Ladies and gentlemen, thank you for standing by. Good day and welcome to the EOG Resources' First Quarter 2015 Earnings Results Conference Call. Just as a reminder, today's call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you. Good morning, and thanks for joining us. We hope everyone has seen the press release announcing first quarter 2015 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 U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. Participating on the call this morning are, Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, VP in Marketing Operations; and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening and we included guidance for the second quarter and full-year 2015 in yesterday's press release. This morning we will discuss topics in the following order. Bill Thomas, will review our 2015 plan and first quarter highlights; David Trice and Billy Helms will review operational results. I'll then discuss EOG's financials, capital structure, and hedge position, and Bill will provide concluding remarks. Here is Bill Thomas.

Thanks, Tim, and good morning. Our strategy this year is to remain laser focused on returns and position EOG to resume peer-leading oil growth when oil prices recover. We laid out a plan two months ago on our year-end call and I am pleased that our first quarter results are right on track. We are quickly transforming the company to be successful in this low price environment. There are four basic objectives to our 2015 plan. Objective number one, maximize 2015 return on capital invested and position the company to resume strong growth when oil prices recover. As we discussed earlier this year, our drilling operations are focused on our top three plays: the Eagle Ford, Delaware Basin, and Bakken, where 85% of our 2015 capital is directed. We generate a direct after-tax rate of return of 35% or greater, with a flat $55 WTI oil price in each of these plays, and returns improve as we lower cost and improve well productivity. We have also stated that we have no interest in accelerating oil production at the bottom of the commodity price cycle. Instead, we are drilling but deferring completions on a significant number of wells known as DUCs until oil prices improve. A $10 increase in the price of oil, with a six month deferral adds about $300,000 of net present value to a typical well. This amounts to a significant value creation from our drilled but uncompleted well inventory. It is the right business decision to drill the wells and defer completions, instead of buying out drilling contracts or growing oil in a low price environment. By deferring completion, and accelerating oil growth in a better price environment, we maximize 2015 return on capital invested and build momentum as we head into 2016. We plan to enter…

Thanks, Bill. If you recall, we increased capital spend this year in the Permian, but we are still in the early innings of evaluating ultimate potential of our Delaware Basin asset. As we ramped up activity in Delaware Basin, we've made quick progress using our integrated completions process. We identified the best drilling targets within the best reservoirs, while making sure we keep our laterals in these discrete intervals. This, combined with our use of advanced EOG completion techniques, has resulted in dramatically improved wells. During the first quarter, we were most active in the Second Bone Spring Sand play, where we are testing various targets as well as different well spacing patterns. Microseismic data we have gathered throughout the play indicates good pressure containment within the individual Second Bone Spring Sand targets. For example, we drilled three wells in Lea County, New Mexico, on the Jolly Roger 16 State Lease. The wells tested three different Second Bone Spring Sand targets at 600 foot well spacing. All three targets are very productive with IP rates ranging from 1,030 to 1,315 barrels of oil per day. And the technical data we collected does not indicate any production sharing between these wells. Going forward, we will continue to push spacing limits and test new targets. Another notable Second Bone Spring Sand well we brought on in the first quarter was the Brown Bear 36 State Number 502H, which IP'd at a rate of 1,700 barrels of oil per day. We are very pleased with these results and expect our individual well performance and recoveries to continue to improve as we refine our drilling targets and implement high density conclusions. In addition to impressive well results, we are pushing down cost. Our current well cost is $6 million, which is down 22% from…

