Tim Driggers - VP, CFO Bill Thomas - Chairman, CEO Gary Thomas - President, COO Billy Helms - EVP, Exploration & Production David Trice - EVP, Exploration & Production.

Doug Leggate - Bank of America Merrill Lynch Evan Calio - Morgan Stanley Charles Meade - Johnson Rice Leo Mariani - RBC Subash Chandra - Guggenheim Securities Brian Cox - Deutsche Bank Pearce Hammond - Simmons & Company Irene Haas - Wunderlich Phillips Johnston - Capital One.

Good day, everyone, and welcome to the EOG Resources Second 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir..

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 guidance for the third quarter and full year 2015 in yesterday's press release.

This morning we will discuss topics in the following order. Bill Thomas will update our 2015 plan. David Trice and Billy Helms will review operational results. I will then discuss EOGs financials, capital structure and hedge position and Bill will provide concluding remarks. Here is Bill Thomas..

Thanks, Tim. Good morning, everyone. There are couple of items; I will cover with you on the call today. First, I will discuss the outstanding progress we have made transitioning the company to be successful in a lower oil price environment. And I will explain why EOG is uniquely positioned to accomplish this.

Second, I will describe the framework we are using to determine our activity level for the remainder of the year. Our goal this year is to remain laser focused on improving returns. At the beginning of the year, we noted that our after-tax rate of return at $65 oil were better than at $95 oil three years ago.

We are pleased to report that we have further improved these well economics even as oil prices have declined. Through improved well productivity and lower cost, our key oil plays now are in a 30% after-tax rate of return with a flat $50 oil price. We have multiple decades of drilling inventory in these high returns world-class assets.

EOG is rapidly adjusting to lower oil prices. We believe that our ability to quickly adapt to this new environment illustrates our competitive advantages. There are five drivers which make EOG uniquely positioned to improve returns year-after-year.

The first is large, high-quality assets, we have captured the sweet spot in the best horizontal crude oil assets in the U.S., The Eagle Ford, Bakken and Delaware Basin. The quality of our assets is why EOG drills the most productive oil wells in the U.S.

The scale of our positions drives tremendous efficiencies and the diversity of our assets allows us to transfer technology gains and cost savings from basin to basin. The second driver is innovations and technology. New ideas and technically drive continuous productivity improvements.

For example, we developed in-house, integrated completion technology that consistently drives field recoveries higher and maximizes NPV. During the first five years of drilling the Eagle Ford, we increased its reserve potential 250%. This quarter we increased our Bakken net potential reserves to 1 billion barrels of oil equivalent, a 150% increase.

EOG has over 10 years of horizontal shale experience to build on and we expect to continue advancing our knowledge through innovation and technology. The third is low cost. We believe EOGs well and operating costs were are already the lowest in the industry and 2015 is proving to be our best year ever for realizing additional cost reductions.

EOG scale and high-quality assets and proprietary technology will continue to drive future efficiency gains and cost reductions. The fourth driver is organic growth. This is the lowest cost, highest return approach to adding drilling potential.

Being first movers in exploration allows us to capture large amounts of high-quality rock at much lower cost than through acquisition and exploit strategy. Organic exploration is an important competitive advantage for EOG and we see significant opportunities ahead of us. Last but not least, is EOGs organization and culture.

This is the catalyst for the first four drivers and underpins our competitive advantage. A decentralized structure encourages asset level, bottom-up decision-making, which leads to better execution, our core culture is return driven.

Employee performance is incentivized by greater return which is a key driver to our peer leading return on capital employed. Return-based decision-making and incentives drive EOGs success. The second item I will cover today is our plan for the remainder of 2015.

We are maintaining total company oil production guidance while reducing 2015 CapEx guidance by approximately $200 million. In addition, our projected year-end uncompleted well inventory has increased from 285 to 320. The bottom line is productivity improvements and reduced costs are allowing us to produce more oil with less capital.

Many of you are asking when will EOG grow oil again? We have said all along that we do not want to grow production until we see the oil market is firmly rebalancing. We will be watching the supply/demand fundamentals in the second half of this year closely as we determine our plan for 2016. Currently, we intend to spend within cash flow.

The capital efficiency gains we have made this year along with our large high-quality inventory of uncompleted wells positions us for an excellent 2016. My number one message is this, we are resetting the economics of our business, EOG is quickly adapting to be successful in a low oil price environment. We expect EOG to remain the lowest cost U.S.

shale producer and competitive in the world oil market. I will now turn it over to David Trice to discuss the update on our Bakken resource estimates as well as other activities in the Rocky..

