Continental Resources, Inc.
Q4 2020 Earnings Call Transcript

Published: 17 Feb 2021

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources, Inc. Fourth Quarter 2020 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 call is being recorded. I would now like to turn the conference over to Rory Sabino, Vice President of Investor Relations. Please go ahead.

[Rory Sabino:]

Thank you, Andrea, and good morning. Welcome to today's earnings call. We'll start today's call with remarks from Harold Hamm, Executive Chairman; Bill Berry, Chief Executive Officer; Jack Stark, President and Chief Operating Officer; and John Hart, Chief Financial Officer. 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 on 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:]

Thank you, Rory, and good morning, everyone. I'd like to begin by commending our employees for their incredible performance in 2020. And Despite all the challenges we faced last year, our teams generated approximately $275 million of free cash flow and delivered better-than-expected production, cost metrics and sustainable go-forward cost savings. Obviously, one of the unprecedented challenges of the past year was price, the WTI falling to negative territory for the first time ever in April 2020. Despite the dramatic impact of COVID on crude oil demand last year, global inventories now appear to be rebalancing on vaccine optimism and tighter supplies as both the U.S. and global producers exhibit capital and market discipline. The current administration's executive orders through additional arbitrary, regulatory and federal leasing and a permitting moratorium tend to hinder U.S. oil and gas supplies driving those prices higher. We have clearly seen this impact to domestic oil prices the past 60 days. Recent weather events have tested the limits of the renewable-laden grid system. A dependable and reliable power based grid is essential to human safety and well-being. A reliable power based grid is not possible with a significant natural gas powering that base. A science-based approach to producing a reliable grid is imperative for today and the future instead of a heavily subsidized governmental mandated wind and solar dependent system.

[Bill Berry:]

Thank you, Harold, and good morning, everyone. Thanks for taking the time to join us on our call. We've got a great update to share with you today. Before I get into my prepared remarks, I thought might go through and talk a little bit about the Arctic blast and the topical things that are going on I know you'd be interested in. As you know, we're getting pretty well stressed here with our electric grids power system. We and our company are producing about 50% of our gas. That is what we're working with every day with the government entities, the regulators; actually working side-by-side, our teams are out working 24-hour shifts to keep everything up and running. We're also working with the pipeline companies, helping them keep their compressors online, working with the power company so that we make sure that we're getting power delivered to the wells so that we can produce all the gas that we can to be able to end up generating power that this state as well as Texas and the other states are needing with this cold blast that's coming through. As I said, we've got about 50% on understanding from talking to the utilities that most of the other operators of 5% to 25% is what they've been able to keep on. It's a real challenge, but as the largest gas producer in the state, we felt that this is something that we just need to put every bit of effort possible into making sure we load all the gas that we could.

[Jack Stark:]

Thanks, Bill, and good morning, everyone. Appreciate you joining our call. Today, I will provide some key operational highlights from 2020 and touch on our drilling plans for 2021. Let's start in Oklahoma, where the majority of our activity focused on the Woodford reservoir as we moved into Phase 2 development of SpringBoard I. Results were right on track with the average performance from 46 Woodford wells completed in SpringBoard I during 2020, slightly beating type curve expectations, as you can see on Slide 9. This demonstrates the consistency of the reservoir and optimal density designed by our teams. Our drilling also expanded into SpringBoard III and IV during 2020, and early results from both the Sycamore and Woodford reservoirs have been impressive. Slide 9 shows that four recently completed wells, including two Woodford and two Sycamore producers, are significantly outperforming our SpringBoard unit type curve. This performance is in line with our expectations for these parent wells and reflects the increased thickness of the Sycamore Woodford reservoirs and SpringBoard III and IV, as shown on Slide 9. Combined, these two reservoirs are up to 750-foot thick in SpringBoard III, which is essentially twice the thickness of the reservoirs in SpringBoard I, with targets in both the upper and Lower Woodford and upper and lower Sycamore reservoirs. Our strategy to focus our Oklahoma rigs on gas weighted assets during the second half of last year brought on some significant gas volumes in recent months.

