Table of contents
  1. Story
    1. Data Science for Energy Outlook 2015
    2. Slides
      1. Slide 1 Data Science for Energy Outlook 2015
      2. Slide 2 Data Community DC Data Owls
      3. Slide 3 Data Mining - Data Science – Data Publication Process
      4. Slide 4 Annual Energy Outlook 2015: Overview
      5. Slide 5 Annual Energy Outlook 2015: Data All Tables
      6. Slide 6 Annual Energy Outlook 2015: Executive Summary
      7. Slide 7 Interactive Table Viewer Beta Testing 1
      8. Slide 8 Interactive Table Viewer Beta Testing 2
      9. Slide 9 Data Science Data Publication: Knowledge Base
      10. Slide 10 Data Science Data Publication: Spreadsheet Index
      11. Slide 11 Data Science Data Publication: Web & PDF Tables to Spreadsheet
      12. Slide 12 Data Science Data Publication: Data Browser
      13. Slide 13 AEO2015 Figure ES-1 Spreadsheet
      14. Slide 14 AEO2015 Figure ES-1 Spreadsheet in Spotfire
      15. Slide 15 Data Science Data Publication: Dynamically Linked Adjacent Visualizations
      16. Slide 16 Conclusions and Recommedations
  2. Spotfire Dashboard
  3. Slides
    1. Slide 1 Annual Energy Outlook 2015
    2. Slide 2 Key results from AEO2015
    3. Slide 3 Key results from AEO2015 (continued)
    4. Slide 4 Overview
    5. Slide 5 Crude oil price projection is lower in the AEO2015 Reference case than in AEO2014, particularly in the near term
    6. Slide 6 Reductions in energy intensity largely offset impact of GDP growth, leading to slow projected growth in energy use
    7. Slide 7 U.S. net energy imports continue to decline in the near term, reflecting increased oil and natural gas production coupled with slow demand growth
    8. Slide 8 CO2 emissions are sensitive to the influence of future economic growth and energy price trends on energy consumption
    9. Slide 9 CO2 emissions per dollar of GDP decline faster than energy use per dollar of GDP with a shift towards lower-carbon fuels
    10. Slide 10 New AEO table browser
    11. Slide 11 Petroleum and other liquid supply
    12. Slide 12 AEO2015 explores scenarios that encompass a wide range of future crude oil price paths
    13. Slide 13 U.S. crude oil production rises above previous historical highs before 2020 in all AEO2015 cases, with a range of longer-term outcomes
    14. Slide 14 Growth of onshore crude oil production varies across supply regions, affecting pipeline and midstream infrastructure needs
    15. Slide 15 Combination of increased tight oil production and higher fuel efficiency drive projected decline in oil imports
    16. Slide 16 Net liquid imports provide a declining share of U.S. liquid fuels supply in most AEO2015 cases; in two cases the nation becomes a net exporter
    17. Slide 17 In the transportation sector, motor gasoline use declines; diesel fuel, jet fuel, and natural gas use all grow
    18. Slide 18 U.S. net exports of petroleum products vary with the level of domestic oil production given current limits on U.S. crude oil exports 
    19. Slide 19 Natural gas
    20. Slide 20 Future domestic natural gas prices depend on both domestic resource availability and world energy prices
    21. Slide 21 Shale resources remain the dominant source of U.S. natural gas production growth
    22. Slide 22 Natural gas consumption growth is driven by increased use in all sectors except residential
    23. Slide 23 Growth in manufacturing output and use of natural gas reflect high natural gas supply and low prices, particularly in near term
    24. Slide 24 Projected U.S. natural gas exports reflect the spread between domestic natural gas prices and world energy prices
    25. Slide 25 Electricity
    26. Slide 26 Growth in electricity use slows, but electricity use still increases by 24% from 2013 to 2040
    27. Slide 27 Over time the electricity mix gradually shifts to lower-carbon options, led by growth in renewables and gas-fired generation 
    28. Slide 28 Non-hydro renewable generation grows to double hydropower generation by 2040
    29. Slide 29 Growth in wind and solar generation meets a significant portion of projected total electric load growth in all AEO2015 cases
    30. Slide 30 For more information
  4. Research Notes
    1. Data Owls
    2. Algorithms for Geospatial Data Analysis
    3. CCRi Offers GeoMesa for Geospatial Analysis on Google’s Newest Platform: Cloud Bigtable
  5. Annual Energy Outlook 2015
    1. Press Release
    2. Preface
      1. Endnotes
    3. Correction/Update
      1. 4/21/2015
    4. Executive Summary
      1. The future path of crude oil prices can vary substantially, depending on assumptions about the size of the resource and growth in demand, particularly in non-OECD countries
        1. Figure ES1 North Sea Brent crude oil prices in four cases, 2005-40
      2. Future natural gas prices will be influenced by a number of factors, including oil prices, resource availability, and demand for natural gas
        1. Figure ES2 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      3. Global growth and trade weaken beyond 2025, creating headwinds for U.S. export-oriented industries
        1. Table ES1. Growth of trade-related factors in the Reference case, 1983-2040
      4. U.S. net energy imports decline and ultimately end, largely in response to increased oil and dry natural gas production
        1. Figure ES3 U.S. net energy imports in six cases, 2005-40
      5. Continued strong growth in domestic production of crude oil from tight formations leads to a decline in net imports of crude oil and petroleum products
        1. Figure ES4 Net crude oil and petroleum products imports as a percentage of U.S. product supplied in four cases, 2005-40
      6. Net natural gas trade, including LNG exports, depends largely on the effects of resource levels and oil prices
        1. Figure ES5 U.S. total net natural gas imports in four cases, 2005-40
      7. Regional variations in domestic crude oil and dry natural gas production can force significant shifts in crude oil and natural gas flows between U.S. regions, requiring investment in or realignment of pipelines and other midstream infrastructure
        1. Figure ES6 Change in U.S. Lower 48 onshore crude oil production by region in six cases. 2013-40
      8. U.S. energy consumption grows at a modest rate over the projection with reductions in energy intensity resulting from improved technologies and from policies in place
        1. Figure ES7 Delivered energy consumption for transportation in six cases, 2008-40
      9. Industrial energy use rises with growth of shale gas supply
      10. Renewables meet much of the growth in electricity demand
        1. Figure ES8 Total U.S. renewable generation in all sectors by fuel in six cases, 2013 and 2040
      11. Electricity prices increase with rising fuel costs and expenditures on electric transmission and distribution infrastructure
      12. Energy-related CO2 emissions stabilize with improvements in the energy intensity and carbon intensity of electricity generation
      13. Endnotes
    5. Introduction
      1. Introduction
        1. Table 1. Summary of AEO2015 cases
      2. Changes in release cycle for EIA’s Annual Energy Outlook
      3. Endnotes
    6. Economic growth
      1. Introduction
        1. Table 2. Growth in key economic factors in historical data and in the Reference case
        2. Figure 1 Annual changes in U.S. gross domestic product, business investment, and exports in the Reference case, 2015-40
        3. Figure 2 Annual growth rates for industrial output in three cases, 2013-40
        4. Table 3. Average annual growth of labor productivity, employment, income, and consumption in three cases
      2. Endnotes
    7. Energy Prices
      1. Crude oil
        1. Figure 3 North Sea Brent crude oil prices in three cases, 2005-40
      2. Petroleum and other liquids products
        1. Figure 4 Motor gasoline prices in three cases, 2005-40
        2. Figure 5 Distillate fuel oil prices in three cases, 2005-40
      3. Natural Gas
        1. Figure 6 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      4. Coal
        1. Figure 7 Average minemouth coal prices by region in the Reference case, 1990-2040
        2. Figure 8 Average delivered coal prices in six cases, 1990-2040
      5. Electricity
        1. Figure 9 Average retail electricity prices in six cases, 2013-40
      6. Endnotes
    8. Delivered energy consumption by sector
      1. Transportation
        1. Figure 10 Delivered energy consunption for transportation by mode in the Reference case, 2013-and 2040
        2. Figure 11 Delivered energy consumption for transportation in six cases, 2008-40
      2. Future gasoline vehicles are strong competitors when compared with other vehicle technology types on the basis of fuel economics
        1. Figure Midsize passenger car fuel economy and vehicle price by technology type in the reference case, 2015-2040
      3. The Annual Energy Outlook 2015 includes several types of light-duty vehicle hybrid technology.
      4. Industrial
        1. Figure 12 Industrial sector total delivered energy consumption in three case, 2010-40
        2. Figure 13 Industrial sector natural gas consumption for heat and power in three cases, 2010-40
      5. Residential and commercial
        1. Figure 14 Residential sector delivered energy consumption by fuel in the reference case, 2010-40
        2. Figure 15 Commercial sector delivered energy consumption by fuel in the Reference case, 2010-40
        3. Table 4. Residential households and commercial indicators in three AEO2015 cases, 2013 and 2040
        4. Figure 16 Residential sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
        5. Figure 17 Commercial sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
      6. Endnotes
    9. Energy consumption by primary fuel
      1. Introduction
        1. Figure 18 Primary energy consumption by fuel in the Reference case, 1980-2040
    10. Energy intensity
      1. Introduction
        1. Figure 19 Energy use per capita and per 2009 dollar of gross domestic product, and carbon dioxide emissions per 2009 dollar of gross domestic product, in the Reference case, 1980-2040
    11. Energy production, imports, and exports
      1. Introduction
        1. Figure 20 Total energy production and consumption in the Reference case, 1980-2040
      2. Petroleum and other liquids
        1. Figure 21 U.S. light oil production in four cases, 2005-40
        2. Figure 22 U.S. total crude oil production in four cases, 2005-40
        3. Figure 23 U.S. net crude oil imports in four cases, 2005-40
        4. Figure 24 U.S. net petroleum product imports in four cases, 2005-40
      3. Natural gas
        1. Production
          1. Figure 25 U.S. total dry natural gas production in four cases, 2005-40
          2. Figure 26 U.S. shale gas production in four cases, 2005-40
        2. Imports and exports
          1. Figure 27 U.S. total natural gas net imports in four cases, 2005-40
          2. Figure 28 U.S. liquefied natural gas imports in four cases, 2005-40
      4. Coal
        1. Figure 29 U.S. coal production in six cases, 1990-2040
        2. Figure 30 U.S. coal exports in six cases, 1990-2040
      5. Endnotes
    12. Electricity generation
      1. Introduction
        1. Figure 31 Electricity generation by fuel in the reference case, 2000-2040
        2. Figure 32 Electricity generation by fuel in six cases, 2013 and 2040
        3. Figure 33 Coal and natural gas combined-cycle generation capacity factors in two cases, 2010-40
        4. Figure 34 Renewable electricity generation by fuel type in the reference case, 2000-2040
        5. Figure 35 Cumulative additions to electricity generation capacity by fuel in six cases 2013-40
      2. Endnotes
    13. Energy-related carbon dioxide emissions
      1. Introduction
        1. Figure 36 Energy-related carbon dioxide emissions in six cases, 2000-2040
        2. Figure 37 Energy-related carbon dioxide emissions by sector in the Reference case, 2005, 2013, 2025, and 2040
    14. Appendices
  6. Data Tables
    1. Supplemental tables for regional detail
      1. Regional energy consumption and prices by sector
      2. Residential, commericial, & industrial demand sector data tables
      3. Transportation demand sector data tables
      4. Electricity and renewable fuel tables
      5. Petroleum, natural gas, coal, and macroeconomic
  7. NEXT

Data Science for Energy Outlook 2015

Last modified
Table of contents
  1. Story
    1. Data Science for Energy Outlook 2015
    2. Slides
      1. Slide 1 Data Science for Energy Outlook 2015
      2. Slide 2 Data Community DC Data Owls
      3. Slide 3 Data Mining - Data Science – Data Publication Process
      4. Slide 4 Annual Energy Outlook 2015: Overview
      5. Slide 5 Annual Energy Outlook 2015: Data All Tables
      6. Slide 6 Annual Energy Outlook 2015: Executive Summary
      7. Slide 7 Interactive Table Viewer Beta Testing 1
      8. Slide 8 Interactive Table Viewer Beta Testing 2
      9. Slide 9 Data Science Data Publication: Knowledge Base
      10. Slide 10 Data Science Data Publication: Spreadsheet Index
      11. Slide 11 Data Science Data Publication: Web & PDF Tables to Spreadsheet
      12. Slide 12 Data Science Data Publication: Data Browser
      13. Slide 13 AEO2015 Figure ES-1 Spreadsheet
      14. Slide 14 AEO2015 Figure ES-1 Spreadsheet in Spotfire
      15. Slide 15 Data Science Data Publication: Dynamically Linked Adjacent Visualizations
      16. Slide 16 Conclusions and Recommedations
  2. Spotfire Dashboard
  3. Slides
    1. Slide 1 Annual Energy Outlook 2015
    2. Slide 2 Key results from AEO2015
    3. Slide 3 Key results from AEO2015 (continued)
    4. Slide 4 Overview
    5. Slide 5 Crude oil price projection is lower in the AEO2015 Reference case than in AEO2014, particularly in the near term
    6. Slide 6 Reductions in energy intensity largely offset impact of GDP growth, leading to slow projected growth in energy use
    7. Slide 7 U.S. net energy imports continue to decline in the near term, reflecting increased oil and natural gas production coupled with slow demand growth
    8. Slide 8 CO2 emissions are sensitive to the influence of future economic growth and energy price trends on energy consumption
    9. Slide 9 CO2 emissions per dollar of GDP decline faster than energy use per dollar of GDP with a shift towards lower-carbon fuels
    10. Slide 10 New AEO table browser
    11. Slide 11 Petroleum and other liquid supply
    12. Slide 12 AEO2015 explores scenarios that encompass a wide range of future crude oil price paths
    13. Slide 13 U.S. crude oil production rises above previous historical highs before 2020 in all AEO2015 cases, with a range of longer-term outcomes
    14. Slide 14 Growth of onshore crude oil production varies across supply regions, affecting pipeline and midstream infrastructure needs
    15. Slide 15 Combination of increased tight oil production and higher fuel efficiency drive projected decline in oil imports
    16. Slide 16 Net liquid imports provide a declining share of U.S. liquid fuels supply in most AEO2015 cases; in two cases the nation becomes a net exporter
    17. Slide 17 In the transportation sector, motor gasoline use declines; diesel fuel, jet fuel, and natural gas use all grow
    18. Slide 18 U.S. net exports of petroleum products vary with the level of domestic oil production given current limits on U.S. crude oil exports 
    19. Slide 19 Natural gas
    20. Slide 20 Future domestic natural gas prices depend on both domestic resource availability and world energy prices
    21. Slide 21 Shale resources remain the dominant source of U.S. natural gas production growth
    22. Slide 22 Natural gas consumption growth is driven by increased use in all sectors except residential
    23. Slide 23 Growth in manufacturing output and use of natural gas reflect high natural gas supply and low prices, particularly in near term
    24. Slide 24 Projected U.S. natural gas exports reflect the spread between domestic natural gas prices and world energy prices
    25. Slide 25 Electricity
    26. Slide 26 Growth in electricity use slows, but electricity use still increases by 24% from 2013 to 2040
    27. Slide 27 Over time the electricity mix gradually shifts to lower-carbon options, led by growth in renewables and gas-fired generation 
    28. Slide 28 Non-hydro renewable generation grows to double hydropower generation by 2040
    29. Slide 29 Growth in wind and solar generation meets a significant portion of projected total electric load growth in all AEO2015 cases
    30. Slide 30 For more information
  4. Research Notes
    1. Data Owls
    2. Algorithms for Geospatial Data Analysis
    3. CCRi Offers GeoMesa for Geospatial Analysis on Google’s Newest Platform: Cloud Bigtable
  5. Annual Energy Outlook 2015
    1. Press Release
    2. Preface
      1. Endnotes
    3. Correction/Update
      1. 4/21/2015
    4. Executive Summary
      1. The future path of crude oil prices can vary substantially, depending on assumptions about the size of the resource and growth in demand, particularly in non-OECD countries
        1. Figure ES1 North Sea Brent crude oil prices in four cases, 2005-40
      2. Future natural gas prices will be influenced by a number of factors, including oil prices, resource availability, and demand for natural gas
        1. Figure ES2 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      3. Global growth and trade weaken beyond 2025, creating headwinds for U.S. export-oriented industries
        1. Table ES1. Growth of trade-related factors in the Reference case, 1983-2040
      4. U.S. net energy imports decline and ultimately end, largely in response to increased oil and dry natural gas production
        1. Figure ES3 U.S. net energy imports in six cases, 2005-40
      5. Continued strong growth in domestic production of crude oil from tight formations leads to a decline in net imports of crude oil and petroleum products
        1. Figure ES4 Net crude oil and petroleum products imports as a percentage of U.S. product supplied in four cases, 2005-40
      6. Net natural gas trade, including LNG exports, depends largely on the effects of resource levels and oil prices
        1. Figure ES5 U.S. total net natural gas imports in four cases, 2005-40
      7. Regional variations in domestic crude oil and dry natural gas production can force significant shifts in crude oil and natural gas flows between U.S. regions, requiring investment in or realignment of pipelines and other midstream infrastructure
        1. Figure ES6 Change in U.S. Lower 48 onshore crude oil production by region in six cases. 2013-40
      8. U.S. energy consumption grows at a modest rate over the projection with reductions in energy intensity resulting from improved technologies and from policies in place
        1. Figure ES7 Delivered energy consumption for transportation in six cases, 2008-40
      9. Industrial energy use rises with growth of shale gas supply
      10. Renewables meet much of the growth in electricity demand
        1. Figure ES8 Total U.S. renewable generation in all sectors by fuel in six cases, 2013 and 2040
      11. Electricity prices increase with rising fuel costs and expenditures on electric transmission and distribution infrastructure
      12. Energy-related CO2 emissions stabilize with improvements in the energy intensity and carbon intensity of electricity generation
      13. Endnotes
    5. Introduction
      1. Introduction
        1. Table 1. Summary of AEO2015 cases
      2. Changes in release cycle for EIA’s Annual Energy Outlook
      3. Endnotes
    6. Economic growth
      1. Introduction
        1. Table 2. Growth in key economic factors in historical data and in the Reference case
        2. Figure 1 Annual changes in U.S. gross domestic product, business investment, and exports in the Reference case, 2015-40
        3. Figure 2 Annual growth rates for industrial output in three cases, 2013-40
        4. Table 3. Average annual growth of labor productivity, employment, income, and consumption in three cases
      2. Endnotes
    7. Energy Prices
      1. Crude oil
        1. Figure 3 North Sea Brent crude oil prices in three cases, 2005-40
      2. Petroleum and other liquids products
        1. Figure 4 Motor gasoline prices in three cases, 2005-40
        2. Figure 5 Distillate fuel oil prices in three cases, 2005-40
      3. Natural Gas
        1. Figure 6 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      4. Coal
        1. Figure 7 Average minemouth coal prices by region in the Reference case, 1990-2040
        2. Figure 8 Average delivered coal prices in six cases, 1990-2040
      5. Electricity
        1. Figure 9 Average retail electricity prices in six cases, 2013-40
      6. Endnotes
    8. Delivered energy consumption by sector
      1. Transportation
        1. Figure 10 Delivered energy consunption for transportation by mode in the Reference case, 2013-and 2040
        2. Figure 11 Delivered energy consumption for transportation in six cases, 2008-40
      2. Future gasoline vehicles are strong competitors when compared with other vehicle technology types on the basis of fuel economics
        1. Figure Midsize passenger car fuel economy and vehicle price by technology type in the reference case, 2015-2040
      3. The Annual Energy Outlook 2015 includes several types of light-duty vehicle hybrid technology.
      4. Industrial
        1. Figure 12 Industrial sector total delivered energy consumption in three case, 2010-40
        2. Figure 13 Industrial sector natural gas consumption for heat and power in three cases, 2010-40
      5. Residential and commercial
        1. Figure 14 Residential sector delivered energy consumption by fuel in the reference case, 2010-40
        2. Figure 15 Commercial sector delivered energy consumption by fuel in the Reference case, 2010-40
        3. Table 4. Residential households and commercial indicators in three AEO2015 cases, 2013 and 2040
        4. Figure 16 Residential sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
        5. Figure 17 Commercial sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
      6. Endnotes
    9. Energy consumption by primary fuel
      1. Introduction
        1. Figure 18 Primary energy consumption by fuel in the Reference case, 1980-2040
    10. Energy intensity
      1. Introduction
        1. Figure 19 Energy use per capita and per 2009 dollar of gross domestic product, and carbon dioxide emissions per 2009 dollar of gross domestic product, in the Reference case, 1980-2040
    11. Energy production, imports, and exports
      1. Introduction
        1. Figure 20 Total energy production and consumption in the Reference case, 1980-2040
      2. Petroleum and other liquids
        1. Figure 21 U.S. light oil production in four cases, 2005-40
        2. Figure 22 U.S. total crude oil production in four cases, 2005-40
        3. Figure 23 U.S. net crude oil imports in four cases, 2005-40
        4. Figure 24 U.S. net petroleum product imports in four cases, 2005-40
      3. Natural gas
        1. Production
          1. Figure 25 U.S. total dry natural gas production in four cases, 2005-40
          2. Figure 26 U.S. shale gas production in four cases, 2005-40
        2. Imports and exports
          1. Figure 27 U.S. total natural gas net imports in four cases, 2005-40
          2. Figure 28 U.S. liquefied natural gas imports in four cases, 2005-40
      4. Coal
        1. Figure 29 U.S. coal production in six cases, 1990-2040
        2. Figure 30 U.S. coal exports in six cases, 1990-2040
      5. Endnotes
    12. Electricity generation
      1. Introduction
        1. Figure 31 Electricity generation by fuel in the reference case, 2000-2040
        2. Figure 32 Electricity generation by fuel in six cases, 2013 and 2040
        3. Figure 33 Coal and natural gas combined-cycle generation capacity factors in two cases, 2010-40
        4. Figure 34 Renewable electricity generation by fuel type in the reference case, 2000-2040
        5. Figure 35 Cumulative additions to electricity generation capacity by fuel in six cases 2013-40
      2. Endnotes
    13. Energy-related carbon dioxide emissions
      1. Introduction
        1. Figure 36 Energy-related carbon dioxide emissions in six cases, 2000-2040
        2. Figure 37 Energy-related carbon dioxide emissions by sector in the Reference case, 2005, 2013, 2025, and 2040
    14. Appendices
  6. Data Tables
    1. Supplemental tables for regional detail
      1. Regional energy consumption and prices by sector
      2. Residential, commericial, & industrial demand sector data tables
      3. Transportation demand sector data tables
      4. Electricity and renewable fuel tables
      5. Petroleum, natural gas, coal, and macroeconomic
  7. NEXT

