EOG Resources, Inc.

Good day everyone and welcome to EOG Resources first 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.

Thank you. Good morning and thanks for joining us. We hope everyone has seen the press release announcing first 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 and 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 to non-GAAP measures can be found on our website at .eogresources.com. Some of the reserve estimates on this conference call and in the accompanying investor presentation slides may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting 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, Lance Terveen, Senior VP Marketing, Ken Beteker, EVP Exploration and Production, Ezra Yaakob, EVP Exploration and Production, and David Streit, VP Investor in Public Relations. Here's Bill Thomas.

Thanks Tim and good morning everyone. EOG's goal is clear and simple. Be one of the best companies across all sectors in the S&P 500 by realizing double digit returns and double digit organic growth through the commodity cycles. Our stellar first quarter performance demonstrates that we are lowering the cost of oil required to achieve that goal. We are confident in our ability to continue to decouple our performance from the commodity price cycles and that our sustainable business model will consistently deliver excellent results in the future. As a result, the Board of Directors approved a 31% increase to our dividend rate. The annualized dividend is now $1.15 per share and represents the largest single dollar increase in EOG's history. This is a tremendous vote of confidence in EOG's future and demonstrates a strong commitment to capital discipline and returning cash to shareholders through the dividend. Our premium combination of high returns and organic growth is evident in every area of the company. With 2019 shaping up to be one of the best operating performances in company history. Well cost and operating costs are falling and well productivity is strong. EOG is growing oil volumes at lower cost per barrel than ever before. We are excited about 2019 and the outstanding operational and financial results we are delivering. Some of the highlights this quarter include year over year oil growth of 20%, exceeding the high end of our crude oil production target, capital expenditures below the low end of expectations, strong year over year lease operating and transportation per unit cost reductions, additional reductions in completed well cost and we secured significant crude oil export capacity, increasing our ability to receive the best prices. EOG continues to improve unit cost, capital efficiency and profitability. In fact, we made the same amount of net income compared to the first quarter of last year with significantly lower oil prices. A remarkable achievement demonstrating EOG's resiliency to low oil prices and the company's sustainable ability to continuously improve. In addition to great results this year, we are excited about the steps we are taking to improve future results through our organic exploration of new high quality plays. Our exploration focus in 15 years of experience drilling horizontal oil wells has generated mountains of proprietary data that gives us an edge in identifying new plays. We have 13 years of premium level inventory so we are squarely focused on further improving the quality of our inventory rather than just adding more quantity. Adding low cost organic inventory with better rock will enable the company to grow oil at lower cost and higher margins for years to come. At EOG we have an unwavering commitment to creating shareholder value through our long standing business model. Exploration driven organic growth, operational excellence, technical leadership all underpin by a distinctive culture. Our decentralized structure and focus on returns combined with our entrepreneurial please but never satisfied mindset continues to produce outstanding results today and is set to produce sustainable improvements in the future. EOG has never been in better shape and the company has never had a brighter future. Next up is Billy to review our first quarter operational performance and outlook for the of 2019.

Thanks Bill. Before I go into the quarter results I want to be clear on this point. We will not increase capex. We remain confident in our 2019 plan and activity will be adjusted throughout the year to achieve our production and capital objectives. Now onto the first quarter. Our results reflect the tremendous efficiency gains that were beginning to emerge late last year and materialized more fully early this year. We delivered more oil producing 436,000 barrels per day exceeding our forecast. To be more specific the wells completed at the end of last year are outperforming our forecast and that trend has continued into the first quarter of this year. Of equal importance we spent less capital than expected. Our capital was well below our forecast for the quarter as we are realizing the increase in efficiencies across our operations. Unit operating cost performance was also stellar coming in at the low end of our forecast and in the case of lease operating expense we were well below our forecast. It's important to note that our strong operational execution is not related to the reduction in service costs. It's driven by a relentless quest for continuous improvements and our intense focus on developing new technology. All areas of our operations contributed to EOG's first quarter execution and capital efficiency. First, our drilling teams continue to markedly improve their drilling times and performance. More importantly the consistency of the improved performance can be seen across our entire system. This is a result of two factors. One, we made the decision to maintain the high performing drilling teams and services that are now consistently executing our internally engineered drilling program. In each of our major areas of activity we continue to achieve new record drilling times and costs. And two, our drilling teams continue to adopt new technology, processes and specialized tools that improve both drilling performance and repeatability. Ideas are developed in house and deployed by partnering with service providers. For example, eliminating even one trip where the drill bit must be brought back to service can save up to $100,000. To capture those savings we first analyzed then designed the best down hole motor to our bottom hole assembly and took the additional step of bringing quality assurance in house. As a result of having direct control of this equipment we have observed a pronounced reduction in the number of trips while also improving the rate of penetration. Together, reducing the trips and increasing the penetration rate is saving up to $400,000 per well. It's this type of innovation that helps EOG continue to deliver best in class drilling performance across all of our plays. Second, our completion teams are experimenting with new design advancements that combine both technique and the use of new diverting agents. This proprietary formula is noticeably improving well performance and equally important, reducing completion costs. Well performance in these low permeability reservoirs improves due to enhanced fracture complexity. Completion costs are reduced due to lower material costs and faster execution allows us to complete more lateral feed per day. The result is a solid improvement in our capital efficiency. Further testing and production time will yield more fulsome data and place specific recipes for each of our operating areas, but suffice it to say that the early results are encouraging. Finally, investments in strategic water, oil and gas infrastructure along with gathering partnerships allow us to leverage our skill in our core operating areas and are having a long-term sustainable impact on our operating costs, particularly lease operating expenses. We continue to evaluate additional high return, long-term impact opportunities to further reduce costs. In summary, we've had a great start to 2019. Our operational teams are on track to deliver on our improved capital efficiency goals. Average well cost across our portfolio are down about 2.5%, halfway toward our 5% goal for the year. We've made significant progress towards our goal to reduce per barrel finding costs. These improvements will continue to drive down our D&A rate over time and along with unit operating costs improvements enable EOG to achieve our return objective in low commodity price environments. Here at Lance, we provide a marketing update highlighted by our recent progress to secure Gulf Coast

