HighPeak Energy, Inc. Q4 FY2021 Earnings Call

Thank you for standing by, and welcome to the HighPeak Energy’s Fourth Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. Please be advised that today’s call is being recorded. I would now like to hand the call over to Steven Tholen, Chief Financial Officer. Please go ahead.

Thank you. Good morning, everyone, and welcome to HighPeak Energy’s fourth quarter 2021 conference call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; Vice President of Business Development, Ryan Hightower; and I’m Steven Tholen, the Chief Financial Officer. During today’s call, we will make reference to our March Investor Presentation, our fourth quarter 2021 earnings release, and our 2021 Form 10-K, all of which can be found on HighPeak’s website. Today’s call participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. So please refer to the cautionary information regarding forward-looking statements and related risks in the company’s SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control. We will also refer to certain non-GAAP financial measures on today’s call. So please see the reconciliations in the earnings release, which was issued yesterday afternoon. Our prepared remarks will begin on Slide 4 of our March Investor Presentation. I will now turn the call over to our Chairman and Chief Executive Officer, Jack Hightower.

Thank you, Steven, and good morning, everyone, and welcome to today’s call. As you probably realize, every CEO is always excited to talk about their company and the performance of the company. I’m more of a macro person in terms of annualized performance. But this is a great exciting time with HighPeak and with oil and gas prices in the world, unfortunately, some of which is contributing to the Ukraine crisis. But we had a great fourth quarter. Our average production averaged over 14,900 barrels a day, which was an 81% increase compared with our third quarter average. We successfully executed our drilling program and averaged almost three rigs throughout the quarter. We had a large number of wells that are in the process of being completed, and most of these wells will come online and be completed, contributing to our production towards the end of this year. The majority of the wells are anticipated to ramp-up and be reaching peak rates towards the end of the year again. We added our fourth rig in January and are now very active with four rigs running in the market. We continue to evaluate adding to our rig count if commodity prices remain strong. And so we are contemplating adding to our drilling activity. And with our cash flow as we go through the numbers, you can see we could do so without increasing our outspend. HighPeak is a growth story, and we’re going to take advantage of the current market strength in oil and gas to create additional value for our shareholders. So I’d like everyone to point to Slide 4 of our March Investor Presentation. This gives you an overview and key statistics for the company. I previously mentioned that our average production was 14,900 barrels a day, consisting of 95% liquids. This contributes tremendously to our economic success. We continue to realize peer-leading prices and cash operating margins. And on a BOE basis, our fourth quarter unhedged cash margin was $60.26 per barrel of oil equivalent, approximately 84% of our fourth quarter realized pricing. Also, in the first quarter of 2022, we entered into a series of acquisitions, which in the aggregate include 9,500 acres and almost 2,500 barrels a day of production, along with an additional 40 locations with a saltwater disposal system, including three disposal wells and rights to the local non-potable water sourcing of approximately 35,000 barrels a day. These acquisitions also contribute to about $3 million per year in savings on water. The acquisitions closing in the first quarter represented a 15% increase to our flat top acreage position. If you think about it, in 2021, we had about 51,000 acres, and today, with the closing of that transaction, we will have almost 72,000 acres, resulting in a little over a year a 40% increase for HighPeak, increasing our scale and providing additional locations to our inventory. The acquisitions check