Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — Q4 2006 Earnings Presentation
110 slides from Williams Companies, Inc. (the)'s earnings presentation, Feb 22, 2007
Slide 1: Williams 2006 4th Quarter Earnings
Williams 2006 4th Quarter Earnings February 22, 2007
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" within the meaning of the Private Securities Litigatio
Slide 3: Forward Looking Statements (cont.)
Forward Looking Statements (cont.) Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; We could be held lia
Slide 4: Oil and Gas Reserves Disclaimer
Oil and 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
Slide 5: 2006 Review
2006 Review Steve Malcolm Chairman, President & CEO
Slide 6: Headlines
Headlines Key earnings measure* jumps 38% for year Record-high margins fuel extraordinary Midstream performance Development activity boosts natural gas production and reserves Production from U.S. assets rises 23% Reserves replaced at rate of 216% $1.6 billion midstream asset dropped down to William
Slide 7: Prime assets deliver growth
E&P - our primary growth: long-lived natural gas assets; development costs among lowest Midstream - significant growth potential; strong free cash flow from ops; drop-downs are source of cash; delivers big benefit when NGL margins are strong Gas Pipeline - anchors credit: expansions support stable a
Slide 8: Value-growth catalysts to watch
Value-growth catalysts to watch Growing segment profit Growing natural gas reserves and production New, higher rates for Northwest and Transco More megawatts contracted into market beyond 2010 Capture of additional midstream projects More potential dropdowns to Williams Partners
Slide 9: Financial Results
Financial Results Don Chappel Chief Financial Officer
Slide 10: Financial Results
Financial Results 2006 2005 2006 2005 Income from Continuing Operations $ 155 $ 69 $ 333 $ 318 (Loss) from Discontinued Operations (9) - (24) (2) Cumulative effect of change in accounting principle - (2) - (2) Net Income $ 146 $ 67 $ 309 $ 314 Net Income/Share $ 0.24 $ 0.11 $ 0.51 $ 0.53 Recurring I
Slide 11: Recurring Income from Continuing Operations
Recurring Income from Continuing Operations 2006 2005 2006 2005 Income from Continuing Operations $ 155 $ 69 $ 333 $ 318 Nonrecurring Items Regulatory & Litigation Contingencies Settlements & Related Costs 7 87 260 106 Debt Retirement Expense - - 31 - Impairments/Losses/Write-offs/Contingency Adj. 1
Slide 12: Recurring Income from Cont. Ops. After MTM Adjustment
Dollars in millions ( except per share amounts) Recurring Income from Cont. Ops. After MTM Adjustment 2006 2005 2006 2005 Recurring Inc. from Cont. Ops. Avail. to Common $ 158 $ 168 $ 520 $ 428 Recurring Diluted Earnings per Common Share $ 0.26 $ 0.28 $ 0.86 $ 0.72 Mark-to-Market (MTM) adjustments f
Slide 13: Fourth Quarter Segment Profit
Fourth Quarter Segment Profit 2006 2005 2006 2005 Exploration & Production (see slide 72) $ 140 $ 206 $ 140 $ 206 Midstream Gas & Liquids (see slide 85) 164 112 166 112 Gas Pipeline (see slide 92) 101 93 101 130 Power (see slide 95) (39) (69) (38) 22 Other 1 (30) 2 - Segment Profit $ 367 $ 312 $ 371
Slide 14: 2006 Segment Profit
2006 2005 2006 2005 Exploration & Production (see slide 72) $ 552 $ 587 $ 552 $ 558 Midstream Gas & Liquids (see slide 85) 658 471 733 471 Gas Pipeline (see slide 92) 467 586 465 574 Power (see slide 95) (211) (257) (219) (140) Other 2 (104) 2 (23) Segment Profit $ 1,468 $ 1,283 $ 1,533 $ 1,440 MTM
Slide 15: Business Unit Results
Business Unit Results
Slide 16: Exploration & Production
Exploration & Production Ralph Hill President
Slide 17: 2006 Accomplishments
2006 Accomplishments Impressive drill bit volume growth of 21% Domestic reserves replacement of 216% 4Q06 production 879 MMcfed, up 26%, 181 MMcfed increase since 4Q05 Powder River volumes continue strong growth Piceance Highlands: Barcus Creek farm-in deal Expanded Barnett Shale position San Juan t
Slide 18: Strong domestic production growth of 23%
