威廉斯 (WMB) 2003 Q3 法說會逐字稿

Good day, everyone. Welcome to this Williams Companies analyst conference call. Today's call is being recorded. There will be a presentation followed by a question and answer session. If you should have a question, please press the star or asterisk key followed by the digit one. We will go to the questions in the order you are signaled. At this time, for opening remarks and introductions, I'd like to turn the call over to Mr. Travis Campbell. Please go ahead, sir.

Good morning. I'm Travis Campbell, the Vice President of Investor Relations for Williams and welcome everybody in on our call this morning. As always, today's call does include forward-looking statements. Please refer to the forward-looking statement information that's included in this presentation and also that that's posted on the www.williams.com web site for further details on risk factors affecting our company.

Also, there are some nonGAAP numbers that are presented, the reconciliation of recurring earning numbers is included on the web site. As always it's attached to the press release. EBITDA reconciliations are included on slides in this presentation. All of our slides are available on our web site in pdf format. With that introduction, let me turn it over to Steve Malcolm our Chairman and President.

Thank you, Travis. Thanks for your continuing interest in our company. We're obviously very pleased with the progress we continue to make on our restructuring plans. Over the past quarter, we sold another $360 million in assets. Our core businesses have performed well. We locked in future cash flows with specific hedging actions. We took a critical step toward delevering the company with our recent tender offer. Bottom line, we are exactly where we told you we would be.

But before we go into any more details on our progress, let's look at the agenda on page four, slide four. I'll start with some highlights of the quarter, then Don Chappel will talk specifically about third quarter financial results. Then our business unit leaders, Doug Whisenant, Ralph Hill, Alan Armstrong, and Bill Hobbs will discuss their results and accomplishments for the quarter. Andrew Sunderman will come on and talk about our new enterprise risk management group, then Don Chappel will come back and talk a little about the outlook and update and refresh our forecast for 2004 and 2005. Then I'll come back for some concluding comments and then we'll certainly have plenty of time for q & a.

So if you would please refer to slide number 5, I always like to review our commercial and financial strategies during these calls. Williams of the future will be a balanced integrated natural gas company with world class assets and exploration and production, gas pipes and midstream. Our so-called three-legged stool. Our complementary financial strategy has us focused on maintaining adequate liquidity, delevering the company over time, and strengthening our balance sheet so we can ultimately grow our core businesses. If you will look at slide six, I'm going to review some evidence of our continuing progress with respect to our restructuring plan. We obviously continue our efforts to delever our balance sheet.

While removing $116 million in scheduled maturities during the third quarter, we also committed to early repayment of almost $1 billion in debt. I believe that our ability to tender for the 9.25% March '04s, and various stub issues speak to the success of our asset sales program and other efforts that we have made to financially strengthen our company over the past 18 months. Obviously this is a significant step in our goal to regain investment-grade ratios by year end 2005. Slide seven. As you will hear more from our business unit leaders, we are sustaining core business earnings capacity. In the gas pipes, we had two important expansions come online. In E & P, we are accelerating our drilling pace. In Midstream, our Deepwater activities are starting to take off and generate revenues for the first time.

Asset sales continue. A total of $364 million closed in the third quarter, probably the most important being the Red Water West Stoddard sale. It was important for us to make progress with respect to the sale of our Canadian assets. So year-to-date, 2003, we've sold $2.8 billion in assets. Almost $6 billion in proceeds since 2002. Next slide, slide 8, we continue to rationalize our cost structure. Year-to-date, 2003, a 32% increase in terms of SG & A costs versus year-to-date 2002. So we've made great progress as well. It seems as if a good portion of our organization is involved in a framing the future initiative, which will allow to us take the next step towards reducing costs.

As you know, we were fairly aggressive in terms of hedging the Barrett reserves and our Barrett production, and did step out in '03 and '04. We thought it was the appropriate time, the right time and we have taken additional hedges. We put additional hedges on. We're currently 47% hedged at $4.44. Lastly, we have added important energy expertise to the board. I think that we had mentioned we were seeking additional E & P experience. E & P is an important part of our portfolio. Near term discretionary capital dollar are being devoted to E & P given the remarkable cash flow characteristics of E & P. So we're delighted to have Bill Lowry, formerly with BP Amoco join our board, and he's already making a difference.

Next slide. With respect to Power, I want to re-emphasize we are committed to exiting this business. We clearly understand it's presence in our portfolio of business. It certainly impacts our ability to attain investment grade characteristics in the future. Since 2002, we have sold or liquidated components of this business for almost $600 million in deals that we believe represent fair value. And in the interim, we are all about reducing risk, generating cash flows and meeting our contractual obligations. In prior calls, you've heard me be cautiously optimistic about our ability to sell the book. I told you that we intend to be patient and prudent in our negotiations, and that obviously remains our game plan.

But I think it's appropriate to recognize that after the $600 million in sales that I mentioned, we are left mainly with long-term fairly complex deals. We're well aware that power markets have deteriorated and are expected to be depressed for at least the next two or three years. The value of our book, as we've said many times, is primarily out west. Therefore it's appropriate that there should be recognition that the timing of our assets and the value associated with that exit is clearly uncertain. I think in the meantime, the good news is the power cash flows for '04 and '05 are expected to be positive. We know many of you have asked for more details concerning our Power book.

And to answer some of those questions, we have scheduled a Power tutorial on Friday, November 21st. Bill Hobbs and Andrew Sunderman will provide more details into the tutorial content later during their remarks. But now, I'll turn it over to Don for an overview of the quarter. Don?

Thanks, Steve. Good morning. We're again presenting a great deal of information. Some of it for the first time as we continue to strive to become more transparent and better understood. As you know, we continue to deal with a good amount of complexity as we continue to restructure the company and simplify Williams. Today we'll move through the presentation fairly quickly and try to leave plenty of time for your questions. 2003 results continue to be significantly affected by restructuring impacts, including gains and losses on sales, impairments, reclassifications to discontinued operations, and the like.

We'll try to highlight these as we walk through this analysis today. Take a look at slide number 11, third quarter 2003 results. We enjoyed significant improvement year-over-year in the third quarter. On the face of our report, however, our core asset performances are somewhat mixed; however, remain solid for the year. However, as you dig deeper, I think you'll see that our solid results in our core businesses continue and the prospects for improvement are very good. Income from continuing operations of $23 million or four cents was a sharp improvement over the $171 million loss, or 34-cent loss in 2002. Income from discontinued operations of $83 million as compared to the $123 million loss last year also was a substantial improvement.

Net income of $106 million or 20 cents a share, again, sharply improved over the $294 million loss or 58 cent loss per share in 2002. And then finally on this page, a look at recurring income of $3 million or 1 cent per share versus a $241 million loss or 47 cent per share loss in 2002. I'd like to point out that the third quarter '03 results include in the area of recurring, excuse me, include $127 million pre-tax mark to market valuation adjustment associated with the Allegheny contract termination. We categorized this as a mark to market adjustment as it is a mark to market valuation of a derivative contract. As such it's much like any other mark to market change in any of our other positions. When we have a mark to market decrease or increase, we do not consider them nonrecurring adjustments.

However, because this is so unusual and material, we've clearly disclosed it for you today. Moving on to slide number 12, 2003 results, again, income from continuing operations in 2003 at $100 million, up from $460 million loss in 2002. Discontinued operations improve from a $75 million loss to a $223 million gain in 2003. As you know, we had income associated, or a loss associated with our accounting change totaling $761 million, netting out for a net income change of $974 million improvement year-over-year. Recurring results reflect a loss of $30 million in 2003 or 6 cents per share as compared to a $266 million loss or 51 cents per share in 2002 for an improvement of $236 million. Again, as Travis pointed out, a reconciliation to our financial statements is included on our web site.

