威廉斯 (WMB) 2004 Q4 法說會逐字稿

Good day, everyone, and welcome to the Williams Companies fourth quarter and year-end 2004 earnings conference call. Today's call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Travis Campbell, Treasurer and Vice President of Corporate Communications and Investor Relations. Please go ahead, sir.

Good morning, everyone, and welcome to our conference call this morning. With me in the room here today is obviously Steve Malcolm, our Chairman, and he's got also with us, is his management team, the business unit leaders, Ralph Hill, Allan Armstrong, Phil Wright, and Bill Hobbs, and our CFO, Don Chappel. All of those will be presenting parts of our presentation today. Before we begin, let me first mention that the slides that we'll be going through today are available on our website, Williams.com in a pdf format. Also we'll be, as always, taking questions at the end of the call. And after Steven finishes off his remarks at the end of the call, we'll turn it back to the operator for instructions on how to get into the queue for questions. Referring now to slide number 2, which is our forward-looking statements, I just want to refer that to you, describing the risks and uncertainties affecting our Company. Please read that over. Slide number 3 is the oil and gas reserves disclaimer, that talks about our presentation of oil and gas reserves. With that, let me turn the call over to Steve Malcolm, our Chairman.

Thank you, Travis, and welcome to our fourth quarter and year-end conference call. And thank you for your interest in our Company. I believe the main message of today's call is that Williams has completed its financial restructuring, that Williams is opportunity rich in terms of our capital spending options, particularly in the E&P sector, and that our management team is now focused on, and confident about, our ability to grow earnings and create shareholder value in the future. Turning to slide 5. As Don Chappel and our business unit leaders will describe in more detail, Williams delivered strong performance in the fourth quarter. Midstream recorded a record quarter, due to continued strong margins, record volumes. Actual margins were more than double the 5-year average in the fourth quarter, NGO volumes were up by 100 million gallons. E&P production volume growth continued, up 26 percent, fourth quarter '04 versus fourth quarter '03. Gas pipeline enjoyed its best quarter in the last 2 years as a result of lower costs and improvement at Gulfstream. Power stand-alone cash flows were 86 million for the fourth quarter '04, 283 million for 2004, and as well, we were able to bring back cash of about $450 million in exchange for letters of credit during the year. And, lastly, our consolidated cash flows continued very strong. Cash flow from operations of over $400 million in the fourth quarter of '04, versus 75 million fourth quarter '03. And for the year '04, 1.5 billion versus 770 million in '03. So we doubled the cash flow year-over-year.

Slide 6, as I indicated earlier, we have completed our restructuring. We removed another $1 billion of debt in the fourth quarter of '04, due to our successful Feline PACS exchange and remarketing, and in fact, decreased debt by $4 billion for the year. Since the end of the year, we retired an additional 200 million at Transco, which has lowered current debt to around $7.8 billion. At year-end 2004, our debt to cap was 61.6 percent, compared to 74.5 percent at year-end 2003. Our current cash balance is $1.3 billion, including Feline PACS proceeds that we received in February. And this does not include restricted cash of around $105 million. As well, we resolved significant litigation during 2004. The most important probably being the refund claims of certain utilities relating to the California energy crisis. We were the first market participant to settle the refund cases with the utilities, just as we were the first to settle with the state back in 2002. I think this demonstrates our leadership in putting these kinds of issues behind us, and certainly FERC has supported our efforts. However, our Securities and ERISA class action litigation is still pending, with trial scheduled for mid-2006. And the DOJ's investigation of inaccurate gas price reporting continues, as does FERC's investigation relating to improper communication of gas storage information.

Looking at slide 7, some of the full year achievements. Certainly E&P had a very strong 2004 reserves performance. 451 Bcfs removed from the probable to proved category. That's almost 1.2 trillion cubic feet moved over the past 3 years. 248 percent reserves replacement rate, 99 percent success rate, total proved reserves of 3.2 trillion cubic feet. In many respects, Midstream's performance was phenomenal during the year, and that performance is not just all about margins. As Alan Armstrong will describe, our deep water investments, which are primarily fee-based, also performed very well. And as a result of Midstream's strong year, combined with relatively low capital spending, obviously they generated very strong cash flows for the Company. Gas Pipes was a consistent steady performer, with year-over-year growth. And we were able to complete several major projects, like the Everett Delta Lateral on Northwest Pipeline, like Momentum Phase ll on Transco. And in terms of power, in the last 4 months, since our decision to retain Power, we are pleased with the positive reaction from our customers. And as you will hear from Bill Hobbs, we have closed several new deals, ranging between 1 and 3 years, which have the effect of reducing risk and increasing cash flow certainty.

Looking at slide 8, once again, we are providing guidance by business units, not just for the current year, and not just for the next year out, but also for 2007. And we are happy to provide that information, and want to provide that information, but do I want to point out that some of our business unit leaders have some trepidations about forecasting so far in advance. And so hopefully you recognize that there are many critical assumptions relating to things like commodity prices and economic conditions and business activity, where significant movement could, in fact, result in changes in our future guidance. The opportunities that are included in the numbers that you'll hear about today relate to things like the fact that we have embedded 12 rigs in the Piceance Basin, total production growth in the 10 to 15 percent per year category, increasing utilization of our existing deep water projects. We do expect rate cases on Transco and Northwest Pipeline to improve segment profit in 2007, and in the power space, we'll be selling megawatts mainly through mid-level mid-term contracts.

But there is potential upside on the horizon that's not included in our base case going forward, and certainly we believe that we can do more in the Piceance Basin. In fact, we've mentioned in prior discussions, that we would like to accelerate our drilling program in the Piceance. And as Ralph Hill will describe later, we are aggressively pursuing additional rigs, and have, in fact, already added 1 in December, expect another 1 within 90 days, and still another by the end of the third quarter. So we're going to be using 15 rigs by the end of the third quarter in the Piceance Basin. Having said that, please don't get ahead of us on the guidance. There probably won't be much impact on the 2005 numbers. These rigs just recently became available. We don't yet know where we can get the greatest bang for the buck, in terms of where we want to do the additional drilling. But we will update '06 and '07 numbers after we've had a chance to fully evaluate the incremental drilling opportunities.

In terms of new E&P opportunities, similar to Trail Ridge, Ryan Gulch, and Red Point that we discussed in our November tutorial, we expect that there will be others identified over the next 3 years. As well, we've talked very clearly about the fact that we're pursuing additional large deep water projects, and you know that those range anywhere from 100 to $400 million in capital spending. We will continue to look for opportunities to place more of our megawatts beyond 2010. Certainly, there could be natural gas price strength beyond that that we've embedded in our plan. NGL margins could come in higher than the 5-year average, and certainly in the fourth quarter of -- I'm sorry, in the first quarter of '05, we're seeing -- we're continuing to see strong margins. And SPARC spreads could improve beyond the current market. One other comment before I move to the next slide. As I mentioned earlier, we are updating our guidance for 2005 through 2007 earnings and cash flows. As you know, we previously announced our intent to form an MLP, and we are continuing to take the steps necessary to proceed with an MLP offering. We hope to file our registration statement sometime in the second quarter, but the guidance numbers that we are providing today do not take into account any MLP offering. And so we will update our guidance once the offering has been completed. Now, this is the only information regarding our proposed MLP that we want and intend to provide today, and we would very much appreciate it if you would not request any additional information at this time.

Finally, turning to slide 9, you've seen this slide before. It kind of foreshadows the road ahead for our various business units, and in the E&P space, of course, near term production growth in the Piceance Basin, E&P is our near-term growth vehicle. In the Midstream segment, again, pursuing very aggressively new deep water opportunities. In Gas Pipeline, steady earnings, stable cash flow, expect a segment profit uptick in 2007 as a result of 2 new rate cases that go into effect. In Power, yes, we are retaining the business, but no change in the strategy that we've pursued over the last 2.5 years. We're all about reducing risk, maximizing cash, and looking for ways to place megawatts beyond 2010. And in the corporate space obviously continuing to look at opportunities for efficiencies, cost reductions, looking to reduce debt, but clearly not at the pace that you've seen the last 2 years. So with that, I'll turn it over to Don Chappel.

Thank you, Steve, and good morning to everyone on the call. I'll run through our results fairly quickly in order to leave more time for your questions. On slide number 11, the financial results, I would just like to review a few highlights from that slide. As you can see, our net income for the year of $164 million, and $73 million for the quarter, are sharply improved over 2003. On a per share basis, the $0.13 for the quarter and the $0.31 for the year are also directionally positive and sharply improved. On a recurring basis, we reported for the quarter $0.12, and for the year $0.49. Again, sharp improvement over the prior year. I would like to point out that mark-to-market does impact the recurring earnings, so the measure that we're most focused on, and we believe that you should be most focused on of these measures, would the final measure; recurring income after mark-to-market adjustments, where we strip out all of the impacts of mark-to-market. And as you'll recall, our Power business was required to use mark-to-market accounting as a result of our intention to sell the business. As of October 1st, as a result of our decision to keep the business, we were then eligible for hedge accounting, and while we will still have some mark-to-market volatility, it will be sharply reduced. And again, so I would guide you to pay particularly close attention to that last item, and for the quarter, that generated $51 million of recurring income after market-to-market, or $0.09 per share, and for the year, $190 million or $0.35 per share. Again, sharp improvements over 2003.

On the next slide, number 12, just walk through a reconciliation of income as reported to recurring income, and just highlight some of the key points here. First, looking at the quarter, starting out with the $95 million reported. We would reverse gains on sales of assets, add back impairments totaling $31 million, add back early debt retirement costs of $30 million, and then eliminate an insurance arbitration award of 103 million, tax affected to come down to our our $68 million or $0.12 per share. Full year basis, again starting with the $93 million, major items there, eliminate the $70 million impairment, eliminate the $282 million of early debt retirement costs, and eliminate the $103 million insurance arbitration award. Tax affect that for the 261 million, or $0.49 per share. Next on slide number 13, I'll walk through the analysis of how we move from recurring earnings to recurring earnings after mark-to-market adjustments. Again, looking at the quarter, starting with the $68 million, you can see 2 items there, the 23 million reversing forward unrealized mark-to-market, and the 6 million unrealized losses from previously mark-to-market items that were recognized in the current period, totals $29 million, which is eliminated from the current period earnings. That's tax affected to come down to a $51 million result, or $0.09 per share. And again, we do the same math for the full year, starting with the 261 million, reverse $304 million of unrealized mark-to-market gains booked in 2004, and then reverse out -- excuse me, add back $186 million of realized mark-to-market that had been previously recorded. Again, that yields $190 million, or $0.35 per share. I would just like to point out that in the appendix to this presentation, we do have a detailed reconciliation in compliance with Reg G that you should take a look at.

