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Executives

Louis Baldwin - Executive Vice President & Chief Financial Officer

Bob Simpson - Chairman & Founder

Keith Hutton - Chief Executive Officer

Vaughn Vennerberg - President

Tim Petrus - Executive Vice President of Acquisitions

Analysts

David Chrysler - Simmons & Co.

Brian Singer - Goldman Sachs

Subash Chandra - Jefferies

Scott Hanold - RBC Capital Markets

David Tameron - Wells Fargo

Joe Hellmann - JP Morgan

David Heikkinen - Tudor Pickering Holt

Phil Dodge - Tuohy Brothers

Nicholas Pope - Dahlman Rose & Co.

Eric Genova - Morganstar

XTO Energy Inc. (XTO) Q3 2009 Earnings Call November 4, 2009 12:00 PM ET

Operator

Good day, ladies and gentlemen and welcome to the third quarter 2009 XTO Energy Inc. earnings conference call. My name is ma Malalia and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions)

XTO management will be making forward-looking statements during this call. Risks associated with such forward-looking statements 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 statements.

I will now like to turn the presentation over to the host of today’s call Mr. Louis Baldwin, Chief Financial Officer and Executive Vice President; please proceed.

Louis Baldwin

Thank you for joining us this morning. Participating on the call are Bob Simpson, Chairman and Founder, Keith Hutton, CEO, and Vaughn Vennerberg, President. I’ll start with a brief review of the financial results. Keith will then updating you on operations. He will turn it over to Vaughn to give you a hedging update and then Bob will wrap up and we’ll open it for questions. We had a great quarter, compared to the third quarter of 2008 was up 23% total revenue is up 8%, earnings down 4% and operating cash flow was up 3%.

A record for operating cash flow, these are outstanding results given the natural gas and oil prices between the two periods. Interestingly while production was up 23%, total production expenses dropped by $14 million or 5%. So excellent results even cost control there, also increased our production guidance for the fourth quarter by about $100 million per day and guidance for 2009 is up 23% growth compared to 2008, up from 20%.

What you’re seeing is the advantages of electro rigs and natural gas producer that is enjoying substantially improved margins, because of hedging operations and our focus on liquids. We’re on track to generate $6 billion in cash flow for the year and if you look at our results for 2009, our expectations for next year and beyond we believe that demonstrate our ability to grow efficiently through disciples.

Among our peers, we have unique ability to grow in double digits while generated substantial free cash flow. For the quarter, if you look at the results, adjusted earnings per share, on a diluted basis of $0.87, beat first call expectations of $0.84 so an excellent quarter in that result. Net income on a GAAP basis was $500 million for the quarter.

Looking at operating cash flow, 1.562 billion that’s up 3%, again, puts us on track to do about $6 billion in cash flow portion of the year. Our cash flow margin assumption that we focus on 68% cash flow, as a portion of revenue and you can see that we’re continuing to protect the margins in spite of weak commodity prices. If you look at production expenses are said it was down from the same quarter of 2008, on a per Mcfe basis and was $0.92, below guidance and we’ve actually lowered our guidance for production expense in the fourth quarter to $0.94 to $0.98.

I typically provide you a breakout of production expense from the quarter, if we look at the $0.92, it was made up of labor and overhead $0.24 per Mcfe, maintenance and work loaded cost $0.56 for Mcfe and CO2 of decline significantly to $0.08 per Mcfe, and compression charges other $0.04 or less the breakout for the $0.92 this represents the fourth sequential decline in our quarterly production costs per Mcfe.

G&A also came in lower than guidance were $0.19 per Mcfe compared to $0.25 to $0.30 guidance and we reduced our guidance to $0.23 to $0.27. Interest expense was below the low end of guidance and we lowered our guidance for the fourth quarter also, this results from our increased volumes, as well as lower interest rates on our commercial paper borrowings.

If we look at our investment activities for the year, the development costs, capitalized exploration costs, dry hole cost $661 million, property acquisitions are primarily undeveloped property for $50 billion, natural gas $6 million of operations were $90 million in expenditures and other property and assets its $22 million, so our total investment activities for the quarter $823 million, turning to the balance sheet, a good result there.

With debt remaining substantially on track to hit our targets of 10 to 10.5 billion in debt at year end. Debt to total cap remained very solid into the 37% area and so another good performance with the balance sheet.

With that great review, I will turn it over to Keith Hutton to update you on operations.

Keith Hutton

Thanks, Louis. Great quarter for us from a production standpoint, from the fact that we were running 100 rigs last year, down to 47 rigs in this quarter. So, less than half the rigs we started this year with about a 14% growth target 4% organic. We’re going to end the year with a 23% growth target and 13% organic for the drill bit. That just really points to the wells and property that we bought over the last couple of years and how good they really are.

They be beating our estimates in every one of the basins. We have had increasing the efficiencies both from lower operating costs and capital costs and with that, I thought I’d step back for a minute and just kinds of reintroduce you to XTO and what we set up over the last couple of years and let’s look at the Shale in particular. We have run 47 rigs total today, 27 of those rigs are drilling in the Shale basins.

If we look at Barnett, we were running 19 rigs last year; we’re currently running 8 rigs and even with that drop in rig count, our production has actually been maintained and we still have a pretty good backlog of wells to complete in the Barnett. If you look at Fayetteville, we have run 6 rigs constantly and I think it has been lost on the street a little bit, is we own in about 600 wells that have been drilled by other operators in the basin, around at 12% average working interest and we own in over a 1,000 sections that both Chesapeake, Southwestern and Petrohawk are all drilling on.

So I think people often think we have a lesser position in the Fayetteville from a quality standpoint not true and we will go through that in a little more detail, but obviously we’re in everybody else as wells so we can see what’s happening in every part of the basin. If you flip from that then to Woodford, we’re running about 3 rigs. That’s about what we need to hold our acreage position. We have been able to increase our production all year with just 3 rigs.

