Good afternoon and welcome to the Prairie Operating Company's Second Quarter 2025 Earnings Conference Call. Today's call is being recorded. At this time, I'd like to turn the call over to Wobbe Ploegsma, Vice President, Investor Relations and Capital Markets. Please go ahead. Thank you, Operator. Good morning, everyone, and thank you for joining us for Prairie Operating Company's Second Quarter 2025 Earnings Call. Before we provide our 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 measures. For a more detailed discussion of the risks and uncertainties that could cause actual results to differ materially from any forward-looking statements, as well as the reconciliations from any non-GAAP financial measures, please see the company's public filings, including the Form 8-K filed today. We have also posted an updated investor presentation on our website. Joining me today are Ed Kovalik, Chairman, CEO, and Co-Founder; Gary Hanna, President and Co-Founder; and Greg Patton, Executive Vice President and Chief Financial Officer. With that, I'll turn the call over to our Chairman, CEO, and Co-Founder, Ed Kovalik. Thanks, Wobbe, and good morning, everyone. I appreciate you guys joining us today. The second quarter of 2025 marks a major step forward for Prairie as we continue to execute across all facets of our business: operationally, financially, and strategically. I'm incredibly proud of the progress our team has made. Moving forward, our focus remains on delivering long-term, sustainable value through disciplined growth, strong capital efficiency, and opportunistic portfolio expansion. We generated $38.6 million in adjusted EBITDA in the second quarter, a new company record that reflects the strength of our asset base, disciplined capital allocation, and continued focus on cost control. Capital expenditures totaled $56.6 million for the quarter, fully aligned with our one-rig development program that targets approximately 60 wells per year on an annualized basis. This measured, high-return approach allows us to grow efficiently while maintaining operational control and balance sheet flexibility. Since inception, Prairie has prioritized cost leadership as a core pillar of our strategy. Through disciplined execution and the implementation of rigorous cost management systems, we've driven our most recent AFEs down to $5.6 million as compared to offset tiers AFEs of $6.5 million - $7.2 million. These savings translate directly into higher IRRs, and we believe we still have room for improvement. Our operations and procurement teams are continuously refining our cost structures to unlock further reductions across all drilling and completions activities. During the quarter, Prairie achieved several key milestones that underscore the strength of our company and the momentum behind our strategy. We delivered record production: 21,052 BOE per day, approximately 50% of which was oil, representing over a 540% increase quarter over quarter. This growth was driven by continued strong performance from our core assets and the integration of our recently acquired properties. Importantly, our strategy is built not just on organic growth but on continued consolidation. In addition to our development program, we have a robust pipeline of accretive acquisition targets being evaluated on an ongoing basis. Our goal is to complement our operated inventory with high-quality bolt-ons and scale-enhancing transactions that support capital efficiency and cash flow generation. This dual-track strategy, disciplined organic growth and selective high-quality acquisitions, positions Prairie to accelerate value creation in any macro environment. We are in the process of closing two additional acquisitions, adding approximately 18,000 net acres that are expected to close in the third quarter. By implementing and executing this strategy, we have closed two significant acquisitions since October 2024, all in off-market transactions at attractive multiples. Each transaction close has added meaningful scale, efficiency, and depth to our portfolio, significantly enhancing Prairie's standing as a returns-focused oil-weighted operator in the DJ Basin. Getting into the specifics of each deal, the Nickel Road acquisition completed late last year added more than 5,500 net acres and 26 operated wells in Weld County, along with 89 approved permits and a robust drilling runway. The Bayswater acquisition, which closed on March 26, was a defining moment for Prairie. The transaction added approximately 29,000 net acres and over 350 operated locations in Weld County, Colorado, along with 77.9 million BOE improved reserves and $1.7 billion in improved PD10 value. This deal was a pivotal milestone for our company. Successfully executing a transaction valued at over $600 million with a market cap under $200 million is a powerful validation of our team's ability to outperform expectations, command market confidence, and deliver results with precision and credibility. These deals, together with our organic development, form the foundation of our company and highlight our ability to accretively grow, create value, and scale quickly with discipline. I want to thank our entire team for their tireless work in sourcing, structuring, and