Next slide, number 14, let's review a summarized income statement and its key components. As you can see, segment profit of $398 million for the quarter, nicely improved over the prior year, and 1.4 billion, again improved over 2003. Net interest expense is sharply lower as a result of the aggressive debt reduction program. Debt retirement expenses were very significant during the quarter and during the year, as we reduced debt by just about $4 billion. Moving down to the bottom line, the $73 million net income, again is compared to the net loss in the prior year, and for the full year the 164 is compared to a very large net loss.

The next slide, number 15, will review segment profit for the fourth quarter, summarizing the business units, as well as the totals. And I would just guide your eye to the segment profit line there. You can see the $398 million of segment profit as compared to the prior year quarter of 153. And then on a recurring basis, the 329 billion as compared to the 267 million in the prior year's quarter. Adjusting out mark-to-market effects, this year 29 million, and the prior year 60 million, would again yield segment profit after mark-to-market adjustments of 300 million as compared to 207 million in the prior year. The next slide, number 16, take a look at the full year segment profit analysis, using the same format. And again, on a reported basis, the 1.406 million, as compared to the 1.39 billion, again favorable progress. And then on a recurring basis, 1.38 billion this year, and again with progress over the prior year. Mark-to- market adjustments for the current quarter total $118 million, and for the prior year $253 million, so segment profit after market-to-market was 1,263,000,000 in the current quarter as compared to $891 million in the prior year's quarter, again a sharp improvement.

Next slide, number 17, summarizes the drivers in segment profit after mark-to-market adjustment quarter-over-quarter. The overall improvement of $93 million is driven principally by strong Midstream margins and performance, and we'll hear more about that, as well as other drivers in each of the business unit presentations. The next slide, number 18, also summarizes drivers of change in segment profit after mark-to-market for the full year. The overall improvement here of $372 million is driven principally by Midstream and Power, and again we'll here more about those as we walk through the presentation. The next slide, number 19, let's review cash and cash flows. And I'll just walk down the fourth quarter here first. Again, cash flow from continuing operations was very strong in the fourth quarter, at 404 million. We received proceeds from asset sales of about $40 million. As you see, the assets sales program is just about ended. We issued $75 million of debt related to Transco, to try to get its capital structure just right. On the debt retirement front, we retired $230 million of debt during the quarter. We invested $249 million in capital. We paid $33 million of premiums and issuance costs on early debt retirement, and we paid out $28 million of dividend to end the period with $930 million of unrestricted cash. I would point out that our current cash balance is $1.332 billion, a sharp improvement since the end of the year, about $400 million.

And let me say a few words about the change since the end of the year. First, we paid off -- we paid down on a scheduled basis $200 million of debt at Transco that was scheduled and maturing. We paid $99 million associated with interest payments. And then sources of cash side, we had proceeds from the final settlement of the Feline PACS, totaling $273 million. And I would note that we issued 11 million shares in February to conclude that transaction. We received about $150 million on the sale of a note and the cancellation of a contract. The balance represents cash flow from operations and changes in margins, again, $400 million increase since the end of the year. Our cash balance, at $1.3 billion, includes about $160 million of international cash, and $180 million which we've earmarked for the settlement of a matter of litigation relating to the Alaska Quality Bank. The balance of about $1 billion is available for general corporate purposes, and we'll certainly be reviewing where we allocate any excess cash that we may have. And let me just remind you that we believe that it's important for us to maintain $500 million to a $1 billion of cash, as well as a line of credit at all times. So we're at the high end of the range in terms of unrestricted and available cash.

The next slide, number 20, I'll highlight some debt changes and some debt components. Again we started 2004 just under 12 billion of debt, with a 7.7 effective rate. We reduced debt during the year by $4 billion, ended the year at 7.962 billion, with a 7.4 percent effective rate. As I mentioned, in January we paid down an additional 200 million of debt, which puts us today at 7.762 billion, which is principally fixed rate debt. On the next slide, 21, let's review 2004 results versus guidance, and I'll just run down to the net income line. And you can see net income of 164 million, which is just above the top of our prior range of guidance, or $0.31, again just above the prior range guidance. On a recurring basis, $261 million, again which is above the prior range of guidance, or $0.49. And then finally, and again most importantly, EPS recurring after mark-to-market adjustments of $0.35, which is near the top of our prior guidance.

On the next slide, number 22, we summarize reported recurring and recurring after mark-to-market adjustments by quarter for you're reference. And I think as a result of our introduction of this recurring EPS after mark-to-market adjustments, earlier this -- in late November, 2004, after our decision to retain the Power business, I think there may have been some confusion, and we're looking to try to clarify that somewhat. I would also just like to mention that the share count went up from the third quarter to the fourth quarter by 56 million shares, as it relates to the Feline PAC settlement totaling 33 million shares, and about 28 million shares related to a convertible debenture that are now in the money. And as I mentioned earlier, during February, we issued an additional 11 million shares, the final component of the Feline PAC transaction. And with that, I'll turn it over to Ralph Hill.

Thank you, Don. Today for the E&P side I'm pleased to discuss with you our fourth quarter results, and this is on slide 24, highlight our 2003 accomplishments, including our very strong 2004 248 percent reserve replacement rate, and our volume growth of 25 percent, discuss our production growth, and also our growth metrics, and then provided you some early comparisons on the industry versus our performance in terms of production growth, and finally development costs. And I'll end with our guidance and our key points. Overall, we look forward to continuing our efforts to increasing the pace of drilling of our extensive development drilling inventory in 2005 and beyond. Turning to slide 25, keep in mind we were still fully hedged during the fourth, but this still turned in a very strong quarter. Our fourth quarter '03 to fourth quarter '04 increase included a volume increase of 25 percent, a recurring profit increase of 50 percent, and in this profit increase, over 80 percent of that was due to volume growth. There was very little price impact in our profit growth from quarter to quarter. I think that reflects our successful drilling program. Looking at sequential quarters, our volumes increased by 5 percent from third quarter '04 to fourth quarter '04. There was a small variance of about 1 percent added to the fourth quarter, 7 a day or 1 percent, that increased those volumes. It was just an adjustment from the '03 -- or from the third quarter to the fourth quarter. Still volumes increased at least 4 to 5 percent. Recurring profit increased 7 percent, and our overall hedge impact was negative $91 million in the fourth quarter.

Looking to slide 26, we had a strong 2004 reserve performance, as discussed in the press release that went out earlier this morning. Our domestic prereserves are up 10.5 percent to 3 Tcf. Our total prereserves, including the international, is 3.2 Tcf. Reserve replacement rate of 248 percent. We had a 99 percent success rate again. We drilled 1,384 successful wells, out of 1,395 total wells. And we moved 451 Bcf to the proven category. This continues our successful trend, as shown as the very bottom of this slide, where we moved about 1.2 Tcf to the proved category from the last 3 years, and as I mentioned before, we expect this trend to continue. Slide 27, other accomplishments. The fourth quarter production as mentioned, was up over 121 million a day, since the the fourth quarter of '03. Piceance is a major driver in that, of 97 million a day increase, or 61 percent increase. On the Powder, our production was essentially flat, and we do expect, as I mentioned, it to decline slightly this year. But the Big George continues to increase. Our Big George gross production was up 5 million a day, or 7 percent from the third quarter, to about 73 million a day gross, and 30 a day net.

Overall, the Powder is producing as an industry about 900 million a day, with the Wyodak at about 720 million a day, and the Big George, the balance of that. The key is the Big George has increased over 50 percent in the the last year. More Big George drilling should offset Wyodak decline as we move closer to the 2006 and 2007 timeframe. Looking at -- as I mentioned, we had a very strong reserve performance. Our F&D costs at $0.92 just for 2004 only, was much better than what we were anticipating the industry average has, and I will have another slide on this in just a minute to discuss. We had a record capital program success we executed, and look for that to increase about 25 percent in 2005. We had additional Piceance down spacing, where we actually prepared in late 2004, and it was actually approved on February 14th of this year. 4,680 additional acres, bringing 350 new bottom hole locations. So that was actually prepared and submitted late '04, and approved this month. We initiated drilling in 2 new Piceance areas of Trail Ridge and Ryan Gulch as I mentioned at the November 30th tutorial. We have 2 wells on-line in the Ryan Gulch area, and 1 completing. We're pleased with our progress, and look forward to additional drilling in Ryan Gulch this year, and additional production history as we move into this area.

On Trail Ridge we had 4 wells flowing to sales, same as the Ryan Gulch area. We do look forward to additional drilling and production history. There's nothing that we've seen that would discourage us from these areas, and we probably will look to expand our activity in these areas. And also, our groups continue to do things the right way. We received environmental awards from the EPA in the Piceance for air sampling, from the Colorado Oil and Gas Conservation Commission in the Piceance for noise mitigation, and from the BLM in the San Juan Basin, we received their Cooperative Excellence Award. Looking to slide 28, a breakdown of our reserves. From 2002 to 2003, our reserves are up about 10.6 percent. And 2003 to 2004 our reserves were up 10.5 percent, as we mentioned. As you can see this year, we a had small acquisitions of 23 Bs, we produced 191 Bcf, and our additions and revisions on a net basis were 451 Bcf, which totaled the approximate 3.0 Tcf. Very strong reserve replacement year, and we look to continue that trend.

Slide 29. I presented this at our E&P forum in late November of 2004. This is updated for our year-end reserves of 3.0 Tcf, and this is just the domestic reserve side. We -- please note that 99 percent of our proved reserves were audited or prepared by Nether and Sule and Associates (ph). It's actually 99.6 percent, I think. Or in the case of the WTU, the Royalty Trust, Miller and Lance. Also, please refer back to the oil and gas reserves disclaimer that's in the front of the presentation, and please note that this excludes new opportunities, such as Trail Ridge, Ryan Gulch, and Red Point that we talked about in the November forum. Our reserve tolerance -- the reserve tolerance for the auditors is 10 percent, as you know in the industry standard, and we were way below that guideline at 2.4 percent. So we were essentially right on with our outside auditors. On a proved basis, our proved undeveloped decreased as a percentage of our reserves, from 57 percent in 2003 to 55 percent in 2004. But what I would like to stress is that we have a very repeatable drilling inventory. We moved 1.2 Bcf from the probable category, which you can see in this pie chart. We are estimating we have total proved problem possibles of approximately 7 Tcf, so we have moved about 1.2 Bcf of that from the probables to proved categories the last 3 years. And our goal, obviously, is to increase our drilling pace.

Looking at slide 30. Our volumes continue their strong growth pattern. We are now above the production levels we had pre the 2002 sales, and this is almost extensively and completely done with organic drilling of our existing positions. Our goal is to increase our production as efficiently and rapidly as possible. Early this year, weather has not cooperated with us as much as we would like it to. It has affected our volumes in the first quarter somewhat so far. We've had record rainfall and muddy conditions in the Piceance and the San Juan Basin, and also very several, very cold periods in Wyoming for the Powder River. It has caused our volumes to fall off a little bit in the first quarter, but we do expect to be able to catch up and meet our volume totals targets for the year. We are fortunate to posess a vast and growing inventory of opportunities in the Piceance Basin. On November 30th, we estimated to you that we had over 3,000 locations in the Piceance. We're very confident in this level, and we also believe that we will increase our drilling at Trail Ridge and Ryan Gulch, and they have a substantial number of locations which would increase this 3,000 location number.

