Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — Q4 2004 Earnings Presentation
101 slides from Williams Companies, Inc. (the)'s earnings presentation, Feb 23, 2005
Slide 1: Williams 2004 4th Quarter Earnings Release
Williams 2004 4th Quarter Earnings Release February 23, 2005
Slide 2: 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" within the meaning of the Private Securities Litigation Reform Act of 1995. You t
Slide 3: Oil & Gas Reserves Disclaimer
Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable and possible" reserves that the SEC's guidelines strictly prohibit us from including in filings with the
Slide 4: Overview
Overview Steve Malcolm, Chairman, President & CEO
Slide 5: What You'll Hear
What You'll Hear Williams delivers strong 4Q performance Midstream sees record quarter due to continued strong margins and record volumes Exploration & Production production volume growth continues Gas Pipeline enjoys best quarter in last two years Power continues positive cash flows Strong consolid
Slide 6: What You'll Hear: Restructuring and Litigation
What You'll Hear Restructuring complete Debt now at $7.8B Debt to capitalization ratio of 61.6% Cash of $1.3B at February 19 Status of litigation and investigations Significant matters resolved in 2004 California utilities' refund claims against Williams Gulf Liquids' insurance arbitration award Sig
Slide 7: What You'll Hear: Segment Performance
What You'll Hear E&P growing Production up 25% for the year 248% reserves replacement rate with >99% success rate Total proved reserves 3.2 Tcfe Midstream phenomenal Record earnings and NGL production levels Deepwater projects performing well Strong free cash flow* Gas Pipeline consistent Steady per
Slide 8: What You'll Hear: 2007 Base Case
What You'll Hear Providing 2007 base case by business unit Opportunities included in our numbers 12 rigs in Piceance; total production growth at 10-15% per year Increasing utilization of existing deepwater projects Rate cases improve segment profit in 2007 Selling megawatts primarily through mid-ter
Slide 9: The Road Ahead
Midstream Enhance competitive position- consider MLP Capture our share of new deepwater production 2005 2006 2007 2008 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES Complete announced expansion projects Northwest capacity replacement Rate cases Expansions / LNG oppor
Slide 10: 2004 Financial Results
2004 Financial Results Don Chappel, CFO
Slide 11: Financial Results
4th Quarter Year 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* $95 ($73) $93 ($57) Income (Loss) from Disc. Ops.* (22) 20 71 327 Effect of Accounting Change - - - (761) Net Income/(Loss)* $73 ($54) $164 ($492) Net Income/(Loss) Share* $0.13 ($0.10) $0.31 ($1.01) Rcr. Inc./(Loss) from Cont.
Slide 12: Recurring Income from Continuing Operations
2004 2003 2004 2003 Income/(Loss) from Cont. Ops. $95 ($73) $93 ($57) Gains on Sale of Assets (10) (16) (10) (337) Impairments/Losses/Write-offs 31 106 70 357 Income (Expense) Related to Prior Periods 4 (9) 15 (117) Debt Retirement Expenses 30 67 282 67 Insurance Arbitration Award (103) - (103) - Ot
Slide 13: Recurring Income After Mark-to-Market Adjustments
Recurring Income from Cont. Ops After Mark-to-Market Adjustments Consolidated Dollars in millions, except for per-share amounts 4th Quarter Year 2004 2003 2004 2003 Recurring income/(loss) from cont. ops avail. to common shldrs 68 $ 58 $ 261 $ (16) $ Recurring diluted earnings/(loss) per common shar
