威廉斯 (WMB) 2004 Q2 法說會逐字稿

Good day everyone. Welcome to the The Williams Companies Analysts Conference Call. Today's call is being recorded. [OPERATOR INSTRUCTIONS] At this time I would like to hand the call over to Travis Campbell, Treasurer and VP of Corporate Communications and Investor Relations.

Thank you, good morning everyone. Welcome to our second quarter analysts call this morning. Today present with me is certainly Steve Malcolm, our Chairman and President, as well as Don Chappel, the CFO, and Ralph Hill, who is our SVP of Exports and Production, Alan Armstrong, who is over the Midstream area, Doug Whisenant who is over our Gas Pipeline area, and Bill Hobbs, who is SVP with our Power group, as well as there are others here. We have plenty of time today, but we'll take questions at the end of the call today, either on the phone, or those that are submitted through the web cast. All the slides that we're going over today are available on the web site in a PDF format for download. Looking at slide 2, forward-looking statements-- today our call will include some forward-looking statements. Please refer to that statement for information in this presentation and what is posted also on williams.com for further details on risk factors affecting our companies. There are also some non-GAAP numbers that are presented. Reconciliation of recurring earnings is included on the website, and is also attached to the press release which we released this morning. Reconciliation of EBITDA to earnings is also included in this presentation and on the web site. With that I'll turn it over to Steve Malcolm, our Chairman.

Thanks Travis. Welcome to our second quarter call, and thank you for your continuing interest in our company. As Travis described, our senior management team is assembled here in Tulsa, and most will be participating in the presentation this morning. We have scheduled plenty of time to run through our 68 or so slides, and then we will certainly take your questions. Let me begin with some of the headlines, or major highlights, that I would hope you would take away from this morning's call. Starting with slide number four, we are certainly delighted with the successful execution of critical components of our financial restructuring plan, all of which have strengthened our balance sheet. Several points that I would wish to make. First, with the sale of the Canadian straddle plants, we have completed the divestiture of the last major asset that we've been trying to sell. Secondly, we negotiated and enhanced new credit facilities with a $500 million unsecured facility which, will be used primarily for issuing letters of credit, and a 3 year billion dollar secured revolving credit facility. Thirdly, we entered into a 7 and 1/2 year agreement with IBM to outsource portions of our accounting, finance, HR, and IT groups, and that agreement eliminates much of the risk associated with our cost reduction plan. Fourthly, we settled refund issues with the major utilities in California, and very importantly received $104 million from those utilities in July. Fifth, as a result of asset sales, new credit facilities, and strong cash flow from operations, we've reduced debt by over $2 billion through the second quarter of this year and have announced another $800 million tender today. Sixth, we are certainly pleased that the ratings agencies have noticed our progress and acknowledged our progress. You've seen S&P revise the outlook to stable from negative. You have seen Moody's suggest our rating is under review for possible upgrade. So those are positive steps. Finally, I would mention there is no updated news with respect to power. We continue to seek to exit the business, but as I have expressed previously, I am not optimistic about our ability to do so in the near term, given current market conditions.

Turning to slide number 5, Don will certainly provide more information, but we did deliver solid second quarter performance. Although our reported earnings were negative due to significant debt retirement expenses, our quarter to quarter recurring earnings showed a significant improvement, with recurring EPS of 12 cents in the second quarter of '04, versus a loss of 2 cents in the second quarter of '03. Gas pipelines continue to generate steady performance. Midstream was boosted by new deep water expansions coming online and by improved results in our Olefins business due primarily to improved margins. As a result, as Alan and Don will describe later, we are increasing Midstream's guidance again this quarter. E& P is lower due to our highly hedged positions which have capped our upside, while some of our variable costs have also increased. But we have lowered our 2004 guidance, but have not changed our 2005/2006 guidance because many of those hedges that I mentioned are rolling off. Finally, with respect to power. Certainly, power was in line with our earnings expectations.

Turning to slide number 6, as we described in some detail in May, the premier integrated natural gas assets that we own and operate are ideally located in growth markets, and offer significant competitive advantage to the company, and these assets allow us to be poised for post restructuring growth. As you look at our core businesses, of course, exploration and production, will be all about exploiting the attractive portfolio of high return drilling opportunities in Midstream, looking for a bolt on acquisitions in the markets in which we already have significant scale positions, and then we expect over time that we'll be able to capture our share of the new deep water opportunities.

In the gas pipeline area, we continue to focus on satisfying our customers; in growing markets; certainly the Leidy-to-Long Island project is a good example. And I guess, the other highlight there is the fact that the gulf stream expansion is underway. The one bit of new news is our stronger view with respect to an MLP. We are seriously considering an MLP for certain Midstream assets and future acquisitions, and I might briefly mention the timeline going forward. Certainly, we need to complete our evaluation but we are far along in that process. Ultimately we need to make a final recommendation to our Board. Complete preparation of audited financials, and then I would expect, perhaps, the end of the first quarter, early second quarter of next year, we would have an MLP in place if we decide to go forward. The other point I would want to make is some of the assets we're currently holding for sale would be moved into the MLP.

Last slide, number 7, before I turn it over to Don, we introduced this slide back in May. It gives the road ahead in terms of our business units and where we're headed corporately. Not too many changes here. E&P certainly reflecting near term production growth from the Piceance Basin, but over time all of our basins will contribute to growth. In the Midstream area, the story is about the fact that our deep water projects are beginning to perform very well, and again, the fact that we're thinking seriously of moving ahead with the MLP. Gas pipelines-- steady earnings, two new great cases going into affect in 2007. In power, seeking to exit, but if not, we would continue with our existing strategy, which is all about continuing to reduce risk, generating cash and meeting our customer commitments. In the corporate area, certainly we're all about a multi-year restructuring, which is in the back stretch but our priority is clearly continued early debt retirement. With that, I'll turn it over to Don Chappel.

Thanks, Steve. Good morning. I'll quickly run through some summary financial information, and leave some of the details to our business unit leaders who will take you through the drivers and the details of the results. Overall, I am pleased with our results, our progress and Williams' outlook. Before I walk through the consolidated results, I would like to remind everyone that a comparison of the results to the prior year prior quarters is very challenging and we'll endeavor it to make that more clear as we go through this process. As a result of our restructuring and other factors, prior period results are impacted by gains, losses, asset sale gains, impairments, mark to market accounting, and the like. We'll detail those as we go through here, and they are well-detailed in the Form 10-Q.

On slide number 9, I would like just like to touch on a couple of highlights. And again, we'll drill into this as we walk through the rest of this presentation this morning.

We reported net loss of $18 million, and recurring income of $64 million, which is 12 cents per share. I won't walk through the comparisons here because they're very complex , but we'll walk through those in more detail as we step through more slides.

On slide 10, I would like to focus our attention on the second quarter of 2004, walking from the loss from continuing operations of $18 million, to that we would add back impairments and write offs; that $24 million consists of $11 million related to Longhorn, that ran into some difficulties bringing that pipeline into service, and as a result we had an impairment that we had to record. Our Northwest pipeline subsidiary had some hydrostatic testing associated with the rupture that occurred last year, that related to a section of pipe that will not be placed back in service; we wrote that cost off, and then finally, $4 million of capitalized debt issuance expense, related to a piece of debt that we're retiring early.

