Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  
TRANSCRIPT SPONSOR
Wall Street Breakfast

XTO Energy Inc.(XTO)

Q2 2007 Earnings Call

July 24, 2007 4:00 am ET

Executives

Louis Baldwin - Executive Vice President and CEO

Bob Simpson - Chairman and CFO

Keith Hutton - President

Vaughn Vennerberg - Senior EVP and Chief of Staff

Tim Petrus - EVP of Acquisitions

Analysts

Scott Hanold - RBC Capital Market

David Tameron - Wachovia Capital Market

Brian Singer - Goldman Sachs

Subash Chandra - Jefferies

Gil Yang - Citigroup

Joe Allman - JP Morgan

John Herrlin - Merrill Lynch

Kent Green - Boston American Asset Management

David Heikkinen - Pickering Energy

David Kistler - Simmons & Company

Presentation

Operator

Good day ladies and gentlemen and welcome to the Second Quarter XTO Energy Incorporated Earnings Call. My name is Tania 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 today’s conference. (Operator Instructions)

XTO's 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 would now like to turn the presentation over to your host for today’s conference Mr. Louis Baldwin, Executive Vice President and CFO. Please proceed sir.

Louis Baldwin

Welcome to the XTO Energy second quarter conference call. Participating today are Bob Simpson, our Chairman and CEO, Keith Hutton, President, Vaughn Vennerberg, Senior Executive Vice President and Chief of Staff, and Tim Petrus, Executive Vice President of Acquisitions.

For today’s agenda, I will start off by briefly reviewing the quarter's financial results and expense guidance for the remainder of 2007. Keith and Tim will then provide an operational update, and finally Bob and Vaughn will give their views and wrap up.

In addition to announcing the $2.5 billion Dominion acquisition during the quarter, XTO really had an excellent quarter financially. Compared to the second quarter of last year a 12% production increase and our consistent hedging program drove over 31% increase in operating cash flow and a 33% increase in adjusted earnings per share.

Operating cash flow as a percentage of total revenues again exceeded 65%. And importantly, we expect to continue to generate positive quarterly comparison as 2007 unfolds due to continued production gains. Following a 6% sequential production gain in the second quarter we are heading towards another similar 10% production gain in the third quarter.

Comparing the financial results to our first call last month, our earnings per share were $0.16 cents on a basic basis and $0.14 on a diluted basis that was a penny better than first call guidance.

GAAP earnings were actually the same. For this quarter, our derivative fair value of change was less than $1 million. So there was really no difference between GAAP earnings and adjusted earnings for the company.

Looking at production, natural gas production averaged 1.331 Bcf per day. It's a 5% increase from the same period, excuse me, 13% increase from 2006 second quarter and a 5% increase from the first quarter of this year.

Oil was just over 46,000 barrels per day, 2% increase from same period of last year. And natural gas liquid was 15,190 barrels per day, that's a 30% increase compared to last year. And on Mcfe basis, as I previously mentioned, production was up 12% compared to second quarter of '06 and 1.698 Bcf.

Natural gas volumes are due to increases from the Barnett Shale, East Texas in the Farmington District, and natural gas liquid volumes are primarily due to start up of Barnett Shale processing plant in the liquids extraction there. Of the 6% sequential production increase from the first quarter, about 5% is due to gains from a development program and 1% due to acquisitions.

Natural gas prices averaged 794 for the company after the benefits of hedging, that’s up 14% from the same period of last year. Oil was $67.03 up 8%, natural gas liquids $41.20, up 7% compared to the second quarter of last year.

Looking at our hedging for the remainder of the year, we have about 60% of our gas hedged going forward 900 million in NYMEX based priced $9.19. And during the second quarter, we added 200 million cubic feet a day to our position in 2008. 2008 calendar hedge is now 400 million cubic feet at an average NYMEX price of $8.80.

Oil for the remainder of the year, about 80% is hedge, 37,500 barrels per day at a price of $74.40, and for 2008 about half of our production 22,500 barrels a day. It's hedged at a price of $74.26. All of our hedges are in form of swaps with basis hedges in place for most volumes.

Looking at revenues and cash flow, revenues for the quarter totaled $1.329 billion, up 25% from the same period of last year. Operating cash flow $870 million up 31% from last year and our cash flow margin was 65.5% compared to only 62% in the second quarter of last year.

Operating cash flow per share is $2.34, on a basic basis fully $2.30 that’s up 28% for the same period of last year. And our gas gathering and processing in the marketing margin was $8.8 million for the quarter.

If we look at our interim analysis and guidance going forward, reduction expense was higher than guided for on $0.95 compared to guidance of $0.85 to $0.90 and we expect the remainder of 2007 to be between $0.90 and $0.95. The higher actual LOE was due primarily to increased maintenance and work over cost, power fuel and Co2 prices. For the power fuel and Co2, higher natural gas prices increased fuel per use gas cost and electric cost that we use in our secondary recovery water flood units in West Texas and Co2 volumes and price increase from the quarter.

If we look at a further breakdown, reduction expense for the quarter, labor and overhead was $0.23 cents. That compares with $0.23 cents in the first quarter of ‘04 sequentially, maintenance and work over was up $0.02 to $0.50 per Mcfe compared to $0.48 in the first quarter. Power fuel on the Co2 again was up about $0.04, $0.20 per Mcfe compared to $0.16 and compression and other $0.02 per Mcfe totaling $0.95 per Mcfe.

Our other expense categories were typically lower than guidance for us, and our aggregated cash expenses were on target, taxes, transportation and other $0.69 per Mcfe compared to guidance of $0.65 to $0.75, which we are guiding for the balance of the year.

Exploration expense $0.05 per Mcfe on the lower end of guidance, $0.25 and $0.10 and that’s the guidance going forward. DD&A was within our 2007 second quarter guidance, $71 and we are up in our guidance to $80 to $90 for the remainder of the year. The increased guidance is due to higher DD&A rates on the Dominion properties that are scheduled to close in the third quarter.

