Mach Natural Resources (MNR) Q2 2026 Earnings Call Transcript

DATE

Friday, August 7, 2026 at 10:00 a.m. ET

CALL PARTICIPANTS

• Chief Executive Officer - Tom Ward
• Chief Financial Officer - Kevin White

TAKEAWAYS

• Total Revenue -- $406 million, including $360 million from oil and gas sales and additional contributions from midstream activities and hedges.
• Net Income -- $98 million for the second quarter, representing $1.01 per common unit.
• Adjusted EBITDA -- $182 million, used by management to evaluate operating performance across various capital structures.
• Operating Cash Flow -- $154 million, providing the basis for the company's 50% capital reinvestment limit.
• Total Production -- 148.9 thousand barrels of oil equivalent per day, consisting of 15% oil, 69% natural gas, and 16% NGLs.
• Oil Production -- 22.7 thousand barrels per day, driven by a strategic reallocation of capital toward oil-weighted projects in the Mid-Continent.
• Natural Gas Production -- 613 million cubic feet per day, representing approximately 69% of the total production mix.
• NGL Production -- 24 thousand barrels per day, contributing 16% of the second quarter production volume.
• Average Realized Oil Price -- $95.40 per barrel, excluding the effects of derivative instruments.
• Average Realized Gas Price -- $1.93 per thousand cubic feet, reflecting realized pricing before hedging activities.
• Average Realized NGL Price -- $28.99 per barrel for the second quarter.
• Lease Operating Expense -- $7.21 per barrel of oil equivalent, totaling $98 million for the period.
• Cash G&A -- $7 million, or $0.54 per barrel of oil equivalent, excluding equity-based compensation.
• Development CapEx -- $97 million in the second quarter, representing 63% of operating cash flow for the period.
• Quarterly Distribution -- $0.36 per common unit, to be paid on August 31, 2026, to holders of record as of August 17, 2026.
• Available Liquidity -- $311 million at the end of the quarter, with $730 million utilized under a $1 billion credit facility.
• Oswego Rate of Return -- 87% at a $75 per barrel oil strip, supported by drilling and completion costs of $3.3 million per well.
• Mancos Well Cost -- $13 million per completed well, representing a reduction from the historical average of $20 million per well.
• Mancos IP Rates -- exceeding 25 million cubic feet of gas per day, which rivals performance in the Haynesville and Marcellus shales.
• San Juan Basin Acreage -- 575,000 acres held by production, allowing the company to maintain output with five net wells per year.
• Debt to EBITDA Ratio -- 1.4 times projected by year-end, which management intends to reduce to 1.0 times by the end of 2027.
• Interest Expense -- $25 million for the second quarter, associated with the $730 million in outstanding credit facility debt.
• Midstream Operating Profit -- approximately $5 million for the quarter.
• Capital Reinvestment Rate -- 50% year to date, aligning with the company's long-term strategic objective.

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RISKS

• Ward stated, "It is important to move leverage back to our stated goal versus the 1.4x we're projected to be at the end of the year," indicating that current debt levels exceed the company's long-term target of one times leverage.
• Ward noted that "more capital is now chasing the same type of cash flowing assets that we propose to buy and are willing to pay premiums to our model," which has increased the difficulty of finding discounted acquisitions.

SUMMARY

Management reported total revenue of $406 million and net income of $98 million for the second quarter. The company maintained its strategic focus on four pillars: disciplined execution, a reinvestment rate below 50% of operating cash flow, financial strength, and maximized distributions. During the quarter, Mach Natural Resources LP (NYSE:MNR) reallocated development capital toward oil-weighted projects, specifically restarting the Oswego drilling program in May 2026, while deferring Mancos Shale completions to 2027. Management stated its intention to reduce leverage from a projected 1.4 times to a goal of 1.0 times by the end of 2027 through potential equity placements, asset acquisitions, or adjustments to distributions.

