EOG Resources Inc (EOG) 2010 Q1 法說會逐字稿

Good day, everyone, and welcome to EOG Resources' 2010 first-quarter earnings conference call. At this time for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing first-quarter 2010 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. 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 comparable GAAP measures can be found on our website at www.eogresources.com.

Effective January 1, 2010, the SEC now permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves, as well as possible reserves. Some of the reserve disclosures on this conference call and webcast, including those for the South Texas Eagle Ford, North Dakota Bakken,/Three Forks, Barnett Shale, Haynesville/Bossier and Horn River plays may include potential reserves or estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to you as investors that appears at the bottom of our press release and investor relations page of our website.

With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President, Investor Relations.

An updated IR presentation was posted to our website last night, and we included second quarter and updated full year 2010 guidance in yesterday's press release. We remain on track to achieve 13% total Company organic production growth this year, dominated by US liquids production.

I will now review our first-quarter net income and discretionary cash flow, and then I will provide some operational highlights. Tim Driggers will provide some financial details, and I will close with some macro comments and concluding remarks.

As outlined in our press release, for the first quarter, EOG reported net income of $118 million or $0.46 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income, to eliminate mark-to-market impacts and certain one-time adjustments as outlined in the press release, EOG's first-quarter adjusted net income was also $118 million or $0.46 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 $765 million.

I will now address a few operational results. My report today will be brief since it has been only a few weeks since our April 7 analyst conference. The bottom line is that everything is on track, consistent with the information we provided at the conference. We still expect to grow total production 13% this year, with year-over-year liquids growth of 47%. Our projected CapEx level is unchanged, and we still expect to sell $1 billion to $1.5 billion of North American gas properties by year-end. Also, we are investigating joint-venture possibilities for our Marcellus and Horn River shale gas acreage.

The only new data since April 7 are a series of individual well results in some of our key plays. Most of these well results simply reinforce the overall analyst conference theme, but one well may have particular significance. This well was in the Barnett combo play, where we've completed our best producer to date. The Settle B1H well began producing at a rate of 1852 barrels of oil per day, with 3.7 million cubic feet a day of liquids-rich gas, and will yield reserves considerably higher than our model horizontal well. This well was significant because it was drilled in the Eastern portion of the play in the 25,000 acres we have designated for vertical drilling. The rock quality in this 25,000-acre area is the best in the play, which is why vertical wells are economic.

However, if we can replicate the Settle results with additional horizontal wells, then these 25,000 acres can be exploited at a higher ROR and reserve recovery than we projected for vertical wells. We'll soon be drilling additional horizontals here and will apprise you of the results later this year.

In addition to the Settle well, we've also completed a number of horizontal wells in the Barnett combo play. The Alamo A1H, 2H and 3H wells were drilled on 55-acre spacing in Montauk County. The wells began producing at a combined rate of over 900 barrels of oil per day, with 2.4 million cubic feet a day. We have 97% working interest in these wells.

Our other well results are simply further confirmations of our key oil plays. In the Eagle Ford, we've completed our 17th oil well, the Harper 4H, which IPed at 602 barrels of oil per day with 650 Mcf of gas a day.

Now that we have delineated our 120-mile Eagle Ford acreage, we are going to moderate our drilling activity for a few months until we have our 3D seismic shot and interpreted. So don't expect constant Eagle Ford news flow from EOG until late this year. Remember that our analyst conference data showed we expect to average only 6000 barrels of oil equivalent per day for the Eagle Ford this year, factoring in the lag period for the 3Ds.

In the Bakken core, we completed the [Leaseal] 22-6 and Austin 23-32 wells with IP rates of 1060 and 955 barrels of oil per day, respectively. We also completed the Van Hook 11-2 well for 1565 barrels of oil per day.

In the Lite, we completed the Sidonia 18-14 and the Ross 21-4 for 719 and 604 barrels of oil per day, respectively. I will note that these reference wells are all 640-acre laterals. We are currently drilling our first 1280-acre lateral well to test optimization. Now that the North Dakota weather has improved, we will be intensifying our well completion and frac operations for the next five months.

