were enacted, renewable generation would be expected to grow more rapidly.

In three cases that assume GHG emissions fees that range from $10 to $25 per metric ton in 2014 and rise by 5 percent per year through 2040 (GHG10, GHG15, and GHG25), the Figure 6. Transportation energy consumption by fuel, 1990-2040 (quadrillion Btu) 35 30 25 20 15 History 2011 E85 Other Projections Figure 7. U. S. dry natural gas consumption by sector, 2005-2040 (trillion cubic feet) 30 25 History Projections Electric power 32% 31% Industrial 33% 33% Gas-to-liquids 2% Transportation 6% 12% Commercial 14% Residential 22% 11% 4% 2% Diesel Jet fuel Pipeline fuel 29% 20 15 CNG/LNG 10 5 0 1990 2000 4% 13% 1% 4% 3% 47% 10 5 0 60% Motor gasoline 3% 13% 19% 2010 2020 2030 2040 2005 2011 2020 2025 2030 2035 2040 U. S.

Energy Information Administration | Annual Energy Outlook 2013 5 Executive summary Figure 8. Renewable energy share of U. S. electricity generation in five cases, 2000-2040 (percent) 40 History 2011 Projections renewable share of total U. S. electricity generation in 2040 ranges from 23 percent to 31 percent (Figure 8). The AEO2013 Reference case reflects a less optimistic outlook for advanced biofuels to capture a rapidly growing share of the liquid fuels market than earlier Annual Energy Outlooks. As a result, biomass use in the Reference case totals 5. 9 quadrillion Btu in 2035 and 7. 1 quadrillion Btu in 2040, up from 4. 0 quadrillion Btu in 2011. 30 GHG25 GHG15 0 GHG10 10 Reference High Oil and Gas Resource 0 2000 2005 2010 2015 2020 2025 2030 2035 2040 Endnotes for Executive summary Links current as of March 2013 6. U. S. Environmental Protection Agency and National Highway Traffic Safety Administration, “2017 and Later Model Year LightDuty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards,” Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www. federalregister. gov/articles/2012/10/15/2012-21972/2017-and-latermodel-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel. 7. Liquid motor fuels include diesel and liquid fuels from gas-to-liquids (GTL) processes.

Liquid fuel volumes from GTL for motor vehicle use are estimated based on the ratio of onroad diesel and gasoline to total diesel and gasoline. 6 U. S. Energy Information Administration | Annual Energy Outlook 2013 Legislation and regulations Legislation and regulations Introduction The Annual Energy Outlook 2013 (AEO2013) generally represents current federal and state legislation and final implementation regulations as of the end of September 2012. The AEO2013 Reference case assumes that current laws and regulations affecting the energy sector are largely unchanged throughout the projection period (including the implication that laws that include sunset dates are no longer in effect at the time of those sunset dates) [8].

The potential impacts of proposed legislation, regulations, or standards—or of sections of authorizing legislation that have been enacted but are not funded or where parameters will be set in a future regulatory process—are not reflected in the AEO2013 Reference case, but some are considered in alternative cases. The AEO2013 Reference case does not reflect the provisions of the American Taxpayer Relief Act of 2012 (P. L. 112-240) enacted on January 1, 2013 [9]. Key energy-related provisions of that legislation—including extension of the production tax credit for renewable generation, tax credits for energy-efficient appliances, and tax credits for selected biofuels—are reflected in an alternative case completed as part of AEO2013.

This section summarizes federal and state legislation and regulations newly incorporated or updated in AEO2013 since the completion of the Annual Energy Outlook 2012 (AEO2012). Examples of federal and state legislation and regulations incorporated in the AEO2013 Reference case or whose handling has been modified include: • Incorporation of new light-duty vehicle greenhouse gas emissions (GHG) and corporate average fuel economy (CAFE) standards for model years 2017 to 2025 [10] • Continuation of the Clean Air Interstate Rule (CAIR) [11] after the court’s announcement of intent to vacate the Cross-State Air Pollution Rule (CSAPR) [12] • Updated handling of the U. S.