From that to Haynesville, where I think there was some talk maybe that we didn’t have as high quality acres position at some point, we currently have five rigs running. We’re making about 45 million a day and we’ll exit at 60 to 70 million a day on an operated gross standpoint. We will have six rigs running here in the next month and by the start of the first quarter, we’ll have at least double digit rigs in the Haynesville going forward for our 2010 budget.

We have about 100,000 net acres in the Haynesville, and about half of it is in the Shelby, Nacogdoches, and San Augustine area where you’ve been hearing about a lot of really big wells and I will go through in that in detail. Going forward Marcellus we have currently 6 wells drills and we’re completing those as we speak we have two rigs running and next year we will push that up to at least 4 rigs.

Now quick discussion on oil, in the Bakken, we have three rigs running in the Bakken, and we’re going to push that to six. We will probably have four or five by the end of the year and may run more than that as we get into 2010. We’re still working on our budget we currently have two rigs in the Permian, and we will push that up to five by the end of the year, so that we’re actually launching into oil production growth at a pretty good pace for next year.

If we look a little bit now at kind of the individual areas for a moment, free stone in particular was up 15% year-over-year and a couple percent quarter-to-quarter, that’s with our rig countdown from 27 last year to 16 at the moment, if you look at why that’s happening we’ve been drilling better wells on free stone over the last six to eight months than we have in long time.

Most of that driven by horizontal Cotton Valley Lime wells and our Southern Bald Prairie extension, where we’ve had some wells coming at 6 million or 7 million a day and we’ve had a recent deed on horizontal well that came in at 7 million a day as well.

Going forward, we’ll be pushing more rigs toward drilling horizontals both in the Bossier and Cotton Valley Lime and in the Petite Intervals throughout the Freestone Trend. If we flip from that to Haynesville then, let’s get a little color on Haynesville. We have four wells that we completed during this quarter.

We are using 30 day production rates on these wells of Texas. We’ve averaged for almost 8 million a day to 9 million a day, first month average on 30 days; we have our first well on at 14.5 million a day, in Louisiana, that’s a two week average.

So we’re not popping out big IPSL, we’re trying to tell you what the actual well rates are here, and if we spend a little bit of time now going down to Shelby and Nacogdoches and St. Augustine, where a lot the chapter has been about recent wells. We have two wells down, we’re completing right now.

Again half of our acreage is in that general vicinity. People have Bossier shale and Haynesville shale loaded up. We’ve been quiet about that as we haven’t really wanted to talk about that while we picked up more acreage in the interim, but now that the cat is out of the bag, we’ll talk a little bit about it.

Our first well that we’ll be completing right now is a 2,400 foot short lateral. The second one is a 6,400 foot lateral that we will start here in the next couple of weeks. So we’ll have some good data going forward. Obviously, with Devon’s announcement of their well just to the south of our acreage, that’s lit up the area for the moment. We have done a vertical Bossier shale test in one of our wells that actually tested around 800 Mcf a day, the vertical well, which means the Bossier shale in this area will be bit as well.

If we flip from that end to the Marcellus, if you guys have our operations report to look at, I’ll give you a little color in the Marcellus spread out. We have the six wells that we drilled horizontally. It’s actually spread all the way from Northern West Virginia, one of our larger acreage basis through the middle of Southwestern Pennsylvania acreage position, where we have three wells down and we’re currently testing and we’ve drilled our first well up in Lycoming, pretty close to where the really hot air is in the northern grouping of wells and our rigs are currently in the Lycoming and the Southwestern Pennsylvania area.

We’ve got a couple of wells on I’m not going to talk about the rates. They’re fine, but they’re choked back real hard because we’ve some pipeline constraints. So we’ll give some more color on those here in the next couple of months, but we are excited about it. We are going to at least four rigs next year, so we can start expanding our position in the Marcellus. If we go to Fayetteville, our productions gone up to 130 million a day net from 40 million a day at the start of last year, basically, it’s about half operated on net basis, and half not operated.

To give you an idea, we haven’t really flush that out until now as our operator is really start taken off over 100 million a year and expect to exit at 120 million a day and here we’ll run at least eight to nine rigs next year as we continue to increase our position, and our production and delineate our acreage position. Average wells are running anywhere from 2 million to 4 million a day.

We put some on the operations support that range in the 2.5 million to 3 million a day, which are very close to what other people are drilling and we’ve got an area that’s very hot that we have a grouping of wells, over 4 million a day, we currently have a rig in there drilling, and should see a large production increase in that particular area by the end of the year.

Woodford, we drilled three wells that in this quarter, averaging from 3 million to 5 million a day. Bakken, we’ve now drilled 10 Three Forks well that have averaged over 1,000 barrels a day IP. Obviously the Jorgensen that we announced with our hedging released a couple of weeks ago came in at over 2,800 barrels a day. We’ve had some other wells better in the 1,500 barrel a day average, and what that’s really known as delineate our acreage position over a large area that we believe has both Three Forks and Bakken’s potential and we’re very excited about what that means for us going forward.

We had talked about it before, but we really think we can probably triple the production from what we had at the time of the acquisition, on a production basis, and on a reserve basis. We’ve already up 38% in production since we took over operations of heading with the acquisition.

With that, let me turn it over to Vaughn Vennerberg to talk about our hedging position. Vaughn.

Vaughn Vennerberg

Thank you, Keith. As released today the company has approximately 55% on 2010, anticipated production hedged at $9.62. We will see that for 2010, we have begun to selectively lock in pricing that will continue to propel the company in value and reserve, both as well as record shareholder returns.

As noted, in our release, regarding trending and performance guidance, we have secured 13,000 Mcf per day for the calendar year 2011, an average price of 702. We felt this was an opportune moment with us to track the price and begin locking in a portion of our anticipated production for that year.

