EOG Resources Inc (EOG) 2018 Q2 法說會逐字稿

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

Good morning, and thanks for joining us. 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. The 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 be included -- may include estimated potential reserves not necessarily calculated in accordance with the SEC reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings press release issued yesterday.

Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, President; Billy Helms, Chief Operating Officer; David Trice, EVP, Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; and David Streit, VP Investor and Public Relations. This morning, we'll discuss topics in the following order. Bill Thomas will review second quarter highlights and corporate growth strategy. David Trice will discuss our new Powder River Basin plans; followed by Lance Terveen, who will cover Powder River Basin takeaway status. I'll then discuss yesterday's dividend announcement and our capital structure outlook. Billy Helms will cover second quarter operating highlights. And Ezra Yacob will give an update on our Eagle Ford and Delaware Basin activity. Then Bill will provide concluding remarks.

Here's Bill Thomas.

Thanks, Tim, and good morning, everyone. EOG is focused on delivering long-term shareholder value through disciplined high-return organic growth. Our Powder River Basin resource addition this quarter demonstrate once again the value of our exploration focus. We were able to grow our premium inventory in both size and quality by adding locations much faster than we drill them.

In addition, our second quarter production results demonstrate our ability to consistently execute and deliver strong double-digit oil growth through our decentralized organization and multi-play asset base. EOG's ability to organically generate new prospects, coupled with our proven ability to execute on our premium drilling program, demonstrates that EOG is a high-return growth machine with the ability to sustainably generate long-term shareholder value.

During the second quarter, we exceeded production targets for oil, natural gas and NGLs; beat our quarterly total per unit operating costs; realized better-than-target prices across all 3 production streams; announced 2 new shale plays in the Powder River Basin; and added over 1,500 premium locations and 1.9 billion barrels of oil equivalent of net resource potential. In addition, we also identified new premium locations in the Delaware Basin and Eagle Ford, effectively replacing the inventory we drilled in our 2 largest core assets. EOG's undrilled net premium resource potential now equals 9.2 billion barrels of oil equivalent and 9,500 net locations, which is more than 13 years of premium return drilling at our current pace.

Last but not least, the Board of Directors approved another increase to the common dividend. The current 19% increase, coupled with our previous 10% increase last February, brings our total dividend increase to 31% this year. This is a tremendous vote of confidence in our premium business strategy, a strong commitment to capital discipline and demonstrates our commitment to returning cash to shareholders through the dividend.

Looking ahead to the remainder of 2018 and beyond, EOG will continue to deploy a disciplined growth strategy. Disciplined growth means pacing long-term growth to allow the company to maximize the value of our acreage, retain efficiencies to support high returns and generate cash flow to both reinvest and reward shareholders. EOG in particular is uniquely positioned for disciplined growth due to our diverse portfolio of assets. We're not relying on any one basin to drive our company's success, which means we are in a position to grow production without straining the return on our capital investment or the underlying assets. In other words, we can grow each asset at a pace that maximize returns and NPV per acre.

Our production growth in 2018 is a result of investing in high-return premium drilling across 9 plays in 6 different basins. Year-to-date, almost every one of our operational areas grew production and did so while maintaining efficiencies and producing premium returns. With the addition of the Mowry and Niobrara in the Powder River Basin, we now have 11 plays to develop and fuel the company's future.

Slide 8 illustrates the progression of our premium inventory, highlighting our ability to consistently replace and grow premium inventory much faster than we drill it. Disciplined reinvestment of cash flow in our deep inventory of high rate of return drilling is fundamental to how EOG creates significant long-term shareholder value.

Next up is David Trice to provide details on our exciting Powder River Basin news.

Thanks, Bill. Yesterday afternoon, we introduced 2 new premium plays in the Powder River Basin, demonstrating once again the value created by our leadership in exploration. Over the last few years, our Powder River Basin team has focused on understanding the geological complexities of our 400,000 net acre position. Like the Delaware basin, the Powder River Basin is prolific with almost a mile-deep column of pay and multiple targets.

We tested many zones over the years and learned that both the Mowry and the Niobrara shales, much like the Eagle Ford, are resource-rich, overpressured source rocks that produce prolific wells when we apply our refined targeting techniques and EOG-style completions. Also, much like the Eagle Ford and the Woodford, the Mowry and Niobrara are both shale resource plays and therefore have great potential for additional efficiencies in the future. Shale allows for tight downspacing, which is a great fit for drilling large packages using multi-well pads, longer laterals and zipper fracs. Furthermore, these 2 resource plays overlap on much of our acreage, allowing development of both concurrently. Tightly spaced wells in codevelopment also translates to less surface disturbance per well, which reduces our environmental footprint and is particularly important for permitting in Wyoming.

Over the last year, we reported some remarkable efficiency records in our Rockies plays, including drilling 18,000 feet in under 3 days and completing 26 stages in a single 24-hour period. While the records are impressive, so are the averages. Drilling days are down 70% since the start of the downturn in 2014, and completion stages per day are up 50% over the last year. Sustainable cost reductions and shorter cycle times driven by efficiencies were a big contributor to adding these 2 shale plays to our Powder River Basin premium inventory.

