Full Year 2025 Mach Natural Resources LP Earnings Call

March 13, 2026

Operator: Good morning, everyone. Thank you for joining us and welcome to Mach Natural Resources LP's Q4 2025 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 a further discussion of risks and uncertainties that could 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.

Speaker #2: 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.

Speaker #2: For further discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements, please read the company's filings with the SEC.

Speaker #2: 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.

Speaker #2: They may refer to some non-GAAP financial measures in today's discussion. For a reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on MACH's website and the company's annual report on Form 10-K, which will also be available on their website or the SEC's website when filed.

Operator: They may refer to some non-GAAP financial measures in today's discussion. For reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach's website and the company's annual report on Form 10-K, which will also be available on their website or the SEC's 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, and then the call will be open for questions. With that, I'll turn the call over to Mr. Tom Ward. Tom?

Speaker #2: 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, and then the call will be open for questions.

Speaker #2: With that, I'll turn the call over to Mr. Tom Ward. Tom? Thank you, Rob. Welcome to MACH Natural Resources' fourth quarter earnings update. Each quarter, we reiterate the company's four strategic pillars that have guided us since our founding in 2018.

Tom Ward: Thank you, Rob. Welcome to Mach Natural Resources' Q4 earnings update. Each quarter, we reiterate the company's four strategic pillars that have guided us since our founding in 2018. Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions. We have distributed back to our unit holders a total of $1.3 billion starting in Q4 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles. We also have remained a consistent distributor of cash to our unit holders post our public offering. Mach has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of $0.53. This is an annualized yield of 15%.

Speaker #2: Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions. We have distributed back to our unitholders a total of $1.3 billion, starting in the fourth quarter of 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles.

Speaker #2: We have also remained a consistent distributor of cash to our unitholders post our public offering. MACH has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of $0.53.

Speaker #2: This is an annualized yield of 15%. I doubt that you'll hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different.

Tom Ward: I doubt that you'll hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different. Additionally, we have delivered an average cash return on capital invested of greater than 30% over the last five years and 23% in 2025 during a down cycle. Clearly, one of the best records of all public equities, not just energy. Therefore, of our four pillars, maximizing distributions is the culmination of the other three and the most important. The second pillar is disciplined execution. Mach has never acquired an asset by paying more than PDP PV-10. In other words, all the blue sky of the company, the acreage, midstream, equipment, offices, are part of our purchase price. We have accomplished this goal 23 times and do not see an end to the requirement.

Speaker #2: Additionally, we have delivered an average cash return on capital invested of greater than 30% over the last five years, and 23% in 2025 during a down cycle.

Speaker #2: Clearly, one of the best records of all public equities, not just energy. Therefore, of our four pillars, maximizing distributions is the culmination of the other three and the most important.

Speaker #2: The second pillar is disciplined execution. MACH has never acquired an asset by paying more than PDP/PV-10. In other words, all of the blue sky of the company—the acreage, midstream, equipment, offices—are part of our purchase price.

Speaker #2: We have accomplished this goal 23 times and do not see an end to the requirement. Through this method of deploying assets across the Mid-Con and San Juan Basin, we have drilling opportunities that we did not have to pay for.

Tom Ward: Through this method of deploying capital, we've been diligent in assembling a set of assets across the MidCon and the San Juan Basin that have drilling opportunities that we did not have to pay for. Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least two areas that were seen as distressed when actually they were not. Since 2018, we've spent $1.4 billion developing assets that others thought were worth zero while compiling acreage that now amounts to nearly 3 million acres. An additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, both the MidCon and San Juan are seeing renewed outside investment searching for drilling rights.

Speaker #2: Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least two areas that were seen as distressed when actually they were not.

Speaker #2: Since 2018, we've spent $1.4 billion developing assets that others thought were worth zero, while compiling acreage that now amounts to nearly 3 million acres.

Speaker #2: An additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, both the Mid-Con and San Juan are seeing renewed outside investment searching for drilling rights.

Speaker #2: Also, the deep end of Darco is the only place we've expended capital to lease land. The vast majority of our acreage is held by production, from the purchases that we've made.

Tom Ward: Also, the Deep Anadarko is the only place we've expended capital to lease land. The vast majority of our acreage is held by production from the purchases that we've made. We will test the market and see if we can recoup any of our costs for acreage, seismic, other expenses associated with the Deep Anadarko. As I mentioned, the San Juan is also now very active with additional sales processes, which are paying for upside where we did not. However, our land in the San Juan is all held by production, and we are not in any hurry to sell there. We've done extremely well buying distressed properties then finding them not in distress sometime later. For example, the Sabinal purchase, which closed last September, was bought when the market was certain we would see oil prices below $50.

Speaker #2: We will test the market and see if we can recoup any of our costs for acreage size, because of other expenses associated with the deep end of Darco.

Speaker #2: As I mentioned, the San Juan is also now very active, with additional sales processes that are paying for upside where we did not. However, our land in the San Juan is all held by production, and we are not in any hurry to sell there.

Speaker #2: We've done extremely well buying distressed properties, then finding them not in distress sometime later. For example, the Sabanol purchase, which closed last September, was bought when the market was certain we would see oil prices below $50.

Speaker #2: We believe that any time you can buy stable crude production in the $60s, you'll be rewarded at some point. This philosophy also drives our hedging decisions.