[John Hart:]

Thanks, Jack, and good day, everyone. As Bill mentioned, Continental has a strong value proposition predicated on our expectation to generate significant free cash flow. We expect to deliver significant return of capital to shareholders by prioritizing debt pay down. Ultimately, we see additional capital returns to shareholders in the form of dividends as our debt goals are reached. I would like to begin by highlighting our strong financial performance in 2020. We generated $332 million of free cash flow in the fourth quarter and $275 million of free cash flow for the full year. Our production expense per BOE came in at $3.27, nearly 7% lower than the low end of our guidance. Our G&A per BOE was in line with guidance at $1.79, while our DD&A increased over prior periods, this was due to downward revisions and proved reserves at year-end, primarily resulting from significantly reduced market prices in 2020, which have since recovered. The downward reserve revisions resulted in an increase in fourth quarter 2020 DD&A expense of approximately $75 million. We expect production expense per BOE of $3.25 to $3.75 in 2021 and total G&A per BOE of $1.65 to $1.95 in 2021. As Bill mentioned, with $1.4 billion of CapEx in '21, net of Franco-Nevada's mid-share of mineral cost, we are right below our target reinvestment rate of 65% to 75% at 58%. Combined with our expectation to deliver 3% to 4% total production growth, this reiterates our continued focus on capital efficiency and discipline. We plan to allocate $1.1 billion to D&C, with the remaining allocated to leasehold facilities, workovers and other non-D&C capital expenditures. This includes Continental's cash portion of planned spending for mineral acquisitions made in conjunction withour relationship with Franco-Nevada. With the carried structure in place, Continental will fund 20% of the 21 planned mineral spending or $13 million, and Franco-Nevada will fund the remaining 80% or $52 million. As an update on our maintenance capital, our long-term maintenance capital is expected to average $1.35 billion, varying within a range of 1.2 to 1.5 depending on commodity mix and project timing. In these ranges, we expect we can deliver flat to low growth. We expect to deliver our sixth consecutive year of positive free cash flow in 2021. We are projecting approximately $1 billion of free cash flow at $52 WTI and $2.75 Henry Hub. Obviously, these prices are higher now at current strip. This equates to a strong cash flow yield of approximately 12%. Every $5 increase in WTI is expected to increase cash flow by approximately $250 million annualized. Thanks to our sustainable free cash flow outlook, we are projecting significant debt reduction this year. Our total debt at January 31 was $5.3 billion, which is a significant improvement from the third quarter 2020 and $200 million lower than what we had at year-end. As Bill highlighted, we have an ultimate long-term debt target of $2 billion to $3 billion, which would equate to approximately 1x debt-to-EBITDA or below at 2021 budget prices. At budget prices, we expect to be at approximately $4.5 billion of total debt by year-end 2021 and below $4 billion by year-end 2022. As part of our commitment to debt reduction, we are also prioritizing continued calls on near-term maturities. In 2021, we expect to use free cash flow to call the remaining $231 million outstanding on our '22 bonds, pay off our revolver and work towards paying off our remaining 2023s. As highlighted in our report yesterday, as an update on the previously disclosed water monetization process, the Company has made the decision not to further pursue this transaction. Ultimately, the Company has elected to maintain full operational flexibility to maximize the long-term value of these assets and enhance broader corporate cash flows. Our primary form of shareholder capital returns will be debt pay down, but we are also focused on the eventual reinstating of our dividend, as Bill mentioned. At this time, we would like to build more protection against price volatility by paying down debt, but our management and the Board are aligned in wanting to see the return of a sustainable and growing dividend sometime in the near future. With that, we are ready to begin the Q&A of our call, and I will turn it back over to the operator. Thank you.

[Operator:]

We will now begin the question-and-answer session. And our first question will come from Neal Dingmann of Truist Securities.