Thanks, David. As we previously stated, most of our 2015 capital in our Rockies plays will be focused in the Bakken, with minimal activity in the DJ Basin and Powder River Basin. Each of these are well established plays with significant remaining potential. And now, all are benefiting greatly from the pull-back in activity. Plans are in place and steady progress is being made in lowering cost in each phase of our operations. In the Bakken, the slowdown in activity is allowing us to focus on three things. First, we have made tremendous progress on operational efficiencies and lowering well cost. Our typical 10,000 foot lateral is now drilled in just over 10 days. And the well cost is currently 14% less than the 2014 well cost. We anticipate this year's well cost will be as much as 20% below 2014 levels with a target of $7.4 million. Second, we are using new technical data from our integrated completion process to further adjust and tailor our high density completion designs to specific formation properties. Understanding and using this data gives us insight into to how to adjust the completion along the lateral to effectively optimize each stage. These modifications are leading to improved results. And third, we're able to maintain a more stable production base with minimal downtime associated with offset competition interference. This allows us to better evaluate the production from various spacing patterns to determine our ultimate development plan. In the first quarter, we began producing eight wells in two 500 foot space patterns in the partial area. Initial per well production rates from a five-well pattern averaged 1,235 barrels of oil per day and a three-well pattern averaged 1,345 barrels of oil per day. We are encouraged by the results from these down spacing patterns and are…

Thanks, Billy. Capitalized interest for the first quarter 2015 was $12 million. Total cash exploration and development expenditures were $1.5 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment, were $117 million. Drilling activity is expected to decline in the second quarter and flat now. And we have maintained our full-year capital expenditure guidance of $4.9 billion to $5.1 billion. At the end of March 2015, total debt outstanding was $6.9 billion, and the debt to total cap ratio was 28%. At March 31, we had $2.1 billion of cash on hand, giving us non-GAAP net debt of $4.8 billion or net debt to total cap ratio of 21%. In April, Moody's confirmed EOG's A3 rating with a stable outlook. The effective tax rate for the first quarter was 28% and the current tax expense was $31 million. For the period May 1, through June 30, 2015, EOG has crude oil financial price swap contracts in place for 47,000 barrels of oil per day at a weighted average price of $91.22 per barrel. For the period July 1, through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 barrels of oil per day at a weighted average price of $89.98 per barrel. These numbers exclude options that are exercisable by our counterparties. For the period June 1, through December 31, 2015, EOG has natural gas financial price swap contracts in place for approximately 203,500 MMBtu per day at a weighted average price of $4.31 per MMBtu. These numbers exclude options that are exercisable by our counterparties. Now, I'll turn it back over to Bill.

Thanks, Tim. We continue to believe that current oil process will discourage oil exploration and development worldwide and will encourage demand growth. This will correct the current oversupply situation and the market will continue to rebalance. We believe there is more upside to the forward curve than downside. In summary, here are some important points to take away from this call. First, EOG remains disciplined. We are committed to maintaining our strong balance sheet. We do not plan to increase 2015 CapEx. And at recent oil price, our CapEx to discretionary cash flow will be balanced for the remainder of the year. Second, the company's priority remains clearly focused on returns. We have directed 2015 capital to our highest oil return plays, which generate 35% or better after-tax rates of return at $55 WTI price environment. Returns are improving on each of these assets as we go forward. Well costs are going down and well productivity is going up. Even as oil prices have retreated, our direct rates of return are improving, and EOG will be more than competitive in the world markets as we go forward. Third, we continue to organically grow reserve potential in our existing plays through down spacing and completion enhancements. We believe that Eagle Ford, Delaware Basin, and Bakken, will continue to grow in drilling potential. We are also optimistic that we will find new potential through our exploration efforts. As we test and confirm meaningful results, we will update you with new potential reserve estimates in the future. Fourth, we've said all along that we are preparing to return to growth in 2016 when oil prices improve. If we have $65 WTI price environment in 2016, we can presume our strong double-digit oil growth profile with a balance CapEx to discretionary cash flow program. And finally, EOG is in this business for the long-term. We've not made short-term decisions this year that would hinder our future growth. This year, we are even more committed to advancements in the technology, exploration, cost reduction, and operational execution. The company is building on the culture that has set EOG apart and resetting the bar to be successful in a lower commodity price environment. As we look to the future, we fully expect to remain the North America growth leader and the peer leader in returns on capital employed. Thanks for listening. Now we'll go to Q&A.

