Travis Campbell - Head of Investor Relations Steve Malcolm - Chairman, President and Chief Executive Officer Donald Chappel - Senior Vice President and Chief Financial Officer Ralph Hill - Senior Vice President, Exploration and Production Alan Armstrong - Senior Vice President, Midstream Gathering & Processing Phillip Wright - Senior Vice President, Gas Pipeline

Carl Kirst - Credit Suisse Faisel Khan - Citigroup Craig Shere - Calyon Securities Shneur Gershuni - UBS Rick Gross - Lehman Brothers Maureen Howe - RBC Capital Markets Rebecca Followill - Howard Weil Sam Brothwell - Wachovia

Good day, everyone, and welcome to the Williams Companies Second-Quarter 2006 Earnings Conference Call. Today's call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Travis Campbell, Head of Investor Relations. Please go ahead, sir. Travis Campbell - Head of Investor Relations: Thank you and good morning, everybody. Welcome to our call this morning. Thanks for your continued interest in our company. Today, you'll hear from Steve Malcolm, our CEO, Don Chappel, the CFO; and Ralph Hill, President of our E&P business and Alan Armstrong, President of the Midstream business, a couple of things about our format today. At last quarter's call, if you recall, we used a more streamlined format. We received a lot of encouragement and feedback to continue that format, so we will do that today. Therefore, all of the business unit heads are not presenting, but be aware that each of them is here in the room with us, available for questions that you might have. Also, we're very well aware that today, a number of other companies are also releasing earnings and are conducting their calls, so we're sensitive to that. As you would expect, all of the slides and the robust detail you have come to expect from us is available in the appendix to the presentation. So any of that information you have found valuable in the past is available. Before I turn it over to Steve, please note that all the slides, both those in the presentation and the appendix, are available on the website, williams.com, in a PDF format. The press release and the accompanying schedules are also available on the website. Later today, we will be filing our 10-Q with the SEC, and that will be available on the website by late today or tomorrow morning. Slide number two, titled forward-looking statements, details various risk factors related to future outcomes. It's important for you to review the information on that slide. Slide number three, 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 Principles. Those schedules follow the presentation and are an integral part of the presentation. With that, I'll turn it over to Steve Malcolm, our Chairman. Steve Malcolm - Chairman, President, Chief Executive Officer: Thanks, Travis. Welcome to our second-quarter conference call, and thank you for your interest in our company. We are very pleased with our second-quarter results. And I believe our investment thesis continues to revolve around four key points. First, we own and operate some of the very best, highest quality, largest scale 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, driven by our adoption of the EVA methodology. And lastly, we believe we are in the midst of a sustained, attractive energy price environment that will allow our businesses to prosper. Let's look at slide number five, which lists the key headlines that you will be hearing much more about during the call this morning. First, crisp execution around our various business unit strategies has delivered a very strong second quarter. Some of the drivers -- 20% growth in natural gas production quarter-over-quarter and the fact that margins remain very strong, creating a nearly $200 million recurring quarter for Midstream. Secondly, we nearly doubled our recurring income from a year ago, after removing marked-to-market effect. Third, we're raising profit guidance for 2006, 2007 and 2008, a 19% increase in guidance specifically for 2006. And we're delighted that, again, production growth is up. We're seeing positive developments in the Piceance Basin, as Ralph Hill will describe in a minute. Continued robust margins, sustained strength in crude prices have allowed us to recalibrate our Midstream expectations upward again. And our gas pipeline rate cases are on pace to go into effect early next year. We're accelerating the production growth by investing incremental dollars in the Piceance Basin, and our MLP strategy will accelerate delivery of financial benefits to Williams by pursuing a goal to complete another $1 billion to $1.5 billion in drop-downs over the next six months. Slide six speaks to the fact that crisp execution around our business unit strategies is driving both near-term growth and strong, sustainable increases in shareholder value. We are clearly delivering on our promises. So far in 2006, you’ve seen increased dividend of 20%, up to $0.09. That's the third increase in less than two years. Again, increased natural gas production by nearly 20% completed a $360 million drop-down into Williams Partners. We resolved significant legacy issues. We have eliminated almost all of our secured debt and improved our credit ratings. As well, we achieved very strong second-quarter results, nearly doubled recurring results after removing the marked-to-market effects; posted nearly $200 billion in Midstream recurring segment profit; experienced robust NGL margins that more than offset the effect of lower and natural gas prices. Importantly, we are well-positioned for continued success. As a result, we have increased our 2006, 2007 and 2008 profit guidance. We have boosted capital spending to develop production and reserves faster, and we're accelerating drop-downs into the MLP. On slide seven, let's talk a little bit more about the drop-downs. We're close to the one year anniversary of our IPO, and over the past year, we've gotten a lot of questions about our strategy and about the pace at which we intend to drop down assets. We have been in and out of quiet periods because of the level of activity at Williams Partners, but let's review the bidding. Again, we had our successful IPO in August of 2005. We recently closed a $360 million transaction, a drop-down of 25.1% of Four Corners gathering and processing assets and we’ve seen a 21% increase in WPZ unit distributions since the IPO. We're pursuing a goal to drop down $1 billion to $1.5 billion in assets over the next six months. And our deep bench of qualifying assets supports annual drop-downs of $1 billion to $2 billion during the guidance period on an annual basis. However, and very importantly, as we talk about our MLP strategy, it is important to note that all of the terms, including price, of any transactions between the Company and the partnership are subject to approval by the Boards of Directors of both Williams and the general partner of Williams Partners. As well, the terms of certain transactions will also be subject to approval by the Conflicts Committee of the Board of Directors of the general partner of Williams Partners. And lastly, keep in mind that our MLP strategy requires a disciplined capital structure, as the partnership's credit rating is linked to Williams'. A reminder on slide eight regarding the key drivers for our MLP drop-downs. These drop-down create an ongoing source of lower-cost capital, essentially funding higher-return growth investments with capital derived from lower-return mature assets. Drop-downs allow Williams' general partnership interests to grow in size and value. These drop-downs drive a growing source of LP unit and general partnership distributions, and to the extent that we retain MLP units in any transactions, there's an opportunity for unit price upside and additional cash flow through distributions. With that, I'll turn it over to Don Chappel. Donald Chappel – Senior Vice President, Chief Financial Officer: Thanks, Steve, and good morning to everyone on the call. Thanks for joining us. I will quickly run through our results, and then come back later in the call to review our new guidance and some other matters. Now, let's turn to slide number ten, financial results. First, I'll just note that the third line, reported net loss for the quarter of $76 million, certainly was burdened by substantial nonrecurring charges related to litigation settlements and litigation contingencies. We will look at the detail of that in just a moment. As well, the reported earnings were affected by marked-to-market accounting business related to our Power business. Both the nonrecurring items and the marked-to-market accounting effects distort the true picture of the business's very strong performance. I'll speak more about those matters in just a moment. Let's look those matters and look to the last line on this slide, the most important earnings measure, recurring income from continuing operations after marked-to-market adjustments. This is a measure that strips out the nonrecurring and marked-to-market effects, and the one we have pointed you to consistently. You can see $0.33 versus $0.17 in the previous quarter, up $0.16 or 94%, and on a year-to-date basis, at $0.59 versus $0.39 in the prior six months, up $0.20 or 51%. Let's turn to slide number 11, recurring income from continuing operations. I'll walk you through our nonrecurring items and calculation of recurring earnings. As you can see, the second quarter of 2006, the major item that I mentioned earlier, regulatory and litigation contingencies, settlements and related costs. As Steve mentioned, we're delighted to be able to put a number of these important matters behind us. The second-quarter item includes the Williams shareholder class-action litigation settlement related to 2002 events, totaling $161 million pretax, and the recent jury award related to the Gulf Liquids litigation at $88 million. Please note that of the $88 million, $68 million was charged to Midstream segment profit and $20 million was charged to interest expense. Again, this is still distorted because of marked-to-market effects. Let's turn the page, and we'll look at recurring income and how we eliminate the marked-to-market effects related to our Power business. Going to the third line, marked-to-market adjustments for Power -- first, we will reverse the forward unrealized marked-to-market loss in the current quarter of $38 million. We will add back realized gains from marked-to-market that was previously recognized that is now reversing off the balance sheet, totaling $100 million, for total marked-to-market adjustments of $138 million, as compared to $55 million in the prior year. There's a tax effect on that, so net of tax, we have an $85 million marked-to-market effect, as compared to $34 million in the prior year, or a change of $52 million. Again, we needed to add back $52 million more than last year, in order to put the business back on an equivalent basis. Looking at the full year, we reversed the forward unrealized marked-to-market gains of $4 million, reduced income by that. We added back the realized gains from marked-to-market previously recognized of $177 million, for a total of $173 million as compared to $53 million the other way in the first half of 2005, or a $226 million swing six months to six months. Again, at the bottom of the slide, recurring diluted earnings per share after marked-to-market adjustments of $0.33 versus the $0.17 I mentioned earlier, and for six months, $0.59 versus $0.39. Next slide please, number 13. Second-quarter segment profit, in a consolidating format for both reported and recurring -- again, both litigation charges and marked-to-market effects and other nonrecurring items affect reported. I will focus my comments on recurring. If you scan down the slide to the bold line segment profit after marked-to-market adjustments, you can see the segment profit on that basis at $500 million, up from $356 million in the prior