Travis Campbell - Head of IR Steve Malcolm - CEO Don Chappel - CFO Ralph Hill - SVP, E&P Alan Armstrong - SVP, Midstream Gas Phil Wright - SVP, Gas Pipeline Bill Hobbs - SVP, Power

Carl Kirst - Credit Suisse Shneur Gershuni - UBS Faisel Khan - Citigroup Sam Brothwell - Wachovia Gordon Howald - Calyon Sven Del Pozzo - John S. Herold Maureen Howe - RBC Capital Markets Margaret Jones - Citigroup Gary Stromberg - Lehman Brothers Peter Monaco - Tudor Investment Corporation

Good day everyone, and welcome to the Williams Companies Fourth 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 very much, and good morning everybody. Welcome to the Williams fourth quarter 2006 earnings call, and thank you for your interest in our company. As usual today, you'll hear from Steve Malcolm, our CEO; Don Chappel, our CFO; and also the heads of each of our business units will share highlights on their segments. That includes Ralph Hill, Alan Armstrong, Phil Wright, and Bill Hobbs. All of the slides and the details are available in the appendix to this presentation. So, any information that you've found valuable in the past is available for your use. Before I turn it over to Steve, please note that all the slides, both those in the presentation today and the appendix, are available on our website williams.com in a PDF format. One correction I do need to mention, you'll notice in the slide presentation today that our segment profit guidance for 2008 is $2.13 billion to $2.98 billion. The press release reflected our prior guidance, which was $2.2 billion to $2.88 billion. We'll be sending out a correction to that press release very quickly. The various press releases and the accompanying schedules for today are also available on the website. If you look at slide two and three, entitled "Forward-looking Statements" it details various risk factors and uncertainties related to future outcomes. Please review that information on those slides. On slide number 4, oil and gas reserves disclaimer. It's 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 integral to the presentation. They are also available on our website, williams.com. So with that, I will turn it over to Steve Malcolm, our Chairman.

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Thanks, Travis. Good morning and welcome to our fourth quarter conference call. We have our usual lineup today. We have lots of slides, but we will try to motor through them quickly, so that we have plenty of time for your questions. I'll review key headlines and accomplishments for 2006 and offer my view of some of the catalysts for creating value in 2007. Don Chappel will go through the financial review. You'll hear updates from our business unit leaders, and we'll be providing our earnings guidance. We're giving earnings guidance today for 2007 and 2008. And, our guidance reflects our expectation of continued significant volatility in commodity prices. You'll see today that even the range for our 2007 guidance is fairly wide. Again, this reflects our expectation for this significant volatility in commodity prices. We are providing the commodity assumptions embedded in our 2007 and 2008 earnings guidance to help you fine tune your own models. And just for your planning purposes, we should be talking about 3P reserves, when we release first quarter results in May. I would anticipate some window on 2009 expectations at the time we release second quarter earnings later this summer after we have completed our annual long-range planning exercise with our Board. If you would please turn to slide 6, this lists some of the major headlines associated with our performance during the fourth quarter and during all of 2006. No doubt, 2006 results were impressive for Williams. We are certainly pleased that recurring adjusted income was up 38% for the full year. Cash flow from operations rose 3%. Please recall last year at this time, we were providing a guidance range for 2006 between $0.78 and $1.03 per share. And so, the $1.17 recurring EPS that we've achieved represents a very strong year for Williams. And just going through the rest of these bullet points, we recorded extraordinary earnings in Midstream with margins about double the five-year average, which drove the segment profit up about 40% for the year. We continued our impressive track record in the E&P sector, as domestic production rose 23%, and production was replaced at a rate of 216%. We completed the dropdown in two phases of a large, significant $1.6 billion asset to WPZ during the year. Importantly, new higher rates are going into effect, subject to refund, on Transco and Northwest Pipeline. We saw an increased level of activity in power and we are delighted that with the SCE transaction, we were able to place megawatts in the marketplace beyond 2010. Our businesses were recognized in many ways during the year for their results, but we were particularly proud that our E&P operation received recognition as the Hydrocarbon Producer of the Year by Platts. And lastly, our discipline around investments in our energy portfolio has allowed shareholders to earn a 65% total return over the past eight quarters. Turning to slide 7. You have seen this slide before. A lot of information on it, but I think it captures our story very succinctly. We have positioned our company for near and long-term value creation. I won't go through each of these bullets, but we do have prime assets that are delivering growth. We are pursuing that growth with discipline, having adopted the EVA methodology. We've produced a solid record of delivering results, a 65% return to shareholders in the last six quarters. And a crisp execution around our game plan will drive value creation in the future. Turning to the next slide, slide 8. As I think about 2007, these appear to be the catalysts that I believe will drive our stock price during the year. Certainly, growth in segment profit, but as well growing our natural gas reserves and production will be important. Our new higher rates on Northwest and Transco, more megawatts contracted into the market post 2010, our ability to capture additional midstream projects, and we have talked about the significant pipeline of projects that we are pursuing. And, more potential dropdowns to Williams Partners. I think, importantly, we have already seen, some great progress on these items in 2007, excellent metrics with respect to reserves and production, apparent settlement of the Northwest Pipeline rate case, and more megawatts moving into the market beyond 2010 as a result of the SCE deal. So, we're delighted with our results in 2006. We're very pleased with our progress already in 2007. And with that I will turn it over to Don Chappel.

Thanks Steve, good morning. I will quickly run through the highlights of our fourth quarter and 2006 full year results, which are analyzed in more detail in our press release, and will be analyzed in much more detail in our 10-K, which we will file next week. Please turn to slide number 10. Just a few comments; we're very pleased with our continued improvement and strong performance for both the fourth quarter and 2006. As you know, our GAAP results include certain non-recurring items and the effects of prior and some current mark-to-market accounting related to our power business and that's principally non-cash. As such, we eliminate, in our analysis for our own management review as well as for your review, these non-recurring items and the cumulative mark-to-market effects to provide a much more clear picture of our results and true earnings power. Having said that I'll turn to net income. Obviously, for the fourth quarter, net income per share on a GAAP basis was $0.24. After we adjust for non-recurring items that total was $0.26 and after eliminating mark-to-market effects, it was $0.30. You can see that in the first column of this slide. And I'll focus on the bottom-line now. The comparison to 2005, the key measure is $0.30 as compared to $0.26 or up $0.04 or about 15% for the quarter. On a full year basis, again net income per share, reported GAAP, was $0.51. After eliminating non-recurring items we have an $0.86 result. However, again we have mark-to-market effects, which after elimination yield a $1.17 and compare very, very well as compared to the $0.86 in the previous year. That's an increase of $0.31 or about 38%. And I am going to walk through some of the details of our non-recurring items and mark-to-market adjustments in just a second here. Let's turn to slide number 11. I am just going to hit on some of the highlights here of the non-recurring items. We had again some litigation settlement totaling $7 million for the quarter and $260 million for the year with our security settlement in the Gulf Liquids litigation. Early debt retirement expenses totaled $31 million for the year, nothing in the current quarter. And then, we had an impairment related to a Venezuelan asset, related to a change in the regulatory environment as well as a change in the form of that investment, which caused an impairment, totaling $16 million. We also had some tax items that were non-recurring in nature. You can see there on the bottom of the slide. Add all that up, that yields the result that I just had previously indicated. Turning next to slide number 12. This is the mark-to-market adjustments related to our power business. Again, we reversed the forward unrealized mark-to-market gains and losses. We add back the realized gains from mark-to-market previously recorded, total that up, tax effect it, and that gives us the result. The total there would be a $22 million increase in the fourth quarter earnings as compared to a $14 million decrease in 2005, or a $36 million change quarter-over-quarter. And for the full year, $188 million after-tax being added back to the earnings, as compared to $85 million in the prior year, a swing of $103 million on a year-over-year basis. The next slide please, number 13, fourth quarter segment profit. We reflect this on both a reported and a recurring basis by BU and consolidated with mark-to-market effects. I'll focus on the bold total segment profit after mark-to-market adjustments of $407 million as compared to $448 million, down $41 million over a year ago. And I think the big story there is E&P and Gas Pipelines were down somewhat, and Midstream up sharply. And, I'll talk a little bit more about that in just a second. E&P increased its domestic production 28% and consolidated production 26%. However, prices were sharply lower than the fourth quarter '05, a period which immediately followed the 2005 hurricanes. Domestic average realized prices were off $1.20 per Mcfe or 21%, and the effects of the price decline offset this 26% production increase. Additionally, operating costs were higher, about $0.12 per Mcfe. The Midstream incredibly strong results were principally driven by sharply higher NGL unit margins, totaling $78 million due to lower natural gas costs and higher volumes caused by periods of ethane rejection, and fee revenue increases totaling $13 million. Offsetting these increases were operating expense increases totaling $28 million. Gas Pipeline recurring results were lower due to cost increases. As you know, we filed a rate case to recover cost increases and new higher rates went into effect at Northwest Pipe on January 1st and will go into effect on Transco, effective 03/01/07, subject to refund. And, Phil will have a few more words on that subject in a few minutes. Power GAAP results include the mark-to-market effects. Excluding mark-to-market effects, Power was about breakeven in both the fourth quarter of '06 and '05. Turn to the next slide please, number 14. We'll take a look at full year results. Again looking at our key earnings measures, segment profit after mark-to-market, $1.837 billion as compared to $1.578 billion, up $259 million or about 16%. Again E&P, domestic production volumes increased 23% and consolidated volumes were up 21% over 2005.However, 2006 domestic average net realized prices were lower, $0.29 lower per Mcf, or about 6%, and costs were higher at $0.11 per Mcf higher. Midstream's record results were principally driven by record NGL margins which were up $242 million, or $0.17 per gallon from 2005 levels. Additionally, fee revenues were $80 million higher, driven by increased volumes from Triton and Goldfinger deepwater projects, higher unit production revenues from Devils Tower, and high fee revenues in the West. Olefins contributed an additional $24 million in higher margins. Operating expenses increased $85 million, due to a variety of factors, and marketing margins were down $25 million. Gas Pipeline 2006 results were lower, as costs increased. And again, those costs were included in our rate filings. Power results were up sharply as a result of improved markets and deals that were realized. I would also note that Power cash flows, as detailed on slide number 96 in the appendix, totaled $93 million for the Power segment. With that, let's turn it to Ralph Hill.

