威廉斯 (WMB) 2003 Q2 法說會逐字稿

Good morning and welcome to the Williams Company analyst conference call. Today's call is being recorded. There will be a presentation followed by a question and answer session. If you should have a question, please press the star or asterisk key followed by the digit 1. We will go to the questions in the order we're signaled. At this time, for opening remarks and introductions, I'd like to turn the conference over to Mr. Travis Campbell. Mr. Campbell, please go ahead, sir.

Good morning. Welcome to the Williams second quarter analyst conference call. I am Travis Campbell the IR Officer of the company. Let me just go through a few things before I turn it over to Steve Malcolm, our Chairman. First, in today's call there are included forward looking statements, please refer to the forward looking statement information in this presentation, also, that that's posted on our website, for more details on the risk factors. There also are some non-GAAP numbers that are presented, reconciliation of recurring earnings is attached to our press release that went out this morning and also on the website.

Also today we will be talking about EBITDA once in a while, the reconciliation of that is included in the slide that we are presenting today. All of these slides are available on our website either in a PDF or a Power Point format. The operator will come back on at the end of the presentation to give information on how to ask questions if you're on the phone lines. If you're on the webcast, there is a button on your screen, to ask a question just punch that and type in your question and we'll get the question that way.

Moving to slide three, the agenda. Today Steve will give an update on what's happened in our company since the May call when we were together. After that Don Chappel will review second quarter earnings and cash and our accomplishments. We'll turn it over then to Doug, Alan and Ralph and Bill who will go through the business units. And then Don will wrap up the consolidated outlook then turn it back to Steve to close the call. So with that, Steve, I'll turn it over to you.

Thank you, Travis. Welcome to our second quarter conference call and thanks for your continuing interest in our company. We are obviously delighted with the progress we have made thus far in 2003. Our core businesses continue to perform well, as you'll hear in much more detail from Don Chappel and our business unit leaders. Our progress on asset sales has been exceptional. We were able to gain access to capital markets much sooner then expected. And we closed several important financings in June and July.

I believe we have clearly addressed the liquidity events that we discussed in detail back in February. The Berkshire Lehman loan was paid off early and we have certainly created sufficient liquidity to handle the March '04 event as well. And we have completed a handful of deals that I believe provide evidence that progress is being made with respect to reducing the risks associated with our marketing and trading business. We will be presenting a great deal of information this morning, I think we have over 100 slides. But my hope is that after the call we will have improved the transparency associated with our businesses.

It will be much clearer where our company is heading, what our priorities are in the future. Back in February you will recall that we gave you a glimpse of what 2004 and 2005 might look like. We have spent a lot of time analyzing, refining those numbers, and we look forward to providing more details. In fact much more financial information by segments. Today you'll also hear for the first time about EVA, about the fact that we intend to adopt EVA in 2004. The fact that we are creating an enterprise wide risk management group, you'll hear much more about growth.

We obviously haven't spoken much about growth over the past year. You'll hear much more about our future growth opportunities. You'll hear that we're evaluating opportunities to retire additional debt early. And you'll hear about the fact that we're renaming marketing and trading to Williams Power to better reflect what that business is all about today. So with that introduction, I'll move to my few slides here at the beginning, slide five, which is one that -- this is one of my favorite slides. I believe it's important to review, our commercial and financial strategies that we ruled out earlier this year. Recall that Williams of the future is a balanced, integrated natural gas company with strong, in many cases world-class assets in E&P gas pipes and midstream. We refer to this as our three-legged stool.

With respect to our commercial strategy we want to own and manage natural gas assets in key growth markets. We have a complimentary financial strategy shown here. The essence of that is we want to maintain adequate liquidity, de-lever the company over time and strengthen our balance sheet. Next slide, number six. Last time that we were together, which was May the 13th, for our first quarter earnings call, we identified these issues as key areas of focus for us going forward. What I would like to do is to give you a brief progress report with respect to these key areas of focus.

Next slide, number seven, with respect to positive results from our core businesses, the second quarter results we issued this morning I believe show continued solid performance in each one of our core businesses. You will receive much more detail on those results in a few minutes, but our results demonstrate solid, sustainable earnings capacity. The key drivers in each of our core businesses, in gas pipes we have major expansions coming on line, on Transco and northwest pipeline, which will generate strong earnings in 2004 and 2005. In exploration and production, we are accelerating the pace of our drilling activity. And in midstream, deep water is starting to contribute much more, and more of our business is turning to fee-based services. Next slide, number eight, again, along the lines of a progress report.

We are clearly managing liquidity. We now have $3.2 billion of unrestricted cash as of June the 30th, and the first six months of 2003 we increased unrestricted cash by $1.5 billion, we reduced debt by $900 million. Next slide, we certainly have identified our priorities and made progress with priorities that are necessary for a sustainable, profitable businesses. We have been successful in reducing interest expense, reduce the weighted average cost of debt by almost 2%, and projected interest cost in the second half of '03, down 32% or $240 million versus the second half of '02. We have been successful in closing asset sales and we've completed $2.4 billion in asset sales year to date. There would be an additional $200 million if you included the sale of our Jackson EMC.

And we have made progress in reducing SG&A, it's down 25% versus the first half of 2002. Slide ten, we are a re-defined Williams is a Williams worth getting excited about. We have the right assets in the right places, we have the right people that are developing the right strategies at the right time, which allows us to be positioned to make the right investments for the future. Slide 11, we continue to focus on marketing and trading. We're actively pursuing an exit of our power business, and I believe that the Hoosier and the Progress Energy and the AEP transactions are evidence that we are making progress toward exiting the business, or ring fencing or reducing the risks associated with that business. Next slide, slide 12, we have narrowed EM&T to being a power business, we're renaming energy marketing trading to Williams Power, we think it best reflects our business focus as it relates to the value of our portfolio.

We have 7500 megawatts, long-term tolling and full requirements contracts, we have hedged out cash flows. This next slide, slide 13, is a schematic, which simply reflects what we're doing with marketing and trading. Bill Hobbs and Andrew, I think, Andrew Sunderman, will discuss this in more detail. Essentially along the left side we talk about what energy marketing and trading was involved with the activities that they were involved with in the past. It shows that we are creating a new enterprise wide risk management group using the capabilities that had resided in marketing and trading, and as well we're creating a power business unit, as I described before. Continuing on, what we've accomplished, we continue to be committed to greater financial discipline in managing the company, slide 14. We are focused on driving toward investment grade ratios in 2005.

Not only debt to cap ratios but as well cash flow to interest coverage, cash flow to long term debt, the kinds of ratios that the ratings agencies are interested in. So the final slide that I have in the introduction, slide 14, these are the themes shown on this slide, and I won't read these, but we will come back. These are the themes that each of our speakers will be addressing today. And the key take aways are embedded in these themes. So I will come back after Don Chappel and after our business unit leaders have spoken, and review the key take aways from our presentation this morning. We've certainly made significant progress on re-building Williams, both from a commercial and financial point of view. So let's now hear more about our second quarter financial results from Don Chappel, and then we'll get a brief overview from each one of our business unit leaders. Don?

Thanks, Steve. Good morning. As Steve mentioned we're presenting a great deal of information today, much of it presented for the first time as we strive to become more transparent and better understood. We'll try to move through the information pretty quickly to make sure that we leave plenty of time for your questions. At the same time we continue to deal with a great deal of complexity, as you do, as we continue to restructure, scale down and simplify the business.

We appreciate your interest and ability to understand the rapidly changing and improving Williams. Our 2003 results continue to be significantly effected by the restructuring impacts, gains and losses on sales, impairments, re-classifications to this continued operation and the like. We'll highlight those for you as we move through the presentation. Let's turn to slide number 17. We enjoyed significant improvements in results year over year as we moved closer to completion of the company's restructuring and turnaround. Our core assets once again delivered solid performance and EM&P sharply improved their results moving from a $500 million loss in '02 to a $350 million profit in '03.

We'll detail the components of those changes as we go through the presentation. Income from continuing operations totals $118 million or 18 cents per share versus a loss of 65 cents per share in 2002. The results in both periods include unusual items related to the restructuring, the highlights of which again we will detail for you as we move through the rest of these slides. Income from continuing operations totaled $152 million or 28 cents, versus a loss of 3 cents in 2002. Re-classifications to discontinued operations during the quarter included Texas Gas, Williams Energy Partners, the Alaskan refinery, Gulf Liquids, ENPS, that's in the Raton and Huegeton basins. These are in addition to others previously re-classed to discontinued, which include Kern River pipeline, MAPL Seminole, soda ash, central, Memphis refinery, travel centers and bioenergy.

Net income totaled $270 million or 46 cents per share versus a 68 cent loss in 2002. Recurring income was break even compared to a 41 cent loss in 2002, and recurring income includes certain nonrecurring items as detailed in the exhibit to this press release and which is available on our website. Let's look at slide number 18. We'll look at our 2003 year to date results taking a look at our year to date performance, income from continuing ops is stronger than first two quarters of 2002, but net income in 2003 is less than 2002 due to the affect of the change of accounting principal for EM&T book. Again, note that this was a noncash charge and had no impact on the value of the portfolio. Next slide, let's take a look at our core business segment profit.

Each of our business unit leaders will talk in some depth about their business, but to highlight for you here, our three core segments' second quarter results for 2003 totaled $345 million versus $285 million in the prior year, and on a year to date basis totaled $728 million versus the $581 million. In the upcoming slides we'll detail those changes for you. Slide number 20 for gas pipelines and Doug Whisenant will speak later in great detail on the business plan outlook. The segment profit totaled $114 million compared to 141 in the prior year. It included some unusual items, which we've detailed for you.

Prior to the unusual items, the segment profit would have been $140 million as compared to the 137, or on a year to date basis 291 versus 272 million. Some key accomplishments during the second quarter included the sale of the Texas gas pipeline for $793 million in cash, and reduction in debt of $250 million. That closed in May. Additionally, the momentum phase one expansion was placed in service, and Gulfstream phase two was contracted and Doug will speak to that. And that expansion is currently underway. Additionally, significant cost reductions in efficiencies were achieved, particularly in the area of office lease costs and related costs.

Slide 21, midstream. Again, Alan Armstrong will speak in detail on the business and the outlook. Segment profit totaled $52 million, same as 2002. And net of these unusual items segment profit totaled 61 million compared to the 58. Year to date basis, segment profit net of the unusual items totaled 179 versus 112 a year ago. In the second quarter of '03, the business suffered somewhat from weak petrochemical and Canadian results, however, those were more than offset by strong deep water results. In the first quarter of '03, Williams enjoyed strong NGO margins, which has since diminished.

2003 accomplishments, again, we enjoyed strong gathering margins, a successful gulf coast fee processing re-negotiations, and asset sales which included Rio Grand, west Texas, and west Stoddart which closed after the close of the second quarter. Slide 22, our E&P business, and Ralph Hill will speak to this in detail, segment profit totaled $179 million as compared with $92 million in the prior quarter. Unusual items included the gain on a sale of assets totaling $92 million, excluding that segment profit was 87 as compared to 92 in the prior year. Of note, the fact that volumes were reduced in '03 as a result of asset sales that occurred in '02 and '03 partially offset by increased production in the retained basins. Those asset sales included Hugeton, Raton and some other assets. Year to date segment profit totaled 293 million as compared to 199. Again, net of the gain on the sale of assets, we're looking at $201 million as compared to the $195 million.

We had higher volumes in the second quarter of '02, as I mentioned, offset by higher net realized price in the second quarter of '03. Key accomplishments in the second quarter in 2003 included ten-acre down spacing in the Piceance, a record of decision in the Powder River, the San Juan environmental impact statement that was favorable to the company, a re-financed RMT loan and as I mentioned asset sales totaling nearly $400 million. Slide 23, looking at E&P results, and again, Bill Hobbs and perhaps Andrew Sunderman will speak to the business later in this presentation. I might first draw your attention to the fact that the segment profit totals $348 million for the quarter as compared to a $498 million loss in the prior year, a change of nearly $850 million. On a year to date basis segment profit totaled $212 million versus a loss of 214 in excess of $400 million improvement.

