威廉斯 (WMB) 2005 Q4 法說會逐字稿

Good day, everyone, and welcome to this Williams Companies' fourth quarter 2005 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, head of Investor Relations. Please go ahead, Sir.

Thank you and good morning, everybody, and welcome to our fourth quarter earnings call today. Thank you for your interest in the Company. As always, today, we will hear from Steve Malcolm, our Chairman; Don Chappel, the CFO; and the heads of our various business units - Ralph Hill, Alan Armstrong, Phil Wright and Bill Hobbs.

But before I turn it over to Steve, please note that all the slides that we will be talking from today are available on our website, Williams.com in a PDF format. Also on slide number 2 forward-looking statements details risk factors related to future outcomes. Please review that slide and slide number 3 talks about oil and gas reserves disclaimer. It's important and we urge you to read that slide as well.

Also included in the presentation today are various non GAAP numbers that have been reconciled back to generally accepted accounting principles. Those schedules follow our presentation and we urge you to look at those slides.

With that, I will turn it over to Steve.

Thanks Travis; and welcome to our fourth quarter conference call and as always thank you for your interest in our Company.

Looking at our first slide -- that would be slide number 5 -- that's some other major headlines for the year. First in 2005 we more than doubled our performance on a key financial measure. That being recurring income from continuing operations after mark-to-market adjustments. That metric increased from about 190 million in 2004 to 513 million in 2005. We also generated $1.45 billion of net cash from operations. Natural gas production was up significantly. In fact, domestic production was up 18%. We've taken steps to accelerate reserves development as evidenced by the fact that we've contracted for ten rigs from [Helmreich and Payne] over a three-year term in the Piceance Basin.

We had a successful launch of our MLP and, as you know, we previously announced that we have proposed to sell an approximate 20 from% interest in our Four Corners business to Williams Partners LP. The terms of this proposed transaction, including price, will be subject to the approval of the Conflicts Committee of the Board of Directions of the general partners of Williams Partners LP.

This proposal is still being considered and this is the only information regarding this proposed transaction that we will provide today.

Finally we made significant progress in resolving some of the legacy issues of the settlements on gas information reporting and ERISA.

Looking at slide 6, some of the details on the business unit results. E&P is growing production, reserves, and profits. Recurring results are up 122% from 251 million to $558 million; U.S. production up 18% mostly through the drill bit. We recorded 277% reserves replacement with a 99% success rate. Total proved reserves at 3.6 Tcfe. And as Ralph Hill will describe, the Piceance Highlands continues to show great promise.

Midstream generated strong earnings despite the impact of two major hurricanes. Our employees performed admirably during these hurricanes.

We are bringing new deepwater volumes online. We are committing to expand our capacity in the Rockies as evidenced by our acquisition of TXP-IV at Opal and the fact that we have commenced construction of TXP-V.

Gas Pipeline customer demand continues to support significant growth. Some of the major projects that we had announced -- Parachute, [Leidy], Potamac, Sentinel, Greasewood -- Phil will talk about those in a few minutes. We set another delivery record on Transco with a 8.73 million dekatherm peak day on January 7, 2005. And our rate case preparation has begun on Northwest Pipe and Transco. We would expect to file on Northwest Pipe on July 1st and on Transco on September 1st.

Finally, Power has continued to reduce risk. Had great success in executing additional mid-term deals and generated positive cash flow for the year.

Turning to slide 7. In terms of our guidance through 2008, as we run through our presentation this morning, you'll hear that we will be growing recurring segment profit after mark-to-market adjustments from about 1.6 billion in 2005 to 2.3 billion in 2008, that number representing the midpoint of our range. We are truly opportunity rich within all four of our business units, that we will be investing $5 billion in capital expenditures over the next three years with the majority of that going to grow our E&P production. And we expect to increase segment profit nearly 50% by 2008; and we will see continued improvement in our debt-to-cap ratio.

With that, let me now turn the call over to Don Chappel.

Thanks, Steve, and good morning. I will quickly run through a summary of our fourth quarter 2005 results and then turn it over to the business unit leaders for a deeper dive. I will come back later in the call to review our consolidated guidance and other matters.

Let's take look at slide number 9, a Financial Results summary. And I would note that income from containing operations and net income both include non-recurring items as well as mark-to-market effects. So I will focus my comment on the last line which is "Recurring Income from Continuing Operations after MTM Adjustments".

And you can see for the fourth quarter, we posted a result of $0.26 per share as compared to $0.09 in the prior year and for the full year $0.86 as compared to $0.35.

I'm pleased with our fourth quarter and 2005 results which are sharply improved from 2004 as well as in line with our previous guidance.

Recurring segment profit after mark-to-market adjustments for the quarter are 448 million versus 300 million of the prior year or up 50%. And that's detailed on slide number 77 in the appendix and for the full year, segment profit after mark-to-market adjustments is at 1.578 billion versus 1.263 billion or up 25%. And that is detailed on slide number 78 in the appendix also.

Additionally we are well positioned to see the many extraordinary value-creating opportunities that lie ahead. And we are even more confident in our ability to achieve the goals that we have set forth and will set forth during this call today. I'd also note that our 2008 segment profit guidance after mark-to-market adjustments is up nearly 50% from 2005 levels.

Next slide, please, No. 10. I will now walk you through the calculation of recurring income from containing operations, just highlighting a few of the non-recurring items in the quarter. We had an accrual for regulatory and litigation contingencies, totaling $78 million in the quarter or $96 million year-to-date. That affected principally the power segment. Impairments, losses, and write-offs related principally to two noncore investments and those were principally Longhorn and [Oxable].

We had expense related to prior periods. During the fourth quarter Transco recorded an expense related to prior periods. An adjustment associated with the accounting in valuation corrections of certain inventory accounts. On the year-to-date basis this adjustment was offset by other items previously discussed.

And then finally a gain on sale of assets, relatively small for the quarter, somewhat larger on the year-to-date basis. And we've detailed that in prior calls. Total non-recurring items for the quarter totaled $167 million before taxes. The tax effect and an adjustment to our tax accounts reduced that to 168 -- excuse me. Reduced the adjustment by 20 million and the total of that is $168 million or $0.28 a share and again on a full year basis $428 million or $0.72 share. Again this includes the mark-to-market effects.

The next slide, please, No. 11. I will walk through the calculation of recurring income from continuing ops after mark-to-market adjustments, really focusing on these mark-to-market adjustments which we think are important to better understanding our real earnings power.

Again, starting with the recurring income that we just calculated on the prior slide. We make some mark-to-market adjustments on our power segment reversing forward unrealized mark-to-market gains totaling 70 million in the quarter $172 million year-to-date. And adding back realized gains from mark-to-mark that was previously recorded, totaling 48 for the quarter and $310 million on a full year basis.

The net of that is, excuse me -- reduction in reported segment profit of 22 million after-tax, a $14 million effect on income as compared to an $85 million effect on a full year basis.

Also looking at the full year you can see that $85 million positive adjustment as compared to a $72 million data adjustment in the prior year or a change after-tax of $157 million. So again, I think it's really necessary to really look at our earnings power after these mark-to-market adjustments given the very large swings.

Next slide please. And this would be slide number 12. Focusing on Williams' liquidity at year end 2005, and I would like just to talk through this slide. Again at the end of the year we had cash and cash equivalents of about $1.6 billion and other cash securities just over $100 million. And then we had some special items that I'd like to note we had subsidiary and international cash, totaling $240 million and customer margin deposits of $321 million much as we deposit margin with other counterparties, other counterparties deposit margin with us. And we could be required to return that if prices were to change or if those customers would replace that cash with letter of credit. So, it's really not viewed as being available to us.

So backing out that $561 million that is earmarked for customers or for our subsidiaries, we have a cash balance of 1.159 billion at the end of the year and available revolver capacity of 961 million or about $2.1 billion of liquidity.

With that I will turn it over to Ralph.

Thank you, Don. Go to slide 14. I'm very pleased again to report a strong quarter for E&P. Our volumes continue to rapidly increase. Our segment profit more than doubled. I want to thank particularly our very talented and dedicated workforce and employees for their relentless pursuit of increasing our production in a very safe and efficient manner while also continuing to add new opportunities for Williams and our shareholders. I hope when I finish today and I share results with you, you agree that we continue to be one of the leaders in the E&P industry in production growth, cost-efficiencies, reserve replacement and you opportunities.

