Bill Thomas - Chairman, Chief Executive Officer Tim Driggers - Chief Financial Officer Billy Helms - Chief Operating Officer Ken Boedeker - EVP, Exploration and Production Ezra Yacob - EVP Exploration and Production Lance Terveen - Senior VP, Marketing David Streit - VP, Investor and Public Relations

Good day, everyone, and welcome to EOG Resources, Second Quarter 2019 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.

Good morning and thanks for joining us. We hope everyone has seen the Press Release announcing second quarter 2019 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 and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. Definitions as well as reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. Some of the reserve estimates on this conference call and they are accompanying Investor Presentation slides may include estimated resource potential and other estimated of potential reserves not necessarily calculated in accordance with the SEC's reserve reported guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings release issued yesterday. Participating on the call this morning are Bill Thomas, Chairman and CEO; Billy Helms, Chief Operating Officer; Ken Boedeker, EVP, Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP, Marketing ;and David Streit, VP, Investor and Public Relations. Here’s Bill Thomas.

Thanks Tim and good morning everyone. EOG does not need high oil prices to create significant value for our shareholders. During the second quarter, despite a 12% decline in WTI oil prices, EOG generated more than $350 million of free cash flow, lowered our long term debt by $900 million and paid a substantially larger dividend than last year, all while organically growing U.S. oil production by 20%. The EOG culture consistently making improvements throughout the company year-after-year has propelled EOG to compete financially with the very best in the S&P500, all with oil prices averaging below $60 per barrel. We are now capable of delivering double digit return on capital employed, and double digit growth while generating substantial free cash flow through the commodity price cycles. Our commitment to strong free cash flow is enabling us to rapidly grow the dividend. We've increased the dividend 72% in the last two years and our ambition is to target a yield that is competitive in the S&P500, which stands around 2%. EOG never stops improving. We are one of the lowest cost producers in the global oil market and we continue to lower the cost of our business. In fact we have strong visibility and high confidence in our ability to lower our costs, so that by 2022 we can earn at least 10% return on capital employed at oil prices below $50 per barrel. Our first half results confirm that EOG is stronger than ever, and we are delivering a banner year in operational performance. For two quarters in a row we delivered more oil for less capital. With efficiency gains and new technology, we are achieving strong capital and operating cost reductions, while at the same time delivering excellent well performance. In addition, the company is leasing anchorage and…

Thanks Bill. For the second consecutive quarter, oil production beats the high end of our forecasted range, while the capital expenditures were below the low end. The performance in the first half of the year demonstrates our focus on continuous improvement as evidenced by our higher capital efficiency, lower operating costs and ongoing integration of operating practices to minimize our environmental footprint. There are several factors that drive these outstanding results. First, our production beat this quarter is due to improve well performance. Our new completion designs, including the use of diverters, along with a continued focus on target selection are the main reasons for the improvement. Beyond the completion design itself, we also developed proprietary technology that allows us to make real time adjustments during the execution of the frac, to minimize the impact on nearby producing wells, thus reducing shut-in volumes. Ken will expand on this technology in a moment. Second, we continue to reduce capital costs and see line of sight to reach our goal of reducing total well cost by 5% this year. Through the first half we have realized about a 4% reduction compared to 2018, as a result of improved operational execution. Design enhancements and efficiency improvements, not service cost reductions, are delivering consistently better results across each of our active areas. Third, our operating cost performance has been outstanding. As a result, we are lowering our full year unit cost forecast for LOE and transportation. Cash operating costs which include LOE, transportation and G&A are expected to be under $9 a barrel for the full year 2019 compared to nearly $13 a barrel as recently as 2014. Fourth, as Bill mentioned in his opening remarks, we are committed to sustainability. Our decision to embrace electric frac fleets is an example of how we…

