EOG Resources Inc (EOG) 2013 Q2 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources second quarter 2013 earnings results conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Executive 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 second quarter 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.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 reserve reporting guidelines. We incorporate by reference the cautionary note to US 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 Maire Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website yesterday evening and we included third quarter and full-year guidance in yesterday's press release. This morning we will discuss topics in the following order. I'll first discuss second 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 will cover our macro view, hedge position and concluding remarks.

As outlined in our press release, for the second quarter 2013, EOG reported net income of $659.7 million, or $2.42 per share. For investors who focus on non-GAAP net income to eliminate mark to market impacts and certain nonrecurring items as outlined in the press release, EOG's second quarter 2013 adjusted net income was $573.8 million, 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 second quarter was $1.9 billion dollars.

Similar to the first quarter, EOG continued to hit on all cylinders in the second 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 estimates from 10% to 14%, and we've increased our total company overall growth target from 4% to 7.5%. 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 first 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 five-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 him well qualified to deliver on a five-year plan and guide the Company for many years beyond that.

Thanks, Mark. I will start with our second quarter 2013 Eagle Ford results. EOG's Eagle Ford acreage continues to prove that it's the premier horizontal oil 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 cost in the Eagle Ford from $6 million to $5.5 million, and we've increased the number of wells we plan to drill this year from 425 to 440. Fine tuning 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 on 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 aligning 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 1-H and 2-H have initial daily production rates of 1,855 barrels of oil and 2,050 barrels of oil with 590 and 400 Mcfs per day of rich gas, respectively. The Smart number 1-H and 2-H began production at 1,495 and 2,030 barrels of oil per day with 480 and 610 Mcf per day of rich gas, respectively. In McMullen County, than Mailer-Jones B number 1-H started production with 1,830 barrels of oil per day and 1,920 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 includes 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 costs through efficiencies. Slide number 22 shows spud to TD drilling days continued to drop, with wells in 2013 down to less than 10 days. As a result, our 2013 well costs have decreased by $1 million 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 a-tax 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 Burrow unit number 5-H, 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 Burrows 5-H. Also in the East, we completed the Wild Trust number 1-H, number 2-H, and number 3-H wells, with initial rates of 5,475, 6,520 and 5,525 barrels of oil per day, with 7,040, 5,690 and 6,200 Mcf per day of rich gas, respectively. We have 100% working interest in each of these wells.

The take-aways from our second quarter Eagle Ford results are -- number one, EOG continues to make significant improvements in well productivity and cost reductions in both the eastern and western portions of our acreage. Number two, EOGs 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 three, 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, down spacing program in the Parshall field in Mountrail County, North Dakota is yielding impressive results. Recent completions include the Parshall 22- and 25-3032-H, with initial production rates of 2,120 and 2,685 barrels of oil per day, with 505 and 945 Mcf of gas per day, respectively. We also completed the Van Hook 29- and 30-1113-H, producing 2,390 and 2,295 barrels of oil per day, with 2.0 million and 1.1 million cubic feet of gas per day, respectively. EOG has a 62% working interest in the Parshall 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 940 MBOE per well gross, more than a 180% improvement over wells we were drilling only two years ago. To control cost as lateral links 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 a-tax rates of returns of 100%. As we have said previously, the majority of the 53 net wells drilled this year will be downspaced, with the goal of maximizing the net present value of this large EOG asset. Based on further evaluation of Three Forks' 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 take away is our Bakken Three Forks asset is another segment of EOG'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 second quarter, we completed three outstanding wells in the Leonard. In Lea County, New Mexico the Diamond 31 [Fedcon] number 2-H, number 3-H, and number 4-H began producing at 1,780, 1,905, and 1,530 barrels of oil per day, plus 215, 165, and150 barrels of NGL per day, and 1,200, and 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 a-tax 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 1,600 Leonard well 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 fourth well in the second quarter. Drilled in a Wolfcamp sweet spot of Reeves County, Texas, the Phillips State 56-301-H was completed in the upper Wolfcamp interval, blowing 870 barrels of oil per day, with 570 barrels of NGL per day and 3.7 million 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, micro seismic frac data, 3-D seismic data, and four recently completed horizontal wells that confirm the strength of the play. With a direct a-tax rate of return of 60% and over 1,100 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 and 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 two very strong horizontal shale plays. Using a conservative recovery factor, we have roughly 2,700 drilling locations with 1.3 billion 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 the future.