export capacity. Thanks Billy. EOG has established marketing agreements that provide access to crude oil export markets in Corpus Christi and Houston. Our capacity in Corpus Christi will ramp up from 100,000 barrels of oil per day in 2020 to 250,000 barrels of oil per day in 2022. We expect to sell crude oil to export markets from multiple place including the Eagleford and Delaware Basin. As we illustrate on slide 19, EOG will control its crude volumes from the basin all the way across the dock as our agreements provide for pipeline capacity, terminal tankage and dock access. With the options of price are crude oil farther downstream, we expand our flexibility to sell product to domestic or international markets, whichever provides the highest margins. This optionality ensures strong price discovery and liquidity for EOG barrels. Our export marketing agreements are an example of our integrated marketing strategy which is designed to achieve four objectives. First is control. Control means firm capacity of our product to the point where margins are maximized. Second is flexibility. We plan ahead to establish multiple options to deliver product to the highest net back market. Third is diversification. We take a portfolio approach knowing the optimal net back price will move around faster than we can adjust transportation agreements. Fourth is duration. We prefer shorter term contracts to avoid long term high cost fixed commitments. This strategy is reflected in the advantage positioning of our oil takeaway in the Permian Basin. EOG controls its barrels from the wellhead to the sales point. Delaware basin barrels are transported out of the basin on a fit for purpose gathering system to five pipeline interconnect points which can transport the oil anywhere from Cushing, Houston, Corpus Christi, and even Midland. We have accomplished this with limited long term commitments and competitive transportation rates. This strategy paid off in the first quarter. Despite the volatility of oil and natural gas prices in the Permian, EOG was able to all of its production and realize strong prices during the quarter. In aggregate, EOG's realized US oil price was $1.21 above WTI in the first quarter and our US gas price was only $0.36 below Henry Hub. This is a tremendous achievement in navigating a volatile market. Crude oil and natural gas marketing is an integral part of EOG's value creation strategy. We anticipate future infrastructure needs to protect flow assurance and diversify our options so that we can maximize our price realizations net of transportation costs. We accomplished this by working closely with the operating teams in each of our major plays and divisions to understand the potential future development plans and by keeping a pulse on market fundamentals of each product and marketing point. Our proven marketing strategy has helped EOG successfully navigate bottlenecks across all areas of operations including most recently and the Permian Basin. We measure the success of our marketing efforts through our price realizations which we highlight on slide number 20 as well as the transportation costs we incur to deliver our production to market. Next up is Ken to review the Eagleford highlights.

Thanks Lance. The Eagleford remains the workhorse asset for EOG earning high returns and delivering sustainable growth while generating strong cash flow. EOG has been developing the Eagleford for about 10 years, however less than 40% of the identified locations have been drilled. Last year Eagleford production grew 9%. We forecast the Eagleford is capable of growing for at least 10 more years at premium rates of return while generating significant cash flow and excessive capital expenditures each year. More importantly we believe the capital productivity of the Eagleford will continue to improve in the years ahead. Sustainable cost reduction has been a key theme throughout our 10 year history developing the Eagleford. Even in a play that has already accumulated significant operating efficiencies we were able to reduce drilling costs by 7% and increase completed lateral feed per day by over 50% in the first quarter of 2019 compared to 2018. In fact the first quarter of 2019 was our best drilling efficiency quarter that we've ever had in the Eagleford on a dollar per foot basis, highlighting our culture of always getting better. On the production side we are continuing our efforts to further optimize artificial lift and manage water production which will help us control lease operating expenses longer term. Drilling in our western Eagleford acreage continues to deliver strong premium returns, net present value, finding cost and capital efficiency. Our western acreage will be a crucial component of long term growth for the play and we expect it will make up the majority of our Eagleford drilling program by 2021, growing from about 40% of our program in 2019. Capital efficiency in the west has caught up over time and is nearing parity with the east as illustrated on slide 39. Compared to the east laterals in the west are longer and per foot drilling costs are lower, so productivity and economics per well are competitive. Our proprietary enhanced oil recovery process in the Eagleford continues to perform at technical and commercial expectations. EOR is a secondary recovery process in this play and primary development remains the main focus of our operations in 2019. The EOR footprint will be expanded after a larger portion of the play has been fully developed. The best days of the Eagleford are still ahead. We continue to convert non-premium inventory to premium status through sustainable cost reductions, productivity improvements and leasehold consolidation. The Eagleford is a strong growth asset for EOG and we expect it to remain one for many years ahead. Now, here's Ezra to discuss the Delaware basin.