year's quarter, up $144 million or 40%. Also note at the bottom of the page that Power, on a basis adjusted for marked-to-market and nonrecurring effects, totaled $59 million versus a loss a year ago of $7 million, for an improvement of $66 million. We will talk about each of the business units as we walk through some subsequent slides. The next slide, please, number 14. On a year-to-date basis -- again, reported as distorted by nonrecurring items and marked-to-market effects. Focusing on recurring, and again scanning down the page, the segment profit after marked-to-market, $938 million in the first half versus $748 million a year ago, an improvement of $190 million or 25%. Again, Power at the bottom of the page, you can see there it's $71 million versus $11 million a year ago. Again, more on this in just a couple of minutes. The next slide, please, number 15. Take a look at E&P in a bit more detail. Again, recurring segment profit of $120 million was up just slightly from 2005 and, on a year-to-date basis, $267 million, up $53 million or 25% from 2005. We continue to be very pleased with our production growth in the E&P unit. Total net production is up over 20%, comparing the second quarter 2006 to the same period a year ago, which equates to adding more than 130 million cubic feet per day since the second quarter of last year. Recurring segment profit is up 25% year to date, compared to the same time last year, with total net production up about 19% and net realized average prices higher by approximately 8%. Operating profit in the second quarter was still up versus last year, despite index gas prices at the basin level being down 10% year over year, while our net realized average prices were essentially flat. We did have some additional operating expense recorded in the second quarter of 2006 that was associated with prior periods, for an amount totaling $9 million. $6 million of that relates to the first quarter of 2006 and $3 million relates to 2005. Excluding these out-of-period expenses, operating profit for the quarter would have been up approximately 9%. So, even though operating expenses are recorded as a up $0.21 per Mcf for the quarter year over year, after adjusting for the prior-period amounts, operating costs were up about $0.09 per Mcf. Of that $0.09, about $0.05 is related to our decision to step up our workover program in the Piceance and the San Juan Basins, further helping our volumes. The remaining $0.04 per Mcfe, or about a 9% increase, we think is not unexpected. We think this is about the same cost increase, or perhaps less than what others in the industry are experiencing. Comparing the current quarter to the prior-year quarter, net realized average natural gas prices were about flat, at $4.17 in the current-year quarter versus $4.16 in the prior-year quarter. For the six-month period, net realized average natural gas prices were approximately 8% higher, $4.42 for the current period as compared to $4.09 in the prior period. Let's turn to the next slide, please, number 16. Reported segment profit of $131 million was reduced by $68 million relating to the Gulf Liquids litigation accrual. Recurring segment profit, $199 million versus $109 million for the same quarter in the prior year, up $90 million or 83%, driven principally by the strong NGL margins. On a year-to-date basis, the recurring segment profit of $344 million compared to 2005 with $106 million, a 45% increase. Looking at the second quarter 2006 versus second quarter 2005, the major drivers to our recurring segment profit -- a record NGL unit margins, higher fee revenue, higher product margins from our Canadian olefins group and increased operating expenses. In the second quarter of 2006, natural gas liquids margins exceeded historic levels, averaging $0.33 per gallon. The price variance contributed $72 million to the overall $75 million margin variance. The remaining $3 million was contributed by slightly higher volumes. Fee revenue increased $13 million quarter over quarter, primarily from the Deepwater Gulf, based on increased Triton, Goldfinger and resident volumes across Devils Tower and higher unit of production rates. Fee revenue in the West also contributed an increase due to contract renegotiations and right escalations. Our olefins group contributed $10 million more than the prior year's quarter, mostly due to $13 million in higher margins, particularly propane and propylene margins in Canada, partially offset by lower volumes. Operating expenses increased $10 million overall, $9 million from the West due to additional turbine overhauls, more lease compression and added personnel. $1 million came from Gulf, attributed to increased insurance premiums. On a year-over-year basis, our major drivers are the very strong NGL unit margins, higher fee revenue and increased operating expenses. NGL unit margins were $0.12 per gallon higher year to date 2006 than year to date 2005. This created the $79 million increase in segment profit. Volume was down 6% from a year ago, causing a negative $6 million volume variance. The price variance was a positive $85 million. Higher fee revenue resulted in a $36 million increase. The West increased $8 million due to higher contract rates. The Gulf increased $28 million, mainly due to increased volumes from Triton and Goldfinger and higher Devils Tower unit-of-production rates. Operating expenses increased $20 million, $17 million from the West, again, with turbine overhauls, more lease compression and additional personnel and $3 million from the Gulf due to higher insurance premiums. Overall, a terrific quarter, once again. Turning next to slide number 17, you can see recurring segment profit of $123 million is $20 million lower than 2005; on a year-to-date basis, $255 million, down $42 million. Again, this is a year in anticipation of rate cases and rate increases, and we expect to recover our higher costs, beginning in 1Q 2007, following the new rate cases, which go into effect in first quarter of 2007, subject to refund. Generally, the lower year-over-year second-quarter recurring results are due to higher operating costs, including labor, benefits and depreciation, as well as higher pension expense and property insurance. These increased expenses are partially offset by higher earnings at Gulfstream and our other joint ventures. Again, it's important to note that these higher expenses will be included in our current rate filings and subject to refund. We expect them to be recovered in 2007 and beyond. The next slide, please, number 18. Segment for Power. Power reported a segment loss of $80 million, fairly comparable to the prior year, and $102 million year to date versus a reported profit of $39 million in the prior year. But again, the reported earnings here are distorted by marked-to-market effects, as well as nonrecurring items. You can see there are no nonrecurring items in the current year. However, marked-to-market effects we walked through before are noted here just above the final total. Recurring segment profit after the marked-to-market, $59 million versus a $7 million loss a year ago, an improvement of $66 million, and year to date, at $71 million versus $11 million, an improvement of $60 million. Overall, Power performance was sharply improved as legacy matters dissipated. These results are in line with our plans and our guidance. Next slide please, number 19. Take a quick look at our liquidity. Cash and cash equivalents at $980 million, other current securities about $400 million. We do subtract subsidiary international cash at $446 million, because it's not readily available for general corporate purposes, as well as we subtract customer margin deposits that we may have to return based on changes in commodity prices. I would note that that number, the $32 million that remains as of June 30, totaled $320 million as of December 2005 and $129 million as of March 2006. The $290 million decreases since the beginning of the year reflects margin that was returned to counterparties as commodity prices changed. However, that had no effect on our calculated liquidity, as we planned to return those. Those monies move in and out quite fluidly. So, after adjusting out $900 million in cash, $1.7 billion in revolver capacity for total liquidity of $2.6 billion, we maintain the substantial cash and liquidity balances to do a few different things. One is to manage our margin positions -- again, very substantial movement in cash and liquidity, related to supporting marginable hedges, as well as our substantial reinvestments into the business are currently exceeding our operating cash flows. That is driving very substantial growth. However, that needs to be funded. Finally, the litigation settlements contingencies and settlements have yet to be funded. Next slide, please, number 20. Cash flow information. Just a few highlights -- a good, strong cash flow quarter with $500 million, $673 million year to date. You can see debt retirements and proceeds from debt issuances were about even. The proceeds from debt issuances do include MLP issuances, which totaled $150 million during the second quarter, related to the Four Corners drop-down. The next line item, proceeds from the sale of partnership units, again related to MLP equity raised, totaling $225 million during the second quarter related to that Four Corners drop-down. Let's move on to slide number 21 and Ralph Hill. Ralph Hill – Senior Vice President, Exploration and Production: Thank you, Don. Let's go ahead and flip to slide 22. 2006 accomplishments is at the top of that slide. As Don and Steve had mentioned, it was a strong quarter and first half of 2006 performance for E&P. I would also like to compliment our other business units on their very strong performance. Second-quarter 2006 production was up 20% or 130 million a day. We now have six H&P rigs operating in the Piceance Valley, additional 12,200 acres of our Piceance Valley had density, 10-acre density, spacing approved. I have a slide on that in just a minute. Our Piceance Highlands continue to build momentum. I have a slide on that also. The Big George and Powder River volumes are impressive. They continue their impressive growth. We expect to expand our Barnett Shale position through a bolt-on expansion. Our first-quarter 10-Q discussed a Barnett type expansion that we did, and we expect to do a similar size expansion in the third or fourth quarter of this year. Our San Juan Basin team was awarded the Best Management Practices from the BLM, which is about the fourth award in the last three or four years that they have won for their outstanding work in the San Juan Basin. Turning to slide 23, looking at our 10-acre densities that have been approved, the colored part of this slide shows the 74,000 acres that we own in the Valley; this is the Piceance Valley alone. The green outline shows the approximately 37,000 acres that we have had downspaced previously. The blue acreage shows approximately a little over 11,000 acres that were approved for 10-acre downspacing density approval in April of 2006, which added 800 additional bottom-hole locations. Most recently, the purple part shows the slightly over 12,000 acres that we had approved for 10-acre development in July of 2006. This will provide about an additional 890 additional bottom-hole locations. In total, we have now downspaced about 60,000 acres in the Valley, of our 74,000 acres, which is about 80% of our Valley acreage. We continue to be very successful in working with our communities, the state and local officials and regulatory officials in downspacing our acreage, which is a testament to our field employees in the Piceance area. Slide 24, looking specifically at the Piceance production, it is up, by itself, 104 million or 34% a year ago. We currently have 23 rigs operating in the Valley and the Highlands combined, compared to 13 a year ago. We will have four additional H&P