Currently, well cost in both plays are around $6 million for laterals approaching 2 miles. Combined with average EURs of more than 1 million barrels of oil equivalent, net after royalty, the Mowry and Niobrara shales are delivering premium rates of returns at very low finding and development cost. Low finding and development costs drive higher corporate-level returns.

We estimate EOG's position in the Mowry shale is prospective for 1.2 billion barrels of oil equivalent from 875 net premium locations using 660-foot spacing. Oil cuts in the Mowry range from 20% to 60% depending on location. We completed 2 Mowry wells during the second quarter, and their 30-day initial production averaged almost 2,200 barrels of oil equivalent per day.

Our Niobrara shale resource estimate is 640 million barrels of oil equivalent from 555 net premium locations, also on 660-foot spacing. We expect about half of our estimated Niobrara resource is crude oil. In addition, we identified another 80 net undrilled locations in the Turner play, bringing our undrilled premium location count in the Powder River Basin to over 1,600 net wells.

The Powder River Basin is now ready to become a meaningful contributor to EOG's future growth. We worked hard to assemble and block up our position as well as permit well locations to capture operatorship. During the second half of 2018, we'll drill the remaining Turner wells planned for the year, and we'll conduct a couple of spacing tests in the Mowry and Niobrara.

For 2019, we expect to increase our activity as we add infrastructure and prepare to bring the Powder into full development. Adding nearly 2 billion barrels of oil equivalent in the Powder River Basin and -- from the Mowry, Niobrara and Turner exemplifies EOG's differentiated investment profile of multiple diverse assets supporting long-term disciplined high-return growth. EOG's extensive and diverse asset portfolio is unmatched in the industry and now totals 11 plays across 6 basins. We have the flexibility to allocate capital to the best performing assets over the long run, ensuring consistent returns to our shareholders throughout the commodity price cycles.

Next up is Lance Terveen to discuss our takeaway positioning in the Powder River Basin.

Thanks, David. The existing midstream presence in the Powder River Basin is strong. For liquids-rich natural gas, there are 4 processors near our operating area with significant low-pressure and high-pressure gathering systems with backup connections as contingencies. This allows EOG to fully utilize existing plant capacity in the area.

In conjunction with midstream providers, planned processing and NGL takeaway expansions, we are designing an EOG gas gathering and compression system. This system is similar to the successful design of our infrastructure in the Bakken, Eagle Ford and Delaware Basin and accomplishes 3 goals: one, control; two, lower operating costs; and three, access to multiple markets.

Now on the oil side, takeaway in the PRB is plentiful. The Casper and Guernsey hubs provide access to multiple local refining markets as well as the Salt Lake City and Denver markets. Other pipelines are available to access the Cushing market, and we're studying all options, even the potential to move barrels to the Gulf Coast. Wellhead netbacks today for lease sales are also strong, and we currently anticipate the local market dynamics for oil and condensate to remain strong into 2019.

Finally, we are working on solutions for longer-term oil gathering and oil terminal infrastructure. We are well positioned for processing and takeaway in the Powder River Basin today, and we are taking steps now to prepare for increased activity longer term. Infrastructure investments we make over the next 18 months will provide the flexibility to respond to changing market dynamics and access a wide variety of markets out of the Powder River Basin.

Here's Tim.

Thanks, Lance. As Bill mentioned, the Board of Directors approved a $0.14 increase in the common stock dividend. The indicated annual rate is now $0.88. Combined with the $0.07 increase approved in February, the dividend has increased by 31% in 2018. This should send a strong signal about the effect of our shift to premium has had in lowering our cost structure and improving the profitability of the company as well as our commitment to returning cash to shareholders.

At the same time, we are making good progress strengthening EOG's financial position. Since year-end 2017, cash on the balance sheet increased by $174 million to $1 billion, and our net debt to capitalization ratio decreased to 24% at June 30. $1.26 billion of debt is now classified as current on the balance sheet as we intend to repay, upon maturity, a $350 million bond due in October of this year and a $900 million bond due in June 2019.

I'm happy to report both Standard & Poor's and Moody's recognized EOG's growing financial strength. Standard & Poor's upgraded EOG's credit rating to A-, and Moody's changed EOG's outlook to positive.

We still expect to generate over $1.5 billion of free cash flow in 2018, assuming $60 oil prices. This is defined as discretionary cash flow less CapEx and dividend payments. The bulk of this free cash flow is anticipated to be generated in the second half of the year. Discretionary cash flow is forecasted to increase through the remainder of the year while our CapEx budget was more heavily weighted towards the first half of the year.

Up next, to provide details on our operational performance, is Billy Helms.

Thanks, Tim. I'm happy to report that our operational teams delivered the well results and volume growth projections that we anticipated at the start of the year.

In 2018, we are forecasted -- focused on increasing the net present value of our acreage through more efficient, larger development packages. Our 2018 capital plan was designed to increase our well inventory during the first half of the year in order to improve the operational flexibility for managing these larger development packages. As indicated on our last call, we expect to see more production growth in the third quarter, following the increase in activity and capital spend that was weighted towards the first half of the year. In addition, our decentralized organization operating in multiple basins gives us the flexibility to adjust our activity to take advantage of changing market conditions.

