EOG Resources, Inc.
Q4 2011 Earnings Call Transcript

Published: 17 Feb 2012

[Operator:]

Good day, everyone, and welcome to EOG Resources Fourth Quarter and Full Year 2011 Earnings Results Conference Call. As a reminder, this call is being recorded. 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.

[Mark G. Papa:]

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2011 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. The SEC 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 estimates on this conference call and webcast, including those for the Eagle Ford, may contain potential reserves or other 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 U.S. investors that appears at the bottom of our press release in the Investor Relations page of our website. With me this morning are Bill Thomas, President; Gary Thomas, COO; Tim Driggers, Vice President and CFO; Maire Baldwin, Vice President, Investor Relations; and Jill Miller, Manager of Engineering and Acquisitions. An updated IR presentation was posted to our website last night, and we included first quarter and full year 2012 guidance in yesterday's press release. This is our 50th quarterly earnings call since we became a fully public company, and fittingly, we have a lot of positives to discuss this morning, including exciting news from several Texas-based liquids resource plays. I'll discuss topics in the following order

[Timothy K. Driggers:]

Good morning. Capitalized interest for the quarter was $13.5 million and $57.7 million for the full year. For the fourth quarter 2011, total cash exploration and development expenditures were $1.66 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $154 million. Total acquisitions for the quarter were $200,000 and $4.2 million for the year. For the full year 2011, total exploration and development expenditures were $6.47 billion excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $656 million. For 2011, approximately 10% of the drilling program CapEx was exploration and 90% was development. Approximately 20% of the CapEx was allocated to dry gas drilling. For the full year 2011, proceeds from asset sales were $1.43 billion. At year end 2011, total debt outstanding was $5.0 billion and the debt-to-total capitalization ratio was 28%. At December 31, we had $616 million of cash on hand, giving us non-GAAP net debt of $4.4 billion for a net debt-to-total capital ratio of 26%. The effective tax rate for the fourth quarter was 50% and the deferred tax ratio was less than 1%. Similarly, the effective tax rate for the year was 43% and the deferred tax ratio was 61%. We also announced another increase in the dividend on the common stock. This is the 13th increase in 13 years. Effective with the next dividend, the annual indicated rate is $0.68 per share, a 6.25% increase. Yesterday, we included a guidance table with the earnings press release for the first quarter and full year 2012. For the first quarter, the effective tax rate is estimated to be 35% to 50%. For the full year 2012, the expected effective tax rate 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 first quarter and for the full year. Regarding price sensitivities, with our current hedge position in 2012, for each $1 move in crude oil prices, net income is impacted $32 million, cash flow is impacted $47 million. For each $0.10 move in natural gas prices, net income is impacted $11 million and cash flow is impacted by $16 million. Now I'll turn it back to Mark.

[Mark G. Papa:]