Tom Ward: We believe that any time you can buy stable crude production in the 60s, you'll be rewarded at some point. This philosophy also drives our hedging decisions. We hedge 50% of our production in year 1 and 25% in year 2 on a rolling basis. We want to lock in near-term cash flow while having exposure to higher prices in the future. We have a strong belief that our business will be critical to the world over the next few decades, and prices will have the tendency to rise faster than the rate of inflation during this time. Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward.

Speaker #2: We hedge 50% of our production in year one, and 25% in year two on a rolling basis. We want to lock in near-term cash flow while having exposure to higher prices in the future.

Speaker #2: We have a strong belief that our business will be critical to the world over the next few decades, and prices will have the tendency to rise faster than the rate of inflation during this time.

Speaker #2: Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward. During the last year, we've moved from drilling oil-dominated assets in the Oswego and Condensate window of the STACK to dry gas locations in the deep end of Darko and San Juan.

Tom Ward: During the last year, we've moved from drilling oil-dominated assets in the Oswego and condensate window of the STACK to dry gas locations in the Deep Anadarko and San Juan. Our reasoning is simple. The Bloomberg fair value price for West Texas Intermediate crude oil was $71.72 in 2024. That reduced to $57.42 in 2025. The Bloomberg fair value price for Henry Hub Natural Gas was $3.43 in 2024. That price improved to $4.42 in 2025. In 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan or Deep Anadarko through the first half of this year.

Speaker #2: Our reasoning is simple: the Bloomberg fair value price for West Texas Intermediate Crude Oil was $7,172.72 in 2024. That reduced to $57.42 in 2025.

Speaker #2: The Bloomberg fair value price for Henry Hub natural gas was $3.43 in 2024. That price improved to $4.42 in 2025. In 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan and deep end of Darco through the first half of this year.

Speaker #2: However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last half of 2026 if crude prices remain elevated.

Tom Ward: However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last half of 2026 if crude prices remain elevated. As you can see in the presentation updated this morning, Oswego drilling program is very good. Since 2021, we've drilled and completed more than 250 Oswego locations, which have consistently had rates of return above 50%. We also have locations in the Red Fork, Sycamore, and Osage that can be added to our drilling schedule. Therefore, we will plan to reduce the Deep Anadarko CapEx by moving from 2 rigs to 1 rig and bring back on the Oswego program if the market allows. The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company.

Speaker #2: As you can see, in the presentation updated this morning, the Oswego drilling program is very good. Since 2021, we've drilled and completed more than 250 Oswego locations, which have consistently had rates of return above 50%.

Speaker #2: We also have locations in the Red Fork, Sycamore, and Osage that can be added to our drilling schedule. Therefore, we will plan to reduce the deep end of Darco capex by moving from two rigs to one rig and bring back on the Oswego program if the market allows.

Speaker #2: The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company. The third pillar to discuss is disciplined reinvestment rate.

Tom Ward: The third pillar to discuss is disciplined reinvestment rate. Our goal is to return as much cash to our unit holders as possible while staying within the guidelines for our strategic principles. We target a reinvestment rate of no more than 50% to maximize cash distribution while maintaining production and profitability. In 2026, we anticipate slightly growing our barrels of oil equivalent while maintaining our desired reinvestment rate. It's a task that is difficult to accomplish, especially with a set of assets that at the time of purchase were not supposed to have any upside value. However, we have not only accomplished this over the past eight years but have thrived by drilling very high rates of return projects. In 2024, we projected our rate of return on drilling projects to be approximately 55%.

Speaker #2: Our goal is to return as much cash to our unit holders as possible while staying within the guidelines for our strategic principles. We target a reinvestment rate of no more than 50% to maximize the cash distribution while maintaining production and profitability.

Speaker #2: In 2026, we anticipate slightly growing our barrels of oil equivalent while maintaining our desired reinvestment rate. It's a task that is difficult to accomplish, especially with a set of assets that, at the time of purchase, were not supposed to have any upside value.

Speaker #2: However, we have not only accomplished this over the past eight years, but have thrived by drilling very high rate-of-return projects. In 2024, we projected our rate of return on drilling projects to be approximately 55%.

Speaker #2: In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment. We succeeded by delivering rates of return of approximately 40%.

Tom Ward: In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment. We succeeded by delivering rates of return of approximately 40%. Since our last earnings release, we have brought on production three additional Deep Anadarko locations. These three locations combined for approximately 40 million cubic feet of gas per day. In the Deep Anadarko, we anticipate an estimated ultimate recovery of approximately 19.5 Bcf or 6.5 Bcf per mile of lateral. We believe ranges will be between 5 to 8 Bcf per mile of lateral. The Deep Anadarko is located, as the name implies, at a true vertical depth of between 14,000 to 17,000 feet. Drilling an additional 15,000 feet of lateral projects make total depth between 29,000 to 32,000 feet.

Speaker #2: Since our last earnings release, we have brought on production three additional Deep End of Darco locations. These three locations combined for approximately 40 million cubic feet of gas per day.

Speaker #2: In the deep end of Darco, we anticipate an estimated ultimate recovery of approximately 19.5 Bcf, or 6.5 Bcf per mile of lateral. We believe ranges will be between 5 to 8 Bcf per mile of lateral.

Speaker #2: The deep end of Darco is located, as the name implies, at a true vertical depth of between 14,000 to 17,000 feet. Drilling an additional 15,000 feet of lateral projects makes total depth between 29,000 to 32,000 feet.