Slide 15. Segment profit is up as we mentioned fourth quarter. Fourth quarter 175%, volumes increased 14%, net realized price increased 79%. So a very strong quarter for us. Keep in mind we do have a significant number of hedges that we are out of the money that did impact fourth quarter earnings but still had very strong earnings growth for the quarter.

Slide 16. Looking directly at the strong production growth of 18%, our domestic volumes continued to grow. 18% this year. Our fourth quarter '05 volumes averaged 25% greater than the 2004 yearly average. So we continue to grow our volumes and as you know we predict our volumes will continue to grow between 15 and 20% growth this year and through our guidance period.

Slide 17. Accomplishments and current updates. I will talk about each of these a little bit more; but just for headlines, domestic volume growth is up 18%; total volume 17%. Reserve replacement I have 2 slides on reserve that's 277%. We added 34% new staff to our -- successfully to our E&P groups and we were able to go out and recruit new talent and also retain the talent we have to operate these assets.

Our Big George production continues to climb. We have 2 rigs operating in the Barnett Shale. San Juan Basin which is a very mature basin still is able to increase production by 4%. Our international group kicked in with a 8% volume increase and also had record operating profit from the volume increase and the increase in oil price.

We now have 19 rigs operating in the Piceance, which includes the second H&P rig which is on-site and should spud this week. And our Piceance Highlands production reached 18 million a day. I'll have some more information on each of these in a minute.

Slide 18. Looking at Powder River. The Big George continues to drive this. It was up 74 million a day or 101% over a year ago. On a sequential basis volumes were up 9% or 11 million a day. The Big George growth in the fourth quarter versus third quarter was up approximately 50 million a day. The [Wyodack] was down about 11 million a day so you can see the Big George is actually more than offsetting the Wyodack decline. Williams and its partner represent about 43% of the Big George volumes in the Powder River. We expect to be able to continue to have this kind of growth.

We are very encouraged by the growth in the Big George production. Generally the Coals are thicker, have higher gas content as we said as we thought they were and they are living up to their potential. Our drilling this year like last year and for the foreseeable future is to target the Big George prolific area. Looking at '06, 100% of our permits are in hand for the from the BLM or submitted. Basically have all our permits in hand through the majority of the year with a few permits needed for the BLM towards the end of the year. But we expect those will be given to us at any time and our water management plans.

Water management is part of the application to the BLM. We have those in place and we have 67% already approved and we expect to see the rest of those as the next few months move -- as we move through the next few months.

Turning to Piceance on slide 19. Piceance production growth, it's up 88 million or 34% in a year. Sequential basis up 5% or 17 million. Our volumes were down a little bit in the fourth quarter from what we thought they would be. We had some compressor maintenance issues, some interruptions on pipeline, a brief period of severe weather in early December. Those things all affected production slightly but still squeezed out 17 million a day growth and expect that to -- those kind of growth numbers to continue at the Piceance.

And as of March 1, we have 19 rigs operating in the Piceance. Those are divided into four Gray Wolf rigs, three Cyclones, nine Neighbors, one that we are borrowing from an industry partner and two H&P rigs. We will add eight more H&P rigs during this year which would take that number up to 27 but the loaner rig will go away at the end of this -- at the end of March. So we will be in the 26 rig range by the end of the year which is, essentially, our target is 25 to 26 rigs. So we will be on target for our rigs even with the delay and the delivery of the H&P rigs that we experienced.

Look at cost performance on slide 20. Our LOE is $0.36 per Mcf. Three-year F&D costs is $0.92 and our G&A is $0.34 for Mcf. We believe we had industry-leading performance in these areas. Not enough industry data is out yet for me to give direct comparisons but I do believe when the 2005 data shakes out and I review this industry -- us versus the industry comparisons with you, you'll see it's very favorable.

For example our three-year F&D costs of $0.92. That is below what the industry had on average and in our more direct competitor areas using the numbers from 2002 through 2004. So adding in 2005 costs which were higher I expect the industry's F&D costs will go up significantly. And ours is at the $0.92 range. I do believe we will compare very favorably in all these areas.

Slide 21 on reserves. I'm very pleased to announce our reserves are up to 3.6 Tcfe. Our domestic reserves are up 13.3% to do 3.4 Tcfe. Last two years we've grown 10.5%. This year we were able to grow 13.3% even from a larger base we're starting from. Domestic reserve replacement was 277%. That is one of the top numbers I've seen reported in the industry. Success rate, we drilled 1,629 wells. We had 1,617 successful wells for again -- for the third or fourth year in a row of 99% success rate. And we moved 603 Bcf of probable reserves to proved reserves and as you can see at the bottom of this slide we continue to be able to move our probables to proved reserves. The last three years we've moved almost 1.5 Tcfe of probable reserves to proved reserves.

So as we mention, talk about our probable reserves we feel very strongly that those are the type of reserves you want to have and the type that can be moved into the proved category.

In addition to moving this 1.5 Tcf of probables to proved the last three years our proved developed producing percentage of our total proved reserves has increased from 43% to 49%. So we are not only moving to prove to -- probable to prove, we are also adding in the sense of, we're not just adding [spuds], we are moving into more of the PDP sides and we have more revenue-generating reserves as we move through each year of drilling programs.

Slide 22 is a reconciliation of getting to our 3.4 Tcf domestic proved reserves. Just looking briefly from '04 to the '05 we sold 11 Bcf. We acquired a very modest range of 28 Bcf. We produced 224 Bcf. And in addition revision, total additions were actually 615 Bcf and we had 12, very minor level. 12 Bcf of revision. So the net number is 603 Bcf. So total 3.4 Tcf to the year end reserves.

Also looking at sensitivities in our reserves we believe the year end Henry Hub price, used as per the guidelines, was in a $10.80 range. If that price was cut in half we still would -- our reserves would only decline by about 1.9% or about 60 b. So our reserves are not really that price-sensitive. They are based on high return, long-lived reserves as you know.

So we do believe these are -- very proud of our reserve replacement ratio. Just to stress approximately 99% of our reserves are audited by either Netherland, Sewell for our conventional reserves and the reserves underlying the Williams Royalty Trust is handled by Miller and Lents. so approximately 99% plus of our reserves are audited by outside firms.

Turning to the Highlands Project summary. I won't go through the numbers on this table but you do see that Trail Ridge has now been approved for 10-acre density. Red Point already was 10-acre density. The importance to make of this slide -- these figures previously have not been included in our 3P reserves that we talked about or 8.5 Ts.

We have now booked of the Highlands 140 Bcf of proved reserves for the Highlands asset teams. So we have actually moved some of these reserves from this category which really wasn't even in our 3P reserves into a proved reserve category based on our drilling from that 2004, 2005. Primarily 2005. We expect to apply for 10-acre space now and point at the appropriate time. Using 10-acre density for all these projects would add a substantial -- more reserves to our portfolio. But as we mentioned before we have not added that in there. And just to stress, these reserves -- vast majority of these potential reserves are not included in our 8.5 Tcf of 3P reserves.

Looking specifically at some of the wells drilled today on slide 24. We have drilled as you can see 15 wells in Trail Ridge, eight in Ryan Gulch, six in Allen Point and two in Red Point. We are excited about what we've been able to accomplish. Our current production from this area is 18 million a day. We expect we have enough data now to know that there is a hydrocarbon system present. We are well along on our understanding of what can happen here and you'll see some of these ranges, particularly in Ryan Gulch, narrow as we continue to have experience.

For 2006, we will significantly ramp up our drilling program with 20 wells in Trail Ridge, 15 in Ryan Gulch and nine in Allen Point for a total of 44 wells. Also in this area you may just for outside knowledge, you probably have seen a [Berry] announce -- Berry Petroleum announce a transaction which was kind of in -- it was in the Piceance Basin area which had a tremendous market value we think on that. So I think if you look at those kinds of numbers that Barry Petroleum was able to do, what they purchased for and add that to some of our projects here, you can see there's a tremendous amount of value here for Williams as we proceed through drilling this up.

Slide 25. We have other opportunities. I believe that a well-established core capability of any organization in the E&P industry is also be able to identify grass-roots opportunities. Several of these opportunities are now at the stage where we are positioned to just began preliminary discussions of them with you.

