Continental Resources, Inc.
Q2 2020 Earnings Call Transcript

Published: 4 Aug 2020

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources, Inc. Second Quarter 2020 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Rory Sabino, Vice President of Investor Relations. Please go ahead, sir.

[Rory Sabino:]

Thank you, Allison. Good morning, and thank you all for joining us on today's call. We'll start today's call with remarks from Harold Hamm, Executive Chairman; Bill Berry, Chief Executive Officer; and John Hart, Chief Financial Officer. Jack Stark, our President and Chief Operating Officer; as well as other members of management, will be available for Q&A. Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the company's SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made in this call. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com. With that, I will turn the call over to Mr. Hamm. Harold?

[Harold Hamm:]

Yes. Good morning. Thank you for joining our second quarter earnings call. First, I want to thank our employees for their hard work and dedication through this last quarter. Over the past 4 months, with the adoption of an intense testing and workplace safety protocol, they have successfully instituted a very successful voluntary return to work, and 97% of our employees are back in the office or in the field. As we have experienced remote work to deliver day-to-day maintenance okay, but it takes on-the-job collaboration to make teams flourish and create new opportunities for the company. At Continental, the morale and productivity of our employees is very high. Our employees remain focused on delivering exceptional results for the future, which you will hear about when Bill discusses our capital efficiency gains. I am very proud of our employees for upcoming the challenges faced with COVID-19 after what we have gained in one of the most volatile quarters in this industry. We welcome the new phase of thinking about COVID-19 as the country enters a lower mortality rate experience due to better patient treatment with more effective drugs and a post vaccine thought process of application to the most vulnerable populus. At the time of our last call, WTI was at $24 a barrel. As we anticipated, we've seen price improve to the $40 per barrel range as economies open up and people get back to work. We believed we can see this initial improvement in prices when we made the decision to curtail 70% of our operated oil volumes in May and June. Recent global crude oil inventory data, initial demand recovery and anecdotal evidence from industry participants suggest supply and demand are rebalancing. Continental has been a leader in aligning activity with market conditions. Decision that -- decide feedback to defer and thereby preserve our production for the future has proven to be a value-enhancing strategy. We will continue to prioritize long-term shareholder interest over production growth for growth's sake. While we may continue to see near-term volatility, I believe ongoing inventory rebalancing in the second half of the year will position us nicely for 2021 and beyond. While market demand continues to recover, times of uncertainty can create substantial opportunity. In fact, our current share price reflects such an opportunity and uncommon value. My recent purchase demonstrates my confidence in our teams, our assets and Continental's future potential to deliver meaningful shareholder value. There is no management team more aligned with shareholders than Continental's. While we have often highlight this alignment, with 5 members of our management team as top 40 holders, we are incentivized to create value. This management team has always been right alongside our shareholders in driving towards a bright and prosperous future. We're all personally invested and 100% committed to doing what we can to enhance value and responsibly steward our access to capital. During the second quarter, we were pleased to release our 2019 ESG report, which can be found on our website. This report highlights our long-standing commitment to providing a low-cost, dependable energy source in an environmentally and socially responsible manner. In fact, providing low cost of supply dependable energy is the social responsibility of any energy company. We are proud of our commitment to developing a new ESG standard for the oil and gas industry, and we'll continue to responsibly manage our operations to power the United States and the world. Lastly, as part of our commitment to being a strong advocate for shareholders in the industry, I became the founding member of the American Gulf Coast Select Best Practices Task Force Association. Our goal was to establish a new competitive standard to accurately reflect the fair market value of the American barrel to the global market. The market was clearly broken when WTI prices fell into the negative territory earlier this year. We have asked the CFTC to investigate and they have. Their report is forthcoming in the coming months through their Chairman, Heath Carbo, as reported by Bloomberg. This extreme discounting of the U.S. oil and gas industry led us to form AGS. In June, 2 leading pricing agencies, Platts and Argus, establishes benchmark to more accurately and reliably price U.S. light sweet crude. AGS is not a replacement for WTI, but it's a confirmation to the world that the American energy renaissance has gone global, and AGS will provide U.S. producers with a waterborne-priced barrel. Despite headwinds faced this year, now is not the time to count out U.S. independent producers from being key future net exporters of crude. And I firmly believe Continental is well positioned to be a leader in this phase as a global hydrocarbon business. I am proud of the progress made to date to establish a stable market for American-produced oil. I would now like to turn the call over to Bill.