Thank you. [Operator Instructions]. And we'll take our first question from Doug Leggate with Bank of America Merrill Lynch.

Bill, I wonder if I could touch on your completion strategy. What would it take -- what would we need to see in order to re-up the -- I guess the pace of completions to match your drilling pace? And I guess, and a related question is the backlog that you've talked about coming out of 2015, what kind of pace would you expect to move those towards production? And then I've got a quick follow-up please.

Yes, Doug, thanks for the question. Yes, the reason we've deferred the completions is to really substantially increase the rate of return. So as we go forward this year, it's really important for us to be patient and allow the prices to continue to firm up. As I've said, every -- the first $10 in oil price increase with a six months deferral is a $300,000 net PV add to typical well. So we want to make sure that we allow prices to firm up and that the prices will continue to be firm and not short-term. And then on a -- we are -- as you see, we're getting significant cost reduction as we go forward. We're gaining on that every day. And we're gaining on well productivity as we go forward. So we don't want to get in a hurry. We want to stay disciplined. We certainly don't want to jump, start completions, and the price may be fall back. So if the forward curve continues to stay firm, then our plan, as we said, is to begin completing wells in the third quarter. And we will really look at what the outlook on 2016 prices are that's what we're targeting and that's what we're really focusing on. So we'll just continue to watch the fundamentals and certainly we want to be convinced that they're strong going forward. And we'll really make the call for the third quarter activity probably July or so after we get a little bit more data.

So just to be clear on the pace of -- I mean you could obviously bring those completions back very, very quickly and turbo charge to your drill. So I don't know how easy as to frame the pace but I mean would you plan to have the backlog with just -- I guess a level of this equivalent to your current drilling rate within a period of time, can you help kind of walk us through how you may think about that, just trying to see what the upside is to the growth side, when you come -- when you go back to completing those wells?

Yes, we're going to -- I guess the answer to that, Doug, is we're going to be really patient and disciplined about it and kind of gradually increase the activities we go forward, making sure that the price is going to hold up. And we really do, as a company, EOG we're very, very focused on returns. So every time that price increases a little bit and every time we get the productivity wells up and get the cost down, we're making higher returns so there is no use pushing that too quickly. And so the ramp up will be, as we talked about, the production shape is going to be U-shaped this year and the second and third quarters will be the low point, but the fourth quarter, with the current plan, is to ramp up production growth and the heading into 2016 on a very strong note.

Appreciate that. But my very quick follow up, hopefully I'm not taking up too much time here, but just on the comment on the tactical acquisitions, I just wonder if I could indulge me as you can get indulge me to may be elaborate a little bit on whether you're -- you see a pipeline has sufficient closer between the bid and ask, if you like. And there's been some speculation that you folks might have been interested or may be still be interested in looking at some of the resource available in California. And I just wonder if you could add that in your answer and I'll leave it there? Thank you.

Yes, I'm going to ask Billy Helms, he is very engaged in that process and so he can bring us up to-date on that.

Yes, good morning, Doug. We're -- yes, we are looking at a lot of opportunities, as you know; there is a lot of opportunities out there. There's still a pretty good spread between the bid and ask on the acquisition front. I think we'll be very selective. We continue to be very selective in our approach, and what we're looking for, and I think we'll see some opportunities as we go forward, but there will be smaller, more tactical acquisitions, as well as just continuing to be able to accrete leasehold in some of our key plays and emerging place. And so I think that's going to be our approach. I don't think you'll see us doing any large M&A kind of things in the future. They'll be more targeted to the smaller things that we've traditionally done as a company. And so continue to be very selective and review those on a one case or case-by-case basis.

And we'll move to our next question that will come from Paul Sankey with Wolfe Research.

