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Natural Gas Demand

Natural Gas Demand. Natural Gas in North America’s Economy. Regional Natural Gas Demand by Sector Year 2002. Canada. Other. Natural Gas. 6%. 31%. Nuclear. 7%. Hydro. Coal. 10%. 12%. Petroleum. 34%. U.S. Nuclear. 8%. Natural Gas. 24%. Hydro. 7%. Coal. 23%. Petroleum. 38%.

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Natural Gas Demand

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  1. Natural Gas Demand

  2. Natural Gas in North America’s Economy Regional Natural Gas Demand by Sector Year 2002 Canada Other Natural Gas 6% 31% Nuclear 7% Hydro Coal 10% 12% Petroleum 34% U.S. Nuclear 8% Natural Gas 24% Hydro 7% Coal 23% Petroleum 38% Mexico Nuclear/Other Natural Gas 10% 23% Coal 4% BCF/Year Petroleum 63% Total Energy Use by Country

  3. Demand Task Group Approach • Develop a sector-by-sector demand picture • Analyze existing and future electric power • Assess industrial process energy and raw materials • Evaluate the role of energy efficiency in all sectors • Integrate U.S. & Canadian demand; Mexico modeled as net export/import

  4. Demand Task Group Participants Demand Task Group: Working Group Team Composition Task GroupLeaders KeySpan David Manning Hal Chappelle DOE Mark Maddox Wade Murphy Economy &Demographics Shell Trading Les Deman BP Burlington Resources ConocoPhillips Dominion El Paso ExxonMobil KeySpan Southern Company Unocal Williams IndustrialConsumers* PGC Dena Wiggins Alcoa BP Chemical Dow Chemical CERA ExxonMobil Chemical KeySpan PCS Nitrogen PPG Praxair Procter & Gamble Temple-Inland Power Generation* AEP Keith Barnett Bonneville Power Burlington Resources CERA Dominion Edison Electric Institute Exelon ExxonMobil Power Florida Power & Light Seminole Electric Southern Company Southern Company Gas Residential/Commercial KeySpan Ron Lukas NiSource Sempra *Substantial additional participation from regional power workshops and industrial sector workshops

  5. Greater energy efficiency and conservation are vital near-term and long-term mechanisms for moderating price levels and reducing volatility Power generators and industrial consumers are more dependent on gas-fired equipment and less able to respond to higher gas prices by utilizing alternate sources of energy Gas consumption will grow, but such growth will be moderated as the most price-sensitive industries become less competitive, causing some industries and associated jobs to relocate outside North America Findings on Natural Gas Demand

  6. Recommendations Related to Natural Gas Demand Objective: Improve demand flexibility and efficiency Recommendation #1 Encourage Increased Efficiency and Conservation through Market-Oriented Initiatives and Consumer Education Recommendation #2 Increase Industrial and Power Generation Capability to Utilize Alternate Fuels

  7. Demand Development Roadmap Macroeconomics Industrial Demand Power Generation Demand Residential & Commercial Demand Demand Outlook

  8. Demand Outlook 35 2%/YEAR GROWTH 1%/YEAR GROWTH Canada 30 U.S. Power 25 U.S. Cogeneration 20 TCF U.S. Industrial 15 10 U.S. Residential/Commercial 5 Other 0 1990 1995 2000 2005 2010 2015 2020 2025

  9. Modeling Assumptions Macroeconomic Assumptions • US GDP Growth 2.8% 2002-2005; 3.0% thereafter • US Industrial Production 3.0% • Canadian GDP Growth 2.4% 2002-2005; 2.6% thereafter • Inflation Rate (GDP Deflator) 2.5% Other Assumptions • Weather Historic 30-year NOAA average • Oil Price WTI at $20/bbl flat (real) after 2004 • Refiner Acquisition Cost 90% of WTIof Crude (RACC) • Residual Fuel Oil Price 84% of RACC by 2004 • Distillate 140% of RACC • Coal Price $1.25/MMbtu and declining in real terms at 1.5%/year to $1/MMbtu by 2025

  10. Recent GDP History Source: FRB

  11. Industrial Production by Industry

  12. Energy Efficiency 35 Projected Demand without Efficiency Gains 30 5 TCF 25 20 TCF 15 U.S. Demand Projection 10 5 0 2003 2010 2020 2025 2015

  13. Industrial Demand

  14. West North Central Pacific 1 Mountain 1 East North Central Pacific 2 East South Central Mountain 2 West South Central U.S. Regional Industrial Energy Use (2002) New England Middle Atlantic Trillion Btu 1,500 1,000 South Atlantic 500 Gas Oil Coal Electric Source: EEA, Inc.

