Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — The Williams Companies — FY2003 Earnings Presentation
104 slides from Williams Companies, Inc. (the)'s earnings presentation, Feb 19, 2004
Slide 1: Williams Analyst Conference Call 2003 Results
Williams Analyst Conference Call 2003 Results February 19, 2004 1
Slide 2: Forward Looking Statements
Forward Looking Statements Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” with in the meaning of Private Securities Litigation R
Slide 3: Agenda
Agenda ! 2003 Review Steve Malcolm ! 2003 Financial Review Don Chappel ! Business Unit Review and Outlook – Exploration & Production Ralph Hill – Gas Pipeline Doug Whisenant – Midstream Alan Armstrong – Power Bill Hobbs ! 2004-2006 Consolidated Outlook Don Chappel ! Summary Steve Malcolm ! Q&A 3
Slide 4: 2003 Review
2003 Review Steve Malcolm President, Chairman & CEO 4
Slide 5: Strategy
Strategy Commercial Financial ! Natural gas assets in key ! Create and maintain adequate growth markets where liquidity from all available we enjoy the competitive sources to fully support advantages of scale, business strategy low-cost position and ! De-leverage through market leadership combinatio
Slide 6: A Work in Progress
A Work in Progress Execute Initiate & Stabilize Emerge Restructuring Measures of Success Avoid bankruptcy Complete asset sales Position company for integrated natural Address liquidity Rationalize cost gas growth crisis structure Optimize capital Restore customer Manage liquidity structure and suppl
Slide 7: Restructuring Success Measures
Restructuring Success Measures ! Asset sales program 90% complete – $3.0 billion net proceeds in 2003; $6.1 billion since 2002 ! Rationalize cost structure – 30% reduction in continuing ops SG&A costs; efforts continue ! Manage liquidity – $2.3 billion in available cash and equivalents at year-end !
Slide 8: Pending Asset Sales
Pending Asset Sales ! Announced but not closed $265 million – Alaska Refinery 1Q04 ! Identified for sale totaling $500-600 million – Midstream Assets 2Q/3Q/4Q04 – Western Canada Assets (Straddle Plants) 3Q04 8
Slide 9: Power Restructuring Outlook
Power Restructuring Outlook ! Actively pursuing full exit of power business – Sold or liquidated nearly $600 million of power-related assets and contracts since June 2002 – Agreed to terminate contract with Allegheny – Managing in the interim to • Reduce risk • Generate cash • Meet contractual commi
Slide 10: Path Ahead
Path Ahead ! Focus on strong business performance ! Disciplined investment in core businesses ! Continued restructuring – De-levering – Complete asset sale program – Cost reductions – Power ! Position for future growth that creates economic value 10
Slide 11: 2003 Financial Review
2003 Financial Review Don Chappel, CFO 11
Slide 12: 2003 Results
2003 Results Dollars in millions (except per share amounts) 4Q03 4Q02 2003 2002 Income (Loss) from Continuing Ops.* ($97) ($151) $3 ($612) Income (Loss) from Discont. Ops. 31 (68) 254 (143) Effect of Accounting Change - - (761) - Net Loss* ($66) ($219) ($504) ($755) Net Loss / Share* ($0.13) ($0.44)
Slide 13: 4th Quarter Recurring Income from Continuing Operations
4th Quarter Recurring Income from Continuing Operations Dollars in millions 4Q03 4Q02 Difference Income (Loss) from Cont. Ops. ($97) ($151) $54 Gains on Asset Sales (16) 2 (18) Impairments/Losses/Write-offs 131 253 (122) Debt Tender Expenses 67 - 67 Cal. Refund & Other Accrual Adj. 33 - 33 Other - N
Slide 14: Full Year Recurring Income from Continuing Operations
Full Year Recurring Income from Continuing Operations Dollars in millions 2003 2002 Difference Income (Loss) from Cont. Ops. $3 ($612) $615 Gains on Asset Sales (337) (220) (117) Impairments/Losses/Write-offs 279 728 (449) Expenses on Debt Tender 67 - 67 Income Related to Prior Periods * (105) - (10