• CEO Ward described the Oswego Limestone formation as the "workhorse" of the company's portfolio, having drilled more than 250 wells in the area since 2021.
• Management expects to lower completion costs for a three-mile lateral in the Mancos Shale to approximately $13 million per well through service optimization and technical improvements.
• The company reported a natural gas marketing agreement in place through 2030, providing strategic optionality for 350 million cubic feet of natural gas production.
• Ward noted that the company maintains nearly 3 million acres of land held by production, which permits rapid adjustments between oil and gas drilling based on market pricing.
• The company projected that five net wells per year in the Mancos Shale would maintain flat production, while 10 net wells could increase output to more than 500 million cubic feet of gas per day.
• Ward stated, "The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want."
• Management indicated that additional takeaway capacity in the San Juan Basin is expected over the next five years to serve Arizona and Pacific Coast liquefied natural gas markets.

INDUSTRY GLOSSARY

• Anadarko Basin: A major oil and natural gas-producing region covering western Oklahoma and the Texas Panhandle.
• Mancos Shale: A geological formation in the San Juan Basin known for natural gas production.
• Oswego Limestone: A shallow oil-producing reservoir in the Anadarko Basin of Oklahoma.
• BOE: Barrels of oil equivalent, a measure used to aggregate oil and natural gas production into a single unit based on energy content.
• PDP: Proved Developed Producing, a category of oil and gas reserves currently being produced from existing wells.
• PV-10: The present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%.
• HBP: Held By Production, a provision in a lease that allows it to continue beyond its primary term as long as the property produces a minimum amount of oil or gas.
• NGLs: Natural Gas Liquids, hydrocarbons such as ethane, propane, and butane separated from natural gas.
• CROCI: Cash Return on Capital Invested, a financial metric used to measure the cash flow generated relative to the capital invested.
• Strip Price: The current market price for future delivery of a commodity, such as oil or natural gas.

Full Conference Call Transcript

Operator: Good morning, everyone. Thank you for joining us and welcome to Mach Natural Resources second quarter 2026 earnings call. During this morning's call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance, and the assumptions underlying such statements. Please note a number of factors may cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in their press release and in other SEC filings. For further discussion of risks and uncertainties that can cause actual results to differ from those in such forward-looking statements, please read the company's filings with the SEC.

Please recognize that except as required by law, they undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. They may refer to some non-GAAP financial measures in today's discussion. For reconciliation from non-GAAP financial measures and the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach's website and their 10-Q, which will be also available on their website when filed. Today's speakers are Tom Ward, CEO, and Kevin White, CFO. Tom will give an introduction and overview. Kevin will discuss Mach's financial results. The call will be open for questions. With that, I'll turn the call over to Mr. Tom Ward. Tom?

Tom Ward: Thank you, Daryl. Welcome to Mach Natural Resources second quarter earnings update. We reiterate the company's four strategic pillars that have guided us since our founding in 2017. These pillars are disciplined execution. We only purchase cash flowing assets at a value of PDP PV-10 or less and do not pay for any leasehold PUDs, midstream, or infrastructure. The second pillar is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. The third pillar is maintain financial strength. We're cognizant of the peril of too much debt.

In order to capture the opportunity of acquiring assets in the San Juan and Central Basin platform, we strategically moved leverage above our goal of one times debt to EBITDA. This pillar is still standing. It is important to move leverage back to our stated goal versus the 1.4x we're projected to be at the end of the year. Outside of waiting to solve through increased pricing, we continue to look for assets at discounted prices to use our equity to purchase. These purchases need to be accretive to our cash available for distribution. We also have an at-the-market equity program to place $100 million of equity at prices that do not disturb trading.

Lastly, we can take a portion of our distribution and pay down debt. Our team is dedicated to meet our goal before the end of 2027. Once we achieve our goal, we'll be in a position to take advantage of any downward movement in the market to make additional bargain purchases. The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want. This is the very essence of our company. The fourth pillar is to maximize distributions to unitholders. This pillar drives all of our decisions. We've distributed back $6.67 to our unitholders since 2024.

