Continental Resources, Inc.

Rory R. Sabino - Continental Resources, Inc.

Harold G. Hamm - Continental Resources, Inc.

Jack H. Stark - Continental Resources, Inc.

John D. Hart - Continental Resources, Inc.

Gary E. Gould - Continental Resources, Inc.

Tony Barrett - Continental Resources, Inc. Pat Bent - Continental Resources, Inc.

Ramiro F. Rangel - Continental Resources, Inc.

Drew Venker - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Arun Jayaram - JPMorgan Securities LLC Brian Corales - Johnson Rice & Co.

LLC Kashy Harrison - Simmons/Piper Jaffray & Co. Brian Singer - Goldman Sachs & Co.

LLC John A. Freeman - Raymond James & Associates, Inc.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Brad Heffern - RBC Capital Markets LLC Derrick Whitfield - Stifel, Nicolaus & Co., Inc. Subash Chandra - Guggenheim Securities LLC David Earl Beard - Coker Palmer Institutional Leo P.

Mariani - NatAlliance Securities Joseph Allman - Robert W. Baird & Co., Inc.

Good morning. Thank you for joining us.

I would like to welcome you to today's earnings call. We'll start today's call with remarks from Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President; and John Hart, Chief Financial Officer.

Also on the call and available for Q&A later will be Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Tony Barrett, Vice President-Exploration; Pat Bent, Senior Vice President-Drilling; Gary Gould, Senior Vice President-Production and Resource Development; Steve Owen, Senior Vice President-Land; Ramiro Rangel, Senior Vice President-Marketing and Human Resources; and Adam Longson, Director of Commodity Research. Today's call will contain forward-looking statements that address projections, assumptions, and guidance.

Actual results may differ materially from those contained in forward-looking statements. Please refer to the company's SEC filings for additional information concerning these statements and risks.

In addition, Continental does not undertake any obligation to update forward-looking statements made in this call. Also this morning, we will refer to initial production levels for new wells, which unless otherwise stated are maximum 24-hour initial test rates.

We will also reference rates of return, which unless otherwise stated are based on $70 per barrel WTI and $3 per Mcf natural gas. Finally, on the call, we will refer to certain non-GAAP financial measures.

For a reconciliation of these measures to Generally Accepted Accounting Principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com. With that, I will turn the call over to Mr.

Hamm. Harold?

Thanks, Rory. Good morning, everyone.

Welcome to our second quarter 2018 earnings call. Over the past three and a half years, our industry has labored to overcome the ill-advised oversupply of oil.

Today, however, the macro look good for the supply and demand oil cycle as annual demand growth nears 1.8 million barrels per day in the strong global economy. Our highly tuned and efficient company is well-positioned to benefit over the next several years as a result of this rebalanced market condition that suits our particular inventory of American oil production.

The Mid-Continent SCOOP and STACK in the Williston Basin, Bakken are not hampered by restricted oil takeaway infrastructure and have additional opportunities for its high-grade and quality crude oil to access the waterborne export market as additional large capacity pipelines are adverse (3:34) to deliver oil to the Gulf for export. I'm excited to discuss the announcement made earlier this week on our minerals transaction, which consisted of a divestiture and new relationship that is expected to enhance shareholder value for many years to come.

Continental created a new business unit and subsidiary for the sole purpose of acquiring oil and gas mineral interest in our future drilling program to increase our net revenue interest. We are pleased to announce this newly formed relationship with a firm that has a long, distinguished track record of success in the precious metals and mineral ownership business, Franco-Nevada.

Both companies will benefit from an expanded mineral acquisition format over the next several years, targeting our near-term drilling in our oil and gas plays as defined by our technical teams. As we described in our earnings release, Continental will apply the initial proceeds of approximately $220 million to partially fund CapEx spend on minerals, which effectively reduces the $400 million additional CapEx spend in 2018 to $180 million.

Congratulations to the teams of both companies for this new and exciting relationship. We've previously disclosed second quarter production and the factors that impacted it.

Our second quarter production fell just slightly below our 285,000 Boe to 290,000 Boe per day guidance due to abnormally wet weather in the Bakken, along with our decision to temporarily curtail gas production in Oklahoma due to the upcoming completion of the Project Wildcat pipeline, which is delivering to the premium market in the Dallas-Fort Worth area. We estimate we would have been approximately 5,000 Boe per day higher if not for these events.

Second quarter production was a transitory event as production quickly recovered in July. Our net income for the second quarter is $242.5 million.

And as in the first quarter, we're delivering on our guidance of positive cash flow growth, and which we are well on our way with our debt goal as evidenced by our recent call of $400 million of bonds. Incidentally, it appeared we're the only unhedged oil producer in our peer group able to fully participate in these higher oil prices we have today.

As we have stated before, we're returns-driven at Continental and our oil-focused drilling and development as well as our entrepreneurial innovation propel our industry leading performance. Today, we will focus on Continental's oil development, which represents 95% of our activity and go-forward budget for 2018 as a follow-up on the shift in drilling resources we talked about briefly last quarter.

Leading in the rates return category are the North Dakota, Bakken and Oklahoma Springer plays with 150% plus rates of return. Both these plays will contribute to a wave of new oil production beginning in the third quarter and growing both second half 2018 and full year 2019 production numbers in terms of both production and oil percentage.

Let's review the Bakken, first. Our Northern team at Continental has positioned us very well in this higher-price environment by improving our type curve once again.

Our new improved type curve announced this quarter is based on a higher completion stage count and more entry points along the lateral, and it further improves the type curve announced earlier in the year. The new higher 1,200 MBoe EUR type curve generates 175% rate of return at $70 oil, based on $8.4 million CapEx per well.

Continental is the largest producer and leaseholder in the Bakken, which positions us for additional oil production growth for many years to come. Secondly, the 85% oil Springer row development at Project SpringBoard is proceeding nicely with drilling underway, and both drilling and completion operations to be systematically executed in very near future.

Production from the first row is due to begin September with up to 18 wells producing by year-end, thereby adding to the 2018 exit rate as well as to the new oil production wave for 2019. Next, our STACK activity has been focused on the over-pressured oil window, which continues to produce great wells such as Swaim number 3 at 3,476 Boe per day, which includes 2,596 barrels of oil per day; and the Madeline number 2 at 3,540 Boe per day, which includes 2,548 barrels of oil per day, all high rate of return oily producers.

In addition, we just set a record for the fastest STACK well drilled to date. The Quintle number 4 well TD-ed in just 19.3 days.

Then there's the oil from Woodford formation SCOOP SpringBoard. You'll hear much more about this in the coming quarters, but we have begun an orderly and systematic development with four rigs at this time in the Williams and Parr (09:32) unit.

This is another high rate of return oil project area that Jack will talk more about today. At Continental, we have always been all about oil, and we certainly are today.

As a leading low-cost producer with outstanding drilling inventories and the best oil plays in America, our focus on capital efficient growth, free cash flow and corporate returns will provide the combination of long-term growth and value creation for the company. During the period of oversupply and rebalancing, Continental remain very disciplined and diligent on our mission to reduce cost.

