Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — The Williams Companies — Q1 2004 Earnings Presentation
124 slides from Williams Companies, Inc. (the)'s earnings presentation, May 6, 2004
Slide 1: Williams Analyst Meeting
Williams Analyst Meeting May 6, 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 ! Overview Steve Malcolm ! 1Q04 Financial Results & 2004 Outlook Don Chappel ! Business Unit Review & Outlook – Exploration & Production Ralph Hill – Midstream Alan Armstrong – Gas Pipeline Doug Whisenant – Power Bill Hobbs ! Financial Overview & 3-Year Outlook Don Chappel ! Summary Steve Mal
Slide 4: Overview
Overview Steve Malcolm President, Chairman & CEO
Slide 5: Headlines
Headlines ! Williams hits backstretch of restructuring – Asset sales nearly done – $1.5 billion credit in hand – Ready to ramp up debt reduction – Cost reductions taking hold – Still have $2 billion cash after major debt retirement – No news on Power 5
Slide 6: Headlines
Headlines ! Williams 1Q segment profit moves up during restructuring – Results on track to meet recurring guidance – Portfolio of natural gas businesses perform – Power posts segment loss, but big improvement – Power generates $163 million cash flow from ops – Interest costs drop $110 million 6
Slide 7: Headlines
Headlines ! Williams poised for post-restructuring growth – Integrated natural gas assets – Organic growth opportunities ample – Investments today preserve competitive position – Maintain financial discipline – Focus on value-creating growth 7
Slide 8: First Quarter Results
First Quarter Results ! Bright points in business performance – Generated positive cash from operations – Midstream exceeded expectations – E&P ramping up this year – Gas Pipeline earnings plateau until rate cases filed – Corporate expenses reflect restructuring ! On track to achieve recurring earni
Slide 9: Changes to Consolidated Guidance
Changes to Consolidated Guidance Dollars in millions Segment Profit: 2004 2005 2006 No Change Capital Expenditures: 725-825 800-1,000 No Change 700 – 800 900 – 1,100 Net Income Reported (50)-125 0 – 200 Recurring 90-210 91 – 210 EPS ($0.10)-$0.24 Reported $0.00 – 0.40 Recurring $0.17 – $0.40 $0.17 –
Slide 10: Continuation of Restructuring
Continuation of Restructuring ! De-leveraging ! Completing asset sale program ! Reducing costs ! Power 10
Slide 11: Power
Power ! Continued success with interim strategy – Reducing risk – Generating cash – Meeting contractual obligations ! Continued disappointment in efforts to fully exit through sale – Depressed market, values – Limited interest ! Preferred path is exit ! May need to continue to operate – Continue cur
Slide 12: Implications of No Power Sale
Implications of No Power Sale ! Favorable – Positive cash flows from Power operations – Qualify for hedge accounting – Earnings better track cash flows; less volatility – Enhanced opportunities to hedge risk – Retain talent ! Unfavorable – Imputed debt from tolling contracts remains – Continued adeq
Slide 13: Growth Strategy
Growth Strategy ! Investment discipline – Value-creation focus – Preserve financial flexibility – Balance with debt reduction ! Optimize competitive advantages – Exploration & Production • Production development • Rockies reserves and tight-sands expertise – Midstream • Incremental deepwater • Aggre
Slide 14: The Road Ahead
The Road Ahead 2004 2005 2006 2007 & beyond Arkoma production doubles Exploration Piceance major growth vehicle Piceance growth continues & Production Powder River permits and dewatering Powder River grows CORE BUSINESSES Complete deepwater Maintain competitive Capture our share Disciplined Midstrea
Slide 15: Key Points
Key Points ! First quarter results on track ! Stronger balance sheet ! Financial flexibility increasing ! Asset sales nearly complete ! Natural gas focus ! Financial discipline embedded throughout ! Sustainable value creation 15
Slide 16: Financial Results & 2004 Outlook
Financial Results & 2004 Outlook Don Chappel, CFO
Slide 17: Financial Results
Financial Results Dollars in millions (except per share amounts) 1Q04 1Q03 Income/(Loss) from Continuing Ops.* $5 ($39) Income/(Loss) from Discontinued Ops. 5 (14) Effect of Accounting Change - (761) Net Income/(Loss)* $10 ($814) Net Income/(Loss) Share* $0.02 ($1.59) Recurring Inc./(Loss) from Cont
Slide 18: Recurring Income from Cont. Operations
Recurring Income from Cont. Operations Dollars in millions 1Q04 1Q03 Difference Income/(Loss) from Cont. Ops. $5 ($39) $44 Impairments/Losses/Write-offs - 12 (12) Workforce Reduction Expenses - 12 (12) Longhorn Recapitalization Fees 7 - 7 Less: Income Tax Provision 3 9 (6) Recurring Income from Cont
