威廉斯 (WMB) 2007 Q1 法說會逐字稿

Good day everyone and welcome to The Williams Companies' first quarter 2007 earnings conference call. Today's call is being recorded. At this time for opening remarks and introductions I would like to turn the call over to Mr. Travis Campbell, head of Investor Relations. Please go ahead, sir.

Good morning everybody. Welcome to our first quarter earnings call. Thanks for your interest in our Company. As usual, today you'll hear from Steve Malcolm, our Chairman, and Don Chappel, the CFO. Also Ralph Hill who heads up the E&P group, and Alan Armstrong who heads the Midstream business will say a few words. Other leaders, including Bill Hobbs and Phil Wright, are here and available for questions after the prepared remarks.

Before I turn it over to Steve, please note that all of the slides, both those used in the presentation and the appendix, are available on our website, Williams.com, in a PDF format. The press release the accompanying schedules are also available on website.

Slide 2 and 3, entitled Forward-looking Statements, detail the risks factors and uncertainties related to our business. Please review those and the information on those slides. Also slide number 4, entitled Oil and Gas Reserves Disclaimers, also very important and you need 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.

With that, I will turn it over to Steve.

Good morning and welcome to our first quarter conference call. For those of you who appreciate concise, snappy earnings calls, I think you will like today's call because we will be able to move through our only 33 slides pretty quickly this morning.

Turning to slide 6 please. The headlines from the first quarter summarize a solid start to what I expect will be a great year for Williams. We produced a double-digit increase, 12%, in our recurring income from continuing operations after mark-to-market adjustments. And our E&P development efforts yielded still larger double-digit increases in our natural gas production. We produced 28% more natural gas in the first quarter in this year than last.

And in the Piceance Basin the growth rate is still higher. As we have discussed in the past, the Piceance is an extraordinary growth engine for Williams, and we have significantly accelerated the pace of our development there. In first quarter this year our Piceance production was 37% higher than the first quarter of '06, an outstanding accomplishment.

Our increased activity and continued success also means we are continuing to grow our reserves. Ralph Hill will provide an update on our 3P reserves -- I am speaking here about proved, probable and possible -- which increased even as we produced 300 Bcf last year. And Ralph will also share an update on the very significant growth in our total resource potential.

In our Midstream business we continue to enjoy the benefit of very strong NGL margins, but more importantly our entry into the Piceance Basin with the new Willow Creek plant will provide a new, exciting large-scale growth platform for our Midstream business.

In the Gas Pipes in the first quarter we benefited from increased rates on our Northwest and Transco systems. Northwest rates went into effect on 1/1/07. And Transco is subject to refund on March 1, 2007.

Also in this business segment Williams has been recognized as the top major pipeline in an annual industrywide customer survey conducted by Mastio. As well, our Northwest and Transco systems both received individual recognition for customer service in the survey. Clearly this is a point of pride, but it is also meaningful from a business expansion standpoint. In this business segment expansions are driven by demand from what the survey tells us is a base of customers who think very highly of our service.

We also continued to grow our dividend. The latest increase is our fourth in less than three years.

Turning to slide 7. During last quarter's call I said that our management team was sharply focused on the crisp execution associated with several catalysts of value creation during 2007. And as you will hear this morning, we have already made strong progresses. You'll note the checkmark next to the growing segment profit. Recurring consolidated segment profit for the first quarter is up 10% over year ago levels. A checkmark next to growing natural gas reserves and production. As I mentioned, we grew those reserves at the same time we increase our U.S. production by 28%.

A checkmark, we did put into effect new higher rates on our Northwest and Transco pipelines. A checkmark next to capturing more Midstream projects. In the Midstream business we announced we will enter the Piceance Basin with a $450 million a day processing plant. And that plant will connect NGLs to market through the Overland Pass Pipeline, a project in which we have an interest. This all adds up to an exciting time for Williams. And let me now turn it over to Don Chappel.

Good morning. Please turn to slide number 9, Financial Results. As you can see, our reported net income per share was $0.22, flat with the prior year; however, non-recurring earnings, and more importantly, mark-to-market effects distorted the true economic results. The last line in the schedule you can see our key earnings measure. Recurring income after mark-to-market adjustments was $0.29 per share, up from $0.26 the prior year, or about 12%. Overall we are pleased with our first quarter results as they are stronger than planned, and up 12% from first quarter '06.

Importantly, our E&P production is up sharply. They are providing a new higher base of production as we enter the second quarter and the balance of the year. Our Midstream business continued its very strong performance. And Gas Pipes are now benefiting from those new higher rates. And Power is on plan.

Turn next please to slide number 10, Recurring Income from Continuing Operation. And this slide details the non-recurring items included in the quarter. They are relatively few and they are detailed on this schedule. I will say no more on that point.

The next schedule number 11 please, Recurring Income from Continuing Ops after Mark-to-Market Adjustments. I will just walk quickly through the reconciliation from recurring to recurring after mark-to-market. Again, we start with recurring income of $128 million, or $0.21, and we make some mark-to-market adjustments related to our Power business.

First, we reverse forward unrealized mark-to-market losses that occurred during the quarter, which we view as a noneconomic. And we add back realized gains from mark-to-market previously recognized of 8, for total mark-to-market adjustments pretax of $79 million, as compared to $34 million in the prior year. We tax effect that, and after tax the adjustment is $48 million positive this year, as compared to a $21 million positive adjustment in the prior year, a $27 million change. Again the after mark-to-market earnings are $0.29 versus $0.26 the previous year.

