Exhibit 99.2
| Williams 2006 2nd Quarter Earnings August 3, 2006 |
| 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 typically can identify forward-looking statements by the use of forward-looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward- looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; Our operating results might fluctuate on a seasonal and quarterly basis; Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; Legal proceedings and governmental investigations related to our business; Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; 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 liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; The continued availability of natural gas reserves to our natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise |
| 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 strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our Web site at www.williams.com. |
| Overview Steve Malcolm Chairman, President & CEO |
| Headlines Execution of strategy delivers very strong 2Q Nearly DOUBLED recurring income after removing mark-to-market effect Raising profit guidance for '06, '07 and '08 19% jump up in guidance for '06 key earnings measure* Boosting planned capital expenditures to develop reserves MLP strategy to accelerate delivery of benefits to Williams *Recurring income from continuing operations after mark-to-market adjustment |
| Executing on our strategy to drive near- and long-term value creation Delivering on our promises. So far in 2006, we have: Increased dividend 20% Increased natural gas production nearly 20% Completed $360 million drop-down into Williams Partners Resolved significant legacy issues Very strong 2Q results 99% higher recurring results after removing mark-to-market effect Posted nearly $200 million in Midstream recurring segment profit Robust NGL margins more than offset lower natural gas prices Well-positioned for continued success Increasing 2006-2008 profit guidance Boosting capital spending to develop reserves Accelerating MLP drop-downs |
| Well-positioned for continued success: Accelerating MLP drop-downs Pursuing growth with discipline and diligence Successful IPO in August 2005 Recently closed $360 million transaction - drop-down of 25.1% of Four Corners gathering and processing assets 21% increase in WPZ unit distribution level since IPO Strategy to accelerate delivery of MLP benefits to Williams Goal to drop down $1 billion to $1.5 billion in assets during next 6 months Deep bench of qualifying assets supports annual drop-downs of $1 billion to $2 billion during guidance period MLP strategy requires disciplined capital structure WPZ access to debt and equity capital markets is key source of funding to acquire drop-down assets WPZ's debt is consolidated on Williams' balance sheet and the partnership's credit rating is linked to Williams' |
| Key drivers for our MLP drop-downs Ongoing source of lower-cost capital WMB's general partnership interest grows in size, value Growing source of cash distributions from LP units and general partnership Some retained MLP units - cash distributions, value upside |
| Financial Results Don Chappel Chief Financial Officer |
| 2006 2005 2006 2005 Income (Loss) from Continuing Operations ($64) $40 $67 $243 Income (Loss) from Discontinued Operations (12) 1 (11) (1) Net Income (Loss) ($76) $41 $56 $242 Net Income (Loss) /Share ($0.13) $0.07 $0.09 $0.41 Recurring Income from Continuing Ops./Share $0.19 $0.11 $0.42 $0.45 Recurring Income from Continuing Operations After MTM Adjustments/Share $0.33 $0.17 $0.59 $0.39 Financial Results Dollars in millions ( except per share amounts) Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD |
| 2006 2005 2006 2005 Income (Loss) from Continuing Operations ($64) $40 $67 $243 Nonrecurring Items Regulatory & Litigation Contingencies/ Settlements and Related Costs 249 13 243 18 Debt Retirement Expense 4 - 31 - Impairments/Losses/Write-offs - 53 - 53 (Income)/expense related to prior periods - (22) (6) (28) Gain on sale of assets - (9) (7) (17) Other - Net - 1 1 3 Total Nonrecurring items before taxes 253 36 262 29 Tax effect of adjustments (76) (10) (80) (8) Recurring Inc. from Continuing Ops. Avail to Com. $113 $66 $249 $264 Recurring Income from Continuing Ops./Share $0.19 $0.11 $0.42 $0.45 Recurring Income from Continuing Operations Dollars in millions ( except per share amounts) Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD |
| 2006 2005 2006 2005 Recurring Inc. from Cont. Ops. Avail. to Common $113 $66 $249 $264 Recurring Diluted Earnings per Common Share $0.19 $0.11 $0.42 $0.45 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains)/losses $38 $(22) $(4) $(243) Add realized gains from MTM previously recognized 100 77 177 190 Total MTM Adjustments 138 55 173 (53) Tax Effect of Total MTM Adjustments (53) (21) (67) 21 After-Tax MTM Adjustments $85 $34 $106 $(32) Recurring Inc. from Cont. Ops. Avail. to Common Shareholders after MTM adjustments $198 $100 $355 $232 Recurring Diluted Earnings Per Share after MTM adjustments $0.33 $0.17 $0.59 $0.39 Recurring Income from Cont. Ops. After MTM Adjustment Dollars in millions ( except per share amounts) Financial Results Note: Adjustments have been made to reverse estimated forward unrealized mark-to-market ("MTM") (gains) /losses and add estimated realized gains from MTM previously recognized; i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD |
| Second Quarter Segment Profit 2006 2005 2006 2005 Exploration & Production $120 $118 $120 $118 Midstream Gas & Liquids 131 109 199 109 Gas Pipeline 123 165 123 143 Power (80) (75) (80) (62) Other (1) (61) (1) (7) Segment Profit $293 $256 $361 $301 MTM Adjustments - Power 139 55 Segment Profit after MTM Adjustments $500 $356 Memo: Power after MTM Adjustments $59 ($7) Dollars in millions 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. Financial Results Reported Recurring |
