威廉斯 (WMB) 2004 Q3 法說會逐字稿

Good day, everyone, and thank you for your patience. We'd like to welcome you to the Williams Companies third-quarter 2004 earnings conference call. As a reminder today's call is being recorded and at this time for opening remarks and introductions, I'd like to turn the conference over to Mr. Travis Campbell. Mr. Campbell, please go ahead.

Thank you. And good morning, everyone. Welcome to our third quarter analysts call this morning. In a minute I'll turn it to Steve Malcom, our Chairman, but present with Steve today are Don Chappel, the CFO, and then also the business unit leaders of our four business units, Ralph Hill, Allen Armstrong, Doug Whisenant (ph), and Bill Hobbs who will be presenting parts of the presentation today.

In today's call, we will be including some forward-looking statements. Please refer to the forward-looking statement which is presented in the beginning of this presentation, is also posted on Williams.com. Also as always, there are some non-GAAP numbers that are presented. The reconciliation of recurring earnings is included on the website and is also attached to the press release, which was released this morning. Also reconciliation of EBITDA or earnings is included in that as well, and all the slides are available on our website in a PDF format.

With that, I'll turn it over to Steve Malcolm our Chairman.

Thanks, Travis and welcome to our third-quarter conference call and thank you for your continuing interest in our company. As Travis mentioned our senior management team is assembled here in Tulsa and most will be participating in today's call. I believe that we have about 85 slides or so including the appendix, but we'll run through those quickly and have plenty of time for your questions. Looking at the first slide, slide number four, let me start with some of the highlights or major headlines relative to our performance during the third quarter. And I believe that these are the major takeaways from today's conference call.

Obviously we are delighted with our progress on our financial restructuring as well as the financial results for the quarter and through the first three-quarters of 2004. Debt reduction of $3 billion has occurred since the beginning of the year. Total debt is now at $8.9 billion. Please recall that total debt was right at $15 billion back in the middle of 2002. Cash flows from operations continued to improve in 2003 through nine months. We were at $567 million through nine months in 2004, $1.1 billion. Obviously our debt-to-cap ratios have moved down this year versus last. We're delighted with that. Overall guidance is slightly up for 2004, and we continue to apply financial discipline as we move out of our restructuring phase.

Slide number five, continuing with some of the headlines, looking specifically at the third quarter, we enjoyed solid performance. Our quarter-to-quarter recurring earnings showed significant improvement with recurring EPS with 26 cents in third quarter '04 versus essentially break even in third quarter '03. E&P volumes and earnings are both up from the previous quarter showing that we are gaining traction in our production growth plan. Midstream was boosted by near record liquids margins be a improved OLEFIN (ph) performance. Gas pipelines continue it's steady performance. And powers expected cash flows are unchanged despite the fact that we decreased segment profit guidance following our decision to adopt hedge accounting.

Slide six, as we announced in mid-September, we have decided to continue operating our power business and have ceased our efforts to exit the business. The primary factors that drove our decision to retain the business included progress that we had made to reduce the size of the portfolio, the fact that the business was expected to generate free cash flows over the near term, and the realization that the marketability of the business was clearly impacted in a negative way by the depressed wholesale power markets. But our strategy that we have employed in the power business since mid 2002 will be unchanged. We will still be all about maximizing cash, pursuing new contracts to further hedge our portfolio, reduce risks, and continue to meet our contractual obligations.

At the time that we announced our decision to remain in the business, we also advised that we would adopt hedge accounting for certain contracts in the portfolio. And the reason that we wanted to do that is because it would have the effect of reducing earnings volatility. However, another effect associated with adopting hedge accounting is that previous mark-to-market gains will impact future reported earnings, and, in fact, as Bill and Don will describe, our previous guidance will need to be adjusted. Importantly, and I can't stress this enough -- the fact that we are adopting hedge accounting will have no impact on future cash flows.

Turning to the next slide, and that would be slide seven, the premier integrated natural gas assets that we own and operate are ideally situated in growth markets and offer significant competitive advantage to Williams. And these assets allow us to be poised for strong post restructuring growth. Looking at each of our businesses in E&P we will be all about exploiting the attractive portfolio of low risk, high return drilling opportunities. In midstream we'll be exploiting our existing scale positions in growth basins and expect that we'll be able to capture new and exciting deep water infrastructure opportunities. We have been very pleased with our experience thus far in the deep water. In gas pipes, we'll continue to focus on satisfying our customer needs and adding capacity where needed to serve our customer needs. And a couple of examples there, the Lidi (ph) to Long Island expansion that we're pursuing and the fact that gulf stream is pursuing an expansion, and, in fact, has one underway. But as we emerge from our restructuring we will be looking to ramp-up our investments in the 2005-2007 time frame. Certainly still in a disciplined manner and ensuring that new projects are EVA positive and are all about creating shareholder value, but as we've indicated earlier, we believe that we will be able to capture our share of new deep water opportunities. As well, we'll be looking at entries into new basins that are consistent with our core competencies in the E&P arena in terms of Titsands (ph) gas and cole steam gas competencies.

The next slide, slide eight, offers a glimpse of the of the future in terms of where we're headed. In E&P, much of the production growth near term is in Piceance (ph) basin, but over time all of our basins will contribute to production growth. In midstream our deep water projects are beginning to ramp-up in terms of volume and earnings. And we're taking advantage of the scale positions that I referred to earlier. Gas pipes generate steady earnings. And we have new rate he cases that will go into effect on Transco (ph) and Northwest Pipeline in 2007. In power, as I said earlier, we have decided to retain the business, but our strategy will be unchanged over that that we've pursued the last two years. And corporately in a enterprise wide basis our number one priority is debt retirement. With that quick overview, I'll turn it over to Don Chappel.

Thanks, Steve. And before I get into the number slides just a few comments. And good morning to all of you joining us on the call. I too am delighted with our continued rapid recovery. With our overall third quarter and year-to-date results as well as our very bright outlook for continued strong growth in EVA and shareholder value as we continue to drive forward.

Our three primary natural gas businesses, E&T midstream and gas pipelines continue grow profits and EVA while power continues to generate solid cash flow despite very difficult but improving market conditions and focusing on risk reducing transactions to further lock in some value and reduce risk to Williams. Our results remain difficult to compare as a result of the massive restructuring which is nearly complete. And the many gains and losses impairments that have been recorded. Also mark-to-market accounting for power has created and continues to create great earnings volatility despite much more steady cash flows. As we said, in the past we would prefer to apply hedge accounting versus mark-to-market. However, we did not qualify as a result of our stated intent to exit the business. Now that we've decided to stick with power, we qualify for and have elected to apply hedge accounting for qualifying derivative contracts effective October 1st. As such, reported earnings will be much less volatile beginning in the fourth quarter. However, as Steve mentioned, the legacy of mark-to-market accounting will remain with us for a number of years as previous gains turn around into higher expenses in subsequent periods. Again, most importantly, the economic hedges remain effective and there is no impact on forecast cash flows.

Today we've added some new material to better explain our actual results, forecast and forecast changes related to mark-to-market accounting. We hope that you find this additional analysis to be helpful to you. Again, let me just sum up by saying again I'm delighted with our continued progress, our results and our outlook, and with that let's dive into the numbers on slide number ten, and as I do that I'll just say that, I'll run through these fairly quickly. I won't try to drill down on every slide because we have subsequent drill downs that either I will present or business unit leaders will. So, I am going to hit the high points. On slide number ten, again, just to cover the earnings for the quarter, continuing ops is $16 million, discontinue of 83, totals up to net income of $99 million or 19 cents a share. On a recurring basis $136 million or 26 cents per share, and again I'll mention that mark-to-market accounting is part of third-quarter results as well as prior year results. And again, I won't attempt to analyze that here on this slide. On a year-to-date basis, net income of $90 million or 17 cents, on a recurring basis $193 million or 37 cents and again comparisons are very difficult as a result of the many restructuring items as well as mark-to-market accounting. So we'll drill down on that in subsequent slides.

Turning next to slide 11 reconcile from income from continuing operation to recurring you can see the major components in the third quarter include an impairment of about $16 million in midstream that we'll talk to later in this presentation. Income related to prior periods, let me say that in the second quarter of this year, we booked revenue on Devils Power (ph) equal to cash received. However, further analysis indicated that the accounting using units of production was required. Therefore, $17 million of revenue booked in the second quarter should have been deferred and will be recognized in later periods. There's no effect on cash flows. There is no effect on the contract profitability over time, just a change in the timing of revenue recognition. Let me just also add that our recurring analysis for the second quarter will be revised to lower the second-quarter earnings by the $17 million or about 2 cents a share and as you can see it increases recurring earnings by that $17 million for 2 cents per share in this third quarter. Debt retirement expenses in the third quarter were $155 million, after a tax provision you can see the $136 million or 26 per share, on a year-to-date basis I'll just hit a couple of points of the debt retirement expenses totaling $252 million.