rigs, Flex rigs, which will be received in 2006. We have four Nabors Super Sundowner rigs, which are similar to the H&P Flex rigs, which we will receive in early 2007. At that time, we will be able to high-grade our fleet. An additional part of what we have done in the Piceance Valley is we did perform, as I mentioned, in the first quarter what we call sim-ops or simultaneous operations. We have been doing that significantly. We had done one at the time of the last call, and now we have done quite a few sim-ops. That is basically where we are -- for the first time ever on land that we can tell, fracing, perforating, drilling and producing at the same time from the same pad. It's part of the reason for our efficiencies. So we are, as you can tell, on the last (indiscernible) able to high-grade our fleet. We are on target to achieve the rig count of 25 that we originally planned. Earlier in the year, we did pick up additional rigs, as you recall, to compensate for the delay in the H&P delivery rigs, due to the hurricanes of last year. Now, due to our efficiencies and increasing industry activity, this year in the Valley, we will drill 19 more operated wells and also, due to outside operating increases in activity, we will have 34 more nonoperated wells we will participate in than originally planned. Our current projection going forward is 20 or 21, possibly 22 rigs operating in the Valley, with about four operating in the Highlands, increasing over time to six or more as we continue to expand the infrastructure in the Highlands. The key is our efficiencies will allow us to drill more wells and high-grade our rig fleet without adding more rigs and stressing the infrastructure. We have seen rig efficiencies from the H&P rigs from 10 to 50%, with the average about 25%. A true testament to our team, they continue to grind out efficiency in the conventional rigs, and we have squeezed out another 5% to 6% improvement in efficiencies in our conventional rigs. Turning to slide 25, Piceance Highlands, we are building momentum. We now have 44 wells currently producing, up from just eight wells a year ago. We have 13 million a day of current net production, over 20 million a day of gross production. That's up over 10 million a day from just a year ago. There are seven rigs in the Highlands operating; that's part of the 23 we are talking about. Currently, we have 16 in the Valley and seven in the Highlands. We are doing major road and pipeline infrastructure buildouts. As you will see in our guidance, we are doing quite a bit. What that does for us -- by building the roads and the infrastructures and the plants and the water lines now, it provides shorter, safer and more reliable access to our thousands of wells we will have in the Highlands. It will save several million dollars per year in rigs moves, cement crew mileage, frac crew and proper transportation. Much time savings, which will ultimately decrease our cycle time and add present value per well. It will save, we believe, millions of dollars over the life of the Trail Ridge and Allen Point projects. So the investments we will be making this year will save millions of dollars in the future for us. Looking at slide 26, turning to the Powder River, continued impressive growth in the Powder River production. We have divided the graph on this page to show the Wyodak, which has generally declined, and the Big George, which has been inclining. Our total Powder River volumes are up 26 million a day or 23% from the second quarter of 2005, and the Big George continues to drive the volume growth, as the slide shows and the graph shows. It was up over 108 million a day or 99% from the second quarter of 2005, and sequentially it was up 44 million a day or 25% from the first quarter of 2006. So we continue to have very impressive results from the Powder River team. and they are doing an outstanding job. Looking at slide 27, a good and a well-established core capability, we believe our organization is to identify new grass-roots opportunities. I announced three last call, which are listed again in the appendix. Those three are listed again in the appendix on slide 62. We have another farm-in opportunity we are moving closer to finalizing that is listed on this slide. It is in the Piceance Basin. It will be a drill-to-earn type deal. It's in the Williams Fork Formation, which is what we drill in both the Valley and in the Highlands, about 11,000 net acres to Williams. Very high net revenue interest, as you can see there, with over 600 plus potential drill locations. We will operate that. That is on a 40-acre spacing. Obviously, first we have to get the deal done and then, obviously, start moving it. But it is in the Piceance, and we continue to be excited about our ability to expand our acreage in the Piceance. Slide 28 -- this is a buildup to slide 29 on our capital guidance change. As I've discussed during this call, with the continued success of our drilling programs overall and the new opportunities we're seeing, we're very pleased to announce an increase in capital guidance, production guidance and segment profit guidance. This is due to additional drilling we believe we can do in the Valley and the Highlands, due to our efficiencies. It is also is due to an increase in costs, which we're projecting at 3.7%, due to the tight nature of our industry. That would be at 3.7% on our base costs from the original budget. We also have additional gathering and processing infrastructure we need, not only for our own volumes but also for an increasing level of third-party volumes, as we become a major gatherer and processor in the Valley. We have major infrastructure buildouts in terms of roads, et cetera, in the Highlands, which I have previously discussed. We have, also, new opportunities in both the Rockies and Barnett that we are pursuing that has also added to our guidance. The changes are listed by category on the top part of this slide. The shaded box shows the midpoint changes. I believe it's also important, as you look through the midpoint changes, to note that our increase in segment profit and DD&A returns about 42% of our capital increase, just in this period alone, which reflects the fast cash return cycles we have in our E&P investments. Also, this is with very significant infrastructure investments we are making currently that will benefit our production for years to come. On slide 29, all that adds into our changes in guidance. You can see the segment profit, the new segment profit, capital spending and production guidance and segment profit and DD&A guidance, and the old guidance is listed below. Keep in mind that our price assumptions, which are listed below on the bottom part of the slide, are also below market. As you can see, they declined from assumptions in 2006. So these price assumptions could prove to be conservative. Finally, slide 30 -- we believe our value creation continues for the E&P industry. Industry leader in production growth, cost efficiencies and reserve replacements. I think that is shown by our 20% production growth. We have a very long-term, repeatable drilling inventory. Please recall we have 10.7 Tcf of 3P reserves, and our resource potential is 13 to 15 Tcf. Our strategy remains a rapid development of our premier drilling inventory, and I believe that is reflected in our increase in guidance for CapEx for our production and our profits. We continue to have a very long history of high drilling successes, short time cycles investments, fast cash returns. I would like to just restress that over 40% of our CapEx is returned by the end of 2008, even with the very large infrastructure buildup we are doing. The Highlands is significantly contributing. We are looking for even more contributions. I continue to be very thankful that we have such an experienced and talented workforce. With that, I will now turn it over the Alan Armstrong, who will reflect on a very strong quarter. Alan Armstrong – Senior Vice President, Midstream Gathering & Processing: Thank you very much, Ralph, appreciate that. I do have the pleasure of announcing some dramatic increases in our second-quarter performance, another increase in our 2006 guidance and, finally, significant increases in our 2007 and 2008 guidance. But first, let me talk about some accomplishments during the second quarter. We reached a new record for recurring segment profit of $199 million during the quarter. We saw our NGL production volumes rebound, as our Cameron Meadows plant got back online with one of its trains. The second training Cameron will be coming back online this month, so we're excited to have that capacity back up. We enjoyed extraordinary margins in the second quarter, and these have persisted into the third quarter as well. Our NGL margins averaged $0.33 per gallon for the second quarter, and this was nearly three times the five-year annual average. We also sold forward NGL volumes during the second quarter, and we sold those forward into the third quarter that equaled about 40% of our projected sales volume. These were at prices that support the type of margin that we saw here in the second quarter. So we're excited about the position we're in, going into the third quarter. We also were very busy during the quarter managing the drop-down transaction for a 25% interest in our San Juan Basin gathering, treating and processing business. We brought in about $360 million in cash to Williams from this transaction. Just as a measure on that, this equated to an EBITDA multiple of about 9.6, based on our 2005 performance on that. The expansion of our business in our core growth area goes on, probably most importantly. Our investment and enhancements of the Opal TXP-IV train that we bought at the first of the year are certainly paying off in this margin environment. We are now hoping for mechanical completion of our TXP-V, our fifth train at Opal, by the end of this year. This is certainly going to be a welcome addition to revenue environment, as that large train starts to produce income for us. Additionally, we continue to build out our very large-scale deepwater infrastructure. The first phase of our Wamsutter gathering expansion was just recently completed at the very end of the second quarter, and we're looking forward to further expansions of that, as BP and Anadarko continue their drilling -- and Devon, actually, continue their drilling plan in that area. So overall, a great quarter and a lot of accomplishments that we are very excited about during the quarter. Going on to the next slide, this shows some exciting news that we have to share here. First of all, we're raising guidance across the board, as you can see. The smaller numbers there below on the segment profit guidance were our previous guidance, and the ones there above are our new guidance. Now, it's important to note that this guidance is on a reported basis, so this does include the Gulf Liquids charge that Don Chappel mentioned earlier. Even with that, we're still raising guidance again. In May, we raised our 2006 guidance from $400 million to $500 million to a $500 million to $600 million. Now we are raising this midpoint again by another $67 million, as measured at the midpoint. Without the Gulf Liquids charge, this guidance would be up by $135 million at the midpoint for 2006. So very strong increases riding on both the back of the strong NGL margins and the continued strong performance at some of our deepwater assets, namely our Devils Tower facility. This raised guidance assumes the commodity environment shown here of $7.84 for Henry Hub prices and a $62 to $70 WTI barrel. So on a recurring basis, it is certainly possible and probable that we could produce over $900 million of recurring segment profit and depreciation for 2006. So we're continuing to enjoy this in the third quarter, and we have got some fairly moderate assumptions in here for crude oil pricing, as you can see, for the