威廉斯 (WMB) 2002 Q4 法說會逐字稿

For those participating in the Webcast, you can submit your questions by clicking on the ask the question button on the Web site. For those listening in on the audiocast, you will be given instructions on how to submit questions. Today's call will include forward-looking statements so please refer to the forward-looking statement information in this presentation and what's posted on Williams.com for further detail on the risk factors impacting Williams. So with that, let me turn it over to Steve Malcolm, our chairman, president, and Chief Executive Officer. Steve?

Thank you, Travis, welcome, and thank everyone for your continuing interest in Williams. We have the entire Williams senior management team assembled here in Tulsa. Some of them will be participating in the presentation. Others will be available for our Q&A session. This first slide sort of runs through our agenda for the day. Obviously, we will be talking about 2002 results, but then I think the meat of our presentation today will talk about 2003 and beyond.

We'll be providing guidance for 2003, discuss the commercial and financial strategies going forward. We'll provide considerable detail in terms of our liquidity management strategy over the next two years. Then the business unit leaders will address their respective businesses. Then I'll come back, talk about 2004 and beyond, steps that we're taking to create shareholder value, the fact that we believe very strongly that our plan is a comprehensive response to the challenges that we face today. We'll give you an outlook given that we have just completed a three-year strategic plan. We'll give you an outlook over the 2003-2005 time plan regarding certain metrics and then we will get into Q&A.

We have about 70 slides in our presentation, but I think we can get through these in a couple hours, so that should leave us plenty of time for questions. I'm going to quickly run through the overall 2002 results. This first slide, of course, we are announcing today a 2002 net loss of $736 million or $1.60 a share, compared with restated loss of 478 million, or 95 cents per share for the same period last year. Consistent with previous guidance, the company's core asset businesses continued to perform well in 2002. Achieving about $1.4 billion in recurring segment profit from these businesses compared with about $983 million in 2001, and this gives you a breakout of E&P, mid stream and gas pipe line on a recurring and reported basis.

There are other major factors that impacted the 2002 performance. Recurring segment loss in EMT of $353 million for the year, but fourth quarter results were significantly improved from the previous two quarters and, in fact, we were positive by $81 million during the quarter. In terms of non-recurring items, we did have Telecom related writedown of WCG receivables in the first, second, and fourth quarters during 2002 and impairments associated with gains and losses for assets sold or held for sale were $469 million for the year. We also reported recurring and net loss from continued operations for the year of approximately $84 million, or 16 cents a share, and fourth quarter earnings were $99 million, or about 19 cents a share.

I believe that these numbers are better than the Street estimates. Couple points to make on this slide, which provides information with respect to 2002 cash. You'll note that cash flow from operations in the fourth quarter of $845 million was positive and strong, we believe, and certainly covered our capital expenditures of $498 million during the quarter. If you also note, we had debt repayments during the fourth quarter of just over a billion dollars. Asset sales of about 650 million ended up the year in the quarter with a strong cash position of in excess of $1.7 billion.

You'll note that we have reflected debt proceeds here of $485 million in the fourth quarter. That is really WEG debt which we reflect here because we consolidate Williams and energy partners. Progress was made in 2002 on a variety of key issues. Even during a very challenging 2002 with respect to liquidity and balance sheet issues. We did sell $5.2 billion in assets. We have another $1.1 billion in sales that we're pursuing today. I think we enhanced our cash management process during the year with respect to EM&T. The team worked hard and was very pleased with the settlement that we achieved in California. Bill Hobbs will describe for you some of the specific steps we have taken to reduce our portfolio risks and liquidity requirements associated with that business, and we reduced our work force by about 62 percent.

We continued to be aggressive in terms of cost reductions company wide, and when you compare fourth quarter 2002 with fourth quarter 2001, we've cut quarterly SG&A by $66 million, and a good part of that is the fact that we have reduced the work force by about 25 percent during the year down to a little over 9,000 employees by February 14th, 2003, and importantly, our core businesses continue to perform very well during the year. That completes a quick overview of 2002. I'd like now to focus on 2003-2004 and just to highlight the agenda and how we'll break up that discussion. First, we will discuss our commercial and financial strategy going forward.

The strategy being the result of an extended review of the various options that we had available to us to restructure the company and clearly, the strategy that we'll be talking about focuses on our core businesses. I believe our plan over the next 18 to 24 months is a comprehensive response to the events which have impacted the integrated energy sector since the Enron meltdown. So we will provide guidance for 2003 by business unit on a consolidated basis. We'll provide details on our liquidity management plan for the next two years, and I truly believe that you will agree that we have developed a clear, straight-forward plan, a plan that's certainly very achievable and one that adds our challenges over the next couple of years.

After considerable discussion and debate by our senior management team, as well as our board, we have agreed on a strategy, which I believe defines Williams as a balanced, integrated natural gas company with world-class assets in E&P, gas pipes and midstream. Essentially, we want to focus on our strongest, most attractive assets in each of our core businesses. And so in terms of our commercial strategy going forward, we will be all about owning and managing natural gas assets in key growth markets where we enjoy competitive advantages of scale, of being a low-cost service provider and a market leader.

Importantly, going along with that commercial strategy, we have -- going along with that commercial strategy, we have a financial strategy, which is complimentary, and we obviously need to create and maintain adequate liquidity from all available sources to fully support that business strategy. We need to deleverage the company through a combination of asset sales, refinancings, and cost cutting, and we need to develop a balance sheet capable of supporting and ultimately growing our high return assets.

Obviously, we are a different company today than we were a year ago, and we are managing our company much differently. We have embraced a more conservative and disciplined financial paradigm, and so we are pro-actively managing cash of we are reducing our costs while employing a more disciplined capital allocation plan, and we are utilizing more balanced financial performance metrics, and we'll be looking at cash and returns on investments and earnings.

The business unit positioning within the Williams portfolio is shown on this slide, and this positioning will be highlighted by each of the business unit leaders in their respective presentations, but essentially, exploration and production will be generating free cash flow over the next three years and will be our primary growth segment, midstream gas and liquids also generates free cash flow, but we'll be decreasing volatility over time as more of the business becomes fee-based and more of the business is associated with some of our deep water projects.

Gas pipe lines generates substantial free cash flow particularly in the 2004-2005 timeframe and with respect to energy marketing and trading, our focus will be to continue to reduce risks, limit liquidity requirements and preserve the portfolio value until a sale is completed. So now 2003 guidance, as I mentioned, we will provide this on a business unit basis that will look at it on a consolidated basis, and then we'll get into our liquidity management game plan. In terms of 2003 guidance by business unit, this slide separates that out in exploration production, segment profit between 300 and $400 million for 2003, midstream between 2 and 300 million, gas pipes between 5 and 600 million.

Energy marketing and trading, 200 to 350. Other, and other here is WEG, petroleum services, and other corporate entities that ranges between 100 and $150 million. Our core natural gas businesses obviously continue to be very healthy. On a consolidated basis, segment profit that we expect recurring segment profit of between 1.3 and 1.8 billion dollars during the year. Cash flow from operations, 800 to 1.5 billion. Net income for 2003, estimated at 250 and 400 million resulting in estimated earnings per share of between 40 and 75 cents. You'll note the footnote on this page regarding the cumulative affect associated with the change in accounting principal.

We expect to record an after-tax charge of approximately 750 to $800 million in the first quarter of 2003, for the adoption of new accounting rules under EITF 0203. A substantial portion of the energy marketing and trading activities previously reported on a fair value basis will now be reflected under the accrual method of accounting, and that's shown on this next slide, which shows the one-time, non-cash accounting charge, which does not change in any way the value of the portfolio, but as I said earlier, that charge will be taken in the first quarter. And so including the cumulative effect of this accounting charge, the company expects a 203 loss, -- 2003 loss of between 70 cents and $1.10 per share.

That was slide number 19. I think pen asked for me to review with you periodically which slide we were on. That was slide number 19. Moving on to slide number 20, I think this is probably one of the most important slides that we have discussed. This is our liquidity management summary over the next two years, and let me take -- focus on 2003 first. Cash of 1.7 billion. Cash flow from operations, and you'll recall from the previous slide cash flow from operations was in the 800 billion 50 range, we're talking -- we're using here cash flow from operations number of $900 million, which obviously is about expenditures about billion dollars. I know this is higher than we have previously indicated.