Very few public companies in this country have yields at Mach's level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a lot of leverage that often can't sustain once credit tightens or rates move against them. Mach was built entirely different. Our distributions and the cash returns we deliver are second to none, and they're the result of the discipline behind our other three pillars. Mach was established around a cash return model.

We've said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash flowing assets at seldom heard of prices by avoiding the tendency of the industry to look for growth through the drill bit. Our goal is to buy distressed assets at discounted prices that throw off cash. We were fortunate to pick the timing correctly and build a large producing base at bargain prices. We continue to look for those types of assets, but it's become harder as more capital is now chasing the same type of cash flowing assets that we propose to buy and are willing to pay premiums to our model.

However, our steadfast approach to value has paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that is held by production, and that holds our production flat by spending less than 50% of our operating cash flow. In times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model. All of our acquisitions have been made at a discount to the strip at the time of purchase. The timing of some of our acquisitions was quite spectacular, such as buying Alta Mesa through the 363 bankruptcy process in April of 2020.

That purchase was made against a $20 oil strip and paid the first lien RBL lenders back less than $0.10 on the dollar. That made the lending institutions leery of investing in the MidCon and gave us additional running room to acquire other assets at rock bottom prices. The tide did not turn on the MidCon for lenders until 2024. There is now a wave of lending and equity providers chasing MidCon assets. As capital started to move back into the MidCon, we've expanded to the San Juan and Central Basin Platform of the Permian.

We were able to purchase the oil assets of Sabinal in the low $60s/bbl range, and also were able to purchase the natural gas assets of IKAV in the San Juan at less than PDP, PV-10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that have less of a 10% decline. Sabinal, in particular, gave us immediate cash flow benefits due to the rise in crude prices since the purchases. Lastly, both have substantial drilling room left on the assets. Mach Natural Resources has a history of strong cash returns on capital invested in cash distributions.

Over the past five years, we have delivered an industry-leading CROCI, averaging 35%. Not only industry-leading but also in the top 1% of all public companies in the U.S. We also have distributed an industry-leading distribution yield of 15% since 2024 through the first quarter of 2026. This performance was achieved through different pricing cycles, ranging from $94.23/bbl in 2022, when we achieved a 53% CROCI, to $64.81/bbl In 2025, when our CROCI was 23%. Since our inception, we've never had a CROCI of less than 20%. We cannot find another public company with such a strong record of cash returns. Our cash distribution policy has led to a yield of four times the peer average since 2024.

As I mentioned, these returns were accomplished through disciplined acquisitions on top of the best-in-class break evens in both natural gas drilling and liquids-weighted peers. Post the start of the conflict in Iran, we moved from drilling 100% natural gas wells to crude heavy drilling. This is the same type of pivot that we made in April 2025 when post-tariff day, we changed our drilling plans from all oil-weighted drilling to natural gas. This is the luxury of having nearly 3 million acres of land that's held by production. Currently, we're drilling our last two wells in the Mancos Shale.

The completion phase of this year's drilling has been delayed until next year in order to stay within our internally mandated annual CapEx of 50% of operating cash flow. Given that restraint, it's more valuable for us to drill for oil rates of return versus natural gas in the last half of this year. We currently have three additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin Sycamore. The Ardmore Basin locations will be completed by the end of Q3. We will defer drilling more Red Fork locations until Q1 of 2027 and keep one rig in the Oswego during Q4 of 2026. Our drilling schedule is very fluid.

One of our hallmarks is the ability to change the product we drill for and the amount we spend very quickly. Mach Natural Resources has a variable distribution to capture the changes in CapEx associated with different drilling patterns. The pattern in 2026 has been to spend more CapEx in Q2 and Q3 while drilling in the San Juan. The variable nature of our CapEx reveals itself in our distribution. This quarter, we will distribute $0.36 per unit. Since we do not have fixed distributions, there's not any pressure to spend more than 50% of our operating cash flow on CapEx. In other words, the cash flow dictates our pace of CapEx, not the lust for growth at any cost.

