Good day, thank you for standing by. Welcome to the HighPeak Energy, Inc 2022 Fourth Quarter Earnings Conference Call. At this time, all participants are on a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during that session, you will need to press star one one on your phone. You will hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, the CFO, Steven Tholen. Mr. Tholen, please go ahead.
Thank you. Good morning, everyone, welcome to HighPeak Energy's Fourth Quarter 2022 Earnings Call. Representing HighPeak today, our Chairman and CEO, Jack Hightower, President Michael Hollis, Vice President of Business Development, Ryan Hightower, I am Steven Tholen, the Chief Financial Officer. During today's call, we will make reference to our March investor presentation and our fourth quarter 2022 earnings release, 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. 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 and our March investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.
Thanks, Steve, good morning, ladies and gentlemen, we wanna thank you for joining our call today. As we go forward and think about the last year, it's just amazing that we've had such a banner year. Also I wanna emphasize that everybody's aware that we have began our process for strategic alternatives, we'll talk a little bit about that today. I wanna just point out that we've posted great year-end 2022 results. Hopefully, you've had a chance to look at your press release, you can see that our expectations further substantiate our long-term strategic plan. As I look back on 2022, unquestionably, we've had a banner year. We increased our business in a really responsible and multi-pronged approach, both through the drill bit and through strategic accretive acquisitions.
That's how we maintain our peer-leading margins and actually increased our cash margins throughout last year as our operating teams continued to make large strides in reducing our lease operating expenses and total cash costs. This is tremendous improvements and continued improvements to be able to do this into the future. I'm really proud of our organization. We have a lean organization. Everybody continues to work hard. Their efforts towards cost reduction on both sides of the equation, maximizing capital efficiency, lowering operating expenses, and optimizing well performance, which we are actually one of the few teams in the Permian Basin that are actually improving on our well performance. The seamless asset integration, which allowed the company to accomplish these milestones in 2022. It was a challenging year due to many factors. We had serious inflationary pressures.
We had supply chain disruptions just like the rest of our peers did, but we navigated through these challenges and actually improved. We ended on a high note, and we fully expect this momentum to continue in 2023. We're gonna stay focused on optimizing shareholder value, optimizing our returns, and optimizing our accomplishments relative to our business. The first slide I wanna talk about is on Page four of the deck, and this is similar to our last slide that we talked about in our third quarter. Very similar, but I think the important thing is that our production averaged 37,300 bbl a day, which is a 42% increase over the third quarter. 150% increase compared to last year's fourth quarter. That is unprecedented growth. We still have lumpy production.
We go up one quarter, we maintain the next quarter. We're gonna continue having lumpy production. Don't multiply that 40% increase four quarters in a row. If you just think about we hit our guidance, we're gonna continue hitting our guidance throughout this year. We exited the year at close to 40,000 bbl a day, which was at the high end of our guidance. We also had somewhere between 1,000 and 2,000 bbl a day curtailed throughout the fourth quarter due to some midstream expansion projects. If it was not for that, we would have surpassed our high end on both our average and exit production guidance ranges. We increased our proved reserves 92% year-over-year to 123 million bbl of oil.
We continue to expand our acreage footprint, which is now over 112,000 acres, with line of sight for additional increases there. We're getting good contiguous add-ons as we expand our acreage blocks. We have two contiguous acreage blocks with high working interest. We're set up for long laterals. We've been averaging somewhere around 12,000-12,500 ft laterals. Our capital efficiency on our development program will allow us to hold our entire acreage position with one to 1.5 rigs. As you can see, we had several wells in progress at the end of the year, which will all come online during the first half of 2023. Presently, we have almost 57 wells that are in the process of drilling and completion.
