Everyone and welcome to the EOG Resources Second Quarter 2012 Earnings Conference Call. As a reminder, this call is being recorded. At this time for opening remarks and introductions, I'd like to turn the call over to 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 Q2 2012 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 also includes certain non GAAP financial measures.
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 may include 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 and Investor Relations page of our website. With me this morning are Bill Thomas, President Gary Thomas, Chief Operating Officer Tim Driggers, Vice President and CFO and Margaret Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website last night and we included Q3 and full year 2012 guidance in yesterday's press release. This morning, I'll discuss topics in the following order. I'll initially review our Q2 20 12 net income and discretionary cash flow.
Then Bill Thomas and I will provide operational results in our second half 2012 and preliminary 2013 business plan. Tim Dreyers will then discuss financials and capital structure and I'll follow with our macro view and hedge position and finish with concluding remarks. As outlined in our press release, the Q2 of 2012, EOG reported net income of $395,800,000 or $1.47 per diluted share. For investors who focus on non GAAP net income to eliminate mark to market impacts and certain non recurring items as outlined in the press release, EOG's Q2 2012 adjusted net income was $312,400,000
or $1.16
per diluted share. For investors who follow the practice of industry analysts who focus on non GAAP discretionary cash flow, EOG's DCF for the 2nd quarter was $1,400,000,000 I'll now address our operational results in key plays. During the Q2, all three of our production components approached or exceeded the high end of our 8 ks guidance. Our total crude and condensate production was up 52% year over year and total liquids were up 49% year over year. Total EOG 2nd quarter year over year production growth was 16.5%.
North American gas was down 7% as predicted, but Trinidad gas was up 21% due to higher contract takes. Our aggregate unit costs were below projections. As we did on the Q1 call, we are again increasing our full year 2012 total company liquids production growth target, this time from 33% to 35%, consisting of 37% crude and condensate growth and 31% NGL growth. Our total company growth target has also increased again from 7% to 9%. As we've previously stated, because of the value imbalance between crude oil NGLs and natural gas, EOG's focus has been primarily on oil growth, which will continue to drive year over year increases in EPS, adjusted EBITDAX and DCF.
The current imbalance between oil and gas is a 33:one ratio. In the Q2, our year over year increase in GAAP EPS was 34%. Adjusted EBITDAX growth was 19% and DCF increased 20%. During the last three years, EOG has proven to be the large cap independent E and P with the highest annual absolute organic crude oil growth rate with increases of 35%, 52% and projected 37% for this year. This growth is more amazing when you consider we've sold $3,200,000,000 of assets during this period.
A chart in our most recent IR presentation shows EOG is the industry leader in horizontal oil production by a 2:one ratio over the number 2 producer. Additionally, we have quite a substantial amount of North American natural gas reserves in large resource plays, which we've inventoried until market conditions improve. I'll now discuss the plays driving our extraordinarily high organic oil growth rate starting with the Eagle Ford. On our May earnings call, I described EOG's Eagle Ford position as our 800 pound gorilla. Based on results in the past 90 days, we still continue to believe our acreage is the largest domestic net oil discovery in the past 40 years and generates the highest tax reinvestment rate of return of any current large hydrocarbon play.
We're the largest crude oil producer in the play with 103,000 barrels of oil equivalent per day net production for June, 76% of which was oil and 14% was NGLs. I'll now discuss 5 key points regarding the Eagle Ford. First, this has been our strongest quarter ever for completion of what I'll call monster oil wells, which I'll define as wells having IP rates of 2,500 barrels of oil a day plus gas and NGLs. Our press release lists several of these, but by my count, we had 16 wells with initial production rates between 2,500 and 4,800 barrels of oil per day plus gas and NGLs this quarter, all in which EOG has 100% working interest. The 16 Monster wells in 1 quarter is particularly startling when we haven't seen any announcement by other Eagle Ford operators of even one such monster well to date.
This is a testament to both the quality of our acreage and our completion expertise. During the quarter, we set a new record for the best single well, the Boost 10H, which IP ed at 4820 barrels of oil per day with 7,500,000 cubic feet a day of rich gas, which is the upper limit of our testing facilities. 2nd, our rate of learning on optimizing oil recovery from this asset continues to dramatically improve. During the quarter, we made excellent technical progress in understanding how to get more oil out of the Eagle Ford and the results are showing up in improved well quality. For proprietary reasons, I'm not going to go into specifics here other than to let you know I'm directionally very pleased with the results and they're showing up in our well results like the booth number 10H.
