XTO Energy Q3 2007 Earnings Call Transcript

Executives

Louis Baldwin - EVP and CFO

Keith Hutton - President

Bob Simpson - Chairman and CEO

Analysts

Tom Gardener - Simmons & Company

Brian Singer - Goldman Sachs

David Tameron - Wachovia

Joe Allman - JP Morgan

David Heikkinen - Tudor Pickering

Scott Hanold - RBC Capital Market

John Herrlin - Merrill Lynch

Jeff Hayden - Pritchard

Benjamin Dell - Bernstein

Stephen Beck - Jefferies & Company

Ray Deacon - BMO Capital Markets

XTO Energy Inc. (XTO) Q3 2007 Earnings Call October 23, 2007 4:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2007 XTO Energy Earnings Conference Call. My name is Shawn, and I'll be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session toward the end of this 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. As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Louis Baldwin, Executive Vice President and CFO.

Louis Baldwin

Thank you for dialing in, and welcome to XTO's third quarter 2007 conference call. Participating here from Fort Worth today are Bob Simpson, our Chairman and CEO; Keith Hutton, President; Vaughn Vennerberg, Senior Executive Vice President and Chief of Staff; Tim Petrus, Executive Vice President of Acquisitions. As we typically do, our agenda today will consist of my briefly summarizing the quarter's financial results. Keith and Tim will then provide an operating update, and Bob and Vaughn will wrap-up and discuss the current environment.

The quarter was another strong quarter for XTO. It was certainly highlighted by the closing of our strategic acquisition from Dominion of $2.5 billion in properties. But certainly on the production growth side and cost side, things worked very well. Production was up sharply, responding to both development and acquisition activity, and cost continued under control and we reported record cash flow.

Natural gas prices were weak during the quarter compared to the second quarter. Fortunately, we're nearly 60% hedged on our gas volumes, for the quarter, hedging added $1.72 to our average price. Gas prices have improved in October into the fourth quarter and we look forward to excellent results in the fourth quarter.

Compared to First Call estimates, our earnings per share were $1.06 on a diluted basis compared with $1.07 for First Call. Our GAAP earnings were $1.05 on a diluted basis, and the only adjusting item was a relatively small (inaudible) change in value.

On the production side, Keith will go into more detail with you there as we get into his presentation. But I can tell you that gas production was up 29% compared to the same period of last year, oil production up 7%, NGLs were up 12%, and on a Mcfe basis, the company was up a very important 24% compared to the third quarter of 2006.

Of the 24% year-over-year production growth, 14% came from our development program and 10% from acquisitions, with the lion's share being two months reported results of the Dominion acquisition. Once again, the East Texas region and Barnett Shale led our production growth through development.

If we look at average prices, gas prices average $7.20, realized basis. And as I said, we had more than $1.70 price advantage through our hedging, oil $70.73 per barrel, NGLs, $45.29. If we look at our hedging update, for the fourth quarter, we've increased our volume slightly there to 980 million cubic feet per day, about 60% of our expected production hedged at a NYMEX equivalent price at $8.97. We have been adding to our 2008 hedge positions and are up to a Bcf a day at a NYMEX price of $8.35.

If we look on the oil side, for the fourth quarter, 37,500 barrels are hedged a day at $74.40. And for 2008, we've increased slightly our hedge there to 30,000 barrels a day at a price of $74.20. As always, all of these hedges are in the form of swaps, but basis hedges in place are to be put in place on a majority of hedges.

Looking at our revenues and cash flow summary, revenues were $1.4 billion, up 30% from the third quarter of last year; operating cash flow $916 million, up 31%; and our cash flow margin was very consistent at 64% cash flow to revenue. I think that continues to show the efficiency of the company and the ability to contain cost, even with an inflationary environment.

On a cash flow per share basis we're at $2.34, that's up 24% from the same period of last year; our gas gathering and processing and marketing margin, $4.1 million.

Looking briefly at our unit cost analysis and guidance for the fourth quarter, production expense was nicely within the range of guidance of $0.93 per Mcfe. That was lower than the second quarter of this year. And guidance remains unchanged for the fourth quarter at $0.90 to $0.95 per Mcfe.

Looking at the production expense breakout that we give you each quarter, labor and overhead was down to $0.21 per Mcfe; maintenance and work-overs were up as our activity levels continued to increased to $0.54 per Mcfe. Power fuel and CO2 was constant at $0.15 per Mcfe; and compression and other charges were $0.03 per Mcfe; totaling, once again, to a production expense of $0.93 per Mcfe; taxes, transportation and other, $0.70 per Mcfe is right in the midpoint; no change to guidance going forward.

Exploration costs was $0.12 per Mcfe. This was higher than guidance due to the purchase of some seismic libraries related to Dominion acquisition. These libraries were expensed 100% in the quarter. We view this as a onetime expense and have our guidance going forward to a nickel to $0.10 per Mcfe, expect those charges to come back down.

DD&A was $1.84 per Mcfe, about the middle of guidance. This reflects two months of the Dominion acquisition. The fourth quarter guidance is $1.85 to $1.90, which will reflect the full three months of the Dominion acquisition, which has a higher DD&A rate than the base company does.

Our asset retirement obligation is $0.03; G&A is below guidance at $0.22 per Mcfe on a cash basis. Also below guidance, on non-cash, stock based G&A at $0.05 per Mcfe. Interest expense was in the middle of guidance at $0.36 per Mcfe and we are guiding next quarter to $0.45 to $0.50 per Mcfe. The increase in guidance for the fourth quarter is due to the full three months of the Dominion acquisition and our borrowing base, as well as the financing of our recently announced or the announcement today of $550 million in acquisitions in the Barnett Shale.

Third quarter interest excludes $8 million of capitalized interest. Income taxes were in the range of, we're predicting 35.9% compared to our guidance of 37%, current portion 43%. Our current taxes of income tax liability were current and that compares to guidance of $0.45.