The greatest value we have to Williams is to increase our pace of drilling in these locations, as quickly and as efficiently as we can. And in order to accomplish this, we are looking everywhere we can for contracting additional rigs. But we are doing it with the right people. We are looking at both existing rigs and new builds. We added 1 rig in December of 2004, really essentially at the very end of December of 2004, which brought us to 13 in Piceance. And we're going to add 2 more rigs, we believe, this year; 1 in mid-year, and 1 late third quarter. We also are working very hard to achieve substantial rig increases the latter part of this year and early next year. The reality of the rig market is, it will be later this year or early next year when these large increases will occur, and when that happens we obviously will keep you informed and let you know our rig count.

Slide 31, looking at our growth metrics, we do expect to continue our rapid growth as we've mentioned during this guidance period, and also beyond. We've updated this slide to show that as our volumes increase, the capital we required as we call on the slide, volume maintenance capital, and that is the level of capital required to keep our volumes flat with the previous year's. On this slide, you can see that in '05, '06, and '07, we are estimating our volume maintenance capital to be $200 million, $220 million, and $240 million, respectively. We believe it provides a significant growth capital, as you can see if you compare segment profit and DDA versus our capital, we are still generating cash. But as I mentioned, our goal is to obviously increase our drilling activity, what is represented here, but it too early to change these numbers, and we need to do that as we continue to add additional rigs. Slide 32, some early industry comparisons. 2 key points I would like to stress on that, is that it appears to be our analysis and other industry experts analysis that we see the domestic deliverability continues to decline, as this slide shows, and also our growth is virtually all organic, or all drilling of our existing positions. Some of the others on this chart as asterisked with the little footnote, did have major acquisitions which allowed them to increase their volumes. So we think we compare very favorable to what the industry did last year in our volume growth.

This list is a list of 20 of the top 25 U.S. gas producers who have reported fourth quarter 2004 results as of a couple of days ago. As you can see from the majors group, their production continues to decline as reported, and is down about 1.2 Bs a day or about 12 percent. The independents that have reported that we have tracked so far, production is up slightly by 0.45. Overall as you can see, we are down, the people who have reported so far, by about 4 percent, or about almost 750 million cubic feet a day. I stress once again, our growth is organic. Other companies are that are close to our growth way, and 1 is actually above, did have major acquisitions to get to theirs. Our sources are Evaluate Energy website, an also company press releases from the various companies on this list. Another outside source that looks at domestic deliverability, Pira, has reported of the 70 companies they've looked at so far, that year to year production is down about 12 percent -- I'm sorry, majors production is down about 12 percent, and the overall U.S. production is down about 1.3 percent. So our numbers are roughly tracking, but again, just to stress that our growth was through the drill bit, and it does appear overall as an industry, the gas market remains tight.

Slide 33. Early indications on some finding and development costs. This has not, obviously been report for the year 2004. The chart we have on here is an RBC Capital Markets research comment from last year, where they tracked '01 through '03 finding and development costs, but I still think it's relevant to compare that to what we have. As I mentioned, our 1 year finding and development cost was $0.92 per Mcf. Our 3 year average cost, updated for '04 data, is $0.78 per Mcf. If you compare that to the industry rolling 3 year average for 2001 through 2003, the average F&D cost was $1.42. We expect that the industry average will increase, when you add in the new data for '04, so the 2002 through 2004 F&D costs should be higher for the industry than the $1.42 that we see, and well above our $0.78 cost that we have for the same period. So I again, I think we compare very favorably to the industry. There are some reports -- a recent industry report I saw, of the 8 large transactions in '04, range in the price range of $1.90 to $2.00 per Mcf. So obviously, if that level is added to last year's $1.42, you can see where the $1.42 will increase. So again, I would just stress that our $0.78 does includes our results from this year. The industry averages we put on here do not include '04 results, but we expect those to go, and we expect to compare very favorably.

Slide 34, updating our guidance for 2007, we did not change 2005 and 2006. As you can see, we expect continued strong growth, and also during this growth, our segment profit and DDA do exceed our capital expenditures. But as I've discussed several times, I think Steve has too, we're pursuing additional rigs, particularly in the Piceance. This guidance reflects 12 rigs in the Piceance. We have gotten to 13 as we speak, and we look to acquire a couple more that we know of this year, late third quarter, and late -- or mid-year and late third quarter. Also, as we acquire additional rigs, the additional ones we've talked about and the new ones we are contracting for, or are trying to contract for, we do expect to be able to strike a good balance of drilling in the Piceance Valley proper, and also do additional drilling in the Trail Ridge area and Ryan Gulch area.

Slide 35. Key points, we did have very strong reserve performance again. That's several consecutive years, or many consecutive years of that, which grew 10.5 percent. Our volumes are up substantially quarter to quarter. We continued to expand our development drilling activity. Piceance is our primary growth driver, and we do intend to try to increase our activity. We have a decreased hedge level as shown on the previous slide, which should increase our upside to price exposure this year. A long history of high drilling success. Once again, we're over 99 percent drilling success rate in 2004. Our investments, as you know, are short time cycle, fast cash returns. We have consistently maintained our top quartile costs and efficiency position, and we have done that again in '04. Our inventory provides significant, significant levels of proved undeveloped probables and possibles, and we look to get to that as quick as possible. And we are excited about our new Piceance Basin area opportunities at Trail Ridge and Ryan Gulch. Thank you for the opportunity to share this with you today, and I will turn it over to Alan. Thank you.

Thanks Ralph, that's a great story. And good morning, everybody. I have the privilege this morning of presenting the results of the best financial year ever for our Midstream group. By just about any facet you can measure, our organization delivered outstanding financial results. Turning to slide 37. Here are the bottom line results for the quarter and for the year. In 2004, we produced $550 million of segment profit, and after accounting for the $94 million extraordinary gain from the Gulf Liquids arbitration award, the gain on our ethylene transport and storage business of about $9 million, both which were offset by asset impairments and depreciable life adjustments, totaling $24 million, we finally get down to a net recurring number of $471 million for the year. So our improvement in recurring segment profit from 2003 to 2004 totals nearly $190 million. This increase was driven by $60 million in better commodity prices, and $45 million in higher NGO equity volumes. We also realized recurring operating profit of $19 million in 2004 from our Canadian and Geismer olefin operations, instead of the $46 million loss that we realized in 2003 from the same assets. This improvement came from improved pricing for ethylene and propylene, but also from much better plant efficiencies at our olefins extraction plant in Ft. McMurray, Alberta Canada, and that was primarily as we go through the start-up phase of that in 2003. And we've worked the bugs out of that, and that facility is operating nicely now. A very similar explanation exists for the $87 million improvement from fourth quarter '03 to fourth '04, and obviously we are very excited to deliver you these results from a net PP&E base of approximately $3 billion.

Moving to slide 37. Sorry, 38. Despite the selloff of over $2.2 billion in assets since 2002, we have continued to increase our recurring earnings, and hit an all time record in 2004 by delivering this $471 million, and an additional $79 million in 1-time events. Certainly the commodity markets are were the single largest driver to these outstanding results. However, please don't underestimate the operational effort that this organization mustered to capture these opportunities. We physically produced a record volume of domestic natural gas liquids for both Williams and our customers, totaling over 164,000 barrels per day. We sold a record amount of equity barrels. We connected a record amount of wells for our customers, for as long as we have tracked them. We started up the fourth train at our world class facility in Opal, Wyoming, and we commissioned the Devils Tower oil and gas pipelines in water over a mile deep. And last but not least, we improved the safety of our operations with some intense focus in this area. This was all accomplished while dealing with the aftermath of selling off more than 40 percent of our asset base, and an associated 50 percent reduction in our work force. Hurricane Ivan got its licks in as well, by delivering an unprecedented blow to our Eastern Gulf of Mexico facilities, so we had plenty of adversity standing in between us and these results. But a very dedicated and loyal work force overcame all of this to deliver a much better bottom line than we had predicted this time last year.

Moving to slide 39. This slide highlights the increased net liquid margins that we realized for equity production of natural gas liquids. Here, equity production refers to those gallons we produce and sell from all of our consolidated domestic processing plants. So for instance, this would not include our discovery Larose plant, because we do not consolidate that. This is where we take title to these liquids through either keyhole processing or percentage of liquids contracts. As you can see, this margin increased from $0.11 in 2003 to an average of about $0.15 in 2004, and you can see the extreme margin that we saw there in the fourth quarter of '04, as well. Also highlighted by this graph is the dramatic increase in our equity volumes, depicted here by the line graph that you see. Our total equity gallons increased from 1 billion in 2003 to over 1.4 billion in 2004, right at a 40 percent increase. Looking forward, we are projecting roughly 1.5 billion gallons of equity volumes over the next several years, and these increases are coming from higher inlet volumes to our western plants, richer volumes coming out the deep water gas that's hitting our Gulf of Mexico plant, and then finally the assumption of (inaudible).

Please standby while we reestablish contact with the speakers. Please standby and do not disconnect.

-- mid-point guidance by $50 million. The increase in fee-based business is coming primarily from an expansion that we have in our Wamsutter, Wyoming, gathering operations, as well as increased deep water revenues. Moving on to slide 41. Many of you have inquired about our deep water business and what our prospects for continued growth look like in these assets. We continue to be excited about both the near-term performance of these assets and the long-term potential for this large scale infrastructure play. We really have 2 ways that we expect to see our deep water earnings grow. First, we expect additional drilling to bring tie-backs to our exiting infrastructure. The most notable impacts in this area will come from tie-backs to our Devils Tower spar, and just to give you some examples there, first of all, Dominion and Pioneer Natural Resources, who -- Dominion is the operator of Devils Tower, are currently working to tie in the Triton and Goldfinger prospects. Prospects like these can add up to an additional $50 million of incremental operating profit per year, on top of the revenues that we're already seeing from the Devils Tower field proper. Profit from these 2 prospects is included in our '06 and '07 plan here, and we expect these 2 prospects to come on in the fourth quarter of '05.

These individual additions are, and will be lumpy, and these fields hold large amount of reserves, but deliver very quickly and decline very rapidly. Our infrastructure is positioned to aggregate and serve just this type of discovery, so as 1 field blows down, another prospect is being tied in. This really is not so different than the conventional onshore gathering business, except it is much lumpier, as the package of the business are much larger. Additionally, we are in negotiations for our second tie-back to Devils Tower. This prospect is expected to bring in much higher levels of profit than the first prospects with Triton/Goldfinger. We would not expect this prospect, however, to begin until 2008, and we also are pursuing numerous other prospects on this map that you can see here with the green dots, that we think the Devils Tower infrastructure is well positioned to serve. These prospects, all of these tie-backs that I mentioned here, require very minimal capital, if any, on our part.