Let's now turn to a new slide that helps to analyze the impacts of mark-to-market accounting and this is slide number 12. We're starting and I'll look at third quarter of 2004 for starters here. If we start with our $136 million or 26 cents of recurring earnings, and we make mark-to-market adjustments that reverse out all the mark-to-market effects as they pertain to the power business, we'll come to the answer that we're looking at on this page. First we'll reverse the forward unrealized mark-to-market gains and losses. $187 million that was recognized as income in the third quarter of this year. Next we'll add back realized gains and losses from mark-to-market that had been previously recognized that lower reported earnings in the current quarter by $45 million. The net of these two adjustments is $142 million after a $55 million tax effect, the after tax impact is $87 million or recurring earnings after mark-to-market adjustments of $49 million or on an EPS basis 9 cents. That compares to 1 cent in the same quarter a year ago. On a year-to-date basis you can see the comparable analysis. Year-to-date we recorded $279 million of mark-to-market gains. But we've also realized gains from previous mark-to-market transactions totaling 192. For a net deduction of $87 million, after tax effect, you can see that that runs down to 27 cents on a year-to-date basis as compared to a 33 cent loss in the prior year. So again I hope this is helpful in describing the underlying economics that are much more comparable and much closer aligned with cash flow.

Next let's turn to slide number 13, net income components. We'll just take another cut at the numbers here starting with segments profit that we're already talk through. You can see net interest expense during the quarter of $196 million down from $265 million, a year ago. Debt retirement expense comprised $155 million and then other income and expense, expense in this case of 21, and the expense is largely up as a result of reduced interest income as we've put more of our cash to work to pay down debt. Looking at year-to-date numbers, you can see the debt retirement expense of $252 million, and that's associated with a very aggressive debt reduction program that we'll walk through in a moment. Our other income and expense, an expense item of $58 million compared to $28 million of income in the prior year and again that's largely due to sharply reduced interest expense again as we sharply reduced our cash balances as we put in new liquidity facilities and used the cash to pay down debt.

Let's turn now to the next slide, slide number 14. Takes a cut at segments profit by business union, and we'll be diving into the business units later in the presentation. However, you can see that both on a reported and recurring basis that segments profit increases year-over-year. Again, I would just reminds everyone that mark-to-market does impact these results.

On a year-to-date basis on slide number 15, again taking a look at on a business unit by business units basis, on this basis you can see reported earnings are somewhat less than 2003. However, recurring is up and there's a number of charges that in mark-to-market items that will once again analyze as we go through the presentation in greater detail.

Slide number 16, analyzes the changes in recurring segment profit from the third quarter from '03 to '04. You can see that power accounts of $94 million of the change, midstream $57 million. And you can see all the key components of the change and again our business unit leaders will talk through their respective business results.

Slide 17, cash flow, we're particularly proud of our cash flow progress this year. You can see in the third quarter we began with cash of just over $1 billion. Cash flow from continuing operations of 462. Asset sales brought in $618 million during the quarter. The largest piece of which was the Canadian straddle plants. We retired $816 million of debt. Invested $209 million in the business. We paid $140 million of premiums to end the quarter with $977 million available cash on a year-to-date basis, you can see we started the year with $2.3 billion of cash, cash from continuing ops of nearly $1.1 billion. Asset sales of just over $1 billion. We were able to return cash to us as a result of our new credit facilities that previously cash collateralized letters of credit totaling $380 million. Again, debt retirements just over $3 billion. Capital spending 540 and the cost to early retire that debt of 240 and again, ended the quarter at 977 million in cash, a reduction of $1.3 billion, but that cash was put to good use through principally through debt reduction, and again cash flows continue to be robust, and we're quickly putting excess cash to work for either debt reduction or to reinvest it in our primary gas businesses to create additional EVA.

Slide number 18, I think we've made enormous progress in debt reduction this year, following strong performance in 2003 as well. While at the same time growing segment profit in EVA. We started the year with debt just under $12 million with an average cost of 7.7%. We ended quarter with debt under $9 billion, a reduction of $3 billion this year. 2.2 of that reduction relates to early debt retirement. Since the end of September, we also reduced debt by a transaction involving the feline pacts (ph) that allowed us to reduce debt by an additional $827 million. Our current approximate long-term debt is $8.1 million with an effective rate of 7.3%. Year-to-date debt reduction again about $3.9 billion and we yet have a couple of additional steps that may allow us to get that below below $8 billion before the end of the year. Fix rate debt totals $8.35 billion at 7.5% and variable debt $589 million at 4.1%. Again we're particularly proud of the tremendous progress on the debt reduction front and we think both the bond markets as well as the rating agencies are taking notice.

Slide number 19, is an EBITDA reconciliation. I won't speak to that slide. It's there for your reference.

Slide number 20 breaks out segment profit by business units and compares the currents forecast of segments profit for 2004 to the prior guidance. You'll see the prior guidance in italics just below the forecast numbers if the guidance has changed, and again our business units leaders will take you through the relative changes. Overall, we've tightened the range. We've increased the bottom end of the range by $75 million and we've lower the top end of the range by $25 million and again the BUs will walk through their components.

The next slide, slide 21 we walk from segments profit to EPS to recurrent EPS to recurring EPS after mark-to-market adjust. And I'll just kind of hit some of the highlights. Net interest expense relatively consistent with our expectation on August 5. We're delighted with our progress. And we expect that certainly that 2005 interest expense will be sharply lower as a result of the great progress we've made this year. We certainly made some investments in order to do that and they're reflected in those early debt retirement costs. Walking all the way down to income before discontinued operations you can see 50 to 100 million, down slightly from the August 5 guidance principally as a result of the increased cost associated with early debt retirement. If we move down to recurring, you can see recurring EPS at 34 to 44 cents. At the higher end of the range that we previously provided, and then diluted EPS after on a recurring basis after these mark-to-market adjustments of 26 to 36 cents again taking about 8 cents per share out related to all mark-to-market impacts. Finally we believe that that new measure will be a better indicator of our performance and more closely track our cash flows.

With that, I'll turn it over to Ralph Hill.

Thank you, Don. Turning to currently slide 23, just the MP (ph) first slide, we're very proud of our progress in the MP segments. We've completed our third quarter in production and growth and recurrent segment profit growth and we continue to rebuild our business rapidly following the asset sales of the last year and a half. Some highlights from my commence today will include that we have grown our production by 18% since the beginning of the year. The Piceance basin continues to deliver strong production growth. Our basins are performing well also. And we've entered into another new area in the Piceance area which I'm excited to show you in a few minutes.

Turning to slide 24, segment profit analysis, segment profit for the third quarter was $70 million, exceeding profits from the same quarter a year ago by 19%. Some of the highlights of that, we are up $10 million on volume from quarter-to-quarter, $6 million on net realized price, slightly offset by some higher costs as mentioned on the slide "insurance and legal area". Our third-quarter daily production volume is $582 million cubic feet a day on average which is up 15% from the year-ago quarter. Looking at sequential quarters which we always think is important to look at also, since last quarter our recurring profit is up 27% from $55 million last quarter to $70 million this quarter. Our total production is increased another 5%. Our LOE has actually gone down from for the quarter, which we think is important by 3%. LOE, lease operating expense is obviously up somewhat this year for the industry, but we think, we hope we have arrested our increase in LOE and actually caused it to decline. Also we did have another hedge, negative hedge impact in the third quarter of $58 million and our year-to-date hedge impact on a negative basis is $159 million.

Turning to slide 25, which is our third-quarter accomplishments, as you can see from this graph, the progress in EMP business is evident. Our segments profitable in DD&A has gained enough ground to almost replace completely the impact of all the asset sales the last year and a half as you can see from the third quarter '04 versus is above the second quarter '03 and approaching first quarter '03 at segments profit plus depreciation levels. Our Piceance production is up 15% from the last quarter. And it's up significantly 53% from the fourth quarter of 2003. We have a rapid drilling program in the Piceance. We're up to 197 gross wells that we have drilled in the Piceance base this year versus 76 wells in all of 2003. We are continuing our 12 rig drilling program with 11 in the Piceance Valley and one in the new area called Ryan Gulch which I'll talk about in just a minute. On the Powder Riverside of the world our permitting is up to 424 permits received which is up from 205 that I mentioned that we had in the last quarter call, so we doubled our permits. Between us and our partners we continue to get around 27 to 30% of the permits that have been issued. And we know our partner and Williams we have about 670 permits in hands now. Looking at the Big George production which is key to the Powder, that production continues to rise rapidly. It's up by 10% since the last quarter and that is a growth we need to see to offset the Wyodak, which is the older production decline that is going on out in the Powder.