Looking at this slide, the first is in the Piceance Basin at the Shale Ridge prospect. It is below the Williams Fork. We've leased about 14,000 in gross and net acres, have 100% working interest; 87.5% net; 10-year leasing term. We have another project continuing in the Piceance Basin, the Williams Fork project. Williams Fork will be similar to what we do right now in all of our drilling mostly the valley in the Highlands.

We are looking to finalize this hopefully in the near future. It will be 11,000 net acres and in 2006 we have a drilled to earn commitment. In Uinta Basin we have been able to lease about almost 40,000 contiguous gross and net acres. This again would be a Mesaverde type gas sands play. 100% working interest, 10-year lease, 87.5% nets. And in the Paradox Basin which is a resource play more the Ismay Group Shale and tight gas sands stones we had 30,000 net gross net acres leased. Again five- and 10-year terms on the leases, 100% working interest.

All of these are in the infancy stage but I think it's important to show you that we have been out doing other things and continue to add to our portfolio. As we get more information we will give you more and when it is appropriate. We do believe that they have or we wouldn't be in these areas that they have maturity potential and they capitalize our strengths in non-conventional plays and they give more gross visibility to our current rich inventory of opportunities.

Slide 26. We do believe we are a leader and I think these facts are proven out by this chart in U.S. gas production growth particularly through the drill bit. The left side of this slide, you can see just ranked by total production we were 16th in 2005 ranked by top 20 gas producers. If you look at production growth, we were 4th. But also I would mention that most of the people on this list in the top 20 U.S. gas producers on the right side, did significant acquisitions in 2000 -- either late 2004 or throughout 2005.

So on organic drill bit growth we believe we are probably the industry leader. I think it's just a testament to our portfolio we have that we can grow this kind and expect to continue this kind of growth for the guidance experience we've talked about.

Slide 27. Cash margin analysis. Similar to what I've shown before representative of our three-year point of view and recall that our point of view at the time of this slide and the time now there was there was a NYMEX price of $8,50 for '06 and $7.00 for '07 and '08. You still use that number minus fuel and shrink of about $0.65 which includes transportation of fuel minus our basis is about $0.75 and the hedge loss -- which is again about $0.75 -- you equate to this $5.75 realized gas margin.

The current three-year NYMEX as of February 24th was more in the 881 range. As of yesterday I think it dropped to like the 859 range. So still those prices are above the calculated strip that we were using which was 750. Even though there's been some weakness in '06 prices, '07 and '08 have actually stayed above our forecast. To reach the cash margin we deduct LOE which is $0.45, gathering of $0.51. operating taxes $0.51 since and our G&A was about $0.30 and we get cash margin of 398.

So this is obviously a very profitable margin on a cash basis. Another way to look at it is look at our three-year F&D cost of $0.92. We paid $0.92 and we are making a $3.06 margin when you take the 398 minus $0.92. We are making a tremendous margin on what we paid for. On an operating profit basis, basically take the 398 subtract about $1.20 to $1.30 DD&A. At times in our production you see how we get into our operating profit guidance range.

So, again, a very strong cash margin business and operating profit margin business. Even with the decline -- the recent decline in '06 gas prices we still have a very profitable business going forward.

Slide 28, our guidance. 2006 and 2007 did not change. We've added 2008. We still plan a very robust drilling program at 2008 that has been added of about 1700 to 1800 wells similar to 2006 and '07. We -- the midpoint of our 2008 production is greater than 1 Bcf a day so significant production growth during this period. Our compound average growth rate over this three-year period falls in the range of what I mentioned annual. Our annual range is 15 to 20%. Our compound average growth rate is in approximately the 16% range for this period. So we look to have a very strong production growth and operating profit growth during this period.

Capital spending stays approximately the same in 2008 and 2007, up slightly for potential new projects which won't really add too much to production. But we did up it some for that.

As for unhedged price assumptions, you can see those at the bottom and I think it is very key to look at our average San Juan/Rockies price at the bottom. 2006 is currently below what -- or above -- I'm sorry -- what the market is actually giving due to the recent decline. 2007, 2008 are below in a sense that the market is higher in '07 and '08 than what we have on this page in 609 and 610. On a 2006 basis 732 is actually above what the market would currently give it if it was priced out today.

Slide 29. Key points, hopefully, will see that we are an industry leader in production growth, cost-efficiency and reserved replacement. Our production increased 18%. We predict our production will be able to grow 15 to 20% through our guidance period. Our cost appears to be some of the industry's lowest and we will provide on our next call much more direct comparisons of our performance versus the industry. Our reserves did increase 13% and reserve replacement rate was 277%. So our strategy remains to be on top of our -- and rapidly develop our premier inventory. Stay on top of industry cost.

We have not seen significant cost increase over the projections we've put in to our plan for 2006. There is cost pressure, however, so what we're looking at is, we believe we put the right numbers in there. We believe the numbers will be able to withstand the cost pressures but as we move through the next three months, we will have to understand if our cost would have to go up at all.

Drilling rates are up slightly while our completion costs are basically locked in. So we don't see any completion costs in the major part of our portfolio. So we don't see a tremendous pressure on our completion side. Drilling rates are probably up about 2 to 5%.

Overall, we don't believe at this point we need to do anything to our ranges for increased costs but we will keep you posted. We're doing everything we can to diligently manage our costs and we think we've done a great job if you look at our record on how we are doing that.

We're also looking for new opportunities to start contributing and that is mostly in Highlands. As you know we have about 100 -- as I mentioned 140 Bcf of reserves booked in the Highlands now. We look for more of that to happen as we continue our drilling program this year. And we've describe four new opportunities that we will start to develop late this year and 2007 and we hope to be able to talk more about those to you as we develop them.

Finally, I would once again thank our workforce for a tremendous amount of work, a great effort during the year and looking forward to their outstanding achievements for 2006.

I'll now turn it over to Alan.

Thanks, Ralph, and good morning. Let's go ahead and turn to slide 31 here.

We're very happy with our 2005 recurring performance within midstream. Especially when you consider the 40% decline in Mont Belvieu frac spreads, three major hurricanes and asset sales that were in excess for our expansion capital placement service during this period. The 471 million was nearly $80 million above the midpoint of the arrangement provided this time last year and near the top of the range we provided in November.

So needless to say, we are very pleased to repeat a record year with continued steady returns and strong cash flows from this business.

Year to year story even though it looks pretty simple here, 471 versus 471, actually consisted of about $20 million lower NGL profits that were offset by higher fee-based revenues. You compare that 40% decline in Mont Belvieu frac spreads that I mentioned earlier, you have to realize the benefit that we enjoy by having the geographic diversity of our Western production offsetting what would represent the Mont Belvieu frac spread which is typically just the Gulf Coast frac spreads but is the industry norm.

So we're pretty excited to have been able to overcome that.

Also during the period, that $20 million lower was offset by higher fee-based revenues as we've indicated to you in the past we were headed towards so strategy continuing to deliver.

In the fourth quarter of '05, we delivered $112 million. This was another good quarter but was $39 million lower than the year-ago blowout of $151 million. And really speak to this, have to realize our NGL profits were reduced by about $51 million, quarter to quarter. And we were able to offset this with lower O&M and some higher fee-based revenues.

So all in all, very pleased with the year and very pleased with the way we performed in the fourth quarter to overcome what was some pretty good pressure on frac spreads.

Moving on to slide 33. Fourth quarter and 2005 highlights. A few points to make on this slide. First, you can see that we had much less volatility in recurring profitability from quarter to quarter in '05 there in the gold than we had in '04. And in fact the fourth quarter was just under the average for the last two years. So some very repeatable performance particularly when you consider the amount of external issues we had like the three major hurricanes that we took on.

Also we made great strides in positioning midstream for growth in the coming years as we established WPZ, which currently enjoys the lowest yield in its sector. We embarked on the construction of several significant expansions in our core growth basins and those are listed here particularly around Opal and in the deepwater. And we embarked on the construction of several significant expansions in our core growth basins.

And in the fourth quarter we were able to negotiate for the acquisition of the Opal TXP-IV terrain at our Opal complex and we enjoyed strong free cash flows from Triton and Goldfinger, which came on out at Devils Tower and just in the month of December there, when that was just starting up we saw $2.5 million in incremental cash flow just for the month of December there. So some strong profitability we are enjoying there.

