Travis Campbell - Head of IR Steve Malcolm - President and CEO Don Chappel - CFO and SVP Ralph Hill - SVP of Exploration and Production Alan Armstrong - SVP of Midstream Gas

Shneur Gershuni - UBS Carl Kirst - Credit Suisse Faisel Khan - Citigroup Sam Brothwell - Wachovia Craig Shere - Calyon Securities Rick Gross - Lehman Brothers

Good day, everyone, and welcome to The Williams Companies Third Quarter 2006 Earnings 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.

Thank you and good morning, everybody. Welcome to our third quarter call, and thank you for your continued interest in our company. As usual today, you'll hear from Steve Malcolm, our Chairman; and Don Chappel, the CFO; also Ralph Hill, President of our E&P business; and Alan Armstrong, President of the Midstream business, will be making some comments. We're aware that there are a number of other companies that are releasing earnings this morning as well, and know many of you need to listen to those calls. So with that in mind, we have a fairly small number of slides as part of the presentation, especially for us. As with the last quarter, all of our business unit heads are here and present and each of them are available to answer questions after we get through the prepared remarks. As you would expect, all the slides and detail are available -- all the slides and all the detail in the appendix are available and for your use. Before I turn it over to Steve Malcolm, please note that all the slides are on our website in a PDF format. The press release and accompanying schedules are also available on the website. If you look at slide number two and three, titled "Forward-looking Statements," that details various risk factors related to our future outcomes, it's important that you review the information on those slides. Slide number four, 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 generally accepted accounting principles. Those schedules follow the presentation and are an integral part of our presentation. So with that, I will turn it over to Steve Malcolm.

Thanks, Travis. Good morning and welcome to our third quarter conference call. We are very excited about our third quarter results. And looking at slide number six, as you can see from these headlines, both quarter-over-quarter and year-to-date numbers are up significantly. Our recurring adjusted earnings per share is up from $0.22 per share last year to $0.28 per share this year, fueled by strong NGL margins and significant increases in production. NGL margins during the quarter, $0.42 a gallon, versus a five-year average of about $0.15 a gallon, versus about $0.20 a gallon experienced a year ago; production, up from 682 a day to 831. As Travis mentioned, Don will be updating you on our quarterly results. We'll also hear from Ralph, who will provide an update on some of the Piceance success. And Alan will fill you in on some exciting opportunities we're seeing in the Western Deepwater. A couple of comments before I proceed. As many of you know, the FERC recently issued an order in a Kern River rate case proceeding. Of particular interest to Williams was the portion of the order addressing Kern River's authorized return on equity. The FERC authorized an 11.2% return on equity for Kern River, which was a modification of an earlier decision by an administrative law judge recommending a return on equity of 9.34%. Certainly the FERC's order on this issue was a significant improvement over the administrative law judge's recommendation. Nevertheless, we remain committed to pursuing higher return levels in our rate cases. The FERC has recognized the importance of continued infrastructure development in this industry, and we believe that authorized returns need to be higher than 11.2% in order to encourage that development. On the topic of MLP drop-downs, and as previously announced, we continue to have a goal of completing additional transactions of approximately 1 billion to 1.5 billion involving gathering and processing assets between us and Williams Partners within the next three months. It is important to remember with respect to our MLP strategy that drop-down transactions are subject to approval by the Board of Directors of both Williams and the general partner of Williams Partners. As well, the terms of certain transactions may be subject to approval by the Conflicts Committee of the Board of Directors of the general partner of Williams Partners. This is about all that we will have to say with respect to our drop-down strategy this morning. Turning to slide seven. I don't intend to cover all of these points, but I believe that we are well-positioned for near to long-term value creation. We have premier assets that are opportunity-rich. We're pursuing growth with discipline. We have had a solid record of delivering results, and in fact have generated more than 100% return to shareholders over the last eight quarters. And I believe we're taking action to drive value creation. And as we've discussed, our MLP and our deep bench of qualifying asset plays an important role in our value creation strategy. The next few slides describe how our portfolio businesses delivers value in a variety of price environments. As this slide, number eight shows, during periods of significant commodity price volatility, our Midstream and E&P businesses have continued to produce positive and growing earnings. Here you see that over the last seven quarters, crude prices have been generally rising, as shown at the top, while natural gas prices, after peaking at historic levels late last year, have come down significantly, shown there in the middle of the slide. But throughout this whole period, our two most commodity price-sensitive segments, E&P and Midstream, have shown steady, combined growth. Another important point is reflected on slide nine. E&P net realized prices have been relatively unaffected by the cash market drop that the industry has experienced. You can see on this slide, over the last five quarters, the Opal and Henry Hub gas prices have had wild swings. Because of hedging and our transportation agreements out of our producing basins, our realized natural gas prices for E&P have fallen less than cash prices, even in what was a highly-volatile commodity price environment. Let me draw your attention to the arrows that highlight our net realized price in the third quarters of 2005 and 2006. Quarter-over-quarter, our net realized price for E&P production was off just 10% from the third quarter of 2005, and compare that with the average cash price moves during those same quarters. At Henry Hub, we saw a drop of nearly 40% from third quarter '05 to third quarter '06, and we saw Opal drop during the same period by 35%. On slide 10, as we have highlighted in the past, Williams is very good at managing the transportation that moves our gas out of the producing basins and on to market. Importantly, in many cases we are moving our production to markets where we can capture a premium over Rockies prices. And as we have said many times in the past, we are a Rockies producer, not necessarily a Rockies price taker. Turning to slide 11, obviously, commodity prices affect Midstream much differently. As you can see from this graph, recent commodity prices have provided us with very strong frac spreads. The effect of weaker natural gas prices in the third quarter in the face of continued strength in crude prices has been very good for our processing business. Slide 12. Therefore, the soft natural gas prices that we have experienced in the Rockies has obviously benefited our Midstream operations. We are a purchaser of Rockies gas to fuel our processing business. And in a strong crude market, lower gas prices dramatically improve the margins for our Midstream business. Another aspect of our portfolio of businesses is our hedging position, as shown on slide 13. Clearly, our E&P production creates a long position for the company. Long, even when you take into account the hedges that we have entered into, as noted by the red line on this graph. Turning to the next slide, slide 14. If you net against our E&P production, the fuel and shrink from our Midstream business, you see that we are slightly short gas for the remainder of 2006, short -- slightly short to balance for 2007, and only in 2008 do we get back into a slightly long position for natural gas. So, I will conclude with slide number 15. Again, we are -- I believe that we are well-positioned for near to long-term value creation. We control premier assets that are rich with growth opportunities. We are pursuing growth with discipline, having adopted the EVA methodology. We have a solid record of delivering results, and we're taking action to drive value creation. So with that, I'll turn it over to Don Chappel.

