Travis Campbell, Vice President of Investor Relations Steven Malcolm, Chairman, President and Chief Executive Officer Donald Chappel, Chief Financial Officer and Senior Vice President Ralph Hill, Senior President, Exploration and Production William Hobbs, Senior Vice President, Power Andrew Sunderman, Chief Risk Officer Alan Armstrong, Senior Vice President, Midstream Gathering & Processing

Scott Soler, Morgan Stanley Craig Shere, Calyon Securities (USA) Inc. Carl Kirst, Credit Suisse First Boston Samuel Brothwell, Wachovia Securities Faisel Khan, Citigroup John Levin, Levin Capital Maureen Howe, RBC Capital Markets Jeff Coviello, Duquesne Capital Drew Swinson, Matador Capital Becca Followill, Howard Weil Richard Gross, Lehman Brothers Jeff Berg, Matador Capital Andrew Levy, Bear Wagner

Good day everyone and welcome to The Williams Companies First Quarter 2006 Earnings Conference Call. Today's call is being recorded. At this time, for opening remarks and introduction, I would like to turn the call over to Mr. Travis Campbell, Investor Relations officer. Please go ahead, sir. Travis Campbell, Vice President, Investor Relations: Thank you, and good morning everybody from Tulsa, Oklahoma. Welcome to The Williams First Quarter 2006 Earnings Call, and thank you so much for your interest in our company. Today, you will hear from Steve Malcolm, our CEO; Don Chappel, our CFO; and Ralph Hill, President of our E&P business. A couple of things about the format today is a little different from previous quarters. It’s more streamlined, all of our business unit heads are not presenting, but be aware that each of them is either here in the room with us or on the phone available for any questions that you might have. Additionally, all the slides and the robust detail that you come to expect from us is available in the appendix to this presentation. So, any information you found valuable in the past is still available for your use. Before I turn it over to Steve, please note that all the slides, both those used in the presentation and the appendix, are available on our website http://www.williams.com/, in a PDF format. Slide No.2 titled "Forward-looking statements," details various risk factors related to our future outcomes. Please read that slide. Slide No.3, "Oil and gas reserves disclaimer" is also very important, and we urge you to read that slide as well. Also included in the presentation today are various non-GAAP numbers that have been reconciled back to GAAP: Generally Accepted Accounting Principle. Those schedules follow the presentation and are integral to our presentation. So with that, I will turn it over to Steve Malcolm. Steven Malcolm, Chairman, President, Chief Executive Officer: Thanks Travis and welcome to our first-quarter conference call. And as always, thank you for your interests in our company. We are delighted with our first-quarter progress, and our investment thesis continues to revolve around four key points. First, we own and operate some of the very best natural gas-related assets in North America. Secondly, we are opportunity-rich in terms of our organic investment options. Thirdly, we are investing in a disciplined and prudent manner, as we have embraced the EVA methodology. And lastly, we believe we are in the midst of a sustained, attractive energy commodity price environment that will allow our businesses to prosper. Looking at slide No.5, which lists the headlines of our first-quarter performance. First of all, our key earnings measure, that being recurring income from continuing operations after mark-to-market adjustments jumped 19% on first-quarter performance from $132 million to $157 million. Key drivers of that improvement: increased natural gas production, higher net realized prices for production sold, and near-record margins realized on our sales of equity NGLs. Secondly, in the E&P space, core development and step-outs have allowed us to increase our proved, probable and possible reserves by 22%. Our 3P reserves now totaled 10.7 trillion cubic feet. Recall that our previous estimate was 8.8 trillion cubic feet. Thirdly, drilling activity has allowed us to increase natural gas production 16%. First quarter '06, our average daily production was approximately 714 million a day compared to first quarter '05, which was 614 million cubic feet a day. Next, the drilling ramp-up is designed to deliver more reserves and create strong production growth. We now have 21 rigs operating in the Colorado Piceance Basin, six more H&P rigs are scheduled for deployment yet this year. And another highlight, in March, we celebrated 400 million a day of production in the Piceance Basin. Our integrated model has allowed us to balance the volatile commodity markets. It should be no surprise, given lower natural gas prices, that we are lowering our expectation for E&P earnings for 2006. But importantly, we are maintaining our consolidated earnings guidance for '06 because of stronger than expected margins and volume demand in our Midstream business. Sixth, the company is working to complete the $360 million transaction with our MLP, WPZ. And we expect the Four Corners deal to be completed and closed in the second quarter. Finally, a series of financings have contributed to a stronger balance sheet. Some of the steps that have been taken include early retirement of secured debt, early conversion of debentures, we have replaced our secured revolver with a larger, unsecured revolver, and we have issued $200 million in senior unsecured notes at Transco. There are other steps planned, as Don will describe later in our call. Another point to make under that last bullet, some late-breaking news, S&P has upgraded Williams to BB minus with a positive outlook based on our continued deleveraging and improved operating performance. So, we are delighted with that. Slide six shows the key operations accomplishments for our four business units. And again, going through here quickly, in the E&P space, we have increased our first quarter '06 versus first quarter '05 natural gas production by nearly 100 million cubic feet a day. We are ramping up our Piceance Basin development. We have deployed four new H&P rigs, and we are capturing the cost and efficiency and environmental benefits associated with those rigs. We have kicked-off our 2006 drilling in the Piceance Highlands, obviously we couldn't kick that off until the winter weather broke. But we plan to drill over 50 wells this year in the Highlands. And, I think, another important point is that we were successful in achieving additional 10 acre spacing on 11,000 acres in the Piceance. In the Midstream space, we firmed up plans for new NGL takeaway capacity from Wyoming. The Overland Pass Pipeline project will create important transportation capacity from our two processing facilities in Wyoming, I am speaking there of Opal and Echo Springs. We have entered into sales hedge for some of our NGL production. I encourage you to look at slide 56 for details of that hedging. We are making good progress on rate case preparation to put new rates into effect on Northwest Pipeline in January of 2007 and Transco in March of 2007. We will be making those filings this summer. With the new 23-year agreements, all of Gulf stream's capacity is contracted under firm, long-term contracts, we are delighted to have that behind us. We have received very strong demand from customers for expansions on our other interstate gas pipelines, on Transco, good examples there: the Leidy to Long Island expansion, Potomac and Sentinel expansions; and on Northwest, the Parachute and Greasewood projects. Lastly, we have executed additional risk-reducing deals in the Power space. I encourage you to take a look at slide 67, which shows how the Power transactions that we have entered into since January of 2005 have increased cash flow dramatically; in fact, by $580 million through 2010. So with that introduction, I will turn it over to Don Chappel. Donald Chappel, Chief Financial Officer, Senior Vice President: Thanks, Steve. Good morning and thanks to all of you for joining us on the call. I will run through a summary of our first-quarter results and then turn it over to Ralph for a deeper dive into E&P. I will come back after Ralph's presentation to review our guidance and some other matters. Now let's turn to slide No.8: financial results. Net income of $132 million at $0.22 a share compared to 201 million or $0.34 a year ago. However, the effects of mark-to-market accounting on our Power business distorted the true economic profit, which was strong and improved as I will note in just a moment. And we will describe in more detail the mark-to-market accounting effects as we walk through the presentation. On the last line, and most importantly is recurring income from continuing operations after a mark-to-market adjustment. And again, we compare the $0.26 that we calculate to $0.22 on the same basis a year ago. And those earnings are up 19%, and really are more representative of the strong improvement in our businesses. I would also note that there is a variety of non-GAAP measures included in this presentation, including this key measure that I just mentioned. And those are fully described in this presentation and in the appendix. The next slide please, No.9. We calculate recurring income by adjusting out certain non-recurring items and I will just hit the highlights there. The key item in the first quarter of 2006 was early debt retirement expense and those are the premiums and fees related to the conversion of the convertible securities to equity during the first quarter. And that totaled $27 million. That was largely offset by a variety of other issues or other matters, for a net non-recurring item of $8 million pre-tax, or $3 million after-tax as compared to a $7 million deduction in 2005 pre-tax. Turning to the next page, and certainly more importantly this quarter, and this is slide No.10, recurring income from continuing ops after mark-to-market adjustments. I will walk you through our calculation of the mark-to-market adjustments, the adjustments where we eliminate the mark-to-market effects from Power's results and consolidated results. Starting in the middle of the page there, mark-to-market adjustments for Power, we first reverse the forward unrealized mark-to-market gains or losses, in this case $43 million of mark-to-market gains which were recorded during the current quarter, as compared to $221 million of such gains a year ago, a $178 million reduction in mark-to-market gains. Again, we eliminate those unrealized gains. And then we add back the realized gains from mark-to-market that was previously recognized. So again the mark-to-market effects that were previously recorded on the books reverse out as those positions are realized. So, we are adding back $77 million in the current quarter and $113 million a year ago. That change is $36 million, and the total mark-to-market adjustments before taxes totaled 34 million this year. Add back to income versus $108 million deduction from reported income last year, or $142 million pre-tax change, or an $87 million after-tax change. Again, I think you will agree with us, or continue to agree with us that this is the key earnings measure after mark-to-market adjustment is depicted at the bottom of this page. The next slide, please, No.11, first-quarter segment profit. This is in a consolidated format, both on a reported and a recurring basis. First, let's look down the page to segment profit after mark-to-market adjustment on a recurring basis. You can see over on the right, $438 million this year versus $392 million last year, an increase of $46 million. Now, let's go back up the page and take a look at the elements of that. E&P on a reported basis had a nice increase in profit and a very strong increase in profit as well on a recurring basis of $52 million or 54%. What is driving that is the 16% volume growth as we continue to expand our drilling program, and $33 million of higher net realized prices. I would also note that the current quarter had an $85 million negative impact from the hedge as compared to a $36 million negative impact in the first quarter of 2005. And the negative impact is the difference between the hedge prices and current market. The hedges are detailed later in this presentation. I believe that is on slide No.46. It is slide No.46. Turning next to Midstream, Midstream had a very strong quarter with a number of very noteworthy positives. We had higher deepwater production handling revenues, and I think that is a particular bright spot. We have made some significant investments in the deepwater, and they are paying off to an even greater extent. And we had higher revenue from increased GNP fees and slightly higher NGL margins; again, the NGL margins in the first quarter were quite high as compared to the five-year average margins. But we also enjoyed quite high margins a year ago. Offsetting that somewhat were lower olefin margins and higher gathering and processing operating expenses. Next let's look at gas pipelines. Reported results and recurring results were down somewhat as a result of higher O&M and G&A expenses totaling about $15 million, and the absence of a couple of items that we had in 2005, most notably a $5 million Gulfstream completion fee and a $3 million operating tax adjustment. Now let's take a look at Power. And again, Power's results are marred by mark-to-market accounting and some non-recurring items. Down at the bottom of the page, we strip out the non-recurring items and mark-to-market effects, and you can see Power in the current quarter earned $11 million on that basis, as compared to $17 million a year ago. We had improved portfolio Power results. Again, the base portfolio results improved somewhat, offset by the absence of natural gas storage and legacy results that benefited 2005. And during 2006, we had a decrease in expenses, largely the result of a $24 million gain related to the sale of a receivable. Let's next turn to slide No.12, and this is 2006 cash information. It really highlights the first-quarter cash flows. I will just walk through the key elements there. We started the year with about 1.6 billion in cash. We had cash flow from continuing operations of $165 million, and that is somewhat below our normal rate of cash flows. And if you can see the footnote on that page, cash flow from operations was reduced by the return of 192 million of margin deposits to counter parties. And we had a large margin return in exchange for a letter of credit. So, cash was returned to a counterparty in exchange for a letter of credit. And that is something that we do not include in our liquidity calculation, so that really had no effect on our calculation of liquidity, and is somewhat unusual. But I'll just note that for you, and we'll touch on that in a couple of further slides. Debt retirements totaled 64 million. Those were scheduled capital spending or investments in the business, 468 million. We paid 45 million of dividends. The other net represents the purchase of other current securities, cash-like securities, ending cash of 1.115 billion, and restricted cash was 118 million. While our cash balance is somewhat higher than what I would consider to be normal for our business, let me remind you that our planned capital spending exceeds our operating cash flows in 2006, and some of this excess cash balance will go to fund that very substantial growth. And I will talk more about that in some upcoming slides. The next slide, please, No.13, liquidity at March 31st. Again, we had cash and cash equivalents of 1.115 billion, other current securities of 184 million. In calculating available liquidity, we back out subsidiary and international cash that is not readily available to us totaling $284 million, and customer margin deposits totaling $129 million. And this is related to the note on the prior page, and I would note that that number at 12/31/05 was $321 million, or $192 million higher. And that is the change that reduced the cash flow from operations during the current quarter, as we returned that cash to a counterparty and received letters of credit in large part. Available unrestricted cash of 886 million is down from 1.159 billion as of yearend. Available revolver capacity at 1.349 billion that’s up from $961 million at yearend and total liquidity is at 2.2 billion, up from about 2.1 billion at yearend. Since the end of the quarter, we’ve reduced liquidity by almost $500 million as we paid off secured debt, that’s the RMT loan, and offset that by increasing liquidity by 225 million as we executed a new revolving credit facility on an unsecured basis that totaled $1.5 billion. That concludes the initial part of my presentation and I will turn it to Ralph. Ralph Hill, Senior Vice President, Exploration and Production: Thanks, Don. E&P, another strong quarter, with production up 16% and segment profit on a recurring basis was up 54%. Turning to slide 15, our total 3P reserves, Steve mentioned, grew by 