Moving on to slide on guidance here. This is pretty simple story here of continued growth. This is tempered very slightly from our NGL profits we are forecasting to be about 20% lower throughout this period from what we saw in 2005 but, overall, very nice growth story here. The capital spending that you see here, the change we made to guidance on capital spending is really driven by two things for '06.

First of all $30 million that we spent to purchase Opal TXP-IV and then about $20 million that has carried IV from our 2005 guidance and so that makes up that $50 million there. So actually very little difference there other than the acquisition of Opal TXP-IV right at the first of the year.

Moving on to slide here on the prospects that we've been showing here. We have we continue to make good great progress here on various growth projects that we are pursuing. Don't have enough time today to go into a detailed update of these prospects. But really the short version is that we moved several projects from the development and proposal stage that was on the left into the Under Negotiations basket. And those of you all that were able to attend the Midstream Tutorial back at the end of November would remember this slide. And you can see that we are progressing some of these projects from the proposal stage into the negotiations stage.

Also a slight increase in the contract and the approved bucket here again just reflecting the added Opal TXP-IV acquisition in there. So we continue to be very pleased with the amount of opportunity that we're seeing in this sector. And we would expect to see that development and proposal stage continue to be filled in as new prospects come forward in all the areas that we are operating.

Just to highlight, moving onto next slide here. This is the Overland Pass Pipeline Proposal and this is just to highlight one of the prospects that we are pursuing. We first publicly announced this project back on November 30th at our Midstream Tutorial. We continue to be excited about this project and are excited to tell you that this project continues to move forward and is really starting to take some shape.

Surveying, engineering and right away on this proposed 7050 mile pipeline are all progressing and we continue to work towards an in-service date at the end of '07 or early '08.

As I stated back at our Midstream Tutorial, this project still represents the lowest cost alternative to flow the liquids from Wyoming into Conway, Kansas. And there will be relatively little horsepower required to move the product from the Wyoming area into Conway. So obviously that gives us a very low variable expense there.

This low cost of transportation will result in a very strong reduction in the tariffs that we are currently paying to be the [MPL] system to clear our NGLs into the market and of course that lower tariff will flow right back to the profitability of the Opal and Echo Springs facilities. So continue to be excited about this and lot of great attributes in this project.

Moving onto the next slide. Just summarize here on the key points. We just slightly edged out last year in terms of record for occurring annual profitability. You have to look pretty close to determine that but we certainly are pleased to the year we produced. Segment profit plus depreciation was $662 million. The MLP proceeds exceeded $78 million after the funding of Tahiti and various IPO fees and we brought in $68 million in before tax asset sale proceeds. And we only spent about $115 million in capital during 2005. So Midstream continues to produced tremendous free cash flows and we are excited Belvieu contributed in that way.

The spread between Henry Hub gas prices and Mt. Belvieu liquids declined 40% from '04 to '05. Yet our NGL margins only declined about 10%. Again that really was attributed to the geographic diversity of our assets and so we are very pleased with our ability to weather some of the volatility in those markets.

Then, finally, we are forecasting very strong growth in several sectors of Midstream and look forward to continuing to update you on the growth of those prospects. With that I will turn it over to Phil Wright.

Thank you Alan. Slide 38 please. Gas Pipeline segment, again, turned in solid profit and cash flow performance with recurring segment profits of $574 million. Fourth quarter reported results include the impact of two non-recurring, non-cash adjustments totaling $37 million associated with the revaluing of certain natural gas inventory accounts.

These fourth quarter charges partially offset the $49 million of non-recurring gains we reported throughout 2005 and will reduce full year reported earnings from 586 million to a recurring level of 574 million. The lower year-over-year recurring results are due primarily to termination of the Gray’s Harbor contract on Northwest pipeline, higher operating expenses partially offset by higher earnings from Gulfstream.

Slide 39, please. In addition to being another year of strong positive cash flow at gas pipes, our team delivered excellent results operationally and commercially. Operationally, we established three-day peak throughput level recorded on Transco and we met all of our demand obligations in spite of two major hurricanes. On the commercial front, as expected, the Central New Jersey expansion project commenced service on Nov. 1st and we held successful open seasons on Transco to serve the Northeast and Greater Washington D.C. areas via the Sentinel and Potomac Expansions, respectively.

Sentinel, which will add firm capacity of about 250,000 dekatherms a day is scheduled to be in-service November of '08. The Potomac Expansion will add 165,000 dekatherms a day of firm capacity and is slated for service in November of '07. We filed a certificate application for the previously announced Leidy to Long Island Expansion and I am pleased with the progress we continue to make on that project. We held a a successful open season for the Parachute lateral which will connect production from the Piceance Basin into a hub at Greasewood Colorado, the origin of another new lateral connecting Northwest customers to new production in the Rockies. Expected in-service dates are January of '07 for Parachute and November of '08 for Greasewood.

Turning now to our profit cash and capital guidance on slide 40. Noted in prior calls during '06 we have no major expansions, no rate cases coming into effect. As well due to a change at FERC and accounting policies will charge about 25 to $35 million of pipeline integrity costs to expense that had been capitalized before the change and will have $20 million of higher interest costs fund Gulfstream following the $850 million financing completed in '05.

So we expect '06 segment profit to be lower but to rebound, following rate cases on Northwest, Transco and Pineneedle in '07. We are lowering our guidance in '06 by $10 million to account for higher insurance premiums due to last year's hurricane and for development costs for the recently announced Pacific Connector pipeline project at Northwest which will be reserved and charged to income until the project is deemed viable, at which time the costs will be capitalized.

The only other material change on this slide is in our capital guidance for '06 and '07, predominantly due to the expansions I noted and which are summarized for you on the following slide, which is No. 41.

We've increased our maintenance capital range in '06 by $35 million to account for deferments from '05 and changes in our hurricane repair assumptions. Last fall, we forecast these repairs to hit in '05 and be reimbursed in '06. Owing to contractor availability and weather difficulties, these are now expected to occur in the first half of '06.

We've also increased our cost estimate to a range of $65 to $75 million, which we anticipate recovering from insurance. We've increased our '07 maintenance capital guidance by $30 million to advance work needed for pipeline integrity assessments that were slated for '08. The ranges for expansion-related expenditures have been increased now to include the Parachute, Sentinel, and Greasewood projects. This level of capital is well within our EBITDA and cash flow from operations projections and allows gas price to continue to generate positive free cash flow through the forecast period.

Slide 42 please. This map shows the excellent growth opportunities served by our pipelines. The projects in the shaded boxes have been recently announced but are currently not included in the capital guidance we discussed. Production area mainline and Mobile-based South expansion will enhance our ability to transport domestic productions an imported LNG from Gulf Coast -- from the Gulf Coast to markets along Transco.

Depending on market interest, the mainline expansion could add that to 750,000 dekatherms a day of firm transportation. We're currently holding open seasons for these projects; and both are targeted to be in-service in '08. We are pleased with the improving situation at Gulfstream, our joint venture system into Florida.

Gulfstream's conducting an open season to assess interest in a proposed compression-based expansion to add about 200,000 dekatherms a day of capacity with an in-service dating anticipated in January of '09. We are very excited about joining with PG&E and Fort Chicago Energy Partners to pursue the Pacific Connector, a 250 mile pipeline tying Fort Chicago's proposed [Jordan Cove] Oregon LNG terminal to Northwest customers and the Pacific gas transmission backbone system into California. Project completion is targeted for 2010.

Also, we've recently announced an open season for incremental firm storage service from the Jackson Prairie storage facility near [Shehalas], Washington where we are one-third owner. The project included in our guidance will provide capacity to serve long-term seasonal and peak day growth in the Pacific Northwest by November of '08.

Slide 43. Summing up, I am pleased to say that by almost any measure 2005 was another successful year. We continue to be a strong cash flow provider, deliver excellent results operationally, and our success is continuing in customer service as evidenced by No. 1 rankings in the Masteo and Company survey in the region served by Northwest and Transco.

Going forward, our focus is on placing new expansions into service and preparing our rate cases. With that, I'll turn it over to Bill Hobbs.