During the second quarter, our Eagle Ford oil production received favorable Gulf Coast prices that were nearly $3 per barrel higher than WTI. Premium Gulf Coast pricing may persist into next year, so we recently added 2 rigs in the Eagle Ford to build well inventory, providing us optionality as we begin to plan for 2019. I want to emphasize that we are still -- that we still expect to spend within our guided capital expenditure range, although most likely above the midpoint.

About 10 more Eagle Ford wells will be completed this year, with most of the additional inventory being carried into 2019. Operating in multiple basins makes this level of flexibility possible and is fundamental to our ability to deliver sustainable, long-term, high-return growth.

We remain focused on our goal of reducing well cost and cash operating cost by 5% this year. Our overall unit operating costs are trending down year-over-year. And while certain lease operating costs are showing signs of upward pressure, we've been able to offset that pressure with other unit cost savings in transportation and DD&A. Total unit costs are still expected to be down at least 10% this year. Looking ahead to 2019, we anticipate the industry will see some inflationary pressures possibly on the order of 5% to 10%.

As we do every year, we are working diligently to find creative solutions to keep our costs flat in the upcoming year. While drilling rigs and tubulars may see upward pressure, we are positioning ourselves to take advantage of pricing softness in other areas. We have good line of sight into our sand and water cost, which we expect to be down in 2019. We currently have about 50% of our 2019 oilfield service needs locked in at very competitive prices and are working to secure more of our service costs ahead of next year.

Finally, we'll continue to benefit from efficiency gains and reduced cycle times, obtained by optimizing well package size and increasing the use of multi-well pads and zipper fracs. Taken altogether, we think we are well positioned to keep costs at least flat in 2019.

I'll turn the call over to Ezra Yacob to provide you an update on the Eagle Ford and Delaware Basin plays.

Thanks, Billy. This quarter, we updated our premium inventory for our 2 largest oil assets: the Eagle Ford and the Delaware Basin, adding 520 net premium locations, primarily as the result of efficiency gains as well as productivity improvements. We added 145 net premium locations to the Eagle Ford, and in the Delaware Basin, we identified an additional 375 net location across our 4 plays.

The last major update to premium inventory for these assets was in early 2017. We have since drilled more than 500 net wells between the 2 basins, 270 in the Eagle Ford and 250 in the Delaware Basin. These 2 workhorse assets made up 73% of our oil production last year and 58% of our total production. With this update to premium locations, we effectively replaced the inventory we have drilled over the last 1.5 years.

Our Eagle Ford asset delivered another great quarter of consistent high-return results with 67 net wells brought online. Utilizing larger well packages, longer laterals and zipper fracs, we continue to incrementally push the boundaries of this world-class play every quarter, and it continues to deliver. Average lateral length on our western acreage is now approaching 2 miles while continuing to deliver excellent initial 30-day production rates. Wells drilled on our western acreage during the second quarter averaged more than 1,700 barrels of oil equivalent per day.

Increased drilling efficiencies are driving down drilling days even as we extend lateral lengths.

In fact, this year we are drilling the same total footage per month as we did in 2014 at the peak of our activity level and doing so with only half the rig count. Furthermore, our drilling team is achieving this performance while staying within a precision drilling window that is approximately 1/5 the size it was 4 years ago.

We've discussed the impact of precision targeting in the past. It is the #1 driver of well productivity and critical to optimizing net present value across our 520,000 net acres.

In the Austin Chalk, the average lateral length of the 5 wells drilled during the second quarter was the longest yet at 7,900 feet. Average initial 30-day production exceeded 3,000 barrels of oil equivalent per day. Austin Chalk wells on average pay out in just over 3 months.

We continue to examine the Austin Chalk's prospectivity in our South Texas Eagle Ford acreage. The target is less consistent than the Eagle Ford Shale. However, where it is prospective, it consistently delivers prolific results. Earlier this year, one of our first successful Austin Chalk wells, the Kilimanjaro, reached 1 million barrels of oil in less than 2 years, averaging more than 1,500 barrels of oil per day for 626 days. Furthermore, the play has an advantageous location with well-developed infrastructure close to the Gulf coast and benefits from our extensive seismic and log control collected through our Eagle Ford development program.

In our Delaware Basin asset, we brought 70 net wells to sales in the Leonard, Bone Spring and Wolfcamp plays. 20% of our Wolfcamp activity during the second quarter was in the Wolfcamp combo trend, a higher GOR play in Reeves County Texas. Over the last 18 months, we've been building out infrastructure to transition a portion of this asset into a core development area, and we are increasing activity commensurate with that construction.

We have captured a 120,000 net acre position across this trend, and the combination of increased operational efficiencies and well performance, permanent infrastructure and our natural gas processing contracts generate some of the highest net present value per well across the company. This quarter, we brought online 10 net wells averaging over 8,000 feet in lateral length and delivering 2,200 barrels of oil equivalent per day per well. We're excited to see this trend become a larger contributor to our portfolio, delivering in excess of 200% direct after-tax rate of return.