[William Berry:]

Thank you, Harold, and good morning, everyone. I hope you're all well and safe. Continental demonstrated a proactive first-mover response to the unprecedented events that have shaped the global commodity landscape in 2020. As you can see on Slide 3, we have prudently responded to demand destruction attributable to COVID by preserving this production for a better market environment. The deferral of approximately 55% of operated oil volumes during the second quarter is estimated to generate about $90 million in incremental future cash flows from operations at $40 WTI. Even after shutting-in these volumes, we are reinstating original per unit cost guidance for the year, reflecting our low-cost, capital-efficient assets. Our priorities continue to be protecting our balance sheet, maximizing cash flow, preserving our world-class assets for future shareholder value and maintaining our commitment to low-cost industry leadership. As part of this, we expect to see total debt between $5.4 billion and $5.5 billion by year-end 2020. Beyond 2020, for our longer-term debt stewardship, we are targeting $4 billion or less over the next 3 to 5 years, assuming a $50 price environment. John will provide more details about our expectations for these sequential reductions. Our team's continuous improvements in abilities consistently delivers material gains and cost efficiency. I'd like to congratulate them once again on a job well done. As evidenced on Slide 6, we expect capital efficiencies to increase across both the Bakken and the South in 2020. In the Bakken, we have achieved a 12% reduction to completed well costs from $8.2 million to $7.2 million per well. In the South, we've achieved a 10% reduction to our overall South completed well cost from $10.5 million to $9.5 million per well. 70% of these reductions are structural in the Bakken, and 80% of these reductions are structural in the South, driven by all aspects of our operations. Both the Bakken and South completed well costs include drilling, completion, full facility costs, including artificial lift. These improvements are coming from drilling execution practice practices, completions design optimization and improved operational efficiencies related to coiled tubing clean house as well as higher utilization and performance of gas lift production operations. As Harold mentioned, our employee morale, enthusiasm and productivity is extremely high in spite of these challenging times. Our employees are the foundation of our company, and we view keeping our teams together as a distinct competitive advantage. This is a part of our DNA and has enabled us to differentially manage and leverage our world-class operations to continue our best-in-class performance. As we look forward, there are a number of factors positioning us for a strong second half of 2020 and beyond. Here are a few key items. First, in terms of our production cadence, recall previously when we provided guidance on our second quarter production in June, we also highlighted July production of about 225,000 to 250,000 BOE per day. Actual July volumes will be in line with this guidance, and we expect to bring the remaining curtailed volumes back online this month, with the exception of approximately 65 million net cubic feet per day of dry gas volumes in Oklahoma we have deferred an expectation of more favorable market conditions. While we do not normally guide production on a quarterly basis, we thought it was appropriate to provide some color given what has transpired year-to-date. We expect third quarter production to range between 280,000 and 300,000 BOE per day. Consequently, production will increase in the second half of 2020, and we expect to exit the year at 310,000 to 330,000 BOE per day. Second, we will be cash flow positive in 2020 and project approximately $200 million of free cash flow for the full year 2020 at $40 WTI or $500 million in the second half of 2020. Our first priority with incremental discretionary cash flow will be to continue paying down debt. If we see supply and demand align to a more sustainable level, we have the ability to consider a managed increase in completion activity, along with additional debt reduction. As of June 30, we have about 215 wells in progress and expect to end the year with about 140 wells in progress. Third, as a result of the aforementioned cost efficiencies, our team continued to drive maintenance capital lower. That, along with the 140 wells expected to be in progress at year-end, will enable us to keep our 2021 production flat year-over-year with a maintenance capital of $1.2 billion or lower in 2021. Fourth, with a lower level of activity, our corporate first year decline rate in 2021 will be in the low 30s compared to the upper 30s in 2020. We are well positioned to efficiently maintain production in 2021. We will continue monitoring near-term market conditions and expect to provide 2021 guidance around our usual historical time frame early next year. Despite the challenges we have faced this year, we have kept our teams together just as we have done in previous downturns. As a result, we continue to drive our well costs and our operating costs lower. And our unique combination of inventory depth workforce stability, technical capabilities and management alignment will enable us to deliver future shareholder value in virtually any market environment. I'll now turn the call over to John.

[John Hart:]

Thank you, Bill, and good morning, everyone. Some of you had questions on maintenance capital. Maintenance capital is intended to help you in calibrating your models for our capital efficiencies, but is not intended as guidance for 2021. We will provide full guidance for 2021 in February, reflecting the full extent of our plans. Our expected multiyear maintenance capital to hold production flat year-over-year in 2021 is $1.2 billion or below for drilling and completion. Whether you are considering year-over-year or fourth quarter exit production, the level of maintenance capital to hold these figures flat in '21 is essentially the same. As we typically look at maintenance capital on a multiyear basis, I will point out that our $1.2 billion estimate includes slightly in excess of $400 million of capital that does not see first production until 2022. So if you're considering a 1-year maintenance capital, it's below $800 million for drilling and completion. If you, like us, are more interested in a multiyear look, we estimate that we could hold production flat for $1.2 billion for multiple years. These numbers reflect well cost efficiencies, as previously noted, in the Bakken in Oklahoma. Our multiyear look is a 30% or more reduction from our previous estimate of $1.5 billion to $2 billion. Let me review a snapshot of several key second quarter financial performance metrics. Despite curtailing approximately 55% of our operated oil volumes, LOE per BOE came in at $3.58, which is within our previously suspended guidance range. While G&A per BOE was slightly higher due to production volumes being curtailed in the second quarter, we expect G&A to revert lower on the balance of this year and be within our original guidance as production has resumed. Even at a slightly elevated level per unit, our second quarter G&A trends below our broader peer set. Our G&A highlights the lean nature of our organization and the sustainable operational efficiencies we deliver. As part of our continued financial stewardship, we have paid down approximately $1.4 billion of debt since the beginning of 2016, and our commitment to a strong balance sheet continues. On the back of lower commodity prices and curtailed production, our net debt increased slightly in the second quarter. Based on our current forecast, we believe our total debt has peaked in July and should decline through the balance of 2020 and continue during 2021 and beyond. Based on current commodity strips, we expect to exit this year with debt between $5.4 billion and $5.5 billion. Our long-term debt reduction goals remain on track, and we expect total debt to approach or drop below $5 billion by year-end 2021. As Bill mentioned, and as we've said in previous years, our ultimate debt target is to be comfortably below $4 billion. We have a proven track record of debt paydown and financial strength and this will continue. While COVID caused a momentary blip, it has not impacted our strategy. Our revised 2020 guidance metrics further highlight our commitment to shareholder value and cost leadership. 2020 CapEx is expected to be on budget at $1.2 billion or lower. The significant transition between first quarter CapEx of $651 million and the second quarter of $191 million is an indication of how quickly we have adjusted to a lower level of capital activity. Third quarter and fourth quarter are expected to be lower yet, putting us on track for an annual budget of $1.2 billion or below. We remain committed to capital discipline. As Bill mentioned, we expect positive annual free cash flow of approximately $200 million at $40 WTI. Said more directly, this means we expect positive cash flow of approximately $500 million for the second half of 2020 at current strip prices. This is the catalyst to reduce debt this year and into 2021. We are also reinstituting previously suspended operating expense guidance for LOE, G&A and DD&A, reflecting continued cost controls, productivity and capital efficiency from our assets. Our guidance and expectations are a reflection of Continental's exceptional capital efficiency and focus on value creation. To be on track with our original guidance after all that 2020 has brought is an accomplishment that we are particularly proud of. With that, we're ready to begin the Q&A section of our call, and I'll turn it back over to the operator. Thank you, everyone.