As you have seen, in the past with XTO, we like to look forward 12 to 18 months at the futures market and capture that advantage for the company. As we move into 2010, with more than half of our production hedged at these strong prices. Our financial basis and also physical contracts has been secured as well. For 2010, our gas prices potential averages around minus $0.23 for hedge volumes, for 2011 we are at about minus $0.16 for those volumes released today.

If we go onto what’s happening in Washington, a quick update for you there. As you probably know, there’s a bipartisan desire in Washington to deal with concerns about manipulation and the like of accountability in the over the counter derivatives markets. The bill is working more into U.S. house.

We are encouraged that the House Financial Services Committee and the Agricultural Committee have attempted to add exceptions for the quote, unquote pure hedger and we continue to assess the possible consequences of this legislative effort. I have been in the offices of various members of Congress explaining how XTO uses the derivatives markets, as a price risk management tool. There’s been no action in the Senate, so far beyond in formal discussions.

On climate change, we’ve reported what’s going on with that. We continue to be part of that discussion as well. The Senate Environment and Public Works Committee have a three day hearing on a draft bill last week and as we all know, the house previously passed a bill in June of this year.

We expect additional Senate Committees to hold hearings on the Senate draft. Here at XTO, we have a tough team regularly to coordinate on the Broad issue of climate change. We do not believe the full Senate will vote on this issue before the end of the year, but it’s imperative that we remain engaged.

Natural gas should play a big role in this debate and we’re working with many of our peer companies to ensure our seat at the table. On the issue of regulating hydraulic fracturing, at the federal level, Congress approved on October 29, language in the interior environment and in the appropriations bill directing the EPA to conduct a study.

In the message, the EPA, Congress directed the agency to conduct a study on the relationship between hydraulic fracturing and drinking water, using a credible approach that relies on the best available signs. XTO welcomes this study, because we hope it with the State regulations are more than adequate to protect ground water from oil gas activity. We believe the study with input from State regulatory agencies will provide the information needed to improve of its best.

Finally, we continue to talk to members of Congress about the significance of industry tax treatments targeted toward elimination or structuring by the current administration. We are very encouraged, when Congress rejected that recommendation in its current fiscal year 2010 budget and we are asking them to do the same when they develop the fiscal year 2011 budget.

With many of the current tax cuts expiring in 2010, the tax bill is likely, and we can reasonably expect other White House recommendation to limit or remove our ability to expense item C costs, geological and geophysical costs and decline the manufacturer’s production. These tax treatments play an important role and when we intend to continue to delay the work oppose a recommendation to eliminate. So we are very engaged, very involved on a daily basis and we continue to monitor how the winds are changing in Washington.

With that, I’ll pass it over to our Chairman, Bob Simpson.

Bob Simpson

Thanks, Vaughn and good morning, everyone. Again, in tune with what Keith was saying, let’s reintroduce the world to XTO. I’m going to flesh that out a little bit more as well because I think it’s an appropriate time. It’s an inflection moment, given the world’s perception of also what’s going on with natural gas.

The company did another record cash flow quarter and record production, given what happened to commodities this last year that is rare statement in this industry and I’m proud of it. With that comes the worry that or the belief that perhaps that is illusory and was propped up by artificial hedging and it is a one time thing.

So our job is to share with you the future, which is always the relevant moment for an investment and disclose that the cash flow continues to be robust, going forward as we transcend to a lower price commodity environment from last year. Given next years hedges the 55% of production that’s hedged at an equivalent of about 962 in Mcf. Cash flow next year I was looking at some projections today is probably within 5% of this year’s.

So if you down tick 5% off of records that were out of last year commodity price, that’s a nice transition. Going a step further you look at 2011 cash flow and given some current projections, I was looking at, it is roughly the same as this year and that’s, with just nominal amount of hedging the 250 a day at $7 that Vaughn mentioned and so basically transcending from a world of hedging to sort of a look at XTO un-hedged, you still see right at these record cash flows maintained.

I don’t believe that is reflected in the equity price and that’s the thesis I would submit for to you consider. If you look at what is the assumption about volumes within the numbers I just mentioned, that is a 10% compounded growth for next year and 10% for the year after and one of the things that I’ve noticed in the last quarter that was sort of floating out there, fairly heavy, sponsored by a couple of fairly prominent analysts was the fact that we’re losing our advantage in terms of the cash flow machine and I’m going to address that during this discussion.

If you look at the XTO model, we’re built on two advantages, one is maintenance capital to preserve production and reserves, is roughly a third of cash flow. Now that’s been going on since 1986 and the good news is coming on our next year and the year after as well and so that advantage is not lost. The other ones we have about half the decline rate underlined, the industry does and that advantage is preserved.

Today it is around 17% and I think the industry is in the 30s. So those two advantages prevail. Our model blends in growth with low decline and a program that results in ultimate low decline and the Shale also take that model eventually. The one thing that we’ve done in the last three years as every business reinvents itself as it goes along, the reinvention for our industry is Shale.

We are I think, the leading Shale player, given the breadth of our exposure, and the number of Shale we’re in and the positions that we have that will be developed, I think, in aggregate, we are the leading Shale guy and I think we have the leading staff to go with that. So that’s been a reinvention and also about a third of the value of this company is now liquids and that’s been done in the last three or four years as well.

Now, that was coincident no one here is going to take a claim to exceptional brilliance in that moves, although in hand sight, it qualifies, but that was some opportunities came along, and we did perceive that the oil markets were going to improved. We got the trend directly and our job I think is to identify trends and I think we’ve done a good job of XTO and they lead where they lead.

So liquids rich is good, probably a third of our cash flow now is from liquids and so between being a leading Shale player and a liquids rich gas company, we are fit for the times and have the correct model for the times and we will go forward with it. I think if you look at an aggregate, I will give you a simplistic way to understand XTO and again it is the free cash flow emphasis.

It takes looking forward the next couple of year, again the relevant moment, the ones we’re transcending into takes about a third of our cash flow to stake hold, it takes about a third of our cash flow to do 10% growth and we have about a third of our cash flow left to pay dividends, buying stock do add-ons, pay down debt, whatever we want, but that is the relevant number.

