Good day everyone, 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.
Thank you. Good morning thanks for joining us. We hope everyone has seen the press release announcing second 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 in EOG's SEC filings, 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. 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, Marketing Operations; Cedric Burgher , Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, we included guidance for the third quarter and full year 2015 in yesterday's press release. This morning, we'll 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 EOG's financials, capital structure, and hedge position, Bill will provide concluding remarks. Here's Bill Thomas.
Thanks, Tim. Good morning, everyone. There are a couple of items I will cover with you on the call today. First, I will discuss the outstanding progress we've made transitioning the company to be successful in a lower oil price environment, I'll explain why EOG is uniquely positioned to accomplish this. Second, I will describe the framework we're 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 earn a 30% after-tax rate of return with a flat $50 oil price. We have multiple decades of drilling inventory in these high return, 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've captured the sweet spots 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 innovation 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 EOG's well and operating costs were already the lowest in the industry, and 2015 is proving to be our best year ever for realizing additional cost reductions. EOG's scale in 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 EOG's organization and culture. This is a 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 rate of return, which is the key driver to our peer-leading return on capital employed. Return-based decision making and incentives drive EOG's 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 and 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've 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're 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 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 two and a half times our original estimate of $420 million barrels of oil equivalent. Remaining drilling inventory increased from 580 to over 1,500 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 2 categories that we have titled core acreage and non-core acreage. The core produces returns 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 Light, 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 10232H 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 3,395 barrels of oil per day and 6 million cubic feet of rich natural gas. With an average rate of 2,760 barrels of oil per day for July, this short 4,300-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 through advanced completions, we've made tremendous progress on Bakken completed well costs, which are now $7.1 million for an 8,400-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, and therefore should be sustainable over time. Drilling times are now averaging 8.2 days spud to TD for an 8,400-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 and drilling inventory illustrates the value of EOG's exploration and technology leadership.
We enter plays as the first mover and capture the best assets. We grow 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 the 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 cost. In the case of improved productivity, we are finding that well bore targeting, along with our integrated completion approach, continues to provide upside on well performance. In the second quarter, we maintained our activity in the Second Bone Spring Sand, testing various spacing patterns and targets. Two recent wells, the Dragon 36 State number 501H and 502H, were completed in 1,000-foot space pattern with initial production rates of 1,075 and 1,755 barrels of oil per day.
Another recent completion in Lea County, New Mexico, the Frazier 34 State Comm number 501H, tested 1,705 barrels of oil per day with 145 barrels per day of NGLs and 1.1 million cubic feet per day of natural gas. The completed well cost for the Second 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 Comm number 703H, had initial production rates per well of 2,650 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 costs $5.5 million, and we are testing spacing patterns of 300 feet and 500 feet between wells. One recent completion in Lea County, New Mexico, the Jim 36 State Comm number 1H, had an initial production rate of 2,200 barrels of oil per day, 460 barrels per day of NGLs, and 2.6 million cubic feet per day of natural gas.
Our down spacing 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 EOG's 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 costs to a minimum. We are very excited about the opportunities and growth potential for EOG's Delaware Basin properties. Now moving to the Eagle Ford, which continues to be our workhorse asset. Due to the sheer scale of our operations there, it functions as a laboratory for technical progress on target selection, geo-steering, and high-density completion designs.
To support our well bore targeting efforts this year, we drilled four pilot wells to gather additional log data and provide a more complete picture of our acreage. This information greatly enhances our understanding of any specific target's variability across the play. We are currently conducting tests using a staggered W pattern in the lower Eagle Ford, and the new data we've gathered on the targets is encouraging as it supports our expectations for success. While it's 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.
Also, the productivity of the wells continues to show steady improvement through our emphasis on targeting and high-density completions. Similar to our other plays, most of these cost reductions are being achieved through efficiency gains and should be sustainable.
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'll 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, and the debt-to-total capitalization ratio was 27%. At June 30, we had $1.4 billion of cash on hand, giving us non-GAAP net debt of $5 billion for a net debt to total cap ratio of 22%. In April, Moody's confirmed EOG's 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 swaps contracts in place for 10,000 barrels of oil per day at a weighted average price of $89.98 per barrel. 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. I'll 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 U.S. oil production will have significant month-over-month declines in the second half of this year. 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 define EOG's 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've 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'll go to Q&A.