Our development pails in the Big George Coles has been slower than planned really by 20 months due to all the permitting delays that happened during the EIS and the subsequent installation or the actual movement under the EIS, which was approved a couple years ago, but because of that we do believe that process is picking up and more and more permits have been received. The industry has received approximately 2500 permits now. If you look at the Big George production itself we're encouraged by its resource, the current industry production for the Big George is about 164 million cubic feet a day, which is up from about 148 million cubic feet a day, so a growth of 11%, and our growth is up by about 10 or 11% also. And if you look at the Big George Coles over other coles the same development cycle the Big George growing has been more rapid and nearly a 25% higher growth rate so we believe that as the constraints and permitting side and water side continue to get closer to nearing resolution we believe it's a very strong resource and we look forward to growing this activity and the production in this area as we overcome those constraints. The Piceance Trail Ridge area which I'll talk about in just a second but we did mention last call that we started drilling in that area, it's near the Piceance proper field, if you will, we've drilled four wells and we have our first gas sales started on one of the wells in October. We've started a new area also in the Piceance called the Ryan Gulch area which I have a slide on which is the next slide which is a farm in from a major which we're very encouraged about. On the San Juan basin program, it's on track the [inaudible] in field drilling is proceeding as expected, and we're happy that we're on track since we initially were delayed about 90 days on permitting rigs and services, which were a challenge but the team has overcome that, and we're on schedule now.

And looking at Piceance basin with all the growth we have there, we need to make sure we stay on top of a proactive capacity plan to move our volumes and we've taken several steps to acquire firm transportation out of the basin both going north, south, and to the east. So we're pleased and believe we have ample capacity to move our volumes from the Piceance. And although the Piceance is the biggest driver growing all the basins continue perform well and our production is up 18% since the beginning of the year so we believe we've had a very good quarter around overall for the year we've had a good year.

Turning to the 26 the Ryan Gulch area, first of all, on this slide you'll see in the bottom right hand corner Grand Valley, Parachute and Ruleson those are existing fields in the Piceance area. That is the area we believe we still have a remaining approximate 3,000 locations left to drill based on 10 acre spacing. Then going to Ryan Gulch, it's a new area just north of the existing Piceance field as you can see on the map. It is adjacent to a major pipeline hub which is the Greasewood (ph) area, so has ample transportation out of there. We've entered an area through a farm in. We spuded our first well in the third quarter, we have a commitment to drill three wells this year and three next year. Ultimately we expect to earn 15,000 contiguous net acres in this area.

On the first well, and we are just at the log stage so far, but we encouraged. It indicates that we have a Williams fork section which is the same section we drill in in the Piceance proper. It looks to be a fully charged gas column about 1900 feet thick. Good perocities, high gas saturations. We like what we see so far. Again we're just in the logging phase, but we'll begin completing the first well this week construct our gas gathering and processing system in November and anticipate first sales from this area in January. Following the drilling of three wells this year and three wells next year we'll earn the 15,000 net acres. On a 40 acre basis we believe we have approximately 770 drilling locations. If this continues to look like the Piceance proper field we could ultimately go down to down spacing to 20 or 10 acres and obviously if we got to 10 acres then that 770 locations would ultimately be over 3,000 locations similar to what see in the Piceance Valley. Again we don't know that's going to happen, but it is great upside for us we believe. It offers us an ability to materially expand our position in the Piceance with no up front leasing cost. And just to recap the Trail Ridge that we talk about last time which is between Ryan Gulch and the Piceance field. It's is, Trail Ridge is about six miles north of the Grand Valley field where we have many wells in the Piceance.

We have drilled four wells, one well is flowing to sales as I mentioned we're in the early in the assessment, but we're encouraged with the results to date. Some of the good things that have happened out there, our drilling times are faster than we thoughts they would be. We have averaged about 17 days to drill incasid (ph) versus the anticipated 23 days. We again accounted a fully charged Williams Fork section of gas, about 1400 feet in thickness, similar gas saturation and reservoir quality to the Grand Valley field just to the south. Just to recap the Trail Ridge piece of the acreage that we own we own about 15,000 net acres there. We believe there are about 500 locations based on 40 acre spacing and again if that would ultimately go down to 10 acre spacing you could quadruple that to about 2,000 locations so very similar to our existing position we see and quite a bit of upside so you can see between the Piceance Valley area which is the Grand Valley, Parachute, and Ruleson, we have substantial opportunities left to drill for a number of years and Trail Ridge and Ryan Gulch can completely add to that substantial inventory.

Turning to slide 27, to looking this, slide will help us to get to our guidance reconciliation which our gar guidance slide in two sides slide. First on capital side you can see in both years we have estimated increased industry costs that would lead to additional $35 million of capital for our base program in '05 and $45 million in '06 which calculates to about 8 and 9% respectively over the base plan that we presented to you. We believe these increases are slightly below the percentage increases noted throughout the industry. Some examples of industry cost increase, tubular goods due to the tight steel market are up between 40 and 90%. Rig rates are up 4 to 15% due to the increased drilling activity. And pumping and completion services are up about 8 to 13%. Overall we believe we're holding our costs down very well but we have experienced a increase in the costs.

Changes in for the operating profit side of the world, there are many factors that go into our production and price but essentially it nets out to about a $5 million impact for production and price in 2005. No significant impact in 2006 at this time. We he do have increase in our operating expenses, as you can see, by the $12 million in each of the years. This is really increases in lease operating expenses. We believe our team has done an excellent job of holding costs down but costs are up and has a slight decrease in segment profit if you look at our base, our changes to the base. Then if you add in the Piceance additional drilling Piceance, as you recall earlier this year we picked up additional rigs to get to the 12 rig drilling program in Piceance, we've also now added Trail Ridge and Ryan Gulch. Those opportunities provide us capital, $70 million over the base plan in 2005 and $60 million in 2006 and obviously add operating profit as we predicted here. So overall our capital is up. The majority is for new projects which we're excited about or increased drilling in our Piceance area, and then we also are experienced some industry costs but I believe our team has done a great job of minimizing those costs while also expanding our opportunities.

Looking at slide 28, to try to get us from the growth that we see in operating profit of between 70 and 80% in 2005 from 2004, and again this is just a midpoint estimate of our ranges we have provided to you, if you look at incremental increase from 2004 to 2005, of $190 million, we expect to see a price improvement, most of that is by moving out of our heavily hedged position in 2004 and that's a positive, overall price impact of $98 million. Our hedge volume in two 2005 drops by 132 million cubic feet a day from 2004 and obviously that 132 million cubic feet a day will receive market pricing and then for 2006, the point of view that we have at Williams, this is a price model actually decreases approximately 35 cents so we actually have a negative price impact from 2005 to 2006 of about $29 million. Our price assumptions are below current market and thus some could say are conservative so, for example, our 2005 price forecast currently is more than $1 below current market and slightly less than $1 below current market of 2006 so there is some upside depending on your view of prices. If you look to the volume line, the impact of our very strong drilling activity and growing in both the Piceance area and the other basins will add significant segment profit growth of about $92 million in 2005 and about $79 million in 2006 both of those years should have a substantial uptick in volumes for us.

Looking at the next, move to slide 29, our 2004 guidance, it's changed as follows. And keep in mind that the guidance has changed. The previous guidance from our August 5 call is an italics directly below. We've increased our operating profit by $25 million in 2005 and 2006. Our DD&A is a function of our increased capital that I've talked about, and our capital has been adjusted for our increased level of joint activity particularly in the core Piceance properties and obviously for the new, promising projects at Trail Ridge and Ryan Gulch. The other reason to increase capital is due to the cost increases the industry, and we are experiencing which I discussed several slides before. If you look at our hedging, and production remains the same. Our hedge price remains the same except on one thing that's not on this graph on the hedged for the first quarter of 2005, in addition to that hedge would be is we put on a collar for 50 million cubic feet a day only for the first quarter of 2005 and the collar has a floor of $7.50 and a ceiling of $10.49 so we do have an additional collar for the first quarter of 2005 for 50 million a day between $7.50 and $10.49.

