Day, everyone, and welcome to EOG Resources' 20 10 First Quarter Earnings Conference Call. At this time, for opening remarks and introductions, I'd 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 Q1 20 10 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 comparable GAAP measures can be found on our website at www.eogresources.com. Effective January 1, 2010, the SEC now 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 Bonk and Three Forks, Barnett Shale, HaynesvilleBossier and Horn River plays, they 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 Lauren Leiker, Senior EVP Exploration Gary Thomas, Senior EVP Operations Bob Garrison, EVP, Exploration Tim Driggers, Vice President and CFO and Moira Baldwin, Vice President of Investor Relations.
An updated IR presentation was posted to our website last night and we included Q2 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 U. S. Liquids production. I'll now review our Q1 net income and discretionary cash flow and then I'll provide some operational highlights.
Tim Driggers will provide some financial details and I'll close with some macro comments and concluding remarks. As outlined in our press release, for the Q1, EOG reported net income of $118,000,000 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 1st quarter adjusted net income was also $118,000,000 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 Q1 was $765,000,000 I'll now address a few operational results. Our report today will be brief since it's 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. 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 $1,000,000,000 to $1,500,000,000 of North American Gas properties by year end. Also, we're 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 settled B-1H well began producing at a rate of 18.50 2 barrels of oil per day with 3,700,000 cubic feet a day of liquids rich gas and we yield reserves considerably higher than our model horizontal well. This well is 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 and 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 A-1H, 2H and 3H wells were drilled on 55 acre spacing in Montag County. The wells began producing at a combined rate of over 900 barrels of oil per day with 2,400,000 cubic feet a day and 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 Harbor 4H, which IP ed at 602 barrels of oil per day with 6 50 Mcf of gas a day. Now that we've delineated our 120 mile Eagle Ford acreage, we're going to moderate our drilling activity for a few months until we have our 3 d 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 6,000 barrels of oil equivalent per day for the Eagle Ford this year factoring in the lag period for the 3Ds.
Or we completed the Lucille twenty two-six and Austin twenty three-thirty two wells with IP rates of 10.60 and 9.55 barrels of oil per day respectively. We also completed the Van Hook eleven-two well for 15 65 barrels of oil per day. In the light, we completed the Sedonia 18-fourteen and Ross 21-four for 719-604 barrels of oil per day respectively. I'll note that these reference wells are all 6 40 Acre Laterals. We're currently drilling our first 12 80 Acre Lateral Well to test optimization.
Now that the North Dakota weather has improved, we'll be intensifying our well completion and frac operations for the next 5 months. In the Mid Continent horizontal Cleveland oil play, we recently completed the Appel 438 5H and 6H wells, which came online for 1,000 barrels of oil per day with 2,500,000 cubic feet of gas and 840 barrels of oil per day with 1,000,000 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 4 versus vertical drilling and greatly improving the economics of the play.
In summary, our 3 big horizontal plays, the Barnett Combo, Eagle Ford and Botkin 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're still continuing our 1 rig operation in China. And this summer, we'll be completing 2 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-twelve well and it's flowing at a rate of 59,000,000 cubic feet a day with 4,000 barrels of condensate per day. Outside of operations, another part of our 20 10 business plan involves the sale of some producing natural gas assets by year end. We're focusing on selling our Canadian shallow gas properties and we'll have them on the market by mid year.
Also, we're 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's not at all certain that we'll implement a JV, but at least we'll investigate it. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Capitalized interest for the quarter was $18,400,000 For the Q1 of 2010, total exploration and development expenditures were $1,100,000,000 excluding asset retirement obligations. Total acquisitions for the quarter were $16,000,000 including contingent consideration an estimated fair value of $3,000,000 related to a previously disclosed unproved property acquisition. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $61,000,000 At quarter end, total debt outstanding was $2,800,000,000 and the debt to total capitalization ratio was 22%. At March 31, we had $230,000,000 of cash giving us non GAAP net debt of $2,600,000,000 for a net debt to total cap ratio of 20%. The effective tax rate for the Q1 was 40% and the deferred tax ratio was 46%.
Yesterday, we included a guidance table with the earnings press release for the Q2 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 Q2 and for the full year. For the full year 2010, EOG's price sensitivity reached $0.10 per Mcf change in wellhead natural gas prices is approximately $30,000,000 for net income and $45,000,000 for operating cash flow. For the full year 2010, EOG's price sensitivity for each $1 per barrel change in wellhead crude oil and condensate price combined with the related change in NGL price is approximately $22,000,000 for net income and $33,000,000 for operating cash flow.