Looking at the capital expenditures for the quarter, development cost, $727 million, unproved property acquisitions. Keith will talk about this some as we have stepped up our acquisition of undeveloped acreage, $230 million, reflecting the Dominion acquisition, proved property acquisitions, $2.558 billion, and gas gathering, processing and other asset additions, $235 million. Keith will also address the step-up in expenditures on our gas gathering compression assets to deal with the increased volumes that his very successful development program is generating.

Looking at the balance sheet, total assets are just over $18 billion with cash and equivalents on the books of $500 million at 9/30. These cash balances were used very shortly after the end of the quarter to fund in portion the $550 million acquisition that's just been announced.

Long-term debt, net of cash $5.6 million compared to shareholder's equity of $7.7 million. If you're looking at net debt to total cap on a book basis, 40.6%, net debt to total cap without the other comprehensive income, 41%. This compares to 39% at the end of 2006. So you can see, that including, some very significant expenditures for the Dominion acquisition and other acquisitions, the company has maintained its balance sheet discipline with debt to total cap being relatively constant from yearend.

That concludes the financial summary. With that, I'll turn it over to Keith Hutton to talk about the operations review.

Keith Hutton

Thanks, Louis. As you guys can see from our production volumes, we had a great quarter. Gas was 50 million over the high side of our anticipated volumes, oil was over the top of our guidance, NGL slightly underneath. That was mainly because of some maintenance shutdown time we had at our Cotton Valley plant and some shutdown time at ETCs plant here in the Barnett. So NGL should be back up next quarter.

If we look from region to region, Eastern region was up 9%, the Permian region up 18%, Barnett up 10%, San Juan region up 29%, even the Mid-Continent region was up 7%. Out of that total 14% for the quarter for the company, about 8% was due to the Dominion acquisition and 6% due to the development that we did during the quarter.

We're currently running about 78 operated rigs. Last quarter it was 79. We're going to maintain around 80 for the rest of the year. And going forward into next year, we haven't announced our budget yet, but you shouldn't see that rig count pick up much.

If we look at the Eastern region, in particular, the Freestone trend, we were up 5% quarter-to-quarter up to 626 million a day, and currently running 635 million a day. So, we have good volume growth. First quarter was about 3% quarter-to-quarter. Second quarter was 3%. This quarter is 5%. We're well on our way to about a 15% growth for the year, which is what we anticipate in the Freestone trend, currently running 26 rigs.

If you look at things that happened during the quarter that point toward our development, we've continued our 20-acre development. We're up to about 70 wells that have been drilled in total since we started it. We still think our costs are about $2.3 million a well, and our reserves are around 2 Bcf per well. So we still believe that that's on track.

If you remember, we think we had 800 potential 20-acre locations and about 200 of those are in our low-risk category, the other 600 in our higher-risk category. So we should be adding a lot of that into our low-risk category this year.

If we look at horizontals, we have both the shallow Cotton Valley lime horizontals and the deep Cotton Valley lime horizontals. We had one shallow Cotton Valley lime horizontal that got completed during this quarter at about 4 million a day. That's a little less than the 5 million a day we were looking for. But what I'd tell you is our cost on the last three was running around $3.5 million to $4 million to drill. We were thinking that was going to cost us $4 to $5 million.

So we were able to drive our cost down. We still think our reserves are close to 5 Bcf per well for those shallow horizontals, which means the economics are improving as we go along.

We are currently drilling our first deep horizontal of the year back into the [Gail King] lease in Farrar Field, should have three of those drilled by the end of the year. And again, those are the wells that have a potential to be 10 million to 15 million a day, and 10 to 15 Bcf.

If we look at step-out wells that we drilled during the quarter in Ball Curry field at the very southern extension of the whole play, we drilled a well at 3 million a day and have Sullivan at 5 million a day. We have several wells that look very good from logs down there. So we don't have too many wells down in that particular area, maybe 20. The potential looks to be pretty good.

If we flip from Freestone trends into Eastern region, Sabine/Cotton Valley Uplift side, we have three development areas that are going full tilt that look very good. First is Tri-Cities Field, an old legacy field that we got from EEX back in 1998. We hadn't drilled any wells until this year in that field.

We have drilled our fifth Cotton Valley Sand horizontal. That averaged 3 million a day. Those wells look to be 3 to 4 Bcf type wells for $2 million to $2.5 million. So again, a very good development program that we've just started on field we've had for a number of years.

If we add to that then our Travis Peak expansion in East Texas, in the Doyle Creek and Decker Switch area, we've had a couple more wells come on at 2 million, 3 million a day. Again, these wells are in the 2 to 2.5 Bcf type range for $2 million to $2.5 million. We have about 40,000 acres here that's not fully developed. So I think you'll see us run two to three rigs next year full time in that particular area.

And then, if we add to that the Cotton Valley field itself, the last three wells we have drilled have produced in excess of 3 million to 4 million a day, and again for about $2.5 million. So these wells are better than we anticipated. Cotton Valley field has gone up from 20 million to in excess of 40 million since we bought it back in early '05 and took over operations. And obviously, we're very early in the drilling program. We're only about 15 wells in.

The Eastern region which has been slow to start on full development has really kicked-in in those last couple of quarters. And we believe, going forward, we can grow this site 10% to 15%, much like we can grow the Freestone Trend side of the Eastern region.

If we flip from that to the Barnett Shale, as usual, it outperformed what we anticipated. On a per well basis we were up 10% quarter to quarter on net basis, currently making over 500 million a day today. So we've crossed the 0.5 billion a day production limit. We've had several wells in the 7 million a day that came in late in the quarter. So you'll see those in the fourth quarter volume, many of the wells in the core ranging from 4 million to 7 million a day. And again, we're drilling those for $2.5 million to $3 million a well. So, very good economics, they're running in the 4 to 4.5 Bcf per well type range.

Tier 1 as well, completing a number of wells out there at the 2 million a day range. And those are probably 2 Bcf wells for about $2.3 million.