The second type of opportunity that we're pursuing in the deep water is new expansion investments. We're getting close to a major commitment for our discovery system that will enable this investment to extend out into even deeper waters, and expose it to some very large reserves that we're excited about. Several other large scale projects requiring this type of stand-alone investment are being pursued at this time, and none of the second type of deep water growth is in our projections. So nor on either capital or on a profit basis do we have any of these large prospects in there. We do, however, as I mentioned earlier, have the tie-backs for Triton and Goldfinger in our '06 and '07 guidance.

Turning to slide 42. While we are certainly excited about our 2004 performance, we realize you really want to know what the future holds. So here is our attempt at that. First of all, for the fourth consecutive quarter, we are raising our near-term guidance for Midstream. In 2005, we are raising the mid-point of our guidance from 360 million to 390 million. This is almost all based on the margin environment we are experiencing, both NGLs and our olefins businesses, in the first quarter. This is is partially offset by the Suncorp refinery fire that has reduced volumes at our Fort McMurray olefins extraction plant and we are expecting that to come back up in the third quarter, but that will have some impact on our olefins business, and that is baked in here.

Our 2006 guidance shows continued growth from the deep water, and the benefits of our expansion capital in 2005. The additional lift in 2007 comes from the Ft. McMurray expansion capital which is projected to be spent in 2006. Some upsides that you would see to this forecast, would first of all be higher than an $0.085 per gallon that is embedded in all 3 of these years right now. Higher than the CMAI forecast of the ethylene and propylene margins which are in here, and then finally the acceleration of deep water tie-backs that are currently constrained by a fairly tight drill ship market for the deeper prospects. The downside of course, would be the flip sides of what I just mentioned, and with the most damaging would probably be an overall lowering of commodity markets which might retard drilling and our margins. Higher gas prices relative to crude oil would cause short term reduction, but a long term increase in our fee based businesses, our gathering services would likely be increased.

Turning to slide 43. This is a very informative slide, so let me explain the graphics first here. First, the taller solid blue bar, is the segment profit plus DD&A from our base business. The light blue bar stacked on top of this, is the amount of increase coming from our expansion capital. And then the short stacks on the left show our capital, with the top green stack being our forecasted expansion capital. And this is averaging about $57 million per year during this plan period. And then the bottom rungs on the capital side there, are the well connect and maintenance capital. The well connect capital being that required to offset the declines on our base assets, and then the maintenance capital that's required to provide reliable and safe services to our customers, and this runs at about $65 million a year during this period.

So all of this depicts our base business continues to throw off significant free cash, even with normalized margins. It also shows the increases coming from our expansion capital investments, beginning in 2005. And that is basically taking the green capital there and looking to the light blue that is the additional earnings coming off of those investments. And finally it shows a steady increase in our base business, with NGL margins held steady at $0.85 per gallon throughout this period. Really the only thing wrong with this picture is a limited reinvestment into this business. And we certainly hope to cure this with new deep water projects, but we will be patient and disciplined in the application of such at-risk capital. Finally, all of this free cash flow is being generated by about $3 billion in net PP&E that actually dwindles during this period, as we are only investing about two-thirds of our depreciation each year. I think this is a great story, and really does stress the strong free cash flow we are generating out of this business.

Moving to the last slide here on the key points. I hope you'll take away the following. First, the more obvious of course, is our record year of $471 million for our recurring, plus a bonus of $79 million in nonrecurring, yielding a total of $550 million for the year. But we also had a great year with operational performance with some of the statistics that I offered up. And we continue to deliver very strong free cash flow, and even an increasing base business with limited expansion capital. We are very excited about the business plans in our deep waters, I explained, and we expect to continue to see that grow even beyond 2007, and feel like we are very well positioned there. And then finally, this performance comes from a continued dedication to a very clear strategy. We're very focused on having the premier assets and growth base. We feel like we do, and we'll continue to invest in those assets. And then we expect to be able to attract volumes through being the most reliable provider of service in this industry, and are exited about the growth prospects that will come from just being able to offer that. That's all I have. I'm going to turn it over now to Phil Wright, the leader of our Gas Pipelines business unit.

Thank you, Allen. Those are phenomenal results. I'm very excited to be a part of the team at Williams Gas Pipeline. In the short time I've been in my new roll, it's become quite clear that my predecessor, Doug Whisenant, turned over the helm of a very well run organization, and I think arguably the best pipelines in the country. As you have seen from our results, the Gas Pipelines team has been quite successful at trimming operating expenses, limiting capital to appropriate maintenance levels, continuing to deliver highly reliable, cost-effective service to our customers. Both Transco and Northwest Pipeline are nearly fully contracted. We serve large customers, with investment grade credit ratings, generally. I think the very favorable feedback we've received in response to our most recent customer surveys, reflects both the high level of committment we have to serving our customers, and and our resolve to maintain our low cost provider status.

I'm on slide 46 now. The segment profit slide here reflects both reported and recurring segment profit for the Gas Pipeline segment, which includes the results of Northwest Pipeline, Transco, and our 50 percent ownership interest in Gulfstream. The final results for 2004 turned out to be better than we had originally forecast, due in part to higher than expected earnings on Gulfstream from additional interruptible transportation revenues, better short term firm transportation, and park and loan revenues at Northwest Pipeline, higher than expected market area revenues on Transco, and lower overall operating expenses, including SG&A, cost of gas, DD&A, and operating taxes. Specifically, we reported segment profit of $586 million in 2004, which compares to $555 million in 2003. Adjusting for the few nonrecurring items in both 2003 and '04 that we've previously disclosed, and are included on this slide, our recurring segment profit of $595 million was $13 million ahead of last year's results. The net improvement of the fourth quarter of '04 versus the fourth quarter of '03 includes $6 million of lower SG&A expenses, and $3 million of increased Gulfstream earnings. While the year-over-year net improvement includes the full year benefit of Transco and Northwest Pipeline expansion projects, totaling $37 million, $14 million of higher interruptible transportation revenue, partially offset by about $18 million of higher net expenses.

Moving to slide 47. This highlights the major accomplishments for Gas Pipelines during the fourth quarter of 2004. On November 10th, Northwest Pipeline place Everett Delta project in service, adding capacity of 113,000 decatherms a day at a cost of $26 million. This was a somewhat unique project, in which the customer funded the construction of this lateral. Northwest Pipeline will operate the line for 5 years, at which time will turn the lateral over to the customer. In return, the customer extended several long-term contracts totaling over 300,000 decatherms a day for 5 years. At a time when capital was in scarcer supply at Williams, this project allowed us to serve a large customer's need, while at the same time conserving cash. Truly a win-win for both Williams and the customer's perspective, and a reflection of the creative work of our commercial teams. Also during the fourth quarter, Northwest Pipeline filed with the FERC for the replacement of capacity of a segment of 26-inch pipeline in Washington. This project encompasses abandonment of 268 miles of 26-inch line, replacement with 79.5 miles of 36-inch pipeline between Sumas and Washougal, Washington, plus a net additional addition of 10,760 horsepower of compression. These measures will replace most of the 360,000 decatherms a day of capacity of the 26-inch pipeline be to replaced.

Pending FERC approval, the construction will principally occur in 2006, with a projected in service date of November 1st, 2006. The cost of the project as outlined in our FERC filing, is $333 million. All of the transmission capacity being replaced is reserved under long-term maximum rate, firm transportation contracts. Costs associated with the capacity replacement project will be rolled in to the Northwest Pipeline customer rates in the next rate case. As well, and in the category of doing things the right way, we received the Environmental Excellence Award for work on the Evergreen Project. This award, given by the Association of Washington Business For Land and Wildlife Conservation Measures, is given to companies who go beyond the requirements of the law to improve the environment. The Evergreen Project involved the installation of 28 miles of large diameter pipeline in environmentally sensitive Western Washington, and included 26 stream and river crossings, and impacted 23 acres of wetland habitat.

Switching from west to east, Transco set a peak day delivery record of 8.7 million decatherms which surpassed the previous high of 8.3 million decatherms in January of 2003. While this won't impact our financial results, it certainly serves to highlight the reliability and flexibility of the Transco system, as well as the strong capability of our people who made that happen. Another event which is not on this slide, but is certainly noteworthy, is the GSX Project. In December, we, along with the co-sponsor of the GSX project, British Columbia Hydro and Power Authority, agreed to end plans to construct the $209 million pipeline across the Strait of Georgia to serve electric generation facilities on Vancouver Island B.C. While we'd have preferred that this project move forward, the project was terminated with no exposure to Williams, as BC Hydro assumed full responsibility for all project costs.

Turning now to slide 48. In addition to the 26-inch line replacement project at Northwest Pipeline, I'll highlight a couple of projects on Transco that we're focusing on during 2005. First is a central New Jersey expansion filed with the FERC in August of 2004, and approved by the commission earlier this month. This expansion will add 105,000 decatherms a day of firm natural gas transportation service to South Jersey Gas, providing service to more than 311,000 customers in southern New Jersey. This requires adding about 3.5 miles of new 36-inch pipeline along Transco's existing system in Burlington County, New Jersey. The project is expected to cost $13 million. Construction is scheduled to begin this summer, and we anticipate completing by November of this year. The second is our Leidy to Long Island expansion, which will provide additional transportation capacity of 100,000 decatherms per day of new capacity from a storage and transportation hub in Leidy, Pennsylvania, to delivery points in New York and New Jersey. In December of 2004, the FERC granted our request to initiate a prefiling environmental review. We expect to file an application for a certificate of public convenience and necessity with the FERC in September of 2005. On February 10th, we received and executed precedent agreement from a customer willing to relinquish a portion of their transportation under an existing contract, to help facilitate a lower overall cost for the new expansion. Their relinquishment reduces the scope of facilities needed to provide the capacity required by the market. Accordingly, the estimated capital cost for the project has been reduced from $143 million to $103 million.

I'm now on slide 49. On February 1st, 2005, Gulfstream placed into service a 109 mile, phase ll natural gas pipeline extension, expanding it's reach across Florida, and facilitating the increase of long-term firm service by 350,000 decatherms a day. Gas began flowing to Florida Power and Light the following day. With the completion of this project and the addition of the related capacity under the Florida Power and Light contract, Gulfstream, a 1.1 billion cubic feet a day line, currently has over 700,000 cubic feet a day of capacity contracted. Thereby increasing long-term capacity sold from 28 percent to 64 percent. While we still have considerable capacity to sell on Gulfstream, with demand growth projected to be 7 percent per year for the Florida market, we're optimistic about the future of this system. Florida is one of the fastest growing gas markets in the U.S. This is driven primarily from new gas-fired power generation. Electricity demand in Florida is increasing at over twice the national average. On a full-year basis beginning 2006, phase ll will contribute approximately $72 million of new FT revenues, firm transportation revenues, related to the Florida Power and Light contract. This revenue will be partially offset by $12 million of additional expenses, primarily DD&A, and ad valorem taxes. In addition, there is assumed to be additional interest expense from any new leverage that the management committee decides to put on Gulfstream. The amount of interest will vary depending upon the amount of additional debt and the associated interest rate. Obviously, Williams will share 50 percent of this net amount. Since the contract does not kick in until May of 2005, the results for 2005 will include only a partial year benefit, and this benefit will be mostly offset by the higher interest cost of having the full balance of of the loan outstanding. However, it's noteworthy that that additional leverage will provide cash to Williams.