[Operator:]

[Operator Instructions]. The first question today will come from Derrick Whitfield of Stifel.

[Derrick Whitfield:]

Perhaps for Harold or Bill, how do you philosophically think about growth rate and reinvestment? It's clear a lower growth, higher return of capital business model is the right approach at current pricing. How does that change in a $50 or $60 world?

[William Berry:]

Yes. I think, Derrick, if you saw what we were doing early in the year, we were saying essentially that -- and early on, that we should not be, as an industry, overproducing into an oversupplied market. And we saw it and we started attenuating our growth rates at that point in time. And as you look at what's going to take to bring back activity, you're probably in that $50, $60 world. And so until that point in time, I think the industry will be pursuing pretty moderate growth rates, if that's what you're trying to get a feel for.

[Derrick Whitfield:]

That is. And then as my follow-up and more specific to what you've outlined in your presentation today. With regard to your 2021 maintenance capital outlook on Page 3, did you outline the broad activity and what cost assumption assumptions embedded in that estimate?

[William Berry:]

Yes. And I'll ask John or Jack to put in comments here as well. But in that -- embedded in that, and you're probably looking at what type of cadence as far as drilling, that's got about 7 rigs in that as far as a drilling program. And potentially, it's not -- we're not specifying North and South because with our product, we'll have a little bit of flexibility built into whether we're drilling North or South, but you could start off saying kind of half and half. And John or Jack, do you have anything to add to that?

[John Hart:]

No. I mean we've assumed the well cost assumptions that we've outlaid to you. Obviously, the Bakken and the South, what Pat and our broader operating teams have done is tremendous there. That's giving us a lot of benefit. We've also given you color today on a 1-year versus a multiyear. I think a lot of times companies just talk about what they can do from 1 year to the next. Well, you've got a steady state going on of operations from drilling and completing and things are coming on at a later time. So we tried to give you a lot of color than that. With our low overhead structure and with the capital efficiencies that we garner, we're very well positioned.

[Jack Stark:]

Yes. And I'll just add too. This is Jack. The inventory that we've got built in is just the top shelf inventory for the company, and we'll continue to expect just excellent results.

[Operator:]

Our next question today will come from Doug Leggate of Bank of America.

[Doug Leggate:]

John, these are probably for you, if you don't mind, 2 questions. One is clarification. So you've been very clear about the $1.2 billion and the $800 million of that is activity in 2021. But I'm a little confused by the production guidance. So you exit this year, $310 million to $330 million. Is that fourth quarter or actual exit? I know it's a bit of semantics. But the implication is if you hold 2020 flat at $295 million, there's some implied decline through the year. So can you just clarify what you meant by hold exit flat or hold full year flat? The number is the same. I'm a little confused by that.

[William Berry:]

Sure. We modeled that maintenance capital is slightly higher than that $295 million, it's at $300 million or above. So the level of maintenance capital, whether you're looking at $310 million to $330 million or whether you're looking at $300 million or a little bit above, you're not getting a big dollar difference in maintenance capital. So they're essentially the same. Does that help you? Does that help when you're...

[Doug Leggate:]

Just to be -- it can and it does, John. But just to be clear, so we are -- to get to $295 million, it would imply just a moderate decline through 2021. Is that the right way to think about it?

[William Berry:]

It'd be a moderate decline of that fourth quarter exit. But again, we're not providing full 2021 guidance. That will come out in February. And you're in a very narrow range of production for us. You've seen us bring production on very easily in those general ranges.