The next line expense related to prior periods, our E&P business recorded a charge related to some well accounting related to prior years, and Ralph Hill will walk through that, that totaled $11 million. The next large item, is early debt retirement expense, that would be premiums and fees and the like, associated with early retirements of debt this year, and that totaled about $1.4 billion of early retirements, and $97 million of nonrecurring costs related there too. The tax effect is $51 million, brings us down to recurring income of $64 million, or 12 cents per share. I might also add that mark to market accounting provided a benefit here of about $70 million pretax, and in prior periods provided a much greater benefit, so again, comparisons are challenging.

Slide number 11, I would like to highlight again, from a different perspective, some of our earnings and expense items. Segment profit of $305 million is up from $276 million in the first quarter. Net interest expense at $222 million is down from $239 million in the first quarter, and again we'll see that dropping sharply throughout the rest of 2004 and beyond. The debt retirement expense on the 1.4 billion of early retirement I mentioned previously, and the other expense is principally unallocated corporate expenses. That all brings us down to the net loss of 18 I described earlier.

On the next slide, slide number 12, depicts a comparison on both reported and recurring earnings by business unit. Our gas pipeline unit at $142 million of recurring earnings is steady, E&P at $55 million down is down from the prior year, as a result of a number of factors. Despite the fact production is now increasing, production had been declining as a result of limited capital spent in 2003 and prior years, as a result of the capital constraints that the company operated under. That's been now reversed, and Ralph Hill will walk through that issue, as well as some expense items that are impacting these near term results. Again, we're pleased with the drilling success and the production increases in our E&P business. On the Midstream side, earnings have nearly doubled at $99 million, and Alan will walk through the components of that. Finally on power, $45 million is about half of 2003's results, however mark to market accounting has accounted for a large portion of that variance. Again, our power team will walk through the components of that variance.

Slide number 13 depicts similar information on a year-to-date basis; many of the same reasons impact that. I won't walk through that, as the business units will.

Slide number 14, depicts recurring segment profit year over year, and key components of that change. I won't walk through this at this point; it is there for your convenience and your reference. However, again, the business units will walk through that on a more detailed basis.

Slide number 15, will focus on cash, and I will walk through this one. We started the year with 2.3 billion of cash. Cash from continuing operations added about $600 million. Assets sales added nearly $400 million. As a result of putting in place new credit facilities, we freed up $381 million that was previously held as collateral. We retired 2.2 billion of debt, 1.4 of which was retired early. We spent about $331 million on capital expenditures, and $100 million on premiums and issuance costs related to debt. Bringing down a final June 30 cash balance of about 1 billion 30 million and as Steve mentioned and we mentioned in our press release, the current balance is in excess of 1.5 billion and we are quite pleased with our cash and liquidity, and we'll talk more about that during this call.

From a debt perspective-- on slide number 16-- we started the year just under 12 billion of debt, finished the quarter at about 9.8 billion, for a reduction of 2.2 billion of debt during the quarter, with $1.4 billion of that reduction being associated with early debt retirement. As you can see, the average cost of our debt came down from 7.7% at the beginning of the year, to 7.3% at the end of the quarter, and we would expect that that would move somewhat with our next debt reduction action that we announced this morning. Variable rate debt totals about $600 million and has an effective rate of 3.3%.

Next on slide number 17, I'd like to focus on our guidance and changes to 2004 guidance. Our prior guidance has been restated, consistent with the accounting restatement related to the sale of the Canadian straddle plants, that were reclassified to discontinued operations. As a result, we lowered the prior Midstream guidance by $25 million; to account for the fact that those earnings are now being reported in discontinued operations, but despite that fact, I think you can see here that total guidance has improved slightly, to a billion 1 to a billion 4. Same level as it was prior, but on a restated basis it is up slightly. Gas pipelines has tightened its guidance somewhat E&P is lowered, and Ralph will walk you through the components, despite the fact that production is increasing. Midstream guidance has been raised and power is unchanged.

On the next slide, slide number 18, we'll again walk through the some of the changes to the previous guidance. And again, the previous guidance has been restated for the Canadian straddle plant sale, and that change totaled $25 million, but on a comparative basis, current guidance a billion 1 to a billion 4 of segment profit. Net interest expenses are down slightly because of the fact that we are a bit ahead on our debt reduction plan. Early debt retirement costs, however, are up a bit, one, because we are ahead of our plan somewhat, and also we targeted some debt with higher coupon that is somewhat more expensive. Walking down to the line income from discontinued operations, the key driver there is the gain on the sale of the Canadian straddle plants, and finally, diluted EPS on a reported basis has improved, from a loss of 12 to 21 cents to 22 to 52 cents. And perhaps most importantly, net income on a recurring basis has improved, and recurring EPS guidance is improved somewhat, from 20 to 40 cents, up from restated prior guidance of 14 to 37 cents.

The next slide, slide number 19, is fundamentally unchanged with EBITDA of a billion 6 to $2 billion for 2004. Let's turn to the subject of an MLP to expand on Steve's comments somewhat. This is slide number 20. We're moving full speed ahead on the next phase of our evaluation, planning, and final decision making, and as Steve indicated, we would believe that we would be in the position to launch an IPO from MLP if we choose to do so, in the late first quarter, early second quarter next year. We would certainly like to accelerate that. However, the timing of and the rigor around financial reporting and audits, as well as the SEC process would likely require that kind of time frame. We believe that formation of an MLP would provide some strategic advantages to us, as well as provide an acquisition currency, and perhaps improve valuation on our Midstream assets. I won't walk through all of the factors here, but from a consideration standpoint, obviously there is some complexities involved, particularly in light of our sub-investment grade rating. I would say it is a minefield out there; however, I think we have a plan that we can navigate the minefield, and create a vehicle that can create some value for Williams and Williams' shareholders.

With that, I'll turn to the next slide, slide number 21. As Steve indicated, our current thoughts are starting relatively small, and then growing this MLP, we think that that will provide us with maximum flexibility to make acquisitions and drop down--- acquisitions of certain WMB assets in the future. We think that growth rate and growth will be more sustainable starting from a smaller base, and then as the general partner, Williams Incentive Distributions, will increase geometrically as distributable cash flows grow. Again, I remind everyone that Williams had tremendous success with the WG MLP, which is now Magellan. From an asset consideration standpoint, not all Midstream assets are appropriate; certainly we've had some foreign assets, as well as a number of assets that we view as growth assets; and certainly we would like to realize the growth potential of those assets before considering those for an MLP. We're targeting more mature assets; those where we've realized much of the growth opportunities. We have some rating agency considerations, in the small initial size would mitigate some of those concerns, we have covenant and asset security issues; however, those will become less of an issue overtime. With that, I'd like to turn it over to Ralph Hill to walk through the E&P results.

Thank you, Don. Slide 23-- Operationally, things are going well in the E&P segment. Our production response has been tremendous this year, and we've added to our development drilling and our capital opportunities, as I'll discuss in a few minutes. We're disappointed our financials don't reflect this yet, due to the high degree of hedging we've had, which offsets the benefit of higher prices, and also leaves behind higher costs in what would be called the current drilling boom. However, I think a close look today will show just how sharply we've turned the corner going forward.