Sorry to press on the drilled uncompleted but I guess a follow-up is trying to get a sense of the pace at which the 285 would come back relative to how much drilling you would do simultaneously. I think what you're saying is that a $65 plus price you would be ramping up I guess the DUCs or the drilling both simultaneously? Could you just go into that again? Thanks.

Yes, Paul, that's a good question. And as we head into the last half of this year and think about 2016, we'll be on a pretty good uptick. So what we want to do is get the equipment and the people and place and get the process started certainly very strongly in the second half of the year. And then, when we hit 2016, if oil prices continue to hold up, we will continue to increase our activity accordingly. Of course the goal is and the plan is to continue to remain CapEx to discretionary cash flow balance. And so that will really govern our activity. The stronger the price of oil is they're more obviously capital we'll have to work with and the more we'll continue to increase our activity. As we look at the second part of this year, part of the process will be evaluating is how many drilling rigs to continue to have joint wells versus releasing rigs. And that certainly will be a function of what the oil price is. And so we won't get too far out in front on the drilling side. The 285 DUC that we start the year with most likely over the first half of the year will reduce significantly as we go forward and we'll exit the year, next year, with considerably less DUCs than we’re exiting this year with.

Yes, I think I understand. So I think -- to reinterpret the close that you're to 65 the more DUCs will be used to generate the double-digit return but excuse me seasonally double-digit growth. But what you're essentially saying if we're 65 or above you will be delivering double-digit growth next year?

Yes, I think that's correct, yes, good.

Thank you. And then the follow-up is there is some criticism always about the relationship between the IRRs of individual wells and how they flow through to corporate returns. Could you just add anything that you have to add on how the current environment and the outlook will flow through, if you like, to your overall corporate return on capital employed? Thank you.

Yes, the rates of return that we talk about -- the direct rates of return and we used direct after-tax numbers when we quote our plays, those are on capital for the well cost and the production facilities of that well and that's the only cost in there. Of course the full corporate returns on ROCE are all capital and all capital spent from the history of the company. And so you’ve got legacy gas properties in there and lots of other things in there over time and that's the real difference in the thing. As you -- everybody has noted over the last several years, EOG's ROCE numbers have continued to improve rather strongly, and over the last year, our ROCE numbers were higher certainly than the E&P peer group and they were even higher than the average of the integrators and the majors. So we have one of the strongest track records and one of the strongest ROCEs in the business and that just reflects EOG's continued focus on returns. Rates of return on our capital drives every decision in EOG and it is the fundamental metric that we use to manage the company. So as we talk about this year we're deferring wells that's really just to drive up the returns on our capital and all these things we're doing to decrease well cost and increase productivity are very, very focused on driving up the returns to the company as we go forward. So really that's the main difference.

Appreciate that. Thank you.

And next we'll go to Leo Mariani with RBC.

Hey guys, I was hoping you could give us a little bit more color around your second quarter U.S. oil production guidance. I look at the -- I guess the midpoint in the second quarter is down roughly 10% sequentially versus the first quarter. Could you guys kind of provide some color around that whether or not number of completions is extremely limited here in the second quarter? When you guys talked about deferring and is that deferring almost all of them or just majority, could you just kind of give us some color around that?

Yes, the reason that we're -- our guidance from the second quarter is down is because we've had a significant reduction in the amount of wells we complete that's really the driver. We were down 39% in completions in the first quarter. And then, in the second quarter, we were down additional 36%. And that is really just a process of deferring the wells and not completing the wells and just really taking off the spin right as we move into the second quarter. So that's really just driving it. And of course those will, we still have maintained our full-year guidance and we'll be making that backup that production backup in the second half of the year and it will be at much higher returns because we are waiting.

All right. I guess obviously you guys talked about sticking to your capital budget here in all costs. But at the same time you’re also talking about starting to accelerate some completions at $65 oil which could happen as soon as this 3Q. Just to clarify is that accelerated activity in 3Q and 4Q, if we get to the right oil price, is that actually in the CapEx budget for 2015 already?

