Good day, everyone, and welcome to the EOG Resources 2012 4th Quarter and Full Year Results Conference Call. As a reminder, this call is recorded. At this time, for opening remarks and introductions, I would 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 taking the time to join us. We hope everyone has seen the press release announcing Q4 and full year 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 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 dot com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast, including those for the Eagle Ford, Wolfcamp and Leonard, may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to 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, COO Billy Helms, EVP, Operations Tim Driggers, Vice President and CFO Moira Baldwin, VP of IR and Jill Miller, Manager of Engineering and Acquisitions.
An updated IR presentation was posted to our website last night and we included Q1 and full year 2013 guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first review our 2012 Q4 and full year net income and discretionary cash flow. Then Bill Thomas and I will provide operational results followed by reserve replacement, our macro view and hedge position and our 2013 business plan. Tim Driggers will then discuss financials and capital structure and I'll finish with concluding remarks.
As outlined in our press release, for the full year of 2012, EOG reported net income of $570,300,000 or $2.11 per share and a net loss of $505,000,000 or $1.88 per share for the Q4. 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 full year adjusted net income was 1,540,000,000 dollars or $5.67 per share $437,000,000 or $1.61 per share
for the Q4 of 2012.
For investors who follow the practice of industry analysts who focus on non GAAP discretionary cash flow, EOG's 2012 DCF was $5,700,000,000 for the full year and $1,400,000,000 for the 4th quarter. I'll now address our operational results in key plays. We had a good 4th quarter, providing a capstone to a very strong full year and partially due to our crude by rail system, our domestic crude netback was at a significant premium over WTI. For the full year, our crude and condensate volumes were up 39% year over year, NGL volumes were up 32% and total liquids increased 37%. North American natural gas volumes were down 9 percent year over year in line with expectations and Trinidad volumes increased 6%.
Overall, total company production grew 10% in 2012 versus 2011. Over the past 3 years, our organic crude and condensate growth rates have been 35%, 52% and 39%, respectively. More importantly, EOG's full year non GAAP EPS, adjusted EBITDAX and discretionary cash flow grew 50%, 26% and 26% respectively above 2011. We believe we have the highest 2 year growth rate in these three important financial parameters of all large cap E and Ps. We expect further growth in each of these three metrics in 2013 as well as improvements in ROE and ROCE.
I'll note that in the Q4, we incurred a significant financial and natural gas reserve write down, which is very unusual for EOG. Approximately 98% of the total financial write down occurred in Canada as a result of low gas prices. We have written off the remaining book value of our entire Horn River acreage along with all PDP and PUD reserves because they are uneconomic at current gas prices. However, the drilling we've done to date holds our remaining 127,000 net acres in the Horn River with an estimated 7 Tcf reserve potential until 2020 providing optionality for us. The other major component involving our Canadian involved our Canadian shallow gas assets.
Even with these write downs affecting our capital account, we accomplished our goal of keeping our net debt to total cap below 30%. I'll now discuss our key oil plays starting with Eagle Ford. The Eagle Ford continues to be our flagship oil asset and we have several important points to share with you today regarding this asset. First, as predicted on our previous call, our 4th quarter Eagle Ford production declined relative to the 3rd quarter since we slowed down our capital spend rate to stay within budget targets. I've previously used the analogy of a coin operated machine and we simply didn't insert as many coins in the Q4.
The good news is we're ramping up in the Q1 and in January, we completed our highest IP well in the Eagle Ford to date. The 100 percent working interest Burrow Unit 2H tested at 6,330 barrels of oil per day with 5,700,000 cubic feet a day of rich natural gas. The Eagle Ford will be the biggest driver of EOG's targeted to surpass the Bakken within the next 2 years. Remember that EOG's 569,000 net oil acres constitute through year end 2012, we drilled and completed 6 30 net wells and conducted multiple spacing studies and reservoir computer simulations. Simply put, we understand the reservoir much better than we did a year ago and we've reached several important conclusions.
The bottom line answer is that we're increasing our net potential recoverable reserve estimate by 600,000,000 BOEs and the development economics are still excellent. However, since some of the data supporting this conclusion may be counterintuitive to speak Street expectations, I'll provide some backup details without dragging you through the minutiae. Conclusion 1 is the downspacing across all of our acreage has been successful and the optimum spacing is 40 acres in the eastern half of our acreage and 65 acres in the west. Previously our spacing was 65 to 90 acres. Conclusion 2 is that with the new spacing, we have a total of 5,500 net drilling locations on our acreage.