Slide 15: 2003 Segment Profit
2003 Segment Profit Reported Recurring Dollars in millions 2003 2002 2003 2002 Gas Pipelines $555 $545 $581 $574 Exploration & Production 401 509 310 368 Midstream Gas & Liquids 286 183 319 309 $1,242 $1,237 $1,210 $1,251 Power** 134 (625) (25) (353) Other (50) 14 (10) (28) Segment Profit* $1,326 $6
Slide 16: 2003 EBITDA Reconciliation
2003 EBITDA Reconciliation Dollars in millions Net (Loss)* ($504) Cum. Effect of Change in Acct. Principle 761 Income from Disc. Operations (254) Net Interest Expense 1,243 DD&A 671 Provision for Income Taxes 29 EBITDA* $1,946 * Includes gains and impairments on asset sales and prior period adjustme
Slide 17: 2003 Segment Contributions
2003 Segment Contributions Dollars in millions Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) * $555 $401 $286 $134 ($50) $1,326 DD&A 247 174 199 31 20 671 Segment Profit before DDA $802 $575 $485 $165 ($30) $1,997 General Corporate Expense (87) Investing Income* * 78 Other Inc
Slide 18: 2003 Cash Information
2003 Cash Information Dollars in millions 4Q03 2003 Beginning Cash* $3,431 $1,736 Cash Flow from Operations 75 770 Capital Expenditures/Investments (353) (1,107) LC Collateral 60 (388) Retirements (Debt & Pref. Stock) (1,221) (3,425) Asset Sales 174 2,983 Debt Proceeds 230 2,006 Other-Net (79) (257)
Slide 19: Debt Balances 2003
Debt Balances 2003 Dollars in millions Avg. Cost Debt Balance @ 12/31/02 (1), (2) $13,991 Debt Associated with Discontinued Operations (897) Debt Balance Adjusted for Disc. Oper. @ 12/31/02 13,094 10.0% Scheduled & Tendered Debt Retirements (1,742) Progeny Debt Payments (460) Accreted Capitalized In
Slide 20: Enterprise Risk Management
Enterprise Risk Management Corp./ Estimated dollars in millions E&P Midstream Power Other Total Margins & Ad. Assur. $281 $ 44 $202 - $527 Prepayments - 12 139 - 151 Subtotal $281 $56 $341 $- $678 Letters of Credit 3 - 190 185 378 Total as of 12/31/03 $284 $56 $531 $185 $1,056 Total as of 12/31/02 $
Slide 21: Enterprise Risk Management
Enterprise Risk Management ■ Margin volatility (99% confidence interval) - liquidity requirement – 30 days ($183) million – 180 days ($324) million – 360 days ($349) million Assumption: - The margin numbers above consist of only the forward marginable position values, starting from February 2004. Do
Slide 22: Enterprise Risk Management
Enterprise Risk Management Estimated dollars in millions Sensitivities Analysis WMB 1 Power2 Midstream 3 Natural Gas West Spark Spread Processing Margin (Per MMBTU) Power Price (Per MWh) NGL Price (Per Gallon) Price Increase $0.10 $5.00 $0.01 2004 ($5) $0-5 $10-15 2005 $4 $5-10 $10-15 2006 $11 $5-15
Slide 23: Business Unit Review and Outlook
Business Unit Review and Outlook 23
Slide 24: Exploration & Production
Exploration & Production Ralph Hill, Senior VP 24
Slide 25: Segment Profit
Exploration & Production Segment Profit 4th Quarter Dollars in millions 2003 2002 2003 2002 Segment Profit $50 $82 $401 $509 Includes ■ (Gain)/Loss on Asset Sale - 3 (91) (141) Recurring Segment Profit $50 $85 $310 $368 ■ Recurring segment profit declined due to expiration of Section 29 tax credits
Slide 26: 4Q/YE 2003 Accomplishments
Exploration & Production 4Q/YE 2003 Accomplishments " 4Q Increased Drilling Activity – Piceance rig count increased to 8 rigs from 1 in 2Q – San Juan added 1 drilling rig and 4 cavitation rigs " Reversed volume decline during fourth quarter " Completed backyard acquisition of working interest partne
Slide 27: Proved Reserves Reconciliation
Exploration & Production Proved Reserves Reconciliation 2,900 -390 2,834 2,800 +445 2,703 2,700 2,600 2,500 Bcfe -186 2,400 2,300 2,200 2,100 2,000 2002 YE Sold Produced Additions 2003 YE 27