Included within that number is a gain on the sale of assets or origination fees. Gain on sale of assets totaling $185 million in the second quarter, which represents a sharp improvement over the prior period, and something we're describing as a prior period adjustment totaling $81 million, which represents a correction of items related to prior periods. And again, very solid results from EM&T and a huge improvement over the prior year. As you may know, reported results do not oftentimes track the economic profits and losses of this business in large part to a miss match between mark to market accounting and accrual accounting, which is caused by the fact that the accounting rules require us to use different methods, since we have a stated intention to exit the business. As we discussed briefly on our prior call, we asked a team at Lehman Brothers to review our positions in EM&T and our strategic alternatives for this business unit.

Lehman Brothers conducted an extensive analysis and discussed their results with management and our board of directors. And I can report to you their conclusions and recommendations generally parallel our own. Specifically they agreed that, one, the trading book has significant value. And two, the portfolio increases the company's overall risk profile, while also adding to our imputed leverage. We plan to continue our efforts to reduce the size of this business, to reduce risk, and to pursue an exit of the business. That exit will be based on fair and reasonable transactions, transactions that are risk reducing and have a positive impact on Williams' credit profile and overall reducing risk for the overall Williams portfolio. Slide 24, EM&T 2003 accomplishments. Just to highlight, we closed the Jackson EMC sale that Steve mentioned earlier for $175 million. The business has been cash positive, and I already spoke to the results of our study.

On slide 25, analyze the components of the change in income from continuing operations, during the quarter we reported $118 million of income from continuing operations compared to a $332 million loss or improvement of $450 million. Let's take a look at the components of that change. Within our core business segments, we have a gain on the sale of the EMT 92 million and a writeoff of software development cost totaling 26 million. Again the core segment changes total about $60 million. EM&T changes total nearly $850 million, and again include the gain on the sale of the Jackson contract and some others, the absence of 2002 impairments of nearly $150 million, change in fair value of $567 million, the income that I mentioned related to prior periods of 81, other items of a negative 136, an interest increase in interest expense related principally to the RMT loan, which has since been retired totaling $152 million and an increase in our income tax provision of 284.

Again this nets down to a $450 million improvement year over year. Slide 26, like to now walk through a schedule reconciling income from continuing operations to recurring income from continuing operations, just hitting on the highlights. Again, gains on asset sales, impairments, the income related to the prior period item we previously discussed, the software item we talked about, and the income tax provision, and then finally reduced by a preferred dividend brings us down effectively to a breakeven as compared to a $211 million loss in the prior year for an improvement of $212 million. And again, that breakeven compares to a 41 cent loss in the prior year. Slide number 27. Take a look at unrestricted cash. Let's roll that from the beginning of the year to June 30. Beginning of the year we had unrestricted cash of $1 billion 736 million.

We added to that operating income of 911, DD&A of 340 and asset impairments of 20. We issued a number of debt items, which totaled nearly $1.8 billion. We sold assets in excess of $2.4 billion. Total in flows, $5.5 billion. Outflows included retirements of debt of 2.1 billion, interest payments of 800 million. Capital expenditures of 452 million. We collateralized our new letter of credit facility for a total deposit of 463 million. We had a change in our energy trading assets and liabilities totaling $357 million, another of 161, gets us to a June 30 unrestricted cash balance of $3.2 billion. Additionally we had restricted cash totaling $232 million. Of the $3.2 billion, approximately $2 to $300 million is in international in the net of about $2.9 billion is free and available here in the United States. Page 28, let's review the asset sales in the first quarter.

We completed sales representing $680 million of cash proceeds. In the second quarter, cash proceeds of 1.765 billion. The largest portions of which were Texas Gas at 793 plus 250 of debt assumed. The E&P property sale to XPO of 381 and Williams Energy Partners cash of 431 plus debt of 570. Total completed in the first half of the year, cash proceeds $2.4 billion as well as debt assumed over $800 million. This excludes the Jackson EMC contract sale for $175 million. Next slide, slide 29 is a look at the asset sales that closed after the second quarter and those which are pending.

Those which closed in the second quarter were refined products and west Stoddart. Those announced but not closed E&P Brundage Canyon, west Texas, certain distributed power assets and the Allegheny's buyout of our west power contract with them totaling $128 million, which we expect to close in the fourth quarter of this year. Finally just to re-confirm our intention to sell an additional billion to a billion two of assets, and there is no debt associated with these assets. These assets include our western Canadian assets, which will close in two phases, the first of which we expect to close in the third quarter of this year, and the second phase in the third quarter of '04.

We have additional midstream assets that have timing of the third and fourth quarter of this year. The Alaska refinery which we believe will close in the fourth quarter of this year and finally soda ash in the third quarter of '03. Slide 30. Like to roll forward our debt balance from the beginning of the year. Started the year with nearly 14 billion of debt, re-classed nearly $900 million to discontinued operations netting down to about 13.1 billion at the beginning of the year, with an effective interest rate of 10%. The activity was we paid scheduled debt retirements of $466 million, we retired structured or progeny of $460 million. We capitalized interest of 69, we retired the Berkshire loan of $988 million plus the deferred setup fees. Total cash outflow on this item was 1.167 billion.

We issued new debt of nearly $1.8 billion, which gets us to a balance of June 30 of $13 billion, an effective rate of about 8%. The decrease in debt during the period was $965 million. When added to the increase in cash during that same period of $1.5 billion, I would say is a net improvement of nearly $2.5 billion. Slide 31 is a required reconciliation from net income to EBITDA. I won't walk through all the components. This is the first time I think we presented EBITDA to you. And it's, I think, an improvement on our part and hopefully it will help you in your analysis.

Slide 32, this slide will hopefully help you understand how each of our businesses contributed to the consolidated segment profit DD&A. All of our businesses generated positive contribution for the first six months including EM&T. As you would expect incorporate another function is very small and consists of our corporate function plus our investments from the Longhorn pipeline, the butane blending program sold to WG in July, and interest in our Bolivian terminal. That wraps up this segment of my presentation. With that I'll turn it over to Doug.

Thank you, Don. I'll begin with slide 35. While Williams has sold several of our pipeline assets since early 2001, we've retained 100% ownership. Let's go to the next slide. We've retained ownership of 2 premier pipelines, Transco and Northwest. Since the end of 2001, expansion of these two pipelines plus the investment we've made in our 50% ownership of Gulfstream have largely replaced the earnings capacity we had in the Kern River, central, and Texas gas pipelines, while Gulfstream does not merit the premier designation at this point, its value is going to improve dramatically over the next few years. Earnings and cash flows for our gas pipelines are predictable and stable. Since growth opportunities on Transco and northwest are expected to be limited over the next three to four years, our gas pipelines are going to generate free cash flow to be largely used by Williams to reduce debt.

Now slide 36. We remain among the largest interstate pipeline companies transporting over 12% of the natural gas consumed in the United States. Enough gas to heat 33 million homes on an average winter day. Our Transco pipeline is the largest interstate pipeline there is in the country, supplying most of the natural gas to New York City, New Jersey, Philadelphia and the middle-Atlantic, virtually all the gas in the Carolinas and the south Atlantic. The gas markets served by Transco are relatively strong. The south Atlantic market is projected to grow by an average compound annual rate of over 4% through 2008 and the middle Atlantic is expected to grow by over 2%.

In the past we've provided competitive rate comparisons that demonstrate the strength of Transco's positions in its markets. We're the low cost provider in virtually every market we serve. And yes, the prodigious gas production connected to Transco is expected to be able to continue to serve these markets. Declines from the shallow Gulf of Mexico are expected to be more than offset by nearly 9% annual average increase through 2008 and deliverability from the deep gulf. To this add significant L&G imports, specifically through the newly reactivated Coal Point L&G which is strategically located to allow middle-Atlantic markets to be served after relatively small investments in forward haul expansion facilities and South Atlantic markets to be served through back hauls using existing facilities.

Capacity on Transco is highly valued by the marketplace. The weighted average contract term of customer contracts is 5.6 years, with few contracts expiring over the next couple of years. And when contracts do expire, they can be expected to be extended. Bottom line, Transco is arguable the premier interstate pipeline asset in the country. Northwest is similarly situated, the low cost provider and strong gas consuming markets and connected to prodigious gas supplies. It's specific northwest markets are expected to grow at a compound average annual rate of over 3%.

Northwest offers its markets tremendous gas supply diversity, providing access not only to the large western Canadian gas reserves at the pipeline's north end but also to growing rocky mountain gas supplies at the pipeline's midsection, as well as San Juan basin supplies at its south end. The optionality provided by this gas supply diversity during periods of sub-peak demand is particularly valued by the marketplace. In fact, in the one market where northwest does not clearly hold low cost provider statis, a largest customer extended their contract by ten years largely due to the gas supply and transportation optionality provided by northwest. Northwest has virtually no contracts expiring over the next five years, with the weighted average contract life of 9.2 years. Indeed, northwest pipeline clearly joins Transco among the very best pipeline investments in the industry. I said earlier that Gulfstream is where we have upside. The FERC Regulated interstate pipeline business does not reward the taking of big risk.

When we have expanded Transco and northwest we've done so with security of long-term contracts for 100% of the capacity. On Gulfstream we took a gamble that Florida would open up to merchant power generators, building the pipeline when it was not fully subscribed. Since Florida largely remains closed to merchant power plants, demand for pipeline capacity for power generation remains in the hands of utility generators and has grown, as a result, at a more deliberate pace. Nonetheless, underlying demand remains very strong. Gas demand in Florida through 2008 is expected to expand at the fastest rate in the country, growing at over 8% compound annual rate. The financial performance of Gulfstream will improve dramatically once firm deliveries to Florida Power pursuant to the contract we announced in June are initiated in 2005. Now slide 37.

I'm not going to give a tutorial for rate making but there is one point I'd like to make. Rates are designed based on straight fixed variable rate design principals, wherein fixed cost, including the return on capital, are recovered through a reservation charge for contracted capacity, that is paid whether or not that capacity is actually used. If a pipeline's capacity is fully contracted, then the downside and upside are pretty small. Transco's and northwest's capacities are fully contracted, Gulfstream's is not. In Gulfstream is where we have the upside. Slide 38. The combination of straight fixed variable rate design, fully contracted capacity and no unsettled rate cases mean that the earnings and operating cash flows for Transco and northwest are stable and predictable.

The next slide. Let's now look at how we expect gas pipelines to perform in 2003. Capital expenditures include 375 to 400 million per expansions and 150 to 175 million for maintenance. In addition, Gulfstream will be funding 15 to 20 million for phase two expansion costs this year. Last year's segment profit benefited from several one-time items, and 2003 numbers have been hit by a 25.7 million writeoff of capitalized software development cost. These one-time items favoring 2002 in a year to year comparison will be largely offset in 2003 by the full and partial year benefits of several expansions completed over the last year and a half. Regarding our exposure to gas prices.

Since our reservation charges are paid, whether gas moves or not, over the short-term, we're not significantly impacted by gas prices. Of course sustained periods of high gas prices will destroy gas demand and encourage fuel substitution. On the other hand sustained periods of low gas prices would destroy producer incentive to drill. Slide 40, expansions this year represent a wind down of a period of significant growth on Transco, all fully subscribed expansions pursuant to long-term contracts. Over the 12-month period from December 2001 through November 2002, Transco completed the market link one expansion, the Sundance expansion, market link two and the light east expansions together adding 660,000 decatherms per day of new capacity and providing over 50 million of increased segment profit in their first full year of operations.

This year the Momentum and Trenton Woodbury expansions together will add 320,000 decatherms of new capacity and over 20 million of first year segment profit. Similarly in November 2002, northwest completed the Grays Harbor lateral providing over 10 million of increased segment profit in its first full year of operation and the Evergreen expansion to be completed in October, will add 277,000 decatherms per day of new capacity into the Pacific northwest and will provide over 30 million of increased segment profit in its first full year of operations. The rocky mountain and Columbia gorge expansions replaced back haul capacity we lose when the contractual obligation of existing customers to flow in the opposite direction expires later this year. The segment profit and cash flow is expected from these two expansions will be realized when they are rolled in into existing rates with the next northwest rate case.

Now, turning to the next slide, expansion capital expenditures are less than 50 million in 2004, and only around 10 million in 2005. Maintenance capital expected to total 225 to 275 million in 2004 and 2005. This is considerably higher than the level we would normally expect to spend for maintenance due to expenditures near 250 million in total over the two years for compressor modifications required prior to a 2006 deadline to comply with the clean air act. And expenditures of 30 million per year to comply with the new pipeline safety act passed by Congress last December. The segment profit guidance shown in this slide reflects the impact of the previous mentioned expansions as well as expansions shown on the next slide. We don't expect a power rate increase on either pipeline for several years. Now let's turn to the next slide and look at 2004, 2005 expansions.

