威廉斯 (WMB) 2003 Q4 法說會逐字稿

Good day everyone and welcome to The Williams Companies analyst conference call. (OPERATOR INSTRUCTIONS). At this time for opening remarks and introductions, I would like to turn the call over to the Vice President of Investor Relations, Corporate Communications and Treasurer, Mr. Travis Campbell. Please go ahead, sir.

Thank you very much. Good morning everyone. Welcome to our call this morning. Just a couple of opening logistical kinds of things, then I will turn it over to Steve Malcolm.

First, all the slides are available on the Website. Obviously if you are own the Website, they will be on the webcast as you watch. But we're doing it a little bit different this morning because we had some additional information that we had. There slides on that we are not going to go through in the presentation, but they are an appendix that is also out on the Website that is available that has additional information that we might refer to in the presentation today.

As always, the call today will include forward-looking statements, so please refer to the statement in the presentation and also that statement that is posted on our Website for further details of risk factors. As always, there are some non-GAAP numbers presented, and reconciliation of those results is also available either in this presentation or on the Website. The Q&A -- at the end of the presentation, we will take questions both on the phone, and those on the Web can sen in their questions in that format as well.

So with that, I will turn it over to Steve Malcolm.

Thanks, Travis. Welcome and thanks to all of the participants for your continuing interest in our company. We are again presenting a great deal of information this morning as we strive to become more transparent and better understood. We have around 80 slides, and I think 25 more in the appendix. We will move through these fairly quickly, and we will have plenty of time for your questions.

Our senior management team is assembled here in Tulsa. Most will be participating in the presentation.

One year ago on February 20th, we presented to you a comprehensive plan designed to strengthen our Company through asset sales, debt reduction, cost savings and a focus on our core natural gas businesses businesses. A year later I believe that we are exactly where we told you we would be.

With respect to slide five, this is simply a reminder that our commercial strategy is to position Williams as a balanced integrated natural gas company with world-class assets in E&P Gas Pipelines and Midstream. We want to operate in key growth markets where we enjoy competitive advantages. Our complementary financial strategy has us focused on maintaining adequate liquidity, de-levering the Company over time and strengthening our balance sheet so that we can ultimately grow our core businesses and create shareholder value.

Slide six is one that we have used many times before and one that we continue to use with our Board as we track our progress. The only point I would make here is that certainly in 2004 we will be spending much more time focusing on emerging as a discipline integrated natural gas company.

Slide 7. Let's look at some of the highlights of the progress that we have made over the past year. Asset sales are about 90 percent complete. $3 billion in net proceeds in 2003. Over $6 billion in assets sold since 2002. During the fourth quarter, we closed on another $173 million in sales.

Our cost reduction efforts continue. We are proud of the fact that our SG&A and corporate expenses from our continuing operations are down about 30 percent when comparing 2003 and 2002. We are making good progress on cost, but there is certainly more work to be done, and we are looking at outsourcing opportunities for the first-time. Our cash position remains very strong with over $2.3 billion of cash available at year-end 2003, and Don will talk a little bit more in a few minutes about how we might use that cash.

In terms of de-levering, we are obviously very pleased to reduce debt during 2003 by about $2 billion, and again Don will talk in more detail about our intentions to do more in 2004. We have restored confidence in Williams in terms of the capital markets, and we have seen solid operating performance by all of our businesses.

Slide eight. In terms of pending asset sales, very briefly we have announced that we have a deal with respect to the Alaska refinery. We have settled on a March 31, 2004 closing date for the sale of the Alaska refinery. Another benefit of that sale is that we will get back two LCs totaling $90 million within 90 days of closing. As well, there is some $500 to $600 million of assets in the Midstream area that we have for sale, and we remain confident that we will complete those asset sales throughout 2004.

Next slide. Slide nine. With respect to power, there is not much change. Make no mistake, we are committed to exiting the business. Since 2002 we have sold or liquidated components of the business for almost $600 million in deals that we believe represent fair value. And as we continue to endeavor to sell the book, we are all about reducing risk, generating cash flows and meeting our contractual obligations. But we recognize there is a great deal of uncertainty around the timing of our exit and the value that we might receive and realize.

And after the $600 million in sales that I mentioned, we are left mainly with long-term complex transactions. The power markets have certainly deteriorated and are expected to be depressed for the next two to three years. The value of our book is primarily out West. We have been very clear with that. The power tutorial that we did in November provided a great deal of additional information. I believe that our efforts in that regard were generally appreciated by the market, and Bill Hobbs will be updating those numbers given during the tutorial during the call this morning. The good news is the cash flows for '04 through '06 are expected to be positive.

Finally before I turn it over to Don, slide 10. Looking ahead, the path ahead for Williams, certainly we intend to focus on maintaining strong business performance in our core businesses. We will be making EVA-based disciplined investments in those core businesses. We will continue our restructuring -- the components of that structuring being the de-levering of the Company over time, the completion of our asset sales program, cost reductions, and the exit from the power business, and we are certainly moving towards positioning our Company for future growth that creates economic value for our shareholders.

With that, I will turn it over to Don Chappel for a review of our fourth quarter and 2003 performance. Don?

Thanks, Steve. I will now run through the highlights of our fourth-quarter and 2003 results starting at a high-level and then drilling down throughout my remarks, and then the business unit leaders will really fill in the picture.

Overall you will see substantial year-over-year improvement and continued improvement in our financial condition, thereby laying a solid foundation for future growth and future value creation. As a result of the significant restructuring that continued throughout 2003, the financial results continue to be affected by numerous unusual and non-recurring items. We will detail those as best we can as we walk through this presentation, and they will be even more fully detailed in the 10-K that we expect to file during the month of March.

As footnoted, the results include certain gains and impairments and asset sales from prior period adjustments that are highlighted. A schedule reconciling from continuing operations to recurring income is available on our Website, and the highlights are included in this presentation. I will look at the results. Income from continuing operations, or actually a loss from continuing operations of 97 million, showed 54 million of improvement over the prior year for the quarter. On a year-to-date basis, full-year basis, the $3 million profit was a $615 million improvement over the prior year, and again we will review the components of that as we walk through the presentation.

Discontinued operations reported 31 million of profitability, a $99 million improvement and for the full-year 254 million or a $397 million improvement. The effect of the accounting change EITF '02 '03 reduced full-year earnings by $761 million after-tax, which resulted in total quarterly earnings of $66 million, again an improvement of 85 million over the prior year, and full-year the net loss of 504 million again reflecting a $251 million improvement despite the effect of the accounting change.

On a per-share basis, for the quarter 13 cents, a 31 cent improvement, and for the full year, a loss of $1.03, a 60 cent improvement over the prior year. On a recurring basis, we reported for the quarter $57 million of earnings, a $10 million improvement. On a full-year basis, $12 million or a $234 million improvement. On a per-share basis, the 11 cents reflecting that 2 cent improvement over the prior year, and on a full year, the 2 cents reflecting the 45 cent improvement.

On the next slide, number 13, I will reconcile from income from continuing operations to recurring just hitting a few of the highlights, starting with that $97 million loss that we reported adding back those gains on asset sales -- I am sorry deducting the gains on asset sales -- adding back the impairments, adding back tender costs and expenses related to the third-quarter or fourth-quarter tender. Adding back 33 million of California refund and other accrual adjustments and then finally an income tax provision gets us from that $97 million loss to the $57 million recurring income, which is 11 cents per share.

Next slide on 14, do the same on a full-year basis, reconciling from the $3 million income from continuing operations down to the $12 million recurring and just hitting on the highlights again, reducing the continuing operations by 337 for the gains on asset sales, 279 is added back for impairments. Highlight the 105 million related to the prior period items that we discussed during the second quarter. That all netting down to the $12 million number that we see or 2 cents per share.

The next slide, slide 15. The BU leaders will run through this in detail for each of their respective business units, but our core business units deliver solid performance at about 1.2 billion of segment profit both in 2003 and 2002, both of them as reported and on a recurring basis. While the year-to-year comparisons are flat for the three core businesses, I think you will find good progress that is masked somewhat by the restructuring and other factors.

Power reported sharply improved results both for the fourth quarter and 2003. Consolidated segment profit is up sharply driven by the changes in power, which we will run through in detail.

Next slide, number 16, has a reconciliation of EBITDA. I will not spend any time to walk through that, but it is there for your reference.

The next slide, number 17, 2003 segment contributions. This slide will help you understand how each of our businesses contributed to the $1.9 billion of consolidated segment profit. All of the businesses contributed for the full year 2003, including power.

The next slide, number 18, is a summary of our cash. Number one, I will start with the beginning of the year. In 2003, we started the year with a 1 billion 736 of cash. We finished the year with 2.3 billion of cash, of which 207 million was restricted, leaving about $2.1 billion that is unrestricted. Walking through the fourth quarter, we started the quarter at 3.4 billion. Capital spending reduced that by nearly 400 million. At the same time, we retired 1.2 billion of debt, and we had a number of other changes that drove us to a year-end number of 2.3 billion, which is on target with our previous guidance. That positions us well for further debt reduction, as well as to maintain a very substantial cash or cash and liquidity cushion to handle working capital requirements that may be required.

The next slide, number 19, I will walk through the changes in our debt balance. We started the year with nearly 14 billion of debt. We finished with less than 12. The components of that was we removed about 900 million associated with discontinued operations. We paid down 3.1 billion of debt. We issued 2 billion of new debt to end the year at that 11.979 billion. Also, very importantly the effective interest rate was reduced from 10 percent to 7.7 percent, a very substantial reduction in interest costs. So the total net decrease in debt was about $2 billion, along with a $600 million increase in cash gets us to about a $2.6 million change in net debt for the year.

The next slide, number 20, some information that is relevant to the Company, each of our business units, and it is monitored and managed overall by our enterprise risk management function led by Andrew Sunderman.

In summary, margins and adequate assurances at the end of the year totaled 527 million prepays at about 150 million. The total of those to at 678 million. LLCs out totaled 378 million, and at the end of the year, we had about $1.1 billion of total liquidity out for margins, adequate assurances and prepaids plus the letters of credit, which was down just slightly from the prior year.