3rd, we plan to drill 3 30 net wells this year up from the 300 we previously indicated. Because our drilling time per well has declined from 21 days in 2,009 to the current 14 days, but dropped from 23 to 20 rigs during the second half of the year. We also front end loaded our 2012 Eagle Ford completion activity. So consequently, our rate of production growth will moderate in the second half. In the first half of the year, we brought 179 wells to sales and plan to bring 145 wells to sales during the second half.
These nuances have been taken into account in our second half guidance. 4th, we're now connected to the Eagle Ford or excuse me, to the Enterprise oil pipeline and the new Enterprise natural gas processing plant and pipelines. So the go forward concern regarding takeaway bottlenecks is considerably reduced. Essentially, all of our Eagle Ford oil is currently priced off an LOS index. And 5th and finally, our logistics regarding our self sourced Wisconsin frac sand have performed smoothly all quarter and our frac cost savings are still $500,000 a well.
However, I will note that we are now pumping bigger fracs and this has offset our cost savings. Combined with the higher cost of gel, our average well cost is about $6,000,000 per well higher than our $5,500,000 target. We've previously given you typical economics noting we expected an 80% direct after tax reinvestment rate of return or $5,500,000 well cost. For the first half of this year, our actual direct after tax reinvestment rate of return exceeded 80 percent using the actual well costs. So our impressive economics are still intact.
To summarize the Eagle Ford, it continues to improve better than expected and I expect to see further improvements in well quality and reserve recovery. We continue to test tighter spacing in the play. I'll now turn it over to Bill Thomas to discuss the Bakken, Wolfcamp and Combo plays.
Thanks, Mark. Last quarter, we advised you that we were more optimistic about the Bakken and Three Forks as growth vehicles than in the past several years for 3 different reasons. I'll give you some updates regarding these reasons. First, 320 Acre Enfield Drilling in the Bakken core continues to generate positive results. The press release shows from several new infield wells.
The reason we're so excited about EOG's core area downspacing is that our 90,000 net acre core is the sweetest spot in the entire Bakken, and it's where 22 of the 30 best Bakken wells in the entire play have been drilled. So this is a rich honey ground for downspacing. With our Bakken acreage now held by production, we are shifting our focus to increasing the recovery factor with downspacing and improved frac technology. 2nd, we continue to have great results in our Antelope Extension area, which is 25 miles southwest of the core area. Typical recent wells here are the Riverview 1003031H and four-three thousand and thirty one H was tested at rates of 1834 barrels of oil per day and 1863 barrels of oil per day, plus rich gas from the Three Forks and Bakken respectively.
3rd, the 3rd growth area is our Stateline area where we recently completed the Stateline 83328H in Eastern Montana at 12 60 barrels of oil per day. With confirmed success, we estimate 200 potential locations in this area. As you can see, we have plenty of room to run-in the Bakken Three Forks. Additionally, we continue our Bakken core waterflood pilot project and we expect to have preliminary results by year end. Shifting to our Permian Basin Wolfcamp and Leonard horizontal plays, our results continue to be consistent with previous quarters.
Recent Wolfcamp completions are the Munson 1000 and 1H, 1002H, 1003H and University 40 three-eight-sevenH wells, which IP ed at 1110, 8 56, 10.15, and 7.60 barrels of oil per day, respectively, plus rich gas on the middle interval. We are currently completing a couple of Wolfcamp wells in the upper zone and expect results later in the year. In the New Mexico Leonard, the Ross Draw 8, Fed 2H and Ross Gulch 8, FedComm 1H tested at 7.22-five forty barrels of oil per day with 270,145 barrels per day of NGLs and 1,901,000,000 cubic feet per day of natural gas, respectively. We have 88% and 91% working interest in these wells, respectively. Also, a significant liner step out, the 100% working interest pitch blend 29, FedComm 1 was successful and tested at 10 26 barrels of oil per day with 120 barrels per day of NGLs and 650 Mcf per day of gas.
This well sets up a lot of additional locations. To summarize, our Permian Basin program is generating excellent results. We continue to test spacing and multiple targets in both plays and we believe our 240,000 acres have significant upside for EOG. In the Barnett combo, our results are consistently good. In the Q2, we completed a 4 well pattern on our Tatum and Tatum A units with initial per well rates of 4 100 and 600 barrels of oil per day with 100 to 100 to 140 barrels per day of NGLs and 700 to 900 Mcf per day of residual gas.