Thanks Bill. We're pleased with the performance from our spacing tests using our integrated the completion process in the Bakken. We now estimate that our Bakken and Three Forks total net resource potential is just over 1 billion barrels of oil equivalent. That's almost 2.5x our original estimate of 420 million barrels of oil equivalent.

Remaining drilling inventory increased from 580 to over 1500 net drilling locations. This represents 760 million barrels of oil equivalent of remaining net potential reserves and decades of drilling in this premier North Dakota asset.

In addition to the updated resource estimate, we split the Bakken into two categories that we have tiled core acreage and non-core acreage. The core producers return that are competitive with both the Eagle Ford and the Delaware Basin and includes our acreage in the Bakken core and Antelope extension.

Non-core represents acreage in the Bakken Lite, State Line and Elm Coulee areas. Although our main focus will be in the core area we believe that with modern high density completions and current well cost, the non-core acreage will be very economic even with low oil prices.

We defined 120,000 net acres and 590 net drilling locations in the core, which represents remaining net resource potential of 360 million barrels of oil equivalent. This inventory alone offers over 10 years of drilling. Non-core acreage represents remaining net resource potential of 400 million barrels equivalent.

In this acreage we defined 110,000 net acres and 950 net drilling locations which provide decades of inventory. Our wells in the Bakken continue to exceed expectations. A great example of the progress we're making is the Riverview 102-32H well. This is the first Bakken well in the Antelope extension we have drilled using a high density completion.

The well came online with a maximum rate of 3395 barrels of oil per day and 6 million feet of rich natural gas. With an average rate of 2760 barrels of oil per day for July, this short 4300 foot lateral will be the highest rate oil well ever recorded for the Bakken or Three Forks.

We are excited to continue applying high density completions throughout the entire play as we move forward. In addition to improved returns to advance completions, we have made tremendous progress on Bakken completed well cost, which are now $7.1 million for an 8400 foot treated lateral this is almost 20% decrease in well costs from 2014.

Most of the well cost savings are due to efficiency gains rather than vendor cost reductions. Therefore, should be sustainable over time. Drilling times are now averaging 8.2 days Spud-to-TD for an 8400 foot lateral with our best being a record 5.6 days. We are also realizing significant completion efficiencies.

Currently we are averaging more than 10 completion stages per day up from 4 to 5 stages per day in 2014. In addition plug drill out times have been cut in half since 2014. Finally, cost savings are not just limited to CapEx. We added infrastructure this year in the Bakken core and as a result we have seen dramatic LOE reductions.

Second quarter LOE is down more than 25% from the first quarter. The increase to our Bakken reserve potential in drilling inventory illustrates the value of the EOGs exploration and technology leadership. We enter play as a first mover and capture the best assets.

Then we drill them through the drill bit and improve recoveries over time with drilling and completion technology developed in-house. This is how EOG continues to grow organically. Here is Billy Helms to update you on the Delaware Basin and Eagle Ford..

Thanks, David. The plays in the Delaware Basin are also proving to be very good examples of how EOG is repositioning itself to generate strong returns in this period of low commodity prices. We have made improvements to productivity while significantly lowering completed well costs.

In the case of improved productivity we're finding that wellbore targeting along with our integrated completion approach continues to provide upside on well performance. In the second quarter, we maintained our activity in the 2nd Bone Spring sand testing various spacing patterns and targets.

Two recent wells, the Dragon 36 State Number 501H and 502H were completed in a 1000 foot space pattern with initial production rates of 1075 and 1755 barrels of oil per day.

Another recent completion in Lea County, New Mexico, the Frazier 34 State Com Number 501H tested 1705 barrels of oil per day with 145 barrels per day of NGL and 1.1 million cubic feet per day of natural gas.

The completed well cost for the 2nd Bone Spring sand are currently averaging $6 million per well representing a 22% reduction from last year's average. A major portion of the cost savings can be attributed to sustainable efficiency improvements in both drilling and completion operations rather than solely vendor cost reductions.

Improved well performance coupled with lower well cost make this play very attractive in this low commodity price environment. We will continue evaluating well performance to determine the proper spacing and ultimate recovery. During the last quarter, we also completed several strong Wolfcamp wells in the overpressured oil window of the play.