We have aggressively scrubbed our capital for the year. The fact is that we simply have mandatory projects. We have projects that we are already moving ahead on in terms of construction. We have a contractual obligation and cannot walk away from. Importantly, I can assure you that we have scrubbed these to the greatest extent possible, and this represents our best guess of capital expenditure for the year. I think importantly and as we'll talk more, as we get further along in the presentation, capital expenditures will drop dramatically in '04 and '05 as the projects that we had previously committed to do as the lag time associated with many of the mid-stream and projects mass passes, we will be in a much better position to control expenditures that we need to in the future.

Margins associated with hedges, 350 million dollars. I believe, I don't believe. I know that there are details on the Web site, so if you want details on that, those are available on our Web site. $500 million associated with cash collateralizations of our LC facilities. Announced asset sales of $1.7 billion. I'll talk more about those with the slide in a minute. Additional asset sales that we have announced today, and I will be discussing those, as well, of $2 billion. And potential additional financings during the year of approximately $750 million, leaving us with ending cash of $2.8 billion in 2003.

A couple points to make on 2004, again, starting the year $2.8 billion cash, capital expenditures down dramatically to $500 million, debt repayments, $1.6 billion. Cash, ending cash 1.65 billion dollars. As you all are well aware, there are two major liquidity events during 2003 and 2004, and at the bottom of the slide, we showed the cash position at August 1st, 2003, after repayment of the Rocky Mountain loan cash between 1.8 billion and 2.4 billion and total cash at April 1, 2004, after the WCG debt repayment repayment cash of 300 million and $1.1 billion.

I think another point I want to make here is that essentially, we are finished with asset sales by the end of 2003. There is 250 million that shows up in 2004, but when you look at the asset sales that we have achieved, that we did achieve in 2002, that we intend to achieve in 2003, that work and that effort is essentially behind us by the end of 2003. Looking at the sales that we -- we're pursuing or have successfully entered into contracts. Gross values, that includes about $1.7 billion in cash.

The difference is associated with debt, $68 million and -- excuse me. Associated with our Canadian midstream assets. You'll note that we have detail on this slide, closing is the Memphis refinery for March 3rd, 2003. And travel centers, February 27th, 2003. And today, we did announce the sale of ethanol and the closing is expected on those assets in the second quarter of 2003. We continue to make progress with respect to the other assets shown on this slide, and I am confident that we will be able to sell these at good value over the next couple months. The liquidity solution that we have foreshadowed for you with some of the previous slides, I believe, is very straight forward.

We're all about creating liquidity by selling additional assets that I believe are fully valued in the marketplace. In addition, we will be attempting to tap additional sources of liquidity, and these are associated with potentially issuing subsidiary debt, selling additional EM&T positions, like we did in the Hoosier transaction, which frees up cash and letters of credit, and we will continue to be relentless in our efforts to cut costs. We announced today four new major divestitures. First, the general partner and limited partner interests in WEG. The thirdly, identify properties in E&P and identified assets in midstream, let me just give you a little better flavor for the assets that we intend sale in E&P and midstream. Within E&P, we're talking about reserves situated in the retone basin, Brundage basin, and certain non-operated, non-trust interests in the San Juan basin. These properties were selected for sale because they are from basins where we have minor positions and these sales permit us to retain our strategic positions in the core basins of , Powder River, San Juan and . With respect to midstream, given the recent sale of map and Seminole to enterprise, the equity positions that we have in Rio Grande, and west Texas pipeline are really no longer strategic to us, as well dry trail, which is the last remaining asset in this declining basin, South Texas, which is part two of the sale of properties to Embridge.

Canyon station in North High Island are other assets that we will be selling in the mid stream areas. You'll note the last bullet obviously, we always want to stress that the resolution of EM&T would obviously provide additional liquidity for the company. I think, importantly, significant work has already occurred relative to these sales. In many cases, data rooms have already been opened, negotiations have been conducted, investment bankers have been retained, bids have been received in some cases. As I've said before, we have demonstrated that we are good at selling assets and I believe that we will be successful in selling these assets reflected on this slide and receive good value.

Let me give you my perspective on when we're going to sell these assets, and if you look at the $1.7 billion of assets that we had previously been working on, add to that the 2 billion that we intend to sell in 2003, talking about now about the new asset sales that we've announced today, that's a total of $3.7 billion. By the end of the first quarter, we will have closed on $750 million of that total. By the end of the second quarter, given that there are several large assets included, I believe that we will have closed on an additional $2.5 billion of asset sales, and by the fourth quarter, another $500 million of asset sales.

That's all the detail we're going to give you today because obviously, it's not prudent for us to tell you which assets we're going to sell by when and for how much because we're negotiating with those -- with counter-parties as we speak, but that gives you an idea of how I see a selling that $3.7 billion in assets over the next ten months. While clearly, and I can't stress this enough, while clearly one of our major financial goals is to delever the company over time, particularly beginning in 2004 after the March maturity has been satisfied. In the interim, the company is pursuing opportunistic financings to stack liquidity pending asset divestitures. One the divestitures are completed, the company can proceed to rapidly delever the company and I think evidence of that is the fact that, again, as we've looked at the next three years, year-end 2002, we had about $14 million of debt.

We see that number falling below $10 billion, and approaching 9 billion by 2005. We've announced today, and I'm sure you picked it up that northwest pipe is planning $150 million offerings of senior notes. Primarily using those proceeds for funding capital expenditures, but that's just one example of gas pipe line financings, and we will be considering, and as well, I believe that we have an opportunity to refinance the rocky mountain reserves. As I mentioned, cost cutting is important. We've made good progress as shown on this slide.

But we need to do more, and we will do more, as additional assets are sold over time, but the team is generally pleased with the progress that we made to date, but also recognize that we can't stop here. So to summarize, what we will be all about over the next 15 to 24 months, from a financial stand point, we are executing the liquidity management plan, which will allow us to delever the company over time. We will be aggressive in terms of pursuing cost reductions. While at the same time, we are retaining sufficient, attractive assets to support long-term earnings and debt repayment, and in terms of EM&T, we will continue to reduce risks, limit liquidity requirements and preserve the portfolio value until a sale is completed. That is a quick overview of really our 2003-2004 plan. We're now going to go into presentations by the business unit leaders, and I think it's appropriate for us to start with marketing and trading.

I think there are many questions that still remain with respect to where we are, and obviously, we continue active negotiations to resolve our exposure to EM&T, and we continue to pursue JV opportunities and sales prospects. But, clearly, progress in terms of resolution is not -- has not been what I had hoped. Bill will describe for you the progress that we have made in reducing the impact. We've reduced earnings volatility. We've cut expenses. Bill will describe the steps that we've taken.

Progress continues to be made in terms of ring fencing this business and its impact on Williams, and I continue to be very optimistic in our ability to do so. But we haven't sold the book, the portfolio yet. Therefore, I believe it's prudent for Bill to discuss how we will manage this business until we are able to ring fence the liabilities and the earnings volatility associated with that business. So with that, I'm going to turn it over to Bill to run through marketing and training.

Thanks, Steve. As the overall marketplace continued to melt down throughout the early part of next year, we realize it was Tim to reduce Williams exposure to the energy risk management business. So we dedicated a team of people under Phil rid to establish a data room that would allow interested parties to look at pieces of our portfolio. We initiated joint venture discussions. We took immediate steps to close our London office. We began to exit specific trading positions, and we moved quickly to reduce the size of our work force.

A major hurdle that needed to be overcome was to resolve the outstanding issues with the state of California and in December, as Steve indicated, we favorably settled those issues for the most part, which has allowed us to attract interested purchasers for that portion of our portfolio. Another major issue with the EM&T business has been the volatility of our earnings as a result of our lost credit. The step we took through the second half of last year to eliminate speculative trading and new origination efforts resulted in dramatically reduced earnings volatility. These steps combined with the adoption of EITF '02-'03 results in our daily earning at risk dropping from a high of 93 million to 22 million currently. We cut cap ex down to virtually nothing going forward, and as Steve indicated earlier, we have reduced our work force from 900 employees to its current level of 340 and reduced annual SG&A expenses from a high of 335 million to its current level of 119 million. I expect further reductions in both work force and SG&A as we streamline processes and sell additional pieces of our book over the next 90 days.