In the Mid-Continent Horizontal Cleveland Oil Play, we recently completed the Appel 438 5H and 6H wells, which came online for 1000 barrels of oil per day, with 2.5 million cubic feet of gas and 840 barrels of oil per day, with 1 million cubic feet of gas per day, respectively. The Cleveland is one of our hybrid oil plays. This is a conventional oil reservoir where we've applied horizontal drilling and completion technology, increasing reserves per well by a factor of four versus vertical drilling and greatly improving the economics of the play.

In summary, our three big horizontal plays, the Barnett combo, Eagle Ford and Bakken, are performing as or better than expected. We don't have any new data on the Niobrara play, and it will be year-end before we can provide an intelligent assessment of the potential Niobrara reserves on our 400,000 net acres in the DJ Basin of Northeast Colorado and southeast Wyoming.

Our gas resource plays are all performing as expected, and we don't have any other further updates since our recent conference.

In terms of our Gulf of Mexico exposure, about 1% of our total North American production is from the Gulf, and we are not active drillers in this area. The current hold on new drilling in the Gulf does not have any impact on our operations.

Outside North America, we are still continuing our one-rig operation in China, and this summer will be completing two additional wells to see if we can replicate the results of our successful first well.

In Trinidad, we've had some good production history from our successful first-quarter PA 12 well, and it's flowing at a rate of 59 million cubic feet a day, with 4000 barrels of condensate per day.

Outside of operations, another part of our 2010 business plan involves a sale of some producing natural gas assets by year-end. We are focusing on selling our Canadian shallow-gas properties and will have them on the market by midyear. Also, we are in the preliminary stage of investigating joint-venture partners for our Marcellus and Horn River shale gas acreage, where we would retain a significant interest and continue to operate. It is not at all certain that we will implement a JV, but at least we will investigate it.

I will now turn it over to Tim Driggers to discuss financials and capital structure.

Capitalized interest for the quarter was $18.4 million. For the first quarter of 2010, total exploration and development expenditures were $1.1 billion, excluding asset retirement obligations.

Total acquisitions for the quarter were $16 million, including contingent consideration with an estimated fair value of $3 million related to a previously disclosed unproved property acquisition. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $61 million.

At quarter-end, total debt outstanding was $2.8 billion, and the debt to total capitalization ratio was 22%. At March 31, we had $230 million of cash, giving us non-GAAP net debt of $2.6 billion for a net debt to total capital ratio of 20%.

The effective tax rate for the first quarter was 40%, and the deferred tax ratio was 46%.

Yesterday, we included a guidance table with our earnings press release for the second quarter and updated full-year 2010. For the full-year 2010, the effective tax range is 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. For the full-year 2010, EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas prices is approximately $30 million for net income and $45 million for operating cash flow.

For the full-year 2010, EOG's price sensitivity for each $1.00 per barrel change in wellhead crude oil and condensate price, combined with the related change in NGL price, is approximately $22 million for net income and $33 million for operating cash flows.

Now I will turn it back to Mark.

Thanks, Tim. Before I summarize, I want to cover a few items on the capital side. We mentioned at our analyst conference that we plan to maintain a low debt-to-cap ratio, while still achieving the high level of organic production growth over the next three years that have been laid out for you. We intend to manage the net-debt-to-cap ratio to a maximum of 25% by either selling mature North American natural gas properties to generate $1 billion to $1.5 billion of pretax proceeds by year-end 2010 or by taking in a joint venture partner on a large natural gas shale position. Taking either scenario into account, with the current Nymex strip, we should be in a free cash flow position by 2012.

I will now provide a few macro comments, which are consistent with our April 7 presentation. Regarding oil, we are rationally bullish both short and long term. We've recently implemented some oil hedges. For September to December of 2010, we hedged 2000 barrels of oil per day at $91.50, and for the full year of 2011, we put in place a hedge position covering 6000 barrels of oil per day at a price just above $93. We will likely implement additional oil hedges should the market present further opportunities.

Regarding North American gas, we are short-term moderately bullish and long-term rather bearish. We think last week's EIA-914 downward revision was only about one third of what we calculate, so we continue to believe the market is tighter than common perception. We will be watching the storage builds this summer to confirm or disprove our thesis. We currently have only a very small 2010 gas hedge position and don't think this is a time to be adding gas hedges.