Slide 28: 2003 Year End U.S. Reserves
Exploration & Production 2003 Year End U.S. Reserves Proved Reserves Proved + Probable Reserves Mid-Cont. & Mid-Cont. Other & Other 4% 6% San Juan 16% San Juan 26% Piceance 58% Piceance 54% Powder River Powder 10% River 26% TOTAL: 2.7 Tcf Proved 28
Slide 29: 2004-2006 Guidance
Exploration & Production 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment profit $275-340 $350-450 $400-500 Annual DD&A $160-180 $195-225 $230-260 Capital spending $300-350 $400-450 $450-500 Production (MMcfed) 500-550 600-700 700-800 29
Slide 30: Arkoma Basin Overview
Exploration & Production Arkoma Basin Overview " Horizontal Hartshorne CBM drilling " Geographic extent of coal offers growth opportunities " In-fill, field extension drilling " Proprietary low-pressure gathering system constructed in 2002 " Key characteristics – 122 Bcfe total proved reserves – 17
Slide 31: San Juan Basin Overview
Exploration & Production San Juan Basin Overview " Conventional and coalbed methane production " Long life / slow decline wells " Low risk in-fill drilling via downspacing and EIS " Good pipeline infrastructure / market access " Key characteristics – 702 Bcfe total proved reserves – 136 Mmcf/d net p
Slide 32: Powder River Basin Overview
Exploration & Production Powder River Basin Overview " High potential, low-risk development play " Low cost wells " Typical well production – Wyodak - 140 Mcf/d peak – Big George - 400Mcf/d peak " Key characteristics – 257 Bcfe total proved reserves – 114 MMcf/d net production – Leasehold 1,021,400
Slide 33: Powder River Basin - Update
Exploration & Production Powder River Basin - Update " 660 Federal Well Permits issued to the industry post Record of Decision (ROD) – Williams received 140 (21%) and partner 61 for total of 201(30% ) " 74 of 140 wells spudded post-ROD " 1,400 industry permits in the approval process; 352 for Willia
Slide 34: Piceance Basin Overview
Exploration & Production Piceance Basin Overview " Large gas-saturated, basin-centered gas trap " High return/low risk economics " Key characteristics – 1.6 Tcfe total proved reserves – 172 MMcf/d net production – Leasehold 173,800 gross /129,900 net acres – 2,500 drilling locations, > 10 yr invento
Slide 35: Basin Comparison
Exploration & Production Basin Comparison Typical 2004 Well Economics Powder San Juan Arkoma River Coal Piceance Cost/well ($/M) $375 $145 $583 $1,030 Typical well reserves (Bcf) 0.8 0.5 1.5 1.3 Drilling costs ($/Mcfe) $0.55 $0.35 $0.44 $0.93 LOE ($/Mcfe) $0.58 $0.24 $0.39 $0.17 Incremental IRR 73%
Slide 36: Hedging
Exploration & Production Hedging " 2004 - 80% hedged at $4.03 NYMEX " 2005 - 47% hedged at $4.44 NYMEX " 2006 - 40% hedged at $4.39 NYMEX " Basis hedges in place to mitigate location risk " Future hedging strategy will continue to be a function of Williams’ portfolio 36
Slide 37: Challenges and Opportunities
Exploration & Production Challenges and Opportunities ■ Challenges – Pace of drilling permit approvals – Rig availability ■ Opportunities – BLM committed to streamlining – Williams has successfully obtained additional rigs – Opportunity to increase drilling pace beyond planned rate – Numerous backya
Slide 38: Platform for Growth
Exploration & Production Platform for Growth " Conservative business strategy " Investments are short time cycle, fast cash returns " High-quality, low-risk reserve base " History of high success, low finding costs " Diverse producing basins, long term drilling inventory " Significant probables and
Slide 39: Gas Pipeline
Gas Pipeline Doug Whisenant, Senior VP 39
Slide 40: Assets
Gas Pipeline Assets Northwest Transco Gulfstream (50% Ownership) 40
Slide 41: Segment Profit