In our Leonard and Bone Spring plays, we completed one of the largest packages we've done to date. The State Viking wells in Loving County are a package of 13 wells drilled across 4 targets, 2 in the Leonard and 2 in the Bone Spring. The combined 30-day rate for this package was a staggering 21,000 barrels of oil equivalent per day or approximately 1,600 barrels of oil equivalent per day per well on laterals averaging about 4,500 feet.

In every one of our unconventional plays, determining optimal well spacing is critical to maximizing the net present value of each acre. Determining optimal well spacing is also a problem-solving exercise that requires balancing multiple variables. Drilling widely spaced wells to maximize initial production rates and early returns can prevent optimal asset development over the long run due to the parent-child effect. However, overly aggressive well spacing will also have a detrimental effect due to potential communication between wells and potential overinvestment. In each of our plays, we collect an extensive amount of robust drilling, completion and production data and integrate it with geologic analysis to build reservoir models. These complex models provide the basis to determine optimal development patterns to maximize the NPV of our acreage.

A basin as target-rich as the Delaware is a great example. During the first half of 2018, we drilled a number of spacing and development patterns across 6 different Upper Wolfcamp targets in different combinations across the play. One of these packages was the Quanah Parker 8H through 11H, a 4-well package drilled on our Texas acreage. Average 30-day IPs for the wells in this package were more than 2,500 barrels of oil equivalent per day per well on lateral lengths approaching 2 miles. The wells in this package were drilled 440 feet apart across 2 Upper Wolfcamp targets. This is some of the tightest spacing we've tested in the Wolfcamp to date, and these wells are generating an outstanding NPV of $10 million per well.

The Delaware Basin is still early in its development. Leveraging our experience and data from 15 years of developing unconventional resources across North America is a tremendous advantage in our efforts to maximize NPV across our 416,000-acre position.

Now I'll turn the call back over to Bill.

Thanks, Ezra. I would like to leave everyone with a few closing thoughts. Number one, EOG continues to solidly execute our 2018 premium drilling program. The company is delivering strong triple-digit direct well returns and strong double-digit U.S. oil growth.

Number two, EOG's exploration effort continues to deliver by organically generating premium drilling potential much faster than we drill it. This quarter's addition of 1.9 billion barrels of oil equivalent in the Powder River Basin is a remarkable and significant resource addition to our portfolio. Since permanently shifting to premium in 2016, we've essentially tripled our premium location count and more than quadrupled our premium resource potential.

Number three, EOG now has 11 premium options to efficiently deploy capital. Our multi-play options enhance our ability to deliver strong returns and growth consistently and sustainably over the long haul.

Number four, we're committed to a disciplined growth strategy. For the remainder of the year and as we look to start planning for 2019, you should expect EOG to remain disciplined about growth and capital allocation to maximize returns.

And number five, executing our premium strategy will grow production and cash flow, produce double-digit ROCE and fund dividend growth. More importantly, we can consistently deliver this performance over the long term and through commodity price cycles. We believe that is unique not just in the E&P industry but in any industry, and it is perfectly aligned with our ultimate goal to create significant shareholder value.

Thanks for listening. And now we'll go to Q&A.

(Operator Instructions) Your first question today will be from Doug Leggate of Bank of America Merrill Lynch.

Bill, I'm not sure who you want to direct this one to, but some time ago, I seem to recall you mentioning that Powder River had some of the best wells in the portfolio. Now that you've shown us what this can do by way of the additional inventory, how would you characterize how activity might evolve there relative to the other plays or [either] additive to the other plays in 2019?

Yes, Doug. This is David Trice. As far as the Mowry and the Niobrara go, those -- we'll be increasing activity in 2019 in those plays. The volume impact of those will be more likely weighted to late 2019 and on into 2020 as we build out our infrastructure there.

So I guess, we'll wait on the [capital]. I guess, there's no specifics you can give us at this time, but I'm presuming it's not going to get 2-rig program out there.

Well, as far as any specifics, we'll give the specifics in February when we give our 2019 plan.

Okay. I thought I would try anyway. But my follow-up is -- Bill, I kind of feel as if I ask you this question a lot nowadays. But the cadence of spending in the second half of the year given -- even at slightly above the midpoint of your guidance suggests that we're dropping off quite a bit to like a [1.25] type run rate. Is that realistic? And how would you start to think about, dare I say it, share buybacks? Are they ever going to be on the table, assuming you remain capital disciplined in, let's say, a $60 type of level? I'm just thinking about the amount of free cash you're generating this year, despite the guidance on the debt reduction, it still looks that you're going to be churning a great deal of free cash beyond your uses.

Doug, we constantly evaluate all of our options, and we are very, very committed to doing what's right for the long-term shareholders. As you know, we manage the company for a sustainable success over the long term. So currently, with the improving commodity prices, we believe certainly that the first thing we want to do is continue to reinvest in our premium drilling, very, very high rates of return, and continue to invest in organic exploration, right, that's produced these Powder River Basin results. And we're focused on debt reduction. And we're certainly focused on and very committed to the shareholders with a very strong dividend increase. And so at this point in the life of the company, that is certainly the best ways, we feel like, to continue to create long-term shareholder value and leave our options open and leave us flexible to do what's right for the shareholders in the long term.

