Continental Resources, Inc.
Q3 2018 Earnings Call Transcript

Published: 31 Oct 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q3 2018 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. As a reminder, this conference is being recorded. I would now like to introduce your host for today's call, Rory Sabino, Vice President of Investor Relations. You may now begin.

[Rory R. Sabino:]

Good morning, and 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

[Harold G. Hamm:]

Good morning, everyone. Thanks for joining us this morning. The third quarter of 2018 proved to be a very straightforward validation of Continental's overall plan for the year. We saw strong price for crude oil averaging nearly $70 WTI for the quarter and natural gas prices above the normal range, validating our decisions to remain unhedged with our crude oil and to curtail our natural gas production in the second quarter until market recovered. Along with record production from the Bakken delivered by Continental teams, net income for the quarter was $314 million, leading consensus. The results of the third quarter began to show the benefits of our decision earlier this year to shift to 95% of drilling activity to our crude oil development projects. In all three operating areas, Bakken, SCOOP and STACK, our teams delivered on unit development with great expertise, while maintaining one of the lowest LOEs per BOE in the industry amongst select oil-weighted peers and delivering on our promise to bring on a new wave of oil growth for the company in the second half of 2018. Approximately, 40% of our Bakken well this year will be brought on in the fourth quarter 2018 as our teams took advantage of the long warm days of summer to drill and complete wells, setting up the third and fourth quarter as well as 2018 to reflect new oil-weighted growth. If you'll recall last quarter, we talked also about a rationale for shifting our focus to oil and accelerating growth in the year end, having recognized an opportunity in the market. While we remain a highly disciplined company with a primary focus on capital, efficient growth, and corporate returns, it was an appropriate time to increase our production growth rate, taking advantage of our inventory and infrastructure within the Mid-Continent and Bakken regions. One of the major benefits from horizontal drilling of large-scale resource plays such as the Bakken that I've witnessed during my 50-year plus as an explorationist is that it has removed much of the drilling inventory and supply side concern from the equation. At least that's the case with us here at Continental. It enables us to accelerate or decrease growth as is warranted. It also gives us the capability to project future activity with a level of confidence never before thought possible in this industry. Our teams are developing a granular update now to our five-year plan, and we will discuss portions of this plan when we give 2019 guidance in early 2019. What I love about this plan is that it's all about the inventory that's on the shelf. In October, we closed on our minerals deal with Franco-Nevada. John Hart will provide more details regarding minerals later in the call. But I want to say thank you to the Continental team, which originated this unique minerals model and have worked very hard to make a close, and Franco team, for all of their hard work. We welcome Franco-Nevada aboard and view this transaction as a growth catalyst for both companies in the future. On the macro side, we see further tightening of oil supply as the Permian Basin remains constrained by infrastructure and Middle East tensions are further elevated by some recent events. Thankfully, the narrative on oil supply can be return – they turned to the positive developments in the U.S. as long-term dependence on foreign oil supply wanes due to our own ability to supply our needs domestically. Although not as financially robust, the natural gas market continues to expand and is showing signs of a much healthier future. Once again, we witnessed the instability of foreign oil supply and the need to put American oil and gas production first. As we believe 2018 is truly proving to be a breakout year for Continental, stronger commodity prices rewarding our non-hedged oil position, along oil price, upside participation for shareholders, and driving free cash flow approaching $1 billion for the entire year. The timing of the planned development of the SpringBoard oil project could not have been better as oil prices and demand have improved in an unhampered infrastructure area. Our years of technology advancements are paying great dividends as our teams are delivering excellent drilling and development results. All these results are just in time for the crude oil super cycle that is now underway in America. Now, I'll turn it over to Jack Stark for more detail on our operating results.

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. We appreciate you joining us on our call today. Our third-quarter production exceeded guidance, coming in at 296,900 Boe per day, up 22% year-over-year and 5% over the second quarter. We exited the third quarter producing approximately 304,000 Boe per day, and the oil production was on the rise. Oil as a percent of production in September averaged 57%, and October is coming in around 58%. By year-end, we expect our oil percentage to approach 60% as we anticipate approximately 10% growth in our oil volumes quarter-over-quarter. This rapid oil growth is driven by two things

[John D. Hart:]