Gas Pipeline Segment Profit 4th Quarter Dollars in millions 2003 2002 2003 2002 Segment Profit $148 $122 $555 $545* Includes ■ Write-off projects - 5 25 19 ■ Gulfstream Project completion fee - - - (27) ■ Early retirement/realignment - - 1 15 ■ Net gains/losses/impairments - 16 - 22 Recurring Segmen
Slide 42: 4Q 2003 Accomplishments
Gas Pipeline 4Q 2003 Accomplishments ! Northwest – Evergreen Expansion placed into service 10/1/03 – Columbia River Gorge Expansion placed into service 10/21/03 – Rocky Mountain Expansion Project placed into service 11/30/03 ! Transco – Trenton-Woodbury Expansion placed into service 11/1/03 – South
Slide 43: Strengths
Gas Pipeline Strengths ! Location ! Low cost provider ! Few expiring long-term contracts ! Customer credit quality ! Gas supplies ! System flexibility 43
Slide 44: Restore/Replace 26"
Gas Pipeline Restore/Replace 26” SUMAS WHATCOM Bellingham ! Corrective Action Order SKAGIT Existing 30” Mainline MT VERNON – Idle 26” mainline Sumas, WA Proposed 26” Replacement Facilities to Washougal, WA SNOHOMISH – Allows temporary removal of restrictions after testing Everett – Required to repla
Slide 45: FERC Issues
Gas Pipeline FERC Issues ! Future Rate Cases – No filing requirement until 2007 – Transco filing possible pre-2007 – 26” Restore/Replace triggers Northwest filing ! Energy Affiliate Rule 45
Slide 46: 2004-2006 Guidance
Gas Pipeline 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment profit $525-575 $525-575 $525-575 Annual DD&A * $275-285 $280-290 $290-300 Capital spending Expansion: $30-40 $15-30 $25-40 Non-Exp: $240-250 $265-280 $165-180 Replacement: $25-50 $100-120 $240-260 Total $295-340 $380-430 $43
Slide 47: Challenges and Opportunities
Gas Pipeline Challenges and Opportunities ! Challenge – Restore/replace Northwest’s 26” pipeline ! Opportunities – Transco rate upside – Gulfstream capacity – Organic growth over long-term 47
Slide 48: Midstream
Midstream Alan Armstrong, Senior VP 48
Slide 49: Midstream asset footprint
Wyoming • Produce over 50% of Fort McMurray NGL’s coming out of (Oil Sands) Wyoming Olefins San Juan Fractionator • Gather approximately Straddle Plants 38% of the gas, ranking Midstream #1 in the basin Gulf Coast • Gather 40% of the gas produced in the Conway Western Gulf of Mexico Venezuela •Gas i
Slide 50: Segment Profit
Midstream Segment Profit 4th Quarter Dollars in millions 2003 2002 2003 2002 Segment Profit $46 $(27) $286 $183 Includes: ■ Impairments 42 115 60 123 ■ Gains on sale of assets (16) - (27) - ■ Early retirement/realignment - - - 3 Recurring Segment Profit $72 $88 $319 $309 ! Operation of Assets sold/T
Slide 51: 4Q 2003 Accomplishments
Midstream 4Q 2003 Accomplishments ! Strong operating cash flow ! Deepwater expansions – Gunnison pipeline in-service – Devils Tower spar topsides set ! Asset sales progress – NGL Trading & Wholesale Propane - closed 12/03 – Wilprise equity ownership - closed 10/03 – Tristates equity ownership - clos
Slide 52: Remaining Assets for Sale
Midstream Remaining Assets for Sale Dollars in millions Timing of Closing ! Cameron Meadows/Black Marlin 2Q04 ! Gulf Liquids (Disc. Operations) 2Q04 ! Ethylene Distribution 2Q04 ! Canadian Straddle Plants 3Q04 ! Conway 3Q04 ! South Texas 4Q04 Pre-tax Proceeds $500 – 600 52
Slide 53: 2004 – 2006 Guidance
Midstream 2004 – 2006 Guidance Dollars in millions 2003FC 2003 2004 2005 2006 2-20-03 Segment profit $200-300 $286 $275-375 $300-400 $350-450 Annual DD&A* $190-200 $199 $180-190 $170-180 $175-185 Capital spending $250 $263 $90-110 $60-80 $50-70 CFFO $300-350 $413 Key Assumptions for Ranges: ! NGL Ma
Slide 54: Segment Profit Breakdown-Guidance