Turning now to slide 50. With the level of capital expenditures required at Northwest Pipeline for the 26-inch line replacement project, we anticipate filing a rate case in July 2006 to be effective January 1st of 2007. Northwest Pipeline has been in constant contact with its customers regarding this issue. While we anticipate that this filing will put upward pressure on our rates, we firmly believe that we will remain the low cost transporter in our major markets. When this rate becomes -- rate case becomes effective, it will have been almost a full 10 years since the current Northwest Pipeline rates became effective. Transco will also be filing a rate case to be effective March 1st, 2007. As a result -- excuse me -- as a part of the settlement agreement in Transco's last rate case, which was effective 2001, we're required to file a new rate case to be effective no later than March 1st, 2007. This case will be designed primarily to collect increased operating expenses and depreciation associated with nonexpansion capital, such as equipment needed for Clean Air Act compliance.

Slide 51, please. Clearly, 1 of the more significant developments in North American natural gas markets over the next decade will be increased importation of liquified natural gas, or LNG. Our pipelines are exceptionally well positioned to accommodate these new suppliers. Expansions of existing LNG import facilities should provide opportunities to expand our Transco system downstream of the co-point Maryland import terminal, and along the Gulf Coast corridor as well. LNG importers should find several features of the Transco and Gulfstream systems very attractive. First, Transco serves large and growing markets throughout the Southeast, Mid-Atlantic, and Northeastern seaboard. The gas-fired power generation market in Florida, served by our Gulfstream system, is growing at a rate of twice the national average, as I mentioned a moment ago. Secondly, while obtaining all of the market permits for an LNG import terminal is no mean feat, regardless of what part of the country you're seeking to locate it, there are a number of features that make the Gulf Coast a more LNG friendly place to locate a terminal. Among these are the proximity to processing plants and markets for gas liquids, which will be contained in many of the new LNG source streams. 1, pipeline and gas storage infrastructure to facility blending of high BTU content gas is prevalent on the Gulf Coast. And 3, a significantly less hostile political environment. Obviously, with their Gulf Coast presence, Transco and Gulfstream are in the fairway of where new LNG import terminals have the highest likelihood of being built.

Thirdly, Transco's size, strategically located storage facilities, interconnectivity to major gas pipelines, and unusually large swing capability make it attractive for receipt of LNG shipments. And finally, we're the low cost provider to large and diverse markets. Our low rates will yield advantage for us in attracting LNG shippers. The challenges we'll face are in the area of gas quality and interchangeability. End users of gas in North America are accustomed to consuming a lower BTU content gas than other areas of the world, such as Japan, that have traditionally been supplied by LNG. Swings in the BTU content of gas streams, caused by the receipt of big cargoes of high BTU LNG, would wreak havoc on end users, whose flame control and furnaces are designed for steady, and generally lower, heat content gas. Maintaining reliability and flexibility of supply may prove challenging, but may also provide some opportunities, as storage infrastructure may need to be expanded to accommodate surges in volume, and help customers manage physical supply risks. While I've not specifically mentioned LNG in the regions served by Northwest Pipeline, we enjoy most of the advantages for Northwest noted for our Gulf Coast pipelines. The extent LNG developers in the Pacific Northwest are successful in overcoming permitting challenges, are low cost service to all of the major cities in that region, should prove attractive to LNG importers in the Pacific Northwest, as well.

Moving to slide 52, please. Imports of of LNG to the continental U.S. reached a new record of 652 Bcf in 2004, about 27 percent higher than the 507 Bcf delivered in 2003. At 462 billion, and 120 billion cubic feet respectively, Trinidad and Algeria were the largest suppliers of LNG to the U.S. The current capacity of the 4 existing terminals is 2.7 billion cubic feet a day. Of the 4, 3 have planned capacity expansion in the fear future. Dozens of new terminals have been proposed in the U.S., Canada, Mexico, and the Bahamas. This is far in excess of the facilities needed. We expect a half a dozen or so to come onstream in 2008 to 2010. Several new terminals are likely to be located along the U.S. Gulf Coast, 1 or 2 in Baja, possibly the Bahamas, and perhaps eastern Canada. This slide provides an excellent picture of where our assets are situated, relative to the LNG import facilities we believe are the most likely be to built.

I'm now on slide 53. Material changes in year-over-year earnings for our regulated pipelines are, for the most part, driven by either incremental expansion projects which go into service during that year, or rate cases which become effective during a particular year. We're expecting neither of these during 2005 or 2006. As well, we expect higher overall costs due to general inflation pressures. Thus, we anticipate that our earnings will be flat to slightly down until 2007, when we begin to realize the benefits of our rate cases. You may note that we've increased the range of our segment profit guidance in 2005 and 2006. Prior guidance is shown on the slide in italics. In 2005, higher revenues at Gulfstream received under the new FP&L contract, will be partially offset by higher DD&A, and ad valorem tax, as well as by interest on the construction loan for the entire year. Depreciation in 2005 should be higher than the prior year, even if you adjust for the favorable adjustment of $9 million recorded in 2004. Operating expense at both Transco and Northwest Pipeline are expected to be higher due to higher labor and benefits, higher corporate costs, and maintenance work related to right of way, and facility repairs, as well as higher ad valorem taxes.

Included in our 2006 range are a refinancing and the placing of additional leverage at Gulfstream. This will result in additional interest expense, and thus will reduce the 50 percent share of pretax Gulfstream income which is included in our segment profit. Depending upon the amount financed and the interest rate assumed, this could negatively impact earnings by 10 to $20 million. However, I should note again that this financing will serve to provide substantial cash to Williams. In '06 as well, we expect to see higher depreciation and ad valorem costs due to maintenance projects, which will be placed into service in 2005 and 2006. Turning to 2007, we expect segment profits to recover to a range of 575 million to 635 million as our Leidy to Long Island project is expected to be placed into service late in the year, and will have the benefits of the new rate cases I discussed a moment ago.

Moving now to slide 54. In an effort to provide detail around our capital needs, we've once again broken our projected spending into 4 major categories. As you can see, our normal maintenance spending should fall in a range around $100 million each year, with higher levels projected in 2005, and slightly lower levels expected in 2007. Included in the regulatory compliance category, are expenditures related to the Clean Air act and Pipeline Safety Improvement act. Clean Air Act spending begins winding down toward the end of 2006, as does the spending required under the Pipeline Safety act. We anticipate spending required for compliance will be more heavily weighted toward the front end. And we expect all costs under both acts to be fully recovered beginning with our 2007 rate cases. We noted earlier, that Northwest Pipeline 26-inch replacement project was recently filed with the FERC at an estimated cost of $333 million. Finally, the expansion category includes the cost of the Central New Jersey project in 2005, the Leidy to Long Island project, most of which will be spent in 2007, and a small number of development projects in each of the years. Beyond that, we have no expansions included. It's noteworthy that the Gas Pipeline segment will flow substantial free cash for each of the years projected in this forecast. Even after funding the capital shown on this slide.

I'll move to a close now with slide number 55. Gas Pipeline continues its solid performance with the highest quarterly segment profit in 2 years. Preparation for the upcoming rate cases at Northwest Pipe and Transco is well underway. We're making substantial headway in completing the investments and programs necessary to comply with applicable laws, and continue to operate safely, responsibly, and reliably. Expansions along our Transco system continue, a reflection of both the strategic position of that system and high growth markets, and the efforts of our people to serve our customers. We are laser focused on maintaining our low cost provider status, and we expect to continue generating strong free cash flow and stable low risk earnings. Now I'll turn it back to Mr. Chappel.

Actually to Mr. Hobbs.

I'm sorry, Bill. I forgot all about you, Bill.

That's okay, Phil. Thanks, Phil, and good morning. As you've heard with other -- with the 3 natural gas businesses, they've had very successful year, and Power is no exception there. It's even more remarkable, our performance, when we consider the uncertainty that our employees faced during the majority of the year and the depressed SPARC spreads that we endured throughout 2004. And I think that's a real testament to the capabilities and the talent, the dedication of our employees, and I want to thank them. The fourth quarter was a good quarter for us, despite being a shoulder quarter in Power, and it capped off a successful year. It's also the first quarter we'll be reporting our financial results under hedge accounting, and as Don indicated, the mark-to-market impact of that was sharply reduced. Also, in our fourth quarter earnings, we have included losses due to liquidating interest rate positions, and losses with the roll off of gas positions that were previously put on in 2001. But our base Power business for the quarter and for the year remain cash flow positive.

Turning to slide 57, Don previously went through these numbers, so I won't reiterate them. But I would point out that you've noticed a lot of the noise from 2003 and previous years did not replicate itself in 2004, and reflects the progress we've made in dealing with a lot of peripheral issues. On slide 58, 2004, and recent accomplishments. Steve indicated we were successful and are very pleased with some early deals that we've been able to close. They are primarily located in the west and the northeast. The deals are risk reducing and create cash flow certainty. Primarily, they're resale of tolls, which is about as perfect of a hedge as we can get in the marketplace. And we also mentioned there we have a 650 megawatt capacity sale. The key point there is that is a capacity sale, and reflects the development of capacity markets, but also provides us upside in selling energy. Confidentiality provisions between us and our customers prevent us from going into more detail on these deals, and the impact, the financial impact of these deals, will be reflected in our first quarter numbers. Also as was previously mentioned, we had a very strong year from a cash flow standpoint. We were successful in reducing risk. We adopted hedge accounting, and thus reducing earnings volatility. We retained our work force, which is key in producing the future cash flows that we've committed to. And we were very successful in working with our E&P groups in ensuring that all their gas was flowing in these high priced environments, and that we maximized their net backs.

Looking at slide 59, which is segment profit after mark-to-market adjustment. The gross margin and segment profit was better than forecasted primarily due to a 23 million mark-to-market gain that Don referenced. To get a segment profit after mark-to-market, we back out the 23 million, and the 6 million from previously recognized mark-to-market, to get to the $73 million loss. And the variance from the $73 million segment profit after mark-to-market to the 54 million forecast, is due to $22 million loss in liquidating our interest rate positions. For the full year, segment profit after mark-to-market is impacted by the $62 million loss in interest rates, and a $20 million loss exiting the crude and refined products business. Turning to slide 60. Power stand alone cash flow for the quarter was 92 million, which was primarily due to the return of working capital. But the quarter also includes positive cash flow from our base power business as you'll see in a slide in a minute, and losses related to interest rates and 2001 gas positions, that I previously mentioned.