The clear workhorse as far as CapEx in our portfolio has been the Oswego Limestone formation in Kingfisher County, Oklahoma. We have drilled more than 250 wells on this asset since 2021 and recently moved a rig back in the area to continue drilling once oil prices improved. We show in our presentation, the Oswego carries a rate of return of 87% at a $75 oil strip. The key to the formation is not how much we find, but in how much we spend. We're only looking for approximately 160,000 bbls of oil, but we'll spend only $3.3 million to drill and complete. Cutting costs is the key to our business model.

The newest field we have acquired that will also become a drilling workhorse is the Mancos Shale of the San Juan Basin. Within the San Juan, we now hold 575,000 acres of land that only expires when production ceases. The key zone to elaborate on is the Mancos Shale. This zone is just now being expanded. Our Mancos Shale position represents one of the most compelling emerging natural gas opportunities in North America. The well performance rivals that of the better-known Haynesville and Marcellus Shale plays, with operators recently reporting Mancos initial production rates exceeding 25 MMcf/d gas. The Mancos footprint is approximately 1/3 the size of the Marcellus and 1/10 the size of the Haynesville.

Mach controls the play with only three other sizable owners. We are the second largest producer of natural gas behind Hilcorp and also the second largest owner of acreage. The play has increased more than twentyfold in the last five years and now exceeds 500 MMcf/d gas. The San Juan also benefits from a mature natural gas transportation network developed over decades of conventional gas production. We expect over the next five years that additional takeaway capacity will be installed to get to premium gas markets of Arizona and the Pacific Coast LNG markets.

This is much different than when the Marcellus and Haynesville were first being explored, and there was no takeaway available, which required operators to take on large firm commitments with pipeline companies. We currently have a gas marketing agreement in place through 2030, therefore by the time the contract amortizes in 2030, we'll have strategic optionality for our 350 million cubic feet of natural gas that can be held flat by drilling only five net wells per year. If we choose to increase activity to 10 net wells per year, we could grow Mach's net production to more than 500 MMcf/d gas. This is the benefit of buying low decline, cash flowing assets that also have fantastic upside potential.

The Mancos has potential to dominate the Mach story in the years to come. As in the Oswego, the key to increasing rates of return in the Mancos is to lower cost. We believe that we could lower CapEx of a 3mi lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway and we have four locations drilled, we expect the ongoing program to be in the $13 million range for a completed well. I'll now turn over the call to Kevin to discuss the financial results.

Kevin White: Thanks, Tom. For the quarter, our production of 149,000 BOE per day was 15% oil, 69% natural gas, and 16% NGLs. Our average realized prices were $95.40/bbl of oil, $1.93/Mcf of gas, and $28.99/bbls of NGLs. Of the $360 million total oil and gas revenues, the relative contribution for oil was 54%, 30% for gas, and 16% for NGLs. On the expense side, our lease operating expense was $98 million, or $7.21 per BOE. Cash G&A was approximately $7 million, or $0.54 per BOE. We ended the quarter with $41 million in cash and $270 million of availability under the credit facility.

Total revenues, including our hedges and midstream activities, totaled $406 million, adjusted EBITDA of $182 million, and $154 million of operating cash flow. Our development CapEx for the quarter was $97 million, or 63% of operating cash flow. Year-to-date, our development CapEx is right on top of 50% of our year-to-date operating cash flow. In the quarter, we generated $60 million of cash available for distribution, resulting in a distribution of $0.36 per unit, which will be paid on August 31st to holders of record on August 17th. Daryl, I'll now turn the call back to you to open the line for questions.

Operator: Thank you. We'll now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for your questions. Our first questions come from the line of Neal Dingmann with William Blair. Please proceed with your questions.

Neal Dingmann: Morning, Tom and team. Thanks for the details. Tom, my first question is just on your upcoming, as you've kind of been moving the upcoming overall drilling program. Can you remind me, I think, just double checking most of your near-term D&C focus will be on the Oswego, and if so, could you just remind us how much activity that will consist of and how you're thinking about the economics behind this play in this environment?

