Thank you, Brock. Welcome to the third quarter earnings update for Mount Natural Resources. Each quarter, we emphasize our four strategic pillars. First, we aim to maintain financial strength. Our long-term objective is to achieve a debt-to-EBITDA ratio of around 1x. We believe this level of leverage contributes to financial stability through various commodity cycles while allowing us to seize unique opportunities in mergers and acquisitions. Our recent transactions with IKAV and Sabinal helped us enter two new basins. Following those acquisitions, our leverage increased to above 1.3x, and we aspire to reduce this over time to maximize our acquisition potential and company growth. We plan to wait a few quarters to assess our debt-to-EBITDA levels, hoping that an increase in EBITDA will facilitate leverage reduction. We also receive interest from private equity firms interested in trading their production to benefit from our upside, which we’re open to if it reduces our leverage. However, we also value the equity stakes from sellers, which allowed us entry into two additional basins, particularly given the size of our acquisitions relative to the extra debt incurred. These developments enable us to consider more acquisitions in the sub-$150 million range in established areas, where higher returns are achievable. Additionally, acquiring Sabinal during a weak crude oil market with prices in the low $60s, combined with the significant upside of IKAV, reflects strategic timing in our acquisitions. Second, we prioritize disciplined execution, only purchasing assets priced below PDP PV-10. We have done this successfully 23 times to date and intend to maintain this standard. Should conditions lead to a scenario where assets are trading at a premium, it would typically mean higher EBITDA levels, allowing for adjustments in our production strategy through increased CapEx driven by improved cash flow. Presently, even post IKAV and Sabinal acquisitions, we can move forward with capital efficiency, evidenced by an 8% reduction in expected CapEx for 2026 without impacting our production guidance. Our outlook for the end of 2026 and 2027 suggests modest production growth, maintaining our CapEx spend at less than 50% of projected operating cash flow. Our business strategy focuses on acquisitions yielding free cash flow at attractive prices, resulting in an industry-leading return on capital. A clear example is the IKAV purchase, where we bought the PDP at a discount and are now poised to drill both the Fruitland Coal and the Mancos Shale within our 2026 budget. Third, we take a disciplined approach to reinvestment, targeting a rate of less than 50% to return cash to our unitholders. Our production remains stable with this low reinvestment rate due to our manageable decline rate of 15%. This allows us to send cash back to unitholders while choosing to drill either natural gas or crude oil based on market prices. In May, we paused drilling our high-return Oswego inventory to focus on gas projects. Our oil inventory is mainly held by leasehold, enabling us to wait until oil markets recover. For 2026, we plan to focus on dry gas projects in the Deep Anadarko and San Juan regions. We make monthly drilling decisions, maintaining flexible contracts with service providers, which allows us to adjust our CapEx in response to pricing, as demonstrated this year. Our strategic acquisitions have generated a substantial backlog of production locations, leading to a difficult drilling schedule under our current reinvestment strategy. Consequently, we might seek a drilling partner for our land in the Deep Anadarko and the Mancos Shale. This approach could generate revenue from our non-EBITDA producing land assets while still achieving high distribution levels. Our fourth and most important pillar is delivering industry-leading cash returns on capital invested through distributions to our unitholders. With our announced third-quarter distribution of $0.27 per unit, we have returned $5.14 per unit to our unitholders since going public in October 2023, totaling over $1.2 billion since 2018. This level of return significantly surpasses that of our public peers. Despite this substantial payout, our enterprise value has grown to more than $3.5 billion without selling any major assets, all while maintaining a cash return on capital invested exceeding 30% annually over the past five years. To date, we have never reported a return lower than 20% since our inception. This singular measure represents the foundation of our goals. We remain optimistic about nearing the end of a cyclical downturn in crude oil that we expect will shift soon, enabling us to profit from Sabinal crude production at higher prices, supported by less than 10% annual production decline. We maintain that acquiring low-decline crude assets priced in the 60s will ultimately yield significant rewards. For natural gas, we anticipate demand growth will soon accelerate. While we have been cautious about pricing since early spring, we recognize that as we approach winter, the market's response will depend heavily on weather conditions. Nevertheless, starting in 2026, U.S. demand through LNG exports is anticipated to increase significantly, adding around 24 Bcf per day between 2026 and 2030, which is notably larger than the growth driven by data centers. That growth could also yield an additional 5 to 10 Bcf per day if half of the demand comes from natural gas. Although there are concerns about associated gas in the Permian as takeaway capacity increases, we see this as more of a basis challenge rather than a fundamental issue with sufficient demand being established. Having invested $1.3 billion in low-decline oil and gas assets, we position ourselves well for increased cash flow in the long term. The IKAV and Sabinal deals were crucial for enhancing our scale and diversification, and we foresee further opportunities in the Anadarko by acquiring smaller assets under $150 million. Importantly, we cannot pursue all acquisitions solely through debt, necessitating that equity holders understand the broader implications of enhancing reserves that increase our cash available for distribution, alongside raising our CapEx budget to elevate our distributions over time. The acquisitions of IKAV and Sabinal serve as illustrative models of our strategy. As the transactions involved considerable equity from IKAV and Cane, we were able to proceed with them, resulting in an immediate 8% increase in year-one cash available for distribution, anticipated to rise to 28% by year five. We've observed early results in both the Deep Anadarko and Mancos Shale projects. In the Deep Anadarko, we've initiated our first two well pads, which have a total of 25,000 horizontal feet and currently produce over 40 million cubic feet of gas daily. At these production levels, we expect to uncover more than 20 Bcf per 3-mile lateral with a PV-10 value of around $15 million per location. We've invested $14 million per well in this initiative. Additionally, we've engaged in three deep Anadarko wells with Continental, holding about a 20% working interest, which are in the early flowback stages and we expect similar results. In the Mancos, we've initiated production from five wells drilled by IKAV during the summer, with lengths of 10,000 and 15,000 feet, achieving initial production rates above our 30 million per day expectations with an expected EOR of 18 Bcf per well. Our 3-well, 3-mile pad commenced production in late October, now yielding over 70 million cubic feet of gas daily, with projections suggesting a 3-mile lateral could provide an EOR of 24 Bcf and a PV-10 of around $14 million. Combined, these five wells are producing over 100 million cubic feet of gas daily. Despite current high drilling costs for Mancos wells, we believe we can achieve future cost reductions. The industry is currently spending between $16 million to $20 million on each 3-mile well. We aim to spend around $15 million initially but believe we can bring costs down to approximately $12 million next year. IKAV drilled all five wells we are now producing from; they finished two 2-mile laterals and we completed the three 3-mile laterals. IKAV incurred $13.75 million in costs for their two wells, while we saved about $2 million on each 3-mile well. We expect these wells will average $15 million in completion costs. I often receive inquiries on how we will achieve these cost reductions. We believe the industry often overstimulates wells and misses opportunities to maximize profits. We can lower costs through more aggressive bidding, optimizing resources like acid and sand, and refining location sizes and rental quantities. This approach can yield significant savings, as larger fracks incur greater costs. The simplest path to better returns is to reduce expenditures. If we succeed in lowering costs, we could see an increase of up to 30 percentage points per location by reducing expenses from $15 million to $12 million across drilling projects. We have applied this strategy across all our drilling efforts at Mach. For example, when launching the Oswego, we managed to halve the well costs while maintaining the same production outcomes. We also anticipate effective cost reductions in the San Juan. During the recent quarter, we completed two Red Fork sand wells, experiencing initial production rates exceeding 600 barrels per day and 1.5 million cubic feet of gas, with expected IRR in the high 30s at current oil prices. Currently, we are in the final stages of completion for our next well in the Deep Anadarko. We have two rigs operating in the region, and our production schedule aims for one location to come online this month, with additional pads in January, March, and June of 2026. The Mancos shale program is set to commence in May 2026, with seven locations projected to begin production in the fall. Our primary focus for 2026 remains natural gas, particularly in regions where gas takeaway is strong. The Mid-Con is well-connected to major interstate systems, and currently produces about 9 Bcf a day with a takeaway capacity of 12 Bcf a day. Midship and Southern Star are expanding capacity by about 400 million cubic feet each. The San Juan also possesses sufficient takeaway capacity in the near term. Growth from Mancos shale development is forthcoming, and Energy Transfer's Transwestern expansion is anticipated to further boost capacity by 1.5 to 3 Bcf a day by 2029, reinforcing the need for gas supply as reflected by Total's collaboration with Continental on their Deep Anadarko holdings. This partnership underscores the potential of the Deep Anadarko inventory to effectively move natural gas to where LNG demand is surging. I'll now hand over the call to Kevin to review our financial results.