We needed an opportunity to take advantage of what we believe are favorable market conditions for Continental and its shareholders. We believe we would be remiss if we did not move when presented with this unique opportunity considering the great potential Continental has in oil, not only the Bakken, but also in the SCOOP.

So, we have elected to accelerate the net asset value of our oil portfolio, while other basins remain constrained by lack of oil and gas infrastructure. The drilling and completion portion of this added investment will be focused on accelerated development of the oil-weighted assets, and increasing recoveries from the reservoirs.

Efficiencies also represent a big part of the investment as we expect to complete 16 additional net wells during the year. The added D&C investment boost our annual production guidance to an average of 290,000 Boe to 300,000 Boe per day and increase our projected exit rate to 315,000 Boe to 325,000 Boe per day.

And again, we're using a very disciplined and guarded approach to additional growth and value creation. Jack will discuss the proportional distribution of the increase per play.

Jack?

Thank you, Harold, and good morning, everyone. Appreciate you joining us on our call today.

As Harold pointed out, we have increased our annual production and exit rate guidance for 2018, and there are three principal drivers for this uplift. First, we expect to complete up to 16 more net wells this year due primarily to the reallocation of rigs to higher-working interest wells with shorter cycle times in the oil windows of SCOOP and STACK.

Second, our Bakken wells are outperforming expectations as we move from 40-stage to 60-stage completions as our new standard. Third, we plan to exit 2018 with 26 rigs, up 3 rigs from the 23 rigs we have drilling today.

Combined, these strategic moves are expected to uplift production in the second half of 2018, particularly in the fourth quarter and we raised our exit rate guidance 10,000 Boe per day above prior guidance. With 95% of our rigs focused on oil, we also project our crude oil production will approach 60% in December.

These moves will provide a significant boost to the company's performance in 2019. To fund this additional activity, we've increased our drilling and completion CapEx for 2018 by $200 million.

This includes $125 million of new capital and $75 million of reallocated capital from our original 2018 non-D&C budget. Approximately one-third of this capital is allocated to the Bakken and two-thirds is allocated to SCOOP and STACK.

In the Bakken, the bulk of the capital will fund our shift to 60-stage completions. We also expect to complete up to two additional net wells and add one rig by year-end.

Moving from 40 to 60-stage completions has increased our Bakken type curve EUR another 9% to 1.2 million Boe per well. This shift is based on results from 70 wells that clearly show our 60-stage completions are outperforming our previous 40-stage completions.

Now for perspective, I want to remind everyone that this is our second type curve uplift over the past 12 months and, cumulatively, we've uplifted our Bakken type curve EUR 22% and doubled the rate of return to 175% by optimizing our completion techniques. This translates to an additional $3.5 million of incremental first year cash flow per well with the payouts as little as seven months.

This is a great example of how our teams continually work to maximize the value of our top-tier assets for Continental shareholders. In SCOOP and STACK, the capital will fund the completion of up to 14 additional net wells due to the improved operating efficiencies and the reallocation of rigs from our carried position in the SK-JDA to a non-carried higher working interest wells in the oil and condensate windows.

We also plan to add two rigs to Project SpringBoard by October to accelerate development there. Now, let's focus on some of the second quarter results.

In Bakken, we continued to deliver record results from our optimized 60-stage completions over an expanding cross-section of our acreage. We completed 35 gross operated wells during the second quarter, flowing at an average initial rate of 2,280 Boe per day with 80% of the production being oil.

4 of the 35 wells made Continental's top-10 list of Bakken producers based on 30-day production rates. One well was a record Bakken producer for the company, flowing at an average 30-day rate of 3,100 Boe per day.

If you look at slide 9, you can see these wells and where they're located, and you can see they are about 40 miles from each other, once again demonstrating the widespread success of Continental's optimized Bakken completions. Similar results are being experienced by other operators throughout the (15:23).

And in a recent report, IHS defined this expanding footprint of outstanding wells as the new fairway for the Bakken. This step-change in performance comes at a great time as the North Dakota Industrial Commission estimates up to 45,000 wells remain to be drilled in the Bakken field, and Continental currently has over 4,000 operated wells in inventory.

So bottom line, the Bakken continues to stand out as the premier oil play in the U.S. Moving on to Oklahoma, I will begin with STACK, where we are starting to see results from the rigs we shifted into the oil and condensate windows.

We completed five strong oil producers that flowed at initial rates ranging from 3,065 Boe to 4,030 Boe per day with 47% to 75% of the production being crude oil. Details of the wells are shown on slide 16 of our deck.

We continue to be very pleased with our results from STACK and plan to keep four rigs focused on unit development in the oil and condensate windows. In SCOOP, our activity is focused primarily on Project SpringBoard, which is a high-impact crude oil project that could add as much as 10% to the company's oil production over the next 12 months.

SpringBoard was announced last quarter, so as a reminder, this is a massive multiyear stacked pay crude oil project with up to 400 million Boe of gross unrisked resource potential, and 70% to 85% of this production is expected to be crude oil. The project is about 70 square miles in size with up to 350 potential locations to be drilled.

This includes around 100 Springer and up to 250 Woodford and Sycamore locations. Continental will operate the project with an impactful average working interest of 75%.

Because of the sheer size of SpringBoard, we expect to realize significant cost savings, driven in large part by road development strategies. Our teams have already saved around $1 million on the cost of drilling Woodford and Sycamore well by eliminating the need for intermediate pipe.

In the Springer, our teams are targeting up to $1 million of additional savings per well through technologies they are currently testing and efficiencies they expect to gain as the project develops. Now, in addition to the cost savings, SpringBoard has significant marketing advantages due to its location and strategic planning by our marketing team.

From a crude oil marketing standpoint, we expect to realize the best netbacks in the company from SpringBoard as pipeline infrastructure is already in place providing access to premium markets. If you look on slide 15, you will see that our midstream provider's oil pipeline goes right through SpringBoard, with an oil terminal strategically located in the center of the project.

This pipeline connects directly with a refiner only 50 miles away and provides optionality to go to Cushing via pipe approximately 100 miles away. As a result, the differential for SpringBoard oil is expected to run under $2 a barrel.

Likewise, our natural gas has access to premium pricing through Enable's Wildcat pipeline that became fully operational in July. Under our agreement, Continental has 400 million cubic feet of firm transportation on Wildcat to the Tolar Hub.

We also plan to install a company-owned water recycling and distribution system in the near future to provide efficient use of our water resources and manage costs. And on top of all this, SpringBoard is located in our own backyard, just 40 miles from our corporate headquarters.

Doesn't get much better than that, and the great news is we have similar projects on the horizon. Now, the development of SpringBoard is divided into two phases, with phase one focusing on the Springer reservoir, and phase two focusing on the Woodford and Sycamore reservoirs.

Both phases are now drilling with seven rigs focused on the Springer and seven rigs focused on the Woodford/Sycamore. We expect to have six rigs drilling in the Woodford and Sycamore by October.

