Operator: Good morning, and welcome to the Prairie Operating Company Second Quarter 2026 Earnings Conference Call. Today's call is being recorded. At this time, I would like to turn the call over to Wobbe Ploegsma, Vice President of Investor Relations and Capital Markets. Please go ahead.

Wobbe Ploegsma: Thank you, operator, and good morning, everyone. Thank you for joining Prairie Operating Company's Second 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 in any 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 ended June 30, 2026. These materials are available on our website, along with an updated investor presentation. Joining me today are Greg Patton, Chief Executive Officer and Director; and Michael Shelly, Executive Vice President and Chief Financial Officer. With that, I'll turn the call over to our CEO, Greg Patton.

Gregory Patton: Thanks, Wobbe, and good morning, everyone. The second quarter was a transformative period for Prairie. We advanced our DJ Basin development program while also making significant changes across the company designed to strengthen our organization and position Prairie for its next phase of growth. During the quarter, we transitioned our management team, refreshed the Board and welcome new directors whose experience and perspectives enhance our oversight and strategic decision-making. We also completed a meaningful partial refinancing of the Series F Preferred stock, reducing the outstanding preferred balance and potential warrant-related dilution and recently extended our anniversary warrant date to August 31, 2026. Together, these actions were focused on increasing liquidity improving financial flexibility and further aligning management and the Board around disciplined execution and long-term shareholder value creation. We remain focused on the priorities that underpin long-term value creation, safe and efficient execution, disciplined capital allocation, continued cost improvement and a strong flexible financial position. The progress we have made year-to-date reflects the quality of our assets and the commitment of our team, and we believe it provides a solid foundation for the balance of 2026 and into 2027. With a broader perspective, I'd like to turn our second quarter operational performance and the progress our team made across production, drilling execution and capital efficiency. During the second quarter, production totaled approximately 2 million BOE or 21,866 BOE per day, with liquids representing approximately 72% of production, including approximately 50% oil. Production increased approximately 4% compared with the second quarter of 2025. Despite the timing of new well activity and a planned pause between the Opal Coalbank and Burnett pad, while we waited for the Colorado Parks and Wildlife seasonal restrictions to end. Our drilling performance also continued to demonstrate steady progress. We drilled 12 wells during the quarter, including 2 Codell and 10 Niobrara wells. 8 of the 12 wells were drilled in a single run, and all 12 were completed below AFE. The wells averaged approximately 19,100 feet in measured depth, an average rate of penetration of 390 feet per hour and an average spud-to-rig release time of 6.65 days. We also achieved several important technical milestones. During the quarter, we successfully drilled our first 3-mile lateral, a Niobrara B well in a single run. On the Castor pad, we completed 2 trials using a 7 7/8-inch hole design compared with our standard 8.5-inch design. The trials generated realized savings of more than $40,000 per well while utilizing the same 5.5-inch production casing with no change to the delivered completion or production configuration. Based on these results, we plan to apply the smaller hole design across a significant portion of our upcoming Niobrara development program. This is a good example of how our team is identifying repeatable efficiencies that can lower well costs without compromising well design or expected performance. Year-to-date, we have drilled 27 wells, including 6 Codell and 21 Niobrara wells with 19 drilled in a single run. On average, the wells were delivered below AFE. Year-to-date, wells averaged approximately 18,700 feet in measured depth, an average rate of penetration at 377 feet per hour and an average spud to rig release time of 6.2 days. We have completed drilling operations at the Elder, Opal Coalbank, Burnett and Castor pads during 2026. Importantly, because the Opal Coalbank wells began producing near the end of June, their contribution to second quarter average production was limited. With these wells now contributing more fully, our average month-to-date production for August has increased to approximately 27,000 net BOE per day. This performance demonstrates the strength of our recently completed wells, reinforces the quality and depth of our DJ Basin asset base and provides encouraging momentum as we move through the second half of the year. These achievements reflect the quality of our assets and the continued improvement of our operating capabilities. As we move through the second half of the year, our priorities remain clear: safely execute our development plan, apply proven efficiencies across the program and allocate capital to the opportunities to generate the strongest returns. I'll now turn the call over to Michael to review our financial results, liquidity and capital structure.

