威廉斯 (WMB) 2005 Q2 法說會逐字稿

Good day, everyone, and welcome to The Williams Companies second quarter 2005 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, Investor Relations officer. Please go ahead sir.

Thank you and good morning, everybody. Welcome to our second-quarter earnings release call this morning. Before I turn it over to Steve Malcolm, our Chairman, just a couple of opening issues. All of the slides that we'll be talking from today are available on our Website in a PDF format. Also, three disclosures, three notes on disclosures that I need to mention. First, please note slide member number which details various risks and -- risks associated with our forward-looking statements that are included. Please read that slide. Slide three deals with our oil and gas disclaimers. Please review that slide as well. Also included in the presentation today are various non-GAAP numbers that have been reconciled back to GAAP numbers in the schedules that are included on the Website and also are included with the press release. So with that, I'll turn it over to Steve Malcolm, our Chairman.

Thanks, Travis, and welcome to our second-quarter conference call. As always, thank you for your interest in our company. We are again very pleased with our financial results and related commercial achievements during the second quarter. Our strong results continue to be driven by our success in executing on our strategy of making disciplined investments in natural gas-related businesses that are located in growth areas and where we enjoy competitive advantages.

Slide five offers some of the headlines regarding our performance in the second quarter. Our businesses are producing the strong cash flows and improved profitability that we expect. E&P segment profit more than doubled for the quarter and for the first six months of 2005. We are especially delighted with the rapid volume growth in our natural gas production business. Domestic production has climbed 18% during the first half of the year. Midstream benefited again from strong gathering volumes and above-average margins. NGL sales volumes were up significantly versus the first six months of '04.

We saw a significant improvement in consolidated cash flow from operations, 489 million in the second quarter. Through June, cash flow in '05 is 793 million, which is a 29% increase versus '04. And recurring results after adjustments for mark-to-market accounting were up dramatically second quarter '05 $0.17 a share versus second quarter '04, $0.04 per share. As well, we're continuing to see strong performance in gas pipeline, and power is performing as expected. Recurring results after mark-to-market adjustments in power are on target, and in fact, better than last year. Cash flow from operations year to date is positive and on target.

Other developments that occurred during the second quarter are shown on slide six. We have refined our earnings guidance by moving the bottom-end of the range up $0.05 for the year. The new range is $0.70 to $0.90 for 2005. Of course in May, we increased our dividend by 50% to 7.5 cents per quarter. We continue to take advantage of hedging opportunities. The collars that we've put on that Ralph will discuss in more detail had a $5 million positive impact in '05, greater impact in '06 and '07, and just as importantly, creates greater certainty around our cash flows.

A brief update on the MLP. As you know, in early May, Williams Partners filed a registration statement with the SEC, and we have since filed three amendments, the most recent of which was filed earlier this week. That gives you an idea of where we stand with respect to the timing of the MLP. As you know and as we have said many times in the past, at this stage in the process there's still very little we can share about the MLP because of the SEC rules that govern initial public offerings. I ask that you bear with us on this issue and we won't be offering any additional information about the MLP today, nor will we be taking any questions about the MLP until the registration statement is declared effective. Of course, you can view the registration statement on the SEC's Website.

We continue to focus on certain legacy issues. With respect to a proposed tax settlement, we have reached a preliminary settlement with the IRS relating to an outstanding tax issue associated with prior years. As a result of the preliminary settlement, we expect to make payments totaling approximately 180 to $200 million in the last half of 2005, all of which is accrued at June 30, 2005. The expected settlement is subject to the approval of the Joint Committee on Taxation.

With respect to Longhorn -- and you will recall that this is our investment in a petroleum products pipeline in Texas -- in the second quarter we did record a $49 million non-cash impairment to fair value because of lower shipped volumes. Volumes are lower as a result of price competition and higher crude prices. We expect a decision on the future operation of the pipeline by year-end 2005. And we continue efforts to resolve ongoing litigation, and an update on that litigation is found in our 10-Q.

Slide seven underscores the fact that we are opportunity-rich. With the companion press release this morning relating to increased Piceance Basin drilling locations, our Piceance Basin story is even brighter. As Ralph will describe, we now project as many as 4600 drilling locations in the Piceance versus our earlier estimate of 3000. Just to offer some perspective on that, 1600 incremental drilling locations divided by 500 wells drilled per year, which is the rate that we think we will be at by, say, 2007 -- that lengthens the inventory, our drilling inventory by three years plus. And so another way of thinking about that is that we have access to these very attractive incremental returns, which currently range between 25 and 75%.

We also increased our 3P reserves by 21% to 8.5 trillion cubic feet. And importantly, these totals do not include any potential contribution from the step outs like Trail Ridge, Ryan Gulch, Red Point, or any of the other new areas.

In May, Williams acquired properties in the Barnett Shale play in North Texas. This acquisition is clearly consistent with our strategy, consistent with our core competencies around tight sands, shale, and coalbed methane development.

In Midstream areas, the significant drilling activity that is ongoing in the west has increased demand for our services, examples being the Quintana (ph) Mesa and Wamsutter Phase I projects that Alan will describe more later. And we continue to be in an excellent position to capture new deepwater business.

In the gas pipeline area, we are seizing opportunities to meet growing demand. Construction has started on the Central New Jersey project, incremental volumes are now flowing under the Phase II expansion on Gulfstream, and we continue to expect rate cases to go into effect in 2007 on Transco and Northwest pipeline. In the power space, we are having growing success in terms of completing midterm deals that reduce risk as we continue to see increasing deal flow.

So with that introduction, I will turn it over to Don.

Thank you, Steve, and good morning to all of those of you that are on the call with us this morning. First, I would like to say I'm pleased by our results which are on to ahead of plan, and I'm also pleased with the outlook for 2005, again, as it is on our plan to a bit ahead of our own plan. And I'm even more pleased with our outlook for 2006 and beyond as I think it is especially bright. I will quickly run through a summary of our second-quarter financial results and then turn it over to the business unit leaders to dive deeper into their results and to also refresh their guidance.

Let's now turn to slide number nine and hit some of the financial highlights. Income from continuing operations for the second quarter of 2005 totaled $40 million, up sharply from the year ago. Net income of $41 million, or $0.07, does include the impacts of both nonrecurring items and mark-to-market accounting. Eliminating the nonrecurring items, we move to $0.11, and then eliminating the effects of mark-to-market accounting we move up to $0.17. And I'll walk through the components of the changes of nonrecurring as well as the mark-to-market adjustments in just a moment.

On a year-to-date basis for 2005, income from continuing operations totaled 243 million, net income 242 million, both up sharply from a year ago, and totaled $0.41 for the current period. Again, with recurring at $0.45 and recurring income from continuing operations after mark-to-market adjustments -- really our most important measure -- that $0.39 up sharply from the $0.17 a year ago. Last, I would just like to note that Regulation G requires us to reconcile to GAAP, and those reconciliations are included in this package and on our Website.

Next slide please, number 10. I will now walk through the calculation of recurring income from continuing operations. Starting with income from continuing operations for the second quarter of 40 million. The nonrecurring items include impairments totaling $53 million, expenses related to prior periods totaling $22 million, gain on sale of assets totaling $9 million, and other of 14. The total nonrecurring items are $36 million pretax. A $10 million tax effect brings us down to the $66 million recurring earnings, or $0.11 per share.

On the next slide, slide number 11, please, I will walk through the calculation of recurring income from continuing operations after mark-to-market adjustments, really focusing on the mark-to-market adjustments which eliminate the cumulative effect of non-cash mark-to-market accounting which distorts our power business earnings.

Again, looking at the second quarter of 2005, starting with the recurring earnings of $66 million, or $0.11, that we just reviewed. Now let's take a look at the mark-to-market adjustments. First, we reversed forward unrealized mark-to-market gains. These are gains that were booked in the current period as the value of various energy commodities changed. These were non-cash earnings, and so we are backing out $22 million pretax. And then we're adding back realized gains from mark-to-market that was previously recognized.

