Good day, everyone, and welcome to EOG Resources Fourth Quarter and Full-Year 2018 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you, and good morning. Thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full-year 2018 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 GAAP measures can be found on our website at www.eogresources.com. Some of the reserve estimates on this conference call 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; Ken Boedeker, EVP, Exploration and Production; Ezra Yacob, EVP Exploration and Production; and David Streit, VP, Investor and Public Relations. Here’s Bill Thomas.

Thanks, Tim, and good morning everyone. Our long-term game plan is simple, be one of the best performing companies across all sectors in the S&P 500. Our goal is to deliver double-digit returns and double-digit growth throughout commodity price cycles. In addition to high returns and disciplined organic growth, our goal is to generate free cash flow that supports a growing dividend and impeccable balance sheet and allows the company to take advantage of other opportunities, such as bolt-on property additions that meet our strict premium reinvestment standard or potential opportunities to repurchase shares when value accretive. In 2018, EOG accomplished our goal by delivering 15% return on capital employed, organically growing oil production 19% and generating $1.7 billion in free cash flow. Our 2018 performance places EOG among the very best, in line with top performers in any sector of the market. Last year, we earned a company record adjusted net income of $3.2 billion. Our 2018 15% return on capital employed at $65 oil surpassed our 2014 return on capital employed when oil prices averaged significantly higher at $95. It’s clear, our permanent shift to premium strategy three years ago has had a dramatic effect on the profitability of the company. EOG’s premium standard requires investments to earn at least 30% direct after-tax rate of return at $40 oil and $2.50 natural gas. Consistently applying this standard to our capital allocation decisions has reset the company to be successful throughout commodity price cycles. In addition to double-digit returns and growth in 2018, we also generated a company record of $1.7 billion in free cash flow, increased the dividend rate 31% and reduced our net debt to capitalization ratio from 25% to 19%, delivering high-return organic growth producing free cash flow, returning cash to shareholders by increasing the dividend…

Thanks, Bill. Our high-return production growth in 2018 is a result of investing in our diverse inventory of premium drilling across 11 plays in six different basins. EOG’s 2018 performance illustrates the perseverance of our operating teams to continually get better by improving both well productivity and reducing cost, the two key components that drive sustainable improvements in capital efficiency. In the fourth quarter of 2018, we made the decision to maintain activity and retain top-performing service providers in order to accomplish these two specific goals. As a result, and in the face of increasing oil prices and service cost inflation throughout most of 2018, EOG achieved a 3% reduction in the average well cost by the fourth quarter. To be clear, the cost improvements are not from decreases in service cost, instead the lower cost are due to more efficient operations from faster drilling speeds, increased completion stages per day, reduced sand cost, water recycling and infrastructure projects. In addition, you can see the improvements in well productivity across our plays, with the fourth quarter well results provided in the presentation slides. Our 2019 program is built upon these already proven results of the existing domestic program. Furthermore, our operating teams continue to deliver results consistent with the well cost and productivity achieved last year. As a result, the momentum carried from 2018 gives us confidence that we can achieve the 2019 plan objectives. In addition, by retaining these services, we have secured about 65% of our anticipated services and materials requirements for 2019. We negotiated terms at both lock in services cost and maintain flexibility to adjust our activity level depending on market conditions. However, it is important to note that we will not increase capital should oil prices increase. We forecast our 2019 $6.3 billion capital program…

Thanks, Billy. Our decentralized structure allows our asset teams to identify high-quality unconventional reservoirs and capture acreage as the first mover with low-entry costs. Our ability to capture the sweet spots of these plays is the most significant reason we consistently drill top tier performing wells. Currently, we are leveraging proprietary knowledge from numerous plays across our portfolio and have identified multiple opportunities. We’re focused on applying our technical knowledge of horizontal drilling and completions to higher-quality unconventional reservoirs, and we’ll be leasing acreage and drilling our initial test wells in 2019. Our goal is to increase the quality of our inventory with new plays that can deliver higher production at lower costs, providing a vehicle for continued improvement of our finding costs, DD&A rate and ultimately ROCE. By focusing more resources to these new innovative play concepts, we’re taking advantage of market conditions to opportunistically add low-cost, high-return inventory to our portfolio. I’ll now discuss our Delaware Basin results, where we produced more than 220,000 barrels of oil equivalent per day in 2018, making it our fastest growing asset for the third year in a row. Oil production grew nearly 50%, averaging 127,000 barrels of oil per day, with more than 260 net wells going to sales. In addition, we more than replaced those wells, identifying 375 net new premium locations last year. We also made significant progress blocking up our acreage through trade adding 600,000 feet of premium treated lateral, which is the equivalent of about 85 well locations. Last year, we focused our attention on developing larger packages, drilling longer laterals and increasing our operational efficiency across our 400,000-plus net acre position in the Delaware Basin. The results of this effort includes a 31% increase in completed lateral feet per day, a 9% decrease in completions cost…