Thanks, Tom. For the quarter, our production of 94,000 BOE per day was 21% oil, 56% natural gas and 23% NGLs. Our average realized prices were $64.79 per barrel of oil, $2.54 per Mcf of gas and $21.78 per barrel of NGLs. Of the $235 million total oil and gas revenues, the relative contribution for oil was 50%, 32% for gas and 18% for NGLs. On the expense side, our lease operating expense was $50 million or $6.52 per BOE. Cash G&A was $21 million. It's an important point this quarter to note that the deal costs associated with IKAV of approximately $13 million are a bit unique. First and foremost, they are nonrecurring. Secondly, due to nuanced GAAP rules, they are required to be expensed whereas in the history of our acquisitions, including Sabinal, the deal costs have been capitalized. Additionally, with the IKAV deal, we engaged an outside adviser, which again is out of the norm for our acquisition history. As a point of reference, the Sabinal deal costs were approximately $4 million and by the way, were capitalized. Excluding the deal costs, recurring cash G&A was around $7.2 million or $0.83 per BOE. As we analyze this quarter's distribution more closely, the free cash flow from our legacy assets performed as we expected. The free cash flow from the acquired assets only contributed for a couple of weeks during the quarter, but also performed as expected. And with a higher outstanding unit count associated with the units issued for the acquisitions, the distributions before the G&A impact would have been approximately $0.35 per unit. The nonrecurring $13 million deal costs reduced the distribution by about $0.08 per unit. It is straightforward to expect higher distributions in the immediate upcoming quarters with the benefit of the acquired assets contributing for the full quarter and the absence of expensed deal costs. We ended the quarter with $54 million in cash and $295 million of availability under the credit facility. Total revenues, including our hedges and midstream activities totaled $273 million, adjusted EBITDA of $134 million and $106 million of operating cash flow and development CapEx of $59 million or 56% for the quarter. Year-to-date, our development costs are approximately 48% of our operating cash flow. We generated $46 million of cash available for distribution, resulting in an approved distribution of $0.27 per unit, which will be paid out December 4 to record holders as of November 20.