Two recent completions in Lea County New Mexico, the Dragon 36 State Number 701H and the Hearns 27 State Com Number 703H had initial production rates per well of 2650 barrels of oil per day along with 285 barrels per day of NGLs and 1.9 million cubic feet per day of natural gas.

As we evaluate various targets and spacing patterns this play promises to be a high return growth asset for EOG. Similar advancements have been achieved in the Leonard play. A typical well now cost $5.5 million and we're testing spacing patterns of 300 feet and 500 feet between wells.

One recent completion in Lea County New Mexico, the Gem 36 State Com 1H had an initial production rate of 2200 barrels of oil per day, 460 barrels per day of NGLs and 2.6 million cubic feet per day of natural gas. Our downspacing efforts demonstrate that we can drill wells closer together without sacrificing production.

These new completion designs are allowing us to improve the overall economics and ultimate recovery. Due to these strong results, we anticipate the Delaware Basin will play a significant role in EOGs long-term growth.

As typical with our other plays, EOG will evaluate options and invest in the infrastructure needed to serve future production growth while keeping our long-term operating cost to a minimum. We are very excited about the opportunities and growth potential for EOGs Delaware Basin properties.

Now moving to the Eagle Ford which continues to be our work horse asset, due to the sheer scale of our operations there it functions as a laboratory for technical progress, on target selection, geosteering and high density completion designs.

To support our wellbore targeting efforts this year, we drilled four pilot wells together additional log data and provide a more complete picture of our acreage. This information greatly enhances our understanding of any specific targets variability across the play. We are currently conducting tests using a staggered W pattern in the lower Eagle Ford.

And the new data we have gathered on the targets is encouraging as it supports our expectations for success. While it is too early to share results we are excited about the benefits our targeting efforts can have on our Eagle Ford drilling program and ultimate field recovery.

We are also pleased with the progress of cost reduction efforts in the Eagle Ford. Our average completed well cost is currently $5.5 million and headed toward our 2015 goal of $5.3 million. Similar to our other plays, most of these cost reductions are being achieved through efficiency gains and should be sustainable.

Also, the productivity of the wells continues to show steady improvement through our emphasis on targeting and high density completions. Some of the recent wells are highlighted in our press release.

The combination of cost reductions and better well performance through the application of technology is ensuring that this world-class asset will continue to deliver stronger growth for years to come. I will now turn it over to Tim Driggers to discuss financials and capital structure..

Thanks Billy. Capitalized interest for the second quarter 2015 was $11 million. Total cash exploration and development expenditures were $1.2 billion excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $85 million.

At the end of June 2015, total debt outstanding was $6.4 billion in the debt to total capitalization ratio was 27%. At June 30, we have $1.4 billion of cash on hand giving us non-GAAP net debt of $5 billion for net debt to total cap ratio of 22%. In April, Moody's confirmed EOGs A3 rating with a stable outlook.

In July, we successfully entered into a new $2 billion credit agreement to replace the existing one which would have matured in October 2016. Terms of the new agreement are similar to the prior credit agreement. The effective tax rate for the second quarter was 146% and current tax expense was $41 million.

For the period August 1 through December 31, 2015, EOG has crude oil financial price swap's contracts in place for 10,000 barrels of oil per day at a weighted average price of $89.98 per barrel.

For the second -- I'm sorry, for the period September 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtu per day at a weighted average price of $4.51 per MMBtu. These numbers exclude options that are exercisable by our counterparties. Now, I will turn it back over to Bill..

Thanks, Tim. Concerning our macro view, we believe current oil prices are not sustainable and the market will rebalance. Low oil prices are slowing supply growth and encouraging demand worldwide. We believe that U.S. oil production will have significant month-over-month declines in the second half of this year.

So our assessment is, there is more upside to the forward curve than downside. In summary, before we open up the call for Q&A, I want to talk about the core fundamentals that defined EOGs strategy for creating long-term shareholder value. The first core fundamental is that EOG is return driven. We allocate capital in order to earn the highest returns.

As we have done for many years, our goal is to be the peer leader in capital returns. Our second core fundamental is organic growth. Growing through the drill bit is the most return friendly, and therefore, shareholder friendly means of growth. Our goal is to be the leader in organic U.S. oil growth. The third core fundamental is a strong balance sheet.

Our goal is to maintain a disciplined spending program that keeps our net debt low and liquidity strong. Finally, the fourth core fundamental is commitment to the dividend. Our track record indicates our continued commitment to the dividend.