I might point out that in the corporate and other category in terms of letters of credit about $90 million of that number relates to the Alaska refinery, which we expect would be eliminated with the sale of the Alaska refinery.

The next slide, number 21. In addition to the margins out that we just looked at, on the prior slide, we have additional potential margin requirements as indicated here. As I said before, we maintain about $1 billion cash and liquidity cushion to meet any such requirements, as well as other working capital fluctuations that may not be anticipated. So, again, the billion is a cushion for extraordinary movements in working capital or margining. This slide would indicate to you that over the next year the maximum amount that we would expect to put out would be $349 million, and that is calculated at a 99 percent confidence level.

The next slide, number 22, is a sensitivities analysis. A number of you have asked from time to time about what is the impact and the change of our key commodity to the Company. It is a very complex question, and to really do justice to it it would require some very very sophisticated modeling. But we tried to simplify things here as best we could, but forecasting the real change is like forecasting the weather because there are some many correlations between commodities and other events.

But having said all that, which is indicated in the footnote, the first column on an WMB (ph) basis, this is a consolidated impact of a change in natural gas price. This would be both -- all of our business units. The price increase of 10 cents in 2004 would result in a reduction in earnings and related cash flows of about $5 million; whereas in 2005 and 2006, that number would be an increase, and the amount would increase in 2006. Some of that is affected in very large part by the hedges that we have in place, both for the sale of gas as well as for the purchase of gas for the power business.

The next column we have changes in spark spreads. What would a $5.00 price increase do in the West? You can see there that it is an increase in earnings and related cash flows for each of the periods and it grows somewhat. Midstream in terms of processing margins on NGL price in terms of what the penny would do, and you can see there it is about $10 to $15 million in each period.

At this point, I will turn it over to Ralph.

Thank you, Don. Let's go to slide 24 if we could. Thanks for your interest today, and I am pleased to again discuss with you what we believe is a leading portfolio of long-term low-risk (inaudible) drilling opportunities. In the E&P segment, we are gaining momentum as we crank up our development drilling machine, and we are focusing on our core competencies in tight SANs gas and coalbed methane.

Turning to slide 25, segment profit results for the quarter. Recurring segment profit declined due to exploration of section 29 tax credits of 8 million, which were affected in fourth quarter '02. 34 million for the whole year of 2002, with the remainder of the decrease primarily due to lower volumes resulting from asset sales. For example, in the fourth quarter '02 versus fourth quarter '03, quarter to quarter asset sales were approximately 30 per day down that we sold. And on the section 29, that is a tax credit, but please recall that we did convert our credits to revenue through several section 29 transactions, which is why operating profit was impacted.

Looking at slide 26, fourth-quarter and some 2003 accomplishments. We did increase our drilling activity significantly from midyear. The recount, for example, in the Piceance was one in late July, and we were at eight paid by year-end. On the San Juan Basin, we added a drilling rig and picked up four cavitation rigs. We have reversed our volume decline during the fourth quarter. You will see in the operating statistics that what a volume decline looks like is apparent from the third quarter of '03 to the fourth quarter '03.

Essentially what we had in the fourth-quarter volumes is a correction from the third-quarter volumes. If you take that into adjustment and into account, volumes were essentially flat third quarter to fourth quarter. Our volumes did hit a low in the fourth quarter from about 440 a day, but more importantly, we are back into the 455 to 456 million cubic feet a day as we speak today. So we arrested that volume decline as we said we would, and we are starting to gain momentum and gain volumes.

We completed a backyard acquisition of working interest partner in Arkoma, in the Arkoma Basin on December 30th. This is again net us. This deal was $10 million in capital, and it brought in approximately 33 Bcf of crude reserves and about 5 million a day of production, so the economics of that deal were very superior.

Looking at reserves and production replacement ratios, we reported last week a 254 percent replacement ratio. We had our second consecutive year of 99 percent success rate, and importantly to us, we did move 412 Bcf from the probable category to the proved categories in the year 2003. I recall that comes off the heels of moving 313 Bcf in 2002, so we continue to be able to prove up not only develop our pud (ph), or proved undevelopeds, but also prove up our probables.

Slide 27, a reconciliation of our reserves. As you can see there, we sold about 390 Bcf. We produced about 186 Bcf. We had reserve additions of 445 Bcf, of which that approximately 33 Bcf was for the acquisition in Arkoma. The rest was through the essentially drill bit. We believe that this year-end balance of 2.7 trillion cubic feet will keep us in the top 10 in domestic gas reserves. And also please recall, we issued our reserves press release on February 3rd. 98 percent, slightly more than 98 percent of our reserves are audited or prepared by Netherland, Sewell & Associates or Miller & Lance (ph), and essentially we were right on target with what their numbers were and our members were. There really were no variances in our reserves. So a very strong reserve report for the year.

Slide 28 just gives a view of the makeup of our reserves. You can see on the proved basis the Piceance is the dominant player there, making up over 2.7 Tcf. If you look at the second pie chart on proved plus probables, although we don't give exact numbers out, we do estimate that our probables are more than our proved reserves. By this, we mean that our total reserves are more than double what the proved reserves at 2.7 Tcf when you add our probable reserves. So we believe we have at least double the opportunity than what we have just on proved. It also shows the significance of the probables just by the way you book reserves in the Powder River. It shows the significant of the probable inventory in the Big George, and I will talk a little bit more about the Powder River and Big George in just a few minutes.

Slide 29, segment guidance, no change in '04, '05. You can see we have added 2006, and I think you can see the momentum we have gained from the positive effects of cranking our development drilling portfolio. Nothing really more to say about that except some new guidance for the year 2006, and you can see our production and segment targets are very aggressive. But we believe we can make these targets, and we feel very confident about our drilling program.

Slide 30, just a quick basin overview of each one. I won't go through all the characteristics of this. You have seen it before. Just on the Arkoma, one thing I do want to point out and this is for each of our basins, we do have a proprietary low-pressure gathering system that we own in the Arkoma, and I think it is very key in each of our core basins we either own the gathering outright in a sense of Arkoma and Piceance or in a sense of San Juan Basin -- our Midstream group operates that -- or in the sense of the Powder -- our significant partner operates that. We believe this provides a competitive advantage, and we're very keen to keeping control of those gathering systems and gives us an opportunity to move our gas we think.

Key characteristics of the Arkoma Basin are listed there. I will say that the net production has tripled since we did the acquisition in 2001. Our leasehold has expanded, and we continue to believe that there are some more stretches for this and more opportunities in the Arkoma Basin, and we had a good success rate of 94 percent in the year 2003.

Looking at San Juan Basin, again not going through all the slides, but you can see it's a key piece of our reserve portfolio at 702 Bcf approved. Our leasehold is very strong, near 100,000 acres. We have had some development drilling opportunities due to some down spacing in there in what is called the Fruitland Fairway (ph) and the Fruitland non-Fairway, which we are attacking this year and the next year. We had an outstanding success rate in drilling of 100 percent, and we have quite a few operated and obviously a large nonoperating interest also in San Juan Basin.

Slide 32, Powder River. We continue to believe this is a very high potential low-risk development play, low-cost wells. We are now moving fully into the Big George area, which Big George basically has twice the reserve potential, twice the production potential for just a fraction of the increase in the prices. Our proved reserves based on the way you book the mass amount of acreage we have out there between us and our partners -- we control about a million acres -- is about 257 Bcf at year-end 2003. Current net production about 114 a day. We operate half of the wells that we see there, and the 4109 wells about 12 percent of those wells are Big George wells, and you will see that ratio go up as we move fully into the Big George. We have a tremendous inventory here with approximately 11,000 drilling locations between us and our partner.

Slide 33, a little more deeper dive into the Powder River. Looking at the permitting, the one thing we need in the Powder River is a pace of play and the sense of permitting to come up a little bit. We have had 660 federal well permits issued to the industry post a record decision. Of those, we received 140 or 21 percent. Our partner received 61 for a total of 30 percent of the wells or the permits that have been issued. Of our 140, we spread at 74 wells at the end of the year, and we are currently drilling some of the balance of that as we speak. In the approval process, we have 1400 the industry has submitted, and between us and our partner, we have I believe 352 in the approval process.

As you know, the BLM has come out very strongly saying their is to issue 3000 permits a year, and they have ongoing streamlining processes. I think that is getting better, and we are optimistic that they are going to continue to strive to meet their goal. And the Big George itself is producing about 120 million today or about 12 percent of the total of the Powder River Basin. Out total Powder River Basin is about 980 million a day. So the Big George is increasing.

One thing also, based on our numbers and things we have seen in the last 12 months, the Big George has increased about 100 percent in production and (inaudible) 118 a day now, and it was about 60 a day about 12 months ago. So we believe it is really starting to kick in. All we really need is the permitting process to continue to speed up.

Of the Big George production, on a gross basis, we have about -- we and our partner have about 38 million a day of that 118 million, which is about 32 percent of the Big George production. On a net basis, obviously we have about 19 million a day.

Looking at slide 34, on the Piceance Basin, this is our largest operated. It is a very large gas saturated Basin Center gas trap. We have been drilling in there since 1984. We have over 800 total operating wells. Have not had a dry hole there. Again, very high success rate in the sense of 100 percent in 2003. Tremendous reserve potential there. We have 1.6 Tcf of proved reserves. Very key I think is the fact that we are now at 10 rigs operating as we speak today, so we have obviously increased from the eight at the end of the year to 10 rigs, and we expect to increase at 12 rigs during that year as we try to crank up this tremendous asset for us.

Slide 35, typical well economics for this year, and basically you can see there are not a whole lot of significant changes. Some numbers are up a little, and some are down a little, but in general the rates of return stayed very very strong.

Just for your modeling purposes, the price we used on these would be a three-year Nymex strip of 492. That is a kind of December price. The current three-year Nymex strip I think as of yesterday was 504. So if you would run that, these numbers would obviously increase. You can see our returns continue to stay very strong, and our net margins continue to stay very strong for our portfolio.

Slide 36, the hedging update. I think 2006 is new information for you. 2004 and 2005 I think are the same as what we have -- the same information we had already published. But as you you can see, just to focus on that, we are 47 percent hedged at a Nymex price of 444 in 2005, and we are now 40 percent hedged in 2006 at 439. As Don has mentioned and Andrew has, we will continue our future hedging strategy. We will continue the function of the Williams portfolio, and we also believe we have the appropriate basin hedges and transportation in place to mitigate any location risks that might be out in our areas.