In addition to those expansions on Transco and northwest to be completed this year, phase two of the momentum project, adding 54,000 decatherms of capacity and first year segment profit of about $5 million is expected to be completed in February 2004. In addition Gulfstream's phase two is expected to add significantly to our 2005 segment profit once it goes into service at the end of next year. On the next slide, what could go right and what could go wrong? Conservatively we have not included in our projections assumptions that we're going to sell more of Gulfstream's un-utilized capacity than that already contracted. Connected new markets to Gulfstream offers us the greatest opportunity to increase shareholder value and we have not shown additional expansions of Transco and northwest, beyond those we already have on the books.

Most likely Transco's next major expansion would be from cole point north into our middle Atlantic markets, probably somewhere around 2007, perhaps 2008. Other expansions when they materialize can only be undertaken if they are fully subscribed and provide solid returns. The down sides, well, expenditures to comply with clean air act and the pipeline safety act could be more than we've estimated, on the other hand they could be lower than we've estimated. Finally our plan to deal with a May 2nd rupture of northwest pipeline's 26 main line in Washington may have to be modified based upon new findings and the resumption of operations at full maximum allowed operating pressure may be delayed.

On the next slide, our pipelines are a strategic fit with Williams strategy, because they will be providing what they can do very well over the next several years. They provide stable earnings and cash flows with a significant free cash flow to reduce debt. Of course we provide E&P and midstream's customers important consuming market access just as EM&T and \midstream will provide our customers access to important gas supplies. That completes my presentation. Alan Armstrong will now cover midstream's outlook.

Thanks, Doug. We certainly do at midstream, our position to where a lot of our supplies that we gather wind up in providing supply to the pipeline customers, both in the Rockies and now with a lot of our investments in the deep water Gulf of Mexico. Going to 46, please. I'm going to quickly brief you on the four items that are laid out here, then I'm going to follow up to what that means to our financial forecast going forward. I want to speak a little bit to the deep water before I get into that. We are very excited about this basin, not only with the performance that we've seen to date from our investment out there but also to the growth potential that we see in the future out there, particularly to the business plan we've chosen our there, which is to focus on helping major independents in the deep water produce both mid-sized and marginal fields.

We feel like there's a tremendous amount of marginal fields to be developed in the future out there. I'll get into that a little bit later here. Next slide, please. We do have well position and large scale infrastructure. I don't think I could stress this enough in terms of how we distinguish ourselves in this business. We are only focused on the large scale infrastructure. We've done a lot of studies to determine that that is the way to have the low cost structure, and we're very aware that that low cost structure and reliability is what our customers demand.

In terms of being positioned in the right basins, from 2002 to 2005, we're seeing on our domestic gas gathering systems we're seeing an increase of 13%, and that is basically just off of the business that we know is coming to us today. So there may be even additional if gas prices remain strong and the drilling remains strong. In Wyoming particularly we do have the scale there. We produce well over 50% of the NGLs coming out of Wyoming. We continue to see a tremendous amount of drilling in the large dedicated areas in Wyoming, namely the Wamsutter field, Pinedale Anticline, and to a lesser degree the Jonah field.

We also are seeing some target exploration in and around our assets that continue to bring business to us as well. In the San Juan we gather 38% of the gas there, making us number one, as the gatherer in the basin. We're seeing, as usual, the San Juan basin just continues to find ways to further develop the reserves there, and the producers continue to exploit that. The latest thing is the San Juan fruit and coal scene, the infill thats going on there. We expect that full impact to actually show up in '04. Just when we think we may start to see declines in this basin on our assets, good things always tend wind up happening there. In the gulf coast our gas volumes are up year to year from the first half of '02 to the first half of '03.

On the shelf assets, our volumes are up by 18%. Part of that is the deep water that we've continued to go and invest and capture business there. But in addition to that we're also capturing a lot of deep shelf. As an example our North High Island system, which is well positioned for the deep shelf production, is running full today, and it does not have any deep water production connected to it. So again, that asset is well positioned to capture even the deep shelf growth. In Venezuelan, the bottom line here is that our infrastructure in Venezuela is very critical to the crude oil production. Our facilities lift by injecting gas, we lift approximately 50% of the crude oil production out of that area today.

As you can see, we have roughly 70% of the gas injection in Venezuela. So very critical infrastructure, and this infrastructure did continue to operate even during the PDVSA workers strike and for that I think Pedavasa, now the new management, sees us as a very reliable service provider there. Next slide, please. I'm on slide 48 now. Talking about how we fit into the Williams strategy. First of all, we have very strong free cash flows coming off these assets. Our capital needs in '04 and '05 drop down to about $50 million, but we continue to have improvement in our segment operating profit, even with this vast reduction in capital spending.

Our portfolio as the Williams Company, we do have exposure to gas prices. As midstream on a short-term basis we have good things that happen to us when we have short-term natural gas price, typically if crude oil stays where it is. So it is a nice natural hedge that we have embedded in our midstream business. Then finally in terms of how this connects into our blueprint for success and being focused on the natural gas business, it is a very, midstream is a very key link for the connection of new gas supplies. And this is probably an area that's overlooked.

There's been a lack of capitalization in this area, particularly in the gathering and processing side, and we've seen some of the normal players being restricted on capital, but we're seeing a lot of demand for our services. And it's very critical for the midstream infrastructure to stay viable for connect new gas supplies, they get developed in new areas to be connected into existing supply area of pooling points. The existing scale and organization capability, again, we have very much focused this organization, the midstream organization on large scale assets. We have the right organizational capability and the right focus to make the best cash flow out of these strong positions.

And then finally, in talking about how we have synergies with our other units, in the San Juan basin, our assets there are well positioned to provide our E&P group with access to multiple markets. Sometimes in the San Juan basin at various times in the year you'll see strong differentials exist between the northern exit out of the basin and the southern exit out of the basin. And this winter we saw that as high as 30 to 40 cents. So we're always positioned well to make sure that we move our Williams production to the very best markets. Next slide. This slide just shows how we're continuing to reduce our volatility in our business, and you can see there the hash line there, you can see that reducing from where we are today, commodity based business makes up about 20% of our net revenue moving in '05 to about 14%.

So a dramatic movement in that. Last year that number was probably, again, using five-year average margins just to neutralize it from many swings in the net pricing, last year that would have been about 22%. We continue to push that down. This is really driven by two primary things. First of all our sale of our Canadian assets in this forecast period and also the dramatic increase in the gathering fees and oil transportation fees that we're seeing coming out of our deep water business. Next slide. This shows the dramatic growth that we're seeing coming from our deep water.

Shows basically the five primary projects that are bringing this kind of growth to us today. And this, again, is on a segment profit before DD&A basis. You can see basically that the devil's tower and Gunnison projects start to really ramp up in '04 and '05. The spar for devil's tower was put on location about two weeks ago, and we're expecting a first quarter 2004 startup for that. We're seeing a lot of development to the south of this facility. That is not in our forecast, the connection of any of those developments to the south, because we feel like it probably by the time those come on, it will probably be just towards the end of this forecast cycle.

But we're feeling very good about the position and location of that facility to capture some of the new deep water production to the south of that out in the deeper fold area. The other thing to note on this, we've spent about $850 million on these investments starting back in '97 with our Grand Canyon investment, which was about $27 million, and so we're getting pretty nice return out of that investment. Next slide, please. Talking about 2003 and forecasting there. You can see a strong segment profit there of $420 to $480. That should be noted there that abut $140 million is embedded in the last half of that for gains on asset sales. You can see our annual depreciation has been running pretty steadily in the 190 to 200 range. Our workforce reduction continues to go down.

This 34% happens to be the same number whether you look at the first part of '02 to the first part of '03, or if you look at first of '03, to end of '03. So with the asset sales that we've got, we've done a pretty good job of continuing to trim our workforce to be appropriate. Basically we will have gone from about 1972 employees in the second quarter of '02 down to about 1100 employees at the end of '03. Next slide. Moving onto the forecast for '04 and '05, you can see our capital spending hang in there very steady. That's about - $30 million of that is for well connects primarily out west and about $20 million for maintenance and regulatory compliance capital.

Fairly low, so we continue to see a lot of very strong cash flow coming off of this business. The key assumptions for these ranges, not necessarily speaking to the movement from year to year here as much as just explaining why we have $100 million of range in there. First of all, and these really are kind of in order of impact, first of all our NGO margins, even though they are reducing, that still is a major assumption in our ranges, and we are fairly conservative in both '04 and '05 on this, in these numbers well below the five-year average historical. Then on the olefins margins, that's another swing that's in there and we've seen very poor olefins' margins this year.

We're forecasting that to continue into '04 and we do see some return, however not real robust in '05. Finally offshore deregulation in 2005, we have received an order from the FERC for several segments of the shelf pipelines, the Transco assets, and so we're assuming some action that we would take to go ahead and follow through on the order that the commission gave us for some of those assets. And that's roughly about a $20 million assumption. That would only be in '05. Finally, deep water timing, I don't see a whole lot of range coming to this in terms of the ultimate numbers on this, but we are making some assumptions about the timing of both Gunnison and Devil's Tower starting up.

So it's not really extremely variable from a profitability on the assets once they get going, but there is some risk in the timing that affects our ranges on here. And finally on the asset sales, we've got some timing associated with the asset sales, and that's about $30 million of impact from '03 to '04. Moving onto the next slide, this kind of shows just how thing are trending, and I'll talk about the drivers here now, about how we go from '03 to '04 and then from '04 to '05, and what is driving those changes from year to year. First of all in the commodity prices, we've got about $40 million lower expectations in '03 from the five-year average, but we also have a $10 million increase associated with the OFO or operational flow order processing that we're doing in the gulf coast that basically pays us treating fees when processing is not profitable in the gulf coast. So net on a commodity basis or NGO margin, we're seeing about a $30 million decrease from '03 to '04.

On the asset sell side, again, we have a little over $30 million from '03 to '04 of reduction, and then finally on the deep water growth, this offsets the two previous downward movements, and that's a positive about $60 million from '03 to '04. On the '04 to '05 numbers, things that are driving that, about $30 million of positive impact in our olefins, that's from '04 to '05 basis. Then, again, as I mentioned earlier about $20 million from the deregulation of the offshore, and then about a $14 million increase in the deep water growth. And finally a little bit more positive expectation out of the NGO margins, however still well below the five-year average with about a $20 million increase coming from '04 to '05 range there. So a lot of things moving back and forth, but in general we've got asset sales bringing it down a little bit, being offset very strong by our deep water growth. Next slide, please.

Moving to the summary on this, as you can see if you do the math on that we have very strong free cash flows. If you take our segment profit before DD&A and you reduce that by the Cap Ex, that's about $450 to $550 million respectively '04 and '05, and this is against a net PP&E of less than $3 billion in that time frame. So really generating some fairly decent returns on that basis. The critical infrastructure in the growth basins, I absolutely feel like we've got the best infrastructure in the midstream business. It is well positioned to capture the growth, and we have very much been focused on accomplishing that over the last two or three years. It is a nice strategic fit within Williams, as I explained, and we are continuing to reduce our volatility through the investments and asset sales that we have been taking on over the last about year and a half.

Then finally, the deep water earnings that you saw in there, that is growth without additional capital. So very strong growth, very strong free cash flow starting to generate. We do see a lot of opportunity and a lot of demand out there for the deep water services, and we'll deal with those opportunities as they come up. But somebody is going to need to serve that. And we will have a choice to make whether just to reap the cash flows from the assets we have or continue to invest out there in the future. Finally, the margins in these forecasts, there is nothing like a first quarter '03 or second half of '02 kind of performance that we saw in the margins. None of that is in these forecasts. So fairly meager margin forecast could certainly push us towards the upside if any of that happened. So that's all I've got, and I appreciate your attention and I'll turn it over to Ralph Hill now.

Thanks, Alan. Today I'd like to discuss our first half highlights for the E&P, discuss our unique drilling portfolio and reemphasize that we have a high quality, low risk reserve base, discuss our decision to ramp back up the drilling program of this unique portfolio and share with you 2004, 2005 outlook, some of our basin matrix and business plan. Turning now to slide 56, investments for E&P here are basically short time cycle fast cash returns. We have diverse producing basins in the long-term drilling inventory, a history of high success and low finding cost, and we're getting ready to kick off an accelerated drilling pace.