  1. Story
    1. Data Science for Energy Outlook 2015
    2. Slides
      1. Slide 1 Data Science for Energy Outlook 2015
      2. Slide 2 Data Community DC Data Owls
      3. Slide 3 Data Mining - Data Science – Data Publication Process
      4. Slide 4 Annual Energy Outlook 2015: Overview
      5. Slide 5 Annual Energy Outlook 2015: Data All Tables
      6. Slide 6 Annual Energy Outlook 2015: Executive Summary
      7. Slide 7 Interactive Table Viewer Beta Testing 1
      8. Slide 8 Interactive Table Viewer Beta Testing 2
      9. Slide 9 Data Science Data Publication: Knowledge Base
      10. Slide 10 Data Science Data Publication: Spreadsheet Index
      11. Slide 11 Data Science Data Publication: Web & PDF Tables to Spreadsheet
      12. Slide 12 Data Science Data Publication: Data Browser
      13. Slide 13 AEO2015 Figure ES-1 Spreadsheet
      14. Slide 14 AEO2015 Figure ES-1 Spreadsheet in Spotfire
      15. Slide 15 Data Science Data Publication: Dynamically Linked Adjacent Visualizations
      16. Slide 16 Conclusions and Recommedations
  2. Spotfire Dashboard
  3. Slides
    1. Slide 1 Annual Energy Outlook 2015
    2. Slide 2 Key results from AEO2015
    3. Slide 3 Key results from AEO2015 (continued)
    4. Slide 4 Overview
    5. Slide 5 Crude oil price projection is lower in the AEO2015 Reference case than in AEO2014, particularly in the near term
    6. Slide 6 Reductions in energy intensity largely offset impact of GDP growth, leading to slow projected growth in energy use
    7. Slide 7 U.S. net energy imports continue to decline in the near term, reflecting increased oil and natural gas production coupled with slow demand growth
    8. Slide 8 CO2 emissions are sensitive to the influence of future economic growth and energy price trends on energy consumption
    9. Slide 9 CO2 emissions per dollar of GDP decline faster than energy use per dollar of GDP with a shift towards lower-carbon fuels
    10. Slide 10 New AEO table browser
    11. Slide 11 Petroleum and other liquid supply
    12. Slide 12 AEO2015 explores scenarios that encompass a wide range of future crude oil price paths
    13. Slide 13 U.S. crude oil production rises above previous historical highs before 2020 in all AEO2015 cases, with a range of longer-term outcomes
    14. Slide 14 Growth of onshore crude oil production varies across supply regions, affecting pipeline and midstream infrastructure needs
    15. Slide 15 Combination of increased tight oil production and higher fuel efficiency drive projected decline in oil imports
    16. Slide 16 Net liquid imports provide a declining share of U.S. liquid fuels supply in most AEO2015 cases; in two cases the nation becomes a net exporter
    17. Slide 17 In the transportation sector, motor gasoline use declines; diesel fuel, jet fuel, and natural gas use all grow
    18. Slide 18 U.S. net exports of petroleum products vary with the level of domestic oil production given current limits on U.S. crude oil exports 
    19. Slide 19 Natural gas
    20. Slide 20 Future domestic natural gas prices depend on both domestic resource availability and world energy prices
    21. Slide 21 Shale resources remain the dominant source of U.S. natural gas production growth
    22. Slide 22 Natural gas consumption growth is driven by increased use in all sectors except residential
    23. Slide 23 Growth in manufacturing output and use of natural gas reflect high natural gas supply and low prices, particularly in near term
    24. Slide 24 Projected U.S. natural gas exports reflect the spread between domestic natural gas prices and world energy prices
    25. Slide 25 Electricity
    26. Slide 26 Growth in electricity use slows, but electricity use still increases by 24% from 2013 to 2040
    27. Slide 27 Over time the electricity mix gradually shifts to lower-carbon options, led by growth in renewables and gas-fired generation 
    28. Slide 28 Non-hydro renewable generation grows to double hydropower generation by 2040
    29. Slide 29 Growth in wind and solar generation meets a significant portion of projected total electric load growth in all AEO2015 cases
    30. Slide 30 For more information
  4. Research Notes
    1. Data Owls
    2. Algorithms for Geospatial Data Analysis
    3. CCRi Offers GeoMesa for Geospatial Analysis on Google’s Newest Platform: Cloud Bigtable
  5. Annual Energy Outlook 2015
    1. Press Release
    2. Preface
      1. Endnotes
    3. Correction/Update
      1. 4/21/2015
    4. Executive Summary
      1. The future path of crude oil prices can vary substantially, depending on assumptions about the size of the resource and growth in demand, particularly in non-OECD countries
        1. Figure ES1 North Sea Brent crude oil prices in four cases, 2005-40
      2. Future natural gas prices will be influenced by a number of factors, including oil prices, resource availability, and demand for natural gas
        1. Figure ES2 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      3. Global growth and trade weaken beyond 2025, creating headwinds for U.S. export-oriented industries
        1. Table ES1. Growth of trade-related factors in the Reference case, 1983-2040
      4. U.S. net energy imports decline and ultimately end, largely in response to increased oil and dry natural gas production
        1. Figure ES3 U.S. net energy imports in six cases, 2005-40
      5. Continued strong growth in domestic production of crude oil from tight formations leads to a decline in net imports of crude oil and petroleum products
        1. Figure ES4 Net crude oil and petroleum products imports as a percentage of U.S. product supplied in four cases, 2005-40
      6. Net natural gas trade, including LNG exports, depends largely on the effects of resource levels and oil prices
        1. Figure ES5 U.S. total net natural gas imports in four cases, 2005-40
      7. Regional variations in domestic crude oil and dry natural gas production can force significant shifts in crude oil and natural gas flows between U.S. regions, requiring investment in or realignment of pipelines and other midstream infrastructure
        1. Figure ES6 Change in U.S. Lower 48 onshore crude oil production by region in six cases. 2013-40
      8. U.S. energy consumption grows at a modest rate over the projection with reductions in energy intensity resulting from improved technologies and from policies in place
        1. Figure ES7 Delivered energy consumption for transportation in six cases, 2008-40
      9. Industrial energy use rises with growth of shale gas supply
      10. Renewables meet much of the growth in electricity demand
        1. Figure ES8 Total U.S. renewable generation in all sectors by fuel in six cases, 2013 and 2040
      11. Electricity prices increase with rising fuel costs and expenditures on electric transmission and distribution infrastructure
      12. Energy-related CO2 emissions stabilize with improvements in the energy intensity and carbon intensity of electricity generation
      13. Endnotes
    5. Introduction
      1. Introduction
        1. Table 1. Summary of AEO2015 cases
      2. Changes in release cycle for EIA’s Annual Energy Outlook
      3. Endnotes
    6. Economic growth
      1. Introduction
        1. Table 2. Growth in key economic factors in historical data and in the Reference case
        2. Figure 1 Annual changes in U.S. gross domestic product, business investment, and exports in the Reference case, 2015-40
        3. Figure 2 Annual growth rates for industrial output in three cases, 2013-40
        4. Table 3. Average annual growth of labor productivity, employment, income, and consumption in three cases
      2. Endnotes
    7. Energy Prices
      1. Crude oil
        1. Figure 3 North Sea Brent crude oil prices in three cases, 2005-40
      2. Petroleum and other liquids products
        1. Figure 4 Motor gasoline prices in three cases, 2005-40
        2. Figure 5 Distillate fuel oil prices in three cases, 2005-40
      3. Natural Gas
        1. Figure 6 Average Henry Hub spot prices for natural gas in four cases, 2005-40
      4. Coal
        1. Figure 7 Average minemouth coal prices by region in the Reference case, 1990-2040
        2. Figure 8 Average delivered coal prices in six cases, 1990-2040
      5. Electricity
        1. Figure 9 Average retail electricity prices in six cases, 2013-40
      6. Endnotes
    8. Delivered energy consumption by sector
      1. Transportation
        1. Figure 10 Delivered energy consunption for transportation by mode in the Reference case, 2013-and 2040
        2. Figure 11 Delivered energy consumption for transportation in six cases, 2008-40
      2. Future gasoline vehicles are strong competitors when compared with other vehicle technology types on the basis of fuel economics
        1. Figure Midsize passenger car fuel economy and vehicle price by technology type in the reference case, 2015-2040
      3. The Annual Energy Outlook 2015 includes several types of light-duty vehicle hybrid technology.
      4. Industrial
        1. Figure 12 Industrial sector total delivered energy consumption in three case, 2010-40
        2. Figure 13 Industrial sector natural gas consumption for heat and power in three cases, 2010-40
      5. Residential and commercial
        1. Figure 14 Residential sector delivered energy consumption by fuel in the reference case, 2010-40
        2. Figure 15 Commercial sector delivered energy consumption by fuel in the Reference case, 2010-40
        3. Table 4. Residential households and commercial indicators in three AEO2015 cases, 2013 and 2040
        4. Figure 16 Residential sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
        5. Figure 17 Commercial sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040
      6. Endnotes
    9. Energy consumption by primary fuel
      1. Introduction
        1. Figure 18 Primary energy consumption by fuel in the Reference case, 1980-2040
    10. Energy intensity
      1. Introduction
        1. Figure 19 Energy use per capita and per 2009 dollar of gross domestic product, and carbon dioxide emissions per 2009 dollar of gross domestic product, in the Reference case, 1980-2040
    11. Energy production, imports, and exports
      1. Introduction
        1. Figure 20 Total energy production and consumption in the Reference case, 1980-2040
      2. Petroleum and other liquids
        1. Figure 21 U.S. light oil production in four cases, 2005-40
        2. Figure 22 U.S. total crude oil production in four cases, 2005-40
        3. Figure 23 U.S. net crude oil imports in four cases, 2005-40
        4. Figure 24 U.S. net petroleum product imports in four cases, 2005-40
      3. Natural gas
        1. Production
          1. Figure 25 U.S. total dry natural gas production in four cases, 2005-40
          2. Figure 26 U.S. shale gas production in four cases, 2005-40
        2. Imports and exports
          1. Figure 27 U.S. total natural gas net imports in four cases, 2005-40
          2. Figure 28 U.S. liquefied natural gas imports in four cases, 2005-40
      4. Coal
        1. Figure 29 U.S. coal production in six cases, 1990-2040
        2. Figure 30 U.S. coal exports in six cases, 1990-2040
      5. Endnotes
    12. Electricity generation
      1. Introduction
        1. Figure 31 Electricity generation by fuel in the reference case, 2000-2040
        2. Figure 32 Electricity generation by fuel in six cases, 2013 and 2040
        3. Figure 33 Coal and natural gas combined-cycle generation capacity factors in two cases, 2010-40
        4. Figure 34 Renewable electricity generation by fuel type in the reference case, 2000-2040
        5. Figure 35 Cumulative additions to electricity generation capacity by fuel in six cases 2013-40
      2. Endnotes
    13. Energy-related carbon dioxide emissions
      1. Introduction
        1. Figure 36 Energy-related carbon dioxide emissions in six cases, 2000-2040
        2. Figure 37 Energy-related carbon dioxide emissions by sector in the Reference case, 2005, 2013, 2025, and 2040
    14. Appendices
  6. Data Tables
    1. Supplemental tables for regional detail
      1. Regional energy consumption and prices by sector
      2. Residential, commericial, & industrial demand sector data tables
      3. Transportation demand sector data tables
      4. Electricity and renewable fuel tables
      5. Petroleum, natural gas, coal, and macroeconomic
  7. NEXT

Story

Data Science for Energy Outlook 2015

I am working on an OSTP/NSF Data Science Meetup of Meetups with Harlan Harris and Tony Ojeda, Organizers of the DC Data Community Meetup, so I thought I should attend their Meetups: Data Owls and Algorithms for Geospatial Data Analysis, this week and learn what they do in their Meetups.

Since the subject is Open Government Energy Data Sets and using spatial graph analysis to model the US fuel energy infrastructure for the Department of Energy, I thought I would work with the Department of Energy Annual Energy Outlook 2015 since it provides Web, PDF, and Excel files to work with in MindTouch and Spotfire to produce a Data Science Data Publication in a Data Browser.

The purpose of doing this additional work (data science) instead of just visualizations, is to provide a structured context for the data, a data viewer for the multiple data sources, and for the multiple visualizations.

The results are shown below:

Slides

Spotfire Dashboard (which contains two Excel spreadsheets: AEO2015 and AEO2015yearbyyear)

More To Follow

ADD MY COMMENTS

Slides

Slides

Slide 1 Data Science for Energy Outlook 2015

Semantic Community

Data Science

Data Science for Energy Outlook 2015

BrandNiemann07302015Slide1.PNG

Slide 3 Data Mining - Data Science – Data Publication Process

BrandNiemann07302015Slide3.PNG

Slide 4 Annual Energy Outlook 2015: Overview

http://www.eia.gov/forecasts/aeo/index.cfm

BrandNiemann07302015Slide4.PNG

Slide 5 Annual Energy Outlook 2015: Data All Tables

http://www.eia.gov/forecasts/aeo/tables_ref.cfm

BrandNiemann07302015Slide5.PNG

Slide 6 Annual Energy Outlook 2015: Executive Summary

http://www.eia.gov/forecasts/aeo/executive_summary.cfm

BrandNiemann07302015Slide6.PNG

Slide 7 Interactive Table Viewer Beta Testing 1

http://www.eia.gov/oiaf/aeo/tablebrowser

BrandNiemann07302015Slide7.PNG

Slide 8 Interactive Table Viewer Beta Testing 2

http://www.eia.gov/beta/aeo

BrandNiemann07302015Slide8.PNG

Slide 9 Data Science Data Publication: Knowledge Base

http://semanticommunity.info/Data_Sc...y_Outlook_2015

BrandNiemann07302015Slide9.PNG

Slide 10 Data Science Data Publication: Spreadsheet Index

AEO2015.xlsx

BrandNiemann07302015Slide10.PNG

Slide 11 Data Science Data Publication: Web & PDF Tables to Spreadsheet

AEO2015.xlsx

BrandNiemann07302015Slide11.PNG

Slide 12 Data Science Data Publication: Data Browser

Web Player

BrandNiemann07302015Slide12.PNG

Slide 13 AEO2015 Figure ES-1 Spreadsheet

fig-es1_data.xls

BrandNiemann07302015Slide13.PNG

Slide 14 AEO2015 Figure ES-1 Spreadsheet in Spotfire

Web Player

BrandNiemann07302015Slide14.PNG

Slide 15 Data Science Data Publication: Dynamically Linked Adjacent Visualizations

Web Player

BrandNiemann07302015Slide15.PNG

Slide 16 Conclusions and Recommedations

BrandNiemann07302015Slide16.PNG

Spotfire Dashboard

For Internet Explorer Users and Those Wanting Full Screen Display Use: Web Player Get Spotfire for iPad App

Error: Embedded data could not be displayed. Use Google Chrome

Slides

Slides

Slide 1 Annual Energy Outlook 2015

aeo2015_rolloutpresSlide1.PNG

Slide 2 Key results from AEO2015

aeo2015_rolloutpresSlide2.PNG

Slide 3 Key results from AEO2015 (continued)

aeo2015_rolloutpresSlide3.PNG

Slide 4 Overview

aeo2015_rolloutpresSlide4.PNG

Slide 5 Crude oil price projection is lower in the AEO2015 Reference case than in AEO2014, particularly in the near term

aeo2015_rolloutpresSlide5.PNG

Slide 6 Reductions in energy intensity largely offset impact of GDP growth, leading to slow projected growth in energy use

aeo2015_rolloutpresSlide6.PNG

Slide 7 U.S. net energy imports continue to decline in the near term, reflecting increased oil and natural gas production coupled with slow demand growth

aeo2015_rolloutpresSlide7.PNG

Slide 8 CO2 emissions are sensitive to the influence of future economic growth and energy price trends on energy consumption

aeo2015_rolloutpresSlide8.PNG

Slide 9 CO2 emissions per dollar of GDP decline faster than energy use per dollar of GDP with a shift towards lower-carbon fuels

aeo2015_rolloutpresSlide9.PNG

Slide 10 New AEO table browser

aeo2015_rolloutpresSlide10.PNG

Slide 11 Petroleum and other liquid supply

aeo2015_rolloutpresSlide11.PNG

Slide 12 AEO2015 explores scenarios that encompass a wide range of future crude oil price paths

aeo2015_rolloutpresSlide12.PNG

Slide 13 U.S. crude oil production rises above previous historical highs before 2020 in all AEO2015 cases, with a range of longer-term outcomes

aeo2015_rolloutpresSlide13.PNG

Slide 14 Growth of onshore crude oil production varies across supply regions, affecting pipeline and midstream infrastructure needs

aeo2015_rolloutpresSlide14.PNG

Slide 15 Combination of increased tight oil production and higher fuel efficiency drive projected decline in oil imports

aeo2015_rolloutpresSlide15.PNG

Slide 16 Net liquid imports provide a declining share of U.S. liquid fuels supply in most AEO2015 cases; in two cases the nation becomes a net exporter

aeo2015_rolloutpresSlide16.PNG

Slide 17 In the transportation sector, motor gasoline use declines; diesel fuel, jet fuel, and natural gas use all grow

aeo2015_rolloutpresSlide17.PNG

Slide 18 U.S. net exports of petroleum products vary with the level of domestic oil production given current limits on U.S. crude oil exports 

aeo2015_rolloutpresSlide18.PNG

Slide 19 Natural gas

aeo2015_rolloutpresSlide19.PNG

Slide 20 Future domestic natural gas prices depend on both domestic resource availability and world energy prices

aeo2015_rolloutpresSlide20.PNG

Slide 21 Shale resources remain the dominant source of U.S. natural gas production growth

aeo2015_rolloutpresSlide21.PNG

Slide 22 Natural gas consumption growth is driven by increased use in all sectors except residential

aeo2015_rolloutpresSlide22.PNG

Slide 23 Growth in manufacturing output and use of natural gas reflect high natural gas supply and low prices, particularly in near term

aeo2015_rolloutpresSlide23.PNG

Slide 24 Projected U.S. natural gas exports reflect the spread between domestic natural gas prices and world energy prices

aeo2015_rolloutpresSlide24.PNG

Slide 25 Electricity

aeo2015_rolloutpresSlide25.PNG

Slide 26 Growth in electricity use slows, but electricity use still increases by 24% from 2013 to 2040

aeo2015_rolloutpresSlide26.PNG

Slide 27 Over time the electricity mix gradually shifts to lower-carbon options, led by growth in renewables and gas-fired generation 

aeo2015_rolloutpresSlide27.PNG

Slide 28 Non-hydro renewable generation grows to double hydropower generation by 2040

aeo2015_rolloutpresSlide28.PNG

Slide 29 Growth in wind and solar generation meets a significant portion of projected total electric load growth in all AEO2015 cases

aeo2015_rolloutpresSlide29.PNG

Slide 30 For more information

U.S. Energy Information Administration home page: http://www.eia.gov
Annual Energy Outlook: http://www.eia.gov/forecasts/aeo
Short-Term Energy Outlook: http://www.eia.gov/forecasts/steo
International Energy Outlook: http://www.eia.gov/forecasts/ieo
Today In Energy: http://www.eia.gov/todayinenergy
Monthly Energy Review: http://www.eia.gov/totalenergy/data/monthly
State Energy Portal: http://www.eia.gov/state 
Drilling Productivity Report: http://www.eia.gov/petroleum/drilling

aeo2015_rolloutpresSlide30.PNG

Research Notes

Data Owls

Source: http://www.meetup.com/Data-Community...nts/224145888/

Thursday, July 30, 2015

8:00 PM

WeWork

641 S St NW, Washington, DC (map)

Adding to the typical Data Owls is a special request from a frequent Data Owl to focus on energy related government open datasets, specifically:

http://energy.gov/data/open-energy-data 
http://catalyst.energy.gov/ 
http://energychallenge.energy.gov/ 
http://www.data.gov/energy/ 
http://catalyst.energy.gov/a/ideas/recent/campaigns/6952

So if you'd like to explore some MASSIVE government energy datasets with your fellow DC data geeks, or you have your own project, let's hack together for a while.

Algorithms for Geospatial Data Analysis

Source: http://www.meetup.com/Data-Science-D...nts/223875087/

Wednesday, July 29, 2015

6:30 PM to 8:30 PM

GWU, Funger Hall, Room 103

2201 G St. NW, Washington, DC (map)

For the July Data Science DC Meetup we're having a themed evening where we'll look at the intersection of data science with mapping and spatial analysis. We will feature two presentations - the first by Anthony Fox from CCRI, who will discuss GeoMesa and how they analyze high-velocity streaming spatio-temporal data.  The second speaker is Jason Dalton of Azimuth1, who will discuss using spatial graph analysis to model the US fuel energy infrastructure for the Dept of Energy.

Agenda:

  • 6:30pm -- Networking, Empanadas, and Refreshments
  • 7:00pm -- Introduction, Announcements
  • 7:15pm -- Presentation and Discussion
  • 8:30pm -- Data Drinks (Tonic, 2036 G St NW)

Abstracts:

Anthony Fox - In this presentation, Anthony will describe several examples of high-velocity streaming spatio-temporal data.  He will highlight challenges faced when dealing with these types of data and some techniques for addressing these challenges.  These techniques revolve around indexing, distributed computation, and visualization with the GeoMesa platform.  

Anthony is Director of Data Science and System Architecture at Commonwealth Computer Research, Inc., where he specializes in scaling compute intensive statistical algorithms using distributed systems. He is the lead developer on GeoMesa, a LocationTech open-source project that brings OGC compliant spatial support to the Accumulo distributed database. Follow Anthony on Twitter @algoriffic

Jason Dalton - By combining graph and geospatial analytics we describe the flow of oil, gas, and other petroleum products around the country with a high degree of accuracy.  These techniques allow us to determine the causes of price spikes, and determine areas that have a weak supply chain and may be particularly vulnerable to future price spikes. 

Jason is Founder and CEO of Azimuth1. Follow him on Twitter @jasonrdalton.

CCRi Offers GeoMesa for Geospatial Analysis on Google’s Newest Platform: Cloud Bigtable

Source: http://www.ccri.com/2015/05/06/ccri-...loud-bigtable/

 

CCRi in collaboration with Google, Inc., has announced the initial release of GeoMesa for Google Cloud Bigtable.
GeoMesa is an open-source system that quickly stores, indexes, and queries hundreds of billions of geospatial features in a distributed (i.e. cloud) database.

GeoMesa’s novel indexing strategy effectively distributes the data across, utilizing the full processing power of the cloud for writing and querying. This index keys on both spatial and temporal attributes to support mapping and analytical functions. GeoMesa’s innovative approach makes it the leading open-source solution for storing big spatial data in the cloud.

Distributed databases already enable developers to store “big data” in the cloud, but without a spatial adapter like GeoMesa, they cannot effectively take advantage of the inherent spatial attributes of the data. GeoMesa works on top of distributed data stores to facilitate spatial analysis. This means developers can query for events that occurred within 4 miles of a location, for example, or within the bounds of a specific polygon (e.g. inside the state of Virginia).

GeoMesa supports the Open Geospatial Consortium (OGC) standards so developers can easily migrate existing systems or build new systems on top of GeoMesa. Developers familiar with GeoServer or the OpenGeo Suite can use the GeoMesa plugin to add new data stores backed by Google Cloud Bigtable.

By using Google Cloud Bigtable to back GeoMesa, developers are freed from the need to stand up and maintain complex cloud computing environments. These environments are not only expensive to build, but they require highly-trained DevOps Engineers to maintain them and grow them as the data accumulates.

CCRi is a data science corporation focused on designing and implementing sophisticated analytical tools to answer important questions for its clients. CCRi also offers professional support packages to stand-up and support GeoMesa. GeoMesa is an open-source system offered through the Eclipse Foundation’s LocationTech Working group. For more information on GeoMesa, see www.geomesa.org. For more information on Google Cloud Bigtable, see http://cloud.google.com/bigtable.

Annual Energy Outlook 2015

Source: http://www.eia.gov/forecasts/aeo/index.cfm

My Note: I need to finish the End Notes

Release Date: April 14, 2015   |  Next Release Date: March 2016 |  CORRECTION (My Note: See below) |  full report (PDF)

presents yearly projections and analysis of energy topics
aeo_tie.png

Download the AEO2015 Report

Projections in the Annual Energy Outlook 2015 (AEO2015) focus on the factors expected to shape U.S. energy markets through 2040. The projections provide a basis for examination and discussion of energy market trends and serve as a starting point for analysis of potential changes in U.S. energy policies, rules, and regulations, as well as the potential role of advanced technologies.

Press Release

Source: http://www.eia.gov/pressroom/releases/press420.cfm

U.S. ENERGY INFORMATION ADMINISTRATION
WASHINGTON DC 20585

FOR IMMEDIATE RELEASE
April 14, 2015

EIA's AEO2015 projects that U.S. energy imports and exports come into balance, a first since the 1950s, because of continued oil and natural gas production growth and slow growth in energy demand

The Annual Energy Outlook 2015 (AEO2015) released today by the U.S. Energy Information Administration (EIA) presents updated projections for U.S. energy markets through 2040 based on six cases (Reference, Low and High Economic Growth, Low and High Oil Price, and High Oil and Gas Resource) that reflect updated scenarios for future crude oil prices.

"EIA's AEO2015 shows that the advanced technologies are reshaping the U.S. energy economy," said EIA Administrator Adam Sieminski. "With continued growth in oil and natural gas production, growth in the use of renewables, and the application of demand-side efficiencies, the projections show the potential to eliminate net U.S. energy imports in the 2020 to 2030 timeframe. The United States has been a net importer of energy since the 1950s. In cases with the highest supply and lowest demand outlooks, the United States becomes a significant net exporter of energy," said Mr. Sieminski.

Some key findings:

Figure 2 Graph

U.S. net energy imports decline and ultimately end in most AEO2015 cases, driven by growth in U.S. energy production—led by crude oil and natural gas—increased use of renewables, and only modest growth in demand. Net energy imports end before 2030 in the AEO2015 Reference case and before 2020 in the High Oil Price and High Oil and Gas Resource cases (Figure 1). Significant net energy imports persist only in the Low Oil Price and High Economic Growth cases, where U.S. supply is lower and demand is higher.