In addition to 10% growth that is very robust and the XTO advantage, and it prevails, those who have said it doesn’t are just wrong, these numbers today are I would submit those it is what it is. If you’re using last year’s finding costs. They’re just wrong I would say our finding costs at this moment, given service costs, of today now this is not this year’s number, it is probably $1.25. If you look at that and say well, okay $1.25, what does that mean. Well that means you got a very robust and profitable model given lower commodity prices.

It is reserved and therefore translates into all of those numbers I just talked about. That’s what it means. Now, this year’s finding costs won’t be that low but it will be lower than last year. It is on the direction reflecting service costs coming down through the year and our inventory and reality, the quality of it and finding costs, for effort is probably the best ever blended in, all molecules and so a deterioration of our inventories incorrect.

It is actually has been enhanced, the activity of last year, really a lot of those dollars, if you go back and analyze and were directed toward becoming the leading Shale producer in America and again, the fruits are coming, and, you will see in some of them now. We tend to be more conservative than most companies I believe in reality and results driven high and so we don’t go around trying to convince you, but of things that are way beyond what we’re delivering.

So sometimes being a little you get left behind and the belief of what you can deliver versus competitors who are talking more, but don’t forget us. In reality, we’re probably the best. The machine’s the best and it is reserved, given its enormity and the thing goes on. So we’re proud of it, its delivering.

With that, I will turn it open to comments.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from David Chrysler - Simmons & Co.

David Chrysler - Simmons & Co.

Real quickly, kind of last quarter you guys talked a little bit about the likelihood of experiencing some involuntary curtailments. Could you just talk a little bit about whether that happened and how that impacted kind of the growth outlook for the balance of this year?

Keith Hutton

We had a little bit of it not as material as we thought it might be, we’re guiding to the four quarter, obviously our rigs down a little bit, but we’re also thinking that we may have some of that going forward. We’ve seen a little this quarter. It is not big numbers, but its there is a chance that happens, but again, a lot of our we probably had, the majority of our overrun was the fact that we had no shut-ins as well plus our wells were a lot better than what we actually forecast.

David Chrysler - Simmons & Co.

Kind of adding to that or thinking about that going forward, you mentioned having a little bit of backlog of drilled uncompleted wells. You can talk about your thought process for completing those, kind of over the next, I don’t know, couple quarters, obviously it is a present value exercise, but just your general thoughts there.

Keith Hutton

Yes you probably step on it next year, as you think prices are coming back and it is not a huge number of wells. It is mainly in the Barnett. Basically, because we didn’t we are already going out our production numbers as it is.

David Chrysler - Simmons & Co.

Then just lastly, you mentioned that you’re kind of moving to a development stage in the Fayetteville. You can talk a little bit about how much of that acreage is held by production, and then while you mentioned going to a development stage. Are you still looking at maybe making around with extended laterals and at least from a development perspective? Can you give us an estimate of well costs, EURs and what not so we can kind of think about how we’d model that out?

Keith Hutton

I mean it takes us probably five or six rigs to hold our acreage position, over the next couple of years and so we are still expanding. We’re getting a lot of help from the other guys. They’re drilling in the sections that we’re not. So I don’t think we’ll have any big losses of acreage and it doesn’t take a tremendous amount of rigs to stay ahead of that.

As far as lateral links go, we’re drilling them 4,000 to 4500 feet. There are a lot of people working on longer laterals. We are actually working interest owner in several of those wells that have been announced by their operators that are big, so we’re very aware of it. We’re two about 12 stages, 10 to 12 stages in our 4,000 foot laterals and we’re looking at actually increasing sand concentrations and drilling longer laterals.

When I say, we’re in development mode, there are a lot of areas that we now have finally finished our infrastructure build out and so we can actually put the wells in low pressure, like you’re seeing with everybody else and deliver the volume straight off of the wells. So there are certain areas now where we can just putting rigs to work, drilling away on 80 acre spacing.

David Chrysler - Simmons & Co.

Do you have an estimate for kind of what you think the ultimate recoveries on those wells will be?

Keith Hutton

I think they’re running toward 2.5 or better. The industry is coming up with numbers even bigger than that. We believe that’s a very possible. I don’t see our acreage being much different than theirs, so we’re probably heading there.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

Your slides on page two and five of your Ops review show that sharp decrease in rig count in both the Freestone and Barnett, but continued production growth in the Freestone and Plateau in the Barnett. In the Freestone, can you talk to if and when production could start to roll? In the Barnett, where production might be if completion activity had been normal through the year?

Keith Hutton

Let’s talk about Freestone first, I really think what has happened guys is we’re drilling more horizontals and we’ve had some of the acreage we bought from Hug, very good along with the Southern Bald Prairie extension. We’ve had some big wells there as well. We’ve also done some infrastructure build out that lowered some pressure that allowed us to pick production up through just lower pressures and per well rates than on the older wells as well.

We think we can actually keep it growing with 16 rigs given that we’re switching to more horizontals in the mix and so we haven’t come away with our numbers yet, but we are heading toward and we have a build out that’s set for 1.1 to 1.2 B’s a day. We’re using Freestone as a throttling animal, which we can either step on or not, give all of the Shale growth that we have in the other Basins.

So that’s the reason we dropped our rig count. We don’t have a big problem with acreage holding here. So it’s just a conscious decision to make sure you’re drilling in the shale basins where you need to hold acreage. It doesn’t mean you can’t just turn the thing back on when you want to.

For Barnett, same theory, we have about 1.1 B’s a day of take away capacity on pipelines. We are currently needed to put some compressors in to get that volume out, but that’s it. We’d actually dropped our rig count because we only need five or six rigs to hold our acreage position. We had a lot of wells in backlog already, so you’ll see us picking rigs back up next year. We don’t need to pick it up a lot and we’ll be able to turn the growth back on again because of some of the uncompleted wells we have.