  15. Industrial Energy Demand (2002) U.S. Total Energy Consumption Natural Gas Consumption By Industrial End-Use Total Energy By Industrial Sector Natural Gas Consumption By Industrial Sector Source: EEA, Inc.

  16. Industrial Demand Approach • Industrial demand for natural gas particularly driven by a discrete group of industries • Chemicals, refining, food, paper, primary metals, stone/clay/glass • Model focused on these industries • Analysis focused on primary industrial uses of natural gas • Feedstock • Boiler Fuel • Process Heating • Other (space heating, cogeneration, on-site electricity generation) • Demand forecasted from • requirements for each end-use • intensity (gas use per unit of output), reflective of technology mix & fuel switching • Capacity idled in modeling for at least two years is assumed to be shut down permanently

  17. Insights on Most Gas-Intensive Industries • Chemicals • Feedstock, steam and process heat • Demand growth driven by cogeneration, hydrogen needs • Ammonia, methanol, ethane-based ethylene experiencing shutdowns • Petroleum Refining • Steam generation and process heat • Demand growth driven by hydrogen, cogeneration, heavier crude feedstocks • No new refineries expected, but industry expected to maintain full capacity • Paper • Steam generation and lime calcining • Demand growth driven by cogeneration and and process reconfigurations • Increased mill production driven by demand for paper and paperboard • Primary metals • Process heating • Lower demand and increased competition from imports • Consolidation and plant closures

  18. Industrial Demand Workshop Observations • Outreach efforts indicate relatively gloomy picture of expected industrial growth • reflective of current economic downturn • concerns for long-term viability of some industries • Gas price not the primary driver in many industries • keys: labor, raw materials, proximity to market, exchange rates, financing arrangements/loan guarantees • for consumer products (e.g., toilet paper, wallboard), higher gas prices mean higher consumer prices • Regulatory limitations exist to energy-intensive retrofits • Bulk paper industry seeks continuation of PURPA or similar enabler to CHP

  19. Fuel Substitution Capability • Public information presents optimistic view on fuel switching capability • Fuel switching inhibited by local siting restrictions and State/Federal air standards, multiple examples cited by range of industries 26%* Natural Gas and Oil-Based Industrial Consumption 5-10% 1995 Today *EIA/Dept. of Commerce MECS Survey

  20. Industrial Demand Workshop Observations • Energy-intensive commodity industries not growing • international competition from areas with “stranded gas” and/or emerging markets and/or other factors • temporary/permanent displacements of capacity planned/possible due to relative price differentials • gas-intensive ammonia and methanol capacity will decrease step-wise with time • primary metals (steel, aluminum) will not grow except in ‘planned economy’ such as Quebec • no new refineries or petrochemicals facilities seen • no new chlor-alkali facilities seen • Outreach efforts consistently reflected • concerns over recent natural gas prices • belief that continued higher prices are detrimental to industrial sector • less demand responsiveness than in past due to environmental (emissions) restrictions and gas-favored process investments • fundamentally different downstream market for products (less liquid, less transparent than electric power, for example) • effect of non-domestic factors on natural gas demand (world markets, emerging economies, proximity to stranded gas, etc)

  21. Modeling Framework for Non-Chemicals Gas Use Industrial Production Growth and Intensity Assumptions Process Heat &Other Gas Uses Boiler Gas Use Base Intensity Trends (Steamrequirement/unit of output)1 Base Intensity Trends (Gas use/unit of output) Base Gas Use in Processesand Other Categories Base Gas Use in Boilers Boiler Fuel Switchingand Efficiency Effects Gas Price Elasticity 2 Natural Gas Consumptionin Boilers Natural Gas Consumptionin Process Heat/Other Uses 1 steam unit efficiencies assumed to improve 0.3%/year 2 gas price elasticity factors from Industrial Sector Technology Use Model, EEA, Inc.

  22. Modeling Framework for Chemicals Feedstock/Raw Material Hydrogen (non-Refinery) Other Chemicals Product Demand Growth(ammonia, methanol, ethylene) Gross Domestic Product Production Index Production Costing Model(domestic cost of production) Base Intensity Trends (Gasuse/unit of production) Import Share(based onimported product prices) Non-refinery produced hydrogen growth rates Baseline Gas Use to Produce Other Chemicals Gas Price Elasticity Natural Gas Consumptionfor Feedstock/Raw Material Natural Gas Consumptionfor non-Refinery Hydrogen Natural Gas Consumptionto Produce Other Chemicals