| 2006 2005 2006 2005 Exploration & Production $267 $222 $267 $214 Midstream Gas & Liquids 282 238 344 238 Gas Pipeline 257 332 255 297 Power (102) 39 (102) 64 Other 1 (65) 1 (12) Segment Profit $705 $766 $765 $801 MTM Adjustments - Power 173 (53) Segment Profit after MTM Adjustments $938 $748 Memo: Power after MTM Adjustments $71 $11 2006 YTD Segment Profit Dollars in millions 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. Financial Results Reported Recurring |
| 2006 2005 2006 2005 Segment Profit $120 $118 $267 $222 Nonrecurring Gain on sale of assets - - - (8) Recurring segment profit $120 $118 $267 $214 Segment Profit - Exploration & Production 2Q06 to 2Q05 financial highlights: 20% volume production growth $50 million negative hedge impact in 2Q06 Operating expense up $0.21/Mfce, $0.09/Mcfe after adjustments for prior periods $0.05 of the $0.09/Mcfe due to production enhancement workover program Dollars in millions 2006 YTD to 2005 YTD financial highlights: 18.5% volume production growth 25% recurring segment profit growth $135MM negative hedge impact year to date Financial Results 2nd Quarter YTD |
| Segment Profit - Midstream 2Q06 to 2Q05 financial highlights: Record NGL unit margins Higher fee revenue Higher Canadian margins Increased operating expenses Financial Results 2006 YTD to 2005 YTD financial highlights: Higher NGL unit margins Higher fee revenue Increased operating expenses 2006 2005 2006 2005 Segment Profit $131 $109 $282 $238 Nonrecurring Accrual for Gulf Liquids litigation 68 - 68 - International Contract Settlement - - (6) - Recurring segment profit $199 $109 $344 $238 Dollars in millions 2nd Quarter YTD |
| 2006 2005 2006 2005 Segment Profit $123 $165 $257 $332 Nonrecurring Excess royalty reserve reversal - - (2) - Pension expense reduction - (17) - (17) Adjustment to carrying value of certain liabilities - (5) - (18) Recurring segment profit $123 $143 $255 $297 Segment Profit - Gas Pipeline 2Q06 to 2Q05 financial highlights: Higher: operating expenses pension expense property insurance Partially offset by higher earnings of Gulfstream & other JVs Financial Results 2006 YTD to 2005 YTD financial highlights: 2006: Higher operating expenses & taxes 2005 recurring income associated with Gulfstream completion fee Operating tax adjustment Dollars in millions 2nd Quarter YTD |
| 2006 2005 2006 2005 Segment Profit/(Loss) ($80) ($75) ($102) $39 Nonrecurring Accrual for regulatory & litigation Contingencies/Settlements - 13 - 17 Expense related to prior periods - - - 8 Recurring segment profit/(loss) (80) (62) (102) 64 MTM Adjustment (Recurring) 138 55 173 (53) Recurring segment profit/(loss) after MTM Adj. $59 ($7) $71 $11 Segment Profit - Power 2Q06 to 2Q05 financial highlights: Increase in hedged cash flows largely due to benefit of structured hedges and improved power market conditions Increase in natural gas results due to monetizing certain non-core basis positions, partially offset by losses on storage portfolio Dollars in millions 2006 YTD to 2005 YTD financial highlights: Increase in hedged cash flows largely due to benefit of structured hedges and improved power market conditions Decrease in expenses (including SG&A) includes $25 million gain related to sale of certain Enron receivables. Financial Results 2nd Quarter YTD |
| Liquidity at June 30, 2006 Financial Results Dollars in millions Cash and cash equivalents 980 $ Other current securities 405 Less: Subsidiary and Int'l cash & cash equivalents 446 $ Customer margin deposits payable 32 (478) Available unrestricted cash 907 Available revolver capacity 1,742 Total Liquidity 2,649 $ |
| 2006 Cash Information Financial Results Dollars in millions 2nd Quarter YTD Beginning Unrestricted Cash 1,115 $ 1,597 $ Cash flow from Continuing Operations 509 673 Debt retirements (664) (728) Proceeds from debt issuance 699 699 Proceeds from sale of limited partnership units 225 225 Capital expenditures (534) (1,003) Dividends (54) (98) Dividends to minority interests (10) (17) Purchase of auction rate securities (232) (327) Other-net (74) (41) Change in Cash and Cash equivalents (135) $ (617) $ Ending Unrestricted Cash at 6/30/06 980 $ Restricted Cash at 06/30/06 (not included above) 118 $ |
| Exploration & Production Ralph Hill President |
| 2006 Accomplishments 2Q06 production up 20%, 131 MMcfed since 2Q05 6 H&P rigs drilling Additional 12,200 acres Piceance Valley 10-acre spacing approved Piceance Highlands building momentum Big George/Powder River volumes continue impressive growth Barnett Shale position expanding San Juan team awarded Best Management Practices from BLM Exploration & Production Recurring Segment Profit + Depreciation 0 50 100 150 200 250 300 1Q 2Q 3Q 4Q $MM 2005 2006 |
| 2006 10-acre Density Applications Approved Exploration & Production 2006 10-Acre Applications Green = Previously Approved - 34,760 Acres Blue = April '06 Approved - 11,200 Acres (approx. 800 additional Bottom Hole Locations) Purple = July '06 Approved - 12,200 Acres (approx. 890 additional Bottom Hole Locations) Williams acreage shown in color Grand Valley Parachute Rulison |
| Piceance Production Growth Up 104 MMcfed or 34% over a year ago 23 total rigs currently operating in Valley and Highlands compared to 13 a year ago 4 additional H&P FlexRigs to be received in 2006 4 Nabors Super Sundowner rigs to be received in early 2007 Williams will be able to high grade rig fleet Net MMcfe/d Exploration & Production Williams' Total Piceance Production 175 225 275 325 375 425 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 Highlands Valley |
| Piceance Highlands - Building Momentum Exploration & Production 44 wells currently producing, up from 8 one year ago 13 MMcfed current net production, up 10 MMcfed year over year 7 rigs currently operating Major road and pipeline infrastructure in progress |
| Powder River Up 26 MMcfed or 23% over a year ago Big George coals driving basin growth Up 99% year over year June vs. March volumes up 25% Net MMcfe/d Exploration & Production |
| Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING Pending Piceance Basin Farm-in Opportunity Drill-to-earn deal pending Targets Williams Fork Formation ~11,000 net acres to Williams 87.5% NRI 600+ potential drill locations Williams to operate Exploration & Production |
| New Capital Projects Exploration & Production Dollars in millions 5/4/06 Capital Guidance $950 $1,050 $950 $1,050 $1,000 $1,150 New Capital Projects Piceance Additional Drilling 65 50 70 Increased Costs 35 30 30 Gathering & Processing * 40 95 30 Other Rockies & Barnett Shale Opportunities 60 25 20 Subtotal 200 200 150 8/3/06 Capital Guidance $1,150 $1,250 $1,150 $1,250 $1,150 $1,300 Midpoint Changes Segment Profit 25 50 75 DD&A 25 30 25 Segment Profit + DD&A 50 80 100 Production (MMcfed) 20 30 40 * Includes 3rd party contracts 2006 2007 2008 |
| 2006-08 Guidance 2006 2007 2008 Segment Profit $550 - 650 $825 - 950 $1,025 - 1,175 525 - 625 775 - 900 950 - 1,100 Annual DD&A 360 - 400 455 - 505 500 - 550 335 - 375 425 - 475 475 - 525 Segment Profit + DD&A $910 - 1,050 $1,280 - 1,455 $1,525 - 1,725 860 - 1,000 1,200 - 1,375 1,425 - 1,625 Capital Spending $1,150 - 1,250 $1,150 - 1,250 $1,150 - 1,300 950 - 1,050 950 - 1,050 1,000 - 1,150 Production (MMcfe/d) 770 - 845 905 - 1,005 990 - 1,140 750 - 825 875 - 975 950 - 1,100 Dollars in millions Exploration & Production Note: 2006-08 hedge information included in Appendix. Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below. Unhedged Price Assumption ($/Mcf) Average San Juan/Rockies Price $6.39 $6.09 $6.10 Average Mid-continent Price $6.55 $6.75 $6.77 NYMEX $7.84 $7.00 $7.00 |
| Key Points - Value Creation Continues An industry leader in production growth, cost efficiencies and reserves replacement Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Strategy remains rapid development of our premier drilling inventory Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Piceance Highlands significantly contributing Experienced and talented work force Exploration & Production |
| Midstream Alan Armstrong President |
| 2006 Accomplishments Midstream Recurring Segment Profit + Depreciation Record quarter NGL production rebounding NGL unit margins at record levels Completed dropdown of 25.1% interest in Four Corners Expanding for the future: Opal TXP-IV Opal TXP-V Tahiti lateral Blind Faith Wamsutter gathering 0 20 40 60 80 100 120 140 160 180 200 220 240 260 1Q 2Q 3Q 4Q $ MM 2005 2006 |
| 2006-08 Guidance 2006 2007 2008 Segment Profit $550 - 675 $500 - 750 $550 - 800 500 - 600 410 - 530 440 - 580 Annual DD&A 190 - 200 200 - 210 210 - 220 Segment Profit + DD&A $740 - 875 $700 - 960 $760 - 1,020 690 - 800 610 - 740 650 - 800 Capital Spending $280 - 300 $230 - 270 $70 - 90 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/2006 is shown in italics directly below. Midstream Un-Hedged Price Assumptions 2006 2007 2008 1Q-2Q 3Q-4Q NYMEX Natural Gas ($/Mcf) $7.00 $7.84 $7.00 $7.00 NYMEX Oil ($/bbl) $67 $62 - $70 $55 - $69 $55 - $69 Realized Margin (cents/gallon) 26.4 |
| 0 100 200 300 400 500 600 700 800 900 1,000 Discretionary Expansion Segment Profit Margin Uplift Base Segment Profit + DDA Discretionary Expansion Historic Expansion Maintenance Well Connects Free Cash Flow - Forecast $'s in Millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 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 five year average margin. Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA 2004 2005 2006 2007 2008 Capital Spending Recurring Segment Profit & DDA Midstream |
| Opal Blind Faith Western Deepwater Western Deepwater Overland Pass Significant Progress Made on Growth Projects Western G&P Expansions Deepwater Expansions Overland Pass In Development/Proposal 2006 2007 2008 Spending $500MM-1,500MM 20% 65% Western G&P Expansions ($75MM in guidance) Deepwater Expansions ($30MM in guidance) Under Negotiation 2006 2007 2008 Spending $350MM-550MM 80% 20% Blind Faith Opal TXP-V Opal TXP-IV Tahiti Lateral Contracted/Approved 2006 2007 2008 Spending $280MM 65% 35% In Guidance Not in Guidance 15% Midstream |
| Key Points Focused on our strategy of reliability Base business continues to generate healthy returns and free cash flows NGL margins exceed historic levels - cushioning enterprise impact of lower gas prices Expect NGL margins to remain above historic levels Progress continues on deepwater expansions Western growth opportunities abound Midstream |
| 2006-08 Consolidated Outlook Don Chappel Chief Financial Officer |
| 2006 Forecast Guidance Consolidated Segment profit before MTM adjustment $1,355 - $1,675 $1,273 - $1,613 Net Interest Expense (670) - (710) (665) - (705) Other (Primarily General Corp. Costs) (105) - (125) (85) - (120) Securities Litigation Settlement & Related Costs (162) - Pretax Income 418 - 678 523 - 788 Provision for Income Tax (185) - (295) (210) - (320) Income from Continuing Ops 233 - 383 313 - 468 Income/(Loss) from Discontinued Ops (5) - 0 (5) - 0 Net Income $228 - 383 $308 - 468 Diluted EPS $0.37 - $0.63 $0.50 - $0.77 Recurring Income from Cont. Ops $414 - $564 $318 - $473 Diluted EPS - Recurring $0.68 - $0.92 $0.52 - $0.78 Diluted EPS - Recurring After MTM Adj. 1 $0.95 - $1.20 $0.78 - $1.03 1 Includes MTM adjustment of $275 million (pretax) in Aug 3 guidance and $255 million (pretax) in May 4 guidance Note: Fully diluted shares of 610 million Dollars in millions, except per-share amounts Aug 3 Guidance May 4 Guidance |
| Consolidated 2006-08 Segment Profit Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total Reported Before MTM Adj. MTM Adjustment Total Reported After MTM Adj. Nonrecurring Items Total Recurring After MTM Adj. 2006 2007 $550 - 650 550 - 675 1 475 - 520 (200) - (150) (20) $1,355 - 1,675 275 $1,630 - 1,950 60 $1,690 - 2,010 2008 $825 - 950 500 - 750 585 - 655 (175) - (75) 10 - (30) $1,745 - 2,250 225 $1,970 - 2,475 - - $1,970 - 2,475 $1,025 - 1,175 550 - 800 590 - 665 (155) - (5) (15) - 35 $1,995 - 2,670 205 $2,200 - 2,875 - - $2,200 - 2,875 Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below $1,273 - 1,613 500 - 600 255 215 215 $1,528 - 1,868 $1,520 - 1,860 (205) - (105) (165) - (15) (165) - (15) $1,615 - 2,040 $1,800 - 2,365 Power After MTM Adj. $75 - 125 $50 - 150 $50 - 200 $50 - 150 525 - 625 775 - 900 950 - 1,100 $1,830 - 2,255 $1,830 - 2,255 $2,015 - 2,580 $2,015 - 2,580 410 - 530 440 - 580 $50 - 200 (22) - (27) (8) 1 Reflects $68 million of nonrecurring litigation accrual |