Michael Shelly: Thanks, Greg. Good morning, everyone. Prairie delivered solid financial performance during the second quarter and throughout the first half of 2026, supported by continued execution of our development program and the strength of our underlying asset base. During the quarter, we made important progress simplifying our capital structure through the partial refinancing of the Series F Preferred stock. The transaction reduced the outstanding preferred balance and significantly lowered potential warrant-related dilution. We remain focused on additional opportunities to address the remaining balance, enhance liquidity and strengthen our balance sheet. For the second quarter, Prairie generated total revenue of $98.9 million, an increase of approximately 45% compared with the prior year period. Oil revenue totaled $93.5 million. Production averaged 21,866 BOE per day and was approximately 72% liquids, including 50% oil. Average realized prices, excluding the effects of derivatives, were $94.21 per barrel for oil, $21.64 per barrel of NGLs and negative $1.30 per Mcf for natural gas. The negative natural gas realization reflected lower gross sales, largely associated with weaker CIG pricing during the quarter. GAAP net income attributable to Prairie was $109 million. After preferred stock dividends and remeasurement adjustments, net income attributable to Prairie's common stockholders was $193.8 million or $1.75 per basic share and $0.23 per diluted share. These results included noncash impacts related to derivatives, income taxes and fair value adjustments associated with our capital structure. Adjusted EBITDA for the quarter totaled $34 million. Net cash provided by operating activities was approximately $52 million and cash capital expenditures during the quarter were approximately $98.5 million, reflecting the concentration of development and turn-in-line activity during the period. On a per BOE basis, lease operating expense was $6.85, transportation and processing expense was $1.22, ad valorem and production taxes were $4.01 and G&A expense was $6.01. The improvement in G&A per BOE compared with the prior year quarter reflects increased scale and continued cost discipline. For the first 6 months of 2026, Prairie generated revenue of $182.3 million, an increase of approximately 125% compared with the prior year period and adjusted EBITDA of $71.1 million, an increase of approximately 65%. Net cash provided by operating activities was $94.3 million and cash capital expenditures during the period totaled $132.6 million. Total production was approximately 4.1 million BOE or approximately 22,500 BOE per day with approximately 72% liquids, including 49% oil. Turning to liquidity. As of June 30, our reserve-based credit facility had a borrowing base and aggregate elected commitments of $475 million with $436 million outstanding under the facility, providing $39 million of availability at quarter end. Our risk management program remains strong. Our commodity hedge portfolio extends through the second quarter of 2029 and provides meaningful downside protection and improved visibility into our future cash flows. For the second half of 2026, our oil swaps cover approximately 2.7 million barrels at a weighted average price of $63.09 per barrel, and our natural gas swaps cover approximately 7.6 million MMBtu at a weighted average price of $4.08 per MMBtu. Our financial priorities remain centered on disciplined capital allocation, maintaining liquidity and aligning capital spending with operating performance. We believe the investments made during the first half of the year position Prairie to benefit from the contribution of recently completed wells during the remainder of 2026. With that, I'll turn the call back to Greg for closing remarks.

Gregory Patton: Thanks, Michael. Our performance during the second quarter and first half of the year demonstrates the progress Prairie is making across the business. We are improving operational execution, advancing a repeatable and capital-efficient development program, expanding cash flow visibility through our hedging strategy and taking meaningful steps to simplify our capital structure. We are adjusting our full year 2026 guidance to average daily production of 23,000 to 25,000 BOE per day, capital expenditures of $185 million to $195 million; adjusted EBITDA of $180 million to $190 million. We are adjusting guidance to preserve and increase liquidity while maintaining a disciplined approach to development as well as to account for the first half 2026 results, including the impact of CIG pricing from April to June and TIL timings. The revised plan emphasizes capital efficiency, incorporates additional planning around Colorado Parks and Wildlife seasonal operating restrictions and allows us to better align the pace of investment with operating performance and available capital. We believe this approach improves execution certainty, protects financial flexibility and positions Prairie to deliver more durable value for our shareholders. As we move into the second half of 2026, our focus remains on safe and consistent execution, disciplined capital allocation, strengthening the balance sheet and converting our high-quality DJ Basin inventory into sustainable production and cash flow. We believe this approach provides the foundation for durable growth and long-term shareholder value. 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.