Thank you, Steve. Good morning to all of you joining us on the call. I'll quickly run through the highlights of our third quarter and year-to-date results, which are more fully described in our press release and 10-Q. I'll come back later in the call to review some updated guidance and other information. Let's turn to slide number 17 please, financial results. As Steve described, we're delighted with the overall performance of our businesses. I would note that our net income is up sharply. However, net income is included -- includes both nonrecurring items and the mark-to-market effects related to our power business. So you can see on a reported basis net income is up sharply for the quarter; somewhat down on a year-to-date basis. A more transparent and a key measure of our earnings performance is on the bottom line, recurring income from continuing operations after mark-to-market adjustments and you will see what we believe is a better indicator of our performance, and this is consistent with what we have done in past quarters. We are reporting $0.28 versus $0.22, an increase of 27%, and on a year-to-date basis $0.87 versus $0.60, an improvement of 45%. Let's turn next to slide number 18, and I'll hit some of the nonrecurring items. Again, we start the slide with income from continuing operations as reported. We make some adjustments for nonrecurring items. Regulatory and litigation contingencies totaled 10 million for the quarter, 253 million on a year-to-date basis. I won't describe those in detail, as they are described in great detail in our Q and press release. We had a contingency adjustment of 8 million in the quarter. We had expense related to prior periods, a correction totaling 11 million for the quarter, 4 million year-to-date, and then finally, eliminated $8 million of gains on asset sales in the quarter, $15 million year-to-date, to come down to a recurring earnings number. But this still includes the effect of mark-to-market accounting on our power business. Let's turn to the next slide, number 19, please, and we'll walk through the mark-to-market adjustments. As you can see there, the mark-to-market adjustments for power for the current quarter, we reversed the forward unrealized mark-to-market losses totaling $16 million, as compared to $141 million in the prior year. And then we add back the realized gains from mark-to-market that was previously recognized of 80 million, as compared to $72 million a year ago. Total mark-to-market adjustments pre-tax totaled 96 million, as compared to 213, and then after-tax, 59 million versus 130 million. And you can see the comparative numbers on a year-to-date basis. The sum total of all that is, again, the recurring earnings after mark-to-market adjustments of $0.28 versus $0.22, and $0.87 versus the $0.60 that I mentioned earlier. Next slide please, number 20. This is the third quarter segment profit, both on a reported and recurring basis by business unit and consolidated. First let's look down the slide to the bold line entitled "segment profit after mark-to-market adjustment". You can see there in 2006, we had profit of $493 million, as compared to $382 million a year ago, an improvement of $111 million, or 29%. E&P profit was up about $8 million, and I'll talk through some detail in just a moment. Midstream nearly doubled. Gas Pipeline is down a bit. And Power, which after mark-to-market is on the final line on this schedule, the 17 compared to the 13 loss in the prior year, is improved quite nicely. Now let's take a little closer look at E&P results. Consolidated production volumes increased during the quarter by 22% over the prior year. Domestic volume increases were up 24%. Domestic revenue was up 68 million from these higher volumes. Average net realized price decreased about $0.49 per Mcf, or about 10%, causing revenues to be down about $35 million. Hedging effectiveness income in the quarter of approximately 5 million, versus an ineffectiveness loss of 16 million in the '05 quarter, caused a $21 million swing in income. DD&A was up 29 million due to substantially increased production and higher capitalized drilling and completion costs. Per unit DD&A is approximately $0.19 per Mcf higher this quarter versus a year ago quarter. Lease operating expense is up about $11 million, reflecting increased number of producing wells, higher industry costs, and production enhancement work-over expenses. LOE costs are $0.05 per Mcf higher this quarter versus the prior year. Turning now to Midstream. The major drivers to our recurring segment profit are another record for NGL unit margins; higher fee revenue, higher product margins from our Canadian olefins group, and increased operating expenses. Natural gas liquids margins again exceeded historic levels, averaging $0.42 per gallon. The price variance contributed 74 million of the overall 85 million margin variance, the remaining 11 million due to higher volumes. Fee revenues increased 13 million quarter-over-quarter, primarily from the Deepwater Gulf-based increase, Triton and Goldfinger volumes, resident volumes across Devils Tower, and unit -- higher unit production rates. Fee revenue in the West also contributed an increase, due to contract renegotiation, rate escalation and volumes from the Wamsutter expansion. Our olefins group contributed 10 million more than 2005 second quarter, due to 16 million in higher commodity margins and volumes, partially offset by $6 million lower trading margins due to falling prices, and about 2 million accrual for that Gulf Liquids litigation. Operating expenses increased 20 million overall, about 12 million from the West, due to large part a 7 million adjustment to O&M accrual to properly reflect liabilities for goods and services that have been received but not paid. That is a nonrecurring item that we mentioned, a portion of it. And the Gulf contributed 7 million in higher O&M, mainly due to 4 million in higher insurance premiums. Let's turn next to Gas Pipelines. Recurring segment profit of 109 million is $38 million below the same period a year ago. The main drivers are 8 million of lower earnings in the JVs and partnerships, due to certain development costs and interest expense at Gulfstream and our participation in the Pacific Connector project, 6 million of higher administrative and general labor and related costs due to the increased cost in our group insurance and retirement costs, 5 million of higher IT support costs as we continue our efforts to complete the installation and make refinements in our new common financial system, and 4 million of higher property insurance premiums due to increased premiums for our offshore facilities due to hurricanes last year. And finally, 7 million of higher contractor and outside service costs related to various repair costs and pipeline assessment work. As a result of tight demand for workers, we've seen an escalation in the costs of these types of services, especially for offshore work. Note that much of these higher costs levels are reflected in our rate filings for both Northwest Pipe and Transco, and as such, should ultimately be recovered on a go-forward basis. Again, we expect new rates to go into effect subject to refund during the first quarter of 2007. And then, let's turn to Power. Power's recurring after mark-to-market adjustment results of $17 million profit, versus a $13 million loss a year ago, reflect increase in hedge cash flows due to the benefit of structured hedges. The third quarter of '06 includes a $13 million loss due to lower cost of market write-downs on storage inventory, and 7 million of realized losses on storage injection hedges. These values are forecast to be recovered when volumes are withdrawn. Next let's turn to slide number 21, and this is a year-to-date basis. And in the interest of time, I won't walk through the detailed results. I'll just focus on the total here. Segment profit after mark-to-market adjustment of 1.430 billion, versus 1.130 billion a year ago, an increase of $300 million, or about 27%, and again, you can see the detail by business unit, with Power after mark-to-market being the final line on the slide. So, again good strong performance for both the quarter as well as on a year-to-date basis after eliminating nonrecurring items and mark-to-market effects. With that, I'm going to turn it to Ralph Hill.