Slide 14: Net Income Components
2004 2003 2004 2003 Segment Profit* $398 $153 $1,406 $1,239 Net Interest Expense (170) (240) (828) (1,248) Debt Retirement Expense (30) (67) (282) (67) Other Income/(Expense) - Net (14) (15) (72) 13 Income/(Loss) from Cont. Ops. Before Tax* 184 (169) 224 (63) Provision/(Benefit) for Income Tax 89 (9
Slide 15: Fourth Quarter Segment Profit
Fourth Quarter Segment Profit Reported Recurring 4Q04 4Q03 4Q04 4Q03 Exploration & Production $71 $50 $75 $50 Midstream Gas & Liquids(1) 236 64 151 64 Gas Pipeline 157 148 157 148 Power (44) (101) (44) 12 Other (22) (8) (10) (7) Segment Profit(2) $398 $153 $329 $267 MTM Adjustments (29) (60) Seg. Pr
Slide 16: 2004 Segment Profit
2004 Segment Profit Reported Recurring 2004 2003 2004 2003 Exploration & Production(1) $236 $401 $251 $310 Midstream Gas & Liquids(2) 550 197 471 283 Gas Pipeline 586 555 595 582 Power(3) 77 135 77 (21) Other (43) (51) (13) (10) Segment Profit(4) $1,406 $1,239 $1,381 $1,144 MTM Adjustments (118) (25
Slide 17: Major Changes in Quarter
Recurring Segment Profit after MTM Adj. 4Q2003 $207 Exploration & Production 25 - Higher production volumes +$20 million - Higher net realized price +$2 million - Favorable international & transport +$4 million Midstream 87 - Higher NGL margins +$58 million - Improved olefins results +$26 million Ga
Slide 18: Major Changes in Year
Major Changes in Year Recurring Segment Profit After Mark-to-Market Adjustments Recurring Segment Profit after MTM Adj. 2003 $891 Exploration & Production (59) - Higher production volumes +$14 million - Lower net realized price -$26 million - Higher operating costs -$22 million - 2003 mark-to-market
Slide 19: Cash Information
4Q04 Year Beginning Unrestricted Cash * $976 $2,318 Cash Flow from Continuing Operations 404 1,473 Cash Flow from Discontinued Operations (3) 16 Asset Sales 40 1,053 Restricted Investments (LC Collateral) - 380 Debt Issuance (Transco) 75 75 Debt Retirements (230) (3,267) Capital Expenditures/Investm
Slide 20: Debt Balance
Debt Balance Debt Balance @ 12/31/03 * $11,978 7.7% Scheduled Debt Retirements & Amortization (831) Tendered Debt Retirements (2,991) Open Market Purchases (269) Debt Issuance (Transco) 75 Debt Balance @ 12/31/04 $7,962 7.4% Less: Scheduled January Retirements (200) Debt Balance @ 1/31/05 $7,762 Fix
Slide 21: 2004 vs. Guidance
Segment profit $1,406 $1,175 - $1,375 Net Interest Expense (828) (810) - (860) Early Debt Retirement Costs (282) (300) - (250) Other (Primarily General Corp. Costs) (72) (90) - (125) Pretax Income (Loss) $224 ($25) - $140 Provision (Benefit) for Income Tax (131) 0 - (80) Income / (Loss) from Continu
Slide 22: EPS Metrics
EPS Metrics Consolidated EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS ($1.59) $0.47 $0.20 ($0.10) ($1.01) Recurring EPS (0.10) (0.03) - 0.11 (0.03) Rec. E
Slide 23: Business Unit Results
Business Unit Results <>
Slide 24: Exploration & Production
Exploration & Production Ralph Hill, Senior Vice President
Slide 25: E&P Segment Profit
4th Quarter Year 2004 2003 2004 2003 Segment Profit Dollars in millions Segment Profit $71 $50 $236 $401 Non recurring: Ownership issue 4 - 15 - Gain on sale of assets - - - (91) Recurring Segment Profit $75 $50 $251 $310 Exploration & Production 4Q03 to 4Q04 increase includes Volume increase of 25%