Looking at slide 24-- quarter to quarter segment profit. To get to our current segment profit, you need to add back $11 million to the second quarter '04; this relates to an ownership issue that occurred during the second quarter. This relates to volumes taken in past years for wells that have reached payout, and hence reduced our working interest after the reversion. Due to the potential size of this estimated liability, we took the financial reserve rather than making up the volume out of future production. The other adjustment to get to recurring profit is to deduct 92 million in gains on asset sales achieved in the second quarter of last year; that makes a recurring quarter over quarter segment profit $55 million this quarter versus $87 million a year ago quarter.

Several items contributed to the $32 million year over year change. I would like to go over those in some detail, and discuss the effects on our guidance going forward on two more slides later. In the Second quarter '03, we had a $17 million gain on some long term excess basis hedges, which we removed from E&P during that 2003 quarter. Basically what we did when the basis blew out last year, we took advantage and cashed out the long term excess basis hedges during the second quarter of '03. Combining that with a slightly higher realized price this year, our segment profit was $18 million higher last year relating to price. Another difference from last year relates to the value of excess transportation. This is firm transportation in the Rockies, and from the Rockies to the Midcontinent, that we will use eventually, as our production grows, particularly in the powder. In the meantime, its value fluctuates according to basis changes between market points. In the second quarter of last year we made a profit of 4 million on this transportation, but this quarter actually cost us $4 million, which caused an $8 million swing quarter to quarter. The basis has narrowed, as I mentioned in the first quarter, which is actually great for us in the long run, but it skews the quarter to quarter results comparison since the basis was so large last year. This also is a price movement effect being related to basis changes.

Like most producers, we also did experience an increase in unit operating cost, which is typically what happens when market prices and drilling activities both are high. This is a combination of several factors: higher operating taxes, which tend to be a percentage of revenues, slightly higher DD&A per unit, due to the asset mix shift from selling properties last year, and higher lease operating costs, which were partially offset by lower G&A costs. Part of this shift is due to selling properties last year, but beyond that our LOE-- higher LOE-- of about 5 to 6 cents relates to increased activity by ourselves and our partners, to optimize production through workovers and other enhancements, and increased labor and fuel cost. LOE also includes effective paying copus overhead on the operator split in the powder that occurred last year, which is about 1-2 cents per MCF for E&P overall, which we didn't have this time last year. However, we are making the labor and the copus piece back to lower G&A.. I think it is important to look at how the business is doing fundamentally. Our second quarter production is up 11%, or 53 million cubic feet a day, since the first quarter of this year, and 13% since the fourth quarter. Recurring segment profit is up 6% since last quarter. This is in spite of having hedge losses of 55 million in the second quarter, which were 9 million worse than the first quarter of this year.

Slide 25-- recurring segment profit, this graph of recurring segment profit plus book depreciation shows that even though our EBITDA isn't caught up to where it was before the 2003 asset sales program, we are gaining quickly, and the upward trend is visible. We've already caught up on production, and as we work our way out from under the out-of-money hedges, in place of [indiscernible] this year this trend should accelerate.

Looking at our accomplishments for the second quarter: our most important accomplishment continues to be exceeding our plan of increasing production through our development drilling program. We are running ahead of where we thought we would be by now, and I have a graph to show that in a few minutes. Solarnet (ph) production is up to 555 million cubic feet a day, versus slightly more than 500 million a day, for our retained properties for last year. The Piceance Basin production is up 19% since last quarter; due to hard work by our team, in terms of drilling efficiencies, we have shortened the days between well spuds from 18 days to 16 days. This allows us to step up development beyond the aggressive rate already planned, by drilling more wells this year with the exact same number of rigs. We also added 2 drilling rigs to San Juan, a third in the Arkoma, and 3 in the Powder River Basin, and are running 3 completion rigs in San Juan to continue our successful well [indiscernible] habitation program in the [indiscernible].

On the permitting side, things continue to pickup in the Powder River Basin. We and our partner have received 414 permits since the record decision last year. We alone have 225 permits that are submitted and pending approval now, which we expect to have approval very soon. For the remainder of the year, we plan to submit 771 more permits, and another 571 permits during the first half of next year, more than enough to take care of the next 2 years drilling programs. We continue to pursue both on acquisitions of the properties adjacent to our core operations. In the second quarter, we've completed deals in the Arkoma Basin, coalbed methane, in the San Juan next to our Rosa [ph] units, and in Big George coal fairway in the Powder. These deals will add ultimately over 60 BCF of proved and probable (ph) reserves, and average cost are approximately 70 cents per MCF, which includes our future development capital. I'll have attractive development drilling (ph) opportunities in the core formations.

Another big milestone for us is we began drilling in the Trail Ridge area of the Piceance Basin. We were able to renegotiate an existing lease to more favorable terms, including a lower royalty rate, better access rights, and allowing for tighter well density. I have more on this in just a few minutes. It could have a material impact ultimately on our improved Piceance reserves.

The core also saw significant growth in the Big George coal area of the Powder River Basin, which is the future of the powder. I have more on that in just a minute. And I will mention that we range for additional capacity out of the Piceance Basin that will ramp up as our production increases. This additional capacity with Wyoming Interstate Company will cover our needs for the future.

Slide 27-- Current Projected Volumes-- this graph we had last time; we've updated it from the last call. Our net volumes in the Piceance, our largest producing area, are up about 60 million a day since the beginning of the year. We are now seeing a higher Piceance exit rate for '04 than we saw last call, due to the increased drilling from the additional rigs we added, and our efficiencies, and also based on the responses we've seen through June. We're also doing well on the other basins with slightly higher exit rates, which really are not shown on this graph, based on the scale of the graph, but we-- higher exit rates than previously shown. As you can see, the Piceance is up substantially from where we were last call in May.

Looking specifically at Powder River on slide 28, I wanted to make sure I showed you-- The industry now has Big George production based on the Wyoming Oil and Gas Conservation Commission data from April, of about 147.5 million cubic feet a day, up substantially from the April numbers. Looking at our production; our total gross operating production from the Big George has grown to about 62 million a day, up from 48 million a day in our last call, and about 37 million a day at the beginning of the year. We have now more that 600 wells drilled in the Big George area. This map displays our major pilots as depicted by the green outline, our partner pilots as depicted by the black outline, and by the triangles just other industry pilots. What's encouraging to me, is to see the production is coming from virtually all areas of Big George. It is still in its early years. It is still dewatering and inclining in areas where the drilling has occurred, and it has thousands of locations left to drill. This is the area of concentration for our Powder River Basin program going forward.

Slide 29-- we’ve begun drilling in what is called the Trail Ridge area, slightly north and west of our Grand Valley area in the Piceance Basin. This map-- the yellow acreage, as depicted by yellow, is our acreage in the Piceance Basin. This Trail Ridge area is an extension of the same basin centered Mesa Verde (ph) gas formation as we drill in the Grand Valley, Parachute, and Wheelerton ph] areas. Where we operate on the Valley floor is shown on the map. Under the current 40-acre spacing rules, this area holds approximately 500 high working interest potential drilling locations for us on more that 20,000 gross acres. As I mentioned, we renegotiated key lease terms of old existing leases. We've enacted some consolidated land trades this year, and we've been able to put together contiguous [ph] highly contracted position for no additional capital cost, and have moved a rig into this area, and are currently drilling our third well. We look forward to sharing results of those in the future with you.