Continued strong growth in domestic production of crude oil from tight formations reduces net imports of petroleum and other liquids. Through 2020, strong growth in domestic crude oil production from tight formations leads to a decline in net petroleum imports and growth in product exports in all AEO2015 cases. The net import share of petroleum and other liquids product supplied falls from 26% in 2014 to 15% in 2025 and then rises slightly to 17% in 2040 in the Reference case. With greater U.S. crude oil production in the High Oil Price and High Oil and Gas Resource cases, the United States becomes a net petroleum exporter after 2020.

Figure 2 Graph

Regional variations in domestic crude oil and natural gas production can force significant shifts in crude oil and natural gas flows between U.S. regions, requiring investment in or realignment of pipelines and other midstream infrastructure. In most AEO2015 cases, Lower 48 crude oil production shows the strongest growth in the Dakotas/Rocky Mountains region, followed by the Southwest region (Figure 2). The strongest growth of natural gas production occurs in the East region, followed by the Gulf Coast onshore and the Dakotas/Rocky Mountains regions. Interregional flows to serve downstream markets vary significantly among the cases.

Technology and policy promote slower growth of energy demand. U.S. energy use grows at 0.3%/year from 2013 through 2040 in the Reference case, far below the rates of economic growth (2.4%/year) and population growth (0.7%/year). Decreases in transportation and residential sector energy consumption partially offset growth in other sectors. Declines in energy use reflect the use of more energy-efficient technologies as well as the effect of existing policies that promote increased energy efficiency. Fuel economy standards and changing driver behavior keep motor gasoline consumption below recent levels through 2040 in the Reference case.

Figure 2 Graph

Renewables meet much of the growth in electricity demand. Rising long-term natural gas prices, the high capital costs of newcoal and nuclear generation capacity, state-level policies, and cost reductions for renewable generation in a market characterized by relatively slow electricity demand growth favor increased use of renewables (Figure 3).

Energy-related carbon dioxide emissions stabilize with improvements in energy and carbon intensity of electricity generation. Improved efficiency in the end-use sectors and a shift away from more carbon-intensive fuels help to stabilize U.S. energy-related carbon dioxide (CO2) emissions, which remain below the 2005 level through 2040.

 

Other AEO2015 highlights:

 

Figure 2 Graph

  • In the AEO2015 Reference case, the price of global marker Brent crude oil is $56/barrel (bbl) (in 2013 dollars) in 2015 (Figure 4). Prices rise steadily after 2015 in response to growth in demand; however, downward price pressure from rising U.S. crude oil production keeps the Brent price below $80/bbl through 2020. U.S. crude oil production starts to decline after 2020, but increased output from non-OECD and OPEC producers helps to keep the Brent price below $100/bbl through most of the next decade and limits price increases through 2040, when Brent reaches roughly $140/bbl. There is significant variation in the alternative cases. In the Low Oil Price case, the Brent price is $52/bbl in 2015 and reaches $76/bbl in 2040. In the High Oil Price case, the Brent price reaches $252/bbl in 2040. In the High Oil and Gas Resource case, with significantly more U.S. production than the Reference case, Brent is under $130/bbl in 2040, more than $10/bbl below its Reference case price.

  • Total U.S. primary energy consumption grows from 97.1 quadrillion Btu in 2013 to 105.7 quadrillion Btu in 2040 in the AEO2015 Reference case with most of the growth in natural gas and renewable energy use. In the High Oil Price case, total primary energy use is 3.9 quadrillion Btu higher in 2040 than in the Reference case, even though liquids consumption is 3.3 quadrillion Btu lower. Total primary energy consumption is very sensitive to economic growth assumptions, with projected levels in 2040 ranging from 98.0 quadrillion Btu in the Low Economic Growth case to 116.2 quadrillion Btu in the High Economic Growth case.
  • In the AEO2015 Reference case, energy use per dollar of GDP declines at an annual rate of 2.0% from 2013 through 2040, as per capita energy use declines at an annual rate of 0.4%. Energy intensity declines at a lower rate in the Low Economic Growth case and at a slightly higher rate in the High Economic Growth case.
  • In the AEO2015 Reference case projection, U.S. energy-related CO2 emissions are roughly 5,550 million metric tons (mt) in 2040. As renewable fuels and natural gas account for larger shares of total energy consumption, CO2 emissions per unit of GDP decline by 2.3%/year from 2013 to 2040. Among the alternative cases, emissions show the greatest sensitivity to levels of economic growth, with 2040 totals varying from roughly 5,980 million mt in the High Economic Growth case to 5,160 million mt in the Low Economic Growth case. In all the AEO2015 cases, emissions remain below the 2005 level of 5,993 million mt.
  • The AEO2015 cases generally reflect current policies, including final regulations and the sunset of tax credits under current law. Consistent with this approach, EPA’s proposed Clean Power Plan rules for existing fossil-fired electric generating units or the effects of relaxing current limits on crude oil exports are not considered in AEO2015. These topics will be addressed in forthcoming EIA service reports.

To focus more resources on rapidly changing energy markets and the ways in which they might evolve over the next few years, EIA has revised the schedule and approach for production of the AEO. Starting with AEO2015, EIA is adopting a two-year release cycle for the AEO, with a full edition of the AEO produced in alternating years and a shorter edition in the other years. AEO2015 is a shorter edition of the AEO. The projections from the AEO2015 Reference and alternative cases are available at http://www.eia.gov/forecasts/aeo/.

 
The product described in this press release 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, analysis, and forecasts are independent of approval by any other officer or employee of the United States Government. The views in the product and press release therefore should not be construed as representing those of the Department of Energy or other federal agencies.

EIA Program Contact: John Conti, 202-586-2222, john.conti@eia.gov

EIA Press Contact: Jonathan Cogan, 202-586-8719, jonathan.cogan@eia.gov

EIA-2015-03

Preface

Source: http://www.eia.gov/forecasts/aeo/preface.cfm

The Annual Energy Outlook 2015 (AEO2015), prepared by the U.S. Energy Information Administration (EIA), presents long-term annual projections of energy supply, demand, and prices through 2040. The projections, focused on U.S. energy markets, are based on results from EIA’s National Energy Modeling System (NEMS). NEMS enables EIA to make projections under alternative, internally-consistent sets of assumptions, the results of which are presented as cases. The analysis in AEO2015 focuses on six cases: Reference case, Low and High Economic Growth cases, Low and High Oil Price cases, and High Oil and Gas Resource case.

For the first time, the Annual Energy Outlook (AEO) is presented as a shorter edition under a newly adopted two-year release cycle. With this approach, full editions and shorter editions of the AEO will be produced in alternating years. This approach will allow EIA to focus more resources on rapidly changing energy markets both in the United States and internationally and how they might evolve over the next few years. The shorter edition of the AEO includes a more limited number of model updates, predominantly to reflect historical data updates and changes in legislation and regulation. The AEO shorter editions will include this publication, which discusses the Reference case and five alternative cases, and an accompanying Assumptions Report.[1] Other documentation— including documentation for each of the NEMS models and a Retrospective Review—will be completed only in years when the full edition of the AEO is published.

This AEO2015 report includes the following major sections:

  • Executive summary, highlighting key results of the projections
  • Economic growth, discussing the economic outlooks completed for each of the AEO2015 cases
  • Energy prices, discussing trends in the markets and prices for crude oil, petroleum and other liquids, [2] natural gas, coal, and electricity for each of the AEO2015 cases
  • Energy consumption by primary fuel, discussing trends in energy consumption by fuel, including natural gas, renewables, coal, nuclear, liquid biofuels, and oil and other liquids
  • Energy intensity, examining trends in energy use per capita, energy use per 2009 dollar of gross domestic product (GDP), and carbon dioxide (CO2) emissions per 2009 dollar of GDP
  • Energy production, imports, and exports, examining production, import, and export trends for petroleum and other liquids, natural gas, and coal
  • Electricity generation, discussing trends in electricity generation by fuel and prime mover for each of the AEO2015 cases
  • Energy-related CO2 emissions, examining trends in CO2 emissions by sector and AEO2015 case.

Summary tables for the six cases are provided in Appendixes A through D. Complete tables are available in a table browser on EIA's website, at http://www.eia.gov/oiaf/aeo/tablebrowser. Appendix E provides a short discussion of the major changes adopted in AEO2015 and a brief comparison of the AEO2015 and Annual Energy Outlook 2014 results. Appendix F provides a summary of the regional formats, and Appendix G provides a summary of the energy conversion factors used in AEO2015.

The AEO2015 projections are based generally on federal, state, and local laws and regulations in effect as of the end of October 2014. 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 (for example, the proposed Clean Power Plan[3]). In certain situations, however, where it is clear that a law or a regulation will take effect shortly after AEO2015 is completed, it may be considered in the projection.

AEO2015 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 EIA are not statements of what will happen but of what might happen, given the assumptions and methodologies used for any particular case. The AEO2015 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 cases with different macroeconomic growth rates, world oil prices, and resource assumptions. The main cases in AEO2015 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. Some key uncertainties in the AEO2015 projections are addressed through alternative cases.

EIA has endeavored 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.

Endnotes

  1. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2015, DOE/EIA-0554(2015) (Washington, DC, to be published),http://www.eia.gov/forecasts/aeo/assumptions.
  2. Liquid fuels (or petroleum and other liquids) include crude oil and products of petroleum refining, natural gas liquids, biofuels, and liquids derived from other hydrocarbon sources (including coal-to-liquids and gas-to-liquids).
  3. U.S. Environmental Protection Agency, "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," Federal Register, pp. 34829-34958 (Washington, DC: June 18, 2014), https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollutionemission- guidelines-for-existing-stationary-sources-electric-utility-generating.

Correction/Update

Source: http://www.eia.gov/forecasts/aeo/correction.cfm

4/21/2015

  • The Energy price section under Electricity, two numbers were corrected as indicated by the following bold value:
    Eight paragraph, first sentence should read -"In the Reference case, new generation capacity added through the projection period includes 167 GW of natural gas capacity, 109GW..."
  • Figure 20 reference in the Energy production, imports, and exports section moved from the following sentence, to end of previous sentence:
    "From 2035 to 2040, energy exports account for about 23% of total annual U.S. energy production in the Reference case (Figure 20)."
  • The decline in net energy imports is projected to continue at a slower rate in the AEO2015 Reference case, with energy imports and exports coming into balance around 2028 (although liquid fuel imports continue, at a reduced level, throughout the Reference case) (Figure 20).
  • Vehicle prices in the Midsize passenger car figure are in 2013 dollars not 2012 dollars in the box in the Delivered energy consumption by sector section

Executive Summary

Source: http://www.eia.gov/forecasts/aeo/exe...ve_summary.cfm

Projections in the Annual Energy Outlook 2015 (AEO2015) focus on the factors expected to shape U.S. energy markets through 2040. The projections provide a basis for examination and discussion of energy market trends and serve as a starting point for analysis of potential changes in U.S. energy policies, rules, and regulations, as well as the potential role of advanced technologies.

Key results from the AEO2015 Reference and alternative cases include the following:

  • The future path of crude oil and natural gas prices can vary substantially, depending on assumptions about the size of global and domestic resources, demand for petroleum products and natural gas (particularly in non-Organization for Economic Cooperation and Development (non-OECD) countries), levels of production, and supplies of other fuels. AEO2015 considers these factors in examining alternative price and resource availability cases.
  • Growth in U.S. energy production—led by crude oil and natural gas—and only modest growth in demand reduces U.S. reliance on imported energy supplies. Energy imports and exports come into balance in the United States starting in 2028 in the AEO2015 Reference case and in 2019 in the High Oil Price and High Oil and Gas Resource cases. Natural gas is the dominant U.S. energy export, while liquid fuels [4] continue to be imported.
  • Through 2020, strong growth in domestic crude oil production from tight formations leads to a decline in net petroleum imports [5] and growth in net petroleum product exports in all AEO2015 cases. In the High Oil and Gas Resource case, increased crude production before 2020 results in increased processed condensate[6] exports. Slowing growth in domestic production after 2020 is offset by increased vehicle fuel economy standards that limit growth in domestic demand. The net import share of crude oil and petroleum products supplied falls from 33% of total supply in 2013 to 17% of total supply in 2040 in the Reference case. The United States becomes a net exporter of petroleum and other liquids after 2020 in the High Oil Price and High Oil and Gas Resource cases because of greater U.S. crude oil production.
  • The United States transitions from being a modest net importer of natural gas to a net exporter by 2017. U.S. export growth continues after 2017, with net exports in 2040 ranging from 3.0 trillion cubic feet (Tcf) in the Low Oil Price case to 13.1 Tcf in the High Oil and Gas Resource case.
  • Growth in crude oil and dry natural gas production varies significantly across oil and natural gas supply regions and cases, forcing shifts in crude oil and natural gas flows between U.S. regions, and requiring investment in or realignment of pipelines and other midstream infrastructure
  • U.S. energy consumption grows at a modest rate over the AEO2015 projection period, averaging 0.3%/year from 2013 through 2040 in the Reference case. A marginal decrease in transportation sector energy consumption contrasts with growth in most other sectors. Declines in energy consumption tend to result from the adoption of more energy-efficient technologies and existing policies that promote increased energy efficiency.
  • Growth in production of dry natural gas and natural gas plant liquids (NGPL) contributes to the expansion of several manufacturing industries (such as bulk chemicals and primary metals) and the increased use of NGPL feedstocks in place of petroleum-based naphtha [7] feedstocks.
  • Rising long-term natural gas prices, the high capital costs of new coal and nuclear generation capacity, state-level policies, and cost reductions for renewable generation in a market characterized by relatively slow electricity demand growth favor increased use of renewables.
  • Rising costs for electric power generation, transmission, and distribution, coupled with relatively slow growth of electricity demand, produce an 18% increase in the average retail price of electricity over the period from 2013 to 2040 in the AEO2015 Reference case. The AEO2015 cases do not include the proposed Clean Power Plan.[8]
  • Improved efficiency in the end-use sectors and a shift away from more carbon-intensive fuels help to stabilize U.S. energy-related carbon dioxide (CO2) emissions, which remain below the 2005 level through 2040.

The future path of crude oil prices can vary substantially, depending on assumptions about the size of the resource and growth in demand, particularly in non-OECD countries

AEO2015 considers a number of factors related to the uncertainty of future crude oil prices, including changes in worldwide demand for petroleum products, crude oil production, and supplies of other liquid fuels. In all the AEO2015 cases, the North Sea Brent crude oil price reflects the world market price for light sweet crude, and all the cases account for market conditions in 2014, including the 10% decline in the average Brent spot price to $97/barrel (bbl) in 2013 dollars.

In the AEO2015 Reference case, continued growth in U.S. crude oil production contributes to a 43% decrease in the Brent crude oil price, to $56/bbl in 2015 (Figure ES1). Prices rise steadily after 2015 in response to growth in demand from countries outside the OECD; however, downward price pressure from continued increases in U.S. crude oil production keeps the Brent price below $80/bbl through 2020. U.S. crude oil production starts to decline after 2020, but increased production from non-OECD countries and from countries in the Organization of the Petroleum Exporting Countries (OPEC) contributes to the Brent price remaining below $100/bbl through 2028 and limits the Brent price increase through 2040, when it reaches $141/bbl.

There is significant price variation in the alternative cases using different assumptions. In the Low Oil Price case, the Brent price drops to $52/bbl in 2015, 7% lower than in the Reference case, and reaches $76/bbl in 2040, 47% lower than in the Reference case, largely as a result of lower non-OECD demand and higher upstream investment by OPEC. In the High Oil Price case, the Brent price increases to $122/bbl in 2015 and to $252/bbl in 2040, largely in response to significantly lower OPEC production and higher non-OECD demand. In the High Oil and Gas Resource case, assumptions about overseas demand and supply decisions do not vary from those in the Reference case, but U.S. crude oil production growth is significantly greater, resulting in lower U.S. net imports of crude oil, and causing the Brent spot price to average $129/bbl in 2040, which is 8% lower than in the Reference case.

Figure ES1 North Sea Brent crude oil prices in four cases, 2005-40


figure data

Future natural gas prices will be influenced by a number of factors, including oil prices, resource availability, and demand for natural gas

Projections of natural gas prices are influenced by assumptions about oil prices, resource availability, and natural gas demand. In the Reference case, the Henry Hub natural gas spot price (in 2013 dollars) rises from $3.69/million British thermal units (Btu) in 2015 to $4.88/million Btu in 2020 and to $7.85/million Btu in 2040 (Figure ES2), as increased demand in domestic and international markets leads to the production of increasingly expensive resources.

In the AEO2015 alternative cases, the Henry Hub natural gas spot price is lowest in the High Oil and Gas Resource case, which assumes greater estimated ultimate recovery per well, closer well spacing, and greater gains in technological development. In the High Oil and Gas Resource case, the Henry Hub natural gas spot price falls from $3.14/million Btu in 2015 to $3.12/million Btu in 2020 (36% below the Reference case price) before rising to $4.38/million Btu in 2040 (44% below the Reference case price). Cumulative U.S. domestic dry natural gas production from 2015 to 2040 is 26% higher in the High Oil and Gas Resource case than in the Reference case and is sufficient to meet rising domestic consumption and exports—both pipeline gas and liquefied natural gas (LNG)—even as prices remain low.

Henry Hub natural gas spot prices are highest in the High Oil Price case, which assumes the same level of resource availability as the AEO2015 Reference case, but different Brent crude oil prices. The higher Brent crude oil prices in the High Oil Price case affect the level of overseas demand for U.S. LNG exports, because international LNG contracts are often linked to crude oil prices—although the linkage is expected to weaken with changing market conditions. When the Brent spot price rises in the High Oil Price case, world LNG contracts that are linked to oil prices become relatively more competitive, making LNG exports from the United States more desirable. In the High Oil Price case, the Henry Hub natural gas spot price remains close to the Reference case price through 2020; however, higher overseas demand for U.S. LNG exports raises the average Henry Hub price to $10.63/million Btu in 2040, which is 35% above the Reference case price. Cumulative U.S. exports of LNG from 2015 to 2040 in the High Oil Price case are more than twice those in the Reference case. The opposite occurs in the Low Oil Price case: low Brent crude oil prices cause oil-linked LNG contracts to become relatively less competitive and make U.S. LNG exports less desirable. Lower overseas demand for U.S. LNG exports causes the average Henry Hub price to reach only $7.15/million Btu in 2040, 9% lower than in the Reference case.

Figure ES2 Average Henry Hub spot prices for natural gas in four cases, 2005-40


figure data

Global growth and trade weaken beyond 2025, creating headwinds for U.S. export-oriented industries

In the AEO2015 projections, growth in U.S. net exports contributes more to GDP growth than it has over the past 30 years (partially due to a reduction in net energy imports); however, its impact diminishes in the later years of the projection, reflecting slowing GDP growth in nations that are U.S. trading partners, along with the impacts of exchange rates and prices on trade. As economic growth in the rest of the world slows (as shown in Table ES1), so does U.S. export growth, with commensurate impacts on growth in manufacturing output, particularly in the paper, chemicals, primary metals, and other energy-intensive industries. The impact varies across industries.

Table ES1. Growth of trade-related factors in the Reference case, 1983-2040

(average annual percent change)

Measure History: 1983-2013 2013-20 2020-25 2025-30 2030-35 2035-40
U.S. GDP 2.8% 2.6% 2.5% 2.3% 2.2% 2.3%
U.S. GDP per capita 1.8% 1.8% 1.8% 1.6% 1.6% 1.8%
U.S. exports 6.1% 4.8% 6.2% 4.8% 4.5% 4.1%
U.S. imports 6.0% 4.6% 4.1% 3.7% 3.7% 3.7%
U.S. net export growth 0.1% 0.3% 2.1% 1.1% 0.8% 0.3%
Real GDP of OECD trading partners 2.4% 2.1% 1.9% 1.8% 1.7% 1.7%
Real GDP of other trading partners 4.7% 4.3% 4.2% 3.7% 3.4% 3.2%

Source: Summary of AEO2015 cases: U.S. Energy Information Administration.
Note: Major U.S. trading partners include Australia, Canada, Switzerland, United Kingdom, Japan, Sweden, and the Eurozone. Other U.S. trading partners include Argentina, Brazil, Chile, Columbia, Mexico, Hong Kong, Indonesia, India, Israel, South Korea, Malaysia, Philippines, Russia, Saudi Arabia, Singapore, Thailand, Taiwan, and Venezuela.
 

Recent model revisions to the underlying industrial supply and demand relationships[9] have emphasized the importance of trade to manufacturing industries, so that the composition of trade determines the level of industrial output. Consumer goods and industrial supplies show higher levels of net export growth than other categories throughout the projection. The diminishing net export growth in all categories in the later years of the projection explains much of the leveling off of growth that occurs in some trade-sensitive industries.

U.S. net energy imports decline and ultimately end, largely in response to increased oil and dry natural gas production

Energy imports and exports come into balance in the United States in the AEO2015 Reference case, starting in 2028. In the High Oil Price and High Oil and Gas Resource cases, with higher U.S. crude oil and dry natural gas production and lower imports, the United States becomes a net exporter of energy in 2019. In contrast, in the Low Oil Price case, the United States remains a net energy importer through 2040 (Figure ES3).

Economic growth assumptions also affect the U.S. energy trade balance. In the Low Economic Growth case, U.S. energy imports are lower than in the Reference case, and the United States becomes a net energy exporter in 2022. In the High Economic Growth case, the United States remains a net energy importer through 2040.

Figure ES3 U.S. net energy imports in six cases, 2005-40


figure data

The share of total U.S. energy production from crude oil and lease condensate rises from 19% in 2013 to 25% in 2040 in the High Oil and Gas Resource case, as compared with no change in the Reference case. Dry natural gas production remains the largest contributor to total U.S. energy production through 2040 in all the AEO2015 cases, with a higher share in the High Oil and Gas Resource case (38%) than in the Reference case (34%) and all other cases. In 2013, dry natural gas accounted for 30% of total U.S. energy production.

Coal's share of total U.S. energy production in the High Oil and Gas Resource case falls from 26% in 2013 to 15% in 2040. In the Reference case and most of the other AEO2015 cases, the coal share remains slightly above 20% of total U.S. energy production through 2040; in the Low Oil Price case, with lower oil and gas production levels, it remains essentially flat at 23% through 2040.

Continued strong growth in domestic production of crude oil from tight formations leads to a decline in net imports of crude oil and petroleum products

U.S. crude oil production from tight formations leads the growth in total U.S. crude oil production in all the AEO2015 cases. In the Reference case, lower levels of domestic consumption of liquid fuels and higher levels of domestic production of crude oil push the net import share of crude oil and petroleum products supplied down from 33% in 2013 to 17% in 2040 (Figure ES4).

In the High Oil Price and High Oil and Gas Resource cases, growth in tight oil production results in significantly higher levels of total U.S. crude oil production than in the Reference case. Crude oil production in the High Oil and Gas Resource case increases to 16.6 million barrels per day (bbl/d) in 2040, compared with a peak of 10.6 million bbl/d in 2020 in the Reference case. In the High Oil Price case, production reaches a high of 13.0 million bbl/d in 2026, then declines to 9.9 million bbl/d in 2040 as a result of earlier resource development. In the Low Oil Price case, U.S. crude oil production totals 7.1 million bbl/d in 2040. The United States becomes a net petroleum exporter in 2021 in both the High Oil Price and High Oil and Gas Resource cases. With lower levels of domestic production and higher domestic consumption in the Low Oil Price case, the net import share of total liquid fuels supply increases to 36% of total domestic supply in 2040.

Figure ES4 Net crude oil and petroleum products imports as a percentage of U.S. product supplied in four cases, 2005-40


figure data

Net natural gas trade, including LNG exports, depends largely on the effects of resource levels and oil prices

In all the AEO2015 cases, the United States transitions from a net importer of 1.3 Tcf of natural gas in 2013 (5.5% of the 23.7 Tcf delivered to consumers) to a net exporter in 2017. Net exports continue to grow after 2017, to a 2040 range between 3.0 Tcf in the Low Oil Price case and 13.1 Tcf in the High Oil and Gas Resource case (Figure ES5).

Figure ES5 U.S. total net natural gas imports in four cases, 2005-40


figure data

In the Reference case, LNG exports reach 3.4 Tcf in 2030 and remain at that level through 2040, when they account for 46% of total U.S. natural gas exports. The growth in U.S. LNG exports is supported by differences between international and domestic natural gas prices. LNG supplied to international markets is primarily priced on the basis of world oil prices, among other factors. This results in significantly higher prices for global LNG than for domestic natural gas supply, particularly in the near term. However, the relationship between the price of international natural gas supplies and world oil prices is assumed to weaken later in the projection period, in part as a result of growth in U.S. LNG export capacity. U.S. natural gas prices are determined primarily by the availability and cost of domestic natural gas resources. In the High Oil Price case, with higher world oil prices resulting in higher international natural gas prices, U.S. LNG exports climb to 8.1 Tcf in 2033 and account for 73% of total U.S. natural gas exports in 2040.