balance of the year. Looking forward, we're raising guidance at the midpoint by over $150 million for both 2007 and 2008. This increase assumes the pricing environment that is shown in the table in the bottom of the page, so you can see that is an oil price environment of between $55 and $69 WTI, and a natural gas price of $7. It's important to note that these natural gas prices coincide with our E&P group's assumptions. So if this price is a little too low for your liking, then the positive is going to show up on E&P segment profit. The really key assumption, then, on an enterprise level gets down to crude oil price. So that $55 to $69 is important to key on. I will tell you that our margins assume a slightly lower correlation of NGLs to crude oil price than what we have seen historically. So we are being conservative in our forecast for that. No changes on our capital budget guidance, even though we have some exciting capital projects that we're anxious to announce, and I'm going to go into that here on the next couple of slides. This graph is depicting the health of our Midstream business, in terms of both sustainable free cash flow and growth. The dark blue bar that you see on the right shows our segment profit plus DD&A from our base business at a five-year average margin, which now stands at about $0.132 per gallon. The blue hashed bar shows the amount of margin lift that we expect at the midpoint, over and above the five-year average. Finally, the purple segment on top of this bar shows the recent expansions and the segment profit improvement that we're expecting from those recent expansions. Some of those in 2006 -- for instance, the Opal TXP-IV -- we're enjoy today, and you can see that there at the top of the 2006 piece. As you can see, our base business is growing even with constant margins and no new investments. This is largely driven by higher deepwater fee-based revenues and higher rates being realized in our GNP business out West. Probably the most impressive thing about this graph is the spread between our segment profit plus DD&A and our capital expense bar. As you can see, in 2008, that is reaching up to nearly $800 million of spread between our segment profit plus DD&A and our capital expenditures. So tremendous free cash flow being generated from this business, even without some of the exciting expansion opportunities I am going to mention on the next page here. This slide gives you a glimpse of the opportunities for additional investments in our business. On the right-hand side, we show projects that have moved to the point of commitment and are included in our guidance through 2008. Of course, this includes our Blind Faith expansion, which is an extension off our Devils Tower system, the Opal TXP-IV that we acquired this year, Opal TXP-V expansion that I mentioned earlier and our Tahiti lateral expansion moving out to Chevron's big play, Tahiti play, coming off our Discovery system. So all of those have been committed, contracted and are under construction. See that there. The column in the center shows the projects that we believe we will be successful in contracting in the near future, and we look forward to announcing. A little bit of that is in guidance -- things, for instance, like continued expansion of our Wamsutter investment. That's just a matter of getting, really, the scope of that project pinned down with BP, and making sure we all agree on what's the best way to expand that system to keep up with their drilling plans out there. But what is really some of the bigger drivers to this are some large Western Gulf of Mexico deepwater expansions that we're hoping to announce very shortly. Then finally, you can see -- we show a very robust set of opportunities that are consistent with our strategy of continuing to invest in very large-scale facilities in these growth basins. That's over on the left, between $0.5 billion and $1.5 billion. You can kind of see how that is broken out in terms of the areas we are expecting those to show up in. And in total, we hope to invest between $1 billion and $2 billion in this business over the next three years, as you look at these opportunities. Moving on to the final slide here, I certainly want to complement our operating team. By continuing to focus on providing our customers with the most reliable service available in the midstream industry, that absolutely is going to be the secret to our success going forward, as it has been to date. We're making great strides in proving up the value of our strategy to both our shareholders and our customers, who value our ability to expand alongside them as they continue to drill in these growth basins. Our base business continues to generate healthy returns and free cash flows. As noted, our NGL margins exceeded historic levels and, mentioned earlier, three times the previous five-year average. And this is an excellent example of how the enterprise and the integrated model is working for us, as we were unable to cushion some of the impact on lower gas prices to the rest of the enterprise. We do expect NGL margins to remain above historic levels in this guidance period, and progress continues on our deepwater expansions. And as I mentioned, we're foreshadowing some additional expansion we hope to announce in the near future on that. And in terms of the Western growth, that is tremendous in terms of the amount of opportunities we're beginning to see, even stretching outside of our Wyoming and Four Corners area, also looking into some opportunities in Colorado. So excited about what lays ahead of us and thrilled with the performance of the business right now. And with that, I will turn it back to Don. Donald Chappel – Senior Vice President, Chief Financial Officer: I'm going to try to run through this next section pretty quickly. I just note that much similar information to what E&P and Midstream presented for Gas Pipes and Power is in the appendix, as well as a lot of other analysis for your reference. Side number 38 forecasts guidance; I'll just jump right to the bottom. $0.95 to $1.20, a midpoint of about $1.08, up about $0.17 or 19% from our prior guidance. And you can see the elements of that. Again, the guidance, the segment profit before marked-to-market adjustment, that also would be including non-recurring items. So those are, again, on a reported basis. The net interest expense, I would note, is up $20 million related to that Gulf Liquids litigation. And let's flip to the next slide. Next slide, number 39, segment profit summary, and again, let's just jump right to the bottom. Total recurring after market-to-market adjustments in a range of about $1.7 billion to $2 billion, midpoint of about $1.850 billion, up nicely from our May guidance. If we look over to 2008, you'll see the range increasing steadily, ‘07 and then ‘08, to 2.2 billion to almost 2.9 billion. And again, let me note that that's based on us and gas price of about $7 in crude oil price assumption that, again, is well below current market. So we believe that our price assumptions are somewhat conservative. But the $1.850 billion midpoint in ‘06 to the $2.550 billion midpoint in ‘08 represents a $700 million increase in expected segment profit, or about 38% in just 24 months. As well, the outlook beyond 2008 remains quite bright. The next slide, please. Number 40, capital spending summary. Again, some increases in the E&P, related to additional drilling activity and infrastructure to support the drilling. Again, these are low-risk, high-return projects that we believe will drive a great deal of value for shareholders. And again, we continue to be opportunity-rich, and we would expect to be adding from time to time to our capital spending guidance, particularly for ’07, ‘08 and beyond, as we are able to seize some additional opportunities that we see in E&P, Midstream and Gas Pipeline. The next slide, please, number 41. We have spent some time on segment profit. Let's look at cash flow from operations this year, in a range of 1.5 billion to 1.8 billion. Growing nicely in ‘07, and by ‘08, in a range of 2.4 billion to 2.825 billion, a very strong increase. And I will say a few more words in just a moment. Operating free cash flow is a bit more negative in 2006 as a result of these increased investments, but we think it's worth it. And again, the funding sources for that negative cash position or cash flow position are the excess liquidity we have today, as well as the expected capital to be raised in the future as a result of actions that we have discussed, particularly related to MLP drop-downs. If we, again, fast forward to 2007 and 2008, you can see operating free cash flow growing substantially. Again, I caveat that. We were opportunity-rich with very high return, low to moderate risk projects. We would intend to seize those in order to drive even more value for you. The next slide here, number 42, just graphically depicts what we just talked about. And again, I would note the increase in cash flow grows again from about $1.650 billion midpoint in 2006 to a $2.6 billion midpoint by 2008. That's a 59% improvement in just two years, almost a $1 billion improvement in cash flow from operations or 59% in just 24 months. Again, we believe that that's going to drive very strong growth and value for shareholders. The next slide, 43, a number of points just kind of made consistently. I won't run through all those today, in the interests of time. Again, I would note that I'm excited about the future. I'm very bullish about Williams and Williams' ability to create value; extraordinary opportunities in our E&P with the strong production growth, cost leadership, low-risk reserves and quickly growing reserves as a result of development, as well as some of the new deals which include farm-ins; and the lower level of legacy gas hedges that we see ahead. In Midstream, we expect continued strong NGL margins, driven by sustained higher oil prices. Again, the margins that we're forecasting are based on prices that are somewhat below current market. As well, we have franchise positions in both the West and the deepwater, and our MLP will add value to not only Midstream but the enterprise in lowering our cost of capital and building value in the GP. In Pipelines, the two rate cases take effect in the first quarter of 2007. The Northwest Pipeline replacement project, a $300 million capital project, will go in service in November of 2006. New rates will take effect in January of 2007. As well, we have a number of other organic growth opportunities. Finally, the power market continues to strengthen, and our major positions are in relatively tight markets. Let me remind you, California and the PJM market -- we have a continued ability to hedge forward and improve prospects for unhedged megawatts. Overall, again, a very bright outlook that we are very excited about. I'll turn it to Steve. Steve Malcolm - Chairman, President, Chief Executive Officer: Thanks, Don. Obviously, a lot of great news, substantial progress, positive developments. I think we're hitting on all cylinders. Again, crisp execution around our strategies caused us to deliver very strong results in the second quarter. We've raised our profit guidance for 2006, 2007 and 2008. We are accelerating the pace of our drilling activities, and we have talked about an MLP strategy that accelerates delivery of financial benefits to Williams. Before we take questions, I'll turn it back to Travis Campbell who has an announcement. Travis Campbell - Head of Investor Relations: Just real quickly, during the call, I was made aware that there was a problem with the webcast, with our third-party provider. Apparently, it was a systemwide problem. Please be aware that the whole call will be available for replay later today on our website, so you can get the whole call. I apologize for that inconvenience. With that, we will go ahead and turn it back to the operator for Q&A.

