EOG Resources - Q1 2011
May 6, 2011
Transcript
Operator (participant)
Good day, everyone, and welcome to the EOG Resources First Quarter 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 Papa (Chairman and CEO)
Good morning, and thanks for joining us. We hope everyone has seen the press release announcing First Quarter 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. Effective January 1st, 2010, the SEC now permits oil and gas companies through the filings with the SEC to disclose not only true 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 include 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 and investor relations page at our website. With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bill Thomas, Senior EVP, Exploitation; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President of Investor Relations. An updated IR presentation was posted to our website last night, and we included second quarter and full-year guidance in yesterday's press release. I'll now review our first quarter net income and cash flow, followed by our operational highlights. Tim Driggers will then provide some financial details.
I'll provide some macro and hedging comments along with concluding remarks. As outlined in our press release, for the first quarter, EOG reported net income of $134 million or $0.52 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 $177 million or $0.68 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 $947 million. I'll now discuss our 2011 business plan and operational results. Our business plan continues to be consistent and straightforward.
We're rapidly making the organic conversion to a liquids-based company by exploiting our world-class North American horizontal oil positions while still preserving 100% of our large North American natural gas resource play assets and maintaining a low net debt-to-capitalization ratio. As our first quarter results indicate, the plan is working just like we drew it up on a chalkboard four years ago. We've invested the majority of our capital in very high reinvestment rate of return domestic oil development projects, which will ultimately flow through our net income and show up as superior ROEs and ROCEs. We're very comfortable regarding our 2011 goal of approximately $1 billion of asset sales, which will help maintain low debt ratios. In the first quarter, we received $260 million from property dispositions and asset sales.
Since March 31, we've received an additional $387 million of proceeds, and we're actively working on an incremental $400 million of sales, so this goal is well in hand. In the first quarter, the total company production averaged 14% year-over-year, total company liquids increased 47%, and unit costs remained in line. Although our second quarter oil estimate has been significantly affected by flooding and ice storms in our North Dakota Bakken and Manitoba Waskada fields and major electricity outages impacting our North Dakota Bakken operations, there's no change to our full-year production growth targets of 9% for total company and 49% for total liquids. This is reflected in last night's guidance. I want to repeat a comment that I made on the previous quarterly call. At the current 23-1 crude oil to natural gas price ratio, I believe the overall production growth yardstick is somewhat meaningless.
In today's world, the metrics of liquids production growth and product mix change should be the focus since cash flow, returns, and earnings will follow liquids growth, and that's how we've defined EOG strategy. I'll now discuss several of our key plays, beginning with the Eagle Ford. I'll start with an editorial comment. I believe Wall Street continues to undervalue our Eagle Ford oil position. Perhaps the undervaluation is disbelief at the sheer size of this onshore position. Not many people can believe the fact that we've captured a 900 million bbl oil equivalent net after royalty position consisting of 77% oil and 11% NGLs with very high reinvestment rates of return. I can't think of a single company, independent or major, who's captured this size net oil accumulation in the onshore lower 48 in the past 40 years.
We're in the first inning of developing this asset, and just like the Bakken, this is becoming one of the hottest plays in North America. EOG, by moving early, has captured the largest acreage position in the crude oil window. We're the biggest producer from the oil window with net production of 23,000 bbl of oil equivalent at the end of the first quarter. Our press release contains multiple individual well results, so rather than providing a well-by-well recitation, I'll provide some context regarding the overall play. There are three key points. First, we are currently drilling with 18 rigs. Simply put, we continue to have 100% success with our drilling results. We've now drilled enough wells throughout our 520,000-net-acre spread to feel very comfortable that all the acreage is good.
Our most recent success is in a new fault block identified on 3D seismic at the northeasternmost end of our acreage, where the Hill Unit Number Two well tested at a 1,233 bbl oil per day initial rate. The results from the wells we drilled across our entire acreage position are very consistent. The wells in the northeast and center portions of our acreage IP at between 800 and 1,500 bbl of oil per day, plus rich gas, while the southwest wells IP at 600 bbl-800 bbl of oil per day, plus rich gas. As with any resource play, the wells exhibit a steep decline the first few years and ultimately level out at 100 bbl-200 bbl of oil per day over the long term. Our per well reserve estimates are unchanged from our previous estimate between 430,000 bbl-460,000 bbl of oil equivalent net after royalty.
Second, project economics have improved with oil prices and our ongoing focus on cost efficiencies. Last quarter, I quoted 65%-110% direct after-tax unlevered reinvestment rates of return using current well costs. Using the current NYMEX oil strip, the per well economics are 95%-140% direct after-tax. Additionally, we still expect to further improve these economics by decreasing well costs from the current $6 million target to our goal of $5 million by 2012 with our self-sourced sand. When combined with the size of the prize, this bodes huge for EOG's future profitability. Over time, we'll invest between $10 billion-$15 billion developing this asset. Again, I can't think of another E&P company or, for that matter, any company in any industry who has captured this magnitude of a very high return reinvestment opportunity.
Third, last quarter I mentioned two Eagle Ford logistics issues: the lack of both frack sand availability and crude oil takeaway capacity. These problems still exist, but so far neither has bitten us. Frack sand availability is still a hand-to-mouth existence, but we've arranged for some temporary fixes until our self-sourced sand arrives later this year. Regarding crude oil takeaway capacity, we've installed a crude-by-rail facility. We're currently moving 4,000 bbl of oil per day and expect to be moving 20,000 bbl of oil per day of Eagle Ford oil by rail by year-end. The concept is the same as our highly successful Bakken crude-by-rail program, where we are moving on average 40,000 bbl of oil per day. Shifting to the Bakken, we continue to be the largest North Dakota oil producer and registered our typical great results from first quarter wells.