22%. During the last call I discussed our year-end proved reserves with you, and they were up 13% to 3.6 trillion cubic feet, with a 277% reserve replacement rate. Looking at our 3P reserves, they are now 10.7 Tcf, which is an increase of 22% from last reported. This increase in estimated reserves is based on our latest analysis in drilling programs and drilling results, and it is primarily a result of our activity and successes in our relatively undeveloped areas of the Piceance Highlands. Looking at our resource potential, which we have talked before with you about being 12 to 15 Tcf, and that is on a resource potential basis, we believe that our resource potential is now at the upper-end of that 12 to 15 Tcf range. And that does not include new opportunities that we identify on appendix slide No.47 that I discussed with you during the last call. So, strong growth in our 3P reserves for E&P and for Williams this year. Looking at slide 16, Powder River, our total Powder River volumes are up 17 million a day, and this is in the overall total Powder River volumes were 16% from first quarter 2005. And the Big George continues to drive the volume growth, more than offsetting the Wyodak decline, which started about four quarters ago. Big George volumes were up 89 million a day, or 105%, from the first quarter of 2005. And if you look at sequential quarters, they were up 28 million a day, or 19% from the fourth quarter 2005. Slide 17, Piceance production growth, up 81 million, or 29% over a year ago. We mentioned that we had 21 rigs currently operating compared to 13 a year ago. Six additional H&P rigs will be received, with four H&P rigs are currently in that 21 number. We are on target to achieve the rig count of 25, and could actually be higher than that with six more H&P rigs coming. Please recall earlier in the year, we picked up additional rigs to compensate for the delay in delivery of the H&P rigs. Looking at the H&P early performance, the first six wells performance versus the field area benchmark on a drilling basis, we have had improvements in our drilling from 14% to 41%. The average of those six wells is a 27% increase in terms of improvement efficiencies. It is way too early to apply that type of percentage improvement to our program, but we are definitely encouraged by the performance of these flex rigs, which is what we expected and hoped to see happen. We also have completed the first simultaneous operations frac job on a pad, we believe, in North America with this kind of close well spacing. What that means is we are drilling on a well at the same time, we are completing a previously drilled well. We did it very safely. We did it in normal cycle time of fracturing, and we believe it is the first time that our team and the Halliburton team was able to accomplish on U.S. land operations. So, many thanks to our team for a lot of hard work to make signups work and it looks like it will work for us. Slide 18, a recap of our low-cost industry leader position on a three-year F&D case cost basis we're at $0.92. On this graph, you will see the top 15 E&P companies ranked by U.S. natural gas reserves so, our average of $0.92 on a three-year F&D cost stacked up against the top 15. If you look on an overall basis of the companies that are followed by Evaluate Energy, which is a source for this data, their F&D cost on a three-year basis is more like $2 on the average of all the companies that participate in that. So, our $0.92 per Mcf tracks very favorably with the industry. We are also top quartile in 2005 production cost per Mcf. And as I mentioned, we were top quartile in reserve replacement rate with 277%. Slide 19, realized gas price assumption is lower, slightly lower as this slide shows than what we had in a previous call. Obviously, that is with the softness that we have seen in the 2006 basin pricing that we are experiencing. However, I would point out that the numbers used for this slide, which basically have a NYMEX of $7 in 2007 and $7 in 2008, which is consistent with what we showed last time, and basin market prices of $6.32 and $6.34 for 2007, 2008 are below what we are seeing in the market today in 2007 and 2008 by approximately $1.80 to $2. So, there still could be some conservatism in this number. But however, for this year, as you see, our cash margin is down slightly on a three-year average, and that is driven primarily by the 2006 softer gas prices. Slide 20, we have numerous questions about our takeaway capacity. This is a slide I have pulled out in the past, and I've brought it back out. We are Rockies producer, but we are not necessarily a Rockies price taker. We have many directions and methods that we move our gas, and what this slide highlights is really our ability to move gas on a firm basis. There are other ways we can do that. Our mission in this -- we also have interruptible gas that we can flow on. But on a firm basis, this slide depicts what we can do. As I have discussed before, our mission is to have flexibility and optionality in moving our gas. We can stay in local markets as well as move our gas North, South, West and East. Our current firm access totals almost 700 million a day. We can go north to Wamsutter, east to the Mid-continent, and south to the San Juan, in addition to staying in the local areas. By 2008 and 2009, our firm access increases to over 1 Bcf a day, and we add the ability to go west to Opal via Northwest Pipe's expansion, and east to the Appalachians via the Rockies Express. So, our key goal is to move our gas and have optionality and flexibility, and we believe we are situated for not only our current volumes, but our future projected volumes. With that, I will turn it back over to Don. Donald Chappel, Chief Financial Officer, Senior Vice President: Thanks, Ralph. We will now look ahead and across the enterprise. Slide No.22, please. Our consolidated guidance stands unchanged, so moving parts within the guidance I would like to discuss. The first one that should be expected by all of you, as you follow the natural gas and energy business closely, is given that natural gas prices weakened following the very, very warm winter, we are adjusting our E&P segment profit guidance downward for 2006, adjusting the bottom-end of the range down by 125 million and the top-end down by 100 million. You can refer to slide No.46 in the appendix for the details and the current price assumptions we are using in our E&P guidance for unhedged volumes. In short, we have lowered our assumptions for those unhedged volumes by about $1 per Mcf in 2006. That brings our revised 2006 price assumptions down in line with our assumed prices for 2007 and 2008. And as a result, I think you will agree there is greater transparency as we compare 2006, '07 and '08 results particularly in the E&P segment. The other moving parts in our earnings guidance is within Midstream. We are moving Midstream's guidance upward by $100 million in 2006. This move is also commodity price driven. In this case, the environment of very strong crude oil prices and weakening natural gas prices is creating stronger than expected margins for natural gas liquids. You can also refer to slide 54 in the appendix for a look at the margin environment over the last 17 quarters. Again, consolidated earnings guidance remains the same at $0.78 to $1.03 per share for recurring earnings adjusted for the effects of mark-to-market accounting. While we are not providing EPS guidance for '07 and '08, we do expect strong increases as a result of the factors that we are discussing during this call. Next slide, please, No.23. 2006 to 2008 segment profit. This summarizes business unit and consolidated guidance. First, again, let's look at the bottomline. Total recurring segment profit after mark-to-market adjustment, 2006, the midpoint of the range is about 1.7 billion, 2007 is about $2 billion, and 2008 at $2.3 billion, a $600 million increase over the two years, or about 35%. Now let's take a look at E&P. As I mentioned earlier, we lowered our price forecast for natural gas prices in 2006, and we held our price forecast for 2007 and 2008. We are using about $6.10 price in the Rockies and San Juan Basin in 6, 7 and 8 as detailed in the appendix as well, let's move down to Midstream. Midstream again increased their forecast for 2006 by about $100 million on the strength of natural gas liquid margins. And I would also note that we used five-year average margins on the unhedged NGL volumes for 2006, '07, and '08. So again, we have experienced quite a bit higher than our five-year average margins over the last, I believe, seven quarters, yet our forecast continues to use five-year average margins. So we think that that's a conservative assumption at this point. I would also note that we have sold forward some NGLs for the first time, and that is detailed in slide 56. And that enables us to lock in those very high prices. The next line, gas pipelines. Again, we are in the year prior to a rate case. We are doing a lot of work in preparation for that rate case, and our 2007 and '08 results reflect the improvement in profitability following those rate cases, as well as the completion of the Northwest Pipeline expansion project, and a variety of other factors. Power results are marred by mark-to-market accounting. In the footnote, you will see Power's results after eliminating mark-to-market accounting effects, and that totals 50 to 150 million in 2006, 50 to 200 million in 2007, and 50 to 200 million in 2008. The mark-to-market adjustments you can see detail there, and those were the only changes in the Power guidance, and really just the effects of current period mark-to-market accounting. So again, no change in consolidated guidance. And over the three years I think you will see very strong improvement, about $600 million, or 35% over 2006. Next slide, please, No.24. 2006 to 2008 CapEx. Guidance, again, is unchanged. However, we are opportunity rich, and we expect to invest even greater amounts of capital, particularly in 2007 and '08 and beyond, as we continue to accelerate our development of our growing E&P reserves and seize the many value-adding opportunities we have in our franchise positions, both in Midstream, in the Western U.S. as well as in the Gulf of Mexico and in our gas pipeline businesses. Details on these growth opportunities are included in the appendix in the business unit reports regarding capital. We will continue to invest in a disciplined way in order to drive further growth in EVA and returns on capital, as well as value for our investors. I would note here, looking at E&P in particular, we are spending about $1 billion a year to develop our E&P reserves. And as Ralph noted, our rig count in the Piceance Basin is up sharply from a year ago. And I think you would agree that our plan is a year from now that the rig count would be up even more substantially as we add the balance of these 10 H&P rigs, with six yet to come. And again, in 2007 we would expect that all 27 rigs would be operating in the Piceance and drive even higher production levels. Midstream has a number of growth projects that are not currently included in capital -- some that are, some that are not. And again, I would refer you to the appendix for the details there. But we do have some exciting growth projects, both in the West and in the deepwater Gulf of Mexico that we expect to add to capital, and that will create a great deal of value for investors. On the gas pipeline business, again, 2006 includes about $300 million for the Northwest Pipeline replacement project, as well as substantial spending on Clean Air Act Pipeline Safety Act matters. Next slide, please, No.25. We have already reviewed segment profit guidance and CapEx. I would like to focus our attention on cash flow. As I mentioned earlier, we returned about 192 million to counterparties in margins, and our cash flow from operations during the current period has been reduced somewhat to reflect that. However, from a liquidity standpoint, it really had no effect on our calculated liquidity. Cash flow from operations is expected to grow from 1.5 billion to 1.8 billion this year to 2.2 to 2.6 by 2008, an increase of $700 or $800 million. Operating free cash flow is substantially negative this year, about $400 million, and forecast here to turn positive in 2007, and very strongly positive in 2008, based on the growth of the business and those strong cash flows and returns. The cash and liquidity to work our way through 2006, we believe is ample. And I will talk about some additional financing transactions that we will complete to fill out that picture. As well, the potential sale of assets to Williams Partners provide an abundant source of tax-advantaged capital, low-cost capital, to fund even greater growth in the future. Next slide, please, No.26. This slide graphically depicts our outlook and our plans; very strong operating cash flow growth, increasing investment opportunities, as well as credit improvement. Next slide, please, No.27. To summarize some of our financing activities to date, we increased equity and reduced debt through the early conversion of $220 million of subordinated convertible debentures. We removed secure debt, we retired the RMT term loan totaling $486 million, and we replaced the 1.275 billion credit facility with a 1.5 billion unsecured revolving credit facility, increasing liquidity by $225 million, and as well as improving our credit. We issued $200 million in senior unsecured notes at Transco and we retired 64 million debt at maturity. What’s ahead? We plan to issue some unsecured debt at the Williams level, in part to replace liquidity that we used in retiring the secured RMT loan. We will also raise capital during the sale of a portion of the Four Corners asset, 25.1% of the Four Corners asset to Williams Partners. And then finally, we will raise capital through a Northwest Pipeline bond issue, again, to finance its growth. These planned financial transactions, along with our strong cash and liquidity position will enable us to continue to grow and grow value rapidly, and continue to seize value-adding opportunities while maintaining and improving our credit metrics. Next slide please, No.29. I'll wrap up here. Again, some key points. We are very focused on driving and enabling sustainable growth in EVA and value for shareholders. We will continue to maintain a cash and liquidity cushion of $1 billion plus. Again, we are well above that today as a result of our need for capital to fund our growth, as well as to manage our commodity hedging positions. We will continue to steadily improve our credit ratios and ratings, ultimately achieving investment-grade ratios. And certainly, we believe that will also create value for investors. We will continue to reduce risk in the Power segment. And I think our Power team has made great progress in that regard. Since we took the business off the market in late 2004, the Power team has been able to hedge substantial forward cash flows. And you will see, I think, a pretty clear graphical depiction of that on slide No.67, which puts us in a position where we have very highly hedged cash flows for the next several years. And we are looking forward to hedging even to a greater extent further forward as the markets continue to tighten and as we just move forward through the calendar. Finally, I mentioned we are opportunity rich. We are increasing our focus, making additional EVA-based investments in our core natural gas businesses. We have substantial opportunities, particularly in our E&P business through the reinvestment in drilling up our reserves at a faster pace, as well as our franchise positions in Midstream and gas pipelines. If new capital is needed, we will choose the optimal source of capital. And as I mentioned earlier, we have abundant source of MLP tax advantage low-cost capital available to us. And the combination of growth and operating cash flow and EVA will continue to drive value creation. I am extremely bullish on our ability to continue to create strong increases in EVA and value for our investors. And while I expect continuous improvement of results, I see 2007 as a real breakout year. As you note that during 2007, we would be drilling in the Piceance with 27 or more rigs, as well as benefit from two successful rate cases, Transco and Northwest Pipeline. Again, I think the picture is quite bright. With that, Steve, I will turn it to you. Steven Malcolm, Chairman, President, Chief Executive Officer: Thank you, Don. And looking at the last slide, which is simply a listing of the headlines, I think we are very pleased with the steady across the board progress that we achieved during the quarter. Certainly achieved recurring earnings growth, we had crisp execution around steps to strengthen our balance sheet, and I think there was clear evidence that we continue to capitalize on the many organic growth opportunities that are available to us. So with that, our team is prepared to take your questions.

