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Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
Us Chamber Of Commerce (May 20)Final
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Us Chamber Of Commerce (May 20)Final

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Operations in a carbon constrained environment

Operations in a carbon constrained environment

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  • 1. El Paso Corporation Fiji C. George Manager, EH&S Emissions Accounting and Cap-and-Trade Policy Considerations for Natural Gas Sector: El Paso Corporation’s Perspective May 20, 2008
  • 2. Cautionary Statement Regarding Forward-looking Statements This presentation includes forward-looking statements and projections, made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including, without limitation, changes in unaudited and/or unreviewed financial information; our ability to implement and achieve our objectives in the 2008 plan, including earnings and cash flow targets; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our E&P segment; uncertainties and potential consequences associated with the outcome of governmental investigations, including, without limitation, those related to the reserve revisions; outcome of litigation; our ability to comply with the covenants in our various financing documents; our ability to obtain necessary governmental approvals for proposed pipeline projects and our ability to successfully construct and operate such projects; the risks associated with recontracting of transportation commitments by our pipelines; regulatory uncertainties associated with pipeline rate cases; actions by the credit rating agencies; the successful close of our financing transactions; our ability to successfully exit the energy trading business; our ability to close our announced asset sales on a timely basis; changes in commodity prices and basis differentials for oil, natural gas, and power and relevant basis spreads; inability to realize anticipated synergies and cost savings associated with restructurings and divestitures on a timely basis; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located; the uncertainties associated with governmental regulation; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company’s (and its affiliates’) Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise. 2
  • 3. Agenda Overview Emissions Accounting & Reporting Cap and trade policy issues 3
  • 4. Overview of El Paso Corporation Wyoming Colorado Tennessee Interstate Interstate Gas Gas Pipeline Cheyenne Mojave Plains Pipeline Pipeline Southern Natural Gas El Paso Elba Island Natural Gas LNG Gulf LNG (50%) Florida Gas 2011 Transmission (50%) Premier Pipeline Franchise Top 10 independent E&P $1.3 billion of 2007 EBIT 3.1 Tcfe YE 2007 proved reserves 42,000 miles of interstate pipeline Top 10 independent domestic with unmatched connectivity gas producer 17 Bcf/d throughput (28% of gas delivered to U.S. consumers) Nearly $4 billion of organic projects with firm customer commitment 4
  • 5. El Paso Corporate: Greenhouse Gas Commitment “Assess, engage and act” Commitment statement http://elpaso.com/profile/mainneighbor.shtm Carbon Disclosure Project (CDP) 5 response http://www.cdproject.net/online_response_pf.asp?cid=558&year=2 California Climate Action Registry (CCAR) First company in CCAR history to certify without significant errors First company to achieve Climate Action Leader™ for 2007 First natural gas company to join CCAR Reported third party verified entity wide emissions to DoE’s 1605(b) program in 2007 Serves on Advisory Committee—The Climate Registry (TCR) El Paso Natural Gas and Colorado Interstate Gas are TCR “Founding Reporters” 2008 Southern Gas Association (SGA) Environmental Excellence Award for leadership on GHG matters 5