Turning to slide 57, look at 2003, our capital spending is in the range of 165 to 190, up slightly from last time due to our incremental spending we will have the last part of this year, segment profit expected to be between 400 and 450 million dollars, production is in the 437 to 455 million cubic feet a day range. That is average for the year. Our exit rate should be somewhere in the middle of that number. Slide 58, our 2003 second quarter accomplishments, we did have ten-acre spacing approved in the Piceance for a portion of our acreage, 11,000 acres that we applied for in February was approved on February 12st. We expect this will add as a significant decision first of all to be a ten-acre down space in the Piceance, and we expect it to add 500 to 600 locations from that initial approval. We've also applied for an additional 16,000 acre application for ten acres in June and we expect approval for last August in this.

This, again, would add about 5 to 600 locations, a very significant in the Peon basin. In the Powder River we received a recorded decision on April 30th, from the BLM. This provides for 39,000 new natural gas wells over about 8 million acres and drilling over a ten-year period, allows for new roads, pipelines for gas gathering. We expect that the record decision to start receiving permits and, in fact, have received permits. Williams received the first permit issued from the BLM based on the record decision. We've now received an additional 12 permits. In total we received 13 permits. We expect in the next 60 days to receive about 200 new permits. I'll talk a little bit more about this in just a minute.

We re-financed the RMT loan down to a new loan of $500 million at LIBOR plus 375, and our asset sales are essentially over. We've closed, or announced, about $490 million of asset sales in the first half of this year. With the exception of a few small properties hanging out there our assets sales are over. We're off to increasing our drilling program in Piceance, San Juan, and Arkoma. Remember that we had fully funded the Powder River this year and our additional capital will be for those three areas. Most of the capital will go into the Peon basin. Turn to slide 59. Segment profit, looking at the second quarter 2003, includes gains from asset sales of approximately $92 million.

If you compare our profit and gains on sales and on apples to apples basis for the assets we have taken out, we're at 87 million dollars in the second quarter '03 versus $77 million in the second quarter '02. Our production only declined 11% for the quarter, even though on a similar basis for the quarter to quarter comparison we sold approximately 20%. In our retained properties are up about 11% for the second quarter 2003, compared to the same quarter last year. I think this reflects our successful 2002 drilling program and the positive rapid impact a normal drilling program has for Williams to have our retained properties up that much quarter over quarter.

Looking at slide 60, we do believe we have a unique drilling portfolio, we have the unique leadership positions in top Rockies basins as you can see here. Our reserve position, if you take the year end reserve report of 2.8 trillion cubic feet and adjust it for the asset sales, we have approximately 2.4 trillion cubic feet of reserves. One of the things I think is the key to our portfolio is that 52% of our proved reserves are undeveloped and that gives the opportunity to develop these low risk high return wells. We have a significant probable reserves inventory we believe is at least equal to our proved reserves, a very long term low risk high return development drilling inventory. This portfolio is capable of 10 - 20% annual production growth. Slide 61. We've been in these basins a long time, so we pursue the low risk development of sizeable known assets.

They play to our expertise and strength, which is tied-sans development and coal bed methane development. We are established in these basins, we have proven organizational capability, a very predictable production profiles. We are the operator, we have high working interest and consolidated land positions which give us economy to scale in our drilling. We understand the geology and it allows for repeatability of results. It is not a question of resource risk, we are in gas saturated areas, which many years of experience. We refine and test our drilling completion practice constantly. I think that's a reflection that the majority of our portfolio we can drill, complete, and flow gas in 30 to 60 days.

And our 2002 success rate was 98.6%. Look at slide 62. We do have a large drilling inventory which we believe represents an excellent opportunity for growth. As I mentioned the problem of possible reserves are significant. Key to what we're looking at here, no acquisitions or exploration is necessary to meet our projections. We can do this with what we have in house today. Our low risk proved undeveloped drilling will give us strong capital opportunities. We have been able to convert a number of probable reserves, as our PUD inventory is drilled. Over the last two years we have converted 350 BCF of probable reserves to PUDs through our drilling of our PUD program. We believe we have the opportunity to exploit advantage and technology, our physical infrastructure, market access, expertise in scale, and we are self funding and generate free cash flows. Slide 62, a response to this unique drilling portfolio. Williams' improved financial health is that we're restoring our drilling program, we plan to expand it. For this year, $26 million of additional capital will be expended. In 2004 and 2005, we intend to add $111 million and $128 million. The primary growth driver is the Piceance Basin.

In July of '03 of this year, we had one rig operating, we're currently up to five rigs operating. We anticipate being at seven rigs in the Peon's by December '03 and increase to 15 rigs by mid 2005. We believe it will result in superior financial matrix and returns for us and will jump-start the growth engine that we have in the E&P side. Slide 64, our matrix look for the next two years capital spending in '04 of $300 to $350 million, '05, $400 to $450 million. The big variance in between those numbers is the number of rigs we have in the Piceance basin. '05 assumes that we get to the 15 rig program. '04 we'll be building to the 15 rig program. Segment profitability should be in the $275 million to $340 million rang in '04, $350 to $400 million in '05. Our production should be between 500 and 550 million a day in '04, and 600 to 700 million a day in '05. On our hedge position which I'll talk a little bit more in just a few minutes, we are 80% hedged in the year 2004 and between 12 and 15% hedged in the year 2005. Looking at the potential problems with basis in the Rockies. We are a Rockies producer primarily, this is on slide 65. Sorry about that. We're not necessarily a Rockies price taker. We have a significant amount of capacity, slightly over 200 million a day of firm capacity that we can get to the mid-continent via Trail Blazer.

We have 51 million a day firm transportation on TransColorado where we can take our Peon's gas down into the San Juan and that increases 250 million a day by 2006. All of our Powder production currently goes to the mid-continent which avoids potential basis blowouts that were out there last year, although the basis has tightened with the Kern River expansion. Part of our Piceance goes to the mid-continent, the same way as the Powder goes around the horn into Trail Blazer. Part of the Piceance goes to San Juan Basin via our firm transportation on TransColorado and part does stay in the Rockies. Our overall current Rockies price exposure is about 23% in 2004 and with our firm increasing in later years, this Rockies exposure will stay about the same or could decrease depending on the amount of volumes we add.

We don't believe we are exposed to the potential for a huge Rockies basis blowout. Not that we're predicting that, but it is a worry out there from time to time, infrastructure capacity. Looking at slide 66, our critical success factors, let me first say that we do believe that in our geology side, which is not listed on here, because I think I've talked about it, just in case, we're in repeatable areas and we have developed a very predictable resource. We believe the geology risk is very, very low. We understand the areas, we've been there a long time and our geology is repeatable, and again, we're in gas saturated areas.

Looking at other risk areas, drilling risk, again we believe is low because we've been doing this for a number of years and we continue to refine and improve our techniques and get our gas on, for example in the Piceance basin drilled, completed and flowing in less than 30 days. Permitting delays, low to moderate. In San Juan, Arkoma and the Piceance it is very low, in the Powder River we have moderate. Powder permitting appears to be gaining momentum, we have received 13 new permits, we were the first company to receive a permit from the BLM based on the new record decision. We expect another 30 or so permits in the next week and another 175 in the next 60 days. We believe we're building momentum and the record decision is starting to play out as we expected.

However, if we were to be delayed in the Powder, we believe we could deploy capital on some other basins on a faster then planned pace, primarily in the Piceance Basin. On safety and right crews, we've been in these area for a long time, we think we can do that and we have done that in the past and will continue that. We believe competition is low in the sense of we have our leasehold already established, it's held by production, we have the opportunity to continue drilling, been there many many years. Gathering transportation is low, as I mentioned on the infrastructure slide before, we believe we're in setup fine to move our gas to wherever the highest price is. Rig availability, low to moderate. So far so good in acquiring rigs to ramp up our drilling program. As you can see we've gone from July, 1 rig in the Piceance to five rigs currently. I think it's a testament to our years of activity and our people in the field working in these core basins and working with our service providers, so we believe that that risk will remain low.

Turning to slide 67, our hedging and pricing strategy, just to reiterate, 80% of E&P's production in 2004 is hedged above $4 Nymex, approximately $4.02. Future hedging strategy, which is something I'm excited about, will be a function of Williams portfolio, working with our enterprise risk management group which I believe we will talk about later in this call. I think it's key for Williams to look at its gas price exposure not solely from an E&P perspective also from a midstream perspective and from a power perspective. And that's what we'll be doing. So our future hedging strategy will be a function of this Williams portfolio. Historically we range from 20 and 50% in our hedging. But again that is not a guide for what we will be doing, it's just what we've done historically and what we have currently on this slide. Where we go in the future will be a function of Williams in our portfolio.

Slide 68, lots of numbers here. I'm not going to speak in detail, but a couple of points I'd like to point out here. This is a typical well in our core basins. I'm trying to give you an average for our basins in the sense of cost, drilling cost and well reserves and well depths, acres, spacing, those kinds of things. As you can see the incremental internal rate of returns of these are very high, as are the net cash margin and net profit margins. These numbers were run off an Nymex price of approximately 489. The strip I looked at yesterday for Nymex, the five-year strip was $4.90. I think they are very representative of the current market that's out there.

We've added a new part to this slide called the net profit margin, which essentially is an add back the drilling cost to the net cash margin and subtract our DD&A to show what it is on a profit basis. Hopefully this will help with some modeling and obviously we can take some questions on this at other times that you may have as you model the E&P portfolio. Turning to slide 69, in summary on our business plan and our strategic fit, we continue to emphasize that we will be developing our long-term low risk high return drilling portfolio. We should be in the range of 1200 to 1400 wells per year. The variance there will be in the Powder River, how many wells we're drilling in the Powder. We are a natural hedge to gas consumed by the mid-stream fuel and shrike as they are gas produce for us. Our San Juan Bain reserves are behind our midstream gathering assets and Alan talked about some of the synergies there.

We expect to continue to have a very high success rate based on our history in these areas and the repeatable geology that we're in. Our average annual production growth should be 10 to 20%. We should be self funding, a free cash flow generator, and should exhibit significant segment profit growth. Thank you for the opportunity to share that with you today, and I'll now turn this over to Bill Hobbs.

Thanks, Ralph. We are now on slide 70. As Steve mentioned earlier today we're a power company that also manages commodity risk for Williams. In the near future we will remove the risk management capabilities to corporate as part of enterprise risk management, which Andrew will speak about shortly. Slide 71, the left column represents what we were a year ago and the right column represents basically what we've been doing for the past year. Our origination and trading efforts have been focused on selling contracts and reducing risk. The gas we buy and sell is to support existing power contracts and Williams' asset businesses.

We are focused on preserving value of the book until we can get fair value for our power contracts. Slide 72, we are a power company with the majority of our capacity sold for the next several years. We have six tolling contracts that provide 7500 megawatts of capacity which we have hedged in two ways. First we've entered into long-term structured sales to utilities that cover 70% of the cost structure of the tolling deals including SG&A. Second, we have entered into bilateral physical and financial sales. When you combine these two hedges, we have more than covered our demand payments under the tolling contracts through 2008. The cash flows from our power business are known and are very manageable.

70% of the expected cash flow in this business occurs in the first ten years. For these reasons and that our power business is a small percentage of Williams' overall business, we believe our power business compares favorably to our peers. Slide 73. As I mentioned earlier we are hedged for the next few years. We agree with most in our sector that sparks spreads will remain depressed for the next few years but we are largely insulated from lower sparks spreads, we've hedged our tolling deals in 2000 and 2001 in an environment when sparks spreads were dramatically better, thus locking in a significant cash flow stream.

Also like most in the industry we believe spark spreads will improve in the 2006 and 2008 time frame. If we're still in the power business we will then be positioned to hedge into improving spark spread cycles thus capturing significantly more value. I will now turn it over to Andrew Sunderman who will discuss financial data and enterprise risk management.

Thanks, Bill. Looking at the incremental liquidity needs for the Williams power and enterprise risk management functions as we move forward, obviously there's been a lot of effort to reduce not only the risk profile to the company but the liquidity needs in these two businesses as we move forward, and that's been very successful over the past year. As we sat at June 30th, you can see from this slide, slide 74, that the total Williams portfolio had approximately $1 billion in working capital out since its credit event, about 45% of that is related directly to the power portfolio with the other 55% related to the other Williams commodity businesses.