[Christopher Svensson:]

Good morning to all and great details. My first question is just, can you talk a little bit about how

[John Hart:]

Hi, Neal. We're not picking you up.

[Neal Dingmann:]

Is that better?

[John Hart:]

That's much better. Thank you.

[Neal Dingmann:]

Okay. Harold, your comment and I agree, I think price will continue to run a little bit. Based on that, you all's thoughts about M&A would you -- besides the piece of the PRB? Are you actively looking at more bolt-ons, other areas? Maybe just your thoughts about how you capitalize on these prices?

[Harold Hamm:]

Well, the bolt-on -- strategic bolt-ons that we've done in the past have been very accretive to the Company as we're all aware. And those are certainly the best kinds that we look across the board, like everybody at M&A possibilities. And we don't have anything we're targeting currently. And at this time, but certainly, we're seeing a lot of those out there in the industry today.

[Neal Dingmann:]

Got it. And then just a follow-up. Jack, or one of you all could comment, maybe just on the water or monetizations, your thoughts on why decided to keep that? Is it just based on sort of what you're going to continue to build out? Or the market wasn't there for that? Maybe potentially talk about why not monetize that? Or if there's anything else you would consider instead to monetize?

[Bill Berry:]

Yes, Neal, it's Bill. Good question. Yes, we looked at the monetization, had a good platform to go and put that out and worked real well with SAP to try to see if we could put something together that worked for both of us. At the end of the day, we thought that where we were as a company with the operational flexibilities and capabilities and optionality that it provided us by keeping it. That was a better thing for the Company to do. So that's what we ended up making the decision on.

[Operator:]

The next question comes from Jeanine Wai of Barclays. Please go ahead.

[Jeanine Wai:]

Hi, good morning everyone. Thanks for taking my question. My first -- and hope everybody is doing well with the deep freeze managing through that. My first question is on 2021 CapEx and higher oil prices. The budget this year is based off of $52 WTI the strip is much higher than that today. And the $250 million cash flow sensitivity that you gave, that's really helpful for every $5 move to help us calibrate. So if the strip turns out to be correct, would the plan be to remain anchored at that 58% reinvestment rate, which is pretty attractive and perhaps accelerate some of the delineation work in the PRB or maybe start working on the 2022 plan?

[Bill Berry:]

Yes. I think as you look at what you're addressing there. I mean there's a discretionary cash that we coming in, what's the first application of that. And the first application is continuing to return it to the shareholders. And the first vehicle we use for that would probably be through debt. And then the second one that we mentioned is that the Board has an option and a desire to consider bringing the dividend back in. So those are probably one that stand in line before we start looking at anything on doing extra money going back in the ground through CapEx.

[Jeanine Wai:]

Okay, great. And then my second question is on just your skew on oil versus gas and the '21 oil forecast. So you made the strategic shift in the back half of last year towards more gas-weighted assets in Oklahoma to take advantage of some commodity price strength. And in this year's outlook, about two-thirds of the D&C CapEx will be in the north, which is overall more oily. So how does this translate into the flat oil volume forecast for the year? And can you discuss whether maybe there's some operational time lag between spud and first production that maybe isn't getting fully appreciated by the market? Or maybe can you address the oil performance in the Bakken, specifically, we've had some questions on whether there's any GOR changes in the base in the Bakken? And whether the oil percentage in new wells, if that's kind of been relatively consistent?

