EOG Resources, Inc. (EOG) Q2 2018 Earnings Conference Call Transcript

EOG Resources, Inc. (EOG 0.47%)
Q2 2018 Earnings Conference Call
Aug. 3, 2018, 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

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.

Timothy K. Driggers -- Executive Vice President and Chief Financial Officer

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 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 plays, 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.

William R. Thomas -- Chairman and Chief Executive Officer

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 additions 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 cost, realized better than target prices across all three production streams, announced two 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 two 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 on 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 maximizes returns and NPV per acre.

Our production growth in 2018 is a result of investing in high-return premium drilling across nine plays in six 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 and our deep inventory of high-rated 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.

David W. Trice -- Executive Vice President, Exploration and Production

Thanks, Bill. Yesterday afternoon, we introduced two 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, over-pressured 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 fracks. Furthermore, these two resource plays overlap on much of our acreage, allowing development of both concurrently. Tightly spaced wells in co-development 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 three 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 two shale plays to our Powder River Basin premium inventory.

Currently, well costs in both plays are around $6 million for laterals approaching two 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 return 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 two 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.

In the Powder River Basin, it 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 our 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 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 six 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.

Lance Terveen -- Senior Vice President, Marketing

Thanks, David. The existing midstream presence in the Powder River Basin is strong. For liquids-rich natural gas, there are four 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, planning 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 three goals: 1) control, 2) lower operating costs, and 3) access to multiple markets.

Now, on the oil side, takeaway in the PRB is plentiful. The Casper and Guernsey hubs provide access to multiple refining markets, as well as the Salt Lake City and Denver markets. Other pipelines are available to access the Cushing market and we are studying all options, even the potential to move barrels to the Gulf Coast. Well head net backs today for lease sales are also strong and we currently anticipate the local market dynamics for oil and common state 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.

Timothy K. Driggers -- Executive Vice President and Chief Financial Officer

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 a $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 pay 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 $60.00 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. The discretionary cash flow is forecasted to increase through the remainder of the year while our CapEx budget was more heavily weighted toward the first half of the year.

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

Lloyd W. Helms -- Chief Operating Officer

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 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 in capital spend that was weighted toward 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 $3.00 per barrel higher than WTI. Premium Gulf Coast pricing may persist into next year, so we recently added two 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 still expect to spend within our guided capital expenditure range, although most likely above the midpoint. About ten 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 costs and cash operating costs 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 DVNA. 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 costs, which we expect to be down in 2019. We currently have about 50% of our 2019 oil field 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 fracks. Taken all together, we think we are well-positioned to keep cost at least flat in 2019.

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

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Thanks, Billy. This quarter, we updated our premium inventory for our two 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 locations across our four 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 two basins: 270 in the Eagle Ford and 250 in the Delaware Basin. These two workhorse assets made up 73% of our oil production last year 58% of our total production. With this update to premium locations, we effectively replaced the inventory we have drilled over the last year and a half.

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 fracks, 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 two 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 one-fifth the size it was four years ago. We've discussed the impact of precision targeting in the past. It is the No. 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 five 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 three 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 two 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've 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 ten 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 four targets, two in the Leonard and two in the Bone Spring. The combined 30-day rate for this package was a staggering 21,000 barrels of oil equivalent a 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 in earlier turns 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 over-investment.

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 six different Upper Wolfcamp targets in different combinations across the play. One of these packages was the Quanah Parker 8H through 11H, a four-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 two miles. The wells in this package were drilled 440 feet apart across two 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.

William R. Thomas -- Chairman and Chief Executive Officer

Thanks, Ezra. I would like to leave everyone with a few closing thoughts. No. 1, 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.

No. 2, 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.

No. 3, 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.

No. 4, 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 No. 5, 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.

Questions and Answers:

Operator

Thank you. The question-and-answer session will be conducted electronically. If you would like to ask a question, please do so by pressing "*1" on your touchtone phone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press "*1" on your touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing "*2". We will pause for just a moment to give everyone an opportunity to signal for questions.

Your first question today will be from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks. Good morning, everybody. 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 be additive to the other plays in 2019?

David W. Trice -- Executive Vice President, Exploration and Production

Yeah, Doug, this is David Trice. As far as the Mowry and the Niobrara go, 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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

So, I guess there's no specifics you can give us at this time, but I'm presuming it's not going to be a two-rig program. Is that fair?

David W. Trice -- Executive Vice President, Exploration and Production

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

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Okay. Thank you. 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 1.25 type run rate. Is that realistic? And how are you starting to think about, dare I say it, share buybacks? Are they ever gonna be on the table, assuming you remain capital disciplined on a, let's say, a 6-year-old 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 like you're going to be turning out a great deal of free cash beyond your uses.