Ladies and gentlemen, if you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touch-tone phone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. We'll take our first question from Doug Leggate with BofA, Bank of America Merrill Lynch.
Thanks. Good morning, everyone, and thanks for all the detail on the slide deck. Bill, I want to start with a macro 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 the slides really speak to the depth of the portfolio. But it seems that you're making a macro decision based on an oil price view and no one else seems to be taking the same view. In other words, you're foregoing production growth and a lot of your peers with lesser economics are continuing to pursue growth. I'm just kind of wondering if you can help us reconcile your macro thoughts with the stock specific opportunities you have in the portfolio, and I guess with a view to 2016. I've got a follow-up.
Yes, Doug, our macro view is we think a pretty solid view. We do a lot of work and a lot of study on the process. We particularly model what everybody's saying in the U.S. and what they're going to be doing in the second half of this year through their guidance. We really believe that in the second part of this year, we're going to see some strong month-over-month decline rates. It may take probably at least two or three more months for the monthly numbers to confirm this. There's a two-month lag in the data, and the data is, as we know, not precise, and it gets updated over time. What we really need to see to confirm this is the July and August monthly data, and that'll come in in September and October.
Hopefully by that time, the declines will be a bit more evident to everybody. If that happens, we could see a bit more firmness in the price. Our model shows, by 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 barrels a day last year. There's a significant drop-off in the year-over-year growth rate. If 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. 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.
Certainly, that was a factor in our decision to defer spending capital, trying to accelerate oil in the current market. The other thing certainly is that we just can't see a good business reason to outspend growing oil in an oversupplied oil market. That just does not make sense to us. We believe we made the right decision.
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 five, you clearly have better returns today, for example, in the Leonard than you did when oil was substantially higher, which obviously fits your incentive structure to attract returns. I guess what I'm really thinking is, let's assume that you're wrong and oil prices don't recover, because consensus seems to be lower for longer. Would you go back to growth in 2016?
Yeah, let me give you a good overview. That's a good question, Doug. The company is set up for exceptionally strong performance in 2016. The capital required for growth in 2016 is considerably lower than we've had in the previous years. Number 1, as you noted, we've achieved very strong efficiency gains on the capital by lowering the cost, by making better wells through 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. The second thing is that, as we've talked about, we have a very large, now 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 that uncompleted inventory, so that won't slow us down. 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 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. To execute that well is very important. When we do that, we now are doing a much better job with these high-density fracs. It's better distributing the frac along the lateral, connecting up more of that good rock, and it's certainly lowering our decline rates over time, and that makes it easier to grow production. 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. We're fully flexible to concentrate our capital, particularly in the first half of the year, on this very high-quality.
Uncompleted well inventory. We're not going to give any specific guidance on our CapEx until February of next year. We want to work the details. We'll make our CapEx plan based on what the 2016 forward curve looks like in February. We're going to remain patient and really run our business right and continue to focus on improving the returns as we go forward.
Bill, I appreciate the length of the answer. I'll get back in queue for my follow-up. I want to be respectful of everybody's time. Thanks again.
We'll next go to Evan Calio with Morgan Stanley.
Hey, good morning, guys. Let me follow up on your 2016 comments. I appreciate your asset position. You're not in the budget mode today. Philosophically, 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 DUCs or move into an outspend?
Yeah, that's the primary goal is to just have a balanced spending program where CapEx is balanced with our discretionary cash flow. Next year, our capital required just to maintain flat production is very low. We don't see a scenario that we can't keep production flat. I'm going to ask Gary Thomas to 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. Like Bill's saying, we're very well positioned with all of our high-quality DUCs, wells not completed. We're going to end the year with 15-18 drilling rigs, and we'll only have 13 under long contract next year. In order to go ahead and just at least maintain, possibly grow production, depending on what the prices are, we'll start with quite a number of completion units. That just allows us to bring production on rapidly. Also we'll be able to do it at low cost with all the reduced costs we've had from just increased efficiencies here through 2015.
Okay.
Evan?
Well, I was curious if you would go and let it go to decline, and it sounded more of a no than a yes.
We've maintained our production as far as domestic, just flat here, and that's what we guide here through 2015. That's probably likely for 2016.