Strong domestic production growth of 23% Exploration & Production 2006 Domestic production grew 23% or 140 MMcfe/d over 2005 400 500 600 700 800 900 Qtr 1 Qtr 2 Qtr 3 Qtr 4 MMcfe/d 2005 2006
Slide 19: Piceance Production Growth
Piceance Production Growth Up 126 MMcfed or 37% over a year ago 25 Total rigs currently operating in Piceance compared to 19 a year ago BLM/DOW awarded Williams first ever Piceance year round drilling pilot All 10 H&P FlexRigs in operation 4 Nabors Super Sundowner rigs scheduled Williams in process
Slide 20: Piceance Highlands - Momentum Continues
Piceance Highlands - Momentum Continues Exploration & Production 43 wells spud in 2006 26 MMcfed current net production, up from 15 MMcfed year ago Major road, pipeline, and facilities construction nearing completion Winter drilling pilot under way
Slide 21: Powder River Production Growth
Powder River Production Growth Up 36 MMcfed or 30% over a year ago Big George coals driving basin growth Up 88% year over year Sequential quarter volumes up 15% Exploration & Production 0 50 100 150 200 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 3Q '06 4Q '06 Wyodak/Other Big George
Slide 22: An Industry Leader in 2006 Cost Performance
An Industry Leader in 2006 Cost Performance Lease operating expense of $0.46 / Mcfe 3-year average F&D cost of $1.55 / Mcfe Depletion, depreciation & amortization cost of $1.28 / Mcfe Exploration & Production
Slide 23: Strong 2006 Reserves Performance
Strong 2006 Reserves Performance Total U.S. proved reserves 3.7 Tcfe, up 9.5% U.S. and International proved reserves 3.9 Tcfe 216% domestic reserves replacement 99% drilling success rate Added 597 Bcfe to proved Exploration & Production 2004 2005 2006 Total Probable to Proved Transfers (Bcfe) 451 60
Slide 24: Domestic Proved Reserves Reconciliation
Domestic Proved Reserves Reconciliation Exploration & Production - -224 - -11 +603 +40 - -277 +557 Prod. +28 Prod. Acq. Sold YE 2004 Adds/ Rev. Acq. Adds/ Rev. YE 2006 YE 2005 Note: May not add due to rounding
Slide 25: Cash Margin Analysis
Realized Gas Price Assumption 6.04 Margin/Cost Assumption 1.96 4.08 F&D Costs 1.55 Cash Margin Analysis Exploration & Production 2-Year Average (2007-08) Reflective of core basins $6.04 is after hedging and includes average basin market price of $6.38 before hedging Cash costs include LOE, G&A, taxe
Slide 26: Guidance Updates Exploration & Production
Guidance Updates Exploration & Production
Slide 27: 2007-08 Guidance
2007-08 Guidance Dollars in millions Exploration & Production Note: 2006-08 hedge information included in Appendix. Note: If guidance has changed, previous guidance from 11/2/06 is shown in italics directly below. 2007 2008 Segment Profit $700 - 975 $950 - 1,250 Annual DD&A 485 - 535 575 - 625 Segme
Slide 28: Key Points - Value Creation Continues
Key Points - Value Creation Continues An industry leader in production growth and cost efficiencies Continued strong reserves replacement through the drill bit Award winning 2006 performance Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Strategy
Slide 29: Midstream
Midstream Alan Armstrong President
Slide 30: 2006 Accomplishments
2006 Accomplishments Record annual recurring segment profit NGL unit margins set new annual record - over 2 times 5 year average Total NGL production record for Midstream operated plants Deepwater fee revenue grew by 49% Great performance by WPZ Gulf Deepwater Expansions Western Basin Progress Opal
Slide 31: Significant Progress Made on Growth Projects
Significant Progress Made on Growth Projects In Development/Proposal 2007& 2008+ Spending $900MM-1,500MM Under Negotiation 2007 & 2008+ Spending $300MM-500MM In Guidance 2007& 2008+ Spending $800-900MM Midstream 54% Major Growth Projects Included in Guidance ($ Millions) Project Name - In Service Da
Slide 32: Free Cash Flow - Forecast
Free Cash Flow - Forecast 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 $'s in Millions Notes: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. Capital Seg Profit + D