  • 6. U.S. Natural Gas Industry ~ 21.65 tcf PoR under S. 2191 Production = End-users ~ Gathering and Transportation 19.94 tcf Processing = and Storage ~18.5 tcf (dry) delivered Imports- ~14.7 tcf Industrials and Power Plants ~4.1 tcf Processing Plant Compressor Station Local Distribution Companies Underground • Over 450,000 Gas Wells LNG/ Propane Storage Fields Exports- LNG Terminals Air Plant • ~14,000 operators ~0.72 tcf • Gathering Pipelines •173 “large” • Processing Plants operators account for ~78% of gas •~530 plants • Pipelines • Over 1200 LDCs production • Of ~14.7 tcf, ~2.75 • 60 interstate •65% of gas delivered • 467 “intermediate” tcf is re-injected pipelines and 72 operators - ~15.6% • Utilities/ Power Plants intrastate • ~12 tcf or ~64% of • Industrials • ~ 13,000 - dry production is • Storage remaining • 0.6 tcf feedstock processed • Interstate Systems • Not Regulated • Regulated by States Regulated by FERC • ~638MMbbl • Intrastate Systems • Regulated in Some States Regulated by States 6
  • 7. 2005 Emissions Profile For the Natural Gas Sector U.S. GHG Emissions by (Million tonnes of CO2e) Total Other Fuel/Source—2005 CO2 CO2e Gases CH4 83.0 – 35.2 47.8 Production Oil 1% (Power) 53.0 – 11.9 41.1 Processing 68.8 – 36.8 32.0 Transmission and Storage 27.4 – 27.4 – Distribution 232.2 – 111.1 120.9 Gas Industry Total CO2 from Coal Transportation 7260.4 631.6 539.3 6,089.5 U.S. Total 28% (Power) 26% 3.2% 0.0% 2.0% 20.6% Gas Industry Share of U.S. CO2 from Gas (Power) Industrial 4% Combustion 12% Relative to total U.S. CO2eq emissions HFC, PFC, SF6 2% Natural Gas combustion ~ 17% N20 (Soil Mgmt, CO2 from Combustion) Commercial Natural Gas Industry Share ~ 3% 7% Combustion 3% Methane (Landfill, Methane emissions ~ 1.5% CO2 from Mining, Ag, Gas) Residential CO2 from 8% Combustion Process and Non-Energy Use 5% 4% Methane Emissions from the gas sector are a small fraction of the total U.S. emissions 7
  • 8. Emissions Accounting & Reporting 8
  • 9. El Paso’s Experience in GHG Emissions Accounting Development of GHG Team (2005) 2004 GHG Inventory – U.S. Operations (2005) Gap Analysis (2005) Corporate GHG Inventory Goals (2006) “Pre-certified” 2005 GHG Inventory – CCAR Standards (2006) Corporate Inventory Management Plan/Technical Manual (2007) Certified 2006 GHG Inventory, CA Operations – Reported to CCAR (2007) Climate Action Leader™ – CA (2007) GHG IMS (2007) Verified 2006 GHG Inventory, U.S. Operations – Reported to 1605(b) (Dec. 2007) Working on Certifiable 2007 GHG Inventory, U.S. Operations – for reporting to CCAR (2008) A three year effort…. Established a process focused on continuous improvement 9
  • 10. 2006 El Paso’s GHG Emissions Total Emissions by Gas* Total Emissions by Emission Category* Emissions Emissions Emission Category Contribution GHG Contribution MMT CO2e MMT CO2e CH4 8.70 55.9% Stationary Combustion 6.58 42.3% CO2 6.72 43.2% Process & Fugitive 8.21 52.8% Mobile Combustion 0.05 0.3% N2O 0.14 0.9% Indirects 0.71 4.6% HFCs 0.001 0.01% Total 15.56 100% Total 15.56 100% Indirects Mobile N2O 0.71 HFCs Combustion 4.6% 0.14 0.05 0.001 1% 0.3% 0% Stationary Combustion CO2 6.58 CH4 6.72 42.3% 8.70 43% Process & 56% Fugitive 8.21 52.8% *As reported to 1605(b), does not include ANR 10
  • 11. GHG Emission Categories and Sources: Natural Gas Transmission Vast number of discrete but “small sources” Direct Emissions Stationary Combustion Fugitive Reciprocating IC engines Transmission and Gathering Pipelines Transmission/Storage Station Piping Turbines Components Process heaters Reciprocal and Centrifugal Compressors Process boilers M&R Stations LNG vaporizers Storage Wells Flares/Thermal Oxidizers Vehicle Fleet A/C Systems Mobile combustion Process Plant piping & components Vehicle fleet Aviation fleet Indirect Emissions Process/Vented Generation of electricity used by: NG blowdowns Stations/office buildings Dehydrators Electric driven compressors Amine units Electric driven pumps (pump-jacks) Pneumatic devices Gas-assisted pumps Work-over & Completion Venting Storage Tanks 11