Q - Scott Soler: Hi good morning. I had a few questions. The first one -- and maybe Steve and maybe Ralph, just kind of think about this as -- it's going to be a long-winded question, but my point is return of capital versus return on capital. With the credit rating being improved because the balance sheet has improved so much, and the company having improving cash flow going forward, if I take your estimate, Ralph, potentially up to 15 Tcf or so of 3P potential for the company, at current rates of production that's a 50-year-plus inventory, which is great. The question I have is, there was a lot of rumors in the industry over the last couple of weeks of all the different companies looking at bidding on these Barnett Shale Properties, Chief. And how do you guys think about the fact that your stock at the current share price really implies that your 3P potential is worth I mean in other words, you could buy back stock at some point down the road for way less than $0.50 in Mcf; Devon purchased Chief for over $1 on 3P. And I am just trying to -- just a little bit philosophically how you think about return of capital versus return on capital. And how does the EVA formula, I guess, that factor in to share buyback opportunity versus continuing to grow? Because you got both opportunities on your plate right now, and I just want to get an update on that. A - Donald Chappel: Scott, this is Don. Certainly, I think you make a good point. And it's a point that we certainly are mindful of. However, I think, credit issues are major issues for us. And for us to continue to have access to the debt capital market, I think we need to continue to maintain and improve somewhat our credit metrics and our ratings. So, I think our view to date has been that a major share repurchase would be a huge setback from a credit standpoint, and would dry up our ability to access the capital market, both at the Williams level and at the Williams Partner level, as a result of ratings momentum that would become negative. And our models indicate that that would destroy value rather than create it. But we are certainly mindful of that opportunity, and we'll continue to analyze it. And if the situation changes enough that we have that flexibility, we'll certainly consider it seriously. A - Steven Malcolm: Scott, this is Steve. Perhaps embedded in your question was an inquiry on our interest in pursuing other E&P opportunities. And as we have said before, we always want to look at these opportunities. We want to evaluate them. We think that we -- in many cases we learn from the exercise. And we will continue to do that. We will continue to evaluate these kinds of opportunities. But the other very important point that we have made is that before we would act on something, it would have to be a very compelling deal. And it is very difficult to make sense of deals given the multiples that are being paid today. Q - Scott Soler: I appreciate you all showed a lot of restraint. And that was my only point, was that very few companies have 50 years of reserve potential long-term. And so, I think you all can be very choosy relative to a lot of companies in North American E&P, who are just trying to replace reserves -- just keep things flat, so. A - Steven Malcolm: Our goal is to drill those reserves up faster and faster. Q - Scott Soler: Okay. Second question if I could. Ralph, we are hearing that on some of these FlexRig and Helmerich, that at least on certain wells, their drill times in spud to spud is just a bit over 10 days. And I think most of those wells tend to flow gas from the time of completing to turning on the valve in maybe 45 days. And so, it seems as though -- I think what you were saying was, look, we are going to keep production guidance as is and be relatively conservative. But is that -- are you seeing those types of -- when you were talking about 41% efficiency, I think that gets to the sort of numbers I am talking about on number of days to drill wells, at least in certain projects. A - Ralph Hill: It does. It gets you in that range. The key is, obviously, we have got -- the numbers I just quoted to you were six wells. And we've drilled another handful since then, but that's as of first quarter '06. So, we are still getting those rigs delivered throughout the balance of this year or through like August, September. So, it takes time for one to make sure those kind of efficiencies are going to continue on, and two, to get the full momentum of that kind of program. But obviously, we are encouraged. And it could, I don't see it doing a lot this year necessarily. Remember again, we were behind on rigs, and we caught up, basically by acquiring some loaner rigs and other things in the wintertime. So, we actually were behind running into this year. We caught up during the first quarter, and now we feel like we are catching up in the sense of rigs. Our volumes have been where we want to be, on target. But it took a while to catch up. And now the good news is, we like what we see. They are more efficient. There is a few things here and there we want to -- we're going to tweak, and our partner is great about tweaking that. So there is a lot of potential in the future, it's too early to say if that means anything for 2006. Q - Scott Soler: Okay. And then my final question, I am not sure if Bill Hobbs is in the room. But on California, we had also been tracking down, I guess there is both the Legislature and PUC are talking more and more, still trying to get companies to extend, I mean now kind of looking for companies to come to them to extend contracts. And Don had alluded to the fact that you all are getting, I guess, at least encouraged that you might be able to do things for a little bit longer term. Could we get just maybe a little bit of context and an update on what the situation is in California? A - Bill Hobbs: Scott, we are certainly talking to the utilities about the existing contracts that we have, and looking to extend those beyond 2010. And I think there is movement in the Legislature and at the PUC, increased interest around creating reliability through these longer-term contracts. So, it's early, but we are certainly engaged in looking to do that. Q - Scott Soler: All right thanks.