Midstream Segment Profit Breakdown-Guidance Dollars in millions 2002 2003 2004 2005 2006 G&P 263 315 280-330 320-370 350-420 Segment Profit 263 333 280-330 320-370 350-420 Gains/Losses/Impairments - (18) - - - Petchem Services (87) (28) (20)-30 (20)-30 (20)-30 Segment Profit (10) (28) (20)-30 (20)-3
Slide 55: Net Revenue Components
Midstream Net Revenue* Components Commodity Commodity Based Based** 21% 17% Other Revenue 3% Other Revenue Storage & 6% Trans. Fee 5% Storage & Fee Proc. Trans. Fee Gathering, 9% Gathering, 6% Compression Compression & Treating & Treating Fee Proc. Fees Fees 14% 53% 66% End of Year 2003 2006 * Net R
Slide 56: Projected Deepwater Growth
Midstream Projected Deepwater Growth ! East Breaks – Placed in service 4th Qtr. 2001 Segment Profit Before DD&A • Original Projection for 2003 = 172MMcfd • 2003 Actual = 343 MMcfd $ Millions ! Canyon Station $250 – Production exceeding estimates by 30+ MMcfd $200 ! Green Canyon $150 – Inception to d
Slide 57: Challenges / Opportunities
Midstream Challenges / Opportunities Challenges ! Commodity margins ! Deepwater - contract identified business in 2006 ! FERC affiliate ruling Opportunities ! Commodity margins ! Additional Deepwater prospects ! Olefins Margins 57
Slide 58: Summary
Midstream Summary ! 2003 strong financial performance ! Strategy intact ! Maintaining focus on core business in spite of asset sales – Success in past, present and future ! Reducing volatility ! Exciting growth opportunities continue to exist – Deepwater – Core basins 58
Slide 59: Power
Power Bill Hobbs, Senior VP 59
Slide 60: 4Q 2003 Segment Profit
Power 4Q 2003 Segment Profit 4th Quarter Dollars in millions Dollars in Millions 4Q03 2003 4Q02 2002 2003 2003 2002 2002 Accrual Earnings (Losses) ($67) $1 ($268) $11 MTM Earnings (Losses)1 73 126 393 (420) Interest Rate Earnings (Losses) 14 (6) (12) 91 SG&A (17) (29) (124) (209) Operating Expenses
Slide 61: Power
Power 4th Quarter Dollars in millions 2003 2002 2003 2002 Segment Profit/(Loss) ($121) ($23) $134 ($625) Includes ■ Impairments 89 98 89 259 ■ Reduction in Force Costs - 6 12 13 ■ Income Related to Prior Periods1 - - (105) - ■ Contract Sales/Liquidations 2 - - (208) - ■ Cal. Refund & Other Accrual A
Slide 62: Undiscounted Cash Flows-Guidance
Power Undiscounted Cash Flows-Guidance Combined Power Portfolio Estimated as of 12/31/03 Dollars in millions Dollars in Millions 4Q03 2003 4Q02 2004 2003 2005 2002 2006 Tolling Demand Payment Obligations ($393) ($391) ($395) ($400) Resale of Tolling 123 143 117 104 Full Requirements 19 16 41 46 Long
Slide 63: 2003 Cash Flow
Power 2003 Cash Flow Power Other Bus. Dollars in millions Only W/C Total Portfolio Cash Flow ($243) - ($243) Unusual Items Jackson Sale 188 - 188 Allegheny Termination 100 - 100 Deferred Tax Change 220 - 220 Working Capital and Other 231 (337) (106) Cash Flows from Operations $496 ($337) $159 63
Slide 64: 2004-2006 Guidance
Power 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $0-150 $50-150 $50-200 Cash Flows from Operations1 $150-350 $50-150 $50-200 1 Power only, excludes all commodity Margin Volatility Note: Because Power does not currently qualify for Hedge Accounting, actual segment profit may
Slide 65: Challenges / Opportunities
Power Challenges / Opportunities Challenges ! Depressed cycle ! Stated intent to exit the business Opportunities ! Higher spark spreads ! New risk reducing, value enhancing origination deals ! Increased liquidity resulting in additional forward hedging ! Improved credit resulting in reduced prepays
Slide 66: Outlook
Power Outlook ■ Power markets depressed – West has positive exit value – Negative exit value for remainder ! Estimated cash flows from hedges cover approximately 98% of demand payment obligations through 2010 ! Expect positive cash flows despite depressed markets through 2010 ! Opportunities and ris
Slide 67: 2004-2006 Consolidated Outlook
