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Executives

Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Keith A. Hutton - Chief Executive Officer

Vaughn O. Vennerberg, II - President

Bob R. Simpson - Chairman and Founder

Analysts

Joe Allman - J.P Morgan

David Heikkinen - Tudor Pickering & Associates

Subhash Chandra - Jefferies & Company

Brian Singer - Goldman Sachs

Scott Hanold - RBC Capital Markets

Michael Hall - Stifel Nicolaus

Shannon Nome - Deutsche Bank

David Tameron - Wachovia

Thomas Gardner - Simmons & Company International

Marshall Carver - Capital One Southcoast, Inc.

XTO Energy, Inc. (XTO) Q4 2008 Earnings Call February 19, 2009 11:00 AM ET

Operator

Good day ladies and gentlemen, and welcome to the Fourth Quarter 2008 XTO Energy Incorporated Earnings Conference Call. My name is Damoli and I will be your operator for today. At this time all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. As a reminder, this conference is being recorded for replay purposes.

XTO's management will be making forward-looking statements during this call. Risks associated with such forward-looking statement have been outlined in our latest 10-K, 10-Q and news release. Actual results may vary materially. The company undertakes no obligation to publicly update or revise any forward-looking statement.

I would now like to turn the presentation to your host for today's conference, Mr. Louis Baldwin, Executive Vice President and Chief Financial Officer. Please proceed sir.

Louis G. Baldwin

Thank you for listening today as we discuss XTO's fourth quarter results... 2008 results and outlook for 2009. Participating in Fort Worth are Bob Simpson, our Chairman and Founder; Keith Hutton, Chief Executive Officer, Vaughn Vennerberg, President; and Tim Petrus, Executive Vice President of Acquisitions.

As we typical do, I'll start with a brief summary of our fourth quarter financial results, touch on proved reserves. Keith will then review XTO operations. Vaughn will give you a brief hedging update, and Bob with wrap up with his perspectives. Then we will open it up for questions.

Please note that our fourth quarter operations review is available on XTO's website. In addition to releasing our financial results today, we also announced our year-end proved reserves of 13.86 trillion cubic feet equivalent, up 23% from 11.29 Tcfe at year end 2007. Those consisted of 64% proved developed reserves, 36% proved undeveloped.

Natural gas proved reserves 11.8 Tcf, oil to 267,000 barrels, natural gas liquids 76,000 barrels... excuse me 267 million barrels, nature gas liquids, 76 million barrels. If you combine natural gas and natural gas liquids, accounted for 88% for proved reserves on equivalent basis. Keep in mind that XTO's reserve estimates are prepared by Miller and Lents, independent petroleum engineers using year-end price and cost assumptions prescribed by the SEC.

During the year, we replaced 401% of production from all sources at a cost of $4.43 per Mcf. Our development program replaced 267% of production at a cost of $1.70, excluding revisions and leasing activities.

If we look at a separate case, $7.50 case for natural gas, $75 for oil, total proved reserves 14.66 trillion cubic feet, that's up 30% from last year. And present value future net revenues discounted at 10% before taxes, 34.2 billion would be our valuation there.

Turning to the fourth quarter results, we had a solid quarter with production up 11% sequentially, and cash per unit costs were lower. Even with our hedges in our book (ph), we were buffeted by the sharply lower oil and gas prices and higher basis differential for natural gas. Keep in mind our hedge prices will increase substantially in the first quarter, and we expect higher cash margins and higher operating cash flow in the first quarter compared to the fourth quarter.

Looking to 2008 annual results, we had record production of 1.91 Bcfe per day, up 31% from 2007 record revenue $7.7 billion. That's up 40% and record earnings $1.91 billion, $3.56 per diluted share and record operating cash flow 5.13 billion, $9.54 per share on a diluted basis.

If we compare our fourth quarter financial results to First Call estimates, our adjusted actual earnings were $0.68 on a diluted basis compared to $0.77 on First Call. Primary difference between First Call and actual is lower price realizations on oil and gas, but primarily natural gas prices due to higher basis differentials that we saw in the fourth quarter.

Our GAAP earnings were 351 million, earnings per share of $0.61 per diluted share. The adjusting items that we had for the fourth quarter was a non-cash derivative fair value gain of $34 billion after-tax and an impairment of proved properties of $81 million, so if we look at as adjusted earnings again $393.

For the quarter, natural gas production 2.66 Bcf per day. That's up 30% from the same period of 2007, oil production about 63,500 barrels, up 30%, natural gas liquids 15,400 barrels, up 7% and on Mcfe basis 2.640 Mcfe per day, up 29%.

If we look at the growth year-over-year, the 29% that we had, 19% of that was related to acquisitions, 10% related to development. If we look at the 11% sequential growth quarter-over-quarter on Mcfe basis, 7% of that was resulted from acquisitions, 4% resulted from development.

Average gas prices for the quarter realized $6.79, for the company, oil price $85.19, NGL average price $29.46. Our natural gas basis did widen in the fourth quarter on a company wide basis from $0.95 in the third quarter to $1.49 in the fourth quarter, again accounting for lower gas prices.

Total revenues for the quarter $1.961 billion, operating cash flow $1.32 billion and our cash flow margin was 67%. Again looking to cash flow for 2008, $5.13 billion with the cash flow margin of 67%.

Looking at operating cash flow per share on a diluted basis $2.29 for the fourth quarter, $9.54 for the entire 2008 year. Looking at our gas gathering, processing and marketing margin that was $35 million, up sharply from $3 million in the same period of 2007.

Turning to unit cost analysis and guidance, production expenses were $1.12 per Mcfe. That is at the top end of our guidance for the fourth quarter of $1.07 to $1.12. It is down from third quarter of $1.19 and the guidance we have going forward is $1 to $1.10 for 2009.

If we look at our further breakout, production expenses for the quarter of $1.12, labor and overhead, $0.24, maintenance and workover $0.66, power and fuel and CO2, $0.16, compression and other charges $0.06 to add up to the $1.12. Obviously our biggest decline on a cash basis was a decrease in power and fuel and CO2 and in compression and other.

Taxes and transportation and other $0.62 per Mcfe compared to $0.75 to $0.85 guidance. Lower oil and gas prices were responsible for the lower cost there. In 2009, we expect $0.60 to $0.70 on a per Mcfe basis.

Exploration costs $0.11 compared to $0.05 and $0.10 expectations, keeping guidance the same for next year going forward at $0.05 to $0.10. DD&A was $2.48 per Mcfe for the quarter, that's net of $0.53 for the proved property, impairment that we had and it compares to guidance of $2.35 to $2.40.

If we look at guidance for 2009, that is up to $2.85 to $2.95. The '09 guidance increase is primarily due to reserved quantities using SEC pricing. If we look in a little detail at the concept of year-end pricing, we have an unfortunate confluence of the lowest prices that we've seen in three or four years combined with higher costs that were used under the SEC. And so that resulted in the lower SEC case reserves that we have, that we are using for depletion. As reserve prices improve which we believe they will, you should see depletion cost go down as we go into 2010.

As for retirement obligation, it was $0.04 per Mcfe. We are keeping guidance the same for 2009 at 2 to $0.04 and cash G&A was $0.25 on the low end of guidance. So we're projecting cash G&A cost as 25 to $0.30 per Mcfe for 2009. Non-cash stock based G&A costs were $0.25 compared to our guidance of 12 to $0.18 and that was due to new plants, investing of stock incentives. We expect to return to lower levels for 2009. Again our guidance would be 12 to $0.18 per Mcfe.

