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 in EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. Definitions as well as reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. Some of the reserve estimates on this conference call and they are accompanying investor presentation slides may include estimated 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 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. 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're 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 the company history. Well costs and operating costs are falling, and well productivity is strong. EOG is growing all volumes at lower cost per barrel than ever before. We are excited about 2019 and the outstanding operational and the financial results we are delivering. Some of the highlights this quarter include year-over-year oil growth of 20%, exiting the high-end of our crude oil production target, capital expenditure below the low end of expectations, strong year-over-year lease operating and transportation per unit cost reductions, additional reductions and completed well costs. And we secured significant crude oil export capacity increasing our ability to receive the best prices. EOG continues to improve unit costs, capital efficiency and profitability. In fact, we made the same amount of net income…

Thank you, 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 our 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 our 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 continued to markedly improve their drilling times and performance. More importantly, the consistency of the improved performance can be seen across our entire rig fleet. 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 continued to achieve new record drilling times and costs.…

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 plays, including the Eagle Ford and Delaware Basins. As we illustrate on Slide 19, EOG will control its crude volumes from the basin all the way across the dock as our agreements provides for pipeline capacity, terminal tankage, and dock access. With the options of price our crude oil further downstream, we expand our flexibility to sell products 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 costs fix commitments. This strategy is reflected in advantage positioning of oil take away in the Permian Basin. EOG controls these barrels from the wellhead to the sales point. Delaware Basin barrels are transported out of basin on a fit for purpose gathering system for five pipeline interconnect points, which can transport the well anywhere from Cushing, Houston, Corpus Christi and even Midland. And we have accomplished this with limited long-term commitments and…

Thanks Lance. The Eagle Ford remains the workhorse asset for EOG, earning high returns and delivering sustainable growth, while generating strong cash flow. EOG has been developing the Eagle Ford for about 10 years. However, less than 40% of the identified locations have been drilled. Last year Eagle Ford production grew 9%. We forecast the Eagle Ford is capable of growing, for at least 10 more years at premium rates of return, while generating significant cash flow in excess of capital expenditures each year. More importantly, we believe the capital productivity of the Eagle Ford will continue to improve in the years ahead. Sustainable cost reduction has been a key theme throughout our 10-year history developing the Eagle Ford. Even in a play that is already accumulated significant operating efficiencies, we were able to reduce drilling costs by 7%, and increase completed lateral fleet 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 Eagle Ford on a dollar per foot basis, highlighting our culture of always getting better. On the production side, we're 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 Eagle Ford acreage continues to deliver strong premium returns, net present value, finding costs 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 Eagle Ford drilling program by 2021, growing from about 40% of our program in 2019. Capital efficiency in the West is 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 Eagle Ford continues to perform the technical and commercial expectations. EUR is a secondary recovery process in this play and primary development remains the main focus of our operations in 2019. The EUR footprint will be expanded after a larger portion of the play has been fully developed. The best days of the Eagle Ford are still ahead. We continue to convert non-premium inventory to premium status through sustainable cost reductions, productivity improvements and leasehold consolidation. The Eagle Ford 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 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 fleet. However, we use 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 saved $2 per barrel compared to trucking. Source more than 70% of our water through reuse and reduced total wells cost 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 in all-in finding costs below $10 per barrel of equivalent, while earning $9 million of MPB 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 is over to Tim Driggers 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 exploration areas. As part of our debt reduction plan, we expect to repay the $900 million bonds 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 the stable outlook. To quote the Moody’s press release announcing the upgrade the company stated. The upgrade of EOG's rating 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 the strong credit profile and that 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 the dividend increase of 31% in the yesterday’s earnings release. The indicated annual rate is now $1.15 per share. EOG have 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 MMBTU 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 crude - our current crude oil and natural gas prices is prudent considering the volatility and prices and 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 well 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&P500 through commodity price cycles, long into the future. Thanks for listening. And now we'll go to Q&A.

[Operator instructions] Your first question will come from Neal Dingmann of SunTrust Robinson, Humphrey. Please go ahead.

My first question, maybe, Bill, for you. Could you all speak to your plans of -- you've done a great job of balancing growth for shareholder return. And, really, when you look at that, you've almost doubled now your dividend in the last year, while production growing about 30% here over the last year. So oil was up only about 15%. So 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 material amount of free cash flow?

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 2020 oil growth. But certainly, you can think of the company in the -- our 14% oil growth target this year is really a bit on the low end. And so we're really focused on high return oil growth. And that's the way we believe will 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 way we think we're going to continue to generate the most value in the long term.

