Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — 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
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
Slide 4: 2003 Review
2003 Review Steve Malcolm President, Chairman & CEO
Slide 5: Strategy
Strategy Commercial Natural gas assets in key growth markets where we enjoy the competitive advantages of scale, low-cost position and market leadership Financial Create and maintain adequate liquidity from all available sources to fully support business strategy De-leverage through combination of a
Slide 6: Initiate & Stabilize, Execute Restructuring, Emerge
Initiate & Stabilize Execute Restructuring Emerge Avoid bankruptcy Address liquidity crisis Restore customer and supplier confidence Complete asset sales Rationalize cost structure Manage liquidity De-lever Restore confidence of and gain access to capital markets Position company for integrated natu
Slide 7: 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 De-lever Net $2 billion decrease in debt in
Slide 8: 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 Pending Asset Sales
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 commitments Exit ti
Slide 10: 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 Path Ahead
Slide 11: 2003 Financial Review
2003 Financial Review Don Chappel, CFO
Slide 12: 2003 Results
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) ($1.03) ($1.63) Recurring Inc./(Loss) from Cont. Ops** $57
Slide 13: 4th Quarter Recurring Income from Continuing Operations
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 - Net - 2 (2) Less: Income Tax Provision 61 52 9 Recurring Income from Cont. Op. $57 $54 $3 Preferre
Slide 14: Full Year Recurring Income from Continuing Operations
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) - (105) Cal. Refund & Other Accrual Adj 33 - 33 Other - Net 45 110 (65) Less: Income Tax Provision (
Slide 15: 2003 Segment Profit
2003 Segment Profit Reported Recurring 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 $626 $1,175 $870 Dolla
Slide 16: 2003 EBITDA Reconciliation
2003 EBITDA Reconciliation 671 DD&A 29 Provision for Income Taxes 1,243 Net Interest Expense Dollars in millions ($504) Net (Loss)* $1,946 EBITDA* (254) Income from Disc. Operations 761 Cum. Effect of Change in Acct. Principle * Includes gains and impairments on asset sales and prior period adjustme
Slide 17: 2003 Segment Contributions
* Includes gains and impairments on asset sales and prior period adjustments **Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 2003 Segment Contributions * * Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) $555 $401 $2
Slide 18: 2003 Cash Information
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) Ending Cash* $2,318 $2,318 Restricted Cas
Slide 19: Debt Balances
Debt Balances 2003 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 Scheduled & Tendered Debt Retirements (1,742) Progeny Debt Payments (460) Accreted Capitalized Interest 69 Lehman/Berkshire Loan Prep
Slide 20: Enterprise Risk Management
Enterprise Risk Management 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 $1,131 Change ($75) Corp./ E&P Midstream Power Other Total Estimated
Slide 21: Enterprise Risk Management: Margin Volatility
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. Does not i
Slide 22: Enterprise Risk Management Sensitivities
Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associat
Slide 23: Business Unit Review and Outlook
Business Unit Review and Outlook
Slide 24: Exploration & Production
Exploration & Production Ralph Hill, Senior VP
Slide 25: Exploration & Production Segment Profit
4th Quarter 2003 2002 2003 2002 Exploration & Production Segment Profit 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 of $8 million in 4Q02 an
Slide 26: Exploration & Production 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 partner in Arkom
Slide 27: Exploration & Production Proved Reserves Reconciliation
Exploration & Production Proved Reserves Reconciliation - -390 - -186 +445
Slide 28: 2003 Year End U.S. Reserves
Proved + Probable Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 1553 264 690 171 Proved Reserves TOTAL: 2.7 Tcf Proved Exploration & Production 2003 Year End U.S. Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 3286 1558 948 229
Slide 29: Exploration & Production 2004-2006 Guidance
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 Dollars in millions Exploration & Production 2004-2006 Guidance
