Alpha Metallurgical Resources Inc (CTRA) — Q4 2020 Transcript

Thank you, Caterina. Good morning, everyone, and thank you for joining us on this call. I want to begin by expressing our well wishes for any of you that may have been impacted by the recent severe cold weather; we were all caught by surprise at the severity of the event and the collapse of infrastructure that resulted from it. Like many of our peers, our operations were significantly impacted by the extreme cold weather. The good news is that our organization - our operations are almost back to normal after an unbelievable effort by our team. Mark will provide more detail on the impact of Cimarex. Despite the tremendous challenges in 2020, and in many instances because of them, Cimarex is a much stronger company as we look ahead. We enter 2021 with a lower cost structure, better asset performance, our commitment to financial performance, our continuing focus on meeting today's ESG challenges, and with our recent dividend increase, our reaffirmation of our commitment to the evolving business model of Shell 3.0. We generated good operating results in 2020 and are optimistic about the recovery in oil and gas demand and pricing as we look ahead. Fourth quarter 2020 oil production came in at 68,000 barrels of oil per day, which was 3.5% above our guidance midpoint. Total capital for 2020 was $577 million, which was below our guidance of $600 million. We generated $279 million of free cash flow after our dividend and exited 2020 with $273 million cash on hand. Blake will comment on our cost structure and John is on the call to answer any questions regarding asset performance. Delivering on our commitment to return cash to our owners, we increased our dividend 23% to an annual rate of $1.08 per share. Although future increases will depend upon market conditions. We approved our recent increase with an analysis that included the potential downside of a $35 flat oil price. Our plan for 2021 reflects our commitment to financial prudence and free cash flow generation. We expect to invest $650 million to $750 million in 2021 with oil production forecasted to grow 2% at the midpoint. More importantly, at $55 oil, our plan calls for us to invest less than half of our cash flow, generating approximately 48% free cash flow after the dividend. At a $35 oil price, free cash flow after the dividend is projected to be 9% of our total cash flow. Last year, we discussed our commitment to Shale 3.0, including our long-term intention to annually invest 70% to 80% of our cash flow. Clearly, our 2021 Capital Investment Plan undershoots this range; we view 2021 through a lens of caution. Although there are many reasons for a constructive outlook on both oil and gas prices, we would like to see a robust restart of the world economy and a balance of supply and demand fundamentals before we would consider the 70% to 80% investment range. At Cimarex, capital planning has always been about investment returns through the cycles. Our goal is long-term profitability, the generation of significant free cash flow, and returning cash to our owners. Moderating our growth in response to supply and demand fundamentals is the best way to achieve these long-term goals. We think that our 2021 capital investment plan is prudent, balanced and will leave us well positioned with great flexibility for future years. In a cyclic commodity business, flexibility is the coin of the realm. Our 2021 plans involve a significant amount of New Mexico work, most of which is on federal lands. On the heels of last month's executive order which suspended federal permit decision-making authority and regional offices, we redirected all New Mexico activity towards Texas projects. We have a deep inventory of top-tier projects in Texas, and fortunately, there were several that were shovel-ready, owing to the executive order coming at a fortuitous time. When we were mobilizing between projects, we were able to pivot from New Mexico to Texas within 48 hours of the executive order's publication. After further analysis, we are confident that permit activity on existing federal leases will continue relatively unabated, and we have restored significant New Mexico activity into our 2021 program. We look forward to working with the state and federal government as we develop our leasehold. We're also continuing our emphasis on environmental excellence in 2021. In 2020, we set aggressive high-pressure flaring and methane intensity goals, linking executive compensation to their achievement. As outlined in our investor presentation, our organization met both goals. They accomplished this through diligence, creative engineering and advanced data analytics. Our environmental goals for 2021 will continue to challenge our organization and comprise 30% of the executive team's annual incentive metrics. Before I turn the call over to Mark and Blake, I want to comment on the tremendous challenges we faced in 2020 and acknowledge how proud we are of our organization's response. It was easy to be humbled in 2020 by the hardships that many of us faced and by the valiant efforts shown by healthcare providers, emergency responders, essential workers and educators. At a time when our offices transitioned to remote work, our field personnel reported to work each day and provided critical attention to our assets. They kept our production flowing and continued to bring new wells online. They shared the same health concerns for themselves and their loved ones as the rest of us had. But they did not have the luxury of working remotely. Although we are deeply grateful to all of our employees who gave their all to keep Cimarex healthy and prosperous during 2020, none of us deserve our gratitude as much as our field staff. They're an example of what excellence and dedication look like. With that, I would like to invite Mark to discuss our financial results and outlook.

