Good day, everyone, and welcome to the EOG Resources Second Quarter 2013 Earnings Results Conference Call. Chairman of the Board, Mr. Mark Papa. Please go ahead, sir.
Good morning and thanks for joining us. We hope everyone has seen the press release announcing Q2 2013 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.aogresources.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 web cast 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 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 and CEO Gary Thomas, COO Billy Helms, Executive VP, Exploration and Production Tim Driggers, Vice President and CFO and Moira Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website yesterday evening and we included Q3 and full year guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first discuss 2nd quarter net income and discretionary cash flow, then Bill Thomas will review operational results.
Tim Driggers will then discuss financials and capital structure. Finally, I'll cover our macro view hedge position and concluding remarks. As outlined in our press release, for the Q2 2013, EOG reported net income of $659,700,000 or $2.42 per 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 2013 adjusted net income was $573,800,000 or $2.10 per 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 $1,900,000,000 Similar to the 1st quarter, EOG continued to hit on all cylinders in the 2nd quarter.
Our oil volumes considerably exceeded guidance, our unit costs beat guidance and EOG's realized domestic oil prices were at a significant premium to WTI. As a result of our exceptional performance in the first half of the year, we've raised our full year oil growth estimate from 28% to 35%, reflecting total organic growth of 55,000 barrels of oil per day year over year. We've increased our NGL growth estimate from 10% to 14% and we've increased our total company overall growth target from 4% to 7.5 percent. The oil growth target increase is emanating primarily from the Eagle Ford with contributions from the Bakken and Delaware Basin. The impact of our domestic onshore oil portfolio in the high rate of return Eagle Ford, Bakken and Leonard is showing up in the bottom line as demonstrated by our 1st and second quarter EPS results, which will show up as a stronger full year ROEs and ROCEs.
On the previous earnings call, we outlined our 5 year plan where we expect to continue to achieve the highest and most profitable oil growth rate of any large cap independent through 2017 and this quarter's results are another building block in that plan. I'll now turn it over to Bill Thomas to discuss specific operational results. Before I do, I want to congratulate Bill on his new role as CEO. He has been with the company for over 34 years and knows the assets inside and out. This makes them well qualified to deliver on a 5 year plan and guide the company for many years beyond that.
Thanks, Mark. I will start with our Q2 2013 Eagle Ford results. EOG's Eagle Ford acreage continues to prove that it's the premier horizontal ore position in North America. During the second quarter, we consistently completed strong wells in both the eastern and western portions of our acreage that drove our record production results. In addition, drilling and completion improvements continue to drive down well costs.
As a result, we have lowered the average completed well costs in the Eagle Ford from $6,000,000 to $5,500,000 and we increased the number of wells we plan to drill this year from 425 to 440. Fine tending this engine with continuous cost reduction and improved well productivity makes EOG's Eagle Ford acreage the strongest oil growth and capital return machine in North America. And the best part is we have a 12 year drilling inventory in this play that will provide many years of oil growth and superior capital returns. In our Western acreage, we have drilled a large number of wells allowing us to fine tune our completion technology. We are now making wells with rates of return that are approaching wells drilled in the eastern part of our acreage.
In LaSalle County, the Keller number 1H and 2H had initial daily production rates of 18.55 barrels of oil and 2,050 barrels of oil with 5.90 and 400 Mcf per day of rich gas respectively. The smart number 1H and 2H began production at 1495,230 barrels of oil per day with 4 80 and 6.10 Mcf per day of rich gas respectively. In McMullen County, the Naylor Jones B 1H started production with 18.30 barrels of oil per day and 19 20 Mcf per day of rich gas. EOG has a 100% working interest in each of these wells. To show how wells have improved on our Western acreage, the updated IR presentation can include slides that show well IPs marching upward as a result of better frac techniques and longer laterals.
As an example, slide number 21 shows that the Keller and Smart Unit wells drilled in 2013 are 30% better than offset wells drilled in 2012. In addition to making better wells, we are driving down well cost through efficiencies. Slide number 22 shows spud continue to drop with wells in 2013 down to less than 10 days. As a result, our 2013 well costs have decreased by $1,000,000 per well in certain areas from 2012 levels. With the combination of improved well productivity and cost reduction, our Western drilling activity now has an average direct ATAX rate of return in the 100% range on par with many of the wells in the East.
