Continental Resources, Inc.
Q4 2017 Earnings Call Transcript

Published: 22 Feb 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q4 Year End 2017 Continental Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. I'd would like to introduce your host for today's conference call, Mr. Warren Henry. You may begin.

[J. Warren Henry:]

Thank you, Kevin, and good morning to everyone joining us today. We'll start today's call with remarks from Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President; 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, SVP-Drilling; Gary Gould, SVP-Production and Resource Development; Steve Owen, SVP-Land; Ramiro Rangel, SVP-Marketing; 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 on 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 $60 per barrel WTI and $3 per Mcf natural gas. Finally, on the call, we will refer to certain non-GAAP financial measures. For 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?

[Harold G. Hamm:]

Thank you, Warren, and good morning, everyone. We're coming to you this morning from cold and frozen-over Oklahoma City. We burn lots of natural gas here and hope you are as well. As you saw on our fourth quarter 2017 earnings release yesterday, Continental's performance in the past 12 months was simply exceptional. We exceeded the production threshold of 300,000 Boe per day. And in the fourth quarter, we averaged 286,985 Boe per day with 59% of that being oil. As predicted, we were cash positive while growing production 37% from fourth quarter 2016 to fourth quarter 2017. In-site operate oil production was up 49% over the same period, demonstrating even stronger execution on our controlled properties. Fourth quarter production was up 35% over third quarter. We continued to reduce our long-term debt to $6.26 billion at the end of January. S&P moved and placed Continental's credit rating at investment grade. Finally throughout the last year, we continue to improve individual well performance in EURs in our plays from North Dakota to Oklahoma. Some type curve EURs were increased twice, reflecting continued refinement of our optimized completions technology. We continue the Bakken celebration. We remain focused on oil. So, 2017 was just a year of exceptionally strong performance, not a ramp-up or activity level change, just steady performance. What's ahead of us, however, will prove to be even more exciting. 2018 is shaping up to be a breakout year for Continental Resources, capitalizing on 2017 and prior years' achievements as we now move to harvest the deep oil-rich resource inventory that we have assembled over the years. We're poised to deliver best-in-class production growth and free cash flow, $800 million to $900 million in free cash flow in a $60 WTI world. We have clearly entered a new era in Continental's history and we are strategically positioned to operate at a high level for many years to come. As the proverbial saying goes, that which is manifest is before us. Continental's strategic position has been long in the making. Today, we are capitalizing on decades of exploration, asset accumulation, operational efficiency gains, and market strength. Asset development in 2018 is the largest part of our operating plan. While we're still exploring and occasionally delineating very attractive plays, our key focus for 2018 is the full field development of the liquids-rich assets we own. Technology has turned on ever greater areas of our strategic leasehold unleashing the full potential of our asset base in a strong price environment. This enables Continental to deliver strong growth with low operating cost on high rate of return projects and strong cash flow for years to come. This completes a prepared and long-coming structural shift in Continental's business plan, which will be a multiyear phenomenon. This was not a ramp-up point in a cycle, but the creation of a self-sustaining business platform. Continental is now an internally funded organic growth machine. Our goals are bold and long-sighted. We intend to be best-in-class in the U.S. E&P industry in terms of free cash flow generation, shareholder value creation, and production growth. We'll remain nimble and opportunistic as exploration and acquisition opportunities arise in and beyond our current assets. Entrepreneurial drive is a large part of our DNA, as is exploration, and we still love stealth plays. As set forth in our recent 2018 guidance release, we're looking forward to an outstanding year in 2018. Literally, a breakout year for Continental. We anticipate continued excellence in drilling, completion in all operation, and Jack and John will have more to say on this. But as an example this quarter, I'd like to highlight a less discussed aspect of our growth strategy, the tremendous job our oil and gas marketing team is doing. We've significantly strengthened the marketing team in the last two years under Ramiro Rangel's leadership and they're delivering tremendous value to Continental. Even with the challenge of low natural gas prices, our gas marketing team had negotiated multiple agreements to various outlets, north and south that are creating substantial marketing optionality and additional value for dry gas and gas liquids in the tens of millions of dollars. They are maximizing the value of Continental's production, both oil and gas. On the oil side, we've been discussing for more than a year the opportunity to renegotiate or Pony Express Pipeline commitment, given a new capacity in the Bakken with the DAPL pipeline. Well, we got that done in late December and as a result, our 2018 outlook for oil differentials is almost $5 below what they were in 2015. That is massive, true value-add for shareholders. In addition, we continue the marketing of our premium-quality Bakken crude oil abroad. U.S. exports have served to shrink the Brent-WTI spread from $6 to $7 down to $3 recently. Our marketing group has also seen the addition of a professional team in hedging science and analytics. Adam Longson from Morgan Stanley, is bringing a greater technical understanding to Continental, and we welcome him aboard. Since WTI's drug (08