Slide 26: Strong 2004 Reserves Performance
Strong 2004 Reserves Performance Exploration & Production Domestic proved reserves up 10.5% to 3.0 Tcfe Total proved reserves 3.2 Tcfe 248% reserves replacement 99% success rate Moved 451 Bcfe to proven Transfers of Probable to Proved (Bcf) 2002 2003 2004 Total Total for retained basins 313 408 451
Slide 27: 2004 Accomplishments
2004 Accomplishments 4Q 2004 production up 25% or 121 MMcfed since 4Q'03 Strong reserves performance $0.92 2004 F&D cost, much better than industry average Record capital program successfully executed Additional Piceance downspacing approved Drilling initiated in new Piceance areas of Trail Ridge an
Slide 28: Domestic Proved Reserves Reconciliation
Exploration & Production Domestic Proved Reserves Reconciliation - -390 - -186 +408 +23 - -191 +451 Prod. +37 Prod. Acqu. Sold YE 2002 Adds/ Rev. Acqu. Adds/ Rev. YE 2003 YE 2004
Slide 29: 2004 Year End Proved Reserves
Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 3660 2063 960 236 Proved, Probable & Possible Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 1830 304 671 181 Total: 3.0 Tcf Proved* * 99% of proved reserves were audited or prepared by Netherland, Sewell & A
Slide 30: Domestic Production Growth
Domestic Production Growth Q1 '02 Q2 '02 Q3 '02 Q4 '02 Q1 '03 Q2 '03 Q3 '03 Q4 '03 Q1 '04 Q2 '04 Q3 '04 Q4 '04 Retained Properties 426 427 492 473 470 475 459 442 457 511 535 566 Sold Properties 121 134 35 31 34 27 2 5 Exploration & Production
Slide 31: Growth Metrics
Growth Metrics Exploration & Production Note:Assumes mid-point of guidance range
Slide 32: U.S. Natural Gas Production
U.S. Natural Gas Production Exploration & Production Source: www.evaluateenergy.com and company press releases * Completed major acquisitions in 2004 Company 4Q 2003 4Q 2004 % Change BP 2,933 2,651 - -10% ExxonMobil 2,038 1,810 - -11% ChevronTexaco 2,110 1,618 - -23% ConocoPhillips 1,469 1,377 - -6%
Slide 33: Finding & Development Cost Comparison
Finding & Development Cost Comparison Williams' 2004 F&D cost was $0.92 per mcfe. The 3-yr Avg ('02-'04) was $0.78 Industry rolling average F&D cost through 2003 was $1.42 per mcfe Expect industry average to increase due to higher 2004 drilling cost and acquisition activity Exploration & Production
Slide 34: E&P 2005-2007 Guidance
2005 2006 2007 Segment profit $400 - 475 $450 - 525 $500 - 625 Annual DD&A $220 - 250 $250 - 290 $300 - 350 Segment Profit + DD&A $620 - 725 $700 - 815 $800 - 975 Capital spending $500 - 575 $525 - 625 $525 - 675 Production (MMcfe/d) 600 - 700 700 - 800 775 - 875 Hedged Volume (MMcfe/d) 286 298 172
Slide 35: Key Points
Key Points Exploration & Production Strong 2004 reserves performance Significant volume growth from existing positions Continuing to expand development drilling activity - Piceance is primary growth driver Decreased hedging increases upside Long history of high drilling success, low finding costs Sh
Slide 36: Midstream
Midstream Alan Armstrong, Senior Vice President
Slide 37: Midstream Segment Profit
4th Quarter Year 2004 2003 2004 2003 Segment Profit $236 $64 $550 $197 Non recurring: Depreciable Life Adjustment 1 - 7 4 Impairments 17 16 17 109 Insurance Arbitration Award (94) - (94) - Gain on Asset Sales (9) (16) (9) (27) Recurring Segment Profit $151 $64 $471 $283 Dollars in millions 2004 vs.
