Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — Q3 2005 Earnings Presentation
93 slides from Williams Companies, Inc. (the)'s earnings presentation, Nov 3, 2005
Slide 1: Williams 2005 3rd Quarter Earnings Release
Williams 2005 3rd Quarter Earnings Release November 3, 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" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines st
Slide 4: 3Q05 Review
3Q05 Review Steve Malcolm Chairman, President & CEO
Slide 5: 3rd Quarter Headlines
3rd Quarter Headlines Recurring earnings after mark-to-market effect climb nearly 150% over year-ago level Exploration & Production growth continues Continued strength in liquids margins drive Midstream results higher Gas Pipeline continues steady performance Mild weather, high gas prices, hurricane
Slide 6: Headlines
Headlines E&P ready to ramp up pace of growth again with arrival of new rigs in Piceance Basin Midstream captures significant deepwater production commitment, prepares to expand capacity in West Gas Pipeline continues to expand system to meet demand of growth markets Power completes deal to resell 1
Slide 7: Effect of Hurricanes
Effect of Hurricanes Overall effect on Williams expected to be minimal Interstate pipelines provided continuous service For Midstream, Katrina and Rita reduced volumes in the Gulf of Mexico area, but boosted margins in its western business Moving incremental volumes - stranded gas - via new intercon
Slide 8: Financial Results and 2005 Outlook
Financial Results and 2005 Outlook Don Chappel CFO
Slide 9: Financial Results
Financial Results Dollars in millions (except per share amounts) 3rd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $5 $16 $249 ($2) Income (Loss) from Disc. Operations (1) 83 (2) 92 Net Income (Loss) $4 $99 $247 $90 Net Income (Loss)/Share $0.01 $0.19 $0.42 $0.17 Recurring Inc
Slide 10: Recurring Income from Continuing Operations
Recurring Income from Cont. Operations A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated Dollars in millions 3rd Qtr YTD
Slide 11: Recurring Income After Mark-to-Market Adjustments
3rd Qtr YTD 2005 2004 2005 2004 Recurring Income from Cont. Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains (losses) and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never b
Slide 12: Net Income Components
Net Income Components A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $
Slide 13: Third Quarter Segment Profit
Third Quarter Segment Profit A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions Exploration & Production $159 $70
Slide 14: 2005 YTD Segment Profit
2005 YTD Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $38 $165 $352 $176 Midstream Gas & Liquids 359 314 359 320 Gas Pipeline 493 429 444 438 Power (187) 121 (162) 121 Other (75) (21) (23) (3) Segment Profit $971 $1,008 $970 $1,052 MTM Adjustments 160 (87) Segment P
Slide 15: Major Changes in Quarter
Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 3Q04 $317 Exploration & Production 67 - Higher production volumes +$14million - Higher net realized price +$82 million - Impact of hedge ineffectiveness -$16 millio
Slide 16: Cash Information
Cash Information Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS 2 Includes international cash ($197), cash to settle legacy matters including tax settlement ($200), AK Quality Bank judgment and other matters. 2
Slide 17: Debt Balance
Debt Balance1 Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/05 7,744 7.5% Scheduled Debt Retirements & Amortization (23) Debt Balance @ 9/30/05 $7,721 7.5% Fixed Rate Debt @ 9/30/05 $7,073 7.7% Variable Rate Debt @ 9/30/05 $648 5.7% Avg. Cost 1 Debt is long-term debt due within 1
Slide 18: Business Unit Results
Business Unit Results Wiliams ——
Slide 19: Exploration & Production
Exploration & Production Ralph Hill Senior Vice President