Slide 30: 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 MMcf/d net production Leasehold 58,000 net acres 168 total we
Slide 31: 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 production Leasehold 94,000 net acres 714 operated and 1,400+ jo
Slide 32: 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 gross/457,900 net acres 4,109 total wells, 50% operated 2003 drilling s
Slide 33: 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 Williams and partner BLM's goal is to issue 3,000 permits per year,
Slide 34: 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 inventory 802 total operated wells, high working interest 2003 drillin
Slide 35: Exploration & Production Basin Comparison
Exploration & Production Basin Comparison
Slide 36: 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 Exploration & Production Hedging
Slide 37: Exploration & Production 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 backyard investment an
Slide 38: 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 possibles inventory Low-cost, high-margin producer Experi
Slide 39: Gas Pipeline
Gas Pipeline Doug Whisenant, Senior VP
Slide 40: Gas Pipeline Assets
Gas Pipeline Assets Transco Northwest Gulfstream (50% Ownership)
Slide 41: Gas Pipeline Segment Profit
Gas Pipeline Segment Profit 4th Quarter 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 Segment Profit $148 $143 $581 $574
Slide 42: Gas Pipeline 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 Central New Je
Slide 43: Gas Pipeline Strengths
Location Low cost provider Few expiring long-term contracts Customer credit quality Gas supplies System flexibility Gas Pipeline Strengths
Slide 44: Gas Pipeline Restore/Replace 26" Pipeline
THURSTON LEWIS GRAYS HARBOR TUMWATER PIERCE SUMNER KING SNOHOMISH SKAGIT WHATCOM Bellingham SUMAS MT VERNON SNOHOMISH Redmond Everett Seattle Existing 30" Mainline Proposed 26" Replacement Facilities CHEHALIS Jackson Prairie Storage Gas Pipeline Restore/Replace 26" Corrective Action Order Idle 26" m
Slide 45: Gas Pipeline 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
Slide 46: Gas Pipeline 2004-2006 Guidance
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 $430-480 Dollars in millions Gas Pipeline 2004-2006 Gui
Slide 47: Gas Pipeline 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
Slide 48: Midstream
Midstream Alan Armstrong, Senior VP
Slide 49: Midstream Assets and Market Positions
Straddle Plants Fort McMurray (Oil Sands) Conway Olefins Fractionator Wyoming Produce over 50% of NGL's coming out of Wyoming San Juan Gather approximately 38% of the gas, ranking Midstream #1 in the basin Gulf Coast Gather 40% of the gas produced in the Western Gulf of Mexico Venezuela Gas injectio
Slide 50: Midstream Segment Profit
Midstream Segment Profit 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/To be sold 5 11 9 55 $67 $77 $310 $254 4Q 2002 vs. 4Q 2003 We
Slide 51: 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 - closed 10/03 Dry Trail - closed 12/03 Satisfactorily r
Slide 52: Midstream Remaining Assets for Sale
Midstream Remaining Assets for Sale 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 Timing of Closing Dollars in millions
Slide 53: Midstream 2004-2006 Guidance
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 Margins Olefins Margins Deepwater Growth Asset Sales Do
Slide 54: Midstream Segment Profit Breakdown-Guidance
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)-30 (20)-30 Gains/Losses/Impairments (77) - - - - Assets Sold/To B
Slide 55: Midstream Net Revenue Components
Midstream Net Revenue* Components End of Year 2003 2006 * Net Revenue is total revenues before eliminations less cost of goods sold for NGLs, Olefins, Condensate, & Trading Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Other Revenue Commodity Based Current 0.53 0.14 0.06 0.06
Slide 56: Midstream Projected Deepwater Growth
$ Millions 2002 2003 2004 2005 2006 Actual / Contracted Business 38.4 98.9 144.1 175.1 157.6 Identified Business 82 Midstream Projected Deepwater Growth East Breaks Placed in service 4th Qtr. 2001 Original Projection for 2003 = 172MMcfd 2003 Actual = 343 MMcfd Canyon Station Production exceeding est
Slide 57: Midstream 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
Slide 58: Midstream 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
Slide 59: Power
Power Bill Hobbs, Senior VP