[Operator instructions]. We go first to Carl Kirst of Credit Suisse. Carl Kirst - Credit Suisse: He good morning everybody and congratulations on a great quarter. First, Ralph, the downspace in the Valley, the 890 additional locations -- are we still looking at roughly a 1.3 Bcfe to 1.4 Bcfe per well EUR for the 10-acre down spacing? And I guess if so, that could at least potentially lead to quite another nice increase to the 3P potential? Am I looking at that correctly?

We basically have said the gross EUR is 1.2 to 1.4 B's, and we have seen that consistently out there. Second thing, though, we have assumed as we have gone forward, and when we've talked about 3P, we have assumed the Valley would receive 10-acre spacing already. So we have those locations in our inventory of 3P's. It's just that we have been able to get approval to ensure that they will be in the locations we can drill. Carl Kirst - Credit Suisse: Appreciate that clarification. One other clarification. You talked about, obviously, expanding acreage at both the Piceance and the Barnett. You mentioned bolt-on. Are these small enough, I guess, that are actually in the currently envisioned CapEx guidance? Or, when you say you could bolt on these with something, you'd be independent of the current CapEx guidance, might be larger transactions?

Well, for the Piceance, they would be independent and they would be an additive to our current guidance. The small amount of the Barnett, since it is a smaller size, is already in the CapEx. We've assumed we're going to have those deals closed in the CapEx guidance. But additional bolt-ons, both in the appendix and in the one I talked about today, that would be additional opportunities for us to go out and drill, and additional locations and production and all that. Carl Kirst - Credit Suisse: Keying off of Don's last comment, and then if Bill is in the room, maybe he could comment on sort of the current view of power market liquidity and, I guess, this latest heatwave that has come across the state. Does that change utilities' longer-term views? It has been our sense that as more, certainly, investment houses have gotten in, we have seen liquidity break out a little bit more into the outer years, 2010 plus. I was wondering if you could comment on that. Donald Chappel: Yeah Carl, I think the heatwave -- a couple of comments. First of all, keep in mind that our portfolio is highly hedged. So we're creating cash flow certainty, but certainly limiting some upside. I do think one thing that will come out of it, though, it shows a tightening in supply and demand. I think that will lead utilities to look longer-term for contracts. Carl Kirst - Credit Suisse: Okay, thank you.