Slide 19: Net Income Components
Net Income Components Dollars in millions (except per share amounts) 1Q04 1Q03 Segment Profit $276 $250 Net Interest Expense (239) (341) Other (17) 41 Income/(Loss) from Cont. Ops. Before Tax* 20 (50) Provision for Income Tax (15) 11 Income/(Loss) from Continuing Ops.* $5 ($39) Income/(Loss) from Di
Slide 20: Segment Profit
Segment Profit Reported Recurring Dollars in millions 1Q04 1Q03 1Q04 1Q03 Gas Pipeline $148 $151 $148 $151 Exploration & Production 52 114 52 114 Midstream Gas & Liquids 118 116 118 116 $318 $381 $318 $381 Power (33) (136) (33) (125) Other (9) 5 (2) 5 Segment Profit* $276 $250 $283 $261 *Reported se
Slide 21: Major Changes in Recurring Segment Profit
Major Changes in Recurring Segment Profit Dollars in millions Recurring Segment Profit 1Q2003 $261 Power 92 - Margin improvement +$89 million Midstream 2 - Improved Canadian performance +$10 million - Venezuela operations improvement +$8 million - Higher Discovery equity earnings +$9 million - Lower
Slide 22: Cash Information
Cash Information Dollars in millions 1Q04 Beginning Cash* $2,318 Cash Flow from Continuing Operations 176 Cash Flow from Discontinued Operations (73) Capital Expenditures/Investments (128) L/C Collateral 95 Debt Retirements (711) Asset Sales 356 Other-Net (34) Ending Cash* $1,999 Change in Cash ($31
Slide 23: Debt Balance
Debt Balance Dollars in millions Avg. Cost Debt Balance @ 12/31/03 * $11,979 7.7% Scheduled Debt Retirements & Amortization (697) Tendered Debt Retirements (14) Debt Balance @ 3/31/04 $11,268 7.7% Net Decrease in Debt ($711) Fixed Rate Debt $10,671 7.9% Variable Rate Debt $597 3.3% * Debt is long-te
Slide 24: Financing Plan Progress to Date
Financing Plan Progress to Date ! Repriced RMT loan at LIBOR + 250 bps – 125 bps reduction, or $6 million annual interest savings ! Retired $711 million in debt in the first quarter ! Closed $1.5 billion of credit facilities – Step 1: $500 million, 5-year unsecured capacity with Citibank and syndica
Slide 25: Rationale for New Credit Facilities
Rationale for New Credit Facilities ! Enables $1.0 billion reduction in cash for debt repayment ! Ensure ample long-term liquidity access ! Unsecured facilities provide 5-year capacity that frees up cash – 135 bps above short-term, secured borrowing cost without typical maintenance covenants of synd
Slide 26: 2004 Segment Profit Guidance
Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast Gas Pipeline $525 - 575 Exploration & Production 275 - 300 $275-340 Midstream 300 - 385 $275-375 Other/Rounding 0 - (10) $1,100 - 1,250 Power* 0 - 150 Total $1,100 - 1,400 * Assumes full-year forward MTM gains or losses are
Slide 27: 2004 Forecast Guidance
Consolidated 2004 Forecast Guidance Dollars in millions, except per-share amounts Segment profit $1,100 – $1,400 Net Interest Expense (840) – (880) Early Debt Retirement Costs (225) – (175) Other (Primarily General Corporate Costs) (80) – (125) Pretax Income (45) - 220 Provision for Income Tax (5) –
Slide 28: 2004 Forecast EBITDA Reconciliation
2004 Forecast EBITDA Reconciliation Dollars in millions Net Income/(Loss) ($50) – 125 Income/(Loss) from Disc. Ops 0 – (20) Net Interest 840 – 880 DD&A 650 – 700 Provision for Income Taxes 5 - 115 Rounding (70) – 25 EBITDA $1,375 – 1,825 Early Debt Retirement Fees 225 – 175 EBITDA - Recurring $1,600
Slide 29: Exploration & Production
Exploration & Production Ralph Hill, Senior Vice President
Slide 30: Segment Profit
Exploration & Production Segment Profit Dollars in millions 1Q04 4Q03 1Q03 Segment Profit $52 $50 $114 ■ Year-over-year decrease includes ■ $33 million due to lower net realized price ■ $14 million due to loss of production associated with asset sales ■ $17 million due to loss of revenues from exces
Slide 31: 2004-2006 Guidance
Exploration & Production 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment profit $275-300 $375-475 $425-525 $275-340 $350-450 $400-500 Annual DD&A $160-180 $195-225 $230-260 Capital spending $325-375 $400-450 $450-500 $300-350 Production (MMcfe/d) 525-550 600-700 700-800 500-550 Note: I
Slide 32: 2004 Impact of Legacy Hedges from Asset Sales
Exploration & Production 2004 Impact of Legacy Hedges from Asset Sales ! Minimal price upside in ’04 ! Asset sales resulted in 80% of wellhead production hedged, which equates to 95%+ of revenue hedged Why… ! Volumes reduced by fuel and shrink ! Severance and ad valorem taxes paid on market price !
