The Williams Companies, Inc. (WMB) 8-K Williams Announces 34% Increase in 2008 Earnings Guidance

Exhibit 99.2

Williams 2008 Analyst Day June 25, 2008

Agenda Continental Breakfast Welcome & Introductions Travis Campbell Introductory Remarks Steve Malcolm Commodity Outlook Jeff Nevins Exploration & Production Ralph Hill Break Midstream Alan Armstrong Gas Pipeline Phil Wright Corporate Overview Don Chappel Summary Steve Malcolm Lunch WPZ Alan Armstrong, Don Chappel WMZ Phil Wright, Don Chappel Conclusion Steve Malcolm

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 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; Our risk measurement and hedging activities might not prevent losses; Natural gas and 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; 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; Despite our restructuring efforts, we may not maintain 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;

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 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. Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the Securities and Exchange Commission on February 26, 2008, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

Oil and Gas Reserves and Resource Potential Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We have used certain terms in this presentation such as "probable" reserves and "possible" reserves and "unrisked theoretical resource estimates" that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated hydrocarbon 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. Generally under such techniques, probable reserve estimates are more than 50% certain and possible reserve estimates are less than 50% but more than 10% certain. Unrisked theoretical resource estimates are even less certain than those for possible reserves and are not risk adjusted. Unrisked theoretical resource estimates include (i) an estimate of hydrocarbon quantities for new areas for which we do not have sufficient information to date to classify the resources as probable or even possible reserves and (ii) the amount by which we have reduced our probable and possible reserves for existing areas to take into account the reduced level of certainty of recovery of the resources. Unlike probable and possible reserves, unrisked theoretical resource estimates do not take into account the uncertainty of resource recovery and, therefore, are not indicative of the expected future recovery and should not be relied upon. Reference to "Resource Potential" includes proved, probable and possible reserves as well as unrisked theoretical resource estimates that might never be recoverable and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors. Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the Securities and Exchange Commission on Feb. 26, 2008, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Steve Malcolm Chairman, President & CEO Williams

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am 87% 13% Very Small Exposure to Rockies Prices Higher-Priced Markets and Hedges Markets in the Rockies 1Q 2008 domestic production

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams' Powerful Piceance Package Top-Tier Growth Basin in North America Colorado Area Shown Rio Blanco County Garfield County Williams Parachute Lateral Williams PGX Pipeline (NGL) Williams Willow Creek Plant Site Proposed NGL Pipeline to Overland Pass Pipeline Barcus Creek Williams Colorado Hub Connection Ryan Gulch Trail Ridge Allen Point Grand Valley / Rulison

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams' Powerful Piceance Package Largest, most active producer Running 26 rigs Delivering production growth Nearly 9,000 drilling locations 9.2 Tcfe proved, probable and possible reserves Operate ~2,400 wells Highly regarded operator - best practices, innovations Top-Tier Growth Basin in North America Colorado Area Shown Rio Blanco County Garfield County

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams' Powerful Piceance Package Willow Creek cryogenic plant PGX pipeline NGL pipeline to Overland Pass Colorado Area Shown Rio Blanco County Garfield County Largest, most active producer Running 26 rigs Delivering production growth Nearly 9,000 drilling locations 9.2 Tcfe proved, probable and possible reserves Operate ~2,400 wells Highly regarded operator - best practices, innovations Top-Tier Growth Basin in North America

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams' Powerful Piceance Package Adding pipeline takeaway capacity Colorado Hub Connection Sunstone Pipeline Top-Tier Growth Basin in North America Colorado Area Shown Rio Blanco County Garfield County Willow Creek cryogenic plant PGX pipeline NGL pipeline to Overland Pass Largest, most active producer Running 26 rigs Delivering production growth Nearly 9,000 drilling locations 9.2 Tcfe proved, probable and possible reserves Operate ~2,400 wells Highly regarded operator - best practices, innovations

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am What's New Today Raising commodity price forecast Increasing earnings guidance Growing Raising capital expenditure guidance for new growth projects Lining up opportunities to significantly expand our gas-processing business in burgeoning Canadian oil sands Looking farther out on the horizon - acquisition-and-development and new-basin teams Buying back shares; progress on our $1 billion program

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams - The Premier Natural Gas Investment Portfolio of best-in-class natural gas assets in North America Sustainable, organic growth opportunities abound Benefit from favorable commodity markets Growth with discipline - EVA1 focus Pulling levers to create additional shareholder value 1 Williams uses Economic Value Added(r) as the tool to measure its success. EVA measures the value created by a company - specifically the financial return in a given period less the capital charge for that period.

June 2008 Economic Overview Jeff Nevins Vice President, Corporate Planning

Macro Environment Commodity Outlook Global Crude Oil Supply / Demand Outlook North America Natural Gas Supply / Demand Outlook Global LNG Supply / Demand Outlook Rockies Basis Outlook Williams Updated Guidance Commodity Prices Crude (WTI) Henry Hub (NYMEX) Regional Basis Segment Profit / EPS

Global Crude Oil Supply / Demand Outlook Production Capacity Demand 2008 16.7 2008 25.3 2013 18.3 2013 25.8 Asia's Thirst for Oil and Ability to Pay for It Will Likely Keep World Oil Markets Moderately Tight Through 2013 Commodity Outlook World Oil Productive Capacity vs. Demand Estimates (mmbpd) North America Capacity Demand 2008 2013 Production Capacity Demand 2008 7.9 2008 5.7 2013 8.4 2013 6.2 Latin America Capacity Demand Production Capacity Demand 2008 27.5 2008 6.8 2013 32.4 2013 7.7 Middle East Capacity Demand Production Capacity Demand 2008 5 2008 16 2013 4.3 2013 15.6 Europe Capacity Demand Production Capacity Demand 2008 10.6 2008 3.1 2013 11.2 2013 3.5 Africa Capacity Demand Production Capacity Demand 2008 13.1 2008 4.2 2013 15.2 2013 4.5 Former Soviet Union Capacity Demand Production Capacity Demand 2008 88.9 2008 86.9 2013 97.3 2013 92.4 Capacity Demand Total World Production Capacity Demand 2008 8.1 2008 25.7 2013 7.7 2013 29 Asia Capacity Demand

2008 2013 Spare Capacity 2.01 4.95 Global Oil Supply / Demand Growth Historical Annual Average of 3.1 Commodity Outlook Global Oil Supplies Are Expected to Expand by Over 8 mmbpd by 2013, Increasing World Spare Oil Capacity by 3 mmbpd Spare Capacity Estimates World Oil Supply and Demand Growth 2008-2013 Supply Non-OPEC Supplies Disappoint Geo-Politics Labor & Material Costs OPEC Bio-Fuels Oil Price Demand Conservation/ Efficiency Global Credit Crunch Rising Interest Rates Climate Change mmbpd

North America Natural Gas Supply / Demand Outlook Commodity Outlook Despite the Recent Surge in US Domestic Natural Gas Supplies, North America Will Still Need Twice the Amount of LNG That it is Importing Today by 2013 US & Canada Supply vs. Demand Estimates (bcfd) Production Capacity Demand 2008 68.7 2008 71.9 2013 67.7 2013 74.3 Supply Demand Total North America Production Capacity Demand 2008 15.7 2008 7.9 2013 13.7 2013 8.7 Canada Supply Demand 2008 2013 Production Capacity Demand 2008 45.1 2008 18.6 2013 46.6 2013 19 West Supply Demand Production Capacity Demand 2008 3.8 2008 33.3 2013 3.9 2013 34.1 East Supply Demand Production Capacity Demand 2008 14.6 2008 12.2 2013 15.1 2013 12.5 Gulf/MidCon Supply Demand

Global LNG Supply / Demand Outlook $18.00 to $20.00 $13.00 to $15.00 $10.20 to $10.60 Commodity Outlook Ample Storage Supplies and Growing US Natural Gas Production Should Allow North American Natural Gas Prices to Maintain a Discount to Oil Indexed Asian/European Cargoes Demand 2008 25.8 2013 38.8 2008 Global LNG Demand 2013 All prices nominal US$ per mmbtu 2008 2013 Demand 2008 2.4 2013 6.2 North America Demand 2008 6.6 2013 11.3 Europe Demand 2008 15.5 2013 19 Asia 1 2 3 (bcfd)

Climate Change Mandate Scenario vs. Base Case Base Case Supply Growth 2008-2013 Base Case Demand Growth 2008-2013 Climate Change Mandate Additional Demand Price assumptions to divert volumes away from... Commodity Outlook By 2013, a Climate Change Mandate Would Significantly Increase US Dependence on LNG and Hence Pull US Natural Gas Prices Up Closer to Oil Based Index Price Levels All prices nominal US$ per mmbtu US Total & LNG Imports Demand Base 1.5 0.5 Climate ch 0 0.8 West 2008-2013 Growth (bcfd) Demand Base 0.5 0.3 Climate ch 0 0.6 Gulf/MidCon Demand Base 0.1 0.8 Climate ch 0 1.6 East LNG Imports Demand Base 3.4 Climate ch 0 3 6.4 3.0 3.4 Asia $18.00 to $20.00 Europe $13.00 to $15.00 1 2 3 US Total Demand Base 2.1 1.6 Climate ch 0 3 4.6 2.1 1.6 3.0

Rockies Basis Outlook Commodity Outlook Incremental Natural Gas Demand Caused by Modest Climate Change Mandate Pulls Rockies Production to Coal Intensive US Midwest, and Declining Western Canadian Imports to US West Coast Pulls Rockies Production Westward 1.5 bcfd pipeline - Rockies to the West Coast by 2011 REX Phase III - to come online in June 2009 and add 1.8 bcfd of capacity (to Covington, OH) 0.75 bcfd pipeline - Rockies to the upper Midwest by 2010 Upside Rockies production should support increased REX pipeline capacity Fundamentals Support New Pipeline Projects to the West Coast and Upper Midwest Rockies Production Up 6% Annually

Economic Indicators Base Case Economic Assumptions US & Western Europe continue to depend on Asia and oil exporting countries for imports of goods, services and energy Global GDP remains strong @ 3.6% average growth through 2013 US GDP moderate growth @ 2.7% average growth through 2013 US Headline Inflation slightly above trend @ 2.4% average through 2013 Commodity Outlook Crude Oil Natural Gas Rockies Asia resolves temporary inflation Oil exporting countries increase oil productive capacity enough to discourage additional alternative fuels development Global oil demand growth: 1.2% Global oil supply growth: 1.1% Global spare oil capacity: 3.8 MMbpd Token climate change Non-OPEC supplies grow, but struggle Modest climate change is implemented to protect US coal industry US demand growth is driven by the growing electric power demand: Power generation, 18.5 - 21.2 bcfd: +3% US supply is being impacted by: US production, 53 - 54 bcfd: +.47% LNG Imports, 2.4 - 5.8 bcfd: +28.3% Canadian Imports, 8.1 - 5.9 bcfd: (-5.4%) Incremental natural gas demand caused by modest Climate Change Mandate pulls Rockies production to coal intensive Midwest Declining Western Canadian imports pulls Rockies production westward Fundamentals support new pipeline projects to the West Coast and Upper Midwest