Slide 60: Power 4Q 2003 Segment Profit
Power 4Q 2003 Segment Profit 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 & Other Inc (Exp) (35) (17) (79) (49) Impairments (89) (98) (89) (253) Gain on Sale of Asset
Slide 61: Power Segment Profit/(Loss) Recurring Reconciliation
4th Quarter 2003 2002 2003 2002 Power 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 Adj. 33 - 33 - Regulatory & Oth
Slide 62: Power Undiscounted Cash Flows-Guidance
Power Undiscounted Cash Flows-Guidance Tolling Demand Payment Obligations ($393) ($391) ($395) ($400) Resale of Tolling 123 143 117 104 Full Requirements 19 16 41 46 Long Term Physical Forward Power Sales 75 97 100 76 OTC Hedges 6 168 52 78 Estimated Hedges Tolling Revenues 51 108 196 251 ($119) $14
Slide 63: Power 2003 Cash Flow
Power Other Bus. 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 Dollars in millions Power 2003 Cash Flow
Slide 64: Power 2004-2006 Guidance
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 vary significantly from given ranges. Future
Slide 65: Power 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 for gas Favo
Slide 66: Power 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 risks greater a
Slide 67: 2004-2006 Consolidated Outlook
2004-2006 Consolidated Outlook Don Chappel
Slide 68: Consolidated 2004 Segment Profit Guidance
Consolidated 2004 Segment Profit Guidance 275 - 375 Midstream 25 - (40) Other/Rounding 275 - 340 Exploration & Production Dollars in millions $525 - 575 Gas Pipeline $1,100 - 1,250 2004 Forecast 0 - 150 Power $1,100 - 1,400 Total
Slide 69: Consolidated 2004 Guidance
1,600 - 2,000 1,000 - 1,300 $1,100 - $1,400 0 - 200 Net Income Cash Flow from Operations 20 - 200 Income from continuing operations Segment profit* $ Dollars in millions, except per-share amounts $0.00 - $0.40 EBITDA Diluted Earnings Per Share Consolidated 2004 Guidance Note: Excludes potential gain
Slide 70: 2004 Forecast EBITDA Reconciliation
2004 Forecast EBITDA Reconciliation 650 - 700 DD&A 60 - 5 Other/Rounding 810 - 900 Net Interest Dollars in millions $0 - 200 Net Income $1,600 - 2,000 EBITDA 0 - 20 Income from Disc. Operations 80 - 175 Provision for Income Taxes
Slide 71: Consolidated 2004 Forecast Segment Contribution
Gas Pipes E&P Midstream Power Corp/Other Total 275 - 340 160 - 180 435 - 520 275 - 375 180 - 190 455 - 565 25 - (40) 15 - 20 40 - (20) 0 - 150 20 - 25 20 - 175 1,100 - 1,400 650 - 700 1,750 - 2,100 (130) - (110) 0 - 50 (20) - (40) 1,600 - 2,000 525 - 575 275 - 285 800 - 860 Segment Profit (Loss) DD&
Slide 72: Consolidated 2004-2006 Outlook
Consolidated 2004 - 2006 Outlook 900 - 1,100 900 - 1,100 700 - 800 Capital Expenditures 700 - 800 650 - 750 650 - 700 DD&A 2006 2005 2004 Dollars in millions 1,100 - 1,400 Segment Profit 39% 39% 39% 1,400 - 1,700 1,300 - 1,600 1,000 - 1,300 Cash flow from Operations 1,400 - 1,700 1,300 - 1,600 Effec
Slide 73: Consolidated Drivers
Consolidated Drivers Dollars in millions
Slide 74: 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(r) -based investment Consider dividend and/or share repurchas
Slide 75: Summary
Summary Steve Malcolm
Slide 76: Strategy
Strategy Commercial Natural gas assets in key growth markets where we enjoy the competitive advantages of scale, low- cost position and market leadership Financial Create and maintain adequate liquidity from all available sources to fully support business strategy De-leverage through combination of
Slide 77: 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 Business Unit Positioning
Slide 78: Initiate & Stabilize, Execute Restructuring, Emerge
Initiate & Stabilize Execute Restructuring Emerge Avoid bankruptcy Address liquidity crisis Restore customer and supplier confidence Complete asset sales Rationalize cost structure Manage liquidity De-lever Restore confidence of and gain access to capital markets Position company for integrated natu
Slide 79: Williams
te Williams. [aa Les | Williams. | ae
Slide 80: Appendix
Appendix A-1
Slide 81: Appendix Contents
Appendix Contents Exploration & Production 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 Expansion Projects A
Slide 82: Appendix Contents (cont.)
Appendix Contents (cont.) Midstream 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-23 East Undiscounted
Slide 83: Arkoma Basin Average Well Economics
20+ years Gross Reserves 848 MMcf 450 Mcfd Mcfd Average 2004 Lona Valley Well Exploration & Production Arkoma Basin A-4
Slide 84: San Juan Basin Average Well Economics