Thanks Billy. The Eagle Ford continues to deliver consistent performance quarter-after-quarter. This world class oil asset is off to a great start in 2019, delivering low finding costs through ongoing cost reductions. Every measure of capital productivity is better in the first half of 2019 compared to full year 2018. This quarter I’ll highlight recent operational efficiencies driven by right sizing our completion designs and refining its execution. The wellbore stimulation process is aided by software developed in house, using our proprietary software and data on the nearby wells geology, spacing, lateral placement and production history, a unique completion design is prepared for each well in a pattern. The software allows EOG engineers to monitor real-time completions data, not only on the well we are stimulating, but also on surrounding wells. This enables the engineers to make real-time adjustments to the stimulation on a stage-by-stage basis. The result is a customized stimulation that can reduce pump time by 10%. The process also yields better well performance, both in and the new wells being completed and in the adjacent producing wells. For the new well, we can realize the same or better well performance with less sand. As a result, our completion costs are down 9% compared to last year, which is a significant contributor to our overall lower finding costs. Second, for the nearby producing wells, reduced sand loadings translate to reduce instances of sand reaching these offset wells. LOE costs come down due to reduced work over expenses to clean out sand during production and the associated downtime due to shut-ins is reduced, increasing volumes. In addition to completion cost reductions, we improved drawing speed and efficiency in the Eagle Ford. Thus far we've nearly realized or full year well cost reduction goal of 5%. Now, moving the discussion…

Thanks Ken. We played 65 net wells to sales in the second quarter and continue to have an outstanding year in the Delaware Basin. Our drilling performance continues to benefit from improved downhole motor designs and increased quality assurance. Year-to-date drilling days are down over 20% compared to 2018 and we continue to utilize proprietary software to balance our drilling speed and steering to stay within our precision targets. Completion costs are also down 10% compared to 2018 due to ongoing improvements to execution, application of our new completion techniques, as well as lower sand and water costs. Year-over-year stand costs are down 35% and our all-in-water costs including reuse have decreased by 30%. The combined impact of improved drilling and completions efficiencies has resulted in a year-to-date total average well cost reduction of 5% compared to 2018. Well productivity similar to operating efficiencies has also improved through the first half of 2019, across all five of our Delaware Basin targets. In our Delaware Basin Wolfcamp play, 30, 60 and 90 day rates have improved. Our 2019 Wolfcamp program is outperforming 2018 performance by 10% and continues to exceed our forecast. Performance of our shallower reservoir is also improving as we integrate geologic data, collected as we develop the deeper targets, along with our new completion technology. Year-to-date we brought on 23 net wealth in the Leonard and Bone Spring, with both formations performance stronger than 2018 results. In addition to tremendous progress lowering our finding and development costs through well productivity and capital cost improvements, we are benefiting from our strategic infrastructure investment. Currently 99% of our water and over 80% of our oil is transferred by pipe rather than trucking and contributes to a 5% reduction in operating costs compared to 2018. The impact of improved productivity and cost reductions have resulted in year-to-date all in finding costs below $10 per barrel of oil equivalent and an average direct after tax rate of return in excess of 100% of the current strip prices. Our progress throughout 2019 in the Delaware Basin highlights our focus on increasing capital efficiency through high return investments. Here’s Lance to provide a marketing update.

Thanks Ezra. During the second quarter our marketing strategy paid dividends. Our execution is a result of a portfolio sales approach; that is we work to ensure each of our asset teams has flexible takeaway and multiple in-markets available, which provide security, a full assurance and access the optimal net back price. Our U.S. crude oil price realizations averaged $1.18 above WTI which was on the high end of our guidance issued at the beginning of the quarter. With respect to natural gas, despite significant volatility and Permian Basin prices and softness in the Rockies and out west in California, EOGs overall natural gas price realizations were only modestly affected. Anticipating infrastructure and transportation capacity, well in advance of our development plans has allowed us to have full assurance to one, mitigate most of the effects of the week local premium pricing; and two, avoid the long term, high fixed cost transport contracts, as we expect the Waha basis will improve significantly as new pipelines in our service later this year and 2021. Downstream markets, natural gas and oil basis differentials change very quickly. Our portfolio approach provides flexibility to quickly pivot to the highest net back markets. For example, in the Permian the Mid‐Cush differential has strengthened considerably since the end of last year. Additionally, looking ahead to the end of this year and into 2020, the market is pricing in crude oil pipeline take away, coming in the service over the next several months, as seen in the narrower Permian to Gulf Coast spread. Our marking arrangements provide flexibility to sell our oil production in the local Midland market to take advantage of strength in the Mid‐Cush basis, or we can elect to utilize our low cost, long haul capacity to the Gulf Coast, the excess domestic refiners and export markets. Our forward looking portfolio approach has established access to Midland, Cushing, Houston, and Corpus Christi, along with doc capacity to access export markets for our Permian basin and oil production. In addition, access to all these markets by our diverse portfolio transportation, and self-markets options allows us to maintain direct control and keep our low cost transportation edge. I’ll now turn it over to Tim Driggers to discuss our financials and capital structure.