Looking at segment profit guidance, on slide 30, in examining items that affect our second quarter results, we've updated guidance quarterly and I need to explain how these should be considered going forward. Our analysis shows that the high degree of hedging that we've had this year caused some disconnect between realized market price and hedge locale. Our high level hedging is a direct result, and this is, just for history's sake, of two items. At the time of the Barrett acquisition, we hedged the Barrett production from 2001 through 2004 period. And then over the last two years, we sold approximately 250 million in production and over 800 BCF of reserves, to do our part to help Williams ride its financial shift. Even though our hedges correlate well enough for accounting hedge treatment, they are no longer perfect, and we are estimating a $7 million negative movement between hedge points and sales points. Starting next year, the hedge volumes are a much lighter percent of revenue, approximately 50%, in '05 and '06, and our more recent match, so we don't expect this to carry forward. I've already discussed the excess transport higher operating expenses during the slide about our second quarter segment profit a few slides ago. To offset this we are pleased with the volume response of the drilling program, based on our improved efficiencies, and we are projecting additional volumes will help us add about $15 million in net profit this year. The additional wells we're drilling in '04 also helps our segment profit in '05 and '06, and it should offset the higher excess transport and operating costs, if they continue to stay higher as with this year, and of course, we are doing everything we can to work internally and with our outside operators to reduce these costs on a per unit basis where possible. We've also experienced an increase in gathering fees related to those areas in San Juan where the fee is indexed to gas price and this has about a $6 million effect on us.

I think a good question to ask is why we couldn't see all this coming in our last call in May. The $7 million related to the hedges, and the increase in the excess transport costs of $15 million, are due to basis developments we couldn't predict at the time, and obviously the $11 million ownership issue was unknown, so that's $33 million of our change. As I mentioned in May, we were seeing some hints of higher costs, but they weren't enough to push us outside the previous segment profit range. But these later changes did cause us to revise our range, as you see here. All together these updates reduce our '04 4-year outlook by about 28 million, and combine that with 11 million nonrecurring ownership reserve, indicated the need to reduce our range for 2004. But for 2005 and 2006, we think these increased costs will be offset by additional income coming from the bigger production results; I'll talk about that in just a moment.

Slide 31-- capital guidance, like the rest of the industry we're experiencing some rise in drilling costs due to steel prices and demand for services. We are billing at about a 4% cost increase to our overall drilling program for the year, based on year to date spending which equals about $13 million, we think we've done a good job of holding costs down, but there is a drilling boom going on and costs have gone up some. With such an extensive development drilling inventory, and you combine that with the robust price environment we have, we have concentrated on pursuing additional drilling opportunities this year. A highlight I mentioned was, in the first quarter we secured rigs earlier in the Piceance than we thought we would be able to, and second quarter our drilling team reduced spud to spud time between wells from 18 days to 16 days. This will allow us to increase the number of wells drilled this year in the Piceance by 39 wells. And in Canada, the acquisition of Tom Brown has sparked activity in the former Tom Brown Piceance area, and thus we've seen the outside operating wells and we participate more than double in number, something we see as good news. In total, additional drilling will be $38 million and we're pleased to achieve this higher level of greater return development drilling. Also, the rapid production response and increased drilling means that the Piceance plan expansion and associated compression that we've planned for the first half of next year, will now begin this year for early in-service date as our volumes are more rapidly growing. We also made a [indiscernible] positive decision to buy compressors that we previously planned to lease. In total this adds about $21 million of additional '04 facilities capital. The bottom line, of the $72 million in additional capital, 59 million is for pure growth and it's due to faster and more efficient times in drilling, which we think causes obviously more wells in associated facilities, and we have seen the same very strong results with no degradation in EUR or ultimate recovery reserves and economics.

Looking at our guidance on 32, we have changes to '04. Segment profit and capital as I've just discussed, and as is shown on this slide-- In the May call, please recall we increased our '05 and '06 segment profit ranging, ranges, and thus, we are not proposing increasing those at this time, although our strong production results and continued price strength have moved us up well within the ranges for those years. We've also put our hedge volumes and prices on the slides for your reference. For the last half of 2004, we are hedged 418 MMCFs a day, which would be about 80% of our gas production based on guidance. On a revenue basis, that is about 95%, when you take into account the fuel use, NGL shrink, a few fixed price contracts, and the fact that direct taxes are basically a percent of revenue.

When looking at our segment profit guidance and the growth in net (ph) in 2005 and 2006, their growth is an increase primarily for higher volumes and prices in '05, and for an impact of higher volumes in '06. From '04 to '05, approximately $90 million comes from the positive price impact of having more unhedged volumes and a higher hedge price. Higher projected volumes for next year also add over $90 million, to make up for the difference in the profits. Going from '05 to '06, we are assuming a negative $55 million price impact based on the current point of view of prices, but that is more than offset by our strong production growth which should be $110 million in operating profit. Keep in mind, our price impact forecast could change in the future according to our view on prices; currently we are seeing strong growth for '05 and '06, based primarily on production, and secondarily, on price, which hits in 2005, and actually would have a negative effect on 2006 based on the point of view.

During the next three months we'll be completing our detailed '05 capital budget and operating plan; we will provide updates in the next call. The increased drilling efficiencies we are displaying in our development drilling programs, and new drilling opportunities such as Trail Ridge, could allow us to put together an even stronger drilling plan for 2005.

Looking at my last slide, slide 33-- to summarize the key points for E&B business units; we are delivering on the promise of our superior development opportunities from our existing positions, as evidenced by the strong growth of 13%, already this year in production. However, and unfortunately this is not fully reflected in this year's operating profit, due to the issues I've discussed, and thus we adjust our profit guidance and we are very disappointed in that. We are very encouraged by our volumes production and our outlook for the future. We believe the noise associated with '04 profit, including our heavily hedged position, will be more than offset in 2005 and '06, due to our strong operating results in '04, and we will expect to see very strong continued operating results in 2005 and '06. Unlike plans that you may see from other companies, that are based on making exploratory discoveries or acquisitions, our plan continues to be based on continuing our high degree of success with our development drilling program, an increase in our footprint and core basins, as evidenced by the new Trail Ridge area in the Piceance. In addition to the rapid rise in production which should continue for years to come, our drilling will continue to prove up our large inventory of problem possible reserves. That ends my part; thank you for the opportunity to share our results. I will now turn it over to Alan Armstrong with Midstream.

Thanks Ralph. I will start off page -- slide 34-- page 34 to begin with. First of all, our employees at Midstream, with some help from the markets and even our legal group, this quarter produced another exceptional quarter of both financial results and accomplishments that provide a bright future for Midstream group.

Turning to slide 35-- the financial strength in the quarter came from 3 primary areas as you can see here. When compared to second quarter of last year, first of all, two new deep water assets the Devil's Tower facilities, the gas pipeline serving that, and the oil pipeline serving that, certainly produced in the quarter, as well as our oil pipeline serving Gunnison field, and both of those combined to increase our profits in the quarter by $13 million. Next our NGL margins improved $13 million over last quarter, but we're still just below our five-year average for domestic NGL margin. So, the story really isn't here that we had a blowout in our NGL margins, they were just slightly below the five-year average, but we’re well above last quarter, sorry, last year's quarter. The largest source of improvement came from the Olefin sector, where both our domestic ethylene cracking operations at Geismer (ph), Louisiana and our Olefins recovery project from the Tar Sands near Fort McMurray, Alberta, both had dramatic improvements that totaled $17 million. So in total, we improved $45 million quarter to quarter on a recurring basis, and improved $41 million year-to-date against 2003 performance. So, needless to say, we are excited about the quarter and feel like we've got a bright future moving ahead.