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. Like Harold, I couldn't be more excited about our outlook for 2018. So I want to provide some color on what we expect our breakout year in 2018 to look like before I get into the fourth quarter highlights. In 2018, we will fund our $2.3 billion CapEx in our projected 17% to 24% production growth entirely from internally generated cash flow. We also expect to generate up to $900 million of free cash flow, which is targeted for further debt reduction. $2 billion of the CapEx is targeted for drilling and completions, with approximately 90% focused on unit development. As Harold mentioned, this is a higher percentage of development than we have had in prior years. It marks the beginning of what we believe is the first of many years of positive cash flow growth as we begin to harvest more than two decades of high-quality inventory in some of the best oil-weighted reservoirs in the U.S. today located in the heart of the Bakken, SCOOP, and STACK plays. I can't emphasize enough what a significant structural change this is for Continental and our shareholders. By no means does this suggest that exploration is a thing of the past, though. We intend to test several new exploratory projects this year as we continue to provide opportunities to fuel future growth and optimize our portfolio. Now, approximately 78% of the drilling and completion budget is allocated towards oil-focused plays, with 60% going to the Bakken and 18% going to the SCOOP Springer. In the Bakken, we plan to complete approximately 187 gross operated wells, including our inventory of drilled but uncompleted wells. At year-end 2018, we expect to have approximately 120 gross operated Bakken wells in various stages of completion at year-end 2018. In the SCOOP Springer, we'll begin our long-awaited development drilling program and expect to complete approximately 31 gross operated wells in 2018. Combined with our other activities in STACK and SCOOP, we expect to complete a total of 305 gross operated wells company-wide in 2018. We expect to keep an average of 21 operated rigs drilling in 2018 which is up only one rig from 2017. Six of these rigs will be focused in the Bakken, five in the Springer, eight in STACK, and two in the SCOOP Woodford. We also plan to keep an average of 10 stimulation crews active during 2018. This is essentially flat with 2017 with six allocated to the Bakken and four allocated to the STACK and SCOOP. Now, let's look at some of the highlights from the fourth quarter. Overall, we continue to have great success across our plays and our density test in STACK and SCOOP are providing the perspectives needed for future development. In the Bakken, we are rewriting the record books for company-operated Bakken wells, thanks to our optimized completions. Five of the 39 operated wells we completed in the fourth quarter delivered the highest 30-day rates the company has ever recorded from the Bakken. These five wells flowed at an average 30-day rate of 2,230 Boe per day during the first 30 days, and the great news is these five wells are units that are located over 25 miles apart, demonstrating the widespread nature of these results. In total, we have brought on 134 optimized Bakken wells since fourth quarter 2016 and on average, these wells are outperforming our updated 1.1 million Boe type curve introduced in mid-2017. Rates of return based on this type curve are running around 125% which is more than double the average rate of return for our previous type curve. We believe these results are structural and represent a step-change in Bakken well performance. The rocks have not changed, our optimized completions are tapping into the Bakken reservoir like never before, uplifting the performance of the wells across this world-class oilfield. The Bakken is the only play I know of where the children wells consistently outperform the parent wells. I believe the Bakken stands alone in the U.S. today in terms of repeatability, economics and cost. Bakken economics compete head-to-head with the best oil plays in the U.S. today and the production stream is 80% oil. As the number one Bakken producer with over 4,000 locations in inventory, the Bakken continues to be an exceptional platform of growth for Continental and its shareholders. In Oklahoma, we continue to have great success with both our step-out drilling and density testing programs. In STACK, we completed six step-out wells during the quarter. A couple wells of note includes the Luttrull 1-30-31XH that flowed 3,500 Boe per day at 5,800 psi flowing casing pressure from a 10,075-foot lateral and 32% of the production was crude oil. The Lorene 1-8-5XH which we reported flowing 6,715 Boe per day on our November call has now been online for more than 100 days. During this time, Lorene has produced an impressive 507,000 Boe, and the well continues to flow at 3,200 Boe per day at 2,250 psi flowing casing pressure with 23% being oil. Perhaps more important than step-out drilling results this quarter is our preliminary conclusions we have drawn from our ongoing STACK Meramec and SCOOP Springer density testing. As you know, the purpose of these tests is to determine the optimum number of wells needed to maximize the PV-10 in the various reservoirs in a unit. From these tests, we can characterize and expect a performance from a fully developed unit and migrate away from the parent and child well comparisons. Today, we are introducing our preliminary unit economic models for our acreage and STACK Meramec over-pressured oil window and the SCOOP Springer based on the results we've seen to-date. I should point out that we recognize one size does not fit all, and well density recoveries and PV-10 will vary depending on geology, prices, and other factors. But these economic models are meant to provide a template for current development and demonstrate the tremendous value to be harvested from these assets in the coming years. In STACK, we have completed six full Meramec density tests in the over-pressured oil window, including the Ludwig, Bernhardt, Blurton, Compton, Verona, and Gillilan units. Well densities of three, four, and five wells per zone were tested, and all but one were dual-zone tests. Based on results, we currently believe four wells per zone on average maximizes the PV-10 of the unit. This is consistent with our original expectations, and we currently estimate a typical Meramec unit in the oil window underlying our acreage will contain on average eight wells drilled in two Meramec zones. We estimate that these eight wells will recover approximately 9.6 million Boe and generate a PV-10 of approximately $87 million with a rate of return of 96% from the unit, assuming well costs of $9.5 million for a 9,800-foot lateral well. I'll refer you to slides 13 and 14 on our slide deck for details on the results of the recent Verona and Gillilan wells and our unit economic model for the Meramec in the oil window. In addition, we can expect up to four wells to be completed in the underlying Woodford formation. We currently have over 40 units ready for development in the over-pressured Meramec oil window at this time. During the fourth quarter, we also completed our first density test in the STACK over-pressured condensate window. The Angus Trust density was a half-unit test with the equivalent of six wells per zone or 12 wells on a fully developed unit. This is the most aggressive well density we have attempted to date in the Meramec reservoir. And this half unit consisted of one parent, two children wells in the upper Meramec and three children wells in the lower Meramec. Early performance indicates the maximum PV-10 per unit can be achieved with fewer than 12 wells in the Meramec – Meramec wells per unit. To further define the optimum well density, we are currently drilling a second density test at the Simba unit located 1 mile southwest of the Angus Trust. The Simba will be a six well, full unit test with three wells in the upper and three wells in the lower Meramec. Now, let's moved to SCOOP Springer, where I'm pleased to say that development of this prolific oil reservoir is underway. As many of you know, we deferred development of the Springer for several years, patiently waiting for better oil prices. During this time, we conducted strategic tests for optimized completions and longer laterals up to 8,300 feet long, and expected the longer laterals and optimized completions clearly improved well performance. On average, these optimized wells outperformed our historical 940 MBoe type curve for 4,500 foot well by over 70% after nine months. We also completed three density pilots that tested four, five and six well configurations in the Springer reservoir. Our most recent test, the six-well Celesta unit was completed in the fourth quarter and was our most aggressive density test in the Springer to-date. The six wells flowed at a combined rate of 6,014 Boe per day averaging 1,002 barrels or Boe per day per well. Comparing results from the Celesta, with the results of our previous four and five well density tests, we have concluded that four wells per unit on average should maximize the PV-10 from the Springer reservoir on a unit basis. So development is underway, with six rigs drilling in the Springer today. Our Springer type curve has been uplifted 28% from our legacy 940 MBoe type curve for a standalone 4,500 lateral to 1.2 million Boe for a 7,500-foot Springer unit well. More importantly, the rate of return for this new Springer type curve is 175%, which is more than double the return delivered by our legacy type curve. This clearly shows the net effect of longer laterals and our optimized completions. Our Springer unit economic model projects a four-well Springer unit will produce a combined 4.8 million Boe over the life of the wells and generate a PV-10 of approximately $68 million assuming a completed well cost of $9.5 million per 7,500-foot lateral. In the SCOOP Woodford oil window, we uplifted our type curve once again to 1.5 million Boe per well and 60% of this is oil. This is up 13% from our previous type curve and once again reflects the value creation from our optimized completions. Net of well cost of $12.7 million, this new type curve delivers a 55% rate of return. Now, I'll close my portion of the call with a glimpse of the future in SCOOP. We often talk about the Woodford, Sycamore, and Springer reservoirs separately in SCOOP. In reality, these reservoirs are stacked on top of each other throughout much of SCOOP within a column of rock up to 2,000 feet thick. This means in some areas we could be looking at as many as 18 wells in three reservoirs with up to 10 wells in Woodford, four wells in the Sycamore, and four wells in the Springer. Simultaneous development of these reservoirs in the unit is the future, and we are testing the mechanics of this right now with our Dicksion unit. We are currently flowing back the Woodford and Sycamore wells that were stimulated while we were drilling – while we're simultaneously drilling wells in the overlying Springer reservoir. It's all about creating value from our assets and I say this to let our shareholders know that we continue to push technology every day to maximize the value of our assets. With that, I'll turn the call over to John for more details on our performance.