In the East, we again set a new record with the completion of the Burrell Unit 5H, which had an initial production rate of 7,515 barrels of oil per day and 6,880 Mcf per day of rich gas. Consistently, the number one driver for better wells in all areas is improved frac techniques and that's the case for the Burroughs 5H. Also in the East, we completed the Wyall Trust 1H, 2H and 3H wells with initial rates of 5,475, 6,520 5,525 barrels of oil per day with 7,040, 5,690 and 6,200 MCO per day of rich gas respectively. We have 100% working interest in each of these wells. The takeaways from our Q2 Eagle Ford results are: number 1, EOG continues to make significant improvements in well productivity and cost reductions in both the Eastern and Western portions of our acreage.
Number 2, EOG's drilling results from the large number of wells in our western acreage confirm that the western part of the play can deliver high direct capital rates of return and strong production growth. Number 3, our large number of high quality drilling locations in the Eagle Ford gives EOG the platform to have superior oil growth for many years to come. In the Bakken core, our 160 acre or 4 wells per unit downspacing program in the Parsha Seal in Montreal County, North Dakota is yielding impressive results. Recent completions include the Parshall 22 and 253032 H with initial production rates of 2,120,680 5 barrels of oil per day with 505 and 9.45 Mcf of gas per day respectively. We also completed the Van Hook 2930-eleven-thirteen H complete producing 2,390 and 2,295 barrels of oil per day with 2,010,000 cubic feet of gas per day respectively.
EOG has a 62% working interest in the partial wells and a 78% working interest in the Van Hook wells. We are very pleased with year to date downspacing results that show excellent progress in both well productivity and cost reduction. We've added some new slides in our IR presentation showing these operational improvements. There is a slide showing EOG's improved well productivity in the core and antelope areas over time. This improvement is a result of drilling longer laterals and using better frac techniques.
The average EUR from our 2013 program is 9.40 MBOE per well gross, more than a 180% improvement over wells we were drilling only 2 years ago. To control costs as lateral lengths increase, we've been able to reduce 2013 drilling times for an average 10,000 foot lateral to 16.9 days, which is a 30% decrease compared to 2012 levels. As a result of better wells with lower cost, our year to date 2013 Bakken program is generating direct ATAX rates of returns of 100%. As we have said previously, the majority of the 53 net wells drilled this year will be down spaced with the goal of maximizing the net present value of this large EOG asset. Based on further evaluation of Three potential on our acreage and the success of our Bakken Downspacing program, we have increased our total Bakken Three Forks drilling inventory from 7 to 12 years.
The takeaway is our Bakken 3 Forks asset is another segment of VOG's deep crude oil inventory that will provide high margin production growth for many years to come. In the Delaware Basin, we continue to see improved results from both our Leonard and Wolfcamp plays. During the Q2, we completed 3 outstanding wells in the Leonard. In Lea County, New Mexico, the Diamond 31 FedComm 2H, 3H and 4H began producing at 1780, 1905, and 1530 barrels of oil per day, plus 215, 165, 150 barrels of NGL per day and 1200, 910 and 835 Mcf of gas per day respectively. EOG has a 91% working interest in each of these wells.
We continue to make strong improvements in both well productivity and cost reduction and our year to date drilling results have a direct ATAX rate of return in excess of 100%. This makes the Leonard one of EOG's top return plays. The returns are competitive with those of the Eagle Ford and the Bakken. As a reminder, we have approximately 1600 Leonard Well Cloak locations in our current drilling inventory. With these excellent returns, we plan to shift more capital to this play in the future.
In the Delaware Wolfcamp, we completed our 4th well in the 2nd quarter, drilled in a Wolfcamp sweet spot of Reeves County, Texas, the Phillips State 506301H was completed in the Upper Wolfcamp interval, flowing 8 70 barrels of oil per day with 5 70 barrels of NGL per day and 3,700,000 cubic feet of gas per day. We have 100% working interest in this well. The Phillips State is our best well to date in this play and it builds on our confidence that the Delaware Basin Wolfcamp is a high quality shale play. We now have a combined database of over 200 subsurface well logs on our acreage along with access to full core rock data, microseismic frac data, 3 d seismic data and four recently completed horizontal wells that confirm the strength of the play with a direct ATAX rate of return of 60% and over 1100 drilling locations in our current inventory, the Delaware Wolfcamp is another strong asset in EOG's portfolio. Since this is a newer play with infrastructure constraints, the newer leases, our development activity will be slower relative to the Leonard.