And finally, our percentage of the total company's earnings have dropped from a high of more than 50 percent to 15 percent in 2003. So as you can clearly see and as promised, we have taken significant steps to dramatically reduce EM&T's presence as part of the overall Williams' business mix. Turning our attention to what we'll be doing in 2003, we clearly remain focused on pursuing sales that realize that $1.6 billion in portfolio value. We are in advance discussions with a financially strong counterparty to sell our JV a significant portion of our portfolio. We are also pursuing sales of individual pieces of our portfolio, such as we did with Hoosier, and in fact, have reached an agreement in principle to reach a sizable position at ease that we expect to announce within the upcoming week.

Moreover, whereas at the end of last year, we had little interest in our west position, we are in active discussions with several counter-parties. We have also liberated over $50 million of trading positions with counter-parties for over 90 cents on the dollar. All of these alternatives are relatively complex and as Steve said, takes time. But if successful, Williams will capture the vast majority of the value of its portfolio. But as we pursue these sales, we still have contractual commitments to honor. A remaining power portfolio of 10,000 megawatts represents a healthy balance between telling arrangements and full requirement transaction. In addition, the natural gas needs of our power business reach a peak day demand of 1 pcf a day. We will continue to market 600 million a day of equity gas and manage related transportation and storage agreements. We will also continue to handle the hedging of our equity gas, and the gas supply needs for our western power position do provide a great outlet for our production.

We will continue to purchase 700 million a day of natural gas from producers for our process plans, and also as it further limits marketing activities for affiliated markets under order 497, it is logical that we take steps to exit the jurisdictional Transco FF business. We expect to complete that by this summer, and as we exit positions, we will continue to right size the organization. In summary, our focus remains to sell our portfolio to create shareholder value. We will no longer be engaged in speculative trading and our origination efforts are now focused on portfolio sales and risk-reducing deals.

We will be an asset-based marketer ensuring that we're preserving the value of our power positions while maximizing commodity opportunities for our E&P and midstream businesses. And we're now on slide 31. We certainly recognize the risks that remain that must be managed. As Steve highlighted in our earlier slide for 2003, we currently have hedges in both our power and our E&P businesses that represent a total liquidity requirement of 350 million based on a 95 percent confidence level. The good news is that the correlation between the power hedges and the E&P hedges reduce our total liquidity requirements by 150 million, due to their natural offsets.

Also embedded in total liquidity number are possible margining requirements against our interest rate hedges. As far as sensitivities are concerned, a dollar increase in gas prices represents approximately 150 million of additional margin costs. Likewise, the basis point drop in interest rates represent approximately 360,000 of additional margin cost costs, and although we view it as unlikely, we may have to post additional credit support if our situation worsens. However, we anticipate that number being no greater than 35 million based on discussions with our customer. Since we've been clear about our intent to exit or dramatically reduce the scope of our business, it is becoming increasingly difficult to retain people. It is a testament to the team we've built that people are being aggressively recruited, but I remain confident in our ability to retain a fully capable work force to manage our contractual commitments. And while we have been successful in resolving much of our litigation, we're still actively dealing with ongoing lawsuits and investigations. Bottom line, we clearly understand our risks and are actively managing them. Steve also wanted me to give you a brief update on EITF '02-'03. First, let's be clear this is purely an accounting change and in no way impacts the value of our portfolio.

We will adopt it effective January 1st and expect the after-tax impact to be between 750 and 800 million as Steve indicated. A positive outcome of the accounting change will be a shift to accrual accounting for a major portion of our portfolio, which is, as I indicated earlier, will have a dampening impact on earnings volatility. However, we will be required to account for interest rate positions and any ineffectiveness of hedges using mark-to-market accounting. We reduced the scope of this business. Our hedge positions reduced liquidity requirements for the next two years. Our west power position does provide a good outlet for equity gas production, and although there is a risk of additional credit support, we view it as unlikely. Higher interest rates increase earnings in cash and we have dramatically reduced the volatility of our earnings. With that, I will turn it over to Ralph.

Thank you, Bill. Today, I will discuss with you key metrics of expiration production. I would like to reemphasize that our expertise remains in basin centered type end gas and coal methane production, and then we have a long-term portfolio which consists exclusively of low risk development drilling that keeps going and going and will provide very high returns that we are in gas saturated areas, that we will develop gas and we will find gas in our core basins, and finally that we are a production company with no real expiration required for to us grow.

Turning now to slide 35, key metrics for expiration production, year 2002, our year-end reserve report shows 2.8 trillion cubic feet of approved reserves and in 2002, as you know, we sold 470 bcf of reserves. We produced 211 bcf, and despite those subtractions from our 3.2 tcf year-end 2001 reserve base, we still ended with a 2.8 trillion cubic feet reserve base. With over 550 million cubic feet a day and to stress, we sold 166 million cubic feet in 2002, but our 550 million cubic feet of current production. We have a reserve replacement rate. We pride ourselves on being low-cost operators. Our 36 cents per lease operating expense we believe is definitely in the top of the upper quartile. We believe the industry average is 50 to 55 cents on lease operating expense. Our three-year finding development costs for xpf for projection, we believe the average industry range is $1.20 per mcf. I would like to stress that we drilled 1,077 wells in 2002 with a 99 percent success rate.

We had 16 unsuccessful wells out of 1,357 for 99 percent success rate, and operating exclusive with the profits that we told was $539 million in the year 2002. We believe we are positioned for growth, and we have a leadership position in the rocky basin. Our key basins are the , San Juan, Powder River and the Key Bay in coal methane. Each of those uses our type gas development and coal methane development. I think it's important to stress that our approved reserves are undeveloped and that we have a significant probable reserves inventory. We believe our lower-risk potential and our key basins can more than double our approved reserves. We also have a 10-year plus low-risk high return development drilling inventory and a normal capital, typical capital environment which for us will be 250 to $300 million of expenditures. We expect we can grow 10 to 15 percent production.

We also think with this normal capital budget, even without that, we will be self-funding and den generate free cash flow, with cap ex of $300 million, we would generate $200 million and we think this level will continue to increase year over year as our compounding intersect happens with our drilling programs. Looking at slide 37, hedging and pricing strategy in 2003 and '04, we are hedged 85 percent above and our price is above $4 in NYMEX. Our future strategy level will be a function of our Williams portfolio. We have a natural hedge with midstream.

We have an offset to the power book. Those things need to be taken into account. Historical hedging ranges we had are between 40 to 85 percent, and I think it's important to stress that even though we are a Rockies producer, we're not necessarily a rocky's price taker. We have transportation to the mid continent for all of our powder river through the trail basin, so it's priced at mid continent and we have the mid-con through through Trailblazer and transColorado. We have a long-term Rockies basin hedge for production that is not moving under this firm transportation. And it is set up to continue to walk to work through firm transportation as our volumes grow in our various basins.

Looking at our approved year-end reserves, the key here is that the peon and San Juan and powder makes up the lion's share of our existing reserves on our approved basis and probable. Approved reserves we would sell this year is about 14 to 16 percent, and if you look at probable basis, our reserves sold this year will be slightly less than 10 percent. So we maintained the upside that we have in this portfolio. This next graph on slide 39, this assumes, this is not our actual production for 2002 and '03, but this graph would assume what would happen if all of the asset sales already occurred. Recognize again that our actual 2002 and 2003 production was higher 2002 and will be slightly higher in 2003 because we will only own properties for part of the respective years.

The part of this graph is our retained properties which may decline slightly this year as the graph shows, although I think it will be actually gross closer to flat, exhibit strong growth in 2004 and '05 and beyond this peer as we ramp our drilling program back to the normal levels which, again is back to $250 to $300 million capital level. We can grow at a robust rate and still spinoff free cash flow as this slide displays from the cash flow from ops versus capital. Our free cash flow average is over $200 million a year.

We expect as a compounding affects of normal '03 and take affect, our capital will level off as I mention $250 to $300 million range and our free cash flow is continued to increase. Looking at the basin, for the next four slides, I won't go into the detail, but I hope it will help each of you model our portfolio. Please focus on what happens in each of the next four slides. The high returns are generated by low-risk drilling portfolio in the core remaining basis. Economics are based on 20 years and actually our wells are produced for 20 years. To give us a few facts about the in 2002, our production increased 37 percent to a record operating volume of 220 million cubic feet on a gross basis. We drilled 129 wells and after this year, we expect to continue our robust drilling program in this prolific high return base basin. Many upsides are in our portfolio and I will highlight . In the , we have upside in 10-acre spacing.

