EOG Resources Inc (EOG) 2007 Q1 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources first-quarter 2007 earnings release conference call. As a reminder, this call is being recorded. At this time, I'd like to turn the conference over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing first-quarter 2007 earnings and operational results.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call.

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to the comparable GAAP measure can be found on our Website.

The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates on this conference call and webcast, including those for the Barnett Shale play, may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears to the bottom of the investor relations page of our Website.

With me this morning are Loren Leiker, Senior EVP, Exploration; Ed Segner, Senior EVP and Chief of Staff; Gary Thomas, Senior EVP, Operations; and Maire Baldwin, Vice President, Investor Relations.

We filed an 8-K with second-quarter and full-year 2007 guidance yesterday. You will note from the 8-K that there is no change to either our full-year 10% 2007 organic production growth expectation or to our mix, that indicates 18% organic North American gas growth and 16% total North American growth. As always, our game plan remains the same, with the standard hallmarks of high returns, strong growth and low debt.

I will now review our first-quarter net income available to common and discretionary cash flow, and then I will discuss our perception of the macro natural gas market and the impact on our CapEx plans. I will follow that with an operational review; Ed will then discuss capital structure; and I will close with a summary.

As outlined in our press release, for the first quarter, EOG reported net income available to common of $217 million, or $0.88 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common [to eliminate] mark-to-market impacts outlined in the press release, EOG's first-quarter adjusted net income available to common was $273 million, or $1.11 per share.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $732 million, or $2.97 per share, versus $712 million, or $2.89 per share, a year ago.

Before I discuss EOG's operations, let me share my thoughts regarding the North American gas macro and how it interacts with our CapEx plan. We continue to believe that concerns regarding domestic gas supply growth are overstated. We predict domestic supply will grow only 1.4% this year. And even recent EIA-914 data, which we believe has been historically optimistic regarding supply growth, is showing a relatively flat supply pattern over the past nine months.

In Canada, we expect production to fall 2.5% this year. The bottom line is we expect full-year 2007 prices to average $8 to $8.50 Henry Hub. And the current NYMEX is indicating $7.90, so we are within striking distance and we expect further strengthening as the year progresses.

With this price expectation, we intend to execute on our original $3.4 billion CapEx budget. We began 2007 with an 8% net debt to total cap ratio. Using prices of a $8 Henry Hub and $66 oil, 10% total Company production growth and our $3.4 billion CapEx plan, we would end '07 with a very strong balance sheet of about 11% net debt. This is well within a very conservative leverage range.

I will now address some of our operational highlights. In the first quarter, we generated 8.5% organic year-over-year production growth, highlighted by 21% organic gas growth in the U.S., very strong Barnett growth and 5.2% North America X Barnett's growth versus the first quarter of last year. I will commence our operational review with the Fort Worth Barnett, then briefly discuss our other shale plays. I will then review our traditional North America ex Barnett activities, and I will conclude discussing Trinidad and the North Sea.

To succinctly summarize the Fort Worth Barnett, all areas are working as well or better than our original prognoses, and we had no unusual or unplanned first-quarter production curtailments in this area. We are currently running 22 rigs -- 14 in Johnson County, two in Hill, and six in the western counties of Hood, Parker, Erath, Palo Pinto and Jack. Of these drilling rigs, we currently have five automated rigs, with another seven scheduled for delivery by year-end 2007 and another three scheduled to arrive in 2008.

As we've previously noted, we are not going to disclose quarterly Barnett production results, except to say that we are on target with our projections. We will, however, disclose whether we achieve our full-year target, which is an average of 280 million cubic feet a day compared to last year's average of 145 million cubic feet a day. We plan to drill about 400 wells this year, and will have approximately 320 of these completed and hooked up to sales by year end.

As an overall statement, I'd say that Barnett continues to overachieve regarding our internal expectations, and we have met or exceeded every promise we have made to the investment community regarding this asset.

The key takeaways at this time are, first, in Johnson County, we're continuing to achieve very consistent well results, with a steady frequency of monster wells in the mix. The Fowler #1H well, highlighted in our press release, commenced production at a 16 million cubic feet a day rate, and is not only EOG's best Barnett well, but we think it may be the single best well in the entire Fort Worth Barnett field. This is partially the result of good quality rock and partially attributable to continued improvements in our well completion technology.

I don't want to focus too much attention on a single well or group of wells because the overall trend is more meaningful, and the trend we are seeing in Johnson County is very positive. I suspect that we will ultimately recover more reserves from Johnson County than the 1.92 to 2.5 net Tcf we are currently indicating, primarily because of technical improvements in our well completions.