Thank you. We are now on slide 45. Slide 45 takes our reported segment profits and then adjusts for non-recurring items such as litigation contingencies, impairments, and then further adjusts for the impacts of mark-to-market accounting which brings us to a quarter-over-quarter and a year-over-year improvement versus 2004. Although a breakeven year for power, it was somewhat below our expectations coming into the year. When you consider very high volatile natural gas prices, hurricanes, plant outages and very mild weather in California, we feel 2005 was a success.

Slide 46. Here we take the segment profit negative 257 and again we adjust for mark-to-market accounting, adjust for working capital changes and you see power segment standalone CFFO of 127 million.

On slide 47, we have two changes to guidance. One is to adjust for the impacts of mark-to-market and the other is we are raising our floor in 2007 to 50 million, given it's a range of 50 million to 200 million, largely on the strength of the new deals that we have done.

Slide 48 shows a success we did have in 2005 and there's a couple of key takeaways here. First of all we were able to contract around each of our tolling positions as well as our customer types reflect a diverse group of utilities, banks, hedge funds and cooperatives.

Starting in 2006 on slide 49, and this slide does have a formatting error that we didn't catch and we will be fixed and on our web site but we have had early success in 2006, primarily in the Northeast. We have contracted for 500 megawatts of additional capacity sales for June 2006 through May 2009 with two utilities. And as well we did our first sale to a retail aggregator in the West position of 175 megawatts that runs through the end of 2006.

Slide 50 shows basically on a bar chart format the success we have had in contracting for additional capacity throughout the guidance period. As you can see, we still have additional megawatts left to sell that provides its upside in the hourly markets but also the opportunity to enter into additional long-term sales.

Slide 51 is a key slide. If you will look at 2006 to 2008, the guidance period, you'll see that the hedge cash flows are extremely significant. Especially compared to the merchant expectations we have. And if you normalize our SG&A for 2006 through 2008 to reduce it for the non-recurring effects in 2005, you can see that we predict a very strong cash flow forecast, even if you would back out the merchant revenues. However, we do see the market improving and we do believe the merchant revenues are very achievable.

Slide 52 walks us from 2005 recurring segment loss after mark-to-market and adjusts for the impacts of the new contracts that we have executed. Again in 2005, high natural gas prices, mild weather, hurricanes, and plant outages had a significant negative impact on our earnings. Although we do not forecast that for 2006, the new contracts have greatly mitigated that risk which gets us to our guidance range of 50 to 150 million.

On slide 53, in summary, again, we did contribute a positive cash flow to the Corporation, a stand-alone basis in 2005. Despite very difficult conditions in 2005, we basically produced a breakeven year and significant improvement over 2004 levels. We do believe in 2006 the market is improving. We are executing contracts. It's showing a lot of interest from our customers and increasing liquidity in the marketplace. So we are very optimistic that we will continue to have success and further contract into the future.

And certainly we are looking at some deals that extend beyond 2010, although at this point it's too early to indicate the possibility of success. We remain very focused on creating additional cash flow certainty and generating EVA and reducing the risk which is evident through the long-term deals we are contracting for. And as I've indicated, we are excited about our future and that we are going to continue to be able to offer risk management services to our customers for years to come.

With that, I'll turn it back to Don.

Thanks Bill. Let's turn next to slide No. 55, summarizes our 2006 forecast guidance. Again segment profit before mark-to-market adjustment is largely unchanged from what we had provided last quarter; and I would note that it includes $280 million of costs, related to mark-to-market effects. We do adjust that out by the bottom of the slide.

And lastly and most importantly, diluted EPS on a recurring basis after mark-to-market, we are estimating in a range of $0.78 to $1.03 up somewhat from 2006 levels. And I think very importantly it positions us for 2007, a breakout year.

The next slide please, No. 56. This summarizes the business unit and consolidated segment profit guidance after mark-to-market adjustment. The guidance is largely unchanged from our November 4th call and, again, I would note that 2008 at approximately 2 by 3 billion is up 700 million or about 45% from 2005.

The next slide please, No. 57. This slide summarizes business unit and consolidated CapEx guidance. I'd note Allen and Phil previously described changes from prior guidance, related principally to some timing rollover from 2005 to 2006 as well as new projects. And certainly in the case of gas pipelines, we would expect that those 2006 costs to the extent that they were maintenance-related would be recoverable in our rate cases that would be filed in late '06 and take effect in early '07 -- and to the extent that the related to growth projects in either midstream or pipelines, those earnings would take hold as those projects go into service.

The next slide please, No. 58. We've previously touched on segment profit. I will focus my comments on cash flow from operations. Again 2006 cash flow from Ops at approximately 1.8 billion, up from 1.4 billion or so in 2005. And, again, by 2008 our forecast is in more in the $2.4 billion range, an increase of about $600 million over '06, or 33%.

Finally, operating free cash flow was a negative number for '06 as a result of some very significant growth projects as well as the Northwest pipeline replacement project. As you can see by 2007 that diminishes somewhat as that Northwest pipeline replacement project and some other maintenance projects are completed, but still very substantial and driving substantial growth.

But operating free cash flow is positive in 2007 and very positive in 2008. And I think we're well positioned to continue to seize opportunities in our core businesses to create additional value.

The next slide please, No. 59, graphically depicts but we just talked about and as you can see, cash flows are strong and growing quite rapidly. And CapEx is expected to climb somewhat following 2006.

The next slide please, No. 60. This slide graphs our segment profit growth again with about $700 million of expected growth over 2005 by 2008 or just under 50%. And then finally on slide No. 61 just to hit a few key points, again, we will continue to focus on driving sustainable growth in EVA and shareholder value. We will maintain adequate cash and liquidity of at least $1 billion to handle margin volatility as well as our capital needs.

We will continuously strive to improve our credit ratios and ratings, ultimately achieving investment grade ratios even if that's out ahead of us a few years. We will continue to reduce risk in the power segment and we will seize many of the terrific opportunities we have ahead of us.

With that I'll turn it back to Steve.

Thank you Don. Briefly I believe our story continues to revolve around four key points. We own and manage world-class natural gas-related businesses. We are opportunity rich in terms of our investment options. We are investing in a disciplined manner by virtue of the fact that we've embraced the EVA methodology and we believe that we are in the midst of an attractive commodity outlook for our businesses. We can certainly prosper in a $6 to $8 gas price environment.

With that we will be happy to take your questions.

(OPERATOR INSTRUCTIONS) Craig Shere with Calyon Securities.

Couple questions. First Don or maybe the segment heads, can you provide what you see as maintenance CapEx numbers for each of your divisions? And then a couple of quick follow-ups after that?

Craig we'll ask each of our segment heads to perhaps make a comment on that. Phil Wright is prepared to that kick off.

Yes if you would turn to slide No. 41. At the top line there, we have our normal maintenance and compliance capital investment detail there. And I think as well we have in the appendix more information on capital. If you need a more detailed breakout of that, we are prepared to do it. But it gets kind of lengthy in slicing it up.

As you can see the big-ticket item there is the second line Northwest Pipeline 26 inch capacity replacement, which we've spoken about throughout the year and 2005 at $276 million in '06 and a couple of million of cleanup in '07.

I'll hit that next and also if you'll look in the appendix under what title, strong free cash flow -- not sure what the slide No. is there but it is in the appendix 87 you can see there both historically and in our forecast what the maintenance CapEx looks like for midstream. And also has the well connects in there and to a certain degree our well connects are running and place capital about 25 to 30 of that is what we think is necessary to keep production volumes level.

So but just the Cliff Notes on that, it runs about $30 million a year of maintenance CapEx and about 25 to 30 of well connects with that well connect capital increasing a little bit last couple of years but we are getting increasing volumes from that.

Gas pipes again. I failed to make one or reinforce a point that Don Chappel made earlier and that is with execution of these projects in '06 and '07 for maintenance, we do expect to be able to recover on those following our rate cases at Northwest and Transco.

This is Ralph Hill. We generated generally defined hours as capital required to keep our production flat. Our production has gone up significantly. We expect to continue. But to keep our production flat at levels we are at now we would estimate between probably 250 to 300 million, probably closer to the higher end of level to keep the volumes flat.

Great. Thank you. And Ralph, what are prospects for new technology deployment or obtaining reasonably priced rigs to meaningfully accelerate the drilling schedule?