William R. Thomas -- Chairman and Chief Executive Officer

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, like 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 way 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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

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

Lloyd W. Helms -- Chief Operating Officer

Yeah, 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 the 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 has declined a little bit. The goal in the first part of the year was to build, as we moved to these larger packages of wells, was to build up our inventory. That gives us a lot of flexibility in managing these programs.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

That's really helpful, guys. Thanks so much.

Operator

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

Paul Sankey -- Mizuho Securities -- Analyst

Hi. Good morning, everyone. 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. You're up to 13 years of future drilling. Is there a terminal point for that at which you don't need anymore? 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? Thank you.

William R. Thomas -- Chairman and Chief Executive Officer

Well, I think our focus is certainly replacing and adding to our premium inventory but it's also very focused on improving the quality of the premium inventory. If you'll look at the slide, I believe it's Slide No. 8, you'll see that our inventory is growing very fast 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 the value for the company going forward.

Paul Sankey -- Mizuho Securities -- Analyst

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?

William R. Thomas -- Chairman and Chief Executive Officer

Yes. They're getting better as we continue to generate over time.

Paul Sankey -- Mizuho Securities -- Analyst

Right. I've got you. And then the CapEx for this year was set at a lower price, I assume. I forget the exact number. But it's been maintained despite higher prices. 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? Thanks.

William R. Thomas -- Chairman and Chief Executive Officer

Well, we don't have any specific guidance for 2019 or forward. The methods and the way we're going to manage the company is we're gonna stay disciplined and we're gonna 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 is going up. But we're not gonna 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. So we're gonna focus and stay very disciplined going forward.

Paul Sankey -- Mizuho Securities -- Analyst

Thank you.

Operator

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

Leo Mariani -- NatAlliance Securities -- Analyst

Hey, guys. I was hoping to dive a little bit more into the Powder River here. I'm just noticing that you haven't had a ton of wells in the Niobrara and Mowry but you guys are certainly coming out with a pretty robust inventory. I was hoping you could 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.

David W. Trice -- Executive Vice President, Exploration and Production

Yeah, 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 nine Niobrara wells and nine Mowry wells since that time. We have five proprietary cores in the Mowry and two proprietary cores in the Niobrara, in addition to all of 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 it helps with our completion as well, which is really critical to the success of the plays.

And then, as you noted, 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 to 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 LOE costs over time. So we've mentioned in some of these calls and even this call, we've set a lot of records over several years in the Powder. We routinely drill these Turner wells -- these are two-mile wells -- in 6-7 days. And our zipper frack operations allow us to complete up to ten stages a day.

So all that really, really helps and it really helps deliver a really low finding cost. As you think about the low finding cost, that ends up flowing through to your corporate level returns. 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 a lot of experience in the Basin.

Leo Mariani -- NatAlliance Securities -- Analyst

Okay. That's helpful. I just wanted to shift gears a little bit over to the Delaware Basin. I 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 are 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 play to reallocate capital going forward?

Lance Terveen -- Senior Vice President, Marketing

Leo. Hey, this is Lance. Hey, thanks for the question. Yeah, 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 in gas. And 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 we 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 then 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 five market connections there long-term. We're moving barrels to Cushing today. We've got capacity down in Corpus today. I mean, we don't talk a lot about it, but 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 the big reason why those got anchored. When you think about the Sunrise Expansion that's going to be starting very quickly going in to 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 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 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've seen things, and 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 in to all those markets.

Leo Mariani -- NatAlliance Securities -- Analyst

Okay. That's a great answer. Thanks.

Operator

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

Bob Brackett -- Sanford C. Bernstein -- Analyst

Good morning. 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?

David W. Trice -- Executive Vice President, Exploration and Production

Yeah, Bob, this is David Trice again. Yeah, 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 co-developed with the Mowry. So where the Niobrara 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 co-developed with the Niobrara.

So, yeah, 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 the 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.

Bob Brackett -- Sanford C. Bernstein -- Analyst

Great. Appreciate it.

Operator

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

Irene Haas -- Imperial Capital -- Analyst

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

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, Irene, this is Ezra Yacob. And, as I mentioned in opening remarks, this quarter, we brought on five 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 in 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, while the industry's success has been pretty inconsistent from well to well, as it 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.

Irene Haas -- Imperial Capital -- Analyst

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 in 2019. Is it going to be sort of a consistent program that would be replicated each year? That's all.

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, 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 unit 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.

Irene Haas -- Imperial Capital -- Analyst

Thank you.