We'll go now to Craig Shere at Calyon Securities. Q - Craig Shere: Hi, congratulations on the quarter. Ralph, can you comment on prospects for, and maybe the timing of when you might be looking at more drilling rigs, and how the labor market looks in terms of adding rigs as we go into 2007. And Don, do the NGL hedges on a consolidated basis should we assume that increases natural gas price sensitivity for Williams going forward? A - Ralph Hill: This is Ralph, I will go first, there is a tight market. We have several things just to be thinking of. We are in the process of contracting for some additional rigs, the new rigs that neighbors is drilling, or is building, called the Sundowner rigs, but those are more like 2007 type rigs when they will get to us. The second thing, we may not need necessarily additional rigs. As we have mentioned before, one of the reasons why is if we do -- are able to achieve the efficiencies we see early in, for example, the H&P program, and if the Sundowner rigs, which is what the neighbors brings to the table at the end of this year if they are more efficient, we actually will be able to do more with the existing rig fleet that we have. Having said that, we continue to be very opportunistic, to pick up additional rigs, and that's just the best we can do. But we have been pretty aggressive in going out and getting the H&P rigs. We are going to have some new neighbors rigs coming in. And the question here is, as we move through this portfolio, do we stay with the existing rig fleet and just add to it or do we weed out some of the inefficient ones. And those are just things we have to work at as we work through our operations this year. Q - Craig Shere: Can you give some color on the quantity of Sundowner rigs you are looking at? A - Ralph Hill: Four. Q - Craig Shere: Okay. A - Donald Chappel: Andrew will take the NGL question. A - Andrew Sunderman: Yeah, this is Andrew. On a consolidated basis, because of the fact that when we look at our portfolio, the NGL barrels that we have hedged at very attractive prices, the offsetting gas position is already considered on a consolidated basis. So, I do not believe that our exposure to natural gas price changes as a result of these hedges, but it does improve the company's overall spread position on the NGL spreads.