Looking at interest expense; $0.64 per Mcfe compared to guidance of 65 to 70 and we are lowering our guidance to next year from 58 to $0.62 range and that will benefit from expected lower debt levels for 2009 compared to the fourth quarter. Capitalized interest for the quarter was $13million, $39 million for the entire year.

Income taxes; we have an effective rate of 36.7%, compared to 37% expected. We do expect a 37% rate for '09, at current portion we actually had negative current portion for the year as lower commodity prices drop our tax estimates we expect to have up to 35% of taxes paid on a current basis for 2009.

Also included with our reserve disclosure was our year-end cost incurred table which we typically will do from our cash flow statement for investment activities. But we can give you that.

Proved property acquisitions, 7.9 billion; unproved properties allocated from acquisitions of 1 billion and unproved properties from leasing 2.1 billion; development expenditures of 3.35 billion; exploration expenditures of 517 million, as overtime and obligation of 287 million or total cost incurred 15.2 billion.

Looking at the balance sheet total assets increased to 38.2 billion. After deducting cash and the equivalence of 25 million, our long-term debt would reduce from 11.9 billion to... 59 to 11.34 billion. Stock holders equity increased to 17.3 billion, including other comprehensive income of 2.6 billion.

If we look at the strength of the balance sheet, our net debt-to-total cap 40.8% at year end on a GAAP basis and 44.7% without other comprehensive income. That compares to 44.2% for year end 2007.

With that I will turn it over to Keith Hutton to talk about our operations.

Keith A. Hutton

Thanks, Louis. 2008 (ph) was a very busy year for us. We ended up increasing our operating well count from 13,000 wells at the end of last year to over 18,000 wells this year, so 40% increase and did a pretty good job of taking those on. You could look at our organic growth for the year, it was over 10%, maybe it was 4% in the fourth quarter alone. If you look at our guidance for next year, about 14%, about 10 to 11% of that is from acquisition rollover and 3 to 4% of it is organic growth.

I mean if you look at where we are going to go and basically push ourselves into some of the newer basins we bought into this year. And I believe through the acquisition and leasing program we have actually strengthened the company's position, moved out of the major leading basins in the U.S. going forward and should actually improve our economic position in all those basin, for drilling and finding costs.

If you look at our finding cost for '08 it was about 70, excluding revisions going forward with costs I believe dropping, probably 10 to 20% this year. It should be in the $1.50 to $1.70 range. Service costs are already down, 10% or so and I think they (ph) will be down 25% by the end of the year.

If you look at what our performance was in each of the regions, let's go first to the Eastern region, our Freestone Trend was actually up 6.2% from the third to the fourth quarter. We're currently running 24 rigs and if we're looking at next year we probably going to drop that down to about 20 rigs in our 14% growth rate, so slow down Freestone Trend's growth a little bit.

If you look at performance, the things that I would like to point out is, we have talked often about our deep Cotton Valley horizontals in the Freestone Trend, we've brought two on during the quarter, one at 13 million a day and the other at 12.7 million a day. Those wells cost about 6.5 to $7 million to drill on around 10 Bcf. So phenomenal finding costs and finding cost that you can drill even at the $5 level.

We also continued our 20 acre development program and those wells came in as expected anywhere from 2 to 3 million a day. And last but not least, we have had an extension area of south of Bald Prairie and Robertson County that we have been working on for two or three years, have increased our position here to almost 80,000 net acres and have started in earnest to drill development wells down there and had two wells coming at 6 million a day in the quarter from the land and Bossier and that gives us lot of hope and belief that area will pan out to be a major growth area, of course in future.

So slipped on the Freestone Trend over to the Sabine Uplift in Cotton Valley area. We drilled first Haynesville shale well in western Panola County, the New Horizon's number one that came in at 8.5 million a day, that is not an IP, that well averaged over 8 million a day for the first 15 days. It's currently offline because of the DCP Cartage flat (ph) issue, should be back up next week.

We believe that well from the way we're choking and holding our performance would have made over 8 million a day for the first month. If you look at the Haynesville wells you are seeing some that have 15 million a day, first month, you are seeing a lot that are 45 million a day first month sales. So, I would say this well as far west as it is, averaging 8 million a day is a good precursor for where our acreage is going to be plenty good on the Texas side. And may not be the top overwhelming growth, may be a hot spot and I am not so sure this well is the first one out of the bag. I am sure we will get better and complete and better, and we are exited about it. It sets up a lot of our acreages in Texas.

If we go from that to Stockman Fields in Shelby County, we drilled our first Haynesville line wells, before other companies talked about this area it came in at 10 million a day. We have pretty extensive acreage position down there for development as well. And then we brought in two James Lime horizontal wells at around 5 million a day in that same Shelby County area, so we're pretty excited about that stuff.

If you flip from the East Texas to Barnett Shale, production was up 14% quarter-to-quarter. We are currently making 70 million day on a gross basis, 550 million a day net. Most of our rigs we currently have 16 million or running in the core. We will drop that rig count through the year to average 14 in '09 and probably drop from the current 16 to 12 as we go later in the year. And try to drill in the core in the best wells we have and if you look at our performance in the fourth quarter, you have a lot of well coming online anywhere from 4 to 5 million a day. So Barnett has continued to perform above what most people's expectations are.

If we go to the Permian region, we have dropped all the way to one rig and we'll try maintain at a very low rig count in Permian. We try to maintain our production out there through work over program. One well that is coming in the Gulf Coast region that will give you an idea of some of the offshore potential we have from our Hunt properties, the South Marsh Island 40 C-2 which was a well drilled off a current existing platform which came at 16 million a day and about 500 barrels a day.

The San Juan region, we have also dropped down to one rig and we'll will stay there we'll probably do mainly coalbed methane wells next year in '09 which takes six months to a year to get to peak right. So you not to be able to drill them in the lowest finding cost and over time may get peak right back into very good gas prices.

In addition to that we have one rig running in natural buttes which we are mainly going to do deepening of our shallow assets wells in the May (ph) which cost about $800,000 or so and make about 800 million cubic feet, so again good finding costs on the spent (ph) gas price.

If we flip to the Mid-Continent division, we are currently running 19 rigs, majority of those are in Fayetteville and Woodford. We currently have 5 rigs in the Woodford shale. We have drilled some of the best wells in this last quarter that we drilled since we've been in the play, two wells coming at 6 million a day that were scattered across two different fields. And then we had our first well in the McAlister area in which we have a large acreage position, came in at over 4 million a day. We think these kinds of wells are 4 to 5 Bcf wells. So there are areas of the Woodford that don't pan out as well, we believe our acreage is in the heart. And we will end up with better performance than lot of our peers.

If we flip from that to the Fayetteville, we currently have 7 rigs running in the Fayetteville play. Our first four wells that we completed on the Southwestern acquisition have averaged 2.8 million a day, a couple at 3.5 to 4. So we're excited and surprised I think with what we found on the Southwestern acquisition.

If you take Fayetteville and Woodford together, we are currently making over 90 million a day net. So around 4% of the company's production is now coming out of these two plays.