Second, in the western counties of Jack, Parker, Erath and Hood, we have made measurable progress this quarter and are starting to build momentum. The pipeline in Palo Pinto County is expected in September, so we don't have anything new from that county. The press release lists multiple successful wells in the western counties, and our confidence continues to increase regarding the repeatability of both reserves and completed well costs. We're able to drill these development wells out west with the new automated single rigs in about nine days, and that is giving us completed well costs on a program basis of about $1.4 million, as predicted.

I think a comparison to two other high-profile shale plays is warranted here. Using the lower end of our 0.8 to 1.0 Bcf net reserve range and the $1.4 million completed well cost, we would achieve a $1.75 direct net finding cost in the Western Barnett. This compares to a $2.40 direct net finding cost reported in the Oklahoma Woodford Shale and a $2 per Mcf direct net finding cost that's been reported in the Fayetteville shale. I'm providing these numbers because there may be a perception in the investment community that the Woodford and Fayetteville shale plays are economically better than the Western Barnett, and we don't think that is the case for EOG.

The third and last point I will make regarding the Barnett involves the southern extension, which is primarily Hill County. Last month, we connected the Radke #1H to sales. This was our first well drilled in Hill and the first Hill County well where we've gained enough production history now to make a reserve estimate. After six weeks on line, the Radke reserves appear to be 1.8 Bcf net, which is towards the upper end of our expected range. We currently have four wells on line in Hill County through a temporary pipeline. We anticipate having a permanent pipeline in May, so that is just in a few weeks.

During our last call, I mentioned that we're working on other possible North American horizontal shale plays, but I wouldn't provide any interim updates regarding these. I will simply reinforce that comment today to let you know that this remains a high priority within the Company and that we will likely provide these results within a seven- to ten-month timeframe.

Now, I will switch to the North America ex Barnett portion of our portfolio, which we grew organically 5.2% year-over-year in the first quarter. Our full-year growth goal was 6%, so we're roughly on target and able to grow our large North American asset base organically at a decent rate, even after subtracting our biggest growth assets. I won't try to cover every piece of our ex Barnett portfolio here; I will hit only some of the salient points.

You will recall that last year we encountered two downstream obstacles to growth -- offshore hurricane infrastructure use and delays in the East Texas Branton Field gas processing plant. The offshore infrastructure issue has been resolved, and the Branton Field gas processing issue has been partially resolved, and we expect it to be totally resolved later in the year. Although resolution of these infrastructure issues was slower than we projected, we still expect to achieve our overall 6% full-year targeted production growth goal for the ex Barnett assets.

Our press release also highlighted two South Texas Lobo vertical wells. We're particularly excited about the Barrocito #6 well, which may set up about 20 offset drilling locations. Our South Texas horizontal Wilcox program is also continuing to yield good results for us.

In our Rocky Mountain operating area, our Uinta Basin program continues to be our most predictable and repeatable program. And in North Dakota, we've increased from one to three rigs in our Bakken horizontal oil play.

Now I will turn to Trinidad and the North Sea. As we previously advised, Trinidad's quarterly and full-year production is expected to lag last year's levels, since we will likely be ratcheted back to contract sales levels this year as compared to contract overdeliveries last year. Additionally, we expect to have our Block 4A gas contract finalized in the third quarter, and we have commenced platform design for this project. Sales under this project will boost overall Trinidad production in late 2009, early 2010 by approximately 60 million a day net.

In the North Sea, we plan to participate in the drilling of two gross exploratory appraisal wells this year. We will have a 25% interest in a follow-up to our fourth-quarter gas condensate discovery in Central North Sea Block 2316F, and also a 40% working interest in a Southern Basic gas exploration test.

I will now turn it over to Ed Segner to review CapEx and capital structure.

Thanks, Mark. For the first quarter, total exploration and development expenditures including asset retirement obligations were $902 million -- 902, with less than $1 million of acquisitions. Capitalized interest for the quarter was $6.3 million. With respect to capital structure, at March 31, total debt outstanding was $820 million and the debt to total capitalization ratio was 12%, essentially flat with year-end 2006.

At quarter end, we had $142 million of cash on the balance sheet, mostly international. Earlier this month, Standard & Poor's rating services upgraded EOG to A- based on our consistent operating results, highly competitive cost structure, low debt leverage and conservative financial policies. We are one of the few E&P companies to hold this high rating. Our Moody's rating is A3.