Thank you, Tom. Good morning everyone. I'll first discuss our 2020 financial results and then move on to our 2021 outlook. As Tom described, Cimarex's 2020 operational performance generated substantial amounts of free cash flow, further strengthening our investment-grade financial position. We exited 2020 with net debt of $1.73 billion, a decrease of $178 million from 2019. In the fourth quarter, we also repurchased 55% of the outstanding 8.125% preferred stock for $43 million. We remain focused on maintaining and improving our strong financial position, generating free cash flow, and providing cash returns to our shareholders, as demonstrated by the 23% increase in our regular cash dividend to an annual rate of $1.08 per share. Our fourth-quarter total capital investment was $136 million, including $101 million of drilling completion capital. Full year 2020 capital investment was $577 million, which was a 56% decrease compared to 2019 and 4% below our guidance range. Our 2020 total cash operating costs, comprised of LOE, workover, transportation production taxes and G&A, totaled $7.46 per BOE, which decreased on a per unit basis by 8% compared to 2019. On an absolute basis, total cash costs in 2020 decreased to $134 million, or 16%, compared to 2019. Adjusted cash flow from operations in the fourth quarter totaled $257 million, and we generated $97 million of free cash flow after our dividend. For the full year 2020, adjusted cash flow from operations was $944 million, with free cash flow of $372 million and $279 million after the dividend. Moving on to 2021 outlook; we expect total capital investment of $650 million to $750 million, bringing on 73 net wells to production. The majority of the capital is being directed to the Permian, with less than 10% being invested in the Anadarko Basin. Oil production in the first quarter of 2021 is expected to average 65,000 to 69,000 barrels per day, with total equivalent production expected to average 205,000 to 225,000 BOE per day. First quarter guidance includes an estimate for the weather impact on production volumes in both the Permian and Mid-Continent regions. We currently estimate that our first quarter volumes are being negatively impacted by 5% to 7% from winter storms, which is around 4,000 barrels of oil per day. For the full year 2021, our oil production is projected to average 75,000 to 81,000 barrels per day; we expect to run two frac crews in the Permian for most of the year, resulting in projected oil exit rate growth from the fourth quarter of 2020 to the fourth quarter of 2021 of over 30%. Total production is expected to average 235,000 to 255,000 barrels of oil equivalent per day. Looking at the 2021 plans in terms of capital investment rate and potential free cash flow, we illustrate on slide 5 of our investor presentation two price scenarios—a $35 WTI and a $55 WTI—to give perspective on reinvestment rate and free cash flow generation. At $35 WTI, we project our total capital investment rate to be 79% of our cash flow. At $55 WTI, which approximates recent four-strip prices, our capital reinvestment rate is 45%, with 55% free cash flow. That would be free cash flow of approximately $850 million for the year, and we estimate we will exit the year with more than $900 million of cash on our balance sheet. At these recent prices, we expect to achieve our goals this year of having sufficient cash to retire our 2024 notes of $750 million, positioning us to evaluate other options for returning cash to shareholders for further sustainable growth, regular dividends, and/or instituting a variable dividend. Our asset quality, cost structure, and organization put us in a great position to generate significant returns and free cash flow for our owners in 2021 and beyond. With that, I'll turn the call over to Blake.