The next slide please, number 12, First Quarter Segment Profit. We display this both on a reported and recurring bases. I will limit my comments to the recurring side of the schedule. The bolded line near the bottom of the page, segment profit after mark-to-market adjustments, $482 million, up $44 million, or about 10%, from the prior year. You can see the detail by each business. And again with Power at the bottom of the page, after eliminating the mark-to-market effects.

Let's take a look at each of the business units, which are detailed in the appendix, as well as full detailed in the 10-Q. E&P increased its domestic production volumes by 28% and total production by 25%. Net realized prices at $5.32 were 13% higher. DD&A was up $41 million, with $26 million related to increased volumes and $14 million related to increased unit costs. Lease operating expenses were up $14 million, with $9 million related to increased volumes and $5 million related to increased unit costs. SG&A was up $15 million, however, $5 million of that increase was related to extra expenses recorded in the quarter that were related to prior periods.

Looking at Midstream's results. Midstream once again delivered very strong results that were somewhat above planned levels and comparable to the strong first quarter of 2006. Midstream continued to enjoy very strong NGL margins, as well as higher volumes in the West. Overall, NGL liquids margins increased $30 million over the first quarter of 2006. Deepwater volumes declined somewhat from higher than normal levels last year, and expenses were somewhat higher.

Gas Pipeline recurring segment profit of $150 million was up $17 million, or 13% from the prior year. New higher rates related to our rate cases contributed $33 million of the increase, which was partially offset by higher costs principally related to insurance and DD&A.

Note that Northwest Pipe's new rates went into effect on January 1. Transco's new rates went into effect on March 1, thereby we didn't have a full quarter effect. And Transco's rate cases remain open.

Next slide please, number 12. Excuse me, number 13. I guess that is -- I will turn it over to Ralph.

I am pleased to share our first quarter results -- our strong first quarter results with you today. I will talk about some Basin highlights, and also dive a little bit deeper into our performance versus the industry in the areas of finding development costs, organic drill bit growth, and discuss our 3P and potential reserves, as Steve mentioned.

Slide 14. First quarter '07 production, total production was up 25% compared to first quarter '06. Our segment profit was up also 27% compared to the first quarter of 2006. We continue to upgrade our rig fleet in the Piceance Basin in particular. And our Nabors rigs are scheduled to start shipping out this month in May. The first of four new what we call Super Sundowner rigs will be coming to the field later this month.

We have had a successful winter drilling at the Highlands and Trail Ridge area, which is one of the areas we were drilling to see if we could do that on an operational aspect. And so far it has been successful. And we have had a significant major road infrastructure to the Highlands has been completed, with just some final touches in a few areas there. So all those things should set the stage for better growth and more rapid growth in the Highlands in the future.

Don talked on it briefly, but looking just on the Investor Relations sheet, the LOE for first quarter of 2007 was $0.574 versus the first half quarter of 2006 $0.505, and that is about up about 14%. Several factors affecting this were the new Basin impact of our Fort Worth activities. It is a higher area to operate in, although it is doing very well for us. We have had numerous facilities expansions I told about in the Piceance in the past that we're building now to be ready for this rapid production growth we continue to have. And if you compare it on an apples-to-apples basis, the second quarter of '06 actually had some costs in its numbers which actually should have been in the first quarter of '06. If you look at that, our actual first quarter '07 numbers for LOE on a per unit basis are slightly down from the first quarter '06. So good performance by the team there.

Don mentioned the SG&A side of the world. We were about, if you adjust out the prior year first quarter SG&A $0.071 that has hit us this quarter, we actually were up about $0.05 on our SG&A, which is exactly in line with what we thought would happen with the increased staffing we had. So on our cost basis we believe we're right on line with where we thought we would be and where we should be.

Turning to slide 15, Basin Highlights, very quickly. Steve talked about the total Piceance is up 37%. This divides it into two areas in the Piceance. The Valley itself is up 34%. Our net production was 453 million a day. In the valley 22 rigs are operating. And our simultaneous operations, which we have talked about before where we frac, perforate, drill and produce on the same pad, continue to do very well and improve our cycle times.

In the Highlands we have three rigs operating. Our production is up over 100% from last year at 25 million a day. And our well performance is meeting expectations. And as I mentioned, we're doing significant work on infrastructure in that area, and most of the major work is nearing or at completion. Powder River continues to do very look good for us. The Big George is driving this production. Big George is up almost 90% year-over-year. A little graph to the right of the Powder River shows how the Big George is becoming an ever-increasing part of this basin's production. Overall, our production in the Powder is up 29%, and we have 12 rigs operating in the Powder River.

Slide 16. San Juan, the mature basin, the team continues to do well. It is up 7% over a year ago. All of our optimization efforts that led to the Oil and Gas Investor Field Rejuvenation Award last year continue to pay dividends this year, as you can see from our performance.

And our newest basin, the Fort Worth Basin, we're up almost threefold from a year ago. Our drilling program, we're really very pleased with this year's drilling program. It is exceeding our expectation. And there are many, many deals out there in the smaller area, what we call more of bolt-on size deals that are out there. And also we have increasing wells beginning to hopefully impact our growth to the positive side.