| 2006-08 Capital Expenditures Consolidated Exploration & Production Midstream Gas Pipeline Power Other/Corporate Total Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range $1,150 - 1,250 280 - 300 745 - 815 - - 10 - 30 $2,200 - 2,400 $1,150 - 1,250 230 - 270 370 - 470 - - 10 - 30 $1,775 - 1,975 $1,150 - 1,300 70 - 90 340 - 440 - - 10 - 30 $1,575 - 1,825 2006 2008 2007 $950 - 1,050 $950 - 1,050 $1,000 - 1,150 $1,950 - 2,150 $1,600 - 1,800 $1,500 - 1,750 710 - 785 390 - 490 410 - 510 |
| 2006-08 Outlook 1 Cash flow from continuing operations. 2 Operating free cash flow is defined as cash flow from continuing operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below 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 2006 2007 $1,630 - 1,950 1,690 - 2,010 820 - 920 1,500 - 1,800 2,200 - 2,400 (700) - (600) 2008 $ 1,970 - 2,475 1,970 - 2,475 930 - 1,030 2,000 - 2,300 1,775 - 1,975 225 - 325 $2,200 - 2,875 2,200 - 2,875 1,010 - 1,110 2,425 - 2,825 1,575 - 1,825 850 - 1,000 $1,528 - 1,868 Consolidated (450) - (350) $1,520 - 1,860 790 - 890 900 - 1,000 1,950 - 2,150 1,600 - 1,800 1,500 - 1,750 250 - 350 700 - 850 1,000 - 1,100 $1,830 - 2,255 $1,830 - 2,255 $2,015 - 2,580 $2,015 - 2,580 1,850 - 2,150 2,200 - 2,600 |
| Strong Operating Cash Flow Growth & Increasing Investment Opportunities Consolidated 2003 2004 2005 2006 2007 2008 Cap Ex-Low 790 1415 2200 1775 1575 Cap Ex-High 790 1415 2400 1975 1825 CFFO-Low 588 1472 1450 1500 2000 2425 CFFO-High 588 1472 1450 1800 2300 2825 Debt to Cap 0.75 0.623 0.586 0.56 0.54 0.51 0.75 0.623 0.586 0.58 0.56 0.53 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,472 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 3 Includes Purchases of Long-term Investments 62% 56% to 58% 54% to 56% $790 Opportunity Rich Declining Debt / Cap % $2,425 to $2,825 59% 51% to 53% $1,415 3 $1,450 $1,575 to $1,825 $1,775 to $1,975 Cap Ex Increasing Cash Flow $1,500 to $1,800 $2,200 to $2,400 $2,000 to $2,300 |
| Financial Strategy/Key Points Drive/enable sustainable growth in EVA(r) / shareholder value Strategy to accelerate delivery of MLP benfits to WMB Continue to maintain and/or improve credit ratios/ratings Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA(r) -adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA(r) drives value creation Consolidated |
| Summary Steve Malcolm Chairman, President & CEO |
| Summary Execution of strategy delivers very strong 2Q Nearly DOUBLED recurring income after removing mark-to-market effect Raising profit guidance for '06, '07 and '08 19% jump up in guidance for '06 key earnings measure* Boosting planned capital expenditures to develop reserves MLP strategy to accelerate delivery of benefits to Williams *Recurring income from continuing operations after mark-to-market adjustment |
| Q&A |
| Non-GAAP Reconciliations |
| 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), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company's results from ongoing operations. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company's assets and the cash that the business is generating. Neither EBITDA nor recurring earnings and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. Certain financial information in this presentation is also shown including Power mark-to-market adjustments. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company's stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power's portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power's results on a basis that is more consistent with Power's portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to- market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment. |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings (Loss) (UNAUDITED) (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr Year Income from continuing operations available to common stockholders $202.2 $40.7 $5.7 $68.8 $317.4 $131.1 ($63.9) $67.2 Income (loss) from continuing operations - diluted earnings (loss) per common share $0.34 $0.07 $0.01 $0.11 $0.53 $0.22 ($0.11) $0.11 Nonrecurring items: Exploration & Production Gain on sale of E&P properties (7.9) - - (21.7) - - (29.6) - - - - - - Loss provision related to an ownership dispute 0.3 - - - - - - 0.3 - - - - - - Total Exploration & Production nonrecurring items (7.6) - - (21.7) - - (29.3) - - - - - - Gas Pipeline Prior period liability corrections - TGPL (13.1) (4.6) - - - - (17.7) - - - - - - Prior period pension adjustment - TGPL - - (17.1) - - - - (17.1) - - - - - - Income from favorable ruling on FERC appeal (1999 Fuel Tracker) - - - - (14.2) - - (14.2) - - - - - - Prior period inventory corrections - TGPL - - - - - - 27.5 27.5 - - - - - - Accrual of contingent refund obligation - TGPL - - - - - - 9.8 9.8 - - - - - - Reversal of litigation contigency due to favorable ruling - TGPL - - - - - - - - - - (2.0) - - (2.0) Total Gas Pipeline nonrecurring items (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) - - (2.0) Midstream Gas & Liquids Accrual for Gulf Liquids litigation contingency - - - - - - - - - - - - 68.0 68.0 Settlement of an international contract dispute - - - - - - - - - - (6.3) - - (6.3) Total Midstream Gas & Liquids nonrecurring items - - - - - - - - - - (6.3) 68.0 61.7 Power Accrual for a regulatory settlement (1) 4.6 - - - - - - 4.6 - - - - - - Accrual for litigation contingencies (1) - - 13.1 0.4 68.7 82.2 - - - - - - Impairment of Aux Sable - - - - - - 23.0 23.0 - - - - - - Prior period correction 6.8 - - - - - - 6.8 - - - - - - Total Power nonrecurring items 11.4 13.1 0.4 91.7 116.6 - - - - - - Other Impairment of Longhorn - - 49.1 - - 38.1 87.2 - - - - - - Write-off of capitalized project