As with the Eagle Ford, I won't go into a well-by-well recitation, but will instead provide an overview. We're currently running 10 rigs and are having consistently good results, i.e., 100% success across our 600,000 acres. Aggregate direct economics in the Bakken are 40%-50% after tax. Currently, the Bakken is our largest crude oil component and will continue to be until the Eagle Ford surpasses it in a few years. Our Barnett Combo play is also performing well. We did have weather hurdles during the first quarter with freeze-offs and associated downtime. We expanded our core position to 185,000 net acres. We're running 11 rigs and are achieving good results in both eastern and western portions of the core area, encompassing Cook and Montague counties. At our $3 million well cost, the typical direct ATRORs here are 40%-60%.
In the Permian Basin, we've had further success in Irion and Crockett counties in our Wolfcamp play, where we're running two rigs. Two wells are the Munson 2701H and the University 43-1001H, which had 30-day production averages of 330 bbl-440 bbl of oil per day with 400 Mcf/d-700 Mcf/d of rich gas, respectively. The Wolfcamp is in the early stages of optimization. We recently completed the University 40-1404H well using a different type frack. The well is currently producing 624 bbl of oil per day with 539 Mcf/d, showing good results. We've proven up 44,000 of our 120,000 acres, and by year-end, we'll have the remaining 76,000 acres tested. This area contains multiple separate Wolfcamp pay horizons, so we're excited about the ultimate potential here.
Also, in the Permian Basin, we're running one rig in our Leonard Shale horizontal play and continue to have positive results, such as the Vaca 14-5H well, which averaged 476 bbl of oil per day with 1.2 MMcf/d of rich gas for the first 15 days. We're executing our Leonard development at a relatively slow pace because we don't have the lease exploration issues that we have in other areas. In our DJ Basin Niobrara oil play, recent results have shifted my feeling regarding the play from cautious to optimistic. We've made great strides in improving our understanding of the play on our 80,000-net-acre Hereford Ranch field, where production is 4,000 bbl of oil per day net. During the remainder of the year, we'll test other portions of our 220,000 total net acres.
Industry results to date have been mixed, but we feel pretty good that we've got a significant oil play to develop. However, it will be year-end before we can provide you a reserve estimate. I'll now discuss a play and acreage position we haven't previously disclosed. We have 138,000 net acres in the Powder River Basin and feel this acreage is prospective in multiple pay horizons. To date, we've concentrated a one-rig program drilling wells in Campbell County, Wyoming. So far, we've drilled eight successful horizontal wells into Turner Sandstone. A typical well is the Crossbow 7-6H, which had a 30-day average rate of 275 bbl of oil per day with 100 bbl per day of NGLs and 2 MMcf/d of gas. We'll be testing other intervals on this acreage later this year and in 2012.
The last oil play I'll discuss is our Waskada horizontal field in Manitoba. Our Canadian crude oil production grew 47% year-over-year in the first quarter due to further field development. During the first quarter, we drilled 47 wells and obtained an average IP of 240 bbl of oil per day from this program. Production will remain flat during the second and third quarters due to flooding and spring breakup. Production growth will resume in the fourth quarter when we put more wells online. This area continues to generate 100% direct after-tax rates of return. Turning to the dry gas side of our ledger, we're focusing essentially all natural gas investments in areas where we have to drill to hold acreage: the Marcellus, Haynesville, and to a lesser extent, the Horn River. In the Marcellus, we've added another data point from our 50,000 net acres in Bradford County.
Using our new frack design, the Gynan number 2H tested at 9 MMcf/d. This complements the Hopaw 3H well that we reported last quarter with a 14 million MMcf/d IP rate and provides further confirmation that our acreage is quite good. We have 100% working interest in both wells. In the Haynesville, we've increased our sweet spot holdings by 7,000 net acres. We'll average eight and a half drilling rigs this year, and we're achieving expected results. In Nacogdoches County, the Kerth number 1 IP'd at a restricted rate of 16 MMcf/d with 8,800 PSI of flowing pressure from the Haynesville. In San Augustine County, the Sunrise number 1 well IP'd at a restricted rate of 12 MMcf/d with 8,600 PSI from the Bossier formation.
We continue to make good progress in reducing completed well costs with a 12% reduction in our Nacogdoches and San Augustine County program in the first quarter versus our 2010 results. In British Columbia, our Kitimat LNG project continues to make progress. The two key commercial items that will determine ultimate project viability are the detailed project cost estimate, which is underway, and securing oil-indexed offtake contracts. I continue to be optimistic regarding this project, but I think it will be year-end or first quarter of 2012 before we can determine if this project is a definite go. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Tim Driggers (VP and CFO)
Good morning. Capitalized interest for the quarter was $15.6 million. For the first quarter 2011, total cash exploration and development expenditures were $1.58 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment expenditures were $160 million. At first quarter end 2011, total debt outstanding was $5.2 billion, and the debt-to-total capitalization ratio was 31%. At March 31, we had $1.7 billion of cash on hand, giving us non-GAAP net debt of $3.5 billion for a net debt-to-total capitalization ratio of 23%. On a GAAP reporting basis, the effective tax rate for the first quarter was 41%, and the deferred tax ratio was 34%. Yesterday, we included a guidance table with the earnings press release for second quarter and updated full year of 2011. For the second quarter, the effective tax range is 35%-50%.