Asset retirement obligation, G&A cash, G&A non-cash stock-based all were within guidance and guidance has not changed going forward, and interest expense was below our guidance $0.31 per Mcfe. We are increasing our guidance to $0.34 to $0.40 per Mcfe to taking for reflect the newly placed corporate bonds and higher commercial paper utilization expected with the Dominion acquisition.

For the second quarter, capitalized interests were $7 million. Income taxes were in the range that we have expected and effective tax rate of 36.2% and a current potion just under 41%. Looking at capital expenditures, our development costs for the quarter were $623 million from the fund statement and developed acreage acquisitions $57 million producing property acquisition at $177 million; gas gathering, processing and other asset additions $136 million for total expenditures for the quarter $993 million.

Looking at the balance sheet, total assets increased to $14.752 billion and importantly cash and equivalents increased to $742 million this reflected proceeds from the common stock offering that we had in June and these will be used to partially fund the Dominion acquisition expected to close in the third quarter.

Long-term debt $3.552 billion, net of -- and shareholders equity on a GAAP basis $7.4 billion. So if we look at our debt-to-cap the strongest that we’ve had in the company’s history on a GAAP basis 25.7% excluding OCI 26.2% these numbers will increase as we go through the third quarter and closing the Dominion acquisition, we’ll get back to the levels that were more similar than what we saw at year end.

With that I’ll turn it over to Keith to discuss the operational results for the quarter.

Keith Hutton

Thank you, Louis. Great quarter for us from an operational standpoint, volume up 6% quarter-to-quarter. Like Louis said 5% of that to the drill bit and 1% through acquisitions that close during the quarter. Driven by Barnett Shale, East Texas and San Juan basin is the growth area. Around 79 rigs during the quarter versus 73 last quarter and you’ll see us probably hold somewhere around 75 to 79 rigs for the rest of the year.

If we look at the Eastern region in particular, Freestone trend was up 3% quarter-to-quarter on average 596 million a day, pretty much on track as we expected. Currently running 25 rigs in the Eastern region Freestone trend. If we look at upsides and things that occurred during the quarter, we had a number of 20 acre wells coming at higher expected rates $3 million to $4 million a day, so the 20 acre well program were about 60 wells into at this point, testing it looks pretty good.

Again we are thinking those wells are 2 Bcf or about $2.5 million or so, a pretty rate of return on funding cost. In addition to that, we did drill two more of our shallow Cotton Valley line horizontals we completed during the quarter. One of them the C&W 1-6H is 4.5 million and the Sartor 4H is 6 million. The last well in Sartor 4H in cost is sub $4 million to drill.

So if you go back and look at what we talked about from a drilling cost at the start of the year in the analyst meeting, we said these shallow wells cost about $5 million for about 5 Bcf reserves. We seem to be able to drive the prices down on the shallow wells again with the Startor it may end up about $4 million, and it's probably going to be at about 5 Bcf well, so better funding cost, better way of returns than we originally indicated.

If you slip from the eastern region Trend to the Sabine Uplift in Cotton Valley side we continued to have good success across through these fields, which is an old field we bought back in the EEX acquisition. We started drilling Cotton Valley Sand wells in that field. We are about four wells and drill on average done, anywhere from $2 million to $4 million a day. We have some 30 to 40 well locations and there are about $2 million worth of wells to drill. So very good rates of return and very good finding cost.

In addition to that, we have Decker Switch and Doyle Creek field area where we've been doing Travis Peak extensions along with [Pettit Doors] and we've been surprised by some of our Travis Peak wells that are coming into $3 million $3.5 million and the last day we drilled six to eight of those. The last two or three have been like that.

So you are talking about an area where your well costs are probably $2.5 million and the wells are somewhere in 2 Bcf range and we have a lot of undeveloped acres, some 40,000 acres.

And in addition to that, the Cotton Valley field itself, we started drilling quite a few good wells some step-out wells exceeding $3 million a day, production has gone from some $20 million a day back in '05 to approaching $40 million today. And we have two rigs in their running and we have some 60 to 80 wells remaining to drill. So the eastern side is beginning to run pretty well, much like the Freestone Trend.

As we shift from that to Barnett Shale it was a fantastic quarter in Barnett Shale. It was a fantastic quarter in the Barnett Shale, up 24% quarter-to-quarter. Let me caution you that we can't keep that pace up, if you did the map on that, they can take us from some $400 million a day to almost $1 billion a day in a year. Why do we have this especially this quarter? Not only were our wells very good, we also brought on some big compression stations. And so we unloaded some areas that were being held back from production.

We also completed some more wells in those areas where those compression stations were so; where we normally complete 50 to 60 wells a quarter, we completed some 90 plus in this quarter. And that’s the reason Barnett took off so explosively.

If you look at where we are, we're currently making $420 million a day on a gross basis today, operated. We've talked about our take away comparative being some $465 million a day currently, with us trying to drive it up to $840 a day by the end of '08.

What I would tell you is, we're accelerating our infrastructure build right now and should expect to have some capacity in excess of $500 million a day by the end of the year, so that we will be able to maintain our growth rate at somewhere around 10% to 12% per quarter, somewhere in that range.

If you look at where those wells are and how well they have done in the Barnett Shale, again, both North and South Tarrant County in the quarter are producing wells anywhere from 3.8 million to almost 6 million a day. And a number of those were spread out pretty evenly between the two areas.

In addition to that significant tier one wells, we are drilling both in Johnson County which some people are calling [Cork], and up in eastern Parker County, where we keep at the wells in the 2 million to 3 million a day range. Currently, we are making quite of bit of volume at tier one at this point.