development costs - - 4.0 - - - - 4.0 - - - - - - Gain on sale of real property - - - - - - (9.0) (9.0) - - - - - - Total Other nonrecurring items - - 53.1 - - 29.1 82.2 - - - - - - Nonrecurring items included in segment profit (loss) (9.3) 44.5 (35.5) 158.1 157.8 (8.3) 68.0 59.7 Nonrecurring items below segment profit (loss) Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss - Midstream) - - (8.6) - - - - (8.6) - - - - - - Loss provision related to an ownership dispute - interest component (Interest accrued - Exploration & Production) 2.7 - - - - - - 2.7 - - - - - - Directors and officers insurance policy adjustment (General corporate expenses - Corporate) - - - - 13.8 - - 13.8 - - - - - - Loss provision related to ERISA litigation settlement (Other income (expense) - net - Corporate) - - - - 5.0 - - 5.0 - - - - - - Securities litigation settlement and related costs (1) - - - - - - 9.4 9.4 1.2 160.7 161.9 Reversal of interest accrual related to reversal of litigation contingency noted above (Interest accrued - Gas Pipeline - TGPL) - - - - - - - - - - (5.0) - - (5.0) Early debt retirement costs (Corporate and Exploration & Production) - - - - - - - - - - 27.0 (1) 4.4 31.4 Gain on sale of Algar/Triangulo shares (Investing income / loss - Other) - - - - - - - - - - (6.7) - - (6.7) Interest related to Gulf Liquids litigation contingency ( Interest accrued - Midstream) - - - - - - - - - - - - 20.0 20.0 2.7 (8.6) 18.8 9.4 22.3 16.5 185.1 201.6 Total nonrecurring items (6.6) 35.9 (16.7) 167.5 180.1 8.2 253.1 261.3 Tax effect for above items (1) (2.8) 10.7 (6.4) 48.0 49.5 3.4 76.6 80.0 Adjustment for nonrecurring excess deferred tax benefit - - - - - - (20.2) (20.2) - - - - - - Recurring income (loss) from continuing operations available to common stockholders $198.4 $65.9 ($4.6) $168.1 $427.8 $135.9 $112.6 $248.5 Recurring diluted earnings (loss) per common share $0.33 $0.11 ($0.01) $0.28 $0.72 $0.23 $0.19 $0.42 Weighted-average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 607,073 595,561 598,634 2005 2006 (1) No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million and $42 million of the accrual for litigation contingencies in 2nd quarter 2005 and 4th quarter 2005, respectively. The tax rate applied to Midstream's international contract dispute settlement in 1st quarter 2006 is 34%. The tax rate applied to nonrecurring items for 2nd quarter 2006 has been adjusted for the effect of nondeductible expenses associated with securities litigation settlement and related costs and early debt retirement costs related to our convertible debt. Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding. |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation Reconciliation of Segment Profit to Recurring Segment Profit (UNAUDITED) (Dollars in millions) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr Year Segment profit (loss): Exploration & Production 103.7 $ 118.3 $ 158.8 $ 206.4 $ 587.2 $ 147.6 $ 119.8 $ 267.4 $ Gas Pipeline 167.4 164.5 161.1 92.8 585.8 134.7 122.7 257.4 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 151.5 130.7 282.2 Power 114.1 (75.0) (226.4) (69.4) (256.7) (22.5) (79.6) (102.1) Other (4.1) (60.5) (10.1) (30.3) (105.0) 1.0 (0.7) 0.3 Total segment profit 509.7 $ 256.4 $ 204.5 $ 311.9 $ 1,282.5 $ 412.3 $ 292.9 $ 705.2 $ Nonrecurring adjustments: Exploration & Production (7.6) $ - - $ (21.7) $ - - $ (29.3) $ - - $ - - $ - - $ Gas Pipeline (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) - - (2.0) Midstream Gas & Liquids - - - - - - - - - - (6.3) 68.0 61.7 Power 11.4 13.1 0.4 91.7 116.6 - - - - - - Other - - 53.1 - - 29.1 82.2 - - - - - - Total segment nonrecurring adjustments (9.3) $ 44.5 $ (35.5) $ 158.1 $ 157.8 $ (8.3) $ 68.0 $ 59.7 $ Recurring segment profit (loss): Exploration & Production 96.1 118.3 137.1 206.4 557.9 147.6 119.8 267.4 Gas Pipeline 154.3 142.8 146.9 130.1 574.1 132.7 122.7 255.4 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 145.2 198.7 343.9 Power 125.5 (61.9) (226.0) 22.3 (140.1) (22.5) (79.6) (102.1) Other (4.1) (7.4) (10.1) (1.2) (22.8) 1.0 (0.7) 0.3 Total recurring segment profit 500.4 $ 300.9 $ 169.0 $ 470.0 $ 1,440.3 $ 404.0 $ 360.9 $ 764.9 $ Note: Segment profit (loss) includes equity earnings (loss) and certain income (loss) from investments reported in Investing income (loss) in the Consolidated Statement of Operations. Equity earnings (loss) results from investments accounted for under the equity method. Income (loss) from investments results from the management of certain equity investments. 2005 2006 |
| Non-GAAP Reconciliation Schedule - EPS after MTM adjustment Non-GAAP Reconciliation Dollars in millions except per share amounts 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 136 $ 113 $ 249 $ Recurring diluted earnings per common share 0.23 $ 0.19 $ 0.42 $ Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (43) 38 (5) Add realized gains/losses from MTM previously recognized 77 100 177 Total MTM adjustments 34 138 172 Tax effect of total MTM adjustments 13 53 66 After tax MTM adjustments 21 85 106 Recurring income from cont. ops available to common shareholders after MTM adjust. 157 $ 198 $ 355 $ Recurring diluted earnings per share after MTM adj. 0.26 $ 0.33 $ 0.59 $ weighted average shares - diluted (thousands) 607,073 595,561 598,634 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 198 $ 66 $ (5) $ 168 $ 428 $ Recurring diluted earnings per common share 0.33 $ 0.11 $ (0.01) $ 0.28 $ 0.72 $ Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (221) (22) 141 (70) (172) Add realized gains/losses from MTM previously recognized 113 77 72 48 310 Total MTM adjustments (108) 55 213 (22) 138 Tax effect of total MTM adjustments (42) 21 83 (8) 53 After tax MTM adjustments (66) 34 130 (14) 85 Recurring income from cont. ops available to common shareholders after MTM adjust. 132 $ 100 $ 125 $ 154 $ 513 $ Recurring diluted earnings per share after MTM adj. 0.22 $ 0.17 $ 0.22 $ 0.26 $ 0.86 $ weighted average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 2005 2006 |