Slide 20: E&P Segment Profit
Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $159 $70 $381 $165 Nonrecurring: Ownership Issue - - - 11 Gain on sale of assets (22) - (29) - Recurring Segment Profit $137 $70 $352 $176 3Q04 to 3Q05 financial highlights include: Volume increase of 17% Net realized
Slide 21: Strong Domestic Production Growth
Strong Domestic Production Growth Exploration & Production 2004 2005
Slide 22: 3rd Quarter and 2005 Accomplishments
Impressive volume growth continues Full year with no lost time accidents for E&P Big George gross production up to 135 MMcf/d 12 rigs operating in Piceance Valley, 3 rigs in Highlands First H&P rig to be delivered in November Highlands production reaches 13 MMcf/d Additional Piceance Highland opport
Slide 23: Powder River - Big George Coal Area
Powder River - Big George Coal Area Up 67 MMcf/d or 98% over a year ago Up 25 MMcf/d or 23% sequentially Big George production increase continues to offset Wyodak decline Exploration & Production Williams' Big George Production 0 20 40 60 80 100 120 140 160 Jun '04 Sep '04 Dec '04 Mar '05 Jun '05 Se
Slide 24: Piceance Production Growth
Piceance Production Growth Up 84 MMcf/d or 34% over a year ago Up 19 MMcf/d or 6% sequentially Exploration & Production
Slide 25: 3P Reserves
3P Reserves August '05 Announcement: 37.5% increase in probable and possible reserves since year end '04 Extensive study of Piceance Valley yielded additional 1,600 locations and approximately 1.5 Tcf probable and possible reserves Rock quality Land/topography Drilling reach H&P rig capabilities pro
Slide 26: Piceance Highlands - Operations Update
Piceance Highlands - Operations Update Exploration & Production
Slide 27: Piceance Highlands Projects Summary
Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (BCF) (1) 2004 Wells 2005 Wells 2006 Wells Trail Ridge (40-acre density)(2) 20,638 500 500 3 12 20 Ryan Gulch (40-acre density) 15,780 770 700 3 8 15 Allen Point (40-acre density) 6,240 200 140 0 6 9 Red Poin
Slide 28: Piceance Highlands - Year to Date Results
Piceance Highlands - Year to Date Results Exploration & Production Project Area Wells Drilled / Completed Average 30 Day Rate / Completed Well (MMCF/D) Preliminary Reserves Range (BCF/well) Trail Ridge 12 / 9 1.1 1.2 - 1.4 Ryan Gulch(1) 2 / 1 1.4 1.2 - 2.0 Red Point (2) - - 1.2 1.2 - 1.4 Allen Point
Slide 29: Cash Margin Analysis
Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Includes acquisition and development expenditures / proved reserves ('02-'04 average) Cash Margin Analysis Exploration & Production Previous 3-Year Average (2005-07) Cash Margin Cash Costs* Previous $1.81 $0.78 $3.71 $5.52 $0.00 $
Slide 30: E&P 2005-2007 Guidance
Dollars in millions Exploration & Production 2005-2007 Guidance 295 - 335 365 - 415 410 - 485 520 - 595 595 - 720 605 - 680 760 - 860 735 - 885 625 - 700 740 - 840 850 - 950 645 - 750 815 - 930 960 - 1,135 Includes YTD nonrecurring adjustments which increase reported earnings by $29 million $8.70 is
Slide 31: E&P 2006-07 Guidance Reconciliation
Dollars in millions 2006-07 Guidance Reconciliation Exploration & Production
Slide 32: E&P Key Points
Strategy remains rapid development of our premier drilling inventory Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Mainta
Slide 33: Midstream
Midstream Alan Armstrong Senior Vice President
Slide 34: Midstream Segment Profit
Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $121 $105 $359 $314 Nonrecurring: Depreciable Life Adjustment - 6 6 Devils Tower Revenue Recognition1 - 17 - - Recurring Segment Profit $121 $128 $359 $320 Key Business Drivers: Higher Gathering and Processing Fee Reve
Slide 35: 3rd Quarter and 2005 Highlights