If you look at slide 13 in our deck, I will explain what development looks like from a purely logistical and timing standpoint. Phase I includes 29 Springer units, with three to four additional wells planned for each unit.

The units had been divided into four rows with plans to develop one and possibly two rows at a time. Phase one is on schedule, with 7 of the 18 Springer wells in row one drilled and waiting on completion.

First production from Phase I should begin in September, and we expect to have up to 18 Springer wells online by year-end, including around 3 in the third quarter and up to 15 in the fourth quarter. Phase II includes 32 Woodford and Sycamore units that are offset 1 mile from our Springer units to allow for simultaneous development.

We currently plan to drill up to five additional Woodford wells and three Sycamore wells in each unit. Production from Phase II should begin during the first quarter of 2019.

Now, as I conclude my comments, I want to emphasize that our uplift to production and CapEx guidance are completely driven by the outperformance both by our teams and our assets and significant operator efficiencies lie ahead. As a result, we expect to remain one of the lowest-cost oil-weighted producers amongst our peers.

Bottom line, we are just starting to realize the true value of our assets as we begin to harvest the deep inventory we've assembled in three of the top plays in the U.S. With that, I'll turn it over to John.

Thank you, Jack. Good morning, everyone.

Our continued focus is predicated on a disciplined approach to production growth, driving strong free cash flow generation and enabling continued debt reduction. First of all, I'm happy to report that during June we achieved our near-term debt target of dropping below $6 billion in net debt.

At the end of June, we were slightly above that level due to working capital timing and mineral acquisitions. On July 12, we announced the partial redemption of our 2022 bonds.

Continental will redeem $400 million or 20% of the $2 billion in aggregate principal amount currently outstanding of our 5% senior notes. The redemption is scheduled to take place on August 16, 2018 and will be funded through a combination of cash on hand and availability under the revolver, which is currently undrawn.

Any such revolver uses is expected to be repaid over the course of the next few months from available free cash flow. Overall, we are making good progress towards our ultimate debt goal of $5 billion or lower.

As such, we anticipate additional bond calls in the not-too-distant future. You may recall that our original 2018 guidance was for us to generate $800 million to $900 million in free cash flow at $60 WTI during the year.

On the last call, we indicated that with prices continuing to strengthen and with our oil being unhedged, we were on track to approach approximately $1 billion in free cash flow for the year. Our estimates remain strong, allowing for us to invest in our minerals relationship and accelerate our focus on oil projects.

Let's take a moment to update you on cash flow in light of these investments. Our new CapEx budget includes $275 million for acquired minerals that we have either already closed on or anticipate closing on before yearend.

As we announced on Monday at the closing of the new relationship with Franco-Nevada, we expect to receive approximately $220 million as Franco acquires an interest in a newly formed subsidiary that will focus on mineral acquisitions. Closing is anticipated in the fourth quarter.

Upon closing, the proceeds of Continental's cumulative divestiture since 2016 will exceed $1 billion in proceeds with very nominal associated production. Our divestiture program has focused on realizing appropriate value, not rushing to divest.

You may recall that we'd previously indicated we were working on a novel approach to enhance shareholder value and reduce debt. We view our strategic relationship with Franco-Nevada as just such a venture, which leverages Continental's proprietary knowledge and expertise to create value while minimizing our capital required to grow this venture and still providing for debt reduction.

This relationship is the first of its kind, combining a proven inventory-rich operator with a leading royalty corporation to actively acquire and develop minerals. As noted in each company's respective releases, we are in the process of building a significant mineral position ahead of future drilling.

Our focus is on the undeveloped acreage in SCOOP and STACK. As we develop these areas, we will capture incremental value through mineral ownership and producing units.

While the revenue generated by minerals today is small, we expect to see accelerated growth as early as 2019 as Continental continues development in areas where we have acquired minerals. As mineral revenues grow, we anticipate this venture to generate solid cash flow relatively quickly.

As an example of the prospective value of our minerals, in one area, Project SpringBoard, our new minerals venture owns an average of 10% of the minerals under the 35 1,280-acre units, representing approximately 4,300 acres. Across the broader minerals position, we expect the majority to have associated production over the next two years as we proceed with development.

As Continental is initially acquiring the minerals, the acquisition will be accounted for as a capital expenditure by Continental with a subsequent recoupment from Franco-Nevada of their share of the acquisition cost. Thus, our CapEx budget will be grossed up a bit, but I would encourage you to consider the net.

We will participate in mineral revenues between 25% and 50% based upon achieving certain predetermined targets. We anticipate fully achieving these targets and realizing 50% of future revenues in the foreseeable future.

Over the next three years, we anticipate an additional $300 million investment by Franco-Nevada with an associated $75 million investment by Continental. In essence, an 80%-20% carry structure.

I would echo Harold's earlier sentiments and congratulate each of the company's teams on establishing a new vehicle expected to build significant value for each company. We anticipate that you likely will want additional details on our new venture such as acreage numbers, per acre cost and other items of that nature.

While we respect your need for details to model our new venture, please respect that we are in the midst of building our acreage position in a very competitive market and we will need to remain silent on some of the particulars today. A key takeaway observation is that we anticipate growing from a relatively small venture today to one with a significantly meaningful valuation in the next few years.

Transitioning to our broader guidance, our updated change in operating plans will specifically benefit the fourth quarter of 2018 with an even greater benefit occurring in 2019. Accordingly, we increased our full year production guidance to a range of 290,000 Boe to 300,000 Boe per day.

Our exit rate guidance was also increased to 315,000 Boe to 325,000 Boe per day, indicating strong momentum entering 2019. Capital efficiency is holding strong and our cost estimates are in line with expectations.

As such, we are tracking towards the top end of our guidance range of 10% to 15% for return on capital employed. We expect continued improvement in capital efficiency moving into 2019 with enhanced well productivity and efficiency.

The net effect of these items, inclusive of strong commodity prices and proceeds of the mineral divestiture, is a net usage of $55 million for minerals and $125 million for drilling and completion or $180 million all in. This will leave us with the expected free cash flow of $800 million to $900 million for 2018, currently tracking towards the higher end of this range, providing significant momentum for continued debt reduction.

This estimate includes the $275 million for CapEx for minerals as well as the $220 million associated recoupment to properly reflect projected cash flow. We continue to be on track to be in the 1.5 times annualized debt to EBITDAX range by the end of the year.

Further, we expect year-end net debt to be between $5.5 billion and $5.7 billion with further debt reduction anticipated in 2019. Revenue for the second quarter was a strong $1.1 billion, 72% higher than the comparable prior year quarter.

Net income for the second quarter was $242 million, or $0.65 per diluted share. Adjusted to remove items typically excluded by the investment community and published estimates, we posted an adjusted net income of $273 million or $0.73 per diluted share for the second quarter, driven by strong price realizations and cost efficiency.

Non-acquisition capital expenditures were $714 million, up $118 million from the first quarter due to faster cycle time improvements along with other changes in our operating plans and mineral acquisitions. Production was 26% higher than the second quarter of 2017 at just over 284,000 Boe per day.

As previously discussed, we expect third quarter production to be between 290,000 Boe and 295,000 Boe per day. July production is above this range.

