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spk05: 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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. 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.
spk02: 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, Confidential 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'll turn the call over to Mr. Hamm. Harold?
spk11: Harold Hammond- Thank you, Rory, and good morning, everyone. I'd like to begin by commending our employees for their incredible performance in 2020. 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 has fallen into 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 that both the US 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 without 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. The U.S. oil and natural gas industry will continue to play a vital part in the American energy landscape as the world seeks access to our gas and light sweet crude. As part of this, we're seeing American Gulf Coast Select, or AGS, continue to gain momentum. Phase one of AGS was completed last year by establishing the benchmark. AGS recently completed its phase two, where it established a Houston-based area-centric delivery point for Gulf Coast barrels. This is a fundamental step for AGS and shows that we're on track with where we want to be at this time. Great progress has been gained with so much potential migrating to the Gulf Coast, and we are pleased where we are in the process. As an independent producer, we've been proud of the progress we have made the past 10 years to strengthen and preserve our nation's energy independence by supporting our economic progress through reliable and affordable energy and job creation. On top of protecting U.S. energy security, U.S. producers have also addressed investor concerns that E&P's prioritized reinvestment ratios, and shareholder returns. We see the critical importance of remaining capital disciplined and believe this will continue to be a key part of Continental's value proposition. I will now turn the call over to Bill Berry.
spk12: 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 I 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 grid's 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 companies so that they 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. I'm understanding from talking to the utilities that most of the other operators are 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 flowed all the gas that we could. With that, let me get into my prepared remarks. We exceeded our free cash flow guidance for a full year 2020, and in spite of industry enduring some of the most unprecedented challenges I've faced in my 44 years of experience, Continental again showed what we're capable of. Thanks to our capital discipline, low cost, nimble operations, strength and optionality of our assets, and most of all, our outstanding employees who, like Harold, I want to thank for their dedication and commitment, which we really saw here recently in Oklahoma with all the snow and the freezing that's happened to us. We've really been able to set up an even stronger and resilient future for Continental and our shareholders. 2020 demonstrated our continued unwavering commitment to delivering free cash flow in service of our focus on returns to shareholders. In a year with a worldwide pandemic, negative oil prices and 20 million barrels of supply and demand imbalance, Continental delivered on the following. Our fifth consecutive year of free cash flow. We said we'd generate $200 million. We generated nearly 40% more, $275 million. Also, we targeted and achieved significant well cost improvement in Bakken and Oklahoma. All in well costs were reduced by 13% and 6% respectively. We captured 98.3% of our gas and delivered our best year of safety performance ever as part of our focus on ESG stewardship. Operationally, our results were strong relative to our guidance for the year. which again underscores that Continental always endeavors to deliver on what we said. For perspective, we said CapEx would be at or below 1.2 billion. We spent approximately 3% less at 1.16 billion. We said we'd produce 155 to 165,000 barrels per day. In 2020, we produced 160.5 thousand. We've ceded our production guidance and delivered 837.5 million cubic feet a day versus a guidance of 800 to 820. Our operations teams did a superb job of managing our production expense per BOE at $3.27 versus our guidance of $3.50 to $3.75. The operational execution and capital discipline we saw in 2020 is only the beginning. As we look ahead to 2021, we're excited to share our strategy and value proposition. Jack and John will provide more operational and financial details respectively. But as a summary, let me highlight that we are absolutely committed to our number one goal of delivering strong returns to shareholders. As part of that commitment, we are targeting returns in excess of 40% cash flow from operations through debt reduction and future dividends. Any reinstated or future dividends considered in 2021 will require Board approval. However, the Board has indicated it is desirous of returning a dividend as soon as prudently possible. We are projecting our sixth consecutive year of positive cash flow in 2021 with approximately $1 billion at $52 WTI, with what we believe will be a peer-leading free cash flow yield. We're targeting approximately $1 billion of debt reduction in 2021 to