Great. My second one, if I could, on the high-density completions. You guys are clearly the leader here. It's 95% of your Eagle Ford wells this year. You've begun in the Bakken with a very strong Antelope extension well. Implemented a second Bone Springs, what, this quarter or last quarter, Wolfcamp in the 3Q, and Leonard since the beginning of the year. 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 the rest of your portfolio.
Evan, we've seen this work so well throughout all of our plays. We're under implementation currently. It's in place, and then we're seeing how we can make further improvements in this, which is just EOG's way to do our business. It's in place in the Eagle Ford, and we're running it in the Permian Basin and also in the Rocky Mountains, in most all of our plays. We're thrilled with the results. At first, our cost was a little bit higher, and you'll notice that looking at the Eagle Ford, slightly higher, but we're finding ways to bring those costs down now.
Great. I'll leave it there. Thanks, guys.
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 question, specifically the enhanced high-density completion in the Bakken. I think during David's prepared comments, he mentioned that what I thought I heard was that was the first completion of this type in the Antelope extension area. I wonder if you could give us a little history of how long you've been doing this and in what areas you've been doing it in. 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?
Yeah, Charles, this is David. Yeah, that's correct. That was the first what we would consider high-density completion in Antelope, obviously the results speak for themselves. It's an excellent well. We've been, like Gary had mentioned, we're applying those techniques really all across the company and certainly across the Bakken. No two wells are exactly the same. We always customize the completion job based on the geology. We are implementing those types of techniques, really there at Antelope and in the Bakken core. Obviously, we're doing that in the Eagle Ford and the Delaware Basin as well. We're seeing a tremendous uplift in the productivity of the wells.
Got it. In the core as well as the Antelope extension?
Yes. Yeah.
Okay.
The completions aren't identical, like I said, because the geology varies throughout the area. The key aspects of the completions will be implemented in the core and on down the road in the non-core as well.
Got it. Thank you. Then, Bill, if I could try one more stab at this 2016 picture that obviously everyone's curious about, but you guys are still working on it. I know that you have this disciplined returns focus. I'm wondering if you could foresee, if the forward curve does bear out, is there a time in 2016 when you could foresee having progressed enough on the efficiency and cost front that the returns would be sufficient that you'd want to go ahead and accelerate completion activity, even if we're still looking at $52 oil at the end of 2016?
Yeah, Charles, that's a really good question. Really, even if oil stays where it is right now, we're 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. 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. We'll be starting completions fairly aggressive on these DUCs early next year.
Thank you, Bill. Appreciate the comments.
We'll take our next question from Leo Mariani with RBC.
Hey, guys. I was hoping for a little bit more color around the stagger stack activity here in the Eagle Ford. Just trying to get a sense of what type of space between well bores you guys are employing and basically how long have you had some of these pilots on, and when do you think we may see results here?
Yeah, Leo, this is Billy Helms. For our staggered W patterns that we're 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 7,200 locations. That's an average of about 40 acre spacing. Obviously, we're testing spacing, and these are W patterns in the lower Eagle Ford only. That spacing would be somewhat less than 40 acres. Each spacing pattern is slightly different. 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. 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're pretty optimistic based on some of the early results we've seen, but it's still early yet to really talk about the impact. We're encouraged, though.
Okay. That's helpful. I think a lot of people are just very curious about whether or not there's any decent kind of M&A or acreage acquisition opportunities out there on the market given low prices. Can you guys address your thoughts on the current M&A market?
Yeah, Leo, this is Billy Helms again. Just like many of our peer companies, we're looking for those opportunities. I think you can see prices have been fairly good as far as people selling properties. I think the valuations are still pretty high. You've seen very few large M&A structures out there, and I think we're kind of seeing the same thing. We've evaluated many things. I think what you'll probably see more of is the smaller tactical acquisitions. That's what we're maybe more focused on than any kind of large M&A things out there. We are seeing opportunities in different basins, we are actively looking at things. We're still optimistic that we're 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 leasehold in some of our new emerging plays, more so than we have in the past. That's positive. Overall, I think right now, the deals that are out there and available, there's still quite a bit of money chasing them. The prices are still pretty highly valued for those properties. For us, for EOG, the key is finding things that will add good valuable acreage that will compete with our existing inventory. 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.