Brian Singer - Goldman Sachs

Sticking with the Barnett, beyond the uncompleted well, I’m looking at the some of the strong well results in the quarter. Where are you in the development stage of the core and Tier 1? What you would call your best prospects and then what your expectations for IP trajectory over the next one to two years?

Vaughn Vennerberg

We really haven’t seen it change. Over the last two or three year, the wells have been fairly consistent in the core. There’s one thing that will change, as you get to more of the inner city, you have to drill longer horizontals and I think one of our competitors along with big wells that’s very close to a lot of our acreage that’s along horizontal and you will see us doing more that just because that’s the best way to hold your acreage.

From a standpoint, we haven’t seen any degradation in our well performance. We’re still drilling 80s and starting to drill some 40s in different areas. We haven’t seen any problem with that. A lot of the industries have already done that, so you can look at some of their data, but I think we’re in good shape. I don’t see any kind of degradation, in fact with longer horizontals maybe a little bit of an up tick in per well rate in reserves.

Operator

Your next question comes from Subash Chandra - Jefferies.

Subash Chandra - Jefferies

First, on East Texas, let’s stick to the northern part of the acreage, really some exceptional wells, probably some of the best wells in the play. Just curious, what well costs are running up there, Pinola, and what do you think the secret sauce is? Is it pretty much the geology, the clay content, that sort of thing? Or is there something else going on?

Keith Hutton

It’s just because we’re so good.

Subash Chandra - Jefferies

Beyond the obvious, please.

Keith Hutton

Really, the advantage we have, guys, as we’ve been the number one drill in East Texas for a long time. So our guys are very good at drilling wells in all of these areas. We’ve been drilling deep horizontal Cotton Valley Lime wells, before the Haynesville became a big deal. So I think our drilling guys were kind of ahead of the curve, if you look at what our costs on Pinola, they’re probably $6.5 million a well.

Do we think we can drive that down? Sure, we’ve been able to do it in every other play that we’ve been in. It’s early we haven’t drilled so that will take us a little time wells so it will take us a little time. Geology, we’re in an area where the shale is actually pretty thick. So there is a large gas in place target for us to go after as well.

Subash Chandra - Jefferies

When we look at sort of the Southern acreage, Shelby and Nacogdoches so on and so forth, are we talking close to $10 million wells? Really, what is the appetite to pursue horizontals in that part of the play, that are at 10,000 feet and deeper, given the current state of the gas markets?

Keith Hutton

Everything in the Haynesville is 10,000 feet or deeper. Most of the play is 11,500 to about 13,000 feet. Those wells down there, most of our acreage is in the 12,500 to 13,000-foot it’s not that much deeper that what we’re drilling right now on Pinola. It will cost a little bit more, obviously. I don’t think it’s going to be in the $10 million range. We’ve already drilled a couple of wells and we’re nowhere near that. I’m not ready to jump out and tell you exactly what that cost is, but let’s get some wells completed down there.

Subash Chandra - Jefferies

Though I guess those wells don’t look identical to Louisiana, or I mean whether it’s pressures, or maybe first month declines, that sort of stuff, you would expect a little bit less EURs in that part of East Texas, versus Louisiana?

Keith Hutton

I don’t think anybody knows that, Subash. The star rates are sure Louisiana-ish, but I don’t know that you know anything about what decline rates are. There is nothing, but that much data down there yet.

Subash Chandra - Jefferies

Woodford, what are the well costs running now?

Keith Hutton

They’re running to 4-7 to 5, in those kind of ranges.

Subash Chandra - Jefferies

That’s for is like 4,500-foot pipe…

Keith Hutton

Lateral, yes.

Subash Chandra - Jefferies

Two quick ones, here: One is just to clarify, the Q4 production, slightly down just because you’re modeling in potential curtailments?

Keith Hutton

Yes.

Subash Chandra - Jefferies

Do you have a specific number, like a few hundred million a day or whatever it is you’re modeling?

Keith Hutton

No. We’re not really going to get into it Subash. We’re just trying to be a little cautious to be honest with you. You don’t really want to jump out there, and obviously our rig counts down too, and we don’t want to jump out we don’t want to jump out there and so we got some big growth, even we’re drilling less rigs plus the fact that there’s a chance you get shed so you’ll notice whose expanded our range a little bit on the gas and that’s because we think there is a little uncertainty as to what that answer is in the fourth quarter, but we’ve been doing out the last couple of quarters and obviously beating it pretty largely.

Subash Chandra - Jefferies

One last one, I’m looking just in the cash flow statement, the $700 million in early settlement of hedges, how should I interpret that? Is that just normal course of business, or was it a early settlement of hedges?

Keith Hutton

That goes back to the hedges that we early settled and re-set in January. I would not pay much attention to it. When you get to the end of the year, everything is the same. It we just took that money, accelerated it forward, so we could make the statement we’re paying down debt by $2 million. When you get to the end of the year, cash flow is the same, debt is the same, it’s all the same, it has no impact on 2010.

Operator

Your next question comes from Scott Hanold - RBC Capital Markets.

Scott Hanold - RBC Capital Markets

It looks pretty clear or it sounds pretty clear that you guys are focused on increasing oil volumes and not only by your talk but by your actions. Can you speak in terms of looking forward are there anything strategic you’re looking to do to ramp those volumes up boxes a big gas producer, having oil make a dented, it is kind of difficult, but would you be an acquire of oil assets and if so, where?

Vaughn Vennerberg

We would be an acquire of all assets, but we have been in that mode for a while, so that is really not new. It is not a reaction to all of a sudden that is popular for us to be saying to you guys. We put an emphasis on oil drilling earlier this year, and looking at oil, in the Bakken, getting ready to try to grow that area.

We look at it more as an economic reality that we are getting substantial amount of our prosperity from oil and natural gas liquids, or the liquids part of our business and so yes we would grow that, but we won’t all of a sudden say, well we will by an oil property and not a gas property.