Thank you, Don. I'm on slide 22. Just to highlight again what Don mentioned. Our production was up 22% for the quarter, almost 150 million a day since third quarter 2005. We also surpassed the 800 million a day of production level. We got an additional 4,000 plus acres of downspacing in the Piceance, and that brings our Piceance downspacing now to about 65,000 acres in the -- or 62,000 acres in the Piceance Valley. In the appendix, you'll see slides on the Big George and Powder River that continue to be very important part of our growth. It was up approximately 24%. We have a new farm-in; I'll talk about in just a few minutes. And we also have made significant strides in two other areas, our San Juan production is at record levels, and our Barnett Shale production is from virtually zero last year is up to about 16 million or 17 million a day on a net basis to us. Turning to slide 23. Looking specifically at Piceance production, it was up 100 million a day -- 101 million a day, or 31%, from a year ago. We currently have 24 rigs operating in the Valley and the Highlands. This time last year, we had 15. We have two of our H&P FlexRigs that remain to be received this year, and they will be received later in the fourth quarter. And as you know, in the first quarter, early part of the second quarter of 2007, we have four of the Nabors Super Sundowner rigs that will be coming in. That will give us a total rig fleet above where we will end up operating. We will now be able to high-grade our rig fleet and retire some of the less-efficient rigs that are out there operating for us. Slide 24. On the Highlands, just an update there. 39 wells were spud year-to-date. We now have over 60 wells that we have drilled in the Piceance Highlands, continues to build impressive momentum. Production this time last year was 5 million cubic feet a day, and now it's over 24 million a day. We were able to get eight rigs operating during the third quarter in the Highlands, which is a record number of rigs operating for us. Now with the winter stipulations and just the winter weather, we are back down to three rigs in this quarter, but we were able to get eight rigs up there. We are working very hard on all of our road, pipeline and facilities under construction. And we also are getting closer to getting approval both in the Valley and in the Piceance Highlands, in addition to getting to our infrastructure built, getting approval to doing year-round drilling in these two areas, which will be important for our developments in the Highlands particularly. Turning to slide 25. We were able to expand our Highlands ownership position. On this slide, the ownership positions are detailed in the red outlines. This slide does not detail Trail Ridge, but recall that is part of the Highlands opportunity that we are drilling. This just discusses the farm-in deals. Please recall in Ryan Gulch. We earned about 16,000 net acres by drilling six earning wells. At Allen Point, we earned about 6,200 net acres by drilling six wells, and we've added a new area in the Highlands which we're calling Barcus Creek. It is a bolt-on to the track of Ryan Gulch. It's in blue on the slide here, because we have not drilled it. But after we drill five earnings wells, we will earn that acreage. Turning to slide 26. Talk a little bit more about Barcus Creek. It is a direct bolt-on to the Ryan Gulch project. It does target the Williams Fork formation, which is where we drill today. We will be able to drill by drilling five wells, and we've already spudded our first well, we will earn this acreage. After earning, those -- after drilling those five wells, we'll have a 45% working interest and approximately 25,000 gross acres, or 11,000 net acres, to Williams. It is federal acreage primarily. So, it has a very healthy net revenue interest of 87.5%. Moving forward we will be partners with our -- we will head -- partners heads up with our partner in this in both the construction and gas gathering and processing systems. We will be the operator in drilling and operating the wells. And on a 40-acre density, we think there would be at least 600 potential drilling locations there, and that is on 40-acre density. And it is too early to tell that density would move away from there. And that is the end of my slides. Other slides are in the appendix, if you have any questions. And I'll now turn it over to Alan Armstrong.