Slide 17, looking at the three year F&D the industry. This chart reflects Evaluate Energy's top 20 U.S. gas producers. It is our three year F&D average. Williams' $1.47 average is definitely in the top quartile, as you can see here. And as this chart will show, it is possibly the industry leader, if not the industry leader. So on a comparison basis we are much lower, our $1.47 on a three year basis, than the top 20 producers' average of $2.77 per Mcf. We believe that is the right way to look at it on a three year basis because it smoothes out potentially high exploration and development costs or acquisitions that could happen in any one year. So you smooth that out in a three year look. But if you do look at it on a one year basis, we do have some numbers on that aspect that is not on the slide.

If you look at [Harold's] 2006 U.S. industry one year F&D, the company average for the top 75 companies, that average was $5.18 per Mcf on the F&D. If you take Evaluate Energy's one year average, based on the companies on this chart, and just look at one year instead of three years, that one year average was $3.50 per Mcf on a F&D. And our one year average, as you recall from the last call, was $2.14 per Mcfe. So looking at it on a one year basis or a three year basis, we're at least $1 better than our competition, and we're making our reserves more productive. So our PDPs are increasing each year as a percentage, while we're also growing these reserves rapidly and with lower cost.

Turning to slide 18. Again, according to Evaluate Energy, these statistics, Williams was the 13th largest U.S. gas producer in the nation last year. And is the 6th fastest growing in production of the 20 largest gas producers in the country. Many of those that grew above us on the chart, as you can see on the right hand side, many of those companies had significant acquisitions in 2006, which obviously impacted their growth rate, and we did not.

Slide 19. Looking at leader in growing reserves organically, it is something we talk about quite a bit. This chart shows us faring very well in reserve additions. We were ranked number 7 out of the top 20. And as this table shows, most of the leading reserve replacement numbers of the people ahead of us were driven by acquisitions. As you can see there the far right column talks about acquisition percentage of net addition. Some of the companies were significant of that percentages. Ours were not. Ours were organic.

Only two companies exceeded our reserve replacement ratio via the drill bit. And as to the previous slide 6 display, neither of those companies can match our production growth rate. And as you recall from slide 5, we achieved this high level of performance by maintaining the lowest three year F&D cost of any of the top 20 domestic gas producers. So we feel very good about our performance in 2006.

Slide 20. As we mentioned the last call our proved reserves are up 8% over the previous year. Our 3P reserves are now 10.8 Ts, and our resource potential, which we talked about previously, last year in the 12 to 15 Tcf range. And on a potential are up to -- now has a reserve potential of up to 22 Tcf.

Looking at our 3P reserves we have reaffirmed and increased our 3P level to 10.8 Ts, even after we produced about approximately 300 Bcf of production last year, obviously more than replacing that production that we had.

Our current 3P reserves exclude new areas of exploration, such as Barcus Creek, Paradox, Uinta and other areas where we have land positions. And they also exclude significant unrisked potential reserves in our other basins -- in our existing basins such as the Piceance.

These areas include where we are utilizing new technology. For instance, in the Piceance we're using longer lateral reaches. We have cut off our 3P reserves to lateral reaches to about 2,000 feet lateral reaches. That is where our 3P reserves estimate cuts off. However, at this time we have already exceeded that 2,000 feet lateral reaches in a number of areas in the Piceance. We just have not yet moved those reserves into the 3P category.

Slide 21. In addition to moving the 1.6 Ts of probables to proved last year, I would like to continue to stress that our proved developed producing percentage of the total proved reserves is increasing, as this slide shows. Our PDP percent is now 53%. That is up from 43% in 2003. This means our assets are generating more productive capacity also while they are in the industry leading side of the cost for the industry.

Finally, I'm very proud of our team. They continue to do very great strength in production growth, cost efficiencies, reserve replacement through the drill bit. Our strategy remains to rapid development of this industry. We have a long-term inventory, as you all know. High drilling success, low finding cost. So we continue to do everything we can to increase this productive capacity in a safe and efficient manner.

Looking forward to this year, and exciting new opportunities at the bottom. We have some other areas we are drilling, as you know about, Barcus Creek, Paradox Basin, Fort Worth and others. And we look forward to sharing those results later this year and early next year with some of those new areas.

I will now turn it over to Alan Armstrong.

I am just going to highlight some of the growth within Midstream that we've got looking forward. As Steve mentioned, we have started into our Willow Creek project, and I will give us a little detail on that. And so we are moving forward to invest approximately $350 million over the next two years to install a 450 million a day gas processing and CO2 treating facility, along with a lot of other pipeline investment in the area that will gather and connect the residue gas into the center state grid in the area.

We are extremely excited about establishing this platform out here that is so well supported by our E&P reserves and their efforts in the area. We believe the Piceance is one of the top three Midstream plays in the U.S. And this investment will also provide further value to the resources that E&P is doing such a fine job of monetizing, as Ralph just got through describing.

Recognizing the growth potential in the area, Williams Northwest Pipeline unit is completing the construction of a 30 in h gas pipeline from the Parachute plant up to the emerging Greasewood hub. And our Willow Creek plant will add even more utilization for this infrastructure. So this really is a great example of Williams' integrated model and the way we're really bringing all the skills and all the expertise that we've got in the Company to bear and really to monetize the streams in this area. So some tremendous opportunity here. And again we're just starting this first train.

We do expect operations at Willow Creek to begin in the mid 2009. Initially we're covering an additional 20,000 barrels per day of natural gas liquids from Williams gas production. And we expect peak productions from this first train to reach nearly 30,000 barrels per day.