Moving to slide 36-- due to some additional highlights beyond strong financial improvement that we showed, first production on Devils Towers’ spar (ph) began on May 5th. But what is really exciting that we're seeing in this area is the number of high potential tie back candidates that are popping up around the spar, and around these associated pipelines so we're really excited to see that, and that is showing up faster than our earlier expectations at this point.

In Canada we had a very effective recontract in marketing effort during the quarter that yielded us $536 million, U.S. dollars, on July 28, just outside the quarter, and that will yield approximately $190 million of gain to be recorded in the third quarter. We are excited about the effort that went on there. Sorry to see a large portion of our organization go in Canada, but they performed very well, and we're excited about the things they accomplished there. We also received a favorable award from an arbitration panel concerning our gulf liquids project. This has been a long fought battle, due to some of the construction overruns on the project and the fact we were bonded and insured from some of those. The arbitration award totaled $83 million, but due to an appeal we have not reflected any of this in our financial statements yet, and for further detail you probably should look at the 10-Q on this, but this is an exciting victory for us, and we feel we will prevail in the appeal process as well obviously.

Another positive development in the deep water area was the dedication of the front runner field in the Green Canyon area. And this ties into our Discovery partnership. This new field came with a 15 field block dedication in the area; we expect first production to begin in the fourth quarter this year. The extension of our system out to this new spar was also nearly completed and just remains for hydrotesting and tie in there. That's a big field and a very productive area that we think will give Discovery reserves for some time to come. Finally, we received a very favorable ruling from the Federal courts concerning first jurisdiction over previously regulated offshore gathering assets. This is in our north Padre Island case. The courts instructed indiscernible] they did not have jurisdiction imposed rate controls, over these north Padre Island offshore gathering assets, and we feel like this opens the door. We really haven't made final plans of what we are going to do with this action, but we do feel like it gives us an ability to reconsider how we're handling our spent-- the assets we have received a spend down order for in the Gulf of Mexico so we'll be pursuing a plan on that in the near future.

As you can see, the recurring segment profit there we continue to perform well over last year as we talked about in the previous stage. Moving to the asset sales on slide 37 then. This would just update where we've been on that. We started with a goal of 500 to 600 million of pretax proceeds for our 2004 asset sell program, and thanks to the successful sales effort of our Canadian straddles, we now expect to exceed that goal, and also to be able to retain our NGL storage and fractionation assets to potentially anchor a Midstream MLP.

A very late breaking piece of news that actually came in after the slides went out last night, is we did sign yesterday a purchase and sell agreement for our ethylene distribution storage systems near Geismer [ph], Louisiana, which throws on another $31 million onto this, and we still are in the process of selecting buyer for our gulf liquids assets but feel confident in our ability to get that accomplished as well. All in all, our asset sale program has gone very well, certainly riding on the strength of our Canadian sale. In addition, we continue to execute on these smaller ones. Probably the most exciting thing from Midstream perspective is the fact we have been able to retain what we think are some very key NGL storage and fractionation assets that we think make a nice anchor for Canada for our MLP.

To talk about the MLP a little bit from an operating perspective, moving onto 38 here. This does provide an acquisition vehicle for additional scale in Midstream as we've talked about several times. Our strategy is very focused around scale so we think it is very important that we have a low cost of capital to compete in this sector. We think this gives us the ability to maintain our competitive advantage in these core basins as well. Another nice thing about this is an MLP allows a continuing presence in the NGL services sector that complements our existing asset base, and leverages off our NGL services scale, and the fact that we're such a large producer of NGLs today to be able to stay in the downstream piece of the Midstream sector is something we're pretty excited about. It also will in the future allow us to retain control of assets that move to a lower risk, lower growth profile but still provide a scale in our basin, so we think in the end it is a great compliment to the WMB holdings. We really do see this as a compliment to our WMB-held assets, not a conversion of our WMB earnings. We are excited about being able to move forward with this, and feel like we've got a lot of great opportunity for acquisition candidates that are in and around our assets that come from the scale that we have. Finally, we don't see any negative impact to our current earnings guidance, because we are really taking most of these assets that were held for sell or that we are planning to sell, excuse me, and those are the assets we use there.

Moving onto the next slide, once again raising our guidance for 2004, if you recall from the past guidance we've consistently advised that our segment profit included operating profit from our Canadian straddle plant. It might be eventually accounted for as discontinued operations. In May our guidance was 300 to 385, including the straddles, and the straddles produced $25 million of segment profit and we have indeed moved them to discontinued operations in the second quarter, and therefore, our restated guidance would have been the 275 to 360 that you see below in the italics here. Our new range of 325 to 375 is an effective movement of $50 million on the bottom end, and $15 million on the top end from our May guidance. This is the second consecutive increase in our guidance, which started out at 250 million to 350 million on a restated basis in our February call. And I also would draw your attention to the DD&A here; even though we don't show any change here, that has been restated from 180 to 190, to now 170 to 180, and that is that $10 million of DD&A that we had associated with the straddle plan. There is not really an effective change on that but just had been moved to discontinued OPS. Finally, we are excited to report that we remain firm our guidance for 2005 and 2006.

So moving to this last slide here, so in summary, the demands for the service in this sector remain very strong. We are raising our guidance for the second time this year partially as a result of that. We expect to exceed our asset sales goals upon the closing of some of these smaller assets we mentioned earlier, and we continue our optimism about the deep water Gulf of Mexico, as our financials continue to reinforce. And our operating group continues to focus on operational excellence, with the goal to be the most reliable service provider to the producing community that we serve. Finally, we're very excited about the benefits an MLP vehicle would bring to WMB's Midstream business, not as a way to monetize all of our business in any way, shape, or form, but in a way to compliment our existing Midstream business. It's something we've been looking at for a long time, and we're excited to be taking the next steps to move ahead with that. That's all I've got. I am going to turn it over to Doug now.

Thank you Alan. Please turn to slide 42. After adjusting 2003 segment profit for the write off of software development costs, and 2004 segment profit for cost incurred late last year and early this year, to test and repair an idle segment of Northwest 26 inch pipeline that we recently determined would not be returned to temporary service, Gas Pipelines quarter and YTD recurring segment profit numbers are flat with last year. Projects completed since the first quarter of 2003, including the momentum expansion, the Evergreen expansion, and the Trenton Woodbury expansion, provide about $14 million of lift to second quarter 2004, over second quarter 2003 segment profit. But there were offsets. Short term transportation revenues declined, since the collapse of the differential between Rocky Mountain and San Juan basin gas prices, after Kern [ph] River was expanded in the middle of last year. There were declines in production area transportation revenues on Transco, and segment profit was negatively impacted by property tax and other cost increases associated with recent plan additions, that do not immediately provide offsetting incremental transportation revenues, such as Transco's clean air at compliance work, and Northwest Rocky Mountain and Columbia Gorge displacement replacement projects. 2003 also benefited from favorable margins on gas used in operations, as well as the harvesting of a unique opportunity to sell environmental credits.