[Doug Leggate:]

Great stuff. And my follow-up is as a [Technical Difficulty] massive step down in sustaining capital. And you know how we think about the world is [Technical Difficulty] by way of free cash flow.

[William Berry:]

On a cash flow basis?

[Doug Leggate:]

Yes, yes. For covering the $1.2 billion CapEx, I guess.

[William Berry:]

And you're talking about a 2021 number on a full year basis? Or you're talking about the balance of this year. Yes, the balance of this year for free cash flow is, in the mid- to low $20 price, we can generate neutral free cash flow. As you look out into 2021, if you're doing -- if you're at a full $1.2 billion, it'd be somewhere in the upper 30s, low 40s.

[Doug Leggate:]

So at $50, you would -- our base case is--

[William Berry:]

At $50, we're putting off a significant amount of free cash flow, hundreds of millions okay.

[Operator:]

Our next question today will come from Jeanine Wai of Barclays.

[Jeanine Wai:]

So I guess my first question is just back to the 2021 maintenance CapEx. We really appreciate all the updated detail on disclosure for capital efficiency purposes. In terms of non-D&C portion of it, can you provide any color on maybe how that would trend next year or generally? Is there anything that biases that whole facilities and others that markets for 2020? Can you just clarify whether it will be higher or lower next year?

[John Hart:]

Yes. I think that's a fair question. There are a number of components in that non-D&C. So let's kind of break those into segments. First one is obviously our mineral activity. And that's something that we, along with our -- with Franco-Nevada, we agree on that. Now you know from a cash flow perspective, that they're covering 80% of the expenditures. So albeit it's a gross-up on our capital dollars, it's not from a net cash perspective the same because of that carry that they have. That ultimately depends on what we see in the markets out there. Currently, we're not that active on the mineral side. We've taken a little bit -- we've slowed down our level of activity. So what we ultimately budget for that if it's in the current price environment, we'll see if we continue at this lower price or if we go back to something closer to what we were before. But that's roughly $100 million or so a year, and we're not spending anywhere near that in the current run rate. And what we do, again, will depend on what we see in the markets as we go forward where and we're choosing to invest. The other factors in there, facilities, they are a component of what we're doing on the D&C side. So we're at $1.2 billion. We would probably be comparable or less than what we are at this year. In leasehold and land, the biggest part of that are -- that ebbs from year-to-year depending on exploration activity or renewals. I'll say I don't think we have a significant amount of renewals coming due next year. And beyond that, it would depend on new plays or new opportunities. That's something that we'll obviously give you a lot more color on when we get around to full guidance in February.

[Jeanine Wai:]

Okay. Great. That's a lot of detail. I hope you can hear me. You're breaking up a little bit for me, but it might have been on my end with the storm here. But my second question is just a little bit on...

[John Hart:]

You're coming through clearly here.

[Jeanine Wai:]

Perfect. Okay. Great. My second question is just a little bit more on the housekeeping side, if you don't mind, and it's on oil percent. Continental's oil percent was understandably low in 2Q due to the nature of the production shut-in. But with the shut-ins coming back online and resuming a lot of completions -- or resuming completions in the Bakken, can you provide any color on where the oil percent may migrate to in the near term and [Technical Difficulty]. I know that the focus is in on--

[Rory Sabino:]

Janine, it's Rory. You're breaking up a little bit on us. So we didn't get the last -- the second part of that question. We did get the first part with regards to the oil percentage. But the second part, we did not get. If you could just repeat that?

[Jeanine Wai:]

It's all the same. It was just if you can provide any color on when the oil percent might migrate to historical levels. And understanding that you've got a lot of flexibility between oil and gas, depending on where the commodities move for each of those.

[Jack Stark:]

Yes. Well, Janine, this is Jack. And the oil percentage, we'll go right back to where we were in the first quarter. We were like 56% in the first quarter. So basically, we shut the oil in, we turn it back on. We go right back to where we were. So there's no real material change there at all. And on top of that, I'd say there has been discussion about will these wells come back on industry-wide and all. And I got to tell you, we're seeing just pretty impressive flush production coming out of these wells when we turn them back on. And that's what we've experienced previously. And that's why we were never concerned about what -- how these wells would perform even though there was a lot of chatter about it. And I guess, there's a good example out in Montana. We shut in all of our mine and a production out there. And we had a shut-in for about 2 months, and we turned it back on and the production was double of what it was before we shut it in. And so what we saw is some significant production flush production related to that whole field. And so you can look at it on a field basis or you can look at on a well basis, bottom line is the oil is there and these reservoirs are performing very nicely for us.

[Operator:]

Our next question will come from Arun Jayaram of JPMorgan.

[Arun Jayaram:]

Harold, I wanted to start with you. I was wondering if you could give us your perspective on the surprise judge's order in July to potentially shut down the DAPL pipeline and your thoughts on what happens from here?

[Harold Hamm:]

Well, we feel very good that, that order will be stayed. It's this thing as we heard. It's -- we felt good that we'd have an initial stage, which we got. And we are very confident that this panel will also stay this thing again. And in the end, we feel like that this pipeline will continue at -- as [indiscernible] operated three years trouble free up there. So it's a good thing. We feel good about it.