Thank you, Jack. Good morning, everyone. The third quarter was strong with $314 million of net income, generating earnings per share ahead of Street consensus. Free cash flow generated from 2018 activity is also strong and is projected to approach $1 billion for the year. As such, debt is continuing to decline towards our ultimate goal of below $5 billion or 1 times debt to EBITDAX. We anticipate achieving these targets in 2019 driven by further strong cash flow. As of September 30, 2018, our net debt was $5.94 billion or roughly 1.5 times debt to EBITDA. As of October 31, 2018, net debt is projected to be further reduced to approximately $5.7 billion after applying the proceeds derived from our minerals transaction with Franco-Nevada as I will discuss momentarily. We are targeting for 2018 year-end debt of approximately $5.5 billion. A higher level of CapEx was deployed in the third quarter than we anticipate in the fourth quarter. This higher level of CapEx was largely focused on completions activity as we took advantage of better summer weather to complete wells. We averaged nine completion crews in the third quarter. For the fourth quarter, we expect to average six completion crews, a full third less. For the fourth quarter, we expect capital expenditures to range between $600 million and $700 million. The benefit of our third quarter activity was seen late in the third quarter and will carry through the fourth quarter with a strong, oil-focused 2018 exit rate entering into 2019. This production growth will generate a higher level of cash for the fourth quarter, driving further debt reduction. Across our broader guidance, we expect G&A, equity comp and DD&A to be towards the lower end or better on guidance. LOE is updated slightly to a range of $3.50 to $3.75 to reflect the volumetric impact on LOE of our enhanced focus on oil volumes. Production annually and exit rate are solidly within our guidance as Jack noted earlier. We estimate that 2018 CapEx includes approximately $650 million of capital with first production not until 2019. We expect our 2018 endeavors to set the stage for a strong 2019. On October 23, we closed on our minerals venture with Franco-Nevada. As announced last quarter, Continental and Franco formed a new entity to acquire minerals, a majority of which are under operated leasehold and our planned drill schedule. At closing and reflective for purchase price adjustments, we received approximately $215 million for Franco's investment in our existing minerals portfolio. Continental and Franco plan to invest an additional $375 million in minerals over the next three years, subject to achieving agreed-upon development thresholds. Continental's portion of the investment is $75 million, or 20% of the total investment, over the next three years to earn 25% to 50% of the revenues based on achieving predetermined targets. We anticipate achieving the full carry and realizing 50% of future revenues in the foreseeable future. Further acquisition of minerals is ongoing. During the third quarter, we spent approximately $90 million on mineral acquisitions. During the fourth quarter, we project minerals activity totaling approximately $50 million or $40 million less than the third quarter. Recall, mineral acquisitions are included in Continental's CapEx, and then we subsequently bill out Franco-Nevada with monthly capital cost. Thus, minerals along with completion activities were the primary drivers of higher third quarter CapEx. Although minerals revenue and volumes are not currently significant, we do expect strong growth in 2019. As an example, under Project SpringBoard, our minerals venture owns approximately 12% of the net mineral acres, an increase from 10% last quarter with an average royalty percentage of 18.75%. This will generate higher revenues and incremental returns for us in an area where significant development in multiple zones is ongoing. This simplifies our minerals strategy. We plan to utilize our geologic knowledge and land expertise to acquire minerals in areas of future growth. Mineral ownership will enhance project economics and result in our prioritizing areas where we have successfully acquired minerals. We see minerals as another avenue for the company to enhance shareholder returns with the potential for a future IPO or to hold long-term generating another source of cash flow. Though ultimate determination will be a value-based decision, it's nice to have options for a vehicle we expect to derive significant value from over the next few years. In the third quarter, we saw strengthened oil differentials due to strong Gulf Coast pricing, strong seasonal demand, and lower Cushing inventories. With our corporate oil differential at $3.72 and our corporate gas differential at a premium of $0.22, we remain well within our annual differentials guidance. In the fourth quarter, we do expect to see higher oil differentials due to a heavy refinery maintenance season, the level of which is about double the norm for this time of year. Although we expect to see oil differentials to be wider for the fourth quarter, we retain our existing annual guidance, although likely in the upper half of the guidance range. The productivity of the Bakken is driving a significant expansion of basin takeaway. We expect to see the expansion of existing pipeline capacity as well as new pipelines entering the basin. Some of this capacity will come online in the next few months with a strong ramp-up through 2019 and entering 2020. On the gas side, we expect fourth quarter gas differentials to remain strong and reiterate our annual guidance. Looking forward to 2019, we expect a significant expansion of gas processing capacity in the Bakken, expanding as much as 50%. We are actively updating our plans for 2019 and will issue formal guidance in early 2019. We expect continued growth of oil volumes, strong cash flow generation and superior returns on capital employed. We will provide specific guidance on oil and gas volumes separately for 2019 to facilitate your understanding of our oil-weighted production growth. You should expect to see strong oil volume growth as well as a growing oil percentage in 2019. Our expectations for more detailed guidance is intended to provide greater transparency. We are well-positioned not only for 2019, but also the years that follow and look forward to providing you the details. With that, we're ready to begin the Q&A session of the call, and I'll turn it back over to the operator for your questions. Thank you.

[Operator:]

Thank you. Our first question comes from Drew Venker with Morgan Stanley.

[Drew Venker:]

Hi, everyone. I was hoping, John, you just gave some color on what you guys are thinking about higher level for 2019. If you could just give us any updated thoughts there as to how you want to set the capital program philosophically for 2019, whether that's a limitation on the upper end of growth or first achieving your debt targets and then maybe you look to return cash is kind of how you're thinking about that.

[John D. Hart:]

I think we're going to get to our debt targets in a fairly easy fashion. Getting there leaves a significant amount of cash flow to invest. I would expect a higher level of capital activity next year. We're obviously growing and continuing to grow on a larger base. So, we're going to deploy more. But I think cash flow, you're looking at numbers that are fairly similar to this year and of a significant nature. So, we do clearly see getting below $5 billion next year and we see it in a fairly reasonable timeframe. You've heard us in previous quarters talk about, and I would say the same today. But we've talked about dividends that tells you that if we're talking about those things, we're obviously expecting to generate a significant amount of cash flow. But we do not intend for that to impact the growth rate. We are a growth company, and we expect to see strong growth in oil volumes.

[Drew Venker:]

Okay. Thanks for that. And Harold, in your prepared remarks, you talked about being in this oil super cycle. Can you just give us your thoughts on, I guess, macro for one and how that relates to your hedging strategy?

[Harold G. Hamm:]

Yeah. It all comes back to supply and demand in the world, and we still see demand strong, about 1.5 million barrel to 1.8 million barrels of new oil. And on the supply side, hopefully, we can keep up with that. About 65% of that will come from the U.S. But if we go forward with the Iranian sanctions, as I anticipate, take another 800,000 barrels off the market, long term, things are going to get tight. And so, we expect it to be pretty close going forward through the end of the year. So, oil prices are going to be strong, and hopefully we'll have a cold winter to keep us there with natural gas.

[Drew Venker:]

And Harold, as it relates to the hedging strategy, is that – that means for foreseeable future no interest to add hedges?

[Harold G. Hamm:]

Yeah. I'm sorry, I didn't address that. We do anticipate, we, of course, will hedge natural gas as we have opportunity. We have a program ongoing with that. But with oil, right now, we're going to remain un-hedged.