Thanks, Tim. Now I'll provide our views regarding macro hedging and then some concluding remarks. Regarding oil, we still think that the global supply demand balance is tight and the fundamentals dictate the current $100 WTI price. The upside risks are mainly geopolitical. The downside risk is a second global recession, and for that contingency, we've recently increased our crude oil hedge position. For 2012, as a percent of North American oil production, we're approximately 23% hedged at $104.95. We're 33% hedged at $105.36 for February 1 to June 30 and 14% hedged at $104.26 for the second half of the year. I'll also note that we expect to commission our St. James crude unloading facility in April. Based on the current WTI LOS differential, we would plan to move up to 100,000 barrels a day from different areas to take advantage of the crude price uplift at St. James. We continue to have a very cautious outlook regarding 2012 natural gas prices and fortunately, as a percentage of North American gas, we're 45% hedged at $5.44 for the year. We've recently layered on 150 million cubic feet a day of hedges for 2013 and 2014 at $4.79. Please see the table that was included in our earnings press release for the details of our hedging contracts. Now let me summarize. In my opinion, there are a lot of important points, 8 in total, we'd like you to take away from this call. First, the game plan we articulated several years ago is working. We've captured world-class, low-risk liquids positions that are driving the strongest organic liquids growth, primarily oil, of any large cap independent. In parallel, our EPS adjusted EBITDAX and discretionary cash flow are growing at high rates. We expect this to be a multiyear trend. Second, we're accomplishing this game plan with relatively low net debt, which was 26% at year end. Third, our 4 liquids plays, the Eagle Ford, Barnett Combo, Bakken and Wolfcamp/Leonard, constitute the most powerful horizontal liquids arsenal of any independent E&P. Each is world-class in size, is located in the onshore, lower 48 in producer-friendly states and generate strong reinvestment rates of return. Additionally, we believe that both public and sell side data indicate EOG is achieving the highest liquids reserves per well at the lowest cost in each play. I'll also note that our front end leasehold costs were likely the lowest in industry for each play. Fourth, with our expanded Eagle Ford reserve estimate, we feel even more confident that our estimated reserve, potential reserve recoverable of 1.6 billion barrels of oil equivalent net after royalty Eagle Ford asset is the largest net oil reserve accumulation found in the U.S. in the past 40 years. Further, we believe that this play generates -- likely generates the highest reinvestment rate of return opportunity in the entire E&P industry for large-scale play. Fifth, our Barnett Combo, North Dakota Bakken and Permian Basin plays are all performing as we expected. All of these have long-term growth upside. Sixth, we have a plan to deal with our 2012 funding GAAP and already, we're nearly 1/3 of the way towards our 2012 property disposition target. Because of our liquids growth, our 2013 funding GAAP narrows considerably or since a lot of our acreage will be vested by then, we could decelerate CapEx and achieve only robust instead of outstanding 2013 liquids growth. Seventh, with 2 EOG sand mines now in operation in our crude-by-rail facilities in the Bakken, Eagle Ford, Cushing and St. James, we're comfortable that we can both reduce well costs and continue to obtain the highest oil net backs. We have recently seen differentials at Clear Brook, Minnesota increase to $15 to $25 off of WTI and as much as $42 below LOS for Bakken-related production. Using our own crude-by-rail facilities in North Dakota, we are currently transporting approximately half of our Bakken oil from Stanley to Cushing to capture the higher margins. During the second quarter, we'll have our St. James rail unloading facility in service giving us the flexibility to quickly react to these types of market conditions. We can then avoid local market disconnects and sell our crude off of either WTI or LOS benchmarks. There are a number of new crude-by-rail projects planned for this year. What's important for EOG is that we secure both the loading and offloading facilities. We have origination facilities in Stanley, North Dakota and in the Eagle Ford. We have offloading or destination facilities at both Cushing and St. James. Unit trains require tremendous amounts of real estate and a secure supply of crude oil and as part of our marketing strategy, we put both pieces in place early on. And finally, there are at least 3 significant discriminators that separate EOG from the pack. First, we have the 4 best domestic liquids resource plays in the industry bar none. Second, our ownership in these 4 plays is 100%. We don't have any JVs. Our Eagle Ford acreage is an example of why we've shunned JVs on our major oil plays. It we had done a JV a year or 2 ago, we would effectively have given away a portion of the 700 million barrel Eagle Ford upside that we just announced. Lastly, we're unique in that we're the only company that's reduced its North American gas production in 2009, 2010, 2011, and plan to do so again in 2012. We think that's a rational business response to chronically low gas prices, and that's what our shareholders expect of us. Thanks for listening. And now we'll go to Q&A.

[Operator:]

[Operator Instructions] We will go first to Doug Leggate of Bank of America Merrill Lynch.

[Douglas George Blyth Leggate:]

I've got a couple of questions. Actually, one specific question on the Eagle Ford and one follow-up, if I may. You've clearly got a world-class asset here under -- obviously congratulations on the results that you've come out with on this. My questions are on the constraints on basically how your drilling plans have changed relative to you prior reserve estimate. And what I'm really getting at is a lot of value could potentially be accelerated if you accelerate the drilling program. But I'm just wondering what your thoughts are around in the context of your balance sheet limitations on the number of wells that you plan to drill. And I've got a follow-up on that subject, please.

[Mark G. Papa:]

Yes, Doug, the real limitation on how much more we can ramp up the Eagle Ford activity level from current levels is personnel, and I'd say learning curve knowledge. On the personnel side, for example, if we said, "Wow, we just increased our reserves considerably, we're going to double activity in 2012 over expectations," we would be flatly out control in terms of being able to intelligently manage that increased investment. We just don't have enough qualified technical people to do that. So that's one issue. The other issue is that it's obvious that we're learning quite a bit as we go on in this Eagle Ford play. You can tell that from the improved quality of our well results that we've reported each quarter. Obviously, the spacing is something we're learning more. So we're going to take this at a moderate pace because we're going to be a lot smarter a year or 2 from now than we are today relating to this asset. So it is possible that with the relative size increase that we've just announced that in 2013 and later, we may elect to accelerate development of this. But it's really not so much on the capital side. It's going to be more a function of have we got the people qualified to handle a further step up and have we got our learning optimization such that we could, say, dramatically increase activity even more on there. So it's a complicated picture. You can't really look at it on just advancing net present value without considering these other items, Doug. What's your follow-up question?