But as we have pure completions coming online near term, due to the timing of pads, we expect production to naturally decline before beginning to grow again as we move through the balance of the year. As more projects come online in the back half of the year, production is expected to ramp up, like it did in 2017.

We expect strong oil growth in the next two quarters with the oil ratio approaching 57% in the third quarter and the fourth quarter to be comfortably within a range of 58% to 60%, reflecting a significant level of Bakken completion and initial results from Project SpringBoard in the back half of the year. Overall, our selected second quarter cash costs were in line with guidance.

G&A, excluding equity compensation, was $1.41 per Boe and production expense was $3.49 per Boe. Production expense was impacted by June weather and workovers in North Dakota, as well as gas curtailment in Oklahoma.

Although year-to-date production expenses of $3.54 per Boe are currently outside of guidance, we expect that on a full year basis we will be within the guidance range previously provided of $3 to $3.50 per Boe. Production tax was an average of 7.7% in the second quarter.

All in, we are executing favorably against guidance. We still remain unhedged on the oil side, allowing for full participation in prices.

Our 2019 outlook continues to remain very strong with current expectations for production to grow 15% to 20% year-over-year, while generating significant free cash flow comparable to 2018 projections. The greatest benefit of the additional capital investment we announced yesterday will be seen in 2019 and beyond as we accelerate activity in our oil-focused assets, resulting in strong 2019 oil production.

We anticipate updating you with 2019 guidance early next year. With that, we're ready to begin the Q&A of our call, and I'll turn the call back over to the operator.

Thank you.

Hi. Good morning, everyone.

Wanted to follow up on your comments, John, about debt targets and you obviously made a lot of progress there. Can you just speak to what you plan to do with your free cash flow after you achieve that $5 billion net debt target?

We have you really getting there, I think, by the early part of next year.

It's a fantastic position to be in. As we've noted, we have the opportunity for continued debt reduction.

I think you'll see some of that in balance. We obviously have the opportunity to put a little more of it back into growth and into the assets and what we're doing.

So, I think there will be some balance with that. And as we previously discussed on the last, I guess, two or three calls, dividends are something that we're actively considering.

We want to see or achieve the $5 billion before any action in that nature, but we are dramatically on progress for that. So, it's a really good, strong position for the company to be in.

And I think we're pleased with the progress we're making today.

Agreed, John, it's a great position to be in. So, just a follow-up on the dividend – potential for the dividend, at least, do you have a specific strategy for that?

Is it to be above the S&P yield or something that really draws new investors into the stock, or would it be just something that's sustainable and you can continue to grow it over time? Have you guys thought through that or have any thoughts to share?

We do have some thoughts, and we are putting together a plan that we can – that will be sustainable, and that we can add to grow as the company grows in the future. So, yes, we have a formula that we're putting together at this time and one that we want to continue with.

Thanks, Harold. Just one follow-up, I guess, as it relates to the operations.

The Bakken performance looks very strong, and you guys are obviously adding rigs in Oklahoma as well. So, indicates very high confidence in all the assets.

Can you just speak to how your more recent results in the Bakken and what do you expect out of SpringBoard is influencing where you think you'll allocate capital in 2019?

Do you want to take that?

Yeah. As far as how we allocate capital in 2019, I think it can be very similar to this move we just recently made.

You see moves throughout the year where we're focusing on oil. And so, as you look forward, that's what you'll see.

And you'll see stronger oil production growth than gas production growth as we move forward. That explains why the oil cut percentage is increasing, such as John spoke to earlier.

Yeah. If you look to 2018, we've got 90% to 95% of our drilling and completion CapEx going into oil-focused projects, liquids-rich.

And I think you'll see something similar in 2019. We are very focused on growing oil production.

And, Drew, in just relationship to the performance, yes, we're seeing an outperformance in all of our assets here. So, we're really pleased with the performance.

And it, obviously, is driving our uplifted guidance that we provided this quarter.

Thank you.

Thanks. Good morning, everybody.

Jack, the increase in the type curve in the Bakken, can you just address a couple of issues relating to the dynamics of the production rates? It doesn't look like the IP rates are changing a ton compared to the last time you raised the type curve.

I think last time, you said you'd added DSPs. So, can you talk to, are we seeing the increase in the curve at the back end of, let's say, post 90 days, if you like, or is it right across timeline of the curve?

And if I may have a bolt-on there, the inventory associated with this new type curve, what's the depths of the inventory you see that we can attribute 1.2 million barrel type curve to?

Okay. Thanks, Doug.

This is Jack. I'll pass the first part of that question to Gary and then I'll pick up on the inventory.

Okay. As far as the first part goes, this new type curve does increase more in the front end than at the back end.

So, what we're seeing is a continued incremental production rates at the very beginning of the type curve. You can see that from the results that you've seen quarter-over-quarter when we talk about our record average IPs, our record 30-day rates.

And that's continued to prove out as we go to these 60-stage completions. But what I would also tell you is that the overall rate of return for this new type curve is higher than the last type curve.

So incrementally, we were able to invest an additional $500,000 per well and still get a very high 175% rate of return for that incremental capital.

So, the slide 9 obviously is what you're referring to, right? So we should take that as a kind of indicative for the inventory going forward, which I guess, like I said (38:18), Jack's part of the question.

Yeah. As far as inventory is concerned, I'd tell you, Doug, we're continuing to see uplift in performance.

So, the average EUR for inventory continues to climb. And so, to try to just give you some color right now on what the inventory looks like, if we're going to stick with 8 to 10 rigs for, say, the next 10 years and drill up about half our inventory during that time, the average blended rate of return, say, at $65 is in that 80% to 90% range.

So, that just gives you an idea of the quality and the depth of that inventory. So, we continue, as I said, to see an uplift and we continue to keep our eye on that, because really what used to be Tier 2 has now turned into Tier 1.

And I mean, this is exactly what you get when you get a breakthrough with technology in a large resource like the Bakken.

Okay. That's helpful.

My follow-up is maybe for John. John, you like to keep us on our toes, I guess, with this minerals joint venture.

And you're right, we'd love a lot more information. I wonder if you could just dumb it down for me.

Is the intention here to enhance the value of your existing assets or take royalty interest in anybody's assets, frankly? In which case, would you intend to have production in kind or cash in terms of how you report this?

And I'll leave it there. Thanks.

Yeah. Our intention's to grow value.

We have a very deep geologic understanding of the plays we're in. We're focused here on SCOOP and STACK.

We've got a team that's got a lot of history and has a lot of views (39:51). We will focus mostly on acreage that is operated by us that enables us to understand the timing of drilling and other things that can go into the economics and what we view as the value to pay.

But there will be opportunities and there have been opportunities where we've taken acreage under other operators. We might have a smaller interest in that well.

We might not have an interest in that well going forward, but we understand the geology and the productivity of those resources. The overall concept with this is to take that knowledge and that expertise and capture incremental value.