Tom Ward: Our cost to drill and complete is projected to be between $14 to 15 million per location. In the San Juan, we plan to drill 7 to 8 dry gas Mancos wells. The true vertical depth of the Mancos is approximately 7,000 feet, and laterals are projected to be a mixture of 2 and 3 miles. A 3-mile horizontal lateral Mancos well is projected to cost $15 million and recover approximately 24 Bcf of reserves. With a 60% first year decline. Our goal is to lower the drilling and completion cost to approximately $13 million during the 2026 drilling season. The drilling season starts on 1 April and runs through the end of November. The fourth pillar to discuss is to maintain financial strength. Our long-term goal is to have a debt-to-EBITDA ratio of one times.

Speaker #2: Our cost to drill and complete are projected to be between $14 to $15 million per location. In the San Juan, we plan to drill 7 to 8 dry gas Mangos wells.

Speaker #2: The true vertical depth of the Mangos is approximately 7,000 feet, and laterals are projected to be a mixture of 2 and 3 miles. A 3-mile horizontal lateral Mangos well is projected to cost $15 million and recover approximately 24 BCF of reserves, with a 60% first-year decline.

Speaker #2: Our goal is to lower the drilling and completion cost to approximately $13 million during the 2026 drilling season. The drilling season starts on April 1st and runs through the end of November.

Speaker #2: The fourth pillar to discuss is to maintain financial strength. Our long-term goal is to have a debt-to-EBITDA ratio of one times. When we're at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution.

Tom Ward: When we're at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution. This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards as we did for the transformative ICAV and Sabinal acquisitions that closed in Q3 2025. By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise in either direction. Currently, during a time when we're not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%.

Speaker #2: This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards, as we did from the transformative ICAV and Savinol acquisitions that closed in Q3 2025.

Speaker #2: By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise, in either direction. Currently, during a time when we're not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%.

Tom Ward: In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow while sending home all of our excess cash. We continue to believe in the long-term value of oil and natural gas. Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience. Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome. As the proverb says, "Good things come to those who wait." I'll turn the call over to Kevin to discuss financial results.

Speaker #2: In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow, while sending home all of our excess cash.

Speaker #2: We continue to believe in the long-term value of oil and natural gas. Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience.

Speaker #2: Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome, as the proverb says, "Good things come to those who wait." I'll turn the call over to Kevin to discuss financial results.

Kevin White: Thanks, Tom. 2025 year-end reserves capturing the results of 2025 drilling and acquisitions during the year, more than doubled from 337 to 705 million barrels of oil equivalent. Also worth noting, the additions from the results of our development program exceeded the 2025 production by 18%. For the quarter, our production of 154,000 BOE per day was 17% oil, 68% natural gas, and 15% NGLs. Our average realized prices were $58.14 per barrel of oil, $2.54 per Mcf of gas, and $21.28 per barrel of NGLs. Of the $331 million in total oil and gas revenues, the relative contribution for oil was 42%, 44% for gas, and 14% for NGLs.

Speaker #3: Thanks, Tom. 2025 year-end reserves, capturing the results of 2025 drilling and acquisitions during the year, more than doubled from 337 to 705 million barrels of oil equivalent.

Speaker #3: Also worth noting, the additions from the results of our development program exceeded the 2025 production by 18%. For the quarter, our production of 154,000 BOE per day was 17% oil, 68% natural gas, and 15% NGLs.

Speaker #3: Our average realized prices were $58.14 per barrel of oil, $2.54 per Mcf of gas, and $21.28 per barrel of NGLs. Of the $331 million in total oil and gas revenues, the relative contribution for oil was 42%, 44% for gas, and 14% for NGLs.

Kevin White: On the expense side, our lease operating expenses was $106 million for the quarter, or $7.50 per BOE. Cash G&A for the quarter was $11 million or $0.77 per BOE. We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges, which contributed $42 million, and midstream activities totaled $388 million. Adjusted EBITDA was $187 million and $169 million of operating cash flow and development CapEx of $77 million or 46% of our operating cash flow. Full year 2025 development costs of $252 million represented 47% of our operating cash flow.

Speaker #3: On the expense side, our lease operating expenses were $106 million for the quarter, or $7.50 per BOE. Cash G&A for the quarter was $11 million, or $0.77 per BOE.

Speaker #3: We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges—which contributed $42 million—and midstream activities, totaled $388 million.

Speaker #3: Adjusted EBITDA was $187 million, and $169 million of operating cash flow, and development capex of $77 million, or 46% of our operating cash flow.

Speaker #3: Full year 2025 development costs of $252 million represented 47% of our operating cash flow. In the quarter, we generated $89 million of cash available for distribution, resulting in a distribution of $0.53 per unit, which was paid out yesterday.

Kevin White: In the quarter, we generated $89 million of cash available for distribution, resulting in a distribution of $0.53 per unit, which was paid out yesterday. Rob, I'll turn the call back to you to open the line for questions.

Speaker #3: Rob, I'll 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'd like to ask a question at this time, please press star one from your telephone keypad, and a confirmation tone will indicate your line's in the question queue. You may press star two if you'd like to withdraw your question from the queue. For participants that are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please for our first question. Thank you. Our first question is from the line of Neal Dingmann with William Blair. Please proceed with your questions.

Speaker #1: Thank you. We'll now be conducting a question-and-answer session. If you'd like to ask a question at this time, please press *1 from your telephone keypad.

Speaker #1: And the confirmation tone indicates your line is in the question queue. You may press star two if you'd like to withdraw your question from the queue.

Speaker #1: For participants that are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, for our first question.