Next on slide number 13, I'd like to take a quick look at our core business segment profit; again in the summary, each business leader will provide a more complete picture following my remarks. All three businesses continue to perform very well, however, quarter to quarter, comparisons are negatively affected by some unusual items related to our restructuring, and also some price volatility period to period. I'll detail this in the next slide. All of our core businesses are on track with our prior guidance for 2003 and 2004. In total, the core segment profits total $274 million for the quarter. This compared to $487 million in the prior year or a decline of $213 million. On a year-to-date basis, the decline was $63 million.

If we turn to slide number 14, we'll start to analyze that change. Again, our change in core business segment profit of $214 million dollars is detailed here. The absence of a 2002 E & P gain on the sale of assets and the absence of a 2002 Transco rate adjustment totaled $169 million. Lower processing margins in the third quarter as compared to the prior year reduced Midstream's segment profit by $47 million. E & P's segment profit was reduced by $29 million. Half is related to divestitures and about half was related to price. Ralph will talk more about that as he walks through his business. On the plus side, we see incremental gas pipes projects and incremental Deepwater earnings, which contributed nicely during the quarter.

Moving onto slide number 15, in terms of, again, changes on a year-to-date basis, the decrease of $63 million in segment profit was comprised of, again, the absence of the 2002 E & P gain of $144 million offset by a 2003 E & P gain on assets. The total of those two nets out to $51 million of the $63. Additionally, we see the absence of the Transco rate case settlement totaling $26. The lower processing margins totaling $17. Again, the reduced E & P production of prices totaling $24. Once again, we see the incremental gas pipes projects and Deepwater revenues contributing quite nicely. So as we take out the unusual items, again, I think we see strength in our core businesses on a same-store sales basis if you will.

Next on slide number 16, let's drill down some more on the income and loss from continuing operations comparing the third quarter of '03 to the third quarter of '02. We see an improvement of $194 million, comprised of a number of key items here. In our core segment profit, we have a $213 million decrease, much of which I just detailed for you. Again, the absence of the 2002 E & P gain totaling $144 million, lower processing margins due to volatility in prices in Midstream. And Alan will talk more about that totaling $47, and other principally again comprised of the Transco rate refund totaling $22 million. We have increases in our Power segment profit totaling $432 million, the largest of which is a change in interest rate, hedge related earnings moved from a large loss in 2002 to a gain in 2003.

Mark to market gains associated with the Allegheny contract totaling $127 million, and other mark to market changes in fair value totaling $100 million. Additionally, other factors, reduction in interest expense totaling $69 and the absence of the Lithuania gain totaling $59. The other changes are miscellaneous and tax related. Let's move on to, again, an analysis of our recurring income on slide number 17 as we eliminate nonrecurring items, the highlights of which are reducing gains on asset sales totaling $47 million in '03 and $211 million in '04. And can you see the other components, which are relatively small by comparison bring us down again to the recurring income from continuing operations of $3 million in the third quarter of '03 as compared to a $241 million loss in the third quarter of '02.

Again, I would point out that the mark to market valuation increase associated with the Allegheny contract termination is included in this recurring income. On slide number 18, we reconcile from net income to EBITDA. Most important here is that after adjusting the cumulative effect of the change in accounting principles, which had no cash effect and the other factors in reconciling down to EBITDA, we generated almost $1.7 billion in EBITDA during the first nine months from continuing operations. The next slide, number 19 helps you understand how each of our business units contributed to the $1.7 billion of total EBITDA. All businesses have generated positive contributions during the first nine months of the year including Power.

As you'd expect, the corporate and other component is relatively small and consists of the corporate plus investments in Longhorn pipeline, the butane blending program sold to WG in July, and interest in a Bolivian terminal. Next on slide number 20, we roll forward cash from the beginning of the year to $930. The major components being as follows. Operating income and DD & A contributed about $1.7 billion. Net issues about $1.8 billion. Asset sales about $2.8 billion for a total of $6.3 billion of cash in.

Retirements of debt at $2.2 billion, interest payments at nearly $1.2 billion, Cap Ex at just under $800 million and collateral posted for our lc facility of about $450 million; bring us down to cash on hand as of 9/30 of $3.4 billion dollars. Additionally, as you know, we are in the process of completing a tender offer. The final payouts for those tenders will occur next week. At that point, our cash balance will be approximately $2.7 billion after reducing debt by $1 billion. Restricted cash totals $217 million. On the assets sales front, as of the end of the second quarter of 2003 on a year-to-date basis, we had $2.4 billion of proceeds and $800 million dollars of debt that buyers assumed. During the third quarter of '03, we completed an additional $364 million of asset sales, the largest of which included Red Water and West Stoddard.

For a total on a year-to-date basis of $2.8 billion. Additionally, after the end of the quarter, we closed an additional asset sale, a west Texas lpg pipeline for $27 million. This listing excludes the sale of a number of contracts, which would include the Jackson EMC contract for $175 million which we previously announced. On slide number 22, pending asset sales, we've announced but not yet closed a sale associated with distributed power-generating assets totaling $10 million. That is expected to close in the fourth quarter of this year. And additionally we've identified for sale additional assets with proceeds expected in the range of $800 million to $1 billion, which will close in the fourth quarter, as well as, throughout 2004 as detailed on the slide. And we'll be pleased to answer any questions that you have on the details of the asset sale program.

On page 23, debt balances, as of the end of the third quarter, and we'll roll this forward from the beginning of the year. Debt at the beginning of the year was nearly $14 billion. At the end of September, reduced to $12.9 billion. The components of that are scheduled debt retirements of about $600 million. The Progeny debt which was paid off of $460 million. The Lehman Birckshire loan that was prepaid for almost $1 billion, offset by some new debt issues and at $1.8 billion, $300 million of which included funds to retire some preferred shares. The total decrease in debt at the end of the third quarter is $1.1 billion. At the same time, we had an increase in available cash of $1.7 billion. For a change in net debt of nearly $2.8 billion.

On slide number 24, give you a look at what debt balances may look like at the end of the year based on transactions that have been completed or are nearly completed. The debt tender that I mentioned earlier, nearly $1 billion at $950. In Venezuela, we completed a project finance that our P-Gap facility. That was done really not to raise cash. It was really done to reduce our investment at risk in Venezuela. That totals, $230 million.

The net proceeds after minority interests in tax was $183 million net proceeds to Williams. Then finally, scheduled maturities and amortizations that are upcoming during the month of December total $187 million, bringing us to an estimated $12 billion debt balance at the end of the year. Next, we'll review each of the business units and our enterprise risk management function. With that, I'll turn it over to Doug.

Thank you, Don. I'm going to start with slide number 26. Gas pipeline segment profit includes profits of our two wholly owned pipelines, Transco and Northwest; as well as, our equity and earnings from our Gulfstream pipeline, Cardinal pipeline, and Pine Needle l & g investments. This slide of just gas pipelines reported segment profit for nonrecurring items including, specifically for 2002, write-offs of abandoned pipeline projects, a project completion fee booked upon the completion of the initial build of Gulfstream, severance and early retirement costs, and earnings related to our interest in Northern Border Alliance Pipeline and Coal Point L & G, which were sold in 2002. 2003 is likewise adjusted. Specifically for a write-off of a large IT project carried on Northwest Pipeline.

In addition, we footnote Transco's $26 million adjustment of prior period rate reserves booked in the third quarter of 2002. We have not included such rate reserve adjustments in our computation of recurring segment profit; because rate reserves are a normal part of business for a regulated pipeline. Nonetheless, adjustments to rate reserves make otherwise stable regulated pipeline earnings a bit lumpy. If we back that rate reserve adjustment out of 2002 earnings, we find our 2003 segment profit is increased over 2002. This increase is due to the $11 million per quarter of segment profit contributions from expansions of the Transco and Northwest systems that were completed since the end of the third quarter of last year.