Operator

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

Brian Singer -- Goldman Sachs -- Analyst

Hi, it's Brian Singer actually. Thanks. Good morning. I wanted to stick in the Eagle Ford for the first question here. You added 145 new premium locations. 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 could you address your latest thoughts on well spacing in the Eagle Ford?

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, Brian, this is Ezra again. 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. To date, 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 and 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 seven 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 well bore and complex, I feel very good about increasing well productivity also.

And then the second part of the question was on the spacing side. That's right. Yeah, 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.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you. And my follow-up also is on the topic of spacing but shifting to the Delaware and the Wolfcamp. You highlighted over multiple quarters the expectations that 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 could you remind us what's built into your premium locations and what milestones that you're looking for further?

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, Brian, this is Ezra again. Let me start with your last question there. Our type curve for the Wolfcamp oil window, 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 on 660-foot spacing. And that type curve, of course, is an average across the 220,000 acres. And so, yeah, what we've highlighted over the last couple of quarters are we've been trying to optimize our spacing, really with a focus on maximizing the 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 Parker 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, 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.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Operator

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

Michael Scialla -- Stifel Nicolaus -- Analyst

Yeah, good morning. Lance, you mentioned in your prepared remarks about the midstream in the Powder River. It sounds like you're gonna 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?

1. Lance Terveen -- Senior Vice President, Marketing

Yeah, no, great question, Michael. I mean, one thing to remember, too, 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 very disciplined about it. I mean, we're looking at all the macro things. What's going on up in Wyoming? We're looking at all the takeaway on the pipes.

And then we also want to be very careful just from a transportation standpoint. I mean, we don't want to make transportation commitments at 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 of all the markets. I mean, we've been operating in marketing in 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 70% to 80% of coverage for the first 3-5 years. Because your crystal ball so far, looking out and what's happening out in the macro environment and with pricing. And so that's traditionally how we like to set things up from a capacity standpoint looking forward.

Michael Scialla -- Stifel Nicolaus -- Analyst

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

David W. Trice -- Executive Vice President, Exploration and Production

Yeah, 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 two four-well packages. Wells that are going to be spacing tests. And so, as you know, 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.

Michael Scialla -- Stifel Nicolaus -- Analyst

Very good. Thank you.

Operator

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

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

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

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, David, this is Ezra. You caught me off guard with the hypotenuse. I will say, in the vertical sense, the spacing between those two targets is approximately 120 feet. So 120 by 440, if you can do that math.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Yep. 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. For the offset wells post-workover, did they come back to the prior production levels before they were frack impacted?

Lloyd W. Helms -- Chief Operating Officer

Yeah, David, this is Billy Helms. Yeah, what we experienced in our plays is we are successful in getting those wells pretty much back to what they were producing prior to the frack hits. I think one thing we've noticed in some of the plays is that production from the offsets can increase. 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 well bores. So that's why it gives us confidence that our expense workover costs are going to trend down through the rest of the year.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

How much down time did you have? Like how many barrels was that? Just curious. In the second quarter.

Lloyd W. Helms -- Chief Operating Officer

Well, it varies certainly by play. And also 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 from that offset production prior to coming in with the new package affects it. The well spacing, the targeting, all those, and how big the fracks 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.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Alright. Thanks, guys.

Operator

The next question will be from Robert Morris of Citigroup. Please go ahead.

Robert Morris -- Citigroup -- Analyst

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

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

Yeah, Robert, this is Ezra. So 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 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 right-size 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 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.

Robert Morris -- Citigroup -- Analyst

No, I appreciate it. I understand it's a lot of data and it's very complicated so I appreciate that. Thanks.

Operator

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.

William R. Thomas -- Chairman and Chief Executive Officer

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 is positioned to deliver long-term shareholder value. Thank you for listening and thank you for your support.

Operator

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

Duration: 61 minutes

Call participants:

Timothy K. Driggers -- Executive Vice President and Chief Financial Officer

William R. Thomas -- Chairman and Chief Executive Officer

David W. Trice -- Executive Vice President, Exploration and Production

D Lance Terveen -- Senior Vice President, Marketing

Lloyd W. Helms -- Chief Operating Officer

Ezra Y. Yacob -- Executive Vice President, Exploration and Production

David J. Streit -- Vice President, Investor and Public Relations

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Paul Sankey -- Mizuho Securities -- Analyst

Leo Mariani -- NatAlliance Securities -- Analyst

Bob Brackett -- Sanford C. Bernstein -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Michael Scialla -- Stifel Nicolaus -- Analyst

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Robert Morris -- Citigroup -- Analyst

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