Thank you. We go next to Faisel Khan of Citigroup. Faisel Khan - Citigroup: Good morning. On your free cash flow projections that you have in your presentation, that does not include proceeds from the drop-down of assets to MLP. Is that correct? Donald Chappel: That is correct. There is no assumption built into our guidance with respect to MLP drop-downs. Faisel Khan - Citigroup: As you bring those proceeds back up to Williams Companies, what is the preference in terms of what you want to do with that excess cash? Donald Chappel: I would note first that, again, we do -- obviously, we consolidate the MLP. But from a credit perspective, the ratings agencies and debt investors look at the combined credit of the two companies, and WPZ's credit is linked very closely to Williams' credit. So we would likely be taking the proceeds from debt capital issuances at the MLP level, and using similar amounts to pay down debt at the Williams level, in order to remain credit neutral, more or less. Then the equity capital raised at the MLP level would be available for reinvestment or other corporate purposes. Again, there is a limit in terms of how much equity capital can be raised in the MLP market. From what we have seen, it has been perhaps in the range of $500 million to $800 million on an annual basis. So $500 million to $800 million combined with a like amount of debt to properly capitalize the MLP gets you to kind of a $1 billion, $1.6 billion annual rate of drop-downs in terms of capital market capacity, without Williams taking units. Anything above that, certainly Williams may have to take Class B units as consideration. Faisel Khan - Citigroup: In terms of increasing your guidance in Midstream, how much of the increase in guidance is really a function of the current commodity prices? Or does the increase in guidance have to do with new projects coming online?

If you look at the free cash flow bar there, you can see the portion of that that is from margin uplift, and you can see the portion that is from discretionary expansion. In 2006, the vast majority of the increase in 2006 is from NGL margins, but we also have a very substantial portion coming from Devils Tower. So I wouldn't want to give you an exact number on the Devils Tower piece, but it is a substantial portion of that. it has to do with the revenue recognition and, as well, the Triton/Goldfinger volumes that are coming in to the tune of about $4 million a month, just to give you an idea compared to last year. So that is a significant increase, and that has been higher than we would have expected from them. Faisel Khan - Citigroup: Okay, I guess asking a different way, what is your assumptions for margin per gallon, out in 2007 and 2008?

Okay, great as you can see there, we've put in that range of $7 gas price and $55 on the bottom crude oil and the $69, I believe that is, on the high end. That would equate to, at a midpoint -- so that basically sets the low and the high of that range. At midpoint, that would be an assumption of about $0.18 per gallon. Faisel Khan - Citigroup: Okay, I got you. Okay, and then if I could ask a question on the Power side to follow up on Carl's question, how much unhedged capacity in the L.A. Basin do you guys have, going into the third quarter?

Faisel we're largely hedged. I'm going to estimate we have probably got around 500 megawatts or so. Faisel Khan - Citigroup: Okay, is that some of those units that you have unhedged, is that kind of the higher heat rate stuff, or is it a mix of kind of low/mid heating?

It's a mix. Faisel Khan - Citigroup: Okay, great and on the E&P side, the four new Super Sundowner rigs that you're going to take delivery on -- in terms of the pricing on those rigs, is it fairly similar to what you got from H&P?