Again in prior periods, gains were taken and in the current period those reversed as those positions settled, and that was a non-cash expense totaling $77 million in the current period. The net of that is $55 million. If we add back to earnings on a pretax basis, tax affecting that it comes down to a $34 million addition to earnings, which leaves us at about $100 million, or $0.17 per share. And you can see the calculation for the prior periods as well as year-to-date, and there are fairly sharp swings in the mark-to-market items, and therefore, the mark-to-market adjustments. And again, the bottom-line recurring earnings after mark-to-market adjustments is our most important measure that really provides the greatest transparency into our earnings power.

Next slide please, number 12. Let's walk through some key elements of our summarized income statement. First, segment profit, which does include nonrecurring items and does include mark-to-market adjustments totals 256 million as compared to 304 million a year ago. And the big story there is really around base improvements in the operations offset by mark-to-market impacts and nonrecurring items. And I will outline those for you as we walk through some subsequent slides.

As a result of our debt reduction efforts over the last two years net interest expense is down sharply. Let's now turn to slide number 13 and we will review second-quarter segment profit both on a reported and a recurring basis. Note that power's results include mark-to-market accounting effects which I will highlight here. E&P Midstream were up, gas pipe is steady on a recurring basis, and power needs some more explanation. Focusing on the first total there, segment profit on a reported basis for the current quarter -- again, the 256 million we saw in the income statement doesn't compare all that favorably to a year ago at 304 million. But as we move across and down the page I will try to provide some clarity to that.

On a recurring basis, that 256 becomes 301 million and the 304 becomes 319 million, and then the mark-to-market adjustments that we make adds 55 million to the current period. It would deduct 59 million from the reported amounts in the prior year to end with a sum --- again, the important sum -- segment profit after mark-to-market adjustments of 356 million versus the 260 million, up about $96 million, or 37% year-over-year.

The last line, power after mark-to-market adjustments makes the same adjustments to eliminate mark-to-market accounting for the power business. And you can see in 2005 we had a small loss of $7 million which was lower than the loss in the prior year. The second quarter is a seasonally weak quarter for the business, and Bill will talk more about power in his presentation.

The next slide, number 14, let's review the same data on a year-to-date basis, and I will focus principally here on the recurring. You can see recurring segment profit at 801 million as compared to the 594. And adjusting for mark-to-market, we have a result of 748 million versus 647 million, an improvement of about $100 million, or 16%. Power after adjustments for mark-to-market is an 11 million profit versus 65 million a year ago; however, power's results a year ago included gains associated with legacy positions that were liquidated as we restructured the business.

The next slide, please, number 15. Let's review some major changes in our segment profit quarter-over-quarter -- again, starting with recurring segment profit of $260 million. E&P drove a $63 million increase and Midstream a $27 million increase, and our business unit leaders will walk through the changes in more detail in their presentations.

The next slide, please, number 16. I will walk through key cash flow elements and balances. We began the quarter at 1.210 billion if cash. We had 489 million of cash flow from operations. Capital spending totaled 294 million. The dividend totaled 29 million, and that will be up somewhat next quarter as a result of our recent increase in the dividend. The total change in cash was a positive 87 million. The ending unrestricted cash balance was 1.297 billion at the end of the quarter, with restricted cash of about $100 million.

On the subject of the cash balance, the 1.297 billion, I think it's somewhat higher than some of you may expect; it is up a bit from where we were a quarter ago. I would normally target the cash balance, including international, at, say, 700 million to 950 million. However, some unusual items and growth opportunities caused us to maintain higher balances. And I've detailed some of those for you in this footnote to -- includes international cash of 185 million, cash to settle legacy matters including the tax settlement Steve already highlighted at about 200 million, and something we highlighted a couple of quarters ago, the Alaska Quality Bank judgment at 180 million. And we're hopeful that that Alaska Quality Bank situation may improve somewhat for us.

Slide number 17, debt. I would just like to focus on the third highlighted area there. Debt balance at June 30 was 7.744 billion with an effective rate of 7.5%, and more than 90% of our debt is fixed rate. In the appendix to this presentation, we have a schedule that provides some guidance on interest expense because we have other elements of interest expense in addition to our long-term debt. So I would encourage you to take a look at that in developing your models regarding interest expense.

As I previously indicated, accelerated debt reduction is no longer a priority as we have much better opportunities to invest excess cash to create value for our shareholders while continuing to improve our credit metrics and ratings. Yet, having said that, it is our intention to continue to improve those credit metrics and credit ratings, ultimately seeking to achieve an investment-grade rating.

With that, I will turn it over to Ralph.

Thank you, Don. I appreciate it. I'm pleased to report a very strong second quarter for E&P. Our volumes increased in all basins. Profit more than doubled. We had a significant increase in our Piceance Valley drilling locations and our problem possible (ph) inventory. We entered the Fort Worth Basin and we're increasing our guidance.

Let's turn to slide number 20. Segment profit, as you can see on second quarter to second quarter financial highlights; our volumes increased 17.5%. Our net realized price increased 35% and recurring profit was up 115%. Looking first quarter to second quarter, our segment profit again increased by 23% and our volumes increased over the first quarter by 6%. So a very strong quarter operationally for us.

Looking at slide number 21, this is an update to the slide I had the first quarter that I showed in May for the first quarter results. It shows again our volumes are increasing. Domestic volumes continue to grow. Our second quarter 2005 volumes are averaging about 16% greater than the average for 2004. We continue to show very strong growth in volumes, as this slide depicts.

Slide 22, some of the accomplishments. And some of these I will talk about more in just a minute on follow-up slides. Volumes were rising or did rise in all core basins. Big George gross production is up to about 110 million today, and I have a slide on that. San Juan hit record production of 152 million a day, so a good performance by the San Juan team. I will talk more about the Piceance Valley location inventory and probable reserves increase.

We have 11 rigs operating in the Piceance Valley, four in Trail Ridge and Ryan Gulch. Next week we will add two more rigs in the Trail Ridge and Ryan Gulch area, so we'll actually have 17 rigs operating in the Piceance Valley. None of these will be the H&P, Helmerich & Payne, rigs which are on schedule to start delivery in November 1. So we have been able to increase our rig count in addition to the H&P. So we should have 17 rigs running in the Piceance Valley area and up on the hillside in the Trail and Ryan Gulch area within a week. And then obviously, starting November 1 Helmerich & Payne will start delivering one rig per month for 10 months to us. And we entered the Fort Worth Barnett shale through an acquisition of land and some production. And I will talk a little bit more about that.

Slide 23, Piceance production growth. Just to show you graphically what's happened in the Piceance. We are up 100 million a day, or 48%, over a year ago looking quarter-to-quarter. And if you look sequentially from the first quarter to the second quarter, we are up 28 million a day, or 10%. So very strong growth in the Piceance Valley area.

Looking at the Big George on slide 24. Again, impressive performance by the Big George. The coal area is really starting to respond. Over a year ago volumes were up 48 million; today, as the slide depicts, they're 78%, and quarter-to-quarter we are up 25 million a day, or 29%. Big George production on a gross basis for Williams is 110 million a day now. That is up from approximately 85 million a day in the first quarter. These are all operated -- all the Big George production is operated by Williams, so we have a substantial expertise in the operations side of the Big George coals. And we are looking forward to our partner's production also starting to kick in in some of their pilots also soon.

Also, for the first time I mentioned in the first quarter that the Big George production was essentially the increase was starting to offset the wide act (ph) decline. And the second quarter did offset the wide act declined. So the Big George incline is clearly offsetting the wide act decline; not by much, but the trend continues to be very positive for us and it did offset it by about 4 million a day in the second quarter.

On the permitting side, just briefly, in the big George area, we do feel we have about almost 87, 88% of our permits for the remainder of this year in hand already. And we are getting a good jump start on next year's permitting, more in about the 45 to 50% range for the next year's permitting.

Looking at slide 25, we had an extensive review, as I've mentioned before, in-house for quite a while by a geologist, our reservoir team, our land personnel, to reassess our few future bottom hole locations in the Valley. After looking at that, we then -- finding all the bottom hole locations that were possible, we then looked at rock quality, land, topographic, the challenges that we might have out there and the drilling reach capabilities of not only our existing rigs, but the new H&P rigs. That study has resulted in, as Steve mentioned, an additional 1600 locations in the Piceance Valley and approximately 1.5 Tcf of additional probable and possible reserves.