Since we've completed 630 net wells to date, there are approximately 4,900 wells yet to drill or a 12 year inventory based on our 2013 program of 400 net wells. Conclusion 3 is that per well reserves will average 400 MBOE net after royalty. This is lower than the 450 MBOE we've previously provided because there is inner well there is an inner well drainage component associated with this closer spacing. A minimal amount of drainage is optimal in developing a resource play and maximizing present value. Multiplying 5,500 net wells times 400 MBOE net after royalty equals 2,200,000,000 BOE net to EOG, which is our new potential reserve estimate.
This translates to an approximate 8% recovery factor of the estimated 26.4 under our acreage. Conclusion 4 is that we plan to drill longer laterals than previously assumed 5,500 feet versus 4,000 feet previously. So the average well cost is now $6,000,000 Adjusted for lateral length, this is equivalent to the $5,500,000 cost target we've previously reported. And the final conclusion is that using the new well cost and reserves and current oil and NGL prices, the direct unlevered after tax reinvestment rate of return per well is 100%. The bottom line is that we've added an estimated $600,000,000 BOE net potential recoverable reserves where the direct ATE ROR is 100% and the incremental infrastructure cost is rather low.
I'll now turn it over to Bill Thomas to discuss other domestic oil plays.
Thanks Mark. Our Bakken and Three Forks drilling results during the Q4 were outstanding and our 2013 program should be one of our strongest in many years. While most of the industry Bakken Three Forks results are trending downward, EOG results are moving in the opposite direction. In other words, our wells are getting better. There are two reasons our well performance is trending higher and why we expect our 2013 results to be strong.
1st, new frac technology is improving our wells in every area of the Bakken Three Forks. In some cases, the new frac technology used in our 320 acre downspacing wells in the Parshall core has resulted in a 30% to 70% improvement in cumulative production over the original offset wells on a per foot of treated lateral basis. For example, the Wyzeeta 1563,329, a 320 Acre Down Space well completed in 2012 has a cumulative production of 330 MBO in the 1st 320 days and is still producing at a rate of over 800 barrels of oil per day. Please see our updated IR slides for an illustrative chart. The second reason to expect strong results in 2013 is that our drilling program is directed to the Parshall Core and Antelope Extension areas, which are some of the best acreage blocks in the play.
2 Antelope Extension wells recently completed are the Hawkeye 102-2501H, a threefourtwelve flowing 2,945 barrels of oil per day and the Hawkeye 12501H, a Bakken well pulling 2,444 barrels of oil per day. EOG has 75% working interest in these wells. In addition to improving well results, we have completed our first two wells on 160 acre downspacing in the Parshall field. The Wayzata 221509H and the Wayzata 1491509H tested at maximum rates of 11.85 and 12.65 barrels of oil per day, respectively. EOG has 68% working interest in these wells.
In 2012, we completed 28 net wells in the Parshall field and Antelope areas with a successful 320 Acre Downspacing program. In 2013, we plan to complete 46 net wells in these same two areas. Our focus this year will be to further down space to 160 acres in both the Bakken and Three Forks pay intervals continue to improve frac efficiency and to optimize the recovery factor of each play. If 160 acre down spacing proves successful, this will allow us to accelerate our development program in 2014 and beyond. The takeaway from our Bakken Three Forks asset is the wells are getting better with continued success in downspacing.
The number of potential locations is growing and this provides us many years of high ROR investment opportunity in the play. In the Delaware Basin, we have completed our first two horizontal Wolfcamp wells in Reeves County, Texas and we have significant results to announce. The Harrison Rants 5six-1,000 and 1H tested in the Upper Wolfcamp at 6.35 barrels of oil per day with 480 barrels of NGL per day and 3,100,000 cubic feet of gas per day. And the Harrison Ranch 5six-1 thousand and 2H was completed in the Middle Wolfcamp at 3 77 barrels of oil per day with 602 barrels of NGL per day and 3,900,000 cubic feet of gas per day. With estimated growth reserves of 900 MBDOE per well and a target completed well cost of $6,500,000 these results yield a strong 60% direct ATAX rate of return.
Our Reeves County acreage has as much as 2,000 feet of gross Wolfcamp thickness in some places and approximately 300,000,000 barrels equivalent per section of resource potential. We have 220 subsurface well control points on our 114,000 net acres and we estimate the reserve potential to be 800,000,000 barrels of oil equivalent net to EOG. This is another substantial addition to our growing opportunities of high rate of return drilling inventory. As a cautionary note, because we have such a large inventory of opportunities across the company, significant production growth on the Delaware Basin Wolfcamp should not be expected until the 2015 time frame. As noticed in previous earnings calls, the results from our Leonard Shale play also in the Delaware Basin keep improving.