If we flip from that to the Bakken shale, we currently have five rigs drilling up there that will probably drop to 3 or 4 as we try to maintain our lease position and not drill outside of our currently hedged volumes for oil. We did have good Three Forks/Sanish well coming in the crowd or number one at 1,300 barrels a day, which makes us have more belief that Three Forks/Sanish will be extensive over our acreage position for development in the future.

In the Marcellus, we did drill four vertical wells over the fourth quarter, two in Pennsylvania and two in West Virginia. None of those wells have been completed. They all look good on launch, in fact a couple of surprises and we'll get into little bit of that at the analyst meeting next week.

If we flip from that to just a quick talk on what we see is happening on gas production, in the U.S., gas rig count has dropped from high of 1600 to about 1030. We know of another 50 or 60 rigs that will be dropped over the next couple of weeks, next month or so. So I would guess that you're going to see natural gas rig count get down to 900 maybe to 800.

If that's true you will have a 50% drop in natural gas rig count. That is going to affect supply, and there has been a lot of worry that Haynesville wells at really higher rate might actually hold supply up. But what I'd tell you is take a quick look at Barnett Shale at the peak there were 200 rigs. I think it will be 90 rigs, soon in the Barnett Shale over the next couple of months. That's more than half cut. Majority of that cut now in the Barnett Shale is actually core drilling rigs on which average 3 to 4 million a day first month sales and they drill a good Haynesville well in 45 to 55 days. And if it makes 9 million a day or 6 million a day actually those Barnett wells are, every bit is productive on a time basis as a single Haynesville well is, because you drill three Barnett wells at the same time period as a single Haynesville well.

So I think you got to pick up as many Haynesville rigs as you drop in Barnett and I am not sure that's going to happen, I believe it is. And so I think what you're going to see by the end of the year is a 3 to 5% drop in production, U.S. natural gas production. And the way to look at that is, it will stay fairly steady through April and May and probably have a 10% tail-back decline in the back half of the year. And that will get you to a 5% decline for the year.

With that, let me turn it over to Vaughn Vennerberg to talk about our hedge. Vaughn?

Vaughn O. Vennerberg, II

Thank you, Keith. I would like to just refresh everyone's memory on XTO 2009 hedging position. As we can see our hedging program that we had in place in 2008 has proved to be very advantages for the company. Now let's see for 2009 we have natural gas and crude oil hedges in place at a $10.39 price on a natural gas equivalent basis. This represents about 80% of our 2009 expected production.

Our hedging goals, as expressed by Mr. Simpson and the company, has been to protect the cash flow so as to continue our development and maintenance programs through the up and down cycles of the industry.

In 2010, we have roughly 30% of our oil and gas projected production hedged at a 10.96 price on a natural gas equivalent basis.

And as previously announced, beginning of this year, and in recent releases we have monetized 70% of our 2009 hedge amounts, realizing $1.7 billion in after-tax proceeds. Those ones being used to reduce our outstanding debt.

For the future, we always are looking for opportunistic times to place additional amounts on for 2010. And we think that we will receive those in the upcoming six to ten months. We continue to monitor that on a daily basis. And so, we are very positive about that.

So, it's a good place to be right now, with the production that we have, that's been hedged and being able to realize the value of that.

And with that, I can turn over to our Chairman and Founder, Bob Simpson.

Bob R. Simpson

Thanks, Vaughn. Welcome everyone to our year-end conference call. I think you can see that the company had a great year in terms of adding inventory and prospects into the future.

One thing you would probably like talk a little more about is did we do at an economic cost, given what's going on, that we protect our values.

In my experience, XTO again, starting from no production in 1986 to equivalent of about 2.7 Bcfs a day now has done a lot of acquisitions and a lot of delta work starting from scratch. And what I would tell you is over a five or six years, we do a significant entrepreneurial move in the history of the company, which personally, I would like to do what I have done in the private arena of that year, because it's a lot of moving parts going on and in the public arena sometimes, there is some confusion and dysfunction from people wondering what's going on. And which is to be expected.

But anyway that's part of 2008, in addition to the extreme volatility of commodity price, commodity price a year today was $100 for oil, and roughly $9 for gas. And it seems further away than a year.

But we're... we have done a lot of hedging. We have secured the company's prosperity through this time and grow. And so, our strategy is that we have had in place for years. We are designed for this time. And so, we are enjoying the fruits of the wisdom of what the past has taught us and that we now implement.

So, if you look at last year was one of those entrepreneurial move years, and overtime you will see the wisdom and the fruits of it, and why we did it. If you look at what it has done for us in aggregate, as we own the inventory now, that we can visibility see how one doubles the size of this very large company.

And that was the major vision within it, just to be easy to be able to continue to grow and to preserve the company's advantage. And one of the results, and the primary results from a financial viewpoint of these significant moves that we make about every five or six years, is to preserve our financial advantage in the industry. And that is to contribute to have about half of the finding costs of our peers, or the industry at very high rates of returns to create shareholder value.

If you look at that, that's been done again, drawing your attention to the acquisitions, which was the primary dollars in 2008 that were expended. About 9 billion was spent for acquisitions.

If you look, you will see we booked about two tee's to that effort. So while that's at first was a that's pretty expensive. Looks like 450 to me, I don't see how that billing frankly equates (ph).

But, let me tell you what's behind that.

First of all, as we announced the acquisitions, we told you there was about 2.3 tees that we would book, or about another 300 billion. That was lost primarily in one area and that's the Bakken proved undeveloped for all at SEC case guide. And again from a business man's viewpoint, we hedge that all the first couple of years for about 125 a barrel. And so that's a write-down or a non-booking, we're in a write-down... non-booking that as a business guy really wasn't appropriate. But it is still what it is. That got restored when we ran a new case at 7.50 and $75, one of the reasons I want to run that is that to give the owners, including the owners here on this conference call as well as management owners and Board, insights of where we are in terms of value and really numbers that we think are sort of the minimum long term values. We would say $7.50 a gas to 10, $75 to 100 is our view over the next five years once we get through this downturn.

So looking at that, I gave you roughly $35 billion PB and for proved which is just the first plus of the values here, scratch of the surface.

Okay. Going back to the acquisitions of two teams, we also charged as we announced those acquisitions that we received six to eight additional teams to both side. And that's why we did it. And that's what turns... the first was not financially beneficial but they're very financially beneficial at the end over time.

So if you go through the math, 750 gas, you would value the proved producing reserves on acquisition is about 4 billion and the undeveloped at about 5 billion, which would have represented an additional... the six to 18 range, if you six plus the one that we did, that's reflected in our runs, at seven -- at 70s of upside for the remainder of the $9 billion expenditure, which is 5 billion plus what I see as the development costs at $1.50 over time, over the days will 9 billion. So, that, that would be all-in additional 7 billion, 7 Tcf for $14 billion are all-in cost of $3 for the products that we see.

And again, our division that I see for 2009 is that at the end of year with the SEC's new view of how to let us book reserves will be able to share more of the proved reserves with the investors than we can now. And that will start... for XTO that will be very significant because we have such significant upsides.

So, as you go back to the 9 billion acquisition accounting what we see as the development potential at the end of the story, you put up 9 billion initially, 9 billion to develop it, you'll have 18 billion in it. And we see all-in rate return on that of in excess of 30% rate return at $7.50 gas. And that's why we did it, as those kind of numbers are how we create value.