Our drilling times continue to improve, allowing us to drill more wells with fewer rigs, and we expect to complete 200 net wells this year. We've also been able to avoid any gas processing pinpoints that we were concerned about earlier in the year. In addition to our big four oil plays, we continue
to have smaller levels of horizontal oil activity in the Mid Continent, Powder River Basin, Southern Manitoba, etcetera. And we continue to test new horizontal oil play concepts. Now I'll turn it back to Mark. Thanks, Bill. Outside North America, we still expect our 100% working interest East Irish Sea Conway Crude Oil Development project to start up in the second half of twenty thirteen.
We recently installed the platform and expect to commence drilling in the Q1 of 2013. In Argentina, our first horizontal Vaca Muerta oil well has been completed and is under evaluation. We hope to have some definitive results on next quarter's call. In Trinidad, recent gas takes have been higher than expected due to higher indigenous gas demand. We expect some methanol and ammonia plant maintenance downtime in the second half and our full year guidance projects only slightly higher full year 2012 Trinidad gas production compared to 2011.
There's nothing new to report on the Kitimat LNG project. I'll now address 2 other key EOG differentiators crude by rail and sand plants. Our St. James, Louisiana crude by rail facility has been operational since mid April and the impact showed up in our overall Q2 U. S.
Crude oil realizations versus WTI. The terminal construction cost is already paid out. Now that the Eagle Ford oil pipeline is operational, we've moved a number of railcars to the Bakken and we're primarily using the crude by rail system to move our Bakken crude to Louisiana capturing the current $20 differential between Clearbrook, Minnesota and St. James, Louisiana. During July, we're selling about 20 excuse me, about 50,000 barrels gross at St.
James and we expect this volume to increase to approximately 80,000 barrels of oil a day by year end as more tank cars become available. Our Wisconsin frac sand system is also working as planned. The first sand shipments began late last year and in combination with our Fort Worth plant is currently providing our frac sand needs for more than 700 wells this year. Most importantly, the sand cost savings to our Eagle Ford program is still $500,000 a well. We've recently had several investor questions regarding NGLs and ethane rejection.
In the Q2 and also in July, we experienced only minor NGL curtailments. Most of our NGLs are processed at Mont Belvieu and not Conway. During the past few weeks, we've seen ethane prices rise as ethylene plants have come online after the planned maintenance shut ins of the first half of the year. As a reminder, in the second quarter, only 9% of EOG's North American revenue emanated from NGLs with 78% emanating from crude oil. Now I'll discuss our second half 2012 and preliminary 2013 business plan.
Because we're happy with our first half results, we're making only a few minor changes to our original 2012 plan. In the Eagle Ford, we plan to shift part of our drilling activity to the West and we'll be drilling a number of lower working interest wells. We've also reduced the number of rigs due to increased drilling efficiencies. On the natural gas side, the changes to our plan involve dry gas drilling. As previously disclosed, we plan to spend about 10% of our CapEx this year or about $750,000,000 on dry gas drilling in the Haynesville, Horn River and Marcellus to HBP, our acreage positions.
Essentially, all of these gas resource plays will be in good shape by year end 2012 as far as acreage holding. We also noted we would likely spend 5% on dry gas drilling next year. We now feel that our natural gas expenditures this year will lock up essentially all of the dry gas acreage we plan to keep and that unless 2013 gas prices rise dramatically, we will spend very minimal CapEx in 2013 on dry gas drilling. We will likely run only 1 dry gas rig next year. This will allow us to concentrate 2013 on oil and rich gas reinvestment opportunities while holding all of our quality multi TCF North American gas acreage.
We expect to sell between $1,200,000,000 and one $250,000,000 of properties this year. And through the end of July, we've closed on $1,200,000,000 of sales. Our single biggest sale involved our outside operated Bakken properties, which closed in the Q2. Even with these sales, many of which involve oil or NGL production, we've increased our 2012 crude oil and liquids production growth target. We are considering doing a joint venture on at least one additional horizontal oil development play, but it won't be one of our big four.
In other words, not the Eagle Ford, Bakken, Permian Basin or Barnett combo place. Our current net debt level is 26% and for 2013, we anticipate living within our self imposed 30% max net debt to cap guideline and not issuing any equity. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks Mark. Capitalized interest for the quarter was $12,100,000 For the Q2 2012, total cash exploration and development expenditures were $1,900,000,000 excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $145,000,000 Year to date, total cash exploration and development expenditures were $3,800,000,000 excluding asset retirement obligations. Expenditures for gathering systems, processing plants and other property plant and equipment were $316,000,000 Total acquisitions for the quarter were $108,000 $435,000 for the first half. Through June 30, proceeds from asset sales were $1,100,000,000 and as Mark mentioned through the end of July proceeds were $1,200,000,000 At the end of June 2012, total debt outstanding was $5,000,000,000 and the debt to total capitalization ratio was 27%.