Speaker #1: Thank you. And our first question is from the line of Neil Dingman with William Blair. Please proceed with your question.

Neal Dingmann: Morning, guys. Tom, nice details this morning. Tom, just a question. You mentioned about possibly bringing the additional rig as we go to take advantage of higher oil. Just curious, are there other things? Is there secondary activity? Are there other things that you're, you know, kind of deliberating to do, that you could do to continue to take advantage of oil prices as well?

Speaker #4: Good morning, guys. Tom, nice details this morning. Tom, just a question. You mentioned about possibly bringing the additional rig at the Oswego to take advantage of higher oil.

Speaker #4: Just curious, are there other things? Is there a secondary activity? Are there other things that you're, you know, kind of deliberating too, that you could do to continue to take advantage of oil prices as well?

Tom Ward: Yeah, Neil, I think right now if we have one rig running for the last half of the year, it's only gonna spend about $25 million. I would love for prices to stay where they are and give us a little more operating cash flow and maybe bring on another oil rig to drill some of the Red Fork locations that we had or even the Southern Oklahoma assets that we've not yet been able to get to because of lower prices after making the Flycatcher acquisition. If we could, it all depends, you know, on staying within our 50% of operating cash flow.

Speaker #3: Yeah, Neil. I think right now if we only look to if we have one rig running for the last half of the year, it's only going to spend about $25 million.

Speaker #3: I would love for prices to stay where they are, and give us a little more operating cash flow, and maybe bring on another oil rig to drill some of the Redfork locations that we had, or even the Southern Oklahoma assets that we've not yet been able to get to because of lower prices, after making the Flycatcher acquisition.

Speaker #3: So if we could, it all depends, you know, on staying within our 50% of operating cash flow. So as long as our cash flow can move up a bit, we would put more, maybe a second rig in and out, to be bringing on more oil if it's staying in the 70s.

Tom Ward: If our cash flow can move up a bit, we would put more, maybe a second rig in and out, to be bringing on more oil if it's staying in the 70s. You know that during any time oil's up in the $70 range, we make very good rates of return and are comparable or competitive with our IKAV and Deep Anadarko gas wells.

Speaker #3: As you know, during any time oil's up in the $70 range, we make very good rates of return and are comparable or competitive with our ICAV and deep end Darco gas wells.

Neal Dingmann: Great, great details. Then just secondly, maybe a bit early on, you know, prices haven't been terribly high yet for just a couple weeks. Do you see anything in the M&A market? I mean, oftentimes, sometimes spreads start to widen when we see periods like this. Is it early? Are you still seeing opportunities? Maybe just any generalities you can sort of comment around the M&A market.

Speaker #1: Great, great details. And then just secondly, maybe a bit early on—you know, prices haven't been terribly high yet for just a couple of weeks.

Speaker #1: If you see anything in the M&A market—I mean, oftentimes, sometimes spreads start to widen when we see periods like this. Is it earlier?

Speaker #1: Are you still seeing opportunities—maybe just any generalities you can sort of comment around that, the M&A market?

Tom Ward: Yeah, we're pretty much on the sidelines for M&A until we move down our debt. We need to move from the 1.3 times leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions. Our focus is to pay down debt, and then we might be able to do that though by bringing in a partner in the Deep Anadarko. We'll see. We don't know yet. We're hopeful to do that. That also, if we did in the Deep Anadarko, we'd be able to keep 2 rigs working and have just less working interest and still cut back our costs, remembering that we're gonna spend over $200 million this year drilling wells there.

Speaker #3: Yeah, we're pretty much on the sidelines for M&A until we move down our debt. So we need to move from the 1.3 times leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions.

Speaker #3: So our focus is to pay down debt, and then we might be able to do that, though, by bringing in a partner in the deep end of Darco.

Speaker #3: We'll see. We don't know yet. We're hopeful to do that. Also, if we did that in the deep end of Darco, we'd be able to keep two rigs working and have just less working interest and still cut back our costs.

Speaker #3: Remembering that we're going to spend over a couple hundred million dollars this year drilling wells there. So, to answer your question directly, we're not really in the market looking, and really, we were never competitive for these larger transactions that are going on just because of the amount of debt that would be required for us to be competitive.

Tom Ward: To answer your question directly, we're not really in the market looking, and really we were never competitive for these larger transactions that are going on just because the amount of debt that it requires for us to be competitive. What we can do is buy a larger transaction by using some equity and some debt, and we hope to be back in the market here this year as we pay down our debt.

Speaker #3: So what we can do is buy a larger transaction by using some equity and some debt, and we hope to be back in the market here this year as we pay down our debt.

Neal Dingmann: Tom, could you monetize midstream to get that debt down quicker?

Speaker #1: Rob, could you monetize midstream to get that debt down quicker?

Tom Ward: Oh, we could, but then you just pay for it in the long run. The midstream systems that we paid nothing for give us a good string of cash flow. I personally don't like to sell those off just because over the long term, they're good for the company.

Speaker #3: Oh, we could, but then you'd just pay for it in the long run. So the midstream systems that we paid nothing for give us a good stream of cash flow.

Speaker #3: And so I personally don't like to sell those off, just because over the long term they're good for the company.

Neal Dingmann: Thanks so much.

Speaker #1: Thanks so much.

Tom Ward: Thank you.

Speaker #3: Thank you.

Operator: Our next questions are from the line of Derrick Whitfield with Texas Capital. Please proceed with your questions.