Slide 33: First Quarter Accomplishments
Exploration & Production First Quarter Accomplishments ! Retained basins’ production increased 3.4% from 4Q ’03 ! Piceance production approached all-time high during the quarter ! Piceance rig count increased from 8 rigs to 12 rigs ! Progress on Powder River CBM permits ! San Juan and Arkoma product
Slide 34: Unique Drilling Portfolio
Exploration & Production Unique Drilling Portfolio Estimated years of drilling inventory ! High-quality reserve base Powder River ! Investments are short cycle 9-10 yrs. time, fast cash returns ! Diverse producing basins, long-term drilling inventory Piceance ! Low-cost, high-margin 10 yrs. producer
Slide 35: Current and Projected Volumes
Exploration & Production Current and Projected Volumes 300 200 Mmcfe/d 100 0 Piceance Powder River San Juan Arkoma/Other International Sep. '03 Current YE '04 Note: Assumes mid-point of guidance range for year-end 2004 35
Slide 36: 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% San Juan 6% 16% San Juan 26% Piceance 58% Piceance 54% Powder Powder River River 10% 26% Total: 2.7 Tcf Proved* *98% of proved reserves were audited or prepared by N
Slide 37: Acquisitions Lead to Successful Reserves Additions
Exploration Exploration & & Production Production Acquisitions Lead to Successful Reserves Additions Development reserves added 2001-2003 2.5 Average Development Cost: 2.0 $0.70 per Mcfe 0.7 Reserves (Tcfe) 1.5 1.0 1.5 1.5 0.5 0.0 Acquisitions Development Reflective of retained basins 37
Slide 38: Margin Analysis
Exploration & Production Margin Analysis 3-Year Average (2004-06) $5.00 $4.00 $3.00 Cash Margin 2.85 $2.00 $4.20 $1.00 Cash Costs* $1.35 $0.91 $0.00 Realized Gas Price Margin/Cost Historical F&D Assumption Assumption Costs** Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Inclu
Slide 39: Where the Growth Is
Exploration & Production Where the Growth Is ! Through the drill bit – Rapid Piceance growth – Powder River growth beginning 2006 – Arkoma/San Juan production increases 20% by 2006 – Drill 1,200 – 1,400 development wells per year – Developing PUDS, proving up probables ! Additional growth - Backyard
Slide 40: Growth by Major Basin
Exploration & Production Growth by Major Basin Piceance San Juan Drilling Capital Drilling Capital 300 Production 300 300 Production 300 $Millions $Millions 200 200 200 200 MMcfd MMcfd 100 100 100 100 0 0 0 0 2003 2004 2005 2006 2003 2004 2005 2006 Powder River Arkoma/Other Drilling Capital Drilling
Slide 41: Challenges and Opportunities
Exploration & Production Challenges and Opportunities ■ Challenges – Pace of drilling permit approvals – Rig availability – Upward cost pressure ■ Opportunities – BLM committed to streamlining – Williams has successfully obtained additional rigs – Opportunity to increase drilling pace beyond planned
Slide 42: Growth Metrics
Exploration & Production Growth Metrics $800 $600 $ Millions $400 $200 $0 2004 2005 2006 Volume Maint Capital Growth Capital Seg Profit + DD&A Note: Assumes midpoint of guidance range 42
Slide 43: The Road Ahead
Exploration & Production The Road Ahead 2004 2005 2006 2007 & beyond Develop current inventory Base Piceance primary growth driver Plan Powder River permits and dewatering Powder River volumes grow San Juan production modest growth Arkoma production doubles Disciplined New exploitation projects grow
Slide 44: Key Points
Exploration & Production Key Points " Plan based on organic growth from existing positions " Investments are short time cycle, fast cash returns " High-quality reserve base " History of high success, low finding costs " Diverse producing basins, long-term drilling inventory " Significant probables a
Slide 45: Midstream
Midstream Alan Armstrong, Senior Vice President
Slide 46: Segment Profit
Midstream Segment Profit Dollars in millions 1Q04 4Q03 1Q03 Segment Profit $118 $46 $116 Includes: Impairments - 42 - Gains on sale of assets - (16) - Recurring Segment Profit $118 $72 $116 ! 1Q03 vs. 1Q04 – Stronger Canadian performance of $10 million in 1Q04 – Discovery expenses lower by $9 millio
Slide 47: First Quarter Accomplishments
Midstream First Quarter Accomplishments Recurring Segment Profit + Depreciation* 180 ! Record quarterly segment profit ! Completed Opal TXP-4 and 160 dehydration facilities 140 ! Completed Devils Tower spar ! Asset sales progress 120 – Ethane re-contracted 100 – Letters of intent executed $ MM 80 60