In summary, EOG's Delaware Basin Leonard and Wolfcamp positions are located in the sweet spots of 2 very strong horizontal shale plays. Using a conservative recovery factor, we have roughly 2,700 drilling locations with 1,300,000,000 barrels equivalent of net reserve potential that we can develop at very high capital investment returns. The Delaware Basin plays are another reason that EOG will continue to have significant production growth for many years in the future. During the Q2, we continue to test multiple pay intervals and spacing patterns in the Midland Basin Look Camp. In Crockett County, the University 40 C 1705H, 1706H and 1707H were completed in the middle zone with initial rates of 1130, 725 and 70 barrels of oil per day, plus 110, 90 and 75 barrels of NGL per day and 800, 635 and 545 Mcf of gas per day, day, respectively.
EOG has a 90% working interest in each of these wells. We also completed another excellent well in the Lower Pike with the University 41,002 H which had an initial rate of 11.10 barrels of oil per day plus 155 barrels of NGL per day and 115 Mcf of gas per day. The company has a 75% working interest in this well. As we have discussed previously, the Midland Basin Wolfcamp play is more technically and economically challenging than the Delaware place. We are using extensive microseismic and 3 d seismic tools to improve the completion effectiveness and reduce the well spacing in order to improve the recovery factor.
We are making steady progress. In the Barnett combo, after more than 10 years in this area, we still continue to drive down drilling days and average well costs and improve well productivity. Recent wells include the 100 percent working interest, Madsen A Unit 1H and 2H and Madsen B Unit 1H with initial production rates of 4 30, 435,335 barrels of oil per day with 340, 330 and 230 Mcf of rich gas per day respectively. We drilled the Matson wells from spud to TD in an average of 4 days with a total completed cost of only $2,400,000 per well. Low cost along with consistently good wells continues to give EOG solid 30% to 40% direct ATAX rate of returns on this program.
In Trinidad, we brought the Osprey OA 4 well online last month at a 30,000,000 cubic feet of gas per day rate. We are in the process of completing an additional 4 wells to increase our overall deliverability. In the East Iris Sea, the start up of our Connolly oil project is now estimated for mid-twenty 14. I'll now turn it over to Tim Drueggers to discuss financials and capital structure. Thanks, Bill.
Capitalized interest
for the quarter was $11,800,000 For the Q2 2013, total cash exploration and development expenditures were $1,700,000,000 excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $91,300,000 As compared to Q2 2012, total cash expenditures decreased by $278,000,000 There were $2,600,000 of acquisitions during the quarter. During the Q2, net cash provided by operating activities exceeded financing and investing cash outflows. In fact, we were cash flow positive during the quarter, excluding any proceeds from asset sales. Through August 1, we closed on asset sales of approximately $580,000,000 At the end of June 2013, total debt outstanding was $6,300,000,000 and the debt to total capitalization ratio was 31%.
At June 30, we $1,200,000,000 of cash on hand, giving us non GAAP net debt of $5,100,000,000 or a net debt to total cap ratio of 26%, a reduction from the year end 2012 ratio of 29%. The effective tax rate for the 2nd quarter was 36% and the deferred tax ratio was 77%. Yesterday, we included a guidance table with the earnings press release for the Q3 and full year 2013. Our original CapEx estimate of $7,000,000 to $7,200,000,000 excluding acquisitions remains unchanged. For the Q3, the effective tax rate is estimated to be 30% to 40%.
For the full year, the effective rate is estimated to be 35% to 40%. We've also provided an estimated range of the dollar amounts of current taxes that we expect to record during the Q3 and for the full year. Now I'll turn it over to Mark.
Thanks, Tim. Now I'll provide some views regarding the macro environment, hedging crude by rail and concluding remarks. Regarding oil, we're hesitant to provide any short range WTI price predictions considering the volatility we've seen over the past month. We note that recent monthly EIA data is consistent with our expectation that 2013 year over year domestic oil growth will be less than poor quality acreage or plays struggle to grow at rates similar to EOG. We believe U.