For the full year of 2011, the effective tax range is 35%-45%. We've also provided an estimated range of the dollar amount of current taxes it would expect to record during the second quarter and for the full year. For each $1 per barrel change in well-head crude oil and condensate price, combined with the related change in NGL price, the sensitivity is approximately $25 million for net income and $36 million for operating cash flow. EOG's price sensitivity for each $0.10 per MCF change in well-head natural gas prices is approximately $16 million for net income and $23 million for operating cash flow, excluding any impacts from swaptions. Now I'll turn it back to Mark to discuss hedging and provide his concluding remarks.
Mark Papa (Chairman and CEO)
Thanks, Tim. Now I'll discuss our views regarding macro and hedging. Regarding crude oil, we still like both the short and long-term supply-demand fundamentals, although guessing which way short-term oil prices will move is a speculative call. We're currently 27% hedged June through December of this year at a $97 price, and for 2012, we're approximately 6% hedged at a $107 price. We continue to have a one to three cautionary view regarding North American natural gas prices, but believe in the 2014+ time period, natural gas markets will balance as gas power generation demand increases. Our hedges are consistent with our macro view. We're approximately 48% hedged at a $4.90 price for June through December this year. Additionally, we sold options at a $4.73 price that, if exercised, would mean we're 86% hedged through year-end.
For 2012, we're approximately 38% hedged at a $5.44 price, with options that, if exercised, would increase to a 69% hedge level at a $5.44 price. Now let me summarize. In my opinion, there are six important points to take away from this call. First, our shift from a natural gas to a liquids company is essentially complete. At current prices, we expect approximately 70% of our North American revenue to emanate from crude oil, condensate, and natural gas liquids, as opposed to 30% from natural gas. A large majority of the liquids are oil and not NGLs. Second, all of our oil plays are onshore North America, with the vast majority in the U.S. All of this oil is sweet, good quality, and highly desired by refineries. Third, our reinvestment rates of return are very strong. I think they're the best in the industry led by the Eagle Ford.
Fourth, during my visits with shareholders, I'm often asked about industry capital allocation. We recently tabulated 2010 actual and 2011 projected North American gas production for all mid and large-cap public independent E&Ps. EOG is practically the only company who's not growing North American gas volumes in this oversupplied market. This is truly amazing to me. For investors who focus on the efficacy of capital allocation, this should be a positive discriminator in EOG's favor. Fifth, for the first time, we've introduced our Powder River Basin acreage position, where we've already drilled eight consecutive successful wells. Sixth, we are on track to execute our 2011 capital expenditure program while maintaining low net debt. Thanks for listening, and now we'll go to Q&A.
Operator (participant)
Thank you. Question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touch-tone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touch-tone phone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the pound key. We'll pause for a moment to give everyone an opportunity to signal for questions. Our first question today comes from Scott Wilmoth, Simmons & Company.
Scott Wilmoth (VP of Equity Research)
Hey guys, looking at your Eagle Ford rail facility, is that crude coming to the Gulf Coast, and how do the transportation costs compare to trucking your crude?
Mark Papa (Chairman and CEO)
Yeah, Scott, good morning. The crude-by-rail that we're moving from the Eagle Ford is currently either going into the Beaumont area or into the Louisiana area. It is currently getting a price that is a hybrid between WTI and LLS. Compared to the trucking opportunities, where you're not going to end up at those end markets, there's a very significant difference right now. The crude takeaway continues to be a very, very large problem in the Eagle Ford. As Eagle Ford production grows, it's going to just get worse, I believe, in terms of crude takeaway. This rail system that we hastily put in is probably going to turn out to be a very profitable item for us, similar to what we've done in the Bakken.
Scott Wilmoth (VP of Equity Research)
Okay, great. Thanks. Next, on Eagle Ford well spacing, I know at the analyst day, you guys were saying anywhere from 125-140. Can you give us an update on that? What percentage of your acreage have you tested on that spacing yet? Thanks.
Mark Papa (Chairman and CEO)
I guess the overall question is what percentage of our acreage have we tested? We'd say we've tested 100% of our acreage with wells. In terms of the spacing, we're still doing some work to determine what the optimum spacing is. You know the range of wells we'll need to drill is still somewhere between 2,100 and maybe 2,800 wells, depending on how the spacing plays out. That's probably going to be another couple of quarters before we can definitely say, you know the spacing is X.
Scott Wilmoth (VP of Equity Research)
Okay, thank you.
Operator (participant)
Our next question today will come from Leo Mariani, RBC.
Leo Mariani (Senior Exploration and Production Analyst)
Yeah, good morning, guys. Just a quick question on asset sales. Just trying to get a sense of a little bit more color on what these $387 million in asset sales were for the quarter, if there was any production associated with that. Also, any thoughts you guys might have on the $400 million in pending asset sales, if you know what those are and what sort of target you have there.
Mark Papa (Chairman and CEO)
Yeah, the $380 million of asset sales that we announced basically year to date in the second quarter were all long-lived gas producing properties, fairly mature producing properties. The biggest portion of that was some Cotton Valley production, Cotton Valley slash Travis Peak production in the East Texas area. We also sold some production in the New Mexico area. If you kind of take a look at what we produced in terms of gas production in the U.S. gas production in the first quarter, I believe it was 1,134 MMcf/d. I think our midpoint for the second quarter is 1,096 MMcf/d. Do not hold me to that number that I have in front of me, but that kind of shows the, you know, an approximate amount of what we sold that we would expect in the second quarter there.
As to remaining sales for the rest of the year, it is going to be a combination of some midstream assets, some just raw acreage, and some additional producing properties. Did that give you enough color there, Leo?
Leo Mariani (Senior Exploration and Production Analyst)
Yeah, no, that was very good color there.