Slide 38: 4th Quarter and 2004 Accomplishments
4th Quarter and 2004 Accomplishments Record recurring earnings Record domestic NGL production: 2004 record year 4Q record quarter December record month Record number of well connects in 2004 (> 500) Devil's Tower start-up (twice) Opal TXP-IV Expansion Asset sales Gulf Liquids insurance arbitration a
Slide 39: Midstream Margins Above Average
Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Margin 5.21 7.7 11.75 12.75 17.16 7.99 6.18 11.01 10.08 8.84 17.64 22.6 Volume (MM Gallons) 292 296 333 271 300 199 228 298 327 328 373 400.5 Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual e
Slide 40: Fee-Based Bedrock of Earnings
Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 755.6 799 823 Commodity 301 201 207.7 210 Note: Total revenues less cost of goods sold. Reflects 5 year average (Jan '00 - Dec '04) margins in 2006- 2007 at mid-point of range. Midstream 30% 70% 21% 21% 20% 79% 79% 80%
Slide 41: Deepwater Success - What to Watch For
Deepwater Success-What to Watch For Midstream Gunnison Devils Tower
Slide 42: Midstream 2005-2007 Guidance
2005 2006 2007 Segment Profit $350-430 $400-500 $400-520 Annual DD&A $180-190 $185-195 $190-200 Segment Profit + DDA $530-620 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: - - Guidance does not include any major deepwater projects - - If guidance has changed, previous guidance
Slide 43: Strong Free Cash Flow
Strong Free Cash Flow Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - 2004 margin uplift represents actual realized
Slide 44: Key Points
Key Points Business generated record segment profit in 2004 Operational high marks set Continued strong free cash flows Deepwater cash flows: Continued strength Upside driven by drill-ship availability One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream
Slide 45: Gas Pipeline
Gas Pipeline Phil Wright, Senior Vice President
Slide 46: Gas Pipeline Segment Profit
4Q04 vs. 4Q03 increase includes $7 million due to lower G&A expenses $3 million due to increased Gulfstream earnings 2004 vs. 2003 increase includes $37 million due to full year of Transco and Northwest expansion projects $14 million due to higher interruptible transportation revenue ($18) million d
Slide 47: Fourth Quarter Accomplishments
Fourth Quarter Accomplishments Everett Delta in-service Nov. 10, 2004 26-inch Replacement project filed with FERC Northwest receives Environmental Excellence Award associated with the Evergreen Project Transco set peak day delivery record in December 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2003 209.1 202
Slide 48: Major Project Update
Major Project Update Northwest Pipeline Replacement Filed Certificate Application on November 29, 2004 Capital ^ $333 million In-service date, November 2006 Central New Jersey FERC Certificate issued February 10, 2005 Capital ^ $13 million In-service date, November 2005 Leidy to Long Island Pre-fili
Slide 49: Gulfstream Update
Gulfstream Update Phase II placed in-service February 1st 2005 Project specifics 109-mile, 30" extension to serve Florida Power & Light's Martin plant 350 Mdth/d, long-term commitment by FPL Cost ^ $225 million Capacity under long-term contract Today: 305 Mdth/d (28% of capacity) Mid-2005: 705 Mdth/
Slide 50: Future Rate Cases
Future Rate Cases Northwest Next anticipated rate case effective 1Q07 26" capacity replacement primary driver Last rate case effective March 1997 No requirement to file Transco Next rate case effective 1Q07 Last rate case effective September 2001 Required to file Gas Pipeline
Slide 51: Accommodating Imported LNG