S. Oil production will continue to grow in future years, but at slower rates than 2012 and this is bullish for the global supply demand picture. Additionally, we are not sanguine regarding any large international shale oil plays affecting global supply within at least the next several years. Overall, we continue to be bullish regarding oil fundamentals and prices. For the remainder of 2013, we're approximately 53% hedged at $98.82 and we have approximately 98,000 barrels per day hedged for the first half of twenty fourteen at $96.48 Because the NYMEX is severely backwardated, we currently have only a very small hedge for the second half of twenty fourteen.
These numbers exclude options that are exercisable by our counterparties. Regarding North American gas prices, we consider 2013 to be another in a long string of disappointing years and we expect gas supply to continue to trump demand causing continued weakness over the next several years. Our gas hedge position is unchanged from last quarter. We also expect NGL prices, especially ethane, to remain weak throughout 2014. Our crude by rail again was a very profitable business for us in the 2nd quarter piece of business for us in the second quarter and
our average U.
S. Wellhead price
was $9.50 over WTI. We expect the premium over the index to decrease in the second half of the year due to the number of new pipelines to the Gulf Coast Louisiana markets, but we see sustained high oil prices. Our Q3 projected average U. S. Oil price is $2.75 above WTI.
The offset is WTI prices have increased over the course of the year, particularly in recent weeks. The net effect is EOG is still receiving a premium to higher overall U. S. Oil prices. To provide some understanding of our oil netbacks, describe our current crude marketing in our 3 major areas.
In the Eagle Ford, the majority of our oil is piped to Houston where it currently receives LOS index prices. In the Bakken, essentially all of our oil is being railed to St. James, Louisiana. And in the Permian, part of our oil is being railed to St. James and part is sold locally.
We have the flexibility to sell any of our rail volumes at Cushing instead of St. James if the differentials dictate that is consistent with what we outlined on the February May calls, except for the 2013 volume growth increases. As Tim mentioned, we still expect CapEx excluding acquisitions to be between $7,000,000,000 $7,200,000,000 and proceeds from dispositions to date are $580,000,000 Effective this quarter on a unit cost basis, we reduced our full year LOE and DD and A estimates. We still don't plan to drill any dry gas wells this year and we continue to have 0 interest in growing gas volumes in the current price environment. Now let me conclude.
There are 3 important takeaways from this call. First, EOG's first and second quarter results are the result of having acreage in the premier domestic shale oil plays and the best in house completion technology. Simply put, our average 2013 Eagle Ford, Bakken and Leonard well is performing better than predicted. This is particularly true of our Western Eagle Ford wells. Our current acreage will position us as an industry oil growth leader for many years to come.
2nd, the vast majority of our CapEx this year is going into 3 plays currently yielding greater than 100 percent direct after tax reinvestment rate of return, the Eagle Ford, Bakken and Leonard. Each of these has 10 plus years of additional drilling inventory. EOG has a track record of execution. Our 7 year compound annual oil growth rate is 38%. This high return domestic onshore oil growth we're achieving isn't just for growth sake.
What's significant is that EOG's production growth is showing up in the bottom line with first half non GAAP net income up 69% year over year driving increasing ROEs and ROCEs. And finally, as is evident by our results, EOG is firing on all cylinders volumes, unit costs, price realizations, returns and net debt reduction. Thanks for listening. And now we'll go to Q and A.
Thank you. The question and answer session will be conducted electronically. And we'll take our first question from Leo Mariani with RBC.
Hey, guys. How are you? Great results here. Just a question on the Western Eagle Ford. Obviously, as you guys have moved west, it just seems like the results have certainly surpassed your expectations.
I think you guys last update on sort of the Eagle Ford average EURs I think was 450,000 BOE. You guys think that that has got some upward bias here given the strength as you've moved out your core
area? Yes, Leo. I'll let Bill answer that. But I think the number is 400 Boe is the last update we've given on that. So that's the number that we're sticking with at this point.
But let me have Bill address that.
Elliot, no, you're right. I mean that's what we have talked about extensively here is that our Western Eagle Ford results are just like in all of our plays. I mean they are coming up really, really nicely. The main driver for that of course is the completion technology and the cost reduction too goes along with that. But the most important factor in improving the wells is the use of EOG sand.