Thanks, Mark. We ended 2020 with and are currently running five rigs and two completion crews in the Permian and one rig in the Anadarko, a marked difference from the one rig and no crews we had running last June. Our 2020 Permian Basin operated DNC capital cost per lateral foot came in at $944 per foot, which was down 15% from our 2019 average. Late in 2020, DNC costs averaged $800 to $850 per foot, and we expect to stay within this range throughout 2021. While we have recently seen some increases in service rates and have incorporated those into our go-forward cost, we expect some of the inflation to be offset by efficiency gains. Our operations teams continued to deliver in 2020 with our average drilling feet per day up 34% and completed feet per day up 29% compared to 2019. These efficiency gains were driven by many factors, including continued multi-well pad drilling, offline cementing, and tank battery commingling. Hats off to all our operations teams who continue to find new ways to increase efficiencies, lower costs, and challenge the status quo. A new initiative we are currently pursuing is the electrification of our DNC operations, as well as fuel compression. Of note, we have been working closely with Halliburton to develop electric frac pumps driven directly from our Cimarex-owned power grid. Three grid-powered frac pumps have been in operation since November of 2020. We have gathered valuable data on fuel savings and emission reductions, while also observing a 30% to 40% increase in pump rate, due to the on-demand power available from our grid. We are incorporating this data into other projects, including the electrification of drilling rigs and compression to guide the development of our power grid in Culberson and Henry's counties, Texas. These large contiguous assets that include the Cimarex owned and controlled power grid provide the scale and inventory needed for these electrification projects. We plan to continue to invest in our power grids during 2021. As we firmly expect, these grid investments will lead to a lower cost structure and substantial emission reductions for many years to come. Our 2020 lifting costs came in at $3.09 per BOE and we are guiding to a 2021 lifting cost of $3.10 to $3.60 per BOE. Our 2021 LOE includes increased workover activity, along with newly instituted maintenance programs focused on limiting emissions, reducing spills, and improving asset reliability. Lastly, a few operational comments regarding the recent storms that impacted our operations in both the Permian and Anadarko. Almost two weeks ago when it became clear that these storms could be significant weather events, our operations teams began putting plans in place to keep our operations running during the storm. We mobilized our entire field staff, which worked diligently and safely through extremely tough conditions. Our teams brought in road-clearing equipment to keep trucks hauling, obtained steamers and heaters to deal with freezing issues, and worked closely with our midstream partners to maximize product flow to the market. During the storm, we did encounter frac downtime due to logistical issues with sand, but our drilling rigs maintained operations throughout the storm. Thanks to these efforts, Cimarex was able to safely keep a significant portion of our operations running throughout the storm. This was an all-hands-on-deck event for Cimarex, and our field staff's efforts are truly commendable. And with that, we will now take questions.

Yes, good morning. Arun Jayaram from JP Morgan. Tom, how are you? Doing well. Just a quick question here. Mark, in your prepared comments you talked about perhaps the board evaluating a variable dividend policy; we didn't have the dividend increase. So could you provide a little bit more information on that? And obviously, I think you said $850 million of free cash flow this year on your updated guide at $55. So just want to get some more color around that variable dividend commentary.

Yes, Arun, with our current emphasis on retaining cash for having sufficient cash to look to retire those 2024 notes as our first priority, as we discussed, and second priority that has been towards increasing a regular dividend on a sustainable basis. So we're checking the sustainable dividend growth this year, and we'll see how prices really stay. And we're very optimistic that the $55 case you ran could come true. But we've seen enough volatility in commodity prices, so we're not going to make any decisions around that at this point. We'll make sure we see the cash flow through and our cash balances improve, and then we'll make further decisions. But definitely, our board's been open to discussions on our next steps, and we're certainly supportive of sustainable regular dividend growth and further open to discussions on a variable dividend.