Now, I'll 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 3 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 generate $1,000,000,000 to $1,500,000,000 of pre tax 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 20 12. I'll now provide a few macro comments, which are consistent our April 7 presentations. Regarding oil, we're rationally bullish both short and long term. We recently implemented some oil hedges. For September to December 2010, we hedged 2,000 barrels of oil per day at $91.50 and for the full year of 2011, we put in place a hedge position covering 6,000 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're short term moderately bullish and long term rather bearish. We think last week's EIA-nine fourteen downward revision was only about 1 third of what we calculate. So we continue to believe the market is tighter than common perception. We'll be watching the storage build 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 3 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. 2nd, 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'll go to Q and A.
Thank you, sir.
The
will take our first question from Michael Jacobs at Tudor, Pickering, Holt and Company.
Good morning and thank you.
Good morning.
Mark, when I think about your planned Haynesville activity, specifically as it relates to not just drilling to hold, 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?
Yes. Our current rig activity there in 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're very cognizant of the fact that the gas market always
has got
a whole lot of gas storage right now and the last thing we need is everybody to be drilling the zillion gas wells in North America. And so what we've done is we've tempered significantly our gas drilling in all those non discretionary really discretionary, excuse me, areas such as in our Rocky Mountain gas drilling area and we've considerably slowed down in the Barnett Shale where we've got most of our acreage vested. And so that kind of leaves us with 3 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're 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 and we were to believe that it was just going to stay there permanently, we'd reassess that. But that's 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's 2 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 does that compare to where you're placing wells on your Eagle Ford acreage and where do you think you're 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 maybe 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 Horn River. Are you going to be running concurrent data rooms and looking for best price or is there a preference to JV ing 1 asset over the other outside of price?
Yes. The JV concept in the Horn River, as you're aware, we're working with Kitimat on that potential LNG project up there. We don't have anything definitive to report. And so the concept of what we do in O'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's 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 to Marcellus, by year end, we should have an answer as to are we going to do 1? 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. And we'll take our next question from Dave Kistler at Simmons and Company.
Good morning, guys.
Hey. Real quickly on the JVs, in the event that those perhaps don't come through or there's any issues 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, Dave, I mean, that's a very hypothetical question. The way we look at it now, we've got 2 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 into 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, I mean, the question would be theoretical if all of our plans fail, what are going to happen. But I'd 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 the Barnett combo and the additional horizontals that you've been doing over there. 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 related to that settle well and kind of that vertical area, is that what Uh-huh. Yes. I guess the best way to explain it is the 25,000 acres that we've got that in our analyst conference we said, well, that's going to be 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.
So we said, well, because this is complex geology, you can't image the 3 d 2 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 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'll be completing and we'll expect to get the typical results there.
On the horizontals, we're just going to see if we can replicate the settled results. The horizontal wells are going to cost us about $3,500,000 a well. The verticals would be I believe it's about $2,100,000 a well. So you have to get more reserves. But right now based on the settled results, if we can replicate that, there's a pretty fair chance we'll just eliminate the vertical program and go to a horizontal program.
But we need to drill 3 or 4 more wells to see if it settles an outlier or is that a typical well we can expect in this area. And just
no, no, that's a great answer. I appreciate it. One quick follow on on that. Given that it's difficult to image with 3 d there, do you think it's 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, and we've done that with we've drilled a fair amount of verticals. So we've got some control points. The question that usually in for example in Montague County, we try and target an individual zone in the Barnett and we can image in 3 d and so we'll stay within perhaps a 50 foot targeted zone for a whole lateral length. We're not going to be able to do that over in this 25,000 Cook County Acres because you got so many thrust faults and just tectonic more complex. But the question is even though we can't stay in one individual layer is rock quality so much better there that that offsets the fact that we'll be going through multiple layers.
And it's an interesting challenge, but it's fair to say right now, none of us expected to settle well to be as strong as it is. So we're just kind of rethinking what's the best way to deal with it.
Well, great guys. Thank you for the additional color there.
Thank you.
We'll take our next question from Brian Singer at Goldman Sachs.
Thank you. Good morning. Actually a follow-up question with regards to the Barnett combo. When you look at the potential additional areas that the Settlewell could make perspective? Is it just limited to 20 5,000 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?
Now 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 in analyst conference is we gave a reserve estimate there assuming it's 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 and what we can 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. So it 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 $1,000,000,000 to $1,500,000,000 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 $1,000,000,000 to $1,500,000,000 in context with the various options you're considering for assets?