So the first part of that question, sorry to push on this, but the drop-off in spending in the second half of the year, is that run rate about right? Can you maybe just give us an idea of what's driving the drop sequentially? And I'll leave it there.

Yes, Doug. This is Billy Helms. So the plan that we put together at the start of the year is consistent with the way it's being executed today. We planned about and actually completed -- about 40% of the wells in the company that were completed in the first half were Delaware Basin wells. That will decline in the second half of the year to about 30% of our overall completions. And on the flip side, our plays up in Rockies that we've talked about, the DJ, the Bakken and the Powder River Basin, will go from about 10% of our completions in the first half to about 20% of our completions in the second half. And so we're bringing in a mixture of just lower-cost wells in the second half of the year as compared to the first half of the year, which is why the spending rate is declined a little bit. The goal in the first part of the year was to build -- as we move to these larger packages wells, was to build up our inventory, and that gives us a lot of flexibility in managing these programs.

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

Gentlemen, I understand your excitement over the operational performance in the Powder River Basin. But it seems to me, especially with the stock trading off this morning, that the inventory is getting sort of bewilderingly large. And you repeated on the call that you're adding inventory faster than you drill it. Is -- you're up to 13 years of future drilling. Is there a terminal point for that which you don't need any more? Or perhaps would you shift to an ultra-premium well location metric or a higher hurdle so that it sort of becomes more meaningful at a given level?

Paul, I think our focus is certainly replacing and adding to our premium inventory, but is also very focused on improving the quality of the premium inventory. If you'll look at the slide, I believe it's Slide #8, you'll see that our inventory is growing very [vastly,] but at the bottom, it shows the per-well productivity and reserve potentials per well. And you can see that, that's also going up, too. So that went up again as we added the Powder River. And what that does, with multiple assets, that gives us the ability to continue to shift our capital based on returns. And that is what we're focused on, is maximizing and continuing to improve the returns in the company. And so that gives us more options and even better quality inventory to continue to do that. And it also gives us an option down the road, that if we're not going to drill that in a certain amount of time, we can certainly get value for that, maybe monetizing it or doing other things with it too. So generating more and better inventory is not a problem. That is a very good thing to do. And that's what we're focused on, and that's what's going to continue to create value for the company going forward.

So I guess what you're saying is that the per-well metric that you highlighted is effectively an increase to the definition -- an ongoing increase to the definition of a premium well?

Yes, so getting better as we continue to generate over time.

Right. I got you. And then the CapEx for this year was set at a lower price. I assume -- I forget the exact number, but it has been maintained despite higher prices. Can we -- really, a follow-up to Doug's question. Can we run this level of CapEx into the future because that becomes such an important way of looking at all this?

Well, we don't have any specific guidance for 2019 or forward. The message we -- and the way we're going to manage the company is we're going to stay disciplined, and we're going to stay focused on returns and not growth. So we'll spend and increase our CapEx only with discipline. Obviously, our cash flow is growing even if oil prices stay the same because our volume's going up. But we're not going to go so fast that we begin to have rising costs or we exceed the learning curve, and we're focused on developing each one of our properties at the maximum NPV and returns. And that takes discipline, and it takes time. And so we're going to focus and stay very disciplined going forward.

The next question will be from Leo Mariani of NatAlliance Securities.

I was hoping to dive a little bit more into the Powder River here. Just noticing that you haven't had a ton of wells in the Niobrara and Mowry. But as you're certainly coming out with a pretty robust inventory, I was hoping you can maybe just give us a bit more color, if there's a lot of industry wells that are sort of giving you confidence. And then also, just trying to get a sense of how the new Powder River plays rank in comparison to some of your other premium plays.

Yes, Leo. This is David Trice. So we've known for quite some time that the Mowry and the Niobrara have a lot of resource potential under our acreage. We began drilling on those actually in 2008 and 2009 as far as -- in the testing phase. So over the years, we've collected a lot of data. We've drilled 9 Niobrara wells and 9 Mowry wells since that time. We have 5 proprietary cores in the Mowry and 2 proprietary cores in the Niobrara in addition to all the publicly available data. So what this has allowed us to do is build over 1,700 full petrophysical models across the Powder River Basin. And what that really does is allow us to define the very best targets, also the resource in place and helps with our completions as well, which is really critical to the success of the plays. And then as you noted, I mean, there has been industry activity in the basin. There's been over 200 Niobrara wells drilled in the Powder River Basin and about 30 Mowry wells. So we can take all that data with all the petrophysical data and core data and we can build some very sophisticated reservoir models that we can really apply across a lot of our different plays and help us to understand both these plays. So all of that data that's been collected over the years has really helped. And then one of the biggest factors in converting this to premium is the fact that our cost structure has dramatically come down over the last several years. We've been able to kind of focus our drilling the last few years on the Turner, which is a higher permeability sandstone that's premium. And so as we've done that, we've gotten a lot better at executing in the Powder River Basin, and we've been able to bring down a lot of our drilling completions facility and the LOE cost over time. So as we mentioned in some of the calls and even in this call, we've set a lot of records over the several years. We -- in the Powder, we routinely drill these Turner wells, these are 2-mile wells, in 6 to 7 days, and our zipper frac operations allow us to complete up to 10 stages a day. So all of that really helps, and it really helps to deliver a really low finding cost. As you think about the low finding cost, that ends up flowing through to your corporate-level return. So that's going to drive the higher ROCE over time. So really, we do have quite a bit of data, and we've got quite a lot of experience in the basin.