Thanks Ken. In the Delaware basin we continue to improve on the operational momentum we gained last year. Retaining top performing drilling rigs and completion crews toward the end of 2018 had an immediate impact on the first quarter. We drilled and completed 78 gross wells across six different premium targets with just 18 rigs and seven completion crews. Compared to the first quarter of 2018 we drilled and completed 42% more lateral feet, however we used one less rig and one less completion crew. As a result, we've made strong progress towards our full year cost reduction goals. In addition, we reduced drilling days by 29%, transferred 99% of our water by pipe, which reduces traffic and saves $2 per barrel compared to trucking, sourced more than 70% of our water through reuse and reduced total well costs by 5%. Finally, first quarter wells are outperforming our expectations and we beat our production and financial targets for the first quarter, including capital expenditures. The result is a first quarter development program that achieved an all-in finding cost below $10 per barrel of equivalent while earning $9 million of NPV per well and an average 100% direct rate of return. EOG is a vast industry-leading 400,000 net acre position in the core of the Delaware basin. The rock is about one mile thick and geologically complex. Due to our 15 years of experience drilling horizontal oil wells, we have accelerated the learning curve in this basin. As a result, even though the Delaware basin is still early in its evolution and one of our highest growth areas, this asset is already creating significant value through high return drilling, low operating expense, and positive cash flow just three short years since focusing on its development. I'll now turn it over to Tim Griggers to discuss our financials and capital structure. Thanks, Ezra. EOG

had strong financial performance in the first quarter. The company generated discretionary cash flow of $1.9 billion, invested $1.7 billion in capital expenditures before acquisitions, which was below the low end of our guidance, and paid $128 million in dividends. This left $55 million in free cash flow. In addition, we invested $303 million in bolt-on property acquisitions located in new expiration areas. As part of our debt reduction plan, we expect to repay the $900 million bond scheduled to mature on June 1 with cash on hand, which as of March 31st was $1.1 billion. I'm happy to report Moody's recognized EOG's growing financial strength last month, upgrading EOG's credit rating to A3 with a stable outlook. To quote the Moody's press release announcing the upgrade, the company stated, The upgrade of EOG's ratings into the A category recognizes the company's high capital productivity backed by operating excellence and a long life, high quality asset base that will continue to underpin its strong credit profile amid a number of oil price scenarios. The A3 rating is also supported by the company's conservative financial policies. Last but not least, we announced a dividend increase of 31% in yesterday's earnings lease. The indicated annual rate is now $1.15 per share. EOG has added hedges for 150,000 barrels of oil per day at an average price of $62.50. This covers about one-third of our crude oil production over the remainder of 2019. For natural gas, we added hedges for 250,000 MMVTU per day at an average price of $2.90, which is about 20% of our U.S. natural gas production through October. We believe the decision to lock in a portion of our current crude oil and natural gas prices is prudent considering the volatility in prices and the high return on investment of our capital program at these prices. I'll turn it back over to Bill for closing remarks.

Thanks, Tim. I have a few highlights to leave you with. First, we are running under-plan on capital and over-plan on volumes and we're not raising capital. Second, EOG has tremendous momentum across all facets of the business, drilling, completions, operating expenses, marketing, and exploration. Third, we're still getting better. Along with continuous cost reduction and strong oil performance, we're optimistic our low cost organic exploration efforts this year will increase the quality of our inventory even further and lower the cost of future oil production. Fourth, our export marketing agreements provide direct access to international markets and expand our ability to capture the best prices. Fifth, the dividend increase shows our confidence in our sustainable business model to deliver performance through the commodity price cycles. And finally, our sustainable business model is driven by our culture. We have an insatiable drive to continue to get better. We're confident EOG can deliver double-digit returns and double-digit growth and achieve our goal of being one of the best performing companies in the S&P 500 through commodity price cycles long into the future. Thanks for listening and now we'll go to Q&A.

Thank you, sir. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by digit one on your touchtone phone. If you are 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 touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. We will pause for a moment to give everyone an opportunity to signal for questions. And your first questions will come from Nail Dingman of SunTrust Robinson Humphrey. Please go ahead.

Good morning, gentlemen. Strong quarter. Congrats. My first question may be built for you. Could you all speak to your plans of you've done a great job of balancing growth with shareholder return? And, you know, really when you look at that, you've almost doubled now your dividend the last year while production is growing about 30% here over the last year or so. All while oil is up, you know, only about 15%. Something my question would be specifically if oil stays here or goes higher, would you stick with the 12 to 16% oil growth plans? And if so, what would you do with the potential of material amount of free cash flow?

Yeah, thank you, Neil. Well, first of all, I think it's really clear. We said that on our first call of the year that we're not going to be shifting into a lower growth mode. And we don't have specifics on, you know, 2020 oil growth. But certainly you can think of the company and our 14% oil growth target this year is really a bit on the low end. And so we're really focused on, you know, high return oil growth. And that's the way we believe we'll create the most value for our shareholders on the long term. You heard, I think, from Ezra, the tremendous rates of return and the NPV we're creating on each well we're drilling. So that's the priority for us in the future. And that's the way we think we're going to continue to generate the most value in the long term.