Accommodating Imported LNG Expansions on existing LNG Facilities WGP advantages Serves markets that are large, diverse, and growing Proximity to anticipated Gulf Coast LNG Delivery flexibility Low rates Challenges Maintaining gas quality Maintaining flexibility Gas Pipeline
Slide 52: Proposed and Existing LNG Importation Facilities
Proposed and Existing LNG Importation Facilities Gas Pipeline
Slide 53: Gas Pipeline 2005-2007 Guidance
2005 2006 2007 Segment profit $545 - 5851 $515 - 5651,2 $575 - 6351,2 Annual DD&A 280 - 290 290 - 300 300 - 310 Segment profit + DDA 725 - 875 805 - 865 875 - 945 Capital spending 370 - 420 475 - 550 250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance fr
Slide 54: 2005-2007 Capital Spending Detail
2005-2007 Capital Spending Detail $250 - 325 $475 - 550 $370 - 420 Total 70 - 90 10 - 20 20 - 30 2 276 48 $95 - 130 $95 - 130 $145 - 165 Normal Maintenance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion Note: Major regulatory compliance includes Pipeline Safety and Clean Air Act ex
Slide 55: Key Points
Key Points Record segment profit in 2004 Rate case preparation in full swing Achieving substantial progress in compliance and reliability investments Transco expansions continue Focused on maintaining low-cost provider status Strong free cash flow generator Stable, low-risk earnings Gas Pipeline
Slide 56: Power
Power Bill Hobbs, Senior Vice President
Slide 57: Power Segment Profit
Gross Margin ($16) $40 $185 $238 SG&A & Other (24) (17) (79) (129) Op. Exp. & Other Inc / (Exp) (4) (124) (29) 26 Segment Profit ($44) ($101) $77 $135 Includes: Asset Impairments - 89 - 103 CA Refund & Other Accrual Adj. - 33 - 33 Prior period correction* - (9) - (117) Regulatory Settlement - - - 20
Slide 58: 2004 & Recent Accomplishments
2004 & Recent Accomplishments Success in signing risk-reducing contracts Contracted re-sale of tolls of 550 MW with 1-3 year terms Sale of capacity of 650 MW in 2005 Realized significant free cash flow Reduced risk of portfolio Adopted hedge accounting, reducing earnings volatility Retained top tale
Slide 59: Power Segment Profit after MTM Adjustment
Dollars in millions Power Segment Profit after MTM Adjustment 1Schedule of expected realization of MTM gains/losses previously recognized from designated Hedges is included in the Appendix. Combined Power Portfolio Estimated as of 12/31/04 4Q04 A 4Q04 F 2004 A 2005 F 2006 F 2007 F Net Revenues 68 41
Slide 60: Segment Profit to Cash Flow
Segment Profit to Cash Flow Dollars in millions Power *Includes liquidation of Interest Rate and Crude & Refined Products portfolios. 4th Quarter 2004
Slide 61: Cash Flow Variance Analysis
Cash Flow Variance Analysis Undiscounted dollars in millions Note: Q4 2004 forecast estimated as of 9/30/04. Q4 2004 Actual cash flows agree in total with Power's Cash Flow Statement; however the allocation of actual cash flows to the various deal types is based on estimates. Power
Slide 62: Power 2005-2007 Guidance
2005-2007 Guidance Power Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below 2005 2006 2007 Segment Profit/(Loss) ($250) - (150) ($200) - (50) ($100) - 50 MTM Adjustments 300 250 150 Segment Profit after MTM Adj. 50 - 150 50 - 200 50 - 200 Cash Flow from
Slide 63: Key Points
Key Points CFFO expected to remain positive Refocused efforts to offer risk management to customers -- deals getting done Continuing to see improvements in Market liquidity Spark spreads Williams credit Focus remains on reducing risk through longer-term sales Factors impacting guidance Spark spread
Slide 64: 2005-2007 Consolidated Outlook
2005-2007 Consolidated Outlook Don Chappel, CFO
Slide 65: 2005 Segment Profit Guidance
Exploration & Production 400 - 475 Midstream 350 - 430 Gas Pipeline 545 - 585 Other/Rounding 5 - 10 $1,300 - 1,500 Power (250) - (150) Seg. Profit before MTM Adj. $1,050 - 1,350 MTM Adjustments 300 Seg. Profit after MTM Adjust. $1,350 - 1,650 Dollars in millions 2005 2005 Segment Profit Guidance Con