We are -- we have accelerated quite a bit. And we look for -- there are other opportunities there are other companies we are talking to in addition to H&P about new technologies. [Nabors] has a similar type of flex rate if you will. It's (indiscernible) call flex rig that we contracted actually for a couple of those rigs to come to us in early 2007. So we are doing things like that and that's the kind of new technology I think that we're seeing right now, the top driven rigs, closed mud pits, closed loop systems on mud. Much more efficient type rigs.

So we are actively out seeking apparently new arrangements with our existing drilling contactors. Possibly others. So there are prospects there at this point we are at the range of the 25 to 26 by the end of this year but we are already in the process of looking to increase that number for 2007 and beyond as we speak.

Last question, Bill, what are prospects for hedging past 2010? And any comments on capacity markets?

Well I think in general still the utility markets are dealing in the three- to five-year range. There are things occurring in the market for instance, the Neptune line that is being built in the Northeast to take PGM power to Long Island. There's interest around that project because people will be signing up for 10-year capacity so I think they're starting to look for supply arrangements in that kind of timeframe.

We're certainly talking to all of our utility customers even the ones we have existing relationships with to kind of blend and extend the contracts that we have to -- the rules are changing very quickly. You mentioned capacity markets. But they are changing. And so we are always working with our customers to try to make sure the contractual arrangements fit their needs and ours.

Our view of capacity markets is you're probably going to see PJMMI occur in 2007 and California is scheduled to be 2007, but could slip into 2008. I will say this. The contracts we are currently entering into, the deals we are referring to do have a capacity feature to them. So even though there's not a defined market in all regions, customers are recognizing the need to contract for capacity.

[Shenir Gurshnooney] with UBS Securities.

Just three quick questions here. I guess the first question is when do you expect to update the 2P and 3P portion of your reserves?

Probably as we move this process we are thinking the next call we should be able to do that which is in May. May be more like midyear but we're in process of doing that now. The push was to finish our proved reserves and get to that process which we've now done and we will start to turn our attention to updating the 3P by midyear.

One other quick question just about reserves and this relates to Piceance Highlands. On slide 24 you have the expected estimated ultimate recovery ranges for the wells. I don't have your previous numbers but did you actually -- did you increase the range for both Trail Ridge and Allen Point?

I don't. I thought we tightened the range. I don't recall us increasing the range but you can see what we're trying to do as we drill more in each of those areas we are tightening the range. I think that should be fairly close to what we had previously. But we can I'll find the other slide and look at that for you.

Just switch me over to power for one second. I realize you just talked now about some of the opportunities that you had in 2010 possibly in the PGM market. But if we can switch to the Western site I guess, specifically, California. Has anything changed on the macro front that would change your outlook for, I guess, the confidence you have in extending contracts beyond 2010?

No. Not really. There's talks of some new power facilities being built but California basically needs about 2000 megawatts a year just to keep pace with the economic growth that it is seeing. So I think we will certainly reach a point I have said before I think it's probably more in 2007 or 2008 when utilities will be looking at contracts is far out as 2015. But there's nothing fundamentally has changed in any way to change our bullish view of that market to longer-term.

Thank you very much.

Nick O'Grady with Sandell Asset Management.

Question is on, as you may know one of your peers Western Gas Resources has talked about finding different ways to maximize value. Curious if you guys are looking at the same types of things specifically Midstream, E&P? Other ways to find value?

I'm not aware of anything new that has come out of Western on that. We will take a look at that if you'd like to call IR.

Next question please.

Carl Kirst with Credit Suisse.

Good morning, everybody. Just a couple quick questions on the E&P side. Ralph, is it fair to say with the new H&P rigs that are going to be coming down, that you guys are still very focused on bringing in new (indiscernible) hovels and possible to improve category in '06? Meaning that, should we still be looking for a double-digit growth in reserves in 2006? I guess partial of that it looks like S&D this year '05 was around $1.25. Is that roughly the range you are looking for 2006 as well?

Well, we -- it's hard to -- I don't think I can predict that at this time but we are all about trying to move our problems over to proved in addition to increasing our production. Costs are up slightly this year. We will have to weigh that versus the amount of reserves that we add.

We are also as you know going into some new areas that don't initially add a lot of reserves. We are also adding a significant amount of facilities this year, meaning 2006. And we started on 2005 to allow us to move all this gas for the period, late 2006 and beyond. So in general, our goal is to move as much over as possible each year and to continue our passive increasing our reserves while also increasing production. But I don't think we've ever protected nor will I predict at this time what we think but we have a great track record and we look to continue our track record.

Fair enough. One follow-up. Just looking at the Highlands, trying to get a sense of timing for when you might be looking at 10-acre spacing on Ryan Gulch as well. Is that something that I mean, could you at least even bucket it into an '06 or '07 type timeframe?

Not yet. And Ryan Gulch is our -- we drill the least amount of wells and as you can see the range on EURs is the widest range and there's still a question of will that even go to 10-acre spacing or stay at 40 or stay at 20. So we just don't know enough yet but we are planning to drill 15 wells there this year and we will have a much better idea by the end of this year on what we think that can be ultimately.

So Ryan Gulch is too early to tell. If it stays at 40 goes to 20s or can ultimately even be a ten. Just -- we just meed to do this some, much more drilling, much more experience in that area first.

That's helpful. Then just lastly, Don can you give us or if there was ever a timeframe ever established for the Four Corners deal? Was any timing ever talked about?

Carl, Steve mentioned earlier in the call that we are unable to discuss that transaction. So I'll respectfully refuse to answer. So you just have to stay tuned.

Fair enough. Thanks a lot.

(OPERATOR INSTRUCTIONS) Faisel Khan with Citigroup.

Good morning. If you could just walk through your guidance for '06. That roughly $1.86 billion in segment or operating income be high-end for '06. I look at your '05 occurring number after mark-to-market adjustments it's roughly 1.58 billion. If I look at your high-end of your EPS guidance of $1.03 compared to the $0.86. Can you just walk me through what is going on below the operating income line to net income?

That's causing a slower net income, net income growth over the last over -- '05 to '06, '05 to '06 versus the operating income growth?

I don't know what I have here to add other than what is on the slide that I'd presented earlier but certainly if you like to call the IR department we can certainly walk you through that. I think we pretty well laid out what the components are.

What about -- how about this? You are in the fourth quarter of '05, your interest expense goes up by about $10 million. Can you talk about what is causing that? Is it short-term, is it short-term rates? And then you're investing income miles that goes the other way by about, it's a loss of about 21 million?

I think during 2005 we did expand our credit facilities and certainly they were in place in the fourth quarter but we expanded our credit facilities to have more capacity to support our hedging program as other -- as well as provide additional liquidity for general corporate purposes. We're also anticipating a couple of financings related to our gas pipeline business to get the capital structure at the optimal level as we approach a rate case. So perhaps those factors are a couple of components of that.

Fair enough. Can you talk about the proved reserve side?

I might point you to slide No. 82 that does excuse me 82 -- that does detail some of the components of interest expense.

And those amortization and premium and other debt expense numbers, is that what -- did you have those types of expenses in 2005?

We had some similar expenses in 2005 and I think we also detailed that in our prior call. The November 4th call. So there should be a schedule similar to the one you're looking at.

On the proved reserve site can you the vested reserves boost of roughly 3.14 but there's an internal 200 (indiscernible) that came from I guess the international segment? Can you talk about what's going on over there?

Similar to last year we had slightly over 200 Bcf and we have that for quite a while and as through our ownership in APCO Argentina, and some other related properties down in, primarily, in Argentina. So that last year as we mentioned our domestic reserves were 3 Tcf meaning year end 2004. And that number has moved to 3.4 Tcf year end 2005. Adding volume -- reserves go up international but not significant amount so adding that to roughly slightly over 200 Bcf to the reserves '04 and '05 get us to the 3.6 Ts. So it's our ownership primarily in our Argentina properties.

You said your reserves are not that price sensitive meaning the higher commodity prices at year end could really effect any positive revisions or moving any more reserves -- did some reserves then become more economic as a result of higher prices. Is that true?

Yes; that is true. We cut price in half just to do some sensitivities and less than 2% of our reserves would actually go away. So that is correct.

Then in your -- for the pipeline companies or the pipeline company the rate cases that you have, that you are going to have ongoing over the next year or two, is that -- are you attributing any success to those rate cases in your guidance?