With improved frac techniques, the wells are getting better and showing a higher percentage of oil production than previously reported. Successful down spacing and the identification of multiple pay targets have substantially increased the number of potential drilling locations. Recent wells include the Vaca 14 Fed 6H with an initial production rate of 12.90 barrels of oil per day with 255 barrels of NGL per day and 1,400,000 cubic feet of gas per day and the Diamond 8 FC 5H with an initial production rate of 11 62 barrels of oil per day and 183 barrels of NGL per day and 1,000,000 cubic feet of gas per day. As a result, we are increasing our gross reserves from 430 MBOE per well to 500 MBOE per well and increasing the percentage of estimated oil from 41% to 50% of total well reserves. In addition, we are increasing EOG's estimated liner plate potential reserves from 65,000,000 barrels of oil equivalent to 550,000,000 barrels of oil equivalent net to EOG.
Our direct ATAX rate of return for the 2012 winter program was 55% and we see this improving in 2013. In summary, our 114,000 net acres in the Delaware Basin has multiple pay zone targets in the Leonard and Wolfcamp shale plays with a combined estimated reserve potential of approximately 1,350,000,000 barrels of oil equivalent net to EOG. Additionally, our results from the Midland Basin Wolfcamp program continue to be on track. The Barnett combo remains a solid 30% direct ATAX rate return drilling program. Cost efficiencies have reduced completed well costs to 3,100,000 dollars and new techniques are helping to improve oil recovery.
In 2013, we plan to drill 130 wells versus 190 in 2012. Because we have an EOG owned processing plant, ethane extraction is still economic and supports our drilling program in spite of soft NGL process. Recent wells include the Evans A Unit 1H, 2H, B Unit 1H with initial production rates of 573, 670 7 and 6.85 barrels of oil per day, respectively, and the Collier A Unit 1H and 2H with initial production rates of 3.71 and 4.47 barrels of oil per day respectively. EOG has 100% working interest in all of these wells. Remaining drilling potential continues to grow for oil activity in the Mid Continent, Powder River Basin and Southern Manitoba.
Also, we continue to test new greenfield horizontal oil ideas in North America. Now I'll turn it back to Mark.
Thanks, Bill. As you can see with our Eagle Ford Reserve estimate upgrade and our success in the Delaware Basin, we're very long on domestic oil and combo reinvestment opportunities for many years, and this affected our decision to exit the Kitimat LNG project. We believe Kitimat is a good project. And with Chevron involved, the project will likely get built. However, the projected Kitimat IRR didn't compare favorably with returns from our domestic shale oil projects, especially in light of our Eagle Ford reserve upgrade.
We weren't desperate to monetize our Kitimat position. We simply believe that the substantial go forward capital required by Kitimat will be best reinvested in U. S. Oil shale plays. We hope this explains to shareholders our logic regarding the exit of this project.
In Trinidad, our 4th quarter gas sales were lower than previous quarters due to downtime from planned maintenance and construction work on our offshore facilities. We are currently in the middle of a drilling program, which includes 4 wells off of our Oskruk platform. These wells are expected to be completed in the first half of twenty thirteen. In Trinidad, we expect natural gas production to decrease by 4% this year. This is a function of the timing of first production from our current drilling program.
In the East Irish Sea, we expect our Conway oil project to start production early in Q4. I'll now address 2 other EOG differentiators frac sand and oil margins. Frac sand is easy to explain. Our sand plants ran at essentially 100% during the Q4 and met our completion needs. In the Q4, our U.
S. Crude oil price realization was $10.52 over WTI, up from $5.45 in the 3rd quarter. During the Q4 and currently, our Eagle Ford crude is priced off an LLS index and essentially all of our Bakken and part of our Wolfcamp crude is being railed to our St. James terminal. To a large degree, our domestic crude price is linked more closely to LLS than WTI.
We expect that the recent Seaway pipeline delays will continue to provide us with a marketing price advantage. I'll now address 2012 reserve replacement and finding costs. Because of the extraordinarily low 2012 gas prices and the current SEC rules, all companies with gas reserves will likely incur reserve write downs and EOG is no exception. This will make it very hard for analysts to compare overall 2012 reserve metrics with past years. Because of low natural gas prices, EOGD has written off essentially all of our dry gas PUDs in the Horn River, Marcellus, Haynesville and Barnett.
Additionally, our existing gas PDPs have been significantly reduced because of tail gas reductions. The total write off related to price is 3.2 Tcfe. However, excluding these price related at a $12.60 BOE total finding cost. This compares to last year's number of $18.74 per BOE. Our ratio of liquids in our total reserves increased from 28% in 20 10 to 36% in 20 11 to 56 percent at year end 2012.