Turn now to slide 43. In June, gas pipeline resumed operations at Transco’s production area facilities from Midstream. You may recall that Midstream operated these assets for Transco pursuant to an agency agreement. After third quarter 2004, continuing that arrangement was problematic. A successful transfer of significant pipeline compression and personnel from Midstream to gas pipeline was no small undertaking. The segment profit of gas pipeline and Midstream for prior periods have been restated to reflect the small segment profit impact of this change. We also begin construction of the Everett Delta Lateral, a 9 mile, 16 inch pipeline with a capacity of 113,000 dekatherms per day. This $25 million project is a unique collaboration between Williams and one of our large customers, Puget Sound Energy. Where we'll build and operate this facility; Puget will own it. It provides them needed new capacity, in an important market growth area. I will elaborate on Gulf Stream's Phase II Northwest 26-inch return for service and replacements, and Transco's lighting and Long Beach projects in a moment.

Slide 44-- With a half year completed we have narrowed the range of our 2004 segment profit guidance. Our guidance for 2005 and 2006 remains unchanged. We tweaked 2004 DD&A. Before I turn to the next slide to discuss the changes in capital expenditures, let me point out that we expect segment profit to increase significantly post-2006, as the large investments we are making in clean air act compliance at Transco, and the 26 inch replacement project in Northwest, are reflected in increased rates in early 2007.

Turning to the next slide on capital spending detail. Most of the changes in CapEX guidance is a shifting of expenditures from 2004 to 2005, and from 2005 to 2006. Beyond that, over the three years for which we are providing guidance, capital expenditures have increased 30 million since our last analyst call. Most of this is due to an acceleration of expenditures to comply with the new pipeline integrity regulations. We continue to expect total spending on pipeline integrity compliance over the next 10 years to be about 300 million in total, we are finding we need to front-end load 2004 and 2005 with facility modifications. Also, in 2005 we added recoding of market area laterals, as part of our risk assessment-driven pipeline integrity work at Northwest. Post 2006, maintenance type CapEX, as identified on the top three lines of this slide, should decline dramatically as we wrap up work to comply with existing clean air act regulations, and on the 26 inch pipeline replacements.

Turning to the next slide, the decision to idle 268 miles of our 26 inch pipeline in western Washington late last year, after two stress corrosion cracking failures, has not had a significant impact on our ability to meet market demand, because we've been able to meet firm service requirements through our parallel pipeline in the same corridor. We have now successfully hydrotested and returned to service 111 miles of the 268 miles of idle pipe, restoring 131,000 dekatherms per day of capacity. This is anticipated to be adequate to meet expected market demand, until we complete the capacity replacement project in late 2006. Total estimated return to service costs are between $40 and $50 million, including the previously mentioned 9 million, spent on an idle segment, that we determined would not be returned to temporary services, and therefore expensed in the second quarter.

Turning to the next slide, we discussed the capacity replacement. As currently required by the office of pipeline safety, we plan to completely replace the capacity of the idle pipeline by November, 2006. We conducted a reverse open season, to determine whether any existing customers were willing to relinquish or reduce their capacity commitments, to allow us to reduce the scope of the pipeline replacement facilities. That resulted in 13,000 dekatherms per day of capacity being relinquished, and incorporated in the replacement project. The total costs of the capacity replacement project are expected to be in the range of 310 to $360 million. We anticipate implementing a rate increase in early 2007 to recover the capitalized cost to temporarily restore, and then permanently replace idle pipeline capacity.

Turning to slide 48, we held an open season for new firm transportation capacity from Leidy, Pennsylvania, the Leidy hub in Pennsylvania, to delivery points in New Jersey and Long Island, under our proposed Leidy-to-Long Island expansion project. As a result of that open season, an expansion has been designed to provide 100,000 dekatherms per day of therm transportation capacity, for which one shipper has submitted a binding commitment for a 20-year primary term. The current design of the project facilities includes pipeline looping and compression facilities at an estimated capital cost of approximately $143 million. Final design of the project facilities is subject to the outcome of a reverse open season solicitation of permanent capacity release. We expect that nearly 3/4 of the project expenditures will occur in 2007. We plan to file for FERC approval of this project in third quarter of 2005; the targeted end service date is November 2007.

On the next slide, we provide an update on Gulfstream. Construction is now underway on the 109 mile extension of Gulfstream to FP&L's [ph] Martin plant in eastern Florida. Construction is on schedule for a December in-service, underpending [ph] a significant increase in Gulfstream capacity subject to long term contracts from 28% currently, to 64% mid next year. And Gulfstream is in discussions with other shippers that will likely lead to further increases in long term contracted capacity. To conclude on the next slide, our work to restore reliable operations to the Northwest system is progressing well. We have several expansion projects underway that will provide incremental revenues and segment profits when completed. We'll see increases in segment profit early in 2007, after the implementation of rate increases on both Northwest and Transco. Bill Hobbs will now cover Power.

Thanks, Doug. Please turn to slide 52, where we'll look at power segment profit for the second quarter. You see our reported segment profit of 45 million, which was primarily driven by mark to market gains as indicated by Don previously. Looking year over year comparisons, you can see that the primary differences are due to sale of contracts--that Jackson contract sale-- in prior period corrections. I'll also point out, under SG&A, the 20 million, that 7 million of that is due to one time items, and under other expense and other income, the 7 million-- 5 million-- of that is depreciation.

Turning to slide 53, we'll look at second quarter accomplishments. Very importantly, our cash flows continue to track what we had previously disclosed in the Power tutorials. Also on a quarter to quarter comparison year over year, you can see there are volumes and cash flows are both up significantly, which we view as a sign of improving spark spreads. We did hold a Power tutorial in June, in our effort to continue to create more transparency around our business, and as Steve indicated earlier, we did resolve-- made major strides in resolving a majority of our Power related issues in the west, and will bring in $104 million in the third quarter.

Looking at slide 54, this is-- I'm just [INAUDIBLE] cash flow slide that's right out of the Power tutorial, it's the same format. As you look through it, you can see the cash flow from the Power tutorial was right in line with expectations. The biggest variance was due to changes in working capital, driven by the issuance of LCs, which brought cash in the door, and also for the year-to-date, that is a primary driver there as well.

Turning to slide 55, the Power portfolio remains cash flow positive, and is expected to remain so for the year. The negative cash flow associated with the legacy positions is primarily rolling off the gas trading positions, and as other gas positions role off through the year, we expect additional losses, but beginning in 2005 we expect the impact of legacy positions to be immaterial. The core power business used 75 million cash flow in the second quarter, but primarily working capital and we would expect the majority of that to return in future periods. As you can see we remain committed to the guidance we've offered throughout the year.

Turning to slide 56, segment profit to cash flows, the mark to market gains on legacy gas contracts was a primary driver of the reported GAAP segment profit. To get to an accrual look at our business, we back out the realized and unrealized mark to market impacts which show the core Power business at a positive 19 million. To get to Power segment gas cash flows, we add 128 million of positive working capital changes, and then to get to Power stand alone cash flow, we back out 202 million of working capital attributable to our other businesses. In summary, the Power cash flow is positive for the year, and we expect it to remain so.