all the boxes; they’re immediately available for development and the related gathering infrastructure is already in place. We paid less than a three times multiple on cash flow and are projected to increase our EBITDAX in 2022 to over $50 million, based on present pricing, but $50 million assuming commodity prices stay in the range of $70 to $90 a barrel. The assets are contiguous to our flat top operating area and provide many synergies, including adding to our robust infrastructure system. The acreage is 100% operated and will be easy to integrate into our development plan. The 40 locations carry $15 million to $20 million of net present value and, of course, it’s challenging to predict pricing right now because prices are so high compared to the numbers we’ve utilized. But they add potential upside value to HighPeak in addition to the current PDP value. In other words, we will be actively developing that area, and each well with an approximate $20 million net present value can add significantly to our value. If you’ll turn to Page 5, or Slide 5, I’m only going to pick out a few things in this particular slide. We still have the highest oil cut among our peers in the basin. Our income stream was 88% oil and 95% liquids. Our realized price was $72.07 on a BOE basis, which was 93% of the weighted average of NYMEX oil price during the quarter. This is due to our high percentage of oil. Our hedge price was $67.50, still a great price compared to many of our peers that are experiencing significant write-downs because of their hedges. We lowered our LOE by $0.60 a barrel in the third quarter compared to the prior quarter. But I look at what’s happening in the future. Mike is going to discuss operationally what’s happening with our lease operating expenses. But they will continue decreasing once the substation and other projects become operable. Our EBITDAX was $72.4 million, which represents a 117% increase, but that was at a very low oil price of $72. Think about what it would be today on an unhedged basis; that gives you a sense of what’s happening in the future and how excited we are about our future plans. If you’ll turn to Slide 6, our track record of delivering capital-efficient growth will continue into the future. You look at 2020 from a 1,900 barrels a day, all the way up to almost 15,000 barrels, and then take our guidance for this year of averaging on the low end 27,000 barrels to 32,500 barrels with the four rigs drilling and going all the way up to around 45,000 barrels. That’s tremendous growth. If you look at our EBITDAX as a function of increasing production, and we’ll talk about drilling performance in terms of single well performance payout and reserves. But if you think about it, this was based on roughly $70 to $90 oil at $600 million to $800 million average for 2022, exiting the year at between $850 million and $1.1 billion at a higher oil price around $110 a barrel, that takes us up to $1.04 billion to $1.06 billion in 2022. You can see what oil and gas prices are doing for HighPeak in terms of cash flow. And now if you turn to Slide 7, HighPeak is continuing to provide rapid proved developed reserves growth. I’ve mentioned many times, and will repeat today, we are a growth company. If you look at our growth from 2020, going from $51 million to $400 million to $744 million, exiting this year at over $815 million in proved developed reserves and another added up to $1.498 billion counting our proved reserves; that's at a low price deck. It's much higher than that at today’s prices just a month or so after the end of the year. Our rapid growth will have significant implications as we move towards the end of 2022. We did some numbers at a price deck of $110 a barrel, almost $19 a barrel more expensive than what we projected, taking us up to $3.8 billion of proved reserves in just this 12-month period, not counting what will be in process of being completed at year-end. We are experiencing rapid growth and are very excited about what’s taking place. We will be drilling over 100 wells this year. And as you can see, we have tremendous success. With that, I’ll turn the presentation over to Mike, who will talk about the next few slides and give you an update on operations.