Yes. We were very fortunate, both on the H&P and on those rigs, to have locked in a rate that we believe today is substantially below market. So yes. Faisel Khan - Citigroup: On the E&P costs sequentially, I understand that there were some adjustments; there were some one-time unusual items this quarter. But sequentially, quarter over quarter, first quarter/second quarter, was there a rise in the E&P guidance? Or was that fairly flat?

We did see a rise yearly, more for the year and I guess a lot of it is sequentially. But we saw about a $0.04 per Mcf rise just in general from last year. Sequentially, we actually, because our volumes have gone up so much on a per-unit basis, if we didn't have the prior period adjustments in there, we actually would have seen our second quarter lower than our first quarter on a per-unit basis. That is something that I wish the numbers reflected, but if you look at it, I think, if you to everything out and kind of normalized it, instead of like a -- I think our investor relations sheet shows the first quarter about $0.505, and it was probably more like $0.58. The second quarter showed $0.65, that was probably more like $0.53. So it was trending down, which I would expect it to do with the strong -- even with costs going up, our volumes are going up on a stronger basis, if you will. Faisel Khan - Citigroup: Okay, great, thank you for your time.

Thank you.

Thank you. We go next to Craig Shere of Calyon Securities. Craig Shere, Calyon Securities: Hi terrific quarter. Kind of following up on a question that Faisel asked, if you're going to raise -- and I don't know if Steve or Don want to comment on this, but if you're going to raise maybe $500 million in equity a year in cash from the MLP, and you're only raising your CapEx guidance maybe a couple hundred million a year, doesn't that create extra cash flow? And what are you going to do with that? Donald Chappel: Craig that's a good question. Again, we have not yet concluded the MLP drop-downs in guidance. Certainly, it's a goal, and one that we believe we can execute on. But we do have some work to do with the Boards of Directors of both Williams and Williams Partners and the Conflicts Committee of Williams Partners and their advisors. But to the extent that we're in a position where we have excess cash, we know the different uses for that. Again, we're very much focused on maintaining our credit rating, improving it over time but also focused very much so on driving value for shareholders. So we will do whatever we can to create as much value as possible.

I would just add that, certainly, we have been very clear that we are opportunity-rich, and we do have many opportunities to invest. Alan Armstrong has foreshadowed some of his opportunities. Ralph has talked about potentially some additional farm-in opportunities in the Piceance. We believe that we are creating the maximum shareholder value by investing in these very high-return projects. Craig Shere - Calyon Securities: So let me see if I can interpret that a little bit. Steve, it sounds like there's plenty of opportunity to ink much more in terms of accretive growth CapEx projects and ultimately raise 2007/2008 guidance and beyond. Is that a fair statement?

Well, I can assure you that, to the extent that we do make additional investments, then you would see an associated boost in earnings guidance. Craig Shere - Calyon Securities: On Don's comment, I kind of heard for the first time maybe a window opening there. Maybe it's because you're having so much success that you all feel that maybe you don't have to wait until you're investment grade to start applying some free cash flow towards options like share repurchases. Did I hear that correctly? Donald Chappel: We're not going to go into the latter part of your comment today, but certainly, I think, as Steve points out, we have very substantial, very attractive growth projects that we're pursuing with a great deal of discipline. We do see that we will have substantial proceeds that will likely be available to us through the drop-down process, to the extent that it's equity that we raise rather than debt. We will continue to look at our cash position and our cash needs and look at appropriate uses, balancing equity and debt considerations. Craig Shere - Calyon Securities: Great and then one question for Ralph, Ralph I'm trying to understand what is driving the increased production guidance. Is it simply the really great success you're getting with increased efficiencies, or are you factoring any potential increase in rig counts in 2007 and 2008 into your increased guidance?

Well, the original guidance was 25 rigs total. We will be more, probably, as I mentioned, 20 or 21, maybe one more in the valley, and four growing to six or more in the latter years, at least, in the Highlands. So it's a slight increase, possibly, in rigs. But most of it is just efficiency guidance, efficiency improvements, which add, for this same number of rigs, additional wells drilled, which add to the production. Craig Shere - Calyon Securities: But when you get the Nabors rigs, assuming you don't lay any older ones down, aren't you going to be over 30?

We would be, but that's the part about high-grading the fleet. We think there's an opportunity to drill at least what we had, and probably more with less rigs, more in the 25 to 27 level, and actually be more efficient. Because some of the rigs, we will just be able to either lay down or use for new opportunities, as the other Piceance areas develop for us. So I think the Valley -- we can do more in the Valley with the number we have given you or slightly higher, and not stress the infrastructure of the Valley. At the same time, we hopefully can high-grade, maybe lay some down and/or move them to new projects. Craig Shere - Calyon Securities: What kind of timeframe would you expect before you decide on what to do with some of those legacy rigs?

That will be mostly in the fourth quarter and the first quarter, not really in the third quarter -- and even into the early part of next year, as I mentioned, first quarter. Because we were projecting the Sundowner rigs to come on in 2007. Obviously, we don't have them yet, so we need those to actually be delivered and all that. So it will take a little while. Craig Shere - Calyon Securities: Okay, thanks a lot.

Thank you. We go next to Shneur Gershuni of UBS. Shneur Gershuni - UBS: Hi, good morning guys great quarter. I just wanted to, I guess, bring the conversation back to Power again. At this point right now, when do you think that we'll start to see interest in users be interested in recontracting in California in the 2011/2012 timeframe? Is it too early to start thinking about that now? Is that six months away? Is that a year away?

I don't think it's too early. I think there's a couple of RFPs that are being discussed that go out as far as 2014 and one as far as 2020. They are not approved, but they're certainly being discussed among various parties, the CP6, et cetera, in California. The normal cycle is three to five years, so I have estimated probably 2008/2009, you'll start to see contracts out as far as 2015. Shneur Gershuni - UBS: Okay and I guess the second question I had was just with respect to repowering the AES plants. Is that something that you're considering? Would it involve a capital contribution on your end?

We're certainly looking at our options as far as repowering. We're not really far enough along to say whether it would involve capital or not. There are options out there. The RFPs that are being put fourth do contemplate repowering. So we will certainly evaluate those as they come up. Shneur Gershuni - UBS: Okay, thank you very much.