Great. Thanks, Ralph. Midstream did have a great quarter from both the short-term and a long-term perspective. On a short-term basis, we had another record quarter for recurring segment profit, allowing us to raise guidance once again. And we made great progress on bringing some of our large projects closer to fruition, like our fifth train at Opal, our discoveries at Tahiti Lateral, and the extension of our Devils Tower system out to Chevron's Blind Faith prospect. Moving on to slide 28 here. We did from a long-term perspective make some great progress as well. We're pleased to announce that we are moving a major deepwater project into our capital guidance, and our pipeline of opportunities continues to fill in behind us as we mature some of these opportunities. Our previous slides similar to this showed about $385 million in guidance for 2006, 2007 and 2008. And we have added a new Western Deepwater expansion project, which totals about 450 million, and that carries on out past '08, actually, in terms of that total 450. You can see a schedule of that below here with the project titled "Western and Gulfwater Deepwater Expansion". I'm going to describe that project in a little more detail on the next slide, and additionally you'll note that even though we are moving this project into the end guidance bucket. Our under negotiations bucket there in the middle has also refilled with a major expansion that we're working on out in our western G&P business in the Rockies. So, we are excited to continue to see these opportunities to continue to fill in as we move forward on this. I'm going to turn to the next slide now, slide 29. As stated previously, we have added capital to our 2007 and 2008 guidance to fund our planned Perdido Norte project, and this project, which would extend out to the Perdido Fold Belt in the lower tertiary play in the western deepwater Gulf of Mexico. This prospect in this area -- the prospects in this area include Shell's Great White, Trident, Tobago, Tiger and Silvertip prospects. And the project includes approximately 65-miles of 18-inch oil line and approximately 100-miles of 18-inch gas line that will tie into our existing Seahawk gas line that serves Anadarko's Boomvang/Nansen platforms. And additionally, we will be making an expansion of our Markham gas processing facility to adequately serve this new gas production. Our Markham facility has basically ran completely full since we started that up, and so we are excited to have this new production to come in, and we will be making some expansion to accommodate this. This total project is expected to be in service and will be ready for service in late 2008, with the first full year of cash flow is expected to be nearly $100 million, and by cash flow, I mean segment profit plus depreciation there. And so, we are very excited about this prospect. It's been a long time, a lot of work, and a lot of effort by our team. We have not executed final agreements on this, but we are far enough along in the process that we felt it was appropriate to add it into our guidance here. And great potential out in this area beyond some of these existing prospects here. There's great potential out here for the future, and even into the Mexican Deepwater, as this pipeline will be positioned to serve that in the future as well. So this is a great long-term play for us, and this is exactly in keeping with our strategy to be a major player in the deepwater and get our foot out here while the window of opportunity exists to install the major infrastructure that will serve the deepwater for years and years to come. So with that, I'm going to turn it back to Don Chappel.

Thanks, Alan. Let's turn to slide number 31 please, 2006 forecast guidance. You will see here, let's focus on the bottom line, the most important line, our key earnings measure, diluted earnings per share recurring after mark-to-market adjustment. We have raised the lower end of our guidance range to $1.05 from $0.95 on the strength of our third quarter performance and the outlook for the balance of this year. The strong Midstream NGL margins are the primary driver of the increases. Let's turn next to slide number 32, please. I will hit a few highlights here. We have walked through some of the details of 2006 year-to-date profit. Now we'll focus on 2006 full year, as well as '07 and '08. 2006, we have some changes, and very few changes to '07 and '08 to our prior guidance, and I'll just hit some of the highlights. Again, let's focus first on the bold item, second line from the bottom, total recurring after mark-to-market adjustments. That's increased to 1.806 billion to 202.1 billion, a range of 1.8 to 2.0 from the prior guidance up about $60 million at the midpoint, and again on the strength of very strong NGL margins and volumes. Going back to the top of the page, well, reducing the top-end of our E&P guidance, very strong production but lower than planned prices. Midstream, increasing guidance once again on the strength of NGL margins and volumes. Gas Pipelines, reducing the top-end of the range slightly as some of those expenses that I noted earlier continue to burden the current year results. And as we look to '07, you will see a nice increase in expected profitability in Gas Pipelines following those rate cases. Looking at Power, we think the clearest way is to look at the bottom line in the schedule. Power, on a recurring basis after the mark-to-market adjustment, unchanged at 75 million to 125 million. The rest of those changes up there reflect the changes in -- that are driven by mark-to-market accounting. Looking forward to '07 and '08, again the bold line near the bottom, total recurring after mark-to-market, you can see a nice increase in 2007 and again in 2008. The 2008 level of expected profitability versus '06 is up about $600 million, or 33%, in just 24 months, from our increased level of current-period guidance. 2007 and '08, I'll focus E&P, profitability nearly doubles by 2008. That's based on a -- an assumption of a steady $7 NYMEX gas price and sharply improved production. Midstream, off a bit, as a result of forecasting somewhat lower margins in '07 and '08 than we experienced this year, certainly at the bottom-end of the range. Gas Pipeline comes up nicely, as we've previously mentioned, as a result of our expectations on our two rate cases. And then Power, again, looking at the bottom line, after mark-to-market adjustments, pretty steady at about $100 million, plus or minus. Next slide please, number 33. So take a look a capital spending. And again, I draw your attention to the bottom line first. On a total basis, 2006 is relatively unchanged. 2007 and 2008 are up substantially as a result of the project that Alan described in the western deepwater Gulf of Mexico. And you can see there that the detail with the change relates to Midstream. So, current-period spending in a range of 2.175 billion to 2.375 billion, about 2.0 billion to 2.2 billion next year, and then 1.8 billion to 2.50 billion in 2008. I would note that we are opportunity-rich. We have some terrific opportunities in our E&P business, our Midstream business, as well as our Gas Pipeline business. And I would expect that our capital spending guidance would continue to increase somewhat as we are able to seize those value-adding opportunities. And more about that in future calls. Next slide please, number 34. Just kind of review some of the items again. Segment profit recurring after mark-to-market adjustment, the second line there again reflects that $600 million increase over the next 24 months to a range of 2.2 billion to 2.875 billion. Cash flow from operations about 1.5 billion to 1.8 billion this year, increasing to 2.4 to 2.8 by 2008. That's an increase of about 900 million to $1 billion, or nearly 59%. So, very strong increase expected in cash flow from operations. Capital spending, I just reviewed, and again, we are opportunity-rich. And it is our intention to continue to seize these value-creating projects, projects that create EVA, and that we expect will create value for our shareholders. And we're pursuing those in a very disciplined fashion. Operating free cash flow is negative this year, but we had a substantial cash balance coming into this year, as well as proceeds from MLP drop-downs that certainly enable that. And as we look forward to 2007 and 2008, again we're wrapping up 2008 with a very strong cash position, as well as the prospect of an MLP drop-down providing some additional cash for reinvestment opportunities. Next slide, please, number 35. Just graphically depicts the guidance that we just discussed, as well as our past performance. And you can see declining debt to cap as we continue to improve our credit as well as capital spending. And our guidance is off somewhat in '07 and '08, meaning lower than '06. However, we've depicted there that we are opportunity-rich, and we would expect to increase CapEx guidance and, obviously, related profitability and value for shareholders in the future. Next slide, please, number 36. Just some financial strategy key points and these are consistent with my prior presentations. Again, we'll continue to drive, enable sustainable growth in EVA and shareholder value, we'll continue to accelerate our delivery of MLP benefits to Williams, and we'll continue to maintain or improve our credit ratios and ratings. We think that's important for a number of reasons. We'll reduce risk in the Power segment. And finally, we are opportunity-rich, and we will continue to pursue EVA-based investments that we believe will create value for shareholders, and these EVA-based investments will oftentimes require a new capital. We have substantial operating cash flows, as well as the ability to raise capital through the MLP drop-downs. And again, the combination of growth and operating cash flows and EVA creates substantial value creation for shareholders. Back to Steve.