Thanks Lance. EOG leveraged its outstanding operation execution in the second quarter into superb financial performance. During the quarter the company generated discretionary cash flow of $2.1 billion, invested $1.6 billion in capital expenditures before acquisitions at the low end of our guidance and paid $127 million in dividends. This allows $352 million in free cash flow. In line with our objective of further strengthening our financial position, we repaid a $900 million bond in June with cash-on-hand. This leaves $1.75 billion remaining in our $3 billion, four year debt reduction plan which we expect to complete in 2021. Cash on the balance sheet at June 30 was $1.2 billion and total debt was $5.2 billion for a net debt to total capitalization ratio 16%, significantly lower than 24% just one year ago. In addition to the excess of the debt reduction plan has had on improving our leverage metrics, it has also meaningfully reducing our cash cost. Net interest expense has fallen about a third to $185 million, the mid-point of our fill year 2019 guidance from $282 million in 2016. The financial model for EOG is straightforward. We can very efficiently generate double digit organic growth at high rates of return, leverage our scale to reduce operating expenses and continue to lower the old price required to earn a double digit ROCE. We believe EOG can accomplish this while supporting a growing dividend competitive with the S&P500 in generating a rising stream of free cash flow. The combination of EOGs financial strength, industry leading cost structure and organic exploration edge can deliver a level of financial performance, competitive not just with the best E&P companies, but competitive with the best companies in the industry in the S&P500 and we can deliver this performance at lower and lower commodity prices. I'll now turn it back over to Bill for closing remarks.

Thanks Tim. In conclusion EOG is executing at the highest level in company history and improving every quarter. Our premium drilling strategy combined with our ability to achieve continuous efficiency gains and technology breakthroughs are producing record results. The company is delivering a strong return on capital employed, production growth, free cash flow, debt reduction and strong dividend growth with oil in the 50s, and we clearly are on a path to achieve strong performance with oil in the 40s. We are accomplishing our goal of achieving results that are competitive with the best companies across all sectors in the S&P500 through the commodity price cycles. In addition to financial returns, EOGs mission is to be a leader in ESG performance. Our unique culture has embraced ESG with the same enthusiasm as everything else we do, innovation, technology and the pleased but not satisfied culture of EOG have a long history of producing outstanding results, and we believe that our best days are still ahead of us. Thanks for listening and now we'll go to Q&A.

Thank you. [Operator Instructions] And today’s first question comes from Arun Jayram of JP Morgan. Please go ahead.

Yeah, good morning. I was wondering if we could maybe start with your thoughts on well spacing in the Delaware Basin and how you guys are managing the process to call it maximize resource recovery while mitigating the impacts from adverse communication?

Yeah, good morning Arun. Thank you for the question. Just in general, you know because we’ve been in the shale business for two decades, you know we have a big learning curve in the history of the company and we recognize the parent child relationship and the importance of proper spacing to develop the assets correctly. And specifically you know in the Delaware Basin we attack that problem very aggressively back in 2017 and the early part of 2018, and we really got the learning curve on that well behind us and we continually are still making progress going forward, but we really are well down the road on maximizing the value of our asset. And so I'd like to maybe let Ezra, he’s really the expert on the Delaware Basin to give you a little bit more color on that.

Yes Arun, it’s Ezra. As you know our resource estimate is based on 660 foot spacing in the Wolfcamp Oil window, and an 880 foot space in the combo side of that play and we are very confident in those numbers still. As you know and as Bill mentioned, we've been drilling multiple targets within the Wolfcamp and actually a tighter spacing on average than what our resource estimate is based on and so I think that you can see we've got a bit upside we feel like, not only really in our Delaware Basin Plays but across the portfolio of our plays. One way that we approached it and some of the testing that we did as Bill mentioned over a year ago is really to look at the number of targets and the quality of our high precision target that need to be co-developed with one another, and we combine our high precision targeting with our completions technology to really optimize that balance between a low finding cost and optimizing really the NPV per drilling unit and we think that that's the best way to really deliver shareholder value in the long term through you know increasing our corporate level returns while still capturing the NPV.

Great and my follow up is the updated guide does assume, call it the deceleration in CapEx in 4Q versus 3Q. I was wondering if you could maybe discuss the cadence of overall [indiscernible] in the second half and just your general thoughts on 4Q oil growth and sustaining some of the upper- aiding momentum into 2020.