Staying focused on these four core fundamentals, return driven, organic growth, strong balance sheet and commitment to the dividend is how EOG consistently delivers long-term shareholder value. Thanks for listening. Now, we will go to Q&A..

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

Thanks. Hi. Good morning, everyone. And thanks for all the detail on the slide deck. Bill, I wanted to start with a micro question if I may because you guys have obviously done a phenomenal job of getting your costs down, your efficiency improvements and I think a couple of slides really speak to the depth of the portfolio.

But, it seems that you are making a micro decision based on oil price and no one else seems to be taken the same view. In other words, you're forgoing production growth and a lot of your peers with lesser economics are continuing to pursue goals.

I'm just kind of wondering, if you can help us reconcile your micro thoughts with the stock specific opportunities you have in the portfolio. And I guess with a view to 2016. I have got a follow-up..

Yes. Doug, our macro view is – we think a very solid view. We do a lot of work and a lot of study on the process and we particularly model what everybody is saying in the U.S. and what they're going to be doing in the second half of this year through their guidance.

And we really believe that in the second part of this year we are going to see some strong month-over-month decline rates. And it may take – it will take probably at least two or three more months for the monthly numbers to confirm this. There is a two-month lag in the data and the data is not, as we know, not precise and it gets updated over time.

So what we really need to see to confirm this is the July and August monthly data and that will come in, in September and October. So hopefully by that time the declines will be a bit more evident to everybody and if that happens we could see a bit more from this in the price. So our model shows what everybody is guiding that the U.S.

will grow about 500,000 to 600,000 barrels a day this year versus the $1.2 million barrel a day last year. So there's a significant drop-off in the year-over-year growth rate. And then if the prices continue to stay low through the end of the year, we expect 2016 to have continued month-over-month decline rates in the U.S.

And that will be joined by decline rates in other non-OPEC supply in 2016. And the combination of those things with the continued reasonable demand growth gives a decent opportunity for prices to be a bit better than they are right now in 2016.

So certainly that was a factor in our decision to defer spending capital, trying to accelerate oil in the current market. The other thing is, certainly is that we just can't see a good business reason to outspend growing oil in an oversupplied oil market. This does not make sense to us. So we believe we made the right decision..

Bill, I admire the discipline. I don't want to belabor this point, but I guess what I'm thinking is, if I look at Slide 5, you clearly have better returns today. For example, in the Leonard than you did when oil was substantially higher, which obviously fits your incentives structure to attract returns.

I guess what I'm really kind of thinking is that, let's assuming that you are wrong in oil prices don't recovery and consensus seems to be lower for longer.

Would you go back to growth in 2016?.

Let me give you a good overview. That's a good question. The company is set up for exceptionally strong performance in 2016. The capital required from growth in 2016 is considerably lower then we have had in the previous years.

Number one, as you noted, we have achieved very strong efficiency gains on the capital by lowering the cost, banking better wells to technology. And we're going to be able to continue that process in the second half of the year and really reap the benefits of that in 2016.

And the second thing is that as we talked about, we have a very large now 320 -- estimate 320 uncompleted well inventory that will be very high quality. I think it will be the highest quality inventory of any operator in the U.S. and that inventory is ready to complete, to begin completion early in the year next year.

We have infrastructure in place for all of that uncompleted inventory. So that won't slow us down. And then we're making significant improvements in lowering decline rates in a number of different ways. The first one is, we continue to drill our laterals in better rock.

We're drilling -- we are taking a lot of time and effort, picking out the best quality rock in each one of these plays and keeping the lateral in that longer. And then and to execute that well is very important.

And when we do that, we now are doing a much better job with these high density fracs and better distributing the frac along the lateral, connecting up more of that good rock. And it certainly lowering our decline rates over time and that makes it easier to grow production.

And the last thing, which is very important, we have tremendous capital flexibility in 2016. We don't have many service or rig contracts that will be in place as we begin 2016. We have very few lease retention requirements and we have very few international commitments.

So we are fully flexible to concentrate our capital, particularly in the first half of the year, on this very high-quality uncompleted well inventory. We are not going to give any specific guidance on our CapEx until February of next year.

We want to work the details and so we're just going to -- we will make our CapEx plans based on what the 2016 forward curve looks like in February. And we are going to remain patient and really run our business right and continue the focus on improving the returns as we go forward..

I appreciate it. That's a lengthy answer. I will get back in queue for my follow-up. [indiscernible] time. Thanks again..

We will next go to Evan Calio with Morgan Stanley..