[Rory R. Sabino:]

Great. Thanks, Drew.

[Drew Venker:]

Thanks, guys.

[Jack H. Stark:]

Thank you.

[Operator:]

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

[Doug Leggate:]

Thanks. Good morning, everybody.

[Harold G. Hamm:]

Good morning.

[Doug Leggate:]

John, I wonder if I could pick up on Harold's comment about offering a five-year look at some point. Just at a high level, how should we think about how the company redeploys its, what's going to be, looks like, significant free cash? And I guess what I'm really thinking about here is, this is going to be a question for a company with your limited free float, obviously, because you can't buy back shares. So, how do you think about how you communicate that? Because, obviously, there's some concern it seems that your capital program could end up and redeployed to other areas outside of the current core areas, such as the Permian. So, any help you can provide...

[John D. Hart:]

Sure.

[Doug Leggate:]

For example, 40% of the cash flow would always go back to shareholders, or something – some commentary along those lines. Is that your intention, or how could you help put some of those concerns to rest?

[John D. Hart:]

Sure. I'll try and address your question. There's a lot in there, so if I miss something, ping me back. Our five-year plan and even beyond that, we have a view towards 10 years, is based on the existing inventory. There is no blue sky in our plans. It's based on primarily what you're seeing in the Bakken and in the South, in Oklahoma, in SCOOP and STACK. The New Mexico asset that you referred to is more in the exploration stage. So, it's not really in our five-year currently. As we go forward and as we get greater visibility on that, it's certainly something that we can add. What that tells you is we have a very deep and rich inventory not only in the Bakken, but also in SCOOP and STACK, and that we've got plenty of inventory to generate significant growth plans. We have a very clear view over the next five years that enables us to do a lot of long-term planning. I would expect capital deployment to be somewhat in the range that – between the assets that we have now. We are going to be focused on the crude oil side of it, in the broader liquid side. So, you'll see a good growth there as well. In terms of a percentage of return of capital, that's something yet to be determined. We're going to hit our debt target. So, we're going to hit them fairly expediently. And then with that, we've talked about dividends before. I don't think we're going to chase dividend yield. We'll put something in place that is a reasonable and prudent and sustainable in a variety of crude oil price environment. So something that we could sustain in a lower market and we'll go from there. As you look to debt, if you just go to our callable bonds, we could take that all the way down to $4.2 billion. So, we've got a lot of room there and then that does position us well for dividends, or to invest in other opportunities as we see them. For instance, if that's New Mexico or other things, we're always looking for opportunities.

[Harold G. Hamm:]

And then we'll probably all be...

[Doug Leggate:]

Go on, Harold. Sorry. Please.

[Harold G. Hamm:]

We'll probably all be looking at a stock buyback as cheap as it is today.

[Doug Leggate:]

Yeah. Well, it kind of leads me to my second question, if I may, and this is really more – or Jack, you know what's coming here, but your stock's down 30% from the top. Obviously, you can't buy back your shares. But I think there's still – despite your incremental disclosure, I guess, this morning, there's still some questions, I think, over what the inventory depths looks like. And Jack, what I'm referring to is when you give a rate of return guide, obviously, that's a great number to show to market, but it has inputs and outputs, meaning that smaller wells have smaller capital cost, for example. So when you talk about the 4,000-location inventory in the Bakken, can you help us understand what proportion of that would you characterize as, let's say, the 1.2 million type curve or better? And how do you think about the average over that range? And I'll leave it there. I've got another one, but I'll leave it there for someone else.

[Jack H. Stark:]

Sure, Doug. What I would say is that this Bakken inventory that we talk about is not, say, high-graded. This 10-year inventory we're talking about, it's not high graded to just the 1.2 million area. There's areas out there where we're seeing a bit less rate EUR, but we're also, as you said, seeing less cost. And we're continuing to push this envelope. But also think about it vertically, we're also seeing various degrees of EUR vertically as well from the Middle Bakken to the Three Forks to the Three Forks 2, as I mentioned. So within units, you have variation in the average EUR per well. But what we've provided here, and what we're trying to do, when we do give you this rate of return, is trying to give you that blended perspective of the quality of that because we have a huge footprint in this Bakken with our leasehold position of 800,000 acres out here. And so, we're drilling in quite diverse areas and continuing to expand that. And our teams have type curves all across this field. And as time goes on, we're going to be able to provide you more clarity on what some of this – the inventory looks like as we continue to expand this play. But I mean, right now, I think, quite frankly, that giving you a rate of return of 80% to 100% shows extremely good capital efficiency that we are able to derive from our assets up here in the Bakken. And I think, as an investor, you should really get great comfort with that. And when we pull out – when we talk about kind of our five-year look on what we believe – our five-year plan here, as we get around to the first year, we talk about that a bit. I think you'll get comfort level in just how strong the Bakken is as a part of that growth.

[Harold G. Hamm:]

Yeah. And don't forget the wells that's above that 1.2 million. That's a blended average. So, there's lot of wells up to 2 million barrels EUR.

[Jack H. Stark:]

Yeah, we've got wells out there, as you know, with – in individual zones where you get in excess of 1.2 million and you get some below, and that's – the 1.2 million is our average.

[John D. Hart:]

Doug, remember, we're one of the few companies that guides on the return on capital employed. We've also indicated that we expect that to be increasing next year. It will be part of our guidance for next year. I would expect a higher range than what we've had in 2018 as it's continuing to improve. That's driven by the Bakken and the strong returns that you're seeing in the South as well. And we'll follow up – you said you had another question, we'll follow up with you on that.

[Doug Leggate:]

Yeah. I'll take that off line, John. But I appreciate the five-year guides. I think everybody listening in would really appreciate when you come out with that. So, thanks for considering, and I'll see you in a couple of weeks. Thank you.