As every quarter, we talked about Barnett tends to exceed what we thought. What I would add here is our acquisitions that we've made during these recent ones to add 24,000 acres to the Barnett Shale position, about 12 dozen of that in the core right next to some of these wells that are producing 4 million to 5 million a day. That's the reason we were aggressive in inquiring it. And in Tier 1, another 12,000 acres that's in that area where the wells are 2 million to 2.5 million a day and around 2 Bcf. So, it’s a nice add.

Louis mentioned how much money we were spending on the NGL side, natural gas operations to lay pipelines and plants and compressors. It's a little higher than what we anticipated this year, but that's because our volume has been higher. And so, we have to put bigger pipe in and build compressor stations and plants faster than we anticipated. So we accelerated capital from '08 into '07 in order to be able to get our volumes up, and we should be in good shape for next year.

If you look at the Permian region, we're currently running six rigs. Oil production is on target. Goldsmith Field is now 3,900 barrels a day. We've drilled a number of wells in the Clear Fork area that are in the 150 to 200 barrel a day range. We just started our St. Andrews development and our last couple of wells, have been much better than we anticipated, 50 to 150 barrels a day. And again, those are relatively cheap wells, $500,000 to 600,000 to drill.

If we look at University Block 9, once again, we've started into our big hammer fracs that we were doing last year. We recently had a well come on at 1,000 barrels a day. We anticipate that we will do four or five more of those before the end of the year and we currently have two horizontal rigs running there in University Block 9 as well. It is at a current peak of 7,500 barrels a day, which is the highest we've had it since we've had it in the field.

Russell is currently at 4,000 barrels a day, which has maintained better than it was in 1992 at 3,000 barrels a day. So again, Russell is running high as well. Yates production, we're still drilling horizontals there and production is the highest we've seen it since we've owned Yates at 27,500 barrels a day.

If we flip then from the oil side to South Texas and the first of the Dominion properties that we bought, if you look at Speaks Field, which is in the Wilcox Northern Trend we bought from Dominion. The first well we drilled there since taking over operations came in at 8 million a day. We also drilled two wells in our legacy asset field from Chevron that are big spud wells, that both came in 7 million to 7.5 million a day. And our first workover in Lopeno Field, which is a Dominion field, came in at around 5 million a day.

So South Texas looks very good. It's early, but several of those wells have virgin pressure and fault blocks that I believe, the previous operator might have thought were drained and they are not. So as you kind of see, in these types of plays, there's a lot more upside than people see at the very beginning.

If we flip from that to the San Juan region, we're keeping up with our multiple pay completions and drilling, still drilling our Gallup, Mesaverde and Chacra wells on target. What I'd point to again, which we seem to do every quarter, is the Raton production, which has now shot up to 70 million a day.

Last year we had a 65 million a day target, we raised it in January to a 75 million a day target. And, I guess we'll have to raise it again. I'm not sure what that final answer is at this point. We'll update you when we get to the Analyst Meeting in the early part of the year.

If we flip to the Dominion properties that we just take over from Natural Buttes. We're currently running three rigs, not completing the wells as fast as we could, due to current Rockies gas price and waiting until we get into the first quarter of next year where we have basis hedge in the Rockies at $1.39.

But the wells that we are completing have come in at where we expected, at 1 million to 1.5 million a day and should be around 1.5 billion or so reserves for a cost of around $1.3 million to $1.4 million. So, everything is going as we expected in the Dominion properties, both in South Texas and in Natural Buttes.

If we look at Piceance Basin, we have drilled five wells, two are producing, currently, we have two rigs drilling. Now, we can only produce about 5 million a day out there due to our capacity constraints. We did get BLM approval here recently, so we should have our new plant on probably late in the first quarter of '08 which will give us 60 million a day capacity.

And we will not complete any more wells until we get that plant up, because we obviously can't produce them all. We push the other wells off so there's no reason to be doing that at this point, especially, into low prices in the Rockies. But from a reserve standpoint, we believe they're still in the 3 to 6 Bcf range. The last well we drilled was around 95 days. Times are dropping, so I think you'll see us improve that in '08.

If you flip from that to the Mid-Continent region, completing as normal our overthrust wells. We did have a couple of wells come in at 4 million to 5 million a day in the Arkansas overthrust trend. But the real point for growth in the Mid-Continent region has been Woodford Shale.

We currently have four rigs running. We have completed three more wells, two of them at around 4 million a day, the other at around 2.5 million a day. That's the four wells now, three of them at 4 million a day that we've completed, all of them scattered across our acreage position. So, we're pleasantly surprised at what the Woodford Shale is doing for us.

Currently we have 30,000 net acres. We are leasing in here. And so, we'll update you again when we get to the Analyst Meeting as to how much total net acreage we've been able to acquire during the year. We are pleasantly surprised at what we're seeing here. Cost on the Woodford wells, last couple of wells have been around $4.5 million, and probably around the 4 Bcf range, so very good economics.

Fayetteville shale, we have gotten to drilling Fayetteville shale. We have drilled six wells that are down and waiting on pipeline. We have one drilling out there right now. Of the six wells, they all had pilot holes to see what the thickness of the Fayetteville shale was. It looks very thick out here, it’s 250 feet, 300 feet thick which is good as the core that's being drilled by other operators.

Shows were very good and log characteristics looked very reasonable. Obviously, we haven't completed one yet, but I would say everything is looking pretty good for the Fayetteville as well.

Now, if we step back for a minute and look what we've been able to do this year, basically, you've gone from a company that was mainly a growth animal in the Freestone Trend a couple of years ago to one that's got Freestone and Barnett. Now through the Dominion acquisition, you've put yourself in a position where you have Rockies growth, with Natural Buttes, South Texas growth, and then, if we add to that, our leasing efforts in the Woodford Shale and the Fayetteville, you now have a company that can grow in all the regions versus just one. It's been a very nice change in a very short period of time.

With that, let me turn it over to Bob Simpson to wrap it up.