We begun this process to get approval for initial application on 3000,000 acres out of the 190,000. We expect bcf recovery out of this 10-acre, 600 bcf in reserves to be added to our portfolio when the approval of the first application of 11,000 acres per 10-acre basin is approved. This is the first in the series of a number of steps are increased in the application of the . A key point in the 10-acre application as we did with the 20-acre applications is that we can access these resources without any new surface location disturbance. Therefore, we won't be disturbing the location. We will be utilizing the existing locations, which I think is key to development in this basin.

On slides 42, it shows the typical big George well. Our after-tax returns on this one is 58 percent on a $4 NYMEX price. Most of our future development will be in big George coals. We're encouraged and we drilled 22 big George wells and we had 227 cubic feet production from the wells which is 20 percent of our total powder river production of 330 million cubic feet today. About 12 percent of the powder river drills have been drilled in the big George so about 491 wells out of our drilling of 4,000 wells right now, but we're showing the big George. That is where the growth will be for us. In the powder, we drilled a total of 139 wells in 2002. Our production increased 39 percent to a gross operating historical high production of 320 million cubic feet a day. In 2003 and beyond, we will continue developing at these levels in this area, equal to the 2002 levels, and another long-term play for us.

San Juan basin, typical San Juan well for coal. In 2002, we participated in 119 wells total, our production increased 11 percent. For the coal-produced gas and our gas is immediately produced versus a dewatering period because a number of this area has been on 320-acre spacing for many years so our dewatering occurs quicker here as the graph shows on this. And we expect to receive approval out of the 160s in what's called the fareway area and we expect it will be approved on 160s when the operator requests approval. Quite a bit of upside for us in San Juan. In the basin we drilled 51 wells in 2002. We had 22 cubic feet a day. This is much more like a tight sand. Very little water. Characteristics of this particular coal. Again, like most of our basins, very attractive, low-risk, high return development in drilling. We have after-tax returns of 41 percent. And I hope and encourage each of you to look at all the data on this and we can talk about that in separate meetings about the portfolio. In summary, for us, we believe we are -- we will be self-funding, primary growth segment for Williams. We can drill 1,400 wells a year in a normal capital expenditure level of 250 to 300. We expect to have a 99 percent success rate, similar to what we have this year. Our portfolio will not change. We expect to achieve these kinds of results. We expect to have average annual production growth of 10 to 15 percent and free cash flow generator. We're also believed that we have a premier long-term, low-risk high-return development program in the portfolio going forward. Now, I will turn it over to Alan Armstrong, senior vice president of mid stream who did an excellent job of developing large-scale positions in key-producing basins. Thanks.

Thanks, Ralph. I'm going to talk this morning about the scale that we developed in the basins that we have and the kind of operational help that that's brought us and then finally, the free cash flow that that's developed for us. The basins that we're in, first of all, starting in Wyoming. I'm going to describe the scale. In general, we have in these basins. In Wyoming, we produce 50 percent of the coming out of Wyoming and in the San Juan basin, we are the number one gatherer in that basin and gather approximately 38 percent of the volumes in that basin. In the Gulf coast area, we've grown to a position of in the deep water of 25 percent from 4 percent in 1998 to now 25 percent in 2003. And we gather about a third of the volumes in the western Gulf Mexico.

Even in Venezuela today, we operate the gas injection facilities that are lifting about 700,000 barrels of oil a day for . That is currently over 50 percent of the oil production coming out of Venezuela and under normal circumstances, that's 25 percent. The good news in Venezuela is that we are getting paid at because we are critical pieces of infrastructure there now. In spite of all the changes that we this year, our focus has prevailed and that is really paying off in a big way, and I'm going to show you the stats that show how it goes. On the cash flow, we had drastic improvement there and we had strong incremental return coming out of the scale in return and not for operating profit. This is just a snapshot that shows the scale that we do have and in the various basins and how that breaks out. I think it's important to note here that even though we do have great scale in these basins, the largest area we have accounts for roughly 27 percent of our EBITDA in the Gulf Coast, so you can see we've done a good job of diversifying to these various basins, and as you look over to the net revenue components, you can see here that only 13 percent of our revenue components is coming from our MGL margins.

The other sectors of the business are coming from fee based or tariff-based income that is not directly impacted by commodity price moves. Getting to what this is doing for us in terms of cash flow and capital spending. First of all, you can see here that our free cash flow grows from 2003 to 2005 and grossed over 420 million. The majority of our 2003 capital, that you can see being spent here is a completion of the buildout of our deep water infrastructure and that really starts to pay dividends as it actually already has in 2002 and it is paying for-more for us in 2003 and beyond.

Our maintenance cap ex, which is a very key point. Our maintenance Cap ex ranges from 12 to 20 million. So there's very little capital required to sustain the kind of profitability that we've got coming from these basins. The other money you see being spent there in 2004 and-2005 is basically well connects that maintain our scale and presence in the various basins and continue to hook up volumes to our customers out west. This just shows how we're reducing volatility over time.

The assumptions here are that the margins are at a 5-year average margin. In 2002, you can see that spike up a bit. Partially, that's because that's a full year of Canada as we sell out of our Canadian position and replace that with deep water revenues, that is tending to drive the volatility downward in our business and that is demonstrated by this. Going to our operational health, this is something I'm very proud of our organization for, in terms of hard work and there's two slides here that really demonstrate this.

First, if you look at our gathering volume, we increased that in 2002, even with all the disruptions that we had in our business with all the asset sales we had going in midstream, we still increased our gathering volume by over 10 percent during the year, and our gathering rate just as important if not more. Actually we were able to push that up during December 2002. I think that is a credit to the health of our positions that we've put together.

Finally on the cost side of that, we're basically pushing our numbers in both directions. We're pushing our unit revenues. We're pushing our unit cost down. You can see that here. This is coming from real intent focus on operational measures in our business and this is simply just to graph it takes our volumes out west and divides it by our operating costs. As you can see, we've made great measures and continue to be able to push that downward.

Getting to our commodity values and our NGO margins here, this slide is really just to point out that where our assumptions are in the projections that you're being seeing made and basically that's the five-year average margin is what we are using for out plan.

As you can see in January and February of 2002, you can see how that compared with eight cents, sorry, a dime over and above the eight cents, that's the five-year average plan. So far to date in January and February that number is going to be right at 16 cents actual year-to-date. So we're off to a very strong start from a margin standpoint and just trying to give you a sensitivity of what is going on in that sector of our revenue component these days.

Finally getting to the deep water area, this is exciting area for us, the deep water continues to have technology lowered the financing cost and the size of reserves that producers can go after out here. We have worked hard with the large independent, such as and Dominion and several other large independents out here and we're really finding a way to add value out here as we aggregate volumes.

One of the things that I hope can be picked off of this slide is the fact that our expectations that we had when we went into these investments has been exceeded considerably and so it gives us great confidence in the projections for the future, which are basically born off of our original projections.

So to date in all three of these projects that you see here, in the deep water, we are exceeding our original projections and got great confidence about the future there.

So to wrap up, our scale and our basins is strong and we are leveraging off of it very well. This is not an endless treadmill business, as some have referred to it in the past, and in midstream business, once you gain the scale, that we've established in the basins we're in, it does generate strong free cash flow and I'm convinced that can continue.

Even with that, our growth remains strong from our core businesses, and particularly the deep water as we back off of our intense capital investment program that built the scale in these basins.

And finally the midstream organization went through tremendous change in 2002 and our employee stayed very focused and engaged and produced great results. And this factor more than any other single factor gives me great confidence about our ability to execute on our plan in the future.

Thanks and I'm going to turn it over now to Doug Whisenant, Vice-President of our Gas Pipeline's Group.

Thank you Alan.

Clearly after selling three of our wholly owned gas pipelines and several of our major gas pipeline joint ventures, our system map is not nearly as densely populated as it was a year ago. Nonetheless, we remain one of the largest interstate pipeline systems, delivering near 14 percent of the natural gas consumed in the United States.

In the past, we've rightly described interstate pipeline business as the lower risk, lower return part of our portfolio.

Like other interstate pipelines, our rate design recovers most of our return and fixed cost and our reservation charge, minimizing the impact of fluctuating demand due to weather and other factors that otherwise would introduce greater volatility into our revenue streams.

Our pipelines enjoy other advantages. Our major markets in the Pacific Northwest, South Atlantic, Middle Atlantic, and Florida, are among the fastest growing in the United States. And the access gas supplies, the Gulf Coast, Gulf of Mexico, Rocky Mountains and Western Canada, are prolific and are expected to continue to meet the demands of our markets.