At June 30, we had $280,000,000 of cash on hand, giving us non GAAP net debt of $4,700,000,000 or net debt to total cap ratio of 26%. The effective tax rate for the 2nd quarter was 39% and the deferred tax ratio was 67%. Yesterday, we included a guidance table with our earnings press release for the Q3 and the full year 2012. For the Q3 and full year, effective tax rate is estimated to be 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the Q3 and for the full year.
Regarding price sensitivities, with our current hedge position for the second half of twenty twelve, for each $1 move in crude oil prices, net income will be impacted by $14,000,000 and cash flow will be impacted by $20,500,000 For each $0.10 move in natural gas prices, net income will be impacted by $4,300,000 and cash flow will be impacted by $6,400,000 Now I'll turn it back to Mark.
Thanks, Tim. Now I'll provide our views regarding macro, hedging and concluding remarks. Regarding oil, we still think the global supply demand balance is tight and we expect prices to strengthen throughout the remainder of the year. Two recent concerns I've heard from oil bears involve horizontal shale oil. One concern is, would U.
S. Create enough shale oil to affect global supply? EOG's forecast is an increase in the U. S. Of 2,000,000 barrels of oil per day by 2015, which we believe will not impact a 90,000,000 barrel oil a day global market.
We think there are only 3 consequential horizontal oil plays in North America, the Eagle Ford, Bakken and Permian and that all other alleged oil praise are either inconsequential on a national scale or really NGL place. A picture is worth a 1000 words. And slide 7, if you take a look at Slide 7 on our website, it makes this blindingly obvious that there's only 3 plays that are meaningful in terms of U. S. Oil impact.
The second concern relates to possible international horizontal oil shale plays and their potential impact on supply? My answer there is, maybe it will happen, but it's not likely for another 10 years at least. Remember, it's been 10 years since horizontal drilling unlocked shale gas in the Barnett and no one yet has found commercial shale gas outside North America. Also, the key to commercial shale oil or gas is the ability to drill thousands of wells at low per well cost and whether this can be done internationally is likely problematic. For August to December 2012, we're approximately 22% hedged at $106.69 price.
We've recently begun to layer in 2013 hedges and currently have 16,000 barrels a day hedged at $98.12 for the first half twenty thirteen. We continue to have a cautious long term view regarding North American gas, but we do believe that 2012 marks the nadir for natural gas prices. We're comfortably hedged for the second half of this year, 45 percent at $5.44 per MMBtu hedged at $4.79 We recently closed out our 2014, 150,000 MMBtu natural gas hedge position. Please see the table that was included in our earnings press release for the details of our hedging contracts. In summary, I want to leave you with 2 thoughts.
1st, how does an investor decide which company to own when it seems like every independent E and P is trying to become a liquids rich company? How to decide when every company is touting new often unproven or marginal liquids rich plays upon which they allege they'll drill thousands of wells. It's really simple. Go with the company that's generating the results quarter after quarter, year after year. In this business, there's a lot of hype.
Results matter and they're easy to measure. And second, there's been a slight change to my retirement timing. The original plan was that I would keep the Chairman and CEO jobs until mid year 2013 when I will retire and hand over both these jobs to Bill Thomas. The new plan is that in mid year 2013, I'll hand over the CEO job to Bill and I'll remain Chairman for 6 additional months until mid year 2020 excuse me, until year end 2013 when I retire. The only read through on this change is that psychologically after 31 years, it's a little harder for me to walk away from EOG cold turkey than I originally thought.
So this plan provides a more gradual approach and orderly transition. Thanks for listening. And now we'll go to Q and A.
Thank you. The question and answer session will be conducted electronically. Take our first question from Brian Lively from Tudor, Pickering, Holt.
Hi, good morning. Good morning, Brian.
Mark, on the your commentary about potentially doing a JV in 1 of the other non 4 big plays. I'm just thinking about it strategically in 2013. Are you saying that basically that in combination with just essentially no gas drilling is going to kind of fund that gap for next year and allow you to continue with the high liquids growth?
Well, we're just our 2013 plan is obviously not specific yet. It will furnish a much more detailed plan as we do every year on our year end earnings call in February that will have specific growth targets for both the liquids and gas. But the predicates of the plan are clearly that the amount of dry gas drilling we're going to do next year is going to be pretty close to nothing. I mean, one rig really, which is just going to be holding acreage primarily in Bradford County and Marcellus. And basically we're going to attempt to hold to the 30% net debt.
We'll consider selling some additional properties. And we're going to heavily fund the oil plays and the NGL plays. Will be more we'll just see what happens to NGL prices. But the oil plays are going to get the vast majority of the funding. And the big plays there that are going to get the funding will be 1, Eagle Ford and 2, the Bakken, because they're primarily oil.