Environmental Protection Agency’s (EPA) National Emissions Standards for Hazardous Air Pollutants (NESHAP) for industrial boilers and process heaters [13] • Modeling of California’s Assembly Bill 32, the Global Warming Solutions Act (AB 32) [14], that allows for representation of a cap-and-trade program developed as part of California’s GHG reduction goals for 2020 • Incorporation of the California Low Carbon Fuel Standard (LCFS) [15], which requires fuel producers and importers who sell motor gasoline or diesel fuel in California to reduce the carbon intensity of those fuels by an average of 10 percent between 2012 and 2020 through the mixing and increased sale of alternative low-carbon fuels. There are many other pieces of legislation and regulation that appear to have some probability of being enacted in the not-toodistant future, and some laws include sunset provisions that may be extended.

However, it is difficult to discern the exact forms that the final provisions of pending legislation or regulations will take, and sunset provisions may or may not be extended. Even in situations where existing legislation contains provisions to allow revision of implementing regulations, those provisions may not be exercised consistently. Many pending provisions are examined in alternative cases included in AEO2013 or in other analyses completed by the U. S. Energy Information Administration (EIA). In addition, at the request of the Administration and Congress, EIA has regularly examined the potential implications of other possible energy options in Service Reports.

Those reports can be found on the EIA website at http://www. eia. gov/oiaf/service_rpts. htm. 1. Greenhouse gas emissions and corporate average fuel economy standards for 2017 and later model year light-duty vehicles On October 15, 2012, EPA and the National Highway Traffic Safety Administration (NHTSA) jointly issued a final rule for tailpipe emissions of carbon dioxide (CO2) and CAFE standards for light-duty vehicles, model years 2017 and beyond [16]. EPA, operating under powers granted by the Clean Air Act (CAA), issued final CO2 emissions standards for model years 2017 through 2025 for passenger cars and light-duty trucks, including medium-duty passenger vehicles.

NHTSA, under powers granted by the Energy Policy and Conservation Act, as amended by the Energy Independence and Security Act, issued CAFE standards for passenger cars and light-duty trucks, including medium-duty passenger vehicles, for model years 2017 through 2025. The new CO2 emissions and CAFE standards will first affect model year 2017 vehicles, with compliance requirements increasing in stringency each year thereafter through model year 2025. EPA has established standards that are expected to require a fleetwide average of 163 grams CO2 per mile for light-duty vehicles in model year 2025, which is equivalent to a fleet-wide average of 54. 5 miles per gallon (mpg) if reached only through fuel economy.

However, the CO2 emissions standards can be met in part through reductions in air-conditioning leakage and the use of alternative refrigerants, which reduce CO2-equivalent GHG emissions but do not affect the estimation of fuel economy compliance in the test procedure. NHTSA has established two phases of CAFE standards for passenger cars and light-duty trucks (Table 1). The first phase, covering model years 2017 through 2021, includes final standards that NHTSA estimates will result in a fleet-wide average of 40. 3 mpg for light-duty vehicles in model year 2021 [17]. The second phase, covering model years 2022 through 2025, requires additional improvements leading to a fleet-wide average of 48. 7 mpg for light-duty vehicles in model year 2025.

Compliance with CO2 emission and CAFE standards is calculated only after final model year vehicle production, with fleet-wide light-duty vehicle standards representing averages based on the sales volume of passenger cars and light-duty trucks for a given year. Because sales 8 U. S. Energy Information Administration | Annual Energy Outlook 2013 Legislation and regulations volumes are not known until after the end of the model year, EPA and NHTSA estimate future fuel economy based on the projected sales volumes of passenger cars and light-duty trucks. The new CO2 emissions and CAFE standards for passenger cars and light-duty trucks use an attribute-based standard that is determined by vehicle footprint—the same methodology that was used in setting the final rule for model year 2012 to 2016 lightduty vehicles.

Footprint is defined as wheelbase size (the distance from the center of the front axle to the center of the rear axle), multiplied by average track width (the distance between the center lines of the tires) in square feet. The minimum requirements for CO2 emissions and CAFE are production-weighted averages based on unique vehicle footprints in a manufacturer’s fleet and are calculated separately for passenger cars and light-duty trucks (Figures 9 and 10), reflecting their different design capabilities. In general, as vehicle footprint increases, compliance requirements decline to account for increased vehicle size and load-carrying capability.