Okay, that's helpful. I just wanted to shift gears a little bit over to the Delaware Basin. Just wanted to get you guys to talk a little bit high level about kind of what your exposure is to some of the weaker differentials there, and if you guys were able to maybe get a bunch of those barrels over to the Gulf Coast. And I guess if there is some exposure to the diffs, would you plan to reallocate capital going forward?

Leo, this is Lance. Thanks for the question. Yes, I mean, I think you can really see the value of our transportations really flowing through. I mean, when you look at our gas differentials, you can absolutely see, for the first quarter and the second quarter, relatively very little exposure related to Waha gas. And then for the oil differentials, I think what you're seeing there too, we've talked about 25% is kind of subject to the Mid-Cush. But when you look at our transportation that we have and then when you look at that with our kind of natural hedges that we have operationally, I mean, the large focus that we have in the Rockies, our big Gulf Coast exposure, it's really distilled, it's really diluted down. So when you really look at kind of the Mid-Cush exposure, even for the rest of this year, it's less than 10%. So when you add in our Mid-Cush hedges, I mean, we're very well insulated in terms of the differential related to the Permian. But I mean, maybe just to talk about the transportation. We've done an exceptional job there. I mean, we've got our Conan terminal. That's up and running kind of full speed. We're going to have 5 market connections there long term. And we're moving barrels to Cushing today. We've got capacity down to Corpus today. I mean, we don't talk a lot about it, but I mean, when you think about a lot of the new pipeline expansions that are going to be starting up starting in late '19 into 2020, I mean, EOG was a big reason why those got anchored. When you think about the Sunrise expansion that's going to be starting very quickly going into Cushing, that's EOG. When you think about Gray Oak pipeline starting up, we're going to have a position behind that with our terminal. So when we think not only '18, for the rest of this year and then also into 2019 and beyond, especially looking into late 2019 moving into 2020, we're effectively going to have very minimal, if any, Mid-Cush exposure. And that's the value of having a lot of optionality. Because, as -- what we've seen in other basins, as you see the infrastructure get built out and somewhat overbuilt, you don't want to have too much exposure into one market. Because as we think things -- see things going into 2020, in an overbuild situation, you could actually see a lot of strength actually in the Midland local market. So long term, we're going to have the flexibility to sell into all those markets.

The next question will be from Bob Brackett of Sanford Bernstein.

Talking a bit about the Powder River Basin. If I think about the way you've talked about those locations, it feels like there's a single landing zone in each of the Mowry and the Niobrara. We know that the Mowry and the Niobrara are regionally extensive. But your sort of acreage footprint is a subset of your total acreage, and you haven't even talked about more than half the targets out in the column there. How should we think about how well refined the numbers are for locations? And what's the potential they could grow?

Yes, Bob. This is David Trice again. Yes, on the Niobrara and Mowry, those do overlap. And so as you think about those -- what we've given you there is a subset of our acreage, and it's only the portion that we feel is premium. So all the locations are premium. If you think about how they overlap, pretty much 100% of our Niobrara will be codeveloped with the Mowry. So where the Nio is premium, the Mowry is also premium. And then the Mowry footprint is a little bit larger than the Niobrara footprint. And so if you think about that, about 60% to 65% of that area will be codeveloped with the Niobrara. So yes, we haven't really talked a lot about the other zones or anything like that, but that's always something we're working on. We're always testing new zones, trying to find better targets. And currently, in both the Niobrara and Mowry, we're focused predominantly on single zones, but we're also looking at potential to stack or stagger in either of those. So that's an ongoing process as we collect more data and get more tests in the ground.

The next question will be from Irene Haas of Imperial Capital.

If I may, to touch a little bit on South Texas, on your Austin Chalk. Right now, you got 582,000 net acres in the area. I was just wondering what percentage is prospective for Chalk and then in terms of the product mix, sort of oil, gas and NGLs. And can you cherrypick and move into the more kind of oily and liquids-rich windows?

Yes, Irene. This is Ezra Yacob. And as I mentioned in the opening remarks, this quarter, we brought on 5 wells there in the Austin Chalk in South Texas at an average lateral length of about 8,000 feet and over 3,000 barrels of equivalents per day. The oil mix on those was about 87%, and we continue to be very pleased, very happy with our Austin Chalk performance down in the South Texas acreage. Part of what makes it so prospective down there is that we've collected an awful lot of data while we've been developing and producing the Eagle Ford underneath the Austin Chalk. And so integrating that core data, the log data that we've collected, along with our seismic, we've really been able to map out and high-grade where we've been developing the Austin Chalk. As we've talked about in the past, it's geologically a bit of a complex play. Historically, the -- while the industry's success has been pretty inconsistent from well-to-well as there was more of a fracture play, we've really been focused on the matrix contribution in the Austin Chalk, making it a bit more repeatable. But outside of that, across our acreage and different GORs, I'm not sure if we're prepared to get into those details today.