[Bill Berry:]

Yes, this is Bill. I'll start off with, and then Jack and John will probably bring a little extra texture into it. If you go back to what we did in 2020, as you mentioned, we intentionally put a couple of extra rigs in the gas play. If we moved rigs up to the North instead of the South, we probably would end up seeing around 2% volume change from 2021 more oily than gas. We did it for the reasons you stated, and the commodity prices have strengthened on this we're still seeing lots of good opportunities in the North, and that's manifesting itself with the drilling rig activity movement that we're going to be doing in the North area. And of course, as you suggest, the oil prices have come up that makes it probably more prudent to be looking at those at this point in time. Jack or John, do you got anything do you want to…

[Jack Stark:]

Well, you're exactly right, it is what we're seeing is just a reflection of where we put our dollars. And in '20, and we'll continue to do that in the South in early '21. And so, you'd expect that you're going to get -- we've brought on some significant volumes. I mentioned in my prepared statements there, and we also have another 22 wells, we're going to be bringing on that are going to be high-volume gas wells in the first half of the year. And so, all these really are really by design that you'll see a little bit more growth in gas this year than you do in oil.

[John Hart:]

Yes. The one other one on the oil side that we might talk to is long Creek, which is a big project we've got up in Bakken. And that's a more long life type of project from the development side of things. And you'll see a lot of the production coming on in '22 from the '21 CapEx spend, about $100 million CapEx we're going to be spending in '21 that doesn't happen with production until '22.

[Jack Stark:]

Yes. I can give you a little more color on that, Jeanine, too, just from the Long Creek unit. This is a huge project that we've got is 56 wells. And Continental obviously operates that, and we have 85% working interest in this. And so we're going to commit two rigs to that or are committing two rigs to that in 2021. And approximately 20% of the wells will be brought on in '21, about 50% in '22, and then you'll see 30% of those wells coming on in '23. So it's a big, big project. A lot of logistics being orchestrated there, but it's going to be extremely efficient operation, given the concentrated position that we have and the plans we have to handle all the water, oil, gas, all it takes a while for all this oil to get on when you have these projects that are at this scale.

[Bill Berry:]

This is also some of the best rock in the basin.

[Jack Stark:]

It is. It is. That's -- we're very excited about this project. We're glad to get back to drilling on this one.

[Operator:]

The next question comes from Arun Jayaram of JPMorgan Chase. Please go ahead.

[Arun Jayaram:]

Yes, good morning. Quick question on maybe -- thoughts on maybe the trajectory of oil volumes in '21. Jack, if I heard you correctly, it sounds like you anticipate greater oil growth in the second half of the year. And I was wondering if maybe you could maybe comment on that and how -- what kind of impacts are you seeing? You mentioned in your prepared comments, maybe, Bill, that a couple of your non-op partners in the Bakken may have been reducing capital allocation. So maybe you could just give us a little bit more color on what some of your non-op partners are doing in the Bakken?

[Bill Berry:]

Yes. Maybe I'll just highlight a couple of things on the non-ops. We talked to both of them, and they have some strategies that are supportive of continuing to pursue the projects. In fact, there's quite a few ducts out there, but as everyone's going through different perspective of where they're going to spend the capital and the capital is being reduced. This is one for a couple of our non-ops, they've opted to slow down the capital spend in the Bakken, but still planned on going forward with both of them are planned on going forward with in the future, just not until maybe the latter part of this year.

[Arun Jayaram:]

Got it. Got it. And that is just impacting maybe the first half a little bit. Is it a fair, Bill, the second half of the year will just have greater or overall oil volumes versus the first half to be a little bit more gas weighted?

[Bill Berry:]

Yes. You're seeing the big gas weighting in the first half for a couple of things. One, we spent all drilling -- a good portion of the drilling last year that hit fourth quarter of last year and in the first half of this year with those gas volumes that Jack was talking about coming on. And then the ramping up of the drilling program, we're going from -- we had about two rigs running up there in the North last year, and we're going to be taking that up to last year, and we're going to be taking that up to about eight, I think, this year. And so that's going to be -- what you're going to see a lot of that. But that's coming on later as oil has come up. But second half, of this year, you'll see it, oil higher than the first half of this year. And then, of course, that will continue to ramp up into '22.