Good morning. Let me follow up on your 2016 comments and I appreciate your asset position and you're not in the budget mode today.

You are philosophically, I mean if necessary to stay within cash flow into 2016, are you willing to go into annual production declines or is that where you would consider drawing ducts or moving into an outspend?.

Evan, we definitely want – that's a primary goal is to just have a balanced spending program or CapEx is balanced with our discretionary cash flow. Next year, our capital required just to maintain the flat production is very low. So we don't see a scenario that we can't keep production flat.

So I'm going to ask Gary Thomas to kind of walk through how 2016 might unfold..

The question there, Evan as far as, yes, would we just grow production? We're not inclined to grow production just in a continued low-price environment. But, like Bill saying, we are well well-positioned with all of our high-quality ducts, wells not completed.

And we are going to end the year with 15 to 18 drilling rigs and we will only have 13 under loan contract next year. So in order to go ahead and just lease maintain, possibly grow production, depending on what the prices are, we will start with quite a number of completion units.

And that allows us to bring production on rapidly and also we will be able to do it at low cost with all of the reduced costs we have had from increased efficiencies here through 2015..

Okay. I was just curious, if you would let it go to decline. It sounded more of a no than a yes. But, let me –.

We have maintained our productions for domestic just flat here. And that's kind of what we got here through 2015. So that's probably likely for 2016..

Great. My second one, if I could on a high density completions. You guys are clearly the leader here. It's 95% of Eagle Ford wells this year. You began the Bakken with a very strong Antelope extension well implemented the 2nd Bone Springs this quarter or last quarter Wolfcamp in the 3Q and Leonard since the beginning of the year.

I mean can you walk me through how long it takes you to substantially implement those designs across your Delaware and Bakken positions? I'm just wondering how we should think about, how long it takes to get to a similar percentage of high-density completions as you have in the Eagle Ford and the rest of your portfolio..

Evan, you have seen this work so well throughout all of our plays. We are under implementation currently. So it's in place and then we are seeing how we can make further improvements in this which is just EOGs way to do our business. So it's in place.

Then the Eagle Ford and we are running it in the Permian Basin and also in the Rocky Mountains and most all of our plays. We're thrilled with the results. And we are being able, at first our cost was a little bit higher and you will notice that looking at the Eagle Ford, slightly higher, but we are finding ways to bring those costs down now..

Great. I will leave it there. Thanks..

Our next question comes from Charles Meade with Johnson Rice..

Yes. Good morning to everyone there. If I could take another stab at the completion questions specifically the high density and the anti-density completion in the Bakken. I think during David's prepared comments you mentioned that what I thought I heard was that was the first completion in the site in the Antelope extension area.

And I'm wondering if you could give us a little history of how long you have been doing this and in what areas you have been doing it and really that's a remarkable result with the Riverview well.

And I'm wondering how applicable is that new completion technique across your whole footprint up there?.

Yes, Charles. This is David. That's correct. That was the first, what we have considered high density completion in Antelope. And obviously, the results speak for themselves. It is an excellent well and we have been, like Gary had mentioned, we are applying those techniques really all across the company and certainly cross the Bakken.

No two wells are exactly the same. We always customize the completion job based on the geology. So we are implementing those types of techniques really there at Antelope and in the Bakken core. Obviously, we are doing that in the Eagle Ford and the Delaware Basin as well. But, we are seeing a tremendous uplift in the productivity of the wells..

Got it.

And so in the core as well as the extension -- antelope extension?.

Yes. The completions aren't identical, like I said, because the geology varies throughout the area, but the key aspects of the completions will be implemented in the core and on down the road and in the non-core as well..

Got it. Thank you. And then, Bill, if I could try one more stab at this 2016 picture that obviously everyone is curious about but you guys are still working on it, if, I knew that you have this discipline returns focus.

I'm wondering if you could foresee, if the forward curve does bear out, is there a time in 2016 when you think -- when you could foresee, having progressed enough on the efficiency and cost front that the returns would be sufficient that you would want to go ahead and accelerate completion activity even if we're still looking at $52 oil at the of 2016?.

Charles, we are going to – that's really good question. Really, even if oil stays where it is right now, we are going to go ahead and move forward in a pretty aggressive fashion on that DUC inventory in the first part of the year. That would be the highest return decision that we could make with our capital.

We really thought through this and we worked on this plan back in late 2014 and really thought the consequences of all the different price scenarios as we considered it over kind of a two year period. And so we will be starting completion fairly aggressive on these DUCs early next year..