Turning to slide 57, Don indicated earlier there is no change to previous guidance. Turning to slide 58, my final slide, we do expect this business to remain cash flow positive as we talked about previously. We are significantly hedged through 2010; through our core gas businesses we still have a very large gas business that we manage. We certainly see merchant upside in the west as well as the PGM area in the northeast. We continue to work to reduce risk through [INAUDIBLE] Power sales where we are selling unhedged megawatts, or unsold megawatts, through our tolling agreements we have very limited operational and environmental obligations, and as we've talked about we're making great progress in resolving legacy issues. We continue to have the commercial and financial capabilities that we neet to manage and optimize the business. We'll continue to create more transparency around the Power business. In that regard I'll remind everyone that there are additional slides in the appendix. That concludes my piece and I'll turn it back to Don Chappel. Thanks, Bill. Next, looking at slide number 60, a consolidated look at our 2004 to 2006 outlook, first I'll say 2005 and 2006 are unchanged from our prior guidance. 2004 we've summarized the changes to that, the slight increase in segment profit, an increase of capital spending of about $50 million principally related to E&P's increased drilling opportunities. Next, flipping to slide 61, which summarizes capital expenditures by business unit, by period, and again highlighting the E&P cap ex increase in 2004, some adjustments in gas pipeline which is principally timing related, all shows a slight increase in 2004 and 2005 and 2006 unchanged. I would also point out that we see maintenance capital at about the 4 to $500 million range; and the way I would define that is the amount of capital required to maintain our E&P production, maintain our Midstream earnings and cash flows, and maintain our gas pipeline system, and again, we believe that's in the 4 to $500 million range and capital above and beyond that is relatively focused on growth.

Slide number 62, focus a moment on our debt reduction action that we announced this morning, as we indicated earlier, we have 1.5 billion of cash on August first, today we launched an $800 million tender for any and all of the 8 and 5/8 notes due in 2010, as well as a consent for solicitation regarding covenants. We'll use available cash and liquidity to fund the purchase of those notes that are accepted under the offer; in order to assure that we continue to have adequate liquidity, and because of the restructuring progress as well as our solid operating performance, additional credit under our revolving credit facility was available to us, and we decided to take advantage of that. As such, we've increased our revolving credit facility by 275 million to total capacity of 1.275 billion, and combined facilities total 1.8 billion, of which $1.1 billion is available to us. This action will allow us to achieve our year end goal of reducing debt to about $9 billion ahead of schedule, and the next big step would be settling up on the fee line pack transactions.

Next on slide number 63, just walk through available liquidity for this tender, again, cash at June 30 of a billion dollars plus the net proceeds from the Canada sale of about $500 million, leaves us with 5.1 billion of cash. Add our existing revolver of about $800 million, and a $300 million increase in the size of that revolver brings us to total liquidity of 2.6 billion. Looking at cushion requirements of about 1.3 billion, we said 1 to 1.3 billion is the amount of liquidity that we would maintain. This gets us with available liquidity of about a billion three, which is more than adequate to retire this $800 million issue, plus the cost of premiums and fees.

Next slide, slide number 64, it depicts our scheduled maturities. I'd like to highlight a few items. First, the very low level of maturities through 2007, and I say 2007 because 2007 includes 1.1 billion of fee line packs that will be effectively defeesed [PHONETIC] or retired by February '05. 2008 includes $500 million of the term loan at that 3.3% that we highlighted earlier. So that is a very attractive piece of paper for us. And in 2010 you can see the $800 million that we target in the tender.

Next slide, slide number 65, just to highlight some of our financial strategies and where we are thinking about things, again we will maintain a cash and liquidity cushion of a billion dollars plus. We'll continue to deliver, striving for investment grade ratios. As Steve indicated, we saw some movement from the rating agencies, directionally that was positive for us, and we would certainly hope and expect to see more movement in future periods. In terms of use of excess cash and terms of priorities, obviously we'll pay our debts when they're due, we'll continue to early retired debt, we'll make disciplined, EBA-based investments in our core businesses, we've made a number of those and we will continue to make those where they are attractive, and we'll consider dividend or share repurchase upon achieving stronger balance sheet and investment grade ratios. A combination of growth and operating cash flows and reduction to interest cost will continue to drive value coration, and we'll be driving and enabling sustainable growth and [INAUDIBLE] to shareholder value. With that I'll turn it back to Steve. Thanks, Don. Let's look at the next slide. I think it is 67, to conclude our presentation this morning, let's look once more at the road ahead slide, and I would just summarize by saying, over the next several years in terms of our core businesses, our focus is on disciplined growth, and we have, as we've said in the past, we are embracing the EBA methodology to ensure we are making prudent decisions with respect to growth. In the Power area we are pursuing risk reduction whether by exiting the business or optimizing the business through continued operation, and at the corporate level, obviously, we desire to complete our multi-year restructuring, focus on creating solid financial footing, and certainly our priority, as we stressed this morning, is all about debt reduction.

Finally, looking at slide number 68, I believe that we have made exceptional progress on the restructuring plan that we first described to you back in February of 2003, and in many respects our progress has been even faster than I had anticipated at the time, but second quarter results were solid, our debt reductions were significant year-to-date, and continue, with our new $800 million tender that we announced today. Asset sales program is essentially completed with the sale of our straddle plants. Liquidity is no longer an issue. Growth opportunities have been clearly identified and many are being currently pursued. Significant work has been outsourced to IBM, and that makes us feel much more confident about our cost savings initiatives. We are seriously considering an MLP and would expect, if things go as we expect, to have an MLP in place at the end of the first quarter of 2005, or early in the second quarter. And we continue our efforts to exit the power business. With that, we'll be happy to take your questions.

Thank you. [OPERATOR INSTRUCTIONS]

First question is from Scott Soler with Morgan Stanley. Good morning. Had a couple questions for Ralph and a few questions regarding Midstream. Ralph, looking at E&P, 2 questions specifically. The first is on hedging. As good as you all are doing in the Piceance Basin, I know you all talked about hedging somewhere between 40 and 60% of the following couple years, at that's always [INAUDIBLE] target, but with Nymex gas so high right now, and basis differentials reasonable, why don't you all consider stepping that up a bit to lock out a much higher level of potential segment profits and your answer on that first?

Scott, currently, as you know, it is an enterprise look and we've run numbers with Andrew Sunderman's [PHONETIC] group with that. We really believe we are at an optimal level of hedging, at the level where we are currently. Now we are looking at that and continuing to revise that. That's also part of the ongoing plan as we look for our 2005 and 2006 plan. But, at this point we are optimally hedged. If we took more out it's just like you said, it means we like the price and we just wanted to do that. Which we may do, but if you look at the balance for the fuel needs from Midstream and from Power and the production level that we have, we're at a very optimal hedged level on that percentage basis. There is an opportunity if prices stay strong, which we think they are, to possibly take some out. It is just an ongoing enterprise look at that. I hope that helps some.

On the Piceance Basin, I want to get a recollection of how much of you all's land is fee [INAUDIBLE] and fee based, and are there any issues with landowners or federal environmental issues that would prohibit you all from when you look at your initial reservoir model and recovery assumptions, it would seem like those would be likely better, given how well you all are doing, and several of your competitors are doing in the Piceance right now-- if you could color that in?

I think about 30% or so of the go- forward basis, and I am pulling that off the top of my head, Scott, so if that's wrong I'll let you know, is Federal acreage going forward, and the remainder is fee, so we do believe we have good relationships and a long history of drilling with our landowners out there, and we do not see anything that would cause us from the aggressive drilling program that we have.