That, wells that are already drilled and being in progress are gonna substantially add to our production as we go forward this year. We had several additional wells in progress that help us substantiate our confidence in achieving production guidance numbers. Very many of these are in other zones. As you can see, looking at financial statistics on this slide, we're projecting $1.525 billion exiting fourth quarter this year. This is utilizing $90 a bbl, which is a price basically that is being utilized by most of our peers into budgeting purposes for prices, even though we recognize prices are below that right now. Then we exit fourth quarter of 2024 with almost $2 billion in EBITDA. Great improvement as we go over. The next Slide five.
I'm gonna try to go through these fairly quickly to just hit the highlights on these slides. Slide five is a differentiated growth story that takes us from overspending to actually having free cash flow in this year's business. I've had people ask me, "When is that gonna take place?" The answer is, we just don't know because we don't have a crystal ball as to where oil prices are gonna be. If the analysts and our own internal projections are correct, we will start seeing free cash flow in the second half of next year. We are on course to reach that inflection point with material free cash flow generation. It's just a function of, is it this 90 days, the next 90 days? When is that gonna take place?
Our asset base has actually grown organically from zero to 40,000 bbl per day over the past two years. There's no way to prove high rock quality better than exhibiting substantial production volumes. By executing our plan, at the end of this year, we'll have an EBITDA run rate of over a $1.5 billion At a reasonable oil price. In addition, we will be positioned to continue increasing our production next year and with this reasonable growth rate similar to the rig cadence that we presently have. That gives us roughly $1 billion of free cash flow on a $90 price per bbl in next year's business. At that point in time, our free cash flow yield and investment rates will compete with anyone in our industry.
As you can see, I'm very excited about what's taking place in the company. I'm gonna turn the call over to Mike now to talk about our margins and provide you with an operational update. Mike?
Thanks, Jack. Turning to Slide six, margins. It sounds like a broken record, our BOEs are not the same as everyone else's. We continue to expand our margins differentially to our peer group. Our fourth quarter margin for BOE was 47% higher than our peer average. This theme will remain over the coming quarters as natural gas prices stay depressed. Don't forget that gas prices in the fourth quarter were higher than what we're seeing today. With our high oil mix, HighPeak's margins will expand even further compared to our peer group next quarter. On a relative value basis, our average peer would need to produce about 60,000 BOEs per day to achieve the same cash flow results that we do with 40,000 BOEs per day.
In today's market, a company that produces in line with 60,000 bbl a day is typically viewed much differently by Wall Street than one at 40. Size matters. I disagree with that thought process. The impetus should be on efficiently converting oil and gas into dollars and cents, and that is exactly what we focus on at HighPeak. Although we're very bullish on oil prices long term, in the short term, price volatility looks like it'll continue. We are very fortunate to produce such valuable barrels, which will help us remain financially strong even during periods of price volatility. In addition to our BOEs being very oil-rich and highly profitable, we continue to drive down our operating costs, which will further increase our per barrel cash flow. Cash cost. All-in cash cost per BOE continues to decrease.
We reduced our LOE 15% quarter-over-quarter. In the fourth quarter, G&A was a little higher due to year-end bonuses, but it's reasonable to expect that it will continue to drop as evidenced by our previous quarters. We continue to keep a lean and efficient workforce as volumes increase. As the denominator grows, the fixed cost will continue to be diluted, again, expanding the margins. This is a great time to throw a shout-out to our HighPeak organization. 2022, as Jack said, was a great year for our company, none of this would be possible without each and every one of you. You make what we do easy. Thanks. We continue to drive operational excellence in all facets of the business. We are continuing to remove costly generators.
Our fixed costs continue to reduce as our production increases. We are building infrastructure in Signal Peak, which will further reduce our cost in that area of the field. Our margin for BOE is the best in the business and will continue to expand, further differentiating HighPeak from our peer group. Turning to Slide eight, ESG. We've been very transparent with our goals and initiatives. Fortunately for us, we were the original architect of our position. We were able to set up everything with efficient operations and environmental stewardship in mind. Power. We run a very energy-intensive business. It's imperative that we be efficient, clean, and scalable. We oversize our substation, which allows another rig or two to utilize high-line power up at Flattop. We've also added another frac crew on dual fuel. Facilities.
