Good day, everyone and welcome to the EOG Resources’ Third Quarter 2015 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 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 saw the press release announcing third quarter 2015 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements are 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 Web site at www.eogresources.com. The SEC permits oil and gas companies and 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 in the Investor Relations page of our Web site. Participating on the call this morning are, Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration & Production; David Trice, EVP, Exploration & Production; Lance Terveen, VP, Marketing Operations and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our Web site yesterday evening and we included fourth quarter and full year guidance in yesterday's press release. This morning Bill Thomas will start with a few opening remarks, followed by Billy Helms and David Trice to review operational results. I will 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 everyone. Our goal this year has been to transition the company to be successful in a low commodity price environment. To achieve this goal, our 2015 game plan is focused on the following objectives; one, maximize return on capital invested; two, improve well performance through technology and innovation; three, achieve significant cost reductions through sustainable efficiency gains; four, take advantage of opportunities to add drilling inventory; and five, maintain a strong balance sheet. As the year draws to a close, I am pleased to report we’re right on track with our plan, we have maximized return on capital invested by directing capital to our best plays, the Eagle Ford, Bakken and Delaware Basin. We are having a record year of well productivity improvements and cost reductions. Ongoing completions and the new work we are doing on targeting mean EOG continues to drill the strongest horizontal wells in the industry. As a result of these efforts, our largest and best assets now generate over 40% direct after tax rate of return with $50 oil. Making a solid return in horizontal oil at $50 is an excellent achievement. On the cost side, we’re making substantial improvements. Year-over-year third quarter per unit lease operating expense was down 17%, per unit transportation was down 11% and total G&A was down 6%. In recent years we’ve grown inventory at twice the rate of drilling, 2015 is no exception. This is a record year for adding high quality drilling potential. Last quarter, we increased our Bakken and Three Forks’ net potential reserves by 600 million barrels of oil equivalent. This quarter we increased our Delaware Basin net potential reserves by 1 billion barrels of oil equivalent. As you read in our press release we made three tactical acquisitions in the Delaware Basin adding significant high quality drilling potential. In total, we added over 1.6 billion barrels of net reserve potential and over 3,000 net locations this year and we’ve achieved this incredible growth through our reserve and drilling potential, while maintaining one of the strongest balance sheets in the industry. To summarize our progress report; in 2015, we maximized return on capital invested, added significant future growth potential and maintained a strong balance sheet. All year long our focus has been on the improving fundamentals and building future potential instead of chasing short-term volume growth. We believe this demonstrates that EOG’s priorities are squarely focused on returns and creating long-term shareholder value. I’ll now turn the call over to Billy Helms to discuss the big news this quarter our resource upgrade to the Delaware Basin.

Thanks Bill. Last night we announced a significant upgrade to our Delaware Basin assets. We increased the estimated net resource potential to 2.35 billion barrels of oil equivalent that is a 74% increase from our resource estimate just two years go. The expanded resource provides 2,200 additional net locations adding to what was already decades of drilling inventory. The primary driver of this upgrade is our constant focus on improving well results through the application of technology and targeting. We've a proven track record of increasing in a play’s potential and this quarter our success is evident in the Wolfcamp and Second Bone Spring Sand plays. In the Wolfcamp we’re adding net potential reserves of 500 million barrels of oil equivalent and almost 1,000 net wells. We now estimate the Wolfcamp's total net potential reserves to be 1.3 million barrels of oil equivalent from 2,050 net drilling locations. This estimate is based on a highly detailed evaluation of multiple distinct intervals within a geologically complex basin like other plays we've found that by first identifying and then targeting discrete intervals we can dramatically improve the performance of the wells and ultimately the recovery from the reservoir. There are several potential targets within the Wolfcamp and we had successful tests in at least three. This resource estimate includes wells plays and these tested intervals across all of our acreage with well spacing that varies from 660 feet to 1,320 feet between wells in the same zone. To summarize it more simply this resource estimate assumes at least one productive interval across all of our acreage with wells spaced about 700 feet apart. Similar to other resource plays we’re testing powder spacing with encouraging results. Last quarter we drilled a two well pattern on 880 foot spacing Dragon 36 State 701H and…