Speaker #1: Our next questions are from the line of Derek Whitfield with Texas Capital. Please receive three questions.

Derrick Whitfield: Good morning, guys, and great year-end update.

Speaker #4: Good morning, guys, and great year-end update.

Tom Ward: Thanks, Derrick.

Speaker #3: Thanks, Derek.

Derrick Whitfield: In your prepared comments, you seem to highlight the desire to monetize assets across the portfolio that could be experienced in a rerate in value based on the current macro environment. Could you place some parameters around the value of types of transactions that you're looking at, just to, again, help us calibrate the type of opportunities that you have?

Speaker #4: In your prepared comments, you seem to highlight the desire to monetize assets across the portfolio that could be experiencing a re-rate in value based on the current macro environment.

Speaker #4: Could you place some parameters around the value of types of transactions that you're looking at, just to, again, help us calibrate the type of opportunities that you have?

Tom Ward: Yeah, I'd like to. I don't really know what size we're talking about because we haven't really negotiated anything. What I'd love to do is pay down some debt so that we can get back in the acquisition market without affecting our distributions. Obviously there are three ways that we can bring our debt down, which is that EBITDA would be prices moving up. That's a simple way, and it's happening now. Along with that, you could cut your distributions back and pay down debt that way, which is not our preference. We could sell some non-EBITDA generating assets.

Speaker #3: Yeah, I'd like to. I don't really know what size we're talking about, because we haven't really negotiated anything. So, what I'd love to do is pay down some debt.

Speaker #3: So that we can get back in the acquisition market without affecting our distributions. So, obviously, there are three ways that we can bring our debt down, which is debt to EBITDA, would be prices moving up.

Speaker #3: That's a simple way, and it's happening now. And then, along with that, you could cut your distributions back and pay down debt that way, which is not our preference.

Speaker #3: Or we could sell some non-EBITDA-generating assets. The deep end of Darco is the only area that's not HPP and has leasehold that has some term on it.

Tom Ward: The Deep Anadarko is the only area that's not HBP and has leasehold that has some term on it, so it seems like the most likely place that we would sell some acreage. You know, the size, I can't really say. We'll know here very quickly, but I mean, it has to be significant or else we would just do it ourselves.

Speaker #3: So it seems like the most likely place that we would sell some acreage. So the size, I can't really say. We'll know here very quickly.

Speaker #3: But I mean, it has to be significant, or else we would just do it ourselves.

Derrick Whitfield: Tom, just on the Deep Anadarko, could you, I guess, frame where we are from an acreage position with that trend now?

Speaker #1: And Tom, just on the deep end of Darco, could you, I guess, frame where we are from an acreage position with that trend now?

Tom Ward: Yeah. We're about 50,000 acres, which is about. That's all we want if we're not gonna bring in a partner. We can effectively drill that out over the time of our term on the leasehold. If we don't bring in a partner, we will not spend more in the second half on of our leasehold on CapEx. That's the way we look at it is we'll either bring in a partner and have some additional acreage that we'll be putting on and drilling more wells over the course of the next, you know, 5 years, or we'll just stop where we are and drill out what we have.

Speaker #3: Yeah, we're about 50,000 acres, which is about all we want, if we're not going to bring in a partner. We can effectively drill that out over the time.

Speaker #3: If our term on the leasehold—so if we don't bring in a partner, we will not spend more in the second half on our leasehold CAPEX.

Speaker #3: So that's the way we look at it: we'll either bring in a partner and have some additional acreage that we'll be putting on and drilling more wells over the course of the next five years, or we'll just stop where we are and drill out what we have.

Derrick Whitfield: Makes sense. Maybe just shifting over to operations. Wanted to focus on your recent Deep Anadarko and Mancos wells. With the benefit of a few advances in these formations, could you speak to how you performed against pre-drill expectations and some of the levers you're planning to pull to drive lower completed well costs?

Speaker #1: Makes sense. And maybe just shifting over to operations, I wanted to focus on your recent Deep End of Darko and MACOS wells. With the benefit of a few at-bats in these formations, could you speak to how you performed against pre-drill expectations and some of the levers you're planning to pull to drive lower completed well costs?

Tom Ward: Yeah. The first few wells that we drilled in the Deep Anadarko were better than anticipated. The last three, I think, are right on our type curve. I would say it's performing as expected. The Mancos is just better than expected. It's, I think, a world-class reservoir that too much money has been spent on drilling, completing wells there over the past. I believe the Mancos will be our highest rate of return project as soon as we lower some costs, and I'm confident that our team will be able to do that.

Speaker #3: Yeah, the first few wells that we drilled in the deep end of Darco were better than anticipated. The last three, I think, are right on our type curve.

Speaker #3: So that's—I would say it's performing as expected. The MACOS is just better than expected. I think it's a world-class reservoir. Too much money has been spent on drilling and completing wells there over the past.

Speaker #3: And we look forward to, I believe, the MACOS will be our highest rate of return project as soon as we lower some costs. And I'm confident that our team will be able to do that.

Derrick Whitfield: Perfect. Great update today, guys.

Speaker #1: Perfect. Great update to you guys.

Tom Ward: Thank you. Just expanding on it. There's just no reason that a Mancos well at 7,000 feet and an easy shale target to drill should cost more than the one of the most difficult wells to drill in the country in the Deep Anadarko. I just don't believe it will.

Speaker #3: Thank you. And just expanding on it, there's just no reason that a MACOS well at 7,000 feet and an easy shell target to drill should cost more than one of the most difficult wells to drill in the country, in the deep end of Darco.