3rd Quarter and 2005 Highlights Rapidly responded to Katrina Providing industry solutions: Discovery open seasons Damaged by Rita Cameron Plant still down Max volume at Canada Won Tahiti Gulf of Mexico business Delivering promised expansions: Opal TXP 5 Blind Faith 3rd quarterly increase in west gat
Slide 36: Midstream 2005-07 Guidance
2005 2006 2007 Segment Profit $440-480 $400-500 $410-530 Annual DD&A 180-190 185-195 195-205 Segment Profit + DDA $620-670 $585-695 $605-735 Capital Spending $120-140 $230-250 $180-220 Note: If guidance has changed, previous guidance from 8/4/2005 is shown in italics directly below Midstream 2005-07
Slide 37: 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. - - Margin uplift represents actual realized margin in excess of foreca
Slide 38: Delivering Promised Expansions: Blind Faith
Midstream Delivering Promised Expansions $177 MM to extend Canyon Chief and Mountaineer 37 miles Expected to be ready for service by 3Q 2007 Opportunity for gas processing at Mobile Bay Opportunity for gas transport through Transco and Gulfstream Liquids could be fractionated at Baton Rouge or Parad
Slide 39: Delivering Promised Expansions: Opal TXP V
Midstream Delivering Promised Expansions Opal TXP V Adding capacity: Gas processing ~ 350 MMcf/day Liquids production ~ 17,000 BBls/day Total post-expansion capacity: Gas processing ~ 1.5 Bcf/day Liquids production ~ 68,000 BBls/day In service by 2Q 2007 Serving the Pinedale Anticline Field
Slide 40: Midstream Key Points
Key Points Strong earnings and cash flows despite hurricanes MLP supplements growth strategy Capturing growth opportunities Delivered on "First Tranche" of expansion opportunities Organic growth around our Western assets Footprint expansion in the deepwater Robust opportunities in the pipeline Midst
Slide 41: Gas Pipeline
Gas Pipeline Phil Wright Senior Vice President
Slide 42: Gas Pipeline Segment Profit
Segment Profit $161 $149 $493 $429 Nonrecurring 1999 Fuel Tracker adjustment1 (14) - (14) - Pension expense reduction1 - - (17) - Adjustment to carrying value of certain liabilities1 - - (18) - Write-off hydrostatic testing - - - 9 Recurring Segment Profit $147 $149 $444 $438 3Q04 to 3Q05 financial
Slide 43: 3rd Quarter and 2005 Accomplishments
Northwest's 26" Replacement receives final FERC approval Transco and Gulfstream remained operational and met market demands throughout hurricane season Successful Gulfstream financing Successful in accelerating growth across our pipelines: Gulfstream began new transportation service to Tampa Electri
Slide 44: Gas Pipeline 2005-2007 Guidance
2005 2006 2007 Segment Profit $630 - 6451 $485 - 5302,3 $585 - 655 Annual DD&A 270 - 280 290 - 300 300 - 310 Segment Profit + DDA $900 - 925 $760 - 815 $885 - 965 Capital Spending $390 - 420 $600 - 6803 $300 - 390 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidanc
Slide 45: 2005-2007 Capital Spending Detail
2005-2007 Capital Spending Detail $300 - 390 $600 - 680 $390 - 420 Total 120 - 155 20 - 35 20 - 30 2 276 48 $180 - 235 $305 - 370 $325 - 335 Normal Maintenance/ Compliance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion1 Note: Sum of ranges may not add due to rounding Gas Pipeline 1
Slide 46: Gas Pipeline Key Points
Key Points Strong performance continues; operationally and financially Strong cash flow provider Continued progress Compliance and reliability projects Expansion developments Preparation for rate cases on schedule to be in effect 2007 Gas Pipeline
Slide 47: Power
Power Bill Hobbs Senior Vice President
Slide 48: Power Segment Profit to Cash Flow
Power 1 Includes YTD nonrecurring adjustments which decrease reported Segment Profit by $25 million and reported Segment Profit after MTM Adjustments and CFFO by $37million. Power Segment Profit after MTM Adjustments and Power Segment Standalone CFFO would be $36 million higher on a recurring basis.