2004-2006 Consolidated Outlook Don Chappel 67
Slide 68: 2004 Segment Profit Guidance
Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast Gas Pipeline $525 - 575 Exploration & Production 275 - 340 Midstream 275 - 375 Other/Rounding 25 - (40) $1,100 - 1,250 Power 0 - 150 Total $1,100 - 1,400 68
Slide 69: 2004 Guidance
Consolidated 2004 Guidance Dollars in millions, except per-share amounts $ Segment profit* $1,100 - $1,400 EBITDA 1,600 - 2,000 Cash Flow from Operations 1,000 - 1,300 Income from continuing operations 20 - 200 Net Income 0 - 200 Diluted Earnings Per Share $0.00 - $0.40 Note: Excludes potential gain
Slide 70: 2004 Forecast EBITDA Reconciliation
2004 Forecast EBITDA Reconciliation Dollars in millions Net Income $0 - 200 Income from Disc. Operations 0 - 20 Net Interest 810 - 900 DD&A 650 - 700 Provision for Income Taxes 80 - 175 Other/Rounding 60 - 5 EBITDA $1,600 – 2,000 70
Slide 71: 2004 Forecast Segment Contribution
Consolidated 2004 Forecast Segment Contribution Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) 525 - 575 275 - 340 275 - 375 0 - 150 25 – (40) 1,100 - 1,400 DD&A* 275 - 285 160 - 180 180 - 190 20 - 25 15 - 20 650 - 700 Segment Profit before DDA 800 - 860 435 - 520 455 - 565 20
Slide 72: 2004 - 2006 Outlook
Consolidated 2004 - 2006 Outlook Dollars in millions 2004 2005 2006 Segment Profit 1,100 - 1,400 1,300 - 1,600 1,400 - 1,700 DD&A 650 - 700 650 - 750 700 - 800 Cash flow from Operations 1,000 - 1,300 1,300 - 1,600 1,400 - 1,700 Capital Expenditures 700 - 800 900 - 1,100 900 - 1,100 Effective Tax Rat
Slide 73: Drivers
Consolidated Drivers Dollars in millions Segment Profit CFFO Low High Low High 2003 1,350 1,650 600 800 Interest savings - - 340 400 Gains on Asset Sales (236) (236) - - Other (14) (14) 60 100 2004 1,100 1,400 1,000 1,300 Interest savings - - 50 200 E&P improvements 75 110 150 200 Other 125 90 100 (
Slide 74: Financial Strategy
Financial Strategy ! Maintain a cash/liquidity cushion of $1.0 billion plus ! Complete new bank credit facilities ! Continue to de-lever - striving for investment grade ratios ! Uses of excess cash – Pay scheduled debt retirements – Early debt reduction – Disciplined EVA® -based investment – Conside
Slide 75: Summary
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Slide 76: Strategy
Strategy Commercial Financial ! Natural gas assets in key ! Create and maintain adequate growth markets where we liquidity from all available enjoy the competitive sources to fully support advantages of scale, low- business strategy cost position and market ! De-leverage through leadership combinati
Slide 77: Business Unit Positioning
Business Unit Positioning ! Exploration & Production – Generates free cash flow, primary growth driver ! Midstream – Generates free cash flow, decreasing volatility, growth in Deepwater ! Gas Pipeline – Generates free cash flow, steady contributor ! Power – Exit business – Reduce risk and volatility
Slide 78: A Work in Progress
A Work in Progress Execute Initiate & Stabilize Emerge Restructuring Measures of Success Avoid bankruptcy Complete asset sales Position company for integrated natural Address liquidity Rationalize cost gas growth crisis structure Optimize capital Restore customer Manage liquidity structure and suppl
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Slide 80: Appendix
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Slide 81: Appendix Contents
Appendix Contents ! Exploration & Production Page – Arkoma Basin Average Well Economics A-4 – San Juan Basin Average Well Economics A-5 – Powder River Basin Average Well Economics A-6 – Piceance Basin Average Well Economics A-7 ! Gas Pipeline – Northwest 2003 Expansion Projects A-8 – Transco 2003/04
Slide 82: Appendix Contents (cont.)