Maire Baldwin (VP of Investor Relations)
Leo, this is Maire. The year-to-date asset sales is $647 million. That $387 million was subsequent to the first quarter.
Leo Mariani (Senior Exploration and Production Analyst)
Right. Gotcha. Okay. Just looking at your CapEx for the quarter, I guess if I sort of add in your total spending on some of the infrastructure as well, you guys are at about $1.72 billion. Just kind of on a run rate basis, if I were to sort of multiply that by four, I think that gets you kind of between $6.8 billion-$6.9 billion for the year. Just curious as to whether or not you had disproportionately high infrastructure expenses in the first quarter and any comments on cost creep that may have hit you and kind of how you think CapEx plays out for the year.
Mark Papa (Chairman and CEO)
Yeah, now we still believe the CapEx number, you know, mid-range is roughly $6.5 billion for the full year. Part of what we'll see in the second half, particularly in the fourth quarter, is the impact of some of our self-sourced sand, particularly in the Eagle Ford division on our fracs. We'd expect our per well cost to go down. The first quarter run rate isn't, you know, you can't really multiply that by four to get there. In terms of cost creep, we're seeing cost creep clearly in the service sector, and you've heard that from practically everybody who's done an earnings call. The biggest proportion of cost creep is the frac jobs, as it was last year. It's incumbent upon us to move to the self-sourced fracs where I think we'll have a differential advantage relative to others in the industry, and we are moving that way.
Leo Mariani (Senior Exploration and Production Analyst)
Okay, thanks, guys.
Operator (participant)
Next is Joe Allman with JPMorgan.
Joe Allman (Exploration and Production Analyst)
Yes, thank you. Good morning, everybody. Hey Mark, just the first question is, in terms of the new Powder River Basin play and also in the horizontal Niobrara play, what are your current costs per well, and where do you expect them to be when you get into development mode? What's your best guess in terms of EURs per well amount?
Tim Driggers (VP and CFO)
As far as the cost on the Powder River, the Turner, yeah, we started out there. It was right at $6 million per well. We're getting those now down to $5.5 million. Yes, we would expect maybe to trim a little bit more off of those costs in a program mode. In the Niobrara, we've got a couple of plays there within the Niobrara, and more in the fracture play, our cost is around $3.6 million per well. Then we get into the matrix play. It's in the $6 million range. We would expect to be able to bring that down in the $5 million-$5.5 million range.
Joe Allman (Exploration and Production Analyst)
What are the EURs per well?
Loren Leiker (Senior EVP Exploration)
Yeah, on the Turner itself, it's a little too soon to tell. We've given you a pie chart in the, I think, in the IRR slide that went out last night that shows that it's about 45% liquids, 55% gas, but that's for the full reserve life of the well. Obviously, we've had to do an internal model to come up with those numbers. It's a higher liquids yield in the first couple of years, as in all these retrograde condensate-type plays, that yield will come down over time. We're modeling a variety of EURs per well, but something in the 350 MBOE-400 MBOE per well growth is our sort of walking around number right now.
Mark Papa (Chairman and CEO)
Yeah, on the Niobrara, it's a bit too soon to give you an estimate on per well reserves. The Niobrara is clearly a more complicated play, and I'd say our degree of understanding is not yet sufficiently strong where we feel comfortable giving either an overall reserve estimate on our captured acreage or a per well basis. That's probably going to have to wait till the end of the year.
Joe Allman (Exploration and Production Analyst)
All right, thank you.
Operator (participant)
Next, we'll hear from Brian Singer with Goldman Sachs.
Brian Singer (Senior Equity Research Analyst)
Thanks, good morning.
Mark Papa (Chairman and CEO)
Hey Brian.
Brian Singer (Senior Equity Research Analyst)
Mark, as you highlighted in your comments, you are implying a big ramp-up of oil production in the third and fourth quarters. That certainly makes sense if there's a weather-impacted wall of oil offline waiting to come back when those weather issues subside. Can you try to quantify the impacts that the weather issues in the Bakken and Williston are having on your current production in terms of what may be shut in or the extent of the potential that would be in backlog by the end of the quarter?
Mark Papa (Chairman and CEO)
Yeah, a wall of oil, that's a good way to characterize it there. Specifically, I'll give you a little color as to what's happened to us, particularly in the second quarter. The second quarter, we had flooding that affected us both in Waskata and in the Bakken, and this was just simply high water where we couldn't have our pumpers access wells to physically maintain them. Last weekend, we had in North Dakota a very severe late-season ice and high windstorm that knocked literally hundreds of thousands of power lines in the area of Williston as well as our field area. We're pretty much without electricity. The power companies are trying to restore it, but obviously, they're giving first priority to things like the city of Williston, the hospitals, the schools, the residential. We're kind of one of the later priorities to get it out into the field operations.
We don't really know how long the power outages are going to last. What's loaded into our estimate for the second quarter for our oil estimate is we're assuming that we're going to get hit for the entire month of May with some pretty significant power outages that are going to affect our North Dakota production. If you just look at the ramp-up that we'll need in the third and fourth quarter to get us to our full-year target, it looks like a pretty steep ramp-up.
I don't want to give you specific quantifications, but what I can tell you is that the third and fourth quarter of the ramp-ups in terms of where they're going to come from in the Bakken, you're clearly going to have a snapback of production in the third and fourth quarter relative to what we're going to achieve in the second quarter just as we get these weather issues and downtime eliminated. The biggest single driver of production growth is going to be the Eagle Ford. We've articulated a series of wells there in the Eagle Ford and in our press release. I would just say, obviously, the more wells we drill with 100% success, the turnout, as we predicted, the higher our degree of confidence is getting that the production target in Eagle Ford is quite achievable.