[John D. Hart:]

Thank you, Jack. Hello, everyone, and thank you for joining us this morning. Let me start off today with a few fourth quarter 2017 accomplishments. Back on the November earnings call, we provided some estimates for the fourth quarter. We performed exceptionally well against these estimates, meeting or beating these targets. We consistently deliver on our guidance. Let's review. First, we guided that we would achieve oil growth of 14% to 18% in the fourth quarter as compared to the third. We did better coming in at 20% oil volume growth in the fourth quarter. Additionally, we gave a fourth quarter production range of 275,000 to 285,000 per day, and we did better once again. Fourth quarter production was approximately 287,000 Boe per day, above range. This growth was led by STACK up by 35% compared to the third quarter, and the Bakken up by 21% compared to Q3. On an annual basis, production grew 12% over 2016, and our exit rate grew 37%. I would like to amplify Harold's earlier comment, our in-site operated oil production grew 49% from fourth quarter of 2016 to the fourth quarter of 2017, exhibiting our team's exceptional performance. Third, we updated fourth quarter oil differential to a range of $4.25 to $4.75 per Bo, reflecting solid improvement in our differentials, driven primarily by the Bakken. We achieved better than that in 4Q at $4.23 per barrel of oil. Finally, we noted we would exit the year at a debt to 4Q annualized EBITDAX ratio of under 2.5 times, a significant improvement from the previous quarter. The fourth quarter annualized ended up better than that at 1.88 times as we reduced debt and grew production and cash flow. I point these things out to remind everyone that Continental is a company that executes at a very high level and is focused on delivering on our guidance. We are a reliable company and we deliver on those commitments. In a lot of cases, we outperformed. 2018 should be no different. All right. Let me run through a few more financial highlights for 2017. Revenue for the fourth quarter was $1 billion. Net cash provided by operating activities was $731 million and EBITDAX was $838 million, all of those up significantly from prior periods. Net income for the fourth quarter was $842 million or $2.25 per diluted share. $128 million of that comes from normal operations and $714 million resulting from the impact of the federal tax reform. Adjusted to remove items typically excluded by the investment community and published estimates, we posted an adjusted net income of $154 million or $0.41 per diluted share for the fourth quarter, driven by strong production, price realizations and cost efficiency, a solid beat compared to street consensus. Revenue for the full year was $3.1 billion. Net cash provided by operating activities was $2.1 billion and EBITDAX was $2.4 billion. Continental reported net income for the year of approximately $789 million or $2.11 per diluted share for the full year. Adjusted to remove typically excluded items, the annual adjusted net income for the year was $191 million or $0.51 per diluted share. Full year production came in at approximately 243,000 Boe per day. Production averaged 287,000 Boe per day in the fourth quarter, increasing 18% from the third quarter average. Oil production was 57% of total production for the full year and 59% for fourth quarter 2017, reflecting the growth I previously noted. Non-acquisition capital expenditures for the fourth quarter were $496 million, bringing full year non-acquisition capital expenditures to $1.99 billion, slightly above our budget of $1.95 billion. For the year, we were cash flow positive by $82 million, excluding proceeds from divestitures. Including divestiture proceeds, we're cash flow positive about $227 million. Our debt position improved by more than $260 million at December 31, 2017 to $6.35 billion as compared to September 30. As of January 31, we further decreased total debt by $95 million, improving to $6.26 billion. We're targeting further – targeting free cash flow to further debt reduction, therefore creating additional shareholder value. You saw last week that we were raised back to investment-grade by S&P. We remain in regular communication with the other rating agencies, and we are focused on returning to investment-grade status there as well. We are well on our way to getting to our short-term debt goal of below $6 billion and with projected free cash flow in 2018 and beyond, combined with the planned asset divestitures, we are focused on achieving our longer term target of $5 billion or lower. We have clear visibility to these targets and are aggressively working towards them while continuing to deliver strong production growth. Operating costs performance continued to be very strong throughout the year. Production expense dropped to an impressive $3.17 per Boe in the fourth quarter, a 17% improvement over the third quarter – among the industry's best. Full-year production expense averaged $3.66 per Boe. Our guidance for 2018 is a continued low $3 to $3.50 per Boe. Fourth quarter G&A excluding equity compensation was $1.80 per Boe. Non-cash equity compensation was $0.50 per Boe of production for total G&A of $2.30 per Boe. Full-year cash G&A was a robust $1.64 per Boe and full-year non-cash equity compensation was $0.52 per Boe for total G&A of $2.16. For the full-year 2018, we expect G&A excluding equity compensation to range between $1.25 and $1.75 per Boe and between $1.70 and $2.30 per Boe, if you include equity compensation. Selected cash costs including lease operating expense, production tax, cash G&A and interest expense were lower at $10.60 per Boe for the fourth quarter, down 9% from the fourth quarter of 2016 and $10.97 for the full year. As we head into 2018, we expect to maintain low operating cost and high margins. As expected, our oil differential continued to improve throughout the year. The full company fourth quarter oil differential was $4.23 per barrel, a year-over-year improvement of 39%. The full year was $5.50, a year-over-year improvement of 25%. We expect further improvement in 2018 and are guiding to a differential of $3.50 to $4.50 per barrel of oil. The fourth quarter gas differential was a positive $0.37 per Mcf, while full year 2017 averaged a negative $0.16 per Mcf. Improving gas differentials were attributable to improving liquids prices. Similar to the oil differential, we expect further improvement in 2018 and are guiding to a positive range of flat to positive $0.50. Now I'd like to discuss our 2018 outlook in a bit of greater detail. For 2018, our capital budget of $2.3 billion should generate 17% to 24% annual production growth with positive cash flow of up to $900 million after funding CapEx. That's at $60 WTI and $3 Henry Hub. Our guidance is inclusive of the updated type curves as announced and is appropriately risked as we've done in the past. We have hedged in excess of 80% of our gas production for the remainder of the year at an average price of $2.88. Gas hedging has been supportive of our business model. For instance, in 2017, we realized approximately $92 million from gas hedges, and we are significantly in the money on our 2018 hedges. We remain un-hedged on the oil side, allowing for full participation in prices. The budget is cash neutral at an average WTI price in the low to mid-40s for the year. As a reference point, a $5 move in WTI prices will impact our full-year cash flow by approximately $250 million to $300 million, and a $0.10 move in gas impacts annual cash flow by $5 million to $10 million. As you can tell by the low cash breakeven price and the sensitivities we are providing, we are well positioned in a wide range of commodity price scenarios. This budget also contains approximately $500 million of capital that will be spent in 2018, but will have no impact on 2018 production, but instead will benefit 2019 production as the wells come on line. The budget targets a 2018 annual production rate of 285,000 to 300,000 Boe per day, and a 2018 exit rate between 305,000 and 315,000 Boe per day. Oil production should range between 57% and 60% of total production throughout the year, depending on the timing of large pad projects coming on line in both the Bakken and Oklahoma. For the first quarter, production should range between 285,000 and 290,000 Boe per day. For 2019, the company currently expects production to grow 15% to 20% year-over-year with a capital budget of $2.5 billion to $2.8 billion while generating significant free cash flow comparable to 2018 projections. 2017 was a great year. This sets us up well with strong momentum carrying into 2018, which we expect to be a breakout year as Harold articulated. With that, we're ready to begin the Q&A session of our call, and I'll turn it back over to the operator. Thank you.