Yes Arun, yeah we are on plan, everything is going just almost perfectly this year. It’s been a great year in performance and capital is running according to plan, and we are going to be really well set up heading into 2020. And I'm going to ask Billy Helms to give a little bit more detail on that.

Yeah, good morning Arun. This is Billy. So as Bill mentioned, we are exactly on plan where we wanted to be. Actually our well performance is exceeding the type curves that we laid out at the beginning at the year, and our well cost is actually coming in lower. So what's driving that really is just the continued efficiencies each of the operating teams continue to have. So we're actually able to – as we go into our second half of the year, in both the Delaware Basin and the Eagle Ford, our two most active plays, we'll see a slight reduction in rig count and frac crews there, just because we don't need as many rigs and frac fleets to achieve our goals that we originally laid out at the beginning of the year. Now also on top of that we have some seasonal programs like the Bakken where you'll see activity there, mainly it happens in the summer-time and in the winter-time we pretty much slow activity there just because of the additional costs associated with winter operations. You'll see a slight reduction also in the Powder River Basin for the same reason. So in general, we don't really see a dramatic change in the rig count, frac fleet count or the wells turned online, a slight drop in the fourth quarter. The big thing to take away is that for 2020 while it’s really early to give you an indication of what we're going to do, we don't see that we’ll have a dramatic drop off in the first quarter of 2020. We are well positioned and well set out to provide growth on a quarter-to-quarter basis as we enter 2020.

Great. Thanks a lot for that commentary.

And our next question today comes from Brian Singer of Goldman Sachs. Please go ahead.

Thank you, good morning. I wanted to see on the dividend. How does your dividend goal that have shifted in terms of the focus of the 2% target yield, how does that, if at all impact your volume growth target? Do you still see growth in 2020 accelerating versus 2019, and how long can that growth be sustained while meeting your dividend targets until the Eagle Ford and Delaware Basin move into a more mature phase as you call it from the growth phase or until you depend more on the newer plays or organic exploration.

Yeah, Brian, good morning. We don’t see that our projection of being competitive with the S&P 500 on the yield as really slowing down our growth. You know we believe that our dividend, you know we've shown a very strong commitment to the dividend, we've increased it over 70% in the last two years and certainly our goal, with reasonable oil prices like we've seen this year, is to continue to grow the dividend at least 20% per year to bring the yield in line with the S&P500 and of course the Board considers the macro outlook in our business plan every quarter concerning the dividend. And then on growth at reasonable oil prices like we've seen this year, we do not envision our growth to be lower than our 14% that we are experiencing this year. So we have a very, I think robust business as Tim pointed out; we are creating significant value through our disciplined reinvestment and the premium drilling and we're generating strong free cash flow. You know we're having a substantial dividend growth and we've got – strengthening our balance sheet all the same time. So we believe our core business is super strong and competitive, with really any business in any sector of the market. So we’ve got a lot of confidence that we're creating a huge amount of value for shareholders and we're going to continue on that plan.

Great, thank you. And then my follow-up in regards to exploration, I realized that there was not a specific update here. On last call you talked about higher quality reservoirs that could lower decline rates in your supply cost and you referred in your opening comments to potentially lowering the decline rate and reducing the cost to produce oil. Can you just give us a general update on what you are seeing within that portfolio and how aspirational that is versus how far you’ve progressed towards that in terms of reality of really having that confidence that the decline rate can come down and the supply costs can come down?

Brian, we are – yeah, thank you. We are very excited about our exploration efforts this year. It's the most robust, diverse exploration effort I think we've ever had in the company. We are in multiple basins and multiple different plays, testing new ideas and they are rock quality, rock that would be able to deliver oil at lower cost and at lower decline rates than our current inventory, the average of our current inventory. So we are really focused on corporate returns. We want to drive, continue to drive down finding costs and that's a particularly strong focus. So we are looking for plays that have low drilling costs, low operating costs and we're working and we want to improve the decline rate of the company also. So low decline, low finding costs is the direction that we are heading, going in, and that's what will help us continue to generate higher corporate returns going forward. So we're really excited, we are really encourage, we are in the process of drilling and testing a lot of new ideas this year. We are also leasing very, very strong acreage positions, building very strong acreage positions at low costs and we’ll be giving up dates on that as we get meaningful results. It takes a little while, we don't want to just drill one well you know and say we got all this. We need to have multiple tests done. Certainly we want to, before we start talking about specifically where these plays are, we want to have the acreage captured and so it's going to take a little bit of time. So we asked the investors to be patient with us on the process, but we're very excited and very encouraged on where we're headed.