Slide 48: Today
Midstream Today Fort McMurray (Oil Sands) Core Areas Olefins Fractionator Wyoming Straddle Plants Produce over 50% of NGL’s coming out of Wyoming San Juan (Four Corners) Gather approximately 38% of the gas, ranking Midstream Conway #1 in the basin Gulf Coast Geismar Gather 40% of the gas produced in
Slide 49: Gulf Coast Overview
Midstream Gulf Coast Overview Unregulated assets NGL services Crude oil pipelines 49
Slide 50: Deepwater Growth
Midstream Deepwater Growth ! East Breaks – Placed in service 4Q 2001 • Original Projection for 2003 = 172MMcf/d / 54 MBOD • 2003 average daily production = 376 MMcf/d / 63 MBOD • 1Q 2004 = 375 MMcf/d / 69 MBOD ! Canyon Station – Production exceeding estimates by 30+ MMcf/d – 2003 average daily produ
Slide 51: Success at East Breaks
Midstream Success at East Breaks Cumulative Wells Drilled Reserves (MMBOE) 45 400 40 350 35 300 30 250 25 200 20 150 15 100 10 5 50 0 0 1998 1999 2000 2001 2002 2003 Sanction (1998) Today 51
Slide 52: Success at East Breaks
Midstream Success at East Breaks 52
Slide 53: Net Revenue Components
Midstream Net Revenue Components NGL - Keep Whole NGL - 13% Keep Whole NGL - 10% NGL - % of Proceeds % of Proceeds 2% 4% Olefins 3% Olefins 3% Fee Based Fee Based 80% 85% 2003 2006 Note: Total revenues less cost of goods sold. Reflects 2003 margins. 53
Slide 54: Domestic NGL Production & Weighted Avg Margins
Midstream Domestic NGL Production & Weighted Avg Margins Williams NGL Equity Mix 15 Williams Wtd Avg Net Liquid Margin 2002 Avg 5-Yr High Gulf Coast 35% 10 Rockies ¢/gal 50% 2003 Avg 5-Yr Avg 5 5-Yr Low San Juan 15% 0 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q 2005 2006 '04-4Q
Slide 55: Challenges and Opportunities
Midstream Challenges and Opportunities ! Challenges – Commodity prices – MLP competition ! Opportunities – Commodity prices – Deepwater growth – Asset sales – Bolt-on growth 55
Slide 56: Growth Metrics
Midstream Growth Metrics Dollars in millions 600 500 Expansion 400 Expansion Carryforward Mand, Rel, Eff Carryforward $ MM 300 Contingency Well Connects 200 Mandatory, Reliability, Efficiency Segment Profit + 100 DDA* 0 2001 2002 2003 2004 2005 2006 Note: Excludes gains/losses/impairments; 2004-2006
Slide 57: 2004-2006 Guidance
Midstream 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $300-385* $300-400 $350-450 $275-375 Annual DD&A $180-190 $175-185 $175-185 $170-180 Capital Spending $90-110 $60-80 $50-70 * Includes results associated with assets to be sold during 2004 Note: If guidance has changed, p
Slide 58: Segment Profit Breakdown
Midstream Segment Profit Breakdown Dollars in millions 2003 1Q04 2004 2005 2006 Oper Profit 333 95 290-340 320-370 350-420 Gains/Losses/Impairments (18) - - - - Total G&P $315 $95 $290-340 $320-370 $350-420 Oper Profit (28) 1 (10)-20 (20)-30 (20)-30 Gains/Losses/Impairments - - - - - Total Petchem S
Slide 59: The Road Ahead
Midstream The Road Ahead 2004 2005 2006 2007 & beyond Complete deepwater Maintain position Capture our share of new projects deepwater production Bolt-on growth 05-07+ Disciplined Complete asset sales growth Focus on operational excellence 04-07+ 59
Slide 60: Key Points
Midstream Key Points ! Continued strong demand for services in core areas ! Record-setting 1Q 2004 performance ! Successful progression of asset sales ! Completion of deepwater projects, adding significant operating profit ! Reducing annual volatility of commodity margins ! Reliable operational perf
Slide 61: Gas Pipeline
Gas Pipeline Doug Whisenant, Senior Vice President
Slide 62: Segment Profit
Gas Pipeline Segment Profit Dollars in millions 1Q04 4Q03 1Q03 Segment profit $148 $148 $151 1Q04 ■ No non-recurring items ■ New projects provided $16 million ■ Offset by : ■ Increased non-tracked fuel expense of $9 million ■ Lower short term firm revenues of $3 million ■ Higher operating and mainte
Slide 63: 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* $295-340 $335-380 $430-490 $380-430 $430-480 •Includes TGPL owned production area assets operated by Midstream and included in Midstr
Slide 64: First Quarter Accomplishments