Feel back to what we told the investor years ago when we first went public, we said we bought acquisitions below teens rate of return and tried to move that into the low 20s. What we've been doing in the last decade is moving into the low 30s. And we think we've done that again and we think we did it in size. And that is the beauty of the work that was done.

Now, it was a lot of work and it was a lot of announcements of equity offerings in this that and other. But it is done, that move was made, and we've gone ahead and cash down 1.7 billion as debt to have paid for it. We put out that half stock as we win. We cash down 1.7 billion in debt.

If you look at the math of it for all the activity that was done, we spent 15 billion last year in aggregate on capital and that is a net about 38 and so it's about 80% paid for already, and that took the financial risk out of the endeavor.

We did that a little long and course we're all very grateful we did that as we went along because it was particularly important during the last year that one paid for it as you went. Now we did that with the combination of equity and hedging in the... operation as we get a hold of it, what you will see as we go forward is some reparation of some of the disturbance last here in other areas such as a more efficient lifting cost, a little better finding cost, our people sleep a little longer and in sort of efficiencies that will be regained as we digest.

Now the government budget we choose, now that we are into the first quarter with the guidance is out, it's basically as steady number as we go through the year. We got the fourth quarter steady, it lets us digest all we've done, work on our efficiencies, take advantage of the falling cost. And take advantages of the XTO advantage in general and that is cost, versus reserves.

And so the advantage is preserved, XTO will continue its high financial rate of returns on its investments. I think in aggregate this capital will yield at least 30% with $75 oil and I think those numbers will probably improve over time.

So looking back at it, value is going to be created and the process is in motion. It was a very good year. We appreciate your patience with us and we hope to reward you and expect to reward you as we move forward through the years with this XTO investment.

If you look at pricing in general, it is depressed at the moment. Gas is approaching $4 dollars today. We've been telling people, we think it bottoms in February. I'll stay with that forecast at least until March and that it's in bad years that's seems to bottom early and then people start thinking about what it mean. Right now we are all trying to digest what's the economy doing.

I think it's overbearing on the pricing of gas at the moment and that's just is what it is, it is a cyclical commodity, does tend to go to low and to high times. Our job is to normalize that and to have a hedging program which moves that out. And we do and we will.

So at the moment natural gas is a little extra depressed as is the economy. And that will serve correct and the scenes in production are sound within that price. And so it will get better, we will take advantage of this falling cost. And we'll spend our year primarily in the efficiencies that will be gained as we gather in all of this debt and all of these acquisitions and gather up our people and let them concentrate without also having to do large acquisitions at the same time. That is done. And so we will exit the year, our goal is 10 to 10.5 billion of debt which is kind of where it is today.

So what says is we'll be running our business our within cash flow the rest of the year to our expectations, considering that we already taking a $1.7 billion of the cash flow this year and put it on debt. So I was prepared to do that early, still have to get the balance sheet strong and we have virtually no short-term debt and that's a good spot to be.

So with that we'll turn it out for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Joe Allman with JP Morgan. Please Proceed.

Joe Allman - J.P Morgan

Thank you good morning everybody.

Bob Simpson

Good morning.

Keith Hutton

Good morning.

Louis Baldwin

Hey Joe.

Joe Allman - J.P Morgan

Hey, Keith, how many rigs do you plan to drop from here as I think you averaged 59 operated rigs in the fourth quarter, how many went down, and how many do you plan to drop.

Keith Hutton

That's actually kind of what the current rig count is we probably averaged 72 or 73 in the fourth quarter. And we're going drop down to 60 by the time we come out of the first quarter.

Joe Allman - J.P Morgan

Okay, and that will be the low.

Keith Hutton

We don't know, we'll see from there, for maintaining our production our rigs are getting much more efficient, guys. So one thing we're seeing is as you built in drop rigs you drop your least efficient rigs and so end up with faster and faster drill founders, there is no need for to us grow more. And so you might see us as our rig efficiencies get better, drop more rigs. 60 is our plan for the moment to hold it pretty flat for the rest of the year.

Joe Allman - J.P Morgan

Got you. Given the estimate on how much more efficient your rig fleet will be in 2009 versus the average of 2008.

Keith Hutton

No, not yet. It will be a moving target, most of our rigs we've had ramped out are pretty efficient. So you might be dropping one that 8 or 9% less efficient than the other ones but it's not a big number.

Joe Allman - J.P Morgan

Got you. And Keith, that net debt here you mentioned that of the Bald Prairie area it's aligned and looks like where was it like two wells or six million a day and you got 80,000 net acres. So what's the formation that you are producing from there?

Keith Hutton

It's actually Bossier and Lime mixed, as Bossier sands that cut through you there, those Cotton Valley centers even throughout this peak, most of what we are drilling for is the deepest inner wells at the moment which is Lime and Bossier. And we've got some normal wells that are 2 million a day and then here recently it's hit a couple of these really big pockets. We haven't drilled many wells down there, I would guess on the 80,000 acres we have a whopping 25 wells or something. So we got quite a bit more drilling to do to flush it out but we're pretty excited about those initial results.

Joe Allman - J.P Morgan

Okay, that's helpful. And then lastly of the negative reserve revisions you had, how much was proved developed and how much was spuds?

Keith Hutton

It's mainly proved developed, spuds don't get hit as much as you think, it's mainly tail end reserves because you had higher op cost and much lower prices. So it chops the stuff out there in the 40th year, and I think its something we should bring out that we often don't on the way we do reserves. We cut our reserves off at 40 years I've noticed a lot of companies are talking about running 60 years, we don't do that because it gives you an OPV. We just kind of settle out, I don't know we'll stick at 40, anyway just a slight likelihood.

Joe Allman - J.P Morgan

Got you, very helpful, thank you.

Keith Hutton

Thanks Joe.

Operator

Your next question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed.

David Heikkinen - Tudor Pickering & Associates

Good morning guys, just...

Louis Baldwin

Hey David.

David Heikkinen - Tudor Pickering & Associates

Thinking through activity levels in North America and the strap of with all your commentary of, I guess holding completions and completing as rig count drops of production and till April and May and then the big drop off, how is that following how XTO's production will look through the year, or how does your profile look versus the industry comments.

Bob Simpson

No I think what we've got is we're basically holding flat that's what our guidance is. So, yes we're not completing as many Barnett wells as fast as we can into $4 gas. Okay, that's we're not completing Bakken wells real fast into the current old pass either. So that means that fans it out for us, we did not drill as many wells as we might have been able to grow at faster at the start of the year that will help us to flatten it out. But what I tell you we're doing there, way to look at is we're cutting our rig counts in Barnett Freestone network, picking them up in Haynesville, Marcellus and Fayetteville. That we're basically delineating all these new areas we are in. So when we get into the 2010 we can go into heavy programs if that's where we choose to do and some of these are based.

Vaughn Vennerberg, II

Well we are having a net drop of probably 50 rigs over what we would have done if the original budget announced last fall.

Bob Simpson

Yeah we would even do 110 rigs originally which would have given us a 22% growth.

David Heikkinen - Tudor Pickering & Associates

So, you think about, what it sounds like as you're deferring some completions, kind of lengthening the cycle time on some of your developments that keep your production probably a little flatter. Why wouldn't the industry be doing that as well then?

Keith Hutton

They are but to get right out of it.

David Heikkinen - Tudor Pickering & Associates

Okay.