Moving to the next slide, we see that since the end of September of this year, we have placed several more expansions into service. The Evergreen expansion of Northwest Pipeline completed on October 1st at a cost of $198 million, netted 277,000 decatherms per day of fully contracted capacity into the Seattle market; and will provide $30 million segment profit in its first year of operations. The Trenton Woodbury expansion on Transco completed on November 1st at a cost of $22 million netted 51,000 decatherms per day of fully contracted new capacity into the Philadelphia area and will provide almost $3 million of additional first-year segment profit. The Rocky Mountain and Columbia Gorge expansions on northwest could not add incremental contracted capacity, but replaced that call capacity we lost when the contractual obligation of some existing shippers to flow gas in the opposite direction recently expired.

Northwest customers have agreed that the cost of these two expansions can be rolled in to existing rates when Northwest files its next rate case. Therefore, only then are the segment profit and cash flows from these two expansions to be realized. The wind down of these expansions mark an ebb after several years of significant growth of our Transco and to a lesser extent our Northwest system. At this stage, the only incremental expansion yet to be placed into service is Transco's Momentum phase two, which is to add 54,000 decatherms per day of fully contracted capacity into south Atlantic markets when completed in February 2004.

Not shown on this slide is the phase two expansion of Gulfstream announced in June, underpenned by new contracts totaling 300,000 decatherms per day for Florida Power. This expansion of Gulfstream is expected to add $30 million to gas pipeline segment profit in the first year after it goes into service at the end of 2004. Bottom line, Gas Pipeline's performance continues to follow very closely the outlook we provided in August. Ralph Hill will now cover Exploration & Production.

Thank you, Doug. On slide number 28, first off, our production for the quarter declined 13% due as, Don, I think, mentioned to our asset sales and reduced drilling activity January through August, as a result of our capital budget. My next slide will talk more about what we're doing now that we're back in the field drilling. Our segment profit net of gain on asset sales declined also due to lower volumes mentioned above and our lower net realized price. Our hedge price that we entered into back at the time of the Barrett acquisition, was lower for the third quarter '03 than for third quarter '02. Third quarter '02 prices was $4.25 and the third quarter '03 NYMEX price was $4.02. So it's 23 cents less our price on the NYMEX basis for the third quarter.

Turning to slide 29 for the third quarter, one of the things that really kicked in for us, our drilling activity's now resuming. The Piceance Basin's rig count increased from one rig to seven rigs. For example, what that means to us, in the second quarter, we only drilled five wells in the Piceance. In the third quarter as we began to ramp up our drilling, we drilled 20 wells. We expect to have 40 wells drilled in the Piceance Basin in the fourth quarter; which is resuming back to our normal activity. San Juan Basin rig count also increased. We went really from no rigs out there to one drilling rig and four cavitation rigs. For example, in the second quarter, we drilled no wells in the San Juan basin, third quarter we drilled three and we expect to have 18 in the fourth quarter. So as you can see, it's picking up.

Another significant event for the third quarter was additional ten-acre downspace in the Piceance. Back in April we received a 10-acre approval for 11,000 fee acres. We added 16,000 BLM acres, was approved in August so now we have 27,000 acres approved in the Piceance basin for 10 acre spacing. Significant to us, is that ultimately will add well over 1,000 new locations to drill in the Piceance Basin. Under the EIS, drilling under EIS in the Powder River Basin and the Western litigation, we did receive the first permit issued from the BLM. We received 49 permits under the new EIS -- or I'm sorry, 59 permits under the new EIS; out of 297 issued by the BLM so far. So through the third quarter, we have 59 permits. We've drilled- on those 59 permits, we've drilled 48 wells. We expect to receive an additional 161 permits in the fourth quarter.

Additional permits are coming in through the rest of next year. We resolved our Western litigation. We received improved terms and a long-term gather agreement and in turn for that Western will operate about half of the properties, jointly we will operate over 4,000 wells and we control about over 1 million gross acres. In the San Juan basin, two significant events for us. The first was the New Mexico Oil & Gas Commission approved Fruitland Fairway downspacing. That will add approximately 300 new locations to Williams. Also, the record decision was issued in late September for the Farmington Research Management Plan. This EIS will cover the development of approximately 10,000 new wells over the next 20 years. So, again, as we are a major participant in the San Juan Basin, that will be good for us.

The Runyon and Canyon sale was completed, as mentioned, for $48.6 million. And finally, we did increase our hedge position and recently in the third quarter. We are now hedged, 80% hedged in 2004. That does not change from where it was before at about $4.03 NYMEX. We've increased our hedge position for 2005, we were about 13% hedged in the $4 ballpark range. We're now 37% hedged at a NYMEX price of $4.44 for 2005. I will now turn it over to Alan Armstrong.

I'm going to start here on slide 30. In the Midstream area, first of all, I think it's important to point out that the segment profit that you see has been restated to move our Red Water and West Stoddard assets into discontinued operations. So both the very significant gain that we had from the sale of those assets, as well as, a little bit of operating profit from the '03 period and from the numbers shown here was moved into discontinued operations. And so then the story in terms of our delta between the third quarter of '02 and '03. First of all, third quarter of '02 was very significant margins. We experienced very strong margins out west as the Rocky Mountain basis continued in the third quarter '02. That was coupled with a very low margin period.

Probably one of the lowest we've seen in the third quarter of '03. Overall, we had $47 million lower in NGL margins. That NGL margin also includes about $7 million of Olefin's margins as well in there. And then coupled with that we continue to see increase in our Deepwater profits quarter-to-quarter, and I think that's especially significant in the fact that we didn't have any new projects come on in this quarter; so this is just from our existing projects that have been online and they continue to perform very well and continue to ramp up. And then on the year-to-date comparison, you can see the '02 number there.

Our margins are about $17 million lower in '03 than '02 for similar reasons and then on the increased Deepwater profits, we've actually seen $38 million higher profits in our '03 to '02 results; so we continue to be impressed with that. Moving onto slide 31, talking about some of the accomplishments we had in the quarter. First of all, we're happy to say that we continue to sell our assets at a gain; and in this quarter, we sold-- our asset sales produced gains of $98 million from the assets listed here and so we continue to be able to find very favorable markets to be able to sell our Midstream assets. We also completed the Gunnison Pipeline. The Gunnison Pipeline goes out to Kerr McGee's Gunnison and Durango projects. That was completed on time and a little bit below budget.

And we continue to enjoy our work with Kerr McGee and continue to be very impressed by their ability to manage projects on time. We expect the Gunnison Pipeline to start flowing oil probably in mid-December at this point now. So we're very excited to see that coming on. Devil's Tower project, our pipelines, both the oil pipeline and gas pipeline were installed on time and on budget. The Spar, however, has had a lot of difficulties due to eddy currants and Dominion continues to work hard to overcome some of the issues there. The Devil's Tower Spar is more now though and we expect our payments under our contract to begin probably on April 1 of '04 of this point. The actual first oil probably won't begin until sometime mid-second quarter, but our payments start whenever the platform is substantially complete.

And we're now expecting that to be at the end of the first quarter. Then on another thing that happened in the quarter we're excited about, we had record cash flows from both our gathering and treating fees and our oil transport. So a lot of that, obviously, is driven off of our continued Deepwater expansion, but that's very important as we continue to try to move away from being so exposed to the gas-to-liquid margin, and as we continue our asset sales and continue to focus on the Deepwater that keeps moving us in that direction. Finally, on the -- to explain this forecast adjustment; really, this is as simple as we've taken. We had about $94 million in discontinued ops that most of which was a gain on the Red Water sale.