Thanks, Ezra. 2019 marks our 10th-year developing the Eagle Ford. This workhorse asset remains EOG’s premier oil play, delivering a consistent performance year-after-year. The Eagle Ford grew oil production by 9% last year to 171,000 barrels of oil per day, representing 43% of EOG’s total crude oil production. Even after 10 years, we continue to learn and improve well productivity, find efficiencies and lower costs. We extended laterals another 7% from 2017, primarily on our western acreage, where there is less faulting. In fact, we drilled a record 65 wells, with laterals over 10,000 feet in 2018. We continue to push the limits of lateral length, setting a record with our Slytherin C#3H at 13,500 feet of treated lateral length. Wells in our western acreage produce lower IPs, but have slightly lower decline rates and are more cost-efficient. In 2018, we updated our premium inventory for the Eagle Ford, adding 145 net locations through infills, acreage bolt-ons and longer laterals. We’re confident we can continue to drive sustainable cost efficiencies in our effort to convert the remaining inventory of our total 7,200 net locations to premium status. In 2018, we also continue to see very positive results in our secondary recovery efforts in the Eagle Ford. Results to date are in line with our early expectations for this enhanced oil recovery process and we have approximately 150 wells in various stages of injection and production. We’re continuing to refine our technique and expect this project to grow in the future. We have found that this process works best, when infill development has been completed throughout the area. So we’re focusing our efforts in 2019 towards finishing primary development of nearby units before expanding our secondary recovery footprint. In 2019, we plan to complete 300 net wells in the Eagle Ford…

Thanks, Ken. The Bakken remains an important asset in EOG’s diverse portfolio of plays, providing flexibility for reinvestment at our premium return hurdle rate. Over the last several years, we’ve made significant progress in the Williston Basin on precision targeting, the drilling and completion efficiencies. Between better well production and tremendous cost improvements, our Bakken program delivered over 70% direct well level returns. In 2019, we’ll continue to focus our 20 net well plan in the Bakken core and expand our development of the Antelope Extension. The Antelope Extension is part of our Williston Basin core acreage and the area now benefits from additional midstream infrastructure and takeaway capacity, driving better economics through reduced transportation cost and LOE. We are also testing new completion technology and are optimistic that it will improve productivity and lower cost. 2018 was an incredible year for operational improvements in our Rockies plays in the Powder River and DJ Basins. We increased our completions efficiency dramatically, achieving a 38% improvement in feet of treated lateral per day. Our cost to drill averaged just $100 per foot and drilling days declined 20%. Rockies-wide, we either met or beat all of our cost targets for the year by the end of the first quarter of 2018. In the Powder River Basin, our core acreage doubled to more than 400,000 net acres following the 2016 Yates merger. In 2018, we added more than 1,500 premium net drilling locations and nearly 2 billion barrels of oil equivalent of net resource potential through the addition of Mowry and Niobrara shale plays and new locations identified in the Turner sand. Furthermore, as we continue to block up our acreage position, we see significant upside to add to our premium inventory over time. During the fourth quarter, two Powder River Basin Mowry wells came online, delivering an average 30-day initial production of more than 2,000 barrels of oil equivalent per day. In the Powder River Basin Turner, we completed four wells that averaged 1,400 barrels of oil equivalent per day for the first 30 days. Last year, we moved the DJ Basin into full development and produced record volumes of nearly 30,000 barrels of oil per day. But the bigger story in the DJ was drilling performance. Average drilling days were already an impressive 4.4 days and we reduced another 7% to 4.1 days. Due to lower pressure, the IP rates aren’t as flashy as some other plays, but these are some of the lowest-cost wells in the company and they consistently deliver premium level returns. The sustainable improvements we have made to the cost structure of the Powder River Basin and the DJ Basin over the last year, combined with moderate decline wells, drove record low finding cost and record high returns in 2018. Performance from our Rockies plays are highly competitive with our largest premium assets. Here’s Ken to review our year-end reserve replacement and finding cost.