I'll turn the call back to you to open the line for questions.

Tom, great quarter. My first question is about the Mid-Con operations. You mentioned some significant well performance in the play, and while things have been positive there, it seems like recently you've observed some impressive gains. Is this due to exploring new zones, or what is contributing to this growth, particularly in that Mid-Con area?

Thanks, Neal. We are making progress by shifting away from the condensate zone and focusing more on the deep gas in the Anadarko region. This area has always been recognized for its significant gas potential, as evidenced by Continental's drilling activities in Custer County Deep gas back in 2017. We acquired Millennial Energy Partners' acreage in 2020 and have since been analyzing the Deep Anadarko. For natural gas producers, the challenge has been that the pricing has not been competitive with oil. Now that natural gas prices are over $4, we can achieve returns exceeding 50%, which aligns with our thresholds, especially when oil prices are lower. Our transition into the Deep Anadarko isn't based on any new discoveries but rather on ongoing drilling activities in the deep gas sector. We understand that drilling 3-mile laterals with 15,000 feet of total vertical depth and lateral lengths is challenging, but there is a significant amount of gas available. Therefore, it’s essential for us to manage our costs and ensure favorable natural gas pricing to achieve the returns we anticipate. However, it's important to note that this natural gas resource has been recognized for quite some time.

Tom, my second question is about your gas strategy. In the Mid-Con or other regions, are there any takeaway constraints? Do you utilize any managed choke program? It seems like the rates are flowing really well. Could you provide some insights on takeaway and chokes in relation to your program?