[Operator:]

Our first question comes from Drew Venker, with Morgan Stanley.

[J. Warren Henry:]

Hey, Drew.

[Drew Venker:]

Hi, everyone. The outlook looks very strong here. And you guys talked about a lot of free cash flow generation. On our numbers at least, I think, you're going to achieve the low end of your leverage target by the end of 2018, so think about a lot of free cash flow generation in 2019. So I'm wondering what you do, when you've already achieve that target if I'm right by the end of this year, do you use some of that additional free cash flow for something other than debt reduction, or if – can you just offer any thoughts you have there?

[John D. Hart:]

I think, that will be a great position to be in. We see a very aggressive path towards achieving our targets as well, timing may be here or there, but for instance getting below $6 billion, your math, our math. I mean, you can see that's coming here in a few short months. Kind of mid part of this year, we'll have a – our revolver will be paid off late this quarter, early next quarter is a further example. So, debt reduction is obviously occurring very rapidly. As we go forward, that gives us – we achieve those targets, that gives us a lot of optionality. We could certainly – we have a long deep inventory base that we could choose to deploy some more capital into in the future to grow at even stronger rate as a larger company if we choose to while still putting up a significant amount of cash flow. We also have various options with shareholder returns and other things that we'll consider. Those are things that we talk about actively and frequently. They're not things that we've made a formal decision on. What we're focused on right now is generating strong cash flow, reducing the debt, and continuing to further strengthen the company and drive shareholder returns.

[Drew Venker:]

Thanks for that, John. And there's obviously a lot of flexibility that you guys have. And I think one of the things that's differentiated Continental over the years is really focusing on new organic play generation. So I was partly wondering if you think it is a really potentially great use of cash to fund some of those. You guys said earlier on the call that you're working on some stealth plays and you really like that stealth play option. But if you could speak to that and anything that you would really consider on the shareholder return front that you just mentioned.

[Harold G. Hamm:]

Yes, Drew, it's a good point. We do like new plays, and we've learning a lot with everything that we're doing, applying horizontal drilling technology to just tight rock reservoirs. And we're certainly going to be testing some of that this coming year, and so we have planned for that. That's we think a good place to put it. As we burn up a little bit of inventory through the years, add a lot more.

[Drew Venker:]

Thanks for that, Harold.

[Harold G. Hamm:]

Yes.

[J. Warren Henry:]

Thanks, Drew.

[Operator:]

Our next question comes from Brian Singer with Goldman Sachs.

[Brian Singer:]

Thank you. Good morning.

[J. Warren Henry:]

Hey, Brian.

[Harold G. Hamm:]

Good morning.

[Brian Singer:]

I wanted to start in the Bakken. You highlighted the improvements in type curve strong wells and I think a 25-mile diameter among some of the recent strong wells. What's the scope and drivers of potential further increases to the type curve, and if at all? And do some of the recent wells have any implications for any changes to inventory or is it simply just better recovery or rates of return on what you already have?

[Jack H. Stark:]

Well, I always talk to Gary about that regularly because we continue to see these optimized stims really have strong, strong performance. In our slide deck in the back, you can see how really we're starting to push the – beyond the type curve we got now with some of the performance of those wells. But we need to get a deeper inventory of these to give us confidence that at some – that type curve represents everything across the board and that's what we're trying to do here. But clearly, we've taken the play to a whole another level and we'll continue to push out from this area, where you can see on the map on page 11, where we've done our 134 optimized stims. So we'll continue to push that envelope out because what we see is essentially the – basically, people talk about core of the Bakken. Bottom line is this technology is expanding the economic core of Bakken really, I mean, all – throughout the whole play. I mean, it's just – it's been a remarkable uplift. And, Gary, you have any comments?

[Gary E. Gould:]

No. We like what we're seeing early on. Fourth quarter, we averaged between 50 and 60 stages. We averaged 1,200 pounds per foot. And you see the great average IP we have, 2,180 Boe per day which was 25% higher than third quarter. So we're very encouraged by our initial results. It is really amazing Brian that here we are, 15 years after being, starting in this play and we're just really now starting to truly unleash the true potential of this resource. It's a remarkable oilfield, and I always say it's 80% oil.

[Brian Singer:]

Great, thanks. And my second follow-up question is with regards to midstream. Harold, I think in your opening remarks, you flagged some of the work that you guys have been doing with regards to trying to ensure better realizations. And I wondered if you could add a little bit more color on that particularly on the natural gas side. And as an example, as we look at your expectations for natural gas realizations for 2018, how much of that is just the uplift from NGLs being a piece of two-stream reporting versus an advantage that you would have in the face of what we've seen as some wider differentials in some of the areas in which you're operating?

[Harold G. Hamm:]

Well, our team has done a wonderful job. As we've gone forward here with a lot of optionalities, we're trying to stay in front of the production wave that we have coming which is a big job in itself and these guys have done a great job. We're always open, we like somebody else to handle the bulk of the facilities that we need out there, but we're always, if they don't do it, we could step in and pick up the slack and hopefully, we don't have to do that but you're right, the bulk of the value has been increased liquids. They were – they value the liquids. And we did a lot of work early on. Ramiro and his team did – a lot of these guys on a lot of these companies wanted to guarantee some rate of return. And so they went to a unit basis on moving to Mcf. And so we took the commodity risk, but that's paying off really good now and will in the future as we go forward. So that was a good move and it worked out exceptionally well.

[Brian Singer:]

Great. Thank you.

[J. Warren Henry:]

Thanks, Brian.

[Operator:]

Our next question comes from Neal Dingmann with SunTrust.

[Neal D. Dingmann:]

Good morning, gentleman. Looking at slide 14, where you sort of lay out your EURs for both the parent and child wells, I'm just wondering, Jack, for either one of the guys, or Gary, how do those wells look? I'm just wondering how each of those type of wells look after, say, four to five years when you look at the parent versus the child there?