Slide 49: Items Impacting 3Q Performance
Dollars in millions Items Impacting 3Q Performance Segment Profit After MTM Adjustments: Q305 Forecast (as of 6/30/05) $54 Estimated impact of mild weather in the West: (30) Cooling Degree Days (CDDs) at Los Angeles (LAX) YTD are 17% below 5 yr avg and 43% below '04 Average September peak load in Ca
Slide 50: Power Cash Flow Analysis
Cash Flow Analysis Power Undiscounted dollars in millions (GAAP Measure) Note: 3Q05 forecast estimated as of 12/30/04. 3Q05 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. Note: Estimated
Slide 51: Power 2005-07 Guidance
2005 2006 2007 Prior Segment Profit Guidance ($50) - 50 ($270) - (120) ($220) - (70) MTM Earnings (3Q05) (141) Est. Forward MTM Impact 50 50 40 Chg due to Mkt Conditions, New deals & Other (108) 0 - (50) Total Impact (199) 50 - 0 40 Change in Segment Profit Guidance (200) 50 - 0 40 Segment Profit Gu
Slide 52: New Power Contracts - 2005 Highlights
New Power Contracts - 2005 Highlights Deals Consummated Around Each Toll All Customer Classes Have Been Represented Utilities Co-ops & Munis Hedge funds & banks Favorable Credit Terms Zero margining provisions in two deals in excess of 4 years Margin Caps in place for approx. 2000 MW of toll resell
Slide 53: 2005 Successes
2005 Successes West 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 490-MW resale of toll from AES 4000 for 2006-08 100-MW heat rate call option for 2008 690-MW capacity sales: from AES 4000 for June-Sept 2005 1,500 MW resale of tolling from AES 4
Slide 54: 2005 Forecast: Recurring Segment Profit
Dollars in millions 2005 Forecast: Recurring Segment Profit After MTM Adjustments Recurring Segment Profit After MTM Adjustments: 2005 Full Year Forecast $(25) - 25 Estimated cash flows from new hedges 50 - 60 Estimated improvement in weather 15 - 55 Reduced plant outages 10 - 10 _______ 2006 Full Y
Slide 55: Power Key Points
Key Points Results for 3rd quarter impacted by Mild weather in west Unplanned outage in east Hurricanes and high natural gas prices CFFO YTD positive Full year recurring segment profit guidance is at break even despite higher NG prices and weak market conditions. Deal flow has increased as previousl
Slide 56: 2005-07 Consolidated Outlook
2005-07 Consolidated Outlook Don Chappel CFO
Slide 57: Consolidated 2005 Forecast Guidance
Segment profit before MTM adjustment $1,375 - $1,525 $1,300 - $1,585 Net Interest Expense (650) - (670) (650) - (670) Other (Primarily General Corp. Costs) (70) - (100) (70) - (100) Pretax Income 655 - 755 580 - 815 Provision for Income Tax (260) - (300) (220) - (335) Income from Continuing Ops 395
Slide 58: 2005-07 Segment Profit
Dollars in millions 2005-07 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total MTM Adjustment Total After MTM Adj. 2005 2006 Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 $650 - 725 400 - 500 4
Slide 59: Consolidated 2005-07 Capital Expenditures
2005 2006 2007 Exploration & Prod. $675 - 725 $950 - 1,050 $950 - 1,050 Midstream 120 - 140 230 - 250 180 - 220 Gas Pipeline 390 - 420 600 - 680 300 - 390 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,200 - 1,350 $1,825 - 2,050 $1,425 - 1,625 Dollars in millions Notes: - - Sum of rang