We also articulated in the Barnett Combo play that we're having pretty good success there, and that's going to be a driver also. Those three plays, Eagle Ford first, snapback in the Williston Basin area, Bakken area, and then the Combo play, are going to be our main drivers of the production growth in the second half. There will be contributions from the Permian Basin, the Mid-Continent, and from Canada. Because our pace of activities in those areas, the number of rigs we're employing is not nearly as high, the contributions there are not going to be all that great in relative terms compared to the first three plays that I mentioned. The punchline is, and I guess let me put it this way, we had a cushion on our oil estimate for the full year, 55% year-over-year going into the second quarter.
We had a little bit of fat in our estimate. This second quarter downtime has pretty much consumed that little cushion. We're still comfortable with our estimate, but we don't have the cushion that we once had due to these weather issues.
Brian Singer (Senior Equity Research Analyst)
That's helpful. That's very helpful, thanks. Secondly, you spoke last quarter regarding proprietary completion methods in the Niobrara. This quarter, you mentioned a new completion in the Marcellus. Are any of these related? Are you doing things differently in terms of completion technique across plays that are having a material impact on economics? Can you put that into context in terms of what that could mean both for the two plays and for the ability to unlock any additional play?
Tim Driggers (VP and CFO)
Yeah, Brian, what we can say about that is, yes, you're right. We are using different completion techniques specifically designed for each play, and they vary widely from area to area. In the Marcellus, we've done one thing that's made tremendous differences in our wells, and we're experimenting with new techniques in the Niobrara. We have multiple play types in the Niobrara, so each play type has a specific completion technique that's proprietary to EOG. We can't really talk much about the details, but we work really hard gathering the data, analyzing the data, and continue to refine our completion techniques for each play. They're very specific, and it's working out really good for the company.
Mark Papa (Chairman and CEO)
Yeah, Brian, just to give a little more color on that, obviously, there's the mixed results from the Niobrara from various companies in the industry, whereas you've heard fairly consistent results on EOG's results in the Niobrara. In the Wolfcamp, if I kind of read some of the earnings data that's come out here from other companies, you're getting kind of mixed results from other companies in the Wolfcamp, whereas EOG, you know, we're pretty well nailing it in the Wolfcamp. Every well is good, and we think getting better. I really think this goes back to EOG being first mover in these plays. I continue to believe that we are number one in technology in horizontal oil plays. That means finding them before everybody else, and it means figuring out how to complete the wells and frack them most efficiently.
I just think the Wolfcamp example is just the latest in a long string of cases where EOG wells are better than results from other companies.
Brian Singer (Senior Equity Research Analyst)
Thank you.
Operator (participant)
Irene Haas, Wunderlich Securities has a question.
Irene Haas (Energy Equity Analyst)
Yeah, I kind of want to drill down a little bit on the Niobrara. I mean, from what I hear, if there's a sorting out process, and even you mentioned there are various sub-plays, and you know the cost for drilling a fracture well versus matrix well is quite a bit different. Just trying to get a sense as to, number one, Mark, why do you feel optimistic? Because there's definitely different usage of adjectives from before. How can we look at this play? Is it going to be a core area, non-core, or is it going to be sort of patchy depending on a specific geology?
Tim Driggers (VP and CFO)
I think it's too early to say really about the full extent of Niobrara. We're in the process of drilling multiple step-out wells on our acreage. The Hereford Ranch has had very encouraging results both in the fractured type play and in the matrix type play, which gives us encouragement. We see those characteristics in much of our acreage. We're in the process of gathering data. We have some very proprietary techniques to evaluate the particular play types, and we've got some techniques that we're trying on the completion side. At this point in the development of the play, they're getting really positive results, which gives us encouragement as we go forward.
Irene Haas (Energy Equity Analyst)
Would you, it seems like the matrix plays are more expensive than the sort of fracture play. Is that correct? If that's the case, would you favor the more fractured zones, or is it too early to tell?
Tim Driggers (VP and CFO)
The plays are different in that the matrix plays will have a higher resource recovery, and you're able to drill more wells per acre or per section. The economics really on both play types we think are going to be very strong. We want to pursue our acreage and our techniques, match all that together to maximize the reserve recovery of our acreage. We feel positive and very encouraged about both types as we go forward.
Irene Haas (Energy Equity Analyst)
Okay, great. Thank you.
Operator (participant)
Biju Perincheril with Jefferies has our next question.
Biju Perincheril (Analyst)
Hey, good morning.
Mark Papa (Chairman and CEO)
Hey, Biju.
Biju Perincheril (Analyst)
Going back to the Powder River Basin, can you talk about if you have tested Niobrara there, you see the potential for Niobrara?
Loren Leiker (Senior EVP Exploration)
Yeah, Biju, we said we had 138,000 net acres in the Powder, and we're really mapping and working up six independent targets. Four of those are sandstones, including this Turner that we're doing work for drilling on so far. The other three are these upper Cretaceous, so-called halo plays that others have talked about, which we do think are prospective on a portion of our acreage. A couple of shale plays, and one of those is, in fact, the Niobrara. We are intending to test the Niobrara either late this year or early next year, waiting on permits in a couple of areas. We certainly see prospectivity in the Niobrara in that basin.
Biju Perincheril (Analyst)
Okay, that's helpful. Is the CapEx, the $1.58 billion, all-inclusive or just inclusive C and D excluding facilities?
Tim Driggers (VP and CFO)
That's inclusive. In that number, it's not inclusive. The facilities number in there was a mixed additional $160 million for facilities.
Biju Perincheril (Analyst)
I'm sorry, is that one specific additional or?
Tim Driggers (VP and CFO)
Yes.