On slide 61, this a slide right out of our tutorial, and the key message is here is cash flow continues to track, both on a quarterly and on an annual basis, our forecast. Will make 1 note here, there is a correction to the slide. The estimated cash flows after SG&A for fourth quarter '04 actual is actually 56 million. And that's due to an increase in working capital from 37 million to 43 million, and that will be reflected in our website. Turning to slide 62. The segment guidance here is driven largely by -- segment profit guidance is driven by the adoption of hedge accounting, which we discussed in a previous call and our tutorial. We have made a change in 2005 segment profit due to mark-to-market earnings recognized in the fourth quarter, that now must be backed out of future periods. But the key message here is segment profit after mark-to-market and cash flows remain unchanged. On slide 63, I'll close with some key points, and that the power business continues to generate free cash flow, so it can be invested in our other business units. We have refocused and dedicated ourselves to getting back in front of our customers, with the message now that we're staying in the business. I think that's driving a lot of our early successes, and we are getting deals done. On a macro basis, we're seeing improved liquidity in the market, we're seeing SPARC spreads improve, and our credit position in the market is improving. And to be clear, our focus continues to remain on reducing risks through long term power sales. Potential factors impacting our guidance is clearly changes in SPARC spreads, capacity market development could be a significant upside for us, and obviously, if we're able to contract for new longer term megawatts, that could provide upside as well. With that, I'll turn it back to Don Chappel.

Thank you, Bill. Let's take a look at slide number 65, 2000 segment profit guidance. We'll just review a summary of that which each of the business unit leaders just presented. Looking at the first subtotal, following the 3 business units and the other rounding line, you can see a total there 1 billion 3, to 1 billion 5, up $50 million from the previous guidance as a result of both Midstream and Gas Pipelines raising their level of guidance. The next line down, Power, as Bill explained, the Power guidance is lower. However, that is offset dollar for dollar by the mark-to-market adjustment change, and the final line there, again, the most important line in our view, is the segment profit after mark-to-market of 1 billion 350 to 1 billion 650. Again, up $50 million as it was for the 3 business units, driven by the change in Midstream and Gas Pipelines. The next slide, number 66. Let's review components of our interest expense. As you know, we finished the year with just under $8 billion of debt, and that now stands at 7.8 billion. The interest on long-term debt ranges from 555 to 575. As well, we have amortization of discounted premiums, a noncash expense totaling $25 million. Our credit facilities, $1.8 billion credit facility, of which $1 billion or so is used for letters of credit, carries about a 30 to $40 million cost. And then interest on a variety of other liabilities totals 20 to $30 million. Backing out capitalized interest of 5 to $10 million, results in our guidance range of 625 to 660.

The next slide, number 67, let's just review the new earnings guidance. Again, we walked through segment profit, as well as net interest. The other, including general corporate costs of 90 to 125, I'd like to point out that that does include the costs of some investments that we're making, which were expected to drive costs lower in '06 and beyond. Those include re-engineering business process and implementation of a new single financial ERP, implementation of outsourcing, as well as SOX 404 compliance costs, and new costs associated with stock option accounting, of which we anticipate a half year impact in '05, and then a full year impact in '06. By 2006, these implementation costs, these investments we're making, will decline sharply. However, the costs of SOX 404, and the stock option accounting will continue. However, SOx 404, we believe will be at a lower level.

The next slide, number 68, review our 3-year segment profit guidance as the business units have already presented. Again, 2007 was presented in detail for the first time. Looking at the total line, you can see the guidance totaling 1 billion 50 million, to 1 billion 350 million, increasing during the 3-year period to 1 billion 375 to 1 billion 8. And the total after mark-to-market increasing from 1 billion 350, 1 billion 650 range, to 1 billion 525 to 1 billion 950. The next slide, number 69, let's review some additional items of guidance. Moving down below segment profit, you'll see DD&A in the 7 to 800 million range, growing to 8 to 900 million, as we invest more capital in the business. Cash flow from operations continues to increase from a range of 1 billion 3 to 1 billion 6 in '05, to 1 billion 6 to 1 billion 9 by '07. Capital spending of 1 billion to 1 billion 2 in '05, is reduced somewhat to 900 million to 1 billion 1 by '07. And let me just pause there, and indicate the reduction is in large part due to the fact that the Northwest Pipeline replacement project will be completed by the end of 2006, and therefore freeing up what was otherwise some capital spending. However, with the opportunities in our E&P business, our Midstream business, and perhaps in our Gas Pipeline business, we're hopeful of having some terrific investment -- reinvestment opportunities in those businesses. Free cash flow, as well, increases from a range of 3 to $400 million, predividend, in 2005, to 7 to 800 million by 2007. And again, very substantial free cash flow for the next 3 years, and particularly by 2007. And as you know, we're hunting for additional drilling opportunities, as well as deep water opportunities.

Effective tax rate of about 39 percent. We've included for the first time a detailed reconciliation of the tax rate in the appendix, and a cash tax rate of 3 to 5 percent for next several years, as we continue to utilize NOL carry forwards. The next slide, number 70, summarizes key drivers of changes in segment profit in CFFO from 2004 to 2007. This schedule is included for your information. However, in the interest of time, I'll move ahead. The next slide, number 71, summarizes 3-year capital guidance that was previously provided by our business unit leaders. And again, CapEx could be somewhat higher if we're able to drill more wells, or we win some new business. The next slide, number 72, 2005 to 2007 maintenance versus growth capital. This is a new slide which summarizes our growth versus maintenance capital, and I'll just kind of drill right down to the bottom there. You can see the bottom in 2005, maintenance capital, 610 to 695, including some very substantial investments in the Gas Pipeline business that we characterize as maintenance. Growing to 735 to 845 in 2006 as we replace that Northwest Pipeline section. And then following that replacement project, as well as a decline in Clean Air act and Pipeline Safety Act spending, we see capital -- maintenance capital declining to the 5 to $600 million range by 2007, and growth capital ranging from 4 to 600 million in 2007. And again that's before we consider any additional opportunities that we may have in E&P and/or Midstream and Gas Pipelines.

The next slide, number 73, also a new slide. It looks at ROC (ph) for 2004 and 2005. As you know, we adopted the EVA Financial Management System at the beginning of 2004. This ROC analysis tracks closely our EVA performance. However, it is much less complex. Therefore, we're providing this for you to give you some guidance of how we think about improvements in returns and improvements in EVA. As you can see, the capital base declined from about $16 billion in -- at the beginning of 2004, to 12.9 by the end of 2004. Average capital of 14.5 billion during the year. And is forecast to stay relatively flat, by the -- to the end of 2005, despite the very significant capital reinvestment in the business. As well, our returns improved from $695 million after tax and interest, to a range of 744 to 906, which yields return on capital employed of about 4.8 percent in 2004, and a range of 5.8 to 7 percent in 2005, an increase ranging from 20 percent to 46 percent. And I would also like to point out that this improvement is despite the fact that we're reinvesting significant amounts of capital into the business that won't yield returns until a later period. An example of that is the capital that we're spending if the pipeline repair area, as well as some of the growth capital we're spending in all of the business units.

The next slide, number 74, just graphically depicts our increasing financial strength, and I would just like to focus on the improvement, not only in cash flow, but in decreasing debt to cap based on a fairly conservative view on debt repayment and the like. But you can see debt to total cap declining from 62 percent in 2004, down to somewhere in the 54 to 56 percent by 2007. The next slide, number 75, depicts a growth in the segment profit. Segment profit after mark-to-market adjustment, as well as the CapEx. And I just, again, point out that that decline in capital spending represents an opportunity to reinvest some of that free cash flow back into the business, into low risk, high return projects. The next slide is consistent with our prior presentation. Summarizes key elements of our financial strategy. Again, we'll continue to focus and drive sustainable growth in EVA and shareholder value, in order to ensure adequate liquidity. We'll maintain the cash and liquidity cushion of at least $1 billion. We'll continue to focus on improving our credit ratios and ratings, ultimately achieving investment grade ratios. We'll continue to reduce risk in our Power segment, and we've taken some steps of late to do just that. We'll continue to increase our focus on disciplined, EVA-based investments in our natural gas businesses. We'll focus on optimizing the use of our free cash flow, whether that be in reinvesting in our core businesses, debt reduction, share repurchase, dividend, and a combination thereof, depending on the opportunities that are available to us. And then finally, we believe the combination of operating cash flow growth and reduction in interest cost will drive value creation for shareholders. And with that, I'll turn it back to Steve.

Thank you, Don. And looking at the last slide, appreciate your patience as we've walked through a lot of slides and provided a lot of information. We endeavor to cover a lot of topics that Don and Travis and I get questions on, as we're out talking at the various energy conferences. Looking at my last slide, key points. As I said earlier, our restructuring is complete. We are seeking growth with discipline. I believe that we have clearly identified the opportunities, some of which are embedded in our guidance, and some we still need to bring across the line. I can't emphasize enough how this management team believes that execution continues be to important. It was vitally important as we worked through our restructuring over the last 2.5 years, and it will continue to be vitally important as we now seek growth. We need to ensure that we get the 1,400 wells drilled in 2005. We need to do the blocking and tackling necessary to provide a very reliable service to our customers. We need to complete the EVA-based capital investments, on time and on budget. We need to hit our numbers, and I can assure you that execution will still be utmost in our minds. So with that, we'll be happy to take your questions.

(OPERATOR INSTRUCTIONS) Jay Yannello, UBS.

Can we have the percentage hedged for '05 and '06? Do you have -- I mean, I see in the appendix you have some sensitivities to gas prices, but -- and I may have missed it, but do you have the percentage hedged?

Roughly -- we give volume on slide 34, the 286 million a day. And that's roughly 40 some percent of our production, and on a revenue basis when you take out taxes and royalties and all that, it's slightly over 50 percent. So what we've tried to do is give the actual volume hedged instead of an actual percentage.

Okay. I was moving ahead too quickly. I guess a question for Bill. Bill, you've mentioned that contracting -- you've had some ability to contract 1 to 3 years out. Do you think going forward, given that you're staying in the business, given that liquidity is improving, you may be able to actually go farther out? And if so, what timeframe do you think that might be achievable?

Yes, Jay. We do. We think just the Power markets in general are recovering, and as they recover, I think customers are getting more comfortable doing longer term deals. I think we'll stay anywhere between 2 and 4 years for the next year or so. But we're starting to get inquiries as far out as 2010, 2011. And I think that will be the natural evolution. So I would expect here in the next fewer year we could move further out on the curve.

Pierce Hammon, Simmons and Company International.

Yes, just 2 questions. First, and I might have missed this, but on the Alaska Quality Bank, if you could just provide an update. I know in the third quarter of '04, you accrued 134 million, and kind of what the status is there with the Quality Bank litigation.

Just a minute, please. We're trying to get the right question to answer the question.

Okay. Thank you.

We'll come back to you on that.