So as you can see from this slide, our year-end proved reserves domestically were 3 Tcf, and that stays the same. That will be updated at year-end, obviously, as we get through this year's drilling program. And we have estimate at the year-end '04 that we had 3Ps, or proved, probable and possible reserves of 7 Ts. And you can see now by this graph we have increased that from 7 Ts to 8.5 Tcf. So bottom line, that is a 37.5% increase in our probable and possible reserves. It's an increase from 4 to 5.5 Tcf. Our new drilling rigs that we will have coming on, and some of the ones that were we are reworking, will have the ability to access some of these additional locations as mentioned in this slide.

And I would like to stress that this does not include Trail Ridge, Ryan Gulch and Red Point, or a new area we spudded just immediately north of the Parachute area. Parachute is one of the three fields in the Valley which we call Allen (ph) Point. None of those are included in this, and those -- if those resource potentials would work out, then our total reserve exposure at some point in the world, if they were to work out and if they moved to 10-acre spaces as I mentioned before, then the 8.5 Tcf could increase substantially somewhere into the 12 to 15 Tcf range. But I would stress again we've just started drilling these areas. They are in the Piceance Basin. We like what we see, but they are new areas for us that we have been drilling, so we're not counting any of those in our reserve inventory at this time.

Slide 26. We did enter the Fort Worth Basin; 13,000 net acre position; proved reserves of 17 Bcf, with probables and possible reserves of 40 to 50. The area we entered has high working interest. It's primarily in Johnson and Denton counties, mostly in Johnson County, in the fairway of the Barnett Shale. We believe it utilizes our Midcontinent horizontal drilling expertise. As you probably recall, the Midcontinent team which will be handling this -- this will be handled solely by the Midcontinent team -- really has no impact on our Piceance or Powder or San Juan operations. This will be picked up by the Arkoma team. We have drilled over 150 horizontal wells in the Arkoma, so we feel we have the expertise to compete and to do very well in the Barnett area.

Also, there are numerous bolt-on opportunities in this play that continues to grow significantly. The acquisition was $40 million. It is subject to post-closing adjustments, so that number could go down somewhat, but it was overall 40 million at this time. We have drilled two wells already in the area. We have a two-rig drilling program that we are planning. We have one rig operating currently and our second rig will be delivered in late September. So we will have access to two rigs beginning late September. We're currently drilling with one rig. We are excited that the Midcontinent team has been able to enter this and looking forward to further expansions in this basin as they work out for us.

Slide 27, hedge update. The bottom part of this slide is the new part; the upper part is the old fixed-price NYMEX hedges that we have and also the collars. As you can see, and I would stress, these are regional numbers, so they're not NYMEX -- they're NYMEX related, but they're at the location of Northwest (indiscernible) or El Paso, as you can see on the slide. We put in a collar for 50 million a day for the fourth quarter of 2005, and then 50 million a day for 2006 for the entire year, and that's at Northwest Pipe price level. And you can see another 50 million we added on for 2007 for a total of 100 in 2007 at the El Paso, San Juan and Wamsutter; 50 at San Juan and 50 at the Rockies. So I just want to stress as you look at this and compare that these are not the NYMEX related prices as they are; they are the actual basin-specific prices.

Finally, we have increased our guidance; this would be slide 28. As you can see our segment profit up, that is primarily to the Fort Worth acquisition, or the Barnett shale acquisition, as well as using the floor price of the new hedge collars. We also increased the capital spending; primarily that was for the $40 million in '05 acquisition and approximate development spending of 35 million this year and about 35 million in '06 for the Barnett, and a slight increase for the Barnett in '07.

Production guidance has increased also. Just to let you know, for the unhedged part of our volumes, the price assumption that we've had consistently through this planned forecast remains the same. And obviously, as you look at our numbers and our projections going forward, you can adjust that price assumption as you would like to. As you know, those prices listed at the bottom of this slide are significantly below the current market curve, which I believe is more like 840 or 830 in 2006 and about 790 or so in 2007.

Looking at our key points on slide 29, we are continuing to deliver very meaningful volume growth as we mentioned on the first slide. Our volumes were up substantially, 18%, just year to year. I think our talented workforce is really paying off. A history of very high drilling success and low finding costs. Maintaining the top quartile cost efficiency position. The recent FAIC study of industry peers put us again very firmly in the top quartile of efficiencies in terms of operating and G&A per Mcf produced. That's the seventh consecutive year we have been in the very top of the top quartile. And our long-term repeatable drilling inventory continues to grow; as we mentioned, the 1600 additional locations in the Piceance Valley, and none of those include the new opportunities that I have mentioned before.

So we feel very good about our quarter and our outlook going forward, and I will now turn it over to Alan Armstrong of Midstream.

Thanks, Ralph, and good morning. Pretty simple story for Midstream this quarter. You're going to hear about strong near-term results, increasing guidance, and a glimpse of the growth that we expect here in the future.

Going on to slide 31. Midstream produced another strong quarter, yielding a 33% increase from last year's second quarter. And year-to-date we are up 24% over our 2004 performance. The $27 million quarterly improvement was driven by a $16 million domestic NGL margin improvement and a $13 million improvement from higher fee-based revenues. So we are excited to continue to see our fee-based business grow, as that is a foundation for all of our business. Most of this was driven by higher gathering and processing volumes from our western region services.

Our NGL production volumes were flat quarter to quarter. Growth on this number was hampered by some nagging power outages at our Opal plant. We have since worked with our power group to install some large power generation units that get us off of the reliance on the local utility out there. So we think we have got that problem nipped. And proud of the organization both in the power group and within Midstream working so quickly to overcome that.

Similar drivers were responsible for the $46 million improvement in our recurring segment profit. The only exception to that is that our NGL volumes were higher year-to-date.

Moving on to slide 32. As stated, we're excited to see our gathering volumes continuing to grow. We were up 5% quarter-to-quarter comparison. Due to the continuing stream of well connect requests and midsize bolt-on expansion projects, we expect the steady increase to continue.

The two new projects that highlight the kind of opportunities that we are seeing out there -- first of all, Quintana Mesa in our San Juan Basin and the Wamsutter Phase I expansion are both backed by agreements with customers that we executed in the second quarter. These are low-risk projects that provide us nice incremental return. And in fact, these two projects will total just under $27 million in capital expenditures that will be spent through the balance of this year -- that is included in our guidance -- and will provide roughly $9 million of incremental operating profit on an annual basis once those projects are started up. So, nice incremental cash flow and profit off of those businesses.

We did see our recurring segment profit plus depreciation decline, as you can see on this slide, from the first quarter to the second quarter, despite these inclining fee-based volumes. And this was driven -- it's very simple. It's driven by $15 million in lower NGL margins and $17 million in lower olefins margin. And thankfully this was offset by some of the higher fee-based revenues that I spoke about.

Finally, I think it's important to note that we also raised an additional $55 million in pretax cash from the sale of a portion of our Gulf liquids business and our remaining 2% interest in the (indiscernible) Seminole Pipeline. We did recognize a nearly $9 million gain on this latter sale; that was not included in Midstream segment profit however. I think we achieved a nice price for those assets, but that is not recorded here.

Turning on to 33. Shows our guidance. We are excited to be raising guidance for the sixth consecutive quarter. This $25 million movement in the midpoint is pretty simple. It reflects another quarter of above five-year average margins and our knowledge of the current margins that we're experiencing here in the third quarter. If we did see a repeat of year-to-date margins in the third and fourth quarter, we should hit the top-end of this range. And the upside to this range would likely be driven by a couple of things. First, improved olefin margins. We did see a softening of our olefins margins in the second quarter. And then the other factor that we are waiting to see how that comes out is some higher deepwater production handling from the Goldfinger and Triton prospects. Our forecast has this production to begin flowing across our Devils Tower facility on October 1. And that is proceeding -- that is looking like that may come in a little earlier if things continue and we don't have any weather out there, and pending the construction out there.

So we are pleased to announce another significant increase in guidance for '05. But really the most exciting news that I have to offer today is the great growth opportunities that are maturing as a result of all the increased drilling activities around our assets.