Each manufacturer faces a unique combination of CO2 emission and CAFE standards, depending on the number of vehicles produced and the footprints of those vehicles, separately for passenger cars and light-duty trucks. For passenger cars, average fleet-wide compliance levels increase in stringency by 3. 9 percent annually between model years 2017 and 2021 and by 4. 7 percent annually between 2022 and 2025, based on the model year 2010 baseline fleet. In recognition of the challenge of improving the fuel economy and reducing CO2 emissions of full-size pickup trucks while maintaining towing and payload capabilities, the average annual rate of increase in the stringency of light-duty truck standards is 2. percent from 2017 to 2021, with smaller light-duty trucks facing higher increases and larger light-duty trucks lower increases in compliance stringency. From 2022 to 2025, the average annual increase in compliance stringency for all light-duty trucks is 4. 7 percent. The CO2 emissions and CAFE standards also include flexibility provisions for compliance by individual manufacturers, such as: (1) credit averaging, which allows credit transfers between a manufacturer’s passenger car and light-duty truck fleets; (2) credit banking, which allows manufacturers to “carry forward” Table 1. NHTSA projected average fleet-wide CAFE credits earned from exceeding the tandards in earlier model compliance levels (miles per gallon) for passenger years and to “carry back” credits earned in later model years cars and light-duty trucks, model years 2017-2025, to offset shortfalls in earlier model years; (3) credit trading based on the model year 2010 baseline fleet between manufacturers who exceed their standards and Passenger Light-duty those who do not; (4) air conditioning improvement credits Model year cars trucks Combined that can be applied toward CO2 emissions standards; (5) offcycle credits for measurable improvements in CO2 emissions 2017 39. 6 29. 1 35. 1 and fuel economy that are not captured by the two-cycle test 2018 41. 1 29. 6 36. 1 procedure used to measure emissions and fuel consumption; 2019 42. 5 30. 0 37. 1 (6) CO2 emissions “compliance multipliers” for electric, 2020 44. 2 30. 6 38. 3 plug-in hybrid electric, compressed natural gas, and fuel cell 2021 46. 1 32. 6 40. 3 vehicles through model year 2021; and (7) incentives for the 2022 48. 2 34. 2 42. use of hybrid electric and other advanced technologies in fullsize pickup trucks. 2023 50. 5 35. 8 44. 3 2024 2025 52. 9 55. 3 37. 5 39. 3 46. 5 48. 7 Finally, flexibility provisions do not allow domestic passenger cars to deviate significantly from annual fuel economy targets. NHTSA retains a required minimum fuel economy level for Figure 9. Projected average passenger car CAFE compliance targets (miles per gallon) by vehicle footprint (square feet), model years 2017-2025 70 2025 2024 2023 2022 Figure 10. Projected average light-duty truck CAFE compliance targets (miles per gallon) by vehicle footprint (square feet), model years 2017-2025 60 2025 2024 2023 2022 60 50 50 40 40 2021 2020 2019 2018 2017 30 30 021 2020 2019 2018 20 2017 0 Vehicle footprint (square feet) 35 40 45 50 55 60 65 70 75 80 0 Vehicle footprint (square feet) 35 40 45 50 55 60 65 U. S. Energy Information Administration | Annual Energy Outlook 2013 9 Legislation and regulations domestically produced passenger cars by manufacturer that is the higher of 27. 5 miles per gallon or 92 percent of the average fuel economy projected for the combined fleet of domestic and foreign passenger cars for sale in the United States. For example, the minimum standard for passenger cars sold by a manufacturer in 2025 would be 50. 9 miles per gallon, based on the estimated fleet average passenger car fuel economy for that year.

The AEO2013 Reference case includes the final CAFE standards for model years 2012 through 2016 (promulgated in March 2010) [18] and the standards for model years 2017 through 2025, with subsequent CAFE standards for years 2026-2040 vehicles calculated using 2025 levels of stringency. The AEO2013 Reference case projects fuel economy values for passenger cars, lightduty trucks, and combined light-duty vehicles that differ from NHTSA projections. This variance is the result of a different distribution of the production of passenger cars and light-duty trucks by footprint as well as a different mix between passenger cars and light-duty trucks (Table 2). CAFE standards are included by using the equations and coefficients employed by NHTSA to determine unique fuel economy requirements based on footprint, along with the ability of manufacturers to earn flexibility credits toward compliance.

The AEO2013 Reference case projects sales of passenger cars and light-duty trucks by vehicle footprint with the key assumption that vehicle footprints are held constant by manufacturer in each light-duty vehicle size class. 2. Recent rulings on the Cross-State Air Pollution Rule and the Clean Air Interstate Rule On August 21, 2012, the United States Court of Appeals for the District of Columbia Circuit announced its intent to vacate CSAPR, which it had stayed from going into effect earlier in 2012. CSAPR was to replace CAIR, which was in effect, by establishing emissions caps (levels) for sulfur dioxide (SO2) and nitrogen oxides (NOX) emissions from power plants in the eastern half of the United States.