We view this as an opportunity to grow a multi-billion-dollar valuation on a company, look to roughly $600 million of investment over the next few years. And then you think of the productivity of the wells that we're bringing on in SCOOP and STACK, there is a valuable concept there that we can move forward with in deploying our knowledge in our longer-term development plans.

And to add to that...

Okay.

To add to John's comment on SpringBoard, that represents just a portion of our minerals. And out of 35 units, we will operate 32 units in SpringBoard, which is pretty impressive.

John, I'm not going to belabor this, I want to let someone else jump on. But I just want to be clear I understand.

So, the royalty piece would go into the joint venture, but I would assume that there may be some working interest add-ons associated with any royalty acquisition? Is that a fair way of thinking about it?

In which case, I assume Continental would fund that on its own.

If there's working interest, we would fund that on our own. Typically – this venture will be targeting the minerals specifically.

I guess there could be situations where an owner of the working lease we take – or interest we take a lease and we acquire the minerals in a similar transaction, but we're trying to keep those as two separate transactions. From an accounting standpoint, you asked about that.

We anticipate we will consolidate this new entity going forward. And as a result, you'll see the 100% of the capital costs flowing through our CapEx, but you'll also see, as a minority interest, the contributions from Franco-Nevada going through.

That's why I encouraged everybody to focus on the net. This $275 million that we're projecting for this year, obviously, we've indicated we expect to close on – receive $220 million from Franco for their buy-in during the fourth quarter.

So, that net, there's only $50 million. And as you go forward, you'll see similar.

And then, as the revenue begins coming on, we feel very comfortable about our ability to hit the targets that are defined in our agreement and to realize up to 50% of the revenue stream. So, this is an opportunity to add on to value that we're generating from our core business in a way that we think can be very meaningful.

And that will be revenue and not barrels in kind, John?

Well, we will reflect it in our production, but we'll show revenue as well.

Got it. Thanks, guys.

Thank you, Doug.

Yeah. John, I wanted to see if you could dive deeper on your comments on capital efficiency improving in 2019 and just give us some thoughts on your views.

And I guess I'm trying to just put that $600 million of CapEx that relates to 2019 production kind of into context.

Well, a portion of that's in SpringBoard where we're seeing very strong results. Everything that we're doing in the Bakken is on pads.

They're pretty much large pads now. You look to the South, we're mostly focused on pads there as well.

So, you do have some timing of when production and CapEx come on. You've seen some of that this year with the quarter-to-quarter sequencing.

So, we've got about $600 million that's carrying into next year that's hitting this year's CapEx. The associated production will come next year, and we expect to see strong results.

Harold gave some indications of some drill times and where we're getting to in the South. Our cost per well is remaining in line.

We've talked about the productivity and the uplift we're seeing in wells with revised type curve with the results that we indicated pretty much across all of our plays; STACK, SCOOP, the Bakken. We're seeing exceptionally productive wells and strong uplift for very efficient deployment of capital.

So, we feel good not only about being towards the higher end of our range for this year. But as we indicated earlier in the year and as we're reaffirming now, we expect that to continue improving as we go forward through the next few years to get back closer to our historical norm.

You look over the last 10 years, we've been in kind of the 20% type range.

Fair enough. And so, in the Bakken, John, you talked about exiting the year with 130 wells in progress, including 50 that have already been stimulated.

How does that – is that a normalized level of backlog, or does that provide extra juice as you think about 2019 production?

This is Gary Gould. I'll answer that question.

At that point, we're pretty much at a standard operational wells-in-progress number. But I think the important part to describe here is how many more net wells we're going to bring online in the second half that will give us that juice for 2019.

So, in the second half of this year, we plan to bring on about 80% more net operated wells in the Bakken compared to the first half. And so, you can see that juice, and the second half of this year is going to provide strong growth into 2019.

Not only providing strong growth. I mean our momentum on oil production, specifically, is very strong entering into 2019.

And as we referenced in Jack's and mine, we see strong oil production as we move forward and through certainly the balance of this year and next year, and beyond.

Gary, if I could just follow-up on that 80% more operated TILs (46:28). Do you have the 3Q versus 4Q kind of breakdown in the Bakken for the operated TILs (46:33)?

More of it will be in the fourth quarter than the third quarter. So, it will be about – if you look at it, in total about 60% of that would be in the fourth quarter and about 40% of the increase would be in the third quarter.

Okay. Great.

That's very helpful. Thanks.

Thank you.

Good morning, guys, and good update. First question on SpringBoard, really impressive development.

Should we just think about those rigs sitting on that acreage for like around two years and then that acreage block is fully completed, and then you probably have SpringBoard 2 or another type of development like that? Is that the way to think about it?

Brian, it obviously depends on the number of rigs that are in there, but we're looking at this as a three- or four-year development project there. So, these rigs will be in there developing both the Springer and the Woodford/Sycamore layers.

We've got three layers that'll be developing in there. And so, as I think you had mentioned last quarter, it's kind of like mowing the yard.

We're starting out on the eastside of the unit and doing row one, and then we'll come back and get row two, and just work it from east to west. So, it's a long – this is just, what I'd call, an ideal project when you look at this.

I mean, you're sitting here and if you look at the sheer size of it, number one, you look at the fact that we have 75% ownership in it, we operate it. We have the marketing infrastructure already in place.

This thing is teed up to really deliver just some outstanding value to Continental and the shareholders. And so, as a project, it's a great opportunity and we're really pleased to have it.

And right now, our plan – as you know, we'll take – right now, we've got four – or seven rigs drilling Springer and four in the Woodford, and we plan on increasing the Woodford rig count up to 6. So, we'll have 13 rigs drilling in there, here I think probably by October – a little bit late October.

And as far as where does this go after this, as I said, we do have some other projects on the horizon, and we'll talk about those at a later date.

Okay. That's helpful.

And then just on slide 10 of your presentation, the evolution, I guess, and the expansion of the Bakken. There is, I guess, some wells showed up – further up in Williams that I wasn't aware of.

Are those anomalies or do you – are those just less active areas? Can you maybe comment on those?

No, they're not anomalies. You're talking about on page 10 here, looking at the wells have been drilled in 2015 to the Q1 2018?

Correct.

And those are just – what you're seeing there is people are just continuing to step out from known results using the newer completion STEM technologies and continuing to drive these uplifted performances further north. And you can see there's a well up there very close to Divide County that is a very interesting well.

And it is performing in line with the wells that are, obviously, bulk of (49:52) the wells that we're seeing down south. So, it's very good, very encouraging for us, and that's why we say we continue to see our inventory up here just getting uplifted in its performance based on the expanding footprint of the play.

And I thought it was really interesting, if you go out and look at the IHS report, I mean, they really have highlighted this expanding what they call, new fairway for the Bakken. And it just dwarfs the old original fairway that was on the map.

Thanks, guys. Very helpful.

Thank you, Brian.

Hi. Good morning, everyone, and thanks for taking my questions.

Good morning, Kashy.

Yes. So, maybe more of some macro questions.

So, Harold, you have access to many individuals both in the U.S. and overseas that really shape global policy and have significant impacts on the global economy that most, if not, all of us don't have any access to.