Thank you. We go next to Rick Gross of Lehman Brothers. Rick Gross - Lehman Brothers: Good morning. I've got a couple of related questions on the MLP. All along, you've indicated that there isn't anything in the guidance for the drop-down, but you have now to some degree indicated that a pretty good chance we're going to see sizable assets move. From a standpoint of just looking at the implications, it would seem that for each $1 billion that you drop down, to do the math simply, 10 times would mean $100 million of EBITDA being dropped down. Over time -- once again, that's not in the forecast. On the other hand, for each $1 billion you spend, your EBITDA multiple is much lower. Let's pick a low number for talking purposes, five times. So you have got, one would think, the ability, given that we think we can spend it but not spend it, that in your own mind between the drop-down loss, the recycling math, the new opportunities that, net-net-net, there won't be a whole lot of change, even if we drop down a lot of the assets in your forecast not adjusted for the drop-down. Is that a bad assumption? Or is there likely to be the math calculus of net loss but higher valuation in the way that the cash comes to the Company? Donald Chappel: Certainly, we don't see that as necessarily driving a great deal of earnings upon drop-down. That's really not the goal; it's to lower the cost of capital, as well as to receive a premium valuation because of that lower cost of capital that WPZ has, as well as grow our GP value. We believe that lowering cost of capital, it will create value for Williams' shareholders. But clearly, taking assets that are in-service and earning and recapitalizing those -- we believe that the reinvestment opportunities are terrific. We have got some very strong reinvestment opportunities, but there's certainly a lag between the time those funds are available for investment or other purposes and actually seeing that show up in earnings. But nonetheless, the lowering of the cost of capital and the growing value of the GP, we think, is powerful. Rick Gross - Lehman Brothers: The other issue, back in the appendix, is that it showed that you go from a marginally short gas position in 2006 to about breakeven in 2007 to, I don't know, a couple hundred, maybe $225 million net long in your gas position, enterprisewide. If you drop down assets, part of that short position in Midstream begins to dissipate. It moves over to the MLP. Is it likely, or is it something you will think about as far as hedging out a little bit more of your production exposure, as this kind of math percolates through the MLP drop-downs as well? Donald Chappel: Another good question. Certainly, we look at the enterprise level, and to the extent that some of that commodity exposure moves over to the MLP, that we would certainly take that into consideration in determining how much to hedge. Rick Gross - Lehman Brothers: This is a very specific question for the Power folks. Mirant has just signed an extension. I haven't seen whether that's filed or not. If it has, have you seen the terms as far as capacity payments or any of the other interesting terms that might give indication of level of market out there?

No, Rick I haven't. We're certainly looking at it, and we will be following to see if anything is public. I also -- and I could be incorrect here -- I think that was with PG&E. Rick Gross - Lehman Brothers: Yes, it was with PG&E. It's different, but it's semi-related.

Yes, certainly, it will give an indication. But we haven't seen anything public yet.

Thank you. We go next to Maureen Howe of RBC Capital Markets. Maureen Howe - RBC Capital Markets: Thanks very much. I'm just wondering, on the Power side as well, if you can give us some color post 2008. It looks like you have done a pretty good job of contracting in the West. Are you seeing an interest in purchases going longer?

In the West, or across --? Maureen Howe - RBC Capital Markets: Well, really across.

Yes, I think so. We're seeing indications that it's an RFP process, in most cases. We are seeing some municipalities and co-ops who are interested in going a little further out. I think, again, some of the things you saw over the last month or two is just another indication that markets may be tightening quicker than people thought. Maureen Howe - RBC Capital Markets: There has been a couple questions that have sort of skirted around the issue a little bit on the credit rating, and I know you've talked about opportunity-reach. So is it fair to say that you are more -- this is probably for Steve and for Don -- more focused on pursuing the growth opportunities, and perhaps less concerned about returning to investment-grade credit rating?

Well, we certainly drew a distinction that in 2003 and 2004, we were all about debt reduction. But beginning in 2005 and continuing in 2006 and the future, it's very much a growth story, and we believe that we are creating the most shareholder value by investing in these very attractive projects. We have also said, however, that we want to continue to take steps and actions that are credit-neutral. But we will continue to make progress towards an investment-grade rating, we believe. Maureen Howe - RBC Capital Markets: But more focused, Steve, on the growth side, perhaps, sort of growing your way out of it, as opposed to perhaps paying your debt down on your way out of it?

That's a good conclusion. I think that's another way to paraphrase what I said. We're clearly about growth, growing our equity. We're not seeking at this point to accelerate debt buyback. Maureen Howe - RBC Capital Markets: Okay, that’s great. Thank you

Thank you. We go next to Rebecca Followill of Howard Weil. Rebecca Followill - Howard Weil: On the Barnett, you have talked about that it was a bolt-on expansion. Can you clarify what that means? Is that an expansion in addition of acreage, or is actually buying proved properties? Or what do you mean by a bolt-on expansion?

It's in the same vicinity of where we are today, which is basically in the core/Tier 1 area, as they call it. Basically, it is an acquisition of both some producing properties, so existing acreage, and opportunities to drill additional wells, some PUDs and some probables. Rebecca Followill - Howard Weil: But it would be fairly small in nature?

Yes, it is pretty small, similar to what we mentioned in the first-quarter 10-Q. Rebecca Followill - Howard Weil: Second, on the Midstream business, can you clarify again -- I know questions have been asked, but the guidance increase that you have for 2007 and 2008 -- how much of that is due to a higher oil price, and how much of it is due to additional development or capital that you're spending on projects?

First of all, just to kind of give you a feel for that, as I mentioned earlier, $0.18 is what we have as far as our midpoint in there. The margins we experience in the second quarter of 2006 were $0.33 on the same basis, just to kind of put that in perspective for you. But if you look at that free cash flow slide that we showed, that shows you the margin uplift over and above the five-year average, which is right now about $0.132. You can see how much is coming from margin uplift there in 2007 and then in 2008. So it's about, all in all, from our earlier guidance, all in all it's about $100 million coming from margin uplift, which includes the average that increased from $0.11 to $0.13 from the recent uplift we had, and then an additional about $0.05 uplift over and above that. Rebecca Followill - Howard Weil: Perfect. Thank you and then the 2006 guidance excludes or includes the charges for Gulfstream Liquids? I think you said that it was $135 million, but I'm looking at the release, and it looks like more like $68 million. Is that correct?

That's right. The midpoint has increased about $68 million on a reported basis on that guidance slide; that is correct. That does include the charge. Rebecca Followill - Howard Weil: Finally, a question on Power. I know that it will be difficult to answer it, given your past stance on this. But any thoughts to once again maybe re-looking at putting that business up for sale? I know you probably can't answer it, but I thought I'd give it a try.

You are right. We can't. That's the short answer. Rebecca Followill - Howard Weil: The short and sweet is no. Okay.

The short answer is we won't comment on that, but I would say that Williams has a history -- we don't fall in love with any of our assets. We're going to do the right thing, and we're always evaluating structural steps that we can take. Rebecca Followill - Howard Weil: Okay, thank you.

Thank you. We go next to Sam Brothwell of Wachovia. Samuel Brothwell - Wachovia: Hi good morning. I think.

Sam, just a minute, we're running out of time, so this will be the last question. Samuel Brothwell - Wachovia: It will be a quick one. Just looking in the appendix at your Pipeline segment profit guidance, can you give us roughly a breakdown on the delta from 2006 into 2007/2008, how much of that is coming from your assumptions on the rate increases, and how much is growth?

If you look in the appendix on slide number -- I can't read that number; somebody help me. Is that 68? We have a box in there that shows the segment profit layers for expansions that you can lift out substantially what is associated with expansions from -- I'm sorry 69. Samuel Brothwell - Wachovia: Slide 69? I see it. Thank you very much.

Yeah.

Thank you. At this time, I would like you can the conference back over to Mr. Steve Malcolm for any additional or closing remarks.

Again, we are delighted with our progress, and we look forward to continued crisp execution around our game plan. Thank you very much for your attention this morning.

Thank you for your participation. That does conclude today's conference. You can disconnect at this time.