The recovery of these high-value liquids and transportation new markets will maximize the value of Williams E&P and our future customers' natural gas production, that today really goes unrecovered in the area. If you look back at 2006, 2005, 2006 there has been a lot of value left to be captured here, and so we're really excited about making this investment to be able to capture that.

The Overland Pass Pipeline, which is a joint venture between Williams and ONEOK, has recently announced plans to construct and operate a 150 mile lateral down from the Wamsutter area into the Piceance into Willow Creek. And this is going to provide both for our own liquids and for our customers ready access to some of the strong markets in both Conway and Belvieu.

Probably a note that needs to be made here as well is very key, is that this is also going to provide an outlet for an additional 180,000 dekatherms per day of production that would otherwise require natural gas transmission capacity to get out of the area. Helping relieve some of the basis pressure from this growing basin and eliminating some of the gas on gas competition. Not only does it allow us to monetize these streams, it also provide us additional take away out of the area.

We feel the combination of these assets provide a true industry solution to maximize these values and efficiently reaching markets that are not accessible today, and doing it in a manner that best serves the industry and the environment. Truly, if it wasn't for Overland Pass Pipeline and our E&P's strong reserves in the area, this project would not be on the drawing board today.

This focus on the development and operation of this large-scale plant is what allows us to make the necessary investments in people and assets for safe and reliable services in the area. It is our belief that these efforts are being recognized more and more by our customers, so we're very excited about some of the discussions we've got going on out here with parties outside of our own Williams business, but certainly that provides the platform and support for the business. We just see this as a great platform and a great example of our strategy coming into play here.

On to the next slide here. These are the pie charts that we have shown before. And the bottom line is that we continue to have success in moving the projects to the right in this graph. And the way this works is starting there on the left are projects when they are in the development and proposal stage. Then in the middle you see the under negotiation. So as we become more certain about the chances of the project moving forward, they move into that bucket. And then finally, if we have contracted or it has been approved by our Boards, we move it over into guidance there. And so as projects mature they move to the right.

The good news is that we're continuing to move projects over into the right there. You will note that in our capital guidance that that has come up significantly, primarily driven by the Willow Creek project and partially driven by some just changes in capital timing, in particular in the Perdido Norte project. So not any additional capital in that project, just moving in terms of timing into '08 and '09.

In looking to the middle pie chart for under negotiations, we did move Willow Creek into guidance. And we included in the under negotiations some exciting new opportunities that we are closing in on in the deepwater Gulf of Mexico. So we're hoping to be able to announce that at the next call. And in our olefins business, we've got a capacity expansion in the strategic Canadian Oil Sands area that we've got in here in the development proposal stage as well.

As we noted in the last call, the Canadian Oil Sands it is another area that provides tremendous growth potential via the processing of oil sands off-gas. We are extremely well positioned with our assets there today. In fact, we're the only processor of off-gas in the area. And we also have the only splitter that can take and make valuable product out of the liquids that are extracted out of the sands there.

Our range of capital spending for these under negotiation projects remains unchanged, even though we do have some things coming in and some things going out. The pie labeled in development and proposal reflects some changes in our real development pipeline as projects become more concrete or shift to the right. Examples in this include removing a potential deepwater project from this category, and adding in a new gas processing capacity in the western U.S. Certainly we're hoping that the first train that we're putting in Willow Creek will not be the last, and certainly don't expect it to be. We see a lot of potential coming down the road in the western U.S., as this reflects. And with that, I will turn it over.

Next slide number 27 please, 2007 Forecast Guidance. Let's focus on the bottom line. Our key earnings measure, diluted EPS, on a recurring basis after mark-to-market adjustments, we have increased the guidance somewhat from our February call to a range of $1.15 to $1.50, up from $1.10 to $1.50, as Midstream raised the lower end of its segment profit guidance by $50 million.

Note that the wide range is principally the result of factoring in a wide range of energy commodity price possibilities into our forecast. These assumptions are summarized on slide number 75. Additionally, natural gas hedges that are in place are summarized on slide number 52.

Let's turn to the next slide, number 28 please, 2007/8 Segment Profit. I will just walk down the slide. E&P, you can see strong increases with very strong production. Midstream and Gas Pipelines are up somewhat as well. And at the bottom of the slide you can see Power, after factoring out mark-to-market adjustments, is also up somewhat, and expected to produce cash in the range of $50 million to $125 million in 2007, and then $50 million to $200 million in 2008.

Total recurring segment profit after mark-to-market adjustments, if you just take the midpoint there of $2.175 billion in 2007 and $2.550 billion in 2008, is up about 17% year-over-year.

The next slide please, number 29, Capital Spending. Midstream has raised its guidance, as Alan mentioned, to include now the Willow Creek project in the Piceance Basin. And that was the only change in our consolidated guidance.

I would also note again that we expect CapEx to continue to increase in future quarters as we continue to seize attractive opportunities that deliver strong returns and increases in EVA. Each of our business leaders has highlighted, either during this call or in the past calls, many of these opportunities.

Turn to the next slide please, number 30. We continue to forecast cash flow from operations in the $2 billion to $2.3 billion range this year, and $2.4 billion to the $2.8 billion in 2008. Again, CapEx has increased and we expect that to increase even further as we move through year.

Operating free cash flow is expected to be negative this year. It is currently forecast to be positive next year, but again the caveat was increased capital spending. And note that the operating free cash flow is before minority interest dividends, debt retirements and other working capital changes.