As we look at stresses and sensitivities around working capital needs going forward as of June 30th, from a margin standpoint, when we've run our models it shows there's a 1% probability of the incremental need for Williams being an additional $300 million over the next 12 months. Now, what's gone our from a sensitivity standpoint that the company is highly sensitive to gas prices, even though we do run a fairly balanced portfolio with power offsetting gas from E&P, you will see margins go out the door primarily from E&P hedges when gas prices rise and dollars come back in the door primarily from E&P hedges when gas prices fall.

Looking at adequate assurances in addition to the margins we have to post the credit event required. Many companies in our sector, as well as us do at times post additional credit assurance. That has traditionally run about 40% of our margin needs and we estimate that to be a 1% probability of an additional 120 million for Williams overall portfolio as we look forward. I think that when you add those two numbers together over an annual period, the total of 420 million, while it's a number that does only have a 1% probability of happening, so we think it's a very low risk of happening, we do realize that that number in light of the cash balance we currently have, as well as our ever improving financial position should not be a major risk to the company's ability to meet its liquidity needs.

Additionally to date, since we began exiting and liquidating the portfolio mid last year we have either liquidated, sold, announced for sale over 500 million dollars of contracts or assets many of which have been highlighted in our press releases over the past year. What does that do for the company? Basically several things. First of all it does bring cash in the door. Secondly it does reduce the peripheral liquidity needs associated with these assets and contracts, such as letters of credit, parental guarantees. Thirdly, it does improve the risk profile of Williams as we continue to exit this business. And lastly, as we continue to receive either fair value or high cents on the dollar of fair value, it does continue to prove that this portfolio does have value and it does not need to be sold at fire sale prices.

Moving on to the next slide, Don covered this earlier in his presentation. I'll walk through a little more detail. I want you to look at the earnings for the second quarter of '03. The primary drivers there obviously are the mark to market earnings, primarily on our gas derivatives positions. The other line includes $20 million charge for the recently announced CFTC settlement. The $185 million includes the $175 million for the gain on sale of the Jackson EMC, and the $81 million prior period adjustment relates to some changes in accounting for some prior period items primarily in 2001.

Looking at cash flows, there's been a lot of concern in the press and in the publications over what is described as a significant usage of cash by the energy, marketing and trading business unit. We're trying to show you here that prior to the credit event and loss of our investment grade rating that the business unit as we previously said did create positive cash flow from operations for the enterprise. Looking at the credit event and primarily limited to the third quarter of last year, that the enterprise did need somewhere near a billion dollars posted for the credit event and then post the credit event, once again, we are back to producing positive cash flows from operations for the enterprise. Hopefully this starts to put to rest any of the concerns around cash flows from the new power company.

Looking at slide 76, this is a similar to the 10-K that we have shown in the past. It's not a required disclosure anymore, but what we thought we would do is we would try to continue to build more transparency into how we expect the cash flows in the power portfolio to roll off. As you can see there's very strong cash flows in the first five or six years, which is closely correlated to Bill Hobbs comments around our hedging. I do want to make note of several things, though. This does not include a fully loaded SG&A. This is the power portfolio only, and it does not account for any working capital increases or decreases, primarily through margin volatility as these derivatives roll off. But that number can be planned for in your models because we gave you a 1% probability number earlier in the presentation. Moving onto slide 77, looking at our outlook, primary thing here is to tie it back to the slide I just showed relative cash flows. These are the expected profit ranges.

A little more of a variance, a little wider distribution in our profit ranges primarily due to the continued disconnect in the accounting principals. When you're looking at segment profit between derivatives being marked to market and the underlying positions that they are hedging economically being accrual once again segment profit does not equate to the economic value, which is another item that we look at on a daily basis. Slide 78, Don, Bill, and Steve all mentioned moving to enterprise risk management. This slide gives you a high level overview of what the objective is of doing that. Clearly the company wants to continue to focus on identifying value, measuring and ultimately managing at an enterprise level its commodity and credit risk as a key driver for incremental value for the company. Why would we do enterprise risk management?

Clearly it's going to enhance the discipline of capital allocation that has been talked about very often in the previous presentations. It will help manage the volatility of cash flows through reasoned hedging strategies around commodities. And it will effectively integrate into our new EVA structure. What is the expected benefit from this? Clearly it will look to continue to decrease the risk profile for Williams around commodity and credit risk while balancing the economic cost to the company for doing so. At this point I'll turn it back to Bill Hobbs.

Thanks Andrew we're now on slide 79. I'll use a slide Steve showed you earlier to close on. To be clear we have not been speculative trading and pursuing new origination business for the past year. We have been focused on preserving value and reducing risk while at the same time selling contracts at very high cents on the dollar. We will stay focused on these efforts. Although we believe our power business is a good business and compares favorable to our peers, we remain committed to selling the book for fair value.

Our risk to cash flow are quantifiable and manageable. And as Andrew pointed out we have not been a cash drain on the company. We have a significant percentage of our tolling capacity hedged which insulates Williams from the depressed sparks spread cycle we find ourselves in. Finally we'll be transferring risk management and quantitative capabilities to our finance group as part of the enterprise risk management and EVA initiatives. With this I'll now turn it back to Don Chappel.

Thanks, Bill. Let's take a look ahead on slide number 81 at our future, which I believe is very bright, and I believe that you will agree. Our business units have provided guidance and this schedule rolls it up to consolidated level. Total segment profit for 2003 forecast at a billion three to a billion eight as compared to about $900 million year to date. Slide 82, we'll now take a look at some of the key items that are important to you and to us.

Segment profit of a billion three to a billion eight, EBITDA a billion nine to 2.5 billion and cash flow from operations, $700 million to $900 million. Diluted loss per share we're forecasting at a $1.40 loss to as little as 55 cents per share loss. Page 83, let's take a look at some of the components of our 2003 EBITDA reconciliation again. We're reconciling from net income or in this case net loss down to EBITDA and I won't walk through each of the components there but it's there for your reference. Slide number 84, let's now break that down by business unit, and we'll summarize our segment contributions by those business units and I think you saw those forecasts earlier in the presentations from each of the business unit leaders. To that we added the DD&A so you can come up with a number that I think you'll find interesting which totals a billion nine to 2.5 billion for 2003.

Flipping to page 85, looking at 2003 to 2005, segment profit increases from a billion three to a billion eight range. It drops a little bit, I'm sorry, in 2004, to a billion one to a billion 440. The variance there being really the gains on asset sales that are included in 2003 that would not be anticipated in 2004 and beyond. Then segment profit increases nicely to a billion four to a billion 750. DD&A 635 to 695, moving to 635 to 705 and up a bit from 675 to 745. Cash flow from operations, 7 to 900 million this year, a billion to a billion three in 2004 and a billion 450 to a billion seven in 2005.

Capital spending add 900 million to a billion this year as we complete a number of projects that were started in some cases a number of years ago, previous commitments that the company had, projects that were already in process, having been completed or in the process of being completed. As such, capital spending for 2004 declines to $400 million to $550 million in 2004 and 5 to 600 million in 2005 despite the increases in our E&P business and some of the compliance cost in our gas pipelines business. Cash taxes range from 3 to 25% during the period and is really, the variation is related really to gains on asset sales.

And finally debt to cap, we're currently in the range of 73 to 75%, and by the end of 2005, we're forecasting 55 to 65% as we seek to achieve investment grade once again, which is very important to us. On chart number 86, you'll view a graph of our scheduled debt maturities, we've effectively pre-funded the 2003 and 2004 maturities, which total $2 billion even there. And additionally remaining asset sales will provide funds along with cash flow from operations to retire additional debt prior to its maturity date. Finally, I might draw your attention to the $1.1 billion section of the bar in 2007, and that represents an obligation associated with our feline tax, which I'll walk you through in just a minute.

Why don't we turn to our next chart, chart number 87, and I won't walk through all of the details here. The key takeaway is in February of '05, Williams will issue 44 million shares and receive 1.1 billion in cash, effectively $25 per share. And then in February of '07, Williams will repay the $1.1 billion note, the obligation that we currently have with proceeds that would come to us in that February of '05. So again, net net, a billion one of our debt will turn into equity and we will receive a billion one in cash to allow us to pay that debt in '07." Chart number 88. Some highlights of our financial strategy, we intend to maintain a cash and liquidity cushion of a billion dollars plus, which we believe, given our current volatility and other factors of the business, is an appropriate cash cushion for us.

We'll continue to de-lever the business striving for those investment grade ratios. We'll establish a new liquidity or credit facility when it becomes attractive to us, there by reducing our cash requirements. As you know we have nearly $500 million in our cash collateralized LC facility plus the billion dollars that I just pointed out in terms of our cash cushion. Additionally I'll mention that perhaps when we return to investment grade as much as a billion dollars outstanding related to the credit event would come back to the Company. Some of that, in fact, will come back we believe prior to that point in time. But achieving an investment grade rating is important to the company for the reasons that I just mentioned.

And we've already been approached by some of the same banks that we negotiated this new letter of credit facility with. Our banks are very interested in extending us real credit. When we believe that the time is optimal, we'll pursue that and perhaps be able to free up some of our cash for other purposes. How will we use our free cash flow, again, first pay down scheduled debt retirements, early debt reduction, to make some disciplined EVA-based investments. Ralph Hill pointed to some of those in the E&P business, very high rates of returns, positive EVA, and we'll consider a dividend or share re-purchase upon achieving or approaching our investment grade rating. Chart number 89 is an attempt to roll forward from where we are today in terms of our debt balance and our debt to cap ratios.

As I mentioned earlier, we currently at June 30 had a debt balance of $13 billion, debt to cap of about 76%. Scheduled payments of this year of about $400 million would bring that down to 12.6 billion at the end of the year. Scheduled debt re-payments in 2004, the largest of which is in March of 2004, and that's a billion four. That along with other debt re-payments in 2004 reduce it to 11 billion or 72% debt to cap. And some additional payments scheduled for '05 would bring us down to a balance of 10.8 billion or 65%, assuming no accelerated debt reduction as a result of the excess cash that we would expect to have on hand.

Assuming that we apply excess cash that would be forthcoming from asset sales as well as cash flow from operations, you can see it's quite an improved picture with debt to cap at 55% by the end of 2005 and debt reduced to a level of about $7 billion. Page 90, just a few words on EVA. Finally, and again, very, very importantly we're moving to implement the EVA financial management system. We launched the initiative in July with full board approval. We retained Stern Stewart to support our implementation.

The implementation is in process and will be effective as of January 2004. We believe the EVA metric will focus managers on value adding decisions and that the EVA based incentive compensation plan will really reinforce the change in thinking and create a lot of value for Williams and Williams shareholders. And finally I would say that the organization is enthusiastic about EVA, and I think we're looking for some great improvements as a result of this much improved management system. With that I'll turn it back over to Steve.

Thank you, Don. We've certainly given you a lot of information here over the past hour or so. We've tried to be responsive to questions that we have received, requests for information that we received while we've been out on road shows on simply fielding calls and questions from analysts and investors and banks. So we've talked about what could go right, what could go wrong. We've talked about our critical success factors within each of our businesses. We've talked about key drivers that will influence our financial performance. I trust that you will find this information helpful and illustrative of our very bright future. Turning to slide number 92 As I promised earlier, I intend to review the key themes, themes that you heard about as our business unit leaders and as Don Chappel have presented today. So these are the main takeaways. When you think or talk about Williams, these are the facts that you should focus on. The first four issues above that line, these are enduring issues, these are long-term in nature. We're going to be talking about these for a long time. The ones below the line are more short-term in nature and hopefully ones that we will largely put to bed in the near term.

So going through each of these individually, slide number 93, in terms of sustaining solid core business performance, the key takeaways in the gas pipeline area, the fact that expansions are coming on line, and as of the third quarter significant free cash flows will be developed. Our revenue stream is largely supported by long-term firm contracts in gas pipes area. This will result in stable, predictable cash flows and earnings, as well we're the low cost service provider in almost every market that we serve. In the exploration production area, the cash return characteristics are remarkable. This is short-term cycle investments, fast cash returns. We have, as we've said many times before, a ten-year inventory of low cost, low risk, high return drilling opportunities. And we've had remarkable success in terms of our drilling progress thus far.