Yes, Leo, let me let Gary Thomas address that.

Yes, Leo. We do have those incorporated in our capital with our ramp up there, as Bill said, may be starting in July just watching oil prices but then will ramp up through the year. As a matter of fact yes we're doing less completions, we're kind of keep our frac rates in place, we've dropped them down from 7 days to 5 days, just everything to conserve capital here in the first half.

All right. That's helpful. And I guess just talking about some down spacing result that you all had. I guess in particular looks like in the Bakken and the Leonard; it looks like some of the IP rates you reported in some of those areas a little bit lower than some of the previous wells. Am I interpreting that you may be seeing some initial interference on those or is that incorrect?

Yes, Leo, this is, Billy Helms. For the Bakken, as we continue to experiment with our completion designs we're seeing different areas of the field have different rock properties and we're tailoring those completion designs to match those rock properties. So we have, as you can imagine the quality of the rock varies across the field, so you got some areas that generate a little bit higher production rates than other areas. So it's just a function of the properties of that particular area other reservoir and we're very confident that our down spacing patterns and our approaches that we're testing are going to lead to our best recovery in net present value for those assets.

And next we'll go to Subash Chandra with Guggenheim.

So a question on the Eagle Ford. I guess the W pattern staggered pattern I guess being described there in some of the other things you're trying. Is it too early to hazard a guess as to the inventory gains you might have come out of this process and similarly and say the Bakken where you're doing similar work?

Yes, it's too early on that to give some guidance on the inventory possibilities but certainly we’re optimistic. There is going to be upside but a little of what we're doing there is we’re using some enhanced identification tools to really identify the very, very best targets in the lower Eagle Ford. The rock quality varies as you go vertically up and down the section and we believe we have the ability to identify better rock in certain parts of the Eagle Ford and then make target selections based on that. So it's not just a geo metric pattern, it really is got a lot of technical work behind it and a lot of high grading as we pick each one of those targets. And so we're really just starting that process and we're optimistic about it but it's really too early to give guidance on the amount of upside it might be.

It is fair to say though I think in your commentary you said that because my initial impression was that individual wells will be better but I think you talked about increasing inventory there. So is it fair to say that as you target these laterals you might actually be accessing or getting a lot more locations out of more of the rock within say a section?

Yes, that's definitely true. We're hopeful that it will continue to build our inventory up. We have to prove that but certainly that is strong possibility.

And next we'll go to Charles Meade with Johnson Rice.

Bill, if I could ask a question again on your 2015 plans, may be from a little different angle. The way it seems to me, what you've articulated this morning it’s pretty much the same as what you talked about two months ago with ramping activity towards the end of the year into 2016. But I'm curious, can you may be speak about at the margin, has there been a shift in your thinking, especially, we're looking at crude over $60, close to $61 here today. And is there may be some subtlety in a shift from which we're thinking a couple of months ago when you talked about Q4 results that you want to direct us to?

No Charles. That’s a good question. We really don’t have a lot of different outlook on the macro or our 2015 plan than we had back in our February call. We made the call to defer drilling, because we thought this would be or could be a short-term cycle, and we're hopeful and certainly we're encouraged by the current firming of the products. So we’re hopeful that’s what will turn out. But we still, as I said earlier, we're more optimistic in the forward curve than what it is right now. So we believe being patient and waiting on that products to continue to come up, while also continuing to take advantages of the cost reductions in the wells and the well productivity improvement. Those will all make a very significant difference in the returns we get on the wells when we begin to complete them. So you're correct. The plan is in the process of thinking is really, basically the same as it was in February?

Right. Thank you for that clarification. Then, if I could ask about the -- you guys talked a few times in your press release about these integrated completion designs and tailoring the completion to the individual wellbore. Can you talk a bit about what that means? Whether it means varying the stage spacing along the wellbore, whether it's -- you’re choosing your different pump rates or sand loadings for one stage versus the next, and perhaps also offer an idea of how big an opportunity is this?