Have your recovery assumptions changed any from your original model that you all had in place?

No, at this point we are right on with the ER we had from the earlier slides this year.

And then Alan on Midstream, just a couple of quick questions. The first is when you look to put out guidance on [INAUDIBLE], does that already include the anticipation of the MLP and how much earnings would go back to Williams for the holdings in the MLP plus the nonMLP assets?

No, Scott, it does not include anything we would see on the GP side at all. The relatively small assets that we're putting in there, probably Conway storage and a few other assets, were not significant enough to have moved the range, even though they were planned to be sold so, to answer your question, it does not include any growth from the GP or the LP units we might hold.

Ok. My last question is I know most of what you are likely to use MLP for are mature assets, but when you look at the possibilities in the Eastern seaport or Gulf of Mexico, as that starts to unfold, would this allow you all a chance to look at projects you may have otherwise had to pass on due to capital constraints to corporate level, and if you could do an MLP you might have more opportunities?

Yeah, I think that's a really good question, and there are some circumstances out there where there is well backed, steady income fee arrangements on some of the assets we think would give us the ability to capitalize that and even beyond that as you point out gives us additional liquidity on the corporate level to put dollars into the higher risk elements out there. The answer to your question is yes we do think that would be a nice complement to our ability to capitalize out there.

Thank you I appreciate you being so open minded about MLP; it looks like it would be very good. And thank you for listening to investors and analysts.

Thanks.

Next question comes from Sam Rockwell with Merrill Lynch.

Good morning. Just a couple quick questions. Ralph, you ran through some numbers on potential drilling locations and so forth in Piceance, and I jumped on the call late and I wasn't able to write it down. I was wondering if you could run through it real quick.

What I ran through was the new Trail Ridge area. And based on about 20,000 gross acres and it's all contiguous out there, we believe on 40 acre space we have slightly more than 500 locations in the Trail Ridge area, and the ongoing Grand Valley, Parachute, [INAUDIBLE] core fields we believe we have, if you count the ultimate down spacing, we think we'll have down there north of 2,000 locations on that.

Right. Any potential for down spacing in the Trail Ridge or over in the Piceance generally?

We are just starting, and it is the same formation we believe is in the basin floor, Mesa Verde, which has been down spaced to 20's and 10's, so I think ultimately there is, assuming we like what we see in Trail Ridge, and the formation is what we think it is, which is the same, there could be that opportunity for further down spacing.

Okay. And then I had two other quick questions. It sounds like in the Midstream it sounds like the contemplated MLP would start out pretty small. I don't know if you can give us any kind of a range in terms of dollar value of assets that you would be looking at dropping in there?

I think we would like to think about it initially in terms of just initial size and ultimately there will be follow on transactions in the $200 million dollar range plus or minus.

The follow ons would be in that range, or is that where you think you would start out?

Start out, 200 plus or minus. Could be a bit smaller or bigger. That's the enterprise value, not the amount of public float that would be out there initially. [INAUDIBLE] half or less than the number that I quoted.

Understood. Okay. And then finally, -- I'm sorry. And then finally, in terms of the result in the Power segment this quarter, back when you did the tutorial, you kind of compared how things look on a, you know, with the mark to market you are currently on, versus what it would have been on an accrual basis. Can you make that comparison again for what happened in the second quarter. I apologize if you did I was having to jump in and out of the call.

We did. If you look at slides, I believe it is going to be 56, we walked there there kind of starting with the GAAP--

I got it. Great. I apologize, I had to jump on and off a couple times. I'll work through that. Thank you very much.

Next to Maureen Howe with RBC Capital Markets.

Actually I just wanted to talk about slide 56, and I am wondering if perhaps Bill could give us more explanation of what the 128 million coming in from 'other' is; it says total working capital, is that working capital that was provided by other businesses during the quarter, so an incremental change?

128 million, Maureen, is what you would see from a GAAP perspective, so that would be the blend between Power and our other E&P, Midstream businesses, that would be the net, in effect, of all those businesses, and what we try to do there is work you down to stand alone power cash flows.

Okay, I think I am following you. So it would be a change in working capital across all businesses that would be impacting the -- I guess, the working capital in Power, and then when you take out the 202 million, that is taking out the other business's working capital?

That's the way to think about it, Maureen.

Okay. That's great. That's my only question.

We do have a question from the web, probably to Ralph. Ralph, when do you expect E& P operating cash flow to significantly exceed the cap ex for that segment?

This year we projected that to happen, but obviously we've increased our capital based on the development opportunities and efficiencies we see the opportunity to drill more, which accelerates some of our plan he investments also, so this year we don't see that. We do see that happening in '05 and '06, although, I will mention-- and I'm not sure how to define 'significantly,'-- but we seen that occurring in '05 and '06, and I'm projecting it probably will stay that way in '06, and in '05, we are revising our capital and segment profit and other opportunities as we look at our '05 operating budget. But it still appears to me that our segment profit in DD&A will be strong, and our capital spending may go up some, but we still will generate precash flow.

Our E&P business is really a high growth unit within Williams, in terms of its ability to grow its segment profit and its cash flow. So really the high growth rate driven by the higher capital spending is by design. If we choose to maximize cash flows, we could certainly reduce our capital spending dramatically and maintain our E&P production. So again, we think these are very solid investments that will drive a lot of value.

[OPERATOR INSTRUCTIONS] Our next question comes from Jay Daniello with UBS.

Good morning. I guess my question is for Bill or Andrew. I just want to make sure I'm clear. In this quarter, there was roughly 70 million of mark to market, and in the 2Q '03 quarter, if you exclude the gain on sale of the big mark there in the prior period correction, I think there was roughly 250 million in mark to market, is that true, 70 million this quarter, versus 250 last quarter, or is that not right?

Jay there was 69 million in mark to market this quarter, and it's around 230 million in '03.

Okay. Great. Thank you. Going onto, I guess the appendix slides 84 to 86 in the power book, focusing on 2005 and 2006 undiscounted cash flows, it looks like, if I am doing the math right, the West went down around 12% from the June meeting, Central went down about 4%, and the East slipped to a negative 13 from a positive 12. Not the end of the world, but down across the board. Is that from higher gas prices during the quarter; could you provide any flavor on that? Also, we don't see the 2007 to 2022 view of the undiscounted cash flows. Can you tell us what is happening there? Thank you.

You have to remember last quarter too we saw some pretty big increases. This quarter we saw some declines. And the majority of that is primarily due to higher gas prices. But on your second part of your question, Jay, what was it?

We don't see the 2007 to 2022 view, where there is, I guess, a disproportionate amount of undiscounted cash flow. Did it decline the same magnitude, was it more-- just any visibility from what happened from '07 to '22.

It probably proportionally declined about the same. We just starting to show now during the guidance period but it certainly declined some.

Primarily that's gas?

Primarily gas driven.

Okay. Thank you.

We'll go next to Yves Siegel with Wachovia Securities.

My questions have been answered, thank you.

Having no further questions, I'll turn the call over to management if you would like to make any additional or closing remarks.

Again, we appreciate your interest in our company. We -- we're endeavoring to make our businesses as transparent as possible. And I know you are not shy about making comments, but certainly offer your input to Travis and his group, in terms of ways that we can make these conference calls even more productive in the future.

Thank you and we look forward to talking with you next time. Thank you everyone for your participation in today's conference call.