Thanks, Billy. We had a great year for reserve replacement, more than doubling what we produced during the year. Our proved reserves increased over 400 million barrels of oil equivalent, or 16% year-over-year to $2.9 billion barrels of oil equivalent. We replaced 238% of our 2018 production at a low finding cost of $9.33 per Boe, which excludes positive revisions due to commodity price improvements. Since the start of the downturn in 2014, we have reduced finding cost 30%. Our ability to consistently add reserves at low-cost demonstrates the tremendous capital efficiency gains we made through the downturn from our permanent shift to premium drilling and laser-focus on cost reductions. Every year, EOG engages DeGolyer and MacNaughton to perform an independently engineered analysis of our reserves. This year, they evaluated nearly 80% of EOG’s proved reserves. And for the 31st consecutive year, they were within 5% of our internal estimates. I’ll now turn it over to Tim Driggers to discuss our financials and capital structure.

Thanks, Ken. EOG further strengthened its financial position in the fourth quarter. The company generated discretionary cash flow of $2.1 billion, invested $1.3 billion in exploration and development expenditures and paid $127 million in dividends. Free cash flow was $637 million in the fourth quarter and totaled almost $1.7 billion for the full-year 2018. Proceeds from asset sales for 2018 totaled $227 million, which was predominantly the UK sale, including the Conway Field. Cash on the balance sheet at December 31 was $1.6 billion and total debt was $6.1 billion, for a net debt-to-total capitalization ratio of 19%, down from 25% at the end of 2017. Our goal is to repay $3 billion of debt from 2018 through 2021. We took a step in this direction by repaying a $350 million bond that came to maturity on October 1. In 2019, we have a $900 million bond scheduled to mature on June 1. We will determine the funding for this bond replacement closer to the date of maturity, whether from cash on hand or other sources based on the company’s financial condition at that time. EOG is currently unhedged for the price of oil or gas for 2019, with the exception of some contracts protecting the price differential between certain sales points. Historically, EOG has hedged up to 50% of our expected production. While our best hedge position is being a low-cost producer, we will continue to evaluate hedging opportunities with the objective of prudently managing our business and providing our shareholders upside to commodity prices. I’ll turn it back over to Bill for closing remarks.

Thanks, Tim. In conclusion, our goal is simple, to be one of the best performing companies in the S&P 500. Our business model of high return organic growth is driven by our culture of return focused decision-making, low-cost operations, innovation, technology and a first mover advantage. We have a pleased, but not satisfied mindset that motivates every fiber of our company to continuously improve. EOG’s core business acumen, organic exploration, low-cost operations, advanced information technology and sustainability powered by our never satisfied innovative culture means, EOG has not remotely peaked. We are excited about our future and our ability to achieve our goal of delivering double-digit returns, double-digit growth and free cash flow throughout commodity price cycles. EOG’s premium combination is rare in the energy sector and places EOG in line with the top performers in any sector of the market. It is a unique and compelling combination we expect to demonstrate again this year and over the long-term to create significant value for our shareholders. Thanks for listening. And now, we’ll go to Q&A.

Thank you, sir. The question-and-answer session will be conducted electronically. [Operator Instructions] And the first question will be from Neal Dingmann of SunTrust Robinson Humphrey. Please go ahead.

Good morning, guys. Great details. My question is just you guys have done a great job continuing to bring out another of these distinct premium plays. Just as you continue to look at some of your exploration opportunities, your thoughts about the potential for – potentially another one of these rolling out this year or next?