Yes, Charles, this is David. On these integrated completion, it's not a whole lot of different than what we've always been. We've always really focused on the very best rock and the very best interval within the overall section. And we try to keep our lateral in that and then when it comes with completions, we integrate that in as well. And we do very; we basically design each stage for the well and for that specific portion of the lateral. So it’s really an overall process and we've seen dramatic results over the years and even over the last several quarters in the well results. We really think of the -- it’s really kind of part of the EOG culture and gives us a big competitive advantage going forward.

And next we'll go to Irene Haas with Wunderlich Securities.

Hello, my question has to do with Delaware Basin. You are in full development mode in the Second Bone Spring, just may be a little bit more color on the Wolfcamp. Your successful wells are they coming from the upper or middle interval; and ultimately, how many benches within the Wolfcamp could be productive in this part of Delaware Basin so in the central North?

Yes, Irene, this is David. As far as the Wolfcamp goes, we mainly have been targeting the upper Wolfcamp. We think that there is a very large potential throughout the Wolfcamp. But our very focus has mainly been on the upper. And with regard to the Second Bone Spring Sand, we're moving towards development mode there. We obviously have a lot of work to do. We're testing a lot of targets. We're testing spacing there, and we're continuing to refine our completions but we see quite a bit upside left, really in all those plays.

And moving on we’ll go to David Tameron with Wells Fargo.

I'll leave the acceleration question alone. I don't want to hit on that anymore. But just to clarify, you guys in the presentation you put in well cost which are running ahead of plan and then you put some target well cost, are those achievable, are those targets achievable? Is that a 2015 goal or is that a 2016 kind of outlook or how should we think about those target well cost?

This is Gary Thomas. On last February, we just mentioned that we were expecting to see our well cost down in the 10% to 20% range. And we're really pleased with the progress that we've made there and various things, but looks to me that our cost is going to be in the 20% to 20% plus. And most all these areas, we’ve got target wells, our record wells that have exceeded our targets. So yes, we're making good strides there. And we're also pleased that about half of that gain has been in vendor-cost reduction, but the other half has been in our efficiency gains. I'm really pleased with the efficiency gains, because you can see that on the number of days per well. And that’s why we had the one Exhibit comparing yes the Barnett that we had worked in for several years versus the Eagle Ford. And there is still quite a lot of room, which is the EOG myntra; pleased, not satisfied. We're going to continue to make gains there.

Moving on we’ll go to Pearce Hammond with Simmons and Company.

Bill, service providers have highlighted refracts as a significant opportunity. Do you see such an opportunity for EOG with refracts?

Pearce, we get that question quite a bit and we've looked at it and talked about it internally and we've not tried any refracts. Our outlook on that is that it really -- technically, we believe that just drilling a new well and kind of starting fresh and making sure your lateral is in the very best target and making sure that you can redistribute the frac very evenly along the wellbore with the new well is probably the preferred way to go. We just think that the upside on the completion will be much greater than if you try to refract the well. Then the other thing, obviously that contributes to that is the well cost on the drilling side is we can see are just getting lower and lower and becoming a smaller percentage of the total well cost. So drilling a new well from the drilling side standpoint is just a pretty low-cost item today. And there is a lot more upside in just drilling the well -- redrilling the well and doing it right.

Great. Thanks for that color. And then my follow-up is how quickly do you think the industry and this includes obviously the service companies have to lay off a lot of people. How quickly do you think the industry can respond to higher prices? Is there going to be a substantial lag to adding activity or do you think there is enough capacity out there, service capacity that it can come back and fairly rapid order?

No, it Pearce, it depends on how much longer this goes. If we were ramping up here in the next month or two, I think you can ramp up pretty rapidly. And that's why many of those operators are trying to keep as many services in place even if reduced work levels just to maintain that support that service companies. So as we've said before, yes, we’ll be able to ramp there pretty rapidly on our production with just our DUCs that we have in inventory. But then it will take possibly a little longer just from the drilling site.