Thanks, Jack. I’d like to start by saying that our hearts, minds, and prayers are with each and every person in Ukraine. Their perseverance, strength, and sheer determination are all inspiring. HighPeak will absolutely do our part to provide the world with clean, cheap, and reliable energy. We do not and should not have to be asked to do the right thing; that’s just embedded in our DNA. We are fortunate to have the acreage position, the rock quality, and a fortress balance sheet that will allow us to respond and lean in during this time. With a heavy heart that we can’t do more, I’m very proud that HighPeak and our employees are doing what we can to reduce our nation’s need for foreign energy. Now turning to Slide 8. Midland Basin benchmarking. Well results illustrated on Slide 8 show how consistent our well performance has been to date. The red curve shows our Midland Basin peer average. The yellow dotted curve shows how our flat top average wells compare. Our wells demonstrate less steep decline, which leads to outperformance in later months. Our low cost structure and strong well performance drive peer-leading economics and efficiencies. The blue dotted line shows our Signal Peak average. The results in Signal Peak, although very early and include many vintage wells, strongly compete for capital not just in our portfolio but in anyone’s portfolio. Turning now to Slide 9. Flat Top single well economics. Slide 9 details our single well economics based on the blended average type curves from our year-end 2021 reserve report for 12,500-foot laterals in lower Spraberry and Wolfcamp A formations. Since we’re focusing on co-developing these zones in flat top, we feel this is a great way to display our average single well economics. Our wells achieve payout quickly and provide very high net present values as shown in the chart. They deliver tremendous rates of return in today’s commodity price environment, and remain extremely economic at low prices. At $80 oil, they have a recycled ratio of 5.7, which is phenomenal. The average well in flat top has a blended break-even of only $28 a barrel. We get asked a lot about inflationary pressures; they are real, and we have accounted for them. We're carrying roughly 10% more CapEx in our budget for 2022 compared to what we achieved in the fourth quarter of 2021. The graph also shows payout sensitivities compared with capital cost. At any reasonable oil price, our wells have a fantastic rate of return and recover our investment in a short period of time. We show the effects of a $0.5 million increase per well on the payout period from first production, and our strong well economics are resilient against inflationary costs, with payout timing not affected significantly at any price shown. If you’ll turn now to Slide 10, 2021 margins. Again, the slide shows margins for the full year of 2021, which were driven by our low-cost, high oil cuts, and great realized pricing, which were peer-leading on both a hedged and unhedged basis. Our margins were approximately 27% higher than our closest peer on an unhedged basis and 45% higher than our closest peer on a hedged basis. But remember, we’ve positioned ourselves for continued margin growth with our LOE reduction initiatives, which will further distinguish us from our peers. For example, we’re increasing recycling, our Horizontal Ellenburger SWDs, full field electrification, and energizing our solar farm. I should also note we are extremely lean, and we’ll continue to be that way. As our production grows, so too will our G&A per barrel, which further enhances our margins. If you’ll turn now to Slide 11, operational update at flat top. We’re currently in full manufacturing mode, co-developing the Wolfcamp A and lower Spraberry. In Signal Peak, we have two new 15,000-foot Wolfcamp B wells that are about to come online in the eastern one-third of our block. That’s a 30,000 lateral foot test. We also have a 10,000-foot Wolfcamp D well on the far east of our acreage. We’re encouraged by the early flowback of our recent Wolfcamp A and lower Spraberry wells; it’s very early days, but results are extremely encouraging and following our type curves. We are also drilling or in the process of drilling two additional 15,000-foot Wolfcamp D wells in the southern part of our block. In addition to our operated wells, we’ve recently participated in three gross non-operated Wolfcamp Ds on the western side of our acreage position, as well as we are currently participating in the drilling of four additional gross non-op Wolfcamp D wells. With that said, we’ll have full insight into the delineation of our Wolfcamp D zone across our entire block in the coming quarters. If you’ll turn now to Slide 12, ESG and sustainability highlights. In the fourth quarter, we recycled 58% of our stimulation fluid company-wide. As Jack mentioned, we now have access through the recent acquisitions to 35,000 barrels a day of non-potable water. So in addition to reducing our need for fresh water makeup, we stand to save roughly $3 million a year in capital costs. We can now supply 100% of the stimulation fluid needs for one frack crew in flat top with recycling non-potable fluid. The HighPeak substation is fully constructed and set for a second-quarter commissioning date, eliminating the need for multiple local generators and the costs and emissions associated with them. Our solar farm is on schedule to be completed this summer. The oil pipeline construction began, and our gas infrastructure upgrade is in process. Phase one is operational today, and we have completed these developments, which will result in reductions in trucking and emissions. Additionally, deliveries from our local sand mine will commence in the third quarter, ensuring sand availability and efficient completion operations while reducing trucking emissions. We are also proud to report that we have had zero employee safety incidents to date. With my comments now complete, I’ll turn the call back over to Jack.