One of the things that we can look forward to next year is resuming more flexibility on what we can do on asset acquisition, just in general. This year was a year of paying down debt, a couple billion. That was our basically our free cash flow and we dedicated that to debt retirement. Next year, we will be a little more flexible and be looking at a little more aggressively at doing add-ons.

Of course, we would consider all add on as well as additional acreage or production in our existing areas, obviously, the Shale have a cutting edge emphasis now and again, it is not from a semantics it is from economics. We will be allocating our capital to the highest rate of return, and recently we’ve added some smaller acreage deals, we’re looking at some more acreage deals that have very high rates of return. So that will have to compete with the rest of the lines of business.

The way acquisitions work is in essence, the economic advantage of oil will be bid out and so it doesn’t you got to keep that in mind. You’re not going to magically have higher rates of return from oil particularly, from the acquisition of it, because you’re in a competitive world that will be bidding out or bidding that down to a rate of return that competes with natural gas as well.

So we’re not and our philosophy is not to spend a lot of time trying to redesign the optics, to cater to receive of the day. So that is not so we won’t be spending a lot of money to try to looks like an oil company or suddenly say we are one. I think that’s kind of silly. The way you see us do is what we do what I would say probably we will do, we will try to keep about a third of our cash flow from liquids and grow our Shale dramatically.

Scott Hanold - RBC Capital Markets

It looks like you’re really stepping up on some of your oil assets organically. It seems like you have a lot of running room and specifically in the Bakken, can you talk about the amount of undeveloped prospective acreage you think or locations you think you could have yet to drill, that is perspective sort of in that trend and also address are you trying different things, obviously, we’ve seen several companies come out there and start putting a lot more energy in the ground and seeing tremendous results. I mean what are your thoughts there and there is some chatter on Simul-Frac now.

Keith Hutton

We are obviously doing the same thing you’re seeing a lot of people doing I think when we bought position they were doing nine lateral and six frac stages and today we’re up to 11 or 12. We’re probably going to do 14 at some point you do too many and economically it didn’t help you so you kind of get over the top, but we’re still working on that. As far as locations, we haven’t flushed that out yet. I would say we’ve got more today than we dreamed that we had, when we bought the Headington acquisition.

I really want to throughout a number, but I’ll give you this. Most of our acreage in Elm Coulee, which is about 120,000 acres of our 450, is already drilled on 12 acre spacing. So we’re despacing it to 640s and ultimately toward 320s probably.

Over in North Dakota, a lot of our acreage position, probably half the remaining acreage position you can end up with Three Forks and Bakken underneath it. So we’ve got a lot of opportunities to drill. We’re still delineating some of that. What you’ll see with us doing next year with our six rigs plus is stepping out and testing some of the outer reaches of the acreage production [Technical Difficulty].

Scott Hanold - RBC Capital Markets

Just real quick clarification, over your 450 total in the Williston, 120s in Elm Coulee, and is the rest in North Dakota or is there still some in Montana, yet?

Keith Hutton

Most of it’s in North Dakota.

Operator

Your next question comes from David Tameron - Wells Fargo.

David Tameron - Wells Fargo

A couple quick questions, Keith starting up with you or Bob, whoever wants to take this, but as you look at the acquisitions you’ve made the last couple of year, what acquisition stands out?

Keith Hutton

They all do. I mean if you look at Headington, I’ll let Bob jump in here, but if you look at Headington, obviously with the advent of the Three Forks, which was kind of our dream case, that thing just explodes for us, and oil prices have held up. If you look at Hunt, all of the properties were great. You refreshed your Freestone with some great opportunities for horizontals and in fills and then you also bought most of your acreage in Haynesville, as kind of a layer on just on top of it.

You go to Fayetteville and yes Southwestern sold a piece they didn’t want to drill, because they had some issues with lease expiration. As probably turned out better than they thought it was going to be. So really, I kind of look through the major ones we spent most of our money on and I don’t know I can pick one out in particular. Bob may have a different opinion of that, but they all turned out to be very good and most of the things that we kind of dreamed would happen have actually come true at this point. Bob.

Bob Simpson

What I would say is that if you look at it in aggregate, another way to view it is that surprisingly, even given the change in the commodity price environment, it’s still all stellar and we can still do it all. So what it did allow us to do is to expand the oil chill business, which I think is a great addition to the technical input from our people. It allowed them to transfer their shale expertise, the shale play.

Then you look at a lot of the other effort was added on great add-ons in East Texas, in addition to Haynesville, a many conventional opportunities and then the rest of the dollars mostly were spent in what I call the reinvention of the age, which is allowing us to get more advanced in the position of a premiere shale player in America and so that’s all excellent.

Now I know that I would be inclined to say, well, sure, if I had that explanation, or sort of a rationalization of even the defense, but surely not. That was the excitement of the moment, it was a hard year. The world was wondering, a little bit have we lost our minds, but when you reinvent yourselves, and transition to a new world, sometimes you go through a moment of the entrepreneurial moment, which is somewhat confusing to those not right in the middle of it like we were.

So what I would say is that it’s turning up very well, the whole package and there’s not. On the other hand, you can say what was the best, there’s a lot of good stuff, the other question, I would ask on that was a failure involved in that, that was dependent on a price environment that’s now dissipated and the answer to that’s just as important is no, there was no failure involved in it.

Now, when talking about all earlier, when someone was talking about where we emphasize all acquisitions, but I was talking about here is what’s a smart way to get into oil production right way? A smart way would be an undeveloped acre that you didn’t have to overpay for, and like the Bakken, would be a good example.

Now, when I was talking, the advantage would be bid out of an oil acquisition, there I’m talking about the producing stream. That’s a present value exercise of future stream of income, which is, as a price deck, which given where oil is, and then you would put your rate of returns on, that you will bid out that advantage, and so buying a stream of oil income doesn’t make you a better company, just because you’ve done that.