Great. And, Tom, my follow-up, as you mentioned, how Cimarex had been pivoting activity between New Mexico and Texas just given some of the rulings from the Department of Interior and the temporary suspension. So I was just wondering why you guys were considering pivoting from New Mexico, because it was our understanding that if a project has been permitted, then you could continue to operate that project. So maybe a little bit of color around your discussion about that pivoting of activity between both states.

Well, sure. In hindsight, I would say we overreacted, and that was the reaction I would have wanted us to have. If I can go back to ancient history a full month ago, this was 24 or 48 hours after the Keystone XL discussion. We had two rigs in route to drill a fairly large project, and we did need additional right-of-way. The drilling permit is often issued or applied for 18 months before the well spud. If anything changes, whether it is a cementing program, casing program, or even a fairly immaterial change, you need a sundry notice and need approval. While a project is underway, you're still securing right-of-way, which involves federal permit approval, even to the extent of laying water lines on the surface for your frac job. If you cross federal lands, it requires federal approval. So when they suspended all local decision-making authority on permitting, we were in a fortuitous position. We were still in the middle of a project; we were about ready to mobilize rigs in New Mexico. On the heels of that Keystone XL decision, we decided not to put $100 million of pipe in the ground until this situation clarified. Since then, I think it has clarified. As I said in my remarks, we're very confident that existing permits on existing leases will be allowed to be developed. It was an extraordinary opportunity for us to pivot to Texas while we figured this out. So yes, we overreacted, and I view that as a positive.

Well, it's great to have the flexibility towards Texas. Thanks, Tom, for clarifying that. Appreciate it.

Hi, good morning, everyone. Thanks for taking our calls or questions. Our first question is on the oil trajectory, and our follow-up is more on medium-term growth. Given the timing of completions for the fourth quarter of 2020 plus the freeze-off in Q1 2021, it looks like your oil guide implies quarter-over-quarter increases from Q2 onwards. So I guess first question is do you have any color on the fourth quarter to fourth quarter for the exit rate growth for this year?

Hi, Jeanine. Yes, we do expect second, third, and fourth quarter sequential growth, leaning a little bit more towards the third and fourth quarters. The fourth quarter 2020 to fourth quarter 2021 rate of growth is targeting 30%. So we do expect a significant year-over-year change in fourth quarter to fourth quarter growth in oil, but again, it's a fairly steady growth, tending to dip more towards the third and fourth quarter.

Okay, great. And then my follow-up is when we do the math on a higher exit rate, it looks like you could be implying double-digit year-over-year oil growth in 2022. If you just held flat at that exit rate because it is so much higher. Is this a reasonable scenario? I know there's some variability on the year-to-year growth. But the overall medium-term outlook is for low single-digit growth. So just wanted to maybe get some clarity on that because it could imply pretty good capitalization save for 2022, given how strong you're entering the year.

Yes, certainly with that trajectory we're carrying into this year—in terms of activity levels—we are resuming to levels more consistent with what we saw in 2020. But in 2021, going into 2022, with that particular exit rate we see in the fourth quarter, we don't expect that we will ultimately have to maintain that fourth-quarter rate. We will be evaluating our 2022 plans and assessing where we invest and the pace of investment, but we don't have a targeted growth rate in 2022.

Jeanine, this is Tom. Let me just comment on that. Our challenge is that 2020 saw such a huge disruption not only in our capital program but also our production. It’s hard to look at quarter-to-quarter and make any kind of inference that that would be a steady state number. We are filled with very good projects. And I want to reiterate what I said in my opening remarks. Our long-term goal is really driven by cash flow generation and not production increase. But when you come off a year like we had in 2020, and we have the kind of projects we have, it’s like asking a thoroughbred to pull a milk truck. We have tremendous assets, and that’s just the way the numbers fell out. Given that we're investing less than half our cash flow this year, it provides us tremendous flexibility, and we can react to the marketplace as the year goes on. So when I see that Q4 to Q4 accelerated change, I think we have unbelievable flexibility, both financial and operational for 2022.