The operating cash flow deficit in 2007 will be funded with the excess cash that is currently on hand. Also note that additional drop down of assets to the MLP WPZ, which are not included in our guidance but are part of our strategy, will continue to provide a low-cost source of equity capital to fund growth.

Next slide please, number 31, again just a refresher. Again our strategy is to drive and enable sustained growth in EVA and shareholder value. The MLP continues to provide some terrific benefits. Very low-cost equity capital is a source for growth. And we also are beginning to see more and more value in our GP value. Just a couple of comments on that.

With our recent increase in our GP distribution to $0.50 a quarter, or $2 annually, we're just below the high split level that requires a distribution of $0.525 per quarter, or $2.10 annually. Above that level we will move from a 25% sharing to a 50% sharing level on further increases above that $2.10 level. Also just a reminder that companies that have public GPs are trading at a range of 20 to 27 times EBITDA on that GP evaluation. So again we think great source of low-cost equity capital, and also growing GP value.

We continue to maintain and improve our credit ratings and ratios, which are important to us as we continue to raise capital, including the capital we raise at the WPZ level. We continue to reduce risk in the Power segment. And we continue to be very opportunity rich, and we are very much focused on seizing these additional value creating opportunities. With that I will turn it to Steve.

Concluding with slide 33. We will continue obviously to focus on these catalysts. As Ralph Hill has described, the outlook is very bright for Williams to continue to grow natural gas production. Of course, we have already settled the Northwest Pipeline rate case, and now we're working towards finalizing the Transco rate case.

Alan Armstrong described an exciting list of potential projects that we're pursuing. In our Power business we remain very focused on continuing to make meaningful progress toward contracting more of our megawatts beyond 2010. And Williams continues to have potential for more drop-downs to Williams Partners.

So clearly we have the assets, the talent and the growth opportunities to create significant shareholder value in the future. So with that we will be happy to take questions.

(OPERATOR INSTRUCTIONS). Shneur Gershuni, UBS.

Just two quick questions here. I guess the first question is I was hoping that we can clarify Ralph's earlier comment about bolt-on acquisitions. Are we talking about $100 million or $200 million type acquisitions, or are we talking something in the neighborhood of what Dominion is trying to sell and (inaudible)?

I was just talking primarily in the Barnett Shale area at that point of the slide. And basically what we see there seem to be deals more in the probably $25 million to $75 million type range.

Thank you for that clarification. My other question is just with respect to Power and so forth. I wanted to get your thoughts on contracting beyond the 2010, 2011 timeframe. There has been a lot of challenges with generation in the past couple of months in terms of environmental issues and so fourth. Would you clarify the market is looking a lot brighter than it has in the past couple of years?

Yes. This is Bill Hobbs. We are certainly seeing more interest in contracting longer-term, especially in PJM and the West Coast. The Mid-Continent markets are not as far out, but we are seeing markets develop in the 2010 range. But I would have to characterize it as we are optimistic that the before the year is over we will be announcing additional transactions, probably in both the Northeast and the West Coast.

Just one last final question. Towards the end of the call you spent a lot of time talking about the value of the general partner, WPZ. Would potentially be doing an IPO on the general partner as WPZ hits the high split be a sort of new source of cheap cost of capital that Williams could tap in the near future?

This is Don. That is always a possibility. Certainly we have no plans in the near term to take such action. We have a very substantial base of assets that are MLP qualifying and able to be dropped down and drive that -- well, one, raise the capital and drive the GP value even higher. That optional will always be open to us. So it is one that we will keep an eye on, but right now we think that the drop-down strategy would be first in our minds.

[Craig Scherer], Scottwood Capital.

A couple of questions. Don, how are the rating agencies viewing the maturing capacity markets relative to the liability of your Power book and your credit? And as a part of this first question, Bill, do you have any views on California capacity markets?

Maybe I will just kickoff. I think the ratings agencies have certainly become more positive in terms of our Power business and the markets more generally for power. I think the deals that we have been able to contact, and particularly the latest large transaction with SCE, was something that certainly got their attention. And I think was one that caused them to have even more confidence in our ability to continue to contract forward at attractive prices. So substantially improved, but we still believe it is still lagging somewhat.

As far as developing capacity markets in California, it is tending to plod along. Ultimately I think it will get there, probably 2008 at the earliest. Our contracting strategy has been more to bundle the capacity and the energy and market that as a bundled product, like we did with the SCE deal. But we are seeing some of the financial players look to capacity only deals beyond 2010. But as far as a functioning capacity market developing in California, it is certainly moving much slower than PJM.

The second question, Steve or Don, how are you all thinking about the deployment of free cash flow, including MLP drop-down? Don, you noted the likely increases in accretive CapEx guidance over time. Do you keep your powder dry for more accretive CapEx opportunities or are you considering share buyback?

I would say right now we have some very attractive CapEx opportunities on the horizon. But to the extent that we do in fact have excess cash, we would certainly look at all the possibilities, including a share repurchase as a possibility.

Sam Brothwell, Wachovia Securities.

I actually got a question for Ralph and a question for Alan. Ralph, with your growth in resource potential can you maybe give us a little bit more color on how you -- what drives your decision as you update your 2P, 3P?

And, Alan, the first quarter Midstream I guess maybe seemed a little bit light compared to what some of us were thinking. Maybe we were being too optimistic, but I see that you nudged the lower end of your guidance for the year. Can you maybe give us a little bit more on what is driving that? Is it a timing issue or something like that?