Slide 33: Key Points
Key Points Annual NGL margins reach historic levels - cushioning enterprise impact of lower gas prices Well positioned for growth WPZ lower cost of capital Deepwater expansions progress Western opportunities abound Canadian Tar Sands off-gas Forecast margins in line with current gas/crude pricing re
Slide 34: Gas Pipeline
Gas Pipeline Phil Wright President
Slide 35: 2006 Accomplishments and Current Update
2006 Accomplishments and Current Update Northwest Completion of 26" line replacement project on time, within budget Contract terms extended with various shippers Higher results in new customer satisfaction survey Filed rate case June 30, effective Jan 1, 2007; Unopposed settlement filed with FERC on
Slide 36: NWP Rate Case Update
NWP Rate Case Update Quick rate case resolution is a testament to a quality customer relationship Provide customers with rate certainty for the next several years 10 years since previous rate case Settlement based on an annual cost of service of $404 million Recovery of the 26" line replacement proj
Slide 37: 2007-08 Capital Spending Detail
2007-08 Capital Spending Detail 2007 2008 Normal Maintenance/Compliance1 $215 -270 $180 - 260 Expansion2 210 - 265 105 - 150 Total $425 - 535 $285 - 410 Dollars in millions Gas Pipeline 370 - 470 160 - 200 1The Normal Maintenance/Compliance line includes the 26" replacement project previously shown
Slide 38: Growth Projects and Opportunities
Sentinel Nov 2008/09 Growth Projects and Opportunities Gulfstream Phase IV Jan 2009 Leidy to Long Island Nov 2007 Potomac Nov 2007 Parachute March 2007 Pacific Connector Pipeline Late 2010 Greasewood Nov 2008 Project in proposal stage and not included in capital guidance Jackson Prairie Nov 2008 Gas
Slide 39: Key Points
Key Points Completion of 26" line replacement project on time, within budget Growth projects progressing with in service dates approaching Rate cases making headway with settlements forthcoming 2007 supported by new rate cases and lower capital Return to cash generator in 2007 Gas Pipeline
Slide 40: Power
Power Bill Hobbs President
Slide 41: Successful 2006
Successful 2006 Commercial operations generated strong results Originated new transactions across all regions Efforts improved cash-flow certainty and expected to provide approximately $120 million in cash flows from 2007 to 2010 $87 million increase in year-over-year recurring segment profit after
Slide 42: Strong Start to 2007
Strong Start to 2007 West: Executed multi-unit tolling re-sales for up to 4 years with Southern California Edison First sale beyond 2010 Currently sold out through 2010 60 percent sold out in 2011 Northeast: Transacted seven incremental capacity sales approximating 20 percent of available capacity o
Slide 43: YTD Origination Success Adds Approx. $250MM to Hedged Cash Flows
YTD Origination Success Adds Approx. $250MM to Hedged Cash Flows Power Demand payments Undiscounted dollars in millions Hedged on 12/31/06 Est. Impact of new orig deals Note: Cash flows presented here are forecasts and do not include the Natural Gas portfolio. Est. Unhedged Merchant $- $100 $200 $30
Slide 44: 2007-08 Consolidated Outlook
2007-08 Consolidated Outlook Don Chappel Chief Financial Officer
Slide 45: 2007 Forecast Guidance
2007 Forecast Guidance Consolidated Segment profit before MTM adjustment $1,775 - $2,275 Net Interest Expense (640) - (700) Other (Primarily General Corp. Costs) (140) - (170) Pretax Income 995 - 1,405 Provision for Income Tax (395) - (560) Recurring Income from Continuing Operations $600 - $845 Dil
Slide 46: Consolidated 2007-08 Segment Profit
Consolidated 2007-08 Segment Profit Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total Reported Before MTM Adj. 1 MTM Adjustment Total Reported After MTM Adj. 1 Nonrecurring Items Total Recurring After MTM Adj. 1 2008 Note: If guidance has change
Slide 47: 2007 Segment Profit Forecast Guidance Change