Very good. And 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 how you're seeing these wells after a number of months?

Yes, Neal. 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 little bit lot 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 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, you want to add anything or?

I'll just highlight too that the team's done a great job in the Permian 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 cost I discussed in the opening remarks and the higher capital efficiency, which we've great success, is going to continue throughout the year.

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

So I would just like to touch on the acquisition capital and, obviously you're not going to tell us where you're acquiring, I guess. But some ideas to what we can expect that plays to look like going forward was -- first quarter very much one off or 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, it was a little bit garbled. So could you be a little bit more clear there?

I apologize. I'm on my cell phone. I'd be coming in okay now Bill.

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?

Okay. Thank you. That was better. Yes, we, as you know the company, we're not really focused on corporate M&As. But we do occasionally look at bolt-on type acquisitions and they're focused primarily in our exploration plays. And these acquisitions are very low cost and very, very high potential, obviously, or 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 anymore. But they're really opportunistic drilling, opportunistic given and certainly our focus on very, very high return and low cost drilling potential.

I appreciate the answer. Hopefully you can still hear me. My follow-up is just a quick one. Obviously, 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 as 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 answer for any company. For EOG, specifically we’re generating super high, fantastic returns on every dollar we spend. And so we believe our allocation on reinvesting in very, very high rate premium drilling is a number one priority. We also strongly believe as we’ve demonstrated this quarter in strong, sustainable dividend growth. And we think that’s the best way to get 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 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.

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

I have a question about your CapEx just year-over-year. If you look at the way you guys have had posted 1Q, and your guidance for 2Q, you have a first half is heavier than the back half. And we saw that same pattern in 2018. So my question is that a feature or manifestation of your planning process? Or was that more just a coincidence with the way that 2019, 2018 had shaken out?

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

And then one, I guess kind of more targeted question on the Delaware Basin position. I noticed that the - your Bone Springs laterals are significantly shorter. I think its 5,500 lateral feet versus really 7,500 or 7,800 on other zones in that same basin. Can you elaborate a little bit on what maybe going on there? Is it about the lease configuration where you’re developing those Bone Springs? Or was a more 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 there in the lateral half of your question, it really just comes down the lease configuration where 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 trying 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 are really increases the capital efficiency. And so I'd look in the future to see that Bone Spring getting longer as well.

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

Eagle Ford inventory depth remains a focus for investors. And I noted pretty interesting comments in the release about high grading the residual 4,900 non premium locations. Is this just a matter of sort of cheaper well costs, longer laterals and the new completions? Or is it really more toward from a delineation or aspiration 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, we're trying to reduce the well costs 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 position. 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'll help convert some of those non premium wells to premium.

Okay. So you expect to see that number, maybe grand higher throughout the year?

That's what we're working towards.

Then my follow-up, your proxy came out in March, and it's 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 threshold? 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.

Yes, Tim, it means that a few of the wells that we drilled, and there is a very few in the total package of wells we drilled last year were either step-out wells or exploration wells in areas where we did -- maybe didn't have the infrastructure in place or we're 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 didn’t or weren't really strong economics. Those wells are fantastic economics, probably better than the -- probably are non premium. Those are better than the average for the whole industry on returns. But it was just a very few of those. And that's what we have.

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

I’m sorry. Off the top of my head, I don't have the number.

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

In the release you discussed testing additional targets in the Woodford. Could you elaborate on what you would be seeing there? And what timeframe we could see results from that portion of the program?

Yes, 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 a point we've really made great strides in the operational efficiency in that. In the Woodford play this year, we've almost dropped our drilling 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 Eagle Ford program matures and there's more development opportunities, the expansion to EOR 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 are matured in the pit at certain level? Just trying to understand when the EOR program could see expansion throughout the Eagle Ford?

This is Ken again. We'll expand the EOR as we really finish up with our primary development in those areas. We'll expand that in the areas that make sense based on some of the results that we've seen already with the EOR 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 to be finished?

I would guess, I would classify primary development as finished when we quit drilling wells in those areas and we can begin the EOR process.

The next question will be from Leo Mariani of KeyBanc. 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, why do you get a sense is 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 you know out there? And then additionally, just with respect to the dividend, is there some kind of price level, for example, on the oil side that 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 color you had around that will be helpful.

Leo, yes, this is Bill. Yes, certainly 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, 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 to 31%. And so our focus on the future is to continue to do that. We will 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.