The effective tax rate for the quarter was 35% and the deferred tax ratio was 82%. As you are aware, the form 10-Q for the first quarter was filed yesterday. A Form 8-K with second-quarter and updated full-year 2007 guidance was also filed yesterday. For the full-year 2007, the guidance 8-K has an effective tax range of 33% to 37% and a deferral percentage of 65% to 85%.

Now I will turn it back to Mark.

Now let me summarize. In my opinion, there are five important points to take away from this call. First, as always, the game plan remains consistent, with a focus on peer-leading returns, low net debt and high organic volume growth. Second, we've become sufficiently comfortable with the 2007 overall North American natural gas supply/demand balance to implement our $3.4 billion original CapEx budget, which will achieve our targeted 10% organic volume growth. We will end the year with our usual conservative balance sheet.

Third, the Barnett asset continues to overachieve and provides us with a large multiyear, high reinvestment rate of return asset. I'm particularly pleased regarding the well completion technical improvements we've recently made and the likely impact to the overall asset size.

Fourth, the North America ex Barnett portfolio is on track to deliver its projected 6% year-on-year growth. And fifth, EOG continues to be a leader among the peers in controlling unit costs. Thanks for listening and I'll now turn it over to Q&A.

Thank you. (OPERATOR INSTRUCTIONS) Brian Singer with Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

Not to focus on that one well, but I will. Could you be more specific on the applicability of the geologic characteristics of the Fowler #1H, and any tweaks to your completion process and how that would apply to other Barnett -- other parts of the Barnett acreage?

Yes. The Fowler well is located in kind of eastern or central eastern Johnson County -- and out of our monster wells -- and we kind of define our monster wells, Brian, as a well having an initial production rate of anywhere over about 7 million a day. Out of our monster wells, about two-thirds or three-quarters of our monster wells end up in central or eastern Johnson County, and the remainder are in western Johnson County.

But what we are seeing is that with some enhancements to our completion technology, our monster wells are getting better, i.e. higher rates, than, say, a year ago. And so I believe that if you project over the next year or two, it is possible that we may have some wells that end up even better than the Fowler well.

And if you track our technology improvements over the last year, I won't go into specifically what we are doing, but I would say the most marked improvements that we have made in the Barnett Shale over the last year have been in how we complete wells. And we have seen this both in the western counties and in the eastern counties. And what that is going to translate to is basically more reserves recovered, we believe, than perhaps we had ultimately predicted. And it's certainly going to end up with better wells, in some instances, or it's going to allow us to drill more of our acreage than we had thought.

So though we have seen -- if you just stand back from the asset, we have seen, on a 12-month basis, a marked improvement on what we are doing on the well completion site. Now there is a cost to that in that our well cost in some cases has gone up a bit for the well completion portion of it. So it's a case of the wells are costing a bit more in some cases, but the incremental reserves we are getting for that we think is worth it.

And if we look at the Western Barnett extension, 0.82 to 1 Bcf or $1.4 million, I guess how much upside would you see, based on some of the recent drilling that you have done, to both of those numbers?

Yes. I would say we would still hold to that reserve range out there, the 0.8 to 1, for the $1.4 million well cost, but I think what you are seeing out in the west is a contrast between what EOG is achieving and perhaps most other operators out there. I think there's a differentiation.

I think if you look at what other operators are reporting out there, you are going to find generally reporting less than consistently successful results; whereas EOG is reporting consistently successful results. And that is the differentiation, is how we are completing wells versus others.

Great. And lastly, any update on the Western Canada winter drilling exploration program?

We are not providing any update at this time on that, Brian.

Could you say whether you were able to drill the wells that you expected, without speaking to the results?

We are just not providing any update at all, other than we did conduct some activity up there this winter. But no specifics.

Great, thank you.

Tom Gardner with Simmons & Company.

Hi, guys.

Tom.

Mark, given your success in the Barnett, can you discuss which basins and horizons elsewhere might hold the greatest potential for horizontal drilling for EOG?

Succinct answer to your question is no, Tom. I will just say that we believe -- you know, I've mentioned on this call, of course, we have the Barnett. There are other successful plays such as the Woodford in Oklahoma, the Fayetteville in Arkansas. We believe that those are not the only successful plays that will be unlocked with horizontal drilling.

And we have as a very high priority within the Company to locate and capture acreage positions on other plays. And we are working very hard on that. But rather than give interim reports, I think it is best that we just are not going to give any reports. But in a seven- to ten-month timeframe, we believe we will be able to give a relatively definitive report on that. But we don't want to really say where they are, where we looking, other than say it is just in onshore North America.

So I shouldn't ask you about the West Texas Barnett then?

We won't answer.