If we flip from Barnett Shale to the Permian region, currently running six wells. Everything is pretty well on target. Things of note would be Russell field, which is now over 4,000 barrel a day on a daily basis. And we started drilling Davonian laterals there and the last couple have been 300 to 400 barrels a day. And again those are about a $1 million cost that we are cutting out of the current wells that are there, and made 200,000 to 300,000 barrels, so very good finding costs rates of account.

In addition to that yeah its steel building, more Co2 and injected into the gas cap, so we still see response from those wells and a continuation of the horizontal soundtrack program there. [Cordon] I feel that what we brought from Exxon in 2005 has kept building as we drove some good building, as 23 drivers some Europeans and care currently drilling verticals and are currently drilling 2 or 3 horizontals hoping that we will have the same kind of success here that we have in Block Nine and Russell field.

If we flip from the Permian region to the San Juan region, again production up in the San Juan region some 9% quarter, a lot of that being driven over return, development and by our CND development in buzzer expansion. If we look at return, in particular, I will take you back to when we brought it for a moment. It was making some $25 million to $26 million a day in 2003 for Williams. We talked about that we might be able to get it by $40 million a day, it is currently making $66 million a day.

We had to up our target last year from 65 to 75 million a day I suspect you will see us up that peak target again as Reton continues to outperform where we thought it really do.

If we switch from the San Juan region, say to Piceance Basin for a minute, we are currently teed in our fourth well, in the Piceance Basin and our Exxon form out that will give us our 50% of the anchorage should be setting pipe over the next couple of days. Well it looks good; the shows were great in both the third and the fourth wells. We talked about the first well last quarter we completed; we have completed the second well during the is quarter. It is currently flowing around 3.7, 3.8 million a day. But again, it is restricted because we can only take about $5 million a day out Piceance, due to our treating facility. We are still waiting on BLM approvable for our plant side which should give us somewhere between 60 to 100 million day of take away capacity. Hoping to have that done late fourth quarter or sometime in the first quarter of next year.

We currently have two rigs drilling: one is still drilling step-out, and another one has just started our first slim-hole pad drilling on a location, it should help us in costs. And I would say that the last well that we drilled, we drilled a little faster than previous ones so we are seeing some performer issues that are good as far as time and drilling on Piceance well.

If you look at the Mid Continent region, pretty flat quarter-to-quarter, that’s mainly been driven by Overthrust trend drilling or it had some good wells, 2.8 to 3.5 million a day. And in addition to that we have started our Woodford and Fayetville drilling programs. We currently have three rigs running in the Woodford and have four wells down and one that was completed during the quarter of Sidmore 11-35H, which is making about 4 million a day.

If we look at cost on those wells, we think we are approaching $4 million. First well was more toward 5, next one was 4.5, next one was going to be closer to four. We are starting to see some AFP’s from further operators as well that are in Woodford. Now we think Sidmore well is probably a 4 Bcf star well.

So I am pretty excited about the Woodford sale as our first couple of wells have come in, we anticipate drilling 12 to 16 wells by year end, give us a pretty good idea what the Woodford would be like. In addition to that Fayetville shale we have drilled our first horizontal and are currently completing it. Have drilled a pilot hole on the second horizontal and are drilling it. Both of them work every bit as good as the other operator's wealth is, both in White county. So we are cautiously optimistic about the Fayetville bill again, wells that are around $2.3 million to $2.5 million to drill in somewhere around 1.5 to 2 BCF per well.

With that, that wraps up the operational review. Let me turn it over to Mr. Simpson to wrap it up.

Bob Simpson

Thanks, Keith, and welcome everybody to our conference call. For this quarter, an exciting quarter, production growth is certainly phenomenal given, particularly, the base, the size of this company, and what we are able to do. We have raised our guidance to 17% growth this year in production and we are excited about being able to do that.

The company continues to hit on all cylinders, as you can see from the results, and we are pleased with other areas of performance. We continue to do what we do and that is to take in assets and make them better, and I think we are demonstrating that at an excellent pace this year.

If you look at our philosophy of hedging, we’ve talked about this quite a bit, I think we are in a moment where one can appreciate hedging, particularly as gas looks a little bit low $6 for the moment, If you look to the future though, we still see good prices and we are so excited about the prospects of natural gas and you see this growth to next years still over $8 and in ’09 its still around $8.50 and so the future of those looks well. So we are having a momentary look at storage again, also this year and all of last year once again there is an issue on the crossing of natural gas.

With that, what we intend to do is continue to protect the company as we move forward, so the hedging blast two and half to two-thirds of production and if you like it where we are right now we are somewhere around 60% hedged for the rest of the year and $9.83 or approximately $10 on an equivalent basis, including all.

So again next year we're about a quarter hedged at the moment. We will be looking to add that again to get within the half to two-thirds hedge band as we move towards that year.

We will be opportunistic. There will be events coming; there are always our events. Last year, we did, had a quite a bit of hedging during and very momentarily worried about hurricanes since they were pleading last year, so tell me those opportunities again, and certainly winter will return again.

Storages, when I say about storage something you feel and we are going to do that again this year. And it's going to be something similar to last year's, or it probably will be right at the same storage as last year's after this number this week, and so there will be a summary that our storage might yield a little bit more than last year, the majority of the scheme of things, that is probably relevant. It will be the events of next year that determine the price it is all I'd say.

We would want to add our heads being a protector, owners and we are excited about what we are doing on a muchc higher, financial prosperity, and value creation machine is secure for this year and so we look forward to the rest of the year with confidence and certainly a crisped place with adding value but then in those contexts.

And where we are today and so we are excited. That’s a technical difficulty there. Okay. That’s gone away. So, looking at where we are, in terms of our acquisition. We are excited about closing that.