Thank you Don. I am on slide 16. I'm pleased to share today with you primarily three main things. First, talk about the strong operating quarter we had. Second, detail you our reserve replacement performance again, which we think was very strong, and our outlook for what we hope is an even better 2007. Moving to slide 17, some of these Don has touched on. And, I have some slides that will also detail a few of these out in more detail in just a few minutes. But basically, our volumes were up 21% this year. Last year, meaning '05's performance, they were up 17%. So, we were able to grow our volumes at a higher rate, if you will, 21% over even a larger base. The reserve replacement, I have a slide on that I'll talk about. Our volumes were up $180 million or more since the fourth quarter of 2005. I have a slide that talks about Powder River, but that continues to do very well for us, and we are very pleased with our new partner in Powder River. I have an update on the Barcus Creek farm-in. We have expanded our Barnett Shale position and are now running three rigs in the Barnett Shale. And we did win two awards, as Steve talked about, which I am very proud of the team for which, is the Oil and Gas Investor's Best Field Rejuvenation and also the Global Energy Awards. We were named the 2006 Hydrocarbon Producer of the Year. Turning to slide 18, this just details by quarter as we've done each quarter. Our domestic production growth of 23%, and I'll just leave it at that. You can see, obviously, very strong and we expect to continue very strong performance going forward. Slide 19, turning more into the Piceance, production is up $126 million or 37% over a year ago. We do now have 25 rigs operating in the Piceance, compared to this time last year. We had about 19. We did get our tenth H&P rig in at the very end of December and it spud at the end of December. So, all 10 rigs are in operation. We have four Nabors rigs scheduled coming in, one in March, one in April, and two in May. And as I mentioned before, as we get these purpose-built rigs, we will have the ability to continue, and we already have started high-grading our fleet. And one other thing is we were awarded the first ever Piceance year-round drilling pilot by the BLM and Department of Wildlife. We think that's a win-win for everybody. It allows us to go to federal acreage and get in there with these new purpose-built rigs and basically finish it up in a quicker and more efficient method, less pads built and also less disturbance and ultimately reclaim the land that much quicker. So we are anxious to have that pilot to be successful, and we believe it will. And we appreciate working with the BLM and the DOW on that. And finally, in the Piceance just to recall, last year at this time we were hoping to be able to do what we called SimOps, which is simultaneous operations. And that did work, it works very well. So, we think on the land side of the world, we are the first company to be able to successfully frac, perforate, drill and produce and have all those operations going on in the same drill pad at the same time. And that has obviously helped us as we move forward. Looking at slide 20 the Piceance Highlands, that momentum does continue. We spud 43 wells in 2006. We are looking for about a 50% increase in that in 2007. Our current production is up from $15 million a year ago to $26 million. And we continue to do a major amount of work on roads, pipeline and facilities to make sure we can access this vast resource we believe we have, in a very efficient way. So a lot of work is going on there and we are actually getting very close to finishing a lot of that work. We were able to get a winter drilling pilot underway, and this is a little different than the valley. This is not regulatory driven, but this is just physically being capable of drilling in harsh winter conditions and much higher altitude. We have built our camp for our employees and vendors to stay at. We have our transportation built, our roads built and our roads are almost finalized, but we are in the process of doing winter round drilling at Trail Ridge. And our pilot is to have eight wells drilled during this winter, to make sure it works the way we think it will be and hopefully that allows to do additional work in the future going forward. Slide 21, Powder River production growth. Again the Big George is the story here. Its increase is vastly overcoming the Wyodak decline. Our production is up 36 million a day on a net basis or 30% over a year ago. And Big George itself is up 88% and our sequential quarter volumes on Big George are up 15%. So the Big George continues to do very well for us, it's what we thought. Again, we are thankful to have our new partner in there and they are managing their business the way we do. We think that will allow more volumes to come on in the future. For 2007, lots of time, questions come up about permitting and how we would be looking for this year's permits. And we're about 70% or more done with our permitting for this year's drilling budget, which is where we usually are at this time of the year. So we feel very good about that. Slide 22, 2006 cost performance. We don't have all the data in from all of our competitors. So in the May call, like I did last year, I'll give more comparisons. But we do believe we continue to be in the top quartile on our performances. Our LOE expense is $0.46 per Mcf. Just to clarify a couple of things on the Investor Relations schedule, which we call the Analyst Package, it details the E&P operating statistics, which reflects LOE and what we call other operating expenses. In that it shows that this year, meaning 2006, it's $0.58 versus a 2005 rate of $0.47. But as I mentioned before, there were some 2005 expenses that were recorded in '06. So, if you actually adjust that to the year incurred, our actual 2006 rate is about $0.5509 versus the '05 rate which would be adjusted to $0.4908. So it's really $0.4908 versus $0.5509, which shows about a 12% increase and not a 23% which is on that chart. Therefore, we think that 12% is very competitive with the industry and it should be a top quartile performance. And it shows that our employees continue to manage their business in a very competitive market. Our three-year F&D is $1.55 per Mcf, and again we'd like to look at it on a three-year basis and our DD&A is $1.28. So we'll have more comparisons for this as we get a lot of the industry data, but we believe we will remain in the top quartile performance and cost performance. Slide 23, reserves, which were announced this morning also. Our proved reserves were up approximately 10% or 9.5% to 3.7 Tcfe. Total U.S. and International reserves were 3.9 Tcfe. Again, we had our fourth consecutive year of over 200% domestic reserves replacement. This year it was 216%. And our 99% drilling success rate continues for, I believe the fourth or fifth year in a row. And in 2006, we had 1,770 successful wells, which were drilled out of a total of 1,783 wells. So, it's a 99.3% success rate. And we were able to add 590 Bcfe to proved. If you look at just pure probable to proved transfers, over the last three years we've transferred about 1.6 Tcfe through our drilling activity from the probable category to the proved. In addition to moving this 1.6 Tcfe of probable to proved, our PDP, as a percentage of the total, continues to increase and is now up to 53%. Last year our PDP as a percent of the total was about 49%. So, we continue to convert our probable to proved, and we are also increasing our productive capacity as our PDP percentage continues to increase also. Slide 24 shows the flying bricks, as we call it, the build-up to get to the 3.7 Tcfe domestic. I won't go into all the numbers there, but you can see we did have a slight bit of acquisitions, primarily in the Barnett of 40 Bcf; additions/revisions, 557 Bcf; and obviously our production is 277. That translates into 3.701 Tcfe, which again gives us the opportunity to have the 216% reserve replacement rate. Slide 25, cash margin analysis. This is a two-year average, as we are giving guidance now. 2006 has dropped off. First, as you look at this slide, when you look at the realized gas price assumption, the price increase is reflected on that. It's not really an increase in our price assumption, but it's 2006 dropping off. And also, once 2006 drops offs, which has a little bit lower price than what we project for '07 and '08, and had more hedges at much lower prices that increases our realized gas price assumption. Again, it's not an increase in our price assumption. It's just the way the math works out. You take the $6.04 and from that we would deduct the following items, which are included in the cash costs. LOE, FOE and other, kind of a catch-all expense item is $0.66. That includes all of our expenses gathering about $0.46, operating tax is $0.48 and SG&A about $0.37 on a fully loaded basis. That gives us our cash margin of $4.08. So, this obviously remains a very profitable business. Another way to look at that is the $4.08, take about $1.50 or so DD&A rate off of that and you can see, obviously that would be your profit line, which is about $2.50 or so on a profit basis. And looking purely at cash, we are paying about $1.55 on our F&D costs to get this $4.08 type cash margin. We've shown this slide before. So, I won't go in any more detail. But you can see our margins remain very strong. Looking at slide 26, our guidance updates. Most of these increases we experienced in 2006. So, really what we are doing is carrying forward our increases we had in 2006 into this 2007 and 2008 timeframe. First of all, if you look at increased costs and facilities in 2007, it's $90 million. About $20 million to $30 million of that is for facilities. And recall, our production continues to increase rapidly more than we even thought in the Piceance, and also there is a very long lead time in facilities. So, what we are doing is accelerating our facilities into this year and also add more production, and there is some cost pressure on the facilities side. And that's for compression gathering and obviously the plants that we've been building. Then if you look at that on a cost basis, really just the straight-up costs, they were up on a CapEx side about 5% to 7% during the year, and we are basically carrying that forward into 2007. So, that's the difference in the guidance update that makes the $90 million. Fort Worth, as I mentioned, we had one to two in the plan. We are now running three rigs. We have about 20,000 net acres there, about $33 million a day of gross production. So, we are enjoying some success there. So, we've added some opportunities and some additional drilling there. And then other opportunities, which I think will ultimately to even a greater future or things such as Barcus Creek, and Paradox and other areas where we have some activity going. And they expose us to multi-Tcfe potential on down the road assuming they would be successful. The key for us is those two, the Fort Worth and other opportunities they are really not impacting our current profits. So thus our profit guidance is not up. But they will impact, we believe, longer range segment profit. So, they don't impact enough in 2007-2008 at this time to revise our profit range, but they are enough to do up the capital range for that. But obviously, we believe those give us tremendous amount of opportunities going forward. And thus, hopefully longer-term guidance would also maybe able to be influenced by those if we are successful, and I have to stress that if we are successful. Looking at the bottom part, the segment profit guidance range. What we've done is we've widened our gas price assumptions, which are in the appendix, and also on the next slide, I can talk about that. So, that shows that the range is wider just because the gas prices have a wider range in 2007 at this time. Although, they do appear to be getting a little more bullish than they were in early January. And then increased operating expenses, once again, we are carrying forward what we experienced in 2006 and also the increased capital we spent in 2006 to accelerate production that's part of that. So basically we are seeing about half of that increases in our DD&A and half is in operating expenses. So that influences the range there as you can see. So we have seen cost increases, but our team continues to manage it very well on the CapEx side. On the drilling side, it's about 5% to 7%. And on the LOE cost, as you saw from last year, it was about a 12% increase. And we have carried that forward, meaning not really accelerated that too much for '07, but carried that increase going forward. Slide 27 that just leads to our guidance slide. I won't walk you through this, but this leads to the changes we have. Obviously wider price range, for example, the NYMEX price range we have in this is more like $7 to $8.30 range. I think previously we had like $7 and some odd cent range. Basin prices depend on location. We have a $5.10 to $7.40 type basin range. So very wide ranges and thus, the wide range in profitability. One key that's not on this slide is, if you look at these ranges and you compare them to 2006 results, we really have a very optimistic outlook in the sense of aggressive outlook for this year, that with legacy hedges going away and our production continue to incline. If you compare our Point estimate for 2006 or well I guess that would be our actual result to these ranges, you can see that the profit range would be between 27% to 77% increase and that obviously depends a lot on the gas price assumptions. And our production range would be increased between 13% to 25%. So we believe will continue to have very strong performance in '07. Finally, slide 28. It is important just to summarize, we did have a greater than 200% reserve replacement. Our success rate was 99%. We continue to be blessed with the long-term inventory. We are adding to that inventory with the new projects that we are doing. We believe we will add to that. And, I think it is very important that I end with, the outside world is recognizing and validating what we believe the true strength we have is in our employees, who work in this asset and work in the E&P side for us. They are managing this vast portfolio, and it's nice to see the outside world has given us some awards in terms of the Oil and Gas Investor Best Field Rejuvenation in San Juan and obviously the Hydrocarbon Producer of the Year at the Global Energy Awards. So I can't thanks our employees enough for a very good and strong 2006. Thank you. And, I will now turn over to Alan Armstrong.