Thanks Don. We have flown through our slides in record time. So, we'll certainly have time for questions. I know that some of you will be pleased that our presentation this morning was crisp and succinct, but I encourage you to review the detailed info contained in the appendix. Again looking at the last slide, slide 38, I believe, our portfolio of natural gas businesses is delivering strong performance. We are delivering both strong short-term results and long-term sustainable growth in economic value and shareholder returns. So with that, we will be happy to take your questions.

Thank you, sir. (Operator Instructions). And our first question will come from Shneur Gershuni with UBS. Shneur Gershuni - UBS: Hi. Good morning, guys. Nice quarter. I just had two questions. I guess the first question is related to Power. As I'm sure you're aware, there's a perception that recontracting this to power beyond 2010 remain a drag on the stock. Can you sort of talk to what the current recontracting environment is right now? Are you excited about potential opportunities? Do you feel pretty confident that you'll be able to extend the quantity -- the contracts beyond 2010 and be able to earn offsetting cash flows against the tolling agreements?

We are excited about the opportunities beyond 2010, either through RFP processes or bilateral negotiation. So from that vantage point, I would have to say we are excited. There are opportunities, we're pursuing them, and hopefully we'll be bringing some good news in the future. Shneur Gershuni - UBS: Okay. And just one second question here. Can you prioritize your expected use of cash flow, if the MLP drops-down generates cash flow beyond your CapEx needs?

This is Don. First and foremost, I would say our reinvestment opportunities in each of our businesses; we think that we have some terrific opportunities in our core businesses that return well above the cost of capital that will create the greatest value for shareholders. And we think that that's first and foremost. Beyond that, we'll have to look at the facts and circumstances at the time and see what the best use of any such capital might be. Shneur Gershuni - UBS: Okay. Would you be targeting debt pay downs versus share buybacks, or is that too far away to figure out?

I think we've said in the past that with the proceeds of our MLP drop-downs, we will need to pay down some debt. As WPZ borrows, our consolidated indebtedness will go up, if we were to not pay some debt down. So, there will be some debt pay downs. I can't tell you it's going to be -- when it's going to be, or that it's going to be dollar for dollar, but there will be likely some debt pay downs along the way. Shneur Gershuni - UBS: Thank you.

And our next question will come from Carl Kirst with Credit Suisse. Carl Kirst - Credit Suisse: Hey. Good morning, everybody. Great quarter. Alan, if I could actually touch on just the Western Deepwater expansion. I believe you mentioned about $100 million of EBITDA that would come in, in the first full year, I guess, 2009. Obviously first and foremost, looks like a pre-tax cash return of about 22%; great project. I know you guys tend to contract for a majority but not all when you do these expansions, and I guess I just wanted to touch based on that $100 million. When you take the, I guess, sort of MOU to definitive agreements here, is that $100 million going to be firm, or is there a certain amount of spot developments that you are expecting to come in over time?

Well, there's really I would categorize, I'm going to get into -- I'm not going to get in too much detail, just for competitive purposes, but I'll put the revenue in three different buckets. One, there is expected to be a minimum volume guarantee from one of the larger producers in that. Another bucket would be off of the proved reserves. And obviously on the front end, of course, the bulk of that money that -- or that revenue we are expecting comes from those two sources, so, pretty low risk on the front end of the project. The back end of the project is where we would be counting on more profitable reserves and other prospects in the area. But before that, first year cash flow pretty well would be in those first two buckets that I mentioned. Carl Kirst - Credit Suisse: Great, helpful. Just turning to E&P, Ralph, obviously, tremendous growth here on the all-in production side; a lot of new rigs coming in, more rigs still coming. Is it perhaps too early to venture an estimate on what you guys are targeting for a proved reserve growth for 2006? Or otherwise, maybe approach it from an F&D cost angle.

Yeah. We actually will probably -- showed as you know, early in 2007. We are in the process of our reserve review right now with our outside auditors. So, it is a little preliminary to do that at this time. Carl Kirst - Credit Suisse: Okay. The last question perhaps, if you could -- a lot going on, obviously, with the Highlands. I guess; one, could you just sort of update us the timing when you think the infrastructure in the Highlands is going to be complete? And obviously, have that area open up with even more activity. And two, remind us with sort of the ongoing oil field cost creep, what you think the economic hurdle is of gas prices in order to develop the Highlands?