Thank you, Tom. I wonder if I could just ask you for a little help on your comments around your confidence that existing leases and permits will be allowed to be developed. I know you talked in your prepared remarks. But I just wonder if you could offer some color on what you're seeing, what you're hearing, and what discussions you've had that lead to that conclusion. Then I have a follow-up.

Well, I don't know if I can offer you any inside information that's not already widely known. We have had lots of discussions with elected officials at the federal level from New Mexico, both senators' offices, and in addition to the governor's office, and we are confident that cooler heads will prevail, and that the tremendous, not just value, but lifeline that the oil and gas industry provides to New Mexico will be kept alive and well. We do expect a new regulatory environment; we expect many of the Obama-era regulations from the federal level to return and be strengthened. And for that, we are ready. We are a better company in every respect, including environmentally, than we were four or five years ago. But every indication we have been given, and again, I don’t claim to be the expert on this, has led us to be optimistic that we will be able to develop our assets in a prudent manner.

Great. I appreciate the answer. Tom, I wonder if I could just - my follow-up is really on the capital allocation, Shale 3.0 moderate and growth type story. I mean, obviously, at your scale, 80,000 barrels a day give or take, 5% growth doesn't really move the needle on a macro level. And your free cash flow yield, in our numbers at least, is getting well into the mid-teens. You've got a ton of options just to decide what to do with that cash, and your balance sheet is in great shape. So I wonder if you can walk us through how well you are in that discussion, over whether you can grow, return the cash on a variable dividend; that has been touched on already, but your debt is already kind of in a good place. I'm just thinking about how it's a nice problem to have, but what are you doing next, assuming this super cycle, as you see, does play out?

Well, it's tough to say how we approach uncertain futures when the topic of discussion for the past 18 months has been like it is. Doug, we’ve paid a dividend since 2006, so culturally, I think the idea of returning cash to our owners is not that difficult for our board to consider. However, we and Mark said it well at the outset, we have made a tactical decision that we would like to have sufficient cash on our balance sheet to call those notes due in 2024. You could argue that this is too conservative, and we ought to return cash in some other fashion, but it certainly looks like we are going to go well beyond that goal of matching that cash required to call those notes. Yes, it does. But we were remarking before the call this morning how optimistic we were about 2021 one year ago today. So reality has a way of intervening. And right now, we would like to just get that cash on our balance sheet, and maintain that defensive posture, which will give us the flexibility to call those notes. And then and only then, do we have something to talk about as far as other avenues of returning cash to shareholders. We are deeply committed to it, and there’s not a blink of an eye in the boardroom when we talk about this. We are also watching some of our peers—there have been some creative strategies out there. We respect those approaches very much, and we’re really interested to see what others do. We do not necessarily want to volunteer as the first heroes in this campaign. So we’re very willing to look at best practices in the marketplace. Mark, do you wish to comment further?

Yes, I think your last point is valid, Tom. I think it will be interesting to see how the market starts valuing some of the variable dividends. And obviously, you want to provide visibility on that, the mechanics of it, and see how others do that. Evaluating the best avenue to do that will be important. And having the cash on our balance sheet for those notes gives us some time to consider these options.

Well, Tom, you've led the market in this, just a comment really, my hope is that the market, my competitors and observers generally start to recognize the free cash flow visibility you and the industry are now generating as appropriate cases for evaluations. I appreciate everything you are doing for us. Thank you for taking my questions.

Thank you. Good morning. I wanted to further follow up on Jeanine's question regarding the implications of the production trajectory as it relates to the end of this year and into next year. Transitioning from mid-60s type production to what could be 80 to 90 plus in the second half of the year is pretty significant. It seems like you raise the possibility of trying to stabilize next year's production at a more materially higher level than this year's. I wondered if you could talk more about maintenance capital and how you expect it to evolve if a new range of production is more like 80 to 90 compared to the $650 million to $750 million of CapEx for this year.