Slide 37, challenges and opportunity. Obviously the pace of drilling permit approvals is a challenge. We continue to believe -- that is really all in one area, and that would be the Powder River. We are picking up more permits. The BLM is doing the best to expedite that process. We believe they will get there.

Rig availability we said last call was a challenge, but as you can see from the peons, we have been very successful in attaining additional rigs since we are at 10 rigs now. Opportunities are that the BLM is committed to streamlining. We are picking up rigs. There is an opportunity to increase our drilling pace beyond our planned rate, and obviously that has to be the right balance for Williams and the right balance for our capital budget. But, for example, if the Powder River would decline more than we think it could this year, we could pick up additional rigs in the Piceance to offset that, so we do believe our portfolio is flexible enough, and we are not predicting the powder would decline in the permitting. We are just saying if that would happen, we could shift some resources to be Piceance for example.

And we are seeing numerous backyard investment and acquisition opportunities. As you can see, we took advantage of one at the end of the year in 2003 when we did the Arkoma acquisition. It is very superior economics, so there are good opportunities for us in our backyards.

But just to stress, the numbers you see in our projections do not rely on acquisition opportunities or any new portfolio. We believe those numbers are achievable with our existing portfolio.

Slide 38, my last slide. We do believe it continues to be a great platform for growth for Williams. We have a conservative business strategy. Our investments are short time cycle and very fast cash return. The Piceance, for example, as we said before, we will drill, complete and have gas flowing within 30 days. The Arkoma and the San Juan Basin, approximately 60 days, and the Powder River depends on the dewatering sign. That can be 12 to 18 months, but again a very short time cycle.

A very high-quality low-risk reserve base as you can see from our portfolio and our success rate. Diverse basins. We like our long-term drilling inventory. That is our strategy is to always have a high undeveloped basis and an opportunity to move our probables and possibles inventory to proved. Low-cost high margin producer.

Our team has stuck together through all this, and they are very excited to be back in the field. We have kept all our key employees, so we have a very experienced management team that has been working these assets and a very talented workforce. We continue to believe we have a premiere long-term low-risk high return development drilling portfolio.

That is the end of my comments, and I will now turn it over to Doug for a Gas Pipelines update.

Thank you, Ralph. I would like to begin with the map on slide 40. Over the last couple of years, Williams has sold several of its pipeline assets, but we kept the largest and the best, Northwest and Transco, both of which are fully contracted and serve strong markets with prolific competitive gas supplies at a cost lower than the competition.

In addition to Northwest and Transco, our Gas Pipeline segment includes our interest in Gulf Stream; Cardinal, which is an interstate pipeline in North Carolina, and Pineneedle L&G (ph).

Turning now to slide 41, this slide adjusts Gas Pipelines' reported segment profit for nonrecurring items, including write-offs of abandon projects for Completion B booked to Gulf Stream, severance and early retirement costs, a charge related to a FERC penalty and gains and losses related to the sales of our interest in Northern Border, Alliance and Coal Point.

A $26 million adjustment to prior period rate reserves booked on Transco in the third quarter 2002 has not been adjusted in our computation of recurring segment profit because rate reserve adjustments are a normal part of business for a regulated pipeline. But they do make the otherwise smooth earnings of Gas Pipelines bumpy should be taken into account in making period to period comparison. We also did not adjust d out 27 million of equity AFUDC (ph) booked at Gulf Stream in our computation of 2002 recurring segment profits.

Once one takes into account the 2002 rate reserve adjustment on Transco and the 2002 equity AFUDC on Gulf Stream, we see the improvement in segment profit that is a result of the numerous expansions of Northwest and Transco completed since mid-2002.

Turning now to slide 42. In the fourth quarter, we built on earlier accomplishments that included the April implementation of Transco's online service delivery system, the May completion of Transco's Momentum Phase I expansion, and in June Gulfstream's agreement with Florida Power & Light that brings total firm long-term contracts on that pipeline to 725,000 thousand dekatherms per day or two-thirds of Gulfstream's capacity.

The Evergreen, Perma (ph) Gorge and Rocky Mountain expansions on Northwest and the Trenton-Woodbury expansion on Transco were all finished in the fourth quarter. And earlier this month, we completed the Momentum Phase II expansion that we concluded -- that was part of the Momentum project the first phase completed last May. Then we concluded an open season that would result in an expansion of our service to markets in South Central New Jersey by November 2005.

Now slide 43. More than anything else, it is our Gas Pipeline's strategic location that allows them to deliver a prolific and diverse gas supply mix to their markets, more economically than any competitor. Over the long-term, the Pacific Northwest has enjoyed about the lowest gas prices in the country as a result of gas on gas competition between the diverse gas supplies available in Northwest. And Transco's route along the Eastern Seaboard, its strategic access to storage and the efficiency and flexibility provided by its very large-scale also provide Transco's customers with incomparable value. Please refer to Gas Pipeline slides in the appendix for data demonstrating many of these strengths listed on this slide.

Turning now to slide 44. While the interstate pipeline business may look like coupon clippings to some of you, there are challenges. After initial failure of Northwest Vintage 26 inch pipeline Southeast of Seattle in May 2003, we experienced a second failure in December, about 70 miles further south. Both barriers were due to stress corrosion cracking caused by a rare combination of susceptible metallurgy and stress from internal pressure and environmental factors.

For this second failure, Northwest and DOT's Office of Pipeline Safety or OPS agreed that we should idle our 26-inch pipeline from Sumas, Washington on the Canadian border to Washova (ph), Washington east of Portland -- a total of 268 miles of pipeline. This removed 360,000 dekatherms per day or over 25 percent of our capacity from Sumas south.

Since we have one and in some cases two other pipelines in this corridor, there has, to this point, been no impact on customers. In fact, our LDC customers delivered record volumes when cold weather moved into the Pacific Northwest earlier this winter. But customer impacts are possible this spring or summer if we are unable to restore key segments of the 26-inch line to service and certain market conditions emerge. While we are confident we will be able to serve the market with sufficient gas supplies, these supplies may not be from the preferred lowest cost sources. At this stage, OPS is requiring that Williams employ extensive hydrotesting before restoring the 26-inch line to temporary service later this year.

Absent strong evidence of the long-term integrity of this line OPS is requiring that we ultimately abandon the line and replace its capacity within three to 10 years. The capital expenditures shown in the guidance we are providing today reflects the cost of restoring service on this line this year and the cost of replacing the capacity entirely by year-end 2006. These costs are recoverable through (inaudible).

Turning now to slide 45. Pursuant into its last rate settlement, Transco is required to implement new rates in early 2007. Northwest has no requirement to ever implement new rates. Our current projections indicate Transco's current rates are insufficient to recover its cost and provide the allowed returns starting later this year. Therefore, Transco could file a rate case anytime, but we are choosing not to file because our costs are in a state of flux, making a rate case proceeding achieving full cost recovery difficult at this time. Of course, we will be frequently reassessing our rate case timing.

On the other hand, Northwest's current rates are sufficient to recover its cost and provide an acceptable return. We will need to file a rate case for Northwest when the extensive facilities required to replace the 26-inch line are placed in service, presumably at the end of 2006.

In November 2003, FERC issued its new affiliate rule called Order 2004. Under this new rule, Gas Pipeline must treat its E&P and Midstream affiliates much the same as we treat our power affiliate today under FERC's Order 497. This means there will be limitations on Gas Pipeline's ability to share information and personnel with our Midstream and E&P affiliates. As a result, we anticipate that Transco will have to assume operations of its production area assets currently operated by Midstream. On the other hand, we believe that we can continue to share enterprise support services.

Turning to our slide show and guidance, slide 46. As you can see, during periods where there is no noise from rate reserve adjustments, restructuring costs and large expansion projects, financial results for our Gas Pipelines are fairly predictable. Capital expenditures also would normally be much lower and follow a similar smooth predictable pattern where it not for large onetime costs of Clean Air Act compliance on Transco, included as part of non-expansion on this slide in 2004, 2005, and to a lesser extent 2006. And the large onetime cost of short-term restoration of service and then the ultimate replacement of Northwest idle 26-inch pipeline in the state of Washington.

Turning to slide 47, Gas Pipeline's greatest challenge centers around the timing of the restoration of service of Northwest idle 26-inch pipeline. During peak periods of demand, Northwest customers have the option of taking gas at Sumas to the North or gas from Alberta, the Rocky Mountains or the San Juan Basin to the south and east. If the cost of gas at Sumas is low relative to these other available sources, then customers will prefer purchasing gas at Sumas.

And a combination of light snow pact this winter and hot weather this summer in the Pacific Northwest could mean heavier than usual overall demand for natural gas for power generation. This combination of operating and market conditions could mean that we are unable to met our firm service obligations at Sumas. In this case, we may be obligated to reduce our billings to our customers this year, the range being from nothing to as much as $15 million.

We will be able to recover the cost of replacing this capacity, including a return on our investment though a rate increase at the end of 2006 or early 2007. As a result, segment profit would increase $50 to $60 million in the first year after this work is completed.

There are other upsides. As I mentioned earlier, Transco is not achieving FERC allowed returns. Therefore, a successful rate filing could provide upside. We still have one-third of Transco's capacity -- of Gulfstream's capacity to sell. The gas market in Florida is the fastest growing in the country, so the potential for Gulfstream is good. Further, the competitive strength of our Northwest and Transco pipelines mean we are well postured to participate in future growth in the strong energy market these pipeline serve as well.

And now Alan Armstrong will cover Midstream.

Thanks, Doug, and good morning. I have really three goals for this quick update on our Midstream segment. First of all, I want to show your financials today in a way that lets you see what our ongoing business looks like post asset sales. I know there has been a lot of confusion on our numbers, so I am hoping to clear some of that up in a way that let's you see what our core business and the strength of our core business really looks like. Second, I am also going to provide a little more clarity and an update on our remaining asset sales effort in Midstream. Finally, I am going to update you on our exciting deepwater efforts and the strong performance we continue to realize there.