Well, we are seeing -- we hope to have a majority of our infrastructure, the major parts of our infrastructure, which is the roads, the water, the employee camps and all that done by early spring at the latest. That will help us substantially. We hope to also hear good progress on our applications for year-round drilling from the various agencies that need to approve that, also in the near future. So, those two things we hope to have, I would say, done by the early springtime. As for -- and that will help the Highlands substantially, as you know. And as for gas prices and cost increases, we are looking at -- we're currently negotiating with a number of our vendors for next year. But there is pressure in various areas on price increases, or cost increases from 5% to 10%. That will not materially affect what we see going forward, as we've always said that we believe we can return our cost of capital and gas price ranges in the -- I think it was in the $2.50 to $3 range; that may move that up slightly to, say, $2.75 to $3.50 type range for those kind of returns. So, we still see a very healthy environment going forward with gas prices that are -- if they're in that range at the NYMEX level, we would be in very good shape E&P-wise. Carl Kirst - Credit Suisse: Great, thanks. Good luck.

And our next question will come from Faisel Khan with Citigroup. Faisel Khan - Citigroup: Good morning. I just wanted to make sure I understood the -- some of the basis assumption and the transportation capacity you have out of the Rockies. If I add up the transportation capacity you guys have, looks like for next year it comes to about 694 million cubic feet a day. And if I take the hedges you guys have outstanding, it's roughly -- and the collars that you have outstanding for next year, it's roughly 442 million cubic feet a day. So, is it right to assume that kind of 1.1 Bcf a day of your basis -- of basis is completely hedged?

I have, this is Ralph. I haven't thought of it that way. I look at it separate. I think that what we say is that since we do believe, we have substantial capacity to move out of the basin, if need be, which we do. We do have a number of local sales anywhere -- can be any -- sometimes up to 75 million to 100 million a day of local sales also that does not need to move out of the Rockies. But our basis is generally matched up with our hedge position. And then I guess you would say that through firm transportation, we have at least locked in the rates out. So, I think that is not a -- I think that's a fair way to look at it. I'd like to think a little more about it. But I think it's generally a fair concept. Faisel Khan - Citigroup: Okay. Either way it looks like for next year and for a lot in '08, you -- a substantial amount of your basis risk is substantially either hedged through transportation or through contracts.

I didn't get that audio. Just one moment please. Faisel Khan - Citigroup: Sorry. Did you hear me that or -- okay, okay.

No, I didn't hear -- I'm sorry. It didn't come through at all. Faisel Khan - Citigroup: No, actually in either case, your basis risk for next year in '07, '08 seems to be substantially hedged through transportation and hedges. Is that fair to say?

Yeah. That's what we believe. Absolutely. Faisel Khan - Citigroup: Okay. Is there any way you can comment on the rates that you got on the new Nabors rigs? Is it comparable to what you were getting either previously or maybe close to your H&P contracts you had?

We feel very good that we were early movers on those rigs, as we were on H&P. Faisel Khan - Citigroup: Okay. And who's your partner in farming into those acreage positions in the Highlands?

They've asked for us not to say their -- to divulge that. Faisel Khan - Citigroup: Okay.

Until they're ready to. Faisel Khan - Citigroup: Okay. And then, I think were another producer in the Piceance that talked about potentially looking at the deep side of the Piceance, in terms of what might be there. Have you guys looked at that at all?

Yeah. We continue to evaluate opportunities in what's called the Cozette and Corcoran formations, which are deeper, and we have and we will test some of that acreage, probably in 2007. Faisel Khan - Citigroup: Okay. On the Midstream side, will the new projects that you guys have in the western part of the Gulf, will that be CapEx spend at the MLP, or will that be at the C. Corporation?

That will be at the C. Corp. Faisel Khan - Citigroup: Okay. And then on the Power book, I just wanted to figure out, if -- there's been strong demand for assets on the -- for Power assets around the US. And thinking about it going forward, is the Power business from your perspective; is it still strategic for you? Is it a core asset that you think will remain with you for the next -- for the foreseeable future? Or if someone came to you with the right prices, is that always an option?

This is Steve. We've said that we don't fall in love with any of our assets, and are open-minded, and will consider any offers that we get from time to time for any of our assets. But having said that, we had the business on the market back in the 2002-2004 timeframe; didn't believe that we got any offers that made sense, and pulled the business back, and what we've been able to do since then. We've done -- we've made some great progress in hedging our positions through 2010. And as Bill described earlier, we have some exciting opportunities, perhaps, to do some things to forward sell beyond 2010. We've adopted hedge accounting, and that creates some obstacles to us in terms of being out actively seeking to sell the portfolio, and so that pretty much summarizes where we are today. Faisel Khan - Citigroup: Okay. Fair enough. And this -- and just last on the pipeline. You talked about a lot of cost increases in the pipeline versus last year. You talked about recovering those in your current rate cases. But -- I mean, is it fair to say that a lot of those costs are -- are they really ongoing costs? Or do those eventually come off or come down in future earnings?

I would just say this, that obviously, in this year we have a very extraordinary item with the capacity replacement project on Northwest. You filter that out. You look at our (inaudible) numbers you can see that we do expect some of that to attenuate, if you look in the out years on the capital slide. So I would refer you to that. Overall, we would expect to have to continue to do some level of maintenance investment associated with our internal inspections. But you will recall my previous comments on that, I hope, that we are having to install, for example, pig launchers and receivers to enable us to do the internal inspections that are part of the Pipeline Safety and Integrity Act. So, you're going to see a bit more investment on the front-end in the maintenance capital area than you would expect to see in the out years. Faisel Khan - Citigroup: And what's the status of Pacific Connector, is that still a viable project? Have you had conversations with suppliers?