Commodity Price Changes (2008) 7 7.5 8 8.5 9 9.5 10 10.5 11 80 Crude Oil - WTI Natural Gas - NYMEX Previous Guidance Range (May 1, 2008) Commodity Outlook Un-hedged Commodity Price Assumptions 2008 2008 Un-hedged Commodity Price Assumptions Previous Range New Range Natural Gas - Henry Hub (NYMEX) (reference only) $7.35 - $8.65 $9.00 - $10.50 Crude Oil - WTI (reference only) $70 - $90 $100 - $120 $100 Oil & $9.00 Gas $120 Oil & $10.50 Gas New Guidance Range

Commodity Price Changes (2009) 7 7.5 8 8.5 9 9.5 10 10.5 11 80 Crude Oil - WTI Natural Gas - NYMEX Previous Guidance Range (May 1, 2008) Commodity Outlook Un-hedged Commodity Price Assumptions 2009 2009 Un-hedged Commodity Price Assumptions Previous Range New Range Natural Gas - Henry Hub (NYMEX) (reference only) $7.35 - $8.65 $8.00 - $10.50 Crude Oil - WTI (reference only) $70 - $90 $80 - $120 $80 Oil & $8.50 Gas $120 Oil & $10.50 Gas New Guidance Range

Oil & Gas History / NYMEX Forward Curve1 Commodity Outlook J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D 63.15 51.13 58.07 56.73 63.38 64.97 68.19 75.57 69.47 83.32 87.56 95.1 90.49 89.85 100.74 104.48 119.37 129.06 134.01 134.53 135.02 135.33 135.54 135.7 135.77 135.78 135.73 135.63 135.49 135.34 135.19 135.05 134.91 134.78 134.67 134.61 5.838 6.917 7.547 7.558 7.508 7.591 6.929 6.11 5.43 6.423 7.269 7.203 7.172 8 8.93 9.578 11.28 11.916 11.969 12.063 12.077 12.144 12.359 12.699 12.909 12.864 12.614 10.649 10.489 10.557 10.645 10.702 10.717 10.779 11.029 11.394 $ / bbl Crude Oil - WTI 1 Actuals through June 2008, NYMEX Forward Curve as of 6/17/08 for Jul 2008-Dec 2009 2007 2008 2009 J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D 63.15 51.13 58.07 56.73 63.38 64.97 68.19 75.57 69.47 83.32 87.56 95.1 90.49 89.85 100.74 104.48 119.37 129.06 134.01 134.53 135.02 135.33 135.54 135.7 135.77 135.78 135.73 135.63 135.49 135.34 135.19 135.05 134.91 134.78 134.67 134.61 5.838 6.917 7.547 7.558 7.508 7.591 6.929 6.11 5.43 6.423 7.269 7.203 7.172 8 8.93 9.578 11.28 11.916 12.952 13.055 13.084 13.152 13.392 13.732 13.927 13.86 13.59 11.4 11.217 11.287 11.379 11.439 11.457 11.53 11.765 12.125 $ / Btu Natural Gas - NYMEX Henry Hub Guidance Range $8.00 - $10.50 2007 2008 2009 Guidance Range $9.00 - $10.50 Guidance Range $80 - $120 Guidance Range $100 - $120

Rockies Basis Overview1 Commodity Outlook J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J Avg 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.4652 1.0826 1.1634 1.5197 1.1993 0.9528 0.8239 1.2426 1.4033 1.0984 2.5735 1.9544 0.5489 1.7491 2.1877 3.0192 3.9471 4.6803 2.4942 3.0625 4.932 3.8871 3.152 1.1167 0.7048 0.837 1.2284 1.3715 2.8029 3.236 $ / bbl Rockies Historical Basis Jan 2006 to June 2008 1 Actuals through June 2008, NYMEX Forward Curve as of 6/17/08 for Jul 2008-Dec 2009 2007 2008 2009 J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D H Hulb 6.33 8.06 7.1 7.57 7.64 7.4 6.21 6.3 5.98 6.68 7.01 7.08 7.93 8.46 9.34 10.11 11.24 11.92 12.95 13.06 13.08 13.15 13.39 13.73 13.93 13.86 13.59 11.4 11.22 11.29 11.38 11.44 11.46 11.53 11.77 12.13 Rockies 5.78 6.31 4.91 4.56 3.69 2.72 3.72 3.23 1.05 2.79 3.85 5.96 7.23 7.62 8.11 8.74 8.44 8.68 7.79 7.92 7.6 7.53 8.71 10.72 11.93 11.83 10.96 7.92 7.4 6.98 6.77 6.8 6.25 5.98 7.53 9.14 $ / Btu Rockies Net Price - Historical / Forward Jan 2007 to Dec 2009 2007 2008 2009 5-Yr Avg $1.51 Henry Hub Guidance Range $6.60 - $8.10 Guidance Range $7.30 - $8.10

Commodity Price Summary (2008-09) 1 Oil = WTI and Natural Gas = Henry Hub Un-hedged Commodity Price Assumptions New (2008) New (2009) Natural Gas: Natural Gas: Natural Gas: Basin Prices Basin Prices Basin Prices Average Rockies $7.30-$8.10 $6.60-$8.10 Average San Juan/Mid-Continent $7.70-$9.00 $7.00-$9.00 NYMEX - (Henry Hub) (reference only) $9.00-$10.50 $8.00-$10.50 Crude Oil to Natural Gas Ratio 1 11.1x-11.4x 10.0x-11.4x Crude Oil: - (WTI) (reference only) $100-$120 $80-$120 Commodity Outlook

2008 Segment Profit / EPS Change 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 2.6 80 Segment Profit ($ Millions)1 Earnings Per Share1 Previous Guidance Range (May 1, 2008) Commodity Outlook ($ in Millions) Previous (5/1/08) New (6/25/08) Segment Profit1 2,500-3,000 3,100-3,650 EPS1 $1.70-$2.10 $2.30-$2.80 1 Recurring and After MTM Adjustment New Guidance Range Segment Profit $3,100-$3,650 EPS $2.30-$2.80

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 2.6 80 2009 Segment Profit / EPS Change Segment Profit ($ Millions)1 Earnings Per Share1 Previous Guidance Range (May 1, 2008) ($ in Millions) Previous (5/1/08) New (6/25/08) Segment Profit1 2,600-3,200 2,900-3,800 EPS1 $1.80-$2.30 $2.05-$2.90 1 Recurring and After MTM Adjustment Commodity Outlook New Guidance Range Segment Profit $2,900-$3,800 EPS $2.05-$2.90

Commodity Price/Segment Profit Sensitivity Commodity Outlook Dollars in Millions Change in Segment Profit Change in Segment Profit Six Month Impact 2008 Full Year Impact 2009 $1.00 Increase in Natural Gas Prices: $1.00 Increase in Natural Gas Prices: $1.00 Increase in Natural Gas Prices: E&P +150 +320 Midstream -50 -100 Total Williams +100 +220 $1.00 Increase in Crude (WTI) Oil Price +5 +11

Q&A

Exploration & Production Ralph Hill President

Agenda Review E&P's Strategy and Outlook Ralph Hill Powder River Basin Jerry Barnes Piceance Basin Alan Harrison Conclusion and Q&A Ralph Hill

Unique Drilling Portfolio Strategy is to rapidly develop our significant drilling inventory while adding new resource potential opportunities Focused North American unconventional natural gas portfolio of large well-defined resources Long-term, low-risk, high-return drilling portfolio Strong organic production growth R/P ratio of 12.4 years Drilled 1,590 wells in 2007, 99% success rate Exploration & Production

Leader in US Gas Production Growth Exploration & Production Source: Publicly reported data from EvaluateEnergy.com Quarterly U.S. Daily Natural Gas Production

Leader in Operating Costs * Top 20 U.S. Gas Producers - 2007 Production Cost* Exploration & Production * Production Cost defined as costs incurred to operate and maintain wells and related equipment and facilities, including property taxes applicable to proved properties, and severance taxes Source: Publicly reported data from EvaluateEnergy.com $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 Questar Williams XTO Shell El Paso Chesapeake Cimarex Noble Devon EOG EnCana Newfield Marathon Anadarko ConocoPhillips Apache BP ExxonMobil Chevron Occidental $/Mcfe Group Average = $1.59

Source: Publicly reported data from EvaluateEnergy.com Leader in F&D Costs Top 20 U.S. Gas Producers - 3 Year Average Finding and Developing Costs (Fully Loaded) Williams Consistently Remains in Top Quartile for F&D Costs Exploration & Production $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 BP XTO Williams EOG ConocoPhillips Occidental Devon Questar Noble Cimarex Chesapeake Newfield EnCana ExxonMobil El Paso Apache Anadarko Shell Chevron Marathon $/Mcfe Group Average = $2.89

Leader in Growing Reserves * Reserves Replacement % calculated as follows: (Revisions + Additions + Acquisitions + Divestitures)/Production Source: Publicly reported data from EvaluateEnergy.com, press releases, and company websites Top 20 U.S. Gas Producers - 2007 Reserves Replacement % (Sorted by Reserves Replacement) 2006 YE Net Additions Production 2007 YE Reserves Replacement* 2007 Acquisitions Acq. % of Net Additions 1 XTO 6,944 3,029 (532) 9,441 569% 1,279 42% 2 Chesapeake 8,319 2,473 (655) 10,137 378% 329 13% 3 EOG 3,471 1,110 (361) 4,220 308% 1 0% 4 ExxonMobil 12,049 1,764 (641) 13,172 275% 9 1% 5 Questar 1,461 329 (122) 1,669 270% 16 5% 6 El Paso 1,864 622 (238) 2,248 261% 339 55% 7 Newfield 1,535 460 (185) 1,810 248% 163 35% 8 Williams 3,701 776 (334) 4,143 232% 19 2% 9 EnCana 5,390 1,109 (491) 6,008 226% 211 19% 10 Devon 6,355 1,423 (635) 7,143 224% 10 1% 11 Occidental 2,424 464 (216) 2,672 215% 18 4% 12 Noble 1,739 252 (150) 1,840 167% 3 1% 13 BP 15,098 1,156 (879) 15,375 132% 23 2% 14 Cimarex 1,090 152 (120) 1,123 127% 11 7% 15 ConocoPhillips 12,441 1,141 (948) 12,634 120% 30 3% 16 Apache 2,695 285 (281) 2,699 101% 80 28% 17 Marathon 1,069 112 (174) 1,007 64% 1 1% 18 Shell 2,629 250 (411) 2,468 61% 0 0% 19 Chevron 4,028 269 (620) 3,677 43% 50 19% 20 Anadarko 10,486 (1,284) (698) 8,504 -184% 4 0% Total 104,790 15,892 (8,691) 111,990 183% 2,595 16% Exploration & Production

3P Reserves and Resource Potential Update Exploration & Production medicare medicaid all other 2.1 1.8 6.9 PDP 2006 3P Reserves 10.8 Tcfe Probable & Possible PUD medicare medicaid all other 2.4 1.9 9 PDP 2007 3P Reserves 13.3 Tcfe Probable & Possible PUD Moved 1.9 Tcfe over last three years from probable to proved Proved reserves are up 11% over one year ago Proved, probable and possible of 13.3 Tcfe which includes the recent SandRidge acquisition Resource potential of up to 22 Tcfe "Resource potential" is defined as proved, probable and possible reserves plus unrisked theoretical resource estimates that might never be recoverable and are contingent on exploration success, technical improvements in drilling access, commerciality, and other factors. Unlike probable and possible reserves, unrisked theoretical resource estimates do not take into account the uncertainty of resource recovery and therefore are not indicative of the expected future recovery and should not be relied upon.

