Good morning and welcome to the Prairie Operating Company third quarter 2026 earnings conference call. Today's call is being recorded. At this time, I'd like to turn the call over to Wabi Plugsma, Vice President of Investor Relations and Capital Markets. Please go ahead.

Wabi Plugsma, Vice President of Investor Relations and Capital Markets. Please go ahead. Wabi Plugsma, Vice President of Investor Relations and Capital Markets. Please go ahead. Thank you, Operator, and good morning, everyone. Thank you for joining Prairie Operating Company's third quarter 2026 earnings call. Before we provide our prepared remarks, I would like to remind all participants that our comments today will include forward-looking statements which are subject to certain risks, uncertainties, and assumptions. Actual results could differ materially from those expressed or implied by these forward-looking statements. Additionally, we may refer to non-GAAP financial measures for a more detailed discussion of the risks and uncertainties that could cause actual results to differ materially as well as reconciliations of non-GAAP financial measures Please refer to the company's earnings release and public filings, including our Form 10-Q for the quarter ending September 30, 2026. These materials, along with an updated investor presentation, are available on our website. Joining me today are Greg Patton, Chief Executive Officer, and Michael Shelly, Executive Vice President and Chief Financial Officer. With that, I'll turn the call over to Greg.

Thanks, Wabi, and good morning, everyone. Prairie's third quarter results demonstrate the strength of our assets and the execution and excellent work our team continues to deliver across our development program. Average daily sales volumes increased 19% from the prior quarter to 26,117 BOE per day. And we exit the quarter at 30,229 BOE per day. Revenue grew 31% from the prior quarter to $129.5 million. We have completed a large portion of our 2026 capital plan, bringing 37 wells across five pads online to date, adding to our stronger production base and generating greater confidence in the opportunities ahead. Third quarter sales volumes totaled approximately 2.4 million BOE, an increase of 21% from the prior quarter. with 77% liquids, including 56% oil. For the first nine months, sales volumes totaled approximately 6.5 million BOE or approximately 23,730 BOE per day with 74% liquids, including 52% oil. Production momentum continued into early October. As a result of the wells turned in line during the third quarter, Production continued to increase, reaching approximately 32,287 BOE per day by early October. Our current results are supported by the execution of our development program. Year-to-date, we have drilled 27 wells across four paths, with 19 wells drilled in a single run. These wells averaged approximately 18,700 feet in measured depth. at an average rate of penetration of 380 feet per hour and an average spud to rig release time of 6.2 days. We have completed 37 wells over five pads consisting of 27 Niobrara and 10 Codales, with the last three new pads coming online in the third quarter all above type curve. We are currently in the process of drilling four additional wells that will come online in 2027. At Castor, completion activities on the six-well pad were finalized in September, with the wells coming online at the end of the month, predominantly contributing to the fourth quarter production. Turning to Burnett, the four-well development came online at the end of August and represents an important milestone in demonstrating the value of Prairie's acreage. The wells were drilled across three distinct drilling and spacing units, including two 1,280 acre units and one 1,920 acre unit. The wells achieved an average maximum initial production rate of approximately 722 BOE per day per well with an 81% oil cut on a two stream basis and generated cumulative gross production of 131,490 BOE through October 20th of this year. By drilling section line wells across each DSU, we demonstrated the consistent reservoir quality and reserve potential of the acreage while securing all three units for future development. These early production results materially de-risk and validate the quality and future development potential of our acreage within the 5,700-acre Genesis OGDP-1 and supported the conversion of 30 gross possible locations to proved undeveloped locations, expanding our proved inventory, reinforcing the commercial potential of nearby undeveloped locations and reducing uncertainty around our near-term development program. We plan to return to each of these DSUs in the future drilling programs to complete their development. As we look ahead to the continued development of these DSUs and the broader Genesis OGDP-1, the infrastructure already in place positions us to efficiently accommodate future production growth. Our existing pipeline network provides reliable production flow and long-term takeaway flexibility with oil, natural gas, and water connections that allow production to move off location without trucking, reducing operating costs, facility requirements, and environmental impacts. Our commercial agreements support and provide flexibility to our development plan, as well as support our artificial lift strategy. The existing infrastructure has been designed with sufficient capacity to maintain flow assurance throughout our future development program. In addition to de-risking acreage, infrastructure capabilities, and production growth, we continue to improve operating efficiencies. Lease operating expense declined to $5.71 per BOE from $6.85 per BOE in the prior quarter. a reduction of 17%. We continue to realize meaningful cost efficiencies following the complete integration of the Bayswater operations and remain focused on sustaining and extending those efficiencies across our larger production base. For example, during the quarter, we established Stagecoach Logistics LLC to bring field maintenance, logistics, and operational support functions in-house. reducing our reliance on third-party service providers. Centralizing these activities enables us to better control costs, equipment, and inventory while improving response times and field execution. Together, these initiatives help reduce LOE per BOE and demonstrate the operating leverage available across our expanded asset base. We will continue to focus on sustaining field-level efficiencies as we manage our larger producing base. With our recently developed wells now online, our priorities are well performance, operating efficiency, and disciplined capital allocation. We believe the progress across our producing base provides a foundation for continued value creation. I'll now turn the call over to Michael to review our financial results, liquidity, and capital structure.