Bob Simpson

Thanks, Keith, and welcome everybody to our third quarter conference call. We're pleased to announce these record results once again. I think what you're seeing as the company continuing to progress in its rapid growth profile and blend in selective long-lived acquisitions as well as bolt-ons and acreage altogether in an ongoing, long-life blend that allows for continued growth.

And I think that's - if I were to point to 2007 and say what did we do? I would say we captured long-life inventory to secure growth for a very large natural gas company. And the growth is a clouding. When you look at 24% year-to-year, I would say that would take me back a few years as this company is still small. That's very remarkable growth for a company that's putting out guidance of over 2 Bs a day equivalent production for the fourth quarter. And so, we're excited about where we are today.

If you look at what we're doing in terms of acquisitions, earlier this year we talked about hoping to achieve $1 billion of add-ons in our key areas in addition to any other strategic acquisitions we might do. And so far we've done the $2.5 billion Dominion deal, which is again, a remarkable property, long-lived property we've added in a very competitive world.

At the same time, with these recent announcements of the $550 million, primarily Barnett Shale acquisitions, we've secured $1 billion in what we call add-ons or bolt-ons as well. So here it is, October, the fourth quarter generally shows a lot of deals in the industry to look at.

And I think one thing we're seeing, which is encouraging to me in terms of adding quality deals to our base is the pickup in deals that we're seeing. And you say, well, what could be driving that. One thing that you would point to is a prospective change in taxes, a worry of it even now. I think it’s propelling some independence that are taxed with individuals to consider liquidating, and so some of them are old line. Old companies that sure fit us.

And so, if I were to put it in perspective, I would say normally, we're looking at $300 million to $500 million in deals. Most any period of bolt-ons that we're studying potentially could add on, I would say the activity today is double that. So I would look to see us add more deals in the bolt-on area in the next few months, three to six months certainly.

And so we'll be working at that. That's an exciting opportunity which is being driven again. Taxes would be one. There may be prospect of a soft economy which worries some people. Certainly gas prices, realizations to the non-hedger have been pretty anemic for the last -- ever since the hurricanes really --the realizations have been. And so, that's probably driving some individuals to consider selling.

Now, again, $500 million to $1 billion is not a landslide, but to us it's certainly exciting and it's probably double what we've been looking at. So we're going to continue to look hard at bolt-ons and expect to have pleasant success with some chance of it being this time of year more than likely. It would be deals closed either right at yearend or in the first quarter of next year should we have further success. And so, that's an exciting development that's going on. The deal market seems to be a little more fluid at the moment.

If you look at what we're doing to protect our growth, and again, it's always a difficult task, and that is to decide when and how much to hedge, what we've done routinely for years is that we want to hedge half to two-thirds. And so, we've kind of picked our parameter of size, and we'd like to have that protecting the next year or the year coming up in view.

Recently we've taken our level of hedging into that range for next year. We're about 55% hedged now at $8.96 equivalent or around $9. And so, I'm excited about that. I think that's a good price that we've been able to secure by doing some hedging and some rallies. And compared to this year, there will be some good realizations.

Now, at some point, the gas bargain or the half price sale will end for us. You don't want to get too hedged too far out because you'll get trapped. Certainly, gas at where it is today is roughly half price. That's energy and that's not going to last forever.

At the moment, it may be profited up a little bit and we can all argue that. The strip next year is I think I checked today, it's $7.84. That doesn't sound particularly robust when all strip next year is 81. And so on the 10 to 1 that would be $8.14, which is going to provide, should oil prices stay high, that will serve as some sort of floor to gas as we go forward.

Now, if you look at gas for the moment, storage is nearing last year's number. It won't be long. We can't beat that dog anymore. And so, we'll look to find a new one. So you will see that what really comes into play next is winter. Now people are worried about a warm winter and that's reflective of the recent past. Whether or not it's warm, time will tell.

I think as we go forward, we'll be looking at a better price environment down the road. I don't know when it's going to come into play, but you've got natural gas wanting to decline at 30%, underlying decline curve. If you hesitate for a moment, that decline curve takes over. And certainly the price of where oil is as a backdrop, gas will go up very quickly.

Recently we've had sort of two positive developments on the gas front. If you look at supply of the rig counts approaching down almost 100 rigs from its recent high and that's as a result of soft prices in the summer and fall. There has been some cutback. It also tells you that we're hitting the limit of economic prospects given today's cost and gas price. So that's also, again, saying to me, the future for gas is bright.

LNG imports are down below a Bcf a day now. If you look at storage increase this year over the five-year average, it's solely attributable to LNG increase over last year as that one variable. And so, whether or not there's a supply response from drilling is debatable. If there is, it wasn't much. In fact, it's surprisingly small to me. It wasn't that long ago if you went above 600 rigs a day, you were looking at a surplus, and now we're doing over 1,400 and wondering if we're holding production.

So what that says is that the individual prospects that are being drilled in natural gas have higher decline characteristics than the old fields did and probably have less reserves, so that bodes well for the future of natural gas pricing.

At some point, natural gas will come roaring out of this bargain matrix, and start seeking its value again. We've seen this before and it does work through it. Our whole philosophy, starting about 10 years ago, was to invest heavily into this kind of scenario. It's just a different matrix of numbers, but it was kind of the same ratio since gas was roughly half price.

And so, if you can make money here, which we can, very profitably, very high rates of return, it's just a matter of time until economics get significantly better, I believe. So we'll continue to build the reserve base and build the production long-life, take down every quality acquisition. That's our criteria and every bolt-on that adds value and just continue to do what we do.

Right now we've protected next year because, with that said, we do have significant amount of hedging to protect us just in case there is a warm winter. And, at the moment of the deflection in here, you could get caught with a few months of weak prices.

Now, in the long run, that's actually going to be the catalyst of much higher prices when that happens. The longer we put that off maybe we'll protract it a little bit. But again, I just step back and look at it, all I know is energy won't sell for half price forever. And so, we'll continue to position ourselves.