closing these transactions. We also enhanced our financial position by amending our $1 billion credit facility agreement with Citibank, expanding our lender syndicate to include Bank of America and West Texas National Bank, reaffirming our borrowing base at $475 million with no other material changes. This significantly improves our liquidity and provides us with the flexibility needed to execute our strategy. Importantly, following the close of the Bayswater acquisition, we executed a comprehensive portfolio of hedges covering approximately 85% of our pre-developed production, inclusive of volumes from Bayswater through 2025. These hedges secured pricing, helping to de-risk our cash flows and support capital planning through future cycles, regardless of broad market volatility in oil prices. As part of the integration process, we front-loaded significant investments in systems and infrastructure across departments, compatible with our mission of scaling the company towards 100,000 barrels of oil of production. These new systems position us to minimize ongoing dependence and costs associated with outsourcing, putting us in a position to enhance shareholder value. We are firmly positioned as a growth company through the drill bit and as a consolidator, maintaining our commitment to capital efficiency and operational excellence. We are also on a clear path to achieving corporate cash flow break-even. Our mission is to deliver sustainable free cash flow and return capital to shareholders, ultimately through dividends, and every aspect of our strategy is aligned with that goal. With that, I'll now turn the call over to our CFO, Greg Patton, to walk through the financial and liquidity position in more detail. Thanks, Ed, and good morning, everyone. For the second quarter of 2025, we delivered strong financial results. Adjusted EBITDA came in at approximately $38.6 million, representing over a 600% increase quarter over quarter. This improvement was driven by a combination of higher production volumes and improved commodity pricing, which together contributed to a strong financial performance. Net income for the quarter totaled $35.7 million, reflecting our disciplined capital deployment and the underlying strength of our asset base. From a top-line perspective, we reported total revenue of $68.1 million for the quarter, supported by realized prices of $65.66 per barrel of oil, $8.70 per barrel for natural gas liquids, and $1.80 per MCF for natural gas. Net income for the quarter was $35.7 million, representing $1.04 per share outstanding. As mentioned, adjusted EBITDA totaled $38.6 million, underscoring the operational and financial progress we continue to make. Net cash provided by operating activities was $9.7 million for the quarter. Looking at our results on a per barrel of oil equivalent basis, total operating expenses were $25.66 per BOE. This includes lease operating expenses of $5.92 per BOE, transportation and gathering costs of $1.17 per BOE, and production and ad valorem taxes of $3.35 per BOE. General and administrative expenses were $8.58 per BOE. Depreciation, depletion, and amortization expense was $6.37 per BOE. These metrics reflect our integration and system implementation costs, of which a significant portion are related to one-time expenses. As we move forward, we will continue our focus on operational efficiency, cost control, and the benefits of increased scale following recent acquisitions. Our CapEx was $56.6 million for the quarter, consistent with our development plan and reflective of the continued execution of our high-return drilling program. We remain on track with our full-year capital budget, which is expected to range between $260 million and $280 million. Turning to our financial position as of June 30th, 2025, our leverage ratio was approximately 1x on an adjusted 12-month rolling average, with total liquidity of approximately $98.7 million, consisting of $88 million of availability under our revolving credit facility and $10.7 million in unrestricted cash. As a reminder, we amended our credit facility in March, reaffirming the borrowing base and aggregate elected commitment to $475 million, with an overall facility size of $1 billion and a maturity date of March 26th, 2029. This provides us ample financial flexibility to support our development program and evaluate strategic opportunities as they arise. Our hedging program remains central to our risk management approach. Following the Bayswater close, we put in place a comprehensive hedge portfolio to protect our expected production from commodity price fluctuation and volatility. These hedges secure pricing of $68.04 per barrel of oil, $4.30 per MMbtu of natural gas through the remainder of 2025, and $64.22 per barrel and $4.06 per MMbtu through the first quarter of 2028. By locking in pricing for the majority of our production, we effectively insulate ourselves from near-term commodity price volatility and position the company to more reliably forecast cash flows and capital expenditures. This proactive approach demonstrates our continued commitment to capital discipline and long-term fiscal responsibility. Turning to reserves, Prairie ended the quarter with total approved reserves