Thanks, Greg. Good morning, everyone. Third quarter revenue totaled $129.5 million, up 31% from the prior quarter, including $114 million of oil revenue. For the first nine months, revenue reached $311.8 million, an increase of 97% year over year, and adjusted EBITDA totaled $136.4 million, an increase of 37% year over year. Prairie generated $65.3 million of adjusted EBITDA in the third quarter, an increase of 92% from the prior quarter as sales volumes increased and unit operating costs declined. With Burnett and Castor now producing, our focus is on realizing the cash returns from the capital invested this year and carefully managing the spending required to sustain that production. Net loss attributable to Prairie was $48.9 million for the quarter. After preferred stock dividends and re-measurement adjustments, net loss attributable to common stockholders was $34 million, or $0.26 per basic share and $0.28 per diluted share. The GAAP result includes $105.7 million of unrealized derivative losses, a $13.1 million fair value gain on financial instrument liabilities, and $18.4 million of income tax benefit. Average realized prices excluding derivatives were $84.48 per barrel of oil, $24.28 per barrel of NGLs, and $1.05 per NCF of natural gas. Including realized derivative settlements, prices were $62.24, $19.98, and $2.14, respectively. Net cash provided by operating activities was $123.4 million for the first nine months. On a per BOE basis, lease operating expense was $5.71, transportation and processing expense was $1, ad valerum and production taxes were $4.96, and G&A was $4.56, which represents a 24% decrease compared to the prior quarter. At September 30, we had $7.8 million of cash and $3 million available under our reserve-based credit facility, the borrowing base and elected commitments were $475 million with $472 million outstanding. During the quarter, we extended the Series F anniversary warrant issuance date to December 1st, 2026. We continue to pursue opportunities to refinance the remaining Series F preferred stock as part of our broader effort to strengthen Prairie's balance sheet, improve financial flexibility, and better align our capital structure with the scale of our operations. Our commodity swaps extend into 2029. Fourth quarter 2026 oil swaps covered approximately 1.37 million barrels at $63.23 per barrel, and natural gas swaps covered approximately 4.3 million MMBTU at $4.09 per MMBTU. These contracts provide downside protection. Our objective is to support Prairie's operating momentum through disciplined financial management and capital allocation that creates sustainable long-term shareholder value. With that, I'll turn the call back to Greg for closing remarks.

Thanks, Michael. With the recent results of the Burnett Pad demonstrating the quality of our acreage, it has validated our development area and expanded our approved undeveloped inventory. Across Prairie, our team is focused on translating that operating progress into cash generation and long-term shareholder value. As we move through the remainder of 2026, our priorities are consistent. Sustained well performance, maintain operating efficiencies, and allocate capital with discipline. On behalf of the board and management team, I want to thank our employees for their continued dedication and execution, and our shareholders for their ongoing support. With that, I'll turn the call back over to the operator for Q&A.

Thank you. At this time, we'll begin the question and answer session. If you'd like to ask a question, please press star 1 on your telephone keypad. Our first question is from the line of Leo Mariani with Roth. Please proceed with your questions.

Hey, guys. I just wanted to touch base on your CapEx here. So it looks like you've spent about $185 million in the first three quarters, which is the low end of the full year budget. What do you see CapEx coming in at in Q4, given that you only have about $10 million left to kind of hit the high end of your budget? Just trying to get a sense of that.

Morning, Leo. Glad to have you on the call this morning and thanks for joining us. So the number you're looking at, obviously, is on the cash flow statement. I'm assuming at the 185. Ultimately, that is our cash out the door. The capex for the year is actually at about a 165 in terms of our DNC capex for the year. So that leaves more of that 15 to 30 range on the rest of the year. As the remarks stated, we have four wells that we are drilling or are about to drill for the year. And so as we think about DNC costs on a gross basis for wells, that's roughly with rig MOB and DMOB under that kind of 8 million marker. So as we're looking at 165 million of DNC costs, some ancillary costs still trickling in, in and around the final completions in the third quarter. coupled with that DNC Capital and some other one-off projects here and there, we still feel strongly about our guidance range that was previously given of the 180 to 195. That being said, there are some inflationary expenses, albeit we had a lot of our products locked in for the year, particularly sand and steel products, but there will be some inflationary aspects that we have seen at the end of the third quarter with costs coming in. And as we get into the drilling expenses here in the fourth quarter, we are seeing some higher costs in and around those products.