Thanks, Mike. If you look on Slide 13, this gives you an overview of our budget increased up to $800 million. We show our production range in terms of guidance for this year, and this has been a year of growth. We revised our capital guidance, as mentioned. The graph on the right shows that our 2022 average production at the midpoint is 220% higher compared to our 2021 average. Our 2022 exit production rate at the midpoint is 350% higher than our 2021 levels. This signifies unparalleled organic growth into 2023. Keeping in mind that we are not going to get ahead of ourselves. I want to emphasize that we have a pristine balance sheet. Our overspend has been almost completely absorbed with where oil and gas prices are today. This growth profile will continue as we advance throughout the year. If you turn your attention to the next page on liquidity and financial overview, it shows our financial position at year-end. It outlines that subsequent to year-end, we closed our $225 million senior unsecured notes. We utilized those dollars to pay off our RBL in full, and we still have $225 million in liquidity between our cash position and undrawn RBL. We expect in April we will have a redetermination period, and we already know that we can increase our RBL significantly. We haven’t specifically outlined exactly what we’re going to apply for, but we’re not going to have any problems relative to liquidity or having access to the necessary capital. We have maintained a low leverage position at 0.2 times net debt to annualized fourth quarter EBITDAX. This shows how little leverage we currently have compared to the value of our PDP and proved reserves. If you look at the box in the lower right-hand corner, it provides an overview of what our coverage looks like relative to our debts. As you can see, we have tremendous coverage relative to our total debt and net debt. I want to emphasize that we will always maintain a debt to EBITDAX ratio of less than one time leverage. We’ve been able to do this effectively and responsibly as we go forward. And if you’ll turn to Slide 15, it continues our responsible growth story. We will continue pursuing efficient production growth while maintaining a very low debt level. We’ve increased our liquidity position as mentioned. Our focus will remain on capital and operational efficiency, especially in light of current industry-wide inflationary pressures. As Mike mentioned earlier, we’ve implemented many strategies to eliminate these inflationary pressures by securing materials in advance and planning for all of our LOE savings. We have one of the most attractive product mixes in the industry, leading to higher oil and liquids production strength, great realized prices for our products, and a low-cost structure that will continue to drive our peer-leading margins for HighPeak. I want to close by emphasizing that prior to the Ukrainian crisis, we recognized the massive underinvestment in energy over the past several years. Many banks were coming out with forward projections, many stating that prices were going to decrease. Contrary to industry sentiment, we forged ahead and positioned ourselves for responsible growth. HighPeak is uniquely poised to take advantage of current market conditions, excellent well economics and performance, operational expertise, and a strong balance sheet. We are contemplating accelerating our drilling activity this year, which at today’s prices, we could accomplish without increasing our near-term outspend. In fact, we would have no outspend at current prices if they stay close to this range. I want to emphasize that we are a growth company. We will take advantage of all available opportunities. With our quick payouts on our wells and high rates of return, we will continue to lean in to increase our drilling activity and ensure that our shareholders receive the returns they expect to see going forward. Now, we’ll turn the call to questions.