[Douglas George Blyth Leggate:]

My follow-up is really on -- you talked about upwards 4% to 10% is the kind of recovery range you'd be, you ultimately think you could maybe move to at some point. Maybe I'm being a little optimistic there. You're currently at 6% on your assumptions. What would it take for you to take that number higher?

[Mark G. Papa:]

Yes, I'm not going to commit to a number in terms of what's the highest percent we could think about. But it's probably in that range of 10% to 12%, really in terms of what we see today with today's technology. The next 2 more steps here, we need to determine is the 65 to 90 acre spacing, is that the most dense we can drill, or is it -- should we be even looking at more dense? And the other possibility here is secondary recovery. And we mentioned on the call that we'll be initiating a pilot project in the Bakken to get more oil out of the ground using water injection. In the Eagle Ford, we probably would not try water injection, but we have some other things in mind there. So it's quite likely that within the next 12 to 18 months, we'll have a pilot project going in the Eagle Ford of a secondary recovery nature that we hope would be successful. But we just have to play it out. With 28 billion barrels of oil net in place under our acreage, this is clearly an improvement. Recovery factors is clearly the single most important thing we can be doing here in EOG, and we're giving it appropriate focus.

[Operator:]

And we'll go next to Brian Lively with Tudor, Pickering, Holt.

[Brian Lively:]

Mark, on the midland Wolfcamp results, it appears that the -- at least to me, the early rates versus the 280,000 barrel equivalent EURs even on an after royalty basis, it seems like those 2 don't jive. Can you just comment on what you're seeing from a curve standpoint as you get this update on higher rates?

[Timothy K. Driggers:]

Yes, Brian, we are making progress. We've continued to increase the lateral link. We're also working on the frac designs to improve the wells and their recoveries. And we're working on the spacing patterns too. So we did update the reserve model last year, one time, and the thing that we're really evaluating there is we test these various spacing patterns and we down spaced to tighter spacing. We're just trying to give us enough information and enough time to fully evaluate the effect on the ultimate EURs on wells. So at this point that the 280 Mboe kind of wells on the model that we're using, I mean, it could increase over time, but we're not ready to do that yet. But the play is going really well. I mean, we're focused primarily on developing the middle zone, and the numbers that we're using for the reserve for well are conservative.

[Brian Lively:]

Okay, that's helpful. My second question is just on the Q1 volumes. 2012 looks great, Q1 volumes are flattish sequentially. Can you guys go into just some more detail on the drivers behind that?

[Mark G. Papa:]

Yes, Brian. Three different drivers on the Q1 volumes. We've always said on these resource plays, you can't just take a straight line quarter to quarter to quarter to quarter and assume that our production growth is going to be that way. The biggest single component of the lumpiness in our production growth is what we call pattern drilling and frac-ing. If you notice in those Henkhaus wells, for example, in Eagle Ford that we mentioned to you on the press release there, typically, what we do there is we drill 4 or 5 of those wells. We don't frac any of them individually, and then we wait till we get all the wells drilled, then we line them up and frac them 1, 2, 3, 4, 5, without producing any of them. And then when they're all frac-ed, we turn them all on at one time. So you get a big burst of production, but it's just a function of how many wells have you drilled in the pattern, what's your frac schedule and everything. And in the first quarter, we've got really, I'd say, an abnormal amount of wells that we're going to be patterned, drilling and frac-ing. So that's affecting it. We've also got some downtime in some gas processing plants that we're anticipating that's going to hurt some of our NGL production and oil production from some of our combo areas. And then, the last thing is a little bit of property dispositions that, as we mentioned, because the gas market is so weak, the majority of our $1.2 billion worth of property dispositions this year are going to have some liquid component with them. And so we're trying to get those scheduled timing. So you can't expect that the first quarter and potentially, the second quarter are not going to have strong year-over-year or quarter-over-quarter growth numbers -- excuse me, the year-over-year is going to be very strong in the first quarter. I believe it's a number like 40%, 40-plus percent. But we just caution you, don't just take a straight line on our quarter-to-quarter growth in 2011 and just extrapolate that in 2012.