Now if you can get smart in the development of oil, from scratch, yes, there is an advantage there, which you should pursue, but you can’t put all of XTO in that direction, but you should devote a better percentage than you used to it, and we are doing that and so that’s the distinction I would make.

David Tameron - Wells Fargo

Another question, just going back to the pipeline constraints, Keith, if there were going to be constraints, where would you expect them, both before the end of the year, and then potentially into the first part of next year? Other than kind of what’s out there is typical.

Keith Hutton

Typically, they’ll just back you up with pipeline pressure. It will be kind of uniform over certain basins. Or you’ll have plant downtime that is not normal. We’ve typically seen that in the Rockies, honestly. Where they’ll just go ahead and where they would normally do their plant maintenance, sometime early next year, they’ll do it in the fourth quarter of this year, because they don’t really want to pull the gas through the system because they’re packed. I wouldn’t be surprised to see it kind of spread across some of these different shale plays, but it wouldn’t surprise me if it’s out in the Rockies either day, it’s kind of hard to pick.

Operator

Your next question comes from Joe Hellmann - JP Morgan.

Joe Hellmann - JP Morgan

In the Fayetteville Shale are you seeing pretty good consistency across you acreage position or are you seeing some areas of particularly strength and particularly weakness?

Keith Hutton

Yes Joe, you always see a little bit of that, but I would say even in the areas where it’s not as good, it is still economics pretty good. There are definite hot pockets where you get wells, everywhere you’re drillings 4 million or 5 million a day, hot pockets, but that happens in the Barnett Shale, it happens in every one of these plays. I would say, we’re seeing more good spots than bad spots across our acreage at this point.

Joe Hellmann - JP Morgan

In terms of the wells that you’ve drilled, but haven’t completed, what’s roughly that number now? How would that compare to where you were in the same time last year? I mean, given that the activity this year has been quite a bit lower.

Keith Hutton

It’s probably a 100 wells outside of which you’d normally be doing, maybe a little more, but it’s not too bigger number, but it’s almost all in the Barnett.

Joe Hellmann - JP Morgan

Keith, have you guys tried any Cotton Valley Teller, horizontals and what do they look like, if so?

Keith Hutton

The industry has been doing that, and they’re actually pretty good, over on the Pinola side. When we bought hunt, they had tried a couple that were actually okay. So we’ve got plans to do some of those and I think that’s an upside that we really don’t talk about much, but it’s definitely with this kind of acreage position we have across East Texas, that will be something we can ferret out over the next couple of years.

Joe Hellmann - JP Morgan

Lastly, just general thoughts about U.S. Natural Gas production declining, that EI, and 14 day data last week wasn’t particularly positive, recognizing that is lag data, though, so any thoughts there?

Keith Hutton

I think basically, I think a lot of people sat on wells, honestly, and didn’t complete them as fast because of what your gas price was in the first half of the year. I think they probably burned through that or very close to it. I think you’ll actually see, gas production start to fall, I think it’s painfully slow, but I think it will happen and you’ll see at end of the first quarter or sometime the second quarter or next year. They just stretched that out by not completing all of their wells.

Operator

Your next question comes from David Heikkinen - Tudor Pickering Holt.

David Heikkinen - Tudor Pickering Holt

As you think about the acquisitions that you made last year, are there any properties that you would put on the market now that you had a recovery in oil price or gas price that just don’t really fit and just aren’t core?

Keith Hutton

Not really, should we go look at some of them, probably, but at the moment, I mean the cash flow out of them is pretty good and I’m sure we will go through a property rationalization at some point here. One of the things we have Barnett through acquisitions. The thing you think is the lowest thing on the totem pole, you better be careful that’s what the other guy thought too, and if you give your tactical team a little time you will actually find some jewels in the rough so you need a little time to figure out what really use the lower end and what is not.

Bob Simpson

The rest of the story with us is we don’t buy companies much. Most of our assets are hand picked the one company in that last year was hunt and they have a similar philosophy dollars which is have long life with a lot of upside. The only but the rest of their philosophy, which was, go slow, sit on it, distribute half of the cash flow rather than develop aggressively meant that those assets in general were under exploited.

So one more reason to go slow and let your staff get your arms around them, because we will find stuff there that is all the way from low hanging fruit to you got to think a little harder, but the concept of are they underexploited. Yes in aggregate and that’s why we bought them. We don’t have a lot of candidates for disposition and just by the way we acquire things in general. Never have, if you go back, all the way back, we sell very little.

David Heikkinen - Tudor Pickering Holt

You would say the stuff you buy, you tend to develop and make…

Keith Hutton

Yes, and was hand picked in general, and already screened.

David Heikkinen - Tudor Pickering Holt

Then as you think about the plan going forward, and as you model your internal base decline, as you shift more as you shift more drilling toward Shale that you outlined really don’t really see any major changes from that 15%, 17% basic line. Is that a fair assessment?

Louis Baldwin

Yes, because really have you been drilling look tight gas wells have similar decline rates to what Shale wells do it is really not that different. So your entire model for the last 10 years has been build on drilling wells for very similar decline rate that you’re seeing in the Shale.

Keith Hutton

The ultimate decline rate is low for Shale as well. So as the wells mature and get the final decline, they go back into the low decline portfolio and it refreshes. So as long as you don’t get too carried away with your drilling program and get it too ramped, you can maintain that balance of pretty aggressive growth company with a low decline, given our asset mix, but it is another reason not to ramp it up 50% in anyone year. You could change the nature of the company into smart.

David Heikkinen - Tudor Pickering Holt

Keith, you just opened up a perfect segue to the next question on last one. We’ve seen a lot of hyperbolic declines in tight gas sands overtime there have been some questions and comments of Barnett Haynesville, Fayetteville, are these exponential decline, is there any credence, or do you have any comments on that perspective? That’s it.