[Arun Jayaram:]

Great. I have one for John Hart. John, you talked about the Board pursuing a dividend at some point in the near future. For memory, John, I know before the pandemic hit, you guys had started a dividend for memory, it felt like it was in the nickel a quarter or $0.20 per annum kind of range. I don't know if you could maybe help us think about how the Board may be thinking about reinstituting the dividend relative to the previous rate or any other high-level thoughts on what type of dividend we could see from CLR in the near future?

[John Hart:]

Yes, great question. It was $0.05 a quarter previously. You may recall that we launched the dividend. We indicated at the time we were going to start in a conservative type range. However, I will point out that was in line with a number of our larger peers from a dividend yield perspective. And stuff. So as we go forward, ultimately, I cannot speak for the Board. We have very close shareholder alignment, obviously. So we have a lot of viewpoints towards where we want to go as a company. The key thing is with the level of cash flows that we're putting off and with the depth of inventory that we have remaining, we've got a significant runway in front of us. So, we have a lot of flexibility, getting debt down as aggressively as we have over the last few years and as aggressively as we are going to in the future leads to even greater flexibility in that. So I think there's certainly a lot of optionality there, but I would hate to speak for the boards in terms of a level or a set number, but we certainly have a great deal of flexibility and that alignment with shareholders.

[Arun Jayaram:]

Harold, maybe just on this variable dividend structure that a couple of your peers are adopting?

[Harold Hamm:]

Well, it could fit this industry due to the volatility of pricing. And what we've seen in the past year or two and there are several companies that considered it. We considered it when we come out with our own. And at that time, it's something that we thought we could always go to and adding that to our own dividend in the future, if the investor base likes that.

[Operator:]

The next question comes from Brian Singer of Goldman Sachs. Please go ahead.

[Brian Singer:]

Thank you. Good morning. My first question is with regards to maintenance capital. I believe in your prepared comments, you talked about long-term maintenance capital of $1.35 billion, and there was a range around that I think was 1.2 to 1.5 billion, and realized that its long-term, but I just wondered more specifically, is that to get a flat to slight growth in volumes based on 2021 average levels or pro forma levels? And what does that assume if any change in mix i.e. would that have a similar rate of flat to low growth from both oil and gas? Or would it imply a mix shift one way or the other?

[Bill Berry:]

Part of the reason you have a range is because of that mixture can change in there. Obviously, we've got a depth of inventory in Oklahoma where we have oilier assets. We've got a lot of condensate. We've got some dryer gas. Bakken is certainly a high oil concentration. Powder River is certainly a very high concentration also. So, if you shift from a gassier mixed or an oilier mix, that can push you towards a higher maintenance capital, if you shift from an oilier mix to gassier mix, that can push you down. We have a tremendous amount of optionality and that enables us to prioritize the product, depending on our views of the commodity prices you've seen, as do with natural gas here. So, that's a driver of the range that you get going forward.

[Jack Stark:]

And Brian just one other thing, that one of the things that'll impact that is, the longer cycle time project year in and year out, each year depending on what's your mixes of those that will impact the range.

[Bill Berry:]

And Brian did a couple of other aspects to your question. Did we cover those?

[Brian Singer:]

I think you did. It was really whether you were talking about keeping 2021 average volumes flat. Is that another way to do that on a going forward basis or flat to rising I think with the commitment made with the language that you used, but it was based on 2021 average pro forma purpose?

[Bill Berry:]

Yes.

[Brian Singer:]

Okay.

[Bill Berry:]

Yes, Brian, that number and those ranges were consistent with what we've had. We've obviously grown the production base, but we would dream greater efficiencies. So, we've kind of been in that range for a bit now and that gives us flexibility in terms of mix and et cetera.

[Brian Singer:]

Thanks. And then, my follow-up is progressed to the addition of the PRB acreage. If we look at the areas that have been generating a lot of your productions here of late the Bakken and scoop those are areas that Continental was a leader in opening those plays from the very beginning. And the Powder River basin is one where there has been some activity over the years from others and industry. We realized that not all acreage positions are created equal, but I wondered, if you could speak to what you think either industry or prior operators have been missing? And ultimately how active you could become and how you would define success from the acquisition?