That has been a major factor in improving our wells. And so it also helps us to drive down the well cost. And we're certainly watching the per well EURs in the Eagle Ford as we go along here. The thing that we're not going to do is we're not going to rush to change the EURs on a per well basis and really until we complete the downspacing program in the Eagle Ford. And we're still actively downspacing both in the east and the west side of the Eagle Ford.
And so while we continue to push wells closer together, we want to be careful about that per well EUR and we want to make sure we have enough time to evaluate the long term effects of the wells on those tight spacing patterns. So we want to we're going to hold firm with that 400 MBOE per well for now.
And we'll take our next question from Pierce Hammond with Simmons and Co.
Yes. Good morning and congratulations on another exceptional quarter. Our EOG's EUR improvements in the Bakken is highlighted on slide 26 in your presentation, is that applicable to your Bakken light acreage as well?
Yes, Pierce. That is. That's a common thing that we've completed a few wells in other areas in the core in Antelope and we've seen excellent results from the new completion techniques in all of our areas. So it would apply across the board. Of course, I mean everybody realizes our core acreage and our Antelope acreage is the highest quality acreage.
So the EURs in the other areas might not be as good, but certainly the completion techniques are very effective in all of the Bakken.
And we'll take our next question from Brian Singer with Goldman Sachs.
Thank you. Good morning. Drilled in the last year, and whether you're seeing the drilled in the last year and whether you're seeing decline rates that are in line better or worse than your type curve. I guess those issues along whether sand supply and sand supply costs will continue to kind of be available to support the remaining inventory. I would think those would all be key towards your ability to someday raise that EUR.
No. I'd say that our remaining inventory in the Eagle Ford is pretty analogous to what we've drilled so far this year. As far as the sand supply issue, that's definitely not a problem. We have our in house sand mine. So the sand supply issue is really off the table.
There's not a question at all there. And I know there have been some questions about our theory that some people have had about us is our as we moved west in the Eagle Ford, the quality of our inventory was alleged to deteriorate. But I think the one thing that results from this earnings call should dispel is the fact that our inventory in the West is pretty darn strong and we've always had a mix of East and West. We've never preferentially drilled in one area per se. So I think the concern people should have about as we drill in later years in the Eagle Ford that the rate of change in the Eagle Ford is going to somehow decline, that's just not true.
And that's why we've been talking so much about this 5 year plan, why we are so confident that our oil growth during that period is going to be superior to all other large cap E and Ps because we have the engines of growth with Eagle Ford, DeBanc and the stuff we have in the Permian. And when you think about it, we've got a 7 year run with 38% compound annual oil growth, which I'm pretty sure is much stronger than any other company, certainly in our peer group. And we're telling you the next 5 years is going to be much stronger than a peer group. Certainly, if you look at our 1st and second quarter results, that should certainly underpin that confidence. So we feel very, very good about this.
And the Q2 data should dispel any notions anyone should have about the rate of change in the Eagle Ford being a concern.
And we'll take our next question from Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, Mark, and good morning, everybody. Mark, first of all, congratulations on your transition. It seems that the quarter hasn't really suffered for it. But if I may ask a question about downspacing in the Eagle Ford.
You talked about 40 in the East and 60 in the West, but it seems from these well results in the West that at least we should be asking the question about how you see the inventory and the downspacing results going forward. Can you speak to whether or not you're continuing to test tighter spacing and what your latest thinking is there? And I've got a follow-up please.
Yes, Doug. Yes, we are continuing to test down spacing in both the eastern portions of our Eagle Ford acreage and the western portions of that. And we're going to continue to push that. The goal that we've always had is to maximize the net present value of the asset and we really approach that from on a per acre basis. So as we drive the well costs down and we push the wells closer together on the spacing patterns, the goal is to maximize the net present value there.
And we're not sure if we've reached those limits or not. We've been able to improve in that present value over time considerably with both cost reduction and well improvements. And certainly that corresponds into additional reserve recovery we've increased several times. So the process continues in all areas. The completion technology continues to advance and we're not letting up on that.
The cost reduction continues to advance. The increase in the recovery factor continues to advance and all of that is focused on the net present value of the asset. So everything is moving ahead.
And we'll take our next question from Matt Portillo with Tudor, Pickering, Holt.