During the second quarter, we continued to test multiple pay intervals and spacing patterns in the Midland Basin Wolfcamp. In Crockett County, the University 40-C number 1705-H, number 1706-H, and number 1707-H were completed in the middle zone with initial rates of 1,130, 725 and 1,070 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, respectively. EOG has a 90% working interest in each of these wells. We also completed another excellent well in Irion County in the lower pay, with the University 40-1002-H, which had an initial rate of 1,110 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 play. We are using extensive micro seismic 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 cost and improve well productivity. Recent wells include the 100% working interest Matson A unit number 1-H and 2-H and Matson B unit number 1-H, with initial production rates of 430, 435 and 335 barrels of oil per day, with 340, 330 and 240 Mcf of rich gas per day, respectively. We drilled the Matson wells from spud to TD in an average of four days, with a total completed cost of only $2.4 million per well. Low cost, along with consistently good wells, continues to give EOG solid 30% to 40% direct a-tax rate of returns on this program.

In Trinidad, we brought the Osprey OA-4 well online last month at a 30-million cubic feet of gas per day rate. We are in the process of completing an additional four wells to increase our overall deliverability. In the East IRC, the start up of our Conway oil project is now estimated for mid-2014. I'll now turn it over to Tim Driggers to discuss financials and capital structure.

Thanks, Bill. Capitalized interest for the quarter was $11.8 million. For the second quarter 2013, total cash exploration and development expenditures were $1.7 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property plant and equipment were $91.3 million. As compared to second quarter 2012, total cash expenditures decreased by $278 million. There were $2.6 million of acquisitions during the quarter.

During the second quarter, net cash provided by operating activities exceeded financing 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 million. At the end of June 2013, total debt outstanding was $6.3 billion and the debt to total capitalization ratio was 31%. At June 30, we had $1.2 billion of cash on hand, giving us non-GAAP net debt of $5.1 billion, for 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 second quarter was 36%, and the deferred tax ratio was 77%.

Yesterday, we included a guidance table with the earnings press release for the third quarter and full-year 2013. Our original CapEx estimate of $7.0 billion to $7.2 billion, excluding acquisitions, remains unchanged. For the third quarter, 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 third quarter 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 2012. We expect EOG's oil growth performance will be atypical of the industry, as other companies with poorer quality acreage or plays struggle to grow at rates similar to EOG. We believe US 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 2014 at $96.48. Because NYMEX is severely back-dated, we currently have only a very small hedge for the second half of 2014. These numbers exclude options that are exercisable by our counter parties. 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 piece of business for us in the second quarter, and our average US 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 third quarter projected average US 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 US oil prices.

To provide some understanding of our oil netbacks, I'll briefly describe our current crude marketing in our three 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 more profitable.

I'll now briefly address our 2013 business plan, which is consistent with what we outlined on the February and May calls, except for the 2013 volume growth increases. As Tim mentioned, we still expect CapEx, excluding acquisitions, to be between $7.0 billion and $7.2 billion, and proceeds from dispositions to date are $580 million. Effective this quarter, on a unit cost basis, we've reduced our full-year LOE and DD&A estimates. We still don't plan to drill any dry gas wells this year, and we continue to have zero interest in growing gas volumes in the current price environment.

Now let me conclude. There are three important take-aways from this call. First, EOG's first and second quarter results are the result of having the best 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. Second, the vast majority of our CapEx this year is going into three plays currently yielding greater than 100% 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 are achieving isn't just for growth's 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&A.

(Operator Instructions)

Leo Mariani, RBC Capital Markets.

Great results here. Just 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 Eagle Ford average EU, I think was 450,000 BOE. Do you guys think that that has got some upward bias here, given the strength as you've moved out of your core area?

Yes, Leo. I'll let Bill answer that, but I think the number is 400 BO 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.

Leo, no, you're right. What we have talked about extensively here is that our western Eagle Ford results are just like in all of our plays. 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 factors 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 Pearl well EURs and the Eagle Ford as we go along here. The thing that we are not going to do is we are not going to rush to change the EURs on a per well basis, and really until we complete the down spacing 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're going to hold firm with that 400 MBOE per well for now.

Pearce Hammond, Simmons & Company.

Good morning, and congratulations on another exceptional quarter. Are EOG's EUR improvements in the Bakken, as highlighted on slide 26 in your presentation, is that applicable to your Bakken light acreage, as well?

Yes, Pearce, that is. That's a common thing that we've completed a few wells in other areas in the Core and 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, everybody realizes our Core acreage and our Antelope acreage is the highest quality acreage we have. So the EURs in the other areas might not as be as good, but certainly the completion techniques are very effective on all of the Bakken.

Brian Singer, Goldman Sachs.