We've done a lot of work to prepare for that, we're taking on some good people when it comes to the acquisition, our staffs, and lot of interviewing and simulation of a fairly large acquisition all it wants. That is, probably acquisition and we did it this way to get people to come with it. And so, we're excited about the integration of that, that’s we were in hand. So any growth will come orderly and then we will take it from there and make that asset grow.

So, we're excited about the remaining opportunity. It certainly bodes well for our future growth and adds some great assets that will contribute to the bag creation machine of XTO at a good price. So, we're excited about that opportunity about the creation here shortly.

If you look at what else is going on in terms of the market. There is quite a bit of a chat about MLP's. The acquisition market certainly will continue to have activity. We are viewing our mechanism of forming our MLP that we talked about, when we announced the Dominion deal and we're looking at it in a number of different ways. We're still on pace to come with it, structure in the first quarter of next year as promised. So we're looking at it, as to how exactly does it fit the XTO model and how will it create value for our owners and so, we probably will look at it a little differently maybe than the rest of the world.

And certainly , the way we will do it, you will have to be in the model that creates value for our owners and the way we have structured it the way to form the ownership. So, we are excited about their [mass account] farm to be worked on and what I am looking at -- again I worked on it in the mid-80s quite a bit. Structure is not all that much different. Today it’s a mechanism to capitalize streams of end count at a higher valuation of them, and in due course currently give streams of quality income.

So our obligations to our owners and to the public ability are to form a quality asset vehicle that delivers by and that will deliver increases in volumes. So we’ll be very careful in doing that. We have a great, quiet and the best asset, that’s really independent, I forget to say that word. And so it will be a reflection of the great asset base assembled here and as we capitalize those assets in different ways. It will be a real event of substance over quality assets that will last.

Going to the uncompleted, those of which were formed before, they have all delivered high rate of returns somewhere around 30% in overtime. Including distributions and we would anticipate that this, we found the best minds with the potential to deliver those same types of return.

So that is exciting and it’s fun to work on. The company has I can say on well – we one well will continue to look at such opportunities as they come along. We'll continue to, certainly for now, we have done a great job for the year of adding assets. But add-on are approaching $400 million in addition to Dominion acquisition and we've talked about, we kind of like to say that they around $1 billion for the year. And we are kind of a mid point and moving up. We have some offers also.

So we are pretty much on pace to do that, and so I would like to get Rohit to get that done this year, but I am certainly not just ready to go, It's not something that is needed in terms of delivering growth this year.

Now we certainly don't have to do anything large at the moment we have done that. We are in process of closing that, so we are way ahead of the game in terms of upside, record upside for the company that are captured, so we are under no pressure to do anything on the acquisition front.

What we will do is continue to look for those opportunities, which will help us to create value and growth. And if they won't do that, we are not interested and so that will be our discipline, we'll keep it as you've seen us keeping it for the last two years and keep this company positioned to the opportunistic for those opportunities that will do that.

So we are in good shape, we are excited, just wait to see how the rest of the year unfolds, it's always interesting. So there is a little difference and we'll see how this one plays out.

With that I'll turn up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Scott Hanold of RBC Capital Market.

Scott Hanold - RBC Capital Market

Thank you. Good afternoon.

Louis Baldwin

How are you, Scott?

Scott Hanold - RBC Capital Market

Could you talk about the service cost, I think the last time you commented on this you indicated that you’re holding off signing some long-term contracts, could you kind of tell us what your thoughts are here, where you see this going?

Louis Baldwin

We are still holding off as best as we can. We probably have 50% to 60% of our rigs open at this point, wondering if we were going to have pull back in gas price, you are seeing a bunch in new rigs at the market. We are getting people coming at us with rigs, where a year ago that was a problem.

So I think you’ll see some softening in the market today. I’d say it’s $18,500 and $19,000 a day for a 1,000 horsepower rig. It peaked in November probably at 21 to 22. For us as a company, we probably averaged 18.5 last year and we are probably going to be close to that again this year -- about leaving it open and not signing a long-term contract. And obviously if price stays down for while, we’ll be looking at signs, because I don’t think it’s going to stay down for a long time.

Service cost on the side of pumping, it’s probably flat to last year. It peaked again in November, December and then fell off 10% to 15% in the first quarter and it’s stayed pretty all year. On pumping services, same answer for case, and so I would guess when you really look at service cost you can be relatively flat to the average of last year unless prices stay down for a while and you see if we can permit.

Scott Hanold - RBC Capital Market

Looking at production of the Barnett Shale, I guess you had little bit of liquids production there this quarter, can you tell us what kind of drill there and what do you expect here going forward?

Keith Hutton

That is all at a Tier 1, we had a contract with ETC who was our gather -- they built plant, now that’s 1150 Btu gas, obviously that’s tough to put into a pipeline without treating it, so we’ve been blending up to this point, starting the second quarter where they got their plan online. In the core itself you are a 1000 to 950 Btu you don’t have any liquids, so it’s all your Tier 1 Parker County, and Western Johnson County type volumes.

Scott Hanold - RBC Capital Market

Okay. So roughly about 5% range going forward to be liquid, do you figure?

Keith Hutton

Yeah. It's pretty close.

Scott Hanold - RBC Capital Market

Okay. One last question Keith, can you talk a little bit about the Fruitland calls? I guess in your update you mentioned something to the effect of some horizontal join you are doing there. What could we potentially see out of that is, if that actually works as you think it could, how much upside is there with the horizon drilling?

Keith Hutton

Well it’s an area in San Juan where verticals are having a low trade well, makes up 10 to 15 foot tall, hard to crack, one of the rigs which went horizontal is you don’t have to crack them that way compared to the quite system and end up with a pretty good well. You got a couple of wells that are approaching through the end of the day, it’s probably acreage, I’m not sure I could name it all off the top of my head but it might open you up for 100 wells or something like that along that well.

Scott Hanold - RBC Capital Market

Okay.