Yes, Neal, this is Ezra Yacob. As we discussed in the opening remarks, and I think it’s – you can see a good illustration on Slide 11 on the presentation. We’re really focused on adding higher-quality plays to the inventory as we’ve done over the past couple of years as opposed to just increasing the quantity. We’ve – we’re utilizing a lot of data captured over the last few years in the Permian and the Powder and the Woodford to develop some new horizontal play concepts. And we’re really focused on applying our horizontal drilling and completions techniques to a higher-quality unconventional reservoir some that we’ve identified. And as we said, we’ll be leasing and drilling some test wells in those – in 2019. And so the important thing, the way to think about it really is, since we’re just kind of leasing and testing those this year, we probably won’t have a potential exploration announcement. But we’ll be able to update you as we gather more data on these.

Okay. And then just sticking with that for my follow-up just on that Slide 11 with total locations, how do you all think there has been some diversion out there? Some folks are thinking about more of an ROR focused, up-spacing versus others thinking they’re still maximizing units by downspacing to get more locations. So again, I’m just wondering sort of your philosophy these days and how that might impact total locations?

Yes, Neal, this is Ezra again. I think, it’s a combination, not really up-spacing. What we try to do as far as converting existing non-premium wells into the premium status is really through two different mechanisms. The first is lowering well costs and dominantly doing that through sustainable kind of operational efficiency gains. But then also making strides on both the high grading of our targets and especially in 2018 advancing our completions technology, where we can actually improve the well productivity. And so, again, it’s a combination of increasing well productivity and lowering cost to get those across our premium threshold.

Great. Thanks, Ezra for the great details.

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

Yes, good morning. My first question relates to Delaware Basin. One of the SMID operators yesterday commented how children well recoveries were lagging parent wells by 15% to 20%, which is a delta relative to the Street. Bill, I was wondering if you could comment on EOG’s published type curves, as well as Billy’s commentary on some of the new advances in completion that you’ve announced, as well as the improvement in Delaware Basin well productivity in the second-half of the year?

Yes, Arun, thank you for the question. If you see the data we’ve released, our well productivity is beginning to improve significantly in most of the plays in the Delaware. And we have been tackling and addressing the parent-child relationship for a number of years and we’re – we have made significant improvements. I think the company’s ability to absorb data real-time and to make changes very quickly in our drilling programs in our well patterns has really paid off. So the new completion – ours that we’re using connects more rock. It also reduces the offset depletion effects and we also improved our targeting and our spacing. And to go back what Ezra talked about just recently, we’ve been able to do this and not really reduce. We’ve actually increased the recovery and we’ve increased the NPV and we’ve increased the rate of return all at the same time. So we made tremendous progress on solving the parent-child relationship.

Great. Just – and my follow-up, Bill, could you maybe discuss the tradeoff before – between investing in premium locations today versus new plays? It seems to us that you’re investing early to prevent an inventory situation down the road. So – and also so you wouldn’t have to make expensive M&A in order to preserve your trends, but I would love to hear your thoughts on that?

Sure, Arun. Yes, the total focus on the new plays is to add better inventory. We have 9,500 premium locations right now. So we really don’t need more, we just need better. And so we’re – as Ezra talked about, we are targeting rocks that have better ability to produce oil and be able to respond to these new completion techniques that we’re coming up with, and to reduce our costs, increase our returns and make the company better in the future. So our total focus on all that is to add a lot better inventory than we have right now. And we are being able to add – or able to add at very, very low costs. So we’re actively leasing in plays like $500, certainly, less than a $1,000 an acre. And that certainly much, much better than trying to compete in these hot areas through M&A.

Great. Thanks a lot.

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

Hi, good morning. Referencing the Slide 13, could you please provide color on the methodology on how the corporate decline rate was derived? And adding in additional color for any variations by major basin? And how does this on the corporate decline rate and the capital efficiencies compare historically prior to 2018?