Thanks Billy. In the Rockies we continue to maximize the value of our acreage position by using enhanced completion techniques and lowering capital and operating expenses dramatically. As you may recall last quarter,we announced that we areimplementing high density completions in some Rockies’ wells that are similar to the completions currently used in the Eagle Ford, while the geology varies from play-to-play and even within the same play we see the upside in our ability to increase value through high density and integrated completion techniques. In the Bakken we are focused on completing infill wells in our core area using our latest completion technology. Even though these infill wells are among oil producing wells our integrated completion approach ensures that we effectively stimulate the reservoir and deliver high rate of return and maximum value. An example of infill wells in our core acreage is a three well pad on the Parshall 3029 unit. This pad came online with an average initial rate of over 1,800 barrels of oil per day and 1 million cubic feet per day of rich natural gas per well. These wells are spaced just 500 feet apart and use shorter laterals that average less than 6,000 feet. Our latest Bakken wells are averaging just 7.6 days spud-to-TD for an 8,400 foot lateral and cost $7 million. This is a reduction of 20% from 2014. In addition, we have lowered LOE in the Bakken core area up to $5 a barrel through infrastructure investment such as water gathering systems. All of these improvements will allow us to maximize the value of this 1 billion barrel equivalent asset and deliver solid returns even in a low oil price environment. In the DJ Basin, we continue to refine our drilling techniques and implement high density completions. Long-term data is…

Thanks David. For the third quarter capitalized interest was $9.8 million. Total cash, exploration and development expenditures were $970 million excluding acquisitions and asset retirement obligations. In addition expenditures for gathering systems, processing plants and other property plant and equipment were $51 million. There were $368 million of property acquisitions during the quarter. Year-to-date total cash exploration and development expenditures were $3.7 billion excluding acquisitions and asset retirement obligations expenditures for gathering systems, processing plants and other property plant and equipment were $253 million. During the third quarter EOG incurred $4.1 billion in non-cash property impairment charges net of tax. The impairments were due to declines in the forward commodity prices and were related to some of our legacy natural gas and marginal liquid assets. At the end of September total debt outstanding was $6.4 billion for debt-to-capitalization ratio of 33%. We had $743 million of cash on hand giving us a non-GAAP net debt of $5.7 billion and a net debt to total cap ratio of 30%. Approximately 5% of the 8% increase from the end of June was due to the non-cash impairment recognized this quarter. The effective tax rate for the third quarter was 35% and the deferred tax ratio was 101%. In terms of our hedge positions for the period November 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. In addition for November 2015 EOG has put options in place which established a core price of $45 per barrel or 82,500 barrels of oil per day. For the month of December 2015 EOG has natural gas financial price swap contracts in place for 175 MMBtu per day at a weighted average price of $4.51 per MMBtu. Now turn I’ll turn it back to Bill.