  23. 1992-1998 2001-2025 Ind Prod Gas Use Ind Prod Gas Use Gas Intensive Industries 2.4% 2.9% 1.1% -0.6% Food 1.8% 3.8% 1.1% -0.4% Paper 0.4% 3.5% 0.0% -1.3% Refining 1.2% 6.7% 1.0% -1.2% Chemical1 0.6% 1.3% 0.8% -0.1% Stone, Clay and Glass 3.8% 2.8% 2.8% 0.8% Primary Metals 3.5% 1.8% -0.2%3 -2.7% Other Industries 5.2% 1.9% 2.6% 0.1% Total2 2.3% 2.7% 1.1% -0.4% Model Inputs and Outputs Table 1. Annual Growth Rates 1Industrial production growth rate for 1992 to 1998 is for the Organic Chemicals industry. Industrial production growth rate for 2001 to 2030 uses the model results’ average of the growth rates of gas feedstocks and non-gas-intensive chemical industry production. 2Industrial production growth rate for both periods are unweighted averages of the seven industries. 3Primary aluminum -1.0%; iron & steel 0.0%; other primary metals 0.5%.

  24. By End Use (U.S.) 3,500 History Outlook History Outlook 3,000 Boilers Chemicals 2,500 Process Heat 2,000 BCF/Year Other 1,500 Cogeneration/Other Refining 1,000 Paper Food 500 Feedstock Stone Clay & Glass Primary Metals - 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 Outlook for Industrial Demand for Natural Gas • Low-growth/no-growth for gas-intensive industries • Competitiveness of individual plants & industries threatened • Modeling focused on industrial production levels, import/export prices, boiler switching • Ammonia, methanol, and primary metals will likely experience demand destruction • Significant stress on North American olefins, particularly ethane-base ethylene • Forecasts made in context of overall GDP growth (3%/year, the 30-year average) By Industry (U.S.)

  25. Power Generation Demand

  26. GDP Effects Demand for Electricity Driven by GDP; Future Gas Demand Driven by Power • Electricity demand growth is strongly correlated to GDP growth • Electricity demand grew faster than GDP in 1950’s and 1960’s • Rate of growth declined to a ratio less than 1.0 in mid-1970’s • Declining energy intensive manufacturing industry • High oil / energy prices • Increased efficiency • Saturation of electric appliances • Ratio factor approximately 0.72 • Gas fueling more hours of power generation will couple gas demand to power and to its GDP relationship • Combined cycles influenced more by GDP driven demand • Combustion Turbines tied more to weather induced demand

  27. Gas Fired Capacity Has Significantly Increased Electric Power Generation Capacity, GW 1,400 Renewables Gas Oil/Distillate Coal Hydroelectric Nuclear 1,200 1,000 800 600 Dual-Fuel 400 200 - 1995 2000 2005 2010 2015 2020 2025

  28. Natural Gas-Fired Capacity Additions by Region Gas-Fired Electric Power Generation Capacity (GW) and

  29. Gas Demand Will Grow But Coal Still Plays Major Role Electricity Generated by Fuel Type, TWH/Year Renewables Gas Oil/Distillate Coal Hydroelectric Nuclear

  30. Modeling Assumptions for New Generation Capacity • Model called for new capacity when reserve margins hit threshold • No coal built on West Coast or in EPA non-attainment areas • Additional coal built beyond reserve margin test if economics support • New coal limited in Florida • Total new coal limited to 14 GW per year • Renewable generation capacity is able to economically compete • Differing alternate fuel capability between cases • Post-run processing to ensure emissions limits not exceeded

  31. New Generation Capacity Technology Assumptions

  32. Other Modeling Assumptions Related to Electric Power • Load growth remains coupled to GDP growth • Growth ratio changes from 0.72 to 0.62 in Reactive Path • Growth ratio changes from 0.72 to 0.55 in Balanced Future • Hydropower capacity unchanged; annual generation multi-year average • Nuclear plants have success in 1 relicensing effort • Capacity increases by 2% in Reactive Path • Capacity increases by 10% in Balanced Future • Capacity factors remain above 90% in future • Mercury regulations cause 20 GW of coal fired capacity shut-down in Reactive Path • Older oil/gas steam units continue retiring through 2010 • Transmission capacity between regions increases by 50% over study period • No attempt to model market rules, market designs, transmission congestion, or locational marginal prices

  33. Sensitivities Related to Electric Power • Directly coupled sensitivities • High and Low GDP growth • High and Low ratio of electric load growth to GDP Growth • Fuel Flexibility • Carbon reduction • Indirectly coupled sensitivities • Weather sensitivities • Higher oil price

  34. Sensitivities Related to Electric Power TCF

  35. Natural Gas and Power Markets Are Connected Electricity Generation by Fuel TWH 200 Other* Gas 100 Nuclear Oil/Gas Hydro Nuclear Other* Gas Oil Coal Hydro Coal *includes renewables U.S. Electricity Generation and Generation Capacity (Year 2002) NPCC/ MAAC ECAR/MAIN/MAPP 140 GW 220 GW WECC 500 TWH 920 TWH 160 GW 590 TWH ERCOT/SPP SERC/ FPCC 180 GW 210 GW 570 TWH 900 TWH Generation Capacity