about $4.5 billion total debt by year-end. As we indicated on our third quarter call in 2020, our ultimate long-term total debt target is $2 to $3 billion. In order to accomplish 40% return to shareholders, we expect to spend $1.4 billion, which is 58% cash flow reinvestment rate, slightly below our current reinvestment framework of 65% to 75%. We expect to deliver 3% to 4% total production growth in 2021. Importantly, our assets are exhibiting continued strong performance with our operated volumes expected to rise 6% to 8%. which is somewhat offset by non-operated volumes, which are expected to be down 7% to 9%. Our 2021 volumes are being impacted by two larger non-operated partners in the Bakken who are delaying oil-related projects this year. As you recall, we shifted some rigs to gas in Oklahoma last year. We're maintaining that level and also increasing our oil rig activity from two to an average of seven rigs in the north. Consequently, we saw gas growing in fourth quarter 2020 and the first half of 2021, as we see oil growing in the second half of the year 2021. We'll continue to focus on our low-cost leadership and are projecting costs consistent with 2020. We expect to deliver strong cash flow of creative asset performance across all our basins, including our recently announced assets in the oil-weighted Powder River Basin. Jack will provide more details, but we are excited to add a third layer to our incredibly rich asset bases in Bakken and Oklahoma. Our strategic marketing effort continues to deliver positive momentum in 2021. To date, approximately 360 million cubic feet of our 2021 natural gas is hedged, with a midpoint of swaths and collars at about 297. With respect to oil and additional 10,000 barrels per day of firm takeaway capacity has been added from the Bakken to Cushing with no dilution of our differentials under any DAPL scenario. Even though we only have about 3,500 barrels a day of firm transportation on DAPL, it is a critical piece of American energy infrastructure supported by numerous states that has aided in our nation's energy independence and security. The line has been operating safely for the last four years and once Fully adjudicated, we expect DAPL to be a long-term transportation option out of the basin, but we have prepared for multiple scenarios. If, in fact, it does shut down, we'd expect our corporate-wide differentials to be adversely impacted by $1 to $2 a barrel. If DAPL does not shut down, we'd expect our differentials to be on the more favorable side of our guidance. Lastly, we are committed to our strong ESG stewardship and will publish 2020 ESG report around mid-year 2021. Across every level of the company, our teams remain keenly focused on sustainability, our environmental impact, and our role in society and corporate governance. With more than 80% of company shares held by insiders, the team at Continental acts, thinks, and operates like owners because we are. The same can be said for our ESG program. When we continue to be where we can continue to be a leader in efforts to responsibly fuel a better world as we serve and support the communities in which we operate. In 2021, Continental is set up to continue its execution excellence while focusing on shareholder returns by maximizing free cash flow. Capital discipline, free cash flow generation, and delivering returns to shareholders are, again, core messages, as stated in many of my prepared comments. I'll now turn the call over to Jack.
spk14: 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 II 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 nine. This demonstrates the consistency of the reservoir and optimal density design by our teams. Our drilling also expanded into springboard three and four during 2020, and early results from both the Sycamore and Woodford reservoirs have been impressive. Slide nine 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 and Woodford reservoirs in Springboard 3 and 4, as shown on slide 9. Combined, these two reservoirs are up to 750 foot thick in Springboard 3, which is essentially twice the thickness of the reservoirs in Springboard 1, 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. Since October of last year, we have put 17 new wells online that flowed at a combined maximum initial 24-hour rate of 256 million cubic feet of gas and 7,500 barrels of oil per day. As anticipated, these volumes are benefiting from the constructive long-range fundamentals for natural gas, while providing the critical supply needed as the country gets hit with a historic Arctic blast, as Bill had mentioned. Approximately 50 percent of our Oklahoma rigs will continue to focus on natural gas in 21, and we expect to put another 22 wells online primarily in the first half of the year. In the Bakken, our completion activity slowed during the year while prices were low, but the results continued to be remarkably consistent year over year. As shown on slide eight, the average performance of 23 wells completed in the fourth quarter fell right in line with the prior three years. We expect our 2021 Bakken drilling program will deliver similar results as illustrated by the dashed line on the chart. During 2020, we also completed our first density development along the southern extents of our Bakken acreage and we are very pleased with the results. Slide eight shows that these five density wells are outperforming our legacy wells expected And wells in this area have a lower completed