Thanks, Tim. Now a quick word on the macro. Our view has not changed the industry is becoming more disciplined. The U.S. is on an oil production decline based on the EIE data and could exit the year 500,000 to 600,000 barrels of oil per day lower than peak production recorded in April. Worldwide longer-term projects are being cut, but we agree with the consensus view that $40 to $50 oil is not sustainable and supply demand is in the process of slowly rebalancing. Regarding 2016 although our planning process won't be complete until the beginning of the year when we have a better view of oil prices, I'll share a little color on our situation. EOG is uniquely positioned for strong performance next year. We’ll enter 2016 with a large high quality inventory of drilled but uncompleted wells and we've few capital commitments, therefore we have flexibility with respect to our CapEx program. The highest return use of our capital next year will be to complete many of our DUCs in the first half of the year. This will allow us to have a strong start to 2016. As always we've no interest in outspending and expect to balance CapEx and discretionary cash flow. Our focus will be on increasing capital returns, increasing the quality of our inventory and reducing operating cost. 2015 is rapidly coming to a close and I could not be prouder of how the EOG team has been executing on our plan. As I have said at the start of the year I've seen many downturns in my 36 years with the company, each time EOG emerges on the other side in better shape, this is exactly how 2015 is playing out. But there is one primary take away from the call today. EOG is quickly adapting to be successful in a low oil price environment. We’re not depending on a rebound to high oil prices instead we’re making the most of the current price environment by focusing on improving fundamentals and building future potential. In fact 2015 has been EOG's best year in terms of the magnitude of improvements in the Company. Regardless of where we’re in the commodity cycle EOG is committed to return focused capital discipline year-after-year. The Company remains focused on creating long-term shareholder value. Thanks for listening. And now we’ll go to Q&A.

Thank you. The question-and-answer session will be conducted electronically. [Operator Instructions] Questions are limited to one question and one follow-up question. We will take as many questions as time permits. [Operator Instructions] And we’ll take our first question from Leo Mariani with RBC.

Wanted to touch base on the enhanced completions, it sounds like you're starting to use these in the Delaware Basin, here. Obviously you've had a lot of success in other plays, any reason to think that these won't give you a nice improvement in economics here?

Leo we’ll ask Billy Helms to comment on that.

Yes Leo, this is Billy Helms. As you mentioned we view these enhanced completions or these high density completions in other plays largely starting in the Eagle Ford where we have certainly demonstrated the uplift associated with executing these high density completions. We are transferring this technology to other plays including the Delaware Basin and I think the results are very encouraging with what we are seeing there and we are incorporating our high density completions along with are focused on targeting. And the targeting I think is going to also make a huge difference in the performance of the wells. I’d say in the Delaware Basin is still early on and we’re evaluating both those two new approaches as well as spacing test in each one of our target intervals and we hope to be able to give you some very positive news in the future on the performance of those efforts.

I guess just turning to the Eagle Ford here, just trying to get a sense of where you are at in the process of testing the W patterns, and the stagger stacks here? And are you able to kind of see any results at this point, and when do you think we'll have a better update on that?

Yes Leo this is Billy Helms again, on the Eagle Ford we’ve actually got several tests underway using this W pattern test and the W pattern just to make sure we are certain about the explanation that is largely and it is only in the lower Eagle Ford that we are doing the W pattern. So we’re not -- we’re just focused solely on the W pattern in the Lower Eagle Ford and that’s largely been the focus as a result of our targeting efforts as I started in the Lower Eagle Ford, we identified through our analysis of all the core data and the petrophysical data that we have that there are two sweet spot intervals that we wanted to target. It's still early on, we’ve just started testing those and we’re testing those in several areas across the field but we are encouraged with their early results. The early results look to indicate that these two areas, these two sweet spot intervals aren’t interfering with each other during the production phase. So that gives us a lot of encouragement for additional resource that we’ll be able to capture in the future it is still early yet to really quantify the results from that test, but I’d say we’re optimistic about the results.

We’ll go next to Evan Calio with Morgan Stanley.

Bill, let me start off on a macro strategy question. You are one of the best, if not the best on conventional operator, deep well inventory, and a relatively bullish outlook on the commodity. Philosophically, what does your reacceleration look like? Will you be pacing activity within cash flow neutrality on a few quarter lag, and, given the efficiencies that have accelerated, does it change your view on a peak rig count being significantly lower than prior rig count in a recovery scenario?