Slide 60: 2005-07 Outlook
1 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below Dollars in millions 2005-07 Outlook Consolidated Segment Profit Reported
Slide 61: Strong Operating Cash Flow Growth & Increasing Investment Opportunities
Strong Operating Cash Flow Growth & Increasing Investment Opportunities . . . 2003 2004 2005 2006 2007 Cap Ex-Low 790 1200 1825 1425 Cap Ex-High 790 1350 2050 1625 CFFO-Low 588 1482 1325 1625 1850 CFFO-High 588 1473 1525 1925 2150 Debt to Cap 0.75 0.623 0.58 0.56 0.54 0.75 0.623 0.59 0.58 0.56 Cash
Slide 62: Segment Profit Guidance Trend
Segment Profit Guidance Trend 2004 2005 2006 2007 2008 SPAM Low 1263 1550 1520 1830 2050 SPAM High 1263 1700 1820 2255 2600 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1175 1825 1450 Cap Ex-High 790 1350 2050 1650 $ Millions $1,550 to $1,700 $1,520 to $1,820 $1,830 to $2,25
Slide 63: 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 Opportunity rich Increasing focus and disciplined EVA(r)-ba
Slide 64: Summary
Summary Steve Malcolm Chairman, President & CEO
Slide 65: Summary Key Points
Key Points Current growth activity continues to move key performance measures up Investing in future growth First planned sale to Williams Partners to deliver growth capital while retaining asset control Scope, scale of growth opportunities continues to expand Raising earnings, cash guidance; expect
Slide 66: Q&A
Q&A Wiliams ——
Slide 67: Non-GAAP Reconciliations
Non-GAAP Reconciliations Wiliams ——
Slide 68: 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 69: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 70: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 71: EBITDA Reconciliation 3Q05
EBITDA Reconciliation 190 DD&A (3) Provision (benefit) for Income Taxes 164 Net Interest Expense $4 Net Income $356 EBITDA 1 Loss from Disc. Operations Non-GAAP Reconciliation 3Q05 Dollars in millions YTD $247 2 491 546 169 $1,455
Slide 72: 3Q 2005 Segment Contribution
* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 3Q 2005 Segment Contribution Non-GAAP Reconciliation
Slide 73: 2005 Forecast EBITDA Reconciliation
Net Income $385 - 455 $350 - 480 Income from Disc. Ops. 10 - 0 10 - 0 Net Interest 650 - 670 650 - 670 DD&A 700 - 775 700 - 775 Provision for Income Taxes 260 - 300 220 - 335 Other/Rounding (5) - 0 (5) EBITDA $2,000 - 2,200 $1,930 - 2,260 MTM Adjustments 175 75 EBITDA - after MTM Adj. $2,175 - 2,375
Slide 74: 2005 Forecast Segment Contribution
Power 1 (225) - (175) 10 - 20 (215) - (155) Gas Pipeline 630 - 645 270 - 280 900 - 925 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P 575 - 600 235 - 265 810 - 865 Midstream 440 - 480 180 - 190 620 - 670 Total *
Slide 75: 2005 Segment Profit - Recurring
Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. Reported Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 YTD Non-Recurring ($29) - - (49) 25 53 $0 - - $0 Recurring
Slide 76: 2005 Forecast Guidance Reconciliation
Net Income $385 - 455 $350 - 480 Less: Discontinued Operations 10 - 0 10 - 0 Income from Continuing Ops $395 - 455 $360 - 480 Non-Recurring Items (Pretax) 7 23 Less / (Plus) Taxes @ Approx. 39% 0 (6) Non-Recurring After Tax 7 17 Recurring Income from Cont. Ops $402 - 462 $377 - 497 Recurring EPS $0.