That is now being removed out of the forecast as you can see, which moves our new continuing ops forecast to $330 to $380. And what that does still have some expectations of gains on some asset sales that we're in the process of wrapping up right now, some of which have already been concluded. And this range assumes -- the high end of the range assumes all that concludes; and the low end of the range would be if only the one sale that we've concluded at this point happens there. So we're feeling good about it and overall, actually, our operations-- what's happening from continuing operations is more bullish than where we were when we reported back in August. That's what I've got and I'm going to turn it over now to Bill Hobbs in Power.

Thanks, Alan. We're on slide 32. The accrual losses are primarily due to depressed spark spreads, as we saw spark spreads decline from the second quarter levels. Mark to market earnings include the impact of the determination on the Allegheny contract, which Don and Steve referenced earlier. We had a slight increase in interest rates that produced a small gain. The gain on the sale of assets is predominantly due to the sale of our interests in Espeed which is an electronic trading platform. Looking at the year-to-date numbers, the accrual loss represents depressed spark spreads as well as the first half of the year we were foregoing profit opportunities in order to preserve cash and liquidity.

The mark to market gains does include Allegheny termination with the remainder coming in gains in our derivative gas book. The other category includes $34 million payment as part of the California settlement, a $20 million settlement payment to the CFTC, $13 million of severance costs and several small adjustments. Gain on sale of assets is primarily attributable to the Jackson contract sale to Progress Energy. Turning our attention to slide 33, this is a slide you saw in our second quarter presentation. We put it in here, again, as a reminder that given our stated objective to exit the power business, it does create some accounting difficulties for us. This is also something that we'll go into much more detail on November 21st in our tutorial.

Looking at slide 34, as Steve indicated, we continue to stay focused on risk reduction, cash flow generation, and honoring our contractual obligations. We continue to make progress on sales of parts of our book that, as Steve also indicated, totaled almost $600 million since June of '02. And we have been a cash flow contributor in 2003. The primary drivers of that cash flow are listed below the Allegheny termination-Jackson sale. The reduction in working capital requirement. Looking at the portfolio realizations, SG&A and others as you'll recall in our 10(k) we had forecasted for 2003, negative cash flows of $83 million coming out of portfolio. Certainly, as that indicated, spark spreads were not as robust as we had hoped. So that number would be slightly larger.

In addition to that, we did have the $34 million to California, $20 million to CFTC, $13 million in severance costs, and $108 million in SG&A which brings you roughly to that number. Also, we still warehouse the working capital requirements and margin requirements for our E & P and Midstream businesses and that was the $61 million negative cash flow. Looking at slide 35, that's an update of the value of our book. As you can see it has reduced in value by a little over $400 million. Notice that the majority of that decrease is coming in the outer years. Year six and beyond.

And also with the termination, the Allegheny contract, some of that value was realized in the payment; but also now that we are in effect longer in California, we've taken additional risk adjustments. That really makes up about half of the $400 million. Looking at slide 36, we'll continue to stay focused on exiting the business, as Steve indicated, continue to focus on reducing risk, generating cash, and making sure we're honoring our contractual commitments. It is a tough market. Steve talked us through that earlier. A lot of the values in our west book, a lot of attentions we're putting there and trying to monetize that position it's certainly taking longer than we hoped.

But when you look at our east positions, although, they are primarily flat to slightly negative in value, they are certainly offer upside in the future as spark spreads improve. Again, in our tutorial, we will be walking through a lot more detail which I'll share with you in a minute. You look at slide 37. Just to try to give you a feel for where our power positions are located, and here we're using an independent consultant, CERA, which is Cambridge Energy Research Associates. Their view of the NERC regions where we have our electric positions located, and if you look here, it's their best guess as to when expected margins are going to return; and the way they define expected margins is largely when supply and demand come back into balance and new generation is required.

You look at slide 38, we now have overlaid our positions and -- in that same time frame, and we've also included our hedge positions during those time frames. The key take aways are that we're largely hedged into those expected recovery periods in three of our positions. Where our difficulties lie, in the Kinder Morgan Jackson position, which is in the midwest, and the Claro position in the southeast. Then we'll obviously be taking efforts-- making efforts to try to further increase the cash flows and create more security of cash flows in those positions.

On slide 39, we have referenced the tutorial. Again, that is going to be a continuing effort to create more clarity around our power business. We're going to take a look at each of our positions; the outlook and the strategies by market. I think more importantly, though, we'll go into detail about the parameters around how we value those positions, so you can build your own conclusions around our book. We're going to talk about how we risk adjust cash flows in more details so when we talk risk adjust details it will become clearer to you as to our methodology.

Of course, Andrew will be speaking as to how this all ties into our financial data, how we report and how it shows up in the GAAP financials. So with that, I'm going to turn it over to Andrew Sunderman to talk about enterprise risk management.

Thanks, Bill. Looking at slide 41. As we talked about in the second quarter conference call, the enterprise risk management group was going to focus on portfolio commodity risk and portfolio credit risk. We want to give you an update on some of the successes Williams has had to date. Ralph touched on it in his presentation, but so far, we have focused on hedging our gas link primarily in 2005, we have successfully completed several hedging programs between $4.65 and $4.70 a deca therm and that had two positive results for our company. It increased cash flow certainty during that time period, in addition, it has reduced the margin volatility that we see around our positions. That will be evidenced on the slide when we get to slide 42.

In addition to that, we focused on reducing credit support and the working capital needed for our commodity businesses. Several successes there. We've been working with the NYMEX over the past 15 months to reduce our margin requirements from a peak of 300%. We've successfully gotten those down to a 100%. That is on par with any other company that does business on the NYMEX. In addition to that adequate assurances, prepays, and margins have been reduced and continue to be reduced. As our credit improves and as we continue to go into the markets, that can be seen by the graph that we show at the bottom of slide 41. You can see the breakout there of the total collateral required for Williams at this time is $961 million.

You can see how that is broken out between business units so that you can begin getting a better understanding of if the power business were exited, what type of collateral requirements would still be required, and the timing of return of those collateral requirements. Moving on to page 42, we talked about sensitivities in the past call. As I've referenced, our margin volatility- that's the amount of cash we're required to maintain for time periods to meet our hedging requirements and maintain our hedges. As can you see, that number I believe in the last conference call was about $390 million, that number is now down to where it's at a peak of $308 million about six months out. It continues to reduce beyond that to about $214 million. Our program of trying to continue to reduce our working capital needs as well as balance our hedging programs is working successfully.

In addition to that, around commodity sensitivities; for everyone to be able to model, we've looked at a $1 correlated natural gas price move. As you can see in 2003, since we're near the end of the year there's very little effect on 2003. For 2004, the correlated move of $1 move in natural gas across our Power portfolio, our E & P portfolio, and NGL portfolio is plus or minus 85 million. At this point, we tend to be short natural gas in 2004. So that should give you some ability to model some expectations around our portfolio.

Lastly, we will be joining the Committee of Chief Risk Officers and look to lead the efforts that they've undertaken to bring transparency in compliance to the trading and energy risk management area. With that, I will turn it back to Don Chappel, our CFO.

Thanks, Travis. Let's take a look at slide number 44. 2003 forecast segment profits. As you can see, a total segment profit from core operations at $955 million is expected to increase to a range of $1.2 billion to $1.35 billion by the end of the year. The Power business which is currently at a $256 million profit is expected to be in the range of $150 million to $300 million. While we only have a couple of months to go, as we know because of mark to market volatility principally, it's more difficult to forecast that within a narrow range. In total, our segment profit of $1.2 billion as of the end of the third quarter will grow to $1.35 billion to $1.65 billion by the end of the year. That's in line with our prior guidance.