Good morning, guys. Just one quick question for me. You mentioned rail marketing and the relative netbacks of LLS versus Cushing pricing on pipe. And I was just curious if you could provide a little bit more color given the current spread dynamics of how you guys are thinking about railing versus piping crude out of the Bakken and how those economics may change over time? Thank you.
Yes. Well, we can say that because relating to our crude, there really isn't a pipeline option. I mean, the only pipeline that's up there is the Enbridge pipeline. And we have very limited access to the Enbridge Pipeline. And so our pragmatic options up there would be trucking the crude versus railing the crude and it's a slam dunk there.
So for us, railing the crude is the only way to go. So then it just boils down to do you bring the crude to Cushing or do you bring it to St. James. And so far for us with the differentials where they sit today, it's still preferential for us to take it to St. James versus Cushing.
And but we have that option if and when the advantage would flip the other way to take it to Cushing. We're one of the few companies who do would have a rail option of either place if and when that became advantageous. Next question?
And we'll take our next question from Irene Haas with Wunderlich Securities.
Hi. Again, congratulations on just doing such great signs and turning out really new place year after year. And my question has to do with Reeves County and the 4 wells that you have drilled thus far. I can see sort of the percentage of oil actually marching up with your newer wells. So it's looking like sort of 40% oil.
Can you shed a little light on when all is said and done sort of what is your EUR composed of in terms of percent oil, natural gas, liquid and gas?
Yes, Irene. Yes, we have a slide on that with a pie chart. I believe that's slide 31. And our latest estimate here is that on the typical Wolfcamp well it's 34% oil, 34% gas and 32% NGL. And we found that the percent oil is a little variable depending on what zone you drill in, in the Wolfcamp.
And so we're testing multiple zones there. Of course, there's an enormous amount of resource in place there in our Reeves County. We've been fortunate to be able to lease up a very strong sweet spot in the Delaware Basin Wolfcamp where the shale thickness is very thick and also the quality of the shale is very high. So we'll get a better handle I think. We're going to drill 10 wells this year approximately and we'll be trying multiple zones there.
And I think by sometime later in the year, by next year, we'll have a little bit better idea kind of what the balance will be on the content of everything. But right now, we feel like this 34% oil is probably going to be pretty close to what it's going to be.
And we'll take our next question from Amir Aras with Stifel.
The question really is about your positive free cash flow position that you're going to start hitting in 2014. I know you lay out 3 different priorities, but could you just give us some more color in terms of how you're thinking of use of that excess free cash flow in terms of excess above a steady dividend growth? How much would go to incremental capital spending? And the follow-up would be on the incremental capital that you would allocate, how would you think about splitting that between your three core areas of Eagle Ford, Bakken and Permian? Thanks.
Yes, Amir, that's a good question. We're going to have a lot of cash. And certainly, the priority is we set out and we've given these guidelines is that we want to continue to work on the dividend. We've had a nice 14 year increases in dividends and so we want to continue that and reward the shareholders in that way. We also want to focus some of the money.
The second party would be to continue to reduce the debt of the company, not to extremely low levels, but a bit lower than where we are right now. And then number 3, we will have additional cash each year to invest in our best place. And certainly, the highest rate of return plays will be the priority there and the places where we can invest to grow oil prices oil production most aggressively. And those will not be much different than they are this year. They'll be certainly the focus number 1 will be the Eagle Ford and the Bakken.
And as we over time, we'll be focusing more capital into the Leonard. It's turning into the very high rate of return play for us and very oily also. So each of those plays have more than 10 years of inventory and they're extremely high quality plays. And that's what gives us the confidence that we can continue to be the peer leader in oil growth through 2017 and beyond.
And we'll take our next question from Arun Jayaram from Credit Suisse.
Good morning, gentlemen. Just wanted to ask you a couple of quick questions. One, Bill, I was just wondering to see if you've done any analysis on maybe stratifying the wells drilled in the Eagle Ford, looking at some of the Monster monster wells versus perhaps a more typical well? And any just general comments on decline rates you've seen over the first year whatnot relative to both of those?
Yes, Arun. The stratigraphy of the Eagle Ford is pretty consistent from east to west. There's not a lot of individual zones developing and coming and going as you kind of go across the play. Some of the changes are I think in the eastern part of the acreage there's more faulting. And so there's more open fracture systems available and that's why you see sometimes you see very high IPs from the wells in the east.