So to summarize our key point for our EMP business units we are more than delivering on the production growth we thought we'd have earlier as evidenced by our 18% growth. We have experienced higher costs along with the rest of the industry but we believe we will offset this with improved performance and stepped-up activity in our key basins in the new projects at Ryan Gulch and Trail Ridge that I've talked about. We continue to have a very high degree of success with our development drilling program and are increasing our positions in our core basins. In addition to the rapid rise in production we expect, which we expect will continue for years, our drilling will also continue to prove up our very large inventory of probable and possible reserves. Appreciate the opportunities to give you an update on our third-quarter and I now will turn it over to Alan Armstrong, Senior Vice-President of Midstream.

Great, thanks, Ralph. And good morning.

Main message you're going to hear in this midstream report is first continued high processing margins have allowed us to raise guidance for the third consecutive quarter. We did have some degree of noise in our numbers in the third quarter due to a change in how we are accounting for our Devils Tower fixed cash payment and I'll hit on that in just a moment, and then finally, we are raising both our capital and segments profit guidance in '05 and '06 due to increased expansion opportunities around our core assets that we're very excited about.

Moving to slide 31, we had a great quarter on a reported basis and we set another record for our recurring segment profit. The big nonrecurring item was an out of period adjustment of approximately $17 million that was due to a change in how we account for our Devils Tower fixed cash payments. In our second quarter our revenue was equal to our cash payments received. However, during the third quarter it was decided that we should recognize the revenue on a units of production basis. That has required us to deferred nearly $17 million of cash in the second quarter and approximately $5.8 million in the third quarter. This change in revenue recognition does not impact the economic value of the project or the cash flows but will tend to push some of these early earnings into the later years. The great performance we had was driven by above average NGL margins and also we had extremely strong performance and improvement with our OLIFENS (ph) group in both the U.S. and Canadian area as well. And then finally the great response from our operations group and our cooperations with our customers out in the Gulf of Mexico allowed us to limit the impact of hurricane Ivan in the third quarter to a little less than $5 million. So a great effort by our operations group and again great cooperation with our customers to accomplish that. There was a lot of the facilities that we had right in the way of the storm.

Moving to slide 32, first you can see the strength of this quarter compared to 03 and year-to-date. But in addition, we overcame a direct hit from hurricane Ivan as I just mentioned. We closed on the sale of our Canadian straddle plants which earned us $190 million gain that's showing up this quarter in discontinued operations. We signed a purchase and sell agreement for our ethylene distribution system which is now closed in early in October. And it's yielding us $28 million of cash and we'll also be booking a gain for that in the fourth quarter as well. And then last but not least, we completed negotiations on a settlement of an insurance dispute that brought in $85 million in cash on November 1. And this will allow us to record another gain of nearly $100 million in discontinued ops category during the fourth quarter. So we're very excited to finally resolve that dispute that we've had with Winterthur and some of the insurance agents on that, and we're glad to have that put behind us.

Moving to slide 33, this just gives a snapshot. It shows the relative strength of our reported net liquid margins during this quarter relative to the historical quarters. As you can see, the last time we saw this kind of blowout was in the first quarter of '03. The realized net liquid margin for this quarter is 17.64 cents a gallon for all of those who track it closely, and we have seen this continue into the fourth quarter particularly October, November. December, however, of course is still very hard to call.

Moving to slide 34, happy to show here we're raising guidance across all three years. This still assumes the five-year average pricing for '05 and '06 and the five-year average is for 99 through 2003 and it does not capture the spiking that we're seeing here during the last half of '04. Then focusing on the '04 guidance, which you can see a substantial increase in, and this is the third time that we've raise this. This increase range assumes a repeat of our third-quarter performance in terms of NGL margins and across the business and it also includes a 10 to $12 million gain from the sale of our ethylene storage and distribution system that I just mentioned earlier. And that does conclude what the sales that we would have that will show up in continuing operations. We are still continuing to negotiate these finalization of sales from our gulf liquids assets but those would be showing up in discontinued ops. On our capital spending, you can see that is up due to growth opportunities and efficiency investments, both of which dropped to the bottom line as early as 2005. The new well connects of $10 million represent the amount over and above the normal well connect of 25 to $30 million. So these would actually show incline and gathering volumes going forward. This is great news and it's certainly evidence of the increased demand that we see out there for liable gathering services in the growth base that we're operating in. These opportunities for expansion that you see here, the new expansion of 40 and 45, are just effectively expansions of our existing business and they don't include any large step out in our deep water Gulf of Mexico area. They do include some add-ons to that, but for the most part these are major expansions in the western areas and some of our more mature areas. To the degree we captured additional deep water opportunities this would show up with higher guidance and segment profit and capital in the future. And I certainly would be you understand stating it if I said that we are seeing plenty of opportunities out there and we expect to be able to come back with some exciting opportunities for growth in the future from that area.

Moving to slide 35, four main messages here really. First our margin normalized business shows continued steady growth. And you can see that with the diagonal bars there for those of you who are looking at black and white, and that is what we've done there is just normalized the margin to the five-year average for '04, '05 and '06 and so you can see we've got nice steady growth going into our base business. The two bars that you see on top they are stacked on top of '04 the blue and gray on top are both the actual margin above the five-year average realized year-to-date and then the expected or forecasted expected for the fourth quarter. Then also I would draw your attention to the green bars that are stacked on top of '05 and '06 there, and again this is showing our segment profit plus DD&A and it is showing the increment that we have showing up as early as '05 and '06 from increased capital that we're spending in '05 and a portion that is showing up in '06 as well. So, just trying to demonstrate there that we really do have nice projects that are even showing up -- they're not long lived project. They're showing up early on in our guidance here. We do continue to show strong free cash flows from this business. And as I mentioned earlier, we are continuing to have plenty of production out in our core areas to replace declines and our new well connects that you can see there with expansion in our well connects continue give us a lot of base of business for the future out there.

So, in summary our Midstream Business continues to produce great results. And we project steady growth despite selling off nearly $2.4 billion in assets over the last eight quarters. And we're very excited to about our future as you can see from what we're forecasting here. With that I will turn it over to Doug Whisenant which has a larger than normal grin on his face today.

Thank you, Alan.

Gas pipelines continues it's solid steady performance. Turning to slide 37, adjusting reported segment profit in 2003, for the write-off of software development cost, in 2004 for the write-off of cost to test and repair an idle of Northwest 26 inch pipeline, gas pipeline's quarter and year-to-date recurring segment profit numbers are slightly, up slightly from last year. Contributions from expansions completed over the last year, the largest being the Evergreen expansion on the Northwest system, lifted third quarter 2004 segments profit. In addition power generation demand in Florida drove gulf stream's earnings contributions up $5 million. These positive developments were offset by a third quarter decline of almost $5 million of short-term firm transportation on Northwest pipeline due to the collapse of the Rocky Mountain to San Juan gas price differentials. In Transco's (ph) third quarter 2004 IT revenues were reduced pursuant to an IT revenue sharing provision triggered because September 2003 to September 2004 IT revenues exceeded the annual thresholds set in the last rate settlement.

Turning now slide 38, gulf stream's operations were not significantly impacted by the weather that ravaged Florida and the gulf coast this year. In fact, for a time gulf stream prospered as power generators found other fuel sources curtailed. In early September daily volumes exceeded one million decatherms per day setting a peak delivery record. Weather has delayed construction work on gulf stream's 109 mile Phase II extension. Completion is now expected January 31, 2005, one month later than we previously estimated. Two expansions of the Transco system are moving forward nicely. We filed the certificate application for the central New Jersey expansion, a $13 million project providing 105,000 decatherms per day of new capacity for a New Jersey gas utility pursuant to a 20 year transportation agreement. We expect to complete construction and initiate service November 2005. We also now have a 20 year transportation agreement with a New York utility for a 100,000 decatherms per day of new capacity from Lidi Pennsylvania to Long Island. This $143 million expansion is expected to be completed in November 2007. At Northwest pipeline, construction has been completed on the Everett Delta lateral. A nine mile pipeline providing 113,000 decatherms per day of needed new capacity and into an important market growth area for Puget Sound Energy. While Puget owns this facility we built it and now operate it for them. In June we temporarily restored to service portions of Northwest idled 26 inch pipeline adequate to meet demand for most market conditions. We're now focused on the long-term solution. A complete replacement of the capacity provided by Northwest 26 inch pipeline in western Washington.