Going to slide 49, this is just a map that helps show what our business looks like post asset sales. You can see the red Straddle Plants there and the Conway are assets that we intend to divest of. The black asset there in the Wyoming, San Juan, Gulf Coast and Venezuela are our core G&P assets, and we continue to stay after that business.

Moving onto the next slide. First of all, our fourth-quarter results here does include about a $42 million impairment related to our Canadian Straddle Plant. I will remind you that for the year this was offset by a $90 million gain that was recorded in discontinued operations when we sold our Red Water NGL business earlier this year. And, of course, these numbers are for continuing operations only, so that 90 showed up elsewhere.

Once you get past these major impairments, you get down to a difference of about $10 million there -- the 77 versus the 67 -- and that was really largely driven by about eight small reserves and impairments that we took that not show up in your recovering statements. They were below a threshold on an individual basis, and those totaled about $15 million, and that really is the primary difference. There was a slightly weaker performance in our (inaudible) business, but it was largely driven by some small onetime things that we took.

Our processing business for the year was relatively flat on a net liquid margin basis, so slightly down but ever so slightly. And then finally, looking to the total year difference there, you can see on an ongoing basis there the 310 versus the 254 at the bottom, and of course, this is corrected again for the assets that have either been sold or will be sold and to get down to about a $56 million difference, and this was almost all completely driven by our growth in the deepwater business.

Next slide. So our accomplishments for the fourth quarter, first of all, very strong operating cash flow. We came out at the end of the year with about $413 million of cash flow from operations, and 147 of that came to us in the fourth quarter of the year. Our deepwater expansions, we made good progress there as well. We brought our Gunnison Pipeline in service, and that was about 10 percent below budget and about two months ahead of schedule. We continue to enjoy our work there with Kerr-McGee and continue to be impressed with their ability to bring projects in on-time and on budget as well.

Our Devil's Tower project, we did get the top side set -- this was a very critical milestone, and at this point, all that really remains is commissioning work and some tie-ins of (inaudible), so we are past the higher risk elements of the construction for that, and we expect that to come on in the second quarter of '04 and provide some very strong operating profit to us.

Under our asset sales progress, you can see these four -- I am sorry; let me back up -- the assets sale progress we made in the fourth quarter of '03 there. Four items. Those totaled about $110 million in cash proceeds, and additionally to that, you can see the final note there, the recontracting of the ethane in Western Canada. That business was -- we have gone through the effort of recontracting the ethane in Western Canada. That was as a result of existing long-term contracts, but they had repricing in them, and when we went through the sales effort last year, we got a lot of pushback from various buyers in not believing that we would be able to get that ethane rate contracted at that price. We thought we could, and so we pulled it off the market to get that accomplished. The good news here is that we have gotten the majority of this ethane re-contracted and at a price even well above what we had in our sales brochure this time last year. So we're pretty excited about the progress there.

As well, we completed a 415 well connect program in our core basins. This shows the continued strong drilling effort that is going on in the four basins. We had some strong operational metrics that showed gathering volumes and NGL volumes up on a year-to-year basis. So we continue to see improvement in operational metrics as well.

Moving onto slide 52, these are the remaining assets that we do have for sale right now. And these total, as you can see, $500 to $600 million. Three of these -- Cameron Meadows, the ethylene distribution and South Texas -- are in very advanced stages. We have got buyers identified, and we are working through some of the details on those. The South Texan one you can see is pushed back for fourth quarter of '04. That is solely driven by the requirement for getting FERC's approval on that. But all of these assets are well on their way, and we feel confident about being able to complete this task.

Next slide, please. Onto slide 53 here, first of all, there are really two stories or messages that come off of this slide. First of all, our performance against forecast you can see there in the first column, the 2003 forecast. So this time last year we told you that our segment profits should rank between 200 to 300. We brought that in at 286, and that is even with the $42 million impairment that we took in the fourth quarter. And our cash flow from operations was well above the range that we suggested of 300 to 350. We brought that in at 413.

So the second-story in this message is really continued growth in our profits looking out into '04, '05 and '06. This is largely driven by deepwater growth, and the depreciation reduction is somewhat driven by our asset sales efforts. And then finally, on the NGL margins in terms of what our expectations are there, those actually decline over this period. So we continue to see in the plan we are being fairly conservative, if you will, as to our NGL margins.

Moving onto the next slide, slide 54. This shows a little more breakdown of our lines of business. You can see that our Petcam (ph) sector has performed poorly over the last two years. Our expected improvement comes primarily on the strength of some new contracts that went into effect in January of '04, and this basically took some commodity risk out of our business there and converted a large portion of our business there to fee-based processing or ethylene production at our Gasmier (ph) ethylene complex. So that improvement that you see there is not driven by an expectation in margin improvement as much as it is just the conversion of those contracts.

The steady improvement in operating profit in the core business is almost all driven by deepwater growth, and again no new investments are required for this plan. So the capital that we are demonstrating there is pretty well well-connect capital and maintenance capital, and there is not any intended major expansions included in these numbers.

If you looked at the bottom there at the number there, you can see a segment profit plus DD&A continues to grow through this period. So again, really what we are producing here is very strong free cash flow.

Moving onto the next slide, this shows our continued reduction in volatility, and this is really driven by two things. First of all, the fee business continues to grow, and also our commodity based business shrinks a bit as we sell out of the Canadian Straddle business. So we continue to stay focused on this effort, and we are making good headway on this.

This chart that you see here, and just so there is clarity around it, is based on our 2003 margins, and so actually if we were going according to our forecast, this might actually reduce a little bit in terms of the commodity base because we are actually forecasting a reduction of the margin that we are making our NGL business from '03. But we just tried to keep it flat, our margins flat across there, so you could see it on an apples-to-apples basis.

Next slide. The story here is the continued growth through 2005 with no new contracts reserves to our deepwater business. So you can see in the blue there, that is, of course, in 2002 and 2003 that is our actual realized performance. '04 and '05 and '06 in blue just assumes that the existing reserves that are connected and contracted to our business stay online. And then in '06, the yellow that you can see there is business that we have identified today, and we are in discussions with various parties on. We have, of course, risk-adjusted that and brought some probabilities of success into that, but that is only identified business.

Just to give you a feel for the potential above this, even in '06 that only assumes 50 percent of the capacity that we have got invested in these assets is utilized. So we feel very confident in the blue, and we also have good reason to think that the yellow will be there and possibly the well above that as we continue to see a lot of growth around our assets out there.

Next slide, please. So our challenges, first of all, we do see continued volatility in the commodity margins. As I mentioned, we have been very conservative in our forecast, but we are always exposed to that. The good news is for '04 on that at least in January of this year we saw very strong margins in our January '04 and expect really a performance even above where we were at this time last year in '03. Now that is not a prediction that that will continue through March, but we have seen strength to date.

In our deepwater business, we have got to make sure we do contract that identified business that I just showed you there in '06, and so we list that as a challenge.

Finally on the FERC affiliate ruling that you heard Doug mention earlier, we operate assets for Transco jointly with a lot of the nonregulated assets in the Gulf Coast. As a result of this new order, it is going to put some pressure on our opening costs. We have done a very good job of integrating our operations out there and squeezing the efficiencies out of jointly operating the assets. We don't expect this to be a really large number, but somewhere in the $2 to $3 million range. And it is certainly within the range we are forecasting to you, so it would make an adjustment to the range that we show you there.

On the opportunity side, our margins again probably a lot of upside there beyond our forecast. We are forecasting through the '04 and '05 timeframe about a $40 million lower NGL margin than we saw in '03. So we could have some upside if all we saw was just '03 type margins in this business.

The additional deepwater prospects, again we are only utilizing 50 percent of the capacity of these assets, and we are absolutely excited about all the continued investment that is going around our assets out there. A lot of drilling activity. Obviously that is sparked by the strong commodity prices that we are realizing right now, but we are more optimistic than ever about the volumes coming into those systems.

And then finally, our Olefin margin, really the cycle that we show here, we do have exposure. It shows a continued depressed Olefin margin, and if that came back to us, we would see some positive improvement to our numbers as well.

Moving onto our summary. First of all, as I mentioned, our strong 2003 financial performance and our strategy remains intact. The strategy of staying focused on large-scale assets and growth basins is absolutely paying off for us and continues to be right on target with that effort. Finally, we continue to maintain focus on our core business. We sold off almost $2 billion in assets, but we continue to be focused on the business and continue to grow the profits despite that sell-off. So we have continued to execute on reducing volatility, and that will continue during this planned period.

And then finally, probably the most important thing from a summary prospective care is that in all of these areas we have a lot of drilling activity, a lot of demand for our services out here to tie in all of the new gas that is being drilled around our assets, but we don't have those expansion opportunities embedded into this plan. So we're very excited about the way this business and these assets are positioned today.

With that, I am going to turn it over to Bill Hobbs to give us a report on our power business.

Thanks, Alan, and good morning. We are now on slide 60. I will hit some highlights regarding our fourth-quarter and year-end segment profit. Note the accrual earnings for the fourth quarter and 2003 are consistent with previous guidance and also what we disclosed in the tutorial. Our mark-to-market earnings continue to be primarily driven by higher gas gas prices related to hedges against our tolling and our full requirement contracts.

You will note the SG&A has continued to decline. The run-rate has continued to move south as we have rightsized the business given where we are at. Other operating expenses and other income are primarily driven by additional reserves related to our California potential refund around gas and electricity. The impairments are 45 million of goodwill related to the Barrett (ph) acquisition and 44 million against our Hazleton (ph) power facility.

Turning to slide 61, this is really just a further breakdown where you remove the unusual items that are in our results, and you can see that we moved close to breakeven for the fourth quarter and slightly negative for the year.

Slide 62 is an update. This slide is out of our power tutorial that you saw in November. It is an update. In 2003, I believe the number we reflected in the tutorial was 236 million negative, so we were fairly close to what we had forecasted there. You will notice some reductions in 2004 and 2005, primarily driven by lower merchant revenue expectations and also the inclusion of 25 million of corporate allocated expense.

Turning to slide 63 and looking at our cash flows for the year, on a power stand-alone basis, you can see that although the portfolio generated a -243 million, when you look at the assets sales -- Jackson and the Allegheny termination and deferred tax charges along with improvements in working capital -- we ended up at about just slightly south of 500 million for the year.