[Gary E. Gould:]

Sure. And we show that a little bit on page 14. I'll take some more time really and expand on this a little bit more. That is an important slide for us. The key for us is that we are working to maximize the value for the entire unit. That means maximizing the PV-10. This slide 14 is probably the first time an oil and gas company has ever described this to investment communities. So I'll take a little time to go through it. I'll point out a few bullets first on the top left. On the top left, we see that in order to maximize the PV-10, we see an optimum well count of eight and optimum EUR of 9.6 million Boe for the entire unit and an optimum very high rate of return of 96% for the unit. To address your question specifically, look at the bottom left which shows comparison to type curves between a unit well and a parent well. And what you can see is those curves are closer together at the IP and then spread apart as the well continues to produce. So early on, we see about a 15% lower IP for unit well than a single parent well and overall for the EUR, we see about a 30% lower EUR of about 1.2 million Boe on average compared to our parent well of 1.7 million Boe on average. And these numbers are very similar with information we have provided in prior quarterly earnings calls. And what I might do to kind of describe our process a little more is finish with the chart in the upper right. On the upper right, what you see is some bars that represent six different cases that increase in well count as we move from left to right. And those bars represent the unit PV-10. So as we move from well counts of 1 to 10, we see that the maximum PV-10 is at a well count of 8 which generates an $87 million maximum PV-10 for the company. And so at that point, we're generating a very high 96% rate of return for a well count of 8 with a unit EUR of 9.6 million barrels or an average or 1.2 million Boe per well. And so that's how we look at it. And again to address your question, we see about 15% impact early on. But then as time goes on over the life of the well, we see about 30% impact.

[Neal D. Dingmann:]

Great, great details, Gary. And then just for my follow-up, I was wondering when you guys look at M&A both sort of inside and outside of the basin, you certainly have a big acreage footprint now between your – obviously your Bakken and your Mid-Con. But again, I believe you've gone a little bit outside of the basin. Just your thoughts as far as looking at additional acreage in and out of the basins.

[Harold G. Hamm:]

Well, Neal, you know we've got exploration in our DNA and we're always looking for new opportunities and so, there is – there are dollars in and have been dollars in our budget to == for additional leasing on new ideas and there will be some testing going on this year on some of those ideas. And not everything has to be a test outside of our leased blocks either because literally, there's a lot of still exploratory opportunities both above and below current zones that we're developing that need to be tested. So, it's a great question, but we constantly are looking. We got a new ventures team that's focused totally on finding new opportunities and we won't stop doing that. It's important to our future, and it's important to us really from high-grading even our existing inventory.

[Neal D. Dingmann:]

Very good. Thanks, guys so much.

[Harold G. Hamm:]

Thank you.

[J. Warren Henry:]

Thank you.

[Operator:]

Our next question comes from Arun Jayaram with JPMorgan.

[Arun Jayaram:]

Yeah, good morning. I wanted to first start in the Bakken. You announced the 39 wells in the fourth quarter. And can you talk about your views on the repeatability of these results as you think about 2018? And could you comment on how the enhanced completions are doing in some of your best core acreage versus some of the non-core acreage or Tier 2 acreage?

[Jack H. Stark:]

As far as the, I guess really the performance of these wells, I mean, you can see it's over a broad area. I think that's the key thing here right now. And if you can – you can see on that map on page 11, we're talking about results being very comparable from south of 40 miles and west 30 miles from that area, say in Montreal and McKenzie County. And so that is a huge footprint, and this type curve, that's the thing you've got to realize, this type curve that we've got here is obviously based on those 134 wells. And I'll tell you, they are really tracking it very nicely. In fact, as you can see there, as you get out there past say 200 days on that chart on page 11, you see that really they're outperforming. So we're very encouraged with what we're seeing. And to your question of just how big of an area might we see this type of performance, well we're continuing to push that envelope, but you got to put into the equation too what you're seeing from other operators out here. The whole Bakken play has been uplifted due to these longer stimulations and all. And you'll find very comparable type results from some operators that have the footprint that are outside of (49

[Arun Jayaram:]

And, Jack, as you're doing these bigger completions, are you using the same spacing or does it cause you to change your spacing assumptions here?

[Jack H. Stark:]

This year we completed about 75% of our program on well spacing that was less than 1,000 feet. And these results include those that are on spacing of 660 to 800 feet, for example. And in this coming year we plan to have the same type of results and our development will be based on about 95% of our development being at that spacing less than 1,000 feet. So we've really already tested in 75% of our program in 2017, and we expect similar results in 2018.

[Arun Jayaram:]

Okay. And my follow-up, we really appreciate the transparency on the well density tests in the STACK. Does the type curve revision change how you think about allocating capital to the STACK, the broader portfolio, and perhaps thinking about another basin on your exploration efforts?

[Jack H. Stark:]

Oh my gosh. No, I mean, if you're looking at the unit economics are 94% or 96%, and that's just excellent. And you can see this year we've added Springer to our inventory. We haven't had any discussion about Springer yet, but we've had it on the sidelines for quite a while. And so we're maintaining 8 rigs in the STACK area, but we're going to have 6 rigs down in the Springer as well as we start bringing on that prolific oil asset down there. So from an allocation standpoint, we're obviously putting a little more emphasis on Springer this year, but that's because it's been sitting on the sidelines waiting for oil prices to improve and they have. And we're ready to get that reservoir start talking to this.

[Arun Jayaram:]

Great. Thanks a lot. Appreciate it.

[Jack H. Stark:]

You bet.

[Operator:]

Our next question comes from Leo Mariani with Nat Alliance.

[Leo P. Mariani:]

Hey, guys. I was hoping to talk in a little bit more detail on the STACK play here. Just kind of looking at your results, I think you guys brought online around 21 wells or so, I think net wells to you guys, in the fourth quarter. Your production was up, I think, roughly 12,000 barrels a day versus the prior quarter. I guess I might have expected it to rise a little bit more based on that. Maybe some of these wells came on late in the quarter, but certainly kind of looking at the well counts you're expecting for 2018, looks like STACK might be down a little bit in terms of certainly run rate versus fourth quarter. I guess there's kind of been some consternation throughout the investment community with respect to the STACK here. Is it something that's going to continue to be a good growth asset for you guys during 2018 for years to come?