Biju Perincheril (Analyst)
Okay. Can you talk about, you know, once you bring in the self-sourced sand solution, how much you expect to save and the timing of that?
Tim Driggers (VP and CFO)
Timing and on the self-sourced sand plants, we have quite a number of the sand plants in place now. What we're doing is sourcing our own proppant, and generally, we're doing that through contract. We've got one sand mine in place, and we're working to bring another online, and that'll be near the first of the year of 2020.
Biju Perincheril (Analyst)
Okay. If I sort of take this first quarter CapEx, it looks like the run rate is a little higher than the annual budget. Are you factoring in some savings, or I mean, I would imagine the second half completion pace would have to pick up to meet the production numbers?
Mark Papa (Chairman and CEO)
It just depends on which play. For example, in the combo, we're really going to be running less rigs in the second half of the year than in the first half of the year. All I can say on CapEx is we expect to achieve the number that we're showing in the guidance last night.
Biju Perincheril (Analyst)
Okay. There is one last question on the rail line in the Eagle Ford. Is 20,000 bbl the max capacity or are there plans to build that out further, and is there a CapEx number there too?
Mark Papa (Chairman and CEO)
Yeah, what we did in this rail line at Eagle Ford, it's a, I don't want to use the word makeshift, but it's one we put together in a 30-day period. It's, you know, realizing the criticalness of the takeaway for crude oil in Eagle Ford. We knew we couldn't basically take an eight or nine-month period to get a rail line crude-by-rail constructed as we did in North Dakota. We just took our learnings from North Dakota and said, what can we get together on a temporary basis that's going to cover us? It's not obvious to me that we'll end up with north of 20,000 bbl a day capacity by year-end. Whether we decide to permanently run that rail line or not is something we'll have to sort out. As you remember, what we're trying to do is bridge the gap between today and mid-2012.
Mid-2012 is when Enterprise is supposed to have that big-inch oil pipeline going down pretty much the heart of our acreage position. We're just, in other words, if we were to invest the capital right now and say, let's build a real, true, absolutely permanent crude-by-rail facility there, it's not certain that we'd be needing it post-mid-2012. The amount of capital we spent on this rail system is pretty de minimis, less than $10 million. It's not a big capital-consuming item. It should be viewed at least right now as an alternative to the trucking that gets us to a higher-priced end-user market, refinery market, if you will.
Biju Perincheril (Analyst)
Got it. Thank you. That's helpful. Appreciate it.
Operator (participant)
Next is John Caldwell, Wells Fargo Advisors. Mr. Caldwell, your line is open. Please go ahead. If you are on a speaker phone, please pick up your handset or depress your mute function. Do we have John Caldwell? Hearing no response, we'll take our next question, Eric Hagen, Lazard Capital Markets.
Eric Hagen (Oil and Gas Analyst)
Yeah, [it was Eric] on my question. Sorry to be out of queue.
Operator (participant)
Thank you very much. Next, we have John Herrlin, Societe Generale.
John Herrlin (Equity Analyst)
Hi, I've got a couple of unrelated ones. Mark, in terms of your total well count right now, or rig count rather, how much is horizontal in total that you're going to spud this year versus vertical?
Tim Driggers (VP and CFO)
We've got currently 72 rigs, and as we mentioned last quarter, we'll be running probably the average 75-78 rigs. Of that, I would say 80% of that is going to be horizontal.
Mark Papa (Chairman and CEO)
Yeah, if I pull a number out of the air, I might even say 85% or 90%. It's pretty rare when we drill a vertical well anymore, John.
John Herrlin (Equity Analyst)
Okay, that's what I thought. I was just confirming. What about lateral lengths? Are you going longer? Are your frac stages increasing? How have you changed your well designs?
Tim Driggers (VP and CFO)
We are going with longer laterals. For instance, in the Bakken, probably 75% or 80% of those wells are going to be the 1,280s or 10,000 ft laterals. We've drilled as long as 14,000 ft laterals there. That's just kind of been the trend in most of our areas. Yes, when you go with the longer laterals, you have larger completions, additional stages, and additional proppant requirements.
John Herrlin (Equity Analyst)
Are your drilling time efficiencies offsetting some of the completion costs?
Tim Driggers (VP and CFO)
Yes, that's how we are, in addition to us doing the self-sourcing and also us sourcing our own profit, etc., for our stimulation jobs. For instance, in the Haynesville, we've reduced our days by about 20%. We've also continued to alter our stimulations there. We've reduced our well costs there from the start of the year by somewhere between 15%-18%.
John Herrlin (Equity Analyst)
Last one from me. You've had some of your competitors talk about being more integrated. You just mentioned that you're mining your own sand as profit. Does that work for you, or just as a business model, does it make sense to you to be more integrated on the services side?
Mark Papa (Chairman and CEO)
Yeah, John, we're certainly not going to integrate ourselves to the tune of buying and drilling rigs. That's not at all what we're considering. On the frac side, what we've been doing in the Barnett, both in the Barnett gas and the combo areas for the last three or four years, is we've been using our own line sand and using third-party contract pumping companies, not necessarily the majors, and going that route as opposed to building our own frac pumps and manning our own frac pumps. We have a business model that seems to work for us. It's worked in the Barnett for the past four years.
That's what we're really looking at doing most everywhere, not having the frac pumps owned by EOG, but having a third party operate those, kind of contracting them, kind of like we contract drilling rigs, and have us provide the profit to those particular pumps.
John Herrlin (Equity Analyst)
I remember when you helped start some of the companies, you talked about that a few years back. I was just wondering if you're going to increase the scale, you know, just given how you're operating.