[John D. Hart:]

Thank you.

[Harold G. Hamm:]

You bet.

[Operator:]

Thank you. Our next question comes from Arun Jayaram with JPMorgan.

[Arun Jayaram:]

Good afternoon. Just some thoughts, John, as you think about some of the near-term Bakken diffs, how do you think the diffs could play out over the next two to three quarters?

[John D. Hart:]

We actually expected some of those questions. So, we've brought Ramiro Rangel and Josh Baskett, the heads of our Marketing Department in, and we're going to let them speak up on some of that today. Thank you for the question.

[Ramiro F. Rangel:]

This is Ramiro Rangel. During the third quarter, we had the record diffs, and they were really attractive. What happened is there were significant pad to refinery turnarounds in October that, coupled with seasonal demand softening, ended up in differentials weakening. But we expect that to get better in the fourth quarter that we feel that there's going to be – capacity is going to be built. So, longer term, we feel that we're in pretty good shape.

[Arun Jayaram:]

Could you maybe quantify kind of your thoughts on how the diffs could play out a little bit more?

[Ramiro F. Rangel:]

Sure. I think a lot of it is going to be tied to future capacity. And we feel that there's probably going to be about 700,000 to 1 million barrels per day of additional pipeline capacity. And we feel that as that comes on, Arun, that the differentials will start to improve. And so, we really feel that that's going to be one of the biggest keys. And then for us, with us being the largest producer in the Bakken, we have significant leverage and options and flexibilities that really allow us to be able to manage our portfolio and optimize our netbacks. So, we feel that we're in better position than most. But the bottom line is that we feel that the midstream companies that are out there have enough proposed pipeline projects that are going to allow differentials to come back in. So, I think that's the key.

[John D. Hart:]

Arun, as a little bit of additional color, recall that in the South in SCOOP and STACK, we're looking at a sub-$2 oil differential, so very attractive that we're continuing to see that strength there. And recall that I also indicated in the call that we are retaining our existing guidance for the year. Our guidance is $3.50 to $4.50 corporate-wide for the full year. We did indicate we expected to probably see it in the upper half, so that's signaling some up in the fourth quarter. You could see a buck or two bucks, a couple of bucks higher in the fourth quarter. But as Ramiro indicated also, as we're coming out of refinery turnaround, we're starting to see some improvement there. So, it's a little bit of a moving target. But I think we're well-positioned. And these things tend to pass. The key is there's a lot of infrastructure coming into the Bakken and there's a lot of long-term capacity there. (40

[Jack H. Stark:]

And Arun, I just think I'd just add in there too that about 50% of our volumes up in the Bakken are on firm commitments there. And then those firm commitments are – I mean, I think we're probably in with (40

[Arun Jayaram:]

Great. Great. Jack, any initial observations on row 1 of the Springer program, how are the initial wells? It looks like they're meeting your expectations, but just any initial observations would be helpful.

[Jack H. Stark:]

It's really where we're at right now. They're just very early in their flowbacks right now, and we've got nine flowing back and another eight there in various stages of completion. So, what we'd really like to do is get these wells on and be able to give a broader, better perspective as opposed to just a couple single wells, give a perspective on just what kind of results we're seeing across row 1. So unfortunately, it's just a bit early for us to be able to do that. The wells are still cleaning up. We really thought we might be able to do have some results to talk about. I mean, I'd love to have some right now, but we're just not quite there. But as we do get these results, we've talked about between now and year-end possibly having some sort of a webinar, perhaps, to discuss the results. We'll just see. But right now, we've got to just continue to be patient and allow these wells to clean up and then we'll have more to talk about.

[Arun Jayaram:]

Fair enough. Look forward to that five-year guide. Thanks a lot, gentlemen.

[Jack H. Stark:]

And I will tell you, it's oil. Oil's coming back. There's no problem. And they're starting out nicely. Thank you.

[Arun Jayaram:]

Great. Thank you.

[Operator:]

Thank you. Our next question comes from Jeanine Wai with Barclays.

[Jeanine Wai:]

Hi. Good morning, everyone.

[Harold G. Hamm:]

Good morning.

[Jeanine Wai:]

In terms of the SCOOP, I was just wondering if we could get a little bit more color there on your near-term activity plans. I think you currently have the 14 rigs allocated to Project SpringBoard, but you reported that you have a total of 16 rigs in the SCOOP overall and you're ramping to 18 by year-end. So, we're just wondering what the non-Project SpringBoard rigs are doing? And how does the oil capital efficiency of whatever those rigs are doing compare to the Bakken and the SpringBoard?

[Pat Bent:]

You bet. This is Pat Bent, and that is correct. We'll exit with 18. The other rigs outside of those 14, we have one in Merge (43

[Jeanine Wai:]

Okay. Great. And then sticking back to some of the CapEx points, you mentioned deploying more capital next year. And I think the old commentary was for $2.5 billion to $2.8 billion for 2019. So, how should we view the $600 million of CapEx this year that won't really produce until next year? Is it more of a credit towards 2019 or it sounds like you're pushing forward a larger program. We're just trying to frame kind of free cash flow and what's available for the dividend? Thank you.

[John D. Hart:]

Well, free cash flow – we'll have plenty for a dividend. The free cash flow that we're looking at is something that's in a comparable type range to what we've had, in what we're projecting in 2018. That could move some, but I think if you compare us to the industry, we are very much in the significant category in terms of cash flow generation versus peers. So, I would expect that to continue. Stronger oil prices, obviously, enable us to do a little more while still generating that cash flow. So, we'll probably be looking at a higher level of CapEx, but it'll be in a reasonable range and it will still allow us to generate that strong amount of cash flow. We're not altering that in any form or fashion.

[Jeanine Wai:]

Okay. Great. Thanks for taking my questions.