We build very large-scale central tank batteries that minimize our footprint and make for adding additional wells cheaper and more environmentally friendly to connect. Recycle. We continue to recycle high levels of our stimulation fluids and are expanding our recycle capabilities across both large acreage blocks, reducing cost and the need for makeup water. Sand. We now have three frac crews utilizing local wet sand, which greatly reduces our emissions and cost. All of our ESG initiatives are both financially and environmentally rewarding for our shareholders. HighPeak looks at these initiatives as just doing the right thing. Turn to Slide nine, Flattop operational update. East Howard County has always been plagued by the reticence of some as to whether we have good rock and enough inventory in multiple formations.
The work we've done to date demonstrates very robust economic results across the entirety of the block, from the northwest to the southeast and from the southwest to the northeast. The Conrad pad, bullet number one, extended the Lower Spraberry and Wolfcamp A into Borden County, four miles northeast of our main development area for the Wolfcamp A and almost seven miles east of our existing Lower Spraberry wells. Both of these Conrad wells are performing similar to the development in the core of the Flattop area, again, expanding the footprint for our inventory. Fleeman pad, bullet number two, a four-well stacked lateral pad with a Wolfcamp D Three Finger test and a Wolfcamp B test, plus a Lower Spraberry and Wolfcamp A. These wells provide multi-zone support for additional inventory down in this area. The Griffin pad, bullet number three.
It's a five-well pad, three Wolfcamp As, and two Lower Spraberry wells. Again, solidifying that the Lower Spraberry and the Wolfcamp A formations are good across our entire Borden County acreage. Southeast Flattop area, bullet number four, the red box, has demonstrated similar well results to the wells back to the west, again, giving us confidence in this area as well. All of these results give line of sight to the inventory runway and ability to continue to efficiently grow HighPeak's production. HighPeak surface, bullet number five, houses our field office, our 1 million bbl recycle facility, and home to the solar farm. If you'll turn now to Slide 10, Signal Peak operational update. There's a ton of exciting activity going on in Signal Peak. HighPeak has previously delineated the base Lower Wolfcamp D across the entire block.
We are now producing 26 wells in the lower base Wolfcamp D. We continue to delineate the Wolfcamp A and the Lower Spraberry, as shown with bullets three, four, and five. Multiple Three-finger Wolfcamp D and Wolfcamp C Hutto tests are in progress, as shown with bullets one and two. We are expanding our recycle capabilities and overhead electric power system, which will continue to drive down our lifting cost. We are excited and look forward to sharing these results from our upside wells and locations in the coming quarters. I'll now hand the call back over to Jack to discuss our year-end reserve.
Thanks, Mike. The next slide on Slide 11 gives you our year-end proved reserve summary. As I mentioned earlier, we've had phenomenal success over the last two years, as evidenced by 130% compounded annual growth rate of our proved reserves. Remember, though, that our BOEs are different, and they currently have 47% higher margin than other reserves from our peers. Our reserve replacement ratio in 2022 was 550% through the drill bit, not including acquisitions. If you look at our 2022 acquisitions, our replacement ratio then increases to over 750%. Unprecedented in my 53 years in the business in terms of growing. Of course, if you didn't have any reserves drilling the well and it was a discovery, it was a tremendous growth.
When you now consider that we have over 220 wells drilled to continue with this growth process, that's something that's substantiated and you can have expectations in the future to continue doing this. Our trajectory of proved reserve growth will continue. We've only scratched the surface of total resource potential for these assets, when you consider that we have over 2,500 locations. We have intentionally been very conservative in our annual reserve booking process. We're not changing anything. If it's not broken, just continue being conservative. We're having a 6% recovery factor of original oil in place. We're not booking reserves from one end of the field to the other. We do step outs, very conservative.