  • 12. Unique Natural Gas Sector Inventory Challenges Relative to electric sector, GHG inventorying is a “new” technical challenge 100% of the emissions non directly measured (non CEMS) Several thousand emission sources for a single company Over 50% of the emissions profile is methane High uncertainty of fugitive methane factors Outdated and unrepresentative Not “cap-and-trade” quality Facility level versus emission unit level combustion (CO2) emissions Lack of fuel metering at every unit Computation of Indirect Emissions can be time consuming Frequent acquisition/divestiture activity Complex ownership Remotely located Data collection issue 12
  • 13. El Paso’s GHG Reporting Recommendations Consistent “national” program Single registry Consider the fact that majority of the affected sources (outside power) have limited experience Use experience from existing programs CCAR, TCR, CARB: AB32, and 1605(b) Seek input from industry “leaders” who have undertaken inventory development Limit to Scope I emissions Phased approach Reporting no more than once a year Consider a “de-minims” list similar to CAA’s Title V program Establishment of appropriate quality assurance programs 13
  • 14. Natural Gas Policy Considerations 14
  • 15. Natural Gas Sector Business Impacts: Impact of Allowance Price on Fuel Natural Gas Gasoline Coal $/Tonne CO2 ($/MMBtu) ($/gallon) ($/MMBtu) $10 $0.53 $0.10 $0.95 $20 $1.06 $0.21 $1.90 $30 $1.60 $0.31 $2.85 $40 $2.13 $0.41 $3.80 $50 $2.66 $0.51 $4.75 15
  • 16. Natural Gas Sector Business Impacts: Summary of Allowance Prices Bill Design Study $/tonne CO2 $/tonne CO2 2015 2030 S.2191 Upstream - EPW version CRA/EEI $48 $76 S.2191 Duke Univ. Downstream - Prior to $18 $38 EPW Upstream - EPW version EPA S.2191 (avg of $38 $78 ADAGE cases) S. 2191 (Low Cost) Upstream - EPW version NAM $42 $228 S.2191 (avg of all Upstream - EPW version $36 $94 EIA (2006$) cases) Upstream - EPW version CATF (2004$) S.2191 (avg of all $17 $45 cases) S.2191 (avg of all Upstream - EPW version $52 $93 MIT (2005$) cases) $36 $93 AVERAGE (S.2191) PROJECTIONS $38 $78 MEDIAN (S.2191) PROJECTIONS = Upstream EIA S. 1766 (Core $10 $25 case) S. 280 (CORE) Downstream EIA $15 $48
  • 17. Natural Gas Sector Business Impacts: Example of Compliance Liability IMPACTS TO NATURAL GAS SECTOR—2015 Processing/ Transmission Bill/Design Framework Production Importers & Storage Distribution 1 S.2191 (Median Allowance Price)— $Billion $50.39 1 S. 1766— $Billion $13.60 2 S. 280—$Billion $1.25 $0.80 $1.04 $0.41 1Based on 2006: Median Price Forecast ($37.83/tonne) and 2006 U.S. Processing: Natural Gas = 14.68 Tcf; natural gas liquids = 637 MMBbl; U.S. gas imports = 4.18 Tcf 2Based on 2005 emissions from USEPA Inventory and S.280 EIA analysis 17
  • 18. Natural Gas in a Carbon Constrained Environment: “Mega” Design Issues Point of regulation Upstream (fuel proxy method) OR Downstream (actual emissions) OR Hybrid Treatment of fugitive emissions In the cap or via offsets? Treatment residential and commercial sector In the cap or via codes/standards? Emissions reporting Protocols? Frequency? Existing regulatory framework FERC, PUC Transitional assistance Free Allocation vs. Auctions Supply/demand dynamics 18
  • 19. Natural Gas in a Carbon Constrained Environment: Cost Flow Through and Price Signals In an upstream program, would natural gas entities be able to pass through the full compliance costs downstream per the economic theory? Regulatory/Legal/Contractual issues may prohibit pass through Processors/Transmission Companies generally do not own title to the gas Long term contractual arrangements and regulated by FERC (transmission) Therefore, any new carbon costs must be re-negotiated and incase of transmission companies approved by the FERC Discounting practices in the natural gas transmission sector may prevent full transmittal of price signal Double counting Cost of service (~$0.10-0.50/MMbtu) <<< Projected Allowance Prices (>$1.60/MMBtu) 19