Great, thank you.

And our next question today comes from Neal Dingmann of SunTrust. Please go ahead.

Good morning all. A question I guess to start around the Powder River. It seems like when it comes to incremental operational efficiencies and lower costs, it appears in terms of your conversations and very much on the Powder River is seen maybe the most in your portfolio, and I'm wondering if this is in fact the case. The Powder has seen you know some of the most improvement and then just wondering for overall portfolio can you continue to see, just the remarkable efficiencies that you all talked about in the last couple of quarters.

Yeah, good morning Neal. Yeah, we are super excited about the Powder. It's got a lot of obviously upside, and we're in a learning curve. So we are testing as Billy talked about, different parts of the play, but particularly we are testing the targeting and the completion technology. So the wells will vary a little bit as we go through that process, but we're learning and that we're not really in a hurry. We want to take advantage of a learning curve before we you know increase activity there significantly. We don't have a lot of acreage exploration issues there. So we've got plenty of inventory in all the places of the company. So we can bring that on at the proper speed to maximize the returns and lower costs and build the inventory correctly.

Okay, and then just one separate one if I could. It appears to me your exploration program remains this year a bit more active than we’ve seen in the last year or two. I’m just kind of curious if you all are focused here on ramp in one potential area or are you all looking at several potential plays when we look at the exploration.

I’m going to ask – Neal, I’m going to ask Ezra to comment on that.

Yes Neal, this is Ezra. We have multiple opportunities that we have this year that were both leasing and testing this year. As Bill highlighted a few minutes ago, really the goal of the exploration program this year is to add quality to our inventory and not just quantity. What we mean by that is you know it all starts with the rock quality and so we're looking at – we basically, you know the advantage of having activity in six different basins this year as we drilled these wells, we collect a lot of data and we're able to formulate that data and that's really the basis for what has created our exploration effort this year. I'm looking at this better rock quality. We think that this rock quality we are targeting will really benefit from our horizontal drilling and completions techniques and as Bill said, should provide us an opportunity to add lower finding cost and higher quality of inventories to our already robust portfolio.

Thank you so much guys.

And our next question today comes from Bob Brackett of Bernstein. Please go ahead.

I had a question on the electric frac spreads. You quoted the $200,000 per well savings. Part of that is the fuel arbitrage diesel verses nat-gas and part of it is the cost you’re paying the service provider. Is there a way I can think about how those two offset each other?

Yeah Bob, this is Billy Helms. Yeah the $200,000 savings, I'd say the majority of that is simply in the fuel cost savings and the reason why it benefits us so much is we're using it in place where we have readily available infrastructure to be able to access gas as a fuel source, relative to diesel as a traditional frac fleet not used. They also do provide us a great deal of a step up and efficiency gains to, so our efficiency games there provide I'd say the balance of the savings, but the majority of it is based on the fuel savings alone. So I wouldn’t want to mislead you there, the efficiency gains are really good, but the majority is fuel savings.

Great, thanks. Follow-on would be, if we think about the 740 net planned completion for 2019 and wanting to hit that activity level, how would you balance that against the macro sell-off in the commodity where price fell and cash flow fell. Would you stick to the plan, would you trim the plan in order to hit cash flow? Where does that balance play out?

Yeah Bob, this is Bill. Certainly you know we are going to run the business with the balance cash flow. You know we're not going to outstand cash flow. So you know depending on our view of the length of that, you know downturn and oil process, we thought it was temporary. You know we might not make much adjustments, but we thought it was a super long term. You know we would certainly readjust the company. Our goal you know is not to grow specifically, our goal is returns. We are focused on increasing corporate returns going forward, generating strong free cash flow, certainly we're committed to the dividend very strongly as a company. So those all have a super priority in the company and we're here for the long term, we are going to run our business right, we're going to generate maximum value for our shareholders.

Thank you.

And our next question today comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Thanks, good morning everyone. Bill, I think you’ve kind of set the cat amongst the pigeons by talking about the uncertain outlook for 2020. I think we're all facing the same thing, but I wonder if I could speak to how you would see relative capital allocation in the event that we did have a downturn. It's really – thinking more along the lines of sustaining capital and then beyond that how you a would allocate incremental dollars. If you could just elaborate a little bit as to what I'm trying to get at. The IRRs are very competitive across your entire portfolio, but the productivity is obviously very different in different plays for the same return. So I'm just curious as to how reallocate or allocating capital to your highest return plays would impact the relative productivity outlook in a downturn. I know it’s kind of a complicated issue, but that’s what I’m trying to get at.