And I just wanted to jump over to the exploration front. I guess, clearly you guys made a couple of bolt-on acquisitions in the first quarter, and I hope that 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 and in the opening comments like you suggested, we’re pretty excited about the exploration opportunities. We're really focused on applying our drilling and completions techniques to higher quality unconventional reservoirs. And what really drives our process of having a multi-basin dataset that allows us to compare 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 increasing 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 little more material, we’ll certainly update you guys.

Okay. That’s helpful. And I guess could have noticed the marketing sort of arrangement for the export capacity that 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 that there is a potential big increase coming over the next couple of years. Just wanted to get a sense of whether or not you've already got some relationships there to international buyers out there that you’re hoping to expand?

Yes, Leo, good morning. This is Lance. So thanks for the question. Yes, when you think about the existing business, I mean we’ve been very active in Houston for quite some. I mean Houston is really kind of been our warehouses, especially since 2012 with a lot of our pipeline capacity that comes into the Houston market. But since the export bans unlisted, we’ve been actively engage there. We’ve got a tank position is 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. And so we’re very excited too about our new capacity that's going to be starting up moving into next year. Really when you think about and you look at the balances in the U.S., you look at supply growth, you look at imports -- exports are going to be here the same. And we really want to have a very large position there. And having that control at the dock, we feel that just going to give us a lot of price discovery. But again it’s about portfolio approach. I mean we want to protect those realizations. And so moving into the next year and you look - we feel we’re going to be very well positioned with our -- its just unique that we’re going to have our Permian, and also our Eagle Ford that we’re going to be able to show across the dock. So we feel we’re very unique relative to when you look at the producer group on the different quality. So we’re going to be able to show to the domestic market, but then also our international customers too.

The next question will be from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.

I just wanted to touch basic on the various technological efforts there 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 just give us a little bit color on that? Thank you.

Yes. Jeff, this is Billy Helms. I can add a little bit of color to that. I think part of that goes down to our very culture of the company, we’re always trying to get better of what we do. And the way we do that as 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 we're seeing that manifest itself on the drilling highlights that we offer today as well as the completion highlight improvements that we’re seeing. So on the drilling side 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 direct reflection, 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, and 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 fracking, 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 you can apply everywhere, its tailored, its specifically designed by each well, by each zone, depending on the target zone and their offsets. It takes an integral approach to be able to analyze the data real time and make the right decisions.

Okay. And if I could just ask a quick follow up to that. This is -- 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 today 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 reducing costs, improving well performance. And it's all directly related to our ability to analyze -- collect the data and analyze it real time.

The next question will be from Jeanine Wai of Barclays. Please go ahead.

My question is on sand. A sand provider recently commented that some E&Ps are switching back to northern white from local sand due to crushing reasons, which I guess there could be production and cost implications through E&Ps. 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 the treatment commentary and how much exposure you have to local sand? Any basins specifically you have would be really helpful too?

Yes, Jeanine, this is Bill. Certainly, we got a tremendous -- we got 20 years of history in horizontal shale plays. And we use every kind of sand pop-up material that's been available over the years. Currently, 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 play, such as Eagle Ford, and many of the Rocky place, and in Oklahoma too. So that's the direction that we're focused in. And along with a 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 at the sand we use in every play. It's kind of tailor fit for each play. We're very confident that the compressive strengths and the quality of sand that we use in each play is the right mix for long-term well performance.

Okay. I think the commentary that's kind of chain leading around, I think maybe the Eagle Ford and the Midcon outside of the Permian. And so you do use local sand in those areas as well and you're satisfied?

Yes. We're satisfied.

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

One of the debates out there is whether for EOG, but also for industry is whether the best of the inventory infield is drilled from either a productivity perspective or rate of return perspective. And I think for EOG, you're more specifically pushing back on this point with the comparison of the Eagle Ford 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 Eagle Ford, the Woodford, the Permian and the Powder. We can take some of these techniques and apply them to basically higher quality reservoir. That's still should be considered unconventional by nature. And we think that 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 that you've 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 Eagle Ford is that every year one of the benefits of working in multiple basins is yet to combine datasets 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 costs to increase the returns of those areas. So the best example I would say for the Permian is really looking back at that Eagle Ford, example, and how we've taken our Western Eagle Ford results today, and really improve them to a point where they are above and beyond what we're doing in the Eastern Eagle Ford just a few years ago.

And then my follow-up is with regards to the Powder River Basin. You highlighted that 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 to be, especially given the competitive profitability you’ve highlighted at least as it relates to that Niobrara and Mowry zones on your Slide 41. The turnover wasn’t there maybe that would be another point to touch on.