Yes, Brian, maintenance capital is certainly a popular topic with various discussions around it, and it depends on what one defines it as. If we think of maintenance capital of somewhere around 80,000 barrel oil per day, generally speaking, that number corresponds with the lower end of our guidance range, likely something less than $650 million to simply maintain that rate.

Do you think the low end of this year's guidance would be able to stabilize at 84 in 2022?

Yes, that's right, Brian.

Got it. Great. And then my follow-up is just a quick one on the use of cash, because I think that's been discussed here. You did spend some capital to buy back preferred shares. I just wondered if you could talk about whether that's a needed further use of cash to close that out prior to considering returning cash to shareholders more incrementally than what you're doing with the dividend.

Yes, the preferred is 8.125%. As we have opportunities to purchase that stock, we'd like to proceed just on our capital structure, as it is relatively expensive. The window for that transaction is uncertain; it'll depend a lot on interest rates and other factors to identify our opportunities to purchase more.

Yes, good morning, everybody. Mark, you brought up an interesting point with Brian's question, in terms of maintenance CapEx, albeit sort of the low end of the range to call it maintaining production flat in that 80,000 BOE per day range. This year; though, you didn't hold your reserves flat. I look at reserve additions relative to production last year, I should say. Is that a consideration when you're thinking about maintenance capital as you go forward? Or how do you think about your reserves relative to maintenance CapEx?

Yes, Mike, certainly, with the significant drop in our capital in 2020—down 56%—we did see a 14% decrease in our reserves. As we look at the current year plan and a maintenance plan, we would view those reserve additions to be somewhat parallel or flat with a plan to be in maintenance mode; pursuing review of our reserves should be relatively flat this year. We expect that the kind of current plan in place will see growth in approved reserves. Again, more respecting the activity levels with a couple of frac crews and five rigs in the Permian to observe our reserves grow this year. In a flat world, we would anticipate our reserves would maintain flat.

We have not discussed any purchasing of carbon credits, and we are focused on the engineering aspects of our own assets. While I wouldn't entirely rule out the possibility of some offsets in the future, I cannot see this being a priority for the next few years. We have tremendous opportunity to make material progress through the aforementioned electrification, along with addressing high- and low-pressure emissions. Our best minds are committed to this project, and I am confident we will make substantial progress. So, to answer your question, no, we have not discussed offsets.

Hey, guys, just looking at your 2021 CapEx budget fairly decent range there of $650 million to $750 million. One of that is, let's just call it 10% or so range between the top and bottom; can you just give us a little color around what's dictating the top and bottom of the range? Is this budget potentially allowing for slightly higher activity at the end of 2021 to get a little bit of a head start on 2022, or is there a significant service cost component? There might be a lot of uncertainty there; what can you tell us about the range?

Yes, let me start, then hand it over to Mark. We keep a fairly wide range because there is quite a bit of elasticity with things we want to do this year. We have some really good opportunities to make some modifications that can reduce our emissions; this will involve some capital. As we reenergize our New Mexico program, we're uncertain on the level of partner participation we may have on certain projects. We do have projects with some lower working interest compared to Texas, so we want to give ourselves some flexibility. Mark, do you want to provide a further explanation?

Yes, Tom, I think you covered a couple of key points. We do have variability there. One additional point, Leo, is that at the midpoint of our guidance, we incorporate our current status of where our authorized fund expenditures (AFEs) are at. We have incorporated some initial—early time data for some increases for later, with hauling and other components. We have some room in our budgets as we see additional inflation; we will also maintain our current range. So really it's a combination of working interest components, potential inflation, and the ESG-related work that contributes to the upper end of the range.

Got it, okay, so it sounds like you're not really planning on changing the activity that you've laid out in the plan for 2021, you're keeping that steady. And then obviously these other variables will dictate kind of where you fall. Just wanted to confirm you're not looking at increasing activity significantly.

That's right, Leo, that’s right.