Our domestic crude oil replacement rate from drilling was 4 42%. Overall, I believe EOG had an outstanding highly economic reserve replacement year and I think the removal of gas reserves from our books properly reflects the new low gas price reality. Our reserve books are now more reflective of an oil company. For the 25th consecutive year, DeGaulier and McNaughton has done their own independent engineering analysis of our reserves and their overall number was within 5% of our internal estimate. Their analysis covered 87% of our proved reserves this year.
Please see the schedules accompanying the earnings release for the calculation of reserve replacement and finding costs. Now I'll provide our views regarding macro hedging and crude by rail. Regarding oil, we think the NYMEX correctly reflects slightly 13 WTI prices, which we expect to be in the mid-90s range. We think the dangers of a global a percent of total company oil production, we're approximately 49% hedged at an average price of $98.85 I'll also note that we have some options that could be exercised further increasing our hedge position. Please see the table that was included in our earnings press release for the details of our hedging contracts.
As you know, our crude by rail system has been a profitable venture for us and is one reason why our average domestic oil price was 10 point WTI during the Q4, likely the highest in the industry for any company with similarly situated crude. Although currently the price differential at St. James and Houston continues to be very advantageous as compared to Cushing, it's possible that the spread between Houston and WTI may narrow late this year as additional pipelines from Cushing and the Permian come online. We're already working on plans to use our rail system to maximize crude margins in 2014 2015 possibly by delivering to different destinations. Regarding North American natural gas, we continue to have a negative outlook and our drilling plans reflect this bias.
We believe that those that are counting on the low gas directed rig count to balance the market will be disappointed because of the large associated gas volumes with drilling and combo type plays. We have 150,000,000 cubic feet per day hedged at $4.79 per MMBtu this year. We are also bearish regarding 2013 ethane prices. We think it's unlikely that ethane will rebound much this year. It's likely that most producers including EOG will be on the cusp of ethane rejection throughout the year.
For example, in January February, EOG for the first time chose to keep our Eagle Ford ethane in the gas stream, reducing our NGL production by 4,000 barrels per day and we're projecting Eagle Ford ethane rejection throughout the year. We have taken this into account in our lower NGL production growth estimates for the year. Now I'll address our 2013 business plan, which is congruent with what we reported in our November call. We expect our 2013 CapEx to be between $7,000,000,000 $7,200,000,000 a reduction of approximately $400,000,000 in 2012. Approximately $1,200,000,000 of this will be devoted to facilities, gathering systems and other infrastructure.
We expect to spend very little approximately $25,000,000 on North American dry gas drilling to hold acreage. We've already invested the drilling capital in previous years to hold the remainder of our dry gas acreage that we want to retain. Because of low NGL pricing, we shift some funds away from the Barnett combo to the Eagle Ford and Bakken. We're targeting 28% oil growth, which on an absolute BOPD basis is the same as last year, a tall order for a company I'll note that only a very small portion of this is condensate. Essentially all of our oil production is exactly that, crude oil.
We're not particularly interested in growing the ethane portion of NGLs and expect 10% NGL growth primarily because we're assuming full year Eagle Ford ethane rejection. It will be purely an economic decision as the year progresses. We are not driven by NGL production growth. Since North American gas continues to be a money loser, we have 0 interest in growing gas volumes and expect decreasing production for the 5th consecutive year regarding gas. We forecast EOG natural gas production to decline 14% in the U.
S. Due to past property sales and lack of gas drilling, but this also could be affected by ethane rejection. In Canada, we also expect natural gas production to decrease by 24%. In Trinidad, we expect natural gas production to decrease by 4%. This is more a function of our well downtime due to our planned redraw program.
Overall, we expect total company production growth of +4%. However, the only metric that drives financial performance is our crude oil growth. Additionally, we plan to sell approximately $550,000,000 worth of assets, of which 85% has already closed this year so far. The biggest component of this is our already closed Kitimat sale. We still plan to maintain a strong balance sheet keeping the net debt to total cap ratio below 30%.
Based on the current NYMEX strip, we expect this plan to generate a reduction in our net debt ratio and year over year growth in DCF, GAAP and non GAAP EPS and adjusted EBITDAX per share as well as healthy year over year improvement in ROE and ROCE. Given that we're bearish regarding pricing for 2 out of 3 of our hydrocarbon products, we think that's quite an impressive outcome. Now I'll turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Mark. Capitalized interest for the quarter was $13,000,000 $49,700,000 for the full year. For the Q4 of 2012, total cash exploration and development expenditures were $1,500,000,000 excluding asset retirement obligations. In addition, cash expenditures for gathering systems, processing plants and other property plant and equipment were $143,000,000 For the full year 2012, total cash exploration and development expenditures were $6,900,000,000 excluding asset retirement obligations. Cash expenditures for gathering systems, processing plants and other property plant and equipment were $620,000,000 Acquisitions for the year were $700,000 For the year, proceeds from asset sales were $1,300,000,000 At December 31, 2012, total debt outstanding was $6,300,000,000 and the debt to total capitalization ratio was 32%.