In the High Oil and Gas Resource case, abundant U.S. dry natural gas production keeps domestic natural gas prices lower than international prices, supporting the growth of U.S. LNG exports, which total 10.3 Tcf in 2037 and account for 66% of total U.S. natural gas exports in 2040. In the Low Oil Price case, with lower world oil prices, U.S. LNG exports are less competitive and grow more slowly, to a peak of 0.8 Tcf in 2018, and account for 13% of total U.S. natural gas exports in 2040.

Additional growth in net natural gas exports comes from growing natural gas pipeline exports to Mexico, which reach a high of 4.7 Tcf in 2040 in the High Oil and Gas Resource case (compared with 0.7 Tcf in 2013). In the High Oil Price case, U.S. natural gas pipeline exports to Mexico peak at 2.2 Tcf in 2040, as higher domestic natural gas prices resulting from increased world demand for LNG reduce the incentive to export natural gas via pipeline. Natural gas pipeline net imports from Canada remain below 2013 levels through 2040 in all the AEO2015 cases, but these imports do increase in response to higher natural gas prices in the latter part of the projection period.

Regional variations in domestic crude oil and dry natural gas production can force significant shifts in crude oil and natural gas flows between U.S. regions, requiring investment in or realignment of pipelines and other midstream infrastructure

U.S. crude oil and dry natural gas production levels have increased rapidly in recent years. From 2008 to 2013, crude oil production grew from 5.0 million bbl/d to 7.4 million bbl/d, and annual dry natural gas production grew from 20.2 Tcf to 24.3 Tcf. All the AEO2015 cases project continued growth in U.S. dry natural gas production, whereas crude oil production continues to increase but eventually declines in all cases except the High Oil and Gas Resource case. In most of the cases, Lower 48 onshore crude oil production shows the strongest growth in the Dakotas/Rocky Mountains region (which includes the Bakken formation), followed by the Southwest region (which includes the Permian Basin) (Figure ES6). The strongest growth of dry natural gas production in the Lower 48 onshore in most of the AEO2015 cases occurs in the East region (which includes the Marcellus Shale and Utica Shale), followed by the Gulf Coast onshore region and the Dakotas/Rocky Mountains region. Interregional flows to serve downstream markets vary significantly among the different cases.

In the High Oil Price case, higher prices for crude oil and increased demand for LNG support higher levels of Lower 48 onshore crude oil and dry natural gas production than in the Reference case. Production in the High Oil Price case is exceeded only in the High Oil and Gas Resource case, where greater availability of oil and natural gas resources leads to more rapid production growth. The higher production levels in the High Oil Price and High Oil and Gas Resource cases are sustained through the entire projection period. Onshore Lower 48 crude oil production in 2040 drops below its 2013 level only in the Low Oil Price case, which also shows the lowest growth of dry natural gas production.

Crude oil imports into the East Coast and Midwest Petroleum Administration for Defense Districts (PADDs) 1 and 2 grow from 2013 to 2040 in all cases except the High Oil and Gas Resource case. All cases, including the High Oil and Gas Resource case, maintain significant crude oil imports into the Gulf Coast (PADD 3) and West Coast (PADD 5) through 2040. The Dakotas/Rocky Mountains (PADD 4) has significant crude oil imports only through 2040 in the High Oil Price case. The high levels of crude oil imports in all cases except the High Oil and Gas Resource case support growing levels of gasoline, diesel, and jet fuel exports as U.S. refineries continue to have a competitive advantage over refineries in the rest of the world. The High Oil and Gas Resource case is the only case with significant crude oil exports, which occur as a result of additional crude oil exports to Canada. The High Oil and Gas Resource case also shows significantly higher amounts of natural gas flowing out of the Mid-Atlantic and Dakotas/Rocky Mountains regions than most other cases, and higher LNG exports out of the Gulf Coast than any other case.

Figure ES6 Change in U.S. Lower 48 onshore crude oil production by region in six cases. 2013-40


figure data

U.S. energy consumption grows at a modest rate over the projection with reductions in energy intensity resulting from improved technologies and from policies in place

U.S. energy consumption grows at a relatively modest rate over the AEO2015 projection period, averaging 0.3%/ year from 2013 through 2040 in the Reference case. The transportation and residential sector’s decreases in energy consumption (less than 2% over the entire projection period) contrast with growth in other sectors. The strongest energy consumption growth is projected for the industrial sector, at 0.7%/year. Declines in energy consumption tend to result from the adoption of more energy-efficient technologies and policies that promote energy efficiency. Increases tend to result from other factors, such as economic growth and the relatively low energy prices that result from an abundance of supplies.

Near-zero growth in energy consumption is a relatively recent phenomenon, and substantial uncertainty is associated with specific aspects of U.S. energy consumption in the AEO2015 projections. This uncertainty is especially relevant as the United States continues to recover from the latest economic recession and resumes more normal economic growth. Although demand for energy often grew with economic recoveries during the second half of the 20th century, technology and policy factors currently are acting in combination to dampen growth in energy consumption.

The AEO2015 alternative cases demonstrate these dynamics. The High and Low Economic Growth cases project higher and lower levels of travel demand, respectively, and of energy consumption growth, while holding policy and technology assumptions constant. In the High Economic Growth case and the High Oil and Gas Resource case, energy consumption growth (0.6%/year and 0.5%/year, respectively) is higher than in the Reference case. Energy consumption growth in the Low Economic Growth case is lower than in the Reference case (nearly flat). In the High Oil Price case, it is higher than in the Reference case, at 0.5%/year, mainly as a result of increased domestic energy production and more consumption of diesel fuel for freight transportation and trucking.

In the AEO2015 Reference case, as a result of increasingly stringent fuel economy standards, gasoline consumption in the transportation sector in 2040 is 21% lower than in 2013. In contrast, diesel fuel consumption, largely for freight transportation and trucking, grows at an average rate of 0.8%/year from 2013 to 2040, as economic growth results in more shipments of goods. Because the United States consumes more gasoline than diesel fuel, the pattern of gasoline consumption strongly influences the overall trend of energy consumption in the transportation sector (Figure ES7).

Figure ES7 Delivered energy consumption for transportation in six cases, 2008-40


figure data

Industrial energy use rises with growth of shale gas supply

Production of dry natural gas and natural gas plant liquids (NGPL) in the United States has increased markedly over the past few years, and the upward production trend continues in the AEO2015 Reference, High Oil Price, and High Oil and Gas Resource cases, with the High Oil and Gas Resource case showing the strongest growth in production of both dry natural gas and NGPL. Sustained high levels of dry natural gas and NGPL production at prices that are attractive to industry in all three cases contribute to the growth of industrial energy consumption over the 2013-40 projection period and expand the range of fuel and feedstock choices.

Increased supply of natural gas from shale resources and the associated liquids contributes to lower prices for natural gas and hydrocarbon gas liquids (HGL), which support higher levels of industrial output. The energy-intensive bulk chemicals industry benefits from lower prices for fuel (primarily natural gas) and feedstocks (natural gas and HGL), as consumption of natural gas and HGL feedstocks increases by more than 50% from 2013 to 2040 in the Reference case, mostly as a result of growth in the total capacity of U.S. methanol, ammonia (mostly for nitrogenous fertilizers), and ethylene catalytic crackers. Increased availability of HGL leads to much slower growth in the use of heavy petroleum-based naphtha feedstocks compared to the lighter HGL feedstocks (ethane, propane, and butane). With sustained low HGL prices, the feedstock slate continues to favor HGL at unprecedented levels.

Other energy-intensive industries, such as primary metals and pulp and paper, also benefit from the availability and pricing of dry natural gas production from shale resources. However, factors other than lower natural gas and HGL prices, such as changes in nonenergy costs and export demand, also play significant roles in increasing manufacturing output.[10]

Manufacturing gross output in the High Oil and Gas Resource case is only slightly higher than in the Reference case, and most of the difference in industrial natural gas use between the two cases is attributable to the mining industry—specifically, oil and gas extraction. With increased extraction activity in the High Oil and Gas Resource case, natural gas consumption for lease and plant use in 2040 is 1.6 quadrillion Btu (68%) higher than in the Reference case.

Increased production of dry natural gas from shale resources(e.g., as seen in the High Oil and Gas Resource case relative to the Reference case) leads to a lower natural gas price, which leads to more natural gas use for combined heat and power (CHP) generation in the industrial sector. In 2040, natural gas use for CHP generation is 12% higher in the High Oil and Gas Resource case than in the Reference case, reflecting the higher levels of dry natural gas production. Finally, the increased supply of dry natural gas from shale resources leads to the increased use of natural gas to meet heat and power needs in the industrial sector.

Renewables meet much of the growth in electricity demand

Renewable electricity generation in the AEO2015 Reference case increases by 72% from 2013 to 2040, accounting for more than one-third of new generation capacity. The renewable share of total generation grows from 13% in 2013 to 18% in 2040. Federal tax credits and state renewable portfolio standards that do not expire (sunset) continue to drive the relatively robust near-term growth of nonhydropower renewable sources, with total renewable generation increasing by 25% from 2013 to 2018. However, from 2018 through about 2030, the growth of renewable capacity moderates, as relatively slow growth of electricity demand reduces the need for new generation capacity. In addition, the combination of relatively low natural gas prices and the expiration of several key federal and state policies results in a challenging economic environment for renewables. After 2030, renewable capacity growth again accelerates, as natural gas prices increase over time and renewables become increasingly cost-competitive in some regions.

Wind and solar generation account for nearly two-thirds of the increase in total renewable generation in the AEO2015 Reference case. Solar photovoltaic (PV) technology is the fastest-growing energy source for renewable generation, at an annual average rate of 6.8%. Wind energy accounts for the largest absolute increase in renewable generation and for 40.0% of the growth in renewable generation from 2013 to 2038, displacing hydropower and becoming the largest source of renewable generation by 2040. PV capacity accounts for nearly all the growth in solar generation, split between the electric power sector and the end-use sectors (e.g., distributed or customer-sited generation). Geothermal generation grows at an average annual rate of about 5.5% over the projection period, but because geothermal resources are concentrated geographically, the growth is limited to the western United States. Biomass generation increases by an average of 3.1%/year, led by cofiring at existing coal plants through about 2030. After 2030, new dedicated biomass plants account for most of the growth in generation from biomass energy sources.

In the High Economic Growth and High Oil Price cases, renewable generation growth exceeds the levels in the Reference case— more than doubling from 2013 to 2040 in both cases (Figure ES8), primarily as a result of increased demand for new generation capacity in the High Economic Growth case and relatively more expensive competing fuel prices in the High Oil Price case. In the Low Economic Growth and Low Oil Price cases, with slower load growth and lower natural gas prices, the overall increase in renewable generation from 2013 to 2040 is somewhat smaller than in the Reference case but still grows by 49% and 61%, respectively, from 2013 to 2040. Wind and solar PV generation in the electric power sector, the sector most affected by renewable electric generation, account for most of the variation across the alternative cases in the later years of the projections.

Figure ES8 Total U.S. renewable generation in all sectors by fuel in six cases, 2013 and 2040


figure data

Electricity prices increase with rising fuel costs and expenditures on electric transmission and distribution infrastructure

In the AEO2015 Reference case, increasing costs of electric power generation and transmission and distribution, coupled with relatively slow growth of electricity sales (averaging 0.7%/year), result in an 18% increase in the average retail price of electricity (in real 2013 dollars) over the projection period. In the Reference case, prices increase from 10.1 cents/kilowatthour (kWh) in 2013 to 11.8 cents/kWh in 2040. In comparison, over the same period, the largest increase in retail electricity prices (28%) is in the High Oil Price case (to 12.9 cents/kWh in 2040), and the smallest increase (2%) is in the High Oil and Gas Resource case (to 10.3 cents/kWh in 2040). Electricity prices are determined by economic conditions, efficiency of energy use, competitiveness of electricity supply, investment in new generation capacity, investment in transmission and distribution infrastructure, and the costs of operating and maintaining plants in service. Those factors vary in the alternative cases.

Fuel costs (mostly for coal and natural gas) account for the largest portion of generation costs in consumer electricity bills. In 2013, coal accounted for 44% and natural gas accounted for 42% of the total fuel costs for electricity generation. In the AEO2015 Reference case, coal accounts for 35% and natural gas for 55% of total fuel costs in 2040. Coal prices rise on average by 0.8% per year and natural gas prices by 2.4%/year in the Reference case, compared with 1.3%/year and 3.1%/year, respectively, in the High Oil Price case and 0.5%/year and 0.2%/year, respectively, in the High Oil and Gas Resource case.

There has been a fivefold increase in investment in new electricity transmission capacity in the United States since 1997, as well as large increases in spending for distribution capacity. Although investments in new transmission and distribution capacity do not continue at the same rates in AEO2015, spending continues on additional transmission and distribution capacity to connect to new renewable energy sources; improvements in the reliability and resiliency of the grid; enhancements to community aesthetics (underground lines); and smart grid construction.

The average annual rate of growth in U.S. electricity use (including sales and direct use) has slowed from 9.8% in the 1950s to 0.5% over the past decade. Factors contributing to the lower rate of growth include slower population growth, market saturation of electricity-intensive appliances, improvements in the efficiency of household appliances, and a shift in the economy toward a larger share of consumption in less energy-intensive industries. In the AEO2015 Reference case,
U.S. electricity use grows by an average of 0.8%/year from 2013 to 2040.

Energy-related CO2 emissions stabilize with improvements in the energy intensity and carbon intensity of electricity generation

U.S. energy-related CO2 emissions in 2013 totaled 5,405 million metric tons (mt).[11] In the AEO2015 Reference case, CO2 emissions increase by 144 million mt (2.7%) from 2013 to 2040, to 5,549 million mt—still 444 million mt below the 2005 level of 5,993 million mt. Among the AEO2015 alternative cases, total emissions in 2040 range from a high of 5,979 million mt in the High Economic Growth case to a low of 5,160 million mt in the Low Economic Growth case.

In the Reference case:

  • CO2 emissions from the electric power sector increase by an average of 0.2%/year from 2013 to 2040, as a result of relatively slow growth in electricity sales (averaging 0.7%/year) and increasing substitution of lower-carbon fuels, such as natural gas and renewable energy sources, for coal in electricity generation.
  • CO2 emissions from the transportation sector decline by an average of 0.2%/year, with overall improvements in vehicle energy efficiency offsetting increased travel demand, growth in diesel consumption in freight trucks, and consumer's preference for larger, less-efficient vehicles as a result of the lower fuel prices that accompany strong growth of domestic oil and dry natural gas production.
  • CO2 emissions from the industrial sector increase by an average of 0.5%/year, reflecting a resurgence of industrial activity fueled by low energy prices, particularly for natural gas and HGL feedstocks in the bulk chemical sector.
  • CO2 emissions from the residential sector decline by an average of 0.2%/year, with improvements in appliance and building shell efficiencies more than offsetting growth in housing units.
  • CO2 emissions from the commercial sector increase by an average of 0.3%/year even with improvements in equipment and building shell efficiency, as a result of increased electricity consumption resulting from the growing proliferation of data centers and electric devices, such as networking equipment and video displays, as well as greater use of natural gas-fueled combined heat and power distributed generation.

Endnotes

  1. Liquid fuels (or petroleum and other liquids) includes crude oil and products of petroleum refining, natural gas liquids, biofuels, and liquids derived from other hydrocarbon sources (including coal-to-liquids and gas-to-liquids).
  2. Net product imports includes trade in crude oil and petroleum products.
  3. The U.S. Department of Commerce, Bureau of Industry and Security has determined that condensate which has been processed through a distillate tower can be exported without licensing.
  4. Naphtha is a refined or semi-refined petroleum fraction used in chemical feedstocks and many other petroleum products. For a complete definition, see http://www.eia.gov/tools/glossary/index.cfm?id=naphtha.
  5. U.S. Environmental Protection Agency, "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," Federal Register, pp. 34829-34958 (Washington, DC: June 18, 2014) https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbonpollution- emission-guidelines-for-existing-stationary-sources-electric-utility-generating.
  6. AEO2015 incorporates the U.S. Bureau of Economic Analysis (BEA) updated 2007 input-output table, released at the end of December 2013. See U.S. Department of Commerce, Bureau of Economic Analysis, “Industry Economic Accounts Information Guide (Washington, DC: December 18, 2014), http://www.bea.gov/industry/iedguide.htm#aia.
  7. E. Sendich, "The Importance of Natural Gas in the Industrial Sector With a Focus on Energy-Intensive Industries," EIA Working Paper (February 28, 2014), http://www.eia.gov/workingpapers/pdf/natgas_indussector.pdf.
  8. Based on EIA, Monthly Energy Review (November 2014), and reported here for consistency with data and other calculations in the AEO2015 tables. The 2013 total was subsequently updated to 5,363 million metric tons in EIA's February 2015 Monthly Energy Review, DOE/EIA-0035(2015/02), http://www.eia.gov/totalenergy/data/monthly/archive/00351502.pdf.

Introduction

Source: http://www.eia.gov/forecasts/aeo/chapter_intro.cfm

Introduction

In preparing the Annual Energy Outlook 2015 (AEO2015)—a shorter edition; see "Changes in release cycle for EIA's Annual Energy Outlook"—the U.S. Energy Information Administration (EIA) evaluated a range of trends and issues that could have major implications for U.S. energy markets. This report presents the AEO2015 Reference case and compares it with five alternative cases (Low and High Oil Price, Low and High Economic Growth, and High Oil and Gas Resource) that were completed as part of AEO2015 (see Appendixes A, B, C, and D).

Because of the uncertainties inherent in any energy market projection, the Reference case results should not be viewed in isolation. Readers are encouraged to review the alternative cases to gain perspective on how variations in key assumptions can lead to different outlooks for energy markets. In addition to the alternative cases prepared for AEO2015, EIA has examined many proposed policies affecting energy markets over the past few years. Reports describing the results of those analyses are available on EIA's website.[12]

Table 1 provides a summary of the six cases produced as part of AEO2015. For each case, the table gives the name used in AEO2015 and a brief description of the major assumptions underlying the projections. Regional results and other details of the projections are available at http://www.eia.gov/forecasts/aeo/tab...cfm#supplement.

Table 1. Summary of AEO2015 cases

 

Case name Description
Reference Real gross domestic product (GDP) grows at an average annual rate of 2.4% from 2013 to 2040, under the assumption that current laws and regulations remain generally unchanged throughout the projection period. North Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 dollars) in 2040. Complete projection tables are provided in Appendix A.
Low Economic Growth Real GDP grows at an average annual rate of 1.8% from 2013 to 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables are provided in Appendix B.
High Economic Growth Real GDP grows at an average annual rate of 2.9% from 2013 to 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables are provided in Appendix B.
Low Oil Price Low oil prices result from a combination of low demand for petroleum and other liquids in nations outside the Organization for Economic Cooperation and Development (non-OECD nations) and higher global supply. On the supply side, the Organization of Petroleum Exporting Countries (OPEC) increases its liquids market share from 40% in 2013 to 51% in 2040, and the costs of other liquids production technologies are lower than in the Reference case. Light, sweet (Brent) crude oil prices remain around $52/bbl (2013 dollars) through 2017, and then rise slowly to $76/bbl in 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables are provided in Appendix C.
High Oil Price High oil prices result from a combination of higher demand for liquid fuels in non-OECD nations and lower global crude oil supply. OPEC’s liquids market share averages 32% throughout the projection. Non-OPEC crude oil production expands more slowly in short- to mid-term relative to the Reference case. Brent crude oil prices rise to $252/bbl (2013 dollars) in 2040. Other energy market assumptions are the same as in the Reference case. Partial projection tables are provided in Appendix C.
High Oil and Gas Resource Estimated ultimate recovery (EUR) per shale gas, tight gas, and tight oil well is 50% higher and well spacing is 50% closer (i.e., the number of wells drilled is 100% higher) than in the Reference case. In addition, tight oil resources are added to reflect new plays or the expansion of known tight oil plays, and the EUR for tight and shale wells increases by 1%/year more than the annual increase in the Reference case to reflect additional technology improvements. This case also includes kerogen development; undiscovered resources in the offshore Lower 48 states and Alaska; and coalbed methane and shale gas resources in Canada that are 50% higher than in the Reference case. Other energy market assumptions are the same as in the Reference case. Partial projection tables are provided in Appendix D.
Source: U.S. Energy Information Administration.

Changes in release cycle for EIA’s Annual Energy Outlook

To focus more resources on rapidly changing energy markets and the ways in which they might evolve over the next few years, the U.S. Energy Information Administration (EIA) is revising the schedule and approach for production of the Annual Energy Outlook (AEO). Starting with this Annual Energy Outlook 2015 (AEO2015), EIA is adopting a two-year release cycle for the AEO, with full and shorter editions of the AEO produced in alternating years. AEO2015 is a shorter edition of the AEO.

The shorter AEO includes a limited number of model updates, which are selected predominantly to reflect historical data updates and changes in legislation and regulations. A complete listing of the changes made for AEO2015 is shown in Appendix E. The shorter edition includes a Reference case and five alternative cases: Low Oil Price, High Oil Price, Low Economic Growth, High Economic Growth, and High Oil and Gas Resource.

The shorter AEO will include this publication, which discusses the Reference case and alternative cases, as well as the report, Assumptions to the Annual Energy Outlook 2015.[13] Other documentation—including model documentation for each of the National Energy Modeling System (NEMS) models and the Retrospective Review—will be completed only for the years when a full edition of the AEO is produced.

To provide a basis against which alternative cases and policies can be compared, the AEO Reference case generally assumes that current laws and regulations affecting the energy sector remain unchanged throughout the projection (including the assumption that laws that include sunset dates do, in fact, expire at the time of those sunset dates). This assumption enables policy analysis with less uncertainty regarding unstated legal or regulatory assumptions.

Endnotes

  1. See “Congressional and other requests,” http://www.eia.gov/analysis/reports.cfm?t=138.
  2. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2015, DOE/EIA-0554(2015) (Washington, DC, to be published), http://www.eia.gov/forecasts/aeo/assumptions.

Economic growth

Source: http://www.eia.gov/forecasts/aeo/section_economic.cfm

Introduction

The AEO economic forecasts are trend projections, with no major shocks assumed and with potential growth determined by the economy’s supply capability. Growth in aggregate supply depends on increases in the labor force, growth of capital stocks, and improvements in productivity. Long-term demand growth depends on labor force growth, income growth, and population growth. The AEO2015 Reference case uses the U.S. Census Bureau’s December 2012 middle population projection: U.S. population grows at an average annual rate of 0.7%, real GDP at 2.4%, labor force at 0.6%, and nonfarm labor productivity at 2.0% from 2013 to 2040.

Table 2 compares key long-run economic growth projections in AEO2015 with actual growth rates over the past 30 years. In the AEO2015 Reference case, U.S. real GDP grows at an average annual rate of 2.4% from 2013 to 2040—a rate that is 0.4 percentage points slower than the average over the past 30 years. GDP expands in the Reference case by 3.1% in 2015, 2.5% in 2016, 2.6% from 2015 to 2025, and 2.4% from 2015 to 2040. As a share of GDP, consumption expenditures account for more than two-thirds of total GDP. In terms of growth, it is exports and business fixed investment that contribute the most to GDP. Growth in these is relatively strong during the first 10 years of the projection and then moderates for the remaining years. The growth rates for both exports and business fixed investment are above the rate of GDP growth with exports dominating throughout the projection (Figure 1).

Table 2. Growth in key economic factors in historical data and in the Reference case

 

  AEO2015 (2013-40) Previous 30 years
Real 2009 dollars (annual average percent change)
GDP 2.4 2.8
GDP oer capita 1.7 1.8
Disposable income 2.5 2.9
Consumer spending 2.4 3.1
Private investment 3.0 3.5
Exports 4.9 6.1
Imports 4.0 6.0
Government expenditures 0.9 1.7
GDP: Major trading countries 1.9 2.4
GDP: Other trading countries 3.8 4.7
Average annual rate
Federal funds rate 3.2 4.5
Unemployment rate 5.3 6.3
Nonfarm business
output per hour
2.0 2.0
Source: AEO2015 Reference case D021915a, based on IHS Global Insight T301114.wf1.
AEO2015 National Energy Modeling System, run REF2015.D021915A.
 