Gas Pipeline First Quarter Accomplishments ! Central Jersey expansion subscribed – 105 Mdth/d – $13 million capital cost – November 2005 in-service ! Momentum Phase II expansion completed – 54 Mdth/d – $25 million capital cost – February 2004 in-service ! Gulfstream Phase II extension progress conti
Slide 65: Today
Gas Pipeline Today Northwest Transco Underground storage Gulfstream LNG facility (50% Ownership) 65
Slide 66: Where the Growth Is
Gas Pipeline Where the Growth Is ! Mid Atlantic – 3% demand growth served from Leidy, Cove Point ! Florida – 8% demand growth highest in nation – Phase II for FPL doubles Gulfstream capacity under long term contract ! LNG provides significant new supply for Transco 66
Slide 67: Eastern US LNG Import Facilities
Eastern US LNG Import Facilities Existing Facilities Proposed Facilities 67
Slide 68: Transco Return Improvement Strategy
Gas Pipeline Transco Return Improvement Strategy ! Reduce SG&A costs ! Implement new rates – Recover increased costs: Clean Air Act, 1Line, DD&A, allocated SG&A ! Increase Mobile Bay throughput ! Realize higher returns in later years with negotiated rates 68
Slide 69: Northwest Restore/Replace 26"
Gas Pipeline Northwest Restore/Replace 26” ! Corrective Action Order SUMAS – Idles 268 miles of 26” mainline; loss of 360 WHATCO M Mdth/d capacity Bellingham SKAGIT – Interim restoration of service through Existing Pipeline MT VERNON hydrostatic testing Proposed Replacement – Ultimate replacement of
Slide 70: Northwest 26" Restore-to-Service Plan
Gas Pipeline Northwest 26” Restore-to-Service Plan ! Commence hydrostatic testing March 2004 ! Return 130 miles to service by June 2004 ! Restore 131 MDth/d of idled capacity ! Provide sufficient capacity for expected demand ! Projected cost $35-50 million in addition to $9 million spent in 2003 70
Slide 71: Northwest 26" Replacement Plan
Gas Pipeline Northwest 26” Replacement Plan ! Replace lost capacity of 360 MDth/d – 75 miles of 36” loop; 17,000 hp of compression – November 2006 in-service ! Verify the need to replace capacity with market ! Projected cost $305-350 million 71
Slide 72: Gulfstream Update
Gas Pipeline Gulfstream Update ! Phase II construction to begin summer 2004 – 109-mile, 30” extension to serve Florida Power & Light’s Martin plant – Supported by 350 Mdth/d, long-term commitment by FPL – December 2004 in-service ! Capacity under long-term contract – Today: 295 Mdth/d (27% of capaci
Slide 73: Gulfstream Competitive Situation
Gas Pipeline Gulfstream Competitive Situation ! Gulfstream negotiated rates: $0.55-0.60/Dth demand, $0.02/Dth commodity, plus 2.0% fuel ! Florida Gas Transmission rates for recent expansions as much as: $0.7618/ Dth demand, $0.0217/Dth usage, plus 3.14% fuel ! Bahamas LNG could compete in South Flor
Slide 74: Challenges and Opportunities
Gas Pipeline Challenges and Opportunities ! Challenge – Restore/replace Northwest’s 26” pipeline ! Opportunities – Transco new rates – Gulfstream unsubscribed capacity – Organic growth 74
Slide 75: 2004-2006 Capital Spending Detail
Gas Pipeline 2004-2006 Capital Spending Detail Dollars in millions 2004 2005 2006 Normal Maintenance $150-160 $155-165 $140-150 Clean Air Act 75-85 105-115 25-30 NWP 26” Restore/Replace 40-50 60-75 240-275 25-50 100-120 240-260 Subtotal $265-295 $320-355 $405-455 Expansion 30-45 15-25 25-35 30-40 15
Slide 76: Growth Metrics
Gas Pipeline Growth Metrics Dollars in millions $1,000 $800 $600 $400 $200 $0 2004 2005 2006 Clean Air Act Restore/Replace Normal Maint. Expansion Seg Profit + DD&A Note: Assumes mid-point of guidance ranges 76
Slide 77: The Road Ahead
Gas Pipeline The Road Ahead 2004 2005 2006 2007 & beyond Complete announced expansion projects Expansions Disciplined Northwest testing and return to service Northwest capacity replacement Rate cases growth 2004 • Feb : Momentum Phase II in-service • June: Northwest testing and return to service • D
Slide 78: Key Points
Gas Pipeline Key Points ! Strategic location ! Access prolific gas supplies ! Highly valued system flexibility ! Low-cost provider ! Long-term contracts with quality customers ! Strong, growing markets ! Lower capital expenditures in 2005 Results in stable segment profit and operating cash flows 78
Slide 79: Power
Power Bill Hobbs, Senior Vice President
Slide 80: Reported Segment Profit