Thanks Ralph. Midstream had a great year by about any measure. We will start off here on slide 30 and highlight our 2006 accomplishments. 2006 was a record year for profits. We generated $733 million in recurring segment profit. This was 55% increase over the previous record of $471 million in 2005. Certainly record unit margins were big part of the story. The recent all time high per unit margins as we have averaged about $0.33 per gallon, which doubled the 2002 through 2006 average of about $16.4 per gallon. Additionally across all the plants we operate, we set a new total liquids production record of almost 2.6 billion gallons in 2006. Our productive capacity in 2007 is even greater as our Cameron Meadows plant has now been fully restored and our new train at Opal kicks in this month. In any other year, the highlight would be our deepwater fee-based revenues which grew by 49% to $158 million from our 2005 level of $106 million. This increase was led primarily by our new volumes at our Devils Tower infrastructure in the Eastern Gulf of Mexico. We are also very excited about how well our new MLP performed in a low cost of capital, we now have available to grow our Midstream business. As we stated previously, this low cost of capital is critical to our strategy of operating large scale and reliable infrastructures in these basins that are continuing to grow for us. Turning now to the growth picture for Midstream, we continue to have great expectations for our deepwater expansion programs. Our Tahiti, Blind Faith, and Perdido Norte projects are all in various stages of planning and construction. In fact, Pipeline for discoveries extension to Chevron's Tahiti prospect out in 4400 feet of water began just last week and our investment in deepwater assets is now roughly $1 billion. When these three projects are completed, we will have approximately $1.7 billion invested in the deepwater infrastructure. Our Western expansion efforts began with the purchase of Opal TXP-IV in the first quarter of 2006 and also our breaking ground on our fifth train at Opal was also in the first quarter of '06. Today, we are happy to announce that on February 17, 2007, we placed Opal TXP-V in service. And at our midpoint commodity price assumption, we anticipate nearly $50 million in segment profit from the first full calendar year of operating this fifth train. Probably one of the highest value transactions that we did in 2006, however, was the development of Overland Pas Pipeline project, which will provide roughly $20 million per year of tariff savings when this project starts up in 2008. And, we will likely see even greater net backs for liquids as we gain access to both Conway and Mount Belleview markets for the same rate. Turn now to slide 31. As we just discussed, these large deepwater projects are dominating the expansion capital that we currently have in guidance for '07 and 08. Additionally, we have capital spending lining down on our Opal TXP-V project, but we are installing quite a bit of new compression in Wyoming and Four Corners that is trying to keep up with the robust drilling environment that we're seeing out west. Looking to this middle pie chart, we have some exciting opportunities we're closing in on in this area as well. One of the more interesting opportunities is the establishment of a Deep Cut Gas processing facility in the Piceance Basin. Our E&P Group has established significant infrastructure to service Piceance's position. It now makes sense to leverage off of this and establish a midstream presence to extract the higher valued liquids, and to aggressively expand this footprint to provide third party services to the multitude of new production developments in this expansive basin. This opportunity brings Williams businesses together in a truly integrated solution to develop the reserves in the Piceance Basin. And it also allows us to bring the full suite of Midstream services that we know how to deliver for these rapidly expanding basins. You will also note in the emergency opportunity pie chart over on the left, is a slice labeled Canadian Oilsands. Canadian Oilsands is another area that provides tremendous growth potential via the processing of oilsands off-gas. There are currently nine announced off-gas generating upgraders that could collectively generate from about $200 million to over $1.2 billion of the NGL from product value annually by 2020. So we see this as a very long-term opportunity for us. But tremendous amount of growth and as you are all very aware, very limited declines on the extraction of those oilsands. We're extremely well-positioned to take advantage of this growth at our Fort McMurray facility, is located in the heart of the oilsands country and is the only facility of its kind currently operating in this exciting region. Turning on to slide 32. This slide will look familiar to many of you. However, we have changed it just a little bit. The main message remains that we continue to generate very strong free cash flows and attractive returns under a wide range of commodity price assumptions. As before, segment profit plus DD&A is stated on a recurring basis with both capital expenditures and segment profit components shown at the midpoint of their respective guidance ranges. The midpoint of our guidance for segment profit plus DD&A for '07 and '08 is shown by the height of the solid blue bar. And the zebra strike boxes that you see just above that, on top of the blue bar represent the difference between the midpoint and the high end of our guidance range. This high end of the guidance range assumes a recurrence of exactly the commodity pricings that we saw in 2006. Relative to the attractive returns, you need to know that this $934 million recurring segment profit plus DD&A that we generated in '06 came from only $3.3 billion in net PP&E and long-term investments. You can do the math, but under just about any return measure you choose to employ here, these are very attractive returns. And the strong returns and free cash flows continue in '07 and '08, even with the lower projected NGL margins and heavy investment period as we aggressively expand our footprint in the deepwater. Move to the closing slide now and key points on slide 33. Midstream certainly has enjoyed the benefits of record NGL margins and very strong production volumes in 2006. Under historically typical crude-to-gas price relationships, Midstream's margins cushion the impact of lower gas prices on the rest of our enterprise. That was certainly the case in 2006. However, even with a more moderate pricing assumption, this business generates very attractive financials. Midstream is well positioned for growth on a number of fronts, like the opportunities in the Western US as we've demonstrated with our rapid expansion of Opal and the Midstream opportunities that we are now pursuing in the Piceance Basin. The aggressive build-out of the key infrastructure that will serve the deepwater Gulf for years to come continues, and we intend to attract additional opportunities through being a highly reliable service provider in these basins. In a similar way our position in the Canadian Oilsands off-gas processing business, positions us for emerging basins or another emerging basin that we will serve there. The last year has demonstrated a new high watermark for NGL margins and of course highlights the challenge that we've got in developing profit guidance in this type of environment. So the low end of our guidance range for '07 and '08 are based on crude-to-gas ratios of about 7.4 and the upper end is based on crude-to-gas ratios of about 9.6, which as I stated earlier was exactly what we experienced in '06. But under either scenario, this is an attractive business generating attractive returns relative to its cost to capital and continued free cash flows. But what will really keep this business healthy in the long-term, is our organization's commitment and focus on providing our customers the most reliable service available. Thanks and with that I will turn it over to Phil Wright.