Keith Hutton

And again they are going to be looking at $750 to $850 to drill and probably a Bcf as far as our reserves have pretty good binding costs.

Scott Hanold - RBC Capital Market

Okay. Thanks guys, good quarter.

Keith Hutton

Thank you.

Louis Baldwin

Thank you.

Operator

Your next question comes from the line David Tameron of Wachovia Capital Market.

David Tameron - Wachovia Capital Market

Hi, good afternoon. Congrats on a good quarter.

Keith Hutton

Thanks Dave.

Louis Baldwin

Thanks Dave.

David Tameron - Wachovia Capital Market

Quick question, a couple of quick questions on the Barnett mid-continent in general, can you talk about weather impacts from the rain -- that has the ability to get some drilling pass down wells down except to the nature of our third quarter?

Keith Hutton

You know it has some but we've been able to move our rigs around ourselves and the Barnett probably the biggest affect was someone needs to take was there was a lot of rain in the Freestone trend but again we have so many rigs running in different areas that's really not going to affect our volumes much, nor in the mid-continent. That doesn’t mean you want to take somebody else’s, but I don’t think you will see a big effect to us.

David Tameron - Wachovia Capital Market

Okay. Overall and if you were to think maybe we get a little bit less coming out of the Barnett than we would have otherwise, is that fair?

Keith Hutton

Not really, I would just have enough wells that are drilled and are completed yet that they could have made up for the difference. If you do see Barnett down, it’s probably going to be secular area in the Barnett -- we don’t have the take-away capacity, but…

David Tameron - Wachovia Capital Market

Okay, fair enough. You talked about, and I guess you are up to your Bcf targets with their most recent well, but the well cost us $4 million, $4.5 million. Can you talk about what you are doing as far as lateral and what the length is and kind of the well design?

Keith Hutton

Yeah, its 3,000 foot lateral. A top answer, you are probably doing five stages, four to five stage fracs, very much like the Barnett. Obviously, coming into it late we are able to watch what mistakes other people made. So, we're doing all basement and we're trying to curve. We are not doing packers class, if that’s what you are talking about. We are actually popping down plugs and shouldn’t have much like we do in the Barnett.

David Tameron - Wachovia Capital Market

Okay. Alright so $4 million is a target of -- $4 million is kind of where you are right now?

Keith Hutton

I would say a target of $4 million, five of the last well is going to be real close to that. We have been able to stay ahead of any troubles, so all people have troubles early. Again we are trying to learn from some of that. So, you are seeing some of the other operators, actually AFE right around $4 million. It doesn’t mean all of that market some of them are. So, again as an industry, I think we're driving the cost down with liquid.

David Tameron - Wachovia Capital Market

All right, good. Thanks and one more question on -- I'll jump off in the Permian, you run about five to six rigs, keeping production flat. Is that what it takes to keep production flat out there right now, in turn with kind of the tight oil play you have up there once they read?

Keith Hutton

That’s pretty close, I mean you could take up rigs and try to get some growth. One of the biggest problems in our fields is a lot of those we bought from majors who had worked on that the structure for a long time. And so what we are doing right now is doing some infrastructure building, save Goldsmith and Russell, because we don’t have the water-moving capability in some of the water plugs to pick up the volume much, so we are building infrastructure right now and I think you will see Permian starts rolling a bit next.

David Tameron - Wachovia Capital Market

All right. And Keith I’ll ask one last question. C&W, can you just talk about the well design and I'll jump off? Thanks.

Keith Hutton

Same kind of answer, Dave. You are drilling 2500 to 3000 foot laterals. Same kind, we will do water fracs. We believe that’s a better answer than what a lot of what everybody else is trying, and probably five stages for a 3000 foot lateral. So it will be very similar again to what we do in the Barnett and in the Woodford.

David Tameron - Wachovia Capital Market

All right, thanks.

Operator

Your next question comes from the line of Brian Singer of Goldman Sachs

Brian Singer - Goldman Sachs

Thanks and good afternoon.

Bob Simpson

Hi, Brian.

Brian Singer - Goldman Sachs

Just picking up on the Woodford with the initial success that you have had, do you think about accelerating, drilling? How many rigs beyond the three do you think you could go to?

Keith Hutton

Brian, we are not ready to say what we did, to be honest with you. Still around to consulting a little bit and getting ourselves in a good position. We are testing different areas, obviously the first area we drilled a well and it looks good, but or it could just spread out over a pretty good size area. So we are just trying to figure out where the hot spot is. There are take away issues in the Woodford for everybody. The pipes are not out there for a big volume build like what you see in Barnett or play and build at this point, so it will take a little time for infrastructure to get built, so there is -- you are not going to see us running rigs that fast at this point.

Brian Singer - Goldman Sachs

Okay and what time period do you see at this window and so you can have to make a call on to revamp up production on?

Keith Hutton

It probably takes about six months to a year before you really know what the answer is and before they can get the pipeline in there.

Brian Singer - Goldman Sachs

Great. And secondly, Bob you mentioned your history was MLPs and royalty trust going back many years. Can you talk to the specifics of potential changes to kind of get the right MLP structures for XTO versus those that have been used by other companies?

Bob Simpson

Actually, as far as the specifics, we are not ready to discuss those yet. But all I can say is we will look at it -- probably, maybe others will. Keeping this in mind the history of ours is specifically to create value for shareholders. So we will get some details out to you pretty soon. Right now, we are starting at, I really don’t -- anything I would say I need to review with the Board, so I am not prepared.

Brian Singer - Goldman Sachs

Maybe if I could ask the question slightly differently, what do you see as the pitfall for the existing MLPs that are out there?

Bob Simpson

The risk, I do know about this. I am not going to comment about the quality the investor wants out there. I would say the risk generically will be quality of asset, there will be some temptation by some people to take advantage of perhaps the evaluation of not making the quality that we would put in there, but again I really am not going to be worried about the rest, I am just going to be worried about ours.