The Permian Basin, even though people think of it as an oil play, it's really a combo play as of course is our Barnett combo. So the both the Wolfcamp and the Leonard have about 40% of that production is oil and the rest of it is NGL. So what you can look for are those 2 plays, the Eagle Ford 1st, Bohnken 2nd are going to get the lion's share of the money. And then we'll look at some plays other than our big four plays. And if it makes sense, we may bring in a JV partner depending on what our cash flow, what our property sales balance is.
So all we want to do really Brian is just signal to you that at this stage the plan is clearly there will be a further ramp down of dry gas drilling and there'll be a definite shift of capital even more heavily likely toward the Eagle Ford and toward the Bakken and that some additional plays which we may look at oil or combo plays other than the big four we may look at bringing in some outside capital.
Mark, that's helpful. Just my follow-up question and it sort of fits in that context. We saw a pretty attractive at least in my view valuation done on a JV in the Pearsall. It looked like that acreage overlapped on your position probably more so than anyone. Could you provide a little bit an update in terms of what you're seeing in the Pearsall and what you're testing there?
Yes. We really I would just say that in relationship to the Eagle Ford acreage, we realize there are multiple zones that are potentially pay zones above and below the Eagle Ford. And it's not particularly likely that we would be splitting horizons vertically splitting horizons in that area. That's not our first choice. So that particular area is not one that directionally we're looking at carbon at some other interval other than the Eagle Ford and JV there.
That's a little bit messy in our opinion.
Moving on, we'll take our next question from Leo Mariani from RBC.
Hey, guys. Obviously, you've detailed some very strong results here in the Eagle Ford. I realize that represents your best results in terms of what you guys have discussed. Just wanted to get some color on how the overall average result in the Eagle Ford, if you take into account all of the wells has changed from earlier this year?
Yes. We're I mean, Leo, we haven't changed at this juncture from the average reserves per well, which we provided to people earlier, which is 450 MBOE per well net after royalty. Now obviously some of these or most of these wells that start out at north of of entire acreage position, we're still sticking to that number. Now obviously, we've made some improvements and it's possible that that number could go up with time. But as you know, we're pretty conservative.
And as we've done with volume growth projections this year, we'd rather be on a conservative side. So all I can tell you is the numbers we provided earlier that come out to the 1,600,000,000 barrels and the average reserve is 450,000,000 are still the numbers we prefer that you use. But hopefully some of the comments we provided on the call would convey our enthusiasm that the Eagle Ford is a very unique rock and that the more time we spend with it, the more enthused we are about the recovery factors and the ultimate potential of that rock. But it's just going to take some time for us technically to get our arms about that. But we are very enthusiastic about that asset and that's why we had zero interest in JV ing that asset.
All right. That's great color. That makes
a lot of sense. I guess, obviously, it's a little too early to discuss 2013 per your prepared comments here. But I guess, hypothetically, if we're at kind of a $90 plus WTI environment year. And with gas drilling coming down and cash flow going up, I mean, there should be materially more cash available to fund the oil plays. So should certainly at least expect in that environment to have significantly more oil directed joint activity next year?
Yes. I really don't want to get into 2013. Yes. I mean as a percentage of our total CapEx more a higher percentage will be oil directed. But beyond that, I don't want to get into any specifics until we really get to our February earnings call.
Moving on, we'll take our next question from Brian Singer with Goldman Sachs. Thank you. Good morning.
Good morning, Brian. Following up on
that last question, last couple of questions there. When you look at the techniques on the fracking side that have really driven some of the improved well results that you're seeing in the East, What's the applicability that you can that you may have or may not have as you move and shift activity more to the West? And is getting more wells completed in the West the main impediment or the main catalyst needed to take up that EUR or you seeing underperformance elsewhere?
I mean the reason we're shifting a bit more of the rigs to the West is mainly just an acreage earning issue. We just we've got all this acreage to hold. And so we just have to we're driven a bit where we locate the rigs by our acreage earning calendar. And so and that's why we're and some of the well a higher percentage of the wells we drill in the second half will be at a lower working interest than generally most of the wells we drilled in the first half of the year 100% working interest
we won't
have that benefit in the second half of the year. And so that's why our overall production growth is going to be tempered. Total company oil production growth will be tempered a bit as well as just a slowdown in our overall CapEx. In terms of the West, the wells in the West as a rule will not be quite as good as the wells in the East. They'll still be wildly economic, but it's on average you're not going to be getting 4,000 barrel a day IP wells typically in the West as you're going to get in the East.