[John D. Hart:]

Yeah. This is John. I appreciate the question. I'm going to give you a little color on that. STACK is going to be a huge growth asset in 2018. We showed that year-over-year STACK production volumes 2018 compared to 2017 are going to grow 50% to 60% in 2018 over what you had in 2017. If you look to the exit rate, obviously, we did have a number come on in the fourth quarter as you indicated. Some of those did come on later in the quarter as you alluded to. But exit rate just 4Q over 4Q 2018 to 2017 it's going to grow 20% to 25%, 20% to 30% fourth quarter of 2018 compared to 2017 is what we're projecting and targeting. That's a lot of growth. We've still got 8 rigs in STACK. We're not pulling out of it. We are putting a little more into the Bakken and the Springer because we're focusing on those 80%, 85% oil fairways that we've got there. So it's a play where we remain very excited about, enthusiastic, and you're going to see a lot of growth and productivity out of it.

[Leo P. Mariani:]

All right. That's very helpful for sure. And can you guys maybe talk a little bit more on sort of the status of your asset sale program? Recognize that you guys are a pretty big company and these aren't asset sales that are a huge deal when you look at them individually. But in the aggregate, I think you're still basically trying to raise several hundred million dollars from this program. Is that something that's going to kind of wrap up in the first half of the year? Maybe you could just talk a little bit more about that.

[John D. Hart:]

Yeah. I'd be glad to. We are very active on a number of fronts on the asset divestiture front. I think you'll see some stuff over the next few months out of that. I think you may see some things that are very novel that you might not have expected, but I think you'd be very pleased and enthusiastic about. So those are ongoing and we want to get the correct price. We obviously don't have to do anything to get to our debt targets. You take that $800,000 million to $900,000 million and when you back it off the $6.3 million debt at the end of the year, I mean, it's just math. That shows you we'll be down around $5.5 million without any divestitures by the end of the year, if not better. And adding those on further accelerates that and we are continuing to work on them and we're making great progress.

[Harold G. Hamm:]

And I might add that these sales that we're anticipating, you will not have any of these on your books...

[John D. Hart:]

Yeah.

[Harold G. Hamm:]

...as assets. So, they may not have probably sold in the past, we're probably surprised we ever even owned it.

[John D. Hart:]

Yeah. That was the allusion to some novel things that I think you'll be very impressed with. So it takes time to get the right deals done, and we're focused on getting the proper value and getting the proper deals done with the proper partner. So it's ongoing, and we're enthusiastic.

[Leo P. Mariani:]

That's great color. Thank you.

[Harold G. Hamm:]

Yeah.

[John D. Hart:]

Thanks, Leo.

[Operator:]

Our next question comes from Paul Grigel with Macquarie. Paul Grigel - Macquarie Capital (USA), Inc. Hi. Good morning. With the new 2018 and 2019 strategy around free cash flow, should we be expecting that that free cash flow is ultimately the focus feature or is it something akin to an ROCE metric and could we see that explicitly incentivized as well for the management team?

[John D. Hart:]

Yeah. I think if you look to – the discussion around executive compensation and the metrics are something that frankly we've been very pleased with the market focus on that. If you look at Continental, we have a shareholder that has in excess of 75% in his family. Then you go to the broader management team, we all have significant holdings in Continental. I would say there is nothing we focus on more than driving shareholder value because we're all very significant shareholders. So we're glad that the investor focus has shifted to that. We're pleased that the industry is focusing on that as well, and frankly we think Continental performs at an exceptionally high level. When you take the free cash flow generation combined with the industry top-end type production growth that we can deliver, that obviously drives significant – and the cost efficiency that we have, we can drive exceptional returns on capital employed and other measures as we have historically. So we're pleased with that. We have not finalized the 2018 budget or bonus metrics yet. That is something that is in process. Those types of factors in one form or another will be a significant component of that, and you'll see that when we file our proxy statement here in the spring. So, yes, we align with that, we always have, and you'll see more of an emphasis in the set metrics. Paul Grigel - Macquarie Capital (USA), Inc. No, certainly appreciate that. And then I guess changing tone maybe for Harold on hedging. Interesting comments there. When would the determination come that it is the appropriate time to hedge realizing that – not asking for a specific price, but conceptually how do you guys have that discussion?

[Harold G. Hamm:]

Well, I'll call on Adam here to give a comment or two. We pay a lot of attention to the science of hedging and also to market liquidity that's out there. The market is very backwardated right now. So, Adam, you may want to comment on that.

[Adam Longson:]

Yeah. I think it's partly a mix of what the market is offering you in different hedging structures relative to the risk-reward ratios that you see out there fundamentally and technically. So one of our challenges to date has been that that hedging skew has been fairly unattractive relative to our fundamental risk-reward view as we see it. One of the things that we've been very keen on is not capping our upside as of now because we do see more upside tail risk than downside tail risk. For example, inventories are still heading in the right direction despite U.S. growth, outages are low around the world with rising geopolitical risk. As Harold said, markets are backwardated everywhere in the world and demand is robust and economic growth is synchronizing. So you have a lot of positives still out there. And then in contrast, the downside tail risk is pretty modest at this point in the cycle, particularly relative to the price and hedging options that are out there. So the way we approach it, we obviously watch the market fundamentals and we'll continue to monitor opportunities, but these types of risk profile assessments will determine not only when we hedge but ultimately how we hedge. And I think that that's a key item here of not just doing blind hedging but thinking about it where we are in the cycle, those sorts of things, and we're just not there yet. Paul Grigel - Macquarie Capital (USA), Inc. And it's part of the element – Sorry, go ahead, there (01

[John D. Hart:]

Paul, I think we also have a natural hedge in place. We have a breakeven on our capital budget in the low-to-mid $40 price range. And with the level of significant free cash flow that we're putting off, we're obviously not overextending ourselves, and that allows us the opportunity to participate some in that market move and those tightening of markets that we see positive for oil prices. Paul Grigel - Macquarie Capital (USA), Inc. No, no, thanks, John. And does the lower leverage play an element within the desire or at least the ability to hold off on hedging as well?

[John D. Hart:]

I would say on leverage, I don't want that to get misconstrued. We are very focused on lowering absolute dollar debt. So we view the market improving, we see the fundamentals on that, and obviously we're not spending every dime we're driving. That benefits the debt metrics. So I don't know that our debt being lower on a leverage ratio now drives us not to hedge. We just see the market's improving, and we continue to have a vast array of opportunities to drive down leverage. That's why we gave you the – you saw the fourth quarter improvement in debt. We gave you the January number also as an indication. We're on a very positive significant trajectory. Paul Grigel - Macquarie Capital (USA), Inc. No, appreciate it. Thanks so much.

[John D. Hart:]

Sure. Thanks, Paul.

[Operator:]

Our next question comes from Doug Leggate with Bank of America Merrill Lynch.