of approximately 100 million BOE. Of this total, 55 million BOE is classified as approved developed producing (PDP) with the remaining 45 million BOE in the approved undeveloped (PUD) category. Our current development inventory includes over 600 gross drilling locations. These reserves reflect the quality of our asset base, the depth of our inventory, and the long-term value we are building through disciplined investment and operational execution. On integration, the transition of the recently acquired assets has been seamless. We've aligned systems, streamlined processes, and attracted and brought on board key personnel from industry-leading companies. The cultural alignment has exceeded expectations, and our combined team is already delivering results. We've also taken key steps to ensure continuity and efficiency across our supply chain. We have focused a significant effort on building relationships with midstream providers, ensuring guaranteed takeaway optionality for the foreseeable future. Additionally, we have secured contracts with ProCraft and Precision Drilling, supporting our capital plans for 2026. These contracts collectively help manage costs and mitigate potential service disruptions. With that, I'll turn the call over to Gary Hanna, our President and Co-Founder, to provide a detailed operational update. Thanks, Greg. I'll start off by highlighting our safe operations across the company with no lost time or recordable incidents in Q1 and Q2. The environment, health, and safety remain a top priority for Prairie, especially as we integrate acquired assets into our safety culture. As to field operations, the second quarter execution was very good, including some technical innovations with continued momentum across our development programs. We drilled 18 wells and completed nine wells during the quarter. We remain on track to exceed 35 total new wells turned in line by year-end. Our average spud to total depth times continues to improve, now averaging just 5.3 days, a testament to the focus and efficiency of our field teams. Cost discipline remains strong, with well cost tracking within 5% of AFE and averaging D&C costs on the most recent wells of approximately $5.6 million. We continue to work to drive our 2 mi well AFE down towards $5 million per well. A major highlight was the successful execution of our Rusch Pad in Weld County, which includes 11 2 mi lateral wells, eight targeting the Niobrara and three targeting the Codell. Eight of the wells were drilled in a single run using Schlumberger's NeoSteer rotary steerable system, driving average rates of penetration to over 450 ft per hour, reducing drill costs and lowering our CO2 footprint. First production from the Rusch Pad is on schedule for early in the third quarter and demonstrates the operational team's focus on capital efficiency. During the second quarter, Prairie achieved an engineering milestone with the deployment of advanced U-shaped lateral designs and innovative well architecture that enables horizontal wells to loop back within the lease boundary, effectively increasing the productive lateral length within a confined footprint. This technique allows us to target multiple reservoir zones and avoid lease line constraints, enhancing recovery without additional service locations. These U-turn or U-well laterals represent a cutting-edge approach to subsurface development that, to our knowledge, has only been attempted in a limited number of wells across the DJ Basin. We successfully implemented this design at our single section noble pad, where four of the seven wells incorporate U-shaped trajectories to optimize drainage between two stacked producing zones. The wells required only 14 hours of additional drill time versus standard linear 2 mi drills but result in a 25% - 30% savings. Confident in our ability to drill and complete these wells efficiently, we are obviously exploring additional applications. Drilling of all seven surface holes was completed in May by Ensign, and Precision's production rig began drilling the production intervals in early June. We also deployed an electric frac fleet, significantly lowering emissions and reducing completion costs, further aligning our operations with sustainability goals. In May, we initiated completions on the Opal Coalb ank pad, targeting nine previously drilled but uncompleted wells acquired in the Bayswater transaction. Our first super frac was executed with excellent efficiency, averaging 14 stages per day and ramping up to 18 stages per day by the final week, all while averaging 22 hours of daily pumping time. Early pressure data is promising, with frac pressures approximately 10% higher than offset activities, suggesting the potential for superior well performance. Completion operations concluded in Q2, and the pad was open to flow back in July. All nine wells began producing oil within the first week, supported by strong average flowing tubing pressures exceeding 1,500 psi. As we have integrated the producing Bayswater and Nickel Road assets, production optimization efforts have also been prioritized through continuous evaluation of each pad. This includes gas lift optimization, workover opportunities, and maximizing surface facilities. As an