May I follow up also? With your enhanced oil recovery, it looks like you guys have added some locations this year. Maybe a little color on what we should be looking forward to 2019. Is it going to be sort of consistent program that would be replicated each year? That's all.

Yes. Irene, again, we've been very pleased with our EOR performance in South Texas. As you know, that's a process that we really implement after the units or the drilling area is fully developed. And so there's kind of a quicker ramp-up over the first few years, and then there will be a little bit of a slowdown as we convert wells because we need to make sure that we're optimally developing for primary recovery. The production profile so far is falling right in line with our early models. We're expecting to produce an incremental 30% to 70% more than the primary recovery. And this year, we're on target to turn over approximately 90 wells onto the EOR process. And as far as the forecast out in 2019, I don't think we're prepared to give guidance on that at this time.

The next question will be from Christine Alfonso of Goldman Sachs.

It's Brian Singer actually. Wanted to stick in the Eagle Ford for the first question here. You added 145 new premium locations but still have substantial locations not classified as premium. Could you talk to the level of certainty that those non-premium locations could or will not become premium? And can you address your latest thoughts on well spacing in the Eagle Ford?

Yes, Brian. This is Ezra again. Let me -- hopefully, I'll hit on all those points here. In the Eagle Ford, so the first thing I'd mention is that inventory update for the Eagle Ford and the Delaware Basin, that's a snapshot in time. We continue -- between lowering well costs through operational efficiencies and increasing well productivity, continue to see and feel good about our ability to convert non-premium wells into the premium status. Today, we've got 7,200 total wells in our provided guidance on the Eagle Ford, and those are actual sticks on a map, with 2,300 of those approximately as premium, about 2,600 of those as drilled wells. And so that leaves roughly about 2,000 wells that are currently non-premium. And with the advancements we've made just in the last few years on operational efficiencies, I think we feel very good about being able to convert a large portion of those. I mentioned in the opening remarks we're averaging 10,000-foot laterals drilled out in the western Eagle Ford. And we brought on 22 wells this quarter, at that treated lateral length, and those wells were actually drilled in less than 7 days' time, again, in that precision target of just a 20-foot window. And so that, combined with our geologic understanding and our completions methodology to really keep that stimulation near wellbore and complex, I feel very good about increasing well productivity also. And then the second part of the question...

Spacing.

Was on the spacing side, that's right. Yes, we're developing currently between 330- to 500-foot spacing across the Eagle Ford. A lot of that is dependent on the different geologic trends that we're in, whether we're in the east or the west, whether or not there's more or less faulting in the area. Again, we strive not to get into kind of a one-size-fits-all manufacturing mode. That's exactly what we don't want to do. We try to integrate as much data as we collect, and we remain flexible to adjust our drilling patterns and our targeting based on the local geology across the asset base.

Great. And my follow-up also is on the topic of spacing, but shifting to the Delaware and the Wolfcamp. You've highlighted over multiple quarters about the expectations the industry could struggle a bit here on parent-child issues and spacing tests. And here, you're highlighting favorable results from your 440-foot spacing test in the Wolfcamp. Can you talk more about the implications of that, if any, across your acreage? How much acreage could be developed potentially at that spacing? And can you remind us what's built into your premium locations? And what milestones that you're looking for further?

Yes, Brian. This is Ezra again. Let me start with your last question there. Our type curve for the Wolfcamp oil window is -- and that's across 226,000 acres in the oil window. That's a 1.3 million barrel of equivalent gross type curve on a 7,000-foot lateral at 660-foot spacing. And that type curve, of course, is an average across the 220,000 foot -- 220,000 acres, excuse me. And so yes, what we've highlighted over the last couple of quarters are, we've been trying to optimize our spacing really with the focus on maximizing NPV for our acreage position. We've been happy year-to-date with our progress there. All of our Wolfcamp wells are performing at or above the type curve that we've released, so we're very, very pleased with that. Really, what happens across the play, I think the way to think about it is, especially in the Delaware Basin, the geology is pretty complex. There's just an abundance of targets. And so again, similar to how I referenced the Eagle Ford, the last thing we want to do is get going too fast and get into a manufacturing mode. I think the 440-foot spacing highlighted on the Quanah Parkers highlights a good spacing for that area and that geology, where those targets are applicable. I think with as many targets as there is in the Delaware Basin and in the Wolfcamp, there -- we think there's a tremendous amount of upside, but we're happy with what we've released right now. And as we gather more data and have more details for you, we'll certainly update you.

The next question will be from Michael Scialla of Stifel.

Lance, you mentioned in your prepared remarks about the midstream in the Powder River. It sounds like you're going to build out your own gathering system, and there's plenty of processing capacity. But I was wondering -- it looks like there's going to be a lot of gas coming out of the play. What are your thoughts about the end markets for that gas? Where is most of that going to go?