Turning to slide 39, we've narrowed the range of our 2004 segment profit guidance while the guidance for 2005 and 2006 remains unchanged. The Downriver vision of 2004 DD&A reflects the $4 million depreciation adjustment booked in the third quarter. Before we turn to the next slide to discuss changes in capital expenditure guidance, let me point out that we expect segment profit to increase significantly post 2006 as a large investments we are making in clean air act compliance at Transco, and the 26 inch pipeline replacement project at Northwest are reflected at increase rates on these pipelines in early 2007.

Now turning to slide 40, much of the change in CapEx guidance is due to deferral of the expenditures to later years. But aggregate 2004 through 2006 capital costs have increased 25 to $30 million since our last analysts's call largely due to an increase in expected expenditures to comply with the new pipe line integrity regulations. We've refined our estimate of total cost to comply with these new regulations through the 10-year period ending 2012 and we now estimate those costs to be 325 to $400 million up from the $265 million to $315 million we estimated last quarter. Much of this pipeline integrity work is front-end loaded in 2004 to 2006 due to the facility modifications required to make some of our pipelines pickable. Post 2006 maintenance type CapEx is identified on the top three lines of this slide should decline dramatically as we move past this front end pipeline integrity work we wrap up work to comply with existing clean air regulations and complete the 26-inch pipeline replacement project.

That concludes gas pipeline's third quarter update. Bill Hobbs will now cover power.

Thank you, Doug.

We're now on slide 42, which are key messages for the quarter. Our base power portfolio continues to generate positive cash flow in line with expectations. We continue to see signs that the market is stabilized and is improving. We're seeing improved liquidity in the market, spark spreads seemed to have bottomed up and are improving in areas such as well as the west and northeast where we have larger positions and we continue to hear favorable messages about competitive markets from FUR (ph) and the state of California. We are managing cash far more effective through the use of LCs and netting agreement. We are also seeing improved credit terms with our counter parties. And since our announcement to retain power we have entered into two risk reducing contracts. Although they are short-term in natures in that they are less than two years we believe they're positive signs that there is still demand for risk management and that we have the opportunity to continue to enter into agreements that solidify cash flows and reduce risk. Last week there was a favorable ruling from the California PUC that accelerated development of capacity markets by requiring the utilities to develop resource adequacy plans by 2006. We believe this will place a premium on in-city generation and provide the impetus for us to contract longer term with the utilities. And finally with our announcement to retain power hedge October 1st as Steve and Don has discussed. The effect of this accounting change will reduce earnings volatility, lower future earnings guidance, and put us on a path where in a few years earnings will more closely track cash flows. This accounting change has no effect on cash flows or economic value. It is purely an accounting change.

Slide 39 denotes recurring segment profit for the quarter and year-to-date of $109 million and $121 million respectively. We continued to reduce SG&A during the quarter. I will remind everyone that the prior period correction of $108 million in 2003 was due to reclassification of certain contracts we had with Enron. The gain on sale of assets of 208 million was largely due to the sale of the Jackson full requirement contract.

Oh, I'm sorry. Slide 44 takes from us segment profit to cash flow, working away from $109 million of segments profit, we subtract the unrealized mark-to-market gains in the quarter of $187 million and add back previously recognized mark-to-market earnings of $45 million which gets us to a segment loss after mark-to-market adjustments of $33 million. We then add the effects of working capital which was a positive $343 million and a credit $186 million back to other Williams businesses. A primary driver of the increased cash flow for the quarter was a return of cash to the issue as soon as of LCs. Power stand alone positive cash flow of 124 million for the quarter and a positive cash flow of $198 million year-to-date.

Slide 45 highlights the portfolio cash flow for the quarter versus our previous forecast. For the quarter our base power business generated $49 million of cash flow versus an expected $62 million. This was largely due to milder weather and less generation in the mid-continent region. California and the northeast cash flows were in line with expectations. For the year we are below expectations by 9%. When we add the effects of working capital, our legacy positions and SG&A, we generated positive cash flow of $310 million for the quarter and a positive $510 million year-to-date and expect to be at or above guidance for the year.

On slide 46, we adjust our segment profit forecast for the effects of mark-to-market in the adoption of hedge accounting. For the third quarter, we reduced $109 million of segments profit by $187 million of unrealized gains and add back $45 million of previously recognized earnings bring bringing us to a negative $33 million of segment profit after mark-to-market adjustments. Year-to-date we are positive $34 million and we forecast negative $20 million of segment profit after mark-to-market adjustments for the year. Please note the effects of adopting hedge accounting for 2005 and 2006 is a residual effects of mark-to-market accounting realized. Again this is an accounting change that does not impact expected cash flows or economic value. Profits on these derivative contracts have previously been recognized.

Slide 47 reflects the residual effect of mark to market accounting on our previous guidance. We start with our previous guidance and adjust for the residual effect of the mark-to-market accounting. The revised segment profit guidance is reflected but as you can see the previous cash flow guidance is unaffected.

In summary, on slide 45 the portfolio continues to generate positive cash flow in line with our expectations. We remain focused on managing the businesses to maximize cash flows and reduce risks. We're seeing market improvement. In the adoption of the hedge accounting reduces earnings volatility and puts us on path more closely aligning earnings and cash flows and has no impact on cash flow guidance and economic value. It is merely a timing issue as future segment profit is being reduced because the income has already been recognized. We'll be disclosing more detailed information or power tutorial on November 18 in New York. And with that, I'll turn it back to Don.

Thanks, Bill.

Next let's look at slide number 50, our consolidated 2000 through -- 2004 to 2006 outlook and we'll walk through the various components of our guidance, our prior guidance as you can see, a 1.1 billion to 1.4 billion four this year and then growing to a 1.4 billion to 1.7 billion by 2006. We have a number of changes. The changes relate to power, principally. The mark-to-market residual mark-to-market effects and the impact of hedge accounting. Other BU changes total $125 million or less in 2004. And $50 million in 2006 gives us a new guidance number which is reflective of the reported guidance reflecting this residual mark-to-market impact. And you can see it's somewhat lower. However, after reversing the mark-to-market impacts that we've previously described, you can see that our guidance, in fact, is increased from our prior guidance.

Cash flow from operations, also increases in 2004 be a 2006 from our prior guidance and grows quite nicely from 2004 to 2006. Capital spending moves up in 2005 relative to 2004 as we really get into some of the clean air act, pipeline safety act and more of the Northwest pipe spending and perhaps -- and that spending peaks in 2006 as well as the Northwest pipeline replacement project is completed. We also are increasing our capital spending as previously covered in the E&P business to drill up some terrific opportunities that we see as well as to expand our midstream gathering systems and take advantage of growing markets. Despite the increase in capital spending, we still have free cash flow in the range of three to $400 million each year, and it's growing quite nicely.

Flipping to slide 51, consolidated capital expenditures by business units, this slide summarized the changes and the capital previously described by each of our business units. And again, our capital spending is increasing somewhat to fund some disciplined EVA creating investments.

Next on slide number 52, this slide graphically depicts our forecast of reported segments profit which is impacted by the residual mark-to-market charges as well as segment profit without that residual mark-to-market impact and again you can see the segment profit without that impact consistently increases year-over-year. The slide also indicates the trend in our capital spending. Again we have an increase in capital spending in '05 over '04 as we drill up far more than our E&P reserves and expand our midstream system to accommodate additional business opportunities as well as comply with clear air act pipeline safety act and prepare to replace the northwest pipeline ruptured area. In 2006, once again, we continue to grow our investments in our business and then in 2007, and this is the first time we've provided any guidance whatsoever on 2007, you can see segment profit both with the residual mark-to-market effects included and excluded, grows quite nicely and capital spending falls off somewhat as well as the Northwest pipeline replacement project is completed. I think as Steve mentioned earlier, we do have some additional opportunities for investment disciplined EVA creating investments. Those are principally in the deep water Gulf of Mexico and the E&P area for the next couple of years, and perhaps our capital spending plan could change somewhat if we're successful in finding such investment opportunities.

Slide 53, again, it depicts graphically the progress that we've promised to our investors. We have sharply increased our cash flows and we continue to drive cash flows higher and higher while at the same time reducing leverage and reducing the ratio of debt to total capital.