We believe the project is quite viable, and conversations are underway with prospective suppliers. I would say that you -- understand that Fort Chicago is developing the LNG terminal, and they are the point people on securing supply. But we do know that those conversations are underway. Faisel Khan - Citigroup: Fair enough. Thank you for the time.

And, our next question will come from Sam Brothwell with Wachovia. Sam Brothwell - Wachovia: Hi, good morning, just two quick ones. Steve, I know you said you couldn't give much detail on the MLP dropdown, but I just wanted to ask is there any reason to think that your timing that you articulated on the second-quarter conference call would change?

I think I would just direct you to my earlier comment. I think it was that we expect to complete $1 billion to $1.5 billion in the half dropdown in the next three months. Sam Brothwell - Wachovia: And Ralph, in terms of the bolt-on up in the Highlands region, you've got 600 drilling locations. Can you give us any sense as to what you expect to recover in terms of reserves per well ultimately?

We expect that it would be somewhat of a look-alike of to our other Highlands projects, but we are just drilling our first well, but we are optimistic that it would be -- turn out to be successful in the sense that it would look like the other Highlands areas. But we're just a little too early to tell so far. Sam Brothwell - Wachovia: Okay, thanks.

Our next question will come from Craig Shere with Calyon Securities. Craig Shere - Calyon Securities: Hi, Don, a couple questions for you to start, and then one for Ralph and one for Alan. First a simple one, I may be using too low a tax rate, mark-to-market adjusted on recurring earnings, what would a good third-quarter income tax rate be, and what would a good full-year '06 and further out be for modeling purposes?

Hi, Craig. We'll get back to you with that one in a second. Craig Shere - Calyon Securities: Okay great. On slide 34 for free cash flow, if I understand it, that slide excludes the dropdowns to the MLP. Am I saying that right? So, if you dropdown $1 billion to $1.5 billion, and the MLP has to issue debt for half of that, so you buyback half -- those same -- the debt they issue, you buy back that amount on your balance sheet as you're consolidating, right? But then, you have another $500 to$750 million extra discretionary equity cash -- cash flows for equity. Am I saying that correctly?

Well, first, I would say that -- again, we'll look at the credit metrics and ensure that we don't slip back on credit. So I don't want to say that we will or will not buyback debt with the proceeds. But certainly over time, we would expect to. But certainly the excess proceeds, the equity proceeds will be dependent on the depth of the equity -- MLP equity market as it pertains to WPZ and this dropdown. So we'll see -- we'll just have to see what that is. And again, given where we are, I really shouldn't comment any further on any MLP dropdown matters. Craig Shere - Calyon Securities: I understand. So in other words, if the markets aren't liquid enough, you may have to take some MLP units. But if they are liquid enough, then in reality, given your guidance, you'd have anywhere from $500 million to $850 million of equity cash flow or available cash in 2007 that you haven't identified new growth projects for or any other value drivers for? Am I saying that correctly?

Craig again, I ought not to comment on any further aspects of our MLP dropdown at this point in time, but I appreciate your question and comment. Craig Shere - Calyon Securities: Okay, I am sorry to press that. Maybe while you're working on the income tax rate, I can jump over to Ralph and Alan. Ralph, does production guidance assume full contributions from the new custom-built rigs? When I say full contributions -- you recently increased guidance for production based on, say 30%, roughly, improvement in efficiency on the new FlexRigs. But are you incorporating that kind of improvement on all the rigs, custom-built rigs to be delivered through first quarter next year? And are you also incorporating the year-round drilling drivers you talked about in the existing production guidance?

We are -- basically, we're assuming in the 20% range on the efficiencies for the rigs. We do have a delay in there for each rig as it comes on, a several-month delay, just to make sure the crew gets up to speed and those kind of things. So there is a lag as the rigs come on, but there is generally about a 20% increase in efficiencies there. So to the extent we can grind that out better that would help us in the future. And, then the second part of your question was, I'm sorry? Craig Shere - Calyon Securities: Is year-round drilling incorporated in existing production guidance?

Well, it is in the sense of -- in the Valley, we're assuming that we can -- the Valley needs have some federal acreage. We'd like to do year-round drilling. We think it's more efficient. We're assuming that if we were able to do that, we would actually drill the federal acreage and do that year-round. If not, we would move to fee acreage. So in that case, yes; it is in the Valley. And then for the Highlands, we are assuming we would be able to drill more wells as we achieved a year-round drilling. So it's in there in a fairly good manner, but there is always opportunities, particularly in the Highlands after we get everything built and done that we could actually do more activity up there. So yes, generally it is, but not in an overly aggressive manner yet. Craig Shere - Calyon Securities: So, year-round drilling would provide upside versus guidance in the Highlands. And also, the rigs thus far, the custom-built rigs thus far that you have had an operation have produced efficiencies a bit better than the 20% that you're modeling in for the existing guidance?

The ones that have been there the longest are doing slightly better -- are doing better than 20. The new ones are typically down on the first few wells. So that's why again on average we're assuming in that 20% range. And then for the Highlands, it all depends -- again, we're still -- some of those areas, we only have 60 total wells up there, so we like what we see. But we're still delineating the fields and all that, so it would take some time to see, I think, additional upside in the production there. But we would like to think that would happen. Craig Shere - Calyon Securities: Okay. But the last of the rigs currently on order will come by the first quarter, and your guidance goes through 2008. So, am I to assume the 2008 production assumes just 20% uplift from all the new rigs?

Yes. Craig Shere - Calyon Securities: And Alan, what is your Midstream hedging philosophy going forward? If my memory is working, last quarter call you all -- you said that for third quarter, you had hedged out 40% of the volumes at second-quarter margins, which apparently third quarter turned out to be healthy margins anyhow. As you move forward, I know you can't hedge out NGLs for years forward, but what's your thinking and philosophy with regards to that?