Brian Singer - Goldman Sachs

Great. Thank you.

Bob Simpson

Fine.

Operator

Your next question comes from the line of Subash Chandra of Jefferies.

Subash Chandra - Jefferies

Thank you. I guess the first one’s for Bob. With prices maybe replaying when they did a year ago, we might have talked about this a year ago. So, is there anything XTO would actively do to manage risk beyond the hedging, such as in delaying completions or curtailing production or anything along those lines?

Bob Simpson

I think what happens is that you will get some curtailment as storage gets full so we will all participate in that either willingly or unwillingly. And so if that happens I don’t -- I guess to the degree that it happened and if it lasts longer we might accept it.

Louis Baldwin

Typically what we do is -- the reason we do hedging at a level we do the significant size that we do it at and so that we can run an orderly shop, less people go about their business on a sort of methodical best efforts where the key is stop and go, so we are not. I definitely don’t introduce speculation about our commodities into our day-to-day workload unless I saw something extreme.

Subash Chandra - Jefferies

Okay. And Keith, and on the drilling side, just a couple here in the East Texas, you talked on the 20s, do you see a haircut based on the IPs you are seeing, or do you think that eventually you might prove your way out of the sort of haircut that might be assessed on the down space locations? And second on the horizontals, I think you talked previously about maybe doing going back to some of the deeper horizontals where you get sort of the target maybe the 10 million a day plus rate, if that sound a horizon.

Keith Hutton

Well, let’s take the second question first. We actually would be shifting out of the shallow condition horizontals into the deep here in the next month or two. And so you will see us running in deep rig for last five months of the year, something like that. Again, what we are trying to do is learn how to drill those horizontals, learn how to complete them and then drop back into the harder step, it’s deeper higher pressure and higher temperature.

As far as the 20s go, actually what I'd say is the starting volumes have been higher than we might have anticipated. We don't know if that correlates to higher reserves, we think it might, but again, you need a year’s worth of history to understand that. So, I wouldn't put too much into that. We did haircut it and say it was 70%, 65%, what the 40s are. We may find out that's not true, I don't know enough data at this point.

Subash Chandra - Jefferies

And then in the Woodford, some of your operators they have had some pretty severe variance in IP rates between wells, even as they might have thought they cracked the code. Is that something you envision or do you think you fixed those problems others have experienced?

Keith Hutton

I think a lot of that start to faulting and so you need 3D over a lot of new area to understand it. We happened to have that over a large portion of our acreage position. We shot our 3D over looking for Cromwell sands way back. So that will help us on, you have variance like that in the Barnett too. They will be hotspot areas that the wells are $4 million to $5 million a day and not too far away it will be 2 million a day. I think that just a shale play in general.

Again, having a good spread of acreage, so that you can be in the right spot when you hit the big wells is the answer.

Subash Chandra - Jefferies

Okay. Yeah, finally, South Texas, where does that fit and do we down the road maybe ask this acquisition -- kind of see where the two or three P number might be coming out of that play or does that not quite fit that type of model?

Keith Hutton

It does, but it will take us a little time to get our hands. We had some ideas. We haven't come out and said what those numbers will be. We will probably tell you that in January, our analysis. Again, give us a little time to get our hands around it. We have some ideas but I don't have the right 50 to 31 to share with you at this point.

Subash Chandra - Jefferies

Okay. Alright, thanks a lot.

Operator

Your next question comes from the line of Gil Yang of Citigroup.

Gil Yang - Citigroup

Hi, could you go back over, you are running through numbers pretty quickly. Can you just give us the numbers again on slow rate though that would drill wells and you said, there are $4 million or 4 B’s rather as your expectation is that right?

Keith Hutton

Well I don't know we just have one well down guys, it’s $4 million a day and what I'll tell you -- that’s probably 4 bcf wells.

Gil Yang - Citigroup

Okay.

Keith Hutton

That doesn’t mean the whole play is 4 B’s of well. I think we came out in January and said it was anywhere from 2.5 to 4. Our first well is on the higher side.

Gil Yang - Citigroup

For Fayetteville, did you for the wells you are drilling now, are you drilling among 3D, and how important do you think 3D is going to be there?

Keith Hutton

Well, now we've got 2D over the areas where we are drilling them. I don’t know that 3D is going to be that important. They don’t tend to have water problems like we do in some place when you get across it all, but obviously you need at least 2D to know where the major faults are so you can avoid them. There are a lot of smaller faults over there 30 or 40 feet, paid bills, 200 to 400 feet fix. So, that doesn’t necessarily put you in a trap. I know some people are shooting 3D and we will kind of see what they get out of that data. At this point, we don’t think you have to do that. But we may change our mind all the time.

Gil Yang - Citigroup

Okay. And then last question is in the Barnett. Why did you have so many wells that were unhooked or that were not completed? Can you comment on your current backlog?

Keith Hutton

Basically, what we were looking at is we had an area where we had a major construction for a pipeline and compressor station that we thought would get done in the fourth quarter last year, that drug until April issue. And so there is no reason to go complete a bunch of wells as you can fill out. So, that’s why we had the backlog. Today, it’s your normal 70 to 80 wells of backlog tight numbers going forward. And that’s about what the other operators on a 24, 25 bring out as well.

Gil Yang - Citigroup

Okay. So, that backlog issues was a problem that was unique to you because of that compression?

Keith Hutton

Yes, it was unique to a certain area.

Gil Yang - Citigroup

Okay. What area is that?

Keith Hutton

It’s tier 1, it’s over in the Walsh Ranch area.

Gil Yang - Citigroup

Okay. And you commented that the reason your production was up so much was because of the compression and also the -- so, it’s the same thing, where you put on the plan, you are able to decompress some regions.