[Arun Jayaram:]

Great. Any other perspective from the team? I just wanted to get some more color just because it is an important data point for CLR and the group.

[William Berry:]

Yes. This is Bill. The only thing we might add on that because I'm sure you're looking at, okay, what's our plan would be in those type of discussions if the DAPL get shut down. And as Harold mentioned, we think there's pretty strong support from the legal side. And we did a thorough analysis looking at the risk around whether this is going to flow, not flow, whether the courts were going to stay or not. And our analysis all came to the same conclusion. And we looked at actually outside pipeline sources, we looked at other rail sources, all those type of things. And we actually had some prices coming in. And we felt it was just economically imprudent to go into -- enter 100% certainty of paying for higher-cost transportation on the chance that this may not get stayed. And so we're waiting to see. We're hopeful that the courts will ultimately do as Harold described and end up staying this and DAPL will keep on producing, and that's our expectation.

[John Hart:]

And Arun, I think you know, but we've only got, I think, 35, 50 barrels a day committed. And those are gross barrels also as an operator. So we don't have a significant direct commitment on DAPL.

[Arun Jayaram:]

Great. That's helpful. And just my follow-up to maybe you, John Hart. Your commentary is the $1.2 billion in D&C sustaining capital would be sufficient to essentially hold the fourth quarter run rate relatively flat in '21. Would that be on a BOE and an oil basis? And maybe...

[John Hart:]

What I said was we ran it on a BOE. I don't think our -- our BO or BOE, it varies from year-to-year, but you know we've been in kind of the same percentage for 6, 7 years, a decade now. So we're -- and the basis of our inventory is consistent with that. So I think it stays in a relatively mid-50-ish type oil percentage range for that. And what I said on the $1.2 billion related, we had questions from a number of people about is that -- when we said in the transcript year-over-year. And we had questions, well, how does it vary between year-over-year, fourth quarter exit? Well, the fourth quarter exit of $310 million to $300 million versus the annual production range, you're not dealing with the big delta. So I don't think it materially impacts the level of CapEx in either of those scenarios. So yes, I think we can hold flat in the relative range on those different scenarios.

[Arun Jayaram:]

And just want to add one more quick question is, John, how would the capital allocation kind of look like between the Bakken and the South in that -- call it, that $1.2 billion kind of number?

[John Hart:]

Relatively consistent with what we've had.

[Operator:]

Our next question will come from Nitin Kumar of Wells Fargo.

[Nitin Kumar:]

I want to start maybe in the same vein as some of the other questions. But you're -- you've indicated exiting the year with about 140 wells in progress. For the level of activity, I think you mentioned 7 rigs, that seems like a lot. Can you give us some color of how many of those wells you expect to -- or what's sort of normal run rate in terms of DUCs by the end of 2021?

[Jack Stark:]

We're not -- Kumar, we're not really giving guidance on '21. But I can tell you, we're -- between now and year-end, we're [indiscernible] on around 100 wells. And most of those have already been stimmed because our stim crew count in the second half of the year, really, we don't have any crews going really in the Bakken at this point and in Oklahoma. We'll probably average about 1 at best in Oklahoma right now. So all these are essentially in the queue, and we're planning to bring those on, about 100 wells that I said, in the second half of the year in an orderly fashion to basically maximize the value of those barrels. And so as we get into '21, we'll be able to give -- or maybe even fourth quarter and give you a little bit better clarity on what that might look like.

[Nitin Kumar:]

Great. I appreciate that.

[Jack Stark:]

If you go back -- let me just say, if you go back to 2019, we were like 215 at year-end. So comparatively, we're 140 versus 215 last year. And so with a little bit increase in rig count, you could probably expect more.

[Nitin Kumar:]

Got it. And I appreciate that you can't give us guidance. Jack, maybe just a quick one. You mentioned bringing the wells back on and seeing some good IP rates when you brought them back on. Any costs associated bringing back volumes? I mean curtailing 70% of your oil production was a pretty big step. How are you finding the costs associated with bringing back that opportunity set?

[Jack Stark:]

Well, really, there -- it's been very minimal cost at all. There had been some numbers shown out there that were -- I think the NDIC had put out some numbers of $20,000 to $25,000 a well type cost. And that -- I'm not sure what were they -- what their nurses were based on where they're coming from. From our standpoint, we go back out and turn these on and they come to see us. And Pat, do you have anything to add?

[Patrick Bent:]

Yes. Just a little additional color. Like Jack, I don't know the basis for the NDIC number. But we've looked back and the numbers that we've calculated on an extraordinary basis, anything out of the normal would be about a little bit less than $1,500 per well and so not much at all.

[Nitin Kumar:]

Excellent. So clearly, the NDIC was a little bit out in left field.

[Patrick Bent:]

I wouldn't say in left field, I just don't know the basis for their calculations. So our calculation methodologies and techniques may be vastly different. So I -- just clarity there.

[John Hart:]

They may be looking at a variety of different operators. In our case, it was minimal.

[Operator:]

Our next question today will come from Brad Heffern of RBC Capital Markets.