Keith Hutton

I will try to stay out of the frac, honestly look, Shale are even tighter than tight gas sands. So we’ve got lots of tight gas sands that go in hyperbolic you’ve got 50 years for the history in some cases in the Rockies and stuff. So that a debate I just want to stay out. We wouldn’t have bought the stuff if we didn’t think they were hyperbolic gas.

Operator

Your next question comes from Phil Dodge - Tuohy Brothers

Phil Dodge - Tuohy Brothers

My question is on your Shale gas acreage position, whether you’re content with what you have now in supporting your programs over the next few years, or whether you would continue to add to it and lastly, how difficult is it to continue to add to it?

Keith Hutton

We don’t need any more than what we have, honestly, but if you’re smart and you see a hot spot other people haven’t noticed yet, you will add to it. Is that going to be a huge number? Not really. I will let Bob comment on that.

Bob Simpson

Yes, I think you have to be careful about getting too much inventory, or you will get into diminishing returns, if not negative returns, for your owners from the market’s viewpoint, but what we should do is be smart and when we see exceptional opportunities, do them. I think for us, it means stay within cash flow, because going outside of that to capture more inventories with equity or debt. This probably is a limitation, but I think if it’s an exceptional opportunity and it’s paid for within cash flow, which I think is organic growth, is as I’ve said many times, go for it.

Phil Dodge - Tuohy Brothers

Bob, you mentioned a couple of minutes ago that acreage in the Williston oil shale was an ideal target. How difficult is that now to achieve?

Bob Simpson

It is not that bad. We’ve actually have been picking up acreage all year slowly, but surely. It depends upon where it is, if it’s really close to partial, obviously we’re going to cost you a lot, but we’re just slowly, but surely working our way through, as we see things that look like there’s a reason to buy, because there’s a couple of good wells or a structural feature or whatever you think actually makes the wells better, we’ve been slowly, but surely adding to our acreage position.

Operator

Your next question comes from Nicholas Pope - Dahlman Rose & Co.

.

Nicholas Pope - Dahlman Rose & Co.

I was hoping just real quick, realized prices, before the effect of hedging. Do you all have that for the different commodities for the quarter?

Bob Simpson

Yes, we do. I can tell you the hedging advantage, if you look on gas, about $3.70 advantage. So your basis or your pre-hedge number would be that. On oil, you have about a $40 advantage due to your hedging on a fairly equivalent basis.

Nicholas Pope - Dahlman Rose & Co.

Then just I was hoping, you gave a lot of numbers as where the rig counts were. I was hoping are you running 47 rigs right now? Is that right?

Keith Hutton

Yes.

Nicholas Pope - Dahlman Rose & Co.

Then just like looking forward to 2010 that kind of double digit growth number that you’re looking at for 2010. I mean it doesn’t seem like 47 rigs would be able to provide that and so I was trying to get an understanding, I know you’re adding some rigs in the Bakken, some rigs in the Haynesville, but where else do we need to see the rig growth to get that kind of production growth?

Keith Hutton

Obviously, you pick up more oil rigs, out in the Permian, but you’re going to add to the 70s, 65 to 70, 75, at different times, probably a constant average is going to be in the 70 type numbers. It is really going to be, we haven’t come out with a budget yet, but it’s probably going to be in the high threes. It’s not going to be what some people have turnout.

Nicholas Pope - Dahlman Rose & Co.

Then I guess there was a comment earlier just about F&D costs kind of like an ongoing F&D cost of like $1.25. I was hoping to get a little bit clarity on that number. Is that number like a drill bit F&D cost? Does it include like PUDs? What is the actually like F&D cost you were like referring to going over with the $1.25?

Louis Baldwin

That’s really going to be a drill bit F&D cost. If you bought some acreage, you would layer it on top and we included our acreage in the F&D cost and I’m speaking for Bob, that’s kind of what your wells are costing today with the reserves you’re getting.

Nicholas Pope - Dahlman Rose & Co.

That doesn’t have an effect on PUDs, is that right or…?

Louis Baldwin

What it costs to get the drill and what you out get it.

Keith Hutton

Yes, it’s cutting edge. Drill well costs versus reserves.

Operator

Your next question comes from David Tameron - Wells Fargo.

David Tameron - Wells Fargo

Bob, let me ask a follow-up question, a strategy question. Aubrey is talking about a different business model, and he talks about a land, not a land bank, but essentially that doing JV’s getting the plays early prove up the acreage, bringing in partners, drilling carry, etc. Can you talk about what your view is on that and maybe I’ll direct the question, why XTO doesn’t do more of that?

Bob Simpson

I mean actually I think that’s a different line of business or a different approach. It dilutes your effort in our view. I mean basically if you start owning half of wells instead of the 100%, you’ve got to drill more holes in the ground, would be another answer.

It’s a form of land speculation, which we’ve always achieved value through production. All the way back and we don’t get into the promotion or another way to approach the business. It does take an awful lot of more effort; I mean they probably have three times the employees we do. We’ve got more production. I prefer our model I think our model creates more value and I’m not really here to basically, my job would be just to promote ours.

David Tameron - Wells Fargo

Is there an argument to be made for the present value though?

Keith Hutton

Actually, I don’t think so, but again, I stated my position.

Operator

Your final question comes from [Eric Genova - Morganstar]

Eric Genova - Morganstar

I was wondering if you could speak to the equal for potential and the Washburn acreage in South Texas or any other acreage positions have you down there and if you have any plans to test that over the next year or two.

Keith Hutton

We do have some acreage down there. We haven’t really put out any numbers. We are planning to drill a couple of wells and that’s really all I would like to say about.

Operator

Ladies and gentlemen, this is the conclusion of the question-and-answer session. I will now like to turn the call back over to Mr. Louis Baldwin for closing remarks.

Louis Baldwin

Well, thank you for listening. Again, as we think it is a great quarter, we’re well set up for continuing the old XTO model, keep in mind that the inventory allows us to do it and look forward to visiting with you again. Thank you.

Operator

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

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Source: XTO Energy Inc. Q3 2009 Earnings Call Transcript
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