Yeah, hi, good morning. From your comment earlier that your base decline rate is you're making progress there, et cetera. Is it fair to conclude then that you're pretty well convinced the combination of lateral targeting and high-density completion is enhancing EUR recovery versus accelerated recovery of existing reserves, and that the decline curve does not change on these completions versus the base completions? Then I have a follow-up.
Yes. Subash, yes. We're fairly convinced that we're not competing for reserves with offset wells. The reason is that these high-density completions, they do two things. They connect up more of the rock along the lateral. The second thing they do is they really help contain the geometry of the frack. The frack does not frack out as long, as far in a lateral extent or even, it doesn't frack vertically a great distance to connect up a significant amount of rock. The fracks are not competing with each other for production. We used to think, and it's really been a shift in thinking. We used to think that these big fracks just connected up a lot of rock, both laterally and vertically.
As we go forward and we change the design and we get more data, we become more convinced that the frack is just, especially these high-density fracks, is really most effective very close to the wellbore. That is really helping to boost our confidence and that we're going to be able to add additional reserve potential going forward.
Okay, got it. Thank you. My follow-up is something you've hesitated to answer before. I'll try it again anyway, is there any regional color you can give on production by basin in your guide? Which areas might be rising 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. You can generally, the Eagle Ford is obviously our strongest producer. The Bakken and the Permian are kind of second and third. Our activity in the, as you all know, in the Delaware Basin this year has doubled from last year, so we're growing volumes there rather rapidly in the Permian.
Okay. Thank you very much.
Our next question comes from Ryan Todd with Deutsche Bank.
Great. Thanks. Good morning, gentlemen. Maybe that segues well into my first question on the Permian. I don't mean to be nitpicky, but it seemed like there was a relative shift away from the Leonard and towards the Wolfcamp in the Delaware Basin. Has there been any change in the way you view the plays? Is this just the Wolfcamp getting better? Maybe just some overall commentary on your thoughts on the Delaware portfolio and potential for acceleration going forward.
Yeah, Ryan, this is Billy Helms. In the Delaware Basin, certainly, we're excited about all three of the major plays we have there, the Wolfcamp, the Bone Springs, and the Leonard. For the Leonard, it's a more mature play for EOG. We've been operating there. We have more history. We understand the play a little bit more than we do some of the other plays. We've 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. The Wolfcamp will be completing more wells in the second half of the year than we have in the first half. In general, the Wolfcamp, we're still learning a lot about it. We've got quite a few target zones we're testing.
We're testing various areas of the Wolfcamp play where we have acreage, and we're testing some various spacing patterns. 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're gathering additional data on the Leonard and Bone Springs pay zones when we drill down through those on our way to the Wolfcamp. By gathering additional petrophysical data and rock data, we're better able to look at the variability of the pay sections in 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. It's kind of an overall approach to understand the play better, and that's one reason the major reason we've shifted more to the Wolfcamp.
Thanks. That's helpful. Then maybe just an overall question on the broader company portfolio. At this point, we've had questions about the potential for acquisitions, is there any interest on your end in divestitures? Are international assets still continued core at this point, are there any other parts of the portfolio when you think about long-term portfolio optimization that where you could be a potential seller?
Ryan, yes. We're always interested in upgrading our portfolio. Every year we mix in property sales in our plan, this year is no different. 2016 will be no different. We want to continue to think about divesting the properties that are less profitable, obviously, and don't fit our CapEx requirements. We have such an enormous high-graded inventory to develop. We're 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. 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. Good morning. Thanks for taking my questions.
Hey, Pearce.
Bill, you had some good commentary, good Q&A earlier on 2016. Appreciate all that, just trying to distill some of the earlier questions this morning. Are you saying that you think at the current strip that EOG can keep exit rate 15 production flat next year within cash flow?
I think that's an accurate statement, Pearce. Yeah, we're 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. My follow-up is, you had a good new slide in your deck about compensation factor weightings for the E&P industry, EOG had much less emphasis on production and reserve growth than did peers, I assume obviously that feeds into your decision to build the DUC inventory in the second half of this year higher than what you originally thought, be restrained on production because of the lower price environment that we're in. However, earlier on the call, you stated that you would not have 2016 production decline year-over-year at the current strip. 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're employing in the second half of this year?
Is there a mechanical reason why you don't want production to decline? Is it problematic or is it just strictly cash flow needs?
Yeah. I think next year, Pearce, what we're saying is that even with a low price cash flow scenario, the highest return on 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. The quality of these DUCs is very high quality. We have infrastructure in place. That would be the highest return place to put the money.