Yes, Paul, this is Billy Helms. Thanks for asking about Slide 13. It’s a new slide that we put into illustrate the confidence we have in improving our capital efficiency year-over-year. We’ve made tremendous strides on both lowering our well cost and improving the productivity of the wells and is starting to dramatically show up. And this slide is based on not forecasting additional cost reductions, but based on our results we’re seeing today in the wells we’re completing here at year-end. So we’re very confident. And basically, the way you calculate the decline from that, if you go back and look at the production year-over-year, you can see the production in 2017 to 2018 and the capital number there $5.9 billion divided into those differences will give you the – and the capital efficiency number will give you the decline rate in 2018. And you do the same mechanism for 2019 using the midpoint of our guidance, compared to the 2018 production volumes with that capital efficiency number you can back into the decline rate of 31%, as it illustrates here on the slide. Year-over-year, our capital efficiency is improving. But as we grow volumes, those first year volumes, of course, are – have a steeper decline in the base production. So year-over-year, the base decline did increase from 2018 to 2019. And that’s just simply, because the volumes are getting much bigger. So that tells you that we’re adding – for the same amount of dollars, we’re adding a lot more new oil at our capital efficiency rate that we have today. So that’s the implication.

Great. I appreciate the color there. And then could you also provide your latest thoughts on the Austin Chalk, and if that falls within the premium category or in the exploration spend? And what’s the driver of moving to 15 completions in 2019 and the Austin Chalk down from 27 in 2018?

Yes, Paul, this is Ezra again. So the Austin Chalk there in South Texas that we’ve talked about is considered part of our premium plays there, where it overlies with our Eagle Ford development program. As far as – it’s been documented out there that we’ve got some other exploration opportunities there in the Austin Chalk. And that part of it would be considered in the exploration spend. As far as the well counts there in Austin Chalk and the Eagle Ford area, that’s just going to – simply the wells that we have put to – the wells that we’re forecasting and put to sale this year are with respect to where we’re at in our development program there. As you know, geologically, as we’ve talked about, it’s a bit of a complicated – a little more complex than the Eagle Ford down in South Texas. And so we’re really moving a little bit slower on that and making sure that the premium wells that we’re drilling on there are the quality that will be additive to our program.

Thanks, Ezra.

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

Hey, guys, just wanted to follow-up on a couple of your prepared comments here on the call. I guess, you guys previously had kind of talked about in the last year sort of 15% to 25% oil growth at $50 to $60. Bill, I think, you said in your prepared comments that you’re not really moving away from that over the next couple of years. But growth a little bit lower this year at sort of 12% to 16%. Can you provide a little bit more sort of color as this maybe just a little bit lower year due to more uncertainty around oil prices? Kind of what’s driving you to move towards the lower-end of that range in 2019 here?

Yes. Leo, this is Bill. We’re not shifting into a low double-digit growth mode that needs to be really clear. We’re not really shifting down into a lower mode and maybe we – people might think. Specifically, this year, we’re allocating a bit less capital to drilling oil and a bit more capital to drilling for new potential. So that affects this year’s rate a little bit. But certainly, as we’ve demonstrated in the past, we have tremendous ability to grow. It’s really easy for EOG to grow with our capital efficiency so high and such a huge deep high-quality inventory. But we said governors with our disciplined growth strategy, investment governors. And so the first one is, we want to generate free cash flow every year; and the second one is, we want to grow at a pace, where we can take advantage of the learning curve and continue to increase our returns and capital efficiency. So as we continue to get better and increase efficiency and add new higher – even higher quality inventory than we have right now, it will become easier for us to grow and to sustain and deliver strong high return growth. So don’t count us shifting into a lower mode.

Okay, that’s great color. And I guess, I just wanted to also follow-up on a comment that you guys made. You certainly are focused on continuing to improve ROCE at EOG, kind of clearly want to lower that over time, because I know you’re spending more money on kind of some newer domestic plays this year. And as I kind of think about that, I guess, I would, maybe assume that maybe the newer plays would initially have a lower ROCE, but might sort of payoff in the longer-term here. So just trying to get a sense of how you square that up with having a really long inventory already. Clearly, you guys have said, you’ve got well north of 10 years of premium oil drilling, even at an accelerated pace over time. So I guess, can you provide a little bit more color on sort of the need to kind of target some more annuity plays with more new exploration dollars here in the short-term?