[John D. Hart:]

Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from Derrick Whitfield with Stifel.

[Derrick Whitfield:]

Good morning, all, and thanks for taking my question.

[Harold G. Hamm:]

You bet.

[Jack H. Stark:]

Good morning, Derrick.

[Derrick Whitfield:]

Building on Arun's Bakken takeaway questions, what's the timing for incremental pipeline capacity in the Bakken and to what degree could rail offer near-term incremental capacity?

[Josh Baskett:]

Sure. This is Josh Baskett. So, we see some fairly substantial opportunities coming our way early 2019 and then throughout the entire year. We're under CA on several of these opportunities, so we can't really throw out the figures, but we definitely see some relief coming very soon. As far as the rail capacity, right now we're at about 270,000 barrels a day and we believe we can get over 300,000 barrels a day. We're also looking into the possibility of converting some of the older rail cars for the new standards.

[Derrick Whitfield:]

Great. And then maybe moving over to the STACK, when you think back to your Q4 2017 disclosures on full field development concepts, has incremental data since then, in any way, biased your thoughts around optimal spacing for future units? And where I'm specifically speaking to is the outperformance of the three units you guys just announced and the comments that you have on page 14, which indicates Simba's results will help you define a development model for the STACK condensate window.

[Gary E. Gould:]

Yes. This is Gary Gould. And yes, we're very proud of our teams for the results that we're seeing from our STACK units. All three of them just give us really strong results for the six wells. I think it's important to note that whether we optimize with six wells or with eight wells, it's going to depend on what the geology is across the field. Some areas have more original oil in place or more condensate in place and so, in some places, we may develop with eight wells and in others it may be six wells. In other words, three to four wells per zone. But as you can see from what we show on page 13, the results that include record results this quarter, show that we're getting almost the same PV-10 from six wells this quarter as we had forecast for eight wells. So, very good results this quarter.

[Derrick Whitfield:]

Thanks, guys.

[Jack H. Stark:]

Yeah. So, I can't help but add there, just the team's done a great job studying this, and the results that we're seeing here just really confirm our model, I mean, and bottom line is that – and it is obviously going to help us as we continue to develop the 65 units we've got yet to develop in the play.

[Rory R. Sabino:]

Thanks, Derrick.

[Derrick Whitfield:]

Thanks, guys.

[Operator:]

Thank you. Our next question comes from Bob Morris with Citi.

[Robert Scott Morris:]

Thank you. Jack, nice results in the STACK oil window. On slide 13, just continuing with that, you show that for the six-well units, the uptick to $100 million in PV, but you're still using a total unit EUR of 8 million barrels, which implies 1,333 MBoe per well, but that uplift from the Jalou and the Homsey on orange part of that bar seems to reflect the outperformance or an even higher EUR. So, my first question is, in that orange bar uptick, what is the assumed EUR to get to that $100 million PV-10 now?

[Gary E. Gould:]

Yes. This is Gary Gould, and that's incremental value reflected in that orange bar. You're right, we kept EUR the same. It's just early on the flowbacks. And so, we clearly see higher IPs, and we expect that EURs could very easily increase as we go forward. But for now, we held the EURs the same, but we did raise the IPs consistent with what you see on the previous page and that's how we got the higher value.

[Robert Scott Morris:]

Okay. So that just essentially assumes acceleration of the same reserves and getting that higher value. So my second question is the factors that drove the outperformance in those wells, which are very good at Jalou and Homsey, how many of those would – or those factors translate to if you were drilling eight wells per section, would you expect to see similar type outperformance on eight-well units from what drove the outperformance on the six-well units to then move up that valuation too?

[Jack H. Stark:]

Well, it really comes down to the oil in place and placing the proper number of wells in each of these units based on those estimates. And so, the performance in these units is demonstrating to me that the teams had identified and figured out what would be the proper well density and well-spacing in these units. And so, each of these units, as we go through them, as Gary said, we're looking at four to six wells per zone is what we anticipate we'll typically put in each of these reservoirs. And we expect to have, on average, about two wells per zone. So, that can mean six to eight wells typically per unit. And with that, we think that gives us the optimum economics for unit development.

[Robert Scott Morris:]

Sure. I guess I was – just with the outperformance in the future, if you drill eight-well units, is there an orange bar then to be put on top of the green bar in the future on what is the eight-well count units?

[Gary E. Gould:]

This is Gary Gould, and that's a possibility. We will continue to evaluate the results that we've seen to-date. We've got several different density tests that we've got in the ground now and with the strongest results most recently. So, we'll continue to optimize as we move forward.

[Jack H. Stark:]

Yeah. If we duplicate these results with eight wells, we're definitely going to see that eight bar – that present value from the eight wells climb, no doubt.

[Robert Scott Morris:]

Yeah. No. Actually, that's what I'm looking for. Great results. Thanks.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. Our next question comes from Brian Singer with Goldman Sachs.

[Brian Singer:]

Thank you very much and good morning.

[John D. Hart:]

Good morning, Brian.

[Brian Singer:]

Can you talk a bit more about how the positive results you're seeing in the Bakken impacts your willingness to allocate increased capital activity on a relative basis, i.e., do you see yourself shifting a bit more on a percentage basis towards the Bakken going forward? And then as more of a follow up to Doug's question earlier, we look at slide 8 where the majority of the wells that have been drilled or that you're highlighting here are within a 30-by-40-mile box. When would you expect to see any geographical shifts away from that box and what impact on productivity would be expected?

[John D. Hart:]

So, on the first part, on the capital allocation, the good part of that is we're blessed with the deep oil-rich inventory in the North and South. Percentages may vary a little bit from one to the other depending on the timing or development plans in a given area. But when you look at Project SpringBoard in the South, it competes very favorably with the strong Bakken results. So, we do have some geographic opportunity, and we have geographic opportunity within basin also just because of the size and scale of our position. So, it's not uncommon. You'll see some moving around. We're still working through some of our plans for next year, finalizing some of those. I would say, for now, the allocation between the Bakken and SCOOP and STACK is relatively consistent. So, the second part...