[Brad Heffern:]

A question sort of related to some of the ones that have come so far on capital allocation. I'm just wondering, there have been a lot of moving pieces in the 2 operating regions from DAPL and High Plains as well. There might be some election risk in the Bakken. And then in the South, you have the higher -- the better outlook for gas and NGL. So I'm just wondering if any of those things would potentially tilt you away from the sort of 50-50 split, more towards the South?

[William Berry:]

Yes. I think there's a couple of parts to that. First talk about the federal acreage, which is maybe what you're referring to up in the North. If you look at company-wide, we only have about 8% of our acreage is federal, so not high exposure at all there. And as far as what's the benefit of that, we've got -- there's optionality around our product mix with -- between gas and crude, and we actually have seen that over the course of multiple years, including this year, that sometimes it's more prudent based on where we're seeing the gas prices to maybe go after a little more gas, sometimes more oil. So we think that, that flexibility that we have with optionality between gas and oil actually is one of the strengths of the company.

[Brad Heffern:]

Okay. And then maybe for John. You have the $500 million free cash flow number for the second half, but it looks like the exit debt number is only about $300 million lower. So I was wondering what that -- the gap between those numbers is.

[John Hart:]

Brad, it's just timing. When we look at free cash flow, we're looking at January to December, what we earn and what we incurred during that period. So we ignore working capital coming in and working capital going out, and we're looking at what that activity generates, if you will. So some of that cash will be received in January and February and debt will continue to trend down. Just the -- just timing of working capital is all it is.

[Operator:]

Our next question today is from Neal Dingmann of SunTrust Robinson Humphrey.

[Neal Dingmann:]

My first question is just on your '20 and latter part of 2021 price expectations. I know [indiscernible] in the past, you all have been willing to build some DUCs in scenarios where you believe that these prices are going to increase. Is that for -- I guess for Bill, for really any -- for you all, just -- is that part of the plan now? I think you mentioned 215 in progress now, 240 potentially by the end of the year. Is that because of just part of that plan and the expectations of higher prices? Or is there more behind that?

[William Berry:]

No. As mentioned, we're bringing back essentially all our oil production in August. So we're up and running all the production that we had shut-in. There is some gas shut-in to address the specific point you're talking about, Neal, that we do think that there's a stronger market in the gas, and we're starting to see a little bit of that happen over the last few days. And so that is part of what we're trying to manage is the expectation of where gas is going. That probably drives it more than anything. As far as oil price, we're in the $40 strip range. We think long term, that's not sustainable. But clearly, there's still a couple of things that are driving that. The coronavirus and what's going on with economic activity around the world, the discipline from OPEC+ as well. And then there's still a pretty significant overhang of inventory out there that needs to be worked off.

[Neal Dingmann:]

I got it. Okay. And -- go ahead.

[Jack Stark:]

And Neal, I was just going to mention -- excuse me, Neal, this is Jack. When you said 240 wells -- DUCs at year-end, and it's 140, just to make sure...

[Neal Dingmann:]

I'm sorry, okay. Right, right. Thanks for the clarification, Jack. Then just a follow-up, you all definitely sound -- it sounds like you've done your due diligence, confident about DAPL. I guess my question is if, for some reason, DAPL were to slow down, given the minimal amount of activity you have in DAPL, I'm just wondering, does that -- have you all thought about how your diffs would be impacted or really if they would if DAPL were to slow down?

[Harold Hamm:]

I think in a little better shape than most just due to historical [indiscernible] status that we have up there in the field. And so yes, we'd be looking for the alternative for what we have on DAPL, certainly. And we feel pretty confident where DAPL is and what the outcome is going to be.

[Operator:]

Our next question will come from Brian Singer of Goldman Sachs.

[Brian Singer:]

My first question is a follow-up on earlier one with regards to debt paydown and capital allocation. Harold, I think at the very beginning, you talked about Continental being a leader in aligning activity with market conditions. And then Bill and John talked about the $4 billion long-term debt target. If oil prices rise at a $50 level or higher, what type of supply response would you contemplate versus maintenance levels? And then most importantly, would you want to meet that $4 billion debt reduction objective first before ramping activity? Or is there -- you could do both at the same time?

[William Berry:]

Yes. Brian, thanks for the question. And when you talk about $50 world, we really don't focus on a target price, we more look at the sustainability of the fundamentals. And so that's why we get into what's OPEC doing, what's OPEC+ doing, what's coronavirus doing, where the inventory is. And so if it spikes up to $50, unlikely we're going to change our behavior at all. What we're trying to message with our approach is that we're laser-focused on free cash flow. We're focused on debt reduction. And as the price moves, if we see fundamental shifts out there, then yes, we might start inching our way back into a little bit more activity, but never compromising that the bulk of our effort is going to go toward debt replacement. And that's why that 3- to 5-year time frame to be able to get to that $4 billion, we've done a lot of scenario analysis as to different oil prices, different gas prices, different capital programs, and it gave us pretty high confidence that we'd hit that in just about any scenario that we see out there.

[Brian Singer:]

Great. And then my follow-up is with regards to exploration and acquisitions. Continental has long been an exploration-focused company, and I wondered whether this down cycle is providing any opportunities. And how maybe near-term impactful those opportunities could be from either an exploration perspective or an acreage or more than acreage, acquisition opportunity.