2007 3P Reserves Update Exploration & Production Piceance Mid-Continent Green River/Int'l San Juan Powder River * Production for 1Q '08 0.4 Tcfe Proved 1.3 Tcfe Prob/Poss 209 MMcfe/d* 2.8 Tcfe Proved 6.4 Tcfe Prob/Poss 607 MMcfe/d* 0.6 Tcfe Proved 0.4 Tcfe Prob/Poss 134 MMcfe/d* 0.3 Tcfe Proved 0.7 Tcfe Prob/Poss 61 MMcfe/d* 0.2 Tcfe Proved 0.2 Tcfe Prob/Poss 51 MMcfe/d*

Evolution of Williams E&P - Historical Reserves Growth Exploration & Production Domestic Proved Reserves (Bcfe) Acquisitions Asset Sales Drillbit Reserves Additions 200 700 1,200 1,700 2,200 2,700 3,200 3,700 4,200 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Cash Margin Analysis Exploration & Production $7.26 is after hedging and includes average basin market price of $7.53 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include capital and exploration costs/proved reserves ('05-'07 average) 2 Year Average (2008-2009) Reflective of Core Basins $7.26 $2.24 $1.77 $5.02 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs $2.14 $6.69 $4.55 '05-'07 Previous Previous Cash Margin Cash Costs 3 Year Historical

87% Domestic Production Not At Rockies Prices Total Domestic 1Q Production of 1,013 MMcfed 37% (370 MMcfed) at Rockies prices before hedging 63% (643 MMcfed) produced or transported to other price points Rockies hedges of ~240 MMcfed 370 MMcfed total less 240 MMcfed hedged = 130 MMcfed or 13% priced in Rockies rockies hedges rockies san Juan Mid Continent Calif & Other 24 13 29 24 10 Rockies Hedges 1Q '08 Sales Points Rockies San Juan Mid Continent CA & Other Exploration & Production

San Juan Basin - Solid Performer Conventional and coalbed methane production Long life / slow decline wells 2007 Proved reserves of 576 Bcfe 1Q '08 net production 134 MMcfe/d Approx. 120,000 net acres Low risk in-fill drilling 40-60 operated wells drilled per year 200-250 undeveloped locations with additional upside potential Attractive returns with near 100% success rates ~820 operated and ~2,200 joint interest wells Good pipeline infrastructure/market access Exploration & Production

Mid-Continent Region Arkoma Basin - Horizontal Expertise Approx. 90,000 net acres 1Q '08 net production 13 MMcfe/d Caney and Woodford Shale offer additional upside opportunities Ft. Worth - Barnett Shale 4 rigs active in the play 32,000+ net acres, 90% of investment in core and tier 1 areas 1Q '08 net production 38 MMcfe/d Approximately 90 drilling locations Gaining efficiencies through size and scale Exploration & Production

Barnett Shale Acreage Position Core Area Tier I Tier II South Tier II West Williams Acreage Exploration & Production

F&D Cost: ~$1.30/Mcf (based on YE2007 3P reserves) 2007 Proved Reserves Replacement: 380+% Barnett Shale Reserves Summary Exploration & Production 175 277 27 80 131 61 116 35 68 0 50 100 150 200 250 300 YE 2005 YE 2006 YE 2007 Reserves, Bcfe 0 50 100 150 200 250 300 Op and Non-Op Well Count Proved Bcfe 3P Bcfe Op & Non-Op Wells

International E&P YE07 Proved reserves total 26 MMboe (154 Bcfe) 8.2 Mboe/d net oil and liquids production 69% ownership in Apco Argentina 70% of production from Entre Lomas in Neuquen basin Bajada del Palo and Agua Amargo acquisitions add Neuquen basin scale In-fill, field extension drilling 283,000 net acres owned/controlled Exploration upside Complements domestic long life reserves strategy Exploration & Production 3.0% Acambuco 26% Tierra del Fuego 41% Canadon Ramirez 53% Entre Lomas 37.5% Capricorn 53% Bajada del Palo 53% Agua Amarga

Powder River Basin Jerry Barnes Vice President

Powder River Basin CBM Production 1 WOGCC Data Feb. 2008 2 USGS Estimate 2002 Current production 1.38 Bcf/d1 ~23% of Wyoming Gas Production Production is from Wyodak, Anderson, Wall, Canyon, and Big George coals ~60% is from the Big George Coals 39 Tcf Gas-In-Place2 25,687 wells drilled to date 25,313 additional potential locations in WY 15,000 potential locations in MT Big George reserves average ~0.5 BCF/well, average depth 1500ft, and average well cost ~$280M/well Cumulative production 2.76 TCF1 Exploration & Production

Williams Operated Pilots Partner Operated Pilots Other Industry Pilots Powder River Basin Cross-Section Exploration & Production 120' Average 65' Average Wyodak Fairway Big George Fairway WEST EAST 200' 400' 600' 800' 1000' 1200' 1400' 1600' 1800' 2000' 24 Miles 12 Miles * IHS Data December 2007 Wyodak Fairway 518 MMcfd* Several Coal Mines Producing 30% of US Production Big George Fairway 826 MMcfd *

Powder River Current Development Status High potential, low-risk development play, low cost wells YTD Big George production has increased over 30% Williams' proved reserves total 413 Bcfe (YE 2007), plus 1.3 Tcf Prob/Pos for a total of 1.7 Tcf reserves Leasehold 939,000 gross/427,000 net acres Williams operates 26% of the Powder River basin and is the largest operator * ~7,400 total JV wells, 55% operated ~700 additional third-party wells 2007 drilling success rate of 99% 1Q'08 net production 209 MMcfe/d ~5,000 drilling locations; 40% operated Ramping up to 20+ Drilling Rigs 135 JV Spuds YTD 1,858 days since last LTA as of 6/15/2008 (5.1 Years) Exploration & Production * WOGCC Data Feb. 2008

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Powder River Achieving Impressive Growth Exploration & Production 100 MMcfd Oct 1999 200 MMcfd Mar 2001 300 MMcfd Aug 2002 300 MMcfd Sep 2005 400 MMcfd Jan 2007 500 MMcfd Nov 2007 600 MMcfd Apr 2008 PRB O&G EIS ROD July 2003

Powder River Wyodak / Big George Production Histories Exploration & Production Source: IHS December 2007 Data 1st Qtr 1987 20.4 88 30.6 89 45.9 90 91 92 93 94 95 96 97 98 99 2000 1 2 3 4 5 6 7 8 826 MMcf/d 518 MMcf/d Wyodak Years '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 Big George '99 '00 '01 '02 '03 '04 '05 '06 '07 '08

Powder River Net Production Forecast Exploration & Production 2007 2008E 2009E Valley 62 75 84 CAGR 16% 637 997 960 170 205 230 Wells Spud MMcfe/d

Powder River Basin Plan of Development Process Submitted Plans of Development Well Permits Date Submitted to BLM SRU 4 31 9/29/06 S Prong 1 and 2 176 8/17/07 E Bullwhacker POD Add 1 2 8/31/07 Wormwood 3 14 9/14/07 Tex Draw 63 9/17/07 Kingsbury 5 47 12/28/07 Laskie Draw 12 1/14/08 Carr V Add II 14 3/13/08 North Butte 2 3/27/08 Ridgeline 16 4/11/08 W Kingsbury 1 48 4/17/08 CCU 1 97 4/30/08 Playa 6 5/21/08 Kingwood 3 37 5/30/08 Carr Draw 3 W 109 5/30/08 15 PODs Pending 674 Exploration & Production

Powder River Water and Surface Use Permits Exploration & Production Water Permits Approved by Plan Year Surface Use Agreements in Place by Plan Year 2008 2009 2010 Valley 97 51 56 96% 80% 65% 2008 2009 2010

Powder River Typical Seasonal Restrictions on Drilling Jan Jan Feb Feb Mar Mar Apr Apr May May Jun Jun Jul Jul Aug Aug Sep Sep Oct Oct Nov Nov Dec Dec Wildlife Restrictions Elk Crucial Winter Range Elk Calving Areas Sage Grouse (Lek and Nesting) Bald Eagle Nesting Bald Eagle Winter Roosting Mountain Plover Breeding & Nesting Raptor Nesting Prairie Dog Avoidance (Not In PRB currently) Sharp Tailed Grouse (Treated the same in PRB as Sage Grouse) Other Restrictions Weather - Archeological & Paleontological (USFS) Studies Lambing & Calving Operations Big Game Hunting Season Williams Operated Wells drilled in 2007 (457 Total) 36 36 26 26 17 17 19 19 19 19 22 22 38 38 56 56 73 73 73 73 52 52 26 26 Exploration & Production

Powder River Produced Water Options Surface Discharge Impoundments Irrigation Sub-irrigation Treatment Storage and Retrieval Re-injection Exploration & Production Surface Discharge Ion Exchange/Reverse Osmosis/Filtration WDEQ WYPDES Permitted Outfall WSEO Permitted Reservoir Tire Tank for Stock Watering

In conjunction with private surface landowners, hundreds of acres are being irrigated with produced CBNG water. Operators apply soil mitigation as soils analyses dictate resulting in the production of over 1 Ton per acre of greater than 10% protein content native hay Powder River Produced Water Irrigation Exploration & Production

Powder River Basin Produced Water Management - Reservoirs Exploration & Production Water Management Plan: WDEQ Permitted Storage and Release with Capability to Pump Water to Various Reservoir Pump Station

Powder River Key Points Production rapidly growing 2008 seasonal bird stipulations behind us Rigs contracted and ramping up to run 20+ rigs Sage Grouse Interim Management Area (IMA) appears acceptable Water issues are manageable Take away capacity is available Exploration & Production

Piceance Basin Alan Harrison Vice President

Piceance Basin Overview Basin centered gas system - Mesa Verde continuous gas play 200-300 Tcfe Piceance basin potential Current Production of ~1.8 Bcfe/d Over 15,000 wells in the basin One of the largest gas basins in the nation Exploration & Production Wood MacKenzie North American Gas Service Mesa Verde Continuous Gas Play Extent of Mesa Verde Play

Piceance Valley and Highlands - World Class Assets Exploration & Production Piceance Valley Piceance Highlands Newly Acquired Acreage Existing Williams Acreage Other operators Naval Oil Shale Res. Piceance Valley Piceance Highlands Williams is the largest gas producer in the Basin 2007 Proved reserves total 2.2 Tcfe Approx. 115,000 net acres Operate ~2,300 wells, 98% WI 1Q'08 net Valley production 565 MMcfe/d 22 rigs operating ~3,700 drilling locations Operate 250+ miles of gathering and 4 gas plants Access to 5 major pipelines Currently 69,000 net acres 2007 Proved reserves total 607 Bcfe 5,000+ potential drilling locations 1Q'08 net production 43 MMcfe/d 4 rigs operating Seasonal drilling ramps up to 7 rigs Operate 153 wells (up from 134 one year ago); 81% avg. W.I. Key infrastructure projects nearing completion