At December 31, we had $900,000,000 of cash on hand, giving us non GAAP net debt of $5,400,000,000 or a net debt to total cap ratio of 29%. On a GAAP basis, the effective tax rate for the 4th quarter was negative 13%, caused principally by impairments recorded in Canada. The deferred tax ratio was negative 157%. The current tax provision for the 4th quarter was $152,000,000 EOG's Board increased the dividend on EOG's common stock for the 14th time in 14 years by 10% to an indicated annual rate of $0.75 per share. Yesterday, we included a guidance table with the earnings press release for the Q1 and full year 2013.
For the Q1 and full year, the 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 Q1 and for the full year. Now I'll turn it back to Mark.
Now let me summarize. In my opinion, there are 5 important points to take away from this call. First, our Eagle Ford potential reserve increase gives EOG a domestic shale oil inventory unsurpassed in the industry. As I stated earlier in the call, we expect industry wide Eagle Ford oil production to surpass the Bakken over the next 2 years and EOG indisputably has a premier Eagle Ford oil position in addition to our strong Bakken position. Boe net Eagle Ford position is not theoretical.
The production results are visible on both an EOG and an industry scale. When you add in our Permian and Barnett combo assets, we have an unsurpassed inventory of proven reinvestment opportunities. 2nd, we've added a new greenfield project to our portfolio with the Permian Basin Delaware Wolfcamp plus a significant Leonard Shale upgrade. Additionally, we're excited about additional future greenfield shale projects. 3rd, as predicted, this is the year when we expect to reduce our net debt ratio based on current futures prices.
4th, our 10% dividend increase is a tangible signal of our growing confidence in our cash flow stream. And finally and most importantly, we expect our key financial metrics such as adjusted EBITDAX, DCF, ROE and ROCE to show positive year over year improvement in 2013. Thanks for listening. And now we'll go to Q and A.
Thank you. We'll take our first question from Doug Leggate of Bank of America Merrill
everybody. And thanks for all the color Mark on the down spacing. You've talked in the past about continued efforts to your recovery rates there. Obviously, you've done a good job on that. Would you now say that 8% is the is that pretty much target achieved?
Or do you think there's still more running than there? And I'm just curious as to what else you might do in terms of trying to lift your recovery rates? And I have a follow-up please.
Yes, Doug. There's no, we can't say that the 8% is the final, final, final answer at all. In terms of what we're still looking at doing there, there is the continued work on potential additional spacing, improvements from frac enhancements. And then the one that I think is the big hitter out there is secondary recovery. In the case of the Eagle Ford, it would be through gas injection.
And we have commenced our pilot gas injection project down there in the Eagle Ford. And the reason I didn't mention it on the script is that it may be as long as 2 years before we really have a read on the outcome of the pilot project. I just don't even want to give a timeline on it. But just it's worth our investors knowing that we are that the pilot project is underway. But it's not anything that we're going to be able to provide a quarter by quarter feedback as to how is the pilot coming or anything like that.
But we it's fair to say that we are cautiously optimistic that we will come up with a method of significantly enhancing the recovery above the 8% number.
Got it. Thank you for the answer. My follow-up is really going back to the you've been very disciplined with obviously your balance sheet and so on. But when you take a write down, obviously, you're inflating your net debt to cap. And it kind of makes me wonder, given that you've got so much resource opportunity, particularly the upgrade in the Leonard, Is that still the right metric, the 30% net debt to cap?
Is that still the right limiter in terms of pacing your development? And if you could maybe share any updated thoughts on how you might look to monetize or bring forward some of those non core assets, not so much non core, but as you referred in the back through a joint venture or something of that nature. And I'll leave it there Mark. Thank you.
Yes. The write down cost is I think I'm right in saying about a 2% kind of net debt penalty if you will on there. We ended the year at 29%. And absent the write down, we probably would have ended the year at about a 27% number on there. So we could you could say we have a little tighter boundary if we stick with the 30%.