Let's turn the page and look at slide number 45. Some additional areas of guidance EBITDA, $1.9 billion to $2.3 billion. Cash flow from operations is $600 million to $800 million, which is down slightly from our prior guidance of $700 million to $900 million; with the principle change being in the Power business resulting from weaker spark spreads and then additionally, the cash associated with some of our debt retirement. Income from continuing operations continues in the similar range of negative $50 to a positive $150. The change-- the income before the change in the accounting principle $150 to $400. That accounting principle change EITF '02 to '03 impacted earnings by $761 million dollars to result in an expected loss of $600 million to $300 million or $1.15 to 60 cents both losses.

Turning next to slide number 46, it's our reconciliation of net income to EBITDA and the components are detailed there for your review. And I won't speak to each of them. Let's turn next to slide number 47. Our segment contributions, which summarizes our 2003 forecast for segment profit and DD & A by segment. Again this is for your reference. And I won't speak to it. And then slide number 48, our consolidated 2003 to 2005 outlook continues to be strong. Segment profit dips a bit in 2004 from 2003 as a result of the many gains and other unusual items that are included in our 2003 results. You can then see it growing nicely in 2005.

I'll walk you through the major components of the changes here in just a moment. DD & A is fairly consistent around the $700 million range. Cash flow from operations grows from a $600 million to $800 million range this year to a $1 billion to $1.3 billion next year, them to $1.4 billion to $1.7 billion in 2005. Capital expenditures this year will total somewhere in the range of $950 million to $1 billion, expected to be in the range of $600 million to $700 million in '04, and $700 million to $800 million in '05. Tax rates 3% to 6% in '03, then increasing from 3% to 25% in '04, and 22% to 25% in '05. The debt to cap ratio we see being reduced to a level of 55% or so by the end of 2005. On page -- slide number 49, take a look at some of the drivers of the changes in segment profit and cash flow from operations.

Let me walk you through the key components. Looking first at the category of segment profit in 2003. Again, our forecast $1,350,000,000 to $1,650,000,000. If we reduce that by the net gains associated with asset sales of about $300 million, and then account for E & P production increases, Deepwater improvements, gas pipeline expansions, and then with a relatively small other net, you can see how we walk from $1,350,000,000 up to $1,100,000,000 or $1,650,000,000 to $1,400,000,000. Looking at CFFO for 2003 to 2004, reduced interest expense and related fees contributes $425 million to $500 million. Again, the variance there would be dependent upon our operating cash flows. So at the high end of the range, we would assume more debt reduction. At the lower end of the range, a bit less.

Again, Midstream, E & P and Gas Pipelines all contribute to the growth and cash flow from operations. Then that change is related to tax and other payments of $60 and other net now at $50 to $25 number brings us to the $1 billion to $1.3 billion. Then walking forward in segment profit to 2004, again Midstream, E & P and Gas Pipelines contribute nicely to the change. The other is a $90 million number leaving a total of $1.4 to $1.7 billion. Cash flow from operations, growing from $1 billion to $1.4 billion at the low end of the range or $1.3 billion to $1.7 billion at the high end of the range with the key components again being reduced interest expense ranging from $20 to $140, Midstream, E & P, and Gas Pipelines again contributing strongly to the growth; and other net ranging from $160 to $40.

So we hope this helps you understand how we roll forward from 2003 to 2004-2005 in these key areas of guidance. On the next page, page 50, once again I'd like to share my thoughts regarding our financial strategy. I see us maintaining a cash and liquidity cushion of $1 billion. That's, we see it necessary for volatility and working capital particularly with marginable hedges. We think that our requirement is substantially less than that, but this provides us with a great deal of cushion. Additionally, we'll continue to delever and striving for investment grade ratios by the end of 2005. We'll establish a new liquidity and credit facility when it's attractive.

That will reduce our cash on hand requirements and allow to us use some of that excess cash to reduce debt. We believe that credit facility is available to us, however, we continue to evaluate the terms and at the appropriate time, we'll act on that. We expect to use our free cash flows first to pay scheduled debt retirements, then for early debt reduction, disciplined EVA-based investments; and then finally, as we return to investment grade, to consider dividend increases and/or share repurchases and the like. I'd just like to note that in the area of delevering, in terms of the key components of the path forward; today we have a cash balance of $2.7 billion. We have cash requirements including our cushion of about $1 billion which leaves an excess of about $1.6 billion.

I'd also like to note we have upcoming maturities in the balance of '03, '04, and '05; assuming the fee line packs convert which we expect them to. Again, those maturities for the balance of '03, '04, and '05 total $1,350,000,000. So we have excess cash on hand of $1.6 billion with maturities over the next 2 and a quarter years totaling $1,350,000,000. We're clearly in a position not to require any refinancings or additional financings. Additionally, the expected proceeds from asset sales totaling $800 million to $1 billion. The free cash flows that I detailed for you, even at the low end of the range, total $1.1 billion. The fee line pack conversion totaling $1.1 billion will reduce debt and then finally, a new credit facility when we're able to bring it on at attractive terms and conditions; will add somewhere in the range of $800 million or more in terms of cash available for debt reduction. So with that, I'll turn it back to Steve.

Thank you, Don. As we have tried to do during our conference calls throughout 2003, we're endeavoring to have our presentations be responsive to the questions, for example, that Don and I receive when we participate in energy conferences or questions that Travis and his team receive periodically. And all of this is designed obviously to create greater transparency around our businesses. We hope that we've done that. If would you turn to the next slide, slide 52, I would just use this to summarize what we have talked about today. I used this slide last time.

The first four issues shown on this slide are the key issues or key themes that are somewhat long-term in nature. But nevertheless, we will be focusing on these and just going through those, we intend to sustain solid, core business performance, and I think you've seen from the business unit presentations that we have some positive things happening within each our businesses. Secondly, we will delever the balance sheet. We've certainly seen evidence of that, particularly with the recent tender offer. Thirdly, we will maintain investment discipline. I think evidence of that is the adoption of EVA. We think that that will drive appropriate behavior throughout our company, and ensure that future investments are value adding.

And we want to position our core businesses for future growth. Clearly, we intend to maintain our competitive advantages and positions and take advantage of growth opportunities that are present in each of our businesses. So those are more long-term in nature. The last four are more short-term in nature. Obviously we do need to wrap up our asset sales. We will do that. We've given you a schedule and the timing as to when those will be completed. We will rationalize our cost structure, and we've already taken steps as we have documented and now we're on to a new initiative framing the future, utilizing AnswerThink to help us out.

We continue to resolve the distractions around Williams and around this business; and I think the CFTC settlement is an example of that. And we're committed to exiting the power business. We've made progress in terms of the $600 million that we've brought back in. Last slide is one that I closed with last time. This one simply measures the progress that we're making on our restructuring efforts, and this is a slide that we review with our board regularly. Clearly, we're past the stabilization column, but under the restructuring column, we have, I believe, effectively managed liquidity and we've demonstrated that we have regained access to the capital markets.

But we've also made significant progress, and you can see emerging check marks on the other three items in terms of asset sales were 85% complete. We've also made significant steps in delevering the company with our tender offer, and we are rationalizing our cost structure and clearly have already reduced SG & A by some $400 million in terms of year-to-year comparisons. My hope is the next time that we talk that we can speak in much more detail about the last column, about re-emerging from the challenges that have faced us over the last year. Re-emerging with the very bright future, and clearly this is a Williams that is worth restructuring. So with that, we've motored through the slides and a little over an hour. We have plenty of time left for your questions and we'll be happy to take those now.

Thank you, Mr. Malcolm. Once again, star one on your Touch-Tone telephone for questions. We'll take our first question from Scott Soler of Morgan Stanley.