I'm sorry. Are we what?

Attributing any success in those rate cases in your guidance? Are you assuming that your rates go up on your pipelines?

Yes.

By the full amount or -- ?

(inaudible) for 2007. There is an assumption that we file rate cases late '06 and they go into effect during the first quarter of 2007 and that is included in the guidance for gas pipelines.

Thank you very much.

If I could respond to an earlier questioned. We did raise the on Trail Ridge and Allen Point previously the upper end of the reserves were 1.4 Bcf well and we raised that to 1.6. So to an earlier call, that is correct. We did raise the upper end of that range, kept the lower end the same and raise the upper end. Thank you.

Scott Soler with Morgan Stanley.

I have two kind of questions. One is just in terms of earnings guidance on '06 and again following on Faisel's question. I wanted to ask two specific points aside from interest expenses that is, Don on the tax rate the same on the effective tax rate? I think most people tend to model 36 to 37%. Is that higher now? Then also on the hedges on slide 84, the hedges are at a lower price than what was previously mentioned on the same production for '06 and '07.

I was curious. Why did that change? Then, I've got one question on E&P.

On the hedges I will jump in there just -- what we did was, the NYMEX price is the same. But in -- try to note here. Please note that it's based on locations, not NYMEX. What we're trying to give you now and we think it is a better way to model is, actually, the fixed price at the basin. So what I'm giving you is the actual basin price versus the -- .

I'm sorry, Ralph. I see that now.

No and we did footnote that but they didn't change in the sense of anything. We just wanted -- I think it's easier if you do the basin price versus the NYMEX price.

Okay. No, I'm sorry.

On your tax rate question we have a slide in the appendix that details that slide No. 83. We are using a 39% effective tax rate and the cash tax of 5 to 10% for the guidance period.

And then I guess on E&P I just want to ask kind of an update question for me. Chatted a month ago and I guess that just the general comment and I don't know what you can answer on (indiscernible) or not. On slide No. 26 it shows and on our numbers too when we look at all the in the companies in North America, Williams is probably the most successful E&P company excluding acquisitions of growing reserves and production through the drill bit yet if I put on that slide my net asset value and back into the value of the E&P business update the market our we think a market is that on the reserves as we roll forward reserves at like $1.25, which would put you at the lower range of valuation with the best E&P business in the industry.

And so I guess what I am trying to understand is how generally are you discussing potentially closing the gap and would it come through acceleration of drilling versus share buyback or, third, other options that you might have? Is there any updated thinking on that from when we met a little over a month ago?

This is Don. I'll just make a comment and if perhaps Steve wants to follow it but I think our strategy is to sharply accelerate our production. I think Ralph and his team have a plan to do that. Really, moving from 15 or so rigs in the Piceance at the end of 2005 to somewhere in the 26, 27 range by the end of 2006. And then kind of going into 2007 with that 26, 27 and perhaps more.

I think as we're able to get our E&P production up to a level that's optimal our -- certainly our earnings will come up sharply; and we would expect to receive a more fulsome valuation and with that and -- Steve has any -- ?

Yes; I would just add to that I think as Ralph Hill has described, we intend to accelerate our drilling in the Piceance and probably most of the new information will be around the Piceance Highlands area and just how attractive that opportunity is going to be. So I think proving up and validating just how good the Highlands are and how strong those stepouts are and to the extent that we can capture additional stepouts would certainly I think further drive value in the E&P sector.

We clearly understand that some investors believe it's possible to create some short-term bursts of value through modifications of our Company structure and to your point where I think you were going, Scott, we have analyzed -- along with many other options -- whether we could create long-term shareholder value through an initial public offering or a partial or complete spinoff of our E&P business. As I've said in the past our current assessment is that value creation if any from such actions would only be short-term in nature and wouldn't be in the best interest of our shareholders.

Now having said that, I think we've demonstrated a willingness to make structural changes when we believe that they support sustainable value creation over the long-term and then I think the evidence of that is the fact that we have, we did go forward and create the MLP.

So we will continue to manage our Company to create sustainable long-term value for our shareholders. To the extent that that objective would lead us to evaluate our structure we will consider all of the various options. But we believe based on our assessment thus far that we can create the greatest long-term value from our E&P NT business and for our shareholders by maintaining the integrated natural gas strategy.

Thanks for addressing it, Steve.

Maureen Howe of RBC.

I just wanted to return to the expansions of the pipeline and so I was wondering when you hold an open season and then proceed on to regulatory filing, what term are you looking for in terms of contractual arrangements from the shippers?

Let me state to reset experiences at example we are striving to maintain this level in our future expenses as well but if you look at the Leidy to Long Island expansion we had 20-year contracts behind that.

So is that sort of an average that you would look at or is that what you expect to get?

That is what we expect to get and what we have gotten in the past. Although I will be quick to say that there's a lot of pressure on that level of term in the marketplace. Competitors have been offering lower terms and we continue to deal with that. It's a situation by situation negotiation.

And before you proceed to a regulatory filing, what is that that you look for in terms of percentage of contractual arrangements? Is there a threshold in terms of covering fixed costs or is there a percentage in terms of available throughput on the line?

Each discrete expansion project is designed after the open season. We understand clearly what the market wants in the way of firm capacity. We design the facilities tailored to fit that and present those costs to the customer and that is, in fact, the rate that will be negotiated into the precedent agreement assigned with the customer. So when we go to certification we essentially have these projects fully put to bed.

When you say that then -- when you go to certification, you have the projects signed up to provide what you are looking for in terms of a threshold return on equity?

Correct.

Then I was just wondering, Don, in terms of the investment grade credit rating, I guess you get asked this almost every conference call -- but what is your current thinking and outlook in terms of meeting in your mind -- realizing that who knows where the credit rating agencies are -- but in Williams' mind, you know how long do you think it will be before you reach the target ratios that will give you an investment grade credit rating?

I think that's a great question and it's one that I probably can't answer but we are and have been reinvesting in a business for a couple of reasons. We think that that drives more value to shareholders than paying down debt and then also I think our investment grade rating will be more a function of our coverage of fixed charges than debt to cap ratio type metric. As well, I think the ratings agencies still are kind of on a wait and see basis on power. I think their view has improved quite a lot over the last couple of years; but I think they will be looking forward to our beginning to hedge beyond 2010.

So having said all that, I think it's just really indeterminable but it's certainly out there a couple of years or more.

You seem to be signing contractual arrangements -- arrangements on the power side and with pipelines or shippers. So what would you characterize as the biggest issues and problems faced by Williams due to a lack of an investment grade credit rating? Is it just the cost of debt or is it reducing your flexibility?

I think we're operating quite nicely with the credit rating that we currently have. Certainly the market is giving us much more credit than the ratings agencies, so we look at really where our bonds trade and how the banks deal with us much more so than our credit rating. So given that we are -- we have a great deal of flexibility. We have great access to capital and we've got reasonable costs. I think what the investment grade will give us is an incremental -- incrementally better cost, more flexibility and the ability to maintain lower cash balances as well as in terms of post less margin and less liquidity environments on hedges, or even on some new long-term contracts. Particularly in the power sector. So I think, overall, it will be a great help to us, but one that is not top of the list at this point.

One final question. It's just a small question for Bill. And it has to do with, we've normally seen, in the past anyways, a graph that is put into the presentation that shows the 400 million in (indiscernible) fixed charges and then your contractual commitment that goes out a number of years and I guess just shows the crossover point. I don't see that in this presentation. I don't see in the appendix.

Is this something that might be posted on the Website or -- ? Are you familiar with the graph I'm -- ?

Well, no, the appendix we are now just reporting through the guidance period so I guess that's the change you are referring to. It is basically the same schedule we showed before. It's just now just for the guidance period.

Thank you very much.

(OPERATOR INSTRUCTIONS) Sam Brothwell, Wachovia.

I know we are getting close to the curtain here but I was going to ask if you could maybe elaborate a little bit more. You touched on the interest expense question. Is it fair to say that you are probably going to see the maximum amount of pressure on that line item this year given the CapEx is so high? And I guess the other thing is, thinking about collateral posting requirements as gas prices move around. Can you comment on that at all? Throughout this year relative to last year?