Thank you, Bill. I appreciate the comments..

We will take our next question from Leo Mariani with RBC..

Hi, guys. I was hoping for a little bit more color around the stagger stack activity here in Eagle Ford.

Just trying to get a sense of what type of space between wellbores you guys are imploring and basically how long have you had some of these pilots on and when you think we might see results here?.

Yes, Leo. This is Billy Helms. For our staggered W patterns that we are testing now we actually have several patterns across the field that we're testing as we speak. Just a reminder, in our last update on the Eagle Ford we have about 3.2 billion barrels of recoverable oil out of 7200 locations. That's an average of about 40 acre spacing.

So obviously we're testing spacing. And these are W patterns in the lower Eagle Ford only. And so that spacing would be somewhat less than 40 acres each. Spacing pattern is slightly different. And we are just beginning to see some of those early results and actually just testing some of them haven't even come on production yet.

So we still need some time to evaluate the production from these to understand what the impact is going to be. To the field, obviously, we are pretty optimistic based on some of the early results we have seen, but it is still early yet to really talk about the impact so we are encouraged though..

Okay. That's helpful.

I guess, I think a lot of people are curious about whether or not there is any decent kind of M&A your acreage acquisition opportunities out there on the market giving low prices? Can you guys kind of address your thoughts on the current M&A market?.

Yes, Leo. This is Billy Helms, again. Just like many of our peer companies we are looking for those opportunities. I think you can see prices have been fairly good as far as people selling properties. I think evaluations are still pretty high. You have seen very few large M&A structures out there and I think we are kind of see the same thing.

We have evaluated many things. I think what you will probably see more of is the smaller tactical acquisitions. That's kind of what we are maybe more focused on than any kind of large M&A things out there.

We are seeing opportunities in different basins and we are actively looking at things we are still optimistic that we are going to be able to do some more small tactical acquisitions and build acreage positions in some of our key or emerging plays.

We are having some success in just acquiring lease sold in some of our new emerging plays more so than we have in the past. So that's positive. So overall, I think right now the deals that are out there and available, there is still quite a bit of money chasing them. The prices are still pretty highly valued for the oil properties.

So the key is trying to find things for us, for EOG the key is finding things that will add good valuable acreage that will compete with our existing inventory. But we're going to be very selective in what we chase..

Okay. That's helpful. Thanks guys..

Our next question comes from Subash Chandra with Guggenheim Securities..

Yes. Hi. Good morning. From your comment earlier that your base decline rate is you're making progress there et cetera.

So is it fair to conclude that you are pretty well convinced the combination of lateral targeting and high density completion is enhancing oil recovery versus accelerated recovery of existing reserves? And, that the decline curve does not change on these completions versus the base completions? And then I have a follow-up..

Yes, Subash. We are fairly convinced that we are not competing for a reserve with offset wells. And the reason is that these high density completions they do two things. They connect up more of the rock along the lateral and the second thing they do is, they really help contain the geometry of the frac.

So the frac does not frac out as long it's far in a lateral extent or even if it doesn't frac vertically a great distance to connect up a significant amount of rock. So the fracs are not competing with each other for production.

So we used to think, it has really been a shift in thinking, we used to think that these big fracs just connected up a lot of rock both laterally and vertically, but as we go forward and we change the design and we get more data we become more convinced that the frac is just, especially these high density fracs is really most effective very, very close to the wellbore.

So that is really helping to boost our confidence and that we're going to add additional reserve potential going forward..

Got it. Thank you. And my follow-up, it is something you have hesitated to answer before. I will try it again anyway.

But is there any regional color you can give on production by basin in your guide, which areas might be raising and falling et cetera?.

No. Other than just generally, we don't guide by area. And we're not going to be doing that in the future, but you can generally, the Eagle Ford is obviously our strongest producer. The Bakken and the Permian are kind of second and third, but our activity, as you all know, in the Delaware Basin this year has doubled from last year.

So we are growing volumes there rather rapidly in the Permian..

Okay. Thank you very much..

Our next question comes from Brian Cox with Deutsche Bank..

Great. Thanks. Good morning, gentlemen. Maybe a segue one, my first question on the Permian. I don't need to be nitpicky, but it seemed like there was a relative shift away from the Leonard and towards the Wolfcamp and the Delaware Basin.

Has there been any change the way you view the plays or is this just the Wolfcamp getting better and maybe just some overall commentary on your thoughts on the Delaware portfolio and potential for acceleration going forward?.