Now let me summarize. In my opinion, there are three points to take away from this call. First, the individual well data points we provided today give further affirmation that our key horizontal oil plays are performing as or better than expected. Second, although we haven't walked through any individual details today, all of our gas plays are all performing as expected. And finally, our capital plan is consistent with what we articulated in detail on April 7.

Thanks for listening, and now we will go to Q&A.

(Operator Instructions) Michael Jacobs, Tudor, Pickering, Holt & Company.

Good morning, and thank you. Mark, when I think about your planned Haynesville activity, specifically as it relates to not just drilling the hole, but rather maximizing activity per section to focus on efficiencies, have you considered tempering the pace of activity in the Haynesville until prices strengthen? And if not, what would it take for you to slow down 2010 activity and play catch-up in 2011?

Our current rig activity there in the Haynesville is about 11 rigs, and we project that our total North American gas growth this year is going to be in a range of 1% to 2%. So we are very cognizant of the fact that the gas market is -- has got a whole lot of gas in storage right now, and the last thing we need is everybody to be drilling a zillion gas wells in North America.

And so what we've done is we've tempered significantly our gas drilling in all those nondiscretionary -- really discretionary -- excuse me -- areas, such as in our Rocky Mountain gas drilling area. And we have considerably slowed down in the Barnett Shale, where we've got most of our acreage vested.

So that kind of leaves us with three places where we have to drill a certain amount to hold acreage. The biggest of those is the Haynesville, and then we've got the Marcellus and then, to some degree, the Horn River.

At this stage, we are going to stick with our plan of running roughly 11 rigs and generating that 1% to 2% North American gas production growth. I guess if gas were to fall south of $4.00 and we were to believe it was just going to stay there permanently, we would reassess that. But that is not our current view right now, Michael.

Okay. My second question relates to your typical Eagle Ford well, and I know you've got two areas. But when I think about the Eagle Ford, it seems like there are two members, an upper and a lower Eagle Ford, and that operators to the south and west of your acreage are primarily targeting the lower member. How did that compare to where you are placing wells on your Eagle Ford acreage, and where do you think you are getting contribution from?

Yes, that's a good question. Most of our wells to date have targeted the lower Eagle Ford, which is a bit thicker, at least on our acreage, than the upper Eagle Ford. But we do recognize that the upper Eagle Ford potentially may be a target, perhaps even a separate target, in terms of things. But you can pretty well mark that the vast majority of our wells so far have been lower Eagle Ford completions.

And my last question, and then I'll hop off. You mentioned JVing the Marcellus and the Horn River. Are you going to be running concurrent data rooms and looking for best price, or is there a preference to JVing one asset over the other, outside of price?

The JV concept -- in the Horn River, as you are aware, we are working with Kitimat on that potential LNG project up there, although we don't have anything definitive to report. And so the concept of what we do in the Horn River will be a function of how things shake out with this Kitimat LNG project. So that area is likely to move a bit more slowly in terms of a JV.

The one that is on a bit faster track is the Marcellus. And we will be looking at an organized approach to screen interested parties, to look and see if we can bring someone in there. And so I would say the Marcellus, by year-end, we should have an answer as to are we going to do one, and if so, what are the terms.

The Horn River will be a function more of what happens with the Kitimat project. And then the Haynesville, we have no plans at this time to even consider a JV in that particular area.

Great. Thank you very much.

Dave Kistler, Simmons & Company.

Real quickly on the JVs, in the event that those perhaps don't come through or there is any issue selling the shallow-gas assets in Canada, would you look to revise the capital budgets to maintain a goal of free cash flow positive by 2012?

Well, that is a very hypothetical question. The way we look at it now, we've got two tracks to meet our capital plan. Either track should be able to do it on its own. The one is to sell some of these Canadian shallow-gas properties and get the price that we would hope.

But if the market for gas properties just utterly collapses, then the second thing would be to do the JV in the Marcellus. And by our calculations, either one of those will get us where we need to be in terms of the debt-to-cap ceiling.

So at this stage, the question would be theoretical -- if all of our plans fail, what are going to happen. But I would say right now the best thing to do is take the process we laid out on the April 7 analyst conference in terms of capital plan and the volume growth, and that is currently our best case estimate as to how this thing is going to play out.

Great. That's helpful. Jumping over to Barnett combo and the additional horizontals that you've been doing over there, can we just talk a little bit about what the cost of those look like and how the service intensity of those horizontal wells is increasing, what that may mean from a cost perspective, as far as cost creep on the service side?