On the previous slide, I mentioned two midsized expansions in our western region, but we are also finalizing agreements and seeking approvals for about $250 million of major expansion projects that are not included in the guidance, neither in the segment profit or in the capital spending guidance. The majority of this capital would be spent in '06 and '07, and about half of these projects are in the west and about half are in the deepwater Gulf of Mexico.

On top of this, we have an additional $250 million of projects that we are currently pursuing and we believe we are well positioned to win the business. Of course these are not as far along as the ones previously mentioned. And a lot of things have to fall into place with that, but we do feel like we are well positioned to capture that. And these opportunities, a second (indiscernible) of $250 million, is also split between the west and the Gulf of Mexico.

And finally, there is another roughly $600 million of capital projects that are mostly in the deepwater that are in the development and proposal stage. Certainly, lower probability of success on those, but plenty of things that are in the pipeline. This capital and this last tranche would probably be '07-'08 kind of spending, but really just wanted to highlight that for the sake of explaining how rich our pipeline is in terms of growth opportunities in Midstream right now.

So we expect to be raising both capital and operating profit ranges as a result of these new projects in the future. We haven't done that yet because we haven't got those projects finalized. These projects all offer returns well in excess of the current acquisition market, and so we're very pleased to have so much organic growth opportunities in our core lines of business.

Moving on to 34. This is just an overview, just to kind of give you an idea of what is going on out around our Devils Tower area, and really to reinforce the optimism that we have for our deepwater business plan. The candidates for connections to our Devils Tower platform, Canyon Chief gas and our Mountaineer oil line are all shown here. Some of these will provide new investment opportunities and some will be tiebacks to Devils Tower that provide strong incremental cash flows without requiring additional capital investment; similar to the Goldfinger and Triton tiebacks which are in the final stages of construction, where we're not spending any capital but we will see some nice incremental operating profit from that.

Just to explain this map a little bit, the leaseholds that are already dedicated to our infrastructure here are shown in orange. Commercial discoveries that we think our infrastructure is well positioned to serve are shown in green here. So these are already drilled prospects, they are known to be commercial and are not dedicated or have the infrastructure declined yet. And finally, a few of the undrilled prospects that will provide the next generation of opportunities are shown in pink. The majority of these prospects require both oil and gas infrastructure, and as a result of this, we think we are well positioned to capture a significant portion of the future development.

In fact, the real story here in this picture is we believe there is more demand for platform space and production handling capacity than currently exists in this area today. And we're working hard to accommodate all these opportunities, but it will ultimately come down to which two or three of these prospects provide Williams with the best NPV (ph). So really the infrastructure is becoming very critical out here to the development of these prospects, and we are working hard with the producers to optimize both their reserves and the value of our infrastructure.

Moving on to 35. Really here on the key points it is the same consistent story we have been telling. Continued strong financial performance. The opportunities that we have been predicting for quite some time are really beginning to hatch as the drilling activity in the prolific basins that we serve are demanding reliable capacity additions to this well positioned infrastructure. And most importantly, I think, we have a very focused organization that will deliver this reliable service.

So that is it for Midstream. Very excited about both the current performance and looking forward to all the growth that we are developing in and around our assets. With that, I'm going to turn it over to Phil Wright, running (ph) our gas pipelines.

Thank you, Alan. If you would please turn to slide 37. Continuing to build on our strong first quarter, Williams' gas pipeline segment, which includes Northwest Pipeline, Transco and our one-half interest in Gulfstream, is reporting yet another strong quarter with segment profit of $165 million. That is $32 million ahead of the same period last year.

While this is supported by solid operating performance, it also includes the favorable impact of a prior period reduction of pension expense and the favorable impacts of adjustments arising from discontinuance of our firm sales service at the end of the first quarter. The nonrecurring item in the second quarter of last year is associated with the write-off of the previously capitalized costs incurred on the testing of our 26-inch Northwest Pipeline.

Adjusting for these nonrecurring items, gas pipes is reporting recurring segment profit slightly ahead of last year. And included in these numbers, the recurring numbers, are higher earnings of $3 million from Gulfstream and an offset due to the absence of $4 million in revenue related to the termination of the Grays Harbor contract which was effective January 2005 at Northwest Pipe.

Slide 38 please. We continue to make timely progress toward the completion of major projects we have currently underway. First is the $330 million 26-inch capacity replacement project on our Northwest pipeline, for which we received a preliminary order from FERC on May 31. This order grants FERC's permission and approval, subject to an environmental review, which we anticipate later in the third quarter, and qualifies the project for rolled-in rate treatment. As you will remember, this project is slated for a November 2006 in-service date and is the primary driver for the rate case we anticipate filing to be effective January 1 of '07.

Our second major project is the Central New Jersey expansion on Transco. This $16 million, 105 million cubic feet a day, fully subscribed project is scheduled for a November 2005 in-service date. Construction on this project began in July and we're on schedule to get it in service on time.

In early June, Gulfstream began pulling (ph) volumes under two new long-term firm contracts that totaled 400,000 dekatherms a day. This equates to a little more than 1/3 of the total capacity and it more than doubled our previous level of firm service.

Finally, Transco announced an open season which ends August 17 for additional firm service into the Greater Washington, D.C. market area. This is yet another example of the continued growth and related opportunities we see in existing markets along our pipeline. We have named this potential new project the Potomac Expansion.

Slide 39 please. As you'll note from this slide, we're increasing our segment profit guidance in 2005 by $30 million to reflect the 22 million of nonrecurring adjustments booked in the second quarter, as well as slightly stronger than anticipated earnings. Additionally, our DD&A amount has been decreased by $10 million to reflect the impact of certain assets that recently became fully depreciated.

I will save discussion of our capital spending changes for the next slide, but I will point out that as a result of new compliance projects in 2006, all of which we would expect to recover returns on once our 2007 rate cases are effective, we have upped our 2007 earnings guidance accordingly.

I would also note that we have not reflected the potential impact of a recent FERC accounting order that would reclassify certain Pipeline Safety and Integrity Act costs from capital to expense beginning in 2006. While we need additional detail and guidance from FERC to pin down the impact, the potential change could conceivably result in up to a $60 million onetime reduction in segment profit and a like reduction in capital in 2006. This is an outside worst case estimate and should be substantially lower. We've asked FERC for clarification on the treatment of these costs, and I should note the Interstate Natural Gas Association has filed for rehearing of the order. So we will be able to provide greater clarity on the issue when such guidance is received.

Turning to slide 40. As we completed the data gathering needed to prepare our 2006 capital budget, several of our major safety and integrity compliance categories were shown to require a higher level of maintenance capital than we had estimated in the long-range plan. Accordingly, we have increased our total capital guidance for 2006 by a range of 125 to $150 million. Again, because of the timing of these expenditures -- just ahead of the effective dates of our rate cases -- we would expect to recover them with our allowed return.

On slide 41 please. Wrapping up, I continue to be pleased with the financial results that the gas pipeline segment has been able to achieve and we continue to deliver strong cash flow back into the Williams organization. Due to the strong financial performance of our segment for the first six months, coupled with the nonrecurring items, I'm also pleased we are again able to increase our earnings guidance for 2005. As always, we remain focused on our compliance and reliability projects and see some very likely development and expansion opportunities on the horizon, as evidenced by our recent open season announcement on the Transco system.

With that, I will conclude my remarks and turn the call over to Bill.

Thank you, Phil. Good morning. We are now on slide 43.

Despite a significantly cooler second quarter versus a year ago and rising natural gas prices, our power business performed as planned, resulting in a quarter-over-quarter improvement of 8 million in recurring segment profit after mark-to-market adjustments. Quarter-over-quarter gross margins were lower due to changes in mark-to-market accounting.

When you adjust segment profit after mark-to-market for expenses related to settlements and litigation contingencies, we achieved a quarter-over-quarter improvement in recurring segment profit after mark-to-market. The difference in year-over-year results is attributable to the absence of a $65 million gain in legacy gas positions realized in 2004. As with the interest rates in crude and refined products businesses, our legacy gas positions have been reduced so that they are no longer material.

Slide 44. Year to date on a reported basis, power's cash flows are 85 million positive. Due to a change in working capital, power's stand-alone was a user of cash in the second quarter. However, as you will see in a few slides, the base portfolio of cash flows were positive and on plan. Also, please note that year-to-date power stand-alone cash flows of 30 million include reductions of 25 million in nonrecurring adjustments.