Thank you Alan, slide 35 please. Operationally and commercially 2006 was a great year with completion of our 26 inch capacity replacement project on time and within budget. Significant contract extensions on Northwest Pipeline and very importantly and as you may have noticed, the settlement of our Northwest rate case was certified by the Administrative Law Judge in the case to the full commission yesterday. On our Transco system, we continued to serve growth in our customers' markets, as evidenced by the receipt of FERC approval for our Leidy to Long Island Expansion Project, execution of precedent agreements totaling 142,000 dekatherms a day with shippers on our Sentinel expansion. And in the first expansion beyond the initial design capacity of the system, we filed an application at the FERC for the Phase IV expansion of Gulf stream. Lastly, but certainly not least of these accomplishments is the even higher results we received from our customers on both Transco and Northwest, where we continued to be first in customer satisfaction. Slide 36, please. I am very proud of our team and most appreciative of the spirit of collaboration among our customers in reaching the recently certified settlement of our Northwest Pipeline rate case. The quick resolution of the case is a testament to a quality customer relationship. We certainly believe the overall settlement provides Northwest a fair and acceptable return. But just as importantly, our customers and other interested parties involved in the negotiations agreed that it was fair resolution of all the issues in the case. Furthermore, it will provide our customers rate certainty for the next few years. I think the fact that we reached a settlement on an expedited basis will serve us all well. This is the first rate case that Northwest has filed in 10 years, which is due to the fact that Northwest has worked diligently to manage its costs. The settlement was negotiated on what is called in rate case parlance, a "Black Box" basis. And therefore, most of the assumptions including rate of return were not identified. Next slide please. Our maintenance capital expenditure projections remain unchanged from prior guidance. Changes to our expected expenditures for major growth projects include, an increase in the cost of our Parachute Lateral due to terrible weather, tightness in contract availability and late receipts of some key permits. The total estimated cost is now pegged at $86 million. We've shifted some expenditures on Sentinel from 2008 to 2009 to match the phasing of the project. And we have decided to postpone applying for a certificate to construct the Greasewood Lateral project. Northwest will continue to work with potential shippers, who may be interested in capacity on the proposed lateral. If in the future we decide to move forward with the project and seek certification to construct for a later end-service date, we will post such a decision on the Northwest Pipeline company website. But for purposes planning, we will be pulling that project out of this range of guidance. Next slide please. This map shows where we are on previously announced growth projects. In the Northwest, at our Jackson Prairie storage field where we are a one-third owner in the facility near Chehalis, Washington, we have an incremental firm storage capacity expansion underway. You probably saw where the open season on the Pacific Connector project will close on March 1st. As I mentioned, to facilitate movement of Exploration and Production's, gas out of the Piceance Basin, the Parachute Lateral project is well on its way to completion. As we continue to support growth in our customers' markets along Transco and Gulfstream, we enjoy terrific growth projects. The Leidy to Long Island expansion project has been approved for start-up construction, and the Potomac expansion of 165,000 dekatherms a day beginning to be constructed in November 2007. We signed seven separate precedent agreements with shippers totaling a 142,000 dekatherms a day for our Sentinel expansion. As I previously mentioned, we've got great expansions, both well on their way and in the final phases of kick-off of construction on Gulfstream. Last slide please. So, again, a strong year operationally and commercially in 2006, with the completion of the 26 inch capacity replacement project on time and within budget. Excellent growth projects progressing with in service dates approaching. And a resurgence in segment profit and free cash flow generation for the Williams' portfolio being supported by our new rate cases and lower capital expenditures. Finally, the strength of our performance was recognized at the Global Energy Awards, where we were a finalist for Energy Transporter of the Year. With that, I'll turn it over to Bill Hobbs.

Thanks, Phil. We are now on slide 41. We had a strong 2006, and I am proud of our employees for the effort that they delivered. We did deals across all of our power regions creating about $120 million of cash flow certainty. Our financial results improved $87 million year-over-year. We were also successful in contracting with both power and natural gas customers. And we continue to focus on a high level of service for our Midstream and E&P businesses. 2006 also represented the fourth consecutive year of positive cash flow out of Power business. We continue to see the market fundamentals improve. Market liquidity, market participants, and our own credit in the market continues to improve. And as you heard about Ralph's growing E&P business, we are now marking over Bcf a day of equity in third-party production. Turning our attention to 2007, on slide 42, we are off to a great start. As Steve indicated, we have cracked the 2010 barrier with our sales to So Cal Edison in the West. We are currently sold out through 2010 of our capacity, which we view as a positive, given the still uncertain regulatory environment that you see in California. And we have sold 60% of our capacity in 2011. But also in the Northeast, we continue to be very active and very successful. We also made our first sales beyond 2010 in PJM. The PJM market, the capacity market, continues to improve, and you are seeing higher capacity values across the board in PJM. And the way we have structured our sales, we still have energy spark spread upside in the future. As the market continues to unfold, I do expect that we will be coming back to you before the end of the year with additional sales beyond 2010. Slide 43 is a recap and shows in effect the success of our strategy we have had since 2002 and also the great start we are off to in 2003. As the title indicates, already alone in 2007, the first two months of the year, we have created $250 million of additional cash flow certainty, which is double what we created throughout the entire year in 2006. So in summary, we had a great 2006. We are off to a great start in 2007. And as I indicated, I expect to be back to you before the year is over with additional sales beyond 2010. With that, I will turn it back to Don.