Yes. No, great question, Michael. I mean, one thing to remember too, I mean, we've been operating out here for a long time, so we actually have existing capacity on intrastate systems there today. And as you think about a lot of that residue gas, it kind of makes its way down to Cheyenne. And then from Cheyenne, we have other transportation arrangements that we can move further downstream from there too. So again, as we've looked back over time, when we look at making commitments, we're going to be really very disciplined about it. I mean, we're looking at all the macro things, what's going on up in Wyoming, looking at all the takeaway on the pipes. And then we also want to be very careful just from a transportation standpoint. We don't want to make transportation commitments at some different rates. As we know, things are going to change. Basis is going to change over time. So I'd say, to get you comfortable there, I mean, we're aware and familiar with all the markets. I mean we've been operating and marketing that area for a long time. And then as we look at layering in additional capacity over time, we're going to be very disciplined on that and ensure that it matches up. And like we've said in the past, we typically like to have anywhere from like kind of 70% to 80% of coverage like for the kind of first 3 to 5 years because [your kind of crystal ball is] so far looking out in what's happening out in the macro environment and with pricing. So that's traditionally how we like to set things up from a capacity standpoint looking forward.

Good. And I was just wondering, any update on the Anadarko Woodford? You guys had talked about it the prior quarter but not much this quarter. Just wondering where that stands.

Yes, Michael. This is David Trice. So on the Woodford, we were reasonably active there in the second quarter. We brought on a number of wells late in the quarter, including 2 4-well packages wells that are going to be spacing tests. And so as you know, the -- what we really like about that play is the high oil cut and the low decline nature of the play. So really, coming out with 24-hour IPs are really not that beneficial. So what we're really looking to do is provide a little more color in the next quarter on those larger packages.

The next question will be from David Heikkinen of Heikkinen Energy Advisors.

A couple of in-the-weeds questions. You commented that you had 2 Wolfcamp targets in the 440-foot testing. What was the hypotenuse between those? I know you gave the lateral at 440.

Yes, David. This is Ezra. You caught me off guard with the hypotenuse. I will say, in the vertical sense,, the spacing between those 2 targets is approximately 120 feet. And so 120 by 440, if you can do that math.

Yes. And then your operating expense guidance was up due to the higher workover expenses, and you expect that to trend down as your larger pads kind of get normalized. One question, when you -- for the offset wells post workover, did they come back to the prior production levels before they were frac impacted?

Yes, David. This is Billy Helms. Yes. What we've experienced in our play is we are successful in getting those wells pretty much back to what they were producing prior to the frac hits. I think one thing we've noticed in some of the plays, production from the offset is going to increase. And -- but in general, they do tend to come back to what they were producing prior to the cleanouts. And sometimes, it just takes a little longer in certain plays to react. We've learned a lot about how to manage those larger packages of wells and the lumpy nature of the production that we see as a result of those and then how to best manage the offset production and clean out the wellbores. So that's why it gives us confidence that our work -- expensed workover cost are going to trend down through the rest of the year.

How much downtime did you have? Like how many barrels was that, just curious, in the second quarter?

Well, it varies certainly by play. So -- and also based -- it varies a lot between -- so it's hard to give you a specific answer. But in each play, the amount of depletion that you have on that -- from the offset production prior to coming in with the new package affected the well spacing, the targeting, all those -- and how big the fracs are that you're putting on the new wells. All those play a role in how much the production is down, so it's hard to give you a specific number really based on that.

The next question will be from Robert Morris of Citigroup.

I think you've hit on almost all my questions. But I guess just following up on -- Ezra, you mentioned that the type curve is 1.3 million barrels gross for a 7,000-foot lateral and a 660-acre spacing on the Wolfcamp A. As you go down to 440-foot spacing, I know Slide 14 gives it on a 5,000-foot lateral basis, but what is -- what would you anticipate the degradation in the per-well EOR as you go to that tighter spacing?

Yes, Robert. This is Ezra. So that -- it's a little bit difficult to quantify. That 1.3 million barrels is an average across our 220,000 acres. Right now, the Quanah Parkers are outperforming that type curve on the 440. I don't want to mislead you and suggest that we're thinking 440-foot spacing is the correct spacing going forward across the entire 226,000 net acre position. Like I said, that's exactly kind of the route that we prefer not to go down to, is to get into a manufacturing mode. We really integrate our completions data, our reservoir data and our geology, most importantly, to rightsize each of these well packages for the area that we're drilling in. This is the approach that we've taken really in each of our plays that we've been developing throughout the kind of 15 years we've been developing unconventional horizontal plays. And so hopefully that gives you a little bit of color on the 440 there at the Quanah Parkers.

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, we want to thank each EOG employee for their contribution to another excellent quarter. 2018 is turning out to be a banner year for the company. We're achieving record returns on investment and record oil production while adding new premium drilling potential much faster than we drill it. EOG has a sustainable high-return business model and positioned to deliver long-term shareholder value.

Thank you for listening, and thank you for your support.

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