Piceance Sub-surface View Piceance Valley: 6,000' - 9,000' Piceance Highlands: 9,000' - 12,000' Horizontal reach up to 3,000' Drilling Depths Piceance Valley 1,800' - 2,400' of Gas Saturated Mesa Verde Formation Coal Rich Interval Interbedded Sand/Mudrock Exploration & Production

Piceance Basin Production Exploration & Production 2007 2008E 2009E Valley 508 611.6 652 Highlands 33 54.6 80 CAGR 16%

Ryan Gulch SandRidge Acquisition Bolt-on acquisition in Ryan Gulch area of Piceance Highlands 32,500 gross / 24,000 net acres with 75% working interest $285 million acquisition price $250 million for wells and acreage $35 million for plant and facilities 1.9 Tcfe net 3P reserves on 10-acre spacing Williams has drilled 48 wells in Ryan Gulch and proven the value of the property Acquired Acreage Existing Williams Acreage Other operators Exploration & Production

Ryan Gulch Acquisition - Strategic Importance Consistent with Williams' strategy of growing in the Piceance Basin Williams is the operator of high working interest properties Low-risk bolt-on acquisition doubling Williams' existing acreage position in the Ryan Gulch area Multi-year drilling inventory of long-lived reserves Combined infrastructure provides cost savings and synergies in development of this asset with the existing Ryan Gulch asset Williams integrated synergies Gas will be delivered to Williams' Midstream Willow Creek processing plant Important supply basin for Northwest Pipeline Exploration & Production

Leader in Innovation 10 H&P Flex Rigs 4 Nabors Super Sundowner High Efficiency/ Fit for Purpose Drilling Rigs Safer Safer operations through more automation Fewer rig moves More Compact Operations - rig layout Iron roughneck Faster Top drive and pumps for greater reach (3,000') Up to 22 wells drilled from one pad Simultaneous operations 20% to 30% greater efficiency in spud-to-spud IN and OUT quicker Cleaner 75% less surface disturbance Consolidation, reduced traffic Quieter engines, less emissions Faster reclamation Exploration & Production

Williams Pioneers Advancements in Piceance First to reduce natural gas flaring by 90%, Green Flow Back Completions First to recycle and handle produced water in more environmentally friendly way First to implement wellhead automation First to design and implement offshore rig design for pad drilling; Up to 75% less surface usage First to be granted year-round drilling by the BLM with area development plans Recognized with 4 COGCC and 1 national BLM awards in the last 2 years for technology and innovation First to work with the community to monitor air quality Exploration & Production

Best Practice: Simultaneous Operations (SIMOPS) These rigs allow for drilling, completing, producing and selling gas at the same time from the same pad Williams green completion process eliminates flaring of produced gas during completions Simultaneous Operations (SIMOPS) means wells can be put on line faster SIMOPS reduces the total time of operations on a pad Exploration & Production

CPODS: Clustered Plan of Development Able to Fracture Stimulate wells using frac pumps up to 2 miles away Can Fracture Stimulate multiple sites from one location Eliminated over 12,000 water truck trips in this area Better efficiencies with Stimulation Crews (more jobs in a given day) Assist Regulatory Agencies in their approval process Additional Benefits Smaller size drilling pads Less traffic resulting in less dust, emissions, road maintenance and accidents More fracs per day Drill faster and reclaim sooner! Exploration & Production 6,200 feet

Hayes Gulch - Piceance Basin Exploration & Production

Piceance Basin Keys Points Largest operator in one of the nation's top basins Tremendous track record and long term opportunity Predictable reservoir performance Operational and cost efficiencies Completion effectiveness SIMOPS CPODS Leader in the Piceance basin Safety performance Pioneering new technology Experienced and talented staff Environmental stewardship Community involvement Exploration & Production

Exploration & Production Ralph Hill President

Other Areas of Interest Exploration & Production Focus will remain on tight sands, shale, and coal bed methane Opportunities remain in existing basins 18 member Exploration staff pursuing other resource plays Dedicated A&D staff pursuing disciplined acquisitions Current Activity Paradox Uinta Piceance Deep Caney Shale Other

Key Points - Value Creation Continues On track for record year for segment profit and production 3P reserves of 13.3 Tcf Strategy is to rapidly develop our premier drilling inventory while adding new resource potential opportunities An industry leader in production growth, reserves replacement, production costs and finding costs Long-term repeatable drilling inventory of significant proved undeveloped, probables and possibles Long history of high drilling success, cost efficiencies Short cycle time investments, fast cash returns Experienced and talented work force Very favorable long term organic growth outlook Pursuit and evaluation of new resource opportunities continues Exploration & Production

Q&A

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream Alan Armstrong President

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Agenda Review Midstream's Strategy and Outlook Alan Armstrong Valuing Midstream's Business David Darcey Exciting Growth Ahead Deepwater Gulf of Mexico Rory Miller Western Region Mac Hummel Canadian Oil Sands Randy Newcomer Conclusion and Q&A Alan Armstrong Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream Assets in Hotspots Sources: Cambridge Energy Research Associates and Canadian Association of Petroleum Producers

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream Peer Comparison Earnings Before Interest & Taxes ($MM) Williams Midstream Enterprise Products Partners ONEOK Partners Williams Partners Energy Transfer Partners** DCP Midstream Partners Copano Energy Crosstex Energy 2007 2006 * CPNO average assets is the quarterly average over 5 quarters from 4Q06 to 4Q07. ** ETP fiscal YE is Aug 31; therefore, the quarters do not correspond with the other companies. The ROAA is calculated based on a trailing 12 months from the Nov. 30, 2007 10-Q. This puts ETP on a similar basis to Dec 31 Full Year 2007 results (Dec 1, 2006 to Nov. 30, 2007). *** ROAA is calculated as EBIT divided by average assets for the 12-month time period Note: Circle size is proportional to average assets Pre-Tax Return on Average Assets (ROAA)*** 1,100 1,000 900 800 700 600 500 400 300 200 100 - - 1% 6% 11% 16% 21% 26% Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm 2006 2007 2008 2009 Series 1 30 50 50 50 29 52 74 62 184 478 700 513 2006 2007 2008 2009 Series 1 2006 2007 2008 2009 Series 1 934 1290 1440 1475 105 205 Free Cash Flow - Forecast Note: Segment Profit is stated on a recurring basis. Segment Profit + DDA and Capital Spending reflect midpoint of ranges Discretionary Expansion Historic Expansion Maintenance Well Connects Guidance Mid-Point to High Case Upper Limit Segment Profit + DDA Capital Seg. Profit + DDA Midstream $ Millions

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Valuing Midstream's Business David Darcey Director, Planning & Analysis

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Free Cash Flow - Forecast Note: Segment Profit is stated on a recurring basis. Segment Profit + DDA and Capital Spending reflect midpoint of ranges Midstream 2006 2007 2008 2009 Series 1 30 50 50 50 29 52 74 62 184 478 700 513 2006 2007 2008 2009 Series 1 2006 2007 2008 2009 Series 1 934 1290 1440 1475 105 205 Discretionary Expansion Historic Expansion Maintenance Well Connects Guidance Mid-Point to High Case Upper Limit Segment Profit + DDA Capital Seg. Profit + DDA $ Millions

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Gross Margin $ Millions Midstream $0 $500 $1,000 $1,500 $2,000 $2,500 2005 2006 2007 2008L 2008H Fee Based Commodity Based Fee Based Commodity Based

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Gross Margin Sensitivity medicare medicaid all other 33 11 48 8 Fee-Based 44% Commodity - -Based 56% 2007 Gross Margin by Revenue Stream medicare medicaid all other 43 15 33 8 Fee-Based 58% Commodity - -Based 41% 2007 Gross Margin by Revenue Stream NGL and Canadian Adjusted to 5 Year Average Fee-Based Gathering and Processing Other Fee-Based Revenues NGL and Other Margins Olefins Margins $1.7B $1.3B Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Historical NGL Margins Domestic NGL Average Realized Net Margin and Volumes by Quarter Note: Actual realized margins, does not include Discovery volumes. Five year average of 28 cpg is calculated for the period 2Q03-1Q08. Realized Margin Equity NGL Prod (MM Gals) NGL Prod for Others & Inventory Build (MM Gals) Avg. Realized Margin Q2'03 70 22 26.6 250 Q3'03 55 26 27 250 Q4'03 98 34 25.8 250 Q1'04 87 37 23.8 250 Q2'04 76 37 26 250 Q3'04 155 42 28 250 Q4'04 200 45 28 250 Q1'05 128 44.5 26.5 250 Q2'05 120 38 28.7 250 Q3'05 175 31 27.2 250 Q4'05 135 29 22.6 250 Q1'06 170 38 23.8 250 Q2'06 300 40 26.3 250 Q3'06 370 38 27.1 250 Q4'06 327 37 31 250 Q1'07 245 38.3 28 250 Q2'07 420 40 29.8 250 Q3'07 550 40 32 250 Q4'07 745 39.5 32.7 250 Q1'08 560 34.2 36.8 250 Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm 2003 2004 2005 2006 2007 2008L 2008H 5YR Average NGL Margin 2003-2007 28 28 28 28 28 Historical NGL Margins 11.1 15.3 15.7 32.6 56.3 2008 Estimated NGL Margins 57 68 Actual Average Domestic NGL Margins * Excludes Discovery Equity Volumes Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Commodity Price Relationships NGL Barrel Composition: Ethane 50% Propane 25% Butane 15% Natural Gasoline 10% Crude (WTI) NGL Barrel Gas at Henry Hub Gas at Rockies 5YR Avg 53.32 33.59 6.8 5.25 2007 70.95 45 6.98 4.52 2008L 100 56 9 7.6 2008H 120 67 10.5 8.1 Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Fee Revenues Data for Graph 2005 2006 2007 2008L 2008H Gathering and Processing 390.81 425.32 414.39 450.6 450.6 Production Handling and Transportation 77.41 133.81 107.61 71.7 71.7 Venezuela 153.51 153.76 147.88 153.2 153.2 Other 80.79 70.02 79.63 127.66 127.66 Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Deepwater Growth Rory Miller Vice President, Gulf Coast