[Doug Leggate:]

Thanks. Good morning. It's actually slipped into afternoon, guys. So good afternoon, everybody. I think just first a comment. Harold, you've got in front of this child well issue back in November. And I really want to commend you for getting in front of that because I think it's going to force the market to look at capital-efficient growth for a change, which we've been talking about for some time. So thank you for that. My questions, I've basically got two, one for Jack and one for John. Jack, the five wells in the Bakken 2,200 barrels a day, 30 days. Your type curve is 1,600 barrels a day, if I'm looking at the chart right. What was different in those five wells? I know it's only a fraction. But I'm just wondering if that is a repeatable situation going forward? How could you characterize what was different about those completions? And maybe as an add-on, the completion evolution in the Bakken's obviously changed dramatically. Where does that go in the STACK-Springer? Are we already at optimum completions or is there a lot of learning still to go there as well? I've got a quick follow-up for John, please.

[Jack H. Stark:]

Okay. Gary, you may want to help me out here a bit.

[Gary E. Gould:]

Sure.

[Jack H. Stark:]

But when you're talking about the actual comparison of the stimulations there, I just don't have those off the top of my head, but I don't think they were significantly different. The key thing here is that these wells obviously, their performance is – I guess we're connecting with more rock. That's all there is to it. I mean this rock, you look at it, they're 25 miles apart, the Monroe's and the Tarentaise wells and look at those ones even further south that are in the top 10, they're another 20 miles south. And so people are looking for something unique and I think probably the better way for me to answer this is just the fact that it isn't unique and it's the technology that's making the difference. The rocks haven't changed. And so when you see that good a response over a broad area, that says we've had a technical shift, a fundamental shift in the way this rock will perform because of technology. So is it repeatable? I believe it is. Is it repeatable at this record level? Maybe not, but close to it will surely work for me.

[Doug Leggate:]

But just to – go on Gary, but I just wanted to check, Jack, before you leave the topic. So if the completions weren't that different, what does that say of the risk profile on your 30-day, 1,600 barrels a day or BOEs a day?

[Jack H. Stark:]

Well, I don't think there's...

[Harold G. Hamm:]

I think where you're going here Doug is I think you're asking are we going to have a type curve uplift?

[Doug Leggate:]

Basically, on the front-end of the curve?

[Jack H. Stark:]

And as I've said before, I ask Gary that probably every week of...

[Doug Leggate:]

And it passes on from there.

[Jack H. Stark:]

But it is really important – you're pointing at a really good point here, though. I mean we are seeing very, very strong performance, and I do think there's upward mobility I guess I'd say in our type curve, and we just need to get more. As you know us, we like to get a little bit more history behind these wells before we take to the next level. But I'm encouraged with what we're seeing.

[Doug Leggate:]

Sorry, Gary. Go ahead.

[Gary E. Gould:]

And then as far as your additional question about what are we seeing in our other areas as far as optimum type curves. Our team has done an excellent job in optimizing our completions over the last year. If you look at all our plays, we've just improved our type curves across our plays both in North Dakota and in Oklahoma. And so we're very pleased with where we're at. We are continuing to experiment. There won't be the same design every place and every play. And so really it's about tweaking them right now to come up with the optimum completion with little variations within a play. I think that's really where we're centered from here on out.

[Doug Leggate:]

Thank you for that, guys. My follow-up, hopefully a quick one for John. John, it's really more of a philosophical question than kind of follow-up to the hedging question. The idea that you could generate $800 million to $900 million of free cash at $60 oil. The curve is fairly backwardated still. So I'm just curious why in order to get market recognition for the debt-adjusted uplift to your growth targets, why wouldn't you try and at least lock in the lower end of that as opposed to lock in swaps? Why not use collars to support the downside risk? Just philosophically, how are you thinking about it and I'll leave it there? Thank you.

[John D. Hart:]

I think you can look at the skew on collars, as Adam talked earlier about some of the market dynamics on that, the skew really hasn't been all of that positive. And then with collars to take that downside, you determine where the downside is, then that kind of sets the upside on the collar. So say I want to lock in at $55 on the downside, that's going to cap me in the low mid-60s on the upside. And frankly, we see the potential for the market to move up a bit more from that. And as I spoke of earlier, with the natural hedge, low breakeven price, low operating debt coming down, and a clear path towards it continuing to come down on an absolute basis further, we don't feel compelled to. Beyond that, we've looked at puts and other things. Those get pretty costly from that perspective. So we're hedging now via physical activity and the way we're managing things with our cost structure and et cetera, and that enables us to participate. You contrast that with some that may have been spending their full budget or beyond, and frankly, felt compelled to go out and hedge in the low-50s and have given up all the upside. So we've got a lot of flexibility. It is something we watch very closely. As Harold said, we will hedge oil again and we're not there yet, but it's because of what we're seeing in the broader markets that we see the upside going forward. And there are some other significant companies that are in that same philosophical category with us.

[Doug Leggate:]

John, is a dividend on the horizon at any point?

[John D. Hart:]

We certainly will have the cash flow generation to do that at some point in the future. Whether that's something that we'll do or not, we're not there today. What we're focused on today is getting the debt down. And then as I said, we could put a little more activity or little more cash back into growing even faster if we chose to or into other broadening opportunities as we spoke some of also, but that is a potential. There are a lot of potentials. The key is we're going to have the ability to do a lot of things. What's going to remain constant is that we're going to be a cash flow positive company, and we're going to generate strong growth going forward. This is not a one-year isolated thing. It's not just 2018 and 2019. It's a long-term philosophical positioning for us.

[Doug Leggate:]

Appreciate your time, guys. Thanks. Congrats, again.

[John D. Hart:]

Thank you. Thank you, Doug.

[Harold G. Hamm:]

Thank you.

[Jack H. Stark:]

Thanks, Doug.

[Operator:]

Our next question comes from Kashy Harrison with Simmons/Piper Jaffray.

[Kashy Harrison:]

Good afternoon, everyone, and thanks for sliding me in here at the end. So you all have outlined an exceptional free cash flow outlook over the next several years coupled with strong corporate returns and production growth. And so I just wanted to confirm what I think I heard in the prepared remarks. Were you highlighting that all the updated type curves in Oklahoma were fully reflected and somewhat risked in your forward guidance? And then incrementally, have you incorporated the outperformance in the Bakken into your forward guidance?

[John D. Hart:]

We put out the guidance last Friday. So, it is certainly inclusive of everything that we're talking about today. So, yes, the new updated type curves are in there. We always risk our forecast in a variety of ways. We've done that again this year. You've seen that in the past. We've outperformed in a number of periods because we've done better than our risking. So maybe we've risked too hard in the past. That is certainly factored in there as well. I'm sorry, I've lost the – what was the third part your question there?

[Kashy Harrison:]

Outperformance in the Bakken.

[John D. Hart:]

The outperformance in the Bakken. The type curves are in there as they are. We're outperforming those type curves. You've certainly seen some results. There was a question earlier about some of these records. And is the type curve fully reflective of what we may see in the future? We'll see. We may outperform that.