As a result of the court’s action, the regulation of SO2 and NOX emissions will continue to be administered under CAIR pending the promulgation of a valid replacement. AEO2013 assumes that CAIR remains a binding regulation through 2040. CAIR covers all fossil-fueled power plant units with nameplate capacity greater than 25 megawatts in 27 eastern states and the District of Columbia (Figure 11). Twenty-two states and the District of Columbia fall under the caps for both annual emissions of SO2 and NOX and ozone season NOX . Three states are controlled for only ozone season NOX , and two states are controlled for only annual SO2 and NOX emissions.

The caps went into effect for NOX in 2009 and for SO2 in 2010. Both caps are scheduled to be tightened again in 2015. AEO2013 considered how the power sector would use the emissions allowance trading that EPA set up to lower compliance costs, including capturing the interplay of the SO2 program for acid rain under the Clean Air Act Amendments Title IV and the CAIR program that uses the same allowances. Although CSAPR shared some basic similarities with CAIR, there are key differences between the two programs. Generally, CSAPR had greater limitations on trading to ensure that emissions reductions would occur in all states; lower emissions caps; and more rapid phasing in of tighter emissions caps.

CSAPR also did not allow carryover of banked allowances from the Acid Rain SO2 and NOX Budget programs. Each program was aimed at substantial reductions of power sector SO2 and NOX emissions. AEO2013 represents the limits on SO2 and NOX emissions trading as specified by CAIR. The National Energy Modeling System (NEMS) includes the representation of emissions for both the CAIR and non-CAIR regions. In NEMS, power plants in both regions are required to submit allowances to account for their emissions as if covered by the rule. NEMS allows for power plants in the CAIR regions to trade SO2 allowances with those plants in the non-CAIR region, but the SO2 allowances are valued differently for each region.

NEMS also allows for the banking of SO2 and NOX allowances consistent with CAIR’s provisions. 3. Nuclear waste disposal and the Waste Confidence Rule Waste confidence is defined by the U. S. Nuclear Regulatory Commission (NRC) as a finding that spent nuclear fuel can be safely stored for decades beyond the licensed operating life of a reactor without significant environmental effects [19]. It enables the NRC to license reactors or renew their licenses without Table 2. AEO2013 projected average fleet-wide CAFE examining the effects of extended waste storage for each compliance levels (miles per gallon) for passenger individual site pending ultimate disposal. ars and light-duty trucks, model years 2017-2025 Model year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026-2040 Passenger cars 40. 1 40. 9 42. 6 44. 4 46. 4 48. 7 51. 3 52. 5 55. 0 Light-duty trucks 30. 1 30. 7 30. 9 32. 0 33. 8 34. 9 36. 5 38. 3 40. 0 Combined 34. 7 35. 5 36. 4 37. 9 39. 8 41. 5 43. 6 45. 2 47. 3 NRC’s Waste Confidence Rule issued in August 1984 [20] included five findings: 1. Spent nuclear fuel can be disposed of safely in a mined geologic repository. 2. A mined geologic repository will be available when needed for disposal of spent nuclear fuel. 3. Until a mined geologic repository is available, spent nuclear fuel can be safely managed. 4.

Spent nuclear fuel can be safely stored at reactors for 30 years without significant environmental impacts. 5. Storage will be made available for spent nuclear fuel onsite or offsite, if required. Projected stringency based on 2025 levels. 10 U. S. Energy Information Administration | Annual Energy Outlook 2013 Legislation and regulations The Waste Confidence Rule was updated in 1990 [21], reviewed in 1999, and updated again in 2010 [22]. In December 2010, with the termination of the repository program at Yucca Mountain, the Waste Confidence Rule was amended to state that spent nuclear fuel could be stored safely at reactor sites for 60 years following reactor shutdown. In June 2012, the U. S.