Slide 66: 2005 Interest Expense Guidance
Interest on Long-Term Debt $555 - 575 Amortization Discount/Premium and other Debt Expense 25 Credit Facilities: (incl. Commitment Fees plus LC Usage) 30 - 40 Interest on other Liabilities 20 - 30 Interest Expense $630 - 670 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $625 -
Slide 67: 2005 Forecast Guidance
Segment profit before MTM adjustment $1,050 - $1,350 Net Interest Expense (625) - (660) Other (Primarily General Corp. Costs) (90) - (125) Pretax Income 335 - 565 Provision for Income Tax (155) - (245) Income from Continuing Ops 180 - 320 Income/(Loss) from Discontinued Ops (5) - 5 Net Income $175 -
Slide 68: 2005-2007 Segment Profit
Dollars in millions 2005-2007 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. 2005 2006 2007 Consolidated $400 - 475 350 - 430 545 - 585 (250) - (150) 5 - 10 $1,050 - 1,350 300 $1,350 - 1,650 $450 - 525 400 - 500 515 - 565 (2
Slide 69: 2005-2007 Outlook
Segment Profit Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Free Cash Flow (1) Effective Tax Rate (2) Cash Tax Rate 2007 2005 (1) Free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal paym
Slide 70: Drivers
Drivers Consolidated Dollars in millions
Slide 71: 2005-2007 Capital Expenditures
2005 2006 2007 Exploration & Prod. $500 - 575 $525 - 625 $525 - 675 Midstream 120 - 140 110 - 130 100 - 130 Gas Pipeline 370 - 420 475 - 550 250 - 325 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,000 - 1,200 $1,150 - 1,350 $900 - 1,100 Dollars in millions Notes: - - Sum of ranges for
Slide 72: 2005-2007 Maintenance vs. Growth Capital
Dollars in millions 2005-2007 Maintenance vs. Growth Capital Note: - - Sum of ranges for each business line does not necessarily match total range Explor. & Prod. Growth Maintenance Total Midstream Growth Maintenance Total Gas Pipeline Growth Maintenance Total Power Other/Corp - Maint. Total: Growth
Slide 73: 2004-2005 Return on Capital Employed
2004 - 2005 Return on Capital Employed Consolidated Dollars in millions
Slide 74: Steady Improvement
Steady Improvement . . . 2003 2004 2005 2006 2007 CFFO-Low 588 1482 1300 1450 1600 CFFO-High 588 1473 1600 1750 1900 Debt to Cap 0.745 0.623 0.591 0.57 0.54 0.623 0.601 0.59 0.56 Cash Flow 1 Debt / Cap 2 75% Increasing Cash Flow 588 $1,473 $1,300 to $1,600 $1,450 to $1,750 $ Millions 1 Cash Flow fro
Slide 75: Guidance Trends
Guidance Trends 2004 2005 2006 2007 SP Old-Low 1262 1325 1450 1525 SP Old-High 1262 1625 1750 1950 SP New-Low 1348 1050 1200 1375 SP New-H 1348 1350 1500 1800 Cap Ex-Low 790 1000 1150 900 Cap Ex-High 790 1200 1350 1100 $1,000 to $1,200 $1,150 to $1,350 $900 to $1,100 $ Millions $790 $1,375 to $1,800
Slide 76: Financial Strategy/Key Points
Drive/enable sustainable growth in EVA(r)/shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Increase focus and disciplined EVA(r) -based investments in
Slide 77: Summary
Summary Steve Malcolm <>
Slide 78: Key Points
Restructuring complete, seeking growth with discipline Opportunities are identified Some already in our guidance Need to bring others across the goal line Will be executing our game plan Measure our success in the upcoming months through updates on our progress Key Points
Slide 79: Q&A
Q&A
Slide 80: Non-GAAP Reconciliations
Non-GAAP Reconciliations <>
Slide 81: Non-GAAP Disclaimer
Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, free cash flow and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss
Slide 82: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 83: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 84: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 85: EBITDA Reconciliation