In midstream gas and liquids, deep water is beginning to contribute fairly significantly to our earnings, represents significant growth potential for the company, and more and more of our earnings are tied to fee-based services. So these are the issues that we would like to you take away from the presentations that our business unit leaders made. Next, slide 94, we are de-levering our balance sheet. We intend to reach critical debt to cap ratios by 2005. Current debt is about $13 billion. We have scheduled payments that allow us to get to 10.8 billion by 12/31/05 or about a 65% debt to cap, but with the excess cash could bring that down to 7.3 billion dollars or about a 55% debt to cap ratio.

Next key theme, we intend to maintain our investment discipline. We recognize, and I hope you recognize, that we are managing the company differently and with greater discipline now than in the past, and an example of that being the adoption of EVA as a key metric going forward, we think it will drive the appropriate behavior as we go forward. Next key theme, major theme, positioning our core businesses for future growth, each of our businesses talked about growth in a little bit more detail than we have in the past. Clearly we intend to maintain our competitive advantages, competitive positions and take advantage of the growth opportunities that are present in each of our businesses. Next slide, we obviously need to wrap up our asset sales. We are committed to selling the Canadian midstream and other midstream assets, the Alaska refinery.

We have given you a forecast as to when we think those sales will close. It's important that we get this done. But it's not important enough that we need to fire sale these assets. So we will be prudent in our negotiations, but we will get these done. Next slide, slide 96, we are making progress and rationalizing our cost structure. We continue to reduce SG&A costs as we sell assets. We're able to reduce our corporate overhead. I can assure you that our senior management team is focused on making this happen. We have achieved some success to date.

I would consider it to a certain extent some low hanging fruit, but we are committed to doing more in this area. Next slide, number 97, we want to continue to resolve the noise around Williams and around our sector, in terms of the litigation and ongoing investigations. We're looking to get as much of this behind us as possible. You've seen recent settlements that we've made with FERK and CFTC. These are appropriate for us, to get these behind us. Next slide, as I have said and as Bill has said, although we're changing the name of Energy Marketing & Trading, it's still our game plan, and we're still committed to exiting the power business. I think that we've made good progress, we've talked about the deals that we've done.

In the interim we will continue to manage the business in ways that preserve our value that we've talked about, allow us to continue to reduce risk in the cash requirements associated with the business and allow us to meet our contractual commitments. This last slide that I have, slide 101, is a slide that we've used with our board, really for the past year. It's one that we looked at and said these are the measures of success that need to be achieved in order for us to move through the challenges that we were faced. As you can see, there are categories called stabilization of restructuring and emergens. In terms of stabilizing the company, clearly and conclusively, we have addressed all of those. We've clearly avoided and taken the issue of bankruptcy off the table.

We have addressed the liquidity needs, and we have restored customer and supplier confidence. In terms of restructuring the company, you can see a dotted check mark, an emerging check mark under complete asset sales. We've made great progress there. There's still some that we need to get done. We've given you the schedule. We will get those done. We will be able to check that box soon. In terms of rationalizing our cost structure, we have captured some of the low hanging fruit. We're committed to doing more.

I believe with the asset sales that we've completed, with the financings that we've done, this summer we clearly have managed liquidity and done that quite well. In terms of de-levering the company, we have a plan to de-lever, but we have to get it done and we've shown you how we intend to do that. In terms of restoring confidence and gaining access to capital markets, I believe we have done that. We've checked that box. Our stock has recovered. Our bonds have moved up, and we were able to gain access to capital markets much sooner than we expected.

Lastly in terms of emerging, with a new and exciting focus for Williams, these are boxes that we cannot check yet, but I can assure you that we're focused on positioning the company for integrated natural gas growth. Optimizing our capital structure and capitalizing on strategic positions. So these are the measures of success that we've identified for the board. These are the ones that we look at every day. These are the ones we focus on in terms of our blueprint for success. We are looking forward to the day that we can check all of these boxes. So I would again conclude that this is a Williams that is worth re-structuring. I believe that we have a bright future as we have described for you in great detail today. Thank you for your patience, and now we'll be delighted to take your questions.

Thank you, sir. Our question-and-answer session will be conducted electronically. If you would like to ask a question, please firmly press the star key followed by the digit one on your touchtone telephone. We will come to you in the order that you signal. If you find that your question has been asked and answered before you could ask it and you would like to remove yourself from the question roster, please firmly press the pound key. Also if you're own on a speakerphone please make sure that your mute button is disengaged so your signal can reach our equipment. Again if you would like to ask a question press the star key followed by digit one. And for our first question we go to Scott Soler with Morgan Stanley.

Hi, good morning. Can you all hear me? Hello. Can you hear me?

Yes, we can.

First off, Steve, congratulations. I think y'all have done a lot very quickly compared to many companies in your industry. I want to applaud you on that. I think you all deserve a lot of credit.

Thank you.

Secondly I want to ask a couple of questions. Don, I understand you have a history of implementing EVA at your prior company. I hope you can color that in for people a little bit, then the second question I had on EVA is return on capital versus cost of capital, what we're curious about is your capital spending budget in '05 does go up because of funding the E&P business, but to us the biggest thing you can probably do is lower your cost of capitol or the assumed risk of the company through perhaps de-leveraging even more aggressively. I just wanted to throw that out, that's my first question, and see what y'all's commentary is on that.

Okay. Scott, this is Don Chappel. Yeah, I had some terrific success before with implementing EVA in another capital intensive business. In that situation, much like Williams, we had some metrics that didn't necessarily cause folks to understand full cost capital and made decisions, I would say, based on incremental cost or the cost of debt. And therefore capital was deployed very, very, I'll just say in a way that oftentimes didn't create value. And felt that the EVA system responded to that challenge, did it very effectively. We began the implementation efforts in the month of August, and had it rolled out and if effect by January 1st, on a company wide basis. So we have a similar time line here. We started in July and we expect to have it in place by January 1st. We'll have some training that will continue into 2004, but make no mistake the metric will be in place and we've have incentives in place to cause everyone to really think about creating economic profit or economic value. In terms of return on capital, and the E&P investments, I think we, like you, took a very careful look at that and felt that the E&P investments had very strong returns, well in excess of our cost of capital. Also they returned cash so quickly that in fact these incremental investments were almost entirely self funding. We see the cash flows coming back so quickly that the impact on free cash flow was not all that great. I think we felt that it was important for us to have some growing assets and growing earnings as well as growing cash flows. And the E&P business provided that for us. We think that the incremental benefit of applying that same cash or free cash to reduce debt was just not nearly as attractive. We are very focused on reducing debt and we're going to scrape up every dollar we can to, in fact, do that and lessen the risk.

Don, what sort of -- this may be too early to ask you this. What sort of looks like the low-lying fruit when you implement EVA? What were the easy things to capture first.

First and foremost, capital spending has been throttled way back. Right now we don't have capital spending out of control. The only spending that's been going on is spending that was previously committed to and in process. Above and beyond that, we've already outlined the E&P investment. Beyond that the only new capital I think we've seen to date is mandatory capital in the gas pipeline business for clean air act or pipeline safety act. From a capital spending standpoint we're very much under control by just not doing very much. But as we attempt to grow the business in a very value adding fashion, I think that's where EVA will really kick in. Additionally I would say that when we make decisions regarding hedging strategy, when we make decisions with respect to spare part inventories on the front lines of the business, things like that, or accounts receivable, I think there will be a much more self motivation than motivation from the top, for managers throughout the organization to reduce the net asset base of the company. So I think there will be some exciting things happening on that front.

Last question on this. Will y'all's compensation structure on EVA be driven all the way down to the staff employee level and will it supersede earnings growth, will it be on par with earnings growth? That's always a struggle it seems like when companies implement EVA for companies. Williams had a culture of growing earnings not EVA.

My prior history is going from a company that was EPS or EBIT growth driven and we moved to 100% EVA. I think in this case the majority incentive will be EVA based versus any other incentive. There may be a part that is related to some other metric or individual performance but the lion's share if it will be EVA based.

That's great. One more question on trading, if I could Bill and Andrew. When y'all look at the book you did a good job of painting the picture for people. But when you look at the cost benefit of keeping most of the pieces of the book versus selling the book and looking at the investment grade status, which I believe is premised upon selling most of it before the rating agencies would come back around to Williams and upgrade. When you look at I guess Lehman's giving you a fair value, assuming that there is positive value in the book, is there anything else, I guess how is progress going when you talk to parties, I know that you've slowed down your pace in which you're trying to sell it, it sounds like, but could y'all give a little bit of color as to why not just -- if there is positive value and you get some positive value offered for the book, why not just sell the book period, instead of holding on. I guess could you talk about the cost benefit of the cash that you think you could get from it versus the company not having investment grade status partly as a result of continuing to be in this business.

Scott, this is Steve. There's a lot more that we need to do than just do something with the book in order to get to investment grade. We have some time to prudently and patiently negotiate with parties with respect to the book. I believe that it is in our best interest and our shareholders best interest to conduct those patient negotiations. We've seen good results from our efforts thus far in terms of cents on the dollar recovery, and I remain cautiously optimistic about our ability to do more deals like that in the future.

I might just add that it's not all about differences in value either. I think in many cases we have the difference on value is not that great. One of the key differences is just really the structure, ability to get it done. We've got some complex structures in place. It just makes the ability to complete a transaction a little bit more complicated. We have some things like that that we're working through as well.

As we've described in the past, these negotiations are very complex. The fairly simple Jackson EMC deal took about six months to negotiate, and that was a pretty plain vanilla transaction. So I can assure you that we're focused and we continue to have negotiations in that regard.

Okay. I'm sorry for asking one more question, but I promise this the last one. On your asset sales you laid out a time line for that billion dollars of asset sales. Do you have bids on those assets or are those anticipated bids.

Scott, I'd prefer not to go into detail on the status of our negotiations. In some cases we have bids, in some cases we're close to getting a PSA signed. In some cases we're still talking with multiple parties.

Thanks a lot, that's it.

For our next question we go to Jay Yannello with UBS.

I also want to congratulation you on the progress you've made and the outlook. My question pertains to slide 77, we've seen a lot of cuts of what's included and not included in various segment profits and I realize that some of that you have to do for regulatory reasons. You can't show too much excluding nonrecurring items. I'm curious slide 77 which shows the segment profit from power/ERM, what is in those tentative projections, does it include mark to market, does it include gains on selling additional pieces of the book? A little more light on what those numbers are.

Jay, this is Andrew. Those numbers include expected accrual earnings. They do not include an estimate for marked to market earnings, because that would be extremely difficult to come up. They do not include any further anticipated asset sales. But as far as the range, the range is intended to allow for some volatility in mark to market, which will happen, but it does not include an absolute number for mark to market. That's primarily just we would expect to roll through an accrual earnings.

That's clear. The second quarter you quoted a number, a recurring number, which, if I'm reading it correctly included, the company's recurring number I think was 0, and that included mark to market but did not include gains from selling portions of the book. My question is looking to the third quarter, since gas prices dropped let's say 80 cents lower right now from at the end of the second quarter, and you benefited in the second quarter on the mark to market basis from the uplifting gas prices, Andrew, does that suggest that we may see a moderate negative mark if prices don't change from where they are now in the gas price book which could flow through 3q making the recurring number you're quoted possibly negative in the third quarter. How should we just be looking at gas prices and the mark that took place in the second quarter?

I would say that looking at just gas prices obviously is a little dangerous, because you'd need to look at how the spread reacts.

Agreed.

In addition to that, the mark to market does not include just gas and power derivatives. If you recall we've also stated several times it includes changes in interest rate derivatives as well. If you just want to say you had a simplistic example of gas only and gas goes up in price under recording mark to market gains. Yes, correspondingly, assuming those positions have not rolled off in the second quarter you would see corresponding gas losses should those values drop. But it's very dangerous just to assume it's just related to gas. You really need to look at the spread and how that's reacting from anything that we've got unhedged on the power side as well as interest rates. So you'll see some dynamics there looking at gas and interest rates in the third quarter. But simple assumption, yes.

Are you able to capture and hold -- again, I know it's dangerous but just looking at gas for a second, were you able to capture some of that upward value or is it going to flow back and forth.

As far as capturing it, realize these are already OTC or Nymex hedges. The value is already locked in it's just you're seeing the accounting disconnect. It's not a matter of did I have a long speculative gas position that went up in value and now I can go out and hedge it, these are the hedges that already exist. So, from an economic standpoint there's really not a lot of change in value, it's merely the accounting. We do still take short-term opportunities to capture value where it reduces risk or where it mitigates risks, absolutely.