No, the Mid-Con is a great place to work, especially in Oklahoma. It's probably the second easiest state to drill in. We can have Kansas being the easiest and the ability to have gas waiting on you when you get a well done is there. Plenty of takeaway capacity. I think we estimate 3 Bcf a day of takeaway capacity now. So there's just no issues with getting gas online and flowing without restrained rates.

Tom, forgive me, you went through a lot of good detail there, and I may have missed some of it. But I wanted to ask on the Deep Anadarko. I know you just said it's 15,000-foot TVD and then you do another 15,000-foot lateral. What is the D&C cost on those Deep Anadarko locations? That's kind of one. And then two, $20 million a day sounds pretty stout to me, but how did that fit versus your expectations?

Yes. To start with the last point, it turned out just as we expected. If we aim for a return rate above 50% and invest $14 million, which is what we have done, the present value per well is approximately $15 million. The return rate is likely to be in the 60s, depending on market conditions. Given this, it's clear why we can reduce capital expenditures while maintaining steady production. The rates we're seeing from these wells are strong, and currently, the natural gas market is favorable. In targeting the Deep Anadarko, we have invested $14 million, and I believe this could improve over time as we drill more wells and enhance our efficiency. Drilling in this area comes with challenges due to the considerable depth and complex completions necessary to establish a fracture, largely influenced by the pressure levels involved.

Starting with your distribution, despite the strength in operations this quarter, it did come in a touch lower than expected due to the nonrecurring factors you noted. If we assume a flattish price environment in the capital plan you've outlined for 2026, is it reasonable to assume your distribution would be flattish year-over-year?

And Derek, our natural gas volumes next year will be moving up to just over 70%. So if you're bullish natural gas, we should do pretty well.

I wanted to ask about your comments that the industry tends to overstimulate wells. You mentioned the potential for cutting costs in the Mancos. I want to see if you have taken that approach with the Deep Anadarko as well. And do you have enough production history on either these wells in the Mancos or the deep play to give you the confidence that you're not impacting well productivity by cutting back on the proppant.

In the Deep Anadarko, we are utilizing a typical frac that has already been adjusted. While the industry has been operating at about 3,000 pounds per foot of sand in recent years, we have decreased our usage to around 2,000 pounds, which is in line with how other operators are managing their costs. However, this approach has not yet been applied in the San Juan region. Focusing on estimated ultimate recoveries can sometimes negatively impact rates of return. Therefore, we aim to stimulate a well without substantial expenditure. I believe that using a 2,000-pound per foot frac job in the Mancos shale will be effective. To answer your question, we do not have conclusive data yet. We have initial production rates on some wells that have been more stimulated than what we will do next year. However, historically, when we reduced our stimulation efforts, we did not experience a decrease in rates of return. We have more acreage than we can effectively drill, with over 500,000 acres in the San Juan and more than 120 locations already leased in the Deep Anadarko. It's important to note that we won't invest all of our cash flow into drilling for growth, which limits our drilling capacity. If we are successful in expanding our operations in the Deep Anadarko, we could potentially partner with other companies to increase our gas output, which would be beneficial for us.

It’s really impressive to see the 18% reduction in the D&C budget while still being able to maintain production. We did notice that the midstream and land budget effectively doubled from the previous update. I'm curious about what drove that increase.

Yes. The land budget primarily focuses on the deep Anadarko. We are acquiring some new leases and reallocating some acreage to consolidate areas that we hadn’t fully held by production through previous acquisitions. Overall, the increase in land for this purpose is relatively small in the broader context of the area. Regarding midstream, we acquired a substantial amount of new midstream assets with our last two acquisitions, which primarily require maintenance and efforts to restore them to optimal operating conditions, particularly for the IKAV acquisition, which needs some upgrades.

I wanted to expand on the drilling partnership opportunity. Any thoughts on what kind of size you're looking for in terms of a partner? I'm just kind of curious what stage of conversations these may be? And is this something that you guys are pretty definitively moving towards? Are we kind of more of an exploratory stage? Just any additional color there would be helpful.