So we're just we're not expecting those kind of well wells for sure. So we're just going to have to see with our recent frac improvements, we expect to see better wells this past in the West than we got a year or 2 going West. So we'll see. And we've done some drilling in the West all this year and we found some quite good wells out there. So all this is ground into plan Brian.
So what we're trying to do is not let you guys on the sell side take our first half results and extrapolate them to the second half and say EOG sandbagging and their oil growth in the second half is going to be off the charts again. So that's my advertisement. I hope I can get across to you guys.
Yes. I guess on the topic of quarter on quarter kind of noise or we can look and see the Eagle Ford number that you reported for June up 26,000 BOE a day versus what you had in April. Now I guess we don't technically know or maybe you could help us with what the real average was during the quarter, but that type of growth should look like you're well on your way in Q3. But I know you always like to say there may be other factors that may be more one off. But can you talk a little bit about that the quarterly trajectory and whether you see any temporary beyond shifting your wealth west, any other temporary hiccups to the pace of Eagle Ford growth?
Yes. I'd just say the number of Monster wells that we got in the Q2 that I bragged about that was an extraordinarily high number of Monster wells. We don't expect that we're going to see that in the Q3. So to that degree, 2nd quarter was maybe a little bit anomalous on there. So
we're
I'd say that there definitely is going to be a slowdown in the Eagle Ford growth, 3rd quarter versus 2nd quarter because of the working interest issues and also because of the number of completions. I quoted the number of completions in the second half versus the on there and the number of rigs we're running. So as you noticed our burn rate in the first half on CapEx was I think $4,100,000,000 And we're trying to limit ourselves just from capital discipline to spending $7,500,000,000 or $7,600,000,000 for the full year. So we are consciously slowing down our CapEx. And our biggest CapEx consumer is the Eagle Ford.
And the analogy I would give you is right now UG is like a coin operated machine. You put in a lot of coins and we are an oil producing behemoth with 100% efficiency. You put in less coins and we don't produce as much oil. But we have 0 inefficiencies, no exploration inefficiencies or anything like that. And we're going to be putting in less coins in the second half than we put in the first half.
And so the rate of oil growth is going to slow down a bit. So it's just that simple.
Moving on, we'll take our next question from Joe Magner from Macquarie Capital.
Good morning. Thanks. I appreciate that you're not necessarily getting into details on 2013 spending yet. Can we expect that you will and I apologize if I missed this earlier, maintain the commitment to keeping your net debt cap below 30%. Is that still a goal for next year?
Yes. That's our target, Joe.
Okay. And I guess as we think about some of the spending that's taking place this year, you mentioned that $750,000,000 of dry gas spending is taking place to hold leases and whatnot. How much of that might occur again next year? Or will you be mostly through a lot of that activity by the end of 20 12?
That'll probably go from $750,000,000 to maybe like $100,000,000 or $150,000,000 So it's going to drastically drop.
Just getting into one of the plays, there's just some differences in terms of how companies are referring to the Wolfcamp Shale horizons that are being targeted. Can you, I guess, maybe remind us how you think about the upper, lower and middle Wolfcamp and how that might compare to some of the other industry just norms that have been discussed?
Yes. Joe, we ours is maybe a little bit simpler nomenclature. We just we divide the 3 the Wolfcamp, it's about 1,000 feet thick. So we divide it into 3 zones: the upper zone, the middle zone and the lower zone. And those are defined stratigraphically.
There's shaleier, more really clay intervals that separate the 3 zones. So they're kind of distinct zones that we can map around the basin. And I'm not we're not real sure. We know some have broken them up into 4 different zones and things like that. And so I'm not sure exactly what the difference is between us and EOG, but ours is a pretty simple thing.
And our focus right now is, of course, has been on the middle zone. It's been really it's got really good consistent pay quality and we're consistently making really good wells in that. And then we are currently completing a couple of upper wells now, and we'll have some results on those later down the road. But that's how we're doing it.
Moving on, we'll take our next question from Pierce Hammond from Simmons. Good morning and great quarter.
Thanks, Pierce.
Could you give an overview of how you see service costs trending right now in your 4 core areas?
Yes. We've seen the drilling rig rates drop. They've been negotiated probably only 10% lower. The tubulars, they're dropping also. They're probably down about 10%.
But as you'll recall most of EOG's services are pretty well contracted. We've got about 40% of our rigs, drilling rigs under long term. And then about 2 thirds of our frac fleets are contracted. And then, yes, EOG provides our own sand. We buy our mud wholesale.