[Jack Stark:]

Great question, Brian. This is Jack. And you know our history, in downturns and times like these, we tend to find good opportunities that generally would not be available otherwise. And the same holds true now. We have teams working very diligently, looking for these unique opportunities that are in this unique window of time. And so -- and I will tell you that they are getting some traction, and we like what we're doing.

[Brian Singer:]

Would these be in basins that you're already in or new areas for the company?

[Jack Stark:]

We are opportunistic and go where the opportunity is.

[Operator:]

The next question will come from Gail Nicholson [ph] of Stephens.

[Unidentified Analyst:]

I'm looking on the LOE side. Is there a delta between the North and South regions and the improvements that you've achieved to date, has that been concentrated in more one region than the other?

[John Hart:]

The North is a little bit higher than the South. The South is in the 2 range, the North is around the four range, but they both shown strength and continue to show improvement. If you look back -- go back and look 5, 6 years, you've seen a continual improvement in LOE. Part of that's [indiscernible] in the South, but the North has improved throughout there as well. So I think we'll continue to see strong performance there.

[Unidentified Analyst:]

Great. And then I just wanted to go back to something that Jack said earlier. You talked about the positive benefit of the volumes in Montana coming back online post shut-ins. Is that something that you expect to see across all areas that have been shut-in? Or is that unique to Montana?

[Jack Stark:]

No. I think we see that across the field and very -- it's the nature of the reservoir. This is a very low permeability reservoir, and you give it time to shut-in, you start seeing it -- the reservoir basically recharge the stimulated rock volume area we've got around the wells. And so the fact is, there's a lot of well out there. Our teams actually went in and reevaluated the Bakken for, I don't know, about the 20th time as far as what kind of reserves there are in there. And quite frankly, they increased the -- basically the reserves in place by 10% based on the knowledge we've gained over the years. And so what we're seeing here is there's a lot more oil in place out there, and these type of responses really help support that finding.

[Operator:]

Our next question will come from Noel Parks of Coker & Palmer.

[Noel Parks:]

I was interested in getting your take on service costs as you look through the end of this year and heading into next year. I'm hearing different schools of thoughts. Some folks saying that they think the service cost component is about as low as it's going to get. And others saying that they think there's more to go and that will at least sustain these level of service costs all the way through next year. So I just wondered what your impression was on that.

[William Berry:]

Yes. This is Bill. Let me -- I'm going to start with a couple of comments and then turn it over to Pat, and he will give you much better detail on it. But as we mentioned, we're seeing 70% to 80% structural changes in our costs. So that doesn't have anything to do with the service companies. So we do worry about the service companies and the unfortunate roller coaster ride they've been on as this oil price collapse has impacted them even more adversely than ourselves. And so the sustainability of good service industry is important for our business. But I do want to start with -- structurally, most of the savings that we've been talking about are in that category. It doesn't have anything to do with the service companies' price book, if you will. But Pat will add a little bit more color to what's going on with the service industry.

[Patrick Bent:]

Thanks, Bill. When I think about the service industry, I think about it in the same way I think about operators. I think there's the opportunity for efficiency gains across the board. We continue to exhibit those efficiency gains from an operating perspective. We would anticipate the service industry to do the same and continue to drive the cost lower. I think the key for Continental is exposure. And so when Bill talks about structural versus market-driven, we've managed to avoid the risk of a market-driven price increase with the structural changes we've got in place. When I think about 70% to 80% North and South structural modification and reduction in pricing, I think we basically manage any risk associated with upward service pressure.

[Noel Parks:]

Okay. Great. And just one other question. As you look at, possibly, on one hand, a $40 ongoing oil price environment that points in more of a maintenance capital direction or hopefully, some rebound to -- maybe getting to $50 or above. Looking at the debt maturities on the horizon, I'm just wondering if you had any thoughts on your cost of capital depending on those couple of scenarios? Some of the rates you got were so particularly low, back 5 or 7 years ago, sub 4% long-term debt. And between the two scenarios, do you think about your cost of capital differently?

[Harold Hamm:]

Well, [indiscernible] in two parts. First of all, $40 a barrel, we don't believe that's going to be here long term. Just -- that's not going to be sufficient to hold production levels in the U.S. and the world. So we think that's a very short-term situation anyway. I'll turn rest over to John to answer the second part of that.

[John Hart:]

Sure. Noel, you had a pretty broad question there. But look, our cost of capital has been very attractive. I think it's going to continue to improve. From where you're seeing our bonds trading now, you've seen an exceptional improvement in those over the last month. The markets are open for us if we chose to do something, I think that the quality of credit for a company that's putting off a significant amount of free cash flow the next 6 months and then continuing that into '21 and '22, we've got the ability to pay off our bonds by generating a lot of cash flow. But with that, if the markets continue to improve and we see some further improvement from where they're at, they're certainly open for us at any given time. So that gives us a lot of flexibility in how we manage that.

[Operator:]

The next question will come from Paul Cheng of Scotiabank.

[Paul Cheng:]

Maybe this is for Bill and John. I just want to make sure I understand. So based on the way that you described, I assume for the next couple of years, your CapEx will be a function of your cash flow at the minimum to generate the amount of free cash flow that next year, your debt will be below the $5 billion. Is that the interpretation that -- the right way to do it -- the right way to look at it?