Court of Appeals for the District of Columbia Circuit struck down the NRC’s 2010 amendment of the Waste Confidence Rule, stating that the NRC should have analyzed the environmental consequences of never building a permanent waste repository, and that the discussion of potential leaks or fires at spent fuel pools was inadequate [23]. The NRC issued an order in August 2012 that suspended actions related to issuance of operating licenses and license renewals [24]. Currently, the NRC is analyzing the potential impacts on licensing reviews and developing a proposed path forward to meet the court’s requirements. Until the NRC revises the Waste Confidence Rule, it will not issue reactor operating licenses or operating license renewals. Licensing reviews and proceedings will continue, but Atomic Safety and Licensing Board hearings will be suspended pending further NRC guidance.

NRC expects to issue a revised Waste Confidence Rule within 2 years [25]. Reactors with license renewal applications under review by the NRC may continue to operate, even if their existing licenses expire, until the NRC can resolve the waste confidence issue and promulgate a revised rule. The regulation states: “If the licensee of a nuclear power plant licensed under 10 CFR 50. 21(b) or 50. 22 files a sufficient application for renewal of either an operating license or a combined license at least 5 years before the expiration of the existing license, the existing license will not be deemed to have expired until the application has been finally determined” [26].

There are currently 15 reactors with license renewal applications in various stages of review by the NRC that are subject to the August 2012 order that suspends licensing decisions. For those reactors that have not submitted applications for license renewal, the first license expiration date would occur in 2020. Because it is anticipated by the NRC that the issues with the Waste Confidence Rule will be resolved within 2 years, well before 2020, the continued operation of those reactors should not be affected. The AEO2013 Reference case assumes plants that have not submitted applications for license renewal will be unaffected. Currently, utilities have the option to license reactors under either of two NRC rules.

The NRC’s Domestic Licensing of Production and Utilization Facilities rule defines a two-step process for obtaining an operating license [27]. First, a construction permit is Figure 11. States covered by CAIR limits on emissions of sulfur dioxide and nitrogen oxides States controlled for both annual SO2 and NOX and ozone season NOX (22 states) States controlled for only annual SO2 and NOX (2 states) States controlled for ozone season NOX (3 states) States not covered by the Clean Air Interstate Rule U. S. Energy Information Administration | Annual Energy Outlook 2013 11 Legislation and regulations issued, and then an operating license is issued. There are two U. S. eactors with current construction permits: Bellefonte Unit 1 and Watts Bar Unit 2. Both plants are owned by the Tennessee Valley Authority (TVA), which has announced that construction of Bellefonte Unit 1 will not proceed until fuel loading at Watts Bar Unit 2 is completed [28]. Neither reactor will be able to receive an operating license until the waste confidence issue is resolved, but construction may continue. TVA has not provided a projected date for commencement of operations at Bellefonte Unit 1, but it is unlikely that resolution of the issues associated with the Waste Confidence Rule will affect the operational date of Bellefonte Unit 1.

Watts Bar Unit 2 was originally scheduled to go online in 2012, but delays in construction make it unlikely that it will be ready to begin operation before the issues with the Waste Confidence Rule can be resolved. AEO2013 assumes that Watts Bar Unit 2 will come online in December 2015. The NRC’s “Licenses, Certifications, and Approvals for Nuclear Power Plants” rule defines a one-step process, whereby the construction permit and operating license are issued as a combined license (COL) [29]. Once an application for a COL is submitted, the utility may engage in certain pre-construction activities. To date, two plants, each with two reactors, have received COLs in 2012.

Vogtle Units 3 and 4 and Summer Units 2 and 3 will both be unaffected by the issues with the Waste Confidence Rule. Once construction and all inspections are complete, the Vogtle and Summer plants may commence operations. For utilities that have submitted applications but have not received COLs, issuance of those licenses may be delayed. For COL applications currently under active review, it is possible that two—Levy County Units 1 and 2 and William States Lee III Units 1 and 2—may be delayed, based on their review status and the NRC’s schedule for application reviews. The online dates for the units should be unaffected if issues with the Waste Confidence Rule are resolved within the next 2 years.

Based on EIA’s analysis of the Waste Confidence Rule and ongoing proceedings, the AEO2013 Reference case assumes that the issuance of new operating licenses will not be affected. AEO2013 also assumes that the Waste Confidence Rule will not affect power uprates, because uprates do not increase the amount of spent nuclear fuel requiring storage, as confirmed in a public policy statement issued by the NRC [30]. 4. Maximum Achievable Control Technology for industrial boilers Section 112 of the CAA requires the regulation of air toxics through implementation of NESHAP for industrial, commercial, and institutional boilers [31]. The final regulations are also known as “Boiler MACT,” where MACT is the Maximum Achievable Control Technology.