Thank you, Bill.
We'll take our next question from Irene Haas with Wunderlich.
Yes, hi. I specifically would like to ask you a question in Northern Delaware Basin. I'm noticing that these wells are really very, very attractively priced, like $7 million D&C. Question is it less overpressure? How many strings of casing do you use up there? Also these quotes we're looking at, are they in sort of batch drilling or pad mode? Could we expect some more reduction to come? Probably alluded to something that you said earlier. In the final development scheme, would you be stacking 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're really pleased with the progress that we've made there in the Delaware, but I would say it's really early on. That was a really good comment there as far as, yes, it is overpressured, and we're still working on our well bore geometry. We've tested several different things. We believe that we'll be able to get to a point where we're looking at two-string design, and just like we always do, and like you've seen us do in the Eagle Ford and in the Bakken, we'll just continue to reduce those days, and we'll reduce those costs.
May I?
Go ahead, Irene.
Go ahead. I'm sorry.
I was just going to say, yes, you look through those various plays, we've reduced our days from anywhere from, oh, goodness, 15%-30%. Of course, that translates to cost. We're really making a lot of progress on the completion side in cost reduction. Yes, overall, our total well cost has been reduced by about 20%. Again, it's less in the Delaware, and we're just kind of turning that on.
That's right. I was wondering, for these two wells you quoted, they're really short lateral, and they got some really impressive grades. My question for you, are you targeting pure shale or are you looking for something a little different?
Well, the Wolfcamp is, I'd say we're looking at whatever the best pay target is in those at this point in time. In every one of these plays, as Bill mentioned earlier, we're spending a lot of time on targeting, trying to understand what the best part of that rock is. If it's a shale, that's great. If it's not, if it's a silt stone, we look at those. Each area, the target varies. We spend quite a bit of time trying to understand what is the best target, and then how do we best develop that. 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're 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. Sounds like a really surgical approach.
We hope so.
Thank you.
Our next question comes from Phillips Johnston with Capital One.
Hey, guys. Thanks. My first question's 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, which is also down from all of last year. We've seen most other companies report lower LOE costs as well. I'm just trying to gauge how sustainable the lower trend is for you guys. It looks like the decline for EOG was less a function of fewer workovers, but rather a significant decline on the O&M front. You've referenced the impact of new infrastructure in the core of the Williston, but can you maybe talk about which components of O&M you're seeing cost declines and how much of those savings are secular versus cyclical?
Phillips, this is Gary Thomas. I'm sure you noticed too that, yes, first quarter, we commented on that last earnings call, it was above our guidance. Our reason is we were a little bit late getting some of our infrastructure installed, and that all did come on. We have that infrastructure in place in our major plays. A few other things yet to be done there. As far as driving our costs 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 the other quarter would be just efficiency gains. A large portion of that'll be sustainable. We always make comments about our infrastructure and that spending, but it sure is beneficial for us getting our costs down.
You'll notice, the our chart number 12 there, we're really pleased with us becoming more of a liquids company and then being able to maintain our lifting costs fairly flat.
Sounds good.
The second
Yeah. Second question. Your production guidance suggests roughly a 2% uptick in U.S. oil volumes in the fourth quarter after three quarters of sequential decline. I just wanted to reconcile that uptick 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.
Yeah. Phillips, that 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. A big part of our wells now are on pads, so you bring numbers of wells on. yes, we're going to be bringing costs down, and we'll be able to maintain our production here with this second half as we've guided. Have a look at the-
Okay. just to follow up on that then, are you able to say what percentage of the 405 net wells you plan to complete in Eagle Ford, Bakken, and Permian have you completed in the first half of the year?
Yeah, the first half is roughly 55%, second half, 45%.
Okay, great. Thank you.
About 450.
Thank you.
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.
Yeah, I do have a couple of final remarks. first of all, just 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 EOG successful. Just doing an outstanding job. My final message is this, and I think you've heard it all through the call. The company continues to be focused on creating long-term shareholder value. We're not chasing short-term volumes in an oversupply oil market. We're really focused on the fundamentals, improving returns, improving operating margins, and building decades of high return growth potential. our plan, EOG's plan, is to deliver value to shareholders with high margin, high return production growth for years to come. 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.