Yes. Leo, this is Bill again. That’s certainly what we’re focused on with our exploration effort is to improve our ability to deliver return on capital employed. And because we’re able to acquire this – these positions at very, very low-cost, $500, $1,000 an acre. And they’re in areas where there infrastructure. We’re not in remote areas that – they’re not going to be difficult to connect really good markets. They’re in areas where we have very capable operating efficiencies with our seven domestic divisions in the company. And so we can move on them and we can test them very quickly and evaluate them. And then pretty quickly within a year or so, we could put them in a pretty strong development mode. And so we – we’re taking our advantage of being first movers in these plays and getting there before other people may not – may realize the potential of them. And we’re focused on better rock than we have right now. And those – that combination of low-cost and better productivity, we believe could meaningfully improve the returns of the company and down the road will improve our ability to deliver oil at even lower prices and generate return on capital employed at even lower prices.

Okay, thanks. Great color.

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

Good morning, Bill to you and your whole team there. I’d like to start with a kind of a big picture question, and this may go over some old territory for you guys. But looking at Slide 14, it looks like the way you guys built your capital program as you decided, you picked an oil price and said, okay, we want to able to fund our dividend. And so our CapEx has to be something less than our cash flow minus our dividend there. And I get the picture that free cash flow will just – will accrue as oil prices perhaps role in higher than that. But can you offer, I guess, a color on whether that is the way that you built your capital program? And if that is the right meat on it, could you give some insights into the process of how you pick that $50 oil or whatever that planning price would seems to be the kind of the organizing data point at the time of holding?

Yes, Charles, this is Bill. Yes, we use multiple parameters to set our program every year. But certainly, one of the first ones is, we want to build a program based on our view of the macro certainly, what oil prices might be and put us in a position to generate free cash flow every year. So that’s the first one. And so, over the last several years, $50 has been a good rule of thumb for that and it’s worked really well for us. And then our goal is to set the capital allocation at a rate that will continue to improve our returns. So that we can take advantage of the learning curve and continue to get better every year and continue to improve our capital efficiency. So with that in mind, we set the program to give us a good chance to generate significant free cash flow to do the things that we’ve talked about reducing our debt and certainly, being able to have the ability to work on the dividend on a much stronger rate than we have in the past years and to get better at the same time.

That’s helpful, Bill. I think I’m picking up what you guys are putting out there on – in that respect. And then, I mean, going back to some of the prepared comments, I believe, by Ezra about the improvements in the Delaware Basin oil productivity. And I know you guys have talked on this a little bit, but you’ve talked about optimizing the spacing and staggering. Can you give us a bit more detail as – does that mean that you guys have gotten closer or rather wider on your Delaware Basin well patterns?

Yes, Charles, this is Ezra. Really, when you look at it over the bulk of the year between 2017 and 2018, I think, on average, our spacing was pretty consistent. As we’ve talked about in the past, it really is going to change across that base and depending on how many of our specific targets that we’re aiming for in developing and co-developing. And we aim to target as we’ve talked about before, any targets that are kind of within maybe a couple of hundred feet of each other. And so as we talk about the improvements and optimization of spacing vertically and horizontally, it’s if you think about it in a stacked and staggered manner. And so we’ve definitely tested as we highlighted on one of the earlier calls last year as tight as a 400 – approximately 400-foot staggered spacing pattern. And obviously, we’ve targeted much wider than that. I think at the end of the day what we’re seeing is, there’s a lot of potential upside there to our announced resource potential. As you recall, our type curve in the Wolfcamp Oil Window is based on a 660-foot spacing in just one Wolfcamp target across the whole of our Wolfcamp oil acreage.

Okay. Thank you for that color, Ezra.

The next question will be from Michael Scialla of Stifel. Please go ahead.

Good morning, everybody. Based on your comments that the exploration ideas are really targeting better quality rock, is it fair to say that you’re really not looking at kind of the massive traditional shale plays like the Eagle Ford or the Bakken, I’m thinking maybe more along the lines of tight sand or carbonate resource plays, I mean, you admitted, I guess, the Chalk over in Louisiana is one of them. But is that more the type of play that you’re looking at with the exploration ideas?