[Jack H. Stark:]

Yeah. And on the second part here, Brian, looking specifically at page 9, looking at that extend – (52

[Brian Singer:]

Page 8, I'm sorry to interrupt.

[Jack H. Stark:]

Page 8. I'm sorry.

[Brian Singer:]

There you've got the 30-by-40-mile box, right, where the majority of the wells are. And I just wondered what the inventory is within the box relative to outside the box? And when there would be a disproportionate shift away from that area.

[Jack H. Stark:]

I don't have that just off the top of my head right now what the inventory would be within that given area. But what I can tell you is if you look at page 9 that – you can't just look at our results, you've got to look at everyone's results across the play to get – really appreciate what's happened in the Bakken, this renaissance as a result of basically previously under stimulating these wells. And this footprint continues to expand. And at this point, I mean, there's wells that obviously aren't – the results aren't shown here yet, but are testing substantially further north and south. And so, I think you'll – some results will be forthcoming in those areas as well. But specifically, for the inventory right in that particular box, I don't have that right now. We can talk later maybe.

[Brian Singer:]

Yeah. That's great.

[Harold G. Hamm:]

You can see some of the wells that Jack's talking about is definitely out of that 30-to-40-mile box already.

[Jack H. Stark:]

Yeah. We've often talked about you see wells up there close to Divide County that are outperforming at the 1.2 MBoe equivalent model. So anyway, I think, just again, this is an expanding play through technology.

[Brian Singer:]

Great. And then, you mentioned – it might have been John mentioned in the comments that you had nine crews running in the third quarter and that's going down to six in the fourth quarter. Can you talk about what is more of a normalized rate or as you think about – broadly, as you think about 2019 or, I guess, to what degree moving from nine to six is a function of timing and capital allocation versus efficiency gains?

[Gary E. Gould:]

Yes. This is Gary Gould. Moving from nine to six is based on having moved our completion inventory to first production. And so, during the summer months, we have a lot more activity, especially in North Dakota when we have those long hours of sunlight and we picked up some frac crews, and got our DUC count well down so that, by the end of this year, we're going to be at just normal operating counts when it comes to wells that are drilled but not yet completed.

[Brian Singer:]

Great. Thank you.

[Operator:]

Thank you. Our next question comes from Ryan Todd with Simmons Energy. Mr. Todd Your line is open.

[Ryan Todd:]

Sorry. I think I was on mute there. Can you hear me now?

[John D. Hart:]

Yes.

[Harold G. Hamm:]

Yes.

[Ryan Todd:]

Great. Thanks. Maybe if I could follow-up with one on the Bakken. You're running eight rigs at present, which is a little ahead of our expectation at this point. Obviously, a lot of completion's taking place in the fourth quarter. How should we think about trajectory there in the 2019 maybe both in terms of rig count and cadence of completions?

[Gary E. Gould:]

Well, we are rigging up to have more activity and growth in the north. And so, as mentioned earlier, we're going to be in a normal well count as far as just standard operations. But then, as we move forward and get more of these wells drilled, then we'll be picking up more completion crews, and this will be a driver for how Continental stays oil-weighted for the next several years.

[Pat Bent:]

And this is rig count for 2019.

[Ryan Todd:]

Sorry, is eight rigs a good assumption to think about for 2019 in the Bakken or will we likely see that go higher?

[Jack H. Stark:]

Well, we really haven't come out with our plan for 2019, obviously. But we do anticipate some additional rigs being added in 2019. We've added these rigs. Like you said, we're ahead of schedule here. We expect it to be about at eight at yearend. We're already there. And that's just basically us getting prepared for continued growth into 2019. And so, you will see some additional rigs coming into the play in 2019. We will get more details on that as we get out our 2019 plan.

[Pat Bent:]

And this is Pat Bent again, and like we'd indicated, we will exit 2018 with eight rigs in the Bakken. I just want to mention that our rig acquisition activity is very opportunistic going into 2019. And so, we don't need to pick up every rig we see come by. And so, we have the opportunity to be fairly selective in any incremental rig activity going into 2019.

[Ryan Todd:]

All right. Thank you. And then maybe one follow-up on an earlier conversation on cash priorities in terms of use of cash, I appreciate some of the discussion about the dividend. Well, what would you need to see – I know you're considering a dividend. What would you need to see kind of to make that happen? Is it a question of do you need to get the debt down to that $5 billion target first? Do you – is it a combination of kind of confidence in the commodity and operational kind of critical mass? How should we think about what you would need to see kind of to kick that off?

[Harold G. Hamm:]

Yes. You're exactly right, Ryan. We intend to get debt down to $5 billion and consider this dividend, or look ahead at as far as oil prices, and supply and demand certainly will be a factor in that.

[Ryan Todd:]

Okay. So, it would – I guess you need to hit the debt target first before you consider that.

[Harold G. Hamm:]

That's correct.

[Ryan Todd:]

Is that fair? Yeah.

[Harold G. Hamm:]

Yes. That's correct.

[Ryan Todd:]

Okay. Thanks. I'll leave it there. Thank you.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. Our next question comes from Brad Heffern with RBC Capital Markets.

[Brad Heffern:]

Hey, everyone. Just going back to some of the STACK spacing questions from earlier in the call. I was just wondering if you could give an update on what the STACK inventory number is. Is it just the 65 units you mentioned times 6 to 8 wells per section or is there a different way we should be thinking about that?