Very good. And then maybe my second question would be for Billy or Ezra. Could you just discuss particularly in the PERM your PDP decline expectations? I mean, in the prepared remarks, I think you all commented just how much better these new wells are than a year ago. So I'm just wondering, is that true as far as how these wells are holding up or just anything you could discuss towards, you know, how you're seeing these wells after a number of months?

Yeah, Neil, this is Billy. I think in general across all of our plays, you see that as we drill longer laterals, that doesn't necessarily translate to directionally higher IP 30s per well. But we see the performance hang in there longer. You see a little bit lower decline over time. And I think that's really, if you look at the first quarter results, that's what's driving a lot of our performance, sustained improvement in all of our programs. And it's a function of just the quality of the wells, the better execution across the wells and the focus of the teams. Ezra, do you want to add anything or?

I'd just highlight too that the teams done a great job in the PERM in the last year, really learning a lot about the reservoir, figuring out across our acreage position which targets need to be co-developed together, the spacing both horizontally and vertically. And when you combine that increase in well productivity with our excellent operational execution, that's why you're seeing the lower finding costs that I discussed in the opening remarks and the higher capital efficiency which we have great success is going to continue throughout the year. Thanks for all the detail guys.

The next question will be from Doug Leggett of Bank of America, Merrill Lynch. Please go ahead.

Thanks, Doug. Good morning everybody. Guys, I wonder if I could touch on the acquisition capital and obviously you're not going to be smiling I guess, but some ideas to what we can expect that case to look like going forward. Was one first quarter very much a one-over should we expect some kind of sustainable level of acquisition spending as we go forward?

Doug, your question, because it's difficult to hear you, was a little bit garbled. So could you be a little bit more clear there?

Oh, I apologize. I'm on my cell phone. Can you hear me okay now,

Doug? Yeah, yes, go ahead.

So my question was on the level of acquisition capital going forward, was first quarter very much a one-off or should we expect acquisition capital to be something of a repeating pattern as we go forward for a period of time?

Okay, thank you. That was better. Yeah, as you know, the company, we're not really focused on corporate M&As, but we do occasionally look at both on-top acquisitions and they're focused primarily in our exploration place. And these acquisitions are very low cost and very, very high potential obviously around the world. We wouldn't be interested in doing them. And they're kind of one-offs. And so it's not something you're going to see repeatedly over every quarter. And so I'm not saying we're not going to do another one this year or not. We don't have any plans at this point to do any more. But they're really opportunistic drilling, opportunistic given, and certainly are focused on very, very high return, low cost drilling potential.

I appreciate the answer. Hopefully you can still hear me. My follow-up is just a quick one. I'm always very really pleased to see the dividend increase. I'm sure a lot of people would applaud that. But I'm curious, what do you think the right payout ratio is for an E&P company? In other words, as you get to where your longer-term plans go, what do you think that right percentage of your operating cash flow should be being returned to shareholders? And I'll leave it there.

Thanks. Well, certainly I think that's operator or company dependent. I don't think there's any one run answer for any company. You know, for EOG specifically, we're generating super high fantastic returns on every dollar we spend. And so we believe our allocation, you know, on reinvesting in very, very high-rate premium drilling is the number one priority. You know, we also strongly believe, as we've demonstrated this quarter, in strong sustainable dividend growth. And we think that's the best way to give cash back to shareholders. And then we're also very focused on having a pristine balance sheet. And we think that's just a fundamental good business practice. And then it gives us an enormous advantage, especially for counter-cyclic opportunities in the future. So that's kind of our allocation. And I think that's very unique to EOG's business model. And I think it's very sustainable for us. Thanks a lot, guys. Appreciate the

answers.

The next question will be from Charles Need of Johnson Rice. Please go ahead.

Good morning, Bill, to you and your team there. I have a question about your cap extra treasury over the year. If you look at the way you guys have posted one queue and your guidance for two queue, you have a first half as heavier than the back half. And we saw that same pattern in 2018. So my question is, is that a feature or a manifestation of your planning process, or is that more just a coincidence with the way that 2019, 2018 is shaking out?

Yeah, Charles, this is Billy Helms. So yeah, our first quarter of capex was about 27% of our total annual budget. And in the first half, you look at our guidance, we'll be slightly more weighted towards the first half than we are the second half. And we have confidence that we'll be able to meet our capital and production goals for the year. So I expect as we go through the year, you'll see us adjust our schedule, probably a slight reduction in the second half. But also it's not just related to the cadence of rigs. We also have infrastructure span and leasehold span that happens in a quarter. So I think we're very confident. What I would say is we're very confident we'll be able to make our production goals and stay within our capex that we've outlined. And it's really kind of early to provide the guidance for how we'll ratio that down through the year. We have a lot of flexibility operating in multiple basins, so it will fluctuate as we go through the year. Got

it. Okay, thank you for that. And then one, I guess, kind of more targeted question on the Delaware basin position, I noticed that your bone springs laterals are significantly shorter. I think it's 5,500 lateral feet versus really 75 or 7,800 on other zones in that same basin. Can you elaborate a little bit on what may be going on there? Is it about the lease configuration, where you're developing those bone springs, or was it more a decision about the way you need to stimulate that formation?