[Kashy Harrison:]

Got it. That's great color there. And then switching gears a little bit to the Dicksion project that you all talked about. It looks extremely interesting from an efficiency gain standpoint. Could you help us think through just in terms of shift in the well cost, what you think you could ultimately accomplish by exploring this kind of a multi-horizon development?

[Pat Bent:]

Yeah. This is Pat. What we've seen historically on our full unit development is somewhere in the neighborhood of 30% stock (1

[John D. Hart:]

Yeah. This Dicksion project has the potential to just really shorten obviously the cycle times and really smooth out some of the lumpiness in production growth once you get into developing these potentially 18-well units out here and it's been really exciting to watch this happening here because right now we're flowing back Sycamore and Woodford wells while we're drilling Springer wells. And that's what you call efficiency. And on page 18 in our deck, we put a picture of it. You can actually see it on the ground out there and see what's happening here, and it's extremely efficient operation.

[Gary E. Gould:]

This is Gary. And I might add that these type of drilling efficiencies like what Pat has been talking about, some of our teams have been working on all our plays and we've been realizing we've gone through all our plays. And now what we're doing is just taking it to the next level and becoming even more efficient on timing, on how fast we can put on these multiple layers of opportunities on the plays in order to accelerate value even more.

[Kashy Harrison:]

Got it. That was it for me. Thank you.

[J. Warren Henry:]

Thank you.

[Operator:]

Our next question comes from Brad Heffern with RBC Capital.

[Brad Heffern:]

Hi. Afternoon, everyone. I was hoping to dig in on the STACK density test a little more. Looking at the two tests on the over-pressured window, the 5-well per zone test was really significantly worse in terms of performance than the 4-well test. It seems kind of surprising to me that in just a 24-hour IP window, you would see that sort of degradation. So was there anything unique going on in that 5-well test versus the 4-well test as far as completion or anything like that or were they truly apples-to-apples?

[Jack H. Stark:]

I would add that for the Gillilan test which had more wells in it, we also had some vertical production in that one at the same time. So there may have been some impact from that as well.

[Gary E. Gould:]

Yeah. Yeah, we believe there were some vertical production in the unit and it's significant enough to have an impact on the performance, we believe. So, I think, we've got a couple of things going. A little bit too tight at well spacing there and also some just historical vertical production.

[Brad Heffern:]

Okay. Got it. Thanks for that. And then just thinking about landing on eight-wells per section, is there anything that you guys are pursuing on the frac side as far as containment or something along those lines that could make that move up over time or is it sort of set at this point?

[Jack H. Stark:]

Based on – we've had several different density tests as I described on page 13. And so, we believe we're a leader in this play as far as figuring out well density. And so, this is where we're at, at this time.

[Gary E. Gould:]

Yeah. There have been a lot of density tests done out there that are partial densities and just basically close-spaced wells and what we've done, is these six tests that we've done here in the oil window, I mean they are full density tests. So we went into it with the plan that we need to understand what a density unit development would look like, and how it would perform. And so, you don't have "the unbounded wells," that aspect to consider. Here, you're actually seeing what a full unit development looks like. And so, it's enabled us to accelerate our knowledge and what we could expect from these units. And so, that's why – that's the whole thing. If you look at it, with us 90% of our capital approximately in 2018 is focused on unit development. And so bottom line is, we need to be focused on unit economics and you as an industry or as an investment community and analyst, need to be focused on unit economics. We need to change the narrative from well, parent well and child well to unit wells and unit performance, and this is the first step in getting us there.

[Brad Heffern:]

Okay. Appreciate the color. Thanks.

[J. Warren Henry:]

Thanks, Brad.

[Operator:]

Our next question comes from Derrick Whitfield with Stifel.

[Derrick Whitfield:]

Thanks. Good afternoon, all. With regard to the Celesta pilot and your units basin views, could you remind me of the thickness in the Springer in that area versus the thickness in the interval on your other pilots in the field average?

[Pat Bent:]

I'm going to say about 50 feet, 50 to 70 feet and I think they were pretty comparable. Tony, is that...

[Tony Barrett:]

That's correct, yeah.

[Pat Bent:]

Yeah. They are pretty comparable, and we kind of designed that way, so we at least have some good comparative metrics, I mean, I hate to go into a density pilot that you just can't – that isn't very representative of the other one, and so, that was – it was part of our plan.

[Derrick Whitfield:]

Okay. And then a quick non-related question and with SCOOP well type curve revision that you guys just announced, is it fair to assume that, that type curve revision was based on data that included bounded results and therefore should experience less degradation under a full field development view?

[Gary E. Gould:]

Yes. That's correct. Exactly, what you said. You said it well. These were based on what we saw from full unit development and when you put these full units – and just go down the road, like the road development that we're planning in Springer. Exactly right, we won't see those significant impacts from unbounded wells.

[Derrick Whitfield:]

Thanks. That's all for me.

[J. Warren Henry:]

Thank you.

[Operator:]

Our next question comes from David Beard with Coker and Palmer.

[David Earl Beard:]

Hey. Good morning, everyone. Appreciate your – good afternoon. I appreciate you squeezing me in. A lot of ground has been covered obviously. But just back to the STACK on page 14 and page 25, can you give a little color of the difference between the parent type curve of 1.7 and the unit-type curve 1.2? How much of that is rock or geology? And how much of the difference can be attributed possibly to completion design or even flow rate? Thanks.

[Jack H. Stark:]

I'll start out and just say that there's always variability in the geology to some degree. So you can't just throw geology out. But in general, in it – within the unit, we're seeing fairly consistent development of the Meramec reservoir itself. So with that said, Gary do you want to – what came to me as I was thinking about page 25, we've – I'm sorry, that's – never mind. It's doesn't have that one in there, I'm sorry (1

[Gary E. Gould:]

Yeah. These are really the impacts that we're seeing based on well spacing. As far as the completion designs, that's not as much of an impact. We've been at these very significant optimized completion designs for the entire STACK play. And so what we're seeing here is based on well spacing.

[David Earl Beard:]

All right. That's great. Thanks for the time. I appreciate it.

[Operator:]

And I'm not showing any further questions at this time. I'd like to turn the call back over to Mr. Hamm.

[Harold G. Hamm:]

Yes. Thank you very much. I want to take just a moment to thank Warren for 10 years of service to Continental and the shareholders. Warren has been nothing short of a class act in all of his representation of Continental throughout these tremendous years of value creation for the company. That's been nothing short of phenomenal, Warren. We wish you nothing but the best in your retirement years on the farm with your pup. I wish you greatly. We are so blessed you chose Continental to get your distinguished career in IR. Thanks again for everyone who joined us today. Have a great day, and thank you, Warren.

[Operator:]

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.