Yes, Michael, this is Ezra again. That’s a great question. Without giving too much away, what I would say is, just reiterate again what we talked about, and I think you’re on the right track with it is we are targeting – we’re looking to apply our horizontal drilling and completions technology to in general just better rock quality in these unconventional reservoirs. It’s a variety of different things that we’re looking at. And really, it comes from combining datasets, as I said, that we’ve collected over the last few years in development in the Permian and the Powder and including the Woodford also. And so the way to think about it really is that, the actual rock quality is going to be better than what we’ve traditionally targeted horizontally. And I think that’s what really we want to – is going to help us increase the quality of our inventory. And it should hopefully shallow the decline that these unconventional plays are kind of known for. And really that should help reduce our finding cost, lower our DD&A and play into helping us achieve our long-term goals of double-digit growth and double-digit returns.

Okay, thanks. And Bill you said in your opening remarks that you would be willing to buyback shares when accretive of just wondering what metrics you’re going to be looking at there and decide if that’s an accretive opportunity or not? Is it simply NAV or something else?

Michael, as we stated on free cash flow, our priorities are to target – to be able to be in a position to target a stronger dividend increase. And we’ve been doing it in historical past, which has been 19%. And then we certainly have outlined a very strong debt reduction, as Tim talked about earlier, and we’ve got about $2.65 billion in the next three years to – we want to reduce that. And so our priority to maintain a strong balance sheet is – has put us in a position, where we have the flexibility to take advantage of opportunities down the road in the future, such as high-return, low-cost property additions, particularly things that could go in conjunction with these new plays that we’re talking about. And it puts us in a position to consider potential share buyback. So share buybacks could be an option, when our senior management and our Board indentify a value-accretive opportunity in the future. So we continuously consider all the options what is in the best interest of the shareholder. And our primary focus is on creating the most value for shareholders in the future. So we’ll continually consider on a quarterly basis free cash flow availability and what is the best allocation of capital to create the most value.

Thank you.

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

Yes. Thank you, and good afternoon, everybody, or good morning, I should say. I’m actually in Europe right now, so sorry about that, Bill. Bill, a bit of a philosophical question, if I may, and it really relates to your comments about being one of the best companies to compete with the S&P. No question, you guys have knocked it out of the park against the E&P sector. But the big difference between the focus on returns and competitive drills is that, the S&P obviously has been dramatically better than the E&P sector over the period that you focus on premium locations. The big difference being that they payout a lot more of their cash flow for those competitive growth companies, think biotech, think technology. So if you’re really talking about – what do you feel – what do you think about that your relative performance to the S&P obviously isn’t delivering that with the current strategy? What makes you think you will do so in the future?

Yes, Doug. Certainly, you’ve identified two of the key things is a return on capital employed. We think we can be competitive even through the commodity cycles with double-digit and we believe on growth that we can be competitive with any sector through the commodity cycle. And as we work on lowering the cost basis of the company and our capital efficiency, we will target free cash flow. And as we continue to generate free cash flow and get better at doing that, that allows us to return more cash to the shareholders. Certainly, first, we picked through dividend. We’ve already outlined our debt reduction. And then down the road, it comes to where we have situations where we can have accretive value through share purchases, we’ll consider that too. So we’re committed to making the company better in every means. And we certainly believe that our culture and our business model has the ability to compete with any company in any business.

No, I understand the philosophy. I’m just trying to understand what – how it changes as it relates to the comment about the relative performance story within the broader market when your cash distributions are so much lower. I guess, that’s what I was getting at. But my follow-up really, if I may, is also kind of a high-level question and it really is related to the same thing, because we’re all wrestling with this. Let’s be honest now for the stock price performance over last several years, and it really is the issue of that. The one thing that’s different obviously with oil and gas is, you’re dealing with a commodity and the volatility of that commodity. You guys are a very large company. On the high-end of your prior target range, 25% at $60 oil, your growth in oil is 10% of global demand growth. And we know the growth isn’t rare, but growth with cash returns is. So I’m just, again, trying to reconcile why not grow at a slower rate and step up the cash distribution? Because you can’t control the oil price. And if you can grow at that rate and the rest of the industry following six, obviously we’ve got a problem with the commodity. So I’m just wondering how you address that circular volatility, and I’ll leave it there. Thanks.