Yes I would expect that 2006 would likely see some more pressure and in light of both the hedges we have in place and our need to have substantial liquidity to support those hedges, as well as the fact that we do have capital spending in front of us that is in excess of our operating cash flow. So we do have a need to find some of that capital spending. So we are maintaining perhaps more cash than we would otherwise, as well as a credit facility that is a bit bigger than we would, absent both the hedges and the high level of spending that is in front of us.

Wade Sookey of Banc of America Securities.

Just a couple of quick questions. I might have missed it but did you mention what the domestic plus percentage was at year end?

Yes I did. The domestic [PUD] percentage as now 41% and the PDP is -- I'm sorry, domestic PUD percentage is 51% and the PDP is 49%.

Was that 55% last year? Something like that?

Last year the PUD was 55%. Correct and the year before that, it was 57%.

And again, I think you mentioned it, Ralph 12 fees in net positive revisions domestically?

They are actually net negative so slight negative. So the slide 22 where you see 603 Bcf of plus -- says plus 603 add/revision there was 615 of add and 12 of revision. Just a slight negative revision. And they were just very miscellaneous.

Cost incurred. Could you walk through that reconciliation with me, exploration development acquisition on (inaudible) ?

Which one now? I'm sorry.

Just your cost incurred in E&P business broken out, exploration, development, unproved leasehold acquisition. Do you have that available?

I'm not -- say it one more -- sorry --

Capital expenditures, cost incurred.

What we spent last year, you mean?

Yes if you had it broken out between development acquisition unproved leaseholds. All that good stuff you usually disclose in the K.

I do have that. I don't have it in front of me. Primarily vast majority was for development drilling with approximately 30 some -- 30 to 35 million for facilities and a small acquisition in the Barnett which is about I think also about 40 million. So we will break that out in the K but it's most -- the vast majority was for drilling last year.

Are there any more questions?

(OPERATOR INSTRUCTIONS) [Jeff Byrne] with Matador Capital.

Just to follow up on the discussion about shareholder value and E&P. First of all, you guys have done a phenomenal job in the Piceance and in E&P and yet there's still this very very significant valuation gas. So kind of a several part question. You guys have done a great job. What will going from 15 rigs to 26 or 27 which will be a great accomplishment -- but how will that change the valuation gap that exists now? And if that valuation gap does in fact persist and it's something that you feel is best not addressed with an IPO or partial spin-out of the E&P business, why is there not perhaps a stronger consideration of a share buyback where you can buy your own reserves at a huge discount to similarly valued assets?

I think the point about what might drive value I think is around quantifying in more certain terms what the Piceance Highlands opportunity might be. And I think that's what -- why we think it's premature to take steps on doing anything with the E&P business. That's one reason.

As well, I really don't think I have anything more to offer on the issue of structural changes that we might take. I think I have been very clear that we have evaluated those options with our Board, with investment bankers and, again, all things considered, don't believe that it makes sense today.

But I'm not suggesting that that's the final answer. We'll continue to be open-minded about that topic. We will continue to evaluate it often and that represents our current thinking.

In terms of the share buyback we've talked about the fact that as we look at how we want to make the best use of the capital and the cash that we have available, we think that most of the -- the best way to grow shareholder value today is by investing in these extraordinary E&P projects. So we will continue to evaluate all of the options, both from a structural standpoint and how we best use our cash. And, Don, I don't know if you want to add anything.

Steve I'd just add and, Jeff, I kind of look ahead about 18 months or so. And, again, by mid 2007, we are drilling with 27 or more rigs in the Piceance as well as drilling in all of our other areas. We will have increased visibility around the Highlands perhaps opportunities to accelerate drilling there. Their two pipelines will have great cases. We'll have new projects both in Midstream and gas pipelines. Go into service we will have more time for the MLP to provide us with some benefits.

And the whole picture if you fast forward about 18 months, I think in terms of earnings, cash flows and prospects is a pretty bright picture. And I think we see a lot of value creation much as we have over the last 12 to 24 months. So I would encourage you to look forward; and I think you'll see the value that we see.

In terms of buyback, I think our credit situation is such that share buyback is out of the question. I think if we were to execute something like that, we would have a pretty severe setback on credit and the markets would be closed to us.

Just as a little bit of a follow on -- and I'm not try to be argumentative here -- I think you guys know we've been ecstatic about the job you guys are doing, excited about the next couple of years. I guess, Steve, what would be helpful, or Don, as you looked at the option of spinoff partial spinoff or an IPO of the E&P because I -- you know -- I mean -- that does not seem like it would prevent you guys on an operational basis from being able to essentially operate in the same manner you have been. The integrated way that you have been talking about. It simply would create a vehicle for those who want to invest in a pure play to do so.

So what am I missing there in terms of why an IPO or partial spinoff of the E&P would prevent you guys from on a day-to-day operational basis -- how would that permit you from continuing to operate the way you are now?

I'll just mention a couple of considerations. One is credit. We have a substantial amount of debt and if we were to hive off some of those cash flows from the E&P business, we would have to load that E&P business with a very substantial amount of debt, which would put it in a fairly weak position for an E&P company. So we really look at both the parent company, as well as the C&P company that we just described as being weaker than the combined company would be.

And I think that would cause some considerable valuation and opportunity issues, as well as the cost of governance and the related governance issues as well as the opportunities that Steve described here that we think are just now emerging. And we think it will be much more valuable in the future than they are today. So I think that along with the fact that we are not currently drilling up the reserves at a pace that is optimal. I think we're moving as fast as can be expected moving from one rig in 2003 in the Piceance, 10 in 2004, and 15 in 2005, to 27 by late 2006. I think we will substantially closed the GAAP along with the other steps that we're taking. So I'd encourage a little bit of patience there.

Well, we love what you're doing. We're excited about the future. We probably, respectfully, just disagree a little bit on the cap structures side but that's what makes the market. Thanks for the answers.

Rick Gross with Lehman Brothers.

I'd like to ask a little bit about the Piceance in the infrastructure spending that you are going to possibly due on expanding the gathering and processing facilities. We've seen in the local news out there in Colorado that you filed to increase the plant capacity from three to maybe six up to 800 million a day. And I'm just curious as to -- if that plan is recognized in your current CapEx either in E&P or over in the midstream business, what type of rig count you would need? By my own calculation you would need well over 35 rigs to build your own equity production which, historically, has been the feed into those plants. To 800 million a day. Can you flesh around what is embedded in the outlook as far as increasing the plant size and the infrastructure out there in the Piazza? I guess the current productions over the plant capacity of roughly 300 right now.

The capital is included in our guidance for the facilities we need. And essentially what we see is the -- basically, we will be getting to those kinds of levels at least our guidance levels with a 25 rig program once that's up by the end of the this year and cranking through. So we can reconcile the difference between 25 and 35 later. But basically that's our 25 rig program and run it at full speed, gaining some efficiencies on the -- in our -- both our days drilling, our completion, lack of rig moves. Because we can stay on the same pad longer in those kinds of things.

Essentially, yes, the capital is included in our guidance for our plant expansions and it is based on primarily a 25 rig program.

From a standpoint of firming up the plant size, and the fact that you are going to feed it with principally equity gas, is the full 800 in by the end of the forecast period -- '08? End of '08?

I think it is. I don't recall directly, so I'll say yes, I think and we can get back to you on that. And there is some -- actually some third party gas that we will be feeding into the plant.

Is it very substantial?

It's -- I don't know what substantial definition is. But it's a -- it's a good level. But not near what we will be putting into it, obviously. So hard to say. We're also negotiating for some of the third party still to come in. So I'll just kind of leave it at that.

[Dave Foley] with Grove Creek Asset Management.

Just one quick question for you and I'll let you guys get out of here. You have or it's my understanding that APCO Argentina just recently had a pretty significant find down in southern Argentina and I was just wondering if you can comment on that?

Not yet. APCO will have its 10-K files I believe within two weeks. I know our partner -- one of our partners in the field has sent some information out on that. I think they filed earlier but we -- they have had some good successes down in the this southern part of Argentina.

Thank you very much.

As there are no further questions at this time, I'd like to turn the conference back for any closing or additional comments.

Yes. Thanks for your patients. Appreciate your support and look forward to speaking with you next time. Thank you.

This does conclude today's conference. We do thank you very much for your participation.