[Operator:]

We will go next to Leo Mariani of RBC.

[Leo P. Mariani:]

Just on the Eagle Ford, I wanted to see if you could comment on whether or not you're seeing any interference on your down space wells when you go into 65 to 90 acres. I know you don't have that much production history, but can you just comment on kind of what you're seeing there, and whether or not you think you maybe need quite a bit more time before seeing that?

[Mark G. Papa:]

Yes. We think we've seen enough to feel pretty comfortable on the down spacing in terms of evaluation. To be honest with you, on many of the down spacing patterns, we found out that the down space wells are better and stronger than the original widely-spaced wells. And of course, if we were to have an interference, it would just the opposite of that. And what we're seeing is the effects of 2 things

[Leo P. Mariani:]

Okay. And, I guess, in terms of your NGL growth guidance for 2012, you took it up pretty significantly. I want to get a sense of what's driving that, whether or not maybe there was some higher than expected NGL cuts in any of your wells here.

[Mark G. Papa:]

Yes. Actually, Leo, to be honest with you, the previous numbers that we had, had for liquids growth expectations, 2012, were 30% oil, and, I believe, the number was 16% NGLs, and now we've jumped the NGLs to 30%. Those previous numbers were about 18 months, maybe 24 months old. You'll remember when we had an analyst conference a couple -- several years ago, we gave a 3-year forecast for '10, '11 and '12, and we really never moved those '12 numbers. So the 30% NGL number currently is, frankly, just simply updating a number that was stale even 12 months ago. So it's not that we're seeing a huge influx of increased NGL mix or anything like that. It's really, we're just updating a stale number.

[Leo P. Mariani:]

All right, that's great. And, I guess, are you guys adding acreage scale in some of your North American plays as well? I know you mentioned that in the past.

[Mark G. Papa:]

Yes. We've got 3 goals, and we highlight that on one of the pages in our outlook [ph] that the -- kind of our goals for this year. The first goal is to find some new greenfield North American horizontal liquids plays, and we're working feverishly on that. Second goal was to improve recovery factors in some of our larger plays that we've already exposed. And today, you saw the results from the Eagle Ford on that, and we mentioned that in the Bakken, we're looking at 2 things there. One is down spacing, and then the second is secondary recovery. And then the third over-arching goal for this year is to find a large horizontal oil accumulation outside North America. And you heard us mention this Vaca Muerta shale that we'll give you more details on as the year progresses. So on all 3 of those goals, those are still our targets our for this year. And clearly, we've nailed goal #2 and goals #1 and 3 hopefully will have good results by the end of the year.

[Operator:]

We'll go next to Brian Singer of Goldman Sachs.

[Brian Singer:]

Going back to the Wolfcamp shale, a couple questions there. First, you highlighted in your comments that you would expect a combo-like, Barnett combo-like mix of oil, gas and NGLs. The IP that you highlighted, though, seemed to have a little bit more of an oilier mix. And I wondered if you expected that mix to change as the wells begin to climb. And then also, whether the goal is -- whether you think you're playing for 2 horizontals, 1 middle and 1 upper, whether you see additional zones that could give perspective.

[Gary L. Thomas:]

Yes, Brian. The Wolfcamp is really a combo-type play. The GURs will gradually go up over time. So the early rates on the oil are a bit higher than they will be later in the life in the well. So, yes, we feel those mixes that we've given are accurate. And then on the -- we are working -- primarily, most of our drilling, nearly all of our drilling so far has been in the middle zone. And we're having really good results in the middle zone in -- really in every acreage block that we test, we tested the middle zone as being really good. We do have the one well that we have in the press release. It's The University 9 #2803 in Reagan County, and we IP-ed that well at 883 barrels of oil a day, and that was a full lateral upper zone test, and that well looks very good to us and is very encouraging. Other than that, we have very limited test in the lower zone and the upper zone. So we have plans to do additional testing this year in those zones, and we'll see how that goes. But we're really optimistic. The middle looks very consistent. And so, we're working on our development patterns out there, trying to establish what's the proper spacing. And we're also -- we've implemented our self-sourced sand and new completion techniques. And so the play is going really well. One of the great things about the play is that we've significantly reduced the well cost over the last few quarters with the implementation of our sand, and our drilling efficiencies have gone up. We recently drilled a well from spud to TD in 4.9 days. And so, our operational people in West Texas are doing an excellent job on reducing cost as well as developing a play properly. So we're very encouraged about the play.