Slide 45. Our segment profit guidance and cash flow guidance remain unchanged during the guidance period. We are reducing our reported segment profit after mark-to-market by 25 million to reflect the impacts of nonrecurring items I mentioned earlier.

Slide 46. This is the updated tutorial slide which reflects how the base business is performing for the quarter and the year. As you can see, total cash flows were spot-on for the second quarter and for the year. The $16 million loss in natural gas and others reflect a timing issue that we were injecting gas into storage in April and May. These cash flows will come back in later periods. The SG&A and other variance is to do the impacts of nonrecurring items. Power's stand-alone cash flows in the second quarter were impacted by changes in working capital. Even so, if you adjust the year-to-date cash flows for the 25 million of nonrecurring items, we are 10 million favorable to plan for the year. Again, this is despite cooler than normal weather and rising gas prices in the first half of the year.

Slide 47. In summary, our results are on target and we remain a contributor of cash to the Company. The power business is seasonal, and assuming normal summer weather we expect to achieve our targets. We continue to see increasing interest from customers and have closed several shorter-term deals during the quarter. We are actively pursuing deals to further hedge our portfolio. You may have noticed in Megawatt Daily that Kleeco (ph) announced they expect to file a contract between us with their PUC this month. We expect to be in a position to talk more about the deal next quarter. And many, including ourselves, are becoming more bullish of the power markets in the years to come as supply and demand seem to be tightening faster than expected.

Thank you and I will now turn it back to Don.

Bill, thanks for battling through that with your cold. I will next turn to slide number 49 please. Let's review updated 2005 guidance. Prior guidance is on the right side of the page. I'm going to focus my comments on the bottom line.

Again, diluted EPS recurring after mark-to-market adjustments, $0.70 to $0.90. And that's up from $0.65 to $0.90 from three months ago. We have raised the lower-end of the guidance by $0.05 and tightened the range. I would say additionally our confidence is even greater that the results will likely fall within this range, and I encourage you to review your own estimates carefully in light of our increasing confidence on the $0.70 to $0.90 range.

Next slide please, number 50. 2005 to 7 segment profit on a reported basis. Again, focusing on the bottom line -- the business unit leaders have taken you through this in each of their presentations -- but on the bottom line, total after mark-to-market, 1.375 billion to 1.660 billion. This year growing to 1.640 billion to 2.65 billion by 2007. Very strong increases and the changes have been previously reviewed and I will look at a summary of some changes in just a moment.

Next slide, please, number 51. 2000 segment profit on a recurring basis; and again, focusing on the total after mark-to-market adjustments, again you can see the elements of that and the growth that we have previously indicated. On a recurring basis, that total is 1.410 billion to 1.695 billion, and power totals 50 to 150 million on a recurring basis after those mark-to-market adjustments.

The next slide please, number 52. Again, the business unit leaders ran through their respective business unit capital guidance. I will focus on the total. You can see the total spend is up in 2005 as well as 2006, principally as a result of the Fort Worth entry and drilling in 2005 and 2006 and beyond, as well as the gas pipeline new 2006 projects.

Next slide please, number 53; 2005 to '07 outlook, including some key financial items. We spent some time already on segment profit. As you can see, DD&A continues to increase as we continue to invest in the business. Cash flow from operations is down a bit in 2005 and then up in 2006 and '07. As Steve previously mentioned, the tax settlement will impact 2005 by nearly $200 million. As well, we reclassed from cash flow from operations to other investing nearly $90 million. Offsetting that we had some underlying operating improvements. 2006 and '07, I will review the changes in those in just a moment. Capital spending is up for the reasons we just mentioned, and then operating cash flow is reduced as a result of the foregoing.

The next slide please, number 54. This is a new presentation in order to provide some additional transparency and to summarize some of the information that you have already heard. I will highlight some of the key changes in guidance. First, capital expenditures. Focusing on 2005, guidance was 1.25 billion to 1.225 billion. As Ralph indicated, we made investments to enter the Fort Worth Basin and we will follow that with drilling. That will add $75 million to our capital spending this year. Following that down to segment profit, starting with 1.375 billion to 1.675 billion from a quarter ago, adding in the impact of the Fort Worth entry -- only $5 million this year, and it grows in 2006 and beyond, as well as adding the impact of the hedge collars that we added. And that would be to take our assumed price deck and move it up to the floor of those collars. That added $5 million for the balance of 2005. Midstream -- strong margins during the quarter and through this date add 20 to 30 million to our segment profit; nonrecurring items subtract 44 million to get to the new total.

Moving on to 2006, I'll just again highlight some of the changes. The E&P Fort Worth entry adds 35 million to capital as we drill those opportunities. Phil highlighted some new 2006 projects in gas pipelines totaling about 125 to $150 million; gets us to a new CapEx number in 2006. Following that down you can see the Fort Worth basin entry adding 20 million of segment profit, the hedge collars 20 million of segment profit and reduced risk.

I would also note that the gas pipeline new 2006 projects, the 125 to 150 -- you can see that down below in the 2007 column, and I will just get to that in a second. So focusing on 2007, no changes in capital spending, segment profit. Again, E&P, Fort Worth, and E&P hedge collars contributing 20 and 25 million, respectively. And then the investments that gas pipeline makes in 2006 begin to provide a return in 2007. So those are the key elements to the changes in our guidance for capital expenditures and segment profit.

On the next slide, number 55, I will review the changes in cash flow from operations from May 5 through this date. And again, focusing on 2005, we started with 1.3 billion to 1.6 billion; the tax settlement that we mentioned of 180 to $200 million; a reclassification to investing deducting $88 million; the E&P segment profit increase of 10, Midstream of 20 to 30, gets us down to our new guidance. And then the same types of items impact '06 and '07 that we previously reviewed on the prior slide as well as this slide. The tax settlement this year will increase cash flows in future years by 20 and 25 million, respectively. The E&P segment profit increase moves up 40 and 45 million to get to the new totals.

The next slide please, number 56, is a graphical depiction of our expected strong operating cash flow growth, our increasing investment opportunities, and our improving credit metric debt to total cap. As Steve and our business unit leaders have indicated, we are opportunity-rich and we expect to develop additional very attractive reinvestment opportunities in our core natural gas businesses. Therefore, we would expect that CapEx would grow somewhat from that, which is charted on this graph. And you can see the light dotted line over on the right that indicates perhaps directionally an increase in capital spending that we would expect to be forthcoming over the coming quarters as we seize those terrific opportunities.

The next slide, number 57, again just depicts graphically our segment profit guidance after mark-to-market adjustment. And you can see 2005 over 2004 is a 20% increase. 2006 two-year increase, nearly 15%. And the three-year compounded annual growth rate of about 14%, and leaving segment profit at the end of that period in the range of 1.6 billion to $2.1 billion.

Finally, on slide number 58 I will highlight a few key points. First, we will continue to drive and enable sustainable growth in EVA and shareholder value. We will maintain a cash and liquidity cushion of $1 billion-plus. And as I indicated earlier, we are quite a bit above that, but we have some specific reasons for that. We will continue to steadily improve our credit ratios and ratings, ultimately seeking to achieve investment-grade ratios and ratings. We'll continue to reduce risk in our power segment, generate positive cash flows. As we previously mentioned, we are opportunity-rich. We're increasing our focus on disciplined, EVA-based investments in our core natural gas businesses. Such attractive EVA-adding opportunities may require new capital. And if new capital is needed, we will make the optimal decision. And we have many sources of such capital, and we believe that the combination and growth in operating cash flows in EVA will drive strong value creation.

And with that, I will turn it back to Steve.

Thanks, Don. Summarizing with slide 60. I truly believe that we are hitting on all cylinders. We have raised our guidance. Cash flows continue to be very strong. We are seizing on rich opportunities to grow. You should keep in mind that the commodity price environment continues to be very attractive to our businesses currently, and that environment is expected to continue to be attractive for some time. The Piceance Basin story is even stronger with the identification of 1600 incremental drilling locations. We're seeing impressive performance from the Big George volumes. We have entered into a new basin with our purchase of acreage in the Barnett Shale. Alan talked about the rich pipeline of growth opportunities out west and in the deepwater. Pipeline numbers continue to be strong. Power is on target. We are delighted with the results for the second quarter, delighted with our first half, and are very optimistic about the future.