Next slide, slide number 54, just cover a moment some information on the feline pacts. In order to eliminate $1.1 billion of debt, and a related cash receipt of $1.1 billion that was coming in February of 2005, and the negative carry on the debt versus the cash that we would have to park in order to be able to pay down that debt two years out, we took a step to take the debt out early. As we proceeded on that path, we received tenders to exchange $827 million, we issued 33.1 million common shares on October 22. We paid $49 million of cash, largely prepaying some interest and a modest incentive for pack holders to tender their pact units. And thereby we reduced debt by $827 million. We have a contractual remarking obligation. In November of this year, we are whereby where we are remarket the remaining $273 million of debt on November 16 and Williams may choose to purchase some of those notes and the remaining units will be exchanged into common shares on February 16, 2005. Overall, a very value-adding transaction for Williams.

Slide number 55, depicts a new view of our debt maturities and as you can see, our near-term maturities for the next couple of years are relatively minor. They build somewhat in 2007 but the top part of the bar there, the 273 million relates to the pacts and it's likely that that bar is going to be shaved somewhat before the end of this year. In 2008, we have our $500 million term loan B that comes due that's secured by some of our E&P properties and again we have a lot of flexibility around that. It's prepayable and to the extent that we have available cash, you could see us taking some action with respect to that or otherwise doing something to restructure that issue. Beyond that, significant maturities are out in 2011 and beyond and not really causing us much concern at this point.

Slide number 56, just to summarize some key points, again we'll continue to drive sustainable growth in EVA and shareholder value will be maintaining the cash and liquidity cushion of $1 billion plus to handle working capital volatility in the event of extraordinary commodity prices and related margins. We'll continue to steadily improve our credit ratios and ratings ultimately achieving investment grade ratios with our decision to retain power. That will take a while longer. And I would also say with our very substantial progress on the debt reduction front, we're well ahead of our plan. We will be reducing the pace of debt reduction in the near future as we really look to create more value through disciplined EVA-based investments in our primary businesses. We'll continue to reduce risk in our power segment, focus on cash generation. We'll -- now that we're in a position with sharply reduced leverage and strong and growing cash flows we're in a position to consider or reconsider our dividend policy and with respect to that we'll be mindful of our risks and credit issues while at the same time, thinking of equity holders and the best use for that cash. We expect to complete such an analysis over the next few months, and make a recommendation to our board of directors. With that, I'll turn it back to Steve.

Thanks, Don.

Looking at slide 58, we've looked at this before but I would just say you've heard this morning about some new exciting Piceance space and opportunities. You've heard the midstream continues to produce strong results, gas pipelines are generating steady earnings. Power continues to generate positive cash flows. Therefore, we believe the road ahead for Williams is very bright.

Next slide, just looking at a summary here, third-quarter results were strong. Our restructuring that I think we have been all about the last couple of years is nearing the finish line, and I think some evidence that we know it is is that this week we have eliminated the chief restructuring officer position. You'll recall that was a position that was created back in late 2002 to help us with asset sales, with cost savings, and ultimately was involved in the attempt to sell our power business. This does allow us to consolidate our senior officer team. Asset sales are essentially completed. Adequate liquidity continues as Don described. We are now much more about looking at growth opportunities. We are retaining power but our strategy continues to be all about reducing risk, generating cash and meeting contractual commitments and I would add to Bill's comments, I would encourage all of you to attend our power tutorial in New York City on the 18th of November.

Finally, the last slide, slide 60, you remember that this is the scorecard that we used during many of our conference calls in 2003. And we thought it would be helpful to provide an update on our progress to date. In terms of this scorecard, as you can see, we have essentially completed or are very close to completing the restructuring of Williams. And certainly the company is all about emerging as a new focused disciplined, integrated natural gas company. So with that we will be happy to take your questions .

What's going on with the Q&A. Are you hearing anything?

No, we are not.

Once again if you would like to ask a question, please press the star key followed by the digit 1. If you are on a speaker phone, please pick up your handset or depress your mute function in order to allow your signal to reach our equipment. Once again that's star 1 to ask a question. And we'll first go to Craig Sheer with Calyon Securities.

Hi, great quarter. Couple quick questions. Hopefully we can rifle through these. Alan, in the midstream what is the five-year average NGL net margin that you're using in the '05 and '06 projections?

It's about just a little under 9 cents a gallon is what we're using there.

Okay. And Ralph, in E&P, excluding the first quarter collar it still looks like you're still hedged on 44% on '05 mid-point production estimates in slides 28 and 29. Given the guidance assumes much lower prices than current market prices. What's available on the curve. Why not hedge out more?

We've looked at it from an enterprise perspective as you know for quite a while and we believe that actually the level we were hedged at is the optimal level for Williams. We just basically were opportunistically and took a little bit more out in the first quarter but based on the balance that we have of our production, also our power consumption of gas and the midstream consumption of gas, we believe the range we're at right now is really the optimal level for Williams.

I see. You see internal business hedges that are beyond the financial hedges you have? Between the segments?

Yes.

Okay. Great. And Bill in power, two quick questions. I just want to make sure I understand. The combination of the [inaudible] agreements and the off tick agreements are basically cash flow positive till the end of the decade; is that correct ? Hello?

Did you hear that, Craig? Yes, the answer's yes, that's what we're forecasting.

Great. And just my last question for you, Bill. And I apologize. I probably should understand this better. But power seems to be cash flow positive before working capital changes. But recurring earnings excluding mark-to-market effects seems to be negative. If mark-to-market isn't a factor, what non-cash costs are being amortized to get to us negative earnings if we have positive cash flow?

We still have positions that we still have legacy, what we term legacy positions like our petroleum business. We largely exited that this year, worked our way out of transport and storage agreements we had that was detrimental to earnings. We still have natural gas storage and transportation agreements from back entered into 99, 2000, 2001, those are underperforming. Those are the takeaways from the positive cash flows that you're seeing on the power side. And we continue work those off.

I see. So the positive cash flow is just for the specific power agreements but these other items make the other items excluding mark-to-market negative.

Yes, that's right.

And these other items are cash flow impacts, they're not non-cash?

They do have cash flow impacts.

Okay. And last question, Don, on slide 20 witness what he is driving the $85 million in potential reduction and other segment guidance?

Craig, just hang on a second. Let me pull out. Slide number 20, your question again?

On the other segment guidance --

Oh, other be a rounding of --

Right we're going to a negative 40 from a potential positive 45 at the peak there. What is kind of driving that?

Craig, there's some corporate costs in there, but principally I would just say rounding where we take some point estimates and we round to a range that we're comfortable with. So I think you can view it principally as a rounding.

Great, thank you.

Just to go back to your comment on power as well we'll be providing some additional information at the power tutorial on November 18 so with respect to under, Bill's comments on some of the legacy portfolio we'll provide some more color on that.

Perfect.

Our next question comes from Scott Soler with Morgan Stanley.

Hi, good morning. I had a few questions. First for you Ralph. In looking at these new locations, you were talking about Ryan Gulch and Trail Ridge, can you talk about potentially how many reserves might be booked per well, because it looks like that's a significant amount of new locations and we were just trying to be able to quantify that?

Well, we believe that it's similar to what we see in -- the Trail Ridge area is similar to what we see in the Piceance proper area and Ryan Gulch, a little deeper, a little additional opportunities possibly there so Ryan Gulch could be slightly higher per well than we see in the Piceance proper. And --

Okay. Okay. And then secondly, in terms of you all's capital budget and returns on capital, Don, I was hoping you could color in a little bit, the $200 million increase in '05 and 250 are showing '06 from prior guidance, what types of returns are you all anticipating and how much variability might you all have around those returns, because it looks like at this point you all are pretty comfortable with having a net debt to cap of around 50% or, therefore, putting more money into the business and I want to assessments that you all are making right now when you're looking at spending that much money?

Scott, I don't want to provide our hurdle rate but as you know we're on EVA and we do calculate our cost to capital and we like to have a nice comfortable margin above our cost to capital. The nature of these investments are such that they drive pretty strong returns. I think you saw within Ralph's area, you know, there's a component of that that is related just higher costs that we're incurring on our base drilling program but much of the increase in E&P, or at least increase in E&P is relating to Ryan Gulf and Trail Ridge and we would expect quite strong returns on those investments. Within our midstream segment, the additional investments we're making in these basins are also quite strong given that we already have very substantial investments in these basins than really extends our system.

On both of those businesses, what are the very basic long term commodity price assessments you all are may go to assess your returns?

Well, I'll let Alan and Ralph speak to that?

On the midstream, the assumption there, the investments that we're making are largely noncommodity related. There is some incremental benefit and some up lift that comes in later years. But for the most part that's all fee-based business as expansions, for instance, of our Wamsetter (ph) gathering system, a major expansion of our or Wamsetter gathering system that both the processing and the gathering business there is primarily fee-based.