Yes, Charles, this is Ezra. That's a great question. Really, you picked up on it there in the latter half of your question. It really just comes down to lease configuration, what shape of our drilling units are. I think in general, as you've seen, as we look back at our well results quarter over quarter, we're trending to get longer with our laterals across all of our plays. And the reason for that is that simply the cost per foot is so much less that it really increases the capital efficiency. And so I'd look in the future to see that bone spring getting longer as well. Got to think for that color.

The next question will be from Tim Resven of Oppenheimer. Please go ahead.

Hi, good morning all. EagleFord inventory depth remains a focus for investors, and I noted pretty interesting comments in the release about high grading the residual 4900 non-premium locations. Is this just a matter of sort of cheaper well costs, longer laterals, and the new completions, or is there really more to it from a delineation or exploration point of view? And kind of how high is getting that number up? How high is that on your priority list this year?

Yes, Tim, this is Ken. As far as converting those non-premium locations to premium, we look at that several ways. We look at that with trying to reduce the well cost and improve the productivity of the wells. So we're always looking at being able to do that and looking at all the different areas. We're actually doing several different packages and tests to improve our conversion of non-premium to premium throughout the year and throughout our acreage positions. So we have a significant number of those laterals to drill this year, and we have a significant number to convert in the future. We're also drilling a lot longer laterals as we go towards the west, and that will help convert some of those non-premium wells to premium.

Okay, so you expect to see that number maybe grind higher throughout the year?

That's what we're working towards.

Okay, thank you. Then my follow-up, your proxy came out in March, and it stated that less than 90% of wells drilled in 2018 qualified as premium. I was hoping to better understand what that means. Does that mean that well-level returns didn't hit thresholds, or does it mean that there was more exploratory drilling in that year? And just thinking about maybe how we should think about that in 2019 given the exploratory focus. Thanks.

Yeah, Tim, it means that a few of the wells that we drilled, and there's very few in the total package of wells we drilled last year, were either step-out wells or exploration wells in areas where we maybe didn't have the infrastructure in place or were on the learning curve in some of the spacing tests, didn't quite make the 30% after-tax rate return at $40 flat. It doesn't mean those wells weren't really strong economics. Those wells are fantastic economics, probably better than the, or probably our non-premium wells are better than the average for the whole industry on returns. But it was just a very few of those, and that's what that meant.

Okay, thanks. And just to push it, do you have a number on that? Is that 11% or is it kind of a higher number?

I'm sorry, off the top of my head, it don't have the number. Okay, all right, thank you.

The next question will be from Paul Griegel of Macquarie. Please go ahead.

Hi, good morning. In the release, you discussed testing additional targets in the Woodford. Could you elaborate on what you'd be seeing there and what timeframe we could see results from that portion of the program?

Yeah, this is Ken. We're continuing to test other areas in the Woodford. As we get additional information on that and anything material we'll release to you guys, I would like to make the point that we've really made great strides in the operational efficiency in that, in the Woodford play this year. We've almost dropped our growing costs down and met our target for the year. So we do still plan to complete about 30 wells in the area this year, and we're real pleased with the progress that we've made.

Okay, and then earlier in the call, there was a comment made as the Eagleford program matures and there's more development opportunities, the expansion of the EO-R program will occur. Could you elaborate on, is that by area, is that geological testing, is that simply you just need to make sure that the wells have matured and have hit a certain level to try to understand when the EO-R program could see expansion throughout the Eagleford?

Yeah, this is Ken again. We'll expand the EO-R as we really finish up with our primary development in those areas. We'll expand that into areas that make sense based on some of the results that we've seen already with the EO-R program, so it's really a matter of finishing up primary development in a lot of those areas.

Is that a certain number of years after initial development or just trying to understand when primary development is considered finished?

I guess I would classify primary development as finished when we quit growing wells in those areas and we can begin the EO-R process. Okay, thank you very much.

The next question will be from Leo Mariani of KeyBank. Please go ahead.

Hey guys, just wanted to follow up a little bit on the dividend increase here. Obviously, as you pointed out, very material increase for EOG. I wanted to get a sense as to whether or not you guys might be seeking a yield that's a little closer to kind of the 2% that the S&P 500 has out there. And then additionally, just with respect to the dividend, is there some kind of price level, for example, on the oil side you guys may stress test that too or for example you say, hey, at $45 we need to be confident that we can manage that and still target our production growth. Just any call you had around that would be helpful.

Leo, yeah, this is Bill. Yeah, certainly, you know, the dividend increase is evaluated every quarter. Obviously, the macro view of oil prices and our ability to sustain the dividend is a very important thing. We've never cut the dividend ever in the history of EOG and we don't ever want to do that. So when we make a commitment on the dividend, we make a commitment. And our commitment, you know, the last two years has been, as we stated, we wanted to increase the dividend faster than our 19% historical average. So the last two years we've increased it 31%. And so our focus on the future is to continue to do that. We don't give a specific number, but certainly we want to have very strong dividend growth for a long number of years and that's a commitment that we're making to our shareholders.