Keith Hutton

Correct.

Gil Yang - Citigroup

As well as the region?

Keith Hutton

Correct.

Gil Yang - Citigroup

Okay. Thank you.

Operator

Your next question comes from the line of Joe Allman of JP Morgan

Joe Allman - JP Morgan

Hi everybody.

Keith Hutton

Hi Joe.

Louis Baldwin

Hi Joe.

Joe Allman - JP Morgan

Hey Keith, in the Piceance Basin when might that Co2 treating plant come on line?

Keith Hutton

You know we are still waiting on BOM -- you guys are used to the Rockies, we thought we’d have an answer by now. Every time we get that, as it takes a little longer we were hoping it would be in the fourth quarter, it may turn out at the end of first quarter.

Joe Allman - JP Morgan

Okay.

Keith Hutton

Again, it’s not a bad time to not be producing Rockies gas at the moment, so.

Joe Allman - JP Morgan

Sure.

Keith Hutton

But it didn’t really bother us too much.

Joe Allman - JP Morgan

I think you are talking about when you got approved, but how long will it take to build that plan?

Keith Hutton

That’s when we think we will get it in.

Joe Allman - JP Morgan

Oh is that right? Okay.

Keith Hutton

Yes.

Joe Allman - JP Morgan

Okay

Keith Hutton

And they don’t approve in anytime soon, that plan is actually sitting out and we are just waiting for approval to move it.

Joe Allman - JP Morgan

Okay, and then moving over to the Fayetteville Shale, that first well you drilled, would you expect the cost to come down fairly meaningfully from that cost for the first well?

Keith Hutton

You know we drilled a pilot hole to see how thick it was so obviously that’s a little more expensive on that first well, but it will take us a little time, we have only drilled one well, but it might obviously like all areas -- why don’t you get enough rigs running in there and you do get faster drilling time, but it’s a little early for us to come up with an answer.

Joe Allman - JP Morgan

Got you. All right, thank you.

Keith Hutton

You bet.

Operator

Your next question comes from the line of John Herrlin of Merrill Lynch.

John Herrlin - Merrill Lynch

Yeah, I have got a couple, Keith, in the Piceance you said that was constrained in terms of the flow rate from the wells that we are producing. What kind of a catalytic flow rate or normalized flow rate do you think you'll get?

Keith Hutton

There are probably 5 million a day well, John.

John Herrlin - Merrill Lynch

Okay.

Keith Hutton

If you get to unload them. I said we are flowing them at 3.8 million a day, 2500 pounds flow in cubic pressure or some.

John Herrlin - Merrill Lynch

Okay. How much was the well cost for the last well? And what kind of savings are you really taking about going slim hole?

Keith Hutton

Do you know, it's a good question. We talked to the other operator about sand in Pinedale when they were drilling big holes, they were drilling them in 90 days. And once they went slim hole, they cut this to 65 to 70 days and with some more tweaking got it to lower numbers than that. So, you might save $1 million a well, something like that by cutting your time down from 90 to 67 days or something.

John Herrlin - Merrill Lynch

With the Dominion assets in the Rockies is basis fully hedge closed?

Louis Baldwin

Yes. With the acquisition, we locked in a 100 million a day and then locked in -- that was for 2008 and then on the basis we locked in $1.39 for '08 and '09. So we are in good shape on basis, once we get to January 1, obviously that's when the basis shrinks down to an attractive level with the pending completion of the Rockies express.

John Herrlin - Merrill Lynch

Alright. Last one for me, Bob, if [gas] for whatever reasons today is kind of where it is today? Would we see more acquisitions, less activity or just to slow down buying?

Bob Simpson

Am I asked?

John Herrlin - Merrill Lynch

Yes.

Bob Simpson

It would be opportunity driven, John and so the -- I would guess after a while there might be more opportunities that would be at a price we would be interested in. Initially there will be [paralysis]. Anytime in my current experience, anytime the commodity price goes down and sits there for a while, the seller wants to get last year’s prices and the buyer wants to get current and so there is the [en passé] for a while.

But if they were very sustained, then I should think by being more on [theories], but we would still have to compare all of that with the growth prospect of the asset and also stack it up against our drilling opportunities.

John Herrlin - Merrill Lynch

Great, thank you.

Bob Simpson

Thanks.

Operator

Your next question comes from the line of Kent Green, of Boston American Asset Management.

Kent Green - Boston American Asset Management

Hi, I guess that was a great quarter.

Louis Baldwin

Thanks.

Bob Simpson

Thanks.

Kent Green - Boston American Asset Management

My question pertains to the MLP, just in a broad classification, before at Royalty Trust you’ve had E&P assets. Now in there, there seems to be a lot of controversy about E&P assets versus midstream assets versus -- also you’ve got a GP structure in here now, instead of a trusty at the Royalty Trust. What do you see is the general trend here? You’ve got to stay with the E&P side and still say that you don’t want to, but midstream assets in here or is that still up in the air Bob?

Bob Simpson

Well, the midstream, they are still very capital intensive in terms of how the capital requirement goes. There is such a state of growth Kent, but they are not -- we will evaluate them eventually, but they are not ready to put in vehicle of -- the vehicles are capitalized and [triple] cash flow to a great deal and if you are using all the cash flow too for capital expenditures and assets, that’s not ready for that vehicle.

On the E&P side, the controversy there I think is whether or not you are doing a good enough job to find completion and again have growth vehicle, so that's going to be asset-specific and management-specific, so I do think it's probably... Well, the results will be more variable for the E&P, MLPs, for midstream.

Kent Green - Boston American Asset Management

But would you consider putting an MLP, with the GP together in LLC, which has been done, so there is no conflict of interest or is that still to be decided?

Keith Hutton

We are looking at structure in all the different ways and so I am really -- it would be premature to tell you we decided on any particular configuration.