In addition, Transco is well situated to access a sizeable portion of the large increase in LNG imports we expect over the next several years. And connections to gas storage with large deliverability, 5.8 bcf per day on Transco and 1.2 bcf per day on Northwest, give our customers tremendous flexibility to serve seasonal and peak lows.

Turning now to slide 57, close to 92 percent of both Northwest and revenues are pursuant to long-term firm transportation contracts. While the current terms of these contracts ultimately expire, no customer is given notice of their intent to terminate. To mitigate risk, we don't seek to expand our pipelines without first giving existing customers the opportunity to sign their capacity to perspective new customers. And we don't build expansions unless they're fully subscribed, being the on the exception.

Mainline expansions into our major markets are backed by contracts of at least 10 years, and often up to 25 years. And contracts to new laterals that serve more isolated markets are for the economic life of the market served, sometimes 30 years.

Gas and electric utilizes remain our largest customers and with few minor exceptions, our contracts are with or guaranteed by investment grade entities. Northwest and Transco are often the principal provider in the markets they serve. Northwest serves all of Seattle, Tacoma, Portland and Boise in the Pacific Northwest. Transco serves 50 percent of New York City, almost two-thirds of New Jersey, 55 percent of Philadelphia and near 100 percent of the Carolinas.

We are the low-cost provider in each of these markets.

We are now wrapping up a long series of expansions on our Transco and Northwest pipelines. With the significant expansions completed since December of 2001 and to be completed by the end of this year, we have in effect, just a large portion of the proceeds from the sale, and Central to replace their earning capabilities with the expansions on Transco and Northwest. On Northwest, the Evergreen project is fully subscribed, one-third for 25 years and two-thirds for 15 years and will provide first-year EBITDA near 28 million once placed in service.

The Georgia Strait joint venture is also fully subscribed for 30 years and is 50 percent owned by . The Rocky Mountain and Columbia gorge expansions replace south to north virtual capacity created by customers current obligations to flow gas from north to south. For this reason, existing customers and have agreed that the cost of these expansions can be rolled in to existing rates with Northwest next rate filing.

Turning now to slide 59, on Transco, the momentum project will be built in two phases. The first phase, adding 269,000 decatherms per day of capacity into south Atlantic markets will go into service in May of this year and the second phase adding another 54,000 decatherms per day of capacity will go into service in May of next year. This project will add about 26 million of EBITDA in the first year of operations. The trend expansion shown here serves markets in the Philadelphia area and New Jersey.

We believe that these expansions will be the last major expansions into our market for the next several years. As a result, gas pipelines is expected to provide Williams substantial cash flow in 2004 and 2005. This slide includes Texas Gas for the first half to 2003, after that, only Transco and Northwest Pipeline are included. Cash flows from Gulf Stream and our other joint ventures are not included.

Together Northwest and Transco will require 150 to 190 million of maintenance capital annually over the next few years. This is higher than we would normally expect, because of the transition requirements of new pipeline, safety and clean air regulations.

Turning now to the key issues slide, slide 61, effective April 1st, we will implement one line, our new service delivery system on Transco. This system represents a significant improvement over the existing systems that it replaces, going beyond merely complying with new energy standard board standards, but providing real-time nominations and confirmations as well as invoices and balances within hours of the close of the gas day.

While it can be said that we don't have a lot of risk in our revenues through volume and price fluctuations, once rates are settled, we do of course have risk, specifically what we realize out of some short-term firm and interruptible capacity, depends on the difference in gas prices at points. For example, in Northwest Pipeline there can be sizable swings in short-term firm revenues up to 10 million a year, depending on the relative gas prices in Wyoming versus the San Juan Basin in New Mexico.

Currently that difference has been relatively large, adding to your revenue. With the completion of Kern River we expect that difference to significantly narrow.

The has been investigating whether Transco has complied with rules that govern the relationship between interstate and natural gas pipelines and their marketing affiliates. In December the staff outlined their concerns to Transco and the company and staff are currently engaged in confidential discussions in an attempt to resolve this matter.

As I indicated the discussions are confidential, so I will not be able to provide any additional information regarding this subject today.

Whenever a pipeline makes a rate filing, it introduces an element of uncertainty for the pipeline and its customers until the rate case is settled. Rates on Northwest and Transco are settled and are not subject to refund. Transco is not required to effect new rates until March of 2007. Northwest has no date certain requirement to effect new rates. Of course if we ever find our rate recovery is inefficient, we will file for a rate increase.

Northwest Pipeline and Transco may well be the premier pipeline assets in the country. For Williams, they provide significant, secure cash flows. For our customers, our low costs, diverse gas supplies and flexible operations, they provide an exceptional transportation and storage value.

I turn it back over to Steve.

Thanks Doug. I really believe that these presentations reflect that our core businesses are very strong, are certainly thriving and enjoy the characteristics that are consistent with our commercial strategy of owning natural gas assets in key growth markets.

I'm now turning to slide number 64. We've recently spent a lot of time talking with our employees and with our board about a blueprint for success, which describes what's important to us over the next couple years, what need to happen, what new performance metrics we will be using to manage our business, the fact that we will be much more disciplined.

And in any event, we certainly stress that that blueprint for success is not just about solving our problems, but as well, it's about building our future. And this slide offers some bullet points on what's important in terms of building Williams future, certainly our continuing focus on our core natural gas businesses and the continued profitability of those businesses.

The fact that we do need to turn more assets into cash, that we do need to continue to reduce risk and liquidity impact associated with marketing and trading, that we need to reduce costs and our work force to align our support groups with the remaining base of core businesses.

We need to create financial flexibility by refinancing, which will permit us to reduce debt levels on our own terms, and consistent with our commitment to live within our means, we will be investing dollars in core businesses with a focus on balancing portfolio risk and maximizing free cash flow.

As I indicated earlier, we have spent a lot of time looking at the next three years and this slide, number 65, gives you some of the results of our strategic plan from a financial metrics standpoint, cash flow operations growing from 800 to a billion to about a billion five in 2005, capital expenditures dropping dramatically again as we complete the significant projects that Doug described on our gas pipes, and some of the deep water projects that Alan Armstrong described.

Free cash flow growing dramatically during the time frame to a billion dollars by 2005 and return on capital employed and cash flow and free cash flow returns growing fairly positively over the time frame, and these just happened to be metrics that will be important to our future and ones that we will be monitoring as we go forward.

The key elements of our plan, $4 billion in announced and new asset divestitures and again, I've said it a couple times, I'll say it again, we sold $5.1 billion of assets last year. I believe that that is a core competency for Williams, I believe that we will be very successful is selling these assets and selling them quickly and at good value.

Substantial free cash flow generation growing to more than a billion dollars in 2005, a disciplined approach, which will allow us to appropriately prioritize capital expenditures going forward. Opportunistic financings with a continuing goal of delevering the company and again, relentless pursuit of cost reductions going forward.

The, I believe, as I indicated earlier that this is a comprehensive response and our plan is designed to address all near-term and medium-term liquidity issues. It is designed to de-lever the company over time with the objective of returning to investment grade by 2005. Our plan downsizes our rich asset base to a core portfolio of world class pipeline mid-stream and ENT operations. And then I don't think there's any doubt that our continuing focus will be on maximizing the return to our shareholders.

So with that, we got through the slides a little faster than I had thought, but now we'll turn to our Q&A session and we look forward to taking your questions now. Thank you.

I'd like to remind everyone on the phones that if you do have a question today, you may press the star key followed by the digit one on your touch-tone telephone.

Again that is star-one to signal to ask a question.

We'll now return to our program.

We'll take our first question from with Morgan Stanley.

Good morning Steve.

Had two questions. First question is in looking at your long-term debt commitments, you all have approximately $3.5 billion of commitments between '05 and '07, and it looks like what you all have announced today will definitely get you through the hump for a while. I wanted to know a little bit about, looks like free cash flow to equity holders after interest expense ongoing is probably sort of break even to modest, just very modestly negative. Is, are the '05 through '07 commitments, have you all already been in process of talking with the different lenders about working through that and potentially pushing that out. And that's my first question.

The short answer to your question is yes, we've already begun the process for the longer dated maturities to see what can be done. One of the biggest ones that people have questions about are the feline packs, and while that's a fairly complicated answer, the truth of the matter is is that the mechanics for that are very straight forward, and we get an additional billion one of cash in the door as a part of that ultimate settlement, so that one is basically already taken care of due to the mechanics and the way it works.

But to answer your question, yes, we've already started that process.