well cost of approximately $6.4 million and are expected to deliver rates of return in excess of 30% at $50 WTI. With an eye on the future, we also grew our assets during 2020 through cost-effective bolt-on acquisitions, leasing, and trades. In Oklahoma, we added approximately 47,000 net acres to our oil-weighted springboard assets. Combined, our four springboard projects now cover approximately 360 square miles, that are dominantly operated by Continental with an average working interest of approximately 70%. We currently estimate up to 650 wells remain to be drilled, targeting multiple stacked reservoirs in these projects. This scale of operation or ownership and operational control is quite unique, and the economy of scale it provides drives efficiencies up and operating costs down. We also made the strategic move to expand our operations into the oil-rich Powder River Basin. In late December, we entered into a PSA to acquire Sampson Resources assets located in the basin. The properties include 130,000 net acres and approximately 9,000 BOE per day, of which 80% is oil. The majority of this acreage is strategically located in the oil and condensate windows where 70 to 80% of the production has proven to be oil from multiple stacked reservoirs. Approximately 80% of this acreage is held by production. These assets provide continental shareholders another great platform for growth, adding over 400 million BOE of net unrisked resource potential to the company's portfolio. The Basin is in its early stage of development with solid results that compete economically with our portfolio, even before adding the benefits of our operating efficiencies and technology. Our teams are on the ground, and we intend to begin delineating and developing the various reservoirs with two rigs in the second quarter of 2021. We currently hold 96 approved federal drilling permits. Operationally, our teams continue to uplift the value of our assets across the board through increased efficiencies and lower costs. Today, we are more capital efficient than ever and continue to be the low-cost leader among our oil-weighted peers, as shown on slide five. Our completed well cost for the Bakken and Oklahoma wells now stand at 6.9 and 8.8 million respectively, including full facilities and artificial lift. But our teams have additional cost reductions in sight for 2021. Now let's take a quick look at our drilling plans for 2021. As announced in our release, we have allocated $1.1 billion for drilling and completion activities in 2021. Approximately 60% is targeted for the Bakken, 35% to Oklahoma, and 5% to our Powder River Basin assets. We plan to operate an average of 11 rigs during the year, with five to six in the Bakken, four in Oklahoma, and one to two in the Powder. We expect to complete approximately 139 net operated and 12 net non-operated wells in 2021, and exit the year with 135 wells in progress. I will now turn the call over to John to provide more color on our plans.
spk09: 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 GNA per BOE was in line with guidance at $1.79. While our DDNA increased over prior periods, this was due to downward revisions improved 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 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 DNC, with the remaining allocated to leasehold facilities, workovers, and other non-DNC capital expenditures. This includes Continental's cash portion of planned spending for mineral acquisitions, made in conjunction with our relationship with Franco Nevada. With the carry 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 script. 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 to $3 billion, which would equate to approximately one times 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 focus, 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.
spk05: We will now begin the question and answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then 2. At this time, we will pause momentarily to assemble our roster. And our first question will come from Neil Dingman of Truist Securities. Please go ahead.
spk07: Great details.
spk10: My first question is just a little bit about, you know, how your thought was.
spk12: Neil? Yes, sir. Yeah, we're not picking you up.
spk07: Is that better?
spk12: That's much better. Thank you.
spk07: Okay. Harold, your comment, and I agree with you. I think price will continue to run a little bit. Based on that, your thoughts about M&A, would you, you know, 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.
spk11: Well, you know, the bolt-ons, strategic bolt-ons that we've done in the past have been very effective. accretive to the company, as we're all aware. And, you know, those are certainly the best kind. But, you know, we look across the board, like everybody, at M&A possibilities. And, you know, we don't have anything we're targeting currently at this time. But certainly we're seeing a lot of those out there in the industry today.
spk07: Got it. And then just to follow up, Jack, if one of you could comment maybe just on the water or monetizations, your thoughts on, you know, why decided to keep that? Is it just based on, you know, 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.
spk12: Yeah, it's Bill. Good question. Yeah, we looked at the monetization, had a good platform to go put that out and work 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.
spk07: Very good. Thanks so much.
spk12: Thank you.