Appendix Contents (cont.) ! Midstream Page – Operational Metrics-Daily Gathering Volume A-18 – Operational Metrics-NGL Production/Spread vs. Margin A-19 ! Power – Physical Natural Gas A-20 – Total Undiscounted Cash Flows A-21 – West Undiscounted Cash Flows A-22 – Mid. Cont. Undiscounted Cash Flows A
Slide 83: Arkoma Basin Average Well Economics
Exploration & Production Arkoma Basin Average 2004 Lona Valley Well Finding Costs Illustrative Economics Drill & Complete $375,000 NYMEX Gas Price (MMbtu) $4.92 Total Development Cost $375,000 Basis adjustment -0.20 Reserves, Mcf 678,473 Midcon. Gas Price (per MMbtu) $4.72 Drilling cost $0.55 BTU Ad
Slide 84: San Juan Basin Average Well Economics
Exploration & Production San Juan Basin Average 2004 Fruitland Coal Well Finding Costs Illustrative Economics Drill & Complete $583,000 NYMEX Gas Price (MMbtu) $4.92 Total Development Cost $583,000 Basis Adjustment -0.42 Reserves, Mcf 1,327,512 San Juan Gas Price (per MMbtu) $4.50 Drilling Cost $0.4
Slide 85: Powder River Basin Average Well Economics
Exploration & Production Powder River Basin Average 2004 Big George Coal Well Finding Costs Illustrative Economics D&C $120,000 NYMEX Gas Price (MMbtu) $4.92 Hook-up $25,000 Basis Adjustment (to Glenrock) -0.57 Total Well Cost $145,000 Rocky Mountain Gas Price (per MMbtu) $4.35 Net Reserves, Mcf 415
Slide 86: Piceance Basin Average Well Economics
Exploration & Production Piceance Basin Average 2004 Mesaverde Well Finding Costs Illustrative Economics D&C $1,030,000 NYMEX Gas Price (MMbtu) $4.92 Total Well Cost, $ $1,030,000 Basis Adjustment -0.55 Net Reserves, Mcf 1,102,329 Basin Gas Price (per MMbtu) $4.37 Drilling Cost $0.93 BTU Adjustment
Slide 87: Northwest 2003 Expansion Projects
Gas Pipeline Northwest 2003 Expansion Projects Evergreen 276 MDth/d Oct 2003 $198 MM Columbia Gorge 57 MDth/d Nov 2003 $43 MM Rockies 175 MDth/d Nov 2003 $124 MM A-8 87
Slide 88: Transco 2003/2004 Expansion Projects
Gas Pipeline Transco 2003/2004 Expansion Projects Momentum Trenton 323 MDth/d Woodbury 2003/2004 51 MDth/d $175 MM Nov 2003 $20 MM A-9 88
Slide 89: Gulfstream 2004 Extension Project
Gas Pipeline Gulfstream 2004 Extension Project FPL’s Manatee Plant FPL’s Martin Plant Gulfstream Phase II 109 Miles Dec 2004 $238.7MM Total Capacity 1.1 Bcf/d A-10 89
Slide 90: Northwest Rate Comparison
Gas Pipeline Northwest Rate Comparison 100% LF Rate Comparison Reno, NV Spokane, WA Medford, OR $1.20 $0.093 $0.010 $1.00 $0.186 $0.80 $0.188 $0.60 $0.483 $0.073 $1.110 $0.309 $0.073 $0.40 $0.037 $0.037 $0.037 $0.008 $0.20 $0.017 $0.270 $0.254 $0.270 $0.270 $0.001 $0.00 $0.069 te ra t N t N i au ro
Slide 91: Transco Rate Comparison
Gas Pipeline Transco Rate Comparison 100% LF Rate Comparison $1.25 $1.173 Zone 4 Zone 5 Zone 6 $1.00 $0.932 $0.75 $0.722 $0.722 $0.666 $.541 $0.558 $0.541 $0.50 $0.486 $0.376 $0.25 $0.00 o o o T T nn O G G is sc sc sc G G SN SN TC o Te C C qu an an an TE Iro Tr Tr Tr System gas prices are as follows
Slide 92: Contract Expirations – Cumulative
Gas Pipeline Contract Expirations – Cumulative ! Northwest’s average contract life is 8.7 years 80% 66% 60% 43% 47% 51% 40% 24% 20% 1% 1% 5% 0% 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Northwest Contract Expiration % ! Transco’s average contract life is 5.8 years 80% 62% 65% 74% 43% 45% 52%
Slide 93: Northwest Customer Base
Gas Pipeline Northwest Customer Base 2003 Revenue Company Credit Rating ($MM) Customer Type Puget Sound Energy, Inc. BBB-/Baa3 $ 49 Local Distribution Co. Northwest Natural Gas Co. A-/A3 38 Local Distribution Co. Duke Energy BBB- 34 Marketer Pan-Alberta Gas (U.S.) Guaranty 26 Producer /Aggregator In
Slide 94: Transco Customer Base