OK, thanks and the my second question is, it looks as though you're, so your ongoing cap ex, total cap ex looks like a 500 to $550 million per year. You all had targeted that your E&P business would drive most of the growth of Williams going forward.

What I was curious about is do you all think that five to 550 is enough cap ex to not only sustain the replacement of reserves in E&P and a little bit of modest growth on the pipes. You all have, in some areas, you all face decline curves that are fairly high looking at the slides. I was just curious, is that 550 maintenance plus upgrade and is that enough to get you the targeted sort of 10 to 15 percent growth that you're seeking.

Thank you. And that's my only other question.

this is Steve Malcolm and I'll let Ralph, if he wants to add anything to this answer, but yes we do believe that the five to 550 is an appropriate capital expenditure number to consider going forward. That does have imbedded in it my recollection somewhere between 250 and $300 million of investments for drilling in the E&P section, and I believe that Ralph and his team are pleased with that level of expenditure. And as well, does give us sufficient capital dollars to keep our gas pipes and mid-stream operations, obviously, operating safely and reliably. And I'm sure there are some minor dollars in there for expansion projects.

OK, and then Ralph, I guess my only question, tying into that real quick is, is the assumption on a cash flow from operations from E&P for your free cash flow premised on a $4 gas or that's what it looks like from looking at the slides. I just wanted to make sure that was the case.

Yes, currently we're hedged at slightly over $4 for '03 and '04. The actual '05 outlook is I think was like $3.80 at that time.

OK, so you're using the forward curve and?

Right, but as you know, I think, the forward curve's way above that, but we're trying to be conservative.

OK, great. Thank you.

We'll go next to Paul Patterson with Glenrock Associates.

Good morning. I was wondering if you could tell us what the interest expense you're expecting in 2003 is.

again, sure. Just to recap it for you, interest expense in 2002 was about a billion 246 and in 2003 it'll be about a billion 226. So down slightly from last year.

OK, and then secondly, in terms of the exceptive '02, '03, I was wondering what the impact in terms of increased to cool earnings might be for 2003, and why does segment profit for the trading and marketing is 200 to 350 million, but the cash flow you guys are projecting is negative 100 million to flat, no cash at all.

Let me address the GAAP first. The primary gap between earnings and the cash flows we're projecting are internal, inter-company interest expense of about 120 million and then potential tax liabilities of about 150 million.

On the tax liabilities, the, because we are a mark-to-market company, we deferred a great deal of taxes and they are scheduled to be paid out over time. With the impact of our cumulative catch up on the EITF '02, '03, we believe that that tax burden's going to be significantly lower and therefore, the cash from operations is going to improve, but that's a primary gap.

As far as 2003, certainly the reversal of mark-to-market numbers is going to create accrual income not only in 2003, but on a go-forward basis and Andrew Sunderman, I don't know if you want to comment, specifically of how much that would be.

This is Andrew, I think that the shape of the improvement due to accrual earnings will closely match the shape of what you'll see in our 10-K when we report our fair value, but it's probably somewhere in the 25 increasing up to about 40 million a year coming in from the change in accounting principle back through accrual earnings.

So you guys are going to have the $700 million, or 750 to $800 million after-tax write-down, but then we would see approximately $25 million I guess to $40 million coming back over a series of years, I guess several years.

Well that number for the plan that we've shown right now is in the 25 to 40. That number ramps up greatly based upon the shape of our, many of our cash flows that are being reversed through the accounting change. That number would get greater as you go out, just because of the nature of our contracts.

OK, how much more mark-to-market gains do you guys expect to have now that 98 cash has been rescinded? What's your expectation for non-cash mark-to-market, revenue recognition for 2003?

ON a go-forward basis as described, this is again, as described in his presentation, our mark-to-market is limited to any ineffectiveness in our hedging, any remaining speculative positions that we've been unable to get out of and will continue to get out of, and any interest rate and I believe that, so that number's extremely small, and I believe that gave a number of around 20 million.

OK, so the number's, the number's insignificant I guess in terms of future revenue ...

Absolutely.

OK, thank you very much.

We'll take our next question from with Bank of America.

Morning. Wondering if you could give us a little bit more color on the earnings guidance from energy marketing and trading. You mentioned that 25 to 40 million is recapture accrual. On the remaining piece, can you give us a sense of, you know, how confident you are in that level of earnings. Is that earnings that are contracted for? And secondly, does it include earnings from the sale of the contracts that you expect to, well that you announced happen relatively in short order?

Well first of all, we are confident in the numbers or we wouldn't have showed them, but the breakout is pretty much around cash flows and Andrew indicated a locked in, it does include sales of certain parts of our book. And as well it includes, we do have underlying positions and power and we certainly will be managing those positions and we'll generate some cash in addition to that.

So those are really the three areas that drive our earnings in '03.

OK and then can you also give me a sense of what the EBITDA is on the, like in all business that you've agreed to sell?

This is Phil Wright. I think it's five million last year, 2002.

OK, why don't we take one question off the web, this question is, "What's your current debt/cap ratio, and what do the ratings agencies think of your program, and then, where do you think the need, where do you think you need to be to restore your rating?

This is , I'll try to answer those questions briefly. In terms of book debt to capitalization ratios, it's around 68 percent, if you look at it on rating agency basis or on a bank basis, where the are converted largely to equity, the rate drops down to about 64 to 65 percent, the way the rating agencies and the banks look at it. In terms of what the rating agencies think of our program, we've previewed it with them very briefly, we will actually be going over it in depth tomorrow in New York, so, assuming the weather holds, we'll be up there to preview this in some depth with the agencies, but their initial reaction was positive.

As far as what does it take to restore the rating? Well, obviously we said that we intend to be back towards investment grade by 2005, and I think this plan that we've outlined today is what it takes to get back to an investment rate credit rating, because we're going to significantly lever the company and generate substantial free cash flow in 2004 and 2005.

OK, go back to the audio please.

We'll take our next question from the phones from Ron Barone with UBS Warburg.

Good morning. Quick question on your interest rate exposure. Could you elaborate, give us a little more details on your interest rate exposure. Is it still with the swaps?

This is , hi Ron. The interest rate exposure, I guess you're referring to what Bill was talking about, and that was actually interest rate swaps that we put on last year to help hedge the portfolio. In terms of other interest rate swaps that we have on, I mean, they're basically all were to support the EMT books, so we have very little other interest rate exposure directly other than just existing maturities that we've already talked about and the fact that we will seek to refinance some of that, so we obviously will have some interest rate exposure there as well.

OK, thanks Jim, and one other if I may, as you work with people to trading book with California settlement behind you. What do you think the biggest hangup is? Is it price?

Yeah, I don't necessarily at this point, Phil Wright and his team I think have done a great job of working with folks to generate interest, and really, so far, the kind of numbers we're seeing are not anything that causes us pause. I think the major issues regarding the exiting of the California position will be California itself, and Phil, I don't want to know if you want to add any color to that or not.

I think that captures it very well. I think, as well, people have to do a level of dilligence to understand what's in there and with the settlement occurring relatively late last year, people are now just coming up to speed fully on the implications of the settlement and are able to monitor it and are fining very attractive value in there. People who had been on the sidelines for a time have now come back in and began looking in earnest at that portfolio.

Thanks for the input.

We'll go next to .

Thank you for laying out what seems to be a doable plan Steve, and with respect to the Texas gas transmission sales, and that was an integral part of Williams and for some time. Could you talk about the growth that you're letting go of in that line and with that sale pending and what kind of timing might we be looking at on the Texas Gas Transmission Sale. While it's not necessarily, relative to Transco or the line, the growth on that line is so much faster I'd assume, but I want to hear it from you all, how much growth you're letting go of by disposing of Texas Gas. Thank you.

Donato, this is Doug, I'll try to respond to that. This past year, Texas gas generated cash from operations of about 35 million, but this was substantially lower than normal because they made some large cash refunds pursuant to some of the rate cases, and on an ongoing basis, the segment profit last year on Texas Gas was about 116 million, that again, was larger than normal, we would expect something less than that on an ongoing basis. The markets there are very stable markets, it's a quality pipeline and a great asset, for -- included in our estimates for 2003, we're assuming the sale takes place in June, is, we're assuming we'll have a segment profit of about $50-60 million and cash from operations of about 60-70 million and apparently low capital expenditure levels, because they're mainly spending maintenance capital at this time. We didn't anticipate a lot of growth, our growth prospect remain on the Northwest and Transco pipelines.