And so, based on your discussions with these individuals, I was just wondering if you could share some thoughts on what the base case expectation is from the resumption of the Iranian sanctions to that country's production and exports moving forward.

Well, due to the amount of production that we're seeing coming out of the U.S. today, we're not seeing a whole lot of impact with that yet.

I think it could impact (51:24) production off, it will have some overall upward impact, eventually. It's not showing up yet, but I think everybody feels like it will in time.

And so, it's yet to be played out, but it's not too soon to see the immediate impact of it, but it will happen. I don't think it's built in to the market.

Some people say, well, it's already into price and in the market. But personally, I don't see that.

There were so much discussion around what happen or not, but I don't believe that was built in yet. So, that's kind of the way I see it.

Got you. And do you have maybe just a ballpark guess of magnitude or not yet?

Yeah. I think, overall, we could see prices run another 10% here before they're leveled off.

Obviously, we're pretty bullish on prices in the macro. We're seeing Permian in – that production being held back by infrastructure, and will for a year or more.

And during that term, that's going to be hard to see a lot more oil coming to market. So overall, we feel pretty good that things could run another 10% higher before it levels out.

And that's actually very segue into my tack-on question, which is in the situation that you just painted with the Permian bottlenecks, Iranian sanctions, what role do you see the Bakken as a whole playing to maybe help balance the markets? Do you see a situation where the Bakken may need to rise to the occasion and a lot of DUCs may need to be drilled to avoid some sort of oil spike?

Or just any thoughts you have on the Bakken next year moving forward in terms of reaction to all these dynamics.

Yeah. We think that the DUCs or drilled, but uncompleted wells are pretty much gone up there.

So, that's – certainly, we're back to the normal situation. At Continental, we have some that we've basically stemmed, cleaned up, that's not on line yet.

But overall, ours are done. So, I think industry-wide, what we're seeing up there, the DUCs are left out and gone at this point.

I know some of the completion crews that we let go, then really they had a little bit of trouble finding home. So, that's kind of where that's at.

So, I think as part of the playing a role, yes, I think we'll, as far as being able to improve, continue to improve, completion technology and bring some more barrels on. So, this will be of a great value to the Bakken going forward.

Got it. And if I could just sneak one last in.

There have been a lot of references today to 2019, and I was just trying to reconcile to the earlier 15% to 20% production growth framework that was provided back in February. Just how should we think about that now today just giving all that's happened and what you guys are seeing today?

As indicated in our transcript, we're still – we feel comfortable in the range of 15% to 20%. I think what you're seeing today should give you a lot of comfort that we can certainly deliver that.

And recognize that 15% to 20% today is on top of a larger amount of production this year, is on top of a larger exit rate, and shows a lot of momentum carrying into next year. So, from a volumetric standpoint, it's more than it was in February.

As we get through the next few months, we'll be firming up our 2019 final drill plans. We certainly have a very good view not only to 2019, but for years beyond that.

But we'll firm that up, and true it up, and I think you'll be pleased with the guidance when we come out in early 2019.

Yeah. And I'll just tack on to that.

This is Jack. Just when you look at our focus on oil, that 15% to 20% is clearly going to be highly oil-weighted.

And so...

Great point.

And so, you'll see that swing as well.

Yeah. You'll see a change in the mix which from a volumetric standpoint certainly flows through Boe percent, but it will be oilier.

Awesome. Thanks for the color.

Really appreciate it. Have a good rest of the day.

Thank you.

Thank you. Good morning.

Hello, Brian.

Wanted to just follow-up on a couple of the questions and your comments on Bakken inventory. If we look at that 40-mile gap between the wells that you've highlighted on slide 9 and then overlay that on to slide 10, is the area bounded by those 40 miles, the acreage that the new type curve should be applied, or should it be applied more widely on your acreage across Williams and even to the north?

You'd commented earlier that you're seeing some uplift in the noncore in terms of more competitive rates of returns. I wonder if you could just kind of talk to any plans you have to expand your drilling further north into Williams and even Divide County.

Yeah. Brian, the type curves that we've put out there, you got to remember that is a blended type curve.

So, you're looking at Little Bakken, Three Forks 1, Three Forks 2 as the reservoirs we're targeting. And in any given area, one of those reservoirs can outperform the other.

And so, it is a blended type curve that we're giving you there. So, some are higher, some are lower than that type curve, obviously.

And as far as how widely you can apply that, well, we're continuing to drill wells to basically prove how wide that is in complete wells. But what I can tell you is it is expanding, as I pointed out on the slide 10, there is a well up there close to Divide County that is conforming very nicely to our uplifted type curve.

And so, I think that should give you a pretty good indication of how wide you might be able to apply this uplift.

Great. Thanks.

And then my follow-up is on exploration. This has always been a core part of your strategy over the years with some big benefits in the Mid-Con, in particular.

Can you just give us an update on the portfolio and what do you think the ability is to add another SCOOP or STACK or Springer-type position somewhere in the portfolio? I think the Permian had come up as one area that you are active in, but just kind of how close do you think you are in any of your exploration plays?

Hi, Brian. This is Tony Barrett, and I'll answer that question.

I mean, obviously we've said over the years we're an exploration company. We're always looking to create value.

And over the years, the development of SCOOP and STACK with additional reservoirs that we've identified has driven our program, Springer being a great example of that. We obviously continue to explore all of those areas.

As we've said in the past, the Anadarko Basin as well as the Williston Basin are great places to look for oil and gas, multiple targets to go search for. Anadarko Basin, 1,000 feet of stacked pay in the pressure window.

So, always looking there. As far as other places that we're looking, it's basically everywhere and we'll always continue to do so.

And is there anything that you see that's kind of front and center or nearing a point where you have more confidence that it is a viable play in the same way that SCOOP, STACK or Springer was at the time that you went forward with that?

Yeah. I might take a shot at that, Brian.

We certainly do. Jack has mentioned a couple other areas that we'll be talking a great deal more on in the next quarters.

And certainly, we're testing and you know, it's looking very promising as well. So, we'll be bringing those to you.

Thank you very much.

Yes.

Hi, guys.

Hello.

The first question on the new minerals venture, is it – I understand right now, it's focused on the SCOOP/STACK, but does the framework allow it to go to the Bakken as well?

This particular framework is focused on SCOOP and STACK. So, if we expand it – they own minerals outside of this.

We certainly have the opportunity to acquire minerals outside of this as we choose. If we were to do something in concert with each other, that would require a new agreement, but there's certainly nothing prohibiting that.

Got it. And then just one follow-up on the Springer where we keep seeing continued efficiency gains.

You highlighted that you're still looking for another $1 million of savings on the Springer wells. Can you just sort of highlight just some of the areas where you think you're going to be able to get those savings from?

This is Gary Gould. I'll start on the completion side, then turn over to Pat for the drilling side.

But on the completion side, when we had this type of concentration of operations, we're able to see lots of efficiencies and how many stages we complete in one day, for example. And that will lower our stimulation costs.

And on the drilling side?

Yeah. This is Pat Bent.