I think what we wanted to indicate, if you look at the bigger picture and we have a chart in our IR slides that we released this morning that kind of shows years of our inventory, if we assume that we turf up 0 additional greenfield plays and we've already advised you we're working on additional greenfield plays that 2 things show up. 1 is the locus of future investments is likely to shift to the Permian Basin more heavily than you would have expected before this earnings call just due to what we're seeing in the Leonard and the Delaware Basin Wolfcamp. And the second thing is that as we develop into a potential free cash flow situation starting in 2014, there were questions as to what are we going to do with the free cash flow. I think that the picture is becoming clearer that where that free cash flow is likely to go is into reinvestments into both Eagle Ford and into the Permian Basin area likely which will generate additional production growth, higher rates of production growth in the out years than we would have expected otherwise. So we're still not we're still in the camp and I know that disagrees with your thinking.
We are still not leaning toward JVs in any of the plays that are key plays, however. Hopefully, that gives you an answer.
It does. Thanks very much, Mark.
We'll go next to Leo Mariani with RBC Capital.
Hey, guys. Just quick follow-up on
the Eagle Ford. Obviously, you guys increased your tremendously here.
If I just
kind of look at some of the numbers, just some quick math, 569,000 net acres, 5,500 locations you've identified, it equates to about 103 acre spacing, you guys are talking more about 50 acre spacing. Is it fair to say that you guys have really high graded that 569,000 acres and are excluding maybe some of the untested areas in that number? And could that potentially if those were to work drive the number higher?
No, it's not so much high graded. It really all the acreage is good. But by the time you eliminate all the subsurface areas such as faults and everything And then by the time you honor the lease lines that are in there such that you can't drill wells across the lease lines and you have to stay certain boundaries away from lease lines, the amount of effective acreage you can drill on is considerably less than that 569,000. So that's really the difference between the 100 acres if that's what you were quoting there and effectively the roughly 50 acres. It's really how much of that acreage can you really access that's not been a geologic fault or that just due to the lease line issues or railroad commission limitation issues you can really access.
All right. That's helpful.
And I guess just switching gears over to the Permian. You're obviously taking your Leonard Shale estimate up tremendously, dollars 65,000,000 BOE to $550,000,000 is a pretty big jump. And you're kind of doing something similar in the Delaware with the 800,000,000 BOE. And those are pretty big numbers. It seems like the results reported you've got not a tremendous number of wells.
I mean what gives you confidence in sort of putting those pretty large numbers out there?
Yes. No, that's a good question, Leo. Both of those shales are extremely rich. The Leonard is in most places up to 200,000,000 barrels of oil equivalent per section. And then in the Wolfcamp Shale, is even richer and thicker in some places.
It's up to 300,000,000 barrels of oil equivalent. So they have a lot of resource in place and a lot to work with. And each play also has multiple targets. We have we're working with at least 2 targets in the Leonard on all of our acreage. And in some places, we have 3 or 4 targets in the Leonard.
In the Wolfcamp, we're looking at least 3 targets in some parts of our acreage also. So there's a lot of potential pay zones. We're able to when we complete the wells, we're able to isolate each individual target. And we've also had really good success in the Leonard at continuing to down space. We've tested patterns on 80 acre spacing per target and we've not seen a lot of interference between the wells.
And so that's very positive. Also the other thing that's going on in all of our plays, our frac technology is really increasing each well. The wells are getting better because of that. And we have a pretty strong history. We have 47 wells we've completed so far in the Leonard.
So we have a lot of history on actual production. And then in the Wolfcamp in the Delaware Basin, as you know, there's a lot of deep penetrations by vertical wells for different plays and deeper targets over the years. And so we have on our acreage, we have over 200 well penetrations that we've gotten logs on and subsurface control for both the Leonard and the Wolfcamp. So we have a lot of confidence that the reserve potential is there and then we've been able to continue to reduce our cost on our drilling program. So we've got a lot of confidence that these plays are really very significant plays and we're excited about them.
They're able to generate very high rates of return on the drilling that we've done so far right now.
That's really helpful. Thanks.
We'll go next to Evan Kallio with Morgan Stanley.
Good morning, guys. Very helpful update. Maybe I'll just follow-up on the down spacing comment one more time on the Eagle Ford. I know you mentioned different lease line issues or other issues that imply 45% of your Eagle Ford acreage works on that tighter spacing. But I also presume there's some risking element on the spacing.
So any comments maybe on how aggressive or conservative that assumption might be currently or how the risking might progress and when you might have more data to adjust us on that potential location increase, which is effectively what it is?
Yes. I mean, I know we kind of if you're kind of saying, can you expect on earnings call next quarter that we're going to again raise reserves in Eagle Ford for the subsequent quarter. I'd say for the year 2013, you should not have any expectations that we're going to be given another number and saying, well, the number of locations is going up again in the Eagle Ford. So it's going to take some time to digest. So there's certainly a possibility down the road.
But for the next 12 months, I think the number that we've given you, the $2,200,000,000 is probably where we're going to sit at. Okay.