Have any questions sir? Q - Craig Shere: No, that’s it. Thank you.

Thank you. We'll go to Carl Kirst at Credit Suisse. Q - Carl Kirst: Good morning everybody, nice quarter as well. A couple of follow-up E&P questions. Ralph, on the increase on the 3P number, can you actually break that down for us as far as what is probable, what is possible? I was also wondering if there was any migration over the last year from one category to the other, if we could start there. A - Ralph Hill: No real migration from one to the other. Our proved, as you know, are about 3.6, our probable are in the range of -- that similar range, 3.6, 3.7, and possible is about 3.4. So that, hopefully, adds up to about the 10.7. Q - Carl Kirst: Roughly equal. Right. And with respect to the Piceance, as far as -- I don't know if you have the absolute numbers, or just a percentage of the probables and possibles. Just wondering how much of that is strictly Piceance versus the other areas? A - Ralph Hill: We split into the Highlands and the Valley. And I would say between the Highlands and the Valley, that is roughly 60% of the 3P number. Q - Carl Kirst: Great, just -- I guess this is maybe more of a question for Don, but just as we look at gas prices right now, your assumption of $7 NYMEX going forward, obviously, we are seeing prices much stronger than right now. Last I checked, and I don't know if there has been any additional update with this slide package but you were 40% hedged for '07. Is there any – we are leaning right now towards increasing that amount? A - Steve Malcolm: This is Steve Malcolm. We have said that normal year, we are going to be between 40 and 60% hedged, based on the businesses that we are in and the risks that we perceive, but that we will always evaluate what opportunities the market is offering us. And so, we evaluate the situation at least weekly, and we'll continue to do so. But I wouldn't want to indicate any leanings at this point. Q - Carl Kirst: Okay, fair enough. And then just one final question if I could, really relating more perhaps to the WPZ. Just a little bit of color, if you would on Overland Pass, the -- I guess the relationship with ONEOK. From a very 30,000-foot standpoint, I guess we saw that as a very, obviously, attractive project, and one that ultimately would be destined for WPZ. Can you give us some color as to why you decided to partner up on that rather than go it alone? A - Alan Armstrong: Sure, Carl this is Alan. Really great benefits that we saw from partnering with ONEOK. First of all, this gives us an option on our liquids between the Conway and Belvieu markets in our deal with ONEOK, which is very attractive to us. And actually, the real benefit of the project is not just the option for investment in it, after we see what construction costs and the volumes look like on it, but in addition to that benefit, the transportation tariff that we are going to see is in the order of a $20 million a year savings. And that's before we realize the benefit of the option value between those markets. So, the real plus on this deal for us is the lower transportation cost on our NGL barrels, as well as the option between Conway and Belvieu. So, it's really very attractive on that basis, and it provides an investment opportunity for us that looks attractive after most of the risk is out of the project. And that will be icing on the cake for us. Q - Carl Kirst: Great, thanks and good luck.