I will point out that the deferred tax charge is a business unit only change, and that it is offset at corporate. Also, you see there the working capital that we have used for other businesses when you make all the adjustments, brings us down to our GAAP disclosed cash flow of 159 million.

Slide 64 is an update on segment profit and cash flow from operations guidance. I will point out cash flows, those are power owned and do not include commodity margin volatility for all of Williams commodity businesses. And I note because power does not currently qualify for hedge accounting due to our stated intent to exit the business, actual segment profit may vary significantly from given ranges.

On slide 65, these are challenges and opportunities as we go forward at least until we can exit the business. As Steve indicated earlier, we are operating in a depressed cycle currently, and if that depressed cycle continues to stay longer than we anticipate, it could impact results.

Also our stated intent to exit the business has created problems in two areas really. One is employee retention. We are managing that well. The other is doing new hedging opportunities through the forward markets and the origination business with our stated intent to exit customers are somewhat hesitant to enter into longer-term deals with us.

On the opportunity side, if you believe what the industry analysts say, there is certainly significant opportunity as FERC spreads achieve the levels that people like Ser (ph) and Piro (ph) and others are projecting. Even though the stated intent to exit the business is limiting us somewhat, we still are in discussion with customers regarding sales from our existing tolls to further hedge those reduced risks and enhanced value.

The market is improving. There is more liquidity in the market today, which is opening up opportunities to forge sales further in time. Also, as we take the steps that Steve and Don have outlined and our credit improves, we would expect to see less prepays for gas, not only for our power business but for our Midstream business as well. Certainly we expect favorable resolution of ongoing litigation and investigations.

With that, I will turn it back to Don Chappel.

Thanks, Bill. I would like to add to the information that Steve and Bill provided on power and the information that we previously provided in our power tutorial during the month of November.

Just running down the points on the slide. Again, the power markets are depressed. The West has positive exit value. We believe the East has negative exit value. The estimated cash flows from the hedges cover approximately 98 percent of the demand payments through 2010. Also, the expected positive cash flows, despite depressed markets, also run through 2010. Obviously opportunities and risks are greater beyond the hedged-in period.

Impairments of goodwill in the Hazleton plant were taken in the fourth quarter, totaling $45 million and $44 million respectively. The net book value of the portfolio and other long-lived assets total about $800 million. Additionally other net assets, things like Accounts Receivable margins and all, total something in excess of about $400 million. Finally, the tolling full requirement storage transportation and transmission contracts represent additional exposure that is not reflected on the balance sheet. Those are the contracts that we use to run the business.

I will now spend a minute or two discussing some of implications of the combination of conditions I just described. I would also like to use this opportunity today to do this in a timeframe that is outside the context of any immediate opportunity to exit the business. As we have discussed before and you have heard again here today, the market conditions create uncertainty about the timing and value of Williams exit from the power business. As a result of our continued focus and evaluation of the prospects to exit part or all of the business, we recorded impairments as I mentioned 45 million related to goodwill and 44 million related to our Hazleton plant during the fourth quarter.

While we are on the topic of impairments, this is a good time to discuss what remains on our books and what is not on our books. In our November power tutorial, we walked through our business, in particular our cash flows, to the level of detail that allowed analysts and investors to get a better picture of our power business. Today I want to walk through a hypothetical scenario that should provide more clarity around the potential financial effects on Williams of a full from the power business.

And again, I want to be clear that this should not be interpreted as a signal that we have a deal or even a possible deal for the power business at this time. We are not close to any such deal.

Many analysts and investors we speak to tell us they assign a value of 0 to power as they model Williams' business. For purposes of illustration, let's walk through a hypothetical scenario consistent with that number -- 0 -- for proceeds from the sale of the power portfolio. Using our December 31 book value for the portfolio and other long-lived assets of $800 million, a 0 proceeds transaction would imply that the buyer recognize about $800 million of positive value for the recorded assets and an offsetting $800 million of negative value for the tolls and other obligations. For Williams, the results of this hypothetical scenario would be an $800 million pre-tax loss, almost $500 million after-tax, associated with such a sale.

Now let's look at the hypothetical transaction from a cash flow perspective. In this hypothetical 0 proceeds deal, we would say the return of cash that today is tied up in other net assets, including adequate insurance, margins, receivables, working capital and such -- an amount in excess of $400 million at December 31, 2003.

Also, we would note that regular and ongoing changes in those values -- derivatives, the working capital -- will drive changes in the portfolio value of 800 million in this hypothetical scenario and other net assets, the approximate $400 million in our scenario. Such changes could impact the potential book loss and cash proceeds unless the deal value and other cash realized change accordingly.

Obviously in a sales scenario, Williams would lose the benefit of the forecasted free cash flow through 2010 and the potential upside and downside inherent in the business. Another result would be the removal of post 2010 exposure related to the tolling contracts and importantly the removal of the obligations associated with those contracts from our debt ratios as computed by the credit ratings agencies.

You will recall that the obligations associated with the tolling contracts, while fully disclosed in our SEC filings and described in our power tutorial, are not accounted for on our balance sheet. Generally Accepted Accounting Principles do not recognize the tolling obligations as debt, though, as we have discussed before, the credit rating agencies do incorporate the tolls into our debt ratios.

The elimination of this imputed debt would accelerate Williams return to investment grade credit characteristics. We believe the rating agencies imputed about 2.5 billion to 3.5 billion of debt related to the tolls. Our objective with this hypothetical scenario is consistent with our continuing efforts to provide transparency into our business through information and education.

I hope this has provided some good perspective to sharpen your analysis of Williams' business and our power portfolio and business. Once again, I would like to state that we are nowhere close to an exit, though we do continue to see potential buyers expending time and energy to explore the business.

With that said, I will move to the consolidated guidance on slide number 68. The BU leaders have delivered details of their guidance. I will just focus on the totals. The three core business units total 1.1 to 1 billion 250, and our consolidated basis, our guidance, is $1.1 to $1.4 billion, in line with our prior guidance to you.

On slide number 69, EBITDA. We are forecasting for 2004 1 billion 6 to 2 billion. Cash flow from operations in the 1 billion to 1 billion 3 range. Income from continuing operations $20 to $200 million and net income of 0 to $200 million, and while I think we are showing sharp improvement, we are still burdened by pretty heavy debt and interest costs. On a per-share basis, our guidance is from 0 to 40 cents, and again this all excludes potential gains, losses and impairments as we continue to restructure the Company.

Slide number 70 is the 2004 forecast, EBITDA reconciliation. I will not walk through the components, but it is there for your reference.

Slide number 71, this is our segment contribution guidance by line of business, and I think you will see that all of the lines of business contribute positively.

Slide number 72, take a look at our guidance through 2006. Segment profit moves from the range of 1 billion 1 to 1 billion 4, up to 1 billion 4 to a 1 billion 7 by 2006. DD&A in the 600 to 700 range increases to 700 to 800. Cash flow from operations starting at 1 billion 1 -- I am sorry -- 1 billion to 1 billion 3 increasing, 1 billion to 1 billion 4 to 1 billion 7. And finally capital spending in the 700 to 800 range in '04, about 900 million to 1 billion 1 in 2006, with a portion of that, as Doug mentioned, driven by Northwest pipe replacement spending.

Slide number 74. Just once again to -- excuse me -- slide number 73. I will look at some of the drivers of the change year-over-year, and I might add that the 2003 numbers are forecast numbers that have not been updated for the final results. I might also add that our final results on segment profit totaled 1 billion 326, below the range. However, what drove that below the range late in the fourth quarter were the impairments we took on the goodwill and Hazleton plant in the power segment, as well as the impairment we took on the Midstream Straddle assets and the litigation settlement. Adding those back, I think you will find that we are right in the middle of the range. We will be providing an updated version of this slide, also breaking out some additional information, by the end of the day today.

Now having said that, I will touch on the changes in 2003 to 2004. We see interest costs from a cash flow standpoint being reduced by $340 to $400 million. Gains on asset sales that would not be expected to be included in 2004, again we have not included any gains, losses or impairments in our 2004 forecast.

Moving from 2004 to 2005, the interest savings contribute $50 to $200 million in CFFO. The range is dependent on how much debt we actually reduced during the period, and that will be dependent upon completion of asset sales, as well as some of the financings that we previously mentioned. BNP (ph) improvements will drive $75 to $110 million of segment profit and $150 to $200 million of CFFO.

Moving from 2005 to 2006, again interest savings $20 to $70 million of additional equipment and E&P improvements to segment profit about $50 million and cash flow of $75 to $90 million. Those are the highlights of the changes in these drivers in terms of year-over-year change, and we will provide some updated information by the end of the day today.

Slide number 72, again consolidated outlook. I think I have touched on these numbers. Excuse me, slide number 74. Moving right ahead, financial strategy. Again we will maintain a cash and liquidity cushion of $1 billion plus, and we think that is appropriate and allows us to sleep at night. We will complete new bank credit facilities when they are attractive to us in order to free up cash that is currently held for working capital requirements. That will allow us to use that freed up cash for further reduction. We will continue to de-lever using cash from a variety of sources, striving to return to investment grade ratios and ultimately ratings.

In terms of priorities, in terms of using excess cash, we will pay our scheduled debt when it is due. We will retire debt early. We will make disciplined EVA-based investments, and ultimately upon returning to investment grade, we will consider a dividend and potential share repurchase.

With that, I will turn it back to Steve.

Thanks, Don, and let me sum up quickly. Let us move on to the next slide. I think we have talked enough about our strategy, let's go to the next one.

The business unit positioning within the Williams portfolio we have shown on this slide and was touched upon by each of the business unit leaders during their presentations. E&P will be generating free cash flow over the next two years and will be our primary growth vehicle. Ralph touched on the long-term inventory of low-cost, low-risk, high return drilling opportunities that offer very attractive cash flow characteristics.