Yes I think the key for us going in next year the advantage we have that we didn’t have in the early part of 2015 is we have an incredible amount of flexibility with our capital. It's really, we just don’t have commitments to international, we don’t have lease retention, we don’t have as much heavy infrastructure especially first part of the year and we don’t have a lot of service contracts in place. So we’re free to really put our money on the best rate of return projects, or wells and the Company and we’re also free to vary that capital spend rate based on the commodity price and we can react very quickly. So as we said we’re not going to -- we won’t give specific growth numbers, or production numbers, or CapEx numbers until February because we’re very committed to staying within cash flow. So that will really determine our view of -- basically we will use the strip process plus form factor that we have on the macro to kind of determine our CapEx for the year. And then we will vary that according to the commodity prices as the year goes through. So it will be a very flexible year and -- but our focus will be of course on increasing returns, increasing the quality of our inventory and continuing to prove up new things.

And it sounds like DUCs will be your first lever there. Let me ask my second or follow-up question on the Delaware. You're making significant progress. How long do you think it takes to get to the same level of technological maturity that you have in the Eagle Ford, where you're satisfied in your ability to drill within zone, optimize completion design? Yes. I'll leave it there. Thanks.

Okay yes Evan this is Billy Helms. Yes for the Delaware Basin as you mentioned there we’re earlier in the ability to really get into a good development program there. I think the key thing you have to realize about the Delaware Basin as opposed to the Eagle Ford is the Delaware Basin is a highly complex basin the geology changes quite a bit across the basin. There are multiple targets, multiple formations and we've done a -- our team out there has done a great job of really delineating their understanding of the play with the data that we have and we’re always collecting more and more data as we develop the program. So I would say just to bullet down to maybe base ball terms we’re probably maybe a third inning on the Delaware Basin as opposed to sixth or seventh inning maybe on the Eagle Ford for instance.

We’ll take our next question from Charles Meade with Johnson Rice.

I'd like to dig in a bit on the -- on the advanced completions and the well productivity that you cited as one of the reasons for your oil volumes coming in over guidance, I know that the most prominent thing we see is these great IP rates that you have turned in, but the other thing that I believe you've mentioned and we certainly see with the results on these Thor wells that, particularly for those Thor wells, the 30-day rate is at least as remarkable as the IP rate. And I'm curious when you look at the effect that these advanced completions are having on your production profile, should we be thinking about the beat in 3Q being a function of wells that were completed in 3Q, or is it more a function of the wells that were completed in the first half of the year that are holding up better with lower decline, that really are leading to beats like this?

Yes Charles this is Billy Helms. Ys I think that’s a good question, I think it’s maybe a factor of both certainly the targeting and the high density completions are making a huge difference as evidenced in as what you just mentioned in the Thor well and the other Wolfcamp wells we completed in the last quarter, and certainly those are new wells and we’re seeing vast improvements in the productivity of the wells, and they are sustaining themselves as evidenced by the 30 day average that you mentioned on the Thor well. And we've been doing this for a while longer in some of the other plays mainly the Eagle Ford and yes we’re seeing the decline as not as steep on those wells, so it has an overall flattening effect on our decline rates on all these programs so we’re seeing the benefit in those two areas.

So it's both. And then, if I could ask a question about the Delaware Basin acquisitions, I know that this is a little bit of a change in MO from you, who you have historically have been focused really on organic leasing. Should we be thinking about these acquisitions or further acquisitions like this as the closest you can get to organic leasing in the Delaware Basin, given the legacy of vertical production out there? And I suppose as a follow-on to that should we be expecting more similarly sized deals from you guys going forward?

Charles this is Bill. I think I'll ask Billy to comment a bit on that. But I think it will be a combination, we’re doing a lot of little deals along with the bigger deals, and so block enough acreage sharing acreage with other operators and slopping it out and some drilled aren’t deals and then we’re also buying some small fracs from different operators. So it will be a combination of multiple things. As Billy said we pretty much ruled out any of the bigger M&A possibilities and mainly we ruled that out on asset quality, it didn't come in comparable to what we already have. So we don't really expect to be pursuing anything like that, Billy you want to add anything?