With that, we will be happy to take your questions.

(OPERATOR INSTRUCTIONS). Scott Soler, Morgan Stanley.

I have a few questions and they really relate to assumptions in E&P and power, and I have one question, Don, on capital allocation. Ralph, on E&P, I wanted to understand that we understood the assumptions correctly on some of the reserve potential. These spacing assumptions I believe are on 20s, not 10-acre spacing, on the potential built into the numbers that you put out this morning. n.

The 8.5 would be us going to 10-acre spacing in our Valley location.

It would, okay.

That is in the Valley only though.

In arriving at those assumptions, will there be any discussion or has there already been with Netherland Sewell? Because it seems in the press release that is internal assumptions. I know that you all typically match up pretty well with Netherland Sewell.

We're typically within less than 1% difference. We will -- at year-end we obviously will relook at everything, but we have not run that by them. But I do believe it's very consistent with everything we have done in the past.

I've been doing some work on looking at what Exxon deems its potential in the Piceance, and I know they have what they consider to be pretty proprietary hydraulic fracturing technology. But their estimates have been about 150 Bcf of gas potential per square mile. And I remember, Ralph, at your primer day on E&P you talked about 100 to 120. Is there any change in the assumption of recoverability? And is that technology still proprietary, or is there something similar that can be replicated that might allow you guys to recover potentially more in the Piceance?

We are still using the 100 Bcf, so our assumptions are slightly lower. So that's -- to get to the locations and the new numbers you have seen, that is using 100 Bcf per square mile. We have seen their technology. We are partners with them. We have not used it yet. We were impressed with what they accomplished and we look forward to utilizing that opportunity. We also are working with our service company, Halliburton, on the Cobra Max (ph) technique. We have just done one well with that. We are going to do another couple. And that's a similar technology. And we are also impressed with the first well's result. None of those results are -- one, we haven't done enough to change any of our assumptions yet; but two, we will -- we liked enough of what we saw that we look forward to using it more and seeing if that can change any of our assumptions.

Last question for you, Ralph. On initial well testing, is there any update on Trail Ridge and Ryan Gulch and those plays close to the Piceance? Are those things that you all have -- you just briefly alluded to it, but is there any update on any of the initial well testing that is going on?

We will give that soon. What we have done -- we've just gotten back in the field based on we wanted to drill as much in the Valley as possible to catch up from the poor weather we had in the first quarter. So we really have just moved up into Trail and Ryan in the last month. So we're spudding our wells up there as we speak and actually drilling. We will get those wells online soon. And then, I assume no later than the next call, we will give the initial results from the handful of wells we drilled last year, and the initial very early results from the wells we are drilling this year. But we have moved up there. We waited a little longer than normal just to try to make sure we could catch up on volumes in the Valley first.

Bill, (indiscernible) we met with two of the California commissioners last week when they were in Austin for NERUC (ph), and I got out of that that power reliability was probably about 80% of their concern of all their four or five key energy issues right now. What I guess I wanted to understand is of your megawatts in Los Angeles, I think there's about 3400 megawatts that potentially could get either some sort of RFP with SoCal Edison or potential capacity payments as that market develops into a capacity market. It sounds like by early to mid '06 they have to have something in front of Schwarzenegger. Could you perhaps provide a little bit more color on that?

Sure, Scott. Hopefully my voice will hold out through the answer. Clearly, reliability is the major issue that California is facing. And unfortunately there's nothing they can do in a very short timeframe to deal with it. We currently have long-term contracts running out to 2010 with CDWR that occupy about 1800 of our megawatts. On an expected basis we can produce around 3600. So we do have 2000 megawatts that are available to either enter into long-term contracts with the utilities, which we are certainly in discussions with, or as capacity markets do develop, which we believe they will probably in late 2006, 2007, we would certainly benefit with those megawatts from the capacity markets.

I just have two very quick questions for Don and Steve. Thanks for your patience. Don, your dividend has now been rebased to 7.5 cents per share per quarter, and your internal rate of return on particularly these E&P projects is at 50% or better by our estimates on most of the four key plays that you have, or now five with Barnett. Could you talk a bit about reinvestment opportunities versus the dividend? Because you're going to be in a pretty favorable free cash flow position in '07 and '08, and yet a lot of guys on the call today have outlined different projects across businesses.

Scott, we will continue to very thoughtfully balance the use of our free cash flow, and certainly thought it was prudent at this point in time to increase the dividend, in part because of our strong operating cash flows, the very bright outlook, and the confidence we have in our future cash flows. As far as looking forward, certainly to the extent that we have a strong point of view that the opportunities deliver a return that exceeds our cost of capital by a nice margin, we would seek to make such investments in our core natural gas businesses. We will use the free cash flow to make such investments. And to the extent that we have to access the capital markets to seize those opportunities, we will do so. And we will reexamine the dividend periodically along the way and try to make choices that are thoughtful and balance the interests of our various constituencies.

Steve, this is my last question. You all recently named Earl Ingerhart (ph) from Peabody to your board, which improves the independence of the board. That's a very good thing. I was curious though, and are we overreading into the potential maybe to do some partnering with Peabody in the Powder River as you are growing that area and Big George. It's a coal area. And I was just curious -- I don't know if I was connecting too many dots on that nomination to the board, but I was just wanting to see what you might have to say about that.

I think, Scott, that you may be as you say connecting too many of the dots. We brought Earl on board because of his experience and knowledge. And he is a guy who is very familiar with the trading environment, for example. Peabody has been a fairly aggressive participant in coal trading. He just brings a lot. He's a sitting Chairman, and we thought that was important to bring to our board. Whether or not that results in any joint opportunities remains to be seen.

Craig Shere, Calyon Securities.

A couple of questions. One, a minor issue that, Don, you may be able to clarify or maybe we can take it off line later. I was just curious if the second quarter last year was $0.03 or $0.04. I think there might be a little discrepancy between slides nine and 73, and we had originally had $0.03 in our numbers for comparisons. A couple of other questions.

Ralph, you had mention the possibility of 3Ps getting up to 12 to 15 There's, assuming the stepout areas turn out as attractive as the initially seem. What do you think you could do to expedite drilling with incremental rigs if that opportunity really develops? How do you see drilling rig costs evolving over time? And then I have two other quick questions for Alan and Bill.

Currently what we are running is we have about 12, 9 -- I'm sorry -- 11 rigs in the Valley and the other rigs are running up in Trail Ridge, Ryan Gulch and Allen Point area. We have just moved those up there. And what we hope to do is, as I mentioned to Scott, as we move through the drilling season this year and further solidify what we think are good positions up there, as we add the Helmerich & Payne rigs we will be exposed to approximately 26 rigs 10 months away from this November. So what we would look to do is continue a robust drilling environment in the Piceance Valley of, say, 18 to 20 rigs probably, and then take the balance there of five to seven rigs or five to eight rigs up in the Trail Ridge and Ryan Gulch area. So that would be a way to do that. We're set up to do that if they are as successful as we think they will be as we add these new rigs. And then on the drilling costs, we did -- we made the decision when we did our term agreements with Helmerich & Payne, and also as we termed up our neighbors rigs, to increase the drilling rates that we were paying. One is because we went for longer-term. But two, we believe as we bring the efficiencies into the marketplace that these rigs will accomplish that even though we will be paying more on a day rate, we will actually ultimately be more efficient because we will drill faster.

As you know and have seen before, 10 years ago or 12 years ago we took 28 days to drill a typical Piceance well, and we're now taking 15 days. To the extent we can -- at 25 rigs operating, if we can improve by one day, that is an additional -- one day per rig, that would be an additional 43 or so wells that we could drill with the same level of equipment. So we think the efficiencies added by these new rigs and by the new agreement with neighbors for example, and obviously the new flex rigs that Helmerich & Payne brings, although they cost a little more on a day rate, ultimately they will drive our costs down.