[Bill Berry:]

We talk about leadership and that's very important comment was always done that from a geologic perspective, and we certainly with kind of Powder River Basin as well. We're not a novice to Wyoming with operate at their great deal in the past. And so, this is home base to all of us. I think we all grew up there. So, operations fit us very well and in both drilling and development and from a technical standpoint. So, yes, I'll look up to the same type of leadership we've shown in other basins and Powder River.

[Brian Singer:]

I guess is there anything specific to the acreage in question that makes it unique relative to the other acreage around it or techniques that you would bring that others aren't using that you could speak to?

[Tony Barrett:]

Brian, this is Tony Barrett. And the position we acquired is right in the core of the basin, it's in the heart of the overpressure cell. So we like it from that aspect. The other key thing that we liked about this position is that it was somewhat tested by our predecessor, Samson, with excellent results. So we think this play in our acreage position there is perfectly set up for the expertise of Continental operationally to go in and reduce costs and really make this a significant add to the portfolio. The other last thing I'll mention is that, this is in also in the heart of the oil window as well. So, we expect about 70% to 80% oil cut on all the reservoirs we're chasing in that particular block.

[Operator:]

The next question comes from Doug Leggate of Bank of America. Please go ahead.

[Doug Leggate:]

Thanks guys and thanks for getting me on and for because I haven’t spoken to you, Happy New Year guys. Appreciate you taking my question. Fellows, I wonder if I could just a follow-up about Samson. Obviously, it's been at pretty hard today. But the size of the position, you've talked about a six-year rig year program. I'm just wondering, is this a starting point for your position? Is this a foothold that you would expect to expand? Because obviously, you're aware, a number of other companies are now declaring the PRB less core than it might have been a year or so ago, FASB, for example.

[John Hart:]

Yes, Doug, thanks for the question. We -- obviously, in Oklahoma and Bakken has established very significant core positions, and that's one that you always try to strive for as you go into areas. We're we look at lots of different basins, and this is one that we looked at. And as Tony mentioned, really, really like the geology. There's running there, and there's opportunities for consolidation in that basin, just like they are in other basins. So, we'd always be interested in seeing if there's something else that we fit with this.

[Doug Leggate:]

So fair to describe it as a starting point or foothold, you're not done, in other words, Jack?

[Jack Stark:]

Doug, it always depends on the value proposition right value proposition, let's -- and if you look -- go back and look at the things that we did this past year with the Samson up and the Powder River, look at what we do with the pieces that we ended up bolting on here in Oklahoma. We continually stress test those against what everybody else is doing as far as either from a bolt-on M&A or from a corporate M&A. And we look at what do the metrics look like and if you look at the metrics on the things that we've added on, they're stronger, stronger than any other assets that have been added either through bolt-on or through corporate acquisitions. So where it's all about value proposition for us. And so if there's an opportunity to grow with a good value proposition, we absolutely grow anywhere, both in the existing basements of Bakken, Oklahoma as well as Powder River, but that's always the key. What's the value?

[Doug Leggate:]

My follow-up, if I may, is for John. And John, I apologize in advance, you're going to hate this, but I'll give it a go anyway. You guys have done a great job, I think, along with a number of your peers in simplifying this business down to a free cash flow yield story, showing us what your business is capable of doing. And I know you've got a lot of optionality, which has now expanded to the Powder River, especially within commodities in Oklahoma, in particular. My question is about sustainability because the one thing that the push back, quite honestly, that we continue to get in our positive view of Continental is it's all very well having free cash flow, but how long can you sustain that for? And I guess it's an inventory debt question. But I just wonder if you could address that in terms of how you think about long term planning. What would you tell the market is the sustainability of that maintenance plus free cash flow yield strategy?