We'll go now to Sam Brothwell at Wachovia. Q - Samuel Brothwell: Hi, good morning, can you hear me? A - Steve Malcolm: Yeah. Q - Samuel Brothwell: The internal hedge, I guess you could call it, between Midstream and E&P worked pretty well, as you raised your guidance in Midstream by a similar amount to what you lowered it in E&P. And obviously, Midstream was helped by very strong crude prices during the quarter. Can you give us a little more color on how that relationship will play out, what kind of sensitivity we should look for in your segment profit going forward for changes in gas and crude? A - Steve Malcolm: First of all, as to the first quarter, we really didn't see that much boost in the first quarter from the frac spread, and we certainly are enjoying that as we speak. But if you recall kind of how prices moved first quarter, while it was good and we certainly enjoyed it, it wasn't the kind of margins that we are enjoying currently. Go ahead, Andrew. A - Andrew Sunderman: Yeah, I think if you look historically at the correlation between, say, the processing spread and the E&P production, I think we would expect -- for a $1 of gain or loss on the E&P side, you would typically expect $0.70, $0.75 in the other direction on the Midstream side only. But you also have to recall we have a Power business as well. So, on a consolidated basis, I think we have some sensitivity slides in our appendix. I don't know exactly what page they're on. But slide number 75 in our appendix, we kind of outline on a consolidated basis our exposure to natural gas. So, I think that's a pretty good guide at the end of the first quarter for what you could expect, at least for the time periods referenced. Q - Samuel Brothwell: Okay, I see that. That's very helpful. And if I may just one quick follow-up. Can you remind us some key dates to watch for in the rate case process in the pipeline segment, particularly in Transco? A - Donald Chappel: This is Don. We expect to file Northwest Pipe July 1, with rates that go effective January 1. And Transco September 1 the filing; rates go effective March 1. And clearly, there certainly could be some other news along the way, but those are the key dates. Q – Samuel Brothwell: Okay, thank you very much.

We'll go now to Faisel Khan at Citigroup. Q - Faisel Khan: Good morning. A - Steve Malcolm: Good morning. Q - Faisel Khan: With the recent increase in your deck rate, does that have any impact on your collateral requirements at all? A - Andrew Sunderman: This is Andrew. What we would expect -- we do have some contracts that have ratings-based improvements that we would expect to see. And I would say that I think that the rating is certainly reflective of the improvements we have made, and we're already seeing improving credit terms before we got the actual ratings increase. So, I do believe it will continue to be positive momentum to getting higher credit limits and return of collateral from our trading counterparties and from our other counterparties. Q - Faisel Khan: Okay. On the E&P unit, was your partner apart from the asset in the Powder River Basin, and you had an option to exercise to buy into some of those assets. What was the rationale for passing on that opportunity? A - Ralph Hill: This is Ralph. It did not meet our economic hurdles. Q - Faisel Khan: Okay, fair enough. And then in terms of some of the news we've been hearing about potential farm-out opportunities for major holders at Piceance Basin acreage -- is that something that you guys might be looking at? A - Ralph Hill: Well, I think that's one of the other operators more in the Valley that -- we have substantial acreage position there, and we, as you can tell by our Ryan Gulch and Allen Point, Trail Ridge activity that we are doing, there is opportunities for us, and there are additional opportunities listed on the additional opportunities slide that we are looking at in the Piceance; not particularly from any recent announcements, we have basically been looking at some of these and been negotiating on some farm-outs for quite awhile, and hope to bring a few of those across the table. Q - Faisel Khan: Okay, great. And just, if I could get some clarification on the pipeline. Your rates go into effect January 1st and March 1st of '07 -- is that right -- subject to refund? A - Ralph Hill: Yes. Q - Faisel Khan: Thank you for your time.

Next we'll go to John Levin, Levin Capital. Q - John Levin: Yes, I had two questions. One is, in the increment that you just reported, maybe the breakdown between possible, proved and probable. And secondly, you did say that you wanted to reduce the risk in the Power segment, and you are hedging perhaps future -- that was the answer to Scott Soler's question. Is there anything you can do to lower your heat rate output out there which would make it more competitive as well? So there are two very detailed technical questions. A - Ralph Hill: Well, I think -- what I said for the 10.7 T's of 3P reserves, it's 3.7 – Q - John Levin: No, no, no; you gave the breakdown. But I was interested in the increment in the quarter as the breakdown, at least between proved, possible and -- the breakdown of the increment is what I was looking for. A - Ralph Hill: The increment just on the probables and the possibles? Q - John Levin: Yes. A - Ralph Hill: I have to get that for you. I don't have that on the tip of my tongue. I will have to get that for you. Q - John Levin: Which category was most of it in? A - Ralph Hill: In what way? Q - John Levin: Well, 50/50, would you say, or three-quarters one way or the other? A - Ralph Hill: Of the movement, or total? Q - John Levin: Of the increment. A - Ralph Hill: I don't know that answer off the top of my head. Q - John Levin: Okay. And then on the heat rate improvement -- what about that anything? A - Andrew Sunderman: We have re-powering rights in California for our positions there. And the average heat rate is about 10,000, which seems high; but again, you have to focus on where the plants are located. They are there for reliability. But to the extent we can enter into longer-term contracts, we will certainly be looking at re-powering those assets. Q - John Levin: Thank you.

We'll go next to Maureen Howe at RBC Capital Markets. Q - Maureen Howe: Thanks very much. Couple of questions. First in the Power segment, I believe, Don, you mentioned you booked a 24 million -- I guess it would be a lower expense due to the sale of a receivable. Is that correct? A - Donald Chappel: Yes it is, Maureen. Q - Maureen Howe: So, I am just wondering, is it normal to sell receivables? And what are the economic factors that would go into that decision to proceed in that sort of strategy? A - Donald Chappel: This was a very unusual situation that I will let Andrew describe. A - Andrew Sunderman: Yeah, Maureen, this is Andrew. This was the finality of most of our remaining Enron receivables. As you know, that bankruptcy case has proceeded forward, and we saw an opportunity in the market to sell a major portion of the remaining receivables we had on that for very attractive prices. And that's what we did. Q - Maureen Howe: Okay. And obviously, that is a pre-tax number. A - Andrew Sunderman: Yes. Q - Maureen Howe: And just moving on, this is just really for clarification in some of the slides that are in the appendix. And first, with the Power slide on page 67, there it looks like, indeed, as has been mentioned, there's been good hedging forward of that book. And I'm just wondering, for 2007, if I add up the hedged amounts, it's about 502 million, I think across the various regions. But I guess also that has some estimates of option value and so forth. I'm wondering if there is a floor to that amount. A - Andrew Sunderman: I think what we have said in the past traditionally, and I think it is based upon some of our schedules that we show in our tutorial is, we feel pretty confident when we call something hedged that it is hedged. We have never really kind of outlined a number on a floor, but the floor is not going to be 50% of that number. If you look at what we presented in our tutorial at the year end last year, and also at year end '04, I think you will see that the numbers from hedged came in pretty close to the number. But we've never really said what the floor is, but there is not a material amount of volatility around that number. Q - Maureen Howe: Okay. So, the distribution around that is pretty tight? A - Andrew Sunderman: Yes. Q - Maureen Howe: Okay, that's great. And then one last question on slide 75, which is your sensitivity slide, and this is really a point of clarification. So, when we are talking about a $0.10 change, for instance, in the price of natural gas, and we look forward to 2007, 2008, this would be the impact across the company's various divisions reflecting what you have locked in or hedged. But for instance, you are not assuming, if I understand your notes correctly, for instance, what the price -- if you have a change in price from natural gas, you are not assuming a correlation, for instance, with the change in the price of Power; it's strictly the price of natural gas in the sensitivity. A - Andrew Sunderman: On column one, it is a completely correlated change. So, to the extent that gas changes, we have historical correlations to power, crude, and other products. So, column one would be a correlated move; columns two and three would not be. Q - Maureen Howe: Okay. So, again -- I'm sorry for this -- but in column one, then, if there is a proven change in that, the natural gas price, you would be capturing in that column, perhaps, some impacts on Power prices. A - Andrew Sunderman: That is correct. Q - Maureen Howe: Okay that’s great. (voice overlapping) Q - Maureen Howe: I appreciate that. Thanks to that clarification.