2007 Segment Profit 1 Forecast Guidance Change Dollars in millions 1 Recurring Segment Profit After MTM Adjustment Previous Segment Profit Guidance Nov. 2 Change in Natural Gas Prices (Consolidated) Change in NGL Margins (Midstream) Additional Costs (E&P) Other / Rounding New Segment Profit Guidance
Slide 48: Commodity Price Summary
Commodity Price Summary Un-hedged Commodity Price Assumptions Exploration & Production: Natural Gas: Basin Prices Average Rockies Average San Juan / Mid-Continent NYMEX (reference only) Midstream: Crude Oil to Natural Gas Ratio 1 Crude Oil - WTI (reference only) 2007 $5.10 - $6.40 $6.10 - $7.40 $7.0
Slide 49: 2007-08 Hedge Update
2007 2008 Fixed Price at the basin: Volume (MMcf/d) 172 73 Average Price ($/Mcf) $3.90 $3.96 NYMEX Collars: Volume (MMcf/d) 15 - Average Price ($/Mcf) $6.50 - $8.25 At the Basin Collars:1 NWPL Rockies Volume (MMcf/d) 50 105 Price ($/Mcf) $5.65 - $7.45 $6.02 - $9.07 EPNG San Juan Volume (MMcf/d) 130
Slide 50: Natural hedges in our commodity businesses
Natural hedges in our commodity businesses Consolidated
Slide 51: 2007-08 Capital Expenditures
2007-08 Capital Expenditures Consolidated Exploration & Prod. Midstream Gas Pipeline Power Other/Corporate Total Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range 2007 2008 $1,300 - 1,400 430 - 470 425 - 535 - - 10 - 30 $2,225 - 2,425 $2,000 -
Slide 52: 2007-08 Outlook
2007-08 Outlook Dollars in millions Segment Profit Reported After MTM Adj. Recurring After MTM Adj. DD&A Cash Flow from Ops.1 Capital Expenditures Operating Free Cash Flow 2 2007 2008 Consolidated 1 Cash flow from continuing operations. 2 Operating free cash flow is defined as cash flow from continu
Slide 53: Allocation of 2007 Available Cash
Allocation of 2007 Available Cash Cash Sources: Available Cash and Cash Equivalents Cash Flow from Operations Total Available Cash Cash Uses: Capital Spending Dividends / Minority Interest Payments Corporate Debt Maturities Settlement of Prior Contingent Obligations Normalized Cash Balance Total Cas
Slide 54: Financial Strategy/Key Points
Financial Strategy/Key Points Drive/enable sustainable growth in EVA(r) / shareholder value MLP continues to provide benefits to WMB Low-cost equity capital funding source for growth Growing incentive distributions and GP value Continue to maintain and/or improve credit ratios/ratings Reduce risk in
Slide 55: Summary
Summary Steve Malcolm Chairman, President & CEO
Slide 56: Value-growth catalysts to watch
Value-growth catalysts to watch Growing segment profit Growing natural gas reserves and production New, higher rates for Northwest and Transco More megawatts contracted into market beyond 2010 Capture of additional midstream projects More potential dropdowns to Williams Partners
Slide 57: Well-positioned for near- to long-term value creation
Well-positioned for near- to long-term value creation Prime assets deliver growth Pursuing growth with discipline Solid record of delivering results Taking action to drive value creation
Slide 58: Q&A
Q&A
Slide 59: Non-GAAP Reconciliations
Non-GAAP Reconciliations
Slide 60: Non-GAAP Disclaimer
Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, operating 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 in
Slide 61: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 62: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation
Slide 63: Non-GAAP Reconciliation Schedule - EPS after MTM adjustment
Non-GAAP Reconciliation Schedule - EPS after MTM adjustment Non-GAAP Reconciliation
Slide 64: EBITDA Reconciliation
EBITDA Reconciliation Non-GAAP Reconciliation
Slide 65: 4Q 2006 Segment Contribution
4Q 2006 Segment Contribution Non-GAAP Reconciliation
Slide 66: 2006 Segment Contribution
2006 Segment Contribution Non-GAAP Reconciliation
Slide 67: 2007 Forecast Segment Contribution
2007 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 Gas Pipeline Segment Profit (Loss) DD&A Segment Profit Before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P Midstream Total Corp/ Other Dollars in millions 1 Segment Profit is prior to MTM adju