Yes the only thing I would add Charles to that as I think it, -- the acquisitions we've done are largely staying within our focus of growing organically. The difference would be that the organic growth in new plays we’re still able to go out and get ahead of the competition and acquire positions in new plays fairly cheaply. In the Delaware Basin it's a very mature basin, it is a lot of ownership, legacy ownership has been out there for years and years as everybody knows. So one way to gain entry into acreage that we see quite a bit of upside is through these tactical acquisitions and I would add to Bill's comment we’re being highly selective in what we acquire. And so we passed up several opportunities that have been transacted that we just passed on and we did focus on these three tactical acquisitions that we are very encouraged with and as a matter of fact we already have drilling operations going on, on the acreage that we acquired. So we’re going to stay selective and continue to grow each of one of these plays in whatever manner we feel like we can.

We’ll take our next question from Bob Brackett with Bernstein Research.

Yes a question on the acquisitions, who were the counter parties, were they privates or publics or landowners?

They were selective companies and we’re not going to get into details about the deals we have done and certainly not again into the details about the things we’ve looked at, it's just something we don’t really comment on. But I’d say they are all existing companies, strong companies that we’ve done business with in the past and hope to continue to do business with in the future and we’ll look at all of the opportunities whether it is small private companies or larger public companies for opportunities to add to our positions.

And then a follow-up on next year, how do you think about debt to cap, and is it a level that you're happy with or is some of next year's cash flow going to debt reduction?

Well yes Bob, we’re very committed to keeping a very strong balance sheet. So we’ll not stretch it much further than then it really is. Although I will say this, we will continue to look for acquisitions and not likely to find a big one, but if we find things that are attractive to us we will use -- evaluate all the options that we have to acquire that. And so the Company is in fantastic shape to do that. Of course the goal for us has always been to generate free cash flow, to continue working on the dividend down the road too we needed a little bit better commodity price, than we have right now to accomplish that, but that will be a goal for us going forward. We also continue to market non-core properties that has been an ongoing process for the Company for years. So we’re in the process of doing that again this year too. So we’ve got multiple ways to continue to keep the net debt of the Company low and to really preserve our balance sheet.

We’ll go next to Doug Leggate with Bank of America/Merrill Lynch.

Bill, within the scheme of living within cash flow, obviously you've had a fairly large international project pretty much close to conclusion now, a lot of exploration spending and a fair amount of midstream spending. Just in the grand scheme of things, within the different buckets can you generalize whether you will see an incremental swing back towards completions within the context of living within cash flow, in terms of your capital spending?

Yes, Doug specifically, yes for 2016 with the very large uncompleted well inventory certainly the focus of the CapEx and that will be the highest return thing we can invest in next year, we will be on completing that inventory and lower that inventory down. So it gives us a lot of flexibility because we just don’t have always all these other big commitments and that will certainly give us I think stronger capital efficiency, a very-very high return on our capital next year.

I guess not to push the point, Bill, but I guess I was kind of hoping you might quantify order of magnitude. Exploration, IOC, midstream I'm guessing it's close to 20%-25% of this year's budget. I mean could it be that big of a swing in terms of incremental completion capital?

No, I think the -- we call that kind of the indirect that will be roughly about the same percentage that it has been in the past. Maybe not quite as much in the first part of the year but certainly we’ve got things that we need to do in those areas. As far as international projects, we don’t have many significant commitments next year on international it's actually less I think than historically. Let me ask Gary Thomas to comment and chime here and give a little bit more color on that.

One thing on the indirects and you talked about the midstream it will be benefitted next year with us having these doubts because they are in areas where we have quite a lot of operations currently, so we will have less infrastructure requirements just to hook those wells up. So it would be a little less than what we have experienced 2014-2015.

We’ll take our next question from David Tameron with Wells Fargo.

Let me run with that same theme. If I think about maintenance CapEx, I think you have thrown out a number before, $4.8 billion. One, is that the right number? And two, obviously that number goes lower. Can you give us any framework around that?