Specifically relating to that Settle well in kind of that vertical area -- is that what you --?

Uh huh..

I guess the best way to explain it is this 25,000 acres that we've got, that in our analyst conference we said, well, that's going to the designated for vertical drilling. We always knew that was the best-quality acreage, but it's also the most tectonically complex -- a lot of kind of thrust faults and so on and so forth. And we had success with the vertical wells, and so we said, well, because this is complex geology, you can't image the 3D too well there. Verticals are the way to go, and they give a pretty healthy return.

And then we said, well, before we just commit to vast quantities of verticals, let's try the horizontal and see what happens. And this horizontal well, the Settle well, has turned out much, much better than -- frankly than any horizontal combo well we've drilled so far and it's kind of startling to us.

And so the game plan now is to -- we've got a lot of verticals that we've already drilled that we will be completing, and we'll expect to get the typical results there. On the horizontals, we are just going to see if we can replicate the Settle results. The horizontal wells are going to cost us about $3.5 million a well. The verticals would be -- I believe it is about $2.1 million a well. So you have to get more reserves.

But right now, based on the Settle results, if we can replicate that, there is a pretty fair chance we will just eliminate the vertical program and go to a horizontal program. But we need to drill three or four more wells to see if the Settle is an outlier or is that a typical well we can expect in this area (multiple speakers).

No, no, that's a great answer, I appreciate it. One quick follow-on on that. Given that it is difficult to image with 3D there, do you think it is going to be necessary to be drilling vertical wells to then tie in the horizontals or be able to see the best place to lay the horizontals?

Yes, we've done that with -- we've drilled a fair amount of verticals, so we've got some control points. The question -- usually -- for example, in Montague County, we try and target individual zone in the Barnett and we can image in 3D. And so we will stay within perhaps a 50-foot targeted zone for a whole lateral length.

We are not going to be able to do that over just 25,000 Cook County acres, because you got so many thrust faults and it's just tectonically more complex. But the question is even though we can't stay in one individual layer, is the rock quality so much better there that that offsets the fact that we will be going through multiple layers? And it's an interesting challenge, but it's fair to say right now none of us expected this Settle well to be as strong as it is. So we are just kind of rethinking what is the best way to deal with that.

Great, guys. Thank you for the additional color there.

Brian Singer, Goldman Sachs.

Actually, a follow-up question with regards to the Barnett combo. When you look at the potential additional areas that the Settle well could make prospective, is it just limited to the 25,000 acres that you mentioned on your existing acreage, or does it also potentially extend the play to the east, which I guess might go into acreage that you don't have?

The way to look at that, Brian, is it really does not extend the acres. What it says is for the 25,000 acres, kind of what we laid out on the analyst conference is we gave a reserve estimate there, assuming it is drilled with vertical wells. And if we can really drill that with horizontal wells, and it looks like they would be pretty closely spaced horizontal wells on what we could tell, then the aggregate reserve estimate for that 25,000 acres will go up, and the aggregate rate of return for the investment for that 25,000 acres will be higher also. But it doesn't really extend the likely acreage that we consider good.

Okay, thanks. And then just a clarification with regards to the asset sales. The $ 1 billion to 1.5 billion, is that your expectation now just from the Canadian shallow-gas assets? Is it your expectation from total asset sales? Does the potential proceeds or carries in a joint venture get worked into that number? And I know you've kind of touched on it, but can you just kind of clarify how we should put the $1 billion to $1.5 billion in context with the various options you are considering for asset sales?

The potential JV is not worked into that number, so that would be something that would be additive to whatever these property sales are. And we are looking at -- in Canada, it is about 150 million cubic feet a day of gas. It's your typical shallow gas in southwestern Saskatchewan, Southern Alberta, and there is also an amount that looks -- has a lot of down-spacing potential, we feel, of the coal bed methane kind of gas in an area that we call a Twining area. It is similar to the coal bed methane areas that other companies have been developing up there.

So that is our game plan, and we'll just see how it turns out. And we are in the fortunate position that if we don't get the prices we want, we are not that financially strapped where we absolutely have to sell it to meet the debt covenants or anything like that. So we've got a fair amount of discretion just to how we play this thing.