We'll go now to Jeff Coviello at Duquesne Capital. Q - Jeff Coviello: Good morning guys. How are you? At a question earlier on the call, you mentioned a technique that you were using in the Piceance; I think it was simultaneous fracking you referred to, I was wondering if that was reflected in your production growth at the E&P segment. Or if you were able to successfully implement that technique, it would be something that could increase your production growth over what you have previously stated. A - Ralph Hill: This is Ralph, I think it could ultimately improve overall, currently always looking to improve our time on drilling time, and also completion time. Obviously, if we are on the same pad, and we have, say, 12 to 22 wells on a pad, and we can drill four, skid over roughly 10 to 20 feet, begin completion operations while we -- begin drilling operations on a new set of wells right next to it, and being completing the other wells, that would decrease the move time you have. So, what we're doing for the first time is we are basically drilling, fracking, perforating and cementing all at the same time on the same pad, all within 20 or 30 feet of each other, all that activity. So, that would be something in the future also we might be able to -- or we hope will increase the ability for the number of wells we can drill and quicker production online. Haven't built that into our numbers, but it is something we would like to see happen. Q - Jeff Coviello: Got it. And the first time you attempted it, it went well? A - Ralph Hill: It has gone very well. And we did it with the first H&P rig over the last month. And we are starting today on the second one, same thing, what we call sim-ops (phonetic). So, we are doing the same thing -- drilling, fracking, perforating, cementing, all on the same pad on different wells at the same time. Q - Jeff Coviello: Great, thank you. And my next question just relates to the take-away capacity from the Rockies. And it seems like, based on the slides in the presentation, that you have gotten 200 Mcf a day on the Rockies Express. And I wanted to just kind of confirm that and also, there is a pipe there -- the Trailblazer, I believe it is called. I was wondering if you could give us a few details on that, when you might expect it to come online, if there is any possibility of getting capacity on it. A - Ralph Hill: Trailblazer is online. It is – it's been online for a long time. So, we have capacity today. And on the Rockies Express, we are not a firm shipper, but we have entered into an agreement with one of the firm shippers to sell them a, if you will, a firm amount of gas. So, that is why we call it a firm basis for our opportunities to move it out of the region. Q - Jeff Coviello: How long does that agreement go for? A - Ralph Hill: We haven’t divulged that, but it is a long-term deal. Q - Jeff Coviello: Got it. Okay, thank you very much.

Next we'll go to Drew Swinson (phonetic) at Matador Capital. Q - Drew Swinson: Yeah, following up a little bit on what Scott Soler had talked about. On page 18 you have -- obviously show great results in terms of your relative F&D costs, and obviously your growth rates, et cetera. But, the credit rating issue that you talked about, in terms of buying back stock versus buying another company -- I guess, how do you view looking at an acquisition in the EVA world -- how do you view that versus an EVA -- the best opportunities -- so if you go out and acquire something, you are going to have positive EVA. But how do you base that or weigh that against the most positive EVA opportunity, which I would think that given your structure and the way that it appears that the E&P business at your company is valued -- can you walk us through maybe more in-depth how you weigh those options off each other? A - Donald Chappel: Drew, we certainly have extraordinary EVA creation return on capital investing in our -- drilling up our E&P reserves. I would say in the E&P space, it’s difficult to find a large acquisition that is EVA-positive, given the volatility of gas prices. Certainly, that could turn out to be EVA-positive; however, risk factors are pretty substantial given the prices being paid and gas price volatility. So typically, larger acquisitions don't come anywhere close to our other opportunities, and therefore, we’ve not done one. Q - Drew Swinson: All right well that I guess is helpful and a good answer. I appreciate it, thank you.

We'll go next to Becca Followill at Howard Weil. Q - Becca Followill: Good morning. Thanks, first, for the abbreviated call, guys. I think I owe you on this one. Two quick questions. One on your 3P reserves, can you talk a little bit about what you have assumed on spacing for the Highlands project? And then second, you had talked about in previous presentations some new E&P opportunities in Uinta, Paradox, and even in the Piceance. Can you update us on if you have any information on that? And if not, when do you think you might? Thank you. A - Ralph Hill: The assumptions for Allen Point and Trail Ridge are 10-acre assumptions, and the assumptions for Ryan Gulch would be a 20-acre assumption, ultimately getting there. As you know, we do have 10-acre spacing in Trail Ridge. We do not have that yet. We do have it for a small portion of Allen, I think; maybe not. And we do not have that -- any down-spacing at Ryan Gulch. So, those are the assumptions there. As for the others, we, three of the four on the new opportunities are acreage that we own today. And it's just -- we are just beginning to establish when we are going to get in the fields and understand what we can do there. So, really no update on those yet, just long-term leases that we will start to prosecute here in the future. And I just don't know when yet. We have just got to continue to work our technical data. Q - Becca Followill: Thank you.

Q - Richard Gross: Yeah, I'm going to kind of meander a little bit, maybe esoteric relative to the other questions. You mentioned that ethylene margins in the first quarter were poor, and I was a little bit curious, given the value of ethane versus naphtha and other crude derivatives. And then, on that business moving forward, what kind of margins have you assumed in the base case for Midstream? A - Alan Armstrong: This is Alan. What we actually saw in the quarter was, it was lower than what we saw in the first quarter, and I think that is what we were referencing in terms of comparison, 1Q '05 to first quarter of '06. And that was about $21 million lower on just a pure margin basis quarter-to-quarter. In terms of the way we look at that going forward, we go purely off with the latest CMAI forecast. And so, you can always look to see what we have embedded in our margins by looking at that. Q - Richard Gross: Given that I can't access the CMAI because it's a pretty pricey item, could you tell me? A - Alan Armstrong: I don't have the complete forecast there, and I am sure we are prohibited from broadcasting that. But we will try to give you some guidance in terms of what we have embedded in a report. Q - Richard Gross: Is it a classic five-year average? A - Alan Armstrong: No, it is not. We will try to get something to you on that, Rick. Q - Richard Gross: Okay, I'm going to try to put words to your mouth on this next question. If I look at the ONEOK deal, my assumption is that you will back in for your interest. And what this does is it allows the other guys to spend money on the construction cost, and WPZ doesn't have to carry financing until start-up of cash flow. So, you back in at moment of start-up of cash flow. And that the other part of this would be because Bushton was struggling, that I assume that you have gotten some sort of reasonable deal to fractionate at Bushton, and you’ve got some, we'll call it reasonable deals to move product down to Mont Belvieu? A - Alan Armstrong: I think those points for the most part are clear. We certainly haven't made a decision as to whether that would be a WPZ or Williams investment. So, I certainly want to be clear on that. But obviously, the primary advantages that we get is we get some time to look at the project after some of the risks we worked out of it on top of that, which is very advantageous to us. But yeah, ONEOK makes a very good partner for us with the coke infrastructure. They make a very good partner in terms of moving product in between Conway and Belvieu. And we think that’s good for our investments at Conway as well, in terms of making that even more substantial market center. So, we are excited about the relationship with them, and we think it is a great use of the assets that they bought from Coke and their previous Bushton acquisition. So, pretty excited about that. I think it’s a great solution for the industry overall in terms of low energy cost transportation between the Rockies and Belvieu and Conway. Q - Richard Gross: Thank you.