Slide 77: 2005-07 Guidance Reconciliation
Dollars in millions 2005-07 Guidance Reconciliation Consolidated CAP EX: Aug. 4 Guidance E&P: Incremental Drilling & costs Midstream: Expansion (Opal & Blind Faith) Gas Pipes: Expansions Other Misc / Rounding Nov. 3 Guidance 2005 $1,100 - 1,300 60 - - - - 40 - (10) $1,200 - 1,350 2006 $1,525 - 1,750
Slide 78: 2005 Guidance Reconciliation: Cash Flow from Operations
Dollars in millions 2005- 07 Guidance Reconciliation Consolidated CASH FLOW FROM OPERATIONS (CFFO): Aug. 4 Guidance E&P Seg Profit / DD&A Increases Midstream Segment Profit Increase Gas Pipes Segment Profit Changes Power Change in CFFO Guidance Other Increases / (Decreases) Nov. 3 Guidance 2005 $1,1
Slide 79: Appendix
A p p end ix G
Slide 80: EPS Metrics
Consolidated EPS $0.34 $0.07 $0.01 - $0.42 Recurring EPS 0.33 0.11 ($0.01) - 0.44 Rec. EPS after MTM Adj. 0.22 0.16 0.22 - 0.60 Average Shares (MM) 599 579 581 - 605 2005 1Q 2Q 3Q 4Q Total 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.
Slide 81: 2005 Interest Expense Guidance
Interest on Long-Term Debt $575 - 583 Amortization Discount/Premium and other Debt Expense 25 - 27 Credit Facilities: (incl. Commitment Fees plus LC Usage) 32 - 40 Interest on other Liabilities 23 - 30 Interest Expense $655 - 680 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $6
Slide 82: 2005 Effective Tax Rates
2005 Effective Tax Rates Consolidated
Slide 83: E&P 2005-2007 Hedge Update
Dollars in millions Exploration & Production 2005-2007 Hedge Update 1 Please note basin locations not NYMEX 2005 2006 2007 Fixed Price: 4th Qtr NYMEX Volume (MMcfe/d) 283 299 172 Price ($/Mcfe) $4.49 $4.39 $4.18 Collars : NYMEX Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 $6.62 - $8.42 $6.
Slide 84: 3Q 2005 Net Realized Price Calculation
3Q 2005 Net Realized Price Calculation Exploration & Production
Slide 85: 2005 4th Quarter Price Modeling
2005 4th Quarter Price Modeling Unhedged Price (NYMEX) $8.70 $8.50 $7.00 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 2005 Unhedged Hedge Market Price: NYMEX $13.00 - $13.60 $4.49 Bas
Slide 86: Midstream Margins Above Average
Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-2004. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production
Slide 87: Fee-Based Bedrock of Earnings
Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 733 763 846 Commodity 301 255 215 212 Note: Total revenues less cost of goods sold. Reflects forecasted margins in 2006-2007 at mid- point of range. Midstream 30% 70% 26% 22% 20% 74% 78% 80%
Slide 88: Midstream 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. - - Margin uplift represents actual realized margin in excess of foreca
Slide 89: Gas Pipeline Strong Free Cash Flow
Gas Pipeline Dollars in millions Strong Free Cash Flow 2003 2004 2005 2006 2007 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion Maintenance Mandatory Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 200
Slide 90: WMB Collateral Outstanding
Corp./ E&P Midstream Power Other Total Dollars in millions As of 9/30/05 *Note: The allocation of LC's between business units as of 3/31 has been adjusted from that previously reported. Total 3/31/05 LC's reported is unchanged. 1Reflects net amount of margins out less margins in. WMB Collateral Outs
Slide 91: WMB Collateral Sensitivity
Dollars in millions WMB Collateral Sensitivity Margin volatility (1% chance of exceeding) - - Potential incremental collateral requirement 9/30/05 6/30/05 3/31/05 30 days ($469) ($178) ($124) 180 days ($868) ($458) ($328) 360 days ($926) ($351) ($341) Increased margin volatility results from high na
Slide 92: 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 93: Types of Sales Around Tolling Deals
Types of Sales Around Tolling Deals - -Generally, from the most to least effective hedges Type of Sale Resale of tolling Heat-rate Sales Full requirements Capacity sales Forward fixed price sales How It Works Williams buys tolling rights for a certain dollar amount per kilowatt-year and: Sells the s