If you had eight to ten rigs working in the stepout areas and things were going well, what do you think could be happening to production estimates?

We're just not prepared yet to do that. But obviously, as we really give the results of what we think Trail and Ryan are starting to do, we obviously would hope for good things here. Let's get a little more experience and a little more wells drilled, and then we will be giving that guidance.

Alan, I was wondering if you had any comments on the possibility of a Wamsutter Phase II project. And Bill, I was wondering if you could give any comments about the impact of summer so far. Is it really looking better than normal for you? Is the rising spark spreads we've seen recently giving increased interest among power users for long-term contracts? And maybe are you seeing a lot more interest versus the last time you spoke at the New York power tutorial?

Craig, I will take that question. First of all, you're perceptive on the name of the Phase I. There certainly is Phase II that we are working to develop on Wamsutter. In fact, it would be actually quite larger than the Phase I, but that is why that was named Phase I. So I appreciate your picking up on that. Is there another question you had there?

I was just wondering on the prospects for actually bringing Phase II to finality, where that is actually going forward.

That was included -- I gave three tranches there. One that was near-term things that are just pending final negotiation and definitive agreement. And the second being things that were requiring further development. And the Phase II would be included in that second tranche. Having said that, we feel like it's fairly certain that it will happen in the future, but we really can't detail the size of it just yet because we are working with the producers to make sure we understand exactly what their needs are. So the needs are certainly there, it is just a matter of scoping it into more detail and getting agreement with the producers on that.

Do you think that is something you can make an announcement before the end of the second half?

It is likely that by the end of the year that we will have that wrapped up.

And Bill?

Craig, as far as the summer, I think it's important to remember the first half of the year was fairly well below normal. I think you have seen that in several power companies' disclosed earnings. July I would characterize as pretty much normal. You had some periods of extreme heat, but you also had some days where it was below normal. I think the key for us is usually September and how deep summer goes in California, which October can be a real important month for us. What we are forecasting is normal weather. Clearly, if it continues to get hotter that is a good thing for us.

We're clearly seeing more interest from customers. I think that is, again, a combination of our decision to stay in the business, but also the market is starting to move up. The challenge we face as we interact with our customers is we want to make sure we are getting fair value for our megawatts, and in effect not selling at the bottom. And I think we have been successful so far in getting fair value. But seeing a lot more interest. Still mainly short-term, one to three-year timeframes, but we are starting to get more discussions with customers five to 10 years out. We are excited about it. I think it's a good sign the market is recovering. And again, I'm hopeful over the next few quarters we'll be able to talk a little bit more specifically about some of our larger deals.

Maureen Howe, RBC Capital Markets.

I just have a couple of sort of I guess quick picky questions in a sense. On page 34, Alan, when you were talking about the Devils Tower platform and the ability to connect, say, Goldfinger and Triton without spending any capital, is it the producers then that are putting the capital up to tie in those platforms?

That's exactly right, Maureen. There's basically two different ways that things will be done out there. But generally when it's a tieback and there is no opportunity for us to aggregate volumes from different producers onto a flow line, we will let the producers make that investment because we don't really add much value in that sake. So that's a perfect example of where that has happened.

And would that be the case for additional tiebacks of other platforms going forward?

On the green prospects that you see shown on this, probably about half of these that would be shown on here would be tiebacks without incremental capital, and about half of them would have some incremental capital.

And then a question regarding the pipeline normal maintenance on page 40. And I guess is the increase in 2006 maintenance, which is pretty substantial -- is that just -- it looks like it is, but is it just the one-year phenomena?

Maureen, this is Phil Wright. A big tranche of those are in fact onetime expenditures. But you should be aware that our world changed very substantially when the Pipeline Safety Act became law. All interstates are going to have an ongoing internal inspection program that will have to be implemented, and those expenditures that are associated with Pipeline Safety and Integrity will to some extent be ongoing.

Among the more expensive parts of our implementation of these maintenance programs and integrity programs, you will recall, is the installation of launchers and receivers to put these sophisticated smart pegs into interstate pipelines, a great number of which were not configured to accommodate the sophisticated inspection tools. And as you get into the program and you begin digging up sections, you find from time to time overbends and fittings that won't accommodate those tools. In other words. you can't pass it by, so you have to put a launcher and scraper receiver in there that you didn't expect to have to put in. So that portion of course would be a onetime kind of an expenditure. But there is about five different major categories for which we saw increase. And I think once we get those up to speed, we would expect that to attenuate.

Do you think that the estimate for 2007 of 180 to 235 million is still reasonable?

We are still comfortable with that estimate range.

This is Don Chappel. Just to reemphasize that the silver lining in the gas pipeline business is we would expect that these new compliance expenditures and the like would be recoverable in rates. So it feels more like a growth project from an economic standpoint, deploying additional capital, getting a return of your costs and a return on that investment.

Perhaps before we go to the next question just to come back to Craig's question on the 2004 second-quarter earnings at $0.04 versus $0.03. I believe the $0.04 is correct. I can't quite tell you how we got the $0.03, but perhaps it was a rounding down. And Travis and his team can probably add a little more color after the call if you would like any.

Pearce Hammond, Simmons & Company.

Two quick questions for Ralph. First, can you provide an update on the Caney Shale, and how similar do you see that to the Fayetteville Shale and what your outlook is there?

We have drilled our third well there. The operated wells we have drilled we continue to be encouraged with. We're just moving into our fourth well, so I can't say if it's a look-alike yet to the Fayetteville Shale. There's been more wells drilled in that area than we have and I think the industry has in the Caney, at least from what I know of. So the update is we're continuing to drill ahead and look forward to a little more experience and a little more knowledge of what makes it work. And it will take some time to get there, but we do have a nice acreage position and we have a rig operating in the area. And at this point that's all I really can say because it's just so early for us.

Do you think we'll get some quantification maybe by the end of the next quarter or at least by the end of the year?

By the end of the year we will have some quantifications, some more wells down. And maybe the next call, but definitely the end of the year call.

Second question. With the XTO (indiscernible) deal with Exxon in the Piceance, do you see it becoming much more competitive for resources in the area and how will that impact you?

They are in the more of what I would call the hogback area of the Piceance. I think it's competitive for resources already. But as you can see from our contracts we have signed and other opportunities, we have been there quite a while. I believe that with our service companies, both the big and the small service companies, and with our drilling contractors that we are set up to secure the resources and already have the resources that we need to achieve our program. So I would guess the answer is yes, it will get competitive for resources. But I would also say the second answer is that we feel very confident we will have the resources we need available to us to make our drilling programs.

Faisel Khan, Citigroup.

Just a few questions on E&P. I want to make sure I understand the 1.5 Tcf increment on proved, probable and possibles. That just has to do more with your survey of the number of locations, not down-spacing or the ultimate recovery of those reserves; is that right?

This is just more of a complete look at the bottom hole locations, and then looking from there looking at the rock quality, the land, access and the ability to reach it from the various well pad types that we see. So it's not a change in the URs and it is for the Valley only.

And there is no down-spacing?

It does assume 10-acre spacing. We have about 35,000 acres already in the Valley that is downs-spaced. And we are assuming as we move into the other parts that aren't down-spaced yet but they're right next to the areas that are down-spaced that we would be able to get the 10-acre spacing.

For the quarter, was there any Barnett Shale production in your domestic volumes for the second quarter?

A slight amount. It may have averaged about 1 million a day. We didn't acquire it at the very start, so a very, very small amount. Probably not even quite that much average, since it wasn't done until the May timeframe.

And you're not disclosing the amount you paid for it or the (multiple speakers)

I did say $40 million. It is subject to some post-closing adjustments on some of the land. That number could go down. It would be a maximum of $40 million entry into the play. It could go down somewhat from there.

On a fully-developed basis?

I'm sorry; let me just say -- I'll back up. $40 million to get the land positioned in the existing reserves, as well as a small amount of production in the wells that are waiting to be turned on. And then we expect in addition to the 40 million -- which that number could go down because there are some post-closing adjustments that are pending out there -- we would extend about another 30 to $35 million this year on drilling as we get a rig program going.

Could you just give an -- I see your production for the quarter out of the Piceance and for Big George, but could you give -- usually you give a production by basin. Do you have those numbers available?