Power Reported Segment Profit Dollars in millions 1Q04 4Q03 1Q03 Gross Margin ($2) $40 ($91) SG&A (16) (17) (36) Op. Exp. & Other Inc / (Exp) (15) (124) (9) Reported Segment Profit ($33) ($101) ($136) Includes: Impairments - 89 - Prior period adjustment - (12) - Cal. Refund & other accrual adj. - 33
Slide 81: Proforma Accrual Basis Results
Power Proforma Accrual Basis Results Dollars in millions 1Q04 Reported Segment Profit (33) Reverse Unrealized MTM (23) Add Realized Prior Period MTM 137 Proforma Accrual Basis Results* $81 * Non-GAAP Proforma Accrual Basis Results – represents amount the portfolio realized on an accrual basis and wo
Slide 82: Power Cash Flows
Power Power Cash Flows Dollars in millions 1Q04 Proforma Accrual Basis Results* $81 Depreciation 5 86 Taxes @ 39% (34) 52 Working Capital Change 116 Other (5) Power CFFO** $163 * Non-GAAP Proforma Basis Results – represents amount the portfolio realized on an accrual basis and would have reported in
Slide 83: Undiscounted Cash Flows Variance Analysis
Power Undiscounted Cash Flows Variance Analysis Dollarsininmillions Dollars millions 4Q03 4Q02 2003 2002 Combined Power Portfolio Actual Forecast Actual 1Q04 v. Forecast 1Q04 1Q04 1Q04 Tolling Demand Payment Obligations $(88) $(85) Resale of Tolling 41 42 Full Requirements (1) (4) Long-term Physical
Slide 84: 2004-2006 Guidance
Power 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit* $0-150 $50-150 $50-200 Capital Expenditures $0 $0 $0 Cash Flows from Operations** $150-350 $50-150 $50-200 * Assumes full year forward MTM gains or losses are zero ** Excludes commodity margin volatility 84
Slide 85: First Quarter Accomplishments
Power First Quarter Accomplishments ! Strong cash flow ! Reduction in Georgia EMCs credit obligation ! Steady progress in resolving legacy issues ! Incremental hedges through forward power sales 85
Slide 86: Today
Power Today ! Gas – Market 500 Bbtu/d for E&P – Purchase up to 1 BCF/d for Midstream and Gas Pipeline – Market 1.5 BCF/d of third-party gas ! Power – 7,723 MW portfolio 86
Slide 87: West Region Today
Power West Region Today ! 4,141 MW in Los Angeles Basin ! Significant hedged cash flow through 2010 ! Delicate supply / demand balance ! Developing Locational Marginal Pricing (LMP) and capacity markets should enhance value ! LNG re-gasification projects could reduce fuel prices NV Owned: Owned: Mil
Slide 88: Midcontinent Region Today
Power Midcontinent Region Today ! 541 MW in Michigan – Depressed market expected through 2009 – Midwest Independent System Tolling: Tolling: Kinder Kinder Morgan -- Jackson Morgan Jackson Operator developing ancillary services and capacity markets – Quick-start facility ! 765 MW in Louisiana Tolling
Slide 89: Southeast Region Today
Power Southeast Region Today ! 844 MW in Alabama ! Largely hedged through sales to Georgia EMCs ! Pursuing additional sales ! Working to improve control-area rules Full Full Requirements: Requirements: Tolling: Tolling: Four Four Georgia Georgia EMCs EMCs Tenaska Tenaska 89
Slide 90: Northeast Region Today
Power Northeast Region Today ! 1,432 MW in PJM ! Good supply / demand balance ! Approximately 500 MW on-peak and 150 MW off-peak sold through 2010 ! Active capacity and energy markets Owned: Owned: Hazleton Hazleton Natural Natural gas-fired gas-fired Tolling: Tolling: AES AES Red Red Oak Oak Full F
Slide 91: Challenges and Opportunities
Power Challenges and 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 pr
Slide 92: Risks to Cash Flows 2004 - 2006
Power Risks to Cash Flows 2004 - 2006 Risk Mitigation Default by significant Significant counter-parties counterparties are creditworthy New in-city generation Permitting challenges and construction time Unexpected working Increased corporate L/C capital fluctuations capacity 92
Slide 93: Current Net Credit Exposure from Derivatives
Power Current Net Credit Exposure from Derivatives Dollars in millions 700 Inv. Grade Non-Inv. Grade 600 500 400 300 200 100 0 Utilities Marketers Financial Institutions NOTE: Power has recorded a credit reserve of $53 million and WMB has approximately $440 million in collateral that ‘backstops’ thi
Slide 94: The Road Ahead
Power The Road Ahead 2004 2005 2006 2007 & beyond If no exit, continue to reduce risk, Spark spreads Risk Exit or Optimize generate cash, meet contractual improve commitments Reduction 94