On the drilling side, one of the things that we're seeing is the application of new technologies from a logging while drilling perspective. And so, we're able to better see bed (1:02:35) boundaries and avoid hazards.

And so, some of those tools are very new to the market. Actually, they haven't been run in the last month and so that opportunity is out there.

And so, that in combination with the efficiencies that Gary talked about could give us upwards of $1 million.

Perfect. Thanks, guys.

Thank you, John.

Afternoon, guys. Thanks for squeezing me in.

Jack, I think my question's for you, if I look at slide 20 that shows just sort of the returns of some of your top plays, I guess, focusing primarily on the Springer SCOOP there, can you talk a bit on how some of the newer – let's start with the Springer, how some of the newer Springer wells are performing, in your opinion, versus that 1.2 million Boe type curve and then maybe the same question for the SCOOP versus that 1.5 million Boe curve on it.

Yeah. That's a good question, Neal.

Our new wells, the Triple H wells that were brought online in Project SpringBoard on the eastside. And if you go to page 22 and you look at the lower right-hand side, that shows the Springer oil type curve, this is our 1.2 million Boe type curve for unit wells, all right.

And what you'll see in there, there is a subset of wells that are in the very beginning of the curve there where you can see they're running at 10 (1:04:03) to take the average down below the curve just a bit. And those are from the Triple H – that's from the Triple H unit.

And that unit is out on the eastside of SpringBoard, and that's where the Springer is thinner. And as you move to the west, it gets thicker, and we will see better wells or, I guess, it's a higher rates from those wells as you move further west across the field.

And so, this would be what we would expect. And the 1.2 million Boe, you've got to remember, it's like I talked about the Bakken, it's an average of outcomes that we expect going across the play.

In some areas, it's going to exceed that 1.2 (1:04:45), clearly. In other, that is maybe just a bit lower, but that 1.2 million Boe is a good average for what we're going to be drilling across the play.

And so, as I said, this Triple H was out on the eastside in the thinner area. And as we move west, we'll see higher early rates.

So, I mean this is just straight off of our results here and I think hopefully that will answer your question of how the performance is. I mean, I could talk about the Triple H by themselves, but you've got to keep them in context for the whole field itself.

No. That's exactly what I was looking for.

Thanks, Jack. And then just one follow-up on the SpringBoard around slide 13.

Could you talk a bit about just sort of the oil breakdown and what you think? I think you kind of like, you said about 75%, 80% of that production would likely to be oil from SpringBoard.

I'm just wondering is that because you'd be doing more Springer initially? And then, as you do more Woodford/Sycamore, again, I think the Woodford is a little bit less oil.

Maybe just talk about the composition from either Phase 1 and Phase 2, Jack?

Yeah. Another good point there and maybe we need to work that slightly differently.

But the 85% oil is what we're typically seeing out of the Springer and you get down more to that 70%, 75% range, maybe 80% in the Woodford. Okay?

And so, that's really – what you're seeing there is kind of a breakout between, on the high end, it's going to be the Springer at 85%, the lower ends, will be like you said, in the Sycamore/Woodford, that will be a little less oily.

Very good. Thanks so much for the details.

Hey. Afternoon, everyone.

Another question on the minerals partnership. What's sort of the endgame for this?

Is it really just there to enhance the drilling economics? Or earlier in the call, you mentioned that there might be a couple billion dollar valuation on it at some point.

Is there the potential for it to be a spin candidate or an IPO candidate sometime in the future?

Yeah. It has potential for any number of things.

The key is it's going to be very valuable. It can certainly fit in an IPO category at some point in the future and capture significant value.

It's also a nice asset to hold to maturity. As I indicated, it's going to be cash flow – it's going to put off a significant amount of cash flow as we go forward, and it'll convert to cash flow positive asset and recoup the investment relatively quickly.

And either way, it's adding to our economics, it's utilizing our team's expertise, and it gives us a great opportunity to approach the future in a number of ways.

Okay. And then, do you have any sort of targets as to what you could potentially get to on the NRI front versus 2019 or so that you have now?

I don't think that we would probably want to discuss all that today. We're very focused on it.

Okay. Thanks.

Sure.

Yeah.

Thanks. Good afternoon, all, and congrats on a strong operational update.

Thank you.

Thank you.

Building on Brian's earlier question on the Bakken fairway. To what degree could the core fairway extend north and west of the most northern Williams well on page 10 based on your understanding of the geology?

Could it be 10 miles to 20 miles to the north and west?

Yeah. I mean, it's – you're asking great questions in here, and we're – we and others in the industry are continuing to push that envelope.

But based on what we know right now and especially just keying off of the results of the well, I keep pointing to out there, that's on the northeast corner of Williams County and south of Divide. The production there is – it's quite impressive, and we think it shows that it has the ability to expand on up into Divide.

And this is an area that we've got out of HBP (1:09:00) acreage up there and it's a very, very sizable amount of acreage in that area.

And I would also – you're looking north, don't forget to look south of Dunn County. You look down there and there's the Billings County, we're not done there either.

It's working all along the anticline, both north and south.

Yeah. Really, what it is, is through this technology, we were basically under-stimulating these wells in the past.

And so, we're not going to 60 stage completions. What we're doing there, they're just connecting with the reservoir better and we're really finally truly realizing the true resource potential or the ability of the Bakken to deliver.

And so, I've got a great example I'll share with you. This is really interesting.

We have a well that we re-entered, okay. And I think it was about a 9,300 foot lateral.

We re-entered it, and it was completed open hole. So this goes a way back.

All right. This was in North Dakota.

And we went in and re-entered the well and drilled it about another 665 feet and then lined it and stimulated the well. And in the first 60 days, that well made 100,000 barrels.

And that's more than the well made in the prior 10 years. So, that is about as a graphic example of what the technology is doing to essentially truly access the oil that exists in the Bakken.

The Bakken is a tremendous resource. I mean 100% of the field is in the oil window.

It's over-pressured and it's a dry system, really no water and so it is a system there that is ideal. And we were just not really effectively connecting with the reservoir.

So technology has taken us to a whole new level in this play. And I think people are finally getting their – starting to understand and get their heads around that.

And that is what's key. So, it's basically a renaissance for the Bakken.

And when we say we, I think that goes for the industry as well. It's not just Continental.

Yes.

It is the entire industry. We work together very well with other operators up there to try to understand this thing and we're closer than we've ever been.

I agree with you guys. It has been quite impressive.

Moving over to the SCOOP, you completed several uplift (1:11:25) wells in the Sycamore during the second half of 2017 and into early 2018. As the Sycamore is part of Project SpringBoard, I was asking, wanted to know if you guys could just share a little bit more color on the performance of those wells in comparison to the Woodford.

The Sycamore wells that you're referring to, we found tend to mimic pretty well the type of performance we're seeing out of the Woodford, in general, out there. And on Project SpringBoard, we're going to be in an area that's a little bit more highly oil rich.

And so, we're actually – we're – in our development there we are testing the Sycamore and we're actually going to be defining in our early units out here just what level of density we can drill in the Sycamore. Okay.