This is Ralph. On our 3P what we do is basically, as you know, the probables and possibles are usually the way it is looked at. One location away from a PUD would be the way we look at that. So I think it is a good look at what we have currently. We do not aggressively go out and say, even though we are doing for example longer laterals in the Piceance, we did not book additional, or add additional reserves, in that classification into the 3P category this year. We want to make sure we continue to be successful in those lateral reaches, which we have been so far, and we expect we will be, but just no reason to do that at this time.

As we look for the floor of the reserve resource potential we just have new areas that we're in now that we weren't in last year that could ultimately bear some fruit for us, we would think, but we don't know that. So that is when you get into areas such as Barcus Creek and Paradox, Uinta and just other land areas -- areas where we have land that we're starting to either continue to accumulate land or begin some exploratory drilling out in those areas.

That basically on the resource potential is just as it says in the definition we have I think on slide 4 or so. It just shows that is out there. It is a potential, but again it is -- a lot has to happen for that to bear fruit. We're very consistent with the way we did it last year on the 3P side. And the 4P side the same way as we did last year, it is just that we have some new areas that we could add to that 4P.

Sam, on your question, first of all first quarter we did in the, if you will, examine the margin, the NGL margin. We had a very soft January for the frac spread, as oil was getting down on to almost $50, and gas prices did not move with that. So January was pretty soft for us in terms of NGL on a frac spread basis. We had some other things that helped us drive that, including volumes coming out of the Opal TXP-5 plant.

Looking into the second quarter, NGL margin's April and May, and it is looking June, are extremely strong, just in terms of looking at the broad markets and looking at the basis differential out West. So a lot of confidence, if you will, in the current NGL margin.

In addition to that in the first quarter, as we usually see, we had quite a bit of volume shut-in out West from a lot of weather issues out in both the San Juan and the Wyoming area. And we've got a tremendous well connect program ongoing as we speak that is really going to be adding to our volumes for the balance of the year. Those two things give us a quite a bit of confidence about the remaining year.

Faisel Khan, Citigroup.

On the -- going back to the Power book for a second, I know you always talked about the Power book, or the Power business, as managing the risk of that business over the long run. But I guess, given the type of opportunities we see in the Power side and on the gas marketing side, when do you think you could make a decision on actually maybe moving away from managing risk to actually investing capital in that business?

A good question. As you know, our strategy regarding Power continues to be focused on reducing risk and creating more cash flow certainty. And in the near term I think that is where we're headed. We're not looking to expand our footprint in any way.

In terms of looking at the Big George, Ralph, what do you think is -- when does the Big George turn into the Wyodak? Is that something that you see that growth continuing for a long run, or is there a point in time where that becomes mature?

Clearly there will be a point in time when it becomes mature, but it is much better than Wyodak. If you look at the first five years of growth in the Big George versus the first five years of growth when the Wyodak was coming on, the Big George is probably three to four times more production than the Wyodak had.

It is really exploding for us. We have approximately 7 or 8,000 locations left between us an our partners to drill, so it is obviously long-term inventory. The key in the Powder continues to be water management. And we have many different ways we handle that. And we are happy to have a new partner in there who actually has a water pipeline, which could help us do some great things there with water removal.

But the Big George is -- and I don't have a side with me today, but I have a side that shows that the Big George growth is far superior than Wyodak. And I think it has got a very bright future ahead for it.

On the Gathering side, I just wanted to ask a question on the volume. If I look at the first quarter of '07 versus the fourth quarter of '06, Gathering volumes were actually down. Is there any reason why that would be the case?

A couple of things again, as I mentioned, we had quite a bit of shut-in production in the first quarter in the San Juan Basin where roads were impassible for a pretty long period of time. So producers were not able to get out their facilities and unload their water and resume production. So that hit us pretty hard in the first quarter, as well as we had some freeze off.

Overall things are looking pretty good. And we did see some decline from the deepwater, particularly the areas around East Breaks, and that is just a matter of production coming back on as now Anadarko gets back into some of the wells out there. So some pretty promising volumes to come from there, but we did see some decline in the East Breaks area in the deepwater that also caused some decline in volumes.

Steve, one more question on the Power side, is it -- are you saying that if the opportunity didn't present itself to invest in a project that would give you positive EVA that you still want to look at that sort of deal?

I would say that we have such extraordinary opportunities in our other three asset-based businesses that that is where we want to focus our capital.

Gordon Howald, Calyon.

A question for Ralph if I could. You touched on this with Sam's question, but being just a humble pipeline guy, could you give me a little more color on your comments about possibly increasing the 3P reserve based on your longer lateral reaches? When could this be reflected in 3P reserves, and why hasn't it been already? And what potential that represents to that 22 Tcf number that you threw out there?

I won't be able to give you the potential, just because it is -- we just don't do that. A lot of this will be firmed up this year on the lateral reaches. As I mentioned, we are already doing it for a number of wells. But we just -- we always believe that we should just make sure that it is working with all wells. And we have had it work on every well we have done, but we just didn't feel we had done enough yet.

But clearly we have the technology with the H&P rigs, and with these new Nabors rigs that will be coming on here later this month. So we believe we have the ability to reach out farther. I think a lot on the lateral reaches will be firmed up this year. And then, if that is true, which I think it will be, then that would be reflected for next year in our 3P.