[William Berry:]

Yes, Paul, let me rephrase it and make sure that we're answering the question that you're asking. [Indiscernible] asking is, is our CapEx spend rate a function of our free cash flow? And the answer is yes. We're focused on the debt. And we, like I said, under various scenarios at various oil prices and gas prices. We have a very clear path to being able to take the debt to the level that we're trying to get it to. And so it is a function of the free cash flow. I think that was your question, right?

[Paul Cheng:]

Right. And that -- should we interpret that, at least for the next 3 or 4 years, until you get your debt to less than $4 billion, that will be the approach?

[John Hart:]

I think that's a long -- if you go back a few years, our focus on free cash flow goes back a number of years. We've been there since '16 on, and we talked about it as far back in 2012, 2013 as we were HBP-ing our assets. So the generation of free cash flow and return to shareholders, that's a long-term structural thing that goes beyond achieving one debt target or the next debt target. Generating free cash flow is what a sustainable thriving company should be doing, and it's part of our go-forward strategy.

[Paul Cheng:]

Okay. And can I just have a quick one. Do you have a split on the oil curtailment in the second quarter by basin between the Bakken, SCOOP and STACK? And also any reason why your second quarter natural gas price realization is so bad? The benchmark doesn't seems it is really that bad, but your gas price realization is really bad.

[William Berry:]

Yes. On the gas price, you're talking about the $0.12 that we had out there that was posted. And obviously, NGL prices were following oil prices, and we're going to report three streams [indiscernible] report two streams. So the NGLs are driving a lot of that differential that you're seeing, Paul.

[Paul Cheng:]

Yes. But Bill, I mean, the other company like Concho that didn't really see that [indiscernible]. I mean they also report two stream.

[John Hart:]

Yes. We had some areas -- if you look in the 10-Q, we discussed it in there. We had some areas where we ended up in a negative position on some of our gas sales, just on the gas, not the total stream where you blend in oil and other things. We've talked about that in the 10-Q. It's also, as you saw, we shut-in some gas going forward because we see better price environments in the future. So I don't think that's a long-term thing. But with the volatility that you saw this quarter in gas, it's certainly bounced off those levels significantly. So you just had some lower gas realizations when you're looking at the cost of producing those wells.

[William Berry:]

Yes. And to build on John's comment, Paul, that -- the NGL pricing, it depends on your contract structure, too, as to how you end up flowing it back to you. And so that -- with different contract structures, you should see different variability, and that's probably why you're seeing differences between ourselves and others. But as John's saying, we think this is an aberration that we don't expect in the future.

[Operator:]

Our next question will come from Josh Silverstein of Wolfe Research.

[Josh Silverstein:]

Just a question on the debt reduction strategy, the $1.4 billion, $1.5 billion over the next few years. Why that number relative to the $4 billion that's maturing over the time period? And is this basically most of Continental's free cash flow? Or is there going to be cash flow in excess of this amount?

[William Berry:]

So the target's -- I think you're asking 2 parts there. One is how do we set the target. And then two, how is the cash is going to be provided to accomplish that. Is that the question, Josh?

[Unidentified Company Representative:]

Yes, think so.

[John Hart:]

So Josh, on the $4 billion, we've had that target for a while, and there are a number of ways we get there. One, we want to get debt down below 1x debt to EBITDA. In a $50 type price environment, that certainly achieves it plus some. Two, in a $40 price environment, we want to keep it where it stays well below 2x debt to EBITDA. So that is something that we think gives us insulation against price volatility. And so we've focused on that for a while, and that remains unchanged, and we'll continue to do so. What was the other part of your question?

[Josh Silverstein:]

Is the debt reduction basically all of Continental's free cash flow? Or is there excess free cash flow above this level?

[John Hart:]

Yes. So as Bill spoke that -- we ran that at a variety of price scenarios, anywhere between $40 and $60 or above. So it really depends on the commodity price. I think we can -- so let's just use the midpoint of that. A $50 price environment, we can generate attractive growth while achieving that debt goal and the time frame that we've factored in. So it's -- I think it's a good balance of being able to do a variety of things with the assets, but also generating the traction towards the debt improvement that we want to see.

[Josh Silverstein:]

And last for me. Harold, I wanted to ask you, you've been involved in some of the important political decisions that have impacted the energy sector. As we come up to an election here, if we have an administration change, what do you see playing out for energy and confidential over the next 4 years? Is there anything that could be supportive? Or is everything moving negative for the sector?

[Harold Hamm:]

Let me start out and say I think that Trump is going to be reelected and the numbers are certainly showing that. And it's hard to contemplate the politics going forward. If Biden were to be elected, he's backed off on several negative things that he said about energy industry, but who knows where to come from if he were there. And who knows how much he would get past in Congress if the Senate is maintained and the House flips to a Republican-dominated Congress. So anyway, it's a -- like always, you do the very best that you could in that critical situation.

[Operator:]

Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Rory Sabino for any closing remarks.

[Rory Sabino:]

Thank you very much for joining us today. Please direct any further questions to the IR team. We look forward to speaking with you. Thank you.

[Operator:]

The conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.