| EBITDA Reconciliation Non-GAAP Reconciliation Dollars in millions 2Q06 YTD Net Income (Loss) (76) $ 56 $ Loss from Discontinued Operations 12 11 Net Interest Expense 178 337 DD&A 210 408 Provision for Income Taxes 1 89 EBITDA 325 $ 901 $ |
| 2Q 2006 Segment Contribution Non-GAAP Reconciliation Dollars in Millions Corp/ E&P Midstream Gas Pipeline Power Other Total Segment Profit (Loss) 120 $ 131 $ 123 $ (80) $ (1) $ 293 $ DD&A 84 50 71 3 2 210 Segment Profit before DDA 204 $ 181 $ 194 $ (77) $ 1 $ 503 $ General corporate expenses (34) Securities litigation settlement and related costs (161) Investing income* 21 Other income (4) TOTAL 325 $ * Excluding equity earnings and income (loss) from investments contained in segment profit |
| 2006 Forecast EBITDA Reconciliation Non-GAAP Reconciliation Net Income $228 - 383 $308 - 468 Loss from Disc. Ops. 5 - 0 5 - 0 Net Interest 670 - 710 665 - 705 DD&A 820 - 920 790 - 890 Provision for Income Taxes 185 - 295 210 - 320 Other/Rounding (8) (3) - (8) EBITDA $1,900 - 2,300 $1,975 - 2,375 MTM Adjustments 275 255 EBITDA - After MTM Adj. $2,175 - 2,575 $2,230 - 2,630 Dollars in millions Aug 3 Guidance May 4 Guidance |
| 2006 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 $(200) - (150) 10 - 20 $(190) - (130) Gas Pipeline $475 - 520 280 - 300 $755 - 820 Segment Profit (Loss) DD&A Segment Profit Before DDA Other (Primarily General Corporate Expense & Investing Income) Securities Litigation Settlement and Related Costs Rounding TOTAL E&P $550 - 650 360 - 400 $910 - 1,050 Midstream $550 - 675 190 - 200 $740 - 875 Total $1,355 - 1,675 820 - 920 $2,175 - 2,595 (105) - (125) (162) (8) $1,900 - 2,300 Corp/ Other $(20) (20) - 0 $(40) - (20) Dollars in millions 1 Segment Profit is prior to MTM adjustments |
| 2006 Forecast Guidance Contribution Non-GAAP Reconciliation Net Income $228 - 383 $308 - 468 Less: Discontinued Operations (Loss) (5) - 0 (5) - 0 Income from Continuing Ops $233 - 383 $313 - 468 Non-Recurring Items (Pretax) 261 8 Less Taxes 80 3 Non-Recurring After Tax 181 5 Recurring Income from Cont. Ops $414 - 564 $318 - 473 Recurring EPS $0.68 - $0.92 $0.52 - $0.78 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Cont. Ops after MTM Adj. EPS 275 107 168 $582 - 732 $0.95 - $1.20 255 99 156 $474 - 629 $0.78 - $1.03 Dollars in millions, except per-share amounts May 4 Guidance Aug 3 Guidance |
| Appendix |
| Rockies Producer Not Rockies Price Taker Exploration & Production Powder River Piceance San Juan Glenrock Opal Wamsutter Cheyenne Greasewood Blanco Meeker CIG NWPL Questar Rockies Express TransColorado WIC Pipes Used to Move Williams ' Gas Trailblazer Firm Access Under Contract North to Wamsutter 200 East to Mid - -continent 209 South to San Juan 285 East to Appalachia (REX) 200 West to Opal 150 2008 - - 2009 adds |
| Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) Reflective of core basins $5.65 is after hedging and includes average basin market price of $6.41 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include acquisition and development expenditures/proved reserves ('03-'05 average) $5.55 Previous Previous $3.82 $1.73 Cash Margin Cash Costs $5.65 $1.75 $0.92 $3.90 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs |
| 2Q Net Realized Price Summary Exploration & Production Unhedged Hedge Market Price: NYMEX including collars $6.90 - $7.20 4.53 Basis Differential (1.40 - 1.60) (0.57) Net basin market price $5.30 - $5.80 $3.96 Net basin market price $5.30 - $5.80 $3.96 Fuel & Shrinkage/Gathering/ (0.60 - 0.80) (0.50 - 0.60) Transportation Net Price $4.50 - $5.20 $3.36 - $3.46 Quarter Volume Totals (qtr daily volumes (qtr daily - - qtr daily volumes) hedge volumes) x (91/1000) x (91/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price) 2Q '06 |
| 2006 2007 2008 Fixed Price at the basin: Volume (MMcf/d) 297 172 73 Average Price ($/Mcf) $3.84 $3.90 $3.96 NYMEX Collars: Volume (MMcf/d) 64 15 - Average Price ($/Mcf) $6.62 - $8.42 $6.50 - $8.25 At the Basin Collars:1 NWPL Rockies Volume (MMcf/d) 50 50 75 Price ($/Mcf) $6.05 - $7.90 $5.65 - $7.45 $6.02 - $9.52 EPNG San Juan Volume (MMcf/d) - 130 25 Average Price ($/Mcf) $5.98 - $9.63 $6.20 - 9.57 Mid-Continent Volume (MMcf/d) - 70 - Price ($/Mcf) $6.78 - $10.89 2006-08 Hedge Update Exploration & Production Dollars in millions 1 Please note basin locations are not NYMEX 3Q-4Q |
| Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING E&P Opportunities - Previously Announced Piceance Basin: Shale Ridge Prospect (Dakota Sandstone play) Leased 13,904 gross/net acres 100% WI; 87.5% NRI 10-year lease term Uinta Basin: Sterling Hollow Prospect (Mesaverde tight gas sands play) Leased 39,911 contiguous gross/net acres 100% WI; 87.5% NRI 10-year lease term Paradox Basin: Resource Play (Ismay Group shales and tight gas sandstones) Leased 30,608 gross/net acres 100% WI; 87.5% NRI 5-year and 10-year terms on leases Exploration & Production |
| Exploration & Production Piceance Highlands - Results to Date Project Area Wells Drilled and Completed Average 30 Day Rate/Completed Well (MMcfed) Expected EUR* Range (Bcfe/well) Trail Ridge 18 1.2 1.2 - 1.8 West Grand Valley 2 1.3 1.2 - 1.8 Ryan Gulch 14 1.2 1.2 - 2.0 Allen Point 6 1.2 1.2 - 1.6 * Estimated Ultimate Recovery |
| Exploration & Production Piceance Highlands Project Summary Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (Bcfe) 2004 Wells 2005 Wells Projected 2006 Wells Trail Ridge (10-acre density) 21,512 1,500 1,500-2,000 3 12 20 West Grand Valley (10-acre density) 1,080 90 80 1 1 0 Ryan Gulch (40-acre density) 16,078 800 700 3 5 22* Allen Point (40-acre density) 6,240 200 140 0 6 9 Total 44,910 2,590 2,420-2,920 7 24 51 * 3 wells non-operated |
| Pricing Assumptions Included in Guidance Midstream Historic Prices Guidance Pricing Assumptions 0 10 20 30 40 50 60 70 80 90 '00 '01 '02 '03 '04 '05 1Q06 2Q06 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu Oil WTI ($/bbl) Nat Gas Henry Hub ($/MMBtu) 0 10 20 30 40 50 60 70 80 90 3Q-4Q06 2007 2008 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu High Oil Low Oil Nat Gas Henry Hub ($/MMBtu) |