The other areas, the exploratory areas and things like that, they will take a little longer. But Barcus Creek, for example, where we are drilling on -- drilling right now, which is just to the north of Ryan Gulch, that could add to the 3P and actually some proved reserves next year, because we are actively drilling in that area.

If I could, one other question maybe for Alan. Venezuela, there has still been a lot of continued uncertainty there and some actions taken recently in Venezuela. Could you talk about your perception of the risk that you have for your Midstream business in Venezuela, just given recent circumstances?

Well, first of all just so we are clear on what we do, do there, we are a service provider there and provide gas compression and some gas processing there to reinject into the oil fields there. So we're not in a position of taking any of the oil or any of the commodity. We're not a producer in any way, and so don't take any rights or title to the product there.

And so far the efforts today of the government has been clearly focused on getting control of oil supplies. And so we do not right now have any discussions or pressure being applied there. We continue to be a very reliable service provider there. And we think that PDVESA very much values that. They have got some similar facilities in the area, and so they understand the difficulties and the performance that we are providing to them, so pretty well-positioned in that regard.

I ask this question all the time and there's no changes then essentially from the last time we spoke last quarter or the quarter before?

That is correct.

Brian Olson, Luminous Management.

I just have a couple follow-ups on the Power questions that were asked earlier. I am just wondering, how do you guys plan on I guess capitalizing on the strength of the capacity market for your Eastern assets? And then also with regard to not expanding the footprint, but having the ability to invest capital in the business, is there any opportunity to reinvest in some of your existing assets?

It is Bill Hobbs. I will answer the capacity question Northeast, and Steve can deal with the second part of the question. We certainly -- there is with the regional pricing model, RPM option, that came out we're very pleased with the capacity prices that originated from that. I think it sends a strong signal that the Northeast, especially the Eastern PJM is getting very tight on capacity quickly.

So we certainly are talking to counterparties, both that are located in PJM utilities about longer-term sales, capacity, as well as the transmission expansions that I had mentioned in previous calls. That is quite a take Power into the Long Island/New York markets. There's interest in contracting long term. Certainly in discussions, and again I'm hopeful before the end of the year we will be making some announcements around those deals.

This is Steve. Again if I got your question right, we're not seeking to expand in the Power space. It is very much a continuing strategy around reducing risk and maximizing cash, and creating more certainty around cash flow certainty, and selling into the market beyond 2010. That is our clear focus in the Power space.

Would there be an opportunity to actually extract cash then from the Power book? And for someone else that maybe would see an opportunity in some of your assets to capitalize on an opportunity to invest in little cash now, is there a way for you guys to cash some of that out then?

As we have also always said, we continue to be very open-minded about how we proceed in the Power space.

Peter Monaco, Tudor Investment Corporation.

As you all look out a couple of years, clearly this is an incredibly cash flow generative Company, even after the prodigious growth CapEx. Talk about, Don, if you would the right capital structure for the Company down the road.

And separately, not to beat a dead horse, but with respect to the Power book, if it is clearly non-core, and in light of the incredible interest in power generating assets, particularly those that represent something of a call option on par prices and spark spreads down the road, will you divest it?

On the capital structure, I will just restate our prior guidance that we believe that returning to an investment-grade rating is the right strategy for Williams at this point in time. Our high-grade indentures restrict us from some of the actions that some investment-grade companies [were built] that sub investment-grade companies have. So we don't have some of flexibility that sub investment-grade companies have. And I think we would be more effective, more efficient as an investment-grade company. So we have been focused on returning to investment-grade, but doing so at a pace that continues to allow us to seize the opportunities, rather than reduce debt or take some other action.

In terms of the Power book, I would just restate Steve's comment that we are certainly open-minded, but our strategy in the near-term has been focused on risk reduction.

Carl Kirst, Credit Suisse.

I certainly appreciate the time here. Ralph, if I could go back to the non-proved reserves for a second. You had mentioned previous to this we're at the 12 to 15 Tcfe of resource potential. I think the delta over the 3P was primarily around 3 Tcf in the Highlands. I was wondering if you could confirm if that was still the case? Or as say, for instance, the production in the Highlands has doubled over last year, if you actually see even a greater resource potential in the Highlands? And then perhaps even between that 12 to 15 and 22, as we look at that delta -- I know you have mentioned a number of areas, Barcus Creek, Paradox and the like -- is there one area more material than the others as far as representative of that resource potential?

I think the resource potential in the Highlands is still in the same area that we have talked about. We like what we see obviously, and we continue to have more and more success. I think through last year we were at about 75 wells drilled in the various areas we call the Highlands. And each one of those have continued to delineate areas of the field that we like, areas of the field that we may not like as much, but they give us good thoughts and good ability to say that our resource potential continues to be very strong in those areas.

But I don't think it has gone up significantly. Really what we're looking at for the difference to go above the 15 into the 22 Ts -- or up to 22 Ts, a lot of it is in the new areas. I would say that as we continue to evaluate our existing core areas, such as the Valley and the Highlands, that does add some to it and to their opportunities to make the resource potential higher.

Some of it is up in that area. But the other areas that are [something]. It is just new areas that we have been quietly accumulating acreage in, and continue to, and that is at Paradox and Uinta. And doing new deals such as Barcus Creek and those things. We have actually increased, not nearly on the scale of the total 22, but we have increased our presence in the new basins in Fort Worth Basin, which obviously adds to this too.

It is kind of a combination of all those things. But we haven't really increased the resource potential of the Highlands, which is to your first question, significantly. It is probably up some. And a lot of the other resource potential up is just because we are expanding in new areas.