In the AEO2015 Reference case, nominal interest rates over the 2013-40 period are generally lower than those observed for the preceding 30 years, based on an expectation of lower inflation rates in the projection period. At present, the term structure of interest rates is still at the lowest level seen over the past 40 years. In 2012, the federal funds rate averaged 0.1%. Longer-term nominal interest rates are projected to average around 6.0%, which is lower than the previous 30- year average of 7.8%. After 2015, interest rates in ensuing five-year periods through 2040 are expected to stabilize at a slightly higher level than the five-year averages through 2013, 2014, and 2015, as the result of a modest inflation rate.

Figure 1 Annual changes in U.S. gross domestic product, business investment, and exports in the Reference case, 2015-40


figure data

Appreciation in the U.S. dollar exchange rate dampens export growth during the first five years of the projections; however, the dollar is expected to depreciate relative to the currencies of major U.S. trading partners after 2020, which combined with modest growth in unit labor costs stimulates U.S. export growth toward the end of the projection, eventually improving the U.S. current account balance. Real exports of goods and services grow at an average annual rate of 4.9%—and real imports of goods and services grow at an average annual rate of 4.0%—from 2013 to 2040 in the Reference case. The inflation rate, as measured by growth in the Consumer Price Index (CPI), averages 2.0% from 2013 to 2040 in the Reference case, compared with the average annual CPI inflation rate of 2.9% from 1983 to 2013.

Annual growth in total gross output of all goods and services, which includes both final and intermediate products, averages 1.9%/year from 2013 to 2040, with growth in the service sector (1.9%/year) just below manufacturing growth (2.0%/year) over the long term. In 2040, the manufacturing share of total gross output (17%) rises slightly above the 2013 level (16%) in the AEO2015 Reference case.

Total industrial production (which includes manufacturing, construction, agriculture, and mining) grows by 1.8%/year from 2013 to 2040 in the AEO2015 Reference case, with slower growth in key manufacturing industries, such as paper, primary metals, and aspects of chemicals excluding the plastic resin and pharmaceutical industries. Except for trade of industrial supplies, which mostly affect energy-intensive industries, net exports show weak growth until 2020. After 2020, export growth recovers as the dollar begins to depreciate and the economic growth of trading partners continues. Net export growth is strongest from the late 2020s through 2034 and declines from 2035 to 2040.

Updated information on how industries supply other industries and meet the demand of different types of GDP expenditures has influenced certain industrial projections.[14] For example, as a result of a better understanding of how the pulp and paper industry supplies other industries, trade of consumer goods and industrial supplies has a greater effect on production in the pulp and paper industry. Nonenergy-intensive manufacturing industries show higher growth than total industrial production, primarily as a result of growth in metal-based durables (Figure 2).

Figure 2 Annual growth rates for industrial output in three cases, 2013-40


figure data

In the AEO2015 Reference case, manufacturing output goes through two distinct growth periods, with the clearest difference between periods seen in the energy-intensive industries. Stronger growth in U.S. manufacturing through 2025 results in part from increased shale gas production, which affects U.S. competitiveness and also results in higher GDP growth early in the projection period. In the Reference case, manufacturing output grows at an average annual rate of 2.3% from 2013 to 2025. After 2025, growth slows to 1.7% as a result of increased foreign competition and rising energy prices, with energy-intensive, trade-exposed industries showing the largest drop in growth. The energy-intensive industries grow at average rates of 1.8%/year from 2013 to 2025 and 0.7%/year from 2025 to 2040. Growth rates in the sector are uneven, with pulp and paper output decreasing at an average annual rate of 0.1% and the cement industry growing at an average annual rate of 3.1% from 2013 to 2040.

AEO2015 presents three economic growth cases: Reference, High, and Low. The High Economic Growth case assumes higher growth and lower inflation, compared with the Reference case, and the Low Economic Growth case assumes lower growth and higher inflation. Differences among the Reference, High Economic Growth, and Low Economic Growth cases reflect different expectations for growth in population (specifically, net immigration), labor force, capital stock, and productivity, which are above trend in the High Economic Growth case and below trend in the Low Economic Growth case. The average annual growth rate for real GDP from 2013 to 2040 in the Reference case is 2.4%, compared with 2.9% in the High Economic Growth case and 1.8% in the Low Economic Growth case.

In the High Economic Growth case, with greater productivity gains and a larger labor force, the U.S. economy expands by 4.1% in 2015, 3.6% in 2016, 3.2% from 2015 to 2025, and 2.9% from 2015 to 2040. In the Low Economic Growth case, the current economic recovery (which is now more than five years old) stalls in the near term, and productivity and labor force growth are weak in the long term. As a result, economic growth averages 2.4% in 2015, 1.6% in 2016, 1.7% from 2015 to 2025, and 1.8% from 2015 to 2040 in the Low Economic Growth case (Table 3).

Table 3. Average annual growth of labor productivity, employment, income, and consumption in three cases


percent per year

  2015 2016 2015-25 2015-40
Productivity
High Economic Growth 2.3 2.3 2.4 2.3
Reference 1.9 1.6 2.1 2.0
Low Economic Growth 1.3 0.9 1.7 1.6
Non-farm employment
High Economic Growth 2.9 1.9 1.2 0.9
Reference 2.2 1.6 0.8 0.7
Low Economic Growth 1.6 1.1 0.6 0.5
Real personal income
High Economic Growth 3.6 3.3 3.4 2.8
Reference 3.3 2.8 2.8 2.5
Low Economic Growth 2.7 2.4 2.4 2.3
Real personal consumption
High Economic Growth 3.6 3.5 3.2 2.9
Reference 3.0 3.0 2.5 2.4
Low Economic Growth 2.5 2.6 1.7 1.7

Source: AEO2015 Reference case D021915a, based on IHS Global Insight T301114.wf1.
AEO2015 National Energy Modeling System, runs REF2015.D021915A, LOWMACRO.D021915A, and HIGHMACRO.D021915A

 

Endnotes

  1. The Industrial Output Model of the NEMS Macroeconomic Activity Module now uses the Bureau of Economic Analysis detailed input-output (IO) matrices for 2007 rather than 2002 (http://bea.gov/industry/io_annual.htm) and also now incorporates information from the aggregate IO matrices (http://bea.gov/industry/gdpbyind_data.htm).

Energy Prices

Source: http://www.eia.gov/forecasts/aeo/section_prices.cfm

Crude oil

AEO2015 considers a number of factors related to the uncertainty of future world crude oil prices, including changes in worldwide demand for petroleum products, crude oil production, and supplies of other liquid fuels.[15] In the Reference, High Oil Price, and Low Oil Price cases, the North Sea Brent (Brent) crude oil price reflects the market price for light sweet crude oil free on board (FOB) at the Sullen Voe oil terminal in Scotland.

The Reference case reflects global oil market events through the end of 2014. Over the past two years, growth in U.S. crude oil production, along with the late-2014 drop in global crude oil prices, has altered the economics of the oil market. These new market conditions are assumed to continue in the Reference case, with the average Brent price dropping from $109/barrel (bbl) in 2013 to $56/bbl in 2015, before increasing to $76/bbl in 2018. After 2018, growth in demand from non-OECD countries—countries outside the Organization for Economic Cooperation and Development (OECD)—pushes the Brent price to $141/bbl in 2040 (in 2013 dollars). The increase in oil prices supports growth in domestic crude oil production.

The High Oil Price case assumes higher world demand for petroleum products, less upstream investment by the Organization of the Petroleum Exporting Countries (OPEC), and higher non-OPEC exploration and development costs. These factors all contribute to a rise in the average spot market price for Brent crude oil to $252/bbl in 2040, 78% above the Reference case. The reverse is true in the Low Oil Price case: lower non-OECD demand, higher OPEC upstream investment, and lower non-OPEC exploration and development costs cause the Brent spot price to increase slowly to $76/bbl, or 47% below the price in the Reference case, in 2040 (Figure 3).

Figure 3 North Sea Brent crude oil prices in three cases, 2005-40


figure data

World liquid fuels consumption varies in the three cases as a result of different assumptions about future trends in oil prices, world oil supply, and the rate of non-OECD demand growth. Uncertainty about world crude oil production is also captured in the three cases. In the Reference case, world production is 99.1 million bbl/d in 2040. In comparison to the Reference case, total liquid fuel supplies and OPEC's market share are higher in the Low Oil Price case and lower in the High Oil Price case. For OPEC
countries in the Middle East, Africa, and South America, combined production grows from less than 32.6 million bbl/d in 2013 to 58.3 million bbl/d in 2040 in the Low Oil Price case, compared with 43.5 million bbl/d in 2040 in the Reference case and 35.0 million bbl/d in 2040 in the High Oil Price case.

As increased OPEC production depresses world oil prices in the Low Oil Price case, development of some non-OPEC resources that are viable in the Reference case become uneconomical. As a result, non-OPEC production increases only slightly in the Low Oil Price case, from 45.3 million bbl/d in 2013 to 46.8 million bbl/d in 2040. In the High Oil Price case, non-OPEC production totals 63.8 million bbl/d in 2040. Unlike the High Oil and Gas Resource case, which assumes higher estimated ultimate recovery of crude oil and natural gas per well, closer well spacing, and greater advancement in production technology than the Reference case, the High Oil Price and Low Oil Price cases assume no changes in those factors from the Reference case.

Petroleum and other liquids products

The prices charged for petroleum products and other liquid products in the United States reflect the price that refiners pay for crude oil inputs, as well as operation, transportation, and distribution costs, and the margins that refiners receive. Changes in gasoline and distillate fuel oil prices generally move in the same direction as changes in the world crude oil price, but the changes in price are also influenced by demand factors. A 30% rise in the North Sea Brent crude oil spot price from 2013 to 2040 in the Reference case results in the weighted average U.S. petroleum product price rising by 15%, from $3.16/gallon to $3.62/gallon (in 2013 dollars). However, the effect of rising crude oil prices on distillate fuel use in the United States is less than for motor gasoline, because of a greater increase in distillate fuel demand as freight requirements continue to grow and the mix of light-duty vehicle fuels shifts from gasoline to diesel fuel. U.S. distillate fuel prices rise by 23% through 2040 in the Reference case, compared to an 11% increase for motor gasoline (Figure 4 and Figure 5). However, distillate fuel consumption rises by 15%, compared to a 20% decrease in motor gasoline consumption.

Figure 4 Motor gasoline prices in three cases, 2005-40


figure data

Figure 5 Distillate fuel oil prices in three cases, 2005-40


figure data

In the High Oil Price case, higher demand for crude oil in non- OECD countries and lower supply of OPEC crude oil push world crude oil prices up. As a result, the weighted average price for U.S. petroleum products increases by 84%, from $3.16/gallon in 2013 to $5.81/gallon in 2040. In the Low Oil Price case, with lower non-OECD demand and higher OPEC supply pushing world oil prices down, the weighted average price for U.S. petroleum products drops by 26%, from $3.16/gallon in 2013 to $2.32/gallon in 2040.

In all the AEO2015 cases, U.S. laws and regulations shape demand and, consequently, the price of petroleum products in the United States. The Corporate Average Fuel Economy (CAFE) standards for new light-duty vehicles (LDVs), which typically use gasoline, rise from 30 miles per gallon (mpg) in 2013 to 54 mpg in 2040 under the fleet composition assumptions used in the final rule issued by the U.S. Environmental Protection Agency (EPA) and National Highway Transportation Safety Administration.[16] The rise in vehicle miles traveled (VMT) for LDVs does not fully offset the increase in fuel efficiency, and motor gasoline consumption declines through 2040 in all the AEO2015 cases. However, the effect of the standards varies by case because of the use of different assumptions about prices and economic growth. The 32% decrease in motor gasoline consumption in the High Oil Price case is larger than the decrease in the Reference case because higher gasoline prices reduce VMT, reducing consumption. In the Low Oil Price case, the decrease in gasoline consumption (11%) is smaller than in the Reference case because lower gasoline prices stimulate enough increased VMT to offset a part of the impact of fuel efficiency improvements resulting from regulation.

The efficiency and greenhouse gas (GHG) standard for heavy-duty vehicles, which typically consume distillate fuel, rises by about 16% through 2040, remaining below 8 mpg in all AEO2015 cases. Unlike the case for LDVs, the higher VMT in the Low Oil Price case more than offsets the increase in vehicle fuel efficiency, and distillate fuel consumption increases by 21% from 2013 to 2040. The increase in fuel consumption in the Low Oil Price case is greater than in the Reference case as a result of a 22% decrease in distillate fuel prices, to $2.97/gallon in 2040. In the High Oil Price case, the price of distillate fuel oil increases to $7.55/gallon in 2040—61% higher than in the Reference case—resulting in a 2% decline in distillate fuel consumption.

Natural Gas

Henry Hub natural gas spot prices vary according to assumptions about the availability of domestically produced natural gas resources, overseas demand for U.S. liquefied natural gas (LNG), and trends in domestic consumption. In all cases, prices are lower in 2015 than the $3.73/million British thermal units (Btu) average Henry Hub spot price in 2013, and in most cases they are above that level by 2020 (Figure 6). In the AEO2015 Reference case, the Henry Hub spot price is $4.88/million Btu (2013 dollars) in 2020 and $7.85/million Btu in 2040, as increased demand in domestic and international markets requires an increased number of well completions to achieve higher levels of production. In addition, lower cost resources generally are expected to be produced earlier, with more expensive production occurring later in the projection period.

Figure 6 Average Henry Hub spot prices for natural gas in four cases, 2005-40


figure data

In the High Oil and Gas Resource case, U.S. domestic production from tight oil and natural gas formations is higher than in the Reference case as a result of assumed greater estimated ultimate recovery (EUR) per well, closer well spacing, and greater gains in technological development. Consequently, even with low natural gas prices, total U.S. domestic dry natural gas production grows sufficiently to satisfy higher levels of domestic consumption, as well as higher pipeline and LNG exports. With the abundance of natural gas produced domestically, the Henry Hub spot price (in 2013 dollars) falls from $3.14/million Btu in 2015 to $3.12/ million Btu in 2020 (36% below the Reference case price) before rising to $4.38/million Btu in 2040 (44% below the Reference case price).

The Low and High Oil Price cases assume the same level of resource availability as the Reference case but different world oil prices, which affect the level of overseas demand for U.S. LNG exports. International LNG contracts are often linked to crude oil prices, even though their relationship may be weakening. Global demand for LNG is also directly influenced by oil prices, as LNG competes directly with petroleum products in many applications. When the North Sea Brent spot price, which is the principal benchmark price for crude oil on world markets, rises in the High Oil Price case, world LNG contracts linked to oil prices become more expensive, making LNG exports from the United States more desirable.

In the High Oil Price case, the Henry Hub natural gas spot price remains close to the Reference case price through 2020. However, higher overseas demand for U.S. LNG exports raises the average Henry Hub spot price to $10.63/million Btu in 2040, which is 35% above the Reference case price.

In the Low Oil Price case, with lower demand for U.S. LNG exports, the Henry Hub spot price is only $7.15/million Btu in 2040— which is 9% lower than in the Reference case but 63% higher than in the High Oil and Gas Resource case.

Changes in the Henry Hub natural gas spot price generally translate to changes in the price of natural gas delivered to end users. The delivered price of natural gas to the electric power sector is highest in the High Oil Price case, where it rises from $4.40/ million Btu in 2013 to $10.08/million Btu in 2040, compared with $8.28/million Btu in the Reference case. Higher delivered natural gas prices result in a decline in natural gas consumption in the electric power sector in the High Oil Price case, from 8.2 Tcf in 2013 to 6.8 Tcf in 2040, compared with an increase in natural gas consumption in the electric power sector to 9.4 Tcf in 2040 in the Reference case. In the Low Oil Price and High Oil and Gas Resource cases, smaller increases in delivered natural gas prices result in more consumption for power generation than in the Reference case or High Oil Price case in 2040.

As in the electric power sector, natural gas consumption in the U.S. industrial sector also changes in response to delivered natural gas prices. However, industrial natural gas consumption also changes in response to shifts in the mix of industrial output, as well as changes in refinery output and utilization. Consumption also varies with the relative economics of using natural gas for electricity generation in industrial combined heat and power (CHP) facilities. The largest increase in the price of natural gas delivered to the industrial sector, from $4.56/million Btu in 2013 to $11.03/million Btu in 2040, is seen in the High Oil Price case, followed by the Reference case ($8.78/million Btu in 2040), Low Oil Price case ($8.25/million Btu in 2040), and High Oil and Gas Resource case ($5.22/million Btu in 2040). Of those four cases, the largest increase in industrial natural gas consumption occurs in the High Oil and Gas Resource case, in which lower prices contribute to higher consumption. The next largest increase occurs in the High Oil Price case, where higher prices spur a significant increase in U.S. crude oil production and, accordingly, natural gas consumption at U.S. oil refineries.[17]

The price of natural gas delivered to the residential and commercial sectors increases from 2013 to 2040 in all the AEO2015 cases. The largest increase in delivered natural gas prices to both sectors through 2040 is in the High Oil Price case, followed by the Reference, Low Oil Price, and High Oil and Gas Resource cases. In the commercial sector, natural gas consumption increases in all cases, mainly as a result of increased commercial CHP use and growth in aggregate commercial square footage. Conversely, consumption in the residential sector decreases in all cases despite economic growth, as overall demand is reduced by population shifts to warmer areas, improvements in appliance efficiency, and increased use of electricity for home heating.

Coal

The average minemouth coal price increases by 1.0%/year in the AEO2015 Reference case, from $1.84/million Btu in 2013 to $2.44/million Btu in 2040. Higher prices result primarily from declines in coal mining productivity in several key supply regions, including Central Appalachia and Wyoming’s Powder River Basin.

Across the AEO2015 alternative cases, the most significant changes in the average minemouth coal price compared with the Reference case occur in the Low and High Oil Price cases. In 2040, the average minemouth price is 6% lower in the Low Oil Price case and 7% higher in the High Oil Price case than in the Reference case. These variations from the Reference case are primarily the result of differences in the projections for diesel fuel and electricity prices in the Low and High Oil Price cases, because diesel fuel and electricity are key inputs to the coal mining process. The AEO2015 cases do not include the EPA’s proposed Clean Power Plan,[18] which if implemented would likely have a substantial impact on coal use for power generation and coal markets more generally.

Increases in minemouth coal prices (in dollars/million Btu) occur in all coal-producing regions (Figure 7). In Appalachia and in the West, increases of 1.2%/year and 1.5%/year between 2013 and 2040, respectively, are primarily the result of continuing declines in coal mining productivity. In the Interior region, a more optimistic outlook for coal mining productivity, combined with substantially higher production quantities, results in slower average price growth of 0.8%/ year from 2013 to 2040. Increased output from large, highly productive longwall mines in the Interior region support labor productivity gains averaging 0.3%/year over the same period.

Figure 7 Average minemouth coal prices by region in the Reference case, 1990-2040


figure data

The average delivered price of coal (the sum of minemouth and coal transportation costs) increases at a similar, but slightly slower pace of 0.8%/year than minemouth prices, with prices rising from $2.50/million Btu in 2013 to $3.09/million Btu in 2040 in the AEO2015 Reference case (Figure 8). A relatively flat outlook for coal transportation rates results in a slightly lower growth rate for the average delivered price of coal.

Figure 8 Average delivered coal prices in six cases, 1990-2040


figure data

Electricity

The average retail price of electricity in real 2013 dollars increases in the AEO2015 Reference case by 18% from 2013 to 2040 as a result of rising costs for power generation and delivery, coupled with relatively slow growth in electricity demand (0.7%/ year on average). Electricity prices are determined by a complex set of factors that include economic conditions; energy use and efficiency; the competitiveness of electricity supply; investment in new generation, transmission, and distribution capacity; and the fuel, operation, and maintenance costs of plants in service. Figure 9 illustrates effects on retail electricity prices in the AEO2015 Reference and alternative cases resulting from different assumptions about the factors determining prices.

Figure 9 Average retail electricity prices in six cases, 2013-40


figure data

In the AEO2015 Reference case, average retail electricity prices (2013 dollars) increase by an average of 0.6%/year, from 10.1 cents/kilowatthour (kWh) in 2013 to 11.8 cents/kWh in 2040, an overall increase of 18%. The High Oil Price case shows the largest overall average price increase, at 28%, to 12.9 cents/kWh in 2040. The High Oil and Gas Resource case shows the smallest average increase, at 2%, to 10.3 cents/kWh in 2040. With more fuel resources available to meet demand from power producers in the High Oil and Gas Resource case, lower fuel prices lead to lower generation costs and lower retail electricity prices for consumers. In the High Economic Growth case, stronger economic growth increases demand for electricity, putting price pressure on the fuel costs and the construction cost of new generating plants. In the Low Economic Growth case, weaker growth results in lower electricity demand and associated costs.

The average annual growth in electricity use (including sales and direct use) in the United States has slowed from 9.8%/year in the 1950s to 0.5%/year over the past decade. Contributing factors include slowing population growth, market saturation of major electricity-using appliances, efficiency improvements in appliances, and a shift in the economy toward a larger share of consumption in less energy-intensive industries. In the AEO2015 Reference case, U.S. electricity use grows by 0.8%/year on average from 2013 to 2040.

Combined electricity demand in the residential and commercial sectors made up over 70% of total electricity demand in 2013, with each sector using roughly the same amount of electricity. From 2013 to 2040, residential and commercial electricity prices increase by 19% and 16%, respectively, in the Reference case; by 30% and 27% in the High Oil Price case; and by 5% and 0% in the High Oil and Gas Resource case. These variations largely reflect the importance of natural gas prices to electricity prices.

Industrial electricity prices grow by 22% in the Reference case, from 6.9 cents/kWh in 2013 to 8.4 cents/kWh in 2040. Among the alternative cases, growth in industrial electricity prices ranges from 35% (9.3 cents/kWh in 2040) in the High Oil Price case to 2% (7.1 cents/KWh in 2040) in the High Oil and Gas Resource case. In the industrial sector, electricity use increases in most industries but falls throughout the projection period for the energy-intensive refining and paper industries and, after 2024, in the aluminum, bulk chemical, and mining industries.

Retail electricity prices include generation, transmission, and distribution components. In the AEO2015 cases, about two-thirds of the retail price of electricity (between 59% and 67%) is attributable to the price of generation, which includes generation costs and retail taxes, with the remaining portion attributable to transmission and distribution costs. The generation price increases by 0.5% annually in the Reference case, from 6.6 cents/kWh in 2013 to 7.6 cents/kWh in 2040. In the High Oil Price Case, the price of generation increases by 1%/year to 8.6 cents/kWh in 2040; and in the High Oil and Gas Resource Case, it falls by 0.3%/year to 6.1 cents/kWh in 2040.

Generation prices are determined differently in states with regulated and competitive electricity supplies. The AEO2015 Reference case assumes that 67% of electricity sales are subject to regulated average-cost pricing and 33% are priced competitively, based on the marginal cost of energy. In fully regulated regions, the price of generation is determined by both fixed costs (such as the costs of paying off electricity plant construction and fixed operation and maintenance costs) and variable costs (fuel and variable operation and maintenance costs).

In the Reference case, new generation capacity added through the projection period includes 167 GW of natural gas capacity, 109 GW of renewable capacity (45% is wind and 44% solar), 9 GW of nuclear capacity, and 1 GW of coal-fired capacity. Significant variation in the mix of generation capacity types added in the different AEO2015 cases also affects generation prices. Natural gas capacity additions vary substantially, with only 117 GW added in the Low Economic Growth case and 236 GW added in the High Economic Growth case. In the High Economic Growth case, a more vibrant economy leads to more industrial and commercial activity, more consumer demand for electric devices and appliances, and consequently greater demand for electricity.

Renewable generation capacity additions vary the most, with 66 GW added in the High Oil and Gas Resource case, but 194 GW added in the High Economic Growth case. Only 6 GW of new nuclear capacity is built in the Low Economic Growth and High Oil and Gas Resource cases, but 22 GW of new nuclear capacity is added in the High Oil Price case where natural gas prices are significantly above those in the Reference case. Across all the AEO2015 cases, very little new coal-fired capacity—and no new oil-fired capacity—is built through 2040.

Most generating fuel costs are attributed to coal and natural gas. In 2013, coal made up 44% of total generation fuel costs, and natural gas made up 42%. In 2040, coal makes up only 35% of total fuel costs in the Reference case, compared with 55% for natural gas. Oil, which is the most expensive fuel for generation, accounted for 6% of the total generating fuel costs in 2013 and from 2019 through 2040 accounts for only 3% of the total. Nuclear fuel accounts for 6% to 8% of electricity generation fuel costs throughout the projection period.