Okay. You mentioned these major technical advances in the area of horizontal drilling. Can you elaborate on that and perhaps discuss the implications for service costs and perhaps changes to demand in particular services?

Just as a general trend, I would say that it is our strong belief that there are going to be a lot of resource plays in the future in onshore North America that will be unlocked with horizontal drilling, and that we are in just the early days of that, and that we are still on the front end of the learning curve in the Barnett Shale as to how to unlock this asset.

I think anyone who's got the position in the Barnett Shale has made mention of the fact that if you look at the gas in place under the Barnett Shale acreage, what we are recovering right now is a very small percentage of the gas in place. I believe that EOG is ultimately going to recover a significantly larger percentage than we are currently indicating through improved technology.

And we've made some pretty good headway just really in the last six months at some items there. And we believe we are maybe on the front end of the industry at figuring out some of that technology and don't want to talk too much about it. But we are seeing clear trends as to how we can improve recovery in the Barnett Shale. So this is a big thrust of the Company across the board, not only in the Barnett Shale but in other horizontal plays.

So the good fields continue to get better?

Yes.

And just one last question, on the 914 data. What do you think we need in the way of gas-directed drill rig count in order to maintain overall domestic production? About where we are today or north of that?

Yes, my sense is that, I guess, if one just absolutely believes the 914 data -- and I'm not necessarily in that camp -- but if you just took that data verbatim, what it is indicating is that production is essentially flat for the last nine months or so. And then if you would project that into 2008, it would say that our year-over-year production growth, 2008 versus 2007, is likely to be roughly just zero.

So it would say if we kept on the current pace3 of rig activity, rig count, we're going to have zero production growth 2008 versus 2007. So, to grow production even 1% or 2% in 2008, we will need a higher rig count than the current rig count we've had for the last six months, would be my -- that is what the data is telling me.

Thanks, Mark. Solid quarter.

Thank you, Tom.

Gil Yang with Citigroup.

Good morning, Mark.

Gil.

Could you just -- for two macros, Mark, that you made comments on, could you just give us your view on the UK gas price going forward? And secondly, you made a comment about Canadian production. Could you comment on how that translates to export to the U.S.?

Yes, on the second question you asked there, our view for full-year on Canadian production and translating to exports is that, on a full-year basis, we are estimating that exports to the U.S. are going to average about 7/10 of a Bcf a day lower this year than last year, from about 8.8 to 8.1 Bcf a day. And that is made up of about a half a Bcf a day less production and about 2/10 of Bcf a day of an increase of intra-Alberta demand.

Okay.

First question again was what, Gil?

What do you see happening in the UK gas market over the next three to five years?

A gas market? We are not particularly sanguine about the UK gas market for the next several years. We think gas, I guess, would be perhaps $5, $6 gas prices over the next couple of years. We think it is probably going to be relatively long on supply between LNG and imports from Norway.

And so we will be ratcheting back our activity as far as gas-directed drilling in the UK. And in fact, if you note on our conference call, we will be drilling really about less than one net well in the UK this year. So don't look for us over the next year or two to have a heavy focus of activity as far as UK directed gas drillings.

Okay. And last question just regards shales. Can you just give us some idea of how much you are spending on these new shales that you are not willing to talk about?

Oh, yes. I'd probably rather not because at this stage -- like I say, I'd probably rather not at this stage, Gil. Like I say, we will kind of have a lot more information in this seven- to ten-month timeframe. But our strategy is to test various ones and then the success ones to accrete acreage. And let's just leave it at that right now.

Okay. All right, thanks.

Ben Dell with Sanford Bernstein.

Hi, Mark. I just had a couple of questions. One was on LNG. You just mentioned, obviously, UK gas prices you expect to stay low. What is your sort of assumptions going forward on the LNG market coming into the U.S. and volumes? Obviously, pricing in the U.S. is better than European pricing right now.

Yes. For this year relative to last year, we are assuming that LNG imports go from last year about 1.6 Bcf a day, and they average this year about 2.3 Bcf a day. So it basically cancels out -- that is up about 0.7 Bcf a day, and that cancels out the drop in Canadian exports. So those two end up a wash for this year, Ben.

And on Canada, how much of that do you expect to actually impact you? I mean, we've heard people talk about Canada going down, but so far most of the people who have reported haven't shown any real signs of it. I was wondering, do you expect that to turn up in your numbers?

In terms of the production?

Yes.

We are projecting our Canadian production to be up -- oh, I believe the 8-K is indicating about 4% production growth -- 3% -- 3% to 4%. I'm not sure exact percentage, but somewhere in that range.