That’s when you look at what we are spending now and that came up and we’re looking at spending $1 billion this quarter and probably somewhere around maybe 900 million for next quarter, this fourth quarter. So it could be talked out there has been maintenance capital but yes when we go into ’16 we’ll not have to be spending money associated with locations with the drilling with quite a lot associated with these stuffs. So that will probably reduce per well about 30% but the 4.8 is -- our maintenance capital was quite a bit less than that.

Yes, yes I think that was a prior number, okay that's helpful. And if I think about the DUC -- the pace of the DUC drawdown, I think before we talked about mid-year, are you just going to take them down -- should we think about it systematically, taking down 200 over the first six months of the year, or how should we -- can you give us any framework around just the pace or the timing of that?

Yes David let me answer that one. We've a lot of flexibility, so really the pace of our spending and the pace of our activity will be very much guided by the commodity price and the resulting cash flow. So that’s the reason we’re not giving any really details because we want to work our plan more every time we work our plan it gets a little better so we’re very encouraged about that, and then we certainly need to have a lot better insight on what the cash flow and commodity price would be. So it will be regulated by really the oil price.

For our next question we’ll go to Kevin Smith with Raymond James.

It seems the industry playbook is fairly standard with drilling longer laterals and pumping more sand in your completions, but you were able to deliver record-breaking well results in the Wolfcamp with a lateral less than 5,000 feet, is it fair to say then that EOG believes completion and maybe zone landing are more incrementally economic than just drilling longer laterals?

Yes Kevin this is Billy Helms. That’s exactly what we would say is that the completion and targeting are making a huge difference regardless of lateral length and we’re not focused on drilling necessarily longer laterals to make better wells we’re focused on increasing our rate of return, driving rate of return through the innovation and application of technology which includes how we analyze and figure out where the place to lateral in each of these pay objectives that’s a big part of why the productivity on these wells is increasing every quarter is that continual focus on those two things, the technology around completions and also the landing spot that we’re working on with our geological effort.

And then lastly, thank you for that, but given the Wolfcamp drilling results, does the Delaware Basin start competing with capital versus the Bakken or other plays?

Yes Kevin this is Billy Helms again. Yes I think while it's still early to think about what that’s going to mean for next year's capital allocation. I think if you look back to this year, this year the Delaware Basin was the only area that saw an increase in capital from 2014. And we’ll certainly assess the way that looks. I would say we’re very encouraged with the productivity gains we've made and the progress we’re seeing on that play to be able to generate growth for the Company, and we’ll evaluate our options on how we allocate capital as we get closer to the year-end.

We’ll take our next question from Pearce Hammond with Simmons & Company.

Bill thanks for your comments on 2016. My first question is if you match CapEx and cash flow, do you expect to deliver oil production growth in 2016?

Yes Pearce again that’s a good question, because we don't know what that cash flow and CapEx will be yet because we will set that based on the oil price and that’s what we’re -- wanted to get a little bit better deal on down the road. We certainly are in a position next year to have a very strong performance. And if we have the support from the oil price the Company is in great shape. So but we’ll just have to wait to give any specific numbers until February.

And then my follow-up is, when it's time to ramp production for EOG and the rest of the industry, are you concerned about the deliverability of the service industry, given the sizable headcount reductions across the states and maybe some degradation on some of the pieces of equipment?

Pearce this is Gary Thomas. And yes there is some concern with that and we've talked quite a lot about that and maintaining the activity level that we have maintained and what we've planned to do in 2016 we’re focused on those companies that are really quality companies and have been tremendous partners to EOG and we’re spreading that word trying to keep them in good shape. So it's going to be hard on the industry. I believe you're correct there, but I think we’re positioned so that we’ll be able to get the top services and hopefully we have got a lot of self sourcing going on with EOG anyway. So I think we can really ramp-up readily when we see commodity prices improve.