Last question. With interests rates going up here in the third quarter I presume the interest rate swaps are performing better, is that a fair statement?

That's a fair statement.

Thank you.

For our next question we go to Donato Eassey with Royalist Research.

Thank you, Steve, and I appreciate this very thorough update. Don, if I could ask two questions. One deals with the debt schedule on page 30 where you talk about the roughly billion dollars in improvement. But it appears that most of it is associated with the debt attributable to discontinued operations. I was wondering if you could identify which businesses that nearly 900 million is associated with and/or provide some level of confidence that that debt will, in fact, be extinguished as you get out of these assets. The second question deals with the -- on the balance sheet in the 10-Q, the accumulated deficit from last year's 884.3 million went to roughly 1.5 billion dollars. I'm wondering what's making up that accumulated deficit. I'm assume part of it is the charge and that maybe it went into the accumulated other income loss differential there. If you could help me with that, I'd appreciate it. Thank you.

Okay. The first question there, the debt associated with those discontinued operations, principally is the debt associated with Texas Gas of 250 million, and the debt associated with Williams Energy Partners at 570 million for a total of 820 of the 897. That's on page 28. Second part of the question, could you repeat the second question?

Typically on the balance sheet that's in the 10-Q, that was just released today as well, shows that the accumulated deficit within the stockholders equity section went from 884 million at year end to now 1.5 billion of the accumulated deficit. I'm wondering what is the makeup of that accumulated deficit?

Let me ask Gary Belitz, our corporate controller to speak to that.

The primary reason for that is two items. One, if you just look at the net loss for the six months, you'll notice that we have a $760 million item related to our accounting change that occurred in the first quarter. That would have run through accumulated deficit. And then we certainly have items of other comprehensive income that are disclosed in one of our notes to the 10-Qs that reflects the fair value of hedges as they are deferred and going through other comprehensive income. The combination of those two items really represent most of the change in accumulated deficit.

Okay. Thank you. And good luck with the continued restructuring efforts, Steve.

Thank you.

This is Don Chappel. I'm just going to take this opportunity to make a correction of something that we stated, in fact, correction of the slide on the webcast. On slide number 85, I don't know if you can pull that up easily, I'll just give a second to do that, but on slide number 85, we had an incorrect slide on our webcast and I had an incorrect slide, in fact, in front of me, and Travis had the correct one in front of him and pointed out to me we made a mistake. I'd just like to correct that for the record, here. Cash flow from operations for 2004, the range should be 950 million to 1.3 billion, rather than the billion to 1.3. The correct number is 950 million to 1.3 billion. But probably more importantly is the capital spending, the range for 2004 is 600 million to 700 million and the range for 2005 is 700 million to 800 million. Again, Cap Ex for 2004, 6 to 700 million and 2005, 7 to 800 million. I think if you add up the presentations that you walk through with each of the business unit leaders, you would have come to that conclusion. We had some erroneous information on the slide. We'll update the webcast so you've got a corrected slide. I just wanted to point that out to you. With that we'll take our next question.

And for our next question we go to David Maccarrone with Goldman Sachs.

Thank you and thanks very much for the thorough presentation. Andrew I wanted to ask you from the enterprise risk management perspective can you walk through what the commodity price assumptions are across the company and what the cash flow sensitivity is to changes in gas prices, NGL prices and processing spreads, oil prices, interest rates and power prices, if that's possible, for 2004 and 2005.

I'm going to attempt to answer that the best way I can by saying I would say at this point we're probably not in a good position to answer every one of those questions. I would say that obviously the primary sensitivity through '04, there's going to be very little sensitivity to any commodity prices through '04 on an overall basis just because of the fact that the primary drivers of commodity exposure, which will be power and our E&P business are so heavily hedged. Looking at '05, I would say if can give us until the third quarter we will probably be able to publish a much more comprehensive list of commodity exposures and their impact on the overall enterprise, we're just not prepared to publish that today. But I would say that obviously the primary driver is going to be gas, it's going to be because primarily of our long position overall as a company. And if you look at a dollar change in gas prices, it's probably pretty reasonable to expect that if gas prices go up or down a dollar from the forecast you see here today, I think Ralph actually gave you some estimate of what his gas price range was, it was a five-year strip in the 470 to 490 range. You can probably just assume that from a gas perspective that the midstream and EM&T portfolio similarly offset each other. Any change in gas prices on the 70 to 80% of E&P production that is currently unhedged would have a dollar for dollar impact upon cash flows and earnings in that time period at least initially today. I think you can run those pretty easily. Overall we have some exposure to crude and refined products but it's not as material as gas. So I'll just focus on gas. Hopefully that gives you enough meat so that we can bring something back for third quarter as we implement more of our in progress management philosophy.

Anything more you can offer on interest rates as relates to the interest rate swaps that are out there, and also on NGLs given the volatility and the midstream performance.

This is Jim Ivey, I'll talk to the interest rate piece of that. Interest rate really is not a risk that we have to worry too much at all about that. The swaps are a very, very small part of the overall portfolio. The vast majority of our interest rate risk is fixed risk. It's already locked in. In terms of the fixed floating mix it's 90 plus% fixed and will remain so for the next couple of years. And recall that we're also in a de-leveraging mode so we're not really going to be seeking to add a lot of debt at all over the course of the next two years.

And on the NGL side.

In response to the NGL, Allen can add his color as he sees fit. But I think primarily for the next couple of years you see that we probably at an enterprise level have a fairly balanced fuel and strength position. That need can be met either from positions that we may already have on our books or from our E&P production as far as the absolute affects to commodity prices on NGL margins, I think Alan already talked about that, that risk should continue to decline. There is risk, but I think as a total value within his portfolio within Williams, it's not that material, but once again we will try to have more granularity around this for our third quarter.

Then for Doug, on the pipeline side, you had indicated that about 29 million of segment profit relating to the Rockies and Columbia gorge expansions won't be recognized until a rate case is filed. You also indicated that you don't expect to file for rate cases for several years, I believe? Can you reconcile those two? When do you generate a return on those investments?

At this stage we have no requirement on northwest pipeline to file for a rate case. And we will file when our returns dropped below those that we feel we can achieve through a new rate case. We've been more recently performing better than the returns that we could achieve in a rate case. Even when you add these facilities in, we're going to continue -- the cost associated with them, the carrying cost and the depreciation, we're still going to be performing better than we could if we went in for a rate case. We had no incentive to go in. At this stage it's hard to predict but I suspect in a couple years after we got some of these clean air expenditures and other things under our belt, that that may be the driver. At this stage we don't see it happening in the next two or three years.

Given the EVA philosophy going forward, and it sounds like fairly low incremental returns on incremental capital invested, is it likely going forward that you would avoid these types of projects, given that you're not going to get a very good return?

Well, I guess the way to describe this, even though it is an expansion of physical capacity, it falls in the category of something mandatory and that for the last over 15 years, our customers of northwest pipeline have enjoyed the use of some backhaul capacity created by capacity flowing in the other direction. The contractual obligation of those customers to provide that, that create that virtual backhaul capacity ends in November. So we were required to replace this capacity with real physical capacity at this time. So it's a difficult question, but I don't believe we had an alternative. Probably looking forward to it, we didn't know that in this -- that we would be at this stage because of all of our cost reductions and everything, that we would be at a stage where we didn't have to file a rate case. Normally when you contemplate these kinds of things, you would time them to go into service at the time you would file a rate case. But because we've been successful with cost reductions, a rate case isn't required now.

Just finally, what are your earnings on a trailing 12-month basis at northwest relative to an authorized ROE?

There's a FERK earning rate and actual GAAP earning rate, because we keep, for rate purposes, we keep the books a little bit differently. And I would just suggest that perhaps you could look at our separate 10-K for northwest pipeline and be able to calculate what the FERK (phonetic) earning rate is.

Why don't we take a couple of questions from the web. Let's see, this first one is probably for Alan. In the deep water there's substantial opportunities for developing new projects. Have you begun identifying potential projects and the cost?

Sure. I'll kind of break those into two groups. First of all there's a lot of small and marginal fields that are being discovered and developed around the east breaks area, that's ironically in the western gulf and around the boombang and the ensign spars, those prospects primary are being driven by Kerr-McGee and DEVIN. Those continue to come on, they don't require capital, they effectively are just waiting on capacity on both the spar and the pipeline. Our gas pipeline is running at capacity out there already. So there's a lot of small marginal fields like in the 20 million barrel oil equivalent range projects that are coming on out there. In terms of larger projects, a lot of activity and success by producers over in the far eastern part of the deep water, right out along the fold belt and we are looking at a couple of projects there that would feed into our eastern gulf infrastructure, both the devil's tower infrastructure and the mobile bay or canyon station facilities as well. And those projects, the one feed that would feed into devil's tower, that's around 180 to $200 million kind of opportunity. And again, those would be '05 kind of opportunities, not anything we would need to act on immediately. But a lot of demand for the infrastructure and a lot of new projects that we're pretty bullish on for the future.

Here is a question for Don, what assets sales need to be completed in '03 to '05 to facilitate accelerated debt retirement?

I would say if you take a look at slide number 89 that indicated the accelerated debt scenario, that would assume the accelerated scenario there with excess cash would assume that all of those excess assets were sold within the time lines that were previously indicated on the asset sales chart. So I think the answer is really to complete this to the point of 12-31-05, we really need all those asset sales to close. However, as you can see, we have very substantial reductions in debt, and we only have about a billion dollars, a billion dollars plus of asset sales to go. So a lot of this also comes from cash flow from operations, which I think is detailed on page 85.

One last question from the web before we go back to the phone lines. What are the ongoing investigations and when do you expect them to be settled?

Yeah. This is Steve. In line with our goal to resolve as much of the noise around Williams as possible, we talked a little bit about some settlements that we had with FERK and CFTC Probably the major ongoing investigations or unresolved issues relate to the California refund methodology, and the FERK investigation around power manipulation in California. In both of those, we don't believe that we have any significant exposure, any exposure at all. I think the key point is when those are going to be resolved. And that's to a certain extent out of our hands. But our hope is that we'll have those put to bed by the end of the year.

And for our next question we go to Hunter Morgan with Emerit Advisors.

It's actually Jim McFadden. The main question is can you itemize the transaction gains that are baked into your $1.3 to $1.8 billion EBIT guidance?

Just give us a moment to dig that out, and perhaps we'll take the next question and then we'll come back after we've pulled that together.

For our next question we go to Dillon Windem with Temco.

Good morning. I was wondering if you could comment as production begins to ramp up with your increased drilling over the next few years, what that's going to require in collateral you feel to be posted or when your midstream operations become on line in the gulf?

Yeah, this is Andrew. In terms of credit and commodity, obviously any increased production from E&P point of view would only require collateral if we as a company decided within the enterprise risk profile to hedge that. Then that would just be the normal margins that are required either on the Nymex or in our current credit situation that would require a dollar for dollar margin posting for the in the money or out of the money position on that hedge. As far as midstream is concerned, to the best of my knowledge, any long-term projects done out there do not require additional credit collateral to expend that capital.

Okay. And then my second question is I'm not that familiar with the feline tax and the remarketing of those. Does that structure allow you to replace it with another type of structure like a preferred or convert or straight debt issues?

This is Jim Ivey, the short answer to that is no.

Okay. Thank you.

Coming back to the prior question on gains included in actual results, in 2003 we had gains totaling $257 million, which included the Jackson EMC sale for 175, the E&P properties for 82. We had impairments on the actuals totaling 84. In our go-forward forecast, we have forecast gains of about 277 million.

For our next question we go to Curt Launer with Credit Suisse First Boston.

Hi, it's actually Phil -- could you just go back to the $560 million mark to market results and just discuss a little bit the contract terms and collateral associated with that? A second question, separate from the mark to market is just the gas price realization in E&P segment of $3.11 compared to the Nymex, just the reason for the lower gas prices? Thank you.