Speaker #3: So, I just don't believe it will.

Operator: Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Speaker #1: Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your three questions.

Charles Meade: Good morning, Tom and Kevin and the rest of the team there. Tom, I wanted to ask about the Oswego, and I guess maybe two questions about the Oswego. First, I think you addressed this, but just to make it clear, what oil price would you need to see or do you need to see to make you want to go forward with that rig in the back half of the year, targeting the oil Oswego?

Speaker #4: Good morning, Tom and Kevin and the rest of the team there. Tom, I wanted to ask about I wanted to ask about the Oswego.

Speaker #4: And I guess maybe two questions about the Oswego. First, I think you addressed this, but just to make it clear: What oil price would you need to see, or do you need to see, to make you want to go forward with that rig in the back half of the year targeting the oily Oswego?

Tom Ward: Yeah, I mean, even right now, the Oswego competes with the Deep Anadarko from rates of return. I think any time that you have oil above $70 we're have rates of return well north of 50%, and that meets the requirement of having capital shipped to it. What we should do in a market like that is to distribute out to all three, the Deep Anadarko, the Mancos, and the Oswego, and that's what we're attempting to do.

Speaker #3: Yeah, I mean, even right now, the Oswego competes with the deep end of Darco from rates of return. So I think anytime that you have oil above $70, we have rates of return well north of 50%.

Speaker #3: And that meets the requirement of having capital shipped to it. And what we should do in a market like that is to distribute out to all three: the deep end of Darco, the MACOs, and the Oswego.

Speaker #3: And that's what we're attempting to do.

Charles Meade: Got it. Thank you for that.

Tom Ward: I think, Charles, to look at our Oswego program and say what we can achieve, just look at the difference between the. If you look at an old presentation of ours in 2024, we show every well we drilled, and then we show every well we drilled in 2025, and the Oswego wells are equivalent, overall, but just a higher rate of return in 2024 due to pricing. That

Speaker #4: Got it. Thank you for that.

Speaker #3: And I think Charles, to look at our Oswego—oh, I'm sorry—to look at our Oswego program and say what we can achieve, just look at the difference between the—if you look at an old presentation of ours in 2024, we show everywhere we drilled.

Speaker #3: And then we show everywhere we drilled in 2025, and the Oswego wells are equivalent overall, but just a higher rate of return in 2024 due to pricing.

Charles Meade: Right.

Tom Ward: Well, the wells are not consistent. They have good wells and bad wells as you do everywhere. Overall, you get a very consistent return.

Speaker #3: And so, it's very consistent. The wells are not consistent; they have good wells and bad wells, as you do everywhere. But overall, you get a very consistent return.

Tom Ward: Well, the wells are not consistent. They have good wells and bad wells as you do everywhere. Overall, you get a very consistent return.

Charles Meade: Right. That's actually a good lead into my follow-up question because that's one of the things that I noticed on your slide 14, is that you have some, you know, there's a wider variance on those Oswego wells, and something I know we've spoken about before. I wondered if you could tell me these four really fabulous wells on the left side of your skyline chart here, are those all in the same section? Really what I'm getting at is, you know, is there room in the you know?

Speaker #4: Right. And that's actually a good lead into my follow-up question because that's one of the things that I noticed on your slide 14 is that you have some there's a wider variance on those Oswego wells.

Speaker #4: And it's something I know we've spoken about before, but I wondered if you could tell me—these four really fabulous wells on the left side of your skyline chart here—are those all in the same section?

Speaker #4: And really what I'm getting at is, is there room on the—are there sticks on the map—for you to come in and lay some wells in the back half of '26 that are right alongside some of these four really fabulous ones?

Charles Meade: Are there sticks on the map for you to come in and lay some wells in the back half of 2026 that they're, you know, right alongside some of these four really fabulous ones?

Tom Ward: Yeah. As in all things are a little more complex. We're drilling within the inside of a field that has vugular porosity and algal mounds, so you have different thicknesses. Wells even that are fairly close together can have different amounts of porosity that has either been drained or not drained. In the past, what we've seen is that if you stay 660 feet apart, you really don't have interference across the play, but you don't know until you drill a well. You can stay within the system, and you can feel very comfortable that you're gonna have some really good wells like this. Again, we probably should have showed the 24 drilling results because we had the same thing.

Speaker #3: Yeah, as in all things, they're a little more complex. So we're drilling within a field that has vugular porosity and algal mounds.

Speaker #3: So you have different thicknesses, so wells, even that are fairly close together, can have different amounts of porosity that has either been drained or not drained.

Speaker #3: And in the past, what we've seen is that if you stay 660 feet apart, you really don't have interference across the play. But you don't know until you drill a well. You can stay within the system, and you can feel very comfortable that, over that, you're going to have some really good wells like this.

Speaker #3: And again, we probably should have showed the '24 drilling results, because we had the same thing. We have wells that have 300% or 400% rates of return.

Tom Ward: We have wells that have 300 or 400 percent rates of return, and then others who might have just a 10 to 20 percent rates of return. They can be right next to each other or they can be at different sections. To answer your question, yes, we have many locations left to drill. I feel comfortable that they're going to be north of 50 percent rates of return once we get the program done. I can't tell you which ones are gonna be 200 percent.

Speaker #3: And then others who might have just a 10 to 20 percent rate of return. But they can be right next to each other, or they can be in different sections.