We provide our own sources of acid, gel that sort of thing. So our costs are pretty well locked in. So we wouldn't see much additional change other than yes we'll continue to drive efficiencies into our operations. And that's how we've reduced our costs, both on the number of stages per day and then dropping the number of days per well.
And then of the Bakken and the Eagle Ford and the Permian, which one of those 3 would be the tightest right now on services in general?
Probably the Permian, the tightest right now. But we're not really having any problems there. That's probably our lowest activity area. Of course, we're busiest in the Eagle Ford and then next in the Bakken.
Moving We'll take our next question from Bob Brackett with Bernstein Research.
I had a question on the impact on production on the various disposals of the non operated properties. What sort of scale is that? And when will that hit? Did that close in the quarter? Or will it come later?
Yes, Bob. Yes, we in terms of when it will hit, it closed late in the second quarter. So when it will really hit is in terms of 3rd quarter. So that's another reason that the growth of second half oil production scale of it, we typically on the assets we sell, which is $1,200,000,000 this year so far, We haven't released who's been the buyer and we haven't released what volume we sold and because we don't really want to get into all this stuff about as adjusted volumes or pro form a or anything like that. We're not an as adjusted company.
So we'll just say it was the biggest single sale of our $1,200,000,000 that we sold. And but that's as far as we want to go on a disclosure on it.
Okay. And then do you have much in the way of non op production left in the Eagle Ford or Bakken?
In the Bakken, no. I don't think we have any. It'd be just a tiny minuscule amount really. In the Eagle Ford, we do have some
we are partners
with PXP on some where we operate some and they operate some on a fifty-fifty basis. So it's not a big amount relative to our Eagle Ford position. As a just a guess Bob wow 90%, 95% maybe a little bit more than that of our Eagle Ford we operate maybe 97% something like that we operate. But there is a little bit that is joint operated outside operated.
And moving on, we'll take our next question from Biju Puran Sheryl from Jefferies.
Yes. Hi, good morning. Going back to the Pure Sol capacity earlier, have you drilled any wells to test the Pure Sol? And drilling Eagle Ford does that hold your Pure Sol rights?
Second question first. Yes drilling an Eagle Ford well generally does not hold the Pure Sol rights, because the PureSol is deeper than the Eagle Ford. And generally most of the leases you only earn to the depth drilled. In terms of we have done a little bit of testing of the Pure Soil and really haven't disclosed any results yet on it. So you can take that as either a positive or a negative.
What we will say again are there are 3 or 4 zones both above and below the Eagle Ford that have the potential maybe to be productive. And we're kind of testing them in time, but they're really so secondary or almost tertiary to the potential of the Eagle Ford that they're not giving it a very high priority relative to optimizing the Eagle Ford. In other words, if we can figure a way to improve our recovery factor by 2% or 3% in Eagle Ford, it dwarfs whatever we might find in some of these other intervals in terms of magnitude. So that's kind of what's driving our priorities.
Got it. And then in the Eagle Ford, it looks like you've recently moved jumped over to I guess farther Northeast in Madison County. Is that are you looking at the Eaglesburg or is that a different player like the Woodbine there? Can you share any color on that?
Yes. We have drilled a well. It's called the Eagle Mine play generally by the industry. And so we're testing some concepts over there. But we've really not talked much about that and not really prepared to talk much about those that kind of play at
this point. And moving on, we'll take our next question from Bob Morris from Citigroup. Good morning, Mark.
Hey, Bob.
When you mentioned potentially doing a JV on another oil play, I assume that's separate from the JV you did with Mitsubishi in the Tuscaloosa Marine Shale and is a play that you've not disclosed or talked about yet?
Yes. Don't try and pin us down too much. We're really what you ought to take directionally out of that is our inventory in out of our big four plays is and our success rate there is so high that we could easily push essentially all of our cash flow into those plays next year. And so in any of our other oil plays, horizontal oil plays, we may elect to push our capital away from those and use JVs and allow us to funnel more money particularly into the high rate of return at Eagle Ford. So that's kind of the thinking behind what we're talking about.
Okay. And then on the joint venture with Mitsubishi and Tuscaloosa Marine Shale, what has been your activity under that joint venture to date?
Yes. Look currently, we've commenced drilling. And probably by year end we'll have first wells results on there. So I guess on the February earnings call, we'll know something from the first well.
All right. Thanks. Great quarter, Mark.
Thank you, Bob.
Moving on, we'll take our next question from Irene Haas from Wonder Lake Securities.
Yes. I have actually two questions for you. Firstly, I want to find out second half looking into the Bakken and also the Eagle Ford, how should we think about the differential versus WTI or LLX however you want to express that? And then also within your U. S.