Keith Hutton

If you normally look at the way the world completes well, this is what happens as you do... you complete your fourth quarter wells in the first two or three months of the first quarter. That's just kind of the way it rolls. So, you'll get a little bit of run out of your stuff you were drilling in '08 in the first quarter. What we're saying is you might get people try and to stall it out for April or May. But, if you're not completing wells as fast your production is falling. So you got an issue of that trap. I just think people will stall some of that out. But that's going to be only in your shale plays. It's going to be in your plays where the rigs are running at massive rate. I mean, they can't get pipelines to them so fast enough.

Yeah, it won't be across the board. That's why I don't think you are going to see the whole. Everybody else has got normal wells. They will be trying to complete, would be my guess.

Bob Simpson

The industry has flattened twice the decline period we are. So, they don't have as much as quiet period we do to do some of these things. It still holds at flat. And so, if you look at what we will be doing, we'll be managing basically a quarter-to-quarter flat for a while. What that allows, in aggregate we'll have a 14% growth year-over-year which is plenty enough from Texas.

But as we will manage that we'll have, that's kind of this quarter's rate throughout the year. What that allows us to do is work on efficiencies. It also allows that underlying decline curve, which is about half the industry already, to get even better, because wells will be settled now. So, we might pick up a point, point and a half this year on underlying decline, right, versus our competitors. It is one of the advantages we have right here that we'll also be deploying in this environment.

David Heikkinen - Tudor Pickering & Associates

And have you built that cost decline into your overall guidance or is it that...

Keith Hutton

We built about 10%. But that's really...

David Heikkinen - Tudor Pickering & Associates

Okay. But not the 25?

Bob Simpson

Yeah, we're making the stab. We hope it will... but it will be an average for the year and...

Louis Baldwin

I mean this 25 at the end of the year will be 12.5, you did exactly right (ph).

David Heikkinen - Tudor Pickering & Associates

Yeah exactly.

Louis Baldwin

So, that's kind of your...

David Heikkinen - Tudor Pickering & Associates

Perfect. Thanks guys. See you next week.

Bob Simpson

You bet. Look forward to it.

Operator

Your next question comes from the line Steven Deck with Jefferies & Company. Please proceed.

Subhash Chandra - Jefferies & Company

Yeah. Hi, this is Subhash for Steve. Good morning. I had a question. In the Barnett, I'm sorry, I missed the rig count going forward.

Keith Hutton

We are currently at 16. We're probably going to drop it to 12.

Subhash Chandra - Jefferies & Company

12, got it. Okay. Have you reviewed sort of what you think Barnett peak production. I know we have had detailed conversations in the past. Anything looking at the sort of the new rig count, what peak and when peak might be out of that play? And is there anything other than price that you think is driving core Barnett rigs to come up so fast, equal to or greater than the national rate, when one might have thought that some of those reserves would be resilient. And maybe not at four, but certainly at 450 or 5?

Keith Hutton

I think, some of that's specific company issues, Subhash. And so, a lot of it is, if you are not hedged, you may be dropping, because you don't have the cash flow for it. And most of it's HP pits, so you don't have to drill it. Okay, so that's kind of your options. Now the same goes for us. We drop into 12. We can hold all our leases, and we don't really press our volume growth that way either. I mean to a lower price deck for the moment.

Why would you drill your wells, if you can wait a year and drill them at $7 gas maybe? It actually makes economic sense to play it that way. I don't think there is anything wrong with the core. If that's what you are asking. I mean, I think everybody's wells is in the core.

One thing, I would say is, if you are looking at Barnett peak, I don't think anybody thought that we would go to the number... well rig count in the Barnett, we now know is going to happen, as people have flushed out their budgets, because of their cash flow issues.

If you have your rig counts, you are going to see production flatten out, if not drop. If they held it for very long, it will drop. So, you are currently at 4.6, 4.8 Bs a day, you may see it peak at 5 or something, not very much above 5 and start to roll in. I can tell you this from, I mean go back and look at the industry as a total in 2001 if you drop your rig count 50% and you don't immediately pick it back up in next year, you will see a decline over next two or three years. Because you just can't chase that underlying decline fast enough.

So, let's say we drop to 90 rigs in the Barnett and go expect to 100 the next year you're going to see the Barnett decline. You're not going to able to chase it. You are going to have to hit back up to 160 or 170 rigs to get start it rolling again. And so, you may very well be seeing in the peak in '09, that may be correct.

Subhash Chandra - Jefferies & Company

Well, good. And in the Haynesville anything unique to that well or that completion or that any sort of comment you can make on the repeatability of what you just did? Or is it too early to say and that were there any challenges unique to drill in the Haynesville in Western Panola?

Keith Hutton

We'll talk a lot more about that in the conference, but I'll tell you no, there is no unique... uniqueness to it. I would tell you that one thing that we have an advantage over many players is because we've been drilling this deep, hard to drill Cotton Valley Lime horizontals over Freestone. They have high temperatures and high frac gradients. We are already up the learning curve more than lot of our competitors, I think for that style of well. We did have a lot of issues on this well. We did drill a pilot hole which costs a little more to make sure about 10% it was (ph). It's very sick over there.

So, its 300 feet acre or so we were drilling. Anyway I don't think otherwise other than that there are real unique issues to that. I do think it's... I'm going to surprise some people, expect good out there, because there's not a lot of chatter, I know about Texas not being that good. I would... we've always said you need to wait till people have drilled enough wells. So there is always well controls in Louisiana. That makes us feel good about it, put it that way.

Subhash Chandra - Jefferies & Company

Thank you.

Unidentified Analyst

Yeah.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs. Please proceed.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Unidentified Analyst

Hi Brian.

Unidentified Analyst

Hi Brian.

Brian Singer - Goldman Sachs

Following-up on Subhash's question, what were the cost of drilling both the Haynesville shale and Haynesville Lime wells? And I guess you mentioned you drilled that pilot hole as well, with and without that and then what are your future plans, one of these wells in terms of your future plans geographically?

Keith Hutton

Haynesville well is probably $300 million well, so not real expensive for $10 million a day well, very good economics. The question will be in that particular play, it is a conventional play that is horst and graven (ph) area. So you get to drill some more delineation wells which we're about doing right now see how big play it really is. We'll talk about a little in the conference.

For the Haynesville, that well cost us over 10 million, closer to 11 to be honest with you. But its pilot hole is probably million or 1.5 million of that. First well at about bucks, I am sure we can get more efficient. I think we tell you we think we can drive those cost down to 8 million. And maybe a little lower but that's as far as we'd say it's about, take your pilot hole out this by 9.5.

Brian Singer - Goldman Sachs

Okay. And what do you think this would, I mean it's too early, what you think this rate would suggest from your perspective?

Keith Hutton

7, about what we think.

Brian Singer - Goldman Sachs

Okay.

Keith Hutton

And again it's an interesting discussion on yards for Haynesville guys because there are no too many wells that have gone on for very long so, we'll talk a little bit about that at the conference as well. But I try to bring that up, there is a lot of wells that came in at 5 million a day that you've got a quite bit history on, you would say are 5 Bcf well. This was going to make 8 million in first month. You can do the math on that. It could be 7 could be 8, but again it's awful early, it's one month.

Brian Singer - Goldman Sachs

And what's the next step from a drilling perspective?

Keith Hutton

We currently have two rigs running. We are drilling a couple of wells that are right on Louisiana border as we speak. And then we have drilled four verticals that are kind of spread out across our acreage and core and so forth that we'll talk about that a little bit at the conference day.