That's helpful. And then maybe a commodity question. I mean, thanks for sharing your view on the commodity. But any views on condensate pricing? I know we're beginning to see some price degradation as light sweet imports are backed out of the Gulf region.
Do you expect any price degradation of this higher API hydrocarbon stream? Thanks.
Yes. I mean, I'll give you a comment regarding condensate vis a vis the Eagle Ford. We have a chart in the IR slides we rolled out this morning, specifically relating to the Eagle Ford. And a point that we will make is that all of our Eagle Ford production is indeed crude oil. And the chart that we have shows kind of major producers there and the relative gravity of the oil or condensate production that the producers have as compiled by IHS.
And kind of a what you will see from that chart is that EOG is clearly the largest producer and EOG's production is well within the oil column in terms of the gravity. But many of the rest of the producers there are actually producing condensate as opposed to oil. And what I will say is there's definitely a difficulty in marketing to condensate in the Eagle Ford area. And you just have to talk to the other producers as to see what kind of prices they're actually receiving for that condensate.
Helpful. Thank you.
We'll go next to Bob Brackett with Bernstein Research.
Hi, good morning. I hate to harp on the Eagle Ford down spacing, but I can't resist. If I think about 40 acre spacing, you're basically sticking 16 1 mile laterals into a square mile. In the past, you've sort of targeted a key zone in the Eagle Ford. Is this go forward plan more of a staggered development with 1 off setting in the upper and one in the lower?
The answer to that is directionally no Bob. It's wells that are spaced quite closely together generally in the same stratigraphic interval in the Eagle Ford as opposed to 1 in say the Upper Eagle Ford and 1 in the Lower Eagle Ford. And that's where you get the issue of a question that logically would come up, wait a minute, you were quoting 450 MBO per well, now you're quoting 400 MBOE per well. And there is some interwell drainage. Bill, you may want to add something to that here.
Yes. One of
the things, Bob, that we've been able to accomplish is on our frac geometry, we've been able to increase the complexity or the amount of surface area that we're connecting with each well. And we've also been able to contain the geometry and that complexity closer to the well. And so we're not fracking really long wing length kind of fracs. We're really keeping that frac really close to the well and just increasing the amount of surface area close to the well. And that really is a big driver in harvesting more and more reserves.
If you can do that, keep it close to the well and then you can drill more wells without significant interference.
And what do you think about the vertical height of these fractures? Are we looking at things that are kind of tall but skinny?
Well, they we have been more aggressive with our fracs, more sand and more frac rates. And one of the advantages that the Eagle Ford has over many of the shale plays, it has a very, very good upper and lower frac barriers. So yes, you're right. I mean the fracs are more contained close to the well, but they are fully contacting the pay, the 200 or 300 feet of net pay in the Eagle Ford and just creating a lot of complexity. So the increased frac rate does help that could connect all the pay.
Thanks. And then a follow-up. In the past, really only 2 world class shale oil plays and resource plays in North America, the Bakken and the Eagle Ford. As you've spent more time in the Permian, is that emerging as a credible number 3? Or is it part of a long tail of number 3s?
Yes. I think it's still certainly number 3 and it's still a bit distant number 3. Part of that is many of the Permian plays are still a bit combo. They're not as rich in oil, although we're making headway on that part of it too. But just the quality of the rock, the kind of matrix contribution you can get from the Eagle Ford and the Bakken is exceptional compared to the kind of matrix contribution you can get from the Permian plays.
The Permian plays are very good plays and don't get us wrong, we're not certainly down on those, but they're still I think a bit distant third.
And we'll go next to Charles Meade with Johnson Rice.
Good morning, everyone. I want to go back to the Bakken on a question. I think Bill Thomas said in his prepared remarks those Hawkeye wells were 3 Forks wells. And I'm curious on 2 things. 1, are those the best Three Forks wells you've seen yet?
And where in that Three Forks section are they placed? And do you see possibility for more than one bench in the Three Forks?
Yes. Those Three Forks wells are on our Antelope in our Antelope area. And in the Antelope area, we do have a significant column hydrocarbon column in the Three Forks. And we have all 4 benches that have oil in them. That particular well I believe is drilled in the upper bench.
And it's certainly a good well. I wouldn't say it's any more outstanding than some of the other wells we completed. And we're working on that Three Forks development and we'll be testing 160 acre spacing and we'll be testing multiple benches over the next year or so. So the Three Forks particularly in the Antelope area has a lot of upside for
us. Got it. Got it. Thank you. And also going back to I think a point we maybe glanced on a few times here crude by rail marketing.