Thank you. Good morning. Wanted to just follow-up on the Eagle Ford here, and wanted to see if you could characterize the remaining locations that you have to drill in the Eagle Ford and the quality of those locations, whether it's meaningfully different from those that have been drilled in the last year and whether you're seeing decline rates that are in line, better or worse, than your type curve? And I guess those issues, along with whether Sand supply and Sand supply costs will continue to be available to support the remaining inventory? I would think those would all be key towards your ability to some day 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 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 in 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 five-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&Ps, because we have the engines of growth, with Eagle Ford, the Bakken, and the stuff we have in the Permian. And when you think about it, we've got a seven-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 five years is going to be much stronger than the peer group. And certainly, if you look at our first and second quarter results, that should certainly underpin that confidence. So we feel very, very good about this. And this second quarter data should dispel any notions anyone should have about the rate of change in the Eagle Ford being a concern.

Doug Leggate, BofA Merrill Lynch.

Thanks. Good morning, Mark, and good morning, everybody. Mark, first of all, congratulations in your transition. It seems like 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 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 in 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. We are continuing to test downspacing 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 reach those limits are not. We've been able to improve the net present value over time considerably, with both cost reduction and well improvements. And certainly, that corresponds into additional reserve recovery, which 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 increasing the recovery factor continues to advance, and all of that is focused on the net present value of the assets. So everything is moving ahead.

Matt Portillo, Tudor, Pickering, Holt.

Good morning, guys. Just one quick question for me. You mentioned rail marketing and the relative netbacks of LOS versus Cushing pricing on pipe, and I was just curious if you could provide a little bit more color given the current spread dynamics and 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. 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. But we have that option, if and when the advantage would flip the other way, to take it 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?

Irene Haas, Wunderlich Securities.

Hello. Again, congratulations on doing such great signs and turning out really new plays year after year. My question has to do with Reeves County and the four wells that you have drilled thus far. I can see some of the percentage of oil actually marching up with your newer wells, so it's looking like 40% oil. Can you shed a little light on when all is said and done, what is your EUR composed of in terms of percent oil, natural gas, liquid and gas?

Yes, Irene. We have a slide on that with a pie chart. I believe that's slide 31. And our latest estimate here is that on a typical Wolfcamp well it's 34% oil, 34% gas and 32% NGLs. 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, maybe next year, we'll have a little bit better idea what the balance will be on the content of everything. But right now we feel like the 34% oil is probably going to be pretty close to what it's going to be.

Amir Arif, Stifel Nicholas.

Thanks. Good morning, guys. Congratulations on a great quarter. The question really is about your positive free cash flow position that you're going to start hitting in '14. I know you lay out three different priorities, but can you 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've set out and we've given these guidelines, is that we want to continue 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 priority 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 three, we will have additional cash each year to invest in our best plays. 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 will be certainly the focus, number one 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 be a 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 are 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.

Arun Jayaram, Credit Suisse.

Good morning, gentlemen. Just wanted to ask you a couple quick questions. One, Bill, just wanted to see if you've done any analysis on maybe stratifying the wells drilled on the Eagle Ford, looking at some of the monster wells versus perhaps the more typical well. And any 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 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 is 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 wells. 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 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.

Marshall Carver, 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, Stateline and Elm Coulee areas?

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.

Barry Haynes, Sage Asset Management.

Hello. 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 on the call. And I guess in the Bakken, you've drilled a few wells with maybe 15,000-foot laterals, and maybe four or five times the amount of [propet]. And I wonder, when you're talking about the different completion techniques, is that what you're alluding to, number one? And then number two, 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 [propet] 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 the Eagle Ford also, and we'd just as soon keep it proprietary. Thank you.

Ray Deacon, Brean Capital.

Hello. 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, in the Delaware Wolfcamp, Ray, we've tested three 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've 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 has 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.

Charles Meade, 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 5-H, or perhaps it was the 4-H, 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 if that's correct to read into it, is that a function of your improved frac design?

The Burrows did have a longer lateral. It's about a 7500-foot lateral. The other two are quite a bit shorter. But as far as us reporting the cumulative, relative to other wells, it's not proportionally 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 two remarks. Just again to summarize, I think two points you'd want to take away from the call. First point is, again, the western Eagle Ford is an area that we are particularly proud of with the results. And the second point is, for the first time, we can highlight three key oil plays where on a direct after-tax rate of return basis in each of these plays, we are achieving 100% or greater rate of return, Eagle Ford, Bakken and Leonard. So thanks for listening, and we'll talk again in three months from now.

And this concludes today's conference. Thank you for your participation.