Keep in mind that in any five-year period with outside engineers, it doesn't matter if it's Netherland, Sewell, Ryder Scott, Cawley, Gillespie, our own internal engineers, you can go right down the list. You have almost double reserve success, especially in the Permian Basin over a period of time with each five-year period of technological improvement. Our reserves are gonna continue going up. Our recoveries are gonna continue going up with technological success. In fact, we're also improving recoveries and we're improving on deliverability and return on investment parameters, and creating better and better as before in this. We're gonna continue being conservative on our booking process, but we got a lot of meat left on the bone, so to speak.
The next slide to look at is, and I mentioned this once before, that we wanted to compare our area in East Howard County to Western Howard County, more in the as we go deeper into the basin, and more compared to some of our larger peers in the area. We've talked about our reserves, how fast they're growing, but Eastern Howard County is a very active area, and the margins are differentiated from other areas of the basin. At the end of the year, our comparison process of Eastern compared to Western, and looking at results from 2020 onward, shows the Eastern area is actually outperforming the West on a recovery factor of oil placed. In addition, HighPeak is outperforming its peers in the Eastern Howard County.
We now have over 700 wells drilled east of this. Our results are over 500,000 bbl recoverable compared to 471 of our peers in the West. We're almost 10% higher on EUR and almost 10% higher on economics, not counting consideration of having a higher oil cut. One of the local newspapers in Midland, the Midland Reporter-Telegram, announced in the last few weeks that Howard County is the fastest-growing producer of oil in the entire United States, and Howard County has now moved into the number three position in the Permian Basin as far as oil production. We're in a great area. It's gonna continue improving as we go forward. These results are indicative of our success in southern Borden County as well.
As Mike previously walked through our delineation of Lower Spraberry and Wolfcamp in this area, that's gonna increase additional shareholder value. We're not just buying leases to buy goat pasture, so to speak. We're buying leases and expanding our footprint, and as we drill it up, it's becoming very commercially successful. In fact, both of those wells are making over 800 bbl a day now, so we're really excited about that area. The next, Slide 13, just shows our inventory, and it gives us a sense of, with running a forward program with 1,300 primary locations, we have over 14 years of primary inventory runway. Every time we make a presentation in 30 days, we have 10 more wells in, and we're delineating other zones now.
When you look at this chart, you see all the way from the Middle Spraberry all the way down to the Wolf D, and that includes the Wolf D Three Fingers and also the Hutto zone. We are developing all these zones now, and we're gonna have a lot more information, and some of our offset operators are also drilling in these zones up in the Middle Spraberry and the Jo Mill. We have expectations to be able to continue going forward with upside formations, and we hope that several of these upside locations will add to our primary count within the next few quarters as we see the results of these wells. I mentioned earlier that our locations are averaging over 12,000 ft laterals now. We have the opportunity to do that because of our contiguous acreage plot.
A lot of our peers have more acreage inventory, but it's unattainable acreage. It's very difficult for them to put units together to deal with pooling problems and to deal with other companies and arguments as to who's gonna operate, what pipeline is a well, gonna sell into, what are the marketing characteristics, who has better marketing. We control everything in our area, so we have the choice to drill and to space our wells primarily best that gives us the maximum shareholder return and ultimately leads to higher free cash flow generation. It's why 40,000 bbl is equal to 60,000 bbl with our peers. In Slide 14, this is an exciting slide also.
We messaged in January press release that we plan to step down from our six-rig program, which we were running in the second half of 2022, to running four rigs throughout 2023 and 2024. Many things considered that. Not because we don't have the results of drilling activity. We wanna keep a strong balance sheet. Oil and gas prices went down during that period. We have a higher number of wells, we expect to turn in line this year with 57 wells in progress. The backlog of those wells in progress that we built while running our six-rig program last year, this point is the primary reason for the delta in our CapEx budget in 2023 compared to our forecasted CapEx budget in 2024. We didn't wanna over-drill.