[Tony Barrett:]

Hey, Brad. This is Tony Barrett. So, when you – the inventory we removed, the (59

[Brad Heffern:]

Okay. Got it. Thanks for that. And then, I guess, on the NGL front, can you talk about how much of your corporate-wide volumes go to Mont Belvieu and any contracts you have for fractionation there?

[Ramiro F. Rangel:]

Sure. Out of the Bakken, a lot of our NGLs are priced out of Conway. But in Oklahoma, the preponderance, 85% to 90% is priced off of Mont Belvieu. And we do see a lot of fractionation being built. We feel that in 2018 about an addition of 100,000 barrels per day is going to be built of new frac in 2019, about 300,000 barrels; and about – 2020, about another 500,000 barrels. So, you've seen a lot of new capacity that's going to be built in Mont Belvieu, which should really help the industry a lot.

[Brad Heffern:]

Okay. Then no concerns about any constraints on fractionation capacity before that comes online?

[Ramiro F. Rangel:]

It's going to be sporadic for some producers. Our agreements are very attractive to us. So, we haven't seen that really impact us. But the industry is responding really well in being able to build the fractionation that's needed.

[Brad Heffern:]

Okay. Thank you.

[Harold G. Hamm:]

Okay. Thanks, Brad.

[Operator:]

Thank you. Our next question comes from Subash Chandra with Guggenheim.

[Subash Chandra:]

Yeah. Hi. Just back to the Bakken oil question, I guess with the takeaway 700 million to 1 million barrels for the basin you're anticipating, do you also anticipate any change in your oil flows, Gulf Coast versus Cushing versus East or West Coast?

[Josh Baskett:]

Sure. This is Josh Baskett again. We are currently evaluating several new projects. And we believe, ultimately, that the Gulf Coast will be where the majority of the growth barrel show up. Again, we're under confidentiality, so we can't share too many details there. But we certainly believe that's the future for the Bakken barrel.

[Subash Chandra:]

Okay. And...

[John D. Hart:]

And we're always working to go to advantaged markets and looking for the best price. So, you can rest assured that's the focus and intent of our activities.

[Subash Chandra:]

Yeah. Sure. I would just, from an urgency perspective, because it looks like the east (1

[Jack H. Stark:]

We believe by January, we'll see some expansions of capacity – pipeline capacity. We also see some expansions come in maybe midyear, and then a big slug towards the end of the year. So, again, it's coming fairly soon.

[Subash Chandra:]

Okay. Terrific. And just as a follow-up, the SpringBoard guidance you'd given earlier, I think it was 10,000 barrels a day of oil from maybe the fourth quarter or something like that. And that was given before any of these rows were drilled or flowing back. Do you anticipate to fine-tune that to reappraise that or should we run with that for the time being?

[Jack H. Stark:]

Well, I think that's a safe number to go with, Subash, right now. I mean, we'll get some results here. But what we put out there was we expected that it could add as much as 10% to our oil volumes over the next 12 months, and I think that was from last quarter, to just provide some perspective. And so, we have no problem sticking with that number.

[Subash Chandra:]

Great. Thanks all.

[Operator:]

Thank you. Our next question comes from Neal Dingmann with SunTrust.

[Neal D. Dingmann:]

Good afternoon, guys. Thanks for all the details. Jack, maybe my question for you, Gary, and a couple have asked about the slide 13, but I always liked that slide of yours. Looking at sort of the optimal, the 6 to 8, are there variables such as if you're able to pick up minerals under there or if some well costs go down further or more efficiencies that you could see change that max economic, that well count would maybe even go up more as far as down-spacing and all, especially if you're able to add minerals under there?

[Gary E. Gould:]

Yes. This is Gary Gould, and we're always looking to optimize. The biggest drivers are always price and production, but the second driver is always CapEx. And we continue to optimize. Right now on the completion side, we're looking at savings of between $100,000 and, say, $500,000 per well. They're really being driven by stage efficiencies as well as lower proppant costs.

[Neal D. Dingmann:]

Got it. And then just my last follow-up – go ahead, guys. I'm sorry.

[Jack H. Stark:]

Neal, I was just going to say that John had mentioned that we have about 12% of the minerals underneath Project SpringBoard, but if you look at it specifically underneath our leasehold, it's knocking on the door of about 17%. And so, that really starts showing how the value of these minerals are really going to hit the bottom line here, because in those units we end up with 100% net revenue.

[Neal D. Dingmann:]

Yeah. Great point. That's exactly what I was after there, Jack. And then just lastly on service cost; one, it sounds like as you continue to use, obviously, being the most active operator in the Bakken, are you seeing yourselves – I've heard some others not as much in the Bakken, do longer-term deals. I've heard of a few deals out there where some other folks are locking in three-year deals. I guess that's kind of my first question as far as would you lock in some other things? And then just curious on, I know Harold kind of gave us supply-demand picture, just again being the service expert, wondering what Harold thinks about the service costs sort of at this level.

[Pat Bent:]

Yeah. Real quickly, this is Pat Bent. And on the rig activity, again, we've been fairly opportunistic and been selective. And so, we don't see entering into any longer-term contracts. A year or less is where we're currently at and where we intend to stay through 2018 and into 2019.

[Harold G. Hamm:]

Yeah. My perspective long term on service costs are that what these companies really needed was utilization and now we're seeing that across the industry. A lot of them are pretty much fully utilized. And we still see a lot of expansion within our industry today. That's what's going on when you look broadly. So, these service companies are – these companies (1

[Neal D. Dingmann:]

Thanks for that perspective, Harold. Appreciate it, guys.

[Operator:]

Thank you. Our next question comes from Daniel Osley with Wells Fargo.

[Nitin Kumar:]

Hi. Actually, this Nitin Kumar from Wells Fargo. Hi, guys. Just maybe one question. One of the comments you made is about $650 million of the capital this year was spent for 2019. Taking an average cost around $10 million or so per well, that suggests you would have a DUC inventory or – not even a DUC inventory, but a completed well inventory of around 60 wells. As I think about the longer term, is that a fair pace for the level of activity you're contemplating in the five-year plan?