Slide 68: 2007 Forecast Guidance Contribution
2007 Forecast Guidance Contribution Non-GAAP Reconciliation Dollars in millions, except per-share amounts Feb 22 Guidance Recurring Income from Cont. Ops Recurring EPS Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Co
Slide 69: Appendix
Appendix
Slide 70: Exploration & Production
Exploration & Production
Slide 71: Piceance Valley - Cornerstone Asset
Piceance Valley - Cornerstone Asset One of the largest gas producers in the Basin 2006 Proved reserves total 2.1 Tcfe ~460 MMcfd net Valley production Approx. 115,000 net acres Operate ~1,800 wells, 98% WI Operate 250+ miles of gathering and 4 gas plants Access to 5 major pipelines Currently operati
Slide 72: Piceance Highlands - Momentum Continues
Piceance Highlands - Momentum Continues 45,000 net acres 2006 Proved reserves total 338 Bcfe ~2,800 potential drilling locations 2.6 - 3.1 Tcf potential net reserves 26 MMcfd net production (up from 15 MMcfd one year ago) Operate 74 wells (up from 31 one year ago); 81% avg. W.I. Key infrastructure p
Slide 73: Piceance Basin: Highlands Ownership Position
Piceance Basin : Highlands Ownership Position Trail Ridge 21,512 acres (10-acre density), 1,500 potential locations Farm-In Deals Ryan Gulch Earned 16,000 net acres by drilling 6 wells Allen Point Earned 6,200 net acres by drilling 6 wells Barcus Creek Newly added farm-in deal Barcus Creek Ryan Gulc
Slide 74: Barcus Creek Farm-In Deal
Barcus Creek Farm-In Deal Industry wells Barcus Creek Earning Wells Ryan Gulch Wells Exploration & Production Direct bolt-on to Ryan Gulch Project Targets Williams Fork Formation Drill 5 wells by October 2007, drilling program under way Earn 45% working interest in ~25,000 gross acres (~11,000 acres
Slide 75: Powder River Basin - Coalbed Methane
High potential, low-risk development play, low cost wells Proved reserves of 372 Bcfe (YE06), plus 1.4 Tcf Prob/Pos ~7,000 total JV wells, 54% operated 2006 drilling success rate of 99% Typical well production 140 Mcf/d peak Wyodak and 400 Mcf/d peak Big George ~160 MMcfe/d net production Approx. 1,
Slide 76: We move Rockies gas to higher-price markets
We move Rockies gas to higher-price markets for sale Rockies price risk managed through transport and basis hedges Our contracted pipeline capacity to moves our Rockies production to more favorable price markets Firm Capacity Under Contract Wamsutter 200 East to Mid continent 209 South to San Juan 2
Slide 77: San Juan Basin - Foundation
Conventional and coalbed methane production Long life / slow decline wells Proved reserves of 614 Bcfe (YE06) ~160 MMcfe/d net production Approx. 120,000 net acres Low risk in-fill drilling 40-60 operated wells drilled per year 200 - 250 undeveloped locations Attractive returns with near 100% succes
Slide 78: Arkoma Basin - Horizontal Expertise
CBM and shale activity Proved reserves of 87 Bcfe (YE06) 20 MMcf/d net production Approx. 90,000 net acres Have drilled ~199 extended reach horizontal lateral wells Five year drilling success rate of 90% Operate 285 wells and ~150 joint interest wells Shale and other conventional sources offer oppor
Slide 79: Fort Worth Basin - Barnett Shale
Fort Worth Basin - Barnett Shale 3 rigs active in the play 20,000 net acres Proved reserves of 80 Bcf (YE 2006) Current net production 23 MMcfed High working interest 56 operated and 15 joint interest wells Utilizes Williams' integrated capabilities Adding value through bolt-on opportunities Explora
Slide 80: International E&P
YE06 Proved reserves total 27 MMboe (163 Bcfe) 5,800 Bbl/d net oil & liquids production 18 MMcf/d net gas production 69% ownership in Apco Argentina 525,000 net acres owned/controlled In-fill, field extension drilling Exploration upside High investment returns, fast cash cycle Complements domestic l
Slide 81: 4Q06 Net Realized Price Summary
4Q06 Net Realized Price Summary Exploration & Production