[Jack Stark:]

Well, Doug, this is Jack. And I may start out. I know you directed this toward to John, but let me just talk about the inventory here. And as I mentioned last quarter, and this is before the Powder River Basin acquisition, is that we've got enough inventory to sustain a 5% compounded annual growth in the Company for the next 10 years. And if you look at the first five years of that, we're looking at about a third of our inventory in the first five years. And the rates of return on that inventory that we'd be drilling, is like 50% at $50 WTI. And so, it's a very strong portfolio. And again, this is before adding in the Powder River Basin. So as far as an inventory and sustainability standpoint, I don't see that as a problem. I see that as an opportunity for us out here to just decide just at what pace do we want to grow.

[John Hart:]

Yes. Doug, you misled me a little bit. I don't hate that question. The other part to Jack's comment there is not only the depth of inventory, but the quality of inventory. We see strong, consistent, sustainable, stable return on capital throughout that. We do not see a degradation in capital employed. It remains at very strong levels. Speaking to sustainability also, it seems like with dynamic markets, which we can have people kind of can focus on the naysayer or type things. This will be the sixth consecutive year of free cash flow for this company. As we look out over that 10-year horizon with a stable capital efficiency with the improving capital efficiency, as commodity prices go up, and with the depth of inventory that Jack has spoken to, we see strong free cash flow throughout that. The ability to pay off all of our debt, if we choose to the ability to put in growing strong dividends, the ability to do variable dividends the optionality to do a lot of things. So, I love the question. And we are very well positioned and we feel very confident in our position.

[Doug Leggate:]

I appreciate the answer guys, thank you.

[John Hart:]

Thank you.

[Operator:]

The next question comes from Charles Meade of Johnson Rice. Please go ahead.

[Charles Meade:]

Good morning, Herald, to you and your whole team there.

[Harold Hamm:]

Thank you.

[Charles Meade:]

I'd like to go back to Bill's prepare remarks or maybe semi prepared at the beginning of the call. Can you give us a sense of in general, I'm sure there's multitude of reasons, but in general, what's the difference between the 50% of the gas production that you have on now and the 50% that's offline? And what is the difference? What is Continental doing differently from the rest of the industry which appears to be at a lower capacity?

[John Hart:]

Yes, let me -- Harold has got some good comments on this and then I'll follow up with his comments.

[Harold Hamm:]

Yes. First for all, I'd say, we've got a team out here and I started off my hats off to team because we've get it done. We work 24x7 that what it takes. A lot of people forget that gas wells can freeze up with liquids with below sub zero, and that's what we've had. We've had 10 days of below zero and the oil is freezing and rather below zero here in Oklahoma. But a lot of people forget what it takes to keep them on, but we've been able to do that. We mentioned -- Bill mentioned the peers out there. Production down to 5% to 10%, 15%, we feel awfully good at having RSF for 50% in times like this. And also, I want to say something about the team's decision last year to bring those gas units on the jump in and complete, and drill and complete when costs were low and get those prepared for the winter that we were anticipating at least that we have now. So Oklahoma has had hardly any blackout, one hour, I think, we've experienced so far and here in Oklahoma, and a lot of Oklahoma's running on Continental gas today.

[John Hart:]

Yes. And I'll just follow-up with that, Charles, that the people that are out there, I just cannot overstate how much they've contributed not only to this company, but to the communities that we're in early on, the teams got together and said, we're going to put double duty. So we started putting night shifts on, and we usually wouldn't run night shifts. Historically, we also cross-trained our people, so we have some folks that can immediately go from doing different jobs to go doing the operator jobs to keep things up and running. Early on, we went and tried to get all the steamers we could to go keep things warm because, as Harold said, this stuff freezes up and once it frees up not much you can do with it. And one of the bigger things that we did early on early on, as reached out to the pipelines, reached out to the government leaders and said, we need to work on this together. And so, there's just been multitude calls at all different levels trying to help each other to keep this up and running. Got it. That's helpful color.