Great, and I expect the interest in TGT to be very high, and Steve I was just wondering if maybe you could contrast that with what you expect on the partnership interest that you've also announced and thanks a lot.

Yeah, . I think the interest will be and has been very strong on both of those assetts and I hate to overpromise, and I won't overpromise, but indicative bids are in with respect to Texas Gas and we're pleased with those bids. We expect bids next week on WEG, and we're optimistic with respect to those as well.

Thanks and good luck throughout this very challenging period. Thanks.

OK, why don't we take a question off the Web. Question is "Could you explain why you put the pension plan into two pieces, active employees and inactive employees, and why you make contributions to the inactive plan but not the active plan?

This is , let me take a stab at that one. In terms of why you ever make changes to your pension plan, it's really just to make sure that you are managing the assets as prudently as you possibly can, and the changes that we made last year were just part of the process of making sure that we had a plan design and assets that support the plan. In terms of why we separated it into active and inactive, it really was an attempt to get a much more firm handle on exactly what the benefit obligation is for our inactive participants, and that's easy to do and easy to isolate. On the active employees, obviously you have a lot longer timeframe in which to grow the earnings of the plan to support their piece of it. So the reason we made the funding is exactly that. The near-term obligations are for the inactive participants, the longer term obligations are for the active participants, we wanted to make sure that we fully-funded the inactive portion of the plan because those are the most near-term obligations.

We go next to .

Good morning, gentleman. I know that you went over a few of the numbers, but could you go over Texas Gas one more time? The '02, and what was recurring?

The operating profit for Texas Gas, segment profit, for 2002 is about 116 million dollars. That included some one-time reversals of prior reserves that were booked in prior years and inflated that number by probably about 15 million dollar or so.

OK, and also on the Williams Energy Partners I know that the segment profit you recorded today was 96 million for '02. How much cash from the general partnership and the limited partnership did you receive in '02.

Well, Dylan, we don't have that number at the tips of our fingers, we will endeavor to answer that question before the end of the session here.

OK, thank you.

We go next to Gordon Howald with Credit Lyonnais.

Thanks guys. Just a quick question regarding Jack's vacated position. Obviously, you guys have a lot of impressive talent within the organization. Where do you stand in terms of refilling that position?

Well, Gordon, as we have told everyone, we're going through an internal and external search, we have hired an external search firm to help us, I've interviewed, to date, I think two external candidates and have three more scheduled next week, and I think two more after that. Again, the internal and external candidates will go through the same process, and my hope is that we will select a new CFO in March.

Great, and congratulations on a great release today, thanks.

Thank you Gordon.

And we'll go next to Curt Launer with Credit Suisse First Boston.

Good morning and thank you for the call. I just want to ask you to expand for a moment relative to the asset sales, particularly Texas Gas and the producing properties and reserves that you wish to sell, and it seems like the plan assumes outright sales of these assets, certainly other transactions have been done by you and others that could be partial sales, joint ventures, financing, and so forth, and I'm wondering if there's any flexibility in the plan for that kind of eventuality?

Well, Curt, the plan that we have outlined today is the one that we will pursue, but recognize that as developments occur, as opportunities arise, there is certainly flexibility that is afforded us and we will take advantage of that flexibility as its offered. I mean, you know, there is the plan that we think makes sense and this is the plan that allows us to address the near term and longer term liquidity needs of the company and yet allows us to continue to retain very strong core assets going forward. But, to the extent that, for example, we would do a timely deal, relative to marketing and trading, selling a piece of that portfolio, this certainly could have an impact on where we go with respect to asset sales.

Or, alternatively, I would add, production payment plans could be considered as joint ventures in pipelines and so forth.

Curt, we, I can assure you that we have looked at analyzed and evaluated every alternative and clearly, those are ones that we'll be.

OK, thank you, very much. operator: We'll go next to Carol Coale with Prudential Securities. coale: Hi, good morning. I had a few specific question, related to your production hedges at your EMP company, you and some of your peers, I understand, have hedges that are currently out market, given current gas prices. In your plans to sell about 20 percent of your existing nonstrategic reserves, do you have hedges associated with those reserves that would require unwinding or result in some sort of a charge related to those sales to make those properties more attractive? hill: Not really, Carol, its maybe a small piece of it, but not, in the overall grand scheme, it would be very, very small. coale: Okay. And then a quick one for Bill. You seem to have gone back and forth on this joint venture strategy for the EMP portfolio, and I believe the last time you got in front of us, joint venturing was not in the picture because of the marketplace. Can you elaborate on what's changed and what the interest in a joint venture is currently? hill: Well, Carol, I don't think we have really flip--flopped at all. I think going well back, Steve has been very clear that that's been our intent. Certainly, as time has passed and there has been not more negative moves for quite some time, I think its made it easier for discussions to continue and where Phil and his team are at is, we're fairly far down that path, whether the joint venture develops or not is yet to be seen.

I just don't think we have been unclear in our desire to find a joint venture partner that not only can take a lot of risk off Williams, but also on going forward and its something, as we have discussed it, back to a previous question about potential upside, probably, if the deal happens, it would be structured in a way that we do have upside going forward in it. So Phil, I don't know if you want add anything to that? wright: I think that covers it very well. coale: Well good luck guys, thank you for the call. operator: We'll go next to with Goldman Sachs. mcroan: Thank you. I was hoping you could review for us your 2003 through 2005 cash flow from operations and what makes up those numbers between net income, depreciation, deferred taxes and any other cash items?

David, let us prepare that answer and we'll do it, we'll give that to you before the session ends. mcroan: OK, thank you.

Okay, why don't we take one off the web. The question is what drives the huge jump in cash flow from operations in '05 relative to '04?

Again, huge jump in cash flow from operations '05 relative to '04. The primary factors would be EMP increases associated with the drilling activity that Ralph described for you. An increase in midstream cash flows associated with deep water projects that will begin fully contributing in 2004 then, lower interest expense is probably a third factor that driving the significant increase in cash flow year to year, '05, '04.

hill I would only add one thing. Interest expense is a very large driver. As we de-lever the company, we will be taking out well in excess 300 million dollars of interest expense by the time we get out to the '04, '05 time frame.

Okay, why don't we take another question from the web. This is, area there more current listing of your debt maturities than what is on your Web site which are as of 9--30--02. And I'll go ahead and answer that question. As we continue to prepare the 10K, we're going to sink those numbers up with the 10K, so they will probably be, there will be a cleaner listing out on the Web site probably in a week or two. operator: We'll take our next question from Scott Suller with Morgan Stanley.

Hi. I had two other questions, I hadn't thought about earlier. First question is, in assessing, when you all are looking at your earnings power, out a couple of years, when we looked at 03, 40 cents, does that, in your opinion, Steve, represent a baseline of earnings to then increase earnings going forward or, because there has been a lot of questions about EM&T, if we take out the earnings in EM&T, and you all had said of the earnings in EM&T includes, I think, assumed sale of some of the book, what is the better way to think about the EM&T earnings so that we can better understand the, sort of the earnings power of the company going forward?

Scott, I do believe the 40 to 75 cents is fairly representative of a baseline number, the marketing and trading profitability, I think, Bill suggested, was representing only about 15 percent of the total and given the growth that we are projecting in EMP that Ralph described, I do believe that the 2003 number does represent a number from which we will grow in the future. sollar: Okay, and then Bill, I was hoping you could help us understand, you all have done a great job. I commend you for your work with California, I think much better than most and what I want to ask though, is, are will other issues in your mind that are lingering in the not really specifically for Williams, but, Williams as a group with other companies, what things sort of need to be resolved, aside from what you all have done company specific with California? hobbs: Well I think for the most part, as far as California, we are in a good position. We have put the majority of that behind us. There are still refund proceedings going on that we are very active in. But we think those will be resolved favorably. So from our standpoint, I think we have largely put that behind us, which is, as I indicated, is great, because it's allowed Phil Wright and his team to now talk to multiple parties about potentially selling that.

As far as the overall industry itself, clearly, it's going to take time. We are going to have to gain our creditability back and so, that's probably the biggest issue that's hanging out there. There is the index investigations and still hasn't issued its report, which Chairman Wood has indicated is coming in early March. That's certainly going to have some impact, good or bad on companies. So I think as far as near term, probably the ongoing index investigations an then issuing their report are things that I see in the next 30 day horizon that could have either positive or negative impact on companies.