spk05: The next question comes from Janine Way of Barclays.
spk04: Please go ahead. Hi, good morning everyone. Thanks for taking my questions. Thank you. I hope everybody's 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 TI. And 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 a 2022 plan?
spk12: Yeah, I think as you look at what you're addressing there, Janine, is discretionary cash that would be 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'd 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 a dividend back in. So those are probably the ones that stand in line before we start looking at anything on doing extra money going back in the ground through CapEx.
spk04: 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 DNC 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. Thank you.
spk12: Yeah, thanks. 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 extra rigs in the gas play. If we'd moved rigs up to the north instead of the south, we probably would end up seeing around a 2% volume change from 2021, more oily. We did it for the reasons you stated, and commodity prices have strengthened on this. But 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 up in the north area. And, of course, as you suggested, 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, have you got anything to add?
spk14: Well, Janina, you're exactly right. What you're seeing is just a reflection of where we put our dollars 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.
spk12: Yeah, 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. You'll see a lot of the production coming on in 22 from the 21 capex spend. It's about 100 million in capex that we're going to be spending in 21 that doesn't happen production until 22.
spk14: Yeah, I can give you a little more color on that, Janine, too, just from Long Creek unit. You know, this is a huge project that we've got. It's 56 wells, and, you know, 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 on pipe. So it takes a while for all this oil to get on when you have these projects that are of this scale.
spk11: This is also some of the best rock in the basin.
spk14: It is. It is. We're very excited about this project. We're glad to get back to drilling on this one.
spk05: Great. Thank you. The next question comes from Arun Jayaram of JPMorgan Chase. Please go ahead.
spk08: Yeah, 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 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 allocations. So maybe just give us a little bit more color on what some of your non-op partners are doing in the Bakken.
spk12: Yeah, maybe I'll just highlight a couple things on the non-ops. We've talked to both of them, and they have some strategies that are supportive of continuing to pursue the project. In fact, there's quite a few ducks out there, but as everyone's going through a different perspective on where they're going to spend the capital, and then capital is being reduced. This is one for a couple of our non-ops they've They've opted to slow down the capital spend in the Bakken, but still planning on going forward with it. Both of them are planning on going forward with it in the future, just not until maybe the latter part of this year.
spk08: Got it, got it. And that is just impacting maybe the first half a little bit. Is it fair, Bill, the second half of the year we'll just have greater overall oil volumes versus the first half to be a little bit more gas-weighted?
spk12: Yeah, you're seeing the big gas waiting in the first half for a couple of things. One, we spent all the drilling, a good portion of the drilling last year. It hit fourth quarter of last year 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 about eight, I think, this year. And so So that's going to be what you're going to see, a lot of that. But that's coming on later as the oil has come up. But the second half of this year, you'll see oil higher than the first half of this year. And then, of course, that will continue to ramp up into 2022.
spk08: Great. I have one for John Hart. John, you talked about the board pursuing a dividend at some point in the near future. From memory, John, I know before the pandemic hit, you guys had started a dividend. From memory, it felt like it was in the nickel, a quarter, or 20 cents 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?
spk09: Yeah, 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 the 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 flow 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.
spk08: And John, any philosophical thoughts from you or Harold, maybe just on this variable dividend structure that a couple of your peers are adopting?
spk11: Well, it could fit this industry due to the volatility of pricing in it with what we've seen in the past year or two. And there are several companies that considered it. We considered it when we came 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, you know, in vector based like that.
spk08: Great. Thanks a lot. Thank you, Arun. Good to talk to you.
spk05: The next question comes from Brian Singer of Goldman Sachs. Please go ahead.
spk00: Thank you. Good morning. Hey, Brian. 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 about $1.35 billion. And there was a range around that that I think was $1.2 to $1.5 billion. And I realize that it's long-term, but I just wondered more specifically, is that to get flat to slag 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?
spk09: Part of the reason you have a range is because 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 drier gas windows in the Bakken area. is certainly a high oil concentration. Powder River is certainly a very high oil concentration also. So if you shift from a gassier mix to an oilier mix, that can push you towards a higher maintenance capital. If you shift from an oilier mix to a 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 us do with natural gas here. So that's a driver of the range that you get going forward.