Speaker #3: So to answer your question, yes, we have many, many locations left to drill. I feel comfortable that they're going to be north of 50% rates of return.

Speaker #3: Once we get the program done, I can't tell you which ones are going to be 200%.

Charles Meade: Got it. Thank you, Tom.

Speaker #4: Got it. Thank you, Tom.

Tom Ward: You bet.

Speaker #3: You bet.

Operator: The next question is from the line of Michael Scialla with Stephens. Please proceed with your questions.

Speaker #1: The next question is from the line of Michael Scalla with Stevens. Please receive three questions.

Michael Scialla: Hi, good morning. I wanted to ask on your guidance, you included wider differentials on natural gas. Excuse me. It seems like there's ample takeaway capacity in both the MidCon and San Juan. Can you talk about what caused you to make that change, and what are you seeing in those local markets? Maybe tie that into how you're feeling about the gas macro in general.

Speaker #5: Hi, good morning. I wanted to ask for your guidance. You included wider differentials on natural gas, and—excuse me—it seems like there’s ample takeaway capacity in both the Mid-Con and San Juan.

Speaker #5: So, can you talk about what caused you to make that change, and what are you seeing in those local markets? Maybe tie that into how you're feeling about the gas macro in general?

Tom Ward: I love gas macro in general, so I can start with there. We are seeing widening basis in the Anadarko and the San Juan. All we do is try to estimate from the past what we've seen and bring that into the future. Do I personally believe that the San Juan, for example, is going to be wider going forward? I don't. I think the same reasons that you have warm weather in the West has caused basis to widen. I think that as you have no hydro in the West, you'll see basis tighten over the course of the year. That's just anybody's guess, but that's mine. I think the takeaway isn't an issue.

Speaker #3: Well, I love gas macro in general, so I can start with there. We are seeing widening basis in the Anadarko and the San Juan.

Speaker #3: So, we just—all we do is try to estimate from the past what we've seen and bring that into the future. Do I personally believe the San Juan, for example, is going to be wider going forward?

Speaker #3: I don't. I think the same reasons that you have warm weather in the West has caused basis to widen. And I think that as you have no hydro in the West, you'll see basis tighten.

Speaker #3: Over the course of the year, that's just anybody's guess, but that's mine. And then I think that the takeaway isn't an issue. So if you look back over five years in the San Juan, the production is the same.

Tom Ward: If you look back over 5 years in the San Juan, the production's the same. It's not driven by oversupply to increase our, or loosen the basis. The same way in the Anadarko. We're not seeing this from a supply perspective, so it's just weather, and for a fairly warm winter that has widened basis in my opinion.

Speaker #3: So it's not driven by oversupply to increase or loosen the basis. And in the same way in the Anadarko, we're not seeing this from a supply perspective.

Speaker #3: So it's just a weather in for a fairly warm winter that is widened basis, in my opinion.

Michael Scialla: I appreciate that, Tom. Thanks. I wanted to ask on the Mancos. I know you talked about the well costs. Do you think you can drive those down with a different completion style?

Speaker #4: I appreciate that, Tom. Thanks. And I wanted to ask on the MACOS—I know you talked about the well costs. Do you think you can drive those down with different completion styles? And I know you completed those three-mile laterals, I think, with less proppant per foot than what has been done there previously.

Michael Scialla: Completed those three-mile laterals, I think, with less proppant per foot than what has been done there previously. I wanted to just see how those are performing now that you've had a little bit more time to look at them relative to the other wells in the play.

Speaker #4: I wanted to just see how those are performing now that you've had a little bit more time to look at them, relative to the other wells in the play.

Tom Ward: Yeah, they're the same. It's not a lack of proppant either. We're still using 2,000 pounds a foot. It's just that others have been using more, which, in my opinion, I don't think is needed. We could probably use less than we do, but where we're gonna save money is not only on how much proppant we use, but just the focus on saving. Just really looking at the best ways to transport sand, chemicals, and rig costs. In my opinion, the San Juan, over the course of time, has been run by majors who spend too much money, and we need some independents in here to cut costs. No different than it would be if a major was trying to drill in the Anadarko Basin.

Speaker #3: Yeah, they're the same. It's not a lack of property either. We're still using 2,000 pounds a foot. It's just that others have been using more, which in my opinion, I don't think is needed.

Speaker #3: We could probably use less than we do. But where we're going to save money is not only on how much profit we use, but just the focus on saving—just really looking at the best ways to transport sand and chemicals and rig costs.

Speaker #3: Just in my opinion, the San Juan, over the course of time, has been run by majors who spend too much money, and we need some independence in here to cut costs.

Speaker #3: No different than it would be if a major was trying to drill in the Anadarko Basin. They just can't do it as well as we can.

Tom Ward: They just can't do it as well as we can. I think we'll just save money, just by watching what we do.

Speaker #3: So I think we'll just save money just by watching what we do.

Michael Scialla: Sounds good. Thanks, Tom.

Speaker #4: Sounds good. Thanks, Tom.

Tom Ward: Thank you.

Speaker #3: Thank you.

Operator: The next questions are from the line of John Freeman with Raymond James. Please proceed with your questions.

Speaker #1: The next questions are from the line of John Freeman with Raymond James. Please receive three questions.

John Freeman: Thanks. Good morning. The biggest change from your previous 2026 guidance was the midstream profit, where y'all raised the guidance by about 40%. Can you just sort of speak to what drove such a significant improvement?

Speaker #6: Thanks. Good morning. The biggest change from your previous '26 guidance was the midstream profit, where you all raised the guidance by about 40%. Can you just sort of speak to what drove that significant of an improvement?