Okay, great. Thank you. operator: We'll go next to Raymond Niles, with Salomon Smith Barney. niles: Good morning, thank you. Question I just wanted to ask about was explain in a little more detail some of the one time charges in the EM&T segment and I apologize if this was gone over in detail before, but, 51 million in the fourth quarter for impairments and loss accruals from commitments related to assets, too, have been used in power projects and I think that another amount, 82 million showed up in the second quarter and I just wanted to know, maybe specifically, what it is and just, for that item in general, what should we expect in terms of charges over the course of 2003 at the EM&T unit? sunderman: This is Andrew. If you recall, we released the announcement about Hoosier Worthington, that we had sold a portion of the write down was for that plan, I think we previously announced, that amount will be about 45 million. In addition to that, we have in inventory of distributative generation assets that we have been actively seeking to sell and it's very similar to any other asset sale process. As the bids continue to change and come in, we look at those bids and if those bids continue to go down, we obviously continue to take write downs against those assets, which is the other primary driver, just for the fourth quarter. And looking at 2002 as a whole, those items along with, I think, in the second quarter we took some good will impairment, those are the primary drivers for the nonrecurring for 2002 and I do not anticipate anything of that magnitude in the future and any assets sales that we do around the portfolio probably would not be considered nonrecurring. niles: Okay, can you just ask, so you are saying no, that there won't be any material charges in 2003? sunderman: No, I don't anticipate any. niles: Okay, but just very specifically, the 50.8 million dollar item. I see Worthington listed separately. I'm referring to the 50.8 million dollar item, you know, which is listed the impairments and loss accruals for commitments related to---- sunderman: Yeah, and most of that's going to be the WDPS assets that I just talked about. About 44 of that was the WDPS assets, which is the distributative generation business that we are trying to get rid of the as well. niles: And so that was the same item in the second quarter, there was another charge in the second quarter for that? sunderman: Yes, there are some similar items, the charges for that in the second quarter as well, yes. niles: Okay, thank you.

Another question from the web. Says please clarify your natural hedge position for 2003 and 2004. When you indicate production is hedged at 85 percent for these years, does that include a natural hedge for electric trading and liquids? hill: This is Ralph. No, that 85 percent I was talking about was the 85 percent I was talking about was straight up percentage of our production. wright: Travis, this is Phil Wright, I believe one of our earlier questioners, I think it was, perhaps, Scott, asked about Williams Energies Partners cash in 2002. Our primary source was dividends, or distributions received at 30.5 million dollars and then we have another couple of items that will total about 5 to 6 million dollars for a ballpark number there, a pretty good number of 37 million and then, of course, we received the proceeds from the Williams pipeline sale.

Okay, another question from the web. How does the value of the trading portfolio change if natural gas prices rise or electricity rates rise or if interest rates rise? hobbs: This is Bill. Since we are largely hedged in the near years, '03 and '04, changes in sparks spread, positive changes will certainly help us, but again, they will be accrual earnings, so you won't see a big market to market gain associated with that. And as far as interest rates, interest rates moving up is good for us, because those are market positions and as I indicated, its about 360 thousand per basis point. So, probably as far as market to market exposure, that is our biggest and so as interest rates move up or down, our earnings rates will fluctuate with it. sunderman: Bill, if you don't mind, I'll just add a little scenario color around that. If you are looking at the economic value of our book over the next two years, if you had a five dollar increase in off peak or five dollar decrease in off peak, that's about 30 million dollars a year. If you had a five dollar increase in peak power prices over that same time period, that would be about 70 million dollars a year and that's fairly linear in both directions. operator: We go next to with JP Morgan.

Good morning. Just wanted to go through the collateral requirements that you guys discussed of 350 million per year. As you unwind the trading book and we think what you guys had to say this morning should improve your credit quality, why do you anticipate such a large draw in terms of the collateral and over two years? sunderman: I think what we have done in the plan and what we have shown there is, that 350 million dollars is very similar to numbers we have communicated in the past around the plan. If we are to be in current price environment and continue to maintain the same hedge program that we have for all commodities, that would be the amount of liquidity that we would need for a two sigma price move at 95 percent confidence intervals. Obviously, you can, we can, we have our own belief of where prices are going to go, but as we said many times in the past, that's more of a planning number if we had the prices with our current existing portfolio. faigon: Thanks, Andrew, and a quick follow up also. You have 500 million of cash being posted in lieu of LCs is that in anticipation of a financing not being renewed or is there another rational for that cash? ivey: , this is Jim Ivey. That is a fairly mechanical process that we go through with our bank deal as it currently exists. We think that we will be able to substantially improve upon that as we renegotiate the bank deal this year. But the truth of the matter is as we sell more assets, the waterfall of cash proceeds go to collateralize our existing LC positions and that's what that represents is as we sell the assets, there is a need to post cash against existing LC facilities.

Thanks, Jim. operator: We go next to . beater: Good morning. With all the changes that you have experienced, I wondered what impact you expect it to have on the tax rate in 2003. What should we assume or what are you assuming for tax rate?

Well, obviously, and the way we do financials, it the full tax burden in terms of what we actually pay in cash taxes if that's different, the difference is whether you are going to be an AMT taxpayer or a full taxpayer. But in terms of the way we do the financials, it's a fairly burdened tax rate. beater: Okay would you expect to get some benefit from some of the write offs and charged you have taken?

Well, from a tax perspective, yes. I don't thing we would call it a benefit to take write offs and charges, but from a tax perspective, absolutely. beater: All right. But no quantification of what that could be?

Well, we could certainly go into that in more detail offline, but to be honest, this is still all in preliminary stage in terms of what the tax position would look like and I really don't want to go down that path right now. beater: Okay, so for purposes, assume 35, 40 percent for calculations.

Yeah, in terms of the way the financials will be presented, yes.

Thank you. sunderman: Okay, this is a question from the web. Can you tell us what the availability of your bank lines was at year end and out line the debt due in 2003 and 2004? ivy: This is Jim Ivy again, we had full availability of our multiyear bank facility, which at year end was about 462 million dollars. It was totally undrawn at year end and it is completely available to the company today. As far as the debt maturities, we have outlined that for you, its about 2.3 billion dollars in 2003, about 900 hundred million of that is the Rocky Mountain reserve loan that will mature in July. The balances are just the regularly scheduled maturity, except that there is about, there is an assumption of liability 200 million dollars of structured bank debt that will be accelerated into 2003 from 2004 as a result of the additional assets sales that we are making and the cascade of the waterfall that we use to pay down the structured bank debt as we, in fact, sell the assets. The debt maturity schedule for 2004, I believe was also on one of the slides. It's roughly 1.4 billion dollars, obviously, or excuse me, 1.8 billion dollars, virtually all of that is WCG note trust notes that come due in March of 2004 and that number is 1.4 billion dollars. sunderman: One more question from the web. Can you give a little more specifics on the announced sale of the portion of your trading book? Size of the contracts, length of the contracts, regions johns, value of the contracts, etc?

And I think that question refers to some comments that Bill made that we expect to be able to announce something in the next couple weeks. The answer - the short answer is, "No, I can't provide any additional information on that." And we'd just ask you to be patient.

We did have - we did have another question that came in earlier from I think it was David concerning 2003 - 2005 cash flows and I'm going to ask Mark Wilson to briefly - I mean you could go into a lot of detail on that, but I think there are four or five components that he can address. Mark?

Yes, I think the question was, "Going through deferred taxes, depreciation, and amortization, and some of those line items, how do you get from income down to the cash flow from operations that we showed?" And I'll hit just a few of those.

In 2003, we've showed a range of income from operations, but if you assume that's in the range of about 400 million, there's about 700 million of depreciation, around 250 million of deferred taxes, we have some gain on sales of assets which we've assumed is around 700 million, and then there is a positive cash impact from change in working capital of about 170. That 700 million on the gain in sale of assets, of course, comes off of the cash flow. And if you add all that up, you get very close to that $900 million number that we showed. There's about 100 million of other line items that come in and out.

When we get out to 2005, at least in the plan, income from continuing operations is about 500 million, depreciation is about 700 still, the deferred taxes are about 175, and those are really the largest components that, when you add them up, gets you out to that - near that 1.3 to 1.5 billion range for cash flow from operations.

That's all, Steve.

Thank you, Mark.

I believe that those are all the questions that we have today. I believe that we have presented a very achievable, a very comprehensive and yet straightforward plan that allows us to address our issues and problems that we're faced with today, but as well allows us to build for the future. And so with that, I appreciate your time, appreciate your interest in the company, and thank you for participating in our call today. Bye.

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