Sure. On the other question, regarding CapEx and the Pipeline segment. Just curious if there is any additional, based on steel pricing right now, if steel pricing were to hold when you look out to '06, and specifically in '06. Do you see maybe some upside to that CapEx number?

I think we'll ask Ralph to address that, because I think -- I'm sorry.

Was the question for gas pipes, or for E&P?

For gas pipes, specifically on the steel.

I'm sorry, will repeat the question?

Sure, on the Pipeline business, as far as CapEx spending is concerned, if steel prices were to hold in here, do you see potential more spending and CapEx on the -- from a steel standpoint in the Pipeline business in '06, and potentially in '07?

Actually, it's possible, but we don't really expect that. In fact, the suppliers we've spoken to of late have indicated to us that steel prices may actually give way a bit in the time frame that's relevant to ordering for our major projects.

Okay.

In the event, however, we did see a steel price increase, a thing to bear in mind is that we would be able to roll those incremental costs into our rates.

Thank you.

Perhaps we can just jump back to the prior question, and Jim Bender, our General Counsel, is going to say a few words on that.

Nothing has changed since the third quarter when the ALJ decisions came out. And we took an accrual in the third quarter, and other than, I think, some ongoing interest accruals, there's been nothing new. The matter is on appeal and there's, I guess, nothing else really I could comment about, other than that's on appeal.

Now, are we looking for a decision from the RCA and FERC by the end of '05?

I'm not sure of the timing exactly, but it's very hard to predict that. I think that's possible, but it could take longer than that. It's a pretty complicated matter.

And then from a dollar amount standpoint, we're not prepared to put a number out there yet?

There's -- other than what we have accrued, no, we're not.

Okay. I just was curious if there's any additional accruals potentially coming.

I mean, not at this time.

Okay. So just the 134 million was that was accrued in the third quarter?

That's correct.

Scott Soler, Morgan Stanley.

I had 3 sets of short questions. The first question was looking at -- when you all are looking at your commodity outlook, Williams' outlook for the next 3 years, what basic gas and oil assumptions are you all using? Because it looks like your 3-year profit forecast still seems fairly conservative in a number of ways. And I was just trying to match up our commodity price forecast versus what you all are considering to be sort of 3-year forecast for gas and oil.

Scott, this is Andrew. Our forecast for gas primarily tracks what the strip prices would have been for those 3 years in the December time frame. For '05, that would have been about 625. or '06, that would have been about 623, and for '07, it would have been about 586. And I think our crude oil pricing range -- I don't have that right in front of me, but the WTI strip in that same time frame was probably about $47 in the front, and then declining probably 3 to $4 a barrel over that time frame. But if you need that specifically, I'll be glad to get you the specifics on the WTI through Travis.

Okay. Thanks, Andrew. And then couple other questions. Ralph, I wanted to ask you a few questions on E&P. When you all look at how much opportunity you have, particularly in the Piceance and the surrounding areas, it looks like your CapEx budget has not changed too much, and I guess I was curious about a couple of factors. One is, is the log jam, or is there a log jam? And if there is one, is it just due to the fact that it is still a very tight rig market, and probably more importantly, a tight labor market to get good hands to drill wells? Could you comment on that maybe very briefly?

I think there is a log jam, I guess. I think we are working hard to break that loose, and as you can see, we are trying to -- we believe we'll be up to about 15 rigs by the third quarter. But we have plans obviously to increase that quite a bit above that. So we are working very hard to do that. There is a log jam, but the industry is being pretty innovative, to either -- we are, in fact, to either contract for new rigs, or find existing rigs somehow and bring them up to our shop. So there a log jam, but I believe quite a few of the rig companies are very interested in that area now, since it is becoming so hot. So I think we can maybe even bring some new players into that area, and increase our rigs. But right now, what you see the guidance is, basically 12 rigs flat through the period. And as I mentioned, we're going to be above that already in '05 -- late '05, and hope to go above that in '06 and '07.

And then Ralph, when you and Joe are looking at F&D costs, and they're up 18 percent over your 3-year average, they are still very low in the Rockies, but when you all are building in and modeling inflation for your segment, how do you all think about F&D and OpEx costs over the next couple of years? And is there enough you can do on the drill time to offset some of the rise?

Well, I think we can on the drill time. We've consistently improved our spud to spud time year after year after year for the last decade. So we obviously are going to try to do that. On the capital cost increase, we modeled in from the original guidance in '05 and '06, we changed that at year end, there the last call. I think I increased it by about 8 percent in '05, and 9 percent in '06. And we're still seeing generally overall that appears to be a good level to increase our CapEx in there. And as for LOE, we did see increases in LOE during the year. A lot of that was increase in salaries, fuel, equipment, tighter service industry in general. But we also did some LOE increases via workover, so to increase production, so kind of a combination there. So we've seen that go up slightly, or it went up about 18 percent. But I think that was a -- will still be at the very upper quartile of the industry, and we are not modeling those kind of increases going forward. We are pretty flat to slightly up.

Okay. Thanks for your patience. I just have one last question for Bill and Andrew. When you all are looking at your capacity in California and in PJM, what type of -- I guess this is all still very preliminary I guess, of course in both regions. But when you're looking at -- California has had a lot of discussions over the past few months about if they're going to go to more of an ICAP market versus the market that seems to be developing in PJM. When you think about how much capacity you have in Southern California, and a fair amount in PJM, how do you all think about or model what the opportunity might be? I know that you all aren't forecasting anything. I think that's all upside. But in terms of just sort of thinking about what the profitability could be on maybe a per KW year, or some way to kind of frame what that would could be potentially. How much of that capacity would be available to sell into that market on a capacity basis?

Yes, Scott. Well we definitely develop views, especially during the guidance periods, around what we believe the value of the capacity is going be, depending on how the markets are going to develop. And I think it is a positive sign that we've got some term capacity sales off, especially in the west, that there's a strong belief that the capacity markets are going to develop. As you indicated, we don't forecast that, but clearly robust capacity markets could be meaningful upside to us, and we believe that's the direction the markets are going.

But if someone was trying to build in a case, I'm not saying you all are, but if someone was trying to build in a case, would it be double counting to assume that you could get a capacity payment maybe in the '06, '07 time frame on California and PJM? Or in other words, would there be the ability to make an extra stream of cash flow from those capacity payments, over and above what you can make by either selling merchant or under your current contracts with the CDWR?

There is Scott. For instance, the 650 megawatt capacity sale we mentioned in '05, we still have the upside that's in our forecast from the energy side of the equation. So what I think you'll see when we get to end the of the first quarter, and we start to reflect these deals in our financials, is you'll see more of the merchant cash flows moving up into the hedge category. But I don't really think you'll see the merchant cash flows coming down, because there's still energy to be sold. So we're already seeing the benefit of that in '05, in both the west and the PJM, and we'll obviously continue to work with all of the agencies to push for capacity markets. But I think it's safe to say that capacity should be added to maybe not dollar for dollar, but clearly additive to what we're forecasting if those markets develop the way we think they will.

Anatol Feygin, Banc of America Securities.

A couple of quick questions. Can you, maybe Alan, can you give us an idea for sensitivity to ethylene margins, and I think you mentioned that for '05, you're using the CMAI forecast. Is that $0.15 or $0.16 or so? Do I have my numbers right there?

Our CMAI forecast, February '05, is what we're using on that. And that is -- you can measure that a lot of different ways. But basically we're taking it on a pound of ethylene produced, and that's at about $0.09 a pound, after our variable expenses are into that. And in terms of how much impact you might see from that, that is, for instance, a $0.09 movement that we had in '04, was about $25 million of movement in the '04 period. So there is a little bit of movement around on that because we do have some fee-based contracts, or tolling contracts at that plant, that sometimes will absorb some of the capacity at the plant. And that's about $0.045 a pound is what we typically get paid on those fee-based kind of contract.

Okay. Just for reference, is that -- it's different numbers than I have for the cent per pound price. I have something like 16.9 for '05 from CMAI, and 10.4 for the fourth quarter. So -- ?

That is correct in terms of what's in the CMAI forecast. What I was giving you was a number that was netted after our variable expenses are put into that, so -- .

Got it. Got it. Okay. A question for Don. Can you give us some guidance on the diluted share count going forward? The way I'm -- I'm coming up with just under 600 million shares, is that about right?

That's about right, Anatol. If you could give us a minute here, we'll dig that up. Just below 600 is a simple answer. And you can check in with our IR team to walk through the details

Great, and 1 other question. You guys had a table in the previous quarter about future realizations, and obviously things have changed from an accounting standpoint. But if you had that table today, what was then $979 million of future realizations, what would -- can you give us a sense for what that number would be?

Anatol, this is Andrew. If you look in the slide where we -- to walk through the segment profit after mark-to-market forecast for the next 3 years, we've given those number for next 3 years. And we're prepared, if we do any future power updates tutorial-wise, we would break it out beyond the guidance period, but we're not prepared to show beyond the guidance period, we've shown that number in those slides.

Sorry, Andrew, do you know off the top of your head what slide number that is?

Just give me a second here to look through the deck. Slide 59. You san see where it has 283 million in 2005, approximately 153 million in 2006, and about 166 million in 2007.

Fai Lee, RBC Capital Markets.

Don, I was just wondering if you could clarify what direction you expect the other costs to go in. It wasn't clear to me with the full year of stock options in '06, if other costs are directionally heading lower in '06, or if they'll be flat. And if you could clarify a bit.

Sure. I think other costs will be moving down. The costs related to stock option accounting will be moving up, as we have a half-year expense in 2005, and a full year expense in 2006. So I think, depending on the rate of business unit growth, I think you'll see it to be overall relatively flat '06 to '05.

Okay. So flat in '06. And should we see some benefit in '07 then?

Again, we're forecasting about flat.

Okay. All right. And with respect to interest expense, it doesn't look like, based on your cash flow forecast, that we shouldn't expect it to change very much from '05, maybe slightly declining? Is that sort of your expectations going forward?

Certainly, we would plan to use some amount of our free cash flow for further debt reduction. The timing of that, we've not been real specific about. But clearly we would anticipate some additional debt reduction over time.

Kelly Krenger , Banc of America Securities.

I just have a question. Don, I think you said on the working capital year-to-date that you had received back $400 million of working capital year-to-date? Is that correct?

We have $400 million of increased cash since the end of the year. And I just indicate that 273 million of that is associated with the Feline PAC final settlement, offset by a $200 million debt pay down at Transco. And then the rest is spread around, but $400 million increase in cash.

Okay. I must have misunderstood you. Okay. Thank you.

Craig Shere, Calyon Securities.

2 questions. 1 for Alan, and 1for Ralph. Alan, on the frac spread assumption of $0.85, where does that stand relative to where the market is these days? And what is your ability to maybe lock in some higher margins, at least for a few months forward, as other companies have in the Midstream space? And, Ralph, in talking to some clients, there's been some discussion about how your experience with drilling in the Piceance has maybe been 100 Bcf per square mile. Other companies in the same vicinity have talked about numbers 80 to 90 Bcf, but your acreage is quite a bit out there. What is the practicality of trying to extrapolate those numbers to your 144,000 net acres? Can you talk about that?