Thank you, Bill. Let's turn to slide number 45. Our 2007 forecast guidance. Our 2007 guidance range is wide as Steve indicated, principally as a result of volatility in energy prices. During the last year, as you know, we have seen a wide variety of prices for NGLs, natural gas and oil. And oil certainly has an effect on both NGL and natural gas prices. Nonetheless, we do believe that prices and margins will continue to remain attractive over the long term such that our investments continue to return very attractive rates of return, as well as provide us with additional attractive opportunities for investment. Just as a point of reference, the 2006 average WTI crude oil price was about $66, and we earned $1.17 on a recurring basis adjusted for mark-to-market effects. Our guidance ranges assume that oil prices will range between about $53 and $73 with the midpoint in the mid-60s. We also assume that NGL prices will continue to correlate closely with oil. Natural gas prices are less of a factor due to financial hedges and offsetting exposures in our E&P and Midstream businesses. And we'll talk more about that in just a moment, as well as some other assumptions. With that, let's turn to slide next, number to 46. 2007 to 2008 segment profit. This slide summarizes what you have heard from each of our business unit leaders, and also gives you consolidated total. As you can see, the $1.9 billion to$2.4 billion total for 2007, is up from 2006, and by 2008, our estimate is $2.125 billion to $2.975 billion. The midpoint increase is about $400 million or 19%. Turning the slide to number 47, please. This summarizes our change in segment profit forecast since the November call. As you can see there, we had a reduction in the mid-point of our NGL margins of about $25 million and again, as we saw some softness in oil and some additional costs that Ralph went through in his discussion of E&P. The next slide please, number 48. This is a summary of our commodity price assumptions. Ralph highlighted some of these. But you can see in the natural gas area. Basin prices in the Rockies are between $5.10 and $6.40, both in 2007 and 2008. And in the San Juan and Mid-Continent area, again averaging for the year between $6.10 and $7.40 in both the years. The NYMEX price is provided for reference only, but we actually build our forecast based on our forecast of basin prices. Midstream, as Alan mentioned, would assume crude oil to natural gas, that's WTI crude to Henry Hub of 7.4 to 9.6 times. And again in 2006, we experienced that 9.6 times. And again, the crude oil is a reference because it has an impact on other prices. The next slide please, number 49. It is just an update on our hedges. We have had added some additional hedges since we last reported to you and they were in the form of collars at the Basin. But as you can see here, we have a substantial amount of volume hedged both in 2007 and 2008. An upcoming slide will show you how significant that is. I'd also note that we are still burdened by the legacy fixed price hedges at the basin. The first one on the slide, which were put in place back in the 2002 and prior periods where we had a 172 million a day at $3.90 in '07 and 73 million a day at $3.96 in 2008, as well, we're disclosing in the footnote that the only additional remaining legacy hedges are in 2009 and 2010 and none thereafter. But the 2009 volume actually increases to 129 million a day and the price declines to 3.67. And then in 2010, it's 70 million a day at 3.73. So, we wanted to provide that for your reference. And again these legacy hedges expire at the end of 2010. The next slide please, number 50. This is just the graphical depiction of our natural gas exposure. The top of the bar here, at nearly 750 million a day is the net E&P production. And as you can see in the gold area, that's the amount of production that's hedged, and the blue area would be the unhedged E&P production. The purplish area below the zero line would be the amount of fuel and shrink consumed by our Midstream business. And as you can see that fuel and shrink almost perfectly offsets the E&P unhedged production, and the net position, therefore is just slightly long, as depicted by the red line. By 2008, our E&P production increases once again and the financial hedges diminish somewhat. However, the Midstream fuel & shrink increases, as that business grows. So the offsetting position isn't as significant and the net position is long, just short of 250 million a day. But again, on our yearly Bcfe of gross production, the net natural gas exposure is reduced to about 250 million a day in 2008. The next slide please, number 51. Capital expenditures, again, this summarizes what the business unit leaders already spoke to. Note, the total CapEx, 2.225 billion to 2.425 billion, up a bit from our prior call as a result of some increasing investments as well as some increased costs. I would also note that we do expect capital expenditures to increase, as we continue to seize attractive, value-adding opportunities in our core businesses. And again, I think Ralph spoke to some of those opportunities. Alan outlined in some detail, some of those opportunities, as did Phil. The next slide provides some additional information. I will speak to cash flow from operations and operating free cash flow. Cash flow from operations, guidance is unchanged from our November guidance at $2 billion to $2.3 billion in '07 and $2.4 billion to about $2.8 billion in 2008. Being free cash flow remains negative in 2007, as a result of the very substantial growth CapEx, and by 2008, in this analysis, it turns positive. However, again I would caveat that we are pursuing substantial additional investment opportunities that we believe will continue to add value, very attractive rates of return, adding EVA, and we will continue to update you on those as we move forward. Good news here is we have MLP capital that can fund the great deal of these projects via dropdowns. Again, very attractive low cost MLP capital can be raised rather than Williams' equity capital to fund such investments. I would also note that this guidance does not assume any additional dropdowns of Midstream assets to WPZ. It's not to say that we don't intend to make such dropdowns, we've just not modeled that and we're not providing any guidance with respect to those dropdowns. The next slide, page 53, is an analysis of our cash balance through 2007. And you can see, we do have a very substantial cash balance plus, and additionally, a very substantial unused credit facility. The credit facility is used principally at this point to support our marginable hedging positions. But the cash available is above $1.9 billion of the total. Cash flow from operations will generate an additional $2 billion to $2.3 billion. Capital spending, as I indicated, $2.2 billion to $2.4 billion and growing, and if you back out the additional activity, we see here yields, an expected surplus in the $600 million to $700 million range. And again, we will consume a substantial amount of that with some additional growth opportunities and then we have some additional cash for general corporate purposes and we'll consider what the best use of that is when considering equity value and credit considerations. Slide number 54, just some key points. Again, we are very much focused on driving and enabling sustainable EVA growth and growth in shareholder value. The MLP is key to us and it continues to enable us to grow without issuing Williams' equity. That low-cost equity capital will fund much of our growth and the growing incentive distributions and GP value will create some nice uplift. We'll continue to focus on maintaining and/or improving our credit ratios and ratings. We think that's key, and particularly so, given our MLP dropdown strategy because WPZ will be in the market issuing debt as well as equity. And WPZ's debt ratings and the market's appetite for WPZ debt will be closely associated with Williams' credit as well. So we think it's important to maintain or improve our credit ratings and ratios in order to ensure that we have adequate capacity and attractive pricing of the debt capital markets, as well as with our bank facilities and alike. We'll continue to reduce risk in the Power segment as Bill outlined. We continue to be opportunity-rich as each of our business leaders have pointed out to you. With that, I'll turn it to Steve.

Thanks Don. Slide 56, we've looked at this before. But again, I want to assure you that our team will be intensely focused on these catalysts of value creation during 2007. And I encourage you to watch for our progress in these areas during the year. My last slide, slide 57, our portfolio of natural gas businesses is delivering strong results. There's no doubt about that. Again, we have premier assets that are opportunity-rich. We are pursuing growth with discipline. We have generated a solid record of results, and we are taking action to drive value creation in the future. So with that, we will be happy to take your questions.

Thank you. (Operator Instructions). We will go first to Carl Kirst of Credit Suisse. Carl Kirst - Credit Suisse: Hey good morning everybody and congratulations on a nice quarter certainly. If I can start actually on the E&P side Ralph, we got a little bit of cost creep coming in here. The first thing, as I just want to make sure I understand that the $150 million of the CapEx rise here in 2007, given that we have additional opportunity, we really shouldn't only be looking at that, half of that as far as capital efficiency slippage. Is that correct?

Yes, I think exactly. The Fort Worth is additional drilling, that's 30. New opportunities in areas that we talked about before, acreage personnel and additional acreage purchases, that's about $30 million, so that's $60 million of it. Then in the $90 million number, there's about $25 million or so that's actually facilities. The facilities do have some cost creep in it, but a lot of it is we continue to accelerate all our facilities because of the long lead times. So really, you're looking at about a $70 million to $80 million number, over about a $1.3 billion budget. So it is not a huge increase, but it is an increase, obviously, with just the scale of the numbers we have now. Carl Kirst - Credit Suisse: Sure. Perhaps maybe even more of my real question, if you can kind of step back and give me your sense of what you think the cost curve is going forward for, in particular, the Rockies E&P. I'm trying to look at in the context of basically flat CapEx guidance into 2008. It looks like the situation you guys are setting up is basically $1.3 billion, continuing into 2008, and yet generating EBITDA substantially greater than that, while still achieving double-digit production growth, which is a pretty strong metric. I'm trying to figure out how much risk there could be in that number, at least you perceive in that number, that that $1.3 billion could become $1.4 billion, $1.5 billion, $1.6 billion, so to speak.

Well, at this point we feel that we baked in the cost increase, we have to see. We are not anticipating '07 will be as high increases as we saw like in '05 and '06. The second thing is a lot of potential increase in CapEx would be from these new opportunities that would come in. So at this point, we feel we've got the increases baked in that we need to have baked in. Obviously, we continue to negotiate strongly with our vendors and others. But we do feel that we're at the right level at this point. An increase in cost would primarily be due to new activity. Carl Kirst - Credit Suisse: Okay. Then lastly on E&P. You're guiding us understandably to sort of three-year average F&D to smooth things out. The F&D in 2006 notably, obviously, higher than that. I don't know, can you sort of prognosticate here a little bit into 2007. I think the three-year F&D is clearly going to continue to rise, as it is for everyone. But is it possible that we could see a reversion in that $238 million back closer towards the three-year average? Or have we basically kind of reset a new baseline?

Well, a couple of things. I think one thing that's in there, and when you get to the one-year F&D, I think you mentioned $238 million or so. It's actually you take a couple hundred million dollars of facilities out. It's more like a $215 million. What we're seeing is obviously some of the years we had, three years ago, a low capital investments, a lot of downspacing, very low F&D. But obviously, that's part of the reality of what our costs were. Facilities drop, another reason, just to back up on your question a minute ago, 2008 has about probably $150 million less facility investment than 2007. So that's another reason why CapEx goes down. Or it goes down for facilities, but not necessarily for drilling. So that's back to your previous question. So I think, as we move forward, what we're seeing is our budget is fairly high, as you see, and it's a very strong budget, more than we're used to. You see our track record has been 500 Bcf to 600 Bcf a year of reserve adds, so that obviously increases the F&D side going forward, but still keeps us very competitive. There won't be years as we've seen in the past, we're primarily in '03 and '04 where we didn't have that bigger budget, we had a lot down spacing. Now going forward, we are down spacing additional reserves, but we are also spending a lot of capital now to increase their productive capacity. But a portion of our capital now is obviously spending on making the PUDs translate into PDPs. But we feel very good that we've been able to spend a lot of money on that, but in addition, spend enough money that will continue to add quite a bit of reserves. Carl Kirst - Credit Suisse: Great. So, just the less facility spending there, the goal is here to actually have a lower F&D in 2007?

Well, that would be, we will have less F&D in 2008, and I am sorry less facility in 2008 than 2007. So that would lower on the gross cost, absolutely. Carl Kirst - Credit Suisse: Great. And then last question I promise. Bill on the Power side, you have mentioned that we're hoping to get some more hedges beyond 2010, by end of year 2007. Can you help us out, that are we looking at slowly pushing out the end of low i.e., doing more deals in the 2011 and 2012, or is there the potential to take even a greater chunk down into, say for instance the team?

Yeah Carl. What we're seeing and I have talked in the past about the normal utility contracting cycle usually runs in three to five-year increments. So I think, with the utility sector largely, with the deals that we're looking at are going to stay in the 2010-2011-2012 timeframe. But the banks are starting to look a little bit further out. In that we're seeing numbers quoted now, especially in PJM, as far as 2013 or 2014. Also, some of the industry players who have taken capacity, like in some of the Northeast expansion projects, are looking for long-term supplies as far out as 2020. So we're certainly talking to people in all those time horizons. I'm optimistic that we're going to have success, but certainly they're competitive and we are not [buying or selling] our portfolio. So it's going to come down to price, ultimately. Carl Kirst - Credit Suisse: Great. Thanks and good luck.

Thank you. We will go next to Shneur Gershuni of UBS. Mr. Gershuni, please go ahead, your line is open. Shneur Gershuni - UBS: Can you hear me now?

Thank you. Please go ahead. Shneur Gershuni - UBS: Hi. Just had a quick question with respect to the Power contract that was signed today. In the past, you have put out disclosures in the back about cash flows with respect to the Power business and whatnot. I was wondering if you can tell us if the business in 2011 is set to be cash flow positive, just based on committed cash flows?

Well, if you look at the slide, which I believe is 43, it shows you the amount of hedged activity we have, which is still short of our demand payments. And the blue shaded area represents what our models would suggest. We're going to realize if we took all those megawatts into the market, which we are clearly not. We will continue to contract for sales in the 2011 and beyond timeframe. I think I'll just point out, the deals that we are doing, if you went back historically and you looked at some of our tutorials, the levels we're contracting at are either equal or higher to those levels we forecasted. So, to me, these sales, we're starting to realize do support the fact that we have been fairly spot-on, as far as our future cash flow forecast. Shneur Gershuni - UBS: Okay. That answers my question here and I can't pretty much ask the rest of my questions. So, thank you.

Thank you. We will go next to Faisel Khan of Citigroup. Faisel Khan - Citigroup: Good morning. The first question I have is on the pipeline side. If I go back in time and look at some of the costs and SG&A, they seem to be rising pretty steadily over the last eight quarters. And I know you have talked about this in the past, in terms of integrity costs and stuff like that. But going forward, how should those numbers be moving around?

I'll try to respond to that as best I can. I would say that, first of all, we don't want to mix up the G&A and necessarily the integrity costs. We have seen some increased A&G, increased labor and the like. But, as Don pointed out, had cost increases baked into our rate recovery. And so that's a way to think about that. Clearly, cost control is among the highest priorities we have in our business. So, we see nothing on the horizon that would cause us to think that there's any kind of trend here for sharply increasing A&G. Faisel Khan - Citigroup: What about reducing it? Are there opportunities, you think, over time to reduce SG&A?

Potentially, yes. Faisel Khan - Citigroup: And then, if I'm looking at the revenue requirement for Northwest, you said about $404 million. If I look back in time, it looks like that roughly in the FERC filings; we're at $320 million. So basically, the $80 million improvement in revenues, does that drop straight through to the bottom line? Is that the right way to look at it?

I don't think that would be an accurate way to look at it. It's not a one-for-one type of a relationship, Faisel. Faisel Khan - Citigroup: And then on the Power side. Basically, the deal that was announced today, basically that are capacity deals, is that right? You are basically selling capacity in the plants you currently contract at? Is that fair to say?

Actually, it's a resell of toll. Where basically, we had resold our tolling obligations to Southern California Edison. So it would include both capacity and energy. Faisel Khan - Citigroup: Capacity and energy. Okay. Is there any way to back into a capacity price, in terms of how you sold those 2 gigawatts of power? Is there any way to back into that?

Not really. Not unless for some reason, SCE has to disclose it publicly. Faisel Khan - Citigroup: Okay. Which 2 gigawatts of the AES 4000 plants, were these? Were these like the higher heat rate stuff, or was it kind of across the board?

No, it was a mix. A mix of the higher heat rates. In fact, I believe and I will confirm this. I think they took most of the higher heat rate units, and we still have, in 2011 the remaining capacity, I think, is more efficient units. Faisel Khan - Citigroup: What does this mean in terms of kind of having to be able to re-power some of those assets, over the long run?

That would be something we would assess independently. The sales we are making now are pretty existing megawatts we have. Clearly, California needs capacity. And that's something that if we are able to work through it with AES, we would be bringing it to Steve and Don to look at future re-powering rights that we have in California. Faisel Khan - Citigroup: Okay. And then in PJM, you said you sold 20% of your capacity there for, I think, the next year or two. What was the capacity price that you were able to sell some of that power at?

Again, we can't disclose what we sold, our pricing. But with the PJM market, it is an active capacity market. There's market participants that are out there. Basically it's run in the range of $110 to $150. Faisel Khan - Citigroup: Okay. And then on the MLP, is there additional cost in your corporate O&M from running that separate entity? Or is it fair to say that that's part of your general G&A? Has there been an additional expense of running that separate entity?

Faisel, there are additional costs. They are relatively modest. They are few million dollars a year, and they are included in the consolidated results. Faisel Khan - Citigroup: Okay. And when you raised that at the MLP that interest expense is consolidated in your overall corporate guidance, is that right?

That is correct. Faisel Khan - Citigroup: Okay. And then to the extent that you raised debt there, there might be timing issues in terms of how pay down debt at the C Corp, is that fair to say also?

Yes, it is. That is fair to say. Faisel Khan - Citigroup: Okay. And on the E&P side, I wonder if you could talk a little bit about the opportunities. You talked about previously, I guess, in the Paradox basin. What's going on there and what type of opportunities are you likely to see out of that position you have?

Well in the Paradox, we have drilled two exploratory wells and we are doing extensive core analysis. And after the core analysis on the first well, we have set casing and we are beginning testing and we are currently evaluating that results. And, we will do the same with the second well. So, obviously we have drilled two, have done a tremendous amount of core analysis, and felt good enough to get into set casing and begin testing to see what's out there. So that's the update on the Paradox. We have two more exploratory tests, we will drill in this year in the other parts of our acreage holding there. And then in the Barcus Creek, I believe we have drilled several wells. We are testing the first couple and we have a total counting last year that we spud. And this year, we will drill five wells in the Barcus Creek area this year to test that area. And that’s just north of Ryan Gulch. So those are primarily the areas that are affecting 2007, and we remain optimistic in those areas. Faisel Khan - Citigroup: Okay, great. Thanks for the time guys.

Thank you. We'll go next to Sam Brothwell of Wachovia. Sam Brothwell - Wachovia: Hi good morning. On the Power business, have your thoughts evolve at all strategically on what you might do in that longer term. I know you kind of address the possibility of re-powering. Are you thinking about possibly looking at selling that again, or increasing its profile within the corporation?

Sam, this is Steve. Our plans and strategies are unchanged from that we've had in mind since we brought the business back and decided to retain the business in the fall of 2004. We are not really seeking to expand our footprint. We are more all about reducing risks, maximizing cash, satisfying our existing customer commitments. And as you have seen here most recently pricing more megawatts into the marketplace beyond 2010. So I think that is a good summary of where we are with respect to the business today. Sam Brothwell - Wachovia: Do you think it could become more of a value generator over time?

I think that certainly we are beginning to see some uptick in people's perception of Power. In certain of the geographic areas where we have facilities, we have seen some excess capacity begin to be worked off. And we're seeing some people pay up for assets and so clearly, the overall feeling about the business appears to be improving. Sam Brothwell - Wachovia: Okay. Thank you very much.

Thank you. We'll go next to Gordon Howald of Calyon. Gordon Howald - Calyon: Hey guys, good morning. Most of the questions have been answered related to power. But regarding Midstream, certainly, it's possible that Midstream assets could continue to command today's higher multiples, but we all know markets are fickle. What sense of urgency, Steve, do you have or does Williams have for more dropdown transactions? You kind of alluded to it earlier, that some could be done. But could you provide a range of what you would anticipate in 2007? And would you at some point consider FERC-regulated pipelines for MLPs, once the tax issues at FERC are resolved?

With respect to Midstream, Gordon, I wouldn't in any way suggest that we have any sense of urgency. I think I would simply go back to what we've done. We did $1.6 billion last year. And what we have said is that we do have a significant inventory of assets, sufficient to support dropdowns in the $1 billion to $2 billion per year over the next few years. And really, that's all the guidance or all the comments that I have to offer today, with respect to the Midstream dropdowns. In terms of gas pipes, we continue to evaluate that issue, and are open-minded going forward. Gordon Howald - Calyon: Great. Thank you for that. And one other quick question on the H&P rigs, you got those 10 under contract. I think those are two-year contracts. How does it work in terms of rolling those contracts forward? And do you have a sense of what the costs could be for those rigs in 2008 and 2009, when those contracts come due?

No, I don't have a thought of that. They were three-year agreements from the time they started drilling, basically. So our first one, we just started drilling in, I think, January and February of last year, we have 2 years left on. And that last one spud in December, so we have three years left on that. We had first-mover advantage, and from what I can tell, what they are doing with the other subsequent flex rigs, our day rate is about $5,000 to $6,000 less per day than what we see competitively out there. And I think, moving forward, when these start to roll over, it depends on what the market is doing at that time. We just don't know. There's no locked-in price past there, but obviously we have the first, essentially, call, if you will, on keeping those rigs. Gordon Howald - Calyon: Great. That's it, and I appreciate that. Thanks guys.

Thank you. We will go next to Sven Del Pozzo of John S. Herold. Sven Del Pozzo - John S. Herold: Good morning gentlemen. Would you be able to tell me whether out of your 2007 production guidance, of 905 to 1,005 million cubic feet per day, how much of that is US?

Almost all US. Approximately 50 million to 60 million a day is international; the rest is US. Sven Del Pozzo - John S. Herold: Okay. And again, regarding day rates, I'm wondering, with the relatively recent influx of rigs into your fleet, I'm wondering how exposed your rig fleet might be to a prospective decline in day rates, considering the influx of new builds into the market in the third quarter and fourth quarter of 2007.

What I'm seeing is that the new builds that most people have contracted for, are much higher than the conventional rigs that are out there. As I mentioned, have a first-mover advantage that we are lower-priced on all of our new builds in I think most of the industry, if not all industry. So what you really see is as those new rigs come in, I think what happens in the drilling industry is actually the old rigs and there are some rigs out there built in the '40s and '50s they basically get retired. They just go away. So I don't see a huge decrease in rig rates going forward from the current levels that we see for new rigs. The good news for us is, if they would go down, they probably would only get down to about where we are already. So I think we already have that advantage. Sven Del Pozzo - John S. Herold: Okay. Alright, that's about it. Thanks.

Thank you.

Thank you. We will go next to Maureen Howe of RBC Capital Markets. Maureen Howe - RBC Capital Markets: Thanks very much and good morning. Ralph, I'm sorry to keep coming back to this issue. And I'm just looking for clarification regarding some of the statements you made with respect to answering a previous question. But on page 25 and, I guess, on 22, where you do set out the cost of production. In your cash costs, presumably the cash cost there is $1.81. So that's $0.46 of lease operating expense, and then the balance would be G&A taxes and gathering?

Yes. What it is, and that $1.96 cash cost, $0.46 was 2006 performance. So it's in that range, 50-some-cents for 2007 type. Then we add FOE, which is $0.10 to $0.12 and just other costs, accretion, rentals and those kinds of things all goes in. So the LOE/FOE/other category, in this case. And it's a little apples-to-oranges versus the earlier slide. It's like $0.66. Maureen Howe - RBC Capital Markets: Okay.

The gathering was $0.46, operating tax is $0.48, and then SG&A fully loaded including E&P and enterprise is $0.37. So, that adds to your $1.96 cash cost. Maureen Howe - RBC Capital Markets: And then the $1.55 which is the three-year average of F&D, but it would relate to 2007-2008 production because that money has already been invested.

That’s the way you look at it. And obviously it will change each year. But, yeah we really invested $1.55 to find this, and now we are producing it. So, that’s the way we look at that. Maureen Howe - RBC Capital Markets: And I might I have misheard you, so I am just wondering, I thought you have thrown out and again, in answer to a previous question, a $2.15 F&D number. But I am not sure if that’s right. Because then, I think you said that you expected F&D cost to decline going forward.

Well, I didn’t really predict going forward decline. But if you look at just one year, I think, just take our total capital divided by reserves that for '06 only, I think the one of the previous callers talked about $2.35 or $2.38. In that is included about $125 million of facilities in '06. So, if you take the facilities out, which I would, that makes one year F&D more like 2.15 or so. Maureen Howe - RBC Capital Markets: Okay.

What I have seen early comparisons in the industry, most F&D I have seen for one year is more like $3. Maureen Howe - RBC Capital Markets: Is that right, okay. So, this --

So, I think we are still advantaged at 2.15 rate or even say, well let's count everything all at 2.38. I am saying that we are well below the average of the one-year average. I think going forward; I think that our capital budget has been as you see $1.3 or $1.4 billion. Maureen Howe - RBC Capital Markets: Right.

Included in '07 is about $200 million of facilities and '08 it's only $65 million of facilities. So the CapEx looks like, it's going down, but a lot of that is just for the facilities as we try to get ahead of the game with facility, which has always been our strategy. So I think that lowers the overall F&D going forward, because we are not spending as much on facilities. But then pure drilling, it probably will stay in this range. Hopefully, we will continue to get better, more efficient, and driver it down a little bit. Maureen Howe - RBC Capital Markets: Okay. That's helpful. That clarifies that situation. Thanks for that. And now just moving to Power bill. On page 43, where you do again set out the cash flows going forward based on the contractual arrangement today. And you do say that cash flows do not include the natural gas portfolio. Can you give us an estimate of what the incremental cash might be, say using your forecast range of natural gas prices, what the top-up might be to that?

Well, really, Maureen, we are not really exposed to natural gas prices. Our natural gas business is primarily marketing E&P gas, which is just transfer pricing, buying, fueling strength for Alan's Midstream business, which is transfer pricing. Maureen Howe - RBC Capital Markets: Okay. So you don't have anything specifically in the Power portfolio that might be related to hedging, a spark spread position?

We certainly, if we are selling power, we are always buying gas, if it is just an outright power sale. The resellers toll, there is no need to purchase gas for it. Maureen Howe - RBC Capital Markets: Right. Right.

We do have some storage positions that are there, primarily again to support E&P, Midstream, and our Power business. But we are always looking to optimize those. But really our natural gas side of our business is tied closely to power, E&P, or Midstream. Maureen Howe - RBC Capital Markets: Okay. So I guess I am just confused by this note then. What exactly are you trying say in this note that these cash flows that you are showing here, the once that are contracted our basically the locked-in margin?

Yeah, we don’t use the term locked-in. We use the term hedge because in fact there is no perfect hedge. But the grey bars and the green bars you're seeing are the expected cash flows from the hedges that we have in place. Maureen Howe - RBC Capital Markets: Okay.

And then the blue bars which suggest, for instance, in California we still have megawatts available in 2011, as well as in the Northeast and our other regions, and the blue bar would represent what we believe the market value of those megawatts are worth. Maureen Howe - RBC Capital Markets: Okay. And then just one final question, it relates in part to the Power portfolio, but it's probably more of a question for Don. And that’s, in light of the transactions that you have undertaken on the Power side of the business, where do you think you are relative to your discussions with the credit rating agencies? And again is there any update on what it might take to get back to an investment grade credit rating?

I'm excited to have the next conversation with the ratings agencies on this subject. Obviously, they know about it. But we're hopeful that they view it to be a significant step forward. We think it's very significant, and we think that the prospects are for continued good news on the front of being able to hedge some Power cash flows, and we believe that should be a factor in our ratings. In terms of when and how much they will react, it's impossible to know. But we're hopeful that this helps to move the needle with them. Maureen Howe - RBC Capital Markets: Okay, thanks for that. Those were my questions.

Thank you, we'll go next to Margaret Jones, Citigroup. Margaret Jones - Citigroup: I may have missed it, but could you just repeat or tell us what you are planning to do with regard to debt retirement either with the cash that's extra over and above your requirements at this point in time or with future dropdowns to WPZ?

Okay. We have made no specific comments with respect to any plans for debt reduction. We have said in the past that from time-to-time we will likely from time to time, we will likely take some of the proceeds from dropdown transactions and reduce debt so the consolidated indebtedness does not go too high. Again, keeping a sharp eye on our credit metrics. So we will certainly be keeping a sharp eye on our credit metrics, and that will guide us as well as looking at other potential uses for that excess cash. Margaret Jones - Citigroup: So right now, there is no immediate intention to retire any debt ahead of the maturity date?

There's no plan, there's no announcement with respect to that. So it's options that we're considering. And again, we have some capital projects that are on the very near horizon here, in addition to what was built in the guidance. As our business unit leaders referenced. We'll take a look at those capital projects and determine how many of them and in what quantity capital will be required in the near term to fund those projects. And see what's left for further uses. Those uses could include debt reduction. Margaret Jones - Citigroup: Thank you very much.

Our next question is a follow-up from Carl Kirst, Credit Suisse. Carl Kirst - Credit Suisse: Yeah, thanks for the time everybody. Just actually a question for Steve. With respect to the international E&P operations, APCO Argentina and like Venezuela, what's changed there? Can you recap for us what the strategic merit is for being down there?

In Venezuela, we are delighted with the returns that we have seen relative to our investments there. It's difficult to conclude that those are core assets as you would view Midstream assets that we have in the US. However, the performance thus far has been very strong, and while at times the political situation there is challenging, thus far we have been able to successfully motor through those waters. In terms of APCO Argentina, as you know, we acquired that interest back when Williams acquired Northwest Energy, back in 1983. We have seen the value of our interest there grow significantly over the last few years. So we would see that investment as potential currency for us to perhaps do something in the future, either through a JV or otherwise. Carl Kirst - Credit Suisse: Fair enough. Thank you.

Thank you. We will return to Sven Del Pozzo of John S. Herold. Sven Del Pozzo - John S. Herold: Hello. Could you walk me through when do you and Anadarko plan to put in a water disposal system in the Big George to lower lifting costs at Big George?

Well, there's quite a bit of discussion going on. As you know, Anadarko already has a water line that takes some of the water out. We are in discussions with them about expanding that, running other lines and those things. But they are still just in the discussion stage. I can just say that we're very pleased to have them in there. They have taken the lead in that pipeline before we were partners, and I think it's working well for them. I also think that we will continue to do what we have been doing, which is build reservoirs, aeration, farming, discharging when allowed, which is allowed during part of the year, and that this water pipeline hopefully will give us a great alternative. And at this point, it's just getting through negotiations and discussion, and also the strategy of where we're drilling and where they are drilling. What they've done is they've taken the Western assets and found a number of stranded wells which we had been mentioning to Western for quite a while. Anadarko is laser-focused on getting those wells to where they are producing water, which ultimately leads to gas. So we appreciate that, and think that the water pipeline is a viable alternative. It's just a matter of finalizing where we are. Sven Del Pozzo - John S. Herold: So you'd both like to do it. It's just placement of the pipeline?

Well, I think it seems to be a good alternative. We have not come to the conclusion we are definitely doing on yet. But there is one out there. It looks like there is the opportunity to build spurs off of that one and/or do some looping. That would probably take care of some of the more problem areas we have, in terms of water disposal. So it's a great alternative that we're definitely evaluating closely. Sven Del Pozzo - John S. Herold: Okay. Thank you.

Thank you.

Thank you. We will go next to Gary Stromberg of Lehman Brothers. Gary Stromberg - Lehman Brothers: Hi. A question for Don. Don, just back to the ratings issues, is there any benefit at all to Williams or Williams Partners achieving an investment-grade rating? Is that a strategic goal for the management team?

I don't view it as a strategic goal. However, I think there are some benefits. The benefits include, obviously, lower borrowing costs, lower facility costs. Certainly with WPZ in particular, accessing the debt capital markets on a regular basis. Its access to those debt capital markets through all market conditions is substantially improved with improved credit, as well as the cost of that debt. So I think that's a factor. Additionally, if and when we return to investment-grade ratings, I think we will also be able to sharply reduce our cash position and redeploy that cash in a more productive fashion. So I think there's a number of benefits. However, I wouldn't view it to be strategic at this point, because we do currently have good access to the capital markets, I believe, because of our positive momentum and the fact the markets view us to be stronger than our rating. Gary Stromberg - Lehman Brothers: I would agree with that. Just on the Midstream business, what percentage of that cash flow in 2006 would you say was fee-based versus more floating?

Of that, probably the best way to measure that would be against the recurring segment profit plus DD&A, because otherwise, you get into a lot of allocations of cost. But of that $934 million, about $440 million of that was NGL-margin related. Gary Stromberg - Lehman Brothers: Okay. Great. Thank you very much.

Thank you. We will go next to Peter Monaco of Tudor Investment Corporation. Peter Monaco - Tudor Investment Corporation: Good morning. Thanks for your time. Not to beat a dead horse, but Don, could you drill down a little bit more what on you all believe to be the optimal capital structure for the firm, sort of down the road a bit, when presumably more of Power is hedged, when presumably E&P, CapEx levels off, etcetera, etcetera?

Here is a good question. I don't think I could provide any guidance, other than to point you at credit metrics that would provide us with strong BB to BBB credit. I think it's important, if we are BB, that we have a positive outlook, positive momentum. And I think it depends on your models. You referenced a number of scenarios there. So again, I think it would depend on the model, in terms of Power and the ratings agencies' views, the debt capital market's views and all. But we would want to be in a position that we could access the capital markets even during turbulent times in the market, and at costs that are affordable. Peter Monaco - Tudor Investment Corporation: Okay. I will follow-up separately maybe with some more specific questions. Thanks.

Thank you. That will conclude today's question-and-answer session. At this time, I would like to turn the conference back over for any additional or closing remarks.

Okay. This is Steve. Thank you very much for your interest in Williams. We are delighted with our results for 2006, very excited about the future. We look forward to talking with you in the future. Thank you.

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

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