Gas Pipeline Transco Customer Base 2003 Revenue Company Credit Rating ($MM) Customer Type PSEG Energy Resources Baa1/BBB $115 Local Distribution Co. KeyspanGas East A3 86 Local Distribution Co. Piedmont Natural Gas Co. A3/A 74 Local Distribution Co. ConEdof NY A1/A 51 Local Distribution Co. SCANA A3
Slide 95: Gulfstream Customer Base
Gas Pipeline Gulfstream Customer Base ! Contract terms are for 18 – 23 years FT Demand Primary Contract Revenue Company Company Mdth/d ($MM) Rating Type PHASE I (May 2002) Seminole 32 $6.4 A IOU Lakeland 30 $6.0 AAA/A1 IOU FPC 190 $38.0 BBB/A2 IOU Central FL Gas 10 $2.0 BBB+ LDC Peoples Gas 35 $7.0
Slide 96: Northwest Supply Diversity
Gas Pipeline Northwest Supply Diversity 100% 2% 3% 3% 5% 7% 9% 7% 9% 8% $6.00 23% 22% $5.00 80% 40% 36% 27% 32% 39% 41% 48% $4.00 60% 47% 47% $3.00 40% 38% 41% 48% 43% 39% 41% $2.00 36% 20% $1.00 20% 20% 27% 26% 18% 16% 15% 9% 8% 0% $0.00 1995 1996 1997 1998 1999 2000 2001 2002 2003 Alberta/Kingsgat
Slide 97: 2003 Strong Operational Metrics: Daily Gas Gathering Volumes
Midstream 2003 Strong Operational Metrics Daily Gas Gathering Volumes 6,500 6,000 5,500 5,000 Bbtud 4,500 4,000 3,500 3,000 2 2 2 2 3 3 3 3 '0 '0 '0 '0 '0 '0 '0 '0 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q A-18 97
Slide 98: 2003 Strong Operational Metrics: NGL Production
Midstream 2003 Strong Operational Metrics Total NGL Production Frac Spread vs. Net Liquid Margin 350 20 300 15 250 cents / gal 200 Mbpd 10 150 100 5 50 0 0 2 2 2 2 3 3 3 3 2 2 2 2 3 3 3 3 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 '0 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q U.S. Canada HH/M
Slide 99: Physical Natural Gas
Power Physical Natural Gas ! Average annual requirements – 2.7 Bcf/d with peak of 3.5 Bcf/d • 48% for Power – 20% power-plant supply – 28% third-party transactions • 52% for Williams’ core businesses ! Transportation – 2.5 Bcf/d • 35% for Power • 65% for Williams’ core businesses ! Storage – 21 Bcf
Slide 100: Total Undiscounted Cash Flows
Power Total Undiscounted Cash Flows ($ Millions) Combined Power Portfolio Estimated as of 12/31/03 2003 2004 2005 2006 2007-2010 2011-2022 Tolling Demand Payment Originations (393) (391) (395) (400) (1,630) (3,839) Resale of Tolling 123 143 117 104 279 0 Full Requirements 19 16 41 46 153 153 Long-te
Slide 101: West Undiscounted Cash Flows
Power West Undiscounted Cash Flows ($ Millions) West Power Portfolio Estimated as of 12/31/03 2003 2004 2005 2006 2007-2010 2011-2022 Tolling Demand Payment Originations (151) (153) (154) (156) (639) (1,240) Resale of Tolling 123 143 117 104 279 0 Long-term Physical Forward Power Sales 73 104 98 76
Slide 102: Mid. Cont. Undiscounted Cash Flows
Power Mid. Cont. Undiscounted Cash Flows ($ Millions) Mid-Continent Power Portfolio Estimated as of 12/31/03 2003 2004 2005 2006 2007-2010 2011-2022 Tolling Demand Payment Originations (87) (88) (89) (89) (365) (844) Long-term Physical Forward Power Sales 1 (7) 2 0 0 0 OTC Hedges 28 34 (6) (8) (8) 0
Slide 103: East Undiscounted Cash Flows
Power East Undiscounted Cash Flows ($ Millions) East Power Portfolio Estimated as of 12/31/03 2003 2004 2005 2006 2007-2010 2011-2022 Tolling Demand Payment Originations (155) (150) (152) (154) (626) (1,755) Full Requirements 19 16 41 46 153 153 OTC Hedges 57 54 32 38 7 (2) Estimated Hedged Tolling
Slide 104: Scheduled Debt Maturities
- 500 1,000 1,500 2,000 2004 285 679 2005 247 Consolidated 2006 972 2007 920 1100 2008 385 2009 138 2010 1014 Misc. Notes 1078 ($ Millions) 2011 Scheduled Debt Maturities 2012 1000 2013-2020 757 9.25% Notes 2021-2022 751 2023-2026 262 PACS 2027-2030 100 2031 1170 2032 850 2033 300 A-25 104
The Williams Companies — FY2003 Earnings Presentation on 6ix