This is Andrew Sunderman. As far as the mark to market piece of Williams EM&T is concerned, last year if you recall the environment we were in, the second quarter was one where we had a severe collapse in commodity prices, sparks spreads and things of that nature. Our entire book at that time was on a mark to market basis. You've kind of got an apples to oranges comparison. Subsequent to those events, the accounting bodies have required us to go off of mark to market accounting for many of our long dated contracts. The only thing you see now on a mark to market basis are OTC and Nymex derivatives that qualifies as a derivative under accounting rules that we are marketing to market because we do not qualify for hedge accounting treatment because of our planned exit from the business. You really have an apples to oranges comparison. The only thing you have in 2003 that's on mark to market would be gas and power and interest rate derivatives. The cash requirements for collateral in our current credit situation, those vary by counter party and by exchange. But for the most part any in the money economic value we would get cash in and any out of the money economic value we would post cash out. That is not directly tied to the earnings. Those earnings are noncash, because those earnings do not represent the economic value of the particular position, nor the cash value of the particular position. I apologize, but that's probably about as confusing as it can get.

Thanks, Andrew. And a comment on the gas price for second quarter?

Our in sales price before gathering transport, this is Ralph Hill, was 408. If you take off gathering transport of about 57 cents, and then you put this to 350, and then the hedge loss offset by basis gain is about 39 cents off of that, gave us $3.11 price.

Any help going forward how we should take a look at the gas price, or is that basis differential and transportation, something that we should look at as an ongoing piece to the overall realized price.

What we've seen ongoing is about a 75 cent to a dollar total counting the transportation, the hedges up or down, type offset from our gas price. So I think if you -- this time it was about 96 cents, I believe. Last quarter was in probably the 80 to 90 cent range. I'd say between 75 cents and a dollar off the price.

Good, appreciate the additional color. Thank you much.

We go next to Kelly Cringer with Banc of America Securities.

Good morning. Just a few questions surrounding the trading book. On the accrual losses for the quarter were $68 million. Year to date they are $85 million. If you flip back a couple pages it shows that you expected an accrual gain I guess over the next 12 months of $144 million. Can you reconcile that a little bit? It seems like in the first half of the year, you've had accrual losses. If I recollect correctly over, on the past calls, I thought the accrual earnings for the year were supposed to be positive.

Okay. I'll try to do my best to reconcile that for you. This is Andrew Sunderman First I'll point you back to the 10-K from last year where we clearly stated that we expected somewhere around an $80 million cash flow negative for the year. That would coincide with what we had expected at December for accrual earnings or losses for the yeat should all of that cash roll off. Since that time we've continued to obviously liquidate positions. Every time you liquidate a position that obviously affects the timing of those cash flows as well as the accrual earnings. In most cases as we have liquidated for gains and positive cash flows, you could assume that forward cash flows will be reduced, thus forward accrual earnings will be reduced as we sell off pieces of the portfolio. So that's one of the primary drivers for that. Secondly the first quarter and two months of the second quarter are traditionally off peak for where our primary revenue drivers are situated. You typically want high cooling and high heating demand times to make your accrual earnings. So I would expect some of that obviously to turn around, depending on the timing, the August, September, July time frame should be good years. Thirdly, a lot of the forward values that you begin seeing in 2004 and 2005 are because of the ramp up in our southeast portfolio where we have a lot of value coming on line with the remaining Georgia EMC contracts, as well as the California Department of Water contract really begins picking up in those time periods as well. Those are the three primary drivers for why you see accrual losses in the current periods that we've reported versus where we expect to come, it's primarily just because of the nature of the business. Lastly I would add that included in those accrual numbers, we still do have a small piece of a crude and refined products portfolio that we had for the last couple of years and we are getting out of that primarily in our international business. But that business continues to be slightly accrual losing as well. So that does contribute some to the accrual losses. Hopefully that answers your question.

Secondly on the mark to market earnings of $250 million on slide 23, it says that you're, I guess, re-booking, you're going to start to account for those, 218 million of those on an accrual basis rather than mark to market basis. Presumably that mark to market number should have a lot less volatility in it. Is that a reasonable assumption.

No. I think what that footnote is designed to tell you is that included in that 250 million is gains, where the derivative was mark to market and the underlying position it was economically hedging was accrual. It does say as I stated in some of the earlier answers that there is volatility around that number. So just as we saw an increase in earnings in the current price environment with gas prices going up against those positions, if gas prices were to drop significantly you could see degradation in the earnings in the quarter in which those prices went the other way. So it's not a direct correlation in the footnote to what you can expect in earnings, but directionally it's it is same.

Then on the other line, it's a negative of 62 million, you said 20 of that was CFTC. What else is in there?

We've got some other one-time charges for things. If you just will hold on a second and let me pull on some information here we'll go on to another question and we'll get back to you with the answers on that.

I have another one regarding your working capital. Looked like second quarter working capital, away from the trading book, just kind of inventory, receivables, payables, that sort of thing, was a pretty significant positive, back of the envelope had 5 or 600 million dollars. Was there anything unusual going on in that part of the cash flow?

This is Gary Belitz. No, there's nothing unusual going in there. You're seeing a continuing emphasis in our working capital area and maximizing working capital ratios.

Okay. Presumably going forward, is that going to continue -- do you expect to continue to get cash out of there.

This is Don Chappel. I think just generally we believe that EVA and the EVA incentive system will drive the kind of behavior that will pull cash out of the business and return it for other purposes.

Okay. Don, one follow-up on the commentary you had regarding the debt reduction with excess cash, you show a big, a billion five of debt reduction with excess cash through the end of this year. I know you said it was somewhat dependent on getting that billion dollars of assets done. Can you give us any sense of what kind of -- how you would accomplish that. I know most of the upstanding debt you have are bonds. Did that imply you intend to be in the market to re-purchase some bonds in the near future?

Well, the most obvious place we can accelerate debt retirement -- this is Jim Ivey. The most obvious place to accelerate debt retirement would be to take the billion four that matures next March out early. In addition we have some debt that's pre-payable with no penalty. In addition to that we could certainly consider tender or open market re-purchase. We haven't said exactly how we intend to do it and it's too early to say exactly how we intend to do it. That would give you some indication of the sorts of things we're looking at.

Okay. Thank you guys.

We go next to Anatol Feygin with JP Morgan.

God afternoon, everyone. A question for Andrew. Trying to reconcile the fair value of mark to market derivatives. At the end of the first quarter it was positive 475 and now it looks like it's negative 50. And reconciled along a couple dimensions, one, the expected cash flows year by year, which are substantially positive obviously adding up to the billion five in the presentation and two to the mark to market gain that was reported intraquarter since both of these quarter end numbers are under EITF ' 02 ' 03, I'm just trying to figure out what the moving pieces were.

Let me look at your 10-Q and let me get back to you with the answer on that as I digest what you just asked. I'll get back to you in just a second.

And for our next question we go to Jeff Dietert with Simons.

Jeff Dietert with Simmons and Company. I've got a question for Alan on page 49. You talked about your commodity based exposure. I was wondering if you could break down within the commodity based exposure your key poll and proceeds exposure, what's exposed primarily to natural gas and what's exposed to liquids pricing relative to natural gas.

Thanks, Jeff. I'll try to hit that for you best I can. That has several elements in it. In the current state it also has some Canadian processing, which has exposure just to natural gas and power prices, because our shrink is provided for by the purchasers. But it does have just raw exposure to natural gas price on some of that. That's probably about, in the current state that's probably about 15% of that 20% slice. And then moving into '05, that's probably about zero, or it is zero that's in there. There's also about 15 to 20% of that that is olefins, so that is an ethane to ethylene spread for the most part that stays steady throughout the period. The balance of that, about 60% that is left there, about 50% keep hole, gas to liquid that's exposed and about 50% that is driven by the price of natural gas liquid. So it's % of liquids. And some of that, though, some of that keep hole and some of that liquids exposed has a floor on it now in the gulf coast where we're receiving basically treating fees when processing is uneconomic. So I hope that answer your question.

Yeah, thank you. Good presentation today. Good luck, guys.

This is Andrew, I had two questions I said I would follow up on. The first question relates to what's in the 60 million of other for energy marketing and trading. I referenced primarily the CFTC settlement, there is a whole list of other little things potential liability, accruals, just some true up of estimates, thing of that nature. Most of them are in the 2 to $6 million range. The only one I think that probably is noteworthy is that everyone is aware that we did settle a dispute with AEP. That did involve a small write down of the exposure we had on our books to the $90 million that they paid us, and that number was about $7 million of the remaining difference. There's no other significant major item of note in those -- in the difference between the 20 and the 60. As it relates to the change in what we are disclosing in our 10-Q, page 48 of the 10-Q and the copy I'm looking at, it is kind of an apples to oranges. In the first quarter, it's really a definitional issue. In the first quarter we called all derivative contracts trading. And what we have done in this second quarter is we have narrowed that definition, and it is referenced in the paragraph above the chart. It says that the table below includes only those contracts that do not hedge or mitigate EM&T and or other Williams owned assets risk but were entered into strictly for helping third parties manage their commodity price exposure. So I think it's really a difference in definition as to why you see the change from 475 to negative 50. But anything included in that would show mark to market gains in the second quarter that I've already referenced on those specific contracts, and on that much further defined set of contracts that we're now calling trading. And what I will try to do is Ill try to get to Travis some sort of a reconciliation of the two schedules to kind of show you what was pulled out.

For our next question we go to Jay Yannello with UBS with a follow-up question.

Just a quick follow up question because there have been changing dynamics with the guidance. Slide 64 E&P, segment profit outlook 2004 and 2005, there's no footnote there. Am I correct to assume that does not include the gains on selling properties?

2004, 2005 outlook, we are not selling any properties, so there are no gains.

Even incidental properties, no gains in that.

Right no gains, that's straight profit.

Okay. And going back, Andrew, really quickly to slide 77, you answered this substantially to a prior question. The increase in earnings, the various guidance for '03, '04, '05 in EM&T, that's your best projection right now for the various accrual movements and without assuming any big swings in mark to market going forward. Is that correct?

That is correct.

Thank you.

Also with a follow up question we return to Kelly Cringer with Banc of America Securities.

Hi, just a couple other questions. First on the production business, it looks like you're full year production relative to your first half is down. I'm presuming that's asset sales, asset sale related. Can you just kind of quantify or specify how much of the assets in the first half, or how much production in the first half was a result of assets you've subsequently sold?

Well, looking from last year to this year, we've sold I believe about 148 million cubic feet a day on a quarter to quarter difference basis, and our production declined about 59 million a day. So production wasn't down near as much as we actually sold, if that helps.

Okay. I guess I thought most of the asset sales had closed by the end of March, so I thought there would be a bigger impact on second quarter production. And it looks like the impact is more on third and fourth quarter production. Was I wrong in my assumption those had closed by March 31st? Or at least had an effective date of March 31st?

The biggest closing was the XTO and that was closed May 30th. I think effective dates were April and May 1, for those two.

Secondly on the guidance, I know in the past you've -- the guidance that you've presented today is similar to the guidance you've presented in the past for '03, or significantly the same. Are the assumptions for the asset sales and the impairments that you have now, is that pretty consistent with what you had previously expected?

This is Don Chappel. I think we certainly came across some impairments during the second quarter that we hadn't previously forecast. We don't forecast impairments. We didn't anticipate those. So those would be new. I think other than that, I think the assumptions are the same.

Okay. So the asset sales that you've announced and expect so far this year and for the rest of this year are consistent with what you had expected previously in your guidance?

I think more or less, yes.

Okay. Thank you.

I think that's all the questions that we had on the phones. We do have a couple that came in on the web that we'll catch up on, then we'll turn it back to Steve just to finish up. First one, both of these I think are to Don. First one is, are the proceeds from the Jackson EMC sale included in the cash flow from continued operations?

The answer to that is yes. I think we have that detailed. I'll have to find the chart number here, Travis. What's your next question?

All right. The last question that we've got is, is it possible to break out the amount of equity earnings tha are included in the segment earnings and EBITDA guidance, and what are your expectations for dividends from equity investments incorporated and operating cash guidance?

Okay. In terms of equity earnings included in segment earnings in EBITDA for 2003, we're looking at about $15 million. In '04, $35 million, and '05, $66 million, and from a dividend perspective, we're anticipating dividends of just short of $3 million in '03 and we had no forecast in '04 and '05.

Okay. This is Steve. I think that's all the time we have for questions. I think that's all the questions we've had. Appreciate your interest. Good questions. We're excited about the future, and we look forward to talking to you next time. Thanks a lot.

Ladies and gentlemen, this does conclude the Williams company analyst conference call. We do appreciate your participation and you may disconnect at this time