EBITDA Reconciliation 173 DD&A 88 Provision for Income Taxes 170 Net Interest Expense Dollars in millions $73 Net Income* $526 EBITDA* 22 Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments Non-GAAP Reconciliation 669 131 828 $164 $1,721 (71) 4Q0
Slide 86: 4Q 2004 Segment Contribution
* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $398 DD&A 173 Segment Profit before DDA $571 General Corporate Expense (35) Investing Income* 22 Other Income (33) TOTAL $526 Gas Pipeline $157 67 $224 Corp/Othe
Slide 87: 2004 Segment Contribution
* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Corp/Other Total Segment Profit (Loss) ($42) $1,406 DD&A 15 669 Segment Profit before DDA ($27) $2,075 General Corporate Expense (120) Investing Income* 34 Other Income (269) TOTAL $1,721 G
Slide 88: 2005 Forecast EBITDA Reconciliation
Net Income Net Income $175 - 325 $175 - 325 Income from Disc. Operations Income from Disc. Operations 5 - (5) 5 - (5) Net Interest Net Interest 625 - 660 625 - 660 DD&A DD&A 700 - 775 700 - 775 Prov. (Benefit) for Income Taxes Prov. (Benefit) for Income Taxes 155 - 245 155 - 245 Other/Rounding Other
Slide 89: 2005 Forecast Segment Contribution
Power (250)-(150) 10 - 20 (240)-(130) Gas Pipeline 545 - 585 280 - 290 825 - 875 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL RECURRING E&P 400 - 475 220 - 250 620 - 725 Midstream 350 - 430 180 - 190 530 - 620 Total 1,050 -
Slide 90: 2005 Forecast Guidance Reconciliation
Net Income $175 - 325 Less: Discontinued Operations 5 - (5) Income from Continuing Ops $180 - $320 Recurring Income from Cont. Ops $180 - $320 Recurring EPS $0.31 - $0.56 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Income from Cont. Ops after MTM Adj. Income
Slide 91: Appendix
Appendix <>
Slide 92: 2004 Effective Tax Rates
2004 Effective Tax Rates Combined Continuing Ops. Disc. Ops. Fourth Quarter 2004 Federal $64 35% $64 35% $0 0% State 17 9% 16 9% 1 500% Foreign 19 10% (2) (1%) 21 10500% Other 10 5% 10 5% 0 0% Tax Provision $110 46% $88 48% 22 11000% Total Year 2004 Federal $107 35% $79 35% $28 35% State 32 11% 28 1
Slide 93: 4Q 2004 Net Realized Price Calculation
4Q 2004 Net Realized Price Calculation Exploration & Production
Slide 94: 2005 Price Modeling
2005 Price Modeling Unhedged Price (NYMEX) $6.34 $5.96 $5.75 2005 2006 2007 Note: Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes Exploration & Production
Slide 95: Enterprise Risk Management
Enterprise Risk Management Margins & Ad. Assur. $50 $10 $74 - $134 $527 Prepayments 1 - 2 38 - 40 81 Subtotal $50 $12 $112 $ - $174 $608 Letters of Credit 399 123 238 95 894 378 Total as of 12/30/04 $449 $135 $350 $95 $1,068 $986 Total as of 9/30/04 $448 $191 $369 $114 $1,122 Change $1 ($56) ($19) (
Slide 96: Enterprise Risk Management: Margin Volatility
Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 12/30/04 9/30/04 30 days ($106) ($118) 180 days ($268) ($234) 360 days ($353) ($336) Assumption: The margin numbers above consist of only the forward marginable position values, starting from
Slide 97: Enterprise Risk Management Sensitivities Analysis
Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units combined. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not includ
Slide 98: Power Estimated Total Cash Flows
Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Power Estimated Total Cash Flows Undiscounted dollars in millions
Slide 99: West - Estimated Total Cash Flows
West - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenue
Slide 100: Central - Estimated Total Cash Flows
Central - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Reve
Slide 101: East - Estimated Total Cash Flows
East - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenue