威廉斯 (WMB) 2006 Q4 法說會逐字稿

Good day, everyone, and welcome to the Williams Companies fourth-quarter 2006 earnings conference call. Today's call is being recorded.

At this time, for opening remarks and introductions, I would like to turn to come 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. 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 detail 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 will 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 four, 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 the 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'll turn it over to Steve Malcolm, our Chairman.

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 will hear updates from our business unit leaders, and we will be providing 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're providing the commodity assumptions embedded in our 2007 and 2008 earnings guidance to help you fine-tune your own models.

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.

So if you would please turn to slide six, 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 30%. Please recall last year at this time, we were providing a guidance range for 2006 between $0.78 and $1.03 per share. So the $1.17 recurring EPS that we achieved represents a very strong year for Williams.

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 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 drop-down 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're delighted that we were able, with the SCE transaction, 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.

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 seven, 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're pursuing that growth with discipline, having adopted the EVA methodology. We have produced a solid record of delivering results -- a 65% return to shareholders the last six quarters -- and crisp execution around our game plan will drive value creation in the future.

Turning to the next slide, slide eight, 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're pursuing -- and more potential drop-downs 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 are delighted with our results in 2006. We are very pleased with our progress already in 2007.

With that, I'll turn it over to Don Chappel.

Thanks, Steve. Good morning. I'll quickly run through 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; 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 the 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 totals $0.26, and after eliminating mark-to-market effects, $0.30. You can see that in the first column of this slide.

I'll focus on the bottom line now, the comparison to 2005. The key measure is $0.30 as compared to that $0.26 or up $0.04 or about 15% for the quarter. On a full-year basis, again, net income per share, reported GAAP, $0.51. After eliminating non-recurring items, we'd have an $0.86 result. However, again, we have mark-to-market effects which, after elimination, yield $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%. I'm 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'm 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, $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. 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 adjustment 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 a 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. For the full year, $188 million after tax being added back to 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 total, 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. 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 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 2005, a period which immediately followed the 2005 hurricanes. Domestic average realized prices were off $1.20 per Mcf or 21%, and the effects of the price decline offset this 26% production increase. Additionally, operating costs were higher, about $0.12 per Mcf.

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 on Northwest Pipe on January 1st and will go into effect on Transco effective 3-1-07, 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 2006 and 2005.

Turn to the next slide, please, number 14. We will 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. 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'd 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'm on slide 16. I'm pleased to share today with you primarily three main themes -- 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 2005's performance, they were up 17%. So we were able to grow our volumes at a higher rate, if you will, 21%, over even an larger base.

The reserve replacement I have a slide on 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.

We did win two towards that Steve talked about, which I'm very proud of the team for, which is the Oil and Gas Investor Best Field Rejuvenation. 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 have done each quarter, our domestic production growth of 23%. 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 10th H&P rig in at the very end of December, and it spudded 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. As I mentioned before, as we get these new rigs in, these purpose-built rigs, we will have the ability to continue and we already have started high-grading our fleet.

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 is 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, more efficient method, less pads built and also less disturbance, and ultimately reclaim the land that much quicker. So we're anxious to have that pilot be successful, and we believe it will. We appreciate working with the BLM and the DOW on that.

Finally, in the Piceance, just to recall, the last year at this time, we were hoping to be able to do what we call 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 the move forward.

Looking at slide 20, the Piceance Highlands, that momentum does continue. We spudded 43 wells in 2006. We're looking for about a 50% increase in that in 2007. Our current production is up from $15 million a year ago to $26 million. 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 going on there, and we're 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 what is harsh winter conditions in this much higher altitude. We've 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 will allow us to do additional work in the future going forward.

Slide 21, Powder River production growth -- again, the Big George is the story here. It's 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. 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 times questions come up about permitting and how we are looking for this year's permits. We are about 70% or more done with our permitting for this year's drilling budget, which is where we usually are this time of year, so we feel very good about that.

Slide 22 -- 2006 cost performance. We don't have all the data in from all our competitors, so on 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 in our performances. Our LOE expense is $0.46 per Mcf.

Just to clarify a couple 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 was $0.58 versus a 2005 rate of $0.47.

But, as I mentioned before, there were some 2005 expenses that were recorded in 2006. So if you actually adjust that to the year incurred, our actual 2006 rate is about $0.559 versus the 2005 rate, which would be adjusted to $0.498. So it's really $0.498 versus $0.559, which shows about a 12% increase and not a 23%, which is on that chart. Therefore, we think that that 12% is very competitive with the industry, and should be a top-quartile performance, and shows that our employees continue to manage their business in a very competitive market.

Our three-year F&D is $1.55 per Mcf. Again, we like to look at it on a three-year basis, and our DD&A is $1.28. So we will have more comparisons for this as we get a lot of the industry data in, but we believe we will remain in top-quartile performance in cost performance.

Slide 23, reserves, which were announced this morning also -- our proved reserves are up approximately 10% or 9.5% to 3.7 trillion cubic feet. Total US international reserves are 3.9 T's. Again, we had our fourth consecutive year of over 200% domestic reserve replacement. This year, it was 216%. Our 99% drilling success rate continues for, I believe, the fourth or fifth year in a row.

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. We were able to add (technical difficulty) to proved. If you look at just pure probables to proved transfers, we are now -- the last three years, we have transferred about 1.6 trillion cubic feet through our drilling activity from the probable category to the proved.

In addition to moving this 1.6 Tcf of probables to proved, our PDP percent per 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 probs to proved, and we're also increasing our productive capacity, as our PDP percentage continues to increase also.

Slide 24 shows the flying bricks, as we call it, the buildup to get to the 3.7 Tcf domestic. I won't go into all the numbers there, but you can see we did have a slight bit acquisitions, primarily in the Barnett, of 40 Bcf; Additions/revisions, 557 Bcf; and obviously, our production is 277 Bcf. That translates into 3.701 Tcf, 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're 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 that's reflected on that is not really an increase in our prices assumption, but it's 2006 dropping off. Also, obviously, then, once 2006 drops off, which has a little bit lower price than what we project for 2007 and 2008 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.

If you take the $6.04, and from that we would deduct for the following items, which are included in the cash costs. LOE, FOE and other, kind of a catchall expense item, is $0.66 -- that includes all of our expenses; gathering, about $0.46; operating taxes, $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, the $4.08 -- take about $1.50 or so of 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 (technical difficulty). Looking purely at cash, we're paying about $1.55 on our F&D cost to get this $4.08 type cash margin.

I've shown this slide before, so I won't go into any more detail. But you can see our margins remain very strong.

Look at slide 26, our guidance updates, most of these increases we experienced in 2006. So really, what we're 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, the $90 million, about $20 million to $30 million of that is for facilities.

Recall, our production continues to increase rapidly, more than we even thought, in the Piceance. Also, there is a very long leadtime in facilities. So what we're doing is accelerating our facilities into this year and also add more production, and there's some cost pressure on the facilities side. That's for compression gathering and obviously the plants that we have been building.

Then, if you look at the -- on a cost basis, really, the straight-up costs, they were up on the CapEx side about 5% to 7% during the year. We're 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're enjoying some success there, so we've added some opportunities and some additional drilling there.

Then other opportunities, which I think will ultimately lead to even a greater future, are things such as Barcus Creek and Paradox and other areas where we have some activity going. They expose us to multi-Tcf potential on down the road, assuming they would be successful.

The key for us is those two, the Fort Worth and other opportunities -- they're really not impacting our current profits, so that's our profit guidance [is not up]. But they will impact, we believe, longer-range segment profit. So they don't impact enough in 2007 and 2008 at this time to revise our profit range, but they are enough that we do up the capital range for that. But obviously, we believe those give us a tremendous amount of opportunities going forward and thus, hopefully, longer-term guidance would hopefully be able to be influenced by those if we are successful, and I have to stress that's if we're successful.

Looking at the bottom parts of segment profit guidance range, what we've done is we've widened our gas prices assumptions, which are in the appendix, and also I have a 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.

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, as part of that. So basically, we're seeing about half of that increase is 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%. On the LOE costs, as you saw from last year, it was about at 12% increase, and we have carried that forward, meaning not really accelerated that too much for 2007 but carried that increase going forward.

Slide 27 -- that just leads to our guidance slide, and I won't walk you through this, but this leads to the changes we have. Obviously, a wider price range -- for example, the NYMEX price range we have in this is more like the $7.00 to $8.30 range. I think previously, we had like a $7-and-some-odd-cent range. Basin prices -- depending 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 continuing to climb, if you compare our point estimate for 2006 -- or I guess that would be our actual result -- to these ranges, you can see that the profit range would be between 27% to 70-some-percent increase, and that obviously depends a lot on the gas price assumption. Our production range would be increased between 13% to 25%, so we believe we will continue to have very strong performance in 2007.

Finally, slide 28 -- it is important to see that just to summarize, we did have a greater than 200% reserve replacement. Our success rate was 99%. We continue to be blessed with a long-term inventory. We're adding to that inventory with the new projects that we're doing. We believe we will add to that.

I think it's very important to end with that the outside world is recognizing and validating what we believe, that the true strength we have is in our employees working this asset and working the E&P side for us. They're 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 thank our employees enough for a very good and strong 2006.

Thank you, and I will now turn it over to Alan Armstrong.

Thanks, Ralph. Midstream had a great year by about any measure. We'll 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 a 55% increase over the previous record of $471 million in 2005.

Certainly, record unit margins were a big part of the story. We reached an all-time high for unit margins, as we averaged about $0.33 per gallon, which doubled the 2002 through 2006 average of about $0.164 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 revenue, 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're also very excited about how well our new MLP performed and the low cost of capital to have available to grow our Midstream business. As we have 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 4,400 foot 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. Also, our breaking ground on our fifth train at Opal was also in the first quarter of 2006. Today, we're happy to announce that on February 17, 2007, we placed Opal TXP-V in service, and at our midpoint commodity price assumptions, 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 the Overland Pass Pipeline project, which will provide roughly $20 million per year of tariff savings when this project starts up in 2008. We will likely see even greater net backs for our liquids as we gain access to both Conway and Mont Belvieu 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 2007 and 2008. Additionally, we have capital spending winding 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 are 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 serve its Piceance 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 expensive Basin.

This opportunity brings Williams business units together in a truly integrated solution to develop the reserves in the Piceance Basin. It also allows us to bring the full suite of Midstream services that we know how to deliver for these rapidly expanding basins.

You'll also note in the [emergency] opportunity pie chart over on the left is a slice labeled Canadian oil sands. Canadian oil sands is another area that provides tremendous growth potential, via the processing of oil sands off-gas. There are currently nine announced off-gas-generating operators that could collectively generate from about $200 million to over $1.2 billion of NGL oil from product value annually by 2020.

So we see this as a very good long-term opportunity for us, but a tremendous amount of growth, and as you are all very well aware, very limited declines on the extraction of those oil sands. We're extremely well-positioned to take advantage of this growth, as our Fort McMurray facility is located in the heart of the oil sands 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 2007 and 2008 is shown by the height of the solid blue bar. The zebra-striped 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.

So, as to the attractive returns, you need to know that this $934 million of recurring segment profit plus DD&A that we generated in 2006 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. The strong returns and free cash flows continue in 2007 and 2008, 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 cushioned the impact of lower gas prices on the rest of our enterprise. That was certainly the case in 2006. However, even with more moderate pricing assumptions, 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 have demonstrated with our rapid expansion of Opal and the Midstream opportunities that we are now pursuing in the Piceance Basin. The aggressive buildout 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 oil sands off-gas processing business positions us for another emerging basin that we'll serve there.

The last year has demonstrated a new high-water mark for NGL margins and, of course, highlights the challenge that we have got in developing profit guidance in this type of environment. So the low end of our guidance range for 2007 and 2008 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 2006.

But under either scenario, this is an attractive business, generating attractive returns relative to its cost of capital and continued free cash flows. But what really keeps this business healthy in the long term is our organization's commitment and focus on providing our customers the most reliable services 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 customer's markets, as evidenced by the receipt of FERC approval for our Leidy to Long Island expansion project; execution of precedent agreements totalling 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 of the Phase IV expansion of Gulfstream.

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 a fair resolution of all the issues in case. Furthermore, it will provide our customers rate certainty for the next few years.

I think the fact that we reached the 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 the high on what is called, in rate case parlance, a black box basis. 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 receipt of some key permits. The total estimated cost is now pegged at $86 million. We've shifted some expenditures on Sentinel all 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 in-service date, we will post such a decision on the Northwest Pipeline Company website. But for purposes of 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 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 & 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 startup construction, and the Potomac expansion of 165,000 dekatherms a day beginning to be constructed in November of 2007.

We signed seven separate precedent agreements with shippers totaling 142,000 dekatherms a day for our Sentinel expansion. As I previously mentioned, we have got great expansions, both well on their way and in the final phases of kickoff of construction on Gulfstream.

Last slide, please. So, again, a strong year operationally and commercially 2006, with 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 or 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'm 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 the Power business. We continue to see the market fundamentals improve -- market liquidity, market participants, our own credit in the market continues to improve. As you heard about Ralph's growing E&P business, we are now marking over a Bcf a day of equity in third-party production.

Turning our attention to 2007, on slide 42, we're off to a great start. As Steve indicated, we have cracked the 2010 barrier with our sale to SoCal 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. 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 sale beyond 2010 in PJM. The PJM market, capacity market, continues to improve, and you're seeing higher capacity values across the board in PJM. 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're 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're off to a great start in 2007. As I indicated, I expect to be back to you before the year is over with additional sales beyond 2010.

With that, I'll 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 NGLs, natural gas and oil. 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 60's. 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 the slide next, number 46, 2007 to 2008 segment profit. This slide summarizes what you heard from each of our business unit leaders, and also gives you a consolidated total. As you can see, the $1.9 billion to $2.4 million 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 midpoint 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 between $5.10 and $6.40, both in 2007 and 2008, and the San Juan and Mid-Continent area, again, averaging for the year between $6.10 and $7.40 in both 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, and that's WTI crude to Henry Hub, of 7.4 to 9.6 times. Again, in 2006, we experienced that 9.6 times. Again, the crude oil is a reference because it has an impact on other prices.

The next slide, please, number 49, is just an update on our hedges. We have 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're still burdened by the legacy fixed-price hedges at the Basin, the first line on the slide, which were put in place back in the 2002 and prior periods, where we had 172 million cubic feet a day at $3.90 in 2007 and 73 million cubic feet 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 cubic feet a day, and the price declines to $3.67, and then 2010 at 70 million cubic feet 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 a graphical depiction of our natural gas exposure. The top of the bar here, at nearly 750 million BTU a day is the net to E&P production. As you can see in the gold area, that's the amount of production that's hedged. 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. As you can see, that fuel and shrink almost perfectly offsets the E&P unhedged production, and the net position therefore as just slightly long, as depicted by the red line.

By 2008, our E&P production increases once again, and the hedges diminish somewhat, the financial hedges. However, the Midstream fuel and 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 BTU a day. But again, on our nearly Bcf of gross production, the net natural gas exposure is reduced to about 250 million BTU a day in 2008.

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. 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 provide 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 2007 and $2.4 billion to about $2.8 billion in 2008.

Being free cash flow, it 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'll continue to update you on those as we move forward.

The good news here is we have MLP capital that can fund a great deal of these projects via drawdowns. 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. That's not to say that we don't intend to make such dropdowns; we have just not modeled that, and we're not providing guidance with respect to those dropdowns.

The next slide, page 53, is an analysis of our cash balance through 2007. 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 about $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, it yields an expected surplus in the $600 million to $700 million range. Again, we will consume a substantial amount of that with some additional growth opportunities. 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're very much focused on driving and enabling sustainable EVA growth and growth in shareholder value. (Technical difficulty) 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 ratios and ratings. We think that's key, and particularly so, given our MLP drawdowns 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 in the debt capital markets, as well as with our bank facilities and the like. We will continue to reduce risk in the Power segment, as Bill outlined, and 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 have 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 (technical difficulty) 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're taking action to drive value creation in the future.

With that, we'll be happy to take your questions.

(OPERATOR INSTRUCTIONS). Carl Kirst, Credit Suisse.

Good morning, everybody, and congratulations on a nice quarter, certainly. If I could like to start, actually, on the E&P side, Ralph, we've got a little bit of cost creep coming in here. I guess the first thing is I just want to make sure I understand the $150 million of the CapEx rise here in 2007, given that we have additional opportunity, we really should only be looking at that, half of that, I guess, as far as capital efficiency slippage. Is that correct?

Yes, I think exactly (technical difficulty) Fort Worth is additional drilling; that's $30 million. New opportunities in areas that we have 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 leadtimes.

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.

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 sort of 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 [continued-ish] into 2008, yet generating EBITDA substantially greater than that, while still achieving double-digit production growth, which is a pretty (indiscernible) 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.

I think at this point, we feel that we have baked in the cost increases we have to see. We're not anticipating 2007 will be as high increases as we saw like in 2005 and 2006.

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 I think -- well, we do feel that we are at the right level at this point, and an increase in costs would primarily be due to new activity.

Lastly, on E&P, you're sort of guiding us, understandably, to sort of three-year average F&D to kind of smooth things out. The F&D in 2006, notably (inaudible) higher than that. I don't know, can you 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 it could -- 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. 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 that we are -- 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 going forward, but it still keeps us very competitive. There won't be years, as we have seen in the past, where -- primarily in 2003 and 2004, where we didn't have that big a budget and we had a lot of downspacing.

Now, going forward, we will have downspacing additional reserves, but we're also spending a lot of capital now to increase that productive capacity. To the portion of our capital now is obviously spending on making the PUDs translate into PDPs. But we feel very good that we have been able to spend a lot of money on that but, in additional, spend enough money that we're continuing to add quite a bit of reserves.

So just with the less facility spending, the goal is here to actually have a lower F&D in 2007?

We will have less facilities in 2008 than 2007, so that would lower it -- on the gross cost, absolutely.

Bill, on the Power side, you made a mention 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 envelope, 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 teens?

What we are seeing, and I've 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 fire-saling our portfolio. So it's going to come down to price, ultimately.

Shneur Gershuni, UBS.

I just had a quick question with respect to the power contract that was signed today. In the past, you have sort of 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.

Faisel Khan, Citigroup.

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 -- call it eight quarters. 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 we, as Don pointed out, had cost increases baked into our rate recovery. 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.

What about reducing it? Are there opportunities, you think, over time to reduce [SG&A]?

Potentially, yes.

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 was 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.

On the Power side, basically, the deal that was announced today -- that's basically that capacity deal, 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.

Is there any way to back into a capacity price, in terms of how you sold those 2 gigawatts of power for? Is there any way to back into that?

Not really, not unless for some reason SCE has to disclose it publicly.

Which 2 gigawatts of your AES 4000 plants, were these? Were these like the higher heat rate stuff, or was it kind of across the board?

It was a mix, a mix of the higher heat rates. In fact, I believe -- and I'll 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.

What does this mean in terms of having to be able to repower some of those assets, over the long run?

That would be something we would assess independently of these sales. The sales we're making are for the existing megawatts we have. Clearly, California needs capacity, and that's something that, if we're able to work through it with AES, we would be bringing it to Steve and Don to look at future repowering rights that we have in California.

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 running in the range of $110 to $150.

On the MLP, is there additional cost in your corporate O&M from running that separate entity? Is it fair to say that that is part of your general G&A? Has there been an additional expense of running that separate entity?

There are additional costs. They are relatively modest. They are a few million dollars a year. They are included in consolidated results.

When you raise debt at the MLP, that interest expense is consolidated in your overall corporate guidance. Is that right?

That is correct.

Then, to the extent that you raise debt there, there might be timing issues in terms of how you pay down debt at the C Corp. Is that fair to say also?

Yes, it is. That is fair to say.

On the E&P side, I wonder if you could talk a little bit about the opportunities. You talked about, previously, I guess, the Paradox Basin. What is going on there, and what type of opportunities are you likely to see out of that position you have?

In the Paradox, we have now drilled the first of two -- we drilled two exploratory wells, and we are doing extensive core analysis. After the core analysis on the first well, we have set casing and we're beginning testing, and we're currently evaluating that results. 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 other parts of our acreage holding there.

Than in the Barcus Creak, we have drilled several wells, we're testing the first couple and we have of total of -- counting last year's that we spudded and this, we will drill five wells in the Barcus Creak area this year to test that area. That's just north of Ryan Gulch.

So those are primarily the areas that are affecting 2007, and we remain optimistic in those areas.

Sam Brothwell, Wachovia.

On the Power business, have your thoughts evolved at all strategically on what you might do with that longer-term? I know you had kind of addressed the possibility of re-powering. Are you thinking about possibly looking at selling that again, or increasing its profile within the corporation?