And next we'll go to Brian Singer with Goldman Sachs.

I wanted to just see if you could provide some clarity on how your decline rates are trending versus your expectations on fee front? It seems you’re naturally seeing sharper first year decline rates that complement your higher initial production rates from enhanced completion. What trends are you seeing overall versus your type curves in the Eagle Ford, Bakken, and Permian, when it comes to declines and the many efforts you’re making on longer-term decline rate mitigation in this environment?

Yes, Brian, this is Billy Helms. What we're actually seeing on our new completion approach is by targeting the wells in the better pay zones and then doing a better job of placing the completions along the lateral is we're seeing actually that declines are flattening over time. So little bit less decline over time and I think that's transferring yourself all through the company level I think as the base of production gets more material and larger and relative to the new wells we're bringing on that our -- our production decline is flattening over time as well. So I think we're seeing a lot of advantages to this new completion technique that we're still yet to fully realize and will material with time.

Got it. Thank you. And then shifting back to the Delaware Basin and the Wolfcamp area you highlighted the Brown Bear Wolfcamp Well. Can you put into context what a 24 hour rate of 2,165 barrels a day means relative to your 900 MBOE typical Wolfcamp EUR it seems like the oil mix there was much higher versus your typical well. And whether this is an area that you already assumed was commercial or whether it represents a step out in Lea County, just kind of want to see whether this is a normal well, an above average well or something that’s more substantive from a resource and productivity perspective?

Yes, Brian, this is David. I would say, certainly this is a very good well and we’re not necessarily surprised by the Lea County is a good area. We’ve drilled some good Wolfcamp wells there in the past. I think as far as how it compares with the model, I think it would be fairly close to the model and we continue to see progress on these wells and I think over time we're hopeful that we'll even see better wells.

And our final question will come from Marshall Carver with Heikkinen Energy Advisors.

Yes, regarding the W shape patterns in the Eagle Ford are you testing that in several areas then how much of your acreage do you think might work for that. And how far are part of the wellbores in those patterns? How much tighter is it than what you were doing before?

Marshall, the W pattern we will do multiple pilots patterns on that and it really will apply to I think the bulk of our Eagle Ford acreage. And what we're doing is we’re bringing the wells in. We've been drilling wells anywhere from 3 to 500 feet apart in our typical patterns, but we're bringing those closer. And we'll be doing that at various spacing closer than 3 to 500 feet and it really will vary a bit on the spacing depending on the area. But the general concept of taking out multiple targets within the lower Eagle Ford using these advanced techniques to identify the best rock will be apical across the bulk of our acreage.

Okay, thank you. And one follow-up if I could the current 2016 strip is at $65 but you mentioned seeing more upside than downside on the strip. How would hedges potentially factor into your plans to accelerate if the strip moves up could we see a flat -- how are you thinking about that hedges and how you could be your plans for acceleration?

Yes, Marshall, we're certainly evaluating that all along and we're really again a bit more optimistic about forward curves even then it is today. But we want to put some hedges in going into next year. And we'll just be looking at that and trying to find the opportunistic entry point as we kind of go forward. So really kind of watch the fundamentals of supply and demand and really pick the point that we think is the right point to make an entry there.

And that does conclude our question-and-answer session. I’ll turn it back to Mr. Bill Thomas for any additional or closing comments.

We’re very excited about what’s happening in EOG this year. We said at the beginning of the year that when this downturn started that we wanted to emerge in better shape than we entered it. And what you’re seeing today and what we're reporting today is exactly that happening. And in my 36 years with the company, I’ve never seen a company respond better. The company is driving down the cost and improving the productivity of the wells rapidly and whether oil prices remain where they are today or continue to improve, EOG is resetting the bar to be successful for many years to come, and we thank -- so thank you for listening today and thank you for all your support.

Thank you. And once again that will conclude today's conference. We'd like to thank everyone for their participation.