Yes, Brian. This is Billy Helms. In the Delaware Basin certainly we are excited about all three of the major plays we have there. The Wolfcamp, the Bone Springs and the Leonard. For the Leonard it's more – it's more mature play for EOG. We have been operating there. We have more history.

We understand the play a little bit more than we do some of the other plays. So we have shifted some of that activity to the Wolfcamp and Bone Springs. The Bone Springs probably has the biggest relative increase in capital this year. We completed quite a few wells in the first half.

And then the Wolfcamp will be completing more wells in the second half of the year than we have in the first half, but in general the Wolfcamp, we are still learning a lot about it. We have got quite a few targets zones we are testing.

We are testing various areas of the Wolfcamp play where we have acreage and we're testing some various spacing patterns. So we still have a lot to learn about the Wolfcamp.

The other thing we're doing is with the Wolfcamp being in the deeper target we are gathering additional data on the Leonard and Bone Springs pay zones when we drill down through those on our way to the Wolfcamp.

So by gathering additional petrophysical data and rock data we are better able to look at the variability of the pace actions and those two shallower pay zones and gives us a better idea about how to develop those, how to better target those and where the best upside might be. So it is kind of an overall approach to understand the play better.

And that's one reason, major reason we have shifted more to the Wolfcamp..

Thanks. That's helpful. And then maybe just an overall question on portfolio -- on the broader company portfolio.

At this point we have had questions about the potential for acquisitions, but are there any interest on your end in divestitures, our international assets still considered core at this point or is there any other parts of the portfolio when you think about long-term portfolio optimization where you could be a potential seller?.

Brian, yes. We were always interested in upgrading our portfolio. And so every year we mix in property sales in our plan and this year is no different; 2016 will be no different. And we want to continue to divest -- think about divesting the properties that are less profitable obviously that don't fit our CapEx requirements.

We have such an enormous high-graded inventory to develop we are always wanting to evaluate the potential of our existing properties. At this point in the company, we don't really have a lot of what I would call crummy properties or not quality properties.

All of our properties are fairly quality, but we're going to be looking at continuing to upgrade our portfolio as we go forward..

Great. Thank you..

Our next question comes from Pearce Hammond with Simmons & Company..

Thank you and good morning. Thanks for taking my questions. Bill, you had some good commentary, good Q&A earlier on 2016. I appreciate all that but just trying to distill some of the earlier questions this morning.

Are you saying that you think if the current strip that EOG can keep exit rate 2015 production flat next year within cash flow?.

I think that is an accurate statement, Pearce. We are set up so well with the DUC inventory that even with the low prices we would have enough cash flow to keep production flat..

All right. Thank you for that. And then my follow-up, does you had the good news slide in your deck about compensation factor weightings for the E&P industry.

And EOG had much less emphasis on production and reserve growth than peers and I assume obviously that leads into your decision to build the DUC inventory in the second half of this year higher than what you originally thought and be restrained on production because of the lower price environment that we are in.

However, earlier on the call you stated that you would not have 2016 production decline year-over-year at the current strip.

So if the returns for 2016 aren't that great and your compensation structure doesn't tell you to push production, why wouldn't you employ the same strategy in 2016 as you are employing in the second half of this year or is there a mechanical reason why you don't want production to decline? Is it problematic or is it just strictly cash flow needs?.

I think next year, Pearce, what we are saying is that even with the minimum, even with the low-price cash flow scenario the highest return investment we could make in the company would be to begin completing those DUCs and complete those DUCs earlier in the year versus spending that money on other things.

So the quality of these DUCs is very high quality. So we have infrastructure in place. So that would be the highest return place to put the money..

Thank you, Bill..

We will take our next question from Irene Haas with Wunderlich..

Yes. Hi. I specifically would like to ask you a question in North Delaware basin. I am noticing these wells are really very, very attractively priced like $7 million D&C.

So question is, this is less overpressure, how many streams of casing do you use up there? And also these quotes we're looking at, are they in patch sort of patch drilling for pat mode, could we expect for the more reduction to come? And then alluding a little bit to something you said earlier, in the final development scheme which would be specing these really prolific zones together when you go into manufacturing mode that's probably something different from Eagle Ford..

Hello, Irene. This is Gary Thomas. Yes, we are really pleased with the progress we have made there in the Delaware. But I would say it's really early on and you really, that was really good comment there as far as, yes, it is overpressured and we are still working on our wellbore geometry. So we have tested several different things.