I think oil stays robust. And you could argue, well, maybe oil is overpriced, and that that will come down and then gas won't be such a bargain. I personally, think oils in for an extended, long-term run. And I know we quadrupled the company's oil production in the last three years with that belief and it's certainly paying big dividends today of them taking that action. So, I don't believe that we can rely on oil collapsing to put gas back in line with its intrinsic value. So we'll continue to build.

And again, what I would say with our philosophy is have not hedged out too far. Let's say that we get into the winter and it's really cold, and gas goes to $10 to $12, we have '09 totally open and would embrace that moment and begin to secure some hedging there. So with our strategy, we're always open to higher prices. Higher prices are not bad news for our strategy. But on the other hand, lower prices don't stop the company's growth. And so, we walk that fine line, and for years it's served us well, and we're going to continue with that strategy.

But overall, the company is in the best shape it's ever been. We're excited about seeing these opportunities come on the horizon. Our people are working hard. It's a great company and we're excited to be here and still excited to see what's happening to XTO.

So with that, we'll throw it back for questions.

Question-and-Answer Session

Operator

(Operator instructions)

Your first question comes from the line of Tom Gardener with Simmons & Company. Please proceed.

Tom Gardener - Simmons & Company

Hi, Bob. You mentioned gas being half price. With respect to taking down your rig count in the non-core Barnett and adding rigs in the core, can we infer anything about the economics in the non-core being somewhat challenged at this lower gas price?

Bob Simpson

I'm glad you asked that question. One of the things that I wanted to touch on was our philosophy about drilling for the next 12 months. One of the things that’s happened is the bolt-ons came harder and faster than you might have anticipated. So, what I've told our people is to take advantage of that by relaxing your activity a little bit.

In other words, let's look at next year's activity for the moment, and we can adjust later if we need to, as being roughly the same as this year. And so, with the Dominion acquisition, you would have expected perhaps, a 10% growth in rig count. I told our people to pullback enough activity, in general, so that we took on Dominion with roughly a flat rig count of around 80 or thereabouts instead of, say, high 80’s.

So with that, you get a number of things. One is you get everybody to take a breath here. This company has been growing at a frenetic pace, we've been managing it. But I've looked for opportunities to take a deep breath for our people and I've always done that.

So our growth of next year of 17%, yes, we could have a higher number. And it would be a good economics. I'm not going to say that we're paring uneconomic activity. But what I'm saying is that 17% as targets enough for a company doing 2 Bs a day, and to push it further wouldn't make any sense to me. Now, some people could argue with me, but that doesn't make any sense to me.

So we will probably make that better as we go forward into next year, as we always have. I mean that's a terrific rate of growth. So what we've said is -- and I gave that instruction to Keith and gave him all the freedom to decide what in the world he wanted to do within that discipline. And so, I'm sure that he cut the activity with the lesser rates of return. But I bet they were very attractive rates of return still.

So I'll let him talk about how he decided to manage that activity.

Keith Hutton

If you look at Barnett in particular, we went from 24 rigs last quarter to 20 this quarter. One of the things that's really happened to us is we started the year off drilling wells at 25, 26 days. The last round of wells is 20 or sub 20 days per well. And so, in effect, we're drilling more wells than we needed to for this year.

Obviously, we're moving as much infrastructure build-out as we can forward. But at some point, you'll get yourself in a trap and there's no need to drill that many more wells. So we basically have shifted rigs. You'll note, we took some out of the non-core and took them into the core. The reason for doing that is we've got some leases in the core we need to drill to hold them. We've drilled most of the leases in the non-core that we needed to hold.

So it's not necessarily tied to economic rate of return in non-core.

Tom Gardener - Simmons & Company

I see. Well, just along the same theme then, with regard to kind of shifting activity. And you mentioned increasing oil production in some plays, are you shifting your focus to liquids rich, oil rich plays with the weaker gas price?

Keith Hutton

Not really. Most of these plays that we're in are 1,000 Btu or better. Obviously, the economics of non-core is pretty good in the Tier 1 area just because of the liquids breakout. Same thing in the Woodford, there's quite a bit of liquid in some of the Woodford.

We're drilling about as many oil wells in West Texas as we'd like to. We had the same problem in those West Texas fields as we do in many others. We've increased production so much since we bought them in '04 and '05 that we actually have infrastructure build-out problems we need to build. You have to drill at a pace that stays up with what you're building out.

Tom Gardener - Simmons & Company

Thanks, Keith. One just last question with regard to the balancing forces of natural gas, the weak natural gas price relative to oil on the demand side. You mentioned a couple of supply base corrective forces, Bob. Do you have anything on the demand side that you see that might bring that back into parity overtime?

Bob Simpson

I think the demand side will continue to be driven by weather more than it used to be, than it was early in my career, because electricity and residential has been so important and replacing industrial demand that was lost or exported. But, I really think that overtime, we'll be challenged to meet demand just given the current scenario in the world. And we don't have to create new markets. I know there's been some talk of that. We're really not setting on a big glut of gas as some people have implied in the last few months. It's momentarily.

We have almost full storage remembering that storage is 15% of demand. And so, whether an extra 200 Bs or 300 Bs is 1% of demand, and so, that's not a glut. It's just at the moment, it's in storage. What I say about storage, it's something you fill for winter. And so, it's going to end up being what kind of demand we have as we go forward. Some people worry about a climate change. But as you have maybe warmer winters, you may have hotter summers over time that offsets.

So, I think natural gas is the premium fuel. It's clean burning, politically going forward as this environment gets a little bit more hostile. If that happens, we have the "Made in America" label which is on our side. And it's real. We tend to supply ourselves. We're not much of an import mechanism. LNG is nothing compared to what we burn. So I think it's going to be a politically advantaged industry as well as an environmentally advantaged industry.

And so I think we're in good shape for the future given the natural forces that I see.

Tom Gardener - Simmons & Company

Thank you, guys, for taking my question.

Operator

Your next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good afternoon.

Keith Hutton

Hi, Brian.