Slide 95: Key Points
Power Key Points ! Expected to generate positive cash flow from operations – Significantly hedged cash flow through 2010 ! Significant natural gas business ! Merchant upside in West and Northeast ! Working to reduce risk through forward power sales ! Operational and environmental obligations contrac
Slide 96: Financial Overview & 3-Year Outlook
Financial Overview & 3-Year Outlook Don Chappel
Slide 97: 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 Ops. $1,000-1,300 $1,300-1,600 $1,400-1,700 Capital Expenditures $725-825 $800-1,000 $900-1,100 700-800 900-1,100 Effective Tax Rat
Slide 98: Drivers
Consolidated Drivers Dollars in millions Segment Profit CFFO Low High Low High 2003 1,346 1,346 770 770 Interest savings - - 360 390 Gains on Asset Sales (337) (337) - - Impairments 220 220 - - Power - 150 - 150 Other (129) 21 (130) (10) 2004 1,100 1,400 1,000 1,300 Interest savings - - 70 200 E&P i
Slide 99: 2004-2006 Capital Exp. By Business
2004-2006 Capital Exp. By Business Dollars in millions 2004 2005 2006 Exploration & Production $325 - 375 $400 - 450 $450 - 500 300 - 350 Midstream 90 - 110 60 - 80 50 - 70 Gas Pipeline 295 - 340 335 - 380 430 - 490 380 - 430 430 - 480 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $725-8
Slide 100: Financial Strategy
Financial Strategy ! Maintain a cash/liquidity cushion of $1.0 billion plus ! Continue to de-lever; striving for investment-grade ratios ! Uses of excess cash – Pay scheduled debt retirements – Early debt reduction – Disciplined EVA® -based investment – Consider dividend and/or share repurchase poli
Slide 101: Cash Sources for Debt Retirement
Cash Sources for Debt Retirement Dollars in billions 2Q04 Thru 2005 Excess Cash @ 3/31/04 1 $0.7 - 1.0 Asset Sales 0.5 – 0.6 Free Cash Flow 2 0.7 – 1.0 New Credit Facilities 3 1.0 $2.9 – 3.6 FELINE PACS Change in Net Debt 1.1 Cash Sources for Debt Retirement $4.0 – 4.7 1 $2.0B at 3/31/04 less $1.0-1
Slide 102: Scheduled Debt Maturities
Consolidated Scheduled Debt Maturities Dollars in millions 2,000 1,500 1100 1,000 1170 1078 1014 1000 500 972 863 850 757 751 442 300 262 247 228 138 100 - 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 04 05 06 07 08 09 10 11 12 13 21 23 27 31 32 33 -2 -2 -2 -2 0 0 0 0 20 22 26 30 Misc. Notes PACS
Slide 103: General Corporate Expenses 2002 - 2006
General Corporate Expenses 2002 - 2006 160 2003 One-Time Benefits Decl 140 ining Expense Savings Cost Struc Implementation Costs ture 120 Recurring 87 35a, b 100 - a, b 13 80 $ Millions 143 - 60 97 90 40 78 72 20 0 (10) (9) a a (19) -20 2002 2003 2004 2005 2006 a) Includes costs / savings associated
Slide 104: Total SG&A Expenses 2002 - 2006
Total SG&A Expenses 2002 - 2006 800 2003 One-Time Benefits Expense Savings 700 Declin Implementation Costs ing Co 600 s t Stru Recurring cture 499 500 - 35 a, b a, b 13 400 - $ Millions 712 300 509 440 424 410 200 100 a a 0 (10) (12) (25) -100 2002 2003 2004 2005 2006 a) Includes costs / savings ass
Slide 105: Cost Reduction Efforts
Cost Reduction Efforts ! Identified potential annual cost savings of $20 million - $30 million by 2006* – One financial system – Process standardization/optimization – Finance, Accounting, HR and IT streamlining ! Considering outsourcing for additional incremental savings of $5 million - $10 million
Slide 106: Enterprise Risk Management
Enterprise Risk Management Dollars in millions Corp./ E&P Midstream Power Other Total Margins & Ad. Assur. $361 $40 $187 - $588 Prepayments - 12 69 - 81 Subtotal $361 $52 $256 $- $669 Letters of Credit 3 22 185 81 291 Total as of 03/31/04 $364 $74 $441 $81 $960 Total as of 12/31/031 $284 $56 $488 $1
Slide 107: Enterprise Risk Management
Enterprise Risk Management Dollars in millions ■ Margin volatility (99% confidence interval) - Incremental liquidity requirement 3/31/04 12/31/03 – 30 days ($185) ($183) – 180 days ($309) ($324) – 360 days ($390) ($349) ■ Incremental Margin requirement from historical price spike 2/27/03 ($139) Assu
Slide 108: Enterprise Risk Management
Enterprise Risk Management Estimated dollars in millions Sensitivities Analysis WMB1 Power 2 Midstream3 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 ($2) $0-5 $6-12 2005 $3 $5-10 $10-15 2006 $12 $5-15 $
Slide 109: EVA Discussion