Tom Ward: Yeah, Neal, you're correct. The ongoing drilling program that we have through Q4 of this year is to keep an Oswego rig running. We have a lot of locations. The Sycamore locations in southern Oklahoma are the highest rates of return we have, but there's really only three of those left that we picked up through a couple of acquisitions in 2024. The Oswego continues to be, as I mentioned, the workhorse of our program. We'll keep a rig, depending on pricing, but keep a rig there through 2027 also. Kind of a consistent rig running in the Oswego.

If prices stay as they are, we'll move a rig back into the Red Fork next year, and that play has a little bit more running room with us also. Those are kind of the two oil plays. We're yet to know where gas prices will be next year. We do plan to have a program in the Mancos Shale to drill and then complete the wells this year, assuming that gas prices are rebounding by next summer.

Neal Dingmann: Tom, does that Oswego compete with other more well-known oily plays in this kind of environment?

Tom Ward: Oh, you'd have to tell me. We have basically an 85% rate of return at $75 oil. I think so.

Neal Dingmann: Got it. If I could, just on capital allocation, could you remind me, you or Kevin, just on broad terms, what around your reinvestment rate and then how you intend to deploy the remainder of the cash flow? I think it's pretty straightforward what you all are doing.

Kevin White: Yeah, Neal, as said in those prepared remarks, we were right on top of 50% year-to-date, and that's one of our pillars to have that reinvestment rate of 50%. We would expect to end the year at a similar number. It may have a little lumpiness quarter-to-quarter, but not much.

Tom Ward: Neal-

Neal Dingmann: Very good. Thank you all.

Tom Ward: The operating cash flow drives what our cash CapEx is. We're going to stay under 50% of operating cash flow. As you can see, quarter-to-quarter, we'll either increase CapEx or decrease CapEx depending on what operating cash flow is or prices.

Neal Dingmann: Thank you all.

Tom Ward: Thanks.

Operator: Thank you. Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Charles Meade: Yes, good morning, Tom and Kevin, and to the rest of the Mach team there. Tom, I'd like to pick up on that last point. Assuming you had the operating cash flow to do the Mancos completions whenever you wanted, what is the price that you'd need to see in the San Juan Basin market for you to pull the trigger and do those completions?

Tom Ward: It's not so much that we wouldn't do the completions. It's probably more that we wouldn't spend any CapEx if prices continued to be under $3. It would be difficult to have any gas program in the U.S. working. If you think of the Bcf/1,000 ft that we see in the Mancos, it sits just under the Marcellus. I think we calculate the Marcellus at 1.9 Bcf/1,000 ft. The Mancos at 1.7 Bcf and the Haynesville 1.6 Bcf. If all three of those are going to be in line with the same types of production.

The San Juan has its difficulties of basis at times, other times it has very good basis, like today, it sits on top of the MidCon. I think that to have an ongoing drilling program for natural gas that competes with oil, our problem is that we only have a certain amount of operating cash flow, and that goes to the highest rates of return. Going into next year, what we have to look at is if the Mancos can compete against our oil reservoirs, and we won't know that really until after we get through this winter.

As you know, Charles, I'm a little hesitant right now to be bullish natural gas, but as we come into full storage into the fall and are looking straight in the face of a strong El Niño winter, that it's difficult to be real bullish about it. We'll just evaluate as the year goes into next year. I'm still very, and I think most people are very bullish long-term natural gas. It's just how to get from here to there, that's basically it might be a next summer event before we really do much spending on natural gas CapEx.

Charles Meade: Right.

Tom Ward: As I look out over the longer term period of five years, and you take that looking with our gas contract that we bought, amortizing that hedge out through 2030, we should be in perfect position to capture the demand that everyone sees coming. I don't think Western supply is going to keep up with that. Ultimately, I feel very good about our natural gas positions. It's just how much we spend in 2027 might fluctuate.

Charles Meade: Right, Tom. I appreciate your comments. You can be a natural gas bull, but at the same time be honest about what the next few months look like. Second question. I wanted to ask about the Central Basin Platform. I actually heard from another company recently about a so-called BMW play, Barnett, Mississippian, and Woodford in the Central Basin Platform. I don't think it's your style to go be a pioneer on a play like that, but I'm curious if you're aware of it, if it's happening near some of your acreage, perhaps in Gaines and Andrews.