  36. Generation Capacity Additions – Power Market Impacts

  37. Efficiency of Gas Use Has an Impact Annual Heat Rate Total Gas Fired Generation • More efficient gas fired units use less natural gas • ERCOT Region • Example: AEP and Centerpoint decommission less-efficient steam units, ~6,000 MW mothballed • 50% Capacity factor • Average Heat Rate of 12 MMBtu/MWh • Combined Cycle heat rate of 7 MMBtu/MWh • Annual gas savings ~130 Bcf • Other considerations keep older steam units in dispatch • Voltage support in congested area • Regional system reliability • Alternate fuel capability • Regulatory compacts at state level Source: EIA STEO Data

  38. Residential & Commercial Demand

  39. Residential & Commercial Demand Residential Commercial Customers (Millions) Demand (TCF) Source: EIA

  40. Residential & Commercial Demand Approach • Key Demand Drivers • demographics • weather (short-run) • price response (long-run) • Econometric and Capital Stock Models • Regionally-disaggregated econometric model • Demographic trends driven by GDP • regional population growth • residential housing stock • commercial floor space • penetration of gas-based technologies • GDP elasticity based on historic GDP growth • 1984-1998 in U.S. • 1988-1998 in Canada • Price elasticity compared historic gas price responses • Weather the major variable in short-run • Contrasting Scenarios Evaluated • Increased rate of efficiency gains assumed in Balanced Future

  41. Demand Projections U.S. Residential Gas Consumption, BCF 6500 Reactive Path 6000 5500 Balanced Future 5000 4500 2000 2005 2010 2015 2020 2025 U.S. Commercial Gas Consumption, BCF 5000 4500 Balanced Future 4000 Reactive Path 3500 3000 2000 2005 2010 2015 2020 2025

  42. Energy Efficiency in Residential/Commercial Use • Reactive Path • current efficiency trends • current price-responsiveness • Balanced Future • greater efficiency gains in residential appliances, commercial equipment, and building standards • efficient market signals

  43. Residential & Commercial Demand Projection Projected U.S. Residential & Commercial Natural Gas Demand (Reactive Path) 4,000 4,000 3,000 2025 2000 2005 2010 2015 2000 2025 2000 2005 2010 2015 2000 2025 2015 2000 2005 2010 2000 1,500 1,500 4,000 2025 2000 2005 2010 2015 2000 2025 2000 2005 2010 2015 2000 2,000 BCF/Year 2025 2000 2015 2000 2005 2010

  44. Demand Summary

  45. Selected Sensitivity Analyses High Resource Base P10 Fuel Flexibility High Supply Technology Low Economic Growth Increased Access High LNG Imports Less Access High Electricity Elasticity High Economic Growth WTI $28 Oil Price No Alaska Pipeline Low LNG Imports Static Supply Technology Low Resource P90 -4.00 -2.00 0.00 2.00 4.00 -4,000 -2,000 0 2,000 4,000 Change in Price Vs. Reactive Path Change in S/D Volumes (BCF/Year) Vs. Reactive Path Values shown are averages for the 2011 to 2025 period

  46. Selected Demand Sensitivity Analyses

  47. Regional Demand Outlook

  48. 35 2%/YEAR GROWTH 1%/YEAR GROWTH Canada 30 U.S. Power 25 U.S. Cogeneration 20 TCF U.S. Industrial 15 10 U.S. Residential/Commercial 5 Other 0 1990 1995 2000 2005 2010 2015 2020 2025 Sector Demand Outlook

  49. Demand Recommendations Recommendation: Encourage Increased Efficiency and Conservation through Market-Oriented Initiatives and Consumer Education • Educate consumers • Improve conservation programs • Review & upgrade efficiency standards • Provide market signals to consumers to facilitate efficient gas use • Improve efficiency of gas consumption by resolving the North American wholesale power market structure • Remove regulatory and rate-structure incentives to inefficient fuel use • Provide industrial cogeneration facilities with access to markets • Remove barriers to energy efficiency from New Source Review

  50. Demand Recommendations Recommendation: Increase Industrial and Power Generation Capability to Utilize Alternate Fuels • Provide certainty of air regulations to create a clear investment setting for industrial consumers & power generators, while maintaining our commitment to improvements in air quality • Provide certainty of Clean Air Act provisions • Propose reasonable, flexible mercury regulations • Reduce barriers to alternate fuels by New Source Review processes • Expedite hydroelectric and nuclear power plant relicensing • Take action at the state level to allow fuel flexibility • Ensure alternate fuel considerations in Integrated Resource Plan • Allow regulatory rate recovery of switching costs • Support fuel backup • Incorporate fuel-switching considerations in power market structures

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