[John D. Hart:]

Recall, in that $650 million, it can be the wells that it's associated with can be in various stages, some could be drilling, some could be in completion, some could be in a DUC inventory. So unfortunately, it's not as easy as that to calculate. I don't have the projected DUC count at year end at hand. That's partially because, as what Gary said, we're projecting to be at normal levels, we're pretty much at normal levels today. So, I think you'll see us at normal levels. It's not uncommon that we have a significant amount of capital. For instance, everybody's asked about the third quarter. We spent a lot of capital in the third quarter completing wells. We're getting the production this quarter. We're spending some capital now and we'll get another slug of production in 2019. So, that's just the normal cadence and pace. And recall, everything that we do in the Bakken is on large pads, and in the south it's more and more pads today than certainly compared to two or three years ago. So, that gives you a little more lumpiness on timing and it can give you some variability quarter-to-quarter on capital, but we feel good about where we're at.

[Gary E. Gould:]

And this is Gary Gould, and right now we're projecting that we'll have about 120 wells in the north drilled, but not yet on first production, and about 33 wells in the south. And so, that's a total of about 150 and that's about 50 reduction for this year. And again, we think that's just normal operations going forward.

[Nitin Kumar:]

Great. Thank you for the color. Maybe just talking about that lumpiness, you talked about, I think, 60% of your Bakken wells in the third quarter were towards the latter part of the quarter. Do you have an estimate of maybe what the cadence is for the 70 wells that you're planning to complete in the Bakken this quarter?

[Gary E. Gould:]

This is Gary Gould, and it's evenly weighted to maybe a little bit earlier. We definitely have a lot of confidence in where we're going as far as production goes. So, we're going to be getting those wells on maybe a little earlier than the midpoint of this quarter.

[John D. Hart:]

And on the 70 wells, some of them were completed at the end of the quarter. They're coming online in the fourth quarter is what we're trying to convey there. There's a lot of new flush (1

[Nitin Kumar:]

Perfect. And if I could just sneak one in. You talked about increasing activity. Maybe directionally, as you talk about free cash flow and dividends, what is the price that you are willing to consider for your budgeting exercise for 2019?

[John D. Hart:]

Commodity price?

[Nitin Kumar:]

Yeah.

[John D. Hart:]

Well, I mean, commodities move. We generally are starting with kind of a $60, $65 price. But then, we're running scenarios across a wide range of prices to stress test in some cases, not because it's our expectation, but we stress the model and evaluate different scenarios that could play out, and that type of thing. But we're utilizing that. I expect that commodity prices next year, oil prices will probably be higher than that. But I think it's a good base to start with and then we work those – look at every $5 increment from there.

[Nitin Kumar:]

We're going to leave it there.

[Operator:]

Thank you. Our next question comes from Matt Portillo with TPH.

[Matthew Merrel Portillo:]

Good morning, guys.

[Harold G. Hamm:]

Hey, Matt.

[John D. Hart:]

Good morning.

[Matthew Merrel Portillo:]

Just a follow up on – I apologize for the third question on rail capacity, I mean, on transportation capacity, but it obviously paints a pretty bullish picture for basis differentials going forward. I was wondering if there's any color you might be able to provide on, of that 700,000 to 1 million barrels of takeaway, how much of that would potentially be brownfield versus new greenfield projects? And if there is any high-level color you might be able to provide in terms of kind of the capacity adds that might be weighted towards 2019 versus 2020 plus?

[Harold G. Hamm:]

Let me try.

[Jack H. Stark:]

Sure.

[Harold G. Hamm:]

Well, first of all, if you look at the DAPL and size that line until (1

[Ramiro F. Rangel:]

That's exactly right, yes. You will see some projects where you're going to be able to add compression, and those are pretty easy. And so, you'll see those coming online. But we do expect that greenfield projects to be able to come on as well a little bit later on in the cycle. So, it's a combination of both.

[Matthew Merrel Portillo:]

Thank you very much. Those are my only questions.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. Our next question comes from Marshall Carver with Heikkinen Energy Advisors.

[Marshall Hampton Carver:]

Yes. Thank you. Just a couple of quick ones. The average working interest has been bouncing around each quarter in the Bakken. About how many net wells would the 70 gross wells be for this quarter?

[John D. Hart:]

Give us a second. We'll see if we've got here at hand. We're pulling that up. Why don't you go to your next question while we're looking for that, and then we'll come back to that.

[Marshall Hampton Carver:]

Okay. The Springer wells, the wells that are completing now, will those be online any day now or more late in the quarter or how should we think of that?

[Jack H. Stark:]

Yeah. They're all in various stages of flowback right now. Obviously, the ones on the east side have been on a little bit longer than the ones on the west side. They're just getting turned on. So, it's row development and it's row flowback. And so, it's quite an operation out there. And so, that's the status right now.

[Harold G. Hamm:]

They're getting close on the number.

[John D. Hart:]

Yeah.

[Marshall Hampton Carver:]

Okay. I guess I could ask another one while they're doing that. The Bakken was...

[John D. Hart:]

It's about a 60% to 65% working interest on average, on the net.

[Marshall Hampton Carver:]

Okay. That's helpful. Thank you. That's all for me.

[Harold G. Hamm:]

Thank you.

[John D. Hart:]

All right.

[Operator:]

Ladies and gentlemen, thank you for participating in today's question-and-answer portion of today's call. I would now like to turn the call back over to management for any closing remarks.

[Rory R. Sabino:]

Thank you very much for your time today. Please reach out to the IR team if you have any further questions, and we look forward to hearing from you.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may all disconnect and have a wonderful day.