I think, Mark, you've kind of made an illusion in your comments that you might be looking at taking crude from the Bakken to the East Coast by rail. And maybe you guys aren't ready to talk about that, but if you were to start that now, when should we expect that crude might be delivered to the East Coast?
Well, actually we've made a few spot deliveries in the last couple of months to the East Coast just kind of as trial balloons. And where we are right now is we're really just kind of doing some strategic work as to with the plethora of new pipelines that will be installed during late 2013 specifically to the Gulf Coast, what does that really mean for likely crude differentials? And then where would we want to place our Bakken and our Eagle Ford crude in 2014 2015 and then what would we need to do to get in place to change our destinations. So we're really not ready to talk about that specifically other than to advise our investors that the system we have in place and the locations where we're selling our crude today are not necessarily where we'll be selling our crude in 2014 2015.
We'll go next to Brian Singer with Goldman Sachs.
Thanks. Good morning. Just following up on the following up on the prior question with regards to transporting crude to different destinations. What if any capital commitment would be required to shift the focus of your crude going from where you have it largely going now to the Gulf Coast? And is there anything baked into your 2013 guidance or to the degree that you feel that there is the need get more crude elsewhere, would you need to raise your capital budget for that?
No. I mean the one thing about the crude by rail is it's pretty flexible. We don't think there's any capital requirement over and above what's already included in our guidance. We've already got the tanker cars, which is a key thing and the track access with railroads. The offloading terminal would be the issues at different destinations.
And we're working on some deals there that would probably end up being joint ventures with other people. So that's at this stage, we don't think
that there
would be huge capital commitments either in 2013 or 2014 for the offloading terminals. So the main thing is just trying to figure out what is likely to happen with these differentials. And as Goldman has their ideas, everybody's got their ideas. But when we're proceeding on the concept that at any point in time, there will be somewhere in the U. S.
Where there is an advantageous differential relative to other locations in the U. S. And our job is to see if we can make sure we can get our crude to that advantageously priced location.
That's helpful. And then as a follow-up, going back to the Delaware Basin. In the Southern Delaware Basin where you reported the Reeves well, is the production mix that you expect going forward consistent with the production mix from that well? And I think Bill mentioned just in a couple questions together. You're making headway on production mix.
And I was wondering if you could add some color to what you can do to improve the oily production mix in the Delaware and the Permian?
Yes. No, I think it is. I think those 2 wells are representative of what we'll see in that particular acreage base going forward. It does get the Wolfcamp does get more oily as you move to the north into New Mexico in some places. So hopefully we have not drilled a Wolfcamp well up there yet, but hopefully that will be a bit more oily.
Yes, the main thing on increasing the oil out of these combo plays is certainly the amount of rock that you connect to the well, the surface area is a big deal. And we also have some production techniques we're working on. I think we're not really ready to talk about those right now, but we're making some headway on helping to increase the recovery of oil there. So but we feel really good. It's I think these whole combo plays are certainly more challenging as these NGL prices have weakened.
But I think going forward, I believe that we'll be able to technically improve those and make those plays better in the future.
Yes. Just to add a little bit of color to that Brian. For example, in the Leonard play out there where we previously had shown that the mix was about 41% oil. Now we're saying the mix is about 50% oil. A lot of it is in the design of the fracs.
And we typically keep kind of close mouth about most of this stuff because we don't want to share our secrets. But the concept of designing the fracs to not have fracs that are necessarily long fracs, but have fracs that really increase the surface area near the wellbore more efficiently as opposed to just having long fracs that increase the surface area far from the wellbore. What that does is it really likely improves the ability for oil to flow in a radius around the wellbore and that's probably what we think is causing the increased oil yield. So there is things you can do on frac designs that can modify things and help in these combo plays to get more oil out of them. So I'm particularly impressed with this Leonard play.
The reason we haven't a couple of reasons why we upgraded the reserves are number 1, that 65,000,000 BOE that's probably a 2 to 3 year old reserve estimate. So it's a very stale reserve estimate. And number 2, all that acreage has been held by production. So we haven't had any urgent lease expirations. So we haven't been drilling frantically on it to hold leases.
And that's one where we've been able to take our time, do our science. We purposely kept quiet as EOG does on some of these plays until we got our Ps and Qs right. But when you take 550 1,000,000 BOEs at 50 percent oil, we've got something pretty good there and that's going to turn into a pretty significant oil play for us. And that's obviously moved up considerably on our priority list for particularly 2014, 2015 kind of time frame for capital.
That's very helpful. Thank you.
And this does conclude today's question and answer session. Mr. Papa, at this time, I will turn the conference back to you for any additional or closing remarks.
I have no additional remarks. Thank you for listening.