  • 20. Natural Gas in a Carbon Constrained Environment: Fairness Fairness – the coal “downstream” vs. gas “upstream” Upstream gas “covered entities” (processors/importers) have limited ability to influence reductions on the end-users Lack of ownership of gas and inability to attach carbon costs to gas prices Emissions profile for natural gas covered entities are < 5% of the entire natural gas related emissions in the US economy If 100% of the allowance costs are passed through, natural gas end users would see the “market price” of the allowances as an incremental cost to fuel prices – i.e. a Btu tax Insignificant emissions profile, limited reduction opportunities Since regulated at the stacks, coal end users retain the cap-and-trade” advantages” The potential flexibility to achieve reductions at the lowest marginal cost (< market price of the allowance) State/Regional “downstream” design vs. “upstream” Federal Program? Example, a gas power plant in RGGI would face higher “Btu tax” due to federal upstream design + face a downstream state/regional program focused on its emissions 20
  • 21. Natural Gas in a Carbon Constrained Environment: Coverage Total Natural Gas Consumed in the Economy = ~21.6 tcf • However, ~ 1.7 tcf is consumed prior to end users • ~ 0.6 tcf is used as “feedstock” • ~ 0.72 tcf is exported Processors ~ 18.5 dry production of which ~14.7 tcf of gas processing; Therefore, about ~3.8 tcf is not processed Within the processed amount (14.7 tcf), ~ 12 tcf is processed put into the natural gas value chain ~2.75 tcf of gas is processed but re-injected in Alaska Coverage ~ 55% of the total natural gas consumed in the economy Imported gas ~ 4.1 tcf ~ 0.5 tcf is imported and processed Coverage ~ 19% of gas consumed Coverage - Processors + Importers ~71% of gas consumed Pipelines ~ 14 tcf (interstates) ~ 4.3 tcf (intrastates) 84% of gas consumed In all cases, 111 MM tonnes of fugitive emissions can not covered since upstream method is a fuel proxy method A well designed “downstream” design can offer equal or higher coverage 21
  • 22. Natural Gas in a Carbon Constrained Environment: Potential Effects of an Upstream Design Partial or no pass through of price signals to the end users Intended mitigation measures by end users are not realized However, the upstream regulated entities are “saddled” with huge compliance costs (potentially greater than gross revenues) Incomplete coverage at processor/importer or transportation upstream design Since required reductions aspired by the program are not being achieved this may drive up allowance prices in the market Therefore, an upstream program is a potential “recipe” for higher compliance costs without environmental benefits 22
  • 23. Natural Gas in a Carbon Constrained Environment: Efficient Cap-and-trade Program Would “fugitive” emissions be part of the cap or available as offsets? Dispersed along thousands of miles of pipelines and thousands of components Substantial uncertainty related to entity-wide fugitive emissions methodology Methodologies exists to quantify “discrete” projects EIA (S.2191) considered fugitive emissions as part of the cap 23
  • 24. Natural Gas in a Carbon Constrained Environment A well thought out cap-and-trade program is needed for natural gas 24
  • 25. Summary and Conclusions National bill likely in < 5 years Natural Gas will be regulated…but how? Upstream regulatory design requires significant review of legal, regulatory and technical Issues with respect to natural gas sector Unintentional consequences to natural gas sector could be significant Will Natural Gas be the “bridge” fuel in a carbon constrained environment? 25
  • 26. El Paso Corporation Fiji C. George Manager, EH&S Emissions Accounting and Cap-and-Trade Policy Considerations for Natural Gas Sector: El Paso Corporation’s Perspective May 20, 2008

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