example, in Q2, we installed gas-assisted plunger lift systems across 30 wells during the second quarter, designed to enhance liquid recovery and improve overall well efficiency. Another 25 - 30 wells are under evaluation for implementation in Q3. Additionally, we have identified and executed three high-return workovers in Q2, with more in the queue. Two wells were brought back online in June after successful reworks, and the third on production at the end of July. Through Q2, the growth has been tremendous, and today we operate over 360 producing wells, with more to come. Our operations team and throughout the organization have been rounded out with skilled and seasoned professionals, making us highly scalable as we move forward. Altogether, our operational performance in the second quarter reflects Prairie's commitment to efficiency, innovation, and disciplined growth. We are maximizing asset value while upholding the highest standards of environmental stewardship, capital returns, and most importantly, safety. Again, we remain uncompromising in our commitment to safety and environmental stewardship, both core to Prairie's culture and long-term value proposition. With that, I'll hand it back to Ed for closing remarks. Thank you, Gary. We are upwardly revising our initial full-year 2025 guidance provided in January to reflect closing the Bayswater transaction on March 26 of this year, as well as the enhanced visibility we now have across our platform after a successful quarter of integration. We are updating our full-year production guidance from a range of 7,000 - 8,000 BOE per day to an increased range of 24,000 - 26,000 BOE per day. We are also updating our full-year capital expenditure guidance from a range of $120 million - $130 million to an increased range of $260 million - $280 million. Lastly, we are updating our full-year adjusted EBITDA guidance from a range of $100 million - $140 million to an increased range of $240 million - $260 million based on a WTI price range of $60 - $70 per barrel. Our operational execution and performance year to date, along with the momentum across our portfolio, remain strong, and we continue to benefit from improved capital efficiency and seamless integration of recent acquisitions. We remain disciplined in our approach and excited about what lies ahead for Prairie. We are committed to creating long-term value for our shareholders through a combination of pursuing double-digit organic growth through the drill bit and pursuing opportunistic and transformative M&A opportunities. Most importantly, the company is making great strides towards our core objective of returning cash to shareholders in the form of a regular dividend program. I want to thank our incredible team for their hard work and dedication. Prairie's foundation has never been stronger. We're incredibly well positioned to continue delivering exceptional results through the remainder of the year and beyond. Our growth story is only just beginning, and we're thankful for your loyal support. With that, I'll turn the call back over to the operator to open the line for questions. Thank you. We'll now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, as we poll for questions. Thank you. Our first question is from Chris Degner with Water Tower Research. Hello. Hi, Chris. Hey, Chris. Hey, Chris. Hey, great to hear from you all, and congrats on a good quarter and integrating the Bayswater acquisition. I'm just curious, as you look around the M&A market, there's been a lot of activity up north and some asset sales that are non-core from some of the larger operators in the basin. I'm just curious how you think about measuring the returns on those incremental development locations within your portfolio versus other acquisitions. How do you measure the potential for returns and capital accretion? Yeah, thanks, Chris. As obvious, given our track record in acquiring assets and doing that, you know, large and small from bolt-ons to significant acquisitions, we're really focused on accretive acquisitions. As a result, we're highly selective, which is really to your question. We've seen some more recent press from peers in the Rockies with divestitures at multiples that are 4x EBITDA or greater. We've been really disciplined in executing deals between 2x and 2.5x EBITDA. You know we have a pretty robust pipeline of deals to continue executing on at those levels. We really don't see ourselves chasing transactions up to those kinds of valuations. Also, all of the deals we've done to date have been off-market transactions rather than through auctions, which I think has helped a lot. For us to do accretive deals, we really need to do them within a multiple that is beneath our traded multiple. Assuming a 4x valuation on our company, our stock deserves to be about $9 - $10 per share. I think that's a great multiple for us as an acquirer, but I think it's pretty expensive for target assets that we would acquire given our current trading valuation. Okay. As you think through some of the ways to execute on operational improvements, I think you mentioned you were going to take well costs from around $5.6 million down to $5 million. What do you think are the key components that you'll be able