| Margins Above Average Midstream Note: Actual realized margins, does not include Discovery volumes. Five year average of 13.2 cpg is calculated for the period 3Q01-2Q06. Domestic NGL Average Realized Net Margin and Volumes by Quarter Realized Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin 0 5 10 15 20 25 30 35 Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Q2'05 Q3'05 Q4'05 Q1'06 Q2'06 0 100 200 300 400 500 600 700 800 Realized Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) |
| 2006 Accomplishments Northwest: Filed rate case on June 30, 2006. The anticipated effective date is January 1, 2007 Open season begins for long-term firm transportation service for Greasewood Lateral expansion FERC certificate application filed for Jackson Prairie Expansion Completed $175 million offering of senior unsecured notes due 2016 Transco: Leidy to Long Island Expansion project receives FERC approval FERC certificate application filed for Potomac Expansion Completed $200 million offering of senior unsecured notes due 2016 Gulfstream: Executed agreement with Progress Energy to provide 155 MDth/d to its Bartow Power Plant with the Gulfstream Phase IV expansion project Gas Pipeline Recurring Segment Profit + Depreciation 0 50 100 150 200 250 1Q 2Q 3Q 4Q 2005 2006 |
| 2006-08 Guidance 2006 2007 2008 Segment Profit $475 - 520 $585 - 655 $590 - 665 Annual DD&A 280 - 300 290 - 310 295 - 315 Segment Profit + DD&A $755 - 820 $875 - 965 $885 - 980 Capital Spending $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/06 is shown in italics directly below. Gas Pipeline 390 - 490 410 - 510 710 - 785 |
| 2006-08 Capital Spending Detail 2006 2007 2008 Normal Maintenance/Compliance $375 - 435 $210 - 265 $180 - 260 Northwest 26-inch Replacement 276 2 - Expansion1 95 - 105 160 - 200 160 - 180 Total $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/06 is shown in italics directly below. Gas Pipeline Note: - Sum of ranges may not necessarily match total range 1Major Growth Projects (in guidance): 2006 2007 2008 1st full yr Seg. Profit Parachute (In Service 1/07) $55 - 65 $9 Leidy to Long Island (In Service11/07) 10 - 15 $85 - 100 $1 - 5 20 Potomac (In Service 11/07) 5 - 10 55 - 65 1 - 5 11 Sentinel (In Service 11/08) 1 - 5 5 - 15 110 - 130 22 Greasewood (In Service 11/08) 25 - 30 5 180 - 220 230 - 250 390 - 490 410 - 510 340 - 405 710 - 785 |
| Sentinel Nov 2008 Growth Projects and Opportunities Update Gulfstream Phase IV Jan 2009 Leidy to Long Island Nov 2007 Potomac Nov 2007 Parachute Jan 2007 Pacific Connector Pipeline Late 2010 Greasewood Nov 2008 Jackson Prairie Nov 2008 Gas Pipeline Gulfstream Phase III Summer 2008 Equity Investments |
| Design - 360 MMcfd Scope of Work Approx. 80 miles of 36" pipeline 10,760 net horsepower added Station Modifications 268 miles of 26" pipeline retired Capital Costs on target - $333 MM Schedule FERC Certificate - 9/2005 Start HDD - 10/2005 Sta. & P/L Mobilized - 5/2006 Construction - Summer 2006 In-service - 11/ 2006 (In rates - 1/2007) Capacity Replacement Project on Track Gas Pipeline |
| Key Points 26-inch Replacement on target to be in-service November 1st Growth projects progressing Rate Case filings continue on target Northwest filed Jun 30th, effective Jan 1st Transco to file Aug 31st, effective Mar 1st Gas Pipeline |
| Long-term Free Cash Flow Gas Pipeline Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2006 - 2008. 2005 2006 2007 2008 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion 26-inch Replacement Maint/Compliance 0 100 200 300 400 500 600 700 800 900 1000 |
| Dollars in millions 2006 2007 2008 Prior Guidance - Segment Loss before MTM Adj ($205) - (105) ($165) - (15) ($165) - (15) Est. Fwd Impact of 2Q06 MTM Earnings and other portolio adjustments New Guidance - Segment Loss before MTM Adj ($200) - (150) ($175) - (75) ($155) - (5) ($205) - (105) ($165) - (15) ($165) - (15) Estimated MTM Adjustments 275 225 205 255 215 215 Segment Profit after MTM Adj 75 - 125 50 - 150 50 - 200 Recurring Segment Profit after MTM Adj $75 - 125 $50 - 150 $50 - 200 $50 - 150 $50 - 200 Capital Expenditures - - - - - - $5 - (45) ($10) - (60) $10 - 10 2006-08 Guidance Note: If guidance has changed, previous guidance from 5/04/06 is shown in italics directly below. Power |
| YTD 2006 - Segment Profit/(Loss) to Cash Flow from Ops Power 1Significant amount of Working Capital used was returned to two counterparties due to commodity settlements and commodity price changes. 2Collateral returned does not impact total WMB liquidity because collateral received is excluded from calculation of available WMB liquidity. 3CFFO includes cash margin dollars sent out on behalf of other business units. Dollars in Millions Commodity Working Power Capital/ & NG Other Total Segment Loss ($88) ($14) ($102) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (4) (4) Add Realized Gains from MTM Previously Recognized 177 177 Segment Profit/(Loss) After MTM Adjustments 85 (14) 71 Total Working Capital Change 1,2&3 (324) (324) Power Segment CFFO $85 ($338) ($253) |
| Power Portfolio Cash Flow Analysis Estimated undiscounted dollars in millions 1 Q206 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. Q206 forecast combines Hedged Cash Flow and Merchant Cash Flow estimates to present comparable to actual. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. 4 YTD SG&A includes $24 million gain related to sale of certain Enron receivables 5 Working Capital & Other changes are zero in future periods, as they are not reasonable estimable. Note: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Power Power Portfolio Actual vs. Forecast 2006 2Q06A 2Q06F YTD06A YTD06F 2006A+F 2007F 2008F Tolling Demand Payment Obligations ($96) ($99) $3 ($182) ($185) $3 ($397) ($406) ($412) Hedged Cash Flows 2 576 476 496 Merchant Cash Flows 3 31 89 78 SG&A and Other 4 (20) (21) 1 (19) (42) 23 (64) (85) (80) Total Power Portfolio Cash Flows $35 $40 ($5) $81 $69 $12 $146 $74 $82 Working Capital & Other 5 (288) n/a (334) n/a n/a n/a n/a Estimated Power Segment Cash Flows ($253) ($253) YTD Variance 282 1 (14) 296 QTD Variance 151 1 160 (9) |