Yes. 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're looking at in Canada, it's about 150,000,000 cubic feet a day of gas, your typical shallow gas in South Western Saskatchewan, Southern Alberta. And there's also an amount that looks has a lot of downspacing potentially feel of the coalbed methane kind of gas in an area that we call a twining area.
It's similar to the cobit methane areas that other companies have been developing up there. So that's our game plan and we'll just see how it turns out. And we're in a fortunate position that if we don't get the price that we want, we're not that financially strapped. We'll be absolutely have to sell it to meet the debt covenants or anything like that. So we've got a fair amount of discretion as 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. But 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 really particularly operating expenses in the as we go into 20 11?
Yes. I mean, we have thorough analysis ourselves of 2011 or 2012 unit costs on this. But directionally what we would say is that our DD and A has turned out a bit higher than we projected. That's due to some startup costs in place like the Eagle Ford and some of these other plays where we spend 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 that's not a trend that you can extrapolate into 11 and 12.
On the LOE cost though, it's pretty well certain that cost to operate oil wells are going to be higher than cost to operate gas wells. So I'm not quite as saying when that we'll be able to contain that with the gas well levels as we become an oil company over the next couple of years.
Great. Thank you.
And we'll take our next question from Leo Mariani at RBC.
Good morning here guys. Just wanted to clarify something on the gas drilling front in North America. I think you guys are talking about running 11 rigs this year and it sounds like all of those in the Haynesville that I hear that right that pretty much the rest of your North American program as they can see anything on the joint side?
No, that's 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 U. S. Gas side in terms of percentage of capital?
Yes.
I would guess the Haynesville might be half of that 25 percent, maybe 12% and then the remaining 13% chopped up among the other plays I articulated there, Leo. Okay. It's a tough call here. It's a logical question as to what do we do vis a vis the Haynesville. But I read is that one, it's hard for anybody to predict long term gas prices.
We take a stab at it, but we're wrong as often as we are right. So at this point, we're not anxious to forfeit any of that Haynesville acreage Don't we just give it up?
Sure. You guys talked about slowing down your Eagle Ford program in the short term as you're kind of waiting for 3 d seismic. Are you starting to see some noise in the rock out there or any type of karsten or faulting or anything like that that's causing your results to be suboptimal and you're 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 lot of 2 d and there is some vertical control. So we know where the faulting is and 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 here, I'd say.
Yes. Just a little more stuff on that. Some of the laterals we drill because we only have 2 d seismic now going in 3 d or what we call short laterals, 2000,2500 feet. And ideally with 3 d seismic we can make future wells in the longer laterals and 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 Eagle Ford, there's probably a 20, 30 foot section that we consider the sweetest part of Eagle Ford and we want to keep the lateral in there for the whole length. And that's pretty hard to do without 3 d seismic. So our view is that once we get the 3 d seismic shot interpreted, then we can go back to and start a pretty intensive drilling program. And there's a fair chance we're going to end up with better wells than the first 2017 just because we've targeted them 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 Eagle Ford, The 2010 production growth coming out of Eagle Ford is really pretty minuscule, 6,000 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 in our 3 year volume growth side and we never expected that we were going to have vast amounts of Eagle Ford production this year.
Okay. Just jumping over to the Permian Basin. Just trying to get a sense of kind of what your current acreage position is out there?
Yes. 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. I mean, 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 related to that mill.
Okay. Just one final question for you guys on China. Obviously, you had the well results you guys announced around your Animal Stay 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 3 months now. So it's got a fairly long term history for us and it's quite stable. So we're pleased with what we're seeing so far. What we need to know is can we replicate that and we're in the process of drilling with that rig that Mark talked about.
Additional wells in that zone as well as the oil zone we mentioned at the conference on April 7 and hope to have more completions by late summer. And then we have to do some production history to be able to comment on those. We're 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?
1 130,000 acre contiguous rectangular block in the center of Sichuan Basin.
Okay. Thanks guys.
We'll take our next question from Irene Haas at Canaccord.
Yeah. Hi guys. This is on the wells you're working on in Montague County, the Alamo A Unit 1, 2, 3. The spacing of 55 acres is roughly about 4 50 feet. Can 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 and sort of rolling multi well pattern?
Yes, Irene. You're correct. Most of this area is being staggered with the spacing being in the 400 to 500 foot between laterals. And yes, we just commented these 3 wells, the net EUR for these wells was 343 1,000 barrels equivalents per well, which kind of fits our 3.37 we're seeing there for the horizontals on the average.
Thanks.