Midstream also generates free cash flow, and Alan has highlighted the growth in the deepwater and the decreasing volatility as more of our revenues are generated by fee-based businesses. So we are excited about some of the deepwater growth opportunities there. Gas Pipeline generate free cash flow even with the Northwest pipeline capacity replacement. I believe that we own the two premiere pipelines in the U.S.. Those pipelines are fully contracted. In power, we will seek to reduce the risks and volatility as we continue to work toward exiting the business.

Last slide, please. In closing, we believe that not only are we making progress on our restructuring, but we are beginning to emerge as the new Williams. We are very excited about our progress, excited about our future and confident in our ability to grow to shareholder value over time.

I think we have emoted through the slides here in less than 90 minutes. We have plenty of time for your questions, and I will open the call for your questions. Thank you.

(OPERATOR INSTRUCTIONS). Scott Soler, Morgan Stanley.

A had a few questions. My first question, Don, is regarding your cash flow from operation assumptions for 2005 and 2006. In terms of working capital changes and in terms of deferred taxes or the benefit of tag yields, of how much of '05 and '06 are those two things?

Scott, I do not have the details of that here today. We are going to have to get back to you on that, and we will try to include some of that information as we add some color to the slide number 73 that I articulated earlier today.

My second question is in looking at cash flow, on your CapEx budget, it looks like on the range from the prior few presentations in the second half of last year to now, it looks like there is about a $220 million increase in CapEx. It looks like about 72 percent of that is coming from pipes and you went through that. There is a little bit of an increase in increase in Midstream and there is a bit of an increase in E&P. When you're looking at paying down debt with free cash flow versus applying that, at what rates of return are you looking at as you were looking at projects and budgeting out through 2006 what you thought you could return on that incremental capital?

Scott, in terms of some of the changes in capital spending in the Midstream business, we had some capital spillover from 2003 to 2004. We were slightly positive in 2003. Some of that capital spilled over in 2004. That was a piece of that. I think the Northwest pipeline rupture created some requirement for capital, so again required capital there. We typically -- we look at what will generate the highest returns and certainly rapid payback, particularly in light of where we are today as a company. Clearly our E&P investments drilling up our own reserves deliver extraordinary returns to us. So that is first and foremost, the priority in terms of where capital goes.

But each of our businesses require capital in order to remain competitive and take advantage of the opportunities in the forefront, and I think with the implementation of the EVA Financial Management System will be looking at insuring the cost of capital that is appropriate for each of the businesses is met, and there is a nice margin for our shareholders as well. So it varies by line of business considering the risk and the returns.

All right. Is there a threshold, Don, on those three businesses that you are looking at incremental returns on capital specific returns?

Nothing we are prepared to disclose. We think that that provides -- it is competitive information that I think we would not want to share with our competitors.

Last question on debt maturities. When you look out -- it sounds as though you are going to let all the debt that is due be paid off and then is there any -- and not be refinanced? I think that is what I heard. And then also, is there any extra debt paydown you plan on budgeting in '04 and '05?

We certainly plan to pay all the debt when it is due. The first big slug of which is in March of 04, nearly $700 million. We also plan to repurchase debt, whether it is tenders or open market repurchases over the next couple of years. I prefer not to talk about the timing of that or any particulars of that, but certainly our goal is to substantially reduce our debt over the next couple of years as we position the return to investment grade.

Sam Brothwell, Merrill Lynch.

(technical difficulty) point in Midstream, your CapEx is up, but it is up relative to what you had guided previously. It is up pretty substantially in percentage terms. Yet your projected segment margin there looks like it is heading down a bit relative to what we had seen previously.

Then I will just mention the other two things I wanted to ask about. Can you get any more specific on the timing of bank facilities? Third, in Transco if you are seeing all of this CapEx pressure, and that obviously is not new with the compressor upgrade, can you get more specific about what is keeping you from filing a rate case there?

We had difficulty hearing your question. Can you repeat it, please?

Let me quickly go through it. First of all, timing any additional color on timing of bank facilities. Two, just to follow up on Scott's question with respect to CapEx in the Midstream segment. It is up pretty sharply, yet relative to your prior guidance, your segment profit outlook seems to be trending downward. And third, if you could just give us a little bit more detail on what is keeping you from filing a rate case at Transco given all of the additional CapEx for clean air compliance?

We got it that time. (multiple speakers). I will kick it off. I will turn it to Alan and then to Doug. In terms of the timing of the bank facilities, we are certainly not prepared to talk about that. I can tell you that we are in continuous discussions with banks regarding those facilities, and we are looking for the right deal to pull the trigger on. So when we get to the right deal, we will pull the trigger. I cannot tell you if that is going to be very soon or later in the year. But we are working hard at it, and we will pull the trigger as soon as we think it is time to do that.

With that, let me turn it to Alan.

First of all, on the capital, as Don mentioned earlier, most of that capital increase actually is not new spending. It is just capital we thought we would spend in '03 that actually rolled into '04, and primarily that was just on the finish-up of the Devil's Tower project. So that is where most of that came from.

I am not sure I understood where your question around margins was?

I think just relative to where you had been before -- I am trying to flip back here to your last book -- but if I'm not mistaken your segment profit outlook in '05 where we are today relative to where we were the last time we went over this, it seems like it is trending down a bit. Obviously I understand the issue in '04 on CapEx, but I think you were in a 40 to 60 million CapEx range previously at Midstream, and you are up from that. So I was just wondering if you could reconcile the downward trend in segment margin there versus an upward trend in CapEx?

Okay. On the downward trend, I would say that is largely driven by more conservative forecast on margins than we previously had in there on the NGL margin side. Other than that, the business is pretty well performing as we forecasted.

Likewise, on the capital spending, that is for some things like, for instance, we've got a little bit of increased capital associated with the FERC affiliate ruling where we have to spend a little bit money separating assets and so forth. But mostly just that '04 change was mostly from, again, just the '03 capital rolling into 04, primarily on Devil's Tower. There was a slight increase in from our earlier projection on what the total cost on the Devil's Tower project was. But most of that gets recovered in extensions and contract modifications that were part of that Devil's Tower deal.

Okay. Then finally on Transco?

One of the issues that is causing Transco's cost to be higher is that Williams has downsized. The allocations to our individual pipelines of allocated corporate overhead has gone up. This is usually a very sensitive item in rate cases, and Williams is undertaking a lot of actions going forward to reduce these costs. So to the extent that these cost increases are not permanent, they are temporary and we probably would not be able to recover them in rates as well.

Plus, we have, as you have noted, some fairly large capital expenditures in 2004 and 2005 related -- larger than normal related to Clean Air Act compliance. We would like to recover those. So those are the primary drivers. Again, we are looking at it closely and evaluating it, but at this stage and reflected in the guidance here -- I guess within the guidance -- we would probably more likely be on the high-end if we were to go in for a rate case.

Paul Patterson, Glenrock Associates.

(multiple speakers). What I wanted to ask you was, there is a figure of $393 million on slide 62 for tolling and demand payment obligations, and that number also seems to repeat itself on slide 60 at the mark-to-market benefit in 2003 as well on slide 60. I am wondering if they are related in some way, or whether or not that is just a coincidence?

On top of that, I am blundering was your expectation for mark-to-market benefit or what have you would be on your 0 to 150 of segment profit for '04?

It is purely coincidence that two numbers -- actually they are not exactly alike, but they are very close. Regarding mark-to-market for all the reasons that we have pointed out in the past, it really is going to depend how portfolio is set up when you look at our derivative positions in gas and power and then how the commodity markets move in relation to that. So it makes forecasting it very difficult, which is why we give you such a wide range of outcomes.

So the 0 to 150, is that the fluctuation you see in the mark-to-market, or is that absent of any mark-to-market benefit or detriment at all?

Yes. It is our best guess at this time as to what we think is going to happen. Clearly we cannot predict commodity price movement, so it will change throughout the year.

And the mark-to-market benefit you said was pretty much from the gas contract, from the gas supply portion. That indicates that the electric side, less of it is seen as a derivative or is accounted such as a derivative; is that correct?

Yes. That is exactly right. We're only really marking the gas hedge. We are not marking the underlying tolling agreement.

Then on the Transco -- just to follow-up on Sam's question -- what was the benefit -- you mentioned that you see some benefit there. What is the benefit that you actually see on a rate case, and what is the ROE that you are currently earning at Transco, that you earned in '03?

I cannot remember the precise and the latest rate settlement, what our allowed ROE was, but it was slightly above 12 percent. If you assume you are going to get a 12 percent return and you are perfect in recovering all your costs or deficiencies over the -- 2004 through 2006 on Transco, we are in the range of $25 to $40 million. Again, that assumes we get perfect cost recovery, and we earn a 12 percent return on equity.

How much equity do you have there?

I do not have with me right now the absolute number. We can get back with you with that.

Okay. Great. Thanks a lot, guys.

Maureen Howe, RBC Capital Markets.

Thanks very much. A couple of quick questions. First for Alan on Midstream. On slide 22, where the sensitivity to segment profit from processing margin is set out or NGL price -- sorry -- assuming it is not decreasing going forward, and yet there continues to be talk about moving to more of fee for service contracts. I am just wondering how is that going? Why are we not seeing it perhaps in the sensitivity going forward, and is there anything else that can be done by the Company to reduce that volatility?

I think that is just a matter of the range that is in there. We absolutely are decreasing that through the contracting process that we are in. But part of that is also driven by the fact that we are actually having an increase in our fee business.

In other words, if we move from 15 to 10 within that range, but our net revenues actually grow, that is a portion of that reduction or that shift towards more fee business if you will or less reduction dependence on that more volatile business. But primarily I would say it is just a matter of that range that we spit out there, that 10 to 15 per that margin.

Thanks. One other question I guess for Doug. Is there any opportunity or are you seeing any opportunities -- maybe it is too early -- but with respect to gas transmission from the Gulf Coast moving north with respect to the LNG proposals that are out there?

I think our belief is the greatest opportunity for transportation from LNG on the Transco system would be from Coal Point North, and if there were any LNG facilities connected that were built new that were connected to Transco on the East Coast, we believe that LNG and the Gulf Coast would be additional supplies that would perhaps offset any natural declines that are taking place in the Gulf Coast. We have the deep Gulf coming on replacing a lot of the declines that are taking place, but the LNG would be another source of gas supplies.