Okay, appreciate that. And I guess, what do you guys see as kind of rough two-mile lateral or well-cost these days as a result of the inflation?

So... That's a great question. Ultimately, as we look at the DNC costs we've talked about before exhibiting that kind of $5.3 to $5.5 million range, those numbers have gone up. We're seeing $300,000 to $500,000 of additional costs and that could continue to go up depending on the geopolitical environment. what we would say would be not this round of drilling cost for the steel, but as we look at Q1 for the year and as we're looking at our programs pushing into 27 and starting that process, it's a little bit of an unknown. We've seen a dramatic reduction in oil costs here recently. We've seen a dramatic increase in the number of ships coming through the strait. We've seen a dramatic increase in imports coming in. So the cost increases could hold flat. at that $300,000 to $500,000 kind of typical increase, and or we could see more or less. It's a little bit of an unknown. So we're watching that very closely.

Okay, that makes sense. And I guess just on your production, obviously you had a nice increase in Q3, but significant momentum on the production heading into Q4. You guys disclosed an early October rate, which looked very strong here at 32,300 barrels a day. Is that rate kind of holding here now that we're about a month later into kind of mid-November? Are you starting to see that kind of rate come off? And, you know, where do you think you're going to kind of end up in the end of the year? Is production kind of declining? And are we going to be lower than that 32,000 and change here in Q4?

So I'm not going to speak to Q4 quarterly guidance, but I will talk about general dynamics and economics of DJ horizontal laterals. So 32,000 barrels a day. obviously in October, as we mentioned in our script. As we think about the wells that came online that supported that with public data, obviously being the burnets and the casters, as we look towards the back of the year from this point forward, production has held very strong, but there's obviously some natural decline as well. So when we look at 32,000 barrels a day, that number has declined over the past 60 days, being the whole month of October, the whole month of November. and as we continue to move forward, ultimately we feel very supportive of our guidance at 23,000 to 25,000 BOEs per day on the annualized average. And we feel very strong about the performance of our wellbores. So, but natural decline is a thing. And so I would not tell you that we would be exiting the year at 32,000 barrels a day, but also we're not guiding to what that exit rate production is at this time.

Good. That makes sense. And then just on liquidity, certainly looked a little bit tight here at September 30th with the cash and kind of the limited balance on the revolver, somewhere around $11 million of liquidity. Can you give us a perspective on, you know, do you think that improves quite a bit? It sounds like CapEx is coming down a lot in Q4 and production's strong. Do you expect considerable free cash flow here in Q4?

Hey, Leo, I'll answer that. You kind of hit the nail on the head there. With production being very strong and kind of limited capex here in the fourth quarter, our liquidity position will continue to improve fairly dramatically as we get into the end of Q4.

Okay, that makes sense. And just on the Series F preferred, I guess the deadline's coming for, you know, warrant, anniversary warrant trigger here, I guess at the end of the month here. Do you guys feel like you might have to extend this again or you think that you might be able to get something done here by December 1st?

Great question again, Leo. And as you are very well aware and close to the matter is we've talked about this a lot over the past year is we've built a really strong relationship with Hytrail. They've been a good partner with us as we've grown and expanded the business. They've been supportive of us through several amendments to push that anniversary warrant out. As we approach the December 1st aspect that you just mentioned, ultimately with the issuance of that anniversary warrant upon us, we are in discussions with Hytrail. We are obviously reporting very good results as part of the quarterly call here. And as we look towards what the next steps are, we're obviously evaluating many things. And so we are very supportive of working with Hytrail and they're supportive of our development plan. And so we believe that an outcome will be available to us and we'll be able to talk more about that as part of the year-end results. Okay, thank you.

Our next question is from the line of Charles Mead with Johnson Rice. Let's just see if there are questions.

Good morning, Greg and Michael and the rest of the Prairie team there.

Greg, I want to ask about the Burnett pad. I wonder if you could talk about two major dimensions of it. Number one, those results look strong to me, but I wanted to see if you could talk about how those came in versus maybe your internal base case or high side case. and then also, because this is a relatively, I guess, more recently tested area of the DJ, and I wonder if you could also talk about how it compares to some of the results from the offset operators that have been drawn around you in the last year or so.