Yeah Doug, I appreciate it, your question. Good morning. We have got tremendous flexibility to allocate capital. We have such an enormously strong premium inventory and it’s across multiple plays. So as I answered in the previous question, you know we're not interested in outstanding cash flow, certainly not on a long term basis. We are going to stay super disciplined and make sure that we generate free cash flow every year. So you know if we had – we don't believe we’re going to have an extended downturn or low downturn, but it’s in an extreme case that we did that, you know we would just tighten the belt all across the company. We would focus our capital on the highest return plays and we would allocate capital appropriately to the macro environment. So we're focused on returns and we believe we can generate the highest returns of any company in the E&P business at the lowest oil price scenarios, because we have the highest reinvestment hurdle of any E&P company we know. And so our premium inventory is good to go at $40 oil and that allows EOG to be the low cost provider of oil and gives us a tremendous competitive advantage.

I know it's not an easy question to answer, so I'm going to follow-up with an even worse question, I apologize. You've also – I don't know if the language was deliberate on your dividend comment on the press release, but targeting, setting out a target yield kind of starts to bring in considerations of how the market thinks about valuations, something about dividend discount models, which then begs a couple of obvious questions as one, what do you see is the appropriate growth rate for the dividend? This is supported basically by what you said earlier about not less than 14% oil growth. And then related to that, those implications for the payout ratio, have you – do you have parameters around that, that you could share with us when you've kind of lead out this subject of up 2% yield. Because it’s basically that you know we can all come up with long term projections of what that could look like, but some framework around that would be helpful.

Yes certainly, Doug. Our goal you know is to continue to aggressively increase the dividend, certainly at the 20% right or better every year, and that would be in consideration of you know reasonable oil prices like we've seen this year, we believe we can do that or better. And so our focus is just to have a sustainable strong dividend growth every year and get the dividend up to the yield of the 2% level. We don't have a specific timeline to give you, because we need to manage the business according to our view of the business environment obviously going forward, but directionally you know we want to be competitive with the S&P500 companies and the dividend yield just like we're going to be competitive in growth and in return on capital employed. And I think the dividend yield for the S&P is about 2% and so that's where we want to be long term in the company.

Sorry Bill, just to be clear, the 2%, does that also have an oil price parameter like a you know obviously premier locations or premium inventories at $40 oil. 2% yield is at what commodity price?

Well no, it's not really based on that. You know the speed of which we can get the yield to that level of course would be you know have oil price considerations. But we are lowering the price of the company to be very successful as we said in the opening remarks, where we can do it very well at 50 with oil in the 50’s right now. But we are really heading the company to where we can be successful with oil in the 40’s. So overtime you know we believe we believe we can be competitive on the dividend returns and growth with oil in the 40’s.

Understood. Thanks for taking the question.

And our next question today comes from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.

Good morning. I’ve just been listening to the lower decline stuff of great interest and I just thought I'd ask you if we think of a typical first year, unconventional decline is say 60%, can you roughly quantify how much the decline rates could be modified with these new exploration plays that you've been discussing? I don't mean the corporate decline, I mean of the well decline in one of these new plays.

Yeah Jeffrey, this is Bill. You know, we are really in the early process of testing these plays and so we just need to get some well results behind us to give you specific numbers on that and some history. But these are plays that have better matrix probability than a typical shale play. We are not looking for a rock that has nanodarcy firm. This is really more microdarcy, maybe even millidarcy firm kind of rocks and there are also rocks that would respond really well to the horizontal completion technology. So we even get a complex fracture pattern, where you can drill long laterals, etcetera, and you can contact a lot of this better probability rock to wellbore. And so that combination and just in general will give you a high recovery for the metal oil in place, but it also gives you lower decline rates than the current shale plays.

And that sounds really interesting. We look forward to hearing more about that in the future. I think my other question is I believe last quarter you said that the Eagle Ford EUR program was completed or more or less complete. I just wondered, do you have any other programs going on anywhere else in the portfolios that’s experimenting with or seeking to try to capture more resource, total resource from the wells than what we typically expect in an unconventional resource.

I’m going to ask Ken to comment on that.