Portfolio percent Bakken crude and Eagle Ford? So that's my first question. The second question is in light of the recent activity in Midland Basin specifically to the Wolfcamp and Klein shale play, are you still sticking with your 430 1,000 barrels per day EUR because one of your competitors have sort of raised that bar?
Yes. Okay. Thanks, Irene. I'll field the question about the differentials and then I'll ask Bill Thomas to field the question about the reserves in the Wolfcamp there. Our plant in the Eagle Ford, we're selling essentially all our oil now in the Houston market.
And currently in the Houston market, we're getting the same price essentially as if we were selling that oil in St. James, Louisiana. So it's we're getting pretty much St. James price. And in the Bakken, we continue to move a little bit of the Bakken oil on pipeline and selling it at Clearbrook just to keep some pipeline access.
And that little bit oil is getting suffering a severe discount like the Bakken oil does up there. But the majority of our Bakken oil is getting moved by rail and sold at St. James. So essentially the majority of both those areas Baca and Eagle Ford is being sold at St. James prices.
Ask a question on the Wolfcamp reserves. Bill?
Yes. Irene, there's a couple of things comments on that. Yes, we're sticking I mean, right now, we're holding to our 430 MBOE per well on the Wolfcamp. And then it's the same really on the Wolfcamp or the Eagle Ford when we're in the early stages on these wells. We're doing 2 things.
We're trying to make better wells, but we're also down spacing. So as we drill wells closer and closer together, we're trying to measure what the EUR per well is going to be. And so we're very cautious on increasing the EUR until we really get the proper spacing. And that goes for really any of these plays. And the other thing I would say about the Wolfcamp is it's not it's clearly in 3rd place as far as rock quality.
And it's clear to us we've completed I think 72 wells so far to date. And it's going to be more difficult in the Wolfcamp play to get the recovery factor up. It's not as going to it's not certainly as easy as the Eagle Ford play or the Bakken play to get really high recovery factor. So we're being very prudent. We're doing everything we can technically to make the play better.
And it's a really good play. We're very, very satisfied with our results there. But I would just be somewhat cautious on trying to extrapolate that we're going to get 6 percent or some really high number recovery factor out of the Wolfcamp as we've done in the Eagle Ford and some of these other plays just because the rock quality and the difficulty there is more has got a higher degree of difficulty.
Okay, great. Thank you.
Moving on, we'll take our next question from Doug Ligati from Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Mark, it'd be nice to have you around a little while longer. Regarding the guidance, I could go back again to the north of 100,000 barrels a day in the Eagle Ford, I got to tell you, I'm struggling to get to your guidance for the year mark. Could you just walk us through I know you've already gone through it, but how many of the 145 completions are planned to be in the lower working interest areas?
And if you could help us with the delta between your 100 percent working interest to what the actual difference is order of magnitude basically? And I have a follow-up please.
I don't know if we have that data right at hand here Doug. Maybe Maura can get some of that information to you later on. I'd say the again, the best way to look at it is probably the we've got more rigs moving to the west. We have less monster wells that are going to be completed in the Q3 versus the second. And some of them are lower work Clearly, some wells are going to be lower working interest and there's just less capital going to be spent in the second half of the year.
And then you've got the effect of in the first half we sold $1,200,000,000 worth of assets. And the effect of the liquids that we sold are going to bite in the second half of the year. So that's kind of the way to get to it. And that's the best explanation I can give you.
Maybe I can try the same question slightly differently. You would still expect Eagle Ford to grow from June levels in the second half. Is that a fair assertion?
Yes.
Okay. My second question is also on guidance. It's on the operating cost this time because it seems you had a pretty phenomenal second quarter on costs. But your guidance again has it moving right back up again in the second half of the year. Can you just walk us through what the why that would be the case?
And I'll leave it at that. Thanks.
Yes. One piece of that guidance relates to Trinidad. If you notice Trinidad, we had very high volumes in the second quarter and then we're toning down those volumes for the second half. Trinidad has quite low operating costs. And so to the degree that those volumes are going to come down in the second half, that's going to skew the average operating cost back up a bit.
So that's one piece of it. And a lot of it is that again the growth in the the volume growth in the second half is going to just average the rate is going to be a bit lower across the whole company. So that's why we're expecting it to go up a little bit more. So we hope we can beat on the operating cost for the second half, but we'll just see.
And at this time, that will conclude our question and answer session. I'd like to turn the conference back over to Mr. Papa for any additional or closing remarks.
No additional remarks. Thank you very much for listening.
And thank you. That will conclude today's conference. We thank everyone for their participation.