to deliver to achieve those goals? That's a great question. You know, a really core pillar of our entire strategy is being cost-focused, really to the level of being religious about it, frankly. When we started that process, we were quoted somewhere between $6.5 million and $7.25 million per well when you roll up all of the various line items in the AFEs. To date, that's still what our offset peers are spending. We attacked that by going for the lowest hanging fruit first. We've knocked down the big line items first and foremost. Now we're really going after the $50,000 here, $20,000 there. There's still some big things we can tackle, and we see a clear line of sight to getting that down to $5 million for a 2 mi AFE. Now running a full one-rig program, which is 100% utilization, really helps us in terms of getting full efficiency out of our operations. It's also a good time to be a customer in the market. We're able to really run competitive RFP processes across vendors in every line item of our RFP. We've also done some unorthodox things like inviting bids from out-of-basin companies. There's no reason why the DJ should be a walled garden where local vendors are free to run up costs to their whim. We've made it a national RFP process and brought in folks that are really capable, highly skilled, and willing to compete. That's the path that we're well on our way on now, and we've still got some work to do and look forward to reporting our progress on our next call. Excellent. Thank you for the input and look forward to seeing you soon. Thanks, Chris. Our next question is from [Charlotte Meade with Johnson Rice]. Yes, good afternoon, Ed, to you and your whole team there. Ed, I don't want to belabor this very much because you guys just got your hands on the Bayswater assets just a few days ago before 2Q came. We were looking for a little higher production number, but I'm sure that that's, you know, we just didn't have the right ramp in. To that point, can you talk about what your learning curve has been like with these Bayswater assets and perhaps give us an idea of what your company-level production was either as you exited 2Q or where it is today? Yeah, I'm happy to answer that. It does speak to the ramp and the timing of the closing more than anything. At the time that we closed the transaction, we did so with a 12/1 effective date as of last year, where the Bayswater assets were producing about 26,000 barrels of oil a day based on about a 20% decline rate, which we anticipated at the time we closed. We've come down about 4,000 barrels a day on production on those assets. We also closed the acquisition about two months later than we originally anticipated. Essentially, it just pushed forward the ramp by that period of time. We're turning in line nine fewer wells this year than we would have otherwise done had we closed that transaction earlier. The ramp trajectory is the same. Nothing's changed there. We've had a little bit of offset shut-ins from neighbors, primarily Chevron, completing wells around us. We've shut in some of our production as a result of that, but that's now coming back online pretty steadily. We see that kind of coming back to anticipated levels here between now and the next call we have. All in all, really just a timing fact around closing and effective date. Got it. That is helpful detail. Thank you. The Rusch Pad, I want to ask about, I think in the press release you say that you expect to complete that well, or that pad rather, in the third quarter. As we're talking here this afternoon, we're close to the halfway mark. Can you give us an update on where you are with those completions and when you might be in a position to share rates? Yeah, this is Gary. I'm happy to answer that. Yeah, everything's on schedule as of today. We do anticipate that coming on in the very near future. We've had very good production, or I should say pressure information out of those wells. We're pretty excited about the potential of those wells, and we can certainly keep you posted on that. It is on schedule for the end of the quarter. Thank you, Gary. Thank you, Ed. Thank you. You got it. Thank you. Our next question is from Leo Mariani with Roth. Hi guys, I just wanted to follow up a little bit on the production here. Just with respect to what you guys had put out, maybe there was an issue in what was communicated in the press release, but on March 26, you guys talked about adding 25,700 net BOE per day of production, you know, from Bayswater. If I heard you right, it sounds like that really wasn't the right number. It was something significantly lower than that that was added. Maybe that's some kind of old number from several months before and the asset would have been declining for several months. Could you maybe just help me out with that? I just maybe I'm not reading the public information correctly here. Yeah, no, the number we announced was the correct number based on the 12/1 effective date, which is how that was couched at the time, and based on what we could report at the time of announcing the closing of that transaction. Okay, I guess I didn't see those details in the release. It just made it sound like that was your March 26th production here, but okay. Moving