In regions with competitive wholesale electricity markets, the generation price generally follows the natural gas price. The price of electricity in wholesale markets is determined by the marginal cost of energy—the cost of serving the next increment of demand for a determined time period. Natural gas fuels the marginal generators during most peak and some off-peak periods in many regions.

There has been a fivefold increase in investment in new electricity transmission capacity since 1997, as well as large increases in spending for distribution capacity. Since 1997, roughly $107 billion has been spent on new transmission infrastructure and $318 billion on new distribution infrastructure, both in 2013 dollars. Those investments are paid off gradually over the projection period.

Although investment in new transmission and distribution capacity does not continue in the AEO2015 Reference case at the pace seen in recent years, spending still occurs at a rate greater than that needed to keep up with demand driven by requirements for additional transmission and distribution capacity to interconnect with new renewable energy sources, grid reliability and resiliency improvements, community aesthetics (including burying lines), and smart grid construction. In the AEO2015 Reference case, the transmission portion of the price of electricity increases by 1.2%/year, from 0.9 cents/kWh in 2013 to 1.3 cents/kWh in 2040. The distribution portion of the electricity price increases by 0.6%/year over the projection period, from 2.6 cents/ kWh in 2013 to 3.0 cents/kWh in 2040. The investments in distribution capacity are undertaken mainly to serve residential and commercial customers. As a result, residential and commercial customers typically pay significantly higher distribution charges per kilowatthour than those paid by industrial customers.

Endnotes

  1. Liquid fuels, or petroleum and other liquids, includes crude oil and products of petroleum refining, natural gas liquids, biofuels, and liquids derived from other hydrocarbon sources (including coal-to-liquids and gas-to-liquids).
  2. U.S. Environmental Protection Agency and National Highway Transportation 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-emissionsand-corporate-average-fuel.
  3. While not discussed in this section, the High Economic Growth case has higher levels of industrial natural gas consumption through 2040 than any of the four cases mentioned, in response to higher demand that results from significantly higher levels of industrial output.
  4. U.S. Environmental Protection Agency, “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” Federal Register, pp. 34829-34958 (Washington, DC: June 18, 2014) https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbonpollution-emission-guidelines-for-existing-stationary-sources-electric-utility-generating.

Delivered energy consumption by sector

Source: http://www.eia.gov/forecasts/aeo/sec...eredenergy.cfm

Transportation

Energy consumption in the transportation sector declines in the AEO2015 Reference case from 27.0 quadrillion Btu (13.8 million bbl/d) in 2013 to 26.4 quadrillion Btu (13.5 million bbl/d) in 2040. Energy consumption falls most rapidly through 2030, primarily as a result of improvement in light-duty vehicle (LDV) fuel economy with the implementation of corporate average fuel economy (CAFE) standards and greenhouse gas emissions (GHG) standards (Figure 10). This projection is a significant departure from the historical trend. Transportation energy consumption grew by an average of 1.3%/year from 1973 to 2007—when it peaked at 28.7 quadrillion Btu—as a result of increases in demand for personal travel and movement of goods that outstripped gains in fuel efficiency.

tu).

Figure 10 Delivered energy consunption for transportation by mode in the Reference case, 2013-and 2040


figure data

Transportation sector energy consumption varies across the alternative cases (Figure 11). Compared with the Reference case, energy consumption levels in 2040 are higher in the High Economic Growth case (by 3.0 quadrillion Btu), Low Oil Price case (by 1.4 quadrillion Btu), and High Oil and Gas Resource case (by 1.2 quadrillion Btu) and lower in the High Oil Price case (by 1.4 quadrillion Btu) and Low Economic Growth case (by 2.6 quadrillion Btu).

Figure 11 Delivered energy consumption for transportation in six cases, 2008-40


figure data

In the Reference case, energy consumption by LDVs—including passenger cars, light-duty trucks, and commercial light-duty trucks—falls from 15.7 quadrillion Btu in 2013 to 12.6 quadrillion Btu in 2040, as increases in fuel economy more than offset increases in LDV travel. Total vehicle miles traveled (VMT) for LDVs increase by 36% from 2013 (2,711 billion miles) to 2040 (3,675 billion miles), and the average VMT per licensed driver increase from about 12,200 miles in 2013 to 13,300 miles in 2040. The fuel economy of new vehicles increases from 32.8 mpg in 2013 to 48.1 mpg in 2040, as more stringent CAFE and GHG emissions standards take effect. As a result, the average fuel economy of the LDV stock increases by 69%, from 21.9 mpg in 2013 to 37.0 mpg in 2040.

Passenger vehicles fueled exclusively by motor gasoline for all motive and accessory power, excluding any hybridization and flex-fuel capabilities, accounted for 83% of new sales in 2013. In the AEO2015 Reference case, gasoline-only vehicles, excluding hybridization or flex-fuel capabilities, still represent the largest share of new sales in 2040, at 46% of the total (see box below for comparison of relative economics of various vehicle technologies). However, alternative fuel vehicles and vehicles with hybrid technologies gain significant market shares, including gasoline vehicles equipped with micro hybrid systems (33%), E85 flex-fuel vehicles (10%), full hybrid electric vehicles (5%), diesel vehicles (4%), and plug-in hybrid vehicles and electric vehicles (2%). (EIA considers several types of hybrid electric vehicles—micro, mild, full, and plug-in—as described in "Future gasoline vehicles are strong competitors when compared with other vehicle technology types on the basis of fuel economics".)

In comparison with the Reference case, LDV energy consumption in 2040 is higher in the Low Oil Price case (14.3 quadrillion Btu), High Economic Growth case (13.2 quadrillion Btu), and High Oil and Gas Resource case (12.9 quadrillion Btu), as a result of projected higher VMT in all three cases and lower fuel economy in the Low Oil Price and High Oil and Gas Resource cases. Conversely, LDV energy consumption in 2040 in the High Oil Price case (10.6 quadrillion Btu) and the Low Economic Growth case (11.3 quadrillion Btu) is lower than projected in the Reference case, as a result of lower VMT in both cases and higher fuel economy in the High Oil Price case.

Energy use by all heavy-duty vehicles (HDVs)—including tractor trailers, buses, vocational vehicles,[19] and heavy-duty pickups and vans—increases from 5.8 quadrillion Btu (2.8 million bbl/d) in 2013 to 7.3 quadrillion Btu (3.5 million bbl/d) in 2040, with higher VMT only partially offset by improved fuel economy. HDV travel grows by 48% in the Reference case—as a result of increases in industrial output—from 268 billion miles in 2013 to 397 billion miles in 2040, while average HDV fuel economy increases from 6.7 mpg in 2013 to 7.8 mpg in 2040 as a result of HDV fuel efficiency standards and GHG emissions standards. Diesel remains the most widely used HDV fuel. The share of diesel falls from 92% of total HDV energy use in 2013—with the remainder 7% motor gasoline and 1% gaseous (propane, natural gas, liquefied natural gas)—to 87% diesel in 2040, with natural gas, either compressed or liquefied, accounting for 7% of HDV energy use in 2040 as the economics of natural gas fuels improve and the refueling infrastructure expands.

The largest differences from the Reference case level of HDV energy consumption in 2040 are in the High and Low Economic Growth cases (9.4 quadrillion Btu and 6.3 quadrillion Btu, respectively), as a result of their higher and lower projections for travel demand, respectively. Notably, the use of natural gas is significantly higher in the High Oil Price case than in the Reference case, at nearly 30% of total HDV energy use in 2040.

Future gasoline vehicles are strong competitors when compared with other vehicle technology types on the basis of fuel economics

Several fuel-efficient technologies are currently, or are expected to be, available for all vehicle fuel types. Those technologies will enable manufacturers to meet upcoming CAFE and GHG emissions standards at a relatively modest cost, predominately with vehicles powered by gasoline only or with gasoline-powered vehicles employing micro hybrid systems. Because of diminishing returns from improved fuel economy, future gasoline vehicles, including those with micro hybrid systems, are strong competitors when compared with other, more expensive vehicle technology types on the basis of fuel economics. Even though the price of vehicles that use some electric drive for motive power is projected to decline, in some cases significantly, their relative cost-effectiveness does not improve over the projection period, due to advances in gasoline-only and gasoline micro hybrid vehicles. While the reasons for consumer vehicle purchases vary and are not always on a strictly economic basis, wider market acceptance would require more favorable fuel economics—as seen in the High Oil Price case, where sales of plug-in hybrid and electric vehicle sales more than double.

Figure Midsize passenger car fuel economy and vehicle price by technology type in the reference case, 2015-2040


figure data

In 2040, compared with gasoline vehicles, fuel cost savings would be $227/year for an electric-gasoline hybrid, with a “payback period” of approximately 13 years for recovery of the difference in vehicle purchase price compared with a conventional gasoline vehicle; $247/year for a PHEV10, with a 27-year payback period; $271/year for a PHEV40, with a 46-year payback period; and $469/year for a 100% electric drive vehicle, with a 19-year payback period. These results are based on the following assumptions for each vehicle type: 12,000 miles traveled per year; average motor gasoline price of $3.90 per gallon; average electricity price of $0.12 per kilowatthour; and 0% discount rate. For plug-in hybrids it is assumed that a hybrid electric 10 (PHEV10) will use electric drive power for 21% of total miles traveled, and a hybrid electric 40 (PHEV40) for 58% of total miles traveled. The assumed vehicle purchase prices do not reflect national or local tax incentives.

The Annual Energy Outlook 2015 includes several types of light-duty vehicle hybrid technology.

Micro hybrids, also known as start/stop technology, are those vehicles with an electrically powered auxiliary system that allow the internal combustion engine to be turned off when the vehicle is coasting or idle and then quickly restarted. These systems do not provide power to the wheels for traction and can use regenerative braking to recharge the batteries.

Mild hybrids are those vehicles that, in addition to start/stop capability, provide some power assist to the wheels but no electriconly motive power. Full hybrid electric vehicles can, in addition to start/stop and mild capabilities, operate at slow speeds for limited distances on the electric motor and assists the drivetrain throughout its drive cycle.

Full hybrid electric vehicle systems are configured in parallel, series, or power split systems, depending on how power is delivered to the drivetrain.

Plug-in hybrid electric vehicles have larger batteries to provide power to drive the vehicle for some distance in charge-depleting mode, until a minimum level of battery power is reached (a “minimum state of charge”), at which point they operate on a mixture of battery and internal combustion engine power (“charge-sustaining mode”). PHEVs also can be engineered to run in a “blended mode,” using an onboard computer to determine the most efficient use of battery and engine power. The battery can be recharged either from the grid (plugging a power cord into an electrical outlet) or by the engine.

Aircraft energy consumption increases from 2.3 quadrillion Btu in 2013 to 3.1 quadrillion Btu in 2040, with growth in personal air travel partially offset by gains in aircraft fuel efficiency. Energy consumption by marine vessels (including international marine, recreational boating, and domestic marine) remains flat, as increases in demand for international marine and recreational boating are offset by declines in fuel use for domestic marine vessels. The decline in domestic marine energy use is the result of improved efficiency and the continuation of the historical decline in travel demand. In the near term, distillate fuel provides a larger share of the fuel used by marine vessels, the result of stricter fuel and emissions standards. Pipeline energy use increases slowly, with growing volumes of natural gas produced from tight formations that are relatively close to end-use markets. Energy consumption for rail travel (freight and passenger) also remains flat, as improvement in locomotive fuel efficiency offsets growth in travel demand. In 2040, natural gas provides about a third of the fuel used for freight rail.

Industrial

Delivered energy consumption in the industrial sector totaled 24.5 quadrillion Btu in 2013, representing approximately 34% of total U.S. delivered energy consumption. In the AEO2015 Reference case, industrial delivered energy consumption grows at an annual rate of 0.7% from 2013 to 2040. The annual growth rate is much higher from 2013 to 2025 (1.3%) than from 2025 to 2040 (0.2%), as increased international competition slows industrial production growth and energy efficiency continues to improve in the industrial sector over the long term. Among the alternative cases, delivered industrial energy consumption grows most rapidly in the High Economic Growth case at 1.2%/year, almost twice the rate in the Reference case. The slowest growth in industrial energy consumption is projected in the Low Economic Growth case, at 0.4%/year from 2013 to 2040 (Figure 12).

Figure 12 Industrial sector total delivered energy consumption in three case, 2010-40


figure data

Total industrial natural gas consumption in the AEO2015 Reference case increases from 9.1 quadrillion Btu in 2013 to 11.2 quadrillion Btu in 2040. Natural gas is used in the industrial sector for heat and power, bulk chemical feedstocks, natural gas-toliquids (GTL) heat and power, and lease and plant fuel. The 6.7 quadrillion Btu of natural gas used for heat and power in 2013 was 74% of total industrial natural gas consumption for the year. From 2013 to 2040, natural gas use for heat and power grows by an average of 0.4%/year in the Reference case, with 41% of the total growth occurring between 2013 and 2020. In the High Oil and Gas Resource case, natural gas use for heat and power grows by 0.7%/year from 2013 to 2040, largely as a result of oil and gas extraction activity (Figure 13).

Figure 13 Industrial sector natural gas consumption for heat and power in three cases, 2010-40


figure data

Natural gas use for GTL is responsible for the rapid post-2025 consumption growth in the High Oil Price compared with the other two cases shown in Figure 13. In the High Oil Price case, natural gas use for heat and power increases by 1.0%/year from 2013 to 2040, including significant use for GTL production, which grows to about 1 quadrillion Btu in 2040 in the High Oil Price case. Natural gas use for GTL occurs only in the High Oil Price case. Market conditions (primarily liquid fuel prices) do not support GTL investments in the other cases.

Purchased electricity (excluding electricity generated and used onsite) used by industrial customers in the AEO2015 Reference case grows from 3.3 quadrillion Btu in 2013 to 4.1 quadrillion Btu in 2040. Most of the growth occurs between 2013 and 2025, when it averages 1.7%/year. After 2025, there is little growth in purchased electricity consumption in the Reference case. In the High Economic Growth case, purchased electricity consumption grows by 1.5%/year from 2013 to 2040, which is almost twice the rate in the Reference case. Consumption increases significantly from 2025 to 2040 in the High Economic Growth case, as shipments of industrial products increase relatively more than in the Reference case and do not slow down nearly as much after 2025.

Purchased electricity consumption in the five metal-based durables industries,[20] which accounted for nearly 25% of the industrial sector total in 2013, grows at a slightly higher rate than in other industries in the Reference case. Although metal-based durable industries are not energy-intensive, they are relatively electricity-intensive, and they are by far the largest industry subgroup as measured by shipments in 2013. In the High Economic Growth case, shipments of metal-based durables grow more rapidly than shipments from many of the other industry segments. As a result, purchased electricity consumption in the metal-based durables industries grows by 2.0% per year from 2013 to 2040 in the High Economic Growth case, which is higher than the rate of growth for the industry in the Reference case.

Combined heat and power (CHP) generation in the industrial sector—almost all of which occurs in the bulk chemicals, food, iron and steel, paper, and refining industries—grows by 50% from 147 billion kWh in 2013 to 221 billion kWh in 2040 in the AEO2015 Reference case. Most of the CHP generation uses natural gas, although the paper industry also has a significant amount of renewables-based generation. All of the CHP-intensive industries are also energy intensive. Growth in CHP generation is slightly higher than growth in purchased electricity consumption, despite a shift toward lower energy intensity in the manufacturing and service sectors in the United States.

Bulk chemicals are the most energy-intensive segment of the industrial sector. In the AEO2015 Reference case, energy consumption in the U.S. bulk chemicals industry, which totaled 5.6 quadrillion Btu in 2013, grows by an average of 2.3%/year from 2013 to 2025. After 2025, energy consumption growth in bulk chemicals is negligible, as U.S. shipments of bulk chemicals begin to decrease because of increased international competition.

Approximately 60% of energy use in the bulk chemicals industry over the projection period is for feedstocks. Hydrocarbon gas liquids (HGL)[21] and petroleum products (such as naphtha)[22] are used as feedstocks for organic chemicals, inorganic chemicals, and resins. Growth in natural gas production from shale formations has contributed to an increase in the supply of HGL. Some chemicals can use either HGL or petroleum as feedstock; for those chemicals, the feedstock used depends on the relative prices of natural gas and petroleum. Although HGL or petroleum is used as a feedstock for most chemicals, natural gas feedstocks are used to manufacture methanol and agricultural chemicals. Natural gas feedstock consumption, which constituted roughly 13% of total bulk chemical feedstock consumption in 2013, grows rapidly from 2014 to 2018, reflecting increased capacity in the U.S. agricultural chemicals industry.

Residential and commercial

Delivered energy consumption decreases at an average rate of 0.3%/year in the residential sector and grows by 0.6%/year in the commercial sector from 2013 through 2040 in the AEO2015 Reference case (Figure 14 and Figure 15). Over the same period, the total number of households grows by 0.8%/year, and commercial floorspace increases by 1.0%/year (Table 4). The AEO2015 alternative cases illustrate the effects of different assumptions on residential and commercial energy consumption. Higher or lower economic growth, fuel prices, and fuel resources yield a range of residential and commercial energy demand. Different levels of economic growth affect the number of households more than the amount of commercial floorspace, leading to greater differences in residential energy demand across the cases.

Figure 14 Residential sector delivered energy consumption by fuel in the reference case, 2010-40


figure data

Figure 15 Commercial sector delivered energy consumption by fuel in the Reference case, 2010-40


figure data

Table 4. Residential households and commercial indicators in three AEO2015 cases, 2013 and 2040

 

Indicator 2013 2040 Aveerage annual growth rate, 2013-40
(percent per year)
Residential households (millions)
High Economic Growth 114.3 158.5 1.2
Reference 114.3 141.0 0.8
Low Economic Growth 114.3 127.9 0.4
Commercial floorspace (billion square feet)
High Economic Growth 82.8 112.4 1.1
Reference 82.8 109.1 1.0
Low Economic Growth 82.8 106.0 0.9
Source: AEO2015 National Energy Modeling System, runs REF2015.D021915A, LOWMACRO.D021915A, and HIGHMACRO.D021915A.

 

In the Reference case, electricity consumption in the residential and commercial sectors increases by 0.5%/year and 0.8%/year from 2013 through 2040, respectively, with the growth in residential electricity use ranging from 0.2%/year to 0.9%/year and the growth in commercial electricity use ranging from 0.7% to 0.9%/year in the alternative cases. In all cases, demand shifts from space heating to space cooling as a growing share of the population moves to warmer regions of the country. Miscellaneous electric loads (MELs)—from a variety of devices and appliances that range from microwave ovens to medical imaging equipment— continue to grow in the residential and commercial sectors, showing both increased market penetration (the share of the potential market that uses the device) and saturation (the number of devices per building).

In the commercial sector, the use of computer servers continues to grow to meet increasing needs for data storage, data processing, and other cloud-based services; however, only a small number of servers are installed in large, dedicated data center buildings. Most of the electricity used by servers can be attributed to equipment located in server rooms at the building site in offices, education buildings, and healthcare facilities.

Residential natural gas use declines in the Reference case with improvements in equipment and building shell efficiencies, price increases over time, and reduced heating needs as populations shift. Natural gas consumption in the commercial sector would be relatively flat as a result of efficiency improvements that offset floorspace growth, but increases in natural gas-fueled CHP capacity keep sector consumption trending upward throughout the projection. In the residential and commercial sectors, natural gas prices increase 2.5 and 3.0 times faster, respectively, than electricity prices through 2040 in the Reference case. In the High Oil and Gas Resources case, with lower natural gas prices, commercial delivered natural gas consumption grows by 0.7%/year, or more than twice the rate in the Reference case.

In the residential sector, distillate consumption and propane consumption, primarily for space heating, decline by 2.7%/year and 2.0%/year, respectively, in the Reference case from 2013 to 2040. The declines are even larger in the High Oil Price case, at 3.1%/ year and 2.3%/year for distillate and propane, respectively, over the same period.

End-use energy intensity, as measured by consumption per residential household or square foot of commercial floorspace, decreases in the Reference case as a result of increases in the efficiency of equipment for many end uses (Figure 16 and Figure 17). Federal standards and voluntary market transformation programs (e.g., Energy Star) target uses such as space heating and cooling, water heating, lighting, and refrigeration, as well as devices that are rapidly proliferating, such as set-top boxes and external power supplies.

Figure 16 Residential sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040


figure data

Figure 17 Commercial sector delivered energy intensity for selected end uses in the Reference case, 2013 and 2040


figure data

As a result of collaboration among industry, efficiency advocates, and government, a voluntary agreement for set-top boxes has been issued in lieu of federal standards.[23] Commercial refrigeration standards that will affect walk-in and reach-in coolers and freezers are under discussion among stakeholders.[24] As more states adopt new building codes, shell efficiencies of newly constructed buildings are improving, which will reduce future energy use for heating and cooling in the residential and commercial sectors.

In the AEO2015 Reference case, residential and commercial energy intensities for miscellaneous electric loads (MEL) and nonelectric miscellaneous uses in 2040 are roughly 18% and 23% higher, respectively, than they were in 2013. These devices and appliances vary greatly in their energy use characteristics, and their total energy consumption is closely tied to their levels of penetration and saturation in the buildings sectors. As a result, MEL and nonelectric miscellaneous uses are difficult targets for federal efficiency standards.[25]

Penetration of grid-connected distributed generation continues to grow as both equipment and non-equipment costs decline, slowing delivered electricity demand growth in both residential and commercial buildings. In the AEO2015 Reference case, solar photovoltaic (PV) capacity in the residential sector grows by an average of about 30%/year from 2013 through 2016, compared with 9%/year for commercial sector PV, driven by the recent popularity of third-party leasing and other innovative financing options and tax credits. Following expiration of the 30% federal investment tax credit at the end of 2016, the average annual growth of PV capacity in residential and commercial buildings slows to about 6% in both sectors through 2040.

Natural gas CHP capacity in the commercial sector grows by an average of 9%/year from 2013 to 2040 in the Reference case and shows little variation across the alternative cases. Although natural gas prices are lower in the High Oil and Gas Resource case than in the Reference case, lower electricity prices limit the attractiveness of commercial CHP relative to purchased electricity.

Endnotes

  1. Vocational vehicles include a diverse group of heavy-duty trucks, such as box/delivery trucks, refuse haulers, dump trucks, etc.
  2. The five metal-based durables industries are fabricated metal products (NAICS 332), machinery (NAICS 333), computers (NAICS 335), transportation equipment (NAICS 336), and electrical equipment (NAICS 335).
  3. Hydrocarbon gas liquids are natural gas liquids (NGL) and olefins. NGL include ethane, propane, normal butane, isobutane, and natural gasoline. Olefins include ethylene, propylene, butylene, and isobutylene. See http://www.eia.gov/tools/glossary/index.cfm?id=Hydrocarbon%20gas%20liquids.
  4. Naphtha is a refined or semi-refined petroleum fraction used in chemical feedstocks and many other petroleum products, see http://www.eia.gov/tools/glossary/index.cfm?id=naphtha.
  5. Following a consensus agreement among manufacturers and industry representatives that is expected to achieve significant energy savings, the U.S. Department of Energy (DOE) has withdrawn its proposed rulemaking for set-top boxes. See https://www.federalregister.gov/articles/text/raw_text/201/331/264.txt.
  6. Walk-in coolers and walk-in freezer panels, doors, and refrigeration systems are currently scheduled to comply with the updated standard beginning in August 2017 (see http://www1.eere.energy.gov/buildings/appliance_standards/product.aspx/productid/26), and DOE has denied a petition from the Air-Conditioning, Heating, and Refrigeration Institute (AHRI) to reconsider its final rulemaking (see http://www.energy.gov/sites/prod/ files/2014/09/f18/petition_denial.pdf).
  7. Navigant Consulting Inc. and Leidos—formerly SAIC, Analysis and Representation of Miscellaneous Electric Loads in NEMS, prepared for the U.S. Energy Information Administration (Washington, DC: May 2013), http://www.eia.gov/analysis/studies/demand/miscelectric/.