Brian Singer - Goldman Sachs

Hi, Keith. A couple of questions, first on the deep horizontal Freestone well, what do you expect that to cost and what would be the minimum rate and EUR you'd like to see to meet your hurdle?

Keith Hutton

If you look at the first couple we drilled, they probably cost us $8 million to $9 million to drill them. I would hope that we could get that $7.5 million to $8 million, say. We'll have to run a little bit bigger pipe than we ran the first ones to be able to frac them. That was part of our problems to be able to frac them.

What I would tell you is a vertical in the particular area we're drilling them comes in at around 4 million a day. Horizontals usually are 4X that number is kind of a good way to look at star rates, so your 12 million to 16 million a day, something like that. Reserve-wise, horizontals are usually 2.5 times a vertical. Those wells are about 4 Bcf verticals. So you're looking at 10 to 15 Bs for reserve as well. It’s very good economics.

Brian Singer - Goldman Sachs

Great. And what would be the timing of accelerating that? What do you need to see to accelerate the drilling of the deeper horizontals?

Keith Hutton

Probably just figure out, it's very hot, it's hard on the tools, it’s 370 degrees down holes. So it makes very tough to work with current tools in the industry. As long as we get these next three -- we're currently drilling one, seems to be fine. The drilling side is okay. It's really the completion side that's the test.

So if we get these three drilled wells down by the end of the year and figure out how we can get bridge plugs in, how we can frac them without destroying tools and so forth, I think we should know sometime midyear next year or so when we can start accelerating our program.

Brian Singer - Goldman Sachs

In South Texas you highlighted a couple of the good wells that you saw there. It's not an area that's always associated with repetitiveness, how do you think about the potential to add low risk inventory there?

Keith Hutton

I think the problem with South Texas is it's a lot like Arkoma from the standpoint of it's faulted, it's heavily faulted. You need the seismic that we bought in this library, and Louis was talking about to be able to see the compartmentalization. Every well that you drill basically sets you up for another well. Some of the sands will be drained, other ones won't be. It has a lot of those types of repetitive nature. It's just hard to say.

If you look at Arkoma when we first bought it back in 1999, I think we thought there were 200 wells we could drill. I think we drilled 400 already and we can see another 250 or 300 going forward. And again, that's just because the nature of the beast. Every well you drill you find a new one in the sand. You find the one that's not drained you thought was drained.

That's what happened here. We've drilled in a couple of fault blocks where we thought they might be drained and they're not. And so, that opens up more drilling for us, tells us there's a fault there we didn't know about, adds a lot of low risk locations for the future.

Brian Singer - Goldman Sachs

I have one last question, quick one, probably for Bob or for Louis. You're going through this major midstream build out here in the Barnett, any thoughts on potentially monetizing that once you're currently through with that (inaudible) asset sale?

Bob Simpson

We'll look at on the midstream situation. I think right now our consensus opinion here is, one, it's too capital intensive and not enough, what you call, free cash flow, to monetize. But we'll continue to monitor it, and then someday may get in that position. But right now, it's an intensive build-out category, so it's a little early. But it's going to be certainly one of the better situations in the industry as we get it built out.

Brian Singer - Goldman Sachs

Great. Thanks, guys.

Operator

Your next question comes for the line of David Tameron with Wachovia.

David Tameron - Wachovia

Hi. Good afternoon. Congratulations on another good quarter.

Bob Simpson

Thank you.

Keith Hutton

Thanks, Dave.

David Tameron - Wachovia

I have a couple of questions. You started to talk about the MLP right there. Have you updated your plans or thoughts on E&P MLP, and can you give us any color there as to if anything is changed versus what you saw six months ago?

Bob Simpson

We really continued to study it. We were not ready for a conclusive announcement yet, but we'll update probably a full update of that in February at our Analyst Meeting.

David Tameron - Wachovia

Alright, fair enough. The Marcellus Shale, I mean, obviously you guys have Barnett, Woodford, Fayetteville. Obviously it's a basin you've looked at, do you have any plans there going forward? And if so, would it be primarily through lease sales through an existing player in the basin. Can you talk at all about that?

Keith Hutton

Talk about…

David Tameron - Wachovia

Just about the Devonian shale in general, kind of Pennsylvania, West Virginia, Appalachia, that whole region.

Keith Hutton

We're not big Appalachia players. That doesn't mean we wouldn't get in there at some point. We are watching the activity with curiosity. We don't have operating region up there, makes it a little bit of a stretch for us. Actually, we have so much upside in what we have today, that would be a bolt-on add-on for something we'd need four or five years down the line. Doesn't mean we're not watching up.

David Tameron - Wachovia

Okay, yes. I'm aware you don't have anything up there right now. But you don't have any immediate plans to jump in, the Appalachia, jump into the fray with all the players running up there right now?

Keith Hutton

No. I say that and we'll announce something in three months. We are watching it close.

David Tameron - Wachovia

Okay and then final question. Piceance, I think you said in the ops update, still planning for two rigs running in 2008. Did I read that right or remember that correctly and kind of what are your '08 plans in the Piceance?

Keith Hutton

We're still playing around. We'd like to get a fit for purpose rig up there. The current two rigs we have are not set up for that. We're going to have five pads built where we can build 12 to 16 wells per pad. It would be better off if we had a rig that moved better than the ones we currently have. You may see us drop one and pick one up later, something later in the year. So probably one rig early, and then maybe pick up a second rig as we go along.

David Tameron - Wachovia

Alright, fair enough. Thanks.

Keith Hutton

Yes.

Operator

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

Joe Allman - JP Morgan

Thank you. Hi, everybody.

Keith Hutton

Hi, Joe.

Joe Allman - JP Morgan

Louis, could you give us that CapEx breakdown you gave to us earlier? I missed some of that.