| 2Q06 Financial Statement Changes for Derivatives Power During 2Q06, Williams reported the following changes related to its derivative portfolio: The net change in Derivative Assets and Liabilities for E&P was positive reflecting the 2Q06 decrease in gas prices against a short derivative position The net change in Derivative Assets and Liabilities for Midstream was negative reflecting the 2Q06 price increase on crude and NGL's against a short derivative position The net change in Derivative Assets and Liabilities for Power was negative, reflecting the 2Q06 decrease in gas prices against a long derivative position 1 Change in OCI shown is before taxes. Therefore, change shown does not tie to balance sheet change which is net of taxes. Dollars in millions Der A/L OCI MTM Gain/(Loss) Realized (Gain)/Loss Total Change in Consolidated Derivative Values 1 ($60) $45 ($33) ($72) Less change in Option Premiums/Prudency/Other (1) (1) Remaining Change in Consolidated Derivative Values ($59) $45 ($33) ($71) Change in E&P Hedge Values 135 86 6 - Prior MTM Realized (Ineffectiveness) (7) - OCI Realized 50 Change in Midstream Hedge Values (21) (21) - Prior MTM Realized (0) - OCI Realized (0) Change in Power Hedge Values (173) (20) (39) - Prior MTM Realized (100) - OCI Realized (14) Balance Sheet Income Statement |
| West Undiscounted Cash Flows Power Dollars in millions 1 Q206 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. West Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($38) ($38) $0 ($154) ($157) ($159) Hedged Cash Flows 2 439 376 355 Merchant Cash Flows 3 (3) 9 9 Total Cash Flows $79 $68 $11 $282 $228 $205 Capacity Available (in MW) 3,805 3,805 3,805 Total Capacity Sold 2,772 3,329 3,452 Remaining Available (in MW) after all hedges 1,033 476 353 117 1 106 11 |
| Mid-Con Undiscounted Cash Flows Power 1 Q206 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions Mid-Continent Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($21) ($22) $1 ($88) ($89) ($90) Hedged Cash Flows 2 37 49 Merchant Cash Flows 3 22 9 Total Cash Flows ($12) ($11) ($1) ($39) ($30) ($32) Capacity Available (in MW) 1,303 1,303 1,303 Total Capacity Sold 401 346 365 Remaining Available (in MW) after all hedges 902 957 938 (2) 49 1 9 1 11 |
| East Undiscounted Cash Flows Power 1 Q206 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions East Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($36) ($39) $3 ($155) ($160) ($162) Hedged Cash Flows 2 63 90 Merchant Cash Flows 3 59 60 Total Cash Flows ($12) $2 ($14) ($32) ($38) ($12) Capacity Available (in MW) 2,280 2,280 2,280 Total Capacity Sold 1,561 631 583 Remaining Available (in MW) after all hedges 719 1,649 1,697 (17) 123 1 25 1 42 |
| WMB Collateral Outstanding Enterprise Risk Management $ $ $ $ $ As of 6/30/06 Corp./ Dollars in millions E&P Midstream Power Other Total Margins & Ad. Assur. $224 $0 $18 $0 $242 Prepayments 0 0 11 0 11 Subtotal 224 0 29 0 253 Letters of Credit 387 109 397 65 958 Total as of 6/30/06 611 109 426 65 1211 Total as of 12/31/05 746 243 343 91 1423 Change ($135) ($134) $83 ($26) ($212) |
| WMB Collateral Sensitivity Enterprise Risk Management Dollars in millions Margin Volatility (1% chance of exceeding) -Potential incremental collateral requirement Days 6/30/2006 3/31/2006 12/30/2005 9/30/2005 30 ($246) ($223) ($325) ($469) 180 ($580) ($769) ($559) ($868) 360 ($489) ($626) ($567) ($926) Assumption: The Margin numbers above consist of only forward marginable positions. |
| 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 2006 $0-$2 MM $0-$2 MM $3-$8 MM 2007 $6-$9 MM $3.5-$5.5 MM $11-$16 MM 2008 $25-$28 MM $6-$8 MM $10-$15 MM |
| Natural Gas Outright Position Enterprise Risk Management - -500,000 - -400,000 - -300,000 - -200,000 - -100,000 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 2006 2007 2008 E&P Gross Position E&P Net Position Midstream Fuel & Shrink Enterprise Net Position MMBtu/Day |
| 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 @ 06/30/06 $7,309 7.7% Variable Rate Debt @ 06/30/06 $154 6.1% Consolidated Additions 699 Early Retirements (485) Scheduled Debt Retirements & Amortization (180) Debt Balance @ 6/30/06 $7,463 7.7% |
| Dollars in millions Debt Amortization - As of 6/30/2006 Consolidated 49 392 239 54 217 1168 80 22 1,850 2,020 998 385 8 10 $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019-2027 2028-2032 2033 |
| Diluted EPS from Cont. Ops. $0.22 ($.11) - - $0.11 Recurring EPS 0.23 0.19 - - 0.42 Recurring EPS after MTM Adj. 0.26 0.33 - - 0.59 Average Shares (MM) 607 596 - - 599 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 (0.01) 0.28 0.72 Recurring EPS after MTM Adj. 0.22 0.17 0.22 0.26 0.86 Average Shares (MM) 599 579 581 609 606 2005 1Q 2Q 3Q 4Q Total EPS Metrics Consolidated |
| 2006 Interest Expense Forecast Guidance Consolidated Interest on Long-Term Debt $570 - $590 Amortization Discount/Premium and other Debt Expense 25 - 30 Credit Facilities: (incl. Commitment Fees plus LC Usage) 40 - 50 Interest on other Liabilities 43 - 53 Interest Expense $678 - $723 Less: Capitalized Interest (8) - (13) Net Interest Expense Guidance $670 - $710 Dollars in millions 2006 |
| 2006 Effective Tax Rates Consolidated Statutory Rate 77 35% (22) 35% 55 35% State 10 5% (1) 1% 9 6% Foreign 0 0% 7 - -10% 7 4% Nondeductible Expenses (Shareholder Litigation/Convertible Debentures) 0 0% 18 - -28% 18 12% Other 1 0% (1) 1% 0 0% Tax Provision/(Benefit) 88 40% 1 - -1% 89 57% Effective Tax Rate Guidance 1 Cash Tax Rate Guidance 2 Note 1: Additional income tax expense of $25-35 million in 2006, $10-15 in 2007 and $5-10 million in 2008 is also forecast. Note 2: Discontinued operations in 2006 have an immaterial impact. 2006 First Quarter Second Quarter Year-to-Date 2006 2007 2008 39% 39% 39% 10-15% 5-10% 9-14% |
| The Williams Companies, Inc. |