Energy consumption by primary fuel

Source: http://www.eia.gov/forecasts/aeo/sec...rgyconsump.cfm

Introduction

Total primary energy consumption grows in the AEO2015 Reference case by 8.6 quadrillion Btu (8.9%), from 97.1 quadrillion Btu in 2013 to 105.7 quadrillion Btu in 2040 (Figure 18). Most of the growth is in consumption of natural gas and renewable energy. Consumption of petroleum products across all sectors in 2040 is unchanged from 2013 levels, as motor gasoline consumption in the transportation sector declines as a result of a 70% increase in the average efficiency of on-road light-duty vehicles (LDVs), to 37 mpg in 2040, which more than offsets projected growth in vehicle miles traveled (VMT). Total motor gasoline consumption in the transportation sector is about 3.4 quadrillion Btu (1.8 million barrels per day (bbl/d)) lower in 2040 than in 2013, and total petroleum consumption in the transportation sector is about 1.6 quadrillion Btu (0.9 million bbl/d) lower in 2040 than in 2013.

Figure 18 Primary energy consumption by fuel in the Reference case, 1980-2040


figure data

U.S. consumption of petroleum and other liquids, which totaled 35.9 quadrillion Btu (19.0 million bbl/d) in 2013, increases to 37.1 quadrillion Btu (19.6 million bbl/d) in 2020, then declines to 36.2 quadrillion Btu (19.3 million bbl/d) in 2040. In the transportation sector, which continues to dominate demand for petroleum and other liquids, there is a shift from motor gasoline to distillate. The gasoline share of total demand for transportation petroleum and other liquids declines by 10.6 percentage points, while distillate consumption increases by 7.2 percentage points. Increased use of compressed natural gas and LNG in vehicles also replaces about 3% of petroleum and other liquids consumption in the transportation sector in 2040. Consumption of ethane and propane (the latter including propylene), which are used in chemical production, shows the largest increase of all petroleum products in the AEO2015 Reference case from 2013 to 2040. Industrial consumption of ethane and propane, extracted from wet gas in natural gas processing plants, grows by almost 1 quadrillion Btu (790 thousand bbl/d) as dry natural gas production increases.

Natural gas consumption in the AEO2015 Reference case increases from 26.9 quadrillion Btu (26.2 Tcf) in 2013 to 30.5 quadrillion Btu (29.7 Tcf) in 2040. The largest share of the growth is for electricity generation in the electric power sector, where demand for natural gas grows from 8.4 quadrillion Btu (8.2 Tcf) in 2013 to 9.6 quadrillion Btu (9.4 Tcf) in 2040, in part as a result of the retirement of 40.1 GW of coal-fired capacity by 2025. Natural gas consumption in the industrial sector also increases, rapidly through 2016 and then more slowly through 2040, benefiting from the increase in shale gas production that is accompanied by slower growth of natural gas prices. Industries such as bulk chemicals, which use natural gas as a feedstock, are more strongly affected than others. Natural gas use as a feedstock in the chemical industry increases by about 0.4 quadrillion Btu from 2013 to 2040. In the residential sector, natural gas consumption declines from 2018 to 2040 and it increases slightly in the commercial sector over the same period.

Coal use in the Reference case grows from 18.0 quadrillion Btu (925 million short tons) in 2013 to 19.0 quadrillion Btu (988 million short tons) in 2040. As previously noted, the Reference case and other AEO2015 cases do not include EPA’s proposed Clean Power Plan, which if it is implemented is likely to have a significant effect on coal use. Coal use in the industrial sector falls off slightly over the projection period, as steel production becomes more energy efficient. On the other hand, if oil prices were significantly higher than projected in the Reference case, coal could be used to make liquids via the Fischer-Tropsch process. In the High Oil Price case—the only AEO2015 case in which coal-to-liquids (CTL) technology becomes economically viable—liquids production from CTL plants totals about 710,000 bbl/d in 2040, representing about 3.3 quadrillion Btu (including liquids value), or about 180 million short tons, of coal consumption.

Consumption of marketed renewable energy increases by about 3.6 quadrillion Btu in the Reference case, from 9.0 quadrillion Btu in 2013 to 12.5 quadrillion Btu in 2040, with most of the growth in the electric power sector. Hydropower, the largest category of renewable electricity generation in 2013, contributes little to the increase in renewable fuel consumption. Wind-powered generation, the second-largest category of renewable electricity generation in 2013, becomes the largest contributor in 2038 (including wind generation by utilities and end-users onsite). However, solar photovoltaics (6.8%/year), geothermal (5.5%/ year), and biomass (3.1%/year) all increase at faster average annual rates than wind (2.4%/year), including all sectors. Modest penetration of E85 and a small increase in liquids blended into diesel fuel result in a slight increase in consumption of renewable liquid fuels for transportation, despite a smaller pool for ethanol blending as a result of a projected overall decrease in motor gasoline consumption in the AEO2015 Reference case.

In the High Oil Price case, total primary energy use in 2040 is 109.7 quadrillion Btu, 3.9 quadrillion Btu higher than in the Reference case, even though total liquids consumption in 2040 is 3.3 quadrillion Btu lower, despite an 0.3 quadrillion Btu increase in renewable liquids. The decrease in petroleum and other liquids consumption is more than offset by increased consumption of natural gas (31.8 quadrillion Btu in 2040, 1.3 quadrillion Btu more than in the Reference case), coal (21.6 quadrillion Btu in 2040, 2.6 quadrillion Btu more, not including the Fischer-Tropsch coal consumed as liquids), nuclear (9.8 quadrillion Btu in 2040, 1.1 quadrillion Btu more), and many renewables (13.2 quadrillion Btu in 2040, 2.3 quadrillion Btu more, not including consumption of liquids from renewable fuels). The increases in coal and natural gas consumption are explained by the attractiveness of turning them into liquid fuels, made profitable by higher oil prices despite lower demand for motor gasoline and diesel fuels.

Uncertainty about economic growth results in the widest variation in the projections for total primary energy consumption in 2040, ranging from 98.0 quadrillion Btu in the Low Economic Growth case (1.8% average annual growth in real GDP measured in 2009 dollars) to 116.2 quadrillion Btu in the High Economic Growth case (2.9% average annual growth in real GDP). Changes in the assumed rate of economic growth lead to variations in the growth of energy consumption across all fuels, whereas changes in crude oil prices or in the size of the oil and natural gas resource base result in shifts among the fuel types consumed, with some fuels gaining share and others losing share. In the Low Oil Price case, the petroleum and other liquids share of total energy consumption is about 36.4% in 2040; in the High Oil Price case, it is 30.0% in the same year. With cheaper natural gas in the High Oil and Gas Resource case, less electricity is generated from coal and renewable fuels.

Energy intensity

Source: http://www.eia.gov/forecasts/aeo/sec...gyintesity.cfm

Introduction

Energy intensity (measured both by energy use per capita and by energy use per dollar of GDP) declines in the AEO2015 Reference case over the projection period (Figure 19). While a portion of the decline results from a small shift from energy-intensive to nonenergy-intensive manufacturing, most of it results from changes in other sectors.

Figure 19 Energy use per capita and per 2009 dollar of gross domestic product, and carbon dioxide emissions per 2009 dollar of gross domestic product, in the Reference case, 1980-2040


figure data

Increasing energy efficiency reduces the energy intensity of many residential end uses between 2013 and 2040. Total energy consumption for space heating is 4.2 quadrillion Btu in 2040, 1.7 quadrillion Btu (57%) lower than it was in 2013, despite a 23% increase in the number of households and an 11% increase in the average size (square feet) of a household. Energy use for lighting is 0.8 quadrillion Btu in 2040, 1.0 quadrillion Btu lower than it was in 2013 reflecting a 57% decline in energy use despite an increase in lighting services. Energy use for computers and related equipment is 0.1 quadrillion Btu, 0.2 quadrillion Btu lower than it was in 2013. Improved efficiency also reduces delivered energy use in the transportation sector from 27.0 quadrillion Btu in 2013 to 26.5 quadrillion Btu in 2040, by 0.5 quadrillion Btu, as motor gasoline consumption declines by 3.4 quadrillion Btu. The result is an average annual reduction in energy use per capita of 0.4%/year from 2013 through 2040 and an average annual decline in energy use per 2009 dollar of GDP of 2.0%/year. As renewable fuels and natural gas account for larger shares of total energy consumption, carbon intensity (CO2 emissions per unit of GDP) declines by 2.3%/year from 2013 to 2040.

Macroeconomic growth has the largest impact on energy intensity among the AEO2015 alternative cases. Real GDP grows by an average of 1.8%/year from 2013 to 2040 in the Low Economic Growth case, and population grows by an average of 0.6%/year over the same period. Even though energy use increases only slightly (growing by 0.9 quadrillion Btu from 2013 to 2040) because GDP growth is lower than in the other cases, energy intensity as measured in relationship to GDP declines the least—an average rate of 1.8% per year from 2013 to 2040. However, the same case shows the largest decline in energy use per person, averaging 0.5%/year from 2013 to 2040. In the High Economic Growth case, real GDP increases at an average annual rate of 2.9%/year, population grows at an average annual rate of 0.8%/year, and energy use increases at an average annual rate of 0.7%/year from 2013 to 2040. As a result, the energy intensity of GDP declines at a slightly higher rate than in the Reference case, while the decline in energy use per person is slower than in the Reference case.

Energy production, imports, and exports

Source: http://www.eia.gov/forecasts/aeo/sec...energyprod.cfm

Introduction

Net U.S. imports of energy declined from 30% of total energy consumption in 2005 to 13% in 2013, as a result of strong growth in domestic oil and dry natural gas production from tight formations and slow growth of total energy consumption. The decline in net energy imports is projected to continue at a slower rate in the AEO2015 Reference case, with energy imports and exports coming into balance around 2028 (although liquid fuel imports continue, at a reduced level, throughout the Reference case) (Figure 20). From 2035 to 2040, energy exports account for about 23% of total annual U.S. energy production in the Reference case. Economic growth has a major influence on U.S. energy consumption, imports, and exports. In the High Economic Growth case, the United States remains a net energy importer through 2040, with net imports equal to about 3% of consumption in 2040. In the Low Economic Growth case, the United States becomes a net exporter of energy in 2022, with energy exports equal to 4% of total domestic energy production in 2040.

Figure 20 Total energy production and consumption in the Reference case, 1980-2040


figure data

Changes in the world oil price affect both consumption and production, but in opposite directions from the effects of changes in U.S. economic growth. Higher world oil prices place downward pressure on consumption while making domestic production more profitable. In the Low Oil Price case, with lower domestic production and higher U.S. energy consumption, the United States remains a net energy importer, with imports increasing every year from 2033 to 2040 and net imports equal to 9% of total domestic energy consumption in 2040. In the High Oil Price case, with stronger growth in production and more incentives for energy efficiency, the United States becomes and remains a net energy exporter starting in 2019, and net exports increase to 9% of total energy production in 2040 after peaking at 11% in 2032. In the High Oil and Gas Resource case, with faster growth in domestic natural gas and crude oil production, U.S. net energy exports, mostly in the form of petroleum and natural gas, grow to almost 19% of total domestic energy production in 2040.

Petroleum and other liquids

Production from tight formations leads the growth in U.S. crude oil production across all AEO2015 cases. The path of projected crude oil production varies significantly across the cases, with total U.S. crude oil production reaching high points of 10.6 million barrels per day (bbl/d) in the Reference case (in 2020), 13.0 million bbl/d in the High Oil Price case (in 2026), 16.6 million bbl/d in the High Oil and Gas Resource case (in 2039), and 10.0 million bbl/d in the Low Oil Price case (in 2020).

In the Reference case, the existing U.S. competitive advantage in oil refining compared to the rest of the world continues over the projection period. This advantage results in growing gasoline and diesel exports through 2040 in the Reference case. The production of motor gasoline blending components, which totaled 7.9 million bbl/d in 2013, begins declining in 2015 and falls to 7.2 million bbl/d by the end of the projection period, while diesel fuel production rises from 4.2 million bbl/d in 2013 to 5.3 million bbl/d in 2040. As a result of declining consumption of liquid fuels and increasing production of domestic crude oil, net imports of crude oil and petroleum products fall from 6.2 million bbl/d in 2013 (33% of total domestic consumption) to 3.3 million bbl/d in 2040 (17% of domestic consumption) in the Reference case. Growth in gross exports of refined petroleum products, particularly of motor gasoline and diesel fuel, results in a significant increase in net petroleum product exports between 2013 and 2040.

In both the High Oil and Gas Resource and High Oil Price cases, total U.S. crude oil production is higher than in the Reference case mainly as a result of growth in tight oil production, which rises at a substantially faster rate in the near term in both cases than in the Reference case. In the High Oil and Gas Resource case, tight oil production grows in response to assumed higher estimated ultimate recovery (EUR) and technology improvements, closer well spacing, and development of new tight oil formations or additional layers within known tight oil formations. Total crude oil production reaches 16.6 million bbl/d in 2037 in the High Oil and Gas Resource case. In the High Oil Price case, higher oil prices improve the economics of production from new wells in tight formations as well as from other domestic production sources, leading to a more rapid increase in production volumes than in the Reference case. Tight oil production increases through 2022, when it totals 7.4 million bbl/d. After 2022, tight oil production declines, as drilling moves into less productive areas. Total U.S. crude oil production reaches 13.0 million bbl/d by 2025 in the High Oil Price case before declining to 9.9 million bbl/d in 2040 (Figure 21 and Figure 22).

Figure 21 U.S. light oil production in four cases, 2005-40


figure data

Figure 22 U.S. total crude oil production in four cases, 2005-40


figure data

Recent declines in West Texas Intermediate[26] oil prices (falling by 59% from June 2014 to January 2015) have triggered interest in the effect of lower prices on U.S. oil production. In the Low Oil Price case, domestic crude oil production is 9.8 million bbl/d in 2022, 0.7 million bbl/d lower than the 10.4 million bbl/d in the Reference case. In 2040, U.S. crude oil production is 7.1 million bbl/d, 2.3 million bbl/d lower than the 9.4 million bbl/d in the Reference case. Most of the difference in total crude oil production levels between the Reference and Low Oil Price cases reflects changes in production from tight oil formations. However, all sources of U.S. oil production are adversely affected by low oil prices. As crude oil prices fall and remain at or below $76/ barrel (Brent) in the Low Oil Price case after 2014, poor investment returns lead to fewer wells being drilled in noncore areas of formations, which have smaller estimated ultimate recoveries (EURs) than wells drilled in core areas. As a result, they have a more limited impact on total production growth in the near term.

In both the High Oil and Gas Resource and High Oil Price cases, growing production of 27°–35° American Petroleum Institute (API) medium sour crude oil from the offshore Gulf of Mexico (GOM) helps balance the crude slate when combined with the increasing production of light, sweet crude from tight oil formations. In all cases, GOM crude oil production increases through 2019, as offshore deepwater projects have relatively long development cycles that have already begun. GOM production declines through at least 2025 in all cases and fluctuates thereafter as a result of the timing of large, discrete discoveries that are brought into production. Overall GOM production through 2040 is highest in the High Oil and Gas Resource case, followed closely by the High Oil Price case and finally by the Reference case and Low Oil Price case.

In the High Oil Price case, producers take greater advantage of CO2-enhanced oil recovery (CO2-EOR) technologies. CO2-EOR production increases at a steady pace over the projection period in the Reference case and increases more dramatically in the High Oil Price case, where higher prices make additional CO2-EOR projects economically viable. In the High Oil and Gas Resource and Low Oil Price cases, with lower crude oil prices, fewer CO2-EOR projects are economical than in the Reference case.

Production of natural gas plant liquids (NGPL), including ethane, propane, butane, isobutane, and natural gasoline, increases from 2013 to 2023 in all the AEO2015 cases. After 2023, only the High Oil and Gas Resource case shows increasing NGPL production through the entire projection period. However, the High Oil Price case also shows significant NGPL production growth through 2026. Most of the early growth in NGPL production is associated with the continued development of liquids-rich areas in the Marcellus, Utica, and Eagle Ford formations.

Production of petroleum products at U.S. refineries depends largely on the cost of crude oil, domestic demand, and the absorption of petroleum product exports in foreign markets. U.S. refinery production of gasoline blending components declines in the Reference and Low Oil Price cases but increases in the High Oil Price and High Oil and Gas Resource cases. The steepest decline in production of motor gasoline blending components is projected in the Reference case, with production of blending components declining from 7.9 million bbl/d in 2013 to 7.2 million bbl/d in 2040, in response to a drop in U.S. crude oil production, higher crude oil prices, and lower demand. In the High Oil and Gas Resource case, production of blending components increases to 9.1 million bbl/d in 2040, because abundant domestic supply of lighter crude oil results in lower feedstock costs for refiners, lower gasoline prices, increased exports, and relatively higher levels of gasoline consumption (including exports) and production.

Diesel fuel output from U.S. refineries rises in the High Oil and Gas Resource case from 4.2 million bbl/d in 2013 to 6.6 million bbl/d in 2037, as a result of lower costs for refinery feedstocks. In the Low Oil Price case, lower domestic diesel fuel prices result in higher levels of domestic consumption, leading to a 4.7 million bbl/d increase in diesel fuel production in 2040. In the High Oil Price case, higher oil prices (which are assumed to occur worldwide) make diesel fuel from U.S. refineries more competitive. Total U.S. diesel fuel output increases to 6.1 million bbl/d in 2040. In the Reference case, U.S. diesel fuel output increases to 5.3 million bbl/d in 2040.

As in the Reference case, the United States remains a net importer of liquid fuels through 2040 in the Low Oil Price case. In the High Oil and Gas Resource case, as a result of higher levels of both domestic crude oil production and petroleum product exports, the United States becomes a net exporter of liquid fuels by 2021. Refiners and oil producers gain a competitive advantage from abundant domestic supply of light crude oil and higher GOM production of lower API crude oil streams, along with lower refinery fuel costs as a result of abundant domestic natural gas supply. In the High Oil Price case, the United States becomes a net exporter of liquid fuels in 2020, as higher oil prices reduce U.S. consumption of petroleum products and spur additional U.S. crude oil production. U.S. net crude oil imports—which fall to 5.5 million bbl/d in 2022 as domestic crude oil production grows—rise to 8.9 million bbl/d in 2040 as domestic production flattens and begins to decline.

By 2040, the level of net liquid fuels exports is significantly larger in the High Oil and Gas Resource case than in the High Oil Price case. In the High Oil Price case, higher world crude oil prices make overseas refineries less competitive compared to U.S. refineries. As a result, net U.S. exports of petroleum products increase by more in the High Oil Price case than in the High Oil and Gas Resource case. However, the availability of more domestic crude oil resources in the High Oil and Gas Resource case results in a significantly greater drop in net crude oil imports and a larger overall swing in liquid fuels trade than in any of the other AEO2015 cases (Figure 23 and Figure 24).

Figure 23 U.S. net crude oil imports in four cases, 2005-40


figure data

Figure 24 U.S. net petroleum product imports in four cases, 2005-40


figure data

In the High Oil and Gas Resource case, the United States swings from net liquid fuels imports equal to 33% of total domestic product supplied in 2013 to net liquid fuels exports equal to 29% of total domestic product supplied in 2040 (compared with net exports equal to 3% of total domestic product supplied in 2040 in the High Oil Price case). In the Reference case, net imports fall to 14% of total domestic product supplied in 2020, before rising to nearly 18% of product supplied in 2033 and remaining around that level through 2040. Net imports of liquid fuels fall to 19% of total product supplied in 2020 in the Low Oil Price case before rising to 36% of total product supplied in 2040.

Cheaper light crude oil production from inland basins and increased production of heavier GOM crude oil leads to a 35% decline in gross crude oil imports in the High Oil and Gas Resource case—from 7.7 million bbl/d in 2013 to 5.0 million bbl/d in 2040. This compares with a 6% increase in the Reference case (to 8.2 million bbl/d in 2040) and a 12% increase in the Low Oil Price case (to 8.7 million bbl/d in 2040).

Net petroleum product exports increase as U.S. refineries become more competitive in all cases except for the Low Oil Price case. Net petroleum product exports increase most in the High Oil Price and High Oil and Gas Resource cases (from 1.4 million bbl/d in 2013 to 9.5 million bbl/d and 9.9 million bbl/d, respectively, in 2040). In the Reference case, net petroleum product exports increase to 4.3 million bbl/d in 2040, and in the Low Oil Price case they increase to 2.2 million bbl/d in 2020 and then decline to 0.7 million bbl/d in 2040.

In the High Oil and Gas Resource case, gross crude oil exports allowed under current laws and regulations, including exports to Canada and exports of processed condensate, rise significantly in response to increased production. It is assumed that condensate which has been processed through a distillation tower can be exported in accordance with a clarification from the U.S. Department of Commerce, Bureau of Industry and Security.[27] Gross crude exports increase from 0.1 million bbl/d in 2013 to a high of 1.3 million bbl/d in 2027 in the High Oil and Gas Resource case, before declining to 0.9 million bbl/d in 2040—compared with 0.6 million bbl/d in 2040 in the Reference, High Oil Price, and Low Oil Price cases. With U.S. refinery access to increased amounts of low-cost domestic crude supplies, gross petroleum product exports increase from 3.4 million bbl/d in 2013 to 12.0 million bbl/d in the High Oil and Gas Resource case and to 11.5 million bbl/d in 2040 in the High Oil Price case, compared with 6.4 million bbl/d in the Reference case and 3.5 million bbl/d in the Low Oil Price case.

Natural gas

Production

Total dry natural gas production in the United States increased by 35% from 2005 to 2013, with the natural gas share of total U.S. energy consumption rising from 23% to 28%. Production growth resulted largely from the development of shale gas resources in the Lower 48 states (including natural gas from tight oil formations), which more than offset declines in other Lower 48 onshore production. In the AEO2015 Reference case, more than half of the total increase in shale gas production over the projection period comes from the Haynesville and Marcellus formations. Lower 48 shale gas production (including natural gas from tight oil formations) increases by 73% in the Reference case, from 11.3 Tcf in 2013 to 19.6 Tcf in 2040, leading to a 45% increase in total U.S. dry natural gas production, from 24.4 Tcf in 2013 to 35.5 Tcf in 2040. Growth in tight gas, federal offshore, and onshore Alaska production also contributes to overall production growth over the projection period (Figure 25 and Figure 26).

Figure 25 U.S. total dry natural gas production in four cases, 2005-40


figure data

Figure 26 U.S. shale gas production in four cases, 2005-40


figure data

Future dry natural gas production depends primarily on the size and cost of tight and shale gas resources, technology improvements, domestic natural gas demand, and the relative price of oil. Projections in the High Oil and Gas Resource case assume closer well spacing; higher EURs per shale gas well, tight gas well, and tight oil well; development of new tight oil formations either from new discoveries or additional layers within known tight oil formations; and additional long-term technology improvements that further increase the EUR per tight gas and shale gas well over the projection period above those in the Reference case. Even with lower prices, total U.S. dry natural gas production increases in the High Oil and Gas Resource case to 50.6 Tcf in 2040, 43% above the Reference case level, with Lower 48 shale gas production of 34.6 Tcf in 2040, or 77% above the Reference case level.

The High and Low Oil Price cases use the same natural gas resource assumptions as the Reference case, but production levels vary in response to natural gas demand, primarily from the transportation sector and global demand for U.S.-origin LNG. In the High Oil Price case, increased demand for natural gas as a fuel for motor vehicles, as LNG for export, and as plant fuel for natural gas liquefaction facilities accounts for the increase in total domestic dry natural gas production to 41.1 Tcf in 2040 (16% above the Reference case). U.S. shale gas production in the High Oil Price case totals 23.6 Tcf in 2040, 21% above the Reference case total. In the Low Oil Price case, with lower demand for natural gas and LNG exports, U.S. dry natural gas production totals 31.9 Tcf in 2040 (10% below the Reference case total), and U.S. shale gas production totals 18.1 Tcf in 2040 (8% below the Reference case).

Tight gas accounts for a smaller, but still significant, portion of the increase in U.S. dry natural gas production compared to shale gas. Tight gas production responds largely to crude oil prices and the same levels of technological progress experienced with shale gas production. Tight gas production increases from 4.4 Tcf in 2013 to 7.0 Tcf in 2040 in the Reference case, compared with 8.1 Tcf in 2040 in the High Oil and Gas Resource case, 8.4 Tcf in the High Oil Price case, and 6.6 Tcf in the Low Oil Price case. Most of the tight gas production growth occurs in the Gulf Coast and Dakotas/Rocky Mountains regions. Tight gas production in the Midcontinent region—which declines in the Reference case—increases by 24% from 2013 to 2040 in the High Oil and Gas Resource case.