I'll take the first question there on the NGL frac spread, and how that compares to current markets. That number of $0.85 is us taking our contract mix as it sits today, and forecasting forward our contract mix, and then applying the 5-year average for the Henry Hub versus Belleview gas price to frac spread, and then we put basis differential to the gas, and so forth, and tnf to the liquid. So fairly complex model. And you will note that it differs substantially from our 5-year average financial forecast, which is around $0.11 -- or 5-year average for financial, which is around $0.11. And that is driven by the fact that we have quite -- we had quite a bit of percent of liquids contracts in the '03, and first part of '04, that actually where we're just taking that whole barrel is included in that mix, and that's what drives that ratio up. Long way of getting to that, is what the markets, we think will give us, against our contracts, if you went back and included the '04 margins, gets you to that 5-year average. We're uncomfortable, obviously, moving off of that, because we've seen this business turn very quickly. And so that is what we have in there. And compared to where that is currently, we're seeing margins that are about 50 percent above that in the current market, as we sit today. Did that answer your question?

Yes, just as a quick follow-up. Are there any opportunities, even for a quarter or 2, to contract out with customers to lock in some of that 50 percent additional margin?

There are in the prompt months, if you will, the very prompt months. We do not look at that on an individual basis. We look at that across the corporation, and obviously we have our gas side exposure on E&P that we would look to, as well there. So we don't try to just individually lock in a commodity just within the business unit.

And we'll take our next question from -- .

As a follow-up. 1 more question, I think, was for me. This is is Ralph. In the Piceance Valley itself, we have about 75,000 net acres. The total Piceance, not counting Ryan, the new areas, Ryan and Trail, we had, I think it's 140,000 gross acres, as we've said before. I think that the Piceance Valley that we're developing currently, is about 40,000 acres, so we do have an additional large amount of acreage that we have available in our inventory, that we really haven't accounted for publicly yet. And what we're doing there is making sure we understand the topographical challenges that might be in there. Also understanding that the industry gets better on drilling longer laterals directionally, and items like that, there probably are additional potential locations, if all of that comes to pass. So I look at it more as the Valley proper, the 70 to 75,000 net acres that we have, and we're developing about 40,000 of those right now. So there could be, based on the gas in place per square mile, there could be additional opportunities as you mentioned in your question.

Maureen Howe, RBC Capital Markets.

Specifically, with respect to the Gas Pipeline division, the operating costs, the expenses did come in better than, I think, the guidance that had previously been provided. And I'm wondering if, perhaps, Phil can give a little color to where the savings were, and whether those savings are something that we're to see continue?

Sure, I can. In a number of areas we had, for example, expected O&M that we were able to do a little bit better. Some of those projects were deferred, and we will be doing a bit of catch up on some of them. We had higher SG&A costs that, as we've talked about, at a corporate level, that we're working down, and have achieved some progress there. But I wouldn't expect to see an ongoing series of reductions. We've gotten a lot of the O&M and operating costs down over the last couple of years, and there's a limit to how much more squeeze we can put upon that. I think at this point, we've rung out about all of the savings that we would expect to garner there.

Well, yes, and I guess I would have thought that, as well. And I'm just wondering, in terms of the projects that were deferred, can you give us some sort of idea of the size of those projects, and will they be incurred in 2005?

They won't have a substantial impact in 2005, but they were fairly minor overall. Nothing material that I would expect in the way of catch up.

And just with respect to the short-term firm, again, revenues seem to be better there than what the guidance was. I think the guidance was that, in light of the expansion of the current pipeline, that in fact, short term firm on Northwest would be somewhat lower. Can you again just provide some color on that, and what was the source of the improvement or the factor behind that?

I may actually have to call on Allison Bridges if in fact there's additional detail required. But I think we saw a couple of occasions when it was substantially colder weather than expected, and we were able to capture a share of that. Allison, if you are on the line, you might, please, chime in on that one.

Yes, I will. While generally the basin spreads were not as attractive, and our revenue was still lower than 2003, we were able to take advantage of certain opportunities when maintenance was going on in other pipes, as well as we were able to take advantage of some seasonal pricing opportunities in the fourth quarter.

Okay. Thank you for that. Moving on to Transco, and any potential opportunities that might come out of new LNG facilities, and perhaps required expansion on Transco moving up the coast. Can you give us some sense -- you mentioned in your remarks that Transco, I believe, is running nearly full. And what order of magnitude of expansion -- I know it's early days, but what order of magnitude would you be expecting in terms of dollars and volume?

Wow, Maureen, that's very hard to pin down, obviously, until we locate which projects we're talking about. But I would say that clearly as Copoint expands, one would look at the logical markets for that import. And with our situation relative to the Leidy hub, we're in good shape to pick up an expansion opportunity there, and that would be a pretty substantial expansion. I would hate, at this point, to put a dollar amount on it, until one sort of got a lot closer to exactly how much volume the market would want us to move. I would say that there are 3 large interstate pipes serving that hub, and we're 1 of them. And we've got probably the -- well, we do have a very low incremental cost to get that gas to market, and the logical markets for it are over in zone 6.

And so the low incremental costs, I guess that's what I'm getting at, is would the first round of expansion be the addition of compression? Is that how you would see it? And make the Transco, perhaps, expansion more economic than what might be available in other pipes?

Actually, I don't know. It's hard to peg down until you know exactly how much volume we're talking about. My sense of the situation is that orders of magnitude, those expansions are going to require some pipe. But even if it does, I think we're going to be in good shape to pick up our share. Frank Ferazzi is on the line, as well, and he might be able to add a little color. Frank, if you want to chime, I would appreciate it.

Sure, Phil. As is the case with most of the Transco expansions, a sizable expansion is going include both a combination of looping the existing pipeline right of way, as well as adding compression. So it will likely be a combination of both. In terms of the quality of markets, I think Transco's physical presence, particularly in the New York City market, puts us in a pretty good position to expand the pipeline to serve growth in that area.

Are there any restrictions on what you could add? I mean, is there -- do you have any restrictions such as if you have you have to add, let's say 500 million cubic feet day, it's very economic, but if you go to a Bcf a day, then you start running into problems? Or is it again, is this all just way too preliminary?

Yes, I think it's a little early to predict whether we're talking about an expansion in the neighborhood of 500 million a day, or Bcf. I mean, I will tell you that given the large metropolitan areas we're taking about, adding any capacity in that region is going to take time. But again, given the physical presence in the marketplace, the facilities that Transco already has on the ground, we'll probably be in a better shape than any anybody else.

Okay. Thanks. And 1 last question, and this is for Ralph. We talked about, or there was -- there's some discussion about funding and development costs, they certainly look competitive. But they are trending up, and I'm wondering if you have an outlook for 2005 and going forward, and what the impact of these additional rigs might be in terms of cost? I guess those are more production costs?

Well, I guess our previous -- our '01 through '03 3-year average was $0.91, and our '02 through '04 is $0.92. So really that's -- I must have missed --

Oh, I must have misinterpreted it, because I actually thought the average was $0.72.

No. The '01 through '03 was $0.91, and now it's -- I'm sorry, '01 through '03 was $0.91, and now it's trended down to $0.78 if you take that average in. Now, our '04 only, stand alone average was $0.92. That's a 1 year thing -- we think in the industry, generally tries to do a 3-year rolling average. I think it's more appropriate, so you don't have strange things that happen 1 year that could offset -- could make a move 1 way or the other. So our costs are up a little bit I guess, on a 1 year basis. We expect to be in this finding and development range. A majority of our budget is in the Piceance, and those wells are typically 1.1 million to 1.2 million type wells, and our Bcfs are 1.2 to 1.3 Bcf, so that's about a dollar or slightly less. And since the majority of our drilling is in that area, it should stay -- it will go up a little bit on a rolling average, but shouldn't be too much. So the annual basis should be in that range.

I'm now thoroughly confused, so I'm going to have to just clarify this. So the $0.91 average is '01 to '04?

Oh, no. $0.91 was '01 through '03, which included the Barrett acquisition.

'01 through '03. And then that $0.78 is '02 to '04.

Right, because the Barrett acquisition rolls out. And then if you look at just a 1 year look at it, '04 only, it is $0.92. Obviously, with the Barrett acquisition rolling out, which was more in the $1.20 range, it did lower our numbers. But 2 things I was trying to stress there is that, 1, we're still -- obviously with the Barrett acquisition of '01 rolling out, it does make our costs go down. But even if you look at our annual costs with higher increases in '04, it was $0.92, and what I was trying to stress is the industry, before the increased costs of '04 added in, their metric was $1.42, and we expect that to go up. So we do expect to be substantially below the industry average.

And just to clarify again, sorry, the $0.92 you see as being a pretty good rate going forward?

You know, it doesn't hurt to say it's going to be between $0.92 and a dollar. I mean, you could almost -- in that range. But it won't go exactly to a dollar, it will stay in this range.

Right, right. Okay, that's great. Thank you for that clarification.

And at this time, we have no further questions. Mr. Malcolm, I would like to turn the conversation back over to you for any additional or closing remarks.

This is Don Chappel. I have got a couple -- or 1 question here, plus a comment on a prior question. We had a question on how much cash comes to Williams from the Gulfstream project financing, timing uses of cash. We've included about $170 million in the fourth quarter of '05, related to that refinancing. However, the range of that is probably in the zero to $200 million range. We do have a partner; our partner has to agree. So that's -- that's still a variable in that refinancing. But again, included in our forecast was about $170 million of refinancing in the fourth quarter. In terms of uses of cash, likely use of cash, as I think about that, would be for debt reduction, as we apply more leverage to Gulfstream. We would likely want to delever somewhere else.

Just perhaps a follow-up thought or comment on the previous question on the cash increase. Again, we -- the unrestricted cash at end the of the year was 930 million. As of yesterday, it was 1 billion 332, an increase of $400 million. 2 components are -- I'll call them financing, really related. Feline PACS sources of cash 273 million, a $200 million debt reduction, paydown results in a net $73 million source of cash. We also, as I mentioned, terminated the contract with a customer, and sold the mortgage note receivable. The combined proceeds there were $131 million, so that 1 combined with Feline PACS and debt reduction item is about $200 million. We had $100 million of cash interest during the quarter, cash outflow, and we had about $300 million of operating cash flows, including margin inflow. So again, the way I think about it is Feline PACS plus 273 debt reduction, minus 200, for a net 73. Termination of contract sale and note, plus 131, cash interest payment of 99, and then all other of about 300. So that's how we end up with a $400 million improvement in cash over the last 7 or 8 weeks.

And this is Steve Malcolm. Again, thank you for your interest in our Company. We are very excited about the future, and look forward to talking with you about our progress throughout 2005. Thank you.

And that does conclude today's presentation. We thank you for your participation, and you may disconnect at this time.