spk12: And, Brian, just one other thing. Sorry to interrupt. One other thing that will impact that is the longer cycle time project year in and year out. Each year, depending on what which are mixes of those that will impact the range. And, Brian, you had a couple of other aspects to your question. Did we cover those?
spk00: Yeah, I think you did. It was really whether you were talking about keeping 2021 average volumes flat if that's the range to do that on a going forward basis or flat to rising, I think, may have been the language that you used. But is it based on 2021 average pro forma? Yeah.
spk09: Yeah. Yeah. Brian, that number and those ranges are consistent with what we've had. We've obviously grown the production base, but we've gained greater efficiency, 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.
spk00: Great, thanks. And then my follow-up is with regards to the addition of the TRB acreage. If we look at the areas that have been generating a lot of your production 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 in industry. Realize 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 acquisitions.
spk11: Yeah, you talk about leadership, and that's very important. Continental's always done that from a geologic perspective, and we certainly will in the Powder River Basin as well. You know, we're not a novice to Wyoming. We've operated up there a great deal in the past, and so this is home base to all of us. Pat Bent, he's the one who grew up there. So operations, you know, fits us very well in both. Drilling and development and from a technical standpoint, I would look to the same type of leadership we've shown in other basins in the Powder River.
spk00: Is there anything specific to the acreage in question that makes it unique relative to other acreage around it? techniques that you would bring that others aren't using that you could speak to.
spk13: Hi, Brian. This is Tony Barrett. The position we acquired is right in the core of the basin. It's in the heart of the over-pressured 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, SAMHSA, with excellent results. 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 also in the heart of the oil window as well. So we expect about a 70% to 80% oil cut on all the reservoirs we're chasing in that particular block. Thank you. Thank you.
spk05: The next question comes from Doug Legate of Bank of America. Please go ahead.
spk10: Thanks, guys. Thanks for getting me on. For those who haven't spoken to you, Happy New Year, guys. I appreciate you taking my questions. Fellas, I wonder if I could just follow up about Samsung. Obviously, it's been beaten pretty hard today, but the size of the position you've talked about you know, a six-year, you know, 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, we're aware a number of other companies are now declaring the PRB less core than it might have been a year or so ago, Chesapeake, for example.
spk12: Yeah, Doug, thanks for the question. Yeah, we obviously in Oklahoma and Bakken established, you know, very significant core positions in That's one that you always try to strive for as you go into areas. We look at lots of different basins, and this is one that we looked at. As Tony mentioned, we really like the geology. There's running room there, and there's opportunities for consolidation in that basin just like there are in other basins. We'd always be interested in seeing if there's something else that would fit with this.
spk10: Care to describe it as a starting point or foothold? You're not done yet, in other words, Jack.
spk12: Doug, it always depends on the value proposition. We look at things and if it's the right value proposition. If you go back and look at the things that we did in this past year with the Samson up in 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, you know, what do the metrics look like? And, you know, 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 both on or through corporate acquisitions. So it's all about value proposition for us. And so if there's an opportunity to grow with a good value proposition, we'd absolutely grow anywhere, both in the existing basements of Baca and Oklahoma as well as Powder River. But that's always the key. What's the value proposition?
spk10: Thank you. 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 with the Powder River, especially within commodities in Oklahoma in particular. My question is about sustainability, because the one thing that the pushback, 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 depth question, but I just wondered 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?
spk14: Well, Doug, this is Jack, and I may start out, I know you directed this towards John, but let me just talk about the inventory here. 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 that 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.
spk09: 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 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 the 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.
spk10: I appreciate the answer, Guy. Thank you. Thank you.
spk05: The next question comes from Charles Mead of Johnson Rice. Please go ahead.
spk01: Good morning, Harold, to you and your whole team there. I'd like to go back to Bill's prepare remarks, or maybe semi-prepared at the very beginning of the call. Can you give us a sense of, in general, I'm sure there's a multitude of reasons, but in general, what's the difference between the 50% of gas production that you have on now in the 50% that's offline. What is Continental doing differently from the rest of the industry, which appears to be at a lower capacity?