But if you look at just the total Canadian production numbers, I think year-to-date so far for the first four months, they are showing production in Canada to be off about 330 million cubic feet a day so far. And like I say, we are projecting for the full year -- that is for the first four months -- and for the full year, we are projecting an average of about 500 million a day. So I think the numbers year-to-date are tracking pretty close to what our expectations are.

Okay. And just lastly, you seem to have made a slight shift between -- previously, you said you really weren't willing to take on any debt. Obviously, you are not talking a huge amount of debt and your balance sheet is party strong, but now you seem more willing to do that.

What gas price or what environment now would project to reconsider your CapEx plan, or is the fact that there is moderating service costs and drilling costs somewhat helping you out in that respect, so you think you'll get some relief there?

Yes, I guess two things have really helped us. On the previous earnings call, we had indicated that we were a bit nervous about the full-year gas price. And frankly, the cold weather in February kind of made us feel a lot more comfortable. And if we would not have had the cold February, frankly, we would have been tempted to make some downward adjustments in our CapEx. Because I think we would not be quite as positive about the gas price outlook for the year.

And then the second thing is that certainly the EIA-914 data, some of which just came out yesterday again, is certainly helping to reinforce our thinking that we are seeing a flattening in U.S. gas production that tells us that even though you've got pockets -- like the aggregate Barnett Shale production is growing very strongly in the state of Texas, production is growing very strongly -- but even with those pockets of production growth, there certainly appears to be a flattening in total U.S. production. Which kind of reinforces the thesis that we've had all along, that it's easy to point to the production growth areas, but if you are in the trenches like us and fighting those production declines every day, it's a different story. And that we believe that production in '08 is likely to be probably flat or up less than 1%, or perhaps even down relative to '07; and I think Canadian production will struggle to be anything but down again.

So we see a pretty -- a reasonably rosy picture in terms of what '08 could be versus '07 also. So taking our debt to cap up to -- net debt to cap up to 11% doesn't seem to be a very scary picture for us.

Okay, that was great. Thank you.

David Tameron with Wachovia.

Good morning. Mark, you mentioned briefly in the western counties kind of what you are doing versus what other operators are doing. Can you tell us exactly what that is as far as completion, how many fracs, kind of differences between completing a well there versus in the core?

Yes, I hate to be so evasive, David, but let me just as an overview here just say that we've taken different tack on what we are doing out there relative to some other companies. And if you compare results -- and I'm sure other companies will be reporting their results in Erath County and Hood County and others, and I would suspect that what you're going to hear from other companies are they are going to reporting very spotty results out west. They will be reporting some good wells and then some wells that are just pretty weak wells.

And our results have been what I would say is quite consistent. We've said all along that our wells are not nearly going to be as strong as Johnson County wells. The pay is thinner, it's shallower there, so there is less bottom hole pressure. So we are resigned to the fact that our wells are going to be 0.8 to 1.0 net Bcf per well. And so our goal has been we have to drive the cost down, the completed well costs down out there, so we can made a good return, generating those kinds of reserves.

And so we've made some radical changes in how we complete the wells, and I think right now it gives us an edge over the rest of the industry out west, in that they're -- and so I'm not going to disclose on the telephone what we are doing that gives us that edge. So I will just give you that vague answer and you will have to be satisfied with that, unfortunately.

Okay. And then the automated rigs, what is that doing to your drilling days? Like in Johnson County, what has been a change just from that, and kind of what are you looking at right now as far as spud completion on a well? Not necessarily hooking it up to sales, but just drilling and completing?

Yes. Let me have Gary Thomas address that.

We are just moving one of the super singles or automated rigs to Johnson County within the next couple of weeks. So we have just been operating with the more conventional type rigs; we have some newer rigs in there. And we've been able to reduce our days. We were pleased with one recent well that we just -- a couple recent wells -- we had drilled with Patterson. And they got them down in 12 days and a half day [for move] because we were able to skid. But normally these wells take somewhere around 15 days.

Now in the western area, where we are using the automated rigs, we are running anywhere from seven to 13 days. And the reason I'd say 13 is because we are operating in eight or nine counties. So when we move to a new area, it takes a little time to get our efficiencies in place and to understand the rocks. But when we are in consistent drilling, one particular area, it takes us about seven days.

All right.

And our drilling costs, yes, we are down to [$1.25] million dollars as far as (technical difficulty), and maybe up to [1.5], to average somewhere around 1.3 to $1.4 million, western counties.

Yes, that is completed well cost.

Yes.

Okay. Thank you. Thank you, Gary. Thank you, Mark.

Leo Mariani with RBC.