[Company Representative] (Mach Natural Resources LP): Yeah. Hey, John, this is Kent. You know, when we first came out with pro forma guidance to capture the effects of the two transactions last year, IKAV and Sabinal, we didn't anticipate some accounting treatment on kinda our own throughput volumes through one of the plants on IKAV. As a result of looking at Q4, a full quarter of results, we're seeing that there's some MOE, midstream operating expense, being reclassed to GP&T. We've captured both components of that in the new guidance, and they're offsetting, but it does improve midstream operating profit.

Speaker #5: Yeah, hey, John. This is Kent. When we first came out with pro forma guidance to capture the effects of the two transactions last year, Icav and Savinol, we didn't anticipate some accounting treatment on kind of our own throughput volumes through one of the plants on Icav.

Speaker #5: And as a result of looking at Q4, a full quarter of results, we're seeing that there's some MOE midstream operating expense being reclassed to GP&T.

Speaker #5: So we've captured both components of that in the new guidance, and they're offsetting, but it does improve midstream operating profit.

John Freeman: Thanks for that color, Kent. Then just one quick one from me following up. Are y'all looking to take advantage, you know, right now of what we've seen on the oil move by adding more hedges, or are y'all sort of like, kind of waiting to see how this plays out?

Speaker #6: Thanks for that color, Kent. And then just one quick one for me, following up. Are y'all looking to take advantage right now of what we've seen on the oil move by adding more hedges?

Speaker #6: Are y'all sort of kind of waiting to see how this plays out?

Tom Ward: Yeah. If you look at the back of the curve, really anything outside of the next 3 to 6 months, the curve falls off fairly quickly. No, we like to stay. I like having access to commodity movement, and so we don't wanna be more than 50% hedged in year one and 25% in year two. We use that as mainly a mechanical hedge just to guarantee cash flows. For example, if we had no debt like we did in 2023, we wouldn't have any hedges on. I want exposure to the curve.

Speaker #3: Yeah, if you look at the back of the curve, really anything outside of the next three to six months, the curve falls off fairly quickly.

Speaker #3: So, no, we like to stay—I like having access to commodity movement. And so, we don't want to be more than 50% hedged in year one, and 25% in year two.

Speaker #3: And we use that as mainly a mechanical hedge, just to guarantee cash flows. But, for example, if we had no debt, like we did in 2023, we wouldn't have any hedges on.

Speaker #3: So I want exposure to the curve.

John Freeman: Thanks, Tom. Appreciate it.

Speaker #6: Thanks, Tom. Appreciate it.

Tom Ward: Thank you, John.

Speaker #3: Thank you, John.

Operator: The next question is from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your questions.

Speaker #1: The next question is from the line of Jeff Gramp with Northland Capital Markets. Please receive three questions.

Jeff Grampp: Morning, guys. First question, I just kinda wanted to clarify the current guidance. Does that contemplate that shift to the Oswego rig in the second half, or is that just kind of, I guess, some optionality or some assessments that you guys will do over the next handful of months?

Speaker #7: Good morning, guys. First question, just kind of wanted to clarify—the current guidance, does that contemplate that shift to the Oswego rig in the second half, or is that just, I guess, some optionality or some assessments that you guys will do over the next handful of months?

Tom Ward: It did not.

Speaker #3: It did not.

Jeff Grampp: Okay. Perfect. Thanks. For my follow-up, it looks like you guys, I think, last call were planning some Fruitland Coal wells as well for 2026. It looks like those have been removed. Is that just a function of the bullishness you guys have of the Mancos, or were there any other factors playing into that?

Speaker #7: Okay, perfect. Thanks. And for my follow-up, it looks like you guys, I think last call, were planning some Fruitland Coal wells as well for '26.

Speaker #7: It looks like those have been removed. Is that just a function of the bullishness you guys have of the MACOs, or were there any other factors playing into that?

Tom Ward: Yeah, both. So I'd say 7 to 8 wells in the Mancos. If we can pull in another well in the Mancos, we'd like to do that. Our Fruitland Coal is a very good reservoir, consistent reservoir for us to drill. It will be easier next year in 2027 program to bring on more of those. And again, it's all associated with how much operating cash flow we have. The restriction to any of this, we have too many locations that are good and not enough operating cash flow.

Speaker #3: Yeah, both. So I said seven to eight wells in the MACOs. If we can pull in another well in the MACOs, we'd like to do that.

Speaker #3: Our Frootland Coal is a very good reservoir, a consistent reservoir for us to drill. It will be easier next year in the 2027 program to bring on more of those.

Speaker #3: And again, it's all associated with how much operating cash flow we have. So, the restriction to any of this is that we have too many locations that are good and not enough operating cash flow.

Jeff Grampp: Yeah. Not a bad problem to have. I appreciate the time. Thank you.

Speaker #7: Yeah, not a bad problem to have. I appreciate it, Tom. Thank you.

Tom Ward: Thank you.

Speaker #3: Thank you.

Operator: Thank you. At this time, we've reached the end of our question and answer session. That will also conclude today's conference. We thank you for your participation. You may now disconnect your lines at this time and have a wonderful day.

Speaker #1: Thank you. At this time, we've reached the end of our question-and-answer session. I will also conclude today's conference. We thank you for your participation.

Speaker #1: You may now disconnect your lines at this time, and have a wonderful day.

Tom Ward: Thanks, Rob.

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