Yes, Brian. This is Billy Helms. Yes, the first quarter we really tested more Turner and apartment zones, particularly. And as we build out infrastructure for the bigger development, it’s, I think our infrastructure build will be -- build out in segments to keep pace where there are plans for drilling in that year’s program. We’re not going to get out ahead and build infrastructure this made for a longer-term drilling program just because of the capital efficiency if that erodes. So the size though the scale of the infrastructure will be able to handle, certainly even the plan that we have in place for those areas. So we’ll be adequately sized, but it’ll be scheduled and pace that keeps up with the current drilling plans for that period. So we got off to a slow start really in the Powder, really due to weather, we plan to ramp up activity as we go through the year. And we’re still very excited about the initial results we’re seeing from the Mowry and Niobrara tests. And as 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.

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

Maybe a couple of follow-ups and some other things. And I appreciate the clarity you have given on the Eagle Ford. And if we look at the -- on the improvement that you’re seeing out to the West, as we look at the type curve that you carry in the Eagle Ford, it’s got 5,300 foot lateral lengths with the concerned level of productivity there. The lateral there feels like it's clearly trending higher. Is it safe to say that as the lateral lengths increases? And as the West is improved, is that type curve probably conservative relative to what we should expect to see going forward?

Yes, 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 120 mile long acreage position. And as we extend our - 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.

And then maybe a follow-up on some of the acquisition activity and exploration versus your core basins, your - you’ve obviously been spending money picking up acreage in some of your core basins you’re really excited about. And is this -- do you still see opportunities to add the 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 U.S., probably not a well being drilled. We don’t know something about. And so, we’re leasing in multiple plays this year at very low cost. And we believe the prospects that we're leasing on have premium economic potential due to the rock quality as Ezra talked about. And so, 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 historic production at all. But they're all very high quality. And the size of the prospects we're working on, we use an example, couple of years ago, we talked about the Woodford oil play we introduced. That's about 200 million barrels of net EOG. That's kind of on the small size. So we're not looking for things smaller than that. But 200 million barrels, net to a company, discovery of that top anywhere in the world is very significant. So, last year, we announced two new plays in the Powder River Basin that totaled 1.9 billion barrels. So that's a very large one. So that's a good way to put the brackets on the size of them. But the good thing is, as Ezra talked about, we believe we can continue, and it'll organically generate significant prospects potential in the future. And added at very, very low cost, much, much lower costs than doing M&As. And so when we do these bolt-on acquisitions, there are large amounts of acreage are very, very low cost, and very, very high potential in our mind. And so we've been generating premium inventory twice as fast as we've been drilling it. And the quality of our inventory is going up at the same time. So some of the previous questions are based on, is EOG's inventory quality declining? And I can tell you-- we can tell you with absolute confidence that we believe our inventory quality will continue to improve. So the quality is going up. And we're not having any problem replacing at much faster than we’re drilling it.

The next question will be from Arun Jayram of JP Morgan. Please go ahead.

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 the oil production, call it, greater than 14%. And I just wonder 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. So most of the things that we're doing right now still have a lot of growth opportunity. And we're adding additional premium locations in each one of those plays. So that's a big source of new potential. And then, we're working on all these emerging plays. And as they come into the development mode, that will keep shifting more and more activity and inventory into the growth mode of the company. And 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. And then the structure of our company, because it's decentralized, we can execute on the large number of multiple plays at the same time with a lot of discipline. So we have very expert strong staff in seven different operating divisions. So 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. So the company has got a tremendous ability to continue our high return growth profile for a very, very long time. And I think that's quite unique in the industry.

And just one question in terms of the agreements they are in place to expand your export capacity from 100,000 barrels to 250,000. For those barrels that you are able to even 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 in 60% of the Brent TI spread, let's call $3 in transportation. I was wondering if there's maybe a formula, anyway we could think about the uplift that you get on those barrels?

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 right is it’s a portfolio approach to us. When we have the diversification, we're going to have the capability there to sell domestically. So if that's a higher realized net back for us, then we can sell them domestically. And as you think about our export capacity, it’s capacity that we can optimize. So again, like if you if you look back over time, you look at our experience, our goal is to maintain our price realizations, and being purely in price realizations. So 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 into the spot business, and we can keep it on the international index like the Brent indices or we can keep it at the local markets. But 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, which is we can move quickly and 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.

And 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 and allow us -- 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.