Gross Reserves 1.52 Bcf 18 years Mcfd 700 Mcfd Average 2004 Fruitland Coal Well Exploration & Production San Juan Basin A-5
Slide 85: Powder River Basin Average Well Economics
Average 2004 Big George Coal Well Exploration & Production Powder River Basin A-6 6-8 years 430 40 430 24 Months Mcfd Dewatering Process 0 12 400 Gross Reserves 0.49 Bcf
Slide 86: Piceance Basin Average Well Economics
Average 2004 Mesaverde Well Exploration & Production Piceance Basin A-7 1561 Mcfd EUR = 1.6 BCF Gross Reserves 1.34 Bcf 20+ years Mcfd
Slide 87: Gas Pipeline Northwest 2003 Expansion Projects
Gas Pipeline Northwest 2003 Expansion Projects Rockies 175 MDth/d Nov 2003 $124 MM Evergreen 276 MDth/d Oct 2003 $198 MM Columbia Gorge 57 MDth/d Nov 2003 $43 MM A-8
Slide 88: Gas Pipeline Transco 2003/2004 Expansion Projects
Gas Pipeline Transco 2003/2004 Expansion Projects Trenton Woodbury 51 MDth/d Nov 2003 $20 MM Momentum 323 MDth/d 2003/2004 $175 MM A-9
Slide 89: Gas Pipeline Gulfstream 2004 Extension Project
Gas Pipeline Gulfstream 2004 Extension Project FPL's Manatee Plant FPL's Martin Plant Total Capacity 1.1 Bcf/d A-10
Slide 90: Gas Pipeline Northwest Rate Comparison
Demand Commodity GTN Third Party Fuel Northwest / Piaute 0.2701 0.037 0.3094 0.188 GTN / Tuscarora 0.254 0.008 0.4833 0.186 Northwest 0.2701 0.037 0 0.073 GTN 0.069 0.001 0 0.017 Northwest 0.2701 0.037 0 0.073 GTN 1.11 0.01 0 0.093 Reno, NV Medford, OR Spokane, WA Gas Pipeline Northwest Rate Compari
Slide 91: Gas Pipeline Transco Rate Comparison
Demand Commodity Fuel Other Transco 0.2369 0.009 0.117 0.0137 SNG 0.3547 0.029 0.1449 0.012 Transco 0.3344 0.0148 0.1957 0.0137 SNG 0.3547 0.029 0.1449 0.012 CGT 0.3939 0.0291 0.2973 0.0026 Transco 0.3935 0.018 0.2409 0.0137 Iroquois 0.4162 0.0054 0.0644 0.0008 CGT 0.3939 0.0291 0.2973 0.0026 Tenn 0
Slide 92: Gas Pipeline Contract Expirations - Cumulative
Gas Pipeline Contract Expirations - Cumulative 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Northwest 9.2 349.1 109.1 496.2 160 58.4 102 379.6 Transco 311.874 370.08 1200.474 590.133 111.115 175.527 477.796 700.187 222.104 635.281 Northwest Capacity 2247.8 2509.7 2509.7 2509.7 2509.7 2509.7 250
Slide 93: Gas Pipeline Northwest Customer Base
Gas Pipeline Northwest Customer Base A-14
Slide 94: Gas Pipeline Transco Customer Base
Gas Pipeline Transco Customer Base A-15 Local Distribution Co. 22 Baa2/BBB+ South Jersey Gas Company Local Distribution Co. 30 Baa2 Philadelphia Gas Works Local Distribution Co. 21 A3/A- Atlanta Gas Light Local Distribution Co. 46 A3/A SCANA Local Distribution Co. 51 A1/A ConEd of NY Local Distribut
Slide 95: Gas Pipeline Gulfstream Customer Base
Gas Pipeline Gulfstream Customer Base Contract terms are for 18 - 23 years Muni. Utility A3 $2.0 10 FMPA 350 68 35 10 190 30 32 FT Contract Mdth/d $70.3 $13.7 $7.0 $2.0 $38.0 $6.0 $6.4 Demand Revenue ($MM) PHASE II (Dec 2004) PHASE I (May 2002) IOU BBB/A1 FPL IPP CCC+/Caa1 Calpine LDC BBB+ Central F
Slide 96: Gas Pipeline Northwest Supply Diversity
Gas Pipeline Northwest Supply Diversity A-17
Slide 97: Midstream 2003 Strong Operational Metrics
Midstream 2003 Strong Operational Metrics A-18 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 Gathering Volumes 5665 5643 5971 5729 6104 6072 6092 5982
Slide 98: Midstream Frac Spread vs. Net Liquid Margin
Midstream 2003 Strong Operational Metrics Frac Spread vs. Net Liquid Margin Total NGL Production A-19 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 U.S. 149 135 151 150 147 119 138 132 Canada 144 145 162 155 153 123 132 150 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 HH/MB Frac
Slide 99: Power 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 67% for Power 33% for Wi
Slide 100: Power Total Undiscounted Cash Flows
Power Total Undiscounted Cash Flows A-21 ($ Millions)
Slide 101: Power West Undiscounted Cash Flows
Power West Undiscounted Cash Flows A-22 ($ Millions)
Slide 102: Power Mid. Cont. Undiscounted Cash Flows
Power Mid. Cont. Undiscounted Cash Flows A-23 ($ Millions)
Slide 103: Power East Undiscounted Cash Flows
Power East Undiscounted Cash Flows A-24 ($ Millions)
Slide 104: Consolidated Scheduled Debt Maturities
Consolidated Scheduled Debt Maturities 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013-2020 2021-2022 2023-2026 2027-2030 2031 2032 2033 Misc. Notes 285 247 972 920 385 138 1014 1078 1000 757 751 262 100 1170 850 300 9.25% Notes 679 PACS 1100 ($ Millions) A-25