On the West side, there's less faulting and less open fracture systems. And so it takes a little bit of a different completion technique, which we obviously we are making very good progress with that. And maybe the IPs may not ever approach the wells on the East, but certainly the results in the West are very, very good. We've been able to develop techniques to increase the amount of rock that we connect to the well. One of it is we drill longer laterals in the west and we use a different kind of completion style and all that's to design to connect up to the more of the matrix of the rock.
And so we're certainly getting really good results in both areas. And both areas as Mark has said, we have an enormous amount of locations in both sides. And so the quality of our program is certainly not going to deteriorate over time. It's very, very, very strong.
And we'll take our next question from Marshall Carver with Heikkinen Energy Advisors.
Yes. Good morning. A question on the Bakken. You have 90,000 acres in the Bakken core. How many acres do you have in the Antelope Extension State Line and Elm Coulee areas?
Yes, Marshall, that's a question. We've not updated our acreage position in Antelope or the core. But you're right, we have 90,000 acres in the core. And this is an estimation, but I think it's approximately about 20,000 acres in the Antelope area.
And we'll take our next question from Barry Haynes with Sage Asset Management.
Hi. Thanks for getting my question in. I had a question in the Bakken. I understand and you alluded to longer lateral lengths and changing completion techniques a couple of times in the call. And I guess in the back end you drilled a few wells with maybe 15,000 foot laterals and maybe 4 or 5 times the amount of proppant.
And I wonder when you're talking about the different completion techniques, is that what you're alluding to? And number 1. And then number 2, how applicable is that across the Bakken and then maybe also in the Eagle Ford? Thanks very much.
Yes. In the Bakken, we feel we have a completion advantage there and we're happy to disclose that we're using more pounds of proppant than we have in the past and that we are drilling longer laterals. But as far as giving any more specifics other than that, we feel we'd be giving away some proprietary secrets. And so I'm afraid, Barry, we're just going to have to leave it at that. And the same for the Eagle Ford.
We have gone to some bigger fracs in Eagle Ford than we have in the past. But again, we feel we clearly have a proprietary advantage in our frac technology in Eagle Ford also and we just assume keep it proprietary. Thank you.
And we'll take our next question from Ray Deacon with Breen Capital.
Yes. Hi, good morning.
I was wondering if you could give a little bit more detail on the Wolfcamp. How many of each zone do you think you will have tested this year?
Yes. Ray, in the Delaware are you talking about the Delaware Wolfcamp? I guess so.
Yes. Thank you. Yes.
In the Delaware Wolfcamp, right, we tested 3 zones this year, call them the upper, middle and lower zone there. And we've had really good results in each one of them. As I said before, there's a little bit of different mix in each zone on the product mix, whether it's oil or gas. But the rock quality and the response of the wells on each one of those have been very, very, very strong. So we feel that we've been very fortunate to lease up a really nice large position of the sweet spot there.
And we'll take our next question from Charles Meade with Johnson Rice.
Yes, good morning and thank you for taking my question. I wanted to get a little more detail on the Burrow unit and particularly I believe it was the 5H or perhaps it was 4H that had that really fabulous IP. But the one thing that I noticed was a little different is that you guys offered the 30 day average and you get to a 30 day cumulative of I think 128,000 barrels, which is really impressive. And would I be wrong to read into that that the reason that you guys chose to include that 30 day rate is that it's better than other wells in the past? And that and if that's correct to read into it, is that a function of your improved frac design?
The boroughs did have a longer lateral. It's about 7,500 foot lateral. The other 2 are quite a bit shorter. But as far as us reporting the cumulative, it's relative to other wells, it's not proportionately any larger. They're all performing about the same, just longer lateral.
And at
this time, I'd like to turn it back to our speakers for any closing or additional remarks.
Yes. I'd just close with 2 remarks. Just again to summarize, I think 2 points you'd want to take away from the call. First point is, again, the Western Eagle Ford is an area that we're particularly proud of with the results. And the second point is for the first time we can highlight 3 key oil plays.
We're on a direct after tax rate of return basis. In each of these plays we're achieving 100% or greater rate of return, Eagle Ford, Bakken and Leonard. So thanks for listening and we'll talk again in 3 months from now.
And this concludes today's conference. Thank you