Okay, that's a good caller. And I just wanted to jump over to the exploration front. I guess clearly you guys made a couple little bolts on acquisitions in the first quarter in the hopes of bolstering that effort, but I certainly sensed a fair bit of excitement around the exploration effort this year from your comments. I'm supposing that you're not going to be ready to share results, but just based on sort of what you're seeing out there, can you qualitatively indicate whether or not you think some of this is working and might we get some announcements here in 2019 from EOG on that front?

Yes, Leo. This is Ezra. Thanks for the question. As we discussed earlier in the year in the opening comments, like you suggested, we're pretty excited about the exploration opportunities. We're really focused on applying our drilling and completion techniques to higher quality unconventional reservoirs. And what really drives our process is having a multi-base and data set that allows us to compare and contrast different reservoir characteristics of each of the sweet spots in the established plays that we're in. And we apply that to new ideas and areas. As Bill highlighted, we're not just interested in adding quantity, but really increase in the quality of our premium inventory. And that really should continue to reduce our finding costs, lower our DDNA, and help achieve our long-term goals of double-digit growth and returns. And when we have a little more insight and color, something a little more material, we'll certainly update you guys.

Okay, that's helpful. And I guess I couldn't help notice the marketing sort of arrangements or the export capacity of you folks signed up here. I just wanted to get a sense. Has EOG already been exporting oil barrels internationally at this point? And it certainly seems as though there's a potential big increase coming over the next couple years. I just wanted to get a sense of whether or not you've already got some relationships with international buyers out there that you're hoping to expand.

Yeah, Leo, good morning. This is Lance. Thanks for the question. Yeah, when you think about the existing business, I mean, we've been very active in Houston for quite some time. I mean, Houston's really kind of been our wheelhouse, especially since 2012 with a lot of our pipeline capacity that comes into the Houston market. But since the export ban has been lifted, we've been actively engaged there. We've got a tank position that's there as well. So we've been making spot sales for quite some time, especially looking in the last year too. So we've been active on that front. I'd say we're very excited too about our new capacity that's going to be starting up moving into next year. You know, really when you think about it and you look at the balances, you know, in the U.S., you look at supply growth, you look at imports, you know, exports are going to be here today. And, you know, we really want to have, you know, a very large position there and having that control at the dock, we feel that's just going to give us a lot of price discovery. But again, it's about a portfolio approach. I mean, we want to protect those realizations. And so, you know, moving into next year and you look, you know, we feel we're going to be very well positioned with our – it's unique that we're going to have our Permian and also our EagleFord that we're going to be able to show across the docks. We feel we're very unique relative to, you know, when you look at the producer group on the different qualities that we're going to be able to show, you know, to the domestic market but then also our international customers too.

Thanks for the call.

Yeah.

The next question will be from Jeffery Campbell of Ture Brothers Investment Research. Please go ahead.

Good morning. I just wanted to touch base again on the various technological efforts, data analysis, all the stuff you're doing. You called it up again and it sounded like it was perhaps getting even more and more into the daily field operations. So I was wondering if you could just give us a little bit of color on that. Thank you.

Yeah. Yeah, Jeffery, this is Billy Helms. I can add a little bit of color to that. I think, you know, part of that goes down to our very culture of the company. We're always striving to get better at what we do and the way we do that is we look at all the details and we gather lots and lots of data and we've had these systems in place for some time. And then the key part of that is delivering that data back to our team so they can exercise good decisions on how to improve our operations and the way we just do our business in all aspects. And you're seeing that manifest itself in the drilling highlights that we offer today as well as the completion highlights and improvements that we're seeing. So on the drilling side, you know, we're monitoring the daily rate of penetration on all of our drilling rigs and making sure our drilling times are not just keeping up with what we're doing, but how do we continue to get better? And so the results we're seeing today are a direct reflection on our ability to gather the data and transport that back and analyze it and deliver it to the field and have the guys making the decisions. So it is part of our culture, real-time, returns-focused decision making.

So, for example, the thing that you talked about earlier today where you're coming up with new completion methods that are using diverters more effectively and you're cutting costs accordingly, these kind of efforts are emanating from all this data analysis that you just talked about.

Absolutely, and we're using, more importantly, we're using that data real-time. So we're actually making decisions based on the pressure rates, pressures and rates we're seeing on the wells we're not only tracking, but the offset wells to make decisions about how to implement our formula. And so that's why the formula is not a cookie cutter formula. It's a formula that you can apply everywhere. It's tailored, it's specifically designed by each well, by each zone, depending on the target zone and the offsets. It takes an integral approach to be able to analyze that data real-time and make the right decisions.

And if I could just ask a quick follow-up to that. When we're thinking about it, is this part of the 5% goal to get costs down or is that 5% goal more based on logistics and contracting and that sort of thing?

No, that's a good question, Tim. I would add to that that really none of the cost savings we're seeing to date are a factor of service cost reductions. It is strictly improving efficiencies, lowering our costs by doing things better, as well as making better wells. So we're seeing the double effect of reducing costs, improving well performance, and it's all directly related to our ability to collect the data and analyze it real-time.

Okay, great. Thanks. I appreciate that color.

The next question will be from Janine Way of Barclays. Please go ahead.

Hi. Good morning, everyone.

Good

morning.