[Charles Meade:]

John, that's helpful color. I appreciate all that detail. And then a follow-up question, hopefully, is a little simple one. I'm curious if you could give a little insight into your thought process on coming up with $52 WTI as your planning case. When I look at it, it makes sense to me because that's where the curve settles out. As you go out in time, but I'm wondering if you could tell me how you came up with that or how you settled on that?

[John Hart:]

Well, we ran it a few weeks ago, and you're right, we were looking at where the curve was in kind of the range of that. The prompt was a bit lower at that time, but it's certainly been lifting up and generally in that range.

[Harold Hamm:]

Yes. It obviously was conservative.

[Charles Meade:]

Right, thanks for that detail guys.

[Operator:]

The next question comes from Derrick Whitfield of Stifel. Please go ahead.

[Derrick Whitfield:]

Thanks. Good morning all congrats on the PRB transaction. It was similarly bought near PDP value.

[Bill Berry:]

Thank you.

[Harold Hamm:]

Thank you.

[Derrick Whitfield:]

Regarding the PRB transaction, could you speak to the relative returns you expect in the PRB and verify that you have associated infrastructure in place are permitted to substantially develop the permits you have in hand?

[Bill Berry:]

Oh, sure. As far as the returns, I think that was the first part of your question here, how do they compete, and they really, they compete quite well with our existing inventory. And they said, We haven't had a chance to get in here and start applying our efficiencies and our operational technology to, as we expect to improve performance and also the just the economics of the play. So, anyway, we're looking forward to that. Now, as far as infrastructure is concerned, yes, there's infrastructure they're actually underutilized, and so we have a plenty of running from there from an infrastructure standpoint, and so we're not, no issues there. And what was third part of your question?

[Derrick Whitfield:]

Its permits and…

[Bill Berry:]

Oh, permits, yes, permits. Yes, we've got 96 permits in hand, federal permits because this is a lot of the acreage, there's going to be federal acreage. And but with the 96 permits there we're looking at essentially the six rigors of inventory. And so we're, we've got plenty of work ahead of us as we start doing our art, what we do, and that's get in and start really delineating and determining what is proper density, and what's the proper technology and all that to apply to, to basically maximize the returns from these assets. So, we're very, very excited about them. And our teams, as I said, are already on the ground, and we're getting ready to put some rigs up and see what we can do.

[Derrick Whitfield:]

Great update. And then with regard to the expected gas-weighted activity for the first half in terms of completions, would it be fair to assume that, that's principally located in the more prolific SpringBoard III and IV areas?

[John Hart:]

No. Yes, you're going to find that it's a mixed bag where these will be located. But actually, you're going to see these being in SpringBoard I and II, more so than, say, SpringBoard III and IV. Actually, there's three -- SpringBoard III and IV actually are more oil weighted in most of those areas. And so, it's a -- so we just have a great optionality with these assets and great product mix in these assets. And we do like the fact, as you mentioned, that we're seeing a substantially thicker overall hydrocarbon column there with the reservoirs there and Sycamore and Woodford, not to mention Springer, and we've got some other things in mind that we're going to be looking at and testing ultimately in these plays. And so, we really like the assets. In my prepared remarks, I mentioned that just -- it's -- I don't think people really fully appreciate just the sheer scale of the operation that we now have down there. When you look at the 360 square miles of acreage that we control with about a 70% average working interest, I mean, that is a huge footprint. And these are large contiguous blocks of acreage that allow us to get in there and really drive cost down through efficiencies or efficient operations. And so from my standpoint, these are the type of projects that Continental does, and we get in early. We have a dominant position. And when we get that position, we continue to build on it. And we really have done that here. So anyways, thanks for the question.

[Operator:]

This concludes our question-and-answer session. I would 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 follow-up with the IR team here with any further questions, and we really appreciate your time. Stay safe out there. Thank you.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation and you may now disconnect.