Tom Ward: I'm not aware of it, and I don't believe it's near any of our properties. We're having any trouble even getting a Clear Fork Group location cleared, so I don't think we'll be doing the BMI.

Charles Meade: All right. Thank you, Tom.

Tom Ward: Thank you.

Operator: Thank you. Our next questions come from the line of Michael Scialla with Stephens. Please proceed with your questions.

Michael Scialla: Good morning, guys. I want to start with your last comment there, Tom, on the Clear Fork. What are the plans there now?

Tom Ward: Well, we don't have it in our drilling schedule yet. Right now, the Clear Fork, again, we were planning on it earlier in the year when we thought we'd add another rig, as prices moved away from where they were, the Clear Fork was the first to be exited. As of right now, we might get the locations in 2027. It's just really more price dependent again, and where our operating cash flow is. I mean, the luxury we have is we sit around on 3 million acres of land that's HBP, and we can pick and choose when we want to drill, where we want to drill at the highest rates of return.

I realize from being an analyst, it's hard to keep track of what we're trying to do, it really can change month to month. Ask Kent. He has to model it every month.

Michael Scialla: I feel his pain. I guess just to get a little bit more color on the Clear Fork. It sounds like it doesn't compete today with the Oswego. Can you just describe what the opportunity set is there? What's the inventory like? Would they be vertical wells? Is it under waterflood? Can you just give us a little bit more color on it?

Tom Ward: It is under a waterflood but we drill horizontal wells within a waterflood. I can tell you. There's only eight locations. It's not hundreds of locations. We pick and choose around what we have. When we buy additional land that comes up, it just happens to have some locations that can be drilled on it. I guess if it all worked well, do you know how many, Rick, that we've got?

Rick Hughes: Seven wells.

Tom Ward: Huh?

Rick Hughes: Like seven wells.

Tom Ward: Yeah. For next year, if it comes into the program. At the end of July, that's going to have a 53% rate of return compared to the Oswego in the 80s. If I had more operating cash flow, we'd drill it. That's where the point is, I guess. It is a target worthy of drilling. It's just that we're going to stay below 50% of operating cash flow.

Michael Scialla: Understood. Wanted to ask on the balance sheet. I think last quarter you said you anticipate as you move forward, leverage will move down naturally just given where, especially where oil prices are. Still feeling that way, or do you feel compelled to pull back at all on the distribution or to do anything differently than what you're planning or have been planning historically?

Tom Ward: Yeah. I think 2027 is a year that we need to get our leverage down, and I think our board is on board with that. It's just basically we recognize that we are running a company today that at today's prices, looking at the end of the year is 1.4x levered, and we want to be at 1x leverage. If you think about that, the reason that we want to be at or below a turn of leverage is because we never know when something's going to happen. In the next few months, it might be a really good time to be buying a natural gas asset.

I'd like to have our leverage back down to a point that we can use some debt to make a purchase before bringing that leverage back down through the equity market. Yeah, we want to be at a point that we're less leveraged. As I mentioned, we have an ATM program that doesn't really affect our trading that will lower our leverage. We can always cut our distribution some. We did that in 2024, I believe, or was it 2025? 2024, where we amortized some of our distribution to pay down debt. Let's just say it's a focal point that I've talked about it now for nearly a year, I guess, three quarters, and our leverage hasn't moved down yet.

It's just time for us to get started here soon if we don't. What I'd love to do is find an acquisition that we could buy using equity. There's just a lot of capital chasing a few deals right now.

Michael Scialla: We'll stay tuned on that. Thanks, Tom.

Tom Ward: Thank you.

Operator: Thank you. Our next question has come from the line of Derrick Whitfield with Texas Capital. Please proceed with your questions.

Derrick Whitfield: Good morning, Tom and team, and thanks for your time.

Tom Ward: You bet.