spk12: Harold's got some good comments on this, and then I'll follow up with his comments.
spk11: First of all, I'd say we've got a team out here. I started off my hat off to our team because You know, we get her done. We work 24-7, if that's what it takes. You know, a lot of people forget that gas wells, you know, tend to freeze up with liquids with, you know, sub-zero, and that's what we've had. We've had 10 days below zero and below freezing, and a lot of those below zero here in Western Oklahoma, but You know, a lot of people forget, you know, what it takes to keep them on. But we've been able to do that. You know, we mentioned, Bill mentioned the peers out there. Production down to 5 to 10, 15%. You know, we feel awfully good at having ours up there 50% in times like this. And also, I want to say something about the team decision. last year to bring those gas units on to 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 blackouts one hour, I think, that we've experienced so far. And here in Oklahoma, a lot of Oklahoma is running on Continental Gas today. Yeah, and I'll just follow up with that, Charles.
spk12: 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, you know, we're going to put double duty. So we started putting night shifts on. We usually wouldn't run night shifts. Historically, we also have 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 freezes up, not much you can do with it. And one of the bigger things that we did early on, early on, is 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.
spk01: Got it. That's hopeful color. I appreciate all that detail. And then follow-up question, hopefully it's a little simpler one. I'm curious if you could give a little insight into your thought process on this. coming up with a $52, uh, WTI as your playing case. When I look at it, it makes sense to me because that's where the curve settles out. Uh, you know, as you go out in time, but, um, I'm wondering if, uh, if you could, uh, tell me how you came up with that or how you settled on that.
spk09: Well, we ran it a few weeks ago and, uh, you're right. We were looking at where the curve was and, and kind of the, uh, a range of that. The prompt was a bit lower at that time, but, uh, it's certainly, um, been lifting up and generally in that range.
spk11: Yeah, it obviously was conservative. Right.
spk01: Thanks for that detail, guys. Thank you. Nice job.
spk05: The next question comes from Derek Whitfield of Stiefel. Please go ahead.
spk03: Thanks. Good morning, all. Congrats on the PRB transaction that was seemingly bought near PDP value.
spk14: Thanks.
spk03: Thank you.
spk14: Thank you.
spk03: Regarding the PRB transaction, could you speak to the relative returns you expect in the PRB and verify that you have the associated infrastructure in place or permitted to substantially develop the permits you have in hand?
spk14: Oh, sure. As far as the returns, I think that was the first part of your question here, how do they compete? And really, they compete quite well with our existing inventory. And as I said, we haven't had a chance to get in there and start applying our efficiencies and our operational technology to, you know, as we expect, to improve performance and also just the economics of the play. So, anyways, we're looking forward to that. Now, as far as infrastructure is concerned, yeah, there's infrastructure out there that's actually underutilized. And, you know, and so we have, you know, plenty of running room there from an infrastructure standpoint. And so we're not, no issues there. And there was a third part to your question. It's permits and... Oh, permits, yeah. Permits, yeah. We've got 96 permits in hand, federal permits, because as you know, a lot of the acreage there is going to be federal acreage. But with the 96 permits there, we're looking at essentially six rig years of inventory. And so we've got plenty of work ahead of us as we start doing 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 basically maximize the returns from these assets. So we're 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.
spk03: Great, 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 three and four areas?
spk14: No, yeah, you're going to find that it's a mixed bag, you know, where these will be located. But actually, you're going to see these being in springboard one and two more so than, say, springboard three and four. Actually, it's three and Springboard 3 and 4 actually are more oil-weighted in most of those areas. And 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 in 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. Really like the assets. In my prepared marks, I mentioned that I don't think people really fully appreciate just the sheer scale of the operation that we now have down there. When you're looking at 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 costs 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... I've done that here. So, anyways, thanks for the question.
spk03: Thanks, guys. Very helpful.
spk12: Thanks, Derek. Yep.
spk05: This concludes our question and answer session. I would like to turn the conference back over to Rory Sabino for any closing remarks.
spk02: 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.
spk05: The conference is now concluded. Thank you for attending today's presentation and you may now disconnect.
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