I don't know if we always give that, but I did say that the San Juan production is up to on a net basis about 152 million a day. And the Arkoma is approximately 20 million a day. And then our international volumes which are included in the overall volumes are usually around 48 to 50 million a day.

And the Powder River volumes, including (indiscernible)?

I think the net basis for Powder River is approximately -- it was between 110 to 115 million a day. I need to look at it. But right in that range would be very close for you.

And then on the power side, have you seen -- I know you were talking a little bit about this in terms of the summer cooling season, but have you seen incremental dispatching out of your Jackson facility and your PJM -- your facilities in the PJM territory, given the hot weather? Or are you seeing that they have kind of been flat?

We have seen additional volumes out of our Jackson Kinder Morgan facility. I think that's really more attributable to the new market design and (indiscernible) than to the hot weather. Our facility is located in a favorable location, so we are dispatching it more than we have historically. As well our Red Oak facility is running more than normal, but that is largely due to transmission constraints. The hot weather is causing some additional dispatch as well, but nothing significant -- not significant increases in either location.

In terms of the deal volume that you guys kind of reported in your May 12 meeting, you talked about how you're working on certain (indiscernible) option deals, capacity deals, and various other types of (indiscernible) sales. Is that deal volume still the same as it was when you talked about it May 12 or has that increased? What are you seeing on that front?

We are seeing more. I don't want to say it's doubled or tripled, but we are seeing considerably more interest. It's probably doubled since then. A lot of interest, and again in the shorter term, the one to three year timeframe. As I indicated earlier, the challenge is to make sure -- it's great more buyers are coming into the market, but that's usually a sign things are about to improve. So the challenge we face is making sure we get good value for our positions that we have. But I'm confident that we can accomplish that so we can get more longer-term sales off and still feel very good about the economics of the transactions.

On the liquids side and the Midstream side, NGL equity sales volumes were down quarter-over-quarter -- sequentially this quarter versus the first quarter. I was wondering if you can comment on what caused this sharp drop-off in volumes? What was the impetus for that?

Sure, two reasons. First of all, we have converted some of our contracts. As margins have been high we've been converting some of our business to fee-based business, and kind of taking advantage of the expectation of higher margins in the business. But probably more importantly as I mentioned, we had an outage due to several power failures at our Opal plant. And that is where a majority of our equity volumes are produced. And so that power outage that happened right around Memorial Day took us down about, I think, 8 to 10,000 barrels a day there for a while. And that is the primary driver in that. And that problem has been cured now though.

One last question. On your consolidated statement of operations, you have got a big swing into the first quarter to the second quarter in investing income. We didn't kind of expect that, -17.2 million versus a $31 million gain last year. What was the cause of that kind of large swing?

Why don't you give us a few moments to look that one up. We will take a look and get back to you in just a few minutes.

(OPERATOR INSTRUCTIONS). Jessie Loudon (ph), Zimmer Lucas.

My questions have been asked and answered. Thank you.

Nick McGann (ph), (indiscernible) Capital Management.

I just had a couple of quick questions regarding your improvement of your credit ratios. First off, do you guys have a tentative timetable to where you guys want to be at investment-grade? And second, what other steps are you guys undertaking to improve your credit ratios since you ceased to target that retirement?

This is Don Chappel. We would like to get there sooner than later, but we think that greater value is achieved by reinvesting in these terrific opportunities we have in front of us versus pointing those dollars at debt reduction. So we are willing to be patient, and we believe that the strong growth and operating cash flows will drive us to a place that allows us to ultimately get back to investment-grade ratings. Not to say that debt reduction might not be in the plan at some point in the future, but with the reinvestment opportunities we have on the horizon today it is less likely for the near-term.

Going back to the prior question on the changing in investing income that moved from the -$17 million this year for the quarter from 11 million in the prior year. The change was principally the Longhorn impairment that was included. The year-over-year change there is $38 million associated with that Longhorn impairment. Next question please.

Rick Gross, Lehman Brothers.

I have got some Piceance Basin questions. Ralph, if I did the math right, the incremental locations were going to add a little less then a b, which is different than the 1.3, 1.4. Is that a net versus gross, or is there something on the margin that you are booking differently on the incremental locations?

That's more of a net versus gross.

Okay, that's fine. The other issue is more infrastructure. As more and more people drill, it is my understanding that Piceance is going to be about 2.5 GPM. Are we going to get building of a large efficient plant NGL takeaway capacity that kind of situation as opposed to kind of the piecemeal building that we have seen to date, and can you be involved in that?

We would like to see that happen, obviously. I think it would be better to have one or two big efficient plants. Our Midstream group is fully engaged in not only working with us, but also working with other producers. So I would like to see that happen. I think it would be more efficient. You never know if all the producers will sign up and do something like that, but I think it is a more efficient answer. Alan, do you want to say anything about the (multiple speakers)

We certainly have been studying that and we think there's some real good opportunities there. As Ralph mentioned, it is kind of the level of commitment that you can get. Everybody is very focused on getting the gas out of the ground right now as opposed to really maximizing or optimizing. And so we are kind of looking down the road to the point where the basin optimizes. Very typical I would add of most basins when they are just coming up, you see a lot of small inefficient infrastructure, and eventually you'll see a major solution. And we certainly intend to be a part of that major solution.

Is that part of any of your we'll call it proposed potential spending? Is that -- it sounds like more like a solution of this sort or a deal of this sort is an '06 not an '05 kind of --

It is not in Midstream's capital. And it certainly would be an '06 and later kind of investment. A lot of the needs are being met right now by smaller facilities that are being invested in right now.

When we did our updated capital for the addition of the new rigs in the May call, we did have slightly over $100 million of facilities for E&P. That included in the increased CapEx that we went out, and that was about 30 million this year and about 80 million or so next year. So we've built some capital in there for our needs that we're proceeding ahead with. But again, that would not preclude an opportunity for a much bigger Midstream opportunity to consolidate the basin.

Maureen Howe, RBC Capital Markets.

Just a follow-up question on the dispatching out of some of the plants. We are seeing pretty strong spark spreads right across the United States, and not just at Williams, but other companies really aren't talking about capturing the benefits, at least through July, of these spark spreads. And I'm just wondering if, Bill, maybe you can help explain. What is happening here? Is it the inefficiency of powering up and powering down between peak and off-peak hours? Why aren't we seeing and hearing companies talk more, including yourselves, about the benefits of the current situation in the power market?

Maureen, from what I've read about other companies, the first year was milder than normal. So to get kind of back to normal you're going to need some hotter than normal weather in the second half of the year. In our case, you have to remember we are highly hedged. We have a lot of our facilities hedged. So we're not always going to see the benefits as prices increase that an unhedged party or pure merchant company would see. But clearly, the hotter weather is good for us. We have a fairly broad range in our guidance. And if the hotter weather hangs around, we will be moving to the upper-end of that range. I know it's August, but really September and October are critical months for us as well, especially on the West Coast. I guess I'm saying it's a little early to come out and revise forecasts or talk about how great the summer is going to be. But make no mistake; the hotter weather is good for us.

Just going on and coming back I guess to the issue of the credit rating. Are the credit rating agencies continuing to look at the merchant car portfolio the same way? Have they revised their approach? Is there any evolution there?

Maureen, I think they continue to move in a positive direction noting the progress that continues to be made in that space. However, they're generally several steps behind the market. So I think we will continue to see progress. We have seen progress to date, but they're going to be the last to move as things continue to improve.

Just one final question. I can appreciate pursuing capital investment opportunities if the returns are there; that makes a lot of sense. But I'm just wondering in light of that strategy and given where the credit rating agencies are today in their approach to looking at Williams, do you have any idea or even just a ballpark estimate of when you might return to an investment-grade credit rating?

Maureen, I hesitate to even throw out a guess. The range would be so wide that it wouldn't be all that useful.

But you don't think it's in the next couple of years?

I wouldn't want to speculate.

There are no further questions at this time. I will turn the conference over to Mr. Steve Malcolm for any additional or closing remarks.

Again, thank you for your interest. We are delighted with the numbers for the second quarter. We are very optimistic about our future and look forward to talking with you after the third quarter. Thank you.

That concludes today's conference call.