Hi. My question is on SAND. A SAND provider recently commented that some EMPs are switching back to Northern White from local SAND due to cross-chain reasons, which I guess there could be production and cost implications for EMPs. And I know EOG does a lot of its own testing, and I believe you are an early mover in this area, so you probably have more data than anyone on this. Can you discuss your thoughts on kind of this recent commentary and how much exposure you have to local SAND? Any basin-specific color you have would be really helpful,

too. Yeah, Jenny, this is Bill. Certainly, we've got a tremendous – we've got 20 years of history in horizontal shale plays, and we've used every kind of SAND profit material that's been available over the years. Currently, you know, we're focused on using local SAND. Certainly, in the Permian, that's a big cost saver for us, and certainly the industry, too. So we're going to continue to do that. And we're also, I think, shifting to local SAND in the other plays, such as the Eagleford in many of the rocky plays and in Oklahoma, too. So that's the direction that we're focused in, and along with the diversion material, we're making significantly better wells and lower-cost wells. We do have our own testing facilities. We've been engaged in capturing SAND in multiple sources, and we screen it and test it. And we're very confident that the SAND we use in every play – it's kind of tailor-picked for each play, but we're very confident that the compressive strength and the quality of SAND that we use in each play is the right mix for long-term well performance.

Okay. And I think the commentary was kind of triangulating around, I think, maybe the Eagleford and the MidCon outside of the Permian. And so you do use local SAND in those areas as well, and you're satisfied.

Yes. Yeah, we're satisfied.

Okay. Great. Thank you for taking my question.

You're welcome.

The next question will be from Brian Singer of Goldman Sachs. Please go ahead.

Thank you. Good morning. Hi, Brian. One of the debates out there is whether – it's for EOG but also for industry – is whether the best of the inventory in trail is drilled from either a productivity perspective or a rate of return perspective. And I think for EOG, you're more specifically pushing back on this point with the comparison of the Eagleford East versus West area. I was wondering if you could touch on two other areas. The first is the Permian and your outlook for the ability of efficiency and productivity gains from here to overcome movement from core to less core over time. And the second is exploration. I think there was a comment earlier that you expect your exploration efforts will lower the cost of future oil production. What has given you confidence that that is the case if it is truly exploratory?

Yes. Brian, thank you for the question. This is Ezra. Let me start with the back half of that question first on the exploration side. And what we're excited about on our exploration opportunities is we feel like we've identified multiple opportunities where we have an opportunity to apply some of the data and the techniques that we've been learning on the Eagleford, the Woodford, the Permian and the Powder. We can take some of these techniques and apply them to basically a higher quality reservoir that still should be considered unconventional by nature. And we think that the well productivity should be on par with some of our best wells with shallower decline basically due to the reservoir quality. The other important thing obviously is, as you touched on, is being a first mover in these basins and being able to capture the sweet spots of each of these plays. If I transition now and sorry I did this in reverse order, but if I go to the Permian for example, I think the way to think about the Permian and one reason we spent the time highlighting the progress that we've made in the Eagleford is that every year one of the benefits of working in multiple basins is that you get to combine data sets from multiple basins and those learnings, as you roll them in and integrate them into the front end of both your geologic models, your drilling and your completions techniques, that's what allows us to improve some of what today might be considered a non-core area and really improve those well productivity results and continue to drive down our cost to increase the returns of those areas. So the best example I would say for the Permian is really looking back at that Eagleford example and how we've taken our Western Eagleford results today and really improved them to a point where they're above and beyond what we were doing in the Eastern Eagleford just a few years ago.

Great, thank you. And then my follow up is with regards to the Powder River Basin. You highlighted that you've made some progress on the infrastructure front. Can you add some more color there, particularly in how big you're sizing that infrastructure and how significant you think production could be, especially given the competitive profitability you've highlighted at least as it relates to the Niobrara and Mowry zones on your slide 41. If the Turner wasn't there, maybe that would be another point to touch on on that.

Yeah, Brian, this is Billy Helms. Yeah, the first quarter we really tested more Turner and Parkman zones particularly and as we build out infrastructure for the bigger development. I think our infrastructure build will be built out in segments to keep pace with our plans for drilling in that year's program. We're not going to get out ahead and build an infrastructure that's made for a longer term drilling program just because of the capital efficiency of that EROADS. So the size though, the scale of the infrastructure will be able to handle certainly the plan that we have in place for those areas. So it'll be adequately sized, but it'll be scheduled in a pace that keeps up with the current drilling plans for that area. So we got off to a slow start really in the powder really due to weather. We plan to ramp up activities as we go through the year and we're still very excited about the initial results we're seeing from the Mowry and Niobrara test. And as we get more data on those, certainly we'll provide more color there. But we're still excited about the powder opportunities we see in front of us.

Great. Thank you.

The next question will be from Ryan Todd of Simmons Energy. Please go ahead.

Thanks. Maybe a couple of follow-ups on some other things. I appreciate the clarity you gave on the Eagleford. If we look at the improvements that you've seen out to the west, as we look at the type curve that you carry on the Eagleford, it's got a ,300-foot lateral length with a certain level of productivity there. The lateral length feels like it's clearly trending higher. Is it safe to say that as the lateral length increases and as the west has improved, is that type curve probably conservative relative to what we should expect to see going forward?

Yeah, Ryan, this is Ken again. We are really pleased with the way the wells have been reacting out there and our well productivity is meeting the expectations. We do see the performance variations across the -mile-long acreage position. As we extend the laterals in the west, we'll be seeing well productivity increase, well rates, and capital efficiency increase out there, as well as reducing finding costs.