Pollutants covered by the Boiler MACT regulations include control of hazardous air pollutants (HAPs), such as hydrogen chloride, mercury (Hg), and dioxin/furan, as well as carbon monoxide (CO), and particulate matter (PM) as surrogates for other HAPs. Boilers used for generating electricity are explicitly covered by the Mercury and Air Toxics Standards, also under Section 112 of the CAA, and are specifically excluded from Boiler MACT regulations. The Final Rule for Boiler MACT was issued in March 2011; a partial Reconsideration Rule concerning limited technical corrections to the Final Rule was issued in December 2011, but it did not replace the Final Rule.

The AEO2013 Reference case assumes that the Final Rule and the partial Reconsideration Rules are in force. The finalized Boiler MACT rule was announced in December 2012, after the modeling work for AEO2013 was completed. The provisions of the finalized Boiler MACT rule are less stringent than the provisions of the Final Rule and the partial Reconsideration Rule assumed in the Reference case. For AEO2013, the upgrade costs of Boiler MACT were implemented in the Macroeconomic Activity Module (MAM). Upgrade costs used are the “nonproductive costs,” which are not associated with efficiency improvements. The upgrade costs are applied as an aggregated cost across all industries.

Because of this aggregation of cost and the need for consistency across industries, the cost in the MAM is manifested as a reduction in shipments in the Industrial Demand Module. There is little difference in the cost of compliance for major sources between the March 2011 Final Rule and the December 2011 Reconsideration Rule, and there is no difference for area sources. Boiler MACT has two compliance groups with different obligations: major source [32] and area source. A site that contains one or more boilers or process heaters that have the potential to emit 10 or more tons of any one HAP per year, or 25 tons or more of a combination of HAP per year, is a major source [33]. An emissions site that is not a major source is classified as an area source [34].

The characteristics of the site determine the compliance group of the boiler. Generally, compliance measures include regular maintenance and tuneups for smaller facilities and emission limits and performance tests for larger facilities. In the Reconsideration Rule, EIA calculations based on EPA estimates revealed that there were 14,111 existing major source boilers in 2011 [35]. Of those, calculations based on EPA estimates revealed that 16 percent burn fuels that potentially may subject them to specific emissions limits and annual performance tests. The existing number of affected area source boilers in 2011 was estimated at 189,450 by EIA, using data from EPA [36].

To comply with Boiler MACT, major source boilers and process heaters whose heat input is less than 10 million Btu per hour must receive tuneups every 2 years [37]. Most existing and new major source boilers or process heaters with heat inputs 10 million Btu per hour or greater that burn coal, biomass, liquid, or “other” gas are subject to emission limits on all five of the HAP listed above [38]. Larger major source boilers with heat input of 25 million Btu per hour or greater that burn coal, biomass, or residual oil must use a continuous emission monitoring system for PM [39]. Major source boilers with heat inputs of 10 million Btu per hour or more that burn natural gas or refinery gas, as well as metal process furnaces, are not subject to specific emissions limits or performance tests [40].

Existing major source boilers must comply with the Final Rule by March 21, 2014; new major source boilers must comply by May 20, 2011, or upon startup, whichever is later [41]. 12 U. S. Energy Information Administration | Annual Energy Outlook 2013 Legislation and regulations Area source natural gas-fired boilers are not subject to Boiler MACT. Area source coal-fired boilers whose heat input is less than 10 million Btu per hour and biomass-fired and liquid fuel-fired boilers of any size must receive a tuneup every 2 years. Existing area source boilers with heat input of 10 million Btu per hour or greater are subject to emissions limits, must receive an initial energy assessment, and must undergo performance tests every 3 years [42].

Existing and new coal-fired boilers must meet Hg and CO limits; new coal-fired boilers must also meet limits for PM. New oil-fired and biomass-fired boilers must meet emissions limits only for PM [43]. Existing area source boilers subject to an energy assessment and emissions limits must comply by March 21, 2014. 5. State renewable energy requirements and goals: Update through 2012 To the extent possible, AEO2013 incorporates the impacts of state laws requiring the addition of renewable generation or capacity by utilities doing business in the states. Currently, 30 states and the District of Columbia have an enforceable renewable portfolio standard (RPS) or similar law (Table 3). Under such standards, each state determines its own levels of renewable

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