Derrick Whitfield: Wanted to circle back on your earlier comments on natural gas as you see it today. While I realize you can't provide 2027 guidance, we in most of the street likely have elevated gas weighted CapEx for 2027, which inherently depresses your CAD at current strip. I think what we're all grappling is how to manage activity as the current pivot favors oil-weighted activity and production into 2027. As we sit here today, should we think about higher activity in oil through the first half and some degree of shift to gas in the second half as a starting point?

You clearly have the flexibility as you've noted today to lean into oil or gas, but just that's kind of what we're grappling with.

Tom Ward: Yeah. I think that's fair. I think that basically we don't have any activity in our gas asset. Next year will be the Mancos. The activity would be that if we choose to spend money in 2027 on natural gas, which right now we would plan on it, just assuming that prices pick up into the summertime, that we'd start our completion program sometime in late spring or the springtime, and then have a drilling program through the summer, and then complete all those wells coming in line with each other.

Derrick Whitfield: Yeah, that makes sense.

Tom Ward: Derrick, we haven't really worked on a 2027 program yet. It's something that we're starting to work on now. I think obviously by our next quarter call, we'll have a better understanding of where at least we plan to have our CapEx. We aren't as easy to follow just because we can change both the amount we spend and on what that we spend it on, and it can happen very quickly. I do understand, but every time that we make a change, it's for a higher rate of return.

Derrick Whitfield: Understood completely. We also appreciate that we can make changes in five minutes, where it's going to take you guys quite a bit longer with the actual plans themselves. We appreciate it. Again, just trying to work through that because at the end of the day, we should be solving for higher CAD. It just means it might counter depending on where we are with oil and gas at any point in time. Maybe staying on gas but going down a different path. With the addition of several large pipelines in the Permian, including the Hughson and black plum this year, how are you guys thinking about the outlook for San Juan basis going into next year?

Tom Ward: Yeah. I'm scared of San Juan basis right now. Luckily, we're fairly well hedged with our San Juan gas, but as we go into- right now, we're sitting, what? San Juan and MidCon are sitting $0.20 under the hub. It just seems pretty tight. I don't know where a San Juan basis goes in the near term. I do believe that over a longer period of time, that everything opens up. There's the GreenView pipeline that's being brought on by Tallgrass that's going to give us 2.5 BCF a day, I think that's what they're projecting, to the Arizona Pacific Coast LNG markets coming in. They project 2029 or 2030.

I think that might be fast-tracked as demand is picking up. I think over time, the San Juan is going to be the key place for us. It's just we have to watch carefully what pricing is in order for our CapEx in the meantime. As we just mentioned, in order to keep our production flat there, we only need five wells. It is a tremendous amount of capital to keep our production flat, or it isn't the end of the world if we let it decline if we're increasing our oil production at a higher price in other places. We're going to be very flexible depending on what price gives us.

Derrick Whitfield: Great. Thanks for your time.

Tom Ward: Thanks, Derrick.

Operator: Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your questions.

Jeff Grampp: Hey, guys. Thanks for the time. Tom, your comments on the Mancos well cost I thought were really interesting. I think you mentioned $20 million historically. You guys think you can get down to $13 on this recent batch. I know in the past you talked about adjusting the completion design was a key lever there. Seems like there's a lot going on to get that kind of reduction. I was just hoping to better understand what you guys are seeing there to drive that kind of cost improvement.

Tom Ward: Yeah. It's really more just getting services, having different types of, like, using wet sand versus dry sand, being comfortable with 2,000 lbs/ft of frack, which we used last year, and it works perfectly fine. Learning a few drilling techniques. Rick could do a lot better job than me explaining. All I can do is look at the results and see that we're going to be closer to $13 million than the $15 million we projected and the $20 million historically. To me, the Mancos is much like the Haynesville, is that the Haynesville started out with very high well costs.

Over time, in their core area, they were able to bring those down and ultimately make the field have a rate of return. That's basically the story of the Mancos, as we started out with incredibly high well costs in the field that are now being brought down. Rick, do you want to mention anything about how costs are coming?