Slide 82: Midstream
Midstream
Slide 83: Segment Profit - Midstream
Segment Profit - Midstream 4Q06 to 4Q05 financial highlights: Strong NGL unit margins Higher fee revenue Increased operating expenses Financial Results 2006 to 2005 financial highlights: Record NGL unit margins Higher fee revenue Increased operating expenses Lower ethylene cracking margins 2006 2005
Slide 84: 2007-08 Guidance
2007-08 Guidance 2007 2008 Segment Profit $450 - 750 $550 - 825 $500 - 750 $550 - 800 Annual DD&A 200 - 210 220 - 230 $210 - 220 Segment Profit + DD&A $650 - 960 $770 - 1,055 $700 - 960 $760 - 1,020 Capital Spending $430 - 470 $260 - 300 $420 - 460 Dollars in millions Note: If guidance has changed,
Slide 85: Margins Above Average (by Quarter)
Margins Above Average Midstream Note: Actual realized margins, does not include Discovery volumes. Five year average of 16.4 cpg is calculated for the period 1Q02-4Q06. Domestic NGL Average Realized Net Margin and Volumes by Quarter Realized Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals)
Slide 86: Margins Above Average (by Year)
Margins Above Average Midstream Note: Actual realized margins, does not include Discovery volumes. Five year average of 16.4 cpg is calculated for the period 1Q02-4Q06. Domestic NGL Average Realized Net Margin and Volumes by Year Realized Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Av
Slide 87: Frac Spread
Gas prices based on average Gas Daily settle prices at NWP, Wyoming. NGL prices based on composition weighted average of Mont Belvieu daily liquids prices; does not include fuel or T&F. Oil prices are based on average of daily NYMEX prompt settle prices. Frac Spread Frac Spread Drivers Midstream
Slide 88: 2006 Domestic Equity NGL Margins by Region
Opal Ignacio Echo Springs Gas Processing & Treatment Plants Gathering Areas Kutz Lybrook Markham Cameron Mobile Bay 2006 Domestic Equity NGL Margins by Region Midstream Domestic Average 33.5 cpg Western Region 35.4 cpg Gulf Coast Region 29.4 cpg Midstream Larose Williams YTD Equity NGL Production 72
Slide 89: Gas Pipeline
Gas Pipeline
Slide 90: Segment Profit - Gas Pipeline
2006 2005 2006 2005 Segment Profit $101 $93 $467 $586 Nonrecurring (Income)/Expense related to prior periods - 32 - (3) Accrual of contingent refund obligation - 5 - 5 1999 Fuel Tracker adjustment - - - (14) Excess royalty reserve reversal - - (2) - Recurring segment profit $101 $130 $465 $574 Segme
Slide 91: 2007-08 Guidance
2007-08 Guidance 2007 2008 Segment Profit $585 - 655 $590 - 665 Annual DD&A 1 280 - 300 300 - 325 Segment Profit + DD&A $865 - 955 $890 - 990 Capital Spending $425 - 535 $285 - 410 Dollars in millions Note: If guidance has changed, previous guidance from 11/02/06 is shown in italics directly below.
Slide 92: Power
Power
Slide 93: Segment Profit - Power
2006 2005 2006 2005 Segment Loss ($39) ($69) ($211) ($257) Nonrecurring Accrual for regulatory & litigation Contingencies/Settlements 1 69 5 87 Impairments, Losses, Write-offs - 23 - 23 Contingent obligation adjustments - - (13) - Expense related to prior periods - - - 7 Recurring segment profit/(lo
Slide 94: 2006 - Segment Profit/(Loss) to Cash Flow from Ops
2006 - Segment Profit/(Loss) to Cash Flow from Ops Power Dollars in Millions Commodity Working Power Capital/ & NG Other Total Segment Loss ($152) ($59) ($211) MTM Adjustments: Reverse Forward Unrealized MTM Losses 22 22 Add Realized Gains from MTM Previously Recognized 282 282 Segment Profit/(Loss)
Slide 95: 2007-08 Guidance
Dollars in millions 2007 2008 Prior Guidance - Segment Profit/(Loss) before MTM Adj ($75) - 25 ($150) - 0 Est. Fwd Impact of 4Q06 MTM Earnings and other portfolio adjustments New Guidance - Segment Profit/(Loss) before MTM Adj ($75) - 0 ($130) -20 Estimated MTM Adjustments 125 180 200 Segment Profit
Slide 96: Key 2006 and YTD 2007 Contracts
Key 2006 and YTD 2007 Contracts Power *Certain deals in this table are reflected in "Key Agreements" in the following Portfolio Overview slides for each region.