Brian Singer - Goldman Sachs

Thanks. And lastly in the Marcellus, can you talk about timing and location of a horizontal activity or are you staying more focused on the verticals out there? It seemed like there were... there are some good rates using the reference on your earlier comments?

Keith Hutton

Yeah, I'll tell on that one Brian. Wait to the conference, we'll lay it all out for everybody if you don't mind.

Brian Singer - Goldman Sachs

Great thanks.

Keith Hutton

You got it.

Operator

Your next question comes from the line of Scott Hanold with RBC Capital. Please proceed.

Scott Hanold - RBC Capital Markets

Good morning.

Keith Hutton

Yes, good morning.

Louis Baldwin

Good morning.

Scott Hanold - RBC Capital Markets

You had made a comment regarding oil and your activity in Bakken to kind of keep it within your hedge position when you step back and look, is there a point in time which you may do that for your entire portfolio when you kind bring it in to 100% hedge position in 2009?

Louis Baldwin

Scott, that's actually what we are doing if you look our guidance is 63,000, our hedge is 62.5 for the year on oil. So it's about as tight is we can tighten it up.

Scott Hanold - RBC Capital Markets

How about on gas and then can you talk little bit about NGLs and relative to whether or not you can protect some of that economics?

Louis Baldwin

NGLs were not hedged, so that's an issue. Gas we are hedged at about 80% of our volume I believe.

Scott Hanold - RBC Capital Markets

Yes.

Louis Baldwin

And again we're not trying, what we're really doing is focus on rate of return, guys. So we are pushing for the areas we believe at five dollars gas are still economic. So that anything we're drilling outside of our hedge volume is still got a 25% rate of return. Obviously there are some areas where you need to go do some delineation drilling that may not fit, there is not much of your budget I tell you that.

Vaughn Vennerberg, II

Natural gas makes up about 4% of our Mcfe and there is not in NGL, excuse me natural gas liquids, 4% equivalent well production, there's never been a real efficient market for hedging that. I've looked into it some, it just really has some flare up, this really hasn't developed at where you feel comfortable.

Scott Hanold - RBC Capital Markets

Okay.

Vaughn Vennerberg, II

Gas and oil.

Scott Hanold - RBC Capital Markets

Okay and then can you talk a little bit of basis for a little bit, how have you protected yourself on bases through '09 and into 0'10?

Vaughn Vennerberg, II

Well, this is Vaughn on '09 we've locked in our basis very shortly after we put our hedges in place and so for the first 10, 11 months this year we have probably 98% of the bases locked in with our hedges at around minus 30, $0.31 and then as the year proceed in 2010, we are working that as an ongoing basis, it trades where its been right now the 7.75 our EPS.

Scott Hanold - RBC Capital Markets

Okay, but it is more for the year for '09 at this point, alright, and one last question on the Haynesville I know you talked a little bit about that already but what do you all see, is this something that you will need seismic to delineate is that sort of a structure type of play down there?

Keith Hutton

It is and your seismic will give you structure, it won't give you reservoir character, so it's you'll there are wells that are producing in the lows and on the highs. So it's just a question of you know, that's actually take the drill that figured out to be honest with you. Seismic gives you some variable rates (ph).

Scott Hanold - RBC Capital Markets

And then I think in an earlier call, I remember it was the third quarter or the one before that. But you had indicated that in east Texas you all had a different concept and that you give to relative to Haynesville shale activity is that Haynesville Lime or you are still working on something out there?

Keith Hutton

Concept wise I am not sure what you are referring to Scott I know in the free stone trend you know, we shoot a bunch of intervals that is different than lot of our competitors. Haynesville Shale I think the difference may have been, there was lot of chatter that anything in Texas is Bossier shale and not Haynesville shale. And I will tell you we never believe that, yes there is Bossier shale there is Berger shale in Louisiana and Texas nothing changes when you cross the border. As far as where it is on the logs which you would call those particular shale's.

Bob Simpson

Obviously if you west the Haynesville shale actually disappears and Bossier shale is the only shell left, so you dig in and vanish.

Scott Hanold - RBC Capital Markets

Okay, all right appreciate, thank guys.

Bob Simpson

You bet.

Operator

Your next question comes from the line of Michael Hall with Stifel Nicolaus. Please proceed.

Michael Hall - Stifel Nicolaus

Thank you, good morning.

Keith Hutton

Good morning Michael.

Bob Simpson

Good morning Michael.

Michael Hall - Stifel Nicolaus

Just wondering if you could kind of continue the commentary about the Barnett peak and maybe take that analogy to U.S. as a whole the idea that as we drop rigs call 50% from the peak that how harsh of a snapback in rig count do we think we need to see to start growing U.S. production again?

Louis Baldwin

I think you've got to back up 30% really fast to be honest with you. But, it may be more than that. Because, I mean again, go back to '01, rig count was 1,100, when gas was $10 I think.

And it dropped back to 650 or so, 600. And then it grew back to 1,100 again, the middle out of '02 to '05. And during that time period U.S. production continued to decline. Because, if you go run a model and then what you guys can do, if you're underlying decline is 30%. And you drop your rig count in half, it is hard as hell to catch back up. And so, you've got to turn those rigs right back on. I mean, I think the real answer is it's hard for people to get their hands around it, but didn't go model it in.

If you start picking rig count up 10 or 15% a year, and it takes you three or four years to get back to the old rig count, you're going to decline almost the entire company. You cannot catch up. And I think that's an issue that's hard for people to get your hands around. But that's why we think you're going to see a '010 actually keep declining as well. And maybe even '011, it must be really jump on it.

So, we are setup for one of those following gas productions for quite a while, even with the shale plays coming in.

Michael Hall - Stifel Nicolaus

Okay. And you don't think that the kind of shift out of the Gulf of Mexico of U.S. gas production profile in this time period versus 2001 type time period, I don't think that will make a meaningful impact?

Keith Hutton

U.S. -- the Gulf of Mexico has a 30% decline rate. So, as the base you ask really.

Michael Hall - Stifel Nicolaus

Okay.

Keith Hutton

And that's what's happened is all these plays we're in, yeah, first your decline rate is 70% of these wells. And so we've accelerated the onshore decline rates, with almost matches up the Gulf of Mexico.

Michael Hall - Stifel Nicolaus

Okay. That's helpful. Thank you for the color. And then, think about your own decline curve all the acquisitions in 2008, has there been any issue with integrating of your decline curve, and what type of work if any you had to do to kind of bring that back up to prior levels.

Keith Hutton

Really, the any acceleration of our decline rate is based on the amount of wells we're drilling at any moment in time. The acquisitions we did are about the base decline rates coming or that in (ph) hand.

Yes, we are at the point or so over last year I think of decline rate. But like Bob said, one of the nice things about this year in particular is by slowing down the drilling rigs we're not drilling as many new wells and turning to the thing that we do best, which is efficiency on old wells that have not been looked at for a while. These acquisitions I think will shore up our decline rates, we may even gain two percentage points over the next year and build back to 15%, initial first year decline which will put us at half industry standard for sure. And that's actually I'm kind of excited about that nothing kind of schedule, we need to got back to basic fixed stuff. And you make a lot more money doing that than you do to your own well, actually.