Yes, Jeff, just a thought. I haven't really articulated much to you yet. There's nothing substantial happening. I believe we have an excess. As I prepared to outline what we possess, I realized we have more than I can handle. We haven't spoken with anyone. We have a Total Continental deal nearby, and I doubt they obtained that without cost. It seems we might have an asset that could be profitable for us. We've successfully managed similar situations before. There are numerous buyers interested here, especially in Mid-Con, which has excellent takeaway capacity. The Total deal indicates that it's possible to transport gas to the hub. Therefore, owning acreage in this area appears to be quite appealing.

Tom, I interpreted your earlier comments on the Mancos as constructive but cautious. Given the strength of the strip in '26, are you satisfied with your current hedging? If I calculated correctly, you are just over 20% hedged for next year. Would you prefer to have that percentage increased, or is it at a desirable level?

Yes, whenever you incorporate the Mancos or San Juan hedges, we are looking at being over 60% hedged on natural gas by 2026. We have made significant hedges for 2026, but I acknowledge there is some risk involved. It feels somewhat precarious to me, especially since making predictions based on weather conditions isn't something I prefer. However, I firmly believe that starting in January, demand will begin to rise. I can't foresee 2027 being anything but positive. When I consider 2027 and beyond, it's clear that we will need considerably more drilling activity than we currently have to meet the demand. I am optimistic about natural gas, but if we experience a warm winter, it might take until late 2026 to see a significant recovery in prices.

I was trying to understand the changes in the 2026 guidance. You issued a release in mid-September, and then there have been significant changes since then. We noticed that the total capital expenditures are down about 10% and production is down about 1% to 2%. Does this change indicate a shift to 100% gas-focused drilling? I'm curious because a 10% reduction in seven weeks is considerable. I'm just trying to understand what has changed in the modeling and strategy forecasting.

Sure, Tim. This is Kevin. That's a good question. As Tom mentioned, we review our drilling schedule every month and can adjust quickly. Your observation is mostly accurate; two things are occurring. First, we see better returns on our gas drilling, which means we are focusing more on gas. Second, the reduction in Capital Expenditures is due to lower strip prices compared to what we initially projected for 2026. With these lower strip prices, we anticipate lower operating cash flow. Our company operates in a straightforward manner, so as we see changes in the strip, we typically adjust our CapEx accordingly. If the strip goes up, we will consider adding locations with good internal rates of return. If it goes down, we will likely scale back some of our activities.

Yes. Tim, I view this as one of our main strategies is a 50% reinvestment rate. The growth in production isn’t fixed. Whenever we experience an increase in operating cash flow, we allocate half of that directly to capital expenditures. Fortunately, since we've reduced our decline rate from 20% to 15%, it has become much easier for us to achieve this modest single-digit growth by only utilizing 50% of our operating cash flow.

This is Tim O'Toole on for Selman. In your prepared comments, you guys talked about the Desert Southwest expansion. It seems like there's just a lot of gas demand kind of coming out of the Southwest and in Arizona, but that project is not coming online until closer to the end of the decade. So just kind of curious how you guys see the San Juan kind of position there kind of short term and maybe longer term as that project comes online.

Thank you, Tim. The ability to increase production really depends on the number of rigs operating. The San Juan region is seasonal, which means we can only effectively drill in the spring and summer, complete projects in the fall, and must move out by November. We see December through May as a preparation period for the next season, which involves getting permits and completing necessary tasks. It's important to note that ramping up production in the San Juan is more challenging than in other areas. However, the Mancos Shale is performing well, as we recently brought on 100 million cubic feet per day from a five-well pad with a decline rate of about 60%, which is not extremely high. If there were significant new drilling, it could potentially overwhelm the system, though I don't anticipate that happening. Looking ahead to the end of the decade, specifically 2029 when Energy Transfer is expected to expand, we currently have a few more billion cubic feet per day of takeaway capacity available, so I don't foresee any immediate issues. Nonetheless, there's still a substantial amount of gas that needs to be brought on.

This now concludes our question-and-answer session. Thank you for your participation. You may disconnect your lines, and have a wonderful day.