Yeah, I'm absolutely happy to, Charles. So the Burnett pad is, first and foremost, was the original inception acreage behind Prairie Operating, dating back to 2023. So that was the first acquisition that was utilized as part of the change in the structure from a crypto company into an oil and gas company on NASDAQ. So also our first original OGDP. And so as we looked to develop the acreage, there was a lot of stepping stones we had to get through in terms of pad development, takeaway, midstream, et cetera, and so forth. And so we were very happy to be able to bring that online in the third quarter. We developed it in a manner. testing the boundaries of that OGDP. And we did that intentionally because ultimately, you know, as you step into a new area, it's a little bit of a step out. Ultimately, you want to understand your geology, your economics and the engineering, let alone just how that well is going to flow and the dynamics of how it interacts with your midstream systems. And so we developed it in a manner that I would say is very conservative. We also developed it in a manner that we can go back and drill out the rest of that OGDP and several additional visits. So very excited about how we were able to do that and get to it. You know, we've talked about this area before. It sits between the Hereford Field and the Northeast Extension. And as we look at historical operators in this area, you have Chevron, which was originally the original Noble Acreage. You have Bison. You had Mallard. You had others that operated in and amongst these areas. And so we are definitely not first inventors here. we are fast followers and so your second question led to you know offset results and how those how we compare and you know ultimately we are we are followers and there are others that are seeing and exhibiting equal and or better results than we are and so we we are definitely paying very close attention to the flow back methodology we're paying very close attention to the frac designs etc and so forth so that you know as we are developing into these newer areas for us, not Greater Wattenberg, where the majority of our acreage sits, and have been very pleased with the results. So I'll end on the results, which was the last part of your question. Internally, they have beat our internal type curve results, both from an initial IP rate as well as from a CUM rate at this point in time. We're being very diligent with these wellbores in terms of the flowback methodology, in terms of the continued production results. and we look forward to continue to develop in this area and continue to use newer technologies as many of our offsetting piers are using to continue to enhance the development in this particular area and zone.

Got it. That's great detail, Greg. Thanks. And then a quick follow-up on the 4Q production trajectory. Do you have any other, you know, wells that you're scheduled to bring online between now and year end? Or are you, you know, or, you know, completions and tills, are they done for the year at this point?

So the drilling schedule, as we announced in this, we are drilling wells. You know, obviously, there is, there's a whole other 45 days ahead of us till the end of the year. the drilling results in ducts available to be able to generate production would be very limited at this point in time. And so most of the activity from this point forward would be benefiting Q1. Right. Okay. Great. Thanks, Greg.

Our next questions are from the line of Jeff Robertson with Water Tower Research. Please receive your questions.

Thank you. Good morning, Greg. To further the production trajectory, I think you mentioned the four wells that are in progress now will be on sometime in 2027. Can you share any color on how you see development maybe for the first couple of quarters of 2027 with new well completions?

So, Jeff, at this point in time, we're not issuing 2027 guidance. I will tell you that the team has a robust amount of permits in hand, as evidenced by our reserve report. and we have initial kind of plans in place and we're being proactive about what that first quarter will look like via those wells that we were drilling and having ready for completions in the fourth quarter. But at this point in time, the quantum number of wells, which wells they will be, et cetera and so forth, we're not disclosing that yet.

Michael, on the balance sheet with the expectation of free cash flow growing in the fourth quarter of 26, can you talk a little bit about balance sheet management between working capital and paying down the RBL?

Yes, as you expect, as cash flow continues to come in, we continue to pay our payables, which will lower kind of our net working capital balance. At the same time, we'll continue to Paydown, our RBL as well as available. So it's kind of tomato-to-mato from my perspective, whether we're thinking about payables or paying down debt. But the point being that our liquidity position continues to improve as we exit the year. When is the next scheduled redetermination on the RBL? So we have quarterly redetermination. So we are in the middle of a redetermination now. And in terms of timing of that, expect some perspective on that in Let's say December.

And lastly, on the RBL, Michael, I believe there are some minimum production thresholds. Can you share any color on what the capital program needs to look like to meet those thresholds?

Yeah, practically speaking, those production metrics have, of course, been met to date and will continue to be met based on our current production and our cash flow. So I think from that perspective, there is no incremental development required in the near term to meet those production targets. Thank you.

Thank you. Ladies and gentlemen, this will conclude today's question and answer session and will also conclude today's conference. We thank you for your participation. You may disconnect your lines and have a wonderful day.