Michael Hall - Stifel Nicolaus

Got you. And then, one more on the acquisitions. Is there any need for additional headcount, and you've seen some layoffs around the industry, you're going to use any opportunity to pick up some talent here this year or...

Keith Hutton

We probably will. But, I'll tell you this, we're... because we grew so fast, we didn't hire like a lot of the people. So we are probably behind the curve, and having a dropped our rig count, we're probably right on it.

Michael Hall - Stifel Nicolaus

Okay.

Keith Hutton

And so, what's really happened is we kept ourselves we will get newer staff, not by the time, by the way but just by the fact that we bought so many things so fast we couldn't hire people fast enough. And so, I think what happens now is we'll pick some selected people that are very good that may want to leave the company they're with. You bet. We always do that. So, somewhere along if we see that opportunities we'll do that. But, it won't be a big large course to do.

Michael Hall - Stifel Nicolaus

Okay. And then, sorry if you already said it, but on the Panola County and the Haynesville Shale well, did you talk about the completion design there?

Keith Hutton

No. And I think we'll get into that the conference, if you don't mind.

Michael Hall - Stifel Nicolaus

Okay.

Keith Hutton

Talk a little bit about that, there.

Michael Hall - Stifel Nicolaus

All right. And then finally, future development costs and your thoughts on 2008. Do you have that number by chance?

Louis Baldwin

I don't have it right of the top of the head.

Michael Hall - Stifel Nicolaus

Okay. All right. Thank you.

Keith Hutton

Okay. You bet.

Operator

Your next question comes from the line of Shannon Nome with Deutsche Bank. Please proceed.

Shannon Nome - Deutsche Bank

Thanks. Good morning.

Keith Hutton

Hi, Shannon.

Bob Simpson

Good morning, Shannon.

Shannon Nome - Deutsche Bank

Keith, you said earlier I think you threw out a range of $1.50 to $1.70 per Mcfe and I missed what that was, was that refining cost expectation for '09?

Keith Hutton

Yeah.

Shannon Nome - Deutsche Bank

Okay.

Keith Hutton

Yeah. And really what we're saying is look, we think service costs are going to go down. Do you think you had to tackle the same, if not better portfolio, so your F&D costs should drop.

Shannon Nome - Deutsche Bank

Yes. And then can you tell us or maybe this is something you'll get into next week, how much of your Haynesville acreage is Louisiana versus East Texas?

Keith Hutton

We'll talk about that next week if you don't mind.

Shannon Nome - Deutsche Bank

Okay. Louis, do you have handy what the bank debt tally was at the year end and where it is now?

Louis Baldwin

Well, we have... most of the amounts over 9.6 is bank debt. And if you look now when we come out certainly at quarter eight (ph) and you'll be 100 million, maybe 200 million in commercial paper bank debt. So with the monetization of the hedges, will have come very close to bank of all of your easily prepayable and redrawable bank debt.

Shannon Nome - Deutsche Bank

Helpful, thank you. And then lastly this is, I don't know if it's a statement or rhetorical question or what. But back to the question about, Keith you were discussing the trend of declining production 2002 to '05 which we also note with interest in. It seems clear the Gulf of Mexico is sort of in the process of playing out. Yet we are having to relay on the Gulf for disproportionate amount of help in the absence of new resource plays which really didn't hit the scene in my view till really after that '06 when production finally started growing. I guess while I paid to figure out, is it different this time? And I guess the math, maybe I am oversimplifying but if you have a Barnett shale well that came on a year ago, let's say, 3 million a day. A year later, now it's doing 1 million a day.

So while that initial decline is weakened and we should have really tough drop facing us at some point in the future, let's assume (ph) that one new well is going to produce 3x what that one year old well is going to produce, right? So how do we reconcile the ease with which the industry can ramp back up given the new edge of resource plays?

Keith Hutton

I think you have to think about it is, it will be a million a day but things are 25% decline right for the next two years after that -- or three years. I think even those wells that are falling are still the first year 70, the next year two or three years of 25, 30.

Shannon Nome - Deutsche Bank

Sure, well then that well goes from 1 to 0.75, that's still one well, one new well replaces three old ones, right?

Keith Hutton

Yeah but that's kind of been going on for ever. I mean -- yeah the Gulf wells didn't decline at all, they hold flat for a while and disappear. Some of them went on 30% normal declines. Some of them actually flatten out like onshore if you are in the big fields. So a large portion of your Gulf production actually doesn't have a 30% decline rate now, and that's the same thing you are talking about.

I think the other thing you have to think about is you are currently in a capital starved environment for infrastructure. Okay, so what are you going to do for all these great plays if you can't get top-line interval.

Shannon Nome - Deutsche Bank

Yeah.

Keith Hutton

So now our wells are good, you can't get to take away. And I think you have seen that issue in Hayneville. You're going to see at Marcellus. I think that's going to cause more issues for us to go fast enough for the whole industry than what anybody can ride the end, because we stalled the pipelines for a year, which I know we're already doing, takes two years to get on build or 2.5 so if you stall them for '09 to '10 you don't get pop the next 2010 to 2012 or 2013. It's going to limit your ability to turn the current.

Shannon Nome - Deutsche Bank

Yeah, that's a fair point.

Bob Simpson

I think one other thing Shannon, I would bring out is if you look at it as an industry and as a decline for an industry and the replacement of production, I don't' believe there is enough free cash flow in this industry to replace production. And that would be at virtually any price within cash flow. Certainly $8 or less there is not. Without outside capital which is a constraint that, the industry goes beyond... has gone beyond routinely in the last decade and it finally resulted in a one-year growth or something. But in this capital constrained days there is no way there is enough capital available to raise -- I mean to increase production. And certainly lower gas prices will not attract outside capital for investment.

And so I think one of the governors that's on this industry hard in terms of trying to grow production is capital constraints and it's renewed and larger than any time in my career. And it will last to a degree for a good while I believe. And so, the shale plays didn't fix that. And we have a... we can have abundant gas for a set of price and it's going... and it isn't cheap, let's say eight bucks, maybe 10, to grow it. And so I think that's one thing to step back and look at. In addition to looking at well performance is to look at the capital needs, to replace production just to keep it flat.

Shannon Nome - Deutsche Bank

Yeah, that's good points, much appreciated. As I sign off, any... last question, any thoughts on LNG increases and LNG imports kind of offsetting those declines?

Bob Simpson

I first look at that as, certainly rest of the world at the moment probably we saw most of it. Again the low gas price doesn't attract LNG at this stage. I think the LNG will probably tend to run lower than we worried about, particularly two or three years ago.

Shannon Nome - Deutsche Bank

Thank you.

Louis Baldwin

Shannon, this is Louis, let me go back to your bank question. I'll give you a more specific answer. If we look at year-end debt, we'll have about 1.9 billion of commercial paper bank debt outstanding that number should go to just one 1 to 200 million at quarter end. If we look at term notes to banks at 600 million, that won't change. Our public notes are about 9.5 billion, that won't change either. So, on the commercial paper of revolving credit facility, that 1.9 will go down to 100 or 200 million.

Shannon Nome - Deutsche Bank

Perfect. Thank you.

Bob Simpson

Okay. One thing I'll mention as a spot add for, we keep talking about next week. We're having our analyst conference in New York next week, starts at 8.45. It's at the Mandarin. Or Mandarin, if I knew how to say it correctly.

Unidentified Analyst

It's perfect Chinese.