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Williams' Deepwater Update Why Deepwater GoM? The size of the prize Why Williams Midstream? Our competitive advantage What is Next? A new wave of development coming Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Estimated Undiscovered Technically Recoverable Oil & Gas Resources* Federal OCS Areas 26.6 BBO + 132.1 TCF 3.8 BBO + 37.0 TCF 44.9 BBO + 232.5 TCF 10.5 BBO + 18.3 TCF * MMS 2006 Fact Sheet, Mean values MMS' Estimated Undiscovered Reserves Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm MMS' Gulf of Mexico Gas Forecast MMS OCS Report - 2007 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Shallow-water Shallow (historical) 11.95 11.83 12.15 11.78 12.21 11.78 11.02 10.41 9.81 9.4 7.56 7 6.05 4.56 4.15 MMS Shallow-water Shallow Projection 4 3.85 3.73 3.57 3.42 3.25 3.12 3.02 2.87 2.74 Shallow-water Deep (historical) 0.55 0.6 0.6 0.8 1 1.28 1.28 1.1 1.05 1.25 1.33 1.25 1.13 0.85 0.82 MMS Shallow-water Deep Projection 1.18 1.08 1.08 1 1 1 1 1 1 1 Deepwater (historical) 0.22 0.29 0.44 0.5 0.75 1.05 1.5 2.26 2.69 3.12 3.47 3.83 3.78 3.17 3.02 Industry Deepwater Projection 2.72 3.17 3.2 3.15 2.62 MMS Deepwater Projection 2.31 2.11 1.78 1.61 1.53 Industry-Announced Discoveries 0.19 0.32 0.22 0.65 1.43 1.96 1.81 1.86 1.73 1.53 Undiscovered Resources 0.17 0.37 0.62 1 1.58 2.14 2.69 2.72 Billion Cubic Feet/Day Year Full Potential Scenario Committed Scenario Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm MMS' Gulf of Mexico Oil Forecast MMS OCS Report - 2007 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Shallow-water (historical) 735 743 743 794 818 833 786 739 695 668 600 577 522 392 356 MMS Shallow-water Projection 337 317 301 274 258 234 214 203 191 183 Shallow-water Deep (historical) 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 MMS Shallow-water Deep Projection 1 1 1 1 1 1 1 1 1 1 Deepwater (historical) 100 100 116 147 191 289 427 617 731 849 936 948 936 881 889 Industry Deepwater Projection 968 1106 1358 1480 1307 MMS Deepwater Projection 1169 1035 916 822 715 Industry-Announced Discoveries 49 61 100 203 435 534 538 534 486 447 Undiscovered Resources 17 57 100 226 360 510 648 759 Thousand Barrels/Day Year Full Potential Scenario Committed Scenario Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm GoM Central Lease Sales Results Source: Wood Mackenzie 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Series 1 600 130 190 310 200 140 170 170 400 2650 3350 1.09 1.43 1.57 1.69 1.17 0.66 0.91 1 2.09 5.43 8.6 Total Sales (US$ Millions) Average Bid Per Block (US$ Millions) Total Sales Average Bid Per Block Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Williams' Deepwater Strategic Advantages Assets: Major oil & gas trunk-lines built in western and eastern corridors Significant Gas infrastructure (Discovery) in Green Canyon corridor Oil infrastructure in Garden Banks corridor All deepwater infrastructure anchored through on-shore gas plants One-of-a-kind deepwater repair readiness (PERK) People: One of the most experienced deepwater pipe-lay teams - worldwide Deep technical bench for spar design and construction Safe, reliable, efficient focus on field operations Leverage: Stand ready to leverage our people and assets to be major player as next round of large-scale deepwater infrastructure is contracted out Will offer unique "speed-to-market" alternatives for maximum NPV alternatives Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Deepwater Generic SPAR Concept Standard design SPAR based floating production system (FPS) "Turn Key" proposal to producers for the ownership & operation of FPS "Speed-to-market"- Producers benefit from improved NPV by reducing costs and cycle-time from sanction to 1st Oil Target opportunities include standalone field developments and co-development of marginal fields Cost estimated at $500 MM per FPS FPS & Export System deployed to capture downstream value chain upside Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Gulf of Mexico Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Western Gulf Perdido project update All pipe and sleds on seafloor No standby so far Markham train #2 design complete, major equipment ordered Lower Tertiary prospects U.S. waters Mexican waters Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Discovery Knottyhead, Pony Cascade & Chinook Jack, St. Malo Corridor Highlights Numerous small mini-basins targets Target-rich Lower Tertiary area Significant new oil infrastructure required Associated gas export and fuel gas import opportunities Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Eastern Gulf Devils Tower area Thunderbird Tubular Bells Kodiak Freedom Biogenic Gas Plays: Near-shelf; Canyon Station tie-backs Ultra-deep; new gas only hub opportunity Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Western Region Growth Mac Hummel Vice President, Western Region

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Competitive Strengths Reliability Scale Hub Access Experience Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Opal - Second largest processor in lower 48 San Juan Basin - Largest gatherer Wamsutter - Largest gatherer and processor Piceance - Future scale position building Western Region - Exposure to significant drilling activity West Region Assets - Scale Positions Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Wamsutter Large, prolific field Robust drilling plans TXP 4 expansion announced in May Gathering expansions expected Opal Connected to Pinedale and Jonah fields Expanded twice in the past four years Second largest processor in Lower 48 Regional trading hub for West Wyoming Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Wamsutter: Future Drilling Drives Growth Well Connects Gathering Volume (Bbtud) 2005 200 460 2006 237.5 500 2007 215 520 2008 225 550 2009 228 600 2010 300 615 2011 354 655 2012 387.5 716 2013 398 775 Plant Capacity (Bbtud) WMB TXP4 Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Piceance Basin Parachute lateral in service May 2007 PGX pipeline in service July 2008 Willow Creek plant in service mid to late 2009 Multiple additional Piceance Basin plants Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Piceance 2004 2005 2006 2007 2008 2009 289.2004 402.6326 550.8143 791.467 1031.8015 1280.7777 Existing Equity Volumes and Future Drilling Drive Growth Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Four Corners Largest gatherer in San Juan Basin Significant flexibility offered by footprint Diversified portfolio of contracts Strong fee-based revenues Predominantly connected at wellhead Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Canadian Oil Sands Opportunity Randy Newcomer Vice President, Olefins & NGLs

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Canadian Oil Sands Are One of the Fastest Growing Basins in the World New Basin G&P Opportunity With Upgrader Offgas Production Venezuela 2.13 UAE 2.5 Canada 2005 2.5 Norway 2.75 Mexico 3.4 China 3.63 Iran 3.92 USA 5.1 Saudi Arabia 9.16 Russia 9.2 Source: EIA & CAPP Stable Growing Stable Stable Stable Stable Declining Growing Stable Growing Oil sands growth will move Canada from #8 to #4 in the world by 2015 Million Barrels per Day Production Outlook Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm The Upgrading Process SAGD Facility Oil Sands Trucks Photo Source: www.ostseis.anl.gov; Suncor Energy, Inc. Suncor Upgrader Oil Sands Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Edmonton Calgary Ft. McMurray Redwater Extraction Compression To Edmonton Fractionation Legend Suncor Facility Williams Facility Suncor Pipeline Williams Pipeline U2 U1 To Edmonton Geographic Location of Assets Canadian Olefins Assets Consists of: Compression Facility Extraction Facility Fractionation Facility One Business: Three Facilities Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Canadian Oil Sands Upgrader Projects: Creating Value Fort McMurray Gas Plant Redwater Fractionator Photo Source: www.novachem.com; NOVA Chemicals Inc. Upgrader Olefins Ethane/ethylene mix Propane Polymer grade propylene (PGP) Butane/butylene mix* Olefinic condensate SURPASS(r) Polyethylene Resins SCLAIR(r) Polyethylene Resins NOVAPOL(r) Polyethylene Resins ARCEL(r) Advanced Foam Resin DYLARK(r) Automotive Resins DYLITE(r) EPS Resins Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream's Canadian Oil Sands Strategy Deploy Midstream's Large Scale Reliability Strategy and Become the Leading Provider of Offgas Liquids Extraction Services to the Oil Sands Upgraders Build on the foundation of our current assets at Fort McMurray and Redwater Leverage our experience with offgas processing at Suncor and our associated fractionation, NGL and olefins marketing experience in the U.S. and Canada to attract other upgraders to our services Develop a mix of fee-based and commodity-exposed projects to reduce margin risk on the downside while retaining some upside Utilize proven and cost-effective construction methods Build the organizational capability to effectively manage the large project flow from conception through start-up and on-going operation Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Potential Upgraders & Fractionation Customers... Some Pretty Good Company CNRL Suncor Ft Hills Redwater Statoil Syncrude Total Fort McMurray Area Facilities already in operation Approved projects under construction Announced projects in approval stage Redwater Area Upgraders Suncor Syncrude CNRL Fort Hills StatoilHydro Total Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Gas/Liquids Commodity Price Spreads Olefins production from NGL's and off-gas recovery adds significant (and increasing) additional margin potential to the natural gas value chain 0 5 10 15 20 25 30 35 Jan-98 May-98 Sep-98 Jan-99 May-99 Sep-99 Jan-00 May-00 Sep-00 Jan-01 May-01 Sep-01 Jan-02 May-02 Sep-02 Jan-03 May-03 Sep-03 Jan-04 May-04 Sep-04 Jan-05 May-05 Sep-05 Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Date $/mmbtu Realized PGP Spot, Avg. Pipeline Ethylene Propane Ethane Gas Crude Natural Gas Ethylene Propylene Propane Ethane Crude Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Conclusion

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream Significant Progress on Growth Projects * Estimated Segment Profit generated in first full calendar year of operation Dollars in Millions In Development/Proposal (through 2012) Spending $3,000 - 4,000 Under Negotiation (through 2012) Spending $1,200 - 1,400 In Guidance Spending $1,500 - 1,600 Deepwater Canadian Oil Sands Western Overland Pass Olefins Major Growth Projects Included in Guidance Major Growth Projects Included in Guidance Major Growth Projects Included in Guidance Major Growth Projects Included in Guidance Major Growth Projects Included in Guidance Major Growth Projects Included in Guidance Project (In-Service Date) Fee/Commodity Pre-2008 2008 2009 Seg Profit* Bass Lite (2Q '08) F $8 $7 $5 $30-$35 Blind Faith (4Q '08) F 212 40 - 10-15 Perdido Norte (4Q '09) F & C 175 203 182 90-100 Willow Creek (3Q '09) C 37 250 70 55-85 Echo Springs - TXP4 (4Q '10) F & C 25 125 40-50

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Key Points Midstream maintains tremendous cash flow generation Continues to generate high returns Strategy continues to yield unique competitive advantage Well positioned for growth Deepwater expansions progress Western opportunities abound Canadian Oil Sands off-gas: unrivaled position creates significant possibilities Midstream

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Q&A

Gas Pipeline Phil Wright President

Introduction Dramatic Changes and Growth for Our Industry Geographic shifts in gas production Greenhouse gas and other environmental concerns driving gas demand Increased future reliance on LNG Competition has intensified Substantial Opportunities Linking Supply and Demand Our Pipelines A Closer Look Inside: Attributes Our Growth Story Gas Pipeline

Industry Overview

Key Supply Changes Geographic shifts in supply Dramatic shift to non-conventional supply sources, especially shale and tight sands New infrastructure needed to link non-conventional supply sources to growth markets LNG imports Western Canadian production declining while oil sands demand explodes Gas Pipeline

WCSB US & Canadian Production Increase (2008-2018) Natural Gas Supply Outlook Arctic Rockies West Coast Permian Barnett MidCon GoM Shelf GoM Deep East US E. Canada San Juan Gulf Coast Total Decrease: (2.5) Bcfd Lower 48 Decrease: (0.4) Gas Pipeline

Key Demand Drivers Power Generation Tightening reserve margins New coal-fired generation plants limited in near-term by environmental concerns Nuclear not a near-term option Greenhouse gases Renewables are unreliable Ethanol and Fertilizers Impacting industrial demand growth Gas Pipeline

Gas Flow - Peak Demand Peak Month Gas Demand Increase (2008-2018) Total Demand Increase: 9.8 Bcfd 0.15 15.4% 0.96 13.2% 0.43 13.2% 0.55 4.8% 0.62 22.7% 1.42 58.0% 0.55 10.1% 1.69 13.6% 1.23 36.8% 0.21 22.3% 0.10 2.8% 0.59 3.8% 1.31 62.8% Bcfd % Gas Pipeline