That's helpful. And I just wanted to follow up a little bit on the dividends question. Obviously, you guys have talked about this a few times already here. But to see a very healthy increase this year at 23% is quite significant. But to start the year, it sounds like you'll have those bonds paid off; I think we plan to call them sometime in early 2022. I know the board will still have to have come together and make decisions about things. But is it fair to say that the preference today would be to have a strongly growing long-term dividend as a foundation for Cimarex over the next several years?

Yes, Leo, let me clarify; we do expect sufficient cash at $55 oil with the current strip to cover those. But those notes aren't callable until the first quarter of 2024. So, we will evaluate our options to chip away at those in the meantime. As to the dividend increase, we want to maintain a pattern of increases, which we've had throughout our history. We want to ensure it's sustainable, and that's how we depicted it in slide five, even at $35 oil; that dividend only represents 12% of our cash flow. At the current strip, it only represents about 7%. In that range—which is around 10% of our cash—we will feel very comfortable that the dividend is sustainable.

Okay, great, very helpful. Thank you.

Let me add that we love our regular dividend, but as Mark aptly stated, we want to ensure it’s sustainable. The beauty of a variable dividend is in its very name—it’s variable. We’ve stated our interest in finding a sustainable dividend philosophy, as the combination of regular and variable is intriguing to us. We're delighted to have increased our dividend, and we felt it was the right time to do a significant increase to reaffirm our commitment to our owners.

Good morning, thanks for taking the questions. Following up on Blake's comments on your electric grid completion and electric rig experiences, any sense for the magnitude of efficiency or cost benefits if those become more widespread? What's the size of the opportunity pie there, both on the subset of projects those could eventually be used on? And what’s the potential magnitude of cost and efficiency savings?

Sure. A lot of this depends on service rates moving forward, which we're all watching closely. However, I think we've gathered enough data to estimate that we are probably pursuing $25 to $50 savings per foot on our cost structure, which is significant. Additionally, we have fuel savings on the operating expense side when we examine compression. Moreover, we see some horsepower efficiencies on top of that. So on the capital side, we're looking at $25 to $50 at today’s prices, and we will see as we gather data regarding our operating expenses as well.

Great, that's helpful. And then maybe for Tom or Mark on the free cash flow scenarios presented on slide five, have there been any changes in how you're thinking about your hedging program regarding either commodity front, as you're building cash for the 2024 notes, and any potential shareholder returns beyond that?

Brian, we've maintained a steady, methodical hedging program over the past several years. In 2020, it proved to our benefit as we layered in hedges through that period for 2021; we've added some cash payments. That's a natural part of a hedging program as you hedge through the cycle. Our approach continues to be methodical, and we avoid speculative timing—our goal is to sample at periodic intervals each quarter.

Good morning. If you could talk a little bit about where the strip is for oil and gas and the economics in your various Oklahoma projects? Also, what kind of working interest do you think you'll be looking at for this year's activity?

We're currently developing our Lone Rock project in Anadarko, where we're drilling five wells. We model that it currently offers very attractive returns compared to a number of our premium projects, which is why we're making this investment right now. However, we need to observe the results firsthand to confirm that our projections hold true. We anticipate that with five wells per section, we will achieve performance that aligns with these financial expectations. If we see the anticipated results, we may pursue additional capital investments. Regarding our working interest there, it's quite high; we show about 94%.

Oh, wow. That's considerably above where it's been for some of your activity, right?

Yes, over the last year, we've been able to accumulate more interest in that area. It’s a strategic area we favor, and we expect great returns. But again, the proof will be in this particular development and the results we see.

Great, and just for my follow-up, do you have any thoughts on NGL pricing and what you think that might look like at the wellhead and also your marketing as the years progress?

With our NGL component of our realization in the fourth quarter, we were at 33% of WTI, and we’ve seen higher propane prices contributing positively. The propane inventories are solid, and we will see as exports trend here going forward, but inventory levels appear reasonable. We’re optimistic about NGLs, though we’re not directly marketing them; our NGLs are predominantly processed at our plants.