[Brian Singer:]

That's great. And then lastly, on the Eagle Ford, you highlight in your presentation some of the IP is exceeding 3,000 barrels a day. Is that a function of longer laterals and where your cost would exceed your $5.5 million objective? Is it a sweet spot around seemingly at Karnes County, or is there some other factor driving those results?

[Mark G. Papa:]

Yes, Brian. The best way to explain that is, is that we've found that there are certain portions of this reservoir that are more prolific than other portions of the reservoir. The average well of 450 Mboe we quoted there is a mix. The kind of wells we quoted in our press release are more like 800 to maybe up to 1 million barrels of oil reserves per well. And we know that we have a tranche of those wells, quite a few of those, in that mix of 3,200 yet to drill. And if we wanted to, we could target and drill that tranche over the next couple years and really shoot up [indiscernible]. But to be fair and objective, it's not so much that they're super long laterals, it's that they're located in a portion of the reservoir that we believe is definitely more prolific than in some other parts of the reservoir. So we'll say, you can expect we'll continue to be able to report wells of that similar type as we go throughout 2012, but we'd kind of point you more to the average well and say, the average well is quite strong and gives you 80% return. So hopefully, that gives you an explanation.

[Operator:]

And our next question comes from us Arun Jayaram with Crédit Suisse.

[Arun Jayaram:]

Mark, you talked about some down spacing opportunities in the Bakken. What does that do in terms of your inventory in the core part of the Bakken? And how many rigs do you plan to run in the core part versus the Bakken Lite in '12?

[Mark G. Papa:]

Yes. Actually, I mentioned in this call kind of focusing on the core, but we're really -- it's fair to say that we're looking at the entire Bakken. The Bakken Core is the sweet spot of the entire Bakken play, and then what we call the Bakken Lite is equivalent to pretty much every other company at Bakken. It's a lesser quality, but it's still good. The spacing that we have initially drilled these on are in the Core 640s and in the Lite 320s. And we're testing the down spacing in both the Core and the Lite. In the Core, we're testing 320 down spacing; in the Lite, we're testing 160 down spacing. If it was to work in both areas, and it looks good so far, the reserve uplift would be about the 50 million barrels. So we don't want to mislead you and mischaracterize it and say, "Wow, we can double our reserves in the whole play under that circumstance there." In terms of the rigs this year, we're running 7 rigs, and I would guess -- Gary, how many are in the Core, how many in the Lite you'd guess?

[Gary L. Thomas:]

We're still trying to retain acreage there. So we'll probably run somewhere around 4 in the Lite and 3 in the down spacing.

[Arun Jayaram:]

That's helpful. Just my quick follow-up. Mark, you did raise your NGL guidance for '12 quite a bit and crude was more flattish, perhaps reflecting property sales. On a same-store sales basis, if you didn't have the asset sales, what would have been the growth guidance on the crude side?

[Mark G. Papa:]

Yes. Well, we kind of -- I don't have the numbers. We quoted you numbers a bit over 3,000 barrels a day of liquids on an annualized basis is what our total liquids would have gone. And maybe that's 2/3 oil, 1/3 gas but -- or NGLs, but I can't quote you an exact number on that, Arun.

[Arun Jayaram:]

Okay, that's fair. But just the mix shift, is it just moving a little bit more towards NGLs versus crude? Is that fair, as you get more experience in the play?

[Mark G. Papa:]

No, not really. What I'd say is that, as I mentioned on one of the previous questions, the increase we showed in NGL growth from, I believe, it was 16% previously, up to 30% in the update, is really that the old NGL number was probably about a 2-year-old stale number that we just never bothered to change. And now we've updated it. So it's -- we haven't really seen a mix change during '11 that says we're becoming more NGL mix versus oil. It was really just updating a stale NGL number.

[Operator:]

And we'll take our next question from Joe Allman with JPMorgan.

[Joseph D. Allman:]

Mark, in terms of the assets you've sold already, could you just identify those for us? And what are some of the assets that you intend to sell? And then, kind of along those lines, apart from asset sales, and in terms of your gas, organic gas production decline, what would you estimate the base decline to be if you did nothing?