Undiscovered crude oil and natural gas resources in the federal offshore and Alaska regions are assumed to be 50% higher in the High Oil and Gas Resource case than in the Reference case. Lower 48 offshore natural gas production increases from 1.5 Tcf in 2013 to 3.0 Tcf in 2040 in the High Oil and Gas Resource case, and to 2.8 Tcf in 2040 in both the High Oil Price and Reference cases. Cumulative federal offshore natural gas production is highest in the High Oil Price case, with federal offshore natural gas production increasing more than in any of the other AEO2015 cases through 2036, before declining. Alaska dry natural gas production begins increasing in 2026 in the High Oil Price case, and in 2027 in the Reference case. Alaska dry natural gas production reaches 1.2 Tcf in 2029 and remains at that level through 2040 in the High Oil Price case. Alaskan production reaches 1.1 Tcf in 2040 in the Reference case, following the projected completion of a new LNG export facility in Alaska. In the Low Oil Price and High Oil and Gas Resource cases, lower international natural gas prices make LNG exports from Alaska uneconomical, and Alaska dry natural gas production falls through 2040 as declines in oil production result in decreased use of natural gas for drilling operations.

Imports and exports

In all the AEO2015 cases, net natural gas imports continue to decline through 2040, as they have since 2007. Gross exports of natural gas increase over the period, and gross imports decline. The rate of decline in net imports varies across the cases— depending on assumptions about changes in world oil prices and U.S. natural gas resources—and slows in the later years of the projections (Figure 27). In all the cases, the United States becomes a net exporter of natural gas in 2017, driven by LNG exports (Figure 28), increased pipeline exports to Mexico, and reduced imports from Canada.

Figure 27 U.S. total natural gas net imports in four cases, 2005-40


figure data

Figure 28 U.S. liquefied natural gas imports in four cases, 2005-40


figure data

In the Reference case, net exports of natural gas from the United States total 5.6 Tcf in 2040. Most of the growth in U.S. net natural gas exports occurs before 2030, when gross liquefied natural gas (LNG) exports reach their highest level of 3.4 Tcf, where they remain through 2040. In all the cases, the United States remains a net pipeline importer of natural gas from Canada through 2040, but at lower levels than in recent history, while net pipeline exports of natural gas to Mexico grow from 0.7 Tcf in 2013 to 3.0 Tcf in 2040 in the Reference case.

The price of LNG supplied to international markets, which in part reflects world oil prices, is significantly higher than the price of U.S. domestic natural gas supply, particularly in the near term. The growth in U.S. LNG exports is driven by this price difference, which also discourages U.S. LNG imports. LNG export growth after 2020 is highest in the High Oil and Gas Resource case, where higher production capability lowers the price of U.S. natural gas supply to the world market, leading to net LNG exports of 10.3 Tcf in 2040 (212% more than in the Reference case) and total net natural gas exports of 13.1 Tcf in 2040 (133% more than in the Reference case).

Most of the variations in projected net exports of U.S. natural gas among the AEO2015 cases result from differences in levels of LNG exports. In the High Oil Price and Low Oil Price cases, projected LNG exports vary in response to differences between international and domestic natural gas prices, after accounting for the costs associated with processing and transporting the gas. Over the projection, the relationship between international LNG prices and world oil prices is assumed to weaken, particularly as U.S. LNG exports increase. Low world oil prices limit the competitiveness of domestic natural gas relative to oil itself and also to LNG volumes sold through contracts linked to oil prices, which are less likely to be renegotiated in a low oil price environment.

In the High Oil Price case, U.S. LNG exports total 8.1 Tcf in 2040, or 142% more than in the Reference case. As a result, U.S. net natural gas exports total 9.1 Tcf in 2040 in the High Oil Price case, or 63% more than in the Reference case. In the Low World Oil Price case, LNG net exports never surpass 0.8 Tcf, and U.S. net exports of natural gas total 3.0 Tcf in 2040, or 46% below the Reference case level.

Canada, which accounted for 97% of total U.S. pipeline imports of natural gas in 2013, continues as the source of nearly all U.S. pipeline imports through 2040. Most natural gas imported into the United States comes from western Canada and is delivered mainly to the West Coast and the Midwest.

In the AEO2015 alternative cases, gross pipeline imports from Canada generally are higher than in the Reference case when prices in the United States are higher, and vice versa. However, gross pipeline imports from Canada in 2040 are highest in the High Oil and Gas Resource case, with growth after 2030 resulting from an assumed increase in Canada’s shale and coalbed resources. Gross exports of U.S. natural gas to Canada, largely into the eastern provinces, generally increase when prices are low in the United States, and vice versa.

U.S. pipeline exports of natural gas—most flowing south to Mexico—have grown substantially since 2010 and are projected to continue increasing in all the AEO2015 cases because increases in Mexico’s production are not expected to keep pace with the country’s growing demand for natural gas, primarily for electric power generation. In the High Oil and Gas Resource case, with the lowest projected U.S. natural gas prices, pipeline exports to Mexico in 2040 total 4.7 Tcf, as compared with 3.3 Tcf in the Low Oil Price case and 2.2 Tcf by 2040 in the High Oil Price case.

Coal

Between 2008 and 2013, U.S. coal production fell by 187 million short tons (16%), as declining natural gas prices made coal less competitive as a fuel for generating electricity (Figure 29). In the AEO2015 Reference case, U.S. coal production increases at an average rate of 0.7%/year from 2013 to 2030, from 985 million short tons (19.9 quadrillion Btu) to 1,118 million short tons (22.4 quadrillion Btu). Over the same period, rising natural gas prices, particularly after 2017, contribute to increases in electricity generation from existing coal-fired power plants as coal prices increase more slowly. After 2030, coal consumption for electricity generation levels off through 2040. The cases presented in AEO2015 do not include EPA’s proposed Clean Power Plan, which would have a material impact on projected levels of coal-fired generation. A separate EIA analysis of the Clean Power Plan is forthcoming.

Figure 29 U.S. coal production in six cases, 1990-2040


figure data

Compliance with the Mercury and Air Toxics Standards (MATS),[28] coupled with low natural gas prices and competition from renewables, leads to the projected retirement of 31 gigawatts (GW) of coal-fired generating capacity and the conversion of 4 GW of coal-fired generating capacity to natural gas between 2014 and 2016. However, coal consumption in the U.S. electric power sector is supported by an increase in output from the remaining coal-fired power plants, with the projected capacity factor for the U.S. coal fleet increasing from 60% in 2013 to 67% in 2016. In the absence of any significant additions of coal-fired electricity generating capacity, coal production after 2030 levels off as many existing coal-fired generating units reach maximum capacity factors and coal exports grow slowly. Total U.S. coal production in the AEO2015 Reference case remains below its 2008 level through 2040.

Across the AEO2015 alternative cases, the largest changes in U.S. coal production relative to the Reference case occur in the High Oil and Gas Resource and High Oil Price cases. In the High Oil and Gas Resource case, lower natural gas prices lead to a significant shift away from the use of coal in the electric power sector, resulting in coal production levels that are 13% lower in 2020 and 11% lower in 2040 than in the Reference case. In the High Oil Price case, higher oil prices spur investments in coal-based synthetic fuels, which result in increasing demand for domestically produced coal, primarily from mines in the Western supply region. In the High Oil Price case, coal consumption at coal-to-liquids (CTL) plants rises from 11 million short tons in 2025 to 181 million short tons in 2040, and total coal production in 2040 is 13% higher than in the Reference case.

In the other AEO2015 cases, variations in the quantities of coal produced relative to the Reference case are more modest, ranging from 4% (49 million short tons) lower in the Low Economic Growth case to 4% (40 million short tons) higher in the High Economic Growth case in 2040. Factors that limit the variation in U.S. coal production across cases include the high capital costs associated with building new coal-fired generating capacity, which limit potential growth in coal use; the relatively low operating costs of existing coal-fired units, which tend to limit the decline in coal use; and limited potential to increase coal use at existing generating units, which already are at maximum utilization rates in some regions.

Changes in assumptions about the rate of economic growth also affect the outlook for coal demand in the U.S. industrial sector (coke and other industrial plants) and, consequently, coal production. In the Low Economic Growth case, lower levels of industrial coal consumption in 2040 account for 17% of the reduction in total coal consumption relative to the Reference case. In the High Economic Growth case, higher levels of coal consumption in the industrial sector in 2040 account for 44% of the increase in total coal consumption relative to the Reference case.

Regionally, strong production growth in the Interior region contrasts with declining production in the Appalachian region in the AEO2015 Reference case. In the Interior region, coal production becomes increasingly competitive as a result of a combination of improving labor productivity and the installation of scrubbers at existing coal-fired power plants, which allows those plants to burn the region’s higher-sulfur coals at a lower delivered cost compared with coal from other regions. Appalachian coal production declines in the Reference case, as coal produced from the extensively mined, higher-cost reserves of Central Appalachia is replaced by lower-cost coals from other regions. Western coal production in the Reference case increases from 2017 to 2024, in line with the increase in U.S. consumption, but falls slightly thereafter as a result of competition from producers in the Interior region and limited growth in coal use at existing coal-fired power plants after 2025.

U.S. coal exports decline from 118 million short tons in 2013 to 97 million short tons in 2014 and to 82 million short tons in 2015 in the AEO2015 Reference case, then increase gradually to 141 million short tons in 2040 (Figure 30). Much of the growth in exports after 2015 is attributable to increased exports of steam coal from mines in the Interior and Western regions. Between 2015 and 2040, U.S. steam coal exports increase by 42 million short tons, and coking coal exports increase by 17 million short tons.

Figure 30 U.S. coal exports in six cases, 1990-2040


figure data

Across the AEO2015 alternative cases, U.S. coal exports in 2040 vary from a low of 132 million short tons in the High Oil Price case (6% lower than in the Reference case) to a high of 158 million short tons in the High Oil and Gas Resource case (12% higher than in the Reference case). Coal exports are also higher in the Low Oil Price case than in the Reference case, increasing to 149 million short tons in 2040. In the Low and High Oil Price cases, variations in the prices of diesel fuel and electricity, which are two important inputs to coal mining and transportation, are key factors affecting U.S. coal exports. The projections of lower and higher fuel prices for coal mining and transportation affect the relative competiveness of U.S. coal in international coal markets. In the High Oil and Gas Resource case, the combination of lower prices for diesel fuel and electricity and lower domestic demand for coal contribute to higher export projections relative to the Reference case.

Endnotes

  1. West Texas Intermediate is a crude stream produced in Texas and southern Oklahoma that serves as a reference, or marker, for pricing a number of other crude streams and is traded in the domestic spot market at Cushing, Oklahoma.
  2. U.S. Department of Commerce, Bureau of Industry and Security, “FAQs–Crude Oil and Petroleum Products December 30, 2014” (see question no. 3, “Is lease condensate considered crude oil?”) (Washington, DC: December 30, 2014), http://www.bis.doc.gov/index.php/policy-guidance/faqs.
  3. U.S. Environmental Protection Agency, “Mercury and Air Toxics Standards,”http://www.epa.gov/mats (Washington, DC: March 27, 2012).

Electricity generation

Source: http://www.eia.gov/forecasts/aeo/sec...generation.cfm

Introduction

Total electricity use in the AEO2015 Reference case, including both purchases from electric power producers and on-site generation, grows by an average of 0.8%/year, from 3,836 billion kilowatthours (kWh) in 2013 to 4,797 billion kWh in 2040. The relatively slow rate of growth in demand, combined with rising natural gas prices, environmental regulations, and continuing growth in renewable generation, leads to tradeoffs between the fuels used for electricity generation. From 2000 to 2012, electricity generation from natural gas-fired plants more than doubled as natural gas prices fell to relatively low levels. In the AEO2015 Reference case, natural gas-fired generation remains below 2012 levels until after 2025, while generation from existing coal-fired plants and new nuclear and renewable plants increases (Figure 31). In the longer term, natural gas fuels more than 60% of the new generation needed from 2025 to 2040, and growth in generation from renewable energy supplies most of the remainder. Generation from coal and nuclear energy remains fairly flat, as high utilization rates at existing units and high capital costs and long lead times for new units mitigate growth in nuclear and coal-fired generation. Considerable variation in the fuel mix results when fuel prices or economic conditions differ from those in the Reference case.

Figure 31 Electricity generation by fuel in the reference case, 2000-2040


figure data

AEO2015 assumes the implementation of the Mercury and Air Toxics Standards (MATS) in 2016, which regulates mercury emissions and other hazardous air pollutants from electric power plants. Because the equipment choices to control these emissions often reduce sulfur dioxide emissions as well, by 2016 sulfur dioxide emissions in the Reference case are well below the levels required by both the Clean Air Interstate Rule (CAIR)[29] and the Cross-State Air Pollution Rule (CSAPR).[30],[31]

Total electricity generation increases by 24% from 2013 to 2040 in the Reference case but varies significantly with different economic assumptions, ranging from a 15% increase in the Low Economic Growth case to a 37% increase in the High Economic Growth case. Coal-fired generation is similar across most of the cases in 2040, except the High Oil and Gas Resource case, which is the only one that shows a significant decline from the Reference case, and the High Oil Price case, which is the only one showing a large increase (Figure 32). The coal share of total electricity generation drops from 39% in 2013 to 34% in 2040 in the Referencecase but still accounts for the largest share of total generation. When natural gas prices are lower than those in the Reference case, as in the High Oil and Gas Resource case, the coal share of total electricity generation drops below the natural gas share by 2020. When total electricity generation is reduced in the Low Economic Growth case, and as a result there is less need for new generation capacity, coal-fired generation maintains a larger share of the total.

Figure 32 Electricity generation by fuel in six cases, 2013 and 2040


figure data

Total natural gas-fired generation grows by 40% from 2013 to 2040 in the AEO2015 Reference case—and the natural gas share of total generation grows from 27% to 31%—with most of the growth occurring in the second half of the projection period. The natural gas share of total generation varies by AEO2015 case, depending on fuel prices; however, its growth is also supported by limited potential to increase coal use at existing coal-fired generating units, which in some regions are already at maximum utilization rates. In the High Oil Price case, the natural gas share of total electricity generation in 2040 drops to 23%. In the High Oil and Gas Resource case, with delivered natural gas prices 44% below those in the Reference case, the natural gas share of total generation in 2040 is 42%. Lower natural gas prices in the High Oil and Gas Resource case result in the addition of new natural gas-fired capacity, as well as increased operation of combined-cycle plants, which displace some coal-fired generation. The average capacity factor of natural gas combined-cycle plants is more than 60% in the High Oil and Gas Resource case, compared with an average capacity factor of around 50% in the Reference case (Figure 33), while the average capacity factor of coal-fired plants is lower in the High Oil and Gas Resource case than in the Reference case.

Figure 33 Coal and natural gas combined-cycle generation capacity factors in two cases, 2010-40


figure data

Electricity generation from nuclear units across the cases reflects the impacts of planned and unplanned builds and retirements. Nuclear power plants provided 19% of total electricity generation in 2013. From 2013 to 2040, the nuclear share of total generation declines in all cases, to 15% in the High Oil and Gas Resource case and to 18% in the High Oil Price case, where higher natural gas prices lead to additional growth in nuclear capacity.

Renewable generation grows substantially from 2013 to 2040 in all the AEO2015 cases, with increases ranging from less than 50% in the High Oil and Gas Resource and Low Economic Growth cases to 121% in the High Economic Growth case. State and national policy requirements play an important role in the continuing growth of renewable generation. In the Reference case, the largest growth is seen for wind and solar generation (Figure 34). In 2013, as a result of increases in wind and solar generation, total nonhydropower renewable generation was almost equal to hydroelectric generation for the first time. In 2040, nonhydropower renewable energy sources account for more than two-thirds of the total renewable generation in the Reference case. The total renewable share of all electricity generation increases from 13% in 2013 to 18% in 2040 in the Reference case and to as much as 22% in 2040 in the High Oil Price case. With lower natural gas prices in the High Oil and Gas Resource case, the renewable generation share of total electricity generation grows more slowly but still increases to 15% of total generation in 2040.

Figure 34 Renewable electricity generation by fuel type in the reference case, 2000-2040


figure data

Total electricity generation capacity, including capacity in the end-use sectors, increases from 1,065 GW in 2013 to 1,261 GW in 2040 in the AEO2015 Reference case. Over the first 10 years of the projection, capacity additions are roughly equal to retirements, and the level of total capacity remains relatively flat as existing capacity is sufficient to meet expected demand. Capacity additions between 2013 and 2040 total 287 GW, and retirements total 90 GW. From 2018 to 2024, capacity additions average less than 4 GW/year, as earlier planned additions are sufficient to meet most demand growth. From 2025 to 2040, average annual capacity additions—primarily natural gas-fired and renewable technologies—average 12 GW/year. The mix of capacity types added varies across the cases, depending on natural gas prices (Figure 35).

Figure 35 Cumulative additions to electricity generation capacity by fuel in six cases 2013-40


figure data

In recent years, natural gas-fired capacity has grown considerably. In particular, combined-cycle plants are relatively inexpensive to build in comparison with new coal, nuclear, or renewable technologies, and they are more efficient to operate than existing natural gas-, oil- or coal-fired steam plants. Natural gas turbines are the most economical way to meet growth for peak demand. In most of the AEO2015 cases, the growth in natural gas capacity continues. Natural gas-fired plants account for 58% of total capacity additions from 2013 to 2040 in the Reference case, and they represent more than 50% of additions in all cases, except for the High Oil Price case, where higher fuel prices for natural gas-fired plants reduce their competitiveness, and only 36% of new builds are gas-fired. With lower fuel prices in the High Oil and Gas Resource case, natural gas-fired capacity makes up three-quarters of total capacity additions.

Coal-fired capacity declines from 304 GW in 2013 to 260 GW in 2040 in the Reference case, as a result of retirements and very few new additions. A total of 40 GW of coal capacity is retired from 2013 to 2040 in the Reference case, representing both announced retirements and those projected on the basis of relative economics, including the costs of meeting environmental regulations and competition with natural gas-fired generation in the near term. As a result of the uncertainty surrounding future greenhouse gas legislation and regulations and given its high capital costs, very little unplanned coal-fired capacity is added across all the AEO2015 cases. About 19 GW of new coal-fired capacity is added in the High Oil Price case, but much of that is associated with CTL plants built in the refinery sector in response to higher oil prices.

Renewables account for more than half the capacity added through 2022, largely to take advantage of the current production tax credit and to help meet state renewable targets. Renewable capacity additions are significant in most of the cases, and in the Reference case they represent 38% of the capacity added from 2013 to 2040. The 109 GW of renewable capacity additions in the Reference case are primarily wind (49 GW) and solar (48 GW) technologies, including 31 GW of solar PV installations in the end-use sectors. The renewable share of total additions ranges from 22% in the High Oil and Gas Resource case to 51% in the High Oil Price case, reflecting the relative economics of natural gas-fired power plants, which are the primary choice for new generating capacity.

High construction costs for nuclear plants limit their competitiveness to meet new demand in the Reference case. In the near term, 5.5 GW of planned additions are put into place by 2020, offset by 3.2 GW of retirements over the same period. After 2025, 3.5 GW of additional nuclear capacity is built, based on relative economics. In the High Economic Growth and High Oil Price cases, an additional 10 GW to 13 GW of nuclear capacity above the Reference case is added by 2040 to meet demand growth, as a result of higher costs for the alternative technologies and/or higher capacity requirements.

Endnotes

  1. U.S. Environmental Protection Agency, “Clean Air Interstate Rule (CAIR)” (Washington, DC: February 5, 2015), http://www.epa.gov/airmarkets/programs/cair/.
  2. U.S. Environmental Protection Agency, “Cross-State Air Pollution Rule (CSAPR)” (Washington, DC: October 23, 2014), http://www.epa.gov/airtransport/CSAP.
  3. The AEO2015 Reference case assumes implementation of the Clean Air Interstate Rule (CAIR), which has been replaced by the Cross-State Air Pollution Rule (CSAPR) following a recent D.C. Circuit Court of Appeals decision to lift a stay on CSAPR. Although CAIR and CSAPR are broadly similar, future AEOs will incorporate CSAPR, absent further court action to stay its implementation.

Energy-related carbon dioxide emissions

Source: http://www.eia.gov/forecasts/aeo/section_carbon.cfm

Introduction

In the AEO2015 Reference case projection, U.S. energy-related CO2 emissions are 5,549 million metric tons (mt) in 2040. Among the alternative cases, emissions totals show the greatest sensitivity to levels of economic growth (Figure 36), with 2040 totals varying from 5,979 million mt in the High Economic Growth case to 5,160 million mt in the Low Economic Growth case. In all the AEO2015 cases, emissions remain below the 2005 level of 5,993 million mt. As noted above, the AEO2015 cases do not assume implementation of EPA’s proposed Clean Power Plan or other actions beyond current policies to limit or reduce CO2 emissions.

Figure 36 Energy-related carbon dioxide emissions in six cases, 2000-2040


figure data

Emissions per dollar of GDP fall from the 2013 level in all the AEO2015 cases. In the Reference case, most of the decline is attributable to a 2.0%/year decrease in energy intensity. In addition, the carbon intensity of the energy supply declines by 0.2%/ year over the projection period.

The main factors influencing CO2 emissions include substitution of natural gas for coal in electricity generation, increases in the use of renewable energy, improvements in vehicle fuel economy, and increases in the efficiencies of appliances and industrial processes. In the Reference case, CO2 emissions growth varies across the end-use sectors (Figure 37). The highest annual growth rate (0.5%) is projected for the industrial sector, reflecting a resurgence of industrial production fueled mainly by natural gas. CO2 emissions in the commercial sector grow by 0.3%/year in the Reference case, while emissions in both the residential and transportation sectors decline on average by 0.2%/year.

Figure 37 Energy-related carbon dioxide emissions by sector in the Reference case, 2005, 2013, 2025, and 2040


figure data

In the alternative cases, various factors play roles in the emissions picture. In the High Economic Growth case, GDP increases annually by 2.9% and overshadows the decrease in energy intensity of 2.2%, leading to the largest annual rate of increase in CO2 emissions (0.4%/year). In the Low Economic Growth case, GDP grows by only 1.8%/year, and that growth is offset by a similar annual average decline in energy intensity. With the additional decline in the carbon intensity of the energy supply, CO2 emissions decline by 0.2%/year in the Low Economic Growth case.

Emissions levels also vary across the other alternative cases. The High Oil and Gas Resource case has the second-highest rate of emissions in 2040 (after the High Economic Growth case) at 5,800 million mt. In the Low Oil Price case, CO2 emissions total 5,671 million mt in 2040. In the High Oil Price case, emissions levels remain lower than projected in the Reference case throughout most of the period from 2013 to 2040, but energy-related CO2 emissions exceed the Reference case level by 35 million mt in 2040, at 5,584 million mt.

Data Tables

Source: http://www.eia.gov/forecasts/aeo/tables_ref.cfm

 

Table Title Formats
Summary Reference Case tables NA
Year-by-year Reference Case tables Excel
Table 1. Total Energy Supply, Disposition, and Price Summary Excel
Table 2. Energy Consumption by Sector and Source Excel
Table 3. Energy Prices by Sector and Source Excel
Table 4. Residential Sector Key Indicators and Consumption Excel
Table 5. Commercial Sector Indicators and Consumption Excel
Table 6. Industrial Sector Key Indicators and Consumption Excel
Table 7. Transportation Sector Key Indicators and Delivered Energy Consumption Excel
Table 8. Electricity Supply, Disposition, Prices, and Emissions Excel
Table 9. Electricity Generating Capacity Excel
Table 10. Electricity Trade Excel
Table 11. Petroleum and Other Liquids Supply and Disposition Excel
Table 12. Petroleum and Other Liquids Prices Excel
Table 13. Natural Gas Supply, Disposition, and Prices Excel
Table 14. Oil and Gas Supply Excel
Table 15. Coal Supply, Disposition, and Price Excel
Table 16. Renewable Energy Generating Capacity and Generation Excel
Table 17. Renewable Energy Consumption by Sector and Source Excel
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source Excel
Table 19. Energy-Related Carbon Dioxide Emissions by End-Use Excel
Table 20. Macroeconomic Indicators Excel
Table 21. International Petroleum and Other Liquids Supply, Disposition, and Prices Excel

 

Supplemental tables for regional detail

Source: http://www.eia.gov/forecasts/aeo/tables_ref.cfm

Most of the tables below are not published in the AEO2015, but contain regional and other more detailed projections underlying the AEO2015 projections. The files containing these tables are in spreadsheet format.

NEXT

Page statistics
1071 view(s) and 49 edit(s)
Social share
Share this page?

Tags

This page has no custom tags.
This page has no classifications.

Comments

You must to post a comment.

Attachments