Operator: [Operator Instructions] Today's first question is coming from Leo Mariani of ROTH MKM.

Leo Mariani: I just wanted to ask around production here. It sounds like it's been up a decent amount here in August. Is that 4-well Burnett pad online? If so, can you talk a little bit about how the rates looked on that initially? And would you expect production to creep higher as we get into 4Q? How do you see that kind of 27,000 BOE per day trending the rest of the quarter and the rest of the year?

Gregory Patton: Leo, Greg Patton. Thank you for the question. And yes, happy to answer that. So Burnett is in the flowback stages right now. It is interconnected to all the necessary infrastructure, but we have not cut hydrocarbons as of this morning. I would expect any moment, we will start seeing cutting hydrocarbons. So we'll be able to talk a little bit more about that. So those wells are not factored into that approximate 27,000 net barrels a day factor. The Castor pad as well is in the middle of completion stages. So those numbers are obviously not factored into that. So we'll see -- those 2 factors obviously relay into the second part of your question, which is what do we anticipate to see in the next -- this quarter and going into next quarter. Ultimately, you'll see some ups and downs, but in and around that 26,000, 28,000 number. So the average of that 26,000, 27,000 number. And so ultimately, as you see that throughout the third quarter, moving into early parts of the fourth quarter, where we do expect to see a small decline exiting the year.

Leo Mariani: Okay. Appreciate that. And then I wanted to ask around some of the changes in the bank facility. There was a comment in one of your 8-Ks about how there's a minimum kind of production threshold around the revolver. Can you maybe just talk about that in terms of the numbers, not something I think I've seen in the past?

Gregory Patton: Yes, absolutely. So obviously, we are just over the year marker into our development stage and operating status as an entity. We have developed very strongly throughout the second quarter. And so with that, we have had to work with the banks in the modification of the credit facility to work with our continued development and to ensure that liquidity is available for us to continue to develop and produce the wells that we have online. That production hurdle is meant to essentially help us balance out not too much growth, but at the same point in time, not just shutting down to a blowdown case. So it's a modifier to work with us to keep liquidity available and to progress forward on our development plan.

Leo Mariani: Okay. And then just on the preferred, I guess you guys have gotten another extension on your anniversary warrant date, I guess, kind of the end of the month here. Can you maybe just talk about the potential to refinance that? Is that something you're kind of actively working to try to accomplish here in the near term?

Gregory Patton: So as we're all aware and all of our investors have seen, we've had success in continuing to modify the pref to reduce its face value on the balance sheet to have a very beneficial partner working with us to do that. We'll continue that relationship with preferred holder as we move forward throughout the third quarter. That extension is beneficial for us to continue to pursue multiple different avenues that we have been pursuing and has been successful with to date. So more to come there, Leo, throughout this next quarter.

Leo Mariani: Okay. And then just on your wells, you talked about some operational progress, most of the wells coming in below AFE, this recent kind of slimmer hole design, saving some more money. But where the kind of well costs stand today for 2-mile laterals, putting all that kind of together here?

Gregory Patton: 2-mile laterals, if we're operating off of a stand-alone pad within that same facility, you're going to be in that 5.2 to 5.5 range depending on the formation, depending on the frac design, the core concentration of the rock that we're developing. As we look at some of the step-outs that we're doing where we're utilizing a pad with permits to develop and offset DSU and may have some extended reach laterals to get there in that 2-mile range, we're seeing in that 5.4 to 5.6 range. So high level, there is an extra $100,000 to $200,000 of pipe in the ground to just get to that offsetting DSU. But the single trips and the smaller wellbore holes have really helped us kind of balance that as we're utilizing those available permits that utilization of a permit that's available to us to help enhance time, save money on the permitting cost to develop offsetting DSUs. And so we're excited about these new technologies the team has been able to deploy and has been successful with.