Good morning. I guess you folks announced that you had some -- sounds like some positive results in the Bakken play and decided to take that play from one to three rigs. Could you give us some more details on what you are seeing over there?

Yes. We believe we have an accumulation there -- we have about 130,000 acres, plus or minus, there. And we believe we have an accumulation somewhere between 40 and 70 million net acres. And the reason that -- I'm sorry net barrels, not acres. And the reason that we've been developing this relatively slowly with one rig up until recently is that we have waited until we've got -- had shot a 3-D seismic survey over the area and got the 3-D seismic interpreted.

So we have now got the 3-D seismic interpreted, and so now that we have that in hand, we've got about all the interpreted tools to try and figure out the geology of this Bakken play. And so with that, we've now ramped up the activity to three rigs. But the size of this resource, obviously, with potentially 40 to 70 million barrels warrants at least three rigs drilling in this area. So we expect to have three rigs and possibly more than that running throughout the rest of the year in this play.

Okay. What are those wells costing you guys to drill over there and what do you estimate, let's just say, assuming you've got three rigs the rest of the year, in terms of number of wells you maybe get drilled here?

We will get probably 10 wells per rig per year. And with the one rig that we had operating in there, we've gotten our costs down to about $4.25 million per well; that is completed well cost. And of course, it's going to take a little time to get these other two rigs up to that level of efficiency.

And I think we are estimating about 500,000 barrels per well reserves. And what that comes out to be is about a 60% return -- after-tax rate of return, using oil prices of about $55 a barrel, roughly, for a long-term forecast.

Okay. Well, it sounds like a great play for you guys. Any sort of visibility in terms of what you guys are doing in the Cotton Valley play or some of the Cotton Valley kind of extension play over there?

Yes, we've got a I'd say reasonable acreage position, not a huge acreage position. And all of our wells over there so far have been just vertical wells, just kind of the standard wells where you frac the large Cotton Valley zone, multistage fracs.

It is likely that before year-end, we will try a horizontal well over there. As you know, we are a very horizontally minded Company. So we will likely try one over there. And I would say there is probably a fair chance that we will have some sort of a horizontal program over there with success in the first well by 2008 in that area.

Okay, thanks a lot. Good quarter.

John Herrlin with Merrill Lynch.

Hey, Mark, a couple of quick ones for you. With Johnson County, with your monster wells, you noted some geographic variation. Are there lithologic or diagenetic differences causing the recoveries to be different?

John, this is Loren. I would say that it's really more a matter of just gross thickness, which is fairly well correlating with net thickness out there. So the diagenetic factors, the lithologic factors are pretty well -- they are clotted, but they are fairly even distributed through Johnson County. So the overall thickness is really what is controlling that.

But the primary factor, I think, is the completion. We are seeing better rates not just in our monster wells but across the board with these new completions.

Good. That is what I wanted you to say. Regarding greater recovery of reserves, is this changing your IP decline curves at all, decline rates at all?

No, it is not changing the shape of those curves; it is just changing what the initial production rate would be. So you still have these very, very sharp declines in the first two or three years, and they still come out to end up after the first four or five years a very flat long-term decline. So it is just what kind of initial production rates you are getting out of the wells.

Okay. Last two for me. You are having good results in terms of efficiencies with your fit-for-purpose rigs. Do you ever see a time where that is all you will be using, is these specially designed rigs, when you are dealing with these kinds of infill plays?

Yes, John, especially on the east (indiscernible), where we are looking at measured depth that is probably somewhere around 12,000 feet.

Yes, I would echo that, John. I think you're going to see a big sea change here in a lot of our plays. We are going to go to almost 100% usage of these fit-for-purpose rigs. We've seen differences that really just knock my socks off in time to drill these wells, with these fit-for-purpose rigs.

We are making a lot of progress with use of the rigs, as well as just the technology in directional drilling today -- bits as well. We were real pleased with one of the recent wells that we drilled in the western Johnson County area, where we were finally able to pick up a motor-one bit and drill out from under surface to T.D. in one trip. And that is what we have been looking forward to.

Sure. Last one for me is on services costs. Obviously, we have been seeing real weakness up in Canada. It doesn't sound like you want to ramp up that program because your returns are better in the U.S. But would you hit a stage, given where service costs are now, that you'd lock in more equipment or do you think rates are going lower?

We are still working that. Our goal is to try to get it back to 2005 costs. But we are not going to be ramping up right now; we will just have another steady program there in Canada for '07.

What about in the U.S., are you seeing any kind of services costs reprieve in the Barnett?