Well, first of all, just to clarify what we have done, when we said hedged -- from a pure accounting term, I suppose it's a hedge -- but what we have sold forward in the past has just been the NGLs. We have not taken out the short gas position because that's covered by our E&P length. So, as a corporation, we've looked to our exposure; not to the individual business unit exposure. And so, the hedge that we had in place are the forward sale that we had on liquids actually fared pretty well for us in the third quarter, because it was gas prices lowering that actually made the difference there. So the liquids price that we sold was not that bad, because -- again as the gas price of the third quarter. In terms of our philosophy on it, we continue to look at the overall corporate exposure that we have and look for opportunities there. We also look for fundamentals that would signal us in terms of individual components, for instance, propane or ethane, and what we know about, what's in storage and so forth, and so we would look to fundamentals like that to make decisions. But we start with a corporate perspective on where we are exposed. Craig Shere - Calyon Securities: Great. Don, do you have any numbers on the tax rate as yet?

Just slide in the back of the package. On slide number 100 that gives both quarter as well as future-year guidance, effective tax-rate guidance is 39% 2007 and '08, as well as cash tax guidance 5% to 10% in '07 and 9% to 14% in '08. And are likely, kind of marginal effective rate is just a little below that 39% rate, in the 38.5. Craig Shere - Calyon Securities: Great thank you.

And our next question will come from Rick Gross with Lehman Brothers. Rick Gross - Lehman Brothers: Good morning. I just want to -- I guess, kind of refine some of the comments around the Piceance. From the standpoint of having 24 rigs operating in the third quarter, and you're going to operate the same number, I assume, in the fourth quarter, and add as you get rigs. You're stepping down from the Highlands, I assume, and redeploying the rigs in the Valley. Is that where the five rigs that aren't running in the Highlands, going to the Valley?

Yeah, there what we do is Rick we have them in the Valley, and then we'll move them up, when the Highlands drilling season opens, we'll move them up to the Highlands, drill as much as we can there. And then like with the weather gets bad and other things come into effect. For example, the third quarter…

Effect.

We were able to average almost eight. Basically, had eight rigs in the Highlands. And now we'll -- for the fourth quarter we'll be at three because we'll move those rigs back down to the Valley. Rick Gross - Lehman Brothers: Okay from the standpoint of moving forward, you have provided in the past, or we could kind of figure out, reverse-engineer, kind of the productivity of these rigs. Because we'd kind of get a well count. How many wells are you actually going to drill this year, in the Piceance, complete?

Counting both Highlands and the Valley, I believe, it's in the 475 range, plus or minus. Rick Gross - Lehman Brothers: Okay and then, the next couple of years?

The guidance at this point is in that same range. And we'll be refining that guidance as we move closer to the -- well, actually when we do the February call. Rick Gross - Lehman Brothers: Okay that's fine. From a standpoint of rig productivity, Highlands versus Valley, my assumption is that because you're drilling in essence extra rock, and you've got logistics issues. Is the productivity up there materially different than when you're drilling down in the Valley?

If you mean times of spud-to-spud, the Valley in general, it varies. But on average, let's just say that's about 15 days. And the Highlands can be anywhere from -- and we've done better and we've done slightly worse; it just depends. But the Highlands spud-to-spud time is more like 25 or 30 days. So you could say 15 days versus 30 days currently. And I think we, as you know, always try to improve both those numbers. And the biggest improvement would be hopefully in the Highlands; we would see that 30-day drop-down. Rick Gross - Lehman Brothers: Right Okay, from a standpoint of looking at -- oh Jesus, where did I go? From a standpoint of the restrictions up there, are the drilling restrictions in the winter environmental, or are they infrastructure?

Oh they're a little of both right now. There is -- infrastructure, clearly, has to be built. The winter can be very severe up there. We are building an employee camp in the Trail Ridge area that essentially would be somewhat like almost like an offshore camp, just a much smaller version of that. But it needs living quarters and all the things that would go with that. And then there's all kinds of animal stipulations and other things that we need to work through that we're working through. So, it's really a combination of both. Rick Gross - Lehman Brothers: Okay, completely different subject. Over on the power side, were there any further contracts signed during the quarter? Is there any information there to report?

Rick we did sign some 2007 capacity sales that we did not report on. So, I guess I shouldn't comment on them. But we are still continuing to have success, especially in the shorter term. Rick Gross - Lehman Brothers: Okay and then from a standpoint of capacity market development, California PJM, any update?

Well FERC did approve the California market design, which is a step in a positive direction. There are negotiations occurring that, I think, are moving in a positive direction in PJM. We would expect some developments in both areas middle to late 2007. Rick Gross - Lehman Brothers: Okay and then, there was a Vernon Hill, almost like right on top of Downtown L.A. project that's kind of running through the CEC right now. How would you handicap that getting through the process? And particularly they've got a startup date '09, '10?

Yeah, I would say there is the lot of hurdles, still to be overcome, with that project. I think it is a viable project. California desperately needs new megawatts. But given its location and given some other political issues, it's going to face, it's got a ways to go. Rick Gross - Lehman Brothers: From a standpoint -- if it's built, will that have -- will that hang because, as long as this is in limbo, will it hang up your ability to possibly contract some of your megawatts beyond '10?

No. I don't think so Rick. I think, as I indicated, California needs a lot of new megawatts. The utilities, I think are becoming more aggressive with looking beyond 2010, at existing generation as well as new. So, I really don't see it hampering us in any way. Rick Gross - Lehman Brothers: Thank you.

And that does conclude the question-and-answer session for today. I would like to turn the call back over to Steve Malcolm for any additional closing remarks.

Well again, thank you for your interest. We're very pleased with our results. We are excited about the future, and look forward to talking with you in the future. Thank you.

And that does conclude today's audio conference. Thank you for your participation. And have a nice day.