Okay. And then well, I guess on A&P, if we could get a little color there please.

Well our point of view is below market and it's one of the things that we look at, but we also run number of scenarios that go substantially below to make sure that we would be, what we would term almost a worst-case scenario where we would be above cost of capital, but our current point of view for 2005 was in the $6.30 range dropping to about 595 or so in 2006 and actually decline through the decade. We also run scenarios of what we would need to be to achieve cost of capital and that number is substantially below by a couple bucks what those point of view numbers are. Does that help?

Yes, Ralph, some more of a normalized if you all are kind of looking at 2007 to 2010 the remainder of the decade you're moving that number toward 450 or something like that or.

I think it is. We can give you the exact. I believe it does turn down. You never know what really goes to go happen because the market is so tight.

And I just have one more question for Bill Hobbs if I could. We met with the regulators not very long ago in California, and it looks like moving to more of a capacity price markets is a very good thing. Could you maybe fill in a little more detail on how it looks like it's initially going in terms of how the capacity payments would work, and how much merchant upside that might potentially leave you in addition to getting capacity payments in California?

Well, the ruling, Scott, accelerated the capacity markets basically from 2008 to 2006 and we do view that as very favorable. We're in city generation and the grid needs our units to run to stabilize the grid and for efficiency as well as reliability. Basically the way the market design works now because price mitigation's in effect. We really don't get, -- we don't extract that value of having units in a load pocket. And there's work to be done on the capacity design so at this point, Scott, it's hard to say what the upside would be but we certainly view it as upside, and we'll be actively involved and are actively involved in all the rate making both the federal and state level and shaping that market design but at this point I couldn't really estimate what that upside could be.

And the assumption on the power business is you all modeled and laid out for people really doesn't, I wouldn't think, assume a lot of upside benefit on the potential there.

It does not.

Okay. All right. Thanks.

Our next question now comes from James Yannello with UBS.

I guess I'm a little confused. I realize that the power book is cash flow positive but I guess looking back the way you look at. The power ERN, is it correct to say that that cash flow is not cash flow positive currently in its entirety?

ERN is really a corporate function but the power portfolio is usually what we focus on. That is cash flow positive be a should remain cash flow positive. We are still working ourselves out of trading contracts both in petroleum and natural gas that originated back in the late '90s and early 2000. And as we work our way out of those due to lack of liquidity in the market and really just not focusing on aggressively trading those positions they have had a negative cash impact this year. One thing we are going to do as Don mentioned in the power tutorial, is we're going to lay out the rolloff of these legacy positions over the next few years so you can get an idea of what the power portfolio's doing and then as we roll out of these positions what the cash flow impacts of those are.

Okay. I guess on slide 47, I just want to make sure I understand this. For example, 2005, the revised segment profit guidance range, you have that there and then you say cash flow from operations below that. That segment profit range, if I'm correct, assumes the performance of the power book and the legacy position the then does the cash flow projection below that assume both of those two?

Yes, that is. That is our estimate to the best of our ability taking working capital rolloff and position rolloff, our legacy positions, and the cash flows that we expect to generate out of the power business and that's included in that range.

And it includes the legacy positions too.

It does.

Very good. One more quick question I guess for Doug. If I plug into the model basically to get to your guidance for 2004, even the high end of your guidance on pipeline, you really have to have a low number in the fourth quarter. To get to the low end, you really have to have a horrifically low number. Is that just being cautious or is that the new integrity expenses or northwest replacement expenses? I mean, I know you suggested that we're going to seeing them in '04, is that a big I am, in fact, '04 or if not what else could cause it to sequentially drop a lot and potentially a real lot from let's say 3Q.

No, there is not going to be any big negative impact of integrity expenses on Northwest or anywhere else. It's -- you know, it's not a commodity sensitive business. I think as you take -- you know, we have some adjustments that, you know, are not adjustments to recurring that positively impact the year-to-date number and that's one reason why you just basically can't take the year-to-date number and pro rate it forward to come up with the total year many of but, no, no there's no significant thing to cause earnings in the fourth quarter to be lower than it has been in the other quarters.

So if I am's correct in what you're saying, there's some lumpy items earlier in the year that are not going to follow through in the fourth quarter.

That's correct.

Okay. Thank you.

Jay, this is Don Chappel maybe just a comments regarding slide 44 of the legacy column there. Within that gross margin of negative 30, there's an interest rate swap loss of $35 million, a couple years ago when power was on mark-to-market, and wanted to preserve or in effect lock in some of the interest rate assumptions on mark-to-market calculations put on a number of swaps, those are still in place. Some cash has gone out, we're in a very low interest rate position so as rates go down it generates losses as rates move up, we generate gains. We have not taken these positions off because we're at such a low interest rate environment, it's something we continue look at but as you can tell it's something that is really -- not really associated with what you might consider to be the power side of the business although it's roots were in the power segment, so I just wanted to provide a little color on that. On an enterprise level basis, the impact is not so great because some of the swaps are in the company so that's something that we look to clarify during this power tutorial.

We look forward to it. Thank you.

You're welcome.

Next we have Faisel Khan with CS First Boston.

I just want to clarify. What percentage of the $100 million increase in CapEx at the production unit is from higher servicing costs?

We had approximately 35 million that have a 100 million so that this that case it would be about 35%.

And that he is for '05-06.

Yeah, that 35% of the 100 million overall from the base we believe our cost before you add in new projects and additional drilling that we were up about 8%.

And Ralph, what do you see your production mix being by basin kind out in '07, i.e., Powder River or Piceance or [inaudible] San Juan.

The Piceance would still be the major player. We do expect that the Powder should begin to add more to it, but I would say we're about 40% Piceance now, be a we expect that that will actually be over 50% Piceance by 2007 and Ryan and Trail Ridge, hopefully, will be adding some to that, and Powder -- -- would be in rough numbers about 20%, 15 to 20% of production and then the San Juan would continue to be about the same, around about 20%.

That's all out 07.

Yeah, those kind of numbers in 07.

And if I can just go to the mark-to-market gain that we saw this quarter, if I can just -- the exact source of the gain, I just assuming that came from the natural gas positions you had in your portfolio. Is that correct or is it the gain coming from somewhere else?

Primarily due to the underlying gas hedges we have against our tolling contracts.

Right. Okay. And then I think on the call you had talked about the cost, what would cost to repower the AS-4,000 plant. What was that number again, if you don't mind?

I don't think we've ever discussed the number.

Okay.

Publicly.

Fair enough, thank you.

I'd like to remind everyone, if you mind that your question has been answered please press the pound key to remove yourself from the queue. Let's move on and take a question from Marlene Howe with RBC Capital Markets.

Thanks very much. Couple questions. First I'm just wondering if you could give us an update on what you're planning in terms of a MLP if that's still on the drawing board?

Yeah, Marlene, this is Steve Malcolm. As we'ved to describe to people the last few times we've been out talking we're essentially in a quiet period in respect to the MLP and we cannot offer any additional insights into what our plans are.

Okay. I'll move on then, thanks. On slide four, Steve, and this is your slide. It shows a debt-to-cap of 69.1% at end of the quarter but then on slide 53 and maybe I'm misinterpreting this, that's possible. It looks like, and obviously one has to infer a little bit, it looks like the debt-to-cap is closer to 63% and I don't know, maybe Don or someone can reconcile that.

I don't have the detailed statistics in front of me here, but we'll look at that up and get you a answer on that point.

I'm sorry, it was 53, slide 53. And then just one final question. And I know it's already been sort of asked, not really the same one earlier, but both for E&P as well as for the midstream, you're talking about using future price of gas or assumed price of gas that's below the forward strip and talking about using the five-year average for NGL prices that don't include, you know, certainly the current spiking and I guess arguably don't reflect a lot of situations and a lot of fundamentals that we're currently seeing. I mean, does that make sense in terms of using a lower than perhaps expected price in terms of determining where to set your hedges, you know, does really result in value maximization? For instance, if you're using an expected price for gas that's lower the forward strip but then you can set hedges at prices that are probably based off the forward strip, doesn't it lead to over hedging?

I would say that, -- this is Don Chappel. What we use in our long-term forecast is one thing. When we make an investment decision or hedging decision we sharpen our pencils and we look at all the information that's available to us. And consider all of the facts be a come to a point of view at a point in time. So this is kind of different, different timing in terms of the forecast for different purposes.

Or different assumptions so you're using one assumption for your future forecast but another assumption with respect to your hedging positions.