We’ll go next to Ryan Todd with Deutsche Bank.

If I could maybe follow up with a couple questions on the Delaware Basin. I appreciate your earlier comments about uncertainties in terms of relative capital allocation across the portfolio next year. Maybe, as you think about relative capital allocation within the Delaware Basin, I mean, is there a pecking order in terms of which of the three plays have the best rates of return at this point, and how much does infrastructure at this point dictate relative activity between Leonard versus Bone Spring, versus Wolfcamp?

Yes Ryan this is Billy Helms. So yes, we’ve got three really good plays out there, the Leonard, the Bone Springs and the Wolf Camp. And what we’re doing right now is we’re focusing most of our activity on the lower most of those zones to Wolf Camp for a couple of reasons; one, the Wolf Camp is generating really high rate of returns that are competitive with pretty much every play in the Company. And then two, it really gives us by drilling the deeper objective it gives us a chance to evaluate the shallower objectives as we drill through them. So we can gather log data and other data that we need to really help delineate the shallower plays and that will help us improve our returns on those plays and make them even stronger when we start our development in those plays. On infrastructure, we’re focusing most of our activity in areas where we already have existing infrastructure. As we step out and test some of the new areas, we’re certainly going to have to build out an infrastructure in those areas. But right now most of our activity is in areas where have infrastructure available to us.

And do you have sufficient infrastructure to allocate materially more capital going forward, or is this still a waiting game, I guess?

Ryan, this is Lance. When we look at their takeaway capacity it's been very encouraging. I mean the midstream operators are really fall through with investment and we’re going to be connected to all that near-term capacity, so, and just to follow-up what Billy said, we’re in great shape as we’re sitting today.

We’ll take our next question from Irene Haas from Wunderlich.

My question has to do with your targeting effort. I wish there's a fancy schmancy name for it, but it's really intriguing. So on slide 9, you show that there's 12 parameters that you have identified. You sum it together, and that kind of gives you the targeted zone. And my question for you is, some those parameters, can you share a little bit like, are they porosity, permeability as such, and is it hard to replicate? My question really stems from you said in Eagle Ford, you're in the sixth inning, so in terms of just data density you have a whole lot to work on. Would it be a harder exercise to pull off in Delaware Basin? And are there anybody else trying to do this? Is this expensive, or is it data intensive, or simply they need brain cells? And lastly, who does the number crunching for you? Do you actually do this analysis in house, or do you farm it out to a third-party?

Yes Irene, this is David Trice. A lot of this that we’re presenting there is proprietary data. So we will just give you an example and this is -- a lot of this is built up, we’ve been pursuing these resource plays for over a decade and so a lot of this is just it means that we’ve learned over the years and we have some of the very best people in the industry. And so we’ve been able to put this together through this integrated approach between our G&G guys, our petrophysicists and the engineers. And this is just kind of a core competency of EOG how we approach things. And so really we can’t really give a lot more detail than that, but it is part of our culture.

So what you're saying is it's kind of hard to replicate for a multitude of reasons, and is it easier to do it on Eagle versus Delaware, because of data density, or are you able to forecast because you've got such a great global database on every single shale?

Yes, I mean if you think about it, we’re in really the three major plays so we have a lot of good data throughout all those plays and we’ve got a lot of good rock data, petrophysical data and everything. And so we have -- we’re testing so many different targets and we just have a lot of information and we are able to apply it from play-to-play. And so I do think as you look towards a play like the Delaware Basin we’re -- you do have multiple targets, a lot of that information is going to be even more critical there. So we do think it is something that is very-very difficult to replicate.

We’ll go now to Brian Singer with Goldman Sachs.