We believe that we will be able to get to a point where we are looking at two string design and just like we always do and like you have seen us do in the Eagle Ford and in the Bakken, we will just continue to reduce those days and we will reduce those costs. Because --, go ahead, Irene..

Go ahead. I’m sorry..

I was just going to say yes, you look through those various plays and we reduced our days anywhere from, oh goodness, 15% to 30%. And of course, that translates to cost. We are really making a lot of progress on the completion side in cost reduction. So yes, overall our total well cost has been reduced by about 20%.

But again, it's less in the Delaware and we're just kind of turning that on [indiscernible]..

So I was wondering, for the two wells you quoted, they are really short lateral and they got some really kind of impressive rates.

And so my question for you, are you targeting pure shale or are you looking for something a little different?.

The Wolfcamp is, I would say it's, we're looking at whatever the best pay target is in those at this point in time. So in every one of these plays, as Bill mentioned earlier, we are spending a lot of time on targeting and trying to understand what the best part of that rock is, if it's a shale that's great.

If it's not it's a silk stone, we look at those. So each area the target varies and so we spend quite a bit of time trying to understand what is the best target and then how do we best develop that? And the completion approach varies on each one of those. And the spacing approach might vary on each one of those.

In general, our target windows are getting much more narrow than they had been in the past and we are seeing that by keeping the wellbores in the best rock longer and being able to more intentionally complete those wells in that best target productivity is better and the declines are lower..

Great. It sounds like a really surgical approach..

We hope so..

Thank you..

Our next question comes from Phillips Johnston with Capital One..

Hi, guys. Thanks. My first question is on LOE costs. We saw a nice decline this quarter and the guidance suggests that the run rate should be in the low $6 range or so because which is also down from all of last year. We have seen most other companies report lower LOE costs as well. I'm just trying to gauge how sustainable to lower trend is for you guys.

It looks like decline for EOG was less a function of fewer workovers, but rather a significant decline on the O&M front.

You have referenced the impact of new infrastructure in the core of the Williston, but can you maybe talk about which components of O&M you are seeing costs decline and how much of those savings are secular versus cyclical?.

Yes. This is Gary Thomas. I'm sure you noticed that the first quarter and we commented on that last earnings call, it was above our guidance and our reason is we were a little bit late getting some of our infrastructure installed and that all did come on.

So we had that infrastructure in place and our major plays, a few other things yet to be done there. So as far as driving our cost down the way we have here this second quarter, it's about half through having infrastructure, maybe a quarter of that just vendor cost reduction and other quarter would be just efficiency gains.

So a large portion of that will be sustainable.

It's really, we always make comments about our infrastructure and that spending, but it sure has been official for us getting our cost down and you will notice that our chart number 12 there, really pleased with us becoming more of liquids company and then being able to maintain our lifting cost fairly flat..

Sounds good..

The second –.

The second question, your production guidance suggests roughly a 2% up tick in [indiscernible] in the fourth quarter after three quarters of sequential declines.

I just wanted to reconcile that up tick with the fact that you guys spent about 60% of your capital budget for the year in the first half and you also reduced the number of expected net completions in the Eagle Ford and the Permian by about 50 wells for the year..

That kind of goes back to the time required from the point of -- yes, you initiate the well or even initiate the completion with us having several of these big part of our wells and now our own on pads, so you bring numbers of wells on.

So yes, we are going to be bringing cost down and we will be able to maintain our production here with this second half as we have guided..

Okay. Just a follow-up on that.

Are you able to say what percentage of the 405 net wells you plan to complete in Eagle Ford, Bakken, Permian, have you completed in the first half of the year?.

Yes. First half is roughly 55%, second half like 45%..

Okay. Great. Thanks guys. Thank you..

And that does conclude today's question-and-answer session. Mr. Thomas, at this time, I will turn the conference back to you for any additional or closing remarks..

Yes. I did have a couple of final remarks. First of all, thank you for the great questions. I also want to thank all the employees of EOG for their tremendous efforts and contributions this year in making the EOG successful just did an outstanding job.

My final message is this, I think you have heard it all through the call, the company continues to be focused on creating long-term shareholder value. We are not chasing short-term volumes in an oversupplied oil market.

We have really focused on the fundamentals, improving returns, improving operating margins and building decades of high return growth potential. Our plan, EOGs plan is to deliver value to shareholders with high margin, high return production growth for years to come. So I want to thank everybody for listening and certainly thank you for your support..

Thank you for your participation. This does conclude today's call..