Yeah, this is Ken. We have about 150 wells in our enhanced delivery process in the Eagle Ford and we are really are seeing premium results in line with our 30% to 70% ad in our primary recovery. You know we are really watching our program and refining our process as we go, the process that you want to do after your primary drilling is complete. So we're going to evaluate expanding that EUR footprint in that area as we finish primary drilling in the surrounding units. As far as expanding that into other areas, we are constantly evaluating that, but we are not expanding that process into any of the other formations at this time.

Okay, great, thank you.

And our next question today comes from Leo Mariani of KeyBanc. Please go ahead.

Hey guys, very impressive progress on the cost reduction initiatives. I guess basically you're sort of in 80% your targets here, you know by mid-year on the well costs. Just wanted to get a sense – I know it’s probably you know difficult question. Of course no one can kind of predict the future here, but just based on efficiencies, do you guys think that it's realistic that you might be able to knock another say 5% off those costs again in 2020 or 2021.

Good morning Leo. I’m going to ask Billy to comment on that.

Yeah Leo, first of all let me just say, we're extremely proud of the efforts that are operational teams have made to get to the 4% hurdle halfway through the year. When we set our 5% goal out at the start of the year, I think you know we had no idea exactly how quickly they would get there, but confidence that they would and they've excelled just tremendously. You know being able to accomplish another 5% next year, it's a little early to say where that’s going to come from, but I do have confidence that we'll be able to continue to lower costs. I mean there's no doubt in my mind that we can continue to push well cost down. And not just well costs, but also our unit costs, you know we're making tremendous progress there. So I don't want to go without given those guys a kudos as well, because they've done a great job and I guess we just have so much confidence in our teams, that I know we can achieve continued cost reductions across the board.

Okay, that's great. And I guess just, you know wanted to – a quick question on some of the guidance here. So just looking at your third quarter U.S. oil production guidance versus the last few quarters, just noticing that you're kind of rate of growth in U.S. oil slows a little bit in the third quarter. Just wanted to get a sense if there is anything to read into that or is that just kind of timing sort of on well tie-ins here.

Yeah Leo, this is Billy again. Yeah the rate of growth certainly slows a little bit in the third quarter, but really it falls directly in line with what our plan was laid out at the start the year, and as you know most of our activity in capital expenditure was in the first half, so that's where you're going to see most your production growth. So it will modestly decrease; the rate of growth will modestly decreased a little bit the third and fourth, but we're still on pace to really stay within our plan and then we're not concerned at all about how that sets up for the following year. We are still in great shape as we go into the next year as well.

Okay, that's very helpful, and I guess just any you know follow-up thoughts on U.S. exports. Obvious you guys unveiled incremental volumes that should be shipping out you know last quarter and certainly made a point to put it in your slide. As you kind of look at the marketing side over the next couple years, do you guys think that U.S. oil exports are going to become even more important for you, and is that an area you are going to be looking to expand going forward.

Let me let Lance comment on that.

Hey Leo, good morning. This is Lance. How are you?

Great.

Yeah good. Hey, here on the exports it's definitely exciting. You know as we’ve talked about in the past we've got our – you know today we've got our existing Houston capacity, you know we're taking advantage of that, but we get more excited about next year with our capacity growing in corpus. So I think one of the things that really you know to think about us from an EOG standpoint, what really differentiates us is when you think about the Corpus capacity, we're going to have the capability to really show you know our segregated WTL, you know that we are going to be able to show across the docks and we're also going to be able to show our Eagle Ford as well. So I think, you know when you look a lot of peers and you look at a lot of our, you know the competition that’s out there too, our capability with our transportation capacity, the storage tankage that we have, ability to deliver segregations you know into the market, you know we're going to be able to show multiple grades across the market. And yes, absolutely, I think you're seeing you know spread tighten up and I think we don't see any concerns as it relates to export capacity, you know at least in the short term. But I think one of the more important points to make is you know if you call export capacity right at 4.5 million barrels per day of export capacity. What we felt was very important is that we secured existing Brownfield capacity, so that way if you do see price dislocations that do occur maybe at the dock. You know we're advantaged there because we're not waiting in on permitting; we're not waiting on doc expansion. So our capacity is going to ramp-up you know as we move in to next year and I think that's going to be key because you know we can really take advantage of the values if there is a dislocation. And again we've got the flexibility that we can pivot our barrels and we can supply our great customers or domestic refiners. But then we can also supply to international markets as well. So we've got a full range you know in our portfolio there Leo.