We'll take our next question from Ray Deacon at Pritchard Capital.
Mark, I was wondering, could you talk about the gas oil ratio in the Barnett combo play and does that vary at all in Cook County versus Montag?
Yes, I mean, in the entire play, it's got a bar chart in the analyst slides, but it's roughly about a third, a third, a third of the life of NGLs, crude oil and natural gas. In terms of Cook County ratio versus the Montag County, that doesn't seem we haven't detected a big difference there from that 3rd, 3rd, 3rd ratio. So I'd say if you have across the whole combo play that's the best knowledge we have today.
Okay, got it. And I guess just one more on the Marcellus. How I saw that a lot of the acreage is in that Elk McKean County and 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 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?
Yes, I guess the real answer is, it's 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're going to start actually in just a few weeks here from some wells we've 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's probably not going to be as highly pressured there as it is in the deeper parts of the trough of the Marcellus Basin. So we're not expecting 5, 6 Bcf kind of wells.
I think like we said at the conference, we're expecting more like 3.5, maybe 4 Bcf per
well. Got it, great. Thank you very much.
We'll take our next question from David Tamarone at Wells Fargo.
Hi, good morning. A couple of questions. You just mentioned, Mark, I think it was Mark you mentioned about the lateral lengths and then maybe you're 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 Conference. Is that are you changing assumptions in the East?
Can you
just talk more about that?
Yes. From the 2 d seismic that we have, the geology is a bit more complex in the East of the Eagle Ford and it's a bit more simple as you go West in 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 2 d seismic, that old 2 d seismic, there's a pretty fair chance that if we try and drill longer laterals, we're just going to cross some sort of a fault.
Okay.
And so what we're doing is particularly in East is we're just saying let's just hold off a bit here. The geology is a little bit more complex there until we get to 3 d 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 East laterals. But in both areas, the laterals will be longer on 3 d than they are that we're capable of doing on 2 d.
All right. And the well cost you throughout like 5, I think you had $500,000 less in the East rather than the West. So those $5,000,000 plus or minus still good well cost assumptions?
Yes, the settled was the one that was $3,500,000 that was the first well over there.
Yes, the $5,000,000 is about right. Okay. And Eagle is on those same standards.
All right. One more question or two more questions actually. Just on the Eagle Ford, you guys drew the map in your books and kind of cut the acreage off or cut the map off for 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 test that area or did you look at it in the past or can you just talk a little bit about outside your window there?
Well, I mean, we showed you the map over our acreage because that's where we're 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. I mean, 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 into that play in terms of permeability and porosity in 8 in Iraq itself, drill depths, oil content. We just think that we studied the entire play and took our 500,000 acres in the oil window and the part of the oil window that we thought had the best
One more question, just on hedges, kind of what level given that you still have a majority of 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'd like to exit this year with maybe about 25% of our crude oil hedged at numbers north of about $93 a barrel. So we're looking at if the market will allow us of adding considerable more oil hedges, but we'd still be 75% unhedged because we are bullish on oil. On the gas side, it's really just a function of whether the EIA is right or whether we're right on how tight supply and demand are right now. It's our belief that storage builds are not going to be as strong this summer as some people are predicting.
Now that's notwithstanding the huge storage build that we're 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 I don't think it's there on the current strip.
Okay. That gives me some color. Thanks.
And we'll take our final question from Bob Morris at Citi.
Good morning, Mark.
Good morning.
Settle well in the Barnett combo play. Do you think there that you got the high rates because you intersected a car stood area? Is that
No. We don't think we intersected any costed area. It's the rock quality is just so much better in this particular area that it's not totally shocking that we've got this kind of a rate on the well. And so and we did kind of measure along the lateral the flow rates and we because our first thought was while we've intersected some big fracture and all the folks coming from one piece of the lateral. The flow rate is pretty uniform across that lateral, which is exactly what we'd hoped it would be, which tells us that it's not one giant fracture that's contributing, but it's the whole length of it.
So that's why we decided to highlight the well because at least 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?
Yes. Actually in this Barnett combo as in Johnson County and the gas, if you don't fracture stimulate these you get pretty close to 0 in terms of production.
Okay. And 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?
Yes, in terms of the plays that we've discussed, whether it's or even the Niobrara or the combo play, We're 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're really not adding much there. We have some other plays, potential plays that we haven't talked about and we're testing and that's where we're concentrating on adding additional acreage right now.
Okay, great. Thanks, Mark.
Thank you, Bob. Okay. I want to thank everyone for Thank you.
That does conclude today's conference. We thank everyone for their participation.