You know, in the Barnett, we haven't seen much there, John. Overall, just throughout the U.S., we might say that we've seen a 5% reduction. But it hasn't been of any real magnitude at this point.

Thanks.

Jennifer (indiscernible) with BMO Capital Markets.

Hey, Mark, it is Ray Deacon. I had a question about the -- last quarter you mentioned that most of your PUDs in the Barnett were in Johnson County. And I was wondering whether, going forward, given some early positive results in the western counties, your DD&A rate could drop as a result of booking more PUDs there?

DD&A rate, talking about total company DD&A rate?

Exactly.

Yes. What you are going to see on a go-forward basis is the Barnett DD&A rate will definitely exert a leavening influence on our total U.S. DD&A rate, because the Barnett will be a lower DD&A rate than everything else we are doing in the U.S. So as the Barnett mix increases, it will leaven the DD&A rate.

Okay.

We will be booking -- because now we are drilling in the western counties more than certainly we did last year, there will be more PUDs booked at year-end this year in the western counties than there were last year. I'm not sure we had hardly any PUDs booked last year out in the western counties. I'm not sure how that will play out relative to the DD&A rate. But the bigger the Barnett gets, the more leavening influence you will see on our DD&A rate.

Okay. Is it a 1-to-1, one PUD for each well drilled? Is that how you've done it to date in Johnson County, or --?

Well, the official rule is two PUDs for one, if you have an offset in either direction from a horizontal well. But because of the way we are patterning these developments, in that we are drilling patterns of wells to keep from fracing already fraced rock, the actual number will turn out to be less than that in practice.

Yes, what we are doing there, Ray -- I think we mentioned this on one earlier call -- is our production growth in the Barnett is very lumpy. Because what we do is we drill about five or six horizontal wells literally 500 feet apart in Johnson County and we have wider spacing in the western counties. But we drill them all and then we don't produce any of them. And then we frac them all in a batch and then we turn them all on at the same time.

So if it happens to be an area, say, like the Fowler area or something, I mean we may turn on 50 million a day on one slug. But when you book PUDs in that area, you've just got five wells side-by-side there and you can only book PUDs on the outer wings of those things because they are all side-by-side. So it is a little bit complicated. It's not necessarily a 2 to 1, like Loren said.

Got it. Just two more quick ones. Your takeaway capacity with the new pipelines to Hill and then out to the West, how long do you go I guess before takeaway capacity becomes an issue?

We are not hurt on takeaway capacity anywhere right now. We don't have a problem at all, simply because we just had put our rigs where we have pipeline takeaway capacity. So in Hill County, we will get our pipeline here later in May and that is why right now we've placed two rigs down there in Hill, but that has only been in the last -- really last few weeks. So we don't have any well reports to give you on Hill County. That will really come in subsequent quarters as to what we are really doing down there in Hill.

The same thing in Palo Pinto County, that well connection, pipeline connection, is really going to come in the third quarter, though we don't have a lot of drilling reports, completion reports to give you there. So all we've done to date is we just haven't positioned any of our rigs in those two counties.

Right, okay. But I guess given that you've got 2000 locations potentially in the Western counties, what kind of takeaway capacity do you think you will need at this point, I guess? Just trying to get a sense for where you think production in the West can go.

Well, we've got it all programmed out. I don't have that in the top of my head. But we've got takeaway capacity programmed and firm transportation programmed throughout the whole area.

Okay.

So we don't think we'll have any bottlenecks anywhere, if that is where your question is.

That is exactly it. I guess just one last one is you spent a lot of time at the analyst meeting talking about more focus on horizontal drilling. And I guess were there any items in the quarter where you saw the benefit of using horizontal drilling in an area where you hadn't used it before?

As far as new plays, again, that would fall under the -- the plays that we had talked about in the analyst conference that are pretty much exactly as we predicted are the North Dakota oil Bakken play, and we still believe that is the same reserve size we gave you in the analyst conference, you know, the 40 to 70 million barrels of oil net.

And then the South Texas horizontal play, which still we believe is a half a Tcf net. And then we have new plays, but again, those kind of fall under the ones we don't want to talk about right now.

Right. You've got a lot of acreage locked up already in Appalachia, but that is [DNFG], JV; that is in the category you just -- it is too early to talk about still?

That is in the category of the 7 to 10 months category.

Okay. Thanks a lot, Mark.

David Heikkinen with Pickering Energy.

Good morning. You guys obviously spent a lot of time looking at the EIA 914 data. Do you think there's anything in the January and February data for weather or freeze-offs impacting onshore production that is unusual?