We wanted to get maximum return on investment. We're being conservative with our development of our pads and with our spacing program. Our unit cost per BOE, which is already very competitive with our peers, is gonna continue to increase and will further expand our peer-leading margins. This wasn't by accident. This was a planned program all the way throughout and the way we have always differentiated ourselves from our peers to have higher return on investment and higher internal rates of return. The key point of this slide is to show where we're going. We're gonna become free cash flow. It's gonna be a free cash flow machine. I've had investors ask me, "Well, when is that gonna happen?" Well, if I knew exactly when prices are gonna be projected, I would be able to say when that's gonna happen.
I'm comfortable that it's gonna happen in the second half of this year. Next year, we're projected to receive to achieve free cash flow at a break even all the way down to $45 oil. That is unprecedented. Most companies can't even get their money back or have any kind of profit at $45 oil. If oil prices stay around $90 a bbl, we estimate our free cash flow to be in excess of $1 billion in 2024. This will allow us to completely pay down 100% of our outstanding debt next year if we chose to do so. We could also increase our drilling program. Prices stay in that $90-$100 range. The point is, we all have excess free cash flow available on our balance sheet.
Our investors can look at that and be excited about what's happening over the next 12 months or so. Even though I know Wall Street is usually quarter to quarter, we take a longer term view. On a separate note, I wanna share with our shareholders to know that we are constantly monitoring the market volatility and commodity prices and service costs. We have the ability to be flexible with our drilling program. We could either increase or decrease our program if necessary. We don't have any long-term contracts that can effectively mess us up, so to speak, and cause us to have what I call the perfect storm, high interest rates and low oil and gas prices. We're gonna continue with that program. In closing our last Slide, 15.
This is kind of encapsulates what we've always talked about, contiguous acreage inventory, consistent well results, operational and environmental focus, leading margins and free cash flow and growth. Looking at the value proposition here, you should look at this, and it kinda tells you why you should own HighPeak stock, and to hold on to your stock for the ride relative to us continuing with our strategic alternatives. We have a large contiguous acreage position providing for maximum capital efficiency. We have a tremendous amount of inventory depth where we've now proven the rock quality of this area. An inventory like this is a huge scarcity in our area. In fact, just notice where one of the CEOs recently said it looks like the Permian is at peak production for only five years here.
Our inventory is defined by consistent high return results across more than 200 wells that we drill today. Our development program is environmentally sound and physically rewarding. Our high oil cut and low cost operations truly lead to differentiated peer leading margins. These things lead to our projection of generating large amounts of free cash flow for years and years and years to come. All of that is from one vantage point today. In addition, we continue to improve all aspects of our business, from repeatedly decreasing our lease operating expenses, improving our well performance, and improving the number of formations that are economically sound, providing for long-term return on investment and an additional upside to exceed our expectations. Considering these points, this is why I'm extremely confident in our ability to optimize shareholder value.
That's what everything is about, and to continue operating in the future and implementing the process for strategic alternatives. We talked about that process. It's a process providing optionality relative to merger, relative to outright sale, relative to refinancing and equity increases to increase shareholder value. With that now, turn the program over to questions. If anybody has any questions, we're glad to answer now.
Thank you. As a reminder, to ask a question, please press star one one on your phone and wait for your name to be announced. To withdraw your question, please press star one one again. Stand by as we compile the Q&A roster. One moment please for our first question. Okay. One moment. Our first question will come from John White of Roth MKM Capital. Your line is open.
Good morning, gentlemen, and congratulations on some very, very strong results.
Thanks, John.
Thank you.
On the front page, I wanna make sure I'm reading things right. On the front page of the press release, you say you extended the development potential to the Lower Spraberry into Borden County based on three Lower Spraberry wells. Are those the wells addressed later in the presentation, the Conrad and the Griffin pads?
Yeah, John. I mean, Mike will elaborate further, it's always, it's from the western part all the way over to the eastern part of the Conrad and Griffin wells. Go ahead, Mike, and answer that.