Great. Thanks. Then maybe a follow-up on some of the acquisition activity and the exploration versus your core basins. You've obviously been spending money picking up acreage in some of your exploratory basins that you're very excited about. Do you still see opportunities to add positions in your core areas of operations, or is the valuation outside of those basins just far more compelling at this point?

Ryan, this is Bill. Certainly we have a very decentralized exploration effort. All seven of our domestic divisions have very strong exploration staff, so we're working literally every basin in the US. It's probably not a well being drilled. We don't know something about. We're leasing in multiple plays this year at very low cost. We believe the prospects that we're leasing on have premium economic potential due to the rock quality, as Ezra talked about. Some of them are in basins that have had a lot of historical production. Some of them are in places where there's not really much historical production at all. But they're all very high quality. The size of the prospects we're working on, we used an example a couple of years ago. We talked about the Woodford Oil play we introduced. That's about 200 million barrels of net DOG. That's kind of on the small side, so we're not looking for things smaller than that. But 200 million barrels net to a company, a discovery of that type anywhere in the world is very significant. Last year we announced two new plays in the Powder River Basin that totaled 1.9 billion barrels. That's a very large one. That's a good way to put the brackets on the size of them. The good thing is, as Ezra talked about, we believe we can continue to organically generate significant prospect potential in the future and add it at very, very low cost, much, much lower cost than doing M&As. When we do these bolt-on acquisitions, there are large amounts of acreage for very, very low cost and very, very high potential in our mind. We've been generating premium inventory twice as fast as we've been drilling it. The quality of our inventory is going up at the same time. Some of the previous questions are based on, is EOG's inventory quality declining? I can tell you, we can tell you with absolute confidence that we believe our inventory quality will continue to improve. The quality is going up and we're not having any problem replacing it much faster than we're drilling it.

The next question will be from Arun Jaram of JPMorgan. Please go ahead.

Good morning, Bill. I wanted to see if you could elaborate on your comments on 2020. I know you don't have an official growth target for 2020, but your comments this morning seem to indicate your confidence that the company could grow its oil production greater than 14%. I just wondered, maybe qualitatively, what would drive you to have that level of confidence, because it would be off of a larger base of production this year?

Yes, Arun. We have that confidence because, I think, of the culture of the company and the structure of the company and our ability to continue to add new plays to the system. We have a chart in our IR deck. I believe it's on page 11 that shows EOG's existing plays and their maturity phase. Most of the things that we're drilling right now still have a lot of growth opportunity. We're adding additional premium locations in each one of those plays, so that's a big source of new potential. Then we're working on all these emerging plays. As they come into the development mode, that will keep shifting more and more activity and inventory into the growth mode of the company. The growth mode for each one of these plays are not a few years. They're multi-years, 10 plus 15 years growth mode for each one of these plays. Then the structure of our company, because it's decentralized, we can execute on a large number of multiple plays at the same time with a lot of discipline. We have very expert, strong staff in seven different operating divisions. We can truly execute in multiple basins and continue to reduce costs, improve technology, be very entrepreneurial, and act quickly and make really quick, crisp, good, high rate of return decisions on each one of the plays at the same time. The company has got a tremendous ability to continue our high return growth profile for a very, very long time. I think that's quite unique in the industry.

That's great. Just one question in terms of the agreements that you have in place to expand your export capacity from 100,000 barrels to 250, for those barrels that you are able to, with that capacity, how should we think about the uplift relative to WTI from those types of barrels? One of your peers has highlighted maybe the ability to get 60% of the Brent TI spread less, called $3 in transportation. I was wondering if there's maybe a formula or any way we could think about the uplift that you get on those barrels.

No, Arun, thanks for the question. We won't go into the detail on what we may or may not speculate on what we think the uplift. The most important thing is it's a portfolio approach to us. When we have the diversification, we're going to have the capability there to sell domestically. If that's a higher realized net back for us, then we can sell domestically. As you think about our export capacity, it's a capacity that we can optimize. Again, if you look back over time and you look at our experience, our goal is to maintain our price realizations and being purely in price realizations. We feel that dock capacity that we have there just positions us that we have agreements in place that we can transact very quickly and we can make sales in the stock business and we can keep it on the international index, like a Brent industry, or we can keep it at the local markets. We can take advantage of where the pricing leads us and we can move very quickly. That's the way you probably need to think about that from our standpoint. It's just we can move quickly. We have the capacity and we can also we can meet that capacity with the Permian and also the Delaware. I think that's also very unique. Thank you so much. Bye bye.

Ladies and gentlemen, this will conclude our question and answer session. I would like to hand the conference back over to Mr. Thomas for his closing remarks.

In closing, we first want to say thank you to the tremendous work by everyone at EOG. The company is starting 2019 with our best operational performance in company history. Costs are coming down, allowing us to deliver more oil for less money than ever before. The best part of EOG's culture is that we're not through getting better. We're excited about where we are, but we're even more excited about our future. Thanks for listening and thanks for your support.

Thank you, sir. Ladies and gentlemen, the conference has concluded. Thank you for attending today's presentation. At this time, you may disconnect your lines.