Mark Papa (Chairman and CEO)
The scale in terms of the fracs, the frac generally is roughly 50% of any of these resource play costs, total well costs, 50%. That's the piece we're really attacking to say we have to get control of our frac costs and not be dependent on the traditional service companies if we're going to be the cost leader in this resource play business. I think we're quite a bit ahead of most everybody else on where we're moving on that piece of the business.
John Herrlin (Equity Analyst)
Great, thanks.
Operator (participant)
Next is Joe Magner with Macquarie.
Joe Magner (Managing Director)
Good morning. With the successful test of the northeastern fault block in the Eagle Ford, can you just remind us how that's captured in your 900 million bbl resource estimate?
Mark Papa (Chairman and CEO)
Yeah, Joe, as I kind of stated in my editorial comment there, I don't believe the 900 million bbl is even remotely captured in our current stock price. If we were to say, wow, we have a new fault block and it increased our barrel, you know, from 900 to X, I'll consider doing that if and when I see the 900 million bbl that we already have reflected in the stock price. Do not look for us to make any adjustments to the 900 million bbl based on one well, one fault block, or anything like that. Obviously, it's an area that we hadn't given any credit to, and then we found it on the 3D seismic and drilled it.
Right now, this Eagle Ford is turning out to be one of those things that you almost have to pinch yourself and say this is too good to be true. A 100% success rate across 120 mi is just phenomenal. That's a good non-answer to your question, but that's the explanation I'll give you, Joe.
Joe Magner (Managing Director)
All right, I'll take that for now. Just over on the Niobrara, I'm wondering if you'd be willing to comment. There have been some challenges discussed by industry participants between completing wells in the fracture area and the matrix area. Just wondering if you'd be willing to comment on any progress you've made overcoming some of those challenges or coming up with solutions to address those.
Tim Driggers (VP and CFO)
Yeah, Joe, I think we're just not quite sure how much the two types of completion techniques are integrated and how they're competing. We're just really gathering data on all that. We're doing micro seismic and other techniques to determine and figure out how those plays work. I'd say we're just really too early to say much about that.
Mark Papa (Chairman and CEO)
Yeah, Joe, the one thing we will offer up there is that there seem to be a couple of different play types, fracture versus matrix, and it's really leading us to two distinctly different completion types depending on, you know, where we are in the Niobrara. That's what's made it a little bit harder and slower for us to really kind of get a handle on what kind of an oil field we really have captured here because we kind of have night and day completion techniques depending on which particular type of rock we're attacking with that particular well.
Joe Magner (Managing Director)
Are you able to understand the type of rock you're going to be completing based on seismic or some sort of mapping? How do you determine going in which completion technique you're going to be able to use on that well?
Mark Papa (Chairman and CEO)
I would just say right now, we think we have a proprietary edge on our understanding of the Niobrara, and we really don't want to give any more of it away on this call.
Eric Hagan (Lazard Capital Markets.)
Okay, fair enough. Thanks for the time.
Operator (participant)
Next, we hear from Richard Durnley with Longport Partners. Mr. Durnley, your line is open. Please go ahead. If you're on a speakerphone, please pick up your handset or depress your mute function. Following our response, we will move to David Tameron, Wells Fargo.
David Tameron (Managing Director)
Thanks, Tom. Good morning. A couple of questions. If I just look at the acreage positions, it looks like you sold down your Niobrara. You're at, I guess, 220 net now. Is that the right number? Then similar in the, you sold down 70,000 or so in the Eagle Ford. Is that accurate?
Mark Papa (Chairman and CEO)
No, in the Eagle Ford, that's not accurate. When we talk about the 520,000, that's how much is in the oil window. We've got roughly another 70,000 that's in either the wet gas or the dry gas window. There's been no change in our aggregate Eagle Ford acreage position. In the Niobrara, yeah, we have sold a bit of acreage there. That's, you know, really didn't want to, but this is part of what we need to do to raise the $1 billion in property sales for this year.
David Tameron (Managing Director)
Okay, fair enough. If you think about the Wolfcamp, can you talk about, from our perspective, modeling, etc., what decline rate should we be thinking about? I know it's early, but what have you seen from these wells? Can you just give some color there?
Loren Leiker (Senior EVP Exploration)
Yeah, what we have so far in the Wolfcamp are six wells with completions, and five of those we have online long enough that we can do good 30-day averages with some confidence. Of those five, we actually talked about four of them on the IR slide, I believe, and they averaged about 350 bbl of oil per day. The one that didn't make the slide was an earlier shorter lateral that averaged about 190 bbl of oil per day in its first 30 days. Decline rates are kind of similar to what we're seeing in a lot of these oil plays. They're fairly steep in the first few months, and then they tend to flatten out. We've given you, in the past, I think, 270 MBOE or 1,000 bbl of oil equivalent net after royalty per well is the number that we're working with right now.
I'd say that based on these first four wells, we're pretty confident we can hit at least that. In fact, they're a little bit above the curve at present. We've also given you a breakdown that shows about 55% oil and 23% NGLs for a total of 78% liquids over the life of that and only 23% gas. I would say in terms of decline curves, they're not dissimilar to our other oil plays.
Mark Papa (Chairman and CEO)
Yeah, David, I'll give a little more color in addition to what Loren said on the Wolfcamp. We're particularly enthused about the Wolfcamp, our 120,000 acres. If you look back, I believe it was our previous quarter's IRR presentation, we quoted a kind of a direct IRR on that after tax of roughly 25%, I believe. If you just looked at the numbers, you'd say the Wolfcamp is a lower return play than the rest of our oil plays. What that 25% kind of represents is stage one of optimization on the Wolfcamp. We think that we can easily beat down the costs on the Wolfcamp play, particularly with self-sourced sand in that particular play, and probably get higher reserves. I guess what we'd say is we're in the first half inning of the Wolfcamp.