Rick Hughes: Yeah. As far as service costs, they're still in line. We're optimizing our drilling performance and being able to get reduced overall days drilling is the main thing we've been able to change. Bringing some new vendors in, obviously, has helped reduce cost as well.

Tom Ward: Yeah, our savings have basically been both on drilling and completion. The completion costs have really come down.

Jeff Grampp: Got it. I appreciate those details. My follow-up, given the pace of development that you're laying out, Tom, obviously focused on the oil side, assuming that kind of program remains static, would you guys anticipate oil production growth in 2027? Is this more kind of a maintenance level of capital that were out there? Just trying to triangulate where oil might go over the next handful of quarters.

Tom Ward: Yeah. I think it's difficult for us to have too much growth in any of our products because basically we're only spending 50% of our cash flow to keep our production flattish. I think that overall, it's easier to grow a natural gas stream, especially if you're drilling 25 million or 30 million a day Mancos wells. I'd say our projection is that 2027 is basically keeping it flat.

Jeff Grampp: Okay, great. I appreciate the details. Thanks, guys.

Tom Ward: Thank you.

Operator: Thank you. Our next question has come from the line of Tim Rezvan with KeyBanc Capital Markets. Please proceed with your question.

Tim Rezvan: Good morning, everybody. Thank you for taking our questions. I just wanted to go back to the balance sheet. I just had one here. Tom, we see the same thing in our model that you do in yours, that around 1.4 times at year-end. We do see sort of it kind of grinding down if you think about strip pricing into 2027, kind of near spitting distance of one times at the end of the year. My question is, if it's such a pressing concern, and I appreciate you being candid about that, are you looking at asset sales? You have a vast acreage footprint.

Are you looking at other things like getting someone to sort of farm into your acreage or some sort of carry? Just kind of curious kind of how broadly you're thinking about options to accelerate that de-leveraging.

Tom Ward: Yeah. Selling assets are difficult because you're losing cash flow, let's just say you're a little not caring for the gas market in the near term. I hate to get rid of low decline gas assets whenever I believe higher gas price is around the corner. You really don't want to be selling your high-priced oil assets either. To me, it's difficult to sell assets to manage for it, especially when we want to keep our declines low. Let's see. The second part of your question was, what else were we thinking about? That was the sell assets. What was your other question or point of it?

Tim Rezvan: I would just ask, are you looking to kind of get someone to farm into acreage to get some sort of carry?

Tom Ward: Yeah, I'm with you now. The problem with selling acreage is you'd love to say it's non-core, but every acre we have today was non-core when we bought it. Yet, if you look at our results, you see that we're in the top of the peers for gas and oil. If you look at any well that we've drilled since inception of the company, we didn't pay for it. That was by definition, a non-core acre. Whenever we plan to go sell a bunch of non-core acreage, you might be selling the next best field.

As Charles mentioned, we're not going to be the guy who goes out and drills the wildcat, but we're going to have 3 million acres kind of hanging around to look at whenever somebody else does. Today we have a lot of different companies. Mewbourne especially, is opening up areas that no one would have ever believed in the MidCon just a couple of years ago. You have Continental that stretches all the way from Western Oklahoma to Southern Oklahoma, so drilling very good wells.

Now Diversified has the Camino asset, and just a lot of activity with Flywheel and others in the MidCon that are developing acreage that if you would've asked me last year, we'd say was non-core, and if we were in that mode of selling it, we'd have given away the ability to have the high rates of return we do today. That's a long-winded way to say I don't really like to sell acreage either. Selling away your assets, to me, is not as efficient as if we were to cut a distribution.

Tim Rezvan: Okay. I guess there's trade-offs to everything, but okay. I appreciate that response. Thank you. That's all I had.

Tom Ward: Okay. Thank you.

Operator: Thank you, ladies and gentlemen. We have reached the end of our question-and-answer session. With that, I would like to bring the call to a close. We appreciate your participation today. You may disconnect your lines at this time, and have a great weekend.

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