on to your guidance here, if I'm doing the math right here, it looks like you guys are going to need to average around 36,000 BOE per day in the second half of 2025 to get to the lower end of your guidance. Given that you were at 21,000 in the second quarter, that would be a heck of a ramp. Could you maybe kind of bridge that gap and how you get to the 36,000 in the second half of 2025? Sure, happy to. We are turning in line 35 total wells this year, with most of that concentrated in the second half of the year here since we've only completed nine wells in the prior quarter. You will see a pretty significant ramp through Q3 and Q4 with a materially higher exit rate of production than what we stated as our average annualized production. Okay. Do you have an oil cut on that 24,000 - 26,000 BOEs per day in your guidance? Approximately 50%, but on a total liquids basis, trending closer to 75%. Okay. On your CapEx, it looked like you guys were spending at a lower rate here in the second quarter. It looks like it's ramping up in the second half per your guidance. Do you expect CapEx to be kind of fairly split evenly between 3Q and 4Q? It looks like those numbers are going to be up a decent amount from where you were in the second quarter. Yeah, I mean, I'll let our guidance speak for itself. We're not really guiding to quarterly CapEx right now, but that's pretty dead on with what we expect to spend for the year. Again, what we really had is just an approximate 60-day delay to starting the ramp, but the ramp is very much well on its way with great results from our drilling and completion execution. We have no reason to believe we're not going to accomplish these kinds of numbers. Okay. On your NGL price for the quarter, I think you guys said it was $8.70 a barrel in the second quarter. I guess other industry prices were a lot closer to kind of high teens or $20. Can you maybe provide a little color why that price was kind of as low as it was? Maybe there was some accounting here or something. That's just a weighted average NGL price calculated on a barrel basis. Ultimately, yes, I would agree with you, the average is closer to the $15 marker, but just based on the accounting methodology that we applied for it for the financials, it came out to the $8.70 mark. Hedging is correlative to the average market price. Okay. Thanks. Our next question is from Tim Moore with Clear Street. Thanks. You know, it's nice to have a full quarter of Bayswater owned under your belt. You already mentioned about the AFEs drilling coming down lower than peers. Ed, I'm just kind of curious if you can maybe add some more color on just what type of efficiencies or improvements maybe do you plan to do at Bayswater. You've had time to walk around that for the full quarter. Is there anything else you're uncovering or thinking of some more best practices to apply? Have you noticed any catch-up maintenance CapEx you got to do there? Yeah, no, that's a great question, Tim. Thank you. We've acquired over 340 wells, and that leaves a lot of room for optimization. We also brought over most of the field personnel that had been working those wells with Bayswater, so now they're Prairie employees. We've taken the last quarter to really get up to speed and evaluate all ways in which we can optimize that production, both near-term, mid-term, and long-term. The big two categories that we're finding are workovers and gas lift optimization. We've already begun in that endeavor, and I'll let Gary share some details with you on that. Yeah, I think, first of all, I think it's safe to say that Bayswater is an excellent operator. It's one of the reasons we like the asset. We really didn't see issues around deferred maintenance, but there's always room for improvement. We've been systematically attacking every pad, every well. We executed on a number, as I pointed out in the opening, on plunger lift efficiencies, how much gas we're putting down, how much gas we're taking to sales, and really optimizing that. We've been able to do certain things at the surface locations to improve upon those. We've now identified a lot of workover opportunities. I pointed out we executed on three of those already with some really great results, picked up 400, 500 barrels just on those little workovers. There's a lot of that work to do. It's just focus, it's really getting into the weeds on these wells, learning about them, discovering what's going on with them, and then attacking them. That's our mission, and we're very active in that regard. There are some really low-hanging fruit where we've got a concentration of fewer than 10 wells that probably amount to 500 or more barrels per day of optimization. That's the way we're approaching the whole opportunity set, going after the highest impact, low-hanging fruit first. No, that's great. Yeah, I got to imagine the IRRs and those workovers will be really terrific as you uncover more of those. Yeah, the payback is super fast. No, that's terrific. Great. That's it for my questions. Thank you. Thank you, Tim. Thank you. There are no further questions at this time. This does conclude today's conference call. You may disconnect your lines at this time. Thank you for your participation. Thank you.