Operator: Our next question is coming from Charles Meade of Johnson Rice.

Charles Meade: Greg, going back to the Series F, and I recognize that discussions are ongoing, and so that's necessarily sensitive. But can you give us a little bit of a flavor for -- I think this is the third or fourth time that you've extended the deadline. Can you just give us a flavor for -- are you making a little bit of progress each time? Are you kind of getting closer and closer? Or is this is a kind of thing where maybe the macro environment is changing and so suddenly, like you both won a deal, but the parameters fall apart? And why not just push it out to year-end or something like that?

Gregory Patton: Great question, Charles, thank you for that. Just a little bit of history in and around the prep. When we closed this 18 months ago, there was $148.5 million of principal units outstanding associated with the prep, obviously, valued at $1,000 a unit or $148 million approximately. As of year-end, we had moved that down to roughly $121 million outstanding as of the end of this last quarter, $78 million outstanding, and we continue to work with the pref alongside that conversion in strategic manners in terms of outcomes of the quarter, continued development as well as other avenues and arenas to refinance. Along that route, we have decreased the coverage of the anniversary warrant from its original inception of 1.25:1 to today, we stand at 0.65:1 coverage. So with the reduction of the face of the pref, coupled with the reduction in the anniversary warrants, we continue to chip away at reducing it, redeeming it and have done so with the help of the pref holder. As we move forward, we don't disagree that some extended period of time to the end of the year would be the easy route. However, there is also the beneficial need to do as much as possible with redeeming the pref as soon as possible. However, not setting any definitive time lines on the exact nature of when we'll get that done. We are obviously very active in entertaining multiple different solutions. We'll continue to entertain those and work with our Board. Obviously, with the restructure of the Board, some different methodologies have been brought to our attention that we are also pursuing. And so we'll continue all avenues of redeeming that pref in the near term and keeping some pressure on some items that we're working through.

Charles Meade: Got it. Got it. And then I want to ask about the Barnett Pad and what you're doing in the Hereford and Eastern extension areas. If we go back to when you were first putting this company together, that part of the DJ was relatively -- had not been derisked. And if you kind of fast forward to today, Bison has been really active right around your pads up there. And so I'm curious if you could calibrate us and calibrate the market for what success would look like as far as production rates from this Barnett pads or the Barnett Pad.

Gregory Patton: Yes. That's Great question. I think the type curves in the area, and again, just circling back to your comment, Bison has done a great job of derisking some areas immediately offset to us. They've been a great operator in the basin in terms of the wells that they've been able to find areas of prolific results that are outlying the kind of what we'd say is the core of the Wattenberg or the DJ. And so the original asset package that was put together in this area was an outlier to Bison. Bison has since encroached very closely in and around our acreage position. And so we've been able to glean more information from that as we've worked through and drilled and completed our Burnett pad. Additionally, Oxy and Chevron have continued to work in and around our acreage position in this particular area. And again, this is the offset area in between the Hereford and the Northeast extension for the rest of the listeners on the phone. And this is the Burnett pad or our OGDP1 location, which is the northeast-western portion of that particular acreage block. And so as we continue to develop there, the type curves are direct correlations from the Critter Creek pad from other offset Bison's pad, the Jaws and others that are offset there in correlation with required reporting requirements for type curves that [ Holly Gillespie ] has also signed off on. So as we work through those wells, the initial IPs, we're not exactly 100% sure on yet, Charles. But we think that the correlating offset type curves that you see out there associated with Critter Creek, Jaws and others will be similar in representation to the Burnett pad.

Operator: Ladies and gentlemen, this brings us to the end of today's question-and-answer session and today's conference. We'd like to thank you for your interest in Prairie Operating. If you have -- once again, the call has now concluded. Thank you for your participation. You may disconnect your lines or log off the webcast at this time, and enjoy the rest of your day.