Our plans and strategies are unchanged from that that we've had in mind since we brought the business back and decided to retain the business in the fall of 2004. We're not really seeking to expand our footprint. We are more all about reducing risk, maximizing cash, satisfying our existing customer commitments and, as you've seen here most recently, placing 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.

Do you think it could become more of a value generator over time?

I think that, certainly, we're beginning to see some uptick in people's perception of power. In certain of the geographic areas where we have facilities, we've seen some excess capacity begin to be worked off. We're seeing some people pay up for assets. So clearly, the overall feeling about the business appears to be improving.

Gordon Howald, Calyon.

Most of the questions have been answered relative 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? Would you at some point consider FERC-regulated pipelines for MLPs, once the tax issues at FERC are resolved?

With respect to Midstream, 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, did $1.6 billion last year. 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. 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.

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? Do you have a sense of what the cost 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 start drilling, basically. So our first one, which just started drilling in, I think, January and February of last year, we have 2 years left on. I can say -- the last one spudded in December, so we have three years left on that -- 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.

I think, moving forward, when these start to roll over, we would just have to -- 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.

Sven Del Pozzo, John S. Herold.

Would you be able to tell me, 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.

Again, regarding day rates, I'm wondering, with the relatively recent influx 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. We also, 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.

Maureen Howe, RBC Capital Markets.

Ralph, I'm sorry to keep coming back to this issue. 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 $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, the LOE is -- the $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 -- is like $0.66. Gathering was $0.46, operating taxes of $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.

Than 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 yes, we really invested $1.55 to find this, and now we're producing it. So that's the way we look at that.

I might have misheard you, so I'm just wondering. I thought you had thrown out a -- again, in answer to a previous question, a $2.15 F&D number, but I'm not sure if that's right, because then I think you said that you expected F&D costs to decline going forward.

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 2006 only, I think one of the previous callers talked about $2.35 or $2.38. In that is included about $125 million of facilities in 2006. So if you take the facilities out, which I would, that makes the one-year F&D more like $2.15 or so.

What I've seen in the industry, early comparisons in the industry, most F&D I've seen for one year is more like $3.00. So I think we are still advantaged at the $2.15 rate or even, say -- well, let's count everything, facilities and all, the $2.38. I'm seeing that we're well below the average for the one-year average.

Then, going forward, I think our capital budget has been, as you see, the $1.3 billion or $1.4 billion. Included in 2007 is about $200 million of facilities. In 2008, it's only about $65 million in facilities. So that 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 facilities, which has always been our strategy.

So I think that lowers the overall F&D going forward, because we're not spending as much on facilities. But then pure drilling -- it probably will stay in this range, since hopefully, we'll continue to get better, more efficient, and drive it down a little bit.

Just moving to Power, Bill, on page 43, where you do again set out the cash flows going forward, based on the contractual arrangements 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, 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 fuel and shrink for Alan's Midstream business, which is transfer pricing.

So you don't have anything specifically in the Power portfolio that that might be related to hedging a spark spread position?

We certainly -- if we're selling power. We are always buying gas, if it's just an outright power sale. The reseller tolls -- there's no need to purchase gas for it.

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, again, our natural gas side of our business is tied closely to Power, E&P or Midstream.

So I guess I'm just confused by this note, then. What exactly are you trying to say in this note, that these cash flows that you're showing here, the ones that are contracted, are basically the locked-in margin?

Yes, that's -- we don't use the term locked-in. We use the term hedged, because, in effect, there's 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. Then the blue bars would suggest, for instance, in California we still have megawatts available in 2011, as well as in the Northeast and our other regions. The blue bar would represent what we believe the market value of those megawatts are worth.

Then just one final question, and it relates in part to the Power portfolio, but it's probably more of a question for Don. 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? 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.

Margaret Jones, Citigroup.

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?

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 take some of the proceeds from drop-down 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.

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. 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.

Carl Kirst, Credit Suisse.

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.

Sven Del Pozzo, John S. Herold.

Could you walk me through when do you and Anadarko plan to put in a water disposal systems 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 kind of 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. 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.

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.

Gary Stromberg, Lehman Brothers.

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 capital markets -- 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.

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.

Peter Monaco, Tudor Investment Corporation.

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, et cetera, et cetera?

It's 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.

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.

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.

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.