[Mark G. Papa:]

Well, yes, in terms of your first part of your question there, Joe, the sales that we've done to date and that we have in progress, which are roughly $400 million, those were predominantly gas. Just a tiny bit of liquids and oil with those. But the remaining sales of roughly $800 million, we have yet to do, we just anticipate that were we to offer just dry gas properties out there in the market that they wouldn't fetch much of a price. And so that's one change we've had to make over the last 6 months. For this year is, originally, we intended that most of our sales in 2012 would be just dry gas. But due to the collapse of gas prices, we've had to change that. And I'd say out of the 800 million remaining, those are going to have -- essentially, all of those are going to have a liquid component. Some of them are just going to be flat oil areas, and we are looking at selling some outside operated stuff in the Bakken, and some of them are going to be gas with rich liquids component in there. In terms of our gas production, base decline and things like that, I'd probably not -- don't want to offer up a specific number for you on that. The only thing I would offer up is that one of the things that I've noted on previous earnings calls is that it's been disturbing to me to see most of the independent group has strongly grown their North American gas volumes over the last 3 years, and have been, in my mind, active contributors to this gas bubble, whereas EOG has done just the anti-thesis of that. As I mentioned earlier, this will be the fourth straight year where our North American gas volumes have declined, which we believe is a rational economic response to these chronic low gas prices.

[Joseph D. Allman:]

That's helpful. And then in the Permian, in your Wolfcamp play, Midland Basin, what's the lateral length you're using right now? What number of fracs? And then could you comment on your prospectivity for the Cline Shale?

[Gary L. Thomas:]

Joe, in the Permian and the Wolfcamp, our average lateral length is about 7,600 feet. And we're typically -- we're experimenting on the number of stages, but they could be anywhere from 20- to 30-plus stages per well. What was the name of that play you...

[Joseph D. Allman:]

The Cline Shale.

[Gary L. Thomas:]

The Cline Shale, no. Not familiar with that.

[Mark G. Papa:]

Yes, I'm not either. It may have some other name out there in the Permian Basin, but it's fair to say that's not one of our stealth plays. We don't even -- we haven't even heard of it hardly.

[Operator:]

And our next question will come from Pearce Hammond with Simmons.

[Pearce W. Hammond:]

I was curious what your outlook is for service cost and what you might be assuming for service cost inflation or deflation in your 2012 CapEx guidance, and then I have a follow-up.

[Gary L. Thomas:]

We've got so much of our services kind of committed on the long-term. Of course, that's in our guidance and in our projections. We've got 42 rigs under long-term contract out of our 75, and we've got 11 of our frac fleets under long-term out of 20. We are seeing quite a lot of services more available with the slowdown in the true gas plays, most especially in the Permian Basin. We're starting to see some of that in Eagle Ford. So we don't see much increase in our cost of services. We do have our own self-sourced sand, and we'll be servicing the majority of our wells with that. We've got self-sourced asset, we've got our own rental fleet. So we're pretty well set here, not see seeing much increase in 2012.

[Pearce W. Hammond:]

And then a follow-up, back into your 3,200 Eagle Ford locations, what spacing assumptions and prospectivity are you assuming across your entire acreage position in the Eagle Ford?

[Mark G. Papa:]

Well, we've reduced the spacing assumption from the previous 130 acres to a mix of between 65 and 90 acres, depending on the different geologic areas of the play. Is that...

[Pearce W. Hammond:]

[indiscernible] perspective, is that all down space then?

[Mark G. Papa:]

Well, the 3,200 incremental wells are what we call sticks on a map and, I guess, the best way to describe those 3,200 wells yet to drill is that we have a map of the Eagle Ford play, and it's got all the subsurface geology with the faults, et cetera, on it. And it's also got all the lease boundaries that we have. And then, our people have laid out actual specific locations for 3,200 wells on that map that will conform to the lease boundaries, conform to the subsurface geology and so on. So, I guess, one way to describe the 3,200 wells is that we already have those 3,200 wells defined as to exactly where we would intend to drill them. Hopefully, that's helpful to you.

[Operator:]

And that does conclude today's question-and-answer session. I'd like to turn the conference back over to Mr. Mark Papa for any additional or closing remarks.

[Mark G. Papa:]

I have no additional remarks. So thank you very much for staying with us on the call.

[Operator:]

And that does conclude today's conference, ladies and gentlemen. We appreciate everyone's participation today.