The bottom line is the most economic expansions on Transco are those that take place closer to the market area, so that is why we think expansions of Coal Point and other LNG along the East Coast are the most likely sources of LNG that result in incremental pipeline capacity.

Thank you very much.

Donato Eassey, Royalist Independent Equity Research.

I wanted to verify that the 10 cents was off the $4.44 price stack if you will for the 5 million -- I guess the negative impact for a 10 cent move of increasing in prices. Was that priced off of a $4.44 price of gas? If you could, given all the reserve issue noise that has been out there of late, can you talk about why your confidence level and your reserve figures are there? How they are verified in the line? Thank you.

This is Andrew Sunderman. As far as the gas price sensitivity, it is not going to be off just the 4.44 because the footnote clearly points out that is a WNB overall portfolio correlated in the average price over those three years is about $4.75 because you have got to take into account the forward markets for our power portfolio as well. So the base price we're looking at there over that time period is about $4.75.

And then I am going to go ahead and answer a question since you asked that question -- it's a good question -- I will go ahead and answer the one off the Internet that we got as well, which is what are the base numbers used to calculate sensitivities? I just stated that the average for that time period and that gas was about 4.75. The power price is about $45, and the NGL average margins are about 5 to 6 cents. So that is the numbers that are the base that would have been used to calculate those sensitivities. I want to point out that the net gas is correlated number across all of Williams, and the other two are not correlated across all of Williams and are merely one-sided either power NGL or price list.

Jay Yanello, UBS.

Not to look back, but I was a little surprised by the tax rate. It looks like there was a 9 cent benefit in the fourth quarter. Is that correct? I guess the 39 percent effective tax rate, that is a good number going forward?

This is Gary Belitz. Related to the tax accrual or the tax provision in the fourth quarter, what we have to remember is that really when you're looking at the tax provision, we're looking at amounts for the full year once we reach year-end. And the benefit that you're thinking of -- remember we have had a number of transactions during the year that provide us some capital benefit from some capital losses that had been generated that we now will be able to utilize from some transactions in the fourth quarter. So I think you are seeing our projected benefit from those transactions that are benefiting the quarter.

Okay and that was primarily captured in the fourth quarter? Also looking forward, which is obviously more important, the enterprise-wide segment EBIT guidance for 2005, if I am correct, has been reduced 100 million from a range of 1.4 to 1.7 billion to a new range of 1.3 to 1.6 billion. If I look back to the Q2 slide, which is the last time you broke out segment guidance, it looks like the $100 million reduction came from pipes 50 million and Midstream 50 million. Am I doing that right, or did I miss a derivation in between? If that basically what is going on? A slight reduction in pipes and a slight reduction in Midstream? Do you want me to repeat that again?

Do not repeat it. We have got it, and we will look at the numbers and give you an answer. But in the meantime, why don't we let Ralph respond to Donato's question on reserves?

Just several comments on that. As you know, we are essentially almost 100 percent audited or the reserves are prepared by two leading firms -- Netherland Sewell or Miller & Lance (ph). But also we had a long history in each of these basins, and by definition gas is present in the type of stuff we do, which is tight SANs gas or coalbed methane. The gas is there. We have had a long history and much repeatability.

All I can say about some of the write-downs you are seeing from other companies is from what I have seen the majority of their write-downs were more into areas of structural plays, our stratagraphic (ph) plays, which are not what we do in our core basins. They are also in areas that are more structural plays such as South Texas or Gulf Coast. I have also seen that a number of the write-downs are international type adventures that they have, and we don't have those.

So we just have repeatability results. We have a long history with our auditors, and we believe that the gas is present, and it continues to be proved up each year as we do our drilling. So we're very confident of our reserve picture.

Why don't we take the next question? We still have a little comparison to do here.

Anatol Feygin, J.P. Morgan.

A couple of questions. Ralph, you laid out the hedging structure for 2004 through 2006. Could you give us a sense for the basis hedges that you mentioned are in place? Does that mirror the Nymex in terms of percentages?

Essentially between the basis and the transportation we believe we are essentially mirrored, and another question that usually comes up, which hopefully will help in the answer, if you take our gas price that we have laid out there, we continued to say historically to get our net realized price, you take approximately 90 cents off, which would be inclusive of basis and transportation and gathering and all the deductions. So that may help also that you look at our hedge price or our gross price, if you will, to get to the net realized price, take about 90 cents off, and you will get to what we think our realized price will be.

And again, the percentages are roughly constant for that?

I believe they are, and I will give you -- if that answer is different in any way, I will chime in here in just a little bit.

Thanks. The other quick one is it looks like there was 127 million spent on acquisitions in the quarter. Is that right? That was what you termed the backyard transactions?

No. We spent $10 million.

In the notes, there is 127 million for E&P in the investment section.

I will need to look at that, but we did not spend -- our acquisition net to us was $10 million in the fourth quarter. I will need to grab that note and see what was in that number.

And the follow-up to Bill I guess in terms of the power segment from the presentation that you guys did from the tutorial in November, it looks like the projections are down about 50 percent for 2004 and about 40 percent for 2005. And if you can comment on what is driving the downward revision there in the power segment?

Yes. Where you will see it is in the merchant revenue. We went down 20 million in 2004 and 25 million in 2005. Again, that is does not really taking our forecast. It is just taking current forward curves, and they are certainly depressed as you well know. And then also, you will notice that we allocated the 25 million we added into corporate allocated. That was not included previously because we are looking at potential exit of the business, and Williams would still incur that cost regardless. So those are the two primary reasons you see the reduction.

In '04, it looks like there was actually an uptick in terms of the forecast for the resale of tolling. Can you give us a sense where that is coming from?

It would just probability be volumes associated with increased -- with our CDWR deal out West.

But what drove the change I guess from November until now in that extra 20 million or so on the tolling resale side?

This is Andrew. Basically what you are going to see there is as we have described in our tutorial you are going to see an increase in value there. Possibly the value of that stand-alone hedge has increased in value, but the offset there is going to be down under the line that we call "Hedged Merchant Merchant revenues." So on an individual basis, that hedge will increase in value or decrease in value. But since it is a hedge, you'll see the offset increase or decrease down in that estimated hedge of revenue line. So that deal obviously has gone up in value versus the market where we hedged it at.

The other thing I want to point out in what Bill has said is, there is the line called "Estimated Merchant Revenue" unhedged where you see a vast majority of the change, and we have made it very clear those are unhedged revenues, and as FERC spreads continue to stay depressed, that line will have a great deal of volatility.

Thanks for the color.

Just to go back to Jay's question, we had little change in the absolute forecast number for either Midstream or Gas Pipelines from that which you saw earlier that you noted where we changed the range. I think our view was just a bit more conservative based on a number of factors, including as an example in the Midstream business, higher gas prices that we thought gave us less of a shot at the higher end of the range, so we adjusted the ranges to be more fair, more conservative.

Carol Coale, Prudential Financial.

A follow-up to Donato's question earlier. Last year there was some noise in the Powder River Basin in the third quarter. One of the transporters in the area took a write-down over concerns as they said, and the rate of future production coming on at the rate that they were expecting, and the production was not meeting expectations.

Now we also follow Western Gas, your partner in the Powder River. They reported a fourth-quarter decline in average production, not huge, but it was a decline in trend for 155 to 100 million cubic feet a day.

This is a trend for the second consecutive quarter that we have been witnessing. I just wonder how core Powder River is to you, and how much confidence you have in your projections that were listed on slide 29 if the permitting process does not improve and if you continue to see challenges out there in the Powder River, including Big George?

Our productions declined slightly, and we said that would happen as we continued to need more permits, if you will, in the Big George and as the Wyodak is declining. So we do need to be out drilling to keep that. This year we are projecting essentially flat production in the Powder River from the first year to the end of the year.

Core to us is that we do believe the resource is there and we believe that the opportunity opportunities, as long as we get permits, will be good. We can, as I have said, if for some reason permitting would shift or slow down or speed up as we anticipate, we have the opportunity to shift to some of our other areas, in particular the Piceance. But we do believe there is a great resource there, and we like its location, and we like the opportunity to take that gas, which we do typically to the mid-continent for those kind of mid-continent type prices.

As for the write-down in third quarter that one of the other people in the basin had, we talked about that. Essentially I think that was primarily a write-down on I don't know what their assumptions were going into it, but they were in a much mature area of the Wyodak, and I am not sure what they spent. So that might be a natural result of what they did to get into it in the area they were in.

So the Big George we think has a lot of potential. It has the opportunity to be very core to us. We do have the ability to shift to some other areas if necessary, but we think ultimately the Big George will be developed. We do like what we see out there, and we do like the incline in production.

As far as some of the others that I have talked about, they have switched their methodology, if you will, of booking reserves from 100 percent gas -- assumption of 100 percent gas saturated to what is actually in those areas. We have been doing that for a couple of years now, so we believe we are very conservative on that, and we look area by area and look at the actual gas saturation versus given a blanket factor for the whole basin.

So we are optimistic it can be core, and if it slows down for a while, we are okay. But I do not think if it did slow down, I don't think it would not slow down for very long because it's a great resource to go develop.

Can you remind me where you are in your permitting? How many you have received out of what have been allowed and what your expectations for '04 are?

Yes. We have received 140 permits and our partners 61, so we have 201 total or 30 percent of the 660 permits that have been issued. We have drilled about 74 of those permits of our 140, and our partners drilled -- I cannot remember exactly how much -- but we probably have I guess about 100 or so -- 80 to 100 that we can drill as we speak, and we are, in fact, running seven rigs out there. So we are starting to drill them.

We have 352 that are in the approval process basically ready to go just waiting for final approval. The industry has about 1400, so that ratio would hold. If we see the ratio of permits been granted so far, we assume we would be getting the same amount that we have submitted.

Our goal this year is approximately 900 wells between us and our partner. If you take about the 100 we have in hand today and the 352 that we have pending, that would be about 450 or slightly about half of what we have, and obviously we continue to put those -- half of what we need, I am sorry -- and we continue to put those permits in front of the BLM. So we should at least get to half of what we have, just what we have existing today in hand, and obviously we will be submitting new permits as we go along.

I am sorry, the 352 was gross or net?

The 352 is us and our partner.

Okay. All right. Thank you.