Slide 97: Regional Highlights
Regional Highlights West Highly hedged through 2011, In-city generation New local resource-adequacy requirement in 2007 Re-designed energy market to be implemented January 2008 Tolling agreement provides re- power rights Reserve margins tight, expected to compress further Market for Williams' E&P ga
Slide 98: 4Q06 Financial Statement Changes for Derivatives
4Q06 Financial Statement Changes for Derivatives Power During 4Q06, Williams reported the following changes related to its derivative portfolio: The net change in Derivative Assets and Liabilities for E&P was positive primarily due to a 4Q06 decrease in gas prices against a short derivative position
Slide 99: Enterprise Risk Management
Enterprise Risk Management
Slide 100: WMB Collateral Outstanding
WMB Collateral Outstanding Enterprise Risk Management * Note: Negative Margin &Adequate Assurance value represents a margin liability, where Power is a net receiver of cash margin.
Slide 101: WMB Collateral Sensitivity
WMB Collateral Sensitivity Enterprise Risk Management Dollars in millions Margin Volatility (1% chance of exceeding) -Potential incremental collateral requirement Days 12/31/2006 9/30/2006 6/30/2006 3/31/2006 30 ($98) ($155) ($246) ($223) 180 ($434) ($459) ($580) ($769) 360 ($521) ($471) ($489) ($62
Slide 102: Sensitivity Analysis
Sensitivity Analysis Dollars in millions, except per unit increases Enterprise Risk Management Enterprise 1 Power Co. 2 Midstream 3 Natural Gas Power Processing Margin Per MMBtu Per MWh Per Gallon of NGL's Increase $0.10 $1 $0.01 2007 $5-$8 MM $1-$3 MM $13-$15 MM 2008 $13-$15 MM $4-$6 MM $15-$17 MM
Slide 103: Consolidated
Consolidated
Slide 104: Liquidity at December 31, 2006
Liquidity at December 31, 2006 Consolidated
Slide 105: 2006 Cash Information
2006 Cash Information Consolidated
Slide 106: Debt Balance
Debt Balance1 Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Debt Balance @ 12/31/05 $7,713 7.6% Early Conversions (220) Scheduled Debt Retirements & Amortization (64) Debt Balance @ 3/31/06 $7,429 7.7% Fixed Rate Debt @ 12/31/06 $7,864 7.7% Variable Ra
Slide 107: Debt Amortization
Dollars in millions Debt Amortization - As of 12/31/2006 Consolidated 392 239 54 217 1,168 998 385 600 700 751 85 208 100 1170 850 80 22 8 10 7 $0 $250 $500 $750 $1,000 $1,250 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Slide 108: EPS Metrics
Diluted EPS from Cont. Ops. $0.22 ($.11) $0.19 $0.25 $0.55 Recurring EPS 0.23 0.19 0.19 0.26 0.86 Recurring EPS after MTM Adj. 0.26 0.33 0.28 0.30 1.17 Average Shares (MM) 607 596 609 610 609 2006 1Q 2Q 3Q 4Q Total Diluted EPS from Cont. Ops. $0.34 $0.07 $0.01 $0.11 $0.53 Recurring EPS 0.33 0.11 (0.
Slide 109: 2007 Interest Expense Forecast Guidance
2007 Interest Expense Forecast Guidance Consolidated Interest on Long-Term Debt $600 - $620 Amortization Discount/Premium and other Debt Expense 25 - 30 Credit Facilities: (Incl. Commitment Fees Plus LC Usage) 35 - 45 Interest on other Liabilities 10 - 20 Interest Expense $670 - $715 Less: Capitaliz
Slide 110: The Williams Companies, Inc.
The Williams Companies, Inc.