EVA®® Discussion ! Risk-adjusted capital charge on all capital drives increased capital efficiency ! Capital allocation criteria – Highest incremental EVA® – Strategic fit with assets in Williams’ portfolio ! Changing employee mindset – Include EVA® in the decision process – Focus on reducing capita
Slide 110: MLP Assessment Efforts to Date
MLP Assessment Efforts to Date ! Aggregated high-level views on MLP merits – Suitable for reliable cash flow assets – Could be attractive for acquisitions and growth – Not appropriate for development projects – Expensive source of financing for initial assets ! Identified possible candidates 110
Slide 111: MLP Discussion
MLP Discussion ! Advantages – Eliminates corporate tax on MLP distributions – Increases valuation of existing assets – Monetizes assets while retaining control – Reduces cost of capital for acquisitions ! Disadvantages – Increases administrative and offering costs – Consolidates debt in credit ratin
Slide 112: The Road Ahead
The Road Ahead 2004 2005 2006 2007 & beyond Early debt retirement Continued debt retirement Investment-grade ratios if Solid exit Power Financial New credit facilities Cost reductions Examine dividend level Footing 112
Slide 113: Key Points
Key Points ! Adequate liquidity now and in future ! Clear path to debt reduction ! Increasing free cash flow ! Disciplined capital investments and cost control ! Organization focusing on driving EVA® improvement/growth 113
Slide 114: Summary
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Slide 115: The New Williams
The New Williams ! Highly competitive, strategically located natural gas assets ! Backstretch of multi-year restructuring – Debt reduction – Disciplined growth ! Vision post-restructuring – Sustainable, value-creation for shareholders – Maintain financial strength – Continue increasing role in servi
Slide 116: The Road Ahead
The Road Ahead 2004 2005 2006 2007 & beyond Arkoma production doubles Exploration Piceance major growth vehicle Piceance growth continues & Production Powder River permits and dewatering Powder River grows CORE BUSINESSES Complete deepwater Maintain competitive Capture our share Disciplined Midstrea
Slide 117: Summary
Summary ! Premier natural gas assets ! Competitive advantage and growth opportunities ! Financial discipline ! Value-creating strategy ! Backstretch of restructuring ! Emerging with commercial and financial strength ! First quarter performance on plan 117
Slide 118: Weve ete Ne ei Uiuieanas: Sart arth? Suey eaine ** Oy he We PO
Weve ete Ne ei Uiuieanas: Sart 2 arth? Suey eaine ** Oy he We PO Ey: SNA te 7 Dan Willian. a SERS NE ENE VES VE PE EE PES TESS DUE DU PES
Slide 119: Non-GAAP Reconciliations
Non-GAAP Reconciliations GRETA LIE NT NPE PR TSM PES IPS IB EN PES PEAT
Slide 120: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings (UNAUDITED) 2003 2004 (Dollars in millions, except for per-share amounts) 1st Qtr 4th Qtr 1st Qtr Income (loss) from continuing operations(1) ($39.3) ($84.5) $5.4 Preferred stock dividen
Slide 121: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Reconciliation of Segment Profit to Recurring Segment Profit (UNAUDITED) 2003 2004 (Dollars in millions) 1st Qtr** 4th Qtr 1st Qtr Segment profit (loss): Power * $ (136.4) $ (101.4) $ (32.7) Gas Pipeline 151.2 148.4 148.5 Exploration & Production 113.8 50.1 51.5 Mids
Slide 122: 1Q 2004 EBITDA Reconciliation
1Q 2004 EBITDA Reconciliation Dollars in millions Net Income* $10 Income from Disc. Operations (5) Net Interest Expense 239 DD&A 164 Provision for Income Taxes 15 EBITDA* $423 * Includes gains and impairments on asset sales 122
Slide 123: 1Q 2004 Segment Contributions
1Q 2004 Segment Contributions Dollars in millions Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) $148 $52 $118 ($33) ($9) $276 DD&A 59 43 53 6 4 164 Segment Profit before DDA $207 $95 $171 ($28) ($5) $440 General Corporate Expense (32) Investing Income* 19 Other Income (4) TOTA
Slide 124: 2004 Forecast Segment Contribution
Consolidated 2004 Forecast Segment Contribution Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) 525 - 575 275 - 300 300 - 385 0 - 150 0 – (10) 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 - 480 480 - 575 20 -
The Williams Companies — Q1 2004 Earnings Presentation on 6ix