Okay, well that's great color. Maybe just on that point, do you think there’s a decent chance there could be dislocations over the next couple years? Just wanted to get a sense how you are thinking about that piece.

Yeah, I'm not going to speculate you know. I think when you've definitely seen you know when you look at the forward curves, you can see kind of the Brent NEH spreads and that's right around $3, so it definitely shows that the export order is opened you know, but I think for us, you’ve seen – we talked about in our opening comments too about the Permian, kind of the Gulf Coast spreads, it’s definitely narrowed. So I think really where you could possibly see the price dislocation is that you got a lot of oil that’s going to show up at Corpus and there's going to be some players that aren’t going to have secure dock capacity, and so there could be a dislocation that occurred there. But as it relates to EOG and what we've done, we went ahead and kind of take that – we took that variable time out of the play. As we think about our growth and then our capacity ramping up and then how we're going to place barrels in the next four months.

And our next question today comes Paul Sankey from Mizuho Securities. Please go ahead.

Good morning all. Just kind of bringing together everything that you talked about this morning, well I was wondering, just in terms of your comp, that’s your position against the oil industry as opposed to the whole market, where do you think you are furthest ahead of the industry and where do you think is the furthest to go and obviously I'm talking about the various components of your business, whether it's the acreage, the exploration, drilling, fracking, operating, transport and even decline rates. Thanks.

Yeah, good morning Paul. You know clearly the competitive advantage that EOG has is our culture. Our culture is just amazing. It really drives all the success of the company. We have tremendous assets because the culture has built out over the years through our exploration efforts. You know we have tremendous cost reduction, continuous sustainable cost reduction, because our culture never is satisfied. It's just continually innovative and it continues to figure out better ways to run our business. So really the confidence that we have about the direction of the company to be able to be very successful, even with oil process in the 40’s is really due to our culture. And of course that's supported by a lot of different things. We have a core competency obviously in exploration; we’ve got a core competency in operations, you know we drilled the wells the fastest in the U.S. and the lowest comps, leading completion technology. We have by far the most advanced information technology systems where we can make real time decisions continuously across the company and the real value of the company is coming from every person in the company, the value of EOG is not top down driven, it's really from every person in the company. So that's our – that's where we have the lead and that is not easily duplicated. It's taken us three decades to build a culture of where it is right now and we believe our culture is improving as we go forward. So we're super excited about where EOG is and where we're heading.

Thanks Bill. If I could make it much more specific, could you just talk a bit more about e-fracking; that seems to be very interesting. Thank you.

Yeah Paul, I’m going to ask Billy to comment on that.

Yeah Paul, as far as e-fracking goes, you know we got into the idea of utilizing the electric frac fleets, mainly because we are attracted by the efficiency gains, as well as the cost reduction. The efficiency gains is what really we view as being sustainable to help lower our cost long term and that has continued to get better with continued use. We've got four of those frac fleets operating today in the Eagle Ford and the Delaware basin and we're always looking for ways to continue to utilize our infrastructure to enable that to be spread into other plays. So I think as you look forward, we will look for opportunities to continue to put those in new plays. It's unique and that the fuel savings are mainly achieved through not only the cost of the gas, but really our ability, the ability of our facility teams to get ahead of the completions and come up with innovative solutions to get the gas readily available to the frac fleets and without that infrastructure and those teams enabling to do that, we wouldn’t be able to take advantage of it to the extent that we are. So just super proud of that effort and where it's taken us.

Yeah, just a quick follow up. Could you talk about the capacity of that and we'll see – I think you mentioned how big you are in the market. Could you just repeat how much of it you'll go in with I think.

Yeah, I think you know what we're hearing and certainly this number might move a little bit, but there's currently about 11 frac fleets available in the market today. We're using about four of those and our frac fleet count varies you know week to week, but typically we’re running about 16 frac fleets, 15 or 16. So that's about a quarter of our frac fleet in the company. End of Q&A:

And ladies and gentlemen, this includes our question-and-answer session. I’d like to turn the conference back over to Mr. Thomas for any final remarks.

In closing, I first want to say thank you to everyone at EOG for their tremendous contribution to our performance in the first half of 2019. We're proud and honored to be on the same team. The company is performing at the highest level in history and we continue to improve every quarter. We’re excited about the second half of the year and the years beyond. We’re focused on returns and creating significant long term value. Well, thanks for listening and thanks for your support.

Thank you, sir. Today’s conference has now concluded and we thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day!