Are any of the other areas as material as the Highlands, or is it just more of a --?

They could be. They could be.

Fair enough. Can you break out on the 2P, 3P, or at least the probables and possibles, how much of that is coming from the Piceance?

I think I said last year, and I think it is -- I would say probably 60, 70% of that is coming from the Piceance. Probably about -- I would say about 50 to 70% from the Piceance. We still have a big 3P piece in the Powder don't forget. So the Powder is a big piece also. But most of it is from the Piceance and then followed by the Powder.

I don't know if Phil is on the phone or, Don, if not, just looking at the pipeline guidance, can you help us out with what you think the largest delta is there in the guidance for the pipeline? Obviously it is not going to be commodity price like everything else. Clearly insurance costs, the costs were a little bit higher this quarter than what we were expecting. And so I was just trying to get a sense of are we seeing rising cost pressures there above and beyond the rate cases? It this insurance cost that moderates going forward? I'm just trying to get a better sense of that dynamic.

This is Phil. On the top line side I would say that revenue-wise the short-term firm out on Northwest and the interruptible on Gulfstream can be a variable. And we like for that to vary obviously to the upside. But we have our marketers working those markets and attempting to capture those revenues full-time. So that is a source of potential variance.

On the cost side of the equation, while we have a pretty good fix on maintenance capital, that is an area that does vary somewhat based on our findings with respect to our internal inspections. Some of that will fall into capital. Some of that, depending upon how many dig outs and that sort of thing you have to do following inspections and the like, make fall in the zone of a maintenance expense. So there are some variance that you can experience there. And there are a long list of other miscellaneous items on the cost side that would be probably too numerous to mention in the course of the call.

But nothing -- no one single variable, if you will, that --?

No.

Then just lastly, Bill, on the Power side, just looking at the profit range for this year. As we have had a strengthening in the market, on the volumes that are noncontracted obviously, would you say that there is, with what you can see out there today with the strengthening of the market, that there is outside potential in that guidance range, or more that we would just kind of be at the higher end of that range perhaps as the market continues to strengthen?

Largely because we have hedged a significant part of our portfolio for 2007, we will stick within the guidance range.

Gary Stromberg, Lehman Brothers.

Two questions. One for Ralph. Not to beat a dead horse, but the 3P number, is 3P sensitive to natural gas prices? How sensitive is it, because we know gas prices were pretty strong at the end of '05 versus '06?

No, we are slightly sensitive to it. But really what we are in the resource potential type plays, those are actually known quantities of gas. And the probable location is one location away from a PUD, and then a possible is probably one more location away from a PUD. So there is really not -- although there was a significant decrease in price year end '06 versus year end '05, we have never felt like our reserves, even in the 3P area, are sensitive to that.

Really what we're looking at is continuing to make sure that we can -- that the technology we need to get to these areas is there. And we believe that is happening. It is just we didn't quite book it as that at this stage yet. But we understand that the hurdles that we need to go over, reach, the topographical situation, landowners and those kind of things, we're just being very diligent in booking those reserves -- or not booking those reserves, those are not booked reserves -- in establishing our 3P area. It really wasn't, both on our proved side and our 3P side, wasn't really affected -- on very, very small amount by the differences in price.

That's helpful. Then, Don, cash flow from operations in the quarter was a little bit lighter than we were looking for. Any unusual items there? And guidance still points to 2 to $2.3 billion versus 300 in the first quarter. Is there going to be some back end catch-up?

I think seasonally the first quarter has been relatively light the last couple of years. And I don't think there's anything unusual, so we would expect to catch-up.

Ray Deacon, BMO Capital Markets.

I had a question for Ralph. I was just curious what is the status of the Roan Plateau, and is that area where you could see yourselves expanding, given the growth that you had in the last four or five years in the Piceance?

I'm not sure what -- I know there has been the draft -- I don't even know if it is called a draft yet, but lots of comments on the EIS. They had five different potentials. And I think the one that they were leaning towards was one where like 80% of the Valley and surrounding areas has to be developed first before you go up there, which I think is very inefficient. So it is just kind of on I think a warm standby.

I would say, with our work that we have done in the Highlands area, particularly the Allen Point area, and some of the infrastructure we have built, that on an infrastructure basis, we probably have a great leg up in that area. And obviously we feel that anything that goes in the Piceance we have a very good knowledge of that. So we also think we have a good technical and operational advantage.

But at this point I'm not even sure -- and I haven't checked for awhile -- what the status is, if they're going to come out with a final word that talks about the Valley has to be developed first. And they also talked about only one operator up there, which might be advantage to us, obviously, if we would be in that area. But that also, I think, would be inefficient because it is a big area and there's a lot that could happen up there.

Just a strange initial draft that came out, or comments. But I would say, you just look at the Roan Plateau and look where we are drilling, and look at the Allen Point area in particular, we have I think as good, if not better, than everybody else operational and infrastructure advantage.

Brooke Glenn Mullin, JP Morgan.

My questions have been asked. Thank you.

That is all the time we have for questions today. I will turn the conference over to Mr. Steven Malcolm, for any additional or closing remarks.

As always, thank you for your interest. We were pleased with the first quarter results. We have strengthened our growth platform, and are excited about our prospects for 2007 and beyond. So look forward to talking with you next time.

Thank you. That does conclude today's conference call. We thank you for your participation. And have a nice day.