If we're in the first inning of the Eagle Ford game, we're in the first half inning on the Wolfcamp. The data we see today tells us that we can turn this into a rate of return play that's probably similar to the Bakken or the Combo once we get into some kind of optimization mode on it. For the rest of this year, what we're going to be doing in the Wolfcamp is exploring so that we've got at least one well down in pretty much all the portions of our 120,000 acres. Right now, we're only kind of concentrating on, I believe, it's 47,000 of those acres. We're going to be working on that and then working on what can we do with both well costs, length of laterals, optimization to fracs.
For example, the well I mentioned in the earnings call, the last well I mentioned there, we tried a completely different frac style than we'd done on the first several fracs. It looks like we have a better result based on early times. I would say we rank Wolfcamp pretty high on our priority list. It's really, as far as a contributor to EOG volume growth and really getting into a drilling mode, that's going to be a 2012 event for us.
David Tameron (Managing Director)
All right, no, a lot of good color. Thank you. Appreciate it.
Operator (participant)
Our next question comes from Ray Deacon, Pritchard Capital Partners.
Ray Deacon (Senior Research Analyst)
The questions have already been answered. Thank you very much.
Operator (participant)
Thank you. Next is David Wheeler, AllianceBernstein.
David Wheeler (Senior Research Analyst)
Morning.
Mark Papa (Chairman and CEO)
Hey David.
David Wheeler (Senior Research Analyst)
Congrats on the commendable results and operational update. We appreciate it. On the returns in the Eagle Ford, you mentioned the returns are 95%-140% at the strip, but at a $6 million well cost. If well costs come down to $5 million, what does that do to the returns?
Mark Papa (Chairman and CEO)
Yeah, they're almost sinful to repeat. You know, they're consistently north of 100%, is, you know, what we can say. It makes a big difference to knock it from $6 million-$5 million. That's why I'm so excited about the play, David, is, you know, we're looking at a play that, at least on a direct basis, is going to yield us north of 100% rate of return for $10 billion-$15 billion of investment. If you think across every other single E&P company in the world, I can't think of one who's got this sort of investment opportunity, particularly in a, let's say, a relatively benign climate like Texas and the United States as opposed to some foreign country. I really think that people just haven't realized exactly what EOG has captured here.
Again, I'm sorry, I'm going off on an editorial comment, but you led me into it there when you said what happens with the well cost gets knocked down $1 million a well.
David Wheeler (Senior Research Analyst)
Sounds like it could be its own company there. The self-sourcing, and you mentioned the Wolfcamp wells, how much could well cost come down in your other plays, self-sourcing fracking? You've talked a lot about how you're going to do it in the Eagle Ford. How many different plays can you self-source, and how much could cost come down in those plays?
Speaker 18
We could, yeah, we're looking at all of our large resource play where we've got pattern drilling and completion. Right now, we've got about 50% of our frac fleets that are the self-sourced or dedicated or daywork sort of fleet. You know, and you we'd probably rather not say right now. We're still putting our interim fan in place, and then we've got the large mine that'll be coming on late this year, first of the year. It makes a significant impression on our cost. When Mark mentions going from $6 million-$5 million, a big part of that is associated with the dedicated fleet and our own profit.
Mark Papa (Chairman and CEO)
Yeah, I think the same range of numbers, roughly a $1 million reduction, is what we're envisioning for the Wolfcamp, for example. Right now, our priorities for the self-sourced sand are first the Eagle Ford level. First of all, all of our Barnett stuff is currently self-sourced. In terms of new fields, Eagle Ford is first priority. Wolfcamp is probably second priority. Marcellus, probably third priority as we would see it today. These will get melded in beginning late this year, and hopefully by mid-2012, we've got them all, all three of those areas working with the self-sourcing.
David Wheeler (Senior Research Analyst)
That's great. Can you remind us, it sounded like you didn't want to compare the trucking cost out of the Eagle Ford versus the new rail cost. As we go from trucking, rail to ultimately pipeline, what's the approximate improvement in the cost per barrel?
Mark Papa (Chairman and CEO)
Yeah, on the first part of that, I mean, we'll give you a general number. You know, the rail versus the trucking current conditions, we're probably in the Eagle Ford, we're probably gaining $4-$5 a barrel, you know, versus trucking on there.
David Wheeler (Senior Research Analyst)
Is that cost and realizations combined?
Mark Papa (Chairman and CEO)
Yeah, that's cost and realizations combined because we're not getting full LLS price right now. We're having to share that with some terminal operators, you know, with the terminus of the line over there. Ultimately, the pipeline cost is going to be, I guess, very pleasant relative to either the current rail or certainly the current trucking cost. Right now, the pipeline terminus is basically the Houston area. We'll be getting into the Houston Ship Channel, which, you know, oil prices today delivered at Houston Ship Channel are about midway between LLS and WTI on there. At this juncture, the rail is not obvious as the long-term answer once that pipeline gets in. It looks like the pipeline would be the cheapest, David.
David Wheeler (Senior Research Analyst)
Okay. That's great. Thank you very much.
Mark Papa (Chairman and CEO)
Thank you.
Operator (participant)
That does conclude our question and answer session. I will now turn the conference over to our host for any closing or additional remarks.
Mark Papa (Chairman and CEO)
I have no further closing remarks. Thank you very much, and we'll talk again next quarter.
Operator (participant)
Thank you very much. That does conclude today's conference call. Thank you for your participation.