Our first question comes from John White of ROTH Capital Partners. Your line is open.

Good morning, gentlemen, and congratulations on a very impressive quarter.

Thank you.

Thanks, John.

If you could, I’d like to get the breakout on fourth quarter completed wells in flat top and Signal Peak, if you have that handy, or you have some ballpark numbers?

Yeah. John, this is Mike Hollis. Basically, we’ve had six wells that were completed and came online in the fourth quarter. Again, kind of the third quarter going into the fourth is when we really began our ramp-up, we went from one rig virtually up to three rigs and picked up the fourth in January. So again, we brought these rigs in and drilled large multi-well pads. As we mentioned in our press release, we’ve got 27 wells in the first quarter that will be turned online, most of which will be in the latter portion of the first quarter. So what you saw in the fourth quarter were the six wells that we had coming online, as well as a large battery of wells in the center part of flat top that came on earlier, kind of late in Q1 into Q2, that really started to perform into the fourth quarter, driving that performance. Again, you saw a bit of lumpiness from the second to third quarters; you’ll see a little more of that going into the early part of 2022 as we bring on these 27 wells. The blended data that we showed in the presentation of our average flat top wells drives net present value dramatically, as well as rate of return. So again, we’re very excited about what’s coming. We feel very confident in our guidance for 2022. However, you did not see all of the wells that were drilled and completed in the fourth quarter. You’re going to see all of those coming on towards the latter half of 2022 and into the first quarter of 2022. So hopefully, that provides a bit of clarity. But yes, six wells and those six wells compared to the 27 coming on in the future. From a go-forward standpoint, think about an average of eight wells per month coming online that are being drilled and completed. And again, it’ll smooth out more as we move into 2022 and 2023; it will be closer to that eight. Again, as we conduct pad drilling, you may have 10 in one month, or eight or six the next month. But in general, eight each month. In Signal Peak, we have completed two of the 15,000-foot wells. If you look back in the fourth quarter, we finished fracking the two Wolfcamp A in the lower Spraberry well. We’ve had them online for roughly a week and a half. We’re very encouraged with those results. The two 15,000-foot wells, we’ve now fracked those and will begin drilling operations to continue completing wells in Signal Peak on a ratable basis. Again, approximately 25/75 split of our CapEx spend for 2022 between Signal Peak and flat top. Apologies for the long-winded response, but hopefully that provides good context.

Okay. Yeah, thanks for all the detail. 27 wells, that’s a lot of wells to complete. So, for 2022, the drilling plans are about 75% flat top 25% Signal Peak, is that right?

That is correct, yes. All right. Thank you.

Thank you. Our next question comes from Nicholas Pope of Seaport Research. Your line is open.

Good morning, guys.

Good morning.

Good morning.

I was hoping you could talk a little bit more on the Signal Peak area as you delineate that acreage. You laid out the map here of what wells we’re going to be looking at in the near-term and over 2022. But I’m curious what data you are going to get from this first set of wells? And I guess maybe what’s missing with the data at this point that was fairly early stage and what the focus is going to be as you start to see these wells come on? And what we should think about that set of wells and what it means for your inventory?

Yeah, Nick, overall, from a big picture perspective, we’re looking at a lot of development from the western part of our acreage, offsetting operators that have drilled four wells, and now we’re participating with them in four more wells. We’re moving from west to east from a depositional perspective coming off the shelf edge to the east. From a geological perspective, we have enough well control to know that the zone is present. We are aware of the thickness of the zone. We want to delineate the area, ensuring that from the eastern part all the way to the western part, we will meet the performance expectations we have regarding the thickness of the reservoir and the necessary technology for completion. Mike can speak more specifically about the data we’re gathering in each area in terms of drilling performance, and what we’re waiting to see, as well as why we are moving deliberately to ensure everything is sound.

You bet. Yeah, Nick in Signal Peak, the map that we’ve shown on Page 11 gives you an idea of what’s in progress today. So a lot more activity is going to take place at Signal Peak throughout the year. This initial phase is all about delineation, as Jack mentioned, moving from east to west. In the eastern third of the block, we’re conducting a 30,000-foot lateral test that’s almost done fracking today. In this area, we’re looking for economic evaluations. We know the rock is present, it produces oil and gas, and every indication suggests it will meet our expectations. Again, as a pragmatic engineer, I seek to see oil in the stock tank. We observe oil in the stock tank a mile and a half to the west that met all expectations. The rock here appears thicker and seems to be better, and we expect the same results. We’ll soon learn everything from west to east, and north to south, delineating the Wolfcamp D. The lower Spraberry, we have an offset well drilled by an adjacent operator. Everything there is progressing as we expected. A Wolfcamp A well has stepped out in the test, and it’s flowing back meeting the type curve at this early time. Thus far, everything is producing and operating as we anticipated. Jack mentioned there is significant scientific work taking place. We’re utilizing advanced completion technology and are very deliberate in our approach, expecting significant optimization in drilling performance, very much like we observed in flat top to distinctly differentiate ourselves from our peers in terms of drilling calls, completion specifics, and well results, thus driving better economics.