I appreciate everything you all are doing. I got a couple of questions for you. First question is regarding the Powder River and maybe Ralph can touch on it a bit. As y'all know, Northern Border Partners recently took a write down on their Power River Basin assets. There was a write up this week in Natural Gas Weekly about the Powder. Ralph, can you comment on what the rationale for that was? Is there anything in terms of insight you can provide us with what's going on? Is there any issues y'all have in the Powder River in terms of well performance?

Scott, we don't see that. I'm not sure. I was traveling this week, I did not see all that. Some of the writedowns you may see, our best guess is some of the participants that got in must have had different expectations or paid differently to get into the basin. We were along with our partners, we were first movers out there.

We believe we've accumulated the best acreage and we continue to see the well performance do exactly what we want it to. We're excited about moving into the Big George area, particularly under the new EIS that we've been able to drill 48 wells under the new EIS. Our performance is right on with what we expected. I'm not sure what their expectations were or what their initial investments were. That might be what the problems are.

Okay. Then my second question is, I guess probably for Andrew and then Don. I now y'all have both been involved in EVA implementation. Can you talk about when you expect it to be fully implemented. Also in any of your estimates of cash balances, liquidity, et cetera, have you built in any assumptions on what cash can be generated, what working capital improvements might be had by EVA implementation?

This is Don. We expect to be implemented effective the first of the year 2004. It will be kind of a running start so people will be kind of learning as we charge forward, but we will be implemented for the beginning of 2004. Incentives will be linked to EVA throughout 2004. We've assumed no improvement within our forecast associated with EVA. Although, we think there should be some.

Okay. Great. Actually, that's all my questions. Thank you.

We'll go next to Anatol Feygin of JP Morgan.

I have a couple of questions. First one for Ralph. You guys gave us hedges at NYMEX. Give us a sense for basis differentials. If that's something you guys have hedged in through swaps, or otherwise, and at what levels?

Well, the hedges we have for 2004 are $4.03 range. What we said to take everything together and all that typically is around 80, 90 cents you would take off of that. For the 2005 hedges so far, we had originally about $85 million a day done at $3.85. And we laid in new hedges as Andrew and I discussed about $200 million a day at $4.70. That gave us our blended price at $4.44. So again if you take about 70 to 90 cents off of that on average, it will give you your base in price. That counts the bases off, the gathering the transport, and all of the things you can take off.

Right. And is that just what we estimate as the secular differential to the Rockies, or is that something that you guys have hedged in for the '04/'05 period?

We have a combination of both. We have basis hedges on and we also have firm transportation out that equates to that basis hedges. Those are the kinds of realized prices we expect to get after we take all of the hedges into account or the firm transportation.

Thanks, Ralph. My second question is on -- if you guys can provide a little bit of color on the Alaska refinery and the Canadian midstream assets in terms of operating income contribution; and obviously how much of that would go away as those assets are divested late this year, early next?

Let us work on those numbers as we've done in some prior calls. We'll find those numbers and respond later in the call.

Thanks very much, Steve. My last question is on the Power segment, I guess it depends on how you slice the numbers, but if we look on sort of accrual plus cash SG&A rate, you guys lost somewhere in the neighborhood of $70 million and then some mark to market on top of that. How does that reconcile with your previous guidance in terms of hedges in that portfolio off take contracts, et cetera, in the 70 plus percent range?

Anatol, as I indicated earlier in the 10 k, we indicated we had had or were projecting negative cash flows given the hedges we had locked in, in our market outlook. Certainly in the third quarter that's normally a more robust period so even on the unhedged megawatts we had, we just didn't see the income come in that offset the hedge revenues we've had. So that is when you look at the SG&A and the accrual losses, that's primarily just due to we just didn't recover as much on the unhedged megawatts that we were hoping to produce.

Is it -- are you saying sort of that the hedging strategy was to be more exposed in the third quarter because that's historically a stronger spark spread quarter?

Yeah. I guess that's one way you would look at it, Anatol. We had to leave some megawatts unhedged. We don't want to be overhedged. We would expect to be able to produce those. And again, the third quarter, especially in California, has traditionally been a good quarter for us. This year just didn't materialize.

Thanks, Bill. That's all my questions.

We'll go next to Jeff Dietert, Simmons.

Following up on the same issue, Bill, on page 35, you talked about being longer in California. Can you give us any type of sensitivity on a dollar move in spark spread and what spark spread is break-even there?

Well, Andrew may have that, so --

Yeah, on a correlated point of view from what I talked about in the energy risk management section; a dollar move in gas, we're going to correlate it back to gas. Our portfolio assumes about a 9200 heat rate. So you can determine there what a dollar move in gas would do from a spark spread point of view. That's not necessarily directly related just to California. That's more across our entire portfolio.

We can get you the numbers if you want just California. I don't have them with me, but since we look at it on a portfolio basis, that's probably a better way to look at it.

Okay. That's the material you presented on page 42?

Correct.

Is that dollar move in natural gas, you said you were short in 2004, so a dollar move higher is negative $85 million in 2004. Am I interpreting that correctly?

Across the entire corporation if gas went up a dollar, you would be interpreting that correctly. That's not necessarily whether NGLs would be up or down or whether Power would be up or down but as a corporation, we would tend to have a negative $85 million, that's correct.

That's helpful. Thank you.

Hey, Jeff, too, when we do our tutorial, we will by position be talking the kind of metrics I think you guys want to see.

Very good. Thank you.

Well go next to Maureen Howe, RBC capital Markets.

Thank you very much. Good morning. A question on page 49 where you reconcile 2003 to the future years 2004 2005. You take out $300 million in gains. I'm wondering if you have anything in those numbers for 2004 for the gains or potential gains, let's say, on the Alaska refinery or the Canadian assets?

Give us a second, please. No, there's no assumed gains in 2004 related to any of those assets.

Okay, thank you very much. Just one other question. It is a follow-up question from the previous one, the previous caller. That has to do with the sensitivity around the gas price of plus or minus $85 million. Can you give us a sense in terms of off of what base? In other words, what base are you using for your forecasts going forward?

NYMEX prices. I would say that our point of view going forward at least for 2004 is probably about 35 to 40 cents lower than where the current NYMEX is at. So I think we're more conservative than where the current NYMEX is at.

So if we take it off of the current spot or the current forward strip?

The forward strip.

Thank you very much.

This is Steve Malcolm, let's go back to the question that Anatol posed. I would just preface the answer that I'm going to let Alan Armstrong and Phil Wright respond with, that we are engaged in ongoing negotiations and we just have to be careful with what we have to say. So the comments we provide here, the information is about all we can do at this point in time. So with that, Alan?

I am going to try to speak to that question in a way that gives you an order of magnitude understanding of that. The -- in the third -- the three quarters to date in '03, the Red Water and West Stoddard, the amount of operating profit that got moved into discontinued ops was about $7 million. So that was for the first three quarters. What was in our plan for the assets that we are retaining or sorry that we are planning to sell in Canada, our plan was roughly $15 to $20 million of operating profit in for the '03 time period; '02 performance was a little stronger, quite a bit stronger than both of those numbers, primarily because we had some strong margins in the third and fourth quarter of '02.

And Alan, I think the question also related to any flavor or color on the asset sale process in Canada?

Of course, the remaining assets that we have to sell there are straddle plants which is the very large Cochran plant. Our interest in E-5, the 50% we own with BP, and our ownership of the Empress 2 battle plant. We under the process of recontracting for the ethane in those assets, and that was as a result -- the contracts required that renegotiation. And once we conclude that, which we expect to be sometime in the first quarter of '04, then we'll move into another sales process for those assets.

Thanks, Allen. Now I'll it turn to over to Phil Wright who will speak to the Alaska question.