We don't think there is that much in the January data. I mean February was cold. I mean there might be, David, but I don't think there is enough to really change the trend of the nine months that we've mentioned.

That is useful. And then looking at Western County Barnett, had a target by year-end of being at completed well cost $1.25 million. Are you still on track? You talked about 1.4 million; don't know if I'm reading too much into that or is that still your --?

The answer is yes, we are on track for $1.25 million at year-end.

Okay, good. That will do it. Thanks a lot, guys.

Robert Morris with Banc of America.

Good morning, Mark. Just two quick questions. You mentioned the Western counties 0.8 to 1.0 Bcf per well, but in the analyst meeting, the upper end of that range was 1.2 Bcf net per well. Any reason for the change or is there a typo there, or what?

I'm not sure what -- we've shown so many numbers there. That may be Palo Pinto County or perhaps Jack County. The Palo Pinto and Jack Counties, the 1.2 number is probably more reasonable there. In Erath and Hood County, it is probably the 1.0 is the upper end of the range there. So it kind of depends. And a lot of the stuff we've been doing here recently has been in the Erath and Hood County's; most of those wells that we've kind of highlighted in the press release are there.

So I would say once we get into Palo Pinto in a big way, we may up the range in that county to the 1.2. But we haven't been in there in a big way yet.

Okay. Second question, just real quick here -- 11% debt to book cap is still pretty low, [even] your constant capital [loan] and the improvement in your rating by the rating agencies, in the returns you're getting here. Any thought to increasing spending or activity, especially given the returns you're getting versus cost of capital, or what would be the constraint to perhaps raising that budget?

Yes, the constraint is really just people. If we were to increase the activity, the logical place to do it would be in the Barnett. Frankly, at about the 400 wells, we are kind of maxed out on people. So that is probably the limitation right now. So at this stage, significantly ramping up activity is something that, above the $3.4 billion, is something we are not likely to do at a significant level, Bob.

One of the things we are looking at is really what is the ramp-up level that we could do for '08 in the Barnett. We definitely are going to ramp it up north of the 400 wells for '08. But one of the factors there is, given the personnel, how much could we ramp it up before we got a little bit out of control, just with the personnel limitations we have. So that is kind of the issue that we are really having to deal with there.

Okay, great. Good quarter. Thank you.

Thank you, Bob.

Joe Magner with Tristone Capital.

Good morning. Just a couple of questions with respect to the Rockies. One, you touched on Uinta Basin and how repeatable that is. We are seeing pretty wide basis differentials and indications that that basis might stay in excess of $3 for the balance of the year. Just thoughts on how that plays out prior to Rockies Express coming online, what you might be doing to mitigate the impacts, and then implications on your program.

And then, two, similar issue, on crude differentials in the Rockies; we're seeing that at pretty wide levels, based on some capacity constraints. Just your thoughts on that and the implications, given your decision to ramp up activity in the North Dakota Bakken play there. Thanks.

Yes, Joe. Both those items on the basis differential are so -- on the crude question there, we've got -- well, I guess the answer to both your questions there are that we've got such relatively fat economics coming from the Uinta Basin as well as from the North Dakota play that, although we don't like the wide differentials there, probably we will deal with them and not back off on our drilling program in either area there.

The Uinta Basin is probably our singlemost consistent program in terms of the results fall within a very, very narrow range in terms of the reserves per well and the cost per well. And we expect the basis to narrow a bit as we go through the year, although we are not saying it's going to narrow considerably. And we are signed up for the Rockies Express Pipeline, so we hope that we will be taking at least some of our gas to Ohio ultimately there.

But at this stage, we don't think that either of those bases are going to cause us to adjust our programs as we go through 2007.

Okay, thanks.

Gil Yang with Citigroup.

Hey, Mark. Just a follow-up question on new shale plays. In west Texas -- I know you do not want to talk about the plays specifically -- but I had heard that you were actually selling some acreage in the area. Could you comment on that, and does that suggest that maybe you are beginning to look beyond what that area holds as an opportunity?

Well, I won't comment on that, Gil, other than just I will reiterate what I did say at the analyst conference in November, that I think somebody asked me, on a relative ranking of the shale plays, and we did make the comment out there that the West Texas shale play out there in Culberson County was one of the lowest ranked plays that we had, out of the ones that we had discussed. But I won't make any other comments relating to any of the shale plays at this time.

Okay, thanks.

We have no further questions at this time. I will turn the conference back over to our speakers for any additional or closing remarks.

I have no further remarks. Thank you for staying with us through all the Q&A.

This does conclude our conference for today. Thank you all for your participation. Have a great day.