That is very thorough. I appreciate that. That’s very helpful. And then kind of changing topics here a bit. On the financial side, I’m curious about the outstanding warrants that are still out there. Is there a timeline for the warrants? Or are they indefinite? Is there anything that could happen leading to converting those to shares? Should I consider those as fully in the money and the potential dilution out there?

Good question, Nick. The warrants are continually being exercised as investors are looking for long-term capital gains, realizing our stock should continue to appreciate in value. We had another 40,000 shares exercised this past week. Eventually, the warrants will be exercised; they were originally for five years, so there are still well over three years left for the original investors to exercise the warrants, which should continue to be well into the money and increasing in value over the next year-and-a-half to two years.

Got it. Regarding the CDRs, at this price – stock price, they shouldn’t even come to the conversation, is that right? I’m trying to remember; it’s been a while since I focused on it.

Yeah, eventually, they come due in August. As long as the original investors realize a 20% gain at $12, and our stock remains at that level, they will have no effect and will expire. That should happen in August.

Got it. That’s all I had. I appreciate the time, guys. Thank you.

Thank you. Our next question comes from Jeff Robertson of Water Tower Research. Your line is open.

Thanks. Good morning. Jack, you talked about potentially adding a fifth rig, and I’m curious where you would take that rig and whether you would accelerate some of what you had talked about previously regarding Signal Peak? Secondly, if you add a rig, does it change anything you’ll need to do on your saltwater disposal or other infrastructure assets in flat top?

Good question, Jeff. When adding a fifth rig, many factors influence that decision-making process. Part of the process involves deciding where we’re going to place it, as we want to be very efficient with pad drilling regarding economics and costs. We have multiple opportunities available to us. We could position it on some of our new acreage acquisitions; it’s essentially development drilling on these 40 locations. We could also deploy it to Signal Peak, while maintaining about four rigs running up north and potentially having half a rig down at Signal Peak. We could even have enough locations identified to consider expanding to six rigs instead of five. However, we will spend the next three to four weeks analyzing this and probably make a decision around mid-March about expanding our operational drilling activity. Given the current pricing environment, with four to five-month payouts, we think it’s in the best interest of our shareholders to be proactive in our approach, which can happen almost anywhere. We have many locations, and all our activities will be focused on development drilling and increasing our cash flow.

Hey, Jeff, regarding the SWD question, absolutely not. Look, we’ve built a pipeline system, namely a 20-inch pipeline that surrounds the core of flat top, allowing us to move large volumes of water anywhere in the field. We can dispose of it efficiently in our high-volume deep Horizontal Ellenburger wells. So again, increasing activity or water production from the field presently will have zero effect. If we need to drill a future SWD a bit sooner, perhaps nine months out, that is likely, but it is driven by receiving unparalleled returns on drilling these wells from an oil perspective. The system was designed to allow for expansion. We discussed the earlier conference call regarding the split, as well as earlier questions about the 75% to 25% split on CapEx for the DC and East side. However, on the infrastructure side, it’s about a different split between flat top and Signal Peak. Once we receive delineation information from our wells, we’ve already prepared designs to implement an SWD system and recycling system in Signal Peak. You’ll see how we’re investing our infrastructure budget for 2022, enabling quick confirmation of sizing based on well performance and water cuts. We’re committed to ensuring a swift setup in Signal Peak like we did in flat top, and we aim for efficient operations to yield the highest returns for our shareholders.

Thanks. That was the next question on Signal Peak. Can you talk, Mike or Jack, about any offset activity on the southern end of your flat top acreage or the eastern flank of flat top that’s helping you delineate through what others are doing surrounding that side of your acreage position?