Louis Baldwin

Sure. Development cost $727 million for the quarter. That takes us to $1.947 billion for the nine months, puts us right on that $2.6 billion path. Proved, unproved property acquisitions, $230 million. That takes us to $324 million for the nine months. Proved property acquisitions, $2.558 billion for the third quarter, takes us to $2.932 billion for nine months. And gas gathering, processing, and other asset additions, this is a category that didn't step-up, $235 million. That takes us to just over $506 million for the nine months.

Joe Allman - JP Morgan

Okay. That's helpful. And then, Keith, one for you, it looks like the Barnett Shale core area, those wells, seem to be getting better and better. Can you just comment on that?

Keith Hutton

Yes, it's interesting because as you get a little -- a lot of it South Tarrant, it's the South Tarrant/Northeast Johnson area. Some areas that originally, the wells were just okay in, I think we're figuring out where to land them, how to frac them. I think the industry, in general, has been surprised at how good those wells are. It's a combination of everything.

Joe Allman - JP Morgan

Got you, okay. And then, also on the Woodford Shale, you said you're pleasantly surprised. I mean, what were your expectations?

Keith Hutton

Well, we had some expectations they would be 3 Bcf type wells. But I think the thing that's been surprising is the four or five wells we've drilled are spread out over a pretty good area. They're each - one is two or three miles apart in our acreage position. It looks like it's fairly repetitive over a large area.

Joe Allman - JP Morgan

Got you, okay. Is it your theory that the Woodford is pretty consistent throughout the play or…

Keith Hutton

Yeah. I mean, at least, where our acreage is at the moment. Yeah.

Joe Allman - JP Morgan

Got you, okay. That’s very helpful. Thank you.

Keith Hutton

You bet.

Operator

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

David Heikkinen - Tudor Pickering

Hi, guys.

Keith Hutton

Hi, Dave.

David Heikkinen - Tudor Pickering

Just picking through questions, the pipeline capacity that you're going to have installed in the Fayetteville shale?

Keith Hutton

Yeah. Right now, we're working on it. We're deciding whether we gather it ourselves and deliver it into SECO or Centerpoint or Boardwalk, whoever, whether we sign a deal with those guys. We're working on what's the best option for that.

David Heikkinen - Tudor Pickering

So, no numbers?

Keith Hutton

No numbers.

David Heikkinen - Tudor Pickering

And what depth was the Fayetteville there?

Keith Hutton

It ranges from 4,000 feet to 1,500 feet. Most of these wells are 2,500 feet or so.

David Heikkinen - Tudor Pickering

Okay. So no really shallow drilling and problems getting horizontal then you'd expect on your acreage?

Keith Hutton

No, not yet.

David Heikkinen - Tudor Pickering

And going into the Piceance, the fit for purpose rig, I mean, availability of those rigs in the Rockies seems like they're available. Any reason why you wouldn't be able to get one sooner than later in '08? Is it just gathering capacity and waiting on Rockies gas prices to improve or is it rig availability?

Keith Hutton

It's a little bit of both. There are a lot of rigs. There are not a lot of good crews.

David Heikkinen - Tudor Pickering

Okay.

Keith Hutton

One of the traps you get into is you can get good iron, but the crews up there leave about every week if you're not careful. You almost have to build a little camp and keep them in one location and feed them. Our biggest problem is we have pretty good iron, but the crews have been tough. We're trying to get hold of a rig that's drilling up there and has a good crew, one we can trust and know we can go forward with the same guys. So that's been more the trap than the iron itself.

David Heikkinen - Tudor Pickering

And you've got to get past ski season so it's a little harder.

Keith Hutton

You're probably right.

David Heikkinen - Tudor Pickering

The final question, on the CapEx, the big uptick in the third quarter and kind of build-out expected, would you think that $235 million run rate should continue or what would be reasonable, Louis?

Louis Baldwin

I know. I don't think it will continue at that rate. As Keith said, we're really accelerating some of the '08. There's probably going to be closer to $500 million number for the year.

David Heikkinen - Tudor Pickering

Okay.

Louis Baldwin

We're gathering portion of that.

David Heikkinen - Tudor Pickering

Okay. Thanks a lot guys.

Operator

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

Scott Hanold - RBC Capital Market

Good afternoon. I have just another follow-up on the Barnett Shale. Can you kind of remind me, just kind of walk through '08 as far as takeaway capacity? Is there going to be at any point in time, a constraint on the system until you get the big install by year end '08?

Keith Hutton

I don't think so. We're trying to build out in front of that. That's where this excess capital is coming. So we don't see any traps. Obviously, everybody needs to get their build-out to us and some of the major pipelines in time. But so far, we've been able to do that. So I don't really see any problem with what we expect to build next year and what our volume takeaway is.

Scott Hanold - RBC Capital Market

Okay. And how about on the liquids side of things, what is sort of the capacity expected by the end of '08 for NGLs for you all?

Keith Hutton

We haven't given guidance on that. Obviously, it will be going up if you're in the Tier 1, Sand 1, and over in our Cotton Valley, but we haven't come out with that.

Scott Hanold - RBC Capital Market

Okay. One last question on the Fayetteville, did you give a data? If you did, I missed it. Potentially, when you could have a pipeline in the Fayetteville?

Keith Hutton

Well, I know David was talking about that. We're looking at our options. We can hook into currently, into either Southwestern (inaudible) 64.50, gathering or in the Centerpoint. There are a number of options we have. Currently we're trying to decide if it's better for them to build it out or for us to build it out. What I think you'll see is through the first six or seven wells, the test wells, find out how good they are, and then we'll decide which way we're going.

Scott Hanold - RBC Capital Market

Okay. And would that occur during this quarter?

Keith Hutton

Yeah. Probably early next year.

Scott Hanold - RBC Capital Market

Okay. Thank you.

Keith Hutton

You bet.

Operator

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

John Herrlin - Merrill Lynch

Yeah, I have quick ones. You spent about $235 million on gathering. Maybe I misunderstood what you said to an earlier question, Louis. You said you spent about $500 million year-to-date, but you are fairly advancing the infrastructure more than you had originally planned because of good well results. What kind of a normalized run rate are you looking for gathering and processing?