We make it, I'd say we make a deep dive at a point that we would consider a hedging position so we see opportunities in the marketplace or we look at our enterprise position relative to commodities and we do deep dive around that analysis and come up with -- it's really more a spot point of view versus a long-term point of view.

Okay. Is thanks very much.

Maureen, this is Don again, just spontaneous to your earlier question on debt-to-cap. The Steve slide references the debt to cap ratio. The slide 53 depicts the depth to cap ratio at end of 2004 and the big variable there was the $827 million of feline pacts that were retired in the months of October. So that's forward-looking on slide 53.

And next with Merrill Lynch we have Sam Brothwell.

I think a lot of these have been hit and perhaps you're going to address this one more at the power tutorial. But as we look out towards 2005, are we still going to be dealing with all of these various mark-to-market reconciliations now that we've adopted hedge accounting effective October one or is that going to start to clarify itself?

Sam, this is Don. You're going to continue to see this analysis quarter after quarter for the next several years as a result of the fact that the residual mark-to-market effects will depress future reported earnings despite the fact that cash flows are expected to be unchanged and much higher than the reported earnings so this is something for, you know, clarity, transparency, better understanding that we'll be presenting quarter in quarter out.

But I think you indicated at the power tutor to recall you're going to give us an idea of how these things roll off over the next several years.

Absolutely, and I'll refer to you a slide that will at least be a first step to that and certainly the tutorial will hopefully take it to the next level. But figure back to slide number 46 you can see on slide number 46, our forward view of how these will reverse. It's also depicted, summarized on slide number 47 so the net, the net impact or reversal in 2005 is $254 million and then the net impact of reversal in 2006 is $269 million. If I refer you to the appendix, you'll be able to see beyond '06 and you'll see that it falls off quite sharply by '07 of the by about half or so. And again we'll provide more detail in the tutorial.

Okay. I did have to drop off the call for a little bit there. One other question on slide 29. Maybe you can clarify this, but you're uping your CapEx in '05 and '06 relative to where you were with your Q2 slides but if I go back and compare to the same slide from your second quarter your production numbers are still at the same levels and particularly looking at '06. When would we expect to see some of the impact of that start to show up on the production line?

We've moved up in the range. Quite a bit. And we may tighten that but at this point we just are leaving our range the same. We do believe that obviously our production will be up from where it was previously. But the range is sufficiently wide enough to keep it at the same level.

Okay. Thank you very much.

Thank you.

Next in our queue we have Kelly Cringer with Banc of America Securities.

Good morning. Just a couple questions. Don, can you tell us what liquidity is or what you expect it to be kind of -- what it is now I guess after you've taken out of the first slug of the feline pacts and what you expect it to be at the end of the $1 billion target that you noted in the presentation?

Kelly, liquidity, total liquidity is well in excess of a $1 billion target number that we've indicated to you. And more in the range of $1.5 billion. In fact, at this point in time.

Okay. And will the incremental, call it $500 million of liquidity that you have there, will that -- the use of that or will you do anything with that or will you carry any more liquidity than the $1billion, and if you won't will that discussion be part of the upcoming discussion that you noted that you would have regarding I think it was your dividend policy, but I don't know if that was more a broader discussion regarding your free cash flow uses.

I we've set the $1 billion as sort of a base level of liquidity and to assure we have to keep something in excess of $1billion for operating, you know, kind of planning purposes we tend to target something in the 1 billion, 1.3 billion range and target something in excess of that, you know, 1 billion, 1.3 billion range to be available for a number of different purposes whether it's debt reduction, reinvestment in the business or perhaps even a dividend.

Okay. And just to clarify, when you said that over the next few months you would consider, I thought I understood it to be you would consider kind of what your dividend policy would be, did I hear that right or is it just for your dividend policy was it a broader discussion regarding free cash flow uses.

I think the comment was specifically around the dividend.

Okay.

But you know we continuously evaluate opportunities to reinvest in the business where we're convinced that these are, you know, EVA, adding opportunities as well as comparing those against other opportunities such as debt reduction or perhaps in the future an increase in the dividend.

Okay. Thank you.

Our next question comes from Peter Monaco with Tutor Investments.

Good morning, thanks for your time. Two quick questions if I may. I believe you said that notwithstanding all the progress that you've made that debt reduction remains something of a priority albeit not at the pace that it's occurred to this point. If we were roughly seven billionish net debt or $7.5 billion net debt at the end of the third quarter, where might be at say the end of '05 or in '06?

Peter, I think that is think that's a very good question. I think we're not inclined to provide some guidance on that at this point. As we continue to evaluate investment opportunities versus debt reduction versus dividend, I can say that we do intend to continue to make progress with respect to our credit metrics and credit ratings. So I think you will certainly see some level of debt reduction, but we'll be balancing that against some of these strong opportunities that we have as well as we consider dividends. So I can't give you -- I don't think it would be prudent to give you any specific guidance but directly it's a more balanced approach going forward.

Fair enough, but given the statement debt reduction remains something of a priority. It's not unreasonable to expect the absolute balance to be somewhat lower still a year down the road?

Yes.

Okay.

That is correct.

And separately, is it correct that if we look out past '06, and assuming no further increase in the E&P growth CapEx budget, and I understand that that's not necessarily a correct assumption. Would be correct to assume that truly referring, truly referring free cash after growth cap next would get a bump from the fall away of the Northwest pipe replacement CapEx.

Peter, you're absolutely right.

Okay. Thanks a lot.

Our next question comes from Dave Thomas with Perry Capital.

Hey guys, good morning. Quick question for Ralph. Ralph, I think circling back to something Scott Soler had asked earlier where are you guys on the drilling operations in Piceance in total and you referenced the average booking per well reserve booking per well, but did you didn't give a number.

The Piceance has traditionally on a gross basis about 1.3 bcf a well. We believe ultimately in the Piceance proper we should have with further down spacing some movement in areas that we have not even done 20 acre spacing on, and obviously in some other areas, we need 10 acre spacing. We believe that we ultimately have over 3,000 locations in the Piceance. The Trail Ridge initially we hope to have, again, we have only drilled four wells, but we hope to have on a 40 acre spacing basis about 500 wells, and that reserve should be equal to the Piceance proper about 1.3 [inaudible], and then Ryan Gulch, we think will have 770 location on 40 acres, of course, now we are just now drilling that that would be our goal. Higher cost, deeper wells but the reserves there would be closer to more like a 2B type well, but, again, costs would be higher and over $2 billion type wells, 2.5 million in that range wells. In the Ryan Gulch it's very early, and those are high level numbers and we need to refine it and look at and slightly deeper and obviously a little different reserve characteristic. Trail looks identical to the Piceance Basin so far that we see there's more out crop of 2000 feet or so to drill through or slightly more than that so it's a higher cost, but, again, good costs and good returns.

On the 43, I just added that up to 4300 well locations and what do you guys net on those, your net interests.

We own essentially on the Piceance proper, it's all ours. The Trail Ridge is also ours. Essentially a 100%, and then we net off royalties and all that and the Ryan Gulch would be 51% for us and 49% for our partner.

So I guess by that math it would be around maybe 4100 located so is it fair to say 4100 times 1.3 gets to you 5.3 TCF incremental to you guys net.

The 40, you have to take part of that, 700 down to 350 and in that case if everything witness good and again we're talking about a lot of new stuff here, that's be more like 3800 locations or so.

3,000, I guess the 3,000 included Trail Ridge?

No, I see what you said -- 3,000 is Piceance, 500 -- Trail, 700 -- Ryan, but you cut that in half by the reserves, so I see what you did.

Right, so that should be in the 3800 --

Right, you're okay there.

Gotcha, and so again, taking that 1.3 VCF a well, I guess that would be around, you're saying, 5 TCF incremental in Colorado.

Some would be incremental, some of the 3,000 locations at Piceance are booked, but a lot of it is new -- it would be in our probable and possible category that would hopefully move to proved.

Okay, great, thanks a lot, guys.

Thank you.

And we have time for one final question coming from Scott Soler from Morgan Stanley.

Hi, actually wasn't a question, but a suggestion, since this is the end of the call. When you all have your tutorial on November 18th, I think it would also be a wise use of time to spend maybe half that time educating people on your EMP business, because you all have a very good EMP business when compared to many other companies that have done tutorials for analysts and investors and just wanted to suggest something to be considered, thank you.

Okay, thank you, we are at the end of our time. Appreciate your interest, appreciate your questions, your suggestions and we look forward to seeing you at the power tutorial on November the 18th, thank you very much.

That concludes today's conference call. Thank you, everyone for your participation.