Great. Thanks. And if I could just ask one more, can you just comment on cost trajectory maybe even kind of beyond the period this year where you've provided some guidance, that as you think about the oil-to-gas mix shifting and as you kind of see current cost trends and your expectations unfolding, how should we expect particularly operating expenses as we go into 2011?

We haven't done a real thorough analysis ourselves of 2011 or 2012 unit costs. But directionally, what we would say is that our DD&A has turned out a bit higher than we projected. That is due to some startup costs in plays like the Eagle Ford and some of these other plays, where we spent a lot of money on the front end to establish the play, and we don't have that much production yet. So we think that is not a trend that you can extrapolate into '11 and '12.

On the LOE costs, though, it is pretty well certain that costs to operate oil wells are going to be higher than costs to operate gas wells. So I'm not quite as a sanguine that we will be able to contain that with -- and gas well levels as we become an oil company over the next couple of years.

Great. Thank you.

Leo Mariani, RBC.

I just wanted to clarify something on the gas going (inaudible) to North America, that you guys are talking about running 11 rigs this year, and it sounds like all of those in the Haynesville. Did I hear that right, that pretty much the rest of your North American program is (inaudible)? Anything on the joint side?

That is just our gas rigs that are running in the Haynesville. The way to look at our capital budget is that of our 2010 CapEx, about 75% of it is devoted to oil or liquids-rich gas; 25% is devoted toward what we call dry gas drilling. And of that 25%, the biggest single chunk of that is the Haynesville, but there are also increments in there for the Marcellus and for the Horn River, and a much smaller increment in there for the Barnett Johnson County stuff.

Okay, got you. And I guess is there kind of a way to sort of quantify that Haynesville versus other on the US gas side in terms of percentage of capital?

Yes, I would guess the Haynesville might be half of that 25%, maybe 12%. And then the remaining 13% chopped up among the other plays I articulated there, Leo.

Okay.

It is a tough call here is -- it's a logical question as to what do we do [usually] to Haynesville. But our read is that, one, it is hard for anybody to predict long-term gas prices. We dab at it, but we are wrong as often as we are right. So at this point, we are not anxious to forfeit any of that Haynesville acreage and just give it up.

Sure. You guys talked about slowing down your Eagle Ford program in the short term, as you are kind of waiting for 3D seismic. Are you starting to see some noise in the rock out there, or any type of [karsteding] or faulting or anything like that that is causing your result to be suboptimal and you're kind of waiting for the seismic? Can you give us a little bit more color around that?

No, nothing that surprises us at all. We've got quite a log of 2D, and there is some vertical control, so we know where the faulting is. We just want to get a better handle on how to design actual lateral wells to take advantage of what we already know. So no real surprises there, I'd say.

Just a little more color on that. Some of the laterals we have drilled, because we only have 2D seismic now, don't have 3D, on our what we call short laterals, 2000, 2500 feet. And ideally, with 3D seismic, we can make future wells in the longer laterals that should have higher reserves per well.

And then the concept of -- what we like to do in any of these plays is pick the sweetest part of a certain zone. For example, in the Eagle Ford, there is probably a 20-, 30-foot section that we consider the sweetest part of the Eagle Ford. We want to keep the lateral in there for the whole length. And that is pretty hard to do without 3D seismic.

So our view is that once we get the 3D seismic shot interpreted, then we can go back and start a pretty intensive drilling program. And there is a fair chance we are going to end up with better wells than the first 17 just because we've targeted more accurately.

So that's why if you look at that graph we provide on April 7 there as to the production growth coming out of the Eagle Ford, the 2010 production growth coming out of the Eagle Ford is really pretty minuscule, 6000 barrels of oil equivalent per day. And we really don't get cranked up until really 2012 to start showing significant production growth. So we've got that planned into our program, into our three-year volume growth side, and we never expected that we were going to have vast amounts of Eagle Ford production this year.

Okay. Jumping over to the Permian Basin, just trying to get a sense of kind of what your current acreage position is out there.

We've got some legacy acreage and items like that, but we don't have anything definitive to report right now on anything in the Permian Basin.

Okay. And obviously, with oil prices being pretty high, and clearly you guys are a technical leader on the horizontal drilling side, just curious as to whether or not you guys are starting to pick up activity out there.