Proximity to Gulf Coast and Eastern LNG Terminals Golden Pass Sabine Pass Freeport Lake Charles Cameron Pascagoula Elba Island Cove Point Everett Neptune NE Gateway Canaport LNG Terminal Capacity Canaport 1.0 Bcf/d Neptune 0.4 Bcf/d NE Gateway 0.4 Bcf/d Everett 0.7 Bcf/d Cove Point 1.8 Bcf/d Elba Island 2.1 Bcf/d Pascagoula 1.3 Bcf/d Lake Charles 1.8 Bcf/d Cameron 2.6 Bcf/d Sabine Pass 2.6 Bcf/d Golden Pass 2.0 Bcf/d Freeport 1.5 Bcf/d Gulf Gateway 0.5 Bcf/d Total 18.7 Bcf/d Gulf Gateway (Being expanded) (Being expanded) (Capacity contracted) In-service Under construction Certificated Gas Pipeline

A Closer Look Inside: Attributes

Stable, Substantial Free Cash Flow Driven by: Long-term contracts with high credit quality customers Supply access Premium growth markets ....and robust outlook for value growth Gas Pipeline

Free Cash Flow Forecast * Segment profit is stated on a recurring basis. Segment profit + DD&A and capital spending reflect midpoint of ranges. Gas Pipeline $0 $200 $400 $600 $800 $1,000 $1,200 2006 Capital Seg Profit + DDA 2007 Capital Seg Profit + DDA 2008G Capital Seg Profit + DDA 2009G Capital Seg Profit + DDA Maintenance Expansion Segment Profit + DDA

TGPL 2007 Revenue $905 MM NWPL 2007 Revenue $413 MM ~90% of 2007 Operating Revenues Were from Transportation and Storage Demand Charges* Revenue Breakout * Notes: Revenue received regardless of pipeline usage Excludes tracked revenue (revenue directly offset by a related expense) Transportation Demand includes incrementally priced projects Transportation Commodity Other Storage Commodity Transportation Demand Storage Demand Gas Pipeline

Northwest Long-term Contracts As of 03/01/2008 * $366 $324 $228 $199 $184 $129 $93 $91 $36 $93 $92 $86 $105 $102 $65 $18 $40 $42 $42 $23 $23 $6 $28 $35 $54 $63 $120 $159 $- $50 $100 $150 $200 $250 $300 $350 $400 2008 2009 2010 2011 2012 2013 2014 2015 In Million $ Base 2006-2007 Ctrct Extensions 2008 Ctrct Extensions Evergreen Col. Hub Estimate Northwest Pipeline Weighted Average Remaining Contract Term of 9.40 Years Based on Revenue * Excludes STF, Lateral TF-1 and Parachute TFL-1 Contracts Gas Pipeline

Transco Long-term Contracts Transcontinental Gas Pipe Line Corporation Contract Primary Term Summary Weighted Average Contract Life = 4.74 In Primary Term In Evergreen/Rollover 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 9,000,000 10,000,000 11,000,000 12,000,000 Firm Contract Volume (dt/d) 8.4 MDth/d 7.6 MDth/d 6.2 MDth/d 5.7 MDth/d 5.0 MDth/d 2.2 MDth/d 2.0 MDth/d 1.4 MDth/d 1.3 MDth/d 0.8 MDth/d 3.1 MDth/d 3.9 MDth/d 5.3 MDth/d 6.5 MDth/d 9.3 MDth/d 9.5 MDth/d 10.2 MDth/d 10.2 MDth/d 10.7 MDth/d 5.8 MDth/d As of 01/01/2008 Gas Pipeline

An Elegant, Simple Strategy Foster a culture of safety Be the low cost provider for our markets Supply access/optionality Cost control Efficiency Flexibility Reliability Uphold continuing high quality customer relationships Gas Pipeline

A Closer Look Inside: Our Growth Story

Northwest Pipeline Transco Gulfstream (50% Ownership) Quality Assets Serving Growing Markets Underground storage LNG peaking facility Gas Pipeline

Transco System Overview Transco Large and diverse supply sources Onshore and offshore Gulf of Mexico Pipeline Interconnects (including Barnett Shale and Bossier Sands) LNG Premium high growth markets Southeast Northeast New Pipeline Interconnects Totaling 18.5 Bcfd (2006-2009) Customers have high level of service flexibility Fully contracted/subscribed Largest pipeline in US 8.4 Bcfd at peak capacity Rate base $2.9 B 60% firm contract capacity into New York City Gas Pipeline

Transco Growth Projects Transco Sta. 85 North May 2011 Sentinel Nov 2008 / Nov 2009 Mobile Bay South May 2010 Eminence Enhancement Nov 09 Pascagoula Oct 2011 NE Supply Project Nov 2011 Gas Pipeline

"Backbone" of delivery infrastructure for northwest markets (WA, OR, ID) Only interstate pipeline serving Seattle, Portland and Boise Connects with major western pipelines Interconnects Off-system opportunities to serve CO, UT, WY, CA, NV, AZ and NM Uniquely situated to access diverse and strategic supply basins Rockies, San Juan and Western Canada Rate base $1.5B New/expanded receipt point capacity 1.6 Bcfd since 2004 Rockies Basins San Juan Basin Western Canadian Sedimentary Basin CA NV ID OR WA WY UT AZ CO NM Jackson Prairie Clay Basin Plymouth Northwest Pipeline MT Cascade Natural Gas Puget Sound Energy Avista Intermountain Gas Northwest Natural Southwest Gas Other Pipelines Northwest System Overview Gas Pipeline

Pipeline Projects - Northwest Pacific Connector Gas Pipeline Nov 2012/2013 Jackson Prairie Nov 2008 Blue Bridge 2011 Sunstone Pipeline Nov 2011 Sundance Trails Nov 2010 Colorado Hub Connection Nov 2009 WGP Projects NWP Projects Gas Pipeline

Gulfstream System Overview Fully Subscribed Long-term contracts (remaining life 21 years) Fastest growing markets in North America Driven by power generation needs Flexible supply Gulfstream Storage Storage Mobile South Mobile Bay SESH Pascagoula Gas Pipeline

Gulfstream Growth Projects SESH FGT Transco Gulfstream Phase IV Expansion Sep 2008 / Jan 2009 Phase III Expansion July 2008 Gas Pipeline

WGP Expansion Projects 2010 & Beyond 2008-2009 2007 Placed In-service Potomac 20 miles 165 MDthd capacity Leidy to Long Island 14.5 miles 100 MDthd capacity Sentinel 16 miles 142 MDthd capacity Eminence Injection Enhancement Compression only Volume TBD Colorado Hub Connection 28 mile lateral 363 MDthd capacity Jackson Prairie Deliverability Deliverability 108 MDthd 2007-2010 capacity 1.2 Bcf GulfStream Phase III (50%) 34 miles 345 MDthd GulfStream Phase IV (50%) 17 miles 155 MDthd capacity Pascagoula Supply Project 15 miles; 467 MDthd capacity 85 North Expansion Capacity - TBD NE Supply Project Capacity - TBD Mobile Bay South Compression Only; Capacity - TBD Sundance Trail 16 miles; 150 MDthd capacity Sunstone Pipeline 585 miles; 1.2 Bcfd capacity Blue Bridge Pipeline 172 miles; 500 MDthd capacity Pacific Connector Gas Pipeline 231 miles; 1.0 Bcfd capacity Projects shown in purple are not included in Guidance Gas Pipeline

Growth Projects Project In-service Date Pre-2008 2008 2009 Post 2009 Segment Profit1 Sentinel (Ph 1-4Q '08 & Ph 2- 4Q '09) $25 $30-40 $80-90 $1-5 $21 Jackson Prairie (4Q '08 1 10-15 - - 3 Eminence (4Q '09) - 1-5 5-10 - 2 Colorado Hub (4Q '09) - 5-10 30-50 1-5 7 Gulfstream III & IV (3Q '08 & 2Q '09) 38 80-100 5-10 - 46 Mobile Bay South (2Q '10) - 5-10 10-15 15-20 6 85 North (2Q '11) - 10-15 60-70 220-275 42 Sundance Trail (4Q '10) - - 5-10 30-50 17 Pascagoula (4Q '11) - 1-5 1-5 20-30 11 Market Access Production Access LNG Access Peaking & Storage Peaking & Storage 0.77 0.15 0.04 0.04 Market Access Production Access LNG Access Peaking & Storage Peaking & Storage Market Growth Production Access LNG Access Peaking & Storage 0.38 0.51 0.11 0 In Guidance ~$750 Million (through 2012) Proposed ~$3.3 Billion (through 2012) Gas Pipeline 1Estimated Segment Profit generated first year of operation

Key Points New pipeline infrastructure is critical Premier pipelines Stable, substantial cash flow Large and diverse supply Close proximity to LNG terminals Premium high growth Excellent investment opportunities Gas Pipeline

Q&A

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Consolidated Outlook Don Chappel Chief Financial Officer

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Commodity Price Summary (2008-09) Consolidated 1 Oil = WTI and Natural Gas = Henry Hub Un-hedged Commodity Price Assumptions 2008 2009 Natural Gas: Natural Gas: Natural Gas: Basin Prices Basin Prices Basin Prices Average Rockies $7.30 - $8.10 $6.60 - $8.10 Average San Juan / Mid-Continent $7.70 - $9.00 $7.00 - $9.00 NYMEX (reference only) $9.00 - $10.50 $8.00 - $10.50 Crude Oil to Natural Gas Ratio 1 11.1x - 11.4x 10.0x - 11.4x Crude Oil: WTI (reference only) $100 - $120 $80 - $120 Average NGL Margins: ($/gallon) $0.57 - $0.68 $0.43 - $0.71