I wanted to just follow up on the questions with regards to 2016 and growth. Just looking at the third quarter here of 2015, where you spent about $1 billion ex the acreage acquisition, you grew your oil volumes, and what I think you're highlighting here is you're going to be more flexible because of the DUC inventory, because you have some of those contracts rolling off. What are the impediments to showing perhaps not just the growth that we saw in US oil volumes in Q3, but even greater growth next year, assuming we're in a $40 to $50 environment? It seems that rate of return is not a question, unless you think it is. What are the impediments to showing -- to showing growth, since we just saw it here in the third quarter?

Brian this is Gary Thomas. And it really just goes back to the cash flow and that’s what we’re working so to balance and we’re still working through that and yes the wells we've drilled and completed that will be being official to us but then just as data we were just mentioning we have these new plays and we’re in the experimental phase as well and we've to gather data and have to run quite a number of logs and also there is just a whole combination of things. So we’re still factoring all those in to see what kind of volume growth we could have with particular oil prices in 2016, but cash flow driven.

And then with regards to the technological improvement here, and the higher density completions in particular which do cost some amount more capital, can you talk about what you would expect to see in terms of incremental EURs in places like the Delaware, the Eagle Ford, and the Bakken? And whether, that is all upside from here and represents an increase in recovery rate?

Yes Brian this is Billy Helms. I would say that we haven't really quantified in most of plays yet just the magnitude of the improvement we’ll hope to see in EURs from testing the new high density completions as well as the targeting efforts. The numbers we've given you to-date are based on the results we have and have data on but as we continue to make improvements in both targeting and the high density completions we’re very encouraged with the early results and as we get more data we’ll certainly update its impact on the resource assessments. So we just need some production time to evaluate that data as well as the different spacing tests that we’re conducting throughout the Company. And we’ll give you more color on that as we get data.

We’ll go now to Subash Chandra with Guggenheim.

Yes, my first question is how do you think about your base decline rate starting in ’16 versus ’15?

Yes Subash this is Bill Thomas. The decline rate in the Company is lowering every year because of we get more old wells versus new wells so the production base gets more mature that’s the major driver. And then the completion technology is a very significant driver and the quality of the rock that you drill the lateral in as that improves the decline rate lower. So we've got multiple things going on, as far as 2016 versus ’15 it will be lower and particularly when you slow growth down say versus 2014 we grew at 31% well in 2015 our decline rate was higher because then it would be in 2016 because of we grew production and added a lot more new wells in 2014. So as the activity, number of wells as you complete each year as that is lower and then we’ll be coming off a flat growth year in 2015, so it will be significantly lower than what it was in 2014.

And my follow-up is, in the Permian plays, between the three that you've mentioned, how do we think about the water oil ratios, either in absolute terms or relative to one other? And that's formation water?

Yes Subash this is Billy Helms. Certainly that’s something we look at on each one of these plays and I would say it varies by target interval but it also varies by where you are in the basin. So all of these plays have some element of formation water and so it's really important that you understand due to the detailed geological work that we had done to really delineate what we think are the sweet spots and that’s where our efforts are focused on picking up acreage in what we do considering the sweet spots, we’re being there very selective about where we drill and where we increased our position in those areas. And I would say the Leonard play probably has a little bit higher water cut than the Wolfcamp in general, but every play has some element of water production. So you need to have infrastructure to go along with that to make sure that your cost over the life of the play are measurable and competitive with other plays that we have in the Company.

That concludes today’s question-and-answer session. At this time, I’d like to turn the conference back to Mr. Thomas for any concluding remarks.

Thank you for your questions and again I want to really thank the EOG employees’ who have done a fantastic job this year in giving the Company reset to be very successful on the low commodity prices. So the combination of the best in class assets, technology, low cost, and organic exploration and all this is driven by EOG’s organization and culture are we believe very sustainable competitive advantages as we go forward. And this powerful combination will allow EOG to be one of the highest return producers and more importantly we believe we’re going to be more than competitive going forward in the world oil market. So we want to thank everybody for listening and especially thank you for your support.

This concludes today’s conference. Thank you for your participation.