First of all, with respect to the sale process, we're in the latter stages of negotiating definitive agreements. We're being diligent and thoughtful in those negotiations so as to maximize value for Williams. This obviously is taking a bit longer than we had previously estimated, and we do expect to close on this transaction sometime in the first quarter. Meanwhile, the Alaska business is flowing free cash, and I want to emphasize that since we are not at all in any kind of a fire sale situation. I would like to be able to give you detail on that amount, but that asset and enterprise is in discontinued operations, and we do not disaggregate that number. I'll just say that it is flowing positive cash.

Thanks, Phil. Now we'll go on to other questions.

And we'll go next to Carol Coale, Prudential.

Most of my questions were answered but I did wonder if could you provide a little more detail. I won't want to rehash the spark spread issue. I heard Doug mention earlier it was primarily related to California. Can you give us an idea of what your spark spreads averaged, and what you need to be profitable, and what your outlook for spark spreads is? Is this a west coast issue or in other regions as well?

Carol, it's Bill. We have our tutorial on the 21st. We'll walk through what we have hedged, locked in cash flows, what our projections are for each of those regions. Part of that, you will see, what kind of break-even economics are going to be for us. So we prefer to just discuss it at that point.

Okay. And is that going to be in New York?

Travis is saying it will be webcast.

A follow-up on Scott Soler's question regarding the Big George. I also read the article in Natural Gas Week. It also alleged that the Big George because of it's density and dewatering issues, would not be -- would probably not be productive until 2005. Do you have any thoughts on that statement?

What we are as we were all delayed to get our permits from the BLM due to the lengthy EIS process. So a number of wells we are drilling right now in the Big George do take 12 months to dewater. Some areas that are close to production will come on immediately. We believe we have some of those areas. So what you'll see from a number of producers and also from us. Some may have declining production. We think ours will stay pretty level during next year.

The declining production is because of the Wayadeck wells are starting to produce out fully, and the Big George wells that are being drilled now do take 10 to 12 months to dewater. We think our Powder production will essentially stay flat because we do have some areas where we think gas production will come on immediately. But in general it does take 12 months to dewater those.

We just started getting permits in the third and fourth quarter for that. I do need to clarify one thing if I could. Just to make sure a couple of my guys called me and wanted to make sure when I talked about the 80 to 90 cent or so that I said would come off of our hedge price; that I did clarify that that does include the gathering of about 40 cents or so. I think I said that, but just in case, I didn't want to think that that 89 cents was a basis only. That's all in basis and gathering and transportation and all those things. So hopefully, that helps.

Thank you, gentlemen.

Now we'll take some questions from the web.

Yeah, we do have some questions. Let's try to cover some from the web site. The first couple are for Don. Don, can you comment on how the tender offer is going?

Sure can, Travis. Again, we tendered for all of the $1.4 billion due in March of '04 and additionally tendered for a few hundred million of what we consider to be stub debt. A lot of issues that were just a little bit messy in total. We successfully tendered for $950 million on the stub issues, we did receive more than 50%, substantially more than 50% of each of the issues.

We will strip the covenants. On the $1.4 billion that's due in March of '04, we received more than half. So again a total of $950 million of principal reduced. The $700 million, or so, associated with March '04 has already been paid out. The balance related to the stub debt will be paid out next Monday. So quite successful tender.

Okay. Another question for you, Don. Do you provide any detail or breakout of the expected segment EBITDA for 2003 if we exclude gains and impairments on asset sales?

I'd be delighted to. If we take a look at slide 47 if that's something you can pull up fairly quickly. If not, just take a note. In the E & P business, we had about $95 million of gains that are expected throughout the year. Most of those behind us. All of those behind us, in fact.

Midstream, a total of about $60 million including about that much in the fourth quarter. Power gains at totaling $200 million, which we've previously detailed for you. Corporate and other, $80 million loss. These are associated with impairments. And Gas Pipelines impairments totaling about $25 million. So I think that all -- that nets out to $260 million of expected gains net of impairments for the year.

Okay. A question for Andrew. How does the increase in interest rates alter the profits in the Power portfolio?

You'll recall from several of the conversations we've had in the past, several years ago when we were mark to market company and focused on forward growth, our program included hedging of our interest rate exposure in our portfolio. Since the change in accounting rules at the first of year, the mark to market gains or losses on the interest rate book are not considered a hedge any longer, so we are required because of GAAP to report those through the income statement as they change. Even though they are an economic hedge of the underlying value in the portfolio. So the simplest way I can say, the accounting rules require it even though cash flow wise, there's not a change in the forward value.

One last one from the web for Ralph. How many wells must be drilled in order to increase gas production by 10%?

Well, what we have is, in our capital budget range of $300 to $350 million, that is a range of wells depending on what we do in the Powder actual wells between 1,200 and 1,300 wells about 900 or 950 of those are in the Powder. Around 180 to 200 are in the Piceance and San Juan's around 60; and Arkoma is around 50 or so. Bottom line is we said before in other presentations, we think we can grow between 10 and 15% in our production. We believe we will each year. And that budget should put us in the upper range of the 10 to 15% production increase. That capital expenditure number I mentioned is around 1200 to 1300 wells with obviously a number of those wells are in the Powder because of the very quick drilling time. I hope that answers the question.

Before we go back to the phone questions, let -- questions, let me mention one other thing. We've got a couple notes that people might be having problems hearing the sound on the webcast. I'm told if you close out the viewer and come up again, it could fix the problem. In any case, the whole presentation is available for replay later this afternoon so you can hear it that way. So let's go back to phone questions.

Thank you. We'll go next to Winfred Fruehauf, National Bank.

Good morning. I have two questions. First on the California refund case. Can you please indicate to me what the current status is of Williams' possible exposure to fines or similar charges?

This is Bill Hobbs. We are still working with FERC on resolving refund issues around economic withholding and physical withholdings, sorry. And currently, we feel we're adequately reserved with those issues. Probably, the timing will be sometime well into next year before those issues are resolved. Again, I think we're adequately reserved and feel good about our position.

Is it correct that your company has agreed to a $45.2 million of settlement obligation?

No, I don't think we've disclosed any potential liability with that.

That number was reported by Reuters on the third of November, but since I'm the not the one who's blindly relying on news agencies, I thought I'd ask the question.

I think we feel we're adequately reserved for exposures we have.

The other question is for Doug Whisenant. It's relates to the status of a proposed pipeline to Vancouver Island. Is this partly comatose or dead, or is there still some hope for it's ability to proceed?

Well, BC Hydro has long identified the need for new dependable generation capacity to meet its long-term electrical load on Vancouver Island. And in response they pursued two alternatives which included a combined cycle turbine generation facility, and the Georgia Strait crossing project which is a natural gas pipeline jointly sponsored by BC Hydro and Williams. Public hearings on the generation facility took place this summer and in September, the BC utility commission basically found that there wasn't enough evidence to conclude that this plant was the least cost alternative and they encouraged BC Hydro to proceed with tenders to determine the best option. So they have initiated that.

In the meantime, we believe that the Georgia Strait crossing project is and will continue to be a best alternative for supplying natural gas and this pipeline project will continue to be the benchmark for this CFT process. The project development costs incurred to date of approximately $32 million has been funded by BC Hydro, and it's anticipated that if the project goes forward, Williams net investment would be about $31 or $32 million. Again, the in-service date is scheduled for October of 2005 of the pipeline.

And is there any obligation or liability on Williams for the project development costs incurred so far or has it already borne its own chair?

Well, if the project doesn't precede the contractual agreements between Williams and BC Hydro specify responsibility for development costs. Williams is responsible for obtaining the U.S. permits and regulatory approvals, which are substantially complete. BC Hydro is responsible for all Canadian permits approval.

So right now, if I understand you correctly, the ball seems to be in BC Hydro's court?

Yeah. We need to see what comes out of this CFT process.

Thanks very much.

This is Bill Hobbs again. I think you are referring to the $45,000 settlement we reached with FERC on the Enron gaming practices.