Bob Simpson

And there in New York. We'll start having our analyst conference there for the convenience of analysts, investors. So it's been well attended. We invite everyone to come if you can and see more color on all of this. But I just interrupt that and stick that in because some of you will be dropping off. Some more questions.

Operator

All right. Your next question comes from the line of David Tameron with Wachovia. Please proceed.

David Tameron - Wachovia

Thanks. Good morning.

Bob Simpson

Good morning.

David Tameron - Wachovia

Couple of questions. PV-10 calculation, the 23.5 billion that's in the press release what price was that based on? I guess 43.5 billion after¬-tax.

Louis Baldwin

Okay. I am sorry to say 30 to 34.5

Unidentified Analyst

34, which one you're talking about?

David Tameron - Wachovia

I guess you put a footnote table 23.5 after-tax?

Louis Baldwin

Yeah, that's 75, 7.50 case that corresponds to the 30.5, 34.5 pre-tax.

David Tameron - Wachovia

And when we look at the K gets filed (ph) what number will be showing and what price, you're using in your pricing?

Louis Baldwin

We're opening the K right now.

David Tameron - Wachovia

While you're digging in that, let me throw another question. I guess it's for Keith but if I look through the half report of the rig count, it looks like you had no simple decline in most areas except the Haynesville and Woodford. Is that due to... does that say about the economics of those or is that due more to more holding leases, or can you talk a little bit about that?

Keith Hutton

It's a little bit about... I mean given that we have for San Juan and Permian, San Juan currently... your basis differential for Rockies is pretty unclear. There is no reason to really keep your rigs there. Permian is always busy, so we can... again why would you drill anything over your current hedged volume with oil hedges? So those are really... doesn't really say anything about the economics at a normal price either one of those areas. Why do we hold Woodford and Fayetteville? Yeah some of is leasing. Some of it is that those wells are economic at $6 gas or some pretty easily. So that's kind of the way we look at it.

David Tameron - Wachovia

All right.

Louis Baldwin

Okay, Dave back to your question if we look at a PV-10 test we've got... we'll have it presented a couple of ways in the K, including before and after hedging. But if we look at the pre-tax number PV-10 SEC case about 17.2 billion, if we include the value of our hedges PV-10 SEC case with hedge values which is allowed under the cash flow hedging method that we use, 21.8 billion will be...

David Tameron - Wachovia

Okay. That's a pre-tax.

Louis Baldwin

Yes pre-tax.

David Tameron - Wachovia

Okay. All right, you have the pie component of that, while I got you?

Louis Baldwin

The... well again 64% is what we dealing on the SEC.

David Tameron - Wachovia

Okay.

Keith Hutton

36% prime.

David Tameron - Wachovia

Yeah, all right. And one more question I'm not trying to be flippant here but if I look at 2009 production growth at 14% I think you said 3% organic, as I think about the other large Cap names, the one thing that's always had to distinguished XTO is that organic growth profile. But if I look at it 3% organic growth versus the other large Cap peers you are kind of inline, how would you respond to that?

Keith Hutton

I'd say we got to step on the accelerator.

Bob Simpson

I would say we paid down, we've got almost 10% NAV in place through debt reduction coupled with that.

Louis Baldwin

So I'd add the two together per share.

David Tameron - Wachovia

Okay so, okay.

Keith Hutton

There is really no reason to grow 10% organic into anything that's above your current hedge prices because you are in the trap of service costs having come down all the way and your venture commodity price has. Okay, so you should you can drill there six or eight months and we will be drilling a lot more economic wells, because your costs will be down 25% so.

David Tameron - Wachovia

Okay, so I will try to tell you down I think you said, if you look at 2010, let's say we get back to a seven dollar price environment.

Keith Hutton

Fine.

David Tameron - Wachovia

Would you expect 10% organic growth for 2010 and beyond?

Keith Hutton

I think you could if you want to we will see what happens when we get there.

Bob Simpson

In terms of our other choices, we've run it from a financial return NAV model. If we were to start to buying stock, I would think that for example. So this year we've got our double digit value creation in hand, go through the debt repayment and the organic growth and still we were very quantifiable so, again there is not the magic organic growth, the value growth per share is what the magic is?

Louis Baldwin

David, it's Louis, I'd also say that if you look at the efficiency of that, we will be doing that 3% organic growth with a little less than half of cash flow or $2.75 billion development budget. Most for the other guys were spending all of there cash flow to get that kind of growth. So that's the efficiency as Bob said, you add the value and you can still pay down a lot of debt within that context.

David Tameron - Wachovia

All right. That's a good answer, just want to see what your response was, thank you.

Keith Hutton

Yeah.

Operator

Your next question comes from the line of Tom Gardner with Simmons and Company. Please proceed.

Keith Hutton

Hey Tom.

Thomas Gardner - Simmons & Company International

Hey, guys, hey quick question regarding your 10 to 20% cost deflation estimate, how much of that is currently factored into your cost guidance?

Louis Baldwin

10%

Thomas Gardner - Simmons & Company International

10%. And question on reserves, given the SEC changes to reporting that now give you the option of reporting probable and possible reserves. Do you plan on disclosing those at the end of the year and so what would that be as a factor of proved?

Keith Hutton

We don't know yet, we're going to kind of wait to talk about how the plays out, I think some of those SEC rules are going to... can cause headache for investors as to how you guys look at it. I am sure we will do something on those lines, I mean '010.

Thomas Gardner - Simmons & Company International

Thanks guys.

Keith Hutton

Okay.

Operator

And your next question comes from the line of Marshall Carver with Capital One. Please proceed.

Marshall Carver - Capital One Southcoast, Inc.

Yes, just a quick question, do you have anything at all earmarked in the $3.2 billion budget for smaller bolt-on acquisitions and if not how much would you anticipate making this here?

Louis Baldwin

We don't have any in that number directly, there might be a low end in their service cost or less than projected. Maybe it will strike in that. But we will do some and again we'll do those as they come along. And our 10 to 10.5 billion exit ray of that gives us the $0.5 billion of slack for that kind of activity or additional or exceptional leasing opportunities or accommodation. So, that's why you see the range on that.

Marshall Carver - Capital One Southcoast, Inc.

Okay. That's helpful. Thank you. Any particular areas that you're looking?

Louis Baldwin

No, we'll do some unsolicited and one of the things we will be done is placing out specifically where you're drilling down the leasing area. And that had a... pennies on the dollar relative to the collapse in leasing dollars per acres. So that, that's an advantage that you will enjoy on the cost side. The bolt-ons are combination of we will do some solicited and that will happen anywhere, we think we got acknowledged advantage, specifically within the area which, so we wouldn't disclose where would be, but and then there will be just well counts it will always have because of the large franchise.

Marshall Carver - Capital One Southcoast, Inc.

Okay. Thank you.

Louis Baldwin

You bet.

Operator

Since there are no further questions at this time; I'd now like to turn the call over to Louis Baldwin for closing remarks. Please proceed.

Louis Baldwin

Thank you. We had some good questions today, for listening again highlighting the efficiency of 2009, the ability to reduce debt significantly, preserve the optionality to grow in 2010 at 10% should that be the smart thing to do and as Bob said continue to focus on value creation for shareholders. With that we'll say good bye. Thank you very much.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day.

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Source: XTO Energy Q4 2008 Earnings Call Transcript
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