Well, Doug, as – if you consider the metrics that and the value that we’re creating by drilling possibly 700 wells this year. As I stated in the opening call, the net present value – discounted net present value is about $6 million per well. So our drilling program this year is creating more than $4 billion of value, that’s a significant thing. And so you can obviously – when you’re reinvesting its super high rates of return and creating that much value per well, that is an exceptionally good. There’s not many businesses and in any business that can create that kind of value. And then second of all, we truly believe that we can be among the low-cost producers in the energy market. So that gives us a competitive advantage. We have a lead we believe versus our competitors in cost and being the low-cost producer and we also have the culture to get better faster than most of our competitors. So we have a long-term sustainable business model. And our goal is to create tremendous value and be able to – through growth and returns and be able to do that sustainably for a long period of time.

I agree with that. I'm going to close that there, Bill. But just with – if there's any sort of comment, though, that has been your strategy for four years. And if you really believe that much value is being dislocated from your share price, which is flat, why not go ahead and buy back your stock? And that’s really all I’m saying is that, the value creation isn’t being recognized at the market, then that means something has to change? Thanks so much.

Thank you. Again, we’ll continue to evaluate what’s best for the shareholders on a quarterly basis and make the appropriate decisions going forward.

The next question will be from Paul Sankey of Mizuho Securities. Please go ahead.

Good morning, everyone. I mean in the uncomfortable position of supporting the previous couple of questions. They were actually very much in line with what I was going to ask about, particularly the accretion definition, which I know is always difficult. But also the balance between growth and returns relative to the stock price performance. One further one I would just add is, do you have a comment on motion for your premium inventory life, which seems to be steadily rising? I wondered if there was a point at which there was no need to raise it anymore now than you’re getting deal for 13 years? Thanks.

Paul, this is Bill again. We – we’re not focused on this the size of it. We’re really focused on the quality of it. And that’s why, of course, we’re – as we talked about, that’s not we’re working on new these new play concepts. And so we believe that our inventory, even the lower tier part of our inventory is probably comparable, maybe even better than much of the inventory that’s been drilled by the U.S. And that has a lot of value in the future. So we’ll continue to work on getting value for that. We’ve sold quite a bit of property over the last few years, I think, over $6 billion over the last five years or so. So we’ll continue working on tearing off the lower-quality and adding on to the higher-quality and improving the overall metrics of our inventory.

Yes. Again, it’s – further to that firstly, if there is a potential to increase your definition of premium inventory and so accrete returns through higher hurdle rate, even I accept that your hurdle rate is impressive. But as you’re constantly growing, potentially, you could skew towards more returns of a growth through that? And secondly, I completely hear what you’re saying about disposals, but you do seem to becoming more and more spread in more and more areas, potentially the – potential for increased disposals, I guess, would be an additional logical continuation of that strategy? Thanks.

Yes That’s correct, Paul. I think we’re a bit more decentralized than most other companies. And that decentralized structure is a huge advantage in the company, because we can execute on each one of these plays with a very dedicated, strong group of people that can learn quickly and apply the technologies and the learnings that we’re getting across the company and we share those. And so we can, with our scale, with our ability to share data and learnings, we can execute each one of those plays at a very efficient manner. And when you have multiple plays, you can take each play slower. So that you can take advantage of the money, because you don’t have to go so fast on any of them and it makes all your plays better. So – and it give you a very stable high-return and high-growth portfolio to continue to build the company on.

Sure. Okay, thanks. I mean, the problem does remain that the stock is not competing with the S&P in the way that you wanted to, I think, that’s what we’re driving at? Thank you.

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

In closing, EOG’s results in 2018 were the best in company history due to the excellent work by everyone in EOG. We’re headed into 2019 with tremendous momentum, so we’re very excited about the year. EOG has never been in better shape. We are pleased, but not satisfied, so we fully expect to continue to get better. Our goal is to be one of the top performers in the S&P 500 with double-digit returns and double-digit growth through commodity cycles and deliver significant long-term shareholder value. Thanks for your support and thanks for listening.

Thank you, sir. Ladies and gentlemen, the conference has now concluded. Thank you for attending today’s presentation. You may now disconnect your lines.