You bet. Yeah, John, you know, as we've picked up acreage up into Borden County, you know, the Crockett operating acreage that we picked up, kind of that 6,500 acres, it was kind of our first foray, and then we put on multiple acquisitions and leases from then. You know, most of that was predicated and underpinned by the Wolfcamp A activity that we had seen. You can notice that we've got much, you know, many more green sticks drilled up in that area. The Wolfcamp A is phenomenal, looks just like down south in Flattop. As we started developing the Lower Spraberry and saw the results in Flattop. The rock looked very similar up on this acreage in Borden.
We extended up into where you see the bullet number three on the Griffin pad and drilled two Lower Spraberry wells, wine racked with the, with the Wolfcamp A. Those two wells, look almost like a laydown to the Wolfcamp A in the area. Again, very encouraging, and added an additional zone to that entire area. Then we stepped all the way out to where the Conrad is, about seven miles west or east of where we, drilled the Griffin pad. As Jack mentioned, the Lower Spraberry and Wolfcamp A there are phenomenal. One's doing over 900 bbl a day, and one's, and that's of just oil, and one over 800. It's very early in the cleanup cycle.
Again, gives us confidence that we can go in and infill between that two development areas, and it's roughly another 75-80 wells that we can feel very confident that in 2023 and 2024 we'll be able to go develop that, very machine-like development, very low cost, efficient, and continue to drive these margins home.
Thank you.
You bet.
Looking on Slide 10, all the pink sticks for the Wolfcamp D, it looks like your confidence is increasing in the development of that zone and that is complete.
Yes, sir. The pink sticks on Slide 10 are the Lower Base Wolfcamp D. We've drilled those across the entire acreage block, so very confident in the results we have with the Lower Base. We have seen some of our peers to the west and to the north of us drill a little shallower in the Wolfcamp D zone. We call it the Three Finger. There's three little streaks on the log that we're able to see. Much more brittle, should hold a frack better. All of the geomechanics, geochemistry, petrophysical analysis all lend itself to suggest that those wells will be even better than the Lower Base D. What we've shown here on the chart is where we've done the Three-fingered test.
We drilled some of the wells, we fracked some of the wells, and look to have results here in the next month and a half. Over the next few quarters, we'll be able to update you on that shallower zone Wolfcamp D. We also walked through some Wolfcamp C Hutto tests, very similar in nature. We've got one drilled out about to come online and a couple others that we're drilling today so that we're, you know, give us another quarter or two, and we'll be able to present to the street. Like Jack mentioned, hopefully we'll be able to move those from upside locations into our primary zone or primary locations. Just extending that runway of high rate of return inventory. Something that we talked about in the past is the Wolfcamp A and Lower Spraberry.
These wells will be very critical to the Lower Spraberry and Flattop. I mentioned three different test areas that we're drilling and completing those wells. A couple of them have been drilled up online. Again, the next few quarters are gonna be very critical for the inventory. I think it'd be the difference between going from our 14-year well replacement to that 20-year rate to be able to keep these kind of returns that we're showing today.
Thanks very much for all that detail and, congratulations again, and I'll pass it back.
Thanks, John.
Thank you. Again, to ask a question, please press star one one on your phone and wait for your name to be announced. To withdraw your question, please press star one one again. One moment please for our next question. Our next question will come from Jeff Robertson of Water Tower Research. Your line is open.
Thank you. Good morning. Mike, on the Slides nine and 10 with some of the pads you're showing, are any of those results additive to the inventory counts you show in those couple slides later in the deck? Secondly, are you testing anything over the next couple of months that's not included in the locations that you show on the inventory slide?
Jeff, all of the locations that we have are in our inventory mix that we have shown in both the primary and the upside locations. What's gonna happen here is as these wells are developed and prove up those zones, again, we had to, you know, we're very, very conservative on those upside zones and what we thought that they may be able to provide. Again, with all of the, all of the data that we have collected and what we truly expect out of these zones, they will absolutely move up into the primary numbers. It will increase the primary numbers. As far as adding to the total of the 2,500 that we have, all of these wells are captured in that.