Kent Green - Boston American Asset Management

Expanding is key in both with this lower gas price. Are you seeing any relaxation of bolt-on acquisitions in the ground other than special situations? Any price concessions that are still very, very high out there due to the nature of the strip?

Keith Hutton

That’s still specific to certain areas within spot you have an undercapitalized independents you can buy versus an auction that's out with everybody shooting at it. The gas prices only went down for a short period of time, so it really hadn't change what people are trying to pay for properties, and you got strip it's pretty strong at the moment but that will change with time.

Louis Baldwin

Everybody points in to strip can if they were seller and as they should, because the strip can be excess, so right now if feels like things were down and because of that you got a core on your stock and that's all, but they're really not yet.

Operator

(Operator Instructions) Your next question comes from the line of David Heikkinen of Pickering Energy. Please proceed.

David Heikkinen - Pickering Energy

Good afternoon.

Louis Baldwin

Hey, David.

David Heikkinen - Pickering Energy

Just a question on deal volume out on the market with Dominion and Anadarko going and finishing a lot of the deals. Where do you see as far as amount of asset packages that are out on the market right now on a relative basis to six months or you are going to?

Keith Hutton

I would say that we still see the same type of market results six months or year ago. It’s the smaller deals that are what I call plug-oriented; a lot of three wells drilled with three to five thousand locations.

David Heikkinen - Pickering Energy

You get a stock for you there.

Keith Hutton

You partner in, but Dominion and Anadarko where reasons to be selling significant production unless you find those situation. I would say that most deals, most packages you see drifting or mostly drilling deals. Our bolt-ons are a little different story. They are generally, significant production with them as we do those. So, I really haven’t seen a real change to the market in my view and what so many think.

Louis Baldwin

I think that’s -- I think you are absolutely right. Deal sizes are about the same and they are going to drift down every once a while like that special situation. But yeah, I think in terms of the size and types of deals, it really hasn’t changed.

David Heikkinen - Pickering Energy

Okay. And then, taking down to the lead on the Woodford for it may be a little more key, eliminating a string of casing that reduced costs by $700,000 to $800,000 per well versus other operators, is that one of the things that's being done or how's that coming down, the $4 million seems a little low versus the comps.

Keith Hutton

I think in the areas we've drilled in, we've drilled a lot of vertical wells. We had pretty good control on where the Woodford was, I mean, we didn't have any trouble on those wells, we just blown right down. So a part of that was bit design. I know we drilled the second and third well faster than we did the first one by a pretty good portion. We're still running pretty much the same casing as everybody else is.

David Heikkinen - Pickering Energy

Okay. So still three strings not doing any taking three quarter at the bottom and small…

Keith Hutton

Right. We've talked about doing that.

David Heikkinen - Pickering Energy

Okay. So that would be another reiteration that could drive down cost further, but you are just getting wells down faster right now.

Keith Hutton

Right.

David Heikkinen - Pickering Energy

Okay. That was it. Thanks guys.

Keith Hutton

Okay. Thanks.

Operator

Your next question comes from the line of David Kistler of Symonds & Company.

David Kistler - Symonds & Company

Hi, guys. A quick follow-up on the Rockies a little bit. Given the Barnett experience and the kind of capacity constraints that were relieved and how quickly production came online, obviously, with the assets you bought, some of the assets you have and then Rockies Express coming, the likelihood that we see an influx of that -- kind of across the Rockies potentially.

Can you guys just give us some more color on your thoughts around that, I realized you dropped in some hedges, basis hedges in '08, '09? Any additional color expectations? That would be great.

Keith Hutton

Are you looking for volume or basis differentials? Both?

David Kistler - Symonds & Company

A little bit of both, yeah.

Keith Hutton

Volume: one of the throttling factors will be BLM and EIS and EAs and all those things that just slowed down Rockies’ volume growth. So from a standpoint is there a bunch of gas sitting out there waiting to go into Rockies Express. I don’t think there is a turn out but there are some, but it won’t be as big of a number. Obviously it will help in pricing which will help you in drilling as well, if you can lower that basis differential and you see it if you look in the outward years -- it is dropping pretty fast. And obviously that will truly happen. The question is will it affect Mid Continent at all, when that comes into Mid Continent. As far as we are concerned you know we are more probably more limited by where we are, the number of rigs we can get in there and how fast it will let us drill, than we are about what capacity constraints can take away at this point.

David Kistler - Symonds & Company

Okay. And then just kind of looking at the prolific growth in production from Barnett as a result of Cap capacity constraint relief, are there other areas in your portfolio that you guys think you are going to see modest uptakes associated with capacity constraint relief? I know it's in the analyst day -- you walked through a lot of that for us.

Keith Hutton

Obviously if we can get to go up volume-wise we will be okay with that. Woodford, you probably a year out before you can take Woodford off. You can hook it up in the current systems but what happens is a lot of that’s low pressure system, so you blow out the old well here in your area. The operators in that particular are together and companies are trying to get around that but it does take time. There are some big pipings built in Woodford and Fayettville which will help some of that.

David Kistler - Symonds & Company

Great. Thanks much guys. Have a good one.

Keith Hutton

Thanks.

Operator

Ladies and Gentlemen this now concludes the Q&A session. I would like to turn it over to management for closing remarks.

Louis Baldwin

Thank you very much for listening. I think you all agreed that XTO is well positioned in 2007 for continued efficient production growth completion very shortly, really exciting $2.5 billion acquisition from Dominion, attractive current hedges and as Bob mentioned a plan to continue to implement additional hedges in 2008 as conditions warm. And so we should have results for the remainder of the year very favorably to 2006. Thank you very much.

Keith Hutton

Thanks everybody.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This now concludes the presentation. You may disconnect. Have a great day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: XTO Energy Q2 2007 Earnings Call Transcript
This Transcript
All Transcripts