We'll go to Scott Soler at Morgan Stanley. Q - Scott Soler: Hi, I have one more question. We may get this answer. I know that Standard & Poor's is having a conference call this afternoon at 2:00 Eastern regarding your debt. But what I wanted to ask, I guess, Don, is when they were going through this process most recently with you, were they specifically looking at certain coverage ratios of debt to EBITDA and CFO to debt, which would be -- debt to EBITDA would be something like 2.5 times in our model next year, if you exclude the tolls. Or was there a change in how they are viewing the tolls and how they are viewing the imputed debt, or at least how they are thinking about your risk management? And just could you maybe just sort of high-level chat for a minute on how that sort of generally was thought about, and what changed? A - Donald Chappel: I think they have some general guidelines, but there's also a lot of judgment in terms of -- they rate us eight on the business risk scale. We think that we are lower than that, but that's their judgment. And then they have guidelines within that methodology, and I think they use their guidelines consistently. However, there is judgment to be applied, and they apply their judgment. We meet with them quarterly. Certainly they’ve given us plenty of feedback along the way, and we are certainly appreciative that they have noticed how much improvement we have made. And in terms of the power tolls, I think they still view the obligation to be an obligation. I think they do have increased confidence that the hedges are in fact good, solid economic hedges, but I think they will talk more about that this afternoon. Q - Scott Soler: Okay.

Now we'll go to Craig Shere at Calyon Securities. Q - Craig Shere: Hi, bit of a follow-up on Sam's question, where you all were alluding to slide 75 with the enterprise gas price sensitivities. Comparing that to slide 96 in the prior fourth quarter presentation, it certainly looks like the enterprise sensitivity to gas prices the next couple of years is lower, and that seems to be driven by the new Power hedges. Is that a fair summary there? A - Donald Chappel: Craig, I would -- I will let Andrew speak to it, but we also hedge natural gas. So, I think if you look at the natural gas hedge slide, you'll see there's additional natural gas hedges on as well. So, Andrew? A - Alan Armstrong: Yes, Don, I think that is accurate. I think all of that is taken into consideration. But I think the biggest change in that is the new hedges that we have put on. Q - Craig Shere: Okay and what are we, are we just assuming the midpoint of your production guidance that you gave previously for like years '07, '08 to arrive at these numbers? A - Andrew Sunderman: Yeah I would have to take a look at exactly what production Ralph has referenced, but we use the internal expectations, which should be right in line with the guidance, for arriving at these numbers. So, there should not be any disconnect. Q - Craig Shere: Okay. You have given ranges previously about production estimates in the future, and it would seem that the growing and biggest question mark as far as exposure to gas prices is on the E&P side versus, say, the Power book or Midstream. Is that a fair statement? A - Andrew Sunderman: Yeah, I think that's fair. And I think probably a good starting point is to use the midpoint of the range. Q - Craig Shere: Okay. So from there we can kind of back into, if we are assuming a higher level, what the deltas would be. Okay I appreciate the help.

And we'll go to Jeff Berg at Matador Capital. Q - Jeff Berg: Yeah good morning guys. Sorry to beat a dead horse, but how you guys allocate capital, in my view, is the most important question you can answer. So, I am going to be as specific as I can here. It was widely rumored that you guys bid about 1.8 billion for Chief. And at that price, that would have been about $0.75, $0.80 per 3P reserves, according to Devon's projection, and about $3 per proved reserve. Right now, the market is valuing your 3Ps at less than half of that. So, the question is very specific. Let's say at 1.8 billion, or whatever the number was, Chief was EVA positive. But yet, it was not nearly as EVA positive as buying your own assets, which as slide 18 shows in great detail, has the lowest F&D costs in the industry. How would you prioritize that? How would you -- would you have done that deal, or any deal, even if it was EVA positive, even if it was not nearly as EVA positive as buying back your stock? Because the corollary to that is a credit rating is a means to an end. I mean if you have -- whether it is an A rating or a B rating and a $20 stock, it really doesn't mean anything to your shareholders. At the end of the day, all things being equal, with a reasonable credit rating, what we are interested in is the share price. And so I think answering this question as specifically as you can is really important. Anyway, thanks. A - Donald Chappel: Jeff, this is Don. I certainly agree that the credit rating is a means to an end. And certainly, we would expect that our improvement in our credit would be reflected in our share price as well. But all I can say on -- our policy is to not comment on rumors. And I just emphasize that it is a rumor, and we can't comment on it. But we are very thoughtful and very disciplined regarding our allocation of capital, and we are very focused on creating value for our investors. We do understand all the levers that we can pull and the levers that we don't want to pull. So, while I can't comment on the rumor, I can tell you that we are very much focused on creating value for our investors and doing things that, I believe, our investors will support. Q - Jeff Berg: So, forget Chief for a second, Don, because I appreciate the sensitivity there. Assume its company XYZ, and it had a positive EVA, but buying your shares back had a positive 3X EVA. Is there -- would you guys still do an acquisition, even though buying in your shares had a much more positive EVA? That’s what -- that’s what we need, I think, clarity on. That's what I haven't heard an answer to. A - Donald Chappel: Jeff, in your simple example, I think it would be an easy decision to get buy back stock. But again, we model all these things, and we are focused on creating value for investors. And if the answer is clear that buying back shares is the right answer, we would be very inclined to buy back shares, if that was going to create more value for investors than some other investment. Q - Jeff Berg: All right I appreciate it. Congrats on the quarter. A - Donald Chappel: Thank you.

And we go to another question this is Andrew Levy at Bear Wagner. Q - Andrew Levy: Guys it seems to me just listening to the call that investors are really not too excited about you making a major acquisition. Can you comment on that, and how you weigh investor sentiment versus your desire to buy something versus buy back stock? A - Steven Malcolm: This is Steve. We were always interested in investor sentiment, and I think we have been pretty clear and, that we will continue to be disciplined. We are all about EVA. And I think we’ve said many, many, many times that it is difficult to acquire something in today's market that makes sense, given the multiples that are being paid. However, we will continue to evaluate deals, because there maybe one that we would find compelling. I probably can't be more specific than that. Q - Andrew Levy: How about monetizing any of your assets to try to outpace some value improve to investors, since the assets are worth more than what the stock is reflecting? A - Steven Malcolm: We're always evaluating those kinds of opportunities. We will never fall in love with any of our assets. And if it makes sense to do so from a shareholder perspective, we will certainly consider it. Q - Andrew Levy: Thank you.

And Mr. Malcolm, we have no other questions, so I would like to turn the call back to you for any closing comments, sir. Steven Malcolm, Chairman, President, Chief Executive Officer: Well thank you. A good quarter. We are pleased with our results. Our growth opportunities are very robust, and we will continue to be crisp around the execution of our game plan. As always, thank you for your interests. We got some early feedback from Becca that she liked our new streamlined approach today, but we would like to hear from others. So, please give us your feedback. Thank you very much.

Thank you. That does conclude the call. We do appreciate your participation. At this time, you may disconnect.