I want to emphasize that the 2020 challenges, including the weather events we faced, have reaffirmed why we have strategically aimed to maintain a multi-basin, multi-commodity company structure. Our marketing group showed remarkable resilience in 2020 when markets were under pressure. Having a diverse asset base has proven invaluable during recent events. John and his team have successfully brought forth some excellent investment opportunities in the Anadarko Basin, ranking at the very top of our list for returns, aligning with our strategic management of the company.

Good morning. Regarding your new well design on slide 9, does that essentially eliminate any interference between the x, y, and z compared to previous designs? Could you discuss some potential upside and what you're anticipating?

Yes, that's right. The slide refers to our development projects, such as in Culberson, where we've adjusted well-spacing or reduced the total count while maintaining landings. This arises from learning lessons through multiple developments. There was greater communication, or permeability, than we initially expected. We’re adjusting to save costs on three fewer wells while striving for the same total recoverable reserves, allowing for greater capital efficiency and better overall project returns. This applies to multiple projects including those in Reeves, Lee, and Lone Rock where we've experienced better economics with fewer wells per section.

The spacing is going to vary across our asset base. For instance, in Culberson, the map on slide 9 shows a range of six to eight wells per section on the western side and eight to ten wells per section on the eastern side. It’s crucial, as John pointed out, that we maximize the value of that section. We have a significant inventory and can make these decisions without the concern of oversaturation in our inventory, providing us with tremendous financial flexibility.

I have one more follow-up on completions. You mentioned potentially doing a couple of frac jobs for the majority of the year. Is this still viewed as an optimal completion strategy? Given the reduced activity, are you losing any optionality?

Blake, go ahead.

Yes, we continuously evaluate efficiencies and appropriate scales. Some completion processes involve thermal fracking, limiting our flexibility in specific cases. Ultimately, being prepared for each project is the prime driver for efficiency, and we focus on maximizing that every chance we get.

Thank you. Good morning. I have to apologize for my first question because I think people have been asking about this already. When I look at your fourth-quarter exit rate showing a 30% growth that's about 88,000 barrels a day, even if we assume that it stays flat for the next three years to 2024, that's about 4% growth. When I examine your presentation on page 6, you indicate that oil volumes are expected to be flat to slightly up year-over-year from 2021 to 2024. Is that statement still correct? Is that the intention of keeping production flat for the next several years? Or is this based on the assumption that commodity prices will potentially be less robust than what we are seeing today? I'm trying to understand what conditions underpin this statement.

Yes, Paul. Our slide 6 aimed to depict potential free cash flow frameworks at lower price points. We were outlining a scenario of $35 oil, and at that level, we would typically adopt a conservative capital reinvestment approach and prioritize debt retirement, leading to flat volumes at $35 WTI. However, even at this level, we gauge maintaining production levels and would have enough cash flow to address our 2024 notes. That describes our strategy.

Slide 6 reflects our steady state aims. Given the substantial disruption experienced in 2020, it's tough to manage growth targets or maintain steady production. Any minor investments—especially with our solid project lineup—will likely keep production rates strong as we head into 2021.

Okay, last question for me on the CapEx trajectory. The amount of wells you have coming on stream is significantly less in the first quarter compared to the rest of the year. Should we assume that it's going to follow a similar pattern going forward, or will the increases be more steady?

For CapEx, we’ll maintain a slightly higher level in the second and third quarters. However, relative to our overall plans, it should remain fairly steady. We do anticipate some completion capital will trend higher in those quarters.

Thank you. I just want to thank everybody that joined us this morning. We're very optimistic about 2021. We appreciate your great questions. I think we are pretty pleased with the shape Cimarex is in. I want to reiterate that we're a much better company entering 2021 than we've been and that’s a testament to the challenges we faced and the organizational response. I hope you’re all doing well, and again, thank you for your interest and excellent questions this morning. Thank you.