Yeah, I mean, Mike can elaborate on operational aspects.

You bet. Jeff, it’s fairly evident who the operator is to the south of us. Look, we’re all friendly here. We consistently share data on drilling, completion, and production with all of our offset operators, particularly the operators directly south of us. They’re fairly active, operating two rigs and a frack crew full-time; several wells are south of our acreage block, all the way to the east, and they’re performing very well. Many of these wells ID well above 1,000 barrels of oil a day. They have similar rock formations, comparable costs, and if we were operating there, those operators are exceedingly good. We're learning a lot from each other, and it's encouraging. They are also progressing more quickly; we’re more focused on co-developing our known zones of Wolfcamp A and lower Spraberry. They’ve completed additional delineation south of our flat top area, with several Wolfcamp B wells. They’ve got wells that have yielded approximately 600,000 barrels of oil with associated gas, which is highly economic at current prices and even when oil was at the $35 to $40 range. One exciting note is that some of the operators near us are exploring Wolfcamp Ds and dog tests. There’s a well right south that has been completed and is flowing back, which makes us very optimistic. I think it’s reasonable to expect that in 2022, we’ll be testing a Wolfcamp D on our southern acreage block. We appreciate the operators who are taking the lead, allowing us to capitalize on their insights.

Thank you.

Thank you. Our next question comes from John White of ROTH Capital Partners. Your line is open.

Yeah. Just wanted to follow-up on your acquisition in the fourth quarter, the 9,500 net acres. The press release described that as contiguous to flat top. I’m looking at Slide 4 of your acreage map; can you verbally walk us through where that acquired acreage is?

John, we intentionally didn’t disclose that on the map at this stage. We are acquiring additional acreage, and the area has become very competitive. From the northern side, as you mentioned, we discussed Borden and Howard from the northern side, all the way to the eastern side and also to the southeastern side of flat top. Until we are successful – or not with additional acquisitions or additional acreage, we’re not going to specify where it is. But when I say contiguous, it is contiguous either north, south, east, and west.

I like it, the undisclosed location. I appreciate the approach and fully understand your rationale.

Yeah, it’s a very competitive area. One of our peers has extended outward now six miles to the east in Mitchell County. We have substantial control and substantial information at play. The entire area has been in the same situation since we purchased our first 7,500 acres. If you recall the SM presentations, they began moving from the western part of Howard County to the eastern section, continuously delineating further east. We acquired our acreage with the confidence that this wouldn’t change; the trend would continue moving eastward. And that’s happening – indeed, it is happening. The wells to the south in both the B and D zones in the lower Spraberry and the Wolfcamp A zones have been performing well. The 15,000-foot laterals are all yielding over a million barrels, so the entire area looks promising, and we’re very excited about developments.

Great! We look forward to seeing more leases signed and look forward to your continued success. I’ll pass it on.

Thanks, John.

Thanks.

Thank you. At this time, I would like to turn the call back over to the CEO, Jack Hightower, for closing remarks. Sir?

In closing, I want to thank everyone for attending the call. I don’t have much more to add other than I am extremely excited about our performance. Our operational team is doing an exceptional job. I regret that we need to navigate these inflated oil prices; we genuinely believe they would have risen regardless. The industry, on a global scale, is not reinvesting enough capital. We face challenges, whether we encounter the Ukraine situation or not, and those challenges are on the horizon. If you analyze all the major company five-year plans, each major company, from sovereign wealth to the biggest operators, are falling short in reserve replacement. Historically, less than 20% of the projected reserves were replaced during the latter part of 2021. We have serious issues regarding our ability to supply the world and maintain our quality of life. Fossil fuels will remain a crucial element, and we are committed to providing as much as possible. Thank you for your time.

This concludes today’s conference call. Thank you for participating. You may now disconnect.