Rich Garrea (ph), Glenview Capital.

A quick question on the Northwest pipe replacement. It sounds like we are going to spend in the guidance we have between 2004 and 2006, we are going to spend somewhere around $400 million to replace that. Doug, did I hear you correct and say, once we're done with that, we would get back through the rate base another 50 to 60 million of EBIT?

Not quite. We get about 50 to 60 million of segment profit, and then to get EBIT, you would have to add the depreciation on those assets. And that is presuming that we get it completed by the end of 2006, which is our plan. Even though the office of Pipeline Safety suggested that we could replace the pipe over three to 10 years, that is not a practical solution. To replace the capacity, we don't have to replace all the pipe. There are 260 to 270 miles of pipe, and it would take less than a third of that of larger diameter pipe to replace it, and you basically have to do that all at one time. That is why it has accelerated to this timeframe. But once it goes into service, then you would take those costs.

The rule of thumb is take the capital costs times about 15 percent, and that is what you would get in incremental segment profit once you get it reflected in rates.

Segment profit is EBIT not EBITDA? Correct?

You are right. I am sorry. I misunderstood your question.

Got it. So we would spend 400 million, and we would just be replacing the pipe and that is it. In other words, these are really one time CapEx expenditures between '04 and '06 for this?

I have to correct you on the 400 million. We gave a range that is not that specific.

Yes, it is 365 to 430. I just took the midpoint. So we would give 50 to 60 million back.

Another question. On the tax rate, it looks like compared to previous presentations we now are showing something called effective tax rate versus before we had cash tax rate. What is the difference?

The effective tax rate would be the tax provision on the income statement versus cash taxes that we provided before. We would certainly be pleased to continue to fill in the blanks. So that number moves around quite a lot depending on the timing of asset sales and the like. So right now we just felt that it was inappropriate for us to provide some guidance on that since it has been moving quite a bit.

Do we expect to pay more or less in cash taxes than we previously had assumed if the cash flow from operations line really has not changed?

I think our previous guidance is still representative of the kind of ranges that we think, so I do not think there has been a lot that has changed there. It is just a little bit on timing in terms of actually what the cash taxes will be in the particular period of 2004. It is just a little bit fuzzy.

Got it.

We will provide further guidance on that as we are able to nail that down, but it is dependent on timing of transactions in large part.

In terms of interest savings or debt reduction, how much debt reduction are we assuming in each year of the forecast period?

We have decided not to disclose that explicitly. We think it is probably in the best interest of our shareholders to be just a bit vague on that. So I think you can make some calculations based on the interest cost assumptions we have given you. But we're very much focused on debt reduction, and we expect that our excess cash will be used for debt reduction over that period of time.

But the range in '05, it seemed the range is pretty wide over the two-year period for interest savings. It is 400 to 600.

That is dependent upon again I think if everything happens the way that we would hope, it would be at the higher end of the range. However, we do have some asset sales to complete. To hit the high end of the range, we need a new bank facility that would allow us to free up cash and things like that. So we are shooting for the high end of the range certainly, but there are a number of things we have to make happen in order to get there.

And the impact of the new bank facility basically would be we have a billion -- we would have a billion revolver type of facility instead of having $1 billion of cash out, so we would be able to utilize that $1 billion to retire debt?

Something like that. I would say I would have to range it a bit. We would keep cash. I think you could think about it, that we would reduce our 1 billion plus of cash down to 500 million plus of cash. So we would reduce our cash by about $500 million and use the revolver as liquidity to serve as a backstop for our requirements. Additionally we would hope to free up a large part of the cash collateral that is now collateralizing our letters of credit.

Okay. Thank you, guys.

Leo Kelsier (ph), Merrill Lynch.

My question was partly answered with the last question. It was just to make sure I understood this whole issue of the pipe replacement program, the timing of the capital spending you are going to be doing, and the risks that you are going to have to be replacing even more pipe than you might be currently thinking?

Part of the corrective action order from the OPS is that we need to look specifically at some other pipe that is in the state of Oregon that runs from Portland south -- what we call our (inaudible) lateral -- and also look through the pipe through the Columbia Gorge. Again, we have no evidence of this problem through the gorge. We have had some of this SEC or stress corrosion cracking along the (inaudible) lateral, but we have tested it extensively and done a lot of remedial work already. There is a risk, but we do not think it is a large one.

We also think there is a good possibility that we have taken the position that we are going to replace all this capacity in assuming that all of this pipe has to be abandoned. That is probably the most likely thing, but it also -- there are a lot of other possibility that would be less, that is most conservative and most likely I guess is what I would like to say relative to the pipe we are replacing.

Does that answer your question?

Yes. And just in terms of the timing of the actual cash outlays for this?

The restoration work, which has to be done this year which most of the dollar that are shown being spent in 2004, again we are targeting to try to get the capacity restored by this summer so that we minimize any possibility of having a market impact. That is, again, that we would deliver -- we believe we will be able to meet market demand under our most extreme market conditions, but maybe not from the sources that they would prefer. In other words, there would be higher gas costs.

But the balance of it would be spent -- a small amount this year, but the biggest, as indicated by the slide, the biggest dollars are spent in the 2005 and 2006 timeframe with the target of having it go into service before we get deep into the winter of 2006/2007.

Jay Yanello, UBS.

Just a quick follow-up. Maybe I can ask my question differently. The $100 million reduction in '05 enterprisewide segment profit, can you give us a little color or flavor on where that is coming from? I know it was an early projection. I realize it is 2005, but any kind of flavor on the delta might be useful? Thank you.

I will, again, take a minute to research that. I don't have a comment offhand. We will take a look at that here as we take a few more questions.

Thank you very much. By the way, I want to complement you guys on an increased level of disclosure. Thank you.

I think we are going to take a couple of questions from the Web. Let me read the first one. This would go to you, Don. Cash flow from operations was 75 million in the fourth quarter versus 770 for the whole year. Was this due to a large working capital buildup in the fourth quarter? If so, what was the working capital build in the fourth quarter?

To answer that question, during the fourth quarter, our margins increased by about $100 million, and that was associated with the higher gas prices and the hedges we have in place on our E&P production. So $100 million of extra margin out in the fourth quarter that impacted CFFO; otherwise, I think you would find it to more in line with the total for the year.

One other question from the Web before we go back to the phones. Given that E&P is currently producing 455 million a day, what level of production are you forecasting for the second, third and fourth quarters in order to reach the projected 500 to 550 a day for 2004? Ralph?

Let me just give some ranges. Looking at that and doing the math and actually looking at our forecast, I would say second quarter we need to be in the 470 to 480 range, third quarter 500 to 510, and fourth quarter 530 to 540, and the majority of that growth is from the Piceance Basin. But we should be able to get -- that should give us a range in where we easily -- not easily -- but we would be able to accomplish the ranges we have given out. That is all I have.

(multiple speakers). We can take another question on the phone.

Ben Shiman (ph), John Levin (ph).

I have a question here. I am looking at slide 69 (inaudible), and I am not quite getting what you're saying about this earnings number you're giving out of 0 to 40 cents. There is a footnote on the slide that says the segment profit number excludes potential gains and losses and impairments. If I plug into my model anything in between 1.1 to 1.4 billion for segment profit and I use your 39 percent tax rate and an interest number of 800 to 900 million, you cannot get 0 to 40 cents.

The only conclusion I can come to is that there must be potential gains and losses and impairment in that earnings number (inaudible) in this segment profit number. Am I correct, or am I just totally out to lunch on reading this slide?

I think what you're seeing is at the low end of the range we have got tender premium, if you will, for recognition of the premium embedded in our bonds that would be recognized expense in the period.

So there is a non-operating -- if I want to look at just the operations of what you guys are doing -- in other words, I want to extrapolate your segment profit number with that footnote there from 1.1 to 1.4 all the way down to an earnings number, you don't get 0 to 40 cents is what you are saying because your buyout of your bonds is in there?

Another factor is in the tax rate. I think we footnoted that in addition to the 39 percent effective rate you have to add $25 million to the tax provision.

All right. That makes more sense. I think that the market is a bit shocked looking at this 0 to 40 cent number. Relative to what people have in the models, no one has $25 million on this onetime number, and I think there is some confusion there. Thanks for clarifying.

Peter Monaco, Tudor Investment Corporation.

I am actually okay for the moment. The question is asked and answered.

Kelly Kringer (ph), Bank of America Securities.

Just a couple of quick questions on the production side. Can you give us what the proved developer reserves were at the end of the year?

Of the 2.7 Tcf of year-end reserves, approximately 57 percent of that is proved undeveloped. About 1.2 Tcf is proved developed -- sorry about that -- and 1.5 is the proved undeveloped.

Just a quick question on the Powder reserves. I think Western Gas wrote down some of the Powder River Basin reserves based on what a previous caller had asked about how they currently have them booked. I think by the disclosure that you had and that they had, it looks like you guys had a little fewer reserves booked at the end of last year in the Powder. Can you give us any sense -- did you guys take any write-downs in the Powder that were consistent with what your partner had done?

Well, we had some areas at Wyodak that went down slightly that were offset by some Big George additions. If you look at our history of reserves, we have been -- this year, for example, we are 257 Bcf, and they are at 326 Bcf. I believe last year they were approximately 100 Bcf higher than us, so I cannot speak to their reserves, but I think some of the changes we saw in the Wyodak, we possibly -- and not knowing exactly what they have done with their reserves -- we probably would have taken those down earlier than they did.

Okay. Thank you, guys.

Martha Tuddle (ph), Prudential. (technical difficulty)--. (OPERATOR INSTRUCTIONS). Becca Falliwell (ph), Howard Wheel (ph).

My question has been asked and answered. Thank you.

At this time, there are no other questions in the queue.

I will come back to Jay's question. Jay, I think similarly to the earlier question, the overall segment profit guidance for 2005 was lowered about $100 million or about maybe 6 to 8 percent based on I would just say judgment. Our actual forecast changed very little. I think when we looked at it, we felt it would be prudent to be a bit more conservative so we shifted the range down by that $100 million.

It appears that there are no further questions. Again, we appreciate your interest in our Company. We're delighted with the progress we are making, and we look forward to talking with you again next quarter.

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