Over time, as we develop more of these, the areas that we had picked for where there would be upside will most likely expand, and you'll see some growth in that 2,500 number. That's kinda how we're attacking it, Jeff.
It's just continued de-risking from the upside to the primary to move categories.
That's correct. Again, every time you go step out, you tend to move the box around where you thought an upside zone would be prospective.
A question just on delineation between that you show on Slide 12. Jack, you mentioned, I think, a 6% recovery factor that Cawley Gillespie is using for your reserves. How does recovery factor on Flat Top and/or Signal Peak compare to the more central part or the western part of Howard County?
You know, Jeff, that's a great question because everybody uses different recovery factors internally for their reserve bookings. It's typical for the majors to use that 6% recovery factor. Some of the smaller midcap companies to compare western to eastern is about a 2% difference running from 6%-8% recovery factor. As you can see in evaluating 2,700 wells out to the west, to 1,700, going very quickly up to 1,800, 1,900 in the next 12 months, the east is actually outperforming the west. The typical difference on a macro scale is about 2% difference, about 25%+ difference between west and east in terms of recovery factor and in terms of the size of the companies.
Our, we know it's gonna increase, and many companies are using up to 14% recovery factors, even in our area. We're gonna take a conservative approach, and we're gonna go with what we have as factual right now and use a conservative re-recovery factor. We can always add to it, and it gives a potential buyer the opportunity to book whatever they wanna book in terms of reserves. We don't have to worry about revisions and write downs and impairments. We're just gonna take a conservative approach. As long as we're getting a 150%+ increase on an annual basis, it doesn't really matter. As we delineate this year, it could be even higher recoveries because we might decide to step out further and have more PUD development than we did in this year's business.
Hopefully, that answers your-
It does. With respect to the revisions, in this year's reserve report, I think before you all had shown maybe a five to six rig cadence from 2020 maybe beyond 2023. Is some of the revision to year-end reserves just related to how you're stacking up the current plan for five-year development that was included in the December Report?
Yes. I mean, it's very nominal anyway, and it's just a function of what we were gonna be drilling versus what we ended up deciding to drill. It's very conservative, and we didn't consider that. We considered mainly just maximizing shareholder value and keeping a strong balance sheet.
Last question. If HighPeak chose to drill more over 2023 and 2024, maybe just think about 2024, and not be as conscientious about generating free cash flow from this asset, Mike or Jack, do you have an idea of what you could do not to outrun the existing infrastructure on this acreage base in terms of the number of rigs you might be able to run or how you think about operating?
We actually have Flat Top, we have increased and added to our infrastructure. We have the ability as we drill additional wells out to the east, we are improving that infrastructure. We're improving our LACT unit system and our tank battery system. We designed everything with the ability to expand particular tank battery facilities. If we decided to go back to six or seven or eight or even 10 rigs with what we have planned in 2023 with Signal Peak, we could actually accommodate that without having to make major changes to our infrastructure. It would just be common add-ons that would fall into the $20 million-$30 million expenditures to add additional production. It's all now planned, Jeff, into the future to even meet almost doubling the capacity of our rigs.
Jack, that's where having the continuous acreage and being the, basically the original developer of these zones on this acreage gives a real infrastructure advantage to future development?
No question. That is a major component of our position. We've developed this not to be critical of private equity, but to be in consideration of building something long term for the future as a major company development that would make this an attractive asset to give optionality for a potential purchaser where they can control their destiny. Because the profit margins are so great here, they literally could move drilling rigs into this area and be able to improve their production and return on investment by focusing some of their capital in this area and growing it. If they wanted to do so, they would have that luxury to do that.
Great. Thank you very much, Jack.
Thank you.
Thank you. Again, to ask a question or make a comment, please press star one one on your phone. Stand by as we compile the Q&A roster. I am seeing no further questions in the queue. This will conclude today's conference call. Thank you all for participating. You may now disconnect and have a pleasant day.