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008 2008 Dollars in millions, except per-share amounts June 25 Guidance May 1 Guidance 2008 Forecast Guidance Reported Segment Profit Before MTM Adjust. Net Interest Expense Minority Interest & Other Pretax Income Provision for Income Tax Income from Continuing Operations Recurring Income from Continuing Operations Diluted EPS - Recurring Diluted EPS - Recurring After MTM Adjust. 1 $3,228 - $3,778 (605) - (670) (220) - (275) 2,403 - 2,833 (945) - (1,075) $1,458 - $1,758 $1,385 - $1,685 $2.31 - $2.81 $2.30 - $2.80 $2,628 - $3,128 (605) - (675) (215) - (260) 1,808 - 2,193 (710) - (855) $1,098 - $1,338 $1,025 - $1,265 $1.71 - $2.11 $1.70 - $2.10 Consolidated 1 Includes MTM adjustment - see slide 185 for guidance Note: See slide 153 for commodity price assumptions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available at the end of this presentation.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2009 Forecast Guidance Recurring Segment Profit Before MTM Adjust. Net Interest Expense Minority Interest & Other Pretax Income Provision for Income Tax Recurring Income from Continuing Operations Diluted EPS - Recurring Diluted EPS - Recurring After MTM Adjust. 1 $2,930 - $3,830 (600) - (665) (240) - (290) 2,090 - 2,875 (840) - (1,115) $1,250 - $1,760 $2.08 - $2.93 $2.05 - $2.90 $2,630 - $3,230 (595) - (665) (230) - (275) 1,805 - 2,290 (705) - (890) $1,100 - $1,400 $1.83 - $2.33 $1.80 - $2.30 Consolidated 2009 2009 Dollars in millions, except per-share amounts June 25 Guidance May 1 Guidance 1 Includes MTM adjustment - see slide 185 for guidance Note: See slide 153 for commodity price assumptions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available at the end of this presentation.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Exploration & Production 1 Midstream Gas Pipeline Gas Marketing 2 Total Recurring Before MTM Adj. 3 MTM Adjustment Total Recurring After MTM Adj. 3 Gas Marketing After MTM Adj. 2 $1,350 - 1,700 1,100 - 1,300 625 - 675 (20) - 10 $3,110 - 3,660 (10) $3,100 - 3,650 ($30) - 0 775 - 1,025 $1,250 - 1,750 1,000 - 1,400 640 - 690 (10) - 30 $2,930 - 3,830 (30) $2,900 - 3,800 ($40) - 0 (10) 2,510 - 3,010 2,500 - 3,000 1,100 - 1,400 2,630 - 3,230 2,600 - 3,200 5 1,000 - 1,300 (20) 850 - 1,150 (25) Potential Future Projects TBD TBD Consolidated 2008-09 Recurring Segment Profit Dollars in millions 2008 2009 Note: If guidance has changed, previous guidance from 5/1/08 is shown in italics directly below. See slide 153 for commodity price assumptions 1 Includes forecast legacy hedge losses totaling $59 MM in '08 and $119 MM in '09. See slide 173 for hedge details 2 Includes losses on certain contracts related to former Power segment and excludes any gains or losses associated with the exit of legacy positions 3 Sum of the ranges for the business units does not match the consolidated total due to the offsetting effect of natural gas prices within our business units. Additionally, corporate and other is not forecast separately but is included in the total guidance.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Economic Natural Gas Exposure for E&P and Midstream Consolidated 2008 2009 E&P Length + Midstream Short 127719 126868 Midstream Fuel & Shrink -321162 -315739 E&P Unhedged Position 448881 442607 E&P Hedged Position 530000 586438 2008-2009 * All values are undiscounted * International E&P volumes are not included * Projected E&P volumes are reduced for fuel & shrink and production taxes * WPZ volumes are not included (expected Fuel & Shrink for WPZ is ~100K/day for 2008 and ~90K/day for 2009) * Hedges are presented in terms of notional quantity

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Economic Rockies Natural Gas Exposure for E&P and Midstream Consolidated 2008 2009 E&P Length + Midstream Short 14219 58288 Midstream Fuel & Shrink -177910 -165401 E&P Unhedged Position 163692 107114 E&P Hedged Position 200000 235000 * All values are undiscounted * International E&P volumes are not included * Projected E&P volumes are reduced for fuel & shrink and production taxes * WPZ volumes are not included (expected Fuel & Shrink for WPZ is ~45K/day for 2008 and ~40K/day for 2009) * Hedges are presented in terms of notional quantity * E&P Gross Commodity Position is net of transportation agreements 2008-2009

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Capital Expenditures Exploration & Production Midstream Gas Pipeline Other/Corporate Total Potential Future Projects Total Potential Capital $1,800 - 2,000 800 - 850 1 350 - 450 60 - 90 1 $3,025 - 3,375 100 - 300 $3,125 - 3,675 $1,625 - 1,825 600 - 650 400 - 550 10 - 30 $2,625 - 3,025 400 - 800 $3,025 - 3,825 2,300 - 2,700 2,600 - 2,950 1,450 - 1,650 700 - 750 360 - 495 1,450 - 1,650 450 - 500 Consolidated Dollars in millions 2008 2009 Notes: - - If guidance has changed, previous guidance from 5/1/08 is shown in italics directly below - - Sum of ranges for each business line does not necessarily match total range - - Investments in additional value adding opportunities will likely cause capital to increase somewhat from guidance ranges 1 Includes carryover from prior year due to capital spending timing differences

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Cash Flow Consolidated Dollars in millions 2008 2009 Notes: 1 Cash flow from continuing operations. 2 Calculated based upon current minority interest levels. 3 Balance of $1 Billion share repurchase program. Note $526 million was repurchased in 2007 with an additional $314 million repurchased through 6/19/08. 4 Potential additional value-adding investments, share or debt repurchases, and drop-downs.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Share Repurchase Update 3Q '07 7.45 $234 $31.40 4Q '07 8.45 $292 $34.56 1Q '08 3.72 $126 $33.93 4/1/08 - 6/19/08 4.92 $188 $38.20 Total 24.53 $840 $34.23 Consolidated Note: The sum of the amounts may not equal due to rounding *Does not include commissions Shares and dollars in millions, except per-share amounts Shares $ $/Share*

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm CFO's Summary Great Businesses with Abundant Opportunities: E&P Midstream Gas Pipeline Vast amount of growing/low-risk reserves Rapid organic production growth Attractive net back prices/low costs Very favorable returns on capital Large scale assets in growth basins Tremendous organic growth opportunities MLP provides lower cost of capital source High returns on capital Large scale assets in growth supply/market areas Low risk/attractive returns Cash generator - fuels other businesses growth MLP provides lower cost of capital source

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm CFO's Summary (continued) Focus on sustainable value creation/EVA growth EPS 2007 vs. 2006: 61.7% increase, 2008 vs. 2007: 47.4% increase CFFO 2007 vs. 2006: 18.4% increase, 2008 vs. 2007: 47.5% increase Total Shareholder Return of 38.5% in 2007 and 7.2% y-t-d 2008 Investment grade capital structure reduces risks & enables rapid value enhancing growth - even in difficult capital markets Disciplined risk management, capital management & capital allocation EVA based management incentive program reinforces capital discipline MLP's provide an attractive/lower cost source of equity capital - enabling even greater value creation Share repurchases with excess cash plus consistent dividend increases Willingness to restructure when convinced sustainable value will be created: 2002/2004 asset sales 2007 Power sale Continuous review & willingness to act if warranted Bottom line - Management is excited about continuing extraordinary value creation ahead!!!

Summary Steve Malcolm Chairman, President & CEO

eSlide - P5055 - Analyst Day - Malcolm 6/23/2008 - 11:45am Williams - The Premier Natural Gas Investment Portfolio of best-in-class natural gas assets in North America Sustainable, organic growth opportunities abound Benefit from favorable commodity markets Growth with discipline - EVA1 focus Pulling levers to create additional shareholder value 1 Williams uses Economic Value Added(r) as the tool to measure its success. EVA measures the value created by a company - specifically the financial return in a given period less the capital charge for that period.

Q&A

Appendix

Exploration & Production

Powder River CBM Production Total Powder River Basin CBM Production * WOGCC Data Feb. 2008 1.38 Bcfd (MMcfd) Exploration & Production 0 200 400 600 800 1,000 1,200 1,400 1,600 Jan 97 Jul 97 Jan 98 Jul 98 Jan 99 Jul 99 Jan 00 Jul 00 Jan 01 Jul 01 Jan 02 Jul 02 Jan 03 Jul 03 Jan 04 Jul 04 Jan 05 Jul 05 Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08

3.65 BCFD Midwest Markets (3.95 BCFD Q2 2009) Trailblazer 905 MMCFD WIC 770 MMCFD CIG 600 MMCFD Powder River Basin Cheyenne Hub KN- PE 135 MMCFD MIGC 185 MMCFD FUGG 1.0 BCFD (1.25 BCFD Q2 2008) Thunder Creek 450 MMCFD WIC Medicine Bow Lateral 1.113 BCFD (1.463 BCFD Q4 2008) KN 150 MMCFD KN 120 MMCFD PSCO 430 MMCFD CIG 55 MMCFD Cheyenne Plains 840 MMCFD CIG 600 MMCFD 1.03 BCFD To Denver Glenrock 1.635 BCFD (1.885 BCFD Q2 2008) WBI @ Landeck 105 MMCFD REX 1.5 BCFD (1.8 BCFD Q2 2009) Bison (400 MMCFD Q4 2010) REX 1.5 BCFD (1.8 BCFD Q2 2009) Powder River Basin Pipeline Capacity 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 60 1.2 1.2 - 1.8 West Grand Valley 2 1.3 1.2 - 1.8 Ryan Gulch 56 1.5 1.2 - 2.4 Allen Point 31 1.3 1.2 - 1.6 * Estimated Ultimate Recovery Exploration & Production

Rockies Producer Not Necessarily a Rockies Price Taker 150 200 209 200 100 285 Rockies price risk managed through transport and basis hedges Our contracted pipeline capacity moves our Rockies production to more favorable price markets Firm Capacity Under Contract Firm Capacity Under Contract Wamsutter 200 East to Midcontinent 209 South to San Juan 285 So. California 100 Opal 150 Additional Firm Capacity Coming in '09 Additional Firm Capacity Coming in '09 East to Appalachia (REX) 200 Exploration & Production

Note: The only remaining legacy fixed price hedges are in 2010 of 70MMcfd @ $3.73 2008-09 Hedge Update Exploration & Production 2Q-4Q 2008 2009 Legacy Fixed Price at the Basin Legacy Fixed Price at the Basin Legacy Fixed Price at the Basin Volume (MMcf/d) 70 106 Average Price ($/Mcf) $3.99 $3.67 At the Basin Collars At the Basin Collars At the Basin Collars NWPL Volume (MMcf/d) 160 150 Average Price ($/Mcf) $6.08-$9.04 $6.11-$9.04 San Juan Volume (MMcf/d) 220 245 Average Price ($/Mcf) $6.37-$9.00 $6.58-$9.62 Mid-Continent Volume (MMcf/d) 80 85 Average Price ($/Mcf) $7.02-$9.77 $7.06-$9,76

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm What is Midstream's Business? Geismar Midstream Net Book Value + Equity Investment @12/31/07 = $3,860 MM 2007 Recurring Segment Profit = $1,071 MM 2007 Recurring Segment Profit + DD&A = $1,285 MM

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm How To Calculate a Frac Spread Midstream Notes: 1. Commodity pricing per published indicies and do not reflect Williams' realized prices, costs or contract structure. 2. Above calculations do not reflect the higher transit inventory impact to Williams' equity NGL sales volume and impact of Williams' NGL Forward Sales

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Midstream Geographic Profile 2007 Gross Margin by Asset 2007 Net Book Value and Equity Investments by Assets MS West Region MS Gulf Region Venezuela Olefins MS Other WPZ West Region WPZ Gulf Region WPZ onway 31 17 8 10 1 26 4 3 MS West Region WPZ West Region MS Gulf Region WPZ Gulf Region MS Other WPZ Conway Venezuela Olefins MS West Region MS Gulf Region Venezuela Olefins MS Other WPZ West Region WPZ Gulf Region WPZ onway 14 33 11 13 22 6 1