So, the performance we expect to be, let's say, comparable to the Woodford. But on density development, we want to understand that.

And so, we'll see, like in the Williams unit that we have drilling right now, we're drilling some wells in the Sycamore as well as the Woodford and we're going to be monitoring the production there. And it will help guide where we go and how densely we drill things going forward.

We're very comfortable, obviously, with the Woodford density. We've been doing that for quite a while and we understand that.

In the Sycamore, we're a little earlier in that development, but we want to include it in our development of SpringBoard. And so, we're just testing as we go.

I think to maybe add one more comment there. I guess, it surprises to the upside at this point, so we're very satisfied with it.

Great. Thanks for all additional detail.

Yeah. Curious on the – as you commit to SpringBoard, more Cushing oil versus Bakken oil, if you worry about basin congestion and want to seek to protect that through hedging.

As far as basic congestion, Ramiro, you might want to step in here, but right now, we're not concerned with that, with our access from a gas market standpoint. The premium markets down in and (1:13:55) out of Tolar Hub with our Wildcat pipeline project with Enable.

I mean we're totally comfortable it's able to handle the growth that we see in our oil – the oil pipeline system that's in there. Likewise is directly connected to the refinery there, Wynnewood, and quite frankly it's a premium oil that they are very – they want very badly and it fits their system very well.

And it's a great relationship that we have. So from a congestion and marketing standpoint, we don't have that here, don't be concerned.

This is Ramiro. From an oil vantage point, the infrastructure is already in there, both from trucking and pipe.

And additionally, as we continue to be able to ramp up, we are very confident that any additional infrastructure that is needed will be built. So, we really don't think that that's going to be an issue.

We have – to reiterate what Jack said, we have a lot of optionality in support of refiners and Cushing. And so, on the crude oil side, lots of optionality.

On natural gas, same way. I think that we have capacity on Wildcat, and then there's other options that we can avail ourselves of.

Okay. Got it.

And then, just can you summarize sort of what you're seeing dollar per foot on AFEs in the SpringBoard project from the Springer on down?

I think we show that on page 14. So, on slide 14, you see the reduction in costs that we've seen in terms of dollars per foot, and this is completed well cost, so it includes both drilling and completion.

You see we've already seen about a 50% reduction in cost per foot to where we are right now. And with the additional technologies and efficiencies that we referred to earlier, both on the drilling and completion side, we see the potential for another 10% savings.

Okay. Got it.

So, the number that I see there is inclusive of all your commentary?

Yes.

To this point. Okay.

Great. Thank you.

Yes, you bet.

Good afternoon, and thanks for running the call a little over. My first question is a macro question maybe for Mr.

Hamm. Given the importance of oil exports to the U.S., do you see there's any way that successive administration to Congress can stop that?

No. In fact – maybe successive administration might.

Certainly not the one that's there now. In fact, the current administration would like to enhance it.

It's been great for balance of trade, but everything else, we're not so dependent on at least as we have been in the past. So, I just don't see it.

I think the further we go down this road, the more everyone is going to realize that today the U.S. has its own petrodollars.

We're seeing the current administration embrace this more and more every day, realizing the importance of it. So, I think it's – and I think that will also set up a precedent for the next administrations that come in.

So, it won't be just this one, it will be future administrations going forward, seeing the importance of it. It's a tremendous effect today to not be beholden to some other government for your wellbeing.

And we have the cheapest gasoline prices in the world of any unsubsidized country. So, it's a great situation due to our ability to supply the market.

I appreciate the color. And then maybe just a micro question for the A&D team, when you look at the recent asset sales, were they, quote-unquote, on your list when you'd identified $1 billion-plus in asset sales or would something like the Franco deal commend over the transom, so to speak?

We've had a number of deals – I mean, there are a number of opportunities that have been on that list. The minerals opportunity is something that we've been working on for a while.

I wouldn't go back to early 2016 and say it was on there, but it is an opportunity that we've had in our mind and been working on for a bit here, and we're making good progress. The key is we're not interested in fire sales.

We want to capture appropriate value. We haven't sold much production with our divestitures, but we've been able to effectively execute on those transactions and to utilize proceeds to delever the company.

And you need to remember, too, these divestitures that we've had, basically, have been driven by the fact that our inventory is so deep that these are the things that we don't see ourselves getting to in the next 15 years or more. And they are things that although they may not have as much value to us, they still are very attractive to other operators or other folks out there.

And so, as John said, it's driven by the fact that we're so flushed with good, high-quality inventory that we're unwilling (1:19:47) to divest, and we do have some other ones that we will have in the queue as well.

Yeah.

Moving forward.

And I think you could call them multifaceted. There are several different aspects of what we're doing here.

And this is an awfully good example of that.

Great. Appreciate the time, and congratulations on the quarter and the outlook.

Thank you.

Thank you

Hey, guys. I was wondering if you could maybe just talk a little bit about the opportunity set that you guys see around the Franco-Nevada deal that you guys did here.

I mean, is there are a substantial mineral acreage out there still to be captured in SCOOP/STACK over the next couple of years? Obviously, you guys have already done a chunk of that and putting that into the vehicle.

Just trying to get a sense of the scale of this opportunity.

Yes. Just like our leasehold position, we continue to acquire and lease every week with a lot of success.

Minerals are in the same boat. It's highly competitive, but we've got a great team.

We have majority of it we have current title on. So, it gives us an advantage over anybody else, but it is highly competitive.

The key on it is we're only going to execute on transactions where the valuations are appropriate that provide that longer-term opportunity in a reasonable and balanced way. If those opportunities don't exist, we won't spend the proceeds or the money.

Okay. Yeah.

That makes sense. And I guess, then incrementally, I don't know if you guys already have some other existing minerals on some of your SCOOP/STACK that may be get drilled a couple of years down the road, that would be more of a dropdown situation, or would it be you guys having to go out and say, hey, look, we're drilling wells another year or two, let's try to pick up those minerals and in sort of advance of the drilling.

Just trying to make sure I kind of understand just sort of specifically what you're sort of targeting. It sounds like it's mostly going to be CLR-operated areas.

Absolutely. That's been our goal since we started this in mid-2016.

It's been our focus to have our drill schedule. We've retained a small amount of minerals outside of the core areas of our SCOOP and STACK, and out geologists are continually expanding our areas.

So, I think that's what the future hold at this point.

Thanks, guys.

Thank you, Leo.

Thank you.

Great. Thanks.

Hi, everybody, and thanks for extending the call.

Thanks, Joe.

Thanks, Joe.

Slide 10, if we can look at slide 10 for a second, that map on the right, it just seems that there's a kind of a donut hole amongst all those great wells. And I'm just wondering, is there a geological reason for that donut hole?

Maybe it's more like a Danish (1:23:06)?

In my opinion, no, it's going to be tied to op ownership (1:23:10) and degree of development already. All right.

Got it.

And other operators.

Yeah.

And other operators.

Okay. All right.

That's all I had. Thanks very much, guys.

Well, thank you, everyone, for joining us today and please reach out if you have any further questions for the IR team. Thank you.