Yes, we just don't have anything to disclose to you at this time relating to that, Leo.

Okay. Just one final question for you guys, on China. Obviously, you had the well results you guys announced around your analyst day there. Just curious as to whether or not that well has actually been producing, or is that just kind of in test phase at this point in time?

Yes, that well that we talked about at the conference has been on production for, I would say, about three months now. So it's got fairly long-term history for us, and it's quite stable. So we are pleased with what we are seeing so far.

What we need to know is can we replicate that, and we are in the process of drilling with that rig that Mark talked about additional wells in that zone, as well as the oil zone that we mentioned at the conference on April 7. And hope to have more completions by late summer. And (multiple speakers) some production history to be able to comment on those. So we are targeting end of the year to really make a decision on all that.

Okay, and can you remind us what your acreage position is over there in China?

130,000-acre contiguous rectangular block in the center of the Sichuan Basin.

Okay. Thanks, guys.

Irene Haas, Canaccord.

This is on the wells you are working on in Montague County, the Alamo A unit Number 1, Number 2, Number 3. The spacing of 55 acres is roughly about 450 feet. Can you sort of give us a little more color on how and why these wells are spaced and how many -- do you have a spread between Barnett A, B and C zone? Is this one of your concept of developing these wells in sort of a rolling, multi-well pattern?

Yes, Irene, you are correct. Most of this area is being staggered, with the spacing being in the 400 to 500 foot between laterals. And yes, we'd just comment that these three wells, the net EUR for these wells was 343,000 barrels equivalents per well, which kind of fits our 337 we are saying there for the horizontals on the average.

Thanks.

(Operator Instructions) Ray Deacon, Pritchard Capital.

I was wondering, could you talk about the gas-oil ratio in the Barnett combo play, and does that vary at all in Cooke County versus Montague?

Yes, in the entire play -- you've got a bar chart on the analyst slides -- but it's roughly about one third, one third, one third (multiple speakers) NGLs, crude oil and natural gas.

In terms of Cooke County ratio versus the Montague County, that doesn't seem -- we haven't detected a big difference there from that one third, one third, one third ratio. So I would say (multiple speakers) across the whole combo play, that is the best knowledge we have today on that play.

Okay. Got it. And I guess just one more, on the Marcellus. I saw that a lot of the acreage is in that Elk McKean County, in your JV with Seneca. And I was wondering is it just lack of activity that might explain the lower IP rates there, or do you think that area is just going to prove to be more tight and maybe less economically attractive than other parts of the Marcellus, or is it too early to know, I guess?

I guess the real answer is it is too early to know, because I'm not sure that we've put our best foot forward yet on learning how to complete those wells. We have some completions that we are going to start actually in just a few weeks here from some wells we are have already drilled in that part of the Marcellus play. And we would hope to improve on the results we've had to date.

I think it is fair to say that it is probably not going to be as highly pressured there as it is in the deeper parts of the trough or the Marcellus Basin. So we are not expecting 5, 6 Bcf kind of wells. I think, like we said at the conference, we are expecting more like 3.5, maybe 4 Bcf per well (multiple speakers).

Got it. Great. Thank you very much.

(Operator Instructions) David Tameron, Wells Fargo.

A couple questions. You just mentioned, Mark -- I think it was Mark -- you mentioned about the lateral lengths and then maybe you doing some longer laterals. I don't have the analyst book in front of me, but you had talked about longer laterals in the East -- I'm sorry -- shorter in the east and longer in the West, I believe, at the analyst contract. Is that -- are you changing assumptions in the East? Can you just talk more about that?

From the 2D seismic that we have, the geology is a bit more complex in the east of the Eagle Ford, and it is a bit more simple as you go west to the Eagle Ford. And kind of offsetting that is the rock quality in the east appears to be a little bit better than in the west.

And so the point is if we drill, particularly in the east, off of just the 2D seismic, that old 2D seismic, there is a pretty fair chance that if we try and drill longer laterals, we are just going to cross some sort of a fault. And so what we are doing is, particularly in East, is we are just saying, let's just hold off a bit here -- the geology is a little bit more complex there -- until we get the 3D seismic, and then we can image these fault blocks properly and decide how best to go.