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Historical Commodity Prices NGL Barrel Composition: Ethane 50%, Propane 25%, Butane 15%, Natural Gasoline 10% 1/1/2003 2/1/2003 3/4/2003 4/4/2003 5/5/2003 6/5/2003 7/6/2003 8/6/2003 9/6/2003 10/7/2003 11/7/2003 12/8/2003 1/8/2004 2/8/2004 3/10/2004 4/10/2004 5/11/2004 6/11/2004 7/12/2004 8/12/2004 9/12/2004 10/13/2004 11/13/2004 12/14/2004 1/14/2005 2/14/2005 3/17/2005 4/17/2005 5/18/2005 6/18/2005 7/19/2005 8/19/2005 9/19/2005 10/20/2005 11/20/2005 12/21/2005 1/21/2006 2/21/2006 3/24/2006 4/ 24/2006 5/25/2006 6/25/2006 7/26/2006 8/26/2006 9/26/2006 10/27/2006 11/27/2006 12/28/2006 1/28/2007 2/28/2007 3/31/2007 4/1/2007 5/2/2007 6/2/2007 7/3/2007 8/3/2007 9/3/2007 10/4/2007 11/4/2007 12/5/2007 1/5/2008 2/5/2008 3/7/2008 4/7/2008 5/8/2008 Crude Oil 32.7 35.733 33.156 28.136 28.071 30.52 30.702 31.597 28.311 30.345 31.056 32.142 34.225 34.5 36.718 36.617 40.28 38.05 40.808 44.884 45.938 53.094 48.476 43.256 46.852 48.053 54.63 53.218 49.798 56.5 60.57 68.94 65.553 62.27 58.34 59.45 65.538 61.926 62.966 70.161 70.961 70.97 74.463 73.084 63.895 59.137 59.43 62.07 63.15 51.13 58.07 56.73 63.88 63 68.18 75.57 79.64 85.683 94.631 91.743 92.929 95.349 105.42 112.4627 114.86 NGLs 22.557 26.889 24.189 19.148 20.48 21.459 20.025 20.507 19.596 21.287 21.328 23.969 27.095 23.528 22.949 23.436 26.02 25.951 28.04 30.769 29.803 34.601 34.399 29.77 28.589 29.387 32.831 32.517 29.24 30.412 32.288 36.989 44.542 43.977 38.394 40.959 38.12 34.155 34.238 38.492 39.238 40.681 45.157 43.717 37.29 35.469 34.987 36.124 33.47 35.446 38.188 41.233 43.963 43.169 44.431 44.934 49.509 59.046 59.046 59.081 59.76 54.78 57.04 58.6 61.55 Rockies Gas 3.057 4.348 4.485 3.316 4.523 4.682 4.348 4.447 4.218 4.179 4.101 5.3 5.444 4.796 4.684 4.941 5.265 5.188 5.175 4.943 4.359 5.108 5.564 6.042 5.466 5.453 6.215 6.401 5.598 5.79 6.24 6.41 9.32 10.37 7.17 10.89 7.301 6.521 5.734 5.648 5.018 5.281 5.24 6.012 3.556 4.498 6.555 5.612 4.55 6.25 5.566 4.064 4.684 4.667 3.698 3.304 1.14 2.716 3.672 5.949 7.21 7.65 8.13 8.79 8.47 Henry Hub Gas 5.387 7.003 6.367 5.266 5.764 5.799 5.036 4.967 4.615 4.655 4.401 6.121 6.041 5.401 5.377 5.698 6.292 6.265 5.918 5.426 4.989 6.266 5.881 6.631 6.174 6.091 6.913 7.187 6.471 7.21 7.58 9.43 12.109 13.36 10.29 12.98 8.757 7.619 6.882 7.105 6.233 6.257 6.051 7.245 4.951 5.653 8.369 7.5 6.905 6.917 7.64 7.558 7.508 8.03 6.211 6. 296 5.98 6.681 7.006 7.081 7.933709677 8.457 9.337 10.1145 11.28 Midstream

eSlide - P5055 - Analyst Day - Midstream 6/22/2008 - 2:00pm Historical Commodity Prices Stated in $ / MMBtu 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 Q3'06 Q4'06 Q1'07 Q2'07 Q3'07 Q4'07 Q1'08 Rockies Gas 3.96 4.17 4.34 4.53 4.97 5.13 4.83 5.57 5.71 5.93 7.32 9.48 6.52 5.32 4.94 5.56 5.46 4.47 4.06 4.11 7.66 NGLs 6.66 5.53 5.44 6.02 6.66 6.82 8.02 8.94 8.22 8.34 10.3 11.16 9.64 10.71 11.42 9.64 9.69 11.61 11.48 16.03 15.53 Henry Hub Gas 6.25 5.61 4.87 5.06 5.61 6.08 5.44 6.26 6.39 6.96 9.71 12.21 7.75 6.53 6.08 7.17 7.15 7.7 6.16 6.92 8.58 Crude Oil 5.84 4.98 5.21 5.38 6.06 6.61 7.56 8.32 8.59 9.17 11.21 10.35 10.94 12.19 12.15 10.38 9.91 10.55 12.84 15.64 16.88 NGL Barrel Composition: Ethane 50%, Propane 25%, Butane 15%, Natural Gasoline 10% Midstream

Gas Pipeline

Transco Rate Comparison Zone 4 (MS thru GA) Rate Comparison - Transco Pipeline vs. Competitors (100% Load Factor with Basis) Zone 5 (SC thru VA) Zone 6 (MD thru NY) $0.448 $0.557 $0.878 $0.891 $1.238 $0.837 $0.878 $0.778 $0.654 $0.749 $0.557 Gas Pipeline ($0.10) $0.10 $0.30 $0.50 $0.70 $0.90 $1.10 $1.30 Transco Sonat Transco Sonat E. Tenn Columbia Transco Tetco Tenn Columbia Iroquois Demand Commodity Fuel Basis

Northwest Rate Comparison Demand Commodity Third Party Fuel Basis NWP/Paiute 0.3798 0.03 0.3353 0.1515 GTN/Tuscarora 0.319 0.0098 0.4019 0.2306 0.67 NWP 0.3798 0.03 0.096 GTN 0.6094 0.0117 0.1044 0.67 NWP 0.3798 0.03 0.096 GTN 0.0868 0.0017 0.0189 0.67 To Reno To Medford To Spokane Rate Comparison - Northwest Pipeline vs. Competitors (100% Load Factor with Basis) Gas Pipeline

2008-09 Capital Spending Detail 2008 2009 Normal Maintenance/Compliance $180 - $260 $180 - $280 Expansion + Contributions to Gulfstream $180 - $235 $220 - $270 Total $360 - $495 $400 - $550 Dollars in Millions Gas Pipeline

Consolidated

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm Exploration & Production 3 Midstream Gas Pipeline Gas Marketing 2 Total Reported Before MTM Adj. 1 MTM Adjustment Total Reported After MTM Adj. 1 Nonrecurring Items Total Recurring After MTM Adj. 1 Gas Marketing After MTM Adj. 2 $1,468 - 1,818 1,100 - 1,300 625 - 675 (20) - 10 $3,228 - 3,778 (10) $3,218 - 3,768 (118) $3,100 - 3,650 ($30) - 0 775 - 1,025 $1,250 - 1,750 1,000 - 1,400 640 - 690 (10) - 30 $2,930 - 3,830 (30) $2,900 - 3,800 - - $2,900 - 3,800 ($40) - 0 (10) $2,628 - 3,128 $2,618 - 3,118 $1,100 - 1,400 $2,630 - 3,230 $2,600 - 3,200 5 $2,500 - 3,000 $2,600 - 3,200 $1,118 - 1,418 (20) 850 - 1,150 (25) Consolidated 2008-09 Reported Segment Profit Dollars in millions 2008 2009 Note: If guidance has changed, previous guidance from 5/1/08 is shown in italics directly below. See slide 153 for commodity price assumptions 1 Sum of the ranges for the business units does not match the consolidated total due to the offsetting effect of natural gas prices within our business units. Additionally, corporate and other is not forecast separately but is included in the total guidance. 2 Includes losses on certain contracts related to former Power segment and excludes any gains or losses associated with the exit of legacy positions 3 Includes forecast legacy hedge losses totaling $59 MM in '08 and $119 MM in '09. See slide 173 for hedge details

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Interest Expense Forecast Guidance Interest on Long-Term Debt $605 - $620 $605 - $620 Amortization Discount/Premium and other Debt Expense 25 - 35 20 - 30 Credit Facilities: (Incl. Commitment Fees Plus LC Usage) 30 - 40 20 - 30 Interest on other Liabilities 5 - 15 5 - 15 Interest Expense $665 - $710 $650 - $695 Less: Capitalized Interest (60) - (40) (50) - (30) Net Interest Expense Guidance $605 - $670 $600 - $665 Consolidated Dollars in millions 2008 2009

Non-GAAP Reconciliations

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 income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Operating free cash flow is defined as cash flow from continuing operations less capital expenditures, before dividend, minority interest or principal payments and financing transactions. Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing 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, operating free cash flow 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 Gas Marketing Services mark-to-market adjustments. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses the mark-to-market adjustments to better reflect Gas Marketing's results on a basis that is more consistent with Gas Marketing'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 derivative assets and liabilities 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 Gas Marketing segment but does not substitute for actual cash flows. We also apply the mark-to-market adjustment and the recurring adjustments to present a measure referred to as recurring income from continuing operations after mark-to-market adjustments.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Forecast EBITDA Reconciliation Income from Continuing Ops. $1,458 - 1,758 $1,250 - 1,760 Net Interest 605 - 670 600 - 665 D D & A 1,230 - 1,330 1,350 - 1,450 Provision for Income Taxes 945 - 1,075 840 - 1,115 Other/Rounding (13) - (8) (40) - 10 EBITDA $4,225 - 4,825 $4,000 - 5,000 MTM Adjustments (10) (30) EBITDA - After MTM Adj. $4,215 - 4,815 $3,970 - 4,970 Non-GAAP Reconciliation Dollars in millions 2008 2009

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Forecast Segment Contribution Segment Profit 1 DD&A Segment Profit Before DDA Minority Interest and Other Rounding TOTAL $3,228 - 3,778 2 1,230 - 1,330 $4,458 - 5,108 (220) - (275) (13) - (8) $4,225 - 4,825 $2,930 - 3,830 1,350 - 1,450 $4,280 - 5,280 (240) - (290) (40) - 10 $4,000 - 5,000 Non-GAAP Reconciliation Dollars in millions 2008 2009 1 Segment Profit is prior to MTM adjustments 2 Includes nonrecurring gain of $118 million on sale of Peru interest Additionally, corporate and other is not forecast separately, but is included in the total guidance.

eSlide - P5055 - Analyst Day - Corporate Finance 6/22/2008 - 2:00pm 2008-09 Forecast Guidance Contribution Income from Continuing Operations: Non-Recurring Items (Pretax) Less Taxes Non-Recurring After Tax 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 Cont. Ops after MTM Adj. EPS $1,458 - 1,758 (118) (45) (73) 1,385 - 1,685 $2.31 - $2.81 (10) (4) (6) 1,379 - 1,679 $2.30 - $2.80 $1,250 - 1,760 - - - - - - 1,250 - 1,760 $2.08 - $2.93 (30) (12) (18) 1,232 - 1,742 $2.05 - $2.90 Non-GAAP Reconciliation Dollars in millions, except per-share amounts 2008 2009

The Williams Companies, Inc.