Keith Hutton

John, it's tough because we've plants in there in big compressor stations. I'd say you're running, if you're looking at '08, somewhere between 400 million and 500 million for the year, something like that. You still have big build-out in several other areas going forward. This time, you had a number of plants coming on and big compressor stations coming on all at one time.

John Herrlin

Okay. That's fine.

Louis Baldwin

And John, we may be confusing you. The category that I gave you had some other asset editions, plant building here in Fort Worth, some things like that. So that's a little confusing, I think the 400 to 500 run rate Keith is talking about is gathering and processing assets.

John Herrlin

Okay. That's fine. Louis, with the 200 plus million you made in property acquisitions in the third quarter, were there any production volumes associated with that?

Louis Baldwin

Again, those were unproved property acquisitions

John Herrlin - Merrill Lynch

Unproved?

Louis Baldwin

Right. $230 million. And the proved would be 2.558.

John Herrlin - Merrill Lynch

Okay, got it. That's fine. Piceance, you said you want a fit for purpose rig, Keith. What have your completed well costs been running and what kind of improvement would you get with a fit for purpose rig?

Keith Hutton

Completing costs are running more than $10 million, I can tell you that. A lot of that is because you've got big road build-outs and big pipelines you've got to land in each one of these pads. We're hoping that if we get a fit for purpose rig in there and you can speed it up much like you've seen them do in Pinedale and some other areas, you might be able to get your drilling time down to 60 days or something, and hopefully get your wells down to that $8 million to $9 million category. And then, if you've got 4 Bcf wells, you start to get into pretty good economics territory.

John Herrlin - Merrill Lynch

Got it. Last two for me, how many wells did you tie into the Barnett and also the Eastern region this quarter, approximately?

Keith Hutton

I think Eastern region was about 40, Barnett was around 70.

John Herrlin - Merrill Lynch

Thank you.

Keith Hutton

You bet.

Operator

The next question on line comes from Jeff Hayden with Pritchard. Please proceed.

Jeff Hayden - Pritchard

Hi, guys. I have a couple of quick questions. First in the Woodford Shale, just quick update, some of those wells you guys have been drilling, what's kind of the average depth for the Woodford where you are and could you talk a little bit about the completion techniques you're using, number of frac stages, lateral, etc? And then, jumping over to Barnett real fast, can you give us any color on your current thought regarding optimal spacing?

Keith Hutton

Woodford first, they're 2500, 3,000 foot laterals, they're 8,000 to 10,000 feet, verticals.

Jeff Hayden - Pritchard

Okay and how many frac stages?

Keith Hutton

They're about 500 foot. They're five stages of wells, something like that.

Barnett, optimal spacing, good question. Obviously 80’s are fine, 40’s look pretty good. Everybody is testing 20’s. Somebody has mentioned 10’s. What I'd tell you is we have so much acreage we're going to have a hard time drilling in on 40’s and 20’s. But I hope 10’s is correct. Gas in place says there's a chance you can do that. Right now, I'd tell you 40’s for sure in the core, probably 20’s and we'll need some time for 10’s.

Jeff Hayden - Pritchard

Okay. And they any thought or any additional color on kind of the EUR impact when you go to 40’s from 80’s to 20’s from 40’s, etc?

Keith Hutton

We still say that there's -- in a test that we've seen 80’s to 40’s. It's anywhere from 75% to 80%. Obviously, you need more time than what everybody has seen to be honest. There are some areas where the 40’s are as good as the 80’s. The question then will be if you go to 20’s, what do you see there? The one 20’s pilot we have, all the wells look fairly similar. But again, it's very early. Let's hope 40’s and 80’s are the same and so are 20’s. But everybody needs more time to figure that out.

Jeff Hayden - Pritchard

Alright, thanks a lot guys. I appreciate it.

Keith Hutton

You bet.

Operator

Your next question comes from Benjamin Dell from Bernstein. Please proceed.

Benjamin Dell - Bernstein

Hi, guys. It's obviously Bernstein. I guess my question was really around the recs. I was wondering if you had any thoughts on what the opening of recs would do to differentials in the Mid-Continent and Texas, and whether you though that would impact them? And if so, what sort of plans do you put in place in terms of hedges to address that?

Bob Simpson

Yes. We've hedged some Rocky Mountain gas basis next year for $1.39. The question is will it be transferred over to the Midwest I think is what Ben is asking. So what we have hedged philosophically, as we do our hedges we do basis across the company. And so, we'll have a basket of hedges otherwise that will sort of automatically contemplate some transfer.

So I can't tell you that we think it's going to be linear into the Mid-Continent. What would you say we've done?

Keith Hutton

Basis?

Bob Simpson

Yeah.

Keith Hutton

Probably 60%. We look for the right opportunities. Since we just put on quite a few of those, we're doing that.

Bob Simpson

We're still adding the basis for the Bcf, but we will get there shortly. And so, we'll consider the impact of recs on the Mid-Continent as we do those.

Benjamin Dell - Bernstein

Okay and just one last follow-up question. On the Dominion assets, do you have a feel for what sort of cost reductions you could see from their assets? Obviously, they were significantly higher cost than yours when they came in, but I'm guessing you see material performance improvement?

Keith Hutton

Ben, they weren't significantly higher op costs. They were about the same. They are mainly flowing gas wells. So there's not a lot of optimization from that standpoint, $0.80 to $0.90 an M, just like our base is in the 90’s or something.

Benjamin Dell - Bernstein

Alright. Great.

Louis Baldwin

I think where you're going to see the difference is capital allocation. And we felt like they were putting money from profitable areas into exploration into other areas and not getting good returns. And so the areas that we bought really were the ones that we felt like we could grow with a portion of cash funds. So the benefit is going to be increasing production, working on costs that way versus lowering costs.

Benjamin Dell - Bernstein

Okay, great. Thank you.

Operator

Your next question comes from Stephen Beck with Jefferies & Company. Please proceed