But probably what's going to happen is the average lateral length on the play will be such that the west laterals are longer than the east laterals, but in both areas, the laterals will be longer on 3D than they are -- than we are capable of doing on 2D.

All right. And the well costs you threw out, like -- I think you had $0.5 million or less in the east rather than the west. So those $5 million, plus or minus, still good well cost assumptions.

Yes, the Settle was the one that was $3.5 million. That was the first well over there.

That was the combo. (inaudible) Eagle Ford.

Oh, he was talking about the Eagle Ford?

Yes, the $5 million is about right for the Eagle Ford on those things, David.

All right. One more question. Or two more questions, actually. On the Eagle Ford, you guys drew the map in your books and kind of cut the acreage off -- or cut the map off where your acreage ended.

To play Devil's Advocate, are you saying that it doesn't extend down south, south and west, or did you not pass that area, or did you look at it and pass, or can you just talk a little bit about outside your window there?

Well, we showed you the map over our acreage because that is where we are most confident, where we have the most control. And I think it really just doesn't help us to give out more data than that, frankly.

Obviously, the play does continue to the west for some distance. I think others have proven that already. The question is quality. We think we've got the better quality end of that play in terms of permeability and porosity innate in the rock itself. Drill depths, oil content, we just think that -- we studied the entire play and took our half a million acres in the oil window -- in the part of the oil window that we thought had the best rock.

All right, that's fair. One more question, just on hedges. Kind of what level --, given that you still have -- a majority of your production is still gas -- what kind of level are you looking to hedge at? I think -- I'll leave it there and let you answer.

Yes, we mentioned in the analyst conference that on the crude oil side for 2011, I guess in an ideal world, I would like to exit this year with maybe about 25% of our crude oil hedged at numbers north of about $93 a barrel. So we are looking at, if the market will allow us, of adding considerable more oil hedges. But we would still be 75% unhedged because we are bullish on oil.

On the gas side, it is really just a function of whether the EIA is right or whether we are right on how tight supply and demand are right now. It is our belief that storage builds are not going to be as strong this summer as some people are predicting. Now, that is not withstanding the huge storage bill that we are seeing right now in April because of the weather. But if we see some strengthening in the 2011, 2012 NYMEX for gas, at some point, we will pull the trigger on some hedges for the gas also. I'm not going to give a price point on that, but we don't think it's there on the current strip.

Okay, all right. That gives me some color. Thanks.

Bob Morris, Citi.

Good morning, Mark. On the Settle well, in the Barnett combo play, do you think there that you got the high rates because you intersected a karsted area? Is that --?

No, we don't think we intersected any karsted area. It is -- the rock quality is just so much better in this particular area that it is not totally shocking that we got this kind of a rate on a well. And we did kind of measure along the lateral the flow rates, and we -- because our first thought was, wow, we've intersected some big fracture [risk] and all the flow is coming from one piece of the lateral (multiple speakers).

The flow rate is pretty uniform across that lateral, which is exactly what we had hoped it would be, which tells us that it is not one giant fracture that is contributing, but it is the whole length of it.

So that is why we decided to highlight the well, because at least on all the technical parameters we can have from one well, it looks like something that we have a reasonable chance of replicating here, and it could be pretty significant in terms of rate of return impact on the whole project.

Did you fracture stimulate this well at all?

Oh, yes, always. Actually, in this Barnett combo, as in Johnson County and the gas, if you don't fracture stimulate these, you get pretty close to zero in terms of production --.

Okay. Then just real quick, secondarily, I know you've got your capital constraints on your goals on the debt-to-book cap, but are you continuing to see opportunities to acquire acreage, and are you continuing to acquire acreage in existing or new plays, and how much might you spend this year on new acreage?

In terms of the plays that we've discussed, whether it is (technical difficulty) or the Bakken or even the Niobrara or the combo play, we are not buying much additional acreage. I mean, acreage costs, since our analyst conference, in all those plays have gone up dramatically, in some cases tenfold just in a month. And so we are really not adding much there. We have some other plays, potential plays, that we haven't talked about and we are testing. And that is where we are concentrating on adding additional acreage right now.

Okay. Great. Thanks, Mark.

Okay. I want to thank everyone for staying with us on this report today, and we will look forward to talking to you again in three months. Thank you.

That does conclude today's conference. We thank everyone for their participation.