I wasn't sure if it was $45,000 or $45 million because some of the numbers seemed to be in millions and others not. So I wasn't quite sure. But if it's $45,230, I certainly won't lose any sleep over it. As for the rest, who knows? Time will tell how this will all end up for your company and others. Thanks very much.

We'll take our next question from Kurt Launer of Credit Suisse First Boston.

It's actually Fisel and Phil. Does the increased segment profit from the production in '04 and '05 E & P, is that directly correlated with the incremental cap ex from '04 to '05 during the same time period; and what is your assumption on the unhedged price for gas in that increased production segment profit?

Well, it is a function of the increased drilling we will be out doing in the field. Our point of view is $4.25. That would be a NYMEX type point of view price.

Thank you.

You're welcome.

We'll go next to Kelly Kringer, Bank of America.

I have two questions. As I look back on your August, I don't know the date here, your August 12th conference call, you had your production range for this year at 437 to 455 million cubic feet a day equivalent of production. It looks to me like based on the first three quarters, you guys are trending a little above that. Is that accurate or am I missing something there?

That is accurate. Our third quarter production was about 461 million a day.

So presumably in the first two quarters it was around 500 million cubic feet a day. So fourth quarter, if it averages like the third quarter you'll be at about 480 for the year which seems like well or comfortably ahead of what your production guidance was previously. So is it --

we -- the range we see is between 170, 172 bcf, which is -- it could be higher just like you mentioned. That's like four, around 465 to 471 a day. There's apples and oranges there with discontinued operations and all that, but net production should be in that range of the ongoing business we have.

Okay so if we take the first three months of the operating summary and add whatever to get to 170 to 172, that's the right number for the fourth quarter?

I think it is. It could be slightly higher. I think it's a good number.

On the Alaskan refining, can you tell us how much working capital you might extract out of that if you are able to sell it?

We haven't disclosed that.

Okay. Thank you.

And we'll go next to Sam Brothwell of Merrill Lynch.

Hi. I think most of my questions have been answered, but just in terms of looking at the E & P segment once you strip out the gains obviously that's done on page 28, but the decline due to properties that have been sold, can you break that out of the 13%, maybe give us a same-store comparison there?

I think if you look at the 13%, and I don't have exactly each property in front of me, but the 13%, about 7% of that is due to properties sold. And about 6% of that would be due to declines in the basins that we kept that are lower than last year due to decreased capital budget. For example, dropping to one rig in the Piceance has dropped us down, through the third quarter versus last year. We need to be in the Piceance, to run flat around 3 to 4 rigs running to do that.

We held it as hard as we could during the first and second quarter as we had a decreased budget and only one rig running. The cumulative effects of lack of drilling hit us in the third quarter. So if that helps, of our approximately-- of our retained properties in the 13% down, half of that roughly was due to the properties being sold and the other half is due to decline in the existing properties that we're keeping.

Okay. We should expect that latter trend to reverse itself now that you are back out there with more rigs?

Absolutely. Absolutely. We should see that trend go the other way.

Okay and on the Midstream given all your activity in the Deepwater, I know your capital budget doesn't contemplate much right now, but are you keeping an eye on other opportunities out there, you know, along the lines of the Gunnison or Devil's Tower, or should we expect things to be pretty flat there once those two come on?

Most of those would be capital that would come to spending probably in the '05 time frame, but most of those items would be both on or expansion of a lot of the infrastructure that we've established out there to date and would be high return, high margin business for us. There is a tremendous amount of opportunity out there with all of the development going on, on the more marginal prospects out there.

Okay, thank you.

We go next to Donato Eassey of Royalist Research.

Steve, I wanted to find out from you, or Bill, you mentioned a couple times that you are exiting the power business. But does that mean you are staying in the gas marketing and trading business for a longer term relative to the power side? Thanks.

Good to hear from you. One thing we're currently evaluating, we'll be an integrated gas company coming out of this. We have to buy gas for our processing plants. There will be inherent opportunities in and around those activities that we'll certainly be looking at. There is certain amount of market knowledge gained by being in the market. I would expect us to have some ongoing marketing. I don't expect it to be anything like we had previously. I would expect it to be more of a smaller boutique type shop that's trading in and around the assets we have.

I appreciate that. With respect to the Midstream, I guess the question is, given what you have in fixed positions out there in terms of pipe and everything, you mentioned the upside was there for other people. You don't necessarily have to build a lot to enjoy expansion opportunities that may come your way. Is that a simple way to look at it?

Approximately into the trunk lines and platforms that we built out there, and so you are exactly right. In fact a lot of business is likely to come to that without any investment on our part that's not reflected in our forecast.

I appreciate it. Good luck with the rest of the year.

We'll go next to Jay Yenello, UBS Securities.

Good morning. I do think there's more work for transparency, particularly walking through all of the slides that include one-time items. I realize there are some accounting rules we have to adhere by, but I think it would be a great service to everyone if these slides were cleaned up for all of the one-time items. In line with that, similar to a question before, slide number 48, am I correct to assume that 2004 and 2005 guidance excludes all gains in sales on assets?

There are -- there is little in terms of gains or excuse me, gains or losses on sales are assets in 2004, 2005. I think it's immaterial.

Okay. And a quick follow-up. Slide number 49, I think it was mentioned that there was no description of $90 million of other. Can we have some idea what that might be?

We're not prepared to go into that level of detail here at this call, and we'll try to get you some more detail next quarter.

Okay, thank you.

And we'll take a follow-up question for Maureen Howe of RBC Capital Markets.

Thanks very much. On the financial highlight report and operating statistics, page 6, and this likely a question for Doug. We don't seem to have the average daily firm reserve capacity for Transco there. I'm just wondering if we could have that number for the third quarter? -- this is on page six.

Yeah. Yeah, the -- I don't have with me right now the exact number, but we haven't added any capacity from the --on Transco other than this 51 million that really didn't come in-- 51,000 deca therms per day that came in November 1st. So the number would be the same as in the second quarter.

Okay that's great. Thank you very much.

And we'll take some questions from the web.

We have one last question from the web. And then I think we've covered all the questions. This question would be for Ralph. What percent of your E & P production is gathered by our Midstream division?

Currently, I would say that's about 15 and 20% of that. I think it's also important to point out that we, meaning the E & P group, gathers all of our own Piceance gas; and substantially all of our own Arkoma gas, and in the Powder River, our 50/50 partner gathers all of the Powder River gas that we have there. So Midstream itself is between 15 and 20%. Piceance we gather all of our own gas, Arkoma almost all of our own gas and in the Powder, our partner gathers all of our gas. So we feel good about our gathering partners there.

Also, one other thing. Some of the questions on the Powder River. This is not on the question from the web. But the Powder River production is 1 bcf a day. The Big George is making an impact already. The Big George is about 100 million cubic feet per day of that 1 bcf per day. I think from our perspective, the Big George is starting to have an impact on the Powder River. Thank you.

Thanks, Ralph. This is Steve Malcolm. I think that we have taken all of the questions that there are no other people that are waiting to ask a question. There was one more question for me that came in on the web: going forward, what worries you the most about your industry and Williams? I guess it's the noise around the ongoing investigations of the industry that are being conducted by FERC and the D.O.J. and the CFTC; and the uncertainty as to where those may lead.

We're certainly aware of the extraordinary political pressure that those agencies are under to find the bad guys, and, you know, we are somewhat exasperated at times by all that's going on; and we had hoped that many of those investigations would be behind us, but it appears that that's going to last for a while. So that's probably the issue that's most disconcerting to me at this point in time. Thank you again for your interest in our company. We are sincerely excited about the progress that we're making.

We have a very enthusiastic and dedicated senior management team and employee workforce. And we look forward to talking with you again at the tutorial on November 21st. So thank you very much.

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